In recent years Americans have been hearing that the United States is poised to regain
its role as the world’s premier oil and natural gas producer, thanks to the widespread use
of horizontal drilling and hydraulic fracturing (“fracking”). This “shale revolution,”
we’re told, will fundamentally change the U.S. energy picture for decades to come—leading
to energy independence, a rebirth of U.S. manufacturing, and a surplus supply of both oil
and natural gas that can be exported to allies around the world. This promise of oil and
natural gas abundance is influencing climate policy, foreign policy, and investments in
alternative energy sources.
The term "shale bubble" is about the idea that the United States is poised to regain "energy
independence" becoming again net exporter instead of major importer of oil and natural gas.
The primary driver of the propaganda campaign was the U.S. Department of Energy’s Energy
Information Administration (EIA). The key technologies that were enabler of shell boom were:
Oil and gas outfit Fieldwood Energy is now in the market with a $2.63 billion
covenant-lite first- and second-lien acquisition loan.
...As lending to lower-rated companies has increased generally, more of them
are also opting for covenant-lite financings.
That trend is evident particularly in the B3 ratings category. Around 18 percent of covenant-lite
loans are for B3 rated companies so far this year, versus 8 percent in 2012 and 3.7 percent in
2011
...Loan portfolio managers said that new institutional clients are also seeking to invest.
More than $57 billion of CLOs have been issued this year, topping 2012 volume.
This refinancing bulge in 2016 became more compressed in time and more imminent.
Most of the defaults, debt restructurings, and bankruptcies so far this year and last year
were triggered when over-indebted cash-flow negative companies could not make interest
payments on their debts.
During the crazy days of the peak of the credit bubble two years ago, they would have been
able to borrow even more money at 8% or 9% and go on as if nothing happened. But those days
are gone. Now the riskiest companies face interest costs of 20% or higher – if they’re able to
get new money at all. Hence, the wave of debt restructurings and bankruptcies.
But that’s small fry. Now comes the wave of companies whose debts mature. They will have to
borrow new money not only to fund their interest payments, cash-flow-negative operations, and
capital expenditures, but also to pay off maturing debt.
That “refinancing cliff” is going to be the biggest, steepest ever, after the greatest credit
bubble in US history when companies took on record amounts of debt, and it comes at the worst
possible time, warned Moody’s in its annual report.
In its report a year ago, Moody’s had already warned that the refinancing cliff for junk-rated
US companies over the next five years – at the time, from 2015 through 2019 – would hit $791
billion. Of that, $349 billion would mature in 2019, the largest amount ever to mature in a
single year.
...Among the other macroeconomic factors, Moody’s lists the slowdown in China and
volatility in oil prices. And there’s another factor that will “make it more difficult for
lower-rated companies to refinance”: worried regulators have been cracking down on banks’
exposure to leveraged loans, which are so risky that even the Fed has been fingering them
publicly.
Banks sell these leveraged loans to loan mutual funds or repackage them into collateralized
loan obligations (CLOs) which they then sell in tranches to institutional investors. When
leveraged loans mature, companies have to come up with the money, but Moody’s warns that
“rising defaults and the impact of the Dodd-Frank Act’s risk retention rule will make it more
difficult for existing CLOs to supply corporate financing.”
The widespread use of horizontal drilling and hydraulic fracturing, the technologies
that while expensive (and unable compete with conventiona oil production price wise) , continue
to evolve and improve.
Spike of oil prices in 2011-2014
This fake promise of oil and natural gas abundance affected both domestic government priorities
and foreign policy. Domestically it slowed down rising of private car fleet efficiency d as well as
investments in alternative energy sources. The implications of this are profound. If the “shale
revolution” is nothing more than a temporary respite from the inevitable decline in US oil and gas
production (not a revolution but a retirement party), then why are there is such a rush to rewrite our
domestic and foreign policy as if we’re going to be “Saudi America” for the rest of the century?
In 2015 U.S. shale oil production has peaked, productivity gains have flatlined and the cheap
money has all but disappeared. Has the U.S. shale game finally blown over? (Alberta
Oil Magazine, Jan 7, 2016):
To summarize the damage: output has peaked, the cheap money and easy private equity are gone,
the gains in per-rig productivity have slowed and the 20 to 30 per cent break that E&P companies
were getting from contractors for labor costs won’t go on much longer. By all metrics, the shale
party is nearly over. The question now is whether the 2015 production peak will forever be the
high-water mark for this uniquely North American industry.
There are three major sources of "subprime" oil: tight oil, shale oil and tar sands.
The term oil shale generally refers to any sedimentary rock that contains solid
bituminous materials (called kerogen) that are released as petroleum-like liquids
when the rock is heated in the chemical process of pyrolysis. Oil shale was formed millions of years
ago by deposition of silt and organic debris on lake beds and sea bottoms. Over long periods of time,
heat and pressure transformed the materials into oil shale in a process similar to the process that
forms oil; however, the heat and pressure were not as great. Oil shale generally contains enough
oil that it will burn without any additional processing, and it is known as "the rock that burns".
Oil shale can be mined and processed to generate oil similar to oil pumped from conventional oil
wells; however, extracting oil from oil shale is more complex than conventional oil recovery and
currently is more expensive. The oil substances in oil shale are solid and cannot be pumped directly
out of the ground. The oil shale must first be mined and then heated to a high temperature (a process
called retorting); the resultant liquid must then be separated and collected. An
alternative but currently experimental process referred to as in situ retorting
involves heating the oil shale while it is still underground, and then pumping the resulting liquid
to the surface.
What bother many observers is the amount of unprofitable (supported by junk bonds) shale oil that
come to the market in the relatively short period of time.
“There is this huge myth propagated by the MSM as well as several of the well-known names in the
alternative analyst community about the wonders of SHALE ENERGY. I can’t tell you how many readers
send me articles from some of these analysts stating how the United States will become energy independent
while pumping some of these shale energy stocks. Nothing has changed in America….. there’s always
another sucker born every minute.
It is extremely frustrating to see the continued GARBAGE called analysis on the SHALE ENERGY INDUSTRY.
I have written several articles listing the energy analysts that I believe truly understand what
is taking place in U.S. energy industry. They are, Art Berman, Bill Powers, David Hughes, Jeffrey
Brown and Rune Likvern.”
While this conversion of junk bonds into oil has features of classic bubble (excessive greed) but
it was also different in some major aspects.
We know that bankers like bubbles because they always make money on swings, either going up or down.
We can accept that that is how things work on this planet under neoliberalism but that does not turn
them less crazy.
At the beginning this was about shale gas, only later it became about shale and tight oil production.
But shale oil production did has major elements of a bubble. And greed was present in large qualities.
Special financial instruments like ETN were created to exploit this greed. MSM staged a compaign of
how the wonders of technology, specifically horizontal drilling and hydraulic fracturing, have unleashed
a new era for energy supplies. Without mentioning that for each dollar shale industry recovered 1.5
dollar of junk bonds was created.
If we think about it in bubble terms that the key selling point of this bubble was that it will lead
to America’s energy independence, a manufacturing renaissance, and will lower gas bills for everyone.
The estimates (based on past reservoir dynamics) were grossly over represented. The factor that is present is bubbles is that they create excess production that at some point far outpace
the demand.
North American crude oil producers are not cash flow positive, and they haven’t been since the beginning
of the shale boom. Capital expenses of shale companies has consistently exceeded cash flow even at $100
per barrel oil price. So essentially this was a risky gamble that oil will go higher, and this gamble failed.
At least for now.
Most experts and analysts agree that, at current oil prices, the shale oil sector will need to
dramatically reduce per-barrel costs in order to make the vast majority of North American plays
viable. “The minimum price I’ve seen [to make production worthwhile] is $50 a barrel in the
very best possible scenarios and with the very best technology,” says Farouq Ali, a chemical and
petroleum engineer at the University of Calgary. “But most of the time they need $65 oil. So the
5.5 million shale barrels we see right now will all decline, but they will decline over time
because there are still thousands of wells. Even if oil prices go to $60 they will still decline
because that’s just not enough profit to operate.”
Of course, those returns aren’t just diminishing on the production side, but in the
pocketbooks of investors, too. Wunderlich Securities senior vice-president Jason Wangler
describes the rise of U.S. shales as a “perfect storm” of cheap money, seemingly limitless
production potential and rapidly advancing technologies. “Now the money is hard to come by,”
Wangler says over the phone from the firm’s Houston office. “With oil at $90 or $100 it was
pretty hard not to be economic.” But that old high-price environment, he says, caused significant
overinvestment in shale assets, including in risky bets on barely marginal plays like the
Tuscaloosa Marine Shale formation that spans parts of Louisiana and Mississippi. “But if you look
at the last year or so, you’ve seen a lot of folks really focus on the Permian and on the
Niobrara,” Wangler says. “Meanwhile you’ve seen the Bakken really fall off very, very hard, as
well as the Eagle Ford and the mid-continent area.”
The decreasing viability of the Bakken region is especially significant. Houston-based shale
expert and petroleum geologist Arthur Berman estimates that with West Texas oil trading at $46, a
mere one per cent of the massive Bakken shale play is profitable. At those prices, just four per
cent of the horizontal wells that have been drilled in the Bakken since 2000 would recover their
costs for drilling, completion and operations, according to Berman. Add to that the competition
from Western Canadian crude oil, which continues to travel down through the U.S. Midwest via rail
and pipeline, and one can assume that a lot of Bakken production will remain economically
underwater without a significant price correction or some breakthrough in cost savings. “In the
Bakken, you’ve got a long way to transport to get that oil to market,” Wangler says. “Obviously
you’re fighting with all that Canadian crude coming down, which makes the price more difficult.
It’s also expensive to [transport oil out of] North Dakota, whether you’re going to the Gulf
Coast or you’re going east or west.”
Due to the dramatic drop of oil prices shale bubble start deflation. Several bankruptcies occurred
in 2015. More expected in 2016 if the price not recover.
Some critics to argue the business model of shale production is fundamentally unsustainable. Before
the oil rice collapse, which started at mid 2014, immediately after signing Iran deal (strange coincidence)
it was expected that producers would have positive returns for the first time in 2015”
“Only 1% of the Bakken Play area is commercial at current oil prices based on my analysis
that follows.
Only 4% of horizontal wells drilled since 2000 meet the EUR (estimated ultimate recovery)
threshold needed to break even at current oil prices, drilling and completion, and operating costs.
The leading producing companies evaluated in this study are losing $11 to $38 on each barrel
of oil that they produce, the very definition of waste. …”
While oil shale is found in many places worldwide, by far the largest deposits in the world are
found in the United States in the Green River Formation, which covers portions of
Colorado, Utah, and Wyoming. Estimates of the oil resource in place within the Green River Formation
range from 1.2 to 1.8 trillion barrels. Not all resources in place are recoverable; however, even
a moderate estimate of 800 billion barrels of recoverable oil from oil shale in
the Green River Formation is three times greater than the proven oil reserves of Saudi Arabia. Present
U.S. demand for petroleum products is about 20 million barrels per day. If oil shale could be used
to meet a quarter of that demand, the estimated 800 billion barrels of recoverable oil from the Green
River Formation would last for more than 400 years1.
More than 70% of the total oil shale acreage in the Green River Formation, including
the richest and thickest oil shale deposits, is under federally owned and managed lands.
Thus, the federal government directly controls access to the most commercially attractive portions
of the oil shale resource base.
See the Maps page for
additional maps of oil shale resources in the Green River Formation.
The Oil Shale Industry
While oil shale has been used as fuel and as a source of oil in small quantities for many years,
few countries currently produce oil from oil shale on a significant commercial level. Many countries
do not have significant oil shale resources, but in those countries that do have significant oil
shale resources, the oil shale industry has not developed because historically, the cost of oil derived
from oil shale has been significantly higher than conventional pumped oil. The lack of commercial
viability of oil shale-derived oil has in turn inhibited the development of better technologies that
might reduce its cost.
Relatively high prices for conventional oil in the 1970s and 1980s stimulated interest and some
development of better oil shale technology, but oil prices eventually fell, and major research and
development activities largely ceased. More recently, prices for crude oil have again risen to levels
that may make oil shale-based oil production commercially viable, and both governments and industry
are interested in pursuing the development of oil shale as an alternative to conventional
oil.
Oil Shale Mining and Processing
Oil shale can be mined using one of two methods: underground mining using the
room-and-pillar method or surface mining. After mining, the oil shale is transported
to a facility for retorting, a heating process that separates the oil fractions of oil shale from
the mineral fraction.. The vessel in which retorting takes place is known as a retort.
After retorting, the oil must be upgraded by further processing before it can be sent to a refinery,
and the spent shale must be disposed of. Spent shale may be disposed of in surface impoundments,
or as fill in graded areas; it may also be disposed of in previously mined areas. Eventually, the
mined land is reclaimed. Both mining and processing of oil shale involve a variety of environmental
impacts, such as global warming and greenhouse gas emissions, disturbance of mined land,
disposal of spent shale, use of water resources, and impacts on air and water quality. The development
of a commercial oil shale industry in the United States would also have significant social
and economic impacts on local communities. Other impediments to development of the oil shale
industry in the United States include the relatively high cost of producing oil from oil shale (currently
greater than $60 per barrel), and the lack of regulations to lease oil shale.
Surface Retorting
While current technologies are adequate for oil shale mining, the technology for surface retorting
has not been successfully applied at a commercially viable level in the United States, although technical
viability has been demonstrated. Further development and testing of surface retorting technology
is needed before the method is likely to succeed on a commercial scale.
In Situ Retorting
Shell Oil is currently developing an in situ conversion process (ICP). The process
involves heating underground oil shale, using electric heaters placed in deep vertical holes drilled
through a section of oil shale. The volume of oil shale is heated over a period of two to three years,
until it reaches 650–700 °F, at which point oil is released from the shale. The released product
is gathered in collection wells positioned within the heated zone.
Shell's current plan involves use of ground-freezing technology to establish an underground barrier
called a "freeze wall" around the perimeter of the extraction zone. The freeze wall
is created by pumping refrigerated fluid through a series of wells drilled around the extraction zone.
The freeze wall prevents groundwater from entering the extraction zone, and keeps hydrocarbons and
other products generated by the in-situ retorting from leaving the project perimeter.
Shell's process is currently unproven at a commercial scale, but is regarded by the U.S. Department
of Energy as a very promising technology. Confirmation of the technical feasibility of the concept,
however, hinges on the resolution of two major technical issues: controlling groundwater during production
and preventing subsurface environmental problems, including groundwater impacts.1
Both mining and processing of oil shale involve a variety of environmental impacts,
such as global warming and greenhouse gas emissions, disturbance of mined land; impacts on wildlife
and air and water quality. The development of a commercial oil shale industry in the U.S. would also
have significant social and economic impacts on local communities. Of special concern
in the relatively arid western United States is the large amount of water required for oil shale processing;
currently, oil shale extraction and processing require several barrels of water for
each barrel of oil produced, though some of the water can be recycled.
1RAND Corporation Oil Shale Development in the United
States Prospects and Policy Issues. J. T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson, and
G. Cecchine, MG-414-NETL, 2005.
For More Information
Additional information on oil shale is available through the Web. Visit the
Links page to access sites
with more information.
Two years ago, Wall Street banks were on their way out of a long-term relationship with the
oil industry. Now, with oil prices over $70 for the first time in three years, big bond buyers
are snapping up oil bonds once again.
Only there is a condition this time.
The Wall Street Journal's Joe Wallace and Collin Eaton
wrote this week that Wall Street was buying bonds from non-investment-grade U.S. energy
companies, which took advantage of record low interest rates to raise some $34 billion in fresh
debt in the first half of the year.
That's twice as much as the industry raised over the same period last year. But investors
don't want borrowers to use the cash to drill new wells. They want them to use it to pay off
older debt and shore up balance sheets.
It makes sense, really, although it is a marked departure from how banks normally react to
oil industry crises. The 2014 oil price collapse, in hindsight, may have been the last "normal"
crisis. Oil prices fell, funding dried up, supply tightened, prices went up, banks were willing
to lend again, and producers poured the money into boosting production.
Since then, however, the energy transition push has really gathered pace and banks have more
than one reason to not be so willing to lend to the oil industry. With the world's biggest
asset managers setting up net-zero groups to effectively force their institutional clients to
reduce their carbon footprint and with the Biden administration throwing its weight behind the
push for lower emissions, banks really have little choice but to follow the current. Their own
shareholders are increasingly concerned about the environment, too.
https://www.youtube.com/embed/aQXqMVeoOPs
Yet business is business, and nowhere is this clearer than in banks' dealings with the oil
industry. Bank shareholders may be concerned about the environment, but they certainly would be
more concerned about their dividend""and part of that comes from income made from lending to
oil. And the higher oil prices go, the more willing banks will be to lend to those that produce
it.
When they were unwilling to lend to the oil industry, other lenders
stepped in . Last year, alternative investment firms scooped up hundreds of millions in oil
industry debt from banks that were cutting their exposure to the politically incorrect
industry. Hedge funds and other so-called shadow lenders don't seem to have banks' misgivings
about profiting from oil and gas.
Now banks have mellowed towards oil somewhat, but it is an interesting twist that the
current loans come with the condition of not boosting output. Again, it makes sense. For years,
the shareholders of U.S. shale oil companies have been complaining about poor returns as the
companies put everything into output growth. Now it's payback time, and shareholders want their
returns.
So do lenders, apparently.
Per the WSJ article, this year, bond buyers "want to see companies repairing their
balance sheets and delivering to creditors and shareholders rather than plowing money into new
wells."
We have owned rigs. We could never keep an operator around long enough to make it
worthwhile. We had a double drum and a single drum. Mud pump. Power swivel. Power tongs on
both. Testing truck. The whole enchilada.
We sold them all to a man who had worked for someone else and then went out on his own. We
gave him a good deal, and he did a lot of work for us. He still does work for us, but he can't
find help that will stay.
We also owned a tank truck. Sold it also. It is currently parked, the man we sold it to
cannot find a driver. He is a one horse tank truck driver. He turns down work all the time. We
had to shut down a lease we haul water on for a few days when he got COVID. Thankfully he
recovered.
All of us around here just cannot quite believe what is going on with the oilfield labor
force. It is a perfect storm.
Meanwhile, most recently we paid $5.63 per foot for 2 3/8" steel tubing, which was under $3
a year ago. We priced a 115 fiberglass tank for $6,800, would have been $3,900 a year ago.
We had a couple wells down for a few weeks because we could neither get new nor rewound
motors for them.
The man who owns the backhoes, trackhoes and cranes that does contract work for us is in his
70's and has great grandkids. He works in the field daily beside his son and grandson.
One of the last rig hands we had broke into our shop last winter. He got out of jail after a
few weeks and immediately got a job in a local factory. Hope he stays clean. He was a good hand
when he was, and had learned to operate a single drum also.
The prosecutor in our county announced the first six months of 2021 that 162 felony cases
had been filed in our small county, that in 2019 the total for the year was 204 felonies, and
that 33 of the 34 jail inmates were addicted to meth.
We do have one pumper now under 50. The rest are from 51 to 63. REPLYINGRAHAMMARK7 IGNORED07/20/2021 at 1:34
am
How much land do you have left? At one well per section how many can you drill and how long
it takes? That's when your business wraps up. REPLYRASPUTIN IGNORED07/20/2021 at 2:40
am
Holy Moly SS
I guess the days of vertical doing things in house are gone. That labor mess is unreal.
However, here in nowhere USA it is hard to find good help but you can usually find help. I was
so surprised at some of the job turnover even during peak covid when some businesses were
restricted and some essential. How are people living that have no jobs? Over the years I hired
relatives that never got it, didn't stay sober and didn't see the long term upside. Maybe it's
all about today for the younger generation.
Over the past year and a half I've been following your posts including labor issues. Were
they so dreadful before covid and helicopter money? It might appear to the uninformed that
training rig help. pumpers and the like is easy, but it's not. One small oops for man is one
huge oops for you.
Perhaps, as we move away from the false narrative that you must have a college degree to get
a good or high paying job, things will improve in the trades and the oilfield.
About 20 years ago I was visiting with a substantial independent stimulation company that
was having labor issues. The head honcho lamented that they had already poached all of the
young guys that grew up on farms and knew machinery, getting up early and how to work. Having
known a few guys and what they earned they most likely didn't point their kids at basket
weaving degrees.
Sure wish I had an answer for you. Personally, I'm shrinking down to a few wells close to
the house/shop/yard, one of which I could walk to for daily exercise. However, I'll run my
equipment myself as long as possible.
The number of basically "homeless" people living here in my part of very rural USA is
startling. People aren't generally sleeping in the parks. They have duffle bags and backpacks
and crash place to place.
We have the tremendous labor shortage, yet the public defender and conflicts public defender
have over 400 clients combined. This in a county of a little less than 20K people. That right
there is the labor force for a decent sized factory around here.
To qualify for the PD you must have income below 125% of federal poverty guidelines, which
is very low. During the height of COVID, nothing got done with their cases because the PD's
couldn't get ahold of them. Few have cell phones that are permanent (track phones) and few have
permanent addresses. The jail is full so there aren't a lot of warrants being issued for the
lower level crimes. So people haven't been showing up for their court cases for months/ over a
year. Our county is going to send close to 100 people to prison this year, almost all for meth
delivery. This is the situation all over rural USA. People who live here and aren't in the
court system are oblivious to it until they get broken into or robbed (or have an addicted
relative, which many do).
The primary reason for the labor shortage here is a combination of young people moving to
larger towns/cities, a very large percentage of the working age population being addicted to
meth (which is now being cut with heroin, fentanyl, etc) and the significant benefits that have
been paid to not work. I hate to think of how many billions of borrowed money stimulus our
future generations are now indebted with that went directly into the pockets of the foreign
drug cartels.
As for the oilfield, add to that the hard work, not the greatest pay in the world at the
bottom end (rig hands) the need to find people who can work unsupervised outdoors, and the
young people being told the industry is dead and a job in that field will soon be gone.
Finally, a ton of "old timers" simply retired during COVID.
Our country has no idea how dependent we are on labor from Mexico and Central America that
keeps us alive. The only farm workers are Hispanic. However, most don't want to work in the
oilfield either, it seems. We just harvested green beans, and all the crew were Hispanic. The
same will be the case here shortly as we harvest watermelons and cabbage. If Trump were
successful and closed the borders and sent everyone back, we would starve.
The largest oil company here shut in everything it owned when oil went negative.
Unfortunately for them they laid off a lot of people. Many of their wells are still idle.
Maybe we are an outlier. But I doubt it. A decent amount people at the lower end of the
labor force seem to have decided they aren't going to work, and offering a lot more $$ won't
bring them back. Maybe they will come back when the government benefits end.
Even the prisons can't find employees. They pay $70K+ plus great benefits. Mentally
difficult work though. Also, can't have a criminal record and cannot use drugs, even pot.
Keep in mind a large percentage of the USA population now smokes or ingests pot. That
doesn't work well in a lot of industries where sobriety is mandatory.
The gas station I fill up at is offering a $300 signing bonus which is paid after 30 days of
no unexcused absences. $13 and hour to start at the cash register. They can't find people to
take that.
I'm rambling now, and I'll stop.
Surely there are some shale basin people reading this. Could any of you comment about
whether there is a labor shortage in your shale basin? If there isn't, maybe we could persuade
a few of them to come to our neck of the woods and work on the simple, shallow wells. Not a lot
of traveling, no weekends unless you pump, and work is daytime only. KANSAS OIL IGNORED07/20/2021 at 9:10
am
Shallow Sand –
I echo all of your sentiments. We are a small operator in Kansas, producing about 300
bbl/day in 13 various counties. We have approximately 50-60 bbl/day offline pushing 3 weeks.
We're talking 8/8ths approximately $75,000 in revenue. Pre-Covid you could count on getting a
pulling unit sometimes next day if you had a mechanical failure. Now it's 3-4 weeks. $20/hour
for green rig hands evidently isn't enough to move the needle, whether it's because the work is
too difficult, or it's easier to keep cashing the government checks. And by my count we are in
a similar situation with oil field pumpers. We have 13 of them. 2 are 50s, and the rest are all
over 60. I'm in my early 40s and my field superintendent is 56. He loves to work and will
probably do so until he's 70-75. When he checks out will probably be when I check out.
REPLYSHALLOW SAND IGNORED07/20/2021 at 9:55
am
Kansas Oil.
Great to hear from you.
Thanks for confirming what we are experiencing.
The big question is whether this is also going on in the shale basins, primarily Permian. If
it is, don't see how USA production grows much.
I drive across Kansas on both I 70 and the South Route through Wichita to the OK panhandle
quite a bit. Always keep my eyes open for whether pumping units are moving or not.
I worry about whether the huge feed lots, hog facilities and packing plants out there can
find enough help. People have no clue how much of the USA is fed from the TX, OK panhandles on
up through Western KS and NE.
Two years ago, Wall Street banks were on their way out of a long-term relationship with the
oil industry. Now, with oil prices over $70 for the first time in three years, big bond buyers
are snapping up oil bonds once again.
Only there is a condition this time.
The Wall Street Journal's Joe Wallace and Collin Eaton
wrote this week that Wall Street was buying bonds from non-investment-grade U.S. energy
companies, which took advantage of record low interest rates to raise some $34 billion in fresh
debt in the first half of the year.
That's twice as much as the industry raised over the same period last year. But investors
don't want borrowers to use the cash to drill new wells. They want them to use it to pay off
older debt and shore up balance sheets.
It makes sense, really, although it is a marked departure from how banks normally react to
oil industry crises. The 2014 oil price collapse, in hindsight, may have been the last "normal"
crisis. Oil prices fell, funding dried up, supply tightened, prices went up, banks were willing
to lend again, and producers poured the money into boosting production.
Since then, however, the energy transition push has really gathered pace and banks have more
than one reason to not be so willing to lend to the oil industry. With the world's biggest
asset managers setting up net-zero groups to effectively force their institutional clients to
reduce their carbon footprint and with the Biden administration throwing its weight behind the
push for lower emissions, banks really have little choice but to follow the current. Their own
shareholders are increasingly concerned about the environment, too.
https://www.youtube.com/embed/aQXqMVeoOPs
Yet business is business, and nowhere is this clearer than in banks' dealings with the oil
industry. Bank shareholders may be concerned about the environment, but they certainly would be
more concerned about their dividend""and part of that comes from income made from lending to
oil. And the higher oil prices go, the more willing banks will be to lend to those that produce
it.
When they were unwilling to lend to the oil industry, other lenders
stepped in . Last year, alternative investment firms scooped up hundreds of millions in oil
industry debt from banks that were cutting their exposure to the politically incorrect
industry. Hedge funds and other so-called shadow lenders don't seem to have banks' misgivings
about profiting from oil and gas.
Now banks have mellowed towards oil somewhat, but it is an interesting twist that the
current loans come with the condition of not boosting output. Again, it makes sense. For years,
the shareholders of U.S. shale oil companies have been complaining about poor returns as the
companies put everything into output growth. Now it's payback time, and shareholders want their
returns.
So do lenders, apparently.
Per the WSJ article, this year, bond buyers "want to see companies repairing their
balance sheets and delivering to creditors and shareholders rather than plowing money into new
wells."
No. Not true and badly misleading. Remaining EIA PDP from the Permian will not generate sufficient net cash flow to self fund
123,000 wells (your estimate) costing nearly $1T, much less do that AND pay down over $100 B of existing debt in the Permian. That's
using EIA PDP estimates; whack those by 30%. It is not possible to drill $9MM wells for a 135% ROI over 15 years and be financially
self-sufficient, service and pay down debt, provide returns to investors and maintain a 100% RRR. The US shale oil model does not
work without credit. $70 "assumptions" do NOT solve the issue of where the money is going to come from for your miracle of abundance
to actually occur. ANCIENTARCHER IGNORED07/05/2021 at 6:01 am
EIA is expecting excess supply in 2022.
Are they smoking some really good stuff to come up with this? I'd like to smoke that too
As I see it, demand will slowly go back up to previous level of 100mmbpd and then resume its slow march upwards. Where is it that
EIA are seeing that extra production from that will lead to oversupply 6-7 months down the line? All I see is that various regions
of the world are slowly declining in production due to a combination of worsening asset quality and a paucity of capex over the last
several years, especially in 2020/21. US Shale, Russia, Offshore, conventional onshore, small members of OPEC and even Saudi"¦ all
are experiencing pressure on production.
OPEC seems to be concerned about the possibility of excess supply next year, probably due to this report by EIA. The Saudis are
especially concerned and therefore are pushing to extend the supply cut to the end of 2022 which UAE is opposing.
So, am I missing a crucial element or are the EIA on to something here?
The U.S. is producing roughly 2 million barrels a day less than it was before the pandemic.
In the USA shale patch many "sweet spots" are now gone and what remains is less proficableto drill and thus requres higher prices.
In this sense the currentoil price might be not enough to spur additional activity.
Frackers have been forced to rein in spending and
live
within their means
after many investors lost faith in the companies following years of poor returns, lenders reduced their
credit lines and capital markets showed little interest in funding expansive new drilling campaigns.
The result is that shale drillers, which in the past have played the role of the oil world's swing producer by quickly increasing
output to meet demand, are largely standing pat for now, as the reopening of Western economies leads to a resurgence of global
oil
and
gas prices
.
The companies are raking in more cash than ever. Public shale companies that drill primarily for oil collectively generated a
record $4.1 billion in free cash flow in the first quarter of 2021 and are poised to take in almost $15 billion for the year if
prices remain higher, according to consulting firm Rystad Energy.
U.S. shale producers generated more free cash
flow in the first quarter than any time
in the
industry's history, analysts said.
Free
cash flow
Source:
Rystad Energy
billion
2014
'15
'16
'17
'18
'19
'20
'21
-12.5
-10.0
-7.5
-5.0
-2.5
0
.0
2.5
$5.0
But instead of pumping that money back into drilling as they have historically done, large producers such as
Occidental
Petroleum
Corp.
OXY
+2.09%
and
Ovintiv
Inc.,
the
company formerly known as Encana Corp., have said they plan to
focus
on reducing debt
, keeping U.S. output flat. Other sizable shale drillers such as
Pioneer
Natural Resources
Co.
PXD
+0.66%
and
Devon
Energy
Corp.
DVN
+3.40%
are
socking away money to return to investors in the form of variable dividends, one of the enticements they want to use to lure more
investors back.
"We're producing all this free cash flow, but it's not going out to investors yet," said Scott Sheffield, chief executive of
Pioneer, noting that many companies are focusing on debt before they return cash to investors. "There's no reason for them to buy
into this sector at this point in time."
... ... ...
In the heyday of the shale boom, publicly traded oil producers typically reinvested more than 100% of the cash flow they made
from operations back into drilling campaigns. Now they are using about half of the income they generate on new drilling and are
only growing output slightly, if at all.
... ... ...
Shale companies had about $148.6 billion in debt coming into the year, according to energy consulting firm Wood Mackenzie, and
much of the cash they are collecting is going toward that debt pile. Securing new capital is increasingly difficult for many.
Many large U.S. banks have cut their energy lending, and some European ones such as
Deutsche
Bank
AG
and
Société
Générale
SA
SCGLY
5.48%
have
exited fossil fuel financing altogether...
Callon said it would cut its 2021 capital expenditures to $430 million, a 12% reduction from its 2020 budget. In 2019, it spent
$515 million. As a result, the company said it would produce about 90,000 barrels of oil and gas a day in 2021, down from more
than 101,000 barrels a day in 2020. Callon said it is focused on reducing its roughly $3 billion in debt. The company declined to
comment.
Many frackers made bad bets early this year, hedging their production with oil in the forties and low fifties -
especially Pioneer and Devon. This article, for some reason, fails to mention that fact and it's impact on their
current production.
PAUL HUNT
After 38years in O&G E&P I filtered out of the industry due to changing industry. The loss of expertise and technology
in the energy industry over the last 5 years has been huge. USA has given the energy industry to China. Look for
overall energy prices to triple in less than 10 years.
DAVID LAWRENCE
What is left out in this article are the returns of the 600lb gorilla of frackers in the room.
XOM alone generated almost $7 billion in free cash flow last quarter. With oil prices where they are that figure is
likely to rise to $10 billion next quarter. The company has only $53 billion in debt outstanding having already pared
down $6 billion during the pandemic.
They are going to gobble up even more weaker little guys shortly.
Peter Sullivan
I don't see XOM significantly increasing production in US shale anytime soon. They are focusing CAPEX on deepwater
assets that present a better ROI than shale. Who would of thought we have reached a time where it is less risky for a
US based company to drill in a small South American country than within our own borders?
DAVID LAWRENCE
XOM CAPEX is greatly reduced (1/2) in 2021 across the board. This is because they spent nearly $20 billion in 2020 using
piles of borrowed money that so many junior analysts obsessed over.. The plan is to pay that pile down with the
windfall those investments are generating.
XOM is far from a pure play fracker and have always developed the largest offshore assets of any company and Guyana is a
hot prospect!
Edward Cotterell
The oil market has always been boom and bust. When the pandemic hit people stopped driving and the oil market went
bust. Prices fell and drillers went bankrupt. Now the economy is reviving, people are driving again and oil is
booming. To those who think otherwise, get a grip. The price of gasoline today is about where it was in 2018 and 2019
pre-pandemic. You know, when Trump was president.
This article points out a longer term change in the market. The hype over fracking is over. The lenders want their
principal back plus interest and they are not taking exaggerations from drillers any more. So oil prices may have to go
a bit higher until the lenders are satisfied that they will get their money. Then they will lend to drillers and
fracking will crank up.
Trash that 12 mpg pickup. Get a vehicle that gets better mileage. Some hybrids get over 50 miles a gallon. Electrics
get the energy equivalent of 100 miles a gallon.
Ben Griffith
How is the electricity produced ? Coal, oil, natural gas produced by fracking, nuclear, hydroelectric dam, harnessing
the hot air of Climate Change speech ?
ROBERT STUPP
Many don't realize how many older, experienced energy professionals took retirement over the last few years. Similar to
the 1980's energy bloodbath, it will take a while to establish teams able to stabilize the companies, let alone grow
them from survival mode. You can't turn on production like your kitchen faucet.
Jerome Abernathy
Fracking wells deplete so fast that the capex expenditures needed to maintain and grow production result in a low ROI
for the industry. Worse yet, given the volatility of oil prices and the precarious state of their balance sheets,
frackers are unattractive borrowers. The industry needs a new, creative financing model.
Matthew Oatway
An interesting article, but the authors should have acknowledged (a) the impact of consolidation in the sector on
production discipline and (b) the fact that many shale producers have a large portion of their production hedged at
lower crude prices. Both factors point to a more restrained return to production growth that we have seen in the past.
Banks have started to cut their exposure to the U.S. shale patch, seeing more than 100
producers and oilfield services firms go bust last year and feeling the environmental, social,
and governance (ESG) pressure to reduce credits to fossil fuels. While traditional lenders are
cutting their losses and de-risking energy loan portfolios, alternative capital providers are
stepping up to scoop up U.S. energy debt at a discount and take part in debt or equity
transactions that could give them returns sooner than a loan would for a bank.
Since the oil price crash in 2020 and the downturn in the U.S. shale industry, banks have
been wary of their exposure to the sector. The commodity price slump last year dramatically cut
the value of the assets of oil and gas firms, against which they have traditionally obtained
loans from banks.
Running for the Exit
Lenders slashed the amounts of reserve-based loans to the U.S. shale firms in the middle
of last year.
But it is not only purely financial considerations that are driving reduced bank exposure
to the oil and gas industry. ESG lending and aligning loan portfolios to the Paris Agreement
goals are now more prominent than ever.
For example, asset manager Schroders, which holds many bonds in the banking sector, is
engaging with banks to understand their fossil fuel exposure.
"Banks that are highly exposed to the fossil fuel industry face significant financial,
regulatory and reputational risks as a result of the transition to a low-carbon economy,"
Schroders said, explaining its rationale to identify the exposure of the banks to oil, gas, and
coal.
Increased pressure from the ESG universe, coupled with years of poor returns of U.S.
shale firms, have prompted several major transactions in which banks have sold energy debt to
hedge funds and private equity firms.
Hancock Whitney, for example, agreed last year to sell $497 million worth of energy loans
to certain funds and accounts managed by alternative investment provider Oaktree Capital
Management. Hancock Whitney expected to receive $257.5 million from the sale of the
reserve-based loans (RBL), midstream, and non-drilling service credits.
Hancock Whitney's main reason to sell the energy loans was to minimize the risks to its
loan portfolio.
"The primary objective of this sale is to continue de-risking our loan portfolio by
accelerating the disposition of assets that have been impacted by ongoing issues within the
energy industry, and have now been further complicated by COVID-19," Hancock Whitney's
President and CEO John M. Hairston said.
At the end of 2020, Bank of Montreal decided it would wind down its non-Canadian
investment and corporate banking energy business.
Most recently, ABN AMRO announced last week it would sell a $1.5 billion portfolio of
energy loans to funds managed by Oaktree Capital Management and affiliates of Sixth Street
Partners. The portfolio consists of loans to around 75 companies active in the North American
energy markets.
With this sale, ABN AMRO is withdrawing from oil and gas related lending in North America
as part of a process to wind down its non-core activities and significantly reducing the
non-core loan book.
"On a daily basis, loadings will decline by 22% in July compared to the current month,
Reuters calculations showed."
REPLYPOLLUX IGNORED06/28/2021
at 1:37 pm
"Russian oil production has declined so far in June from average levels in May despite a
price rally in oil market and OPEC+ output cuts easing, two sources familiar with the data told
Reuters on Monday.
Russia's compliance with the OPEC+ oil output deal was at close to 100% in May, which
means the state is about to exceed its target in June.
Two industry sources said that lower output levels may be due to technical issues some
Russian oil producers are experiencing with output at older oilfields."RON PATTERSON IGNORED
06/28/2021 at 2:38 pm
Yes, they are definitely experiencing issues with their older oilfields, it's called
depletion. But that decline is only 33,000 bpd or .3%. But your post above that one says
exports in the third quarter will decline by 22%. What gives there?
I just checked the Russia site and they have revised up their original May estimate. It is
one week later than the original. Production is now down 9,000 b/d. RON PATTERSON IGNORED06/28/2021
at 4:50 pm
Yeah, they revised it up by 14,000 pbd. A pittance. Now they are down only 9,000 bpd instead
of 23,000. Nothing to get excited about. Basically, they were flat in May.
JEAN-FRANÇOIS FLEURY IGNORED06/28/2021
at 4:09 pm
"Russia plans to decrease oil loadings from its Western ports to 6.22 million tonnes for
July compared to 7.75 million tonnes planned for loading in June, the preliminary schedule
showed." 7,75 x 10^6 – 6,62 x 10^6 = 1130000 t. 1130000×7,3/30 = 274966 b/d.
Therefore, these decrease of oil export suggests a decrease of production of 274966 b/d.
Precedently, it was announced that oil exports of Russia would decrease of 7,2 % for the period
July-September or a decrease of 308222 b/d. Therefore, it's coherent.
https://www.zawya.com/mena/en/markets/story/Russias_quarterly_crude_oil_exports_to_drop_72_schedule-TR20210617nL5N2NY2IQX8/?fbclid=IwAR0ZjvwzjVS427CbUAzTL1vJfqog7R8CDwaJAvI3uUdaw_0z5S5l_57SGFY
I notice that it concerns the "Western ports", therefore the exports toward EU and USA. Well,
EU is also the main customer of Russia with 59% of the oil exports of Russia. RON PATTERSON IGNORED
06/28/2021 at 4:59 pm
Western Syberia is where all the very old supergiant fields are. They produce 60% of Russian
crude oil. Or at least they used to. LIGHTSOUT IGNORED06/29/2021
at 2:11 am
Ron
If one of the West Siberian giants is rolling over in the same way as Daquing did, things could
get very interesting very quickly. RON
PATTERSON IGNORED06/29/2021
at 7:24 am
Four of Russia's five giant fields are in Western Siberia. The fifth is in the Urals, on the
European side. All five have been creamed with infill horizontal drilling for almost 20 years.
All five are on the verge of a steep decline. Obviously, one and possibly more have already hit
that point.
This linked article below is 18 months old but there is a chart here that shows where
Russia's oil is coming from. Notice only a tiny part is coming from Eastern Siberia, the hope
for Russia's oil future. Those hopes are fading fast.
As I have written a few months ago: When you reduce output voluntarily for a longer time,
all the nickel nursers from accounting and controlling will cut you any investing in over
capacity you can't use at the moment. That works like this in any industry.
So you have to drill these additional infills and extensions after the cut is liftet. And
this will take time, while fighting against the ever lasting decline.
"Abu Dhabi's state-owned Adnoc has informed customers that it will implement cuts of
around 15pc to client nominations of all its crude exports loading in September, even as the
Opec+ coalition considers further relaxing production quotas.
It was unclear why Adnoc is deepening reductions for its September-loading term crude
exports, with the decision coming ahead of the next meeting of Opec+ ministers scheduled for 1
July when the group is expected to decide on its production strategy for at least one
month"
As oil price stays above $70/barrel, most shale will come back. However the max reached by
USA was 13,100 million b/d. So whether World will hit 75 million b/d is doubtful. But NGL keeps
increasing because of increase in natgas output. Besides nearly 6 million b/d that comes from
CTL, GTL and bio-fuels will keep overall oil consumption above 100 million b/d.
Despite rapid increase in electric vehicles, oil will hold above 100 minion b/d mark.
REPLYHOLE IN HEAD IGNORED06/20/2021
at 1:34 pm
Ted , demand is governed by price and availability . Demand of 100 mbpd is immaterial if the
supply is only 80mbpd . Shale is not coming back . USA has peaked . Period . The peak in shale
was (is) the peak of oil production in USA . I have commented earlier that " all liquids " is
BS . The 6mbpd of NGPL ,CTL , GTL etc. are just " fill in the blanks " . These are not
transportation fuels and have 65% of the BTU of crude . HICKORY IGNORED 06/20/2021
at 2:30 pm
Hole- Hydrocarbon Gas Liquids are nothing to belittle. It is a lot of energy-
"HGLs accounted for over a quarter of total U.S. petroleum products output in 2018"
NGL has about 70% of the energy content of a barrel of crude. In addition most uses for HGLs
are not for transportation which is the the main use for crude plus condensate.
As Ron has said we don't count bottled gas. I would say NGL should be put in a basket with
natural gas.
Or we could define liquid petroleum as that which is a liquid at 1 atmosphere pressure and
25C aka STP.
By that standard only pentanes plus would qualify, which makes sense as it is essentially
condensate, the proportion of pentanes plus in the US NGL mix is less than 12% by volume, 2020
data (582
kbpd). RON PATTERSON IGNORED06/21/2021
at 4:01 pm
I am expecting prices a lot higher in 2022. An average of $85 would not shock me at all.
They will be higher because oil production will not fully recover to the 2019 level as everyone
expects it to.
The EIA Short Term Outlook has production fully recovered by the end of 2022 and total
liquids about one million barrels per day higher for non-OPEC.
OPEC officials heard from industry experts that US oil output growth will likely remain
limited in 2021 despite rising prices,
While there was general agreement on limited US supply growth this year, an industry source
said for 2022 forecasts ranged from growth of 500,000 bpd to 1.3 million bpd
The forecasts for 2021 were for average output to be close to 200 kb/d. The 1.3 Mb/d
prediction for 2022 is out to lunch. The 500 kb/d has a chance but I think the average will be
closer to 350 kb/d.
I think WTI will be $85 plus/minus $5 in mid 2022. This will push the average price of
gasoline slightly above $3/gal. As for output, the US will add somewhere close to 300 kb/d
average in 2022 over 2021. I am betting on some restraint on the part of the drillers. The
Permian is the pivotal basin and I see that the early results for 2021 wells are not as good as
2020.
The big unknown for me is: What is a sustainable price for WTI, $100? At what point does
gasoline suck too much money out of the economy. Once the economy starts to slow, oil demand
will slow. We can all remember 2008.
If WTI crosses $90, OPEC might start to worry. However will they have the spare capacity to
try to control it? Six months from now we can revise our estimates.
What do you mean by confirmation? Do you mean they will confirm that the peak was 2018-2019?
If so, I cannot agree. No, there will be deniers all the way down. There is something about the
human psyche that just cannot accept reality... MATT MUSHALIK IGNORED06/19/2021
at 8:57 pm
Thanks for continuing to monitor crude oil production. As of now, we are back to 2005
levels!
Frac Sand Baroness @sand_frac · Jun 16 There is
currently a @chevron well
uncontrollably blowing out on my land that I live and raise cattle on in West Texas. It is
injecting super concentrated brine and benzene into my water supply. The casing (metal pipe) is
so corroded that Chevron literally cannot re plug it. 5.7K views 0:01 / 0:06 3 60 117
Frac Sand Baroness @sand_frac
· Jun 16 More concerningly, this
well was plugged and abandoned (P&A) in 1995. For those not in the oil industry, a P&A
blowout is extremely rare. A plugged well is exactly that: plugged. It is filled with concrete
plugs, and considered to be permanently deactivated and safe. 2 7 67 Frac Sand Baroness @sand_frac · Jun 16 We've had
issues with Chevron before. In 2002, we flushed a toilet at the ranch house (approximately 1.5
miles south of the blowout) and crude oil bubbled up. The leak source was never fully
identified, and we shut in that water well. 2 6 66 Frac Sand Baroness @sand_frac · Jun 16 Chevron had
operations nearby, so drilled water monitoring wells. These monitoring wells identified a crude
oil plume in the groundwater, and also found a large salt water plume. See Texas Railroad
Commission OCP #08-2423. Again, we never found the source. 1 5 57 Frac Sand Baroness @sand_frac · Jun 16 This
required Chevron to provide an annual water test result to the landowners (me). Of course, they
didn't comply from 2007 through 2013. We never heard about this, and thought our water was safe
again.
One of the biggest pieces of news for Royal Dutch Shell recently has been the Dutch court
ruling that forces them to make a larger 45% emissions reduction by 2030.
Despite this sounding very transformation, considering the geological and economic
reality of their current situation, it actually does not significantly change their underlying
future.
Their reserve life is only sitting at just above seven years and thus even if they wished
to maintain their fossil fuel production, they already required significant investments before
2030.
SNIP You Cannot Fight Geology
Upon reviewing their reserves, it may initially sound very impressive to hear that their
oil and gas reserves currently stand at slightly over nine billion barrels of oil equivalent.
Although in reality this actually sits rather low when compared to their annual production
during 2020 of 1.239b barrels of oil equivalent. This effectively only leaves their reserve
life at just above seven years, which is not particularly long and thus means that their fossil
fuel production would already begin shrinking dramatically by the latter half of this decade.
Admittedly they would likely continue replacing a portion of their oil and gas reserves in the
future but their current production rate would still see them running very low by 2030 if
approximately half were replaced per annum, as the graph included below displays.
There are two charts in this article. The second on titled: Oil Discoveries Lowest Since
1847 is alarming. STEPHEN HREN IGNORED06/17/2021 at 8:25 am
Hi Ron, any thoughts on why Shell would bag their operations in the Permian while they are
also running low on reserves everywhere else? Seems like they would be holding on to every
scrap of producing land they could. Unless one of two things: 1) they are making a serious
attempt to transition to a low carbon energy company; and/or 2) their holdings in the Permian
are worth squat REPLYRON PATTERSON IGNORED06/17/2021 at
9:22 am
NEW YORK/HOUSTON, June 15 (Reuters) – A cadre of oil companies, seeing continued
profits in shale, are mulling Royal Dutch Shell's (RDSa.L) holdings in the largest U.S. oil
field as the European giant considers an exit from the Permian Basin, according to market
experts.
The potential sale of Shell's Permian holdings, located in Texas, would be a litmus test
of whether rivals are willing to bet on shale's profitability through the energy transition to
reduce carbon emissions.
Shell would follow in the footsteps of other producers, including Equinor (EQNR.OL)
and Occidental Petroleum (OXY.N) that have shed shale assets this year, looking to cut debt and
reduce carbon output in the face of investor pressure.
Shell, like a lot of other companies, sees shale assets as a very low profit, or even a
losing proposition. They can take the money from the sale, reduce their debt, and reduce carbon
emissions of their company in one fell swoop. More from the article:
Against this backdrop, estimates for Shell's acreage run from $7 billion to over $10
billion, the latter implying a valuation of almost $40,000 an acre.
That would be in line with the per-acre price Pioneer Natural Resources (PXD.N) paid for
DoublePoint Energy in April, the most costly deal since a 2014-2016 rush by producers to grab
positions in the Permian.
Most Permian deals this year have closed between $7,000 and $12,000 per acre, said
Andrew Dittmar, senior mergers and acquisitions analyst at data provider Enverus.
If they can get $40,000 per acre they have found a greater fool to offload their acreage on.
HICKORY IGNORED06/17/2021 at 9:44 am
Something about that doesn't make sense. The need or desire to downsize is likely due to an
inability to project making profit on the shale assets rather than any concern over a carbon
footprint- I don't believe they are in business to win any kind of beauty contest. REPLYROGER
IGNORED06/17/2021 at 8:17 pm
"Shell's position as a major European enterprise has become untenable. The Spar had gained a
symbolic significance out of all proportion to its environmental effect. In consequence, Shell
companies were faced with increasingly intense public criticism, mostly in Continental northern
Europe. Many politicians and ministers were openly hostile and several called for consumer
boycotts. There was violence against Shell service stations, accompanied by threats to Shell
staff."
Things are a little different for European companies I recall "Greenpeace sympathizers"
fire-bombed a gas station back then; in light of what has transpired in the US recently who is
to say it couldn't happen again?
Shell is well aware of peak oil, and can't solve the problem. So, what would you have them
do? REPLYKOLBEINIH IGNORED06/17/2021 at 1:26 pm
"Shell would follow in the footsteps of other producers, including Equinor (EQNR.OL) and
Occidental Petroleum (OXY.N) that have shed shale assets this year, looking to cut debt and
reduce carbon output in the face of investor pressure."
I don't think it has anything to do with shale oil specifically. For Equinor it has to do
with that it can draw on competence in Norway in the harsh offshore environment in the North
Sea. Floating offshore wind power is where Equinor is world leading with technology and know
how; now about to be utilised in the North Sea, Japan, US East coast and California. It is not
more economical than ground based offshore wind mills, but has some advantages when it comes to
lifecycle costs. For one, the wind mills can be placed in optimal wind condition areas not in
the way of fishing resources. The big size of wind mills will not cause problems (the height
and diameter of the blades are necessary to capture enough wind energy). And also the wind
mills can be more easily moved to land and recycled, e.g. the steel. Wear and tear offshore is
on the minus side.
Usually the blades are made of carbon fiber to make it lighter, but it can also be made of
aluminum in the future with lower efficiency.
Shell is just now investing in North Sea South II in Norway for ground based offshore mill
farms together with BP. To make the North Sea work with the enormous amount of wind power
coming online and connection cables everywhere is very serious business and just a priority.
Shale oil is too much of a distraction for Shell and Equinor, not even within their core
competence area. REPLYJAY
WOODS IGNORED06/18/2021 at 7:50 am
Shell was ordered by a Dutch court to cut by 45%. Of course, they will cut their "losers"
first.
The chart is old and was published in 2016 by Wood Mackenzie and there is no data for 2016.
It also leaves out the discovery of Ghawar in 1948, first bar/spike. I have not seen any
updates since then. Not sure if Guyana had been discovered in 2016. The original is
attached.
Ironically, the wave of ESG investing in global energy markets may lead to much higher
oil prices as a serious lack of capital expenditure on new fossil fuels dries up just as demand
for crude continues to grow
Pressure from investors, tighter emissions regulation from governments, and public
protests against their business have become more or less the new normal for oil companies. What
the world -- or at least the most affluent parts of it -- seem to want from the oil industry is
to stop being the oil industry.
Many investors are buying into this pressure. ESG investing is all the rage, and
sustainable ETFs are popping up like mushrooms after a rain. But some investors are taking a
different approach. They are betting on oil. Because what many in the pressure camp seem to
underestimate is the fact that the supply of oil is not the only element of the oil
equation.
"Imagine Shell decided to stop selling petrol and diesel today," the supermajor's CEO Ben
van Beurden wrote in a LinkedIn post earlier this month. "This would certainly cut Shell's
carbon emissions. But it would not help the world one bit. Demand for fuel would not change.
People would fill up their cars and delivery trucks at other service stations."
Van Beurden was commenting on a Dutch court's ruling that environmentalists hailed as a
landmark decision, ordering Shell to reduce its emissions footprint by 45 percent from 2019
levels by 2030.
Total DUCs in shale basins are falling at the rate of about 250 per month. I don't know how long this can continue. I have been
told by some experts in the field that there are some DUCs that will never be completed because they would not produce enough oil
to pay the completion cost. So we just cannot count the DUCs and divide by 250. The decline in DUCs will have to stop sooner or
later.
Frugal, I am not an oilman, and an oilman could obviously give a better answer than I. But I will give it a shot, and hopefully,
I will be corrected for any mistakes I make.
Drillers are not frackers and frackers are not drillers. That is an entirely different operation requiring different crews, different
equipment, and different CAPEX. But the driller leaves behind samples from the well, indicating just how productive the well should
be. The best wells will obviously be fracked first. The less promising wells will be left for times when the price is high enough
to justify the fracking cost.
But"¦. the total cost of the well is the drilling cost plus the fracking cost. And in a DUC, the drilling cost has already been
spent. So when times get hard, and you can get a well, though it might not be the best well, you have already paid the drilling
cost, so you can get it for only the fracking cost now. So you pay the fracking cost and recover what you can. And this would
be the case especially if the new wells that are coming in are less promising than the poor wells already drilled.
But then, that's just my opinion, for what it's worth.
Exxon Mobil Corporation XOM has been generating fewer barrels of oil from the prolific
shale fields of the United States since 2019, per Reuters.
According to a latest report, the company's oil wells, which are involved in some of the
most promising shale fields, produced fewer barrels of oil per well despite an increase in
overall expenditure and production.
In 2017, Exxon, which is one of the largest shale oil producers, acquired $6.6 billion of
net acres in New Mexico, which doubled the company's assets in the Permian basin that spans
west Texas and New Mexico. Notably, the company intends to boost shale output in the New Mexico
portion of the Permian basin to 700,000 barrels per day (bpd) by 2025.
Per data released by the Institute for Energy Economics and Financial Analysis ("IEEFA"),
Exxon's average liquid output for the first 12 months of a well dropped to 521 bpd in 2019
from an average of 635 bpd in 2018 in its Delaware basin assets of New Mexico.
That's an 18% drop in production per well. And this was before the pandemic
Another scenario is that some exporting nations realize they will need this oil as the world
stares into a scarcity of oil. They might say: "Shit, why are we selling this stuff when we
will desperately need it for ourselves in a few years?" And as they cut back, or stop exporting
altogether, the problem gets a lot worse, and prices spike even higher. REPLYDOUG LEIGHTON IGNORED06/13/2021 at 3:34 pm
L.O.L. The decision concerning the proportion of a domestic resource that should be
preserved for domestic needs, and how much to export, is interesting. China's REE deposits come
to mind. Also, the impact of the immediate use of a resource versus a lower level of
exploitation over time might come into play in some (perhaps unrealistic) scenarios as well.
Not many examples of countries that have exhaustible natural resources saving some for future
generations I'm aware of; probably would result in an unwelcome war or another ugly result!
John Kilduff of Again Capital has predicted Brent to hit $80 a barrel and WTI to trade
between $75 and $80 in the summer, thanks to robust gasoline demand. Brent is currently trading
at $71.63 per barrel, while WTI is changing hands at $69.13.
On 05/07/21 the US 10year chart formed a hammer candlestick on daily chart within a consolidation pattern. Which suggested higher
yields coming. Well little over a month later price broke below the bottom of that candlestick which suggest that the bond market
doesn't believe the inflation we have seen is here to stay. Yield headed lower.
The inflation we have had seems to be supply side due to covid. If inflation is at peak which bond market is suggesting. Oil price
might not have much more room to run higher. And I'd take it a step further and say price inflation due to a weaker dollar is starting
to real hurt places like China and they are going to act by tightening monetary policy. You think this would be positive for the
yuan and push the dollar even lower. But when you tightening monetary policy credit contracts and economic activity contracts.
I do expect oil price to rollover and head back to $50-$55 might happen from a slightly higher price from here because of lag
time between when bond market signals rollover in inflation back into deflation and when prices start reacting to this.
REPLYEULENSPIEGEL IGNORED06/11/2021
at 10:07 am
This isn't your history bond market.
Inflation doesn't really matters, what only matters is the one big question: "How much bonds does the one market member with unlimited
funds buy?".
And the time the FED was able to rise more than .25% is in the rear mirror "" when they hike now, inflation or not, all these
zombie companies and zombie banks will fail and no lawyer in the world will be able to clean up the chaos after all these insolvency
filings.
They have to talk the way out of this inflation. They have to talk until it stops, or longer. They can't hike. They can perhaps
hike again when most of the debt is inflated away "" a period with 10+% inflation and 1% bond interrest.
And yes, they can buy litterally any bond dumped onto the market "" shown this in March last year when they stopped the corona
crash in an action of one week.
I think most non-investment-banks are zombies at the moment, and more than 20% of all companies. They all will fail in less than
1 year when we would have realistic interrest rates. On the dirty end, this would mean 10%+ for all this junk out there "" even mighty
EXXON will be downgraded to B fast.
In old times the FED rates would be more than 5% now with these inflation numbers. Nobody can pay this these days.
And now in the USA "" look for how much social justice and social security laws you'll get. The FED has to provide cover for all
of them.
We in Europe will do this, too. New green deal, new CO2 taxes, better social security "" the ECB already has said they will swallow
everything dumped on the market.
So, oil 100$ the next years "" but some kind of strange dollars buying less then they used to.
This is nonsense. They have Brent crude oil prices peaking, so far, in March 2025 at $164.11. And they have WTI peaking the same
month at $132.55, $32.56 lower. There is no way the spread could be that large. Also, they have natural gas prices dropping over
the same period. Just who the hell are these "Longforcast.com" people?
Disregard anything with "forecast" in the title. They don't have a time machine, and extrapolation is a horrible metric with dynamic
markets as complex as the energy ones.
Might as well show me the tea leaves or goat entrails and tell me the price on 11 June 2027.
REPLYSHALLOW SAND IGNORED06/11/2021
at 3:58 pm
Dennis Gartman is still considered a commodities expert.
He infamously said in 2016 that WTI would never be above $44 again in his lifetime. He is still alive last I knew.
Since I have owned working interests in oil wells (1997) I have sold oil for a low of $8 and a high of $140 per barrel. 6/14 oil
sold for $99.25 per barrel. 4/20 oil sold for $15.40 per barrel.
Predicting oil prices is impossible.
About the only oil price prediction I have had right so far is that if Biden won, oil prices would rebound. Of course, we can
argue about why that is, and if there is even any connection.
There are still no drilling rigs running in the field we operate in. There are still hundreds of production wells shut in. There
are still less than 10 workover rigs running in our field. The largest operator still has a help wanted sign up in front of its office.
We finally found one summer worker, he is still in high school, but thankfully covered by our workers comp. He cannot drive our trucks,
and is limited to painting, mowing, weed control, digging with a shovel, cleaning the shops and pump houses and other tasks like
those. That's ok, because we need that, but not being able to drive is a pain. But auto ins won't allow anyone under 21 to be covered.
REPLYIRON MIKE IGNORED06/11/2021
at 11:53 am
Yea Ron i agree with Kleiber, I wouldn't take anything on that site too seriously.
REPLYOVI IGNORED06/11/2021
at 1:34 pm
The IEA is now starting to sound warnings about supply. Last week they were telling the oil companies to stop exploring and to
move toward a renewable energy future.
IEA: OPEC needs to increase supply to keep global oil markets adequately supplied
In its monthly oil report, the International Energy Agency (IEA) has said that global oil demand is set to return to pre-pandemic
levels by the end of 2022, rising by 5.4 million bpd in 2021 and by a further 3.1 million bpd next year. The OECD accounts for 1.3
million bpd of 2022 growth while non-OECD countries contribute 1.8 million bpd. Jet and kerosene demand will see the largest increase
( 1.5 million bpd year-on-year), followed by gasoline ( 660 000 bpd year-on-year) and gasoil/diesel ( 520 000 bpd year-on-year).
World oil supply is expected to grow at a faster rate in 2022, with the US driving gains of 1.6 million bpd from producers outside
the OPEC alliance. That leaves room for OPEC to boost crude oil production by 1.4 million bpd above its July 2021-March 2022 target
to meet demand growth. In 2021, oil output from non-OPEC is set to rise 710 000 bpd, while total oil supply from OPEC could increase
by 800 000 bpd if the bloc sticks with its existing policy.
(IEA) has said that global oil demand is set to return to pre-pandemic levels by the end of 2022, rising by 5.4 million bpd
in 2021 and by a further 3.1 million bpd next year.
That comes to about 500,000 barrels per day monthly increase, every month until the end of 2022. I really don't believe that is
going to happen. No doubt most nations can increase production somewhat, but returning to pre-pandemic levels will be a herculean
task for most of them.
WTI Punched a $70 ticket sometime after 6:00 PM EST, June 6, 2021. The last time this
happened was Oct 16, 2018, $71.92 before falling below $70 the next day.
"Igor Sechin, the head of Russian oil major Rosneft (ROSN.MM), said on Saturday the world
was facing an acute oil shortage in the long-term due to underinvestment amid a drive for
alternative energy, while demand for oil continued to rise."
Exxon Mobil Corp. is
pulling out of a deep-water oil prospect in Ghana just two years after the west African nation
ratified an
exploration and production agreement with the U.S. oil titan.
The company relinquished the entirety of its stake in the Deepwater Cape Three Points block
and resigned as its operator after fulfilling its contractual obligations during the initial
exploration period, according to a letter to Ghana's government seen by Bloomberg and people
familiar with the matter, who asked not to be named because the information isn't
public.
Energy giant BP Plc
sees a strong recovery in global crude demand and expects it to last for some time, with U.S.
shale production being kept in check, according to Chief Executive Officer Bernard Looney.
"There is a lot of evidence that suggests that demand will be strong, and the
shale seems to be remaining disciplined," Looney told Bloomberg News in St. Petersburg,
Russia. "I think that the situation we're in at the moment could last like this for a
while."
Defeats in the courtroom and boardroom mean Royal Dutch Shell (RDSa.L) , ExxonMobil (XOM.N) and Chevron (CVX.N) are all under pressure to cut carbon
emissions faster. That's good news for the likes of Saudi Arabia's national oil company Saudi
Aramco (2222.SE) , Abu
Dhabi National Oil Co, and Russia's Gazprom (GAZP.MM) and Rosneft (ROSN.MM) .
It means more business for them and the Saudi-led Organization of the Petroleum Exporting
Countries (OPEC).
"Oil and gas demand is far from peaking and supplies will be needed, but
international oil companies will not be allowed to invest in this environment, meaning
national oil companies have to step in," said Amrita Sen from consultancy Energy Aspects.
... ... ...
Climate activists scored a major victory with a Dutch court ruling requiring Shell to drastically cut emissions, which in
effect means cutting oil and gas output. The company will appeal.
The same day, the top two U.S. oil companies, Exxon Mobil and Chevron, both lost battles with shareholders who accused them
of dragging their feet on climate change.
...Western oil majors control around 15% of global output, while OPEC and Russia have a share of around 40 percent. That
share has been relatively stable in recent decades as rising demand was met with new producers like smaller private U.S. shale
firms, which face similar climate-related pressures.
...Despite pressure from activists, investors and banks to cut emissions, Western oil majors are also tasked with maintaining
high dividends amid heavy debts. Dividends from oil companies represent significant contributions to pension funds.
"This time is different" may be the most dangerous words in business: billions of dollars
have been lost betting that history won't repeat itself. And yet now, in the oil world, it
looks like this time really will be.
For the first time in decades, oil companies aren't rushing to increase production to
chase rising oil prices as Brent crude approaches $70. Even in the Permian, the prolific shale
basin at the center of the U.S. energy boom, drillers are resisting their traditional
boom-and-bust cycle of spending.
The oil industry is on the ropes, constrained by Wall Street investors demanding that
companies spend less on drilling and instead return more money to shareholders, and climate
change activists pushing against fossil fuels. Exxon Mobil Corp. is paradigmatic of the
trend, after its humiliating defeat at the hands of a tiny activist elbowing itself onto the
board.
And what they don't realize is that the two largest producers in OPEC+, Russia and Saudi
Arabia, are on the ropes also. Russia has admitted it but Saudi is still trying to deny the
fact.
"This time is different" may be the most dangerous words in business: billions of dollars
have been lost betting that history won't repeat itself. And yet now, in the oil world, it
looks like this time really will be.
For the first time in decades, oil companies aren't rushing to increase production to chase
rising oil prices as Brent crude approaches $70. Even in the Permian, the prolific shale basin
at the center of the U.S. energy boom, drillers are resisting their traditional boom-and-bust
cycle of spending.
The oil industry is on the ropes, constrained by Wall Street investors demanding that
companies spend less on drilling and instead return more money to shareholders, and climate
change activists pushing against fossil fuels. Exxon Mobil Corp. is paradigmatic of the trend,
after its humiliating defeat at the hands of a tiny activist elbowing itself onto the
board.
The dramatic events in the industry last week only add to what is emerging as an opportunity
for the producers of OPEC+, giving the coalition led by Saudi Arabia and Russia more room for
maneuver to bring back their own production. As non-OPEC output fails to rebound as fast as
many expected -- or feared based on past experience -- the cartel is likely to continue adding
more supply when it meets on June 1.
'Criminalization'
Shareholders are asking Exxon to drill less and focus on returning money to investors. "They
have been throwing money down the drill hole like crazy," Christopher Ailman, chief investment
officer for CalSTRS. "We really saw that company just heading down the hole, not surviving into
the future, unless they change and adapt. And now they have to."
Exxon is unlikely to be alone. Royal Dutch Shell Plc lost a landmark legal battle last week
when a Dutch court told it to cut emissions significantly by 2030 -- something that would
require less oil production. Many in the industry fear a wave of lawsuits elsewhere, with
western oil majors more immediate targets than the state-owned oil companies that make up much
of OPEC production.
"We see a shift from stigmatization toward criminalization of investing in higher oil
production," said Bob McNally, president of consultant Rapidan Energy Group and a former White
House official.
While it's true that non-OPEC+ output is creeping back from the crash of 2020 -- and the
ultra-depressed levels of April and May last year -- it's far from a full recovery. Overall,
non-OPEC+ output will grow this year by 620,000 barrels a day, less than half the 1.3 million
barrels a day it fell in 2020. The supply growth forecast through the rest of this year
"comes nowhere close to matching" the expected increase in demand, according to the
International Energy Agency.
Beyond 2021, oil output is likely to rise in a handful of nations, including the U.S.,
Brazil, Canada and new oil-producer Guyana. But production will decline elsewhere, from the
U.K. to Colombia, Malaysia and Argentina.
As non-OPEC+ production increases less than global oil demand, the cartel will be in control
of the market, executives and traders said. It's a major break with the past, when oil
companies responded to higher prices by rushing to invest again, boosting non-OPEC output and
leaving the ministers led by Saudi Arabia's Abdulaziz bin Salman with a much more difficult
balancing act.
Drilling Down
So far, the lack of non-OPEC+ oil production growth isn't registering much in the market.
After all, the coronavirus pandemic continues to constrain global oil demand. It may be more
noticeable later this year and into 2022 . By then, vaccination campaigns against Covid-19
are likely to be bearing fruit, and the world will need more oil. The expected return of Iran
into the market will provide some of that, but there will likely be a need for more.
When that happens, it will be largely up to OPEC to plug the gap. One signal of how the
recovery will be different this time is the U.S. drilling count: It is gradually increasing,
but the recovery is slower than it was after the last big oil price crash in 2008-09. Shale
companies are sticking to their commitment to return more money to shareholders via dividends.
While before the pandemic shale companies re-used 70-90% of their cash flow into further
drilling, they are now keeping that metric at around 50%.
The result is that U.S. crude production has flat-lined at around 11 million barrels a day
since July 2020. Outside the U.S. and Canada, the outlook is even more somber: at the end of
April, the ex-North America oil rig count stood at 523, lower than it was a year ago, and
nearly 40% below the same month two years earlier, according to data from Baker Hughes Co.
When Saudi Energy Minister Prince Abdulaziz predicted earlier this year that "'drill, baby,
drill' is gone for ever," it sounded like a bold call. As ministers meet this week, they may
dare to hope he's right.
More stories like this are available on bloomberg.com
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now to stay ahead with the most trusted business news source.
The OPEC Monthly Oil Market Report said the
world oil supply fell by 150,000 barrels per day in April.
World oil supply
Preliminary data indicates that global liquids production in April decreased by 0.15 mb/d to
average
93.06 mb/d compared with the previous month, and was lower by 6.45 mb/d y-o-y.
World oil supply rose 330 kb/d to 93.4 mb/d in April and will increase further in May as
the OPEC+ alliance continues to ease output cuts. Based on the current agreement, global oil
production is set to grow by 3.8 mb/d from April to December. For 2021 as a whole, world oil
production expands by 1.4 mb/d year-on-year versus a collapse of 6.6 mb/d in 2020. Canada leads
non-OPEC+ with growth of 340 kb/d while the US is set to contract by a further 160
kb/d.
That's a difference of just under half a million barrels per day, (480,000 bpd). That's a
huge difference. Which one should we believe? Which organization has the most credibility?
We live in a world of half-truth where words are very carefully chosen. Companies hire
public relations firms to give just the right "spin" to what they are saying. CEO make
statements that suggest that everything is going well. Newspapers would like their advertisers
to be happy. Still is at the limit of Moore's law and fither shriking of dier is
impossible due to physical limits. One of the key challenges of CPU engineering is the design
of transistors gates. As device dimension shrinks, controlling the current flow in the thin
channel becomes more difficult. So callled 8mn process (not that this is a marketing not
technological term) is possible and now used in production, 5mn is problematic but used for
example by Apple in A14 CPU ( iPhone 12) / According to some sources, the A14 processor has the
transistor density of 134 million transistors per mm2. 3mn is probably the current
technological limit (TSMC is on track for production first 3 nm chips at the end of 2022
Anton Shilov, Anandtech April 26, 2021 ). It is unclear, if 2mn process will be
technologically viable or not. So the only way for CPU manufactures to increase the processing
power of CPUs is to increase the number of cores.
I We live in a finite world; we are rapidly approaching limits of many kinds. Which creates
problem, in some ways, somewhat similar to the world of the 1920s.
Yields on the US 10 year formed a bullish hammer within consolidation on Friday. Suggests
that yields are headed to 2% or above. It suggests that the move higher is now. Higher yields
will lead to stronger dollar. Might be the beginning of where price inflation becomes a drag on
economy as yields rise on debt. And as long as price inflation continues yields will rise.
Might put a cap on oil price in near future. Maybe we get another $5-$15 rise in oil price
before credit blows up due to rise in yields.
As the cost of credit rises due to price inflation. If you borrowed money at rock bottom
interest rates and you now have to rollover debt at a higher interest rate that is a problem
for corporate USA.
Anyone that doesn't believe that there will be a huge price to pay for the policy response
of Covid-19 is kidding themselves.
Even just on a relative basis. When you expand monetary and fiscal policy by that much in
one year. Things tighten on a relative basis as what comes next in the years after is less
support.
He is right that it doesn't work at $55/b, at $61 (today's price for WTI) it works in the
Permian basin. Note that I also use the data from shaleprofile as the basis for my models.
Though I clearly don't know the oil business as well as an old pro like Mike, not even
close.
The average price of oil in 2020 was about $36/b, in 2021 it will be about $60/b and in 2022
about $70/b (WTI prices). Decline will stop at $70/b for sure and probably at $60/b.
Note that in 2017 the average WTI price was about $52/b, and in 2018 it was $67/b, and in 2019
it was $60/b. 2018 saw a very large increase in tight oil output and the increase in 2019 was
pretty big as well.
My Permian model assumes new wells are financed from cash flow rather than new debt, debt
paid back in full by 2026. REPLYSCHINZY
IGNORED04/27/2021 at 4:21
am
Dennis,
Your observations are correct with the implicit assumption that extraction costs do not rise
at the same rate as the price of oil. Shallow Sand has remarked that in the 1990s $20/barrel
was considered a good price but today most wells, either onshore or off, are not profitable at
$50/barrel. Shallow is our invaluable guide to the evolution of costs in the oil patch.
My prediction is that oil prices will stay in the current range ~$55-$65/ barrel until
decreased investment (see
http://peakoilbarrel.com/december-non-opec-oil-output-continues-rebound-from-may-low/#comment-715646
) results in a shortage. I believe the shortage will cause oil prices to kick on the order of
50% in a year. The price kick will then provoke a financial crisis similar to that of 2008, but
central banks will have far fewer options to alleviate the crisis. REPLYHOLE IN HEAD IGNORED04/27/2021 at 6:24
am
Schinzy , I agree with you . Dennis is underestimating a few critical issues ;
1. End of OPM finance .
2. Underestimating the GOR and WOR rise .
3. Underestimating decline rates in shale .
4. Underestimating the rise in costs now ( steel above by 50% in 2021) which makes $ 75 non
viable .
5 . His contention that the big corporations will buy out the bankrupt corporations . The flaw
is that the big corporations themselves want to exit . Further as Mike S has pointed out " who
wants to buy wells which are at the tail end of their production and are going to have a
shutdown expense of $ 100000 to bear " .
All three agree that there is going to be shortage in 2022 sometime in the second or third half
and your scenario that the resultant high price will provoke an even deeper financial crisis
than that exists now will play out . Let me add that Covid damage cannot be assessed at this
stage as the virus is mutating at a rapid pace . It has moved from India to Pakistan. https://www.rt.com/news/522199-pakistan-military-coronavirus-khan/
P.S : He always give's EOG as an example of a well run shale play but " one swallow does not
the summer make " . For every one EOG there are 10/15 waiting in line for bankruptcy .
SHALLOW SAND IGNORED04/26/2021 at 6:48
am
I don't see how these wells can be profitably operated by a company with a lot of overhead,
which I assume these publicly traded companies have. DENNIS COYNE IGNORED04/26/2021 at 7:31
pm
I have discussed before the uselessness of GAAP accounting in US shale.
Raw Energy, who writes articles on Seeking Alpha, has addressed this much better than I
can.
Over 3,000 of the approximately 19,000 oil wells in ND produced 0 barrels of oil in the last
reported month, 2/21. Some of this could be weather related. I suspect more of the problem is
economic, even at improved oil prices.
I suspect the numbers are similar in the other shale basins. Mike says there are many
inactive shale wells in EFS, where he operates his conventional production.
US shale oil producers shut in production because it became hugely. A large part of US
production even saw negative prices. But even as prices recovered quickly to $40/bbl, hardly
any producer could cover their operating costs, let alone being profitable. This lead to a
continuous decline in output and only very recently we saw a modest recovery in production. At
this point, production is down around 2.5mb/d from peak.
One might argue that we have seen the same dynamics before. Back in 2014, US shale oil
production was also growing at breakneck pace. This eventually led to a much oversupplied
global market and a price crash from $110/bbl to $30/bbl over 18 months. As a consequence, US
shale oil production also sharply declined, which eventually rebalanced the market. Prices
recovered and stabilized at around $60-70/bbl. Subsequently US shale producers slowly adapted
to the new price environment and by 2019, production again grew at over 2mb/d. But in 2019, the
market had not much trouble absorbing that kind of production. In fact, it depended on it.
However, the recent price crash and ensuing production decline doesn't seem to follow the
same path. Oil prices have fully recovered by now, but production has not. In fact, US
production is near the lowest it has been since the outbreak of the pandemic. Moreover,
drilling activity is also greatly lagging. Arguably the US oil rig count has recovered from 172
in August 2020 to currently 344, but this seems not enough to keep production even
constant.
Exhibit 11: US production has yet to show any meaningful recovery despite the full price
recovery (Kb/d year-over-year)
Source: EIA. Goldmoney Research
In fact, the reason why US shale output is not lower despite this very low rig count is
because producers reverted to high grading. High grading means the producers are producing from
their most prolific acreage. This also means that any production increase would require a
massive redeployment of rigs as new wells would be less prolific than the current ones. But US
producers vowed to their investors as well as to their banks that – unlike the last time
prices recovered – they would refrain from growing output and focus on profitability
instead.
Exhibit 12: As the rig count fell, average production per rig increased due to high grading
(B/d and rig count (Permian Basin))
Source: EIA, Goldmoney Research
A further issue is the size of US shale output and the steep decline rates. Unlike shale gas
producers which somehow managed to flatten their decline curves, shale oil producers still
struggling with decline rates around 70% in the first year. The larger total US shale oil
output gets, the more new production has to be brought online to simply offset the decline
rates in existing output. This is not a new problem, but the recent reluctance of US producers
to grow output at all costs means this issue is now real.
Exhibit 13: Steep decline rates remain a problem as US shale oil output remains high even
after the crash (B/d all basins)
Source: EIA, Goldmoney Research
The pandemic and the price crash have also accelerated phenomenon that was already known
from the shale gas market, but is new to the shale oil market. In the US, there used to be
multiple shale oil basins which all showed production growth, albeit at different speeds. The
Permian basin became sort of the king of shale oil, but other basins such as the Bakken (the
first), Eagle Ford, Mississippi Lime and Niobrara all grew as well. But in this price recovery,
and despite the rebound in the rig count, all those basins show a continuous decline. The
Permian Basin is the only shale oil Basin that shows a recovery in supply (albeit a small one).
This is not unlike what we have seen in US gas, where shale gas production started in the
Barnett shale, then Haynesville Basin outgrew everything else, but now the Marcellus shale is
dominating US gas markets.
Exhibit 14: Only the Permian Basin shows some output recovery (b/d)
Source: EIA, Goldmoney Research
If this fully repeats in the shale oil space, then production is limited to how much
pipeline space can grow out of the Permian. Arguably that was an issue before, but if
production continues to decline in other basins, then the Permian has to offset those declines
as well. This would further restrict how fast production can growth in the future.
We believe that the necessary focus on profitability, combined with the issue of high
decline rates which become more dominate as base production grows, limit US shale oil
production growth long term. We don't think we see production again growing at the record rates
of the past, certainly not at these prices. Much higher prices would likely ignite another rush
in the sector, but eventually the decline rates will dominate and effetely limit production
growth.
The future of global supply growth:
On net, this means that supply will struggle to return to pre-COVID-19 levels quickly as
non-OPEC ex US shale will be permanently lower and continue to decline while it will take time
for US to reach old highs. US shale oil production is unlikely to grow again at past rates,
particularly with current prices. And once US shale production has reached the previous peaks,
it will be increasingly difficult to grow much further as high decline rates simply limit to
how high production can go. Even before the pandemic, most OPEC countries were already more
concerned about maintaining their production rather than growing it over the long run. Low
prices and high spare capacity also prompted core OPEC members to lower their CAPEX, at least
temporarily.
The duration mismatch between supply and demand peaks
The problem is, while oil producers are preparing for a low carbon future with potentially
declining oil demand, oil demand itself will still grow for many years to come. The oil space
is facing a duration mismatch.
Oil demand is primarily driven by the transportation sector and to a lower extent by the
petrochemical industry and industrial sector as a whole. Together they account for 84% of
global oil demand, 87% if demand from the agricultural, forestry and fishing sectors are added
(as it is likely also mostly transportation related oil demand). The transportation sector
accounts for about 2/3 of global oil demand and it is still growing. The petrochemical sector
accounts for 11% and is the fastest growing sector for oil demand. Industrial demand comes in
third at 7% and it has been declining for decades.
The future of oil demand
Industrial demand will likely continue to decline slowly. Wherever possible it's substituted
as oil tends to be one of the most expensive energy sources compared to power or gas. But this
is an ongoing process and the low hanging fruits have been harvested decades ago. Hence this
future decline is irrelevant in the grand scheme of things.
In contrast, demand from the petrochemical sector will continue to grow in the foreseeable
future as plastics demand will continue to rise with population growth and global economic
expansion. We expect Petchem demand growth to offset declines from all sectors other than the
transportation sector.
The big question therefore is what will happen to transportation demand. Transportation fuel
demand has been declining for many years in most Western economies even as Western economies
continued to expand and both the population as whole and mobility continued to rise. This is
mainly due to much better fuel economies in transportation vehicles driven mostly by
regulations. Importantly, the regulatory frameworks that drive these efficiency gains are not
new. In the US, the Corporate Average Fuel Economy (CAFE) standards were introduced already in
1975 as a reaction to the 1973-1974 oil embargo. The regulatory frameworks aims at fuel
consumptions directly. The CAFE standards have been continuously tightened over the past 45
years.
Exhibit 17: Fuel efficiencies have been increasing for decades without electrification
Source: Wikipedia
The European Union adopted a regulatory framework with a dual mandate that not just targets
fuel economy, but also emissions. European manufacturers have a binding emission target of CO2
95g/km for the average mass of their vehicles from 2021 onwards. It was CO2 130g/km from
2015-2019. Other OECD nations have similar standards that have tightened over the past
decades.
The result is that fuel consumption in most OECD countries has actually peaked a while ago.
Countries with high population growth such as the US have seen their overall fuel consumption
rising, but not at the same speed as their population and economy was growing.
The main contributor to fuel demand growth over the past 20+ years this were the emerging
markets. In Emerging Markets, the fuel economy of newly sold cars is already quite high as the
cars sold tend to be smaller, lighter and equipped with smaller engines. According to the SIPA
center on global energy policy, the fuel economy of average car sold in China in 2018 was
roughly 5.8 liters per 100km, equivalent to 40.5Mpg. In contrast, the average vehicle sold in
the US had a fuel economy of around 33.8Mpg. However, given the rapid expansion of the car
fleets in these countries, fuel demand has been strongly rising over the past decades.
Importantly, the rise in popularity of hybrid cars and EVs over the past years has not yet
lead to a complete change in trend in fuel consumption. The efficiency gains over the past
years were still primarily driven by more fuel efficient cars with combustion units. The reason
is that despite their popularity, hybrid and full EVs are still only a small fraction of all
transportation vehicles sold in the world and even a smaller share of the global car fleet.
According to the international Energy Agency (IEA) roughly 90 million of cars are sold
worldwide, up from around 60 million units by 2005. According the IEA, only 2.1 of the vehicles
sold in 2019 were electric in some form, which includes hybrid cars.
According to Bloomberg, there are currently 1.2 billion vehicles in the world. According to
the IEA, the total electric car flight is just 7 million. Again, this includes hybrid cars.
The important part for future production is that we make a clear distinction between those
three supply sources (counting OPEC and the + states as one source). There are very different
reasons for why production is down from each source and more importantly, what the long term
prospects are.
In the second part of this report, we will discuss the prospects of each source in detail
and show that the pandemic, and the ensuing price crash, have accelerate a process where global
production will hardly be able to grow. At the same time, demand will not peak as quickly as
people believe. This has the potential for a massive supply shortfall in the medium term.
smellmyfingers 2 hours ago
The only real shortage we have is truth.
We're all being fed a huge steaming pile of BS on everything. Oil build/draw. Crypto
currencies based upon what? Fiat money, paper.
All these lying politicians and banksters just jockeying for positions to steal as much as
they can as they push the human family to genocide.
wick7 38 minutes ago
Either way oil is going over the Seneca cliff and then Mad max here we come.
wick7 35 minutes ago
Every oil well that has ever existed has followed a bell curve. Pretending oil is infinite
is like believing in a flat earth.
Galtmandu 1 hour ago (Edited)
This is some weak sauce analysis on the relationship between gold and energy prices. Here
is a summary:
Energy prices and gold prices tend to correlate.
I have simplified,
Galtmandu
PS, your model is basically, interest rate policy, fed reserves of gold supply, and
inflation - not groundbreaking stuff. You have created an algorithm that uses these three
inputs to overlay on gold prices. Simple stuff. In fact, a basic polynomial exercise gets you
your best fit.
Now, predict the movements of fed gold reserves, inflation, and interest rate policy. You
can't. Therefore, your model has no predictive capability beyond your opinion. Otherwise, you
would be spending your days sipping umbrella drinks.
If I seem aggressive about this stuff its because I hate this kind of faux-analytical
b@llsh&t that is just sales propaganda.
Thrashed10 2 hours ago
I'm sitting mostly in cash right now. I do have a little exposure to oil. And food.
The oil market is so manipulated. Probably a smart move long term. But I have to trade so
my kids get ice cream. I already know my trade for Monday if I feel motivated. I trade
commodities and industrials. The boring stuff that is not sexy.
hanekhw 1 hour ago
Oil prices linked to the worthless dollar won't continue and this Administration is
working hard to make our dollars even more worthless.
...Raymond James analyst John Freeman, who claimed this year in a note to clients that the
United States' true DUC count is much lower, given that many of the wells included in the EIA's
DUC count are dead in the water and many years old, likely never to be completed. According to
Freeman, this figure is as much as 22% too high.
A 2019 Federal Reserve of Dallas survey of oil and gas company executives suggests that half
of the respondents agree that the EIA is overestimating the number of DUCs.
Related: Investors Rush To Oil Stocks Despite ESG Push
In a low oil price environment, oil and gas companies may spend money on finishing off an
already drilled well, rather than on drilling a new well. But companies will continue to strive
to keep that DUC inventory in their back pocket should the market call for it. But when oil
prices have been low for a long time -- and demand for crude or gas remains low, those low oil
prices may never justify completing a well, resulting in another dead DUC.
The essence of shale operation is generation of the stream of junk bonds along with the
stream of oil and gas. In other words profitability is low or nagative. Junk bond need buyers do
this is a confidence gate -- as sson as confidence drops buyers will evaporate. At this point
there will be writing on the wall. We do not need necessary a stock crash for that. But as just
bond moves in parallel with stock that will also be the Minsky moment for shale oil
production.
Nice charts and summary of U.S. Oil & Gas Reserves.
However, it seems to me that a large percentage of these "supposed" unconventional reserves
will never be extracted. Thus, the U.S. Shale Industry will have permanent DUCs that will never
be completed and proved undeveloped reserves that will evaporate into thin air.
Why? Well, if we look at some of the top shale players, total long-term debt from just
five companies increased from $17 billion in 2006 to $133 billion in 2020 (XOM, CVX, EOG, OXY
& CLR).
With Equinor selling its Bakken assets (liabilities), writing down $11.5 billion from the
company's original price-tag, and saying it was a big mistake to get into shale . why would it
be any different for ExxonMobil or OXY?
Indeed, the U.S. Shale Ponzi Scheme will continue a bit longer until the day the
highly-leveraged over-inflated broader stock markets finally crash. At that point there will
not be a SHALE 3.0. I see U.S. shale oil production falling 75% by 2030.WATCHER
IGNORED04/09/2021
at 11:05 pm
Feb this year Exxon erased oil sands from its reserves.
Article talked pandemic so doubt they sold anything. Probably just a price determinant.
JEAN-FRANÇOIS FLEURY IGNORED04/11/2021
at 2:51 pm
This one is also laughable : "That gives plenty of incentive for giants like Total or Royal
Dutch Shell Plc, plus the hundreds of smaller explorers that remain in business, to keep
searching the world's frontiers for the next place to sink their drill bits." Royal Dutch Shell
stated that their production did peak in 2019 and that their production will decrease by 1 or 2
% per year. That means that they decided to cease exploration and implementation of new
oilfields or gasfields, if I am not wrong.Therefore, why there are still people who decide that
oil companies should look for new oilfields ? They want to make real their dreams despite the
crude reality ?
Consolidation continues in the Permian. Pioneer CEO Sheffield has stated repeatedly recently
that the goal is free cash flow now and not growth at all costs. As smaller producers continue
to get marginalized, rapid production increases in tight oil are likely a thing of the past.
Most likely a good thing for everyone.
(Reuters) – Exxon Mobil and Chevron Corp have scaled back activity dramatically in
the top U.S. shale oil field, where just a year ago the two companies were dominating in the
high-desert landscape.
The cautious approach of the two largest U.S. oil companies is a major reason domestic
oil production has been slow to rebound since prices crashed during pandemic lockdowns in 2020.
Production now is about 11 million barrels per day (bpd), down sharply from the record of
nearly 13 million bpd hit in late 2019.
The share of drilling activity by Exxon and Chevron in the Permian Basin oil field in
Texas and New Mexico dropped to less than 5% this month from 28% last spring, according to data
from Rystad Energy.
"We essentially hit a pause button," said Chevron Chief Financial Officer Pierre
Breber. "When the world was oversupplied we didn't see the virtue in putting more capital to
add barrels." (Graphic: Exxon and Chevron slash Permian drilling, here)
Neither company is likely to boost spending until next year, according to the
companies and analysts. Chevron expects to produce around 1 million barrels daily by 2025 and
Exxon 700,000 bpd by 2025, the companies said at investor days this month.
Chevron will increase Permian spending from $2 billion now to pre-Covid levels of $4
billion annually "over the course of the next several years," Breber said, but the
company will not increase drilling in the Permian this year. It is currently running about five
rigs in the Permian with two completion crews, down from just under 20 a year ago.
SNIP However, output is unlikely to increase dramatically, due to the swift decline rates for
shale wells.
"We would need three months of oil prices sustained at current levels followed by six
months of drilling activity before production begins to climb higher on a sustained basis,"
said Peter McNally at Third Bridge.
Exxon and Chevron are not the only producers keeping spending down. Many shale companies
have hedged a majority of expected 2021 oil production at an average price below $45 a barrel,
well below current market prices, Enverus' Andy McConn said. The hedges reduce exposure to the
recent increase in oil prices, discouraging near-term growth. (Graphic: Permian oil production
stalls, )
It looks like they hope to return to normal production by 2025.
Biden's plan will end tax preferences for fossil fuel companies. I am not sure if there are
more specifics than that.
However, if expensing intangible drilling costs is eliminated, the shale boom will
officially be dead.
As percentage depletion applies only to the first 1,000 BOEPD per company, elimination of
that would primarily hurt marginal wells.
Also, Biden has proposed $16 billion to plug abandoned wells and reclaim abandoned
mines.
Of course, at this point, the infrastructure bill is not entirely specific. There will be a
lot of negotiation in Congress.
To me, it would seem short to medium term positive for oil prices. Shale companies will
finally have to pay income taxes, and assuming the corporate rate goes to 28%, I don't see how
there would be another drilling boom in shale, absent a super spike in oil and/or natural gas
prices.
Further, the bill would cause a spike in US oil demand. Lots of heavy equipment and
materials that will consume petroleum, even that needed for more clean energy.
Future will be more clear once the plan is signed into law.
I would note grain spiked on the USDA estimates for corn and soybean acres. This could
affect oil prices short term.
The 12 nation group might not see annual C plus C output increases of 1400 kbo/d in the
future, but it will take time for the rate of increase to fall to 455 kbo/d (where a
plateau in World output would occur) especially if oil prices rise to $80/bo or more.
No, it will not take time. Why would you think production would graduallly fall off?
Yes, decline slops are usually gradual as well as increasing slopes. But the change from
increase to plateau or increase to decline is seldom, if ever gradual. USA+Saudi+Russia has
already plateaued. Their decline is very likely to be sudden, well, it has actually already
happened.
However, in the two charts below, I have used your method of stopping the chart just before
the Covid induced decline. The charts speak for themselves.
I think it instructive to recall oil and gas investment history. Unregulated oil and gas
markets have always yielded boom bust cycles. There was a bust cycle from 1986 to 2000. A boom
cycle started in 2001 with investment in oil and gas rising on average 11% per year to $780
billion in 2014 (this was from a Kopits talk in 2014, but the link I have no longer works).
There is a lag between increased or decreased investment and the response in extraction
rates. The lag is longer offshore than onshore. For example, in spite of the investment boom
from 2001 to 2014, extraction rates were stagnant between 2005 and 2010.
A bust began in 2015 with investment dropping 25% in 2015 and a further 20% in 2016. The
drop was more pronounced offshore than onshore. Investment stayed essentially flat through
2019. Extraction rates continued to climb through 2018 but were flat in 2019.
The IEA began warning in 2016 that investment was not sufficient to meet demand in the early
2020s. In their 2019 WEO they stated that $650 to $750 billion was needed annually to attain
106 mb/d in 2030. I am assuming this sum referred to oil AND gas investment. In 2019 oil and
gas investment was $483 billion. In 2020 it was $313 billion (close to 2009 levels).
As Dennis noted in response to my comment above, the relationship between a drop in
investment and the corresponding drop in supply is not linear. But unless investment increases,
I don't expect extraction rates to achieve 2018 levels soon.
REPLYSHALLOW SAND IGNORED
03/28/2021 at 6:08 am
Ovi. I appreciate your posts. Thanks.
Schinzy. Look at what the integrated oil companies are forecasting. BP, RDS and TOT are
shrinking production. CVX and XOM are greatly reducing CAPEX. So is COP, the largest
independent. So is PXD, one of the largest shale players. Of course, these companies can change
strategy quickly, likely next year if any do.
For the first time I can recall, the government of the United States is not supportive of it
increasing production. Contrary to popular belief, this matters.
To keep a lid on oil prices, on the supply side, either the USA needs to keep adding barrels
or some other country that does not benefit as a whole from high oil prices will need to step
up. The CAPEX currently isn't budgeted to do that.
Of course, decreased demand due to the continued spikes in COVID cases will continue to put
a lid on demand. Hopefully by fall this won't be much of an issue, not for oils sake, but for
public health sake.
The other demand side lids I see could be Western EV adoption offsetting developing world
oil demand growth. Worried here about both the needed upgrades to the grids, plus the lack of
rare earth metals. The other could be another big economic issue. Don't want that, but seems
economy issues are also going to be with us given the high debt levels. The stimulus in
response to COVID isn't cheap.
REPLYSCHINZY
IGNORED
03/28/2021 at 7:41 am
All very true Shallow. I suspect these companies are reducing CAPEX because of increasing
debt. The more conservative CAPEX spending seems to be helping their share prices. SHALLOW
SAND IGNORED
03/28/2021 at 7:55 am
Schinzy.
IHS Markit doesn't see US CAPEX spending at the 2018-19 levels returning until 2024-25.
Probably too far out in the future to be accurate. However, it's 2021 forecast is for lower
CAPEX in all years since 2010 except for 2020.
I will add another big player to my list above, EOG also lowered CAPEX guidance for 2021
from where it had been pre-pandemic. Will seek to hold production flat in 2021.
Here is the C Plus C chart to to December 2022. In the original chart in the post above, I
only took it out to March 2021.
The March STEO report along with the International Energy Statistics are used to make the
projection. It projects that world crude production December 2022 will be 81,759 kb/d, 2,735
kb/d lower than November 2018
Ovi, thanks for a great chart. And even this, 2,735 kb/d below the previous peak, I think is
overly optimistic.
I think, at least two of the world's three greatest oil producers have peaked, (The USA,
Saudi Arabia, and Russia), have peaked, and the rest of the world has clearly peaked, there is
no way we can possibly surpass that 2018 peak. Actually, I think all three have peaked. I was
just being conservative.
World less USA, Saudi Arabia, and Russia peaked in 2017. All three peaked, yearly average,
in 2019. Of course you can argue that this is just the peak "so far". But I do not believe any
of the three will ever surpass their 2019 yearly average peak.
Dennis, you wrote: Below I use the trend in the ratio of World C plus C to World
petroleum liquids from Jan 2017 to Dec 2019 to estimate World C+C from Jan 2021 to Dec
2022.
Okay, you use past trend lines to estimate future production. Well, I guess there is
also how the EIA does it and the IEA does it. I just don't have confidence in that type of
analysis.
Above I have charted past World oil production less the USA, Russia, and Saudi Arabia. There
is clearly a trend there. Do you think this trend will continue?
World C+C production in 2018 averaged 82,897,000 barrels per day. In 2019 that average was
82,306,000 barrels per day. I have little doubt that future world oil production can come close
to those averages. But I would bet my SS check that the 2018 peak will never be surpassed. (I
like annual averages but if you like centered 12-month averages, then go with that.)
At any rate here are four possible sources for a surge in World oil production:
1. THE USA
2. Russia
3. Saudi Arabia
4. The World less USA, Russia, and Saudi Arabia
If World oil production is yet to peak, which one, or ones, of these four sources, will it
come from? RON PATTERSON IGNORED
03/26/2021 at 12:00 pm
I believe I have seen reports that suggest a plateau near the recent 12 month peak output
can be maintained for 5 to 10 years.
No Dennis, you have not seen that. I posted that myself some time ago. Russia stated that
they hoped to hold production at about 11.2 million barrels per day for the next four years,
2021 through 2024. I have since lost the link but it was posted right here on this list.
However, I think that was wishful thinking on Russia's part. I don't think they will hold that
level, ever again.
The drop in World minus KSA, US, and Russia C plus C output since 2018 has mostly been
due to a combination of lower oil prices and OPEC reducing output to try to bring oil prices
back up,
I am not talking about the drop since 2018, I am talking about the peak and decline
before 2018. The peak month in my chart above was November of 2016 at 52,206,000. The
peak 12-month average was September of 2017 at 51,161,000 barrels per day. At that point, in
September of 2017, the World less USA, Russia, and Saudi produced 63% of all World production.
63% of World oil production peaked in September of 2017.
While World oil production was peaking in 2018, due to increased production by the USA,
Saudi, and Russia, the World less these big three was declining to 50,737,000 barrels per day,
the average for 2018. A decline of almost half a million barrels per day.
Dennis, regardless of what happens in Canada, Brazil, and Norway over the next 5 to 10
years, the World less the big three peaked in 2016 monthly and 2017 annually. Any increase in
World production must come from one or more of the big three. HOLE IN HEAD IGNORED
03/26/2021 at 1:22 pm
Dennis , your post on the last thread .
"I stand by my estimate, in 2020 World C plus C output dropped by 5.5 Mbo/d due to a lack of
oil demand and the resulting drop in oil prices from the 2019 annual average, so a 10 Mbo/d
increase from the 2020 level (annual average) of C plus C output requires a return to the 2019
average level (roughly 82.3 Mb/d) requiring a 5.6 Mbo/d increase and then a further 4.4 Mbo/d
increase in output to reach 87 Mbo/d.
If World demand for C plus C warrants such an increase by 2028, I believe it can be
produced, and yes the model accounts for depletion, which has been ongoing since the first
barrel of oil was produced. The basis for the estimate is likely World resources of 3400 Gb of
C plus C (this includes the 1428 Gb of crude plus condensate that was produced from 1860 to
2020), remaining resources (this includes conventional and unconventional C plus C) are about
1972 Gb (this includes future discoveries and reserve growth).
It is possible less will be produced due to lack of demand, if a rapid transition to
non-fossil fuel energy sources occurs, I hope that is the case, but I am skeptical"
Well, 2020 production came in at an average of 75.93 mbpd . Decline rate was 7.5% compared to
2019. How will you achieve additional 10 mbpd by 2028 ? Ron is correct . Igor Sechin boss at
Rosneft confirms what Ron has stated , shale party is over , KSA is going to cut domestic
consumption by 1mbpd so that it can export that oil . Sorry, Brazil , Norway ,Tom Dick and
Harry are in no position to cover this lag in production .In the future decline rates will
increase as horizontal wells reach their limits of extraction . You must rethink your models
with the new facts . Your statement "If World demand for C plus C warrants such an increase by
2028, I believe it can be produced " does not hold water . Your belief or mine is irrelevant .
Geology prevails . RON PATTERSON
IGNORED
03/27/2021 at 8:55 am
OPEC has been holding back production since 2017 in order to get oil prices up, how much
different nations produce depends on their cost of production relative to price,
I don't see any evidence to support that statement. Average OPEC production in 2018 was only
170,000 barrels per day below the average for 2017. If they were holding back, they weren't
doing a very good job of it. I think they were producing flat out all three years, 2016 through
2018.
I remembered incorrectly, OPEC likely started cutting back on output in the middle of
2016 to get oil prices higher,
You remember very incorrectly. OPEC, in the last months of 2016 was emptying their storage
tanks in order to produce as much oil as they could. They would set their quotas on the amount
produced in November and December of 2016, so they were making heroic attempts to produce every
barrel possible in order to get a higher quota. (November 2016 was the OPEC all-time peak. And
in my opinion, will remain so forever.)
They started cutting in January of 2017. But by June everyone was cheating and they were
all, by July 2017, producing flat out.
Why does OPEC exist?
OPEC was formally constituted in January 1961 by five countries: Saudi Arabia, Iran, Iraq,
Kuwait, and Venezuela. They existed then for the sole reason of trying to drive oil prices
higher. They would like to do that today but squabbling among members has made them somewhat of
a joke. They are a disorganized bunch of buffoons. Yes, they have dramatically cut production
during the pandemic. But so has everyone else in the world. The bottom dropped out of
demand so everyone cut production trying to save money.
A decline in output for the World has occurred since 2018 because oil prices dropped due
to oversupply of oil relative to demand.
Okay, but what about 2017 and 2018? OPEC could not keep their members in line and by June of
2017 everyone was again producing flat out, causing that oversupply. And their cut was a
pittance anyway, not enough to make much difference. For most of 2017 and all of 2018, every
OPEC member was producing every barrel they could. (With the exception of Iran and Venezuela of
course, but that is another story for another thread.)
Just look at the chart Dennis, that is just so damn obvious it cannot be denied.
For OPEC minus Iran, Libya, and Venezuela the centered 12 month average peak was 26759
kbo/d in January 2019.
Okay, you need to update your nations here. Libya is already back, producing at maximum
possible capacity for the last 4 months. Venezuela will never be back, not in the next decade
anyway, long after peak oil is history. That leaves only Iran. Iran, if sanctions were lifted
today, could possibly increase production by approximately 1.6 million barrels per day in the
next six months or so. That would not be nearly enough to make up for the natural decline in
OPEC, especially Saudi Arabia, since the peak in 2016.
Iran is the only nation on earth that can possibly increase production in any significant
amount. So you should only deal with Iran when talking about possible OPEC production
increases.
Dennis, OPEC has done nothing but basically tread water since 2005. Why do you think they
will now save the world?
(In the chart below 2021 is only two months, January and February.
OPEC does not produce at maximum output, except when fighting for quotas.
Dennis, OPEC is not an oil company, they are a cartel. The only ones that increased when
battling for quota were Saudi, the UAE, and Kuwait. The rest just produced flat out all the
time. Check the charts.
Yes, they were all producing flat out most of the time. Only in a few instances did they
actually cut production. Of course, the pandemic hit everyone. But as you can see by the yearly
chart I posted their total share of the market has shrunk dramatically since 2005.
Dennis, OPEC peaked in 2016. Saudi Arabia is in decline. End of story. ALIMBIQUATED
IGNORED
03/27/2021 at 7:47 am
Ron,
Good point about past trends lines being a dubious predictor of future trends. This is testable
too. In this case three years of past data was used to predict the future.
If there is 40 years of data, you could run the algorithm on 35 three-year data sets and
check the accuracy of the prediction. That would give you some idea of how likely the latest
prediction is to be accurate.
My guess is that the accuracy is fairly low, but checking would reveal the truth. POLLUX
IGNORED
03/26/2021 at 3:30 am
In November, Saudi Arabia's domestic crude stockpiles fell to 17-year low: "Saudi Arabia's domestic crude stockpiles fell by 1.2 million barrels in November to 143.43
million barrels, the lowest since November 2003." (
source )
This trend continues and in January, stockpiles fell to 137.207 million barrels: "The country's domestic refinery crude throughput rose to 2.343 million bpd while crude
stocks fell to 137.207 million barrels in January." (
source ) HOLE IN HEAD IGNORED
03/26/2021 at 11:19 am
In an article Steven Kopits wrote "In its February Short Term Energy Outlook (STEO), the EIA
forecasts this month's world oil consumption at 96.7 million barrels per day (mbpd). The oil
supply, however, is much lower, only 93.6 mbpd, with the difference of 3.1 mbpd of necessity
being drawn from crude oil and refined product inventories. This is a shortfall of 3.5% "
Is he correct ? if yes ,then are we in trouble ?
One more observation from my seat in the gallery: FOSSIL ENERGY is the basis of industrial
civilization, and our complete dependence on it portends our extinction as a species. We
might as well accept the fact that we are done.
On the technical side, drillers have vastly lengthened the horizontal leg of the typical
shale well, from slightly over a mile in
2014 to an average of 8,500 feet in early 2019. The ability to do this has come in part
from improvements in drilling fluids design to permit entry into longer sections, and better
rotary steerable MWD/LWD assemblies that enable more reliable real time drilling data from the
bit to ensure they are staying in the sweet spot of the reservoir. Improvements in perforating,
frac stage design with 4-D fracking that takes into account the frac's progress over time have
also contributed to this increase in productivity.
The amount of sand or proppant pumped per foot of interval has also increased hugely from
around a
1,000 pounds per foot-PPF, to between 2,000 and 2,500 PPF. Increasing the amount of
proppant ads to the well's cost, but it also hugely increases the permeability of the
completion. Permeability is a measure of the flow capacity of the rock. More permeability
results in more production for longer periods of time.
High grading of drilling opportunities has been a prime contributor to being able to
maintain a lower decline rate that originally supposed in my calculations. What this means is
that operators have been focusing on their Tier I acreage and bypassing lower tier
opportunities.
When you take this performance and multiply it across the top twenty or so drillers, you can
begin to see how shale production manages to hover around the 7.5 mm BOEPD level.
... ... ...
One of the questions that often comes up is what will happen when Tier I acreage is
drilled up. Some estimates have been put forward that this might occur within the next
decade.
Rystad has challenged those estimates showing an estimate of the longevity of Tier I shale
in years at present rates of drilling.
It comes as no surprise the Delaware sub-basin of the larger Permian basin is the king of
shale, and operators there will retain a low cost drilling advantage for a number years beyond
other plays.
Most analysts believe that most public companies will stick to discipline. OPEC+ also seems
to have gambled on expectations that U.S. shale will look at higher profits instead of
production this time - unlike in any of the previous oil price spikes in recent years - when it
decided not to raise production from April, except for small increases for Russia and
Kazakhstan.
In view of the recent high prices, JP Morgan now expects U.S. oil production to average
11.36 million bpd in 2021, slightly up from 11.32 million bpd last year.
Sweet spots depletion might be a problem for them. U.S. shale production as a whole is
unlikely to return to the levels before the pandemic. The high decline rates of shale well are
more acure outside of sweet spot. Larger firms which still have sweet spots feel the pressure
from investors to produce level of dividends expected in the industry. That excude "all-in"
drilling as happned inthe past when Wall Stertt money were abundant and discipline was
lacking.
Currently, OPEC itself sees U.S. crude oil production for 2021 at 11.2 million bpd, slightly
down from an estimated 11.28 million bpd output for 2020. In its latest Monthly Oil Market Report
(MOMR) for February, the cartel actually revised down its 2021 forecast for U.S. oil production
by 210,000 bpd and now expects a 70,000-bpd annual decline from 2020, as continued capital
expenditure discipline is "expected to weigh on production prospects in 2021."
Larger listed U.S. producers are concerned
that some drillers would break promises of output restraint.
"There are going to be bad actors [who pursue] growth for growth's sake," Matthew Gallagher,
an executive at Pioneer Natural Resources, told the Financial Times in
January.
Pioneer Natural Resources itself will look to limit production growth to an average 5
percent over the long term, CEO Scott Sheffield
said on the Q4 earnings call last week. Moreover, Pioneer expects to return up to 75
percent of its annual free cash flow to shareholders after the base dividend is paid, Sheffield
noted. This will be returned in the form of variable dividends paid out quarterly the following
year, the executive said. Related:
Is This The World's Next Big Offshore Oil Region?
While Pioneer and other major listed shale players seem to be heeding investors' calls for
higher returns to shareholders, the smaller closely held operators are not promising anything
other than chasing higher returns on their investment, which is being generated by more oil
production.
Dennis, I must disagree with your assessment. OPEC peaked in 2016. Yes, Iran can come back
and increase production by about 1.5 million barrels per day. But that still will not make up
for the decline in the rest of OPEC. No need to mention Venezuela, they may come back around
2030 or so, long after the peak has passed.
Russia said they had peaked in early 2020. I see no reason to think they were lying.
That leaves Brazil, Norway, and Canada. They all three may increase production but nothing
spectacular. Not nearly enough to make up for the rest of the world in decline. REPLYSTEPHEN HREN IGNORED02/27/2021 at
5:58 pm
I'm inclined to agree with Ron. So much investment deferred because of 2014 and 2020 price
crashes. LTO can come back quickly if the price stays consistently high (a big if) but it
won't be enough to save the day. Investors are expecting cash from LTO these days, not
production increases. I imagine most other countries are just coasting after the turmoil of
the last year. Also still plenty of wildcards in the collapse department over the next 5-10
years: Iraq, Nigeria, Libya, etc. WATCHER IGNORED02/28/2021 at
1:12 am
Factions in the administration are on record as wanting sharply higher oil prices. Seems
difficult to see how this would get through the Senate, but it is a green priority.
RON PATTERSON IGNORED02/28/2021 at
8:48 am
Does Occidental know what they are talking about? They are saying that the investors are
just not there for a massive increase in production. And they are one of the two largest
producers in the Permian Basin.
America's oil production will never again reach the record 13 million barrels a day set
earlier this year, just before the pandemic devastated global demand, according to Occidental
Petroleum Corp.
"It's just going to be too difficult to replace the 2 million barrels a day of
production that we've lost, and then to further grow beyond that," Chief Executive Officer
Vicki Hollub said Wednesday at the Energy Intelligence Forum. "Over the next three to four
years there's going to be moderate restoration of production, but not at high
growth."
Occidental is one of the biggest producers in the U.S. shale industry, which added
wells at such a rate prior to the spread of Covid-19 that the country became the world's top
crude producer, overtaking Saudi Arabia and Russia, ushering in an era that President Donald
Trump called "American energy dominance."
U.S. oil production is stuck below it's pre-pandemic high
Shale's debt-fueled expansion came to a juddering halt due to lower gasoline demand and oil
prices, but also because of Wall Street's increasing reluctance to fund growth at any
cost. Shale operators are increasingly prioritizing cash flow and returns to investors over
production growth.
Occidental, which vies with Chevron Corp. to be the biggest producer in the Permian
Basin, has been forced to throttle back capital spending, lower growth targets and cut its
dividend in a bid to save cash during the downturn. Its finances were already severely
challenged by the debt taken on through its $37 billion purchase of rival Anadarko Petroleum
Corp. last year.
Hollub said global consumption stands at about 94 billion barrels a day, and it will
take a Covid-19 vaccine before it returns to 100 million barrels. Due to cutbacks around the
world, supply and demand for oil will likely balance again by the end of 2021, she
said.
Unlike some of her European peers, Hollub sees strong long-term demand for oil. "I
expect we'll get to peak supply before we get to peak demand," she said.HICKORY
IGNORED02/28/2021 at
11:31 am
"Unlike some of her European peers, Hollub sees strong long-term demand for oil. "I expect
we'll get to peak supply before we get to peak demand," she said."
Thanks Ron.
I wonder if she is referring to the balance in the USA, or the world.
It will be a horse-race finish for the whole decade- "and here comes Demand up the
backstretch " RON PATTERSON
IGNORED02/28/2021 at
11:26 am
Figure this one out. The EIA's AEO2021 In
the past they have always given scenarios based on "Low Price" and "High Price". But now it
is "Low Supply" and "High Supply".
They are not making a prediction, they are just saying: "Here is what low supply looks
like", and "Here is what high supply looks like". Hell, we already knew that.
Anyway, it is all about tight oil. Everything depends on tight oil. Occidental says tight
oil has peaked. But the EIA is taking no chances. They are saying in effect: "Here is what it
looks like if tight oil has peaked and here is what it looks like if it has not."
One factor is a change in one of the three large producer's policies. This large producer is
also the only producer that consumes more than it produces and therefore the only one of the
three that favors lower prices. I'm referring to USA, of course.
USA shale (and to a much lesser extent GOM) growth kept a lid on prices. Where would prices
have been 2010-19 without USA adding 7 million BOPD?
USA growth doesn't appear to be headed toward adding 1 million BOPD or more per year in the
future. USA companies are all being pressured to pay dividends. To cover dividends, USA
companies need much higher prices. USA companies aren't forecasting growth like past years.
For the first time ever, the USA government is not making oil production growth, either
domestic or foreign, a priority. I am not making a "political" statement here trying to rile up
the left on the board. Just look at oil prices since the USA election on 11/3. Not a
coincidence. Not likely USA will be intervening anytime soon in the ME to protect oil supplies.
At least not in a big way.
I have no idea how high oil prices will go. I wonder what happens politically in USA with $3
gasoline? $4 ? Are high gasoline prices no longer a political liability? They weren't for Obama
in 2012. But USA was drilling like crazy in 2012. Not sure what happens this time if that
occurs, given clear desire of Biden Administration to discourage USA oil production growth.
Another factor is the Western European producers have told the market recently in a very
straightforward manner that their oil production is past peak. The CEO's of both BP and RDS
have stated this. Total is also transitioning away from oil. Equinor also, it changed its name
to remove the word oil.
Next, even though total worldwide demand will still be below a record, demand growth from
2020 to 2021 worldwide will be big, much bigger than from 2009 to 2010 after GFC. What did
prices do from the depths of GFC to 2011? Compare GFC stimulus to COVID stimulus.
Last, how many paper barrels are traded per physical barrel? With the increase in paper
barrels (I would call them more accurately day trader barrels) volatility in the oil market has
grown. The price went negative big time one day last April. It was purely a day trader
phenomenon.
Everyday you can find headlines that point to a huge transition underway in the world energy
scene.
For example today-
-Exclusive: Equinor considers more US asset sales in global strategy revamp, and
-Ford bets $29B on leading the 'electric vehicle revolution'
There is a huge scramble underway to adapt to the conditions these big companies now see
coming to be over this decade.
In the meantime, I think that oil demand growth will be very strong over the next 18-24
months.
And as the price of gas in the USA goes up in this rebound phase, the great difference in
travel cost/mile between plug-in vehicles (like a Ford mustang) and ICE vehicles will become a
widely known fact. Ford (and the other manufacturers) all know that now, even if they were slow
on the uptake.
This world is going to change rapidly this decade in so many ways. REPLYALIMBIQUATED IGNORED02/15/2021 at 11:34
am
I think a general feeling of optimism that there is light at the end of the Covid 19 tunnel
is helping as well. REPLYSURVIVALIST IGNORED02/15/2021 at 12:23
pm
" For the first time ever, the USA government is not making oil production growth, either
domestic or foreign, a priority."
Great observation. I recall when GWB2 went to KSA to 'kiss the ring' and ask for more oil
production. I wonder how it will play out next time. REPLYHICKORY IGNORED02/15/2021 at 12:33
pm
"" For the first time ever, the USA government is not making oil production growth, either
domestic or foreign, a priority."
Of much greater impact- For the first time ever, the major oil companies are not making oil
production growth, either domestic or foreign, a priority. REPLYSHALLOW SAND IGNORED02/15/2021 at 1:11
pm
The Biden administration is under pressure to see oil prices rise. The green agenda of wind,
solar and EV's is only cost competitive with fossil fuels in two ways: 1) green subsidies; or
2) higher oil prices. Until high oil prices threaten the economy, the Biden administration will
enact policies that gladly see oil prices rise. And with the oil price experience of 2009 to
2014 still relatively fresh in people's minds, the Biden administration is not afraid of $60,
$70, or even $90 oil. They are hoping for it. REPLYHICKORY IGNORED02/15/2021 at 2:13
pm
"$60, $70, or even $90 oil. They are hoping for it."
As are the people working in the oil industry. REPLYSTEPHEN HREN IGNORED02/15/2021 at 4:59
pm
As far as anyone on this board is considered, the higher the price of oil the better. Let's
phase out oil production in the US over the next three decades and keep the price high the
entire time so the producers make money and people are incentivized to switch to less polluting
EVs. It'll be like the TRC for the whole country but heading towards a bottleneck. Auction
drilling rights so only the best wells get drilled. Keep restricting drilling in a phased
manner, enact a gradually lower cap on the number of wells that can be drilled until it goes to
zero in twenty years and then maintain these stripper wells until they are empty. REPLYPAULO IGNORED02/15/2021 at 6:33
pm
Can you imagine any US party that would actually dare to promote a higher cost for gasoline?
Personally, I think there should be a big carbon tax and fuel tax surcharge imposed to fix
infrastructure, but whatever.
Confession: I am not anti oil. My son works in the Cdn industry. I just think people drive
more than they should and that energy should be priced higher. Win win. LLOYD IGNORED02/16/2021 at 3:55
pm
So $90 oil is good for:
-Saudi
-Democrats
-Shallow
-Tesla
-Renewables
PAOIL-
I disagree that high oil prices are needed to make green energy competitive, because oil is
already very expensive energy, which is why it is rarely used to generate electricity. Wind and
solar compete against coal, nuclear and gas, not oil.
Oil shines as a way to store energy in a moving vehicle and power internal combustion
engines. As such, it really competes with batteries, not with the rest of the energy market at
all. And batteries still have a tiny impact on oil markets.
So higher oil prices might be useful for the EVs, but not particularly useful for wind and
solar. But in reality, the EV market is suffering from chronic battery shortages as
manufacturers struggle to build factories fast enough to meet 20% or more annual demand growth.
The oil price really isn't an issue, and raising oil prices wouldn't help.
If Biden's goal was to make EVs more competitive, the government has an easy way to raise
oil prices, which is to raise taxes at the pump. This would be more or less neutral to the oil
price from the producer point of view. It would just encourage exports and discourage imports,
improving America's balance of payments. But it hasn't worked in Europe, where taxes are over
60% of the price at the pump. The most effective way to promote EVs is subsidizing the purchase
price of the vehicle. That has been very effective.
Hoping that the American consumer will keep oil demand up internationally no longer makes
sense, as America's relative economic importance has been falling since 1945. I'm not sure what
the previous administration was trying to accomplish by talking down the price. REPLYJEFF IGNORED02/16/2021 at 5:13
am
"But it hasn't worked in Europe, where taxes are over 60% of the price at the pump. "
I have driven a Toyota Corolla on an 4 week US trip.
With an engine for the US market – you can't buy this modell in Europe. It was very
steady going – and thirsty. At least for european thinking, we used 7-8 litres / 100 km
by mostly driving country roads in cruise control at the given speed (didn't wanted to deal
with US police). Slow for my feeling, I'm driving faster in Germany.
And use only round about 6 litres with a car of similar size, which is a bit faster than
this Corolla – with this lazy slow driving I would use below 5 litres with my car (and
get a lot of flashing).
Jeff –
That was a little unclear on my part. I meant high gasoline prices haven't gotten people to
buy, EVs, but direct subsidies seem to work.
It's also worth mentioning that $120 oil didn't really dent consumption much, and certainly
didn't inspire many to buy EVs.
In my opinion liquid fuel is cheap. I mean I think that consumers aren't willing to make
significant changes in behavior even if prices increase significantly. S IGNORED02/17/2021 at 3:05
am
Alimbiquated, as an European in a well-to-do country, the matter of car buying is somewhat
more complicated than just gasoline price. E.g. fully electric car availibily, their price,
distances that need to be travelled (range anxiety in other words) are still important. Hybrid
cars are also rather expensive. Here it seems that these two car groups are selling better and
better, public charging points are increasing etc so we will see what happens. As I have a full
electric car I got relatively cheaply (still a bit of ouch ) I think I will not get a petroleum
or diesel car ever J HOUSMAN IGNORED02/18/2021 at 4:08
pm
"The green agenda of wind, solar and EV's is only cost competitive with fossil fuels in two
way" Three ways, actually. The third is when we finally start to realize the actual cost of
destroying the environment by burning fossil fuels REPLYMATT MUSHALIK IGNORED02/15/2021 at 10:01
pm
Global crude oil may have peaked 2018-19 before Covid
A dozen workers that are members of the Safe union are threatening to down tools at the
Mongstad terminal from midnight on Monday if talks with the industry body aimed at breaking an
impasse over a 2020 wage settlement with Equinor fail.
Other fields that could be impacted include Kvitebjorn, Visund, Byrding, Fram and
Valemon, with gas output exports from the Troll area also in danger of being hit.REPLYMATT MUSHALIK IGNORED02/15/2021 at 8:05
am
An interesting scenario showing what happens when demand outstrips supply due to lack of
investment is playing out right now in Oklahoma and Texas. There has been a lack of investment
in the region last year due to the drop in prices, and in Oklahoma, the slowing of investment
has been happening for a few years. The massive cold snap that descended on the region made
spot prices (not the futures price you can look up on Bloomberg etc) rise from $2 an MMBTU, to
$5, to $9, to $300, to $600, all in the course of a week. It is currently higher. The cold
weather has caused shut ins of wells, and processing plants. You have a situation where demand
is increasing but supply cannot keep up. I know this is a micro problem that will resolve
itself as temperatures increase, in the coming weeks, but this could be an example of what oil
prices might see in the near future. There has been a lack of investment for years in large
projects, if demand rebounds quickly as vaccine roll out continues, we will not be able to turn
back on new production fast enough to keep prices from running higher, resulting in some
temporary ridiculous price spikes. REPLYSHALLOW SAND IGNORED02/15/2021 at 10:31
am
I saw this resulted in a lot of wells that have been shut in for 5-10 years being
reactivated. REPLYGREENBUB IGNORED02/15/2021 at 8:25
pm
Shallow, are you affected by the cold snap or power outages? REPLYSHALLOW SAND IGNORED02/16/2021 at 12:41
am
Yes. We have about 10% frozen off. Our pumpers decided what to drain and shut in, and what
to keep on. They are real pros. You can't find better.
Our people are the key. We owe them bigtime. They have been out there in this stuff keeping
the rest from freezing.
We will be good soon, temps will come up.
Keep in mind, with one exception, our pumpers are 50+ years old.
Are there millennials that are going to keep the strippers going 24/7/365?
No. I work in construction biz. 90% of twenty somethings can't work five minutes without
looking at their phones. They are useless. All my buddies have the same complaint. REPLYOVI IGNORED02/15/2021 at 9:49
pm
An interesting clip from this article:
"This isn't a consensus view yet but it's quickly coming. Two heavyweights in the past week
have stepped up and called out the problem.
The first was Goldman Sach's Jeff Currie, who called the bull market in the early 2000s.
"I want to be long oil and hang on for the ride," Currie said in an interview with S&P
Global Platts on Feb. 5, warning "there is a lot of upside here."
"Is it back to $150/b? I don't know as it is a macro repricing we are talking about and
everything needs to reprice."
The other is JPMorgan and Marko Kolanovic, who said Friday that oil and commodities appear
to be entering a supercycle.
"We believe that the new commodity upswing, and in particular oil up cycle, has started,"
the JPMorgan analysts said in their note. "The tide on yields and inflation is turning."
"We believe that the last supercycle peaked in 2008 (after 12 years of expansion), bottomed
in 2020 (after a 12-year contraction) and that we likely entered an upswing phase of a new
commodity supercycle."
Shale driller bases rig lease costs on well performance
Rigs are typically rented out at a daily rate for a period of a few months, which has meant
less money for oilfield service providers as drilling becomes quicker and more efficient. So
Helmerich & Payne Inc. is touting a new pricing model based on overall well performance,
and almost a third of its U.S. rigs are now being leased on that basis, CEO John Lindsay said
Wednesday on an earnings call.
In the Permian Basin of West Texas and New Mexico, home to the busiest shale patch in North
America, operators are now drilling the same number of wells with 180 rigs as they were with
300 rigs a year ago, according to industry data provider Lium.
Yeah okay. That's all great. But what I was looking at was oil production. It's going down,
not up. With these prices oil production should be increasing, not decling. Why is that? After
all, that's really all that matters.
In ShaleProfile published today, the Permian is showing a slight bump up in production. It
may have hit bottom. The latest STEO is showing US production dropping till June and July
before beginning to increase. Looks like many more LTO wells have to be put on line before the
decline from all of the current wells can be offset. OVI IGNORED02/16/2021 at 6:36
pm
U.S. oil output plunges as Arctic air freezes Permian shale fields
(Bloomberg) –U.S. oil production has plunged by more than 2 million barrels a day as
the coldest weather in 30 years brings havoc to key producing states that rarely have to deal
with frigid Arctic blasts.
Oil traders and company executives, who asked not to be identified, lifted their forecasts
for supply losses from an earlier estimate on Monday of 1.5 million to 1.7 million barrels.
They said the losses were particularly large in the Permian Basin, the most prolific U.S. oil
region, which straddles West Texas and southeast New Mexico. Output cuts were also significant
in the Eagle Ford, in southern Texas, and the Anadarko basin in Oklahoma.
Two million barrels would be the equivalent of about 18% of overall U.S. crude production,
based on the most recent government data.
Wonder if this drop will show up as a drop in US inventories on Feb 24. While production is
down, so is driving.
Reminder back in the day in the Bakken they had to equip their onsite huge storage of
fracking water with heaters, because NoDak is cold. One suspects the Permian is not equipped
with that and widespread frozen pipe damage can be expected. HOLE IN HEAD IGNORED02/18/2021 at 8:31
am
There is a lot of reasons to be bullish on oil at the moment. There is one problem lurking
over next 4-5 months though. Treasury will shrink the TGA by about 1 trillion USD. Most assume
this will be bullish for most things other than the dollar. But as this cash gets pushed into
the economy/markets. Banks are forced to hold more collateral, mainly T bills. Short end of
treasury yield curve is without a doubt going negative as banks have to have collateral to
except all this cash. Likely another collateral shortage in the making (repo blowup) Fed would
likely have to cut QE purchases to get yields back into positive territory. Which is no
different than hiking interest rates on an economy with a massive debt load that can't handle
higher rates.
Most of the US government debt is on short end of the curve. Therefore most of the debt will
have a negative yield. This would likely end the reflation narrative/ inflation narrative we
currently have. It's likely dollar bullish because the collateral underpinning everything just
went negative yield. And if it turns out to be highly dollar bearish. Well lookout oil prices
would be well beyond the moon.
"... U.S. oil production has fallen more than 2 million barrels per day since March 2020. It will fall much lower. ..."
"... EIA's forecast is impossible. It does not account for the low level of drilling and for the high decline rates of U.S. wells. It seems more likely that production will drop by at least another million barrels per day below October's level later in 2021. ..."
U.S. oil production has fallen more than 2 million barrels per day since March 2020. It will
fall much lower.
Output has fallen from almost 13 mmb/d in late 2019 to below 10.5 mmb/d in October 2020
(Figure 1). EIA forecasts an increase in November to 11.0 mmb/d and then an average level of
about 11.1 mmb/d for the rest of 2021.
... ... ...
EIA Forecast is Impossible
EIA's forecast is impossible. It does not account for the low level of drilling and for the
high decline rates of U.S. wells. It seems more likely that production will drop by at least
another million barrels per day below October's level later in 2021.
... ... ...
What About DUCs?
Many reasonably expect that DUCs (drilled uncompleted wells) provide a solution to the lag
between drilling and production. There are, after all, about 5,800 DUCs in the main U.S. tight oil plays.
These are already drilled and could be converted into producing wells for the cost of
completion which is about half the total well cost.
Most DUCs, however, are uncompleted for a reason namely, that their owners don't believe
that their performance will be as good as wells that they chose to complete instead.
... It doesn't matter whether wells are newly drilled and completed or DUCs -- there are
simply too few wells being added to maintain present levels of production.
... ... ...
It is unlikely that the tight oil business will recover from the effect of Covid-19 and
lower oil prices. Markets will continue to send higher price signals until rig counts recover
to the 800 or so rigs needed to support EIA's 11 mmb/d forecast.
The public and many investors have the peculiar belief that the world will be just fine
without oil. The world will be fine. It has survived meteor impacts and mass extinctions
but humans are more fragile. Higher oil prices are the last thing the global economy
needs right now.
Art, I couldn't agree more. Commodities are rising and oil price is set to rise, in the
midst of a global economic crisis. A perfect storm is brewing and no amount of money printing
can fix that. If things take a turn for the worst the economic crisis could be followed by a
monetary crisis. Energy per capita and standard of living are going down for the majority no
matter what.
That could easily add a social crisis whose first signs we are all seeing. Peter Turchin predicted the increase in social instability 10 years ago in Nature Vol 46, 4 February
2010, pg 608.
The pandemic was just a catalyst for what was already brewing. We are living in
interesting times.
How will the USA regain its advantage in this world?
It will not.....
USA domestic petroleum liquids production is scheduled to drop to 5 million bbl / day by
july. Shale is loss making at prices less than $80 / bbl. Investors/banks have wised up. $$$
has dried up. There are no greater fools with $$ to burn... Drop in production ~ 45% / annum
exponential declining function.
US corporate governance favors quick returns via share buybacks stock kiting schemes
instead of product development. Boeing / GE / Lockheed / and other Fortune 500 firms not
hiring engineers, not developing new products. Experienced engineers going to China for work
or retiring. Shortly, US will not have enough petroleum geologists, mining engineers,
software engineers, hardware engineers, electrical engineers, civil engineers, chemical
engineers, etc to run it's industries.
Lawyers, political scientists, historians, economists... can't do the math.... are
useless....
Trump said "I like being energy independent, don't you? I'm sure that most of you noticed
when you go to fill up your tank in your car, oftentimes it's below two dollars "
But energy "independence" has got little to do with price at the pump. The marginal barrel
sets the price. If the world price for crude goes to $100/barrel, West Texas Intermediate is
going to the same level and gasoline will rise to $4.00.
Oil is at $40/barrel because the Gulf producers and Saudi Arabia want to insure a long
term market for their one export product while making a lot of high cost production
unsustainable and alternate energy sources less attractive.
Below are a number of oil (C + C ) production charts for Non-OPEC countries created from
data provided by the EIA's
International Energy Statistics and updated to May 2020. Information from other sources
such as the OPEC and country specific sites is used to provide a short term outlook for future
output and direction.
Non-OPEC production dropped slowly from a high of 52,638 kb/d in December 2019 to 52,396
kb/d in March 2020. In April that changed when we saw the first big drop in output from the
Non-OPEC countries associated with Covid and with the drop in world oil prices. May output
collapsed to 45,340 kb/d, which is close to the production level in September 2013.
The projection to September (red square) was made using the September STEO report. It
projects that after the low of 45,350 kb/d in May, production will increase by close to 3,500
kb/d to just under 49,000 kb/d in September.
Above are listed the worldʼs 15th largest Non-OPEC producers. They produced 83.6% of
the Non-OPEC output in May. On a YoY basis, Non-OPEC production was down by 5,011 kb/d. On a
MoM basis, production was down by 5,282 kb/d. World oil production was down by 11,418 kb/d, MoM
and 10,318 kb/d YoY.
May saw a drop in output to 2,765 kb/d but rebounded in June to 3,013 kb/d according to this
source . Maintenance and extensive turnarounds planned between September and November could
shave around 200,000 b/d from Brazil's output.
The EIA shows Canadian production was down in May by 658 kb/d by 248 kb/d to 3,694 kb/d. The
CER data is higher because it includes NGPLs in their estimates and is close to 6% of total
output.
Canadian oil exports by rail to the US fell from a high of 411,991 b/d in February to a new
low of 48,820 kb/d in June.
April 156,242 kb/d May 58,048 kb/d June 48,820 kb/d
At the same time, according to this
source , "The Trans Mountain pipeline carried a record-breaking amount of oil to British
Columbia from Alberta in August, despite persistent price and demand woes gripping the energy
sector as the COVID-19 pandemic drags on".
"We have been full every day during the COVID period. Demand for the pipeline has not
softened at all," he told The Globe and Mail in an interview Tuesday.
Chinaʼs production peaked in June-15 at 4,408 kb/d and has been in a steady decline up
to September 2018 where it reached an output low of 3,694 kb/d. According to this
source, Chinaʼs August production increased by 2.6% over last August. Output increased
by 59 kb/d to 3,899 kb/d (Red square). However August's output is still slightly lower than the
June 2019 output of 3,918 kb/d even though Chinese oil companies have increased their spending
to reduce the decline rate.
Kazakhstan production hit a new output high in February, 1,976 kb/d. For May, production
dropped by 203 kb/d to 1,738 kb/d. OPEC expects their output to drop by an average 15 kb/d this
year.
Mexicoʼs production decreased in May by 85 kb/d to 1,686 kb/d, according to the EIA.
Data from Pemex shows that production dropped to 1,647 kb/d in July (red square). Under the
OPEC + Declaration of Cooperation, Mexico committed to reduce output by 100 kb/d in May. Their
target was almost met.
The EIA reported that Norway's May production was 1,775 kb/d, a decrease of 14 kb/d from
April.
According to the Norwegian Petroleum Directorate, "average daily liquids production in July
was: 1 739 000 barrels of oil, 296 000 barrels of NGL and 27 000 barrels of condensate. (Red
lines)
On 29 April 2020, the Government decided to implement a cut in Norwegian oil production. The
production figures for oil in July include this cut of 134 000 barrels per day in the second
half of 2020."
In other words, if Norway hadn't made their commitment to reduce production, May's oil
output would have been (1,739 + 134) 1,873 kb/d. This output level would have been very close
to some earlier highs.
According to the Russian Ministry of energy, Russian production increased by 479 kb/d in
August to 9,860 kb/d. July was revised up by 11 kb/d from 9,371 kb/d to 9,382 kb/d.
UKʼs production decreased by 63 kb/d in May to 1,004 kb/d. According to OPEC, crude
production is expected to increase to 1,010 kb/d in June (Red square).
June's production rebounded from May's low by adding 420 kb/d according to the the EIA's
August report. May's output was revised up by 15 kb/d in the EIA's September report.
US and Permian oil rigs decreased by 1 to 179 and 121 respectively in the week of September
18. As a percentage, Permian oil rigs represented 67.5% of the total for the week of Aug
21.
According to the September DPR, the 121 rigs operating in the Permian in September will be
sufficient to raise production in September by 42 kb/d to 4,150 kb/d.
While WTI has remained close to $40/bbbl, there has been essentially no change in drilling
activity since the week of July 17 in the US. There were 180 oil rigs in operation that week vs
179 for the week of September 18.
These five countries complete the list of Non-OPEC countries with annual production between
500 kb/d and 1,000 kb/d. All five are in overall decline. Their combined May production was
3,263 kb/d down 232 kb/d from April's output of 3,495 kb/d. Azerbaijan, Indonesia and India
appear to be in a slow steady decline phase. Columbia's production began to drop in March as
Brent prices began to drop.
According to Colombia's minister of energy, Maria Fernanda Suarez, ANH president Armando
Zamora said if Brent oil prices hit around $35 a
barrel national oil output could average around 850,000 barrels a day, down from a previous
forecast of 900,000 barrels.
Guyana is a new oil producing country that started production in December 2019. According to
this s ource
, production was supposed to reach 120 kb/d by June. However gas re-injection issues have
delayed its planned production rise. Output in June is expected to be close to 80 kb/d (red
square). This new source for oil will offset some of the decline in other countries, which
currently is close to 400 kb/d/yr.
NON OPEC W/O US PRODUCTION
This chart shows that oil production in Non-OPEC countries has only increased by 541 kb/d
from December 2014 t0 December 2019. It is an indication that these countries as a whole are
approaching an output plateau. April is the first month in which the large production drop
associated with CV-19 and the plunge in oil prices shows up in this chart. In May 0utput from
these countries dropped by 3,293 kb/d to 35,348 kb/d.
Using information from the September STEO, output from the Non OPEC countries W/O the US, is
expected to rebound to 37,054 kb/d in September (red square). Looking further out to October
2021, output is predicted to reach 39,692 kb/d. (Blue graph). Note that the October 2021 high
is currently expected to be 143 kb/d lower than the December 2019 peak. The 143 kb/d difference
is probably well within the margin of error in making these projections.
World Oil
Production
World oil production in May decreased by 11,417 kb/d to 71,374 kb/d. This chart also
projects world production out to October 2020. It uses the September STEO along with the
International Energy Statistics to make the projection. It projects that world production will
recover by close to 5,000 kb/d in October 20202 to 76,019 kb/d.
This chart presents world oil production without the US. Note that the November 2016 peak is
two years prior to all the worldʼs peak shown in the previous chart. May production was
61,372 kb/d, a decrease of 9,429 kb/d from April.
Using the STEO and the EIA international Energy Statistics, output for September is
projected to be 63,768 kb/d, an increase of 2,396 kb/d higher than May.
1. Shale bust is here
- Shale wells decline somewhere between 70 and 90 percent from their initial peak within 3
years, with the bulk of that decline coming within the first 12 months.
- As a result, the pause in drilling quickly translates into U.S. oil production declines.
- "We just have no new drilling and these decline curves are going to catch up," Mark Rossano,
founder and chief executive officer of private-equity firm C6 Capital Holdings LLC, told
Bloomberg. "That hits really fast when you're not looking at new production."
- With no drilling at all, U.S. shale oil production would theoretically fall by more than a
third to less than 5 mb/d by the end of the year.
2. Bankruptcies to spike
- Between 2015 and 2019, there were roughly 200 bankruptcies in the North American oil and gas
sector.
- Through April of this year, there have been another 7 bankruptcies, according to Haynes and
Boone, although the value of the debt involved is 2.8 times larger compared to the first
quarter bankruptcies in 2019.
- Around 70 companies are on track for bankruptcy by the end of the year with WTI averaging $30
per barrel, according to Rystad Energy. If WTI remains stuck at $30, that total would rise to
150 to 200 by the end of 2021.
- "In our view, we will need WTI prices of $40 to $45 per barrel to eliminate the upcoming
explosion in the number of financially distressed US E&Ps, https://oilprice.com/Energy/Energy-General/The-Shale-Bust-Has-Arrived.html
It's now canonized in American public opinion, as the NYT has published an authorial
article (in the pedantic upper middle class I-wanna-win-a-Pulitzer style) about it:
For
most any nation, let alone a superpower, energy independence is considered the geopolitical
holy grail. So when fracking lured in American investors, everyone had high hopes the country
would finally break free of OPEC. But oil is a complex game, and 2020 saw sharp declines in
demand caused by the cartel's maneuvering, shale oil's oversupply, and now the devastating
effects of the coronavirus. What's worse, the startup mentality of the U.S. fracking industry
promised investors mythical growth and nonexistent returns. In the end, it burned a $340
billion hole in Wall Street's pocket. (Source: Bloomberg)
"... "Well, I think it's automatic. Because they're already cutting. I mean, if you look, they're cutting back. Because it's it's market. It's demand. It's supply and demand. They're already cutting back, and they're cutting back very seriously," ..."
The United States is on track to cut 1.7 million barrels of oil production per day,
according to Reuters calculations of state and company data shared on Thursday. It was US
President Donald Trump that suggested
at the beginning of April, prior to the most recent OPEC deal signing that the United
States would cut its oil output as a natural response to the worsening market conditions. The
statement was not initially good enough for OPEC, who wanted more of a commitment from the
world's largest producer and consumer of crude oil.
"Well, I think it's automatic. Because they're already cutting. I mean, if you look,
they're cutting back. Because it's it's market. It's demand. It's supply and demand. They're
already cutting back, and they're cutting back very seriously," US President Trump said at
a press briefing early last month.
US Energy Secretary said last month that the DoE expected that production in the United
States would fall by between two and three million bpd by the end of the year -- it appears the
cuts have come even quicker than the department expected.
The need for the production cuts grew more evident as the United States shut down nearly all
activity in an attempt to flatten that curve of infections that sought to overwhelm the
country's healthcare system. Doing so, however, has idled much of the economy and crippled
demand -- and as such, its oil and gas industry that fuels that economy.
The cuts from US producers may seek to quiet the disgruntlement of OPEC and Russia, in
particular, who expressed their displeasure that the US would not require its producers to curb
production. After all, the US shale industry has benefited greatly from previous rounds of OPEC
cuts.
On Monday, the price of West Texas Intermediate petroleum fell below
$30 a barrel for the first time in four years.
Elliot Smith at CNBC reports that BP CFO Brian Gilvary is braced for petroleum demand
actually to contract in 2020.
This prediction is very bad news for US fracking firms, most of which need a price point of
from $40 to $60 a barrel to make their hydraulic fracturing method of oil production
profitable.
In the Democratic primary debate on Sunday, Bernie Sanders pledged to ban fracking entirely,
and even Joe Biden said no
new fracking would be allowed. Fracking may be moribund anyway by November, and if a
Democrat wins the presidency, the industry may never recover.
Not only is petroleum likely headed way below that profitability floor, but many energy
firms involved with fracking are deeply in debt, and had taken out the debts with their
petroleum fields as collateral. Since their collateral is worth only half what it used to be,
the banks will call in their loans. Other energy firms involved in fracking have held
significant assets in their own stocks, the price of which just zoomed to earth like a crashing
meteor.
Fracking has been banned by countries such as France, and by states such as New York because
it is highly polluting, leaving behind ponds of toxic water. Moreover, research has
demonstrated that the process of fracking, which involves pumping water under high pressure
underground to break up rocks and release oil or natural gas, causes gargantuan
methane emissions that had earlier been underestimated as much as 45% . The
methane in the atmosphere is burgeoning, and scientists had puzzled over why. But scientists
have fingered the culprit: fracking. Methane is 80 times as potent a heat-trapping gas as
carbon dioxide over two decades, and carbon dioxide is no slouch. A quarter of the global
heating effect of greenhouse gas emissions put out by humans burning fossil fuels is owing to
methane emissions. Rapid heating is melting the North and South Poles, causing sea level rise
that will soon be calamitous.
Given that the world population is increasing and that developing countries such as China
and India and Indonesia are seeing more and more people abandoning their bicycles or bus rides
for mopeds or automobile ownership, for the world to want less petroleum this year than it did
last is extremely unusual.
We are getting a preview courtesy COVID-19 of what will happen through the next decade and a
half as electric vehicles take off, significantly reducing demand.
The world produces about $100 million barrels of petroleum a day, and given the Saudi
determination to expand production starting on April 1, it could be producing 102 million
barrels a day later this spring. The world may only want
90 mn. barrels a day this spring. What with the novel coronavirus pandemic, fewer trucks
and cars will be on the road. Petroleum is largely used for transportation fuel.
Do you know what happens if demand falls and production increases? The price falls. In fact,
it doesn't just fall. It collapses. It takes a deep dive. It falls off a cliff. It craters deep
beneath the earth's crust.
How steep the fall is depends in part on whether Saudi Arabia and Russia keep playing
chicken. Saudi Arabia wants to discipline Moscow, which rejected OPEC + production quotas aimed
at reducing supply and supporting a $60 per barrel price. So Riyadh is opening the spigots,
upping its production by two million barrels a day. Saudi Aramco says it is comfortable with a
price point of $30 a barrel. But unfortunately for Aramco, the price may not have stopped
falling.
Andreas de Vries at
Oilspot.com believes the price could fall to as little as $10 a barrel later this spring.
In 2019 the price tended to be around $60 a barrel.
The fossil fuel companies that lack deep pockets could well just fail this year.
Brenda Sapino Jeffreys quotes Jason Cohen, an attorney at Bracewell in Houston, as saying
of the oil industry, "There is, I'd say, a sellers market for bankruptcy talent." His
observation gave me my title.
This steep decline in stock prices and oil prices comes on top of a 5-year run in which the
market has destroyed 90% of the value of US investor stocks in oil services. That is, we could
this year be entering an oil market crisis as severe as the
Asian banking crash of 1997-1998 .
The difference is that by the time fossil fuels come out of their economic doldrums,
renewables will have stolen a further march on them. From here on in, hydrocarbons are
beginning their death spiral. Friends don't let friends invest in petroleum companies, and
nobody should have those stocks in their retirement accounts– if they want ever to
retire.
Colonel, you are NOT wrong. The oil business in America is going to take a very long time to
recover. There are complete shutterings of businesses, bankruptcies and more - all while we
were in the middle of a downturn. Personally, I just folded up my tent because my my active
client list went from 21 to zero over this last month (and that includes intl clients).
As the number one buyer of US steel, the oilpatch represents much more than people
realize. We have also been the number one buyer of many other items - where sales have
disappeared as company quietly and reluctantly face the reality of the current induced
glut.
I'm being forced to change livelihoods - interesting for me, as I am short of the age to
get my SS check and too old to employ by most corporate masters....
div
This (oil + the virus) is looking like an economic Pearl Harbor for shale oil industry
This (oil + the virus) is looking like an economic Pearl Harbor. I think BRICS is playing a
far better game of chess so far and will win if we don't replace The Swamp with dedicated
people with vision and smarts and who put country above cronyism and self-enrichment.
What has the fluctuating price of oil got to do with peak oil? One is reflection of demand,
plus manipulation of the price by producers, and the other has to do with the long term rates
of extraction relative to the creation of new reserves by deposition of marine micro-organism
and there decay under pressure and temperature conditions only geological time scales. the
two are as similar as the price of fish and oranges.
You were spot on about Peak Oil. US shale will not die. While shareholders and bond
holders will take a haircut today, the extraction technology will continue to improve and
their costs of production will decline. As oil prices improve shale production will return.
The US is in a strong position as it doesn't have to be concerned about oil at least for the
next several decades.
From a supply/demand perspective, oil density in the west will continue to decline as our
economies become more efficient and as solar and nuclear becomes more cost competitive for
electricity generation.
An investment maxim is to buy when there's blood in the streets. We will continue to use
oil for at least another couple generations IMO.
The big issue in the short term is going to be the drastic impacts for those economies
entirely dependent on crude revenues. The last time crude prices were lower for a sustained
period the Soviet Union collapsed. MbS is running massive budget deficits as he keeps his
population from revolting against the monarchy. One possible good outcome is there's going to
be less funding for the jihadists in the short term.
There is oil out there and there will be for a long, long, time. The only determining factor
is the price to get it out of the ground. Here in North America fracking has opened the
spigot but the price is $40+ a barrel to get it out of the ground.
What I can't fathom is why Canada is pushing through with the Keystone XL pipeline taking
tar sands oil from Alberta to Nebraska and eventually to the gulf coast.
Obama put the stop to it but the Trumpster reversed his executive order and they started
building again this month, although a federal judge just stopped it due to environmental
review.
Several years ago I read that tar sands oil costs $70+/barrel and that doesn't include
shipping cost. Does Canada know something about the future price of oil or are they just
subsiding their oil companies/workers? I sure wouldn't invest in it.
"... JPMorgan Chase & Co, Wells Fargo & Co, Bank of America Corp and Citigroup Inc are each in the process of setting up independent companies to own oil and gas assets, said three people who were not authorized to discuss the matter publicly. The banks are also looking to hire executives with relevant expertise to manage them, the sources said. ..."
"... U.S. oil and gas producers have increasingly relied on banks for cash over the past year, as debt or equity options dried up. Lenders have been conservative in valuing hydrocarbons used as collateral, but recent restructurings have left them spooked. ..."
NEW YORK (Reuters) - Major U.S. lenders are preparing to become operators of oil and gas
fields across the country for the first time in a generation to avoid losses on loans to energy
companies that may go bankrupt, sources aware of the plans told Reuters.
JPMorgan Chase & Co, Wells Fargo & Co, Bank of America Corp and Citigroup Inc
are each in the process of setting up independent companies to own oil and gas assets, said
three people who were not authorized to discuss the matter publicly. The banks are also looking
to hire executives with relevant expertise to manage them, the sources said.
The banks did not provide comment in time for publication.
Energy companies are suffering through a plunge in oil prices caused by the coronavirus
pandemic and a supply glut, with crude prices down more than 60% this year.
Although oil prices may gain support from a potential agreement Thursday between Saudi
Arabia and Russia to cut production, few believe the curtailment can offset a 30% drop in
global fuel demand, as the coronavirus has grounded aircraft, reduced vehicle use and curbed
economic activity more broadly.
Oil and gas companies working in shale basins from Texas to Wyoming are saddled with
debt.
The industry is estimated to owe more than $200 billion to lenders through loans backed by
oil and gas reserves. As revenue has plummeted and assets have declined in value, some
companies are saying they may be unable to repay.
Whiting Petroleum Corp became the first producer to file for Chapter 11 bankruptcy on April
1. Others, including Chesapeake Energy Corp, Denbury Resources Inc and Callon Petroleum Co,
have also hired debt advisers.
If banks do not retain bankrupt assets, they might be forced to sell them for pennies on the
dollar at current prices. The companies they are setting up could manage oil and gas assets
until conditions improve enough to sell at a meaningful value.
Big banks will need to get regulatory waivers to execute their plans, because of limitations
on their involvement with physical commodities, sources said.
Banks are hoping their planned ownership time frame of a year or so will pass a Federal
Reserve requirement that they do not plan to hold assets for a long time. Because lenders would
be stepping in to support part of the economy that is important to any potential rebound, and
which has not gotten direct bailouts from the federal government, that might help applications,
too.
For now, the banks are establishing holding companies that can sit above limited liability
companies (LLCs) containing seized assets. The LLCs would be owned proportionally by banks
participating in the original secured loan.
To run the oil-and-gas operations, banks might hire former industry executives or specialty
firms that have done so for private equity, sources said. Houston-based EnerVest Operating LLC
would be among the most likely operators, sources said.
"We regularly look for opportunities to operate on behalf of other entities, that is no
different in this market," said EnerVest Operating's chief executive, Alex Zazzi.
GETTING ASSERTIVE
U.S. banks have not done anything like this since the late-1980s, when another oil-price
rout bankrupted a bunch of energy companies. More recently, they have relied on restructuring
processes that prioritize them as secured creditors and leave bondholders to seek control in
lieu of payment.
But banks are becoming more assertive because of the coronavirus recession and balance sheet
vulnerabilities that have developed in recent years.
U.S. oil and gas producers have increasingly relied on banks for cash over the past
year, as debt or equity options dried up. Lenders have been conservative in valuing
hydrocarbons used as collateral, but recent restructurings have left them spooked.
Alta Mesa Resources' bankruptcy will likely provide banks with less than two-thirds of their
money, while Sanchez Energy's could leave them with nothing.
The structures banks are setting up will take a few months to establish, sources said. That
gives producers until the fall - the next time banks will evaluate the collateral behind energy
loans - to get their houses in order.
After several years of on-and-off issues with energy borrowers, lenders have little choice
but to take more dramatic steps, said Buddy Clark, a restructuring partner at law firm Haynes
and Boone.
"Banks can now believably wield the threat that they will foreclose on the company and its
properties if they don't pay their loan back," he said.
(Reporting by David French and Imani Moise in New York; Additional Reporting by Elizabeth
Dilts Marshall; Editing by Leslie Adler; Editing by Lauren Tara LaCapra)
Trump announced that he would use the cheap prices to fill the U.S. strategic oil reserve.
But the spare room in the reserve storage at that time was only some 150 million barrels.
As it can only be filled at a rate of 2 million barrels per day the topping off of the
reserve is insignificant in the current market.
The oil producers at first pumped their oil into storage tanks to be sold later. When
those filled up they rented supertankers to store the oil at sea. But empty supertankers
are now also getting rare and the price for them
is increasing :
The CEO of the world's largest tanker owner, Frontline Ltd., said on Friday that he'd
never known such demand to hire ships for long-term storage. Traders could book ships to
put 100 million barrels at sea this week alone, he estimated, but even that could
accounts for less than a week's oversupply.
The only solution will be a shut down of the more expensive oil fields. Canada and
Brazil are already doing it. U.S. shale producers who are bleeding cash will now have to
follow.
As soon as U.S. shale leaves the market, prices will rebound and could reach $60 a
barrel, Rosneft's Igor Sechin said recently. As fate would have it, in what many would
have until recently considered an impossible scenario, a lot of U.S. shale might do just
that.
Breakeven prices for U.S. shale basins range between $39 and $48 a barrel, according
to data compiled by Reuters. Meanwhile, West Texas Intermediate (WTI) is trading below
$25 a barrel and has been for over a week now.
The Trump administration has asked the Saudis to
produce less oil but as the Saudi tourist industry is currently also dead the Saudi clown
prince needs every dollar he can get. The Saudis will continue to pump and they will sell
their oil at any price.
The White House is now concerned that it will completely lose its beloved shale oil
industry and all the jobs connected to it.
A new OPEC+ deal to balance oil markets might be possible if other countries join in,
Kirill Dmitriev, head of Russia's sovereign wealth fund said, adding that countries
should also cooperate to cushion the economic fallout from coronavirus.
...
"Joint actions by countries are needed to restore the(global) economy... They (joint
actions) are also possible in OPEC+ deal's framework," Dmitriev, head of the Russian
Direct Investment Fund (RDIF), told Reuters in a phone interview.
...
"We are in contact with Saudi Arabia and a number of other countries. Based on these
contacts we see that if the number of OPEC+ members will increase and other countries
will join there is a possibility of a joint agreement to balance oil markets."
Dmitriev declined to say who the new deal's members should or could be. U.S. President
Donald Trump said last week he would get involved in the oil price war between Saudi
Arabia and Russia at the appropriate time.
A logical new member of an expanded crude oil cartel would be one of the biggest global
producer that so far was not a member of that club - the U.S. of A.
We now learn that Trump is ready to talk about
that or other concepts:
As Ria reports (in Russian) the
topics of upcoming phone call [between Putin and Trump] will be Covid-19, trade (???)
and, you guessed it, oil prices.
Trump, who sanctioned the Russian-German Nord-Stream II pipeline while telling Germany
to buy U.S. shale gas, is now in a quite bad negotiation position. Russia does not need a
new OPEC deal right now. It has many financial reserves and can live with low oil prices
for much longer than the
Saudis and other oil producing countries. Trump would have to make a strategic offer
that Russia could not resist to get some cooperation on oil prices.
But what strategic offer could Trump make that would move Putin to agree to some
new deal?
Ukraine? Russia is not interested in that
unrulable , bankrupt and fascist infested entity.
Syria? The Zionist billionaires would stop their donations to Trump if he were to give
up on destroying it.
Joining an OPEC++ deal and limit U.S. oil production? That would be an anti-American
intervention in free markets and Congress would never agree to it.
And what reason has Russia to believe that Trump or his successor would stick to any
deal? As the U.S. is non-agreement-capable it has none.
The outcome of the phone call will therefore likely be nothing.
The carnage in the oil markets will continue and will ravage those producer countries
that need every penny while the corona virus is ravaging their people. Meanwhile the U.S.
shale market
will go bust . US financial companies had a big exposure to the Shale Oil frackers.
Good thing trillions of dollars of 'liquidity' has been shoveled their way.
FWIW:
One aspect of the crude complete collapse is to keep an eye on futures and the serious
contango at the moment: contango=prices on future contracts are higher than current
contract.
e.g. May 2020 CL contract=~$20, May 2021 =~$35.50.
Someone or someones are betting that the crude market will improve, i.e. they are
storing crude in very large crude carriers (VLCC) @>$200k per day lease cost. That is a
serious commitment/bet on future price/mkt improvement.
Unmentioned is the connection between Fracking Fraud and the Bond Market Bubble with
Congress actively intervening/abetting the Fraud by providing more money to the Ponzi
Scheme.
It was time. The shale industry already was a huge bubble even when oil prices were at USD
60.00 (because it had to borrow a lot to invest, and the more wells drilled, the lower was
the oil output per USD invested), which insiders in Wall Street were already discussing how
to burst it.
And this is a 100% intentional by the Russians. If American shale really go down, then
it would be ironic, since it was the oil crisis of 1975 that effectively ended the Soviet
Union.
Another factor going against the shale fracking pipe dream is that the Strategic Petroleum
Reserve (SPR) is filled with real oil. Fracking produces light condensate (not oil) that
does not meet this criteria, and thus the frackers will not benefit from filling the SPR
(unless Trump changes the rules)
A study by the Wall Street Journal concluded that in one ten year period, the shale oil
companies' total costs had exceeded their revenues by two hundred and eighty billion
dollars. They have stayed in business by issuing new stock and more debt to cover their
losses. Their prime fields are seeing production declines. Their costs are rising as the
price of is oil tanking. Collapse is imminent. It's going to have far-reaching
consequences.
Yet another example of the utter intellectual bankruptcy of the US ruling class. They've
been playing a rigged game for so long, they've forgotten how to think.
As others here have pointed out, not to worry, the US fracking industry will get bailed
out.
The real thing the US might do, is not to join an expanded OPEC+, but to limit imports
of foreign oil and protect the domestic industry. Contrary to current 'free trade' dogma,
protectionism does work (example A: the United States from 1776 to 1970. Any questions?),
but classically you want to limit imports of MANUFACTURED goods and keep the cost of raw
materials low. Increasing the relative costs of raw materials in the US while still
allowing mass importation of manufactured goods from low-wage nations is anti-Hamiltonian
and will crush what remains of US domestic manufacturing..)
Not sure the US shale market can "go bust" as such. The owners can go bankrupt, but that
just means banks and bondholders become the new owners, and their debt investment suddenly
turns into equity investment with zero gearing. Once that happens the US shale producers
become solid companies financed with zero debt and no incentive to hold back on production.
They pump and pump and pump until the pumps no longer work.
Sure, no new developments, but the existing infrastructure will last a few years yet.
I don't see a way out for the US fracking industry. Their product is too expensive in the
current times, and those setting the rules in these times (Russia and Saud Arabia) have no
good reason to help.
The social damage from a collapse in the US will be papered over with printed money. I
don't know how that will play out.
One scenario is time being called on the US's forever-wars in the Middle East, but would
they be replaced by an invasion of Venezuela? There is good stuff down there, as well as
the heavy stuff they've been pulling out. And just across the border into Brazil there is
some high ground that looks like a good spot to build a command post.
The US could cut its losses in the wider world, something that seems to be happening
anyway, and return to America, north and south. I don't see it just quietly going down the
gurgler, but the European Union might.
Of course it is already a war. The question I ask is, who is fighting and against whom?
The tactical aim at the moment is the end of the petro-dollar. A secondary aim is finding a
limit to US militarism. Which in turn depends on the pork.... soorry.... the grifting of
large sums of unlimited largess. Third, is trade and domination of markets including
sanctions and "treaties". Fourth, is the "domination" of population dissent and overriding
Judicial systems.
So the US, China and Russia are at it "hammer and tongs" (old saying but apt). Covid is
just one means to an end, regime change another. Who else is in the fight? I would suggest
that the Oligarchy and the Termites, the Fed and the deep parallel financial pool, the
uncontrolled but unified intelligence "agencies", all have their own agendas.
"The slow collapse of the US position in Iraq means that the US is not going to hold
those oil-fields for too long."
Remember where this oil is going to. During the previous presidential term, it was
discovered that the oil was going into Turkey, aided and abetted by the profiteers Erdogan
and his son, and then onto oil tankers that shipped it to Occupied Palestine. Current
production is also going into Jordan, where it is being shipped by pipeline into the
refinery in Eliat(?). I can only surmise the price to be extremely cheap.
So the inhabitants of Occupied Palestine will expect the US to maintain this flow as
long as they can, come hell or dead GIs.
The problem with shale became clear right after the first wells were drilled.
If I understood the reports from the "shale bubble" website correctly, originally the
magic over shale gas and oil came from the fact that Wall Street was involved since the
beginning (so it was a "coastal elites/heartland rednecks alliance" from birth) and the
expectation was that a horizontal well would perform the same way as the traditional
vertical well.
A traditional vertical well follows are normal curve graphic, imitating a hill. It
starts low, but keeps growing until reaching a peak, maintains this peak for a while (some
decades) and then begin a suave fall, which also takes decades.
No wonder, then, the huge euphoria that started in Wall Street when those horizontal
wells begun pumping out oil at absurd quantities - they imagine that was the output floor
of such wells, and that productivity would only rise after the decades. Indeed, it was
predicted at the time that the USA not only was firmly walking towards self-sufficiency -
many also predicted it would become the world's greatest oil exporter (yes, above Saudi
Arabia, Venezuela, Russia etc.).
But this euphoria was short-lived, as, some years later, productivity of the horizontal
wells begun to suddenly fall. It was then realized, after further research, that those
wells performed differently than the vertical wells: they begun directly with peak
production, then immediately started to fall. Their output graphic looks like an
upside-down, slightly inclined letter L.
Even after this discovery, the investors didn't immediately give up. They thought: let's
just drill longer wells. And they did. It was then that another problem came out: it seems
that, after 3-5 miles, those horizontal wells suddenly lose a lot of pressure necessary to
pump the oil out of it. To make things worse, after this length, they begin to suck out
pressure from the neighboring wells as well. Therefore, it is a self-defeating enterprise
to extend the horizontal wells beyond 3 miles length. And the situation is even direr
because shale reserves are usually concentrated in one specific area - it's not like you
can drill one horizontal well in Ohio and another one in Florida and so on: the rule of
thumb that the oil and gas "must be there" to be extracted in economically viable
quantities still do apply to horizontal wells.
After that, all that kept the American shale industry alive was Wall Street and its
rotten papers recycling machine.
A friendly reminder to all barflies that fracking within the Outlaw US Empire also takes
more energy to operate than the energy extracted. The business was bankrupt before it
began, and nothing can change that fundamental fact.
"I believe that yuan pricing of oil is coming and as soon as the Saudis move to accept it
-- as the Chinese will compel them to do -- then the rest of the oil market will move
along with them," Carl Weinberg, chief economist and managing director at High Frequency
Economics, told CNBC
Also, recall the recent ARAMCO IPO, reportedly China took a 5 % stake. Hmmm. Was it with
USTs?
The minute the Al Saud family begins accepting yuan for oil their days are numbered.
The US put them there, put the Saudi in Saudi Arabia. Any move to accept yuan will be seen
as betrayal, and the Al Sauds will be removed, either replaced or simply obliterated.
Posted by: Realist | Mar 30 2020 23:21 utc | 86
+++
If Saudi Arabia shifts to the Yuan, it would have to diversify away from buying US arms.
They might be the undisclosed buyer of high-end Chinese missiles, said to have an "urgent
need" for them, as per Chinese media on 2020/3/29. This news might be functioning as
diplomatic signalling.
It was the first time a third-generation anti-tank weapon system developed by the Chinese
company has been exported, according to the statement.
As the client was in urgent need of the missiles, the successful delivery had
significant meaning for establishing Norinco's (China North Industries Group Corporation)
market position and further opening up the market, the company said.
Norinco did not disclose more details on the deal in the statement, including the name
of the buyer, the quantity purchased and the value of the deal.
The US put them there, put the Saudi in Saudi Arabia. Any move to accept yuan will be
seen as betrayal, and the Al Sauds will be removed, either replaced or simply
obliterated.
You hug that thought. Newsflash: The horses camels have already bolted. China is
expanding its presence/influence in ME.
These 35 agreements with KSA,'centered around ways to align the Saudi Vision 2030 with
the Chinese Belt and Road Initiative' will not be in USD - unless China is unloading USTs.
There is nothing US can do except sell more arms to the kingdom. Reuters, WSJ reported the
big signing and likely, CNN, Fox, ABC buried it.
The meeting took place in the grand surroundings of the Great Hall of the People in
the Chinese capital Beijing. After their talks, the crown prince headed the Saudi
delegation at the third session of the China-Saudi Arabia High-Level Joint Committee
which he co-chaired with Zheng.
Delegates at the meeting discussed moves to strengthen cooperation between the two
countries on trade, investment, energy, culture and technology, as well as the
coordination of political and security matters. The committee also reviewed plans for
greater integration between China's Belt and Road development strategy and the Saudi
Vision 2030 reform program.
After agreeing on the minutes of the meeting, the Saudi royal and Zheng took part in
the signing of a range of agreements, memorandums of understanding (MoU), investment
projects and bilateral cooperation accords between the Kingdom and China:[.]
MoU between the Kingdom's Ministry of Energy, Industry and Mineral Resources and the
National Development and Reform Commission in China, signed by Saudi Energy Minister
Khalid Al-Falih and Ning Jizhe, vice chairman of the National Development and Reform
Commission.
MoU between the Chinese Ministry of Commerce and Saudi Ministry of Commerce and
Investment to form a working group to facilitate trade, signed by Abdul Rahman Al-Harbi,
the Kingdom's deputy minister of commerce and investment, and Qian Keming, Chinese vice
minister of commerce.[.]
Deciphering the mental processes of MBS is always speculative, but it is very hard for KSA
to deliver on the threat to increase the deliveries by 2.5 mln bbl/day. As we can see,
planes fly only a fraction of pre-virus level, people on quarantine drive much less, you
can offer fuel for free and it will not sell more. Now, if you could offer some hand
sanitizer and facial tissues with each "full tank", perhaps it could work... But stopping
oil production is troublesome for some reasons, to the ignorant me it seems that if you
interrupt flow dynamic of oil, it is troublesome to restart it, shale oil may suffer from
something similar. Thus tanker ships are being filled up and used for storage as
destination ports refuse to take cargoes invoking "higher power". Hapless KSA cannot find
enough tankers, and when they find them, hard to find a port to accept them. So KSA
combative threat could impact psychology of the traders, but the virus made a dent in
demand of several times larger magnitude.
Nobody knows how long the demand will stay low, but as it does, storage will be
bursting, renting tanker ships became expensive. so the glut it will take time to dissipate
(folks renting the tanker ships will be pressed to get rid of the cargoes at the first
opportunity), and with no coordination to cut the production, low prices may stay for a
year or more. This seems necessary to cut shale oil and other high cost oil project down to
size. Periodic down period of pricing does not change long term calculations, but long
periods will drive a lot of small players out of business. This means so-called
consolidation, creditors become owners and sell it to vultures (regular folks cannot own
something that costs more to maintain than it brings revenue). And what do the vultures do?
"Paring excess capacity". Happened to many industries in the past. And even brainless
bankers will give it two thoughts before lending money for projects in high cost oil
production.
BTW, Putin is doing a gently MBS-like manouver, with the assist from Trump. To wit,
Russia started to tax repatriated profits -- no need to imprison the account holders in
Ritz Carton. But why would they be motivated to repatriate the profits back to Mother
Russia? A patriotic virus? Or pestering with account freezes that Trumpian robbers are so
fond of doing?
One mystery for me is why Canadians bother to produce oil with single-digit prices.
Stopping tar oil production should be simple, just mothball the equipment.
One rumour in the oil patch is that USG will give them bail out. That could be a boon
for green thinking idealists who are hostile to carbon energy production, because many
deplorables do not like bailout (unless they are the beneficiaries). This could allow Trump
to be defeated by a brain dead opponent.
"Bloomberg reports that Plains All American Pipeline asked its suppliers to scale back
production,
and Plains and Enterprise Products Partners is requiring customers to prove they have a
buyer or place to offload the crude they are shipping
The companies made the requests during the past week.
This is a clear sign that a growing glut of crude is overwhelming storage capacity.
Pipeline companies are running out of storage space for oil. Coronavirus related lockdowns
are resulting in plunging demand."
It is payback time for Russia no doubt, but Russia plays always the long game, any decision
or concession will always be related to the long game. for Russia, which is the global
leader in energy supplier (oil, gas & nuclear).
Russia got really mad with the Nordstream II delay, this is something Russia will not
forget that easy, besides costing them a lot, it was some sort of global humiliation, that
combination is pure fire. Even if the sanction are lifted now, Nordstream would start late
2020 and not late 2019....1 year delay anyway, so lifting sanctions won't matter here.
My first reaction is that Russia will not agree with the USA in anything, it will drive the
shale market dry for a little longer, it must if it wants to cause long term problems for
the players in the US, so no short term relieve for the shale players here, and if Russia
does agree in the OPEC++ with the US and other export players then this will take time, and
then US Gov can not intervene in the local production, more time...and no results, at the
end the US will have to give up something, and I do not think lifting sanctions will be it,
they may try it, bit it has no real value for Russia....only a global military retreat,
something that will cost dearly, politically and in image will. serve Russia and its key
strategic ally...China, mind you that cheap oil and gas helps China's recovery...March nbrs
came in from China and it has already shown a better recovery than expected.
This is the only way I can see Russia playing the long game, together with China and a
major strategic geopolitical defeat for the US.
They're going to have to bail out/nationalize the shale oil industry.
Or "They" could just ignore it.
It has achieved these outcomes – despite steep decline rates and a constant need
for huge numbers of new wells – through massive levels of junk debt forced into
existence by almost zero interest rates and by having little to no profits since 2008.
Sounds like a really rotten business model. "steep decline rates and a constant need for
huge numbers of new wells" describes an industry in eclipse, to put it kindly.
The break-even for shale oils wells varies, but $70 a barrel is a good average
figure.
Even worse. This 'business' is essentially fake and should be shuttered. Every dollar
thrown at it will be wasted. If everything in the world somehow reverses itself one day and
shale oil is once again needed, we can restart it. Won't happen, though. Obsolete.
@Kim One part of the New Deal, that seemed to work very well for all parties concerned,
was the Department of Agriculture's willingness to buy up excess grain/dairy production in
order to encourage an ample supply of grain/dairy and a sustainable price, so that farmers
could get out of the boom/bust cycle. These excess stores were intended to provide supplies
when weather or disasters disrupted the harvests. The AG Dept. also established guidelines
for farmers on how much acreage should be allocated to which type of food product, based upon
its own estimates of aggregate demand and needs for strategic reserves. It even paid farmers
to keep acreage fallow at times.
The Department of Energy could do something similar (provided the Congress should
legislate it). For this to work, the government must limit foreign sources from supplying the
US markets to serve only as augmentation to US energy production whenever/wherever the US
energy producers can't meet the demand at the price level that the Energy Department sets. If
the price is determined on an average COST+ ROI basis, our energy producers would effectively
become utilities.
They're going to have to bail out/nationalize the shale oil industry.
Why? These were private failed investment decisions, so let the industry go bankrupt along
with their shareholders and junk bond investors.
The world doesn't need oil supplied at $70 – And what has this got to do with the US
public? They didn't make these shale oil investment decisions.
TBTF (Too Big To Fail) is another fake argument. If the investment banks had been allowed
to fail in 2008, we would now have a smaller and more prudent banking sector. There are
always some serious banks out there to pick up the pieces.
"The U.S. shale sector is getting completely killed. A complete bloodbath. Billions of
dollars in equity wiped out.
"Occidental Petroleum is down 44%. EOG is down 35%. Continental Resources down 40%.
Smaller players like Parsley down more than 50%."
I suggest this bird look at one of those corp's balance sheets since they had very little
equity but lots of liabilities (Assets=Liabilities+Equity) as Assets and Liabilities where
allowed to grow with the use of interest-free money to keep the Ponzi Scheme afloat. Also
recall that CEOs often get paid in shares which get dividends. Often those dividends are paid
using the zero interest loan money leaving the corp with a bigger, unstable pile of debt and
the CEO with a purse fattened by the loan instead of actual company performance, ie,
profits.
Soon people won't have to worry much about damage from new wells. Instead they will have
to worry about existing-and-soon-to-be-abandoned wells. This is already a huge problem in
Alberta, where "it's estimated that more than 155,000 Alberta energy wells have no
economic potential and will eventually require reclamation".
But not to worry. It will only cost $47 Billion for Alberta to clean up
the mess .
No surprise that it is worse in the US. I couldn't quickly find a cost estimate.
Nobody knows how many orphan and abandoned drilling sites litter farms, forests and
backyards nationwide. The U.S. Environmental Protection Agency estimates there are more
than a million of them. Unplugged wells can leak methane, an explosive gas, into
neighborhoods and leach toxins into groundwater.
"... As Fastow explained, in finance, the difference between a loophole and fraud isn't always easy to identify. And that may be something the U.S. fracking industry is working to its advantage. ..."
Posted on March 6,
2020 by Yves
Smith Yves here. It really is remarkable how super low interest rates have led investors on
a widespread basis to pour money down ratholes. Unicorns is one. Another has been fracking,
which despite being another widespread cash sink, remarkably has kept sucking in funding.
As we pointed out in 2014 :
John Dizard at the
Financial Times (hat tip Scott) gives a more intriguing piece of the puzzle: the degree
to which production is still chugging along despite it being uneconomical. The oil majors
have been criticized for levering up to continue developing when it is cash-flow negative;
they are presumably betting that prices will be much higher in short order.
But the same thing is happening further down the food chain, among players that don't
begin to have the deep pockets of the industry behemoths: many of them are still in "drill
baby, drill" mode. Per Dizard:
Even long-time energy industry people cannot remember an overinvestment cycle lasting as
long as the one in unconventional US resources. It is not just the hydrocarbon engineers
who have created this bubble; there are the financial engineers who came up with new ways
to pay for it.
Justin Mikulka argues that one reason these persistently unprofitable fracking companies
keep going is via fraud.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg,
NY. Originally published at DeSmogBlog
In a 2016 interview with Fraud Magazine , former Enron
CFO Andrew Fastow explained what he thought made him so successful while at the former energy
corporation that's now infamous for financial scandal.
"I think my ability to do structured financing, to finance things off-balance sheet and to
find ways to manipulate financial statements -- there's no nice way to say it. Like I said at
the conference, I was good at finding loopholes."
As Fastow explained, in finance, the difference between a loophole and fraud isn't always
easy to identify. And that may be something the U.S. fracking industry is working to its
advantage.
Fastow, the convicted fraudster, does admit that what they did at Enron misled investors.
"We created something that was monstrously misleading, but any one of those deals alone wasn't
necessarily considered fraudulent," he said.
Fast-forward to today and a different part of the energy industry: The U.S. shale oil and
gas industry has lost more than a quarter trillion dollars since 2007, while being sold to
investors as an economic boom, even at oil prices much lower than those of recent years. Does
that financial mismatch seem misleading? Or perhaps, familiar?
In an unexpected twist, Fastow now gives talks to the energy industry on ethical leadership.
Sounding the Alarm
Bethany McLean was the first reporter to question whether Enron was a financially sound
company in a 2001 article
for Fortune magazine. McLean went on to co-author the book The Smartest Guys in the
Room , which documented the fall of Enron due to its fraudulent practices, including the
ones Fastow engineered.
In 2018, McLean also published the book Saudi America , which highlighted many of the
financial challenges the fracking industry has faced. In a recent interview for Texas Monthly's
podcast Boomtown , McLean
explained one of the very accepted and blatantly misleading practices of the fracking
industry:
I'd raise a couple of points. One is that companies have long hyped these break-even
numbers. They say we can break even at $25 a barrel, we can break even at $20 a barrel. And
then you look at their consolidated financial statements and they are losing money. And so
something is going wrong the people called it to me [sic] corporate math or investor
economics. So they were trying to put together these investor pitch decks that would show
investors a set of economics that weren't real. So they would show you that they could break
even on a well at $25 barrel of oil but then yet you'd go to the corporate financial
statements and they were losing money.
Is that a loophole? Where you can openly misrepresent to investors the financial reality of
your business? Or is it fraud?
As more and more players in the fracking industry run out of options and file for
bankruptcy, investors are beginning to ask questions about why all the money is gone.
"This is an industry that has always been filled with promoters and stock scams and
swindlers and people have made billions when investors have lost their shirts."
Much like with the housing crisis that caused the financial crisis of 2008, the fracking
boom has led to Wall Street bankers finding innovative ways to finance a money-losing endeavor.
Some companies are now even
selling bonds based on future well performance , a concept similar to the
mortgage-backed securities that led to the 2008 housing crisis.
Another Wall Street invention is what is called a "special purpose acquisition company" (
SPAC ), or, as they are also known,
blank check companies. The way these investments work is a big bank or private equity firm
backs a management team to raise money for the SPAC with the agreement that the leaders of the
SPAC will then at some point make a "special purpose acquisition" -- which means they will find
an existing company and buy it.
They are called blank check companies because the management is given a blank check to buy
whatever they choose. In the 1980s, the
Wall Street Journal ( WSJ ) noted that "blank-check companies were often associated with
penny-stock frauds." In a 2017 article on the oil industry, the
WSJ reported that " SPAC s were a hallmark of the frothy days before the financial crisis
[of 2008]."
Understandably, SPAC s were often seen as a risky investment, but much like with the housing
crisis, the biggest names on Wall Street are getting involved and giving the concept
legitimacy, with Goldman Sachs starting to back SPAC s in 2016. And new fracking companies have
come about as a result.
Ben Dell, a managing partner at investment firm Kimmeridge Energy, explained one of the
risks of SPAC investments to the Wall Street Journal. " SPAC management teams have an incentive
to spend the money they have raised no matter what, so they can collect fees and pay themselves
a salary and stock options at the company they purchase," Dell said.
" SPAC s are the most egregious example in the industry of executive misalignment with
investors," Dell
told the WSJ .
As I
have previously reported , one of the problems with the fracking industry is that CEO s are
paid very well even when the companies lose money. According to Dell, SPAC s take this problem
to a new "egregious" level.
Alta Mesa: A Star Is Born
To successfully raise money for a blank check company, having some star power in the
management helps. As the Wall Street Journal has noted, investments in SPAC s "
are largely bets on their executives ."
Jim Hackett would seem to be the ideal candidate to lead a SPAC in the fracking industry.
Hackett has an impressive resume: the former CEO of fracking company Anadarko, former
chairman
of the Federal Reserve Bank of Dallas , an executive committee member of the industry
lobbying group American Petroleum Institute ,
and
partner at the major private equity firm Riverstone Holdings.
In 2013 Hackett retired from Anadarko to attend Harvard Divinity School to get a degree in
theology. However, he was still a partner at Riverstone and in 2017 was lured back to the
fracking business to run a SPAC backed by Riverstone.
The SPAC raised a billion dollars while being advised by the biggest names in the business,
including Goldman Sachs and CitiGroup. The initial blank check company was called Silver Run
Acquisition Corp. II .
Hackett used the money to buy two companies in Oklahoma -- an oil producer and a pipeline --
and the new combined company Alta Mesa was valued at $3.8 billion.
The Future Was Bright for Alta Mesa
Hackett and Alta Mesa had big plans for making money fracking wells in Oklahoma, which
included forecasts for big increases in oil and gas production from the newly acquired assets
with very low break-even numbers.
When the Wall Street Journal reported the creation of Alta Mesa,
it noted , "Alta Mesa's core acreage in Northeast Kingfisher County has among the lowest
breakevens in the U.S. at around $25 per barrel, the company said." Because oil was well over
that price at the time, the future looked good, according to Hackett and Alta Mesa. Forbes
reported that Hackett said Alta Mesa's holdings were "oil that will be economic even at $40
WTI [West Texas Intermediate]" and oil has been well over that mark since Hackett made that
statement in 2017.
Like break-even numbers, another area where misleading investors in the oil industry might
be particularly easy is making overly optimistic forecasts about how much oil will be produced
by future wells. The Wall Street Journal
has documented this as a significant problem for the U.S. shale industry.
Description of Alta Mesa assets in investor proxy statement. Credit: Screen capture from
proxy
statement.
In early 2018 when touting the potential of the proposed new company Alta Mesa, Hackett said
that "its average well would produce nearly 250,000 barrels of oil over its life." A year
later, Alta Mesa said it expected those wells would produce less than half that, only 120,000
barrels of oil over the life of the well.
Later in 2019, Alta Mesa filed for bankruptcy after writing down its assets by $3.1 billion.
The billion-dollar blank check had been spent, and it took less than two years to lose it
all.
SEC Investigation and Multiple Investor Lawsuits
Alta Mesa's assets were sold off earlier this year. The SEC declined to comment on the
status of the investigation.
In May 2019,
the Houston Chronicle reported , "Alta Mesa also is facing a series of lawsuits. Some
shareholders are suing claiming they were defrauded and lied to about the value of the company
and its assets when the company was formed."
One lawsuit filed by the Plumbers and Pipefitters National Pension Fund claims that the
proxy statement for Alta Mesa contained materially false and misleading information. That
filing lays out a lot of facts to support that claim.
Yet another lawsuit has been filed against Riverstone for " misleading
statements ."
Investors are saying they were misled by Hackett and Riverstone. The allegations are based
on the claims that were made about how much oil the company could produce. In hindsight, those
claims appeared wildly inaccurate and misleading. But is that fraud? Or just taking advantage
of a loophole?
In January, the Houston Chronicle summed up the situation as it described Alta Mesa's downfall : "It was a dramatic fall from grace after
significantly overestimating its potential in Oklahoma's STACK shale play "
While Alta Mesa is a spectacular example of how fast the fracking business can make large
sums of money disappear after "significantly overestimating its potential," it also likely
marks the beginning of investor lawsuits against many other failing fracking companies with
similar histories.
Learning From Enron
When Jim Hackett decided to go to Harvard Divinity School, several favorable profiles about
his choice were written, including one on the Harvard website.
That article noted that one of the reasons Hackett decided to go to school was because of "the
collapse of Enron, a disaster that he attributed to 'a failure in leadership' among people he
knew well."
The speed with which Hackett and Alta Mesa went bankrupt is remarkable, indicating a likely
failure in leadership.
However, Hackett seems to have learned something from former Enron executive Andrew Fastow:
that there is work for former executives like them to teach the energy industry about ethics
and morality.
Fraud? Or Just a Laughing Matter?
Good reporting is hard work but sometimes involves a bit of luck. Like when a
Wall Street Journal reporter , in a room full of people hired to make forecasts of fracked
oil and gas production, learned about the existence of much more accurate methods for
predicting that oil production. And also learned that with accuracy comes much lower estimates
of shale oil reserves.
The WSJ article that followed quoted Texas A&M professor and expert on calculating oil
and gas reserves John Lee. "There are a number of practices that are almost inevitably going to
lead to overestimates," said Lee. Those are the practices used by the industry, with Alta Mesa
serving as just one example.
Overestimates are why Alta Mesa received funding but now no longer exists.
The Wall Street Journal reported that during a presentation given by Lee, an audience member
"stood up and challenged the engineers in attendance," asking why the forecasters weren't using
accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
" Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal.
Is it misleading to laugh at your company's investors if you know the estimates you are
giving them are inflated, but because you own the stock that benefits from those estimates, you
do it anyway? Is that fraud? Perhaps that depends on if you get you get ethics lessons from
Andrew Fastow and Jim Hackett.
Will the biggest innovation of the fracking revolution be making financial fraud a laughing
matter?
A lot of people on EFT like to talk about how shale is fraudulent. That's simply not
true:
You can't commit fraud when the rules are so lax you can just make shit up and it's still
allowed.
While I've little doubt there is a lot of fraud, so much of the stupidity around fracking
comes down to the old saying that its hard to make a man undrestand something when his job is
to not understand it.
The financing of the oil and gas industry is almost entirely dependent on projections
– projections of flow per well, and projections of future prices. All you need to do is
make a few optimistic projections of one or both, and you've suddenly turned a dud into a
highly valuable asset. Anyone can look at the pricing and question it, but with oil/gas, that
is much harder with 'novel' types of well as there are few if any precedents. So if someone
says 'the well is producing X per day, we can continue this flow for 3 years and when thats
finished, we can drill down another 200 metres and replicate the same flow', there is nobody
to contradict it. The drilling guys aren't going to argue, they want to keep their jobs. The
geologist isn't going to argue, he has his mortgage to pay. The senior manager won't argue,
he wants a promotion. The drilling company owners won't argue, they want to cash out. And the
Wall Street financier won't argue, because he can pass on the risk to the equivelent of the
last booms 'German bankers'.
So when someone like Arthur Berman – a geologist who has continuously being
questioning the underlying geological assumptions – raises concerns – he's
listened to politely, even invited to some conferences, but is otherwise ignored. Because its
not in anyones interest to listen. There is literally nobody who's job it is to shout 'stop'.
So much for self regulating markets.
While there may well be very severe economic consequences if and when this blows up in
everyones face (and I suspect that Covid-19 will be the catalyst for this, oil demand is
collapsing day by day), the big loser is the planet we depend on for our survival.
I live in NY on the PA border. Fracking is still happening south in PA but is only a
fraction of what it once was. If you drive into PA you will see lots full of fracking
materials that have sat there for a long time. At first for about two years it was a boom.
The activity from fracking was amazing. Then as fast as it started it slowed down to a crawl.
There are a few reasons in my opinion. The so called sweet sports were quickly fracked
leaving less attractive sights. It was concealed that a fracked well produced most of it's
gas in the first two years. After that the production from a well dropped off drastically.
Locals soon lost their enthusiasm for fracking.There is still some fracking but it is hardly
noticeable. Local people thought this would be great but attitudes soon soured. A few made
big bucks at the expense of the rest. The fracking was in former coal country. The difference
is coal lasted a lot longer. Now the majority of people in the area oppose fracking. I'm
thankful that NY state banned fracking because of the negatives associated with fracking. I
own 50 acres near the PA border. Before fracking was banned I was constantly hounded by
leasing companies. I refuse to lease because to me my land was more important than a few
bucks. I hope in my life time NY doesn't reverse the fracking ban. On another note there are
wind farms where I live. I would leas to a wind company because there are fewer negatives and
it's less intrusive.
The good news is that if the companies were chasing you, you own the minerals. You can
donate them to a conservation land trust and assure that no mineral extraction takes place,
and get a tax benefit for the foregone production.
It can be argued that the money invested in many fracking companies with such inflated
pay-back periods, ROIs or breakeven estimates, apart from fraud, could be considered as a
private subsidy, just like Uber investors subsidize Uber taxi services. If we can blame it to
low interest rates resulting in such subsidies, for fracking oil, unicorns, education,
housing etc. to my knowledge this has only been argued in very few sites like here at NC or
Wolf Street but merits a close examination. If pension and mutual funds are pouring a lot of
money in such business with low to negative returns what consequences are to be expected in
the future?
Eight to Ten years ago you would have seen giant trucks moving water and dirt from
fracking sites when you got off the turnpike around Donegal PA. Since about 2015 or 2016 i'd
say that completely died. Pittsburgh actually had one year of population gain due to the
fracking boom but thats done. Yves mentioned investors and low interest rates chasing bad
investments and fraud. I'd say the same thing is going on in healthcare based on my exp. of
it and the amount of money floating around. We need higher interest rates to nip this stuff
in the bud and re-balance the economy.
This pretty much says it all regarding the health of our eCONomy, but hey, after it all
falls apart we should have plenty of reformed criminals to teach ethics classes
"The Wall Street Journal reported that during a presentation given by Lee, an audience
member "stood up and challenged the engineers in attendance," asking why the forecasters
weren't using accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
"Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal."
In a 2016 interview with Fraud Magazine,
==============================================
I have to say, I was shocked, SHOCKED to find that there is a magazine actually, only devoted
to fraud – that is published bi-monthly.
AND than I was shocked to find out that the magaine actually, only devoted to fraud is ONLY
published bi-monthly
Is the U.S. Fracking Boom Based on Fraud? Is the Pope Catholic? There are going to have to
be major structural changes in the world's economy in the next few years and with the demand
for oil dropping, prices have gotten cheaper which is turning fracking into a non-profit
industry. In any case, how are you suppose to frack with sick crews? This is one industry
that needs to go away before it causes any more damage. You'd find more honesty in a boiler
room brokerage firm than in this industry.
There's a recent documentary called The Price of Everything that is about the enormous
sums being paid for every latest fad in modern art. The show says that all the great masters,
old and new, have been locked up by museums or the super rich and so a recent flood of new
investors are looking for any excuse to spend lots of money on paintings. Apparently there is
so much money sloshing around at the top of our unequal economy that that these plutocrats
don't even care if they lose their shirts on bad investments. The main thing is to keep it
out of the hands of the poor.
Clearly we as a society are suffering from affluenza, at least among the elites who should
all be virus quarantined and then maybe we will forget to check back.The show tries to
pretend that this money driven art world is a cool thing. It had this viewer thinking of
guillotines.
Yes, like all the people who cannot see the art. It's mostly buried in storage. What is
the point of having over two thousand years of art from multiple civilizations, if most of it
is hidden away and often only known from catalog descriptions or cramped tiny pictures.
You must mean the insiders who suckered the rubes into taking shares off their hands at
the IPO. IIRC the IPO price was over $70/share. Right now it's just under $32 with no signs
of every being a profitable enterprise.
Grifters, charlatans and mountebanks everywhere you look.
Charging mineral resource rent, which everyone has an equal claim to, would help to reduce
the tendency of financial shenanigans. The profit motive is crack to rent seekers.
Speaking of Enron, it is perhaps appropriate that my employer's head of non core assets,
toxic waste for fire sale, came from Enron. Standard Chartered has some, too.
I think the big issue goes back to the investors and bond rating agencies, similar to the
subprime mortgage crisis. If bondholders aren't willing to do the homework, then they don't
get paid for the risk that they are undertaking. with the multiple prediction tools for well
production, you can make up an optimistic and pessimistic case. If the bond yield doesn't
cover that risk to your satisfaction, then you don't buy the bond or you demand a higher
interest yield and lower bond price.
Instead, it seems like the industry is raising money from people who don't want to think
more than a few months ahead on a multi-year investment. The challenges faced by the fracking
industry have been well publicized for several years now. If an investor doesn't understand
those challenges now and isn't looking at specific methods of calculating production yield
etc., then they have only themselves to blame if their investment loses money.
This is a very different issue than if somebody flat out lies about whether or not wells
exist etc.
A single well can make financial sense even if there will never be a net profit from it.
Fracking is pretty similar to the Hollywood film industry where nobody ever has any net
profits despite living high on the hog. "Don't ever settle for net profits. It's called
'creative accounting'." – Lynda Carter: https://en.wikipedia.org/wiki/Hollywood_accounting
I dunno. There may be a sucker born every minute, but I can't picture enough of them
getting born with a million (or billion) Dollars to blow on rackets like this to keep it
going this long.
Sad to see that the Plumbers' Union Pension Fund was a victim; I hope that's not a
pattern, but it would make sense. If it's a pattern, then it's no wonder the Fed tried so
hard to postpone the next Crash until after the elections. How much junk paper has Wall
Street sold to other Pension Funds? States & Municipalities are already squeezed by
"unfunded liabilities"; how much repackaged funky Fracking paper are held by public
(governmental) agencies? Damn, this is gonna be a mess.
I'd advise investing in popcorn, except that my 401k will probably evaporate soon, so
maybe it's pitchforks.
CFO Fastow of Enron. How nice to see him land on his feet. The company made listening to
the rolling blackout reports for California while driving to work a requirement.
Posted on March 6,
2020 by Yves
Smith Yves here. It really is remarkable how super low interest rates have led investors on
a widespread basis to pour money down ratholes. Unicorns is one. Another has been fracking,
which despite being another widespread cash sink, remarkably has kept sucking in funding.
As we pointed out in 2014 :
John Dizard at the
Financial Times (hat tip Scott) gives a more intriguing piece of the puzzle: the degree
to which production is still chugging along despite it being uneconomical. The oil majors
have been criticized for levering up to continue developing when it is cash-flow negative;
they are presumably betting that prices will be much higher in short order.
But the same thing is happening further down the food chain, among players that don't
begin to have the deep pockets of the industry behemoths: many of them are still in "drill
baby, drill" mode. Per Dizard:
Even long-time energy industry people cannot remember an overinvestment cycle lasting as
long as the one in unconventional US resources. It is not just the hydrocarbon engineers
who have created this bubble; there are the financial engineers who came up with new ways
to pay for it.
Justin Mikulka argues that one reason these persistently unprofitable fracking companies
keep going is via fraud.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg,
NY. Originally published at DeSmogBlog
In a 2016 interview with Fraud Magazine , former Enron
CFO Andrew Fastow explained what he thought made him so successful while at the former energy
corporation that's now infamous for financial scandal.
"I think my ability to do structured financing, to finance things off-balance sheet and to
find ways to manipulate financial statements -- there's no nice way to say it. Like I said at
the conference, I was good at finding loopholes."
As Fastow explained, in finance, the difference between a loophole and fraud isn't always
easy to identify. And that may be something the U.S. fracking industry is working to its
advantage.
Fastow, the convicted fraudster, does admit that what they did at Enron misled investors.
"We created something that was monstrously misleading, but any one of those deals alone wasn't
necessarily considered fraudulent," he said.
Fast-forward to today and a different part of the energy industry: The U.S. shale oil and
gas industry has lost more than a quarter trillion dollars since 2007, while being sold to
investors as an economic boom, even at oil prices much lower than those of recent years. Does
that financial mismatch seem misleading? Or perhaps, familiar?
In an unexpected twist, Fastow now gives talks to the energy industry on ethical leadership.
Sounding the Alarm
Bethany McLean was the first reporter to question whether Enron was a financially sound
company in a 2001 article
for Fortune magazine. McLean went on to co-author the book The Smartest Guys in the
Room , which documented the fall of Enron due to its fraudulent practices, including the
ones Fastow engineered.
In 2018, McLean also published the book Saudi America , which highlighted many of the
financial challenges the fracking industry has faced. In a recent interview for Texas Monthly's
podcast Boomtown , McLean
explained one of the very accepted and blatantly misleading practices of the fracking
industry:
I'd raise a couple of points. One is that companies have long hyped these break-even
numbers. They say we can break even at $25 a barrel, we can break even at $20 a barrel. And
then you look at their consolidated financial statements and they are losing money. And so
something is going wrong the people called it to me [sic] corporate math or investor
economics. So they were trying to put together these investor pitch decks that would show
investors a set of economics that weren't real. So they would show you that they could break
even on a well at $25 barrel of oil but then yet you'd go to the corporate financial
statements and they were losing money.
Is that a loophole? Where you can openly misrepresent to investors the financial reality of
your business? Or is it fraud?
As more and more players in the fracking industry run out of options and file for
bankruptcy, investors are beginning to ask questions about why all the money is gone.
"This is an industry that has always been filled with promoters and stock scams and
swindlers and people have made billions when investors have lost their shirts."
Much like with the housing crisis that caused the financial crisis of 2008, the fracking
boom has led to Wall Street bankers finding innovative ways to finance a money-losing endeavor.
Some companies are now even
selling bonds based on future well performance , a concept similar to the
mortgage-backed securities that led to the 2008 housing crisis.
Another Wall Street invention is what is called a "special purpose acquisition company" (
SPAC ), or, as they are also known,
blank check companies. The way these investments work is a big bank or private equity firm
backs a management team to raise money for the SPAC with the agreement that the leaders of the
SPAC will then at some point make a "special purpose acquisition" -- which means they will find
an existing company and buy it.
They are called blank check companies because the management is given a blank check to buy
whatever they choose. In the 1980s, the
Wall Street Journal ( WSJ ) noted that "blank-check companies were often associated with
penny-stock frauds." In a 2017 article on the oil industry, the
WSJ reported that " SPAC s were a hallmark of the frothy days before the financial crisis
[of 2008]."
Understandably, SPAC s were often seen as a risky investment, but much like with the housing
crisis, the biggest names on Wall Street are getting involved and giving the concept
legitimacy, with Goldman Sachs starting to back SPAC s in 2016. And new fracking companies have
come about as a result.
Ben Dell, a managing partner at investment firm Kimmeridge Energy, explained one of the
risks of SPAC investments to the Wall Street Journal. " SPAC management teams have an incentive
to spend the money they have raised no matter what, so they can collect fees and pay themselves
a salary and stock options at the company they purchase," Dell said.
" SPAC s are the most egregious example in the industry of executive misalignment with
investors," Dell
told the WSJ .
As I
have previously reported , one of the problems with the fracking industry is that CEO s are
paid very well even when the companies lose money. According to Dell, SPAC s take this problem
to a new "egregious" level.
Alta Mesa: A Star Is Born
To successfully raise money for a blank check company, having some star power in the
management helps. As the Wall Street Journal has noted, investments in SPAC s "
are largely bets on their executives ."
Jim Hackett would seem to be the ideal candidate to lead a SPAC in the fracking industry.
Hackett has an impressive resume: the former CEO of fracking company Anadarko, former
chairman
of the Federal Reserve Bank of Dallas , an executive committee member of the industry
lobbying group American Petroleum Institute ,
and
partner at the major private equity firm Riverstone Holdings.
In 2013 Hackett retired from Anadarko to attend Harvard Divinity School to get a degree in
theology. However, he was still a partner at Riverstone and in 2017 was lured back to the
fracking business to run a SPAC backed by Riverstone.
The SPAC raised a billion dollars while being advised by the biggest names in the business,
including Goldman Sachs and CitiGroup. The initial blank check company was called Silver Run
Acquisition Corp. II .
Hackett used the money to buy two companies in Oklahoma -- an oil producer and a pipeline --
and the new combined company Alta Mesa was valued at $3.8 billion.
The Future Was Bright for Alta Mesa
Hackett and Alta Mesa had big plans for making money fracking wells in Oklahoma, which
included forecasts for big increases in oil and gas production from the newly acquired assets
with very low break-even numbers.
When the Wall Street Journal reported the creation of Alta Mesa,
it noted , "Alta Mesa's core acreage in Northeast Kingfisher County has among the lowest
breakevens in the U.S. at around $25 per barrel, the company said." Because oil was well over
that price at the time, the future looked good, according to Hackett and Alta Mesa. Forbes
reported that Hackett said Alta Mesa's holdings were "oil that will be economic even at $40
WTI [West Texas Intermediate]" and oil has been well over that mark since Hackett made that
statement in 2017.
Like break-even numbers, another area where misleading investors in the oil industry might
be particularly easy is making overly optimistic forecasts about how much oil will be produced
by future wells. The Wall Street Journal
has documented this as a significant problem for the U.S. shale industry.
Description of Alta Mesa assets in investor proxy statement. Credit: Screen capture from
proxy
statement.
In early 2018 when touting the potential of the proposed new company Alta Mesa, Hackett said
that "its average well would produce nearly 250,000 barrels of oil over its life." A year
later, Alta Mesa said it expected those wells would produce less than half that, only 120,000
barrels of oil over the life of the well.
Later in 2019, Alta Mesa filed for bankruptcy after writing down its assets by $3.1 billion.
The billion-dollar blank check had been spent, and it took less than two years to lose it
all.
SEC Investigation and Multiple Investor Lawsuits
Alta Mesa's assets were sold off earlier this year. The SEC declined to comment on the
status of the investigation.
In May 2019,
the Houston Chronicle reported , "Alta Mesa also is facing a series of lawsuits. Some
shareholders are suing claiming they were defrauded and lied to about the value of the company
and its assets when the company was formed."
One lawsuit filed by the Plumbers and Pipefitters National Pension Fund claims that the
proxy statement for Alta Mesa contained materially false and misleading information. That
filing lays out a lot of facts to support that claim.
Yet another lawsuit has been filed against Riverstone for " misleading
statements ."
Investors are saying they were misled by Hackett and Riverstone. The allegations are based
on the claims that were made about how much oil the company could produce. In hindsight, those
claims appeared wildly inaccurate and misleading. But is that fraud? Or just taking advantage
of a loophole?
In January, the Houston Chronicle summed up the situation as it described Alta Mesa's downfall : "It was a dramatic fall from grace after
significantly overestimating its potential in Oklahoma's STACK shale play "
While Alta Mesa is a spectacular example of how fast the fracking business can make large
sums of money disappear after "significantly overestimating its potential," it also likely
marks the beginning of investor lawsuits against many other failing fracking companies with
similar histories.
Learning From Enron
When Jim Hackett decided to go to Harvard Divinity School, several favorable profiles about
his choice were written, including one on the Harvard website.
That article noted that one of the reasons Hackett decided to go to school was because of "the
collapse of Enron, a disaster that he attributed to 'a failure in leadership' among people he
knew well."
The speed with which Hackett and Alta Mesa went bankrupt is remarkable, indicating a likely
failure in leadership.
However, Hackett seems to have learned something from former Enron executive Andrew Fastow:
that there is work for former executives like them to teach the energy industry about ethics
and morality.
Fraud? Or Just a Laughing Matter?
Good reporting is hard work but sometimes involves a bit of luck. Like when a
Wall Street Journal reporter , in a room full of people hired to make forecasts of fracked
oil and gas production, learned about the existence of much more accurate methods for
predicting that oil production. And also learned that with accuracy comes much lower estimates
of shale oil reserves.
The WSJ article that followed quoted Texas A&M professor and expert on calculating oil
and gas reserves John Lee. "There are a number of practices that are almost inevitably going to
lead to overestimates," said Lee. Those are the practices used by the industry, with Alta Mesa
serving as just one example.
Overestimates are why Alta Mesa received funding but now no longer exists.
The Wall Street Journal reported that during a presentation given by Lee, an audience member
"stood up and challenged the engineers in attendance," asking why the forecasters weren't using
accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
" Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal.
Is it misleading to laugh at your company's investors if you know the estimates you are
giving them are inflated, but because you own the stock that benefits from those estimates, you
do it anyway? Is that fraud? Perhaps that depends on if you get you get ethics lessons from
Andrew Fastow and Jim Hackett.
Will the biggest innovation of the fracking revolution be making financial fraud a laughing
matter?
A lot of people on EFT like to talk about how shale is fraudulent. That's simply not
true:
You can't commit fraud when the rules are so lax you can just make shit up and it's still
allowed.
While I've little doubt there is a lot of fraud, so much of the stupidity around fracking
comes down to the old saying that its hard to make a man undrestand something when his job is
to not understand it.
The financing of the oil and gas industry is almost entirely dependent on projections
– projections of flow per well, and projections of future prices. All you need to do is
make a few optimistic projections of one or both, and you've suddenly turned a dud into a
highly valuable asset. Anyone can look at the pricing and question it, but with oil/gas, that
is much harder with 'novel' types of well as there are few if any precedents. So if someone
says 'the well is producing X per day, we can continue this flow for 3 years and when thats
finished, we can drill down another 200 metres and replicate the same flow', there is nobody
to contradict it. The drilling guys aren't going to argue, they want to keep their jobs. The
geologist isn't going to argue, he has his mortgage to pay. The senior manager won't argue,
he wants a promotion. The drilling company owners won't argue, they want to cash out. And the
Wall Street financier won't argue, because he can pass on the risk to the equivelent of the
last booms 'German bankers'.
So when someone like Arthur Berman – a geologist who has continuously being
questioning the underlying geological assumptions – raises concerns – he's
listened to politely, even invited to some conferences, but is otherwise ignored. Because its
not in anyones interest to listen. There is literally nobody who's job it is to shout 'stop'.
So much for self regulating markets.
While there may well be very severe economic consequences if and when this blows up in
everyones face (and I suspect that Covid-19 will be the catalyst for this, oil demand is
collapsing day by day), the big loser is the planet we depend on for our survival.
I live in NY on the PA border. Fracking is still happening south in PA but is only a
fraction of what it once was. If you drive into PA you will see lots full of fracking
materials that have sat there for a long time. At first for about two years it was a boom.
The activity from fracking was amazing. Then as fast as it started it slowed down to a crawl.
There are a few reasons in my opinion. The so called sweet sports were quickly fracked
leaving less attractive sights. It was concealed that a fracked well produced most of it's
gas in the first two years. After that the production from a well dropped off drastically.
Locals soon lost their enthusiasm for fracking.There is still some fracking but it is hardly
noticeable. Local people thought this would be great but attitudes soon soured. A few made
big bucks at the expense of the rest. The fracking was in former coal country. The difference
is coal lasted a lot longer. Now the majority of people in the area oppose fracking. I'm
thankful that NY state banned fracking because of the negatives associated with fracking. I
own 50 acres near the PA border. Before fracking was banned I was constantly hounded by
leasing companies. I refuse to lease because to me my land was more important than a few
bucks. I hope in my life time NY doesn't reverse the fracking ban. On another note there are
wind farms where I live. I would leas to a wind company because there are fewer negatives and
it's less intrusive.
The good news is that if the companies were chasing you, you own the minerals. You can
donate them to a conservation land trust and assure that no mineral extraction takes place,
and get a tax benefit for the foregone production.
It can be argued that the money invested in many fracking companies with such inflated
pay-back periods, ROIs or breakeven estimates, apart from fraud, could be considered as a
private subsidy, just like Uber investors subsidize Uber taxi services. If we can blame it to
low interest rates resulting in such subsidies, for fracking oil, unicorns, education,
housing etc. to my knowledge this has only been argued in very few sites like here at NC or
Wolf Street but merits a close examination. If pension and mutual funds are pouring a lot of
money in such business with low to negative returns what consequences are to be expected in
the future?
Eight to Ten years ago you would have seen giant trucks moving water and dirt from
fracking sites when you got off the turnpike around Donegal PA. Since about 2015 or 2016 i'd
say that completely died. Pittsburgh actually had one year of population gain due to the
fracking boom but thats done. Yves mentioned investors and low interest rates chasing bad
investments and fraud. I'd say the same thing is going on in healthcare based on my exp. of
it and the amount of money floating around. We need higher interest rates to nip this stuff
in the bud and re-balance the economy.
This pretty much says it all regarding the health of our eCONomy, but hey, after it all
falls apart we should have plenty of reformed criminals to teach ethics classes
"The Wall Street Journal reported that during a presentation given by Lee, an audience
member "stood up and challenged the engineers in attendance," asking why the forecasters
weren't using accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
"Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal."
In a 2016 interview with Fraud Magazine,
==============================================
I have to say, I was shocked, SHOCKED to find that there is a magazine actually, only devoted
to fraud – that is published bi-monthly.
AND than I was shocked to find out that the magaine actually, only devoted to fraud is ONLY
published bi-monthly
Is the U.S. Fracking Boom Based on Fraud? Is the Pope Catholic? There are going to have to
be major structural changes in the world's economy in the next few years and with the demand
for oil dropping, prices have gotten cheaper which is turning fracking into a non-profit
industry. In any case, how are you suppose to frack with sick crews? This is one industry
that needs to go away before it causes any more damage. You'd find more honesty in a boiler
room brokerage firm than in this industry.
There's a recent documentary called The Price of Everything that is about the enormous
sums being paid for every latest fad in modern art. The show says that all the great masters,
old and new, have been locked up by museums or the super rich and so a recent flood of new
investors are looking for any excuse to spend lots of money on paintings. Apparently there is
so much money sloshing around at the top of our unequal economy that that these plutocrats
don't even care if they lose their shirts on bad investments. The main thing is to keep it
out of the hands of the poor.
Clearly we as a society are suffering from affluenza, at least among the elites who should
all be virus quarantined and then maybe we will forget to check back.The show tries to
pretend that this money driven art world is a cool thing. It had this viewer thinking of
guillotines.
Yes, like all the people who cannot see the art. It's mostly buried in storage. What is
the point of having over two thousand years of art from multiple civilizations, if most of it
is hidden away and often only known from catalog descriptions or cramped tiny pictures.
You must mean the insiders who suckered the rubes into taking shares off their hands at
the IPO. IIRC the IPO price was over $70/share. Right now it's just under $32 with no signs
of every being a profitable enterprise.
Grifters, charlatans and mountebanks everywhere you look.
Charging mineral resource rent, which everyone has an equal claim to, would help to reduce
the tendency of financial shenanigans. The profit motive is crack to rent seekers.
Speaking of Enron, it is perhaps appropriate that my employer's head of non core assets,
toxic waste for fire sale, came from Enron. Standard Chartered has some, too.
I think the big issue goes back to the investors and bond rating agencies, similar to the
subprime mortgage crisis. If bondholders aren't willing to do the homework, then they don't
get paid for the risk that they are undertaking. with the multiple prediction tools for well
production, you can make up an optimistic and pessimistic case. If the bond yield doesn't
cover that risk to your satisfaction, then you don't buy the bond or you demand a higher
interest yield and lower bond price.
Instead, it seems like the industry is raising money from people who don't want to think
more than a few months ahead on a multi-year investment. The challenges faced by the fracking
industry have been well publicized for several years now. If an investor doesn't understand
those challenges now and isn't looking at specific methods of calculating production yield
etc., then they have only themselves to blame if their investment loses money.
This is a very different issue than if somebody flat out lies about whether or not wells
exist etc.
A single well can make financial sense even if there will never be a net profit from it.
Fracking is pretty similar to the Hollywood film industry where nobody ever has any net
profits despite living high on the hog. "Don't ever settle for net profits. It's called
'creative accounting'." – Lynda Carter: https://en.wikipedia.org/wiki/Hollywood_accounting
I dunno. There may be a sucker born every minute, but I can't picture enough of them
getting born with a million (or billion) Dollars to blow on rackets like this to keep it
going this long.
Sad to see that the Plumbers' Union Pension Fund was a victim; I hope that's not a
pattern, but it would make sense. If it's a pattern, then it's no wonder the Fed tried so
hard to postpone the next Crash until after the elections. How much junk paper has Wall
Street sold to other Pension Funds? States & Municipalities are already squeezed by
"unfunded liabilities"; how much repackaged funky Fracking paper are held by public
(governmental) agencies? Damn, this is gonna be a mess.
I'd advise investing in popcorn, except that my 401k will probably evaporate soon, so
maybe it's pitchforks.
CFO Fastow of Enron. How nice to see him land on his feet. The company made listening to
the rolling blackout reports for California while driving to work a requirement.
Africa's largest oil producer could see oil production fall by 35 percent as low oil prices
and regulatory uncertainty threaten to prompt oil majors to postpone final investment
decisions. OPEC member Nigeria is the largest oil producer in Africa and it pumped 1.776
million barrels of oil per day (bpd) in January 2020, according to OPEC's secondary sources in
its monthly report published this week. Adding condensate production, Nigeria's total oil
output exceeds 2 million bpd.
However, three deepwater projects offshore Nigeria, operated by oil majors Exxon, Shell, and
Total, could see their start-up dates delayed by two to four years to the late 2020s, according
to the research WoodMac shared with Reuters ahead of publishing it on Friday.
The regulatory changes in Nigeria's oil industry and the still pending final approval of a
petroleum bill - after two decades of delays and wrangling - act as deterrents to the oil
majors' investment decisions, according to Wood Mackenzie.
Moreover, the three deepwater projects - which could add a combined 300,000 bpd to Nigeria's
production - are not profitable at current oil prices with Brent Crude below $60 a barrel, the
consultancy noted.
Just this week, Nigeria assured foreign oil investors that the country is open to business
and can guarantee high returns on investment, the country's President Muhammadu Buhari told an
energy conference on Monday.
Nigeria is set to finally pass a new bill regulating the petroleum industry by the middle of
this year, after nearly two decades of delays, the country's Minister of Petroleum Timipre
Sylva said at the same event.
Mele Kyari, Group Managing Director at the Nigerian National Petroleum Corporation (NNPC),
said at the conference that "We are, more than ever before, committed to working with
stakeholders to increase our crude oil production from 2.3 million bbl per day to 3 million bbl
per day."
The recent amendment to the Deep Offshore Act will improve financial stability and investor
confidence, NNPC's head said.
"... that every nation produces what oil they can produce. Production must have some relation to reserves. ..."
"... The normal R/P ratio is around 20. That doesn't mean a nation with an R/P ratio of 20 will run out of oil in 20 years. Because as their production declines, their R/P ratio will still hold at about 20 because they are producing less oil therefore their reserves will go further. So an R/P ratio of about 20 is the norm for normal size conventional fields. ..."
"... For giant and supergiant fields the R/P ratio would be greater and for smaller fields, as well as shale fields, the R/P ratio would be smaller. ..."
"... Using OPEC's reserves data for both OPEC and Non-OPEC, OPEC has an R/P of 109 while Non-OPEC has an R/P ratio of about 12. That OPEC number is absurd beyond belief. ..."
"... If we exclude the heavy oil then OPEC's share is close to the 70% I suggested. How does this square its share of the production numbers for the world. This was my original question. I would like to read what the thoughts of other posters are on this as well. ..."
What is the explanation that Non-OPEC produces more than OPEC, but OPEC has 70% of world
reserves?
Although this might have been the case in the early history of oil production, I
would think that this should not be the case near the peak. If I recall correctly, Campbell
thought that OPEC's stated reserves are actually the estimated values produced by the government for each OPEC country?
Well, 79.4% to be exact Some people really believe that unbelievable crap. Well hell,
there are still people who believe the earth is flat and that the sun revolves around the
earth. So why should we be surprised? Some people will believe anything.
I would like to think that most people on this list know that OPEC quoted reserves is
pure bullshit.
Hey, we have a president who lies every time he tweets. And sometimes he tweets 200 times
a day. And perhaps 45% of the nation believes him. The capacity of humans to believe the
absurd is unbounded.
Anyway if IEA and EIA projections are made on the basis of OPEC claimed reserves, we
have a serious problem.
Well, I have always stated, on this blog as well as The Oil Drum, that every nation produces
what oil they can produce. Production must have some relation to reserves.
The normal R/P ratio is around 20. That doesn't mean a nation with an R/P ratio of 20 will
run out of oil in 20 years. Because as their production declines, their R/P ratio will still
hold at about 20 because they are producing less oil therefore their reserves will go
further. So an R/P ratio of about 20 is the norm for normal size conventional fields.
For giant and supergiant fields the R/P ratio would be greater and for smaller fields, as
well as shale fields, the R/P ratio would be smaller.
If a giant or supergiant field is nearing the end of its life, but infill drilling,
creaming the top of the reservoir, this will throw a monkey wrench into their R/P ratio.
While in its prime, the field may have had an R/P ration of 40 or even greater, its R/P ratio
while being creamed will be much smaller, less than 20.
Using OPEC's reserves data for both OPEC and Non-OPEC, OPEC has an R/P of 109 while
Non-OPEC has an R/P ratio of about 12. That OPEC number is absurd beyond belief.
According to Hubbert methodology, at the peak production the number of years to exhaust
the reserve is N = 2/a in which "a" is the intrinsic growth rate
dQ/dt=a Q (1-Q/Q_0)
From Laherrere's reports for world peak, this is between 0.04 and 0.05. This means that
the R/P ratio is between 40 and 50 at the peak. Thus if we say that 1/2 of the reserves are
left at the peak and we take Laherre's URR = 2500, this gives R/P=1250/35=36 years. These are
ball park figures, but suggest that R/P ~ 20 is low. These numbers are for the entire world
and for example for North Sea at its peak Hubbert's analysis gave a = 0.12, so
R/P=2/0.12=16.6, and this illustrates the fact that smaller fields are closer to your number
R/P=20.
If we exclude the heavy oil then OPEC's share is close to the 70% I suggested. How does
this square its share of the production numbers for the world. This was my original question.
I would like to read what the thoughts of other posters are on this as well.
Following the sharp re-drop in oil and natural gas prices in late 2018, bankruptcy filings
in the US by already weakened exploration and production companies , oilfield services
companies, and "midstream" companies (they gather, transport, process, or store oil and natural
gas) jumped by 51% in 2019, to 65 filings, according to data compiled by law firm Haynes and
Boone . This brought the total of the Great American Shale Oil & Gas Bust since 2015 in
these three sectors to 402 bankruptcy filings.
The debt involved in these bankruptcies in 2019 doubled from 2018 to $35 billion. This
pushed the total debt listed in these bankruptcy filings since 2015 to $207 billion. The chart
below shows the cumulative total debt involved in these bankruptcies since 2015.
But this does not include the much larger losses suffered by shareholders that get mostly
wiped out in the years before the bankruptcy as the shares descend into worthlessness,
and that then may get finished off in bankruptcy court.
The banks, which generally had the best collateral, took the smallest losses; bondholders
took bigger losses, with unsecured bondholders taking the biggest losses. Some of them lost
most of their investment; others got high-and-tight haircuts; others held debt that was
converted to equity in the restructured companies, some of which soon became worthless again
when the company filed for bankruptcy a second time. The old shareholders took the biggest
losses.
The Great American Fracking Bust started in mid-2014, when the price of WTI dropped from
over $100 a barrel to below $30 a barrel by early 2016. Then the price began to recover, going
over $70 a barrel in September and October 2018. But then it began to re-plunge. By the end of
2018, WTI had dropped to $47 a barrel.
Two major geopolitical events in the Middle East – the attack on Saudi Aramco's oil
facilities last September and the US assassination of Iranian Major General Qasem Soleimani
– that would have shaken up oil markets before, only caused brief ripples, quickly
squashed by the onslaught of surging US production. At the moment, WTI trades at $56.08 per
barrel, which is still below where the shale oil industry can survive long-term:
And 2020 is starting out terrible for natural gas producers. The price of natural gas has
plunged to $1.90 per million Btu at the moment, a dreadfully low price where no one can make
any money. Producers in shale fields that produce mostly gas, such as the Marcellus, are in
deeper trouble still, because oil, even at these prices, would be a lot better than just
natural gas.
Producing areas with constrained takeaway capacity (it takes a lot longer to build pipelines
than to ramp up production) are subject to local prices, which can be lower still. In some
areas, such as the Permian in Texas and New Mexico, the most prolific oil field in the US,
where natural gas is a byproduct of oil production, limited takeaway capacity has caused local
prices to collapse, and flaring to surge.
The chart shows the spot price for delivery at the Henry Hub:
Texas at the Epicenter.
The most affected state, in terms of the number of bankruptcy filings, is Texas, the largest
oil producer in the US. Since 2015, the state had 207 oil-and-gas bankruptcy filings, of the
402 total US filings. In 2019, Texas had 30 of the 65 US filings.
Delaware, obviously, is not into oil and gas production, but into coddling corporations, and
many companies are incorporated in Delaware, including some oil-and-gas companies in Texas.
When they file for bankruptcy, they do so in Delaware. These are the eight states with the most
oil-and-gas bankruptcy filings since 2015:
Bankruptcy filings are triggered when the E&P companies no longer get funding from Wall
Street or from their banks to continue with their perennially cash-flow negative operations and
service their debts. And this is what is happening now. Wall Street and the banks have started
to demand that these companies stick to an entirely new mantra in the fracking business: "live
within cash flow."
When E&P companies run short on funding, they cut back on drilling activity which puts
the squeeze on oilfield services companies that provide products and services to the oilfield,
including drilling and completing wells. And then these OFS companies go bankrupt.
This is what happened to oilfield-services giant Weatherford
which filed for a prepackaged bankruptcy last July . Back in 2014, before the oil bust, it
had 67,000 employees; by July, it was down to about 26,000. The reorganization plan allowed
Weatherford to shed $5.8 billion of its $7.6 billion in long-term debt. Old shareholders got
wiped out. The creditors got 99% of the restructured company's new shares.
In its report on the OFS bankruptcies, Haynes and Boone cited this pressure from Wall Street
and its cascading effect, which Weatherford had pointed out in its bankruptcy filing:
We note that Weatherford, in its July 2019 filing, attributed its insolvency in part to
reduced drilling activity by producers who have also been dramatically affected by the
commodity price slump since 2015. Investors' pressure on producers to "live within cash flow"
is further reducing demand for OFS services and supplies leaving the OFS sector with little
near term hope for a turnaround in prospects.
What this sector needs are much higher prices for oil and natural gas. But that cannot
happen while production continues to surge. A large-scale culling in the sector – a lot
more bankruptcies – could reduce production, and support higher prices.
But as soon as prices rise above certain levels, with investors still chasing yield at every
twist and turn, the flood of new money will wash over the sector again, with investors having
already forgotten by then that shale oil and gas was where money went to die every time. And
this new money will cause a new surge in production, which will collapse prices once again.
It's a cycle that the shale industry has a hard time getting out of, under the current
loosey-goosey monetary conditions.
The cratering of natural gas prices is bad news for any attempt to encourage
renewables.
From my own situation, I made a substantial capital investment in moving my domestic space
heating from gas to ultra-high efficiency air source heat pumps.
The economics worked out as broadly favourable (this wasn't my motivation, but it helped
justify the investment). My heat pumps have a raw (non-seasonally adjusted) coefficient of
performance of a little over 5. So I get 5kW of heat for every 1kW of electrical input). Here
in the UK I was paying 14 pence per kW/hr for electricity compared with 3.5 pence for natural
gas. With a AFUE efficiency on the gas heat of 90% my heat pumps generated heat at just under
3 pence per kilowatt, the gas heat would work out, net, at around 3.8 pence. So I saved about
10% to 15% in energy costs doing space heating via renewables. Again, here in the UK market,
electicity is about one-third to 40 percent from zero-carbon sources, wind, hydro and
nucelar. So my carbon footprint for space heating using heat pumps was hugely lower (maybe up
to half).
I've just got my utility's latest quote on energy prices. Electricity charges are about
the same. But I'm being quoted 2.5 pence per kilowatt hour for natural gas.
There's no way my air source heat pumps can compete with that. I might as well just burn
the gas and say screw the carbon dioxide emissions. I won't, of course. I'll grin and bear
it. But the shale glut and the uneconomic (wasted) investment in overproduction is massively
distorting the energy market.
Yes. Those are the calculations to be done. I am in the same situation though in Spain the
"spread" between gas and electricity prices in energy terms is smaller compared with the UK
and will probably get even smaller in the future despite the natl gas glut (because tariff
policies and investment in renewables). I am paying about 0,14€/kWh on electricity
consumed (fixed power contract apart but I needn't change it) and gas is at 0,06€/kWh.
The seasonal coefficient of performance of my reversible air/water heat exchanger is 4.5 by
Eurovent (third party certification of performance) so current expenses relative to natural
gas are 0.14/(0.06 x 4.5) = 0,52 that means I save 48% relative to the gas boiler. In fact a
bit less because the seasonal COP of the condensation boiler was about 1.05. But then, there
are other advantages about getting freed of natural gas: not needed periodical inspections.
Also my boiler was ageing and requiring more frequent revisions and repairs. In Spain the
electrical mix is now about 60% renewable + nuclear (approx). Gas prices are also more
volatile.
I among other things was designing, sourcing and installing high efficient NG powered
floor heating system in the North West of British Columbia. I once participated in 2012 in a
symposium by a supplier of heat pump systems.
The maximum savings one could expect because of the demand of the system (basically a reverse
refrigerator with a compressor demanding the most power) was actually 30% of the cost of
gas.
However – and that is the big one – a gas powered system at the time using high
efficiency boilers cost about 5 – 7$/ square foot, depending how much electronic
controls you threw into the system.
This way a new house install at an average 2500 square foot house would set you back an
average of 15 grand. Installing a heatpump system with either 8 -10′ buried PEX loops
or wells to 100′ deep would add between 25 – 30 000$ on top minus the cost for
the boilers at an average of 4500$.
And the typical heat-pump unit would cost between 8-10 000$ with a lifetime of about 10
years, double the cost of a boiler who usually have a somewhat longer lifespan.
The reason: air heat extraction systems in Canada do not work, when the heat is needed the
air temp. is at about – 5 to – 35C ..so only subsoil extraction works with
attending cost of machinery and labour.
The conclusion by all 25 contractors attending was quite unanimous – heat pump
systems in Canada except maybe in the most southern portions – are a waste of resources
and money.
Even here in mild England, despite having a heat pump installation which has capacity for
the space heating load even on a design condition day for winter extremes (let's say minus
5C) I have done a lot of data logging which has shown that in some not exactly challenging or
unusual climatic situations, the heat pump performance doesn't meet anything like submittal
sheet claims.
A few weeks ago, I'd forgotten to run the systems overnight at a low setpoint (but enough
to keep the space at a reasonable temperature -- I usually pick 16C or the low 60s F). When I
went into the kitchen / breakfast nook at seven o'clock-ish it was freezing cold (okay, maybe
not freezing, about 14C) with an outside temperature of 1 or 2C (low 30s F).
I turned the heat pump on, set it to a high output as I needed the space to warm through
relatively quickly before I had coffee then had to leave.
After less than five minutes, the outdoor unit went straight into a defrost cycle. Why?
Because it was one of those typically English damp, foggy mornings (where there was almost
100% RH outside). Even though the outdoor coil would have been, say, 2 or 3C, as soon as the
system started, the coil surface temperature would have crashed to minus 3 or 4C -- whereupon
the saturated outside air promptly froze the coil solid. Coefficient of performance would
have been less than one for the twenty minutes or so I needed to heat the space. I'd have
been better off firing up the gas heat.
Only an isolated and probably unusual use case. But a good illustration that green
technology has limits. For US climate zone 3 or 4 inhabitants, I suspect heat pumps will only
ever be viable in the shoulder months. For the severe winters you guys get, I can't see how
you can avoid combustion heat sources. Not to say that renewables such as air source (or
ground source) heat pumps aren't a partial solution, but the capital costs will be high,
probably prohibitively so for a monovalent system and overall carbon emissions savings won't
be especially spectacular.
Coastal temperate US regions might the best. Many inhabitants there. But I guess it works
in Texas, New México, Arizona (may be not so well in high plains north to the Canyon)
and others. May be Arkansas for instance and north up to Iowa?. It has to be noted that when
temperatures go close to 0ºC or below, and for long hours, performance is much worse.
So, in Madrid (a urban heat island itself) this occurs in winter for about 3-10 hours during
the night (I set thermostats at 19ºC during the night) in an average January day and it
is not big deal.
But, again, the climate is very important indeed. It has to be carefully analysed.
IMO Air heatpump is good for Oz, NZ and the likes, with the south UK being marginal now,
but not-applicable once Gulf Stream goes :)
ground-water, or water-water HP are needed for anything that gets freezing 3-4 months a
year, but that, as you say, has nontrivial capital costs, unless costs of carbon goes up by a
lot.
And, TBH, there are problems even with that. Say if ground-water is using subsurface loop,
it actually has a measurable impact on the soil temperature over few years, which is bad for
a number of reasons. Water-water can be ok if the water source is running water and not
over-used, but I've seen water-water sources that were using ponds freeze large ponds that
under normal circumstances would never fully freeze.
That said, ground-water well driven HPs are IMO very good for large office or apartment
buildings, especially if they work both ways (i.e. cooling into ground in the summer,
avoiding city heat islands).
I think the broadest lesson to be drawn from Clive's experience is that investment capital
is actively making it difficult to transition away from fossil fuels because investment
managers and underwriters absolutely insist on continuing to invest in fossil fuel projects,
even if it loses tons of money!!!
How can we compete with rich, powerful people who insist on wasting money!?!?!!
I have long wanted to use geothermal heat pump. In my case it simply won't happen, sadly.
For one, I would never be able to get the permit to drill the well in city limits. Two, the
equipment would cost more than my older, poorly insulated house itself. Three, our state
government has allowed and caused some of the highest electric prices in the nation, despite
having a huge hydro electric plant in town. We don't get that electricity, it gets sold to
NYC at greatly inflated prices. We don't get the money either. Instead we are forced to
import our electricity with full taxes and tariffs on it.
Last week, the temperatures were down to -15C at night And of course the snow.
Yes, the condition of the building is such a crucial aspect. I used to have beautiful
hardwood window frames, but there were an unmitigated disaster for energy efficiency and
creating a good building envelope. They were an almost complete thermal bridge. And they
could only accommodate the thinnest of double glazing. In a really cold winter's day, I'd
have to set the leaving air discharge temperature fairly high on the heat pump indoor coil to
get warm, which hampered efficiency. I was able to change to triple glazing (which fixed the
problem and significantly reduced heat loss but, again, at a cost ) because the property is
modern. If I'd had an older property, the windows would only have been part of the problem
(solid or poorly insulated walls and an un-insulated slab, for example, would be worse). And
the chances of getting permission to replace windows in a historic house would be slim,
certainly with the UK's tight building control.
And as you say, if you're in zone 5 or 6, you're a bit stuffed with regular drops to -15C
(5F). My heat pumps guarentee operation down to -15C, but capacity takes a nosedive. Luckily,
design conditions here in southern England are -5C, which reduces capital cost massively. And
if design conditions demand operation is guaranteed down to -20C (c. 0F), there is not much
choice of air source equipment available at any price. The only unit I know which is rated
down to below -30C is a Panasonic mini split, which here in the UK costs nearly £2,000
(c. $2,600) for a 3/4 ton unit. Out of reach for most. So you're left with ground source, but
-- as you say about NYC -- forget that idea in, say, London where tunnels and utility
wayleaves can't be interfered with. And ground conditions are difficult too, with a heavy
clay.
Green tech is not a panacea. I don't want to be discouraging, just the opposite. But some
of the talk about how practical it is is fanciful.
I do believe that much good is possible by greatly revising and liberalizing the building
codes, but practally trying to accomplish this is like pulling teeth. For some reason there
is large political resistance to change in this area. Older buildings can easily be made
quite efficient with current tech, but then the problem becomes an economic one. How to
overcome the first costs when the cost of upgrading is more than the structure itself?
FWIW many homes in my area were built in the 70s and 1980s with the assumption that
electric power would be free, or nearly free once the original bond issue for the power plant
was paid off. LOL the bastards managed a 30% rate hike the same year they paid it off, using
every little excuse possible.
Reading your reply, I was struck with just how underdeveloped the building insulation
field is. I have seen blow in and spray in foam retrofit insulation systems used in
commercial construction. (I particularly remember a system for inserting expanding cellular
foam into the void spaces in concrete block walls. [Yes! It can be done!])
Saying the above, I have read about the building insulation codes in the Nordic countries
being very 'tight.' Anyone from there care to enlighten us?
All the above is referencing winter heating. Where we live, summer time air conditioning is
the main energy sink.
Excellent points. Of course there is one plus. In the US we also need cooling in the
summer. My impression was that the heat pump systems could provide this as well, and very
economically.
Yes, we had a hot summer (hot by north European standards at any rate, we had about 10-15
days in the low 90s F and only a single day over 100F, maybe another few weeks in the 80s)
and my A/C cost was well under $100 for the whole cooling season, just because the heat pumps
with variable speed compressors and larger coil surface areas are so efficient when in A/C
mode.
As ambrit says above, even with low US electricity costs (in some areas, anyway), I don't
know how feul-poor folks manage in the south and so-cal with 10 SEER equipment and poorly
insulated homes when you have day after day at 95-100F.
It's dry in SoCal. One can easily survive by opening the windows, avoid direct sun on
windows, and dress accordingly.
I lived in the tropics under the same conditions, no direct sun on windows, behind insect
screen. That, one bed sheet to cover oneself, and a ceiling fan worked well.
Yes, the avoidance of service costs for gas-fired equipment plus the utility connection
fee for the gas service does make me consider the idea of moving away from gas as a fuel
source entirety. I must run the numbers on that to see how it might work out. It's a good
point to consider for anyone looking at the long-term costs for air source water or space
heating.
And you UKers are not precisely big spenders of electricity in per capita terms. About
half than French with all that nuclear power in place. Guess that how the power is delivered
to the grid has an important effect in consumption patterns.
If natural gas prices stayed cratered just long enough to exterminate thermal coal beyond
hope of revival in many countries before the natural gas prices went back up . . . would that
be a good thing?
Can someone at NC explain why the government allows burning flared gas? If it was outlawed
production would drop for oil as well until some way to store and use the gas was developed.
It seems burning natural gas at the wellhead must increase CO2 since gas is a
hydrocarbon.
I think you've answered your own question. The US govt has long had a policy to INCREASE
oil/gas production, side effects be damned.
There's a collective action problem among producers where they'd all benefit if they all
agreed to drop production 20%, say. But, each individual player benefits if they get to cheat
on those production cuts.
Plus, they've all floated a ton of high interest debt, which requires that they put
capital to work to generate cash flow to service that debt. It's clear that we're in the
'ponzi finance' stage of the cycle where new debt has to be issued to keep up payments on the
interest of the older debt. That's why the bankruptcies are perking up.
Bond underwiters, investment mgrs, oil services execs, and other players are all very
incentivized to keep getting new deals done.
First of all, it seems to be up to the states (?). There actually are regulations in Texas
(the Permian basin is the marginal-cost producing location in the US, where most of these
stories are centered). But the state is a friend of the industry and these regs are loosely
enforced. Secondly, emitting unburned natgas (mostly methane) is even worse than CO2 as a
greenhouse gas. Thirdly, they are drilling for oil, not gas, and are hoping to maximize the
oil-to-gas ratio. With low natgas prices and smaller amounts per well than elsewhere in the
US, putting in pipe for natgas is not economical. In fact the oil-gas-ratio varies in simple
geographic pattern that was known for years. The best, i.e. oil-rich land was claimed early,
subsequent waves of development that came on line during the oil price spike in mid 2000s,
are now getting killed. Fourthly, the ones losing money can't afford the extra ongoing
capital investment anyway – recall the very short life cycle of wells in fracking. They
are certainly cutting corners in other environment related tasks, like wastewater
disposal.
So will it stop? Not at the moment no. On the legal front, not until the next Ralph Nader
comes along and we get another wave of federal public interest legislation like we had in the
70s (which neither major party wanted at the time, just like now, and always). Economically,
also no. The marginal producers who were late to the gold rush will exit, but there is no
shortage of oil at even $50. The wildcard is in international developments. We are
suppressing production and export of conventional oil from Iraq, Iran, Libya, and Venezuela.
We are suppressing transport of natural gas from Russia to the EU. There is also
unconventional oil in Canada. I.e. US policy is supporting prices. Net effect on global oil
and gas use? None, since we just produce the difference ourselves, with a bunch of extra
natgas the world doesn't want, and can't be stored, so we burn it. Sucks.
Flaring is usually classed as solution gas flaring, emergency flaring and just unwanted
gas flaring.
These days flaring unwanted gas is rare because of the huge waste. But not long ago
producers could just flare stuff they didn't feel like getting to market, so entire
reservoirs of gas were burned just to get to the oil. This mostly doesn't happen anymore.
Emergency flaring happens in production or refining when a sudden unwanted flow of gas
manifests and for safety reasons, it must be disposed of rapidly. This appears a sudden very
large luminous flares over short timescales. Again, this is rare and essentially can't be
avoided. Flaring is much safer than just releasing.
Solution gas flaring is the bubbles of gas dissolved in liquid that come out of solution
during production as liquid pressure drops close to the wellhead. These need to be collected
or they would fill up liquid storage tanks. The volume and composition of the gas flows
determines the cost of collection. Companies have to balance the cost of collection vs. the
damage to the environment if flared. They usually try to make a case that the containment
cost (the cost to produce it to market, since the market value is usually minimal) is
prohibitive and request a permit to flare. This is the usual minimum compliance approach of
most resource development.
Basically, the conditions to obtain flaring permits vary with jurisdiction and are based
on a balance of revenue vs. environmental damage. These days most places encourage developers
to collect solution gas, but for remote locations in sour plays, that is costly to the
viability of the play.
If no one will build the gas-flaring oil fielders a free pipeline from oilfield to
gas-market, and building their own pipeline would cost more than what the oilfielders could
sell the gas for; they will just burn it in place. The other alternative would be for them to
release the methane UNburned into the air, which would be even worse than burning it
first.
But as soon as prices rise above certain levels, with investors still chasing yield at
every twist and turn, the flood of new money will wash over the sector again, with
investors having already forgotten by then that shale oil and gas was where money went to
die every time
This among the agricultural folk is called the "Schweinezyklus" or "pig cycle". Typical
for larger scale farming when from a previous oversupply the market has tried up, raising
prices and everyone increasing again their pig production till – again – the
market collapses.
I studied agricultural economy and production in the early 1970's when this type of cycle
became typical when farmers moved from mixed production providing risk compensation to dual
or even single products.
Indeed, the situation you refer to looks suspiciously like a process of financialization
of agriculture. Not to wax nostalgic for the "good old days" of backbreaking labour and
crummy living standards, but agriculture used to be a form of 'calling.' Now it's just a job.
Of course, the serfs and other 'forced' agricultural labourers of yesteryear disproved the
ethos of Goldsmith's "The Deserted Villiage."
There was a Golden Age, but it was not evenly distributed.
Frankly it is hard from Wolf's figures to know if he is even right. $207bn of defaulted
debt sounds like a lot of money, but is that from a total of $250bn or $2.5tn? I have no idea
if this is a lot of the industry or a little. And 2019 may be worse than 2018 for defaults,
but both 2016 and 2017 were way higher than that. Are things really getting worse or not? I
am deeply sceptical about the financial viability of fracking, but the case being made here
doesn't justify the sensation rhetoric.
In 1993 I built a house guaranteed to use 6,192 Kwh per year for heating and cooling here
in central PA, near Harrisburg. That includes resistance electric heat for backup. At that
time the cost was less than $40 a month.
Following the specifications to achieve this added about $2,500 to the cost of this 1288
sq.ft. house. It was a result of government requirements but no subsidies except for
administrative cost by the utility. Those requirements were subsequently dropped and the
program disappeared.
My question would be, was this program dropped because of complaints from the general
public, the homeowners as a group, or the builders and developers? $2 USD a square foot added
to construction expense wasn't chicken feed back in the 1970s.
Great article! It causes me to wonder, are the neocons trying to start a shooting war in
the Middle East to drive up US petroleum prices? Make America Great at least Texas. ;-)
I feel like supply control over there is more about petrodollars and perhaps efforts to
hurt Russia and Iran. Meanwhile the US seems to essentially be dumping oil with QE and repo
money funding money losing small fracking plays. I figured ages ago the plan was always to
have the supermajors mop up the wreckage at pennies on the dollar when the party ends.
Paper bankruptcies seem like a small price to pay for the gain in geopolitical influence
of all that extra production. Not being at the mercy of someone turning down the crude tap
can foster much more unilateral, terrible decision making in the middle east.
The invisible hand of the market did well to coddle a massive infrastructure buildup I saw
first hand in the Eagle Ford in Texas. Long term well production may have dropped off
significantly faster than the sales pitch but all of those wells will still be in place to
re-fracture when the market demands it.
"... Such is the extent of the shakeout in the U.S. shale industry that Permian Basin oil production is closer to peaking than many forecasts suggest, according to one energy investor. ..."
"... Adam Waterous, who runs Waterous Energy Fund, regards the sector's financial position as unsustainable after years of disappointing returns for investors and negative free cash flow. With capital markets now largely shunning shale producers, the impact will begin to show in oil and natural gas output from the largest U.S. oil patch, he said. ..."
Production from these selected top 9 US shale oil companies might be about to fall as shown
by decreasing quarterly crude oil production changes in chart. ExxonMobil (XOM) shale oil is
growing fast about 11% per quarter but probably not enough to offset declines from other
operators.
XOM data is taken from shaleprofile.com, averaging three months into a quarter, then
multiplying by 75% to get crude oil. 75% is used because Pioneer Natural Resources crude to
total shale oil is 75% and Pioneer operates in the Permian which is also XOM main basin.
Pretty sure shale profile reports crude plus condensate, for "oil" production. As the data
matches pretty closely with the EIA's tight oil estimates by play when Oklahoma output is
excluded (shaleprofile only reports Oklahoma output on the subscription service.)
In short, one should not assume 75% of what is reported at shale profile is the "crude"
portion of output. In fact all US output is reported as crude plus condensate, all the way
back to 1860.
There is also Chevron, BP, and Shell operating in US tight oil, all have deep pockets and
will be unaffected by the tightening up of the credit markets. In the past 2 years these 5
have doubled their tight oil output, though most of the increase occurred in 2018 when oil
prices were higher.
Output may drop, that in turn will lead to higher oil prices and higher tight oil output,
also the majors will be able to pick up cheap assets as smaller oil companies that have not
been financially prudent go bankrupt, that may accelerate the growth of tight oil output from
the majors as oil prices rise.
Liquids produced at natural-gas processing plants are excluded. Those are the NGPLs if
memory serves and are not NGLs which I think of as coming from NG at the well head.
In other words liquid from NG is listed two ways: The stuff obtained at the well head
(NGL) and the stuff obtained farther down the line at NG processing plants (NGPL), and the
latter is not included as oil. This is from my failing memory but so is my ability to find my
way home most of the time.
What some do not realize is that the natural gasoline (which condenses from the natural gas
stream at standard temperature and pressure of 1 ATM, 25 C) has always been included in the
crude plus condensate data in the US since 1860. The lower carbon chain products (C2, C3, C4)
are not liquids at STP, they are gases and remain in the natural gas stream until they are
separated at the natural gas processing plant. The definition given by the EIA is quite clear
on this point.
In the Permian basin, the ratio of crude to total oil (incl NGL) produced by Pioneer has
fallen from 81% at beginning of 2016 to 75% at the end of 2019. If this fall is similar for
other Permian producers then it may be harder to continue increasing Permian crude
production.
The comparison between oil production from shaleprofile.com and from Pioneer is very close,
as shown by the two green lines. For 2019Q3, shaleprofile production was 286 kbd compared to
290 kbd from Pioneer quarterly report. Note that both these numbers include crude, lease
condensate and NGLs. http://www.pxd.com/
I read an very interested report here on this forum where US geological Institute had
estimated break even prices for Thiere 6 to 1. Thiere 6 was categorizized as sweet spots with
more than 800 kbpd. As I remember this had break even cost 18 usd each barrel and to next
class you could aproximately multiplay it with 3. I believe this is much of the core
knowledge the Pioneer Mark Papa is estimated US future shale production at wich again is
related to change in rock quality. What we know is in 2014 -2015 I believe US could earn
money at least with some borrowings at 30 usd WTI , 5 years after tjey cant earn money at 60
usd WTI even with huge improvement in drilling efficiency that it is a reason to believe will
go much slower in future. Labour cost and all other will continue to increase. It might be
break even price in 2025 will be above 120 usd WTI iff Thiere 5 runs out as same as Tiere 6
the sweet spots. This mean we will be back to the situation before 2014 when the main source
off oil was offshore, and investment was there. It simply means US need to cut more cost in
shale oil, develop more oil from wells drilled in less quality rock but this challange might
be very hard to solve even for Exxon that is ramping up, the question will be if their
barrels are profittable at 42 usd WTI as they predict. Perhaps Mr. President could give tax
release, or simply start buy up the 1500 billion in depth that need to be payed next 4 years.
Some people may consider natural gasoline (which condenses from Natural gas in the lease
separators) as "NGL", I consider this this to be lease condensate and generally is is mixed
with the crude and sold with the crude. Perhaps Pioneer keeps a separate account of "crude"
and "condensate", in the US these are usually lumped together as C+C, most of the NGPL
produced in the US is Ethane (C2), Propane (C3), and Butane (C4), about 12% of the NGPL is
natural gasoline (C5), roughly 600 kb/d of a 5000 kb/d total output of NGPL. Note that the US
does not count the pentanes plus from NGPL plants as part of C+C output even though it is
chemically very similar to lease condensate. In Canada, for example the pentanes plus from
NGPL is added to C+C from the field, not sure why the US does things this way, Canada's
approach seems more sensible.
Such is the extent of the shakeout in the U.S. shale industry that Permian Basin oil
production is closer to peaking than many forecasts suggest, according to one energy
investor.
Adam Waterous, who runs Waterous Energy Fund, regards the sector's financial position as
unsustainable after years of disappointing returns for investors and negative free cash flow.
With capital markets now largely shunning shale producers, the impact will begin to show in
oil and natural gas output from the largest U.S. oil patch, he said.
"We think we are at or near peak Permian" production, Waterous said last week in an
interview. "The North American oil market has been grossly overcapitalized, which is not
sustainable."
Predicting peak Permian output for 2020 isn't a mainstream view. There's plenty of debate
about how much production growth in the West Texas and New Mexico patch may slow this year as
shale drillers slash capital spending, but the consensus is that supplies will rise, albeit
at a slower pace. Tai Liu, an analyst at BloombergNEF, said in a report Tuesday that the
pessimism may be overdone.
Just because there are newcomers I will re offer up a consideration.
If you have to have it, and you do have to have it, you are not going to let a substance
created from nothingness on a whim by the local Central Bank get in the way.
This is a peak oil blog, and that means scarcity. When something that you have to have is
scarce, then you are going to go get it. The concept of price is a parameter of value --
value that exists only in the imagination of counterparties. Oil moves food and your stomach
doesn't care about the imagination of counterparties. So don't be so sure that price
determines production. Or consumption.
Anybody notice that the price is rather a lot less than it was five or six years ago? How
does production compare to then?
"'There are known knowns. There are things we know that we know. There are known unknowns.
That is to say, there are things that we now know we don't know. But there are also unknown
unknowns. There are things we do not know we don't know."
Economics is the study of how people allocate scarce resources for production,
distribution, and consumption, both individually and collectively.
Supply and demand is the amount of a commodity, product, or service available and the
desire of buyers for it, considered as factors regulating its price.
Watcher, we don't live in a perfect world of instant information and production.
" Over the past five years, the industry and its investors "mistook a massive structural
change for a simple cyclical event," he said. "It's impossible to continue to have uneconomic
production and capex.""
It is basic stuff. I can show you many time periods of increasing price that aligned with
increasing consumption.
And again, worst of all, you know I can show those time periods.
The theory fails. If you find even one instance where it is wrong, it fails. That's the
scientific method. The hypothesis is proposed. Experiments are observed. If even one fails to
support it, that's failure. That's how it's always worked.
There is no oh, but. Price is lower than 6 years ago and production is higher. 2010 to
2014 price rose from $95/b to $112/b. Consumption 2010 89 bpd to 2014 93 mbpd. I found that
without breaking a sweat.
The theory fails. Embrace a new one. And why be surprised? It's a substance whose value
derives from whimsy and counterparty imagination
So rigs and frac spreads continue to fall yet almost all experts predict continued LTO growth
. it would appear the day of reckoning is coming and the majors in the Permian will not save
the day .. wasn't everyone hoping for a pick up in rigs and spreads as budgets were meant to
be renewed in the new year
I think independents are finally getting it that they can't simply look to increase
production as soon as the POO goes up.
I think the change has solely been bought about by investors requiring a return on
investment, I'm not sure we can surmise that LTO producers will act as they have in the past,
I suspect it will take a sustained period of high POO before LTO producers open the spigots
it will create even more of a boom/bust scenario going forward ..
I agree with you Jack, a large increase in oil prices seems unlikely to have much boost in
LTO production for several years because banks will want significant loan payback before
increasing drilling budgets. Dennis' model is an excellent BAU projection, but we live in
more dynamic times than that imho. Banks will need a consistent high oil price to lend like
they did in the past. That seems unlikely given possibility for recession, war, EV adoption,
increased regulation from Democratic prez, etc.
Wall Street is obsessed with the shiny new thing and that is not FF production. Tesla's
share price now more than GM and Ford combined.
Debt mountain for shale producers 2020-2023. Maybe once they get past this mountain banks
will be ready to loan again and rig counts and frac spreads will increase. But only if
there's a consistently high oil price during this period so banks have confidence to lend and
debt is substantially reduced.
It's all about the Permian and has been for quite some time.
None of the other shale basins have enough rigs running to grow production
significantly.
The Bakken is probably the most economic besides the Permian, and it seems the operators
there are in maintenance mode with regard to production.
There are still 397 rigs running in the PB. That is still a large number. I suspect there
are more locations left there than in the remaining shale basins combined (not counting the
ones which produce mostly natural gas).
It takes rigs to drill wells and frak spreads to complete them. No, rigs and frak spreads
have not improved their efficiency that much in such a short time. And drillers and frakers
are not working that much faster.
What you are seeing, or are about to see, is a slowdown in completions. The frak
spreads that are being retired have obviously just finished completing a well. But they
will not be completing another one. That's why you see a lag between falling rig and frak
spread count and completions.
Hell, that's all we need Dennis. If the total number of national frac spreads fall then the
total completions, nationwide, will fall. If production falls everywhere except the Permian,
then that decline will offset any increase in the Permian.
Okay, we know that the lions share of frac spreads are for oil therefore???
I think you are way overplaying your hand with this efficiency stuff. Last time when rigs
and frac spreads declined, then production declined. Why should it be any different this
time?
The simple fact of the matter is: "The total number of frac spreads are falling".
Therefore completions will fall because retired frac spreads frac no new wells. Yes, it is as
simple as that. Saying the remaining frac spreads will be more efficient therefore
completions will not fall, is just wishful thinking at best, and total nonsense at worst.
Well said Ron losing frac spreads means that the maximum number of completions able to be
completed has decreased – the concept of increased efficiency is a red herring when
spreads have fallen 40%!in the past 6 months – spreads efficiency sure hasn't risen 65%
in the same time ..
I think we all agree once the worm turns in the Permian LTO production will decrease, I am
not sure producers will increase production as the POO rises they do have to pay back a lot
of debt and have shareholders to answer to who want a return ..
From what I have read there is always improvement of efficiency in operation regarding new
Buisinesses such as shale. This improvement is normaly linked to exsperiance, increased
volumes i.e. but typical it will slow down during time as much of the easy potential will be
taken out. I see this as drilling padds, skidding systems as same rig could drill more wells
without be dismantled and mounting again. Dere have also been improvements in latheral
lenghts, propant, and fluid . But as Slumberger wrote in 2019, they believed max latheral
lenght already is reach as if increased cost off equipment will be much higher and also risk
increase when operating atbthe limit, more tear i.e. There might still be improvements but
more slow than it have been. According to reports the break even price increase 4-5 times
each Tiere class, and I believe rock quality will be a main challange in years to come as
shale will need higher oil price to earn money, pay back ballons and dividends.
Let's see the next quarterlies from LTO producers noting the continued comments about being
profitable under $50. If Permian centric producers cannot profit on maintaining production
output we know Houston we have a problem going forward .. will the companies be able to stick
to using cash flows from continued operations only or will we see more excuses carted out
again .
Gail makes the case for an oil peak for 2018, predicting production down 1% in 2020 in a
low-price environment. Her take is worth a read even though she likes to go far out on a limb
with little support sometimes
Production from these selected top 8 US shale oil companies might be about to fall as shown
by decreasing quarterly crude oil production changes as in chart below.
very interesting graph it shows what is evident that independents are being forced into
financial discipline at last. I cannot see the majors picking up the slack regardless of what
the MSM say, why would they continue with the growth at all costs strategy which has caused
noting but carnage for the above 8 producers.
Can XOM do all the heavy lifting itself once the independent growth plateaus then falls is
the million $ question. My bet XOM will grow but in a sustainable way, the impact of the
Permian increase will be interesting to note in their quarterly how much has that growth cost
them is the question ..
If we look at Exxon/Mobil, Chevron, Conoco-Philips, Shell, and Total combined, they have
increased combined tight oil output from 400 kb/d to 840 kb/d in the past 2 years (Sept 2017
to Sept 2019). Most of this increase occurred from Sept 2017 to Sept 2018 when oil prices
were a bit higher, in the past 12 months output grew by only 155 kb/d. Oil prices matter, low
oil prices may kill tight oil output growth, if so, oil prices are likely to rise.
For my "medium oil price scenario" (maximum WTI price of $83/b in 2018$ reached in 2027),
we get about 195,000 total wells drilled, about 110,000 total horizontal tight oil wells get
completed from 2010 to 2030 (about 26,000 have been completed through November 2019) so
roughly 80k wells completed from Sept 2019 to Sept 2029 in scenario below.
Also link below has spreadsheet you can play with.
Changing row 4 changes completion rate to any rate that seems reasonable. Scenario ends in
2030 for this particular spreadsheet, you can use excel, google sheets, or some other
spreadsheet program, it is saved in microsoft excel format.
On prices remaining range bound, that depends in part of how quickly oil consumption
grows. From 1982 to 2018 the average rate of growth in annual oil consumption has been about
800 kb/d. My $83/bo model has US tight oil growing by about 385 kb/d over the next 7 years,
it is not clear that the rest of the World will be able to fill the 415 kb/d gap each year
(assuming the 800 kb/d C+C consumption growth continues for the next 7 years). That is why I
expect oil prices to rise.
There has been relatively low offshore oil investment over the past 5 years and this is
likely to start affecting World oil output soon, the bumps in output from Brazil and Norway
are likely to be offset by declines in other producing nations (Mexico, China, and UK) and it
is far from clear that we will see higher output from Iran, Venezuela, Libya, or Nigeria.
As always the future is difficult to predict and I am often wrong, so perhaps oil prices
will remain "range bound" in your preferred $55 to $65/bo range. If that is correct Permian
output will grow far more slowly, perhaps growing from 4 Mb/d to about 6 Mb/d. The low oil
price scenario has about 72,000 wells completed from Sept 2019 to May 2030 in the Permian,
about 52,000 wells in all other US tight oil basins for a total of about 124,000 wells for
the low oil price scenario over that period. The completion rate falls from 850 in 2030 to
zero in 2035 for the low oil price scenario and output falls from 8200 kb/d at the start of
2030 to 2600 kb/d at the end of 2035.
I think it unlikely oil prices will remain range bound when World oil output peaks in
2026, that is only 6 years away, growth in oil output will slow significantly starting in
2024 and oil prices are likely to rise (at the latest) by June 2023.
That is a lot of locations. Of course, not all locations are the same productivity
wise.
Incredible how much oil the Permian Basin has produced and will produce in the next
decade.
Interesting how many companies sold out most of their acreage in the PB in the late 1980s
and 1990s, thinking it was past its prime.
I know of a small operator that bought leases in the PB and drilled some good vertical
wells. Martin Co. I don't know what they paid, but I am sure it was a tiny fraction of the
$600 million they sold out for a three years ago.
QEP bought about 9,500 acres from them for $600 million. There was 1,400 BOPD of
production from vertical wells at the time of the sale.
I have been looking at the wells QEP has drilled on this acreage. I don't think $600
million for 450 hz locations was a good deal for QEP. There are some good wells, but not
enough of them.
Yes I agree, all locations will not have the same productivity, I use the average for all
wells drilled for any given month as I am interested in the entire industry, some operators
will have better wells than others, some of this is skill and some of it is luck, I simply
assume generic company X will have a well productivity distribution that will be similar to
the industry average, in practice this is not likely to be true, but if we think of the
entire Permian basin as being run by a single large oil producer (Big Permian Oil Company) it
would be approximately correct, if my economic assumptions are correct.
I also find it amazing how much tight oil has been produced (5.6 Gb so for for Permian
since Jan 2000) and will be produced ( a total of 29 Gb for my model from Jan 2000 to May
2030, and for longer scenarios out to Dec 2079, about 60 Gb URR for Permian basin alone.)
Mike Shellman thinks that is completely wrong, but if the USGS mean estimate is roughly
correct and my medium oil price scenario and other economic assumptions are correct, that is
what the model suggests might happen. Mike is not a fan of the USGS TRR estimates, their F95
estimate is 43 Gb for Permian Basin URR, my low oil price scenario is in line with that F95
TRR estimate, with a URR of about 37 Gb.
If the TRR is low, oil prices are likely to be higher and a higher percentage of the TRR
is likely to be profitable to produce. (For a low TRR scenario the EUR would decrease more
rapidly than my "medium" TRR assumption (the basis for my best guess estimates).
I assume new well EUR starts to decrease starting in Jan 2019. In Dec 2018, my model has
the average Permian well with an EUR of 378 kbo. Chart below shows how the model assumes the
EUR will change from Sept 2019 to May 2030 (end of model scenario) for the Permian scenario I
presented above.
Again this is a guess for how future EUR will change based on a TRR scenario (no
economics) with 255,000 wells and a TRR matching the USGS mean estimate of 75 Gb for the
Permian basin. The rate that the EUR decreases depends on the number of wells completed each
month. Chart is small, click on chart for larger chart.
So they paid 1.33 million per well, I agree the wells do not look very good, for a 2017
average well, QEP has cumulative output of 145 kbo, my basin wide average well has about 190
kbo at 24 months, so the QEP wells about 24% lower than average, yikes.
This month, the energy consulting firm Wood MacKenzie gave an
online presentation that basically debunked the whole business model of the shale industry.
In this webinar, which explored the declining
production rates of oil wells in the Permian region , research director Ben Shattuck noted
how it was impossible to accurately forecast how much oil a shale play held based on estimates
from existing wells.
" Over the years of us doing this, as analysts, we've learned that you really have to do it
well by well," Shattuck explained of analyzing well performance. "You cannot take anything for
granted."
For an industry that has raised hundreds of billions of dollars promising future performance
based on the production of a few wells, this is not good news. And particularly for the
Permian, the nation's most
productive shale play , located in Texas and New Mexico.
Up until now, the basic premise of the fracking business model has been for a company to
lease some land, drill until finding a high-volume well, hype to the press this well and the
many others it plans to drill on the rest of its acreage, and promise a bright future, all
while borrowing huge sums of money to drill and frack the wells.
Throughout the seminar, Wood MacKenzie analysts emphasized that companies can't reliably
predict future oil production by "clustering" wells, that is, estimating volumes of many future
wells based on the performance of a small number of nearby existing wells, and described the
practice as potentially "misleading."
Shattuck called out how the old business model of firms borrowing money from investors while
hoping for future payouts on record-breaking wells no longer works. He summed up the
situation:
" We're transitioning to a point in time, where the investment community was enamored of
the next well and how big it might be. That has changed for a variety of reasons. One very
important reason is the next well might not be bigger. It might be smaller."
The fracking industry is now being asked to produce positive financial results -- not just
promises of new
super wells, or cube development, or artificial intelligence. And yet the industry couldn't
deliver profits while drilling all the best acreage over the last decade. Now, shale companies
need to do that with oil wells that may not produce as much.
Seven years ago, Rolling Stone referred to the fracking industry as a "
scam " while profiling the "Shale King" Aubrey McClendon, the man generally credited with
inventing the business model the shale industry has used the past decade. Today, McClendon's
old company Chesapeake Energy is
in danger of going bankrupt .
Perhaps investors are finally catching on.
Are Child Wells the New Normal?
Last year I covered the issue of
child wells , or secondary wells drilled close to an existing "parent" well, and the risk
they posed to the fracking industry. Child wells often cannibalize or damage parent wells,
leading to an overall drop in oil production.
At the time, I cited a warning about this situation from Wood MacKenzie, which said,
"Closely spaced child well performance presents not only a risk to the viability of the ongoing
drilling recovery but also to the industry's long-term prospects."
Over a year later, has the shale oil industry abandoned this approach or are child wells
still an issue?
During this month's webinar, Ben Shattuck answered that question, making a statement that
should strike fear in the heart of shale investors and the owners of all this shale
acreage:
" We know we're on the cusp of a child-well world."
One of the biggest problems with fracked oil well production is child wells, and according
to Shattuck, that looks like the new normal. When the bug in an unprofitable business becomes
the main feature of the business model, its future is definitely at "risk."
In the Eagle Ford shale, average production per foot of well length and per pound of
"proppant" has been falling steadily. Mr Kibsgaard blamed the decline on a rising proportion
of child wells, which are now up to about 70 per cent of all new wells drilled https://t.co/uG58KcNNJp
As long as shale firms could keep borrowing and losing money to drill new wells, producing
more oil was simple. When profits weren't a concern, the debt-heavy business model worked. But
similar to the dot com boom and bust, the fracking industry is learning that if you want to
stay in business, you need to make a profit.
Without a doubt, drilling and fracking shale can produce a lot of oil and gas in the right
geological regions. It just usually costs more to get the oil and gas out of the rock than the
fossil fuels are worth on the free market. Now, however, the much-lauded "shale revolution" is
facing two big issues -- the best rock has been
drilled and few are eager to
loan money to drill the remaining acreage.
E&E News recently highlighted
what this reality means for Texas's Eagle Ford shale play, where production is now 20 percent
lower than at its peak in early 2015. For an oil basin that's only been producing oil via
fracking for
just over a decade , that is a pretty grim number. However, an analyst quoted by E&E
News highlights the secret to making money while fracking for oil: Simply stop fracking.
"Generating free cash is easy: Stop spending on new wells," said Raoul LeBlanc, vice
president for North American unconventionals at IHS Markit. "The catch is that production will
immediately move into steep decline in many cases."
# IHSM arkit
forecasts capital spending for shale drilling & completions to fall by 10% to $102
billion this year. By 2021, we'll see a near $20 billion decline in annual spending. What's
causing this? Raoul LeBlanc comments- https://t.co/7q1QTiWZVs @HoustonChron
Ah, the catch. To generate cash while fracking requires companies to stop fracking and sell
whatever oil they have left from rapidly declining wells. Because fracked wells decline quickly
even when everything goes perfectly, if a producer isn't constantly drilling new wells, then
the oil production of a field drops off very quickly -- the "steep decline" noted by
LeBlanc.
That's exactly what happened in the Eagle Ford shale, an early darling of the fracking
industry, and most of the top acreage
in the Bakken shale play in North Dakota and Montana has already been drilled, and will
likely see similar declines.
LeBlanc emphasizes this point again in the Journal of Petroleum Technology
, where he is recently quoted saying that the decline rates in the Permian region have
"increased dramatically" for new fracked wells.
A year and a half ago, DeSmog launched a special series exploring the finances
of the fracking industry , putting a spotlight on its financial failings. At the time,
optimism about the future of fracking was still filling the pages of the financial press.
Hughes told DeSmog that with the finances of fracking, "Ultimately, you hit the wall. It's
just a question of time."
With the industry on the cusp of a "child-well world," that wall appears to be approaching
quickly -- unless you still believe the industry promises that fracking's big money is right
around the corner.
As the article says, the key scary thing for investors and the industry about fracking is
that fracked wells don't tail off over years like conventional ones – they stop
producing quite abruptly. Once the sweet spots are sucked dry, the drop off in production
will be calamitous with all sorts of potential impacts through both the oil/gas and the
finance world. It will probably happen far too quickly for most investors to jump off the
carousel in time. It will be a game changer when it happens (and probably, sadly, quite good
news for the Gulf States).
In past years, whenever I've expressed scepticism about the finances of fracking, the
usual response is 'but those guys wouldn't be putting in billions unless they knew there was
lots of oil and gas there'. What they don't seem to grasp is that making money from oil and
gas exploration is not the same as making money from oil production. Its not about selling on
the fuel. Its about first of all extracting money from investors for the exploration (and
getting your cut), then its about developing a prospect and selling it on for a big profit.
They don't really care if the well is profitable in the long term or not. I know of at least
one oil company (not in fracking, mostly off-shore), which has made millions for its owners
over the 40 years of its existence, despite the fact that it has never sold one barrel of
oil, nor ever found a field which could be brought to full production. All their profits have
come from their cut in selling on prospective fields, not one of which has ever come to
production.
===Its about first of all extracting money from investors for the exploration (and getting
your cut)==
==All their profits have come from their cut in selling on prospective fields, not one of
which has ever come to production===
What that tells me is there are a lot of investors that have soo much idle money floating
around the world and can literally throw huge sums of money at some venture and if the
venture fails oh well.
Many authors (Susan Strange, etc.) have used the term Casino Capitalism and this seems to
fit that.
It's like taking millions of dollars and making an idle bet at the roulette wheel and if
you lose oh well it was just pocket change or I'll just make up the losses on some other
scam. Meanwhile millions of people are homeless, without healthcare, hungry, etc. It's is
long past time to storm the castles! Pitchforks Up!!
I predict a nightmare of numerous abandoned wells as the many unprofitable fracking
companies go belly up, leaving the public with an expensive environmental mess to clean
up.
Just another example of western cronie capitalism where you privatise all profit, and
socialise all losses including both monetary and environmental.
The only way to stop this is to make shareholders personally responsible for such losses
including environmental clean up, even after a company goes belly up. Only then will
shareholders demand long term viability and more sustainable environmental practices, instead
of only short term profits.
A much simpler way is to simply insist that any license to drill can only be granted if it
is tied to a certified insurance bond for correct capping and abandonment. It would be
interesting to see just how many insurance companies would be willing to take on that
risk.
This should be the norm for all resource extraction permits: mining, logging, drilling,
whatever. A "restoration bond" has to be in place to finance the restoration of the site
after the valuable resources have been carted away.
This would be cheap in some cases, and very expensive in others (e.g., uranium mining). It
would be a way of factoring the externalities (as economists like to call them) into the
overall cost of the project, as well as decreasing the odds that fly by night operators will
trash the planet.
"You wouldn't know you were near an uranium mine any more ."
Alas, the residents of Red Shirt, South Dakota, a tiny Lakota community on the fringes of
the Pine Ridge Reservation, know about uranium mining. Past uranium mining
activity has resulted in the leaching of radioactive materials into their ground water
and wells. Even the nearby Cheyenne River has been contaminated. They can't drink the water.
Or use it for irrigation or fishing. The entire region is an official National Sacrifice
Area. Just a bunch of poor Indians.
The Defenders of the Black Hills are now fighting efforts to mine uranium using in-situ
leach mining. In this process, holes are dug, water and solvents injected to dissolve the
uranium, then the waste water is brought to the surface and temporarily stored in mud waste
ponds. Sounds like 'fracking?' Concerns are for the spread of contaminants in ground water
and aquifers. Where you can't see it.
Granted, no type of mining is without its problems.
But you could live in an area like mine where well water has to be tested routinely for
the high levels of uranium that occurs naturally in our water. No uranium mines around
here.
I'm going to be polite and ignore the tone of your comment. I was merely pointing out that
uranium mining is not the only reason for high uranium levels in ground water. There is a lot
of uranium in the earth's crust and it is dissolvable in water. All well water should be
checked for uranium levels but it is rarely done.
I'd favor forcing the investors and executives that want to erect these horrors to
personally (along with their family members) do the on-site labor of closing and cleanup,
while breathing the air and drinking the water that locals do. Still, of course, possible to
game even that by capturing the regulatory process of setting cleanup standards and
requirements, a la the federal and state Superfund programs.
Malum prohibitum vs. malum in se
" Latin referring to an act that is "wrong in itself," in its very nature being illegal
because it violates the natural, moral or public principles of a civilized society. In
criminal law it is one of the collection of crimes which are traditional and not just created
by statute, which are "malum prohibitum." Example: murder, rape, burglary and robbery are
malum in se, while violations of the Securities and Exchange Act or most "white collar
crimes" are malum prohibitum." https://dictionary.law.com/Default.aspx?selected=1201
The public won't be asked to fund the cleanup because there will be no cleanup. The
responsible parties aren't interested, and our government is no longer interested either.
It's another one of those issues in which communities without power will insist on government
action, and they will be ignored.
I wonder if could it be the case that some government considers strategically important to
keep production from free-falling, no matter if the economics are not sound, and shifting the
cost to the Treasury. MMT to the rescue of shale plays and financiers.
If the article is correct, calling for a plateau as soon as in 2021, the shale boom will
prove more transient than expected.
I can't keep up with all the interlocks and back-scratches. But Banksters are getting
rich, the intermediators in exploration and production are getting rich, the petroleum Bigs
are getting rich and using the notional global competition and Market to damage one
"nation's" comparative advantage to their own ends. And as with all the behaviors leading to
the conclusion that humanity is a failed, and maybe more honestly a plague species, all the
incentives and flows of power are in the direction of what I believe it was a Reagan
appointee offered as the moral underpinning of globalization and ruination: "God gave us
dominion over the planet, and Jesus is coming back real soon and if we have not used up the
whole place in accordance with His Holy Word as i read it, He is going to be really pissed
"
As with all the stuff we NCers read here, everything seems to drive the truly awake soul
in the direction of despair and that sense of vast futility, and that mindset of "Eat, drink
and be merry, for tomorrow we shall die " And screw future generations – past
generations said that to us, so why should we, or some small elite among us, who now are in a
position to have all our pleasure centers fully engaged and satiated to the max, behave
"Responsibly?" "Responsible people maximize shareholder value (and executive looting)!"
5 million EV takes inevitably back to nuclear energy. Without nukes you can anticipate
losing your residential AC for several hours/day. PG&E is the future.
The Forbes article is crap. Any analysis of electricity costs coming from renewable power
that does not include the costs of the energy storage systems required at high
penetration levels will underestimate the costs. Badly. The solar panels and wind turbines
are the easy part. The energy storage systems will easily cost 10X as much (and take 10X as
much time). Because of this, we've seen renewable energy deployment efforts stall out in
Germany, Spain, China, Denmark, and elsewhere, as they bumped into grid stability issues that
require storage to mitigate. And the storage costs too much.
Using "batteries" also produces a 10%* net loss to charge the batteries right off the bat.
You need 110% of the electricity to get to same 100% you were getting before the battery.
Rather than batteries helping, they actually end up using more electricity. That's also
before counting the electricity to make the battery.
* that's best case, theoretical, scenario.
Batteries are net users of electricity. The do not make it.
The Forbes article talks about balancing the grid so that variable energy sources can be
incorporated reliably. To whit:
Actually, battery storage, though often cost-effective today, is rarely needed to "firm"
the output of variable renewables (photovoltaics and windpower), because there are eight
ample cheaper methods.
I believe the author's thesis is for the electricity from renewables to be fed into the
grid when it is available, not to store it.
Do you think nuclear power plants run continuously and are never taken off the grid? Do
you think we use huge storage batteries when they are down?
Both your quote, and the pdf 'talk about' that. That's all they do. The forbes author
really is a treat. "There are 8 ample, cheaper methods" What are those eight methods? why
only 8? No further details.
"I believe the author's thesis is for the electricity from renewables to be fed into the
grid when it is available, not to store it."
It seems you noticed it too. No details, just numbers spelled out as words and asserted as
evidence.
Well, unfortunately the link that explains his 8 methods is behind a paywall.
But I think we are talking apples and oranges here.
The author of the Forbes article is talking about how a grid works. When a power plant is
taken off the grid, energy is moved in from some other area to take up the slack as long as
that power plant is offline. He expects that should be done with renewable energy also.
If you are depending on only one form of renewable energy, then of course you would need
batteries when that form of energy is not available. But batteries are an added cost and not
as efficient as moving energy via the grid. A better method would be to have many types of
renewable energies available so that you can switch between them as necessary. It is what he
means when he is talking about needing to firm the output of variable renewables.
So for example, in my area, the winds kick up when the sun goes down so it makes sense to
switch from solar to wind power at dusk.
I'm don't buy Amory Lovins' thesis. Bob's criticism is correct. The other 8 methods aren't
listed. The required sizes and associated costs aren't listed. It is impossible to judge the
viability of the scheme he envisions when the relevant information is missing.
A real plan would list nameplate GW for all types of generation assets and GW and
GWh for all energy storage assets. In other words, full details.
The only "plan" I've seen for supplying US energy needs with 100% renewable power that
actually contained full details came from Mark Jacobson of Stanford University: https://web.stanford.edu/group/efmh/jacobson/Articles/I/USStatesWWS.pdf
. To his credit, he did the time-domain analysis necessary to determine the amount of
load-sharing and energy storage necessary to keep the lights on through even extended periods
of unfavorable weather.
Unfortunately, his "solution" required two things: (1) expanding US hydro capacity by a
factor of 10, and (2) deploying a stupendous 541 TWh of energy storage. Neither is feasible.
The first would cause massive flooding and ruin river ecosystems if ever run at full power,
and the second would cost over $100 trillion at today's energy storage costs of $200/kWh. His
plan was so wildly unrealistic (and yet popular with Democrats) that a team of scientists and
engineers issued a formal rebuttal: https://www.pnas.org/content/114/26/6722 .
Jacobson's plan has been debunked .
The South Koreans deployed their nuclear fleet for approximately $3000/kW. At this cost,
we could completely de-carbonize the US electrical system for less than $2.5 trillion. It
would be quite the bargain in comparison.
The South Koreans do have one of the lowest costs for nuclear energy production – a
LCOE of about $2021/kWe compared to the US of $4100/kWe and the world average of $4702/kWe
– but the way they do that is by having much looser regulations and by severely
underestimating the decommissioning, waste management, and accident compensation costs. Is
that what you want for nuclear energy in the US?
I think it's kind of dangerous to just throw numbers around unless you understand what
they actually mean.
Ah, the wonderful "Heaters". They are situated outside EBR-1, just south of ID-20, west of
Idaho Falls, and east of Arco.
The whole of the area around there is a fascinating place to visit for a nuclear nerd like
me, plus you have the wonderful Craters of the Moon NM there too.
Other interesting places to visit are Atomic City, which has a population of around 25,
and is a weird time capsule from the '60s, plus Big Southern Butte, which is a, er, big
butte.
You can also find a gate leading off ID-20 to the north, into INL (Idaho National
Laboratory), which used to be the access road to the army's SL-1 reactor, which underwent a
steam explosion due to a core excursion in 1961, and is (as far as is admitted) the only
nuclear accident that led to immediate deaths in the US.
For a really interesting review of nuclear history read the three books by James Mahaffey.
He was a nuclear plant operator for a while, and describes the little pastime of "reactor
racing", which was seeing who could get a reactor up to nominal operating capacity in the
shortest time.
I guess that this means that Trump and his crew will make another run at Venezuela –
before the fracking industry goes down the gurgler. All of Venezuela's oil fields are like a
big box of chocolates in America's backyard. But if they try to take it, like life, you never
know what you are going to get.
Am I right in guessing that this will significantly impact forecasts of aggregate US
domestic oil production? Do we remain the global "swing" producer?
As PlutoniumKun says above, the collapse of the shale field production will be great news
for the Gulf Coast's petroleum industry. Not only is the Gulf a proven reserve, but with the
inevitable higher prices for crude oil, many more of the offshore wells will become
profitable.
The American shale collapse will also be good news for other world producers of petroleum.
OPEC will regain some of it's lost political influence.
On the down side; all forms of shipping and transportation will have a spike in per unit
costs. A canny politician could use this factor to push an onshoring of lost industrial and
manufacturing capacity. Put Americans back to work in America. That will be a winning
strategy.
Yes, well, I generally assume that the definition of "profitable" in use in the board
rooms of the giant conglomerates 'rules the day.' Until some method of 'regulating' the
actions of the board rooms of industry are brought into play, I'm afraid we are stuck with
some version of the status quo.
Just as the German usual suspects moved nations into 'Realpolitik' after the War, so too have
the modern Austrian usual suspects moved the world into 'Realeconomik.' Both have led our
best of all possible worlds into a Neoliberal Paradise.
Didn't Chesapeake Energy declare bankruptcy a good ten years ago? And then restructured
itself into a shale fracking company with the extreme help of the Obama administration? When
Obama "pivoted" away from KSA he went straight to US drillers. Allowing any hype necessary to
get the needed investments. Obama was clearly panicked. I wonder if it is possible that that
is when he learned that Aramco's reserves were only a fraction of the Saudi hype? Bin
Sawbones was subsequently allowed to provide the estimate of the worth of KSA's oil reserves
at 2 Trillion. The IPO went forward at that estimate and just today there is an article in ZH
about Aramco's actual value being much less. It looks to me like we just up and left KSA. Why
on earth would we do that unless they were running dry? And why would they have fought that
obscene war with Yemen unless they (the Saudis) were getting desperate? Secure people
generally don't do things that stupid. And the next logical question might be, How long will
Russian reserves hold up as they supply both China and the EU? The simple answer is it is all
just a question of time. We need to envision a lifestyle that is far more compatible with the
planet. Fracking was just a distraction. A farce. It would be better to own warm sox than oil
shares. And electricity is not going to help us out if we do not aggressively restrict our
use. I'd just like to know why we can't all come together and admit this one elemental
fact.
Drainage! Draaaainage, Eli, you boy! Drained dry. I'm so sorry.
Here, if you have a milkshake, and I have a milkshake, and I have a straw. There it is,
that's a straw, you see? You watching? And my straw reaches acroooooooss the room, and starts
to drink your milkshake.
I drink your milkshake! slurp I drink it up! Every day I drink the Blood of Lamb from
Bandy's tract.
The last man standing might be profitable.
Not so long ago gas was much higher I think the peak during a pre fracking cold winter was
$15 now under $3. Plus we're exporting the stuff bc us price is so far below Eu price. But us
price is clearly unstable Bc it's too low for frackers to break even, much less make
money.
It's the large fracking production that's driven price down to sub $3. Maybe foolish
investors and banks will soon stop burning $, after which price will rise towards $10 as this
happens utilities will really jump on solar bc gas will be increasingly non competitive.
Ca should refuse all utility requests to build more gas-fired generating plants existing ones
will be shut over the next decade as solar plus storage price continues falling and gas price
rises.
From graphs 2 and 3, you can see that half or more of the national oil production comes
from about 50,000 high producing wells (out of roughly 1mm total). These are of course on the
treadmill of decline and need continuous investment to be renewed.
Anyway after 2014 the national production responded to the price collapse within about a
year. This is what is somewhat different about fracking -- the short time horizon and the
outsize contribution of the "top" wells -- constant depletion and investment -- results in a
fairly fast response to the price environment.
Factor in pipeline capacity shortages come and go, affecting the share of $$ taken by the
midstream. In any case, they're losing money when the WTI price is in the $50-$60 range. What
does that mean? Great question.
So, the shale/fracking industry has ~$200bn in debt, god only knows how much market cap is
at risk on Shale and fracking alone, and it's COMPLETELY UN PREDICTABLE. And people buy
shares in this snake oil on the market? SEC sleeping? what a crock.
I suspect that shale plays like OXY, with marketwatch assigning a "beta" of (get this!)
0.99 to this stock, are fundamental misallocations of capital. In a political sense, it's a
red state SOE type play that doesn't pass snuff. I saw the entire Wood MacKenzie webinar
linked in Lambert's article, and even THEY themselves are amazed at the range of valuations
in the shale sector. No two wells can be compared truly. The webinar references when Ben
Shattuck asked a wall street analyst for their comps on some company, and Wood MacKenzie's
analysis using on the ground depletion knowledge, was 40% lower, versus a higher paid wall
street "comps" analysis!
This entire sector is SNAKE OIL, imho, not to mention the environmental degradation not on
the balance sheets. But it is politically privileged, so we must zip it.
HB. I have used leases developed in our field in the past ten years to demonstrate that shale
is high cost. Again, rule of thumb the cost of a conventional well in our field is
approximately 1/100 of a shale oil well ($70K range v $7 million range).
Here are some examples with production through 10/31/19:
8 producers 4 injection wells. Cumulative BO 83,466. YTD BO 2,085. First production
4/2003.
10 producers 4 injection wells. Cumulative BO 116,065. YTD BO 2089. First production
9/2005.
10 producers 4 injection wells. Cumulative Bo 55,595. YTD BO 3,023. First production
3/2006.
4 producers 1 injection well. Cumulative BO 37,418. YTD BO 1,289. First production
8/2008.
8 producers 3 injection wells. Cumulative BO 42,494. YTD BO 2,328. First production
10/2008.
4 producers 1 injection well. Cumulative BO 19,216. YTD BO 1,220. First production
12/2010.
8 producers 3 injection wells. Cumulative BO 46,463. YTD BO 1,877. First production
8/2011.
4 producers 2 injection wells. Cumulative BO 10,700. YTD BO 634. First production
10/2011.
8 producers 3 injection wells. Cumulative 59,592 BO. YTD 4,956 BO. First production
11/2011.
1 producer. Water disposed of in adjoining lease. Cumulative BO 7,872. YTD BO 444 BO.
First production 5/2012.
8 producers 3 injection wells. Cumulative 56,500 BO. YTD 3,858 BO. First production
6/2012.
4 producers 1 injection well. Cumulative BO 11,758. YTD BO 1,457. First production
6/2013.
2 producers. Water disposed of on adjoining lease. Cumulative 3,524 BO. YTD BO 393. First
production 11/2013.
6 producers Two injection wells. Cumulative 25,988 BO. YTD 3,233 BO. First production
9/2014.
Figure in anywhere from $60K-80K to drill, complete and equip each well including
electric, flow and/or injection lines. Figure another $20-30K for a tank battery.
Assume anywhere from 12.5 to 20 percent royalty.
Of course, some projects do better than others. But compare this to shaleprofile.com
wells.
There was very little drilling in our field from 1987 to 2003. There has been very little
since 2015. Century plus year old stripper field.
There have also been many reclamation projects in our field during 2005-2014 of abandoned
wells wherein the producers went bust in the 1990s, with 1998 being a knockout blow.
We took over 2 wells drilled in the 1950s they were abandoned in 1998. We just had to
equip them and build a new tank battery. We also took over three wells also drilled in the
1950s where we had to do the same, plus plug the injection well and convert one producer to
an injector. These work well at $55-65 WTI also.
I can also point to many projects developed in our field in the 1980s where cumulative per
well has topped 40K BO to date.
Conventional oil is a much better deal than shale usually when you can find it. And also
when you aren't trying to pay for 8 figure CEO pay, skyscrapers and jets out of it.
Shale just has the scale. Huge scale. Worldwide game changing size.
Shallow, I can't thank you enough. Alot to digest here. My first glance gave me the feeling
shale drilling dollars are about half as productive. Maybe you have a better number.
When a new field is drilled, is it always under pressure without the cost of lifting it
from the hole? Then once the pressure is exhausted it becomes a stripper?
A lot of the Huntington Beach field lays under the ocean. There is over a mile long row of
wells along the shoreline. I'm assuming they go horizontal under the ocean. Only a few wells
have lift Jacks. Can strippers wells go horizontal?
There isn't enough down hole pressure here for natural flow. Everything goes on pumping unit
immediately and injection wells are also drilled at the same time as production wells.
To put into perspective, the field was originally drilled over 100 years ago. Waterflood
was initiated on a large scale right after WW2. Many wells were plugged in the late
1960s-early 1970s when oil prices were low. The field was redrilled in the late 1970s –
early 1980s. Little activity after 1986, until prices took off during the Iraq War.
For example, we operate a lease that was originally drilled in the 1950s. It was plugged
out in 1972. In 1979-81, all of the plugged wells were drilled out (casing had not been
pulled). New injection wells were drilled.
Cumulative from 9 producing wells since 1979 is over 140K BO with production currently at
5.5 BOPD. It is difficult to tell what these wells produced from 1953-1972, because they were
part of a larger unitized waterflood project. Our guess is around 200-250K BO during that
time frame.
Only a small company would be interested in 9 wells making 5.5 BOPD, but they have been
economic even during the worst part of 2016 (barely during Q1 – 2016).
There haven't been HZ wells drilled in the shallow zones (1,500' and below). However,
there has been some success with 1,800'-5,000' TVD hz wells. Not sure of the economics.
There has been success with slick water fracks in deeper vertical wells also.
No way. It's already here, and there will be no rebound. BTW I did carefully read your
comments above Dennis and thank you for your time to respond. As always, your responses are
significantly better than what my caustic remarks deserve.
As has been said many times, money does not equal geology. Even if a new tranche of
'investment' could be begged, borrowed, or stolen (likely stolen) it would be spent to build
new drilling equipment, pay for new leases/roads/infrastructure, with all of it into new
wells that will produce less than any before them. If inflation is a factor (and it is), the
borrowed & eventually defaulted upon money will buy less than before.
Shale started bad, and it will stay bad. No shale well was a gusher instead, they all
needed huge horsepower, millions of gallons of water, hundreds of tons of sand, and lots of
investment dollars just to get started. None of these were ever a Texas gusher. To me, this
is no business model to follow, it is a debacle.
We have seen hundreds of shale companies go bankrupt over the last couple of years. Going
forward, there won't be hundreds of bankruptcies because there won't be hundreds of shalies
to go bankrupt. Like the motorcar companies of old, it'll go from dozens of market
participants to a handful through M&A and bankruptcies. There is still plenty of surface
carnage to come and it is far from over. Bear in mind, this is largely the same crowd that
kept exclaiming a dropping 'breakeven' price from 2010 forward, to the point where $20 was
wildly shouted from the rooftops (particularly from John Mauldin) as the point of
profitability. Of course, none of it was true. Now we see at long last that $60 (and probably
$75) was the true breakeven point. Lots of C-suite executives should be in jail for their
malfeasance, but of course none are and with the exception of Aubrey McClendon, all of them
are still 'at large'.
So with all this in mind and to round off a long screech, I summarize by saying that 2019
is peak shale.
The small companies, which have gotten only B class land will have to reduce, leading the
decline.
The bigger ones can continue to grow to a certain amount – but using up their A
class land. Especially all non-Permian will see this very soon and start declining. So
Permian growth soon will not be enough to keep up all shale decline – and this at the
cost of the Permian Tier A claims.
Oil production from shale will have a long future if prices settle at 100$ – but
with worse land it will just not be a bit boom.
A boom means high drilling everything costs, in a long calm era everything has more normal
prices (why should a truck driver carrying fertiliser to farm tows earn much less than a
truck driver delivering sand to a hole). And so finally some money can be earned in the oil
spot.
If the Democrats take over and get more green, taxes on oil production will be increased
anyway, and tax credits cut – so more calm drilling anyway. This is a big "if", I don't
know how the D – R battle stands now.
" The golden age of U.S. shale is far from over, with an expected slowdown in the Permian
Basin likely to be temporary, according to the new U.S. Energy Secretary.
The shale boom helped transform the U.S. into a net exporter of crude and petroleum
products in September from a major importer a decade ago. Even as growth is set to slow next
year in the Permian and elsewhere as drillers respond to investor demands for capital
restraint, Dan Brouillette said the shale boom has further to run."
Permian Drillers Are Struggling To Keep Output Flat
Newer wells in the Permian see their oil and gas production declining much faster than
older wells, and operators will need to drill a large number of wells just to keep current
production levels, an IHS Markit analysis showed on Thursday.
IHS Markit has analyzed what it calls the "base decline" rate, calculating the actual or
expected production of all the operating wells at the start of the year and tracking their
cumulative decline by the end of the year. Over the past decade, the base decline rate of
the more than 150,000 producing oil and gas wells in the Permian has "increased
dramatically," according to the analysis.
Your article goes into a lot of depth. I noticed these statements:
"The main driver of Legacy Loss is Total Production, which is logical.
In Permian, higher Initial Production (IPt) increased legacy loss, probably because new wells
deplete faster than old wells"
New wells depleting fasting than old wells partly explains why the monthly legacy loss
keeps increasing from month to month. It's now close to 600kbd/month, according to EIA
DPR.
The chart below from the article shows Jan 2015 as Peak Shale No 1 as legacy loss was
above new monthly shale production. The author says when "red line gets above new monthly
initial production then that's Peak Shale No 2", which might happen as soon as early 2020.
This is shown by the dashed line "IPt minus Legacy Loss" reaching zero, which means Peak
Shale No 2. The author says that this could happen if WTI stays at $55.
The basic premise is that productivity per completion has stalled, and there is no longer
a huge overhang of cheap frac spreads keeping the frac market oversupplied.
And what, Dennis? How, pray tell, will 17 million horsepower -and other infrastructure
including manpower – magically re-appear in 2020 and inflate another peak? With
existing shale finances in the tank, $300 billion of already accumulated and un-repayable
debt, and Wall Street financiers demanding repayment on their investments, your
prognostication for a rebound has a tinge of 'wildly unrealistic' about it.
ExxonMoble boe per day is 2.25 millon and has a market value of $300 billion. The tight oil
shale play over the last decade has increased production 7 million bpd. Is $300 billion of
debt really out of line? Do you have CFO experience with a multi-billion dollar company?
In the trucking industry the major freight companies running 24/7 turn their tractor fleet
over on a 5 year rotation receiving 20 cents on the dollar at retirement. Ready mix trucks
are turned over after 10 years rotation at 20 cents or less on the dollar running 12/5. When
the business environment is good. It's easy to delay retirement a little to meet demand. When
times are difficult, the old trucks sit in the yard and can be stripped for parts.
I have to question your hair on fire comment. Do you know the life expectancy of a
drilling rig for a large corporation ? The related article is talking about retiring 10
percent. That's a 10 year rotation. Maybe replacement is just cost efficient verses down
time. The big boys don't work on the same time frame as the little guy.
HB. $300 billion divided by 7 million comes to over $42,000 per barrel of debt. IMO that
is a high level of debt unless oil prices recover to 2011-14 levels.
Only the best oil production is selling for that in our part of the world and that is
production with a decline rate of 3% per year or less.
Regarding XOM, keep in mind that includes not just the upstream, but the midstream and
down stream, both of which are substantial.
XOM also has substantial international upstream assets which are generating substantial
cash flow at $60s Brent.
The only reason there is any production of shale oil at all is that there is a combination of
cheap money and a plethora of desperate investors starved for yield. Well guess what, the
investors want a return on their investment and the cheap money is drying up. So, artificial
life support is being withdrawn and the patient is now expected to get off the emergency room
gurney and start working for his keep. We shall see how that turns out.
This whole exercise in perfidy is much like Uber, that has never made a profit to date,
and yet was supported by billions of investor dollars. The whole ignominious affair put
hundreds of thousands of cabbies into destitution and bankruptcy, i.e those who didn't enjoy
the largess of investors willing to put up with loss-making operations for years on end.
Uber and Shale; the twin shitstorms of inequity, capital misalocation, and widespread
collateral damage to their respective proximal markets.
I agree with your concerns Mike. It seems to me that debt will be accumulated in the system
until it needs to be defaulted on. The governments of the world have become expert on kicking
the can down the road.
But that path will end one day, perhaps suddenly. Default will come via one of several
mechanisms- currency devaluation and debt write-off, for example. Whatever method, it will
severely hurt those who were expecting pensions or government payments (Medicare/SS), or to
live on savings or investment yield. These things will be massively de-valuated. Negative
interest rates you have been hearing about are just the early symptom of this process. A
president who cannot release his tax returns because he has a long pattern of committing
severe financial crimes, is another. The extreme accumulation of wealth among the super
wealthy is yet another.
I have given up expecting a 'fair' or rational game.
The EIA has December 2019 C+C production at 12.99 million bpd. They have December 2020 at
13.28 million bpd. That is an increase, December to December of .29 million bpd. Quite a
comedown from the over 2 million bpd increase in 2018.
The financial struggles of the U.S. shale industry are
becoming increasingly hard to
ignore,
but drillers in Appalachia are in particularly bad shape.
The Permian has recently seen
job
losses
, and for the first time since 2016, the hottest shale basin in the world has seen job
growth lag the broader Texas economy.
The industry is cutting back amid heightened
financial scrutiny from investors, as debt-fueled drilling has become increasingly hard to justify.
But E&P companies focused almost exclusively on gas, such as those in the Marcellus and Utica
shales, are in even worse shape. An IEEFA
analysis
found
that seven of the largest producers in Appalachia burned through about a half billion dollars in
the third quarter.
Gas production continues to rise, but profits remain elusive.
"Despite booming
gas output, Appalachian oil and gas companies consistently failed to produce positive cash flow
over the past five quarters," the authors of the IEEFA report said.
Of the seven companies analyzed, five had negative cash flow, including Antero Resources,
Chesapeake Energy, EQT, Range Resources, and Southwestern Energy. Only Cabot Oil & Gas and Gulfport
Energy had positive cash flow in the third quarter.
The sector was weighed down but a sharp drop in natural gas prices, with
Henry
Hub
off by 18 percent compared to a year earlier. But the losses are highly problematic. After
all, we are more than a decade into the shale revolution and the industry is still not really able
to post positive cash flow. Worse, these are not the laggards; these are the largest producers in
the region.
The outlook is not encouraging.
The gas glut is expected to stick around for a
few years. Bank of America Merrill Lynch has repeatedly warned that unless there is an unusually
frigid winter, which could lead to higher-than-expected demand, the gas market is headed for
trouble. "A mild winter across the northern hemisphere or a worsening macro backdrop could be
catastrophic for gas prices in all regions," Bank of America
said
in
a note in October.
The problem for Appalachian drillers is that Permian producers are not really interested in all
of the gas they are producing. That makes them unresponsive to price signals. Gas prices in the
Permian have plunged close to zero, and have at times turned negative, but gas production in Texas
really hinges on the industry's interest in oil. This dynamic means that the gas glut becomes
entrenched longer than it otherwise might. It's a grim reality plaguing the gas-focused producers
in Appalachia.
With capital markets growing less friendly, the only response for drillers is to cut back. IEEFA
notes that drilling permits in Pennsylvania in October fell by half from the same month a year
earlier. The number of rigs sidelined and the number of workers cut from payrolls also continues to
pile up.
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The negative cash flow in the third quarter was led by Chesapeake Energy (-$264 million)
and EQT (-$173 million), but the red ink is only the latest in a string of losses for the sector
over the last few years. As a result, the sector has completely fallen out of favor with investors.
But gas drillers have fared worse, with share prices lagging not just the broader S&P 500, but
also the fracking-focused XOP ETF, which has fallen sharply this year. In other words, oil
companies have seen their share prices hit hard, but gas drillers have completely fallen off of a
cliff. Chesapeake Energy even
warned
last
month that it there was "substantial doubt about our ability to continue as a going concern." Its
stock is trading below $1 per share.
Even Cabot Oil & Gas, which posted positive cash flow in the third quarter, has seen its share
price fall by roughly 30 percent year-to-date.
"Even though Appalachian gas companies
have proven that they can produce abundant supplies of gas, their financial struggles show that the
business case for fracking remains unproven,"
IEEFA concluded.
Tags
Business Finance
"... StateImpact Pennsylvania noted that costs to reclaim a well could add up to $20,000, and DEPspokesperson Fraley said they could be "much, much higher." The GAO report noted that "low-cost wells typically cost about $20,000 to reclaim, and high-cost wells typically cost about $145,000 to reclaim." ..."
"... The Western Organization of Resource Councils summarized bonding requirements by state, and none of them came even close to being adequate to cover estimated costs to deal with old wells. In North Dakota, a $50,000 bond is required for a well. But a $100,000 bond can cover up to 6 wells, which comes out to $16,667 per well -- or approximately one tenth of the estimated cost to reclaim a well in that state. ..."
"... By any measure, the amount of private money currently allocated in the U.S. to plug and reclaim oil and gas wells is a small fraction of the real costs. That means oil and gas wells -- and the U.S. had one million active wells in 2017 , and even more abandoned -- will either be left to fail and potentially contaminate the surrounding water, air, and soil, or the public will have to pick up the tab. This represents just one of the many ways the public subsidizes the oil and gas industry. ..."
"... The mineral extraction business model in the U.S. is set up to maximize profits for executives, even as they lose investor money and bankrupt their companies. That is true of the coal industry and that is true of the shale oil and gas industry . ..."
Increasingly, U.S. shale firms appear unable to pay back
investors for the money borrowed to fuel the last decade of the fracking boom. In a similar
vein, those companies also seem poised to stiff the public on cleanup costs for abandoned oil
and gas wells once the producers have moved on.
"It's starting to become out of control, and we want to rein this in," Bruce Hicks,
Assistant Director of the North Dakota Oil and Gas Division,
said in August about companies abandoning oil and gas wells. If North Dakota's regulators,
some of the
most industry-friendly in the country , are sounding the alarm, then that doesn't bode well
for the rest of the nation.
In fact, officials in North Dakota are using Pennsylvania as an example of what they want to
avoid when it comes to abandoned wells, and with good reason.
The first oil well drilled in
America was in Pennsylvania in 1859, and the oil and gas industry has been drilling -- and
abandoning -- wells there ever since. Pennsylvania's Department of Environmental Protection
(DEP) says that while it only has documentation of 8,000 orphaned and abandoned wells, it
estimates the state actually has over a half million.
"We anticipate as many as 560,000 are in existence that we just don't know of yet," DEP
spokesperson Laura Fraley told
StateImpact Pennsylvania . "There's no responsible party and so it's on state government to
pay to have those potential environmental and public health hazards remediated."
According to StateImpact, "The state considers any well that doesn't produce oil and gas for
a calendar year to be an abandoned well."
That first oil well drilled in Pennsylvania was 70 feet deep. Modern fracked wells, however,
can be well over 10,000 feet in total length (most new fracked wells are drilled vertically to
a depth where they turn horizontal to fracture the shale that contains the oil and gas).
Because the longer the total length of the well, the more it costs to clean up, the funding
required to properly clean up and cap wells has grown as drillers have continued to use new
technologies to greatly extend well lengths. Evidence from the federal government points to the
potential for these costs being shifted to the tax-paying public.
The Government Accountability Office (GAO)
released a report this September about the risks from insufficient bonds to reclaim wells
on public lands. It said, "the bonds operators provide as insurance are often not enough to
cover the costs of this cleanup." The report cited a Bureau of Land Management (BLM) official's
estimate of $10 a foot for well cleanup costs.
StateImpact Pennsylvania noted that costs to reclaim a well could add up to $20,000, and
DEPspokesperson Fraley said they could be "much, much higher." The
GAO report noted that "low-cost wells typically cost about $20,000 to reclaim, and
high-cost wells typically cost about $145,000 to reclaim."
In North Dakota, where state regulators have raised concerns about this growing problem, one
of the top industry regulators, State Mineral Resources Director Lynn Helms, estimated that
wells there cost
$150,000 to plug and reclaim.
And this problem isn't just in the U.S. Canada is facing a similar cleanup crisis.
Financial Bonding Requirements for Well Cleanup
Legally, oil and gas companies are required to set aside money to pay for well cleanup
costs, a process known as bonding. These requirements vary by state and for public lands, but
in all cases, the amounts required are so small as to be practically irrelevant.
The GAO report reviewed the bonds held by the Bureau of Land Management for wells on public
lands and found that the average bond per well in 2018 was worth $2,122.
The Western Organization of Resource Councils summarized bonding requirements by
state, and none of them came even close to being adequate to cover estimated costs to deal with
old wells. In North Dakota, a $50,000 bond is required for a well. But a $100,000 bond can
cover up to 6 wells, which comes out to $16,667 per well -- or approximately one tenth of the
estimated cost to reclaim a well in that state.
North Dakota has a history of bending to oil and gas industry pressure when it comes to
regulations. While North Dakota's bonding rules fall far short of what's needed to actually
cover full cleanup costs, the reality on the ground is much worse. Regulators allow companies
to
"temporarily abandon" wells, which requires no action from companies for at least seven
years. Wells can hold this "temporary status" for decades. And another practice in the state
allows a company to sell old, under-performing wells to another company, passing along the
liability but not the bonding funds.
By any measure, the amount of private money currently allocated in the U.S. to plug and
reclaim oil and gas wells is a small fraction of the real costs. That means oil and gas wells
-- and the U.S. had one million
active wells in 2017 , and even more abandoned -- will either be left to fail and
potentially contaminate the surrounding water, air, and soil, or the public will have to pick
up the tab. This represents just one of the many ways the public subsidizes the oil and gas
industry.
A South Dakota Case Study
South Dakota allows companies to post a $30,000 bond for as many wells as the company
chooses to drill. Spyglass Cedar Creek is a Texas-based company that was operating in South
Dakota and recently
abandoned 40 wells, which the state has estimated will have a cleanup cost of $1.2
million.
However, there is a twist to this story. That $30,000 bond doesn't really exist. The owners
of the company had put $20,000 of it into a Certificate of Deposit. But when the state went
looking for that money, the owners said they had cashed it in 2015 because, as reported by the
Rapid City Journal , "company officials did not remember what the money was for."
Spyglass Cedar Creek does not have the money set aside that was required to clean up these
wells, the state does not have recourse to get that money, and some of the wells are reportedly
leaking. So, what can be done?
According to Doyle Karpen, member of the South Dakota Board of Minerals and Environment, the
answer is for the taxpayers of that state to cover the cost.
" I think the only way we can correct this is go to the Legislature and ask for money,"
Karpen
said earlier this year.
Following the Coal Industry Business Model
What is starting to unfold with the oil and gas industry is very similar to what has already
been playing out with the U.S. coal industry.
The paper notes how the bankruptcy process is used by coal companies to rid themselves of
environmental cleanup liabilities and pension costs "in a manner that has eviscerated the
regulatory schemes that gave rise to those obligations."
This summer, Blackjewel famously failed to pay its coal miners, and even pulled funds out of
their bank accounts, after the company suddenly declared bankruptcy in July. That prompted
workers to sit on train tracks in Kentucky, blocking a $1 million shipment of coal, in a
two-month protest . And Blackjewel is poised to leave behind
thousands of acres of mined land in Appalachia without adequate reclamation.
Privatize the Profits, Socialize the Losses
The mineral extraction business model in the U.S. is set up to maximize profits for
executives, even as they lose investor money and bankrupt their companies. That is true of the
coal industry and that
is true of the shale oil and gas industry .
At the same time, the regulatory capture by these industries at both state and federal
levels allows private companies to pass on environmental cleanup costs to the public, and the
inadequate bonding system for oil and gas well reclamation represents just one more
example.
The so-called fracking revolution in America has resulted in many new records: record
amounts of U.S. oil and gas exported (to the detriment of a livable climate), new levels of
human
health impacts on surrounding communities, record numbers of industry-induced earthquakes , record amounts of flaring
natural gas
in oil and gas fields, and record-breaking
depths and lengths of wells.
And the cleanup costs for the fracking boom are also poised to be staggering.
The answer to the question posed is yes. History confirms this. Present laws allow
companies to get away with this. I don't see this changing in the future.
Socializing the cost of cleanup/decommissioning was one of the reasons the people in our
township fought, and won, to stop Duke Energy's wind power project which would have put a few
hundred industrial turbines over three townships.
I was offered a contract and it was truly toxic. Duke would not have been required to fund
decommissioning until 20 years into what is a 25 year lifespan for the generators and that
bond would have been held in Duke's accounts. Duke could have merely walked away before 20
years leaving a liability for any landowner. My expectation would be a $250,000 escrow for
each tower/generator and held by the landowner so that Duke would have no access to it until
decommissioning.
My reaction to seeing the headline was "is the Pope Catholic?"
Of course, the public will pay. Texas govt already pays to cap abandoned wells.
As for decommissioning costs, utilities typically keep decom accounts, and include the costs
of decom in their revenue requirement, when coming in for a rate case. The money should be
there, when needed. (Of course, anything can happen – but if that were the case, we'll
have bigger things to worry about than the decommissioning of wind turbines.)
Rich Texans like small government when they can profit from governmental smallness.
Rich Texans like big government when they can profit from governmental bigness. If Rich
Texans can make the Texas government pay bigly for capping abandoned privately profitable
frack well, such Texas big government payments to cap the abandoned wells just make the Rich
Texans richer by relieving them of paying themselves for the costs they themselves caused by
fracking those wells.
1. Increase the EPA budget tenfold or more for cleanup, adding fracksites to the superfund
list. This will provide much-needed jobs for millions of Americans as they help in greening
Earth.
2. Require that Native American tribes get busy recovering natural resource damages. If
they refuse, this would provide a much-needed opportunity to establish military bases on
reservations to quell rebellions against superfund cleanup.
3. Some alarmists have alleged that cleanup of toxic superfund sites can pose health
risks, which is a well-known talking point of enemies of Earth. Even so, Congress can require
healthcare providers to deliver all necessary treatments to superfund workers in order to
assuage any concerns of the workforce.
4. Congress can relax labor laws so that undocumented migrants and their children are
allowed to participate in healing Earth by joining the superfund cleanup workforce.
These measures will ensure Full Employment, Earthhealth, Native Pacification, and
Demographic Diversity throughout the nation.
>>>Require that N<ative American tribes get busy recovering natural resource
damages. If they refuse, this would provide a much-needed opportunity to establish military
bases on reservations to quell rebellions against superfund cleanup.<<<
It has been a decade since I have done any research, but that said, requiring the
destitute to demand that they somehow get the money needed to get recompense from the Feds
and corporations is silly. Many tribes are dirt poor and others are marginal, even though
many nations have been trying for decades, perhaps longer than anyone alive, to get the
payments owned from the mineral and oil extraction from their lands. Records and payments
that the federal government are supposed to manage, but never have. Records go missing, the
decision making process is obfuscated, and billions have gone missing.
One of the big reasons I just loathe Identity Politics, victim blaming, and other current
dodges is that the current political establishment and all their little minions in social
media and nonprofits pay no mind to the continuing financial, political, legal and social
rape, impoverishment, and degradation of millions of Americans have and do endure is just
ignored. Although Standing Rock was a nice blip. At least the Disposables are worthy of
conscious contempt. The Indians are sent to oblivion where they can go finish
dying.
Well, yes and no. Yes, the public will pay for any 'cleanup' that is actually done (ie,
YOOGE dollars to 'remediation' companies), but really, my bet is that most of these orphan
wells and mines will just be left as they are.
Exactly what I was about to say. The wells will leak their toxins, the rich will escape to
some idyllic bunker, while the poor are offered oxycodone or fentanyl to alleviate their
suffering.
Cleveland is an example not one of the dying industries that once flourished here cleaned
up after themselves before they shut down most of the former degraded sites don't rise to the
level of a superfund problem, but they are virtually irredeemable nonetheless
do not know how the figure for abandoned well cleanup is derived. In Canada, estimates by
the industry friendly Fraser Institute and the CD Howe Institute claim those figures:
C.D. Howe estimates there are more than 155,000 wells with no economic potential that
must be reclaimed, with cleanup costs for an orphan well ranging from $129 million to $257
million, with a total provincial cleanup bill of $8 billion. Glen cites a far higher
estimate from the Orphan Well Association -- $47 billion.
And the problems regarding financing are the same as in the USA – although the
Supreme Court of Canada has ruled in favour of clean-up cost coverage before debtor
payout:
Glen quotes Daryl Bennett of My Landman Group who observes that not only are the funds
on deposit insufficient, but "the cost to reclaim all these assets is now far higher than
the value of those assets." With the oil and gas sector unable to shoulder these costs, the
costs look likely to land in two places -- the pockets of landowners with land dotted with
abandoned wells, and the taxpayers who will pay those landowners to ensure the land is kept
in productive use.
Energy companies must fulfil their environmental obligations before paying back creditors
in the case of insolvency or bankruptcy, Canada's Supreme Court has ruled.
The top court's ruling released Thursday overturns two lower court decisions that said
bankruptcy law has paramountcy over provincial environmental responsibilities in the case
of Redwater Energy, which became insolvent in 2015. That meant energy companies could first
pay back creditors before cleaning up old wells. In practical terms, that means energy
companies could walk away from old oil and gas wells, leaving them someone else's
responsibility.
I live in the hills of SE Ohio. Gas is everywhere down here, but (fortunately) not in the
commercial quantities needed for major fracking operations. Small gas wells dot the
landscape. Due to the crash and the oversupply of the fracking boom, gas prices fetch a small
fraction (about 20%) of their previous peak. No new wells have been placed in years.
A neighbor of mine has a has well that has ceased commercial operation. He still gets free
gas from it as per the lease agreement, but the small local gas company no longer wants to
pay to maintain and operate it, as in no longer yields any appreciable commercial output. The
gas company initially said that they would sell him the well for $7,000, and he agreed
(verbally, I believe) to that price. The gas company then said it wasn't even worth that, and
would just give him the well.
It struck me as decidedly odd that a business, which by all accounts is cash-strapped and
barely getting by, would voluntarily forgo any amount of money. It makes me think that there
must be certain laws and regulations that apply to a commercial transaction that do not apply
to what is in effect a donation.
Does anyone know if there are reasons why someone would give away as opposed to sell an
asset, particularly one that has clear and significant liabilities and/or associated cleanup
expenses? I know that the landowner should be responsible for cleanup and capping costs
whether they bought for money or were given the gas well for free, but does the gas company
get out of something by giving as opposed to selling the asset? They certainly did not do it
out of the kindness of their hearts; they hate that landowner. He opened up a business and a
commercial kitchen and hooked it to his gas well, which was almost certainly responsible for
its commercial depletion.
Can't give you that answer but have a similar observation. My homeplace is just up the
road a bit–bought sans Mineral Rights in the 1960's–and had a well placed just
off the property line on a pad located in the swamp/drainage next door in 1981.
We got no free gas–but hundreds in the Township couldn't resist. Too good to be true.
Lots of wells installed–with FREE GAS and a Royalty Check which helped many heat
through winter and constant Lay-offs in that churning, rust-belting economy of late 80's and
90's
It was a 90 day drill–24/7, then pumped with an electric skip jack until early 2000s
when production petered out.
Still idled–however that swampland finally sold 2 months ago–and Seller was
insistent that well ownership transferred with the sale. No transfer–No Sale. There was
a token of 1,000$ for the well included in the Land Price. The five adjoining landowners (all
No Mineral Rights and 2 with located wells) all looked at purchase and walked
away–partly because of the Lay(2 of 7 acres high ground) but all because you had to
take the "dead well" with the land.
Locals thought that was just plain "fishy" about something.
Ohio EPA isn't very effective–note the Mud Spill at the Tuscarawas R–and as more
and more well plays are petering out and Service Co.'s going out of business concern IS
rising among landowners.
I won't say my Homesteads neighbors are environmentalists as much as PO'd that the access
roads have not been graded and graveled and that inconsistent gas flows are causing them to
go Propane
It might come under Real Estate full disclosure laws, which require a seller to notify
buyers of any liabilities – like the cost of closing and cleanup of a well. Might not
apply to a "gift."
If course, if the owner keeps it operating for their own use, they don't have to cap and
restore it – but it will run out some day.
Not well understood is the fact that:
State taxpayers fund state spending, and
County taxpayers fund county spending, and
City taxpayers fund city spending, but
Federal taxpayers do not fund federal spending.
The federal government neither needs nor uses tax income for anything. In fact, federal
taxes are destroyed upon receipt.
The federal government, being Monetarily Sovereign, creates brand new dollars, ad hoc, by
spending.
Thus, all the federal spending to remediate any polluted sites in America add dollars to
the economy, and thereby benefit taxpayers.
Benefits natural-person taxpayers just how? By underwriting the looting behaviors of
corporations and their executives, sparing them from having to internalize the "costs" that
leavings from industry impose on "neighbors" and all the natural persons, and nature,
downwind and downstream and living next to those industrial and extractive spots? Not much
healthy incentive or public benefit in that formulation.
The federal "Superfund" was funded by a tax on feedstock chemicals, and "responsible
parties" that caused or contributed to the release of hazardous substances, anyone related by
contract to them, and site owners, were to pay all removal and remedial response costs. Why
not that model, which sought to force the costs back into the calculus? And yes, the
Superfund program had its share of problems, still does -- contractor gold-plating,
goldbricking, and fraud, corruption of the processes, and others, and of course the exemption
of "petroleum products" from the definition of hazardous substances. But it did effect some
significant changes, along with the federal Resource Conservation and Recovery Act, in
generation and disposal of hazardous substances.
Its pretty simple. Most governments have been collecting royalties on the extracted oil
and gas. They can just repurpose that past and future money to cleanup. The politicians said
it would pay for schools and firemen but future politicians will likely need to repurpose
money. At least Superfund exists, so there is a mechanism to do it.
In Colorado there are 60,000 active oil and gas wells and 20,000 that are abandoned. That
count is from 2017. Several thousand more wells have been permitted and drilled since
then. https://corising.org/colorado-map-oil-gas-wells/
A more-to-the-point question in response to this title is; When has Big Oil, Big Mineral,
Big any natural resource exploiter ever paid to clean up their mess? The answer is only when
there is a gun at its head and all the owners have not yet run off with their booty.
Beulah, North Dakota, has a coal gasification plant, open for free public tours. It's a
closed loop – shallow strip mining on their property, has sold to a single nearby
customer. The size of the equipment is mind-boggling. They are required to recontour the land
to exact pre-mining measurements and to replace every shrub and tree. The reclaimed land
looked lovely.
As a passing tourist, I know nothing in depth, but I was impressed and see no reason why
the same is not required of any resource extraction.
I think it's time we take a long hard look at this country's bankruptcy laws. For as long
as I can remember, bankruptcy has been a "tool" of business to escape what is most often the
responsibility of the business and/or business owner. See DJT et.al. The idea that a business
like the ones in this article can declare bankruptcy , dump the debt owed to creditors, and
continue to give huge bonuses to management members is foolish. When a business like the
fracking industry operators can't pay it's debts, the doors should close, the assets sold and
the creditors (in this case, the state involved) receive everything necessary to "clean up"
the mess. Most cases involving fracking wells would need more in funds than the company has
in assets. Bottom line, that's it folks. The state gets it all (which will almost never be
enough) and the folks go home, no bonus, no car, end of story. Many things would change in a
system that does not allow the dumping of debt onto society so people who were very bad at
running a business can continue to be rewarded. Just sayin ..
In many cases, the state could impose a unit royalty dedicate to future clean-up. The
royalties could go into a dedicated trust fund. The cash flow of producing wells would set
aside the means to cleanup many wells.
If by "the public," the author is referring to federal taxpayers, the answer is, "NO." Not
well understood is the fact that:
State taxpayers fund state spending, and
County taxpayers fund county spending, and
City taxpayers fund city spending, but
Federal taxpayers do not fund federal spending.
But, but, but we are "energy-independent!". Surely a small price to pay for massive
environmental despoliation in the era of late-capitalism, where "externalities" are booked on
the public ledger.
Yes, so Dubya invades Iraq to make sure the supply of black gold to the US is not
interrupted (and hey Dad – look, we got Saddam .), then the pendulum swings and Obama
mostly pulls out of the ME and " encourages" fracking to get domestic oil security. In the
meantime the political vacuum caused allows the rise of ISIS, so Syria is destroyed and
millions of refugees overwhelm Jordan, Turkey and Europe. Then along comes Trump and doubles
down, allowing the Saudis to commit unfettered genocide in Yemen (with a nice little side in
US arms sales), and now the Turks to indulge in a bit of "ethnic cleansing" of their Kurds
– you know that mob who have fighting for a bit of their own country for a hundred
years since they were unfortunately overlooked when the British and French divided up the
Middle East.
We all really need to get off this addiction to fossil fuels ASAP and convert to electric
cars and road transport and household and industry power derived from solar, wind and hydro
electricity.
It is not just climate change which is the " collateral damage" of fossil fuel use.
And in my country we have to do the same, and STOP MINING F .. COAL and allowing new coal
mines to be run by environmental vandals like Adani. AAAAAAAGH!
Obama pulled out of the ME? I must missed that during the US invasion/occupation of parts
of Syria as part of its illegal regime change war, that provided safe haven for jihadists and
ISIS in Syria
Skip-As I read it Obama pulled many, but not all obviously ,of the troops from Afghanistan
and Iraq, – and was widely criticised for doing so "prematurely" by the media and
commentariat.
Mind you, that could have been just " fake news" .
Of course that the Public will pay for the environmental cleanup of the pollution of dead
fracking wells. Just as they will pay for dead oil platforms in high seas, or
"decommissioning" of spent nuclear fuel (when someone figures out how that's done), or
underfunded pension plans or any other such scam that was advertised as doing something for
greater good but which always was, and always will be, extraction of something out of
presumed public ownership (earth) for benefit of those who figured out what to extract.
Bottled water comes to mind too.
How will public pay? Entropy, of course. No need to involve printed papers masquerading as
"money". Public will simply work harder and harder, but will have less and less of
everything, firstly less hospitals and schools, then less police and firefighters, then less
judiciary and then less water, less food and less air suitable for breathing.
The sad part is, we taxpayers, continue to live in an imaginary world where we expect that
"government" will do "something for us, the people". Governments do not look at it that way.
"Governments" are just an extraction apparatus, by which those that can extract, extract, and
those that cannot, provide the extracted material.
I looked at governments and economical systems all over the world and there is no
exceptions to this. The conundrum is, what to do about it and how?
I apologise to the commentariat but I simply must enclose two links to my favourite brain
washing outlet, BBC, here in UK. While our parliament continues to work for everyone else but
the British People, the Big Brother outfit goes on to disseminate dross like this:
It seems as if ole David Hughes, which I have a lot of respect, decided to come on the
website and leave a few comments. Basically, Hughes's reply was, "WHAT'S THE BIG DEAL IN
2018?" He went on to say that we all know these wells decline 50+% in the first year, so why
start to make a STINK about it now?
I also had several email replies from some other folks. And then we had a bit of a TIT for
TAT here in this blog with HUNTY.
However, what is going on in the Permian is only a small part of the overall situation.
Regardless if we bicker about the future Permian revisions due to the incomplete TRRC data,
the fact remains, if you look at the "Annual Compounded Decline Rate" presently, it resembles
a 70-75% STEEP CLIFF. And, the Permian isn't the only one that looks like that. You can add
the Bakken and Eagle Ford to varying degrees.
So, while a portion of the "OIL FOLKS" and a large percentage of the "DUMBED DOWN PUBLIC"
believe there is NOTHING TO SEE HERE, they couldn't be more wrong.
Furthermore, the U.S. public debt just ballooned by $227 billion in less than two weeks
and $814 billion since August 1st. While everyone has seemingly become NUMB to the amount of
these figures, the rate at which debt is being added in the United States and globally is
heading up in an exponential trend. But, there is nothing to see here.
And, then we have the fun taking place in the REPO MARKETS when, according to a specialist
in the field, a large BLOCK of CASH has been removed from the market and hasn't come back, I
gather it's just another sign that EVERYTHING IS OKAY . .nothing to see here.
Also, ExxonMobil, the largest U.S. oil company, had to borrow $7 billion in August to
repay the huge $11 billion in short term paper it borrowed 1H 2019 in order to pay dividends
and fortify its balance sheet as its Permian stake is destroying its bottom line.
And today, we see that ExxonMobil just sold its $4.5 billion upstream assets in Norway.
Yes, this is part of Exxon's plan to sell $15 billion by 2021 to focus on KEY ASSETS. I
gather that really means, they are going to have to fill in the RED they will be suffering in
the Permian as its U.S. upstream earnings continue to suffer. But again nothing to see
here
Lastly while the NOTHING TO SEE here mentality will continue even as the U.S. and global
economy heads over the cliff, taking the highly leveraged debt-based financial system down
with it, I'll make sure that I schedule some time from my day to come in here and read all
the "I TOLD YOU SO" comments.
Pop on over to the BP spreadsheet and find the regional consumption tab. For some regions
there are countries broken out and for others, not. But on this tab you can get granularity
on what kind of oil, what constituent part of crude, was consumed.
Japan. The population decline is actually pretty recent -- only since 2010. Their decline
in consumption is popularly attributed to population reduction, and I have gotten this wrong,
too, but consumption decline has been since 1995 with population gain for 15 of those years.
In more detail, their consumption decline is not gasoline. They have increased gasoline burn
since 1995. (The Prius is the 2nd most popular car in Japan and it first went on sale in
1997, so Prius didn't kill gasoline burn, which has increased).
It's middle distillates and Fuel Oil that are way down. Stuff that fuels big commercial
engines. That's what has fallen. Fuel Oil is more than maritime bunker fuel. It powers big
stuff. There was a sharp uptick of Fuel Oil consumption . . of 44% in 2012 because it was
Fuel Oil that was called on to generate electricity when all the reactors were shut down
during the quake panic. But the reactors returned and Fuel Oil resumed its decline.
One last thing that could blow all those paras out of the water. Japan had until recently
more refinery capacity than internal consumption. It's a lot like Singapore. The crude comes
in and product exports and this seems to somehow corrupt all measurements. The govt recently
shut down many of the refineries. It wasn't voluntary. Gov't ordered. Now Japan has to import
fuels, not just crude. Quite a lot. Which likely confuses the consumption measurements
further.
Ok I read this blog quite regularly but now I'm confused. US oil production has actually
fallen since the start of the year?
Dennis, can you respond to that? I thought I was just reading in the last post that the
current completion rate in the Permian was enough to raise production for five more years or
so. July is probably skewed because of the hurricane, but what gives?
It's definitely slowing. See my first post on June monthly production. When you add all the
states with shale production, there is no growth from May to June. Yes, July should be down
significantly due to the hurricane, but I expect no growth from shale.
Dennis sees an increase, Ron sees it plunging. I see it flat for a few months, and slowly
trending down. Pick your poison.
Yes the increase is pretty small for tight oil over the next 5 years only an average
annual rate of increase of 344 kb/d for US tight oil from 2019 to 2024 for the flat
completion rate scenario. This is a far cry from the 1620 kb/d increase in US tight oil
output from Dec 2017 to Dec 2018, a factor of 4.7 times slower on average than the rapid rate
of increase in 2018.
No US C+C output in June 2019 was 12,082 kb/d and in Dec 2018 US C+C output was 12,038
kb/d, so output has risen, but not by much. Yes a flat completion rate could lead to a rise
in tight oil output until 2025, though conventional output could fall to offset this.
Conventional output has been falling of late as fewer new conventional wells have been
completed for the past 6 months.
The current financial strain on shale producers is likely to intensify as many companies that
took on debt after the 2016 oil slump face large debt maturities in the next four years. As
of July, about $9 billion was set to mature throughout the remainder of 2019, but about $137
billion will be due between 2020 and 2022, according to S&P.
Seems that there will be more bancurupt filings in the years to come.
What is interesting is the footnotes. The first one says: " The supply of existing oil
production naturally declines at an **estimated 7 percent per year** without further
investment. Significant investment is needed to offset this natural decline and meet the
projected demand growth." The 7 percent figure caught my eye.
Also see the footnote about the switch over to Biofuels but Biofuels are such a very small
amount.
Continuing to look at the Regional Consumption tab from the World Stat stuff.
There is this category called Others. BP defines it as:
" 'Others' consists of refinery gas, liquefied petroleum gas (LPG), solvents, petroleum
coke, lubricants, bitumen, wax, other refined products and refinery fuel and loss."
This is not trivial afterthought. This is over 20% of the total oil consumption for nearly
all countries/regions. 24% for the whole world, and that deserves a !!!
It's 41% for India, also deserving a !!! I happen to know this derives from LPG, a hugely
popular transportation fuel in India.
China, 30%.
US 22.6%
India's total oil consumption last year was 5.9%. Light distillates had 10% growth,
gasoline 8.9%. Others, 6%. EVs and hybrids did nothing to gasoline burn there, which you
would expect for such a narrow niche product for rich people in year-round warm cities. They
didn't drive much anyway. And of course rural driving is a big thing in India, per the recent
item about political campaigns travelling place to place by road.
China's total oil consumption last year was +5.6%. Light distillates +7.3%. Kerosene/jet
fuel + 14% (!!!) Others, 7.1%.
And ditto.
As noted above Japan's consumption drop has been from lost economic activity, not
population, and it burns more gasoline today than in 1995, so Prius didn't do much there.
Their big loss is in middle distillates, because they shut down a lot of factories. Repeat,
population ROSE in Japan up to 2010. Only since then has it fallen and middle distillate
consumption (and Others consumption) has been falling steadily since 1995, even when
population was rising.
First you lose your economy, then you lose your food.
(Caveat about refinery exports from previous comment)
From the EIA monthly I see the US oil and condensate production was:
April 12. 123 Mbpd
May 12. 115 Mbpd ( – 8 000 bpd / 0,1%)
June 12. 082 Mbpd ( – 33 000 bpd/ 0,3%).
Will be very i teresting to see the production for July and August including new pipeline
capacity. To me it seems like the DUCS that was good have now been used, Baker Hughes drill
statistick document number of riggs still go down. In January EIA and Rystad believed US oil
production would reach 13 Mbpd in 4th Quartile 2019, the truth is this might already be below
12 Mbpd . As they told the growth in US shale have be funded by borrowed money , now
investors have far from get back what they where promissed, they are pissed off
There is no good real time data, at least not publicly available, on global stocks but US
stocks have declined so far this year ( https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCESTUS1&f=W
). It seems to me that we are starting to see the effect now on lower OPEC production (cut or
whatever reasons) and LTO not growing as fast as forecasted.
A quote from IEA's last OMR (
https://www.iea.org/newsroom/news/2019/august/economic-woes-hold-sway-over-geopolitics.html
): "If the July level of OPEC crude oil production at 29.7 mb/d is maintained through 2019,
the implied stock draw in 2H19 is 0.7 mb/d, helped also by a slower rate of non-OPEC
production growth." Note that this assumes LTO-growth in US causing the market to be
oversupplied next year
The market sentiment is currently bearish on oil for whatever reason (US LTO growth,
economic slowdown, etc.), you can see this on the yield curve that Art provides, the curve
has become more flat ( https://pbs.twimg.com/media/EDENJx2XUAIR5lC.png:large
). I find the herd mentality of the oil market interesting and would not be surprised if the
herd changes direction in a not too distant future. The big question mark I see is what will
happen with the Iran-deal if/when stocks continue to decline.
Even though Norway is "the darling of alternative transport", EV sales are still a small part
of their transportation mix. All-electric 7.8%, Plug-In hybrids, 3.6%, and Hybrids 4.0%.
Without the impact of EVs, their consumption would likely have been higher.
It looks like Nick Cunningham, the author of the article below, reads peakoilbarrel.com
"The more important point is that the oil industry is slowing down more generally.
Most oil forecasters expected explosive production growth to continue through this year
and into 2020. But with June U.S. production at 12.082 mb/d, output is only about 80,000 bpd
above levels seen at the end of 2018. In other words, growth has been pretty slow this
year.
Financial stress is really setting in, forcing drillers to cut back. The rig count fell by
12 in the last week of August, part of an ongoing slide since reaching a peak late last year.
Bankruptcies are on the rise. As the Wall Street Journal notes, an estimated 26 U.S. oil and
gas companies have declared bankruptcy this year, which is close to the full-year 2018 total.
More are expected.
Worse, there is a tsunami of debt that comes due in the years ahead. According to the WSJ,
roughly $9 billion worth of debt was set to mature over the second half of 2019. But a
whopping $137 billion in debt matures between 2020 and 2022, a massive total that stems from
the huge debt issuance following the oil market meltdown a few years ago. A serious reckoning
is just around the corner."
Raymond James recently estimated that over the last three years the U.S. decline rate for oil has doubled from
1.6 to 3.2 million barrels per day. The drilled but uncompleted well inventory ("DUC") is back to normal, so the
number of wells being drilled and the number of wells being completed is now about the same. We need over 12,000 new
horizontal oil wells completed each year to hold production flat and the number of completed wells will need to go up
each year.
The U.S. Energy Information Administration ("EIA") forecast at the beginning of this year was that the U.S.
shale oil plays were just getting started and that production would increase by at least 2 million barrels of oil per
day ("MMBOPD") each year for several more years.
Now if you believe that U.S. shale production will increase by 2 million barrels per day each year for several
more years, then I have a bridge that I think you might be interested in. But let's just play "what if", or what if
it really did increase by 2 million barrels per day for the next five years.
According to the EIA's Drilling Productivity Report, December 2018 shale production, all basins, was 8,232,750
barrels per day and the legacy decline, for all basins, averaged 6.14 percent per month or 505,737 barrels per day.
Legacy decline of over one million barrels per day would be a crippling requirement of shale producers. But not to
worry, that is simply not going to happen. Now total US production did increase by two million barrels per day 2018.
In fact, according to the EI.s Monthly Energy Review, US production increased by 2,064,000 barrels per day in 2018.
But for the first 7 months of 2019, total US production has declined by 54,000 barrels per day.
USA production appears to have hit a snag. July production is now below November 2018 production.
In my opinion, legacy decline in shale production has reached a point where new production only replaces legacy
decline. In fact, legacy decline may have reached a point where it is crippling shale oil production.
Those who have followed this blog for years know that Texas oil production is reported by the Texas Railroad
Commission. But their data is very slow coming in, sometimes it is more than a year before all the data has come in.
However, Dean Fantazzini, Energy economist, Deputy Head of MSU's Chair of Econometrics and Mathematical Methods in
Economics, has developed a program that uses the vintage data to make a pretty good estimate of the actual data. His
past corrected data has been relatively accurate.
If Dr. Fantazzini's data is correct then Texas peaked in December 2018 and has declined by 280,000 by June.
All the below charts were created from the EIA's Drilling Productivity Report. The data is through September 2019
and the last few months is, of course, an estimate. Historically the estimate for those last few months has been
overestimated.
Notice the last six months is pretty much a straight line. That is because most of it is just an estimate.
It looks like the Permian is pretty much the story as far as US shale is concerned.
The Permian is now just over 50% of total US shale production.
Permian Legacy Decline has been slowly rising and now sits at about 6%.
Eagle Ford has the highest legacy decline rate, now about 8.5% per month.
It looks like shale production, outside the Permian, has pretty much hit the wall. Pay no attention to those last
four months. They are just the EIA's wild ass guess.
In conclusion: Very high legacy decline, now over 6% per month, is shale's Achilles heel. Of course, there are
other problems as well. Bankruptcies are rampant, running out of sweet spots and the price of oil is just not high
enough. It appears that the USA has peaked, or peaked until the price of oil rises at least $20 a month.
Dean's charts self correct after a couple of months. Good estimates. Red Queen is already catching up. And,
it will catch up faster the next six months from June, as most of the independents have severely cut back on
capex.
Your Wall Street journal link has a firewall. Never mind, I got through. Good post.
Pioneer has not only reduced its capex, it's reduced its workforce by 25%. Apache has given up on
the Alpine High, their biggest capex. It's 90 % gas, how stupid can you get? Yadda, yadda, Yadda. Just
google the company for capex, and put 2nd quarter 2019. Voila!
Your sure to get a positive statement from the company, but just concentrate on the capex going
forward. For example, we're losing money had over fist, translates to reduced operating expenses will
provide an increased return for 2019. Get serious. None of these companies are going to say, we are
screwed.
EOG could make it, most of the rest are totally screwed.
"I have no doubt in my mind that U.S. shale will peak, plateau and then decline like every other basin in
history," Al-Falih told reporters at OPEC's Vienna headquarters. "Until it does I think it's prudent for
those of us who have a lot at stake, and also for us who want to protect the global economy and provide
visibility going forward, to keep adjusting to it."
Dr. Raymond Pierrehumbert will be proven right belatedly.
The article does say US production still has an up side, but prices would have to be higher.
If there is
not enough supply then oil prices will obviously go higher as the did in 2003-2005 and in 2012-13.
US drilling rig count is very low at the moment being only 742, at it's highest recently the US could
have 1,400 drilling rigs working.
1,400 drilling rigs will certainly complete enough wells so new supply would exceed decline rates. When
oil prices are over $100 as they were in 2012 and the number of drilling rigs are 1,400 then you can wake me
up.
You want to focus on horizontal oil rigs. The count was as high as 1100, but many of those rigs
were lower power rigs no longer economic to operate, a lot of the current rigs are higher power and far
more efficient at drilling 3300 meter laterals commonly drilled today.
Holy f*ck Hugo, you are a raving lunatic. The oil prices can't go higher, otherwise there will be a
repeat of 2008. Clearly you are incapable of learning from the past.
Yeah, there is sort of a contradiction there. Sorry about that. But we are seeing the physical limits hit
in much of the world, regardless of the price. But if oil hits $80 to $100 a barrel, a lot more shale
could be produced. But that will not change things in the long run. It could delay peak oil by a year or
two.
In a
study of 29 fracking-focused oil and gas companies by the Sightline Institute and the
Institute for Energy Economics and Financial Analysis (IEEFA), only 11 companies posted
positive free cash flow. Even then, the figures were paltry. Collectively, the group only
reported $26 million in free cash flow for the second quarter, "far too modest to make a
significant dent in the more than $100 billion in long-term debt owed by these companies, let
alone reward equity investors who have been waiting for a decade for robust and sustainable
results," the report said.
I think a key point about a future shale bust is that it will leave very little in long
term assets. In other busts, someone comes along to cherrypick the assets with potential
profitability – its the early investors who get burnt. But if shale operators aren't
even breaking even on cashflow excluding early borrowings, then its likely that any attempt
to consolidate and shrink the industry to make it profitable would fail in the absence of a
significant price rise. Since a typical fracked well for tight oil or gas has about 18 months
production, this means that constant capital inputs are essential, an investor can't just get
a free ride for a few years on past investments.
What this means in reality is that a year or more after the inevitable bust, there will be
a massive drop off in production. Ironically of course this will lead to exactly the sort of
price rise the industry is craving – but by then it may be too late. It could of course
also be highly disruptive to the world fuel market if the US suddenly finds itself needing a
few million barrels a day of SA crude.
I tend to think of shale as an out of the money option, that the industry keeps on early
exercising to generate the appearance of a going concern, despite it losing money. As absurd
as this model of events sounds, it would predict that in a consolidation, these assets would
be picked up by oil majors, who would "mothball" till higher prices. Of course the longer
these bozos are allowed to pump at capital depleting oil prices, the less there is for the
eventual buyer in bankruptcy.
There's an interesting story in Reuters today about how towns in the Permian are starting
to make long-term bets on shale production there, in the form of investing in education and
infrastructure. It seems like the entrance of oil majors sent a signal to people there that
the bust hasn't come yet and apparently won't come for a little while. After reading the
coverage of fracking on NC and Bethany McLean's book Saudi America this seems like a bad
idea, as the financial problems of fracking stem from physical limitations of the technology.
It doesn't seem like a big oil company would be able to solve this problem, besides maybe
having deeper pockets and greater ability to ride out low prices, but that still doesn't make
fracking profitable, just less unprofitable. Here's the link:
Yes, I fwded that link to Yves & Lambert earlier today – the key thing to me is
that the oil majors don't make such long-term investments lightly. From the story:
Some of the smaller producers that pioneered shale drilling in the Permian, such as
Concho Resources (CXO.N), Laredo Petroleum (LPI.N) and Whiting Petroleum (WLL.N), are
downshifting as West Texas oil prices have lost 16% and natural gas has tumbled 36% over
the past year.
But the world's biggest oil majors are increasingly taking control of the Texas shale
business, and their drilling plans – sometimes sketched out in decades rather than
years – are envisioned to withstand the usual price drops.
The Permian Strategic Partnership, a group of 20 energy companies operating in the area,
promises to spend $100 million to promote training, education, health care, housing and
roads. The partnership chipped in $16.5 million for the charter school initiative, which
will open its first campus in August 2020 and plans to offer public education to 10,000
students over time.
The only thing in all this that is baffling me is that Wall st. just keeps giving loans to
and buying bonds for these companies to the tunes of 10s of billions of dollars. Everyone on
Wall St can't all be willfully in denial and completely blind to the fact that these were bad
investments from the beginning and that continuing to give them money is just throwing good
money after bad. Everyone makes a bad investment from time to time, but the solution isn't to
just burn money indefinitely to turn it into a zombie corporation when there are no signs it
will ever be profitable – indeed from what I have read fracking and shale's best ROI is
right after the well is turned on, after that it only gets worse so these bad investments are
only gangrening and rotting faster and faster. Yet still, ever more more money from Wall st.,
the same people who chide any and all public services for being unprofitable and engendering
unprofitable subsidized behavior.
So if they can't all be that stupid, the only other explanation is that at least some of
them are just plain evil. In this case that would entail them working on "greater fool
theory" where they are planing something like the old sub-prime mortgage CDOs. Something
like: 1. package all this festering financial garbage they created into illegible little
financial products; 2. pay-off the rating's agency to give this repackaged garbage AAA
rating; 3. sell to sovereign wealth, retirement, and pension funds; 4. take out
credit-default swaps and other bets against the garbage they have sold off because they know
it is going to imploade; 5. run like hell; 6. blame poor people for destroying the economy
while begging for a government bailout as a result of fallout from destroying the world
again.
I'm somewhat familiar with Noble Energy, one of the 29 companies the authors claim to have
examined.
They report Noble as having a cash flow deficit of $499 million, a full 20% of their grand
total for all 29 companies. The grand total, of course, purports to demonstrate the weakness
of the US shale plays.
The thing is, the cash flow from Noble's shale operations in Texas and Colorado is solidly
positive. The company has a cash flow deficit because it is finishing up its share of the
Leviathan project offshore Israel, which by this time next year will have that country energy
independent while enabling a massive shift from coal to natural gas as their primary energy
source. Not a bad thing, IMO.
The anti-hydrocarbon jihadists have some valid points, but they also generate a lot of
propaganda that has no relation to reality. This "study" is an example of what happens when
you know the answer you want before you do your investigation.
The risks and benefits of hydrocarbon energy is an important question. Unfortunately
there's a lot of garbage produced on both sides.
Why should the Shale Business feel bad about bleeding money? It isn't their money. It is
"other peoples' money". It is investors' money. As long as the Shale Business operators are
retaining for their personal selves some of the "investor peoples' money" which they are
bleeding from investors, why should they feel bad about it? Maybe their whole business model
was based on bleeding other peoples' money till other people have no more money left to
bleed. . . . and keeping a little bit of the money-bleed for themselves.
It's like with mosquitoes . . . . mosquitoes aren't "bleeding" blood. They are sucking
blood. It is the animals they are sucking blood FROM . . . which are bleeding blood. If the
animals eventually die from blood loss, the mosquitoes at least got some blood in the
meantime.
And so it is with the shale frackers. They aren't bleeding money. They are sucking money.
The investors they suck money from are the people who are bleeding money. And if the
investors finally die from money loss, the shale frackers at least got some money in the
meantime.
The only production preventing Oil from peaking as far back as 2013-2014 was US Shale,
which can only function by borrowing Billions from gullible investors that will never be paid
back. If investors were not so gullible, US production would have peaked years ago. Global
Peak Oil is controlled by cheap & easy credit. Take away the credit punch bowl and US
Shale production collapses, and global production peaks. PO is no longer dependent of
geology, but credit.
FWIW: I suspect Shale drillers are going to have a hard time finding more investors
willing to part with their capital, especially when Oil prices are very low. That said its
possible that the Federal gov't (via Fed) will step in and start buying billions of shale
debt (via QE or some other financial bailout mechanism) so Shale drilling can continue on. It
appears that the US is running into liquidity problems again as Bond markets are showing
signs that they are freezing up again.
Banks and investors took away the punch bowl, and second quarter losses reflect that. Third
is going to be the same, and too late for any price increases to reflect anything but losses
for this year. No positives going into 2020. Their best option is to find adoption. And being
a bunch of spoiled brats, that's going to be somewhat difficult.
I agree that shale has been the biggest contributor to increase in global oil supply.
However it has also distorted the entire industry.
If the shale companies had to make a profit each year, global supply would have been a
less and prices much higher.
This in turn would have supported e&p investment around the world. The fall in
investment has been due entirely to shale companies that have been allowed to run at a loss
for so many years.
I don't think we would see a massive rebound in E&P if US shale was eliminated. Shell,
Exxon, BP and other started pulling back on Megaprojects back in 2012-2013, since it was
doubtful that it would be economical. Basically megaprojects (deepwater & arctic)
required $120 to $150 (in 2013 dollars) per bbl to be economically. I don't believe those
prices would be sustainable as it would result in demand destruction as consumers would cut
back on consumption. The fact that Oil majors were looking at Arctic and deepwater back in
2010-2013 indicates they are reaching the bottom of the barrel for production. There was a
long term trend of declining exploration finds even when exploration budgets increased.
At this point any major rebound isn't going to make a difference, if a Oil major started
on a new megaproject it would be between 5 and 7 years before new oil reaches the market, and
very unlikely to offset declines from existing production (5% to 7% annual declines). We are
already behind the curve on gains from any new projects to offset ongoing declines with out
shale growth). Perhaps a some of the declines in existing fields could be offset some with
higher oil prices. Still reaching to scrap the bottom by trying to extract trapped oil in
fields in terminal decline. With all of the supergiants in terminal decline (with the
exception of Kazakhstan), its going to be very difficult to expand production further.
Personally I am guessing that global production has already peaked or within the next 18
months if we are lucky). Its difficult to pinpoint an exact period since their are way to
many variables to gage effectively. That said I cannot say my record for guessing peak
production is any better than winning a lottery, but as the window narrows due to depletion
and a shrinking supply of future projects the guessing gets a lot easier.
Shale had already taken off by then and predictions of possible productions were being
made and importantly have come true.
The majors would have realised there would be too much oil in the short to medium term, so
they sensibly postponed more expensive drilling.
How this mess with heavy indebted shale companies and years of under investment plays out
I am not sure.
Probably a lower and sooner peak oil than would otherwise have been.
Not sure anyone has said US has peaked, the point is that US tight oil growth will slow
and it is not apparent that any other nations are increasing output in 2019, so far the drop
by OPEC/NOPEC has been greater than any US increase in 2019 and it is looking like 2019
output will be lower than 2018 if current trends continue. When we get to the point that oil
prices rise to $80/b, I expect OPEC/NOPEC will increase output, but we do not know when that
will be and it is certainly possible that US output might be falling at a faster rate than
the rest of the World's rise in output so the net might be a plateau or decline.
Note also that my "medium URR" estimates might be too optimistic, if my "low URR
scenarios" prove correct, the peak is likely to be earlier (2022/2023), and if there is a
fast transition to EVs, more public transport, etc perhaps the peak in World C+C output could
be earlier still. I doubt this will be the case, but in the past I doubted that World C+C
output would exceed 80 Mb/d, I was wrong then and I may be wrong now.
Hugo, something peaked in 2011, so I'd say the peak oil gang is onto something worth
listening to. Perhaps you disagree. The graph is a bit dated, but you get the point I'm
sure.
I'd say calling peak oil to be in 2018/2019, vs to be within 2022 to 2026 time frame, is
pretty much splitting hairs. Perhaps you're just smarter than everyone else here and don't
tolerate such loose parameters?
How did you come to your prediction, riding on Dennis' coattails, or do you have any original
ideas of your own to contribute?
The assumptions make all the difference. And no one can accurately predict what will happen
the rest of the day, much less tomorrow.
The key to the future, so far, is how the majority of independents will fare. Dennis sees
prices improving so that many of them heal up, and production is restored to a norm. Ron sees
them as totally messed up, which is more my take.
And I am also betting on the majors. They don't lay out hundreds of billions of dollars
for downstream without a big plan in mind. And, that plan could not call for those
investments to be totally useless in ten years. It wouldn't surprise me to see the skies over
the shale areas filled with golden parachutes.
Ten years, or less, based on EOGs quarterly tell sheet. Do you opt for the golden
parachute soon, or use your own just before the plane crashes?
Inventory draws should begin to pick up for the US soon. 1 million in pipeline from the
Permian to the coast. Exports to increase, Cushing to decrease, and production mostly flat. A
lot of the Permian production has been going to Cushing as an outlet. Depends on how much can
be loaded on to ships, now, and how much lite oil can be sold. Pipelines are going to be
losers for awhile. Additional pipelines need to take note.
There are two, sure fire, statistics and reports that will define where we are going. You can
argue them, but you will lose. One is the EIA monthly 914 report, the other is the Texas RRC
permits. There's some DUCs, but by this time, I consider them as normal DUCs between drilling
and completion as is norm. And the 914 May show it up a little for June, but I don't see it
going up further. Or, much more.
Attached is the latest LTO data from the monthly EIA 914 page. The main difference that I
can see is the drop in the monthly production growth from 2018 to 2019. 2018 production
growth averaged 153 kb/d/mth. 2019 production growth over the first seven months has dropped
to an average of 97 kb/d/mth. The total July increase over June was 107 kb/d/mth. The biggest
increases for July came from Sprayberry (33 kb/d) and Wolfcamp (46 kb/d).
"... He says everything USA lower 48 other than shale is completely dead, and has been for sometime. He said look at Kansas since 2014. That is pretty much the rest of conventional lower 48. ..."
"... They are also concerned about 2020 big time. A lot of wasted money on new pipes if there is a fracking ban, which they are taking seriously. ..."
"... I would say that as far as the shale industry is concerned, the shit is about to hit the fan. ..."
"... Yes, all liquids includes ethanol from corn or sugar cane. ..."
I talked to a guy with a pretty key position in a pipeline company recently.
He says everything USA lower 48 other than shale is completely dead, and has been for
sometime. He said look at Kansas since 2014. That is pretty much the rest of conventional
lower 48.
He also said they are getting nervous about shale because the financial people in New York
are turning against it. He says it is not profitable sub $75 WTI and if the money is cut off,
it's going to fall like a rock.
They are also concerned about 2020 big time. A lot of wasted money on new pipes if there
is a fracking ban, which they are taking seriously.
I'm a little bit suspicious of Rystad because they tilt bullish consistently, and I'm
specifically suspicious because only 10% of the shale companies operating int he US have
positive free cash flows.
If these wells were really spitting out mid to high double digit IRR's then these
companies would be rolling in cash.
They are not.
Despite saying "fully burdened" multiple times, it wasn't until I got to the very last
paragraph of the report where I found this:
++++++++++
"While the economics of recent vintages in the most prospective US liquid basin remain
exceptionally robust, we should note that these ATAX IRRs still do not correspond to
fully-burdened returns.
For a complete picture, we also need to take into account land cost, where the variability
between early and late entrants is expected to be significant. We aim to tackle this
assumption in a forthcoming analysis."
+++++++
Oh.
They left out land costs. You know, one of the largest line-item expenses there is.
Put those back and these wells are negative I will bet you. And that's a decidedly
"bearish tilting" discovery.
Yeah, the "singers" leave off land cost, road cost, earth moving equipment, tanks, and
pipelines, which can easily add up to a couple of million more per well.
Thanks Chris
I missed that. For some basins there might be a 10% IRR at 65 per barrel for the average new
well over its productive life for all costs including land.
Howdy from a hot S. Texas, Chris. IRR is a bad financial metric for the shale oil biz; its
easily manipulated, much like break'even prices. And generally speaking it's the same folks
always doing the manipulating. The IEA and the EIA are Rystad, DI and IHS's biggest clients.
Good news sells, bad news, not. As George says, it's not a lie if you believe it.
ROI's on CAPEX have always been an important, and overlooked key to the failed shale oil
business model. The possibility (often based on exaggerated EUR's to begin with) of earning
$13MM undiscounted cash flow on a $8.5MM dollar investment, over 15-20 years, no less, was
never conducive to staying out of debt to grow. And current 165% ROI's on the very BEST of
wells are not now conducive to paying interest, reserve replacement and ultimately, we hope,
deleveraging debt. It simply does not work. The "models" that predict growth, and debt
reduction, short of $85 oil prices, sustained for many consecutive years, are ridiculous. By
year end '19 we'll see how ridiculous.
The American shale oil phenomena (not to be confused with the American oil industry) is a
textbook example of "non-profit capitalism." From printing press to Central Banks to lenders
to shale companies, the end result is suppose to benefit the American consumer at the pump
and burner tip and is a great redistribution of wealth in our nation. But it's the people in
the middle that are making the killing, the lawyers that put the deals together, the banks
that get the yields, the CEO's that make the +$20MM annual compensation packages while their
EPS suck the royalty owners getting the free money, they are the big winners. And none of
those folks want to see it end. EVER. They could care less about 2 BCFPD of associated gas
being flared, or all the LTO getting exported at $20 discounts to Brent, or ground water
levels in Reeves County they love the shale thing because it makes them money. And they all
do whatever they can to make sure people believe it's a miracle, a revolution; a game
changer.
Phftttttt.
The real oil business, the real America, works on profit. Debt is for pussies, for
weenie-necks, for dads who do not care what sort of life they leave for their kids.
Yeah, $85 and above would work for some, not all. $65 would work for a lot less of them, and
$55 is pretty much a sucking action for cash on almost all. And as a royalty owner, I would
much prefer them not to drill until $85. But, royalty owners do not run the damn companies.
Faulting them is like laughing at the homeless. I have about 30, or more, wells that can be
drilled on my lease, and I have a tiny ownership. Do you think I am happy with $55 to $60
drilling on it, you are wrong. It's about the last hope in life I have, and I am happy with
wasting it??? GD, I am 70, but not that senile, yet. Ok, I may be an exception, but, at
least, you could say some, or maybe even a lot. Otherwise, it's discrimination, which for
you, I would not guess. But, all royalty owners, is like downgrading the homeless. Most, do
not have a clue they could have had steaks, instead of mush.
I am "discriminating" against greed and in any way I can trying to draw attention to the need
to conserve America's remaining resources. Continuous 120 day drilling commitments in MOST
oil and gas leases, term assignments and/or farmouts has led to over drilling, increased GOR
and potential loss of BHP and recovery rates. It's also led to excessive flaring and the
waste of associated gas, overproduction, much lower product prices and more debt. If
operators (Lessees/Assignees) do not comply with these continuous drilling provisions they
typically lose acreage they've paid thousands of dollars per acre to lease.
I am a royalty owner and consider it one of America's great privileges. By proper
management of my minerals I have ensured my family will benefit from them for many, many
decades. Onerous drilling to earn provisions, however, are part of why the shale oil and
shale phenomena in America is, essentially, out of control and on a mission to drain the last
of our country's hydrocarbon resources as fast as borrowed capital will allow. If your leases
do not contain Pugh clauses and drilling commitments then ignore my observations and
goodonya.
I guess I see a different picture of most royalty owners than you, and I will just
concentrate on the EF, as that's where I am. Most of the EF was leased up by around 2009, far
before public knowledge of the field. Ours was originally with Cheatapeak for about $800 a
net acre. The common way to lease it, was through third party land men, who would lie with
impunity. The standard story was, if you don't lease it, with our lease, you may not get
anything if they find oil. In return for signing their lease, as is, was a generous quarter,
rather than the usual eighth. I knew the rest was BS, but a quarter sounded pretty good. The
continuous drilling clause in that, was so weak to be non-existent. No Pugh clause. That was
standard. I actually did not sign with Cheatapeake, nor EOG, but the lease wording was
basically the same. My guess, is the vast majority of mineral right owners were given the
same deal. Maybe not the majority of land, but certainly the number of signers. Most of the
Permian was leased many years ago, with an eighth, or less. Chevron actually owns 100% on a
lot, and so does Oxy, no doubt. Exxon's acquisition of the Bass families' holdings in the
Delaware span 4 decades. EOG's entry into the Delaware was through purchase of Yates. I
believe the picture you are painting of royalty owners is distorted, for most. With, at
least, the big holders, the number of wells is determined by the company. Not the lease. And
most of the rest have very little capex to complete with.
There are so many mineral owners in so many different situations that it is difficult to
paint all with a broad brush.
However, management of shale weren't playing with their own money, and so what happened
happened.
If we could just not keep having these quick drops like Q4 2018 and Q2 2019.
I think that it will be interesting to see what happens to all of the sub 10 BOPD shale
wells. Better hope no down hole failures. Pretty hard to pay 8 figure pay packages to
management on the backs of those. Lol.
I think all investors need to think about what happens when these companies start to run
out of shale locations and have falling production.
Just go to shaleprofile.com and run some calculations on 2014-2016 wells in the various shale
basins.
By the time you subtract 25% royalty, then severance, LOE, G & A, it's apparent that
the majority of the wells cannot payout in a reasonable time. 3-5 years.
I guess in early 2015 those of us in the conventional upstream arena were saying this.
Vertical wells fell off a cliff. But shale wells (with OPM) kept on trucking.
And the stories told about break evens, which we knew were fraudulent, have proven
such.
It is not necessary I "distort" the truth or generalize the role greedy mineral owners have
in the overdrilling and premature depletion of America's shale oil resources; the evidence is
in every courthouse in every county in every shale oil basin in America. Google it, or better
yet, go research public records yourself, as I often have to do. It is abysmal, the
requirements made of Lessees, Assignees and Farmoutees to develop those shale oil resources,
regardless of price, or pressure preservation or common sense. It is very much part of the
problem the shale industry faces. They, and the regulatory agencies that protect them, may
have brought it on themselves when they changed applicable field rules nevertheless the big
winner in all of this shale gig is the American royalty owner, RI and ORRI combined. I
estimate to the tune of about $800 billion in free money the past decade. Those are just the
facts, as painful as they may be.
As a side note, the Texas DPS reports 30 people have been killed on Texas oilfield roads
in July so far all in a hurry to deplete America's last remaining hydrocarbon resources,
flare its associated gas, and export the shit to Korea.
I'm not familiar with Texas shale leases nor who the mineral owners tend to be, so I am
not qualified to comment as I did.
Where I am, several royalty companies have bought fractional interests in active leases
and also where production is inactive.
During the high prices we tried to lease a tract offsetting us, which had been abandoned.
The wells are in the state plugging fund. The mineral owners are from a shale state, and they
wanted a large royalty, much larger than had been granted here. Plus cash upfront. Plus
wanted us to drill the two remaining locations within a certain time or forfeit them (which
made no sense given the lease boundaries, etc. So we passed. It has sat abandoned for several
more years, Wells haven't been plugged either.
However, we have reactivated several leases from 1990s to present, and we are working on
two more small ones that offset us right now. In each case the mineral owners have been
relatively easy to work with.
I ballpark that we have produced over 50K BO from those reclamation projects. With
royalties from 1/6 to 1/8, I'd say those that worked with us have fared pretty well.
I guess maybe when you aren't operating near shale things are a lot easier.
This is a whole different topic: Kayross (I haven't heard of them) are quoted on Rigzone
today as saying that Permian CAPEX data for 2018 have been underreported by some $4.1
billion. They quote Andrew Gould: Average production costs have been underestimated and
production per well overestimated. He says that current shale-oil production is substantially
more water- and sand- intensive than commonly believed.
Kayross: Sand and water intensity in Permian tight-oil production in 2018 is 23% higher
than previously recorded, with sand demand underestimated by 9.2 billion pounds and water by
12.5 billion gallons.
Chart below from that Bloomberg piece suggests that without all the external capital, US
tight oil output would be only about 2 Mb/d instead of 7.5 Mb/d in May 2019. We might see
relatively flat growth going forward, much will depend on future oil prices (low prices might
result in decline, medium prices, flat output and high prices a small increase, perhaps to 9
Mb/d or so.
Even EOG. Flat, at best. One could expect more rig count drops soon. Because, this does
not reflect the multitude of smaller companies that make up a good portion of production.
This can be used for reference to the article for perspective. https://www.rrc.state.tx.us/media/50413/top32producers2018.pdf
Oxy is actually three of those companies, now. Both the Oxies and Anadarko.
" Chinese consumption is enroute to a 6-7% growth year .It's relentless'
I'll leave other to respond to the call for war, if they so choose.
But I will say that the USA would be wise to have no plan to import oil from beyond this
hemisphere, because others, including China, will be consuming all that is available from
Africa and Asia.
There will come a time when EV's look brilliant. To some they already do.
The early season hurricane in the GOM is going to put a major dent in US July crude output.
Around 60% of production is shut-in and will be that way for around a week. This storm is
weak but so sprawling there is a huge area of the Gulf flying helicopters is dangerous
Not the Big One for the industry, New Orleans or Houston by any means. Still, Gulf is hot
and favorable for storms this year.
As long as this BS continues, oil prices will stay low. More BKs and mergers, and flat
shale output. Because, it's now official, big oil determines Permian output. Which will not
be recognized much until 2020. Because, the elevator do not go to upper floors. I wasn't
going to call it until an Oxy takeover by a major, but I can finish the sentence with the
words we have. Final conclusion will have to wait for the official autopsy, but the doc needs
to be smart enough to know that the patient died. May be quite smelly by then.
Lots of Ag professors at major universities study grain trade. I listen to some of their
podcasts. This is what they say in unison.
Right now the US corn and soybean crop is not looking good. But the funds do not so crop
tours, talk to farmers, fly drones over fields, etc. So as long as USDA says all is well,
grain prices stay low.
USDA estimated 91.7 million acres of corn planted most recently. None of the Ag professors
believe the number, nor do the various independent traders I listen to. But the funds went
with it and corn sold off limit down.
Crude -1.401M Cushing: -1.115 M Gasoline -476K Distillate +6.226M
U.S. crude stocks fell less than expected last week, while gasoline inventories decreased
and distillate stocks built, industry group the American Petroleum Institute said on Tuesday.
Crude inventories fell by 1.4 million barrels in the week to July 12 to 460 million, compared
with analysts' expectations for a decrease of 2.7 million barrels. Crude stocks at the
Cushing, Oklahoma, delivery hub fell by 1.1 million barrels, API said. Refinery crude runs
rose by 17,000 barrels per day, API data showed. Gasoline stocks fell by 476,000 barrels,
compared with analysts' expectations in a Reuters poll for a 925,000-barrel decline.
Distillate fuels stockpiles, which include diesel and heating oil, rose by 6.2 million
barrels, compared with expectations for a 613,000-barrel gain, the API data showed. U.S.
crude imports fell last week by 41,000 barrels per day to 7 million bpd.
Just as I predicted, plant condensate which is not crude has entered the refinery as crude.
Mason Hamilton of EIA confirmed it in his tweets yesterday.
The adjustment factor will likely remain above 500 KBD as a portion of plant condensate has
entered the refinery as input on a consistent basis. The plant condensate can be directly
used as gasoline blend material just as butane in winter months. Expect gasoline production
to remain high as a result.
These NG shale management folks have even less of a brain that shale oil folks. The NG
stocks have pummeled and many stocks such as RRC and AR hit 52 week lows.
Enno posted yesterday that the shale decline rate is running at the rate of 350KBD/month (or
4.2 MBD/year). I expect the treadmill effect to slow down the shale growth to a virtual crawl
sooner rather than later.
An answer to my own Q from The (IEEFA) – Institute for Energy Economics and Financial
Analysis.
"EQT's former CEO Steve Schlotterbeck recently made headlines when he called fracking an
"unmitigated disaster" because it helped crash prices and produce mountains of red ink."
"In fact, I'm not aware of another case of a disruptive technological change that has done so
much harm to the industry that created the change," Schlotterbeck said at an industry
conference in June.
Amazingly Appears EQT displaced CHK as the GASSEST one to rule them all with an Unresolved
Strategy to bury their stakeholders even deeper in doom. https://www.zerohedge.com/news/2019-07-22/why-us-shale-doomed-no-matter-what-they-do
https://www.rigzone.com/news/permian_fracking_activity_underreported_in_2018-23-jul-2019-159378-article/
Latest news from Rig zone , fracking underreported in permian in 2018. Seems there are not
maby DUCs left to compleate and the oroduction each well is lower than reported that increase
the break even price each barrel.significant. If this is true EIA need to revice their shale
play forcast, also the majours their plans if they used the data reported that was wrong
U.S. crude stocks fell more than expected last week, while gasoline and distillate
inventories built, industry group the American Petroleum Institute said on Tuesday.
Crude inventories fell by 11 million barrels in the week to July 19 to 449 million,
compared with analysts' expectations for a decrease of 4 million barrels.
Crude stocks at the Cushing, Oklahoma, delivery hub fell by 448,000 barrels, API said.
Refinery crude runs fell by 396,000 barrels per day, API data showed.
Gasoline stocks rose by 4.4 million barrels, compared with analysts' expectations in a
Reuters poll for a 730,000-barrel decline.
Distillate fuels stockpiles, which include diesel and heating oil, rose by 1.4 million
barrels, compared with expectations for a 499,000-barrel gain, the API data showed.
U.S. crude imports fell last week by 467,000 barrels per day to 6.6 million bpd.
Hi guys, please read this article in the Oil&Gas journal:
"Oil and gas companies under-reported hydraulic fracturing activity for producing light,
tight oil by more than 20% in the Permian basin during 2018, estimates Kayrros, a data
analytics company serving energy markets.
Using optical and synthetic aperture radar imagery tracking coupled with proprietary
algorithms to identify rigs and fracturing crews, Kayrros found that more than 1,100 Permian
wells were completed but not reported through state commissions or FracFocus, a public
repository for information on fracturing chemicals.
Kayrros counted 6,394 completed wells for 2018, representing a 21% increase on the FracFocus
estimate of 5,272 wells as of June 20.
The backlog of drilled but uncompleted (DUC) wells is considerably smaller than believed,
Kayrros said. In any given month, Kayrros evaluates the Permian DUC inventory at just about
1,000 wells."
If this were true, it would be a massive fraudulent behavior, more typical of an emerging
market with a large black economy. I am somewhat speechless and waiting for more
information.
That part may not be illegal but it certainly sounds like the average return per well is 20%
less than we thought. So, the already poor productivity of shale wells is now 20% less than
previous estimates.
Commenting on the discovery, Andrew Gould, former Chairman of BG and Chairman CEO of
Schlumberger and Kayrros advisory board chairman, said: "Misperceptions about shale oil in
general and the Permian in particular have consequences, hence the importance of these
measurements that show Permian production per well has been substantially overestimated. By
the same token, average production costs per well are understated. With far more wells
contributing to Permian and US oil production than accounted for, current shale oil
production is substantially more water- and sand-intensive than is commonly believed."
The findings have significant implications for the assumed efficiency of the Permian
Basin. The analysis revealed that while oil production is accurately measured in monthly US
statistics, it took many more wells to account for that production in 2018 than were
reported. Assuming a cost of $5 million per horizontal completion, 2018 operator capex is
also underestimated by as much as USD 4.1 billion. Further, the sand and water intensity of
Permian tight oil production in 2018 was 23% greater than previously recorded with sand
demand being underestimated by 9.2 billion pounds and water by 12.5 billion gallons.
Seems this finding by Kayrros could be a really big deal. I am unclear on how exactly a well
gets completed and put into production without triggering the state reporting mechanisms
seems nigh impossible to me.
But it's a heavy-hitting firm with Andrew Gould on its board. From the Kayrros media page
of their website:
+++++++++++++++
New Satellite Data Highlight Large Underreporting of Hydraulic Fracturing Activity
Houston, 23 July 2019
Kayrros, the leading data-driven analysis company serving the energy markets, disclosed
today that hydraulic fracturing activity (fracking), the process for producing light tight
oil, was underreported by more than 20% in the Permian, the most prolific US basin, in
2018.
Using optical and synthetic aperture radar imagery tracking together with proprietary
algorithms to identify rigs and frac crews, Kayrros found that in 2018 alone, more than 1,100
wells were completed in the Permian basin but not reported through state commissions or
FracFocus, a public repository for information on the chemicals used during fracking. The
total figure of 6,394 completed wells counted by Kayrros for 2018 represents a 21% increase
on the FracFocus estimate of 5,272 wells as of June 20, 2019.
US light tight oil (commonly referred to as "shale oil") has been the world's fastest
growing source of oil supply in the last 10 years, turning the United States into the largest
liquids producer and a major exporter of crude oil and refined products. Experts rely their
analysis of the sector on data submitted by operators to state commissions and FracFocus.
Kayrros measurements reveal that public data fail to capture the full scale of fracking.
The macroeconomic implications of this underreporting are far-reaching. For one thing, the
backlog of drilled but uncompleted (DUC) wells is considerably smaller than thought. In any
given month, Kayrros evaluates the Permian DUC inventory at just around 1,000 wells. Most of
this rolling inventory results from regular drilling and completions operations. Over time,
the number of wells drilled generally matches that of wells completed, leaving DUC
inventories relatively unchanged.
The prevalent view that shale operators sit on a large backlog of DUCs that could be
quickly brought to production in the event of an oil crisis even without further drilling is
thus deeply misleading. There is just no such inventory.
The findings also transform the perception of light tight oil economics. In light of these
measurements, the average well is both less productive and higher-cost than reflected in
public data.
Commenting on the discovery, Andrew Gould, former Chairman of BG and Chairman CEO of
Schlumberger and Kayrros advisory board chairman, said: "Misperceptions about shale oil in
general and the Permian in particular have consequences, hence the importance of these
measurements that show Permian production per well has been substantially overestimated. By
the same token, average production costs per well are understated. With far more wells
contributing to Permian and US oil production than accounted for, current shale oil
production is substantially more water- and sand-intensive than is commonly believed."
Kayrros Chief Analyst and Co-Founder Antoine Halff added: "For all its revolutionary
impact on the oil industry, shale remains poorly understood. Publicly available data based on
old-fashioned company reporting have their limits. Hard measurements unlocked by new data
technologies show that contrary to public belief, there is no great buildup of DUCs just
waiting to be brought online. The whole idea that the market can rely on this sort of de
facto spare production capacity is an illusion. The industry is actually running on a much
tighter leash than that."
The findings have significant implications for the assumed efficiency of the Permian
Basin. The analysis revealed that while oil production is accurately measured in monthly US
statistics, it took many more wells to account for that production in 2018 than were
reported. Assuming a cost of $5 million per horizontal completion, 2018 operator capex is
also underestimated by as much as USD 4.1 billion. Further, the sand and water intensity of
Permian tight oil production in 2018 was 23% greater than previously recorded with sand
demand being underestimated by 9.2 billion pounds and water by 12.5 billion gallons.
+++++++++++++++++++++
Enno Peters reports 4832 horizontal wells completed in the Permian basin in 2018, his data
tends to be quite good, though over time more data shows up at the state agencies so this
number will likely get revised higher. The most recent Permian basin report has 3583 Permian
wells completed in 2017, in July 2018 the estimate was 3251 Permian wells completed in 2017,
so about 91% of wells were reported after 7 months, if this rate is consistent (and it may
not be) this suggests perhaps 5310 total wells will be reported for 2018 by July 2020. Pretty
convinced that Enno Peters gets this right.
There is a bit of discussion of this at shaleprofile.com
This shale oil/gas is no less important news. Careful analysis already knew shale oil/gas was
a farce: the problem with it is that it provides a boom of production followed quickly by a
bust (like an ejaculation). It follows a free-fall graphic line.
This is awful for investors,
who expect a more rollercoaster-like productivity typical of the normal oil reserves (slowly
crescent production, with an apex, followed by a slow decline in output).
The USA will never be self-sufficient in oil. The government's official projections are a
farce and they know it.
This is about gas, but most info probably can be extrapolated on oil well too...
Notable quotes:
"... " While hundreds of billions of dollars of benefits have accrued to hundreds of millions of people, the amount of shareholder value destruction registers in the hundreds of billions of dollars," he said. "The industry is self-destructive." ..."
"... Schlotterbeck's remarks, delivered to petrochemical and gas industry executives at the David L. Lawrence Convention Center in Pittsburgh, come from an individual uniquely positioned to understand how major Marcellus drillers make financial decisions -- because he so recently ran a major shale gas drilling firm. Schlotterbeck now serves as a member of the board of directors at the Energy Innovation Center Institute, a nonprofit that offers energy industry training programs. ..."
"... Since 2015, there's been 172 E&P company bankruptcies involving nearly a hundred billion dollars of debt." ..."
"... At the Friday conference, he displayed a slide showing the stock prices of eight major Marcellus shale gas drillers: Antero, Range Resources, Cabot Oil and Gas, Southwestern Energy, CNX Gas, Gulfport, Chesapeake Energy, and EQT , the company that Schlotterbeck ran until he resigned in March 2018. Seven of the eight companies saw their stock prices fall between 40 percent and 95 percent since 2008, the slide showed. ..."
"... " Excluding capital, the big eight basin producers have destroyed on average 80 percent of the value of their companies since the beginning of the shale revolution," Schlotterbeck said. "This is not the fall from the peak price during the shale decade, this is the drop in their share price from before the shale revolution began." ..."
"... " Nearly every American has benefited from shale gas, with one big exception," he said, "the shale gas investors." ..."
"... " The fact is that every time they put the drill bit to the ground, they erode the value of the billions of dollars of previous investments they have made," he said. "It's frankly no wonder that their equity valuations continue to fall dramatically." ..."
"... " As a result of investor pressure, all these companies have committed to lower growth rates and to live within cash flow," said Schlotterbeck. He noted that the drillers had slashed their gas production growth forecasts from over 20 percent down to 11 percent this year. "Yet both the gas commodity market and the equities market are saying this is not nearly enough of a cut." ..."
"... " And at $2 even the mighty Marcellus does not make economic sense," he said, later clarifying that that included both "dry" gas wells, which produce mostly methane, and "wet" gas wells, which also produce the natural gas liquids ( NGL s) that can be used by the petrochemical industry as raw materials for making plastic and chemicals. "Wet gas is better, but nobody's making money at $2 gas." ..."
"... " I tell you this because the current gas commodity price environment is not sustainable and higher gas prices are required for the shale revolution to continue," Schlotterbeck said. "Exactly what prices are required for the industry to become reasonably healthy is hard to predict." ..."
By Sharon Kelly, an attorney and freelance writer based in Philadelphia. She has reported
for The New York Times, The Guardian, The Nation, National Wildlife, Earth Island Journal, and
a variety of other
publications. Prior to beginning freelance writing, she worked as a law clerk for the ACLU of
Delaware.
Originally published at DeSmogBlog .
Steve Schlotterbeck, who led drilling company EQT as it expanded to become the nation's
largest
producer of natural gas
in 2017 , arrived at a petrochemical industry conference in Pittsburgh Friday morning with
a blunt message about shale gas drilling and fracking.
" The shale gas revolution has frankly been an unmitigated disaster for any buy-and-hold
investor in the shale gas industry with very few limited exceptions," Schlotterbeck, who left
the helm of EQT last year, continued. "In fact, I'm not aware of another case of a disruptive
technological change that has done so much harm to the industry that created the change."
" While hundreds of billions of dollars of benefits have accrued to hundreds of millions of
people, the amount of shareholder value destruction registers in the hundreds of billions of
dollars," he said. "The industry is self-destructive."
Schlotterbeck is not the first industry insider to ring alarm bells about the shale
industry's record of producing vast amounts of gas while burning through far more cash than it
can earn by selling that gas. And drillers' own numbers speak for themselves. Reported spending
outweighed income for a group of 29 large public shale gas companies by $6.7 billion in 2018,
bringing the group's 2010 to 2018 cash flow to a total of negative $181 billion, according to a
March 2019
report by the Institute for Energy Economics and Financial Analysis.
But Schlotterbeck's remarks, delivered to petrochemical and gas industry executives at the
David L. Lawrence Convention Center in Pittsburgh, come from an individual uniquely positioned
to understand how major Marcellus drillers make financial decisions -- because he so recently
ran a major shale gas drilling firm. Schlotterbeck now serves as a member of the board of
directors at the Energy Innovation Center Institute, a nonprofit that offers energy industry training programs.
His warnings on Friday were also offered in unusually stark terms.
'Destroyed on
Average 80 Percent of the Value of Their Companies'
" The technological advancements developed by the industry have been the weapon of its own
suicide," Schlotterbeck added, referring to the financial impacts of shale gas drilling on
shale gas drillers. "And unfortunately, the industry still has not fully realized how it's
killing itself. Since 2015, there's been 172 E&P company bankruptcies involving nearly a
hundred billion dollars of debt."
" In a little more than a decade, most of these companies just destroyed a very large
percentage of their companies' value that they had at the beginning of the shale revolution,"
he said. "It's frankly hard to imagine the scope of the value destruction that has occurred.
And it continues."
At the Friday conference, he displayed a slide showing the stock prices of eight major
Marcellus shale gas drillers: Antero, Range Resources, Cabot Oil and Gas, Southwestern Energy,
CNX Gas, Gulfport, Chesapeake Energy, and EQT , the company that Schlotterbeck ran until he
resigned in March 2018. Seven of the eight companies saw their stock prices fall between 40
percent and 95 percent since 2008, the slide showed.
" Excluding capital, the big eight basin producers have destroyed on average 80 percent of
the value of their companies since the beginning of the shale revolution," Schlotterbeck said.
"This is not the fall from the peak price during the shale decade, this is the drop in their
share price from before the shale revolution began."
Mr. Schlotterbeck credited the shale rush with lowering power and natural gas bills
nationwide and offering significant economic benefits since 2008, when he said the shale
revolution began.
" Nearly every American has benefited from shale gas, with one big exception," he said, "the
shale gas investors."
Residents of communities where shale gas drilling and fracking have caused disruptions and
health issues might take exception to Mr. Schlotterbeck's categorical description of the
beneficiaries of shale gas, as might climate scientists who have warned that the shale
industry's greenhouse gas emissions are so severe that burning gas for power may be worse for
the global climate than burning coal.
Only Cabot Oil and Gas, which owns the rights to drill gas from roughly 174,000 acres , mostly in one county
in the northeastern corner of Pennsylvania, saw its stock price rise since 2008, according to
Schlotterbeck's presentation.
Cabot remains at the center of disputes
tied to water contamination, a gas well blow-out, and other problems in Dimock, PA . One major
lawsuit in that dispute was filed against Cabot back in November 2009 and legal battles
have continued since. The company has denied liability and settled on undisclosed terms with landowners along Carter
Road in Dimock.
Schlotterbeck made no mention of Dimock, focusing his remarks on the economic decisions made
by the shale gas industry's corporate management and boards of directors -- not just in the
past, but also in the present.
" The fact is that every time they put the drill bit to the ground, they erode the value of
the billions of dollars of previous investments they have made," he said. "It's frankly no
wonder that their equity valuations continue to fall dramatically."
Slowing the Flow?
More recently, shale gas producers have begun to feel the heat from investors who are
pushing to see signs that the gas can be produced not just in high volume, but also at a
profit.
" As a result of investor pressure, all these companies have committed to lower growth rates
and to live within cash flow," said Schlotterbeck. He noted that the drillers had slashed their
gas production growth forecasts from over 20 percent down to 11 percent this year. "Yet both
the gas commodity market and the equities market are saying this is not nearly enough of a
cut."
He noted that the at-the-wellhead price of natural gas in the Marcellus region was around
$8/ MMB tu back in 2008, and had plunged to less than $2/ MMB tu today. That price plunge was caused by a massive glut of shale gas production as drillers raced
first to hold acreage by producing gas, then competed to see who could make individual wells
produce at higher rates by using tactics like drilling longer horizontal well bores and
experimenting with the proppants used during fracking.
" And at $2 even the mighty Marcellus does not make economic sense," he said, later
clarifying that that included both "dry" gas wells, which produce mostly methane, and "wet" gas
wells, which also produce the natural gas liquids ( NGL s) that can be used by the
petrochemical industry as raw materials for making plastic and chemicals. "Wet gas is better,
but nobody's making money at $2 gas."
" Over the past year or so, most of the producers have shifted away from the phenomenal
growth rates of the past to more moderate growth projections," Schlotterbeck said. "The market
is clearly telling them that they haven't slowed down enough."
" Now I tell you all this because I think it has long-term implications for the end users of
natural gas. This situation cannot continue indefinitely," Schlotterbeck continued. "There will
be a reckoning and the only questions is whether it happens in a controlled manner or whether
it comes as an unexpected shock to the system."
Schlotterbeck's presentation separately
described additional challenges facing shale gas producers. Credit: Sharon Kelly
Frackers Projected Returns 'Should Not Exist' -- and Don't
He pointed to profit predictions in a "current investor presentation" by a shale driller he
did not name but described as one of the eight largest in the Marcellus. That driller, he said,
presently predicts it can make a 46 percent internal rate of return by drilling their dry gas
wells at current gas prices, and 61 percent internal returns from the same wells if gas prices
rise 36 percent.
" Economics and common sense will tell you that in a world of abundant similar
opportunities, rates of return at that level should not exist," Schlotterbeck said. "And they
don't."
" Really indicates to me that there's a lot of these companies that still don't get it," he
said. "They still think they're gonna earn 40, 50, 60 percent returns on their investment, even
after six years now of saying that and getting negative returns."
Schlotterbeck said there was a reason he made his presentation to the petrochemical industry
in Pittsburgh, where industry plans a massive construction spree to build plastics and chemical
factories in large part because gas prices have fallen so sharply. In December, the Department
of Energy cited the "tremendous low-cost resource from the Marcellus and Utica shales" as it
announced publication of a report touting benefits from building new petrochemical
infrastructure in Appalachia.
Drillers' financial troubles could have significant implications for the petrochemical
build-out in the Ohio River Valley.
" I tell you this because the current gas commodity price environment is not sustainable and
higher gas prices are required for the shale revolution to continue," Schlotterbeck said.
"Exactly what prices are required for the industry to become reasonably healthy is hard to
predict."
His own personal prediction, he added, was that prices would rise 60 to 80 percent, reaching
$3.50 or $4 per thousand cubic feet (mcf). And production growth will have to slow.
In response to an audience question about the impact of demand from new petrochemical plants
currently planned for the region, Schlotterbeck said that for drillers, those plans were "great
news on the demand side."
" But when producers are growing 11 percent per year, I don't think demand can keep up at
that pace," he added.
" The large gas producers will need to make further reductions in their drilling activity,"
he said. "Whether they do it on their own accord or if shareholders and bondholders revolt and
force them to, I think remains to be seen."
Shale Crescent USA , a petrochemical industry group pushing to transform the Ohio River
Valley and Appalachia into a plastics and chemical manufacturing center to rival the one on the
Gulf Coast -- known locally as "cancer alley" -- offered their projections, which predict
production will continue to grow rapidly, in a presentation following Schlotterbeck's.
Shale Crescent USA 's Wally Kandel and Jerry James presented at the Northeast Petrochemical
Exhibition and Conference in Pittsburgh on Friday. Credit: Sharon Kelly, DeSmog
Shale Crescent USA 's pitch to policy-makers in Pennsylvania, Ohio, West Virginia and
Kentucky and to plastics and chemical manufacturers has heavily emphasized the low cost of
shale gas and NGL s in the region.
On Friday, Wally Kandel, a Solvay Specialty Polymers vice president, and Jerry James,
president of Artex Oil Co., played back a video segment about Shale Crescent USA
aired by Bloomberg in June 2018.
" In Shale Crescent USA , you have the most abundant natural gas, the cheapest natural gas
in the developed world," Kandel told Bloomberg in the clip.
" It was that rapid increase in production that got us to start Shale Crescent USA ," James
told the conference in Pittsburgh Friday.
James didn't take issue with Schlotterbeck's conclusions about the shale revolution. "It's
profoundly changed the market," said James. "It's just absolutely amazing what we've been able
to do."
" We've achieved everything but big profits -- and I agree with him," James continued,
referring to Schlotterbeck, "but for people on the downstream side [i.e. industrial consumers
of shale gas and NGL s], this is revolutionary."
In brief comments following Schlotterbeck's remarks, Charles Schliebs of Stone Pier Capital
Advisors recalled an earlier -- but failed -- plan to drive demand for shale gas, one heavily
pushed by former Chesapeake Energy CEO Aubrey McClendon, who died in a car crash a day after
being indicted
by federal prosecutors with the Department of Justice over alleged bid-rigging.
McClendon, Schliebs recalled, had urged car makers to start building cars that would run on
compressed natural gas, or CNG . "Aubrey had amazing plans and was spending a lot of money and
doing things to push CNG in cars and in light trucks," Schliebs recalled.
These days, CNG passenger vehicles seem more like a passing fad, overshadowed by the rise of
electric vehicles. Schliebs noted that just two or three weeks before the petrochemical
conference, EQT 's CNG fueling station in Pittsburgh's strip district closed permanently and
quietly, adding that he'd been told its owners had no plans to open a replacement.
"... The Wall Street Journal today has an article about how sources of funding have dried up for frackers. ..."
"... LTO is going to have to slow down with low prices and less access to capital. North Dakota drilling in at least the past 8 months is going to lose money. Getting mid-$40s at best and in December much worse in the initial flow burst is no bueno. Even if hedged, it's still an overall economic loser with operators having no positive free cash flow. ..."
"... Cash for additional drilling *has* to come from investors or lenders. That gets choked off, theres no money to pay the up front capital and labor costs of new wells. ..."
The Wall Street Journal today has an article about how sources of funding have dried up for
frackers.
I'm not sure substitution will kill oil prices. And while I know peak oil will happen,
putting a date on it doesn't much matter to me.
What most interests me is when investors, lenders, and execs at oil companies decide
having their money tied up in petroleum just doesn't make financial sense and it is time to
bail.
LTO is going to have to slow down with low prices and less access to capital. North Dakota
drilling in at least the past 8 months is going to lose money. Getting mid-$40s at best and
in December much worse in the initial flow burst is no bueno. Even if hedged, it's still an
overall economic loser with operators having no positive free cash flow.
Cash for additional
drilling *has* to come from investors or lenders. That gets choked off, theres no money to
pay the up front capital and labor costs of new wells.
According to Mark Papa in Q4 2018 presentation EOG did not see any possibility to increase
oil production as they need 75 usd / bbl WTI. They priority to pay depth , interest and
dividend to their investors.
If the vreak even price WTI average shale oil is 65 usd today ,
I doubt this will be reduced the next 3-5 years as the rock formation will have reduced
production Quality, the max. latitude lenght and number each drill pad might be reach, now I
read gaz is injected to stimulat production the impact of this remain to see.
Higher labour
cost , increase cost of funding as oil & Gaz is already less popular because of
environmental issues. Than there is some increase offshore activity, and onshore drilling in
Europe.
But even the oil majours want cheeper wells and service work it will not be any
cheaper because all need profit to grow a healthy Buisiness. In the mean time about 15% of
the oil produced are replaced adding 6-7% decline rate to that and at least 1% growth in
demand even with trade war it seems clear the world need significant more oil that is
profittable to develop to a cost consumers around the globe , mostely poor in development
Country can afford to buy and during time there need to be less energy made from fosil fuel.
I saved the Rystad article that has US at 12.5 now, and 13.4 by the end of the year. I will
revisit it from time to time. It's classic BS to the point of being really funny. Like
"Little shop of Horrors" (the original, not the 1986 remake) the really bad SF movie.
I mean, really. We were at 11.9 the end of March per EIA monthlies. With no substantial
increase in completions and drops in active rigs, we have increased 600k in two months???
Then in the last half of 2019, we are going to increase another 900k per day, when prices are
less than $55 now? Well, if your going to lie, tell a big one. My Venus flytrap ate my
homework :-)
In 2018 World C+C average output was about 82.84 Mb/d, so my "best guess" (which could
indeed be incorrect) scenario sees an increase of 4.46 Mb/d from 2018 to 2026.
Okay, that ain't all that unreasonable except except you have C+C production in 2019
increasing by 1,449 over the average of 2018. February 2019 World C+C production was
82,389,000 barrels per day. Your 2019 average is 1,901,000 barrels per day above that figure.
Dennis, that just ain't gonna happen.
OPEC + Russia + Canada accounts for 55% of the World's oil production. These 14
OPEC nations plus Canada plus Russia averaged 47,849,000 barrels per day in 2018. Their
average for the first four months of 2019 was exactly 46,000,000 barrels per day or 1,848,000
barrels per day below their 2018 average. Their April output was 2,352,000 barrels per day
below their 2019 average.
If World C+C is higher in 2019 than in 2018, who will make up this huge difference. US
Shale?
Canada still has lots of potential, their tars sands are just declining because of low oil
prices.
I believe that the Aberta Tar Sands are pretty much "guaranteed" (much less risk compared
to drilling for nothing) as long as the price is right. They are definitely there.
I am sure that statement will be destroyed by oil professionals (which I am not). But
RockMtnGuy from Oil Drum who used to work on them I think, said pretty much the same
thing.
Isn't the answer the difference will be made up by drawing from storage until the price gets
high enough to bring more production on? $120 barrel is going to get offshore fired back up
and maybe even Venezuela.
No, there is just not that much storage. A nation can draw from storage for only a couple of
months until they run out of storage. That is unless they have a tremendous amount of
storage. Not many nations have that much storage. 120$ a barrel? You're dreaming. Perhaps in
a decade or so.
What role do the giant oil fields play? As I write in my book "When trucks stop running:
the average size of new oil fields has declined, leaving us heavily dependent on the
original giant oil fields discovered many decades ago.
Of the roughly 47,500 oil fields in the world, 507 of them, about one percent, are
giant oil fields holding nearly two-thirds of all the oil that has ever been, or ever
will be produced, with the largest 100 giants, the "elephants," providing nearly half of all
oil today
Since giant oil fields dominate oil production, the rate they decline at is a good
predictor of future world oil production. In 2005, they provided 60 % of world oil. Giant
fields only begin to decline after a long plateau phase where production
fluctuates within a 4 % range. In 2007, the 261 giants past their plateau phase were
declining at an average rate of 6 % a year. Their decline rate will continue to increase by
0.15 % a year, to 6.15, 6.3, 6.45 % and so on. By 2030 these giants, and the other giants
joining them as time goes on, will be declining at an average rate of over 9 % a year
Since nongiant oil fields decline at much higher rates, especially offshore and tight
oil, by 2030, the average decline rate of all oil fields past their peak production
will be higher than 9 percent.
by 2030, from half to two-thirds of global crude oil production will need to be replaced --
40 to 50 Mb/d of today's 77.8 Mb/d
Making up this shortfall will be difficult, since four out of five barrels now
come from fields found before 1973 and the majority of them are declining.
So far, Enhanced oil recovery in giant fields has increased the decline rate after peak
production, because oil extracted now is unavailable after the peak, making the decline rate
steeper. For example, Cantarell in Mexico, the second largest oil field ever found,
declined at 20 % rates due to the EOR used to increase the maximum rate of production
Aleklett, K., et al. 2012. Peeking at peak oil. Berlin: Springer.
Hook, M., et al. 2009. Giant oil field decline rates and their influence on world
oil production. Energy Policy 37(6):2262–2272.
Murphy, D.J., et al. 2011. Energy return on investment, peak oil, and the end of economic
growth. Annals of the New York Academy of Sciences 1219: 52–72.
Thanks Alice, that was very informative. That is why I believe the decline curve will be much
steeper than the ascension curve. Individual fields, of course, reach their peak production
in only a few years and their decline could take many years. But I am speaking of all the
world's production combined. I think the decline curve will shock most people.
I once made a large poster about this 1978 Rand study. Had become interested in resource
studies years earlier and occasionally lectured at ZPG and elsewhere. https://www.rand.org/pubs/reports/R2284.html
That's very informative, Alice. Very rough estimation from that, is that if shale were able
to eke out another 600k increase a year, for a year or two, it could not possibly keep up
with current decline rates in the bigger fields. Especially, when that shale increase is not
going to start in 2019. World will be down, and add on another year of decline. 2018 will be
looking more like peak year.
This poster has been considering post peak for, obviously, years. Kudos, this stuff is
good! http://energyskeptic.com/
First of all, oil field geography (not geology) can be changed. So that can be one source of
corruption in whatever number you want to quote for field production.
Second of all, choke management can also corrupt whatever number you want to quote for
field production.
And how about third of all you can change the definition of oil and call all sorts of
liquids coming up the well bore "oil" regardless of API density and corrupt whatever number
you want to quote for field production. Executives are paid for production, agencies collect
taxes for production, royalty recipients are paid regardless of profit, so who is it that
would oppose manufacturing any number for production you want to quote? Lenders? The Fed is
providing nearly 0% interest rates. Why would lenders care? Maybe refineries would care, but
you can probably cut them in.
So you can pretty much put numbers and conclusions about flow to bed.
I do think that geological depletion isn't the only factor that could knock it up to
6%.
Very little oil has been explored for and found in the past 5 years, plus add on another
10 years to develop what's discovered
As the contribution declines from the Giants more will have to be provided by the other
50,000 fields that have much higher decline rates. Onshore may be 3.5%, but a lot of new oil
is offshore with a much higher decline rate, perhaps higher than it needs to be. I've heard
that oil is left offshore due to the haste in building these rigs to pay investors off as
quickly as possible.
Since diesel is all that matters in keeping civilization alive, and U.S. shale oil is only
good for plastics, we depend on heavy oil producers like venezuela, mexico, Iran, and
canadian tar sands which are all problematic
I'm not so sure there are a lot of good places to drill. A quarter of remaining oil is in
the arctic and can't be obtained because of ice bergs, nor is it likely fields will be
developed on land in Alaska due to the challenges of permafrost.
A financial crash stops or slows much of the exploration and production. Potentially for a
long time, since unlike in the Great Depression, we won't have fossils to recover with as we
did back then.
Oil is a global commodity today, but will it be when production declines? If not, that
will accelerate the decline rate for nation's that can't get oil (i.e. the export land model
of Jeffrey Brown).
Though we'll be just fine, I'm sure most nations will be keen to send us diesel in
exchange for U.S. fracked plastic.
This is only true to an extent. Because refineries we're designed over the years to process
heavier oils than LTO the ones that exist have trouble handling all the light stuff. And the
light stuff has less of the distillates needed for diesel. However, they don't produce no
diesel at all, and refineries can be modified/upgraded to produce diesel from pretty much
whatever oil you want, for a cost.
What products you get out from the refinery is a function of both what oil you put into it
and what refinery you have. There is some diesel in LTO but not as high as conventional oil.
Getting a higher share diesel requires a complex refinery (and is costly). It currently makes
more sense for refineries to blend with medium and heavy oil.
Oil demand has over time shifted to higher API oil. LTO is too high but perhaps not that
bad. I think the main issue is that supply of LTO has increased very fast and demand was not
as responsive due to lack of investments in US refineries and export capacity.
In addition to what Jeff said, LTO is just that Light Tight Oil. Light implies short
polymers. Gasoline has (ideally) 8 carbon atoms, kerosene 12 to 15 and diesel 16, or mostly
around 16. So you can see that in very light oil, only a tiny fraction would have polymers
that long.
In petroleum molecules, the carbon atoms are all in a string. That's why they call them
polymer strings.
"... Upstream spending rose by a modest 4 percent, which only partially repairs the savage cuts following the 2014 bust, which saw upstream spending fall by about 30 percent. However, the IEA said that 2019 could be a bit of a turning point, with a "new wave of conventional projects" in the works. ..."
"... Despite the increase in spending on new oil projects, "today's investment trends are misaligned with where the world appears to be heading," the IEA said. "Notably, approvals of new conventional oil and gas projects fall short of what would be needed to meet continued robust demand growth." ..."
"... Geographically, investment [in solar and wind] is concentrated in rich countries. Roughly 90 percent of total energy investment – both for fossil fuels and for renewable energy – was funneled into high- and upper-middle income regions. Rich countries alone accounted for 40 percent of total energy investment, despite only making up 15 percent of the global population. ..."
Global energy investment "stabilised" at just over $1.8 trillion in 2018, ending three years
of declines.
Higher spending on oil, natural gas and coal was offset by declines in fossil fuel-based
electricity generation and even a dip in renewable energy spending. China was the largest
market for energy investment, even as the U.S. closed the gap.
After the 2014-2016 oil market bust, spending on oil and gas plunged, and only started to
tick up last year. But the oil industry is not returning to its old spending ways. New
investment is increasingly concentrated in short-cycle projects, namely, U.S. shale, "partly
reflecting investor preferences for better managing capital at risk amid uncertainties over the
future direction of the energy system," the IEA wrote in its report.
Upstream spending rose by a modest 4 percent, which only partially repairs the savage
cuts following the 2014 bust, which saw upstream spending fall by about 30 percent. However,
the IEA said that 2019 could be a bit of a turning point, with a "new wave of conventional
projects" in the works.
Despite the increase in spending on new oil projects, "today's investment trends are
misaligned with where the world appears to be heading," the IEA said. "Notably, approvals of
new conventional oil and gas projects fall short of what would be needed to meet continued
robust demand growth."
... ... ...
The good news is that costs continue to fall. Solar PV has seen costs decline by 75 percent
since 2010, and onshore wind and battery storage costs are down by 20 percent and 50 percent,
respectively. As such, a dollar spent on renewables buys a lot more energy than it used to, so
flat investment is not entirely negative. And in a growing number of places, solar and wind are
the cheapest option for power generation – increasingly
cheaper than existing coal plants .
Geographically, investment [in solar and wind] is concentrated in rich countries.
Roughly 90 percent of total energy investment – both for fossil fuels and for renewable
energy – was funneled into high- and upper-middle income regions. Rich countries alone
accounted for 40 percent of total energy investment, despite only making up 15 percent of the
global population.
Nothing, no EV's, solar, wind, coal or uranium is going to help. No tight shale, Arctic or
North Slope oil is going to lift this sinking ship. There are no more new oil reserves to
find and all the old fields are in a state of desperate high-tech extraction. We took all the
easy stuff, Bakken and Permian are the last ditch effort. That's why all the playas have
negative cash flow. That's why we are fecked.
That was the last great elephant field. The largest resource ever discovered on the
planet. Finally in decline. So goes Saudi Arabia. So goes OPEC. So goes mankind.
Cheap crude was a 100 year party, the hangover has already begun. Fracked oil, tar sands,
were a rescue remedy, funded by low interest rates, (debt). The massive population boom of
the last century and a half directly coordinates with increasing oil production. If you
aren't preparing yourself and your children for energy-down/population-down, you are insuring
that YOUR decedents won't be among the 100 million or so people scratching out a living in
North America in 100 years.
Before 1850 and the discovery of oil and coal, there were 1 billion people on the planet.
Now there are 7 billion. 6 billion will die as the oil economy and oil infrastructure grinds
to a halt. Better make you peace. Your plans are too late.
"...Declining uranium production will make it impossible to obtain a significant increase
in electrical power from nuclear plants in the coming decades."
Thorium Reactors...
"...A similar fate was encountered by another idea that involved "breeding" a nuclear fuel
from a naturally existing element -- thorium. The concept involved transforming the 232
isotope of thorium into the fissile 233 isotope of uranium, which then could be used as fuel
for a nuclear reactor (or for nuclear warheads). The idea was discussed at length during the
heydays of the nuclear industry, andit is still discussed today; but so far, nothing has come
out of it and the nuclear industry is still based on mineral uranium as fuel..."
OPEC was the necessary cartel that helped to stabilize production and prices.
Now all of it including Saudi Arabia, Iran and the rest, all 14 nations past and present,
is defunct. Output has been in decline since Nov. 2016. See IEA data or peakoilbarrel for a
summary
Cool..How do I fill my BMW up with coal? How about that just in time delivery. Anyone ever
try to power a semi-truck with coal? Eactly what do we pave the road ways with? Coal?
Yeesh. All wrong. Most important, slick Willie gave us our china trade problems, and then
demand for raw commods in china soared. In response, his geniuses gave us the cfma, which was
passed to let the JPMs of the world naked short commodities till the cows came home. However,
china demand growth was so far in excess of supply growth that several of the WS firms saw
the writing on the wall and went long. Thus the pols amazement when finding out v=bear
stearns was actually long oil. Finally prices got high enough that supply growth started
overtaking demand growth. We have been going down , on average, since. china demand late 90s
oil wa 3Mbpd, currently 13Mbpd
As many of you, I don't expect business as usual to continue. We get projections based on
past trends, but with oil being finite and the globe already showing the effects of climate
change, I think we are in for a tumultuous future.
"... Arthur Berman has been predicting exactly this for year. They'll spend more and more pushing production up, but eventually you get diminishing returns – the drop off in production, when it happens, will be quite dramatic as the sweet spots run dry. ..."
"... Just to add – one possible catastrophic outcome for the planet of a shale bust is poorly capped wells. Properly capping a fracked well is very difficult (you need to plug each individual geological layer, its not just a matter of putting a concrete plug on the well head). If they are not properly plugged, they will leak gas for decades and its extremely difficult and expensive to properly plug. In theory of course they are supposed to be properly capped by the operators, but if they go out of business . ..."
"... So even if gas and oil fracking stopped today, they will be a major source of CO2 emissions for decades to come, one that will cost many billions to mitigate. ..."
"... Natural gas is methane, so badly capped fracked gas wells would be really bad for climate change. ..."
"... Fracking the modern equivalent to hydrological gold mining. But money [tm] was made some confuse this with value ..."
"... This is old news. Drillers over estimated the production length for fracked wells to help their Ponzi Scheme. For a natural gas well the production tanks in most cases in 3 years. To keep production up more wells had to be drilled. Eventually places to drill become hard to locate.I witnessed this in northern PA. It was boom for about 5 years then came the bust. Although there is still some fracking it is only minor compared to what it was. A few made money but the cost to the environment was passed on to the taxpayers. ..."
"... Venezuelan oil is very important to frackers because almost all refineries in the US were built to handle the mid-density oils from Texas and Alaska. Tight oil (fracked) is super light (it can't be fracked otherwise), and so it needs to be mixed in with heavy grade oil to make it refinable. This is where heavy Venezuelan crude and Canadian tar sand oil comes in – they are essential to create a crude that can be refined in existing plants. ..."
"... So the relationship between the US tight oil industry and Venezuela/Canada is quite complex – they all need each other to some extent otherwise they are stuck with oil that can't be refined. This is of course one reason why Washington absolutely hates not having firm control of Venezuelan production. But its also why they can't afford to shut it down entirely (which would happen if there was a military invasion or civil war). ..."
"... The fracked oil and gas often have low market value. The gas wells may produce relatively low quantities of high value natural gas liquids. The oil often is so light that it produces low quantities of high value distillates like diesel fuel. The fracked crude may contain high amounts of impurities that make it difficult and expensive to refine. ..."
"... Venezuela oil can be delivered directly to the Gulf Coast refineries in tankers that require no permitting or construction. Canadian oil requires pipelines (e.g. Keystone XL) which are held up in permitting. So it is ironic that the Keystone pipeline permitting quagmire is likely to be a proximate cause for the Trump administration dabbling in Venezuela as many Gulf Coast refineries are geared for Alberta/Venezuela oil. ..."
"... It was the fruits of Bush admin energy policy. Doubt it was primarily geopolitical, more like tail wagging the dog. Though the distinction is increasingly blurry now. ..."
"... Destroying limited fresh water is insane. This is a perfect example of the horrible consequences of capitalism. Profit corrupts the political system as the state merges to serve the oligarchs. ..."
By Nick Cunningham, a freelance writer on oil and gas, renewable energy, climate
change, energy policy and geopolitics based in Pittsburgh, PA. Originally published at
OilPrice
The shale industry faces an uncertain future as drillers try to outrun the treadmill of
precipitous well declines.
For years, companies have deployed an array of drilling techniques to extract more oil and
gas out of their wells, steadily intensifying each stage of the operation. Longer laterals,
more water, more frac sand, closer spacing of wells – pushing each of these to their
limits, for the most part, led to more production. Higher output allowed the industry to
outpace the infamous decline rates from shale wells.
In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet
and the volume of water used in drilling has surged more than 250 percent, according to a
new report for
the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and
sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well
drilled in 2012, the report says.
That sounds impressive, but the industry may simply be frontloading production. The suite of
drilling techniques "have lowered costs and allowed the resource to be extracted with fewer
wells, but have not significantly increased the ultimate recoverable resource," J. David
Hughes, an earth scientist, and author of the Post Carbon report, warned. Technological
improvements "don't change the fundamental characteristics of shale production, they only speed
up the boom-to-bust life cycle," he said.
For a while, there was enough acreage to allow for a blistering growth rate, but the boom
days eventually have to come to an end. There are already some signs of strain in the shale
patch, where intensification of drilling techniques has begun to see diminishing returns.
Putting wells too close together can lead to less reservoir pressure, reducing overall
production. The industry is only now reckoning with this so-called "parent-child" well
interference problem.
Also, more water and more sand and longer laterals all have their limits .
Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company
boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT
quickly found out that it had problems when it exceeded 15,000 feet. "The decision to drill
some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing
hundreds of millions of dollars," the Wall Street Journal reported
earlier this year.
Ultimately, precipitous decline rates mean that huge volumes of capital are needed just to
keep output from declining. In 2018, the industry spent $70 billion on drilling 9,975 wells,
according to Hughes, with $54 billion going specifically to oil. "Of the $54 billion spent on
tight oil plays in 2018, 70% served to offset field declines and 30% to increase production,"
Hughes wrote.
As the shale play matures, the field gets crowded, the sweet spots are all drilled, and some
of these operational problems begin to mushroom. "Declining well productivity in some plays,
despite application of better technology, are a prelude to what will eventually happen in all
plays: production will fall as costs rise," Hughes said. "Assuming shale production can grow
forever based on ever-improving technology is a mistake -- geology will ultimately dictate the
costs and quantity of resources that can be recovered."
There are already examples of this scenario unfolding. The Eagle Ford and Bakken, for
instance, are both "mature plays," Hughes argues, in which the best acreage has been picked
over. Better technology and an intensification of drilling techniques have arrested decline,
and even led to a renewed increase in production. But ultimate recovery won't be any higher;
drilling techniques merely allow "the play to be drained with fewer wells," Hughes said. And in
the case of the Eagle Ford, "there appears to be significant deterioration in longer-term well
productivity through overcrowding of wells in sweet spots, resulting in well interference
and/or drilling in more marginal areas that are outside of sweet-spots within counties."
In other words, a more aggressive drilling approach just frontloads production, and leads to
exhaustion sooner. "Technology improvements appear to have hit the law of diminishing returns
in terms of increasing production -- they cannot reverse the realities of over-crowded wells
and geology," Hughes said.
The story is not all that different in the Permian, save for the much higher levels of
spending and drilling. Post Carbon estimates that it the Permian requires 2,121 new wells each
year just to keep production flat, and in 2018 the industry drilled 4,133 wells, leading to a
big jump in output. At such frenzied levels of drilling, the Permian could continue to see
production growth in the years ahead, but the steady increase in water and frac sand "have
reached their limits." As a result, "declining well productivity as sweet-spots are exhausted
will require higher drilling rates and expenditures in the future to maintain growth and offset
field decline," Hughes warned.
I think everybody knew that the shale boom would prove to be transient –I consider
several years as transient– and it will end with holes in earth and wallets. The Bakken
and Eagle Ford have become mature plays in a relatively short period and we will learn,
sooner than later, how the decline of these plays unfolds. Somehow the shale business model
depends on ever increasing production and production would have increased even faster if it
wasn`t for resource constraints (takeaway capacity, crew availability ). According to the EIA
the Permian is now filled with DUCKS, sorry, DUCs (drilled but uncompleted wells) waiting for
production. Those are waiting for new pipelines and, "hopefully", oil price increases
engineered by the US by production suppression in Venezuela and Iran.
Count me amongst those that would like oil price increases, although for different
reasons.
The forecasts I saw earlier were that production would peak in the early 2020s, decline
gradually for the rest of the decade, and then fall off sharply.
Arthur Berman has
been predicting exactly this for year. They'll spend more and more pushing production up, but
eventually you get diminishing returns – the drop off in production, when it happens,
will be quite dramatic as the sweet spots run dry.
The equally big question though is the influence of oil and gas prices. A crisis in the
shale fields might be precipitated not by a drop in production, but further downward pressure
on prices. Or likewise, a spike in oil prices could give a boost to yet more capital
investment in those fields. For now, I suspect the producers are far more worried about low
prices than running out of oil/gas. A lot of them are betting on substantial rises in the
future in order to make their balance sheets look better. So that's a lot of rich people who
would welcome a Middle East war.
Just to add – one possible catastrophic outcome for the planet of a shale bust is
poorly capped wells. Properly capping a fracked well is very difficult (you need to plug each
individual geological layer, its not just a matter of putting a concrete plug on the well
head). If they are not properly plugged, they will leak gas for decades and its extremely
difficult and expensive to properly plug. In theory of course they are supposed to be
properly capped by the operators, but if they go out of business .
So even if gas and oil fracking stopped today, they will be a major source of CO2
emissions for decades to come, one that will cost many billions to mitigate.
States and provinces have started program to cap old O&G wells abandoned decades ago
that are leaking methane. All they need to do for new fracking wells is put in tight
regulations and enforce them. But that requires political will.
So even if gas and oil fracking stopped today, they will be a major source of CO2
emissions for decades to come, one that will cost many billions to mitigate.
When we'd fish, mountain bike or varmint hunt in Western PA., many decades ago (ie:
ancient conventional oil & gas wells only) it was clear; not only was none of the leaking
gas ever flared, but folks were tapping the rusted christmas trees. By the 80's, as we were
building the rail trails, it was far worse than our memories. Fracked ethane/ wet gas wells
are off-limits, unless you have FLIR drones.
Well, gold does a: not explode (oh, yes it DOES!) b: does not cause 20%-89% more global
warming than CO2 (oh yes it DO!) c: "water is precious, sometimes more precious than gold?"
Walter Houston, as Howard: The Treasure of the Sierra Madre, who called Bogart, "no, not ME
baby!"
This is old news. Drillers over estimated the production length for fracked wells to help
their Ponzi Scheme. For a natural gas well the production tanks in most cases in 3 years. To
keep production up more wells had to be drilled. Eventually places to drill become hard to
locate.I witnessed this in northern PA. It was boom for about 5 years then came the bust.
Although there is still some fracking it is only minor compared to what it was. A few made
money but the cost to the environment was passed on to the taxpayers.
There may be another factor at work here. Granted that the shale boom was always going to
be a short term play, maybe the move on Venezuela is all about having oil to replace US
production as it taps out – slowly at first, then all at once. Trump & Co could
always buy Venezuelan oil at a market price but I think that the idea is to seize it to
control more of the international oil market by being able to control international prices
and you can't do that if Venezuela is an independent country. I just wonder how much damage
is going to be done in America in terms of the environment and more importantly water
supplies by all the chemicals pumped into the ground. It is going to be a toxic legacy that
will be there for generations to come.
Venezuelan oil is very important to frackers because almost all refineries in the US were
built to handle the mid-density oils from Texas and Alaska. Tight oil (fracked) is super
light (it can't be fracked otherwise), and so it needs to be mixed in with heavy grade oil to
make it refinable. This is where heavy Venezuelan crude and Canadian tar sand oil comes in
– they are essential to create a crude that can be refined in existing plants.
So the relationship between the US tight oil industry and Venezuela/Canada is quite
complex – they all need each other to some extent otherwise they are stuck with oil
that can't be refined. This is of course one reason why Washington absolutely hates not
having firm control of Venezuelan production. But its also why they can't afford to shut it
down entirely (which would happen if there was a military invasion or civil war).
So the calculations are complex, and they are being made by idiots, so there is no telling
what they are planning.
There are several facets to this. The light oil from fracking and elsewhere is needed as a
dilutent for the very heavy Venezuelan crude to enable it to be pumped on and off tank ships
and through pipelines. Dilutents are also needed for the bitumen from the Alberta tar sands.
The reason for the Keystone pipeline system is to pump diluted bitumen (dilbit) from Alberta
to the Texas refineries is that are equipped to process this very heavy material similar to
the very heavy Mexican and Venezuelan crudes. (Crude oils around the world vary greatly in
composition. Refineries are equipped to process only certain types of crude.)
The fracked oil and gas often have low market value. The gas wells may produce relatively
low quantities of high value natural gas liquids. The oil often is so light that it produces
low quantities of high value distillates like diesel fuel. The fracked crude may contain high
amounts of impurities that make it difficult and expensive to refine.
The problem seems to be a lack of pipelines to get the gas to customers.
Not that I disagree with "the boom is over" too much, but Permian is a large area and has a
way to go. But it will fizzle out in time.
Venezuela oil can be delivered directly to the Gulf Coast refineries in tankers that
require no permitting or construction. Canadian oil requires pipelines (e.g. Keystone XL)
which are held up in permitting. So it is ironic that the Keystone pipeline permitting
quagmire is likely to be a proximate cause for the Trump administration dabbling in Venezuela
as many Gulf Coast refineries are geared for Alberta/Venezuela oil.
Using data from field experiments and computer modeling of ground faults, researchers have
discovered that the practice of subsurface fluid injection used in 'fracking' and wastewater
disposal for oil and gas exploration could cause significant, rapidly spreading earthquake
activity beyond the fluid diffusion zone. The results account for the observation that the
frequency of man-made earthquakes in some regions of the country surpass natural earthquake
hotspots.
According to the U.S. Geological Survey, the largest earthquake induced by fluid injection
and documented in the scientific literature was a magnitude 5.8 earthquake in September 2016
in central Oklahoma. Four other earthquakes greater than 5.0 have occurred in Oklahoma as a
result of fluid injection, and earthquakes of magnitude between 4.5 and 5.0 have been induced
by fluid injection in Arkansas, Colorado, Kansas and Texas.
I seriously doubt that the shale boom was ever about being profitable. I have long held
that the shale industry has been artificially elevated as a hedge against risks induced by
the long term Middle East geopolitical and military strategy. It was always expected to loose
money and have negative secondary effects, but it had been decided to be necessary. Shale has
survived because of a gentleman's agreement by the power players to cover the costs of the
shale strategy; that along with investment media hype and stealthy subsidies to try to induce
outside suckers to reduce some of the burden of those behind the hedge.
The shale industry was largely small to mid-sized firms that figured out the technology to
go into low-priced leases because the oil was inaccessible. Junk bonds have fueled their
growth and operations. As long as they get the cash flow from wells to pay their junk bond
interest payment, it can keep going. Once they can't, expect a Wile E. Coyote splat in the
junk bonds market and the fracking oil patch. The majors have moved in so they might be a bit
of a flywheel for the system, but ultimately if prices are too low to support drilling, then
the majors will pull the plug as fracking is not a long-term investment play over multiple
price cycles in the same way an offshore oil field is. Instead, it can be turned on and off
at will with new drilling always required to sustain production, so you just stop drilling
when prices are too low.
a couple of on the ground, as it were, observations:
i live in frac sand country("Brady Brown"). there was a crisis of late to my north, as 2 of
the 3 sand plants in and around Voca and Brady Texas suddenly closed(after a few years of
financial shenanigans/scandal, and them being sold to multnational outfits, etc). West Texas
found a way to use the more local, white sand for their purposes, and stopped buying the
Brady Brown.
Immediate local Depression, folks moving if they could sell their houses( for sale signs there
are routinely a decade old ), local pols/big wigs freaking out.
one of them just reopened and all of a sudden, there's gobs of sand trucks heading
South(Eagle Ford). first time in prolly 8 years.
Both of my brothers in law work in the patch in the Permian roughnecking. When i probe them for anecdotes being careful not to ask leading questions they expect more
or less permanent employment. one, against my advice(which he asked for), just bought a house
in Sanderson which has no reason for being save oil.
My cousin, in East Texas, just hired on with a pipeline company headed to either the Permian
or the Bakken(he's waiting to find out).
So there's a spurt of renewed activity in South Texas, and the expectation(both in the
workforce, and in the boardroom) that West Texas(and Dakota) will continue for some time.
and i just remembered my last trip through Pasadena, Texas a year ago
the great big refinery on 225(I think it's Exxon) was putting in a gigantic separater(or
whatever you call those things) easily as tall as the smaller skyscrapers in downtown
houston(maybe 20+ stories) using 2 of the biggest, tallest cranes i've ever seen or heard
of.
Dad says it's for heavy, sour crude(a la Venezuela and Iran). so there's at least year old
expectations there, as well ie: exxon thinks it's gonna need much more refining capacity for
that oil.
it can't last forever, of course.
Midland & Odessa are definitely planning on the continuation of oil production and are
forecasting no busts. This hurts my head to understand as there are still people alive there who have been thru
multiple booms and busts over the past 70 years.
I would imagine its for the same reason there is no global warming or climate change in
Florida. Its bad for business. Those guys know the truth. But theres no advantage in talking
about it.
I don't know about that particular cracker but Exxon is building up refining capability
for the light tight oil and condensate coming out of the Permian. That work is in the Houston
area.
The idea may be Why ship it out when we can make money out of the products? I dunno.
In summary: If you're leaving an exceedingly expensive, but eminently walkable major city,
with acceptable (off peak) mass tramsit, prodigeous gas/coal/nuclear/hydroelectric sources
immediately available to move to a "normal" southern Appalachian city? Don't neglect to
research PV, geothermal, "passive" convection, and plug-in hybrid or EV transportation
options? When we were awaiting news from LA/MS friends in 2005, I'd been wondering about what
my actually retiring atop the Marcellus would be like. We'd all figured Katrina's tour of
Mars, Ursa, Mensa, Bullwinkle & Ram Powell platforms would (given Halliburton ruling the
country) touch off a slick water fracking pyramid scheme that would have the Acela
megalopolis simply killing us for our fracked gas, as they'd simply stolen our coal, gas, oil
and nuclear energy? Silly, substance abusing, deplorables!
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal.
CVX knows exactly what Anadarko's actual and potential wells are worth to them under a
variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a
bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of
the chapeau to them.
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal.
CVX knows exactly what Anadarko's actual and potential wells are worth to them under a
variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a
bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of
the chapeau to them.
The evidence for production-suppression is opposition to the new Russia to Germany
pipeline and US sanctions on Iran and Venezuela. Poland is America's stalking horse in Europe
but is not getting much support from its neighbors.
Its my suspicion that vast sums of speculative money have gone into fracking in USA and UK
because there was nothing better to do with the great increase in the money supply. That
seems to be what's keeping the industry afloat for the time being.
Plutonium Kun's advice about plugging wells points to the frightful environmental effects
that are coming to those countries that have allowed fracking. It will be the people that
suffer.
It was the fruits of Bush admin energy policy. Doubt it was primarily geopolitical, more
like tail wagging the dog. Though the distinction is increasingly blurry now.
Every presidency seems to have a couple of these programs. Mixed range of soundness as
policy
Market innovation (Enron), corn ethanol, developing H2 fuel cells (with the H2 coming from
natgas at the time), subsidies (and loan guarantees!) for electric cars, even bigger ones for
luxury electric cars, natgas import facilities, natgas export facilities, favor pipe to
Canada and block the rail, favor rail to Canada and block the pipe, govt indemnifying the
nuke industry from lawsuit damages arising from accidents, allowing utilities to "bail in"
customers in case of losses from nuke projects, exempting any and all fracking waste products
from clean water regs, actually subsidizing solar and wind, actually retiring coal, also
actually sanctioning or invading no less than big 5 oil producing countries
Whew! Policy!
Destroying limited fresh water is insane. This is a perfect example of the horrible
consequences of capitalism. Profit corrupts the political system as the state merges to serve
the oligarchs.
https://acdn.adnxs.com/ib/static/usersync/v3/async_usersync.html <img
src="http://b.scorecardresearch.com/p?c1=2&c2=16807273&cv=2.0&cj=1" />
The Shale
Boom Is About To Go Bust Posted on May 10,
2019 by Yves
SmithBy Nick Cunningham, a freelance writer on oil and gas, renewable energy, climate
change, energy policy and geopolitics based in Pittsburgh, PA. Originally published at
OilPrice
The shale industry faces an uncertain future as drillers try to outrun the treadmill of
precipitous well declines.
For years, companies have deployed an array of drilling techniques to extract more oil and
gas out of their wells, steadily intensifying each stage of the operation. Longer laterals,
more water, more frac sand, closer spacing of wells – pushing each of these to their
limits, for the most part, led to more production. Higher output allowed the industry to
outpace the infamous decline rates from shale wells.
In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet
and the volume of water used in drilling has surged more than 250 percent, according to a
new report for
the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and
sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well
drilled in 2012, the report says.
That sounds impressive, but the industry may simply be frontloading production. The suite of
drilling techniques "have lowered costs and allowed the resource to be extracted with fewer
wells, but have not significantly increased the ultimate recoverable resource," J. David
Hughes, an earth scientist, and author of the Post Carbon report, warned. Technological
improvements "don't change the fundamental characteristics of shale production, they only speed
up the boom-to-bust life cycle," he said.
For a while, there was enough acreage to allow for a blistering growth rate, but the boom
days eventually have to come to an end. There are already some signs of strain in the shale
patch, where intensification of drilling techniques has begun to see diminishing returns.
Putting wells too close together can lead to less reservoir pressure, reducing overall
production. The industry is only now reckoning with this so-called "parent-child" well
interference problem.
Also, more water and more sand and longer laterals all have their limits .
Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company
boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT
quickly found out that it had problems when it exceeded 15,000 feet. "The decision to drill
some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing
hundreds of millions of dollars," the Wall Street Journal reported
earlier this year.
Ultimately, precipitous decline rates mean that huge volumes of capital are needed just to
keep output from declining. In 2018, the industry spent $70 billion on drilling 9,975 wells,
according to Hughes, with $54 billion going specifically to oil. "Of the $54 billion spent on
tight oil plays in 2018, 70% served to offset field declines and 30% to increase production,"
Hughes wrote.
As the shale play matures, the field gets crowded, the sweet spots are all drilled, and some
of these operational problems begin to mushroom. "Declining well productivity in some plays,
despite application of better technology, are a prelude to what will eventually happen in all
plays: production will fall as costs rise," Hughes said. "Assuming shale production can grow
forever based on ever-improving technology is a mistake -- geology will ultimately dictate the
costs and quantity of resources that can be recovered."
There are already examples of this scenario unfolding. The Eagle Ford and Bakken, for
instance, are both "mature plays," Hughes argues, in which the best acreage has been picked
over. Better technology and an intensification of drilling techniques have arrested decline,
and even led to a renewed increase in production. But ultimate recovery won't be any higher;
drilling techniques merely allow "the play to be drained with fewer wells," Hughes said. And in
the case of the Eagle Ford, "there appears to be significant deterioration in longer-term well
productivity through overcrowding of wells in sweet spots, resulting in well interference
and/or drilling in more marginal areas that are outside of sweet-spots within counties."
In other words, a more aggressive drilling approach just frontloads production, and leads to
exhaustion sooner. "Technology improvements appear to have hit the law of diminishing returns
in terms of increasing production -- they cannot reverse the realities of over-crowded wells
and geology," Hughes said.
The story is not all that different in the Permian, save for the much higher levels of
spending and drilling. Post Carbon estimates that it the Permian requires 2,121 new wells each
year just to keep production flat, and in 2018 the industry drilled 4,133 wells, leading to a
big jump in output. At such frenzied levels of drilling, the Permian could continue to see
production growth in the years ahead, but the steady increase in water and frac sand "have
reached their limits." As a result, "declining well productivity as sweet-spots are exhausted
will require higher drilling rates and expenditures in the future to maintain growth and offset
field decline," Hughes warned.
I think everybody knew that the shale boom would prove to be transient –I consider
several years as transient– and it will end with holes in earth and wallets. The Bakken
and Eagle Ford have become mature plays in a relatively short period and we will learn,
sooner than later, how the decline of these plays unfolds. Somehow the shale business model
depends on ever increasing production and production would have increased even faster if it
wasn`t for resource constraints (takeaway capacity, crew availability ). According to the EIA
the Permian is now filled with DUCKS, sorry, DUCs (drilled but uncompleted wells) waiting for
production. Those are waiting for new pipelines and, "hopefully", oil price increases
engineered by the US by production suppression in Venezuela and Iran.
Count me amongst those that would like oil price increases, although for different
reasons.
The forecasts I saw earlier were that production would peak in the early 2020s, decline
gradually for the rest of the decade, and then fall off sharply.
Arthur Berman has
been predicting exactly this for year. They'll spend more and more pushing production up, but
eventually you get diminishing returns – the drop off in production, when it happens,
will be quite dramatic as the sweet spots run dry.
The equally big question though is the influence of oil and gas prices. A crisis in the
shale fields might be precipitated not by a drop in production, but further downward pressure
on prices. Or likewise, a spike in oil prices could give a boost to yet more capital
investment in those fields. For now, I suspect the producers are far more worried about low
prices than running out of oil/gas. A lot of them are betting on substantial rises in the
future in order to make their balance sheets look better. So that's a lot of rich people who
would welcome a Middle East war.
Just to add – one possible catastrophic outcome for the planet of a shale bust is
poorly capped wells. Properly capping a fracked well is very difficult (you need to plug each
individual geological layer, its not just a matter of putting a concrete plug on the well
head). If they are not properly plugged, they will leak gas for decades and its extremely
difficult and expensive to properly plug. In theory of course they are supposed to be
properly capped by the operators, but if they go out of business .
So even if gas and oil fracking stopped today, they will be a major source of CO2
emissions for decades to come, one that will cost many billions to mitigate.
States and provinces have started program to cap old O&G wells abandoned decades ago
that are leaking methane. All they need to do for new fracking wells is put in tight
regulations and enforce them. But that requires political will.
So even if gas and oil fracking stopped today, they will be a major source of CO2
emissions for decades to come, one that will cost many billions to mitigate.
When we'd fish, mountain bike or varmint hunt in Western PA., many decades ago (ie:
ancient conventional oil & gas wells only) it was clear; not only was none of the leaking
gas ever flared, but folks were tapping the rusted christmas trees. By the 80's, as we were
building the rail trails, it was far worse than our memories. Fracked ethane/ wet gas wells
are off-limits, unless you have FLIR drones.
Well, gold does a: not explode (oh, yes it DOES!) b: does not cause 20%-89% more global
warming than CO2 (oh yes it DO!) c: "water is precious, sometimes more precious than gold?"
Walter Houston, as Howard: The Treasure of the Sierra Madre, who called Bogart, "no, not ME
baby!"
This is old news. Drillers over estimated the production length for fracked wells to help
their Ponzi Scheme. For a natural gas well the production tanks in most cases in 3 years. To
keep production up more wells had to be drilled. Eventually places to drill become hard to
locate.I witnessed this in northern PA. It was boom for about 5 years then came the bust.
Although there is still some fracking it is only minor compared to what it was. A few made
money but the cost to the environment was passed on to the taxpayers.
There may be another factor at work here. Granted that the shale boom was always going to
be a short term play, maybe the move on Venezuela is all about having oil to replace US
production as it taps out – slowly at first, then all at once. Trump & Co could
always buy Venezuelan oil at a market price but I think that the idea is to seize it to
control more of the international oil market by being able to control international prices
and you can't do that if Venezuela is an independent country. I just wonder how much damage
is going to be done in America in terms of the environment and more importantly water
supplies by all the chemicals pumped into the ground. It is going to be a toxic legacy that
will be there for generations to come.
Venezuelan oil is very important to frackers because almost all refineries in the US were
built to handle the mid-density oils from Texas and Alaska. Tight oil (fracked) is super
light (it can't be fracked otherwise), and so it needs to be mixed in with heavy grade oil to
make it refinable. This is where heavy Venezuelan crude and Canadian tar sand oil comes in
– they are essential to create a crude that can be refined in existing plants.
So the relationship between the US tight oil industry and Venezuela/Canada is quite
complex – they all need each other to some extent otherwise they are stuck with oil
that can't be refined. This is of course one reason why Washington absolutely hates not
having firm control of Venezuelan production. But its also why they can't afford to shut it
down entirely (which would happen if there was a military invasion or civil war).
So the calculations are complex, and they are being made by idiots, so there is no telling
what they are planning.
There are several facets to this. The light oil from fracking and elsewhere is needed as a
dilutent for the very heavy Venezuelan crude to enable it to be pumped on and off tank ships
and through pipelines. Dilutents are also needed for the bitumen from the Alberta tar sands.
The reason for the Keystone pipeline system is to pump diluted bitumen (dilbit) from Alberta
to the Texas refineries is that are equipped to process this very heavy material similar to
the very heavy Mexican and Venezuelan crudes. (Crude oils around the world vary greatly in
composition. Refineries are equipped to process only certain types of crude.)
Well, and then there is this: https://www.worldoil.com/news/2019/4/11/permians-flaring-rises-by-85-as-oil-boom-continues
"The Permian Basin has produced so much natural gas that by the end of 2018 producers were
burning off more than enough of the fuel to meet residential demand across Texas. The
phenomenon has likely only intensified since then."
The problem seems to be a lack of pipelines to get the gas to customers.
Not that I disagree with "the boom is over" too much, but Permian is a large area and has a
way to go. But it will fizzle out in time.
Venezuela oil can be delivered directly to the Gulf Coast refineries in tankers that
require no permitting or construction. Canadian oil requires pipelines (e.g. Keystone XL)
which are held up in permitting. So it is ironic that the Keystone pipeline permitting
quagmire is likely to be a proximate cause for the Trump administration dabbling in Venezuela
as many Gulf Coast refineries are geared for Alberta/Venezuela oil.
Using data from field experiments and computer modeling of ground faults, researchers have
discovered that the practice of subsurface fluid injection used in 'fracking' and wastewater
disposal for oil and gas exploration could cause significant, rapidly spreading earthquake
activity beyond the fluid diffusion zone. The results account for the observation that the
frequency of man-made earthquakes in some regions of the country surpass natural earthquake
hotspots.
According to the U.S. Geological Survey, the largest earthquake induced by fluid injection
and documented in the scientific literature was a magnitude 5.8 earthquake in September 2016
in central Oklahoma. Four other earthquakes greater than 5.0 have occurred in Oklahoma as a
result of fluid injection, and earthquakes of magnitude between 4.5 and 5.0 have been induced
by fluid injection in Arkansas, Colorado, Kansas and Texas.
I seriously doubt that the shale boom was ever about being profitable. I have long held
that the shale industry has been artificially elevated as a hedge against risks induced by
the long term Middle East geopolitical and military strategy. It was always expected to loose
money and have negative secondary effects, but it had been decided to be necessary. Shale has
survived because of a gentleman's agreement by the power players to cover the costs of the
shale strategy; that along with investment media hype and stealthy subsidies to try to induce
outside suckers to reduce some of the burden of those behind the hedge.
The shale industry was largely small to mid-sized firms that figured out the technology to
go into low-priced leases because the oil was inaccessible. Junk bonds have fueled their
growth and operations. As long as they get the cash flow from wells to pay their junk bond
interest payment, it can keep going. Once they can't, expect a Wile E. Coyote splat in the
junk bonds market and the fracking oil patch. The majors have moved in so they might be a bit
of a flywheel for the system, but ultimately if prices are too low to support drilling, then
the majors will pull the plug as fracking is not a long-term investment play over multiple
price cycles in the same way an offshore oil field is. Instead, it can be turned on and off
at will with new drilling always required to sustain production, so you just stop drilling
when prices are too low.
a couple of on the ground, as it were, observations:
i live in frac sand country("Brady Brown"). there was a crisis of late to my north, as 2 of
the 3 sand plants in and around Voca and Brady Texas suddenly closed(after a few years of
financial shenanigans/scandal, and them being sold to multnational outfits, etc). West Texas
found a way to use the more local, white sand for their purposes, and stopped buying the
Brady Brown.
Immediate local Depression, folks moving if they could sell their houses(for sale signs there
are routinely a decade old), local pols/big wigs freaking out.
one of them just reopened and all of a sudden, there's gobs of sand trucks heading
South(Eagle Ford). first time in prolly 8 years.
Both of my brothers in law work in the patch in the Permian roughnecking.
when i probe them for anecdotes being careful not to ask leading questions they expect more
or less permanent employment. one, against my advice(which he asked for), just bought a house
in Sanderson which has no reason for being save oil.
My cousin, in East Texas, just hired on with a pipeline company headed to either the Permian
or the Bakken(he's waiting to find out).
so there's a spurt of renewed activity in South Texas, and the expectation(both in the
workforce, and in the boardroom) that West Texas(and Dakota) will continue for some time.
and i just remembered my last trip through Pasadena, Texas a year ago
the great big refinery on 225(I think it's Exxon) was putting in a gigantic separater(or
whatever you call those things) easily as tall as the smaller skyscrapers in downtown
houston(maybe 20+ stories) using 2 of the biggest, tallest cranes i've ever seen or heard
of.
Dad says it's for heavy, sour crude(a la Venezuela and Iran). so there's at least year old
expectations there, as well ie: exxon thinks it's gonna need much more refining capacity for
that oil.
it can't last forever, of course.
I would imagine its for the same reason there is no global warming or climate change in
Florida. Its bad for business. Those guys know the truth. But theres no advantage in talking
about it.
I don't know about that particular cracker but Exxon is building up refining capability
for the light tight oil and condensate coming out of the Permian. That work is in the Houston
area.
The idea may be Why ship it out when we can make money out of the products? I dunno.
In summary: If you're leaving an exceedingly expensive, but eminently walkable major city,
with acceptable (off peak) mass tramsit, prodigeous gas/coal/nuclear/hydroelectric sources
immediately available to move to a "normal" southern Appalachian city? Don't neglect to
research PV, geothermal, "passive" convection, and plug-in hybrid or EV transportation
options? When we were awaiting news from LA/MS friends in 2005, I'd been wondering about what
my actually retiring atop the Marcellus would be like. We'd all figured Katrina's tour of
Mars, Ursa, Mensa, Bullwinkle & Ram Powell platforms would (given Halliburton ruling the
country) touch off a slick water fracking pyramid scheme that would have the Acela
megalopolis simply killing us for our fracked gas, as they'd simply stolen our coal, gas, oil
and nuclear energy? Silly, substance abusing, deplorables!
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal.
CVX knows exactly what Anadarko's actual and potential wells are worth to them under a
variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a
bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of
the chapeau to them.
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal.
CVX knows exactly what Anadarko's actual and potential wells are worth to them under a
variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a
bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of
the chapeau to them.
The evidence for production-suppression is opposition to the new Russia to Germany
pipeline and US sanctions on Iran and Venezuela. Poland is America's stalking horse in Europe
but is not getting much support from its neighbors.
Its my suspicion that vast sums of speculative money have gone into fracking in USA and UK
because there was nothing better to do with the great increase in the money supply. That
seems to be what's keeping the industry afloat for the time being.
Plutonium Kun's advice about plugging wells points to the frightful environmental effects
that are coming to those countries that have allowed fracking. It will be the people that
suffer.
It was the fruits of Bush admin energy policy. Doubt it was primarily geopolitical, more
like tail wagging the dog. Though the distinction is increasingly blurry now.
Every presidency seems to have a couple of these programs. Mixed range of soundness as
policy
Market innovation (Enron), corn ethanol, developing H2 fuel cells (with the H2 coming from
natgas at the time), subsidies (and loan guarantees!) for electric cars, even bigger ones for
luxury electric cars, natgas import facilities, natgas export facilities, favor pipe to
Canada and block the rail, favor rail to Canada and block the pipe, govt indemnifying the
nuke industry from lawsuit damages arising from accidents, allowing utilities to "bail in"
customers in case of losses from nuke projects, exempting any and all fracking waste products
from clean water regs, actually subsidizing solar and wind, actually retiring coal, also
actually sanctioning or invading no less than big 5 oil producing countries
Whew! Policy!
Destroying limited fresh water is insane. This is a perfect example of the horrible
consequences of capitalism. Profit corrupts the political system as the state merges to serve
the oligarchs.
"... In a properly accounted world all of those wells from 2 years ago which cannot be repay their debt should have that debt apply to the new wells that are drilled now -- and erase their profit. This is forever, by the way. Anytime oil drops below whatever 60, or 55 or 50, the wells drilled then and the money borrowed to drill them is essentially guaranteed to get applied to future wells. ..."
"... But this won't happen. When you have to have the oil you get the oil. ..."
Not going to scroll up for the spreadsheet above, not easy where I am sitting right now.
Concerning net revenue and production. The problem is not future price of oil. The problem
is the past price of oil. Two-thirds of the total lifetime production of one of these shale
wells comes out of the ground in the first two years. The price was sub-60 a couple of years
back and that oil flowed and generated only that much money. That well's debt is not going to
get repaid by that well. The oil came out at a lower price and that deal is done.
This means that the month number where revenue becomes negative is much sooner. And if
things were logical and money was not created from thin air, the fact that the well in
question cannot repay its debt does not make the debt go away.
In a properly accounted world
all of those wells from 2 years ago which cannot be repay their debt should have that debt
apply to the new wells that are drilled now -- and erase their profit. This is forever, by
the way. Anytime oil drops below whatever 60, or 55 or 50, the wells drilled then and the
money borrowed to drill them is essentially guaranteed to get applied to future wells.
But this won't happen. When you have to have the oil you get the oil.
What it really means. 42 more years, and it's gone. 1.531 trillion bbls divided by a no
grow of 100 million bbls consumption a day, simple math. And we rant about finding another 50
billion bbls. That only takes the total of the recoverable oil to 1.581 trillion bbls.
Oil will leave us before we leave oil. We are heading for mass starvation. There are no
electric fire engines, there are no electric ambulances, there are no electric farm
machinery, there are no electric military machinery, there are no electric boats or ships or
ferries, there are no electric airplanes, fighter jets, helicopters, there are 1.4 billion
cars in the world of which 3 million are electric, if Tesla quadruples production it couldn't
replace the gas and diesel powered vehicles in 1200 years, and the Chinese electrics are
crap.
This map is complete BS. No one, especially some spy agency, knows how much of anything is
underground.
The only known fact is current production. "Known Reserves" is a hopelessly politicized
exercise in conjecture, primarily for the purpose of securitizing international loans at
favorable rates.
Proved reserves of crude oil in the United States increased 19.5% (6.4 billion barrels)
to 39.2 billion barrels at Year-End 2017, setting a new U.S. record for crude oil proved
reserves. The previous record was 39.0 billion barrels set in 1970.
The USGS says all 20 billion barrels of oil are "technically recoverable," meaning the
oil could be brought to the surface "using currently available technology and industry
practices."
Between the corrupt politicians, and oil execs. these morons can't even concoct a decent
lie anymore.
"... We can, however, demand reserve transparency in our own country and that we are NOT getting. In essence the lies being said about "economically" recoverable shale oil reserves in America are way bigger whoppers than any lies the Middle East has ever told. ..."
"... U.S. shale drillers have run into a series of problems that have resulted in increased scrutiny on their operations. The difficulties span their operations – production issues, poor financials and less love from Wall Street. ..."
"... Even as WTI has moved solidly above $60 per barrel, the U.S. shale industry is trying to find ways to right the ship. As Reuters reports, a series of drillers, even prominent ones, are laying off workers. Pioneer Natural Resources – often held up as one of the better of the bunch – and Laredo Petroleum announced just this week that they will be cutting staff. As Jennifer Hiller of Reuters points out, Pioneer has not laid off workers since 1998. ..."
"... In March, Devon Energy eliminated 200 jobs. ..."
"... According to a report from Tudor, Pickering, Holt & Co., the recent layoffs may not be the end of the story. Everyone should expect more job cuts "over the coming quarters as companies address right-sizing the corporate cost structures," the firm said in its report. ..."
Hello Dennis. Have you ever really thought about why the Saudi's would keep their
production info as a state secret? I think it has much less to do about quotas than maintaining
the status quo of a country and society much different than our western norms.
I have guessed their remaining reserves around 80 gb before, and still believe its in that
area. Of course ANYONE without actual production and reservoir info is also guessing whether
they are economists, engineers, geologists, or whoever.
If my guess is correct, we will see KSA production declining on a accelerating rate within a
few years. Kuwait will not be far behind. North American shale will likely be topped out by
then. Gee, that might be post peak.
I hope they have more recoverable oil than my guess, because its going to be a difficult
transition.
Mr. Patterson, thanks for the article. You have defended it quite well, this in spite of
Dennis Coyne's constant interjections.
Estimating remaining reserves from mature fields is not difficult from an engineering
standpoint and how one tinkers with known reservoirs in that field (stuffing gas back into
them, HZ laterals above O/W contacts, etc.) does not magically create "new" reserves, it
simply speeds up the rate of extraction (arrests natural decline rates). The Saudis lie about
their sovereign wealth and it's their right to lie, I suppose; all we can do is try to
outsmart them, as you have. America cannot control the Saudi's, regardless of tweets.
We can, however, demand reserve transparency in our own country and that we are NOT
getting. In essence the lies being said about "economically" recoverable shale oil reserves
in America are way bigger whoppers than any lies the Middle East has ever told.
Mike, thanks for the kind words. I am quite used to Dennis' interjections. They don't bother
me. In fact, I enjoy the dialogue with him. It keeps me on my toes.
I can feel the tide turning concerning peak oil. I think OPEC peaked in 2016, politically
suppressed production notwithstanding. However, the bigger surprise may be right here in the
good old USA. The shale bubble could be bursting a lot sooner than a lot of people think.
U.S. shale drillers have run into a series of problems that have resulted in increased
scrutiny on their operations. The difficulties span their operations – production
issues, poor financials and less love from Wall Street.
Even as WTI has moved solidly above $60 per barrel, the U.S. shale industry is trying
to find ways to right the ship. As Reuters reports, a series of drillers, even prominent
ones, are laying off workers. Pioneer Natural Resources – often held up as one of the
better of the bunch – and Laredo Petroleum announced just this week that they will be
cutting staff. As Jennifer Hiller of Reuters points out, Pioneer has not laid off workers
since 1998.
In March, Devon Energy eliminated 200 jobs.
According to a report from Tudor, Pickering, Holt & Co., the recent layoffs may not
be the end of the story. Everyone should expect more job cuts "over the coming quarters as
companies address right-sizing the corporate cost structures," the firm said in its
report.
Nevertheless, the EIA still expects the boom to continue for years and years. We shall
see.
Nice summary, Ron. Brought to mind the old Oil Drum days. Thanks for taking the time to
provide this information. Given the admittedly not high-confidence prognostications in
Saudi/world oil production, it looks to me like the global economy may be in for at least one
serious oil shock in the 2020s.
"... add to that the usual woes of increasing internal oil consumption (3 mbd and rising fast) and the need to try and build their way out of their demise (requiring more oil and money), and the usual predictions of the 'export land model' look very reasonable, and disastrous for the House of Saud. There will be a tapered end, but the potential for acute instability in production and the in political and social environments of the country within the next decade is real. ..."
A great article that offers a more realistic view of the very old giant oil fields. It is
very obvious that what they are doing to maintain production will result in a more rapid
decline in the future. When that happens KSA will be in a lot of hurt, and the world will
have an abrupt awakening.
So my simple math says: 256 URR was to last 53 years, 74 URR at the same production rate will
last 15 years. Seneca with a vengeance! Rite? EOLAWKI here we come!
add to that the usual woes of increasing internal oil consumption (3 mbd and rising fast)
and the need to try and build their way out of their demise (requiring more oil and money),
and the usual predictions of the 'export land model' look very reasonable, and disastrous for
the House of Saud. There will be a tapered end, but the potential for acute instability in
production and the in political and social environments of the country within the next decade
is real.
"... Oil consumption has been increasing in all sectors and the growing global economy will require more oil in industry. You seem to think oil is just used in transportation. NOT true. ..."
"... Imagine oil production peaked today. In order for aviation to continue to grow, along with other industries that use oil. How many of the 98 million vehicles sold this year would need to be electric cars? How many electric motorcycles would have to be sold? ..."
"... I believe a Seneca cliff scenario would be a catastrophic one hence the reaction to such a scenario would also be catastrophic. ..."
"... World demand is currently over 100 mb/day, while production is at about 99 mb/day. Does that mean we are using up the already produced reserves? ..."
At some point the Seneca Cliff will be hit. If they are doing all this advanced recovery to to keep flow rates up then fields
will probably hit a wall and crash rather than slow decline. Is my thinking correct on that? Karen
Oil consumption has been increasing in all sectors and the growing global economy will require more oil in industry. You seem
to think oil is just used in transportation. NOT true.
Imagine oil production peaked today. In order for aviation to continue to grow, along with other industries that use oil. How many of the 98 million vehicles sold
this year would need to be electric cars? How many electric motorcycles would have to be sold?
The Seneca cliff for World output requires heroic assumptions which are unlikely to be true in practice.
I strongly disagree with that assessment. I believe the probability of a Seneca cliff is increasing. I think oil extraction is an economic phenomena, not a geological phenomena. During economic expansion, a positive feedback loop is in place: oil extraction produces economic growth which encourages investment in oil extraction producing more economic growth. Once peak oil occurs, I anticipate that this feedback loop will go into reverse: decreased oil production will produce economic contraction which will discourage investment in oil extraction reducing extraction rates leading to economic collapse.
Without investment the IEA estimates that production would fall by 50% in 2025 and by 80% in 2040.
I actually think economic collapse is a great opportunity to introduce a new economic system. The one we have is not only unfair, it encourages environmental devastation.
David Graebner asks rhetorically how a theory such as neoclassic economics based on false hypotheses perdures. His answer is that you teach the biggest lies in the first year. That's why false preconceptions about the economy are so common. I think neoclassical economics chose the wrong mathematical tool to analyse the economy, they chose optimisation. I don't see anything optimal in the economy, I think differential systems would be a much more appropriate mathematical tool with which to analyse the economy, keeping track of money flows.
I assume a Seneca cliff scenario would imply rapid economic collapse, as a result i think there will be war over resources.
Between which countries i don't know, but i assume U.S will go to war with Russia and or China, via direct war or proxy wars in
regions were the countries national security depends on specific resources. So the middle east would as usual be a key area of
conflict.
I believe a Seneca cliff scenario would be a catastrophic one hence the reaction to such a scenario would also be catastrophic.
U.S will go to war with Russia and or China, via direct war or proxy wars in regions were the countries national security depends
on specific resources.
Perhaps! However modern warfare tends to be very energy intensive. It seems to me a rather safe bet that in a post peak oil
world, mostly running on renewables, it might be more likely that societies will be trying to conserve their energy resources
and not waste it on war.
But the verdict is not yet in, on whether or not humans are smarter than yeast!
It simply means we are using oil that is being stored, the so-called oil stocks, eventually as these are reduced, oil prices
start to rise and demand (consumption) decreases while supply (production) increases in response to the change in oil price.
Well, no, Ghawar is not declining at 2% per year. Ghawar did not start declining in 2004. And
the southern two fields are not declining at all. The northern three fields reached their
Seneca Cliff somewhere around 2010 and began declining at several times 2%. They will decline
to near nothing in the next few years. Then Ghawar will have level production at somewhere
around 2 million barrels per day and hold that level for a decade or two.
Ghawar cannot possibly be adequately described as one field. It is five different fields
with five different decline and depletion rates.
When Saudi said, in 2006, that their average decline rate was down to almost 2%, that was
the average for all their fields. Some fields were declining at a much faster rate and some
fields were not declining at all. Khurais and Manifa were still to be ramped up. Those fields
had been in mothballs and would be brought back on line. Now they are likely not declining at
all but other fields are declining at a much faster rate than 2%.
But here is the important point. The depletion rate is another matter altogether. That
figure is likely above 8% per year.
Do you have production data for the various fields from 2006 to 2018?
Dennis, you know better than ask such a silly question. Saudi production of individual
fields is a closely guarded secret.
Dennis, have you ever wondered why the Saudis keep all this data such a secret? Why don't
they just let the actual data known to the world? What was the production data from Safaniya
in 2018? Or what was the production data from Manifa in 2018? Or what was the production data
from Khurais in 2018, or from Berri, or from all their other fields? And how did that compare
to the production in 2017, or 2016?
Dennis, we don't know shit about any of this. We don't know because it is a closely
guarded secret. Why, Dennis, Why?
They know Dennis, they know and they don't want you to know. Why?
I know why Dennis. Because what they actually report, which is almost nothing, is a lie.
You simply choose to believe it. I do not. I choose to believe the analysis who try to figure
out why they are lying. You choose to simply believe the Saudis.
Dennis, the idea that Saudi Arabia has 266 billion barrels of reserves is preposterous
beyond belief. Even the Saudis realize that now are trying to slowly reduce that figure. Yet
some people, like you, Robert Rapier and Michael Lynch, seemed perfectly ready to believe
such an absurd figure. That just floored me. Goddammit, have some people gone insane?
Okay, I have said my peace here and showed my ignorance as to what Saudi Arabia actually
can produce for the next 50 years. But you know, it is what they say they can produce.
You believe them. I don't. And neither of us can prove our case. And there it must rest
until the actual production data comes in next year and next year and ..
When this is true, that's the reason China is pushing electric travel as hard as they
can.
They have more possibilites to know the truth (secret service) than we reading reports.
And with SA and Russia having only round about 80 GB left, and producing each round about 10
mbpd, there are not many years left before a major oil incident.
I wonder why oil prices are that stable at the moment. Oil production fell hard this year
so far, down everywhere except USA. And there the growth is decelerated.
And demand is still climbing, it will use up all the US growth projected by the optimistic
EIA.
A 500 kbpd decline from OPEC is not included here, they still calculate with an increase from
opec.
Last question: Where is Russia standing at the moment?
"... Saudi Arabia, in 2018 produced approximately 3.76 billion barrels of crude only. Their BOE produced was approximately 4.75 billion barrels. That would account for the revenue is they sold every barrel of it. But they consumed a lot themselves. So other than that I have no explanation. Do they count their own consumption as revenue? ..."
In the bond prospectus SA revealed their financials. Puzzling to me was the claim of
revenue of $356 billion.
Why puzzling?
Because Brent averaged ~$75/bbl in 2018. Divide $356 by $75 and you come up with 4.75
Gbbl, which when we divide by 365 days in a year, we get 13 million barrels per day
production.
???
I can't get their numbers to work. Even with a 10% premium on their grades of crude
(generous), that leaves 11.7 mbd of production . I can't get anything to line up here.
They also produce NGL and natural gas, in 2016 it was about 1.94 Mb/d or 708 MMb of NGL, I
have no idea what the average selling price is for NGL on World markets, it would depend on
the mix of NGL of course.
Saudi Arabia, in 2018 produced approximately 3.76 billion barrels of crude only. Their BOE
produced was approximately 4.75 billion barrels. That would account for the revenue is they
sold every barrel of it. But they consumed a lot themselves. So other than that I have no
explanation. Do they count their own consumption as revenue?
(2018) Oil production from wells started in 2018 is at: 3,541,921 bo/day, this is 54.4% of the total 6,512,307 bo/day.
(2017) Oil production from wells started in 2017 peaked in December 2017 at 2,889,460 bo/day, they are now producing,
December 2018: 1,178,108 bo/day. Giving a drop from the peak of -59.2% in the last 12 months.
(2016) Production from wells started in 2016 peaked in December 2016 at 1,561,476 bo/day, they are now producing,
December 2018: 416,032 bo/day. Giving a drop from the peak of -73.4% in the last 24 months. After one year they were at, December
2017: 662,907 bo/day. Giving a drop from the peak of -57.5% over 12 months
An annual decline rate of 57.5 percent is insane. Yet 3,541,921 bo/day from 2018 wells is even more insane. Shale oil is a phenomenon
no one would have believed just a few years ago.
But now it is obvious that this juggernaut called shale oil is slowing down. And its crash will likely be more shocking than
its rise.
The decline is likely to be less steep than the increase
Have you heard about a Seneca cliff? It is called that way because Seneca in his letter
number 91 to Lucillius (Epistulae Morales ad Lucilium), written towards the end of the year
AD 64, a year before he died, refers to the fire that destroyed Lugdunum (Lyon) the summer of
that year in the following terms:
It would be some consolation for the feebleness of our selves and our works, if all
things should perish as slowly as they come into being; but as it is, increases are of
sluggish growth, but the way to ruin is rapid.
It appears he knew almost two thousand years ago what you don't.
I expect that a long slow declining tail of production will have some abrupt
jolts downward along the way, and end up lower quicker as a result.
The jolts downward will come as producing countries become failed states and the chaos
disrupts operations.
For examples of how this comes to be, just look at the past 5 yrs of Venez and Libya as
examples. Sure they may pick back up at some point, but overall effect is diminished global
production, well below a theoretically well managed industry.
Secondly, (and likely a smaller effect) some deposits will likely be kept in the ground
because of choices some cultures make. For example, I could see the USA deciding to keep its
large remaining coal deposits largely in the ground after 2030. Canada could decide to put a
big constraint on oil sand production, keeping just enough for domestic use, if they so
desired.
Why you think such scenario is so improbable?
Venezuela is living a Seneca cliff in its oil production right now. Did anybody predicted it
before it took place?
We have no idea of what will happen after Peak Oil. Some people assume nothing, while
others think it will be the end of our civilization. Somewhere in between probably. But I
fail to see how the economy can take it well if for most applications we can't substitute
oil. The globalization is run on oil and its derivatives.
Your assumptions can only be valid at this side of the peak. If you think otherwise you
fool yourself.
"... Better propant , longer laterals , some improvement of fluid , improved rigs and pads enable to drill several laterals simultaneously have made the improvement they call shale revolution. ..."
There is no doubt the tight rock structures which are much more difficult to extract oil from
than sandstone reservoir can be stimulated in different ways with good result. But that costs
a lot of money.
As I read fracking uses a very high hydraulic pressure open up the tight rock layers and
until a few years ago the oil flow dropped at a very early stage because the overlaying
weight and beacuse the oil flow carries with with itself particles that block the fraction.
Later it followed a propant research that was done before but again this gave improvement
and could hold the fracs open for longer.
Than there was research on chemical injected that should reduce friction between oil flow
and rock. There is also lots of other factores like gazes, metal that in certain pressures, temperatures
might react and create pollutant as happened lately when oil cargo was sent back from
Asia.
Better propant , longer laterals , some improvement of fluid , improved rigs and pads
enable to drill several laterals simultaneously have made the improvement they call shale
revolution.
Still very few are able to earn money to pay dividend, loan, interest and finance expansion with
WTI 60 USD.
Now number of rigs increasing again, but why when there are so many DUCS? Probably because investors tells
the business shall be cash neutral. Could it be the DUCS are so closely spaced that using along with the existing wells might
be not
profitable because of interference with nearby wells.
"... Hubbert wrote in 1948: "How soon the decline may set in is not possible to say, Nevertheless the higher the peak to which the production curve rises, the sooner and sharper will be the decline." ..."
"... In fact, Ghawar is not as resilient as we were led to believe. We just found out that its output has fallen substantially since Aramco previously came clean on its reserves and production. If Ghawar is losing momentum fast, peak oil – remember that theory? – might be closer than we had thought. And Ghawar is just one of dozens of enormous conventional-oil reservoirs scattered around the planet that are in various stages of decline. ..."
"... Those include the North Sea, Alaska's Prudhoe Bay, and Reguly reminds us that Mexico's Cantarell reservoir used to supply 2.1 million barrels a day and is now down to 135,000. ..."
It seems that the biggest Saudi field is losing its punch.
Years ago we used to talk a lot about peak oil, the prediction made by M. King Hubbert that
the easy oil was going to run out, that it was going to get harder and harder to find the
stuff, and it was going to get more and more expensive to get out of the ground.
Hubbert
wrote in 1948: "How soon the decline may set in is not possible to say, Nevertheless the
higher the peak to which the production curve rises, the sooner and sharper will be the
decline."
According to the predictions made back in 2005, right about now the Saudis are running
out and we are smack in the middle of confusion, heading for chaos. Of course we are not, we
are flooded with fossil fuels, thanks to the fracking boom.
But according to Eric Reguly, writing in the Globe and Mail, there is trouble ahead,
because that prediction about Saudi oil may not be that far off. He writes that the giant
Ghawar field used to produce ten percent of the world's oil, five million barrels a
day.
The US Permian shale basin now supplies 4.1 million barrels a day, but fracked wells
run out pretty quickly, and the fracking companies are all losing money. Better sell that
pickup truck; it may well cost a lot more to fill it. As Reguly concludes, the Ghawar field
is indeed in trouble,"and if it does collapse, peak oil will come a bit sooner."
In fact, Ghawar is not as resilient as we were led to believe. We just found out that its
output has fallen substantially since Aramco previously came clean on its reserves and
production. If Ghawar is losing momentum fast, peak oil – remember that theory? –
might be closer than we had thought. And Ghawar is just one of dozens of enormous
conventional-oil reservoirs scattered around the planet that are in various stages of
decline.
Those include the North Sea, Alaska's Prudhoe Bay, and Reguly reminds us that Mexico's
Cantarell reservoir used to supply 2.1 million barrels a day and is now down to
135,000.
If you listen to the interview he has lined up the 7 month lag time with Rig Count and
Lagged Production. If this ends up sticking then the production flattening should show up in
July. Just wanted to hear what you guys have to say about it.
Thanks! Karen
Seems US oil production from shale now are declining, seems the growth based on lended money
now will stop.
https://oilprice.com/Energy/Crude-Oil/US-Oil-Production-Dips-For-First-Time-In-Nearly-Six-Months.html From the Rig Count we know this decrease will be strengthening the comming months until
the oil price increase to a level profit will be possible that can pay dividend and growth.
This might take time as soon Trump will tweet again as oil is to expensive and OPEC will be
forced to take action.
I'm sure that so long as the world wide economy remains on its feet that there will be huge
increases in demand for oil for transportation.
But nobody seems to give any thought here to things that will reduce demand. Cars will be
driving themselves soon. Think about trains. Before too much longer, railroaders will be able
to move stuff on trains almost as nimbly as truckers do today, at least on city to city basis
when the cities are at least a couple of hundred miles apart. Long distance trucking may be a
thing of the past within, like camera film and typewriters, within a couple of decades. These
possibilities are worthy of thought if you are in the oil biz for the long haul.
Every country that imports oil is going to have a powerful incentive to reduce demand for
it to the extent it can as depletion sooner or later pushes one exporting country after
another into the importer category. Countries in the Middle East with oil and gas to export
are going to find it so profitable to build wind and solar farms that they will be building
them like mushrooms popping up after a spring rain, because they can sell some or maybe even
most of the oil and gas they are burning now to generate electricity, thereby earning a big
profit on their solar and wind farm investment.
My thinking is that these changes will actually PROLONG our dependence on oil, taken all
around, by helping hold the price down so we can afford to run existing legacy equipment, and
have affordable petrol based chemicals, etc. I don't think anybody currently in the biz needs
to worry about selling out anytime soon, lol. But considerations such as these may have a
huge impact on exploration and development starting within a decade or so.
Times change. Doom doesn't necessarily have anything to do with it.
They lost control of Saudi Arabia, after trying to take down MBS and then betraying him by unexpectedly allowing waivers on
Iranian oil in November.
The U.S. cannot take down Iran without Venezuelan oil. What is worse, right now they don't have access to enough heavy oil
to meet their own needs.
Controlling the world oil trade is central to Trump's strategy for the U.S. to continue its empire. Without Venezuelan oil,
the U.S. is a bit player in the energy markets, and will remain so.
Having Russia block the U.S. in Venezuela adds insult to injury. After Crimea and Syria, now Venezuela, Russia exposes the
U.S. as a loud mouthed-bully without the capacity to back up its threats, a 'toothless tiger', an 'emperor without clothes'.
If the U.S. cannot dislodge Russia from Venezuela, its days as 'global hegemon' are finished. For this reason the U.S. will
continue escalating the situation with ever-riskier actions, until it succeeds or breaks.
In the same manor, if Russia backs off, its resistance to the U.S. is finished. And the U.S. will eventually move to destroy
Russia, like it has been actively trying to do for the past 30 years. Russia cannot and will not back off.
Venezuela thus becomes the stage where the final act in the clash of empires plays out. Will the world become a multi-polar
world, in which the U.S. becomes a relatively isolated and insignificant pole? Or will the world become more fully dominated by
a brutal, erratic hegemon?
"The latest Brent rally has brought prices to our peak forecast of $67.5/bbl, three months
early," Goldman Sachs wrote in a note. The investment bank said that "resilient demand
growth" and supply outages could push prices up to $70 per barrel in the near future. It's a
perfect storm: "supply loses are exceeding our expectations, demand growth is beating low
consensus expectations with technicals supportive and net long positioning still depressed,"
the bank said.
The outages in Venezuela could swamp the rebound in supply from Libya, Goldman noted. But
the real surprise has been demand. At the end of 2018 and the start of this year, oil prices
hit a bottom and concerns about global economic stability dominated the narrative. But, for
now at least, demand has been solid. In January, demand grew by 1.55 million barrels per day
(mb/d) year-on-year. "Gasoline in particular is surprising to the upside, helped by low
prices, confirming our view that the weakness in cracks at the turn of the year was supply
driven," Goldman noted. "This comforts us in our above consensus 1.45 mb/d [year-on-year]
demand growth forecast."
If so, economics will suffer and chances for Trump for re-election are much lower, of exist at all due to all his betrayals
In the fable of "The Boy Who Cried Wolf," the wolf actually arrives at the end. Never forget that. Peak oil will arrive. We don't
know when, and we are not prepared for it.
Shale play without more borrowed money might be the next Venezuela. .
I am now of the opinion that 2018 will be the peak in crude oil production, not 2019 as I earlier predicted. Russia is slowing down
and may have peaked. Canada is slowing down and Brazil is slowing down. OPEC likely peaked in 2016. It is all up to the USA. Can
shale oil save us from peak oil?
OPEC + Russia + Canada, about 57% of world oil production.
"I am now of the opinion that 2018 will be the peak in crude oil production, not 2019 as I earlier predicted. Russia
is slowing down and may have peaked. Canada is slowing down and Brazil is slowing down. OPEC likely peaked in 2016. It is all
up to the USA. Can shale oil save us from peak oil?"
IEA´s Oil 2019 5y forecast has global conventional oil on a plateau, i.e. declines and growth match each other perfectly
and net growth will come from LTO, NGL, biofuels and a small amount of other unconventional and "process gains".
Iran is ofc a jocker, since it can quickly add supply. Will be interesting to see how Trump will proceed.
I am quite original in my opinion about Peak Oil. I think it took place in late 2015. I will explain. If we define Peak Oil as
the maximum in production over a certain period of time we will not know it has taken place for a long time, until we lose the
hope of going above. That is not practical, as it might take years.
I prefer to define Peak Oil as the point in time when vigorous growth in oil production ended and we entered an undulating
plateau when periods of slow growth and slow decline will alternate, affected by oil price and variable demand by economy until
we reach terminal decline in production permanently abandoning the plateau towards lower oil production.
The 12-year rate of growth in C+C production took a big hit in late 2015 and has not recovered. The increase in 2 Mb since
is just an anemic 2.5% over 3 years or 0.8% per year, and it keeps going down. This is plateau behavior since there was no economic
crisis to blame. It will become negative when the economy sours.
Peak Oil has already arrived. We are not recognizing it because production still increases a little bit, but we are in Peak
Oil mode. Oil production will decrease a lot more easily that it will increase over the next decade. The economy is going to be
a real bitch.
Interesting thesis, keep in mind that the price of oil was relatively low from 2015 to 2018 because for much of the period
there was an excess of oil stocks built up over the 2013 to 2015 period when output growth outpaced demand growth due to very
high oil prices. Supply has been adequate to keep oil prices relatively low through March 2019 and US sanctions on Iran, political
instability in Libya and Venezuela, and action by OPEC and several non-OPEC nations to restrict supply have resulted in slower
growth in oil output.
Eventually World Petroleum stocks will fall to a level that will drive oil prices higher, there is very poor visibility for
World Petroleum Stocks, so there may be a 6 to 12 month lag between petroleum stocks falling to critically low levels and market
realization of that fact, by Sept to Dec 2019 this may be apparent and oil prices may spike (perhaps to $90/b by May 2020).
At that point we may start to see some higher investment levels with higher output coming 12 to 60 months later (some projects
such as deep water and Arctic projects take a lot of time to become operational, there may be some OPEC projects that might be
developed as well, there are also Canadian Oil sands projects that might be developed in a high oil price environment.
I define the peak as the highest 12 month centered average World C+C output, but it can be define many different ways.
Our capability to store oil is very limited considering the volume being moved at any time from production to consumption.
I understand that it is the marginal price of the last barrel of oil that sets the price for oil, but given the relatively inexpensive
oil between 2015 and now, and the fact that we have not been in an economical crisis, what is according to you the cause that
world oil production has grown so anemically these past three years?
Do you think that if oil had been at 20$/b as it used to be for decades the growth in consumption/production would have been
significantly higher?
I'll give you a hint, with real negative interest rates and comparatively inexpensive oil most OECD economies are unable to
grow robustly.
To me Peak Oil is an economical question, not a geological one. The geology just sets the cost of production (not the price)
too high, making the operation uneconomical. It is the economy that becomes unable to pump more oil. That's why the beginning
of Peak Oil can be placed at late 2015.
The economic system has three legs, cheap energy, demographic growth, and debt growth. All three are failing simultaneously
so we are facing the perfect storm. Social unrest is the most likely consequence almost everywhere.
If prices are low that means there is plenty of oil supply relative to demand. It also means that some oil cannot be produced
profitably, so oil companies invest less and oil output grows more slowly.
So you seem to have the story backwards. Low oil prices means low growth in supply.
So if oil prices were $20/b, oil supply would grow more slowly, we have had an oversupply of oil that ls what led to low oil
prices. When oil prices increase, supply growth will ne higher. Evause profits will be higher and there will be more investment.
It is you who has it backwards, as you only see the issue from an oil price point of view, and oil price responds to supply
and demand, and higher prices are an estimulus to higher production.
But there is a more important point of view, because oil is one of the main inputs of the economy. If the price of oil is sufficiently
low it stimulates the economy. New businesses are created, more people go farther on vacation, and so on, increasing oil demand
and oil production. If the price is sufficiently high it depresses the economy. A higher percentage of wealth is transferred from
consumer countries to producing countries and consumer countries require more debt. During the 2010-2014 period high oil prices
were sustained by the phenomenal push of the Chinese economy, while European and Japanese economies suffered enormously and their
oil consumption depressed and hasn't fully recovered since.
In the long term it is the economy that pumps the oil, and that is what you cannot understand.
The economy decides when and how Peak Oil takes place. If you knew that you wouldn't bother with all those models.
And in my opinion the economy already decided in late 2015 when the drive to increase oil production to compensate for low
oil prices couldn't be sustained.
Both supply and demand matter. I understand economics quite well thank you. You are correct that the economy is very important,
it will determine oil prices to some degree especially on the demand side of the market. If one looks at the price of oil and
economic growth or GDP, there is very little correlation.
The fact is the World economy grew quite nicely from 2011 to 2014 when oil prices averaged over $100/b.
There may be some point that high oil prices are a problem, apparently $100/b in 2014 US$ is below that price. Perhaps at $150/b
your argument would be correct. Why would the economy need more oil when oil prices are low? The low price is a signal that there
is too much oil being produced relative to the demand for oil.
I agree the economy will be a major factor in when peak oil occurs, but as most economists understand quite well, it is both
supply and demand that will determine market prices for oil.
My models are based on the predictions of the geophysicists at the USGS (estimating TRR for tight oil) and the economists at
the EIA (who attempt to predict future oil prices). Both predictions are used as inputs to the model along with past completion
rates and well productivity and assumptions about potential future completion rates and future well productivity, bounded by the
predictions of both the USGS and the EIA along with economic assumptions about well cost, royalties and taxes, transport costs,
discount rate, and lease operating expenses.
Note that my results for economically recoverable resources are in line with the USGS TRR mean estimates and are somewhat lower
when the economic assumptions are applied (ERR/TRR is roughly 0.85), the EIA AEO has economically recoverable tight oil resources
at about 115% of the USGS mean TRR estimate. The main EIA estimate I use is their AEO reference oil price case (which may be too
low with oil prices gradually rising to $110/b (2017$) by 2050.
Assumptions for Permian Basin are royalties and taxes 33% of wellhead revenue, transport cost $5/b, LOE=$2.3/b plus $15000/month,
annual discount rate is 10%/year and well cost is $10 million, annual interest rate is 7.4%/year, annual inflation rate assumed
to be 2.5%/year, income tax and revenue from natural gas and NGL are ignored all dollar costs in constant 2017 US$.
You do incredible work Dennis and I believe you are correct. Demand for oil is relatively inelastic which accounts for huge price
swings when inventories get uncomfortably high or low. If supply doesn't keep up with our needs, price will rise to levels that
will eventually create more supply and create switching into other energy sources which will reduce demand.
Why would the economy need more oil when oil prices are low? The low price is a signal that there is too much oil being
produced relative to the demand for oil.
You don't seem to be aware of historical oil prices. For inflation adjusted oil prices since 1946 oil (WTI) spent:
27 years below $30
13 years at ~ $70
18 years at ~ $40
10 years at ~ $90
5 years at ~ $50 https://www.macrotrends.net/1369/crude-oil-price-history-chart
And the fastest growth in oil production took place precisely at the periods when oil was cheapest.
You simply cannot be more wrong about that.
And your models are based on a very big assumption, that the geology of the reserves is determinant for Peak Oil. It is not.
There is plenty of oil in the world, but the extraction of most of it is unaffordable. The economy will decide (has decided) when
Oil Peak takes place and what happens afterwards. Predictions/projections aren't worth a cent as usual. You could save yourself
the trouble.
I use both geophysics and economics, it is not one or the other it is both of these that will determine peak oil.
Of course oil prices have increased, the cheapest oil gets produced first and oil gradually gets more expensive as the marginal
barrel produced to meet demand at the margin is more costly to produce.
Real Oil Prices do not correlate well with real economic growth and on a microeconomic level the price of oil will affect profits
and willingness of oil companies to invest which in turn will affect future output. Demand will be a function of both economic
output and efficiency improvements in the use of oil.
Also keep in mind that during the 1945-1975 period economic growth rates were very high as population growth rates were very
high and the World economy was expanding rapidly as population grew and the World rebuilt in the aftermath of World War 2. Oil
was indeed plentiful and cheap over this period and output grew rapidly to meet expanding World demand for oil. The cheapness
of the oil led to relatively inefficient use of the resource, as constraints in output became evident and more expensive offshore,
Arctic oil were extracted oil prices increased and there was high volatility due to Wars in the Middle east and other political
developments. Oil output (C+C) since 1982 has grown fairly steadily at about an 800 kb/d annual average each year, oil prices
move up and down in response to anticipated oil stock movements and are volatile because these estimates are often incorrect (the
World petroleum stock numbers are far from transparent.)
On average since the Iran/Iraq crash in output (1982-2017) World output has grown by about 1.2% per year and 800 kb/d per year
on average, prices have risen or fallen when there was inadequate or excess stocks of petroleum, this pattern (prices adjusting
to stock levels) is likely to continue.
There has been little change when we compare 1982 to 1999 to 1999-2017 (divide overall period of interest in half) for either
percentage increase of absolute increase in output.
I would agree that severe shortages of oil supply relative to demand (likely apparent by 2030) is likely to lead to an economic
crisis as oil prices rise to levels that the World economy cannot adjust to (my guess is that this level will be $165/b in 2018$).
Potentially high oil prices might lead to faster adoption of alternative modes of transport that might avert a crisis, but that
is too optimistic a scenario even for me.
China will be in outright deflation soon enough. Economic stimulus is starting to fail in China. They can't fill the so called
bathtub up fast enough to keep pace with the water draining out the bottom. So to speak.
Interest rates in China will soon be exactly where they are in Europe and Japan. Maybe lower.
In order to get oil to $90-$100 the value of the dollar is going to have to sink a little bit. In order to get oil to $140-$160
the dollar has to make a new all time low. Anybody predicting prices shooting up to $200 needs the dollar index to sink to 60
or below.
The reality is oil is going to $20. Because the rest of the world outside the US is failing. Dennis makes some nice graphs
and charts and under his assumptions his charts and graphs are correct. But his assumptions aren't correct.
We got $20 oil and an economic depression coming.
Peak Oil is going to be deflationary as hell. Higher prices aren't in the cards even when a shortage actually shows up. We
will get less supply at a lower price. Demand destruction is actually going to happen when economies and debt bubbles implode
so we actually can't be totally sure we are ever going to see an actual shortage.
We could very well be producing 20-30% less oil than we do now and still not have a shortage.
Oh and EV's are going to have to compete with $20 oil not $150 oil.
When do you expect the oil price to reach $20/b? We will have to see when this occurs.
It may come true when EVs and AVs have decimated demand for oil in 2050, but not before. EIA's oil price reference scenario
from AEO 2019 below. That is a far more realistic prediction (though likely too low especially when peak oil arrives in 2025),
oil prices from $100 to $160/b in 2018 US$ are more likely from 2023 to 2035 (for three year centered average Brent oil price).
My assumptions are based on USGS mean resource estimates and EIA oil price estimates, as well as BIS estimates for the World
monetary and financial system.
Your assumption that oil prices are determined by exchange rates only is not borne out by historical evidence. Exchange
rates are a minor, not a major determinant of oil prices.
Technically speaking. The most relevant trendline on price chart currently comes off the lows of 2016/02/08. It intersects
with 2017/06/19. You draw the trendline on out to where price is currently. Currently price is trying to backtest that trendline.
On a weekly price chart i'd say it touches the underside of that trendline sometime in April in the low 60's somewhere between
$62-$66 kinda depends on when it arrives there time wise. The later it takes to arrive there the higher price will be. I've been
trading well over 20 years can't tell you how many times i've seen price backtest a trendline after it's been broken. It's a very
common occurrence. And i wouldn't short oil until after it does.
But back to your question. $20 oil what kind of timetable. My best guess is 2021-2022. Might happen 2020 or 2023. And FED can
always step in and weaken the dollar. Fundamentally the only way oil doesn't sink to $20 is the FED finds a way to weaken the
dollar.
But understand the FED is the only major CB that currently doesn't have the need to open up monetary policy. It's really the
rest of the worlds CB ultra loose monetary policy which is going to drive oil to $20.
Countries that have reported their January production (shown on the chart)
OPEC14 -822
Alberta -268
Mexico -87
Russian Federation -78
Brazil -60
Norway -48
Total -1,429 kb/day
Chart https://pbs.twimg.com/media/D12BlLBW0AEDR6G.png
So far for February: Russia, OPEC14, Norway
Total: -330 kb/day
The Organization of Petroleum Exporting Countries will once again become a nemesis for U.S.
shale if the U.S. Congress passes a bill dubbed NOPEC, or No Oil Producing and Exporting
Cartels Act, Bloomberg
reported this week , citing sources present at a meeting between a senior OPEC official and
U.S. bankers.
The oil minister of the UAE, Suhail al-Mazrouei, reportedly told lenders at the meeting that
if the bill was made into law that made OPEC members liable to U.S. anti-cartel legislation,
the group, which is to all intents and purposes indeed a cartel, would break up and every
member would boost production to its maximum.
This would be a repeat of what happened in 2013 and 2014, and ultimately led to another oil
price crash like the one that saw Brent crude and WTI sink below US$30 a barrel. As a result, a
lot of U.S. shale-focused, debt-dependent producers would go under.
Bankers who provide the debt financing that shale producers need are the natural target for
opponents of the NOPEC bill. Banks got burned during the 2014 crisis and are still recovering
and regaining their trust in the industry. Purse strings are being loosened as WTI climbs
closer to US$60 a barrel, but lenders are certainly aware that this is to a large extent the
result of OPEC action: the cartel is cutting production again and the effect on prices is
becoming increasingly visible.
Indeed, if OPEC starts pumping again at maximum capacity, even without Iran and Venezuela,
and with continued outages in Libya, it would pressure prices significantly, especially if
Russia joins in. After all, its state oil companies have been itching to start pumping
more.
The NOPEC legislation has little chance of becoming a law. It is not the first attempt by
U.S. legislators to make OPEC liable for its cartel behavior, and none of the others made it to
a law. However, Al-Mazrouei's not too subtle threat highlights the weakest point of U.S. shale:
the industry's dependence on borrowed money.
The issue was analyzed in depth by energy expert Philip Verleger in an Oilprice
story earlier this month and what the problem boils down to is too much debt. Shale, as
Total's chief executive put it in a 2018 interview with Bloomberg, is very capital-intensive.
The returns can be appealing if you're drilling and fracking in a sweet spot in the shale
patch. They can also be improved by making everything more efficient but ultimately you'd need
quite a lot of cash to continue drilling and fracking, despite all the praise about the decline
in production costs across shale plays.
The fact that a lot of this cash could come only from banks has been highlighted before: the
shale oil and gas industry faced a crisis of investor confidence after the 2014 crash because
the only way it knew how to do business was to pump ever-increasing amounts of oil and gas.
Shareholder returns were not top of the agenda. This had to change after the crash and most of
the smaller players -- those that survived -- have yet to fully recover. Free cash remains a
luxury.
The industry is aware of this vulnerability. The American Petroleum Institute has vocally
opposed NOPEC, almost as vocally as OPEC itself, and BP's Bob Dudley said this week at CERAWeek
in Houston that NOPEC "could have severe unintended consequences if it unleashed litigation
around the world."
"Severe unintended consequences" is not a phrase bankers like to hear. Chances are they will
join in the opposition to the legislation to keep shale's wheels turning. The industry,
meanwhile, might want to consider ways to reduce its reliance on borrowed money, perhaps by
capping production at some point before it becomes forced to do it.
1. When something is increasing 0.8% a year based on data with, say, 2% or higher margin of error this is not a growth.
This is a number racket.
2. We need to use proper coefficients to correctly estimate energy output of different types of oil We do not know real
EROEI of shale oil, but some sources claim that it is in the 1.5-4.5 range. Let's assume that it is 3. In comparison, Saudi oil
has 80-100 range. In this sense shale oil is not a part of the solution; it is a part of the problem (stream of just bonds produced
in parallel is the testament of that). In other words, all shale oil is "subprime oil," and an increase of shale oil production
is correctly called the oil retirement party. The same is true for the tar sands oil.
So the proper formula for total world production in "normalized by ERORI units" might be approximated by the equation:
where coefficients (I do not claim that they are accurate; they are provided just for demonstration) reflect EROEI of particular
types of oil.
If we assume that 58% of the US oil production is shale oil and condensate then the amount of "normalized" oil extracted in
the USA can be approximated by the formula
total * 0.83
In other words 17% of the volume is a fiction. Simplifying it was spent on extraction of shale oil and condensate (for concentrate
lower energy content might justify lower coefficient; but for simplicity we assume that it is equal to shale oil).
Among other things that means that 1970 peak of production probably was never exceeded.
3. EROEI of most types of oil continues to decline (from 35 in 1999 to 18 in 2006 according to
http://www.euanmearns.com/wp-content/uploads/2016/05/eroeihalletal.png).
Which means that in reality physical volume became a very deceptive metric as you need to sink more and more money/energy into
producing every single barrel and that fact is not reflected in the volume. In other words, the barrel of shale oil is already
50% empty when it was lifted to the ground (aka "subprime oil"). In this sense, shale wells with their three years of the high
producing period are simply money dumping grounds for money in comparison with Saudi oil wells.
4. The higher price does not solve the problem of the decline of EROEI. It just allows the allocation of a larger portion
of national wealth to the oil extraction putting the rest of the economy into permanent stagnation.
5. If we assume average EROEI equal 3 (or even 5) for shale oil then rising shale oil production along with almost constant
world oil production is clearly a Pyrrhic victory. Again, putting a single curve for all types of oil is the number racket,
or voodoo dances around the fire.
NOTES:
1. IMHO Ron made a correct observation about Saudi behavior: the declines of production can well be masked under pretention
of meeting the quota to save face. That might be true about OPEC and Russia as a whole too. Exceptions like Iraq only confirm
the rule.
Dennis Wrote:
"I think the 4 Mb/d of increased tight oil output from Dec 2019 to Dec 2025 may be enough to
keep World C+C output increasing through 2025, this assumes oil prices follow the AEO 2018
reference case "
I am sure there is sufficient Oil in the ground to delay Peak production to about 2040, if
the consumer demand can afford $300 bbl. Shale drilling is a lot like the housing bubble that
began in 2003 and when bust in 2008. It made no sense to lend people with no job, no income
and no assets, money to buy a home, but Lenders did it anyway and they did it for 5 years
straight. While Shale Drillers aren't Ninja home buyers they continue to fund operations
using debt.
Shale growth is a function of credit available to shale drillers. As long as they can
find a sucker^H^H^H^H lender to finance their growth, it will continue.
My wild-ass guess is that credit growth for shale drillers ends in 2021, because a lot
of old shale debt comes due between 2020 and 2022.
My guess is that the shale drillers will have trouble rolling over the existing debt
will also finding lenders to provide them more credit. In the past I presumed that interest
rates would rise to the point it cut them off from adding new debt. but the ECB & the Fed
continue to keep rates low. Perhaps the Shale drillers will get direct gov't funding to
continue, pseudo nationalization as Watcher has proposed over many years on POB.
I don't see much traction in significantly higher oil prices. with 78% of US consumers
living paycheck to paycheck, already, I don't believe they can absorb any substantial
increase in energy costs.
Its also very likely demographics will start impacting energy consumption in the west
as Boomers start retiring. A lot of boomers have postponed retirement, but I suspect that
this will start to change in the early 2020s as age related issues make it more difficult for
them to keep on working. Usually retired workers, consume considerably less energy as they no
longer commute to work, and usually downsize their lifestyles.
(Global) peak oil comes in phases. The 1st phase 2005-2008 caused the 2008 oil price shock
and the financial crisis. Money printing was used to keep the system afloat and finance the
US shale oil boom. The resulting high debt levels are now limiting economic activities. A lot
of the problems we see in the world come from this chain of events.
I warned the Australian Prime Minister John Howard in 2004/05 but he did not want to
listen.
As Art Berman said, shale oil is oil's retirement party.
When we are down to fracturing rocks and drilling tens of thousands of horizontal wells
that produce tiny streams of oil that decline by 70% in just three years we should
instinctively know that we are reaching the bottom of the proverbial barrel, literally.
Amazing how most people think just the opposite .
There is an interesting article in the Journal Of Petroleum Technology which summarizes an
SPE article by Schlumberger.
"Yet another SPE paper has concluded that old wells outperform new ones, but this study
offers a lot more detail about development in the Permian.
The paper, authored by Schlumberger (SPE 194310), offers comparisons of five major plays
in the Midland and Delaware basins, including details down to the pounds of proppant pumped
per foot, that show that completions are becoming increasingly similar.
"In general, normalized production from child wells is lower than parent wells," said Wei
Zheng, production stimulation engineer for Schlumberger. Older wells outperform newer ones
even when adjusting for the fact that new horizontal wells extend further through the
reservoir and more proppant is pumped.
"We are getting the same result as 5 years ago when we were spending less," she said
during a presentation at the recent SPE Hydraulic Fracturing Technology Conference."
Figure 2 which adjusts production for lateral length and proppant is particularly
interesting.
It describes especially most comapanies going to a more wide well spacing – so total
recovery of the basin will fall, but drilled wells will be more profitable.
US shale companies' decision to drill thousands of new wells closely together - and close to
already existing wells - is
turning out to be a bust
; worse, this approach is
hurting the performance
of wells
already in existence, posing an even greater threat to the already struggling industry. In order to
keep the United States as an energy supplying powerhouse, shale companies have pitched bunching
wells in close proximity, hoping they would produce as much as older ones, allowing companies to
extract more oil overall while maintaining good results from each well.
These types of predictions helped fuel investor interest in shale companies, who raised nearly $57
billion from equity and debt financing in 2016 – up from $34 billion five years earlier, when oil
was over $110 per barrel.
In 2016, oil prices dipped below $30 a barrel at one point.
And now -
surprise
– the actual results from these wells are finally coming in and they
are quite disappointing.
Newer wells that have been set up near older wells were found to pump less oil and gas,
and
engineers warn that these new wells could produce as much as 50% less in some circumstances.
This is not what investors - who contributed to the billions in capital used by these companies
back in 2016 - want to hear.
Making matters worse, newer wells often interfere with the output of older wells because creating
too many holes in dense rock formations can damage nearby wells and make it harder for oil to seep
out. The "child" wells could also cause permanent damage to older "parent" wells. This is known in
the industry as the "parent-child" well problem. Billionaire Harold Hamm, who founded shale
driller Continental Resources, said last year: "
Shale producers across the country are finding
you can get a lot of interference, one well to the other. Laying out a whole lot of wells can get
you in trouble."
Some of the biggest names in shale, including Devon Energy, EOG Resources and Concho
Resources, have already disclosed that they are suffering from this problem. As a result, they and
many others could be forced to take massive write-downs if they have to downsize their already
optimistic estimates from drill sites.
Companies continue to try and find the perfect balance between using single wells that are
operating at peak productivity and multiple wells that can provide better returns.
Laredo Petroleum is a great example. Two years ago, it was valued at more than $3 billion and
was a strong advocate for packing wells into the Permian Basin. Its CEO Randy Foutch said a year
ago that the company could drill 32 wells per drilling unit, with each producing an average of 1.3
million barrels of oil and gas. In November, the company announced that wells it had fracked in
2018 were producing 11% less than projected, in part due to "parent-child" issues.
Laredo spokesman Ron Hagood told the WSJ: "We tightened spacing during 2017 and 2018 to increase
location inventory and resource recovery in our highest-return formations, and we achieved this
goal."
The company's market value has fallen about 75% to $800 million since the end of 2016.
Goal achieved?
Incidentally, we first
reported
that shale companies may be facing "catastrophic failure ahead" back in October of 2018. Days
before that report, we
said that
shale companies had a "glaring problem". We concluded that the glaring problem with 2018's poor
financial results was that 2018 was supposed to be the year that the shale industry finally turned
a corner.
Earlier in 2018, the International Energy Agency had painted a rosy portrait of U.S. shale,
arguing
in
a report that "higher prices and operational improvements are putting the US shale sector on track
to achieve positive free cash flow in 2018 for the first time ever."
Now, it all appearst to have been a "pipe" - or rather "milkshake" - dream.
In its January Short-Term Energy Outlook (STEO), the EIA
said last week that continuously rising U.S. shale production
would make the United States a
net exporter
of crude oil and petroleum products in the fourth
quarter of 2020.
This whole shale oil boom started back when Baby Bush was
president, and Hugo Chavez announced to the world (at the UN)
that W "smelled of sulfur". To add insult to injury, Hugo sent
aid, in the form of fuel oil and a hospital ship, to help the
victims of Hurricane Katrina, while W was busy eating cake and
clearing brush with Jeff Gannon.
From that moment on, W had it
in for Hugo. Venezuela was doing very well at the time. Besides
sanctions, Bush figured that the best way to attack Hugo and
Venezuela was to crash the price of crude. So suddenly there were
financial incentives and lax regulations in the US regarding
Fracking, and the Shale Oil Boom in America was born! Bush didn't
care that it was costing Americans - both financially and by
ruining the quality of the ground water - the lifeblood of
agriculture. This oil borne of vengence went to market at way
below cost of production, but it succeeded in driving the price of
crude to the point of financial pain for Venezuela.
After all that, Hugo survived several assassination attempts,
only to die suddenly and mysteriously from - depending on the
source - either a heart attack or stroke.
Shale oil had a negative EROEI from the start, it just took
this long for that to be realized.
I'll bet they are understating the loan problem. I think this
industry has real problems along with the banks that financed
them. Someone, somewhere has some data on this issue but I've only
seen it alluded too. With the cost of oil down and these wells
starting to underproduce, I'll bet there is some real risk to
solvency for some banks we are not hearing about.
These articles against shale are so biased. I work in the Delaware
Basin and have intimate knowledge of the financials. The shale BS
spewed on zerohedge only looks at the negative side of things. The
article above is correct about the problem of well spacing, but I
could write 5 positive articles about upward revisions of expected
well productivity those same companies have had as they refined
their frac techniques and got better at drilling laterals.
Zerohedge only reports the negative revisions, not the numerous
positive revisions. These companies are now going on a decade of
growth and their financials are actually improving.
The shale
business is fundamentally sound if you have the right acreage and
don't overpay to get acreage. The naysayers are correct in
that production decline in unconventionals requires ever
increasing investment so as long as the company is trying to grow
they will have negative cash flow and expanding debt loads to
fight the decline curves of unconventionals. (The rig count you
need to just to counteract natural decline keeps growing as you
grow.) But it also doesn't mean jack **** for the profitability of
each well. Unless you are a poorly run shale company like Encana,
BHP, or BP, you would instantly be massively cash flow positive
and easily pay off all your debt if you stopped drilling. In
Delaware Basin, companies like EOG are hitting 40% ROCE (Return on
Capital Employed) and the basin average is probably 20%. Those are
good numbers.
I explain it in my post. Don't confuse profits with cash
flow and debt. The individual projects are profitable and so
are the companies, but to keep growing and fight the decline
they capital budget has to grow in unconventionals. The
shareholders in the company push for more growth, to deliver
that growth they have to first make up the natural decline
plus add to the baseline. As your baseline grows the first
part of the equation, fighting the natural decline, grows
along with you. To show cash flow positive results and
reduce debt, all the companies have to do is keep rig and
frac crew counts constant, and about a year later they will
all show positive cash flow and reductions in debt. However,
by in large most companies are choosing to increase rig and
frac crew counts year over year and thus the cash flow
remains negative and debt grows because the companies
themselves are growing. What the naysayers are doing is just
looking at the liabilities on the balance sheet, while
ignoring the asset growth.
The naysayers are not wrong
about the balance sheets, they are just not talking about
the full picture. Eventually these predictions will be right
as viable acreage runs out and companies start throwing good
money at bad projects just to show production growth, but
that isn't happening yet except for at the weakest players.
And that truth is the same even for conventional fields.
Unconventionals just shorten the lifecycle, but it doesn't
change the fact that the oil business has always been one
where you produce yourselves out of business, and to remain
viability you constantly have to be exploring for new
opportunies. 150 years and still going and people still
write articles without understanding.
Show me a single shale play with an EROEI above 5:1 and
we'll talk.
EDIT: full disclosure: I'm invested in shale, and have
made good money from it. But long-term I still think it's
a loser. Net energy gain is too low to be viable.
These articles have been predicting the demise of US shale
since 2010. As in any industry especially one as
technologically driven as US shale you have good and bad
results across the space, yet the space as a whole will
continue to grow and good operators will thrive.
Shale is end game stuff. At the end of the day the average
jobless consumer can't afford to run a vehicle on 100$+ per
barrel shale. And producers can't really stay in business at
current prices. The funding is mostly zero cost debt provided
to keep the dream alive for a few more years.
I've been in shale for quite awhile, and have made good money.
It's a good investment if you're careful, but it's also a low
EROEI product that the numbers have never really made sense on.
The companies producing it are leveraged to the gills, and if
interest rates were to pop and make it more expensive to roll over
their debt it'd explode like a ******* bomb. On my more tinfoilly
days I wonder if the whole purpose of the '08 financial crisis
(which was deliberately engineered; that much I am sure of) was to
give them excuse to drop the interest rates enough to make shale
viable. Get a hard look at the financials of any company producing
shale... you'll see some serious weirdness in their cash flow.
This was the case even when crude prices were parked around $100.
Hard cold fact: net energy gain on this stuff is positive, but
not by very goddamn much. Left strictly to market forces, it would
not be economically viable at all. Ultimately I think what we're
going to see is some kind of a nationalization of oil supplies as
a security measure; there's plenty of stuff out there that is net
energy positive but still not profitable to extract. But so long
as it takes marginally less energy to get it out than you produce,
it'll be propped up. Once net energy goes negative (and it will;
we always take the low-hanging fruit first) then it's game over.
Mankind build industrial society on 30+ to 1 oil. Shale is
scraping the bottom of the barrel.. tar sands the same. They
take fresh water and natural gas to cook the oil out of the
sand for christ sake.. that's late end game stuff right there.
The late Matthew Simmons called the advanced extraction
thechniques like water injection etc used on legacy oil
fields
"super-straws" sucking the last oil faster and
in no way expanding the total recoverable oil from the
field. We can expect much steeper decline curves because
of it when reservoir pressures are finally depleted.
Cold cold fact:
net energy gain on this stuff is
positive, but not by very goddamn much.
Left strictly to
market forces, it would not be economically viable at all.
Ultimately I think what we're going to see is some kind
of a nationalization of oil supplies as a security measure;
there's plenty of stuff out there that is net energy
positive but still not profitable to extract.
But so long
as it takes marginally less energy to get it out than you
produce, it'll be propped up
. Once net energy goes
negative (and it will; we always take the low-hanging fruit
first)
then it's game over.
Great balanced comment.
I see shale as essentially
thermodynamic
autocannibalism
from the point of view that at an EROEI
of 1.5-3 to 1, it can power it's extraction and refinement and
(sometimes) transport, but not anything else. It cannot provide
the energy needed to run a mid-19th century economy let alone a
parasitic 21st century one. There is no fat to run our
civilization and this is largely a desperate delay mechanism.
The West has used up most it's net positive EROEI to the pump
oil and gas and now it needs to plunder other economies if it
isn't to go down in flames. It will implode after 2030 anyway
as the global EROEI inflects, but these are in denial moves to
delay the inevitable .
Again - great to see a non binary comment here on ZH on this
polarising topic.
Edit
Also your comments about the
probable nationalisation
of the industry
I believe is spot on - not only will it
occur organically as these companies declare huge
bankruptcies
and the policy makers opt for nationalization
(i.e. bail in by Joe taxpayer) rather than bail out. Note also
how such a nationalization will cohere to the increasingly
communist mentality of the political landscape - Big Gov
redistribution & equity outcomes inclinations will all feed
into the state owning and controlling te means of production.
AOC is a ******, but she is simply an expression of broader
psychological and financial vectors. It's coming and
you
can't vote your way out of it.
And yes it WILL be declared a national security issue and NO
MATTER WHAT THE PRICE TO THE REST OF THE ECONOMY while there is
any
net EROEI (net of extraction, refinement and
distribution) it wil continue.
there's plenty of stuff out there that is net energy
positive but still not profitable to extract.
Only caveat I would add is that
it will only be extracted
when "not profitable" only while global fiat parasitism can be
used to skim wealth from outside of the US
. Once the US $
ceases to be able to do this then
profit = net energy again,
and the negative-sum game will no longer be able to be
subsidised nor concealed. The remaining billions of theoretical
barrels if oil at that stage will remain in the ground, of no
utility to maintaining negative entropy civilization.
Before it ceases you will essentially see only the MIC and
'Strategic' government use of US oil and gas ny the early 2030s
and little to no use by the domestic economy at large. Once the
last slither of net calorific benefit is gone, thing go
entropic.
However if they manage to steal Venezuela or Iran, this
would change.
If we assume as 10 million per well total cost, then 200K barrel needs to be extracted to
break even. Assuming average life of the well of 5 years you need to produce on average 1000
barrel a day to break even. In the past that were possible (the average was 143), now it is
not
The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant
do the analysis and it was mostly based on investor presentations, very little geological
analysis.
It would be better if the USGS did an economic analysis as they do with coal for the
Powder River Basin. They could develop a supply curve based on current costs, but they
don't.
Do you have any idea of the capital cost of the wells (ballpark guess) for a horizontal
multifracked well in the Wolfcamp? Would $7 million be about right (a WAG by me)?
On ignoring economics, I show my oil price assumptions. Other financial assumptions for
the Bakken are $8 million for capital cost of the well (2016$). OPEX=$9/b, other costs=$5/b,
royalty and taxes=29% of gross revenue, $10/b transport cost, and a real discount rate of 7%
(10% nominal discount rate assuming 3% inflation).
I do a DCF based on my assumed real oil price curve. Brent oil price rises to $77/b
(2016$) by June 2017 and continue to rise at 17% per year until Oct 2020 when the oil price
reaches $130/b, it is assumed that average oil prices remain at that level until Dec 2060.
The last well is drilled in Dec 2035 and stops producing 25 years later in Dec 2060.
EUR of wells today is assumed to be 321 kb and EUR falls to 160 kb by 2035. The
last well drilled only makes $243,000 over the 7% real rate of return, so the 9 Gb scenario
is probably too optimistic, it is assumed that any gas sales are used to offset OPEX and
other costs, though no natural gas price assumptions have been made to simplify the
analysis.
This analysis is based on the analyses that Rune Likvern has done in the past, though his
analyses are far superior to my own.
I think when seismic, land, surface and down hole equipment is included, the number is much
higher. With $20-60K per acre being paid, land definitely has to be factored in. Depending on
spacing, $1-5 million per well?
I am doing the analysis for the Bakken. A lot of the leases are already held and I don't
know that those were the prices paid. Give me a number for total capital cost that makes sense,
are you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the
different assumptions you would like to change would be good so I don't redo it 5 times.
Mostly I would like to clear up "the number".
I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes,
real discount rate (adjusted for inflation), well cost.
I think you a re talking about well cost as "the number". I include down hole costs as part
of OPEX (think of it as OPEX plus maintenance maybe).
Dennis. The very high acreage numbers are for recent sales in the Permian Basin. In reading
company reports, it seems they state a cost to drill and case the hole, another to complete the
well, then add the two for well cost.
This does not include costs incurred prior to the well being drilled, which are not
insignificant. Nor does it include costs of down hole and surface equipment, which also are not
insignificant.
Land costs are all over the map, and I think Bakken land costs overall are the lowest,
because much of the leasing occurred prior to US shale production boom. I think a lot of
acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading
around since, so we have to look project by project, unfortunately. For purposes of a model, I
think $8 million is probably in the ballpark.
I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to
stick with, being US based). The companies do not do that, those costs are included in
depreciation, depletion and amortization expense.
Once the well is in production, and failures occur, I include the cost of repairs, including
replacement equipment, in LOE. I am not sure that the companies do that, however.
I think the Permian is going to be much tougher to estimate, as there are different
producing formations at different depths, whereas the Bakken primarily has two, and the Eagle
Ford has 1 or 2.
An example:
QEP paid roughly $60,000 per acre for land in Martin Co., TX. If we assume one drilling unit
is 1280 acres (two sections), how many two mile laterals will be drilled in the unit?
1280 acres x $60,000 = $76,800,000.
Assume 440′ spacing, 12 wells per unit.
$76,800,000/12 = $6,400,000 per well.
However, there are claims of up to 8 producing zones in the Permian.
So, 12 x 8 = 96 wells.
$76,800,000 / 96 = $800,000 per well.
Even assuming 96 wells, the cost per well is still significant.
If we assume 96 wells x $7 million to drill, complete and equip, total cost to develop is
$.75 BILLION. That is a lot of money for one 1280 acre unit, need to recover a lot of oil and
gas to get that to payout.
I am neither an oil man nor an accountant, so regardless of what we call it I am assuming
natural gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to
operate the well (LOE, OPEX, financial costs, etc), we could add another million to the cost of
the well for surface and downhole equipment and land costs.
Does an average operating cost over the life of a well of about $17/b ($14/b plus natural
gas sales of $3/b of oil produced)seem reasonable? That would be about $5.4 million spent on
LOE etc. over the life of the well (assuming 320 kbo produced). Also does the 10% nominal rate
of return sound high enough, what number would you use as a cutoff?
You use a different method than a DCF and want the well to pay out in 60 months. This would
correspond to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3%
annual inflation rate.)
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do
the analysis and it was mostly based on investor presentations, very little geological
analysis."
Exactly. USGS' estimate as of October 2015 is very conservative:
"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an
estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1
million barrels of natural gas liquids, according to the first USGS assessment of continuous
(unconventional), technically recoverable resources in the Monterey Formation."
"The volume estimated in the new study is small, compared to previous USGS estimates of
conventionally trapped recoverable oil in the Monterey Formation in the San Joaquin Basin.
Those earlier estimates were for oil that could come either from producing more Monterey oil
from existing fields, or from discovering new conventional resources in the Monterey
Formation."
Previous USGS estimates were for conventional oil:
"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin,
estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in
2012, USGS assessed the potential volume of oil that could be added to reserves in the San
Joaquin Basin from increasing recovery in existing fields. The results of that study suggested
that a mean of about 3 billion barrels of oil might eventually be added to reserves from
Monterey reservoirs in conventional traps, mostly from a type of rock in the Monterey called
diatomite, which has recently been producing over 20 million barrels of oil per year."
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp.
Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA
and awaiting re-drills; that should tell you something. With acreage, infrastructure and water
costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's
what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste
of time, sorry.
What most interests me are suggestions that there is so much available oil in Wolfcamp and what
that will do to oil prices and national policy.
Seems like any announcement of more oil will likely keep prices low. And if they stay low,
there's little reason to open up more areas for oil drilling.
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well
spacing, pick total acreage, pick a factor for dry holes – multiply a by c by d and
divide by b."
USGS estimates for average well EUR in Wolfcamp shale look reasonable: 167,ooo barrels in the
core areas and much lower in other parts of the formation.
I do not know if the estimated potential production area is too big, or assumed well spacing
is too tight.
The key question is what part of these estimated technically recoverable resources are
economically viable at $50; $60; $70; $80; $90, $100, etc.
Significant part of resources may never be developed, even if they are technically
recoverable.
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves
times 1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3
Gb of 2P reserves that have been added to Permian reserves since 2011, if we assume most of
these are from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that
total proved plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved
plus 3.5 GB probable with the assumption that probable=proved/2). I have assumed about 30% of
total Permian 2P reserves is in the Wolfcamp shale. That is a WAG.
Note the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a
conservative guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go
to $85/b and remain at that level the F95 estimate may become ERR, at $100/b maybe the median
is potentially ERR. It will depend how long prices can remain at $100/b before an economic
crash, prices are Brent Crude price in 2016$ with various crude spreads assumed to be about
where they are now.
Dennis,
where your number for proven reserves in the Permian comes from?
In November 2015, the EIA estimated proven reserves of tight oil in Wolfcamp and Bone Spring
formations as of end 2014 at just 722 million barrels.
I just looked at Permian Basin crude reserves (Districts 7C, 8 and 8A) and assumed the
change in reserves from 2011 to 2014 was from the Wolfcamp. I didn't know about that page for
reserves. It is surprising it is that low.
In any case the difference is small relative to the UTRR, it will be interesting to see what
the reserves are for year end 2015.
Based on this I would revise my estimate to 20 Gb for URR with a conservative estimate of 12
Gb until we have the data for year end 2015 to be released later this month.
My guess is that the USGS probably already has the 2015 year end reserve data.
The EIA proved reserves estimate for 2015 will be issued this month. I think we will see a
significant increase in the number for the Permian basin LTO.
Also note that USGS TRR estimate is only for Wolfcamp.
I can only guess what could be their estimate for the whole Permian tight oil reserves.
But the share of Wolfcamp in the Permian LTO output is only 24% (according to the
EIA/DrillingInfo report).
That makes sense. I also imagine the USGS focused on the formation with the bulk of the
remaining resources. It is conceivable that the 30 Gb estimate is closer to the remaining oil
in place and that more like 90% of the TRR is in the Wolfcamp, considering that the F5 estimate
is about 30 Gb. That older study from 2005 may be an under estimate of TRR for the Permian,
likewise the USGS might have overestimated the UTRR.
If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could
ramp up at the speed of the Eagle Ford (say 2 to 3 years). It will be oil price dependent and
perhaps they won't over do it like in 2011-2014, but who knows, some people don't learn from
past mistakes. If you or Mike were running things it would be done right, but the LTO guys, I
don't know.
"This estimate is for continuous (unconventional) oil, and consists of undiscovered,
technically recoverable resources.
Undiscovered resources are those that are estimated to exist based on geologic knowledge and
theory, while technically recoverable resources are those that can be produced using currently
available technology and industry practices. Whether or not it is profitable to produce these
resources has not been evaluated."
If it requires slave labor at gunpoint to get the oil out, then that's what will happen
because you MUST have oil, and a day will soon come when that sort of thing is reqd.
Nice apocalyptic vision of the future you've got there!
Whatever happened to the ideals of democracy, capitalism, business, profits, free markets
etc ? Don't worry, no need to answer, that was purely a rhetorical question. I'm quite aware of
the realities of the world!
However, not to pour too much sand on your vision, But I have to wonder? Since your
potential slaves in 21st century America are already armed to the teeth, they might decide not
to just go with the flow. (pun intended)
Anyways slaves don't buy cars or too many consumer goods so that might, in and of itself,
put a bit of a damper on the raison d'etre, excuse my french, of the oil companies and the very
existence of these future slave owners.
because you MUST have oil
Really now?! You know, as time goes by, I'm less and less convinced of that!
This follows on from reserve post above (two a couple of comments). In terms of changes over
the last three years – there really weren't anything much dramatic. We'll see what 2016
brings, especially for ExxonMobil, but it looks like they already knocked a big chunk off of
their Bitumen numbers already in 2015.
Note I went through a lot of 20-F and 10-K reports watching the rain fall this morning and
copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general
trends are shown.
Note the figures are totals for all nine companies I looked at.
IEA WEO is out: http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html
presentation slides, fact sheet and summary are available online (report can be purchased). IEA
seems to be _very_ concerned about underinvestment in upstream oil production. Several pages of
the report is devoted to this, the title of that section is "mind the gap". More or less all of
the content has been discussed on this website, including the issue with high levels of debt
and that this can affect suppliers' capacity to rebound, and how much demand can be reduced as
a result of a stringent carbon cap.
From the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production
in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil
sands) approved for development in 2015 sank to the lowest level since the 1950s, with no sign
of a rebound in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely
that demand (as projected in our main scenario) and supply can be matched in the early 2020s
without the start of a new boom/bust cycle for the industry"
Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"
I wonder who that paragraph is aimed at. As I indicated above the companies that would be
investing in long term conventional projects don't have a very large inventory of undeveloped
reserves (17 Gb as of end of 2015, some of this has gone already this year and more is in
development and will come on stream in 2017 and 2018 (and a small amount in later years for
approved projects). I'd guess there might only be less than 10 Gb (and this the most expensive
to develop) that is currently under appraisal among the major western IOCs and larger
independents; allowing for their partnerships with NOCs in a lot of the available projects that
could represent 20 to 30 Gb total. That really isn't very much new supply available, and a
large proportion is in complex deep water projects that wouldn't be ramped up fully until 6 to
7 years after FID (i.e. already too late for 2020). Really the main players need to find new
fields with easy developments, but they obviously aren't, probably never will, and actually
aren't looking very hard at the moment.
My interpretation is that this is IEAs way of saying that it does not look good. Those who can
read between the lines get the message. Also, a few years from they will be able to say "see we
told you so".
It's impossible for IEA to make statements like: "the end of low cost oil will negatively
affect economic growth", "geology is about to beat human ingenuity" etc.
WEO have become more and more bizarre over the years. On the one hand they contain
quantitative projections which tell the story politicians wants to hear. On the other hand, the
text describes all sorts of reason of why the assumptions are unlikely to hold. Normally, if
you don't believe in your own assumptions you would change them.
Here is the production graph. Not that much has happened. There was a big drop for 2011. 2009
on the other hand saw an increase. Up to the left, which is very hard to see, 2015 continues to
follow 2014 which follows 2013 which follows 2012. Will we see 2013 reach 2007 the next few
months?
Its on purpose both because I wanted to zoom in and because the data for first 18 months or so
for the method I used above is not very usable. Bellow is the production profile which is
better for seeing differences the first 18 months. Above graph is roughly 6 months ahead of the
production profile graph.
And I guess we can all see no technological breakthru. 2014's green line looks superior to
first 3 mos 2015.
2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper
decline at that point and is likely going to intersect 2014's line probably within the
year.
There is zero evidence on that compilation of any technological breakthrough surging output
per well in the past 2-3 yrs.
In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular
EUR improvement.
And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also
no evidence of sweetspots first.
I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with
inferior technology, and then as they became less sweet the technological breakthroughs brought
output up to look the same.
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.
And it would be far too much coincidence for techno breakthrus to just happen to increase
flow the exact amount lost from exhausting sweet spots.
This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning
it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather
than sweet.
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric
calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal
lateral that might be "obtained" from stimulation. More sand along a longer lateral does not
necessarily translate into greater frac growth (an increase in the radius around the horizontal
lateral). Novices in frac technology believe in halo effects, or that more sand equates to
higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals
simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre
foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take
much higher oil prices.
Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals
result in higher IP's and higher ensuing 90 day production results. That generates more cash
flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked
reserve assets. More assets means the shale oil industry can borrow more money against those
assets. Its a game, and a very obvious one at that. Nobody is breaking new ground or making big
strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is
pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of
depletion. Moving off those sweet spots into flank areas will be even less economical (if that
is possible) and will result in significantly less UR per well. That is what is ridiculous
about modeling the future based on X wells per month and trying to determine how much
unconventional shale oil can be produced in the US thru 2035. The term, "past performance is
not indicative of future results?" We invented that phrase 120 years ago in the oil
business.
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra
stages post 2008/9/10. How could there not be going from 15 stages to 30+?
I see NO magic post peak. They all descend exactly the same way and by 18-20 months every
drill year is lined up. That's actually astounding - given 15 vs 30 stages. There should be
more volume draining on day 1 and year 2, but the flow is the same at month 20+ for all drill
years. This should kill the profitability on those later wells because 30 stages must cost
more.
But profit is not required when you MUST have oil.
Freddy, is there something going on in the data? How can 30 stage long laterals flow the
same at production month 24 as the earlier dated wells at their production month 24
–whose lengths of well were MUCH shorter?
I can only speculate why the curves look like they do. It could be that the newer wells would
have produced more than the older wells, but closer well spacing is causing the UR to go down.
Here is the updated yearly decline rate graph. 2010 has seen increased decline rates as I
suspected. The curves are currently gathering in the 15%-20% range.
2007 only has 161 wells. So it makes the production curve a bit noisy as you can see above.
Current yearly decline rate for 2007 is 7,2% and the average from month 98 to 117 would
translate to a 10,3% yearly decline rate. The 2007 curve look quite different from the other
curves, so thats why I did not include it.
Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore
2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I
guess one way to do it would be to look at the natural log of monthly output vs month for each
year and see where the curve starts to become straight indicating exponential decline. The
decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010,
2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or
super fracking (more frack stages and more proppant) has changed the shape of the decline
curve. The shape is definitely different, I am speculating about the possible cause.
2007 had much lower initial production and the long late plateau gives it a low decline rate
also. But yes, initial decline rates look similar to the other curves. If you look at the
individual 2007 wells then you can see that some of them have similar increases to production
as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that
those increases are fewer and distributed over a longer time span than 2008 and it is what has
caused the plateau. If that is the case, then 2007 may not be different from the others at and
we will see increased decline rates in the future.
Regarding natural log plots. Yes it could be good if you want to find a constant exponential
decline. But we are not there yet as you can see in above graph.
One good reason why decline rates are increasing is because of the GOR increase. When they
pump up the oil so fast that GOR is increasing, then it's expected that there are some
production increases first but higher decline rates later. Perhaps completion techniques have
something to do with it also. Well spacing is getting closer and closer also and is definitely
close enough in some areas to cause reductions in UR. But I would expect lower inital
production rather than higher decline rates from that. But maybe I´m wrong.
Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were
confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND
Bakken/TF wells completed in Sept 2016.
I have 75 in my data, so about the same. They have increased the number of new wells quite alot
the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it
increased withouth the rig count going up. But I see that the rig count has gone up now too.
Ron you say " Bakken production continues to decline though I expect it to level off soon."
A few words of wisdom as to the main reasons why it would level off? Price rise?
Even though you asked Ron. He might think that the decline in the number of new wells per
month may have stabilized at around 71 new wells per month. If that rate of new completions per
month stays the same there will still be decline but the rate of decline will be slower.
Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017
and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec
2018).
I am not so convinced that either Texas or the Bakken is finished declining at the current
level of completions. There was consistent completions of over 1000 wells in Texas until about
October of 2015. Then it dropped to less than half of that. The number of producing wells in
Texas peaked in June of this year. Since then, through October, it has decreased by roughly
1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than
they are completing.
I remember reading one projection recently for what wells will be doing over time in the Eagle
Ford. They ran those projections for a well for over 22 years. Not sure which planet we are
talking about, but in Texas an Eagle Ford does well to survive 6 years. They keep referring to
an Eagle Ford producing half of what they will in the first two years. In most areas, I would
say that it is half in the first year.
The EIA, IEA, Opec, and most pundits have the US shale drilling turning on a dime when the oil
price reaches a certain level. If it was at a hundred now, it would still take about two years
to significantly increase production, if it ever happens. I am not a big believer that US shale
is the new spigot for supply.
The wells being shut in are not nearly as important as the number of wells completed because
the output volume is so different. So the average well in the Eagle Ford in its second month of
production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So
about 37 average wells need to be shut in to offset one average new well completion.
Point is that total well counts are not so important, it is well completions that drive
output higher.
Output is falling because fewer wells are being completed. When oil prices rise and profits
increase, completions per month will increase and slow the decline rate and eventually raise
output if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec
2017 about 79 new wells per month is enough to cause a slight increase in output. My model
slightly underestimates Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30
kb/d lower than actual output (3% too low), my well profile may be slightly too low, but I
expect eventually new well EUR will start to decrease and my model will start to match actual
output better by mid 2017 as sweet spots run out of room for new wells.
Guess I will remember that for the future. The number of producing wells is not important.
Kinda like I got pooh poohed when I said the production would drop to over 1 million barrels
back in early 2015.
Do you agree that the shut in wells tend to be low output wells? So if I shut down 37 of
those but complete one well the net change in output is zero.
Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the
net change in output would be zero, but there would be 19,000 fewer producing wells, if we
assume the average output of the 1000 new wells completed was 200 b/d for the year and the
stripper wells produced 10 b/d on average.
How much do you expect output to fall in the US by Dec 2017?
Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by
about 1 million barrels per day from April 2015 to July 2016, can you point me to your comment
where you predicted this?
Tell us what it will be in August 2017.
I expected the fall in supply would lead to higher prices, I did not expect World output to
be as resilient as it has been and I also did not realize how oversupplied the market was in
April 2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan
to April, so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US
output has decreased by 635 kb/d.
If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would
also have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400
kb/d. If we consider 12 month average output of World C+C, the decline has been 340 kb/d from
the 12 month average peak in August 2015 (centered 12 month average).
The dropping numbers are not as much from the wells that produce less than 10 barrels a day,
but from those producing greater than 10, but less than 100. The ones producing greater than
100 are remaining at a consistent level over 9000 to 9500. The prediction on one million was as
to the US shale only. It is your site, you can search it better than I can,
But then don't take my word for it. You can find the same information under the Texas RRC site
under oil and gas/research and statistics/well distribution tables. Current production for Sep
can be found at online research queries/statewide. It is still dropping, and will long term at
the current activity level. Production drop for oil, only, is a little over 40k per day
barrels, and condensate is lower for September. Proofs in the pudding.
My guess is that you would see a lot more plugging reports, if it were not so expensive to plug
a well. At net income levels where they are, I expect they would put that off as long as they
could.
I trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno
Peters data has 66 completions in August 2016, he has not put up his post for the Sept data yet
so I am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno
tends to be spot on for the Bakken data, for Texas he relies on RRC data which is not very
good.
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.
It appears this was because another 13 wells in the field were recently completed.
It appears that when all 29 wells are returned to full production, this field will be very
prolific initially. Therefore, on this one field alone, we could see some impact for the entire
state.
Does anyone know if these wells are part of Whiting's JV? Telling if they had to do that on
these strong wells. Bakken just not close to economic.
I also note that average production days per well in for EOG in Parshall was 24. I haven't
looked at some of the other "older" large fields yet, but assume the numbers are similar.
I agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I
don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk
costs in wells drilled but not completed and running the numbers based on whether they can pay
back the completion costs. Everyone may be hoping the other guys fail and are just trying to
pay the bills as best they can, not sure if just stopping altogether is the best strategy.
There is the old adage that when your in a hole, more digging doesn't help much.
So my model just assumes continued completions at the August rate for about 12 months with
gradually rising prices as the market starts to balance, then a gradual increase in completions
as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90
completions per month 18 months later). At that point oil prices have risen to $97/b and LTO
companies are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at
that level for 40 years (not likely, but the model is simplistic).
I could easily do a model with no wells completed, but I doubt that will be correct.
Suggestions?
Dennis. As we have discussed before, tough to model when there is no way to be accurate
regarding the oil price.
I continue to contend that there will be no quick price recovery without an OPEC cut.
Further, the US dollar is very important too, as are interest rates.
At some point OPEC may not be able to increase output much more and overall World supply
will increase less than demand. My guess is that this will occur by mid 2017 and oil prices
will rise. OPEC output from Libya an Nigeria has recovered, but this can only go so far, maybe
another 1 Mb/d at most. I don't expect any big increases from other OPEC nations in the near
term.
A big guess as to oil prices has to be made to do a model.
I believe my guess is conservative, but maybe oil prices will remain where they are now
beyond mid 2017.
I expected World supply to have fallen much more quickly than has been the case at oil
prices of $50/b.
"EIA does this by using a relatively new dataset-FracFocus.org's national fracking chemical
registry-to identify the completion phase, marked by the first fracking. If a well shows up on
the registry, it's considered completed "
There is an unlikely peak oil related editorial writer hiding in the most unlikely place: a
weekly English business paper called Capital Ethiopia. The latest editorial is again putting an
excellent perspective on world events. http://capitalethiopia.com/2016/11/15/system-failure/#.WC1ZCvl9600
For the record, I have no interest or connection to this publication other than that of a
paying reader.
Wouldn't it be nice if mainstream publications would sound a bit more like this.
Thanks all. I thought that the red queen concept meant that there had to be an increase in the
rate of completions. So that 71 year-on-year in north Dakota would only stabilise temporarily.
Perhaps the loss of sweet spots are being counteracted by the improvements in technology? I'm
assuming that even with difficulties of financing there will be a swift increase in completions
should the oil price take off, but not sure how sustainable this would be
Sometimes I think that once the price of oil is up enough that sellers can hedge the their
selling price for two or three years at a profitable level, it will hardly matter what the
banks have to say about financing new wells.
At five to ten million apiece, there will probably be plenty of money coming out of various
deep pockets to get the well drilling ball rolling again, if the profits look good.
Sometimes the folks who think the industry will not be able to raise money forget that it's
not a scratch job anymore. The land surveys, roads, a good bit of pipeline, housing, leases,
etc are already in place, meaning all it takes to get the oil started now is a drill and frack
rig.
I don't know what the price will have to be, but considering that a lot of lease and other
money is a sunk cost that can't be recovered, and will have to be written off, along with the
mountain of debts accumulated so far, the price might be lower than a lot of people
estimate.
Bankruptcy of old owners results in lowering the price at which an old business makes money
for its new owners.
The Red Queen effect is that more and more wells need to be completed to increase
output. As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output
it might require 120 wells to be completed to maintain output (if new well EUR did not
eventually decrease), but at 850 kb/d it might require about 78 new wells per month to maintain
output.
I think your numbers reflect numbers reported from ND DMR but Bloomberg might be closer to
reality for wells that will actually ever be completed (just a guess by me though). How do
Bloomberg get their numbers (e.g. removing Tight Holes, or removing old wells, not counting
non-completed waivers etc.)?
Yes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old
wells for example, and already include those that were spud last month (even though maybe
casing has not been set). I don't do a lot of filtering, so the actual # wells that really can
be completed is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know
Bloombergs method exactly, so I can't comment on that.
Concerning Freddy's chart of production profile of wells drilled in various years.
They all line up by about month 18 of production. This should not be possible. The later
wells have many more stages of frack. They are longer, draining more volume of rock. But the
chart says what it says. At month about 18 the 2014 wells are flowing the same rate as 2008
wells. We know stage count has risen over those 6 yrs. 2014 wells should flow a higher rate.
The shape of the curve can be the same, but it should be offset higher.
Explanation?
How about above ground issues . . . older wells get pipelines and can flow more oil . . .
nah, that's absurd.
There needs to be a physical explanation for this.
These new wells have higher IPs, but also higher decline rates.
Closer spacing (see Freddy's comment above) and depletion of the sweet spots may also impact
production curves and EURs.
That doesn't make sense. They are longer. By a factor of 2ish. How can a 6000 foot lateral flow
exactly the same amount 2 yrs into production as a 3000 foot lateral flows 2 yrs into
production?
Look at the lines. At 18 months AND BEYOND, these longer laterals flow the same oil rate as
the shorter laterals did at the same month number of production. Higher IP and higher decline
rate will affect the shape, but There Is Twice The Length..
I don't think we have information on the length of the wells, since 2008 the length of the
lateral has not changed, just the number of frack stages and amount of proppant. This seems to
primarily affect the output in the first 12 to 18 months, and well spacing and room in the
sweet spots no doubt has some effect (offsetting the greater number of frack stages etc.).
The combination of longer lateral lengths and advancements in completion technology has
allowed operators to increase the number of frac stages during completions and space them
closer together. The result has been a higher completion cost per well but with increased
production and more emphasis on profitability.
In the past five years, DTC Energy Group completion supervisors in the Bakken have helped
oversee a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even
40-stage fracs have been achieved.
One of the main reasons for this is the longer lateral lengths – operators now have
twice as much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are
also being spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet
in 2008, as experienced by DTC supervisors.
By placing more fracture stages closer together, over a longer lateral length, operators
have successfully been able to improve initial production (IP) rates, as well as increase EURs
over the life of the well.
blah blah, but they make clear the years have increased length. Freddy was talking about
well spacing, this text is about stage spacing, but that is achieved because of lateral
length.
Freddy can you revisit your graph code? It's just bizarre that different length wells have
the same flow rate 2 yrs out, and later.
Take a look at Enno´s graphs at https://shaleprofile.com/ . They look the same as my graphs and
we have collected and processed the data independently from each other.
If the wells have the same wellbore riser design irrespective of lateral length (i.e. same
depth, which is a given, same bore, same downhole pump) then that section might become the main
bottleneck later in life and not the reservoir rock. With a long fat tail that seems more
likely somehow compared to the faster falling Eagle Ford wells say (but that is just a guess
really). But there may be lots of other nuances, we just don't have enough data in enough
detail especially on the late life performance for all different well designs – it looks
like the early ones are just reaching shut off stage in numbers now. I doubt if the E&Ps
concentrated on later life when the wells were planned – they wanted early production,
and still do, to pay their creditors and company officers bonuses (not necessarily in that
order).
Hmmm. I know it is speculation, but can you flesh that out?
If some bottleneck physically exists that defines a flow rate for all wells from all years
then that does indeed explain the graphs, but what such thing could exist that has a new number
each year past year 2?
We certainly have discussed chokes for reservoir/EUR management, but the same setting to
define flow regardless of length?
The flow depends on the available pressure drop, which is made up of friction through the rock
and up the well bore (plus maybe some through the choke but not much), plus the head of the
well, plus a negative number if there is a pump. The frictional and pump numbers depend on the
flow and all the numbers depend on gas-oil ratio. Initially there is a big pressure drop in the
rock because of the high flow, then not so much. Once the flow drops the pressure at base of
the well bore just falls as a result of depletion over time, the effect of the completion
design is a lot less and lost in the noise, so all the wells behave similarly. That's just a
guess – I have never seen a shale well and never run a well with 10 bpd production,
conventional or anything else.
A question might be if the flow is the same why doesn't the longer well with the bigger
volume deplete more slowly, and I don't know the answer. It may be too small to notice and lost
in the noise, or to do with gas breakout dominating the pressure balance, or just the way the
the physics plays out as the fluids permeate through the rock, or we don't have long enough
history to see the differences yet.
RRC Texas for September came out recently. As others will probably elaborate more on the data,
I just want to show if year over year changes in production could be use as a predictive tool
for future production (see below chart).
It is obvious that year over year changes (green line) beautifully predicted oil production
(red line) at a time lag of about 15 month. Even when production was still growing, the steep
decline of growth rate indicated already the current steep decline.
The interesting thing is that the year over year change is a summary indicator. It does not
tell why production declines or rises. It can be the oil price, interest rates or just
depletion – even seasonal factors are eliminated. It just shows the strength of a
trend.
I am curious myself how this works out. The yoy% indicator predicts that Texas will have
lost another million bbl per day by end next year. That sounds quite like a big plunge. One
explanation could be the fact that we have now low oil prices and high interest rates. In all
other cycles it has been the other way around: low oil prices came hand in hand with low
interest rates. This could be now a major obstacle for companies to grow production.
This concept of following year over year changes works of course just for big trends, yet
for investment timing it seems exactly the right tool. Another huge wave is coming in electric
vehicles which are growing in China by 120% year over year. Here we have the same situation as
for shale 7 years ago: Although current EV sales are barely 1 million per year worldwide, the
growth rate reveals already an huge wave coming. So as an investor it is always necessary to
stay ahead of the trend and I think this can be done by observing the year over year%
change.
Peak oil is the simplest label for the problem of energy resource depletion, or more
specifically, the peak in global oil production.
Oil is a finite, non-renewable resource, one that has powered phenomenal economic and
population growth over the last century and a half.
The rate of oil 'production', meaning extraction and refining (currently about 85 million
barrels/day), has grown almost every year of the last century.
Once we have used up about half of the original reserves, oil production becomes ever more
likely stop growing and begin a terminal decline, hence 'peak'.
The peak in oil production does not signify 'running out of oil', but it does mean the end
of cheap oil, as we switch from a buyers' to a sellers' market.
For economies leveraged on ever increasing quantities of cheap oil, the consequences may
be dire.
Without significant successful cultural reform, severe economic and social consequences
seem inevitable.
There's no doubt that economies suffer under high energy prices. Recently POTUS
acknowledged this when he said oil is too damn high.
Oil producers (frackers) have to be profitable and they just aren't. It seems to unclear
what the break even point is for fracking operations in the US, but let's say $50 per barrel
goes to production costs. That doesn't leave much room. If oil is selling for less than that
on the open market, the frackers are forced to finance their operations. This can't go on.
Clearly the cheap oil era has peaked.
In the third decade of the XXI century, which is about to come, one of the main problems
facing humanity, again, as in the 60s, will be its energy supply, as well as the search for
the main "energy carrier of the future."
The three whales that the world's energy industry today holds: oil, natural gas and coal
are, by their nature, non-renewable sources of energy. True, with regard to oil and gas, this
thesis is actively debated at the academic level, but for practical purposes it is
indisputable: modern civilization consumes so much hydrocarbons that their natural
substitution, if it exists, is not able to compensate for this exemption. The energy sources
mentioned above in 2017 accounted for about 81% of world primary energy production, and they
still define the image of our modern industrial world, while all renewable energy sources
provide only about 14% of primary energy production, and about 5% The balance comes from
nuclear energy (International Energy Agency, 2017).
At the same time, the situation with renewable sources is not at all as rosy as it may
seem at first glance: out of 14% of renewable sources, 10% is the energy from burning wood
and biomass, and 2.5% is hydropower. At the same time, the "fashionable" in the last decade,
and having received at the same time gigantic, almost trillion-dollar investments in solar
and wind energy projects, are not as high as 2% in the overall balance of the production of
primary energy. At the same time, it is not even about the absolute figures for the
introduction of new capacities of green energy, which may seem impressive, but about the
exponential dynamics of the relationship between "oil-coal-gas" and "green" in the long term.
After all, a decade ago, in 2008, the world balance of power generation looked like this: 78%
were oil, natural gas and coal, 5% were atomic energy, 3% were hydropower, about 13.5% were
wood and biomass, and 0, 5% produced wind and solar energy. Surprisingly, over the past ten
years, the transition from "wood and straw" to the energy of oil, natural gas and coal, which
occurred naturally, turned out to be two and a half times more significant for the global
energy balance than the development of "green" energy technologies.
The phenomenon of such meager growth of "green" energy is interesting in itself: for the
first time the capitalist mode of production, in which investments in fixed assets imply
quick returns in the form of profits, gives an obvious, albeit programmed failure. Its
essence becomes clear if we take into account in the picture the "quiet" transition of the
world from "firewood and straw" to oil, gas and coal, which lasted throughout the decade of
2008–2018. This process, which no one financed in a targeted manner or advertised in
the world media or Western scientific publications, went forward thanks to economic
expediency. At the same time, the planting of green energy was accompanied not only by a
powerful public relations campaign and trillions of financing, but also forced almost all
countries to accept special, non-economic overpriced tariffs for the purchase of green energy
in order to somehow force capital to finance unprofitable production. energy with wind
turbines and solar panels.
World energy: a general view
Several reputable organizations are engaged in the problem of the global energy balance.
These include the United States Department of Energy (DOE), the International Energy Agency
(IEA), located in Paris, and the well-known oil company BP (ex-British Petroleum). Each of
these organizations publishes annual reports on the situation in the global energy industry
and the prospects for its development. These reports are compiled on the basis of an analysis
of the mass of primary information, often of an incomplete and contradictory nature.
Nevertheless, due to a certain averaging of all the initial data, the annual reports of these
organizations quite fully and clearly reflect the overall world dynamics. In this article, in
order to bring the data to one standard, we will rely on the annual reports of BP, unless
otherwise explicitly stated in the text.
In accordance with the latest available BP report, global energy consumption reached
13,511 million tons of oil equivalent in 2017 (TNE, eng. "Tonne of oil equivalent", TOE). At
the same time, over the decade between 2007 and 2017, world primary energy consumption grew
by an average of 1.5%. That is, the dynamics of energy consumption correlate well with the
observed growth rates of the global economy over the same period – an average of 3.2%
per year (World Bank and IMF, 2018).
The fluctuations of this second parameter, associated with economic crises and recessions
observed in the period under review, make it possible to evaluate the contribution of the
notorious "energy efficiency" to the global growth in demand
No, there does not even remotely a hint of abiotic oil. Read the last two paragraphs again.
That is what it hints to. An average growth of 1.5% in energy consumption and a growth of
3.2% in the global economy has been enabled by a continual growth in energy efficiency. This
cannot possibly continue, especially the 3.2% growth in global economy. When the global
economy does not grow it receeds. This is called a recession.
So it's up to Canada, Russia and the USA to keep Non-OPEC from tanking. Canada is nearing
maximum production due to pipeline constraints and even the optimistic oil experts are saying
Russia is near her peak, so it is up to the USA to keep Non-OPEC peak oil at bay. And that
means it's all up to the shale oil patch to keep increasing production.
Olson, Bradley; Elliott, Rebecca.Wall Street Journal (Online); New York, N.Y.
The once-powerful partnership between fracking companies and Wall Street is fraying as
the industry struggles to attract investors after nearly a decade of losing money.
Frequent infusions of Wall Street capital have sustained the U.S. shale boom. But that
largess is running out. New bond and equity deals have dwindled to the lowest level since 2007.
Companies raised about $22 billion from equity and debt financing in 2018, less than half the
total in 2016 and almost one-third of what they raised in 2012, according to Dealogic.
The loss of that lifeline is forcing shale companies -- which have helped to turn the
U.S. into an energy superpower -- to reduce spending and face the prospect of slower growth
. More than a dozen companies have announced spending reductions so far this year, even as
crude-oil prices have rallied more than 20% from December lows. More are expected to tighten
budgets as they release earnings in coming weeks.
The drop in financial backing is especially being felt by smaller, more indebted
drillers. But even larger, better-capitalized frackers are facing renewed investor skepticism
about whether they can keep spending in check and still hit growth and cash-flow
targets.
Shares of Continental Resources Inc. fell 5.4% Tuesday after the shale company, founded
by billionaire Harold Hamm, disclosed that fourth-quarter spending was almost 10% higher than
analyst expectations.
Wall Street support allowed shale companies to persevere through a plunge in oil prices
that began in 2014, eventually helping the U.S. surpass Saudi Arabia and Russia as the world's
largest producer of oil , with 11.9 million barrels a day in November, according to the
U.S. Energy Information Administration.
Banks have provided financing when producers spend more cash than they take in from
operations, something that has happened every year since 2010. They also help companies hedge
their future oil production to lock in prices and avoid market volatility, and provide them
with revolving loans backed by future oil and natural-gas prospects.
But in 2016, federal regulators concerned about banks' exposure to shale drillers
tightened standards for lending to oil-and-gas companies after dozens went bankrupt amid the
drop in commodity prices. The U.S. Treasury Department guidelines require lenders to regard
loans as troubled if a company's total debt reaches more than 3.5 times a producer's earnings,
excluding interest, taxes and other accounting items.
There is more to this article. You can find it by clicking on the link above. It appears
that the shale celebration is finally slowing down. But those in the shale cheering section
still far outnumber us naysayers.
And that was just overnight. On Friday morning, another activist, Kimmeridge Energy
Management Co., announced it had taken a stake in PDC Energy Inc., an exploration and
production company with operations in Colorado and Texas. Kimmeridge wants PDC to overhaul
its financial priorities, costs, governance and maybe, given the line about "considering
all strategic alternatives," its entire identity.
Fracking has helped the USA boost oil production, but that is pressuring to get oil out of
older wells. Once those have been sucked dry, we'll need to import lots more. You read news
about occasional big new discoveries in the USA, but read the details to see that each
amounts only to a few days of oil consumption in the USA.
The world still runs on oil and the USA wants to control it all. If you doubt the
importance, look at a freeway or airport or seaport to see oil at work.
I just copied this from Quora, posted as part of a long comment by a person who understands
the basics of the oil biz.
"Oil is becoming difficult to extract, and this operation is becoming increasingly expensive.
While it is true that the use of fracking has enabled the extraction of previously
inaccessible deposits, this just buys us a little more time. As it is, a Goldman Sachs study
found that the cost of extracting crude oil went up over 15% a year in the decade prior to
the economic slowdown (and is still rising by possibly 10% a year)."
Obviously enough, the cost of getting tight oil out is declining, but tight oil is only a
small part of total oil production. I'm not sure about the costs of tar sands oil, it may be
declining in real terms, or rising. I haven't seen anything recent on the costs of tight
oil.
Hopefully somebody in the biz will have something to say about the cost of conventional
oil production is changing, based on their personal knowledge.
If it is going up anywhere close to ten percent a year, in real terms, world wide, the
price of oil will HAVE to get back into the hundred dollar plus range within five or six
years, maybe sooner.. economic troubles can lead to some countries selling for less than
production costs.
My opinion is since the crack in 2014 aproximately all exploration offshore stopped, there
have been some discoveries near exsisting infrastructure that some have been built out as
tieback. In General even with cut in drilling cost , subsea tecnology , remote controlled
platforms a brent price of 65 usd bbl will make some profit for oil Companies but you will
never see a huge increase in activity to find billions of new barrels that is needed. There
is also a fact less discoveries are made each 100 wells drilled and size declining in
average. This trend together with increase labour cost , everything else in general will
demand higher oil price to solve a global supply crize..
This doesn't explain why the Saudi's spend billions building and operating peripheral water
injection systems and refineries that can handle oil with vanadium. If they truly have 266
billion barrels in the ground, all they would have to do is drill some wells and millions of
cheap, extra barrels/day would gush out of the ground.
They say, total new shale oil produced in March will be 628,526 barrels per day. (Net
increace+Legacy decline)
Net Increase will be 84,406 barrels per day.
Legacy Decline will be 544,119 barrels per day
Therefore for every 1 barrel per day increase, 7.45 barrels of new oil had to be produced.
Therefore for every 1 barrel per day increase, 7.45 barrels of new oil had to be
produced.
This is simply mind-blowing. And the more oil they produce, the more oil they need to
produce to keep from going negative. How long can they keep this up?
https://www.rigzone.com/news/permian_oil_and_gas_production_to_hit_new_records-21-feb-2019-158209-article/
Seems EIA predict production in Permian will increase from 3.98 MMbpd to 4.02 MMbpd next
month. Guess it have been mostely flat at least US production have been 11.9 MMbpd since
January. Think than an increase of 40 000 /3 month = 13. 333 x12 = 160 000 barrels for 2019
increase seems reasonable. World demand seems increase by 1.5-2.0 MMbpd. Hopefully Permian
production will increase significant when tje new pipeline is compleated 4th Quartile 2019
but that remaind to see.
Reviewing this past weekly(2/15) oil inventory report reveals import of 7.5 million
barrels/day and 7.0 million barrels/day for the past 4 weeks. Yet I hear how we are down to
perhaps 1-2 million/day and even that we are a net exporter. Could someone Help me understand
what is going on to this non oil person! Thanks in advance
I'm not one of the experts, but I can nevertheless answer your question!
Short answer:
The fossil fuel industry is in bed with certain politicians whose mascot is the elephant,
and together they put out a continuous stream of half facts, cherry picked facts, and
outright lies in furtherance of their own ends.
You're at the right place to get the straight dope. HERE.
Crude imports on line 5 as 7,522 kbpd, crude exports on line 9 are 3,607 kbpd for net
crude imports on line 4 of 3,915 kbpd.
Other supply includes products and natural gas liquids. It shows net imports on line 21 of
-2,809 kbpd. Total net imports of Crude and Petroleum Products on line 33 are 1,106 kbpd.
How they can claim that US tight oil will be produced in larger quantities if they predict stagnant oil prices and at those price
the US production is unprofitable.
So from now on it's all condensate, and very little heavy and medium oil.
I like BP propaganda: "The abundance of oil resources, and risk that large quantities of recoverable oil will never be extracted,
may prompt low-cost producers to use their comparative advantage to expand their market share in order to help ensure their resources
are produced." That's not only stupid but also gives up the intent...
Notable quotes:
"... In the ET scenario, global demand for liquid fuels – crude and condensates, natural gas liquids (NGLs), and other liquids – increases by 10 Mb/d, plateauing around 108 Mb/d in the 2030s. ..."
"... All of the demand growth comes from developing economies, driven by the burgeoning middle class in developing Asian economies. Consumption of liquid fuels within the OECD resumes its declining trend. ..."
"... The increase in liquid fuels supplies is set to be dominated by increases in NGLs and biofuels, with only limited growth in crude ..."
In the ET scenario, global demand for liquid fuels – crude and condensates, natural gas liquids (NGLs), and other liquids
– increases by 10 Mb/d, plateauing around 108 Mb/d in the 2030s.
All of the demand growth comes from developing economies, driven by the burgeoning middle class in developing Asian economies.
Consumption of liquid fuels within the OECD resumes its declining trend. The growth in demand is initially met from non-OPEC
producers, led by US tight oil. But as US tight oil production declines in the final decade of the Outlook, OPEC becomes the main
source of incremental supply. OPEC output increases by 4 Mb/d over the Outlook, with all of this growth concentrated in the 2030s.
Non-OPEC supply grows by 6 Mb/d, led by the US (5 Mb/d), Brazil (2 Mb/d) and Russia (1 Mb/d) offset by declines in higher-cost, mature
basins.
Consumption of liquid fuels grows over the next decade, before broadly plateauing in the 2030s
Demand for liquid fuels looks set to expand for a period before gradually plateauing as efficiency improvements in the transport
sector accelerate. In the ET scenario, consumption of liquid fuels increases by 10 Mb/d (from 98 Mb/d to 108 Mb/d), with the majority
of that growth happening over the next 10 years or so. The demand for liquid fuels continues to be dominated by the transport sector,
with its share of liquids consumption remaining around 55%. Transport demand for liquid fuels increases from 56 Mb/d to 61 Mb/d by
2040, with this expansion split between road (2 Mb/d) (divided broadly equally between cars, trucks, and 2/3 wheelers) and aviation/marine
(3 Mb/d). But the impetus from transport demand fades over the Outlook as the pace of vehicle efficiency improvements quicken and
alternative sources of energy penetrate the
transport system . In contrast, efficiency gains when using oil for non-combusted uses, especially as a feedstock in petrochemicals,
are more limited. As a result, the
non-combusted use of oil takes over as the largest source of demand growth over the Outlook, increasing by 7 Mb/d to 22 Mb/d
by 2040.
The outlook for oil demand is uncertain but looks set to play a major role in global energy out to 2040
Although the precise outlook is uncertain, the world looks set to consume significant amounts of oil (crude plus NGLs) for several
decades, requiring substantial investment. This year's Energy Outlook considers a range of scenarios for oil demand, with the timing
of the peak in demand varying from the next few years to beyond 2040. Despite these differences, the scenarios share two common features.
First, all the scenarios suggest that oil will continue to play a significant role in the global energy system in 2040, with the
level of oil demand in 2040 ranging from around 80 Mb/d to 130 Mb/d. In all scenarios, trillions of dollars of investment in oil
is needed Second, significant levels of investment are required for there to be sufficient supplies of oil to meet demand in
2040. If future investment was limited to developing existing fields and there was no investment in new production areas, global
production would decline at an average rate of around 4.5% p.a. (based on IEA's estimates), implying global oil supply would be only
around 35 Mb/d in 2040. Closing the gap between this supply profile and any of the demand scenarios in the Outlook would require
many trillions of dollars of investment over the next 20 years.
Growth in liquids supply is initially dominated by US tight oil, with OPEC production increasing only as US tight oil declines
Growth in global liquids production is dominated in the first part of the Outlook by US tight oil, with OPEC production gaining
in importance further out. In the ET scenario, total US liquids production accounts for the vast majority of the increase in global
supplies out to 2030, driven by US tight oil and NGLs. US tight oil increases by almost 6 Mb/d in the next 10 years, peaking at close
to 10.5 Mb/d in the late 2020s, before falling back to around 8.5 Mb/d by 2040. The strong growth in US tight oil reinforces the
US's position as the world's largest producer of liquid fuels. As US tight oil declines, this space is filled by OPEC production,
which more than accounts for the increase in liquid supplies in the final decade of the Outlook.
The increase in OPEC production is aided by OPEC members responding to the increasing abundance of global oil resources by reforming
their economies and reducing their dependency on oil, allowing them gradually to adopt a more competitive strategy of increasing
their market share. The speed and extent of this reform is a key uncertainty affecting the outlook for global oil markets (see pp
88-89).
The stalling in OPEC production during the first part of the Outlook causes OPEC's share of global liquids production to fall
to its lowest level since the late 1980s before recovering towards the end of the Outlook.
Low-cost producers: Saudi Arabia, UAE, Kuwait, Iraq and Russia
The abundance of oil resources, and risk that large quantities of recoverable oil will never be extracted, may prompt low-cost
producers to use their comparative advantage to expand their market share in order to help ensure their resources are produced.
The extent to which low-cost producers can sustainably adopt such a 'higher production, lower price' strategy depends on their
progress in reforming their economies, reducing their dependence on oil revenues.
In the ET scenario, low-cost producers are assumed to make some progress in the second half of the Outlook, but the structure
of their economies still acts as a material constraint on their ability to exploit fully their low-cost barrels.
The alternative 'Greater reform' scenario assumes a faster pace of economic reform, allowing low-cost producers to increase their
market share. The extent to which low-cost producers can increase their market share depends on: the time needed to increase production
capacity; and on the ability of higher-cost producers to compete, by either reducing production costs or varying fiscal terms.
The lower price environment associated with this more competitive market structure boosts demand, with the consumption of oil
growing throughout the Outlook.
Growth in liquid fuels supplies is driven by NGLs and biofuels, with only limited growth in crude oil production
The increase in liquid fuels supplies is set to be dominated by increases in NGLs and biofuels, with only limited growth in
crude.
US reserves are estimated by some to about 50 billion barrels. Oil production, along with
reserve estimates, are growing in the US for one reason and one reason only, the advent of shale
oil. Reserve estimates before 2008 were based on conventional oil.
Onshore conventional oil production in the USA is in steep decline. Shale oil production is
intistically connected with financing and it produce along with oil a stream of junk bonds. At
some point investors might do not want them of the bubble start deflating. Then what.
Hugo Wrote:
"Dennis, with his calculation of a peak in 2025 + or – 3 years is about right."
That really depends on how much debt the Shale Drillers can take on, and presumes there is
not another global recession before 2025. Next three years for Shale Drillers may be a
problem. I believe something like $150B in debt comes due between now and 2023. That's a lot
of debt to roll over, as well as take on more debt to fund CapEx. Without constant US Shale
production increases, world production peaks.
"... I have been suspicious for some time that production numbers can be corrupted by fuzzy definitions. ..."
"... You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be. ..."
I have been suspicious for some time that production numbers can be corrupted by fuzzy
definitions. Iran is being sanctioned, but Iran shares that enormous gas field under the
Persian Gulf with Qatar. Gas production yields condensate and it yields NGLs.
High vapor pressure NGLs get labeled liquefied petroleum gas, and that is used for
transportation fuel in India. Pentane Plus is used or called something akin to natural
gasoline.
You can see how the definitions are going to blur and they're going to allow declaring oil
production numbers to be anything that they want them to be. Iran is using this to dodge
sanctions, or they did use it when condensate was not restricted. Don't recall if that
loophole was closed in the current sanctions. That would be a good thing to know.
The same thing can happen with shale. We hear all sorts of talk about how much gas is
being flared and how much gas is being captured, and you know perfectly well there has to be
condensate involved. There was an article a year or so ago about NGL capture in the Bakken,
but I don't recall any follow-up. It shouldn't take too much of a stretch on the part of
state regulators to find a way to count the high vapor pressure portion of NGL as oil.
You can see how the definitions are going to blur and they're going to allow declaring
oil production numbers to be anything that they want them to be.
Exactly. And this, in turn, allows Wall Street to suppress the price of "prime oil"
using fake production numbers, fake storage glut (which is essentially condensate glut)
and similar tricks. Please note that the US refineries consume mainly "prime oil" while
the USA mainly produces (and tries to export at a discount) "subprime oil."
Pretty polished and sophisticated racket. It might well be that shale oil companies are
partially financed from those Wall Street profits as nobody in serious mind expect those
loans to be ever repaid.
So OPEC cuts are the only weapon that OPEC countries have against this racket.
In any case, I think all those nice charts now need to be split into "prime oil" and
subprime oil parts and analyzed separately. In the current conditions, treating "heavy
oil" and condensate as a single commodity looks to me like pseudoscience.
I do not follow Laredo Petroleum closely, however their recent year-end results and
operations summary contained disclosures that may affect north American shale production more
broadly, or perhaps they are company specific, I don't know.
Laredo is a nice sized E&P producing around 70,000 boepd in the permian, mostly in
Glasscock and Regan counties. Much of their production is horizontal Wolfcamp.
Laredo has been disappointed with its oil production recently, as well as an increasing
GOR.
"Laredo has taken action to address the reduced oil productivity experienced in 2018 that
we believe was impacted by the tighter spacing of some wells drilled in 2017 and 2018.
Responding to these results, the Company began widening spacing on wells spud in the first
quarter of 2019. Laredo expects this shift in development strategy to drive higher returns
and increased capital efficiency versus 2018 as widening spacing is anticipated to address
one of the causes of higher oil decline rates."
They have changed their developmental strategy to widen spacing to improve recovery and
mitigate the increasing GOR. They have also reduced their capex by around 35 % from $575
million in 2018 to a planned $365 million in 2019.
"Responding to the current commodity price environment of WTI strip pricing of
approximately $54 per barrel, Laredo expects to invest approximately $365 million in 2019,
excluding non-budgeted acquisitions. This budget includes approximately $300 million for
drilling and completion activities and approximately $65 million for
production facilities, land and other capitalized costs. Laredo anticipates adjusting capital
spending levels to match operating cash flow if operating cash flow does not meet budgeted
expectations. Should operating cash flow exceed budget expectations, free cash flow could be
used to complete additional wells, repurchase stock or pay
down debt.
By the third quarter of 2019, enabled by the Company's operational flexibility, Laredo
anticipates reducing activity from the current three horizontal rigs and two completion crews
to operating one horizontal rig and utilizing a single completion crew, as needed. The
front-loaded completion schedule and disciplined reduction in activity should drive free cash
flow generation in the second half of 2019 that is expected to balance capital expenditures
with cash flow from operations for full-year 2019."
Of course this is just one producers take on productivity concerns. Link below.
Interesting. They are more a gas company than an oil company with only 23000 of the 70000
BOEs being oil. Interestingly, they are forecasting oil production to decline 5% year over
year while BOEs rises high single digits, showing how gas to oil keeps rising.
As such a tiny oil producer (23000 barrels) its pretty meaningless in the grand scheme,
but very interesting nonetheless. Thanks for sharing.
Okay, you will have to read the article to see how Robert arrived at his conclusion. But
his conclusion is:
So, I have no good reason to doubt Saudi Arabia's official numbers. They probably do
have 270 billion barrels of proved oil reserves.
I find his logic horribly flawed. Robert compares Saudi's growing reserve estimates with
those of the USA.
First, the US Securities and Exchange Commission have the strictest oil reporting laws in
the world, or did have in 1982. Also, better technology has greatly improved reserve
estimates. And third, the advent of shale oil has dramatically added to US reserve
estimates.
Saudi has no laws that govern their reserve reporting estimates.
From Wikipedia, US Oil Reserves: Proven oil reserves in the United States were 36.4
billion barrels (5.79×109 m3) of crude oil as of the end of 2014, excluding the
Strategic Petroleum Reserve. The 2014 reserves represent the largest US proven reserves since
1972, and a 90% increase in proved reserves since 2008.
Robert says US reserves are 50 billion barrels. I don't know where he gets that number but
it really doesn't matter. Oil production, along with reserve estimates, are growing in the US
for one reason and one reason only, the advent of shale oil. Reserve estimates before 2008
were based on conventional oil. Onshore conventional oil production in the USA is in steep
decline.
Robert Rapier is brillant oil man, but a brilliant downstream oil man. Refineries are his
forte. He should know better than the shit he produced in that article.
100 percent of Saudi Arabia's reserves are based on conventional oil. Their true reserves
are very likely somewhere in the neighborhood of 70 billion barrels.
OPEC says they have 1214.21 billion barrels of proven reserves. And they say non-OPEC has
268.56 billion barrels of proven reserves. Average OPEC C+C production, over the last four
years, has been 12.78 billion barrels per year according to the EIA. The EIA says the average
non-OPEC C+C production over the last four years has been 16.8 billion barrels per year.
Okay, here is the killer. If those numbers are correct then the average non-OPEC nation
has an R/P ratio of 16 while the average OPEC nation has an R/P ratio of 95. If you think
those R/P ratio numbers are even remotely correct then I have a bridge I would like to sell
you.
I agree that the R/P numbers seem very suspicious. But if this is true then OPEC reserves
are closer to 400-500 billion barrels not 1.2 trillion barrels. That would give us another
trillion barrels at best to consume in the future in addition to the 1.3 trillion already
consumed. This brings the URR to 2.2-2.5 trillion barrels at best including extra heavy. What
do you think of the URR of 3.1 trillion barrels that is commonly assumed? Also canadian tar
sands and venezuelan heavy oil have very low EROI which brings down the extractable oil
reserves further. Do you think that is taken into account?
This fallacious narrative of the U.S. tight oil industry overcoming the oil price crash of
2014 through innovation and better efficiency is the product of bundling various tight oil
basins under one umbrella and the presentation of the resulting production data as a proof U.S.
shale resiliency.
To properly understand the impact of the oil price crash of 2014 on U.S. tight oil
production one must focus on shale basins with sufficient operating history prior to the oil
price crash and examine their performance post the crash.
To that end, the Bakken and the Eagle Ford are the perfect specimen.
The Bakken and the Eagle Ford are the two oldest tight oil basins in the United States, with
the former developed as early as 2007 and the latter in 2010.
Examining the production performance of these two basins in the 4 years preceding the oil
crash and contrasting it to the 4 years subsequent to it, offers important insight as to the
resiliency of U.S. tight oil production in a low oil price environment.
... ... ...
Both the Bakken and the Eagle Ford grew at a phenomenal rate between 2010 and
2014. The Eagle Ford grew from practically nothing in 2010 to 1.3M barrels by 2014, while the
Bakken grew five fold from 190K barrels to 1.08M barrels. Following the collapse in oil prices
in late 2014, the Bakken and Eagle Ford growth continued for another year, albeit at a slower
pace, as the pre-crash momentum carried production to new highs. However, by 2016, both the
Bakken and the Eagle Ford went into a decline and have hardly recovered since. It took the
Bakken three years to match its 2015 production level, meanwhile the Eagle Ford production
remains 22% below its 2015 peak. During the pre-crash years these two fields grew by a combined
yearly average of 600K to 700K barrels from 2012 to 2014. Post the oil price collapse, this
torrid growth turned into a sizable decline by 2016 before stabilizing in 2017.
Growth in both fields only resumed in 2018 at a combined yearly rate of 210K barrels, a 70%
reduction from the combined fields pre-crash growth rate.
The dismal performance of these two fields over the last few years paints a different
picture as to U.S. tight oil resiliency in a low oil price environment. The sizable declines,
and muted production growth in both the Bakken and the Eagle Ford since 2014 discredit the leap
in technology and the efficiency gains narrative that has been espoused as the underlying
reason beyond the strong growth in U.S. oil production. As we expand our look into other tight
oil basins, it becomes apparent that it was neither technology or efficiency that saved the
U.S. tight oil industry, although these factors may have played a supporting role. In simple
terms, the key reason as to the strength of U.S. production since the 2014 oil crash is better
rock, or rather, the commercial exploitation of a higher quality shale resource, namely the
Permian oil field.
... ... ...
The Permian oil field, unlike the Bakken and the Eagle Ford, was a relative latecomer to the
U.S. tight oil story. It was only in 2013, only a year before the oil crash, that the industry
commenced full scale development of that giant field's shale resources. Prior to 2013, the
Permian lagged both the Bakken and the Eagle Ford in total tight oil production and growth. As
can be seen from the preceding graph, the oil crash had only a minor dampening effect on the
Permian oil production growth. By 2017, Permian tight oil growth resumed at a healthy clip, and
by 2018, Permian tight oil production growth shattered a new record with production
skyrocketing by 860K barrels in a single year to 2.76M barrels. This timely unlocking and
exploitation of the Permian oil basin masked to a large degree the devastation endured by the
Bakken and the Eagle Ford post 2014. In essence, the U.S. tight oil story has two phases
masquerading as one: the pre-2014 period marked by the birth and rise of the Bakken and Eagle
Ford, and the post-2014 period, marked by the rise of the Permian.
To speak of the U.S. tight oil industry as one is to mistake a long-distance relay race
for the accomplishment of a single runner.
The performance divergence between the Bakken, Eagle Ford, and the Permian has major
implications as to the likelihood of U.S. tight oil production suppressing oil price over the
medium and long term. A close examination of U.S. tight oil production data leads to a single
indisputable conclusion: without the advent of the Permian, the U.S. tight oil industry would
have lost the OPEC lead price war. Hence, it's a misnomer to treat the U.S. tight oil industry
as a monolith, in many ways, the Bakken and the Eagle Ford tight oil fields are as much a
victim of the Permian success as the OPEC nations themselves.
... ... ...
Considering that the majority of U.S. tight oil production growth is
generated by a single field, the Permian, changes in the growth outlook of this basin have
major implications as to the evolution of global oil prices over the short, medium and long
term. Its important to keep in mind that the Permian oil field, despite its large scope, is
bound to flatten, peak and decline at some point. While forecasters differ as to the exact year
when the Permian oil production will flatten, the majority agree that a slowdown in Permian oil
production growth will take place in the early 2020s.
According to OPEC (2018 World Oil Outlook), the Permian basin oil production curve is likely
to flatten by 2020, with growth slowing down from 860K barrels in 2018 to a mere 230K barrels
by 2020:
"... they expect maybe 200 kb/d higher output in the GOM and my interpretation of George Kaplan's and SouthLaGeo's recent comments is that flat or possibly declining GOM output is a more likely scenario. ..."
The EIA's STEO released today. https://www.eia.gov/outlooks/steo/
They forecast US C+C production to increase +0.79 million barrels per day during 2019
From Dec 2018 11.93 million barrels per day
To Dec 2019 12.72 million barrels per day
The EIA's forecast might not be too far off, but I think they expect maybe 200 kb/d
higher output in the GOM and my interpretation of George Kaplan's and SouthLaGeo's recent
comments is that flat or possibly declining GOM output is a more likely scenario.
"... By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg, NY. Originally published at DeSmog Blog ..."
"... Hints that gas investors are no longer happy with growth-at-any-cost abound. For starters, several major natural gas producers have announced spending cuts for 2019. After announcing layoffs this January, EQT, the largest natural gas producer in the U.S., also promised to decrease spending by 20 percent in 2019. ..."
"... As DeSmog has reported, the historically low interest rates following the 2008 housing crisis were a major enabler of the free-spending and money-losing attitudes in the shale industry. Wall Street has funded a decade of oil and gas production via fracking and incentivized production over profits. Those incentives have worked, with record production and large losses. ..."
"... However, much like giving mortgages to people without jobs wasn't a sustainable business model, loaning money to shale companies that spend it all without making a profit is not sustainable. Wall Street investors are now worried about getting paid back, and interest rates are rising for shale companies to the point that borrowing more money is too financially risky for them. And because they aren't earning more money than they spend, these companies need to cut spending. ..."
"... The days of unlimited low-interest loans for an industry on a decade-long losing streak might be coming to an end. As Bloomberg credit analyst Spencer Cutter explained to CNN : "Investors woke up and realized this was built on debt." ..."
"... One reason natural gas is so cheap right now is that fracking for oil in the U.S. ends up producing huge amounts of gas at the same time. This gas that comes out of the wells with the oil is known as "associated gas." And it is so plentiful that in places like the Permian Basin in Texas, the price of natural gas has actually gone negative . Paying someone to take the product that a company spent money to produce is not a sustainable business model. ..."
"... While U.S. politicians from both parties have given standing ovations for the U.S. oil and gas industry , investors appear to be losing their enthusiasm. The so-called shale revolution, the fracking miracle, may have resulted in record oil and gas production in North America, but the real miracle -- in which shale companies make money fracking that oil and gas -- has yet to occur. ..."
"... This has long been one of my concerns in the field. I've long held that the federal government should simply outlaw the practice, forcing drillers to find something to do with the gas (bury it, ship it or use it to create electricity). At the very least, it should be prohibited on federal lands as part of the contracts that are signed. ..."
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg,
NY. Originally published at
DeSmog Blog
The fracked gas industry's long borrowing binge may finally be hitting a hard reality:
paying back investors.
Enabled by
rising debt , shale companies have been achieving record fracked oil and gas production,
while promising investors a big future payoff. But over a decade into the "
fracking miracle ," investors are showing signs they're worried that payoff will never come
-- and as a result, loans are drying up.
Growth is apparently no longer the answer for the U.S. natural gas industry, as Matthew
Portillo, director of exploration and production research at the investment bank Tudor,
Pickering, Holt & Co., recently told The Wall Street
Journal .
"Growth is a disease that has plagued the space," Portillo said. "And it needs to be cured
before the [natural gas] sector can garner long-term investor interest."
Hints that gas investors are no longer happy with growth-at-any-cost abound. For starters,
several major natural gas producers have
announced spending cuts for 2019. After
announcing layoffs this January, EQT, the largest natural
gas producer in the U.S., also promised to decrease spending by 20 percent in
2019.
Such pledges of newfound fiscal restraint are most likely the result of natural gas
producers' inability to borrow more money at low rates.
As
DeSmog has reported, the historically low interest rates following the 2008 housing crisis
were a major enabler of the free-spending and money-losing attitudes in the shale industry.
Wall Street has funded a decade of oil and gas production via fracking and incentivized
production over profits. Those incentives have worked, with record production and large
losses.
However, much like giving mortgages to people without jobs wasn't a sustainable business
model, loaning money to shale companies that spend it all without making a profit is not
sustainable. Wall Street investors are now worried about getting paid back, and interest rates
are rising for shale companies to the point that borrowing more money is too financially risky
for them. And because they aren't earning more money than they spend, these companies need to
cut spending.
CNN
Business recently reported that oil and gas companies stopped borrowing money in October
2018, but not out of restraint. Instead, CNN wrote, "investors, fearful of defaults, demanded a
hefty premium to lend to energy companies."
The days of unlimited low-interest loans for an industry on a decade-long losing streak
might be coming to an end. As Bloomberg credit analyst Spencer Cutter explained
to CNN : "Investors woke up and realized this was built on debt."
Canada's Natural Gas Market Facing 'A Daunting Crisis'
Prospects for natural gas don't look much better north of the U.S. border. Like the Canadian tar
sands oil market , the Canadian natural gas market is also in the midst of a long losing
streak. The problems facing the natural gas market in Alberta, Canada, is "far worse than it is
for oil," said Samir Kayande, director at RS Energy, according
to Oilprice.com .
Canadian natural gas producers are being crushed by the free-spending American companies
that could produce records amounts of gas at a loss while using borrowed money.
One reason natural gas is so cheap right now is that fracking for oil in the U.S. ends up
producing huge amounts of gas at the same time. This gas that comes out of the wells with the
oil is known as "associated gas." And it is so plentiful that in places like the Permian Basin
in Texas, the price of natural gas has actually
gone negative . Paying someone to take the product that a company spent money to produce is not a
sustainable business model.
Additionally, the U.S. oil and gas industry chooses to flare large
amounts of natural gas in oil fields because it's cheaper than building the necessary
infrastructure to capture it -- literally burning its own product instead of selling it. And the Canadian producers, who used to sell gas to the U.S. market, simply can't
compete.
A natural gas advisory panel to Alberta's energy minister addressed the crisis for Canadian
natural gas producers in the December 2018 report "
Roadmap to Recovery: Reviving Alberta's Natural Gas Industry ." The report's opening line
summarizes the problem:
" Traditional markets for Alberta natural gas are oversupplied. Prices, and therefore
industry and government revenues, are crushingly low and have been increasingly volatile
locally since the summer of 2017."
Noting the dire situation, one natural gas executive
predicted that "this will only get worse in 2019." Too much supply, not enough demand. To remedy this problem, the report recommended expanding supply, decreasing regulation, and
bailing out companies with financial backing from the government, with the ultimate goal of
producing more gas and exporting it to Asia.
With Alberta's reliance
on oil and gas to support its economy, it is easy to see why its politicians are loathe to
recognize the economic realities of the natural gas (and tar sands oil) industries. However, some politicians feel the same way about the American coal industry, and that
is dying
primarily because renewables and natural gas are cheaper ways to produce electricity.
Desperate Times for Leading Gas Producer
Chesapeake Energy is often held up as a case study
for the fracking boom. It was a huge early financial success story (based on its stock
price, not actual profits), and in 2008, its then- CEO Aubrey McClendon, known as the "Shale
King," was the highest paid
Fortune 500 CEO in America. Since those high times, it has been a rough decade for Chesapeake. The stock price is near
all-time lows -- where it has remained for years.
Chesapeake has stayed afloat by borrowing cash and currently owes around $10 billion in
debt. Unable to make money fracking gas in America since the days of the Shale King, Chesapeake
has a new strategy -- fracking for oil.
The Wall Street Journal
recently reported this shift in Chesapeake's strategy, referring to it as "ill-timed" and
"straining already frayed finances."
But Chesapeake is all-in on this new strategy. According to The Wall Street Journal,
Chesapeake CEO Doug Lawler said the company "plans to dedicate at least 80 percent of 2019
capital expenditures to oil production because it sees crude as the key to a more profitable
future."
One of the top gas producers in America and a "fracking pioneer" is abandoning fracked gas
as a path to a profitable future. The fact that Chesapeake now believes fracking for oil is a
path to a profitable future -- despite all the evidence
to the contrary -- gives this move an air of desperation.
While U.S. politicians from both parties have given standing ovations for the
U.S. oil and gas industry , investors appear to be losing their enthusiasm. The so-called
shale revolution, the fracking miracle, may have resulted in record oil and gas production in
North America, but the real miracle -- in which shale companies make money fracking that oil
and gas -- has yet to occur.
The North American natural gas industry is facing a crisis with an oversupplied market and
producers that are losing money. Those producers desperately need higher natural gas
prices. However, higher gas prices mean renewables become even more attractive to investors, which
may lead to gas following in the footsteps of coal -- dying at the hands of the free
market. It may take some time, but eventually investors wake up -- or run out of money.
I no longer wonder why US press treats the Nord Stream 2 as "controversial" with this glut
of debt fuelled natl. gas. Instead, the media should be clamoring against gas flaring, a
practice that should be banned. ClimateChange101 regulation.
It does illustrate what any Green New Deal would be up against. Not only are simple
environmental steps like no flaring opposed, but investors and drillers cling to an
extraction process that doesn't even make money rather than give in to a more rational,
government planned energy system. You begin to think it's not even about the money but more
about who's in charge. Before we conquer AGW we may have to conquer human nature. The
assumption behind the GND and indeed all AGW activism seems to be that if the world is just
shown the rational path then the world will take it. The above illustrates how very
irrational the world really is.
But the real miracle -- in which shale companies make money fracking that oil and gas --
has yet to occur.
Which will be a miracle.
I was involved in the service part of the Peace River area gas extraction (and some oil)
since the early 1980, and also when the shale gas extraction started in the early 2000's with
horizontal drilling changing the face of gas production.
By 2006/8 there was talk after heavy investment by Petronas of up to TEN LNG plants at the
west coats in the Kitimat area not one has been build to date, no pipeline exists and no
means to get any gas to market other than to the internal Canadian and the now oversupplied
US market. It was a failure of politicians and regulatory agencies to speed up the
permissions and likely as well the dithering by investors, that now Australia has taken on
the supply of the Asian market.
Granted they are speaking of Canada as the source of bailout, but the country will be
bailing globalist investors which maybe has gone on long enough? Anyway, the same neoliberal
playbook "I got your free market right here shame if somethin' was to happen to it "
To remedy this problem, the report recommended expanding supply, decreasing
regulation, and bailing out companies with financial backing from the government, with the
ultimate goal of producing more gas and exporting it to Asia.
This has long been one of my concerns in the field. I've long held that the federal
government should simply outlaw the practice, forcing drillers to find something to do with
the gas (bury it, ship it or use it to create electricity). At the very least, it should be
prohibited on federal lands as part of the contracts that are signed.
>in the U.S. ends up producing huge amounts of gas at the same time.
And thus they were family-blogged. For the simple reason that this wasn't your, let alone
your father's "oil bidness" anymore. Once upon a time wells were dug for water. You pumped water out, more seeped in. Should
have been forever but well that's another discussion. Then you dug wells for oil. They were finite, but they lasted decades. Now you think you are "digging wells", but what you really are doing is building an
underground factory. In a factory, you seed the inventory and say "go" and stuff comes out
the other end. To make another batch the crank needs to be turned again.
They don't have any model in their heads that matches this. Thus they wind up with what to
a manufacturer is obviously "scrap" production, aka stuff that they don't have a market for.
Why it took Wall Street so long to understand this is a mystery, except I do wonder if many
of them knew it but just wanted to "screw the greenies". They aren't going to miss any meals,
so why not I guess.
This is just f*&%"#g depressing. A decade of using debt that will be never be paid
back to put carbon into the atmosphere that will never go back in the ground, sometimes not
even extracting the energy from it first. We deserve what is coming.
I read "investors are showing signs they're worried that payoff will never come" as
"investors can't borrow money for cheap anymore now that the Fed has raised rates". If the Fed were to reverse course and CUT interest rates, the party will continue. Wanna
bet? In another topic, how would MMT prevent people from investing in fracking?
Talking to a 2nd or 3rd generation owner of a small family run oil and gas company that
maintains local wells about 8 months ago. I expressed my concern about fracking locally. He
laughed. Then said in a serious and not at all condescending tone that there is no money
going into fracking at these NG prices and it's unlikely to change in the future. He went on
to explain where the deposits were, the expense and environmental issues the large frackers
are up against and basically said he doesn't see a scenario where it's ever expanded close to
populated areas, if it recovers at all. He genuinely didn't see much future in it.
Of course there is no future in it. Shale deposits are vertically small that horizontally
extend large distances, which means horizontal drilling. Not only that, usually you need
parallel wells for water injection to force the oil or gas out. The cost are much greater
compared to conventional vertical drilling with the technical solutions necessarily involved.
The wells deplete rapidly within a few years, requiring new wells.
I have been on sites in the Peace where wells were producing mainly water after three
years.
Those opposed to fracking for environmental reasons should perhaps also consider opposing
it on national security grounds, since, given the limitations/costs of fracking, those
resources should be seen as emergency rations, to be tapped only when absolutely
necessary.
That fracked oil and gas is being spewed into the atmosphere when prices are low and
falling, and more easily-obtained stocks are plentiful elsewhere, is just compounding the
mania with insanity.
It also suggests to me that, since there isn't real money being made, there are
geo-strategic, National Security State-related reasons for the US' sudden impulse to jack up
oil production.
These Wall Street fracking and shale subsidies percolate through the entire economy. In
addition to obvious hangers-on like the automobile industry, you have privately owned
electrical utilities rushing to load up on as much stranded asset, centralized fossil fuels
generation and distribution infrastructure as they can jam through their respective state
public utilities commission before the gas bubble bursts.
What is important here is extending and preserving stock price rallies, elevated CEO
salaries and coupon-clipping opportunities for rentiers as possible, not economic
efficiency in any form that could be understood by anyone but bankers and financiers.
> Are Investors Finally Waking up to North America's Fracked Gas Crisis?
No, because they are not investors but gamblers.
Wall Street has funded a decade of oil and gas production via fracking and incentivized
production over profits.
More to the point, no Wall Street criminal was harmed because not one was stupid enough to
throw his or her own money on the roll of the dice, but they certainly took the gamblers
money and for a fat fee, throw the dice for them.
This is getting old. Why does anyone believe in free-market economics in an emergency?
It's puzzling that just when oil went into a huge glut and the heavy, full-to-the-brim
tankers lined up in all the deep ports, like treasure chests, and the price of oil dropped
because the global economy had been slashed by a third it was just at this time that Obama
made his panicked decision to frack, to deregulate, and to subsidize it. So these so-called
"investors" who are raising their prices for loans, have either seen demand come back and
want their fair share of the whole ponzi operation, or the QE that facilitated it all has
been tapped out politically, regardless of the economics. No one seemed to care that all the
natgas blown off each well was accelerating the CO2 effect, measurably. No one cared about
the polluted ground water. Nobody acknowledged that Germany didn't want our LNG. Only free
money could have caused this perversion of productivity, all this destruction, this gold rush
to nowhere. Our sovereign money should be distributed wisely. Never like this. And never into
a deregulated market.
Yikes, ugh, and AAARRRRRGH! Not the 1st I've heard of this (Gas Bubble), but this nails it
all down.
Was this (partly/directly) caused by QE? My impression is that QE pumped a bunch of
"money" into the top end of the economy (Assets/Wall Street), propping up the Stock Market,
but I've never gotten exactly HOW they did it.
Did the Fed just buy lotsa Stock (or Corp Bonds)? If so, did they (partly) create the Gas
Bubble by (over-) investing in Fracking companies? If so, they are now stuck bursting that
bubble as they "De-QE"; either they (We!) get out of that market early – blowing it up
sooner – or wait until it deflates "normally" and lose a bunch of (Our?) money.
Are the details of QE (how much of which assets the Fed bought) public?
Nations should explore better system to break US hegemony
"The US dollar is used for the international oil and gas trade and a wide part of global
trade. This gives the US an exorbitant privilege to sanction countries it opposes.
..
The latest sanctions on Venezuela's state-owned oil company aim to cut off source of foreign
currency of Venezuelan strongman Nicolas Maduro's government and eventually force him to step
down.
..
A new mechanism should be devised to thwart such a vicious circle"
My question is really about those at the top of the power pyramid (those few hundred
families who own the controling share of the wealth of the world) -- those who position
idiots like Bolton to do their work, do they comprehend 'exergy' decline ?
If we can, then can they not? I agree with Parenti that they are not
'somnambulists'. They are strategists looking out for their own interests, and that means
scrutinising trends in political movements, culture, technology and, well, just about
everything. I find it hard, the idea that all these people -- people who have seen their
businesses shaped by resource discovery, exploitation and then depletion, have no firm grasp
on the realities of dwindling returns on energy.
The models were drawn up 47 years ago. I think that some of them at least, do
understand that economic growth is coming to a halt, and have understood for decades. If true
then they are planning that transition in their favour.
These hard to swallow facts about oil are still on the far fringes of any political
conversation. The neoliberal cultists are deaf to them for obvious reasons; the socialist
idealists believe that a 'New Deal' can lead us off the death train, but mostly ignore the
intractable relationship between energy decline and financial problems; even the anarchists
want their work free utopia run by robots and AI but stop short of asking whether solar
panels and wind turbines can actually provide the power for all that tech. It's the news that
nobody wants to think about, but which they will be forced to thinking about in the very near
future.
The Twitter feed 'Limits to Growth' has less than 800 followers (excellent though it
is).
I do not want to get into the mind of the Walrus of Death Bolton! I do not want to know
what he does, as he does. But at lower levels of government, and corporatism, there is an
awareness of surplus energy economics. And as Nafeez has also pointed out, the military (the
Pentagon) are taking an interest. And though it could rapidly change, who really appreciates
the nuances of EROEI? I'm guessing at less than a single percent of all populations? And how
many include its effects in a integrated political sense?
Its appreciation is sporadic: ranging from tech-utopia hopium to a defeated fatalism of
the inevitability of collapse. Unless and until people want to face the harshness of the
reality that capitalism has created: we are going to be involved in a marginal analysis.
There are very few people who have realised that capitalism is long dead.
Dr Tim Morgan estimates that world capitalism has conservatively had $140tn in stimulus
since 2008 -- without stimulating anything or reviving it at all. In fact, that amounts to
the greatest robbery in history -- the theft of the future. Inasmuch as they can, those
unrepayable debts -- transferred to inflate the parasitic assets of capitalists -- will be
socialised. Except they cannot be. Not without surplus energy.
Brexit, gilets jaunes, Venezuela, unending crises in MENA, China's economic slowdown, etc
-- all linked by EROEI.
It is a common socio-politico-economic energy nexus -- but linked together by whom? And
the emergent surplus energy-mind-environmental ecology nexus? All the information is
available. The formation of a new political manifesto started in the 1960s with the New Left
but it seems to have been in stasis since. Perhaps this might stimulate the conversation.
According to Nate Hagens: there is 4.5 years of human muscle power leveraged by each
barrel of oil. We are all going to be working for a very long time to pay back the debts
the possessing classes have built up for us -- with absolutely no marginal utility for
ourselves.
We are subsidising our own voluntary slavery unless we develop an emergent ecosocialist
and ecosophical alternative to carbon capitalism. We cannot expect paleoconservative carbon
relics like Bolton -- or anyone else -- to do it for us. The current political landscape is
dominated by a hierarchical, vested interest, carbon aristocracy. We can't expect that to
change for our benefit any time ever. Expect the opposite.
Graeber has a point, though. We could already have a post-scarcity, post-production society
but for the egregious maldistribution of resources and employment. Andre Gorz said as much 50
years ago (Critique of Economic Reason). Why do we organise around production: it makes no
sense but for the relations of production are, and remain, the relations of hierarchical
rule. So long as we assign value to a human life on the basis of meritocratic productivity --
we will have dehumanisation, marginalisation, and subjugation (haves and have nots). So why
not organisation around care, freedom and play?
Such a solution would require the transversalistion of society and not-full-employment: so
that no part of the system is subordinate, and no part is privileged. All systems and
sub-ordinate (care) systems would be co-equal, of corresponding value and worth. So, without
invoking EROEI, that would go a long way to solve our exergy, waste, pollution, and
inequality problems. It is the profligate, unproductive superstructure: supporting rentier,
surplus energy accumulating, profit-seeking suprasocieties -- that squanders our excess
energy and puts expansive spatio-temporal pressures on already stretched biophysical
ecological systems that engenders potential collapse. It is their -- the possessing classes
-- assets that are being inflated, at our environmental expense. When it comes to
survivability, we cannot afford a parasitic globalised superstructure draining the host --
the ecologically productive base. Without the over-accumulation, overconsumption, and wastage
(the accursed share) associated with the superstructure of the advanced economies -- and
their cultural, credit, military imperialisms I expect we could live quite well. Without the
pressures of globalised transportation networks, and unnecessary military budgets -- the
pressure on oil is minimised. It could be used for the 1001 other uses it has, rather than
fuelling Saudi Eurofighters bombing Yemeni schoolchildren, for instance. The surplus energy
could be used to educate, clothe and feed them instead. That would be a better use of
resources, for sure.
If we took stock of what we really have, and what we really are -- a form of spiritual
neo-self-sufficiency, augmented and extended into co-mutual care and freedom valorising
ecologies we wouldn't need to chase the perceived loss all over the globe, killing everything
that moves. The solutions are not hard, they are normative, once we are shocked out of this
awful near-life trance state of separationism. Thanks for the link.
It seems to me that there are two parallel arguments going on.
One is about social organisation, attitudes towards and policies determining work, money,
paid employment, technological development and the distribution of weath.
The other is fundamentally based on the laws of thermodynamics and concerns resource limits,
energy surpluses, the role of 'stored sunlight' in producing things and doing work for each
other, pollution and projections about these into the future.
I am surprised that Graeber (just as an example) seems to basically ignore the second of
these even though he clearly is an incisive thinker and makes good points about the first. It
is taken as a given that, theoretically at least, human civilisation could re-organise around
a new ethic, transform the economy into a 'caring economy', re-structure money, government
and do away with militarism. In terms of what to do now, as an individual, what choices to
make, it is disconcerting to me when talk of these ideals seems to ignore those latter
questions about overshoot.
I wonder if the egalitarian nature of much of indiginous North American society was
inescapably bound with the realities of a low population density, low technology,
intimate relationship with the natural world and a culture completely steeped in reverence
for Mother Earth.
The talk I hear from Bastani or Graeber along the lines of 'we could be flying around in jet
packs on the moon, if only society was organised sensibly' rings hollow to me.
Welcome to my world! Apart from as a managerial tool, systems thinking has yet to catch on
in the wider population. According to reductive materialism: there are two unlinked
arguments. According to Dynamic Systems Theory (DST) there is only one integrated argument --
with two inter-connected correlative aspects. We can only organise around what we can
energetically afford. Consequently, we cannot organise around what we cannot afford -- that
is, global industrialised production with a supervenient elitist superstructure.
Let's face it : ethical arguments carry little weight against organisation around
hierarchical rule. The current talk of an ethical capitalism -- in mixed economies with
'commons' elements -- is an appeasement. and distractional to the gathering and ineluctable
reality.
The current (2012) EROI for the UK is 6.2:1 -- barely above the 'energy cliff' of 5:1. The
GDP 'growth' and bullshit jobs are funded by monetised debt (we borrow around £5 to
make every £1 -- from Tim Morgan's SEEDS). From the Earth Overshoot Day website: the UK
is in economic overshoot from May 8th onward.
These are indicators that we will not be "flying jetpacks on the moon": even if we
reorganise. Everyone, and I mean everyone, will have to make do with less. A lot less.
Everything would have to be localised and sustainable. Production would be minimised, and not
at all full. Two major systems of production -- food (agroecology) and energy -- would have
to be sustainable and self-sovereign. And financialisation and the rentier, service economy?
Now you can see why no one, not even Dave the crypto-anarchist, is talking about reality.
Elitism, establishment and entitlement do not figure in an equitable future. We can't afford
it, energetically or ethically.
So when will the debate move on? Not any time the populace is bought into ideational
deferred prosperity. All the time that EROEI is ignored as the fundamental concept governing
dwindling prosperity -- no one, and I mean no one, will be talking about a minimal surplus
energy future. The magic realism is that the economic affordances of cheap oil (unsustainably
mimicked by debt-funding) will return sometime, somehow (the technocratic superfix). The
aporia is that the longer the delay, the less surplus energy we will have available to
utilise. Something like the Green New Deal -- that has been proposed for around two decades
now -- may give us some quality of life to sustain. Pseudo-talk of a Customs Union, 'clean'
coal, and nuclear power, will not.
An integrated reality -- along the model of Guattari's 'Three Ecologies' -- of mind,
economy, and environment is well, we are not alone, but we are ahead of the curve. The other
cultural aporia is that we need to implement such vision now. Actually, about thirty years
ago but let's not get depressive!
We are going to need that cooperative organisation around care and freedom just to get
through the coming century.
As mentioned elsewhere here, Venezualan oil deposits are not all that the hype cracks them up
to be. They are mostly oil sands that produce little in the way of net energy gain after the
lengthy process of extraction.The Venezuala drama is about the empire crushing democracy
(i.e. socialism), not oil. [not that this detracts from Kit's essential point in the
article].
The Left (as well as the Right), by and large have not come to terms with the realities of
the decline in net surplus energy that is unfolding around the world and driving the
political changes that we see. So they still view geopolitics in terms of the oil economy of
pre-2008.
The productive economies of Europe are falling apart (check Steve Keen's latest on Max and
Stacy -- although even i he doesn't delve into the energy decline aspect).
The carbon density of the global economy has not changed in the 27 years since the founding
of the UNFCCC.
The Peak Oil phenomenon was oversimplified, misrepresented and misunderstood as a simple
turning point in overall oil production. In truth it was a turning point in energy
surplus.
I predict that by the end of this or next year, everyone will be talking about ERoEI.
Everyone will realise that there is no way out of this predicament. Maybe there are ways to
lessen the catastrophe, but no way to avert it. This will change the conversation, and even
change what 'politics' means (i.e. you cannot campaign on a 'new start' or a 'better,
brighter future' if everyone knows that that physically cannot happen).
Everyone will understand that their civilisation is collapsing.
Does Bolton understand this?
If you were referring to my earlier comments about Venezuelan extra heavy crude: it's
still massively about the oil. The current carbon capitalist world system does not understand
surplus energy or EROEI, as it is so fixated on maximal short term returns for shareholders.
It can't comprehend that their entire business model is unsustainable and self cannibalising.
Which is bad for us: because carbon net-energy (exergy) economics it is foundational to all
civilisation. The ignorance of it and subsequent environmental and social convergence crises
threatens the systemic failure of our entire civilisation. The Venezuelan crisis affects us
all: and is symptomatic of a decline in cheap oil due to rapidly falling EROEI.
I can't find the EROEI specifically for Venezuelan heavy oil: but it is only slightly more
viscous than bitumen -- which has an EROEI of 3:1. Let's call it 4:1: the same as other tight
oils and shale. Anything less than 5:1 is more or less an energy sink: with virtually no net
energy left for society. The minimum EROEI for societal needs is 11:1. Does Bolton understand
this? Francis hit the nail on the head there.
Do any of our leaders? No. If they did, a transition to decentralisation would be well
under way. Globalised supply chains are systemically threatened and fragile. A globalised
economy is spectacularly vulnerable. Especially a debt-ridden one. Which way are our leaders
trying to take us? At what point will humanity realise we are following clueless Pied Pipers
off the Seneca Cliff -- into globalised energy oblivion?
The rapid investment -- not in a post-carbon transition -- but in increased
militarisation, and resource and market driven aggressive foreign intervention policies
reveal the mindset of insanity. As people come to understand the energy basis of the world
crisis: the fact of permanent austerity and increased pauperisation looms large. What will
the outcome be when an armed nuclear madhouse becomes increasingly protectionsist of their
dwindling share? Too alarmist, perhaps? Let's play pretend that we can plant a few trees and
captive breed a few rhinos and it will all be fine. BAU?
The world runs on cheap oil: our socio-politico-economic expectations of progress depend
on it. Which means that the modern human mind is, in effect, a thought-process predicated on
cheap oil. Oleum ergo sum? Apart from the Middle East: we are already past the point where
oil is a liability, not a viability. Debt funding its extraction, selling below the cost of
production -- both assume the continual expansion of global GDP. Oil is a highly subsidised
-- with our surplus socialisation capital -- negative asset. We foot the bill. A bill that
EROEI predicts will keep on rising. At what point do we realise this? Or do we live in hopium
of a return to historical prosperity? Or hang on the every word of the populist magic realism
demagogue who promises a future social utopia?
EROEI = Energy Returned on Energy Invested (also known as EROI = Energy Return on Investment)
EROEI refers to the amount of usable energy that can be extracted from a resource compared
to the amount of energy (usually considered to come from the same resource) used to extract
it. It's calculated by dividing the amount of energy obtained from a source by the amount of
energy needed to get it out.
An EROEI of 1:1 means that the amount of usable energy that a resource generates is the
same as the amount of energy that went into getting it out. A resource with an EROEI of 1:1
or anything less isn't considered a viable resource if it delivers the same or less energy
than what was invested in it. A viable resource is one with an EROEI of at least 3:1.
The concept of EROEI assumes that the energy needed to get more energy out of a resource
is the same as the extracted energy ie you need oil to extract oil or you need electricity to
extract electricity. In real life, you often need another source of energy to extract energy
eg in some countries, to extract electricity, you need to burn coal, and in other countries,
to extract electricity you need to build dams on rivers. So comparing the EROEI of
electricity extraction across different countries will be difficult because you have to
consider how and where they're generating electricity and factor in the opportunity costs
involved (that is, what the coal or the water or other energy source -- like solar or wind
energy -- could have been used for instead of electricity generation).
That is probably why EROEI is used mainly in the context of oil or natural gas
extraction.
@Ilyana_Rozumova Despite huge increases in domestic oil production in the last years the
USA is still the second largest net oil importer in the word (behind China).
Also the USA is extracting its proven reserves at a much faster rate than any other large
producer (a pattern it also had in the past, leading to high fluctuation in its production)
so unless new reserves are discovered US production will likely start to decline again within
a few years.
@Ilyana_Rozumova Condensate, not oil. Only good for gas or lighter fluid. It may be
called oil but that's a deliberate misnomer.
Only financial engineering makes it appear profitable. Its a money losing psychopaths
power play, not a business. Without a heavy real oil to blend it with its useless, heavy oil
is where Venezuela comes in.
@Ilyana_Rozumova "Main factor here is that US due to fracking become self sufficient,
what actually nobody could foresee. Just a bad luck".
Bad luck for the USA. They have fallen into an elephant trap, because fracking has already
become unprofitable and is only being financed by ever-increasing debt.
Admittedly this gives them some advantage, but only in the very short term.
Of course, it doesn't really matter – in the short to medium term – whether
fracking is profitable or grossly unprofitable. They can still pay for it by printing more
dollars, as long as the "greater fools" (or heavily bribed officials) in other countries go
on accepting dollars.
"America's energy security just got a lot more secure . Located in the Wolfcamp Shale
and overlying Bone Spring Formation, the unproven, technically recoverable reserves are
officially the largest on the planet."
None of these breathlessly optimistic articles say how expensive it will be to get this
oil. If a dollar's worth of oil costs you more than a dollar to recover, you are obviously
losing in the deal. If you print the dollars, your entire economy loses.
"... Big oil has its benefits, and this benefit fits into big oil's need for future existence. When the price of oil goes up, then what's the projected stock price of Exxon or Chevron? They will be back into the mode they were in decades ago, start to finish. ..."
Motiva had previously upgraded refinery capacity to accept light oil, Exxon keeps adding
more, and now Chevron will, no doubt, expand.
Maybe the big oil will buy up some more of the weaker Permian players, which could slow
down the insane growth; and make the Permian more of a feeder for their refineries than an
export source. I really can't imagine that they are spending billions on refineries with the
expectation that it may start to expire in five years. Exxon and Chevron are already two of
the top ten producers in the Permian, and they can get bigger, if they want to.
Gobbling up most of these producers would only amount to a snack for them. And doing it
while the pure Permian producers a floating in the doldrums of 2019 would fit perfectly.
That could affect projections for US shale growth. The refiners would look at it over a
longer term usage, and not how much they can ship out. However, it could still lower net
imports. Win, win.
Thus, possibly saving West Texas from extinction, and move away from boom or bust some.
Add pipelines to the East and West coast, and upgrade refineries, and you have a longer term
solution.
With Canadian and Mexican heavy oil and sprinkle in some EOR, we could get by for a longer
period of time. Peak oil is a meaningful event, but it does not, absolutely, have to affect
the US for a while.
On a different topic, a Japanese company is interested in becoming an Eagle Ford player.
Japan needs LNG. Eagle Ford has a largely untapped huge gas window. So, even if we do not use
the planned upgraded ports for oil, we may still be using them for LNG.
Ok, it's only a dream, now, but the parts are beginning to come together. Big oil has
its benefits, and this benefit fits into big oil's need for future existence. When the price
of oil goes up, then what's the projected stock price of Exxon or Chevron? They will be back
into the mode they were in decades ago, start to finish.
This rings true to me. The big boys have few other options left for expansion (Guyana, Mexico
and/or Brazil if they can work their way through the corruption) other than the Permian. Oil
prices are likely to remain volatile for the foreseeable future, generating occasional buying
opportunities for companies with lots of cash on hand. Kind of the way the tech giants like
Apple and Amazon and Facebook bought up all the small fry app/tech companies for lack of
anything better to do with their money. If this happens I would expect a slower pace of
development to emerge for tight oil over the next decade and a longer tail.
Yeah, that's what I'm thinking. Make peak closer to the time period of somewhere pretty
close. I think we better move, we may be sitting to close to that smelly fan.
Chevron's holdings are the size of Yellowstone, and Exxon is not far behind. Will they
pick up any additional acreage if the get a good buy? Does a dog bark?
This says nothing about the quality of rock, but lists acreage by the top holders. Oxy,
ConocoPhillips, and EOG will be more conservative in development, and are not really prime
acquisition targets. But adding them and Exxon and Chevron, you get most of the acreage.
Energen and Diamondback have merged.
Leach, chairman and chief executive officer of Concho Resources, cited statistics
indicating Permian Basin crude production is expected to climb from the current 4 million
barrels a day to 6 million barrels a day in just six years. That, he told the sold-out crowd
at the Horseshoe, would comprise 7 percent of total world oil production and 40 percent of
U.S. production. In addition, the Permian Basin could see 45,000 new high-paying technical
jobs on top of the 50,000 jobs that have been created since about 2000.
"Companies operating here today will be investing $50 billion a year in drilling and
completing wells," leading to over $1 trillion in spending in that same timeframe, he said.
That has created numerous opportunities throughout the Permian Basin, but also significant
challenges, he said.
When he and other leaders of local oil companies review their business plans and consider
their greatest concerns, he said it's not sand or pipeline capacity or technology.
"Collectively, they say it's schools, roads, doctors and housing."
The problem is that the decline of the conventional fields does not sleep...
Notable quotes:
"... If it takes more energy to extract the oil from shale than you get from the oil you pump out then it is a sink, not a source. For instance it would be extremely difficult to extract oil from offshore shale. You would have to ship the sand out by barge, build huge platforms for every well to hold all that fracking equipment and so on. ..."
"... Return on investment is the primary problem with shale. If it cost more in time and energy than you receive from the extracted producte, it will stay in the ground. Anyway, that's just my unprofessional opinion. Some of the professionals on this blog may have a better educated opinion. ..."
"... New shale production, which is subject to extraordinarily fast decline in and of it self, would have to be brought online fast enough to offset both its own decline PLUS the decline of the worlds giant conventional legacy oil fields. ..."
"... Even if it's profitable to do so, and in large enough quantities, at some particular price, this does not necessarily mean that it will be possible to muster enough capital, equipment, skilled labor, and political will to make it happen FAST ENOUGH to offset conventional legacy oil declining production. ..."
"... I have read from news lately a more strict requirements from investors, banks, hedge funds makes it reasonable that investment in shale oil compeared to 2018.budget will be reduced by 19%. ..."
"... I doubt there will be lots of investments in US shale with oil price in range 50-60 USD, because there is significant documentation only a very limited part ( decreasing) within core area is profitable as of now. Beside this a oil price in range 50-60.WTI or 55- 65 usd each barrel Brent is not enough to pay the cost of exploration drilling offshore, build new infra structure. ..."
New here, been lurking for a while. I'm a geologist with a small oil and gas exploration and
operating company. We explore conventional only. I have however read all your predictions of
peak oil etc. but don't you think that given higher prices, other basins world wide that are
similar to the Permian could be successfully exploited for years to come holding off peak oil
for decades? I'm no expert but I would venture there are hundreds of basins that could as
good or better than the Permian. Just in the U.S., we have the Permian, Bakken, Niobrara,
Eagleford and about a dozen others. Surely our success could be duplicated on a global scale
if the price was right.
There is the Vaca Muerte in Argentina, but probably under the scale of the Eagle Ford. There
are a LOT of contraints holding the dead cow back. A lot of countries I have heard of that
have gas potential, e.g. China, even UK. But, I have not heard of a lot of oil potential. The
way my limited understanding goes, the play has to be new enough on the geological age, to
still have oil. As in, the Eagle Ford has three windows which depend on geological age, and
pressure. The oil window is younger, the condensate and gas windows are older. I think the
Permian will have areas, too. But, I received my geology degree from a cracker jacks box
but your last sentence may hold some
validity. For that matter, I don't think shale has given up completely after the first go
round, if the price is right. Would that delay peak to another date? Quien sabe. Money talks.
What price? I know I would keep an ICE around for long trips at $200 a barrel for the
convenience. Food may be higher, though.
Speaking as a geologist, this is incorrect. Thermal maturity depends on far more than age. The Utica gas window is 300 million years older than the eagle fords gas window, just for
example.
Yes, of course there are more shale sources out there. But perhaps not as many as you think.
All reservoir rock is not so tight as to hold most of its oil in place. There is, or rather
was, lots of oil in West Texas but not much shale oil. The same is true for Southern
California. I suspect most of the Middle east is similar.
Also there is the cost. If it takes more energy to extract the oil from shale than you get
from the oil you pump out then it is a sink, not a source. For instance it would be extremely
difficult to extract oil from offshore shale. You would have to ship the sand out by barge,
build huge platforms for every well to hold all that fracking equipment and so on.
There are lots of shale oil sources in Russia. And if prices get high enough, they will
probably try to extract it. Imagine hauling train loads of sand to the north slope of Alaska,
then trucking it over the tundra by truck to every well. You would have similar problems in
Western Siberia.
Return on investment is the primary problem with shale. If it cost more in time and energy
than you receive from the extracted producte, it will stay in the ground. Anyway, that's just
my unprofessional opinion. Some of the professionals on this blog may have a better educated
opinion.
"If it cost more in time and energy than you receive from the extracted producte, it will
stay in the ground."
@Ron Patterson, you seem to be saying that extraction will go forward as long as there is
the potential for *any* marginal return, at least expressed in money if not in EROEI. So for
example, as long as I can charge $101 for a barrel of oil that cost me $100 to get out of the
ground, I'll keep doing it (or someone else will). Do you really think this is the case, or
is there a threshold/floor below which it won't make economic sense due to produce oil? Due
perhaps to knock-on factors in the larger economy? Obviously I'm no expert on any of this, so
please take it easy on me in any replies. Thanks!
Phil, I really have no idea at what point oil companies will decide it is not worth the
effort due to low profits or other causes, they will cease drilling. However it must be noted
that a majority of oil companies producing shale oil today are doing it at a loss. Of course
they all expect to be making money sometime soon. They expect prices to rise so they are just
trying to hang on until they are profitible.
So you see it is just not that simple. They may produce oil at a loss for some time before
they fold. But obviously they cannot produce oil at a loss forever. There are many factors
that govern their decision to fold their tents and walk away. I think it is impossible to
predict exactly at what or when that point is. At least it is beyond my ability to do so.
I don't have any better idea how much shale oil is out there, or whether it can be produced
profitably, than you do.
But I will add this much to the discussion. Even if it is out there , and can be produced profitably, this is no guarantee that shale
oil can prevent peak oil happening.
New shale production, which is subject to extraordinarily fast decline in and of it self,
would have to be brought online fast enough to offset both its own decline PLUS the decline
of the worlds giant conventional legacy oil fields.
Even if it's profitable to do so, and in large enough quantities, at some particular
price, this does not necessarily mean that it will be possible to muster enough capital,
equipment, skilled labor, and political will to make it happen FAST ENOUGH to offset
conventional legacy oil declining production.
It's been a while since I paid much attention to the actual numbers, but I know you are
well acquainted with them.
So what's your estimate, these days, of the conventional legacy oil decline rate? Have you
raised it or lowered it recently?
As I have read from news lately a more strict requirements from investors, banks, hedge funds
makes it reasonable that investment in shale oil compeared to 2018.budget will be reduced by
19%.
One significant player will reduce their number if riggs from 24 to 18 as they expect
oil price WTI in 2019 to be in mid 50 usd range.
To me it seems the confident among investors
to US shale have changed significant espesialy 4th quartile of 2018. Now they only want to
support projects that give cash return , seems they are tiered of promises as there have been
to much of and shale oil depth have never been higher.
Since oil demand is linked to groth
in world economy that is also same for interest of liability. EIA , and some other analyst
like Rystad sees US shale production in 2019 will continue with strong increase and predict
we only have seen the beginning. After working within oil and gaz projects in many years I
know the oil majours dont want to loose money ,when a project seems not profittable they stop
until oil price incresse or they get cost down.
I doubt there will be lots of investments in
US shale with oil price in range 50-60 USD, because there is significant documentation only
a very limited part ( decreasing) within core area is profitable as of now. Beside this a
oil price in range 50-60.WTI or 55- 65 usd each barrel Brent is not enough to pay the cost of
exploration drilling offshore, build new infra structure.
Karl- I see that you asked 'what' rather than when.
Seneca Cliff refers to a very rapid decline in a feature (such as global oil production)
after it has achieved a peak. This is as opposed to a very slow decline.
Obviously for oil, a fast decline would be catastrophic.
US production will be close to flat 2019, and if ports are not improved much until late
2020, then 2020 will not be great. After that, I don't see it catching up.
As stated many times on 'theoildrum', State of the art EOR projects deplete oilfields, who
without EOR would go in terminal decline much earlier, very rapidly. So a world oilproduction
cliff cannot be ruled out, especially if money reserves from oil companies dry up.
Oil prices are likely to rise if there is a shortage of oil, this will mean oil companies
will have plenty of financial resources as long as demand is sufficient to consume the oil
produced. Not suggesting there will not be a decline, just unlikely there will be a cliff
unless oil prices drop, so far there is no evidence of a cliff and given World stock level
trend, prices are unlikely to drop further and are more likely to increase in the future.
But to repeat a cliché: depletion never sleeps. Already about fifteen years ago EOR
projects were started that extracted oil from (quite) 'past peak' or 'on plateau production'
oilfields. EOR projects in case of 'quite past peak' fields, to get 'the last recoverable'
barrel out resulting in oil production/day far less than peak production.
I know, the recoverable quantity increases with rising oilprices and better extraction
techniques, but still the production/day way past peak will be much less than on peak.
What will happen when oilprices don't increase a lot for the next ten years, for a
combination of reasons ?
At a certain point in time all the money in the world couldn't prevent world production
decline and the further that point will be in the future, the steeper will be the decline I
think. So better sooner than later oilprices begin to increase significantly, to buy some
time for the transition to EV's, etc.
I am not an expert in engineering nor in geology, far from that, just expressing a feeling
that I got after having read the many posts on theoildrum regarding this matter.
"... The news that the Saudis will cut even more production than specified in their recent pledge in hopes of raising world prices to $80 a barrel was an important part of last week's price jump. Hopes that the US and China would settle their trade dispute during on-going talks was also an important factor in the recent price jump. ..."
"... While the US economy has been bumping along nicely in recent months, the same is not true for the other major centers of economic power – China and Europe. ..."
Oil prices continued to climb last week and are now some $10 a barrel higher than they were
just before Christmas when recent lows were set. Prices now have retraced about 30 percent of
the $35 a barrel drop that took place between late September and late December. Part of the
recent price correction likely is due to technical factors such as closing out long positions
in the futures markets. The news that the Saudis will cut even more production than specified
in their recent pledge in hopes of raising world prices to $80 a barrel was an important part
of last week's price jump. Hopes that the US and China would settle their trade dispute during
on-going talks was also an important factor in the recent price jump.
Looming over the talk about OPEC+ production cuts and how fast US shale oil production might
grow are the prospects for the global economy. A major recession could drive the demand for oil
so low that even current prices would be difficult to maintain. While there have always been
people convinced that a major economic crash is in the offing, in recent weeks there has been a
noticeable increase in the number and stridency of these predictions.
While the US economy has been bumping along nicely in recent months, the same is not true
for the other major centers of economic power – China and Europe. The Washington Post
headlines that "Economic growth is slowing all around the world," citing declines in the equity
markets; sputtering German factories, and Chinese retail sales growing at their slowest pace in
15 years. Even Beijing is looking for its GDP to grow by 6-6.5 percent this year which is way
off from the heady days of double digits ten years ago.
Eurozone economic forecasts fell last Monday again after a survey of economists found that
GDP is expected to grow just below 1.6 percent this year, 0.4 percentage points lower than an
already conservative estimate from March. A new report from the World Bank, citing a variety of
data, including softening international trade and investment, ongoing trade tensions, and
financial turmoil concludes that "the outlook for the global economy in 2019 has darkened."
Among the darker forecasts for the future are those that speculate on a global depression on
the scale of the 1930s where GDPs fall by 10 to 25 percent. Others are saying that the global
economy may be approaching " The Limits to Growth " as discussed in the famous 1972
book.
... ... ...
Virendra Chauhan of Energy Aspects told CNBC last week that "$50 oil is not a level at which
US producers can generate cash flow and production growth, so we do expect a slowdown." In a
Bloomberg radio interview John Kilduff, founding partner of Again Capital Management, said "we
were getting into the zone where U.S. shale producers stop making money particularly when you
sort of add in all the costs, not just the pure say drilling and extraction. It's going to
start to get tough for them right now."
... ... ...
Iran : Iran's crude exports dropped to 1 million b/d in November from 2.5 million b/d
in April, taking exports back to where they stood during the 2012-2016 sanctions. According to
three companies that track Iranian exports, Tehran's crude shipments remained below 1 million
b/d in December and are unlikely to exceed that level in January. Tracking
... ... ...
Iraq : Baghdad posted its highest monthly export total to date in December and,
combined with Kurdistan, set a nationwide annual record of 4.15 million b/d -- more than
100,000 b/d above the previous record, set in December 2016. The government said on Friday it
is committed to the OPEC+ output-cutting deal and would keep its oil production at 4.513
million b/d for the first half of 2019
... ... ...
Saudi Arabia : According to OPEC officials, Saudi Arabia is planning to cut crude
exports to around 7.1 million b/d by the end of January in hopes of lifting oil prices above
$80 a barrel.
... ... ...
Libya: Tripoli plans to pump 2.1 million b/d of crude oil by 2021 if the security
situation improves, the chairman of the National Oil Corporation said last week. The plan would
represent a doubling of the current rate of production, which currently stands at 953,000
b/d.
... ... ....
4. Russia
Moscow has already lowered its oil output by around 30,000 b/d compared with October
volumes, which is used as the baseline under the latest OPEC/non-OPEC crude production
agreement. Russian energy minister Novak said Friday: "We are gradually lowering output; our
plan is that overall production in January will be 50,000 b/d less than in October."
"... Last year, oil production in Norway fell to 1.49 million barrels per day (bpd), down by 6.3 percent compared to the 1.59 million bpd production in 2017, the oil industry regulator, the Norwegian Petroleum Directorate (NPD), said in its annual report this week. Oil production this year is forecast to drop by another 4.7 percent from last year to reach in 2019 its lowest level in thirty years -- 1.42 million bpd, the NPD estimates show. ..."
"... However, the Norwegian oil regulator warned that "resource growth at this level is not sufficient to maintain production of oil and gas at a high level after 2025. Therefore, it is essential that more profitable resources are proven in the next few years." ..."
"... The industry's problem is that after Johan Sverdrup and Johan Castberg there haven't been major discoveries. ..."
Despite cost controls, increased efficiency, and higher activity offshore Norway, oil
production at Western Europe's largest oil producer fell in 2018 compared to 2017 and is
further expected to drop this year to its lowest level since 1988.
Last year, oil production in Norway fell to 1.49 million barrels per day (bpd), down by 6.3
percent compared to the 1.59 million bpd production in 2017, the oil industry regulator, the
Norwegian Petroleum Directorate (NPD), said in its annual report this week. Oil
production this year is forecast to drop by another 4.7 percent from last year to reach in 2019
its lowest level in thirty years -- 1.42 million bpd, the NPD estimates show.
As bad as it sounds, this year's expected low production is not the worst news for the
Norwegian Continental Shelf (NCS) going forward.
Oil production is expected to jump in 2020 through 2023, thanks to the start up in late 2019
of Johan
Sverdrup -- the North Sea giant, as operator Equinor calls it. With expected resources of
2.1 billion -- 3.1 billion barrels of oil equivalent, Johan Sverdrup is one of the largest
discoveries on the NCS ever made. It will be one of the most important industrial projects in
Norway in the next 50 years, and at its peak, the project's production will account for 25
percent of Norway's total oil production, Equinor says.
The worst news for Norway's oil production, as things stand now, is that after Johan
Sverdrup and after Johan Castberg
in the Barents Sea scheduled for first oil in 2022, Norway doesn't have major oil discoveries
and projects to sustain its oil production after the middle of the 2020s.
The NPD
started warning last year that from the mid-2020s onward, production offshore Norway will
start to decline "so making new and large discoveries quickly is necessary for maintaining
production at the same level from the mid-2020s."
In the report this week, NPD Director General Bente Nyland said:
"The high level of exploration activity proves that the Norwegian Shelf is attractive.
That is good news! However, resource growth at this level is not sufficient to maintain a
high level of production after 2025. Therefore, more profitable resources must be proven, and
the clock is ticking".
Norwegian oil production in 2018 was expected to drop compared to the previous year, but the
decline "proved to be greater than expected," the NPD said, attributing part of the production
fall to the fact that some of the newer fields are more complex than previously assumed, and
certain other fields delivered below forecast, mainly because fewer wells were drilled than
expected.
In October 2018, Germany's Wintershall
warned that its Maria oil and gas field off Norway was not fully meeting expectations due
to issues with water injection. Those issues haven't been solved yet, NPD's Nyland told
Reuters this week.
Exploration activity in Norway considerably increased in 2018 compared to 2017, with 53
exploration wells spud, up by 17 wells compared to the previous year. Based on company plans,
this year's exploration activity is expected to remain high and around the 2018 number of wells
spud, the NPD says.
The key reasons for higher exploration activity have been reduced costs, higher oil prices
lifting exploration profitability, and new and improved seismic data on large parts of the
Shelf, the NPD noted.
However, the Norwegian oil regulator warned that "resource growth at this level is not
sufficient to maintain production of oil and gas at a high level after 2025. Therefore, it is
essential that more profitable resources are proven in the next few years."
Norway still holds a lot of oil under its Shelf, and those remaining resources could sustain
its oil and gas production for decades to come. The industry's problem is that after Johan
Sverdrup and Johan Castberg there haven't been major discoveries.
According to the NPD's resource estimate, nearly two-thirds of the undiscovered resources
lie in the Barents Sea.
"Therefore, this area will be important for maintaining production over the longer term,"
the regulator said.
Operators on the NCS have made great efforts to try to make even smaller discoveries
profitable by hooking them to existing platforms and production hubs. However, these smaller
finds alone can't offset maturing production -- Norway needs major oil discoveries, and it
needs them soon , considering that the lead time from discovery to production is several
years.
2019-01-11 (Bloomberg) Saudi and Canadian cuts are leaving world hungry for heavy crude
Refiners along the Gulf Coast and in the Midwest invested billions of dollars in cokers and
other heavy-oil processing units over the past three decades anticipating supplies of light
oil would become scarce while heavy crude from Canada's oil sands, Venezuela and Mexico would
grow. Instead, the opposite occurred.
The shale revolution, as well as new offshore supplies form Brazil and West Africa, caused a
surge of light oil, while supplies from Venezuela to Mexico declined. Canada's growth has
been stymied by delays in getting new pipelines built.
https://www.bnnbloomberg.ca/saudi-and-canadian-cuts-are-leaving-world-hungry-for-heavy-crude-1.1197259
India – Consumption of Petroleum Products (Without LPG or PetCoke)(kt/day)
December 2018 up +7.01% higher than December 2017
Average full year 2018 up +6.80% higher than full year 2017
Chart https://pbs.twimg.com/media/DwoYp5xWsAA_vRh.jpg
India Light Distillates Consumption (shown in chart)
Average full year 2018 up +9.74% higher than full year 2017
Chart https://pbs.twimg.com/media/DwoY_yjX4AA-S9K.jpg
India Middle Distillates Consumption
Average full year 2018 up +3.92% higher than full year 2017
U.S. shale industry could struggle if WTI remains below $60-$70 per barrel (differ by the
area and the spots). Investing in $50th range is just "hope" investmnet which is reling og
positive price dynamics, and below them is clear losses for produces, which means additional
junk bond issues.
... ... ...
But even as production held up, drilling activity indicated a sharper slowdown was underway.
The index for utilization of equipment by oilfield services firms dropped sharply in the fourth
quarter, down from 43 points in the third quarter to just 1.6 in the fourth – falling to
the point where there was almost no growth at all quarter-on-quarter.
Meanwhile, employment has also taken a hit. The employment index fell from 31.7 to 17.5,
suggesting a "moderating in both employment and work hours growth in the fourth quarter," the
Dallas Fed wrote. Labor conditions in oilfield services were particularly hit hard.
The data lends weight to comments made by top oilfield service firms from several months
ago. Schlumberger and Halliburton warned in the third
quarter of last year that shale companies were slowing drilling activity. Pipeline constraints,
well productivity problems and "budget exhaustion" was leading to weaker drilling conditions.
The comments were notable at the time, and received press coverage, but oil prices were still
high and still rising, and so was shale output. The crash in oil prices and the worsening
slowdown in the shale patch puts those comments in new light.
What does all of this mean? If oil producers are not hiring service firms and deploying
equipment, that suggests they are rather price sensitive. The fall in oil prices forced
cutbacks in drilling activity. Oilfield service firms in particular are bearing the brunt of
the slowdown. Executives from oilfield service firms told the Dallas Fed that their operating
margins declined in the quarter.
Baker huges reports a current US rig count decrease of 1% in the past two weeks. Several
companies I support in the Permian have stacked rigs and layed off workers. $50 bbl is the
magic number, the longer below that number the worse it will get.
Or it shows how much better the industry has gotten in response to production and prices.
It's like a capital intensive industry that doesn't waste capital drilling for something that
won't make them money. That's preservation of capital.
It doesn't take years or months to respond. It takes weeks.
Yes sure, the easiest datasets to follow in one place are at SRSrocco. Steve StAngelo,
kudos to him, has been onto this for years and has analyzed a lot of data from different
sources.
There are lots of other sources if you duck it (Google is, of course, much more of the
official narrative) but Steve has done a pretty good job of pulling a lot of information
together over many years and for free. Even the paid access business facilities don't have
much information (Surprise?).
The shale industry has been a kind of Ponzi scheme with OPM, entirely dependent on
constant new loans to keep production levels up with new wells, and has never made a profit.
I have often wondered, actually, to what extent the ESF (That is, USG) has supported the
industry as a means of attempting to put more pressure on RRRRUUUUUSSSSSIIIAAAAA!!!!!!! and
its energy income. Ultimately, unsuccessfully so, so perhaps this support might not last too
much longer?
Without subsidies from "someone", it's difficult to understand how an unprofitable
industry could have survived for so long. The Banks are not stupid. Wait, let me re-consider
that last remark!! But not in the way I meant
From the piece you linked above which seems to indicate capex spending will be flat to
slightly down there was also this:
Asked to provide a specific price for WTI used for capital planning this year,
executives said they expect prices to average $54/bbl, with responses ranging from $50 to
$64.99. Only 9% thought prices would be below $50.
If their oil price expectation (the average) proves correct, there will not be a lot of
money made in 2019 in the tight oil plays of Texas.
America is now the largest producer of oil in the world. For the U.S., this is great news as
the dream of energy independence grows and maybe one day we can tell OPEC to go take a
hike.
However, while the shale oil revolution has helped change the energy landscape forever, we
cannot take shale for granted. We can't just assume that the industry can withstand any price
and that production can keep rising despite the market conditions. We can't assume that shale
oil producers can match OPEC production cuts barrel for barrel.
We also can't assume OPEC, weakened by falling prices of late, won't strike back like they
did in 2014. That's when OPEC declared a production war on U.S. shale producers. The then de
facto head of the OPEC Cartel Ali al-Naimi spoke about market share rivalry with the United
States and said that they wanted a battle with the U.S. There were no winners in that
production war. Ali al-Naimi was sacked as he almost bankrupted Saudi Arabia. It took its toll
on U.S. producers as well, as many were forced into bankruptcy despite making significant
progress on efficiency and cost cutting.
With 2019 underway, OPEC, along with Russia, agreed to remove 1.2 million barrels per day
off the market for the first six months of the year. Early reports on OPEC compliance to the
agreed upon production cuts is overwhelming at a time when there are new questions about how
shale oil producers are faring after this recent oil price drop.
Private forecasters are showing that there are major cuts in Saudi exports and even signs
that OPEC production is falling sharply. Bloomberg News confirmed that by reporting "observed
crude exports from Saudi Arabia fell to 7.253 million barrels per day in December on lower
flows to the U.S. and China." Furthermore, other private trackers believe that the drop may be
the biggest in exports since Bloomberg began tracking shipments in early 2017. Oil saw another
boost after Bloomberg reported that OPEC oil production had the biggest monthly drop in two
years falling by 530,000 barrels a day to 32.6 million a day last month. It's the sharpest
pullback since January 2017.
Rewind to 2017, there was talk that shale oil producers would make up the difference and the
cut would not matter, but that was proven wrong. This time expect the same because it is likely
that shale oil producers may have to cut back as the sharp price drop has put them in a bad
position. The Wall Street Journal pointed out that, even now, some shale oil wells are not
producing as much oil as expected. This coupled with a large declining production rate in shale
swells means that they need capital to keep drilling to keep those record production numbers
moving higher. "Two-thirds of projections made by the fracking companies between 2014 and 2017
in America's four hottest drilling regions appear to have been overly optimistic, according to
the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in
Texas and North Dakota. Collectively, the companies that made projections are on track to pump
nearly 10% less oil and gas than they forecast for those areas, according to the analysis of
data from Rystad Energy AS, an energy consulting firm. That is the equivalent of almost one
billion barrels of oil and gas over 30 years, worth more than $30 billion at current prices.
Some companies are off track by more than 50% in certain regions" the Journal reported.
"While U.S. output rose to an all-time high of 11.5 million barrels a day, shaking up the
geopolitical balance by putting U.S. production on par with Saudi Arabia and Russia. The
Journal's findings suggest current production levels may be hard to sustain without greater
spending, because operators will have to drill more wells to meet growth targets. Yet shale
drillers, most of whom have yet to consistently make money, are under pressure to cut spending
in the face of a 40% crude-oil price decline since October."
Of course, none of this matters if we see a prolonged slowdown in the global economy, Demand
may indeed turn out to be the great equalizer. Yet if growth comes back, say if we get a China
trade deal or if they ever reopen the U.S. government, we will most likely see a very tight
market in the new year. The OPEC cuts will lead to a big drawdown in supply and shale oil
producers will find it hard to match OPEC and demand growth barrel for barrel.
"... Two-thirds of projections made by the fracking companies between 2014 and 2017 in America's four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers ..."
"... Collectively, the [shale] companies that made projections are on track to pump nearly 10% less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm. That is the equivalent of almost one billion barrels of oil and gas over 30 years, worth more than $30 billion at current prices. Some companies are off track by more than 50% in certain regions. ..."
MSM seems to be catching on to the hype in shale, excerpts from an excellent article on
shale on WSJ today:
Two-thirds of projections made by the fracking companies between 2014 and 2017 in
America's four hottest drilling regions appear to have been overly optimistic, according to
the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in
Texas and North Dakota.
Collectively, the [shale] companies that made projections are on track to pump nearly 10% less oil
and gas than they forecast for those areas, according to the analysis of data from Rystad
Energy AS, an energy consulting firm. That is the equivalent of almost one billion barrels of
oil and gas over 30 years, worth more than $30 billion at current prices. Some companies are
off track by more than 50% in certain regions.
-- --
In September 2015, Pioneer Natural Resources, based in Irving, Texas, told investors that
it expected wells in the Eagle Ford shale of South Texas to produce 1.3 million barrels of
oil and gas apiece. Those wells now appear to be on a pace to produce about 482,000 barrels,
63% less than forecast, according to the Journal's analysis.
An average of Pioneer's 2015 forecasts for wells it had recently fracked in the Midland
portion of the Permian basin suggested they would produce about 960,000 barrels of oil and
gas each. Those wells are now on track to produce about 720,000 barrels, according to the
Journal's review, 25% below Pioneer's projections.
In 2014, Parsley Energy, an Austin, Texas-based producer, told investors its average well
in the Midland section of the Permian basin would produce 690,000 barrels, according to a
review of Parsley's quarterly earnings presentations. By 2015, its estimates averaged
1,050,000 barrels.
Parsley is on track to miss its Midland well forecasts for every year from 2014 to 2017 by
an average of 25%, according to the Journal's analysis.
-- --
One reason thousands of early shale wells aren't meeting expectations is that many
companies extrapolated how much they would produce from small clusters of prolific initial
wells, according to reserves specialists. Some also excluded their worst-performing wells
from the calculations, which is akin to eliminating strikeouts when projecting a baseball
player's batting average.
"... Based on first year production numbers supplied by Shallow Sand, production can't increase without borrowing, except in some isolated areas. ..."
"... Consumption of oil is up. OPEC and Russia have reduced output. The price falls, because there is no meaning to anything created from thin air when applied to something that depends on physics. ..."
As I have posted before, the wells we apply a 60 month payout to have a much lower
decline rate than the shale wells, and are being drilled out of cash flow, not borrowed
money.
For example, a well we drilled in 2006 just passed 10,000 BO and produced 370 BO in
2018. It cost about 1/100 the cost of a shale well ($70K +/-).
Maybe not a valid comparison, but. 100:1 ratio would be cumulative of 1 million BO
and annual of 37,000 BO, which I think a rate you will not find often for any US shale well
after 12.5 years on production.
Our LOE is higher per BO, so not entirely valid, but still maybe somewhat useful for
comparison.
I note in the WSJ article PXD argued that the comparisons weren't valid because they
use a 50 year well life in calculating EUR v 30 year well life in the study.
I would think the PV of years 30-50 would be tiny on a 20,000' hz well producing
under 20 BOEPD! That PXD uses that argument seems to make them look a little foolish? Or am I
being too tough on them?
Shallow, you know they can't run a stripper well like you. Damn thing will be
plugged at seven years. Dennis can calculate his damn curves to twenty to thirty years if
he wants to. I can't disprove it, because we are only in about year eight, and some have
probably been plugged already, although I have no statistics on it. Although, I found one
of EOGs that didn't make it 7 years without trying too hard.
Mike was talking about borrowing on conventional production that has a much
smaller decline rate. You drill one this year, and borrow the next year to drill another,
you are increasing production. Not running on a treadmill.
Don't have the paywall, but you've given the gist. Investors were not happy with
returns. Now, they are being fact checked, and that can look real messy. Borrowing is set
to become restricted for many reasons. I really see some headwinds for future production
increases.
Based on first year production numbers supplied by Shallow Sand, production
can't increase without borrowing, except in some isolated areas.
To get even close to
covering declines from last years wells, they have to, at least, recover most of that
capex cost in the first year of production. That is far from reality, right now. To
increase, or later to even keep up, with production, they will have to borrow money. They
can possibly make a profit in three years, but that is meaningless to providing for
growth. Think it going to start looking nastier.
And to add to Ron's answer, God would have to add, and make each well profitable the
first year.
The miracle of US shale is about to have Toto pull back the curtain and reveal the
real wizard.
Shale was, is, and will be just a supplemental source of oil supply. An investor
could, if it was managed right, put x amount into the business, and in several years get
a marginal return. In two to three years, a second well could be drilled to increase that
income. That would be shale production growth. Not the imaginary growth numbers that are
being thrown out.
The putrid 10Qs and 10ks for 2019 will add to the fire.
You guys insist on continuing to think money isn't created from thin air by the Fed and
actually means something in the context of a substance that feeds you food. If you have to
have it, and you do have to have it, things will be done for you to get it. Borrowed money
that was created from thin air . . . who cares if you can't pay it back? You have to
eat.
Consumption of oil is up. OPEC and Russia have reduced output. The price falls, because
there is no meaning to anything created from thin air when applied to something that
depends on physics.
You won't know anything until you find yourself sitting in a line waiting for gasoline.
You won't see it coming. You won't predict it. It will just happen someday.
Some truth to that Watcher. Simplistic thinking in investors. If we aren't making much
money, the US won't be making much money, so the price of oil must go lower. Not just
simplistic, flat out stupid.
And the number of people who think oil supply is limited is fairly scarce in relation to
the population as a whole. Probably less than the number of people who think chocolate milk
comes from brown cows.
And if you think I am being unreasonably hard on the average IQ, google who is now
running the country, and consider almost 50% voted for him. Ok, I'll give them somewhat of
a break, as I didn't like the alternative, either. They should allow write ins, so we can
all vote.
And any moron can borrow 20 billion and service the debt for awhile. Maybe all of it, if
they are lucky. Who cares, it's only paper. Not a bad idea. I have an oil company, I can
borrow 20 billion, stick half into BNO, and have a ball with the rest. If I lose, I can
declare bankruptcy, and they can get my prepaid funeral expenses, but none of my gold bars
in the Caymans. And, I am 99.9% certain that is less of a risk than any E&P I can think
of.
Jerri-Lynn here. This is
the latest installment in Justin Mikulka's excellent series on the fracking beat,
Finances
of Fracking: Shale Industry Drills More Debt Than Profit
. The industry lacks even the excuse of profit to justify
the environmental costs it inflicts – yet the mainstream media continue to swallow industry waffle. I've crossposted other
articles in the series, and I encourage interested readers to look at them – the entire series is well worth your time.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg, NY.
Originally published at
DeSmog
Blog
2018 was the year the oil
and gas industry promised that its darling, the shale fracking revolution, would stop focusing on endless production and
instead turn a profit for its investors. But as the year winds to a close, it's clear that hasn't happened.
Instead, the fracking
industry has helped set new
records
for
U.S. oil production while continuing to lose huge amounts of money -- and that was before the recent crash in oil prices.
But plenty of people in
the industry and media make it sound like a much different, and more profitable, story.
Broken Promises and Record Production
Going into this year, the
fracking industry needed to prove it was a good investment (and not just for its CEOs, who are garnering
massive
paychecks
).
In January,
The
Wall Street Journal touted the prospect
of frackers finally making "real money for the first time" this year. "Shale
drillers are heeding growing calls from investors who have chastened the companies for pumping ever more oil and gas even as
they incur losses doing so," oil and energy reporter Bradley Olson wrote.
Olson's story quoted an
energy asset manager making the (always) ill-fated prediction about the oil and gas industry that
this time will
be different.
Is this time going to be
different? I think yes, a little bit," said energy asset manager Will Riley. "Companies will look to increase growth a little,
but at a more moderate pace."
Despite this early
optimism,
Bloomberg noted in
February
that even the Permian Basin -- "America's hottest oilfield" -- faced "hidden pitfalls" that could "hamstring"
the industry.
They were right.
Those pitfalls turned out to be the ugly reality of the fracking industry's finances.
And this time was
not different.
On the edge of the Permian
in New Mexico,
The
Albuquerque Journal
reported the industry is "on pace this year to leap past last year's record oil production," according
to Ryan Flynn, executive director of the New Mexico Oil and Gas Association. And yet that oil has at times been discounted as
much as
$20
a barrel
compared to world oil prices because New Mexico doesn't have the infrastructure to move all of it.
Who would be foolish
enough to produce more oil than the existing infrastructure could handle in a year when the industry promised restraint and a
focus on profits? New Mexico, for one. And North Dakota. And Texas.
Texas is experiencing a
similar story. Oilprice.com cites a
Goldman
Sachs
prediction of discounts "around $19-$22 per [barrel]" for the fourth quarter of 2018 and through the first three
quarters of next year.
Oil producers in fracking
fields across the country seem to have resisted the urge to reign in production and instead produced record volumes of oil in
2018. In the process -- much like the
tar
sands industry in Canada
-- they have created a situation where the market devalues their oil. Unsurprisingly, this is not a
recipe for profits.
Shale Oil Industry 'More Profitable Than Ever'
--
Or
Is It?
However,
Reuters
recently
analyzed 32 fracking companies and declared that "U.S. shale firms are more profitable than ever after a strong third
quarter." How is this possible?
Reading a bit
further reveals what Reuters considers "profits."
"The group's cash flow
deficit has narrowed to $945 million as U.S.benchmark crude hit $70 a barrel and production soared," reported Reuters.
So, "more profitable than
ever" means that those 32 companies are running a deficit of nearly $1 billion. That does not meet the accepted
definition
of profit.
A
separate
analysis
released earlier this month by the Institute for Energy Economics and Financial Analysis and The Sightline
Institute also reviewed 32 companies in the fracking industry and reached the same conclusion: "The 32 mid-size
U.S.exploration companies included in this review reported nearly $1 billion in negative cash flows through September."
The numbers don't lie.
Despite the highest oil prices in years and record amounts of oil production, the fracking industry continued to spend more
than it made in 2018. And somehow, smaller industry losses can still be interpreted as being "more profitable than ever."
The Fracking Industry's Fuzzy Math
One practice the fracking
industry uses to obfuscate its long money-losing streak is to change the goal posts for what it means to be profitable.
The
Wall Street Journal recently highlighted
this practice, writing: "Claims of low 'break-even' prices for shale drilling
hardly square with frackers' bottom lines."
The industry likes to talk
about
low
"break-even"
numbers and how individual wells are profitable -- but somehow the companies themselves keep losing money.
This can lead to statements like this one from Chris Duncan, an energy analyst at Brandes Investment Partners:
"You always scratch
your head as to how they can have these well economics that can have double-digit returns on investment, but it never flows
through to the total company return."
Head-scratching, indeed.
The explanation is pretty
simple: Shale companies are not counting many of their operating expenses in the "break-even" calculations. Convenient for
them, but highly misleading about the economics of fracking because factoring in the costs of running one of these companies
often leads those so-called profits from the black and into the red.
The Wall Street Journal
explains the flaw in the fracking industry's questionable break-even claims: "break-evens generally exclude such key costs as
land, overhead and even at times transportation."
Other tricks, The Wall
Street Journal notes, include companies only claiming the break-even prices of their most profitable land (known in the
industry as "sweet spots") or using artificially low costs for drilling contractors and oil service companies.
While the mystery of
fracking industry finances appears to be solved, the mystery of why oil companies are allowed to make such misleading
claims remains.
Why does the fracking
industry continue to receive more investments from Wall Street despite breaking its "promises" this year?
Because that is how
Wall
Street makes money
. Whether fracking companies are profitable or not doesn't really matter to Wall Street executives who
are getting rich making the loans that the fracking industry struggles to repay.
An excellent example of
this is the risk that
rising
interest rates pose
to the fracking industry. Even shale companies that have made profits occasionally have done so while
also
amassing
large debts
. As interest rates rise, those companies will have to borrow at higher rates, which increases operating costs
and decreases the likelihood that shale companies losing cash will ever pay back that debt.
Continental Resources, one
of the largest fracking companies, is often touted as an excellent investment. Investor's Business Daily
recently
noted t
hat "[w]ithin the Oil& Gas-U.S.Exploration & Production industry, Continental is the fourth-ranked stock with a
strong 98 out of a highest-possible 99 [Investor's Business Daily] Composite Rating."
And yet when
Simply
Wall St.
analyzed the company's ability to pay back its over $6 billion in debt, the stockmarket news site concluded that
Continental isn't well positioned to repay that debt. However, it noted "[t]he sheer size of Continental Resources means it is
unlikely to default or announce bankruptcy anytime soon." For frackers, being at the top of the industry apparently means
being too big to fail.
As interest rates rise,
common sense might suggest that Wall Street would rein in its lending to shale companies. But when has common sense applied to
Wall Street?
The Chronicle notes the
epic money-losing streak for the industry and how fracking bankruptcies have already ended up "stiffing lenders and investors
on more than $70 billion in outstanding loans."
So, is the party over?
Not according to Katherine
Spector,
a
research scholar
at Columbia University's Center on Global Energy Policy. She explains how Wall Street will reconcile
investing in these fracking firms during a period of higher interest rates: "Banks are going to make more money [through
higher interest rates], so they're going to want to get more money out the door."
1. The
Sightline Institute methodology had 33 cos. Not 32. I would bet the Reuters reporter took out one company out from the
analysis. Bear in mind XOP has 72 or so companies so there is a lot of scope for cherry picking there too.
2. What
bank wants to run an oil company? The banks lent to a sector which conned them. I guess rates were too low for too long. Those
loans/bonds are only recoverable if oil prices are high. The oil men know they are long a massive call option, and you can't
take it off them. They can't get new money so they won't give back the old.
3.
Diamondback and maybe 8 others make money. Infrastructure in the right place and good geologies.
4. The
numbers are unfair to Andarko cos the cut off misses a bunch of cash coming back in q3
Remember Enron? We're clearly not smart enough to understand the genius of how this is profitable. I guess we should
just step aside and watch the smart guys spin straw into gold. I'm sure they will share the wealth with the land
owners right?
These oil men are not stupid. They like to get their DUCs in a row – wells drilled but uncompleted. If oil goes up
enough they can open the DUCs in less than 2 months. Its the weakly capitalized ones who will pump oil out of a
reservoir with low oil prices to service debt. Also by drilling they often validate a lease which would void if
they didnt drill. However by not pumping they dont have to pay any royalties – just rents.
Below $50 on WTI a lot of the sector doesn't generate enough cashflow to meet investment plans.
I think a lot of the funding is with junk bonds. So most of those bonds are sold to investors, including ETFs, mutual
funds, and pension funds. Many of the banks are just middlemen and will probably not be left holding too much of the bag if
they haven't kept them on their own books or written lots of stupid derivatives on them.
This
should be a much smaller sector than the housing sector so a sub-prime mortgage bond-like crash shouldn't have the impact
of 2008. But who knows, the main thing aI marvel about with the financial sector is their unerring ability to take
something that should be relatively safe, weaponize it, and threaten global financial stability with it.
I've watched in horror from a distance in regards to fracking, and then a few days ago, this planning area map for open
hydraulic fracking leases has me surrounded in a sea of red
We're on
a fractured rock aquifer in the foothills here that's separate from the one on the valley floor, and because it gets scant use
in Ag, and not many people live here (we're 2.5x as big as Paradise,Ca. in size, with 1/10th of the population and at a
similar altitude) nobody's hard rock wells had any issues with going dry during the lengthy drought and having to drill
hundreds if not a thousand feet deeper in search of H20, as was occurring to the farmers et al on the fruited plain.
I sure
don't like the idea of a fractured rock aquifer and fracking
One thing
going against us, is land is cheap here, it's nature acres, nice to look at. but no development potential, as the trees are
all in the way, and what sorry sap is going to cut down oaks a couple hundred old and level the hills to put in tiny boxes?
That
villain doesn't exist, luckily.
But if
you were to dangle large amounts of money at the owners of such low value acres, in oil leases?
And the
idea it was all a circle jerk by Wall*Street & Big Oil, to get the money!
.
Makes it even harder to swallow
Its not just the environmental damage. Banks lending to frackers will be precedent creditors. They'll keep loaning until
whatever value in the company that can be extracted in extremis has been used up. One can easily imagine the sort of
accounting Wall Street uses.
So when these companies finally go bust, faced with the diminishment of oil production, will US taxpayers be forced to bail
out the industry because of the economic/national security implications of the prospects of eviscerated US oil production
volumes? If so, Wall Street wins yet again.
A gigantic hidden cost is the liabilities associated with the resulting abandoned wells. This is why this fall there was a
Supreme Court challenge in Canada to a ruling on who gets paid first in such cases. In Canada the reclamation costs fall to
the remaining producers who share costs of the Orphan Well Association. In the US, it is completely off the books, and
therefore falls to the government to clean up abandoned plays when companies go bust.
So,
taxpayers could be on the hook both if there is a government bailout on bad loans, a al 2008/2009, AND will have to pay to
clean this up (it's expensive, by the way, there are thousands and thousands of these sites that need to be remediated). I
suspect the reason all this is happening is a strategic effort to use tax payer backstopped risk to punish Russia to daring
to exist.
This is similar to mines and old waste dumps. If the owners were limited partnerships or companies that went bankrupt
with no remaining solvent pieces, then there is no money in the kitty to clean them up. The remaining game in town then
is Superfund and state programs for inactive hazardous waste sites and orphan wells.
The
RCRA Subtitle C and D regulations in the 1980s and early 90s required landfill operators to set aside funds in
lock-boxes so that if they went bankrupt, the state could access those funds to close the landfills. The landfills
typically charge a fee per ton just to fund these financial assurance accounts and they need to keep them on file with
the states. Unfortunately, the resource extraction industry has generally been able to successfully fight against these
types of requirements as "job-killers".
One economic problem with fracked gas wells is they only produce large quantities of gas for a short time. It's usually 2 to 3
years. After that production tanks. I suspect a similar thing happens with fracked oil wells. I I've in NY close to the PA
boarder. For about 4 years, fracking was really booming. Now it has almost stopped. You see big lots filled with fracking
equipment gathering rust. It didn't take most people long to realize that only a few made money while the rest pay the bill
for all of the damage done. I'm glad in NY state they banned fracking. I own 50 acres and refused to buy into a leasing deal
before fracking was banned. My biggest concern was my well water becoming contaminated as well as losing control over how my
land is used. A big problem is that a company is allowed to drill under your land even if you don't have a lease agreement
with them. They have to pay you but they can also pollute your well. If that happens your property becomes of no value and
useless.
We'd become curious about folks moving to the NE tip of PA, as it looked like NJT might actually reopen rail service to all
those $80-$140K houses, right before Williams/ Transco's Constitution Pipeline finally caused hundreds of new fracked
wells? We'd guessed the only effect of the '16 election was who'd be prodding retirees into GasLand Poconos. Seems like a
great location for a remake of Green Acres meets Deliverance?
https://www.njherald.com/20180410/lackawanna-cutoff-project-may-finally-be-back-on-track
Looks like there's a mess of unwatchable YouTube videos. I wonder if refugees have any idea of what could happen up there?
Yes, when liquidity has a much smaller time constant then actual production, the rules of liquidity will decouple from the
production and actually dominate the process.
This is
well-known from physics, and why many economic theories are obviously and fundamentally wrong.
As long
as the economy is financialized with almost infinite velocity, nothing in the real world (including profits) will actually
drive the system. This is trivially obvious.
This kind of thing makes me chuckle. So the CEOs and other suits at the fracking companies are scamming their investors to
enrich themselves. Hard to feel bad about it (even though a fair number of the investors are probably "institutional") if it
wasn't for the needless environmental destruction that goes along with these two groups of elites ripping each other off.
Very broadly speaking, wouldn't this be a good real-world example of MMT? There is a natural resource we want to extract, we
have the manpower and machinery to do it, so we just do it? The money to fund it is limitless bound only by the constraints of
the resource itself. Wall street is just a rent-extracting intermediary
It's ironic that, having lived thru the 80's when the financial "geniuses" took over and it was all about ROI – Westinghouse
somehow came to the conclusion that you could make 6% on golf courses (they didn't even know, I don't think) instead of 2% on
industrials (that was probably correct) so they basically sold the store. Except for the nukes, sigh.
The
comments above, apes's for instance, point to the whole slosh of money. And there is some truth to that. But in this case, I'm
afraid much of the answer is that people in the oil bidness make oil wells because that's what they know how to do. ROI, Scmoi
O I.
Of all
the industries that are gone because they weren't allowed to "do what they know" because it was "cheaper to offshore" – read a
greater ROI to Wall Street – how come the worst is the only one that keeps its nose to the grindstone and does the actual work
it knows how to do?
No, what I meant was those other ones just "diversified" or whatever the word of the moment was, just did whatever made
the people at the top money.
But
oil/gas is different. They just "have to go get it". It's like termites and wood. I respect that, even if it's the wrong
thing to do. If I must refer to The Terminator again, "it's what they do. It's ALL they do".
PS:
there is oil/gas everywhere. I worked in the "bidness,"btw.
So frackers can take out billions of unpayable debt and discharge it in bankruptcy, but I get to carry a millstone of student
debt around my neck for the rest of my life? Great system we got here. Pretty flipping great.
You should have issued a junk bond on yourself instead of taking a student loan. You could then just default on the junk
bond (after having written some derivatives to short it to profit from your financial demise).
I have a different take on all this fracking.
I believe it was decided at the highest levels of our government to support it; including financially if necessary. The basis
for this support and secrecy would be national security. Easy enough to see how this could have transpired.
All that
said, if my theory is correct, the frackers will be bailed in some form or fashion. Probably the next QE will pick up the tab
or perhaps the DOD is funding it indirectly already.
Your take parallels Pym of Nantucket's. Ever since the end of WWII, the United States has been allowed to just 'print
money', first to pay for its contest with the former Soviet Union for global hegemony and then to 'pay for' its energy and
the products its industries could no longer profitably produce – at least as profitably as they could by off-shoring those
industries. This is all really just an extension of 'petrodollar warfare' – gigantic bluff the US can continue to go it
alone if necessary – having salted the central banks of 'developing countries' with all the 'reserve currencies' they
realistically need, at least if the depredations of the likes of George Soros are held in check.
In
summary, fracked oil is propping up not just Big Oil but the US military industrial complex and ultimately Wall Street and
its banks. As long as the US can control the world's access to energy (and possibly retard its transition to renewable
sources?), US politicians and bankers can continue to 'print money' (i.e. export debt) and sustain the whole rotten edifice
of US and Western 'political economy'.
As
usual Michael Hudson has it right:
"Finance is the new form of warfare – without the expense of a military overhead and an occupation against unwilling
hosts." It is a competition in credit creation to buy foreign resources, real estate, public and privatized
infrastructure, bonds and corporate stock ownership. Who needs an army when you can obtain the usual objective (monetary
wealth and asset appropriation) simply by financial means?
The time will come, as a result of this, that the US
will
have to go it alone. They are turning your money to
shit. Unless our corporate masters sell out the rest of the country to foreigners, like they already have much of our
nation's productive capital.We won't be alone, but like Greece, we will no longer be independent or free.
This kind of crap increasingly pervades our economy. Military. Finance. Healthcare. Like money with Gresham's Law, bad
investment drives out good. Every cost is also someone's profit opportunity, so costs are magnifying and spinning out of
control. More and more the welfare of society depends on 'borrowed' money.
It's like the modern day pyramids. Nicely dressed piles of rocks in the desert. Total waste and destruction of
resources. It also destroyed the social capital of Ancient Egypt, and turned them into slaves of Pharoah. It was the
people of Egypt who paid for the pyramids, with their labor and their liberties.
So
that's what else is going on. Your freedoms are going down those wells. And up the towers of finance. The Egyptians, at
least, got something to look at. They already had the barren wastelands.
At least these depressed oil prices from over fracking in the US will make Saudi Arabia poorer. Possibly poorer to the point
that widespread social unrest ensues there, leading to the dethroning of the House Of Saud, which, in turn, will cause the
dethroning of their chief covert friend and ally Israel.
Then in
order to stave off social unrest here in the US, we'll have to cut off ties with these two roguish troublemakers in the
region. Much needed balance of power will then be restored to the region with Iran and Syria restored to their former glory,
sparking peace and prosperity from Pakistan and Afghanistan to Egypt, Somalia and Yemen.
I don't
know if the pieces on the chessboard will ever realign this way, but it's rather amusing to speculate that this realignment
could possibly be triggered by the stupidity and shortsightedness of the US to over frack!
You got it backwards. KSA and Russia need lower oil prices to force US producers off the field and get their supply chains
back. Your thinking like a 1970's person. Think 2010's.
This is a non-climate change reason why developing electric vehicles in North America, Europe, and China would be good.
It would strip away much of the demand for oil which is a major funding source for Russia and KSA.
Jesus Herbert Walker Christ. Is anyone else getting sick of this stupid series? If you keep writing the same article every
year, and Wall Street keeps engaging in the same apparently irrational behavior, you might want to rethink your smug pose and
ask yourself whether there might be some additional digging to do to understand what the hell is going on.
The
contrast between this series and Hubert Horan's Uber work is striking. Horan not only points out the fact that Uber is
unprofitable, but also clearly shows who has an interest in extending the hype, and how and why the bandwagon keeps rolling.
This series is the complete opposite.
Fracking
"investors" aren't getting ripped off, and they're not stupid. You've just completely missed half the point of the Master
LImited Partnership structure. For the limited partners, the losses are a feature, not a bug. Until MLP shares are cashed in,
they generate tax losses for the LPs. Those losses are valuable generally, but 501c3s, especially love them because they allow
non-profits to offset Unrelated Business Income.
Go to
Guidestar or Nonprofit Explorer and pull down the 990T of any nonprofit with a few billion dollars worth of invested assets.
Line 5 (usually blank but filled in as a long attachment at the end) is almost invariably a who's who of the fracking
industry, with thousands of dollars in losses from each company. In any given year, LPs only liquidate positions in a small
number of the companies their holding each year, allowing them to avoid taxes with the annual losses, then cash in (at least
sometimes) when the value of the company is high.
The
industry's a scam, but just as much of the taxpayers as of the investors.
Do you make a habit of putting your foot in your mouth and chewing? Because you did it here, by copping a 'tude while being
100% wrong.
Passive tax exempt investors have no use for losses. Zero. Zip. Nada.
An
investor in a limited partnership is a passive investor. Income from a passive investment NEVER generates Unrelated
Business Income. If the idiocy you presented was correct, no endowment or public pension fund could ever show a net profit
from their investments in private equity and hedge funds without it being taxed as UBI. There would literally be no private
equity industry as we know it because most of its money comes from tax exempt investors, namely public pension funds,
endowments, foundations, private pension funds.
UBI
results from activity conducted by the not for profit. The classic example is an art museum's gift shop. See IRS
Publication 598 (emphasis ours):
Unrelated business income is the income from a trade or business
regularly
conducted by an exempt organization
and not substantially related to the performance by the organization
of its exempt purpose or function, except that the organization uses the profits derived from this activity.
Limited partners are required to be passive and have nada to do with the operation of the partnership. They typically make
double sure that their investment income won't be characterized as business income. As one tax expert confirmed by e-mail:
Endowments/exempts/pension funds can wind up having UBTI when they don't structure their investments through
corporations. They rarely fail to do this structuring. They wouldn't put themselves in the position of deliberately
incur UBTI and then go hunting for losses to offset it.
So it
is possible that you heard of a not-very-competent endowment that wound up seeking tax losses, but that would be highly
unusual, when you incorrectly said the opposite.
There
are other tells that you don't even remotely understand the how limited partnerships work, such as your comment "In any
given year, LPs only liquidate positions in a small number of the companies their holding each year, allowing them to avoid
taxes with the annual losses."
Limited partnerships are pass-through entities. LPs receive their pro-rata share of income and loss annually. They do not
need to sell to recognize gains or losses resulting from their participation in operations.
The
mainstream journalist who first wrote about the pervasiveness of losses in fracking after oil prices started trading in the
new normal of $70 a barrel and below, John Dizard of the Financial Times, explained why frackers would keep drilling at
losses as long as they could get their hands on funding, so this is entirely consistent with his forecast. And Dizard's
column is for wealthy individuals and he is conversant with tax issues, unlike you.
"... Of course, I was just trying to make a point that wells drilled in 2015 that had seen 3 years of weak (and one year of average) oil prices were going to be total losers that would not payout within any reasonable time horizon, if at all. ..."
"... To continue, there is no mention in these numbers of how much land costs. I seem to recall many Permian players paying $15-60K per acre. So a two mile DSU would cost $19.2 million to $76.8 million. I just ignored land costs completely. Further, each of these companies has interest expense. One can go to the 10K's and 10Q's to see how much that is costing each per BOE. I just ignored interest expense too. ..."
"... I do argue until we see some well payout data (hard data, not power point variety) from these companies, we should assume the wells generally do not payout within 36 months, or even 60 months. ..."
"... I was just trying to remind people of the numbers. I think most of the investing public has figured it out, based on where these companies are trading since oil dumped again. ..."
So to keep everyone happy, here are some averages for the all wells EFS, Bakken and Permian.
Decided to exclude Niobrara, oil numbers are much lower.
2015 Q3 36 months of production: 162,635 BO most recent monthly rate 58.6 BOPD
2016 Q3 24 months of production: 169,078 BO most recent monthly rate 103.5 BOPD
2017 Q3 12 months of production: 136,850 BO most recent monthly rate 213.1 BOPD
For 2015 162,635 x .80 x $45 = $5,854,860
7% severance $409,840
$5 per BO LOE $650,540
$2 per BO G & A $260,216
Net = $4,534,264
I lowered the costs some to make the economics more favorable from the standpoint of those
who love the sub $2 gasoline. Might be ok to look at 10K and 10Q if anyone would like to plug
in different cost estimates.
The 2016 wells described above are at $4,713,894 per well after 24 months.
The 2017 wells described above are at $3,815,378 per well after 12 months.
Of course, I was just trying to make a point that wells drilled in 2015 that had seen
3 years of weak (and one year of average) oil prices were going to be total losers that would
not payout within any reasonable time horizon, if at all.
To continue, there is no mention in these numbers of how much land costs. I seem to
recall many Permian players paying $15-60K per acre. So a two mile DSU would cost $19.2
million to $76.8 million. I just ignored land costs completely. Further, each of these
companies has interest expense. One can go to the 10K's and 10Q's to see how much that is
costing each per BOE. I just ignored interest expense too.
These wells are a lousy investment at $50 WTI. Only gets worse as the oil price sinks.
I think this all started because maybe GuyM was actually giving some credence to EOG
guidance. I don't blame GuyM, or anyone else, for believing what the companies say.
I do argue until we see some well payout data (hard data, not power point variety)
from these companies, we should assume the wells generally do not payout within 36 months, or
even 60 months.
I do agree, wells have residual value after 36 and 60 months. I also agree that much
higher oil prices make this business a money maker. Finally, I agree the wells have improved
every year, although it is looking like 2016 might have been the high water mark, with later
wells not moving the needle much higher.
Time for me to exit for awhile. I was just trying to remind people of the numbers. I
think most of the investing public has figured it out, based on where these companies are
trading since oil dumped again.
Good analysis, and thanks, again. No amount of increased productivity could make them
profitable at $45, especially not $37, or $16. The clock is ticking. Yeah, EOG has gone from
over $120 to $87.
Looks like a lot of bubbles bursting. Not likely to bounce back, so not much financing
available to float pure Permian players. Doesn't look good for any increase in production.
Oil prices will probably stay low with Dow for awhile. Until inventories get closer to zero.
Madness.
Interesting article from Goehring investment bank. They estimate that KSA remaining reserves
are around 50 billion bbls, instead of the 260 b claimed. They also (surprise) think that was
the reason the Aramco IPO was pulled. I also thought the Aramco IPO would never happen
because they would not be able to buy an acceptable reserve report.
Interesting, they are probably right.
I knew Aramco would pull out of the IPO. They are one of the most secretive companies. How
you going to float on the NYSE or London SE with no transparency, which is required by
law.
50 billion sounds about right in my worthless opinion. Interestingly enough that would be
more or less close to the Permian basin reserves.
I think peak oil will arrive without many people noticing until after it has occurred.
A few more thoughts about the referenced Goering report.
First, the basis or their report: "We have good data going up to 2008, however after that
point data becomes difficult to find."
Does anyone else have good data on Ghawar production through 2008. Actual Saudi production
data is hard to come by, and I would like to see a table of Ghawar production through 2008 if
it is out there.
Based on their 2008 data they have included a Hubbert Linearization which is the basis for
their claim.
Second, if their production data and linearization are correct, they have not been
adjusted for improved results from better technology. I believe the multi lateral super wells
Saleri described in his 2005 SPE paper have allowed KSA to recover several percent of
additional original oil in place, as well as to maintain high production rates longer.
Third is that it appears many of those super wells were drilled beginning in mid 2000's.
It would make sense that the change in Saudi attitudes regarding production restraint between
2014 and now could be due to those multilateral wells watering out.
Coffee. I hope if you have been investing in the Appalachian gas players that you have been
short.
The only investment class in oil and gas that may be worse over the past ten years would
be the service sector, particularly the drillers.
Interesting that, despite all the activity, the US onshore drillers are becoming penny
stocks. I have pointed out Nabors. The rest are all tanking bad it appears.
You made a big deal out of a very long lateral operated by Eclipse Resources. Eclipse
equity closed at 76 cents a share.
I am not so sure that ultra cheap oil and gas is such a great thing for the US, given we
are now the world's largest producer of both.
I never have, nor will I ever in the future, take any financial stake in these or any
other companies.
As I have stated numerous times over the years, my primary interest is in operations who
is doing what, how it is being done, who is doing it better – or claims to be.
My initial interest in this site way back when was to learn why some people seemed to
think this so called Shale Revolution was No Big Deal a retirement party, in the words of
Berman.
It was quickly apparent to me that a great deal of unawareness vis a vis industry
developments permeated this site's participants.
This, alongside several predisposing factors to NOT want the shale production to explode
upwards provided fertile grounds for the soon 12 to 16 million barrels per day US oil
production, along with 100+ Bcfd gas production to be a spectaculsrly unforseen reality.
What I prefer or not prefer is secondary to what I believe to be occurring, shallow.
If anyone cares to spend 3 minutes reading the April, 2017 USGS press release accompanying
the Haynesville/Bossier assessment, they will read the following from Walter Guidroz, Program
Coordinator of the USGS Energy Resources Program
"As the USGS revisits many of the oil and gas basins of the US, we continually find that
technological revolutions of the past few years have truly been a game changer in the amount
of resources that are now technically recoverable".
Addendum Eclipse is being shut down/folded into another entity.
The lead engineer behind their ultra long laterals is now working with the new outfit from
which this technology will continue to spread.
No offense meant coffee. I know some who post here like to tangle with you. I am not
interested in that, just straightforward discussion.
Shale has surprised the heck out of me, and has made me several times strongly consider
liquidating my entire investment in oil and gas, absent maybe keeping just a couple of KSA
like cheap (to quote PXD CEO) LOE wells to fool around with. Had I known in 2012-13 that this
was coming, would have sold all but those few "piddle around with wells." It has been
absolutely no fun when these price crashes occur, and is especially no fun knowing that this
shale miracle is less profitable than an operation producing less than one bopd per well from
very, very old and tired wells.
You have to admit that the way the shale is being developed is destroying the oil and gas
industries that are developing it.
Particularly hard hit are the service companies, many which are already bankrupt.
Even XOM, which I have owned for many, many years (prior to the merger, I owned both Exxon
and Mobil) has hit the skids, having fallen through the $70 per share barrier.
Range Resources is at $10.26, a level not seen since 2004. It traded as high as $90 before
the 2014 crash.
EQT was over $100. Today $18.55
Whiting was nearly $400 (accounting for a reverse split) and now is $21.98
CHK closed at $1.84. All time high was $64.
Nabors Industries, the largest onshore US driller closed at $2.09. Traded at split
adjusted $10 in 1978.
Halcon Resources Corp. was over $3,000 split adjusted at one time, went Ch 11 BK, now at
$1.65, looking not so good re: BK again.
We shall soon see who can access what in the way of capital to keep going assuming oil
prices stay below $50 WTI for a considerable time.
I guess I am always concerned about whether businesses make money. Seems to me that would
be of some importance to you, but it isn't, and I suppose there is no harm in that.
I have yet to work anywhere where making money was not the primary motivation.
If the money wasn't important, the shale executives would not make so much of it, I
suppose.
I have always had a hard time understanding why they kept drilling wells in Appalachia
when the gas was selling for 50 cents per mcf. Not important to you, but maybe to others.
Anyway, if we didn't have different views, places like this wouldn't be very
interesting.
As big declines in legacy production are a characteristic of shale oil, then there will come a time when production from new
wells cannot keep up with the decline from the legacy wells. It can happen in 2019 or 2020.
My suspicion is that the economics are not that good and most wells are not profitable from November 2018 or so. So there is
something fishy that the shale oil industry ploughs on and continues to set new highs month after month.
Notable quotes:
"... We won't have much, or any growth in the first half of 2019, no matter what the hype is, unless prices spike. ..."
EF does not have pipeline problems, but it is not going to grow at $55 or less oil price. If
prices rise to $80, yes. But, the price will need to be consistent for a good long while.
GOM
has hit its high back in August according to SLa and George.
We won't have much, or any growth
in the first half of 2019, no matter what the hype is, unless prices spike.
Yeah, seems highly unlikely at best that Eagle Ford will ever regain its high. Even the EIA
forecast – notorious blue sky that it is – only gets it back to 1.5 million bpd.
And that on a theory of producers shifting from Permian due to logistical constraints in the
latter.
It's a mature area, only so many decent spots to drill.
"... Great article, thanks. Author says US LTO will be done by 2040, which makes sense. The speed and acceleration of sinking oil production is critical since we have not been strongly pursuing alternatives. If the production is down 50 percent by 2030 to 2035 it's going to be a tough go. If it falls faster then we are in severe trouble. ..."
"... The uncertainties he notes are shocking. That we have spent the last ten years pissing away our remaining "pennies" on a driving spree, instead of using it to build a renewable future, really makes me think that the backside of the peak is going to be awful. ..."
"... As a working petroleum geologist in the Delaware Basin and others, I will say USGS and EIA assessments are considered a joke. They do little to take into account the actual geology, or changes in the thermal maturity of the rock across a basin, it is more multiply an average well performance for a certain amount of acres drilled, times the total area of the basin, minus the number of drilled wells. ..."
"... I would not doubt oil production peaks in the mid-2020s as people drill up the best rock, and have to keep shifting to less productive horizons. ..."
"... So the oil cut is out: 1.2 mb. Together with russia and others. So LTO is saved, the frenzy can go on soon. ..."
Great article, thanks. Author says US LTO will be done by 2040, which makes sense. The
speed and acceleration of sinking oil production is critical since we have not been strongly
pursuing alternatives. If the production is down 50 percent by 2030 to 2035 it's going to be
a tough go. If it falls faster then we are in severe trouble.
Jean Laherrere knows a lot, but on LTO I think he may be wrong.
From the piece linked above: The best approach for forecasting future production is the extrapolation of past
production (called Hubbert linearization). For Eagle Ford the trend can be extrapolated
toward an ultimate quantity of 3 Gb.
The USGS estimates about a 12.5 Gb mean for the TRR of the Eagle Ford, when economics is
considered the URR might be reduced to 10Gb under a reasonable oil price scenario (AEO 2018
reference oil price scenario).
Recent USGS estimates for the Permian Delaware Basin have lead to a revision of my US
tight oil estimate to a mean of 74 Gb with peak probably in 2025 to 2030. Decline will be
relatively steep from 2030 to 2040, if the USGS estimates for the US tight oil resource prove
correct.
This is a terrific article. It takes all the confusions around oil and articulates them
beautifully. His review really makes me want to buy the book.
This is a delight to me because while I've always liked Laherrere's charts, I find his
English writing atrocious (not all his fault as a native speaker of French). This could
alienate lay readers, which is too bad because his message really needs to get out there.
The uncertainties he notes are shocking. That we have spent the last ten years pissing
away our remaining "pennies" on a driving spree, instead of using it to build a renewable
future, really makes me think that the backside of the peak is going to be awful.
Laherrere's knowledge is magisterial. Good on the editor who worked with him on this.
Indeed the amount of work that Jean is producing is truly quite amazing.
By the way what about Kjell Aleklett ?
According to his blog he didn't publish anything since 2017, the case ?
The "issue" with Jean is that he also is a climato skeptic (regarding CO2 effects) and this
has been detrimental to his ressource studies.
But one exercice in comparing the urgencies (taking the IPCC models just as they are), and
feeding them with the resource aspects of Laherrere, clearly shows that peak oil or even peak
fossile is the most urgent matter (knowing that anyway the mitigation measures, dimishing
fossile fuels burning, are usually the same, except stuff like CSS, that will most probably
never happen anyway).
Overall the terrible deficit of the "resource message" compared to the climate/CO2 one,
could be seen as a key reason for no measures being taken for the two aspects
Laherrere also suggests a 3 Gb URR for Eagle Ford where the USGS TRR mean estimate is
about 12.5 Gb and when economic assumptions are applied the ERR is probably about 10 Gb.
You are much more familiar with the Eagle Ford, at $80/b (2017$) does a 3 Gb URR estimate
seem correct?
Thanks. Does 10 Gb seem reasonable or is that too high? Average of USGS mean and
Laherrere's estimate would be about 6.5 Gb, again you know the area so your estimates would
probably be better than most.
It's pretty difficult to measure with strictly an $80 price. Some depends on gas price. There
are three windows in the EF. Oil, gas/condensate, and mostly gas. Gas has barely been
touched, and is the biggest window. Geologically older. It still will produce some oil and
condensate. If any, it will be mostly condensate. But it is still production as yet mostly
untouched. Gas/condensate has been drilled, and is responsible for the higher api coming out
of the EF, but in the past few years, less has been drilled due to the api. Oil window is
being drilled, but there is still plenty of tier two and three areas to go. Not so much tier
one. How do you measure that, and at what oil and gas price. I would say 12 is possible, but
it includes a lot of condensate and gas.
You could look at the USGS assessment of the Delaware in the same light. It may be there,
but is it cost productive? You may only get gas and/or condensate, depending on geological
age of the formation. Or, you may have to keep chasing after anything, as it moves quickly as
wells are drilled.
Thanks for the correction. Yes Gas prices would also be needed. The 10 Gb was C+C and yes
there is probably lots of condensate. I guess I would make it $4/ MCF for NG, you would
probably need condensate and NGL prices to do a full analysis, way too many moving parts for
me.
Got that right. Here's my cracker jacks geology assessment in the Permian. midland and
Delaware basins are slightly different, but the both have a wolfcamp as the lower level. It's
primarily a shale from my view of core samples. From the Bone Springs to the bottom wolfcamp,
there is no clear formation that acts as a container, Bone Springs looks like it is closer to
a sandstone, but closely formed from my view of the core samples. Not conducive to water
flooding due to lack of "walls". But, because of the lack of walls, the oil/condensate/gas
travels when wells are drilled. Indications are that EF has the same problems, but not as
fast? Very simplistic, and possibly wrong viewpoint.
And there is a fairly wide variety of prices depending on what comes out. I'm still trying
to figure out my pay Stubbs.
LARGEST CONTINUOUS OIL AND GAS RESOURCE POTENTIAL EVER
Today, the U.S. Department of the Interior announced the Wolfcamp Shale and overlying Bone
Spring Formation in the Delaware Basin portion of Texas and New Mexico's Permian Basin
province contain an estimated mean of 46.3 billion barrels of oil, 281 trillion cubic feet of
natural gas, and 20 billion barrels of natural gas liquids, according to an assessment by the
U.S. Geological Survey (USGS). This estimate is for continuous (unconventional) oil, and
consists of undiscovered, technically recoverable resources.
The Easter Bunny, Santa Clause, Tooth Fairy, but no Trolls? Conventional? They are out of
their Fxxng minds. Dept of the Interior is sharing the same hospital suite with the EIA. Both
digging for that phantom oil.
Somebody ought to tell the oil companies to quit using all this fracking stuff. All they
need to do is drill straight down. Sheesh!
I'm not a geologist, but your original projections peaking in 2025 appear reasonable to me.
Slow peak, not a huge peak like some. To add to that, JG Tulsa (below post), who is a working
geologist in the area, agrees with a mid 2020's peak. I'm not stupid enough to argue with
experts
You are clearly smarter than me. I do tend to listen when geologists and geophysicists try to educate me.
Here is a preliminary estimate for US LTO assuming USGS mean estimates are correct, the
Permian is up to date, but the older Bakken, EF, Niobrara, and US other LTO scenarios need to
be revised to reflect the AEO reference oil price scenario. Peak about 9 Mb/d in 2025, also
shown is an older estimate from June 2018 (before the recent Delaware Basin Wolfcamp and
Bonespring assessment from the USGS.)
This 46 billion barrels oil – along with 20 billion barrels NGLs and 281 Tcf gas
– is for the Delaware Basin Wolfcamp and Bone Spring only.
Combined with the earlier Midland Basin assessments of the Wolfcamp and Spraberry of 24
billion barrels combined, the total so far Technically Recoverable Resource is over 70
billion barrels oil.
Just as the Haynesville jumped from 39 Tcf to over 300 Tcf as the Haynesville/Bossier, the
Mancos from 1.6 to 66 Tcf, the Barnett from 26 to 52 Tcf, the Bakken/TF will jump next
assessment and both the Utica and Marcellus will skyrocket.
I know less about Marcellus, but Bakken/Three Forks was recently assessed in 2013, the new
assessment may be an increase, but I won't speculate in advance what it will be.
The 46 Gb mean undiscovered TRR for the Wolfcamp (Delaware Basin) and Bonespring is a
surprise to me, based on this the Permian tight oil TRR would be about 74 Gb, before this
assessment I had guessed 8 Gb for Delaware Wolfcamp based on output compared to Midland
Wolfcamp (it was about 30% of Midland so I took the 20 Gb Midland Wolfcamp times 0.3 and
rounded to 8 Gb). My previous mean estimate for Permian tight oil TRR was 38 Gb, so I was too
low by more than a factor of 2. My F5 (5% probability TRR might be higher) estimate was 54 Gb
before and the F95 estimate was 20 Gb, these are revised to F95=43 Gb and F5=113 Gb.
For the entire US I had a previous TRR estimate of 70 Gb for all of the US, this is
revised to 107 Gb for the mean US tight oil TRR.
An interesting development that might push the US peak in tight oil a little later and/or
a little higher. My F5 model had the Permian peak at about 7.5 Mb/d in 2027, a new model
might result in 2029 at 9.5 Mb/d, for the US as a whole, other tight oil plays might be
declining by 2029, so the overall US peak might be 2027 or 2028, based on current
information.
The formal report. The references are . . . a bit odd. There is a sense the whole thing is
dependent on technology results assessment from IHS.
Meaning, I don't see anything here that suggests USGS sent teams out to look at rock for
this whole area. They seem to have taken info from other IHS papers -- and the recent ones
from USGS were for what looks like much more limited geographic areas. Looks like IHS
encouraged extrapolation.
Btw someone at Bloomberg has declared this is a X2 on previous estimates. That would suggest
46 billion barrels of oil we're not just added to the US resource database. It would be more
like 23.
The Bloomberg guy didn't seem all that sharp, and so let's not take that as gospel.
Probably worth noting that it would not take much variance to move this resource into an
API 45+ or even 50+ configuration, and given the NAT gas and NGL estimates, that would seem a
pretty credible scenario. In which case it's not oil.
The Monterrey estimate was a study done for the EIA which was poorly done (it was not a USGS
estimate), the USGS estimates tend to be pretty good and have tended to be on the
conservative side, though we won't know for sure until all the oil is produced and the last
well is shut in. Every resource estimate involves extrapolation and/or modelling of future
well output by definition.
Some estimates are better than others, for example the USGS estimates are better than the
EIA estimates in most cases.
Previously I has guessed (incorrectly) that Permian mean TRR would be 38 Gb, this new
assessment would lead to a revision to about 74 Gb for mean TRR of the Permian Basin tight
oil resource.
In the scenario below I have a 253,000 well scenario (about 6 times more than my ND
Bakken/Three Forks mean scenario with 42,000 wells completed.) I assume new well EUR starts
to decrease in Jan 2023(about 3 years after my estimate of the future ND Bakken EUR decrease
start as Permian ramp up started about 3 years after Bakken). This assumption is easily
modified.
Peak is about 2028 with peak output at about 7000 kb/d (currently Permian tight oil output
is about 2750 kb/d based on EIA tight oil production estimates by play).
The scenario above does not consider economics. When we consider the discounted net revenue
over the life of the well and assume this must equal the real well cost in order for the well
to be completed using the assumptions below, then we find an economically recoverable
resource (ERR) scenario.
Economic assumptions (all costs in constant 2017$) are:
real oil prices in 2017$ follow the EIA AEO 2018 Reference Brent Oil Price scenario
royalties and taxes are 32% of wellhead revenue
transport cost is $4/b
OPEX is $2.3/b plus $15000 per month per well
real annual discount rate is 7% (nominal rate is 10% at 3% annual inflation rate)
real well cost=9.5 million 2017US$
Peak output is unchanged but wells completed are reduced to 173,000 and ERR=60 Gb.
The indications from drilling companies, so far, operating in the Delaware do not seem to
jive with the assessment of grandiosity. So, I am more than skeptical. The government can
create all the reserves they want, but if the oil companies can't get it out of the ground??
My understanding is that there is a core area in West Texas and NM. EOG is there. Extends a
few Counties in West Texas and NM starting around Loving County. Even there, it is high api.
Outside of that, it is highly sporadic. If you extrapolate what they are doing in tiny Loving
County to the rest of the Delaware, you can come up with these numbers. But, you can't. As I
read, there are over 800 Ducs outside of this area. You leave them as Ducs, because you
pretty much know what the completion will look like after drilling. Basically, the report is
hogwash. It's pretty easy to tell on the Texas side, as you can pull up completions by
county.
It may require higher oil prices and the associated gas is a problem, not enough
infrastructure to move it.
Also the USGS simply does a resource assessment, these are not reserves, no economic
assessment was done, the USGS leaves that to others.
I have often been skeptical of USGS Assessments (such as Bakken Assessment in 2013),
looking at proved reserves and cumulative production to data in the ND Bakken/Three Forks,
the 11 Gb mean TRR estimate from 2013 looks pretty good.
As a working petroleum geologist in the Delaware Basin and others, I will say USGS and EIA
assessments are considered a joke. They do little to take into account the actual geology, or
changes in the thermal maturity of the rock across a basin, it is more multiply an average
well performance for a certain amount of acres drilled, times the total area of the basin,
minus the number of drilled wells.
Everything is more complex than that. Right now operators
are drilling the best, most economic parts of the Delaware basin, at the going rate it will
not be too many years before they have to shift over to other benches of the Wolfcamp or Bone
Spring, which will be less productive. for deeper Wolfcamp benches you get more condensate,
less oil, much more gas, you might go from a 10,000′ lateral making 1-2 MMBO in the
Wolfcamp A, down to one making 300-500 MBO.
Still a decent well when you add in the gas, but
if you take that across a large area that will lead to a substantial decline in new well
performance. I would not doubt oil production peaks in the mid-2020s as people drill up the
best rock, and have to keep shifting to less productive horizons.
Can you give us your estimate of the TRR or ERR of the Delaware Wolfcamp and Bonespring.
There is a wide range in the USGS TRR estimate from 27 to 71 Gb with a mean of 46 Gb and a
median of 45 Gb. Would you say that 27 Gb is too high? It seems clear you think that 46 Gb is
far too optimistic. Note that the mean ERR would probably be around 38 Gb if the mean TRR
estimate was correct and prices follow the AEO 2018 reference price scenario. For the F95
USGS TRR estimate the ERR would be around 21 Gb.
Maybe you could also comment on other USGS assessments for Eagle Ford, Wolfcamp Midland
basin and Spraberry. Perhaps you could give us the "correct assessment".
I agree the EIA assessments are not good, economists do not know much about geophysics.
The people at the USGS are scientists, though they have limited information and thus use
statistical analysis to fill the data gaps.
Come on, Dennis. He may be a geologist, but my bet he is mortal, like you and I.
I really believe your first graph with 8 million as the high is the best I have seen. The
tail of that is probably not ever to be properly guessed, until it happens.
Dood, one of the most frequent points we deal with on this blog is the claim that technology
in horizontal fracking has multiplied output tremendously -- excluding from consideration
stage count/length.
The extra production "per well" seems to be from the well being longer in length and thus
consuming more water and proppant. Is this true, or is there some magical improvement in
proppant type or fracking pressure or whatever?
It's mostly the length of the lateral, although some is due to increased fracking stages
within the lateral (more holes in the pipe). Better drilling is another, although extra
lateral makes up most of it. The laterals, in general, are about twice as long.
Hanh? And this paragraph strikes this lay reader as utterly incoherent:
The U.S. sold overseas last week a net 211,000 barrels a day of crude and refined
products such as gasoline and diesel, compared to net imports of about 3 million barrels a
day on average so far in 2018, and an annual peak of more than 12 million barrels a day in
2005, according to the U.S. Energy Information Administration.
From EIA: "In 2017, the United States consumed about 19.96 million barrels per day." Let's
call it 20.
Also from EIA: US weekly field production ending 11/30: 11.7 million barrels.
20-11.7=8.3????
True? Fudging? Lying? What am I missing?
Then, you read further into the article:
While the net balance shows the U.S. is selling more petroleum than buying, American
refiners continue to buy millions of barrels each day of overseas crude and fuel. The U.S.
imports more than 7 million barrels a day of crude from all over the globe to help feed its
refineries, which consume more than 17 million barrels each day.
The US refines a lot of imported oil -- for export. There is refinery gain in this. This
means a barrel comes in. It is refined to various constituent parts like gasoline, diesel,
kerosene, etc. The VOLUME of these parts are liquids of less density and this means their
volume is greater. So a barrel of crude will yield a sum total of more than 1 barrel of
liquids of lower density. Since these products are exported, the barrel count is in favor of
exports vs the barrel count imported.
This is not a huge effect, but it's significant.
There's an EIA page for US sales volume consumed. If you add up all the products you get
well over 15 million bpd. US production is rather less than that. Imports must exceed
exports.
Thanks for trying to explain it to me. Maybe it's just too complicated for me to understand.
I still can't reconcile the headline, "US becomes a net oil exporter" with the EIA's
numbers: The US consumes 20 million barrels a day. The US produces 12 million barrels a day.
But, yes, they're net exporters. Whatever.
After 14 years, the niceties of peak oil still escape me.
I am not sure I follow you entirely, but for heavier crude oils there is waste to get to
diesel (a bit higher than 30 API). And for extra light oil there is a huge waste to get to
diesel, as much has to be segregated to petroleum gas and gasoline components due to length
of carbon chain.
The case for diesel shortage in 2020 due to shipping legislation is still very much
legit.
I was talking about imported crude (that would not be LTO and probably diesel rich) being
refined into a larger number of barrels of product vs the barrels of input crude. They
export. It's a bias towards export.
I think mostly the report derives from very noisy weekly data. The US is not a net
exporter.
Donald Trump could hardly have chosen a more treacherous economic moment to tear up the
"decaying and rotten deal" with Iran. The world crude market is already tightening very fast. He
estimates that sanctions will cut Iran's exports by up to 500,000 barrels this year. "It could
well be twice more cut in 2019
North America has run into an infrastructure crunch. There are not yet enough pipelines to
keep pace with shale oil output from the Permian Basin of west Texas, and it is much the same
story in the Alberta tar sands. The prospect of losing several hundred thousand barrels a day of
Iranian oil exports would not have mattered much a year ago. It certainly matters now.
Notable quotes:
"... The peak oil theme is very much forgotten in all the turmoil, but is very real still. ..."
"... How much more reserves to classify as probable (2p) is a movable target, it depends on the oil price. ..."
"... I agree that 2019 will show big declines in OECD inventory primarily because core OPEC wants it. (increasing KSA premiums to the US +3,5 dollars in Jan and lowering it to Asia). ..."
"... Or still more likely, a spike in oil prices in 2H 2019 and a recession soon thereafter. ..."
"... Who knows..the only thing certain is that oil is being pressured towards the final "spare capacity" (whatever that is) and that a recession will come anyway as a result of the low oil price environment the last 4 years. ..."
The peak oil theme is very much forgotten in all the turmoil, but is very real
still.
How much more reserves to classify as probable (2p) is a movable target, it depends on
the oil price.
And how rapid the extraction rates of reserves can extend to difficult to say; technology
and not at least the 3D maps of reservoirs coupled with improved seismic data, more precise
drilling and lower costs due to excess oil service capacity (at least for offshore) have
countered the inevitable declining quality of oil reservoirs and size of new ones coming
online for some time now.
I agree that 2019 will show big declines in OECD inventory primarily because core OPEC
wants it. (increasing KSA premiums to the US +3,5 dollars in Jan and lowering it to
Asia).
The next question is how high oil prices will go before there is some reaction from the
nations that have spare storage/capacity. I am thinking there is some relief in increased
pipeline capacity in Texas in 2H 2019 and also Johan Sverdrup in Norway (since I follow
things close to home) in the same time period to save the oil market in winter 2020.
Or still more likely, a spike in oil prices in 2H 2019 and a recession soon
thereafter.
Who knows..the only thing certain is that oil is being pressured towards the final "spare
capacity" (whatever that is) and that a recession will come anyway as a result of the low oil
price environment the last 4 years.
Offshore is hit hard, so are supply in places "too risky" for cheap financing the hidden
secret of the oil market (why so few news stories covering this?)
Saved from $40 oil, but I really doubt there will be much of a frenzy at $52 oil price.
Hopefully, that will give them enough cash flow for stationary. They need to write Christmas
letters to their shareholders telling them everything will be better next year.
That discovery chart shows the problem well, I hadn't seen it before. The big blip in deep
water discoveries in the 2000s from improved technologies and higher prices contributed
greatly to the subsequent glut and price collapse – and now what's left? There hasn't
been much of an uptick in exploration despite the price rally, offshore drillers continue to
go bust, leasing activity still fairly slow – the tranches get bigger as the last, less
attractive bits are released but lease ratio falls, Permian dominates all news stories. Why
would the recent decline curve turn around? And the biggest surprise might be that gas is
just as bad as oil, so the recent boost in supplies from condensate and NGL might also have
run its course.
I tracked FIDs for oil through 2017, I've been a bit less diligent this year so may have
missed some, but for greenfield conventional plus oil sands I have for the remainder of 2018
through 2025: 400, 1770, 1170, 800, 985, 70, 250, 400 kbpd added – about 6 mmbpd total,
nothing after 2025, plus another 1 mmbpd from ramp ups from this year. Only pretty small
projects could get done now before 2022, and there aren't many of those left. Anything else
would need to come from brownfield (in-fill), LTO or new discoveries (including existing
known resources that become reserves once a development decision is made).
High economic growth matched high growth in energy consumption and recessions saw fall in
energy consumption.
Since 90% of the energy consumed comes from burning the stored energy in coal, oil, gas
and wood. It is hardly surprising that during high economic growth CO2 emissions increase
also.
Those who not not wish to see this link, obviously think Peak Oil is not a problem. GDP
growth will continue even though oil becomes more scarce.
If oil production falls by just 1% per year, taking into account new vehicle production.
The world would have to produce 90 million electric cars each year in order to prevent oil
prices from destroying other users such as the aviation industry.
This year 1.5 million fully electric cars were made and according to several people here
peak oil is no more then 4 years away.
Since 90% of the energy consumed comes from burning the stored energy in coal, oil, gas
and wood. It is hardly surprising that during high economic growth CO2 emissions increase
also
I have a hunch that we are about to see some major changes to that paradigm.
I hope you are correct, but I have done some calculations on what is needed.
According to reports around $1.7 trillion was invested in energy supply in 2017. $790
billion on oil, gas and coal supply. $320 billion was spent on solar and wind.
During 2017 oil consumption increased by 1 million barrels per day. Gas consumption increased
by 3% and even coal consumption went up.
The world needs to spend about $2.5 trillion per year on wind, solar and batteries in
order to meet increased energy demand and reduce fossil fuel burning by about 1% per year.
This obviously depends on GDP growth being about average.
Since recent scientific observations have discovered that Greenland, the Arctic and
Antarctica melting much faster than anyone thought. The shift needs to be a minimum of 2.5%.
Thus a spending of around £4 trillion per year is needed.
I do not see any country spending a minimum of 12 times more on solar and wind in the next
3-5 years. It would take every country doing so.
Agreed Hugo. The world is only making token moves towards installation of the necessary wind
and solar.
This coming decade will see everyone scrambling to get the equipment built and installed.
Looks like centralized planning (China) is going to beat 'the market' on being the primary
supplier. Our 'free' market has tariffs on PV imported. Brilliant.
Does having a 5 (or 10 yr) plan make you communist?
Or just smart.
"The world needs to spend about $2.5 trillion per year on wind, solar and batteries in order
to meet increased energy demand and reduce fossil fuel burning by about 1% per year. This
obviously depends on GDP growth being about average."
1% per year? You have got to be kidding.
The global oil consumption for transport is about 39.5 million barrels of oil per day. Using
PV to drive EV transport would mean an investment of 2.2 trillion dollars in PV to provide
global road transport energy.
So what do we use next year's money for?
.
"The global oil consumption for transport is about 39.5 million barrels of oil per day"
39.5 million is only gasoline in the world. Add diesel and jet fuel and you get to about
75 million barrels a day for transportation or about 75% of oil produced.
Did you get the point? That Hugo overstated the cost of renewables to replace fossil fuels
by a huge amount and understated their effect by another huge amount.
We have a couple of people that consistently do that on this site.
The cost of producing a large lithium battery is high and it is "perishable product",
which will not last even 10 years. The average life expectancy of a new EV battery at about
five (Tesla) to eight years. Or about 1500 cycles (assuming daily partial recharge, which
prolongs the life of the battery) before reaching 80% of its capacity rating. https://www.quora.com/What-is-the-cycle-lifetime-of-lithium-ion-batteries
Battery performance and lifespan begins to suffer as soon as the temperature climbs above
86 degrees Fahrenheit. A temperature above 86 degrees F affects the battery pack performance
instantly and often permanently. https://phys.org/news/2013-04-life-lithium-ion-batteries-electric.html
It is also became almost inoperative at below freezing point temperatures. For example it
can't be charged.
So they need to be cooled at summer and heated at winter. Storing such a car on the street
is out of question. You need a garage.
And large auto battery typically starts deteriorating after three years of daily use or
800 daily cycles.
Regular gas, and , especially, diesel cars can last 20 years, and larger trucks can last
30 years.
This fracking can't go on much longer. They've drilled out much of the sweet spots already,
and from what I hear, there are already 7 'child' wells being drilled for every 'parent'
well. (as I understand it, a 'child' well is drilled in close proximity to the 'parent'
without – hopefully-hitting and drawing from the same formation') If fracking were to
stop tomorrow, you'd lose over 600k bbls/day in production immediately and the whatever is
leftover tapering off to zero over the course of two-three years.
The question is: Just how long will the USA be able to continue to increase production in
order to hold off peak oil?
Yes will it go bankrupt first or continue to run on until peak and depletion. Meanwhile it
drags down the oil price artificially making most other oil development less likely, and
increasing volatility.
The FED is reducing money supply by 50 billions per month at the moment. The first feeling it
will be comanies needing to sell junk bonds.
This is a big ploblem for the relentless "drill baby drill" programs of several LTO
companies.
And a global economic crises, even if only a few years long, will crash oil prices AND
credit supply. This will hurt LTO more than the oil price crash from 2015.
On the shale topic; it is marvelously stupefying to observe a heavily indebted shale
industry supplying increasing volumes of oil, to an extent that the price/bbl never hits a
level where any debt reduction can be realized. (to say nothing of profit)
Its' almost as if they have no intention of becoming solvent.
Some time ago presented estimate of oil used to create and move food in the US. My recall is
the number wasn't huge.
Recently came across new data. Will get around to laying it out.
25% of total US consumption. Tractors, insecticides, some fertilizer(transport of those to
the field), transport of animal food to hogs, beef, etc, transport of human food to shelves,
transport of people to the shelf and home. 15% pre transport of human food, 10% transport
human food.
Pretty efficient agriculture in the US. No squeezing that 5 mbpd.
There are a lot of things that you can running one trillion deficit ;-)
Notable quotes:
"... U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to EIA's latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy's estimated August production of 11.2 million b/d, making the United States the leading crude oil producer in the world. ..."
"... All of this bullshit is straight, I mean straight off Continental's self servicing investor presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some common sense and think for yourself. As opposed to letting someone else do your thinking for you. ..."
"... Watcher is correct, CLR's credit rating, its credit score, so to speak, is so bad it could not in the real world buy a pickup truck without its mama co-signing the note. If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to? Never mind, you can't answer that. ..."
"... "If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to?" ..."
"... We had 5-6 years of the highest, sustained oil prices in history and the shale oil industry could NOT make a profit. People seem to think now things have changed for some reason, that the shale oil industry has now become more ethical, and temporarily higher productivity of wells, and some imaginary oil price off in the future (for most shale guys its now down in the mid to low $50's) will allow them to pay down debt. Its absurd logic, but keeps people occupied, I guess, speculating about it. ..."
"... One thing to add. The shale companies did all this in the lowest interest rate environment we have had in a long time. They could not pay off their debt or even put a dent in it. What is going to happen when their interest costs increase 30-50% over the next 2-3 years? ..."
"... I was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in 2007 and gas prices were the highest they had ever been, it was not cash flow positive. ..."
"... On the price, I understand why you use different scenarios. However, the average price over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14 and 2015–17. ..."
"... However, the price is far too volatile to model anything very far into the future, just like we cannot budget past one year, and usually have to make adjustments to that. ..."
"... Our price has dropped over $10 in less than one month. That makes a huge difference, yet that level of volatility is common and has been for many years. ..."
"... What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the market prices of 2011-14, we would be bankrupt, absent having hedged everything for four years, which is very difficult to do. ..."
"... Few companies with zero debt ever go BK. We would with WTI at $30 for about three years. Is that likely? No, but oil did drop below that level in 2016. ..."
U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018,
according to EIA's latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is
the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil
production exceeded the Russian Ministry of Energy's estimated August production of 11.2
million b/d, making the United States the leading crude oil producer in the world.
Dennis, Coffee's comment did not turn me into a shale cheerleader. I suppose I am more in the
shale sceptic camp for the reasons you mention and others.
Nevertheless, I think Coffee's comment was correct, it does appear that shale producers in
the Bakken have expanded the area that produces exceptional wells. As one who underestimated
shale's viability before, I don't want to repeat the same mistake.
As you note, it is difficult to predict when average well productivity in the Bakken (or
anywhere) will occur. I had thought that current drilling levels would be inadequate to
sustain 1.15 million bpd production levels, but somehow they are increasing production there.
It does appear that for now, the shale operators are having some success.
How long that success will last depends not only on the operational decisions made, but macro
factors such as debt, interest rates, and the economy will play out, and eventually Bakken
production will decline. But for now
I have not read Continental's conference call transcript yet (Seeking Alpha provides
them), but it seems the suit from Continental now feels they will recover – from
present completions – 15 to 20 per cent of the OOIP.
That is huge as the norm was 3 to 5 per cent a few years back.
All of this bullshit is straight, I mean straight off Continental's self servicing investor
presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some
common sense and think for yourself. As opposed to letting someone else do your thinking for
you.
Watcher is correct, CLR's credit rating, its credit score, so to speak, is so bad it could
not in the real world buy a pickup truck without its mama co-signing the note. If its wells
are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt
back? I mean really, who in their right mind would actually WANT to pay $420MM a year in
interest on long term debt if it didn't have to? Never mind, you can't answer that.
If you are not in the oil business and have never balanced an oil well's checkbook in your
life, which Coffee hasn't, then you don't know that higher productivity comes with a higher
cost in the shale biz. The bottom line then is that the bottom line does not change if it did
the shale oil industry would be paying down some debt, right? Its not. Private debt is
skyrocketing.
Are things getting better for the shale biz? Right. Case in point, the largest pure
Permian Basin oil and associated gas producer, Concho, the genius behind a recent $8 billion
dollar acquisition from RSP, LOST $199MM 3Q2018. Inventories are going back up, prices are
down 18% the past month and what does the shale oil industry do?
It adds more rigs.
Productivity is not the same as profitability. In the real oil biz you learn that on about
day six.
"If its wells are sooooooo much better, why don't they pay some of that $6 billion plus
dollars of debt back? I mean really, who in their right mind would actually WANT to pay
$420MM a year in interest on long term debt if it didn't have to?"
I wonder about debt service, too.
When Dennis runs his scenarios he says that at a certain oil price, these companies will
be quite able to pay down debt.
But will they? Or will they just pay themselves as much as they can as long as they can
get away with it, and then declare bankruptcy and walk away.
We had 5-6 years of the highest, sustained oil prices in history and the shale oil
industry could NOT make a profit. People seem to think now things have changed for some
reason, that the shale oil industry has now become more ethical, and temporarily higher
productivity of wells, and some imaginary oil price off in the future (for most shale guys
its now down in the mid to low $50's) will allow them to pay down debt. Its absurd logic, but
keeps people occupied, I guess, speculating about it.
I urge folks to ignore the guessing, and the lying, (Hamm's 20% of OOIP in the Bakken is a
big 'ol whopper) and look at the shale industry's financial performance over the past 10
years and decide for yourselves if it is sustainable or not.
One thing to add. The shale companies did all this in the lowest interest rate environment we
have had in a long time. They could not pay off their debt or even put a dent in it. What is
going to happen when their interest costs increase 30-50% over the next 2-3 years?
I was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in
2007 and gas prices were the highest they had ever been, it was not cash flow positive. It
actually ate all the revenue from the rest of the company. Getting to be in the black for the
play was always a year off. a decade later it never got there, they just got more and more
debt sold more producing assets to pay for it to keep the shell game going and just got
bought by Encanna. I have seen the same at every public company I have worked for, many of
them survived the downturn only because costs dropped and so did the cost of debt. Now with
increasing costs and cost of debt there will likely be many bankruptcies.
Yeah, I agree with Mike, Rystads announcements are mainly just self serving hogwash. Yes, oil
production in the US looks to be close to 11.3 million for August. EIA's reported production
for Texas is only about 50k over my high estimate, so I see nothing to argue about. GOM is
the main surprise, and George and others are better suited to comment on that. The
understanding I had was that it was temporary. As far as Texas goes, I'm pretty sure it is
the high, for awhile. Completions dictate how much oil comes out of the ground, not drilling
rigs. That is for unconventional wells, not conventional. That is why I think the EIA's DPR
is a ridiculous measurement assessment. Apples and oranges. Articles that I have read
indicate a significant decrease in completions in the Permian by the end of August. Texas
production is not all about the Permian. A significant amount was contributed by the Eagle
Ford and other areas. All completions have slowed to the point that by the end of September,
they were at slightly over 60% of June's completion numbers according to RRC statistics.
Significant drop, and it will show up in following months. First years decline rates will
assure that it will drop slightly from this point. $64 WTI won't motivate it to expand to any
extent. The next year will see US wavering along the 11.1 million barrel level, I still
think. Unless, George thinks the GOM increase is somewhat permanent, which I doubt.
And try to locate a time in history when production is trending up, while completions are
trending down. There is usually a several month lag by the time production slows. Takes a
while to get out of the ground if they are completed towards the end of the month.
Don't you just love simple logic? Like: fire burns, water is wet, stuff like that?
I second that. Being from Norway myself, and having actually been working in consulting some
years ago. It looks nice on paper, but the world is changing and it is wise to look out for
deception and that is often the case in consulting (customer/revenue first and reality
second).
Based on the shaleprofile data it looks as if well productivity increased alot in 2016 and
2017 due to longer laterals and increased proppant intensity. 2018 well productivity looks to
be trending pretty close to 2017, so the productivity gains from longer lats and increased
proppant might have been exhausted by now. Therefore, comparing 2018 well completion numbers
to any pre 2017 completion numbers won't tell you much, but a comparison of 2018 and 2017
numbers should. In the 4 months ending in September 2018 completions grew year over year by
almost 70% from 2017, hence the large assumed increase in production in the last four months
of 2018. What is interesting though is that it looks like the free lunch from increased lats
and proppant looks to be almost over, and any future increases in production must be the
result of an increase in completion activity, which should result in some inflation for the
service providers going forward. And, according to Schlumberger, if you adjust for the longer
lats and increased proppant it actually appears that productivity is starting to trend down
(and the increased usage of poor quality in basin sand will likely contribute to this as
well)
I take your word for it. Thank you, BTW. You are the only one left on this site that has any
common sense regarding shale oil economics and the burden all that massive, massive amount of
debt has on running a business where your assets decline at the rate of 28-15% annually.
Everybody else seems mesmerized by productivity.
Paying the debt off will depend very much on future oil and natural gas prices.
Once growth slows the companies will be companies operating many low volume wells.
Investors will want these companies to pay dividends because they will not be in a position
to grow. The operating costs will be higher, even though CAPEX will drop.
You are very confident prices will be high in the future. I suspect they will be volatile
in the future, as they have been for the past 20 years.
So, on a company by company basis, timing will be critical, IMO.
The prices can be thought of as 3 year average prices, yes there will be volatility, my
"low price scenario" has Brent Oil Price in 2017 $ never rising above $80/b. I cannot hope to
predict the exact oil price and of course oil prices will be volatile, but the average over
time allows a pretty good estimate.
Also a company by company model is a little too much work. I just do the industry average,
some companies will be better and some worse than average.
It certainly is the case that oil prices have been volatile and I agree this will
continue, but the three year trend in prices (centered 3 year average) has been up $7/b for
the past year, my expectation is that this trend will continue and the 3 year centered
average price will reach $80/b (in 2017$) by 2021 or 2022. The trend of oil prices will be
higher, if the peak arrives by 2025 as I expect prices (3 year centered average oil price in
2017$) are likely to reach $100/b by 2024 or 2025.
I think company by company because I have an investment in a private company. I know how
important timing is in the upstream industry to individual companies.
Likewise, I understand you aren't all that interested in individual companies. No problem
there.
On the price, I understand why you use different scenarios. However, the average price
over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14
and 2015–17.
I was recently in a major city and saw more Tesla's than I ever had, including my first
Model 3 sighting.
Our little area now has two Model S, with the early adopter trading his 2012 for a
2018.
Pretty doubtful it will be $50/b over the next three years, in my opinion. If you believe
that you should find another business More likely is a gradual increase in
oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price
(today's future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61
(Dec 2026). By Contrast the EIA's AEO 2018 reference oil price scenario for Brent crude has
the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too
low.)
As always clicking on the chart give a larger view.
The price could be $50 from 2019-2021, and then $125 from 2022-2025. (Averages, of
course).
So in that scenario I'd feel pretty bad if I sold out in say 2020.
Your models are ok, I have no problem with you doing them. We try to make a budget for
every year.
However, the price is far too volatile to model anything very far into the future, just
like we cannot budget past one year, and usually have to make adjustments to that.
Our price has dropped over $10 in less than one month. That makes a huge difference, yet
that level of volatility is common and has been for many years.
What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate
to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the
market prices of 2011-14, we would be bankrupt, absent having hedged everything for four
years, which is very difficult to do.
On a flowing barrel basis, I have seen leases sell as low as $2,000 per barrel and as high
as $180,000 per barrel in our basin from 1997-2018. That is what an oil price range of $8-140
per barrel will do.
Few companies with zero debt ever go BK. We would with WTI at $30 for about three years.
Is that likely? No, but oil did drop below that level in 2016.
The volatility is a big problem, there is no doubt of that. When imagining the "big
picture". I use the estimates of the EIA's AEO as a starting point then add my personal
perspective (that at some point oil output will peak.) Below is a chart with my guess from
Dec 2014 for future Brent oil prices in constant 2014$, nominal Brent spot price is give for
comparison.
Clearly my guess was not very good, the EIA guess from the AEO 2015 was also not great,
but better than my guess. Future guesses will be equally bad.
In 2013 we assumed prices in a range of $60-120 WTI moving forward.
In June of 2014 when oil spiked up and we received $99.25 in the field, we suspected oil
would fall and it began to. We again continued to assume $60 WTI would be a low.
We were dead wrong, of course.
Oil dropped again today. We will get $67 in the field for October sales paid in November.
However, our price today is down to $56.50. That is about a $60,000 per month revenue hit to
a small company which employs 8 full time employees, one part time employee office manager
and utilized numerous contractors (rigs, electricians, etc.).
Corn here is $3.51 per bushel today. Less than a month ago it was $2.96 per bushel.
Yes, yes, a hedging program would mitigate the price volatility.
Until you actually try to hedge with money at risk, don't talk to me about that. It's
about as easy as trading stocks. It is also very expensive due to the volatility. Or, if you
do SWAPS or Collars, you need to put up a lot of margin money.
Hedging seems a risky business, not sure I would come out ahead by hedging. You are in a
tough business, the volatility sucks. The silver lining is that prices will be
increasing.
Shallow Sand Wrote:
"Paying the debt off will depend very much on future oil and natural gas prices."
I don't think so. When energy prices rise, so do prices of everything else, included
interest rates. The only way the shale drillers could play off there debt is if the left
large number of completed wells untapped (ie leave it in the ground) while taking advantage
of cheap debt & low labor\material costs. Then selling the oil when prices & costs
have soared above investment costs.
The issue is that as soon as a well is completed, they start producing, at market prices.
Thus when oil prices rise most of the oil is already produced & drilling new wells (using
more debt) does not pay down the old debt.
Also consider the costs shale drillers will need for decommissioning older\depleted well.
I believe the cleanup cost is between $50K & $100K per drill site. To date have any shale
drillers spent money on clean up for depleted wells yet, or is it all deferred (ie never
going to happen)?
FWIW: I don't believe any of the shale companies are in game for the long term. They are
simply a modern Ponzi scam, taking investor money & providing an illusion of profitabity
by selling a product below cost. They will continue to play the game until investor capital
dries up.
I suspect that most shale drillers will go bust in the next 5 years when the bulk of their
bonds come due & they won't have the ability to refinance it or pay it off. If I recall
correctly Shale drillers will need to payoff or refinance about $270B in high-yield bonds
between 2020 & 2022.
The key question not addressed by the author is how long the period of "plato oil
production" (the last stage of the so called "oil age", which started around 1911) might
last -- 10, 20 or 50 years. And the oil age is just a very short blip in Earth
history.
Let's assume that this means less the $100 per barrel; in the past, it was $70 per
barrel that considered the level that guarantees the recession in the USA, but financial
system machinations now probably reached a new level, so that might not be true any
longer. The trillion dollars question is "How long this period can be extended?"
It is important to understand the US shale oil is not profitable and never will be for
prices under $80 or so. At prices below that level, it actually produces three products,
not two – oil, gas and junk bonds.
I view it as a very sophisticated, very innovative gamble to pressure oil prices down
and get compensation for the losses due to large amount of imported oil (the USA export
mainly lightweight oil which is kind of "subprime oil" often used for dilution of heavy
oil in countries such as Canada and Venezuela, but imports quality oil).
If the hypothesis that Saudis and Russians are close to Seneca Cliff (Saudi prince
recently said that Russian are just 10-15 years from it) and that best days of the US
shale and Gulf of Mexico deep oil is in the past if true, then "Houston we have a
problem".
That means that in 20 years, or so the civilization might experience some kind of
collapse, and the population of the Earth might start rapidly shrinking.
While the U.S. Shale Industry
produces a record amount of oil, it continues to be plagued by massive oil decline rates and debt.
Moreover, even as the companies brag about lowering the break-even cost to produce shale oil, the
industry still spends more than it makes. When we add up all the negative factors weighing down
the shale oil industry, it should be no surprise that a catastrophic failure lies dead ahead.
Of course, most Americans have no idea that the U.S. Shale Oil Industry is nothing more than a
Ponzi Scheme because of the mainstream media's inability to report FACT from FICTION. However,
they don't deserve all of the blame as the shale energy industry has done an excellent job hiding
the financial distress from the public and investors by the use of highly technical jargon and BS.
For example, Pioneer published this in the recent Q2 2018 Press Release:
Pioneer placed 38 Version 3.0 wells on production during the second quarter of 2018. The
Company also placed 29 wells on production during the second quarter of 2018 that utilized
higher intensity completions compared to Version 3.0 wells. These are referred to as Version
3.0+ completions. Results from the 65 Version 3.0+ wells completed in 2017 and the first half of
2018 are outperforming production from nearby offset wells with less intense completions. Based
on the success of the higher intensity completions to date, the Company is adding approximately
60 Version 3.0+ completions in the second half of 2018.
Now, the information Pioneer published above wasn't all that technical, but it was full of BS.
Anytime the industry uses terms like "Version 3.0+ completions" to describe shale wells, this
normally means the use of "more technology" equals "more money."
As the shale industry
goes from 30 to 60 to 70 stage frack wells, this takes one hell of a lot more pipe, water, sand,
fracking chemicals and of course, money
.
However, the majority of investors and the public are clueless in regards to the staggering
costs it takes to produce shale oil because they are enamored by the "wonders of technology." For
some odd reason, they tend to overlook the simple premise that
MORE STUFF costs MORE MONEY.
Of course, the shale industry doesn't mind using MORE MONEY, especially if some other poor slob
pays the bill.
Shale Oil Industry: Deep The Denial
According to a recently released article by 40-year oil industry veteran, Mike Shellman,
"Deep
The Denial,"
he provided some sobering statistics on the shale industry:
I recently put somebody very smart on the necessary research (SEC K's, press releases
regarding private equity to private producers, etc.) to determine what total upstream shale oil
debt actually is.
We found it to be between $285-$300B (billion), both public and
private
. Kallanish Energy Consultants recently wrote that there is $240B of long term
E&P debt in the US maturing by 2023 and I think we should assume that at least 90 plus percent
of that is associated with shale oil. That is maturing debt, not total debt.
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B
annually in interest on long term debt.
Using its own self-touted "breakeven" oil price, the shale oil industry must then produce
over 1.5 Million BOPD just to pay interest on that debt each year. Those are barrels of oil that
cannot be used to deleverage debt, grow reserves, not even replace reserves that are declining
at rates of 28% to 15% per year that is just what it will take to service debt.
Using its own "breakeven" prices the US shale oil industry will ultimately have to
produce 9G BO of oil, as much as it has already produced in 10 years just to pay its total long
term debt back
.
Using Mike's figures, I made the following chart below:
For the U.S. Shale Oil Industry just to pay back its debt, it must produce 9 billion
barrels of oil.
That is one heck of a lot of oil as the industry has produced about 10
billion barrels to date. Again, as Mike states, it would take 9 billion barrels of shale oil to
pay back its $285-300 billion of debt (based on the shale industry's very own breakeven prices).
Furthermore, the shale industry may have to sell a quarter of its oil production (1.5
million barrels per day) just to service its debt by the end of 2019.
According to the
EIA, the U.S. Energy Information Agency, total shale oil (tight oil) production is now 6.2 million
barrels per day (mbd):
The majority of shale oil production comes from three fields and regions, the Eagle Ford (Blue),
the Bakken (Yellow) and the Permian (light, medium & dark brown). These three fields and regions
produce 5.2 mbd of the total 6.2 mbd of shale production.
Unfortunately, the shale industry continues to struggle with mounting debt and negative free
cash flow. The EIA recently published this chart showing the cash from operations versus capital
expenditures for 48 public domestic oil producers:
You will notice that capital expenditures (
brown line
) are still higher than
cash from operations (
blue line
). So, it doesn't seem to matter if the oil price
is over $100 (2013-2014) or less than $70 (2017-2018), the shale oil industry continues to spend
more money than it's making.
The shale energy companies have resorted to selling assets,
issuing stock and increasing debt to supplement their inadequate cash flow to fund operations.
A perfect example of this in practice is Pioneer Resources the number one shale oil producer in
the mighty Permian. While most companies increased their debt to fund operations, Pioneer decided
to take advantage of its high stock price by raising money via share dilution.
Pioneer's
outstanding shares ballooned from 115 million shares in 2010 to 170 million by 2017. From 2011 to
2016, Pioneer issued a staggering $5.4 billion in new stock
:
So, as Pioneer issued over $5 billion in stock to produce unprofitable shale oil and gas,
Continental Resources racked up more than $5 billion in debt during the same period. These are
both examples of "Ponzi Finance." Thus, the shale energy industry has been quite creative in
hoodwinking both the shareholder and capital investor.
Now, there is no coincidence that I have focused my research on Pioneer and Continental
Resources.
While Continental is the poster child of what's horribly wrong with the shale
oil industry in the Bakken, Pioneer is a role model for the same sort of insanity and delusional
thinking taking place in the Permian.
Pioneer Spends A Lot More Money With Unsatisfactory Production Results
To be able to understand what is going on in the U.S. shale industry, you have to be clever
enough to ignore the "Techno-jargon" in the press releases and read between the lines. As
mentioned above, Pioneer stated that it was going to add a lot more of its "high-tech" Version 3.0+
completion wells in the second half of 2018 because they were outperforming the older versions.
Well, I hope this is true because Pioneer's first half 2018 production results in the Permian
were quite disappointing compared to the previous period.
If we compare the increase of
Pioneer's shale oil production in the Permian versus its capital expenditures, something must be
seriously wrong
.
First, let's look at a breakdown of Pioneer's Permian energy production from their September
2018 Investor Presentation:
Pioneer's Permian oil and gas production is broken down between its horizontal shale and
vertical convention production. I will only focus on its horizontal shale production as this is
where the majority of their capital expenditures are taking place. The highlighted yellow line
shows Pioneer's horizontal shale oil production in the Permian Basin.
You will notice that Pioneer's shale oil production increased significantly in Q3 & Q4 2017
versus Q1 & Q2 2018. Furthermore, Pioneer's shale gas production surged in Q2 2018 by nearly 50%
(highlighted with a red box) compared to oil production only increasing 5%. That is a serious RED
FLAG for natural gas production to jump that much in one quarter.
Secondly, by comparing the increase of Pioneer's quarterly shale oil production in the Permian
with its capital expenditures, the results are less than satisfactory:
The RED LINE shows the amount of capital expenditures spent each quarter while the OLIVE colored
BARS represent the increase in Permian shale oil production. To simplify the figures in this
chart, I made the following graphic below:
Pioneer spent $1.36 billion in the second half of 2017 to increase its Permian shale oil
production by 30,232 barrels per day (bopd) compared to $1.7 billion in the first half of 2018
which only resulted in an additional 10,832 bopd
. Folks, it seems as if something
seriously went wrong for Pioneer in the Permian as the expenditure of $340 million more CAPEX
resulted in two-thirds less the production growth versus the previous period.
Third, while Pioneer (stock ticker PXD) proudly lists that they are one of the lowest cost
shale producers in the industry, they still suffer from negative free cash flow:
As we can see, Pioneer lists their breakeven oil price at approximately $22, which is downright
hilarious when they spent $132 million more on capital expenditures than the made in cash from
operations:
The public and investors need to understand that "oil breakeven costs" do not include capital
expenditures. And according to Pioneer's Q2 2018 Press Release, the company plans on spending
$3.4 billion on capital expenditures in 2018. The majority of the capital expenditures are spent
on drilling and completing horizontal shale wells.
For example, Pioneer brought on 130 new wells in the first half of 2018 and spent $1.7
billion on CAPEX (capital expenditures) versus 125 wells and $1.36 billion in 2H 2017.
I
have seen estimates that it cost approximately $9 million for Pioneer to drill a horizontal shale
well in the Permian. Thus, the 130 wells cost nearly $1.2 billion.
However, the interesting thing to take note is that Pioneer brought on 125 wells in 2H 2017 to
add 30,000+ barrels of new oil production compared to 130 wells in 1H 2018 that only added 10,000+
barrels.
So, how can Pioneer add five more wells (130 vs. 125) in 1H 2018 to see its oil
production increase a third of what it was in the previous period?
Regardless, the U.S. shale oil industry continues to spend more money than they make from
operations. While energy companies may have enjoyed lower costs when the industry was gutted by
super-low oil prices in 2015 and 2016, it seems as if inflation has made its way back into the
shale patch. Rising energy prices translate to higher costs for the shale energy industry. Rinse
and repeat.
Unfortunately, when the stock markets finally crack, so will energy and commodity prices.
Falling oil prices will cause severe damage to the Shale Industry as it struggles to stay afloat by
selling assets, issuing stock and increasing debt to continue producing unprofitable oil.
I believe the U.S. Shale Oil Industry will suffer catastrophic failure from the impact
of deflationary oil prices along with peaking production.
While U.S. Shale Oil production
has increased exponentially over the past decade, it will likely come down even faster.
Oil prices are down a bit, but are still close to multi-year highs. That should leave the
shale industry flush with cash. However, a long list of US shale companies are still struggling
to turn a profit. A new report
from the Institute for Energy Economics and Financial Analysis (IEEFA) and the Sightline
Institute detail the "alarming volumes of red ink" within the shale industry.
"Even after two and a half years of rising oil prices and growing expectations for
improved financial results, a review of 33 publicly traded oil and gas fracking companies shows
the companies posting negative free cash flows through June," the report's authors write.
The 33 small and medium-sized drillers posted a combined $3.9 billion in negative cash flow in
the first half of 2018.
The glaring problem with the poor financial results is that 2018 was supposed to be the year
that the shale industry finally turned a corner. Earlier this year, the International Energy
Agency painted a rosy portrait of US shale,
arguing in a report that "higher prices and operational improvements are putting the US
shale sector on track to achieve positive free cash flow in 2018 for the first time
ever."
The improved outlook came after years of mounting debt and negative cash flow. The IEA
estimates that the US shale industry generated cumulative negative free cash flow of over
$200 billion between 2010 and 2014. The oil market downturn that began in 2014 was supposed to
have changed profligate spending, pushing out inefficient companies and leaving the sector as a
whole much leaner and healthier.
"Current trends suggest that the shale industry as a whole may finally turn a profit in
2018, although downside risks remain," the IEA wrote in July. " Several companies expect
positive free cash flow based on an assumed oil price well below the levels seen so far in 2018
and there are clear indications that bond markets and banks are taking a more positive attitude
to the sector, following encouraging financial results for the first quarter."
But the warning signs
have been clear for some time. The Wall Street Journal reported
in August that the second quarter was a disappointment. The WSJ analyzed 50 companies, finding
that they spent a combined $2 billion more than they generated in the second quarter.
The new report from IEEFA and the Sightline Institute add more detail the industry's recent
performance. Only seven out of the 33 companies analyzed in the report had positive cash flow
in the first half of the year, and the whole group burned through a combined $5 billion in cash
reserves over that time period.
Even more remarkable is the fact that the negative financials come amidst a production boom.
The US continues to break production records week after week, and at over 11 million barrels
per day, the US could soon become the world's largest oil producer. Analysts differ over the
trajectory of shale, but they only argue over how fast output will grow.
Yet, even as drillers extract ever greater volumes of oil from the ground, they still are
not turning a profit. "To outward appearances, the US oil and gas industry is in the midst
of a decade-long boom," IEEFA and the Sightline Institute write in their report. However,
"America's fracking boom has been a world-class bust."
The ongoing struggles raises questions about the long-term. If the industry is still not
profitable – after a decade of drilling, after major efficiency improvements since 2014,
and after a sharp rebound in oil prices – when will it ever be profitable? Is there
something fundamentally problematic about the nature of shale drilling, which suffers from
steep decline rates over relatively short periods of time and requires constant spending and
drilling to maintain?
Third quarter results will start trickling in over the next few days and weeks, which should
provide more clues into the shale industry's health. There is even more pressure on drillers to
post profits because the third quarter saw much higher oil prices.
"Until the industry as a whole improves, producing both sustained profits and
consistently positive cash flows, careful investors would be wise to view fracking companies as
speculative investments," the authors of the report concluded.
"... US tight oil output was about 6200 kb/d in August 2018 according to the EIA, not that the DPR includes oil from the region of tight oil plays that is conventional oil, also it is a model that is not very good so I ignore the DPR ..."
Any guess what the price of crude would be today if we had no fracking in N. America?
Wild guess is all I've got, but I'm saying $142 (and much lower economic growth over the past
9 yrs- maybe even flat averaged for the whole period).
Any other speculations on this?
USA LTO is ~7.5 million bpd. That exceeds global spare capacity over demand as-is today by at
least four times. So if the world was still trying to consume what it is today, we would be
several million short and would have been short by seven figures for several years.
I think we would have found out if there really are any huge but uneconomical fields out
there by now as the panic from that set in a few years ago. A shortage on that scale means
arbitrary prices pending demand cap/destruction.
US tight oil output was about 6200 kb/d in August 2018 according to the EIA, not that the
DPR includes oil from the region of tight oil plays that is conventional oil, also it is a
model that is not very good so I ignore the DPR .
WAG on oil price with zero LTO output is $120/b in 2017$, plus or minus $20/b.
Canada (offshore), Hebron is expected to produce around 150,000 barrels a day, from about
40,000 barrels a day now.
2018-10-22 (The Globe and Mail) It's been one year since ExxonMobil's long-awaited Hebron
platform off the southeast coast of Newfoundland started pumping crude from its first well.
It took four years, $14 billion, 132,000 cubic metres of concrete and a few thousand workers
to bring it online, and so far, it's churning out about 40,000 barrels a day, with the crude
bound for markets in the U.S. Gulf states, Europe and much of eastern North America.
Eventually, Hebron will drill 20 to 30 wells, and is expected to produce around 150,000
barrels a day.
With an expected reserve of 700 million barrels of recoverable crude, the Hebron project is
expected to operate for 30 years. As Newfoundland's fourth offshore platform, it will play a
key role in the province's plan to double overall production to more than 650,000 barrels a
day by 2030.
https://www.theglobeandmail.com/business/article-why-hebron-has-a-leg-up-on-albertas-oil-sands/
Hebron is already at 70 kbpd and has been for a few months. I thinks its expected annual
average for oil only is 135 and it will take a year or so to get there as the coming wells
will be less productive that the first ones. In the mean time the three other platforms are
in decline (Terra Nova was originally due to be taken off line next year – not sure
what the latest thinking is). They dropped about 35 kbpd last year but that may accelerate as
Hibernia is coming off a secondary plateau.
Yeah, that's going to get a lot worse. It's counting Iran production, and not what it can
sell. A lot in floating storage, and being stored close to China and elsewhere. US is the
only one with an increase, and that increase is on a hiatus until new pipelines come on,
regardless of the EIA overstated production numbers. So, we would be short before any demand
increase, or non-OPEC declines. But, never worry, as IEA says peak oil is just a figment of
our imagination
"The Saudi government said it would take another month to complete a full investigation,
which would be overseen by Mohammed.
Mohammad will find that Mohammad had nothing to do with the issue."
Perhaps an anti-KSA Boycott, Divestment, Sanctions (BDS) Movement will get started.
Consumers and competitors might find the idea appealing.
Nice ideas for new KSA flag designs at this link here (I most like the chainsaw instead of
the current sword design- reminds me of Scarface- Mo Bin Clownstick™ is about as
legitimate and sophisticated as a coke runner): https://www.moonofalabama.org/2018/10/saudis-admit-khashoggi-murder.html
The Sultan is playing his hand well (drip drip drip Turkish Int. leaks to the news with an
intensifying puke factor- one recent read that Khashoggi was dismembered alive and dissolved
in acid). Has Mo Bin Clownstick™ met his match? https://lobelog.com/the-geopolitics-of-the-khashoggi-murder/
I can't help but wonder about all those guys he threw into a hotel prison and shook down for
billions of dollars. They can afford a lot of media with the money they had remaining.
From the report: The $3.9 billion in negative cash flows in the first two quarters of 2018 represented an
improvement over the first halves of 2016 and 2017, when red ink totaled $11 billion and $7.2
billion, respectively.
These 33 companies have had positive net income since 2017Q4 and long term debt reached
its peak for these companies in 2018Q1 at 138 billion with a gradual decrease to 126 billion
in 2018Q2. As prices continue to rise debt will gradually be paid down,
When I look at that report I see an improving situation for these companies. I would
prefer it if they broke the data into two groups, oil focused and natural gas focused
companies. There has been a better recovery in oil prices than natural gas prices though it
looks like we might see a spike in natural gas prices if we have a colder than normal
winter.
India's crude oil imports, the average for the first 9 months of 2018 is up +279 kb/day
compared to first 9 months of 2017
Seasonal chart: https://pbs.twimg.com/media/DqGtWDoX4AAYDwJ.jpg
India's crude oil refinery processing, the average for the first 9 months of 2018 is up +231
kb/day compared to first 9 months of 2017
Seasonal chart: https://pbs.twimg.com/media/DqGttFOW4AAr0Uy.jpg
Saudi Arabia spare capacity, there seems to be a consensus that Saudi Arabia can produce 11
million b/day. I guess that producing above that level would be subject to maintenance,
outages and natural decline? (Also I'm guessing that the Khurais field expansion might not be
ready until later in 2019?)
2018-10-22 Saudi Arabia Energy Minister Al Falih speaks to TASS
Saudi Arabia now in October is producing 10.7 million b/day.
And is likely to go up, in the near future, to 11 million b/day on a steady basis.
Our total production capacity is currently 12 million b/day.
And that could be increased to 13 million b/day with an investment of $20 to $30 billion.
Interview with TASS: http://tass.com/economy/1026924
Exxon in Brazil holds potential 41 billion barrels based on preliminary studies
2018-10-18 RIO DE JANEIRO and HOUSTON (Bloomberg) -- In a single year, Exxon Mobil has
gone from being a tiny bit player in Brazil to the second-largest holder of oil exploration
acreage, trailing only state-controlled Petroleo Brasileiro.
The last 24 concessions the U.S. giant bought with its partners may hold 41 billion bbl,
based on preliminary studies, according to Eliane Petersohn, a superintendent at Brazil's
National Petroleum Agency, or ANP. While the existence of the oil still needs to be
confirmed, along with whether its extraction will be cost-effective, it's a huge figure --
almost double Exxon's current reserves.
The Irving, Texas-based company is betting big in particular on Brazil's offshore, where a
single block is currently producing more than all of Colombia and profitability compares to
the best U.S. tight oil, according to Decio Oddone, the head of ANP.
It should take six to eight years for oil to start flowing if economically viable deposits
are discovered, according to ANP.
https://www.worldoil.com/news/2018/10/18/exxon-makes-major-bet-on-brazil-as-petrobras-eases-its-grip
Mike Shellman writes again. No need for me to elaborate much on his persistent and very much needed gentle nudgings about debts
coming due in the U.S. Shale Oil industry.
Ignoring debt doesn't make it go away < cough > Venezuela < cough >
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B annually in interest on long term debt.
...
In other words, at the moment about 29% of total LTO production in America is used just to pay debt interest.
Using its own "breakeven" prices the US shale oil industry will ultimately have to produce 9G BO of oil, as much as it has
already produced in 10 years...just to pay its total long term debt back. Essentially the only chance it has of doing that is
if oil prices go to $125 a barrel, and stays there for a very long time.
The debate about peak oil demand always tends to focus on how quickly electric vehicles will
replace the internal-combustion engine , especially as EV sales are accelerating. However, the
petrochemical sector will be much more difficult to dislodge , and with alternatives far
behind, petrochemicals will account for an increasing share of crude oil demand growth in the
years ahead.
"... "Barring technology breakthrough beyond what we already assume, we'll need new oil discoveries," ..."
"... "We haven't seen anything like this since the 1940s," ..."
"... "The most worrisome is the fact that the reserve replacement ratio in the current year reached only 11 percent (for oil and gas combined) - compared to over 50 percent in 2012." ..."
"... "The mind set for most E&Ps is still to be conservative, and default is to return capital to shareholders. Yet the duty to shareholders' interests cannot be myopically short term. More of the 'windfall' cash needs to find its way into exploration to sustain the business in the long term," ..."
"... "frontier areas," ..."
"... "Suriname, the Brazilian Equatorial Margin; Mexico; Senegal, Gambia, Namibia and South Africa; Australia and Alaska." ..."
"... "More explorers need to get in on the action if the spectre of 'peak supply' is to be kept at bay," ..."
"The warning signs are there – the industry isn't finding enough oil." That's the
start of a new report from Wood Mackenzie. The report concludes that a supply gap could emerge
in the mid-2020s as demand rises at a time when too few new sources of supply are coming
online.
By 2030, there could be a supply shortfall on the order of 3 million barrels per day (mb/d),
WoodMac argues. By 2035, it balloons to 7 mb/d, and by 2040, it reaches 12 mb/d. "Barring
technology breakthrough beyond what we already assume, we'll need new oil discoveries,"
the report says.
The seeds of the problem were sown during the oil market downturn that began in 2014. Global
upstream exploration spending plunged from $60 billion in 2014 to just $25 billion in 2018,
according to WoodMac. Unsurprisingly, that translated into a steep decline in new discoveries.
In the early part of this decade, the oil industry was discovering around 8 billion barrels of
oil annually. That figure has plunged by three quarters since 2014.
The precise figures vary, but Rystad Energy came a similar conclusion, noting that the total
volume of new oil and gas reserves discovered plunged to a record low in 2017. "We haven't
seen anything like this since the 1940s," Sonia Mladá Passos, Senior Analyst at
Rystad Energy, said in a December 2017
statement . "The most worrisome is the fact that the reserve replacement ratio in the
current year reached only 11 percent (for oil and gas combined) - compared to over 50 percent
in 2012."
This year, the industry has had a bit more success. Spending is on the rebound and new
discoveries are on
track to rise by about 30 percent, although that is heavily influenced by the developments
in Guyana, where ExxonMobil and Hess Corp. have reported nearly a dozen discoveries, and hope
to ramp up production to around
750,000 bpd by 2025.
It still may not be enough. Even if the industry were to somehow return to the good ol' days
prior to the 2014 market crash, and begin discovering around 8 billion barrels of oil each
year, it would only delay the supply crunch into the 2030s, according to WoodMac.
But, of course, that rate of discovery remains far below those levels, so the supply crunch
may take place much sooner. Moreover, because large-scale projects take several years to
develop, the activity taking place today will determine the supply mix in the mid- to
late-2020s.
WoodMac says that the rate of discovery is highly correlated with the level of spending, so
closing the supply gap will require more capital. And because of the run up in oil prices this
year, the industry will have a lot more cash to throw around.
The problem for the industry is that over the last few years the mindset, and the demands of
shareholders, have shifted from production growth to profitability and investor returns.
Shareholders are pressuring executives to return cash in the form of dividends and share
buybacks. Energy stocks are not the darlings of Wall Street in the way they once were,
particularly prior to the 2014 market meltdown. That puts extra pressure on oil and gas
companies to dish out more of their earnings to investors rather than plowing it back into the
ground.
But that means less spending on exploration. "The mind set for most E&Ps is still to
be conservative, and default is to return capital to shareholders. Yet the duty to
shareholders' interests cannot be myopically short term. More of the 'windfall' cash needs to
find its way into exploration to sustain the business in the long term," WoodMac said in
its report.
Shale output will continue to grow, especially after new pipelines come online in Texas,
which will ease the current bottleneck. But the large-scale increases in production in the
medium-term will come from "frontier areas," WoodMac says, as the string of
discoveries in Guyana prove. WoodMac says the areas with the highest potential include
"Suriname, the Brazilian Equatorial Margin; Mexico; Senegal, Gambia, Namibia and South
Africa; Australia and Alaska."
For now, the level of activity is not enough to stave off the supply crunch, WoodMac warns,
unless there is a dramatic increase in spending. "More explorers need to get in on the
action if the spectre of 'peak supply' is to be kept at bay," the consultancy says.
The breakout in Brent crude prices above $80 this week has prompted analysts at the sell
side banks to start talking about a return to $100 a
barrel oil . Even President Trump has gotten involved, demanding that OPEC ramp up
production to send oil prices lower before they start to weigh on US consumer spending, which
has helped fuel the economic boom over which Trump has presided, and for which he has been
eager to take credit.
But to hear respected petroleum geologist and oil analyst Art Berman tell it, Trump should
relax. That's because supply fundamentals in the US market suggest that the recent breakout in
prices will be largely ephemeral, and that crude supplies will soon move back into a
surplus.
Indeed, a close anaysis of supply trends suggests that the secular deflationary trend in oil
prices remains very much intact. And in an interview with MacroVoices , Berman laid out his argument using a handy
chart deck to illustrate his findings (some of these charts are excerpted below).
As the bedrock for his argument, Berman uses a metric that he calls comparative petroleum
inventories. Instead of just looking at EIA inventory data, Berman adjusts these figures by
comparing them to the five year average for any given week. This smooths out purely seasonal
changes.
And as he shows in the following chart, changes in comparative inventory levels have
precipitated most of the shifts in oil prices since the early 1990s, Berman explains. As the
charts below illustrate, once reported inventories for US crude oil and refined petroleum
products crosses into a deficit relative to comparative inventories, the price of WTI climbs;
when they cross into a surplus, WTI falls.
Looking back to March of this year, when the rally in WTI started to accelerate, we can on
the left-hand chart above how inventories crossed below their historical average, which Berman
claims prompted the most recent run up in prices.
Comparative inventories typically correlate negatively to the price of WTI. But
occasionally, perceptions of supply security may prompt producers to either ramp up - or cut
back - production. One example of this preceded the ramp of prices that started in 2010 when
markets drove prices higher despite supplies being above their historical average. The ramp
continued, even as supplies increased, largely due to fears about stagnant global growth in the
early recovery period following the financial crisis.
The most rally that started around July 2017 correlated with a period of flat production
between early 2016 and early 2018.
Meanwhile, speculators have been unwinding their long positions. Between mid-June 2017 and
January 2018, net long positions increased +615 mmb for WTI crude + products, and +776 for WTI
and Brent combined. Since then, combined Brent and WTI net longs have fallen -335 mmb, while
WTI crude + refined product net long positions have fallen -225 mmb since January 2018 and -104
mmb since the week ending July 10. This shows that, despite high frequency price fluctuation,
the overall trend in positioning is down.
And as longs have been unwinding, data show that the US export party has been slowing, as
distillate exports, which have been the cash cow driving US refined product exports, have
declined. Though they remain strong relative to the 5-year average, they have fallen relative
to last year. This has accompanied refinery expansions in Mexico and Brazil.
Meanwhile, distillate and gasoline inventories have been building.
Meanwhile, US exports of crude have remained below the 2018 average in recent weeks, even as
prices have continued to climb.
This could reflect supply fears in the global markets. The blowout in WTI-Brent spreads
would seem to confirm this. However, foreign refineries recognize that there are limitations
when it comes to processing US crude (hence the slumping demand for exports).
In recent weeks, markets have been sensitive to supply concerns thanks to falling production
in Venezuela and worries about what will happen with Iranian crude exports after US sanctions
kick in in November.
But supply forecasts for the US are telling a different story than supply forecasts for
OPEC. In the US, markets will likely remain in equilibrium for the rest of the year, until a
state of oversupply returns in 2019. But OPEC production will likely continue to constrict,
returning to a deficit in 2019.
Bottom line: According to Berman, the trend of secular deflation in oil prices remains very
much intact. While Berman expects prices to remain rangebound for the duration of 2018 - at
least in the US - it's likely markets will turn to a supply surplus next year, sending prices
lower once again.
Perhaps the Eagle Ford will never be profitable, it will depend on the price of oil and
many other factors.
I guess I have a little more faith in the oil industry than you.
EOG has produced a fair amount of oil in the Eagle Ford and their net income in 2014 (when
oil prices were high) was $2.9 billion, about 178 kb/d of C+C was produced from Eagle Ford in
2014 (about 65 million barrels) by EOG (about 62% of total 2014 EOG C+C output). The average
price for C+C in the US received by EOG was about $93/b in 2014.
So it seems in 2014, for a well run oil company, $93/b worked just fine. Over the period
from 2010 to 2014 EOG's net income was about $6 billion. From 2010 to 2017, the total net
income was about $2.6 billion (not adjusted for inflation) as 2015 and 2016 were bad years
with 5 billion losses in net income.
Debt to assets at the end of 2017 was about 21% with debt at $6.4 billion and assets at
$29.8 billion. In 2017 Eagle Ford output was about 47% of EOG's C+C output, the average oil
price EOG received in the US was $50.91/b in 2017, about $600 million of long term debt was
paid off in 2017 with no new long term debt issued, but net cash flow was negative $766
million.
A discounted cash flow at a 10% annual discount rate results in a breakeven oil price (10%
annual ROI) of $90.3/b for the average 2016 Eagle Ford well, if we assume a well cost of 9
million. Note that this is a "real" discount rate as I do costs in real inflation adjusted
dollars, so it is equivalent to a nominal discount rate of 12.5% so would be equivalent to a
nominal annual ROI of 12.5%.
EUR is 238 kb over 13.8 years and the well is shut in at 10 b/d. An assumption of 15 b/d
shut in reduces EUR to 220 kb and well life to 9.75 years, and breakeven oil price rises to
$91/b, an increase of 70 cents per barrel. Well payout is in 46 months at $91/b.
What is the full cost of the average Eagle Ford well?
Note that I have assumed zero revenue from natural gas or NGL in my breakeven analysis and am
considering C+C output only, not sure if there are natural gas pipeline bottlenecks in the
EFS as there seems to be in the Permian basin. In any case, the economics might be slightly
better when natural gas is included.
There wasn't significant drilling in the Eagle Ford Shale until 2011. How many of the 700
inactive wells started producing in 2009 and 2010? By Enno Peters data using Eagle Ford and
unknown wells in Karnes County from Jan 2011 to Dec 2016, I get 2487 horizontal wells
completed in total over that period. Note that the productivity rate distribution at Enno's
site gives some funky numbers at the low end, so they should probably be ignored. "Zero"
output after 24 months should probably be less than 15 b/d after 24 months. For Eagle Ford
2014 wells, supposedly there are 1747 wells with zero production rate after 24 months out of
3962 total wells, this is just a programming error. That is, zero does not mean zero in this
case, would be my guess.
I checked with Enno Peters on this and the lowest column means output at 24 months is 0 to 50
b/d, same is true for each column it is from the previous to the next label so 0-50, 50-100,
etc.
Could over 20% of the horizontal wells in Karnes Co., TX already be shut in for over
one year? These wells first produced 1/1/2019 to 12/31/2016, so they are not old wells at
all? Less than 10 year economic life?
No the wells have not been shut in as you think, for 2009 to 2016 wells in Karnes county
and Eagle Ford Formation I get 763 wells with "zero" production rate at Enno's site. He has
pointed out that this is really 0 to 50 bopd for those 763 wells out of a total of 2425 wells
producing that started production from 2009 to 2016. The average production rate was 86 bopd
for all of the Karnes county Eagle Ford formation wells.
For all counties there were 15,600 wells with 7754 wells with output at 0 to 50 bopd at 24
months. Average for all counties is 63 bopd at 24 months. At 12 months the average rate was
127 bopd for all counties with about 25% of the wells at 0 to 50 bopd at 12 months.
Older article, but more important, now. EIA, and most of the Rystad type companies are
continuing to report significant increases in the Permian. Latest monthlies are from June,
all else is estimated, including drilling info. Completions are happening, and the new wells
included in drilling info are, no doubt, true as to production. Who measures shut ins until
final numbers are accumulated? Who spends significant time communicating with the small
producer? Heck, they make up half the wells drilled in the Permian. I think there are
considerable shut ins that will eventually reduce the magnificent increases that are
currently being reported.
I ran a quick search on horizontal wells in Karnes Co., TX.
I found 2,778 active horizontal wells with first production from 1/1/2009 to
12/31/2016,
In the most recent month, here are the numbers:
170 wells produced 3,001+ BO
1,034 wells produced 1,001-3,000 BO
872 wells produced 501-1,000 BO
702 wells produced 1-500 BO
Could that be correct?
Furthermore, there appear to be over 700 inactive wells, which are defined as wells that
have no recorded oil or gas production in the last 12 months.
Could over 20% of the horizontal wells in Karnes Co., TX already be shut in for over one
year? These wells first produced 1/1/2019 to 12/31/2016, so they are not old wells at all?
Less than 10 year economic life?
I know Mike has commented on how bad the EFS really is economically. It seems the hyper
focus is now on the PB. However, EFS produces significant volumes of oil. Looks like this one
could really collapse once the last locations are completed.
I saw many, many wells with cumulative production of 250K oil, that are now producing
under 500 BO per month.
I ran the same search on De Witt Co., TX. Less wells, but similar results. Interesting to
see all the wells in both counties that have maybe paid out, but are now producing less than
500 BO per month.
Even Karnes County has it's less than tier one oil areas, and a lot of the wells were not up
to par in the beginning. The well has to pay out capex in the first year, or its not worth
drilling. Profit in year two and three, and not much after that. Period. End of story. I
don't see much better out of the Permian, and may be getting worse. Yes, on the whole, less
than a ten year economic life. Gets a lot worse in tier two stuff, and tier three stuff is,
at these prices, a definite loss. But they are still drilling in tier three areas, go figure.
My lease area is producing around 250k to 300k total, and it is barely touched, because EOG
wants 300k. Yeah, when the tier one areas play out, costs to maintain will be prohibitive.
Increase? Just a dream.
Look at EOG's economics of which wells are "premium" locations. There are not many left, and
EOG probably owns the lion's share. It has to produce 200k barrels the first year. They
priced that at $40 oil price, but it makes no difference, because it doesn't change the
number of locations that can generate 200k barrels. They are justifying production to a 5200
ft lateral. Some make significantly more, some less. I have that memorized, as my wells have
proven from the 125k to 175k the first year. Probably, a 250k to 300k EUR. So, I have to
wait. They will be venturing into my area sometime before their "premium" locations are
depleted. Beginning of the year, that count was at 2300. About 10 years at their current
drilling rate, and less if they pick up activity. These are developmental wells, the Permian
is still largely exploratory.
As far as holdings go, EOG is the cream of the crop. So, you can't make averages based on
one company. Most look far, far worse. Their financial info was shit before, as were all the
rest. Setting a bar for where to drill, will, in all likelihood, make them much better. There
are a large number of smaller companies who still complete wells in tier three acreage. It's
amazing, they know what they will get. I see initial production at 500 barrels a day, or
less, and I know that someone is losing money.
Now, do the math. There is not 10 years, or in most cases even five years of economically
recoverable oil from shale. A 60 month payback???? At the highest bracket, it includes wells
with about 3000 barrels a month. And there are only about 10k of those. Less than 3 years of
completions. And if you look at the total number of producing wells it is slightly less now
than in 2014. So, what happened to them??! To make it clearer, the number of wells that has
become inactive is pretty close to the number of wells that has been drilled in four years.
Yeah, production is up, because the wells producing over 3000 a month is up. But applying a
ten year, or even five year economic life to them is pretty stupid. But, I don't have to look
at total numbers to get to that conclusion, I look at individual wells, or groups of wells in
a lease. It's a lot steeper treadmill than the hoopla indicates. Here's the count from Dec
2014. Shale wells will probably not drop down into the last category, so just look at the
first two to compare them to current. If they do drop into the last category, the production
doesn't mean much to the cost of the well, or profitability. About four thousand more, and
tens of thousands of new wells since then. http://www.rrc.state.tx.us/media/26405/welldistribution1214.pdf
So, think about this when your looking at Eno's data, averages are deceiving. Whether they
are tier one, two, or three makes a huge difference.
The links to the report show plugging activity. Substantial. In August EF had 120 oil
completions, and 50 something oil wells plugged. Completions were higher in August. Dec 2017,
oil wells completed and plugged were almost equal. That is not an exact description of EF
horizontals, but that is the main thing going in these districts. $250 sounds low, I think.
Shallow, FTR, last thread: my current est. economic limits of 15-18 BOPD for LTO wells will
be much higher for major integrated companies, yes. The everything is peachy 'assumption' is
that smaller companies will buy those wells and carry on. I do not believe that. A 6-10%
decline in total UR because of premature economic limits IS a big deal. It makes or breaks
thousands of wells.
The liquids rich gas leg of DeWitt and Karnes Counties IMO will see <35% of its wells
be 'significantly' profitable, for instance above 150 ROI. Your data you are showing is a big
deal that seems to be going plum over peoples heads. Sorry. Time will show that the Eagle
Ford was, is the biggest financial toilet of all three shale basins; the economics are indeed
awful. I operate conventional production IN the EF trend and have interest in wells. Folks
don't realize how many $10-12MM dollar wells were drilled from 2009-2013. Jeff Brown and I
guessed eight years ago only 35-40% of shale oil wells in the EF will even pay back
D&C&A costs. I think that is way too high now.
Whatever the definition of "works," means, Dennis, for the EF; newer well designs are
leading to much higher IP180-360, but not higher UR. It does not look that way to me. Now new
wells in the EF must carry the burden of the highest level of legacy debt in the LTO
industry. To maintain and actually pay that debt back will take much higher oil prices than
you think as the play is now pretty much exhausted. At current oil prices it takes 325-350K
BO to pay new wells with longer laterals and much bigger frac's out.
The LTO industry is not in business so people can speculate about how much oil it is going
to make, or the jobs it provides, or how much cheaper gasoline it can provide for
consumers https://www.oilystuffblog.com/single-post/2018/09/12/Cartoon-Of-the-Week
; its in business to MAKE money. 150 ROI's is not making sufficient money to be self
sustainable and be able to kick the credit/debt addiction.
Longhorn is correct, Matador did indeed pay $95K an acre for PMNM acreage. I suggest we
bow our heads and honor its shareholders with a moment of silence and a little prayer to the
Goddess of Wolfcamp in order that she be merciful. Another bench Matador is touting to
justify its "wisdom" is the (De) Cline shale interval. Phftttttt.
The irony is that the majors and large independents divested of many assets in the US lower
48 in the 1990s because they were perceived as high cost with little economic future.
However, folks like us are still producing that stuff profitably.
OTOH the same companies are now spending large sums on shale, which is economically
inferior to what they divested 20-30 years ago.
Mr.Simmons likely never considered the productive wonders of a cash flow negative oil boom
aka USA LTO sarc/
I wonder how many more cash flow negative oil booms the world can endure, and how long USA
LTO will last. While we're at it, I wonder how the pension funds invested in USA LTO are
gonna do for their members once the rats under the floorboards get flushed out.
Buckle your chin strap. Within a few to several years we'll perhaps know better how this
is gonna shake out. George Kaplan and Dennis Coyne had some future production charts in the
comments of last post. By my rough eyeball and memory, I think George Kaplan had future
production down to about 40 million barrels a day by 2050 (see link below). Dennis, ever the
optimist ;), had us down to about 50 million barrels a day by 2050 (see Mr. Coynes comments
in response to George). Either way, those alive in 2050 are gonna be living in a very
different world!
A lot depends on how much oil can be extracted. George Kaplan's scenario looks to be
roughly a URR of 2400 Gb if the 2020 to 2063 trend continues in future years (it is roughly
straight line decline over that period so I just extended the line to zero and estimated URR.
It is more likely, in my view that URR will be about 3060 Gb (including 260 Gb of extra heavy
and LTO oil), that's about midway between a pessimistic HL scenario(2600 GB) and optimistic
USGS scenario (3000 Gb) for conventional oil.
Also higher rates of extraction could keep production a bit higher maybe 64 Mb/d in 2050,
it will depend on the length of Great Depression 2 in 2030. Of course I think that might only
last 4-5 years, being an optimist.
I haven't worked it out but I'd guess the ultimate recovery is more than your estimate.
First, as I said before, the XH production is based on long cycle projects, so it would have
a fat tail extending beyond when most of the conventional oil is exhausted (there are a few
reasons for that but one is that it needs upgraders and those are not built with excess
capacity). Second, as I said twice before, Laherrere has about 180 Gb of "rest of the world"
reserves that I didn't include as I don't know what they represent – if they are
undiscovered oil then at current rates it will take about 40 years to find them, or if the
recent trend for declining discoveries holds then forever.
And that is the last I am going to write – or read – on that Laherrere paper. It
was just a comment on a blog, not an article in Nature or the Times or even a letter to
either of those, or even a letter to the local free advertising paper. I wrote it most for my
own interest, writing things out help clarify ideas, but I rarely do more than a cursory
proofread. Most people who bothered to look at it would have read a couple of sentences and
skimmed the rest, a very few might have got more out of it. It didn't change anything
fundamental. If somebody was going to write another comment they wrote exactly what they were
going to write anyway.
It won't take to 2050 to see a different world. Just a small fall in supply has effects
well out of proportion to the nominal cash value of the oil lost. Cheap flights would
disappear, trade would plummet, GDPs shrink – the books have to balance one way or
another (see recent paper on impact on trade, I think by Barclays, and works by Hall and
Kummel). The biggest impact might be food prices, they could easily double and more short
term, then the few billion who spend half their income on food suddenly have to spend it all.
Turmoil would ensue and likely knock more oil supply off line. There was a paper about Sweden
I think – from memory (don't quote me) a rapid fall by a quarter of the oil available
leads to collapse and by a half to complete loss of civilization.
At the same time the declining cheap and efficient energy would hamper efforts to address
the other big ticket, long term issues: rising population, evolutionary inevitable
aspirations – "poor man wanna be rich, rich man wanna be king, and a king ain't
satisfied till he rules everything" (of course); declining levels in some of the big aquifers
(a few are getting to the point where the basic pump designs don't work, the replacements
needed are much more expensive and much more energy intensive); declining soil loss (at
current rate all the soil on sloped arable land will be gone in 50 years – that's a
third – and most of the rest in another 50); and of course climate change related
extreme weather. This year we've had record heat waves, wild fires, typhoons and (soon)
hurricanes plus droughts etc. Soon those will be weekly events (we're not far off now) but on
top of that we will be having two or three extreme extreme-weather events per year. More and
more of the oil will be going simply to triage on these (but the patient will get worse
anyway). At some point countries will cease to be liberal democracies, the USA seems to be
leading the way there, and say what you like about liberal democracies they have never
declared war on each other, dictatorships on the other hand
People will say oh we just need to do this, that or the other – but there is no
"just" about any of it, and especially as oil disappears: ignoring the externalities there is
absolutely no better real energy source imaginable by some way, especially the cheap stuff we
used to have.
You of course know all this and are preparing much better than me, I do not much more than
appease my conscience by not flying and hardly ever riding in a car, but I think I'm getting
to the "acceptance" stage and pretty much missed out on depression (no physical symptoms
anyway).
[end of rant].
I tend to agree with you George. Only a small decrease a short time after peak, and the
realization that it's not going back up, will likely open a lot of people's eyes to the fact
that almost every stock and equity is overvalued (come to understand that anticipated future
growth will not be realized). I plan to hunker down and catch up on my reading while the dust
settles, and I'm thinking there'll be a lot of dust. I'll send you a map. Password is 'I
think I'm with the band'.
I find this to be also an interesting take on the future of oil
"The short-term investment focus adopted since 2014 offers a finite set of opportunities
over a limited period of time, and this period is now clearly coming to an end as seen by
accelerating decline rates in many countries around the world," Kibsgaard pointed out.
BAU won't get it done – no quick fixes, 'new shale revolution' or 'reserve
production' to get us through – my interest is mostly how we (as a society and culture)
will react as constraints on the resource 'haves' and 'have nots' set in.
Went through Irma in South Florida last Fall – and in general order was maintained
– but really only out of Gas for about 3 days – and was more of a shock type
shortage. A very slow decline of world supply will hit those who can't pay for it most
– and maybe wake up enough through higher prices to begin planning for what will be the
greatest energy transition that must take place!
The big oil companies are selling a story of long term stability to their investors, partly
so they can justify the long term investments needed for the mega-projects where they get
most of their oil and cashflow (some of those see no net return for many years). They only
need to sell themselves to their investors, not their customers who just buy the cheapest or
most convenient, be it crude to refineries or petrol to motorists.
The service companies live more year to year – they get hired to help develop and
drill a field and then their workload drops a lot except for some well servicing during
operation. Schlumberger is selling itself to its customers (the 'operators' who are the
E&P companies) and investors as the go to guy for the next couple of years as activity
tries to pick up but faces increasing issues as the easy (and now not so easy but still
OK-ish) oil goes away.
Schlumberger is not a typical service provider to the producers, although that is a large
portion of their business. Since their purchase of Cameron International and other oilfield
manufacturing companies, they have been providing facility engineering and fabrication
services to the oil producers worldwide.
In point of fact, Schlumberger does have the information that the producers have, and then
some. They use those numbers as a basis for facility engineering, and as such are arguably in
a better position to interpret them than the producer as of late.
I've regularly read the BP annual report, and have come to regard it as little more than a
curiosity. Schlumberger, Shell and Total have a firmer grip on the world oil situation, based
on my read of their CEO's comments. However that may be confirmation bias on my part. We
shall see .
Probably the more important item is Russian reserves my estimate is we are at 90% depletion
for existing technology and OIP at cost for western Russian reserves. At this point a squeeze
plan in Syria would ensure foreign reserve earnings to into wars and not fuels outcome is
standard wars as a result of miss spending income
Yes, I assume they have some problems since they reformed the tax system in favor of upstream
risky projects and at the same time imposed more taxes on downstream refineries. But to
assume Russia has problems is like assuming the whole world has a problem. Could be perfectly
right, but why expose Russia as opposed to others? Russia has a lot of higher cost oil; just
look at the land mass and offshore mass. How could there not be prospects? Some inside
knowledge is sorely lacking, since I like most western people don't have connections in that
part of the world.
80% of the world's oil has peaked, and the resulting oil crunch will flatten the
economy.
New scientific research suggests that the world faces an imminent oil crunch, which
will trigger another financial crisis.
A report by HSBC shows that contrary to the commonplace narrative in the industry, even
amidst the glut of unconventional oil and gas, the vast bulk of the world's oil production
has already peaked and is now in decline; while European government scientists show that the
value of energy produced by oil has declined by half within just the first 15 years of the
21st century.
The upshot? Welcome to a new age of permanent economic recession driven by ongoing
dependence on dirty, expensive, difficult oil unless we choose a fundamentally different
path.
Then they say: The HSBC report you need to read, now
Real issue is giants, your article in 2015 real issue is 90% ..real issue is squeeze play in
motion in Syria..goal? if don't have it, don't drill it at home, no rig increases so 'end
game' is cut off Isreali/Saudi friendly arab gas to Europe own Caspian area (city I recall
owned by Ukraine under British treaty Yelsin) in end no WW2 buildup during economic issues
(Russia 5M/day, Saudi similar) no Hilter, just preempt what's left..
I downloaded it then, and just had to look at the date the file was created. You probably
also have it in your hard-drive.
It provided a nice confirmation to my thesis that Peak Oil won't happen in the future. It
is taking place now, and the date we entered the Peak Oil plateau was 2015. You also
forecasted that, as I did.
You are correct. Hey, I am 80 years old and I just can't remember shit anymore.
Okay, I posted a few days ago that I thought peak oil would be in 2019. Perhaps I was
wrong. Hell, I have been wrong quite a few times. But now perhaps peak oil is right now.
Perhaps? We shall see.
But my point is everyone seems to be agreeing with me now. Old giant fields are seeing an
ever increase in decline rates. I predicted this a long time ago. Once the water hits those
horizontal laterals at the very top of the reservoir, the game is over.
The decline rate in those old giant fields is increasing at an alarming rate.
Obviously! Fucking obviously. It could not possibly be otherwise. Thank you and
goodnight.
Memory is less necessary these days with internet, computers, and smart phones, where
searches can be run in a moment. Don't worry too much about that.
"But my point is everyone seems to be agreeing with me now."
I discovered your blog in 2014 when looking for confirmation on my suspicion that the oil
price crash was going to result in Peak Oil. I was impressed to see that you were there years
before through your analyses. I have a lot of respect for you and your intellectual capacity,
and I agree with you in many things, besides Peak Oil, including the population problem, and
your worries about the environment.
I don't believe the world cannot increase its oil production, I just believe it won't do
it. Both Saudi Arabia and Russia have the capacity to go full throttle on what they have
left. Shaybah is the most recent supergiant in KSA and expected to produce until 2060 at
current output. No doubt they could increase production from Shaybah by a lot, but it is not
in their interest to do so. Russia lacks the capacity to quickly increase its production, but
there's still plenty of oil in Eastern Siberia, so they could also produce more. Again it is
also unlikely, as it would require an investment and effort that goes against their own
interest.
Peak Oil is not happening because the world is trying to produce more oil and failing, it
is happening by a combination of economical, geological, and political factors that could not
be easily predicted and that were set in motion in the early 2000's when the low-hanging
fruit of conventional on-shore and off-shore crude oil (the cheapest kind to produce) reached
its production limit. Political errors, like taking out Gaddafi, added unnecessary
difficulties. The collapse of Venezuela is the latest political cause. And when things start
to go wrong, it never rains, but it pours.
"Peak Oil is not happening because the world is trying to produce more oil and failing, it is
happening by a combination of economical, geological, and political factors that could not be
easily predicted and that were set in motion in the early 2000's when the low-hanging fruit
of conventional on-shore and off-shore crude oil (the cheapest kind to produce) reached its
production limit."
Isn't this just a distinction without a difference? It's peak oil.
The issue is that Peak Oil has been misunderstood by most people. The argument that Peak Oil
won't happen until this or that date because ultimate reserves are such or such, so often
read in this forum, is incorrect. Even economically recoverable reserves are not decisive. To
make the problem intractable there are many liquids so some might peak while others don't so
discussions about Peak Oil are endless.
But it is very simple. Peak Oil is when the world no longer gets the oil it needs to keep
expanding its economy. And the best way to measure it is through C+C, because crude oil is
what we have been getting since the late 19th C ans is the stuff that produces everything our
economy needs, from asphalt to diesel, plane fuel, and gasoline. NGL won't cut it. Biofuels
won't cut it.
And Peak Oil is being determined by economical and political factors, besides the
geology.
The difference matters because Peak Oil is going to get almost everybody by surprise. Most
won't realize what is the cause of all the troubles we are going to get and they'll be
reassured that there is plenty of oil to be extracted, which is true but irrelevant.
Thanks for the reply. I also tremble at the prospect of what is to happen because of the
failure of the predictions last decade. I can only describe it through an analogy (being a
lay reader and a writer):
In the 2000s, people were saying that we had an ugly wound and that we had better do
something about it. But instead of properly addressing the wound, we just wrapped it in
gauze, and when the blood stopped showing through, we said, "See? All better." That's my
analogy for the "shale revolution" -- it was essentially a Bandaid. The complacency has only
worsened in the last ten years.
This has just made the infection all the worse. When pus starts showing through the
dressing and we unwrap it this time -- we're going to find gangrene.
I am re-reading Joseph Tainter's 1998 book "The collapse of complex societies." It is a
sober reading that shows that in the end the laws of entropy and diminishing returns always
produce the same result. We are not more intelligent than the people that preceded us. If
anything we can only be stupider on average. We just have a very high opinion of
ourselves.
Time for a wake up and a little bit more darwinism in our lives. The problem is the pain.
With so many people it is just going to be unbearable. On a scale never imagined, not even by
writers of bad sci-fi.
That would be a more important definition of peak oil to me, and I think we are definitely
there. Then we have the absolute production definition, which was the original definition, as
to production. It is now anticlimactic to your definition. As to the date or year it happens,
who cares? More importantly, now, is when demand will lower enough to stop draining
inventories. At what oil price will that start occurring? How fast will alternate sources
replace unmet demand? New directions and everyone is likely to be wrong on estimates. EIA and
IEA were totally useless before, and that will probably not change in the near future.
Looking in the past won't give us much, and the future is anybody's guess.
As to current prices, $68 oil won't get any extra interest from E&Ps outside of the
Permian that is stalled. To any measurable extent. Close to $80 oil is not expanding interest
very much outside of the US. We are just living on borrowed time.
Oil prices are likely to continue to rise, especially if your estimates of future
production (roughly similar to my estimates, but perhaps a bit more pessimistic) are correct,
unless consumption of oil stops increasing. My guess is that oil (C+C) consumption will
continue to increase at 400 to 800 kb/d each year , until oil prices get to about $150/b or
more (around 2025 to 2027),by that time or soon after ( maybe 2030) oil consumption growth
may stop either because of the expansion of electric and natural gas powered transport or
because of a second Great Financial Crisis. My hope is it will be the former, but I think the
latter scenario is much more likely.
Hopefully Keynes' General Theory will make a comeback before then.
Ron Wrote:
"I predicted this a long time ago. Once the water hits those horizontal laterals at the very
top of the reservoir, the game is over. "
FWIW: That's already happened. when it occurs, they drill a new horizontal above the old
one. The new lateral also have valves on there ports. so that when the water breaches one or
more of the ports, they shut them off to reduce water cut. I posted Saudi Aramco tech
articles here back between 2014 and 2016 when they were available on the SA website.
Hi Carlos, thanks for the trip down memory lane. I tend to agree with peak oil being now
(ish). From what I recall the peak month for C+C was, so far, in November 2016. I suppose
there is also a peak day, a peak weak, and a peak year. Folks seem to like packaging time in
various proportions. Hell, there's probably a peak decade and a peak hour. My guess is the
peak year will be 2018. I like, because I'm a bit thick at maths, how Ron has added trailing
12 month average to his world production chart. I just look at the 12 month trailing average
for each December to get an idea of how much was produced in each calendar year. It seems
that 12 month trailing average for December 2018 will beat that of 2017. My guess is 2019
won't beat 2018. Or will any other year after that. So, if Ron say's 2019, and I say 2018,
then it seems that I think he is wrong lol he's probably 100 times smarter than me so doesn't
lose sleep over it lol. Up until this time I have always agreed with Ron on peak oil. But
now, I throw down the gauntlet! 2018 vs 2019. Two will enter, one will leave.
The exact week, month, or year when maximal production is reached has only historical
interest. The point is that since the end of 2015 the 12-month averaged C+C production has
barely increased (EIA data) despite the increase in demand.
Dec 2015 80,564 100.0%
Dec 2016 80,579 100.0%
Dec 2017 80,936 100.5%
Apr 2018 81,363 101.0%
We will have to see how it evolves over to the next December, but so far it is annualized
to a 0.4% increase. To me we are in a bumpy plateau since late 2015 and all those meager
gains and more will be lost in the next crisis. The problem will be evident to many when
after the crisis we are not able to increase production above those values.
Peak Oil is a situation, not a date, and we are in that situation since late 2015. The oil
that the world demands cannot be produced so prices are going up, and up. I suppose it is
possible that the powers that be intervene to reduce global oil demand by favoring a crisis
in developing countries, like Argentina, Brazil, Turkey, South Africa, through interest rate
changes. Wait, it is already happening. It is a dangerous tactic, as crises can spread
around, and the interest rise weakens the economy.
Well one has to define the plateau a bit better. If we make the bounds wide enough one
could say the peak was 2005 or even 1980 and we have been on a bumpy plateau since that
point.
Better in my view to define peak as peak in centered 12 month average output wth center
between month 6 and 7.
I use a 13-month centered average, so it is symmetrical with 6 months at each side.
But really, after a clear period of production growth 2010-2014, there was a strong growth
in production 2014-2015 in response to falling prices, and then production got stuck in late
2015.
It is not a question if we are in a plateau (or very reduced growth) period, but what
happens afterwards. After the previous plateau 2005-2009 there was a clear fall 2009-2010,
before tight oil saved the day.
The recent plateau is due to excess inventory and the resulting low oil price level. Oil
inventories have been reduced over the past 12 to 18 months and as oil prices increase,
output will also increase with perhaps a 6 to 12 month lag. How much will it need to rise
above the Dec 2015 level before you no longer consider that output has not risen above your
"plateau". Give me a number, is it 81.5 Mb/d, 82 Mb/b, I prefer to use a year rather than 13
months, that's 182 days on either side of the middle of the 12 month period. On leap years we
can use Midnight of day 183
One issue that has been corrected is that reserve requirements for large banks have
increased.
Also lenders are more careful with their mortgages making a housing bubble less
likely.
In addition, the assumption that higher oil prices played a major role in the GFC is
incorrect.
Perhaps there is a looming recession, whether this happens in 2018, 2030 or some other
year we will only know when it occurs.
Someone who predicts a recession every year will be right eventually.
I maintain my guess of 2023 to 2027 for the 12 month centered average c+c peak and severe
recession GFC2 starting 2029 to 2033, lasting 5 to 7 years.
Second oil reserves have been flat since around 2010, and declining recently for the first
time since the 1970s. Note, before someone points it out, they don't count Canadian Bitumen.
This is so ridiculous it is funny. Oil discoveries have been going down, down, and down, way
below replacement level. Yet so-called "proven" reserves keep going up, up and up.
"This is so ridiculous it is funny. Oil discoveries have been going down, down, and down, way
below replacement level. Yet so-called "proven" reserves keep going up, up and up."
Well to some degree, technology has been able to extract more oil from a field. Thus a
field discovered in 1950 with an initial proven reserve of 100mbbls, may have 125mbbls or
proven reserves as technology has improved recovery rates. That said technology improvements
likely don't match the paper proven reserves.
The Venezuelan heavy oil reserves are overstated (I assume the large bump prior to 2010 is
the booking of the Magna Reserva in the Orinoco Oil belt, which i know are fake). It's fairly
easy to eyeball the better number by substracting 300 billion a flat line around 1200. If you
want to add future bookings in that heavy oil belt, add up to 50 billion gradually. Dont
forget that at the current decline rate Venezuela will be producing about 1.1 million BOPD in
december, and IF things go as I think they will sometime in the first half of 2019 exports
will drop to zero for a few months.
Third gas reserves also flat. If condensate and NGLs have been meeting the increased demand
that crude has been unable to, then that might be about to stop.
"... Fracking has indeed produced oil and gas, but the fields deplete rapidly without massive additional investment. Only the zero-interest rates of the Fed's Quantitative Easing could have financed the fracking boom - without QE, US oil and gas would not even exist on the world's radar. ..."
The Keiser Report has a very upbeat show today on RT, in which they celebrate how the NYT
has finally come round to reporting the truth about US fracking, in ways that Max and Stacy
were reporting 9 years ago.
Fracking has indeed produced oil and gas, but the fields deplete rapidly without massive
additional investment. Only the zero-interest rates of the Fed's Quantitative Easing could
have financed the fracking boom - without QE, US oil and gas would not even exist on the
world's radar.
And yet Neocons are taking the US production of hydrocarbons as a major plank in their
platform of war, building castles in the air from a mythical "energy supremacy" and treating
current production levels as a weapon of war -- but the economics of this relatively minor
industry will shut it down soon.
In the second half of the 30-minute show, Max interviews Wolf Richter and they discuss
Argentina mostly. It's a rapid and valuable overview of how the US Hegemon deals with its
favorite suckers south of the border, and how currencies and bonds work - and also why the
IMF acts only to bail out investors and bond-holders, and never the real economy of the
victim nation.
"... The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e. Federal Reserve policy. Even The New York Times said so yesterday ( The Next Financial Crisis Lurks Underground ). ..."
"... As with shale oil, they depend largely on dishonest financial legerdemain. They are also threatened by the crack-up of globalism, and its 12,000-mile supply lines, now well underway. Get ready for business at a much smaller scale. ..."
"... Hard as this sounds, it presents great opportunities for making Americans useful again, that is, giving them something to do, a meaningful place in society, and livelihoods. ..."
"... Pervasive racketeering rules because we allow it to, especially in education and medicine. Both are self-destructing under the weight of their own money-grubbing schemes. ..."
"... A lot of colleges will go out of business. Most college loans will never be paid back (and the derivatives based on them will blow up) ..."
"... The leviathan state is too large, too reckless, and too corrupt. Insolvency will eventually reduce its scope and scale. Most immediately, the giant matrix of domestic spying agencies has turned on American citizens. ..."
"... It will resist at all costs being dismantled or even reined in. One task at hand is to prosecute the people in the Department of Justice and the FBI who ran illegal political operations in and around the 2016 election. These are agencies which use their considerable power to destroy the lives of individual citizens. Their officers must answer to grand juries. ..."
"... As with everything else on the table for debate, the reach and scope of US imperial arrangements has to be reduced. ..."
And so the sun seems to stand still this last day before the resumption of
business-as-usual, and whatever remains of labor in this sclerotic republic takes its ease in
the ominous late summer heat, and the people across this land marinate in anxious
uncertainty.
What can be done?
Some kind of epic national restructuring is in the works. It will either happen consciously
and deliberately or it will be forced on us by circumstance. One side wants to magically
reenact the 1950s; the other wants a Gnostic transhuman utopia. Neither of these is a plausible
outcome.
Most of the arguments ranging around them are what Jordan Peterson calls "pseudo issues."
Let's try to take stock of what the real issues might be.
Energy
The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e.
Federal Reserve policy. Even The New York Times said so yesterday ( The
Next Financial Crisis Lurks Underground ).
For all that, the shale oil producers still
couldn't make money at it. If interest rates go up, the industry will choke on the debt it has
already accumulated and lose access to new loans. If the Fed reverses its current course - say,
to rescue the stock and bond markets - then the shale oil industry has perhaps three more years
before it collapses on a geological basis, maybe less. After that, we're out of tricks. It will
affect everything.
The perceived solution is to run all our stuff on electricity, with the electricity produced
by other means than fossil fuels , so-called alt energy. This will only happen on the most
limited basis and perhaps not at all. (And it is apart from the question of the decrepit
electric grid itself.) What's required is a political conversation about how we inhabit the
landscape, how we do business, and what kind of business we do. The prospect of dismantling
suburbia -- or at least moving out of it -- is evidently unthinkable. But it's going to happen
whether we make plans and policies, or we're dragged kicking and screaming away from
it.
Corporate tyranny
The nation is groaning under despotic corporate rule. The fragility of these operations is
moving toward criticality. As with shale oil, they depend largely on dishonest financial
legerdemain. They are also threatened by the crack-up of globalism, and its 12,000-mile supply
lines, now well underway. Get ready for business at a much smaller scale.
Hard as this sounds, it presents great opportunities for making Americans useful again, that
is, giving them something to do, a meaningful place in society, and livelihoods.
The implosion
of national chain retail is already underway. Amazon is not the answer, because each Amazon
sales item requires a separate truck trip to its destination, and that just doesn't square with
our energy predicament. We've got to rebuild main street economies and the layers of local and
regional distribution that support them. That's where many jobs and careers are.
Climate change is most immediately affecting farming. 2018 will be a year of bad harvests in
many parts of the world. Agri-biz style farming, based on oil-and-gas plus bank loans is a
ruinous practice, and will not continue in any case. Can we make choices and policies to
promote a return to smaller scale farming with intelligent methods rather than just brute
industrial force plus debt? If we don't, a lot of people will starve to death. By the way, here
is the useful work for a large number of citizens currently regarded as unemployable for one
reason or another.
Pervasive racketeering rules because we allow it to, especially in education and medicine.
Both are self-destructing under the weight of their own money-grubbing schemes. Both are
destined to be severely downscaled.
A lot of colleges will go out of business. Most college
loans will never be paid back (and the derivatives based on them will blow up).
We need
millions of small farmers more than we need millions of communications majors with a public
relations minor. It may be too late for a single-payer medical system. A collapsing oil-based
industrial economy means a lack of capital, and fiscal hocus-pocus is just another form of
racketeering. Medicine will have to get smaller and less complex and that means local
clinic-based health care. Lots of careers there, and that is where things are going, so get
ready.
Government over-reach
The leviathan state is too large, too reckless, and too corrupt. Insolvency will eventually
reduce its scope and scale. Most immediately, the giant matrix of domestic spying agencies has
turned on American citizens.
It will resist at all costs being dismantled or even reined in.
One task at hand is to prosecute the people in the Department of Justice and the FBI who ran
illegal political operations in and around the 2016 election. These are agencies which use
their considerable power to destroy the lives of individual citizens. Their officers must
answer to grand juries.
As with everything else on the table for debate, the reach and scope of US imperial
arrangements has to be reduced. It's happening already, whether we like it or not, as
geopolitical relations shift drastically and the other nations on the planet scramble for
survival in a post-industrial world that will be a good deal harsher than the robotic paradise
of digitally "creative" economies that the credulous expect.
This country has enough to do
within its own boundaries to prepare for survival without making extra trouble for itself and
other people around the world. As a practical matter, this means close as many overseas bases
as possible, as soon as possible.
As we get back to business tomorrow, ask yourself where you stand in the blather-storm of
false issues and foolish ideas, in contrast to the things that actually matter.
Most of the arguments ranging around them are what Jordan Peterson calls "pseudo issues."
Let's try to take stock of what the real issues might be.
Energy
The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e.
Federal Reserve policy. Even The New York Times said so yesterday ( The
Next Financial Crisis Lurks Underground ). For all that, the shale oil producers still
couldn't make money at it. If interest rates go up, the industry will choke on the debt it has
already accumulated and lose access to new loans. If the Fed reverses its current course - say,
to rescue the stock and bond markets - then the shale oil industry has perhaps three more years
before it collapses on a geological basis, maybe less. After that, we're out of tricks. It will
affect everything.
The perceived solution is to run all our stuff on electricity, with the electricity produced
by other means than fossil fuels , so-called alt energy. This will only happen on the most
limited basis and perhaps not at all. (And it is apart from the question of the decrepit
electric grid itself.) What's required is a political conversation about how we inhabit the
landscape, how we do business, and what kind of business we do. The prospect of dismantling
suburbia -- or at least moving out of it -- is evidently unthinkable. But it's going to happen
whether we make plans and policies, or we're dragged kicking and screaming away from it.
The message I get from that piece is that companies are getting ready for next year so
they can hit the ground running when the pipeline bottleneck is removed. Output has not
decreased, it is just rising more slowly than capital expenditures. No point in completing
wells if there is not pipeline space to move the oil, so they are building pads and other
facilities and drilling wells, but waiting on completion.
So far this year Permian tight oil output has increased by 478 kb/d, an annual rate of
increase of about 820 kb/d. The annual rate of increase from Jan 2017 to July 2018 has been
about 829 kb/d.
Output has not decreased, productivity has. There's a lot in that article. Yeah, DUCs are
increasing for next year. Late next year. Conoco is the only company that I read about, that
said we do not intend to expand much in the Permian, until they get the infrastructure in
place (pipelines). They started running out of pipeline capacity the beginning of the year. I
don't know about you, but if I was a CEO, I'd feel like an absolute idiot for not figuring
that into the plans. So, for another year, they get to feed the DUCs.
Many a show and tell from the operators, is how they have brought down costs. Now, I have
tell everyone that costs are higher than before. That will never go into an annual report, as
it makes the CEO look like an idiot.
The companies are not making the production per well that was hyped. Er, maybe we should
not include that in the annual report, either. That's what I got from the article.
You don't want people to say you wound up with egg on your face, so you tell them you have
decorated your face with egg. It was your intent to look better. Spin.
I don't follow the dog and pony shows given by the oil companies, I just look at the data
from the EIA, OPEC, and shaleprofile. I guess everyone interprets information differently,
what I see in the article is that output has not risen as high as previously projected
because fewer wells are being completed than was projected. It is also probably true that the
average completed well has lower EUR than the ridiculous well profiles that are typically
presented to investors, but I always dismiss those as hype and smart investors do the same
and look up the information at drilling info, frac focus or shaleprofile.com.
The average well productivity in the Permian basin has not decreased, also no decrease in
the North Dakota Bakken, or the Eagle Ford, or the Niobrara all based on Enno Peter's
presentations at shaleprofile.com.
I also ignore the estimates by the EIA's drilling productivity report as I think that
model is poorly done.
Dennis, respectfully, you need to stop whatever you are doing and go seek help
immediately. In an effort to be the eternal optimist, or the staff contrarian, you are losing
all credibility with regards to analyzing anything oily in the world. I have no charts, or I
would stick them here.
Guy is basically right, there is nothing good to draw from this article whatsoever and the
author is one of the best there is. All costs in the shale biz are significantly higher than
EVER before. Well productivity is declining, not from takeaway restraints but from well
interference, increasing GOR and depletion. Profitability has NOT improved thus far in 2018,
the Permian unconventional oil industry is still outspending revenue and interest rates are
on their way up, up, and up.
If anybody is spending $3.5MM to drill DUC's and not paying back debt, they too need to
seek immediate help. You have become the King of Debt on POB and are discounting completely
the role that debt will play in your lofty supply demand economic theories. Rune has just
written something very good on that and Art has good data now regarding declining gasoline
consumption in the US due to higher prices. That is all debt related, man. You have gone
freaking chart bonkers.
And why argue what the KSA says about its reserves? Its their oil, they can say whatever
they want to about it and no dumb ass American is going to change it. Right here in the good
'ol US of A, reserve reporting under the ever watchful eye of the SEC, is embarrassingly
awful. Shale oil EURS are exaggerated by 30% or more. We now lie in America way better than
the Saudis ever did and get this: a lot of people believe it !! Ahem.
Dennis, I have to work for a living but I don't want you to think I criticized you and
don't have the balls to respond to all your hours of research arguing with me. I got it. And
all the charts. And the models. And the criticism directed at others for guessing, which is
all you EVER do. Have you ever seen the back in of a drilling rig in your life? You gotta
balance about 500 oil well check books to even be allowed to analyze the oil industry,
IMO.
Look, even the EIA seems to thing productivity is declining in the Permian. Goggle it. I
get the full meaning of Enno's work, all of it, including this: "all shale oil wells drilled
in America before January of 2016 now only account for 27% of total LTO production." Let that
sink in a minute.
You embrace debt as thought that is an acceptable thing in the world we live in today, and
especially from the shale oil industry, and though you want to be un-hinged from fossil fuels
as much as any of the permanent residents you have on your blog, rational ones they are, one
and all, you believe strongly in the shale oil industry's ability to pay down its debt,
improve its dismal financial performance, and deliver the goods it has promised to America.
Its very confusing, actually. And hypocritical. I guess when the shale oil industry says past
performance is not indicative of future results, you believe them.
I think, really, all you are doing is defending your damn models.
I have some serious doubts about how much and how fast shale oil will grow over the next few
years. I have accumulated no statistics, and have prepared no computations and charts to back
up my doubts. However, they should be easily understood in theory, as that's all it is, a
general theory.
While I know of no industry standards to define the difference between tier one, tier two,
and tier three oil, I have made my own guesses based on operators statements. Tier one has EUR
of 600k barrels, or more. It will produce over 200k in the first year. Tier two has EUR closer
to 300k, and will produce 100k to 200k the first year, or an off the wall estimate of 150k.
Tier three is probably closer to 150k EUR, and it's long term profitability is dependent on a
very high oil price. It will be drilled, but only when price is high, and tier two is gone.
If you look at tier one, it can be drilled at today's prices, and income from the first year
will fund one or more wells the next year with cash flow, hypothetically.
You would need about twice the number of tier two wells to equal a tier one. At present
prices you would have to borrow money to fund the equivalent number next year.
We have a limited amount of tier one wells left in the Eagle Ford and Bakken. There is
beginning to be some question as to the number of tier one spots in the Permian. Plus
increasing GOR is raising questions.
As more wells are drilled, of course the price of the well increases. Simple micro
supply/demand.
Interest rates will increase, causing borrowing costs to increase.
Even at $100 oil price, I can't see over a two million barrel a day increase in a short
period of time (three to five years).
I could put numbers to this, but I could never reach what it actually would be, anyway. Do
your own figures and see what you come up with. I just can't get to over 2 million barrels, and
that would be tough.
I'm not saying that the estimates for recovery are wrong. I'm saying using past data to
estimate the future does not take into consideration that all rock is not the same, and that
costs and borrowing ability will put their own limits on how much, and how fast growth occurs.
REPLY
All very much guess work. There are factors such as improved well layout, better well
design and so forth that tend to drive well cost for some "optimized" well design (a given
lateral length, number of frac stages and pounds of proppant and other materials) lower that
may offset the microeconomic tendency for costs to go up as constraints are reached (not
enough workers, equipment, or infrastructure). That's the reason I assume for simplicity that
long term well cost in constant dollars remained fixed.
I also have no idea on the numbers of tier one to three wells that potentially can be
drilled. All I have used is average well output for ND Bakken, Eagle Ford, and Permian from
shale profile. That is simply a mix of all wells producing. I assume oil companies attempt to
drill the most prospective areas first (not an exact science) so that as the play is
understood average new well EUR will gradually rise to some maximum (as oil companies figure
out both the best areas to drill and the best well design) and then after some period
(probably 2 to 3 years) the best areas will become saturated with wells so that less
prospective areas will be drilled and new well EUR will gradually decrease. That is my model
in a nutshell and the result for the US is that tight oil output may be able to rise from
6000 kb/d in July 2018 to about 8000 kb/d by July 2023 (about 5 years). This scenario assumes
high oil prices and is optimistic, a "medium" oil price scenario would result in maybe a 1.5
Mb/d increase in tight oil output over 5 years and a "low oil price scenario" ($80/b in 2017$
maximum by 2025) might see only a 500 kb/d increase in tight oil output from 2018 to
2023.
Note that US tight oil output has risen by about 700 kb/d over the first 7 months of 2018.
I do not believe this rate of increase will continue for much longer and will gradually
decrease as we approach 2021.
For the Permian basin specifically the peak is about 1 Mb/d lower for my "low oil price"
scenario relative to the medium price scenario ($80/b vs $113/b max price). Other basins
would also be affected, but I haven't run the scenarios on all tight oil basins so I am not
sure how much the entire US tight oil peak would be affected, probably 1.5 Mb/d lower than
the medium price scenario. For Rune Likvern's near term oil price scenario tight oil output
would be fairly flat from current output levels in my opinion and that would tend to put
upward pressure on oil prices.
We have not had any difference of opinion on future shale output, in the last 6 months,
according to my recollection. Any minor differences that may have been discussed fit into the
"who knows" classification. My comment was for those "other" projections coming out, that
basically are surreal. They have caused, in my opinion, an excess of pipelines being built,
and massive expenditures to be able to export another 3 to four million barrels of oil a day
that will probably never show up.
700k a day out of the Permian, is actually what I am projecting for 2018. Even 800k is
within probability. 200k of extra pipeline is due sometime before year end. Not much more
than that until late 2019 when bigger pipelines may be available. But the amount you could
crank it up to would be limited by the number of months left in 2019.
Agree 100%. Note that 700 kb/d is roughly my estimate for Permian increase in 2018 as
well, for the US tight oil as a whole possibly 1000 to 1200 Kb/d increase in 2018. Many of
the estimates are too high on that point we are definitely on the same page.
I mean, there are only four months left. I know the Eagle Ford can't do hardly anything in
that time fraim, Bakken is stuck at a high of about a 100k increase, so what fields will add
that much?
From Bakken, Eagle Ford, Niobrara, and STACK/SCOOP.
So far non-Permian US tight oil has increased about 215 kb/d through the first 7 months of
2018, I would expect this to accelerate if anything as capital moves to other tight oil
basins due to the low oil prices at Midland. So a 400 kb/d increase from other tight oil
basins (exit rate for 2018), plus 700 kb/d from Permian basin would give us 1100 kb/d.
So far in 2018 we have increases of 92 kb/d in Bakken, 61 kb/d from Eagle Ford, 38 kb/d
from Niobrara, 479 kb/d from Permian, and 24 kb/d from all other US tight oil plays.
If all output stopped increasing in other tight oil plays besides the Permian after July
2018 we would have a 915 kb/d increase in US tight oil output in 2018, if my guess of a 700
kb/d increase for the Permian basin tight oil output in 2018 is correct. My best guess
remains 1100+/-100 kb/d for the US tight oil increase in output from Dec 2017 to Dec
2018.
I only have data through July 2018, so 5 months left for increases, if we extrapolate the
rate of increase for the first 7 months of 2018 we get 1190 kb/d for the 2018 increase in
tight oil output. I scale it back a bit because I expect Permian output increase will slow
down. Other plays might also speed up.
Ok, your looking at EIAs production estimate per play, again. I'm only going to go by
monthlies. There will be other field declines, besides tight oil. GOM, Alaska, and non tight
oil Texas.
Haven't looked at rig counts lately so it's a guess. Just figure the capial may move to
higher profit areas such as Bakken or Niobrara. Yes there are DUCs that could be completed.
There may be more available frac crews in other plays as everyone has flocked to Permian.
The Kashagan oilfield is proving to be a real nightmare for operators and partners. No
wonder a decision was made to expand capacity for the land based Tengiz field. No similar
call was made for Kashagan even if stated reserves are a bit higher than for Tengiz.
It is a bit like offshore deepwater. If the size of a new prospect warrants it, the cost
can be kept down reasonably. And the North Slope is probably one of the places it is possible
to find another or even several gigant oil fields (above 500 million barrels). Just shows
that some majors are betting on higher oil prices.
EIA Weekly U.S. Ending Stocks to Friday 17th August
Crude oil down -5.8 million barrels
Oil products up +1.5
Overall total, down -4.3 (shown on chart)
Natural Gas: Propane & NGPLs up +1.5 (not included in the chart) https://pbs.twimg.com/media/DlZH1X2X0AIPDLR.jpg
Big drop in Iranian exports the first of August, and not close to Nov. yet. One million
looks more likely, eventually. And for those that may have missed it, Sinopec has started
buying US oil, again. To me, that indicates China is attempting to remain somewhat
neutral.
It's pretty clever. They want money from the state before they do any work developing
their own lease. The money would fund . . . haha . . . management salaries, among other
things.
And if it proves out as no oil, well, then they got the state to fund exploration. If
there is oil, they get the money from selling the oil. It's no lose.
Big trouble is brewing in the mighty North Dakota Bakken Oil Field. While oil production in
the Bakken has reversed since it bottomed in 2016 and increased over the past few years, so has
the amount of by-product wastewater. Now, it's not an issue if water production increases along
with oil. However, it's a serious RED FLAG if by-product wastewater rises a great deal more
than oil.
And... unfortunately, that is exactly what has taken place in the Bakken over the past two
years. In the oil industry, they call it, the rising "Water Cut." Furthermore, the rapid
increase in the amount of water to oil from a well or field suggests that peak production is at
hand . So, now the shale companies will have an uphill battle to try to increase or hold
production flat as the water cut rises.
According to the North Dakota Department of Mineral Resources, the Bakken produced 201
million barrels of oil in the first six months of 2018. However, it also produced a stunning
268 million barrels of wastewater:
Thus, the companies producing shale oil in the Bakken had to dispose of 268 million barrels
of by-product wastewater in just the first half of the year. I have spoken to a few people in
the industry, and the estimate is that it cost approximately $4 a barrel to gather, transport
and dispose of this wastewater. Which means, the shale companies will have to pay an estimated
$2.2 billion just to get rid of their wastewater this year.
Now, some companies may be recycling their wastewater, but this isn't free. Actually, I have
seen estimates that it cost more money to recycle wastewater than it does to simply dispose of
it. So, as the volume of wastewater increases while the percentage of oil production declines,
then the shale companies are hit with a double-whammy... less oil revenue and rising wastewater
disposal costs.
To give you an idea just how much more water is being produced versus oil in the Bakken, I
went back to the North Dakota Department of Mineral Resources and looked at their data back to
2015. Unfortunately, the data published in excel only goes back to 2015, even though they have
figures published in PDF form starting in 2003.
Regardless, four years is plenty of time to show just how bad the situation is becoming in
the Bakken. In June 2015, the North Dakota Bakken produced 16% more water than oil. However
June this year, the Bakken field produced 38% more water than oil :
You will notice that overall oil and water production declined in 2016, due to the falling
oil price, but as production grew in 2017 and 2018, the percentage increase of by-product
wastewater surged to 32% and 38% respectively. Here is an interesting comparison:
Bakken Oil & Water Production:
June 2015 Oil = 34.4 million barrels
June 2015 Water = 39.8 million barrels (16% more water)
June 2018 Oil = 33.8 million barrels
June 2018 Water = 46.8 million barrels (38% more water)
As we can see, while overall Bakken oil production in June 2018 was less than it was in June
2015, the volume of waster water increased by an additional 7 million barrels.
I believe there are two negative forces at work in the Bakken as it pertains to the rising
volume of wastewater.
As the wells and field age, more water is produced than oil
Larger Frac Stages, which require more water and sand, are now being utilized to keep
production growing or to keep it from falling
While a rising water cut isn't a surprise to the industry as it is a natural progression of
an aging oil well or field, the use of Larger Frac Stage wells should be a WAKE-UP CALL to
investors. Why? Because Larger Frac Stage wells consume a great deal more water and sand to
produce more oil initially, but the decline rates are even more severe than regular shale
wells.
So, when the Investor Relations are bragging how the companies are using the newer
technology of more complex Large Frac Stage wells, this isn't a good sign. This means that the
company is now desperate to try and grow production, or at worst, to keep it from falling.
Unfortunately, the U.S. Shale Industry is in serious trouble. Most of the shale fields have
reached a peak and when production starts to decline, especially during a collapsing oil price,
I forecast a rapid disintegration of the industry. We must remember, as the oil price and oil
production falls, then company stock and asset values will plummet while the high debt levels
remain. Thus, the shale industry will have increasing difficulty in servicing its debt.
I will continue to monitor the production of oil and wastewater in the Bakken. Please check
back for updates.
It is a little early to really get a sense of how much the Permian is slowing down. Most
analysts have been assuming an overall slowdown over the next 12 months because of pipeline
constraints. However, the EIA figures might suggest that the problem has already started to
bite. In April, the EIA predicted in its Drilling Productivity
Report that Permian production would jump by 73,000 bpd in May. But the monthly data just
released finds only modest gains in Texas (+20,000 bpd) and New Mexico (+3,000 bpd).
Second, the EIA thinks output broke 11 mb/d in July, an all-time high. But judging by the
overly-optimistic monthly data from April and May, perhaps the agency is also overstating July
figures, which raises the possibility that production is not nearly as high as we currently
think.
In the coming months, if monthly U.S. production figures continue to show output
undershooting expectations, that would have global ramifications. Most analysts still are
baking in strong U.S. shale growth figures into their forecasts. If that additional output
fails to materialize, the oil market could end up being a lot tighter than we all expected it
to be.
Earlier estimates of OPEC have now changed, and there is no increase from June. Probably, a
slight decrease from SA. From OPEC sources, not Platts. I think they would start increasing
if Iran drops, but not much otherwise. I think Sauds and Kuwait joint venture is set up for
that potential.
Changing the way I gage things, into a much simpler format. Now, I look at world inventory
drops, and look at current increases from OPEC and US. Neither will change much, so inventory
drops should continue. Opec needs to come up with a lot more, or it will look damn scary in
2019. With pipeline constraints, Canada is pretty much out of the picture for further
increases this year, and not much, elsewhere.
Yes the outlook for OPEC's July production is looking more flat now. This is a strange
situation because Platts is one of OPEC secondary sources and so I assume that they see all
the numbers
Thank you. This news confirms that world production is stagnating. Possibly very close to the
decline. We will have to be attentive to the inventories. It will be the first place that the
nations get hold of in order to supply themselves with oil.
It is a little early to really get a sense of how much the Permian is slowing down. Most
analysts have been assuming an overall slowdown over the next 12 months because of pipeline
constraints. However, the EIA figures might suggest that the problem has already started to
bite. In April, the EIA predicted in its Drilling Productivity
Report that Permian production would jump by 73,000 bpd in May. But the monthly data just
released finds only modest gains in Texas (+20,000 bpd) and New Mexico (+3,000 bpd).
Second, the EIA thinks output broke 11 mb/d in July, an all-time high. But judging by the
overly-optimistic monthly data from April and May, perhaps the agency is also overstating July
figures, which raises the possibility that production is not nearly as high as we currently
think.
In the coming months, if monthly U.S. production figures continue to show output
undershooting expectations, that would have global ramifications. Most analysts still are
baking in strong U.S. shale growth figures into their forecasts. If that additional output
fails to materialize, the oil market could end up being a lot tighter than we all expected it
to be.
Dearth of investments in oil projects mean a spike in prices above $100 could be on the
horizon
Crude across the globe is being used up faster than it is being replaced, raising the
prospect of even higher oil prices in the coming years. The world isn't running out of oil. Rather, energy companies and petro-states -- burned by
2014's price collapse -- are spending less on new projects, even though oil prices have more
than doubled since 2016. That has sparked concerns among some industry watchers of a massive
price spike that could hurt businesses and consumers. The oil industry needs to replace 33 billion barrels of crude every year to satisfy anticipated
demand growth, particularly as developing countries like China and India are consuming more
oil. This year, new investments are set to account for an increase of just 20 billion barrels,
according to data from Rystad Energy.
The industry's average decline rate -- the speed at which output falls without field
maintenance or new drilling -- was 6.3% in 2016 and 5.7% last year, the Norway-based
consultancy said. In the four years before the crash, that decline rate was 3.9%.
Any shortfall in supply could push prices higher, similar to when oil hit nearly $150 a
barrel in 2008, some industry participants say. "The years of underinvestment are setting the scene for a supply crunch," said Virendra
Chauhan, an oil industry analyst at consultancy Energy Aspects. He believes a production
deficit could come as soon as the end of next year, potentially pushing oil above $100 a
barrel.
SNIP In parts of Brazil and Norway, decline rates are already above 10-15%, Energy Aspects' Mr.
Chauhan said. Output from Venezuela's aging fields fell by more than 700,000 barrels a day over
the past year, according to the IEA. In June, Angola's output hit a 12-year low, while Mexico's
production is down nearly 300,000 barrels a day since the middle of 2016, despite efforts to
open up the industry and reverse declines, the IEA said. "Nobody is really stepping in," said Doug King, chief investment officer of the $140 million
Merchant Commodity hedge fund. "People still got burned by the downturn."
Rystad has first half figures for discoveries a bit better than last year, though more on the
gas side than oil, but there was a billion barrel Equinor discovery in Brazil this week that
will make things look better. I thought things were worse, partly because I assumed the
Guyana discoveries would count as appraisals and be back dated against 2016 and 2017, but it
looks like they are new fields. Overall though it still shows a big drop over the past few
years.
A "remarkable" recovery from "abnormally" low levels – complete bollocks, and pretty
close to self-contadictory. Everything is, and always will be, awesome in the oilprice
universe, if not they'd lose their revenue stream.
x
Ignored says:
07/27/2018 at 3:53 am Iran would not try to block anything unless it is under attack by the
US. The Pentagon is opposed to such an attack, but Trump is heavily influenced by Netanyahu and
is advised by the same neocons who got the US into the fiasco in Iraq. Given the inability of
the US Congress to enforce the constitution by denying the Prsident to start a war without a
congressional declaration of war, it seems the USA may be on its way to destroy the world
economy to please an extremist Israeli right wing government.
I write destroy the world economy because it's doubtful Iran would respond as anticipated by
the Americans, who have a tendency to fight wars with strategies based on previous wars and an
excess of complex gadgets and extremely expensive technology. I don't know what they have in
mind, but I'm sure it would be unexpected, calibrated to avoid nuclear retaliation, and may
evolve over time. But I'm sure others will see the risks, and the oil market will take off into
the $100's and possibly $200's unless there's adults left in the USA senate to block this
craziness.
Hightrekker x
Ignored says:
07/26/2018 at 9:51 am I agree– and with all those KSA installations just
15 minutes away by unstoppable missile technology (1970 midrange seems a little
hard for current technology), we have a quandary, not a problem.
Reply
Fernando Leanme
x Ignored says:
07/27/2018 at 3:57 am Exactly. But I'm not sure US National Security advisor
Bolton knows anything about low technology midrange missiles and drones, some of
which, in a pinch, can be piloted by small light weight kamikaze martyrs.
Eulenspiegel x
Ignored says:
07/26/2018 at 10:24 am The worst thing for a date to guess is politics.
There are 10 countries that have to grow oil production to avoid peak oil –
these with still big reserves.
One knocked out itself – Venezuela
One is under attack from the USA – Iran
Irak isn't that stable, either.
A hot war can break out every moment, or a civil war devasting and blocking
infrastructure for years, while other countries deplete.
Or peace can come and these ressources can get used.
These combined 10 mb/d alone will determine peak oil – by 5 years or more in
either direction. These 10 mb/day can't be replaced by russion oil tsars, US rednecks
with too much Wallstreet money or Saudis opening secret valves of instant oil wonder
production.
Venezuela can get a new government and increase production by a big amount, helped
by international money. It has the ressources to get one of the big producers when the
tar oil is lifted.
So in my eyes, it looks like somewhere between 2020 and 2030, perhaps even
later.
Couldn't agree with you more regarding OPEC reserve estimates, they are all full of
shit, and no one except a handful of people in those countries would know how much they
have left.
Solving this peak oil timing is more similar to a quantum mechanics problem rather
than a Newtonian mechanics one. It complexity, lack of transparency and political and
economic implication make it impossible to have a deterministic answer, its pure
probability, and also speculations.
Like you i think all these projections are wrong. Maybe we will extract a lot more
oil with newer technologies or new field discoveries and end up cooking the planet with
climate change, and we won't see a "peak oil" for 100s of years who knows.
TechGuy x
Ignored says:
07/26/2018 at 2:54 pm "The peak oil experts were dreadfully wrong with their HL 15
years ago, so what prevents their being just as wrong now? "
Why is Oil at $70/bbl? Back in 1999 its was about $10/bbl. If there no supply
constraints why did the price increase ~7 fold in less than 20 years? Also why the need
to to drill for Shale Oil (Source Rocks) & develop in Deep & ultradeep
water?
Conventional oil peaked in 2005, All the growth is coming from offshore & Shale.
New Oil discoveries have dropped off the cliff. We found almost nothing in 2017. Oil
Discoveries peaked in 1960s and been in permanent decline. Thus if we are discovery
less and less new oil fields every year, below the rate of consumption, Oil production
will have to fall to match discoveries at some point in the future.
Other clues:
1. Oil Majors perfer to drill on Wall street (aka using debt to fund stock buybacks)
instead of developing new fields for future production.
2. Shale Debt: Shale drilling never made a profit, except for using OPM (other People's
money) to fund CapEx\OpEx.
3. US invaded or targeted with Regime change in Middle East Oil producing nations. Only
Iran remains and you can already hear the War drumbeats for Iran.
Reply
Michael B x
Ignored says:
07/26/2018 at 3:31 pm Indeed, and thanks. Note that your answer has to do not
with HL but with obvious signs & symptoms. Believe me, I've been watching, too.
The uncertainty is killing me.
Fernando Leanmex
Ignored says:
07/27/2018 at 4:25 am Michael, I have never been a peak oiler. I come at this from
a different perspective: about 30 years ago I noticed exploration results were
decaying, and started working in areas which would allow producing oil and gas in the
far future from sources we weren't tapping much at the time.
I remember sitting in a meeting around 1990 and suggesting to managers in a
committee I was briefing that we needed to focus on locking up hydrocarbon molecules,
wherever they were, cut down exploration and use that money on technology and getting
access.
This is one reason why eventually I got involved in gas conversion to liquids, heavy
oil, and the former Soviet Union, which to us appeared like a happy hunting ground,
including its Arctic targets in the Barents, Kara, Yamal, etc. I also had colleagues
who went into deep water, EOR, North America Arctic, and of course the hydraulic
fracturing of vertical horizontal wells drilled in low perm formations.
So in my case I've been about 30 years now working on replacing conventional oil
barrels with more difficult barrels. And those difficult barrels require higher prices.
So the question is, what can poor countries afford?
Reply
Michael B x
Ignored says:
07/27/2018 at 5:13 am So, "not a peak oiler" means you think the fate of
conventional oil is not really all that important, and cost is the ultimate
arbiter, not the resource?
Reply
Fernando Leanme
x Ignored says:
07/27/2018 at 6:19 am Not a peak oiler means I don't use Hubbert
Linearization or similar techniques. In the past, my job has included the
estimate of resources (not reserves). The preferred technique was to estimate
technical reserves, meaning we supposedly didn't focus on economics. But I
couldn't have staff working out numbers doing endless iterations and model runs
for highly speculative cases, so I gave them the guidance to assume a really
high price, a higher OPEX and CAPEX environment, and prepare conceptual field
redevelopments and marginal field developments or targeting really low quality
reservoirs. We devoted about 5% of the time budget for this effort. And I told
head office I wasn't about to use more manpower working such hypothetical
figures, because we had to focus on reserve studies, and preparing projects to
move reserves along the reserve progression pathway so we could meet our
targets.
The fate of conventional oil is already written, in the sense that most of
the extra oil we get from conventional fields comes from redevelopments which
rely on higher prices, and EOR. The typical field with say 45% recovery factor
can be pounded hard to push it to say 55%, going above 55% gets mighty hard,
and pushing to 60% is nearly impossible. So there are limits, which involve the
huge amount of resources (cash, steel, chemicals, and people) we use up to get
those extra barrels.
One issue to consider is that these redevelopments which include EOR are not
contributing that much extra rate. They stop decline, get a slight bump, and
then yield a slower decline rate for 10-20 years. This means investments take
tine to payout and if the world is suffering from acute shortages they don't
help that much. The on,y fast reaction comes from fracturing "shales" and low
permeability sands, infills in newer fields, and workovers.
Reply
Michael B
x Ignored says:
07/27/2018 at 6:53 am Thanks. If you were doing this in the 90s, sounds
like you were "predicting" the future!
Reply
Hickory
x Ignored says:
07/27/2018 at 9:20 am Sure sounds like a long explanation for your
understanding of 'peak conventional oil'. Nothing to be ashamed of.
Reply
AdamB x
Ignored says:
07/26/2018 at 10:08 am With oil discoveries the last 3 years in the toilet due to lack
of capital investment and lack of major fields its just a matter of time mathematically. Be
thankful we still have time before peak production hits cause I don't think it will be fun
post peak. Hopefully still 5 years until its official maybe less When will Ghawar give up
the ghost .?
Reply
Dennis Coyne x
Ignored says:
07/26/2018 at 11:21 am Saudi Arabia may keep going for many years at 10 Mb/d,
probably until 2030, perhaps beyond.
Reply
AdamB x
Ignored says:
07/26/2018 at 12:02 pm One can hope .they can produce 10 Mb/d to infinity
according to their reserve numbers which never budge .I'd be curious what posters
think their reserves are. 175-225 GB?
Reply
Survivalist
x Ignored says:
07/26/2018 at 2:27 pm It'll be interesting to see how KSA shakes out when
oil consumption begins to zero in on oil production, and exports decrease..
ELM.
Dennis Coyne x
Ignored says:
07/26/2018 at 10:58 am Another consideration is discoveries and reserve appreciation.
Consider estimates of conventional C+C using Hubbert Linearization by Jean Laherrere which
have gradually increased from 1998 (1800 Gb) to 2016 (2500 Gb.) In addition, there is not
any particular reason that output would tend to follow a "Hubbert" type logistical
function.
Generally estimates based on Hubbert Linearization would be a minimum estimate in my
view.
In addition conventional oil Extraction rates (output divided by producing reserves) in
the World (5.6% in 2016) are far lower than the United States (14.8% in 2016, all C+C), so
there is the potential that with higher oil prices the average extraction rate for the
World may increase. The World conventional extraction rate was about 11.6% in 1979. A
gradually increasing rate of extraction might allow a plateau in output to be extended for
many years (to 2030 at least). Impossible to predict of course, the number of scenarios
that can be created is large.
One such scenario is presented below (peak in 2025 at 85.5 Mb/d of C+C or 4275
Mt/year).
The analysis using the logistic function does not account for this potential.
Dennis Coyne x
Ignored says:
07/26/2018 at 6:49 pm I disagree. Oil prices are more likely to increase than
to fall to $30/b and more of these companies are likely to be profitable as oil
prices rise, also 3 of the top companies are profitable, so a "well run" oil
company can indeed be profitable, those that are less well run will either change
the way they operate or they will go out of business. The better companies buy the
worthwhile assets on the cheap and life goes on.
It's called capitalism folks.
Also the DPR is not very good, I ignore that report and use EIA's tight oil
estimates (link below) and shaleprofile.com for good information.
GuyM
x Ignored says:
07/27/2018 at 9:12 am "Also the DPR is not very good", is an understatement.
I have never seen an analysis use so many different fruits to come up with
bananas expected.
Reply
Minqi Li x
Ignored says:
07/26/2018 at 3:55 pm I suppose by "decline rate" they are talking about the
"legacy decline"
Reply
Guym x
Ignored says:
07/26/2018 at 5:48 pm As an example, I will use approximate data from a fairly
good tier 2 well in the Eagle Ford. It starts off production at 33k the first
month, and drops rapidly after that to reach 8k by the final month. Let's say it
produces 175k the first year, which would be profitable at today's prices. The next
year it produces 55k, and the next year 36k. By the fourth year it is producing
less than 100 barrels a day, and by the sixth year it is questionable to keep up.
Little better than stripper status. Tier three stuff is much worse, it may reach
stripper status by the third year. Eventually, all will be tier two and three
status wells. That's the majority of reserves estimated. Estimating future
production from current production doesn't touch on reality. Eventually, to keep up
on initial production, you would have to drill twice as many wells. But, you won't
keep up with twice as many, because the decline rates will be higher. There is a
lot of difference between a 600k EUR well, and a 300k EUR, or a 150k EUR. 2042 for
US peak? Not hardly.
Reply
I agree, probably 2023 to 2025 will be the US peak, after that decline is
likely to be rapid because mostly tier 2 and tier 3 wells will be left, high
oil prices may make them profitable, but it will be impossible to keep up with
the decline rate of legacy wells after 2025 and US output will decline rapidly
(4 or 5% per year) after 2030.
Reply
TechGuy
x Ignored says:
07/26/2018 at 7:48 pm One snag: The Shale Debt starts coming due in
2019 and continues through to 2024. Shale drillers were successful since
the borrowed at rock bottom interest rates and investors practically fought
each other begging Shale drillers to take their money. Not so sure it will
work if interest rates are higher, and The Shale sweet spots aren't
endless.
Reply
Guym
x Ignored says:
07/26/2018 at 8:49 pm That might slow the start up, for sure. If
the price of oil gets high enough, that will barrier will be short
lived.
Reply
TechGuy
x Ignored says:
07/27/2018 at 2:43 pm As oil prices increase so does the costs.
It takes a lot of diesel to haul Water, Sand, and oil. Shale
drillers never really made a real profit, even when Oil was over
$100/bbl. One must consider the EROEI for Shale & rising
CapEx\OpEx as the cost of Oil rises.
Second, its likely that consumers cannot afford high oil prices.
As prices rise, Consumers will cut back and it will plunge the
global economy back into recession. Perhaps the Worlds Central
banks can coach something back into the global economy, but it
won't work over the long term.
FWIW: Some of the recent data is showing weakness in the global
economy: Housing sales are falling and prices in the hot regions
are flatlining. Trumps tariffs are also taking a toll as global
trade is falling. And there are cracks in the developing world
credit markets. We might see a stock market correction this fall,
which would likely see commodity prices fall (including Oil).
Reply
Hickory
x Ignored says:
07/27/2018 at 10:37 pm " consumers cannot afford high oil
prices. As prices rise, Consumers will cut back and it will
plunge the global economy back into recession."
Well, that likely depends on how fast and far the prices go.
Slow steady rise can be well tolerated pretty far. Energy is so
cheap for what you get, after all.
Many other countries have a much better GDP/unit energy
consumed than the USA, and with price pressure the USA could
get there too. I suspect we could shed 10-20% of our oil
consumption without big effect, particularly if we did it
slowly. For example, it wouldn't affect the GDP at all if we
slowed down to max 60 mph. Painless saving of energy, if you
choose good music.
It is the fast changes in price that really tend to hurt.
Reply
TechGuy
x Ignored says:
07/27/2018 at 11:45 pm "I suspect we could shed 10-20%
of our oil consumption without big effect, particularly if
we did it slowly."
It doesn't work that way. Consumers cut back on
spending, from eating out, going on vacations. They loss
confidence and delay major purchases like new cars, homes,
etc.
Most of the population commute to work well below 60
mph. Traffic usually limits speeds to 40 mph or less during
commuting hours.
To understand how high oil prices affect the economy
just research the events around 2007/2008. Schools &
business were planning to reduce work & school days to
3 or 4 days a week. Thieves were draining fuel from parked
trucks and cars. The higher oil prices caused food prices
to soar, which lead to the arab spring in Africa & the
middle east. Europe had frequent riots. Airlines &
shipping companies impose fuel surcharges. People homes had
utilities shutoff. since they could afford their energy
bills.
Funny how quickly people forget the aftermath of high
energy prices. Doesn't anyone read or study economics?
GoneFishing x
Ignored says:
07/26/2018 at 5:28 pm Nice report. Production decline is a short time away if we
don't keep drilling.
Speaking of legacy wells, the huge number of abandoned wells from the past is
leaving us a legacy of leakage. The even bigger number of recent wells will continue
that legacy.
Fernando Leanmex
Ignored says:
07/27/2018 at 4:33 am 150 year old wells in the eastern USA could indeed leak
methane. But I would not rely much on Arstechnica, it's a blog run by a guy with a
liberal arts degree very well crafted to be a cheering section for renewables. It
may even be subsidized by Yingli Green, a Chinese solar panel maker.
Reply
Fred Magyar
x Ignored says:
07/27/2018 at 6:57 am Are you seriously claiming that a peer reviewed
scientific paper, in the 'Proceedings of The National Academy of Sciences of
The United States of America' is somehow untrustworthy because it's conclusions
were mentioned by Ars Technica?!
Identification and characterization of high methane-emitting abandoned oil
and gas wells
Abstract Recent measurements of methane emissions from abandoned oil/gas wells show
that these wells can be a substantial source of methane to the atmosphere,
particularly from a small proportion of high-emitting wells. However,
identifying high emitters remains a challenge. We couple 163 well measurements
of methane flow rates; ethane, propane, and n-butane concentrations; isotopes
of methane; and noble gas concentrations from 88 wells in Pennsylvania with
synthesized data from historical documents, field investigations, and state
databases. Using our databases, we (i) improve estimates of the number of
abandoned wells in Pennsylvania; (ii) characterize key attributes that
accompany high emitters, including depth, type, plugging status, and coal area
designation; and (iii) estimate attribute-specific and overall methane
emissions from abandoned wells. High emitters are best predicted as unplugged
gas wells and plugged/vented gas wells in coal areas and appear to be unrelated
to the presence of underground natural gas storage areas or unconventional
oil/gas production. Repeat measurements over 2 years show that flow rates of
high emitters are sustained through time. Our attribute-based methane emission
data and our comprehensive estimate of 470,000–750,000 abandoned wells in
Pennsylvania result in estimated state-wide emissions of 0.04–0.07 Mt
(1012 g) CH4 per year. This estimate represents 5–8% of annual
anthropogenic methane emissions in Pennsylvania. Our methodology combining new
field measurements with data mining of previously unavailable well attributes
and numbers of wells can be used to improve methane emission estimates and
prioritize cost-effective mitigation strategies for Pennsylvania and
beyond.
Reply
Fernando Leanme
x Ignored says:
07/27/2018 at 8:33 am I am an academy member. I also know how to search
for methane leaks. And I'm aware the academy publishes papers which lack
the quality one would like to see. But if you want credibility, I would
skip Arstechnica and link directly to the paper.
The Arstechnica editor has an axe to grind, publishes a bunch of
garbage, therefore I never pay attention to it. Regarding the paper itself,
it's not representative of what goes on in say Texas. There are areas in
Texas (say Spindletop) where gas leaks should be present from the wells
drilled with cable tools in the old days. But a better sense for what goes
on now is gained from looking at wells drilled and abandoned in Texas and
Louisiana in the last 40 years.
Regarding Pennsylvania methane leaks, in the overall picture they are
meaningless. There are coal mining regions in India and China which can be
seen as very large hot spots from satellites.
Fred Magyar
x Ignored says:
07/27/2018 at 3:11 pm Hippity hoppity! Off to a tea party
with the Mad Hatter and Alice! As in A Large Ion Collider
Experiment at the LHC. Much more fun than dealing with the
crippled egos of idealogues.
Cheers!
Reply
If the wells are plugged, the concrete eventually fails (30 years) so we
have an ongoing source of methane that could last for centuries. Millions
of wells across the US, much more across the world.
And guess what, those ideas of storing CO2 underground, well now we have
millions of pathways for the CO2 to escape, so actual sites would be few
and far between.
The original Canadian study I read a few years ago has disappeared from
the internet. It showed the long term potential leakage of well systems.
Reply
Dave Kimblex
Ignored says:
07/26/2018 at 6:11 pm All this Hubbertian analysis is useful to set a ceiling on
production, but the world's economy runs on making a profit and so producers have a minimum
price they must receive, while the end consumers have a maximum price they can afford to
pay.
In mid-2008 the effect of a 72% price rise in 18 months caused a $1.75 trillion extra
cost on OECD oil imports and the world economy crashed. Recovery required the USG to
guarantee loans to frackers to get the production numbers up. I am not saying that they
won't try that again, but this can only go so far. Surely next time this happens, no one
will be able to avoid the obvious conclusion that there is no future profit in oil
production, and the oil industry will have its share prices downgraded, reducing the
collateral for loans, whereupon they will go out of business in a puff of smoke.
This will happen long before any URR impacts, so I wonder at how much this analysis is
worth.
Reply
Guym x
Ignored says:
07/26/2018 at 8:25 pm USG guaranteed loans to frackers???? Interest rates for
everyone was low then, but I don't remember reading about any guarantees. Drilling
horizontals is a little past SBA stuff.
Reply
George Kaplan x
Ignored says:
07/27/2018 at 1:56 am If the "oil industry" means the IOCs then they are a minor
player now. The NOCs dominate the reserves and production, of course they all seem to
be having money issues as well but maybe they manifest in a slightly different way
– i.e riots, uprisings and infrastructure collapse.
It's already noticeable that many of the big companies are switching to share buy
backs (Total, Shell, Anadarko) and less development spending even as the price has been
rising. The one which has switched the other way is ExxonMobil, and not
uncoincidentally it is the only one with really good recent discoveries. That straight
line H/L for the rest of the world is just the tail run out on existing discoveries,
most of which are also already developed and wouldn't be taken off line even with
bankruptcies for the operators. If only as chemical feedstock oil is way better in
almost every way than anything that could be made from water/CO2/renewable energy so if
civilisation lasts long enough most of it will be used.
Reply
George Kaplan x
Ignored says:
07/27/2018 at 1:44 am Forcing a logistic curve on some of those production histories
might give some big errors, though maybe they cancel out overall. Hubbert said himself that
H/L wouldn't work well on production that had been artificially constrained by a cartel
(e.g. OPEC for Saudi, Kuwait, UAE, Iran and Iraq) or environmental moratoria (e.g. some US
and Canada oil). For oil sands they tend to be built on 50 year project lives, with steady
production and a fast fall off rather than a traditional decline curve. About 50 mmbbls of
reserve is already tied into operating, steady production. Future developments will be
similarly constrained with the additional limit from environmental objectives to both the
extraction and pipelines. Logistics curves might still come close if the reserve estimates
are good, but that is also the biggest unknown as other comments have said.
Reply
Minqi Li x
Ignored says:
07/27/2018 at 2:54 pm Projections are not meant to be predictions. Even EIA or IEA
say that. But they are always useful to illustrate given certain assumptions, what will
or what are likely to happen.
That has been said, given our understanding of the inherent limitations of
projections/data, a careful and cautious application of these projections does provide
us some idea regarding the likely range of future development. For example, the
projection for the US oil used in this report is likely to be too optimistic especially
for years after 2025, as many have pointed out. That will reinforce the case for a
global peak oil before 2025
In addition to production, I think the consumption data in the report also provides
some interesting information. I wonder if someone cares to comment about that.
Reply
Guym x
Ignored says:
07/27/2018 at 7:37 pm Well, obviously consumption can't be over production for
any great amount, or we won't have inventory. Peak production precedes any mythical
peak demand. Consumption mostly follows production is my guess. At probably a much
higher price than today.
Reply
"Pioneer spent $818 million on capital expenditures (CapEx) for additions to oil and gas
properties (drilling and completion costs) during Q1 2018, brought on 63 horizontal wells
in the Permian, and only added 9,000 barrels per day of oil equivalent over the previous
quarter"
So it's round about 13 million $ per well, not 7 million.
Reply
Fernando Leanmex
Ignored says:
07/27/2018 at 8:38 am The number of wells brought on isn't proportional to wells
drilled. And the CAPEX isn't proportional to wells drilled. Therefore it's hard to
derive a per well cost from such figures.
Reply
GuyM x
Ignored says:
07/27/2018 at 9:06 am Yeah, there a lot of DUCs, and you have to consider that
Pioneer lays out some bucks for its gathering system and gas processing plant in the
Permian. Hard to isolate per well from total capex figures.
Reply
(Sale of oil) – well cost – variable cost per barrel = profit
does not work that good – there are lots of hidden costs even under CAPEX,
that are almost as high as completion costs when these 7 million$ / well are
right.
And I think these cost are not one time cost just only in this quarter –
there is alway a pipeline to build, a convertert to install, a gravel road to the
site to build and so on.
Reply
George Kaplan x
Ignored says:
07/27/2018 at 3:42 pm Rystad has first half figures for discoveries a bit better than
last year, though more on the gas side than oil, but there was a billion barrel Equinor
discovery in Brazil this week that will make things look better. I thought things were
worse, partly because I assumed the Guyana discoveries would count as appraisals and be
back dated against 2016 and 2017, but it looks like they are new fields. Overall though it
still shows a big drop over the past few years.
With over 3000 platforms, 25,000 miles of pipeline, all unsecure in the Gulf of Mexico,
they provide a lucrative target in any conflict with the US. Energy disruptions and
environmental calamities would reek havoc. Surely there is a plan to quickly secure the Gulf
from under/over/on the water threats? If not get at it.
More Oilprice.com industry pimping. The world uses 36 billion barrels (Gb) of crude per
year. Plus they are quoting boe, or barrels equivalent. Gas is not crude. The article should
read: "The world is still pumping 9 barrels for every 1 it finds". D day is not something the
industry doesn't wants advertised.
Look at the graph again. Draw a trend line from left to right across the peaks from 2014
til now. Is the line pointing up or down? That's peak oil.
So there's been an up tick this year. How much has been discovered. Ooooh, 4.5 billion
barrels. Sounds like a lot to you? What's the world consumption rate expressed in millions of
barrels per DAY? Don't know? It's around 90 million barrels per DAY. Look it up if you doubt
me. If you divide 4.5 billion by 90 million, you'll calculate how many DAYS it takes to
consume 4.5 billion barrels. To make it easier for you, just reduce the fraction by stroking
6 zeros off each number. That's 4,500/90. Not too hard. That's 50 DAYS of supply!!! OK, maybe
another 4.5 billion will be found in 2H2018. Oooooh, another 50 DAYS worth. We're
saved!!!
In the last paragraph, what's the Reserve Replacement Rate? 10% . That's not so good.
Also, a large portion of the newly discovered oil is offshore, in ultra deep reservoirs.
Do you think that might be more expensive to produce?
As for abiotic oil, as Laws of Physics pointed out, even if that desperate theory were
true -- which it isn't -- it's the rate of replacement that matters, and it's nowhere near 90
million barrels per day.
So, fore-warned is fore-armed, but if you'd rather bury your head in the sand that's your
prerogative.
"... Crude price manipulation is important to maintain the (fraudulent) petrodollar system because the sheeple subconsciously measure inflation through the price of gasoline. The Oligarchy that owns The Fed will not give up the petrodollar system because it is their main weapon for global domination and control. Unprofitable shale companies will continue to be lent money ;) ..."
"... That's not what the article is saying. If we stopped drilling and fracking today, in one month's time, the production would decline by 500k bbl/day. To offset that, 500k bbl/day production from new wells needs to be brought online in a month, which is what they're doing. The problem is, the more production, the more they have to drill just to keep production flat. ..."
"... it really was by the end of aug the production will drop by 1/2 mbpd making 10.5 mbpd unless somewhere else they made up for that loss, and thats prolly not counting your ability to bring that new production to mkt, via VW bus? ..."
"... Shale production is used primarily as a diluent, and as a petro chemical feed stock. The majority of it is used by Canada and Mexico. ..."
"... The Eagle Ford shale play here at home went bust two years ago. It has never recovered and does not look like it ever will. Most of my family have to drive to Odessa for oil work. Now the greed over there is raping the workers with exorbitant rental rates. Those poor slobs can't get a break. Well most working folks just can't get a break period. ..."
While the U.S. reached a new record of 11 million barrels of oil production per day last week,
the top five shale oil fields also suffered the highest monthly decline rate ever. This is bad
news for the U.S. shale industry as it must produce more and more oil each month, to keep oil
production from falling.
According to the newest EIA Drilling Productivity Report, the top five U.S. Shale Oil
fields monthly oil decline rate is set to surpass a half million barrels per day in August.
Thus, the companies will have to produce at last 500,000 barrels of new oil next month just to keep
production flat.
Here are the individual shale oil field charts from the EIA's July Drilling Productivity Report:
The figures that are shown above the UP arrow denote the forecasted new production added next
month while the figures above the DOWN arrow provide the monthly legacy decline rate. For example,
the chart on the bottom right-hand side is for the Permian Region. The EIA forecasts that the
Permian will add 296,000 barrels per day (bpd) of new shale oil production in August, while the
existing wells in the field will decline by 223,000 bpd.
If we add up these top five shale oil fields monthly decline rate for August will be 503,000
bpd. Thus, the shale oil companies must produce at least 503,000 bpd of new oil supply next month
just to keep production from falling. And, we must remember, this decline rate will continue to
increase as shale oil production rises.
We can see this in the following chart below. Again, according to the EIA's figures,
the top five U.S. shale oil fields monthly legacy decline rate increased from 398,000 bpd in
January to 503,000 bpd for August
:
In just the first seven months of 2018, the total monthly decline rate from these top shale
fields increased by 26%. These massive decline rates are the very reason the shale oil and gas
companies are struggling to make money. A perfect example of this is PXD, Pioneer Resources.
Pioneer is the largest shale oil producer in the Permian. According to Pioneer's Q1 2018 Report:
Producing 260 thousand barrels oil equivalent per day (MBOEPD) in the Permian Basin,
an increase of 9 MBOEPD, or 3%, compared to the fourth quarter of 2017;
first quarter
Permian Basin production was at the top end of Pioneer's production guidance range of 252 MBOEPD
to 260 MBOEPD; as previously announced, freezing temperatures in early January resulted in
production losses of approximately 6 MBOEPD; Permian Basin oil production increased to 170
thousand barrels of oil per day (MBOPD);
63 horizontal wells were placed on production
.
Pioneer spent $818 million on capital expenditures (CapEx) for additions to oil and gas
properties (drilling and completion costs) during Q1 2018, brought on 63 horizontal wells in the
Permian, and only added 9,000 barrels per day of oil equivalent over the previous quarter.
So, how much Free Cash Flow did Pioneer make with oil prices at the highest level in almost four
years?? Well, you're not going to believe me... so here is Pioneer's Cash Flow Statement below:
Pioneer reported $554 million in cash from operations and spent $818 million drilling and
completing oil wells in the Permian and a few other locations. Thus, Pioneer's Free Cash Flow was
a negative $264 million. However, Pioneer spent an additional $51 million for additions to other
assets and other property and equipment shown right below the RED highlighted line for a total of
$869 million in total CapEx spending. Total net free cash flow for Pioneer is -$315 million if we
include the additional $51 million.
Therefore, the largest shale oil producer in the Permian spent $264 million more than they made
from operations drilling 63 new wells in the Permian and only added a net 9,000 barrels per day of
oil equivalent. Now, how economical is that???
How long can this insanity go on??
If we look at the Free Cash Flow for some of the top shale energy companies in Q1 2018, here is
the result:
Of the ten shale companies in the chart above (in order: Continental, EOG, Whiting, Concho,
Marathon, Oasis, Occidental, Hess, Apache & Pioneer), only three enjoyed positive free cash flow,
while seven suffered negative free cash flow losses.
The net result of the group was a
negative $455 million in free cash flow.
Even with higher oil prices, the U.S. shale energy companies are still struggling to make money.
So, the question remains. What happens to these shale oil companies when the oil price falls
back towards $30 when the stock market drops by 50+% over the next few years?? And how is the U.S.
Shale Energy Industry going to pay back the $250+ billion in debt??
Lastly, here is my recent video on the Shale Oil Ponzi Scheme if you haven't seen it yet:
Crude price manipulation is important to maintain the (fraudulent)
petrodollar system because the sheeple subconsciously measure inflation
through the price of gasoline. The Oligarchy that owns The Fed will not
give up the petrodollar system because it is their main weapon for global
domination and control. Unprofitable shale companies will continue to be
lent
money
;)
Let's do the math: US produced 11 million bbls a day recently, but
production is declining at a rate of 1/2 million bbls/day according to
the article. So that means US oil production will be zero bbl/day in
about 3 weeks.
That's not what the article is saying. If we stopped drilling and
fracking today, in one month's time, the production would decline by
500k bbl/day. To offset that, 500k bbl/day production from new wells
needs to be brought online in a month, which is what they're doing.
The problem is, the more production, the more they have to drill just
to keep production flat.
This is a well know item, horizontal fracking produces very well
for a couple years and then not so much. Also known that the US uses
17 to 19 (depending on who is telling) million barrels per day so the
US still imports a lot of crude per day. We use it like there is no
tomorrow and one day there won't be but I'm 85 so the three words
to tranquility applies. "Not my problem".
it really was by the end of aug the production will drop by 1/2 mbpd
making 10.5 mbpd unless somewhere else they made up for that loss,
and thats prolly not counting your ability to bring that new
production to mkt, via VW bus?
the yearly chart is very telling. we stayed in a $20-$40 range from the
70's to mid 2000's then bush drove the price up but we fell exactly when
obama won the election BUT UNDER OBAMA WE SETTLED INTO A RANGE OF
$40-$100....fucking double the old range.
The US has 1.7 million operating shale wells. Over the next five years 1.4
million of those wells will have to be replaced to keep production
constant. The decline rate for the average shale well is 89% over its first
five years. At an average replacement cost of $4.4 million per well the
total cost of replacing 1.4 million wells will be $6.2 trillion. The total
cost of all the petroleum products consumed by the US over the next five
years will approximately $2.5 trillion.
To keep the shale industry alive over the next five years it will cost
the US economy 2.5 times as much as it will spend on all the petroleum
products it will consume. Expect a massive dislocation in the petroleum
industry in the very near future!
http://www.thehillsgroup.org/
First... I don't trust Continental
Resources figures, but I can't get into that yet... long story.
Second, EOG is spending twice as much as most shale players on
CapEx per quarter and are making some free cash flow. However,
EOG also paid $97 million in dividends Q1 2018. So, if we
subtract out their dividend payouts, EOG only netted $14 million
after spending $1.4 billion in Capex during Q1 2018.
Lastly, Whiting's oil production is still less than what it was
in 2016. By cutting CapEx spending drastically, from $600 million
a quarter two years ago to only $178 million in Q1 2018, they can
make some free cash flow. But, by drastically cutting CapEx
spending, Whiting won't be able to increase production to pay back
the $2.8 billion in long-term debt that they owe.
And this is the same pattern for our govts.... spend more and
get less..... the result is inevitable, same with our pumped up
markets.... not if, but when.... and it looks to be soon...
Now, Trump wants the EU to buy this gas? It's obviously a very
short term deal, or he hasn't looked at the numbers at all...
which makes him perfect for his role in the 'out with the OWO,
in with the NWO'.
Ponzi scheme is the correct word for this shale industry,
same with all of our industries ,as empires all operate this
way... pushing off paying the bills till tomorrow, always a new
tomorrow... kick that can down the road... the states do it,
the fed govt does it... all those not making money do it... and
these are the opposite of startups.
Buying time. Short and sweet. The mere fact that they are so
actively "buying time" with these short-term policies is
proof that they are aware time is running out, which leaves
one to ponder just exactly "how much" time are they trying
to buy, and toward what end. Big plans are in the works I
suspect, and the end of "buying time" is rapidly
approaching.
For as long as there are enough natural resources left in the
world to be able to strip-mine at about exponentially increasing
rates, as enabled by making "money" out of nothing as debts in order
to "pay" for doing so, which is a debt slavery system based on the
public powers of governments used to back up legalized counterfeiting
by private banks, and the big corporations that grew up around those
big banks. The oil extraction corporations operate inside of that
overall context where everything they are able to do is based on the
degree to which the sources of their funding ultimately depend upon
being able to continue enforcing frauds.
It is too good a phrase to use to refer to those aspects of that
process as being "Ponzi Schemes," since deceived people voluntarily
participated in Ponzi's Scheme. The dominant Pyramid Schemes of
Globalized Neolithic Civilization are systems that offered people a
deal they could not refuse.
The history of oil can not be separated from the history of war.
Within the overall context that money is measurement backed by
murder, the funding of the oil industry developed as vicious feedback
loops due to be able to
enforce frauds
, despite that
about exponentially advancing technologies were enabling about
exponentially increasing fraudulence, with respect to the related
about exponentially increasing strip-mining.
"How long can this insanity go on?"
Probably for a relatively long time for those who are old and
rich, and positioned near the center, toward the top, of the Pyramid
Scheme of enforced frauds which achieve
symbolic robberies
for those people.
Shale oil extraction exemplifies DIMINISHING RETURNS, which
applies across everything else that Civilization is doing.
"It's amazing the amount of money that needs to be invested
just to replace production."
It is more
"amazing"
when one goes through the labyrinth of Money
As Debt, which is the MADNESS of
negative capital
,
which is able to be publicly presented as if that is still positive
capital. While it is abstractly obvious that murder systems are
manifestations of general energy systems, there is relatively little
public appreciation of those murder systems backing up the money
systems.
Around about the 15 minute mark in the video embedded in the
article above, some of the reasons for calling shale oil extraction a
"Ponzi Scheme" are outlined, including "Ponzi Stock Finance," which
are secondary mechanisms where the MAD Money As Debt travels from its
original source
ex nihilo
through other
investors, before going into the shale oil industry. The underlying
issues related to DIMINISHING RETURNS will manifest first and
foremost through the fundamentally fraudulent financial accounting
systems which almost totally dominant Globalized Neolithic
Civilization.
"How long can this insanity go on?"
Until those runaway debt insanities provoke sufficient runaway
death insanities to cause series of crazy collapses which result in
whatever systems of organized crime could continue to operate after
the consequences of DIMINISHING RETURNS have worked their way
through. Since it is barely possible to exaggerate the degree to
which
negative extraction
was presented as
if that was positive production, it is also barely possible to
exaggerate the degree of psychotic breakdowns that will manifest when
runaway enforced frauds finally have their about exponentially
increasing fraudulence go past their tipping points.
The USA became the most important component in Globalized
Neolithic Civilization. The USA has led the way into the development
of globalized monkey money frauds, backed by the threat of force from
apes with atomic bombs, whose lives still mostly became dependent
upon the chemical energy in petroleum resources. The USA, therefore,
also led the way to the development of shale oil extraction, while
that continued to be publicly presented as if that was production.
At the present time, and for the foreseeable finite future, it is
politically impossible for human beings living inside of the dominant
Civilization to better understand themselves as manifestations of
general energy systems. Instead, almost everyone who is adapted to
living inside that Civilization has developed ways to present what
they are actually doing in the most dishonest and absurdly backward
ways possible.
Extracting more and more expensive petroleum resources is merely
one of the leading symbols of what is happening everywhere else one
looks. That Civilization is almost totally based on being able to
back up legalized lies with legalized violence continues to be
socially successful to the degree that most people do not understand
that, because they have been conditioned to not want to understand
that being able to back up lies with violence never stops those lies
from still being fundamentally
false.
THAT
was the source of the
"insanity."
It is too optimistic to expect that will
not continue, despite series of collapses into crazy chaos, and the
related series of psychotic breakdowns. Whatever civilization
survives will continue to operate according to the principles and
methods of organized crime, which will continue to have the related
corollaries that the apparent successfulness of those organized
crimes will depend upon most people not wanting to understand what is
actually happening.
Theoretically, enough people "should" better understand themselves
as manifestations of energy systems, which would then include their
perceptions of the ways that they lived as
nested toroidal
vortices engaged in entropic pumping of environmental energy sources.
That is made even more theoretically imperative to the degree that
some people have better understood some energy systems.
However, throughout everything that operates through Pyramid
Schemes, for those continue requires that the pyramidion people do
everything they can to make sure that those lower down in those
Pyramid Schemes do not understand that those Pyramids are actually
NESTED TOROIDAL VORTICES. At the present time, and in the foreseeable
finite future, the dominant Civilization will continue intensifying
its paradoxical Grand Canyon Contradictions that physical science
makes prodigious progress in understanding some energy systems, while
political science makes no similar progress in understanding human
energy systems, except to the degree that human systems are thereby
enabled to become about exponentially more dishonest.
Fracking symbolizes advancing physical technologies, channeled
through financial systems which only "advance" by becoming about
exponentially more fraudulent. Since almost everything Civilization
is doing has become based on that exponentially increasing
fraudulence, which in turn is based on exponentially increasing
strip-mining, it is politically impossible for that Civilization to
stop that
"insanity"
other than by driving
itself some series of psychotic breakdowns.
That
"lousy shale oil economics will pull down the U.S
economy"
is only one of the more and more painfully
obviously tips of the immense icebergs of enforced frauds, whose own
exponentially increasing fraudulences are melting themselves. (In
that context it is old-fashioned nonsense that possessing precious
metals is a somewhat saner "solution" to the runaway criminal
"insanity"
of Civilization.)
"At an average replacement cost of $4.4 million per well the total cost
of replacing 1.4 million wells will be $6.2 trillion. "
I think your
math is way off, To To date, Shale spent about $500B to $750B drilling &
operating those 1.7M wells. That said, Shale drillers borrowed about
$400B, Its unlikely they'll find more Suckers^H^H^H^H investors to
borrow another $400B. Plus they are running out of sweet spots to drill
in Bakken & Eagle Ford. I believe currently the only remaining sweet
spot they can develop is the Permian Basin. Plus the debt coupon on the
borrowed money start coming due between 2019-2023 (They need to roll
that debt over).
Frackers are really dumb. They can't refracture the wells. As soon as their
wells run dry, it's game over. Financial guys are really smart. They make
pronouncements from their desk. They are never wrong.
I'm going back under my bed and work on my Zombie apocalypse cookbook. On
sale soon.
"Frackers are really dumb. They can't refracture the wells."
They can
re-frack their wells, but the yield is abysmally low; so it is rarely
attempted. Re-fracking produces very little additional oil. Most of what is
produced from refracking is gas, which is a low revenue product. It is, by
far, more cost effective to just drill a new well.
By our calculations the US is selling the oil it produces at 46% below its
full life cycle cost of production. The shale industry is apparently using
a business plan that was developed by an Ivy League business school MBA.
They got their degree in Advance Ponzi Schemes.
http://www.thehillsgroup.org/
My family owned some mineral interest in Blaine County, Oklahoma. It's one of
the hottest shale plays out there right now. A well was drilled and it came in
just gang busters. Within 3 months, the production had fallen by 86%. The well
results out of the gate were so good that the well was mentioned in an investor
presentation for a major oil company. I doubt anyone went back to inform the
investors of the results 90 days later.
That's Shale. If you're lucky you get initial high rates BUT IT WILL drop
in production like hell with time. It's all in the geology. Just look at
the perms and you will understand.
Any idiot can sell goods at half the price it costs them to produce. That
is shale.
Peak oil theory was proved to be correct. It referred to conventional oil.
At the time sour oil wasn't even used, now a majority of the world's oil
is sour. No enhanced oil recovery techniques were available, now every barrel is
geeked out. Water flooding failing Ghawar super giant oilfield, shows the
desperation to keep up oil production.
As far as I know, every Giant in the world (the less than 1% of total
fields that produce 60% of world production) is using some form of
tertiary extraction method to keep producing. Tertiary extraction
methods retrieve anywhere from 2 to 20% of OOIP (original oil in place).
6 to 7% is probably the average. Ghawar is using CO2 injection, in
junction with horizontal wells to extract the last 30 feet of its
original 350 foot oil seam. In other words Ghawar is over 90% depleted.
That was the main reason that the Saudi's $2 trillion IPO for Aramco
fell apart.
With the huge amount of capital outflow now leaving the EM
it seems likely that world demand will begin to decline at about the
same time production begins to decline. The EM constitutes 38% of world
GDP, and 47% of world trade. They also use a greater amount of oil per
GDP $ produced than does the DE. As they continue to fail, as we have
seen recently from Turkey to Venezuela, their petroleum usage will fall.
As Shale has a very limited shelf life (now needing $6.2 trillion over
the next five years to keep production even) the US will find itself in
the situation of having to deal with whipsawing oil markets. Its
precarious debt situation means that it is going to be a rough ride down
from here.
As far as I know no one has called a peak in shale production. As long as
the FED is giving them a $65/ barrel subsidy with ZIRP it is hard to do.
What we can say is that they are planning on taking the $6.2 trillion they
will need for new wells over the next 5 years out of your hide. Invest in
Neosporin, there is gong to be some chapped asses coming down the pike.
I for one want to thank you SOO. Your analysis is also spot on, and
along with your real world experience it reminds me of that ole
detective show Dragnet, "Just the facts Ma'm, just the facts".
Now if
there was an answer that we could all live with....
About what I'd expect. We are 2 years out from the bottom. Exploration and
drilling came to halt. Now that's starting to show up in the declines. It will
start to pick up now with higher prices. Pendulum swings both ways.
"What happens to these shale oil companies when the oil price falls back towards
$30..."
This is the part I don't get, unless you are making two separate
arguments.
Oil is a strategic resource
and as so is an issue of
national security.
They will produce at a loss until they're all dry, if
they have to. The financing will not stop. Same reasoning: Since Musk is
advancing the whole globalist agenda, I hesitate to short the hell out of Tesla.
The financing may just not ever stop. Can the same be said of the broader market?
They've been wiping out EM debt with jubilees; is that how they plan on printing
forever and fueling GDP with debt?
I would protest. They will produce at a fiat loss until dry (assuming fiat
is still accepted of course). The will not produce at an energy loss
though, less than 3 to 4 EROEI.
A Shale well, with an IP (initial production) of 450 b/d, reaches its
energy breakeven point at about 70,000 barrels, or about 10 months. After
that point they must be energy subsidized to keep producing; they go from
being an energy source to become an energy sink. A conventional well
remains an energy source until the WOR (water oil ratio) reaches 45:1, or a
97.8% water cut. At which point they become uneconomical to operate and are
shut in. Shale wells are only operational past their energy source/sink
point because energy is being input from other sources. Much of that comes
from conventional crude - but - the ERoEI of conventional is also falling.
The average conventional well will reach its energy breakeven point by
2030. In thermodynamics that is referred to as the "dead state".
Shale production is used primarily as a diluent, and as a petro chemical
feed stock. The majority of it is used by Canada and Mexico. The Canadians
need it to produce their tar sands oil, and Mexico uses it for their Mayan
Heavy. Both are important raw material sources for US oil refineries.
Even
though Shale is net energy neutral, or negative, and will never be
economical to produce, if the US wants to keep its primary suppliers of
crude in business it has to supply them with diluent. The FED has already
been subsidizing Shale through its ZIRP policy.
Over its full production
life cycle that has contributed about $65 a barrel. In the event that the
FED can no longer keep interest rates suppressed subsidizes will have to
come from some other source. Those may come through the refineries, or like
farmers they may be paid by the bushel. In any event those costs are going
to become extremely burdensome as these high decline rate wells need to be
replaced frequently. Shale will remain a massive, and growing expensive
until the economy has chugged to a halt, and it is no longer needed.
I'm telling you they're lying thru their teeth about oil. We are sucking the
planet dry faster than you can say, "Dry as a popcorn fart."
The powers that
be dont want you to know this because they dont want you to slow down because
they need your tax money to hold up the sick wobbling over weight monster they
created.
It's common knowledge, at least to anyone glancing at the industry, that shale
oil has a two-year boom/bust cycle.
But that oil was not supposed to
exist. Nor any of the last half century's production.
A year ago, there were articles predicting the shale-induced peak would be
2019. (But shale gas was going to be increasing for another couple of
decades.)
You expect profit margins to fall as you squeeze the last of the juice.
Not really sure what the news is, or at least why it is so remarkable.
Calling it a Ponzi scheme, come now.
The Eagle Ford shale play here at home went bust two years ago.
It has never
recovered and does not look like it ever will. Most of my family have to drive
to Odessa for oil work. Now the greed over there is raping the workers with
exorbitant rental rates.
Those poor slobs can't get a break.
Well most working folks just can't get a break period.
Major oil producers agreed Friday to a nominal increase in crude production of about 1
million barrels per day, a bid to put a damper on high oil prices. But in practice, major oil
exporters will likely only be able to add about half that total to global markets, because many
countries are already producing at capacity or face severe threats of supply disruption.
Oil markets weren't calmed by the agreement announced Friday by the Organization of the
Petroleum Exporting Countries after a contentious week of meetings. Crude prices in New York
rose more than 3 percent to almost $68 a barrel and rose about 2 percent in London to more than
$74 a barrel.
OPEC didn't agree to increase production as such. Rather the group, with the addition of
nonmember Russia, agreed to respect its existing program of restricting supplies. But since the
group had gone well overboard and trimmed output by almost 2 million barrels a day, due in
large part to a steep falloff in Venezuelan oil production, respecting the original target will
translate into more oil for the global market -- on paper, at least.
In practice, only Saudi Arabia and Russia have the capacity to add significant amounts of
crude in the next few months. That means Friday's agreement will end up adding about 600,000
barrels of oil a day to the global market.
The contentious meeting took place under the shadow of vituperation from U.S. President
Donald Trump, who worried that high oil and gasoline prices would be politically painful ahead
of midterm elections later this year. Even after the group's decision had been announced, Trump
was still tweeting hopefully about OPEC increasing production.
"... "Conclusion. No matter what clever US energy independence calculations are out there, the fact remains that the US is physically dependent on around 8 mb/d of crude oil imports, 4.3 mb/d out of which come from countries where oil production has already peaked and/or where there are socio-economic or geopolitical problems. As of April 2018 US net crude imports were about 6 mb/d, far from oil independence." ..."
"... I note also that about 45% of USA imports come from Canada, as well depicted in in your Fig 1. Thus we are 'captives' of Canada (to use the terminology of trump), but don't seem to have much appreciation or respect for their position. ..."
US total (oil + products) inventories made a new low (from the high February 2017)
US ending stocks July 6th
Crude oil down -12.6 million barrels
Oil products down -0.7
Overall total, down -13.3 (shown on chart)
Natural Gas: Propane & NGPLs up +6.1 (not included in chart)
Chart: https://pbs.twimg.com/media/Dh1-upjXUBEOjvn.jpg
"Conclusion.
No matter what clever US energy independence calculations are out there, the fact remains
that the US is physically dependent on around 8 mb/d of crude oil imports, 4.3 mb/d out of
which come from countries where oil production has already peaked and/or where there are
socio-economic or geopolitical problems. As of April 2018 US net crude imports were about 6
mb/d, far from oil independence."
I note also that about 45% of USA imports come from Canada, as well depicted in in your
Fig 1. Thus we are 'captives' of Canada (to use the terminology of trump), but don't seem to
have much appreciation or respect for their position.
The completed around 95 according to my data. The is lag in the data on confidential wells
that will show up next month in the final data. Also if the Bakken was to get and hold 1.4
million barrels a day the would need to complete around 1500 wells per year.
I managed to erase my own comment on this. And my comment was simple, the only true
measurement of market balance for oil going forward is global inventory level. Everything
else is perhaps manipulation or guesses.
I agree, with all the intentional and unintentional confusion it stays confused. I stay
confused trying to figure out what is confused. Inventory levels will be the only clear
measure of what is happening. US inventories should not be dropping fast, as we are about the
only country with increased production, but we dropped over 30 million last month. That's
really not small potatoes, as commercial stocks are just a little over 400 million. Though, I
think the US will be one of the last that would hit the danger zone.
Good point. My intention was not to give more confusion. These are forecasts from eia and, I
always like to remind this, they forecasted Brent averaging 105$ for 2015 in the STEO of
October 2014. They never forecast big surplus or deficit.
I messed with the numbers of the STEO from 2018 to guess when the are reliable. Inventory
levels are accurate for the US from the monthly report, which is 3 months old (april for July
STEO). Other inventory levels are less accurate, but stock changes are reliable from 4-5
month data.
Global inventories increased in April (0.74 Mb/d) and May (1.14 Mb/d). This would be quite
a change, as April would be a record inventory build since January 2017, and it would be
followed by another record. This have to be confirmed later.
So, now I know what I will look for in these STEO.
How does this fit with production and consumption?
I thought we have still increasing consumption of about 1.5 mb/year, and production in
April/May didn't jumped thad much – Opec flat and Permian already near it's pipeline
bottleneck.
As much as I know, many storages are unknown, especially Opec / China. There are these
satellite measurements, but there are additional deep storages.
Gathering all comsumption / raffinery input / production data would give an additional
picture. Still not easy.
With 1mb/day surplus we should go soon into the next oil price crash to 30-40.
Even if we haven't hit peak yet, the fact that production is likely to be going up by a
snail's pace the next 3 years is a problem. If consumption just goes up 0.75% a year we need
600K extra a year. That seems like a big challenge to a layman like myself.
Well what will happen is that the price of oil will hit $150-$200 a barrel to ration demand.
Which will cause much pain and ruction and gnashing of teeth among the voters, but Europe
has had those oil equivalent prices owing to taxation for quite some time and they manage
high living standards. $200/bbl probably destroys 10 million a day in superfluous 'Becky
driving by herself to the mall in a 3 ton SUV for no reason' kind of demand and incentivizes
quite a bit of production.
The transition period will be moody for sure, but at $200/bbl, the amount of economic EOR
targets in the US is somewhere in excess of 70 BBO from old conventional fields from the
industry reports I have seen – its just not economic to do since there isn't enough CO2
available to flood them, so you need to use more expensive techniques which require very high
prices (ethane flooding might be useful????). Worldwide its hundreds of billions. High prices
that encourage us to use the resource wisely and not waste the goddamn stuff liberally would
be a godsend, if we could quit wasting gigatons of plastic bullshit and 40% of our food
– i.e. if everything made from oil was more expensive as well.
It would be painful economically, but Mad Max isn't coming our way. After 5 years of pain,
we might actually finally get our shit together and research some goddamn alternatives.
I believe sugar cane ethanol is very competitive at $120 per barrel. This allows converting
grass cattle grazing ground to cane. I believe soy and palm will also become very attractive
crops. And I suspect countries like Haiti and Nicaragua will continue having riots.
Yes, I believe you are right. The future energy picture is complex, but authors writing books
about this say sugar cane ethanol could have EROEI (energy return on energy invested) of up
to 4. Even based on mechanised agriculture. And the big advantage of this crop is that it is
not very nitrogen intensive, the biggest fertilizer, currently energy intensive when it comes
to natural gas usage. Even when it comes to preindustrial crop rotation, the nitrogen
intensive main food crops were often rotated with legume crops which were not nitrogen
intesive in the hope to rebuild nitrogen content in the earth. So very long term, sugar cane
ethanol is a superb type of renewable energy. (that is what I read, no expert).
Brazil has the biggest potential out there when it comes to size, and it is not
inconceivable that they can cover much of domestic fuel demand with this outside aviation and
possibly shipping (no need for diesel and gasoline ;-)). It would be in competition with food
crops and concerns about deforestation, but still; a big potential there. Brazil is well off
in a more renewable future btw, having loads of hydro power, wind power, in addition to
biomass power (sugar cane the most promising).
"[Exxon's] approach is a gamble in a new era of energy breakthroughs such
as fracking and electric vehicles. Many of Exxon's competi-tors are
transforming their businesses to move away from oil exploration, and
have begun to spend carefully and diversify into renewable
energy ."
"'Most investors like Exxon, but they like other companies better,'
said Mark Stoeckle, chief executive of Adams Funds, which owns about $100
million in Exxon shares. 'The market is not willing to reward Exxon for
spending today in hopes that it will bring good returns
tomorrow.'
"Exxon has been pledging to produce more oil and gas for years, but its
output of about four million barrels a day is no higher today than it was
after its merger with Mobil Corp. in 1999. Even if Exxon succeeds in
doubling last year's earnings of $15 billion (excluding
impairments and tax reform impacts) by 2025, as Mr. Woods vowed in his
eight-year spending plan, it would still be making far less than in 2008, when it
set what was then a record for annual profits by an American
corporation, at $45 billion .
"Exxon's fracking prospects in the Permian basin in West Texas and New
Mexico, developed by its XTO unit, remain among its most profitable
opportunities, the company says. Still, its U.S. drilling
business has lost money in 11 of the last 15 quarters."
Hi Steve, this is exactly what we have been talking about for the last 8 years. To make
matters worse there seems to be a completely irrational belief that Shale will save the day.
Outside of the fact that shale is not processable without heavier crude, and it is at best
energy neutral, and probably negative, it is also long term unaffordable. There are 1.7
million Shale wells in the US. Over the next 5 years 1.4 million of those wells will have to
be replaced to just keep production even. That will be $6.2 trillion even if done on the
cheap. $6.2 trillion is equal to the total cost of all the finished product that will be
consumed by the US for the next 12.8 years (@ $75/barrel). Expending 12.8 years of sales
revenue to produce 5 years of oil is just not going to happen!
There seems to be a black out on this terrible situation. Some of that may be just plain
ignorance, but I suspect that the main reason is that it is politically unspeakable. For that
reason nothing is being spoken. As I have been saying for some time no one should expect big
oil, big government, or big anything to come riding to the rescue. The individual is now
completely on their own. Chose your options with discretion.
Agreed. The U.S. Shale Oil Ponzi Scheme will likely begin to disintegrate within the next
1-3 years. Already, the Permian oil productivity per well has peaked.
Then when the next Shale Oil ENRON event takes place... watch as the dominos fall.
@SRSrocco, U.S. Tight Oil depends on cheap credit. Regardless of oil prices.
Once cheap credit dries up and the previous debts are unable to be paid by drilling new
wells, the entire scheme falls apart.
Oil prices do not drive U.S. Tight Oil as much as cheap credit from easy loans.
Eventually, U S. Tight Oil using new credit cards to pay debts on old credit cards will
catch up with a vengence. Rising interest rates will be the catalyst. Rising oil prices only
prolong the increasing debt.
Didn't the EIA publish something not long ago stating their concerns that we could see oil
shortages by 2020? And around the same time, I recall that the Saudi Oil Minister came out
and stated that without more investment, we would likely see oil shortages by 2020. And then
at the recent OPEC meeting, I believe it was the Oil Minister from UAE who stated that we
need to find a new North Seas equivalent oil field EVERY YEAR to meet projected demand, which
of course is not going to happen. It has been a long slow grind since 2008 to get to this
point, but from here on out I anticipate that things will start unraveling at an ever faster
pace. Big changes on the way. But one thing that will NEVER happen is that the POTUS or some
other world leader comes out and says we are running short on energy. Instead it will be
Trade Wars, the damned Russians or some other lame propaganda -- anything but the truth.
The mitigation section of the study was most telling. It simply stated that local
sustainable economies would replace the modern era. These economies included local food
production and energy production. As this process unfolds, I simply do not see how a high
rise is going to remain habitable.
Zero hedge put a news story a while ago where (I think 2016) the US oil industry lost more
in that it earned in the previous 7 years (mining in general), so more investment wouldn't
have been coming in the US anyway - the price wasn't high enough to justify it.
Worldwide we are going to see some almightly crunch, whether it will arrive after 2020
will be seen. Ironically it might save Trump anyway if the world is seen to be beset by a oil
supply crunch since its hard to blame that on him.
The U.S. needs to get off its dead ass and start developing better batteries, solar power,
and other alternative energy sources. This was talked about in 1973, during the Oil Embargo
days, and its just astonishing the U.S. has done little since to ween itself off of oil. And
now we now have a tariff against Chinese made solar panels. DUH!!! How dumb can you get?
Look at the energy density of those power sources. You'll never run an industrial
civilization off of them. Electric cars may be great for zipping a couple of people around
town from day to day, but you're never going to run the large mining and shipping equipment
needed for our society. If you want to do that, you're going to have to develop viable
breeder reactors and the technology to manufacture liquid fuels with that energy - and this
is doable.
Right. There is nothing.....NOTHING....that can replace oil and gas as it is used and
utilized by the modern industrial society. Nothing......
What needs to happen right now is a steady rise in prices that will condition our
population to start learning to do with less cheap, easy energy. We have got to curb usage to
give society a chance to begin to learn another way.
The major obstacle to doing this responsible, rational action? The egregious, criminal
banking system that has gotten the world awash in debt to feed their greed. Any cut back in
the use of energy will destroy the economy and their gravy train.
Those suckers from Sanford and Bernstein again try to push thier view that shale oil has
great potential instead of potential to bury even more money in the sand. production of shale oil includes production of a
parallel stream of junk bonds.
"... statements from the U.S. government about "zero tolerance" towards Iran could mean that those losses will end up being much higher. Just by shifting the supply outages from 0.5 to 1 mb/d would translate into an oil price increase of about $8 to $9 per barrel, according to Bank of America Merrill Lynch. ..."
"... "We estimate that every million b/d shift in [supply and demand] balances would push the oil price by $17/bbl on average. So based on those assumptions, we estimate zero Iran exports could push oil up by $50/bbl if Saudi caps out. We expect in this game of chicken, someone will blink before that happens." ..."
"Investors who had egged on management teams to reign in capex and return cash will lament
the underinvestment in the industry," the analysts
wrote . "Any shortfall in supply will result in a super-spike in prices, potentially much
larger than the $150 a barrel spike witnessed in 2008."
... ... ...
Of course, for many, this is a problem for another day. The oil market is
arguably facing a supply crisis right now. Until recently, the oil market assumed a loss of
about 0.5 mb/d from Iran because of U.S. sanctions. But statements from the U.S. government
about "zero tolerance" towards Iran could mean that those losses will end up being much higher.
Just by shifting the supply outages from 0.5 to 1 mb/d would translate into an oil price
increase of about $8 to $9 per barrel, according to Bank of America Merrill Lynch.
"We estimate that every million b/d shift in [supply and demand] balances would push the
oil price by $17/bbl on average. So based on those assumptions, we estimate zero Iran exports
could push oil up by $50/bbl if Saudi caps out. We expect in this game of chicken, someone will
blink before that happens."
In other words, if Saudi Arabia is unable to plug the deficit, the U.S. would likely have to
back down on its "zero tolerance" policy towards Iran. The oil market is too tight, and the
supply gap would be too large. Cutting Iran exports by that much, in an increasingly tight oil
market, would send prices skyrocketing, something that the Trump administration probably won't
be able to stomach. If Trump proceeded, a price spike of that magnitude would lead to a
meltdown in demand.
As the world continues to burn energy like there is no tomorrow, global oil and gas discoveries
fell to another low in 2017. And to make matters worse, world oil investment has dropped 45% from
its peak in 2014. If the world oil industry doesn't increase its capital expenditures
significantly, we are going to hit the Energy Cliff much sooner than later.
According to Rystad Energy, total global conventional oil and gas discoveries fell to a low of
6.7 billion barrels of oil equivalent (Boe). To arrive at a Boe, Rystad Energy converts natural
gas to a barrel of oil equivalent. In 2012, the world discovered 30 billion Boe of oil and gas
versus the 6.7 billion Boe last year:
"We haven't seen anything like this since the 1940s," says Sonia Mladá Passos, senior analyst
at Rystad Energy. "The discovered volumes averaged at ~550 MMboe per month.
The most
worrisome is the fact that the reserve replacement ratio in the current year reached only 11%
(for oil and gas combined) - compared to over 50% in 2012."
According to Rystad's
analysis, 2006 was the last year when reserve replacement ratio reached 100%.
The critical information in the quote above is that the world only replaced 11% of its oil and
gas consumption last year compared to 50% in 2012. However, the article goes on to say that the
last time global oil and gas discoveries were 100% of consumption was back in 2006. So, even at
high $100+ oil prices in 2013 and 2014, oil and gas discoveries were only 25% of global
consumption.
As I mentioned at the beginning of the article, global oil capital investment has fallen right
at the very time we need it the most. In the EIA's International Energy Outlook 2017, world oil
capital investment fell 45% to $316 billion in 2016 versus $578 billion in 2014:
In just ten years (2007-2016), the world oil industry spent $4.1 trillion to maintain and grow
production. However, as shown in the first chart, global conventional oil and gas discoveries fell
to a new low of 6.7 billion Boe in 2017. So, even though more money is being spent, the world
isn't finding much more new oil.
I believe we are going to start running into serious trouble, first in the U.S. Shale Energy
Industry, and then globally, within the next 1-3 years. The major global oil companies have been
forced to cut capital expenditures to remain profitable and to provide free cash flow.
Unfortunately, this will impact oil production in the coming years.
Thus, the world will be facing the Energy Cliff much sooner than later.
Yeah tHis article is ridiculous, resident ZH self-purported Mensa members
like Tmos' have proven beyond any doubt that 'abiotic oil' replenishes the
world's supply of easily accessed hydrocarbons every fifteen minutes or so,
regardless of increasing consumption rates; indeed regardless of any
veritable facts whatsoever.
Worked by whole life in the oil business. Depletion is real. Abiotic oil
replenishment is Magic unicorns dancing on rainbows. Oil won't run out
ever, but the energy required to extract the oil will make remaining oil
reserves uneconomic at some point.
Strange that the oil industry does not agree with you. And it's strange
that reserves all over the world are not stable but decreasing. Your
Mensa idol is full of shit.
A field is creamed by massive infill drilling with horizontal wells that skim the very top
of the reservoir. The decline rate is the[n] drastically reduced while the depletion rate is
drastically increased. Things will go just great until the water hits those horizontal wells
at the top of the reservoir. Then production will drop like a rock.
I assume this is the money quote. These methods comprise the "game changer" that scuttled
peak oil predictions circa 2005.
By demurring a prediction as to when the stone might–will!–drop, you're
acknowledging the deplorable state of the data. This should give us pause. We might call this
the New Peak Oil Reticence.
Let's grant that what you say is true (I'm certainly not qualified to refute it). If you
know it (that is, that the rock will drop), then "they" know it, and by "they" I mean those
who are in the business of developing these "creaming" methods. They must know it.
No one producing country is looking at the global problem. They are only concerned with their
own country and the problems at home. Most are old men who realize that they will be long
dead if there is ever a catastrophe. And most, like the contributors to this blog, believe
that there will never be a catastrophe. They believe that renewables, or fusion energy, or
God, human ingenuity, or something else will save us from any type of collapse.
But the point is, the oil barons of each individual country, are not even remotely
concerned with the collapse of civilization as we know it. They believe God, or Allah, or
human ingenuity, will simply not allow that to happen.
"And most, like the contributors to this blog, believe that there will never be a
catastrophe. They believe that renewables, or fusion energy, or God, human ingenuity, or
something else will save us from any type of collapse."
But doesn't that require, like, planning? Plenty of planning?
I think Dr. Minqi Li put together an exceptionally well researched paper. The only one I have
a faintest glimmer of knowledge in is oil. 2021. Give or take a couple of years is a good
estimate of when peak oil occurs, based on current findings and technology. Improvements in
either would probably only affect the tail of the decline rate. Which, based on the immense
overstatement of EIA, and the creaming you mentioned, the tail should have much more of a
decline than depicted. I am tending towards 2022 to 2023 as the final peak, due to the little
over a year hiatus on the Permian final push due to pipeline and other constraints. We all
know 2042 is a bad projection for the US, it will get there as soon as it can. It will get
there as soon as it can, because the oil price will be high enough to beg, borrow, or steal
to get there. For that reason, all other sources will be staining to get there at the same
time. We are in the final stage, I do think.
Yes, I agree with you on Dr. Minqi Li's paper. I am not sure, however, that the Permian will
show enough yearly increase to hold off the peak until 2023.
The implied increase in the Permian would be staggering. US onshore outside of fracking is in
terminal decline. US GOM is peak/decline. Eagle Ford is peak/decline. Bakken is close to
peak. Eagle Ford and Bakken have very high existing production decline rates, meaning they
will fall like a brick if drilling moves to the Permian.
There isn't anything new beyond the Permian. People have looked. No more plays.
And after covering all of that and its own existing production decline (not as extreme as
the other plays but large in absolute number), the Permian is supposed to add millions of
barrels per day?
I don't think that adds up no matter what the price of oil is.
"... I believe due to OPEC massively inflating their URR, and the inaccuracy of the Hubbert method due to the creaming of all giant fields, the expected peak dates here are highly inaccurate. ..."
In the table below I have converted the data Dr. Minqi Li presented in metric tons per year
to million barrels per day. Again, this is C+C plus natural gas liquids.
2017
At Peak
Year Peak
BPD Increase
us
11.47
15.08
2042
3.61
Saudi
11.29
12.17
2030
0.88
Russia
11.13
12.01
2033
0.88
Canada
4.74
7.85
2049
3.11
Iran
4.70
5.40
2039
0.70
Iraq
4.44
6.51
2042
2.07
China
3.S6
4.32
2015
UAE
3.53
4.38
2037
0.84
Kuwait
2.93
3.35
2040
0.42
Brazil
2.87
3.03
2025
0.16
Rest of W
27.13
33.22
2004
Total World
88.10
90.95
2021
2.85
The source for this chart is the same as the table above. I believe due to OPEC
massively inflating their URR, and the inaccuracy of the Hubbert method due to the creaming of
all giant fields, the expected peak dates here are highly inaccurate.
Well, all except three. The rest of the world did peak in 2004, China did peak in 2015, and
the world will peak by 2021 or before. Congratulations to Dr. Minqi Li, the most accurate
future peak there is the one that he calculated. Guym x Ignored says:
07/04/2018 at 8:10
am
I think Dr. Minqi Li put together an exceptionally well researched paper. The only one I have
a faintest glimmer of knowledge in is oil. 2021. Give or take a couple of years is a good
estimate of when peak oil occurs, based on current findings and technology. Improvements in
either would probably only affect the tail of the decline rate. Which, based on the immense
overstatement of EIA, and the creaming you mentioned, the tail should have much more of a
decline than depicted. I am tending towards 2022 to 2023 as the final peak, due to the little
over a year hiatus on the Permian final push due to pipeline and other constraints. We all
know 2042 is a bad projection for the US, it will get there as soon as it can. It will get
there as soon as it can, because the oil price will be high enough to beg, borrow, or steal
to get there. For that reason, all other sources will be staining to get there at the same
time. We are in the final stage, I do think.
Ron, many thanks for your very informative post about world oil (as always) and your
comments on my post.
However, like much of the peak oil community, having missed some of the previous peak
oil predictions, now I may err on the conservative side. Many have criticized the EIA
projections and OPEC reserves. But again, even with those projections/reserves, the world
oil production is still projected to peak in 2021. This suggests that world oil production
may indeed peak in the near future. As I promised, I will follow up with part 2 on
this.
Regarding China, China's oil consumption growth has re-accelerated as its oil production
is in decline. This development may have some major impact on global economy/geopolitics in
the coming years. On top of that, China is (or will soon become) the world's largest
natural gas importer.
World cumulative oil production up to 2017 was 192 billion metric tons. The world's
remaining recoverable oil resources are estimated to be 276 billion metric tons and ultimately
recoverable oil resources are estimated to be 468 billion metric tons. By comparison, the BP
Statistical Review of World Energy reports that the world oil reserves at the end of 2017 were
239 billion metric tons.
World oil production is projected to peak at 4,529 million metric tons in 2021.
2017 Production and Peak Production are in million metric tons; Cumulative Production, RRR
(remaining recoverable resources or reserves), and URR (ultimately recoverable resources) are
in billion metric tons. For Peak Production and Peak Year, regular characters indicate
historical peak production and year and italicized blue characters indicate theoretical peak
production and year projected by statistical models. Cumulative production up to 2007 is from
BGR (2009, Table A 3-2), extended to 2017 using annual production data from BP (2018).
Fun to look at this analysis, and plug in a one million shortage from North America.
Obviously, there would not be a one million drop in Iran, as it would be sold somewhere.
We might be seeing similar articles about gas over the next couple of years. Driving a bit
less is maybe a good thing, pensioners and children freezing to death and industry shut down
with rolling blackouts is maybe less negotiable.
Suppose there is too little oil and the price doesn't change. Producing countries will be
sure their own countries have a sufficient amount so regardless of price, that oil isn't
leaving the country. It stays right there for consumption. External price is meaningless to
that country, as it should be.
There are countries that produce about what they consume. Mexico is one. Argentina. Their
oil isn't going anywhere. A higher price elsewhere tries to get it exported? Clearly the govt
will stop anything like that. Just as the US did with its export ban in the 70s. Price
doesn't matter if bans are in place.
Oh, and another annoying thing in that article. Something like . . . if supply shrinks,
only "demand destruction" can avoid some sort of catastrophe. This is absurd. Demand is not
destroyed. The desire for oil will grow with population. The population demands oil. It is
consumption that is destroyed by lack of supply. Can't consume what doesn't exist.
Besides which, if some level of "grim" is approached, then some decision is going to be
made to liberate that Orinoco heavy from the horrible popularly elected government that
controls it. As I noted before, there is a large ethnic Russian population in Venezuela. The
1917 revolution sent many people there, fleeing confiscation. Liberation may not go
smoothly.
Mexico doesn't use what it produces, it doesn't have the refining capacity – it exports
crude and imports products.
Invading Venezuela wouldn't necessarily stop the decline in production – their
equipment and wells are falling apart, to get back to where they were a couple of years ago
would require a five year occupation, probably with forced labour (or really high wages), and
the investment money all coming from the invading country, with no net returns for longer
than that.
Demand is usually defined with some relation to price, not assuming a commodity is free.
"... tier plays that have been a bust. With the seismic and visualisation technology improvements the E&Ps should know better where and where not to drill. They seem to be more selective with falling wildcat numbers (and that is not much of a function of price that I can see as it has been happening since 2010) and yet the commercial discovery rates are staying fairly low. I can only interpret that as indicating that there just isn't that much left. With Rystad indicating 6 to 8% decline rates in mature fields, and rising, and few new prospects how can there not be a peak? ..."
"... Saudi ministers spout out any thing that comes to mind to support flip-flop policies and their feud with Iran seems to be bubbling in the background of a lot that's going on; every year Iran and/or Iraq say they have a new plan and target for higher production, which is 100% guaranteed not to be met even remotely. ..."
I think if the world economy starts to drop, which is overdue and looking increasingly likely
every time Trump opens his mouth, and keeps the oil price down then it's likely we'll be in a
slow but accelerating decline. That might be a good thing – the further the peak is
pushed out the steeper the decline when it comes.
What has surprised my most recently has been the fall in discoveries for oil and, maybe
more so, gas, and with that the number of new fron tier plays that have been a bust. With
the seismic and visualisation technology improvements the E&Ps should know better where
and where not to drill. They seem to be more selective with falling wildcat numbers (and that
is not much of a function of price that I can see as it has been happening since 2010) and
yet the commercial discovery rates are staying fairly low. I can only interpret that as
indicating that there just isn't that much left. With Rystad indicating 6 to 8% decline rates
in mature fields, and rising, and few new prospects how can there not be a peak?
The oil drop might have been more expected than the gas, and was predicted by some when
peak oil was first mentioned, I think gas less so, but perhaps the price has had a bigger
effect there. Whatever the cause many countries have been banking on ever rising supplies,
either by pipeline or LNG, that might not be forthcoming.
Having said that simple economic arguments rarely seem to work as predicted, oil supplies
would have peaked well before now without, mostly non-proftable, LTO; Venezuela production
should be rising not a basket case; Saudi ministers spout out any thing that comes to
mind to support flip-flop policies and their feud with Iran seems to be bubbling in the
background of a lot that's going on; every year Iran and/or Iraq say they have a new plan and
target for higher production, which is 100% guaranteed not to be met even remotely.
At the moment the traders don't seem certain which way to turn – falling/rising
supplies, short/long term demand rise/fall – you can see why they tend to fixate on US
crude stocks, everything else is too complicated. The next few Wednesday/Thursday trading
patterns will be interesting.
(ps if anything highlights the state of the oil industry at the moment it's that Fram, a
two well, eight year life-cycle, gas condensate tie-back with about 10 mmboe reserves, has
been the main headline news on at least four of the trade magazines this week.)
A little short by over 2 million a day. Perry has to know the Permian is on a hiatus for
at least a year. That's probably over a million. Iran push is for another million. Yeah,
that's a little short. Idiocy reigns. Russia just called for tariffs against the US. Any
assistance from Russia ain't gonna happen.
The slow motion train wreck in progress. No one knows why the driver of the Lower for
Longer Train has picked up speed down the curving stretch .
Ok, I'll forgo the train wreck series. Yeah, it's serious. So was the ridiculous pricing
we've had for the past four years, and no one but the people who relied on oil income
complained. There was not enough for capex to get new oil. The trainweck happened already.
U.S. oil production is booming at record levels, and U.S. oil exports have also reached
new highs -- 3 million barrels a day in the last week, according to government data.
Those exports are more than most OPEC countries can produce each day and only lag two OPEC
countries, Saudi Arabia and Iraq, in terms of exports.
And if you read far enough down in that article they do mention imports, as if they hardly
matter.
As U.S. production has grown, U.S. imports have decreased. The U.S. imported a
relatively high 8.4 million barrels per day last week.
Okay, the US exported 3 million barrels per day and imported 8.4 million barrels per day.
Yet the headline says the US exported more oil than most OPEC countries. Is this Orwellian
Newspeak?
We all agree that 2+ 2 = 5, but what we don't know is which one belongs to the thought
police. I agree the Permian will produce 1.3 million this year, just take the rat cage off my
head.
"the US exported 3 million barrels per day and imported 8.4 million barrels per day. Yet the
headline says the US exported more oil than most OPEC countries. Is this Orwellian Newspeak?"
At the just concluded OPEC meeting, Iran, Iraq and Venezuela were against any increase in
extraction, while the Saudis wanted an increase. What resulted is
detailed in this article . Moneygraph:
"... OPEC does not need to change its output deal since the group had already cut supply
by much more than it had agreed. What Zanganeh offered was for OPEC and Russia to pump back
up to decrease the current cuts to the initial 1.176 million barrels per day (bpd).
"Output in May 2018 was actually down by 1.9 million, somehow 62 percent or 724,000 bpd
more than what was agreed upon in 2016."
The upshot is an increase will occur but no increase will occur--understand? The
extraction amount agreed to in 2016 remains the amount OPEC will extract. There will be
no increase in that amount this year.
"... Houston, 11 June (Argus) Plains All American Pipeline, a prime mover of crude around and away from the Permian, reiterated last week that there is not enough trucking capacity to address skyrocketing production, and potential rail slots are limited. With most material pipeline capacity additions a year or more away, Plains said the logical solution is slowing output ..."
"... That's really kind of funny. The takeaway professionals have to tell them, "come on guys, put a brake on it. It can't be moved." Note, the article stated that the pipeline company said production is already slowing. Wonder if EIA will finally read the memo? Also, it may result in more little fish, being eaten by the bigger fish. ..."
"... The next 3 or 4 months for EF and Bakken might be interesting – they've both been steady or slightly declining with no pick up in drilling or, I think, permitting even as the price has risen, and the initial well production and ultimate recovery look to be declining on recent wells. If Permian is closed off I wonder if the operators will bother to move back to these. ..."
"... Yeah, I think they will. You just won't see growth just overnight from these areas, and the ones who had good areas in these, never left. EOG, Conoco and others are still doing their thing. Growth will mainly show up the first and second quarter of 2019. Maybe some the last quarter of 2018. My guess. It just won't ramp up like the Permian, EIA predicts a bunch, but they are smoking some strong stuff. They believe in teleportation of oil to the coast, and further teleportation to VLCCs off the coast. ..."
"... Wild guess on the 22nd. OPEC releases non-opec from the agreement. Increasing OPEC, at this point, will involve disintegration of OPEC, which it really is, anyway. But, a modest increase may hold them together for a little while. Although, for the Sauds part, I don't know why they would, except to keep up the illusion. ..."
That's really kind of funny. The takeaway professionals have to tell them, "come on guys,
put a brake on it. It can't be moved." Note, the article stated that the pipeline company
said production is already slowing. Wonder if EIA will finally read the memo? Also, it may
result in more little fish, being eaten by the bigger fish.
Energy News, you constantly amaze me with your finds of information. Everything is
extremely pertinent.
The next 3 or 4 months for EF and Bakken might be interesting – they've both been
steady or slightly declining with no pick up in drilling or, I think, permitting even as the
price has risen, and the initial well production and ultimate recovery look to be declining
on recent wells. If Permian is closed off I wonder if the operators will bother to move back
to these.
State of North Dakota came out with a new presentation a few weeks ago showing revised
predictions for Bakken oil output. They now have production likely reaching 1,900,000 BOPD
within the next decade while the best forecast offers better than 2,200,000 BOPD.
Yeah, I think they will. You just won't see growth just overnight from these areas, and
the ones who had good areas in these, never left. EOG, Conoco and others are still doing
their thing. Growth will mainly show up the first and second quarter of 2019. Maybe some the
last quarter of 2018. My guess. It just won't ramp up like the Permian, EIA predicts a bunch,
but they are smoking some strong stuff. They believe in teleportation of oil to the coast,
and further teleportation to VLCCs off the coast.
That not everyone believes the EIA is evident in the huge, many billions of dollars,
losses in stock value of the "Permian pure play" companies recently. EIAs and IEAs fairy
tales are coming unraveled. About the only section of the investment community that still
believes them, is that percentage of adults that still believe chocolate milk comes from
brown cows. What they are still unsure of, is how much excess capacity OPEC now has.
Wild guess on the 22nd. OPEC releases non-opec from the agreement. Increasing OPEC, at
this point, will involve disintegration of OPEC, which it really is, anyway. But, a modest
increase may hold them together for a little while. Although, for the Sauds part, I don't
know why they would, except to keep up the illusion.
There is a narrative that oil demand will soon begin dropping due to widespread use of EV.
1 million EV just replaces 14,000 BOPD of demand. Conservatively assuming those one
million EV require $40K per unit of CAPEX, just to replace 14,000 BOPD of demand took $40
billion of CAPEX.
Likewise, to replace 1.4 million BOPD of demand via EV would take $4 trillion of
CAPEX.
Worldwide demand has been growing somewhere between 1.2-2.0 million BOPD annually,
depending on who one believes.
See where I am going with this? How do the EV disruption proponents explain away the
massive CAPEX required just to cause oil demand to flatten, let alone render it near
obsolete?
The average US car gets 25 mpg and travels 12,500 miles per year for 500 gallons of gasoline
per year.
Refineries in the US produce 20 gallons of gasoline per barrel of oil.
That gives 69,000 BOPD per day reduction per million EV cars in the US and 110,000 BOPD oil
equivalent energy due to the multiple energies put into gasoline and distillate
production.
At current rates of EV sales growth the US will reach 50 million EV cars by 2031. That should
put he US to being mostly independent of external oil for gasoline by mid 2030's and
It's tough to predict a complete transition in the US since cars as a service could greatly
reduce the numbers of cars needed, especially in dense population areas. That would mean a
much earlier transition.
If US ICE cars trend upward in mpg during that time, the demand for oil could be quite low
by the early 2030's.
All depends on continuation of trends, for which the auto manufacturers seem to be on board.
Just have to get the public charging infrastructure out ahead of the trend.
Here is an interesting article, from a couple of years ago, showing the trend and sales at
that time.
Cars get replaced all the time and the cost of new EVs will fall over time to the same
price as ICEV, so it's simply a matter of replacing the ICEV currently sold with EVs over
time, in addition cars can get better gas mileage (50 MPG in a Prius vs 35 MPG in a Toyota
Corolla or 25 MPG in a Camry.) There's also plug in hybrids like the Honda Clarity (47 miles
batttery range) or Prius Prime(25 mile range on battery) these have an ICE for when the
battery is used up.
If oil prices rise in the short term to over $100/b (probably around 2022 to 2030), there
will be demand for other types of transport besides a pure ICEV.
EVs and plugin hybrids will become cheaper as manufacturing is scaled up due to economies
of scale.
Surprising stuff. Huge oil consumption growth rates in Eastern Europe. 8+% growth %s in
Poland, Czech Republic and Slovakia. Something weird going on because Romania and Slovenia
didn't show the same thing.
Western Africa grew consumption of oil 13% last year. I'll add a !!!!. East Africa about 6%.
Both are over 600K bpd, so that growth rate is not on tiny burn.
Poland's official oil consumption growth is caused by better fighting with illegal, and
unregistered fuel imports since mid 2016. When taxes are 50% of fuel price, there is big
incentive for illegal activities. Real oil consumption probably didn't increase much.
Poland, Czech and Slovakia are going through a huge economic boom now (I live in Slovakia and
party in Czech Republic). It's visible everywhere, there wasn't this much spending and
employment ever in the last 28 years
Oil demand is mostly determined by GDP growth, oil price has a minor influence on short term
demand. World GDP grew by about 5% from 2016 to 2017 according to the IMF, so oil demand
increased by 1.8% possibly less than one would expect. Real GDP (at market exchange rates)
grew by about 3% in 2017.
The idea behind peak demand is simply that oil supply may at some point become relatively
abundant relative to demand in the future (date unknown). When and if that occurs, OPEC may
become worried that their oil resources will never be used and will begin to fight for market
share by increasing production and driving down the price of oil to try to spur demand. That
is the theory, I think we are probably 20 to 40 years from reaching that point for
conventional oil.
Oil still contributes quite a bit to carbon emissions and while I agree coal use needs to
be reduced (as carbon emissions per unit of exergy is higher for coal than oil), I would
think it may be possible to work on reducing both coal and oil use at the same time. Using
electric rail combined with electric trucks, cars and busses could reduce quite a bit of
carbon emissions from land transport, ships and air transport may be more difficult.
It's better to sell half of your ressources for 90$ / barrel than all at 30$ / barrel.
The gulf states will always have cheap production costs at their side, they will earn more
at each price of oil. Why not make big money, especially when at lower production speed the
production costs are much lower (less expensive infrastructure).
And in the first case you can sell chemical feedstock for a few 100 years ongoing for a
good coin. Theocracies and Kingdoms plan sometimes for a long time. When you bail out
everything at sale prices, you end with nothing ( and even no profit).
You assume half the resource can be sold at $90/b, at some point in the future oil supply
may be greater than demand at a price of $90/b, so at $90/b no oil is sold and revenue is
zero.
In a situation of over supply there will be competition for customers and the supply will
fall to the point where supply and demand are matched. Under those conditions OPEC may decide
to drive higher cost producers out of business and take market share, oil price will fall to
the cost of the most expensive (marginal) barrel that satisfies World demand.
I don't think we are close to reaching this point, but perhaps by 2035 or 2040 alternative
transport may have ramped to the point where World demand for oil falls below World Supply of
oil at $90/b and the oil price will gradually drop to a level where supply and demand
match.
Older wells are declining at about 8% per year. A 25 BOPD well with a 10 BOPD economic limit
should have 70,000 barrels of oil left to produce in about 12 years.
Is it safe to assume that newer wells will behave the same as older wells?
Some petroleum engineers that have commented at shaleprofile.com (Enno Peters wonderful
resource) that the high level of extraction from newer wells will likely lead to a thinner
tail.
illustrates this, notice how the 2014 and 2015 wells fall below the 2010 well profile
after 24 months, the same is likely to occur for 2016 and later wells. Also note that the
2010 well profile is representative (close to the mean) for 2009 to 2012 average well
profiles.
Dennis, i would say the decline rate (8%) is very safe to use for all LTO wells, i would
definitely apply it after the 6th year of well life, because by then what counts is rock
quality and fluid type. This is only good for a bulk projection.
By the way I tweaked my price model when I was preparing my CO2 pathway. I took into
account the Venezuela crash, the difficulties the Canadians have moving their crude, etc. The
price projection is $88 per barrel Brent for evaluating projects which start spending in
2019. I also prepared a different look for very long term projects which start spending in
2023: $110 per barrel.
Don't forget these aren't prices predicted for those particular years. They are prices one
can use to evaluate long term projects such as exploring in the Kara Sea, offshore West
Africa deep water, the African rifts, Venezuela heavy oil developments, etc. These prices are
plugged in and escalated with inflation for the 20-30 year project period. Real prices should
oscillate back and forth around these values.
Norwegian crude oil & condensate production (without NGLs) at 1,321
kb/day in May, down -223 m/m, down -297 from 2017 average or -18%. The main reasons that
production in May was below forecast is maintenance work and technical problems on some
fields. http://www.npd.no/en/news/Production-figures/2018/May-2018/ Almost down to the Sept 2012 low at 1,310 kb/day
This is what happens when there are no sizeable new fields coming online for 1/2 year and as
G.Kaplan has mentioned not enough allocation for supply disruptions are included in the
forecast.
A brutal decline, even if this month is an anomaly as NPD say.
Looking at the field numbers (only through April) it looks like Troll Oil is in decline a bit
earlier and a bit steeper than expected. It's the biggest oil producer still bu has dropped
fairly consistently and slightly accelerating from 161 kbpd in October to 121 in April. It's
all horizontal wells and requires continuous drilling to maintain production, it's close to
exhaustion with only 10% remaining at the end of 2017 (about R/P of 3 years) and had been
holding a good plateau around 150 for a few years. The gas is due to be developed starting in
2021 so the oil rim would need to be depleted by then, but maybe dropping a bit sooner than
expected – is a reservoir not behaving as modelled a "technical problem"?
I don't know about the price as it depends on the demand side and the global economy looks to
me increasingly rocky, but the supply side analysis looks pretty good, except as you say a
bit conservative. One thing missing was consideration of increasing decline rates on mature
fields, especially offshore, partly a result of accelerating production in the high price
years and partly because of an increasing ratio for deep and ultra deep water. Additionally I
think the lack of increase in non-US drilling rigs as the price has risen is relevant and
partly represents a shortage of in-fill prospects and short cycle appraisals.
If they are relying on GoM to add the 300 kbpb (or more into 2020) that EIA are predicting
then I think they are going to be short by 400 to 500 kbpd for a 2020 exit rate.
(I don't follow the chart showing new OPEC developments, the numbers can't be number of
projects, probably kbpd added, or maybe mmbbls reserves, and I'm betting they've mixed in gas
with the oil.)
As in all these investment type analyses they don't look too far ahead and there's a kind
of tacit assumption that everything will be sorted out with more investment later on, but
five years of low discoveries and accelerated development of the good ones means there's
actually not that much new to invest in, and if there is then ExxonMobil will be looking to
buy it.
Yeah, demand is always a big question. Hard to measure, even in the rear view mirror.
However, their constant increase of 1.2 million barrels in the US over a three year period,
should offset any question of demand. While 1.2 in 2020 is something I can't predict, 1.2
million for 2018 and 2019 is impossible without increased pipelines long before the second
half of 2019. So, I think it is way conservative.
They say "We believe we are 6-9 months ahead of consensus with our oil forecast. Why is no
one else seeing what we see?." Obviously they haven't been reading POB for the last two
years.
POB made it possible to piece together in my own way, otherwise I would be like most. Staying
confused with constant conflicting info. Predicting price is virtually impossible, as is
demand to a large extent. But, when supply is ready to fall off a cliff, then being exact is
not required.
A simple way to think about C+C demand is to assume over the long run that supply and
demand will be roughly equal (though of course there will be short term imbalances which
changes in the oil price over the short term will try to correct). From 1982 to 2017 C+C
output grew at an average annual rate of about 800 kb/d. It is probably safe to assume that
oil demand will continue to grow at roughly that pace in the absence of a severe global
recession and those are pretty rare. I define a "severe global recession" as one where real
World GDP (constant prices) based on market exchange rates decreases over an annual cycle for
one or more years. Since 1900 there have been two cases where this occurred, the Great
Depression and the Global Financial Crisis (GFC) in 2008/2009. These have been on roughly a
60 to 70 year cycle (a previous crisis occurred in 1870, but this might have only been a US
crisis and possibly not a global one.)
In any case, my guess is that a Global economic crisis may result a the World tries to
adjust to declining (or stagnant) World Oil output after 2025, probably hitting around 2030
to 2035. If economists re-read Keynes General Theory and respond to the crisis with
appropriate policy recommendations, the economic crisis may be short lived. On the other hand
a World response similar to the European response to the GFC, where fiscal austerity is
considered the appropriate response to a lack of aggregate demand (this was also Herbert
Hoover's response to the 1929 Stock Crash), then a prolonged deep depression will be the
result.
The somewhat vast majority of countries say their reserves are flat in 2017 vs 2016. They
pumped billions of barrels, but no change to reserves for . . . lemme count . . . 36
countries (of which the US was one).
World as a whole reserves total declined 0.03%.
BP's flow report is "all liquids". Dunno if that is consumption, too. And if reserves . .
. reserves are in a footnote. Crude, Condensate AND NGLs. Probably excludes algae.
What? Me worry? Rystadt says US has 79 more years of oil still available. Of course, that
is the imaginary oil. They admit that commercially recoverable oil in the world only has 13
years left. Where did we pick up another 50 billion of imaginary oil in the US this year?
India's oil consumption growth was only 2.9%. Derives from their monetary debacle early in
the year. We should see signs of whether or not that corrects back to their much higher norm
before next year.
China consumption growth 4%. Higher than India. Clearly an aberration.
KSA consumption actually declined fractionally, which allows Japan to still be ahead of them
in consumption.
US consumption growth 1%. So much for EV silliness.
Oil production seems to have left its bumpy 6 year long (2010-2015) plateau of 8.4 mb/d and
is now back to 2004 levels of 7.9 mb/d, a decline of 6% over 2 years.
Base production is the sum of the minimum production levels in each country during the
period under consideration. Incremental production is the production above that base
production. In this way we clearly see that the peak was shaped by China, sitting on a
declining wedge of all other Asian countries together. Note that growing production in Thailand
and India could not stop that decline. Now let's look at the other side of the coin,
consumption:
There has been a relentless increase in consumption since the mid 80s. The growth rate after
the financial crisis in 2008 was an average of 3% pa.
Chinese annual oil consumption growth
rates have been quite variable between 2% and a whopping 16% in 2004 which contributed to high
oil prices. Fig 4 also shows there is little correlation between GDP growth and oil consumption
growth (statistical problems?). There is nothing in this graph that could tell us that the
Chinese economy has a consistent trend to become less dependent on oil. In the years since
2011, oil consumption growth was around 60% of GDP growth.
Let's compare China with the US. China's oil consumption is catching up fast with US
consumption.
On current trends, China's oil consumption would reach US consumption levels of 20 mb/d in
just 14 years.
Contrary to misinformation by the media, the US is still a net importer of oil. Even blind
Freddy can see that there will be intense competition for oil on global markets.
All governments who plan for perpetual growth in Asia (new freeways, road tunnels, airports
etc) should fill in the above graph. Hint: We can see that Asia has diversified its sources of
oil imports but is still utterly dependent on Middle East oil
"Other Middle East" is Iran
and Oman (as Syria and Yemen no longer export oil)
China is preparing for the future by building bases to secure oil supply routes:
Proven reserves have not changed much in the last years meaning that P2 and P3 reserves have
been proved up commensurate with production. The reserve to production ratio is 16.7 years
equivalent to an annual depletion rate of 6%, a little bit higher than a reasonable rate of 5%
(R/P of 20 years).
The depletion rates vary considerably and may only be approximate as oil
reserves will have been estimated by using differing methodology and accuracy. Indonesia's
depletion rate is very high. Not shown in Fig 14 is Thailand where the depletion rate is off
the charts (almost 50%) suggesting reserves are too low.
There are some rumors that KSA has increased exports starting in May (about 0.5 m b/d more
than prior months) by drawing even more from storage. If we are to believe OPEC production
numbers from May which are steady, that must be the case. OPEC has essentially flooded the
market with exports before the meeting on Friday. The nearest month Brent future changed to
contango compared to closest month some weeks ago, but it has now all changed again to
backwardation. Point being, it seems the physical market is getting tighter again and that
the export flood may have something to do with the meeting. Or it could be that reduced
exports from Iran, Venezuela and Libya are starting to impact the market.
If the market balance overall is to change from a a deficit to near balanced, production
within OPEC has to be increased with almost maximum of whatever spare capacity available in
my opinion. The assumption is that spare capacity in reality is smaller than stated by the
agencies.
"... The author is a prominent American social critic, blogger, and podcaster , and one of our all-time favorite pessimists. We carry his articles regularly on RI . His writing on Russia-gate has been highly entertaining. ..."
"... He is one of the better-known thinkers The New Yorker has dubbed 'The Dystopians' in an excellent 2009 profile , along with the brilliant Dmitry Orlov, another regular contributor to RI (archive) . These theorists believe that modern society is headed for a jarring and painful crack-up. ..."
"... You can find his popular fiction and novels on this subject, here . To get a sense of how entertaining he is, watch this 2004 TED talk about the cruel misery of American urban design - it is one of the most-viewed on TED. Here is a recent audio interview with him which gives a good overview of his work. ..."
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"... Quite the opposite of a dilettante, Kunstler has dug into the research on oil and related energy technologies, and is extremely well-informed, writing books on the subject. What he says implies a massive wealth transfer to Russia, Iran, and the Middle East, as the wells start to dry up. ..."
"Anyway, we're not going back to the Detroit of 1957. We'll be fortunate if we can turn out brooms and scythes twenty years from
now, let alone flying Teslas." 10 hours ago | 1,690
41 MORE:
Business The author is a prominent American
social critic, blogger, and podcaster , and one of our all-time favorite pessimists.
We carry his articles regularly on RI . His writing
on Russia-gate has been highly entertaining.
He is one of the better-known thinkers The New Yorker has dubbed 'The Dystopians' in
an excellent 2009 profile , along with
the brilliant Dmitry Orlov, another regular contributor to RI
(archive) . These theorists believe that modern society is headed for a jarring and painful crack-up.
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Quite the opposite of a dilettante, Kunstler has dug into the research on oil and related energy technologies, and is extremely
well-informed, writing books on the subject. What he says implies a massive wealth transfer to Russia, Iran, and the Middle East,
as the wells start to dry up.
The ill feeling among leaders of the G-7 nations -- essentially, the West plus Japan -- was mirrored early this morning in the
puking financial market futures, so odious, apparently, is the presence of America's Golden Golem of Greatness at the Quebec meet-up
of First World poobahs. It's hard to blame them. The GGG refuses to play nice in the sandbox of the old order.
Completely, totally, delusional
Like many observers here in the USA, I can't tell exactly whether Donald Trump is out of his mind or justifiably blowing up out-of-date
relationships and conventions in a world that is desperately seeking a new disposition of things. The West had a mighty good run
in the decades since the fiascos of the mid-20 th century. My guess is that we're witnessing a slow-burning panic over
the impossibility of maintaining the enviable standard of living we've all enjoyed.
All the jabber is about trade and obstacles to trade, but the real action probably emanates from the energy sector, especially
oil. The G-7 nations are nothing without it, and the supply is getting sketchy at the margins in a way that probably and rightfully
scares them. I'd suppose, for instance, that the recent run-up in oil prices from $40-a-barrel to nearly $80 has had the usual effect
of dampening economic activity worldwide. For some odd reason, the media doesn't pay attention to any of that. But it's become virtually
an axiom that oil over $75-a-barrel smashes economies while oil under $75-a-barrel crushes oil companies.
Mr. Trump probably believes that the USA is in the catbird seat with oil because of the so-called "shale oil miracle." If so,
he is no more deluded than the rest of his fellow citizens, including government officials and journalists, who have failed to notice
that the economics of shale oil don't pencil out -- or are afraid to say.
The oil companies are not making a red cent at it, despite the record-breaking production numbers that recently exceeded the previous
all-time-peak set in 1970. The public believes that we're "energy independent" now, which is simply not true because we still import
way more oil than we export: 10.7 million barrels incoming versus 7.1 million barrels a week outgoing (US EIA).
Shale oil is not a miracle so much as a spectacular stunt: how to leverage cheap debt for a short-term bump in resource extraction
at the expense of a future that will surely be starved for oil. Now that the world is having major problems with excessive debt,
it is also going to have major problems with oil.
The quarrels over trade arise from this unacknowledged predicament: there will be less of everything that the economically hyper-developed
nations want and need, including capital. So, what's shaping up is a fight over the table scraps of the banquet that is shutting
down.
That quandary is surely enough to make powerful nations very nervous. It may also prompt them to actions and outcomes that were
previously unthinkable. At the moment the excessive debt threatens to blow up the European Union, which is liable to be a much bigger
problem for the EU than anything Trump is up to. It has been an admirably stable era for Europe and Japan, and I suppose the Boomers
and X gens don't really remember a time not so long ago when Europe was a cauldron of tribal hatreds and stupendous violence, with
Japan marching all over East Asia, wrecking things.
There is also surprisingly little critical commentary on the notion that Mr. Trump is seeking to "re-industrialize" America. It's
perhaps an understandable wish to return to the magical prosperity of yesteryear. But things have changed. And if wishes were fishes,
the state of the earth's oceans is chastening to enough to give you the heebie-jeebies. Anyway, we're not going back to the Detroit
of 1957. We'll be fortunate if we can turn out brooms and scythes twenty years from now, let alone flying Teslas.
This will be the summer of discontent for the West especially. The fact that populism is still a rising force among these nations
is a clue of broad public skepticism about maintaining the current order. No wonder the massive bureaucracies vested in that order
are freaking out.
I'm not sure Mr. Trump even knows or appreciates just how he represents these dangerous dynamics.
Sand is not a problem. The real question is how much oil is consumed getting this amount od
sand to their designation. 91,000 truckloads of frac sand using, on average say 5 miles per
gallon and 100 miles each way (200 miles roundtrip) would be 3,5 million gallons of fuel per
month. That means that one day a month is essentially lost to sand transportation costs.
The U.S. Shale Oil Industry utilizes a stunning amount of equipment and consumes a massive
amount of materials to produce more than half of the country's oil production. One of the vital
materials used in the production of shale oil is frac sand. The amount of frac sand used in the
shale oil business has skyrocketed by more than 10 times since the industry took off in
2007.
According to the data by
Rockproducts.com and
IHS Markit , frac sand consumption by the U.S. shale oil and gas industry increased from 10
billion pounds a year in 2007 to over 120 billion pounds in 2017. This year, frac sand
consumption is forecasted to climb to over 135 billion pounds, with the country's largest shale
field, the Permian, accounting for 37% of the total at 50 billion pounds.
Now, 50 billion pounds of frac sand in the Permian is an enormous amount when we compare it
to the total 10 billion pounds consumed by the entire shale oil and gas industry in 2007.
(charts courtesy of the EIA - U.S. Energy Information Agency)
As we can see in the graph above, the Permian Region is the largest shale oil field in the
United States with over 3 million barrels per day (mbd) of production compared to 1.7 mbd in
the Eagle Ford, 1.2 mbd at the Bakken and nearly 600,000 barrels per day in the Niobrara.
However, only about 2 mbd of the Permian's total production is from horizontal shale oil
fracking. The remainder is from conventional oil production.
Now, to produce shale oil or gas, the shale drillers pump down the horizontal oil well a
mixture of water, frac sand, and chemicals to release the oil and gas. You can see this process
in the video below (example used for shale gas extraction):
The Permian Region, being the largest shale oil field in the United States, it consumes the
most frac sand. According to BlackMountainSand.com Infographic , the
Permian will consume 68,500 tons of frac sand a day, enough to fill 600 railcars . This equals
50 billion pounds of frac sand a year. And, that figure is forecasted to increase every
year.
Now, if we calculate the number of truckloads it takes to transport this frac sand to the
Permian shale oil wells, it's truly a staggering figure. While estimates vary, I used 45,000
pounds of frac sand per sem-tractor load. By dividing 50 billion pounds of frac sand by 45,000
pounds per truckload, we arrive at the following figures in the chart below:
Each month, over 91,000 truckloads of frac sand will be delivered to the Permian shale oil
wells. However, by the end of 2018, over 1.1 million truckloads of frac sand will be used to
produce the Permian's shale oil and gas . I don't believe investors realize just how much 1.1
million truckloads represents until we compare it to the largest retailer in the United
States.
According to Walmart, their drivers travel approximately 700 million miles per year to
deliver products from the 160 distribution centers to thousands of stores across the country.
From the information, I obtained at MWPWL International on Walmart's distribution
supply chain, the average one-way distance to its Walmart stores is about 130 miles. By
dividing the annual 700 million miles traveled by Walmart drivers by the average 130-mile trip,
the company will utilize approximately 5.5 million truckloads to deliver its products to all of
its stores in 2018.
The following chart compares the annual amount of Walmart's truckloads to frac sand
delivered in the Permian for 2018:
To provide the frac sand to produce shale oil and gas in the Permian this year, it will take
1.1 million truckloads or 20% of the truckloads to supply all the Walmart stores in the United
States. Over 140 million Americans visit Walmart (store or online) every week. However, the
Industry estimates that the Permian's frac sand consumption will jump from 50 billion pounds
this year to 119 billion pounds by 2022. Which means, the Permian will be utilizing 2.6 million
truckloads to deliver frac sand by 2022, or nearly 50% of Walmart's supply chain :
This is an insane number of truckloads just to deliver sand to produce shale oil and gas in
the Permian. Unfortunately, I don't believe the Permian will be consuming this much frac sand
by 2022. As I have stated in several articles and interviews, I see a massive deflationary
spiral taking place in the markets over the next 2-4 years. This will cause the oil price to
fall back much lower, possibly to $30 once again. Thus, drilling activity will collapse in the
shale oil and gas industry, reducing the need for frac sand.
Regardless, I wanted to show the tremendous amount of frac sand that is consumed in the
largest shale oil field in the United States. I calculated that for every gallon of oil
produced in the Permian in 2018, it would need about one pound of frac sand. But, this does not
include all the other materials, such as steel pipe, cement, water, chemicals, etc.
For example, the Permian is estimated to use 71 billion gallons of water to produce oil this
year. Thus, the fracking crews will be pumping down more than 1.5 gallons of water for each
gallon of oil they extract in 2018. So, the shale industry is consuming a larger volume of
water and sand to just produce a smaller quantity of uneconomic shale oil in the Permian .
Lastly, I have provided information in several articles and videos explaining why I believe
the U.S. Shale Oil Industry is a Ponzi Scheme. From my analysis, I see the disintegration of
the U.S. shale oil industry to start to take place within the next 1-3 years. Once the market
realizes it has been investing in a $250+ billion Shale Oil Ponzi Scheme, the impact on the
U.S. economy and financial system will be quite devastating.
Check back for new articles and updates at the SRSrocco Report .
Sand, a material so abundant, you could not give it away, but now, it has worth, thanks
frackers. His article a week or so back was claiming that all the sand had to be shipped out
of michigan, a blatant lie, or perhaps he really is just that ignorant.
A fellow in west texas bought some sparse land a few years back for about $40,000, it was
10's of acres. He was offered $13,000,000 recently, which he lept at. then he found out the
people that bought it from him, flipped it to a sand company for $200,000,000. Now he wants
to sue.
the point being that technology can make formally useless things, worth more. This is the
fundamental reason that economies grow. Knowledge adds value, making the pie larger for
everyone.
Oil may be a ponzi scheme, who knows, if a trade war crashes the global economies and
energy usage plummets by 20-50%, I would expect the deflationary environment he is talking
about. On the other hand if that does not happen, and oil goes to $100 or $200 then we will
hear a bunch of whining, but everything will keep chugging along.
and if graphene filters allow for the energy efficient filtration of salts from produced
water, and those salts are then processed for the elements such as lithium found in them, and
produced water becomes net profit stream instead of a net cost stream, then the whole
equation changes, technology adding value.
A lot of if's, that is what makes the future interesting.
you are an idiot...all sand is not the same. sand runs the gamut of smooth and round to
rough course edged. sand isnt that easy to find when you have to have a particular kind of
sand.....
Permium 1.1 million truckloads per day and + 71 billion gallons of water per year!
People in North America will be in serious need of fresh water soon, however, with
fracking spoiling water nationally and the combined effect of increased earth
tremors/potholes in vast areas, well mother nature is calling in the cards.
Combine that with GM food hidden in most products plus the millions of pharmaceutical
lovers, poisoning their own water supplies and effecting most native species and perhaps a
little radiation from Nukes and the Sun and the cell towers and a few miles of chem trails i
don't give much hope for a sustainable North American future.
I was just telling the second head growing out of my back, the other day, 'man this is the
best it has ever been', and he said ' groik splish!' and bit me on the arm. So I would say we
are of two minds on the matter.
You can make fresh water from sea water for about $2000 per acre foot using expensive
california power. I think that comes to $60 per month for a family of 4 using the fairly high
rate of water consumption by california residents.
(desalination plants already exist in Santa Barbara and San Diego, CA and there are desal
plants all over the world)
80 gallons per day * 4 people * 365 days / 330000 gallons * $2000 / 12 months = $60
An acre foot of water is about 330,000 US gallons.
Reverse osmosis in the home runs about $75 per year and cleans up most of the
problems.
Now what about the cost of distributing that? See that the thing about getting water the
old fashioned ways. Water actually cost nothing to make. The cost is building a system to
distribute the free water. It also come with gravity assist moving water from high to low.
That way you use natural property of water to flow from high places to lower ones. Now in
your system you take sea water and have to move that up from sea level. That cost is addition
to cost of converting sea water to fresh water.
Maybe we could substitute illegal aliens, or Obama-ites convicted of felonies for much of
the frac-sand?
Think of how much money that would save vs incarceration costs!
If we moved up to insane Liberal idiots who were about to explode anyway because their
Liberal world is crashing down, we'd further save the environment from all the silly electric
cars they drive. Its a win-win!
Thanks for pointing out alternatives we never thought of before!
Art presentation raises numerous points that are worth mulling over and at least considering.
According to Art: Eagle Ford production growth is unlikely and that reserves should be exhausted at current production rates
in ~7 years. While Permian production growth is likely, reserves will be exhausted in ~4 years.
Petroleum Age after WWII produced unprecedented economic growth.
Oil shocks of 1974-1986 threatened to end that party.
Demand destruction & oil production bubble resulted in 18 years of cheap energy.
Debt re-started economic growth & debt-based growth of China challenged oil supply
after 2004.
Second oil shock made unconventional oil possible. Zero-interest rates led to 2 nd oil
bubble.
Longest period of high oil prices in history.
That bubble burst in 2014 and oil prices collapsed but without demand destruction.
Now, we are near the end of long-term debt cycle but in denial that the economic basics
have fundamentally changed since the post-war era.
SLIDE 5: Low Interest Rates Created A Capital Bubble For Tight Oil & The Permian
Basin
The oil-price collapse coincided with the end of QE 3 and the beginning of U.S. interest
rate increases.
Continued low interest rates caused margin hunters to focus first on tight oil and then,
specifically on the Permian basin.
$30 oil prices brought large capital flows to a select group of producers seen as
winners.
Tight oil and Permian rig counts have more than doubled since August 2016. Rig
countsincrease with expectation of $55+ oil prices
Increased rig count and fear of ongoing over-supply is a major drag on oil prices.
OPEC production cuts have balanced oil markets since early 2017 & some are now
questioning the lower-for-longer paradigm that dominated the last 3 years.
SLIDE 6: The False Premise that Tight Oil Plays Are the New Swing Producer
No factual support for widespread belief that there is a price war between OPEC &
U.S. tight oil.
OPEC/Saudi Arabia reacted pragmatically to price collapse & recovery.
Prime directive not to repeat mistake of 1982-1986 production cuts.
"Just-in-time production" is another baseless theory.
Shale output reacts to price just like all plays -- slowly & in long-period
cycles.
Idea that U.S. shale is the new swing producer of the world also has no basis.
Being a swing producer means that there is sufficient spare capacity to turn on and off
based on market signals. Shale plays have no spare capacity (they are just-in-time).
Even if DUCs provide some spare capacity, there is no decision-making process that
governs 1000s of independent producers.
SLIDE 7: Shale Cost Reductions 90% Industry Bust, 10% Innovation and Efficiency
Lower costs of shale production widely attributed to technology and efficiency.
Price deflation accounts for 90% of lower costs because of a depression in the oil
industry; 10% is because of technology & efficiency.
That is over for now and prices increased 8% in 2017.
Shale growth has more to do with outside capital supply than break-even prices.
Investors need to believe that significantly higher prices are coming.
"Buy low, sell high" not a sophisticated concept but was responsible for capital flow
into tight oil after price bottom in early 2016.
Smart money has always believed in limits to oil supply.
That will drive the next inflow of capital as markets understand the limits of tight oil
supply.
SLIDE 8: Two of the Largest Tight Oil Plays are in Texas: Eagle Ford & Permian
The Eagle Ford Shale play is expected to recover to 1.3 mmb/d by 2022 & then decline to 1.2 mmb/d by 2050.
The Permian basin plays are anticipated to grow from 2.2 mmb/d in 2018 to more than 3.5 mmb/d by 2044 & then
decline to 3.4 mmb/d by 2050.
Geologist Arthur Berman, who has been skeptical about the shale boom,
warned on Thursday that the Permian's best years are gone and that the most productive U.S.
shale play has just seven years of proven oil reserves left.
"The best years are behind us," Bloomberg quoted Berman as saying at the Texas Energy
Council's annual gathering in Dallas.
The Eagle Ford is not looking good, either, according to Berman, who is now working as an
industry consultant, and whose pessimistic outlook is based on analyses of data about reserves
and production from more than a dozen prominent U.S. shale companies.
"The growth is done," he said at the gathering.
Those who think that the U.S. shale production could add significant crude oil supply to the
global market are in for a disappointment, according to Berman.
"The reserves are respectable but they ain't great and ain't going to save the world,"
Bloomberg quoted Berman as saying.
Yet, Berman has not sold the EOG Resources stock that he has inherited from his father
"because they're a pretty good company."
The short-term drilling productivity outlook by the EIA estimates that the Permian's oil
production hit 3.110 million bpd in April, and will rise by 73,000 bpd to 3.183
million bpd in May.
Earlier this week, the EIA raised its forecast for total U.S. production
this year and next. In the latest Short-Term Energy Outlook (STEO), the EIA said that it
expects U.S. crude oil production to average 10.7 million bpd in 2018, up from 9.4 million bpd
in 2017, and to average 11.9 million bpd in 2019, which is 400,000 bpd higher than forecast in
the April STEO. In the current outlook, the EIA forecasts U.S. crude oil production will end
2019 at more than 12 million bpd.
Yet, production is starting to outpace takeaway capacity in the Permian, creating
bottlenecks that could slow down the growth pace.
Drillers may soon start to test the Permian region's geological limits, Wood Mackenzie has
warned. And if E&P companies can't overcome the geological constraints with tech
breakthroughs, WoodMac has warned that Permian production could
peak in 2021 , putting more than 1.5 million bpd of future production in question, and
potentially significantly influencing oil prices.
The takeaway bottlenecks have hit WTI crude oil priced in Midland, Texas, which declined
sharply compared with Brent in April, the EIA said in the May STEO.
" As production grows beyond the capacity of existing pipeline infrastructure, producers
must use more expensive forms of transportation, including rail and trucks. As a result, WTI
Midland price spreads widened to the largest discount to Brent since 2014. The WTI Midland
differential to Brent settled at -$17.69/b on May 3, which represents a widening of $9.76/b
since April 2," the EIA said.
"... By Gary North, Oilprice.com's South-East Asia & Pacific correspondent. He writes about energy matters, geopolitics and international financial markets. Originally published at OilPrice ..."
"... A more conservative rate of growth may simply be desired by some, but it also may be an inevitability. Kevin Holt, chief investment officer of Invesco's U.S. value equities has said that the situation many companies find themselves in is in part a consequence of the link between their leaders' pay and production growth, rather than returns on investment. ..."
"... Ultimately the market is subject to myriad pressures, such as the heterogeneous quality of oil, fluctuations in labor costs and oil prices, as well as changes in the pace of technological development. These pressures shape the nature of the market, and also make it difficult to predict the longevity of tight oil reserves, and the ability of companies to exploit them. Another significant factor is regulation. How long will Trump's EPA remain the castrated shadow of its former self, and how long until it begins to bare its own teeth? ..."
"... The US might produce 11 million bpd of oil and condensates, but it still consumes nearly 20 million bpd. So, while the US might become a large exporter, it will be a large net importer. I don't see how shale or fantasy oil fields offshore Florida or in the ANWR will add 21 million bdp of production which would allow the US to be a net 12 million exporter. And by 2023? This must have been a typo. ..."
"... "The US might produce 11 million bpd of oil and condensates, but it still consumes nearly 20 million bpd." Exactly. The US is going to be a net exporter .and a net importer . of the same thing. And people accept this. We are leaving the Orwellian Age behind, and entering the Age of Insanity. ..."
"... Has anybody worked out how many years it will be until those particular shale formations have been sucked dry? The article mentioned that some formations had already been run dry. This somehow smacks to me of trying to keep the age of cheap oil going a little bit longer. ..."
"... Yes, most of the increase in oil comes from oil shale. Unlike a conventional oil well, shale extraction means a constant process of fracking (driving a hydraulic fluid into the geology to release light oil and gas trapped in the rock pores), so its much harder to assess the long term viability of a reserve than with a conventional well, which is usually an oil filled underground void with a measurable capacity. The typical production life of a single 'frack' is around 9 months or so, although a single well can be fracked multiple times if the geology is right. ..."
"... Ditto Genscape.com regarding overall supply-demand factors. Not a subscriber nor do I regularly follow sector developments, but big inventory drawdowns at Cushing, OK terminal over the past four months are puzzling in the face of rising EIA oil production data. ..."
"... Slow us expansion and the next recession, which might rival the last one because private sector debt, will push price sub 40. But majors have cut back exploration for some time, OPEC and Russia maybe in decline, and conversion to electrical cars minimal I'm guessing new price record in five years. ..."
"... The weird thing about shale is it unites the power of the financial lobby who finance the drilling with the power of the oil barons who control the market – that gives it 'umph' in the capitalist world. ..."
Yves here. The US seems overeager to be exceptional.
By Gary North, Oilprice.com's South-East Asia & Pacific correspondent. He writes
about energy matters, geopolitics and international financial markets. Originally published at
OilPrice
U.S. shale has effectively upended the oil industry, with
predictions that total U.S. oil production will surpass Saudi Arabia's output this year, in
turn rivalling Russia's to become the preeminent global producer. From its position of being
dependent on, and subordinate to OPEC, the U.S. has seemingly become the big bad wolf. Through
a catalogue of tactical errors and misplaced belief in its own muscle, the mighty brick edifice
of OPEC has begun to look more like a bundle of sticks.
The International Energy Agency (IEA) forecasts that the U.S. will become a net energy exporter by
the late 2020s, but how accurate is that forecast, and to what extent is it mere hyperbole? In
October last year there were already caveats
about the nature of U.S. shale, with some warning that aggressive expansion was leading to
rapid initial growth that would ultimately peak too soon. Mark Papa, former head of EOG
Resources (NYSE: EOG)
raised the question of flatlining output in the face of the doubling of the oil rig count,
"(h)ow can a rig count be double and yet production be stagnant?"
Figures have also been influenced by the
rapid pace of technological development, a pace which has itself plateaued. Robert Clarke,
WoodMac research director for Lower 48 upstream,
said that "(i)f future wells are not offset by continued technology evolution, the Permian
may peak in 2021". IEA forecasts then, may be based on rapid growth and technological
development that simply isn't sustainable. Related:
Shell Outsmarts Competition In The Gulf Of Mexico
Is U.S. shale just a sheep in wolf's clothing, its bite ultimately as benign as grandma's?
The IEA is
still forecasting that the U.S. will be the number one oil exporter by 2023 at 12.1 million
bpd, but at the CERAWeek Conference in Houston on Tuesday, Papa is set to turn that thinking on
its head when he warns the industry that shale will hit roadblocks that prevent such forecasts
from being realized. He
says the best drilling locations in North Dakota and South Texas are already tapped out.
"The oil market is in a state of misdirection now," Papa told the WSJ. "Someone needs to speak
out."
How much of this is indeed misdirection on his part? Papa is CEO at Centennial Resource
Development (NASDAQ: CDEV), which holds the rights to 77,000 acres in the oil-rich Delaware
sub-basin of the Permian. A slowdown in expansion and its potential consequence of increased
oil prices is advantageous to Centennial's shareholders, so who are we to believe guilty of
misdirection?
A more conservative rate of growth may simply be desired by some, but it also may be an
inevitability. Kevin Holt, chief investment officer of Invesco's U.S. value equities has said
that the situation many companies find themselves in is in part a consequence of the link
between their leaders' pay and production growth, rather than returns on investment. This
has fostered a drilling frenzy that has resulted in an explosion of production – an
unregulated drilling frenzy that may be at odds with the long term survival of those companies.
Investors have subsequently demanded a more conservative approach to drilling, which appears to
be having a stabilizing effect.
Ultimately the market is subject to myriad pressures, such as the heterogeneous quality
of oil, fluctuations in labor costs and oil prices, as well as changes in the pace of
technological development. These pressures shape the nature of the market, and also make it
difficult to predict the longevity of tight oil reserves, and the ability of companies to
exploit them. Another significant factor is regulation. How long will Trump's EPA remain the
castrated shadow of its former self, and how long until it begins to bare its own
teeth?
Is Papa's anticipated warning about to shake up the industry? Or is it merely the
continuation of the chorus of restraint that many in the industry have been voicing in this
period of massive growth and upheaval? Ultimately the industry will decide whether it will be
eating out of Papa's hand, or persist in biting the hand that feeds it.
The US might produce 11 million bpd of oil and condensates, but it still consumes nearly
20 million bpd. So, while the US might become a large exporter, it will be a large net
importer. I don't see how shale or fantasy oil fields offshore Florida or in the ANWR will
add 21 million bdp of production which would allow the US to be a net 12 million exporter.
And by 2023? This must have been a typo.
In any case, without a major transition away from internal combustion engines and heating
oil, the US will not be a net export any time soon.
As for shale, while the technology is improving, the rig counts show the true story. US
production is not expanding in line with rigs, nowhere near it. Shale is not Ghawar and never
will be.
"The US might produce 11 million bpd of oil and condensates, but it still consumes nearly
20 million bpd." Exactly. The US is going to be a net exporter .and a net importer . of the same thing. And people accept this. We are leaving the Orwellian Age behind, and entering the Age of
Insanity.
I'm probably going to get smacked down on this but all the oil that the US is pushing out
comes from those shale formations, don't they? But they are not like oil wells which you can
keep pumping for decades but are more about sucking all the loose stuff that you can out of
geological formations. And they deplete – rapidly!
Has anybody worked out how many years it will be until those particular shale formations have
been sucked dry? The article mentioned that some formations had already been run dry. This
somehow smacks to me of trying to keep the age of cheap oil going a little bit longer.
Yes, most of the increase in oil comes from oil shale. Unlike a conventional oil well,
shale extraction means a constant process of fracking (driving a hydraulic fluid into the
geology to release light oil and gas trapped in the rock pores), so its much harder to assess
the long term viability of a reserve than with a conventional well, which is usually an oil
filled underground void with a measurable capacity. The typical production life of a single
'frack' is around 9 months or so, although a single well can be fracked multiple times if the
geology is right.
If you google the geologist Arthur Berman, you'll find many of his articles on the topic.
He's long been something of a fly in the ointment for the trade, as he has argued that
extrapolations based on early explorations are likely to be too optimistic, as the industry
is aiming for 'sweet spots', which will provide very good flows, but not a good indication of
longer term potential. He has also pointed out (which is not denied in the industry), that
unless new technologies are developed, the 'drop off' from peak production will be a much
sharper decline than from a conventional oil field, as there will come a point where repeated
fracking is not economically viable.
So nobody ultimately really knows – if you believe the industry, better and cheaper
techniques will allow fracking to extend outwards from known sweet spots to extend over the
truly vast expanse of oil and gas shales that run from Texas up to Pennsylvania and New York
state. The pessimists (who tend to include most oil geologists) say that the extractable oil
is already getting worked, and the point of unviability will come very quickly, and there
will be a very rapid drop-off. Only time will tell.
Another point worth making is that oil is not as fungible a product as is often assumed.
Shale oil is known as 'tight oil – its very light, but there are only very limited
numbers of refineries that can deal with it. This is why it goes hand in hand with the use of
heavier grades to mix in, so it can be refined in existing facilities which are designed
usually for Gulf of Mexico or Alaskan crudes. This oil is mostly Venezuelan heavy crude or
Canadian oil sands product. So there is a sort of dance going on between these products to
ensure tight oils viability. Its notable that so far as I've seen, nobody seems willing to
invest in tight oil refineries, which to me suggests the industry is not optimistic about its
long term potential.
Another point worth making is that oil is not as fungible a product as is often
assumed
Very true. Refineries have to be "tuned" for a specif type of oil. Most refineries can
only process oil from a single origin, and change of origin requires expensive, slow changes,
made reluctantly.
Why reluctant to change? Construction in refineries is dangerous.
Yup. Fracking means scraping the dregs out of spent fields.
Permian Basin(which I've seen touted as the "new saudi arabia", lately) peaked in like 72 or
73.
all over that part of texas are rusty pumpjacks, idle until the oil price gets rather
high(Bush Darkness, they started running again)
These are marginal wells, at best, without extraordinary measures(like fracking what they
used to call bottle-brushing*).
Oil is finite which means that at some point it will no longer be worth it to get it out of
the ground(EROEI).
Ergo, these big plays that will "make us energy independent" are flashes in the pan.
(* my dad used to fish with a guy who did bottle brushing for saudi aramco, circa late
80's, apparently a rare skill at the time. he said back then that they were gonna run out,
because you don't do that to healthy(sic) fields. )
https://peakprosperity.com has
been behind shale oil production issues for the last decade and has published blogs /
podcasts, interviewed experts, etc
Some articles are behind a paywall, but it is a very good source
Ditto Genscape.com regarding overall supply-demand factors. Not a subscriber nor do I
regularly follow sector developments, but big inventory drawdowns at Cushing, OK terminal
over the past four months are puzzling in the face of rising EIA oil production data.
Exports?
Read that OPEC representatives are meeting with US in Houston this week.
Slow us expansion and the next recession, which might rival the last one because private
sector debt, will push price sub 40.
But majors have cut back exploration for some time, OPEC and Russia maybe in decline, and
conversion to electrical cars minimal I'm guessing new price record in five years.
The weird thing about shale is it unites the power of the financial lobby who finance the
drilling with the power of the oil barons who control the market – that gives it 'umph'
in the capitalist world.
My particular fear for America is that the entire country except the east and west coasts
are approved for fracking. An important part of national food production comes from states
like Kansas which use aquifer water entirely. If the farmers pump oil-flavored water on their
fields it will have an effect on the harvests. In profiting one way, the country sustains a
loss in another.
What Is The Right Price For Oil In A Balanced Market?
By
Dan Steffens
-
Feb 21, 2018, 6:00 PM CST
The price of oil is well off the low for this cycle because the OPEC + Russia plan to rebalance supply &
demand has worked. Now the question is
"What is the Right Price for oil in a balanced market?"
(Click to enlarge)
The price of
West Texas Intermediate (WTI)
crude oil, like the stock market, was
overdue for a bit of a pullback or "correction". After peaking at over $66/bbl on January 26, 2018 the
front month NYMEX contract for WTI followed the stock market correction down to just above $59/bbl on
February 13. By the close on February 16 it had rebounded back to $61.55/bbl. The fact that a key
resistance level at $57.65 was not tested during the selloff is encouraging.
WTI has been moving in a strong upward channel since last summer. Right now there is strong support at
$57.65 and strong resistance at $66.70. A close above $67.00 should set up a test of $75.00 sometime in
the 3rd quarter. At least that's what the "tea leaves" are telling me.
In my opinion, there are several "myths" or "false paradigms" that are holding down the price of oil.
Myth #1: U.S. Tight Oil production can meet the world's future demand for oil.
U.S. oil production is on the rise. There is no doubt that vast improvements in horizontal drilling
technology and completion methods have made harvesting oil from shale and other tight zones possible.
U.S. oil production now exceeds 10,000,000 barrels per day; a level no one in the industry believed was
possible at the turn of the century. However, U.S. tight oil production is still only 5% of the global
oil supply. It is highly unlikely that U.S. oil production will be able to ever meet U.S. demand
(currently over 17,000,000 barrels per day), much less supply the rest of the world.
Myth #2: All Shale Leasehold is the same.
The Permian Basin covers 19 million acres, however only a small percentage of the leasehold is
considered "Tier One" for shale oil recovery. Upstream companies are rapidly drilling up their best
acreage, a process called "High Grading". Once they have drilled out the Tier One locations, it will be
extremely difficult to maintain the pace of production growth that we have seen recently.
Adding to the problem is the fact that horizontal wells are completed with massive frac jobs, which
enable the wells to have very strong initial production rates. Initial production ("IP") rates are
unsustainable. After the initial surge, production declines rapidly in all horizontal wells. In most
areas, production declines by more than 50% from the IP rate within a year. After three years, most
horizontal shale wells are producing less than 10% of their "IP Rate".
Related: The U.S. Oil Industry Sets Its Sights On Asia
From a well-level economic standpoint this is great since the wells payout quickly. However, we now
have 100s of thousands of high decline rate horizontal wells online and another 20,000 new shale wells
will be completed this year. Soon after the Tier One areas are developed, it will be mathematically
impossible to drill enough Tier Two wells to maintain production growth. Most people that I talk to think
the Bakken Shale and the Eagle Ford Shale have already seen their peak production.
Myth #3: All oil is the same.
This is really more of a common misunderstanding than a
myth. The oil being extracted from shale and other tight formations has very high API gravity (over 40
degrees). To a point this was good news, but now we are producing so much "Light Oil" that our refineries
cannot handle all of it. This is one reason that the U.S. is now exporting more oil and why Brent oil
trades at about a $4.00/bbl premium to WTI. Per the most recent U.S. Energy Information Administration's
("EIA") weekly report, over the last six weeks ending February 9, 2018 the U.S.:
• Produced 9,926,800 barrels of crude oil per day
• Imported 7,976,500 barrels of crude oil per day (mostly heavy oil)
• Exported 1,341,500 barrels of crude oil per day (all light oil)
• Exported 4,885,000 barrels of refined products per day
I am expecting the problem of too much light oil production to get more press coverage this summer
because (a) it takes more crude oil to produce summer blend gasolines & diesel and (b) there is a limit
to how much light oil we can export.
Myth #4: We no longer need conventional exploration.
You could argue that this is the same as Myth #1. The thinking among investors is why waste capital on
exploration in remote areas or on high risk drilling like deep water prospects when shale can produce all
the oil we will ever need? The truth is that Non-OPEC / Non-U.S. oil accounts for over 45% of this
world's crude oil supply and it is now at risk of going on steady decline because so little capital has
been deployed in these "Other Areas". With demand for oil now increasing by 1.5 to 2.0 million barrels
per day year-after-year, we are going to need lots of new supply outside of the shales.
Myth #5: OPEC and Russia can flood the market with oil whenever they feel like it.
• First of all it would be incredibly stupid for the cartel members to over produce again since they
were the ones that suffered the most during the recent oil price collapse.
• Second, OPEC may actually have very little production capacity beyond what they are producing today.
In the International Energy Agency's most recent "
Oil
Market Report
" that was published on February 13, 2018 it was reported that OPEC members were 137% in
compliance with their production agreement and the Russian lead Non-OPEC group was 85% in compliance with
their agreement. In my opinion, the real reason that OPEC is holding down production is because they
can't produce much more oil than they are producing today. Regardless of the reason, this one is a fear
that should not keep investors up at night.
Related: Frac Sand Shortage Threatens Shale Boom
If you're considering investing in the Saudi Aramco IPO later this year, you may want to think about
the paragrap:above.
One of my friends with decades of oil & gas industry experience sent me this note: "I attended an
energy conference in Houston last year and the speaker from Tudor Pickering Holt & Co. (a highly
respected energy investment & banking firm) made this comment:"
"When oil was over $100/bbl, did any new production come on in OPEC or Russia? The only area that saw
a significant increase in oil production was North America. No other geologic province increased
production. That tells you that if it were there, it would have been brought on to produce during a
period of $100 + oil. It is the belief of TPH that any production outside of North America and big
offshore projects requiring years to develop do not exist".
I'm sure there are many industry experts that believe there are massive recoverable oil reserves out
there, but TPH's comment does give one pause.
Myth #6: Electric Vehicles and Renewables will soon slow oil consumption.
There is no evidence that this is going to happen anytime soon. The "Millennials", defined as persons
reaching adulthood in the early 21st century, have been brainwashed to believe we'd be better off without
hydrocarbon based fuels and feedstock. Nothing could be further from the truth, but that is a subject for
another time. Millennials believe that all educated people will be driving electric cars within a few
years. They never pause to think about where all the rechargeable battery materials will come from or the
massive changes that will be required to the power grid.
If you are over 30, you may recall that biofuels were going to cause oil demand to go down. It never
happened.
We are going to see more electric vehicles in the future, but they won't make a dent in gasoline and
diesel demand for at least another decade. Wind and solar generate electricity and therefore are more of
a threat to coal, but they still cannot compete with gas fired power plants.
Like it or not, this world runs on oil. Nothing can come close to the energy density of gasoline &
diesel and they are still relatively cheap compare to other transportation fuels.
(Click to enlarge)
Fact: In April, demand for crude oil is expect to spike by over 2.0 million barrels per day.
In 2017, demand for oil increased by 2.3 million barrels per day from the first to the second quarter.
Last year, U.S. crude oil inventories were at the top of the five year range. Today, U.S. crude oil
inventories are in the middle of the five year range. Facts eventually top Myths.
Some statistics in the IEA's Oil Market Report that should have raised a few more eyebrows:
• Global oil supply in January edged lower to 97,700,000 barrels per day. Compare this to global
demand that IEA forecasts will exceed 100,000,000 barrels per day by the 4th quarter.
• IEA's oil demand growth forecast for 2018 was raised to 1,400,000 barrels per day. In my opinion, when
the actual data is in for 2018, demand will have gone up by over 2,000,000 barrels per day. Global GDP
growth estimates just keep going up and GDP growth is the primary driver of oil demand.
• OECD commercial stocks (crude oil and refined products) fell in December by 55,600,000 barrels, the
steepest drop in over seven years. OECD stocks are now 2,851 million barrels, which is way below "glut"
level.
My prediction:
When the U.S. refinery maintenance season is over in March,
supply/demand statistics are going to turn VERY BULLISH for oil in April.
By Dan Steffens for Oilprice.com
Mamdouh G Salameh
on February 22 2018 said:
While I agree with you on myths surrounding US shale oil production, I disagree that OPEC can't produce
more given the right oil price. Iraq alone could add more than 2 million barrels a day (mbd) by 2021/22
given the ongoing development of many discovered oilfields. Iraq has a large number of huge discovered
oilfields that are waiting to be developed. A successful development programme could take Iraq's oil
production to more than 10 mbd by 2026/27.
Moreover, OPEC could easily raise their production by more than 2.5 mbd at an oil price of $100/barrel or
higher. But having suffered a real ordeal with the oil price crash in 2014, they are not going to flood
the oil market again.
I totally agree with you that there is a huge hype about the impact of a wider use of electric vehicles (EVs)
on the global oil market and the demand for oil. EVs will hardly make a dent on the global demand for
oil. There will never be a post-oil era during the 21st century and far beyond.
The oil price is heading towards $70/barrel and beyond during 2018 and could even touch $80 in 2019
buoyed by very positive oil market fundamentals and a re-balanced oil market.
In my considered opinion, a fair price for oil ranges from $100-$130. Such a price will provide good
revenues to the oil-producing nations and will enable them to invest in exploration and in expanding
oil-production capacity. It will also enhance global investment in oil and energy projects and will
enable major oil companies to balance their books and invest further in oil projects. All in all, it will
stimulate the global economy and impact positively on it.
Dr Mamdouh G Salameh
International Oil Economist
Visiting Professor of Energy Economics at ESCP Europe Business School, London
Pankaj Kumar
on February 22 2018 said:
What happens if India and China start booming? Their oil consumption and appetite increase beyond the
projected estimate. This could mean oil prices reach the highest threshold they've ever seen. This
is important with many countries (USA) now becoming more territorial and protection driven. $100-130
would be conservative numbers if this happens.
The increase in well productivity comes with a higher cost tag and whether it is 225 or 250K
BO EUR, at a gross WH price of $60 per barrel and a net back price of $30, those kinds of
estimated UR's are barely (in)sufficient to pay out $7.5M well costs. One cannot replace
reserve inventories that are declining precipitously, much less grow reserves, by breaking
even. It is, in my opinion, a mistake to assume the future of unconventional shale oil
resources in our country is strictly price dependent. It is very much money dependent.
I think one of the primary reasons there are any rigs still running in the EF is to comply
with SEC, 5 year, drill-it-or-lose-it rules for proximity related PUD reserves. If you have
borrowed money on PUD reserves and are about ready to have to impair, again, because you are
running out of time, you are up Shit Creek. Or further up Shit Creek than you already were.
Otherwise, I don't know why anyone is drilling Eagle Ford wells anymore unless they know,
guaranteed, the price of oil is going to $85 and will STAY there.
Just thinking about all these stripper horizontal wells gives me LOE nightmares.
A major expense being downhole failures, doesn't it make practical sense that these wells
will be very high cost? Over 10,000' of rods rubbing up and down against 10,000' of tubing,
and in particular in beginning of the "curve" where the down hole pump apparently must sit in
order to keep from pumping off.
We have wells that haven't been pulled in years, but those are slow pumping verticals that
are very shallow. Many drilled with a cable tool. Straight holes, little rod wear.
I just cannot imagine getting a long run without a failure on these hz wells with a 640
Lufkin pounding away 24/7/365.
I drove by 33 Eagle Ford shale oil wells today, Shallow; did a little windshield poll. Twenty
one of them were down. Or on pump-off controls. Either way, they weren't making money. Might
be they were all WOR; everybody has fled S. Texas for points West. Hauling frac sand can now
make you upper middle class in less than 6 months.
Rod lifting those kinds of wells you describe been there, done that. It sucks. Steal one
in a garage sale, or off eBay and for a while you think you hit a big lick. Then along comes
a $135K well intervention that takes 2 years to payout and you wish you'd become a landscape
engineer (lawnmower) instead.
All wells on rod lift eventually will have down hole failures. When wells fail often, or are
low oil volume, they may become uneconomic to produce.
From what I have seen from actual joint interest statements to non-operated working
interest owners, it costs between $3,000-$20,000 per month to operate a shale oil well. Much
of the expense depends upon how much water is produced with the oil. Almost all produced
water is truck hauled. Water disposal systems are being constructed, but those are very
expensive.
The $$ figure I cite does not include repairs of down hole failures such as pump failures
or tubing leaks. About the cheapest downhole repair I have seen for one of these wells was
$15,000. The highest I have seen was almost $500,000.
EUR estimates for these wells are for a 40-50 year well life. Much of that life the well
will produce under 25 BOPD. Most of the wells in TX are burdened with a 1/4 royalty.
So, just for illustrative purposes, let's say a 5 year old EFS in TX is now producing
6,000 net BO to the working interest owners. At $50 WTI it is providing gross income of
$300,000. By the time we subtract LOE, G & A, and severance taxes, there is likely less
than $100,000 left.
Then, realize many shale companies, to raise money, have sold their gathering systems,
something which kind of astonished me at first. Therefore, the working interest owners are
also paying to use those systems. Even less $$ to the bottom line.
So, as Mike says, it just becomes a gamble on how many down hole failures occur. If you
luck out and have none in the year, you might make a little at $50 oil, more than one per
year and you have likely lost $$.
There will be several hundred thousand of these wells onshore US before it is over. Each
with a plugging and abandonment cost of around $250K estimated.
But, at $100+ oil, these might work. Just a big risk.
Looses of shale companies which hedged oil production for 2018 at 2017 prices can be
tremendous.
Notable quotes:
"... Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at prices that could end up being quite a bit lower than the market price, which could limit their upside exposure should prices continue to rise. ..."
too
much hype surrounding U.S. shale from the Saudi oil minister last week, a new report finds
that shale drilling is still largely not profitable. Not only that, but costs are on the rise
and drillers are pursuing "irrational production."
Riyadh-based Al Rajhi Capital dug
into the financials of a long list of U.S. shale companies, and found that "despite rising
prices most firms under our study are still in losses with no signs of improvement." The
average return on asset for U.S. shale companies "is still a measly 0.8 percent," the financial
services company wrote in its report.
Moreover, the widely-publicized efficiency gains could be overstated, at least according to
Al Rajhi Capital. The firm said that in the third quarter of 2017, the "average operating cost
per barrel has broadly remained the same without any efficiency gains." Not only that, but the
cost of producing a barrel of oil, after factoring in the cost of spending and higher debt
levels, has actually been rising quite a bit.
Shale companies often tout their rock-bottom breakeven prices, and they often use a narrowly
defined metric that only includes the cost of drilling and production, leaving out all other
costs. But because there are a lot of other expenses, only focusing on operating costs can be a
bit misleading.
The Al Rajhi Capital report concludes that operating costs have indeed edged down over the
past several years. However, a broader measure of the "cash required per barrel," which
includes other costs such as depreciation, interest expense, tax expense, and spending on
drilling and exploration, reveals a more damning picture. Al Rajhi finds that this "cash
required per barrel" metric has been rising for several consecutive quarters, hitting an
average $64 per barrel in the third quarter of 2017. That was a period of time in which WTI
traded much lower, which essentially means that the average shale player was not profitable.
Not everyone is posting poor figures. Diamondback Energy and Continental Resources had
breakeven prices at about $52 and $37 per barrel in the third quarter, respectively, according
to the Al Rajhi report. Parsley Energy, on the other hand, saw its "cash required per barrel"
price rise to nearly $100 per barrel in the third quarter.
A long list of shale companies have promised a more cautious approach this year, with an
emphasis on profits. It remains to be seen if that will happen, especially given the recent run
up in prices. But Al Rajhi questions whether spending cuts will even result in a better
financial position. "Even when capex declines, we are unlikely to see any sustained drop in
cash flow required per barrel due to the nature of shale production and rising interest
expenses," the Al Rajhi report concluded. In other words, cutting spending only leads to lower
production, and the resulting decline in revenues will offset the benefit of lower spending.
All the while, interest payments need to be made, which could be on the rise if debt levels are
climbing.
One factor that has worked against some shale drillers is that the advantage of hedging
future production has all but disappeared. In FY15 and FY16, the companies surveyed realized
revenue gains on the order of $15 and $9 per barrel, respectively, by locking in future
production at higher prices than what ended up prevailing in the market. But, that advantage
has vanished. In the third quarter of 2017, the same companies only earned an extra $1 per
barrel on average by hedging. Part of the reason for that is rising oil prices, as well as a
flattening of the futures curve. Indeed, recently WTI and Brent have showed a strong trend
toward backwardation -- in which longer-dated prices trade lower than near-term. That makes it
much less attractive to lock in future production.
Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at
prices that could end up being quite a bit lower than the market price, which could limit their
upside exposure should prices continue to rise.
In short, the report needs to be offered as a retort against aggressive forecasts for shale
production growth. Drilling is clearly on the rise and U.S. oil production is expected to
increase for the foreseeable future. But the lack of profitability remains a significant
problem for the shale industry.
"... Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at prices that could end up being quite a bit lower than the market price, which could limit their upside exposure should prices continue to rise ..."
Riyadh-based Al Rajhi Capital dug
into the financials of a long list of U.S. shale companies, and found that "despite rising
prices most firms under our study are still in losses with no signs of improvement." The
average return on asset for U.S. shale companies "is still a measly 0.8 percent," the financial
services company wrote in its report.
Moreover, the widely-publicized efficiency gains could be overstated, at least according to
Al Rajhi Capital. The firm said that in the third quarter of 2017, the "average operating cost
per barrel has broadly remained the same without any efficiency gains." Not only that, but the
cost of producing a barrel of oil, after factoring in the cost of spending and higher debt
levels, has actually been rising quite a bit.
Shale companies often tout their rock-bottom breakeven prices, and they often use a narrowly
defined metric that only includes the cost of drilling and production, leaving out all other
costs. But because there are a lot of other expenses, only focusing on operating costs can be a
bit misleading.
The Al Rajhi Capital report concludes that operating costs have indeed edged down over the
past several years. However, a broader measure of the "cash required per barrel," which
includes other costs such as depreciation, interest expense, tax expense, and spending on
drilling and exploration, reveals a more damning picture. Al Rajhi finds that this "cash
required per barrel" metric has been rising for several consecutive quarters, hitting an
average $64 per barrel in the third quarter of 2017. That was a period of time in which WTI
traded much lower, which essentially means that the average shale player was not
profitable.
Not everyone is posting poor figures. Diamondback Energy and Continental Resources had
breakeven prices at about $52 and $37 per barrel in the third quarter, respectively, according
to the Al Rajhi report. Parsley Energy, on the other hand, saw its "cash required per barrel"
price rise to nearly $100 per barrel in the third quarter.
A long list of shale companies have promised a more cautious approach this year, with an
emphasis on profits. It remains to be seen if that will happen, especially given the recent run
up in prices.
But Al Rajhi questions whether spending cuts will even result in a better financial
position. "Even when capex declines, we are unlikely to see any sustained drop in cash flow
required per barrel due to the nature of shale production and rising interest expenses," the Al
Rajhi report concluded. In other words, cutting spending only leads to lower production, and
the resulting decline in revenues will offset the benefit of lower spending. All the while,
interest payments need to be made, which could be on the rise if debt levels are climbing.
One factor that has worked against some shale drillers is that the advantage of hedging
future production has all but disappeared. In FY15 and FY16, the companies surveyed realized
revenue gains on the order of $15 and $9 per barrel, respectively, by locking in future
production at higher prices than what ended up prevailing in the market. But, that advantage
has vanished. In the third quarter of 2017, the same companies only earned an extra $1 per
barrel on average by hedging. Related: The
Unstoppable Oil Rally
Part of the reason for that is rising oil prices, as well as a flattening of the futures
curve. Indeed, recently WTI and Brent have showed a strong trend toward backwardation -- in
which longer-dated prices trade lower than near-term. That makes it much less attractive to
lock in future production.
Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at
prices that could end up being quite a bit lower than the market price, which could limit their
upside exposure should prices continue to rise .
In short, the report needs to be offered as a retort against aggressive forecasts for shale
production growth. Drilling is clearly on the rise and U.S. oil production is expected to
increase for the foreseeable future. But the lack of profitability remains a significant
problem for the shale industry.
The last time U.S. drillers pumped 10 million barrels of crude a day, Richard Nixon was in
the White House. The first oil crisis hadn't yet scared Americans into buying Toyotas, and
fracking was an experimental technique a handful of engineers were trying, with meager
success, to popularize. It was 1970, and oil sold for $1.80 a barrel.
Almost five decades later, with oil hovering near $65 a barrel, daily U.S. crude output is
about to hit the eight-digit mark again. It's a significant milestone on the way to
fulfilling a dream that a generation ago seemed far-fetched: By the end of the year, the U.S.
may well be the world's biggest oil producer. With that, America takes a big step toward
energy independence.
The U.S. crowing from the top of a hill long occupied by Saudi Arabia or Russia would
scramble geopolitics. A new world energy order could emerge. That shuffling will be good for
America but not so much for the planet.
For now, though, the petroleum train is chugging. And you can thank the resilience of the
U.S. shale industry for it.
What didn't kill shale drillers made them stronger. The survivors have transformed
themselves into leaner, faster versions that can thrive even at lower oil prices. Shale isn't
any longer just about grit, sweat, and luck. Technology is key. Geologists use smartphones to
direct drilling, and companies are putting in longer and longer wells. At current prices,
drillers can walk and chew gum at the same time -- lifting production and profits
simultaneously.
Fracking -- blasting water and sand deep underground to free oil from shale rock -- has
improved, too. It's what many call Shale 2.0. And it's not just the risk-taking pioneers who
dominated the first phase of the revolution, such as Trump friend Harold Hamm of Continental
Resources Inc., who are benefiting from the surge. Exxon Mobil Corp., Chevron Corp., and
other major oil groups are joining the rush. U.S. shale is "seemingly on steroids," says
Amrita Sen, chief oil analyst at consultant Energy Aspects Ltd. in London. "The market
remains enchanted by the ability of shale producers to adapt to lower prices and to continue
to grow."
Geez Mike, your link to the oilprice.com story will surely bring Texas Tea back. Upsetting
the oil minister of KSA is the ultimate sign of victory to the shale/political types.
These shale guys are bound and determined to kill the oil price rally, and IEA and EIA
(which BTW in my opinion are both very political organizations) are really boosting it
too.
I know you feel you have a short window, but hang in there. The current price is pretty
good for "us types" and maybe it will hold between here and $55 WTI for the downside, while
we blow through 10 million and 11 million, all the while thinking, just like 1970, that USA
has unlimited supplies of oil.
I am starting to think the dollar is the key anyway. It was weak in 2011-2014, and oil was
sky high. Might be headed that way again, who knows.
Really enjoying all of the history on Oilystuff. Keep it coming!
Will be interesting to see US shale production in response to increasing frac hits,
increasing costs, mounting debt wall. These are all legitimate issues which IEA seems to
overlook when issuing rosy predictions. Three Stooges thought they could repair a hole in a
pair of pants by cutting it out .same logic as IEA.
Yeah, it's those items and more. The biggest they overlook is declines from production. The
past two years, they have concentrated in sweet spots, to keep their chins above water. In
doing so, they have miraculously brought production back up to 2015 highs, and not much more,
although the EIA is reporting imaginary oil. Underneath all that production, wells are
declining at a rapid rate. The biggest rates are what they drilled last year. Those wells
will produce less than half of what they produced last year. So, how many wells would need to
be completed to increase production over a million barrels in 2018? More than current
capacity, that's for sure.
Although tight oil output has increased at an annual rate of close to 1000 kb/d over the
past 12 months (Dec 2016 to Nov 2017), I doubt that rate of increase will continue, probably
about half that unless oil prices rise more than I expect (and I expect we might get to $85/b
by Jan 2019).
I'd say it's a crap shoot as to whether it goes up, or down with about the same number of
completions in 2018 as 2017. Ok, let's say we have more completions, I still can't say it
will go up 500k barrels. While people place statistics on depletion rates, I haven't seen a
well, yet, that can comprehend statistics. As a matter of fact, they defy statistics.
There are 180k producing wells in Texas. There were about 5400 completions in 2017. That's
about 3% of total producing wells.
"... Major oil producing countries, Saudi Arabia chief among them, are using technology to stave off production declines. These YouTube videos are a perfect example of the extreme lengths being employed to continue production: ..."
"... When the decline kicks in, these technologies will ensure that the cliff will be steeper. While I believe we are living at the absolute peak of world production and that decline will kick in soon, I'm not so concerned about specific predictions. It will happen soon enough and when it does the impact will be severe. ..."
"... I think of this problem in personal terms -- my son was born in 2000. He will live to see a world of diminishing oil production (as well as sea level rise, resource conflicts, and many other problems). Does anyone doubt that by the time he is 30 (2030) world oil production will be in decline? Does anyone doubt by the time he is 50 (2050) the world will be a drastically different place than it is today? I have lived through the peak period. I cannot envision what comes after. I can only hope that my son finds a way through it. ..."
"... "Does anyone doubt that by the time he is 30 (2030) world oil production will be in decline? Does anyone doubt by the time he is 50 (2050) the world will be a drastically different place than it is today?" ..."
"... Perhaps. But such sentiments were very common ten, fifteen years ago, and they were directed toward today, not 2030. So, yes, I do "doubt" it, but that's not saying much, as it's a subject I find interesting but useless to speculate about. ..."
"... I'm checking in here for the first time in about 9 years. I'm an old-time peaker, who jumped ship in 2009 when it became clear the dire predictions of Campbell, Deffeyes, et al., were failing to materialize. ..."
Ron is absolutely right about the creaming issue. Major oil producing countries, Saudi Arabia
chief among them, are using technology to stave off production declines. These YouTube videos
are a perfect example of the extreme lengths being employed to continue production:
These videos underscore how uniquely valuable oil is as an energy source and how no other
substitute will ever come close to matching its utility.
When the decline kicks in, these technologies will ensure that the cliff will be
steeper. While I believe we are living at the absolute peak of world production and that
decline will kick in soon, I'm not so concerned about specific predictions. It will happen
soon enough and when it does the impact will be severe.
I think of this problem in personal terms -- my son was born in 2000. He will live to see
a world of diminishing oil production (as well as sea level rise, resource conflicts, and
many other problems). Does anyone doubt that by the time he is 30 (2030) world oil production
will be in decline? Does anyone doubt by the time he is 50 (2050) the world will be a
drastically different place than it is today? I have lived through the peak period. I cannot
envision what comes after. I can only hope that my son finds a way through it.
"Does anyone doubt that by the time he is 30 (2030) world oil production will be in decline?
Does anyone doubt by the time he is 50 (2050) the world will be a drastically different place
than it is today?"
Perhaps. But such sentiments were very common ten, fifteen years ago, and they were directed toward
today, not 2030. So, yes, I do "doubt" it, but that's not saying much, as it's a subject I
find interesting but useless to speculate about.
I'm checking in here for the first time in about 9 years. I'm an old-time peaker, who
jumped ship in 2009 when it became clear the dire predictions of Campbell, Deffeyes, et al.,
were failing to materialize.
This doesn't mean I think oil is infinite or anything. I do think our capacity to predict
doom is much more circumscribed than our abilities to avoid it.
Interesting BOEM report attached – their prediction of GOM oil and gas production from
2018-2027.
They predict oil production will increase from 1.65-1.67 mmbopd in the 2017-2019 window to
1.74-1.77 mmbopd in the 2023-2027 time frame. They include future production from current
reserves, contingent resources and undiscovered resources. Contingent resources are mainly
field expansion projects, new fault blocks, new reservoirs, and resources from discoveries
that have not been put on production.
They have initial production from undiscovered resources occurring already in 2019 –
suggesting that a few discoveries will be made and be on line by the end of 2019. Seems
rather ambitious even for subsea tiebacks.
Given the lack of GOM exploration success in the last few years, my biggest challenge to
these predictions are their estimates of production coming from new discoveries. They show
about 1 BBO of production comes from currently undiscovered resources in this 10 year window.
SLG – hope you are well and had a good holidays. Here is my updated effort at the same
thing. I've added some new discoveries, but not as big or developed as fast BOEM show. I've
included all qualified fields as named entries except a few discovered in 2016 and 2017, and
for a lot I've had to make guesses for reserves based on the expected development size
(numbers in brackets show nameplate capacity). I might be able to improve things a bit when
BOEM reserve numbers for end of 2016 come out, but it's still not going to look much like
their estimates. It's noticeable that there's a lot of activity in short term, small tie
backs now – but these only add about 5 to 10 kbpd and immediately start to decline. So
like you I don't know where they are getting such high contingent resource production
additions from unless it is all on existing developments – I guess if a lot of fields
get to grow like Mars-Ursa has and Atlantis might this year then there'd be enough, but that
seems unlikely to me, especially at the rate they show it.
Thanks George, and same to you for the new year.
I've made a stab at comparing numerous production profiles for the 2018-2027 window –
your's from above, my midcase and downside estimates from a little over a year ago, and
BOEM's estimates – both their total estimate, and their total estimate minus any new
resources/discoveries.
I plan to expand on this in a future post – including revised EUR estimate ranges.
They are all models with something worthwhile to add to the discussion, which is not what I
would say about the EIA projections. They just add have some kind of growth rate, with no
basis in actual numbers, and make it look fancy by adding a hurricane effect – and yet
this is the number usually quoted in the MSM. I think their predictions a couple of years ago
had an exit rate for this year of 2.2 mmbpd – miles off, and when they do try to
provide bottom up justification they look ridiculously ill informed.
Maybe they have a higher oil price forecast? Or they don't bother to see if what gets put on
line is worth developing? I know this is hard, but try preparing a forecast with prices
increasing 3% per year above inflation for 30 years, and you will get a higher forecast.
There is natural gas coming out of our ears at the moment because of the shale phenomena; the
price is tanking back to the mid $2's and there is no place to put anymore gas.
Notable quotes:
"... Shale companies are on track to spend $20 billion more than they will generate in the next six months if prices hover around $40 a barrel, analysts say. ..."
"... Compensation practices play a role in the behavior of U.S. shale producers: Most of their management teams are paid based on growth or adding new oil and gas reserves -- not on profits -- according to Matt Portillo, an analyst at Tudor Pickering Holt & Co., in Houston. "Until that changes, growth may continue to prevail," he said. ..."
The shale oil industry is NOT profitable. It never has been and in general terms it will not
be in 2018 either. There has always been something fishy about its funding, particularly when
wanders like this guy can make $16M a year in compensation, while his company looses money
year over year for stock holders.
Clearly, however, it is not his fault his company can't be profitable and it is not their
fault they are "forced" to borrow all that money
As we've noted on too many occasions to count, this is aiding and abetting a situation
where these companies effectively sow the seeds of their own demise. They're running up the
down escalator. They're working their asses off to drive down the price of the very
commodity they're producing.
And hilariously, they think maybe you're the problem. Here's the
Journal again:
"The biggest problem our industry faces today is you guys," Al Walker, chief executive
of Anadarko Petroleum Corp. , told investors at a conference last month.
Wall Street has become an enabler that pushes companies to grow production at any
cost, while punishing those that try to live within their means, Mr. Walker said, adding:
"It's kind of like going to AA. You know, we need a partner. We really need the
investment community to show discipline."
Even if companies cut back on drilling now, it wouldn't be enough to stop a new wave
of oil from hitting the market in the second half of the year : U.S. shale output
typically lags behind new drilling by four to six months, analysts say.
Shale companies are on track to spend $20 billion more than they will generate in the
next six months if prices hover around $40 a barrel, analysts say.
Compensation practices play a role in the behavior of U.S. shale producers: Most of
their management teams are paid based on growth or adding new oil and gas reserves -- not
on profits -- according to Matt Portillo, an analyst at Tudor Pickering Holt & Co.,
in Houston. "Until that changes, growth may continue to prevail," he said.
Isn't that last bit about executive compensation great?
So folks like Al Walker are paid based not on profits, but on growth, and that growth is
funded by investors like you.
So if you connect the dots there, it means you are literally giving these management
teams money to fund the growth that ends up boosting their compensation, and that growth is
going to ultimately bankrupt the companies you're investing in by creating a supply
glut.
Welcome to the shale industry, goddammit. Enjoy your stay.
Every article on oil prices in the last several months says the ONLY downside is US shale.
Do the larger US shale companies pay attention to supply/demand dynamics at all? At
current prices most can show positive EPS, assuming service costs do not surge too much?
For example, auto manufacturers do not produce the maximum vehicles possible. They pay
attention to supply and demand. Almost every single manufacturer tries to forecast demand for
its product.
Even farmers try to grow what crops are in most demand and raise what livestock is most in
demand.
We have not drilled a well in over 3 years due to lack of oil demand, our production has
fallen.
"Rystad Energy is even bullish on American oil. The Norwegian firm sees U.S. crude output
hitting 11 million barrels per day by December, narrowly surpassing global leader Russia and
OPEC kingpin Saudi Arabia."
Absolute poppycock! US output will do good to get to the level that EIA is currently
reporting, about 9.75 by the end of 2018. Mike's post explains why. 11 million barrels a
day,? Man, that is some potent stuff they are smoking.
>Do the larger US shale companies pay attention to supply/demand dynamics at all?
> At current prices most can show positive EPS, assuming service costs do not surge too
much?
This might be a wrong question. The right question IMHO is: "To what extent shale
companies are just prostitutes of Wall Street and to what extent they are independent oil
production companies? "
What if the key role for such companies is to be a part of "price crasher" mechanism
(along with "naked shorts" and similar financial chicanery) ?
I believe that with the shale boom it is Wall Street that obtained mechanism using which
they can dictate oil prices.
Not Saudies or OPEC in general but Wall Street titans are now in the driving seat,
although OPEC and Russia are fighting back by limiting production.
And Wall Street is not shy to step on the throat of "conventional" oil producers and force
them to produce with no or even negative margins because of the specific of oil industry.
When you gets so much money on such lenient conditions something is fishy This dual
production mode (oil plus junk bonds and evergreen loans) looks to me just a variable of
"subprime housing boom" on a new level.
The past week of continuous record low temperatures and snowfall has oil-dependent power
plants in the northeast scrambling to secure supplies of some of the dirtiest burning oil
available in the market due to an impending supply shortage, according to a new report by
Hellenic Shipping News .
Oil fuels 30 percent of the New England power plant market, but winter storms could lead to
another foot of snow, making it difficult for tankers or trains to deliver needed commodities,
Marcia Blomberg of regional grid operator ISO New England, said.
Oil imports to the East Coast jumped by almost 60 percent last week in anticipation of
increased demand due to heating needs. JBC Energy predicts distillate use to increase by 90,000
barrels per day in January and February as well.
The cold weather, expected to become a "bomb cyclone" in the coming days, has also
shocked
natural gas markets. Extreme cold is cutting production in North Dakota's Bakken, while demand
is surging because everyone is turning up the thermostat to stay warm.
Reuters said that gas flowing through interstate pipelines from North Dakota dropped from
1.3 billion cubic feet per day in the week ending on December 25 to just 1 bcf/d as of Tuesday.
Texas (-20 percent) Oklahoma (-22 percent) and Pennsylvania (-5 percent) are also reporting
weather-related production problems, Genscape data says.
Yes, it is unreal: either at the Texas RRC they had really HUGE problems in the past months collecting data, or the EIA used only
model estimates without any form of revision.
The correcting factors of the Texas RRC have not changed much and they showed they usual variability, so that I cannot explain
why there is such a big divergence between corrected RRC data and EIA. They only problem that I can think of (on the part of the
RRC) is that the hurricane completely disrupted their work: does anyone know whether the offices and data servers of the Texas
RRC were damaged during the hurricane? Thanks for the information.
I had a very interesting discussion on Twitter: operators in Texas confirmed me that the RRC offices were not affected by the
hurricane and data reporting proceeded normally. At this point the only (legal) reason left to explain the divergence is that
the EIA has started including NGL into their numbers:
"... Rystad Energy concluded this week that 2017 was yet another record low year for discovered conventional volumes globally. Less than seven billion barrels of oil equivalent has been discovered YTD. "We haven't seen anything like this since the 1940s," says Sonia Mladá Passos, Senior Analyst at Rystad Energy. "The discovered volumes averaged at ~550 million barrels of oil equivalent per month. The most worrisome is the fact that the reserve replacement ratio* in the current year reached only 11% (for oil and gas combined) – compared to over 50% in 2012." According to Rystad's analysis, 2006 was the last year when reserve replacement ratio reached 100%; largely thanks to the giant onshore gas field Galkynysh in Turkmenistan. Not only did the total volume of discovered resources decrease – so did the resources per discovered field. An average offshore discovery in 2017 held ~100 million barrels of oil equivalent, compared to 150 million boe in 2012. "Low resources per discovered field can influence its commerciality. Under our current base case price scenario, we estimate that over 1 billion boe discovered during 2017 might never be developed", says Passos. ..."
"... We have recently observed strong empiric evidence for the theory that a positive tendency in initial production rates for shale wells does not always lead to similar improvements in ultimate recovery. ..."
"... But profits and stock valuations are terrible over the past five to ten years. Drillers, Explorers, Services, I'd be shocked if you could find an index combo that has come even close to matching S&P, Biotech, Semiconductors, NASDAQ. Not positive but E&P et al might not even have beaten transportation over the past decade. If you've been invested in Oil and Gas you are officially a loser. ..."
"... The cooperative program and understanding between the Kingdom and Russia, the two largest producers in the market. ..."
"... Last but not least, we need to develop a culture of saving to increase our capital buildup for the economy. This is not an easy task, and requires a total rehabilitation of our consuming behavior." ..."
"... At this posting, New England is burning oil for 17% of their electricity generation. Wholesale spot price for electricity is $230/Mwh, about 10 times regular pricing. Later this afternoon, demand is expected to increase more. ..."
ALL-TIME LOW FOR DISCOVERED RESOURCES IN 2017: AROUND 7 BILLION BARRELS OF OIL EQUIVALENT WAS DISCOVERED
Rystad Energy concluded this week that 2017 was yet another record low year for discovered conventional volumes globally.
Less than seven billion barrels of oil equivalent has been discovered YTD.
"We haven't seen anything like this since the 1940s," says Sonia Mladá Passos, Senior Analyst at Rystad Energy. "The discovered
volumes averaged at ~550 million barrels of oil equivalent per month. The most worrisome is the fact that the reserve replacement
ratio* in the current year reached only 11% (for oil and gas combined) – compared to over 50% in 2012."
According to Rystad's analysis, 2006 was the last year when reserve replacement ratio reached 100%; largely thanks to the giant
onshore gas field Galkynysh in Turkmenistan.
Not only did the total volume of discovered resources decrease – so did the resources per discovered field.
An average offshore discovery in 2017 held ~100 million barrels of oil equivalent, compared to 150 million boe in 2012.
"Low resources per discovered field can influence its commerciality. Under our current base case price scenario, we estimate that
over 1 billion boe discovered during 2017 might never be developed", says Passos.
I think every drilled high impact wildcat well identified by Rystad at the end of 2016 has now turned out dry, with a couple
postponed for lack of finance.
It would be great if they gave the gas/liquids split all rolled up. Does it look to your eyes like a roughly 50/50 gas/liquids
split in 2017, as it does to mine? (Talking about Rystad chart.)
2017 looks likes another very disappointing year for conventional discoveries. I wonder how unconventional resource adds have
been over the last few years. I suspect that is how many of our big oil friends are achieving their annual resource add goals.
The EIA reserves are going to be interesting: even before the price crash the extension numbers, which is where all the LTO growth
came from rather than discoveries, were starting to fall and reserve changes looked like they might be going negative, which I'd
guess is due to decreases in URR estimates; e.g. below for Bakken.
Yes reserves decreased in 2015, probably due (in part) to a fall in oil prices from $59/b in Dec 2014 to $37/b in Dec 2015,
the price in Dec 2016 was $52/b, using spot prices from the EIA, so perhaps reserves increased a bit in 2016, it will be interesting
to see the 2016 estimate.
I think they have to use averages for determining economic recovery not spot prices – I can't remember now if it's six month or
annual (or other – I think maybe six months to March and September when they reevaluate) – 2016 would be bout the same or a bit
lower depending on the time frame.
Initially, SEC rules required a single-day, fiscal-year-end spot price to determine a company's oil and gas reserves and
economic production capability. The SEC Final Rule changes this requirement to a 12-month average of the first-of-the-month prices.
Using this I get
2014, 101
2015, 54
2016, 42
So 2016 reserves should decrease further if prices affect reserves.
EMPIRICAL EVIDENCE FOR COLLAPSING PRODUCTION RATES IN EAGLE FORD
We have recently observed strong empiric evidence for the theory that a positive tendency in initial production rates for
shale wells does not always lead to similar improvements in ultimate recovery.
Cabot announced they are selling up in the EF and concentrating on gas (15,000 bpd), maybe more likr them to come.
I have had to work hard over the years to explain to management that oil completions have to be optimized, and that seeking the
highest peak rate wasn't likely to be the best answer. This of course happens because high level oil company managers are good
at sales and PowerPoint, but have opportunities for improvement in key areas.
This confirms the suspicion of many that the high peak rates on newer wells (often with longer laterals and more frack stages
and proppant, in short more expensive wells) don't boost cumulative output much. In the case of the Eagle Ford, wells in Karnes
county (the core of the play) only increased output by about 40 kb over the older wells with less expensive completion methods.
Looking at Bakken data, it is clear that this is the case as well, with about a 10%to 15 % increase in cumulative output over
the first 24 months and then similar output to older wells thereafter.
Many observers assume that a higher peak production from a well leads to higher cumulative output of the same proportion. That
is if the peak goes from 400 kbo/d for a well projected to have an EUR of 200 kbo to a peak of 800 kbo/d for a newer well, it
is often assumed that the new well will have cumulative output of 400 kbo. This is incorrect, in fact the newer well is more likely
to have an output of 240 kbo an increase of only 20% rather than the 100% often assumed.
However, Rystad Energy argues that there is some evidence that suggests those higher initial production (IP) rates do not
necessarily translate into larger gains in the total volume of oil and gas that is ultimately recovered. A sample of wells in
the Eagle Ford showed steadily higher IPs in recent years, but they also exhibited steeper and steeper decline rates.
It seems a bit unlikely that Canada is going to continue increasing production as shown above over the next 6 to 8 years (after
2018 ramp ups are complete). There are no major greenfiled developments currently under construction and these take at least 5
years from FEED to production, there are continuing redundancies in the oil patch as some of the large, recent developments move
from development to operations, and there is no spare pipeline (or rail) capacity such that the oil is at about $10 to $15 discount
which is likely to increase as Fort Hill's ramps up through next year (and new pipeline permitting and construction is likely
to take even longer than the actual oil sands project).
With Iran and Iraq – they may have oil in the ground, but they need huge,new surface production facilites to process it and
supply water/gas for injection – those too take about 5 years to construct, assuming they can find some outside funding.
"OPEC has already demonstrated it can produce more, before they cut back in Jan 2017"
Yes OPEC may have some capacity to increase production. But many OPEC countries are in decline and Saudi Arabia does not have
any Khurais or Manifa like fields left to develop. If I ruled Saudi Arabia then I wouldn´t produce more than 10 mb/d even if there
were shortages. Better to stay on the platau a little bit longer. Iraq is the country with the biggest possibilities for increases.
But they will do so when they are able to, not because of shortages. The other countries you mentioned have mainly expensive oil
like tar sands in Canada, arctic in Russia and ultra deepwater in Brazil. Sure we can see increases there but it takes a long
time to develop.
"I don't think oil producers were struggling at $100/b, they were overproducing so prices dropped."
For the World Debt to GDP has increased from 226% in 2012 to 243% in 2Q2017, for advanced economies over the same period debt
to GDP went from 272% to 275% and for emerging economies over the same period 145% to 190%.
The story is better access to credit for emerging economies from 2012 to 2017.
A major recession is not very likely.
The IMF forecasts real GDP growth of 3.75% for the World from 2018 to 2022.
Oil prices at over $100/b were no problem for the World economy from 2011-2014, real GDP grew at 3.5% per year. No reason $100/b
oil would cause a recession.
The $160/b (2017$) will only be about 3.3% of World GDP in 2026, assuming medium UN population growth scenario and real per
capita GDP growth at 1.5%/year and 84 Mb/d C+C output in 2026.
There was another big drop in US crude stocks by the twip – down 6.5 mmbbls with gasoline and diesel up 2 mmbbls combined.
The crude level is fast approaching the middle of the 5 year average – how far does it have to undershoot before panic sets in?
US SPR drawdown this year is about 21.5 million barrels, this is usually not included when calculating the 5y average. Planned
annual sales are similar for the next couple of years (
https://www.eia.gov/todayinenergy/detail.php?id=29692
note that the figure shows fiscal year).
The story being told is that oil markets should be in balance next year or slight surplus if LTO maintains its pace. KSA low
production during end of 2017 and the problems in Venezuela should result in continued stock drawdowns or only a small build during
the spring (forties supports this too). Next summer driving season can be interesting, assuming the economy remains healthy. 2019
will be _very_ interesting since it will be revealed how much of the OPEC cuts were made voluntary.
As inventories are still way above historical averages, it is important to bear in mind that substantial infrastructure in form
of tanks and pipelines have been constructed over the last few years. This increased the necessary working inventory to keep the
system functioning. So, the critical inventory level might be much higher than in previous years.
They need a minimum amount of empty capacity to allow for blending and movement, not a minimum amount of stored volume to keep
it working. The storage is to cover for upsets and to allow people to make money from arbitrage.
It was propably close to the point where it was low enough to cause problems at that time. Why? Because from a commercial point
of view, it´s just stupid to have more storage than you need. It´s cost money to store it and it´s better to sell it and get the
money instead of just having it in storage. Also there is the SPR from where you can get oil if there is supply problems. So really
no need to have large amounts of oil in storage.
Yes that was how I interpreted your original comment. At least for US commercial crude stocks for the current week we are currently
about 95 million barrels above the 2012 and 2013 average for the same week of the year, so perhaps another few years before any
panic if stocks continue to decrease by 50 Mb per year as they did from 2016 to 2017. I chose 2012 and 2013 because oil prices
were relatively high in 2012 and 2013 ($88/b and $98/b in Dec 2012 and Dec 2013 for WTI).
On rereading your original comment, I think when it gets near the lower edge of the 5 year average, panics sets in, it may
take a few years.
"You can just say it is an industry in decline and there are better places to put one's money in." yes you can say "the industry
is in decline" but then you would be wrong, not usual for you or many on the board. In this case however, the statement is not
only wrong but delusional. Both production and demand are at record highs for oil natural gas and natural gas liquids. Of course
why let facts get in the way of your political views, to quote a old line; fat, drunk and stupid in no way to go through life,
son
"Both production and demand are at record highs for oil natural gas and natural gas liquids. "
But profits and stock valuations are terrible over the past five to ten years. Drillers, Explorers, Services, I'd be shocked
if you could find an index combo that has come even close to matching S&P, Biotech, Semiconductors, NASDAQ. Not positive but E&P
et al might not even have beaten transportation over the past decade. If you've been invested in Oil and Gas you are officially
a loser.
Now, high yield bonds might be a different story. But in the wake of all the bankruptcies for the past five years was 100%
of all bonds paid? They might have been, not sure.
Oil companies themselves have changed the way they are investing. So I take that as a sign they, too, think their best times are
behind them.
In terms of financial management, there are industries that have done better and are likely to do better than gas and oil.
It's simply not a growth industry anymore.
I think oil prices have an effect on investment, especially outside the LTO focused companies. For the LTO players they seem
to focus on output growth regardless of profits, not a great long term business model.
Regarding the gap, a third of the consumption growth over the last decade was from China. If Chinese consumption plateaus, as
it very well might, then consumption growth from here will be less and the gap smaller. But putting in an assumption to change
an established trend would just add another point of failure. This piece isn't so much a model as a creation story, trying to
figure out why past expectations weren't met and where the known unkowns might come from. A big one of these is what the Permian
might end up doing. I think that is why industry is paying up to get into the Permian. If you are not in the Permian you don't
have a future. And shareholders will pay any amount of money for you to keep your job.
The piece was prompted by Ovi's observation that Non-OPEC less the big three has been in decline since 2004 – very encouraging.
There are some systems in which a price rise does not result in an increase in production simply because the resource is clapped
out. The gold market last decade for example. The gold price rose at an average of about 17% per annum year after year but gold
production fell. That is not supposed to happen. Now some mines are digging up rock with just over one part in a million of gold
in it and that pays for turning that rock into mud.
There was a July report for China imports that extrapolated to another 6.6% consumption growth year for them. No evidence of slow
down. Ditto India.
Reminder to folks because it is a tad obscure. India's consumption growth is 8% but it's concentrated in an unusual way. LPG.
They run motors on LPG, mostly motorbikes.
Vehicle miles driven. The increase is relentless as is US population growth. In the big smash of 2008/2009 there was a flattening
of the increase but not really any sort of collapse. There was in oil price, but there was no need for it since consumption did
not decline more than 5%. A quick look at historical consumption not just miles driven shows essentially the same tiniest of down
ticks during that timeframe.
So I would say we need a new theory as to why price declines during recession. Doesn't appear to be less driving to work.
Consumption of oil would seem to decline a little bit right across the board during a recession, especially a big one. Construction
machinery runs less, people travel less, buy fewer new things. It doesn't take very much by way of falling consumption to reduce
the price of oil. The price of oil is highly inelastic, in the short term, and it's like milk.
The price of milk has to fall a long way before you can find uses for more than the usual amount.
People buy as much milk as they want for their kids, and maybe a little to cook with. NO MORE, even if the price goes down
a lot. They don't have any use for it. So .. if it's coming to market, it has to sell cheaper in order for people to FIND uses
for it. You can feed milk to the cat, and even to the pigs, if it's cheap enough. Farmers have been feeding excess milk to pigs
just about forever, lol. I did so myself when we had more than we could use otherwise when I was a kid.
So . if the price of gasoline falls, maybe you take the ski boat to the lake one extra weekend , which can easily result in
burning a couple of hundred gallons, round trip, as opposed to spending the weekend golfing at a cheap nearby course.
Or you drive the old car that's a gas hog more, because it saves putting miles on a newer car. When the price of gasoline bottomed
out, I drove my old four by four truck a lot more than I would have otherwise, because I knew I would be retiring it before long,
and wanted to get as many miles out of it as I could, saving wear and tear on the car .. which I'm planning on keeping indefinitely.
It broke down yesterday, and while it's not quite dead, I 'm thinking it's time to euthanize it, lol.
I'm also running my big yellow machines a lot more than usual, because when diesel is down close to two bucks, as opposed to
four bucks or so, this saves me a hundred bucks a day, or more, if I stay with it, and I've got some pretty big long term projects
such as a new lake, which I work on at odd times, whenever circumstances permit.
IF I were hiring out, which I don't , I would be able to offer a neighbor a hundred bucks or more off for a days work, with
diesel at two, as opposed to four bucks. That would result in neighbors with cash, and thrifty Scots habits, spending some of
their savings, doing long planned work sooner, or maybe going for a new small project.
Overall though construction falls off during a recession.
Most of the increase in total miles happens as the result of people driving new cars, and by and large, new cars and light
trucks are far more fuel efficient than old ones.
And people who are broke spend as much on gasoline as they can afford, period. They MUST spend to get to work. If a tank at
twenty bucks will get them to Grandma's house and back in their old clunker, they go. A tank a forty bucks often means calling
rather than visiting.
It is pretty much a given that Permian oil needs export market. This is from PAA conference call.
" PAA comments: If you look at the amount of 45-plus gravity. It's about 300,000 barrels a day now, growing to 1 million plus.
So, a lot of those volumes are coming, and that's really the crux of the benefit of a Cactus pipeline being able to take that
directly to the water because I think we are going to see a lot of pushback from refiners. We are already starting to see it as
far as the lightning of the general stream going up to Cushing.
The refiners don't want any lighter. So, it's an integral part of the strategy and a piece of everything we've been building."
Delaware basin produces 56% oil that is greater than API gravity 50 plus according to Woodmac.
Every week I see announcements to export US oil. Here are some.
"OPINION-
Don't be taken in by the surge in oil prices
But oil prices have continued to be volatile. They went down from $114 per barrel in June 2014 to $26 per barrel in early 2016
and moved gradually upward to touch $64 per barrel in late November 2017. On the other hand, economic forecasts expect oil prices
to continue to rise to a range of between $70 to $80 by the end of the first quarter of 2018. Futurists in the field base their
expectations on the following indicators:
1) The cooperative program and understanding between the Kingdom and Russia, the two largest producers in the market.
2) The continuation of efforts to reduce oil surplus in the market 3) The agreement among OPEC members and some non-members to
continue their programs of production reduction up to the end of 2018. 8. Last but not least, we need to develop a culture
of saving to increase our capital buildup for the economy. This is not an easy task, and requires a total rehabilitation of our
consuming behavior."
Interesting development for natgas: Iroquois zone 2 spot prices just shot up to over 32 USD per mcf. This is nearly 1000% up from
last month. As much depends now on the future weather, it shows how volatile the US gas market can be – despite massive efforts
towards more supply.
As the industry has completely shifted the supply from the South to the Northeast, hurricanes are no more a threat to supply,
yet freeze offs become now a major issue. Previously just the supply of the Rockies has been hampered by freeze offs. As this
concerned just 10% of US total production, this has never been an issue for gas supply. However, as currently 70% of supply comes
from the Northeast and the Rockies, freeze off could lead to serious supply disruptions, if the freeze continues.
Not freeze offs, simply lack of pipeline capacity in the face of unprecedented demand. When the receipt figures from the various
transfer points are published, they should show 100% capacity utilization.
At this posting, New England is burning oil for 17% of their electricity generation. Wholesale spot price for electricity
is $230/Mwh, about 10 times regular pricing. Later this afternoon, demand is expected to increase more.
The supply is there in the pipelines, Mr. Leopold, there just isn't enough of them to satisfy demand during this cold spell.
I was expecting your reply. Thanks for your opinion.
Nevertheless, there has been huge infrastructure spending over the last years. The pipelines should be already in place.
However, freeze offs are not an issue just yet. If the gas wells freeze off later in the week (temperatures are going to zero
down until Cincinnati) , the shortage of supply may be really a concern. There is just one week left and we know it.
This is one of the structural weaknesses of Shale gas:you probably do not have it when you need it the most.
The pipelines that have been completed greatly favor delivery west to southwest from the Appalachian Basin.
The Atlantic Sunrise is being built that will deliver into the NYC area via a hookup with Transco, I believe.
Deliveries to the north, that is New York State and New England have been virtually nil.
Yes, the storage aspects of all gas products is a challenge, and – as you mentioned – the coming cold days will highlight the
vulnerabilities of the situation, sadly, at great expense to many.
Are companies which produce it profitable or they survive by generating a parallel stream
of junk bonds and evergreen loans?
Most of them are also shale oil producers and might well depend on revenue from shale oil
to produce gas. Shale oil proved to unsustainable at prices below, say $65-$75 per barrel or
even higher, excluding few "sweet spots". Also a lot of liquids the shale well produce are
"subprime oil" that refiners shun.
They are not only much lighter but also they have fewer hydrocarbons necessary for
producing kerosene and diesel fuel. Mixing it with heavy oil proved to be double edged sword
and still inferior to "natural" oil. So right now the USA imports "quality" oil and sells its
own" subprime oil" at discount to refineries that are capable of dealing with such a mix.
Say, buying a barrel for $60 and selling a barrel of "subprime oil" at $30.
And without revenue from oil and liquids it can well be that natural gas production might
be uneconomical.
I wonder what percentage of the total US oil production now is subprime oil.
Modern multistage shale well now cost around $7-10 million. And that's only beginning as
its exploitation also costs money (fuel, maintenance, pumping back highly salinated and often
toxic water the well produces, etc). So neither oil nor gas from such wells can be very
cheap.
Generally such a well is highly productive only the first couple of years. After that you
need to drill more.
Also there is a damage to environment including such dangerous thing as pollution of
drinking water in the area,
So, is there a big wall of US shale oil coming from Texas that will dash my "happy times" of
$55-65 WTI?
So thankful to get up to this level after 36 months of headaches about the oil price.
Seems the only thing that could screw it up is US shale, which apparently is set to explode
in 2018.
I saw someone touting Halcon stock today on SA. Making a big deal about having little
debt. Too bad they flushed about $3 billion of debt when they went BK. I'm sure Mr Wilson
(CEO) is, "still getting his" so to speak.
My brother is griping about why he hasn't been able to draw a salary for the last three
years, heck all the shalie management has! Have to remind him we aren't in the shale fantasy
land. He knows, he's just blowing like I'm prone to do.
If I don't post anymore this year, happy New Year everyone!! Things are looking up, just
hope the shale industry doesn't torch it again!
IN my view you will be sleeping well in the next year. Shale increases mostly the supply
of condensate and light distillates, which does little to cover the worldwide shortage of
middle distillates. So, the price of 'real' oil will very likely increase over the next
future whereas the prices of light distillates (propane, butane, pentane , LPG, NGPL
composite .. ) are very likely depressed. Light distillates can substitute middle distillates
to some degree, yet the potential is limited. So, in that sense I wish you a happy and
successful New Year.
There is no question, Shale is a disaster for investors. Nevertheless, it is a blessing for
Wall Street as high oil and gas production ensures dollar stability and a growing bond
bubble. The only question is when will investors will wake up. As it is perfectly OK for
small companies to sacrifice themselves and burn the cash of investors through, big companies
are less willing to do so. Who is next? XOM, Statoil , APA ?
The ratio of commodities / S&P500 is at a record low, S&P_GSCI / S&P_500
The S&P GSCI currently comprises 24 commodities from all commodity sectors – energy
products, industrial metals, agricultural products, livestock products and precious
metals.
Bloomberg chart on Twitter: https://pbs.twimg.com/media/DSCfWj6W4AA7xyW.jpg
Discoveries of new reserves this year were the fewest on record and replaced just 11
percent of what was produced, according to a Dec. 21 report by consultant Rystad Energy.
While shale wells are creating a glut now, without more investment in bigger, conventional
supply, the world may see output deficits as soon as 2019, according to Canadian producer
Suncor Energy Inc.
Are we not now near enough to 2019 to say that there just isn't time to bring major new
conventional projects on-line before mid to late 2019? The only offshore projects that could
be approved and developed earlier than that would be single well tie backs using the
wildcat/appraisal well as a producer, probably no more than 5 to 10 kbpd and in immediate
(and likely rapid) decline, and would be dependent on there being spare processing capacity
on a nearby hub (i.e. production the new production would be mitigating decline not adding
output).
But the issue isn't lack of discoveries this year, as the headline implies, it's the lack of
recent FIDs which might be in part because of the drop off in discoveries in 2012 to 2015
(for all oil, but particularly easily developed oil), coupled with high debt loads, and
prices that aren't high enough (or at least not yet for long enough) to allow development of
what resources there are available to the IOCs. As prices rise and IOCs become more confident
and are able to pay dividends as well as fund longer term developments then the really low
discoveries in 2015 to 2017 might give them far fewer options than people expect (noteworthy
is that any discoveries in that period that have been attractive, like Liza, have been
immediately fast-tracked, so there really isn't much of a backlog of attractive projects at
all).
I was basing my comment on what the article said. Many of the companies are aware that
discoveries have been low and not many projects will be coming online soon.
Mexico may be heading for a period of accelerated decline (above 10%). Their two onshore
regions and the southern marine region are falling at 15 to 20%, and the largest producing
region (Northern Marine, which includes KMZ and Cantarell) looks like it may be starting to
accelerate. The non KMZ nd Cantarell fields had been the only ones increasing, but look to
now be in decline or at least on plateau, and by PEMEX forecast KMZ should be off plateau in
the next couple of months or so. Mexico has now stopped exporting light oil (which mostly
comes from the three smaller regions, with KMZ and Cantarell producing heavy and medium
heavy) and will presumably be looking for increasing imports of it, which is probably good
for the Texas LTO producers. Operating rigs have recently been declining fast.
Do you have any information on how the ramp up of production is going for the Western
isles project following first oil on 15th November. On a side it looks like the Weald basin myth is starting to unravel.
Not yet -first numbers for December start-up should be in March, it's a question of limiting
their losses at current prices I think. All the wells were predrilled so ramp up should be
fast but I wouldn't be surprised if they get pretty low reliability in the first 6 to 12
months given all the construction problems they had. Also interesting that Catcher started up
on time, against most expectations. Wonder if Clair Ridge will make it this year – do
you know if there are big tax benefits from depreciation for starting within a given calendar
year in the UK (or might be financial yar end is more important)?
This shows how fast the SW marine region fields are now falling (a lot of small fields were
added 2007 to 2015 and are now in steep decline).
There seems no reason this and the two land regions shouldn't continue to fall at current
rates (they may even accelerate given how the rig count has dropped), and if KMZ follows the
predicted PEMEX curve Mexico could drop around 350 kbpd this year, possibly the same in 2019
in decline (but with 60 kbpd additions due from Abkatun), but maybe approaching as low as
1000 kbpd by mid 2020, which is probably the earliest ENI will be able to get their shallow
water field on line if they fast track it.
CALGARY -- Imperial Oil says its much-delayed $16.1-billion project to build a natural
gas pipeline across the Northwest Territories from the coast of the Beaufort Sea to northern
Alberta has finally been cancelled.
Originally the plan was to increase Majnoon to over 1 mmbpd. That has now been downgraded
to 400 kbpd (from current 220). Shell and Petronas have pulled out and a "government panel"
will oversee the development. I'd bet on continued decline rather than any increase, and
potential for significant reservoir damage along the way.
Similarly for Nasirya oil field – intend is to increase from 90 kbpd to 200, using a
local oil company that also sounds like it has a lot of government input.
To me none of this ever declining brownfield development with IOCs pulling out, and
promises of more exploration "coming" is compatible with the claims for their discovered
resources (developed or not), or any chance of a quick ramp up if oil prices start to inflate
rapidly after 2018.
So far, the experiences about freeze off Shale wells are limited. Will glycol also work for
Shale wells when there is much water involved? I think nobody knows yet how big the impact of
the cold will be on Shale wells. However, it looks like shorts are getting hyper-nervous.
Oil and Gas Producers Find Frac Hits in Shale Wells a Major Challenge In North America's most active shale fields, the drilling and hydraulic fracturing of new
wells is directly placing older adjacent wells at risk of suffering a premature decline in
oil and gas production.
The underlying issue has been coined as a "frac hit." And though they have long been a
known side effect of hydraulic fracturing, frac hits have never mattered or occurred as much
as they have recently, according to several shale experts who say the main culprit is infill
drilling.
"It is a very common occurrence -- almost to the point where it is a routinely expected
part of the operations," said Bob Barree, an industry consultant and president of
Colorado-based petroleum engineering firm Barree & Associates.
He added that frac hits are also an expensive problem that involve costly downtime to
prepare for, remediation efforts after the fact, and lost productivity in the older wells on
a pad site.
A frac hit is typically described as an interwell communication event where an offset
well, often termed a parent well in this setting, is affected by the pumping of a hydraulic
fracturing treatment in a new well, called the child well. As the name suggests, frac hits
can be a violent affair as they are known to be strong enough to damage production tubing,
casing, and even wellheads https://www.spe.org/en/jpt/jpt-article-detail/?art=2819
FWIW The first SPE paper referenced discusses mediating the negative nature of frac hits.
It discusses the refrakking of a six well pad drilled in 2010 in the middle Bakken and three
forks, North Fork Field, McKenzie. The six wells have a cumulative oil production to date of
3.6mmboe and 7.7bcf.
Since I am not in the field, much of the paper went over my head, I merely skimmed through
it, however it appears that well communication was observed for horizontal and vertical
spacing of 1000 feet.
"... Old "classic" land-based oil fields deteriorate to the tune of 5% per year, while deep sea deteriorate more and subprime wells much more. You can probably double the figure for each, although much depends on particular geology. Infill drilling accelerates depletion, allowing to maintain high production for sometimes so changes can be abrupt. ..."
"... Moreover, with each year, "subprime wells" (multi-stage shale well) costs more and now are at a range of n 6-10 million depending on the number and the length of horizontals and number of fracking stages and other factors. Only few area (sweet spots) can recover this capital investment during the life of the shale well at current prices). More at around $80 and almost all around $100 per barrel. The later is also the price that KSA needs to remain solvent (rumored to be in low 90th). ..."
"... The shale oil produced in the USA is really "subprime" because large part of it has lower energy content (by 20% or more) and different mix of various hydrocarbons that "classic" oil. Especially condensate from gas wells. Which optimally can be used only as diluter for heavy oil. EIA does not differentiate between different types oil and use wrong metric (volume instead of weight). May be intentionally. ..."
"... Another factor is that world consumption continue to grow and will do so because population in large part of Asia and Africa is still growing and number of cars on the road increase each year requiring on average 1-1.4 MB/d additionally. ..."
"... By continuing its' easy money policies well past any recession or growth scare, the Fed has created a monster. Most shale companies aren't profitable and are in fact losing money using any kind of GAAP. However, cheap financing allows them to survive and "drill baby drill." The unintended consequences may include destabilizing Saudi Arabia to the point of an economic and political collapse. One can always hope ..."
"... Economic collapse in Venezuela due to low oil prices – good! Economic collapse in Saudi Arabia due to low oil prices – bad! Solution – extend cheap financing to Saudi Arabia via Aramco IPO! ..."
"... The 36″ North Sea Forties pipeline is currently shut down for repairs. Short and medium term prices will carry the effect of that supply loss. In the long term, unexpected developments are common. Considering how completely wrong so many oil analysts have been over the past ten years, including the IEA, there is not a lot of credibility in oil market predictions. ..."
My impression is that this a gap (could be intentional) between IEA statistics and predictions and the reality. This is propaganda
agency after all, with the explicit agenda of keeping the oil price for Us consumers low. So typically that produce too "rosy"
forecasts that later are quietly corrected. Their short-term forecasts are based on oil futures and as such has nothing to do
with the reality on the ground. Which is quite disturbing.
It is undeniable that shale boom which played such a beneficial role for the USA allowing to squeeze oil price (with generous
help from KSA) for two and half years is dead.
Now is kept artificially alive by junk bonds and directs loans that will never be repaid. In other words, the USA now enjoys
a period of "subprime oil. Unless there is a new technological breakthrough there will be an only minor improvement in efficiency
of drilling and oil extraction in the next couple of years, but the lion share of those was already implemented, and on the current
technological level we are close to the "peak efficiency" in drilling and services.
Those minor efficiencies will be negated by rising prices of service industries, which can't take the current pricing any longer
and need to raise prices for their services.
Old "classic" land-based oil fields deteriorate to the tune of 5% per year, while deep sea deteriorate more and subprime
wells much more. You can probably double the figure for each, although much depends on particular geology. Infill drilling accelerates
depletion, allowing to maintain high production for sometimes so changes can be abrupt.
In any case each year you need somehow to find 5 MB/d of oil, finance new wells in those areas and infrastructure required.
All Us shale production is around 6 MD/day. So you get the idea.
Moreover, with each year, "subprime wells" (multi-stage shale well) costs more and now are at a range of n 6-10 million
depending on the number and the length of horizontals and number of fracking stages and other factors. Only few area (sweet spots)
can recover this capital investment during the life of the shale well at current prices). More at around $80 and almost all around
$100 per barrel. The later is also the price that KSA needs to remain solvent (rumored to be in low 90th).
The shale oil produced in the USA is really "subprime" because large part of it has lower energy content (by 20% or more)
and different mix of various hydrocarbons that "classic" oil. Especially condensate from gas wells. Which optimally can be used
only as diluter for heavy oil. EIA does not differentiate between different types oil and use wrong metric (volume instead of
weight). May be intentionally.
So the future remains unpredictable but general trend for oil prices might be up with some spikes, not down. Although many
people, including myself, thought so in early 2015 ;-)
Another factor is that world consumption continue to grow and will do so because population in large part of Asia and Africa
is still growing and number of cars on the road increase each year requiring on average 1-1.4 MB/d additionally.
So it looks like the situation gradually deteriorate despite all efforts and related technological breakthrough which allow
to extract more from the old wells and more efficiently extract shale oil.
The problem is that new large deposits are very hard to find now and several previously oil-exporting countries gradually became
oil-importers. Mexico is one, which will be huge hit.
Obama administration screw the opportunity to move US consumers to hybrid cars so the situation in the USA deteriorates too
despite rise of percentage of more economical vehicle in the personal car fleet each year. Rumors were that they pursue vendetta
against Russia and that was primary consideration - to crash Russian economy and install a new "Yeltsin".
The USA generally is in better position then many other countries as the switch to natural gas and hybrid electric cars for
personal transportation is still possible. It already happened in several European countries for selected types of cars, buses
and trucks (taxi, in-city buses and "daily round trip or short trips trucks).
But there is no money for infrastructure anymore and for example many miles of US rail remain non-electrified. Burning diesel
instead.
As maintenance was neglected for two and half year disruption of existing supply might became more frequent. also mid Eastern
war is also a possibility with Trump saber-rattling against Iran. Recently the leak in undersea pipeline removed 0.5 MB/d from
the market and caused a price spike to $65 for Brent (WTI remains cheaper and never crosses $60 this time).
Also with a young prince in charge and the revolution against "old guard" KSA became more and more unstable so the next "oil
shock" might come from them. They also have problem of depletion which until now they compensated pitting more and more heavy
high sulfur oil deposits online. At some point they will be exhausted too. They also pitch for war with Iran, but they would prefer
somebody else to do heavy lifting.
The only one or countries still can significantly increase oil production now – Libya (were we have problem because of the
civil war after US-sponsored Kaddafi removal and killing), and Iraq where there are still untapped areas that might contain some
oil; nothing big, but still substantial in the range of 1 MB/d. Looks like Iran now exports all it could. Same is true for KSA
and Russia. In this sense OPEN oil production cuts might an attempt to preserve impression that they are untapped reserved. I
doubt that there are much and those cuts are just a reasonable insurance policy against quick depletion of existing wells as higher
price gives some space for innovation.
There is also such thing as EBITRA which gradually deteriorates everywhere and can become negative for certain types of oil
(for oil sands it depends on the price of natural gas and they are primary candidate if the price doubles or triples from the
current level).
By continuing its' easy money policies well past any recession or growth scare, the Fed has created a monster. Most shale companies
aren't profitable and are in fact losing money using any kind of GAAP. However, cheap financing allows them to survive and "drill
baby drill." The unintended consequences may include destabilizing Saudi Arabia to the point of an economic and political collapse. One
can always hope
Economic collapse in Venezuela due to low oil prices – good!
Economic collapse in Saudi Arabia due to low oil prices – bad!
Solution – extend cheap financing to Saudi Arabia via Aramco IPO!
Meanwhile, China says it will be moving to all-electric cars and trucks to help solve its horrible urban air pollution problem.
. . Meaning global demand has nowhere to go but down.
Why do I feel that this will not end well for the American hegemon? Particularly with Trump in office working overtime with
boy genius Rick Perry to promote coal and sabotage renewable energy. . .
The 36″ North Sea Forties pipeline is currently shut down for repairs. Short and medium term prices will carry the effect of
that supply loss. In the long term, unexpected developments are common. Considering how completely wrong so many oil analysts
have been over the past ten years, including the IEA, there is not a lot of credibility in oil market predictions.
"... The fact is that the rise of the West to global dominance is due to a historical anomaly. It was fuelled (literally) by the discovery and harnessing of the chemical energy embedded in coal (late 18thC) and then oil (late 19thC). The first doubled the population, and as first movers gave the West a running start. The second turned on the afterburners, and population grew >3.5 fold. Again the West led the way. To fuel that ahistorical step-function growth curve, control of resources on a global scale became its civilizational imperative. ..."
From Patrick Armstrong's article (a good one, by the way):
A Russian threat is good for business: there's poor money in a threat made of IEDs, bomb
vests and small arms. Big profits require big threats.
Actually, I'd say the Russian threat is necessary to keep the Europeans too
frightened to protest while the U.S. steals wealth from them. After all, when the U.S.
imports goods and "pays" for them with printed money, it is basically stealing those goods.
The U.S. is draining a lot of wealth from Europe (like $150 billion a year), so something
must be done to keep them docile. Russia's perfect for that.
"(Failed) West and a multipolar Rest". The latter is what I think will actually happen
in the near and medium term.
I think we already have it, except I don't think West has failed yet. Or it has in a way,
the process of failing goes on, but the consequences have not been felt much in the West
yet.
Well, exogenous events aside, "decline and fall" is necessarily a process. A
series of steps and plateaus is typical. A major step occurred in 2007/8, when the money
failed. The bankers, in a frankly heroic display of coordination, propped up the $$$ and the
West got a decade long plateau. Things are going wobbly again, financially speaking and I
suspect the next step function to occur rather soon. Stays of execution have been exhausted, so
it'll be interesting how the West handles it, and how the RoW reacts.
Europeans have been invited to join the Eurasian Project, to create a continental market from
"Lisbon to Vladivostok". Latent dreams of Hegemony hold at least some of their elites back. The
USA has also been invited, but its dreams remain much more virile. That is, until Trump who's
backers seem to read the writing on the wall better than the Straussians.
I don't see any other power than the West (=US) aspiring to 'manage the world'....
The other 'powers' have very modest, regional aspirations... US seems to be obsessed with it.
The fact is that the rise of the West to global dominance is due to a
historical anomaly. It was fuelled (literally) by the discovery and harnessing of the chemical
energy embedded in coal (late 18thC) and then oil (late 19thC). The first doubled the
population, and as first movers gave the West a running start. The second turned on the
afterburners, and population grew >3.5 fold. Again the West led the way. To fuel that
ahistorical step-function growth curve, control of resources on a global scale became its
civilizational imperative.
That growth curve has plateaued, and the rest of the world has caught/is catching up
developmentally. The resources the West needs aren't going to be available to it in the way
they were 100 years ago. Them days is over, for everybody really, but especially for the West
because it has depleted its own hi-ROI resources, and both of its means of control (IMF$ System
& U$M) of what's left of everybody else's are failing simultaneously. So its plateau will
not be flat, or not flat for long between increasingly violent steps.
The West rode an ahistorical rogue wave of development to a point just short of Global
Hegemony. That wave broke, and is now rolling back out into the world leaving the West just
short of its civilizational resource requirements. No way to get back on a broken wave. In any
case, China now holds the $$$ hammer, and Russia holds the military hammer, and they've now got
the surfboard. Both of them, led by historically aware elites, know that Hegemony doesn't work,
so will focus on keeping their neck of the woods as stable & prosperous as possible while
hell blazes elsewhere.
What is really going on is that West has over-reached and can barely handle its own
problems.
IMHO, what's really going on is that the West's problems are simply symptomatic of
what "decline and fall", if not "collapse" looks like from within a failing system. A long time
ago I read the diary of a Roman nobleman who in the most matter-of-fact style wrote of exactly
the same things Westerners complain about today. How this, that or the other thing no longer
works the way it did. For all of his 60+ years, every day was infinitesimally worse than the
day before, until finally he decides to pack up his Roman households and move to his estates in
Spain. It took 170(iirc) more years of continuous decline until Alaric finally arrived at the
Gates of Rome. If wholly due to internal causes, collapse is almost always a slow motion train
wreck.
...
'there would be a vacuum' and 'Russians would move in'. This is obvious nonsense and only
elderly paranoid Cold Warrior types believe it (peterAUS?).
Actually, it's just stupid. Cold Warrior or not, the view betrays a deep and
abiding ignorance of both history and a large part of what drove the West's hegemonic
successes. That both militate against anyone else ever even trying such a thing on a global
scale can't be seen if you look at historical developments and the rest of the world through
10' of 1" pipe.
The idea that Russia wants/needs the Baltics is even more laughable than that it wants/needs
the Ukraine or Poland. None of these tarbabies have anything to offer but trouble. Noisome
flies on an elephant, it is only if they make themselves more troublesome as outsiders than
they would be as vassals would Russia move.
Venezuela's oil production has been sliding for years, but the descent accelerated in 2015
amid low oil prices and a deteriorating cash position for PDVSA and the government. Production
dipped below 1.9 million barrels in recent weeks, the lowest level in more than three
decades.
The problems will only grow worse, especially because they tend to snowball. Without cash,
PDVSA will struggle to import diluent to blend with its heavy oil – the result could be
steeper production losses. Again, without cash, existing facilities cannot be maintained,
likely leading to an accelerating pace of decline. An array of refineries are "completely
paralyzed," the head of an oil workers union told Bloomberg. Defaults on more debt payments
could spark retaliation from creditors, which could eventually put oil exports in jeopardy.
In short, the woes in Venezuela's oil industry contributed to the crisis, but the dire
economic situation will accelerate the decline of oil production.
A group of analysts told Bloomberg that they expect Venezuela's output to average 1.84 mb/d
in 2018, a level that seems surprisingly optimistic given the pace of decline underway. Other
analysts predict output will plunge much lower.
Venezuela's oil production has been sliding for years, but the descent accelerated in 2015
amid low oil prices and a deteriorating cash position for PDVSA and the government. Production
dipped below 1.9 million barrels in recent weeks, the lowest level in more than three
decades.
The problems will only grow worse, especially because they tend to snowball. Without cash,
PDVSA will struggle to import diluent to blend with its heavy oil – the result could be
steeper production losses. Again, without cash, existing facilities cannot be maintained,
likely leading to an accelerating pace of decline. An array of refineries are "completely
paralyzed," the head of an oil workers union told Bloomberg. Defaults on more debt payments
could spark retaliation from creditors, which could eventually put oil exports in jeopardy.
In short, the woes in Venezuela's oil industry contributed to the crisis, but the dire
economic situation will accelerate the decline of oil production.
A group of analysts told Bloomberg that they expect Venezuela's output to average 1.84 mb/d
in 2018, a level that seems surprisingly optimistic given the pace of decline underway. Other
analysts predict output will plunge much lower.
"... To render credible analysis of the future of unconventional shale resources in America one must have had actual first hand experience in the actual business of oil extraction. In other words, one must have had to write checks to drill wells, write checks to pay operating costs, write checks to the Federal government for taxes, write check after check, etc, etc., and watch their net revenue drop like a rock every month. Ignoring debt and economics to simply say there is 40GBO of recoverable shale oil in America is, forgive me, not in the least bit credible. ..."
"... The EIA, the IEA, almost every predictor of the future ignores the economics of shale extraction and it's debt. Those predictions are therefore meaningless. Hoping for higher oil prices to make the future work out like you want it to is not a tactic, it is not a plan. It is a disservice to people searching for knowledge. ..."
"... So, ignore the Million Dollar Way thing, and Michael Filloon, the self serving dribble in investor presentations, the "we are going to unleash America's oil 'might' on the rest of the world" Perry/Trump bullshit and listen instead to Shallow Sand. He has written some checks in his day. Best not run him off. ..."
In the interest of those few oily readers you have left on POB, Dennis (I see you ran Guy, a knowledgeable royalty owner from
Texas, off with that stupid comment about the Texas Railroad Commission), lets NOT say what you said.
Instead lets say that at $50 dollar hedged oil prices the net back, take home pay for a Bakken operator is actually $20 a barrel.
And it is. Costs are not going down, they are going up, and longer laterals and enormous frac's make true well costs actually
closer to $9M. Such a well would therefore require 450,000 BO to payout.
Some very learned people on this site, actually knowledgeable about the oil industry, who are now also gone, have proven it
will take $85 dollar plus oil prices, sustained, for the unconventional shale oil industry to pay back its debt and simply be
able to replace reserves. The days of all this enormous 'growth' crap are over.
To render credible analysis of the future of unconventional shale resources in America one must have had actual first hand
experience in the actual business of oil extraction. In other words, one must have had to write checks to drill wells, write checks
to pay operating costs, write checks to the Federal government for taxes, write check after check, etc, etc., and watch their
net revenue drop like a rock every month. Ignoring debt and economics to simply say there is 40GBO of recoverable shale oil in
America is, forgive me, not in the least bit credible.
The EIA, the IEA, almost every predictor of the future ignores the economics of shale extraction and it's debt. Those predictions
are therefore meaningless. Hoping for higher oil prices to make the future work out like you want it to is not a tactic, it is
not a plan. It is a disservice to people searching for knowledge.
So, ignore the Million Dollar Way thing, and Michael Filloon, the self serving dribble in investor presentations, the "we
are going to unleash America's oil 'might' on the rest of the world" Perry/Trump bullshit and listen instead to Shallow Sand.
He has written some checks in his day. Best not run him off.
"... I have mentioned this before, but SERIOUS TROUBLE will come down hard on the Bakken. Looks like someone hasn't been honest about its production figures. ..."
"... Fireworks will arrive shortly .. hehehe. ..."
I have mentioned this before, but SERIOUS TROUBLE will come down hard on the Bakken. Looks like someone hasn't been honest
about its production figures.
active wells increased by 158 from August to Sept and output increased by 19 kb/d for the Bakken Three Forks to 1055 kb/d.
Only 77 new wells were completed in the North Dakota in August 2017 and output increased that month by 23 kb/d.
They have added over 1,100 Bakken and/or Three Forks wells to boost production back to where it was in March, 2016.
So, conservatively $8 billion spent just to climb back up.
The amount of capital being burned on energy in the USA is truly remarkable.
Dennis, I have seen data that shows the total cost of all "shale" oil and gas wells from maybe 2003 forward, and then the gross
proceeds from same. Very interesting how far from payout the USA wells are, in aggregate.
This May 20, 2016 post was probably two years early ;-) I remember looking back on the IEA's 2005 World Energy Outlook and being perplexed that
anyone still takes their price or production forecasts with any seriousness whatsoever. Their 2003 WEO is even more hilarious.
Notable quotes:
"... Eventually market sentiment focused on the recency bias of a 2 year glut is going to shift into the realization that disruptions, depletion, and growing demand have thrown the global balance into a dearth where inventories are being drawn to meet demand – such as the news about Saudi's relying on inventory to meet demand, the "missing" 800,000,000 barrels of OECD inventory from Q1 2016, or next weeks inevitable U.S. inventory draw. ..."
"... Suddenly, an extra outage (like say if anything happens to Venezuela) will cause meaningful rallies instead of being mostly written off. ..."
"... The best, live, interactive charts I am most fond of are here: https://www.dailyfx.com/crude-oil ..."
"... I expect one last fight around $50, a few day consolidation move lower. Then market realities will push WTI past $50, and shorts will have to cover pushing it even higher. ..."
"... Next thing you know were range bound in the mid-$50s at the end of June as everyone questions if shale production will magically skyrocket overnight. Maybe the rig count will go up by 3 or 4, and it'll spark a sell-off back to or below $50 because of the psychological recency bias of a "repeat of 2015". ..."
"... I remember looking back on the IEA's 2005 World Energy Outlook and being perplexed that anyone still takes their price or production forecasts with any seriousness whatsoever. Their 2003 WEO is even more hilarious. ..."
"... Most people are simply incapable of seeing a bigger picture, and they'll simply never understand the relationship between depletion, economic and population growth, and the long-term fact that this equals higher prices (and probably also, in the long run, higher poverty and unemployment). ..."
"... It is for that exact same reason that so many people we know will simply never get it. Physics doesn't have agency, it cannot be avoided, cajoled, or "blamed". It simply is, and that is so unsettling to our psyche that most people have a strong, unconscious drive to negate and ignore that conclusion even if they will acknowledge it is a sound and true explanation of how economics, growth, employment, wealth, energy (physics and thermodynamics), and depletion are woven of the same fabric. ..."
"... Brian – I think you are closer to reality than EIA or USGS, it will be interesting to see how it plays out against your scenario. ..."
"... There doesn't necessarily have to be more social breakdown in Venezuela to have an impact – Haliburton and Schlumberger are pulling out and will have immediate effect as the extra heavy oil production needs continuous attention to the wells. I'm surprised Angola and Algeria haven't seen disruptions yet either. ..."
"The joint-venture Syncrude project told customers to expect no further crude shipments for May, trading sources said on Thursday,
extending a force majeure on crude production from earlier in the month."
Eventually market sentiment focused on the recency bias of a 2 year glut is going to shift into the realization that disruptions,
depletion, and growing demand have thrown the global balance into a dearth where inventories are being drawn to meet demand –
such as the news about Saudi's relying on inventory to meet demand, the "missing" 800,000,000 barrels of OECD inventory from Q1
2016, or next weeks inevitable U.S. inventory draw.
Suddenly, an extra outage (like say if anything happens to Venezuela) will cause meaningful rallies instead of being mostly
written off.
In fact, judging by the price action on oil over the last 24 hours, I'd say that sentiment is very close to a shift. From 11
AM forward crude oil marched higher relentlessly, even in opposition to dollar strength. Most every single commodity was down,
as we're most every stock market except oil.
I expect one last fight around $50, a few day consolidation move lower. Then market realities will push WTI past $50, and
shorts will have to cover pushing it even higher.
Next thing you know were range bound in the mid-$50s at the end of June as everyone questions if shale production will
magically skyrocket overnight. Maybe the rig count will go up by 3 or 4, and it'll spark a sell-off back to or below $50 because
of the psychological recency bias of a "repeat of 2015".
That is, until rational minds, or the market itself pushes prices back up as it becomes obvious that a slowdown in U.S. production
declines will mean little in the face of mounting production declines around the globe, and "surprisingly" strong demand – because
apparently predicting that lower prices will cause stronger than average demand growth is beyond the economic capability of the
EIA or IEA, and markets tend to take their word as gospel.
I remember looking back on the IEA's 2005 World Energy Outlook and being perplexed that anyone still takes their price
or production forecasts with any seriousness whatsoever. Their 2003 WEO is even more hilarious.
Every step of the way analysts and talking heads will be confused that prices aren't dropping back to $30 just like they were
for 5 straight years from 2003 to 2008. They'll predict Saudi's will raise production to 12 mbpd any day now, or that shale will
magically take off overnight.
They'll never even realize that they don't understand the history of Saudi production, or the logistical and financial complexities
of shale production rising as fast as it did before. Instead they'll blame the banks, or speculators, or Big Oil for artificially
making oil prices rise (without questioning why they let them fall for 2 years in the first place)
But then again if gas is cheap, which average people are fond of, their brain says "I like this, so it must be right". If gas
is expensive their brain says "I don't like this, it must be wrong, what evil force made this happen?!?"
Most people are simply incapable of seeing a bigger picture, and they'll simply never understand the relationship between
depletion, economic and population growth, and the long-term fact that this equals higher prices (and probably also, in the long
run, higher poverty and unemployment).
Their lives will have ups and down, growth and recession, but they'll know and feel it is generally getting harder. They'll
never be aware that this is the "fault" of nothing but physics and thermodynamics, even if told directly and shown all the rather
clear evidence (I know every one of you has experienced this as I have). Instead, they'll blame those dang immigrants, or the
Chinese, or the Congress, or regulations.
They'll blame anything that fits their paradigm enough to allow cohesiveness so their fragile lives can at least MAKE SENSE.
You can't blame physics, and, frankly, I think that is a large psychological barrier for people comprehending what is happening.
We need to have some agent to blame for things, and physics has no agency. Blaming something for a problem is settling because
it gives us something to focus on to solve the problem, or, at the very least, avoid it. The evolutionarily beneficial need to
assign agents as the cause of events is what pre-disposes us to believing that events we cannot easily assign agency to are, nonetheless,
the will of a greater, invisible, omnipresent agent.
It is for that exact same reason that so many people we know will simply never get it. Physics doesn't have agency, it
cannot be avoided, cajoled, or "blamed". It simply is, and that is so unsettling to our psyche that most people have a strong,
unconscious drive to negate and ignore that conclusion even if they will acknowledge it is a sound and true explanation of how
economics, growth, employment, wealth, energy (physics and thermodynamics), and depletion are woven of the same fabric.
Brian – I think you are closer to reality than EIA or USGS, it will be interesting to see how it plays out against your scenario.
A couple of other impacts are summer maintenance season in North Sea (Buzzard and, I think, Ekofisk have major turnarounds),
Alaska and Canada (maybe Russia as well) and increased demand from driving season in USA and AC use in Middle East.
There doesn't necessarily have to be more social breakdown in Venezuela to have an impact – Haliburton and Schlumberger
are pulling out and will have immediate effect as the extra heavy oil production needs continuous attention to the wells. I'm
surprised Angola and Algeria haven't seen disruptions yet either.
Thank you George. IEA will release their WEO next week (14th).
From the OPEC-report:
"Total non-OPEC liquids supply is now forecast to grow from 57 mb/d in 2016 to 62 mb/d in
2022, with the US alone making up 75% of that increase."
The section on decline rates was interesting too (p.184): "the WOO analysis suggests an
average implied decline rate of around 4.4 mb/d in the 2018–2028 period, or 7%, of
underlying non-OPEC suply. Note that this compares with previous, more in-depth, work done by
the Secretariat, which indicated
that underlying observed decline rates in non-OPEC were lower – on average around 5.4%
– though with significant regional variations.
On the one hand, this analysis shows the challenge facing the upstream sector, with a
requirement for more than 5 mb/d p.a. of new supply, if annual average demand growth of 0.9
mb/d in the Reference Case is added to the implied 4.4 mb/d 'lost' due to natural decline. On
the other hand, the calculated implied decline rates and substantial new upstream volumes
coming online suggest that overall upstream investment activity is perhaps higher than a
quick glance at headline capex numbers would suggest "
"with tight oil making up a substantial and growing share of total non-OPEC supply (around
12% in 2016), and given its innate rapid decline rates after initial production, this may in
a sense have accelerated the underlying decline. In other words, the system can said to be
coping, with supply growth meeting demand needs at the moment"
"that overall upstream investment activity is perhaps higher than a quick glance at headline
capex numbers would suggest "
Nope it would suggest that the developments coming on line now follow a normal project
S-curve with the big investment costs in the middle then slowing down during installation and
commissioning.
There aren't many projects in the middle of the development so costs are down but the new
production coming on line is still fairly high (until the second half of next year). The
investment problem isn't going to show up really until a couple of years out, but it can't be
halted by anything that's done now, just like the over-investment impact kept running even as
oil prices crashed.
With all the kerfuffle in Saudi whatever happened to the independent assessments of their
reserves? There was a leaked report that said everything was exactly as the Saudi had been
reporting, which couldn't possibly have credibility as it came out about a week after the
consultants had started work so they wouldn't even have got their computers working properly
yet, and then something about the reports being released early next year – and since
then nothing.
"... So perhaps Bakken oil production peaked in 2015. But that depends on how many new wells will be added the coming years. ..."
"... Regarding downspacing, it has been a real crapshoot throughout all the shale plays. Operators had been purposefully drilling closer and closer and monitoring results. The biggest influencing factors (among many) seems to be the permeability and brittleness of the rock. ..."
"... Utica operators are back to 1,000 foot spacing while Marcellus operators continue to drill 500′ or less. Again, the thickness of these formations plays a big role as 3 dimension, not 2, come into play. 80% production in offset wells is the commonly quoted figure from several operators, and they seem to be okay with that. ..."
"... Be advised, Bakken operators have recently changed their flowback procedures and early month produced water numbers have skyrocketed. New wells now show 150/200 thousand barrels produced water their first few months online. ..."
Thanks that is really interesting. As most wells in Bakken are 10000 feet long, 500 feet well
spacing would translate into about 5 wells per section in Bakken. As I mentioned some time
ago, the Grail area in McKensey has close to 5 wells per section now. The 2016 wells there
had worse production than previous years and they have almost stopped drilling new wells
there. As there are maybe 1500 well locations left in the sweet spot area of McKensey
(assuming 5 wells per section) and they are adding perhaps 40 wells per month now, it means
that there are only some 3 years of new wells left. But it's not like they will add 40 wells
per month and then suddenly stop.
So more and more wells need to come from outside the sweet spots the coming years. Because
of the red queen phenomena, if new wells start to produce less, then more wells are needed
just to keep total production flat. So perhaps Bakken oil production peaked in 2015. But
that depends on how many new wells will be added the coming years.
One needs to remember the Three Forks formation when doing those kind of calculations.
Some of the higher producing wells in North Dakota these past 2 years targeted the second
bench of the TF.
There have been very few third bench TF wells and, I believe, only a couple targeting the
fourth bench so far.
Regarding downspacing, it has been a real crapshoot throughout all the shale plays.
Operators had been purposefully drilling closer and closer and monitoring results. The
biggest influencing factors (among many) seems to be the permeability and brittleness of the
rock.
Utica operators are back to 1,000 foot spacing while Marcellus operators continue to
drill 500′ or less. Again, the thickness of these formations plays a big role as 3
dimension, not 2, come into play. 80% production in offset wells is the commonly quoted
figure from several operators, and they seem to be okay with that.
BTW, I appreciate the charts you regularly post here.
Be advised, Bakken operators have recently changed their flowback procedures and early
month produced water numbers have skyrocketed. New wells now show 150/200 thousand barrels
produced water their first few months online.
As much as
US$1 trillion
of investments has either been deferred or canceled
with the lower-for-longer oil prices, and this underinvestment will
impact the future of energy, Amin Nasser, the chief executive of Saudi
Aramco, said on Tuesday.
"Not much investments have been going into the
energy sector... $1 trillion has been either deferred or cancelled,"
Nasser said at the Future Investment Initiative conference in Riyadh.
Of the US$1 trillion investment, US$300 billion was earmarked for oil
exploration and another US$700 billion for project developments,
according to the CEO of the state-held oil giant of OPEC's biggest
exporter and de facto leader Saudi Arabia.
"This will have an impact on the future of energy if nothing happens,"
Nasser noted, adding that investments are necessary because of "natural
depreciation of fields and normal rise in demand."
"We are witnessing a transformation... But it will be decades before
renewable energy takes a major share in the energy mix," the head of the
oil giant said.
In July, Nasser said that if the oil and gas industry didn't start
investing again, the global oil supply/demand curve will
reach a turning point
in "a couple of years."
"About $1 trillion in investments have already been lost since the
current downturn began," Nasser said in a
speech
at
the World Petroleum Congress in Istanbul in July.
One of the world's largest fossil fuel companies is betting on electric cars.
Royal Dutch Shell (RDSA) revealed a deal on Thursday to acquire NewMotion, one of Europe's
largest electric vehicle charging providers. NewMotion specializes in converting parking
spots into electric charging stations. The Dutch firm has more than 30,000 electric charge
points in Europe.
The acquisition, Shell's first in this space, shows how Big Oil is being forced to confront
the long-term threat posed by electric cars and efforts to phase out gasoline and diesel
vehicles.
Or maybe the other way round – there's no oil left to develop so they have to find
something else to do – or both supply and demand influences, which is the reality of
all economic decisions, not one or the other however much the media feels it has to simplify
things to that level.
Interesting article. I believe we are going to see a more rapid disintegration of the
Ultra-Deepwater Drilling Industry when the markets finally correct by 20-50%. The notion that
the Ultra-Deepwater Drilling Industry will recover by 2020 or 2024 doesn't take into account
that the broader U.S. Stock markets have experienced a 230% increase from the lows without a
typical 15-20% correction.
Hell, I believe the S&P 500 just hit a record of not experiencing a 3% correction for
more than 453 days.
Transocean drilling rig utilization fell from a peak of 95% in 1H 2013 to 37% in the 1H
2017. Of the 17 Ultra-Deepwater rigs currently drilling for oil in the GoM (source: Baker
Hughes), one leased by Chevron was terminated early. So, the total will be down to 16 in
November.
Again, the wild card of much higher oil prices will only occur if the Fed and Central
banks start up the printing press BIG TIME. When the Fed's QE3 program ended, the price of
oil plummeted.
However, when the Central banks print like crazy, this won't last long. Thus, it won't be
enough to allow the Ultra-Deepwater Drilling Industry to recover.
No idea – I don't do the oil price prediction thing because I'm pretty sure nobody in
history has ever got it right for the right reason. For real 'frontier' type exploration to
start again then there would have to be a pick up in lease sales and really they have been
tailing off even in the high price years (I think I put some charts in a previous post on the
GoM showing how the percentage of offered leases taken up has been falling off. I doubt if
shallow a lot of the deep lease areas will pick up again though, there's little left.
In my opinion, exploration will not pick up too much regardless of oil price because of the
maturity of the basin, as George suggests above. (Actually, exploration may pick up a fair
bit with higher oil prices, but significant successes probably won't).
Now there certainly are those that would disagree with that, and, since I'm still in the
industry, I often hear the message about the tremendous remaining potential in the northern
deepwater GOM coming from those in the ra-ra corner.
Not much and no. I think, if anything, the future GoM production will be a bit less than I
expected about six months ago. As far as STEO goes I think they come up with a future profile
once a year and then just bias it up and down to meet this month's production number –
I think a new profile must be due soon. There is about a 10% decline per year, which might
increase a bit now, so about 170,000 bpd is needed to maintain a plateau, but the STEO has
another 100,000 per year of growth. Next year there is only Stampede early on, which has
topsides nameplate of 60,000, but only 50,000 planned with the rest available for tie backs
and probably only about 70% availability in the first year; plus Constellation – which
has maybe 30,000 but depends on decline in the rest of the Caesar-Tonga field to allow
capacity for some of it, so not all of that is net gain; the LLOG fields I described above;
and Big Foot at the end which won't contribute much in 2018. So from July 2017 to Dec. 2018
they lose maybe 230,000 and add about 90,000 to 110,000 maybe with a bit of brownfield as
well. There's also Atlantis North but I think that only maintains a plateau against fast
declines from their other wells. But EIA are saying the GoM adds 330,000. Also in 2019 Big
Foot isn't going to ramp up fast, contrary to what I previously thought. It has dry trees,
only two have been fully predrilled, the others have the top two conductor sections drilled
but the on-platform rig will have to complete them. I think the oil is pretty heavy so not
huge production from a single well, therefore even with a 70,000 nominal topsides nameplate,
the wells and the usual low availability in the first year will be limiting.
EIA's monthly production data to end of July says US production vs 2016 is averaging about
3.4 million barrels per month higher. divided by 30 is 114K bpd increase over last year
averaged month by month. (not month to month)
For Texas it's 90K bpd increase over last year, as of end of July, averaged month by
month. That's most of the 114K.
Don't know if that's far enough back in months for the correction we get here to have
moderated.
It contains a lot of interesting information. For example on page 15 we can see that oil
field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has
fallen of a cliff is not an exaggeration.
"... I already picked the peak, 2015. So I was slightly off, but not by all that much as you can clearly see by the chart. I think we are on the peak plateau right now. ..."
I already picked the peak, 2015. So I was slightly off, but not by all that much as you can
clearly see by the chart. I think we are on the peak plateau right now.
The actual 12-month
peak could be anywhere from 2017 to 2019 but no later than that. Well, in my humble opinion
anyway.
The question was about US LTO, you have picked the World C+C peak, but as far as I
remember you have not said anything recently about US LTO except that it will be before
2025.
So far the 12 month centered average for US LTO peaked in June 2015.
If US LTO output continues at the August output level (4750 kb/d) for 5 months, then a new
12 month centered average peak will be reached by Aug 2017 (average output from Feb 2017 to
Jan 2018). US LTO output has risen about 600 kb/d over the past 12 months so an assumption of
no further US LTO output increases over the next 5 months is a conservative estimate in my
view.
"... A bit old so you may have seen it already. But if you haven´t then I highly recommend you to read the global oil supply report from HSBC: YouTube clip: https://www.youtube.com/watch?v=7KfVJBNX2U4 The report: https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view contains a lot of interesting information. For example on page 15 we can see that oil field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has fallen of a cliff is not an exaggeration. ..."
Iraq's oil production has increased by 1.4 million b/day since oil prices last averaged $100
in July 2014. More than any other country
Chart on Twitter: https://pbs.twimg.com/media/DMHrqLZXkAAFiro.jpg
The report:
https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view contains a lot of interesting information. For example on page 15 we can see that oil
field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has
fallen of a cliff is not an exaggeration.
Great to see you posting an update. I can honestly tell you that the "WEIRD" rise in
production per well in the Bakken may not be as high as the data shows. Unfortunately, I
can't publicly state the reason I know this. If you contact me via my email address: [email protected] , I can provide a few more
clues.
However, the SHITE is going to hit the fan in the U.S. Shale Oil Industry once this news
gets out which will likely be made public shortly.
2017-10-11 BSEEgov: From operator reports, it is estimated that approximately 32.68 percent
of the current oil production in the Gulf of Mexico remains shut-in, which equates to 571,854
barrels of oil per day. It is also estimated that approximately 20.51 percent of the natural
gas production, or 660.55 million cubic feet per day in the Gulf of Mexico is shut-in.
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-tropical-storm-nate-activity-4
Estimate of "Lost" Gulf of Mexico crude production due to Hurricane Nate is 7.82 million
barrels of oil.
(Possible paywall, I can't quite figure out how it works on Energy Voice)
"This is particularly evident when we look at investment. While investments are expected
to pick up slightly this year and in 2018, it is clear that this is not anywhere close to
past levels and it is more evident in short-cycle, rather than long-cycle projects, which are
the industry's baseload.
"The issue of a potential investment shortfall was a recurring theme at last week's
Russia Energy Week conference, with President Vladimir Putin, as well as many oil and
energy ministers making reference to the critical investment challenge.
"As we have all learned from previous price cycles, such pronounced and long-term
declines in investments are a serious threat to future supply. But given our projected
future demand for oil, with our upcoming World Oil Outlook 2017 expecting demand to reach
over 111 million barrels a day by 2040, an increase of almost 16 million barrels a day, the
world simply cannot afford a supply crunch."
It's noticeable that OPEC, IEA and drillers/service companies, even the Aramco CEO are
raising the lack of investment more and more, but they all stay away from discussing the fall
in discoveries and lack of attractive prospective projects. Part of it is real concern,
though it's noticeable they don't offer much in the way of solutions, and definitely none
that might impact their bottom lines in the short term, but part is pre-emptive
arse-coverage.
A lot of factors seem to be lining up for an economic bust next year, but then they have
looked like that for a few years (maybe the low oil price has contributed to staving off the
problem), if it happens a supply crunch might go unnoticed for some time, and only come
appear as the real problem it will be when there is some sort of recovery expected.
"... This year's rise is likely to be closer to about 500,000 barrels, far off an initial forecast by the U.S. Energy Information Administration, according to Hamm, the chairman of Continental Resources Inc. and a pioneer in the shale industry. ..."
"... The EIA projection is "just flat wrong," failing to take into account a new discipline among U.S. drillers, Hamm said in an interview Thursday on Bloomberg TV. "We have capability of producing a whole lot, but you have to get a return on investment," he said, adding, "that's where people have been this last quarter and this year." ..."
"... . "When we're lagging the Brent world price by $6 a barrel, that's not putting America first, that's putting America last. And that's the result of this exaggerated amount that EIA has out there." ..."
"... Once it's clear the EIA is off base, prices could rise to $60 a barrel from around $50 now, Hamm said. ..."
Shale oil entrepreneur Harold Hamm is back doing interviews on the business networks again.
Now he is speaking out against how the oil prices are low due to the EIA.
Shale Billionaire Hamm Slams 'Exaggerated' U.S. Oil Projections
Billionaire oilman Harold Hamm says the government was way too optimistic with its
prediction of more than 1 million new barrels a day in U.S. production, and the snafu is
"distorting" global crude prices.
This year's rise is likely to be closer to about 500,000 barrels, far off an initial
forecast by the U.S. Energy Information Administration, according to Hamm, the chairman of
Continental Resources Inc. and a pioneer in the shale industry.
The EIA projection is "just flat wrong," failing to take into account a new discipline
among U.S. drillers, Hamm said in an interview Thursday on Bloomberg TV. "We have capability
of producing a whole lot, but you have to get a return on investment," he said, adding,
"that's where people have been this last quarter and this year."
The government scenario has contributed to worries about an oversupply that puts U.S. oil
at a steep discount to international crude, according to Hamm. "It's distorting," he said
. "When we're lagging the Brent world price by $6 a barrel, that's not putting America
first, that's putting America last. And that's the result of this exaggerated amount that EIA
has out there."
Once it's clear the EIA is off base, prices could rise to $60 a barrel from around $50
now, Hamm said.
The EIA is making these projections because knuckleheads in the C suite at US shale companies
went hog wild at the first sign of oil price improvement and made these growth projections
for their individual companies, and the EIA just totaled them up.
Every Shale CEO bashes OPEC. OPEC tried to give shale a break by cutting production, and
shale absolutely blew it, just like shale absolutely blew it in late 2014 by not pretty much
shutting down. Instead, shale has lied about profitability for 3 years, and the world E &
P industry has paid the price.
Too bad Oilpro shut down. Lots of non-US E & P Industry folks posted there. They
absolutely could not stand US shale and the US shale CEO smack talk. Hundreds of thousands
out of work, because of shale smack talk and Wall Street encouragement of same, which crashed
oil prices below $30.
Shale better come through. No one seems to be taking serious the possibility of a supply
shock if it cannot.
When shale clearly peaks, what is to keep OPEC and Russia from suddenly making a big cut,
driving prices past $200 and crashing Western economies? Why wouldn't they afterthe hubris of
US shale CEO's, the Wall Street guys who pull their strings, and the US business media who
report everything they say as gospel?
I'd guess a lot of the non-US E&P people complaining about LTO would by from offshore,
and I think that side has been just as much to blame for boom and bust mentality with rose
tinted specs. (see below the UK investment which went nuts when oil went above $100 and now
they have nothing much left). I'd question with the jobs are going to come back offshore even
with a big price rise. As I keep pointing out, there have to be discoveries before
development, and there have to be lease sales before that. We're not seeing either, and
though exploration is down compared with 2011 to 2014, there's still a significant amount
going on, but wildcat, frontier success rates are what have fallen the most (even with the
best seismic methods and computer models we have ever had).
Shallow, I too miss the hell out of Oilpro. That community could debate the unconventional
shale phenomena without bias and with a clear understanding of how it has completely changed
the world oil order.
American's, on the other hand, simply enjoy cheap gasoline; they don't care how they get
it, what it costs, who ultimately pays for it or that it will not last forever. The American
public, and the politicians that govern it, have been lied to and completely deceived about
shale oil and shale gas abundance. It is a matter of American nationalistic pride to believe
what one reads on the internet and to otherwise be stupid about our hydrocarbon future.
I suggested to you several years ago that OPEC and the rest of the world's producing oil
countries were not dumb; they read shale oil K's and Q's and have the same access to SEC
filings we do. They know the shale oil phenomena is failing financially and that in the
process America is drilling the snot out of its last remaining, bottom of the barrel oil
resources. OPEC's production cuts in late 2016, in my opinion, were an effort to give the US
shale oil industry just enough rope to eventually hang itself. It has done just that; in the
past 24 months it has bankrupted out on another $50B, borrowed yet another $50B and is now
back over $300B of upstream long term debt with no current ability to pay that back. Hope
(for higher oil prices) is not a plan. The Bakken and the Eagle Ford have peaked and now well
productivity in the Permian is starting to fade. In a few more years the rest of the world
will have the US right back it its teet and will dictate what the price of oil well be. I
think in the next 12-18 months we are going to see big reserve impairments in the US, again,
and a pretty big shale oil company will end up the toilet, bankrupt. They'll be a bunch of
fist pumping going around the world when that happens.
Harold Hamm is whiner; he has always blamed OPEC for lower oil prices, demanded that OPEC
cut more production, he needs more pipelines, fewer regulations (where are those, by the
way?), needs to be able to export his oil, warned OTHER shale oil companies in the Permian
not to overproduce and drive the price of HIS oil down, the sun is always in his eyes now its
the EIA's fault. He, like the rest of America's shale oil industry, is desperate for
attention and desperate for help. Once again, Shallow, you are spot on.
Mike. It might be worth mentioning here the recent judgment a small OK producer won against
Devon Energy.
Apparently one of Devon's high volume fracs destroyed one of the the conventional
producers' wells.
When I read about these frac hits, I really worry that US is not properly managing these
shale oil resources.
From some reading it appears frac hits are a big deal in PB, and that just a few years in,
PB shale could wind up unperformimg due to reservoir damage from these massive fracs.
So if we assume that since 2014 at least 8 million barrels per day were lost due to aging
fields. Who provided additional supply to keep it steady. Something is fishy here.
Notable quotes:
"... If you're not bringing new production online and the global decline rate is call it 5% then each year from now until 2020 we should see a loss of about four and a half million barrels per day off of supply ..."
"... And in 3 years that's 13 million barrels per day supply reduction and there is no way countries can feed themselves with that quick level of scarcity. ..."
"... Venezuela dropping to 0 while the Lybian civil war flames up again – and there isn't 3 MB/D spare capacity left. Nobody besides SA perhaps does frenetic infill drilling for capacity he don't need and use. Or develops fields and put them on idle. ..."
"... Venezuela is the best example of low oil prices making high one – the production will halt sooner or later. ..."
Way too glib a presumption of supply shortage in the 2020 time frame.
If you're not bringing new production online and the global decline rate is call it 5%
then each year from now until 2020 we should see a loss of about four and a half million
barrels per day off of supply
And in 3 years that's 13 million barrels per day supply reduction and there is no way
countries can feed themselves with that quick level of scarcity.
When one says "supply shortage" the consequence of significance is not higher prices; the
consequence is unfilled orders.
RIO DE JANEIRO, Sept 27 (Reuters) – Only one block in Brazil's prized offshore Santos
basin received a bid in the country's 14th oil round on Wednesday, a sign low global oil
prices may have reduced the allure of potential new crude and gas investments in Latin
America's largest economy.
A lot more interest in the other basins though, especially Campos. It can't be just oil price
that is against Santos, maybe it's similar to the mirror province in Angola, Kwamza, and it's
turning out to be a bust.
I think this year has killed off a few of the promising frontier basins now – Kwanza in
Angola – bust, deep water offshore Canada – mostly bust, Barents – mostly
bust, Santos – looks bust, ultra deep US GoM – mostly played out or uncommercial,
offshore Colombia – looks bust for oil, couple of West Africa areas – dry holes,
offshore Ireland – half way to bust, UK North Sea – very poor lease sale, also
one other lease sale (maybe Oman?) I think didn't do very well from memory.
MARKET SHOULD PREPARE MORE FOR OIL SQUEEZE THAN OPEC SUPPLY GAIN, CITIGROUP SAYS
Those in the oil market fearing a flood of OPEC supply next year will probably be better
off preparing for a shortage, according to Citigroup Inc.
Five countries in the group -- Libya, Nigeria, Venezuela, Iran and Iraq -- may already
be pumping at their maximum capacity this year, Ed Morse, the bank's global head of
commodities research, said in an interview. Rather than a surge in output, there's a risk
of a market squeeze emerging as early as 2018, driven by those nations because of weaker
investment in exploration and development, he said.
"Fear in the market has been that OPEC production will rise dramatically," said Morse.
However, "there could be a supply gap emerging, which could point to a tighter market," he
said in Singapore on the sidelines of the S&P Global Platts APPEC Conference.
Geology has to do a lot with oil prices – the run up in price the last 40 years is
mostly due to geology.
Why? The original oil was the kind of very conventional land based oil. Once discovered,
the most costly thing was the infrastructure to transport it away.
This came to a limit in the 70s. After this, more and more expensive projects where
necessary.
Off shore oil, deep sea oil, small spots on land, arctic oil and last fracking oil. And
old fields with injections, infill, pressure control.
All things with big investments – much more than "we build an oil terminal for
supertankers and drill a few holes".
And so the market gets more and more unstable – these big investments have to pay
out, even when done by a state. And you have bigger and bigger planning time lags, so the
classical pork cycle can get investors in the false moment.
US fracking oil adds to the chaos – it's expensive, but fast rampup – but not
able to replace deep sea oil due to it's pure size.
Old cheap fields are in decline, or not longer cheap as the chinese giants on secondary or
tertiary recovery enhancements. So more and more expensive technology with long planing
horizonts comes to a short paced market, together with the political chaos describes by
you.
And geology gets more complicated, so the long project times you describe will get
longer.
I, without a mathematically model, expect a chaotic market in the future until oil gets
(hopeful) phased out and put in the steam engine age.
Low oil prices make high oil prices, and high ones low. The demand is very inelastic on
the short term, trucks have to drive and people have to drive to work (and the aunt wants the
chrismas visit). Only mid way demand gets flexible, a japanese car instead a SUV next or a
house nearer at the job. Or a company reduces work travelling.
Many 3rd world countries have regulated gas prices – so a price spike don't reduce
demand here on the short term. That makes things even more scary when something happens on
the political scale.
Venezuela dropping to 0 while the Lybian civil war flames up again – and there
isn't 3 MB/D spare capacity left. Nobody besides SA perhaps does frenetic infill drilling for
capacity he don't need and use. Or develops fields and put them on idle.
Venezuela is the best example of low oil prices making high one – the production
will halt sooner or later.
Higher than $50 per barrel WTI essential for a meaningful return on capital. May be even
higher then $65 per barrel. right now shale oil production is possible only by simultaneous
generation of junk bonds.
Notable quotes:
"... Higher than $50 per barrel WTI essential for a meaningful return on capital ..."
"... if WTI remains stuck at about $50 per barrel, U.S. shale drillers might be forced to reign in their ambitions, because they won't generate enough cash to reinvest in growth. Second, shale drillers might actually worsen their financial position if they pursue growth. Spending more to produce more -- while that could lead to more oil sales -- might not necessarily be the wisest strategy. ..."
"... For similar reasons, Jim Chanos, short-seller and founder of Kynikos Associates, has made some headlines shorting Continental Resources. He argues that shale companies simply have to spend too much to keep production going. Shale drillers "are creatures of the capital markets," he told Bloomberg . "Because the wells deplete so quickly, they constantly need to raise money to replace the assets. And this is the crux of the story." ..."
"... Another significant observation is that the shaky financial position for some shale drillers also suggests that the downside risk to oil prices might not be as serious as once thought. ..."
"... "The market may well discover it has been asleep at the wheel and far too relaxed about shale keeping a ceiling on prices forever," Ben Luckock, a senior executive at oil trader Trafigura, told an industry conference in Singapore last week. ..."
"... All of the highly-touted cost reductions and efficiency gains have already been "realized." Moody's lowered its outlook for these large oil companies in 2018 from "positive" to simply "stable ..."
The
extraordinary cost reductions achieved by North American oil and gas companies have likely
reached their limit, and any boost in profitability for much of the U.S. shale and Canadian
oil sands industries will have to come from higher oil prices, according to a new report from
Moody's Investors Service.
Moody's studied 37 oil and gas companies in Canada and the U.S., concluding that although
the oil industry has dramatically slashed its cost of production in the past three years and
is currently in the midst of posting much better financials this year, there is little room
left for more progress.
"After substantially improving their cost structures through 2015 and 2016, North American
exploration and production (E&P) companies will demonstrate meaningful capital efficiency
to the extent the West Texas Intermediate (WTI) oil price is above $50 per barrel and the
Henry Hub natural gas price is at least $3.00 per MMBtu," Moody's
said . In other words, WTI will need to rise further if the industry is to improve its
financial position.
The report is another piece of evidence that suggests the U.S. shale industry is perhaps
struggling a bit more than is commonly thought. U.S. shale has been portrayed as nimble, lean
and quick to respond to oil price changes. And while that is largely true, strong profits
remain elusive, despite the huge uptick in production.
Shale drillers have substantially lowered their breakeven prices, but further reductions
will be difficult to achieve, Moody's Vice President Sreedhar Kona said in a statement.
" Higher than $50 per barrel WTI essential for a meaningful return on capital ,"
Moody's said.
The findings are important for a few reasons. First, it suggests that if WTI remains
stuck at about $50 per barrel, U.S. shale drillers might be forced to reign in their
ambitions, because they won't generate enough cash to reinvest in growth. Second, shale
drillers might actually worsen their financial position if they pursue growth. Spending more
to produce more -- while that could lead to more oil sales -- might not necessarily be the
wisest strategy.
For similar reasons, Jim Chanos, short-seller and founder of Kynikos Associates, has
made some headlines shorting Continental Resources. He argues that shale companies simply
have to spend too much to keep production going. Shale drillers "are creatures of the capital
markets," he told
Bloomberg . "Because the wells deplete so quickly, they constantly need to raise money to
replace the assets. And this is the crux of the story."
Another significant observation is that the shaky financial position for some shale
drillers also suggests that the downside risk to oil prices might not be as serious as once
thought. The oil market has tried to assess how quickly shale production would come
roaring back. Reports that shale companies were posting juicy profits at very low oil prices
has likely factored into heady projections for shale output. The EIA has repeatedly projected
that shale output would average 10 million barrels per day next year (although they have
revised that down recently to just 9.8 mb/d).
But that might be overly optimistic if a long list of shale companies are not posting
"meaningful" returns on capital.
"The market may well discover it has been asleep at the wheel and far too relaxed
about shale keeping a ceiling on prices forever," Ben Luckock, a senior executive at oil
trader Trafigura,
told an industry conference in Singapore last week. Bloomberg surveyed a bunch of
oil traders and energy executives at the conference, and the general sense was that oil would
trade between $50 and $60 per barrel, up from an informal consensus of between $40 and $60
last year. While there are many reasons for the newfound bullishness, more modest
expectations about shale growth is certainly one of them.
In a
separate report focusing on larger integrated oil companies, Moody's came to a similar
conclusion -- that the substantial improvement in the financial position of the oil industry
over the past year is poised to slow down. All of the highly-touted cost reductions and
efficiency gains have already been "realized." Moody's lowered its outlook for these large
oil companies in 2018 from "positive" to simply "stable ."
How comes? Annual world demand raises around 1.5 million BPD per year. So since 2014 it rose
probably 4 million BPD. And there is no sizable new discoveries. Iran and Libya cards were
already played and total from them is less then 4 million barrel per day. US output is stagnant.
Canadian is down. Where all this additional oil is coming from ?
Iran is currently exporting about 3 million BPD of crude and condensate vs. less than 1
million BPD when the sanctions were in place.
Libya and Nigeria have increased production by about 0.5 BPD undercutting the 1.2 million BPD
OPEC production cut.
Turkey already threatened to close their border with Iraqi Kurdistan, halting the 0.6 BPD of
oil that the Kurds are exporting through Turkey.
Venezuela problems might take another million BPD off the global market.
KSA has recently been forced to borrow $12.5 billion after borrowing $17.5 billion last
year.
Notable quotes:
"... The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day (BPD) to 1.42 million BPD. ..."
"... China's oil demand rose by 690,000 BPD in July, marking a 6 percent year-over-year (YOY) increase. China's total oil demand reached 11.67 million BPD in July. Year-to-date data indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded during the same period in 2016. ..."
OPEC crude oil production decreased by 79,000 BPD in August to average 32.8 million BPD.
This marks the first OPEC production decline since April and was primarily driven by sizable
outages in Libya.
The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day
(BPD) to 1.42 million BPD. The group reports strong growth from the OECD Americas, Europe,
and China. Global oil demand for 2018 is expected to grow by 1.35 million BPD, an upward
revision of 70,000 BPD from the previous report. Growth next year is expected to be driven by
OECD Europe and China.
China's oil demand rose by 690,000 BPD in July, marking a 6 percent year-over-year (YOY)
increase. China's total oil demand reached 11.67 million BPD in July. Year-to-date data
indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded
during the same period in 2016.
China's gasoline demand was higher by around 0.10 million BPD YOY, driven by robust sports
utility vehicle (SUV) sales, which were around 17 percent higher than one year ago. China's
overall vehicle sales in July rose by 4 percent YOY, with total sales reaching 1.7 million
units.
The numbers from China are interesting given the constant refrain of weakening Chinese
demand. This seems to be wishful thinking based on China's investments in clean technology.
Proppant isn"t free. If you use more of it, it costs more. If you add a different kind it
costs more.
And the executive bonuses are production based, not profit based. If they can get other
people to fund via loans those bonuses then of course they will do it.
You want evidence the proppant pays for itself in production? You can find it. It appears
in the earnings per share number. If it doesn't then there is no evidence.
This is no different than drilling holes to recover pores of oil amounting to 20 barrels,
total. At $45/b you get $900 from that. If someone else pays the $7 million for the hole, why
not drill?
"Investors who'd plowed $2 billion four years ago into a private equity fund that had also
borrowed $1.3 billion to lever up may receive "at most, pennies for every dollar they
invested," people familiar with the matter told the Wall Street Journal."
It is the same WSJ that last 4 years were writing about "resilience of shale" like
parrots, every day. Of course it is resilient with Gran Ma and Gran Pa money if you look that
it was mostly pension funds that are invested.
"Only seven private-equity funds larger than $1 billion have ever lost money for
investors, according to investment firm Cambridge Associates LLC. Among those of any size to
end in the red, losses greater than 25% or so are almost unheard of, though there are several
energy-focused funds in danger of doing so, according to public pension records."
So now those evil shale people are screwing Grand Pa and Grand Ma out of their hard-earned
savings?
After all, we have it straight from WolfStreet. Wolf Richter blasts the unscrupulous shale
industry when he writes:
"
The renewed hype about shale oil – which is curiously similar to the prior hype
about shale oil that ended in the oil bust – and the new drilling boom it has
engendered, with tens of billions of dollars being once again thrown at it by institutional
investors, has skillfully covered up the other reality: The damage from the oil bust is far
from over, losses continue to percolate through portfolios and retirement savings, and in
many cases – as with pensions funds – the ultimate losers, whose money this is,
are blissfully unaware of it."
There's a problem, however, with using EnerVest to bash the shale industry. And the
problem is very easy to spot for anyone who has even the most rudimentary knowledge of the
oil and gas industry (which of course leaves Richter out): EnerVest's portfolio has very few
shale assets.
• EnerVest is the largest
conventional
oil and natural gas operator in
Ohio
• EnerVest is the largest producer in the Austin Chalk, another
conventional
field.
• EnerVest is the fifth largest producer in the Barnett Shale, which is the only
shale holding listed in the company's list of core areas.
• EnerVest has spent $1.5 billion purchasing assets in the Anadarko Basin since 2013,
again in
conventional
fields.
• EnerVest is a top 20 producer in the San Juan Basin, again a
conventional
field.
So Richter uses the implosion of EnerVest, a company that is predominately a
conventonal
oil and gas producer, to bash shale? That really makes a lot of sense.
Glenn,
shale/no shale, they lost every single penny. and btw wsj lied to you every single day for
the last 4 years about milk & honey in oil patch. how do you feel about it?
Freddy, I doubt you can get this data, but a gassy geology flows liquid that isn't oil. The
relentless march upward of API speaks of NGLs rather than oil. If people just ignore API
degrees and flow liquid that is API 47 or even 51, but still call it oil, the numbers will
all be corrupted and no one will know.
I gotta go research NoDak's taxation regulation on liquids that are not crude.
coffee: Thanks for the heads up on Rockman BK discussion on PeakOil.com. I had quit looking
at that site because it seemed to have become very radical. Rockman is a good poster,
however, lots of knowledge, and a down to earth guy too.
What he describes there is why this is probably going to play out like 1986-1999. Takes
years for US onshore upstream to be placed in the category of "not investible". So $40s or
lower, on average, until mid-2020's, unless there is a prolonged major supply disruption,
which necessarily means a major Middle Eastern war lasting for years.
The possibility of $90 WTI has to be erased from memory, just like $30 WTI had to be
erased from memory from 1986-1998.
Over the course of the history of mankind, more assets have changed hands at a price
completely absent any effect of supply and demand than those that might have cared about such
things. Vastly more. Let's count a few.
1) Every single inheritance. In the history of mankind, every single inheritance.
2) All gifts.
3) All conquests.
4) All manifestations of economic predation. Predatory pricing established those
levels.
5) All monopolies
6) All thefts
7) All taxation
8) All govt decreed excise or tarrif
Want more proof? How about the ultimate:
The purchase of about 2 Trillion dollars of mortgage backed securities by the Federal
Reserve from 2009 to 2015. The pricing of those securities was 0 at mark to market, so mark
to market was disallowed, but even with that, the Fed specified the price to be whatever they
wished, and the sellers didn't have any reason to complain. The price paid was far above
supply and demand (aka 0). $2 Trillion. That probably exceeds amounts for assets from all
history that someone imagined was taking place at a free market price. Not to mention the
ongoing buys from the ECB in progress today.
So the price of oil will be what the lowest priced large sellers want it to be, and they
have no reason to imagine that their victory should be measured in a whimsically created
substance.
The upside potential might be stronger than appears at present for many reasons.
Although the Enervest situation has been conflated with the shale industry, the exact
opposite reality might prove to your (smaller operators) collective benefit as you ride out
this current storm.
Time was, ss, that some camel upwind in the desert somewhere would fart and global oil
markets would reverberate for days.
Now, in hydrocarbon producing countries from Nigeria to the Philippines, including Iraq,
Libya, Yemen, Syria, KSA and others there is conflict raging from low level to all out
warfare. Heck, there were reports the other day of a thwarted attack on a Saudi offshore
facility.
Qatar is virtually quarantined.
Russia is battling international sanctions.
And $46 WTI???
You kidding me???
We ain't in Denmark (most of us), but something's sure is rotten,
SS – It has been my experience that concerning financial matters, nothing "plays out"
like the past. Consider the period 1986-1999: No one was concerned that the world was near
peak oil. OPEC spare capacity was at least 4 times what it is today, [ask Ron], at a time
when final demand was much less. Iraq invaded Kuwait, and then we went to war to get them out
– remember the oil well fires. Russia collapsed. The "BRIC" countries [Brazil, Russia,
India and China] were inconsequential. The Dow Jones was down 22.6% in ONE DAY in 1987. The
International Monetary system almost collapsed in 1997. The world was transitioning from a
period of high inflation to much lower inflation. Japan was booming [until 1990].
You can probably add a dozen significant happenings to the list without thinking too hard.
The point is, so many variables have changed that something as significant as oil is going to
"play out" based upon today's factors, not "like" 1986-1999. Some people are still trying to
analog to the 1930's in order to predict the next great depression in the stock market
– do not listen to them.
I know things never play out exactly as in the past.
However, one has to prepare for the worst, and prices will be low for awhile IMO.
The Rockman BK discussion helped put it in focus for me. The wells will be drilled, and
only when it is clear all large US shale oil basins have hit their limit, will prices begin
to rise. That might not take 12 years, but I think at least 5 is likely.
The only intervenor would be a supply shock from the Middle East.
Another poster on another site also has given me some clarity. He states there has not
been enough suffering experienced yet in the US oil patch by those responsible for the
production boom.
We just went through two bad years of prices in 2015-2016, and at the first sign of light,
the industry was able to raise a ton of cash and go back with guns a blazing. There were no
consequences to the powers that be from the 2015-2016 low prices. Heck, the strip was higher
this time last year, yet we are still adding rigs.
It will take a minimum of five years, until it is universally believed that prices will be
low forever, that supply will be abundant forever, and that the sector is a bad
investment.
Once that happens, look out, price could rocket. But it will be awhile IMO.
Some difference between now and 86-99: i) decline rates are higher, ii) Spare capacity is
_much_ lower (oil stocks are high which apparently is what traders observe) – back in
86 KSA could flood the market, iii) not much new big projects in the pipe after 2019 and
North Sea is declining this time while it was increasing back then.
Rebalancing should go faster this time if (!) demand continues to increase.
EIA numbers are basically worthless, as far as the Permian goes. To analyze it like they are
trying to do, you would have to separate conventional production from horizontal production.
Take more gathering tools than they are using to accomplish that. Until 2015, they were still
drilling 800 a month or so vertical wells, which dropped down to 100 to 150 a month since
then. Looking at district 8A, that production is dropping like a rock. Combining the two,
production appears to be pretty flat for Texas since the first of the year.
"... Intensive drilling is causing a problem called 'frac-hits', which are cross-well interferences. These happen when fracking pressure is accidently transferred to adjacent wells that have less pressure integrity. As a result a failure of pressure control occurs, which reduces production flow. ..."
"... as the following chart from Goldman shows, the number of horizontal rigs funded by public junk bond issuance has not changed in the past 3 months. Is the funding market about to cool dramatically on US shale, and if so, just how high will oil surge? ..."
"... They want control of Russian oil and resources, so it may be cheap for a long, long time. This means the banksters will fund shale production 'til hell freezes over. They want another Russian revolution. ..."
"... Outside of Shale is DeepWater, Artic and Oil Sands. None of these are much better, and I think it will be harder this time for Oil prices to increase to make these non-convensional oil projects profitable. ..."
From Horseman Capital Management's July Monthly Newsleter
...Having grown up, and spent my entire investing career in periods of bubble inflation and
deflation , I am constantly minded to look for where the market is deceiving itself, and then
positioning the fund to benefit from the process of realisation. Many years ago, I could see
that the commodity bubble was ending, and Chinese growth was peaking. This meant that
commodities would be weaker and inflation lower, making a short commodities, long bond position
very effective. It was a great strategy, but its effectiveness ended early last year.
The good news is that new market delusion is now apparent to me. When I moved long emerging
markets, and short developed markets, the one commodity I could not give detailed bullish
reasons for was oil. Unlike most other commodities, the oil industry, in the form of US shale
drillers has continued to receive investment flows throughout the entire downturn
I had shorted shale producers and the related MLP stocks before, and I knew there was
something wrong with the industry, but I failed to find the trigger for the US shale industry
to fail. And like most other investors I was continually swayed by the statements from the US
shale drillers that they have managed to cut breakeven prices even further. However, I have
taken a closer look at the data from EIA and from the company presentations. The rising decline
rates of major US shale basins, and the increasing incidents of frac hits (also a cause of
rising decline rates) have convinced me that US shale producers are not only losing
competitiveness against other oil drillers, but they will find it hard to make money . If US
rates continue to stay low, then it is possible that the high yield markets may continue to
supply these drillers with capital, but I think that this is unlikely. More likely is that at
some point debt investors start to worry that they will not get their capital back and cut
lending to the industry. Even a small reduction in capital, would likely lead to a steep fall
in US oil production. If new drilling stopped today, daily US oil production would fall by 350
thousand barrels a day over the
next month (Source: EIA).
What I also find extraordinary, is that it seems to me shale drilling is a very unprofitable
industry, and becoming more so. And yet, many businesses in the US have expended large amounts
of capital on the basis that US oil will always be cheap and plentiful. I am thinking of
pipelines, refineries, LNG exporters, chemical plants to name the most obvious. Even more
amazing is that other oil sources have become more cost competitive but have been starved of
resources. If US oil production declines, the rest of the world will struggle to increase
output. An oil squeeze looks more likely to me. A broader commodity squeeze also looks likely
to me.
In the latest letter's sector allocation, Clark also added the following section providing a
more detailed explanation why he has boosted his shale short to 15.5%:
We are negative on the US shale sector, during the month we increased the short exposure to
oil exploration and MLPs to about 15.5%. Conventional oil wells typically produce in 3 stages:
the start-up rising production stage lasts 2 to 3 years, it is followed by a plateau stage
which lasts another 2-3 years and a long declining stage, during which production declines at
rates of 1% to 10% per year. These wells generally produce over 15 to 30 years ( Source:
Planete energies).
In contrast, production from unconventional / shale wells peaks within a few months after it
starts and decreases by about 75% after one year and by about 85% after two years (Source
Permian basin, Goldman Sachs). This means that, in order to keep producing, shale producers
need to constantly drill new wells.
Shale drilling is characterised by drilling horizontally into the layers of rock where
hydrocarbons lie. Then hydraulic fracturing which consists of pumping a mixture of water,
proppant (sand) and chemicals into the rock at high pressure, allows hydrocarbons to be
extracted out to the head of the well.
Since 2016, as oil prices rallied, the number of rigs in the Permian basin, which is
currently the most sought after drilling area in the US, rose from about 150 to almost 400 .
Furthermore, operations have moved into a high intensity phase as wells are drilled closer
together, average lateral lengths increased over 80% from 2,687 ft in early 2012 to 4,875 ft in
2016 and the average volume of proppant per lateral foot more has than doubled (Source: Stratas
Advisors).
Intensive drilling is causing a problem called 'frac-hits', which are cross-well
interferences. These happen when fracking pressure is accidently transferred to adjacent wells
that have less pressure integrity. As a result a failure of pressure control occurs, which
reduces production flow.
In the worst cases, pressure losses can result in a total loss of
production that never returns. According to a senior reservoir engineer at CNOOC Nexen,
frac-hits have now become a top concern, they can affect several wells on a pad along with
those on nearby pads (Sources: Journal of Petroleum Technology).
A former engineer for Southwestern Energy said that frac-hits are very difficult to predict,
the best way to respond is with trial and error and experimenting with well spacing and frac
sizes to find the optimal combination.
In May Range Resources reported that it was forced to shut wells in order to minimise the
impact of frac-hits. This month Abbraxas Petroleum said it will be shutting in several
high-volume wells for about a month (Source: Upstream).
In the Permian basin new well production per rig continued to decline in June, from 617
barrels per day down to 602 . In the meantime , legacy oil production, which is a function of
the number of wells, depletion rates and production outages such as frac hits, is continuing to
rise . (Source: EIA)
In light of the above growing short bet on shale, this is how Clark is positioned:
The analysis leads me to be potentially bearish on bonds, bearish on US shale drillers, but
bullish on commodities. Over the month, we have added to US shale shorts, while also selling
our US housebuilder longs . We continue to build our US consumer shorts, where the combination
of higher oil prices and higher interest rates should devastate an industry already dealing
with oversupply and the entry of Amazon into ever more areas . The combination of long mining
and short shale drillers has the nice effect of reducing volatility, but ultimately offering
high returns. The combination of portfolio changes has taken us back to a net short of over
40%. I find market action is supporting my thesis, and the research and analysis is compelling.
Your fund remains short developed markets, long emerging markets.
While we will have more to say on this, Clark may be on to something:
as the following chart
from Goldman shows, the number of horizontal rigs funded by public junk bond issuance has not
changed in the past 3 months. Is the funding market about to cool dramatically on US shale, and
if so, just how high will oil surge?
LetThemEatRand
•Jul 22, 2017 5:44 PM
A short bet on shale is also a bet on no war that disrupts supply/increases demand. It is
also a bet against any kind of crisis in the dollar. As it stands now, that seems pretty
risky to me.
NoWayJose -> LetThemEatRand
•Jul 22, 2017 6:12 PM
I'd rather be long oil services - the inevitable conclusion of the author is that fracked
oil depletes faster, the quality drops, that they cannot get more financing and that
production will fall? And you want to be 'short' when all this happens?
LetThemEatRand -> NoWayJose
•Jul 22, 2017 6:31 PM
Agreed. A lot of people have already forgotten that oil dropped massively after the US
decided (under zero) that it wanted to punish Russia because "Russia invaded Crimea."
I didn't fully believe that TPTB had so much control over the price of oil before it
happened, but the timing could not have been coincidental. When they want oil to go back up,
it will.
When that happens is anyone's guess for those of us not in the Big Club, but the idea that
oil is in a new normal price range is not supported by history. Oil was double or almost
triple its current price under similar economic conditions in the past.
daveO -> LetThemEatRand
•Jul 22, 2017 10:10 PM
They want control of Russian oil and resources, so it may be cheap for a long, long
time. This means the banksters will fund shale production 'til hell freezes over. They want
another Russian revolution.
AGuy -> NoWayJose
•Jul 23, 2017 2:43 AM
"I'd rather be long oil services"
Seems likely oil services will get hit hard when the shale bubble pops. Its likely they are
owed money by shale drillers.
Outside of Shale is DeepWater, Artic and Oil Sands. None of these are much better, and I
think it will be harder this time for Oil prices to increase to make these non-convensional
oil projects profitable.
Consumers and business are even deeper debt than they were in
2008-2009. With the Boomers entering retirement, Companies moving to automation and
technology reducing the need for travel, its likely that Oil consumption will start to
decline. Hire energy prices would accelerate the declines via demand destruction
Deep Snorkeler
•Jul 22, 2017 6:00 PM
1. Fracked fields deplete fast.
2. Frackers need low interest financing for more fracking.
3. Increased fracking density depletes fields even faster.
4. Fracked wells produce ever poorer oil quality.
EROI is against all you frickn fracking f**kers. There is no economic theory that addresses
resource depletion.
fattail -> Deep Snorkeler
•Jul 23, 2017 8:08 AM
There is no economic theory that addresses resource depletion.
How about printing a fiat currency so that you can buy them all up? Backed by nothing.....
Except.... 11 carrier groups and 18 submarines loaded with nuclear missles?
TeraByte
•Jul 22, 2017 10:18 PM
This is not at all that black and white. Dirty and expensive shale extraction however had
advantages and saved trillions dollars in war expense now required to keep the "cheap" ME oil
flowing...
"I had shorted shale producers and the related MLP stocks before, and I knew there was
something wrong with the industry, but I failed to find the trigger for the US shale industry
to fail.
And like most other investors I was continually swayed by the statements from the US shale
drillers that they have managed to cut breakeven prices even further. However, I have taken a
closer look at the data from EIA and from the company presentations.
The rising decline rates of major US shale basins, and the increasing incidents of frac
hits (also a cause of rising decline rates) have convinced me that US shale producers are not
only losing competitiveness against other oil drillers, but they will find it hard to make
money.
If US rates continue to stay low, then it is possible that the high yield markets may
continue to supply these drillers with capital, but I think that this is unlikely.
More likely is that at some point debt investors start to worry that they will not get
their capital back and cut lending to the industry. Even a small reduction in capital, would
likely lead to a steep fall in US oil production. If new drilling stopped today, daily US oil
production would fall by 350 thousand barrels a day over the next month. (Source: EIA)."
"... Not only will enhanced recovery affect the economics of present unconventional operations, it has the potential to greatly expand the application to numerous, older conventional sources as well as undeveloped – yet recognized – formations with hydrocarbons within them ..."
"... But the problem isn't so much whether oil is still in the ground, but how much it costs to get it out. ..."
"... New technologies that don't reduce costs to make oil profitable to drill aren't all that helpful in keeping the oil flowing. Right now we have LTO because the system accepts financial loss. That could change if alternatives promise a better financial return. ..."
"... The way I understand the term Maximum Reservoir Contact (MRC) is that it refers to multiple laterals being drilled from a single vertical wellbore. ..."
"... From what I have read MRC technology is a great fit for a number of fields in the gulf countries and may be practical in other places including USA. Of course one of the problems applying it here is that I think you need a unitized field, or at least a very large area to be implemented. ..."
"... At that time, I was amazed to learn of the multi lateral, extended reach drilling using ultra sophisticated whipstocks in the mid east, offshore, and – if memory serves – Sakhalin. Probably do need large reservoir to be viable. ..."
"... The article says this: "On the supply side, global oil production advanced by 0.5 percent to reach 92.2 million BPD." You know, factoring in both population growth and world economic growth, this isn't much. There might be a crunch coming. ..."
New technologies did postoned the day f reconing, but they can't increase the total amount
of oil availble so the effects are temporary. Adn they are costly. right now low oil price is
financial scam.
I agree with George that getting stuff wrong is no reason to quit trying. To do so would be
stupid. To look back at why projections were wrong is a much more interesting thing. To that
end, I have been looking back at predictions from the 2005 to 2010 period, starting with
Simmons and progressing to the oil drum and some others. I do not have the technical
expertise that many of these people had, but looking back is a lot easier than looking
forward.
In my opinion, there are two big reasons the projected decline hasn't come about yet.
First, most of the work done was based upon inferred data. Because, the GCC countries don't
release much, most of the folks making these projections took whatever info was available and
ran with it. I don't blame them for this, as I believe they did what they could with what was
out there, but I think they went too far in some instances, and confirmation bias is
evident.
A part of Mr Simmon's efforts to deal with the lack of hard data was his review of many
SPE papers dealing with various issues. I believe one of these papers is a key to
understanding how KSA and others have exceeded projected production. Paper (SPE 88986) deals
with well "Shaybah-220 A Maximum Reservoir Contact (MRC) Well and its implications for
developing tight-facies reservoirs."
https://www.onepetro.org/download/journal-paper/SPE-88986-PA?id=journal-paper%2FSPE-88986-PA
This paper by N.G. Saleri describes the efforts to develop the Shaybah Field. After some
initial efforts to produce there were unsatisfactory, Aramco kept on trying and came up with
the Shaybah 220, a well with eight laterals of around 40,000 feet of reservoir contact, and
producing around 12,000 bbls per day for its first year. Saleri describes this as a
"disruptive technology".
Simmons devoted a lot of attention to Shaybah, calling it "The difficult last Giant". He
included a discussion of horizontal and MRC wells including the aforementioned paper, but I
don't think he fully appreciated these MRC wells. They have allowed KSA to produce lots of
oil in many fields that were in decline. Another example is shown by the 2008 paper by Mr
Asaad Al-Towalib on "Advanced completion technologies in successful extraction of attic oil
reserves in a mature giant carbonate field." In this paper they describe how this technology
was adapted to produce the attic oil of Abqaiq, KSA's oldest giant. To summarize, Abqaiq had
been produced since the 40's, and had produced about 57% of the original oil, but had around
25 feet of attic oil in poorer reservoir that they had not been able to produce. They tried
to produce this attic oil via vertical and conventional horizontal wells with little success.
They improved their technology and eventually completed many successful MRC wells with
geosteering which allowed them to follow structure, and intelligent completions which delay
the effects of coning.
So, much as most of us would have underestimated how successful our light-tight frac oil
has now become, many underestimated how successful MRC, and associated technology has been
for many gulf nations.
I think the next question is what happens next, so using Abqaiq as an example, after
successfully producing that attic oil is there another encore or does it become just a
depleted field? They have also used this technology to get more out of Ghawar and many other
fields, do they have room to run, or are they done?
That is simply an outstanding display of, and description of, a serious effort in
understanding what is unfolding in the world of hydrocarbon production.
I would suggest that the entire concept of MRC is being currently applied in this 'shale
revolution' primarily in the area of maximizing recovery rates, aka better
fracturing/completion processes.
Not only will enhanced recovery affect the economics of present unconventional
operations, it has the potential to greatly expand the application to numerous, older
conventional sources as well as undeveloped – yet recognized – formations with
hydrocarbons within them
But the problem isn't so much whether oil is still in the ground, but how much it costs
to get it out.
New technologies that don't reduce costs to make oil profitable to drill aren't all
that helpful in keeping the oil flowing. Right now we have LTO because the system accepts
financial loss. That could change if alternatives promise a better financial return.
I kind of 'flipped' the MRC concept in dc's post of 'more iron meeting' oil to 'more oil
meeting iron' via the greatly enhanced fracturing/conductivity recently taking place in the
shales.
Regarding multilaterals, the early (2007-2009) Bakken wells regularly contained 2 or 3
lateral from one vertical.
They used the term "turkey legs' and can still be easily seen on the ND DMR Gis map.
Virtually no one except Slawson still does this and even then, only rarely.
(Correction, might still be done in Madison formation, especially Bottineau county. Would
have to check. Gis map is easiest way to literally see this).
BHP said a year ago that they would attempt to try this in the future, but I've not kept
close track of their efforts.
Thank you very much coffee, I appreciate your kind words.
From what I have read MRC
technology is a great fit for a number of fields in the gulf countries and may be practical
in other places including USA. Of course one of the problems applying it here is that I think
you need a unitized field, or at least a very large area to be implemented.
I'm pretty sure you know a whole lot more about this stuff than I do.
I started digging into it a few years back when the series of stunningly high IPs started
to emerge from the Deep Utica.
Big buzz developed about feasibility of sharing hardware/facilities to develop Marcellus and
Utica together.
At that time, I was amazed to learn of the multi lateral, extended reach drilling
using ultra sophisticated whipstocks in the mid east, offshore, and – if memory serves
– Sakhalin. Probably do need large reservoir to be viable.
Time will tell if this approach makes sense in the shales. Like everything else, economics
will be the ultimate determinator.
The article says this: "On the supply side, global oil production advanced by 0.5 percent
to reach 92.2 million BPD." You know, factoring in both population growth and world economic
growth, this isn't much. There might be a crunch coming.
The 1973 so-called "oil embargo" which reduced oil supply to the USA by somewhere around 3%
or 4%. It slammed the US economy, caused the largest stock market crash since the great
depression, doubled gasoline prices, severely damaged US industry and caused a 55 MPH
national speed limit which remained in effect for ten years.
Just wait until we experience a 10% or 20% drop in oil supplies. In a few years or sooner
we certainly will. When it hits the economic and social damage will be catastrophic.
The end of Western Civilization, from China to Europe, to the US, will not occur when oil
runs out. The economic and social chaos will occur when supplies are merely reduced
sufficiently. As former Saudi Oil Minister Sheikh Yamani once said "The Oil Age may come to
an end for a shortage of oil".
They are talking about 25-30% and the verbage talks about it being in railcars . . . the
suggestion is it's part of the total Bakken flow of 1 million bpd. 25-30% of that is ethane?
What a scam this would be.
"Big Ships Account for 80 Percent of Shipping's CO2"
By Paul Benecki...2017-06-13...20:16:44
"At Nor-Shipping 2017, researchers with DNV GL released a study that points to the difficulty
of reducing the industry's CO2 output below current levels. The problem is structural: big cargo
vessels emit 80 percent of shipping's greenhouse gases, but they're also the industry's most efficient
ships, and squeezing out additional improvements may be a challenge.
Just 35 percent of the fleet – mostly large bulkers, tankers and container ships – is responsible
for 80 percent of shipping's fuel consumption, according to Christos Chryssakis, DNV GL's group leader
for greener shipping. Unfortunately, these are already the fleet's most efficient vessels per ton-mile.
"This is a paradox, but if we want to reduce our greenhouse gas emissions, we actually have to improve
the best performers," Chryssakis says."...
Similar situation with trucking, but in the USA around one half of gas consumption goes into
private cars. So by improving efficiency of private fleet by 100% you can cut total consumption
only by 25%. All this talk about electrical cars like Tesla Model 3 right now is mostly cheap talk. They
by-and-large belong to the luxury segment.
"the President cited this NERA study, commissioned by the American Council for Capital Formation,
and the U.S. Chamber of Commerce. Why didn't the President rely upon his own experts within the
White House?"
Because his CEA is not yet staffed. The NERA "study":
NERA uses its "model" to forecast that the cost to real GDP by2040 will be a 9% shortfall and
the cost to employment will by 31.6 million jobs. Now that sounds BAD, BAD. But it sort of reminds
me of the kind of "quality analysis" we might expect from the Heritage Foundation. Of course that
is what the American Council for Capital Formation, and the U.S. Chamber of Commerce paid NERA
to do.
I learned much reading this about Russia's taxing of its crude oil...you may find it interesting
as well...
Careful though, Irina Slav neglected to mention that Russia never stopped producing as much
oil as it could during OPEC's deal to cut production so this is hardly a balanced article
Putin and the Russian Oligarchs are not going to cut production, Mother Russia (Putin) needs
the cash flow (as do the other OPEC cheaters)
"OPEC Cuts Send Russia's Oil Heartland Into Decline"
By Irina Slav...Jun 03, 2017,...2:00 PM CDT
"Western Siberia is to Russia what the Permian is to the U.S. Well, kind of. Kind of in a sense
that it's one of the longest-producing oil regions and there's still a lot of oil in it. Yet,
thanks to the production cut deal with OPEC, Russian companies have had additional motivation
to move to new territories in the east and the north, where taxes are lower.
In Russia, the older the fields, the higher the taxes operators have to pay. Now that the country
has pledged to continue cutting 300,000 bpd for another nine months, the most obvious choices
for the cut are the mature Western Siberian fields. In the first quarter of 2017, for example,
output at Rosneft's Yugansk field fell by 4.2 percent, Bloomberg reported.
Production at other Western Siberian fields is set for a decline as well, with the daily output
rate from lower-tax deposits in the Caspian Sea, Eastern Siberia, and the North seen to rise to
866,000 bpd by the end of the year, or 74 percent on the year. The shift away from mature fields
to new ones will continue over the medium term, according to BofA analyst Karen Kostanian, as
overall Russian output grows. No wonder, as tax relief on new projects sometimes reaches 90 percent.
Lukoil's output from the Filanovsky field in the Caspian, for instance, is taxed at 15 percent
at a price per barrel of US$50. The average for mature fields is 58.1 percent, in a combination
of mineral resource tax and export duty.
And this is not the end of it: in 2018, the Kremlin will test a new tax regime for the oil
industry as it seeks to maintain production growth and the respective revenues, contributing a
solid chunk of federal budget revenues. The new regime, Deputy Energy Minister Alexei Texler told
Reuters, will first be introduced for a selection of 21 fields with a combined output of 300,000
bpd for a period of five years.
In case the government is happy with the results from the test, the new regime would be expanded
to the whole industry. Hopes are for a substantial increase in output thanks to the new tax regime:
up to 20 percent over the five-year period. These hopes seem to be limited to the Energy Ministry,
however, the Finance Ministry worries that the new regime will make it harder to control the flow
of tax money. The treasury is also against combining the new regime with already existing tax
incentives for the industry.
So, the move away from what Bloomberg calls the oil heartland of the world's top producer is
all but inevitable. It will come at a cost for the state coffers of some US$25 a barrel of Western
Siberian oil, or US$2.7 billion annually, according to a Renaissance Capital analyst, but the
cost will be worth it. The cost would increase, too, if the current output cut arrangement with
OPEC fails to push up prices, which for now is exactly what we are seeing, while the ramp-up in
the U.S. oil heartland continues."
"With enough thrusts pigs can fly. It is just dangerous to stand were they are going to land."
This quote is perfectly applicable to OPEC and Russia oil production now.
Neglecting maintenances and using "in fill" drilling just shorten the life of the traditional
oil fields. And new large oil fields are difficult to come by.
My impression is that most of "cuts" in production by Russia and OPEC are "forced moves". Production
was declining from mid 2016 when old investment were already all put into production and few new
investments were made since late 2014.
If we assume the lag period of two years, than in mid 2018 we will feel the results of decisions
to cut investments made in 2016.
In this situation announcing cuts allow to save face.
The net result is the same -- the oil price should rise to the level when it is economical
to develop "more expensive oil" (deep see drilling, Arctic oil and such) as replacement rate in
traditional fields is insufficient to maintain the production.
As long as The US government allow shale companies to generate junk bonds (which will never
be repaid representing kind of hidden subsidy) along with "subprime oil", shale can slightly compensate
the decline in production, but my impression is that this card was already played. Despite all
hoopla from WSJ and other major MSM.
The fact that oil production for some time was artificially kept flat or slightly rising is
strange and might be politically motivated (Saudi) which put other producers in situation when
they were force to follow Saudi lead or lose customers. China played Russians against Saudi pretty
well and got what they want at lower prices.
Those "intensification of production" were short term measures which in a long run are detrimental
to old oil fields output.
They might even lessen the total amount of oil that can be extracted from a given field.
The key question here is: Does Russian oil firms has the amount of money needed to maintain
production on the current level (at the current oil price levels ) or not.
Obama has a chance to move the US personal fleet to hybrid and more economical cars. He lost
this chance. SUV is now dominant type of personal cars int he USA, the trend opposite to what
it should be. Even hybrid SUVs like RAV4 hybrid get only around 33 miles highway, less in city
traffic.
Transition to Prius type cars (with their around 50 miles per gallon) would allow US consumers
to save almost half of oil spend on personal transportation (which probably represent around 60%
of total US consumption
http://needtoknow.nas.edu/energy/energy-use/transportation/
)
US shale production increase scenarios at different $WTI prices and cost inflation levels assuming
no new debt (no mention of paying down existing debt?)
May 24, 2017 – Leslie Wei – Rystad Energy
Figure 3 shows the estimated Y/Y growth in NA liquids shale production for different WTI oil prices
and cost inflation scenarios compared to 2016 cost levels. The "Call on shale" highlighted section
represents the 1.3 million bbl/d average taken from figure 2. The key assumption for this analysis
is that the E&P companies will balance the investments with operational free cash flow (cash neutrality).
For example, in a 70 USD/bbl oil price range, cost inflation within the range of 0% to 25% is
required to meet the 1.3 million bbl/d y/y growth in the "call on shale." In a 50 USD/bbl scenario,
the liquids production may only grow as much as 0.5 million bbl/d on a yearly basis even if the
costs remain flat. To reach the call on shale of a yearly growth of about 1.3 million bbl/d, the
oil price needs to move into the range of 70 to 80 USD/bbl for the companies to stay cash flow
neutral.
https://www.rystadenergy.com/NewsEvents/PressReleases/the-call-on-shale
"Figure 2 shows the necessary yearly growth in shale production to balance supply and demand
from 2017 to 2021. To achieve this, shale has to grow by 1.6 million bbl/d in 2017, and more than
2 million bbl/d in 2021. This implies a total shale oil production of 14.1 million bbl/d in 2021.
To achieve such growth in shale production, the number of spudded shale oil wells has to reach
~20,000 wells in 2021, or two times the number of spudded wells in 2016."
Now we have roundabout 4-5 million b/d shale production – how can only the double number of new
wells bring the triple production?
On the other hand, is shale now unlimited in resources and can supply the whole world with
oil, enough wallstreet silly money (TM) provided?
Oh, and another thing: Do the shale oil wells no more decline rapidly after drilled, but add
up nice to such production numbers.
PS: Here in financtial newspapers the typical shale break even price is now at 23$/barrel.
There are only a few oil wells left production cheaper than US shale oil.
Let us see the well completion numbers from Texas for May first (RRC), and step by step judge
if enough wells are actually completed. The trend is not going right through the roof when looking
at the April oil well completion numbers tbh.
I don´t like the expression "call on shale" as it implies that there is a vast base of resources
there to be exploited, which could turn out to not be true. I also do not like the term "call
on OPEC" as it implies the same.
The countries in OPEC are very different and just some of them can ramp up I can imagine. Who
knows actually with all the secrecy and lack of accurate oil field data coming from some of the
participants in the organisation.
2. The shale column in the Permian Basin is about 4,000 feet thick, whereas in the Eagle Ford
and Williston Basin it is only a few tens or hundreds of feet thick.
3. There are at least seven productive shale zones (which have already been tested), and several
more that have not been tested, stacked like pancakes, one right on top of the other, in the Permian
Basin.
4. The stacked plays in the Permian Basin allow for economies of scale not offered by the other
shale plays.
5. Improved drilling techniques have cut the number of drilling rig days needed from spud to
finishing of drilling operations (that is, the cementing of production casing) substantially.
6. Post-2015 fracking techniques (Fracking 2.0 and Fracking 3.0) are producing far more prolific
wells. Offsetting wells, with identical lateral lengths, and completed with Fracking 3.0 are producing
almost twice as much oil as the pre-2015 wells completed with Fracking 1.0.
7. The Permian Basin, being a mature oil and gas basin, already has a great deal of existing
infrastructure already in place, and is not too terribly far from the refinery complex on the
Gulf Coast, as the Williston Basin is.
The only public company that is solely focused on fracking services in the US shale basins in
Keane Group, ticker symbol FRAC. The company just went public at the end of 2016.
Keane's 10Q for 1/17 is interesting. The company lost $72 million. Their costs of services,
which excludes depreciation, selling, general and administrative expenses and interest, was just
$16 million less than revenues. The margin between revenues and costs of services was just 6%.
This was an improvement over 2016, where costs of services were actually more than revenues.
In the business outlook section, the company states they are seeing higher pricing for services.
In particular, due to greatly increasing volumes of sand per well, the company has seen certain
grades of sand doubling in price since the second half of 2016.
This is not a small company, they are in all shale basins and do work for some of the big names.
Clearly, as more fracking crews are utilized, costs are headed up.
Of course, they still do not have all of their frack crews working. There is still overcapacity
in all service areas, as active rigs are still far below the peak in 2014. Well costs have fallen
several million dollars since 2014. It is interesting that even with the price recovery in Q1,
2017, most upstream US shale companies showed losses or small earnings per share. ExxonMobil,
Chevron, Pioneer, Marathon and EOG all either showed small positive or negative EPS in Q1 from
US upstream.
There were outliers, such as Diamondback(FANG), which showed high EPS. However, a close look
shows FANG's CAPEX is still significantly higher than D,D&A.
Looking back since 2014, very interesting how the US shale industry battled to maintain production.
Saudi Arabia surely didn't anticipate the ability of US firms to operate at a loss for such a
long time. 2 1/2 years later, US service firms are still operating at a loss, if Keane's example
is accurate. US financial markets are very deep, interest rates remain very low on a historic
basis, and executives earning 7-8 figures annually are not simply going to shut down, as no growth
equals lower bonuses.
The numbers reported in 2015 and 2016 in aggregate by US shale firms clearly show that the
vast majority of 2015 and 2016 shale oil wells were operated at a loss. Almost all will not reach
payout in 36-60 months at the current futures strip. Hopefully, when this shale phenomenon has
concluded, there will be some in depth studies conducted of the financial side. Those reports
should make for very interesting reading.
Our small family business was not immune from cutting, such that 2016 was in the black, despite
well head prices for the year it just $36. True, we are not drilling still, and production is
slowly declining. This will continue until prices solidly rise into the $55-65 WTI band we desire.
However, we can take several more years of $45-53 WTI, if that is what the future holds. The consensus
in our small oil patch is that we need to be more worried about future demand, than future supply.
As US shale continues to climb the wall, taking total US C+C to 10, 11 or even 12 million BOPD,
that climb will get tougher, and more expensive per barrel. Maintaining 10-12 million BOPD for
a few years will take more CAPEX than is currently being spent. Maybe Dennis knows how much more?
It seems more of the public is pushing for EV, ride sharing, autonomous vehicles, etc. I have
tough time envisioning this, living in the middle of nowhere, in the middle of "fly over territory".
But, even though these initiatives are also generally hemorrhaging cash, just as shale has, dollars
and cents do not seem to matter. Kind of like how a company like Facebook can be worth $450 billion,
yet I have not used it once and see it as nothing but online gossip and a complete waste of time.
I can't understand it, but it is reality.
> In particular, due to greatly increasing volumes of sand per well, the company has seen certain
grades of sand doubling in price since the second half of 2016.
Son of a gun. Imagine that. Here's my fave photo of fracking in the Bakken. It's from 2012:
Look real careful. Bags of ceramic proppant. From China. It's better at holding fractures open
than sand. Sand was the downshift because of cost. hahahahahaha
We never do hear about the lower ultimate recoveries simply accepted from use of inferior proppant.
Not part of the narrative.
There seems to be increasing mention of Occidental being bought out by someone with extremely
deep pockets. Owning over 2 million net acres, Oxy is the biggest leaseholder in the Permian.
Two points in following up on Glen's post
The productive footprint of the Permian continues to expand up into New Mexico.
The output from wells in many of the basins has significantly increased in the past 12 months.
More precise targeting, staying in zone near 100%, and diversion processes are the biggest reasons.
aaannd, speaking of Oxy, they just loaded the first VLCC – Very Large Crude Carrier, capacity
2.2 million barrels – at their dock at Corpus Christi.
66 foot draft is too deep, presently, for the channel so 60% loading at dock and balance from
smaller vessel when out in deeper water.
Red balance sheet ink doesn't matter for shale companies – as long as there is a story. They'll
get new loans, or enough investors buying new stock.
Shale companies are like .coms in the 2000s – they are about the story, not paying big dividents.
That's what old oil is for.
If now everyone of big oil drills in perminal and abandones deep water and other long run projects
– it's a 0 sum game in global supply. Perhaps permian can get really 15 millions or more barrels
a day, but without deep see and Alaska + other difficult projects, that's not 1 barrel more in
global supply.
And it will be the mother of all oil rushes, with not being able to see a piece of Texas without
drilling towers.
HOUSTON - May 4, 2017 - Occidental Petroleum Corporation (NYSE:OXY) today announced reported
net income of $117 million, or $0.15 per diluted share, compared with a reported loss of $272
million, or $0.36 per diluted share, for the fourth quarter of 2016 .
"Our focus remains on areas that generate the best returns and we are seeing improvements
in margins across all of our businesses," said President and Chief Executive Officer Vicki
Hollub.
"Permian Resources continues to be a growth engine for our company, with a 5 percent improvement
in production this quarter, reflecting increased drilling activity and well productivity in
the Delaware Basin."
I know the information I am providing is anathema for those who have been waiting around with
baited breath for the last forty years, hoping to see the last gasps of the Age of Oil. But it
looks like you might have to wait a bit longer for that longed-for event, maybe quite a bit longer.
It is also anathema to those like Mike and shallow sands, and OPEC and Russia, who with their
conventional oil portfolios had hoped for the quick demise of shale. After all, if the cost to
produce that marginal barrel is now $50 to $60, and it remains at that cost, there is little hope
for an oil price recovery much above that price. Shale killed the price of oil, and may continue
to do so for some time in the future. This is not what those vested in conventional oil had hoped
for, and continue to hope for.
When Khalid Al-Falih arrived at Davos in late January, the Saudi oil minister was exultant .
Almost five months later, U.S. production is rising faster than anyone predicted and his
plan has been shredded .
[S]hale has defied the naysayers. By the time OPEC meets in Vienna on May 25, U.S. output
will be approaching the 9.5 million barrels a day mark - higher than in November 2014 when
OPEC started a two-year price war. The rebound has been powered by turbocharged output in the
Permian basin straddling Texas and New Mexico.
Forced to adjust to lower prices, shale firms reshaped themselves into leaner operations
that can thrive with oil just above $50 a barrel.
Since OPEC agreed to cut output six months ago, U.S. shale production has risen by about
600,000 barrels a day, wiping out half of the cartel's cut of 1.2 million barrels a day and
turning the rapid victory Saudi Arabia foresaw is turning into a stalemate .
On Thursday, OPEC's own monthly oil market report said that production from non-members
would rise 64 percent faster than previously forecast this year, driven mainly by U.S. shale
fields.
So far, OPEC hasn't been able to "cut supplies faster than shale oil can increase," said
Olivier Jakob of consultant Petromatrix GmbH .
[T]he cartel faces big risks. The most prominent is that extending cuts lifts the oil price
high enough for shale to hedge again, as it did earlier this year .
Increasingly, the oil market believes the real battle between OPEC and Russia, on one side,
and shale, on the other, will take place in 2018, when an increasing number of observers predict
U.S. production will flood the market as it did in 2014 .
U.S. shale producers used the price spike that OPEC triggered earlier this year to lock-in
revenues for 2017, 2018 and, in some cases, even 2019. With their financial future relatively
secure, they started deploying rigs. Since the count of active rigs in the U.S. reached a low
last, producers have added an average seven units per week, the strongest recovery in 30 years .
According to the U.S. Energy Information Administration, American crude production will
surpass the 10 million barrel a day mark by late next year, breaching the record high set in
1970. The shale boom will propel non-OPEC output up 1.3 million barrels a day next year, effectively
filling up almost all the expected growth in demand.
"The supply and demand balance for 2018 looks very bad," said Fared Mohamedi, chief economist
at consultant The Rapidan Group in Washington. "That's when the big fight is going to happen."
Occidental
profit beats; shares fall on weak output forecast | Reuters : "Occidental Petroleum Corp's
quarterly profit beat estimates on Thursday but the company's shares fell to a near eight-year
low as the oil and gas producer forecast lower-than-expected production for the current quarter."
Oxy is still largely a conventional producer.
Permian EOR is conventional, not sure about South Texas. Non-US accounts for almost half of total
output.
So Oxy's 1Q results are not representative for the shale sector in general
In fact, during the years of the shale boom, in 2011-14, OXY was one of the very few publicly
traded U.S. E&Ps with positive free cash flow. All of those 3 or 4 companies had large non-shale
operations. On the contrary, all pure shale players had significant negative free cash flows.
I agree that "negative free cash flow is not bad in itself". The question is for how long
negative free cash flow is not bad?
Most shale companies had negative free cash flows since 2011 (already 6 years), having accumulated
large debts. There was a short period in 2H16 when, due to sharply reduced capex, the shale sector
was
free cash flow neutral. But recovering investments since 2017 will result in renewed period of
burning cash (as evident from 1Q17 results). So how many more years the markets will tolerate
shale companies' negative free cash flows?
I personally think that the shale sector could remain cash flow neutral or even slightly free
cash flow positive, especially with gradually rising oil prices. But that would imply very modest
growth in capex, and hence in production. And that still does not solve the problem of repaying
accumulated debt, unless shale companies sell part of their assets and/or issue new shares, diluting
existing shareholders.
Exposure to shale operations has actually proven a burden for the U.S. oil companies' financials
In Oxy's case,from 2014 to 1Q17, domestic upstream operations were a negative contributor to
the company's earnings (unlike international oil and gas). Positive 1Q17 earnings were due to
non-shale operations that offset a $122 million loss from the US oil and gas segment. For 2016
as a whole, U.S. oil and gas had a net loss of $999 million, while all other segments, combined,
have shown net earnings of $493 million. The same is true for the large US integrateds, like Exxon,
which consistently had negative earnings in its US upstream segment in the past few years due
to shale exposure.
"Most of the giant oil companies seem to think they're not, as they write off or sell their crown
jewels of 2011 – 2014 (Shell, Conoco and Exxon have all done so with their Canadian sands, and
as you point out Oxy did with its Bakken shale) and pivot towards the Permian shale. It's called
creative destruction, as older producing properties and techniques can no longer compete with
the new ones."
Glenn,
To make a sale someone must buy. Logic does not apply that the sellers are smart and the buyers
are dumb at this point. There was a seller and there was a buyer and that is all that we can say
about oil sand deals. We don't know the real reasons for these sales. It is just interesting that
all deals with oil sands with majors happened in downturn and that all buyers are Canadian companies.
And there is nothing creative about Shell, Exxon, Conoco acquiring all these oil sands properties
at inflated prices when oil was at north of $100 during 10 years span and selling all at ultimate
bottom when price at one point was $26.
For Q1, 2017:
US upstream -$191 million
Foreign upstream $418 million
Chemicals $170 million
Marketing and Midstream -$47 million.
The above are pre-interest and pre-tax. Oxy paid quite a bit in foreign taxes, received a large
US tax benefit due to US losses, and paid over $70 million in interest, a good chunk being on
debt incurred by spending in excess of cash flow on US unconventional in 2010-2014. OXY lost a
good chunk of change in the Bakken and completely left the area including a multi-million $ regional
headquarters they had just built in Dickinson, ND. Took a big write down on it.
I have looked a OXY Permian unconventional wells. Many pre-2016 were bad, sub 100K BO to date.
I assume they are getting better, like the rest of the Permian.
If I am not mistaken, XOM, CVX and COP made positive EPS other than in US upstream in Q1, 2017.
CLR broke even, PXD posted a small loss, EOG posted small net income.
FANG and XEC were outliers with strong EPS, but upon closer look, these numbers were aided
greatly by low DD&A per BOE, as both elected to not place substantial CAPEX on DD&A yet.
Although I'd like $55-65 WTI, can live with $45-53. We will see how many years it takes for
Permian to top out, akin to Bakken and EFS. Could take awhile, given land area. Will take awhile
to see how much of the Permian is "good".
My issue isn't about production. It's the underhanded methods to switch from one measurement to
another to suit their narrative.
When US production was declining last year they stopped posting US production charts. The moment
that changed and production had consistent increases the charts reappeared. I don't understand
their issue with being honest.
They have some good stuff there, but for anyone paying attention it really detracts and casts
a dark light on them.
The EIA makes lots of predictions and many of them are wrong. Conventional output will decline,
GOM will be flat or declining and LTO may increase by as much as 2 Mb/d from the previous peak
by 2023 and will then decline sharply (peak LTO will be about 6.5 Mb/d at most, but other US C+C
output will decrease by 1 Mb/d at 3%/year annual decline). US output might reach 10.5 Mb/d, but
not until 2022 rather than 2018, note that this does not satisfy 2016 crude inputs to refineries
and blenders which was about 16 Mb/d, unless demand decreases by 5 Mb/d from 2017 to 2022.
I doubt that will be the case, by June 2019 we will probably see $80/b (2016$) for Brent crude.
and by June 2020 the price may be North of $100/b (2016$).
Texas oil production has increased in Districts 5,7c,and 8 since October 2014. All the other 10
districts have dropped by a total of 714,406 bbls per day. I am using Texas RRC District production
October 14 to January 17.
There's a plausible sounding theory, even though posted on Zero Hedge, that the Chinese have been
filling their SPR over the last two years, and that is about to stop. This would mostly account
for why OECD storage levels only took about 35% of the supply-demand imbalance. If they do stop
then about 1 mmbpd of demand would suddenly be lost, but it might also imply that the real economy
demand growth in the period since January 2015 has only been half what it looks to have been.
Taking account of the sudden drop and a slower growth in demand would mean a longer time would
be needed to draw down OECD stocks. However if the China SPR scenario is correct then almost all
the drawdown would come from OECD. By my reckoning this would push a balancing out to late 2018
(although by then we may be seeing some bigger supply drops as the pipeline for new project start-ups
will be drying up). But if the balancing is pushed out then the chances of many FIDs this year
or next will decline and the possibility of a sudden supply crunch in 2019 through 2022 would
be greater. The green curve below gives possible drawdown under this scenario. The red one was
a previous assumption that the OECD stocks would be drawn down at only about 35% of the imbalance
(as happened when they were rising). I seemed a bit iffy when I fitted it that way, and I think
the China SPR filling is a better explanation.
SPRs in general try to have 90 days of domestic consumption in them. This was a standard put into
place mostly in Europe. China has embraced it.
The US at 750ish million barrels and having a consumption (net of production) of about 11 million
bpd (remember, this is real stuff . . . consumption, no refinery gain BS allowed) and so not quite
70 days domestic consumption.
China, at net consumption of about 7 million bpd X 90 needs an SPR of 630 million barrels.
That's about what they have, but of course with 5% consumption growth they'll have to adjust up,
but for now . . . all is well.
There probably is no flow in or out of China for SPR reasons. Already full. Have been for a
while.
This is the chart Zero Hedge had, or linked to – the key is Xinhua CFC, who have Chinese data
not otherwise available and charge a lot of money for it. I don't know how you'd go about checking
if it's correct.
Hello, don't forget that Xinhua doesn't publish China's SPR figures. The SPR figure in the chart
is an estimate based on (Production + Imports – Refinery Inputs). I'm not sure if all the teapots
are included in the official refinery data.
I guess that Chinese demand must be higher than estimated. Like this article was suggesting
Bloomberg – October 11th 2016
China's appetite for oil.
Fuel use grew by about 5 percent in the first half of 2016, according to China's biggest oil refiner,
faster than the 0.4 percent derived from government data. That "official" number is clouded by
rising gasoline exports - blends that don't show up in official figures, according to the International
Energy Agency, Sinopec Group and Energy Aspects Ltd.
Chinese authorities are also having trouble tracking refinery activity because of the surge of
processing by independent refiners, known as teapots, according to Energy Aspects' Meidan.
http://www.bloomberg.com/news/articles/2016-10-10/gasoline-cocktails-mix-with-gaps-in-data-to-cloud-china-oil-view
?
Enno's shaleprofile.com is full of facts. I went back and looked at his 1/17 summary of all US
oil producing shale fields. Interesting that despite adding over 13,000 new wells since the peak
in 3/15, US as of 1/17 was still 600K bopd below the 3/15 peak.
I do realize data is somewhat incomplete due to TX. I also realize not all wells are included.
Still, going to take a lot of CAPEX to climb the ladder back to 5, 6 and maybe 7 million bopd
from the shale fields.
Soon, GOM will start declining. Onshore conventional is like the sun setting. Just 60 or so
straight hole rigs active, half of the 1998-99 trough. Alaska doesn't appear to add anything.
Unless demand tanks, per Tony Seba's theories, maybe its time to be bullish? When it is clear
US shale has hit the wall, price could sky?
XOM – Potential 2nd Downgrade – unless APPL or Bazos jumps to the rescue. /
sarc
"However,
unlike its peers such as Chevron and BP, Exxon Mobil is
not targeting meaningful growth in production.
Although Exxon Mobil is working on a number of shale oil, conventional oil
and LNG projects which will come online in the near term, they will largely
help the company in offsetting the negative impact of field declines and asset
sales -
Shell, Chevron, and BP carry debt loads of $91.6 billion, $45.3
billion and $61.8 billion, respectively. "
"... Hopefully everyone involved in defending Bakken production upswings will not disappear into the woodwork next month, or the month after, when production drops again. ..."
"... Of course marginal shale oil wells that are at or below economic limits get shut in during winter, or get shut in and stay shut in because workover costs to restore production simply do not make economic sense. ..."
"... Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack thereof); in the end the latter always wins out. ..."
"... A little more time and realized production data will prove that downsizing actually reduced UR per incremental well and was yet another economic disaster in a string of economic disasters for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices. ..."
Hopefully everyone involved in defending Bakken production upswings will not disappear into
the woodwork next month, or the month after, when production drops again.
Of course marginal shale oil wells that are at or below economic limits get shut in during
winter, or get shut in and stay shut in because workover costs to restore production simply do
not make economic sense. There are gazillions of those kinds of well in all three of America's
shale oil basins. There need not be a flush 'uptick' of production when those wells come back
on line (that's investor presentation dribble), in fact it can be just the opposite because of
bubble point/higher water saturations.
Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires
ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack
thereof); in the end the latter always wins out.
Imagine a situation where you are drilling these $6.5M wells so close together (Marathon at
330 feet, toe to toe) that you have to "protect" them by shutting them in for prolonged periods
of time while you frac a new well 3000 feet away. That makes a lot of sense, doesn't it?
A little more time and realized production data will prove that downsizing actually reduced
UR per incremental well and was yet another economic disaster in a string of economic disasters
for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices.
The actual reserve that is being produced in the Bakken was "discovered, undeveloped and developed"
in 2013, and not covered by the USGS. It's difficult to find break out information for individual
areas in most companies reports but I don't think there was more than about 5 Gb developed and
undeveloped reserves in 2013, and it might have declined a bit since then, even including actual
production.
When I give the cumulative output of the scenarios, it is
from the start of production in the Bakken/TF in ND, about 1.6 Gb had
been produced at the end of 2015 and Bakken Three Forks proved reserves
were about 5 Gb at the end of 2015, that gets us to 6.6 Gb, typically
there are probable reserves as well, though we would have to guess at how
much. Also as oil prices increase in the future 2P reserves are likely to
increase.
Note that the F95 USGS TRR estimate for the ND Bakken Three Forks is
about 7.2 Gb, if we assume probable reserves at the end of 2012 were zero
(in my view not a very good assumption). What do you think is a
reasonable estimate for probable reserves if proved reserves are 5 Gb?
Your guess would be better than mine. For UK North Sea a typical number
would be 3 Gb of probable for 5 Gb of proved (all UK North Sea reserves).
For the Bakken it would likely be lower, maybe 1 Gb of probable for 5 Gb
of proved reserves might be a reasonable guess.
Bakken average well profile from June 2015 to Dec 2017 shown below
(after that the EUR decreases).
If you pull up data at shaleprofile.com
and look at wells from 2014 to 2017, there are 1388 Three Forks wells
that have been producing for 20 months (cumulative is 118kb) and there
are 1689 Middle Bakken wells (cumulative is 143kb@20 months). So
lately (past 3 years) a fairly large proportion of wells have been
Three Forks wells (about 45%). After 36 months the difference in
cumulative output is about 30 kb (TF is lower at 155kb@36 mo, Bakken
is 185 kb at 36 months).
I think you are mixing proved reserves from EIA with the
undiscovered numbers from USGS. The proved reserves might have some
basis and 5 to 6 might be right, I haven't sen any kind of detail
of how they are arrived at. But that is not the same oil as in the
USGS report – it was mostly already known about in 2012 when the
E&Ps stopped drilling wildcats. Since then they have been
converting probable to proven, and in some cases writing off some
of the reserves. If you want to include the USGS data then it
should be added to whatever there was as 2P in 2012 as a final
recovery.
I don't know where there 1300+ Three Forks wells come
from – the ND production wells for January shows only 1 well in the
Three Forks and 45 Three Forks / Bakken. There are other pool's
like Sanish and Madison. Madison is a big producer so maybe that is
counted as Three Forks in USGS. The ND DMR overall production up to
2015 gives 10 million for Three Forks / Bakken, 1600 for Bakken,
950 for Madison and < 1 for Three Forks alone.
The 220,000 EUR I quoted was for the Three Forks alone from
USGS, not Bakken.
It's looking like the shorter cycle times for LTO just means the the
volatility acts over higher frequency but doesn't go away. A fundamental
problem remains that all the E&Ps use basically the same model, and
therefore they all make essentially the same decisions at around the same
time, and therefore you get boom and bust. Volatility may be the biggest
contribution to delaying or preventing long term investment in bigger
(principally deep water and oil sand) projects, but I think the impact of
the big drop off in discoveries is significant, and not being fully
appreciated.
The backlog of discoveries are mostly difficult and expensive
developments that were not considered as top prospects when oil was over
$100.
The few larger, new discoveries are also in frontier, and therefore
generally more expensive, regions. E&Ps are turning to gas, or near field
developments, or are giving up on offshore altogether. Much higher, and
stable, prices might be needed to get these big projects going. If high
prices cause a fast demand collapse, by whatever mix of mechanisms, then
they might well not get done.
"A few comments from Steven Kopits of Princeton Energy
Advisors LLC"
Mar 17, 2017:
• The US oil rig count was up by 14 this week to 631
• US horizontal oil rigs were up by 14 to 530
...
• This was another very aggressive rig add, but curiously
came from outside the major plays. This suggests that either
the business is spreading beyond its historical boundaries,
or that some technical and non-recurring issues may be at
play.
"... A large part of the problem is, as is often repeated, "the cheap oil is gone". How are prices going to fall no matter how efficient things get ("work smart not hard" the project managers used to say when budgets got bust – complete cobblers) when you need to use 15000# Duplex piping instead of 600# mild steel, use latest generation (is it 5th now?) ultra deep water rigs which still only hit one in twenty exploration successes, have miles and miles of anchor cables and riser tubing instead of a short jacket etc. ..."
"... Looking at what Exxon is doing to make itself look good to investors, and then reading articles like this, I wonder if we are seeing the decline of the majors, but people aren't openly saying that yet. They keep hedging their bets by saying the oil business is cyclical, but we are talking about not only lower oil prices, but also declining reserves and higher production costs. ..."
"... The title should be "cost per barrel developed increase 66%". Adjusting for inflation we see that each dollar develops about 70% of the oil it did before. This is reasonable when we consider deep water developments don't have such good wells anymore, and that other areas are mostly limited to pounding increasingly poorer reservoirs or implementing EOR in known fields. ..."
"... Successful efforts accounting methods, as opposed to full cost, are preferred by the shale oil industry because, in my opinion, it helps distort the economic picture and makes them look better than they actually are. Hardly ever is lease acquisition costs (lease bonuses), land work, curative title work, geophysical or infrastructure costs (upstream to midstream gathering systems) used when quoting well costs to the public. This might help answer your question in the Permian: http://info.drillinginfo.com/permian-premium-are-high-prices-justified/ ..."
"... I would say in OKLA the EUR is much to low by a factor of 2-4 for a single horizon, in other words a ~100 acres can be expected to produce any where from 400,000 to 800,000 BO and can have 3 or more productive horizons each capable of those types of production numbers. So for example a ~100 acres can produce 1,500,000BO or more. ..."
"... "Several companies which were early adopters of enhanced completion techniques and have their acreage concentrated in sweet spots have seen significant declines of their IP30 values of new wells, indicating an exhaustion of their acreage. More recent adopters of enhanced completion methods, by limiting drilling to their best acreage, have seen a boost of IP30 of new wells since 2014 but will sooner or later face the same exhaustion problems." ..."
"... The oil and gas sector was particularly hammered in the three-month period, according to the report. The industry employed 3,640 fewer jobs compared to third quarter 2015, a 26 percent drop." ..."
This could probably go into the previous post about petroleum, but I will
put it here.
Oil Majors' Costs Have Risen 66% Since 2011 | OilPrice.com
: "According
to new research from Apex Consulting Ltd., the oil majors are still spending
more to develop a barrel of oil equivalent than they were before the
downturn in prices – in fact, much more. Apex put together a proprietary
index that measures cost pressure for the 'supermajors' – ExxonMobil, Royal
Dutch Shell, Chevron, Eni, Total and ConocoPhillips. Dubbed the
'Supermajors' Cost Index,' Apex concludes that the supermajors spent 66
percent more on development costs in 2015 than they did in 2011, despite the
widely-touted 'efficiency gains' implemented during the worst of the market
slump. It is important to note that this measures 'development costs,' and
not exploration or operational costs."
Interesting article and so was the Reuters one it referenced. One thing I
missed was a discussion of gas versus oil versus oil sands, I assume the
figures are for all combined, but it would be interesting to see how
things changed for each section (though probably the data is only
available internally to the companies or at a big cost from IHS or Rystad).
2011 was an era of mega projects though especially for some huge LNG
(many of which ran way over budget) and oil sands, and would also include
the cost overruns from the Kashagan debacle.
He concludes:
"In other words, the decline in costs post-2014 are, at least in part,
cyclical. Costs will rise again as activity picks up unless oil producers
work with their suppliers to address the underlying structural costs of
oil production."
But is that possible?
A large part of the problem is, as is often
repeated, "the cheap oil is gone". How are prices going to fall no matter
how efficient things get ("work smart not hard" the project managers used
to say when budgets got bust – complete cobblers) when you need to use
15000# Duplex piping instead of 600# mild steel, use latest generation
(is it 5th now?) ultra deep water rigs which still only hit one in twenty
exploration successes, have miles and miles of anchor cables and riser
tubing instead of a short jacket etc.
Looking at what Exxon is doing to make itself look good to
investors, and then reading articles like this, I wonder if we are
seeing the decline of the majors, but people aren't openly saying that
yet. They keep hedging their bets by saying the oil business is
cyclical, but we are talking about not only lower oil prices, but also
declining reserves and higher production costs.
Just as coal
has seen its best days come and go, I think that is happening with
oil, too, but there is a reluctance to call it.
The title should be "cost per barrel developed increase 66%".
Adjusting for inflation we see that each dollar develops about 70% of the
oil it did before. This is reasonable when we consider deep water
developments don't have such good wells anymore, and that other areas are
mostly limited to pounding increasingly poorer reservoirs or implementing
EOR in known fields.
For LTO it's interesting how EagleFord are piling on rigs (5 more this week)
and the permitting seems to have increased dramatically, whereas the Bakken
is steady to maybe slightly down, certainly for permitting at the moment. I
don't know where the difference for this is and I expected the opposite, but
it seems EIA knows something as their predicted flattening in the EFS
decline rate is looking pretty likely know, while Bakken is looking
increasingly weary, with only the outstanding DUCs as a big potential source
of new oil.
During the past 2 years, there has been a tremendous amount of great quality
work concerning the economics of onshore LTO production. Much of it has been
done by those who post here.
But, although I may have missed it, I still have a question that I do not
recall being discussed. Buried in each of these economic models, is there a
land resource cost?
For example what I would like to see separated out for each model is
information such as this (a hypothetical by me, for illustrative purposes
only): "The 60 Gb scenario assumes that each average onshore LTO well
utilizes 100 acres of oil resource; has an average EUR of 200,000 bbl of
oil; at an average leasehold cost of $10,000 per acre. So each average well
has an upfront leasehold cost of $1 million, and that cost is [or is not]
included in the cost per well shown.
However, let me be clear: if that information is not available, I am not
asking anyone to go get it. Just state that it is up to the reader to make
their own assumptions of what the leasehold cost is for an average onshore
LTO well. But, in that regard, it would be usefull to know how many acres
are being used for an average well.
Successful efforts accounting methods, as opposed to full cost, are
preferred by the shale oil industry because, in my opinion, it helps
distort the economic picture and makes them look better than they
actually are. Hardly ever is lease acquisition costs (lease bonuses),
land work, curative title work, geophysical or infrastructure costs
(upstream to midstream gathering systems) used when quoting well costs to
the public. This might help answer your question in the Permian:
http://info.drillinginfo.com/permian-premium-are-high-prices-justified/
"The 60 Gb scenario assumes that each average onshore LTO well
utilizes 100 acres of oil resource; has an average EUR of 200,000 bbl of
oil; at an average leasehold cost of $10,000 per acre."
I would say in OKLA the EUR is much to low by a factor of 2-4 for
a single horizon, in other words a ~100 acres can be expected to produce
any where from 400,000 to 800,000 BO and can have 3 or more productive
horizons each capable of those types of production numbers. So for
example a ~100 acres can produce 1,500,000BO or more.
Current density plots indicate 113 acre drainage will be achieved with
a 7500′ lateral with 660′ between wells. A 10,000′ lateral would be 151
acres. I can also say, because of government interference, "forced
pooling" the average leasehold cost is something under $2000 an acre.
Leasehold cost are usually added to the first producing well as part of
the "full cycle" cost and are a one time expense.
Any given unit may ultimately have 10-15 wells. Once the Unit is HBP
and the primary term of the leases have expired the full land cost will
have been expensed.
My oldest well LTO well in SCOOP has produced over 300,000 barrels of
liquids from approximately 51 acres.
Thanks TT! Since I live in OK, your information appears to be very
positive information for OK – which currently is in a poor economic
environment due to low oil [and gas] prices. However, based upon your
information, why, in your opinion, has this OK play not attracted
nearly as much "hype" as the Permian [or Baaken or Eagle Ford]? Is the
long-term potential [ultimate oil to be extracted from the entire
play] much less?
Good presentation by BTU Analytics. And it shows
that SCOOP and STACK are not a new Bakken, Eagle Ford or Permian
in terms of oil production potential.
In Texas and New Mexico, there is private fee land
and state land. New Mexico also has federal land ownership. Texas has very
little Federal ownership but there are Relinquishment Act Lands, University
Lands, and School Lands, and Stare Fee Lands which would have public records
available to review.
The state and federal agencies are mandated to seek competitive fair
market prices for land leased for oil and gas exploration. If one obtained
the lease sale results from the appropriate state and federal agencies for
each scheduled lease sale for the last ten years you might approximately
determine an average lease bonus by year that the oil and gas industry paid
for both private fee and state lands in an area.
This would not help with acreage acquired early in a play and then
flipped to a subsequent purchaser but I think it would be a reasonable
number to work with for example the Eagle Ford, Delaware Permian or New
Mexico Permian. Colorado, South Dakota, Oklahoma all contain a combination
of private and state or federal lands.
Bakken Oil Producers: IP30 And Well Decline Rate Trends Since 2014 | Seeking
Alpha
:
"Several companies which were early adopters of enhanced
completion techniques and have their acreage concentrated in sweet spots
have seen significant declines of their IP30 values of new wells, indicating
an exhaustion of their acreage. More recent adopters of enhanced completion
methods, by limiting drilling to their best acreage, have seen a boost of
IP30 of new wells since 2014 but will sooner or later face the same
exhaustion problems."
The oil and gas sector was particularly hammered in the three-month
period, according to the report. The industry employed 3,640 fewer jobs
compared to third quarter 2015, a 26 percent drop."
Unburnable Wealth of Nations - Finance & Development, March 2017
: "[Poor
countries] face three special challenges. First, they have a higher
proportion of their national wealth at risk than do wealthier countries and
on average more years of reserves than major oil and gas companies. Second,
they have limited ability to diversify their economies and sources of
government revenues-and it would take them longer to do so than countries
less dependent on fossil fuel deposits.
Last, economic and political
forces in many of these countries create pressure to invest in industries,
national companies, and projects based on fossil fuels-in essence doubling
down on the risk and exacerbating the ultimate consequences of a decline in
demand for their natural resources (see map)."
This article gives a good overview of what is happening in Colorado.
There
is activity, but it is unlikely Colorado will have any sort of boom, like
was talked about a few years ago.
Rebound predicted for Weld crude oil production | GreeleyTribune.com
:
"DJ Basin crude oil sells at a discount of $2 to $3 per barrel to benchmark
West Texas Intermediate oil from the Permian Basin. 'Companies here still
need prices to go a bit higher before we will see a significant increase in
activity,' she said."
"U.S. oil exporters set a new record last week: shipments leaving the country averaged 1.2
million barrels of crude per day, roughly double the levels seen at the end of last year.
Analysts told Bloomberg that the rising American exports are driven in large part by falling
domestic prices. West Texas Intermediate futures (the domestic benchmark) are trading below the
international Brent standard by $2 per barrel or more, and are now cheaper than some Middle Eastern
grades of lesser quality. This makes American crude more attractive to Asian buyers.
There is also an incentive for traders to sell their oil abroad: U.S. storage is costly. If
the price of crude is not expected to rise, brokers have no incentive to hang on to their supply
and pay rent on a tank to put it in."...
You are just regular incompetent chichenhawk. And it shows. Try to read something about US oil
industry before positing. It is actually a very fascinating topic. That's where the battle for
survival of neoliberalism in the USA (with its rampant militarism and impoverishment of lower
50% of population) is now fought.
If you list also domestic consumption, you will understand that you are completely misunderstanding
and misrepresenting the situation. The USA is a huge oil importer (Net Imports: 6.075 Mbbl; see
ilsm post), not an exporter. You can consider it to be exported only after drinking something
really strong.
It refines and re-export refined products and also export condensate and shale light oil that
is used for dilution of heavy oils in Canada and Latin America. That's it.
US shale can't be profitable below, say, $65 per barrel (so called "break-even" price for well
started in 2009-2016), and if interest on already existing loans (all shale industry is deeply
in debt; ) and minimum profitability (2.5%) is factored in, probably $77.
That's why production is declining and will decline further is prices stay low because there
is only fixed amount of "sweet spots" which can produce oil profitably at lower prices. In 2017
they are mostly gone, so what's left is not so attractive at the current prices. And this is an
understatement.
The same is true to Canadian sands. Plans for expansion are now revised down and investments
postponed.
So in order to sustain the US shale industry prices need to grow at least over $65 this year
And those war-crazy militarists from Obama administration essentially continued Bush II policies
and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating conversion of
passenger cards to hybrids (and electrical for short commutes).
The US as a country waisted its time and now is completely unprepared for down of oil age.
The net result of Obama policies is that SUVs became that most popular type of passenger cars
in the USA. That can be called Iran revenge on the USA.
The conflict between Donald Trump and the US Deep State can be explained that deep state can't
allow Trump détente with Russia and stopping wars on neoliberal expansion at Middle East. That's
why they torpedoed General Flynn. It is not about Flynn, it was about Trump. To show him who is
the boss and warn "You can be fired".
Due to "overconsumption" of oil inherent in neoliberalism with its crazy goods flows that might
cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism
as social system) can well go off the cliff when cheap oil is gone.
The only question is when it happens and estimates vary from 10 to 50 years.
So in the best case neoliberalism might be able to outlive Bolshevism which lasted 74 years
(1917-1991) by only something like 15 years.
"Noble Energy has sanctioned the first phase of the Leviathan natural gas project offshore Israel,
with first gas targeted for the end of 2019.
Noble Energy is the operator of the Leviathan Field, which contains 22 trillion cubic feet (Tcf)
of gross recoverable natural gas resources.
The announcement was hailed by Israeli Prime Minister Benjamin Netanyahu who has played a key
role in negotiations with Noble. Netanyahu says the discovery of large reserves will bring energy
self-sufficiency and billions of dollars in tax revenues, reports The Times of Israel, but critics
say the deal gave excessively favorable terms to the government's corporate partners...
Production will be gathered at the field and delivered via two 73-mile flowlines to a fixed platform,
with full processing capabilities, located approximately six miles offshore."...
"U.S. oil exporters set a new record last week: shipments leaving the country averaged 1.2
million barrels of crude per day, roughly double the levels seen at the end of last year.
Analysts told Bloomberg that the rising American exports are driven in large part by falling
domestic prices. West Texas Intermediate futures (the domestic benchmark) are trading below
the international Brent standard by $2 per barrel or more, and are now cheaper than some Middle
Eastern grades of lesser quality. This makes American crude more attractive to Asian buyers.
There is also an incentive for traders to sell their oil abroad: U.S. storage is costly.
If the price of crude is not expected to rise, brokers have no incentive to hang on to their
supply and pay rent on a tank to put it in."...
You are just regular incompetent
chichenhawk. And it shows. Try to read something about US oil industry before positing. It
is actually a very fascinating topic. That's where the battle for survival of neoliberalism
in the USA (with its rampant militarism and impoverishment of lower 50% of population) is now
fought.
If you list also domestic consumption, you will understand that you are completely misunderstanding
and misrepresenting the situation. The USA is a huge oil importer (Net Imports: 6.075 Mbbl;
see ilsm post), not an exporter. You can consider it to be exported only after drinking something
really strong.
It refines and re-export refined products and also export condensate and shale light oil
that is used for dilution of heavy oils in Canada and Latin America. That's it.
US shale can't be profitable below, say, $65 per barrel (so called "break-even" price for
well started in 2009-2016), and if interest on already existing loans (all shale industry is
deeply in debt; ) and minimum profitability (2.5% is factored in, probably $77.
That's why production is declining and will decline further is prices stay low because there
is only fixed amount of "sweet spots" which can produce oil profitably at lower prices. In
2017 they are mostly gone, so what's left is not so attractive at the current prices. And this
is an understatement.
The same is true to Canadian sands. Plans for expansion are now revised down and investments
postponed.
So in order to sustain the US shale industry prices need to grow at least over $65 this
year
And those war-crazy militarists from Obama administration essentially continued Bush II
policies and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating
conversion of passenger cards to hybrids (and electrical for short commutes).
The US as a country wasted its time and now is completely unprepared for down of oil age.
The net result of Obama policies is that SUVs became that most popular type of passenger
cars in the USA. That can be called Iran revenge on the USA.
The conflict between Donald Trump and the US Deep State can be explained that deep state
can't allow Trump détente with Russia and stopping wars on neoliberal expansion at Middle East.
That's why they torpedoed General Flynn. It is not about Flynn, it was about Trump. To show
him who is the boss and warn "You can be fired".
Due to "overconsumption" of oil inherent in neoliberalism with its crazy goods flows that
might cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism
as social system) can well go off the cliff when cheap oil is gone.
The only question is when it happens and estimates vary from 10 to 50 years.
So in the best case neoliberalism might be able to outlive Bolshevism which lasted 74 years
(1917-1991) by only something like 15 years.
A big contributor to the legacy oil decline is the unrelenting physics of fluid
phase behavior, with gas becoming more prevalent in the production stream.
Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The legacy wells
will be worse (i.e. the newer wells dampen the effect, which have an initial
GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is considered a "gas"
well or field.
Most of these LTO fields will eventually be abandoned as gas fields.
note – I tried to post a *.png graph, but the reply tool failed.
I missed to take into account the number of days in the month for
total producing days in my last post. I wanted to investigate this more.
So I did a bit of programing and adjusted each individual well for the
number of days it was in production in December to see what the
production would have been if it produced as many days as it did in
November (adjusted for number of days in that month). I looked at wells
that started production in 2014 and wells that started production in
2010. In short, both groups looked very similar and it turned out that
about 86% of the increase in decline rate, for both 2014 and 2010, were
because of fewer producing days and the rest for other reasons. However
there is more to it than that. First of all, adjusted for number of
producing days, the decline rate should stay the same or decrease a
little every month, not increase. Secondly wells that are of the same age
as the 2014 wells have historically had a monthly decline rate of around
3%. The decline rate in November (days adjusted) was 6,9% and in December
8,1. For the 2010 wells, monthly decline rates should have been around
1,5% but were 5,6% in November and 6,9% in December. So the decline rates
are currently very very high. The huge drop in December could not have
been that huge if the underlying decline rates would not have been that
large.
I think the decline in GOR has something to do with it. If the reason
for the increase in decline rates are that they are choking the wells,
then I expect these high decline rates to be rather temporary, because I
would guess that they adjust the choke only once per well. It may take
some time to adjust all wells they have planned to adjust, but when that
is done then decline rates should normalize. So if that is the reason
then maybe it will take a few months to normalize. If the decline rates
are still very high in a few months, then it doesn´t look good for
Bakken..
I found a bug in my code. For 2014 about 100% of the increase in
decline rates from November to December was because of fewer
production days and decline rate in November was 6,43% and December
6,35% (a bit conservative). For 2010 the numbers are 86%, 4,16% and
5,16%. So lower underlying decline rates, but still very high. Sorry
about that.
Is the 2000 GOR a North Dakota convention? There's no reservoir engineering
reason to designate a depleted well as a gas well when GOR increases to 2000
scf/bo. Depleted oil wells under depletion drive do experience very high
GORs, but they remain oil wells.
My recall is there's a regulation in Texas that classifies liquids from a
gas well as condensate vs oil from an oil well. Almost certainly has some
tax consequence.
Can any of you professional fellows explain the upsurge in "Legacy Oil Well"
production shown in the monthly EIA Drilling Productivity Reports? The major
fields, except. Permian, show that the legacy wells are rising after having
been on seemingly steady downslopes for the years leading up to about early
2015. Are they reworking old wells? What's the industry practice that has
reversed the declines.
The legacy well production graph represents the monthly expected change
in production.
In the example you referenced monthly legacy decline was
about 140,000 bopd at the beginning of 2015. This legacy decline
represents the decline of wells producing in the prior month. This
decline was large because there were many recently drilled legacy wells,
and the recently drilled wells decline more than wells which have
produced for a longer period.
By the beginning of 2017 the legacy decline had decreased to about
80,000 bopd per month because there hadn't been as many wells drilled
recently.
Some of y'all are newishcomers and cannot remember how very many times monthly
production reports would report completely inconsistent with new completions
totals and weather and more or less 15 gazillion other factors we'd throw in.
Point being, don't think you have why the big recent increase or why this big
decrease understood. Your odds on this are poor.
Reminder from last thread:. That Enno chart color coded by year - look at
how shallow the post Peak descent slope 2010, 2011, 2012 is vs 2014. Damn near
vertical. That would be the last non price smash year.
This speaks to EUR, but not loudly because of . . . Wait, do we have proof
these recompletions are happening? Or is this presumption.
Also suggest a read thru of the new rule making paras of the directors cut.
I can remember months when new completions and new wells operating numbers
completely failed to explain a change in quoted oil production that month .
. . and I embarked on chasing down traffic reports and stop light failures
at intersections because trucks hauling oil having been slowed down could
conceivably have been the explanation for the numbers. Nada.
What we DID
conclude was negative - zero explanation for oil output quotes from the
number of wells completed in a month. Number of days of bad weather
preventing completions also failed to explain. Bad weather slowing down
trucks remained a maybe, but for trucks hauling oil, not trucks hauling
proppant.
Ceramic proppant for Bakken. From China. Soon after this it was
magically discovered that special sand from the US was "superior"
(meaning cheaper, but didn't hold the fractures open as well).
Munger would have us import oil and gas now from OPEC so that we can save
our oil and gas for the future when the world is going to have major
shortages."
The day comes when a firebrand is in control and dares to rock the
societal systemic boat by declaring the price of oil will be non monetary.
You want oil from Russia, America? Disarm. You want oil from KSA, America?
Convert to Islam.
"We have enough of your dollars created from thin air. Let's have
something of real value to us before we send you oil. The price is described
above."
But if we haven't wasted our own oil, we'll still have it. And then if
other countries want to give us terms we won't accept, then we don't use
their oil.
Of course, without imports, we won't have enough to run our
country business as usual. But we're going to head that way anyway, as
global supplies become more scarce and/or expensive.
When the shit is well and truly in the fan, in terms of oil available for
import to the USA, which will probably come to pass within the next
couple of decades, barring the technocopians being right in predicting
electricity displacing oil, well
We have both economic and military muscle enough , assuming we wise up
about globalization , and don't export the rest of our industrial base,
to INSIST on oil being sold to us , although getting it for dollars will
be harder from year to year.
Saudia Arabia will never be self sufficient in food until the
population there falls by what, eighty percent or better? If anybody will
have the capacity to export food on the grand scale, it will be the USA.
And if anybody has a military umbrella under which smaller and less
powerful countries can shelter at relatively low risk of the people there
being treated like convicts, it will be the USA.
This is not to say we have been or are altogether NICE about the way
we treat our allies, but compared to other countries, we stack up pretty
well in this respect.
Nothing will move on the world ocean for quite some time if Uncle Sam
finds himself in a corner where in his own interests indicate that
nothing moves.
Of course considering that ninety percent of the leadership in China
consists of engineers and scientists, where as ninety percent plus of
western leadership consists of lawyers and other mostly parasitic types,
it 's only a question of WHEN, rather than IF China will be a military
superpower, and maybe the SOLE super power.
We need to account for the fact that shale oil production was
supported by junk bond issuance. The loss on shale oil junk bonds is
not that big: the U.S. energy companies have defaulted on ~$40 billion
in high-yield bonds in 2016, more then doubling the $15 billion for
2015 according to Fitch. But they do affect future junk bond issuance
What is interesting is that MSM stopped talking about shale junk
bonds in 2015 as if they got some order from above
Most warnings are from 2014, some from 2015:
In this sense, even $ 63 might be too low, if loans became more
expensive and well servicing costs continue t0 rise. Printing junk
bonds is a necessary side effect of shale oil production and this is
now definitely more expensive activity then before.
I think that the return to profitability for shale at oil prices
below $70 bbl is very problematic.
We have now graphed the whole of BP oil
production and consumption and calculated the net export balance which is not
in decline but it has been flat since 2005.
Nice, Thanks!
The net exports available on the global oil markets are some 60% of the
total production. In the case of dropping global oil production it will take
a while for the markets to dry out. If you make this same exercise on coal
and gas, you get different numbers. Only a tiny fraction of global coal and
gas production is available on the global markets. Dwindling global
production will result in disappearing global markets in a very short time
frame.
Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production
down
92,029 bpd
to 942,455 bpd. It was noted that this the largest decline ever in North Dakota
production. But it should not be overlooked that the October in crease in production was also the
largest ever increase in North Dakota production.
EIA wildly optimistic in Bakken, Gulf and Texas. Their current numbers have
to be way high in relation to what is actually happening. Even Texas RRC
site is not predicting an upturn until current permits and completions get a
lot higher. At $53 oil, it is not happening, or going to happen.
In my view there is simply a cost issue here. If a
well goes from 100 barrels to 20 barrels per day, the mainenance,
operating and transport costs go up fivefold per barrel, even if
they are the same for the well. So, it might not pay off to send a
crew there and pay for transport. Unless, the oil price does not go
up, these wells and many more wells are likely to shut down for a
while.
I saw a recent story about the rise in the cost of fracking to completion
for these DUC wells. Costs are said to have risen to something like $3.2
million in some of the areas where wells need completion. I believe the
Director's Cut said last month there were 86o wells awaiting completion.
If the story I read was true, then it will be around $2.8 billion to
frack those 860 wells. I don't know what the cost of getting a well to
the DUC stage is, but it sure seems a lot of money to have sunk in the
ground for wells that will be outputting just 100 barrel a day after
their first 24 months.
Bruno Verwimp wrote back in 2016, September 16th, " .Hold your breath for
the next winter. It might bring severe decline in oil production in ND
Bakken ."
I wrote at the same time: " FWIW my 'money' is on Verwimp's observation
and model for the Bakken. I for one will be interested to see your chart
next spring!"
Another 3 months will be interesting. By the look of it, it might well be
down to 700,000 bpd in a year if the uncanny accuracy continues. As I
understand it, his chart has nothing in it derived from price.
That is correct. Verwimp's model has no oil price input. This is a
serious problem since everybody recognizes that oil price has been
determinant in the current oil situation. Therefore one can only conclude
that Verwimp's model is accurate due to chance, and therefore has no
predicting capability. It will continue to be accurate until it doesn't.
It probably represents oil production decay in the absence of sufficient
economical incentive.
Geology absolutely plays a role, especially when oil
prices are relatively high it is clear which fields are constrained by
geology. When oil prices fall by a factor of 3 or 4 fields that are
not constrained by geology will decline due to economic constraints
(poor profitability.) The Bakken only increased in output due to high
oil prices and a high well completion rate. Eventually geology will be
the reason for Bakken decline, low oil prices clearly are the reason
at present.
In Jan 2018 your model predicts about 680 kb/d for ND Bakken/TF
output. My 61 well model predicts about 818 kb/d in Jan 2018 and the
85 well model predicts 900 kb/d in Jan 2018, I expect ND Bakken/Three
Forks output will be around 825 to 900 kb/d in Jan 2018, with a best
guess of 866 kb/d (847 kb/d in Dec 2018). This corresponds to a 75
well model, chart below.
A big contributor to the legacy oil decline is the unrelenting physics of
fluid phase behavior, with gas becoming more prevalent in the production
stream. Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The
legacy wells will be worse (i.e. the newer wells dampen the effect, which
have an initial GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is
considered a "gas" well or field.
Most of these LTO fields will eventually be abandoned as gas fields.
note – I tried to post a *.png graph, but the reply tool failed.
Is the 2000 GOR a North Dakota convention? There's no reservoir
engineering reason to designate a depleted well as a gas well when GOR
increases to 2000 scf/bo. Depleted oil wells under depletion drive do
experience very high GORs, but they remain oil wells.
My recall is there's a regulation in Texas that classifies liquids
from a gas well as condensate vs oil from an oil well. Almost
certainly has some tax consequence.
Munger would have us import oil and gas now from OPEC so that we can save
our oil and gas for the future when the world is going to have major
shortages."
The day comes when a firebrand is in control and dares to rock the
societal systemic boat by declaring the price of oil will be non
monetary. You want oil from Russia, America? Disarm. You want oil from
KSA, America? Convert to Islam.
"We have enough of your dollars created from thin air. Let's have
something of real value to us before we send you oil. The price is
described above."
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require
the addition of an average of about 95 wells/month (61 wells/month were added through 2016).
In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent.
This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus
a steeper decline in production.
Looking at Bakken(ND) as one big project, it has now spent an estimated total of about
$36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach
pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI)
starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B
requires an estimated oil price of $77/bo (WTI).
To enable a debt reduction requires a net positive cash flow from operations and the
longer it takes before positive cash flow happens, the higher the required oil price becomes
to earn some return.
Some of this $36B debt has already been written down (also through bankruptcies (Chapter
11s), the business model is not sustainable with low oil prices!), which means that the companies
now needs to recover less than the $36B.
Write downs/impairments shrinks the affected companies' assets/equities and thus debt
carrying capacities. Some make forecasts about future developments without considering the
companies' balance sheets.
At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month
from cash from operations, this will likely be a mixture of DUCs and "new" wells.
For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated
from operations.
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated
this would require the addition of an average of about 95 wells/month (61
wells/month were added through 2016).
In 2016 an estimated $2.0 –
$2.5Billion more than (net) cash flow from operations was spent. This is
about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought
to flow and thus a steeper decline in production.
Looking at Bakken(ND) as one big project, it has now spent an
estimated total of about $36Billion more than generated from net operational
cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in
2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17.
To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B
requires an estimated oil price of $77/bo (WTI).
To enable a debt reduction requires a net positive cash flow from
operations and the longer it takes before positive cash flow happens, the
higher the required oil price becomes to earn some return.
Some of this $36B debt has already been written down (also through
bankruptcies (Chapter 11s), the business model is not sustainable with low
oil prices!), which means that the companies now needs to recover less than
the $36B.
Write downs/impairments shrinks the affected companies'
assets/equities and thus debt carrying capacities. Some make forecasts about
future developments without considering the companies' balance sheets.
At present oil pries (low/mid 50's) the companies may add an average
of 60-70 wells/month from cash from operations, this will likely be a
mixture of DUCs and "new" wells.
For 2017 I expect companies in Bakken(ND) will continue to spend
above what is generated from operations.
Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production
down
92,029 bpd
to 942,455 bpd. It was noted that this the largest decline ever in North Dakota
production. But it should not be overlooked that the October in crease in production was also the
largest ever increase in North Dakota production.
If I'm not mistaken, this means that the North Dakota production (BPD) is now
only slightly more than than the existing pipeline capacity leading out of
North Dakota (BPD), which is 851,000 at the end of 2016. Production will
probably be down to the existing pipeline capacity by March.
Now this isn't quite comparable because part of the Williston isn't in North
Dakota, so I'd have to look at the Montana numbers. But still, it looks likely
that the moment Dakota Access is built, there will be a pipeline capacity glut.
So is the Dakota Access Pipeline going to be half-empty, or will some of the
other pipelines be empty and go bankrupt? They're fighting over market share in
a surplus-capacity environment.
"The incremental investment is budgeted to deliver an average
estimated ultimate recovery (EUR) of, or approximately 15% over the
previous average EUR of 850,000 Boe per well. At $55 per barrel WTI,
these completions should generate a cost forward average rate of
return in excess of 100%"
The estimated EUR's appear VERY high
for Bakken wells by my untrained eye. Any thoughts from the
resident experts?
I am certainly not an expert on tight oil but see above. If they
get 30 to 40% extra from gas I think they might make it (GOR of
1500 adds 25% I think, and it looks like it will be more than
that for most wells). What I don't get is a 'previous average'
of 850,000. There's not even one well that looks like that at
the moment, based on Enno Peters' charts.
"The Company plans to complete 131 gross (100
net) operated wells out of its Bakken uncompleted well inventory with
first production commencing by year end. In addition, Continental
plans to complete with first production approximately 17 gross (8 net)
newly drilled Bakken wells in 2017. At year-end 2017, the Company
expects to have 140 Bakken wells in inventory, of which 72 gross (40
net) wells will have been completed but waiting on first sales and 68
gross (47 net) operated wells will be waiting on completion.
The Company also plans to participate in completing 40 net
non-operated wells in 2017, 35 of which will be in the Bakken.
Continental expects to grow Bakken production by approximately 26%
in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.
Approximately $550 million, or 70%, of the operated Bakken capital
investment in 2017 will be focused on completing wells from the
Company's uncompleted well inventory. The Company has five stimulation
crews working currently and plans to average seven crews for 2017 as a
whole.
Continental plans to apply various enhanced stimulation techniques
on all Bakken completions in 2017 to define the optimum designs for
future completions. This includes larger proppant loads, diverter
technology, shorter stage lengths and shorter cluster spacing. The
Company is also applying high-rate production lift technology to
accelerate fluid recovery and early production rates. Combined, these
techniques add an average of approximately $1.4 million to the
previous standard enhanced completion cost of $3.5 million.
For the uncompleted well inventory, the average budgeted completion
cost for the larger enhanced completion is approximately $4.9 million
per well. The incremental investment is budgeted to deliver an average
estimated ultimate recovery (EUR) of 980,000 Boe per well, or
approximately 15% over the previous average EUR of 850,000 Boe per
well. At $55 per barrel WTI, these completions should generate a cost
forward average rate of return in excess of 100%.
The Company also plans to maintain four operated drilling rigs in
the Bakken throughout 2017 and drill 101 gross (57 net) operated
wells, with 17 gross (8 net) of these wells completed in 2017 with
first production. The 17 gross wells will have an average budgeted
well cost of approximately $7.0 million. The average EUR for wells
drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price
of $55 per barrel, these wells should generate over a 40% rate of
return."
According to Enno, an average
Bakken well gives about 200k+ of oil, not 900k. It looks like it's
much more gas than oil, or the numbers are completely bogus. Or
they have bought the sweetest center of all sweet spots in Bakken?
As of 3Q16, oil accounted for 61% of total CLR output.
Apparently, oil's share in CLR production in the Bakken is
higher.
According to Enno, CLR Bakken wells with the first
flow in 2014 have on average already produced > 200kb of oil.
Their average EUR may exceed 400 kb and probably reach 500 kb.
Wells with first flow in 2015 and 2016 perform better.
That said, even including gas, EURs of 900 kboe look
unrealistic
I have mentioned company proved reserves and PV10 quite a bit
here in the past two years.
I am coming to the opinion that these numbers, required by the
SEC, have too many uncertainties to make them worthwhile, at least
as to PUD. PDP may be useful.
They appear to have been increasing well performance since 2014,
maybe getting above 400k for oil if the curves continue (as below).
It looks like they recomplete after some time. It will be
interesting to see how the two 2016 curves go – started high and
then the first took a dive. The late 2015 wells did the same and
then jumped up, which looks like a re-completion. How much area
does one of their new wells drain? Presumably the savings must
mostly be on reduced drilling and completions cost, and maybe front
loading the returns with higher initial production, not overall
additional recovery.
Marathon announced today they'd have six
rigs average this year – up one – not sure if that is enough to
hold the decline near present levels, mostly that depends on
completions rather than rigs though, but they are going for
"multiple enhanced completion trials" and expect to increase
overall USA production by up to 20% (also six rigs in Eagle Ford).
Bakken data were out yesterday and we have seen a steep drop below 900 000
bbl/d nearly 300 000 bbl/d below its peak of 1.164 mill bbl/d in December (see
below chart). Well performance (new and existing wells) is down to a five year
low of 83 bbl per well and falling -20% year over year. This means a cost
increase per produced barrel of 20%, even if new wells are performing better
and costs per rig are down.
Since the well production declines by -20% over two years now, costs per
produced barrel are up 40% and rising fast. No wonder companies seem to abandon
Bakken for less mature fields such as the Permian. New permits are at five year
low and rig count is also grinding down slowly. Inerestingly, number of wells
are also falling – down 100 wells in December – which has been deemed as
impossible in some forecasting models.
I looked at Mexico production by area as below. The numbers in brackets show
percentage year on year change for exit rate 2016 to 2017. Only the small area
in northern offshore, which is not LMZ or Cantarell, is not declining. Even KMZ
looks like it might be turning over. If it goes like Cantarell as Nitrogen and
or water start hitting the producers then the will be a big acceleration, if
not then the decline might flatten out as the other fields make up increasingly
less of the mix. The plateau that KMZ achieved after N2 injection was started
is now quite long for an offshore field.
"... For the past eight years we were fed the constant stream of stories of mythical economic "recovery" and all the wealth created in this period from the bankers and economist. And as a result of all that illusory "wealth" retail sector was able to sell goods to consumers with empty wallets and maxed credit cards only by smashing prices to the bone – leaving almost nothing for the profit. ..."
"... Imagine the state of economy without this extra unconventional 5-6 mbd and $100 per barrel as a consequence. ..."
Steve,
Oil industry, and particularly Shale & Oil Sands part, lives in hope for the
last 3 years. And that is not reality, because hope means dream. Unless
someone's live in reality, here and now, they are dreaming. They are dead
weight, and tomorrow which will fulfill all their hopes is never to come.
Shale and Oil Sands are mostly North American origin of production with 5-6 mbd.
where we have the most consumption per capita in the entire world.
For the past eight years we were fed the constant stream of stories of
mythical economic "recovery" and all the wealth created in this period from the
bankers and economist. And as a result of all that illusory "wealth" retail
sector was able to sell goods to consumers with empty wallets and maxed credit
cards only by smashing prices to the bone – leaving almost nothing for the
profit.
Imagine the state of economy without this extra unconventional 5-6 mbd
and $100 per barrel as a consequence.
I disagree that it implies subsidies. What is implied is that
when oil is scarce, the price of oil will increase and more of the expensive
oil will be profitable to produce. Eventually the high oil price will lead
to greater efficiency in the use of oil (as measured by real World GDP per
barrel of oil consumed) and also some substitution of natural gas, and
electricity for oil in the transportation sector and after 10 to 20 years
demand for oil might fall below the supply of oil and lead to lower prices.
My main point is that the supply of oil depends on profits, not on net
energy or exergy of the oil produced. Profits will depend on revenue minus
costs and revenue will be determined by the oil price which is a function of
both
supply and demand for oil.
There is strong evidence that the US economy can survive only oil
prices below $100 per barrel without sliding into recession. Some
researchers put this magic "perma-stagnation" oil price as low as $60
per barrel. I think understanding of this fact is partially behind
this prolonged "oil price crush".
So it might well be that we do not have the freedom of "arbitrary"
oil prices in the US economy. and in worst case scenario we have oil
prices already close to the celling, unless the economy is
restructured.
That's why your line of thinking about this problem might be wrong.
In other words, this is a very serious situation for the USA. "The
long emergency" as James Howard Kunstler aptly called it (not that I
agree with his line of thinking or endorse his book).
Meanwhile the US is wasting time and money on the wars of
neoliberal expansion, which partially is "brut force" way of securing
privileged access to remaining oil deposits. Around 5 trillion was
spent so far, or 167 millions of Toyota Priuses at $30K per car, or
half of the US passenger fleet (there were 260 million registered
passenger vehicles in the United States in 2014)
So instead on concentrating on this fundamental problem that nation
is facing, the USA is just "waiving dead chicken" with the military
force. If we add the possibility of Seneca cliff that situation might
be even worse then I described. The nation does need radically cut the
amount of oil spend on personal transportation. Using all ways for
this that are technologically feasible. Because this is the lowest
hanging fruit. But very little was done in this direction on both
federal and state levels.
Meanwhile we expanded the fleet of SUVs for personal transportation
- this is now the most popular "form factor" for personal car, which
overtook sedans. Growth of the fleet of hybrid cars is unacceptably
slow (over 4 million units sold through April 2016; Japan, a much
smaller and compact nation, sold 5 millions).
Even such a symbolic act as switching of all personal government
cars to hybrids was not done by Obama administration, which preferred
only talk about the problem and opened spigot for shale junk bond. The
only their "real" achievement was "Iran deal" which probably was
instrumental in crashing oil prices. Which probably helped Obama much
more than it helped the USA economy as whole, but we should not
inspect the teeth of the horse that was given as a gift, as old saying
goes.
Also attempts to lessen huge traffic jams in large cities like NY
and SF are feeble, despite the fact that the technology is available
both to reroute the cars and to optimize traffic lights.
Converting existing roads network into "one way" network is almost
unheard outside the city center, even when two more or less adequate
parallel roads exists with the short distance of each other.
Variation of the number of lines each way is practiced very rarely,
in some city centers and selected bridges.
Green wave for traffic using Wifi connections between traffic
lights and cameras is in a very rudimentary stage.
The only progress that I noticed is that more and more traffic
lights at night autodetect the presence of the car on intersection and
switch to green light if there is not traffic in "main" direction.
From what I have seen it is generally accepted that EROEI for FF has
been and will continue (lots of peer reviewed papers documenting this)
to be in a downward trend. Then it is open for projections how fast
this downward trend will develop and its consequences.
What matters
is net affordable energy that will be made available for societies.
In the short term it is about flows, longer term; size and quality of
remaining stocks.
Selling assets to pay down dividends/buy back stocks is
liquidation.
Further up in this post Nathanel shared some great insights;
"Personally, from my background in general financial analysis,
the two really big metrics I've been watching lately: Dividends in
excess of current earnings mean a company in decline. Borrowing money
to pay the dividend means a company which is in unmanaged,
uncontrolled decline. (Managed decline would involve liquidating
assets to pay dividends, and *paying off* debt.)
"
"Look at what they do and not what they say."
Several big oil companies have used money for stock buy backs, but
another trend I found interesting is also how they move into renewable
(solar and wind). This should be an indicator about what these
companies find profitable.
Just to be clear, I think renewables are great, but we also need to
recognize the dominant role of FF.
I had trouble following the logic – one line seems to be that investors
continue to put money into oil companies because they (the investors)
believe in abiotic oil. I'm pretty sure that is wholly incorrect.
I don't get why the recent uptick in USA production (much of which was
due to GoM projects that had been started several years ago, not just from
shale drilling) has got anything really to do with the losses of the
companies highlighted. Is the suggestion that without that uptick investors
would have suddenly realised that all the oil companies are going down the
toilet? I'm pretty sure that's wrong as well.
LTO is still a relatively small part of ExxonMobil and Chevrons portfolio
(note if you look only at the upstream parts of those companies the losses
actually have been worse than shown, they were saved by downstream profits).
The losses are because of over investment leading to a supply glut. There
has been almost no impact from falling global demand. The over investment
was in all sections not just in LTO. LTO stands out because the supply can
be seen to clearly increase over the past few years, but it had not much
more impact than oil sands (also showing a clear increase) or in fill
drilling in Russia and Opec ME, which just acted to stop decline, and
therefore doesn't stand out so much.
That ETP thing gets thrown in but, apart from being wrong in many
different ways, doesn't seem to be linked to any of the other observations
or conclusions.
Negative cash flow does not automatically translate into unprofitably if
CAPEX is a big portion of it.
There are no doubts that oil companies have taken on more debts, but it
would be more helpful if debts were presented on a specific basis that is $$
of debt per barrel of oil (or oil equivalent) of reserves.
So far I cannot see the author has made any real attempts to explain the
thermodynamic oil collapse.
Good to see you woke up from the DEAD. Haven't seen you posting
much. Glad to know I am able to get you out of BED once in a while.
Anyhow . I would imagine we can use any financial metric to show how
profitable or unprofitable a company is by relating it to this or that
metric, but in the end the figures speak for themselves. The U.S. Major
Oil Industry is in big trouble. Hell, the majority of the economy and
financial system is one big BUBBLE looking for a PIN.
Regardless, ExxonMobil and the rest of the U.S. energy sector is in
serious trouble. While ExxonMobil only has $29 billion in long term debt,
their total liabilities are $169 billion.
There's lots of garbage hidden in these companies that most investors
tend to overlook.
"... Furthermore, well productivity in the Eagle Ford is detereorating over time compared to the wells drilled in previous years, which may suggest that longer laterals and bigger fracs result in only slightly higher IPs but much steeper declines. ..."
"... By contrast, new wells in the Permian continue to perform better than older wells. ..."
"... That may explain why drilling/completion activity and LTO production in the Permian have remained more resilient and are quickly recovering; while EFS has seen the biggest decline in production among the key LTO plays. ..."
"There is no data on average well quality for the wells that started production
in 2016. Is that because the data for last year is incomplete?"
If you go to the "Well quality" tab in the first presentation, you'll see 2016 profiles
as well.
The "Ultimate Recovery" overview only supports displaying production histories for wells
of the same age. As there are still 2016 vintage wells on which I have no data (the ones
that started in Nov/Dec), 2016 is not yet shown if you display it by "Year of first flow".
However, if you change the selection to "Quarter of first flow", or "Month of first flow",
then you will see more recent data as well, incl 2016.
You may remember past discussions here where we discussed displaying or omitting incomplete
tails in the well profile graphs. The Well Quality tab can show incomplete tails, while
the Ultimate Recover tab can't.
I just found that the number 2016 in the legend was hidden.
Comparing well performance in the Permian and the Eagle Ford, it seems that average
IP rates are not that different (582 b/d and 510 b/d, respectively, in the second month
of production), but declines in the EFS are much steeper.
As a result, by the tenth month, average well in the Permian produces 210.7 b/d, and
in the EFS only 122.6 b/d.
Furthermore, well productivity in the Eagle Ford is detereorating over time compared
to the wells drilled in previous years, which may suggest that
longer laterals and bigger fracs result in only slightly higher IPs but much steeper
declines.
By contrast, new wells in the Permian continue to perform better than older wells.
That may explain why drilling/completion activity and LTO production in the Permian
have remained more resilient and are quickly recovering; while EFS has seen the biggest
decline in production among the key LTO plays.
"In a somewhat related aspect, I've not seen
an updated graphic from Rune on the cash flow from major Bakken operators.
I've always felt that single frame told a very powerful tale, but not so much
pessimistic as one might think."
The chart likely referred to looks at Bakken(ND) as one entity and below is
an updated chart as per November 2016 and instead of monthly free net cash flow
it has now been annualized (last 12 months total free net cash flow) to enable
the same units on both axis.
For all 2016 the companies in Bakken will use about $2,500 Million more than
their free cash flow from operations (this is by not including the effects from
natural gas sales).
Using Billions = 1,000 Millions on one axis and Millions on the other may be
deceptive.
Average gross specific interest cost is now at an estimated $7/bo.
Whoever holds that debt
doesn't get repaid. What does that mean?
Nothing. If they are systemically vital to the global financial
structure, the central banks (plural) will create the necessary money and
GIVE IT TO THEM.
It doesn't have to mean anything. And further . . . if YOU were in charge
of the situation . . . YOU would do exactly the same thing. You would create
the money and GIVE IT TO THEM.
How could you not?
There's also another conceptual leap pending.
If that debt is NOT systemically vital to the global financial system,
but IS systemically vital to flowing enough oil for civilization to function
- that gets those debt holders bailed out, too.
whatever is the primary source of funds that flow to the LTO
industry, if they still flow, LTO production will continue. The recent
data suggest that inflows (in the form of IPOs, secondary share
issuances, proceeds from asset sales, acquisitions by the oil majors and
private equity firms, etc.) are again increasing. That means that
investments in shale oil and gas will rise in 2017 and the next several
years, and LTO production will rebound. And that will have an impact on
the global oil market.
As regards (excess) money printing by central banks, it affects all
parts of the economy, not just oil and gas industry. If there were no
money printing, people would not be able to spend thousands of dollars on
electronic gadgets; cars, including EVs; solar panels, wind turbines,
etc.
If they are systemically vital to the global financial structure, the
central banks (plural) will create the necessary money and GIVE IT TO
THEM.
I guess that's what happened to the sub-prime mortgage
crisis. The banks were "systemically vital to the global financial
structure". They all got bailed out. But the purchasers of those
sub-prime mortgages, mostly pension funds and such, were not considered
vital.
They got nothing!
Watcher,
You should write a post and ask for it to be posted on POB where you lay
out what it is we do not get.
I for one did not get the memo on central banks omnipotence.
Setting aside ground water contamination issues associated
with fracking, barring a major reduction in per capita energy
use even if (when) you replace coal with natural gas the CO2
emission rate is still a problem. Switching to non-fossil
fuel sources needs to be on the to-do list.
EPA said fracking isn't having "widespread, systematic
impacts on drinking water."
Even with non-fossil fuel
sources, C02 emissions rate will still be a problem. You
still need to build the wind turbines and transport them to
locations, you can't get do that until the transportation
sector reduces emissions.
My impression is that the current price of natural gas in
the USA is unsustainable. It is a kind of "subprime gas".
A side effect (externality if you wish) of fracking is
junk bonds bubble. At one point anybody with a lease can get
a loan to drill. Not that different from subprime, just much
smaller. Many people are not aware about it.
It might well be that "human induced climate change"
enthusiasts are barking to the wrong tree.
Oil depletion might take care of the "climate change" (as
well as "excessive" humans) even without Trump or and other
politician. This is probably a matter of a decade or two.
The key here is proactive switching the use private car
fleet to more economical model and without draconian measures
such as $4 per gallon gas or $1K per cubic centimeter of
engine volume tax the process is very slow.
Obama administration was pretty inactive in this area,
despite all rhetoric.
There is no justification of using full size SUV or light
truck for communizing to work unless you agree to pay extra
for this privilege.
Cumulative total of Bakken Formation oil production.
One billion of those barrels produced in the past five years, four billion
barrels to go with the projected 5.7 billion recoverable, another 20 years of
production in the pipeline to go.
By 2035, the Bakken oil will be about done, can't get anymore.
75 new wells per month, 12×20, 240×75=18,000 more wells over twenty years
time.
The price of oil at 50, 4.5 billion barrels of oil, 225 billion dollars.
5,000,000 dollars of cost per well, 90,000,000,000 dollars invested in
drilling those 18,000 new wells, 400,000,000 barrels for the extraction taxes,
money for the state, 20% for royalties, 80,000,000 barrels for mineral owners,
480,000,000 barrels to keep everyone happy all of those years.
The oil companies can keep 3.52 billion barrels to sell to get them some
money.
Times 50 USD per barrel to assess a value, 160,000,000,000 dollars in future
income to pay the 90,000,000,000 dollars owed for oil wells drilled. After
twenty years of production you will have 70,000,000,000 dollars left over for
the buzzards to pick clean.
A measly 3,500,000,000 dollars per year for the oil companies to share. 350
oil companies working, ten million dollars to share amongst stockholders and
employees.
The price of oil has to be more or the Bakken will slow to a crawl, then an
end.
What % of US oil consumption is food transport? This got tricky quickly.
Average US person eats about 5.4 pounds of food a day. That's just the food.
Average meal travels 1500 miles to reach your mouth.
First tricky item - packaging. It has to transport, too. Amazing variance on
this. Glass jar of pickles vs paper around candy bars. The only estimate out
there is numbers for municipal solid waste and estimates of % of that is food
packaging. Year 2000 US waste generation 4.5 pounds/day/person, and growing.
Probably over 6 by now based on the curve, but will use 5 lbs/day cuz round
number.
31% of that is packaging and half of that number is food packaging. Some
2006 study. So 15% of 5 lbs a day is 0.75 pounds added to the 5.4 pounds of
food is 6.15 pounds shipped a day per person.
For 1500 miles.
Eyeballing some charts looks like typical/average truck hauling weight for
stuff hauled is 60,000 lbs. Typical diesel mileage 6 miles/gallon.
6.15 pounds X 320 million mouths = about 2 billion pounds of food moved each
day
1500 miles / 6 = 250 gallons truck burned
2 billion lbs / 60,000 lbs = 33,333 truck trips X 250 gallons/truck trip =
198.4K bpd to move food.
Ain't much. Maybe there's an error in there. Top of my head . . . things not
included, hauling spare parts for the food moving trucks, spare parts for the
packaging gizmos, plastic packaging, agricultural consumption itself.
[Edit] Blurb says 17% of total US oil use is agricultural, up and downstream
(fertilizer plus fuel). This would be far more than food transport.
I am suspicious of that fifteen hundred mile figure, but it may be accurate.
Or it may have assumed a life of it's own, after being tossed out by one or
two people who really just guessed at it.
Most of the food that is produced in truly huge amounts, staple food, is
shipped by water, and or by rail, if it travels a LONG way. A VERY limited
amount of food, in relation to the total amount, is air freighted.
Here in the USA, it's not too likely that very much in the way of
unprocessed or processed staple food is shipped more than a thousand miles
by truck. Exceptions will be mostly fresh high retail value produce, shipped
as directly and quickly as possible from grower to retailer.
The REAL food miles come at the very tail end of the distribution chain.
I never owned an eighteen wheeler, but I did once own a C70 Chevy which
would legally haul about sixteen thousand pounds of apples to market. The
farthest local growers usually go with their own truck of this sort is about
a hundred miles, one way. Thirty gallons of diesel would take me that far,
and home again.
The people who actually bought my apples at retail, after they were
picked up at the wholesale market and delivered around town in smaller
trucks, usually bought no more than five pounds at a time.
I'm guessing, pulling numbers out of my hat, but I suppose a typical
shoppers average grocery purchase weighs from about twenty five to thirty
pounds, up to a hundred pounds,depending on family size, and is made on
roughly a weekly basis, on average.
And I'm guessing that the average trip to the super market is at least
six to ten miles, round trip. THAT's where the food miles really pile up. A
liter of gasoline burnt to get fifty pounds home, the last five miles, times
around a hundred million households, times fifty weeks, adds up. FAST.
Maybe. The pickle jar weighs a LOT and there's not much food weight part
of that. The whole packaging thing is a significant thing, and that's
another food item I didn't include, disposal of it.
I'm going to guess
the 1500 mile thing came from the coasts' pop centers and their daily
bread from Iowa and Nebraska. The various websites talking about this
like to talk about a head of Imperial Valley California lettuce going to
England. X calories burned for 1 or two calories delivered to the mouth.
But that sort of thing definitely would drag the average up. 1500 miles
maybe is legit.
I am surprised the total transport is south of 1 mbpd, if it truly is.
As for shipping, I can't see Iowa bread going to NYC any way but by
truck. Not going to fly it there. And the canals don't reach.
Everybody driving the last 5 miles to the store . . . maybe that
really doesn't show in the diesel calc. Oh! Of course. The issue is not
diesel. It's the 60,000 pounds per trip. A car is carrying the much lower
weight per your estimate. Will redo.
14 billion pounds of food move the last 5 miles by car per week,
probably at 150 lbs per weekly load (family of 4 at 6 lbs/day/mouth
incl packaging)
14 billion / 150 lbs = 93 million car trips per
week.
5 miles in a 25 mpg car is 0.2 gallons. X 93 million /7 and /42 =
an additional 63,000 bpd from the car trips added to the trucks above.
About 260K bpd for food transport.
Hmmm of course if it's 5 miles each way that's a X 2 on the 63K.
And SUVs for that trip, not a Datsun. Might be up nudging 400K.
It occurs to me that Pepsi and Coke may not be food, and they are
heavy.
I'm having problems with this 400ish K number because the
famous 2004 pie chart of US oil consumption said 65%
transportation, and of that 65% it was only 37% passenger cars, 18%
heavy trucks and 27% light trucks (sums to 45%), and that was
before SUVs (called light trucks) had swept up sales. Though F-150s
may have arrived.
0.37 X 0.65 is only 24% of consumption. Trucks light and heavy
rather more. So what are they hauling. Food as a daily consumable
would seem to be the dominant hauled stuff, but apparently not.
Most of the grain or flour that goes from the midwest to the northeast
probably gets there by rail, where it will then be baked into bread,
packaged, and shipped by truck to food distribution centers, or
directly to supermarkets. But the distribution center food warehouse
seems to rule these days, because it's better to load a truck up to
the doors with a variety of stuff all destined for one address or
maybe two or three, than it is to have a truck stop to deliver bread
and nothing but bread to a bunch of different stores. That means a lot
more total time and miles invested in stop and go driving, compared to
the one stop load. That still happens, but not as often as in the
past.
Grain is milled into flour near where it's grown, when possible,
because this reduces total shipping costs, being that the weight and
volume of flour is less than the weight of whole unprocessed grain,
plus the tailings are used mostly in livestock rations, and customer
for that product is most definitely NOT in NYC, lol.
Most of the cows,hogs and chickens we eat are raised in
confinement, and are raised in the mid west and southeast, closer to
the feed supply, and where land and water are cheaper, and neighbors
less fussy, and mostly in localities where neighbors are relatively
few in number.
Nobody's ever going to operate a modern supersize hog farm anywhere
close to the BIG APPLE,
Watcher's conclusion is probably right – not much fuel used to transport
food compared to the total available. On the other hand, some random
thoughts. 5.4 pounds/day/person is too high. Babies, young children,
seniors, etc. Second, the 1500 miles is too high. Some of the basics make up
a significant amount of the weight – like liquid milk, along with other
dairy products, cheese and eggs. These products generally will never go 1500
miles. Vegetables, seafood, fruit, etc yes. But, chicken, pork and beef – I
think that 1500 miles is too high.
Pre oil, railroad cars had no refrigeration to speak of in summer months.
That's where the term cattle car came from. Had to ship beef alive to the
cities.
I am not at all sure just HOW much of a cow winds up as nekkid ape
chow these days, but YOU most definitely don't WANT to know much about
what goes into processed meat products, if you plan on eating them.
Fifty years ago when I had the "insider tour" of a huge and
extremely famous hog slaugher plant that you get only by personal
invitation from management,even back then, they bragged about selling
everything but the squeal.
I'm pretty sure that well over fifty percent of the live weight of
a cow winds up as nekkid ape chow these days, but how much over I
can't say. Fifty to fifty five percent would be a reasonable guess.
Farmers have been breeding cows for more milk and meat, and less
waste, since the beginning. For the last seventy five years or so,
this breeding has been based on high tech such as artificial
insemination, a solid understanding of genetics, and very sharp
pencils. So a typical cow TODAY is going to yield significantly more
more than she did a decade or two back.
U.S. independent shale oil and gas producers are now cash flow neutral
From
the IEA Oil Market Report:
"So far, the shale and tight oil industry has always been characterized by
spending levels exceeding cash flow generated. Benefitting from the improved
price environment (including a 50% natural gas price increase over the last six
months), increased activity and enhanced cost efficiency, the US shale industry
is now closer to being able to fund capex programs within operational cash
flows. During 3Q16, for the first time in its history, the sector reached free
cash flow neutrality. In other words, after more two years of very difficult
times, the US shale business model seems on a much more sustainable path.
Nonetheless, it remains to be seen whether companies can remain cash flow
positive when the industry scales up activity and capital spending and as
upward pressure on costs once again takes hold."
Free Cash FLow for US Independents* (USD billion)
* / Free Cash Flow has been calculated analyzing balance sheets of about 50
US shale operators, having more than 80% of their revenues coming from shale
activities and covering over 60% of US tight oil and shale gas production
Operating cashflow
= net income excluding all non-cash items: depreciation and
amortization; asset writedowns; gains and losses on asset sales,
etc.
Operating cashflow includes only those interest expenses and taxes
that were actually paid during a certain period and differ from
"nominal" interest expenses and taxes that are shown in income
statement (as interest can be capitalized, tax payments can be
delayed, etc.).
In my view, operating cashflow is a better metric of oil and gas
companies' operating results than net income.
Free cashflow shows what is left in a company's coffer after it
has spent part of its cash on organic (non-acquisition) capex.
Negative free cashflow means that the company has to borrow money
to cover its expenses.
Positive free cashflow means that the company can pay down part of
its debt or keep free cash on its accounts.
Unlike oil majors, which tend to spend a significant part of
their cash on dividends and repurchase of their own shares, U.S.
E&Ps normally do not pay or pay relatively small dividends.
The above chart from the IEA monthly report shows that the group
of 50 largest shale companies have finally achieved free cash flow
neutrality in 3Q2016, which means their quarterly operating
cashflow is roughly equal to the sum of their capex and dividends.
That was due to a sharp reduction in capex and lower costs.
I came to similar conclusions, as the IEA, after looking at 2Q
and 3Q results from a few large U.S. shale companies.(Of course, my
sample group was much narrower than 50 companies).
The shale oil industry has been in positive cash flow situation
since prices got above 40 dollars a barrel. Sorry, this is a
meaningless assessment of a meaningless article. Positive cash
flow basis to what extent, exactly?
"Free cash flow (two words) shows what is left in a company's
coffer after it has spent part of its cash on organic
(non-acquisition) capex." Negative. This implies that all wells
being drilled by the 50 shale oil companies referenced are now
being paid for out of positive cash flow. I don't think so. If
so, at the expense of deleveraging, so what?
"Negative free cash flow (two words) means that the company
has to borrow money to cover its expenses." Define expenses,
please. Including developmental CAPEX?
"Positive free cash flow (two words) means that the company
can pay down part of its debt or keep free cash on its
accounts." Right. Give me a percentage of the total 50 shale
companies surveyed that paid down debt in 2016 and to what
extent, please. Last I looked even EOG did not have COH to cover
this years maturities.
"The above chart from the IEA monthly report shows that the
group of 50 largest shale companies have finally achieved free
cash flow neutrality in 3Q2016, which means their quarterly
operating cash flow (two words) is roughly equal to the sum of
their capex and dividends." How many of these stinking shale oil
companies even pay dividends? Come on, Alex. That's BS and you
know it. List the 50 and show their losses for 3Q16.
Shallow is right, positive cash flow fills the coke machine
down the hall, for the first time in 25 months, that's it. If
these shale guys are using cash flow to drill more stinking
wells, they are doing so at the expense of deleveraging legacy
debt. The marginal price per barrel of shale oil is a
meaningless metric now. All of these guys are up to their asses
in debt. Folks have got to let this ridiculous IEA, EIA, SPCA
and NCAA bunk go and get planted on earth about this shale oil
stuff. Nothing has changed in the past 5 months except that OPEC
added 5 dollars a barrel to the bottom line. Temporarily.
I guess our goal every time we have borrowed money to buy an
asset, be it an oil lease or otherwise, was to pay down the
loan principal to zero.
Further, we have not borrowed money to drill or work over
wells.
Currently, in the commodity spaces I am familiar with,
most asset values are still high, despite much lower
commodity prices (grains, oil and natural gas).
I assume increasing interest rates may change this, but
maybe not?
We looked at a small oil lease recently. It was priced as
if the price of oil was a steady $80. It sold for the asking
price. In the first quarter of 2016 the lease lost money on
an operating basis. It was barely cash flow positive for
2016. Fifteen years ago, the same lease, being also barely
cash flow positive in 2001, would have sold for 1/10 of the
current sale price, IMO.
Witness record acreage prices paid in the Permian earlier
this year.
Farmland is the same. Grain prices are down for the third
year, yet land is barely off highs. Net cash rental income,
after payment of real estate taxes, is 2.5% or less. This is
pre-income tax returns.
I am not smart enough to know what this means, or what one
should do in this situation, unfortunately.
I will say, however, I believe few now have the goal of
buying assets and paying the debt down to zero. It appears
commodity assets are now about leverage, churn and other ways
to make money from them, besides from the income produced by
the assets themselves.
One area that I think will only get worse is commodity
price volatility. I read a long article recently about this
with regard to grain prices, written by a large, well
respected farm management company. They have really put an
emphasis on marketing, they say farmers that don't
aggressively hedge will have a tough time.
This I believe is true for oil and gas too. Unfortunately,
the cost to hedge has risen dramatically. I recall buying put
options near the market for under a buck a barrel around
12-14 years ago. Those now go for $4+.
AlexS, I do not think operating cash flow is the only
metric to look at. If we had paid $150K per barrel in 2013
with borrowed funds, the fact that we have had positive
operating cash flow in 2016 would be of little solace.
I contend there is mucho debt in the industry that will
continue to be "rolled", little will be paid through net
operating income. However, much may be paid through equity
issuance.
I sure hope the upstream oil and gas industry is not a
microcosm for the whole economy. I'm not smart enough to know
that either.
"I am not smart enough to know what this means, or what
one should do in this situation, unfortunately."
That's
fascinating data, "shallow sand". This is the sort of
information I love to get so that I can analyze it, so
I'll give it a shot. This is first pass.
I think we're watching a bubble. This smells like
bubble.
(1) There is too much money among very rich people
chasing too few good investments. Accordingly, the prices
of investment products are getting bid up in a bubble.
(2) The bubble in oil, in particular, will burst as they
see how terrible the rates of return are.
(3) The middlemen and speculators are of course
exacerbating the bubble; they always do.
(4) When the bubble bursts, a lot of wealth will "vanish"
overnight. It is best to be out of it before it bursts -
sell at the top of the bubble if you can, and switch to
something which is selling with less inflated prices.
(5) Farmland might be the same sort of bubble. The other
possibility is that it might not have the same bubble
behavior: its value might increase - if you get the right
farmland, farmland which is likely to continue to do well
despite climate change - as there are definitely
predictions of droughts and crop failures coming in the
next few years.
(6) Because of the excess of investment money, it may be
impossible to find anything you're comfortable with which
isn't selling at inflated prices, sadly. Paying off debt
is an option if you have debt. Or insuring yourself
against liabilities (are all your well capping and
clean-shutdown costs prepaid?). That sort of thing.
Clueless should weigh in. I've seen the definition get massaged
here and there.
Cash flow is inputs and outputs, and while SS
is asking about interest above, that's not the debt focus. New
borrowing can be called a cash influx. I've seen it done. New
borrowing improves cash flow over a period measured. If you
define it that way, you can borrow your way to prosperity.
Watcher is mostly right. For example, there are only a small
minority of companies that use GAAP earnings as their primary
earnings measure. They all must report GAAP earnings, but
usually tout some other earnings measure as their earnings
that "are more useful for investors to understand the
company's financial performance." The GAAP earnings for the
most part are standardized. The "more useful" numbers are
based upon each company determining for themselves what they
will include/exclude. In many cases, totally self-serving.
However, they must provide a reconciliation between GAAP
earnings and the "more useful" earnings.
With respect to
cash flow, each 10-K (annual) report and 10-Q (quarterly)
report includes a GAAP standardized statement of cash flow.
You may not be able to glean the information that you seek
from that report, but it is the only one that I would trust.
Other statements that a company may make in presentations,
discussions, etc about "cash flow" I would not trust without
a complete detailed discussion of what they were
including/excluding in the calculation.
I used the term for GAAP earnings as being "somewhat"
standardized. With respect to oil and gas exploration
companies, there are 2 different acceptable GAAP standards:
successful efforts and full cost. Successful efforts expenses
dry holes. Full cost capitalizes them into the pool of
depletable costs and expenses them as the reserves are
depleted. [Kind of like a manufacturer. Say that quality
control finds one out of every 500 circuit boards to be
defective. The company does not immediately expense that
circuit board. The total manufacturing costs are allocated to
the inventory of 499 circuit boards.] But, in the event of
significant oil/gas price plunges, the calculation of the
amount of write-downs of capitalized/depletable property is
also different, depending on which method is used. That
becomes a big deal if prices fully recover, because the
write-downs are never reinstated.
Not very busy at this moment, so you got a lot of
rambling, which I hope is mostly correct.
Free cash flow is a widely used measure of a
company's financial performance.
Unlike breakeven price and similar indicators which everyone
calculates using its own methodology (and nobody discloses this
methodology), free cash flow can be easily calculated using the data
from company's SEC fillings.
Below is a definition of free cash flow from investopedia:
Free cash flow (FCF) is a measure of a company's financial
performance, calculated as operating cash flow minus capital
expenditures. FCF represents the cash that a company is able to
generate after spending the money required to maintain or expand its
asset base.
FCF is an assessment of the amount of cash a company generates
after accounting for all capital expenditures. The excess cash is used
to expand production, develop new products, make acquisitions, pay
dividends and reduce debt.
Some believe that Wall Street focuses only on earnings while
ignoring the real cash that a firm generates. Earnings can often be
adjusted by various accounting practices, but it's tougher to fake
cash flow. For this reason, some investors believe that FCF gives a
much clearer view of a company's ability to generate cash and profits.
However, it is important to note that negative free cash flow is not
bad in itself. If free cash flow is negative, it could be a sign that
a company is making large investments. If these investments earn a
high return, the strategy has the potential to pay off in the long
run. FCF is also better indicator than the P/E ratio.
FCF is a good indicator of the performance of a public company.
Many investors base their investment decisions on the free cash
generated by a company or its equity price to FCF ratio.
It may seem strange that shale companies had negative free cash
flow when oil prices were around $100, but achieved FCF neutrality
in 3Q16 when WTI averaged only about $45.
The explanation is very
simple. In 2010-14, shale companies were heavily investing, which
helped them to achieve double-digit growth in production and to
increase overall U.S. LTO output by ~1 mb/d each year in 2012-14.
While negative FCF is not necessarily negative, in this
particular case, shale companies' strategies proved
self-destroying.
1) Negative FCF led to accumulation of very high debt;
2) High demand from shale companies resulted in a sharp increase in
unit costs for oil services and other inputs;
3) Rapid growth in LTO production caused the glut in the the global
oil market and consequent drop in oil prices.
Lower oil prices led to a sharp reduction in shale companies'
operating cash flows. But these companies even more sharply reduced
their capex.
Finally, in 3Q2016 their combined capex was roughly equal to
combined operating cash flow.
The above chart from the IEA Oil Market Report shows it very
clearly.
AlexS. I do not disagree with you that the metrics you are
explaining (very well, I might add) are very important.
However, I assume you agree that balance sheets and estimates
of future cash flows are also important to look at.
In reality, all can be reviewed in SEC filings, which are the
only numbers that are reliable. Company power point
presentations are meant to be promotional material.
FCF is a good shapshot of a company's
financial performance in a particular period. Of course, it
is not sufficient for understanding of this company's whole
financial situation and its future prospects.
FCF neutrality in 3Q2016 means that the group of 50
companies didn't have to increase their debt, but debt
accumulated over the previous years remains on their balance
sheets and is a heavy burden for future development.
Furthermore, FCF neutrality was achieved thanks to lower
capex which resulted in declining oil production.
Higher oil and gas prices expected for 2017 should improve
oil companies' operating cash flows. A number of shale
players have already announced planned increases in capex of
10-50% for next year. That will likely reverse the decline in
LTO output. But higher capex will not allow shale companies
to achieve significant positive FCF, and hence to start
repaying their debt.
At $55-60 they will be able to only slightly increase
output by year-end 2017 vs. year-end 2016, while maintaining
FCF neutrality. A more aggressive increase in capex would
result again in negative FCF and increase in debt.
Furthermore, increase in shale companies' spending will
reverse oil service cost deflation, which was the main
contributor to declining unit costs in 2015-16.
In my view, a conservative financial and operational
strategy, with gradual and modest increases in capex, should
allow a moderate growth in LTO production over the next few
years without significant increase in debt levels.
But a return to previous growth rates of 1 mb/d p.a.
anticipated by some experts (including Rystad Energy) from
2018, would result in further deterioration of shale
companies' financial situation. And it would have a negative
impact on oil prices.
Yeah, something critically important in addition to free
cash flow is the growth (or, in *this* industry, decline)
trajectory. It's great to have free cash flow this year,
but if your wells all run out in two years and you haven't
drilled more, well, your free cash flow this year and next
*is the total value of the company*, because there won't
be any free cash flow in year three.
Well, actually,
it's not even that good: liabilities also have to be
considered.
Easier said than done. Look at the latest 10-Q for CLR. It seems to
me that there would be a lot of questions about their results,
especially when you look at their operating cash flow and notice
the large impairment charge that is added back, thereby not
affecting cash flow from operations negatively. But they lost that
cash almost as surely as if they drilled a dry hole.
clueless. Regarding CLR and SEC filings, I have brought up
several times that the company managed to reduce its estimate of
future production costs by 60% from 2014 to 2015, while only
reducing all categories of proved reserves by just 9% during the
same period.
I believe there were some things pulled to keep
PV10 above long term debt in 2015 and I expect the same for year
end 2016.
the large property impairment charge in CLR accounts
for 3Q2016 ( $57 million for 3Q and $203 million for 9 months of
2016) is the result of negative revaluation of their reserves
(due to lower oil price). It is reflected in the balance sheet
as lower net property and equipment (compared with previous
period) and as lower shareholers equity.
It is also shown in the income statement, but added back in cash
flow statement as that's not real cash paid by the company.
It's a paper loss.
Dry hole cost is very small ( $27 thousands for 3Q and $233
thousands for 9 months of 2016). The cost of drilling wells was
already accounted as capex. Then the cost of of successful wells
was capitalized (and added to PP&E in the balance sheet) and dry
hole costs are expensed and appear in the income statement as
expenses. But they are added back in cash flow statement as cash
paid for both succesful and dry wells was already included in
capex.
Alex, thank you for your detailed explanation of free cash
flow. After 40 years of operating oil and gas wells I
understand the definition very well. It can indeed be used,
as you have said, as a snapshot of financial activity within
in a brief period of time. As I have said, and Shallow, I
believe, it is of little importance in the grand scheme of
things. The shale oil industry is in serious financial
trouble and 5 dollars a barrel on the "hope" of OPEC cuts has
not changed that.
Its curious to me this intense need for some folks to make
predictions about the future. Predicting the role shale oil
might play in that future over the next decade, or decades,
without understanding the financial condition of those
companies extracting it, is a big mistake in my opinion. The
shale oil phenomena has not been paid for yet, nevertheless
you and others are counting on it decades thirty years from
now. I do not understand that, sorry. I really don't have
much to contribute here, it seems.
I agree LTO will contribute very little in the
grand scheme.
Lots of agencies and companies provide outlooks of the
future. The Chart below shows the BP Outlook 2016 for
C+C+NGL and my "medium" scenario for C+C+NGL with URR=3600
Gb for 2015 to 2035.
I don't know who is the author of that
article, but the very first phrase about operating cash
flow is a complete nonsense:
"The way Cash Flow from Operations is calculated is by
starting with net income (equity earnings) which doesn't
include interest paid to debt holders."
Of course, net income includes "Interest expense".
See CLR's 3Q accounts; income statement.
Net interest expense for the quarter was $82 million.
Developing countries, like China and India are urbanizing and their populations are becoming more affluent, this will increase
global energy demand 24% by 2040. This includes the ExxonMobil prediction that energy use efficiency will double (figure 4).
The world population will increase from 7.3 billion today to over 9 billion in 2040, with a much larger middle class population
(defined as >$14,600 and <$29,200 yearly for a family of 4) using energy than today. World GDP will effectively double by 2040.
Living standards will rise dramatically, especially in the developing world.
Natural gas consumption will increase 54 quadrillion BTUs by 2040. Nuclear and renewables will increase 24 and 20 quadrillion
BTUs, respectively. The 2040 energy mix will remain about the same as today (figure 5 and Table 1).
Rising electricity demand will drive the growth in global energy between now and 2040. The increase in the number of homes
with electricity, industrialization of the developing world and our increasingly digital and plugged-in lifestyles will drive
this growth. Half of global electricity demand is from industrial activity; thus good jobs can be lost if electricity costs
are too high. Jobs will move to locations where electricity is cheap, an example is the new Voestalpine steel plant in Corpus
Christi, Texas.
Crude oil and natural gas will remain the world's primary energy source. Even in 2040 oil and natural gas will supply 57%
of all energy demand, this is an increase from 56% today. Oil demand will grow 18% through 2040 and natural gas demand will
grow 44%. The developing world will account for the largest increases. Unconventional ("fracked") oil and gas, oil ("tar")
sands, and deep water oil production will account for over 25% of the liquid supply in 2040.
Carbon dioxide emissions will increase, at least until 2030."
High taxes create a "tax shield". The price at the pump in Europe is approx. 1/3 oil and refining and 2/3 tax and duty (see
http://euanmearns.com/energy-prices-in-europe/ ). Consumption
is therefore less responsive (inelastic) to the international oil market price compared to the USA. Also, Europeans have adapted
to this over time and drive smaller and more fuel efficient cars.
Several oil producers have cut back on subsidies during the last couple of years. This should restrict domestic demand increase.
Most oil exporters' oil consumption/capita will probably level off and never come close to the US figure. However, given the level
of population growth and demographics (young people) in MENA their domestic consumption is unlikely to reduce significantly (slight
increase seems more likely).
The only major exporter not there is Russia at 0.02, but President Trump will help them increase. Not an exporter, but FYI Singapore is highest I've seen at 0.24.
"The only major exporter not there is Russia at 0.02, but President Trump will help them increase."
How? Will he help to increase car fleet in Russia? KSA and its neighbours use a lot of oil for electricity generation.
Russia uses natural gas, nuclear, hydro and coal.
Just to add information, in Europe, taxes are split in two parts: excise (typically fixed amount) and VAT (variable amount). For
gas in Belgium, excise are about 0.60 per litre or half the price of gas.
So price variations due to oil international prices
are attenuated. Add to these that taxes decreases when oil price increase and increase when oil price decrease. This is a way
to guarantee revenue for the State when oil prices decrease.
After the Jean Laherrere post on global reserves I had a go at predicting a future supply trajectory
myself. It is based on 620 Gb developed declining at 4.35% annually; 150 Gb discovered and undeveloped
with about 120 identified from identified conventional projects on companies' books and 30 from
shale; and 25 Gb undiscovered represented by a linear decline from current discovery numbers over
twenty years. That gives 795 Gb reserves remaining – about what he had.
Note the figures in the legend give the overall production in the years shown on the chart.
Extra heavy oil is given as 30 kbpd coming on stream every year until 2023 representing the
drop off in tar sands development and probable falls in Venezuela production, and then 200 kbpd
added for every year after. As the projects take about 5 years to complete this would represent
about 8 in development at any one time, but also requiring projects for 3 or 4 upgraders, 1 or
2 pipelines and a new refinery to be ongoing in parallel.
For new conventional projects I assumed a one-year ramp up, a ten-year plateau and 10% yearly
decline to shut down after 25 years. The numbers coming on line until 2022 I've taken from what
is currently on the E&Ps books with some probable short-term projects that could be developed
in time. After that I just made reasonable guesses, assuming an extra three-year development time
from discoveries for ne fields.
The results aren't very different from Dennis Coyne's except there isn't a new peak (in 2018
which he is predicting – I don't know where that extra production could come from based on current
development activity) and there is a big gap in 2019 to 2022 reflecting the capital cuts over
the past 3 years.
The biggest issue for me is that, assuming exporter countries maintain the same overall internal
demand at about half current production, then net exports would fall by 50% in 2032 and to zero
by 2041. There is also a 20% decline in available exports between 2018 and 2023. Things wouldn't
be quite so clear cut as some countries will continue to export while other producers become net
importers.
If this is close to reality I don't see it making transition very easy. Apart from added renewables
and nuclear, and increasing efficiencies there will be a turn to gas if there is sufficient easily
available, a loss in demand from recession (depression in a lot of places I suspect), and I think
also an inevitable turn back to coal maybe with another push to in-situ gasification.
OK, I have to bring in a not-directly-oil-related comment, because it's related to demand.
My non-oil projections for growth of electric cars - which are the key technology displacing
oil usage. I believe since they are superior technology, they are essentially production-limited.
I believe price issues will be automatically addressed by economies of scale as production
increases.
So my production projections see a big increase in electric car sales in 2018 (thanks
to models we already know about). I believe the high sales in 2018 cause much, much more
capital , which causes much more investment by car companies. This takes 2-5 years to pay
off. So I see a huge increase in production (and therefore sales) in the 2020-2023 time
range.
Specifically - to get back to oil - I believe sometime in that time range, 2020-2023,
is when electric car sales per year become large enough to displace an amount of oil exceeded
the natural decline rate of oil fields (I've seen different estimates for that rate, but
it's a close enough range that it doesn't matter for this projection). This is still well
before market saturation is reached.
So combine this with your projection out to 2022, along with Laherrere's and Coyne's
projections out to 2022, all of which are similar. Before sometime in the 2020-2023 range,
we can expect petroleum demand to remain solid. But after that, demand will be dropping
faster than the natural drop in supply. There will be a *glut* of oil. There will be no
new drilling, or at least not profitably.
If a bunch of oil projects are started in the 2016-2023 period which start producing
after 2023, they won't pay off, they'll be big money-losers and make the glut worse. (With
a three-year project time, the glut will remain brutal for three years afterwards as old
projects go online.)
At that point, low oil prices become the determining factor in the size of reserves.
High-priced producers go bankrupt and shut down. Refineries, now with excess capacity, go
bankrupt and shut down. Refineries have to retool to optimize for aircraft kerosene production
instead of gasoline production. I think it's about this time - after a bunch of bankruptcies
which leave wells in a derelict state - that the regulators start going after the survivors
to cover their environmental liabilities preemptively, making them plug wells properly.
I'm not exactly sure how the rest of the shakeout happens, but I'm glad to be totally out
of the industry before then.
Thanks George. That's a fascinating chart. Thanks for breaking out the different production
sources. How the world is going to get by on 20% less available exports by 2018 to 2023
is going to be interesting. Zero available exports by 2041! That's gonna be a damned mess.
When oil prices rise in 2017 and 2018 there will be
increased output from Russia and OPEC, in my view.
A lot of output in those nations has relatively short time for
development, they just need to develop already discovered reserves, there
will also be some increase in US LTO output and Canadian oil sands output
with higher oil prices. Possibly the peak will be lower, but I expect a
at least a 50% probability that the 2015 peak will be surpassed.
Dennis – can you say what those resources are – i.e. field names,
expected production, time to develop. Because I know of nothing like
that, and can't think of anything in the past where 1 or 2 mmbpd has
been bought on line from FEED to plateau in 18 months, which is what
you seem to be assuming. I can only think of Iran as a possible source
– but most of their stuff is gas flood, that needs big compressors to
provide the injected gas – it is impossible to go through a design,
procurement and start-up cycle on such systems in under 24 months.
There are combined cuts of 1.7 Mb/d. That production from OPEC
and Russia can be brought online in June 2017. Also infill drilling
will increase in other nations as oil prices increase.. My scenario
is pretty conservative relative to IEA and EIA Outlooks.
I do not have information on specific fields and
developments.
The IEA and EIA do have this information and their future
outlooks are quite a bit more optimistic than what I have
presented. I believe that those estimates are too optimistic and
yours may be too pessimistic.
A problem with your analysis is that you seem to assume no
reserve growth just as Jean Laherrere does. I believe an
assumption of no future reserve growth leads to too pessimistic
an outlook.
US reserve growth from 1980 to 2005 was about 63%. I have
assumed C+C minus extra heavy reserves will grow by about 300 Gb
from 2010 to 2060 or 300/850=35% over 50 years. Perhaps that is
too optimistic, time will tell. Also I assume LTO resources in
the US are only about 40 to 50 Gb, possibly too optimistic, but
less so than the EIA.
Oil price appears to be
shyly
creeping up maybe because it's
testing the ceiling at where the economic engine starts sputtering and
backfiring?
A little late, but, just-viewed (and recommended)
The Overnighters
Desperate, broken men chase their dreams and run from their demons in
the
North Dakota oil fields
. A local Pastor risks
everything to help them.
"The Overnighters is a feature documentary produced, directed and
photographed by Jesse Moss was awarded the Special Jury Prize for
Intuitive Filmmaking [etc.]
'The director, Jesse Moss, plays it as it lays. An observational,
near-invisible presence, he fills the frame with the faces of economic
deprivation and bad choices, neither judging nor sugarcoating. What
emerges is a blue-collar meditation on the meaning of community and the
imperative of compassion.' ~ The New York Times, Critics' Pick, Jeanette
Catsoulis
'A remarkable nonfiction essay on golden rules and grand intentions
and oil booms that do not pay off for everyone a rich and troubling
documentary highlight of the year.' ~ The Chicago Tribune, Michael
Phillips
'Like a punch in the gut. I can't remember the last time a documentary
hit me so hard layered, provocative, and surprisingly intimate" ~
Leonard Maltin
'If John Steinbeck were writing in the second decade of the 21st
century, 'The Overnighters' is precisely the story he'd want to tell' ~
Salon, Andrew O'Hehir
Another year; another section of the Russian-roulette rollercoaster ride
(where corkscrews could mean missing rivets )
A ten percent drop in oil production over 12 years appears quite manageable.
All we need is a twenty percent efficiency gain in that time to handle it
easily. It will help push EV production.
Yes, there is value. The long term predicament has
potentially awful implications, and it seems better to prolong the status
quo than face the reality that things are changing. Increased production
efforts now will result in some additional supply coming online a few
years down the road when it will likely be sorely wanted.
Besides, the short term goal is more likely tax reductions and
subsidies that can affect balance sheets in the shorter term. In the oil
business, the long emergency is now. New production for the long term is
less critical than financial survival.
More free money is probably the only thing that will increase
production. I can't see reasoned investment decisions going to E&P in
this uncertain business climate, but free money clouds the view of risk,
so fools will rush in, if history repeats.
Yes, there is value in political hopium. Keeps the masses from
thinking about change.
The politicians won't do what we think they will anyway, for the most
part.
Oil and gas supply is now falling. The chart below shows pretty clearly why
there was a glut: over investment leading to over supply, which is now
correcting. Nothing much to do with demand reduction that I can see. One thing
I haven't seen discussed, and can't find find a lot of analysis on, is how much
either direct motor fuel subsidies (e.g. in producer countries and some other
developing countries) or high taxes in Europe tend to reduce the impact of
prices on demand changes. I'd be interested in any opinions or references.
This is the a boom and bust cycle combined with the end of life in a mature
basin looks like (for the UK – only one new field approval this year to
September).
And this is why the coming bust in supply might be a bit different from
previously – something changed in the oil industry in December 2014 and I
don't think things will play out quite as they have previously, even with
rapidly rising prices, given the debt load.
According to the
Energy Export
Databrowser
they were still exporting about 600,000 bpd in 2015. That
year their exports dropped by 21%. It is entirely possible that export
dropped past zero in 2016 and they became a net importer.
However I guess we will just have to wait until we have the total 2016
data. But if anyone else has any further data I would love to hear it.
"I had read somewhere that the value of imported refined products was
near to equaling the value of their exported crude."
Correct.
The drop in Mexico's net exports of crude oil and refined products was
much steeper in value terms than in volume terms. It declined from
US$26.2bn in 2011 to U.S.15.6 bn in 2014 and just 400 million in 2016.
Mexico: value of the foreign trade of crude oil and refined
products (billion U.S. dollars)
source: PEMEX
"It would be interesting to compare the money they earn exporting
crude to the money they spend importing refined products. Either way,
Mexico is on the brink. Just as Indonesia had to fall back on other
forms of revenue, like destroying their forests, once oil exports
became oil imports, Mexico will have to find something else to lean on
once oil doesn't pay the bills."
A sharp drop in the value of net
crude and product exports had a negative impact on Mexico's foreign
trade balance, which deteriorated from virtually zero in 2012 to a
deficit of US$14-15 in 2015-2016.
But that's not critical, as oil and product exports now account for
only 5% of Mexico's total exports, down from 16% in 2011.
Has there been a country before in which oil and gas production has stopped? I
can't think of one, but Denmark might be the first in coming years, what with
DONG pulling out of fossil fuels, cancellation of an oil project last year (I
think the last real prospect for them – I've forgotten the name though) and now
this:
"Maersk Oil today confirmed it would cease production on its North Sea Trya
field. The operator said it had failed to identify an economically viable
solution for the full recovery of the remaining resources in the Denmark's
largest gas field. Maersk Oil COO Martin Rune Pedersen said: "Tyra has since
1984 been the main hub for gas production and processing in the Danish North
Sea. The Tyra facilities are approaching the end of their operational life, and
together with our partners in DUC we have assessed solutions for safe
decommissioning and possible rebuilding of the Tyra facilities."'
As I recall the seafloor had been subsiding as the reservoir pressure has
been reduced. Jacking up existing facilities or rebuilding would be expensive
for the remaining gas resource. I think the hub receives associated gas from
some oil fields which will need to be rerouted as part of the decommissioning.
December U.S. light-vehicle sales are forecast to finish strong enough for
2016 to top 2015's record 17.396 million units. However, actual volume
largely will be determined by results in the final third of the month,
because a major portion of December's deliveries typically occur after
Christmas.
The forecast
17.7 million-unit seasonally adjusted annual rate
is
below November's 17.8 million, but above December 2015's 17.4 million.
...
Despite the drop in December's volume, total 2016 sales will end at 17.41
million units, barely edging out the all-time high set last year.
emphasis added
Here is a table (source: BEA) showing the 5 top years for light vehicle sales
through November, and the top 5 full years. 2016 will probably finish in the
top 3, and could be the best year ever - just beating last year.
Light Vehicle Sales, Top 5 Years and Through November
"... ...in 2016, 96 percent of all new vehicle sales featured a combustion engine. IHS Markit estimates the average vehicle life globally to be about 15 years, which means that the impact of new vehicle technologies is expected to take time to materially affect the vehicle fleet and overall fuel demand. ..."
...in 2016, 96 percent of all new vehicle sales featured a combustion engine. IHS Markit
estimates the average vehicle life globally to be about 15 years, which means that the impact of
new vehicle technologies is expected to take time to materially affect the vehicle fleet and
overall fuel demand.
Proved reserves of crude oil in the U.S. declined by 4.7 billion barrels or 11.8 percent from
their year-end 2014 level to 35.2 BBbls at year-end 2015. Natural gas proved reserves decreased
64.5 Tcf to 324.3 Tcf, a 16.6 percent decline.
... ... ...
Proved reserves are volumes of oil and natural gas that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
"... What's shocking about that chart AlexS is that even with the sharp price increases of oil between 2000 and 2014, the oil R/P ratio has still steadily declined. With investment having been crushed in the last few years, looks like we are facing a Seneca cliff. ..."
The situation with global natural gas is different.
1) There is significant spare capacity in a number of countries. For
example, Russia has reduced gas production in the past few years due to
falling demand from Europe, but can easily increase it if demand returns.
2) There are significant developed and undeveloped proven reserves.
Reserves/production ratio is much higher for natural gas (see the chart
below).
3) Natural gas resources are generally explored less than oil. Potential
for increase in proven reserves is much bigger for natural gas.
The countries and regions with significant resource potential and able to
sharply increase production include: Iran, U.S., Russia, East Mediteranean,
several countries in Asia (including China).
Several countries in Africa are not producing at full potential.
Global proven reserves / production ratio for oil and natural gas
source: BP Statistical Review of World Energy 2016
What's shocking about that chart AlexS is that even with the sharp price
increases of oil between 2000 and 2014, the oil R/P ratio has still
steadily declined. With investment having been crushed in the last few
years, looks like we are facing a Seneca cliff.
The chart is named "Annual conventional oil and gas volumes discovered".
Onshore Canada production is dominated by oil sands; US lower-48 onshore
– by tight oil.
Conventional output in both cases is from mature fields; and there were
no major conventional discoveries for many years.
US shallow-water GoM is also a mature province. New discoveries were
made in deepwater GoM.
Instead of switch to
hybrids and smaller cars as well as using nat gas for local city tranport they are trying to comsume
as much as possible. Without high tax of SUVs and opther "oil waisting" personal tranporation
veiches it is impossible to sustain the US economy. the only question is when it falls from the
cliff.
I've never understood the urgency of using up US oil so quickly. Better to buy someone else's at
a cheap price and save ours for a time when it is depleted elsewhere.
Its' not only the USA. KAS, Iran and Russia are doing
the same. There are a lot of short termism obsessed
politicians besides Obama administration
Especially KAS in 2014-2016. Who were instrumental
in the current oil price crash.
But behavior of the Iran and Russia was also
deplorable. Iran decided to get back its former market
share at all costs. But they like KAS are governed by
religious fanatics, so what we can expect?
At the same time Russia, which theoretically should
be a rational player and have enough space and steel to
build huge national oil reserves, using it as
alternative currency reserves, did nothing. Instead
Russia also increased oil production selling its
national treasure left and right, while prices were
hovering below $50.
Another bunch of short termism obsessed suckers. So
much about Putin as a great statesman. And what he got
in return for his stupidity - only additional sanctions
and allegations that he fixed elections for Trump. Such
a huge payoff.
IMHO of big oil producing nations only China behaved
rationally.
Oil is not renewable resource and burning it in
large SUVs and small trucks carrying one person to
commute to work is a suicide. That's what the USA is
doing on the national scale. Add to this all those wars
for the expansion of the US neoliberal empire, the USA
is fighting, which also consume large amount of oil and
it looks even worse. See
http://www.ucsusa.org/clean_vehicles/smart-transportation-solutions/us-military-oil-use.html
The U.S. military is the largest institutional
consumer of oil in the world. Every year, our armed
forces consume more than 100 million barrels of oil
to power ships, vehicles, aircraft, and ground
operations-enough for over 4 million trips around
the Earth, assuming 25 mpg.
So out of the total US oil consumption (let's say 20
MB/day) around 0.3 MB/day is consumed by military. I
think that the figure in reality might be twice larger
that cited as it is not clear how consumption of planes
operating in Iran, Syria, Libya, Yemen (and generally
outside the USA) is counted. But even 0.3 Mb/day is
approximately the same amount that Greece, or Sweden,
or Philippines are consuming. The latter is a country
with over 100 million people.
In twenty-forty years this period would probably be
viewed as really crazy.
The IEA's estimate from its Oil Market Report shows an even bigger growth: by 300 kb/d to 34.20 mb/d,
led by increases from Angola along with Libya and Saudi Arabia. The group's output stood 1.4 mb/d
higher than a year ago.
https://www.iea.org/oilmarketreport/omrpublic/
China's crude oil production increased 3.6% in November from the previous month to about 3,915
kb/d, the highest since July.
Output was down 382 kb/d (8.9%) from the same month last year.
Crude production has fallen 294 kb/d (6.9%) in the first 11 months of 2016 to 3,984 kb/d.
Comment
from Bloomberg:
"China's output has declined this year as state-owned firms shut wells at mature fields that
are too expensive to operate at current prices. The country needs oil above $50 a barrel to stabilize
production, according to analysts at Sanford C. Bernstein, as well asFu Chengyu, the former chairman
of both Cnooc Ltd. and China Petroleum & Chemical Corp. Production is forecast to drop 335,000
barrels a day this year, followed by a further slide next year of 240,000 barrel a day, the International
Energy Agency said Tuesday.
"November's output pickup is probably just a blip, which won't likely persist," said Gao Jian,
an analyst with Shandong-based industry consultant SCI International. "For the next six months,
unless oil prices stay above $50 a barrel, we we won't see solid recovery."
The rise in production last month was in anticipation of higher crude prices amid OPEC meetings,
said Amy Sun, an analyst with Shanghai-based commodities researcher ICIS-China.
China's annual crude output is seen falling to 200 million tons this year (about 4 million
barrels a day), down roughly 7 percent from nearly 215 million tons last year, according to estimates
from SCI International and ICIS-China."
Yes, the US clearly needs some kind of energy policy, and I think one thing that highlights
how badly this is needed is the ability of anyone who can raise the money to be able
to drill 96 horizontal wells in one section of land (two if the laterals are the two
mile variety).
But, I guess any mention of conservation in the US industry these days
is heresy.
I would not be too critical of Chinese production falling. Seems to me they are buying
up all the cheap oil they can from overproducing nations, and storing it. Makes sense
to me.
"... its amazing to me, given how many times we have caught the shale oil industry lying thru its teeth, how many people (EIA and the NDIC) still believe everything it says about itself: http://www.worldoil.com/news/2016/9/22/analyst-touts-industry-s-cost-reductions-in-us-shale-plays ..."
"... "Technically" recoverable reserves is a wild ass guess based on volumetric calculations of shale OOIP over a hypothetical homogeneous area in all the producing basins throughout the country that has absolutely nothing to do with reality. Reality is that only about 5-6% of that oil is recoverable thru primary means, not 74%. ..."
"... as we have seen in the past, poor economics did not deter sharp growth in LTO production. It seems that financial markets are ready to resume funding of the shale sector, although more cautiously than in 2011-14. And shale companies are already announcing their growth plans for next year. ..."
"... I expect growth in LTO production to resume next year and accelerate in 2018. This growth will be much slower than during the years of the shale boom, but the U.S. LTO production may reach a new peak in the beginning of the next decade. ..."
"... When the EIA states we can recover 70 plus percent of TRR shale oil in America that is a grave disservice to the public. As is "undiscovered TRR," whatever the hell that is. ..."
"... If you were to poll most Americans I believe the vast majority would say we no longer have a hydrocarbon problem in America, that we have 150 years of shale oil and more than that in natural gas and that we should, and can, isolate ourselves from the rest of the energy world and become energy independent. That is a mistake. ..."
"... The shale industry, and its "groupies," has deceived many people over the past 14 years and that pisses me off, big time. ..."
Alex S is mostly talking about the short term forecast. I agree that the long term forecast
in the EIA's AEO for LTO is much too optimistic and that Hughes' estimates are quite good.
Note that one mistake Hughes makes is confusing the undiscovered TRR with TRR, he needs to
account for 2P reserves and add those to UTRR for the Bakken/Three Forks. His estimates for Bakken/Three
Forks are a bit low. Maybe a couple of Gb.
Dennis, what in the hell is the difference in undiscovered TRR and TRR? What shale oil resources
are out there left to be discovered, do you reckon? "Technically" recoverable reserves is a wild
ass guess based on volumetric calculations of shale OOIP over a hypothetical homogeneous area
in all the producing basins throughout the country that has absolutely nothing to do with reality.
Reality is that only about 5-6% of that oil is recoverable thru primary means, not 74%. Lordy.
As Dennis says, I was talking about the EIA's short-term forecasts, which are the initial topic
of this thread. The fact is that the EIA was generally too conservative in its forecasts for U.S. C+C production,
which my charts above show. I think their forecast for 2017 is still too low and will be revised
upwards, especially as oil prices will likely be higher than the EIA was assuming in December
STEO ($51 average).
Long-term forecasts in the Annual Energy Outlook are a different story.
AEO-2012, 2013 and 2014 had too conservative projections.
AEO-2015 was more realistic, in my view, although it failed to predict the extent of the 2015-16
oil price slump and its impact on LTO production. Finally, projections in the AEO-2016 indeed look speculative, especially as they did not provide
detailed assumptions.
Note, that I totally agree with your view on shale economics. But as we have seen in the
past, poor economics did not deter sharp growth in LTO production. It seems that financial markets
are ready to resume funding of the shale sector, although more cautiously than in 2011-14. And
shale companies are already announcing their growth plans for next year.
I expect growth in LTO production to resume next year and accelerate in 2018. This growth
will be much slower than during the years of the shale boom, but the U.S. LTO production may reach
a new peak in the beginning of the next decade.
Thank you, Alex; I am aware of the title of the post and the fact that it contains information
on IEA export data for Iran, JODI data on the KSA, the Marcellus gas "miracle" a discussion of
Russian politics, the usual sprinkling of ant-oil, EV stuff, Donald Trump and Obamacare. You will
of course forgive me for not fully understanding this statement: " the EIA's projections tend
to underestimate U.S. oil production in general, and LTO output, in particular."
My interest in LTO economics is multi-faceted and because shale oil extraction is extremely
expensive, and woefully unprofitable, unlike yourself, perhaps, I do not believe it will have
a significant role in our energy future until we sort out how to pay for it. Hoping for higher
oil prices, and "predicting" higher oil prices is not a plan, therefore stating it will grow in
the future, without stating how, is dangerous, in my opinion. I don't believe it can be funded
as it has been; that WILL stop, eventually. At best, whether we believe people like David Hughes,
or the EIA, we only have 6-8 years of shale oil to provide to the US's total annual crude oil
needs. When the EIA states we can recover 70 plus percent of TRR shale oil in America that is
a grave disservice to the public. As is "undiscovered TRR," whatever the hell that is.
If you were to poll most Americans I believe the vast majority would say we no longer have
a hydrocarbon problem in America, that we have 150 years of shale oil and more than that in natural
gas and that we should, and can, isolate ourselves from the rest of the energy world and become
energy independent. That is a mistake.
The shale industry, and its "groupies," has deceived many
people over the past 14 years and that pisses me off, big time. MY industry should tell the truth
about the oil and gas future. It doesn't. We will likely have to explain to our children someday
why we pissed off all of our remaining resources and did not leave them anything.
IEA also upped its forecast for global oil demand for this year and next year due
to revised estimates for Russian and Chinese demand. It saw growth of 1.4 mb/d for 2016,
120,000 barrels a day above the previous forecast. Growth in 2017 is now seen at 1.3
mb/d, an increase of 110,000 barrels a day from its previous estimate.
likbez, 12/13/2016 at 11:40 am
Realistically the only country that can substantially increase its oil production in 2017 in
Libya. But that requires the end of the civil war in the country which is unlikely. Iran card was
already played.
Iraq is producing without proper maintenance. At some point they might have substantial
difficulties.
"... The IEA also upped its forecast for global oil demand for this year and next year due to revised estimates for Russian and Chinese demand. It saw growth of 1.4 mb/d for 2016, 120,000 barrels a day above the previous forecast. Growth in 2017 is now seen at 1.3 mb/d, an increase of 110,000 barrels a day from its previous estimate. ..."
...OPEC ... crude output in November was 34.2 million barrels per day (mb/d) - a record high -
and 300,000 barrels a day higher than in October.
The IEA also upped its forecast for global oil demand for this year and next year due to
revised estimates for Russian and Chinese demand. It saw growth of 1.4 mb/d for 2016, 120,000
barrels a day above the previous forecast. Growth in 2017 is now seen at 1.3 mb/d, an increase of
110,000 barrels a day from its previous estimate.
"... Peak oil is not just about cars. Oil is the reason why our civilization exists in its current form. Oil is why we have 7 billion people on this planet. Oil is about agriculture and food supply, it is about distribution of everything we buy and not least it is about the raw materials for many if not most of our goods. It is about almost every economic and social transaction that takes place. ..."
"... It is unbelievable what misinformation has been spread by the media. I attended a public forum of the Australian Energy Council and one participant thought that OPEC had increased oil production. My presentation on the need to replace oil by natural gas as transport fuel (instead of exporting it as LNG) was met with silence and did not spark a debate. Another participant was running away when he heard the word peak oil. ..."
"... Further re climate, most agree CO2 is a greenhouse gas but estimates of the temperature change caused by a doubling of its concentration have been coming down over the last 15 years. In other words, it may not warrant the type of policy response that is being promoted at present. ..."
"... Meanwhile the IPCC projections continue with climate sensitivity estimates of 3 to 6 degrees when the more recent estimates of ECS and TRC are consistently under 2 degrees. So contrary to what is alleged above, there is lots of doubt about the IPCC models. ..."
"... I agree with author. If you look at 2 previous OPEC meetings, the players claim disorder and inability to control output only to find resolution the day after the meeting. I believe OPEC is setting up for a freeze as we are only 1% oversupplied now. If the OPEC big wigs need to fatten the bank accounts, what better way than to set up your own long call on the cheap? ..."
"... Balance this with Iran and Iraq incapable of proper well maintenance and we will soon see inadequate supply not later than 2qtr 17′. ..."
is out with crude only production numbers for October 2016. All charts are in thousand barrels
per day.
OPEC crude only production reached 33,643,000 barrels per day in October. This includes Gabon.
Since May, OPEC production has increased 1.05 million barrels per day.
Algeria is in slow decline.
There was a sudden drop in Angola oil production in October, down 200,000 barrels per day
since August. I have no idea what the problem was. There is nothing in the news to indicate any
problem.
Ecuador was sharply down in August but seems to be holding steady for the last two years.
Gabon was added to OPEC a few months ago but their production is so low it will have little
effect one way or the other.
Indonesia will also not affect OPEC production in a big way one way or the other.
Iran's increase since sanctions were lifted has slowed to a crawl. There are other problems
on the horizon for Iran. They are talking about changing all their oil field contracts to "buy
back" contracts. That is they want the option to nationalize all everything. This will likely
cause a mass exodus of foreign oil companies from Iran and hit their production considerably.
Iraq's production was up 97,000 bpd in September and another 89,000 bpd in October. Iraq,
like everyone else in OPEC, is positioning themselves for an OPEC "freeze" in oil production.
So they are producing every barrel possible in order to freeze at the very highest level possible.
Kuwait has recovered from the problems they had in April. I expect their production to flatten
out soon with a slight decline over the next few years.
Libya's oil production was up 168,000 bpd in October. Is peace breaking out in Libya? I doubt
it but only time will tell.
Nigeria increased production 170,000 bpd in October. It is likely erratic increases and declines
in production will continue.
The decline in Qatar's oil production seems to have slowed since late 2014.
Saudi saw a slight decline in October.
The United Arab Emirates had some problems earlier this year but they seem to have recovered.
I think they will hold production steady for a while now. I really don't think they can increase
production much above 3 million barrels per day.
Venezuela's oil production is still dropping but the decline seems to be slowing. Venezuela has
very serious economic problems. They are nearing the "failed state" status.
World oil supply is very near its November 2015 peak.
All this oil tens of billions of barrels all of it non-renewable, never to be seen- or made
use of again for a hundred million or more years, for all practical purpose, ever!
the greatest bulk of it put into cars where it is wasted, by people driving aimlessly in
circles from gas station to gas station for entertainment purposes only By way of this idiocy
we destroy ourselves and our futures. We aren't doomed, we are damned.
The big mistake most energy illiterates make is to talk about their cars when the peak oil subject
comes up. Most hope or assume that another form of fuel or energy will power their ride post oil.
Peak oil is not just about cars. Oil is the reason why our civilization exists in its current
form. Oil is why we have 7 billion people on this planet. Oil is about agriculture and food supply,
it is about distribution of everything we buy and not least it is about the raw materials for
many if not most of our goods. It is about almost every economic and social transaction that takes
place.
When oil becomes expensive our economies and societies will implode, jobs and goods imported
from far away will disappear. This will apply worldwide. The citizens of Addis Ababa are just
as dependent as the ones in Amsterdam or Atlanta.
We have exhausted most of our soils and lost the skill to eke out a living from Mother Nature
without fertilizers and machines. Could it be that the least "developed" countries will lead post
oil because our "developed" nations are the least able to cope without oil?
Mike, that's exactly what I have been trying to tell folks for years. Most just don't want to
believe it. They see solar, wind and other such things as keeping BAU going for awhile.
Why don't you post over on the post section. We get a lot more traffic over there.
Big mistake thinking that this crisis will not arrive with plenty of time to avoid it. Oil prices
will rise slowly over time. However we create energy, we will find a way to pay for locomotion
or create food.
Oil is down 50% This is because of new sources of supply combined with continuing energy efficiency
improvement. Doomed or damned, don't hold your breath. I am sure you will find something else
-- perhaps global warming, now climate change, to scare people with.
Argh. Your comment suggests that you are a militantly ignorant troll. 97% of the competent climatologists
fully support the IPCC global warming summary model. There is no reasonable doubt about this science.
In my opinion there has been a revolution in drilling technology over recent years. However,
the measured rate of additional improvement is now very modest as measured by the US EIA.
Most of the recent improvement is explained by the discovery and exploitation of sweet
spots which are being rapidly drained. For an objective look at prospects going forward for oil
and gas you should read David Hughes' Drilling Deeper report.
This is an exhaustive analysis based on a data base of all existing US oil and gas wells. It
impressively documents a future of peak oil and gas based on fully exploiting fracking technology.
I don't see any magical technology that will get the projected fossil fuel resources required
for business as usual. It is just not there.
Oil is the reason why our civilization exists in its current form.
Not really. There's nothing magical about oil. 100 years ago civilization was pretty recognizable,
and it didn't require oil.
Oil is about agriculture and food supply
For the moment. Batteries and synthetic fuel can move tractors. Electricity (from many sources)
can create fertilizer.
it is about distribution of everything we buy
Rail works awfully well.
is about the raw materials for many if not most of our goods.
Meh. It produces some of our raw materials. But plastic can be produced from a lot of different
hydrocarbons, and it's production doesn' necessarilly create CO2, so we could produce plastic
from coal for centuries. That's plenty of time for a smooth transition.
"Not really. There's nothing magical about oil. 100 years ago civilization was pretty recognizable,
and it didn't require oil." You missed his point entirely. The reason there is 7 billion people
now is because of oil and what it has done for industrial, agriculture ect ect ect.
There was 1.7 billion people 100 years ago. How many people do you think would be here if not
for oil and all it has done?
">For the moment. Batteries and synthetic fuel can move tractors. Electricity (from many sources)
can create fertilizer<".
This is lack of a better word retarded for you to even consider that a battery will be used
even in the distant future to power agricultural machinery on a mass scale. Maybe the little ride
on mower you cut grass with, but that is it.
" Rail works awfully well."
Ya it does, but when it gets to a terminal, it will have to be unloaded and transported
then. Which basically happens now, so what is your point? And your last comment I wont even pick
apart because you obviously know little to very little about the uses of oil and the advantages
it has brought humanity.
@ Steve from Vaginia: Did you ever consider that some People have to drive to *work* and *produce*
so that you can sit around and swing your testicles and so that your mommy can prepare your lunch
and dinner?
So when you sit around the whole day you can think what happens in 300 years, when most of the
oil and gas has been used up. We don't have time for that, but we are sure that People will find
a solution.
One or the solution will be not driving to work and wasting time in gridlock so we can
have more time to swing our balls be 'productive' on our own and our real community's
terms. Real community that includes momma
Oil will get more expensive, some day slowly. Right now the cost is down (50%!!!) because of new
sources and efficiency improvements. I think that those who predict doom will be disappointed.
The falling EROI destroys your lousy assumption in spades. Your time might be better spent burning books or working on one of the dozen worthless Presidential
campaigns.
Oil is very precious raw material, our demand for oil increases day after day, year after year
and century after another. The search and use other sources such as atomic, wind, tide, solar,
geothermal and others will continue but the prospects / trend to keep on using oil as a main source
of energy still quite high and will continue with time due to the following reasons:
– Worldwide population trend is going up drastically. (Main factor).
– Oil as a source of energy still quite cheap in comparison with other sources.
– It may be easy to apply the new technology in certain fields but not for all fields.
– Oil proofs to be available all over the world and at different levels, hence oil production
cost will suit all the times and condition worldwide but not for all the countries.
– Oil is quite important as a raw material for petrochemical products, and our needs for plastic,
paints and other products increases day after day drastically.
– Oil civilization will continue for a few centuries to come if not for ever and playing with
its prices is subject to market condition, political matters, and other technical issues.
Thanks for the graphs. Saudi Arabia may be ramping up production ahead of the air-conditioning
season. Around 600 kb/d are needed in the hottest month.
It is unbelievable what misinformation has been spread by the media. I attended a public
forum of the Australian Energy Council and one participant thought that OPEC had increased oil
production. My presentation on the need to replace oil by natural gas as transport fuel (instead
of exporting it as LNG) was met with silence and did not spark a debate. Another participant was
running away when he heard the word peak oil.
Im lost by ur comments. 1st of all the graphs clearly show that Opec has increased production
by 2+m/d in the last year.
2ndly, Saudi's oil output charts above are for just Oil not NG. Ive never been there, are you
suggesting they run generators from oil for electricity and subsequent air conditioning. Why
wouldn't
they run thier power plants on Natural Gas? Please educate me.
No doubt that investor sentiment and market makers are playing a significant role in price
decline, as opposed to actual supply/demand issues. How do you find out how much the Opec nations
have sold oil short in the various markets. Not a bad deal for them, if they can lay rigs down
World wide and make the money in the commodity markets while doing so. But prices can only slide
so far and for so long before that game is up. It seems like if short selling or hedging slows,
buyers will outweigh sellers and the price should rise soon
Greg, Saudi Arabia is very short of natural gas and have been for several years now. They would
love to run all their power plants and desal plants on natural gas if they just had enough of
it. They don't. They do burn a lot of natural gas but their supply is far short of what they need.
...Saudi is producing flat out right now just like every other OPEC country except Iran. Sanctions
are holding Iran back. Political violence is holding Libya back, but they are still producing every
barrel they can. It's just that violence keeps them from producing any more.
Re Saudi, yes their domestic usage of oil is around 3 M bopd (they produced 10.5 M in June
but exported around 7 M bopd). Their refinery capacity is increasing but a large amount is burnt
for electricity generation. They have delays in the development of some large gas fields, and
so gas supply is behind the demand curve. Various service companies such as Baker Hughes, Halliburton
and Schlumberger have been demonstrating unconventional gas production in Saudi as a response.
Meanwhile the IPCC projections continue with climate sensitivity estimates of 3 to 6 degrees
when the more recent estimates of ECS and TRC are consistently under 2 degrees. So contrary to
what is alleged above, there is lots of doubt about the IPCC models. The latter point comes from
peer reviewed science, by, among others, Nic Lewis.
Another point of interest is the relative steadiness of Venezuelan production. Allegedly various
of the empresas mixtas (Joint Ventures between PDVSA and International Oil Co.'s) are not proportionally
funded by PDVSA as they should be. As a result production is down or is not reaching targets.
Apparently contractor companies will not accept new contracts from PDVSA unless they set up an
escrow account or other arrangement that guarantees payment in foreign currency. It is surprising
therefore that Venezuelan production shows a slight rise since December.
Yes one day we will be without oil that is pumped from the earth. This is not going to happen
for 100's of years. Our intellect will probably find chemical or biological solution to this problem
long before we run out. If not humanity will survive. Global warming, yes its real and one day
the Sun will double in size and engulf the earth. I am not worried about either. I hate winter
anyway.
The problem humanity will face and not discussed near enough is the lack of clean drinking
water. Everyday it becomes harder to deliver enough clean water to all areas in need. States fight
over the rights to what little water pass through their terrain every year. Many times it has
to be pumped from other states at a premium. The worlds population grows larger every second.
crops demand more and more. Ethanol was forced on us without thought as usual by the oil fear
mongers. You do not grow food to solve a commodity problem.
The land resources, water resources, and corrosive properties that Ethanol introduced far out
weigh any benefit accomplished but still its forced down our throats destroying everything its
poured into. So please build those oil pipelines all across the country and pump that oil at rates
that keep our prices low so I can drive in circles any time I feel like it. I am not going to
worry about it because about the time we run out of oil we will need those pipelines to pump clean
water to all that need it.
I agree with author. If you look at 2 previous OPEC meetings, the players claim disorder and inability
to control output only to find resolution the day after the meeting.
I believe OPEC is setting up for a freeze as we are only 1% oversupplied now. If the OPEC big
wigs need to fatten the bank accounts, what better way than to set up your own long call on the
cheap?
OPEC will shut in wells before the Fed adjusts interest rates resulting in magnified downward
pressure on oil.
Balance this with Iran and Iraq incapable of proper well maintenance and we will soon see inadequate
supply not later than 2qtr 17′.
"... Most shale oil companies are looking down the barrel of loans coming due beginning 2017 and continue to do stupid things with borrowed money because they have no choice. In spite of lower costs and higher EUR's brain washing campaign, they are all still losing money hand over fist. Even mighty EOG. ..."
I won't deny there is an uptick in drilling coming, it is just that I perceive
a different rationale for it, than assuming they are jumping at $50 oil to plan
to go all out for that reason. Some companies are completing wells that would
only be profitable at $100 a barrel. No rationale for those, other than they
are simply trying to hold on to the lease, and hope. I follow EOG fairly
closely, and from my own lease, I know they are trying to hold on to fairly
good leases, but only drill what they have to. I think that is the reason your
seeing an uptick. They are planning on what will hold the leases for 2017. They
are balancing those permits for "marginal" wells at $50, with permits in the
sweet spots. From a planning perspective, it makes sense on getting that over
with first. Then you can concentrate on what is going to keep you alive. It is
interesting to note that the Austin Chalk (Sugarcane) has become their new
sweet spot in Karnes County. They have 5 or 6 now producing, and 9 more planned
so far for next year. All are doing very well, and two had first month
production in excess of 100k barrels a month. Less decline than the Eagle Ford,
so far. Other companies are now jumping on it, too.
Mr. Minton do you have continuous drilling provisions in your lease and if
so may I ask, what year did you lease to EOG?
I contend that at these oil prices the speculation about "drilling to
hold leases" is vastly overblown, that most leases made in the Eagle Ford
and Bakken before 2012-2013 had no continuous drilling provisions in them,
and that most of the drilling still being done in those two plays, at these
oil prices, are actually related to loan covenants regarding booking PDP
reserves, SEC 5 year rules regarding PDNP reserves and to reduce taxable
income thru IDC deductions.
Most shale oil companies are looking down
the barrel of loans coming due beginning 2017 and continue to do stupid
things with borrowed money because they have no choice. In spite of lower
costs and higher EUR's brain washing campaign, they are all still losing
money hand over fist. Even mighty EOG.
HZ Austin Chalk wells cost considerably less that shale wells because
they don't typically require frac'ing. Some of the initial IP's and IP90's
in the Chalk have been spectacular, especially for EOG who is well know for
gutting wells to create big EUR's; take it from me, an old Chalk hand,
however, the decline on Chalk wells after 12-18 months will suck the hardhat
over the top of your head and I am quite certain 95% of those wells will NOT
payout either. They did not in 1981, 1991, 2001 nor will they this time
around the block either.
Yes it has continuous drilling clause.
Austin chalk wells by EOG are frac'ed. Who cares what happens to the
decline in 12 to 18, if you recover over 300k the first year?
If EOG frac's those Chalk wells then they cost essentially what an EF
well costs. If a Chalk well makes 300,000 BO in the first year, which
they don't, then declines 80% annually after the first 12 months and
every year thereafter, they'll never reach payout. If your only
interest in any of that is from the standpoint of a royalty owner,
then I am sure you don't care about profitability. I do.
I contend that most mineral leases made before 2013 did not contain
"drill and earn provisions" in them (drilling commitments) and that
one well could hold the entire lease. I can confirm that in S. Texas
and I suspect less knowledgeable mineral owners in the Bakken that
leased early in the play had no drilling commitment provisions in them
either. Leases made later in both plays involved more sophisticated
mineral owners who required drilling commitments. In W. Texas, for
instance, all that now being drilled is subject to drilling
commitments.
SEC rules are very clear regarding 'proven but not producing'
reserves that were "booked" and made into assets they must be drilled
within 5 years or lost. DUC wells are PDNP reserves and they too must
be completed within 5 years.
I am familiar with two new loan covenants, particularly relative to
recent credit swaps, etc. that if a company gets more money in the
equity swap, they must develop PDNP reserves or suffer penalties.
None of this precludes the fact that 95% of the shale oil wells
being drilled in America and these oil price levels will not payout
unless prices rise dramatically. Those wells ARE drilled at a sure
loss. The shale oil industry is penned up now like a heard of goats;
they voluntarily drill unprofitable wells with borrowed money because
they need cash flow and they need to book more assets to be able to
borrow more money. They are also forced to drill and complete wells
that are unprofitable for reasons I have explained. The ONLY way out
for them, even the biggest of them, is if oil prices rise into the
80's and 90's and that is not going to happen for a long time, short
of some big chicken fight somewhere in the world that would have an
affect on supply.
Not really. There is not a lot of interest in drilling for $50 to $60 oil in
the shale. Go back and look at what happened in 2009 when oil dropped to
$60. Most places are profitable to drill at $80 to $100. Very few are
profitable at $50. The press can hype all they want. It won't change
reality.
I think the press helps – if enough people buy it, silly money will give
free loans to these companies to continue drilling. You can loose as much
money as you like, as long as you have creative bookkeeping and a
neverending roll in of money.
We had this here in Germany in the wild
2000s – film making fonds have been the red hot burner, people lost
millions but continues investing until alle these companies where
history. Hollywood was laughing about Germany "silly money".
It's
little surprise that Credit Suisse recently stated:
"With service prices, particularly pressure pumping expected to rise in
2017 on the back of increased activity, a Permian operator commented that it is
already seeing greater than a 20% increase in completion costs. The biggest
concern for Permian management teams has been a potential scramble for
equipment and services that higher commodity pricing could introduce, and the
OPEC move has the potential to drive faster service cost inflation than we
would have otherwise seen, muting the impact of the oil spike on returns for US
shale operators."
In other words, the cost of drilling is likely to go up just as fast as the
price of oil goes up if there is a cut in production by OPEC.
Most of the new "drilling efficieny" is a result of depressed
costs and drilling in primarily "sweet spots". Easy financing
is a thing of the past. Can't see a big enough resurgence in
shale drilling to overcome drops in production in the short
term. A 20% increase is a killer, but that is only the
beginning. The way I see it, because the new drills won't
keep up wit the decline rates of the old wells; they have to
recoup all their drilling costs the first year, to enable
them to keep drilling. That leaves only a few areas to drill
in. The only reasons it surged in the past, were easy money
and oil at $100 a barrel. Both are no longer available, now.
BP's numbers for oil exports (available from 1980) and production less
consumption (available from 1965) are slightly different, which may reflect
changes in inventories and other balancing items.
According to BP, Middle
East oil exports in 2015 was 20.6 mb/d, the record for the period from 1980.
Production less consumption was 20.5 mb/d vs. all-time high of 20.8 mb/d in
1976-1977.
But 2016 should see a new record due to ramp-up in production and exports
from Saudi Arabia, Iran and Iraq.
Middle East oil exports (mb/d)
Source: BP Statistical Review of World Energy
"... The real danger is that the media, as well as the general public, has been sold the idea that peak oil has now been discredited because of shale oil. It has not. And that only increases the dramatic shock effect it will have when it finally becomes obvious that peak oil has arrived. ..."
"... Of course some will agree but say that "No big deal, renewables will make peak oil a non event!" And these folks are in for an even bigger shock than the peak oil deniers . Well, in my opinion anyway. ..."
"... To me, that is like a farmer saying I estimate next year and beyond that the cost of seed, chemicals, fertilizer, fuel, labor, real estate taxes, etc, will fall by 60%. I am not familiar with any commodity based business where that is reality. Yet almost ALL US LTO did the same thing, 30-60% reduction. ..."
"... The point is, had they not done that, they would have basically lost ALL of their proved reserves at 2015 prices. My point is, how can a company that is losing large amounts, pre-reserve write downs, have any economic reserves? If the costs cannot all be recovered for the well at SEC prices, there are no reserves for that well. ..."
"... 2016 SEC prices are about $10 lower. We shall see what they come up with. ..."
"... I also agree peak oil will be obvious before long, I think eventually (by 2020 at least unless a big recession intervenes) oil prices will rise, maybe to $100/b. Most will expect a big surge in output, but any surge will be small (1 Mb/d at most) and likely short lived (if it happens at all). ..."
Hi Ron. Thanks for your awesome website. The word blog doesn't do it justice.. It is truly the
best, and attracts a great group of commenters. May I ask how you might see 'serious depletion'
playing out, roughly speaking? Do you have any predictions or wild ass guesses on the slope of
the production decline or perhaps where world crude plus condensate production might be by 2020
and/or 2025? Given your wisdom and insight into human nature what are your feelings about the
human response to these future conditions?
Do you have any predictions or wild ass guesses on the slope of the production decline or perhaps
where world crude plus condensate production might be by 2020 and/or 2025?
Not really. We all had a pretty good idea where things were heading until shale oil raised
its ugly head. No one that I know of predicted that. But now it looks like shale oil is a USA
phenomenon with no appreciable production anywhere else in the world.
My strong feeling right now is that the shale oil phenomenon has given the entire world the
idea that peak oil is, or was, an illusion or an idea that had no valid support in the real world.
But peak oil is as real as it ever was. The amount of recoverable oil in the ground is finite.
We may have had the numbers wrong in our personifications because of shale oil. But that does
not change the big picture. The peak oil phenomenon is as real as it ever was.
The real danger is that the media, as well as the general public, has been sold the idea that
peak oil has now been discredited because of shale oil. It has not. And that only increases the
dramatic shock effect it will have when it finally becomes obvious that peak oil has arrived.
Of course some will agree but say that "No big deal, renewables will make peak oil a non event!" And these folks are in for an even bigger shock than the peak oil deniers . Well, in my opinion
anyway.
2016 10K will be out in late February-early March for US LTO producers.
It will be interesting to compare 2014, 2015 and 2016. In particular I am waiting to see the
estimates of future cash flows to see how much more the engineering firms let them slash future
estimated production costs and estimated future development costs.
In my opinion, there was a lot of hocus pocus in those particular numbers, which, of course
provide the basis for proved reserves and PV10.
The amounts slashed from 2014 to 2015 were incredible, for example Mr. Hamm's CLR dropped its
estimate of future production costs by 60%.
To me, that is like a farmer saying I estimate next year and beyond that the cost of seed,
chemicals, fertilizer, fuel, labor, real estate taxes, etc, will fall by 60%. I am not familiar
with any commodity based business where that is reality. Yet almost ALL US LTO did the same thing,
30-60% reduction.
The point is, had they not done that, they would have basically lost ALL of their proved reserves
at 2015 prices. My point is, how can a company that is losing large amounts, pre-reserve write
downs, have any economic reserves? If the costs cannot all be recovered for the well at SEC prices,
there are no reserves for that well.
2016 SEC prices are about $10 lower. We shall see what they come up with.
"And these folks are in for an even bigger shock than the peak oil deniers . Well, in my opinion
anyway."
I think the odds are pretty good that Ron is right. We can hope that Dennis C and the others
who think production will stay on a plateau for a while and then gradually decline rather slowly
are right.
If they are, and the electric car industry does as well as hoped, then the economy national
and world wide can probably adapt fast enough to avoid catastrophic economic depression brought
on specifically by scarce and expensive oil.
If for some reason, any reason, oil production declines sharply and suddenly, for a long period
or permanently, we are going to be in a world of hurt.
People need not starve, at least in richer and economically advanced countries, but millions
of people could lose their jobs and a lot of businesses dependent on cheap travel would fail.
The effects of these lost jobs would expand outward thru the economy doing Sky Daddy alone knows
how much damage.
In poor countries, starvation is a real possibility.
The time frame I have in mind in making this comment is out to twenty or thirty years. After
that, it's anybody's guess what the population will be, and what the economy will be like.Hell,
it's anybody's guess as far as next week is concerned, so far as that goes.
Plateau until 2019 or 2020 then some decline slow at first and gradually accelerating. Unless
a recession hits in that case acceleration is more rapid.
I also agree peak oil will be obvious before long, I think eventually (by 2020 at least unless
a big recession intervenes) oil prices will rise, maybe to $100/b. Most will expect a big surge
in output, but any surge will be small (1 Mb/d at most) and likely short lived (if it happens
at all).
Whether oil prices spike and this leads to either Great Depression(GD) 2 or a lot of EV and
plugin sales is unknown, it might be the latter at first with GD2 following between 2025 and 2030.
It will depend on how quickly oil output falls, I think it might be 1% or less until 2030 if oil
prices are high with faster decline rates once the depression hits.
As usual big WAGs by me. Of course nobody knows, but your insights on how things might play
out would be interesting.
Hi Dennis,
If I am not mistaken, you have moved up your estimate of global petroleum peak, and perhaps the
pace of the decline.
Just months ago, your opinion was that it would not occur until 2025. Are you moved by any specifics
that you would like to share?
Thank you, and as a follower of your good work, I appreciate your insight.
Steve at SRS Rocco report has a new, very informative post up showing that Middle East oil exports
are lower today than 40 years ago!
"According to the 2016 BP Statistical Review, the Middle East produced 30.10 mbd of oil in
2015 compared to 22.35 mbd in 1976. This was a growth of 7.75 mbd. However, Middle East domestic
oil consumption increased from 1.51 mbd in 1976 to 9.57 mbd in 2015. Thus, the Middle Eastern
economies devoured an additional 8.06 mbd of oil during that 40 year time-period."
Would be great to see an update on the global export land model that Jeff Brown (westexas)
used to update us on. How much C+C is available on the global markets as of today after domestic
consumption?
I´m not Jeff B. but if I remember last version of BP stats. correctly, the net export market has
been on a bumpy plateau between 2005-2015. It has varied between 41-44 Mb/day (approx.). 2015
set a record which was just slightly higher than 2005. It´s possible that 2016 will be slightly
higher.
World exports have been bumpy flat for 10 years or so.
Ecuador might be an importer soon'ish.
I like this site as I take an interest in observing the changes as exporters become importers.
The country charts provide some rough idea of those timings.
2015 was indeed a net export record. The increase came mainly from Canada, Iraq and Russia. Iran
may boost net exports in 2016, Kazakhstan will also add some. At least to me it seems unlikely
that net-exports will grow substantially above the 2015/16-level. Increase from the mentioned
countries will be needed to compensate decline in Mexico, Colombia, etc (+problems in Venezuela).
Seems more likely it will continue on the plateau or decline. Nigeria and Libya are wildcards.
mazamascience also use BP-data but seems to give a much higher number, ~48Mb/day. Don't know
why.
How do you calculate world total net export numbers if total global exports = total global imports?
Meanwhile, BP statistics for world oil exports (not net exports) show a rising trend.
I expect further increase in 2016, due to rising exports from Saudi Arabia, Iran, Iraq and Russia.
The IEA Oil Market Report, November 2016 on Iran's oil production and exports:
"With gains of 810 kb/d so far this year, Iran has emerged as the world's fastest source of
supply growth. Crude oil output rose by 40 kb/d in October to reach a pre-sanctions rate of 3.72
mb/d and shipments of crude oil climbed well above 2.4 mb/d, a rate not seen in at least seven
years.
For six straight months, the National Iranian Oil Co (NIOC) has been exporting more than 2 mb/d
of crude – double the volume seen under sanctions."
But that's not what your chart says, in controvention to BP's data.
Your chart says KSA exports at 9. Production is known or thought to be 10.5. And since consumption
is all liquids, that chart's products level is the correct number.
"... I do not understand the financial behavior of shale oil development, no. In the Bakken and the Eagle Ford it was indeed about reserve "growth," as Alex points out. Growth at the expense of profitability. That model failed (look at the debt, debt to asset ratios and losses for operators in those two shale oil plays) because the price of oil collapsed. ..."
"... Now, in spite of that, the Permian is using the same business model; growth at the expense of profitability. It is borrowing billions in the bottom of a price down cycle (it thinks) believing prices have no where to go but up. ..."
"... I think oil prices are a long way away from being high enough to save the shale oil industry. ..."
"... We may be overthinking all this and Alex is right again; it may be a simple matter of everyone taking advantage of a loosey goosey monetary policy in America. Money gets printed, Central Banks give it away, lenders are in desperate need of miniscule yields and CEO's and upper management borrow it, make millions personally on bonuses and incentives for growing reserves, then walk away from the whole shebang (Sheffield) before the loans come due. America looks the other way because they get cheap gasoline. ..."
I do not understand the financial behavior of shale oil development, no. In the Bakken and the
Eagle Ford it was indeed about reserve "growth," as Alex points out. Growth at the expense of profitability.
That model failed (look at the debt, debt to asset ratios and losses for operators in those two shale
oil plays) because the price of oil collapsed.
Now, in spite of that, the Permian is using
the same business model; growth at the expense of profitability. It is borrowing billions in the
bottom of a price down cycle (it thinks) believing prices have no where to go but up.
I would
say this particular shale play might work, except that from the data I see the UR's on those wells
are going to be pitiful at best, far less than the Bakken. Unless it is by the shear number of wells
those operators are not going to have a lot of reserves that will appreciate with rising prices.
It will therefore fail too, just like the others, perhaps for different reasons, I don't know.
I think oil prices are a long way away from being high enough to save the shale oil industry.
We may be overthinking all this and Alex is right again; it may be a simple matter of everyone
taking advantage of a loosey goosey monetary policy in America. Money gets printed, Central Banks
give it away, lenders are in desperate need of miniscule yields and CEO's and upper management borrow
it, make millions personally on bonuses and incentives for growing reserves, then walk away from
the whole shebang (Sheffield) before the loans come due. America looks the other way because they
get cheap gasoline.
Happy
Thanksgiving Mike! This article is for you! The RRC just refused to allow Pioneer to reclassify
oil wells in the Eagle Ford to .. wait for it .GAS WELLS.
I believe Pioneer just admitted the you, Shallow, Alex, and the others have been right all
along about the GOR going up, up and up.
It seems that Pioneer is trying to take advantage of the "high cost gas tax credit" designed
to encourage gas production in HIGH COST low permeable tight gas reservoirs.
Interestingly, this move by Pioneer has initiated a discussion about whether there should
be a new category for classifying wells. Hmmm sounds like the industry is about to hit the
new Texas Legislative session up for some new tax relief to encourage horizontal drilling in
its new favorite geological province the Permian Basin. But it will apply to the Barnett, Haynesville,
Eagle Ford, and all those other disasters.
Happy Thanksgiving to you too, John -- I had actually seen this before. Scoundrels they are,
one and all; Pioneer too, a Texas Company start to finish. The TRRC will roll over in another
year or so, watch.
Despite the CEOs not worrying about profits, I would think at some point the people
buying the bonds or stock of these companies would realize that the Emperor is naked.
Eventually when enough investors get burned, the money will stop flowing. Maybe not in 2016,
and perhaps not in 2017, but if oil prices remain low for the long term as experts in the field
seem to suggest is a likely event (though nobody really knows future oil prices), the money
will dry up. In that case these companies are done.
"... "Our analysis shows we are entering a period of greater oil price volatility (partly) as a result of three years in a row of global oil investments in decline: in 2015, 2016 and most likely 2017," IEA director general Fatih Birol said, speaking at an energy conference in Tokyo. ..."
"... Oil prices have risen to their highest in nearly a month, as expectations grow among traders and investors that OPEC will agree to cut production, but market watchers reckon a deal may pack less punch than Saudi Arabia and its partners want. ..."
"... BMI's outlook is more optimistic than groups like the International Energy Agency, which said last week that the industry might cut spending in 2017 for a third year in a row as companies continue to grapple with weaker finances. Oil prices still hover around $50 a barrel, less than half the level of the summer of 2014. ..."
"... The chart below shows Exxon's E&P capex in 2007-2015 (in US$bn). There was a sharp increase in US capex (both in absolute in relative terms) following the XTO deal. In 2015, the company cut spending both in the US and abroad ..."
Investment in new oil production is likely to fall for a third year in 2017
as a global supply glut persists, stoking volatility in crude markets, the head
of the International Energy Agency (IEA) said on Thursday.
"Our analysis shows we are entering a period of greater oil price
volatility (partly) as a result of three years in a row of global oil
investments in decline: in 2015, 2016 and most likely 2017," IEA director
general Fatih Birol said, speaking at an energy conference in Tokyo.
"This is the first time in the history of oil that investments are
declining three years in a row," he said, adding that this would cause
"difficulties" in global oil markets in a few years.
Oil prices have risen to their highest in nearly a month, as
expectations grow among traders and investors that OPEC will agree to cut
production, but market watchers reckon a deal may pack less punch than Saudi
Arabia and its partners want.
The Organization of the Petroleum Exporting Countries meets next week to try
to finalize to output curbs.
"Our analysis shows that when prices go to $60, we'll make a big chunk of
U.S. shale oil economical and within the nine months to 12 months of time, we
may see a response coming from the shale oil and other high-cost areas," Birol
told Reuters, speaking in an interview on the sidelines of the conference.
"And this may again put downward pressure on the prices."
Birol said that level would be enough for many U.S. shale companies to
restart stalled production, although it would take around nine months for the
new supply to reach the market.
The IEA director general said it is still early to speculate what Donald
Trump's presidency in the United States will have on energy policies.
"Having said that, both U.S. shale oil and U.S. shale gas have a very strong
economic momentum behind them," Birol said.
"Shale gas has significant economic competitiveness today, and we think it
will be so in the next years to come."
• Capital spending seen growing 2.5% in 2017 and 7%-14% in 2018
• U.S. independents, Asian giants seen spurring spending growth
The oil industry may be ready to open its wallet after two years of
slashing investments.
Companies will spend 2.5 percent more on capital expenditure next year
than they did this year, the first yearly growth in such spending since
2014, BMI Research said in a Sept. 22 report. Spending will increase by
another 7 percent to 14 percent in 2018. It will remain well below the $724
billion spent in 2014, before the worst oil crash in a generation caused
firms to cut back on drilling and exploration to conserve cash, the
researcher said.
North American independent producers, Asian state-run oil companies and
Russian firms are prepared to boost investments next year, outweighing
continued cuts from global oil majors such as Exxon Mobil Corp. and Total
SA, BMI said, based on company guidance and its own estimates. Spending will
increase to a total of $455 billion next year from $444 billion this year,
BMI said.
"North America is where we're really expecting things to turn around,"
Christopher Haines, BMI's head of oil and gas research, said by telephone.
"We've seen a push to really reduce costs, reduce spending and take out any
waste and inefficiency. These companies have gotten to the point where
they're all set up to react."
BMI's outlook is more optimistic than groups like the International
Energy Agency, which said last week that the industry might cut spending in
2017 for a third year in a row as companies continue to grapple with weaker
finances. Oil prices still hover around $50 a barrel, less than half the
level of the summer of 2014.
From what I am reading, Permian hz wells will be drilled in greater numbers in
2017, regardless of price.
These wells are generally less prolific than those in the Bakken and EFS.
However, the money has been raised and therefore it will spent.
To me, a good question is how much money is being diverted away from longer
term projects that will ultimately produce more oil, to drill these Permian
wells?
The Permain wells have no staying power. Under 50 bopd after 24 months is
the rule, not the exception. Under 200,000 cumulative in 60 months is the rule,
not the exception.
"To me, a good question is how much money is being diverted away from longer
term projects that will ultimately produce more oil, to drill these Permian
wells?"
shallow sand
The companies that are postponing longer term projects are not the same
companies that are planning to increase drilling in LTO plays.
"The companies that are postponing longer term projects are not the same
companies that are planning to increase drilling in LTO plays."
I
assumed he meant investment money. If investors want to be in gas and
oil, are they picking the companies with best chance of long-term success
(if there is such a thing anymore)?
ExxonMobil, Chevron, ConnocoPhillips, Hess, Marathon and Oxy all
have significant LTO production and all are, or were considered
international upstream producers.
I agree the supermajors are defensive stocks. But there were
many "growth" stock US companies which explored and produced
offshore/internationally or both, prior to the LTO boom.
Most of large US E&Ps and mid-sized integrateds have divested
their overseas assets during the years of shale boom.
I'm not sure that Exxon and Chevron are planning to increase
their shale exposure in the near term. For Exxon, US upstream
operations were hugely loss-making in 2015-16. And it has
recently made two relatively large discoveries outside US.
AlexS. Are those XOM international discoveries primarily oil
or gas?
Also, for the international assets you refer to
which US companies divested, do you know whether the buyers
are aggressively developing them? Just a guess, but I suspect
maybe not.
11/30 is a big day, hoping for a cut, hard to say if it
occurs whether it will be adhered to, other than by maybe the
Gulf States.
Interesting to
note Nexen is a partner in both ventures, while Hess
and Chevron are in one each.
I agree XOM has sustained significant losses in
North America, but they continue to spend money on new
wells. Had they not spent the money they have in North
America (both shale and tar sands) would the money have
been spent elsewhere. A tough one to know the answer
to.
I recall XOM was going to partner in Russia on
projects and those were halted for political reasons?
Did those projects go ahead without them?
I'm not saying that Exxon stopped
investing in U.S. upstream. My point is that oil
supermajors, like Exxon, Chevron, BP, Shell and Total are
not diverting investments from deep offshore, LNG and
other long-term projects to U.S. shale. They cut upstream
capex both in U.S. and in overseas projects.
The chart below shows Exxon's E&P capex in
2007-2015 (in US$bn). There was a sharp increase in US
capex (both in absolute in relative terms) following the
XTO deal. In 2015, the company cut spending both in the US
and abroad
"... In the second quarter of 2016, the companies reduced production by nearly 930,000 bpd, according to Morgan Stanley. ..."
"... Large oilfields, such as deepwater developments off the coasts of the United States, Brazil, Africa and Southeast Asia, typically take three to five years and billions in investment to develop. ..."
"... "Still, unless investment rebounds relatively soon, this steep downward trend is likely to resume in 2018 and beyond." ..."
"... We haven't even begun to see a "steep downward trend" yet. As to "softening" – there is less new production coming on next year, overall and for the IOCs, than this – highlighting Canada, Brazil etc. doesn't change that. ..."
"... Also when are they going to actually understand that the companies don't ever "slash" output, like its a choice – depletion does it for them. ..."
"... I don't know when peak decent reporting happened but it's well into decline now (another big internet age negative). ..."
"... Also, the author quotes a report by Morgan Stanley (that we haven't seen). Apparently, those "109 listed companies that produce more than a third of the world's oil" are covered by MS equity research team. And changes in their output may not fully reflect trends in overall global oil production. ..."
"... But I agree that articles in Reuters, Bloomberg and other MSM sources often misinterpret third party research. A recent example are numerous article about USGS assessment of TRR in the Wolfcamp formation ..."
The world's listed oil companies have slashed oil output by 2.4 percent so
far this year.
The aggregated production of 109 listed companies that produce more than a
third of the world's oil fell in the third quarter of 2016 by 838,000 barrels
per day from a year earlier to 33.88 million bpd, data provided by Morgan
Stanley showed.
In the second quarter of 2016, the companies reduced production by
nearly 930,000 bpd, according to Morgan Stanley.
The firms include national oil champions of China, Russia and Brazil,
international producers such as Exxon Mobil and Royal Dutch Shell, as well as
U.S. shale oil producers like EOG Resources and Occidental Petroleum.
The drop in oil companies' output is particularly compelling given the
increase in 2015, when third-quarter production rose by some 1.9 million bpd.
"Clearly, we have seen a large swing in the year-on-year trend in
production, from strong growth as recent as a year ago, now to steep decline.
This is the outcome of the strong cutbacks in investment," Morgan Stanley
equity analyst Martijn Rats said.
Capital expenditure for the companies combined more than halved from $136
billion in the third quarter of 2014 to $58 billion in the same period this
year, according to Rats.
Oil executives and the International Energy Agency have warned that a sharp
drop in global investment in oil and gas would result in a supply shortage by
the end of the decade.
Large oilfields, such as deepwater developments off the coasts of the
United States, Brazil, Africa and Southeast Asia, typically take three to five
years and billions in investment to develop.
Cost reductions and increased efficiencies have only partly offset the drop
in production as a result of the lower investment. Technological advancements
have also helped boost onshore U.S shale production.
"These declines should temporarily soften in 2017 as new fields are coming
on-stream in Canada, Brazil, the former Soviet Union and U.S. tight oil
probably stabilizes," Rats said.
"Still, unless investment rebounds relatively soon, this steep downward
trend is likely to resume in 2018 and beyond."
We haven't even begun to see a "steep downward trend" yet. As to
"softening" – there is less new production coming on next year, overall and
for the IOCs, than this – highlighting Canada, Brazil etc. doesn't change
that.
When is someone in Reuters or Bloomberg going to figure out that 2017 + 3
(or 5) + 1 (for FEED and FID approval at the beginning and ramp up at the
end) = 2021 (or 2023) so there is no way to cover drops "at the end of the
decade" now.
Also when are they going to actually understand that the
companies don't ever "slash" output, like its a choice – depletion does it
for them.
And how about this paragraph
"Cost reductions and increased efficiencies have only partly offset
the drop in production as a result of the lower investment. Technological
advancements have also helped boost onshore U.S shale production."
He/she has suddenly started to talk about company finances rather than
production, but without actually telling the reading public.
Cost reductions caused the drop for heavens sake. "Increased
efficiencies" and "technological advancements" – do you think the author has
the faintest idea what that actually means and how it is related to anything
else he says.
I don't know when peak decent reporting happened but it's well into
decline now (another big internet age negative).
"When is someone in Reuters or Bloomberg going to figure out that 2017 +
3 (or 5) + 1 (for FEED and FID approval at the beginning and ramp up at
the end) = 2021 (or 2023) so there is no way to cover drops "at the end
of the decade" now."
It should be actually 2015 + 3 (or 5), as pre-FID
projects have been posponed since end-2014 – early 2015.
Also, the author quotes a report by Morgan Stanley (that we
haven't seen). Apparently, those "109 listed companies that produce more
than a third of the world's oil" are covered by MS equity research team.
And changes in their output may not fully reflect trends in overall
global oil production.
But I agree that articles in Reuters, Bloomberg and other MSM
sources often misinterpret third party research. A recent example are
numerous article about USGS assessment of TRR in the Wolfcamp formation
"... This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet. ..."
"... It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices. ..."
"... Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. ..."
Here is the production graph. Not that much has happened. There was a big drop for 2011. 2009
on the other hand saw an increase. Up to the left, which is very hard to see, 2015 continues to
follow 2014 which follows 2013 which follows 2012. Will we see 2013 reach 2007 the next few months?
Its on purpose both because I wanted to zoom in and because the data for first 18 months or so
for the method I used above is not very usable. Bellow is the production profile which is better
for seeing differences the first 18 months. Above graph is roughly 6 months ahead of the production
profile graph.
And I guess we can all see no technological breakthru. 2014's green line looks superior to
first 3 mos 2015.
2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper
decline at that point and is likely going to intersect 2014's line probably within the year.
There is zero evidence on that compilation of any technological breakthrough surging output
per well in the past 2-3 yrs.
In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular EUR
improvement.
And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also
no evidence of sweetspots first.
I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with
inferior technology, and then as they became less sweet the technological breakthroughs brought
output up to look the same.
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.
And it would be far too much coincidence for techno breakthrus to just happen to increase flow
the exact amount lost from exhausting sweet spots.
This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning
it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather
than sweet.
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric
calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal
lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily
translate into greater frac growth (an increase in the radius around the horizontal lateral).
Novices in frac technology believe in halo effects, or that more sand equates to higher UR of
OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more
acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed
5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.
Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals
result in higher IP's and higher ensuing 90 day production results. That generates more cash flow
(imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve
assets. More assets means the shale oil industry can borrow more money against those assets. Its
a game, and a very obvious one at that.
Nobody is breaking new ground or making big strides in greater UR. That's internet dribble.
Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they
call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank
areas will be even less economical (if that is possible) and will result in significantly less
UR per well. That is what is ridiculous about modeling the future based on X wells per month and
trying to determine how much unconventional shale oil can be produced in the US thru 2035. The
term, "past performance is not indicative of future results?" We invented that phrase 120 years
ago in the oil business.
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra
stages post 2008/9/10. How could there not be going from 15 stages to 30+?
I see NO magic post peak. They all descend exactly the same way and by 18-20 months every drill
year is lined up. That's actually astounding - given 15 vs 30 stages. There should be more volume
draining on day 1 and year 2, but the flow is the same at month 20+ for all drill years. This
should kill the profitability on those later wells because 30 stages must cost more.
But profit is not required when you MUST have oil.
Freddy, is there something going on in the data? How can 30 stage long laterals flow the same
at production month 24 as the earlier dated wells at their production month 24 –whose lengths
of well were MUCH shorter?
I can only speculate why the curves look like they do. It could be that the newer wells would
have produced more than the older wells, but closer well spacing is causing the UR to go down.
Here is the updated yearly decline rate graph. 2010 has seen increased decline rates as I suspected.
The curves are currently gathering in the 15%-20% range.
2007 only has 161 wells. So it makes the production curve a bit noisy as you can see above. Current
yearly decline rate for 2007 is 7,2% and the average from month 98 to 117 would translate to a
10,3% yearly decline rate. The 2007 curve look quite different from the other curves, so thats
why I did not include it.
Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008,
2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one
way to do it would be to look at the natural log of monthly output vs month for each year and
see where the curve starts to become straight indicating exponential decline. The decline rates
of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011
(2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more
frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely
different, I am speculating about the possible cause.
2007 had much lower initial production and the long late plateau gives it a low decline rate also.
But yes, initial decline rates look similar to the other curves. If you look at the individual
2007 wells then you can see that some of them have similar increases to production as the 2008
wells had during 2014. I have not investigated this in detail, but it could be that those increases
are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau.
If that is the case, then 2007 may not be different from the others at and we will see increased
decline rates in the future.
Regarding natural log plots. Yes it could be good if you want to find a constant exponential
decline. But we are not there yet as you can see in above graph.
One good reason why decline rates are increasing is because of the GOR increase. When they
pump up the oil so fast that GOR is increasing, then it's expected that there are some production
increases first but higher decline rates later. Perhaps completion techniques have something to
do with it also. Well spacing is getting closer and closer also and is definitely close enough
in some areas to cause reductions in UR. But I would expect lower inital production rather than
higher decline rates from that. But maybe I´m wrong.
Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential
wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed
in Sept 2016.
I have 75 in my data, so about the same. They have increased the number of new wells quite alot
the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it
increased withouth the rig count going up. But I see that the rig count has gone up now too.
Ron you say " Bakken production continues to decline though I expect it to level off soon."
A few words of wisdom as to the main reasons why it would level off? Price rise?
Even though you asked Ron. He might think that the decline in the number of new wells per month
may have stabilized at around 71 new wells per month. If that rate of new completions per month
stays the same there will still be decline but the rate of decline will be slower. Scenario below
shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well
per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).
I am not so convinced that either Texas or the Bakken is finished declining at the current level
of completions. There was consistent completions of over 1000 wells in Texas until about October
of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked
in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month.
The Texas RRC reports are indicating that they are still plugging more than they are completing.
I remember reading one projection recently for what wells will be doing over time in the Eagle
Ford. They ran those projections for a well for over 22 years. Not sure which planet we are talking
about, but in Texas an Eagle Ford does well to survive 6 years. They keep referring to an Eagle
Ford producing half of what they will in the first two years. In most areas, I would say that
it is half in the first year.
The EIA, IEA, Opec, and most pundits have the US shale drilling turning on a dime when the oil
price reaches a certain level. If it was at a hundred now, it would still take about two years
to significantly increase production, if it ever happens. I am not a big believer that US shale
is the new spigot for supply.
The wells being shut in are not nearly as important as the number of wells completed because
the output volume is so different. So the average well in the Eagle Ford in its second month of
production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So
about 37 average wells need to be shut in to offset one average new well completion.
Point is that total well counts are not so important, it is well completions that drive output
higher.
Output is falling because fewer wells are being completed. When oil prices rise and profits
increase, completions per month will increase and slow the decline rate and eventually raise output
if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec 2017 about
79 new wells per month is enough to cause a slight increase in output. My model slightly underestimates
Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30 kb/d lower than actual
output (3% too low), my well profile may be slightly too low, but I expect eventually new well
EUR will start to decrease and my model will start to match actual output better by mid 2017 as
sweet spots run out of room for new wells.
Guess I will remember that for the future. The number of producing wells is not important. Kinda
like I got pooh poohed when I said the production would drop to over 1 million barrels back in
early 2015.
Do you agree that the shut in wells tend to be low output wells? So if I shut down 37 of those
but complete one well the net change in output is zero.
Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the
net change in output would be zero, but there would be 19,000 fewer producing wells, if we assume
the average output of the 1000 new wells completed was 200 b/d for the year and the stripper wells
produced 10 b/d on average.
How much do you expect output to fall in the US by Dec 2017?
Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by about
1 million barrels per day from April 2015 to July 2016, can you point me to your comment where
you predicted this?
Tell us what it will be in August 2017.
I expected the fall in supply would lead to higher prices, I did not expect World output to
be as resilient as it has been and I also did not realize how oversupplied the market was in April
2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan to April,
so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US output has decreased
by 635 kb/d.
If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would also
have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400 kb/d.
If we consider 12 month average output of World C+C, the decline has been 340 kb/d from the 12
month average peak in August 2015 (centered 12 month average).
The dropping numbers are not as much from the wells that produce less than 10 barrels a day, but
from those producing greater than 10, but less than 100. The ones producing greater than 100 are
remaining at a consistent level over 9000 to 9500. The prediction on one million was as to the
US shale only. It is your site, you can search it better than I can,
But then don't take my word for it. You can find the same information under the Texas RRC site
under oil and gas/research and statistics/well distribution tables. Current production for Sep
can be found at online research queries/statewide. It is still dropping, and will long term at
the current activity level. Production drop for oil, only, is a little over 40k per day barrels,
and condensate is lower for September. Proofs in the pudding.
My guess is that you would see a lot more plugging reports, if it were not so expensive to plug
a well. At net income levels where they are, I expect they would put that off as long as they
could.
I trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno Peters
data has 66 completions in August 2016, he has not put up his post for the Sept data yet so I
am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno tends
to be spot on for the Bakken data, for Texas he relies on RRC data which is not very good.
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.
It appears this was because another 13 wells in the field were recently completed.
It appears that when all 29 wells are returned to full production, this field will be very
prolific initially. Therefore, on this one field alone, we could see some impact for the entire
state.
Does anyone know if these wells are part of Whiting's JV? Telling if they had to do that on
these strong wells. Bakken just not close to economic.
I also note that average production days per well in for EOG in Parshall was 24. I haven't
looked at some of the other "older" large fields yet, but assume the numbers are similar.
I agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I
don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk
costs in wells drilled but not completed and running the numbers based on whether they can pay
back the completion costs. Everyone may be hoping the other guys fail and are just trying to pay
the bills as best they can, not sure if just stopping altogether is the best strategy.
There is the old adage that when your in a hole, more digging doesn't help much.
So my model just assumes continued completions at the August rate for about 12 months with
gradually rising prices as the market starts to balance, then a gradual increase in completions
as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90
completions per month 18 months later). At that point oil prices have risen to $97/b and LTO companies
are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at that level
for 40 years (not likely, but the model is simplistic).
I could easily do a model with no wells completed, but I doubt that will be correct. Suggestions?
Dennis. As we have discussed before, tough to model when there is no way to be accurate regarding
the oil price.
I continue to contend that there will be no quick price recovery without an OPEC cut. Further,
the US dollar is very important too, as are interest rates.
At some point OPEC may not be able to increase output much more and overall World supply will
increase less than demand. My guess is that this will occur by mid 2017 and oil prices will rise.
OPEC output from Libya an Nigeria has recovered, but this can only go so far, maybe another 1
Mb/d at most. I don't expect any big increases from other OPEC nations in the near term.
A big guess as to oil prices has to be made to do a model.
I believe my guess is conservative, but maybe oil prices will remain where they are now beyond
mid 2017.
I expected World supply to have fallen much more quickly than has been the case at oil prices
of $50/b.
"EIA does this by using a relatively new dataset-FracFocus.org's national fracking chemical
registry-to identify the completion phase, marked by the first fracking. If a well shows up on
the registry, it's considered completed "
There is an unlikely peak oil related editorial writer hiding in the most unlikely place: a weekly
English business paper called Capital Ethiopia. The latest editorial is again putting an excellent
perspective on world events.
http://capitalethiopia.com/2016/11/15/system-failure/#.WC1ZCvl9600
For the record, I have no interest or connection to this publication other than that of a paying
reader.
Wouldn't it be nice if mainstream publications would sound a bit more like this.
Thanks all. I thought that the red queen concept meant that there had to be an increase in the
rate of completions. So that 71 year-on-year in north Dakota would only stabilise temporarily.
Perhaps the loss of sweet spots are being counteracted by the improvements in technology? I'm
assuming that even with difficulties of financing there will be a swift increase in completions
should the oil price take off, but not sure how sustainable this would be
Sometimes I think that once the price of oil is up enough that sellers can hedge the their
selling price for two or three years at a profitable level, it will hardly matter what the banks
have to say about financing new wells.
At five to ten million apiece, there will probably be plenty of money coming out of various
deep pockets to get the well drilling ball rolling again, if the profits look good.
Sometimes the folks who think the industry will not be able to raise money forget that it's
not a scratch job anymore. The land surveys, roads, a good bit of pipeline, housing, leases, etc
are already in place, meaning all it takes to get the oil started now is a drill and frack rig.
I don't know what the price will have to be, but considering that a lot of lease and other
money is a sunk cost that can't be recovered, and will have to be written off, along with the
mountain of debts accumulated so far, the price might be lower than a lot of people estimate.
Bankruptcy of old owners results in lowering the price at which an old business makes money
for its new owners.
The Red Queen effect is that more and more wells need to be completed to increase output.
As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output it might
require 120 wells to be completed to maintain output (if new well EUR did not eventually decrease),
but at 850 kb/d it might require about 78 new wells per month to maintain output.
The FED oil production number for October came out yesterday. In below chart the production decline
(blue line) is the same as in the previous month, yet the trend is still a massive decline year
over year. In my view year over year comparison can show the dynamic of a trend. And it shows
clearly that in the current cycle the oil price recovery is – in contrast to the cycle in 2008/9
– very slow and tentative.
The year over year oil price (green line in below chart) actually decreased again year over
year and the risk of a double dip in the oil price is growing by the day. Drilling follows very
cautiously the oil price in a parallel line (red line in below chart). If there would be really
a technological advantage for shale, the red and the green line would not be paralell, but the
red line for drilling would rise much stronger. This is actually the case for Middle East drilling,
which barely fell during this cycle. This indicates that most Middle East producers still have
high margins at the current oil price. Middle East producers – and also Russia – can quite easily
cope with an oil price of 40 +/- 10 USD per barrel. This is why I think that the oil price will
bounce at the bottom of the barrel within above range for a few years.
There is also something interesting going on with the world economy. The shippers rose exponentionally
over the last few days (DRYS up over 1000%). Also the baltic Dry index is up 600% since the beginning
of this year. House prices here in London fell – mostly at the high end. Rents for expensives
homes are down by up to 36%. Donald Trump has clearly changed something already as it becomes
increasingly clear that the dollar hoarders are paying for the infrastructure spending. I am not
sure if he understands that he is doing a lot of harm to his own business empire as well.
I expect if that depressing old banker were here he would note that instability is dangerous,
and that all the moves in treasuries currency and possibly trade flow create changes of which
the results are difficult or impossible to predict
I can easily understand your assertion that Middle Eastern and Russian oil is profitable at
forty bucks.
But if the price is to stay around forty, then it follows that you think that between them,
the producers in the Middle East and Russia will be able to supply all the oil the world wants
for the next few years.
Am I correct in saying this?
Do you think western producers will continue to pump enough at a loss ( most of them are apparently
losing money at forty bucks ) to make up the difference?
If you are willing to venture a guess, when do you think the price will get back into the sixty
dollar and up range?
If you think it won't for a lot of years, is that because you believe the economy is will be
that anemic, or because electric cars will substantially reduce demand, or both ? Or maybe you
have other reasons ?
The US has thrown the gauntlet to OPEC by claiming to becoming an oil net exporter. This has
brought OPEC in a very difficult situation. If they cut – and oil gets to 70 USD per barrel –
shale will pick up the slack and produce the amount OPEC has cut within a short period of time.
So, OPEC is forced to cut again, until it has lost a lot of market share – and thus also a lot
of revenue.
In my view OPEC has no other choice than to produce come hell and water – until something breaks.
This could be that many shale companies give up or that for instance Iran is not allowed to export
as much as they do, or there is a major conflict in the Middle East, or Saudi Arabia is running
out of cash ..
He who has the market share now, will cash in when the oil price rises. And it will rise, yet
not until something breaks. This is how business works. This is how Microsoft crushed Apple in
the nineties in the PC market – and Apple then crushed Nokia in the smart phone market .
I do not think that Saudi Arabia has the freedom to compromise here – even if they want. If
they blink they will be crushed by shale producers. So, the stand-off will go on for a while,
at a loose-loose situation for both parties. However this is great luck for consumers as they
can enjoy low energy prices for 2 to 3 years.
I think your numbers reflect numbers reported from ND DMR but Bloomberg might be closer to
reality for wells that will actually ever be completed (just a guess by me though). How do Bloomberg
get their numbers (e.g. removing Tight Holes, or removing old wells, not counting non-completed
waivers etc.)?
Yes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old
wells for example, and already include those that were spud last month (even though maybe casing
has not been set). I don't do a lot of filtering, so the actual # wells that really can be completed
is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know Bloombergs
method exactly, so I can't comment on that.
Discussion of Venezuelan politics should be in the open thread, but politics are going to determine
how much oil is produced there for the next few years, and the situation looks iffy indeed.
Concerning Freddy's chart of production profile of wells drilled in various years.
They all line up by about month 18 of production. This should not be possible. The later wells
have many more stages of frack. They are longer, draining more volume of rock. But the chart says
what it says. At month about 18 the 2014 wells are flowing the same rate as 2008 wells. We know
stage count has risen over those 6 yrs. 2014 wells should flow a higher rate. The shape of the
curve can be the same, but it should be offset higher.
Explanation?
How about above ground issues . . . older wells get pipelines and can flow more oil . . . nah,
that's absurd.
There needs to be a physical explanation for this.
These new wells have higher IPs, but also higher decline rates.
Closer spacing (see Freddy's comment above) and depletion of the sweet spots may also impact production
curves and EURs.
That doesn't make sense. They are longer. By a factor of 2ish. How can a 6000 foot lateral flow
exactly the same amount 2 yrs into production as a 3000 foot lateral flows 2 yrs into production?
Look at the lines. At 18 months AND BEYOND, these longer laterals flow the same oil rate as
the shorter laterals did at the same month number of production. Higher IP and higher decline
rate will affect the shape, but There Is Twice The Length..
I don't think we have information on the length of the wells, since 2008 the length of the
lateral has not changed, just the number of frack stages and amount of proppant. This seems to
primarily affect the output in the first 12 to 18 months, and well spacing and room in the sweet
spots no doubt has some effect (offsetting the greater number of frack stages etc.).
The combination of longer lateral lengths and advancements in completion technology has allowed
operators to increase the number of frac stages during completions and space them closer together.
The result has been a higher completion cost per well but with increased production and more emphasis
on profitability.
In the past five years, DTC Energy Group completion supervisors in the Bakken have helped oversee
a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even 40-stage fracs
have been achieved.
One of the main reasons for this is the longer lateral lengths – operators now have twice as
much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are also being
spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet in 2008,
as experienced by DTC supervisors.
By placing more fracture stages closer together, over a longer lateral length, operators have
successfully been able to improve initial production (IP) rates, as well as increase EURs over
the life of the well.
blah blah, but they make clear the years have increased length. Freddy was talking about well
spacing, this text is about stage spacing, but that is achieved because of lateral length.
Freddy can you revisit your graph code? It's just bizarre that different length wells have
the same flow rate 2 yrs out, and later.
Take a look at Enno´s graphs at https://shaleprofile.com/
. They look the same as my graphs and we have collected and processed the data independently
from each other.
If the wells have the same wellbore riser design irrespective of lateral length (i.e. same depth,
which is a given, same bore, same downhole pump) then that section might become the main bottleneck
later in life and not the reservoir rock. With a long fat tail that seems more likely somehow
compared to the faster falling Eagle Ford wells say (but that is just a guess really). But there
may be lots of other nuances, we just don't have enough data in enough detail especially on the
late life performance for all different well designs – it looks like the early ones are just reaching
shut off stage in numbers now. I doubt if the E&Ps concentrated on later life when the wells were
planned – they wanted early production, and still do, to pay their creditors and company officers
bonuses (not necessarily in that order).
Hmmm. I know it is speculation, but can you flesh that out?
If some bottleneck physically exists that defines a flow rate for all wells from all years
then that does indeed explain the graphs, but what such thing could exist that has a new number
each year past year 2?
We certainly have discussed chokes for reservoir/EUR management, but the same setting to define
flow regardless of length?
The flow depends on the available pressure drop, which is made up of friction through the rock
and up the well bore (plus maybe some through the choke but not much), plus the head of the well,
plus a negative number if there is a pump. The frictional and pump numbers depend on the flow
and all the numbers depend on gas-oil ratio. Initially there is a big pressure drop in the rock
because of the high flow, then not so much. Once the flow drops the pressure at base of the well
bore just falls as a result of depletion over time, the effect of the completion design is a lot
less and lost in the noise, so all the wells behave similarly. That's just a guess – I have never
seen a shale well and never run a well with 10 bpd production, conventional or anything else.
A question might be if the flow is the same why doesn't the longer well with the bigger volume
deplete more slowly, and I don't know the answer. It may be too small to notice and lost in the
noise, or to do with gas breakout dominating the pressure balance, or just the way the the physics
plays out as the fluids permeate through the rock, or we don't have long enough history to see
the differences yet.
The number of rail cars hauling petroleum is a constant in the range of 7,200 to 7,400 petroleum
cars hauled each week for a good six months now.
Seems as though petroleum by rail is more of a necessity than a choice.
The volume is down a good thirty percent since about 2013 when over 10,000 cars were hauled
per week.
Demand decreases, contracts expire, better modes of transport emerge and cost less. not as
much call for Bakken oil. Plenty of the stuff somewhere else in this world.
The trend is down, not up for petroleum hauled by rail.
If there were orders for Bakken oil for one million bpd, the production would be one million
bpd.
Over the whole rail system, petroleum and petroleum product rail car loadings were down to
10.5 thousand in September. That compares to a high point of 16.3 thousand railcars in Sept of
2014.
Coal car loadings are on the rise, from a low of 61,000 in April to 86,000 in Sept. Coal was
running a near steady 105,00 to 110,000 railcars every month in 2013 and 2014.
The chart below from RBN shows that Bakken pipeline capacity did not increase since early 2015.
But production dropped, and this primarily affected volumes of Bakken oil transported by rail.
Given the higher percentage of oil transported by pipelines, the average transporation cost
for Bakken crude should have decreased. Interesting, however, that the price differential between
the well-head Bakken sweet crude and WTI has remained within the $10-12/bbl range.
Bakken Crude Production and Takeaway Capacity
Source: RBN
Bakken Blend differentials at terminals close to North Dakota wellheads held their lowest assessment
since December Tuesday, closing at the calendar-month average of the NYMEX light sweet crude oil
contract (WTI CMA) minus $6.25/b.
While one factor dragging on Bakken differentials has clearly been a tight Brent/WTI spread -
trading around 42 cents/b Tuesday, well in from the steady $2/b seen this summer - the return
of Louisiana Light Sweet to the Midwest market may also be having an impact, according to traders.
One trader said there was an increase in volumes heading up the Capline pipeline, however, differentials
suggest LLS is still too expensive, at least compared to Bakken. Platts assessed LLS at WTI plus
$1.15/b Tuesday.
Considered by some to be the "champagne of crudes," it is unclear what appeal LLS still has for
a Midwest refiner as margins for LLS actually - and unusually - lag those for Bakken.
S&P Global Platts data shows LLS cracking margins in the Midwest closed at $3.30/b Monday, compared
to Bakken cracking margins of $6.37/b. In fact, the advantage of cracking Bakken has grown steadily
since August.
Platts margin data reflects the difference between a crude's netback and its spot price.
Netbacks are based on crude yields, which are calculated by applying Platts product price assessments
to yield formulas designed by Turner, Mason & Co.
What is clear however, is that the steeper discounts available for Bakken provide the biggest
incentive for a Midwest refiner.
The cost of getting Bakken to this market is around $3.48/b, according to Platts netback calculations,
compared to just $1.02/b for LLS.
These costs make up a significant portion of the Bakken discount.
Further, LLS moving up the Capline after many years of relative inactivity does not necessarily
suggest a new trend is in the making. However, recent pipeline reversals between Texas and Louisiana
mean more Permian crudes are capable of reaching Louisiana refineries, and thus, if priced accordingly,
could displace incremental volumes of LLS from its home market.
With current pipeline capacity out of North Dakota typically full, the marginal Bakken barrel
often gets to market via rail, and this cost has traditionally sets the floor to Bakken's discount
to WTI. And part of the recent downturn in Bakken could be chalked up to an increase in railed
volumes to the US Atlantic Coast, as Bakken cracking margins there are again in the black.
In fact, Association of American Railroad's latest monthly and weekly data shows crude and refined
product rail movements appear to have bottomed, having grown in September from August.
Weekly data bears this out as well, showing increases in three of the last four weeks.
It remains to be seen how long this will last, however, should Energy Transfer Partners Dakota
Access Pipeline go ahead as planned.
Linefill for the pipeline could boost Bakken differentials, potentially making the grade too expensive
to rail east. However, the devil is in the details.
Traders and analysts have pegged Dakota Access pipeline tariffs between $4.50-$5.50/b for uncommitted
shippers between North Dakota and Patoka, Illinois. A further $6.50/b would be needed to bring
the crude south from Patoka to Nederland, Texas, sources have said.
If this $11-$12/b combined pipeline estimated cost were to pan out, it would be more expensive
than the $10.20/b Platts assumes in its Bakken USAC rail-based netback calculation.
Oil rig count in the Permian is up 73.5% from this year's low – the biggest increase among
all US basins.
It is still only 41% of October 2014 peak, but this is much better than the Bakken and especially
the Eagle Ford where drilling activity remains depressed.
As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production
in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota
Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number
of producing wells is up 1861 based upon data from the state.
Based upon state data, the number of producing wells/square mile is 1.29 in Mountrail County,
1.22 in McKenzie County, 1.02 in Willams County, and 0.86 in Dunn County. How high can the number
of producing wells/square mile go?
Is there something more than reduced drilling to explain the drop in production?
This shows well density and production from last September. The distance is concentric from a
"production centre of gravity" – i.e. weighted average by production for all wells. The core area
("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and
missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres,
and falls off quickly outside the core. The core is getting saturated.
"U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now
holds nearly as many active oil rigs as the rest of the United States combined, including both
onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where
crude oil production is expected to increase for the third consecutive month."
Permian Basin also dominates M&A activity in the US E&P sector.
From the same EIA report:
"Several of the larger M&A deals involved Permian Basin assets, where drilling and production
is beginning to increase.
Based on data through November 10, the second half of 2016 already has more M&A spending than
the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016
totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since
the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016
are in the Permian Basin, they accounted for more than half of total deal value."
RRC Texas for September came out recently. As others will probably elaborate more on the data,
I just want to show if year over year changes in production could be use as a predictive tool
for future production (see below chart).
It is obvious that year over year changes (green line) beautifully predicted oil production
(red line) at a time lag of about 15 month. Even when production was still growing, the steep
decline of growth rate indicated already the current steep decline.
The interesting thing is that the year over year change is a summary indicator. It does not
tell why production declines or rises. It can be the oil price, interest rates or just depletion
– even seasonal factors are eliminated. It just shows the strength of a trend.
I am curious myself how this works out. The yoy% indicator predicts that Texas will have lost
another million bbl per day by end next year. That sounds quite like a big plunge. One explanation
could be the fact that we have now low oil prices and high interest rates. In all other cycles
it has been the other way around: low oil prices came hand in hand with low interest rates. This
could be now a major obstacle for companies to grow production.
This concept of following year over year changes works of course just for big trends, yet for
investment timing it seems exactly the right tool. Another huge wave is coming in electric vehicles
which are growing in China by 120% year over year. Here we have the same situation as for shale
7 years ago: Although current EV sales are barely 1 million per year worldwide, the growth rate
reveals already an huge wave coming. So as an investor it is always necessary to stay ahead of
the trend and I think this can be done by observing the year over year% change.
"... I am a petroleum Geologist drilling wells in the Wolfcamp, the USGS report means nothing. They periodically review basins to assess how much petroleum is there, we have been drilling Horizontal wells in the Wolfcamp for almost a decade, and vertical wells for many decades. Right now there are as many rigs running drilling this rock formation as there are in the rest of the country combined, so it is already baked in to the US production data. This is not like a Saudi Arabia field with a low drill and complete and development cost, it will take many billions of drilling capital to get a small percentage of the oil in place. The big deal is that the area is fairly resilient to low oil prices and will cushion the drop in US production due to lack of investment in other basins. ..."
"... I think when seismic, land, surface and down hole equipment is included, the number is much higher. With $20-60K per acre being paid, land definitely has to be factored in. Depending on spacing, $1-5 million per well? ..."
"... In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost. This does not include costs incurred prior to the well being drilled, which are not insignificant. Nor does it include costs of down hole and surface equipment, which also are not insignificant. ..."
"... Land costs are all over the map, and I think Bakken land costs overall are the lowest, because much of the leasing occurred prior to US shale production boom. I think a lot of acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so we have to look project by project, unfortunately. For purposes of a model, I think $8 million is probably in the ballpark. ..."
"... I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick with, being US based). The companies do not do that, those costs are included in depreciation, depletion and amortization expense. ..."
"... Once the well is in production, and failures occur, I include the cost of repairs, including replacement equipment, in LOE. I am not sure that the companies do that, however. ..."
"... I think the Permian is going to be much tougher to estimate, as there are different producing formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1 or 2. ..."
"... What most interests me are suggestions that there is so much available oil in Wolfcamp and what that will do to oil prices and national policy. Seems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling. ..."
"... The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc. ..."
"... In November 2015, the EIA estimated proven reserves of tight oil in Wolfcamp and Bone Spring formations as of end 2014 at just 722 million barrels. ..."
"... AlexS. Another key question, which is price dependent, is how many years will it take to fully develop the reserves? ..."
"... If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp up at the speed of the Eagle Ford ..."
"... It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect economic growth", "geology is about to beat human ingenuity" etc. ..."
I am a petroleum Geologist drilling wells in the Wolfcamp, the USGS report means nothing. They
periodically review basins to assess how much petroleum is there, we have been drilling Horizontal
wells in the Wolfcamp for almost a decade, and vertical wells for many decades. Right now there
are as many rigs running drilling this rock formation as there are in the rest of the country
combined, so it is already baked in to the US production data. This is not like a Saudi Arabia
field with a low drill and complete and development cost, it will take many billions of drilling
capital to get a small percentage of the oil in place. The big deal is that the area is fairly
resilient to low oil prices and will cushion the drop in US production due to lack of investment
in other basins.
Thank you, JG -- Straight from the horses mouth, respectfully. The USGS lost all credibility with
me as to estimating TRR in the Monterrey Shale in California. It baffles me, after five years
of publically discussing unconventional shale oil resources, that modelers, internet analysts
and predictors completely ignore economics, debt and finances. Extracting oil is a business; it
must make money to succeed. If it does not succeed, all bets are off regarding predictions.
The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant
do the analysis and it was mostly based on investor presentations, very little geological analysis.
It would be better if the USGS did an economic analysis as they do with coal for the Powder
River Basin. They could develop a supply curve based on current costs, but they don't.
Do you have any idea of the capital cost of the wells (ballpark guess) for a horizontal multifracked
well in the Wolfcamp? Would $7 million be about right (a WAG by me)?
On ignoring economics, I show my oil price assumptions. Other financial assumptions for the
Bakken are $8 million for capital cost of the well (2016$). OPEX=$9/b, other costs=$5/b, royalty
and taxes=29% of gross revenue, $10/b transport cost, and a real discount rate of 7% (10% nominal
discount rate assuming 3% inflation).
I do a DCF based on my assumed real oil price curve. Brent oil price rises to $77/b (2016$)
by June 2017 and continue to rise at 17% per year until Oct 2020 when the oil price reaches $130/b,
it is assumed that average oil prices remain at that level until Dec 2060. The last well is drilled
in Dec 2035 and stops producing 25 years later in Dec 2060.
EUR of wells today is assumed to be 321 kb and EUR falls to 160 kb by 2035. The last well drilled
only makes $243,000 over the 7% real rate of return, so the 9 Gb scenario is probably too optimistic,
it is assumed that any gas sales are used to offset OPEX and other costs, though no natural gas
price assumptions have been made to simplify the analysis.
This analysis is based on the analyses that Rune Likvern has done in the past, though his analyses
are far superior to my own.
I think when seismic, land, surface and down hole equipment is included, the number is much higher.
With $20-60K per acre being paid, land definitely has to be factored in. Depending on spacing,
$1-5 million per well?
I am doing the analysis for the Bakken. A lot of the leases are already held and I don't know
that those were the prices paid. Give me a number for total capital cost that makes sense, are
you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the different
assumptions you would like to change would be good so I don't redo it 5 times.
Mostly I would like to clear up "the number".
I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes,
real discount rate (adjusted for inflation), well cost.
I think you a re talking about well cost as "the number". I include down hole costs as part
of OPEX (think of it as OPEX plus maintenance maybe).
Dennis. The very high acreage numbers are for recent sales in the Permian Basin.
In reading company reports, it seems they state a cost to drill and case the hole, another
to complete the well, then add the two for well cost. This does not include costs incurred prior to the well being drilled, which are not insignificant.
Nor does it include costs of down hole and surface equipment, which also are not insignificant.
Land costs are all over the map, and I think Bakken land costs overall are the lowest, because
much of the leasing occurred prior to US shale production boom. I think a lot of acreage early
on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so
we have to look project by project, unfortunately. For purposes of a model, I think $8 million
is probably in the ballpark.
I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick
with, being US based). The companies do not do that, those costs are included in depreciation,
depletion and amortization expense.
Once the well is in production, and failures occur, I include the cost of repairs, including
replacement equipment, in LOE. I am not sure that the companies do that, however.
I think the Permian is going to be much tougher to estimate, as there are different producing
formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1
or 2.
An example:
QEP paid roughly $60,000 per acre for land in Martin Co., TX. If we assume one drilling unit
is 1280 acres (two sections), how many two mile laterals will be drilled in the unit?
1280 acres x $60,000 = $76,800,000.
Assume 440′ spacing, 12 wells per unit.
$76,800,000/12 = $6,400,000 per well.
However, there are claims of up to 8 producing zones in the Permian.
So, 12 x 8 = 96 wells.
$76,800,000 / 96 = $800,000 per well.
Even assuming 96 wells, the cost per well is still significant.
If we assume 96 wells x $7 million to drill, complete and equip, total cost to develop is $.75
BILLION. That is a lot of money for one 1280 acre unit, need to recover a lot of oil and gas to
get that to payout.
I am neither an oil man nor an accountant, so regardless of what we call it I am assuming natural
gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to operate the
well (LOE, OPEX, financial costs, etc), we could add another million to the cost of the well for
surface and downhole equipment and land costs. Does an average operating cost over the life of
a well of about $17/b ($14/b plus natural gas sales of $3/b of oil produced)seem reasonable?
That
would be about $5.4 million spent on LOE etc. over the life of the well (assuming 320 kbo produced).
Also does the 10% nominal rate of return sound high enough, what number would you use as a cutoff?
You use a different method than a DCF and want the well to pay out in 60 months. This would correspond
to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3% annual inflation
rate.)
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do
the analysis and it was mostly based on investor presentations, very little geological analysis."
Exactly.
USGS' estimate as of October 2015 is very conservative:
"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an
estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1 million
barrels of natural gas liquids, according to the first USGS assessment of continuous (unconventional),
technically recoverable resources in the Monterey Formation."
"The volume estimated in the new study is small, compared to previous USGS estimates of conventionally
trapped recoverable oil in the Monterey Formation in the San Joaquin Basin. Those earlier estimates
were for oil that could come either from producing more Monterey oil from existing fields, or
from discovering new conventional resources in the Monterey Formation."
Previous USGS estimates were for conventional oil:
"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin,
estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in
2012, USGS assessed the potential volume of oil that could be added to reserves in the San Joaquin
Basin from increasing recovery in existing fields. The results of that study suggested that a
mean of about 3 billion barrels of oil might eventually be added to reserves from Monterey reservoirs
in conventional traps, mostly from a type of rock in the Monterey called diatomite, which has
recently been producing over 20 million barrels of oil per year."
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp.
Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA
and awaiting re-drills; that should tell you something. With acreage, infrastructure and water
costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's
what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste
of time, sorry.
What most interests me are suggestions that there is so much available oil in Wolfcamp and what
that will do to oil prices and national policy. Seems like any announcement of more oil will likely keep prices low. And if they stay low,
there's little reason to open up more areas for oil drilling.
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well spacing,
pick total acreage, pick a factor for dry holes – multiply a by c by d and divide by b."
USGS estimates for average well EUR in Wolfcamp shale look reasonable: 167,ooo barrels in the
core areas and much lower in other parts of the formation.
I do not know if the estimated potential production area is too big, or assumed well spacing
is too tight.
The key question is what part of these estimated technically recoverable resources are economically
viable at $50; $60; $70; $80; $90, $100, etc.
Significant part of resources may never be developed, even if they are technically recoverable.
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves times
1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3 Gb of
2P reserves that have been added to Permian reserves since 2011, if we assume most of these are
from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that total proved
plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved plus 3.5 GB
probable with the assumption that probable=proved/2). I have assumed about 30% of total Permian
2P reserves is in the Wolfcamp shale. That is a WAG.
Note the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a conservative
guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go to $85/b and
remain at that level the F95 estimate may become ERR, at $100/b maybe the median is potentially
ERR. It will depend how long prices can remain at $100/b before an economic crash, prices are
Brent Crude price in 2016$ with various crude spreads assumed to be about where they are now.
I just looked at Permian Basin crude reserves (Districts 7C, 8 and 8A) and assumed the change
in reserves from 2011 to 2014 was from the Wolfcamp. I didn't know about that page for reserves.
It is surprising it is that low.
In any case the difference is small relative to the UTRR, it will be interesting to see what
the reserves are for year end 2015.
Based on this I would revise my estimate to 20 Gb for URR with a conservative estimate of 12
Gb until we have the data for year end 2015 to be released later this month.
My guess is that the USGS probably already has the 2015 year end reserve data.
The EIA proved reserves estimate for 2015 will be issued this month. I think we will see a
significant increase in the number for the Permian basin LTO.
Also note that USGS TRR estimate is only for Wolfcamp.
I can only guess what could be their estimate for the whole Permian tight oil reserves.
But the share of Wolfcamp in the Permian LTO output is only 24% (according to the EIA/DrillingInfo
report).
That makes sense. I also imagine the USGS focused on the formation with the bulk of the remaining
resources. It is conceivable that the 30 Gb estimate is closer to the remaining oil in place and
that more like 90% of the TRR is in the Wolfcamp, considering that the F5 estimate is about 30
Gb. That older study from 2005 may be an under estimate of TRR for the Permian, likewise the USGS
might have overestimated the UTRR.
If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp
up at the speed of the Eagle Ford (say 2 to 3 years). It will be oil price dependent and perhaps
they won't over do it like in 2011-2014, but who knows, some people don't learn from past mistakes.
If you or Mike were running things it would be done right, but the LTO guys, I don't know.
"This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically
recoverable resources.
Undiscovered resources are those that are estimated to exist based on geologic knowledge and
theory, while technically recoverable resources are those that can be produced using currently
available technology and industry practices. Whether or not it is profitable to produce these
resources has not been evaluated."
If it requires slave labor at gunpoint to get the oil out, then that's what will happen because
you MUST have oil, and a day will soon come when that sort of thing is reqd.
This follows on from reserve post above (two a couple of comments). In terms of changes over the
last three years – there really weren't anything much dramatic. We'll see what 2016 brings, especially
for ExxonMobil, but it looks like they already knocked a big chunk off of their Bitumen numbers
already in 2015.
Note I went through a lot of 20-F and 10-K reports watching the rain fall this morning and
copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general trends
are shown.
Note the figures are totals for all nine companies I looked at.
IEA WEO is out:
http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html presentation
slides, fact sheet and summary are available online (report can be purchased). IEA seems to be
_very_ concerned about underinvestment in upstream oil production. Several pages of the report
is devoted to this, the title of that section is "mind the gap". More or less all of the content
has been discussed on this website, including the issue with high levels of debt and that this
can affect suppliers' capacity to rebound, and how much demand can be reduced as a result of a
stringent carbon cap.
From the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production
in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil sands)
approved for development in 2015 sank to the lowest level since the 1950s, with no sign of a rebound
in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely that demand (as
projected in our main scenario) and supply can be matched in the early 2020s without the start
of a new boom/bust cycle for the industry"
Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"
I wonder who that paragraph is aimed at. As I indicated above the companies that would be investing
in long term conventional projects don't have a very large inventory of undeveloped reserves (17
Gb as of end of 2015, some of this has gone already this year and more is in development and will
come on stream in 2017 and 2018 (and a small amount in later years for approved projects). I'd
guess there might only be less than 10 Gb (and this the most expensive to develop) that is currently
under appraisal among the major western IOCs and larger independents; allowing for their partnerships
with NOCs in a lot of the available projects that could represent 20 to 30 Gb total. That really
isn't very much new supply available, and a large proportion is in complex deep water projects
that wouldn't be ramped up fully until 6 to 7 years after FID (i.e. already too late for 2020).
Really the main players need to find new fields with easy developments, but they obviously aren't,
probably never will, and actually aren't looking very hard at the moment.
My interpretation is that this is IEAs way of saying that it does not look good. Those who can
read between the lines get the message. Also, a few years from they will be able to say "see we
told you so".
It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect
economic growth", "geology is about to beat human ingenuity" etc.
WEO have become more and more bizarre over the years. On the one hand they contain quantitative
projections which tell the story politicians wants to hear. On the other hand, the text describes
all sorts of reason of why the assumptions are unlikely to hold. Normally, if you don't believe
in your own assumptions you would change them.
"... As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state. ..."
"... This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated. ..."
"... "U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month." ..."
"... "Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase. Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value." ..."
The number of rail cars hauling petroleum is a constant in the range of 7,200 to 7,400
petroleum cars hauled each week for a good six months now.
Seems as though petroleum by rail is more of a necessity than a choice.
The volume is down a good thirty percent since about 2013 when over 10,000 cars were
hauled per week.
Demand decreases, contracts expire, better modes of transport emerge and cost less. not
as much call for Bakken oil. Plenty of the stuff somewhere else in this world.
The trend is down, not up for petroleum hauled by rail.
If there were orders for Bakken oil for one million bpd, the production would be one
million bpd. Bakken oil lost marketshare due to price drop. Buyers can buy oil from
anywhere.
More Bakken petroleum is being moved by pipeline. Over the whole rail system, petroleum
and petroleum product rail car loadings were down to 10.5 thousand in September. That
compares to a high point of 16.3 thousand railcars in Sept of 2014.
Coal car loadings are on the rise, from a low of 61,000 in April to 86,000 in Sept.
Coal was running a near steady 105,00 to 110,000 railcars every month in 2013 and 2014.
The chart below from RBN shows that Bakken pipeline capacity did not increase since
early 2015. But production dropped, and this primarily affected volumes of Bakken oil
transported by rail.
Given the higher percentage of oil transported by pipelines, the average
transportation cost for Bakken crude should have decreased. Interesting, however,
that the price differential between the well-head Bakken sweet crude and WTI has
remained within the $10-12/bbl range.
Bakken Crude Production and Takeaway Capacity
Source: RBN
Bakken Blend differentials at terminals close to North Dakota wellheads held their
lowest assessment since December Tuesday, closing at the calendar-month average of
the NYMEX light sweet crude oil contract (WTI CMA) minus $6.25/b.
While one factor dragging on Bakken differentials has clearly been a tight Brent/WTI
spread - trading around 42 cents/b Tuesday, well in from the steady $2/b seen this
summer - the return of Louisiana Light Sweet to the Midwest market may also be having
an impact, according to traders.
One trader said there was an increase in volumes heading up the Capline pipeline,
however, differentials suggest LLS is still too expensive, at least compared to
Bakken. Platts assessed LLS at WTI plus $1.15/b Tuesday.
Considered by some to be the "champagne of crudes," it is unclear what appeal LLS
still has for a Midwest refiner as margins for LLS actually - and unusually - lag
those for Bakken.
S&P Global Platts data shows LLS cracking margins in the Midwest closed at $3.30/b
Monday, compared to Bakken cracking margins of $6.37/b. In fact, the advantage of
cracking Bakken has grown steadily since August.
Platts margin data reflects the difference between a crude's netback and its spot
price.
Netbacks are based on crude yields, which are calculated by applying Platts
product price assessments to yield formulas designed by Turner, Mason & Co.
What is clear however, is that the steeper discounts available for Bakken provide
the biggest incentive for a Midwest refiner.
The cost of getting Bakken to this market is around $3.48/b, according to Platts
netback calculations, compared to just $1.02/b for LLS.
These costs make up a significant portion of the Bakken discount.
Further, LLS moving up the Capline after many years of relative inactivity does
not necessarily suggest a new trend is in the making. However, recent pipeline
reversals between Texas and Louisiana mean more Permian crudes are capable of
reaching Louisiana refineries, and thus, if priced accordingly, could displace
incremental volumes of LLS from its home market.
With current pipeline capacity out of North Dakota typically full, the marginal
Bakken barrel often gets to market via rail, and this cost has traditionally sets the
floor to Bakken's discount to WTI. And part of the recent downturn in Bakken could be
chalked up to an increase in railed volumes to the US Atlantic Coast, as Bakken
cracking margins there are again in the black.
In fact, Association of American Railroad's latest monthly and weekly data shows
crude and refined product rail movements appear to have bottomed, having grown in
September from August.
Weekly data bears this out as well, showing increases in three of the last four
weeks.
It remains to be seen how long this will last, however, should Energy Transfer
Partners Dakota Access Pipeline go ahead as planned.
Linefill for the pipeline could boost Bakken differentials, potentially making the
grade too expensive to rail east. However, the devil is in the details.
Traders and analysts have pegged Dakota Access pipeline tariffs between
$4.50-$5.50/b for uncommitted shippers between North Dakota and Patoka, Illinois. A
further $6.50/b would be needed to bring the crude south from Patoka to Nederland,
Texas, sources have said.
If this $11-$12/b combined pipeline estimated cost were to pan out, it would be
more expensive than the $10.20/b Platts assumes in its Bakken USAC rail-based netback
calculation.
Oil rig count in the Permian is up 73.5% from this year's low – the biggest increase
among all US basins.
It is still only 41% of October 2014 peak, but this is much better than the Bakken and
especially the Eagle Ford where drilling activity remains depressed.
As of September 2016, 4 counties produced 90.1% of all the Bakken/Three
Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn.
Relative to December 2014, North Dakota Bakken/Three Forks oil production is off
243,098 b/d relative to December 2014 while the number of producing wells is up 1861
based upon data from the state.
Based upon state data, the number of producing wells/square mile is 1.29 in
Mountrail County, 1.22 in McKenzie County, 1.02 in Willams County, and 0.86 in Dunn
County. How high can the number of producing wells/square mile go?
Is there something more than reduced drilling to explain the drop in production?
This shows well density and production from last September. The distance is
concentric from a "production centre of gravity" – i.e. weighted average by
production for all wells. The core area ("sweet spot") is a circle of about 50 to
60 kms only (it's squashed out a bit to the west and missing a bite in the SW).
Maximum well density (and with the best wells is 120 to 160 acres, and falls off
quickly outside the core. The core is getting saturated.
"U.S. drilling activity is increasingly concentrated in
the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of
the United States combined, including both onshore and offshore rigs, and it is the only
region in EIA's Drilling Productivity Report where crude oil production is expected to
increase for the third consecutive month."
Permian Basin also dominates M&A activity in the US E&P sector.
From the same EIA
report:
"Several of the larger M&A deals involved Permian Basin assets, where drilling
and production is beginning to increase.
Based on data through November 10, the second half of 2016 already has more M&A spending
than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third
quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the
largest per deal average since the third quarter of 2014. Although only 11 of the 49
deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for
more than half of total deal value."
"... Right now there are as many rigs running drilling this rock formation as there are in the rest of the country combined, so it is already baked in to the US production data. This is not like a Saudi Arabia field with a low drill and complete and development cost, it will take many billions of drilling capital to get a small percentage of the oil in place. The big deal is that the area is fairly resilient to low oil prices and will cushion the drop in US production due to lack of investment in other basins. ..."
"... The USGS lost all credibility with me as to estimating TRR in the Monterrey Shale in California. It baffles me, after five years of publically discussing unconventional shale oil resources, that modelers, internet analysts and predictors completely ignore economics, debt and finances. Extracting oil is a business; it must make money to succeed. If it does not succeed, all bets are off regarding predictions. ..."
I am a petroleum Geologist drilling wells in the Wolfcamp, the USGS report means
nothing. They periodically review basins to assess how much petroleum is there, we have
been drilling Horizontal wells in the Wolfcamp for almost a decade, and vertical wells
for many decades.
Right now there are as many rigs running drilling this rock
formation as there are in the rest of the country combined, so it is already baked in to
the US production data. This is not like a Saudi Arabia field with a low drill and
complete and development cost, it will take many billions of drilling capital to get a
small percentage of the oil in place. The big deal is that the area is fairly resilient
to low oil prices and will cushion the drop in US production due to lack of investment
in other basins.
Thank you, JG -- Straight from the horses mouth, respectfully.
The USGS lost all
credibility with me as to estimating TRR in the Monterrey Shale in California. It
baffles me, after five years of publically discussing unconventional shale oil
resources, that modelers, internet analysts and predictors completely ignore
economics, debt and finances. Extracting oil is a business; it must make money to
succeed. If it does not succeed, all bets are off regarding predictions.
The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private
consultant do the analysis and it was mostly based on investor presentations, very little
geological analysis.
It would be better if the USGS did an economic analysis as they do with coal for the
Powder River Basin. They could develop a supply curve based on current costs, but they
don't.
Do you have any idea of the capital cost of the wells (ballpark guess) for a horizontal
multifracked well in the Wolfcamp? Would $7 million be about right (a WAG by me)?
On ignoring economics, I show my oil price assumptions. Other financial assumptions for
the Bakken are $8 million for capital cost of the well (2016$). OPEX=$9/b, other
costs=$5/b, royalty and taxes=29% of gross revenue, $10/b transport cost, and a real
discount rate of 7% (10% nominal discount rate assuming 3% inflation).
I do a DCF based on my assumed real oil price curve. Brent oil price rises to $77/b
(2016$) by June 2017 and continue to rise at 17% per year until Oct 2020 when the oil price
reaches $130/b, it is assumed that average oil prices remain at that level until Dec 2060.
The last well is drilled in Dec 2035 and stops producing 25 years later in Dec 2060.
EUR of wells today is assumed to be 321 kb and EUR falls to 160 kb by 2035. The last
well drilled only makes $243,000 over the 7% real rate of return, so the 9 Gb scenario is
probably too optimistic, it is assumed that any gas sales are used to offset OPEX and other
costs, though no natural gas price assumptions have been made to simplify the analysis.
This analysis is based on the analyses that Rune Likvern has done in the past, though
his analyses are far superior to my own.
"... But it gets more apparent with each report they are concerned with a sudden drop in supply in the medium term (I think supply will decline gradually through 2017 but then accelerate in 2Q2018 and fall off a cliff in 2019 given current project planning. ..."
"... It is now becoming too late to do much that will impact supplies then and with the likelihood of low prices through next year and few attractive recent discoveries (and getting worse each quarter in that respect) there are unlikely to be many more FIDs next year than this – I think only 12 so far and more gas than oil – therefore that supply drought will probably extend through 2020. ..."
"... Decline rates could increase on existing fields at the same time as in-fill drilling marginal gains start to decline and the impact of reduced maintenance and brownfield spending during these low price years start to impact. ..."
"... People may point to US LTO fields to be able to quickly fill any gap, but I'd point out it took about 5 years for Bakken to ramp up to 1 mmbpd ..."
It looks like this month (Nov.) will probably be a new global oil supply record barring major
disruptions anywhere. But it gets more apparent with each report they are concerned with a sudden
drop in supply in the medium term (I think supply will decline gradually through 2017 but then
accelerate in 2Q2018 and fall off a cliff in 2019 given current project planning.
It is now becoming
too late to do much that will impact supplies then and with the likelihood of low prices through
next year and few attractive recent discoveries (and getting worse each quarter in that respect)
there are unlikely to be many more FIDs next year than this – I think only 12 so far and more
gas than oil – therefore that supply drought will probably extend through 2020.
Decline rates
could increase on existing fields at the same time as in-fill drilling marginal gains start to
decline and the impact of reduced maintenance and brownfield spending during these low price years
start to impact.
People may point to US LTO fields to be able to quickly fill any gap, but I'd point out it
took about 5 years for Bakken to ramp up to 1 mmbpd, and that was when the sweet spots were available
and with an industry not already loaded down with debt. That rate is not much better than a new
conventional basin with similar reserves would have achieved (as long as it wasn't in Kazahkstan
of course).
"It is not the role of the IEA to urge any oil industry player to take one course of
action rather than another, and we are not doing so now. Over time, market forces will do their
job and the oil price will respond to the signals provided by demand and supply. What the IEA
has argued for consistently is the need for investments necessary to meet rising oil demand.
Such investments ensure that the market remains close to balance and that prices are as stable
and as fair for both producers and consumers as can ever be possible in such a dynamic industry."
Related to ExxonMobil – they are the only major company so far this year to have had a couple
of good successes with exploration, that is a reverse previous history when they were known having
much more success "drilling on Wall Street" to boost their reserves – part of the reason for the
Mobil acquisition who always did pretty with with wildcatting.
It would be interesting to know how their reserves (and other companies as well) are broken
down between developed and undeveloped for oil and gas, before Liza in Guyana and the Owowo (Nigeria)
discovery this year they were pretty short of oil projects of any kind, irrespective of price,
except in support of some OPEC countries on buyback contracts, and I don't know how that oil is
counted against their reserves if at all.
Other majors might be in worse shape than them once
the current bubble of projects works through.
"... The approved projects coming on line are about 500 kbpd in 2019, 700 in 2020 and 200 in 2021. There will also be about 1 mmbpd still ramping up, but I think the supply will be slightly in deficit and any stock overhang will have largely gone by the end of 2018 (assuming demand stays as predicted). In terms of decline existing fields it is minimum 3.3% (based on Core labs) up to 5.5% by Rystad – but I think the cuts in maintenance and brownfield work, exhaustion of marginal in-fill drilling benefits and extended use of horizontal drilling over the last 15 years will mean this is likely to accelerate. ..."
"... I, like many, quote start-up date for end of project development but often it takes 12 to 18 months to ramp up to plateau, so all that lack of new supply in 2019 to 2021 can impact through to 2023. ..."
Price depends on supply and demand – I don't know what is going to happen in demand: it seems
to be predictable until suddenly it isn't. Recessions can have reasonably large impacts to demand
and these have proportionally larger impacts on price.
The approved projects coming on line are about 500 kbpd in 2019, 700 in 2020 and 200 in 2021.
There will also be about 1 mmbpd still ramping up, but I think the supply will be slightly in
deficit and any stock overhang will have largely gone by the end of 2018 (assuming demand stays
as predicted). In terms of decline existing fields it is minimum 3.3% (based on Core labs) up
to 5.5% by Rystad – but I think the cuts in maintenance and brownfield work, exhaustion of marginal
in-fill drilling benefits and extended use of horizontal drilling over the last 15 years will
mean this is likely to accelerate.
Note there will of course be other projects added, but another low price year in 2017 with
additional cuts (e.g. see CoP, Statoil, PetroBras, Pemex news over the last weeks) and there just
won't be enough time to get much online before 2021, especially as the service industries and
development groups in the E&Ps are still getting thinned out (see Weatherford, Heerema, Hess news
recently).
I, like many, quote start-up date for end of project development but often it takes
12 to 18 months to ramp up to plateau, so all that lack of new supply in 2019 to 2021 can impact
through to 2023.
"... It would appear that perhaps a lot of infill drilling is taking place in Saudi Arabia, Kuwait and UAE in order to achieve these recent oil production values. It'll be interesting to see how this infill drilling might one day impact the decline side of the curve. ..."
"... According to Bedford Hill and the oil engineers at the Hills Group, Saudi oil production will experience at SENECA CLIFF like decline. I agree. ..."
"... I'm no expert but from what I understand infill drilling causes what might have been a roughly Hubbert shaped production curve to flatten out at the top for a while and then in the future experience a steeper decline curve; basically representing future production on the Hubbert curve being brought forward to maintain a plateau at the peak. This does seem to move the curve profile from Hubbert to Seneca, so to speak. ..."
"... This image from Matt certainly represents a plateau at approx 72 million barrels a day taking place in all jurisdictions outside of Canada and USA. ..."
"... I'm very interested in the timing and the steepness of this impending decline. Figure 10 mentioned above shows the rig count in Kuwait, Saudi and UAE really taking of 'bigly' in 2010-2011 'ish. ..."
It would appear that perhaps a lot of infill drilling is taking place in Saudi Arabia,
Kuwait and UAE in order to achieve these recent oil production values. It'll be interesting to
see how this infill drilling might one day impact the decline side of the curve.
I'm no expert but from what I understand infill drilling causes what might have been a roughly
Hubbert shaped production curve to flatten out at the top for a while and then in the future experience
a steeper decline curve; basically representing future production on the Hubbert curve being brought
forward to maintain a plateau at the peak. This does seem to move the curve profile from Hubbert
to Seneca, so to speak.
This image from Matt certainly represents a plateau at approx 72 million barrels a day
taking place in all jurisdictions outside of Canada and USA.
I'm very interested in the timing and the steepness of this impending decline. Figure 10
mentioned above shows the rig count in Kuwait, Saudi and UAE really taking of 'bigly' in 2010-2011
'ish.
"... If all those resources which some fear may be unleashed had been profitable to work, they would have been worked already. Regardless of what areas get released for exploitation, there has to be profit to be made, or it will not happen. ..."
"One thing is for sure: he will usher in one of the most deregulated eras for
oil and gas in recent memory. He will rescind regulations that affect methane emissions, hydraulic
fracturing, and greenhouse gas emissions. He will likely streamline or gut permitting requirements
for major infrastructure projects, clearing the way for pipelines. He will probably open up public
lands for expanded drilling opportunities, and in time, he could auction off drilling rights in the
Atlantic Ocean, Arctic Ocean, Alaskan wilderness, and even the Eastern Gulf of Mexico. He has also
promised to withdraw from the Paris Climate Accord. Some of that agenda will require acts of Congress,
but with Republican control of both the House and Senate, nearly all of that agenda is within reach.
It is hard to overstate what a revolution in energy policy this could be."
Why yes. Let's "drill, baby, drill." Have oil companies put more money into drilling, dump more
supplies on the market, and see what happens to prices.
Ah, commodity pricing. The best way to get higher prices is to increase supply, right?
Well, it's not the best way. It's just largely irrelevant.
But along these lines of Trump's
impact on oil - there is rather a lot of talk about a tsunami of money coming to fund his priorities,
which certainly include shale.
I say wait a minute. He's an independent who managed to get the GOP nomination. He isn't
afraid of borrowing money, but the tsunami to help shale and coal . . . the debt ceiling has
to be raised in the Feb time frame and Wall Street this week has conveniently forgotten this.
A totally GOP govt has to raise the debt ceiling.
The fiscal conservatives will RAGE. It will be a vicious fight. And when it's done and the
ceiling is raised, is it really rational to think that the very next thing that happens is
a tsunami of spending on infrastructure, coal and shale?
No way in hell. I smell budget neutral as the soon to be order of the day. Something will
get gutted to pay for something else.
If all those resources which some fear may be unleashed had been
profitable to work, they would have been worked already. Regardless of
what areas get released for exploitation, there has to be profit to be
made, or it will not happen.
So I think fears of an explosion of
exploitation, of solid and liquid fuel production and resulting carbon
emissions are founded on too narrow a view of what it takes to get those
resources up, out and into the market place.
There may be a few parts of those areas which may be viable in today's
economic climate, but I doubt that they will even make up the annual
decline rate.
At the same time tho, a few local companies may get to redeploy a few
unemployed workers from shale and tar sands work, and thus save a few
jobs for a while. Enough to look good on the books, without really
changing much either way.
Or they could buy all the bad investments and call it liquidity
support. Socializing the risks and privatizing the profits is
certainly a key feature of the American way. The true free market
is a kind of myth because it has never existed under industrial
capitalism. Governments, rather than markets, have always
determined the fortunes of corporations, through preferential
contracting, tax breaks and direct subsidies. Now we can add
bailouts and liquidity support to the list of measures. It's
interesting to note that USA is the only democracy without a left
wing party. The spectrum starts at centre right and then spans
further to the right where it eventually stops at approximately
crazy-insane right.
Direct subsidies and bailouts for the bankrupt frackers is going
to be one of the least popular policies *ever*. Also, Trump
doesn't owe those guys *anything*.
I would expect Trump to
funnel money to real estate developers, bluntly…
"... It would appear that perhaps a lot of infill drilling is taking place in Saudi Arabia, Kuwait and UAE in order to achieve these recent oil production values. It'll be interesting to see how this infill drilling might one day impact the decline side of the curve. ..."
It would appear that perhaps a lot of infill drilling is taking place
in Saudi Arabia, Kuwait and UAE in order to achieve these recent oil production
values. It'll be interesting to see how this infill drilling might one day
impact the decline side of the curve.
I'm no expert but from what I understand infill drilling causes what
might have been a roughly Hubbert shaped production curve to flatten
out at the top for a while and then in the future experience a steeper
decline curve; basically representing future production on the Hubbert
curve being brought forward to maintain a plateau at the peak. This
does seem to move the curve profile from Hubbert to Seneca, so to speak.
This image from Matt certainly represents a plateau at approx 72 million
barrels a day taking place in all jurisdictions outside of Canada and
USA.
I'm very interested in the timing and the steepness of this impending
decline. Figure 10 mentioned above shows the rig count in Kuwait, Saudi
and UAE really taking of 'bigly' in 2010-2011 'ish.
I am working (on and off) on something on world crude oil supplies that may end up as a post
on Fractionalflow.
I agree with Rystad Energy (ref Caelan's post further up. Disclosure, I have never had anything
to do with Rystad) that global oil extraction will decline towards the end of this decade.
I look at this through the lenses of discoveries (and their sizes) not FID, expected changes
to the oil companies' balance sheets at end 2016 (financial leverage will by default come up,
assets/equity come down due to lower oil price and lower reserves [of which some will be rebooked
at a higher price]), CAPEX constraints, their Reserves Replacement Ratios (RRR), likely near term
(oil) price and cost developments to name the most important ones.
The chart below [note scaling on the right axis] is now my conceptual understanding of global
crude oil supplies towards the end of 2018. We are soon entering November 2016 which makes me
now expect the period with decline to last longer.
I expect capacity of about 5 Mb/d of global crude oil capacities to vanish by end 2018. That
will have some implications. It took years with a high oil price ($100/b) to grow supplies with
5 Mb/d.
During the next upturn in the price things will be different, most of the "easy" oil was developed
during the last high price cycle.
I do not expect the decline to accurately follow my suggested span. Depletion induced declines
never sleeps and some portion of world crude oil supplies is now from sources (like LTO, "small"
offshore discoveries) that depletes fast and other legacy sources are also in general decline.
The decline is already baked into the cake. It does not matter if oil prices moved above $80/bo
as of next week. This would stimulate more drilling for tight oil, but for other developments,
it would take anywhere between 2-4 years from these are FIDed (Final Investment Decision) until
they flow.
The oil companies drew down their portfolios of discoveries being profitable at $80/bo during
the high oil price period that ended during the summer of 2014, and still there are some developments
in the pipeline that will start up during the next few years, but this portfolio is shrinking
fast. The tight oil companies have drilled most of their sweet spots and are now cash flow constrained
wrt drilling.
"... China and Mexico are in rapid decline at the moment but are supposed to have respectively, contingent 10 and 8 Gb and undiscovered 17 and 56 (!) – that has to be assuming a big shale resource for Mexico I'd guess. ..."
"... China has more rigs relative to its production than anywhere and this year is probably going to drill the most wells of any country. And yet they haven't found a new oil field for many years (quite a bit of gas though) and have only bought on a couple of small offshore fields recently. ..."
"... Norway and UK combined have developed a lot of their older contingent fields over the last few years, at very high cost and in some cases are now losing money on the investment. ..."
"... The biggest two confirmed finds are gas offshore Angola and Senegal (400+ and 800+ mmboe respectively), both probably need to be developed through LNG so might be years away given the current glut and normal schedules for such projects). ..."
"... In the North Sea reserves have been downgraded, not only because of price but also as some of the smaller finds no longer have options for tie backs because the possible hubs are coming to the end of their lives an new finds are in the 20 to 50 mmbbls range and heavy (also a number of dry wells there). I'd say it will likely be significantly worse than last year (which was the worst for 70 years) for both oil and gas discoveries. ..."
"... By coincidence, this morning: "BP dumps plans to drill for oil in the Great Australian Bight" ..."
"... I would imagine the reserve numbers by Rystad Energy are likely to be more FICTION than REALITY. I spent a few hours talking to Bedford Hill of the Hills Group on their "Thermodynamic Oil Collapse" model, and the more I find out about it, the more I am convinced the reserve numbers shown in the table above are completely out of touch with reality. ..."
"... According to the Hills Group Thermodynamic Oil Limit model, they took the total amount of energy in a barrel of oil and subtracted the waste heat. They then programmed into the software all the inputs from the oil industry. Bedford stated that according to the second law of Thermodynamics the amount of energy consumed in the production of oil continues to increase. Their model predicted the oil price collapse and forecasts that within a decade (+/- 4%) there will be no more net energy from a barrel of oil by the oil industry. ..."
"... There is this notion that SUPPLY & DEMAND or CREDIT & DEBT have distorted this thermodynamic oil limit. While these factors have changed the oil production graph, the Hills Group model suggests this has not changed the date. What has changed is that we have pulled future oil production forward which will make the Seneca Cliff much steeper. ..."
"... EROI is falling for new sources of oil but I don't know that it would count as "rapid" yet and it doesn't change much for already developed fields as they age – in fact if energy for the development stage is taken out then the EROI increases during operations. ..."
The numbers are even harder to understand looking at some of the other individual countries.
China and Mexico are in rapid decline at the moment but are supposed to have respectively,
contingent 10 and 8 Gb and undiscovered 17 and 56 (!) – that has to be assuming a big shale
resource for Mexico I'd guess.
China has more rigs relative to its production than anywhere
and this year is probably going to drill the most wells of any country. And yet they haven't
found a new oil field for many years (quite a bit of gas though) and have only bought on a
couple of small offshore fields recently. Mexico has decided they need help from outside IOCs
to find and develop all that resource.
Norway and UK combined have developed a lot of their older contingent fields over the last
few years, at very high cost and in some cases are now losing money on the investment.
Exploration
success is now very low, reserve are being downgraded and yet they are supposed to have 7 +
4 Gb contingent and 13 + 6 Gb undiscovered. The 13 Gb for Norway includes frontier territory
in the Barents Sea, but I think it's turning out that there is more gas there (TBC).
It will be interesting to see the final discovery number for this year from IHS, Richmond Energy
Partners, Rystad and Wood Mackenzie. I doubt if they will include the recent Alaska discovery
given that the test well wasn't flowed – the announcement looks to be more of a ploy to get
some tax break and/or outside money into the private company. The other supposed monster find
by Apache in Permian shale is 3 Gb equivalent oil in place, I'd expect it to be at the lower
end for shale recovery, say 3 to 5%, so that could be only around 75 to 125 mmbbbls oil.
In GoM Fort Sumter was 125 mmbbls (equivalent) but it cn only be developed through Appomatox
so might be many years away before there is processing capacity for it. Anadarko announced
Caisco, but with no numbers which is usually a bad sign. On the other hand Hopkins looks to
have been downgraded maybe 50%, so it is only a tie back option. Kaskida has gone quiet (HTHP
and high sand), Shenandoah/Coronado (very HTHP probably needing 20 ksi wellheads) looks like
it might be relatively smaller as a development than expected (or a series of smaller projects)
, Freeport MacMoran projects (such as Horn Mountain Deep) are all on hold while it tries to
sell up. Next year there is only Thunder Horse extension (27,000 bpd) and the year after Stampede
(75,000) and Big Foot (80,000) ramping up in late 2018 through 2019.
A couple of highly anticipated and expensive frontier wildcats have been dry (Total offshore
Uruguay and Shell offshore Nova Scotia – still drilling a second well there though). The Bight
Basin in Australia is delayed because of environmental concerns.
The biggest two confirmed finds are gas offshore Angola and Senegal (400+ and 800+ mmboe
respectively), both probably need to be developed through LNG so might be years away given
the current glut and normal schedules for such projects).
In the North Sea reserves have been downgraded, not only because of price but also as some
of the smaller finds no longer have options for tie backs because the possible hubs are coming
to the end of their lives an new finds are in the 20 to 50 mmbbls range and heavy (also a number
of dry wells there). I'd say it will likely be significantly worse than last year (which was
the worst for 70 years) for both oil and gas discoveries.
At some point soon there's surely going to be realisation, maybe starting with the investors,
that oil and gas industry BAU as it's been for the past 40 odd years is over and isn't going
to come back the same no matter what the oil price does. I don't know what comes in it's place
though.
Hi Matt, thanks for the interesting posts. I sent a comment to Art Berman to both his websites
(artberman.com and forbes.com) about the post dealing with the unaccounted oil storage and
I report it below (the comment is not yet visible there):
"Hi Art,
I agree with most of your article, but I would like to point out your attention to a possible
explanation which can account for part of the unaccounted oil storage.
In the last 4 years, I have developed a methodology to re-construct the "real" Texas oil
and gas production data using the data published by the Texas RRC: as it is well known, these
data are only preliminary and it may take up to 2 years to have the final estimates. My method
has proved to be reliable over time, providing estimates of Texas oil production very close
to the final data and much earlier than the latter are published. Moreover, these estimates
proved to be closer to the real data than the official EIA data for Texas: for example, on
the 31/08/2016, with more than a 1-year delay, the EIA revised its Texas data for 2014 and
2015 and aligned it to my corrected Texas RRC data.
Having said that, if we compare my corrected Texas RRC data with the EIA data, it is visible
that the EIA has started to increasingly underestimate Texas crudeoil production data since
July 2015, and the cumulative sum of this discrepancy is approximately 46 million barrels.
Of course, this does not explain all unaccounted oil storage, and I agree with you that
the real inventories are probably much lower than what is reported. However, one (minor) reason
is the underestimated EIA production data for Texas. Thanks"
I would imagine the reserve numbers by Rystad Energy are likely to be more FICTION than REALITY.
I spent a few hours talking to Bedford Hill of the Hills Group on their "Thermodynamic Oil
Collapse" model, and the more I find out about it, the more I am convinced the reserve numbers
shown in the table above are completely out of touch with reality.
The reason the Hills Group decided to design the software model to forecast the Thermodynamic
oil Limit was due to one of the members losing money when a shale oil company overstated reserves
by a wide margin. Thus, these engineers were tired of the crapola put out by either the EIA
or the companies themselves.
It took several years and about 10,000 hours to create this ETP Oil price model as well
as the Thermodynamic Oil Limit model. After they hit "ENTER", it took several hours before
the results came out. From what Bedford told me, the results were so shocking, that they decided
to sit on them for a few years before publishing.
From what I understand, a small team of oil engineers helped design the program. I asked
Bedford how many of the engineers DID NOT AGREE with the results. He replied by saying, "Not
one disagreed."
Furthermore, The Hills Group sent their report to dozens of professors in leading colleges
(mostly professors teaching Thermodynamics), and none of them disagreed with the results, even
though some had questions on the data or inputs used.
There is this notion that SUPPLY & DEMAND will continue to be the leading driver in controlling
the price of oil in the future. However, the rapidly falling EROI is destroying the remaining
net energy, thus leaving very little supply. Thus, Thermodynamics has been and will be the
leading economic driver of human economies, not supply and demand.
According to the Hills Group Thermodynamic Oil Limit model, they took the total amount of
energy in a barrel of oil and subtracted the waste heat. They then programmed into the software
all the inputs from the oil industry. Bedford stated that according to the second law of Thermodynamics the amount of energy consumed
in the production of oil continues to increase. Their model predicted the oil price collapse and forecasts that within a decade (+/- 4%)
there will be no more net energy from a barrel of oil by the oil industry.
There is this notion that SUPPLY & DEMAND or CREDIT & DEBT have distorted this thermodynamic
oil limit. While these factors have changed the oil production graph, the Hills Group model
suggests this has not changed the date. What has changed is that we have pulled future oil
production forward which will make the Seneca Cliff much steeper.
With Chevron, ConocoPhillips and ExxonMobil losing $18 billion in the first six months of
2016 after CAPEX and Dividends were paid reveals just how bad the situation has become in the
Major Oil Companies.
Furthermore, the U.S. Energy Sector interest on the debt consumed 86% of their operating
income in the first quarter of 2016. The situation is much worse than the market has realized.
Anyhow, I will be interviewing Bedford Hill and Louis Arnoux in a few weeks on their ETP
Oil Price Model and Thermodynamic Oil Collapse.
"According to the Hills Group Thermodynamic Oil Limit model, they took the total amount
of energy in a barrel of oil and subtracted the waste heat. They then programmed into the software
all the inputs from the oil industry."
And the explanation in English is? Burning oil will ultimately lead to some thermodynamic
losses.
Hint oil is about 30-33% the worlds total energy consumption.
"Their model predicted the oil price collapse and forecasts that within a decade (+/-
4%) there will be no more net energy from a barrel of oil by the oil industry."
Was the oil price collapse due to thermodynamic reasons?
If that is so [no net energy from a barrel of oil within a decade (2026)], then there should
already be several real world examples to support this with.
What portion of present global oil production (C+C) is consumed by the oil industry? Surely
the Hills Group must have the estimates for that as they have projected the development for
the next decade.
"With Chevron, ConocoPhillips and ExxonMobil losing $18 billion in the first six months
of 2016 after CAPEX and Dividends were paid reveals just how bad the situation has become in
the Major Oil Companies. "
Are you confusing losses/profits with cash flows? Using figures for only Q1 16 does not justify a trend and certainly not justify a conclusion
or projection.
Yes, I was referring to the companies Free Cash Flow minus Dividends. While one quarter
does not justify a trend, the Hills Group forecasts the price of oil to fall to $12 by 2020.
This is due to what a net barrel would be worth to the Global Industrialized World.
Rune, they have calculated the waste energy of a barrel of oil to be one-third. So, what
remains is net energy. However, the energy cost to produce this energy has continued to increase
since the world started producing oil.
The waste energy of a barrel of oil is missed by most economists or analysts when forecasting
price.
Rune, you are more than welcome to check out the Hills Group work at the site here:
http://thehillsgroup.org/
I am getting 40.7% for oil (in 2012?) and electricity is a secondary energy source, so I am
wondering if the 40.7% includes some oil for that.
Even so, how does that reflect the utility of oil, compared with the rest on that list? How
well can the projection of political/military power and control be run on them?
In any case, money/price, as a symbol, is a detachment from reality, along with too many
human detachments from reality to list, so whatever the price of oil is, once thermodynamic
reality and reality in general really start to kick in, the price of it, among a litany of
other human detachments, won't matter anymore. I guess that's when things will be considered
increasingly in the process of collapse or decline.
Steve, I am unsure about gold or silver by the way, since they are still mere symbols for
reality (that rely on some sort of 'trust' of some system that may be dubious). Maybe they
are more 'pegged' to it, but still symbols nonetheless, and so woefully-limited in their peg,
their 'visceral tangibility'.
Also, as gold and silver are hoardable, would those who have and hoard more of it, such
as governpimps and the elite, etc., be able to control it more, such as at the expense of those
who have less of it?
Electricity is NOT an energy source – it is an energy carrier like hydrogen.
BP SR 2016 has oil at about 33% of global energy consumption in 2015 which does not include
biofuels and biomass.
Electricity is considered a SECONDARY ENERGY SOURCE derived from whatever (nuclear power, wind,
etc.). Of course, strictly speaking, electricity is just an accumulation OR motion of electrons.
Therefore, a battery or a capacitor (accumulation of electrons) is a potential energy carrier.
I should have specified primary energy sources.
Lumping together primary and secondary sources confuses the issue.
Where in nature is there free electricity (apart from lightening)?
Follow the flow and all energy is solar.
:-)
To some degree costs acts as a proxy for EROI. The general trend is for costlier oil.
Low priced oil => Higher (composite) EROI (Unprofitable oil is shut down)
High priced oil => Lower (composite) EROI
This article by Ron is about stocks and flows.
Thermodynamics is about flows.
– If net energy from oil move towards zero during the next decade, this implies that
the oil companies would morph into giant heat engines and become bankrupt long before this
(net energy becomes zero) happens. Are there now any signs of this happening?
– If EROI declines at the rate referred and estimated by the Hills Group, net oil
(energy) would enter a steep decline and prices would move significantly and steadily up to
reflect this.
It could be useful to present estimates at what EROI (based on flow) a well or field becomes
shut in and later P&A ed.
'Cost', to me at least, is real and is different from 'price', which is symbolic, and 'Energy
Returned on Energy Invested' is different than 'Energy Return On Investment', but I suppose
it is treated the same to some.
Right now, from what has been read and understood at least, the 'money/finance/banking/BAU-cum-government-as-usual'
clusterfuck of 'establishments' are looking very strange/bizarre/weird/crazy/etc. to the clusterfuck
of many 'analysts/experts/pundits/etc.'. This seems indicative of an overlying symbolic/sociopolitical/socioeconomic
(denialistic/extend-and-pretend) 'formative' response to an underlying thermodynamic issue/problem
and maybe other problems as well, some as feedbacks/perturbations in/from the system.
Along with the ostensibly-increasing and increasingly perverted financial smoke-and-mirrors,
I wonder, in part, what the statistics are on company bankruptcies, takeovers and cannibalizations
these days, as well as investments in so-called alternative energies.
Where's this stuff going?
Steve apparently says 'gold and silver', yes?, but I don't buy it (pun intended too) from
a fundamental-problem-solving standpoint and neither should he.
Gold and silver seem just part of the same or similar scams, but just operate a little differently.
Steve, if you're reading this, I noticed, under one of your articles on Zero Hedge, you
arguing with some of the 'commentgentsia'…
Well, of coure, they know 'nothing', I know 'nothing', you know 'nothing' and Rune knows
'nothing'. Of course we know things, but we are all 'insignificant' cogs in this machined clusterfuck
with limited autonomy and spending too much of our industrially-derived/putrified food energy
and internet energy arguing about known unknowns and unknown knowns and what we and 'the others'
know, don't know, think they know and want everyone to know, even if it's not true– whatever
that means.
Alas, 'Leviathan', as Oldfarmermac has put it, will do what it has to to survive, come hell
or high water or the puny little humans that it squishes along the way– maybe in its death
throes. Why, there appear to be purveyors of Leviathan, or aspects thereof, right here on this
very blog.
I just wish that I was not on the same ship, as I really dislike being dragged along for the
ride.
This comment was brought to you this week by the word, clusterfuck .
"Where's this stuff going?"
That is something I observe a growing number of people wants to inform them about.
As we come to learn something we discover it is just a small piece of the BIG puzzle. We all
have blind spots and are delusional.
Sometime ago I watched some (BBC) documentaries about Keynes, Hayek and Marx and a very
interesting interview with Bank of England's former director Sir Mervyn King (this appears
to be a man of integrity and good moral compass).
There is one common message from all these;
"It is not possible to accurately predict human behavior."
Therein lies a very important bit of information.
I hear you, Rune.
(That BBC piece might be on You Tube.)
Alas, it is of course impossible to predict anything with 100% certainty. If we could, then
there would no consciousness, maybe no universe. And what fun would that be? 'u^
" … within a decade (+/- 4%) there will be no more net energy from a barrel of oil by the oil
industry."
EROI is falling for new sources of oil but I don't know that it would count as "rapid" yet
and it doesn't change much for already developed fields as they age – in fact if energy for
the development stage is taken out then the EROI increases during operations.
If no more wells were drilled starting today then world oil production would fall at around
5%. So in a decade there would be 60% of current supply. The EROI on that wouldn't have changed
much from today – there'd be proportionally a bit more water and gas to handle, but equally
it could all go to the most efficient refineries. Therefore for the overall net energy to be
zero would imply all new stuff bought on line is hugely negative. No such project would be
even considered at conceptual stage and it would stand out a mile. The closest anything gets
to that is Tar Sands where there is arbitrage from energy in natural gas converted to energy
in synthetic oil, but while energy in gas is cheap this still makes sense (or made sense rather
– as soon as the economics became bad, partly as a result of the net energy issues, the projects
were stopped). So if new projects are so bad don't do them – the world might be in a mess at
that point but the remaining oil would be a much sort after entity.
Also the shale reserve that initiated the study wasn't overstated because it's net energy
was incorrectly estimated, it was because someone in the E&P company lied, or rather let's
say 'dissimulated'.
The reason much of the damage of the rapidly falling EROI is not made its way into global
oil industry and the world financial-economic system is due to the massive amount of debt.
The Hills Group model calculates that the second law of Thermodynamics says that the amount
of energy to produce oil has continued to increase since we started producing the liquid over
150 years ago.
They have developed this model showing the average increase in energy cost in terms of a
barrel of oil. They remove the waste heat which is approximately one-third of the barrel. They
model shows that within a decade, the Thermodynamic limit for oil will be reached, thus no
net energy will be available.
Again, the massive amount of debt has distorted the global oil production curve, not the
ultimate date of the thermodynamic collapse. So, we experience a much higher on violent SENECA
CLIFF due to the massive amount of debt that has brought forward production.
Some are waking up to the Magnitude of the Challenge:
"At the same time, the engineer in me cannot be blinded by the physics of logistics underlying
the quintessential challenge posed by oil: how to replace the 560 exajoules of energy that is
required every year to keep the world turning.
That's 5.6 followed by 20 zeroes, whose magnitude was explored in my previous post hocus pocus.
80% of the world's energy requirements are supplied by hydrocarbon combustion."
IMFDirect - "futures markets point to slight gains in oil
prices. But a glance at shifts in futures-price curves in the
past few months suggests that the prospects for higher prices
have been worsening (see Chart 3)."
Ten years ago, oil
prices were $60 a barrel. These charts are pointing at $60 a
barrel. Which would translate into $2.50 per gallon for
gasoline. Of course that assumes the current level of
gasoline taxes.
A carbon tax is sounding more and more like a good idea.
Greg Mankiw insist this should be "revenue neutral". Some of
his would spend some of the extra revenue on public
investments in green technology and infrastructure
investment.
Reply
Friday, October 28, 2016 at 01:44 AM
likbez -> pgl...
, -1
IMF is always predicting lower oil prices :-). That the
nature of the beast.
I am not a specialist, but I do see the picture
differently.
Outside the Middle East, there is not much oil left in the
world that can be extracted profitably for $60 a barrel. IMHO
spikes to $100 are now quite possible. Sustained oil price
over $100 per barrel means recession and reversal of
neoliberal globalization with its crazy and often useless
transport flows from one continent to another (salmon caught
in Europe processed in China, apples flown to NJ, etc).
The current period of low prices masks rapid depletion of
major oil reserves in non OPEC countries and decimation of
shale oil industry in the USA.
Capital investment is now slashed to the bone. And that
might have an outsize effect on oil production in non-OPEC
countries in 2018 - 2020 (such predictions always skip the
next year in a hope that people will forget about them, if
they do not materialize :-)
That means that while the crisis of supply is not
immediate it is looming on the horizon. And might well be
within less then a decade to reach.
Obama administration policy in this area was classic
"after me, the deluge". Low oil prices partially reversed the
replacement process for private transportation and made SUVs
the most popular class of personal cars in the USA. In other
words they reversed the trend to more economical cars in the
USA. So the USA might enter the crisis in worse shape then it
would be, if the energy saving policies were the focus of the
current administration. Obama focused on wars of neoliberal
expansion.
The USA pretty shrewdly used Saudis and Iran as two Trojan
horses able to keep prices low since late 2014. Saudi Arabia
is now issuing bonds left and right as they can't balance the
budget at prices below $100 or so. Iran in general behaves
pretty crazy in this respect as if it has unlimited reserves
and does not need to save them for future generations. They
are fighting for return of their pre-sanctions market share
in $40-$50 environment, as if this is the life and death
question for them. But if they managed to survive sanctions
for so long, why the rush ?
In any case my point is simple: if something can't run
forever it will eventually stop. That include both Saudis and
Iran. They have large reserves, but they are not unlimited
and the most profitable fields with high quality oil already
substantially depleted. Low quality high sulfur oil still is
more plentiful.
The problem is that high oil prices mean trouble for
Western economies. That's why Western MSM reacted so paranoid
on OPEC+Russia decision to freeze production starting Nov. 1.
Also it is not clear how the US oil stocks were/are kept
on such a high level (depressing oil prices): manipulation of
stats by EIA, hidden sale from the strategic reserve,
unaccounted by state oil production (black market oil ;-)
Art Bergman has an interesting article on the subject
"U.S. shale oil production is expected to fall for a tenth consecutive month
in September, according to a U.S. government forecast released on Monday, as
low oil prices continue to weigh on production.
"Total output is expected to drop 85,000 bpd to 4.47 million bpd, according
to the U.S. Energy Information Administration's drilling productivity report.
That is the lowest output number since April 2014.
"The EIA's previous forecast calling for an output decline in August of 99,000
bpd was revised up to nearly 112,000 bpd, data shows.
"Bakken production from North Dakota is expected to fall 26,000 bpd, while
production from the Eagle Ford formation is expected to drop 53,000 bpd. Production
from the Permian Basin in West Texas is expected to rise 3,000 bpd, according
to the data."
Ron's graphs summarised this better but I don't have the previous history
to show it. Has anybody here explained why Eagle Ford drops are so much more
than Bakken?
The DPR tends to overestimate the decline in the Eagle Ford.
Enno Peters uses Texas RRC data to estimate Eagle Ford output and that also
underestimates output for the same reason that Texas data in general is too
low because it is incomplete.
I have estimated Eagle Ford output by finding the percentage of total Texas
C+C output from the Eagle Ford for each of the most recent 24 reported months
and than multiplied this percentage by Dean Fantazzini's estimate of Texas C+C
output (which is better than any other estimate in my opinion).
The Chart below compares this method using Dean's estimate (DC estimate)
and the EIA estimate for Texas C+C output, to find Eagle Ford output through
June 2016.
The reason Eagle Ford output has decreased more rapidly is because the wells
decline more rapidly and because the ramp up in the Eagle Ford was more rapid
than in the Bakken/Three Forks so that a lot more wells are declining at once.
It shows the number of new wells completed in the Eagle Ford (he calls these
wells "first flow" as in the month that the well started producing oil). Compare
this chart to the Bakken chart in the post.
I don't know if they might have reached saturation in the sweet spots in
the Eagle Ford, they seem to have an advantage in Texas with infrastructure
and pipeline capacity, but a lot of that has now been established in North Dakota
so going forward the main advantage for Texas is lower transportation costs
to refineries.
> Has anybody here explained why Eagle Ford drops are so much more than Bakken?
Although the number of new wells producing dropped very similarly (relatively)
in these two basins, Eagle Ford wells decline faster after initial production.
You can see this most clearly by:
1. Going to my latest US presentation
here .
2. Go to the "Well quality" tab.
3. Group wells by "Basin".
=> You can see the profiles of the average well in each of the basins, and
that Bakken wells in general have a longer production life. Note that there
is some distortion as especially the early 2007-2008 Bakken wells (Sanish &
Parshall) were exceptionally good.
You can play with the "first flow" filter to see this for wells starting
in different years.
Thanks. Using your link above I created the following chart from your website.
I compare only wells with first flow from 2012 to 2016 because the Eagle
Ford play did not really start being developed as an oil basin until late 2010
and they probably hadn't really figured out optimal well spacing and frack setup
until 2012.
This demonstrates the steeper decline for the Eagle Ford that you refer to.
No, the "other" represents other horizontal wells that were drilled in Texas
in the last couple of years, outside the Eagle Ford & Permian area, e.g. in
the Barnett, Granite Wash, etc.
These charts from the EIA confirm your conclusions.
They show that, while IP rates in the Bakken and the Eagle Ford are similar,
EFS production rates are declining much faster.
Would be interesting to know if this is due to more rapidly falling reservoir
pressures, different completion techniques, or something else.
New-well oil production per rig is higher in the Eagle Ford.
Apparently, this is because EFS is shallower and it takes less time to drill
a well than in the Bakken.
As a result, more wells can be drilled by 1 rig in the same period of time.
To put Enno's "relatively" into perspective: Peak output of Eagle Ford used
to be bigger than peak output of Bakken. The more you have, the more you can
lose.
The number of drilled but uncompleted wells is bigger in the Eagle Ford.
According to Rystad Energy, it was 1000 as of May 2016 in EFS vs. 850 in the
Bakken.
The intentionally postponed (abnormal) part of the DUC inventory has been growing
much faster in the Eagle Ford than in the Bakken since mid-2015.
That could also explain steeper declines in EFS oil production vs. the Bakken.
Bloomberg shows a different trend in DUCs inventory: a decline in the Eagle
Ford vs. continued growth in the Bakken. That would suggest more resilient production
volumes in EFS.
But I think that Rystad's estimate is more reliable.
"... The Norwegian Petroleum Directorate reported that Norway's oil production in July reached its highest level in 5 years because many fields were "producing above prognosis ..."
"... Oil output of 1.728 million b/d was 10% above July 2015 and about 18% above this past June, which had 1.449 million b/d. [June production was low due to maintenance ..."
"The Norwegian Petroleum Directorate reported that Norway's oil production in July reached its
highest level in 5 years because many fields were "producing above prognosis."
Oil output of 1.728 million b/d was 10% above July 2015 and about 18% above this past June, which
had 1.449 million b/d. [June production was low due to maintenance – AlexS].
The July liquids total averaged 2.136 million b/d after combining the oil number with 375,000
b/d of natural gas liquids and 33,000 b/d of condensate."
"... Interesting that now we have multi billion dollar companies doing the same. Just listening to Harold Hamm talk, he seems little concerned about the price of oil and gas. He seems most concerned about regulation of the industry. The catch phrase now is every well not drilled in the US is funding terrorism. Hamm claims we can be completely oil independent. Interesting he doesn't mention what oil price he thinks is needed to accomplish that goal. ..."
SS says, "We have guys in the industry who make their money, not off the oil, but off the promotion
of new wells. It has been that way for decades." it has been that way since the very start of our industry :-)
Interesting that now we have multi billion dollar companies doing the same. Just listening to Harold Hamm talk, he seems little concerned about the price of oil and gas.
He seems most concerned about regulation of the industry. The catch phrase now is every well not drilled in the US is funding terrorism. Hamm claims we can be completely oil independent. Interesting he doesn't mention what oil price
he thinks is needed to accomplish that goal.
EOG lost 4.5 billion dollars in 2015 and 747 million thus far in 2016. CLR and MRO are also
net losers in 2016. In fact, of the 17 public shale oil companies I've looked post 2Q 2016, total
losses are over 7.5 billion dollars. NONE of them made money in 2015 and none have thus far made
money in 2016.
I have run a 12M pound frac described above using pre-pads, spacers and increasing sand concentrations
per incremental stage commonly used in shale wells thru my computer programs and indeed a frac
like that would require every bit of 600,000 bbls of fresh, potable water suitable for human consumption.
That's 25 million gallons, not 1.6 gallons (my bad), enough water for 335,000 people to consume…one
well. Fresh water is a big deal, particularly in the arid West, and for all the bullshit about
use of wastewater, or brackish water in the Permian, for instance, very little of that has actually
been done yet. The shale industry, after all, is not well known for telling the truth.
For those "open minded oil men with actual experience in the oilfield, capable of critical
thinking skills," its possible, it seems, to ignore lack of profitability, debt and the complete
failure of the shale oil business model. That's all fine and dandy; you can't be helped much by
way of thinking. But forsaking fresh water to cram more sand in a stinking shale well that is
STILL not going to pay out at any oil price less than 80 dollars a barrel… is pretty stupid. Oil
prices remain low, primarily because of an oversupply of light, tight condensate we cannot get
rid of (imports are up, not down) and drilling any shale oil well right now makes no sense whatsoever.
Its keeping prices low and people out of work. It may be entertaining to surf the internet for
techno-dribble about the shale industry but the US LTO industry is now foolishly drilling wells
that are unnecessary and unprofitable. That is NOT good for America's energy future.
I don't think you "hate to be dismissive of anyone views," you do it all the time and in a
rude, condescending manner, Tea. The only way you can make a point appears to be at others expense.
We're all close minded, or incapable of intellectual process, it seems, if we don't agree with
you.
How about changing that handle to Kansas Tea? As a Texan, I am offended.
Till the LTO companies release payout statements, I call bull sh#%.
If I was getting wells to payout at current prices, I'd be advertising it to the world, were
I a public company.
But no one is, so therefore I assume they are all losing their a$@es.
XTO has lost a fortune in the shale basins since Q1 2015. So has Statoil. I'd think given the
brain power these companies have, if anyone could figure a way not to lose money at LTO, they
could. But they haven't. Why? LTO is high cost.
Schlumberger's CEO says little new tech has been unleashed, that most of the cost savings is
the result of service companies slashing costs to the bone. He says that cannot continue, is not
sustainable.
Hang in there Mike. When I hear the LTO guys say it is possible that US can be oil independent,
if only the gubment would stay out of the way, I know they are full of it.
What price would we need to get US oil production to 17 million barrels per day?
"... As worldwide net exports capacity barely changed over the last ten years, the fall of net imports from 2008 to 2015 created a gap of surplus export capacity of 4 mill b/d in 2015. Even higher Chinese and Indian net oil imports could not compensate for the fall in worldwide net imports. Should US producers really increase production (and reduce US net imports further) over the coming years, this gap will not vanish and oil prices will be low. If US oil producers go as far as oil independence over the next ten years, it will take ten years until the oil price can go up again as this will bring out another 6 mill b/d of net imports which gives a total gap of 10 mill b/d. This gap can only be filled by China and India (together roughly 1 mill/d per year) over the next ten years. ..."
"... It would make much more sense for US producers to cut production another 2 mill b/d, which will bring up the oil price with the help of higher Chinese and Indian net imports over the next two years ( net imports would then surpass net exports of 40 mill b/d again), and then reduce net imports at a slower rate than Chinese and Indian growth. This could be done at much higher oil prices and much less pain for shareholders and investors. ..."
"... With hindsight this is what US oil producers should have done over the last five years. It was just unnecessary greed, which has led to the current disaster. It is unrealistic to expect low cost oil producers to cut net export capacity. As long this capacity is there, it will be used. It is however another question how much oil net exporter can increase their capacity. This is in my view another unlikely scenario. ..."
"... That shows nothing, of course. The price of oil in Argentina is now over $67/barrel. ..."
"... Oil price won't be low for long – deep see oil will see no investments if prices keep low for longer, 3rd world states with low production costs but high deficit will go into political unrest – and won't invest in infill drilling, gas injection to keep up performance, but in weapons and bribing important people. ..."
"... No one except the US shale producers can keep producing red ink permanently – so if there will be cheap oil, it will be much less than now. It's like filling a car in the socialistic countries in the 80s – you will pay only cheap money, but will have to wait to get some gas. ..."
As oil moved down during the last few days, the question arises about where oil prices are
heading for the next few years. Wall Street and friends have advertised for the x-th time that
oil prices will be at 70 by year end , by the summer, by fall …
…some people are not so sure about higher oil prices in the future.
My personal view is that it is in the hands of Wall Street and US oil producers, where oil
prices are heading. Below chart shows that US oil producers triggered themselves the fall in oil
prices by rapidly reducing US net imports since 2008. From 1991 wordlwide increasing net imports
– up a staggering 15 mill b/d – drove the oil price to record highs when net imports went over
available net exports of 40 mill b/d.
As worldwide net exports capacity barely changed over the last ten years, the fall of net
imports from 2008 to 2015 created a gap of surplus export capacity of 4 mill b/d in 2015. Even
higher Chinese and Indian net oil imports could not compensate for the fall in worldwide net imports.
Should US producers really increase production (and reduce US net imports further) over the coming
years, this gap will not vanish and oil prices will be low. If US oil producers go as far as oil
independence over the next ten years, it will take ten years until the oil price can go up again
as this will bring out another 6 mill b/d of net imports which gives a total gap of 10 mill b/d.
This gap can only be filled by China and India (together roughly 1 mill/d per year) over the next
ten years.
It would make much more sense for US producers to cut production another 2 mill b/d, which
will bring up the oil price with the help of higher Chinese and Indian net imports over the next
two years ( net imports would then surpass net exports of 40 mill b/d again), and then reduce
net imports at a slower rate than Chinese and Indian growth. This could be done at much higher
oil prices and much less pain for shareholders and investors.
With hindsight this is what US oil producers should have done over the last five years.
It was just unnecessary greed, which has led to the current disaster. It is unrealistic to expect
low cost oil producers to cut net export capacity. As long this capacity is there, it will be
used. It is however another question how much oil net exporter can increase their capacity. This
is in my view another unlikely scenario.
Oil price won't be low for long – deep see oil will see no investments if prices keep low
for longer, 3rd world states with low production costs but high deficit will go into political
unrest – and won't invest in infill drilling, gas injection to keep up performance, but in weapons
and bribing important people.
North sea oil will die, it's already in decline and if a few producers stop the common infrastructure
will be too expensive for the rest to maintain.
No one except the US shale producers can keep producing red ink permanently – so if there
will be cheap oil, it will be much less than now. It's like filling a car in the socialistic countries
in the 80s – you will pay only cheap money, but will have to wait to get some gas.
"... As worldwide net exports capacity barely changed over the last ten years, the fall of net imports from 2008 to 2015 created a gap of surplus export capacity of 4 mill b/d in 2015. Even higher Chinese and Indian net oil imports could not compensate for the fall in worldwide net imports. Should US producers really increase production (and reduce US net imports further) over the coming years, this gap will not vanish and oil prices will be low. If US oil producers go as far as oil independence over the next ten years, it will take ten years until the oil price can go up again as this will bring out another 6 mill b/d of net imports which gives a total gap of 10 mill b/d. This gap can only be filled by China and India (together roughly 1 mill/d per year) over the next ten years. ..."
"... It would make much more sense for US producers to cut production another 2 mill b/d, which will bring up the oil price with the help of higher Chinese and Indian net imports over the next two years ( net imports would then surpass net exports of 40 mill b/d again), and then reduce net imports at a slower rate than Chinese and Indian growth. This could be done at much higher oil prices and much less pain for shareholders and investors. ..."
"... With hindsight this is what US oil producers should have done over the last five years. It was just unnecessary greed, which has led to the current disaster. It is unrealistic to expect low cost oil producers to cut net export capacity. As long this capacity is there, it will be used. It is however another question how much oil net exporter can increase their capacity. This is in my view another unlikely scenario. ..."
"... That shows nothing, of course. The price of oil in Argentina is now over $67/barrel. ..."
As oil moved down during the last few days, the question arises about where oil prices are
heading for the next few years. Wall Street and friends have advertised for the x-th time that
oil prices will be at 70 by year end , by the summer, by fall …
…some people are not so sure about higher oil prices in the future.
My personal view is that it is in the hands of Wall Street and US oil producers, where oil
prices are heading. Below chart shows that US oil producers triggered themselves the fall in oil
prices by rapidly reducing US net imports since 2008. From 1991 wordlwide increasing net imports
– up a staggering 15 mill b/d – drove the oil price to record highs when net imports went over
available net exports of 40 mill b/d.
As worldwide net exports capacity barely changed over the last ten years, the fall of net imports
from 2008 to 2015 created a gap of surplus export capacity of 4 mill b/d in 2015. Even higher
Chinese and Indian net oil imports could not compensate for the fall in worldwide net imports.
Should US producers really increase production (and reduce US net imports further) over the coming
years, this gap will not vanish and oil prices will be low. If US oil producers go as far as oil
independence over the next ten years, it will take ten years until the oil price can go up again
as this will bring out another 6 mill b/d of net imports which gives a total gap of 10 mill b/d.
This gap can only be filled by China and India (together roughly 1 mill/d per year) over the next
ten years.
It would make much more sense for US producers to cut production another 2 mill b/d, which
will bring up the oil price with the help of higher Chinese and Indian net imports over the next
two years ( net imports would then surpass net exports of 40 mill b/d again), and then reduce
net imports at a slower rate than Chinese and Indian growth. This could be done at much higher
oil prices and much less pain for shareholders and investors.
With hindsight this is what US oil producers should have done over the last five years. It
was just unnecessary greed, which has led to the current disaster. It is unrealistic to expect
low cost oil producers to cut net export capacity. As long this capacity is there, it will be
used. It is however another question how much oil net exporter can increase their capacity. This
is in my view another unlikely scenario.
That shows nothing, of course. The price of oil in Argentina is now over $67/barrel.
http://oilprice.com/Energy/Crude-Oil/Would-Regulated-Oil-Prices-Argentine-Style-Help-US-Shale.html
Eulenspiegel ,
08/10/2016 at 10:51 am
Oil price won't be low for long – deep see oil will see no investments if prices keep low for
longer, 3rd world states with low production costs but high deficit will go into political
unrest – and won't invest in infill drilling, gas injection to keep up performance, but in
weapons and bribing important people.
North sea oil will die, it's already in decline and if a few producers stop the common infrastructure
will be too expensive for the rest to maintain.
No one except the US shale producers can keep producing red ink permanently – so if there
will be cheap oil, it will be much less than now.
It's like filling a car in the socialistic countries in the 80s – you will pay only cheap
money, but will have to wait to get some gas.
"... I think you need 12 months minimum to get an idea of what wells will produce long term. That is where I am getting criticized by the believers, they say I am ignoring recent well improvements. ..."
"... The bottom line is the companies have found US land based oil. They know it is there, and as long as they are given the money to drill for it, they will, regardless of ultimate profitability. The CEO's are more in the position of promoter than business owner. Promoters talk about IP and exaggerated ultimate recoveries. It is interesting how much similarity there is between company presentations and the promotion materials I have read seeking to sell 1/16 non-operated WI to doctors and other unsophisticated investors. ..."
Toolpush. I recall reading in PXD's presentation that they are choking back new wells
The reason for this is they do not want to overbuild facilities.
Acreage in the Permian many times comprises of thousands of acres in one lease, so many wells'
production can be ran into the same facility.
So, say a total of 50 wells were going into one facility. They have to plan this out, because
the 50 wells at their peak production might produce a combined 50,000 barrels of oil and 150,000
barrels of water per day plus 100,000 mcf of gas per day.
However, in three years, those wells will be producing in the neighboorhood of 2,500 barrels
of oil and 5,000 barrels of water per day, plus maybe another 1,000 mcf of gas.
My numbers are hypothetical, but imagine how much less equipment will be required after 3 years
in that scenario.
There has been a lot of discussion about facility over build in the Bakken and Permian, where
large facilities are, 5 years later, handling a fraction of the production.
I think you need 12 months minimum to get an idea of what wells will produce long term.
That is where I am getting criticized by the believers, they say I am ignoring recent well improvements.
The bottom line is the companies have found US land based oil. They know it is there, and
as long as they are given the money to drill for it, they will, regardless of ultimate profitability.
The CEO's are more in the position of promoter than business owner. Promoters talk about IP and
exaggerated ultimate recoveries. It is interesting how much similarity there is between company
presentations and the promotion materials I have read seeking to sell 1/16 non-operated WI to
doctors and other unsophisticated investors.
We have guys in the industry who make their money, not off the oil, but off the promotion of
new wells. It has been that way for decades.
I assume few CEO's have taken a pay cut during this downturn. If they suspend drilling, they
have nothing to promote at investor forums and quarterly conference calls. So they will drill.
Heck, Halcon is still running rigs even though they are bankrupt.
It is going to take action by Russia and OPEC to drive prices higher in the next few years,
at it appears there are still a lot of locations left to drill in the US shale basins.
In fact, several of the leases we own were originally promotion projects. That was extremely
hot in our area in the early 1980s. Then, the price crashed and about all of the dumb money gave
their interests back to the operator, as the operator billed hard for overhead, and they were
paying $15+ per barrel in expense while selling oil for $10 in 1986.
Interesting that now we have multi billion dollar companies doing the same.
Just listening to Harold Hamm talk, he seems little concerned about the price of oil and gas.
He seems most concerned about regulation of the industry.
The catch phrase now is every well not drilled in the US is funding terrorism.
Hamm claims we can be completely oil independent. Interesting he doesn't mention what oil price
he thinks is needed to accomplish that goal.
You know why Aubrey started paying $10,000/acre in the Haynesville? After spending 2+ years putting
together his acreage block at an average of $500-1000/acre?
So he could flip 20% to Plains at $15,000/acre and a huge carry on the front end. That deal
paid for all his bonuses paid to that point and he pocketed a nice chunk of change.
Aubrey was a world class promoter. Here is a link to the Reuters article
It is funny looking back at what they have for estimated reserves. Significantly more than what
has played out.
"... Output was 79,784 kb/d in April 2016, I believe the decline rate will decrease by Oct and output will be around 78.5 +/- 0.5 Mb/d in Nov 2016, decline will continue into 2017 and the rate of decline may reach zero some time in 2017. ..."
World C+C using EIA data, but substituting the Russian Ministry of Energy Data for Russia
shown in the chart below. The monthly peak was 81, 047 kb/d in Nov 2015. The centered 12 month running
average is also shown with a peak at 80,642 kb/d in Sept 2015. The annual decline rate since the
Nov 2015 peak has been 4.2% per year or about 3.4 Mb/d over a 12 month period if the rate does not
change before Nov 2016. That would imply 77.6 Mb/d by Nov 2016.
Output was 79,784 kb/d in April 2016, I believe the decline rate will decrease by Oct and output
will be around 78.5 +/- 0.5 Mb/d in Nov 2016, decline will continue into 2017 and the rate of decline
may reach zero some time in 2017.
Toolpush. I recall reading in PXD's presentation that they are choking back new wells
The reason
for this is they do not want to overbuild facilities.
Acreage in the Permian many times comprises of thousands of acres in one lease, so many wells'
production can be ran into the same facility.
So, say a total of 50 wells were
going into one facility. They have to plan this out, because the 50 wells at their peak production
might produce a combined 50,000 barrels of oil and 150,000 barrels of water per day plus 100,000
mcf of gas per day.
However, in three years, those wells will be producing in the neighboorhood of 2,500 barrels of
oil and 5,000 barrels of water per day, plus maybe another 1,000 mcf of gas.
My numbers are hypothetical, but imagine how much less equipment will be required after 3 years
in that scenario.
There has been a lot of discussion about facility over build in the Bakken and Permian, where
large facilities are, 5 years later, handling a
fraction of the production.
I think you need 12 months minimum to get an idea of what wells will produce long term. That is
where I am getting criticized by the believers, they say I am ignoring recent well improvements.
The bottom line is the companies have found US land based oil. They know it is there, and as long
as they are given the money to drill for it, they will, regardless of ultimate profitability. The
CEO's are more in the position of promoter than business owner. Promoters talk about IP and exaggerated
ultimate recoveries. It is interesting how much similarity there is between company presentations
and the promotion materials I have read seeking to sell 1/16 non-operated WI to doctors and other
unsophisticated investors.
We have guys in the industry who make their money, not off the oil, but off the promotion of new
wells. It has been that way for decades.
I assume few CEO's have taken a pay cut during this downturn. If they suspend drilling, they have
nothing to promote at investor forums and quarterly conference calls. So they will drill. Heck, Halcon
is still running rigs even though they are bankrupt.
It is going to take action by Russia and OPEC to drive prices higher in the next few years, at
it appears there are still a lot of locations left to drill in the US shale basins.
In fact, several of the leases we own were originally promotion projects. That was extremely hot
in our area in the early 1980s. Then, the price crashed and about all of the dumb money gave their
interests back to the operator, as the operator billed hard for overhead, and they were paying $15+
per barrel in expense while selling oil for $10 in 1986.
"... The type curves these guys are coming up with are way off. Exaggerated by more than double. ..."
"... Seems SEC should be involved, but who wants to stop the flow of cheap oil, which today translates to $1.77 per gallon at the pump just down the street from me? ..."
"... "As Bloomberg reports, despite what Hall called a "miserable month" for oil in July, supplies are still shrinking, he said in his letter, setting up prices to reverse themselves. "Prices are now back at levels that would ensure the eventual bankruptcy of most of the oil industry", hammering both private oil companies and producing countries like Iraq, Nigeria and Venezuela, Hall said. "Prices at current levels are just not sustainable."" ..."
Watcher. 200 bopd in months 13+. The best wells produce 125-200K barrels in first 12 And that
is gross oil, before deducting the part which goes to the royalty owners, which is 25% typically
in the Permian. But, they never disclose that either. So the type curves, are gross oil, which
is also deceiving.
It is very hard to find payout statements for LTO wells. But I have seen some.
What is see is a lot of oil in year one, with the well being about 1/2 paid out, followed by
not nearly enough in years 2 and 3 to make a big enough dent. By year 4, the well is generating
low to mid five figures per month, with $2-4 million still owed, depending on how good the well
is.
Until I hear the companies' management talk about well payout in real (not projected) numbers,
I assume that most wells are like the one's I have seen. In fact, I just looked at four of PXD's
on the Sale Ranch, which is their best Martin Co. lease by far. One of the wells, the best out
of 53, will payout. One will not, the other two will need production to hold up at around 200
bopd IMO. Very few wells have been producing 200 bopd after month 12. But maybe they have figured
something out?
It is also interesting on the few payout statements I have seen, that CAPEX seems to continue
on for months after the well's first production month. Only when the well is down to low volume,
do we see the CAPEX stop. Not sure why that is.
So, if we have a well producing 50 bopd gross oil, with a 25% royalty, the monthly gross income
at $40 oil (we are now below that BTW) is $45,000. Figure $10,000 of LOE, we are at $35,000. Knock
of taxes, down to about $31,000.
Will take a long time to pay the remaining $2-$4 million left at $30,000 per month. Then, if
we have a down hole failure, look at another $25-100K of expense.
The type curves these guys are coming up with are way off. Exaggerated by more than double.
Seems SEC should be involved, but who wants to stop the flow of cheap oil, which today translates
to $1.77 per gallon at the pump just down the street from me?
There has been a lot of well economics analysis over the past X yrs. Usually they end with presumptions
of higher oil price just in time to save the day.
What they don't usually have is an assessment of not only high yield paper burden (annual interest
expense on the loan PLUS principal repayment per year), nor anything about compliance with loan
covenants which . . . pre Fed involvement one could presume would force some sort of ongoing production
requirements lest there be LOCs (Lines of Credit) shut off, preventing more completions.
Really hard to see how the loans still flow, unless the lenders have been assured backstop.
On most sites. SEeking alpha, oilpro, etc, the shale believers all share one common thread. Lack
of any concern with making a profit.
They discuss reserves, IP rates, decline rates, rig efficiencies, but never discuss how these
companies are all losing money every day they operate and with every well they drill.
it seems that some industry observers agree with my post above:
"As Bloomberg reports, despite what Hall called a "miserable month" for oil in July, supplies
are still shrinking, he said in his letter, setting up prices to reverse themselves. "Prices are
now back at levels that would ensure the eventual bankruptcy of most of the oil industry", hammering
both private oil companies and producing countries like Iraq, Nigeria and Venezuela, Hall said.
"Prices at current levels are just not sustainable.""
I am just going by what I am reading on a subscription site that I pay for. Maybe it is wrong?
Every one of the leases I own an interest in is always correct. The data always matches ND,
which has good data. It matches TX when TX reports individual wells. It matches WY, CO, KS, NM.
I guess when CLR states their average well will cumulative 806,000 BO, I would think I would
see some evidence of that showing up, instead of what I posted above.
I think you also have to understand why those of us who own working interests question you.
We have seen our income fall from a lot to practically nothing, I talk to many producers, all
the same. Worst time since 1998-1999. Some think worst they have ever been through.
I look at Energynet auction quite often. There are a lot of WI for sale. The collapse of income
since 2014, not just from the price crash, but from LTO well decline, takes your breath away.
Saw an EFS package on there this week. 3/15 income was $1.1 million from 9 wells. 12/15 income
was $240K from same 9 wells. I figure they have $45 million plus sunk into those.
I'm just repeating $$ and cents and production info I see.
For example, all we hear about PXD is Permian. Yet they operate more EFS wells than Permian,
70 of which have cumulative oil of 300K, v 1 Permian well with cumulative of 300K. Yet, somehow
Permian is more economic, even though EFS wells generally cost less than Permian to D & C.
Just stating facts I pull off the net. If you think I'm wrong, let me know. I don't want to
be putting out wrong info.
"Worldwide, average oil production costs have fallen by $19 a barrel to $51 a barrel. At least
for now, the oil industry has squeezed its production costs down to 2009 levels, and drillers
could make a profit extracting 9 million barrels a day over the next decade, a 20 percent increase
from the days of $100 oil.
In West Texas, oil companies could make money in the Bone Spring and Wolfcamp tight oil plays
with $37 a barrel oil, while their rivals in the Eagle Ford Shale in South Texas could turn a
profit at $48 a barrel. The average break-even price in North Dakota's Bakken Shale is $58 a barrel.
In Oklahoma's Scoop region, it's $35 a barrel, Wood Mackenzie estimates."
I think I have mentioned here before, OKLA is happening, and "appears" to be the lost cost
LTO play in US. Now that does not mean I know a damn thing about the oil business but it does
mean you boys should keep a eye out in the future for considerable production coming out of this
area as "development" gets underway.
"... it seem that the IP's out of the Bakken in the Daily reports are trending towards the "less spectacular"? Lots of sub 1,000, and more than a few sub 500 BO IP. ..."
"... I always thought that EOG was the "darling" of the group. But, they having the lowest % of remaining – 36% (64% produced). In that regard, with respect to the production remaining, can you advise "about" how many years of production is represented for an average producer that you note? ..."
This comment is without me doing any analysis, but does it seem that the IP's out of the Bakken
in the Daily reports are trending towards the "less spectacular"? Lots of sub 1,000, and more
than a few sub 500 BO IP.
I created a presentation where I show where
oil production from existing shale US wells is heading in the coming years. It only includes
the actual & projected production of horizontal wells that started production before 2016.
Enno – Excellent information! I always thought that EOG was the "darling" of the group. But, they
having the lowest % of remaining – 36% (64% produced). In that regard, with respect to the production
remaining, can you advise "about" how many years of production is represented for an average producer
that you note?
I don't get your question exactly, can you rephrase? The remaining production is all the production
that is still expected from the legacy wells, in the coming 20 years, although most of it will
of course be produced early on.
"... There seems to be a general assumption that the larger conventional producers can choose to significantly ramp up production when they like, but I doubt that is true. Saudi have just bought on line the Shaybah extension which was a pretty big job to extend production facilities for 'just' 250,000 bpd. ..."
"... Usually in mature fields the wells become limiting. For example as water cut increases not only does the water displace the oil but also, as it is significantly heavier than the oil/gas mix in the wellbore, the overall flow rate declines rapidly. ..."
There seems to be a general assumption that the larger conventional producers can choose to
significantly ramp up production when they like, but I doubt that is true. Saudi have just bought
on line the Shaybah extension which was a pretty big job to extend production facilities for 'just'
250,000 bpd.
Production from a given field may be limited by different parts of the facilities at different
times. Typically the limit will be the lowest nameplate capacity between each of: the reservoir
/ wells; oil processing; produced water handling; associated gas compression; total liquids flow;
water (or gas) injection capacity. Overall power availability may also be limiting at some combination
of oil/water/gas flow below each one of their individual limits.
Usually in mature fields the wells become limiting. For example as water cut increases
not only does the water displace the oil but also, as it is significantly heavier than the oil/gas
mix in the wellbore, the overall flow rate declines rapidly. However this need not always
be the case. In Saudi I think they design and manage their facilities to keep the production at
the oil flow design capacity, which is nominally set to give 2% depletion of the original estimated
ultimate reserves per year. To maintain this they maintain excess capacity in the other key facilities.
In particular they need to control the water cut by using intelligent wells, expandable liners,
and recompletions, or when needed drill new wells higher in the formation. If they lose control
of the water cut, which must happen one day (ideally for them it would be the day they flow the
last barrel of oil and shut in but that is not going to happen) then the likely limit will be
water injection capacity. Water has to be pumped in to maintain pressure to exactly balance the
volume pumped out. For the produced water in the oil that is about one for one, for a stock tank
barrel of oil it is higher because the oil shrinks as it cools, but mainly because of the gas
that is lost. This is ratio is called the formation volume factor and typically is 1.1 to 1.8.
Say for a field the water cut is 50% and the FVF is 1.5, this means 2.5 bbls of injection water
are needed to give one bbl of oil. I don't know the Saudi figures but something like that for
them means 25 mmbwpd injection (that represents a huge amount of large pipes and pumps, and power
– the water isn't like domestic supply, it has to be at high pressure). It's not normally economic
to build in much spare capacity for the piping systems (but who knows with Saudi). Once water
can't be controlled in horizontal wells the cut increases quickly, if it can't be handled within
the facilities and enough pressure maintenance from injected water supplied then the oil production
has to fall (i.e. wells choked back) accordingly.
If at a capacity limit (or limits) increasing production may need new wells, but more than
that completely new topsides facilities, anything more than a few tweaks would need at least 2
to 3 years engineering, procurement and construction effort.
Very good overview. I worked with a field set up to handle extra water, but they forgot the water
heat capacity requires more heaters. So as water cut climbed we had to use lots of chemicals to
get clean oil, until we could install more heaters and heat exchangers. These bottlenecks can
be really subtle, so I took to asking for full surface system simulation runs at 90 % field water
cut to see where the troubles were bound to pop up.
I think Survivalist and Petro have nailed a very good analysis of the situation. When prices crashed
most National Oil Companies and many independent producers tried (and are trying) to produce more
to maintain income. The real tragedy comes when prices remain low and production falls like in
Venezuela. Lack of investments guarantees that this will happen eventually to most producers,
and then once production falls enough we will get very destructive price spikes.
Petro, we see eye to eye on much these issues, but I do think that the world economy will be able
to pay much more for oil than 60$ without crashing. Probably more than $100.
The stuff is too useful, and money will be diverted from other uses to keep buying it.
We'll see, one way or another….
You cannot simply look at the oil price between 2010 and 2014 and deduce that those prices
are sustainable for the World economy. You need to understand the situation under which those
prices were made possible at the time. The period 2009-2014 was a time when Chinese debt was growing
at unsustainable levels to fuel an oil demand that compensated the demand contraction from an
overindebted Europe that could not accept those high oil prices and went into recession and debt
crisis. The period 2009-2014 was also a time when central banks engaged in exceptional ZIRP and
quantitative easing policies with most countries significantly increasing their public debt.
But there is only one China and all significant economies have now a high level of indebtment
so a very rapid growth of debt has become a lot less likely. At the same time ZIRP and quantitative
easing policies are a one way avenue of increasing risk, decreasing effect, and extremely difficult
return.
The oil price crash has probably delayed the next economic crisis. However the world economy
is in no position to assume the oil prices required to guarantee the level of investment required
to increase oil production above 2015 levels.
Oil depletion, debt, and low economic growth, will all work to make 2015 the year of Peak Oil.
If we enter a period of high oil price volatility due to mismatches between production and demand
that will be very destructive both to the economy and to oil production.
Possibly $100/b is a problem, but there is a lot of room between $50/b and $100/b. When oil
supply decreases, oil price will increase. How much oil prices can increase without damaging the
World economy is far from clear.
One can arbitrarily claim $75/b is the magic number that will make the economy crash,
nobody knows. There might be a sweet spot between $75/b and $95/b where oil supply can
either be maintained or possibly increase slightly and not cause World output to decline. World
debt to GDP has been relatively stable since 2010 based on BIS data.
Javier- you (and Petro etc) may be right, and the civil difficulties of Venez and poverty of Moldova
may be coming to places far and wide.
I'm thinking that most commerce will still churn on, even if oil is 100$. Maybe just wishful thinking.
I agree. There is very little evidence that oil over $75/b kills the economy, what it has done
recently is result in too much oil production relative to demand.
What has changed is that there is no one willing to cut back on output. From 1930-1970, Texas
was the World's swing producer and from 1985-2014 Saudi Arabia fulfilled that role. Now we will
see volatility in oil prices unless some new cartel is formed, maybe OPPC (Organization of Petroleum
Producing Countries).
US, Norway, UK, Russia, Brazil, and Canada could join the OPEC nations and have a production agreement
to control oil prices.
This would never happen, but maybe each nation should regulate output as the RRC once did for
Texas, it would help with oil price volatility.
Reply
"... Survey of international spending reveals a 19% decline compared with an initial estimate of 14% in January. The Middle East remains an area of stability while the largest negative revisions come from large IOCs, Latin America, and the Asia Pacific region, excluding China. Latin America is still the weakest region, where spending is expected to decline 30%. ..."
"... IOCs and independents are projected to have spending declines of 24% this year, while other independents are expected to spend 45% less. This compares with prior decline estimates of 10% and 17%, respectively." ..."
E&P spending is much lower this year than was expected even after the big cuts initially announced.
US independents and Canada in particular are hurting. Middle East is the only place holding up.
"In its midyear E&P spending update, Cowen & Co. now estimates global expenditures to fall
24% compared with a 16% decline in its January survey. The downward revisions were primarily driven
by larger spending cuts from North America-focused E&Ps and major international oil companies.
In this update, Cowen & Co. expects US spending to decline 45%, reflecting oil prices of $40/bbl
and natural gas prices of $2.50/MMbtu. This was down from a 22% estimate at the time of January's
survey, which was based on $48.5/bbl oil and $2.50/MMbtu gas. Canada spending is expected to fall
33% compared with an earlier estimate of an 18% falloff.
Survey of international spending reveals a 19% decline compared with an initial estimate of 14%
in January. The Middle East remains an area of stability while the largest negative revisions
come from large IOCs, Latin America, and the Asia Pacific region, excluding China. Latin America
is still the weakest region, where spending is expected to decline 30%.
IOCs and independents are projected to have spending declines of 24% this year, while other independents
are expected to spend 45% less. This compares with prior decline estimates of 10% and 17%, respectively."
"... That break-even bullshit is just nonsense. What is happening in oil industry is debt deflation aka "you have to eat less". That debt deflation is direct result of debt infused shale development by Wall Street in order to prevent debt deflation in the rest of economy. Wall Street kicked the can of debt deflation in economy for about 10 years with 3 major shale plays in US. That' all. ..."
"... Why do I need Wood Mackenzie's interpretation? Reality does not need any interpretation. US oil production is down 1 mil within a year from the peak and folding like cheap wall mart chair, oil price is still in the basement at $46, and shale has outstanding credit card debt of 300 billion. And you are dialling 1 – 800 VISA to finance more drilling of shale in OKLA hoping for different outcome. Priceless, as VISA would say. ..."
"... Their only purpose is to keep you in a dream. You are dreaming. If you are in oil business today the present is almost a hell. You can endure it only because of the hopes that you have projected into the future. You can live today because of the tomorrow. You are hoping something is going to happen tomorrow, some doors to paradise will open tomorrow. They never open today. And when tomorrow comes, it will not come as tomorrow, it will come as today – but by that time your hope have moved again. ..."
"... I again wish all would realize that OK resource plays are generally wet gas plays, not oil plays. Just did a quick search. Found 539 hz wells with first production in OK since 1/1/15. ..."
"... Again, another quick search, looks like over 1/3 of the OK Woodford wells with first production 1/13 or later have hit 1 million mcf. Also looks like most are producing over 30K mcf per month. ..."
Production costs dropped because the industry hit the fan and today there's contractors, subcontractors,
and individuals willing to give bargain prices to survive as long as possible, hoping demand will
rise and they can return to being profitable.
Yes, a trillion $ old economy industry can't cut prices by 50% by "innovation" in a few years.
It's all about subcontractors working for just cashflow to pay interrest on their loans.
When they all resume drillig to these low prices (and in shale all drill in the same few sweatspots
with the low $ oil), prices will crash up since there are few workers left to do all this additional
work.
No kidding. Back in the 1980's I was a junior supervisor, but I was asked to cut budgets to the
bone during the 1985-86 crash. The whole process was incredibly stressful, but we managed to achieve
significant cuts by having rather forceful talks with service providers to get cuts. In some cases
they had to sit down with unions and their subcontractors, but it seemed to work pretty well after
we cancelled a platform painting contract on the spot after they refused to reduce their charges.
I don't know any oil business here, since I sit in Germany, but we have lot's of industry.
And in the last crisis 2007 you could produce for lots less than break even, just to maintain
a cashflow. Workers have been on short labor here (It's a thing from the state to prevent firing,
it paid out big time later).
But when the economy picked up prices got higher again. So – you get only the low prices when
few people buy – if everyone and his dog would run out drilling new wells these low prices would
be history again.
That break-even bullshit is just nonsense. What is happening in oil industry is debt deflation
aka "you have to eat less". That debt deflation is direct result of debt infused shale development
by Wall Street in order to prevent debt deflation in the rest of economy. Wall Street kicked the
can of debt deflation in economy for about 10 years with 3 major shale plays in US. That' all.
OKLA plays maybe will get drilled but they will not make a dime like the rest of shale did
not make dime by extracting oil, other than by doing the ponzi type of reselling of leases, companies
to a greater fool.
you are ignorant, I personally have wells in this trend that will make money, that is working
interest that I pay out of pocket money for and get a real after tax return. You should take a
little time to learn and then think before you write, or you can continue to show the cyber world
just how little you really know about the subjects you write about. decisions decisions…:-) I
have not ask because i do not care but your understanding of the real world seems rather limited,
do you profess to know more or have equal or better credentials, education and information, or
more access to objective worldwide data within the oil and gas business than Wood Mackenzie? Thats
what I thought
texas said: "Wood Mackenzie?… made of credentials, education and information…."
That is scary.
Why do I need Wood Mackenzie's interpretation? Reality does not need any interpretation. US oil
production is down 1 mil within a year from the peak and folding like cheap wall mart chair, oil
price is still in the basement at $46, and shale has outstanding credit card debt of 300 billion.
And you are dialling 1 – 800 VISA to finance more drilling of shale in OKLA hoping for different
outcome. Priceless, as VISA would say.
I now must assume you may have graduated high school, and were in the bottom 1/4 of your class
and you may have taken remedial reading. So here is a little help for someone who is just so special.
From the report:
"In West Texas, oil companies could make money in the Bone Spring and Wolfcamp tight oil plays
with $37 a barrel oil, while their rivals in the Eagle Ford Shale in South Texas could turn a
profit at $48 a barrel. The average break-even price in North Dakota's Bakken Shale is $58 a barrel.
In Oklahoma's Scoop region, it's $35 a barrel, Wood Mackenzie estimates."
Do you see where it said Bakken @$58? This is in North Dakota, not OKLA.
Do you see where it said Eagle Ford @ $48. That is in South Texas. again not in OKLA, Those $$$
numbers were far higher last year.
Now can we name the two biggest LTO fields in the US, stay with me, I know this is hard for you.
It is the Bakken and the Eagleford, both on a field wide basis are currently uneconomic and have
been for well over 20 months. Most all LTO and conventional production world wide was uneconomic
for the 4th 1/4 2015 and the first 1/4 2016, perhaps that explains why production has dropped.
With regard to the economics of my personal business, it will not matter what I say, because
you are just plain to ignorant to understand our business. But I will again share, if at such
time we see $4.00 nat gas and $75 oil, this play will have risk weighted returns that exceed most
of any projects I have been associated with in my 30 years. That includes a number of very prolific
trends within the lower 48
You really don't understand numbers. So let's leave at that. I will tell you the secret about
these reports you religiously read by Wood Mackenzie, Citi, Bloomberg whatever.
Their only purpose is to keep you in a dream. You are dreaming. If you are in oil business
today the present is almost a hell. You can endure it only because of the hopes that you have
projected into the future. You can live today because of the tomorrow. You are hoping something
is going to happen tomorrow, some doors to paradise will open tomorrow. They never open today.
And when tomorrow comes, it will not come as tomorrow, it will come as today – but by that time
your hope have moved again.
You go on moving ahead of yourself – this is what dreaming means. You are not one with the
real, you are somewhere else ( like $4.00 nat gas and $75 oil), moving ahead, jumping ahead. You
are dreaming.
I have asked texas the same question few weeks ago and no answer so maybe he is still calculating
ROI :-)
True story: Once I was standing in line for some Korean fast food and guy next to me start
talking. "How yu duing?" , "What do yuo do"….. so the guy says "I am investor" for a living .
I said "Cool". So he starts talking about his investments in real estate, abraka-dabra …so he
, "profit 200% in 2 years, so you can make 100% annually"
And my antennas start beeping right away. The guy was adding the percentages to calculate the
profit after 2 years!!! Catastrophe. So he did not even know how to calculate a profit and he
was "investor"!!!
If he was making 100% annually then 2*2=4, so he had 4 times more money than in the beginning.
4 times more is 300% and not 200% as he claimed. That was in 2005-6 when RE was "hot" and anyone
was RE "investors", so maybe he is shale investor today :-)
I doubt those quoted costs are full cycle costs in those plays for the average well. They may
be based on the fantasy type curves found in investor presentations. When one takes a close look
at actual average well output data, the well profiles in investor presentations are usually about
a factor of 2 higher than real world results. So the real world full cycle (vs point forward)
cost per barrel would be roughly double what you quoted above.
I again wish all would realize that OK resource plays are generally wet gas plays, not oil plays.
Just did a quick search. Found 539 hz wells with first production in OK since 1/1/15.
13 have hit 100,000 cumulative BO or more.
248 have hit 300,000 cumulative mcf gas or more.
It is a wet gas play, just like the Woodford has been for decades. Springer is the only one
I would call an oil resource play, I think it is generally agreed to be uneconomic at present
prices.
Woodford wells will produce a lot of gas, obtain a premium gas price due to high BTU, and produce
little water, so LOE per mcf is low.
I cannot comment on the economics of these wells, but do believe the data, thus far, shows
these to be gas. Yes, many have initial high % of liquids, but the liquids disappear quickly.
I think TT has generally agreed with me on these observations.
Again, another quick search, looks like over 1/3 of the OK Woodford wells with first production
1/13 or later have hit 1 million mcf. Also looks like most are producing over 30K mcf per month.
OTOH, most did not produce any oil in the most recent month. The big oil producers currently
are for wells less than 12 months old.
Safe to say these wells generally will produce a lot of gas. I am not able to discuss economics,
do not have enough data.
Hope I'm not annoying anyone as I have typed this numerous times. My beef is the wells are
advertised as oil wells, in an "oil window" with IP and cumulative production measured in BOE.
Kind of like calling driver assist function " Auto pilot".
Your posts are always solid information and useful. Anyone who might be annoyed is no-one you
need even think about. I bet a lot of us here count on you.
For all:
Can we please see an end–an END–to the snotty tone in far too many of the comments here? There
is no call for any comment of the "I see that you have no understanding of (fill in the blank)"
type, or of anything like it.
Content and accuracy of post are important. Clarity of presentation is important. Civility
and courtesy are important. What anyone posting here thinks of anyone else posting here is not
important for the public discussion.
"... Therefore overall the undiscovered resources might now be zero for maximum, median and minimum cases, which would be quite a bit different from USGS numbers of 4, 7 and 11 Gb respectively, with a mean of 7.4 Gb. ..."
The USGS should revisit their earlier estimate for undiscovered resources in Bakken / Three Forks
now that about four times as many wells have been drilled since the first release.
The way USGS estimated the undiscovered resources was quite simple. Split the region into 6
production zones (which may be stacked); for each zone split into core (sweet spots) and non core
areas to give twelve assessment units. For each unit estimate total area (A), drainage area for
each well (a), EUR per well (U), the proportion of the area unexplored (p) and the chance of not
getting a dry well when drilling (r). Then resource is (A/a)*U*p*r. The values are different for
each zone and they actually give three alternatives: maximum, median, minimum. Then they add up
all twelve (or 36) estimates to give the total (or 3 different totals). The values for A, a and
U might have some reasonable chance of being correct but p and, especially, r are just best guesses;
for the maximum cases r is greater than 80% for all areas and for some minimum cases 90% and higher
is used.
In reality the E&Ps stopped wild cat permitting when they got to 50% success rate (and
falling fast) in 2013/2014. Therefore, in the core areas p might be zero – the lease holders know
what is there and have already included it in 'proven undeveloped', they don't need to drill to
be confident – and in the non core areas p * r is zero – the lease holders drilled wildcats out
from the core until they started hitting dry holes, and then they stopped because there is nothing
else to find (r is zero for all the remaining p). Therefore overall the undiscovered resources
might now be zero for maximum, median and minimum cases, which would be quite a bit different
from USGS numbers of 4, 7 and 11 Gb respectively, with a mean of 7.4 Gb.
"... Steve Kopits at Princeton energy advisors has shown that between 1998-2005 $1.5 Trillion was spent on oil CapEX to increase oil output by 8.4 Mbpd and that from 2005-2013, $4.0 Trillion was spent on CapEx to increase output by just 2.4 Mbpd. ..."
The price of oil seems pretty darn important. Art Berman had an interview with Chris Martenson
on peak prosperity that projects with some 20 Billion barrels of oil have been deferred due to
the current low price. That's a pretty large amount of oil that's not coming online when required
as a result of price.
Not to mention that oil is becoming much harder to find, Steve Kopits at Princeton energy advisors
has shown that between 1998-2005 $1.5 Trillion was spent on oil CapEX to increase oil output by
8.4 Mbpd and that from 2005-2013, $4.0 Trillion was spent on CapEx to increase output by just
2.4 Mbpd.
Society is energy constrained and it's showing up in the economy with crazy effects like NIRP,
where $13 Trillion worth of global bonds now yield negative returns from Zero just a few years
ago, think about that, paying someone to borrow your money!! Also an economy where young people
aren't getting decent jobs to pay for incredibly overpriced house prices as evidenced by affordability
ratios, where populism and extremism is on the rise globally as well as large swathes of society
are left out of prosperity. Energy is the ability to do work, without increasing energy supplies
society has to fundamentally change.
"... There are still a lot of projects due this year and next and even into 2018, but not quite enough to make up for the declines. ..."
"... Probably 2.5 to 3.5 mmbpd fall over the three years barring big, unexpected outages. In 2019, 2020 and 2021 there will be dramatic and accelerating falls unless a lot of expensive, and currently delayed, oil developments are fast tracked soon, or a lot of very cheap oil is found somewhere, or in fill drilling ramps up quickly on the big reservoirs. ..."
"... It's time lag. Simply said, when prices where at 100$+, everyone had lot's of money to invest and drilled like mad to get even more oil, explored, developed new fields. These operations have normally completion times of a few years, so they come alltogether online now. A typically pork circle. Price does matter – now new projects are delayed or canceled, ready to go into the next round. ..."
"... How can anyone possibly deny the effect the price of oil has on the production of oil? The very high price of oil brought on the shale revolution. Oil prices above $80 a barrel caused shale oil production to boom. However shale oil production is just uneconomical at prices below $60 a barrel, or somewhere in that neighborhood. ..."
"... Almost every barrel being produced cost a different amount to produce. There is a thing called "the margin". That is what it cost to produce the most expensive barrel of oil being produced. As the price of oil drops, barrels being produced "at the margin" starts to drop off. More expensive oil stops being produced, less expensive oil continues to be produced. Of course there is a delay between the price dropping below the margin and that marginal barrel dropping from production. ..."
Has depletion finally gained the upper hand? My back of the envelope calculation:
Conventional: 78 million barrels at 4% = 3.1 million barrels.
All other: 19 million barrels at 10% = 1.9 million barrels.
Total: 5 million barrels per year
2015 was a year where a lot of projects came online that were developed in previous years. There
is less of that this year. So 2 million for this year seem reasonable. Next year will be interesting.
If demand keeps growing, there should be a substantial shortfall, draining storage. The only way
to close the fast growing gap is a miraculous recovery of Libya and others that are currently
hampered by political unrest.
There are still a lot of projects due this year and next and even into 2018, but not quite enough
to make up for the declines.
Probably 2.5 to 3.5 mmbpd fall over the three years barring big,
unexpected outages. In 2019, 2020 and 2021 there will be dramatic and accelerating falls unless
a lot of expensive, and currently delayed, oil developments are fast tracked soon, or a lot of
very cheap oil is found somewhere, or in fill drilling ramps up quickly on the big reservoirs.
We'll get to see the truth behind LTO sustainability and flexibility; that and depending on how
demand goes, plus the real storage numbers will determine prices and therefore future supply developments.
Overall though I agree, I think we will suddenly find ourselves short at some point in the next
5 years, and without many options.
Watcher – I think that Ron "almost" has you pegged. Basically he notes that no one can be that
Fu–ing stupid. But, he may be wrong. What in the hell are you talking about when you say "you
can kill competing consumption with weapons?" Why would anyone in the supply chain want to kill
"CONSUMPTION?"
It's time lag. Simply said, when prices where at 100$+, everyone had lot's of money to invest
and drilled like mad to get even more oil, explored, developed new fields.
These operations have normally completion times of a few years, so they come alltogether online
now. A typically pork circle. Price does matter – now new projects are delayed or canceled, ready to go into the next round.
How can anyone possibly deny the effect the price of oil has on the production of oil? The very
high price of oil brought on the shale revolution. Oil prices above $80 a barrel caused shale
oil production to boom. However shale oil production is just uneconomical at prices below $60
a barrel, or somewhere in that neighborhood.
Dammit, it is as plain as the nose on your face. Price determines production. Does Watcher
really deny that simple fact? No, Dennis, you are simply mistaken. Watcher is not so dumb as to
deny that simple fact…. Is he???
Watcher has BEEN denying it, as steadily as if somebody were paying him by the word, for as far
back as I can remember.
Some people, quite a few actually, believe God looks after their lives for them on an every
day basis, and no amount of evidence, good or bad, is enough to shake this conviction.
Watcher apparently believes in some UNIDENTIFIED POWER that keeps oil coming regardless of
the price, or perhaps more accurately, keeps it coming even while controlling the price and forcing
it down by half or three quarters.
Of course there might be another explanation. Maybe he just enjoys rubbing everybody nose in
the apparent failure of the market system in the case of oil.
The explanation is simple enough, in principle. The oil industry is the biggest and slowest
moving of all industries, when it comes to NECESSARILY operating on a five to ten year time scale
in terms of making production decisions.
Being an orchardist, I am personally quite comfortable with such planning time scales, because
my kind of work is planned on a very similar time scale. If I miscalculate , meaning guess, really,
what the price of apples will be ten years down the road, and plant too many new trees, I am not
just going to take a chainsaw or bulldozer to my orchard because the price collapses. I wait it
out, and hopefully OTHER orchardists go broke first. Old trees will be dying, there is depletion
in apples, lol.
The production decision making process is triply compounded in difficulty by what we usually
forget , because in a forum such as this one, the discussion is centered around BUSINESSMEN out
to make a living, folks such as Mike, Shallow Sand, Texas Tea, etc. They make rational decisions,
as best they can.
What we forget is that the oil industry is an industry dominated by governments, and governments
are notoriously clumsy in managing their business affairs when circumstances demand action.
Politicians, be they Saudi kings or socialist Venezuelans, or right wing dictators or more
middle of the road types, are NOT going to do anything to upset their citizens, or piss them off,
if it can be avoided. Laying off a few tens of thousands of people is just not DONE until there
is NO OTHER choice.
Nobody would notice if we laid off half the people who work in the post office here in the
USA. Every body I know , excepting my cousin who is a carrier, and the post master, thinks we
could get along JUST FINE delivering the mail three days a week instead of six.
Politicians at the top of the heap are mostly interested in one thing, that thing being to
stay in power, and to do that, they play an incredibly complicated, fluid game maintaining the
network of supporters who ENABLE them to STAY in power.
Expecting them to act like BUSINESSMEN running a business is naive. As a rule, they will never
do anything proactive in order to solve a problem that might just go away by itself. When they
DO do something , it is to be expected that the doing will be undertaken much later than it ought
to be, and that it will be inadequate to deal with the problem until the problem becomes an existential
emergency.
ONCE all the chips are on the table, and it's literally do or die, or be sent home, out of
office and out of power, governments can do some pretty spectacular things, such as mobilize to
fight a flat out war.
Things aren't that bad yet, in the countries dependent on oil revenues,excepting Venezuela.
Maduro is actively constructing a police state in hopes of staying in power.
The industry has excess capacity. It took years to build that capacity, and the economy couldn't
absorb the amount of oil coming to market at a hundred bucks, so the price collapsed. The economy
IS absorbing the oil coming to market, about the same amount , at about forty bucks.
It will take a WHILE for the excess capacity to dry up.Maybe another year or two, maybe less,
maybe longer. If the economy turns sour, it will take longer.If the electric car revolution really
comes to pass, on the GRAND SCALE, and very quickly, demand destruction will mean there is so
much excess capacity that the price will stay low for a long time.
There is nothing involved in understanding the oil price question that requires more than a
basic understanding of supply and demand, plus an additional understanding of the relevant time
scales and the nature of GOVERNMENTS as opposed to BUSINESSMEN making decisions.
If businessmen were running the post office, we would have half as many postal employees, lol.
Maybe even less.
Farmers have generally done the same thing, collectively, when the price of whichever crop they
produced crashed.
As an individual guy growing corn, or wheat, or rice, or apples, I cannot produce enough, or
cut back far enough, to influence the market price. What I CAN do, is go flat out to produce every
possible last bushel, going for the all important marginal dollar that might enable me to survive
short term. This is what the SMALLER oil producers are doing, by and large.
While producing flat out individually, and collectively, we make the price crash even lower,
and stay in the pits longer, but then this is what drowning men who cannot swim do in the water-
try to survive by pushing themselves up by pushing another man under.
The game changes when one (or more) supplier is big enough and rich enough to have pricing
power and staying power running at a loss. In that case, the big boy can "sweat" the little fellow
, in the words of John D Rockefeller, running him out of business, deliberately.
Now this didn't take long at all while Rockefeller was running a small local company out back
in the early days of big oil, but it can take a hell of a long time when the little guy is a sovereign
government, or a giant corporation. I should say that SA and Russia are engaged in BOTH ways,
producing flat out to maximize revenues, plus hoping to run some competitors out of the market,
at least temporarily.
Folks who aren't TOO simple minded to think a little also realize there is such a thing as
war and politics, and that war can be fought in markets as well as with guns. The USA basically
broke the old USSR by making it impossible for that now dead empire to compete with us on building
guns, never mind butter, plus encouraging the Saudis to flood the market and deprive the Soviets
of oil revenue. Hard core D types will never admit that this is true however, because it is grounds
for being kicked out of the party to admit that a Republican has ever succeeded at doing anything
at all except creating more and bigger problems.
There is an element of WAR being played out in the oil markets now, and for the last year or
two, and it will continue to be important for a while.
Anybody who thinks anybody in DC, excepting oil state congress critters and oil lobbyists,
gives a flying fuck about the oil industries problems has a near zero understanding of economic
politics. Cheap gasoline is an elixer that is damned good for the OVERALL economy, and as good
as a zanax for soothing the nerves of consumers. To expect the Obama administration to do anything
to raise the price of oil, when raising it would cost D 's elections, is tantamount to insanity.
Who can remember this quote? "It's the economy, stupid"?
Hells bells, the R party rakes the D 's over the coals for LOWERING the price of oil by insisting
on higher fuel economy standards, lol.
And one last little bit of ranting, and I will lay off for an hour or two , at least, so help
me Jesus. This is history we are talking about, not a goddamned thirty minute tv show.
Looking at what Ron has said that the threshold for LTO production is $60, what I find important
is that just a few years ago that threshold was in the $80 to $100 range.
Even at today's prices, $45 to $50 range, we have seen the oil directed rig count, increase
over the past few weeks.
This indicates that some of the better plays have a lower threshold.
As we go out in time I would not be surprised that the $60 threshold will move down again.
R DesRoches,
absence of some new technology, I expect we are at the lows of what LTO break-even cost will be
for the best LTO plays. As oil prices pick up and balance sheets get better the drilling companies,
Fracking co will begin to have some better pricing power and I expect they will use it. So for
a time expect break even to stay low but begin to rise "somewhat" as prices move up. I still think
$75 WTI is what the best companies in the best plays really need to MAKE MONEY not just break-even
in a normal business environment. (lets says 1200 rigs running lower 48 ) I know I would be drilling
in the areas I am active at that price, $50 not so much and only with a gun to my head :-)
RDR – I am never sure of what anybody said about breakeven, unless it is accompanied by a complete
financial statement.
If an oil company has undrilled land in an LTO area, that (1) needs production to "hold" the
lease, and/or (2) has bank debt related to its lease acquisition, then: Their breakeven point
and perspective is totally different (lower) than if you or I tried to determine our breakeven
point if we went someplace, bought acreage and drilled a well.
OTOH, I notice 2 yrs later KSA is producing 600K bpd more oil at less than half the price.
And what is Russia producing now at less than half the price?
Watcher, you cannot measure every barrel produced with the same yard stick.
It cost KSA about $20 a barrel to produce oil, more in some places less in others. Therefore
they want to produce every barrel possible in order to meet their budget.
It cost Russia pretty much the same to produce oil from their old fields. But it cost them
much more to find new oil and produce it. The price of oil is hitting Russia very hard but will
hit them much harder unless the price rises soon.
The low price of oil is killing Venezuela. Their production is dropping. It will drop much
further unless the price starts to rise soon.
Almost every barrel being produced cost a different amount to produce. There is a thing
called "the margin". That is what it cost to produce the most expensive barrel of oil being produced.
As the price of oil drops, barrels being produced "at the margin" starts to drop off. More
expensive oil stops being produced, less expensive oil continues to be produced. Of course
there is a delay between the price dropping below the margin and that marginal barrel dropping
from production.
Watcher, it is just fucking insane to claim that price has no effect on production. You have
to know better than that. Why on earth do you think the number of oil rigs working in North Dakota
dropped fro 215 rigs four years ago today, to 30 today? It was because the price of oil dropped
and for no other reason. And that decline in the number of rigs is currently having a dramatic
effect on oil production in North Dakota.
Dennis, I was just being sarcastic. I know that Watcher really does believe that the price of
oil makes no difference. Imagine that! He also believes that money is just a piece of paper.
If you go to any of the big LTO independent oil companies web sites and look at their investor
presentations you will find two trends.
First the day to drill wells have come down in the last couple of years, in many cases by over
30%.
Second with bigger fracs and changes in the mix, IPs and EURs have gone up, in many cases above
25%.
What this means is that the break even price of oil has been coming down.
We are starting to see rigs coming back to the patch at oil prices below $50. IMO as the oil
prices moves up towards the $60 level the rate of increase in rig counts will also increase.
Well costs went down and then back up as more esoteric well designs have become common. Note
that supd costs may have gone down and LOE might also have gone down, but you are leaving out
completion costs which is about 2/3 of the capital cost of the well, the decrease in spud cost
has been more than offset by increases in completion costs (this includes the fracking). On balance
total well cost has probably not decreased much and for the newer designs with more stages (up
to 40 or so in the Bakken) and higher amounts of proppant, total well cost has probably increased.
The "lower well cost" presented in the investor presentations is for an older "standard well
design". The newer well designs that have increased the output per well cost an extra 1 or 2 million
per well (in the ND Bakken/Three Forks).
What does frac water cost per barrel, or at least a range? How many barrels of water are needed
to drill and complete a hz well? How much does trucking the water cost.
I know all this can vary, so just some ranges will do.
I took a look at oil rigs operating in the Permian, Bakken and Eagle Ford.
For those 3 plays we have:
Total oil rigs- 213
Horizontal-191
Vertical- 22
Bakken – 28T, 27H
EF- 27T, 26H
Permian-158T, 138H, 74% of oil rigs in the big 3 LTO plays.
Of the 28 oil rigs added since May 27, 2016, 22 were added to the Permian and all were horizontal
rigs. The Bakken added 5 horizontal rigs and 1 vertical and the EF 1 vertical rig.
Based on this, Eagle Ford is probably the high cost play, then Bakken, with the Permian perceived
as best at the moment of the LTO plays.
-Not only price does matter, but It is PRECISELY due to the low prices that everybody is producing
in a " …the last big party…" mode, … last oomph, if you will!
All in!
All they can!
….and has little to do with the "delayed effect"…. if there is such a thing.
Some 20 carmakers have committed to making automatic emergency braking systems a standard feature
on virtually all new cars sold in the U.S. by 2022, according to a new plan from the
National Highway Traffic Safety Administration and the Insurance Institute for Highway Safety.
Automatic brakes are designed to stop a vehicle before it collides with a car or another object.
Experts say that making them standard could prevent as much as 20 percent of accidents.
NPR's Sonari Glinton reports for our Newscast unit:
"Many cars on the road now have automated brakes. And when you're new to them, it's pretty scary
when the car stops on its own. But experts say automatic brakes could make the fender bender a
thing of the past.
...
"It's part of a push to fight the growing problem of driver distraction and a step closer to
driverless cars. Now carmakers have to figure out by 2022 how they'll integrate the systems."
NHTSA released a list of the car companies that have committed to the system:
"Audi, BMW, FCA US LLC, Ford, General Motors, Honda, Hyundai, Jaguar Land Rover, Kia, Maserati,
Mazda, Mercedes-Benz, Mitsubishi Motors, Nissan, Porsche, Subaru, Tesla Motors Inc., Toyota, Volkswagen
and Volvo."
"In 2012, one-third of all police-reported crashes involved a rear-end collision with another
vehicle as the first harmful event in the crash," according to the government's information page
on Automatic Emergency Braking systems.
It adds that AEB systems can either avoid or reduce the severity of some of those rear-end crashes.
In a statement about the plan, NHTSA says the "unprecedented commitment" from the automakers will
bring the safety technology to "more consumers more quickly than would be possible through the regulatory
process."
"... It looks like the increase in GOR has finally stopped, at least for wells earlier than 2015. GOR for 2015 is still increasing fast. 2008 and 2009 are on the other hand decreasing. ..."
"... Here we can see that for 2009 there is a huge drop, about 6%. As a comparison it would translate into more than 50% in one year. ..."
"... This graph looks like a mess, I know. I hope you can make something out if though. It shows the percentage of wells that are producing in a certain month. There is a downward trend over time, but the oil price is not affecting it much at all. ..."
Hello guys. Here is my updated Bakken GOR graph. It looks like the increase in GOR has finally
stopped, at least for wells earlier than 2015. GOR for 2015 is still increasing fast. 2008 and
2009 are on the other hand decreasing. So what does this mean for production? Lets see in
my next graph bellow.
Here we can see that for 2009 there is a huge drop, about 6%. As a comparison it would translate
into more than 50% in one year. But of course you should not extrapolate from a (cherry picked)
single month like that. For 2008 there is instead a slight increase. At least some of that can
be explained by that some wells that were previously not producing, are now back online. I don´t
know how much of an effect that has though. I´ll show more about that in my next graph. 2013 has
slowed down the decline since last month, but is still bellow 2012. So overall nothing dramatic
except for 2009.
This graph looks like a mess, I know. I hope you can make something out if though. It shows the
percentage of wells that are producing in a certain month. There is a downward trend over time,
but the oil price is not affecting it much at all. It´s only this spring when the oil price was
in the 30s that you can notice some decline. But it´s not more than 1-2% of the wells that were
put offline. Never the less, there were some wells that were put back on production in May which
should have a positive effect on production. Also ,the total producing "days" for all wells combined
has increased by about 5% since last month (which I don´t show in any graph here).
Looking at Art Berman's chart below. World oil production since 2005, less US and Canada, has
been pretty much flat. This is despite the fact that prices have risen dramatically in that period
of time. So lets look at the other huge gainers since 2005.
Russia: See the EIA's take above. Even if they are wrong, Russia's huge gains are gone forever.
Angola, Brazil, China and Colombia: China and Colombia have definitely peaked. Angola peaked
in 2010 and has declined slightly and been flat since then. Only Brazil has any hope of increasing
production, and tat not by very much.
Iraq: I believe Iraq has peaked. Some may disagree but there is no doubt that their best days
are behind them. They have far more downside potential than upside potential.
There is little doubt that all those countries will decline in the next few years regardless
of what the price of oil is. After all, if oil above $100 a barrel in the past did not sent them
producing massive amounts of oil, there is no reason to believe it will do so in the future.
That leaves the USA and Canada. To those massive high prices in the past few years, only
the USA and Canada responded. So… will higher prices bring on enough US and Canadian production,
to make up for the decline in the rest of the world… plus increase production enough to push production
above the 2015 peak?
Sobering, as Euan writes. Alarming I'd say.
In a possible future's retrospect, it may turn out to have come as a surprise how fast things
unraveled sociogeopolitically so close after the peak.
Fossil fuel, within a certain EROEI range is, of course, power. It powers pseudoeconomies,
governpimps, and their militaries. And now China and Russia, for two examples, are not nearly
as 'backwoods' as they may have been, historically. They have become, 'Westernized'…
After a year of trying to increase their production they have been unable to do so. Now things
are likely to get worse. Iraq depends almost entirely on outside contractors. Also there has been
a steady stream of skeptical news coming out of Iraq.
Iraq is Opec's second-largest producer after Saudi Arabia and has ambitious plans to increase
production capacity to between 5.5m b/d and 6m b/d by 2020.
This target, which has been revised downward in recent months, has been viewed with scepticism
as a budget crisis is limiting the federal government's ability to pay companies that are producing
oil in Iraq. These include from BP, Royal Dutch Shell and Russia's Lukoil.
Although they are developing some of the lowest cost easy-to-access deposits of oil in the
world, the fields need more investment to maintain production at current levels and increase future
capacity. At the same time, the government in Baghdad is requesting companies reduce spending.
"We're taking more risk to keep production the same, while not getting paid. We can't
continue to produce for 2-3 years like this, it's not possible," said one executive at an oil
company operating in Iraq. "Maybe they can achieve 6m b/d by 2030."
These numbers are through June. As you can see they still have not matched January's numbers.
And their contractors are not getting paid. Now what would you think would be the likely effect
on Iraqi oil production?
My guess is that Iraq oil production will struggle to maintain current levels over the next
couple of years and then drop rapidly as their ongoing religious civil war makes the situation
too dangerous for continued foreign investment.
Another guess is that the global economy will be in recession by 2020, reducing demand, lowering
world oil prices, and pushing many national economies into bankruptcy. The impact for countries
highly dependent on oil revenue to maintain social services and stability will be devastating
and we'll see the breakdown of societies and the rise of dictatorship.
All wags of course. But it seems to me, generally, that geopolitics and social/economic problems
will begin to overtake any geologic and technological limitations in world oil production. Venezuela
is a current example, and now Iraq, starting with their "budget crisis" and workers "not getting
paid", as your article describes. In other words, above ground factors are determining production
and not the lack of oil in place.
Thanks for your reply, always appreciate your clear-headed thinking.
Probably Art is basing his incremental graph in Matt's ones.
Also very noteworthy is Matt's graph on "Conventional Oil Plateau" from his May 2015 update on
that link.
If we had a whole century ahead of
us to transition, it would be
comparatively easy.
Unfortunately, we no longer have
that leisure since the second key
challenge is the remaining
timeframe for whole system
replacement. What most people
miss is that the rapid end of the
Oil Age began in 2012 and will be
over within some 10 years. To the
best of my knowledge, the most
advanced material in this matter
is the thermodynamic analysis of
the oil industry taken as a whole
system (OI) produced by The Hill's
Group (THG) over the last two
years or so (
http://www.thehillsgroup.org
).
THG are seasoned US oil industry
engineers led by B.W. Hill. I
find its analysis elegant and rock
hard. For example, one of its
outputs concerns oil prices. Over
a 56 year time period, its
correlation factor with historical
data is 0.995. In consequence,
they began to warn in 2013 about
the oil price crash that began
late 2014 (see:
http://www.thehillsgroup.org/depletion2_022.htm
).
In what follows I rely on THG's
report and my own work.
Three figures summarise the
situation we are in rather well,
in my view.
Figure
SEQ Figure \* ARABIC 1
– End Game
For purely thermodynamic reasons
net energy delivered to the
globalised industrial world (GIW)
per barrel by the oil industry (OI)
is rapidly trending to zero. By
net energy we mean here what the
OI delivers to the GIW,
essentially in the form of
transport fuels, after the energy
used by the OI for exploration,
production, transport, refining
and end products delivery have
been deducted.
However, things break down well
before reaching
"ground zero"
;
i.e. within 10 years the OI as we
know it will have disintegrated.
Actually, a number of analysts
from entities like Deloitte or
Chatham House, reading financial
tealeaves, are progressively
reaching the same kind of
conclusions.
[1]
The Oil Age is finishing now, not
in a slow, smooth, long slide down
from
"Peak Oil"
, but in a
rapid fizzling out of net energy.
This is now combining with things
like climate change and the global
debt issues to generate what I
call a
"Perfect Storm"
big
enough to bring the GIW to its
knees.
In an Alice world
At present, under the prevailing
paradigm, there is no known way to
exit from the
Perfect Storm
within the emerging time
constraint (available time
has shrunk by one order of
magnitude, from 100 to 10 years).
This is where I think that
Doomstead Diner's
readers are
guessing right. Many readers are
no doubt familiar with the
so-called
"Red Queen"
effect illustrated in REF
_Ref329530846 \h Figure 2
08D0C9EA79F9BACE118C8200AA004BA90B02000000080000000E0000005F005200650066003300320039003500330030003800340036000000
– to have to run fast to stay put, and even faster to be able to move forward.
The OI is fully caught in it.
I find in this article
too many crass claims
and too few simple
facts, and even those
questionable.
Take graph 1. It
suggests, that in
2015, i.e. a year ago,
the EROI of oil were
1.17. In fact it was
always more than 5, in
most cases even more
then 10, afaik, even
for the "new sources",
i.e. tar sands &c.
Concerning the
energetic cost of the
transition: In a first
approximation, energy
investment in
renewables and saving
has paid for itself
within a year. This
means, that if we
transform 10 % of our
energy infrastructure
to renewables and
saving per year, we
have to use 10 % of
our available power
for it. This is
certainly a lot. But
it is certainly
doable, if we want.
The latter, of course,
is the nub of the
matter.
I have the feeling i
have to wade through a
rhetoric jungle to
search for valuable
information. May be a
matter of taste, i
admit.
It is
important
to not
confuse
EROi or
EROEI at
the well
head and
for the
whole
system up
to the
end-users.
The Hill's
Group
people
have shown
that the
EROIE as
defined by
them
passed
below the
critical
viability
level of
10:1
around
2010 and
that along
current
dynamics
by circa
2030 it
will be
about
6.89:1, by
which time
no net
energy per
barrel
will reach
end-users
(assuming
there is
still an
oil
industry
at this
point,
which a
number of
us
consider
most
unlikely,
at least
not the
oil
industry
as we
presently
know it).
Net energy
here means
what is
available
to
end-users
typically
to go from
A to B,
the energy
lost as
waste heat
(2nd
principle)
and the
energy
used by
the oil
industry
having
been fully
deducted -
as such it
cannot be
directly
linked in
reverse to
evaluate
an EROI.
Re the
necessary
energy
investments
to
build-up a
renewable
capacity,
Parts 2
and 3 will
elaborate
on the
matter.
Let's just
say for
now that
we are
talking
here of
whole
system
replacement,
globally,
and not
just
considering
the energy
embodied
in the
implementation
of this or
that bit
of
renewable
technology
- the
pictures
look very
different
at the
micro and
macro
levels.
"... In June alone, China pumped 8.9 percent less crude than a year earlier, with state-owned giants such as PetroChina and CNOOC shuttering unprofitable fields ..."
"... Crude oil imports in January-June jumped 14 percent, China's national Bureau of Statistics said ..."
China's crude oil output over the first half of the year stood at 101.59 million metric tons,
down 4.6 percent and the lowest six-month figure since 2012, Bloomberg
reports. The decline reflects China's stated shift from an industry-focused economic model
to a more service-oriented one. It is also related to a drive by the government to cut the country's
environmental footprint, struggling with a reputation of China as one of the most polluted places
on earth. Low oil prices were also a factor in the production trend.
In June alone, China pumped 8.9 percent less crude than a year earlier, with state-owned giants
such as PetroChina and CNOOC shuttering unprofitable fields and turning to low-cost imports instead.
Crude oil imports in January-June jumped 14 percent, China's national Bureau of Statistics said,
with June recording the weakest growth.
And this article. Interesting point that Saudi Arabia will have a dilemma when they attempt
to represent the interests of future shareholders in Saudi Aramco as well as be a cartel member
and cooperate with OPEC interests.
The developed proved and probable is 655 Gb, which would equate to about 4.5% natural decay
rate.
There is supposed to be about 900 Gb undiscovered, which at last years rates would take about
300 years to find (and my guess is that if there is that much hydrocarbon it has a significant
amount of gas).
And there are 500 Gb discovered and undeveloped, I don't follow that much but there is a country
break down to check out, but the IOCs stopped development with prices at $110 per barrel so it's
probably going to cost more than $8 trillion to put that much on line.
"... So he's covered. I'm about to publish something here maybe today and the sub title of this section is called "It's not a lie if we tell you it's a lie." That's the name of the game. As long as the investor presentation or the news release says somewhere that we're using language here that we would never ever use in an SEC filing because they'd put us in jail. And so you guys need to know that. In other words, "we're lying," then it's technically not a lie. It's not fraud because we told you it was a lie. ..."
"... Well we started this conversation with your important observation that we're only talking about a million or million and a half barrels a day of oversupply. So we could go from over supply to deficit pretty quickly ..."
"... So just the capital cuts in US companies have effectively deferred $20 billion-or maybe the world, I'm sorry-$20 billion barrels of development of known proven reserves. ..."
"... Well there's a big lag. There's a huge time lag between when the price responds and people actually get around to drilling and they actually start bringing the oil onto the market and it becomes available as supply, because they've been asleep at the wheel for how many months or years. You don't just turn a valve and all of a sudden everything is okay again. ..."
"... There's this tremendous gap between "okay we know there's a reserve," but what's it take to turn it into supply? Well it takes time and it takes money and it doesn't happen overnight. ..."
"... EIA says average price in 2016 will be $53 a barrel. They're not always right and in fact they're often wrong but they're not stupid either. They're doing the best they can. They have got some good people there. ..."
"... Well just turn the clock back to 2012-2013 when oil prices were sky high, were $100 a barrel or more, and what we saw was consistent negative cash flow from virtually all of the major players. So what that says is they weren't making money when oil prices were high, so is it a big shock that they're hemorrhaging when oil prices are lower? So oil prices go back up-the bottom line Chris is the only way that they were able to stay looking fairly good back then to somebody, not me, was that people were giving them money. They had infinite access to capital at almost no cost, and so they were spending it. But their income statements and balance sheets look like crap and the investment community I guess was willing to look past that or didn't want to look at it or whatever. ..."
Chris Martenson: ... And still when I look at the operators in those plays they're claiming that they're going to get
twice that, sometimes even more than twice that out of each well. When I've calculated the economics
in that play myself-I got a little spreadsheet, I did my level best. And then I found that you had
calculated what's going on in that play as well. So let's cut right to that. In the Bakken, how many
wells that get drilled out here right now would be economic in today's prices?
Arthur Berman:
Almost none at today's prices. The latest from the North Dakota Department of Mineral Resources
says that wellhead prices are in the 20's so… I published a report not very long ago that said that
1% of the Bakken was breaking even at $30 oil prices. So now we're below that and I don't remember
exactly what percentage of wells but it was something like maybe 5 or 6%. But so right now let's
face it Chris, let's just get it right out there in the open: Everybody is losing their ass at current
oil prices. I don't care what they say. I'm in this business, okay? I just drilled two discoveries
in the last month or two at the bottom of the cycle and we can make a weak profit off of what we
found-first of all they're conventional reservoirs so they didn't cost us $6-$10 million to drill.
And we don't have to drill them horizontally. We don't have to frack them. And we have got no overhead
and we have got no debt; so that puts us in kind of a really different situation for most public
companies.
The truth is that everybody-the best positions in the best plays in the United States, the core
of the core, if you will-nobody can break even at less than about $45 a barrel and that's just reality.
That's not sticking them with their land costs that they sunk and wrote off long ago; that's just
basic operating expenses and severance taxes and stuff that I publish in all of my reports and nobody
ever argues with me about that. They may disagree with a lot of my conclusions or etc. but they never
say "Oh no, your economic assumptions were way off base." No they're not off base.
So take that to the bank and let's just get that whole silly conversation off the table. Everybody
is losing their ass at $20 or $30 oil, everybody. And that includes Saudi Arabia, Kuwait and everybody
in the world is. But certainly US producers, very best of the best, they got to have $45 or $50,
and that's a small subset of their wells in a play. And realistically $60-$65 is bare bones for the
average well positioned company, all of their better wells or current wells in play. That's just
the way it works. And if you hear something else, ask a lot of questions, like: "Tell me what costs
you're excluding," because that's the only way to get there is just be excluding costs.
Chris Martenson:
... When I look at it that way, just sort of high level, I'm looking at 10 billion barrels, what are the reserves? Total reserves? Across all the plays that these operators are in? It can't be a whole heck of a lot more than that, can it?
Arthur Berman:
Proven reserves in the United States as of EIA's latest report a couple weeks ago are 40 billion barrels of oil. Now there is a Proven Undeveloped which is another category that is also proven, which you can add another 40 or 50% but the number you're talking about there is a huge proportion of the total United States' proven reserves, any way you cut it. And so yeah, be scared. That's the message.
.
... ... ...
Arthur Berman:
There is no difference between what EIA is saying and the companies are
saying, okay? So there's two realities here. There is the reality of truth, like go to jail
truth-that's what the companies actually report in their quarterly and annual filings to the
Securities and Exchange Commission. That's where EIA gets its data. That's where EIA's proven
reserves come from; so there's that reality and that truth, and I think it's reasonably close to
the truth. And then there's what companies tell investors, who believe almost anything and don't
understand-again like Yergin's lifting cost. They don't understand, nor should they be required to
understand that he's not actually talking about total cost. He's talking about a subset of costs.
So your question: The proven reserves of the Bakken, according to the latest EIA, which comes from
companies, is 6 billion barrels. The Eagle Ford is a little more than 5, and the Permian is about
700 million. You add up all the rest of them, the Niobrara and the whatever, the Mississippi Lime
and you name it, and the total is about 13.5 billion barrels. That's the truth. And there's
probably an almost – there's a slightly smaller but large proven undeveloped reserve category as
well.
Chris Martenson:
Art I was just reading an investor presentation where one company
claimed to have access to almost that same number just in the Spraberry play.
Arthur Berman:
Well yeah, Pioneer Natural Resources, that truthfully is not a bad company,
if you just look at their financials. But their CEO, Scott Sheffield, has been making just
absolutely preposterous claims for several years now about this Spraberry resource that they have
out in the Permian Basin. The Spraberry was discovered in 1946 for God's sake. In the industry, we
talk about and have talked about the Spraberry as being the largest non-commercial field in the
world. And we've talked about that for 50 years because nobody can figure out how to make money
off of that deal. So Sheffield says that they've got 10 billion barrels in the Spraberry. But
listen to his words; what is he really saying? He's got himself protected. He says that they've
got 10 billion net recoverable, resource potential. That's not a reserve.
Okay so what is a resource? Well a resource-and I'm going to the Society of Petroleum Engineers
here. The definition is a known and yet-to-be-discovered accumulation. It's vapor. We kind of know
it's there but we haven't found it yet. And so that's a resource, and now he's talking about a
resource potential. So it's not even a resource; it's a potential resource. So what he's saying is
that it's some vague number that we kind of think may be out there. And of course a resource has
nothing whatever to do with price. It's absolutely not – it doesn't have anything – it's any
price. It just says it's technically recoverable. So it means nothing, zero, zip. It means
nothing.
So he's covered. I'm about to publish something here maybe today and the sub title of this
section is called "It's not a lie if we tell you it's a lie." That's the name of the game. As long
as the investor presentation or the news release says somewhere that we're using language here
that we would never ever use in an SEC filing because they'd put us in jail. And so you guys need
to know that. In other words, "we're lying," then it's technically not a lie. It's not fraud
because we told you it was a lie.
... ... ...
Chris Martenson:
Well yes with over
200 trillion dollars of debt
outstanding of course you
have to service that debt and
high oil prices just don't
help that. The model I've
been working with for a long
time is there's a price of
oil at which the world
economy chokes and there's a
floor at which the energy
company's don't want to
pursue oil anymore and that
ceiling and that floor have
been coming closer and closer
together. So here we are,
we're clearly at a price
below which oil and natural
gas-in America here, I'm
staring at natural gas at
$1.83 is the quote I've got
on my screen right now,
yikes. That's way below the
all-in costs for most
companies that I've been
looking at.
But let's dial
this back a bit. Globally
we've see this astonishing
pull back in CAPEX spending
by the oil majors, by the
mids, the minors, national
oil companies, all of
them-over a trillion dollars,
by a bunch of estimates. Talk
to us about what's the impact
on future oil supplies with
this just absolute
destruction of CAPEX spending
globally?
Arthur Berman:
Somewhere between
profound and extreme
[laughter]. We've got to be
constantly discovering
several million barrels of
oil per day to make up for
our consumption. It's easy to
get confused and to say well
geez, we've got such an
oversupply right now, we
don't have to worry about
that.
Well we started
this conversation with your
important observation that
we're only talking about a
million or million and a half
barrels a day of oversupply.
So we could go from over
supply to deficit pretty
quickly
because we're
not investing in finding that
additional couple of million
barrels a day that we need to
be discovering. So we're
deferring major, major
investments and we're not
just deferring exploration,
we're deferring development
of proven reserves.
So
just the capital cuts in US
companies have effectively
deferred $20 billion-or maybe
the world, I'm sorry-$20
billion barrels of
development of known proven
reserves.
And so if we get to a
point- and we will, we almost
certainly will-where suddenly
everybody wakes up and says
"Oh my God we don't have
enough oil." We're now half a
million barrels a day low,
and what happens? The price
shoots up, okay? That's the
way commodity markets work.
And everybody says "Whoopee,
let's get back to drilling
big time."
Well there's a
big lag. There's a huge time
lag between when the price
responds and people actually
get around to drilling and
they actually start bringing
the oil onto the market and
it becomes available as
supply, because they've been
asleep at the wheel for how
many months or years. You
don't just turn a valve and
all of a sudden everything is
okay again.
We saw this during the
Libyan Civil War. Saudi
Arabia said "Don't worry
guys, we've got all this
spare capacity. We'll just
turn it on and produce it and
the world won't see a
shortage." It never happened
because they had to actually
drill wells. Their spare
capacity means they have got
to drill wells to produce it
and that takes time. They
have got to drill it, they
have to test it, they have to
build pipelines, and by the
time they actually got any of
that work done, the Libyan
conflict was over. We've now
seen low production because
the Civil War continues, but
that's another story.
There's this
tremendous gap between "okay
we know there's a reserve,"
but what's it take to turn it
into supply? Well it takes
time and it takes money and
it doesn't happen overnight.
Chris Martenson:
Well no and as you
mentioned it hasn't just been
the exploration but the more
pedestrian stuff like infill
drilling-that's pretty much
come to a complete halt in
the North Sea as far as I can
tell. And it looks like
Mexico is not doing a lot
with their investment down in
their plays at this point in
time, and Brazil doesn't even
begin to know how to get
started with their whole
Petrobras scandal and
drilling through those
really, really expensive deep
water finds they've got. Just
don't make any sense at this
price. So when I look across
really where the oil supply
growth is coming from, Art,
I'm pretty much-like it's
really down to the Middle
East and this hope that the
United States could rapidly
ramp up its shale "miracle"
if prices spike back up.
But I'm with you. I think
that as much as people are
focused on the oversupply
right now-and in two or three
years I'll be really
surprised, unless the world
economy crashes and demand
goes down, with that caveat
attached-I think the world
will be equally surprised by
the shortages that are
coming, because you can't
just… Here's what I see: I
look at this chart and I talk
about this in talks and I say
"Hey look from 2005 to 2012
the world spent about three
trillion dollars on upstream
oil and gas exploration and
production and basically got
the same amount of crude and
condensate out of ground for
its trouble," right? We
doubled our investment on a
yearly basis from $300 to
$600 billion and basically
held production flat. I can
only imagine what happens to
production once you take a
trillion in spend off of the
top of that.
Obviously it looks like to
me we're going to be facing a
multi-million barrel a day
shortfall, as long as things
don't fall apart on the world
economy stage.
Arthur Berman:
And I think even if
things do fall apart on the
world economy stage. I
haven't done this, because
the records aren't there, but
you go back to a period like
the Great Depression in the
world and it's not as if
people stopped buying and
selling goods or transporting
themselves or materials. It
was a big – it was a
depression, and there were a
lot of people out of work,
but the world moves along and
consumption of oil and
natural gas isn't going to go
to zero. I think the forecast
that we've just recently seen
from the International Energy
Agency just last week,
they're saying "okay so
demand is probably going to
be down from 1.8 million
barrels a day of growth to
1.2 million barrels a day of
growth," and that's awful.
But wait a minute, 1.2
million barrels a day of
growth is – you're still
growing at a fairly high
rate. So you have got to be
replenishing your supply or
else you reach this zero
point where you're in deep
trouble.
So I'm with you Chris.
Even in my darkest view of
where the economy could go, I
find myself on a very
different page than most of
the forecasters who think
that we're in for a decade or
decades of low oil prices. I
think we're going to be
struggling under the yolk of
much higher oil prices,
probably beginning next year.
I'm not a price forecaster
but it's hard for me to see-I
am a supply/demand kind of
guy and I would be very
surprised if by this time
next year we're not seeing
oil prices moving toward
something like $60 a barrel.
And you look at the forecast-
EIA
says average price in 2016
will be $53 a barrel. They're
not always right and in fact
they're often wrong but
they're not stupid either.
They're doing the best they
can. They have got some good
people there.
So I think
this notion that we're
somehow stuck in $30 or $40
oil forever and ever, it just
doesn't square with the
reality.
Chris Martenson:
Well it would mean
that we're anticipating that
oil is going to stay below
its marginal cost of
production for a very long
time. It's very difficult for
any commodity to stay there
for long but oil in
particular because of its
stock versus flows. Yes
there's 3 billion barrels
above ground right now but
hey, that's only so many days
of consumption if you decided
to stop producing. So yes,
I'm with you. I think that
obviously oil has to go up in
price at some point and
that's even exclusive of any
geopolitical accidents that
might happen in the Middle
East; just simple
supply/demand and all of
that.
If oil does go back up,
last question, you study the
companies that are involved
in this very carefully and I
think a lot of investors,
especially the banks who have
put the lines of credit out
there, are really double
fingers crossed hoping that
the price of oil moves back
up and all these problems
that these companies are
facing economically will sort
of be in the rear view
mirror. Would you share that
view or do you think that
even if oil rebounds there's
a number of companies here
that have gotten themselves
in over their heads with
respect to debt versus
assets?
Arthur Berman:
Well just turn the
clock back to 2012-2013 when
oil prices were sky high,
were $100 a barrel or more,
and what we saw was
consistent negative cash flow
from virtually all of the
major players. So what that
says is they weren't making
money when oil prices were
high, so is it a big shock
that they're hemorrhaging
when oil prices are lower? So
oil prices go back up-the
bottom line Chris is the only
way that they were able to
stay looking fairly good back
then to somebody, not me, was
that people were giving them
money. They had infinite
access to capital at almost
no cost, and so they were
spending it. But their income
statements and balance sheets
look like crap and the
investment community I guess
was willing to look past that
or didn't want to look at it
or whatever.
So rearview mirror? No,
these are companies that are
highly leveraged and unless
and until that changes-maybe
that's one of the positive
outcomes of this. Maybe we
see a turnover of players.
There are better companies
whose balance sheets look
better and they're the ones
who can afford to say "Okay,
we're going to slow down
production right now because
we don't have the same debt
service that the guy next
door does." So my hope is
that like all crises this is
going to flush out a lot of
the bad players, or at least
some of them. But will higher
oil prices solve the problem
and save the day for the
people that hold the debt?
No. It won't hurt, but if
they couldn't make a profit
at higher prices, going back
to higher prices doesn't fix
the problem.
Chris Martenson:
So for many of these
investors and players, in
many cases, the best that
they can hope for if oil
prices rise is a higher
recovery of cents on the
dollar, but they're probably
not going to get back to
whole on this?
Arthur Berman:
No. Unless somebody
is willing to forgive debt.
If we get that bad, then
there's the solution of last
recourse, right?
"... As I pointed out above, Q1 2016 wells were significantly more productive than Q1 2015 wells, in the wells' first 90 days or less. As time goes by, we will get a clearer picture of how much more oil they will produce during the critical 36-60 months when the wells need to payout. ..."
This is interesting and I realize goes against many here who view LTO as a plague, I think the
industry has it right, not the naysayers -- this is not to say the economies are like the East
Texas field, but it is to say given the alternatives best of class LTO played will be the focus
of activity/development coming out of this depression.
TT
That article (the referenced Reuters story describing a lessening of the decline curve) is only
the tip of the iceberg.
Many of the operators are catching on to what EOG has been doing with their fracs, namely scouring/sandblasting
the heck out of the near wellbore area with 100 mesh and then following up with larger proppant
to maintain conductivity.
In addition, the increased formation pressure induced by new fracs is increasing output in
nearby, older wells. This process has been repeated over and over again in numerous older wells
in the core of the Bakken now that the drilling has contracted to a fairly small, highly productive
area full of the older wells.
LTO is not a plague. The plague is development of same out of primarily debt, as opposed to primarily
out of cash flow.
As I pointed out above, Q1 2016 wells were significantly more productive than Q1 2015 wells,
in the wells' first 90 days or less. As time goes by, we will get a clearer picture of how much
more oil they will produce during the critical 36-60 months when the wells need to payout.
$50 WTI looks to be a very hard ceiling last couple of months.
More important is the money made available to drill, complete and equip them. The banks appear
to be wary. Equity investors like the Permian and SCOOP/STACK.
"... In a business as usual demand case (linear trends), Asia needs an additional 11 mb/d of oil imports (crude and products) by 2031. That oil would have to come from following sources ..."
In a business as usual demand case (linear trends), Asia needs an additional 11 mb/d of
oil imports (crude and products) by 2031. That oil would have to come from following sources
8.4 mb/d or 76% would have to come from taking away market share of other importing countries.
That's what the Asian Century will be all about.
"... The STEO has Colombia production holding at around 1 mmbpd for the next two years, but in fact they are declining at about 12% y-o-y ..."
"... Their internal consumption is rising fast as well and at this decline rate they could need to import within three or four years (Figures in chart from Reuters and Energy Ministry, one value for March 2015 looked a bit off so I interpolated). ..."
"... Note also for Norway May figures are down 87,000 bpd and a bigger drop expected for June, mainly for maintenance but overall they are now expected to be in decline again following a small secondary peak until Johan Sverdrup starts up in 2020. ..."
The STEO has Colombia production holding at around 1 mmbpd for the next two years, but in
fact they are declining at about 12% y-o-y (903 kbpd for May). Some might be due to sabotage,
but they have a low R/P ratio (2.2 Gb of reserves so only about 6 years) and rig counts have dropped
by 90% over the year.
I think they were using some EOR methods to boost production as well. Therefore a rapid decline
might not be unexpected. They might have some offshore oil, but only two exploration wells so
far, and both dry, and some shale potential (either way any production is at least 5 years away).
Their internal consumption is rising fast as well and at this decline rate they could need
to import within three or four years (Figures in chart from Reuters and Energy Ministry, one value
for March 2015 looked a bit off so I interpolated).
Note also for Norway May figures are down 87,000 bpd and a bigger drop expected for June,
mainly for maintenance but overall they are now expected to be in decline again following a small
secondary peak until Johan Sverdrup starts up in 2020.
The EIA's
Petroleum Supply Monthly is out with US and individual states production data through April,
2016.
The Petroleum Supply Monthly now agrees almost exactly with the Monthly Energy Review.
The Petroleum Supply Monthly has US production dropping 222,000 barrels per day in April. The
Monthly Energy Review has US production dropping 212,000 bpd in April and 148,000 bpd in May.
Texas production fell 47,000 barrels per day in April. Texas production is down 414,000 barrels
per day since peaking in March 2015.
Ron, are you able to post a graph comparing this peak to the 1970s and 1980s peaks?
I looked at the one on EIA website from 1920 to date, really shows how the shale boom rose
much more steeply, and looks poised to likewise fall much more steeply than in early 1970s or
mid 1980s.
This EIA site, Monthly
Crude Oil and Natural Gas Production , gives us the percentage change for the last month and
the last 12 months for the US and all states and other producing areas. The US was down 2.4%
in April and 7.9% since April of 2015. Texas was down 1.4% in April and down 10% since April
2015. North Dakota was down 6% in April and down 10.6% since April 2015. It looks like April was
just a catch up month for North Dakota.
"... China produced 7.4 percent less domestic crude oil in May compared to a year ago, settling at 16.76 million tonnes. This was due to plans by state-owned oil companies to slash output that is weighed down by languishing oil prices, official data showed. ..."
"... All the Chinese decline is not due to the price drop. China had peaked and would be in decline even if the price had stayed high. The price drop just made it a bit worse. ..."
China produced 7.4 percent less domestic crude oil in May compared to a year ago, settling
at 16.76 million tonnes. This was due to plans by state-owned oil companies to slash output that
is weighed down by languishing oil prices, official data showed.
Time for a special post on rate of decay from peak oil? I am not liking what I am seeing because
it matches quite well my [bad] outlook. Perhaps there is hope that prices will increase to a level
that will reduce the rate of fall. It is going to be very difficult to recover production.
All the Chinese decline is not due to the price drop. China had peaked and would be in decline
even if the price had stayed high. The price drop just made it a bit worse.
"... Higher declines were observed for several of the major non-OPEC countries such as Russia, United States, Canada and Norway in 2014 and 2015. For 2016, the decline is expected to continue increasing and in terms of barrels, this represents a 700 kbbl/d increase in the yearly decline from the mature oil fields. ..."
"... The 2016 report will be more interesting but it might not be issued and/or available for free for some time. For oil they give 168 Gb reserves and 12 Gb production – without any discovery, extension or purchase that would give 7.5% natural decline. ..."
Rystad Energy's latest analysis shows that, for the first time since the 1980s, we will have
two consecutive years of decreased global E&P investments. A lot of the investment cuts have been
related to new projects and shale drilling, but we have also observed lower activity on mature
producing fields. This decreased activity is starting to show on the production side, with the
decline rates starting to increase. Higher declines were observed for several of the major
non-OPEC countries such as Russia, United States, Canada and Norway in 2014 and 2015. For 2016,
the decline is expected to continue increasing and in terms of barrels, this represents a 700
kbbl/d increase in the yearly decline from the mature oil fields.
The 2016 report will be more interesting but it might not be issued and/or available for
free for some time. For oil they give 168 Gb reserves and 12 Gb production – without any discovery,
extension or purchase that would give 7.5% natural decline. I think that might be what's
coming in 2018 at current discovery and development levels (only covering 35% of production though,
NOCs should still be holding up better overall).
"... Imports are definitely rising. The three month NET imports of crude oil and petroleum products bottomed out last November at 4,661,000 barrels per day and last week stood at 5,890,000 bpd for an increase of 1,229,000 bpd. ..."
"... The fact that imports are rising even faster than production is declining is a sure sign that production is actually falling and not just an anomaly of the EIA's measuring algorithm. This decline is real people. ..."
Imports are definitely rising. The three month NET imports of crude oil and petroleum products
bottomed out last November at 4,661,000 barrels per day and last week stood at 5,890,000 bpd for
an increase of 1,229,000 bpd.
The fact that imports are rising even faster than production is declining is a sure sign that
production is actually falling and not just an anomaly of the EIA's measuring algorithm. This
decline is real people.
"... Looking at the drop in iranian export of 20% you would have to assume that the story is similar….which makes their approach/policy even more idiotic ..."
"... Ron, the Monthly energy review also gave an estimate for May natural gas plant liquids of 3,256,000 bpd. A decline of 258,000 bpd (7.3%) from April's estimate of 3,514,000 bpd. So, thats a decline of 406,000 bpd crude and ngpl. ..."
"... It is starting to look worrisome. US has lost almost 1 mbpd from peak and almost 0.5 mbpd in the last 5 months. It is looking as if US loses might constitute the bulk of the world oil production loses in 2016. ..."
The EIA's Monthly
Energy Review is out with US production numbers for May 2016. US production down 148,000 barrels
per day. US Lower 48 down 161,000 bpd, Alaska up 13,000 bpd.
Ron, the Monthly energy review also gave an estimate for May natural gas plant liquids of
3,256,000 bpd. A decline of 258,000 bpd (7.3%) from April's estimate of 3,514,000 bpd. So, thats
a decline of 406,000 bpd crude and ngpl.
Even if it is an estimate, thats a huge decline.
It is starting to look worrisome. US has lost almost 1 mbpd from peak and almost 0.5 mbpd
in the last 5 months. It is looking as if US loses might constitute the bulk of the world oil
production loses in 2016.
"... LTO development in rocks similar to the Bakken and Eagle Ford has a physical boundary, the recovery per well appears to be linked to fluid properties (the oil has to be low viscosity, a fairly high gas to oil ratio, and have above normal gradient pressure). The reservoir geometry has to allow drilling long horizontal wells, the zone can't be interbedded with water bearing sands, etc. ..."
"... When we screen reservoirs to account for these limits, add cost environment and economics, we see that outside the USA the prospective resources are slim. ..."
"... Where would these massive quantities of oil come from. There must be some huge hidden fields where nobody's looked! ..."
"... I'm still having trouble with the EIA estimate of 160 billion tons of US URR versus 32 billion tons produced to date. This would imply that US oil reserves are only 20% depleted after something like 150 years of intense extraction. Is this reasonable? ..."
The EIA doesnt know what its talking about. Rather than quoting the EIA you should try to look
up the prospective targets they include in their estimate, mention them, and then we can discuss
them individually.
LTO development in rocks similar to the Bakken and Eagle Ford has a physical boundary, the
recovery per well appears to be linked to fluid properties (the oil has to be low viscosity, a
fairly high gas to oil ratio, and have above normal gradient pressure). The reservoir geometry
has to allow drilling long horizontal wells, the zone can't be interbedded with water bearing
sands, etc.
When we screen reservoirs to account for these limits, add cost environment and economics,
we see that outside the USA the prospective resources are slim.
Test yourself with a simple exercise: why is LTO so anemic in Australia? It's a whole continent.
What about Canada? It has a very dynamic oil industry. Venezuela? It needs light oil desperately
to dilute the heavy oil. Mexico? Why can't it even develop Chicontepec? Colombia? It has a very
active oil industry…so what's wrong with them?
I can see viable developments in some high graded spots in Russia, Argentina, and a few other
locations. But the critical combination of properties just isn't that common.
The "oil" is C+C+NGL. Hubbert linearization results in an estimate of 2500 Gb (or 341 Gtoe)
of C+C less extra heavy (XH) oil. Jean Laherrrere estimates 500 Gb of XH oil so that's 2900 Gboe,
NGL URR will be about 400 Gboe, which brings the total to 3300 Gboe. Finally, there has been a
tendency for the HL method to underestimate URR (in 2005 the estimate was 2000 Gb) so I have added
300 Gb to account for this, bringing the total C+C+NGL URR to 3600 Gboe (or 490 Gtoe). Political
Economist's estimate for World C+C+NGL URR is about 500 Gtoe, fairly close to my "medium" scenario.
That does not mean Political Economist is correct, but Fernando thinks my medium scenario is
reasonable and he knows a thing or 2 about how oil is produced. I know far less than he does about
the practical ins and outs of the oil industry.
I'm still having trouble with the EIA estimate of 160 billion tons of US URR versus 32 billion
tons produced to date. This would imply that US oil reserves are only 20% depleted after something
like 150 years of intense extraction. Is this reasonable?
The US URR estimate is too high by about 100 Gtoe, but the rest of the World is too low by
about the same amount, the two errors cancel.
Political economist is interested in the World total
and that estimate is approximately correct. Remember that his estimate for "oil" includes NGL,
just like the BP production data.
The World C+C+NGL URR is expected to be about 500 Gtoe or about
3670 Gboe (assuming 7.33 boe per metric tonne of oil equivalent).
"... This new drop in oil price has to do with extreme financial instability and not with supply and demand. Everybody is pumping with full force regardless of price for various reasons. Price does not matter at this point. When Total went to buy Iranian oil it brought with them Airbus people to pay for the oil. ..."
"... you have to keep dancing even if you don't like the music. Look at the drop in US production in the last 1 year and that is still with 400-600 rigs running in the last year with all extra printed money (aka "new investors") being available to them. It's very bleak. ..."
"... At some point there can be shortages. That would be a game changer. Before that this is just kicking the can down the road. ..."
"... In a short term shortages will be avoided by removing credit to certain countries and certain segments of population in synchronized effort by major Central Banks so it will appear that there are no shortages. ..."
"... There is no shortage of oil in Greece but there is a shortage of credit. But if Greece wants independent policy they get threatened with a shutting down of their banking system. ..."
"... The Brexit marks the end of the ideological domination of this neoliberal economy. How long the disintegration process will last it is very hard to predict but it could be very short like in the case of Soviet system. ..."
Is there already a reaction in the oil countries, this should demotivate companies to pick
up drilling again, or creditors to hand out new billions to be buried in the rocks?
This new drop in oil price has to do with extreme financial instability and not with supply
and demand. Everybody is pumping with full force regardless of price for various reasons. Price
does not matter at this point. When Total went to buy Iranian oil it brought with them Airbus
people to pay for the oil.
NA producers are taking paper for oil because there is no other option and with negative interest
rates approaching it is a losing option even if the oil goes somehow to unimaginable price at
this point of $70-80. But if you stop drilling the game is over. So you have to keep dancing
even if you don't like the music. Look at the drop in US production in the last 1 year and that
is still with 400-600 rigs running in the last year with all extra printed money (aka "new investors")
being available to them. It's very bleak.
At some point there can be shortages. That would be a game changer. Before that this is
just kicking the can down the road.
Ves, 06/27/2016 at 10:14 pm
likbez,
In a short term shortages will be avoided by removing credit to certain countries and certain
segments of population in synchronized effort by major Central Banks so it will appear that there
are no shortages. That is why you see all the effort in creating big currency blocks that
could control emission of the currency. One of the reasons is to control oil consumption by the
center through credit emission. Then you depend on the center for credit emission.
There is no shortage of oil in Greece but there is a shortage of credit. But if Greece
wants independent policy they get threatened with a shutting down of their banking system.
So they are allocated certain amount of credit and that is their available oil foot print.
But it is the same in so called "rich" G7 countries where large segments of population live below
poverty line and that is because they don't have access to credit. That's why it was so easy to
pull Brexit stunt because elite already had very fertile ground to work with. Majority felt less
well off then 20 years ago. That is the main reason; all other reasons like EU bureaucracy, refugees
are just nonsense. Bureaucracy, refugees of course exist but these are just borrowed reasons that
they have been told to adopt on TV to frame the debate.
likbez, 06/28/2016 at 7:37 pm
Ves,
Allocation of credit works while there are growing economies. In this case this is a regular neoliberal
redistribution of wealth by other name. So countries with "exorbitant privilege" can just print
money while everyone else are the second class citizens who were robbed at daylight. Debt slaves
by other name.
But after conversion of most countries into debt slaves, in order for the system to work you need
positive GDP growth. Otherwise there is nothing to rob. Even if the GDP "growth" is fake and is
just an accounting trick based of underestimating of inflation or including in the total vices
like prostitution and gambling, the system can work. Get negative GDP for a substantial period
of time (secular negative growth) and all bets are off. Capitalism was not designed for such an
environment, and neoliberalism, which is just a modern flavor of corporatism, can't work either.
In shrinking economies allocation of the credit is like pushing on the string. You just can't
pay credit lines back in shrinking economies. That means financial collapse. Now what ?
Barter?
Ves, 06/28/2016 at 10:31 pm
" That means financial collapse.Now what ? Barter?"
Well, it looks to me we are watching collapse "LIVE". Look, the magnitude of Brexit is hardly
even understood or no-one seems comprehend the consequences. This is on the scale of fall of Berlin
wall in 1989 and shortly after the dissolution of the USSR in 1991.
The Brexit marks the end of the ideological domination of this neoliberal economy. How
long the disintegration process will last it is very hard to predict but it could be very short
like in the case of Soviet system.
Brexit is more response and break with Wall Street then EU in order to save what can be saved
and that is mainly finance of the City of London for probable Yuan trade in near future. So this
pretty much tells you where this is all going in terms of global trade.
In terms of debt that is straightforward "Debt that cannot be paid will not be paid".
In terms of trade it will be much smaller world for trade then in the past and with new sets
of rules.
I don't think it will be barter but it will start with clean slate and with a new currency
in the indebted countries.
"... It is also interesting to see how year over year % declines are leading the actual production data and indicate that the drop will march on much further. Even if drilling resumes, natgas production will not rise before year end due to the drilling time lag. ..."
Texas RRC data for April 2016 are out. As others will probably elaborate more on the data, I cannot
resist to show the interesting situation of Texan natgas production (see below chart), which is
in a stage of freefall and in complete contradiction to above scenarios for US natgas production.
It is also interesting to see how year over year % declines are leading the actual production
data and indicate that the drop will march on much further. Even if drilling resumes, natgas production
will not rise before year end due to the drilling time lag.
In the meantime, natgas prices continue to soar, smashing through USD 2.70. A heat wave in
the SouthWest helps as power burn will reach very likely 5.5 bcf/d over the next few days. Natgas
consumption soars despite – and in my view because of – high solar capacity in California. The
high solar capacity does not reduce natgas demand yet drives it to record highs.
"... You and SS (and others) have quite the inaccurate idea about shale company financing and the role of oil price on that. This type of linear/classical thinking (i.e.: "…price rose, so the banks must lent to the drillers now…") does not represent the reality today when loans to the drillers are used as futures' derivatives' bets and far, far, far exceed the ability of some of these companies to pay back their debt even if oil was to be $1.000/brl for the next 20 years. ..."
"... Much higher oil prices would give the shale folks the ABILITY to pay debt. Question is, wouldn't they drill more wells instead, and roll over the debt? So, what would happen if US, Europe and Japan just coordinated .25 rate hikes each quarter for the next three years? Would that result in a catastrophe? Rune Likvern , 06/16/2016 at 10:07 pm Shallow, What most oil companies [other companies/entities as well] did as they assumed more debt was in reality to enter into a bet that consumers would be able to access more credit/go deeper into debt to enable the oil companies to retire their debts which was assumed to pay for development of costlier oil. [Rollovers are not retirement.] ..."
"... Debt is borrowing from the future. ..."
"... "Some describes this process as transforming wealth into income." Or perhaps it's just transforming billionaires into trillionaires and leaving the rest where they are (or worse). ..."
"... If oil went to $100 WTI, and stayed there for 5 years, and gas went to $6 per mcf, and stayed there for five years, and if the shale companies determined to only spend enough CAPEX to maintain flat production, I think they could generally pay off, or at least substantially pay down debt, in that 5 year period. Some are better off than others. ..."
you get entangled so much in numbers, data and lines that you miss and/or
confuse the logical big picture.
-Before we enter price/brl/oil and financing of drillers into the equation
and, well before we then discuss if your's or somebodyelse's (i.e.: virwimp's)
are the more plausible scenarios and more likely to materialize, we have
to see if your chart stands logically and mathematically.
And looking at it, that can be only if the following conditions are met:
The "sweet spot/s" of Bakken has not yet been found and it will
be in 2019-2020.
The "i-gadgets" of fracking technology have gotten so advanced by
2019-2020 that we can expects wells then to have 30-50-70% more output/day
than the comparable well of 2014-2015 (% are for illustration only,
I have not crunched the numbers to be precise).
Judging by that almost plateau-ish curb top you have on your production
line 2020-2025, the decline rates of wells in 2020-2025 are far, far.
far less than those of comparable wells of 2014-2015.
All of the above
Now, can you (or anyone who knows a thing, or two about oil and mathematics
for that matter) explain and defend the above scenario logically and scientifically?
Don't you see to much magic and wishful thinking?
If you can do that (explain logically and scientifically), then and only
then I will engage in the price/financing debate with you and after that,
in the one that discusses which is the most plausible to represent reality
10-20-30 years in the future.
Be well,
Petro
P.S.: You and SS (and others) have quite the inaccurate idea about
shale company financing and the role of oil price on that.
This type of linear/classical thinking (i.e.: "…price rose, so the banks
must lent to the drillers now…") does not represent the reality today when
loans to the drillers are used as futures' derivatives' bets and far, far,
far exceed the ability of some of these companies to pay back their debt
even if oil was to be $1.000/brl for the next 20 years.
But that is a very complex matter which you (and I am not being offensive
here…believe me!) and almost all here cannot understand easily, so I will
leave that for another day.
Much higher oil prices would give the shale folks the ABILITY to pay
debt. Question is, wouldn't they drill more wells instead, and roll over
the debt?
So, what would happen if US, Europe and Japan just coordinated .25
rate hikes each quarter for the next three years?
What most oil companies [other companies/entities as well] did as
they assumed more debt was in reality to enter into a bet that consumers
would be able to access more credit/go deeper into debt to enable the oil
companies to retire their debts which was assumed to pay for development
of costlier oil. [Rollovers are not retirement.]
Central banks lowering the interest rate [described as interest suppression
by many] served several purposes like easing services of existing debt overhang
and allow for further debt expansion in an effort to bring our economies
back on the [economic] growth trajectory.
Debt is borrowing from the future.
Increasing the interest rate as described by a quarter percent over 3
years would introduce severe strain on the system as it becomes harder to
service the present huge debt overhang and make it hard for anyone to assume
more debt [it would likely blow out many balance sheets].
The Fed now keeps deferring further increases to the feds funds rate.
The Fed is worried about what an increase could entail.
In short a higher interest rate would bring the oil price down as more income
becomes diverted to servicing debts and thus less available to pay for amongst
other things higher priced oil.
First you described the interest rate with raising it a quarter percent
each quarter over 3 years. (Something became omitted in my reply, but it
looks like the objective of the discussion was sustained.)
What you describe about those who live on income from their own savings
or pension funds I agree with, lower interest rates now wreaks havoc with
many pension plans and also the insurance industry.
I also agree that ultra low rates have caused misallocation of capital.
Yield starved investors started chasing riskier projects/investments.
To me this illustrates that there is no easy fix to the interest dilemma.
Damned if interest rates are raised and damned if they are not.
Low rates have led to capital destruction, I agree.
Some describes this process as transforming wealth into income.
"Some describes this process as transforming wealth into income." Or
perhaps it's just transforming billionaires into trillionaires and leaving
the rest where they are (or worse).
"Much higher oil prices would give the shale folks the ABILITY to pay debt."
-NO.
Debt is at unsustainable levels. You seem to have missed the P.S. section
of the comment of mine you replied to. I suggest you revisit it.
"Question is, wouldn't they drill more wells instead, and roll over the
debt?"
-That is NOT the question. That is the ONLY thing they can do with higher
oil prices at this point.
"So, what would happen if US, Europe and Japan just coordinated .25 rate
hikes each quarter for the next three years?
Would that result in a catastrophe?"
Folks who say: "ahh, what's a .25% increase to our economy? Nothing…let
the FED do that…" know nothing about the economy and finance. Do not waste
your time listening to them.
As I said this is a very complex matter, but for now let me tell you that
the economy and finance work NOT on nominal rates (the famous FED rate,
or BOJ rate or ECB rate you hear about on TV and how they manipulate it…ha,
ha, ha…), but on REAL interest rates …which are totally a different beast.
If the FED, BOJ and ECB did what you suggest and in a coordinated matter
increased the nominal rate .25% every quarter we would literally plunge
into the dark ages in short, very short order!!!!
Who tells you otherwise is an idiot.
Forget about the "PONZI FIAT money scheme" and the "FED MANIPULATION" you
hear from obviously "experts" on the matter here and elsewhere….
FED, BOJ and ECB have NO choice but to lower the rates and print digits/money.
Again, I cannot stress this enough:
who tells you otherwise, and who tells you that (at this point in time)
we can go to a gold standard, or some kind responsible debt reduction economy
knows nothing of today's economy and finance and is an idiot.
And NO, this has nothing to do with some kind of Marxist redistribution
of wealth.
Even if we somehow did that, we would still be in the same place in the
near future.
It is human nature and the behavior of our inner human animal.
That is why a while back – when everybody was saying that FED is increasing
rates and rates will go up – I told you: " 10year note is going to 1% BEFORE
going to 3% like everybody says…."
….and perhaps is going to 0% soon.
Expect no more rate increases and going back to QE (with other names perhaps)
– NOT because the FED is evil (as you hear here all the time) but because
there is NO other choice!
Rates shall spike up in the future, but when they do is time to go underground
with our loved ones, a loaf of bread, a gun and pray….if you believe that
is'
Pay, pray, pray that Yellen, Kuroda and Draghi go each month on TV and
bullshit us some more, for if they do not …..well let's just say that we
will not have computers to reply to each other anymore…..
"Rates shall spike up in the future, but when they do is time to go underground
with our loved ones, a loaf of bread, a gun and pray….if you believe that
is'"
Petro ….'a' gun come now. all things being equal i think I will have
a couple of semi auto, as well as revolvers, pump action and double barrels.
Ironic so many here can make a reasoned case for civil breakdown and at
the same time want to restrict guns of law abiding citizens. I suspect your
analysis posted here is more realistic than many others, the timing issue
is the real question. Next up more QE and then helicopter money!
If oil went to $100 WTI, and stayed there for 5 years, and gas went
to $6 per mcf, and stayed there for five years, and if the shale companies
determined to only spend enough CAPEX to maintain flat production, I think
they could generally pay off, or at least substantially pay down debt, in
that 5 year period. Some are better off than others.
I suspect costs would rise, both LOE and CAPEX, but I will do an example.
Shale R Us has 200,000 BOE per day, 80% oil 20% gas. So, lets say after
well head discounts, they get $85 per BOE. LOE is $8. G & A is $3. They
have to spend $20 per BOE in CAPEX to keep production at 200,000 BOE per
day ($1.46 billion per year). Severance tax is 10%. They have $3 billion
of debt, interest rate is 6%.
By my calculations, over five years, Shale R Us generates $16.6075 billion
of pre-tax and pre-interest cash flow in this scenario. There is $900 million
of interest that has to be paid, plus the $3 billion of principal. Assuming
income tax of 35%, subtract about $5.5 billion for income tax.
I come up with Shale R Us having $7.2 billion left in this scenario,
at the end of five years after payment of income tax, principal and interest.
I did this quickly, so if there are computational errors, let me know
and I will correct them.
Now, my example is of a strong company. Most wont work out that well,
but they can pay the debt off at $100 WTI plus $6 gas.
Petro, you are either talking over my head and/or we are talking past
each other. I am not considering what those prices do to the world economy,
demand, etc., only whether Shale R Us can eliminate their debt.
Sorry if I am too dense to follow how $1,000 oil for 20 years would not
cause all the LTO companies to mint money. Again, not talking about the
economy, etc. Just doing math, really.
you are falling in the same trap as Dennis: getting entangled in too
much data.
Yes indeed, as you say, I am talking way above your head here.
Now before you hate me, trust me I mean no disrespect.
But the subject is such….so please stay with me.
What you are asking me is another difficult and long answer.
I either have to do that post I mentioned about debt and money, or stop
answering and replying.
First of, you have the wrong idea as to how the financing of shale drillers
happens.
The way you think it happens (i.e.: they go to bank, present their business
model and oil price expectations and blah, blah , blah and bingo….Goldman
gives them the money!) does not exist anymore.
It indeed happened that way (more or less, of course I am simplifying) PRIOR
to 2000 – not today.
Goldman (or any bank…put the name you like here) uses the oil price and
business model of the sale player ONLY to bullshit the shareholders into
voting it…..it does not give a crap what the company does and how it does
it and at what price.
Here where the "beauty" starts:
that loan then, which on bank's balance sheet is considered an asset, is
re-hypothecated dozens, upon dozens, upon dozens of times as a futures'
OTC derivatives' bet with businesses that have nothing to do with shale
players and are half a world away – china let's say.
So, if one too many of them fail, driven out of business by responsible
guys like you – even though their combined debt size is nothing compared
to….oh, lets say JP Morgans' assets, the avalanche it starts buries us all.
You are thinking in terms of only one good company – that my friend is
linear/classical thinking.
Is like this: the risk increased by 2 times so the outcome shall be 2 times
worse or maybe 4.
That to you (and most) is manageable if you tighten your belt and plan well.
-But our economy and our energy/finance system is a COMPLEX INTERCONNECTED
SYSTEM.
That means that small stimuli, bring about exponentially worse and uncontrollable
outcomes.
Its like Lehman Bros. in 2008.
Their assets and liabilities were nothing compared to the whole economy…..but
the cascade they would have started would have plunged the entire global
finance/economy into dark ages within hours…literally.
So, contrary to what you have learned by "experts" here that: "…the Evil
FED helped their crony bodies and destroyed the economy…ha, ha , ha…", if
the 1st QE aka TARP did not happened, we literally would have eaten each
other as food by now (walking dead type thing….ish).
DEBT cannot be eliminated.
It has to increase more and more if you would like to continue the life
you have.
If we eliminate debt, we eliminate money including that $100 that you like
to get per barrel of your own oil…………it cannot be!
Stick that in your head.
Petro. I'd like to see a post from you. I doubt you'd get blasted, and if
you do, so what? If anything, I kind of enjoy debating this stuff with someone
on the other side.
Couple of questions.
First, you talk about shareholders approving loans. I am assuming you
just misspoke, as shareholders of banks do not approve of anything, except
voting on directors, some compensation issues, and sometimes stuff put on
proxy cards by activists (i.e. divest of fossil fuel loans LOL!)
Second, I did not think that reserve based energy loans were being packaged
and sold in derivative markets, at least not like home mortgages were. I
also was unaware banks were insuring them to a large extent with CDS's.
My understanding is there is a consortium of banks on most of these,
with one bank as lead, the others each taking a participating percentage.
The note is secured by a first lien on the shale company assets. The size
of the loan is based on the PV10 (or PV9) of the assets, with PDP valued
at 100% and with PDNP, PDBP and PUD possibly being given some collateral
value, but being greatly discounted, say for PUD, maybe assigned only 20-30%
of PV10.
The maximum amount that may be extended should be no more than 65% of
PV10 or PV9. If the value of the reserves drops, the borrowing base is cut.
Petro, you probably know all this stuff, maybe more in depth than me.
I'm posting this for other's benefit.
The game the shale guys played in 2010-2014 was to fill up the first
lien bank line, then float an unsecured bond to pay it off. Most shale guys
did this several times. I assume it is on these unsecured bonds, where credit
default swaps (insurance) was likely sold, where you think there will be
a black swan event? My understanding is this junk is a small fraction of
what the mortgage derivative market was and still is. Many of these bonds
have defaulted, or are at extreme stress levels already.
Would seem to me, given oil cratered to the $20s in early 2016, we would
have seen signs of the black swan, maybe we did, as the markets fell, almost
perfect correlation with oil, which has now, somewhat broken.
However, if we take my hypothetical $100 WTI and $6 HH per mcf, how do
those CDS on shale bonds cause any problems?
Also, back to the horse and pony show with regard to bank loans, I am
not so sure how much puffery there has been. It really depends on how the
engineering firm did the reserve report, and if the bank's price deck utilized
was realistic.
I will say, unlike the mortgage meltdown, where there were fraudulent
appraisals all over the place, there are not a lot of petroleum engineering
firms, and they are not fly by night outfits.
I will also say, it seems to me energy lending is pretty specialized,
there weren't energy loan brokers setting up shop on every street corner
and advertising on late night cable TV. Mostly big banks, or large regionals,
in this market.
Finally, these loans are not of the $150K mortgage variety. When the
bank examiners come, they look into the big loans much more closely. Easier
for OCC to examine 10 billion $ worth of 10 reserve backed energy loans
than $10 billion $ of home mortgages, of which there would be 50-100K individual
loan files, appraisals, etc.
Where the OCC screwed up was by not figuring in the junior debt when
they examined the bank loans. But, they finally are now, and that is a big
deal IMO.
The way I see it, if WTI hits $100 2017-2021, and gas is $6 during the
same time, and the shale knuckleheads have learned something from the most
recent Arab OPEC "good sweating" and don't overdo it, they mostly pay down
substantially/payoff debt.
I'm talking Newfield, QEP, OXY, PXD, EGN, EOG, COP, MRO, WPX, SM, HES,
APA, APC, XEC, FANG, MTDR, DVN and a few others. CLR and WLL would pay down,
but not off. Same with OAS. CHK too. The few MLP that have survived thus
far, would also at least pay down, but think they are required to distribute
most cash flow.
Oil at $125 for five years, they about all get out of debt IMO.
And, in the event this happens, these guys would be well advised to just
issue equity to grow, going forward. Where price wont help them is when
the locations run out. Especially the good ones. Better to have little to
no debt when that happens, which is probably by 2021, even if these dudes
are more sane about development.
Keep in mind, in my example, the pre-tax, pre-interest profit margin
is $45.5 per BOE. Right now, and pretty much since Thanksgiving, 2014 unhedged
profit margin has been less than zero.
I agree, the world economy is screwed up. But, I think I am going to
need some more detail to figure out what you are saying. I also do not think
TARP was bad. Clueless described TARP very well recently.
Don't worry about offending me, I'm called a lot of stuff and don't care.
Know who I am pretty well. Would really like a post, but understand if you
don't. Its kind of daunting.
I am just going to touch a couple of points only.
First, as far as offending you:
yeah, you might have been called names and have a thick skin, but I do not
want to go that route to begin with.
Not because you don't care, but because I do not offend people…intentionally
that is.
So, I said that to warn you that if it comes out that way, it is not my
intention.
Second, I did not misspeak.
I already spent too much time comenting and I went short, obviously way
short.
I meant they'd have it on the books in order in case something happened,
or somebody inquired, or to present their "strategy" at their shareholders
or their newsletters for investors (i.e.: Goldmans' outlook on the oil market….and
BS like that)
Most of the big guys repackaged and resold those loand to greater fools
way, way before oil price rout started.
They own very little directly……
However – and this is the important part – they are affected by them indirectly
by other companies derivatives which have direct exposure to the loans presently.
Think of it as: you fire a gun at a target in front of you, but it makes
10 ricochets at the walls and trees and what not around and comes back and
kills you.
Third, as the result of the repeal of Glass_Stegal in 1999 – thank you
very much R. Rubin, L. Summers and most importantly our dear B.Clinton who
signed it into law
(don't fuss democrats. For me there is NO difference between republicrats
and democlicans. Reagan and Bush were as bad, or worse!) – commercial and
investment banking became one and all and turned to what's called TRANSACTIONAL
banking.
Meaning: everything, without exception is repackaged and resold multiple
times to grater fools.
Forth, the task of a post is not daunting!
heck, I have posted here in the last 2-3 years to last me for 3 posts.
It is first that, even knowledgeable, well meaning people have preset concepts
that they are not willing to change.
I mean, look at the amount of time I am spending replying to you and you
ask me the same things…..does "linear/classical" thinking ring a bell?
You wrote it yourself: "Hard to change long held views".
and second, some people act as experts in things they know nothing about….and
they are going to reply to me with stupid: "evil FED" , "Real Gold Money
vs. Fiat" and " Rockefeller- Rothchild cospiracy" bull shit…………………………………….
and I am not sure I can handle that politely…………………..
…and then you have Nik Gs and the rest who think that oil and energy are
just like any other commodity and we somehow can do without them and so
on and so on…..
You get my point….
" repeal of Glass_Stegal in 1999 – thank you very much R. Rubin, L. Summers
and most importantly our dear B.Clinton who signed it into law
(don't fuss democrats. For me there is NO difference between republicrats
and democlicans."
Petro, you are one heap big smart fella, or else I am a mental midget.
I just can't see any way you are wrong.
The key problem with our current two party political set up is that both
parties were long ago captured by Wall Street type interests.
Political reform on the grand scale would help immensely, but political
reform is not enough to solve the overshoot problem.
Also, I should point out my banking experience is with a small, local
bank, privately traded shares, less than 500 shareholders. The stock price
barely moves, however it has slowly ground upward over time. Has always
paid a dividend which has been 4-5% of share price.
The bank makes fixed rate mortgages, which it sells off to Fannie or
Freddie, but retains all servicing. It retains all other loans in house,
such as auto, Ag, small business, rental real estate. It has a few larger
customers where it has to participate with others, and occasional will participate
with other banks on loans the others originate.
The 2008 financial crisis did not affect it. No one sold their shares
anymore than usual, the stock price didn't drop.
The only real thing they do which was prohibited by Glass Stegal is they
have an in house stock broker, where customers hold brokerage accounts.
I don't see that as a problem, and that service ties in well with the primary
duty of being a trust officer.
The primary problem in the aftermath of 2008 is the banks cost of compliance
went up.
So, you can see, my background in this area is very foreign. I am coming
from a totally different view, so yours, or any other serious and on topic
views are appreciated. My views are very 1980s, I remember when a bank in
one town could not open a branch in the next town over.
I continue to be surprised that interest rates "have not risen on their
own".
Petro,
Thanks for your interesting contributions and viewpoints to this debate.
I believe we are headed for some non linear events and the thing is the
human brains are NOT evolved/trained to think in non linear terms. We tend
to extrapolate past experiences into the future with some noise around a
constructed [wished for] trend line.
Looking forward to your future elaborations on this subject.
"... As for damage, that will be the final proof of what has been happening. I will be watching Rune's graphs to see if the recent years start to drop below previous years totals. ..."
"... There was a great summary by somebody else a few posts back. The big issue is that you have condensate get into gasphase inside the reservoir. This in turn will result in more "stranded" oil. I fear we will only see the results later this year/2017. I would expect the production rates to drop of steeper than before and result in lower ultimate recoveries (but i know conventional plays much better). Maybe somebody with more knowledge can chime in? ..."
"... As for damaged wells. We will just have to wait for the data to come in. April's decreasing GOR has given me confidence in my original suspicions of over producing wells. Not sure how keen Shallow will be pumping dead oil from 10,000 ft TVD and 20,000 ft MD. At least there will be plenty of wells to experiment with, until you can make it work! ..."
"... Although it intrigues me, don't worry, we will leave the deep stuff to someone else. Low volume wells that produce little to no water can work even in a low price environment. ..."
"... Besides the costs in the event of a down hole failure being down right frightening, it has not been determined where these wells will settle out in years 10-30+ ..."
I believe you are in the patch? Do you have any on the ground experience
you can relate? As for damage, that will be the final proof of what
has been happening. I will be watching Rune's graphs to see if the recent
years start to drop below previous years totals.
There was a great summary by somebody else a few posts back. The big
issue is that you have condensate get into gasphase inside the reservoir.
This in turn will result in more "stranded" oil. I fear we will only see
the results later this year/2017. I would expect the production rates to
drop of steeper than before and result in lower ultimate recoveries (but
i know conventional plays much better). Maybe somebody with more knowledge
can chime in?
You raised an interesting point. Everybody that bothers to write on these
blogs, that have any hands on experience, all seem to be from the conventional
oil field. Either the shale players, are not interested, or are keeping
a big secret. Smiles.
I would really love to hear some real inside info. I am sure a lot of
speculation could be put to rest very quickly.
As for damaged wells. We will just have to wait for the data to come
in. April's decreasing GOR has given me confidence in my original suspicions
of over producing wells. Not sure how keen Shallow will be pumping dead
oil from 10,000 ft TVD and 20,000 ft MD. At least there will be plenty of
wells to experiment with, until you can make it work! lol
Although it intrigues me, don't worry, we will leave the deep stuff
to someone else. Low volume wells that produce little to no water can work
even in a low price environment.
Besides the costs in the event of a down hole failure being down
right frightening, it has not been determined where these wells will settle
out in years 10-30+.
"... Furthermore, the U.S. Energy Sector is paying at least 50% of its operating profit now to just pay the interest on the debt. Q1 2016, it was 86% of their operation income just to pay the interest on the debt. ..."
"... Unless Uncle Sam comes in and BAILS OUT the U.S. Energy Sector, it's in serious trouble. ..."
I find it interesting that the U.S. Energy Sector now has twice as much debt as it did ten
years ago at $370 billion… as production declines.
Furthermore, the U.S. Energy Sector is paying at least 50% of its operating profit now to just
pay the interest on the debt. Q1 2016, it was 86% of their operation income just to pay the interest
on the debt.
Unless Uncle Sam comes in and BAILS OUT the U.S. Energy Sector, it's in serious trouble.
"... Slight aside, but just a comment on the public understanding of energy issues- I engaged with a senate candidate recently regarding a comment she made at a public debate. She exclaimed that one way the USA should work to contain Putin was to export energy to Europe so they are not hostage to Russian energy supply. I later pointed put to her that she ought to study up on energy some more, since we are big importers of energy. She said she had been hearing that we are approaching independence on energy. I was very surprised by her lack of understanding of this critical issue, since in other respects I found her to be very smart and well studied. Goes to show that people generally hear what they want to hear, or they simply swallow the most convenient truth. And this includes our policy makers, our voters, and ourselves. ..."
"... Look at the second to last slide "Resilience of the three American gas plays (UFDsim)" decline around 15% during the first four years for shale gas. We live in interesting times. ..."
Slight aside, but just a comment on the public understanding of energy issues-
I engaged with a senate candidate recently regarding a comment she made at a public debate.
She exclaimed that one way the USA should work to contain Putin was to export energy to Europe
so they are not hostage to Russian energy supply. I later pointed put to her that she ought to study up on energy some more, since we are big
importers of energy. She said she had been hearing that we are approaching independence on energy.
I was very surprised by her lack of understanding of this critical issue, since in other respects
I found her to be very smart and well studied.
Goes to show that people generally hear what they want to hear, or they simply swallow the
most convenient truth. And this includes our policy makers, our voters, and ourselves.
[Hi Petro- this also explains my wooden nickel vote, wrong though it may be]
When 180 new wells per month were being added output was increasing, when new wells added fell
the output flattened. New well EUR has been going up in 2014 and 2015, the current wells have
been performing better over the first 12 months of output than earlier wells so fewer wells are
needed to increase output. With current average wells about 105 new wells per month is enough
to increase output.
The EUR of the average well increased from 2013 to 2015, especially over the first 24 months
of output, the well profile was adjusted upwards to reflect this (and to get the model to match
actual output), it had been running "low" for several months. A steady 150 new wells per month
using the 400 kb well profile I had constructed would result in 1300 kb/d.
The well profile could be too high, an alternative scenario uses a 366 kb well profile (which
matches pretty well the 12 month increase in output we see with recent wells compared to the 2008
to 2015 average well with EUR of 350 kb). That alternative is up thread. When oil prices go up,
financing will be available.
The average 12 month completion rate was 177 new wells per month (centered average) in Dec
2014 when ND Bakken/TF output peaked at 1163 kb/d. This was enough to raise output by 300 kb/d
from Dec 2013 to Dec 2014, if fewer wells had been completed (for example and average of 150 new
wells per month), the rate of increase in output would have been smaller. By July 2015 the centered
12 month average completion rate had fallen to 148 new wells per month, but output had only fallen
by 13 kb/d (1150 kb/d).
Only 105 new wells per month after July 2015 would have been enough to keep output rising.
A scenario with 105 wells added after 2017 shown below. You won't believe this, but only 105 wells
per month are needed to increase output, at least for a time.
The difference is simply the number of wells added per month. There is no a priori reason that
the number of new wells will be limited to 105 new wells per month, perhaps there will be no financing
available, but I doubt this would be a problem for Statoil or Exxon Mobil, they can do this out
of cash flow if needed.
I also doubt that oil prices will remain under $80/b long term (more than 5 years). I expect
by 2021, oil at $80/b(2016$) will be considered cheap.
A different view from a Total engineer, looks to be using proprietary modeling software. Seems
to capture the possibility of a fatter tail than the logistic curve does, but has already missed
the flat peak area:
Look at the second to last slide "Resilience of the three American gas plays (UFDsim)" decline
around 15% during the first four years for shale gas. We live in interesting times.
Higher borrowing costs and tighter lending standards will act to restrain growth in the Bakken
going forward and along with continued advances in alternatives may well make it unlikely to
peak higher. Prices however can go substantially higher before restraining U.S. growth
than they could in 2008 since the economy has changed.
New vehicle efficiency alone increased 25 percent:
http://www.umich.edu/~umtriswt/img/EDI_mpg_May-2016.png
Power burn stands at an all time high and up over 20% from last year. In addition, huge
write downs of the industry of 40 Tcf for 2015, which – including oil – brought overall impairments
to over 10 bn boe (or USD 500 bn loss for investors in 2015) reduced investors appetite for
new investments. How many investors are left ready to lose another 500 bn on write downs alone?
On the other hand, the growing market share for wind and solar triggered massively demand
for natural gas which reached an all time high market share of 35%.
If there is a hot summer this year, power burn could go over 40 bcf/d and maybe even
reach 50bcf/d for some days.
The consequence would be the first significant stock draw over the summer, which for
sure will have an impact on prices.
This is only a little surprise. This decline takes away the surplus that was built up during the
last two months (Fabruari and March) compared to the Season Effect Model. I was rather surprised
by the modest declines those last two months.
I try to attach the graph once more to this comment (or I will ask Ron for support).
You can clearly see the dataset crosses the modelled line for the sixth time now. The first
derivative of the model and the change of the data are still within the same error range as prior
to the moment the model was built.
Difference between the model and the data is -2.4% now. The age of the model is 29 months now.
Excellent chart. Just wanted to let you know that you were one of the few who presented the
CORRECT Bakken chart in this blog. There may have been others, but well done. Jean Laherrere and
Tad Patzek both have the same Bakken production profile as yours.
By 2025, the United States will be pumping 75% less oil than it is today. It will be interesting
to see how we run the LEECH & SPEND SERVICE ECONOMY on that little amount of oil. Americans who
think we will be able to exchange worthless paper dollars or Treasuries for oil at that time,
better stop sniffing the glue.
"... Some commentators have asserted that the 2008 financial crises was due to high fuel costs, and not necessarily due to the cascading collapse of Wall Street financial legerdemain (although this undoubtedly helped fan the flames). ..."
"... Social Security is a big part of the "unfunded liabilities". That's a transfer. It's not available to the working person who gets it deducted from their paycheck, but it's available to the retiree who gets it. And, the retiree is more likely to spend it. ..."
Thank you for your excellent reply, and as Cracker says the extensive work you've done provide
a constructive counter to the less optimistic among us, of which I am one.
I am with Cracker in that I think your charts are chronically optimistically lopsided, but
held my opinion on this for a long time until now.
The resources amounting to URR 8-9.2GB of oil as you surmise may indeed be there, however I
remain highly skeptical of this reported volume for a variety of reasons.
At the end of the day, whether the URR of 8-9.2GB is there or not, I am of the opinion that
only a fraction of it will ever be recovered and the true amount never realized. The reason is
that the condition of the world economy won't support anything higher than $50 based on what I've
seen this year. To wit;
1. Student and consumer debt is at an all-time high, compounded with the problem that most
highly paid jobs are disappearing for the middle class . The June 2016 jobs report was pretty
lackluster, with a +38,000 nonfarm payroll jobs increase reported. It is to be noted that the
civilian long term unemployed has changed little at about 7.4 million.
2. Most driving is of itself for non-productive activities, and includes travel to jobs
that are generally non-productive. If fuel gets more expensive, I expect that much of this
non-essential travel will drop off. Some commentators have asserted that the 2008 financial
crises was due to high fuel costs, and not necessarily due to the cascading collapse of Wall Street
financial legerdemain (although this undoubtedly helped fan the flames).
3. The FED has pumped over $4 trillion of cash into the US economy, but the net benefit
is estimated to be less than $1 trillion to GDP. It is unknown how the FED is going to unload
this pure dreck on its books, and I suspect that it will not comport with higher oil prices in
the cogs and wheels of the economy;
4. US debt is at a fantastic level of $19.3 trillion, with another $67 trillion of unfunded
liabilities on the books. It's hard to see how this debt will be reduced to manageable levels
with higher oil prices.
5. An Internet 2.0, or some other economically transformative technology, doesn't appear
to be on the horizon. Currently, all we know how to do is burn fuel, heat a working fluid,
and use it to drive a piston or turbine. The alternatives, such as solar and wind, will only come
on as oil heads into it's retirement party.
6. Related to point #1; if the current trend to transfer jobs over to automation continues,
it's hard to see how there will be people driving to their (former) employment, and for that matter
afford things that are (of course) produced by petroleum;
7. For what it's worth, I think that the 2008 crises hasn't gone away despite massive money
printing efforts. They're trying to keep demand artificially supported with easy money and
the incurring of unrepayable debt, which is terrifyingly criminal as it is simply passed unto
the very young and the unborn. How can we expect them to pay our debts and then go out and buy
fuel, when their jobs have been outsourced and/or automated? The whole thing has gone far over
the top and is way beyond the point of no return. As mentioned previously, I see no significant
industrial (i.e inventive) development or for that matter, improvements in demographics that will
turn this around.
So at the end of all this, I think that baring hyperinflation the prospects for oil over $50-$55
for the next couple of years is looking fairly dim. Hence, that claimed 8-9.2 GB UR is not going
to be realized in real production.
There are many that are very pessimistic about the economy. Unfunded liabilities are not the
same as debt, so I don't count those.
The retirement age can be raised and eventually the US will follow the rest of the advanced
economies and reform the health care system to control costs.
(First we need to exhaust all other possibilities, before doing the right thing.)
Note that my scenario has oil prices rising very gradually. Also oil prices were over $100/b
for 3 years with the World economy continuing to grow.
All that money printing has had very little positive or negative effect, mostly the velocity
of money has slowed because most of that money is just sitting in bank accounts. Inflation is
not high, if it were the Fed would simply reduce the money supply.
A debt of $19 trillion for an economy with an income of $18.2 trillion is not really a problem.
A debt free consumer with a good credit rating and a 20% down payment in savings can typically
borrow up to 3 times their income for a mortgage. The US government debt is at 104% based on fred
data.
According to BIS for the US total non-financial sector debt is about 250% of GDP.
For all counties that report to the Bank for International Settlements (BIS) the total non-financial
sector debt to GDP was 235% in the fourth quarter of 2015 (most recent data point) at market weighted
exchange rates. (220% using PPP weighted exchange rates.) See
"Unfunded liabilities are not the same as debt, so I don't count those."
I'd like to point out that both of these things act as a dead weight on a chain that must be
carried by those who are working and generating income, as we go forward in time.
And income, or savings derived from it, must then be used to service the debt and pay for the
liabilities/entitlements.
This is money that then cannot go towards buying fuel, or funding innovation and transition- things
like EV, solar, etc.
A dead weight is a dead weight.
And going into a crisis you have a better chance of surviving it if you are lean and mean, not
if you have this ugly balance sheet. It doesn't help that most of the worlds countries are in
poor shape in this regard as well.
I have to agree with Mike Sutherlands view that these factors could very well decrease the URR
significantly.
On the other hand, the other 7 Billion people of the world will keep increasing their demand
and, along with depletion, this will leave less cheap oil for the USA to import. This will tend
to raise the price here.
These are conflicting forces, and I think we will end up with a scenario with both lower URR
of these domestic sources, and yet also higher prices. Good for solar/wind I suppose- if we can
afford it.
Very tough on the average family and local businesses.
Social Security is a big part of the "unfunded liabilities". That's a transfer. It's not available
to the working person who gets it deducted from their paycheck, but it's available to the retiree
who gets it. And, the retiree is more likely to spend it.
So, SS doesn't slow down the economy, it helps it.
Transferring money from a working family to a retired one doesn't help the economy, it helps the
elderly person, and hurts the working family (in the here and now).
Its overall pretty neutral, but it surely takes resources that could go towards energy infrastructure
and development and shifts it towards the pharma industry, for example.
I'm not trying to make a value judgement here, just pointing out that in the scope of our prior
discussion, this is fairly neutral and doesn't change the conclusions.
Currently, all we know how to do is burn fuel, heat a working fluid, and use it to drive a
piston or turbine. The alternatives, such as solar and wind, will only come on as oil heads into
it's retirement party.
Well, no, we know a lot more than that. We have superior alternatives for most of the uses
for oil, and adequate ones for the rest.
The single biggest use is personal transportation, and EVs will work fine for that. We don't
need turbines for that, electric motors will do just fine.
And…we don't need wind or solar to get rid off oil. Not at the moment. All we need is electricity,
and we have plenty of that, right now.
My humble apologies, Dennis, just too funny, and appropriate. I do appreciate your charts,
but I wish you would occasionally plug is some other values to provide a contrast to your ever-optimistic
assumptions. My reaction to your chart was the same as Ron's.
Make your chart reflect lower and fluctuating oil prices, instead of coynecopian, steady-state
high prices and it might make more sense. Add a factor for debt restraining new wells at higher
oil prices (see SS's comment about $75 without debt below). Your assumptions just seem too optimistic
to be realistic. Maybe I just underestimate BAU's ability to fund stupidity and you don't:-)
It will be interesting to see what really happens.
Thanks to all for your comments. Always educational.
"... April 13,050 (preliminary)(all-time high was Oct 2015 13,190) ..."
"... March 56 drilling and 4 seismic ..."
"... April 66 drilling and 0 seismic ..."
"... May 42 drilling and 0 seismic (all time high was 370 in 10/2012) ..."
"... ND Sweet Crude Price ..."
"... March $26.62/barrel ..."
"... April $30.75/barrel ..."
"... May $33.74/barrel ..."
"... Today $38.25/barrel (all-time high was $136.29 7/3/2008) ..."
"... Today's rig count is 28 (lowest since July 2005 when it was 27)(all-time high was 218 on 5/29/2012) ..."
"... The drilling rig count fell 3 from March to April, 2 from April to May, and increased 1 from May to today. Operators remain committed to running the minimum number of rigs while oil prices remain below $60/barrel WTI. The number of well completions fell from 66 (final) in March to 41 (preliminary) in April. Oil price weakness is the primary reason for the slow-down and is now anticipated to last into at least the third quarter of this year and perhaps into the second quarter of 2017. There was 1 significant precipitation event, 15 days with wind speeds in excess of 35 mph (too high for completion work), and no days with temperatures below -10F. ..."
"... Over 98% of drilling now targets the Bakken and Three Forks formations. ..."
"... Estimated wells waiting on completion services is 892, down 28 from the end of March to the end of April. Estimated inactive well count is 1,590, up 67 from the end of March to the end of April. ..."
"... Crude oil take away capacity remains dependent on rail deliveries to coastal refineries to remain adequate. ..."
"... Low oil price associated with lifting of sanctions on Iran and a weaker economy in China are expected to lead to continued low drilling rig count. Utilization rate for rigs capable of 20,000+ feet is 25-30% and for shallow well rigs (7,000 feet or less) 15-20%. ..."
"... Drilling permit activity increased from March to April then fell back in May as operators continue to position themselves for low 2016 price scenarios. Operators have a significant permit inventory should a return to the drilling price point occur in the next 12 months. ..."
by
Ron Patterson
Posted on
06/15/2016
The
Bakken
and
North
Dakota
production data is out. Big surprise. The Bakken was down 69,420 barrels per
day in April while all North Dakota was down 70,414 bpd.
Largest drop ever in North
Dakota production. The Bakken is now under one million barrels per day.
This gives you some idea of the erratic nature of North Dakota production.
But as you can see, the decline is accelerating.
The EIA's Drilling Productivity Report gives past Bakken production numbers, which includes the
Montana portion, and future estimates for the next couple of months. The average difference between
North Dakota production and total Bakken production has been about 27,500 bpd. However for April the
difference is almost 63,000 barrels. So it looks like for once the DPR estimate is way too
conservative. The DPR estimate is through July while the north Dakota data is only through April.
In April Bakken barrels per day per well fell by 7 to 94, North Dakota bpd per well fell by 5 to
82.
March 13,052
April 13,050 (preliminary)(all-time high was Oct 2015 13,190)
Permitting
March 56 drilling and 4 seismic
April 66 drilling and 0 seismic
May 42 drilling and 0 seismic (all time high was 370 in 10/2012)
ND Sweet Crude Price
March $26.62/barrel
April $30.75/barrel
May $33.74/barrel
Today $38.25/barrel (all-time high was $136.29 7/3/2008)
Rig Count
March 32
April 29
May 27
Today's rig count is 28 (lowest since July 2005 when it was 27)(all-time high was
218 on 5/29/2012)
Comments:
The drilling rig count fell 3 from March to April, 2 from April to May, and
increased 1 from May to today. Operators remain committed to running the minimum number
of rigs while oil prices remain below $60/barrel WTI. The number of well completions
fell from 66 (final) in March to 41 (preliminary) in April. Oil price weakness is the
primary reason for the slow-down and is now anticipated to last into at least the third
quarter of this year and perhaps into the second quarter of 2017. There was 1
significant precipitation event, 15 days with wind speeds in excess of 35 mph (too high
for completion work), and no days with temperatures below -10F.
Over 98% of drilling now targets the Bakken and Three Forks formations.
Estimated wells waiting on completion services is 892, down 28 from the end of
March to the end of April. Estimated inactive well count is 1,590, up 67 from the end of
March to the end of April.
Crude oil take away capacity remains dependent on rail deliveries to coastal
refineries to remain adequate.
Low oil price associated with lifting of sanctions on Iran and a weaker economy in
China are expected to lead to continued low drilling rig count. Utilization rate for
rigs capable of 20,000+ feet is 25-30% and for shallow well rigs (7,000 feet or less)
15-20%.
Drilling permit activity increased from March to April then fell back in May as
operators continue to position themselves for low 2016 price scenarios. Operators have a
significant permit inventory should a return to the drilling price point occur in the
next 12 months.
... ... ...
New wells added in the Bakken/Three Forks are assumed to drop to 25 new wells in April and remain
at that level until Jan 2017. Last month about 64 new wells were added.
"... Note that at $90/b at the wellhead, the average 2014-2015 Bakken well pays out in 27 months. ..."
"... Note that 10,000 wells were drilled over an 8 year period from 2008 to 2016. ..."
"... My scenario has another 14,000 wells drilled over 11 years, possibly too optimistic, but similar to past history. ..."
"... 'Rationing' the remaining affordable oil supply will ONLY work as intended if the entire world does it together and the same time simultaneously and harmoniously.. . Not a snowballs chance of that is there. ..."
"... Usually rationing causes more problems than it solves, it usually is best to let the market handle it, high prices will reduce the quantity that people are able to purchase and behaviors will change. More efficient vehicles, car pooling, use of public transportation where available, etc. ..."
"... In june 2010 the average well production was 145 barrels per day, with a total of 1663 wells. Now the average well production is 94 barrels per day with a total of ten thousand five hundred and six wells. That's a lot of wells. All of them declining from day one. There is an enormous amount of inertia built in into the system now. It will take another ten-, twenty- of even fiftythousand wells to make the red queen recover. She will not. In the mean time companies go broke and the whole thing comes to a grinding halt. ..."
"... Dennis. $75 [is Ok to drill shale well] using cash. How many in the Bakken shale are using cash? Also, $75 assumes service companies continue to agree to low to no profit from services provided. Bakken wells were north of $10 million per in 2011-14. Again, CLR $11 million cash, $7.3 billion debt. WLL over $5 billion debt. HRC is bankrupt. From memory QEP, SM, HES, EOG, MRO, etc. All have billions of debt. PDP PV10 is less than long term debt at current prices. ..."
"... One thing, it appears that only equity markets are open to shale drillers. That, of course, is the best approach IMO. Promoters usually make money if investors pay for the well, regardless of whether the well pays out. Issuing gobs of debt turned out to be a big mistake. Think how much $$ shale could have gotten 2011-14 by just issuing shares. Break even would certainly be less. ..."
"... You think perhaps they drilled the worst spots first, saving the sweet spots for last? No, the sweet spots have already been drilled. Future wells will, almost certainly, produce less oil than those already drilled. Drillers just don't think that way Dennis. They would never save the sweet spots for last. ..."
"... Dennis, in the early days of Bakken fracking the wells had short laterals and fewer fracking stages. They got better with much longer laterals. They also got better at locating the sweet spots. But now the laterals and number of stages has maxed out. And the sweet spots are all drilled up. ..."
"... There is no doubt whatsoever that the very best and most productive wells have already been drilled. ..."
"... Low oil prices are forcing operators to focus drilling activity only in the core areas of the Bakken where wells have the greatest production. As oil prices recover and drilling expands to other areas of the Bakken, those high-producing wells will be declining, Helms said. "It's really kind of doubtful that we're going to make that (2 million barrels per day) because we're drilling everything in the core where the best wells are," he said. ..."
The E&P companies stopped drilling wildcats starting in 2013, and haven't
applied for such a permit for months, I'd suggest that means there are no
undiscovered reserves, all wells are in known areas now.
What do you think will happen to oil prices when oil output decreases?
The scenario is optimistic and assumes high oil prices, note that output
does not start to increase until 2019 in this scenario, when oil prices
have risen to $88/b (2015$).
The high oil price for this model is $116/b in 2016$ which is reached
in late 2020, does that seem unreasonable? The number of wells added is
1800 per year starting in 2021 with a gradual ramp up to that level over
a 2.5 year period from mid 2018 to the end of 2020.
I think it likely that if oil prices rise and remain over $100/b for
a few years that oil output will expand rapidly.
Note that at $90/b at the wellhead, the average 2014-2015 Bakken
well pays out in 27 months.
The net discounted cash flow for that well, a 10% annual discount rate
is $12.6 million with a well cost of about $8.5 million that leaves $4.1
million for profit or to be used to pay interest and debt.
I doubt we will be seeing more oil surpluses in the near future. Perhaps
if people start to move to EVs in 20 years or so we might see demand fall
faster than supply, but it will probably be 30 years or more before we get
there so 2045, beyond the scope of my scenario.
At some point there could be a financial crisis, but I will leave it
to others to predict when that will occur. In that case demand for oil will
fall along with oil prices and supply.
You asked "What do you think will happen to oil prices when oil output
decreases?"
I agree the initial reaction will be higher oil prices, but I don't expect
the stability in high prices, oil markets, and free money that existed in
the last cycle will ever be repeated. And you need those conditions to ramp
up shale again to production levels that can overcome the inertia of decline.
I think the stability expected is the root of our separate views. You
foresee (and hope) for it while I don't see it (but hope for it).
I think the only reason the global economy seemed to be able to afford
$100 oil is because abundant cheap money (from central banks) reduced interest
costs, which were able to help pay for higher energy costs. It bought time,
but I'm still seeing its effects, in the form of activities and businesses
that just aren't productive enough to continue, and shut down, without being
replaced. The effects of the last round of high oil prices are still slowly
but surely creeping around in the US economy.
Sure, oil prices will go back up soon enough. But can they go up and
stay stable at high enough levels to overcome the memories of shale ponzi
financials? And can the rest of the world avoid instability that affects
oil demand and supply for that same period?
Seems unlikely from here.
I'm glad I'm not making your models because I would go nuts trying to
figure out how to build in some of my variables of instability. It can't
be easy or you would have done because I (and others) have suggested it
in recent past.
Thanks for putting some numbers and graphics on these things. We may
not all agree with you, but you sure make us think. Thank you for that.
I don't expect the price will be stable, I don't know how the instability
will manifest.
When you look at my models just imagine the real values will wiggle above
and below the trend line, prices are very hard to predict. Also if we look
at the 36 month centered running average of monthly WTI prices since 1986,
prices look somewhat less volatile. I expect prices will rise to the 80
to 90 dollar range and perhaps stabilize (if we looked at future 36 month
running average). I also don't predict oil prices well so perhaps it will
be $60 to $70/b, in that case there will be less LTO wells drilled, or perhaps
none.
Wouldn't it be a lot more prudent to just ration oil and move to EV's and
renewables as fast as possible?
Putting in another 15,000 wells that are mostly not in sweet spots will
make most of the players even more vulnerable to a downturn in oil prices
than they were the last time.
At high oil prices wells will be drilled. If oil prices stay low because
we move quickly to EVs, the scenario will be incorrect. I would love to
be wrong, unfortunately this is fairly likely to occur. Note that 10,000
wells were drilled over an 8 year period from 2008 to 2016.
My scenario has another 14,000 wells drilled over 11 years, possibly
too optimistic, but similar to past history.
Dennis, I don't see any way that low oil prices can occur again for any
period of time. We are entering the final descent phase of LTO, exports
will be falling worldwide and prices will stay high.
Rationing is just around the corner anyway, so why not be sensible about
it and start it sooner. People can put up with being transport limited or
they can switch to EV's.
15.000 more wells in the Bakken saturate it and there is no more room. End
of story. Probably stop drilling long before that as they will be far off
the sweet spots and profits will not be there, even at high oil prices.
'Rationing' the remaining affordable oil supply will ONLY work as intended
if the entire world does it together and the same time simultaneously and
harmoniously.. . Not a snowballs chance of that is there.
So if say UK and USA ration, all it will do is reduce the price (due
to reduced demand) which will encourage other unconstrained users to increase
their consumption.
In the absence of a One World Govt and its associated Inspired Benevolent
Dictator we are screwed either way. The yeast is running our of sugar, we
are heading down the back of the resource supply curve, and everybody here
knows what a bumpy horrid ride it is going to be.
(That's my cheerful appreciation of our predicament for today! Carry
on!)
When you have a shortfall, rationing what you do have has no effect on world
demand or use. It is merely a way of controlling distribution of product
in hand and product you can get hold of. If you can't get more, how does
that change anything.
Demand reduction will occur as alternatives and lifestyle changes take
over. That is going to happen anyway. Let the ROTFW fight over the last
dribbles if they are stupid.
Usually rationing causes more problems than it solves, it usually
is best to let the market handle it, high prices will reduce the quantity
that people are able to purchase and behaviors will change. More efficient
vehicles, car pooling, use of public transportation where available, etc.
Still, I stick to my model as I have been doing for 29 months now. Especially
because price is not a parameter in the model. In june 2010 the average well production was 145 barrels per day, with
a total of 1663 wells. Now the average well production is 94 barrels per
day with a total of ten thousand five hundred and six wells. That's a lot
of wells. All of them declining from day one. There is an enormous amount
of inertia built in into the system now. It will take another ten-, twenty-
of even fiftythousand wells to make the red queen recover. She will not.
In the mean time companies go broke and the whole thing comes to a grinding
halt.
That's my take on it.
I like your analyses and, subject to unexpected crises, suspect you've
pretty well nailed it. Of course, expired (and expiring) hedges will serve
to exacerbate decline as well.
The average Bakken well pays back drilling and completion costs in 60
months at about $75/b. The resources are there, if oil prices are high enough
the oil will be recovered. the F50 technically recoverable resources are
about 11 Gb based on USGS estimates and the F95 estimate is about 8 Gb.
I will go with the USGS and the likelihood that as oil output decreases
oil prices will increase.
"The average Bakken well pays back drilling and completion costs in 60 months
at about $75/b."
That is impossible to happen in short term because business cycle (real
economy) has to grow at least the same rate or higher then finance cycle
of shale drillers (money that shale borrowed) and that went exponential
in the last 8 years.
-We can say that about your chart, but for Dennis' there is nothing to
tell!
The curbs on that chart cannot coexist together mathematically.
Whether one believes that projections for 2020, 2030 or 2040 and beyond
shall materialize, or not is besides the point – we can argue that forever
(as we have been).
-Dennis' chart cannot be, both logically and mathematically.
Unless one believes that they used the wrong narrow pipes from 2010 to
2015 and the large correct ones from 2020-2025 to get the oil out of the
ground (I am joking, of course!), for that chart to make sense, either production
curb 2020-2025 has to come down below the level of that 2014-2015, or the
line representing wells during 2020-2025 has to be way above the level of
that representing wells from 2012-2015…or both.
Or, here's a third " bright" scenario for you:
one has to believe that some very advanced (not known today) way of fracking
will exist by 2020 in order to "squeeze" far more oil than we do today from
a, by then – for all practical intents and purposes – totally exhausted
oil field (i.e.: Bakken, circa 2025).
I am surprised some of you "well versed on charts guys" did not see that.
The output has decreased because fewer wells have been added each month,
if the number of wells completed per month increases, output also increases.
Do you see a logical reason that the number of wells completed per month
cannot increase if oil prices increase to a level which makes wells profitable?
Shallow sand has shown very clearly that $75/b is enough to make an average
Bakken well profitable.
Also my scenario has 8 Gb from 24,000 wells, and average EUR per well
of about 330 kb. The average well from 2008 to 2015 gas a well profile with
a URR of about 350 kb.
The model is very straightforward, but could overestimate the well profile
for recent wells.
We do not know what the wells will produce in the future,
I have estimated future well output on the performance of past wells,
future well could be worse (or better than I have estimated). The scenario
below assumes higher oil prices ($154/b) and fewer wells added per month
(a maximum of 130 new wells per month), a more conservative well profile
for 2015 and later is used (EUR=369 kb), ERR is 8.5 Gb with 33,000 total
wells completed. That is fairly close to the USGS F95 estimate.
Dennis. $75 [is Ok to drill shale well] using cash. How many in the
Bakken shale are using cash? Also, $75 assumes service companies continue
to agree to low to no profit from services provided. Bakken wells were north
of $10 million per in 2011-14. Again, CLR $11 million cash, $7.3 billion
debt. WLL over $5 billion debt. HRC is bankrupt. From memory QEP, SM, HES,
EOG, MRO, etc. All have billions of debt. PDP PV10 is less than long term
debt at current prices.
One thing, it appears that only equity markets are open to shale
drillers. That, of course, is the best approach IMO. Promoters usually make
money if investors pay for the well, regardless of whether the well pays
out. Issuing gobs of debt turned out to be a big mistake. Think how much
$$ shale could have gotten 2011-14 by just issuing shares. Break even would
certainly be less.
I have estimated future well output on the performance of past wells,
future well could be worse (or better than I have estimated).
They could be better? Really? You think perhaps they drilled the
worst spots first, saving the sweet spots for last? No, the sweet spots
have already been drilled. Future wells will, almost certainly, produce
less oil than those already drilled. Drillers just don't think that way
Dennis. They would never save the sweet spots for last.
My projection of future output from recent wells has much steeper decline
than older wells, so I could have overestimated or underestimated what the
future output will be from a well that was drilled in 2015.
In 2005 to 2007 the EUR of the average well was much lower than 2008
to 2013, so it is possible that improved techniques might increase output,
the first 12 months of output was higher in 2013 wells and 2014 wells than
the earlier 2008 to 2012 average well. At some point this will reverse and
my model has new well EUR decreasing after June 2018, this guess could be
too early or too late.
So basically I am not assuming anyone is saving the sweet spots, just
that my estimate could be low or high, we won't know until we have more
data.
Dennis, in the early days of Bakken fracking the wells had short laterals
and fewer fracking stages. They got better with much longer laterals. They
also got better at locating the sweet spots. But now the laterals and number
of stages has maxed out. And the sweet spots are all drilled up.
There is no doubt whatsoever that the very best and most productive
wells have already been drilled.
I will wait for the data that confirms you are correct. So far the productivity
of the average well for the first 12 months of output has been increasing,
later months we can only guess at for the wells that were recently drilled
(wells starting production after May 2015 we don't have data for production
beyond month 12).
I thought we would see new well EUR decreasing by 2014, so far the data
shows little evidence of that.
Low oil prices are forcing operators to focus drilling activity only
in the core areas of the Bakken where wells have the greatest production.
As oil prices recover and drilling expands to other areas of the Bakken,
those high-producing wells will be declining, Helms said.
"It's really kind of doubtful that we're going to make that (2 million
barrels per day) because we're drilling everything in the core where the
best wells are," he said.
He said he thinks North Dakota production will eventually reach 1.8 million
barrels per day. I wonder if he said that with a straight face, especially
after just admitting that all the good spots will soon be gone.
I repeat, I do not expect the well profile will increase. When I said
it may be better or worse than my estimate of the well profile, it
simply means that we do not know what the well profile is, we have to estimate
and sometimes the "best guess" is too high and other times it is too low,
just like any other guess.
When you make an estimate is it always too high? My estimates may be
different, about half the time they are too high, and the other half they
are too low. :)
That is all that I meant.
Also, my "funny model" uses exactly the same well profile that I have
been using since Enno suggested I should correct my model because it consistently
was under predicting Bakken output.
Maybe new well EUR will start to decrease sooner than I have predicted
(June 2018), but with only 980 new wells completed in the model over a 28
month period and that for the past 2 years the well profile has been increasing,
I think the June 2018 guess is reasonable.
The eventual number of wells was 150 per month which is 21% less than
the high 12 month rate of 186 wells per month, only 80 wells per month are
needed for 1000 kb/d with the current well profile.
If i understand Verwimp's chart correctly, he started it when the price
of oil was over 100. So Verwimp, did you know something the rest of us didn't
or was this just a good educated guess.
At any rate your chart has nailed it to date. Congrats.
You do understand correctly. The model was built before the price collapse.
It's a Hubbert analysis basically. The dataset prior to the moment the model
was built was a Hubbert poster child and it still is. When linearised according
to Hubbert Linearisation, the data is still a straight line. There is no
drop in that line. A sudden policy change coinciding with lower prices would
have generated a drop in that line. That would also be visible in the change
in daily oil shifting away from the first derivative of the model. Both
are not occuring. So the only resulting conclusion is: ND Bakken is running
out of oil, despite the high USGS EUR estimate.
I may stand corrected in the future. If prices rise and production rises
again, I missed something. Until now (today's WTI prices are almost double
the WTI price in Februari -- ) that is not the case, as you can see.
A Hubbert analysis only makes sense when a lot of data on the upgoing side
of the curve already exists. 10 years ago there was virtually no LTO. So
no Hubbert analysis could have been made.
No, it wasn't a guess. It's just the nature of things that what goes up
must come down. The Hubbert analysis provides a tool to calculate the altitude
and the timing of the top, as well as the steepness of the decline. These
calculations are more accurate when the top is closer by (or past). Apparently
29 months after the calculations were done, the reality is still in line
with the modelled curve.
(I also added a seasonal correction to the Hubbert Curve, that as proven
to be pretty accurate, but that is a minor feature of the curve compared
to the underlying Hybbert Curve.)
The only guess was that ND Bakken would stay being the Hubbert poster
child it was prior to the calculations. Apparently it still is. That guess
was based on the fact Lower48 and Alaska production are also pretty Hubbert-like
curves, just like earlier smaller booms in North Dakota. It's in the 'genes'
of Americans, I presume, to go for it as soon as possible, as hard as possible
and as fast as possible when it comes to earn money extracting a resource,
until the show is over. A Hubbert curve is the result then…
"... So, if one says such well's EUR is 750,000 BO, shouldn't they also be required to disclose that will take around 75 years to achieve? What is the PV10 of oil produced in years 20-75? ..."
"... Wonder how much reserves will have to be written down? This is such a joke. ..."
"... Dennis. You note that you guess the 10K estimates differ from the investor presentation estimates. Seems like if companies would provide us with the reserves reports themselves, it might help see if your guess is correct? Also seems claiming roughly double is a little too much to take care of with a mere disclaimer? I wish the SEC letters to companies requesting them to restate reserves would be made public immediately. We are just now finding out about many of these, after the companies have already BK. ..."
"... We do a regular chart showing gains in average cumulative production month by month benchmarked to 2010. It clearly shows steeper decline rates for wells with higher early production. 2013 wells were 10% or more above 2010's cumulative production in month 6 – by month 33 they are just 2.5% above 2010's cumulative production. 2015 wells were 31% above 2010's cumulative production in month 7 – they are now in month 17 and are 20% above, and falling. ..."
Wonder if the SEC should take this data and analyze company EUR projections?
It seems 2008 had strong wells. After 100 months, average well has produced 260,210 BO per
Enno's data.
So, if one says such well's EUR is 750,000 BO, shouldn't they also be required to disclose
that will take around 75 years to achieve? What is the PV10 of oil produced in years 20-75?
Wonder how much reserves will have to be written down? This is such a joke.
My guess is that the reserves in the 10K are very different from investor presentations where
there are disclaimers that say, essentially, that they stretch the truth.
So a "typical well" in an investor presentation is not an "average well".
In North Dakota at the end of 2014 proved reserves were 6 Gb in the Bakken Three/Forks and
1.2 Gb of C+C had been produced to that date.
A very conservative URR projection would be 7.2 Gb, if probable reserves were included (another
3 Gb would be a conservative estimate), then URR might be as high as 10.2 Gb if oil prices rise
to 2014 levels or higher in the future.
I use a well profile with 400 kb of C+C output, 266.6 kb are produced in the first 5 years,
output falls to 10 b/d in 19.4 years. I also assume the sweet spots get saturated with wells by
June 2018 and EUR starts to decrease. The rate of decrease in new well EUR gradually increases
over 12 months reaching a maximum rate of 7% per year by June 2019, by June 2025 the new well
EUR falls to 250 kb (166 kb at 5 years), and to 127 kb by August 2036 when wells are no longer
added to the ND Bakken/TF (at a total of 36,250 wells). Thus model assumes oil prices rise to
$154/b in 2016$ and remain at that level until 2033.
Dennis. You note that you guess the 10K estimates differ from the investor presentation estimates.
Seems like if companies would provide us with the reserves reports themselves, it might help
see if your guess is correct? Also seems claiming roughly double is a little too much to take care of with a mere disclaimer?
I wish the SEC letters to companies requesting them to restate reserves would be made public
immediately. We are just now finding out about many of these, after the companies have already
BK.
Aren't the reserves reported in the 10K checked by outside accounting firms? You are no doubt
correct that some reserves will no longer be profitable to developed at current oil price levels.
I imagine this will change when oil prices increase.
The oil is there, but it requires higher prices.
Eventually the debt will be paid, or companies will go under.
We do a regular chart showing gains in average cumulative production month by month benchmarked
to 2010. It clearly shows steeper decline rates for wells with higher early production. 2013 wells
were 10% or more above 2010's cumulative production in month 6 – by month 33 they are just 2.5%
above 2010's cumulative production. 2015 wells were 31% above 2010's cumulative production in
month 7 – they are now in month 17 and are 20% above, and falling.
I remember Lynn Helms predicting a sharp drop in production for March. In fact, in March Bakken output declined only 8 kb/d, but was down 69 kb/d in April.
April number for ND Bakken is down 6.6% vs. March, 10.9% vs. April 2015 and 15.2% (176 kb/d)
from the peak reached in December 2014. Average output for January-April 2016 is 1044 kb/d, down 6.9% year-on-year.
As CLR's Harold Hamm and several other E&P CEOs are saying, $50 is a trigger for increased
completion of the DUCs. Rig count has also bottomed, but significant increase in drilling activity is unlikely until WTI
reaches $60.
Nonetheless, it seems that we will see further declines in LTO output in the next several months
due to delayed impact of low oil prices.
"... Yes it is the normal cycle pattern, but going into Q3, we have been seeing draws over the last few weeks, and world S/D has been close to being balanced. ..."
"... It is normal for Q2 to have storage builds, and this year the builds were on the low side. ..."
"... The market is not expecting to see higher demand than supply, and the next step in prices may be soon than expected. ..."
I know that this presentation is about production, but on the other side
of production, that is demand, according to the IEA demand tables, going
from Q2 to Q3 increases demand by about 1.5 million barrels a day.
There is also a additional small increase going from Q3 to Q4.
With supply decreasing and demand increasing looks like oil prices may
be headed higher over the next six months.
The Alberta fires along with Nigeras problems came at the right time
yo tighten things up a bit.
Yes it is the normal cycle pattern, but going into Q3, we have been
seeing draws over the last few weeks, and world S/D has been close to being
balanced.
It is normal for Q2 to have storage builds, and this year the builds
were on the low side.
The market is not expecting to see higher demand than supply, and
the next step in prices may be soon than expected.
"... Global demand is indeed strong. All key forecasting agencies are still projecting annual demand growth of 1.2mb/d, but it may surprise on the upside (~1.4mb/d). But supply/demand rebalancing is mainly due to declining non-OPEC output and supply outages. ..."
Global demand is indeed strong. All key forecasting agencies are still projecting annual demand
growth of 1.2mb/d, but it may surprise on the upside (~1.4mb/d).
But supply/demand rebalancing is mainly due to declining non-OPEC output and supply outages.
Quarterly global oil demand (mb/d)
source: IEA Oil Market Report, May 2016
It appears that world oil exports has increased very little, if any, since 2005.
Notable quotes:
"... I can only guess that oil production in importing nations, which are generally capitalist countries, is more sensitive to oil price changes than exporters (whose systems of govt allows for maintaining production regardless of price). ..."
"... The largest increase in production, by far, came from the US which is an importing nation. And huge declines came from Norway, the UK and Mexico, all exporting nations. That is largely why we see production increasing while exports stayed flat. ..."
"... Exporting nations, the UK and Indonesia, became net importers during that period. There may have been others, I haven't looked that closely. ..."
"... I find Mexico to be an interesting case. I read somewhere that 30% of federal tax revenue is received from taxation of Pemex. Mexico exports are down 21% in 2015 compared to 2014. I'm not sure what is going to happen to Mexico when it becomes a net oil importer. ..."
This mostly means that importers have simply increased production right?
Gains in U.S. and Canadian production reduced imports, and allowed countries like China and
India to import more even though net export availability remained flat.
I can only guess that oil production in importing nations, which are generally capitalist
countries, is more sensitive to oil price changes than exporters (whose systems of govt allows
for maintaining production regardless of price).
The next 12 months may see increasing prices even if net exports do not decline simply due
to increased export demand from countries like the U.S. that flip from a multi-year decline in
import demand.
Yes, exactly. The largest increase in production, by far, came from the US which is an importing
nation. And huge declines came from Norway, the UK and Mexico, all exporting nations. That is
largely why we see production increasing while exports stayed flat.
Exporting nations, the UK and Indonesia, became net importers during that period. There
may have been others, I haven't looked that closely.
Hi Ron, according to the Energy Export Data Browser UK is an importer.
I find Mexico to be an interesting case. I read somewhere that 30% of federal tax revenue
is received from taxation of Pemex. Mexico exports are down 21% in 2015 compared to 2014. I'm
not sure what is going to happen to Mexico when it becomes a net oil importer. Whenever it
is it won't be good. Perhaps Mexico will join their neighbors to the south (El Salvador, Guatemala
and Honduras) in being failed states.
"... Worldwide investment in the development of oil and gas resources from 2015 to 2020 will be 22 percent, or $740 billion, lower than anticipated before prices plunged in 2014, with the deepest cuts in the U.S., Wood Mackenzie said in a statement Wednesday. A further $300 billion will be eliminated from exploration spending. Global production this year will be 3 percent lower than previously forecast, the consultant said. ..."
The oil and gas industry will cut $1 trillion from planned spending on exploration and development
because of the slump in prices, leading to slower growth in production, according to consultant Wood
Mackenzie Ltd.
Worldwide investment in the development of oil and gas resources from 2015 to 2020 will be 22 percent,
or $740 billion, lower than anticipated before prices plunged in 2014, with the deepest cuts in the
U.S., Wood Mackenzie said in a statement Wednesday. A further $300 billion will be eliminated from
exploration spending. Global production this year will be 3 percent lower than previously forecast,
the consultant said.
"... I hope everyone understands that by 2020, most of the 2014 and prior vintage Bakken and TFS wells will be just like what Oasis sold, 21,000′ well bores making under 20 bopd. ..."
"... There are going to be about 40,000 stripper wells in the US that have a TD in excess of 15,000′ in about 5 years. If those are economic I think we will be very happy. ..."
"... I sure agree, hope this rally isn't a repeat of last year. ..."
"... WPX Energy Inc prices public offering of 49.5 mln shares for total gross proceeds (before estimated expenses) of about $485 mln ..."
"... You know that Permian, break even at $30, 30% IRR at $35. LOL! ..."
"... The Mighty MIGHTY MARKET and the ( near) Invincible Invisible Hand really can work economic miracles, sometimes, not every time, given time enough. ..."
"... The "Invisible Fist" generally just plummets our proletarian friends. ..."
Article in WSJ about shut in wells in the Bakken and various entities and individuals who are
taking their first stab in the oil business by purchasing distressed Bakken production.
Hope they have their eyes wide open, so to speak.
Saw that Oasis sold all of its non Middle Bakken/TFS wells and acreage for $16.5 million to
Samson. Not the KKR bankrupt Samson, but the Austrailian penny stock Samson.
780 BOEPD net and over 50K of acreage, but lots of shut in wells.
I hope everyone understands that by 2020, most of the 2014 and prior vintage Bakken and TFS
wells will be just like what Oasis sold, 21,000′ well bores making under 20 bopd.
Think we'll stick to the ones that make 1/20th of the oil but are also 1/20th of the depth.
There are going to be about 40,000 stripper wells in the US that have a TD in excess of
15,000′ in about 5 years. If those are economic I think we will be very happy.
is that "we" meant to be the you oil barrons :-), I think the Nathaniel's and Fred's of the world
might have a different perspective, but it may also be a learning experience. For the first time
in a year the light at the end of the tunnel might not be the another freakin train.
BRIEF -- WPX Energy Inc prices public offering of 49.5 mln shares for total gross proceeds (before
estimated expenses) of about $485 mln
The stock went up with the dilution (?) and they plan to use the money to drill wells:
"WPX says it plans to use the proceeds for general corporate purposes, which may include an acceleration
of drilling and completion activities, bolt-on acreage acquisition, and midstream infrastructure
in the Delaware Basin."
The Mighty MIGHTY MARKET and the ( near) Invincible Invisible Hand really can work economic
miracles, sometimes, not every time, given time enough.
Here is an example of incremental change that can WORK, NOW. Plug in hybrid trucks aren't going
to solve the oil depletion problem. Electric cars won't solve it either. But they will DELAY the
day of reckoning- maybe long enough for us to change our ways sufficiently to avoid an economic
catastrophe.
Twenty four miles on battery power alone is enough to cut substantially into diesel fuel consumption
if a truck is running a short route. Ten years from now, fifty miles on battery power alone will
probably be feasible.
06/09/2016 at 12:11 am
Some interesting DUC numbers from Bentekenergy.com for the Marcelus. 2010
current, down 700 since Oct last year. The question remains, at what price and
stock of DUCs, is required for the producers start drilling again.
Northeast rig count continues downward march
Tuesday, June 07, 2016 – 5:45 AM
Active rigs in the Northeast have, yet again, hit another all-time low at 30
rigs for the week-ending June 3, down by 66% over the past year and by two rigs
over the past week. Rigs have been on a precipitous slide since a recent peak
of 144 during the first week of August 2014, declining by about 1.2 rigs per
week. Producers Chesapeake Energy, Consol Gas, EQT, Range Resources, and Ascent
Resources have accounted for half of the total drop since the August peak, with
Chesapeake and Consol reporting zero rigs in the most recent data. Bentek is
currently tracking 2,010 wells in inventory for March, down by nearly 700 wells
since the October 2015 high and has helped production stay afloat as active
rigs dwindle across the region. The wells in inventory will help offset the
0.8-1.0 Bcf/d first month-on-month decline from existing producing wells and if
assuming drilling remains flat.
The best thing here is:
Capex is slashed worldwide, hidden capex from 3rd world states I think even more since they are
simply broke with the current oil prices.
And the production continues to increase – why this Capex frenzy the last years, if you can
increase production simply on no money spending, rust and decline being no problem anymore.
"... The major factor pushing prices higher last week was the unplanned production outages in Alberta, Nigeria, and Venezuela. Although the fires are now well past the Alberta tar sands, it will be several weeks before the 1 million b/d of production that had to be shut down during the firestorms can return fully to production. In the meantime, the Alberta outage and the one in Nigeria have likely removed much or all of the production surplus that has overhung the markets and for now, there may be a rough balance of supply and demand. ..."
"... In recent years, these companies have seen a string of massive cost overruns such as in the Caspian and Bering Seas, and disasters such is Deepwater Horizon in the Gulf of Mexico. Last year the oil industry discovered only 12 billion barrels of new reserves, about a third of annual global consumption. ..."
"... Nearly all of the major oil companies reduced capital spending to less than half of what it as been in recent years. With decreasing oil production, supply is likely to start falling short of demand later this year, if it has not already, due to the various outages. ..."
Oil prices hovered just below the $50 level last week with Brent closing just above $50 on
Thursday before settling at $49.46 on Friday. As has been the case lately, there were numerous
factors pressuring oil prices one way or another. The week opened with much enthusiasm that OPEC
would agree to a production freeze, but this went away when the OPEC meeting failed to take any
action. The major factor pushing prices higher last week was the unplanned production outages
in Alberta, Nigeria, and Venezuela. Although the fires are now well past the Alberta tar sands,
it will be several weeks before the 1 million b/d of production that had to be shut down during
the firestorms can return fully to production. In the meantime, the Alberta outage and the one in
Nigeria have likely removed much or all of the production surplus that has overhung the markets
and for now, there may be a rough balance of supply and demand.
While production in Alberta is returning to normal, the political/economic situations in Nigeria
and Venezuela continue to get worse with the likelihood that both countries will soon see a
significant drop in oil production – possibly enough to offset surplus production elsewhere.
There is no end in sight to the problems in either of these countries, and their situations
seemed destined to get worse before they get better.
The US crude inventory saw a small drawdown last week, which is not surprising considering the
outages in Alberta over the past month. The EIA continues to estimate that US production is still
dropping. However, the US oil rig count climbed by nine units last week as drillers responded to
oil prices approaching $50 a barrel coupled with a buyers' market for oil production services and
oilfield workers. The meager increase in US employment last week has some worried about the
outlook for US economic growth in the near future. At a minimum, the widely expected interest
rate increase by the Federal Reserve is likely to go on hold for a while.
The problems of the oil industry continue, however, with US bank earnings down 2 percent in the
first quarter largely due to delinquent loans to the oil industry where bankruptcies continue to
be announced. Observers are starting to talk about the inevitable decline of the large
international oil companies. These companies are finding it increasingly difficult to find new
reserves to exploit and those that are available are mostly in deepwater projects where the costs
of extraction are well above the current selling price of oil. In recent years, these
companies have seen a string of massive cost overruns such as in the Caspian and Bering Seas, and
disasters such is Deepwater Horizon in the Gulf of Mexico. Last year the oil industry discovered
only 12 billion barrels of new reserves, about a third of annual global consumption.
Nearly all of the major oil companies reduced capital spending to less than half of what it
as been in recent years. With decreasing oil production, supply is likely to start falling short
of demand later this year, if it has not already, due to the various outages. Global crude
reserves are still at record levels, so daily shortages of even a million b/d or two are unlikely
to send prices into three figures right away.
By 2020, give or take a bit, prices are likely to start climbing into new territory as
shortages become larger, and rationing-by-price again comes into effect.
"... My initial advice would be to see what the CEO, upper management, etc., are being paid and then compare that to the company's total production. Look at G & A per barrel, or per BOE. ..."
"... The problem with a lot of public companies in the E & P space, both shale and non-shale, is that they are ran primarily for management, and not for the shareholders. ..."
"... I see a lot of relatively small E & P's that are cash flow negative that are borrowing to pay the upper management big salaries. ..."
"... So, if you see a public company producing under 10K BOEPD, where top management are being paid in the hundreds of thousands of dollars (or millions) in salary, my general advice is to stay away. ..."
"... Most private conventional E & P in onshore lower 48 have been paying little to no distributions since the end of 2014. Management is taking just enough salary to pay their personal expenses, if that even. Things are still very dire, although there is considerable improvement since Q1 2016. ..."
"... Please note my comment regarding the revised OCC (Office of the Comptroller of the Currency) guidelines. I see there are not comments on this. Further, the MSM has totally missed the boat on this. ..."
"... Shallow, I wish to acknowledge your OCC findings and all of your analysis regarding the economics and finances of shale oil development. Your value here on this blog is immense. I agree with you, by the way, that the ramifications of these new banking requirements will potentially end any additional lending to the shale industry…until it find ways to worm around these new standards. Which we should expect, of course. I mean, after all, the lower the price of oil goes, the lower shale oil breakeven costs go, the higher EUR's go. Its a miracle -- ..."
"... Shale oil proponents have the unique ability to disassociate themselves completely from the business of producing hydrocarbons and, forgive me, are delusional about economics, profit, and where the money comes from to drill wells. They don't get it. They don't want to get it. ..."
"... For financing reasons, environmental and social reasons, for reasons of enormous, unmanageable debt, the shale oil industry in America will never again be what it was, not even close. ..."
"... Initially, OCC was going to include ALL junior debt. The OCC apparently found out (I wonder how they did not already know?) that including ALL junior debt would result in massive borrowing base cuts, and force many more E & P's into either BK, or into mezzanine financing (high interest/onerous terms). To quote Raw Energy, cause a mini-meltdown akin to the mortgage backed security financial crisis. ..."
"... I think this issue is critical here, where many readers and posters are closely following US production. Absent the ability to issue equity, or obtain mezzanine financing, I'd say shale is going to have to drill out of cash flow. Further, shale is now taking a big risk by not setting aside any money to pay down junior debt. So, what little cash flow there is may be needed to pay down junior debt, not drill new wells. ..."
"... I don't think we would want the LTO industry to be what it once was, a loss making enterprise (for most companies), there were a few well run companies such as EOG that were profitable before the crash in oil prices. ..."
"... I expect by 2020 (at least) oil prices will be at least $80/b (in 2016$). ..."
"... The EIA's AEO 2016 reference case has WTI at $71/b in 2020 and $97/b in 2030 (both in 2015$). ..."
I just learned of the revised OCC guidelines for US upstream E & P.
They were released in late March, 2016.
I am embarrassed I am just learning of them. However, I am not aware of the US business
media reporting on them either.
I believe these new guidelines directly resulted in the numerous May, 2016 BK, and effectively
end much of the shale revolution. No longer will banks be permitted to ignore a company's junior
debt.
Haynes and Boone has a good summary dated 3/28/16.
Years ago I bought shares in a London listed company with producing assets in Russia. In
2012, Maxim Barskiy made a strategic investment in the Company. Shortly after doing so, he
took over as CEO. They sold the field in Russia and bought leases in the Texas pan handle with
active and non active stripper wells.
There have been various acquisitions and mergers, some wells are currently shut in but they
are still drilling vertical wells ( but only 4 this year). The interesting point is that they
are now fracturing these new wells in the old conventional fields.
I just wondered if you knew of any other operator that was re completing stripper well by
fracturing them.
My initial advice would be to see what the CEO, upper management, etc., are being paid
and then compare that to the company's total production. Look at G & A per barrel, or per BOE.
The problem with a lot of public companies in the E & P space, both shale and non-shale,
is that they are ran primarily for management, and not for the shareholders.
I see a lot of relatively small E & P's that are cash flow negative that are borrowing
to pay the upper management big salaries.
So, if you see a public company producing under 10K BOEPD, where top management are
being paid in the hundreds of thousands of dollars (or millions) in salary, my general advice
is to stay away.
Most private conventional E & P in onshore lower 48 have been paying little to no distributions
since the end of 2014. Management is taking just enough salary to pay their personal expenses,
if that even. Things are still very dire, although there is considerable improvement since
Q1 2016.
Please note my comment regarding the revised OCC (Office of the Comptroller of the Currency)
guidelines. I see there are not comments on this. Further, the MSM has totally missed the boat
on this.
I think many more public E & P's will be forced into bankruptcy due to the tighter guidelines
(which IMO should have been in place from the beginning – we would not be where we are today
if they had been).
Again, Haynes and Boone has a client letter dated 3/28/16 which can easily be found by Google
search. Maybe someone here can provide a link.
It is a big deal, IMO. Anyone who is trying to forecast US oil production needs to look
at this issue. I think it is going to choke off the alleged, "Return of rigs at $50 WTI".
The only companies able to do much now are those Permian guys who raised cash through diluting
the equity. I'd say the Bakken, EFS and Niobrara focused companies will not be able to do much
absent the NYMEX strip jumping about $25+ as that is what will be needed, minimum, to get PV10
high enough for them to qualify for more reserve backed funds.
Shallow, I wish to acknowledge your OCC findings and all of your analysis regarding the
economics and finances of shale oil development. Your value here on this blog is immense. I
agree with you, by the way, that the ramifications of these new banking requirements will potentially
end any additional lending to the shale industry…until it find ways to worm around these new
standards. Which we should expect, of course. I mean, after all, the lower the price of oil
goes, the lower shale oil breakeven costs go, the higher EUR's go. Its a miracle --
This OCC matter will be of little interest to most people, however. Shale oil proponents
have the unique ability to disassociate themselves completely from the business of producing
hydrocarbons and, forgive me, are delusional about economics, profit, and where the money comes
from to drill wells. They don't get it. They don't want to get it.
For financing reasons, environmental and social reasons, for reasons of enormous, unmanageable
debt, the shale oil industry in America will never again be what it was, not even close.
From what I have read, there are presently/will be a lot of energy loans examined under
these new guidelines between now and the next borrowing base redeterminations coming this fall.
Initially, OCC was going to include ALL junior debt. The OCC apparently found out (I
wonder how they did not already know?) that including ALL junior debt would result in massive
borrowing base cuts, and force many more E & P's into either BK, or into mezzanine financing
(high interest/onerous terms). To quote Raw Energy, cause a mini-meltdown akin to the mortgage
backed security financial crisis.
So, for now OCC is only including any junior debt which COMES DUE prior to the first lien
bank lines. Most of the bank lines are multi-year, so there could be a lot of junior debt which
does come due prior.
Further, OCC is counting not just the drawn, but also the undrawn amounts on the bank lines.
So, if Shale R Us brags they have a $2 billion line of credit, but only have $100 million drawn,
there is still a problem as the whole line is included in the calculation. It actually becomes
a detriment to have a large, undrawn, bank line.
Further, banks are now also being directed to use the NYMEX forward strip, rather than their
own price decks. This is a problem, as I suspect many of the banks have been assuming much
higher prices in 2018 and beyond, than is indicated by the futures strip.
Raw Energy, on Seeking Alpha, is much better versed on these matters than I am. Hopefully
he will write an article there about the implications of the new OCC guidelines.
I think this issue is critical here, where many readers and posters are closely following
US production. Absent the ability to issue equity, or obtain mezzanine financing, I'd say shale
is going to have to drill out of cash flow. Further, shale is now taking a big risk by not
setting aside any money to pay down junior debt. So, what little cash flow there is may be
needed to pay down junior debt, not drill new wells.
Consider the possibility that many LTO companies go bankrupt, that wipes out most of the
debt. Oil output decreases in the US. What would you expect might happen to World oil prices?
I don't think we would want the LTO industry to be what it once was, a loss making enterprise
(for most companies), there were a few well run companies such as EOG that were profitable
before the crash in oil prices.
Based on EIA data on proved reserves at the end of 2014 there is still some LTO oil that
can be produced. Higher oil prices ($80/b or more) will be needed for this oil to be produced
profitably.
I expect by 2020 (at least) oil prices will be at least $80/b (in 2016$).
What is your expectation for future oil prices? Do you believe oil prices will be less than
$70/b (2016$) in 2020?
Current futures strip is $56/b in Dec 2020, but futures do not predict future prices very
well that far forward.
The EIA's AEO 2016 reference case has WTI at $71/b in 2020 and $97/b in 2030 (both in
2015$).
IEA is probably OK for use as historical data source, but any use of their forecasts is a sign
of gross negligence, based on their track record. Their 'waterfall" style forecasts are just
propaganda.
My feeling is that 80 dollars bbl are needs to increase shale oil production. Before that it will might be
continue to decline. Saudis are a spent bullet. So chances of them coming into play again with more oil to
suppress oil price further are close to zero.
If so, the key question we need to answer is when oil will hit this magic price point.
U.S. crude oil production averaged 9.4 million barrels per day (b/d) in 2015. Production is
forecast to average 8.6 million b/d in 2016 and 8.2 million b/d in 2017, both unchanged from last
month's STEO.
EIA estimates that crude oil production for May 2016 averaged 8.7 million b/d,
which is more than 0.2 million b/d below the April 2016 level, and approximately 1 million b/d
below the 9.7 million b/d level reached in April 2015.
Dennis – you asked at some previous post about discovered, undeveloped reserves. Overall I'd
go with Jean Laherrere, he knows more about these things than most and definitely understands
the politics behind some government forecasts, looks at things globally and probably still has
access to some of the more confidential figures. My less informed view is as follows.
So far about 1350 billion barrels C&C have been produced. Current production is about 28 billion
per year excluding extra heavy oil. Recently Rystad indicated mature filed decline rates at 5%
per year, if that held through the complete depletion (unlikely but all I have to go on) that
would mean another 540 billion, at 3% average decline it would be 900 billion. For 2200 billion
total that could mean (say) another 100 billion to find, 50 billion which is developed but offline
(in Libya, neutral zone, Abqaiq maybe, Syria etc.) and 150 billion discovered but undeveloped.
If there is that amount (or more for higher URR or higher overall decline rates, maybe up to 900
billion by your figures) it must be in OPEC Middle East countries or Russia. A lot of the older
undeveloped, mostly heavy oil, reserves elsewhere have been developed recently (e.g. in the North
Sea) in response to high oil prices. Similarly deep sea in GoM and offshore Africa and Brazil
(see the paper above – there isn't much left in the GoM and discoveries have dropped to near zero
per year). The larger reserves that I know about are complicated and expensive to develop (e.g.
Brazil pre salt, Kazakhstan high sulphur) or have some political issues (offshore Nigeria). I
don't think these would total more than 50 billion though.
If the Middle East OPEC countries have significant known undeveloped reserves they don't act
like it – i.e. why develop tight gas fields, or explore deep sea pre-salt, or double or more the
number of exploration and in fill wells, or get IOCs to come in and redeveloped existing fields.
Somewhere I read that Saudi assume 75% recovery and develop their fields to deplete 2% of the
field per year during plateau phase. That sounds about right for a URR of 250 billion (i.e. assuming
they report total recoverable resources, not what is left) but would mean pretty much everything
they have is on production with nothing much known but undeveloped. 75% may be high but I think
probably achievable for huge onshore fields (not so much for heavy oil offshore like Safinayah;
Abqaiq, which may be exhausted by now; or the neutral zone, which sounds like it needs steam flood
to recover much more). To me Saudi's recent posturing is about setting up excuses for post peak
declines, without having to admit they don't have as much oil as they've stated. Also Kuwait's
initiative as described in terms of new exploration and debottlenecking existing facilities, not
developing known fields.
IHS, Rystad and Wood Mackenzie probably know more, but their past performance at predicting
anything makes you wonder (Rystad seems better than the others though).
For extra heavy oil I think the recovery factors are probably overstated and based on the early,
and easiest to exploit developments. However this probably doesn't make much difference as the
limiting factor is the surface production facilities, and will be for the next few decades. CAPP
predict Canadian oil sands rising to about 3 to 4 mmbpd by 2030, but even this presupposes another
two pipelines approved and built and a sustained, high oil price (i.e. above $100, and probably
more if natural gas prices start to rise at the same time).
In Venezuela exploiting the extra heavy oil would be difficult even for a stable society. It
needs a large amount of oil wells in areas without that great infrastructure (I think around 5
to 10,000 per mmbpd), additional pipelines (I guess piggybacked so the Naphtha diluent can be
recycled), and a bunch of new upgraders – one for every new 200 to 300,000 bpd. The existing upgraders
aren't in great shape, a lot of the skilled workforce from these actually left for USA when the
industry was nationalised. There is a significant shrinkage (I think 15 to 30%) in the upgraders
as they take out carbon to make the oil lighter (compared to hydrocrackers used in places in Canada
which add hydrogen from natural gas). They produce highly toxic waste streams of coke, sulphur
and heavy metals, which need to be safely stored for ever after (I wonder how that's going there
at the moment). The three phases of the Carabobo development, which was supposed to get to 1.2
mmbpd by 2018 don't seem to be going anywhere – oil is still being trucked I think, the new upgraders
are on permanent hold, the well services companies are pulling out, and the government can't afford
to buy the diluent naphtha. That is a recipe for prolonged decline, not growth to 8 mmbpd, which
was once proposed.
Ecuador has ultra heavy oil, discovered and undeveloped, of about 6 billion – but no-one has
figured out how to develop it commercially. The upgrader required has really been proved technically.
They were working with Ivanhoe on something that looked to me a bit like a CTL system, but Ivanhoe
went bust so I don't think this is going anywhere. Overall anything more than about 5 or 6 mmbpd
from extra heavy sources would be stretch over the next 20 to 30 years.
The recent UK production benefited mostly from Golden Eagle ramp up through 2015. Buzzard is by
far the largest single producer at about 180,000 bpd. It is due for an extended turn around this
year. It also more than doubled it's water cut over the last six months, so could be coming off
plateau quickly (ramp up was through 2007). It will be a contest between it's decline against
new production from Clair Ridge and Glen Lyon and 3 or 4 smaller projects over the next 2 years
(about 300,000 bpd combined plateaus).
The government prediction is for a gentle decline of about 15% overall to 2021, but if a lot
of the smaller producers get shut down in the near term it might be a bit steeper.
• Decade-long improvement in fuel efficiency in U.S. seen ending
• Light trucks, vans, SUVs account for 60% of U.S. vehicle sales
Last year, SUVs outsold any other type of passenger vehicle in Europe
for the first time, according to auto industry consultants JATO Dynamics.
The trend has continued in 2016, with demand for SUVs … accounting for a
quarter of sales in the biggest European countries.
Europe is a mirror of what's happening across the world. From China to the
U.S., drivers are buying bigger vehicles, while sales of fuel-efficient
hybrids struggle.
[In the U.S.] the average car sold in April achieved a fuel economy of
25.2 miles per gallon, down from a peak of 25.8 set in August 2014, just
before oil prices crashed, according to data from the Transportation Research
Institute at the University of Michigan. At current trends, this year will
mark the first drop in average U.S. fuel economy since at least 2007, the
data show.
"Fuel-economy improvement is really flatlining," said Sam Ori, executive
director of theEnergy Policy Institute at the University of Chicago. "The
gains completely stopped right at the same time that oil prices started
to decline."
Today in the U.S., light trucks, vans and SUVs account for 60 percent of
total vehicle sales - a level only reached briefly in 2005, when Brent crude,
the global oil benchmark, averaged $55 a barrel. It's now around $50. The
International Energy Agency said in May that less-efficient vehicles, including
four-wheel drives, "remain very much in vogue, a consequence of persistently
lower retail pump prices."
In 2008, when oil prices averaged $100 a barrel, the share of gas guzzlers
in U.S. total vehicles sales dropped at one point to just 43 percent.
With larger vehicles hitting the roads and Americans driving longer distances
as the economy recovers, U.S. gasoline consumption is set to rise to a record
in 2016, according to the Energy Information Administration. U.S. gasoline
demand will average 9.3 million barrels a day this year, surpassing the
peak set in 2007, the EIA said in its most recent monthly report.
The EIA forecast U.S. drivers will enjoy the cheapest gasoline this driving
season in 12 years.
In China, the world's second-biggest oil consumer, drivers are also opting
for larger vehicles as never before. While cheaper gasoline and diesel helps,
analysts said it's higher incomes - and a desire to impress relatives and
friends - that's driving the purchases. According to official data, vehicles
such as light trucks and SUVs accounted for almost 35 percent of total Chinese
passenger sales in April, up from 10 percent in 2010 and less than 5 percent
a decade ago.
You are right AlexS, Americans need to be more frugal and forward thinking.
My town wants to allow a gas station to be put in near the highway, there
is a gas station a short drive away. Not only will the gas station be mere
feet from a Category 1 trout stream, it will be almost at the level of the
stream. The three large tanks will be actually buried in the aquifer for
the town and have to be held down from floating. Everything runs off wells
here, so contamination will effect much of the town and wreck the aquifer.
To top it all off, the land is now a ride-sharing lot, something that
reduces fuel use and pollution as well as reduces the wear and tear on cars
(slowing down the need for vehicle replacement and all the energy/pollution
that involves).
There are gas stations just a few miles in either direction along the
highway.
US Weekly Petroleum
Status Report has US C+C production down 32,000 bpd for the last full week in May to 8,735,000
bpd. No surprises here, this is exactly what I had predicted. US lower 48 production was down
40,000 bpd for the week, Alaska was up 8,000 bpd.
This is important people, US crude oil production is now in full scale retreat.
If you doubt these doubt these falling production numbers then explain the climbing net import
numbers. US weekly net petroleum products imports, 3 month average and 6 month average reached
a two year high this week.
When production is falling, and consumption is not falling, then the only solution is import
more, a lot more.
We are importing, on average, almost one million barrels per day more than we were just
last November.
"... Well, all I can say is the 'plan' did not work out so well. The US LTO industry is 250 billion in debt and dead broke. It will have to hoc it's fleet of G-4 600's and all of it's copying machines just to frac it's DUC wells. The only way it can drill another shale well is paying for it with MasterCard, on installments. Its at a dead stop alright. ..."
"... Lots of roads got tore up, then they got fixed, sort of, with all those "taxes" paid. Nobody got too drunk and save for a few earthquakes out in the parking lot, everybody had a grand time. Now pay the bill -- The band, the hall, the beer distributor, everybody wants to get paid. Can't throw a party and not pay the bills. Its un-Texas like not to. ..."
"... Again the shale boom has made my normal business life a much difficult environment to conduct business. However, it seems to me, taking Texas as an example, where Rick Perry used to run around telling people that 99% of NEW jobs in the US were generated in Texas, was a direct result of the boom even though it made my life more difficult. From a government point of view, compared to the alternatives, was/is the shale boom more efficient at increasing the velocity of money compared to let us say "cash for clunkers" or all those "shovel ready jobs" where government at all levels, union bosses etc take their cut of the money before it is ever spent at digging the hole. ..."
"... I have hammered and hammered on this, but apparently future net cash flows do not matter to shale. That is a big problem. Future net cash flow are the most important metric for any business. If those cannot retire the debt, over the long term, the business cannot survive. ..."
"... PXD says they need $50 WTI and they will add rigs. Per their own 10K, if the price stays at $50 WTI, they have almost no PUD value. So which are we supposed to believe? Why would they add rigs when the net future cash flows from those rigs will not pay back their cost? ..."
"... Then, we have the issue of CEO pay. Of course, CEO pay is akin to the oil lease promoter, who gets paid whether the well succeeds or fails. Management is still getting paid high salaries, despite that the companies cannot afford to pay them. ..."
"... Was looking at a shale gas company, Eclipse Resources, over on Seeking Alpha. They lost .58 per share in 2013, 1.27 in 2014 and 4.46 in 2015. PV10 all categories is $212 million, long term debt $527 million. The top three in management are still tapping the company for $500-$700K in salaries. And, this company is talking about making a profit on $30 million (yes, that is the cost) Utica wells with record length laterals. At $2.00 gas. The company is OPERATING at a loss, and always have. ..."
"... Sorry if this kind of nonsense makes me a little emotional. ..."
"... My model keeps saying the oil price average will be $65 (more or less) over the next three years. I guess I need to update the input data, and it may be a little bit different. ..."
"... The shale companies have posted losses every quarter in the last five. The upper management keeps making the big bucks. ..."
"... Now that Is Over report from Pew Research Center reveals that between the third quarter of 2000 and the same period of last year, wages across the U.S. rose by an impressive 7.4 percent in real terms, driven largely by the oil and gas industry. ..."
"... Wages in energy-dependent communities rose by the most, in some cases more than twofold, such as in Texas. This shouldn't be surprising as the period reviewed coincides with the peak of the shale boom in the country, even though it also covers two periods of recession. ..."
"... Before we tout all the amazing benefits that the shale oil revolution has given society, we should first see who actually pays for those benefits, right? I mean if it ends up being society that pays for it, soon, or down the road with the other 19 trillion dollars of debt we are leaving our kids, then it really isn't the shale oil industry we should be thanking, is it? ..."
"Shale oil offers a predictable, manufacturing-like business model around which companies
can plan. And it can be stopped and started on a dime depending on oil prices."
Well, all I can say is the 'plan' did not work out so well. The US LTO industry is 250
billion in debt and dead broke. It will have to hoc it's fleet of G-4 600's and all of it's copying
machines just to frac it's DUC wells. The only way it can drill another shale well is paying for
it with MasterCard, on installments. Its at a dead stop alright.
Yes, Mr. Tea; it was a great party the shale industry threw. It was really fun for less than 1/100th
of 1% of American's who got free royalty income, not so good for the hundreds of thousands of
men and women that got hired, then fired. Shareholder equity had an OK time; most I'll bet wish
they'd never come.
Lots of roads got tore up, then they got fixed, sort of, with all those "taxes" paid. Nobody
got too drunk and save for a few earthquakes out in the parking lot, everybody had a grand time.
Now pay the bill -- The band, the hall, the beer distributor, everybody wants to get paid. Can't
throw a party and not pay the bills. Its un-Texas like not to.
Texas tea. If you are equating shale to the US government borrowing money to give everyone $600
to stimulate the economy, I think you are making Mike's point.
SS, I am trying to understand the why and hows. I try to leave emotion at the doorstep and see
things from a bigger picture.
Again the shale boom has made my normal business life a much difficult environment to conduct
business. However, it seems to me, taking Texas as an example, where Rick Perry used to run around
telling people that 99% of NEW jobs in the US were generated in Texas, was a direct result of
the boom even though it made my life more difficult. From a government point of view, compared
to the alternatives, was/is the shale boom more efficient at increasing the velocity of money
compared to let us say "cash for clunkers" or all those "shovel ready jobs" where government at
all levels, union bosses etc take their cut of the money before it is ever spent at digging the
hole.
The answer to that question give us great insight to the future in terms of where we may make
investments decisions today. Lastly, irrespective of the economics, not compared to yesteryear,
but the alternatives of today, based on the article cited and the actual decisions being in corporate
boardrooms it appears LTO is here to stay.
I start with reading 10K and 10Q, and with actual production data. Facts.
The emotion comes from reading the facts, and then matching them to the claims. The claims
appear to be at best, misleading, at worst, false.
Over a year ago, when 2014 10K came out, I noted here that almost every shale player would
have PDP PV10 less than long term debt at $50 WTI.
As it turns out, in looking at the 2015 10K, many have PV10 ALL CATEGORIES less than long term
debt. Further, most took great liberties with estimates of future production costs in even arriving
at the 2015 PV10 numbers.
I have hammered and hammered on this, but apparently future net cash flows do not matter to
shale. That is a big problem. Future net cash flow are the most important metric for any business.
If those cannot retire the debt, over the long term, the business cannot survive.
PXD says they need $50 WTI and they will add rigs. Per their own 10K, if the price stays at
$50 WTI, they have almost no PUD value. So which are we supposed to believe? Why would they add
rigs when the net future cash flows from those rigs will not pay back their cost?
I'd be glad if you could explain how any of these companies are going to make it at the current
WTI and HH strips.
Heck, I would be happy if you can explain how CLR was able to reduce estimated future production
costs by 60% year over year, but yet only reduce reserves 9%. I continue to be astonished that
no one has noticed stuff like this.
Then, we have the issue of CEO pay. Of course, CEO pay is akin to the oil lease promoter, who
gets paid whether the well succeeds or fails. Management is still getting paid high salaries, despite that the companies cannot afford to
pay them.
Was looking at a shale gas company, Eclipse Resources, over on Seeking Alpha. They lost .58
per share in 2013, 1.27 in 2014 and 4.46 in 2015. PV10 all categories is $212 million, long term
debt $527 million. The top three in management are still tapping the company for $500-$700K in
salaries. And, this company is talking about making a profit on $30 million (yes, that is the
cost) Utica wells with record length laterals. At $2.00 gas. The company is OPERATING at a loss,
and always have.
Sorry if this kind of nonsense makes me a little emotional.
Shale is here to stay, and I hope it can someday pay for itself, because that will mean long
term $100+ oil.
Most companies set up budgets and plans on a price forecast which may be higher or lower than
current prices. They take that price forecast and use it to estimate project economics. Therefore,
this company is using a higher price forecast.
My model keeps saying the oil price average will be $65 (more or less) over the next three
years. I guess I need to update the input data, and it may be a little bit different.
you say "Shale is here to stay, and I hope it can someday pay for itself, because that will
mean long term $100+ oil."
I think the odd favor that scenario. To your larger question question, I don't think any body
on shore US thinks they will make money on any drilling prospect, be they conventional or unconventional
with the prices we have seen over the last 6 months. Here is the question, where do you feel the
most comfortable buying production, when oil is at $110 or $28, and why. That is the same calculation
that is being made industry wide.
The article I cited above make some very good points, drilling and marketing risk are greatly
reduced, the mix of product (gor) is also known. The one, and it is a big unknown variable, is
price, but price is and has always been the unknown. The energy is there, the amount is know (within
certain parameters) and it is my professional life experience that the industry will find a way
to produce it, to make it "economic" that assumes a higher price, better efficiencies and do not
discount the possibility of certain tax incentives, we have seen them before.
Shallow, you need not explain the emotional component to your shale oil economic analysis to anyone,
sir. Thank you for being gracious, but certainly not to me you do not need to explain. You, like
thousands of other operators in America, stripper or otherwise, have been devastated by the price
collapse recently, caused entirely by overleveraged LTO oversupply. You have your OWN money, and
likely a good part of your life, invested in your production and in caring for your employees.
Its hard not to be emotional when you are getting run over by a freight train. A freight train,
I might add, that drilled 41,000 shale wells with finding costs way less than the even the KSA's
finding costs…because the shale oil industry has essentially not paid for it's wells yet. It probably
won't ever be able to pay for them. Yet, you are correct, upper management in every public shale
oil company in the country is still making tons of money, with little regard for shareholder equity
and the probability of bankruptcy. If it doesn't seem fair, it's not fair. Anybody cheerleading
for the shale oil industry needs to carefully re-examine their own values.
Hold your head up high, buddy. You were here before the shale oil industry fell on the floor,
you'll be here long after they are gone.
Now that Is Over report from Pew Research Center reveals that between the third quarter of
2000 and the same period of last year, wages across the U.S. rose by an impressive 7.4 percent
in real terms, driven largely by the oil and gas industry.
Wages in energy-dependent communities rose by the most, in some cases more than twofold, such
as in Texas. This shouldn't be surprising as the period reviewed coincides with the peak of the
shale boom in the country, even though it also covers two periods of recession.
Respectfully, Mr. Tea, the oil industry did not drive wage growth, a Federal monetary policy that
allowed limitless, low interest loans to the oil industry, particularly the shale oil industry,
is what drove wage growth. It was just another form of economic stimulus.
Before we tout all the amazing benefits that the shale oil revolution has given society, we
should first see who actually pays for those benefits, right? I mean if it ends up being society
that pays for it, soon, or down the road with the other 19 trillion dollars of debt we are leaving
our kids, then it really isn't the shale oil industry we should be thanking, is it?
"... But… the decline has only just begun. The price collapse caused the plateau in world oil production that begun about March 2015. However, the decline did not actually begin until January 2016. The dramatic rise in production from Iran has kept the decline from becoming obvious to everyone. However when the May production numbers come in, I think it will then become obvious to everyone. ..."
In conclusion, In spite of the recent increase in Russian production, as well as the slight increase
from the North Sea, and in spite of the dramatic production increase from Iran due to the lifting
of sanctions, world crude oil production is in decline. And while it is true that most of this decline
is due to the price crash, it remains to be seen just how much production will recover when the price
returns to… to… wherever it returns to before it stops.
But… the decline has only just begun. The price collapse caused the plateau in world oil production
that begun about March 2015. However, the decline did not actually begin until January 2016. The
dramatic rise in production from Iran has kept the decline from becoming obvious to everyone. However
when the May production numbers come in, I think it will then become obvious to everyone.
"... It is hard to pinpoint these decline rates exactly since each field is unique unto itself. What the industry generally believes is that offshore production declines at twice the rateof conventional onshore. ..."
"... That would put the offshore decline rate somewhere between 15-20% per year. These higher decline rates mean that the sudden halt to offshore development will result in BIG offshore production declines. ..."
"... Off a 22 million barrel per day production base-15-20%= 3.3-4.4 million barrels a day-gone. That is substantially more than the spare capacity of OPEC right now. That means that in just one year, the world oil supply could be put into deep undersupply (pardon the pun) as offshore exploration and development stagnate. ..."
"Offshore production has lower decline rates than shale does, but considerably higher decline
rates than onshore vertical developments.
It is hard to pinpoint these decline rates exactly since each field is unique unto itself.
What the industry generally believes is that offshore production declines at twice the rateof
conventional onshore.
That would put the offshore decline rate somewhere between 15-20% per year. These higher
decline rates mean that the sudden halt to offshore development will result in BIG offshore production
declines.
Off a 22 million barrel per day production base-15-20%= 3.3-4.4 million barrels a day-gone.
That is substantially more than the spare capacity of OPEC right now. That means that in just
one year, the world oil supply could be put into deep undersupply (pardon the pun) as offshore
exploration and development stagnate.
"... Offshore production has lower decline rates than shale does, but considerably higher decline rates than onshore vertical developments. ..."
"... That would put the offshore decline rate somewhere between 15-20 percent per year. These higher decline rates mean that the sudden halt to offshore development will result in BIG offshore production declines. ..."
"... That is substantially more than the spare capacity of OPEC right now. ..."
Offshore production accounts for 30 percent of total global oil
production. The percentage of global production has remained the same
since the early 2000s but the absolute amount of production has grown.
(Click to enlarge)
Today nearly 22 million barrels of oil per day is produced offshore;
the figure in the chart above includes all liquids.
Offshore production has lower decline rates than shale does, but
considerably higher decline rates than onshore vertical developments.
It is hard to pinpoint these decline rates exactly since each field is
unique. What the industry generally believes is that offshore production
declines at twice the rate of conventional onshore.
That would put the offshore decline rate somewhere between 15-20
percent per year. These higher decline rates mean that the sudden halt to
offshore development will result in BIG offshore production declines.
Off a 22 million barrel per day production base, 15-20 percent would
equal 3.3 to 4.4 million barrels a day-gone. That is substantially
more than the spare capacity of OPEC right now. That means that in
just one year, the world oil supply could be put into deep undersupply
(pardon the pun) as offshore exploration and development stagnate.
"... So I am asking you or whoever thinks price had any role in CAPEX to show me where is that correlation between price, CAPEX and Debt? If Debt has been increasing progressively every single year regardless of price how can you say that CAPEX has any correlation with price? ..."
"... There is clear correlation between oil price and oil companies capex. Combined capex of the U.S. E&Ps was down more than 40% last year and will decline further this year. ..."
"... The issue with the shale players is that the decline in capex is not sufficient to achieve cashflow neutrality. Operating cashflow declines even more than capex; therefore their debt is rising. They were outspending cash when oil was at $100/bbl, and they continue to outspend it with much lower capex at $30-50/bbl. ..."
"... Just like Tesla :-). ..."
"... Big guys/majors that you mentioned that also reduced CAPEX are completely different animal: they are vertically integrated, they produce overseas, in different currencies, they do all kinds of deals, they have economy of scales, and they are big and established long enough to make balance of payments in offices in New York or Panama and not just on the oil field, they have army of lobbyist, tax breaks, whatever they like. You can't compare them with shale. They are protected like polar bears. ..."
"... Disturbing indeed. That said, at $75k/BOPD (giving credit for what I suspect is ample PUDs), YE15 value is about $16B. They will survive…but debt will tie their hands until oil is above $150/bbl. ..."
"My point is in response to the price collapse at the end of 2008, CAPEX in 2009 was cut substantially
from 2008 levels."
But that is only true if you pick years 2008 & 2009 and compare it. If you pick 2008 and 2015
CAPEX did not get cut substantially considering the price drop. CAPEX is 3x higher than in 2008
and debt is 6x higher. So I am asking where is correlation with the oil price in 2015? There is
no correlation because CAPEX should be zero in 2016.
Yes they need the price of $150 for the next 10 years if you look just debt but hey that's
why there is Chapter 11 so they will still be around for few more years (like Halcon) drilling
little bit here and there even without $150 price.
I don't disagree that they should have spent less, or even zero, CAPEX in 2015.
I am just making the point CAPEX was cut in half in 2009 as a result of 2008 crash, and again
in 2015 as a result of 2014-15 crash, and in half again as prices trended even lower second half
2015 into 2016.
I agree with you that CAPEX was cut but I don't agree with you and Dennis that price was factor
because look from 2008 untill 2015 BOE went from $77.66 (2008) to $31.48 (2015) and in between
and debt increased from $376 million to 7 billion regardless of price movement.
So I am asking you or whoever thinks price had any role in CAPEX to show me where is that
correlation between price, CAPEX and Debt? If Debt has been increasing progressively every single
year regardless of price how can you say that CAPEX has any correlation with price?
12/31/2008.
Long term debt $376 million
12/31/2009
Long term debt $524 million
12/31/2010
Long term debt $926 million
12/31/2011
Long term debt $1.254 billion
12/31/2012
Long term debt $3.540 billion
12/31/2013
Long Term Debt: $4.651 billion
12/31/2014
Long Term Debt $5.929 billion
12/31/2015
Long Term Debt $7.118 billion
The only correlation that I see if you look numbers that you have put together is that CLR
produce LESS debt if produce LESS oil and produce MORE debt if produce MORE oil.
2008 Production 36,018 BOEPD
2008 Long term debt $376 million
2015 BOEPD 221,715 66% oil
2015 Long Term Debt $7.118 billion
There is clear correlation between oil price and oil companies capex. Combined capex of
the U.S. E&Ps was down more than 40% last year and will decline further this year.
The issue with the shale players is that the decline in capex is not sufficient to achieve
cashflow neutrality. Operating cashflow declines even more than capex; therefore their debt is
rising. They were outspending cash when oil was at $100/bbl, and they continue to outspend it
with much lower capex at $30-50/bbl.
In that sense you are right that they "produce LESS debt if produce LESS oil and produce MORE
debt if produce MORE oil."
" In that sense you are right that they "produce LESS debt if produce LESS oil and produce
MORE debt if produce MORE oil."
That is good that we agree because I was not sure that we looking at the same numbers that
Shallow posted :-)
Well I was strictly speaking about shale and the oil price, and I said that in one of my posts
above. But we have to remember that they are significant, (with tar sands nearly half) part of
oil production in North America so obviously it is very important to see how their finances distort
the market.
Big guys/majors that you mentioned that also reduced CAPEX are completely different animal:
they are vertically integrated, they produce overseas, in different currencies, they do all kinds
of deals, they have economy of scales, and they are big and established long enough to make balance
of payments in offices in New York or Panama and not just on the oil field, they have army of
lobbyist, tax breaks, whatever they like. You can't compare them with shale. They are protected
like polar bears.
Disturbing indeed. That said, at $75k/BOPD (giving credit for what I suspect is ample PUDs),
YE15 value is about $16B. They will survive…but debt will tie their hands until oil is above $150/bbl.
For volumes you need to take into account the margin of error of data. Any attempt to exceed the
margin of error of input data by some voodoo methods is suspect. That's a pretty serious and debilitating
disease a lot of "graphic artists" working on oil production forecasts suffer from: they never try
to address the question of the accuracy of input data and resulting "zones of uncertainty" if future
volumes. For example if margin or error of the input data is 0.1Mb/d, any change below that is essentially
the same as no change. It represents "status quo".
All this attempts to guess the future volume "to a barrel" are futile, because people who are
doing this do not understand the concept of the "margin of error" (and probably never will). That
actually create excellent propaganda opportunities that were used during oil glut paranoia.
But in any forecast the most important variable is not exact volume, but guessing the correct
trend, the first derivative of the volume dynamics Which BTW is also difficult, to the extent that
the EIA honchos can be call charlatans.
So before we discuss the question of forecasting correct volume, we need to address the question
of forecasting of the correct trend. There are laws of economics, there is pretty reliable information
about the US LTO reservoirs, there is significant volume of historical data, and there are laws of
physics. All of that makes pretty reliable short-term forecasts of the trend possible.
For example nobody expect that LTO producers will increase production this year. This is a pretty
reliable forecast, that cuts 50% of possibilities.
Also any simplistic adherence to neoclassical economy (religious belief in supply/demand equilibrium
as a normal condition of the market) is suspect in the world of HFT. It ignored the existence of
what we called arbitrary coherence. The basic idea of arbitrary coherence is this: although even
if initial prices are completely arbitrary, once those prices are established they will shape future
prices serving as an anchor for market participants (this makes them "coherent"). For oil this effect
is called "low price forever" mentality which now affects us all became of "legitimacy" of recent
"below $30" prices, even if they were achieved by blatant manipulation of the markets.
That's why many "market watchers" are now too shy to predict oil price spike because of destruction
of the industry caused by the regime of low oil prices in 2015-2016.
"... One analyst told CNBC that he doubted the very foundation of the U.S. shale oil industry which he said had been founded and expanded on cheap money and had effectively been a "Ponzi scheme" – an investment operation that generates returns for older investors by acquiring new investors. ..."
"... "I think in ten years' time someone is going to write a great book and make a great movie about the shale industry in the U.S. because I think it is, quite frankly, one of the biggest Ponzi schemes known to mankind," Gavin Wendt, founding director & senior resource analyst at MineLife, told CNBC on Thursday. ..."
One analyst told CNBC that he doubted the very foundation of the U.S. shale oil industry
which he said had been founded and expanded on cheap money and had effectively been a "Ponzi scheme"
– an investment operation that generates returns for older investors by acquiring new investors.
"I think in ten years' time someone is going to write a great book and make a great movie
about the shale industry in the U.S. because I think it is, quite frankly, one of the biggest
Ponzi schemes known to mankind," Gavin Wendt, founding director & senior resource analyst at MineLife,
told CNBC on Thursday.
On Friday, May 13, IHS Energy released an alarming new study. It found that the volumes
of oil and gas discovered outside of the U.S. last year were the lowest since 1952.
Oil alone set a record low, with only 2.8 billion barrels of oil equivalent found during
2015.
The vast majority of large, conventional undiscovered oil and gas fields are offshore. Unfortunately,
these fields are uneconomical to develop with oil prices below $80 per barrel.
That's why a few years ago, when prices first dipped under $60, many oil companies refocused
their efforts. They bet big on U.S. shale.
Now, many are regretting that decision. Most shale basins – other than the Permian – are
losers at current WTI prices. (Though there are some winners, as I showed you
here .)
Reply
"... Art says that the average debt to cash flow ratio has increased 4 times in 2016. Gas production is falling in all shale gas plays with the exception of the Utica which managed a small increase. It would be interesting to know more precisely where all of this debt is being invested and how much is in the Utica. ..."
"... I asked Berman about a year ago if he had changed his opinion on the gas shales. He said he had not. I think Berman has been right all along. I just don't think geology can be trumped with with financial accounting. Notwithstanding GORs in the LTO plays, the first Seneca Cliff may well be natural gas. ..."
"... as two third of production represents shale, the decline may be much faster than in previous declines; ..."
Art Berman has a new post out on shale gas. He goes into some detail on the 1st Qtr financial
results of several companies that are not often discussed here. Among them: Devon, Southwestern,
EQT, Encana, Rice.
Art says that the average debt to cash flow ratio has increased 4 times in 2016. Gas production
is falling in all shale gas plays with the exception of the Utica which managed a small increase.
It would be interesting to know more precisely where all of this debt is being invested and how
much is in the Utica.
It was a warm winter, storage is already full. They only need to average 68 mmcf per week to
totally fill their storage. The supply can stay low this year and still have storage in good order
for next winter.
Now if the 2016-17 is cold and storage drops significantly, then the spot light will be on
the producers and how they can ramp up their production. If they can't, due to money problems
or any other issues, that is when your sudden price increases may occur. It won't be until the
producers are put under pressure to perform, that we will know the result. After the 2013-14 arctic
vortex, they did step up to the plate and performed. Can they do the same in 2017 with limited
money supply, that will be interesting to watch!
I think you are both correct. Shale gas production seems to be falling, though not as fast
as I would like it to. Storage is market supply. PDP reserves and PUD reserves are the unknowns
to me.
The SOB at the family reunion seems to be the DUCS. At what price are those wells really economic?
How many exist and where are they in relation to the economic sweet spots? If a DUC can't be counted
as PDP or PUD then to me it's a plugging liability and who would pay money for a liability?
What about gathering systems or production facilities to get from the well head to a point
of sale with a mid stream provider?
There in lies the rub.
I asked Berman about a year ago if he had changed his opinion on the gas shales. He said he
had not. I think Berman has been right all along. I just don't think geology can be trumped with
with financial accounting. Notwithstanding GORs in the LTO plays, the first Seneca Cliff may well
be natural gas.
In my view there are three factors influencing the supply/demand picture and may come as a
surprise to the market.
– as two third of production represents shale, the decline may be much faster than in previous
declines;
– net imports could turn into net exports and this will draw much faster on inventories;
– power burn is around 20% higher than last year (see beow chart) and rising much faster than
even renewables due to retirement of coal power plants; in my view the reason for the high power
burn could be also role of gas as a swing producer for PV and wind generation;
"... If one assumes that gas stays low priced, WTI will need to pass $55 sustained for 3 months for most US LTO producers to not show losses for GAAP purposes. This, of course, does not include hedges. ..."
ExxonMobil and Chevron also had large North American losses.
Due to the high CAPEX spent 2011-14, and given depreciation, depletion
and amortization methods selected by US producers, expect $20-$25 per BOE
in D,D & A for US oil weighted LTO producers for at least the next 3 years.
Then add in $8 or more of LOE, $3-5 G & A, and $4-$7 in interest, all in
BOE terms. Also, some monetized gathering, so there could be expenses there.
Also include severance taxes of 6-10% of $ per BOE sold.
If one assumes that gas stays low priced, WTI will need to pass $55
sustained for 3 months for most US LTO producers to not show losses for
GAAP purposes. This, of course, does not include hedges.
"... "cash flow neutral" is not good if you are actually in the oil business. The point in the exercise is to make money . I won't now get argue with you, except to ask what is your definition of profitable "enough." Is 80 dollars profitable enough to manage new debt and pay down old debt with wells that decline 73% in 3 years? No, not in the face of declining productivity and even higher costs. ..."
"... My analysis of SEC fillings shows that a vast majority of shale players were deeply cash negative even before the drop in oil prices. This includes the largest oil producers in the Bakken, Continental and Whiting. ..."
"... It is just hilarious that you got call from WSJ just right now to have a chat after all has been printed regarding fake shale "technology improvements", "efficiency", and "energy revolution" in general. ..."
"... Mike has opened several investment bankers eyes over there. These guys believed the shale guys break evens until the 2015 10K came out, and some of us started saying, "hey, these guys are ALL insolvent at $50 WTI, and the price is currently $30". ..."
I would consider XOM and Statoil as major oil companies. Both are involved in LTO.
Rune Likvern showed the Bakken LTO players were cash flow neutral before the price crash, but
perhaps there are no more good wells left to drill.
I think $80/b will be enough for the current average well to be profitable. I agree that eventually
average new well EUR will decrease and higher prices will be needed for profitable wells. The
figure below shows debt was being paid down in 2013, based on Rune Likvern's analysis.
Since that time well costs have decreased and lower prices may be adequate ($80/b rather than
$100/b).
Yes, Dennis; I know they are majors. I suspect they would like to have now stayed out of the shale
oil and shale gas business completely.
I appreciate your work a lot but I've leaned over the years to not get in pissing matches with
you, Dennis. You are into numbers, I am into solving problems in real life. For instance, "cash
flow neutral" is not good if you are actually in the oil business. The point in the exercise is
to make money . I won't now get argue with you, except to ask what is your definition of profitable
"enough." Is 80 dollars profitable enough to manage new debt and pay down old debt with wells
that decline 73% in 3 years? No, not in the face of declining productivity and even higher costs.
Take care, sir; and thanks for the venue to occasionally blow down my SICP.
Dennis. XOM, through it's subsidiary, XTO, lost over $800 million in the first 90 days of 2016.
I should probably let Rune address this, but the impression I get from him is that Statoil
likewise has suffered some heavy losses in the lower 48.
Furthermore, look at Schlumberger CEO recent comments about the profitability of lower 48 for
service companies.
We have beaten some of this stuff to death, but we have a large incentive to do so.
So I am going to keep at it, LTO is high cost, it generally needs prices of at least those
seen in 2010-2014 to be successful. Practically every LTO company has PDP PV10 less than long
term debt at $50 oil. Further, this is after most knocked the crap out of estimated future production
costs (IMO they had to fudge some numbers to even get them where they were reported).
99% of US residents want to believe that the "shale renaissance" means $20-$30 oil for the
next 20 years. I want to help make sure they, and Wall Street in particular, know that isn't going
to work.
I also want it known the reason there is so much interest in LTO in the lower 48 is because
these large companies have few other options. We have went through those.
Finally, we do not want to go through $20-$30 WTI again. It has been a harrowing experience.
Maybe no traders read this stuff, but if they do I want them to know if they are shorting oil
they better have good timing, because the price is STILL far below what is needed to meet estimates
of future demand.
Dennis, I will again say thank you for keeping POB going.
My analysis of SEC fillings shows that a vast majority of shale players were deeply cash negative
even before the drop in oil prices. This includes the largest oil producers in the Bakken, Continental
and Whiting.
One of a few exceptions is EOG, which was cash-positive in 2013 and 2014. Others were large
E&Ps with significant conventional assets (such as Oxy)
Dennis wrote; "The figure below shows debt was being paid down in 2013, based on Rune Likvern's analysis."
What my chart shows is that some of the investments/CAPEX was recovered [temporarily cash flow
positive] while oil prices were high, WTI above $100/bo.
It is not possible to derive from the chart how all the surplus [positive cash flows] was disposed.
Positive cash flows have likely been used for dividend payments, pay down some principal and/or
increase cash to make companies better prepared to ride out what many expected to be a temporarily
down leg in the oil price.
For the months Jan – Mar-16, my estimates show that for all Bakken(ND) it was cash flow
negative of about $1.1 – $1.2Billion .
That explains the resilience of the Bakken LTO extraction.
"I think $80/b will be enough for the current average well to be profitable."
Current as in existent producing wells?
And is $80/bo (@WH) a weighted average price?
Average for May-16 is $33/bo for ND sweet (and nat gas now comes with a loss on sales).
The thing is, and due to the geometrical shape of the profile from the existing producing wells,
the longer the price remains low, the higher it needs to become later to reach a weighted average
of $80/bo.
The $80/b is a breakeven price for a well drilled today, including only the cost of debt for
that well.
Imagine a company who has bought up some existing leases from a bankrupt company. They are
a company with deep pockets that can borrow at the prime rate.
For such a company, or a well run LTO player such as EOG, a 2014/2015 average LTO well in the
Bakken, or Eagle Ford breaks even at about $80/b at the refinery gate.
The average well will not be profitable below $80/b.
The companies that continue to drill and complete wells are just trying to stay afloat, hoping
other companies go bankrupt.
Or they think that most of their wells will be above average.
:-)
To be honest I expected the decline rates to be much higher in the LTO plays at current price
levels than we have seen.
The DUCs can pay back the completion costs at $50/b. The money spent on drilling cannot be
unspent, so perhaps that explains some of the continued well completion.
Thanks Mike.
When 2 years ago at the time of oil price collapse I first looked at this "black box" called LTO
the only people that made sense regarding LTO economics were you, shallow, Mr Berman, and Mr.
Likvern. 4 people in the whole English speaking world!! There was one more person in Russian language
that I have read his thoughts where he touched on LTO economics but more in context of general
oil depletion.
So 1000's of blogs, 1000's of tv channels, 1000's of newspapers and only 4 people
that made sense regarding this LTO subject in English!!! So after 2 years when shale economics
are crystal clear there are still 4 people in English speaking world talking common sense!! Unbelievable.
It is just hilarious that you got call from WSJ just right now to have a chat after all has
been printed regarding fake shale "technology improvements", "efficiency", and "energy revolution"
in general.
If you get ever invite by CNBC/Bloomberg for live TV appearance please let us now
so we can all watch :-)
But I know that they don't want you near their parking lot because their audience is not ready
to handle the truth. They will bring Mr. Ward who is not really independent analyst but he was
part of shale for so many years so of course he knows the numbers. But he will only say things
in small dosages, one tea-spoon at the time so audience can absorb the news in small bits.
Have a nice day.
Ves. Mike deserves some credit for taking the message to Oilpro. Rune and Enno do too.
Mike has opened several investment bankers eyes over there. These guys believed the shale guys
break evens until the 2015 10K came out, and some of us started saying, "hey, these guys are ALL
insolvent at $50 WTI, and the price is currently $30".
Suddenly some light bulbs started going off that a lot of BS was being tossed around.
Shallow. Yes, Rune and I did mention Mr. Likvern but forgot about Mr Enno. That is some great
stuff that Enno is doing and I am always wondering how he finds time with data that he is collecting
because I am always short on time.
And Mr. David Hughes at this website http://shalebubble.org
"... Some days ago I had the opportunity to watch a picture titled "The Big Short", an opus on the 2008 financial crisis. It portraits remarkably well how the marriage of ignorance with the lack of scruples can concoct the most toxic of outcomes. The so called "shale oil boom" is not much of a different story, only perhaps at a different scale. ..."
"... This contraction cycle will resound for years to come. Existing fields decline at a rate somewhere between 4% to 5% per year, meaning that the industry needs to bring online additional 3 Mb/d to 4 Mb/d every year just to keep extraction levelled. The investment deferrals under way and the time lag required to bring new fields online guarantee this replacement will be missed several years going forwards. ..."
"... Rystad Energy, a Norwegian petroleum and gas business intelligence consultancy, projects new extraction projects to miss the yearly decline of existing fields for at least the next five years . This consultancy expects an overall extraction decline of 300 kb/d this year, 1.2 Mb/d in 2017 and 2018 and deeper declines in 2019 and 2020. ..."
"... There are also reasons to believe the IEA is underestimating consumption , but this estimate produces a conservative (nearly best case) scenario: growth of 1.25 %/a. ..."
"... the extra stocks built by the OECD can alone keep consumers happy until the end of 2017; to go beyond that China has to follow the same strategy. However, if the trends identified here prevail, by the beginning of 2018 consumption will be exceeding extraction by almost 3 Mb/d, exhausting the remaining stocks of 0.5 Gb in a matter of months. ..."
"... The successive supply destruction - demand destruction cycles are the key dynamics of peak oil at an yearly scale. These cycles push left and transform each curve in succession, eventually producing a stall of traded volumes and finally a decline. The petroleum market has endured a supply destruction cycle for almost two years now, that while clearly closing, is yet far from the 100+ $/b price required to provide a reversing signal to the industry. With various petroleum exporting nations on the brink - in great measure due to the financial machinations concocted in the US - this supply destruction cycle might have been just too long. ..."
"... Present supply destruction cycle is coming to an end. ..."
Titling the
last press review of 2015
I asked if that had been the year petroleum peaked. The question mark
was not just a precaution, the uncertainty was really there. Five months later the reported world
petroleum extraction rate is pretty much still were it was then. This is not a surprise, but the
impact of two years of depressed prices is over due.
Nevertheless, during these five months of lethargy the information I gathered brings me considerably
closer to remove the question mark from the sentence and acknowledge that a long term decline is
settling in. Understanding the present petroleum market as a feature of the supply destruction -
demand destruction cycle makes this case clear.
Looking Backwards
Worldwide petroleum extraction hit some sort of ceiling back in 2004, once it crossed above 70
Mb/d. The volume coming to the market kept increasing, but at a shy pace. From 2004 to 2012 the extraction
rate grew only 3%, from 72 Md/b to 74 Mb/d.
At the same time, the Brent index endured a remarkable rise from 2004 to 2008. Some called this
the "end of cheap oil", alluding to the increasing need for lower return-on-investment resources:
ultra-deep water, heavy petroleums, Arctic, etc. Nevertheless, the price collapsed to a third from
2008 to 2009. Back then I explained how
the concept of an ever rising petroleum price was at odds with "peak oil"
. For the world extraction
to enter a declining trend, periods of supply destruction must take place to keep those higher entropy
resources at bay.
Today the market lives the second supply destruction cycle since the 2004 shift. In reality these
cycles are lasting far longer than I anticipated, showing a considerable time lag in the adjustment
of the supply curve. There is however something especial to this supply destruction cycle, that could
possibly be sealing the end of growth to what petroleum is concerned.
The Miracle
Some days ago I had the opportunity to watch a picture titled "The Big Short", an opus on the
2008 financial crisis. It portraits remarkably well how the marriage of ignorance with the lack of
scruples can concoct the most toxic of outcomes. The so called "shale oil boom" is not much of a
different story, only perhaps at a different scale.
From 2011 to 2013 the extraction of petroleum from source rocks and other low permeability
reservoirs in the US grew almost 2 Mb/d. These were remarkable days for the industry, with plenty
of jobs created and a major revival to the American hands-on approach to business. However, such
a rapid growth on a relatively small resource left many wondering if something else was at play.
By the beginning of 2014 it was becoming evident that the "shale oil boom" had been largely fuelled
by the finance industry, that was feeding relentless amounts of what is sometimes called "dumb money"
to be burned on America's source rocks. The scheme was simple: petroleum companies inflated their
reserve assessments 10 times or more and imprudent investors kept buying bonds irrespective of losses.
They thought they were investing on conventional 30 years petroleum bearing wells, when in fact were
getting 3 years lifetime wells.
By late 2014 "shale oil" extraction in the US had increased 3.5 Mb/d since 2011, but at that point
the price of petroleum in international markets was already coming off a cliff. 200 G$ rested on
the American junk bond market, left to be trounced by a deep supply destruction cycle.
A bond default and bankruptcy wave formed throughout 2015, and is still surging today. One third
of the companies involved in the "shale boom"
should go belly up
this year alone
. However, these financial owes have not yet translated into a visible decline
in extraction rates. This means that even bankrupt, petroleum companies are still bringing new source
rock wells online, only deepening further the present supply destruction cycle.
When the WTI index (the regional equivalent to Brent) sank under 40 $/b late last year, Arthur
Berman produced
a most elucidating set of maps
spatially portraying well profitability. At those prices only
a small fraction of the wells extracting petroleum in the Permian formation were profitable.
And this is the remarkable achievement engendered by the marriage of America's petroleum and finance
industries. Petroleum extraction became effectively insulated from prices; bankrupt or not, the wells
on the Permian, Bakken and Eagle Ford formations will keep pumping - because the dumb money keeps
burning. For the rest of the world, this is like inserting a sliver of 4 Mb/d at 0 $ at the far left
of the supply curve, pushing all other resources rightwards. For an international industry already
in contraction, this is like adding gasoline to the fire.
Supply Destruction
The present supply destruction cycle dates back to the beginning of 2014 - it actually unfolded
before the price collapse. While prices still held above 100 $/b, international petroleum companies
started facing issues regarding shareholder revenues. The supply curve is simply becoming too steep,
when resources such as "Arctic oil" or "pre-salt" enter the portfolios of petroleum companies. The
scale down of exploration activities started that year, as so the slashing of staff. In 2014 circa
100 000 jobs were laid off by the industry
.
The price rout brought about by the shale miracle only accelerated this contraction. In 2015 the
number of jobs laid off
is estimated to have hit 250 000
. 2016 could end up close to that.
In panic mode, petroleum companies have been postponing or outright cancelling projects. Recent
estimates point to
a total of 400 G$ in deferred investments
. A new wave of mergers in the industry is now expected.
This contraction cycle will resound for years to come. Existing fields decline at a rate somewhere
between 4% to 5% per year, meaning that the industry needs to bring online additional 3 Mb/d to 4
Mb/d every year just to keep extraction levelled. The investment deferrals under way and the time
lag required to bring new fields online guarantee this replacement will be missed several years going
forwards.
Rystad Energy, a Norwegian petroleum and gas business intelligence consultancy, projects new
extraction projects to miss the yearly decline of existing fields
for at least the next five years
. This consultancy expects an overall extraction decline of 300
kb/d this year, 1.2 Mb/d in 2017 and 2018 and deeper declines in 2019 and 2020.
Looking Forwards
In a previous post
I analysed the gap between petroleum extraction and consumption reported by
the IEA. Using data fragments published by the press I then produced an estimate for China's stock
flows that greatly explains what have been heretofore unaccounted barrels. In essence, the OECD and
China could have amassed together a total of extra 900 Mb in stocks since the beginning of 2014.
Using this estimate for worldwide stocks I was then able to compute world petroleum consumption
for the past two years.
There are also reasons to believe
the IEA is underestimating consumption
, but this estimate produces a conservative (nearly best
case) scenario: growth of 1.25 %/a.
Matching the outlook produced by Rystad with this consumption trend one can start the always risky
exercise of predicting the future. In this case I projected forwards the consumption pattern of 2015
- with a double slump in later Winter and Spring, and the Summer up-tick - increasing at the steady
pace identified before. As for extraction, I simple spread Rystad's outlook into a monthly dataset.
The end result can be observed in the graph below.
The extraordinary stocks built by the OECD and China since 2014 are projected to hit 1 Gb right about
now, but also to soon stop growing. None of this counts with the fires in Alberta, or the social-economic
owes endured presently by Nigeria or Venezuela. Still, in this conservative scenario consumption
is just about to exceed extraction.
In the scenario above I also made the exercise of estimating how long can these extraordinary
stocks last if they are immediately released on the market to stave off an immediate price reaction.
That being the case,
the extra stocks built by the OECD can alone keep consumers happy until
the end of 2017; to go beyond that China has to follow the same strategy. However, if the trends
identified here prevail, by the beginning of 2018 consumption will be exceeding extraction by almost
3 Mb/d, exhausting the remaining stocks of 0.5 Gb in a matter of months.
How likely is this scenario? Is the OECD willing to bring its stocks promptly on the market to
keep prices where they are now? Or will it wait for prices to rise to provide breathing air to the
petroleum industry? And for how long can countries like Iraq, Nigeria or Venezuela withstand prices
under 100 $/b?
As the events of recent months show, it might be far more likely for some disruptive happening
to shake things up, than for these pretty trends to endure. In any case, this supply destruction
cycle is coming to an end sooner rather than later. The market will eventually have to fix the widening
gap projected in the graph above.
Consequences
These two years of supply destructive prices have pushed various important petroleum nations and
regions to the brink. If there is some unexpected event shaking up the petroleum market, it will
likely be in one of these places.
Iraq
- a country in war and divided in four different zones of military influence.
The impact of low petroleum prices on the Bagdad budget is postponing a victory over Daesh and
brewing political chaos. The increase in extraction of recent years halted and could reverse if
the politico-military situation does not improve. Daesh' burnt land policy is not helping either.
Nigeria
- shortages of hard currency have greatly impaired daily economic life and
an IMF intervention seems likely. In parallel, rebel groups have entailed a series of sabotage
operations on petroleum assets. Petroleum extraction should decline visibly in the next few years
and some fields even abandoned if petroleum prices stay below 60 $/b.
Venezuela
- overwhelmed by a snowball effect where under-priced petroleum causes such
economic disruption that impacts extraction itself. Exporting less petroleum for less money and
on the verge of serious social convulsion.
Canada
- petroleum regions in depression menace to drag down the whole economy with
visible impacts on housing and all industries related to extraction. Number and size of new projects
greatly reduced in recent months may augur an almost unthinkable long term extraction decline
in the country with the largest claimed petroleum reserves in the world. The long term effect
of the wild fires raging presently in Alberta is still unknown. If petroleum facilities are destroyed,
it might not be easy to recover with prices under 50 $/b.
Angola
- ran out of hard currency reserves to pay foreign contractors, sending the
latter on the run. Presently negotiating an aid programme with the IMF. Meanwhile, the ruling
regime has imprisoned numbers of opponents. Petroleum extraction bound to decline in the next
few years.
Azerbaidjan
- for long in "secret" talks with the IMF over an aid programme. Ambitious
prospects for export hikes are likely unattainable.
Mexico
- lost 1 Mb/d to depletion during the past ten years and is unlikely to hold
or halt the decline. Relevant downwards reserve revisions have been conducted in recent times.
Brasil
- engulfed in political chaos tied to misuse and mismanagement of its national
petroleum company, Petrobras, one of the most indebted companies in the world. The pre-salt resource
seems adjourned
sine die
.
North Sea
- extraction is expected to stop in 100 different fields throughout 2016.
Conclusion
Depending on how the OECD (and perhaps China) decide to manage their extra petroleum stocks, the
shift to a new demand destruction cycle closing the gap portrayed in the graph above will be complete
by early 2018 the latest. If something goes seriously wrong with one of the key petroleum exporting
nations, this shift could happen overnight.
What will such new cycle bring? Recent experience provides some clues: it took eight years for
world extraction to rise from 72 Mb/d to 74 Mb/d; the so called "shale boom" required four years
at prices above 110 $/b. These long time lags mean that Rystad's declining outlook is by this time
almost certain.
The coming demand destruction cycle is therefore likely to be a long one too. And at some point
it can invert the extraction trend upwards. In such a scenario, can extraction return to the 80 Mb/d
rate of 2015? That is the big question, which I will abstain from answering definitively. Looking
at it from the other side of the equation, for such a scenario to ever materialize, demand must withstand
again a good number of years at high prices without undershooting.
The successive supply destruction - demand destruction cycles are the key dynamics of peak
oil at an yearly scale. These cycles push left and transform each curve in succession, eventually
producing a stall of traded volumes and finally a decline. The petroleum market has endured a supply
destruction cycle for almost two years now, that while clearly closing, is yet far from the 100+
$/b price required to provide a reversing signal to the industry. With various petroleum exporting
nations on the brink - in great measure due to the financial machinations concocted in the US - this
supply destruction cycle might have been just too long.
The Take Away
"Shale oil" is effectively insulated from prices by the US finance industry.
Present supply destruction cycle is coming to an end.
After two years of low prices, extraction is set for a multi-year decline.
New demand destruction cycle to start in the next 18 months, depending on how stocks are managed.
A return to an extraction rate of 80 Mb/d seems unlikely for the foreseeable future.
"... Tom Ward, formerly of Chesapeake and Sandridge, yesterday on CNBC. "The dirty little secret in our business is that you cannot grow production within cash flow.". This, my friends, is a statement guys like Mike and me have been waiting for the "shale barons" to admit. ..."
"... At least he admits it. They claim they are drilling "world class" reservoirs, but they drill hundreds of wells a year and NEVER reach a point where they can develop out of cash flow. That is far from a world class reservoir. ..."
"... When even hard core businessmen stop making sense, we know that is just another sign of a failing society. The ride down is going to produce some strange actions and some strange bedfellows. ..."
Tom Ward, formerly of Chesapeake and Sandridge, yesterday on CNBC. "The dirty little secret
in our business is that you cannot grow production within cash flow.". This, my friends, is a
statement guys like Mike and me have been waiting for the "shale barons" to admit.
At least he admits it. They claim they are drilling "world class" reservoirs, but they drill
hundreds of wells a year and NEVER reach a point where they can develop out of cash flow. That
is far from a world class reservoir.
When even hard core businessmen stop making sense, we know that is just another sign of a
failing society. The ride down is going to produce some strange actions and some strange bedfellows.
Reply
"... as a newbie to post but a long time reader of this blog, i think you hit the nail on the head. I have participated in LTO wells with CLR and others in Oklahoma (we own minerals) and have followed the companies who are active there since the "discovery" of the Woordford and others. Paying particular attention to CLR when they use the words like "patience" before starting to drill again, this is a sea change in attitude. ..."
"... I for one am in the camp that with higher frac loads and increased number of stages not only does the IP rate increase but I think the ultimate recovery also increases as more rock is broken down and open to the well bore. again just MHO, time will tell. ..."
"... One other quick point, a lot of the LTO players are selling assets elsewhere and buying leasehold in SCOOP and STACK. Over pressured, great infrastructure, favorable business climate, now if we can just get rid of the pesky earthquakes. ..."
Shallow sand, As for shale, it is very dependent on credit. If credit does not come back as prices rise,
and just develops out of cash flow, I think the actual data from CLR is evidence that a very high
price will be needed for it to begin to grow again.
Exactly. LTO companies will not be able to rump up production because:
1. They have little or no positive cash flow
2. Need to service accumulated (huge) level of debt
3. Can not increase the level of debt further, as they fell out of favor for Wall Street.
as a newbie to post but a long time reader of this blog, i think you hit the nail on the
head. I have participated in LTO wells with CLR and others in Oklahoma (we own minerals) and have
followed the companies who are active there since the "discovery" of the Woordford and others.
Paying particular attention to CLR when they use the words like "patience" before starting to
drill again, this is a sea change in attitude.
Their stock price has been rewarded I think because they have hinted that their priority is
maintaining liquidity and servicing their debt. If you can't increase your production, how can
you increase your net income? By letting prices raise and limiting spending.
If prices rise 50% from here to $90WTIC, that is better then doubling your production and selling
it at $45. There will be "new" money for sure come back into the LTO space as prices increase,
but the best "sweet spots" are now HBP and will be developed as cash flow allows.
Just my humble opinion. I have watched in amazement as marathon oil has permitted two multiunit
wells on us and has spud one. I can't help but think they believe oil prices will be higher (while
drilling cost are lowest) by the time these wells get to market in late fall.
If I had to pick a price point for the best areas in the LTO space it is $80 plus to make a
decent return.
If you do not mind me asking, am I correct that most of the BOE out of these "new" OK hz plays
consists of natural gas and condensate, and that oil tends to decline very fast?
I have read your comments with interest as your experiences are very much mainstream of what
the oil and gas industry is enduring. My first bust was 85-86 so this is not new to us. To your
question, based on all the data public and otherwise some of the very best wells in the LTO space
are being made in the SCOOP area of central Oklahoma. As with many of the shale plays there are
different "zones" from dry gas at the deeper part of the play to "oil" in the most up dip areas.
Thickness varies from 150′-350′. The area that is being focused on under the economic parameters
that now exist is the "wet gas" area where you will get a flush of oil say 100,000 BO in the first
year or so but the oil will decline rapidly and you are left with "wet gas". 1350BTU.
Some operators strip out the liquids other do not. But I have wells that are 4 years old still
producing over 3oooMCFD. Now at $2MMBTU that sucks but when (if) nat gas prices normalizes it
will ring the cash register.
On the up dip oil part we have only two fully developed units, Good Martin with 8 wells and
the May Unit with 7 wells. The Good Martin unit has been on production for a year last month.
The production is within the range that was expected but I do not have pressure data to give me
full confidence in the ultimate recovery. The May unit is still being completed. I will say, both
CLR and Marathon have INCREASED their BOE recovery in the most recent reports.
As with all things, as completion cost have come down, you can increase the load and up the
recovery. I for one am in the camp that with higher frac loads and increased number of stages
not only does the IP rate increase but I think the ultimate recovery also increases as more rock
is broken down and open to the well bore. again just MHO, time will tell.
One other quick point, a lot of the LTO players are selling assets elsewhere and buying
leasehold in SCOOP and STACK. Over pressured, great infrastructure, favorable business climate,
now if we can just get rid of the pesky earthquakes.
"... I also question as to whether or not this extreme debt-fueled LTO production will ever be able to ramp up again as we have recently seen? It looks as if gullible investors are lining up with every increase in price, but the real onslaught of bankruptcies are just beginning, imho. ..."
"... This is a pretty big bust, and as mentioned by a few insiders in the last post, (Doug Leighton and a few others), will the experienced and knowledgeable 'hands' be available to ramp up production in such big numbers, ever again? Will there be financing? Will they be forced to produce by Govt decree/intervention? How about by a 2 for 1 tax incentive like Canada has done in the past? ..."
"... Not to doom and gloom a new reality, mostly because I am optimistic by nature, nevertheless, an acknowledged Plateau or decline will shake society to its very core as we move forward. I think it will be like those cheap B level movies about the looming asteroid casting a shadow on Earth, with hordes of people frantically looking for any means to escape the ramifications. ..."
regarding statement: "but the USGS may be mistaken in assuming that US reserve growth is a good
analog for the rest of the world."
Is oil distribution different than every other resource as it applies to the US? I don't think
so. That is a very big assumption and does not take into account misrepresented reserves by more
secretive countries, as well as political unrest and other disruptions that may occur going forward.
Furthermore, as the Majors seem to be dropping in profitability will they be able to continuing
producing at today's rates, or will they wind down and/or diversify with respect to their shareholders,
their first responsibility? I also question as to whether or not this extreme debt-fueled LTO
production will ever be able to ramp up again as we have recently seen? It looks as if gullible
investors are lining up with every increase in price, but the real onslaught of bankruptcies are
just beginning, imho.
This is a pretty big bust, and as mentioned by a few insiders in the last post, (Doug Leighton
and a few others), will the experienced and knowledgeable 'hands' be available to ramp up production
in such big numbers, ever again? Will there be financing? Will they be forced to produce by Govt
decree/intervention? How about by a 2 for 1 tax incentive like Canada has done in the past?
Every one of these graphed scenarios but one show the 'Peak' 15-20 years out. Ron P, who I
respect very highly, has said in the past he believes that 2015-16 will/might/just may be the
peak, which we will know only in hindsight. Has anything really changed beyond dodgy economics
and a slowing economy? I suppose if the economy continues slowing the peak might ultimately be
delayed, but then if this is the case BAU is finished, anyway.
Not to doom and gloom a new reality, mostly because I am optimistic by nature, nevertheless,
an acknowledged Plateau or decline will shake society to its very core as we move forward. I think
it will be like those cheap B level movies about the looming asteroid casting a shadow on Earth,
with hordes of people frantically looking for any means to escape the ramifications.
I sent an oil post to my best friend last week. Actually, it was the article I shared with
this forum in the last post about Ft Mac. His response was, "wasn't Jeff Rubin the guy who once
predicted Peak Oil"? I wrote back with several other articles attached and said, "This is Peak
right now, it is beginning….the effects are simply not acknowledged, etc etc etc". The conundrum,
as I see it, is that every time this industry goes bust, for whatever reason(s), the entrenched
say, "See, there's no Peak, what a bunch of bullshit. If there was a Peak the prices would be
climbing"!
Dennis, I would really appreciate reading a strong prediction from you, and others from this
forum. I appreciate that you kind of did this with the caveat, (very polite I might add) that
said, "a more realistic decline scenario might be"… (or words to that effect), but it's driving
me nuts. I kind of see why TOD shut down, now. Their reasons were that there were simply not enough
solid articles about PO to keep a good discussion flowing. I reluctantly switched to PO.com for
daily background reading and the quality of discussion and ideas have been reduced on that site
to playground levels of name calling with lots of swearing and personal attacks tossed in. The
contibutors on this forum are the only game in town these days. I thank you all in advance for
sharing you opinions and knowledge.
Denis does good work, but its very difficult to pin down numbers when nobody releases detailed
data. The ones who have the better data bases are IHS and the oil companies which purchase it
from IHS. But nobody is about to release something that's probably worth several hundred million
$.
For example, what is the usgs estimate for reserv increases at El Furrial in Venezuela? That
reservoir has been badly mismanaged over the last 10 years. The mismanagement reduces booked reserves,
and also makes impossible the introduction of a large tertiary process project such as CO2 injection.
The same applies to dozens of fields. Several Venezuelan heavy oil fields with more than 10
billion barrels of oil in place are headed towards less than half of the pdvsa booked reserves.
And given the current practices and political regime, the reservoirs will be left gutted, which
makes impossible introducing meaningful changes in the future. The Maduro regime has turned into
a full blown dictatorship as of this week, it will change for the worse, so it looks like the
ongoing reserve destruction will continue for at least a decade.
"... I would say shale is not viable below $80 per barrel, at a minimum. ..."
"... I completely agree. I think that conventional oil production will get some boost in $50-$80 price range, but not the US LTO oil production. Prices of metals, transportation, almost everything, correlate with the price of oil. So they will move up and that (along with heavy debt load) makes the repetition of "carpet drilling" unlikely and a large part of so called "productivity gains" a mirage. IMHO. ..."
"... Add to this debt load and the status of red hair step child that LTO now got in financial industry and it is plausible that we need $100 per bbl for full revival. ..."
"... I think that oil industry internationally is now sufficiently screwed up for another oil price spike (and possibly a second crash in five-seven years time frame). So all those "linear extrapolation" forecasts in best EIA style does not take into account one crucial variable: the level of financialization of the world economy and as such are mostly wrong. ..."
"... Instability due to strong positive feedback loops provided by financialization is the hall mark of neoliberalism. ..."
Texas C&C is also falling, yet not as strongly as condensate and gas (see below chart).
In my view there is something slowly cooking up for gas. As below chart shows total Texas gas
still above 20 bcf/d in March, the recent
http://www.bentekenergy.com report
for the week to May 14 shows Texas gas at 18.3 bcf/d. This is a steep plunge from last year. If
you take look at below chart you can feel the gravity drawing down the curves.
And given the recent plunge of gas drilling to 88 rigs from a high of 1600 not so long ago,
this can only mean a massive gas shortage in a few months. I took for my part considerable buy
options for natgas.
I will do a full post in a few days, but Dean sent me the following Chart.
He also said:
…find attached the Texas data for March 2016. I also attach the evolution of my correcting
factors over time: given these data, I've started thinking that Texas oil production did not fall
in the first months of 2016, but actually increased (a bit), similarly to what we observed in
2015.
I would say shale is not viable below $80 per barrel, at a minimum.
I completely agree. I think that conventional oil production will get some boost in $50-$80 price range, but not
the US LTO oil production. Prices of metals, transportation, almost everything, correlate with the price of oil. So they
will move up and that (along with heavy debt load) makes the repetition of "carpet drilling" unlikely
and a large part of so called "productivity gains" a mirage. IMHO.
Add to this debt load and the status of red hair step child that LTO now got in financial industry
and it is plausible that we need $100 per bbl for full revival.
I think that oil industry internationally is now sufficiently screwed up for another oil price
spike (and possibly a second crash in five-seven years time frame). So all those "linear extrapolation"
forecasts in best EIA style does not take into account one crucial variable: the level of financialization
of the world economy and as such are mostly wrong.
Instability due to strong positive feedback loops provided by financialization is the hall
mark of neoliberalism.
"... I think posting these historical numbers from the 10K since CLR went public tell a story. I am not good at guessing what will happen in terms of production at $50 WTI, $60 WTI, etc. I have made general views here pretty clear, and I do not think I need to repeat them. ..."
"... I will note, however, that CLR has about 6 times long term debt per BOEPD as of 12/31/2015 than it had as of 12/31/2007. I think this is a relevant metric. ..."
"... Assuming investors and banks look at figures like these, it should take a very high price for LTO to "ramp back up". It did not do so well, IMO, despite very high prices from 2007-2014. ..."
"... The price of oil will always be a major factor with regard to CAPEX levels, but there is a lag, as companies react to oil prices. ..."
There were some comments above about what price is needed to ramp up shale production, and whether
price is a big factor. Thought I would post down here to widen things out.
I always pick on Continental Resources, primarily because they are big enough to draw some
conclusions about LTO, but also because their financials are straightforward, they pretty much
strictly operate LTO, and they have not raised funds through equity issuances. In other words,
10K's are straightforward.
CLR went public 5/14/2007. They had been in business as a private company since 1967.
As of 12/31/2007, per the 10K, CLR produced 30,369 BOEPD, 82% oil, spent $526 million in CAPEX
for the year, and had long term debt of $165 million at year end. For 2007 their realized prices
were $63.55 for oil, $5.87 for gas, for BOE of $58.32
12/31/2008.
Production 36,018 BOEPD, 76% oil.
CAPEX $989 million
Long term debt $376 million
Oil price $88.87
Gas price $6.90
BOE $77.66
12/31/2009
Production 37,323 BOEPD 74% oil
CAPEX $444 million (refutes the idea that oil price does not matter – see 2008)
Long term debt $524 million
Oil price $54.44
Gas price $3.22
BOE $45.10
12/31/2010
BOEPD 43,318 75% oil
CAPEX $1,237 million
Long term debt $926 million
Oil price $70.69
Gas $4.49
BOE $59.70
12/31/2011
BOEPD 61,866 73% oil
CAPEX $2.224 billion
Long term debt $1.254 billion
Oil price $88.51
Gas price $5.24
BOE $73.05
12/31/2012
BOEPD 97,585 70% oil
CAPEX $4.358 billion
Long term debt $3.540 billion
Oil Price $84.59
Gas price $4.20
BOE $66.83
12/31/2013
BOEPD 135,918 71% oil
CAPEX $3.842 billion
Long Term Debt: $4.651 billion
Oil price $89.93
Gas price $4.87
BOE $72.04
12/31/2014
BOEPD 174,189 70% oil
CAPEX $5.016 billion
Long Term Debt $5.929 billion
Oil price $81.26
Gas price $5.40
BOE $66.53
12/31/2015
BOEPD 221,715 66% oil (note for 2016 guiding 60% oil)
CAPEX $2.564 billion
Long Term Debt $7.118 billion
Oil Price $40.50
Gas Price $2.31
BOE $31.48
They are guiding about 15,000 BOEPD less production in 2016, are going to be spending close
to $1 billion in CAPEX in 2016. They are going to be producing more gas as almost all completions
will be in OK, which are primarily gas plays.
I think posting these historical numbers from the 10K since CLR went public tell a story.
I am not good at guessing what will happen in terms of production at $50 WTI, $60 WTI, etc. I
have made general views here pretty clear, and I do not think I need to repeat them.
I will note, however, that CLR has about 6 times long term debt per BOEPD as of 12/31/2015
than it had as of 12/31/2007. I think this is a relevant metric.
Assuming investors and banks look at figures like these, it should take a very high price
for LTO to "ramp back up". It did not do so well, IMO, despite very high prices from 2007-2014.
2010
Price $59
CAPEX 1,2 m (refutes idea that price matters, see the price and CAPEX in 2008)
And let's look at Long term debt.
Shallow when your debt starts increasing do you cut CAPEX spending or you keep increasing? Obviously
if you look at that long term debt of CLR that did not matter in relation to CAPEX . So how can
you say that price matters when CAPEX increased and Long term debt increased even at higher rate??
and then 2015
Price $31
CAPEX 2.5 bilion (refutes idea that price matters see 2008 price and CAPEX)
Here I am talking only about shale not the rest of conventional.
Ves. My point is in response to the price collapse at the end of 2008, CAPEX in 2009 was cut substantially
from 2008 levels.
The same happened if we compare 2014 CAPEX to 2015 CAPEX, and will happen again 2015 compared
to 2016.
The 2008 collapse was very severe, I remember it very well. The price dropped over $100 in
around 5 months. But the price recovered fairly well.
The price of oil will always be a major factor with regard to CAPEX levels, but there is
a lag, as companies react to oil prices.
As for shale, it is very dependent on credit. If credit does not come back as prices
rise, and just develops out of cash flow, I think the actual data from CLR is evidence that a
very high price will be needed for it to begin to grow again.
"... So at $35/b at the wellhead you get $31.85/b after taxes, then if we deduct OPEX we get $23.85/b, so net revenue would be 1.67 million the first year. Also remember the future revenue should be discounted at 10% per year. With no discount shallow sands wants the net revenue to pay for the well after 5 years. In this case the net revenue is $3.737 million after 5 years and the well is a failure (it loses money). Even after 14 years net revenue is only $5.25 million. I have ignored interest in this example and have assumed the well has been paid for out of cash flow. If the well head price were between 50 and 51 per barrel the well would be paid for after 5 years. ..."
"... I quickly checked the same analysis for the recent Bakken well profile, which has a higher 60 month EUR (266 kb vs 196 kb for the 2013 well). The well is paid for in 60 months at a wellhead price of $40/b using the same assumptions I used in the previous example. ..."
"... Of course, as you mention, none of the companies are able to pay for wells right now out of cash flow. All have interest expense, many have interest expense in excess of $5 per barrel. ..."
"... Also, another expense I have noticed with more frequency are gathering expenses. Many of the LTO companies sold their gathering and/or produced water disposal infrastructure in order to raise cash. They now are required to pay $X per barrel or mcf of gas in order to get their products to market. ..."
"... I would also note, 20% is a "base case" for Bakken royalties. The actual figures can range from 12.5% (1/8) to over 25% (1/4). If one is looking at the EFS or Permian, I suggest using a "base case" royalty of 25% (1/4). However, taxes in TX are less than ND. ..."
"... "We are slowly technologizing ourselves into extinction. Technology is seductive. Is it the power? Is it the comfort? Or is it some internal particularly human attribute that drives it? Technology surrounds us and becomes part of our story and myths. Technology tantalizes the human mind to make, combine, invent. There are always unintended consequences with technology. It affects how we experience the world in time and space. It affects how we feel about the world. If all the externalities were included in the prices and cost to nature, we would be very, very wary of technology. ..."
"... We will do more of the same, business as usual until there are no more holes in the ground to dig, no more water above and below to contaminate, no humans to wage slave, no other lifeforms to eliminate. Yes, we are building Trojan horses in our hearts, minds and spirits. It will be elitist and entitlement and hubris – it will end with both a bang and a whimper." ~ John Weber ..."
The wells never stop declining so for your final three years each year
should be 93% of the previous year, this doesn't really happen for about
10 to 15 years. Below are annual decline rates for an average new Bakken
well in 2013. The first year's average output is 2.9 kb/d and the decline
rates are year 1 to 2, 2 to 3, …, 9 to 10.
Output in barrels per year
87696
42170
28453
20911
16643
13811
11796
10289
9120
8187
7425
6792
6252
5763
Hope that helps. The decline rate eventually levels out at about 7% per
year by year 15 and remains at that rate until the well is shut in about
12 years later (with the well producing about 6 b/d).
Thanks Dennis, I worked those decline rates into my spreadsheet but the
essential message is the same, relative to PV shale oil will generate more
than 15 times the gross revenue in year 1 and still be generating more than
twice the gross revenue in year 7! Your figure of 2.9 kb/d for the average
first year production seems way out of line with the numbers that shallow
sand used in the analysis I referred to or anything that can be interpreted
from Enno's graph below. I was really hoping that shallow or Ciaran would
have commented on my estimate but, I guess my work is way too amateurish
for them! :-)
Edit: Dennis, after I posted this, I noticed your additional responses
below. I will try to add these additional factors into my spreadsheet as
I am interested in how these enterprises gobble up millions of dollars!
I also noticed where you mention 266 kb as EUR and wonder how a well
that produces 2.9 kb/d can end up with an EUR of 266 kb after 60 months?
My mistake 2.9 is a factor of 12 too high, I multiplied by 12 where I
shouldn't have, but the numbers for barrels per year are correct. It should
have been 240 barrels per day for the average first year output.
Also if you look at the numbers for output per year that I posted (which
can be copied and pasted into a spreadsheet) it is clear that 87,696/365
is not equal to 2900 b/d, it is 240.2 b/d. Sorry for the mistake.
The royalties are 20% of output, taxes are another 9% or so. So if you
had 100,000 barrels of output, you keep 80,000 barrels and then figure you
only get net revenue of 91% of the wellhead price and then you have to subtract
opex, G+A, etc.
So at $35/b at the wellhead you get $31.85/b after taxes, then if
we deduct OPEX we get $23.85/b, so net revenue would be 1.67 million the
first year. Also remember the future revenue should be discounted at 10%
per year. With no discount shallow sands wants the net revenue to pay for
the well after 5 years. In this case the net revenue is $3.737 million after
5 years and the well is a failure (it loses money). Even after 14 years
net revenue is only $5.25 million. I have ignored interest in this example
and have assumed the well has been paid for out of cash flow. If the well
head price were between 50 and 51 per barrel the well would be paid for
after 5 years.
Shallow sand can correct my mistakes. Note that I have used my numbers
for yearly well output, based on data from Enno Peters. The well used is
the average 2013 Bakken well.
I quickly checked the same analysis for the recent Bakken well profile,
which has a higher 60 month EUR (266 kb vs 196 kb for the 2013 well). The
well is paid for in 60 months at a wellhead price of $40/b using the same
assumptions I used in the previous example.
Of course, as you mention, none of the companies are able to pay
for wells right now out of cash flow. All have interest expense, many
have interest expense in excess of $5 per barrel. Then, the question
is when will any of these companies begin to use cash flow to reduce debt
principal. Some have reduced debt, by buying back their own debt at distressed
levels, and/or exchanging the debt with creditors for reduced principal
new debt, but at much higher interest rates and more stringent terms (liens
upon company assets as opposed to unsecured bonds).
Also, another expense I have noticed with more frequency are gathering
expenses. Many of the LTO companies sold their gathering and/or produced
water disposal infrastructure in order to raise cash. They now are required
to pay $X per barrel or mcf of gas in order to get their products to market.
I would also note, 20% is a "base case" for Bakken royalties. The
actual figures can range from 12.5% (1/8) to over 25% (1/4). If one is looking
at the EFS or Permian, I suggest using a "base case" royalty of 25% (1/4).
However, taxes in TX are less than ND.
I was trying to keep it simple. For someone like you who probably does
not borrow, there would be very little interest expense. This may also be
true for XTO and Statoil. So basically someone who uses a 60 month payout
rule, probably is not in debt so interest payments are not a factor. I also
was trying to get it done in 5 minutes so skipped some steps.
I get 137 million miles of driving, if we ignore the energy used for
refining and distribution of the oil produced for the 2013 average Bakken
well, for the more recent wells it is 185 million miles over 7 years. For
the late 2015 to early 2016 Bakken average well we get 248 million miles
of driving over a 25 year well life (ignoring refining and distribution
energy). So over the long term we get more driving miles out of the PV.
Note that the average Bakken well really costs more like 8 million rather
than 5.9 million so the apples to apples comparison over 25 years would
be 378 million miles from PV and 248 million miles from the LTO well. So
50% more miles of driving per dollar spent on energy to fuel the ICEV or
EV.
2.8 acres of PV produces 1 GWh annually of output (fixed array). PV farm
cost is about $500,000 per acre. Typical well cost is $15 million (initial
plus continuous costs) and lasts for about 15 years, with low output the
last 10.
So $15 million of PV would be thirty acres at 10.7 GWh output. By year 15
the output might be at 90% so average is 95% over 15 years giving 152 GWh
total ouput for 15 years. Since the PV is local I won't use transmission
losses. At 0.3 kWh per mile that is 506 million miles. The PV farm will
produce almost double that over it's full lifetime. No pollution produced,
no pipelines, no refineries, no spills, no smog, no noise, no global warming,
etc. No Red Queen effect. No depletion problem. PV panels are getting better
and cheaper, oil is not.
URR of well being about 300,000 barrels would give 265 million miles
at 30 mpg (70 percent fuel recovery). When one starts to take into account
the energy losses in drilling, transport, refining, more transport, etc.
That would drop significantly.
No brainer for transportation.
Consider also that hydropower uses over 25 times the area to produce
the same amount of power and also messes up the environment. PV looks a
lot better all around.
Photovoltaic panels have a significant opex. This is associated with parts
replacement, as well as panel washing (they are worse than cars left in
the open). When you compare apples to lemons make sure you include everything.
Yair . . .
This "panel washing" may be a factor on commercial installations but I occasionally
see it mentioned in relation to domestic as a difficult problem on hard
to access roofs . . . well we have been running panels for over twenty five
years and they get washed when it rains.
"We are slowly technologizing ourselves into extinction. Technology
is seductive. Is it the power? Is it the comfort? Or is it some internal
particularly human attribute that drives it? Technology surrounds us
and becomes part of our story and myths. Technology tantalizes the human
mind to make, combine, invent. There are always unintended consequences
with technology. It affects how we experience the world in time and
space. It affects how we feel about the world. If all the externalities
were included in the prices and cost to nature, we would be very, very
wary of technology.
I think we have moved from technology in the service of religion
(pyramids and gothic cathedrals) to religion and culture in the service
of technology. It isn't a deity that will save humanity but in the eyes
of many – it will be technology.
We will do more of the same, business as usual until there are
no more holes in the ground to dig, no more water above and below to
contaminate, no humans to wage slave, no other lifeforms to eliminate.
Yes, we are building Trojan horses in our hearts, minds and spirits.
It will be elitist and entitlement and hubris – it will end with both
a bang and a whimper." ~
John Weber
"... 0-12 month production is a combination of reservoir and fracture dominated flow. Increases in mean rates are mainly related to advances in completion technology (longer horizontals, > number of stages, reduced spacing between stages, improved proppant technology). ..."
"... After 12 months, liquid production is reservoir dominated. Decline curves converge to +/- 5 bopd. Geology is the main controlling factor. From 2008 to 2015, the following increases have been observed; ..."
"... Completion technology gets you more gas (and oil) in the short term. In the longer term geology plays a far more important role on single well life of field economics than completion technology. ..."
Completion technology gets you more gas (and oil) in the short term. In
the longer term geology plays a far more important role on single well life
of field economics than completion technology.
0-12 month production is a combination of reservoir and fracture
dominated flow. Increases in mean rates are mainly related to advances
in completion technology (longer horizontals, > number of stages, reduced
spacing between stages, improved proppant technology).
After 12 months, liquid production is reservoir dominated. Decline
curves converge to +/- 5 bopd. Geology is the main controlling factor.
From 2008 to 2015, the following increases have been observed;
197% increase in 90 day gas only production
46% increase in 90 day oil and gas production
27% increase in 90 day oil only production
10% increase in 90 day income
Extrapolating the 2008 to 2015 curves to 20 years of production,
the following changes have been estimated;
6% increase in 20 year income
Break Even oil price lowered from $64 to $60
Conclusion: Completion technology gets you more gas (and oil) in
the short term. In the longer term geology plays a far more important role
on single well life of field economics than completion technology.
"... Increasing gor in an oil reservoir is not good. But I thought you were inferring that Texas was in worse shape. My point was you can't make that assumption. My only point ..."
"... I thought maybe the units should be thousands of cubic feet of natural gas per barrel of oil because both Texas and North Dakota are over 1200 cf/bo GOR. ..."
My point is simply that currently North Dakota is at about 1500 cubic
feet natural gas per barrel of oil produced.
Fernando says this is a problem, I think.
Not sure if it is or isn't. Increasing gor in an oil reservoir is not
good. But I thought you were inferring that Texas was in worse shape. My
point was you can't make that assumption. My only point
I thought maybe the units should be thousands of cubic feet of natural
gas per barrel of oil because both Texas and North Dakota are over 1200
cf/bo GOR.
"... Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil. ..."
"... Sorum said a recent audit of the state Department of Trust Lands that identified errors in how oil and gas royalty payments were made underscores the need for an independent audit of the Oil and Gas Division, which oversees about 13,000 active oil and gas wells. ..."
"... He said mineral owners who receive oil and gas royalty payments often receive revised settlement sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately tracked and shows the need for an audit so mineral owners don't get shortchanged. ..."
Two gubernatorial candidates from opposing parties called Thursday for an audit of North Dakota's
Oil and Gas Division, raising concerns that production numbers are not being verified and citing
a tip that employees were ordered to destroy public records – a claim the agency's spokeswoman called
"completely baseless." Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin
Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for
a performance audit of the division within the Department of Mineral Resources.
"This is not a partisan issue, which is why Marvin and I and many other people are on the same
page. We just want the law to be followed," Sorum said.
Both candidates said they had planned to hold the press conference next Monday but moved it up
after they were contacted by an attorney for a division employee who claimed Mineral Resources Director
Lynn Helms ordered the destruction of emails and records related to the transportation and sale of
oil.
Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to
be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower
laws provide inadequate protection.
"Even without those rumors, there's still significant reasons why we should be do that (audit),
and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.
Division spokeswoman Alison Ritter said the allegation of destroying records was untrue. "That's completely baseless," she said. "I think it's just absurd, actually." Ritter added that the office had a staff meeting Wednesday which involved making sure staff were
reading the code of ethics policy, which includes a page related to records and making records available.
Sorum and Nelson said they did not contact Attorney General Wayne Stenehjem, chief enforcer of
the state's open records laws, about the report of records being destroyed. Stenehjem, who is the
Republican Party's endorsed candidate for governor and also serves on the three-member Industrial
Commission that oversees the Oil and Gas Division, "is part of the problem," Sorum said.
Stenehjem was on the campaign trail and could not immediately be reached for comment. Fargo businessman
Doug Burgum also is seeking the GOP nomination in the June 14 primary.
Sorum said a recent audit of the state Department of Trust Lands that identified errors in how
oil and gas royalty payments were made underscores the need for an independent audit of the Oil and
Gas Division, which oversees about 13,000 active oil and gas wells.
A bill co-sponsored by Nelson last year would have required a performance audit of state agencies
that regulate oil and gas development, but House lawmakers rejected it 67-22.
Nelson serves on the Legislative Audit and Fiscal Review Committee, which has the authority to
request performance audits, but he couldn't recall if there had been a formal request for a division
audit.
He said mineral owners who receive oil and gas royalty payments often receive revised settlement
sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately
tracked and shows the need for an audit so mineral owners don't get shortchanged.
"There's really a public responsibility to get it right," he said.
Ritter noted the state auditor's office recently completed a routine audit of the agency for the
2013-15 biennium and there were no formal findings for the Oil and Gas Division and a few formal
fin
Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative
from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division
within the Department of Mineral Resources.
"This is not a partisan issue, which is why Marvin and I and many other people are on the same
page. We just want the law to be followed," Sorum said.
Both candidates said they had planned to hold the press conference next Monday but moved it up
after they were contacted by an attorney for a division employee who claimed Mineral Resources Director
Lynn Helms ordered the destruction of emails and records related to the transportation and sale of
oil.
Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to
be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower
laws provide inadequate protection.
"Even without those rumors, there's still significant reasons why we should be do that (audit),
and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.
Division spokeswoman Alison Ritter said the allegation of destroying records was untrue.
"That's completely baseless," she said. "I think it's just absurd, actually."
Ritter added that the office had a staff meeting Wednesday which involved making sure staff were
reading the code of ethics policy, which includes a page related to records and making records available.
Sorum and Nelson said they did not contact Attorney General Wayne Stenehjem, chief enforcer of
the state's open records laws, about the report of records being destroyed. Stenehjem, who is the
Republican Party's endorsed candidate for governor and also serves on the three-member Industrial
Commission that oversees the Oil and Gas Division, "is part of the problem," Sorum said.
Stenehjem was on the campaign trail and could not immediately be reached for comment. Fargo businessman
Doug Burgum also is seeking the GOP nomination in the June 14 primary.
Sorum said a recent audit of the state Department of Trust Lands that identified errors in how
oil and gas royalty payments were made underscores the need for an independent audit of the Oil and
Gas Division, which oversees about 13,000 active oil and gas wells.
A bill co-sponsored by Nelson last year would have required a performance audit of state agencies
that regulate oil and gas development, but House lawmakers rejected it 67-22.
Nelson serves on the Legislative Audit and Fiscal Review Committee, which has the authority to
request performance audits, but he couldn't recall if there had been a formal request for a division
audit.
He said mineral owners who receive oil and gas royalty payments often receive revised settlement
sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately
tracked and shows the need for an audit so mineral owners don't get shortchanged.
"There's really a public responsibility to get it right," he said.
Ritter noted the state auditor's office recently completed a routine audit of the agency for the
2013-15 biennium and there were no formal findings for the Oil and Gas Division and a few formal
fin
Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative
from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division
within the Department of Mineral Resources.
"This is not a partisan issue, which is why Marvin and I and many other people are on the same
page. We just want the law to be followed," Sorum said.
Both candidates said they had planned to hold the press conference next Monday but moved it up
after they were contacted by an attorney for a division employee who claimed Mineral Resources Director
Lynn Helms ordered the destruction of emails and records related to the transportation and sale of
oil.
Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to
be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower
laws provide inadequate protection.
"Even without those rumors, there's still significant reasons why we should be do that (audit),
and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.
The International Energy Agency estimates that the world is dealing with a supply surplus of 1.3
million barrels per day (mb/d) right now, which should last through the end of the second quarter.
By the third and fourth quarters, however, the surplus shrinks to just 0.2 mb/d.
The IEA reiterated its forecast that demand will hold at 1.2 mb/d, and expressed a growing sense
of confidence that oil markets are only a few months away from moving into balance.
For its part, OPEC largely agreed in its May
Oil Market Report. But OPEC also chose to focus on the slightly longer-term, citing the massive
cut in capital expenditures taken over the past two years. The industry has slashed $290 billion
from 2015 and 2016 spending levels so far, with more cuts expected. The spending reductions contributed
to the shockingly low level of new oil discoveries last year – the industry discovered less than
3 billion barrels of new oil reserves in 2015, the lowest level in six decades. With few new discoveries,
and a rising number of projects deferred, there is a very low level of new projects in the pipeline,
so to speak. In other words, oil supply and demand curves are converging towards a balance, and could
even cross over at some point a few years down the line as supply fails to keep up with demand.
... ... ...
Canadian wildfires knocked off more than 1.2 million barrels per day of production, a disruption
that will be temporary, but ultimately could last a few weeks.
Nigeria has lost roughly 0.4 to 0.5 mb/d due to a handful of attacks on oil pipelines and platforms.
Shell and Chevron have shut down facilities and evacuated personnel because of attacks from the Niger
Delta Avengers. Venezuela has seen production
decline at least 0.1 mb/d from last year, and could fall another 0.2 mb/d at least over the course
of 2016.
All of these supply disruptions come on top of the expected decline in output from around
the world, especially high cost U.S. shale. U.S. oil production has fallen to 8.8 mb/d as of early
May, taking the loss in U.S. oil production to about 900,000 barrels per day since April 2015.
"... Angola has become Africa's biggest oil producer as Nigeria's output slumped to 1.4 million barrels a day, Oil Minister Ibe Kachikwu said Monday, endangering a budget based on production of 2.2 million barrels. ..."
"... Some 70 percent of Nigerians are living below the poverty line, according to the United Nations, despite the country's wealth. ..."
"... The threatened strike comes as militants in the Niger Delta resumed attacks and forced oil majors to evacuate some workers. There are reports the Niger Delta Avengers are sponsored by southern politicians to sabotage Buhari. The president has deployed thousands of troops to the area, where the Avengers are demanding a greater share of the country's oil wealth and protesting cuts to a 2009 amnesty program that paid 30,000 militants to guard installations they once attacked. ..."
LAGOS, Nigeria (AP) - Militant attacks on oil installations and a threatened nationwide strike
are driving Nigeria's petroleum production and its naira currency to new lows.
Angola has become Africa's biggest oil producer as Nigeria's output slumped to 1.4 million barrels
a day, Oil Minister Ibe Kachikwu said Monday, endangering a budget based on production of 2.2 million
barrels. Angolan production was steady at near 1.8 million barrels daily, according to the Organization
of Petroleum Exporting Countries.
The naira fell to 350 to the dollar on the parallel market, against an official rate of 199, amid
reports and denials that President Muhammadu Buhari's government plans an imminent devaluation, bowing
to demands of the International Monetary Fund in exchange for soft loans.
Nigeria's National Labour Congress and the Trade Union Congress, which say they represent 6.5
million workers, and some civic organizations called for a strike Wednesday to protest a 70 percent
increase in gasoline prices, forced by shortages of foreign currency. Nigeria is dependent upon imports
with oil accounting for 70 percent of government revenue.
The crisis is dividing labor leaders on religious and ethnic lines, with those from the mainly
Muslim north against the strike and Christians who dominate the oil-producing south urging citizens
to "Occupy Nigeria!" Buhari is a northerner.
The division may mean that the country will not be subjected to the massive protests that forced
the previous government to shelve plans to do away with a fuel subsidy in 2012, although many Nigerians
are stocking up on food and water.
Inflation officially rose nearly 14 percent last month and prices of food and electrical goods
have doubled while tens of thousands of workers have not been paid in months. Many angry Nigerians
say the government could not have chosen a worse time to drop the fuel subsidy, though shortages
forced people to pay double the fixed price anyway.
Some 70 percent of Nigerians are living below the poverty line, according to the United Nations,
despite the country's wealth.
Buhari took over a year ago from President Goodluck Jonathan, whose government is accused of looting
the treasury of billions of dollars.
The threatened strike comes as militants in the Niger Delta resumed attacks and forced oil majors
to evacuate some workers. There are reports the Niger Delta Avengers are sponsored by southern politicians
to sabotage Buhari. The president has deployed thousands of troops to the area, where the Avengers
are demanding a greater share of the country's oil wealth and protesting cuts to a 2009 amnesty program
that paid 30,000 militants to guard installations they once attacked.
"... While oil production in the Bakken has been in decline for more than a year, natural gas production continues to increase. As there is no big natural gas fields in North Dakota and most of the gas is associated, this trend can be entirely attributed to the rising GOR. ..."
"... Since the beginning of the shale boom in the Bakken North Dakota the natural gas to oil production ratio has increased almost 3 times ..."
While oil production in the Bakken has been in decline for more than a year, natural gas production
continues to increase. As there is no big natural gas fields in North Dakota and most of the gas
is associated, this trend can be entirely attributed to the rising GOR.
Oil and natural gas production in the Bakken
source: NDIC
"... Generally speaking (in Texas anyway) a lease must generate cash flow in excess of its monthly cost of production. $1 over that monthly cost is sufficient. Naturally, each operator's cost are different and each lease/well is different. ..."
Generally speaking, an OGL that is past its primary term must produce
oil and/or gas in "paying quantities" with no cessation of more than xx
days (depends on lease language) to continue to be held in effect. There
are many ways an operator can handle this situation by producing just a
few days a month. An operator can pay a "shut-in gas" royalty to defer a
production obligation in certain circumstances. Each situation is different
and requires its own analysis.
An operator is not required to show that a well or leasewell is capable
of "paying out" it's cost of the lease, drilling and completion, gathering,
treating facilities and so forth.
The important issue is that a well or lease must be capable of producing
oil or gas in "paying quantities".
Generally speaking (in Texas anyway) a lease must generate cash flow
in excess of its monthly cost of production. $1 over that monthly cost is
sufficient. Naturally, each operator's cost are different and each lease/well
is different.
In my opinion, many wells are "magically" producing just enough oil and
gas to generate a marginally positive cash flow. Why you ask? To avoid plugging
and abandonment until a greater fool comes along to buy the lease and allow
the current operator to get off the hook.
I know of one case where SandRidge Energy (Arena Acquisition) drilled
52 vertical wells in one 640 acre section. Each well is capable of producing
1-2 bbls/day. Payout will never happen and I doubt that production in paying
quantities is happening. I also doubt that a greater fool exists to take
over this lease
But…… someday someone (perhaps you) will be on the hook to plug and abandon
and restore the surface to its original condition.
Russia is not planning to significantly ramp production capacity.
Energy Minister Novak said today that the country will be able to maintain
long-term production levels within the range 525-545 million tons per year
(10.5-10.9 mb/d). That's what Russian officials were saying earlier.
According to the Saudi officials, planned expansion of the Khurais and
Shaybah oil fields will only
compensate for falling output at other fields. They claim that the country's
"maximum sustainable output capacity is 12 million barrels per day and the
nation's total capacity is 12.5 million bpd", but there are no plans to
increase capacity and there is no evidence that this capacity really exists.
I think that in reality Saudi Arabia is able to increase crude production
from the current 10.2 mb/d to 10.5-10.6 mb/d during the peak season for
local demand in the Summer, but not well above those levels.
"... We just did some work on the EIA/IHS report on well costs that came out a little while ago. We suspect that these longer peaking wells may be possible due to lower service costs. Operators have switched to natural sand, and lots of it. Not being an engineer, this is only an educated guess, but the general gist I can gather is that natural sand crushes more easily than artificial ceramic proppant, but is significantly cheaper. ..."
"... Our assumption on the interests of operators like CLR and WLL is that they currently want to maximise short-term production to boost revenue, and they care significantly less about maximising recovery. Using lots of natural sand fits in with that – though the sand will be crushed more quickly than if artificial proppant will be used, more fractures will be propped open in the short term. ..."
"... Many of these short term production gains may be given up shortly after any price increase, as the service costs will also rise, and the short term revenue considerations will become less important. That's the theory we're working under currently, anyway… ..."
Great comment, Enno, as ever. It's important to remember that the EIA's
forecasts seem to generally be very "smooth", and their models are mostly
done at an economic level, meaning they aren't working from number of wells
upwards. This meant they completely missed the beginning of the production
decline – their initial forecasts kept on adding ~30kbpd a month to Bakken
until April15, for example. Now they are a little to heavy to the downside.
We just did some work on the EIA/IHS report on well costs that came
out a little while ago. We suspect that these longer peaking wells may be
possible due to lower service costs. Operators have switched to natural
sand, and lots of it. Not being an engineer, this is only an educated guess,
but the general gist I can gather is that natural sand crushes more easily
than artificial ceramic proppant, but is significantly cheaper.
Our assumption on the interests of operators like CLR and WLL is
that they currently want to maximise short-term production to boost revenue,
and they care significantly less about maximising recovery. Using lots of
natural sand fits in with that – though the sand will be crushed more quickly
than if artificial proppant will be used, more fractures will be propped
open in the short term.
Many of these short term production gains may be given up shortly
after any price increase, as the service costs will also rise, and the short
term revenue considerations will become less important. That's the theory
we're working under currently, anyway…
The decline after peak of new wells appears to be significantly steeper
than previous years, so when companies claim 40% IP increase = 40% EUR increase,
one should be extremely skeptical. By month 7 of production, the average
2014 well had produced 18% more oil than the average 2010 well at the same
stage of its life – but by month 26, that difference was down to 7.6%. In
month 3, the average 2014 well had produced nearly 9% more than the average
2013 well – by month 26, that was down to 2%. Those are total cumulative
oil produced figures, btw.
"... Total oil production in North Dakota Bakken fell to 1057 kb/d in March, a monthly drop of 8 kb/d. Decline in February-March was only 10 kb/d. Cumulative decline from December 2014 peak level is 107 kb/d (-9%). ..."
"... as Shallow Sand pointed out: "It surprised me that production in ND didn't fall much when Mr. Helms stated there would be a dramatic drop." ..."
Total oil production in North Dakota Bakken fell to 1057 kb/d in March, a monthly drop of 8
kb/d.
Decline in February-March was only 10 kb/d. Cumulative decline from December 2014 peak level is 107 kb/d (-9%).
The chart below shows that both the EIA Drilling Productivity Report and the EIA/DrillingInfo
monthly LTO production statistics tend to underestimate the resilience of tight oil production,
at least in the case of the Bakken. The EIA estimates for February and March will likely be revised
upward. I think that even bigger upward revisions will be done for the Eagle Ford.
Bakken oil production statistics: NDIC data vs. the EIA reports (kb/d)
Early March oil production numbers show that North Dakota will likely drop below 1.1 million
barrels per day for the first time since June 2014, the state's top oil regulator said.
An official update will be released next week, but Director of Mineral Resources Lynn Helms told
an oil industry group in Williston he expects to see a "severe" production drop.
"It's going to be bad," Helms told the Williston Basin chapter of the American Petroleum Institute
Tuesday night."
In fact, the decline was not as big as was expected and total ND oil production (incl. conventional)
in March was 1109 kb/d.
The chart below does not show any acceleration in monthly decline rates:
Year-on-year and month-on-month growth/decline rates in Bakken North Dakota oil production
(%)
"... Daniel Katzenberg, a senior analyst at Robert W. Baird, says investors aren't worried about profits as much as production. Quarter after quarter, the output of Pioneer's new horizontal wells has exceeded expectations, and that's why the stock price keeps rising. "What the market sees is that they're sitting on one of the most attractive and economic resource plays in the world," says Katzenberg. "Pioneer is tasked with proving their acreage is as good as the hype." ..."
"... I like this way of thinking: "investors aren't worried about profits as much as production". However absurd it sounds, that is true. There is a class of investors that aren't worried about profits. Same can be said about investors in Tesla: "investors aren't worried about profits as much as new EV technologies". ..."
"... New financing will be tough for survivors, and debt overhand will not dissipate any time soon. As for investors putting money into questionable companies (that Alex used as a counterargument) this is just throwing good money after bad. Most of those "new" investors are already up to the neck in this s**t and are afraid to write down holdings. So they decided to double down hoping that rising oil price will bail them out. ..."
"... Nothing new here. America became the nation of speculators, big and small, so a new sucker is born every minute. They expect that the rising tide will lift all boats. And they already forgot lessons of 2008: I do not think investors memory (as a class) lasts more then five years. So a new bubble and related fraud can have any period larger then five years. Almost eight year passed from previous crash, so it's about time to milk those suckers again :-) ..."
"... I think there will observable divergence between oil price rise and energy mutual funds/ETFs price rise. The latter will rise more slowly as bankruptcies might spoil the show. ..."
"... US Production is falling (substantially) and rigs are still declining so obviously "investors" are not interested in production either. So Mr Katzenberg is talking baloneys. There are no investors. This just last gasps of money printing. You can see the cracks everywhere. ..."
"... "If oil prices average $40 per barrel, U.S. shale oil production will likely decline by 3 million barrels per day between 2015 and 2020, and even if oil prices reach $60 per barrel, a decline is still imminent, according to the International Energy Agency (IEA). US shale production is not expected to halt the decline until we reach prices of $70 per barrel over the same period." ..."
"... There will be time in a year when EIA will report the same and Wall Street will proclaim "We are shocked. No one could have predicted this". Same old same old. ..."
US E&Ps were able to sell 10 billion not for the purpose of investing but for hiding the losses
for little bit longer. That shale business model is dead.
But investors don't think so.
Despite all those bankrupcies, they continue to invest in shale players, particularly in those
who continue to increase production volumes.
A good example is Pioneer, which is up almost 60% from 52-week lows.
Interesting quotes from an article in Bloomberg:
"The company, meanwhile, is spending a lot of money now in the belief that oil prices will
soon rise. Not everyone thinks it will pay off. Criticizing shale drillers at the Sohn Investment
Conference a year ago, David Einhorn singled out Pioneer, in which he has a short position, as
the "Mother-Fracker." Einhorn, president of Greenlight Capital, argued that Pioneer lost $12 for
every barrel it developed over the previous nine years. "That's like using $50 bills to counterfeit
$20s," he said.
…………………….. Daniel Katzenberg, a senior analyst at Robert W. Baird, says investors aren't worried about
profits as much as production. Quarter after quarter, the output of Pioneer's new horizontal wells
has exceeded expectations, and that's why the stock price keeps rising. "What the market sees
is that they're sitting on one of the most attractive and economic resource plays in the world,"
says Katzenberg. "Pioneer is tasked with proving their acreage is as good as the hype."
I like this way of thinking: "investors aren't worried about profits as much as production".
However absurd it sounds, that is true. There is a class of investors that aren't worried about
profits. Same can be said about investors in Tesla: "investors aren't worried about profits as
much as new EV technologies".
Dead - no. Severely squeezed - yes. New financing will be tough for survivors, and debt
overhand will not dissipate any time soon. As for investors putting money into questionable companies
(that Alex used as a counterargument) this is just throwing good money after bad. Most of those
"new" investors are already up to the neck in this s**t and are afraid to write down holdings.
So they decided to double down hoping that rising oil price will bail them out.
Nothing new here. America became the nation of speculators, big and small, so a new sucker
is born every minute. They expect that the rising tide will lift all boats. And they already forgot
lessons of 2008: I do not think investors memory (as a class) lasts more then five years. So a
new bubble and related fraud can have any period larger then five years. Almost eight year passed
from previous crash, so it's about time to milk those suckers again :-)
I think there will observable divergence between oil price rise and energy mutual funds/ETFs
price rise. The latter will rise more slowly as bankruptcies might spoil the show.
" Daniel Katzenberg, a senior analyst at Robert W. Baird, says investors aren't worried
about profits as much as production"
Alex,
" investors aren't worried about profits as much as production".
Is this America? Profits are not important? Well if investors are not worried about profits
than what is this? Charity, non-profit think-tank venture?
US Production is falling (substantially) and rigs are still declining so obviously "investors"
are not interested in production either. So Mr Katzenberg is talking baloneys. There are no investors.
This just last gasps of money printing. You can see the cracks everywhere.
Tesla is different. Tesla is still in hype 'stage" considering the number of vehicles sold..
You can run up Tesla stock so high just outside solar system and crash back and nobody will notice
a thing. Oil is different because all 7 billions of us are using it.
"If oil prices average $40 per barrel, U.S. shale oil production will likely decline by
3 million barrels per day between 2015 and 2020, and even if oil prices reach $60 per barrel,
a decline is still imminent, according to the International Energy Agency (IEA). US shale
production is not expected to halt the decline until we reach prices of $70 per barrel over the
same period."
IEA is completely disagreeing with anyone who is still claiming that shale has life below $70.
And you know what is interesting is that that 2 years ago IEA & EIA were singing the same song
but at this point IEA is splitting with that narrative because it is so obvious that you cannot
hide it anymore.
There will be time in a year when EIA will report the same and Wall Street will proclaim
"We are shocked. No one could have predicted this". Same old same old.
"... Why someone was investing in those cash-negative companies at the bottom of the cycle? And why they will not be investing when oil price will rise to $50 with prospects of further growth? ..."
"... US E&Ps were able to sell 10 billion not for the purpose of investing but for hiding the losses for little bit longer. That shale business model is dead. ..."
US E&Ps were able to sell about $10 billion in equity in 1Q16, most of it in January-February,
when oil price was around $30 and Goldman Sachs and others were predicting $20. Why someone
was investing in those cash-negative companies at the bottom of the cycle? And why they will not
be investing when oil price will rise to $50 with prospects of further growth?
Cost deflation will not continue in 2017 as demand for drillling and fracking services will
start to gradually recover.
US E&Ps were able to sell 10 billion not for the purpose of investing but for hiding the losses
for little bit longer. That shale business model is dead.
"... From the Iranian side, I have no doubts that an increase of another 1m barrels a day is precisely what they hope will happen, but the reality will surely be different. For all oil production, whether it is from an independent oil company or a sovereign nation, capital expenditures will determine the increase or decrease that can be achieved. Iran has a decidedly arthritic oil infrastructure, slowed by the lack of Western technology and the impact of a decade of sanctions. Their own economy is too weak to generate anywhere near the capex required to increase another 1 million barrels in the next year, and their overtures to foreign oil companies for leases inside Iran has been met cooly by prime contenders Total (TOT) and Eni (E). There is a lagged amount of already developed barrels that Iran can push onto the global market – perhaps 300,000 barrels a day; but by my reckoning, already 150,000 of those barrels have been added – making their ultimate targets very unlikely indeed to be reached. ..."
"... It wouldn't be consistent to believe that for the last year and a half, the Saudis have been capable of increasing their production by another 20 percent, but have so far kept that potential under wraps. Instead, I am fully of the opinion that the Saudis are near, if not at their full production potential right now. ..."
"... The oil market seems to agree – in February, if the threat of another 3 million barrels of oil hitting the global market had been unleashed, oil might have reached below $20 a barrel; today, oil is getting very close to rallying towards $50 a barrel instead. ..."
In light of the missed opportunity at Doha to curb OPEC production, angry statements have emerged
from both Iran and Saudi Arabia on oil production – the Iranians saying that they cannot be stopped
in increasing their exports another 1m barrels a day in the next 12 months, the Saudi oil minister
in turn threatening to increase production another 2m barrels a day. Both of these statements need
to be taken with not a grain, but a 5-pound bag of salt.
From the Iranian side, I have no doubts that an increase of another 1m barrels a day is precisely
what they hope will happen, but the reality will surely be different. For all oil production, whether
it is from an independent oil company or a sovereign nation, capital expenditures will determine
the increase or decrease that can be achieved. Iran has a decidedly arthritic oil infrastructure,
slowed by the lack of Western technology and the impact of a decade of sanctions. Their own economy
is too weak to generate anywhere near the capex required to increase another 1 million barrels in
the next year, and their overtures to foreign oil companies for leases inside Iran has been met cooly
by prime contenders Total (TOT) and Eni (E). There is a lagged amount of already developed barrels
that Iran can push onto the global market – perhaps 300,000 barrels a day; but by my reckoning, already
150,000 of those barrels have been added – making their ultimate targets very unlikely indeed to
be reached.
The Saudis do not have any of the capex or technology problems that plague the Iranians. But the
question of how much capacity the Saudis actually do have comes into play when they threaten to increase
production by another 2 million barrels. For my entire career in oil, there has always been a dark
question on Saudi 'spare capacity' – How much could the Saudis ultimately pump, if they were willing
to open the spigots up fully? For years, the speculation from most oil analysts was near to 7.5m
or 8m barrels a day – a number that was blown out in the last two years as Saudi production rocketed
above 10m barrels a day.
But the strategy the Saudis have pursued has been clear – they have been working towards full
production and an aggressive fight for market share since the failure of the Vienna OPEC meeting
in November of 2014. It is very difficult to believe that the Saudis have had much, if any, remaining
capacity to easily put on the market since that time, or if any spare capacity could be developed
at all. It wouldn't be consistent to believe that for the last year and a half, the Saudis have been
capable of increasing their production by another 20 percent, but have so far kept that potential
under wraps. Instead, I am fully of the opinion that the Saudis are near, if not at their full production
potential right now.
The oil market seems to agree – in February, if the threat of another 3 million barrels of oil
hitting the global market had been unleashed, oil might have reached below $20 a barrel; today, oil
is getting very close to rallying towards $50 a barrel instead.
"... Americans are driving more than ever before. Vehicle miles traveled (VMT) reached an all-time high of 3.15 trillion miles in February 2016 (Figure 2). VMT have increased 97 billion miles per month (3 percent) since the beginning of 2015 and gasoline sales have increased 187 kbpd (2 percent). The rates of increase are not proportional. ..."
Americans are driving more than ever before. Vehicle miles traveled (VMT) reached an all-time
high of 3.15 trillion miles in February 2016 (Figure 2). VMT have increased 97 billion miles per
month (3 percent) since the beginning of 2015 and gasoline sales have increased 187 kbpd (2 percent).
The rates of increase are not proportional.
... ... ...
From April 2015 to March 2016, oil production decreased 660 kbpd (-7 percent) but net crude oil
imports increased 800 kbpd (+10 percent) (Figure 5).
"... Last year, the seven biggest oil companies in the West only replaced 75 percent of their reserves. This is seriously bad news, especially combined with the fact that many new discoveries made in the last four years have disappointed. ..."
"... In the last four years the industry has seen disappointing - largely gas prone - exploration results, with the volume of liquids discovered annually falling from around 19 billion barrels between 2008 and 2011 to 8 billion barrels between 2012 and 2015 ..."
The third part of the problem is reserves replacement. New exploration is not just a form of art
for art's sake, or a means of expansion to boost bottom lines. It's an essential part of the operations
of an oil business. Oil is finite, and in order to stay profitable, an oil company needs to maintain
a consistent rate of reserves replacement.
And here's more bad news: Last year, the seven biggest oil companies in the West
only replaced 75 percent of their reserves. This is seriously bad news, especially combined with
the fact that many new discoveries made in the last four years have disappointed.
Wood Mac's exploration research vice-president told Offshore magazine that "In the last four years
the industry has seen disappointing - largely gas prone - exploration results, with the volume of
liquids discovered annually falling from around 19 billion barrels between 2008 and 2011 to 8 billion
barrels between 2012 and 2015."
"... Chevron Corp. shut down about 90,000 barrels a day of output following an attack on a joint-venture offshore platform that serves as a gathering point for production from several fields. Even before that strike on Wednesday night, Nigerian oil production had fallen below 1.7 million barrels a day for the first time since 1994, according to data compiled by Bloomberg. ..."
• Strike on Chevron platform cuts output by about 90,000 b/d
• Crude output fell in April to lowest in more than two decades
Nigeria is suffering a worsening bout of oil disruption that has pushed production to the lowest
in 20 years, as attacks against facilities in the energy-rich but impoverished nation increase
in number and audacity.
Chevron Corp. shut down about 90,000 barrels a day of output following an attack on a joint-venture
offshore platform that serves as a gathering point for production from several fields. Even before
that strike on Wednesday night, Nigerian oil production had fallen below 1.7 million barrels a
day for the first time since 1994, according to data compiled by Bloomberg.
"... that ND general stats show 13012 wells producing in Feb 2016 and 13212 in Oct 2016 (this is net i.e. wells added minus wells shut in), and 5) that taken together these do not indicate that there is any potential for a large production increase in the near or far future. ..."
"... I think we will have to see what happens when oil prices rise to $75/b or so, my expectation is that there will be at least 15,000 more wells completed in the Bakken/Three Forks in the next 10 years or so if oil prices rise to $75/b and remain at that level or higher. ..."
"... I expect ND Bakken/Three Forks output will increase gradually to maybe 1.22 Mb/d (only 60 kb/d above the previous peak) by about 2022 and then will gradually decline. This is under a scenario where the completion rate increases to 155 new wells per month and then gradually declines along with output. Total ERR of about 8.4 Gb and 27k total Bakken/Three Forks wells completed. The scenario requires high oil prices ($155/b in 2015$) by 2020, lower oil prices will mean less output. ..."
"... They know where it is because they searched heavily up to 2012. They didn't stop searching because of the price, or because they had so much acreage they didn't need any more. They stopped because they were hitting dry holes and ran out of places to look. That definitely does mean lack of success at the periphery. ..."
Dennis, I didn't look at well productivity, which is what you seem to be discussing. My points
were:
1) that there is no exploration drilling being conducted at present and that it declined quickly
after 2012 when prices were high, implying that there aren't any areas left worth looking at,
2) that 5 counties had high exploration success and these are the ones now responsible for
almost all production (and actually all in decline) and that the development in each county quickly
followed the exploration, suggesting core areas are key for overall production rates,
3) that other counties have been explored without success and are likely to be unproductive,
4) that ND general stats show 13012 wells producing in Feb 2016 and 13212 in Oct 2016 (this
is net i.e. wells added minus wells shut in), and 5) that taken together these do not indicate
that there is any potential for a large production increase in the near or far future.
If you think productivity increase is going to compensate for overall depletion and lack of
new exploration success then I think you are wrong.
They know where the oil is, there is not much need for exploration. I do not expect well productivity
to continue to increase, the chart was intended to show that there has been no productivity decrease
so far. I agree that at some point the sweet spots will be fully drilled and drilling will need
to move to less productive areas.
When that point is reached we will see new well productivity decrease.
Older low output wells from the non-Bakken formations have been shut in at faster rates due
to low prices, though some may be reactivated as oil prices rise. The NDIC seems to think there
are another 30,000 potential well locations, perhaps they are mistaken, the USGS also thinks there
are that many potential well sites and they could also be wrong.
I think we will have to see what happens when oil prices rise to $75/b or so, my expectation
is that there will be at least 15,000 more wells completed in the Bakken/Three Forks in the next
10 years or so if oil prices rise to $75/b and remain at that level or higher.
I also agree there won't be a large production increase (though we have not defined large).
I expect ND Bakken/Three Forks output will increase gradually to maybe 1.22 Mb/d (only
60 kb/d above the previous peak) by about 2022 and then will gradually decline. This is under
a scenario where the completion rate increases to 155 new wells per month and then gradually declines
along with output. Total ERR of about 8.4 Gb and 27k total Bakken/Three Forks wells completed.
The scenario requires high oil prices ($155/b in 2015$) by 2020, lower oil prices will mean less
output.
Exploration drilling in shale plays is important only in early stages of development. The
geology of the Bakken, Eagle Ford and the Permian is already very well known, and there is
no need for additional exploration. The fact that activity is currently concentrated in the
sweet spots does not mean lack of exploration success in the periphery. Resources are there,
but they are too costly to produce at current oil prices.
They know where it is because they searched heavily up to 2012. They didn't stop searching
because of the price, or because they had so much acreage they didn't need any more. They stopped
because they were hitting dry holes and ran out of places to look. That definitely does mean
lack of success at the periphery.
"... We could make a simple approximation of how much the decline will be in 2016: Production from wells starting in year 1, typically decline somewhere around 59% the next year. Older wells decline in total about 45%. ..."
"... Based on this I estimate that the wells in my dataset will do about ( 1400 * 41% + 1617 * 55% = ) 1463 kbo/d by Dec 2016. Add a little extra due to revisions, improved initial production, and maybe a somewhat slower drop in older production, and I would say that 1600-1800 is a close call, or a drop of about 1.4 mbo/d (not counting the output of any new completions in 2016). ..."
"... Last year, by December, total output from wells starting in 2015 was about that size (1.4 mbo/d). But the rate of completions is probably half (very roughly) the size this year, so the drop till 2016 Dec could be in the order of 700 kbo/d, just from the areas I'm looking at. ..."
U.S. shale producers are returning to unfinished business – completing previously drilled
wells – offering a ray of hope for oilfield service providers battered by the oil slump.
Halliburton Co and Baker Hughes Inc, the world's second and third-largest oilfield services
companies, indicated on Tuesday that they expected a drop in the large number of drilled-but-uncompleted
wells (DUCs) as crude oil prices steady.
Oil is hovering above the $40/barrel mark after having rallied 20 percent in the past month.
This has been enough for several producers to return to the thousands of unfinished wells that
dot shale fields across the United States – essentially to ready them for production.
Devon Energy Corp, Diamondback Energy Inc and SM Energy Co all said on post-earnings calls
on Wednesday that they were completing more wells.
There were 1,732 "abnormal" DUC wells in March – those that hadn't been completed within three
months of drilling – in the top five U.S. shale fields, including Eagle Ford in Texas and Bakken
in North Dakota, according to Alex Beeker, an analyst at energy consultant Wood Mackenzie.
That number is expected to consistently fall through the year.
Next month, for example, Beeker expects the number of such wells to drop by about 400. "We
don't see that volume (of DUCs) continuing to build; and in fact, it's being worked off in
the stream of work that's out there today," Halliburton President Jeff Miller said on Tuesday.
Baker Hughes said it expected oil producers to complete several hundred wells every month
as oil prices climb back into the mid-$50s.
… … …
To be sure, the fledgling recovery in spending won't mean the end of troubles for these
[oil services – AlexS] companies. "Even if DUCs come online, U.S. production will continue
to fall, and until output stops declining, it's going to be a challenging market for oilfield
service companies," said Rob Thummel, a portfolio manager at Tortoise Capital Advisors LLC.
"The number of new wells drilled in the United States has halved from 40,000, and the addition
of a thousand or two thousand wells will not do much to arrest steep declines in shale production."
The title of the article is misleading: "as more wells completed" => no, there will be less
wells completed compared with 2015, only more than are being drilled.
I just made an update on shale production in the US. What I found interesting to see is that
the legacy decline of wells > 1 year was about 50%, each year in the past few years (wells in
the non-Bakken basins decline much faster). For example, wells starting production before 2015,
dropped in total output from around 3.2 in Dec 2014, to 1.6 mbo/d by Dec 2015.
We could make a simple approximation of how much the decline will be in 2016:
Production from wells starting in year 1, typically decline somewhere around 59% the next year.
Older wells decline in total about 45%.
Based on this I estimate that the wells in my dataset will do about ( 1400 * 41% + 1617
* 55% = ) 1463 kbo/d by Dec 2016. Add a little extra due to revisions, improved initial production,
and maybe a somewhat slower drop in older production, and I would say that 1600-1800 is a close
call, or a drop of about 1.4 mbo/d (not counting the output of any new completions in 2016).
Last year, by December, total output from wells starting in 2015 was about that size (1.4
mbo/d). But the rate of completions is probably half (very roughly) the size this year, so the
drop till 2016 Dec could be in the order of 700 kbo/d, just from the areas I'm looking at.
This is not a prediction, just a rough guess at what might be in store.
"... Iraq: Production at an oilfield near Kirkuk, in northern Iraq, has been stopped after unidentified gunmen set at least two wells on fire on Tuesday night. ..."
"... US: An official update will be released next week, but Director of Mineral Resources Lynn Helms told an oil industry group in Williston he expects to see a "severe" production drop. ..."
"... IPD's prediction comes on the heels of its quarterly sector survey, which estimated Venezuela's oil output tumbled 6.8 percent to 2.59 million bpd in the first quarter compared with the same period of 2015, due to drilling delays, insufficient maintenance, theft, and diluent shortfalls. ..."
"... …Morgan Stanley's Benny Wong … estimates that the total number of offline capacity will be anywhere between 400 and 500 mbbl/d, with the shut-in expected to last about 10 days, potentially reducing total market output by as much as 5 million barrels. ..."
"... Americans are driving more than ever before. Vehicle miles traveled (VMT) reached an all-time high of 3.15 trillion miles in February 2016 Figure 2). VMT have increased 97 billion miles per month (3 percent) since the beginning of 2015 and gasoline sales have increased 187 kbpd (2 percent). The rates of increase are not proportional. ..."
Canada: Taken together this amounts to some 0.5 million [barrels a day] of capacity that is
currently offline. Infrastructure is being affected too, with the 560,000 b/d Corridor pipeline
shut down and movement along the 140,000 b/d Polaris pipeline significantly curtailed.
Lybia: An official at the port told the news agency that tanks at Hariga were 7-10 days away
from hitting their full capacity. This means, Reuters reported, that with no tankers loading oil
at the port, Libya will be forced to shut in about 120,000 bpd of output, which is the export
capacity of the port.
Iraq: Production at an oilfield near Kirkuk, in northern Iraq, has been stopped after unidentified
gunmen set at least two wells on fire on Tuesday night.
US: An official update will be released next week, but Director of Mineral Resources Lynn Helms
told an oil industry group in Williston he expects to see a "severe" production drop.
And all of that is worth a $1.17 of increase on WTI/Brent in the last 24h!!! Really? :-)
Venezuela's oil output may fall to average some 2.35 million barrels-per-day this year, as
the South American OPEC country's cash crunch and shortages weigh on production, according to
energy consulting firm IPD Latin America.
IPD's prediction comes on the heels of its quarterly sector survey, which estimated Venezuela's
oil output tumbled 6.8 percent to 2.59 million bpd in the first quarter compared with the same
period of 2015, due to drilling delays, insufficient maintenance, theft, and diluent shortfalls.
That estimate is a whisker above the 2.53 million bpd Venezuela produced in the first quarter,
according to OPEC numbers. But it marks the first time since the third quarter of 2008 that production
fell in all districts, including the extra-heavy crude Orinoco Belt, IPD added.
"…Analysts noted that Shell shut its Albian Sands mine and Suncor shut its base plant, while
producers Syncrude Canada and Connacher Oil & also reduced output in the region."Taken together
this amounts to some 0.5 million b/d of capacity that is currently offline. Infrastructure
is being affected too, with the 560,000 b/d Corridor pipeline shut down and movement along
the 140,000 b/d Polaris pipeline significantly curtailed. On top of that, trains are not operating
near Fort McMurray, according to the Canadian National Railway," said the analysts.
…Morgan Stanley's Benny Wong … estimates that the total number of offline capacity will
be anywhere between 400 and 500 mbbl/d, with the shut-in expected to last about 10 days, potentially
reducing total market output by as much as 5 million barrels.
Americans are driving more than ever before. Vehicle miles traveled (VMT) reached an all-time
high of 3.15 trillion miles in February 2016 Figure 2). VMT have increased 97 billion miles
per month (3 percent) since the beginning of 2015 and gasoline sales have increased 187 kbpd
(2 percent). The rates of increase are not proportional.
…From April 2015 to March 2016, oil production decreased 660 kbpd (-7 percent) but net crude
oil imports increased 800 kbpd (+10 percent) (Figure 5).
"... "It's going to be bad," Helms told the Williston Basin chapter of the American Petroleum Institute Tuesday night. North Dakota saw a smaller than expected drop in oil production in February as more companies put fracking crews to work to complete wells and maintain cash flow. ..."
"... March figures, scheduled to be released May 12, are reflecting the more significant production drop Helms had been anticipating. "I think that's a significant milestone," ..."
"... The declining North Dakota oil production – down from the record 1,227,483 barrels per day set in December 2014 – is prompting Helms to reevaluate an earlier projection he made that the state could one day produce 2 million barrels of oil per day. ..."
"... "It's kind of taken away hope of getting to 2 million barrels per day," Helms said. ..."
"... Low oil prices are forcing operators to focus drilling activity only in the core areas of the Bakken where wells have the greatest production. As oil prices recover and drilling expands to other areas of the Bakken, those high-producing wells will be declining, Helms said. ..."
WILLISTON – Early
March oil production numbers show that North Dakota will likely drop below 1.1 million barrels
per day for the first time since June 2014, the state's top oil regulator said. An official update
will be released next week, but Director of Mineral Resources Lynn Helms told an oil industry
group in Williston he expects to see a "severe" production drop.
"It's going to be bad," Helms told the Williston Basin chapter of the American Petroleum
Institute Tuesday night. North Dakota saw a smaller than expected drop in oil production in February
as more companies put fracking crews to work to complete wells and maintain cash flow.
The state produced an average of 1,118,333 barrels of oil per day in February, a 0.4 percent
drop from January, according to preliminary figures released in April. But March figures,
scheduled to be released May 12, are reflecting the more significant production drop Helms had
been anticipating. "I think that's a significant milestone," Helms told the oil industry
group.
The declining North Dakota oil production – down from the record 1,227,483 barrels per
day set in December 2014 – is prompting Helms to reevaluate an earlier projection he made that
the state could one day produce 2 million barrels of oil per day.
"It's kind of taken away hope of getting to 2 million barrels per day," Helms said.
Low oil prices are forcing operators to focus drilling activity only in the core areas
of the Bakken where wells have the greatest production. As oil prices recover and drilling expands
to other areas of the Bakken, those high-producing wells will be declining, Helms said.
"... 72% of petroleum used is for transportation. 63% of that is light duty
vehicles. So of 90mbod, 40 million barrels are subject to potential substitution
by electric vehicles. The adoption curve need only stay ahead of the decline curve.
..."
"... As an ex Mack Trucks sales person. I always considered SUVs and pickups
as light duty. I agree they will be electrified but it's going to take a little
longer than passenger vehicles. Right now hybrids are much more feasible because
of the more extreme workload they preform. Towing a 10k trailer a couple of hundred
of miles is going to take a lot of juice. ..."
"... America already runs hybrid buses if you consider that electric. To get
were the world needs to be, we're going to need a lot of f'n batteries. Once the
world solves the battery issue, there is not much reason class 8's can't be electrified
starting with local delivery trucks. ..."
Differences of opinion are what make discussion interesting.
72% of petroleum used is for transportation. 63% of that is light
duty vehicles. So of 90mbod, 40 million barrels are subject to potential
substitution by electric vehicles. The adoption curve need only stay ahead
of the decline curve.
Why worry about Caterpillars first when transportation is the biggest
slice of the petroleum pie, and the most readily subject to supercession
by other energy sources?
Transition may be improbable, but that's different than impossible.
Assuming that an ICE is 20% as efficient as an EV, which seems reasonable
as one barrel of oil is energy equivalent to 1628.2kWh, and will produce
19 gallons of gasoline, and 12 gallons of diesel. Assuming 30 mpg economy
for each, the barrel of oil provides 930 miles of travel, while 1628.2 kWh
at 3mpkWh will provide 4,884 miles of travel.
So if the light duty transport fleet was replaced 100% with electric
vehicles, 40.8 mbo/day would require 13.3 TWh of electric power substitution.
We have increased global annual renewable power production by 3,250 TWh's
in the last decade, so to increase renewable power production by 2030 to
produce 13TWh/day to offset 40.8 MBO/day used in the transportation sector
would require that we accomplish in the next fifteen years what we have
accomplished in the last ten (+3,250TWhp/decade).
As for the vehicles, all we must do is replace 100% of the light duty
fleet with EV's in that same 15 years. Easy as pie, right? :-)
As an ex Mack Trucks sales person. I always considered SUVs and pickups
as light duty. I agree they will be electrified but it's going to take a
little longer than passenger vehicles. Right now hybrids are much more feasible
because of the more extreme workload they preform. Towing a 10k trailer
a couple of hundred of miles is going to take a lot of juice.
America already runs hybrid buses if you consider that electric.
To get were the world needs to be, we're going to need a lot of f'n batteries.
Once the world solves the battery issue, there is not much reason class
8's can't be electrified starting with local delivery trucks.
"... As a warning to investors, EIA (Energy Information Administration) and IEA (International Energy Agency) data is reliable; however, their judgments are politically motivated. ..."
"... Also, there is no "glut" of oil. The market need is to power a 365-day food cycle. The reported "glut" is a storage problem of having 33.8 Days of Supply, 10 days more than the 24 Days of Supply typical for the past decade. ..."
As a warning to investors, EIA (Energy Information Administration) and IEA (International
Energy Agency) data is reliable; however, their judgments are politically motivated. Here is
a graph by the Dallas Federal Reserve on how, year after year, EIA forecasts repeatedly estimated
oil prices would drop as the 2008 economic collapse approached.
...As with failing to warn of higher oil costs in the ramp to the 2008 economic collapse, the
EIA is failing to warn the nation of the economic consequences of Peak Fracking. This provides investors
a knowledge gap.
... ... ...
To better understand oil geology and economics here are two links:
The mega-trends will force oil prices higher much faster than most believe.
Also, there is no "glut" of oil. The market need is to power a 365-day food cycle. The reported
"glut" is a storage problem of having 33.8 Days of Supply, 10 days more than the 24 Days of Supply
typical for the past decade. Economic fragility is created by not having 365 Days of Supply to meet
the needs of a 365-day food cycle; Examples: 1973 Oil Embargo, 1979 Iranian Revolution. Having 33.8
Days of Supply is only a 9% safety factor on a survival need. Take away the 18 Days of Supply required
to fill pipelines and there is a 4% safety margin on a non-elastic survival need. Fragility is extreme.
"... a true crisis is looming-and for the moment, there is no apparent way around it. ..."
"... Wood Mac's exploration research vice-president told Offshore magazine that "In the last four years the industry has seen disappointing - largely gas prone - exploration results, with the volume of liquids discovered annually falling from around 19 billion barrels between 2008 and 2011 to 8 billion barrels between 2012 and 2015." ..."
A
report by Wood Mackenzie has warned the world may face a daily oil shortage of 4.5 million barrels
by 2035. The amount represents around half of the global consumption
estimate of the International Energy Agency (IEA)
for 2016. In other words, a true crisis is looming-and for the moment, there is no apparent way around
it.
The most obvious reason is that energy companies don't want to spend money on exploration when
prices are so disappointingly low. Many of them simply can't afford to spend on exploration if they
want to survive in today's price environment. Ironically, their long-term survival can only be guaranteed
by further exploration spending.
A lot of costly projects have been shelved since the summer of 2014 when oil prices started falling,
with the initial investments basically written off. Reviving these projects will cost more money.
Where this money will come from is unclear-there is no certainty where oil prices are going in the
near term, let alone any longer period, and the European Commission today forecasted $41/barrel oil
for the rest of this year and just over $45 for 2017.
... ... ...
The third part of the problem is reserves replacement. New exploration is not just a form of art
for art's sake, or a means of expansion to boost bottom lines. It's an essential part of the operations
of an oil business. Oil is finite, and in order to stay profitable, an oil company needs to maintain
a consistent rate of reserves replacement.
And here's more bad news: Last year, the seven biggest oil companies in the West
only replaced 75 percent of their reserves. This is seriously bad news, especially combined with
the fact that many new discoveries made in the last four years have disappointed.
Wood Mac's exploration research vice-president told Offshore magazine that "In the last four years
the industry has seen disappointing - largely gas prone - exploration results, with the volume of
liquids discovered annually falling from around 19 billion barrels between 2008 and 2011 to 8 billion
barrels between 2012 and 2015."
"... rates are indeed down 30-35%, in some cases 40%. This fact, rather than technological improvements, largely explains lower upstream costs. And current rates are indeed unsustainable, so further cost cuts are very unlikely. ..."
"... I personally think that upstream capex and drilling activity will increase rather slowly and will not reach 2013-14 levels any time soon. Therefore, drilling/services rates will remain well below previous peak levels in the next few years. ..."
rates are indeed down 30-35%, in some cases 40%. This fact, rather than technological improvements,
largely explains lower upstream costs.
And current rates are indeed unsustainable, so further cost cuts are very unlikely.
But rates are down because of weak demand from the E&Ps. If demand surges, so will the
drilling/fracking rates.
I personally think that upstream capex and drilling activity will increase rather slowly
and will not reach 2013-14 levels any time soon. Therefore, drilling/services rates will remain
well below previous peak levels in the next few years.
And I agree that Rystad's LTO production forecast seems too optimistic.
I personally think that upstream capex and drilling activity
will increase rather slowly and will not reach 2013-14 levels any time soon. Therefore, drilling/services
rates will remain well below previous peak levels in the next few years.
I agree. Decisions to cut the US presence were made by some service companies and probably will
not be reversed "on the spot"
Oil price recovery will be gradual and probably slow. There are powerful forces behind "low oil
price forever" regime and they will counterattack sooner or later. This loss of control of oil price
by "paper oil" producers that we saw recently might be temporary. Any reversal will increase uncertainly
and low down recovery of drilling.
Please look at Art presentation - he predicts a leg down for oil prices "soon".
Surge of rates alone might well make $80 instead of $70 to be the minimum realistic price at which
mass drilling can be resumed for LTO. Now everybody is scared as hell (which is visible from rigs
dynamics).
And remember that LTO producers milked their best spots at a loss for more then a year now. Those
spots are gone. So to make modest profits they need higher prices now. As somebody said here that
reminds Toll Brothers strategy after subprime crisis.
"... The future decline rate will depend on many factors including the price of oil, my guess is that it will be between 1.1 percent/year and 4.7 percent/year. At 4.7 percent output in Texas would fall 210 kb/d over the next 12 months, the Bakken may fall about 200 kb/d, the rest of the lower 48 onshore maybe 100 kb/d, for a total decrease in U.S. L48 onshore C+C output of 500 kb/d in 2016. ..."
"... from Feb 2015 to Jan 2016, the decline rate is 7 percent/year, which would result in a 500 kb/d drop in U.S. L48 OS C+C output in the next 12 months if the decline rate remains 7 percent/year and Dean's estimate is correct for Texas. ..."
"... The decline rate from the peak in March 2015 is about 8.1 percent, if that trend continues for all of 2016, L48 OS C+C output will fall by 560 kb/d in 2016, increases in output in the Gulf of Mexico may offset this decline by 100 kb/d, if so U.S. C+C output would fall by 485 kb/d in 2016, assuming Alaska continues its 5 percent/year decline rate. ..."
The future decline rate will depend on many factors including the price of oil, my guess
is that it will be between 1.1 percent/year and 4.7 percent/year. At 4.7 percent output in Texas
would fall 210 kb/d over the next 12 months, the Bakken may fall about 200 kb/d, the rest of the
lower 48 onshore maybe 100 kb/d, for a total decrease in U.S. L48 onshore C+C output of 500 kb/d
in 2016.
An alternative estimate can be found by considering U.S. lower 48 onshore (L48 OS) C+C annual
decline rates.
The chart above replaces the EIA estimate for Texas C+C with Dean's "best guess" for Texas C+C
to estimate U.S. L48 OS C+C output from Feb 2015 to Jan 2016, the decline rate is 7
percent/year, which would result in a 500 kb/d drop in U.S. L48 OS C+C output in the next 12
months if the decline rate remains 7 percent/year and Dean's estimate is correct for Texas.
The decline rate from the peak in March 2015 is about 8.1 percent, if that trend continues
for all of 2016, L48 OS C+C output will fall by 560 kb/d in 2016, increases in output in the Gulf
of Mexico may offset this decline by 100 kb/d, if so U.S. C+C output would fall by 485 kb/d in
2016, assuming Alaska continues its 5 percent/year decline rate.
I wonder what ShallowS thinks of EOG's new strategy? That is, to choose their very best of the
best projects, cut costs to the bone and hope that they can make a profit.
Good analogies are
hard to come by, but I will throw one out. In 2009, at the depths of the housing collapse, what
if the CEO of Toll Brothers proposed: "We are going to select our very best lots – the Crown Jewels
in our inventory. Then we are going to build some of our more modest houses on them, cutting costs
to the bone. We hope that we can then sell them for at least break even." Personally, if I owned
the stock, I would have sold immediately.
Clueless. You know what I think. And I do really like your Toll Brothers example. What I think
is more impressive than their current meme on $30 oil is how they cut their estimate of future
production costs from $52 billion at the end of 2014 to $32 billion at the end of 2015, without
a major proved reserve reduction.
But hey, Continental cut theirs from $26 billion to $11 billion. So no big deal.
We have decided to that we too need to reduce our future production costs by 60%. The electric
cooperative said no problem. So did the chemical company, our workers comp carrier , liability
insurance carrier. The steel manufacturers did too , so our tubing and rods dropped 60%. The down
hole and injection pump service providers were ok with that.
Hey Clueless, even our accountant said, "No problem! Since you need to compete with OPEC and
Russia, we are knocking 60% off our bill! Now go beat those Saudi's and Russians in this oil price
war! Show em who is boss!"
Seriously, we have seen some cost reductions, but nothing remotely near 40-60%. And, of course,
although we pay the most to the electric coop of anyone, they just don't seem too keen on lowering
rates for us.
OFM. Look up above. I mentioned three publicly traded companies whose combined BOE was 160K BOEPD
who shut in production in Q4, before the latest $10+ dollar drop.
Just about every word you post makes good sense to me.
I am wondering about something just a little different, that being mainly HOW FAST this other
companies follow after the three you wrote about.
Let's suppose the price of oil gets up to fifty bucks. How many producers are going to be not
only losing money, but bleeding cash on a day to day basis at fifty bucks? Or sixty or seventy
?
You keep a hotel open if you generate more cash than it costs to operate it,from one day to
the next, even if it is losing money overall. I am thinking most oil producers will continue to
produce as long as they are generating some cash, but not much longer after that.
Who has the highest day to day production costs in the entire industry ? Some deep water operators,
most likely. They may hang on a while waiting for higher prices, or avoiding shut down and plugging
expenses, but not forever.
How long can they possibly hold on, if it costs them fifty or sixty bucks to get a barrel out
of the well and to shore?
So far as I can see, oil markets will remain COMPETITIVE.Nobody is going to pay a dime more
for a liter of gasoline or diesel fuel than necessary.
The price of oil WILL NOT go up, until either the economy picks up a good bit, or the amount
of oil coming to market drops off a a little.
All this talk about TRADERS controlling the price of oil is bullshit so far as I am concerned,
until somebody shows me HOW THEY CONTROL the production and distribution of oil.
IF the world economy actually does start going downhill, there are enough desperate for cash
oil producers out there for the cutthroat pricing to continue for a long time.
OFM. The way to look at production being shut in is not on a companywide level, but on a well
by well level.
A good well goes down with a failure, you pull it and get it back going. A not
so good well goes down with a failure, you leave it. Or, you have wells that are so out of the
money you just put a good coat of chemical down hole and then shut them in.
We have wells that we would run at $10, not many, but we do. Others do not work at $60. They
produce out of the same zone and can even be right next to each other.
For example, we have a lease where one well makes almost straight oil, about 3 barrels per
day, I think the pumping unit just makes six strokes per minute. The well just 330′ away makes
maybe 1/2 barrel of oil per day and about 30 barrels of water per day. Furthermore, the good well
is a straight hole. Bought the lease in 2005, have changed the pump twice and fixed a tubing leak
once in eleven years. The not so good well has been pulled 14 times, mostly due to tubing leaks.
Likely a crooked hole.
So when not so good well goes off, at $25 oil, its stays off. If the good well goes off, it
is repaired ASAP.
Companies don't just shut everything down, unless they are very small. Normally, if they go
bankrupt, the trustee will find a contractor to pump the good wells until sold, in a Chapter 7
anyway.
"... According to Professor Michael Jefferson, who spent nearly 20 years at Shell in various senior roles from head of planning in Europe to director of oil supply and trading, "the five major Middle East oil exporters altered the basis of their definition of 'proved' conventional oil reserves from a 90 percent probability down to a 50 percent probability from 1984. The result has been an apparent (but not real) increase in their 'proved' conventional oil reserves of some 435 billion barrels." ..."
"... Global reserves have been further inflated, he wrote in his study, by adding reserve figures from Venezuelan heavy oil and Canadian tar sands – despite the fact that they are "more difficult and costly to extract" and generally of "poorer quality" than conventional oil. This has brought up global reserve estimates by a further 440 billion barrels. ..."
"... Jefferson's conclusion is stark: "Put bluntly, the standard claim that the world has proved conventional oil reserves of nearly 1.7 trillion barrels is overstated by about 875 billion barrels. Thus, despite the fall in crude oil prices from a new peak in June, 2014, after that of July, 2008, the 'peak oil' issue remains with us." ..."
An extensive new scientific
analysis published in Wiley Interdisciplinary Reviews: Energy & Environment says that proved
conventional oil reserves as detailed in industry sources are likely "overstated" by half.
According to standard sources like the Oil & Gas Journal, BP's Annual Statistical Review of World
Energy, and the US Energy Information Administration, the world contains 1.7 trillion barrels of
proved conventional reserves.
However, according to the new study by Professor Michael Jefferson of the ESCP Europe Business
School, a former chief economist at oil major Royal Dutch/Shell Group, this official figure which
has helped justify massive investments in new exploration and development, is almost double the real
size of world reserves.
Wiley Interdisciplinary Reviews (WIRES) is a series of high-quality peer-reviewed publications
which runs authoritative reviews of the literature across relevant academic disciplines.
According to Professor Michael Jefferson, who spent nearly 20 years at Shell in various senior
roles from head of planning in Europe to director of oil supply and trading, "the five major Middle
East oil exporters altered the basis of their definition of 'proved' conventional oil reserves from
a 90 percent probability down to a 50 percent probability from 1984. The result has been an apparent
(but not real) increase in their 'proved' conventional oil reserves of some 435 billion barrels."
Global reserves have been further inflated, he wrote in his study, by adding reserve figures from
Venezuelan heavy oil and Canadian tar sands – despite the fact that they are "more difficult and
costly to extract" and generally of "poorer quality" than conventional oil. This has brought up global
reserve estimates by a further 440 billion barrels.
Jefferson's conclusion is stark: "Put bluntly, the standard claim that the world has proved conventional
oil reserves of nearly 1.7 trillion barrels is overstated by about 875 billion barrels. Thus, despite
the fall in crude oil prices from a new peak in June, 2014, after that of July, 2008, the 'peak oil'
issue remains with us."
That spells big trouble for the USA oil production in 2017 and 2018...
Notable quotes:
"... I see the only bright spot in the rig count, is the long forgotten Barnett. It appears it is no longer a gas play, but is now seen as a oil play. There are 6 oil rigs working, increasing one per week all through April. It seems to be the only area that has more rigs drilling this year, than last. ..."
"... I think the rigs per "play" is geography more than geology. There are not that many rigs drilling haynesille shale wells ..."
"... I assume that possibly there have been improvements (technological, etc.) that make newer vintage wells more productive? Keep in mind these wells cost in the $7-9 million dollar ballpark to drill, complete and equip. ..."
I see the only bright spot in the rig count, is the long forgotten Barnett. It appears it is
no longer a gas play, but is now seen as a oil play. There are 6 oil rigs working, increasing
one per week all through April. It seems to be the only area that has more rigs drilling this
year, than last.
Based on what I can tell, here is a distribution for horizontal Spraberry wells with first
production on or before 7/2014. There appear to be 715 active wells.
First, cumulative oil through 1/16:
2% 200,000 bo or more
7% 150,000-199,999 bo
26% 100,000-149,999 bo
41% 50,000-99,999 bo
17% 25,000-49,999 bo
7% 1-24,999 bo
Next, most recent monthly production (1/16) for these wells:
9% 3,100 bo or more
32% 1,530-3,099 bo
30% 775-1,529 bo
29% 1-774 bo
I assume that possibly there have been improvements (technological, etc.) that make newer vintage
wells more productive? Keep in mind these wells cost in the $7-9 million dollar ballpark to drill, complete and equip.
Enno has a post coming out soon on the Permian, interested to see what it reveals.
"... But it can deflate in 3 years if there is no capital as we are watching it right now. And you are left just with debt on the end of cycle. For big majors to go into shale and do that kind of investment that is solely based on market timing it is equivalent of individual investors picking individual stocks based on market timing and going in and out. That is equivalent to suicide in long run and no one who even remotely understands how market works would do that kind of thing. ..."
"... Which would require another 30,000 shale wells at an estimated total cost of 250 billion more dollars. The first 30,000 shale oil wells have not been paid for yet and short of 100 dollars a barrel, sustained, won't. Besides, it looks like a game of Pixie Stix out there in sweet spots now, where might these other 30,000 wells get drilled? If off on the flanks, it will take 50,000 shale wells to get back to 4 MBOPD, and 400 billion more dollars. Much longer laterals, oodels more sand and horsepower, much poorer wells, you see. ..."
"... Shale fell out or favor for Wall Street if we look at which rates and on what terms credit lines are rotated. So this hypothesis about re-appearance of "available capital" with "proper" oil prices is weaker then it looks. ..."
"... Loosing a couple of billion dollars provide (a temporary) lesson for a bank. Let's say for three years (may be slightly longer - five years). After that they again are ready to break their neck running for better profits :-). So "reckless" capital might not be available for shale before 2020. ..."
"... In other words, "carpet drilling" is a feat that is difficult to repeat unless something fundamentally changes in shale technologies or world oil production picture. ..."
Alex, But it can deflate in 3 years if there is no capital as we are watching it right now. And
you are left just with debt on the end of cycle. For big majors to go into shale and do that kind
of investment that is solely based on market timing it is equivalent of individual investors picking
individual stocks based on market timing and going in and out. That is equivalent to suicide in
long run and no one who even remotely understands how market works would do that kind of thing.
Which would require another 30,000 shale wells at an estimated total cost of 250 billion more
dollars. The first 30,000 shale oil wells have not been paid for yet and short of 100 dollars
a barrel, sustained, won't. Besides, it looks like a game of Pixie Stix out there in sweet spots
now, where might these other 30,000 wells get drilled? If off on the flanks, it will take 50,000
shale wells to get back to 4 MBOPD, and 400 billion more dollars. Much longer laterals, oodels
more sand and horsepower, much poorer wells, you see.
By the time the shale oil industry admits it needs help and wants to sell assets to majors,
or bigger companies, or anybody with new credit, it will be too late. Those "assets" will have
already depleted 50% of their exaggerated EUR's, the remaining 50% will take 20 more years to
realize, maybe, and be nothing more than stripper wells. Buyers will not be paying a lot of money
for 'de-risked' acreage and PUD's when all the wells nearby have already proven themselves grossly
unprofitable. There is a reason major integrated companies did not get into shale oil plays in
the first place. They are not going to change their minds because the price of oil is now 40,
instead of 100.
This M&A stuff is more shale oil hope. Like 50 dollar oil will supposedly put them all back
cranking out the wells again and everything will be peachy.
Shale fell out or favor for Wall Street if
we look at which rates and on what terms credit lines are rotated. So this hypothesis about re-appearance
of "available capital" with "proper" oil prices is weaker then it looks.
It might not be available before, say, $100 per bbl and before 2020. And even in this case
amount will be less then in the past and conditions less favorable.
Loosing a couple of billion dollars provide (a temporary) lesson for a bank. Let's say
for three years (may be slightly longer - five years). After that they again are ready to break
their neck running for better profits :-). So "reckless" capital might not be available for shale
before 2020.
In other words, "carpet drilling" is a feat that is difficult to repeat unless something
fundamentally changes in shale technologies or world oil production picture.
Looks like "Go to Iran my friend to drill" is the slogan now :-)
"... I have been discussing this play with Mike, he has knowledge of the area. He says that, despite the low volume, the vertical wells (which are 7-10,000′ deep) are profitable because of the low produced water volume. ..."
"... I really think what is happening here is very simple, the hz wells just pull out a lot more oil up front, but likely by years 3 and on, they really do not produce much, if any, more than the vertical Spraberry wells. ..."
"... Therefore, it appears to me the 1-1.25 million BOE EUR type curves are vastly overstated. ..."
"... There are exceptions, PXD's wells on the ET O'Connor and Donald Hutt leases are very strong. There are a few others. There are also exceptions with regard to the vertical wells, but, like the hz, those appear to be few and far between, less of those on a percentage basis than Parshall and Grail in the Bakken, for example. ..."
"... In summary, I question whether allowing tightly spaced horizontal wells in the Spraberry is in the best interests of both economics and conservation practices? I am not qualified to delve into that, but I think someone should. ..."
"... I am concerned that Mike is exactly right, that the horizontal well boom, and the lack of spacing rules for those wells, is leading to significant waste, that is going to bite us in a few years. ..."
"... Really surprising that the spacing rules are being ignored for short term gain? I guess that is what the US stock markets are all about, so no surprise at all. After all, who is going to get excited about $1 million vertical Spraberry wells that IP 150 bopd, cum. 75,000 barrels of oil in the first couple or three years, and then produce 1,500 – 7,500 barrels of oil for the next 40 years? 3,000 BOE IP's and 1.25 million BOE EUR type curves sell so much better, I suppose. ..."
"... Thanks for information Shallow, and this is a bit off topic but you follow the financials of these companies. I see these companies touting that they can make money with a 30-50% ROI drilling these wells. I assume this is for the first year. How in the hell are they making money on these wells that deplete at the rate they do, with only a 30% ROI in the first year. ..."
"... In other words this is a new way of infill drilling ..."
I have been studying the Spraberry horizontal wells in the Permian basin, which appear to be
the most favored LTO well by Wall Street at the present time.
It appears to me that there is no magic, so to speak. The Spraberry was first developed on
large scale in 1950-51. The vertical wells of that era came in with very high IP, but rapidly
fell off.
There was tremendous activity in the Spraberry with vertical wells in the last ten years, when
oil made its rapid climb.
Little paid attention to when PXD is discussed, is that they operate over 6,500 vertical Spraberry
wells in the Permian Basin. Of those, almost 6,000 have attained "stripper well status" of 15
barrels of oil per day, or less. It appears the wells settle out in a range of 5-15 barrels per
day, and produce around 2-3 barrels of water for every barrel of oil. The wells also tend to produce
minor amounts of gas.
I have been discussing this play with Mike, he has knowledge of the area. He says that, despite
the low volume, the vertical wells (which are 7-10,000′ deep) are profitable because of the low
produced water volume.
Basically, it seems the vertical wells are only pumped a few days per month. I am not from
the PB, but have been through Midland and Upton Co. TX, and have seen scores of very large (160K
pound and greater) pump jacks, most of them idle.
When I look at the older (2+ years, so not really that old, but just in relative terms) hz
Spraberry wells, I see the same thing, very low volumes. Almost none of PXD's hz wells still produce
100+ bopd after two years, most are already below 50 bopd after two years.
I really think what is happening here is very simple, the hz wells just pull out a lot more
oil up front, but likely by years 3 and on, they really do not produce much, if any, more than
the vertical Spraberry wells.
Therefore, it appears to me the 1-1.25 million BOE EUR type curves are vastly overstated.
There are exceptions, PXD's wells on the ET O'Connor and Donald Hutt leases are very strong.
There are a few others. There are also exceptions with regard to the vertical wells, but, like
the hz, those appear to be few and far between, less of those on a percentage basis than Parshall
and Grail in the Bakken, for example.
One other interesting thing I noted. Summit Petroleum is a decent sized private company which
has been drilling, completing and operating Spraberry wells for many years. I noticed that they
have only drilled 3 horizontal Spraberry wells, or at least that is all I can find producing as
of 1/16. It appears they continued to drill vertical wells in 2015, albeit at a much slower pace
than prior years.
In summary, I question whether allowing tightly spaced horizontal wells in the Spraberry is
in the best interests of both economics and conservation practices? I am not qualified to delve
into that, but I think someone should.
I am concerned that Mike is exactly right, that the horizontal well boom, and the lack of spacing
rules for those wells, is leading to significant waste, that is going to bite us in a few years.
Really surprising that the spacing rules are being ignored for short term gain? I guess that
is what the US stock markets are all about, so no surprise at all. After all, who is going to
get excited about $1 million vertical Spraberry wells that IP 150 bopd, cum. 75,000 barrels of
oil in the first couple or three years, and then produce 1,500 – 7,500 barrels of oil for the
next 40 years? 3,000 BOE IP's and 1.25 million BOE EUR type curves sell so much better, I suppose.
Again, would be interested in comments on this from those who have better technical background
than me. In particular, would like to hear from horizontal proponents, but seems coffee is the
only one that lurks around here. Coffee, what do you think?
Thanks for information Shallow, and this is a bit off topic but you follow the financials of
these companies.
I see these companies touting that they can make money with a 30-50% ROI drilling these
wells. I assume this is for the first year. How in the hell are they making money on these
wells that deplete at the rate they do, with only a 30% ROI in the first year.
"... "Schlumberger-after posting its first North American operating loss since at least the turn of the century, according to Barclays Plc-is evaluating whether it's worth temporarily shuttering its business in the region. Baker Hughes said Wednesday it has decided to limit its exposure to unprofitable onshore fracking work in North America because of the unsustainable pricing. ..."
"... This indicates there will be no quick return to high volume horizontal fracking on a large scale in North America. ..."
"HOUSTON (Bloomberg) - Two of the three largest oil rig operators and frackers are considering
pulling back from the North American market as losses mount.
"Schlumberger-after posting its first North American operating loss since at least the turn
of the century, according to Barclays Plc-is evaluating whether it's worth temporarily shuttering
its business in the region. Baker Hughes said Wednesday it has decided to limit its exposure to
unprofitable onshore fracking work in North America because of the unsustainable pricing.
"It's the first time in at least a decade that those companies and Halliburton Co., the big
3 in oil services, all lost money in the region during the first three months of the year, according
to Bloomberg Intelligence."
Has any upstream division of any operator so far reporting 1Q16 shown a profit? ExxonMobil,
BP, and Statoil had profits overall but only because of downstream and marketing operations.
This indicates there will be no quick return to high volume horizontal fracking on a large
scale in North America.
I am not aware on any company in the E & P upstream focused in North America that has positive
earnings for Q1, 2016, but I have not made an exhaustive look.
The U.S. Shale Boom Was Financed By Low Interest Rates
The hunt for yield in the era of lower to zero interest rates leads
to peculiar investment decisions. In 2008 the collapse of the
housing bubble – driven by an endless investor appetite for
high-yield mortgage bonds of questionable quality – was said to
cause the global recession. This precipitated the collapse of major
financial institutions like Lehman Brothers and the bailout of many
more. Regulators frowned and tried to bring in policies to ensure
it would not happen again.
The great light tight oil (LTO) or shale boom in the U.S. since
2010 has all the hallmarks of a similar asset bubble. Exploration
and production (E&P) companies were able to finance significant
drilling through the sale of subordinated bonds with an attractive
yield of 6 percent or more. They were for the most part
interest-only and due in several years. The problem with drilling
high decline LTO wells with high-yield debt is by the time the
bonds mature, the production from the wells the debt paid for has
declined to the point the assets are only worth a fraction of the
leverage outstanding. Many companies in the U.S. are already broke
and more will follow. Much analysis has been done to show some of
the top LTO drillers in the U.S. spent $2 on drilling for every $1
of cash flow prior investments had generated. The difference was
made up by seemingly limitless capital inflows.
This has created two problems for Canada's oil future. The first
is even if commodity prices rise and transportation issues are
solved, the ability of companies to raise cheap debt will be
impaired for some time, perhaps forever, depending on what happens
to interest rates. Historical E&P spending has almost always
exceeded cash flow providing investment, jobs and opportunity that
would not exist otherwise. External capital inflows are essential
to feed the machine.
The other is the impact debt-financing has had on oilfield
services (OFS) sector balance sheets. As has been written on these
pages before, in 2014 and 2015 alone 21 diversified Canadian OFS
operators invested $37 billion adding new rigs, frack spreads,
camps, processing plants, midstream facilities and pipelines for a
growing North American oilpatch. Three large Canadian pressure
pumpers alone carried a combined $2.6 billion in debt and one has
gone broke. A lot of E&P demand was financed by debt, which is no
longer available. Now OFS is overbuilt and many operators
over-levered. It will take some recovery to clean this up.
U.S. gasoline consumption, averaged over four weeks, rose 3.9 percent from
a year earlier to 9.39 million barrels a day through April 15, Energy Information
Administration data show. Demand this summer will increase 1.4 percent to a
record, the EIA said April 12. Americans drove 232.2 billion vehicle miles in
February, up 5.6 percent from a year earlier, Transportation Department data
show.
"Gasoline demand is quite strong and that's all price driven," said Thomas
Finlon, director of Energy Analytics Group LLC in Wellington, Florida. "Demand
for gasoline should provide support for crude."
The average price of regular gasoline at the pump nationwide was $2.136 a
gallon on Sunday, down 15 percent from a year earlier, according to data from
Heathrow, Florida-based AAA, a national federation of motor clubs.
Speculators' net-long position in WTI gained by 30,357 futures and options
combined to 245,987, CFTC data show. Long positions, or bets that prices will
rise, increased 4.8 percent, while shorts tumbled 19 percent.
In other markets, net bullish bets on Nymex gasoline climbed 15 percent to
23,357 contracts. Gasoline futures declined 3.5 percent in the period. Net bearish
wagers on U.S. ultra low sulfur diesel decreased 11 percent to 7,773 contracts,
the least since June as futures slipped 1 percent.
"... All of them are already in decline, as well as fields discovered in the sixties and seventies. There are a few exception – fields discovered several decades ago, but developed only recently (Manifa in Saudi Arabia, Kashagan in Kazakhstan). ..."
"... Rystad Energy estimates that only 9 Billion boe were discovered during 2015. This is 30% down from 2014 which was an all-time low. For comparison, world oil production is in the order of 30+ billion barrels each year. ..."
"... only 19% of the produced conventional resources were replaced by new discovered volumes last year, says Nils-Henrik Bjurstrřm, Senior Project Manager, in Rystad Energy ..."
"... Regrettably, the negative trend continues. In January 2016, only 250 million boe were discovered (in comparison, the Goliath field in the Barents Sea has reserves of approximately 200 MMbo), indicating a possibility for an even lower exploration result in 2016, says Bjurstrřm. ..."
"... So potentially going from just 9 billion BOE in 2015 to maybe 3 billion BOE in 2016. When will the oil markets take notice of this? Also, wonder how much of that is natural gas and condensate? ..."
"... Nobody is arguing that "all the supergiants" will come off their plateaus at the same time. That's a cheap straw man argument. Plus it's meaningless because there's no sense of that "at the same time" means. ..."
"... We don't need all of the super giants to go into decline all at the same time - two or three going into decline within a five year period would suffice. Or just one - Gawhar - would do. I think the probability of several super giants going into decline more or less at the same time is quite possible. But since nobody knows what the probabilities are, making any statements about the probabilities is pointless. ..."
"... I agree. Furthermore, I think everyone here realizes most oil comes from oilfields discovered prior to 1970 and almost all oilfields that still produce an average of over 500,000 barrels per day are 70-ish years old. So, ignoring Ghawar, Burgan and Daquing, oilfields that HAD a productive capacity exceeding one million barrels a day include Samotlor (1965), Prudhoe Bay (1968) and Cantarell (1976). That's not a flush but it is three of a kind. ..."
"... And all of those 1mb/d+ supergiants are already in decline (the most recent – Daquing) ..."
From a statistics perspective the chances of all the supergiants coming off their plateaus
at about the same time is quite an unrealistic assumption. Do you guys get a lot of straight flushes
when you play poker (no wild cards)? I have played a little poker and have never seen a straight
flush in real life, only in the movies.
You are no doubt correct that the old supergiants won't all go into terminal decline together,
but it does seem reasonable to assume that most of them will peak and begin to go downhill within
some particular time frame measured from first production.
Now I am going to pull some numbers out of thin air to illustrate my point, and then maybe
somebody who knows more can elaborate on the significance of it.
Let us suppose that the really big oil fields mostly peak between say thirty and forty years
from first production.
It is my impression as a casual observer rather than a numbers cruncher or hands on investor
that just about all the really big oil fields were discovered and put into production at least
that long ago.
So taken as a group, they will probably begin going into decline AS A GROUP all together over
about the same time frame as they were discovered as a group.
Fields discovered and first produced in the fifties, if I am right about this, will probably
mostly all go into decline together over a period of about a decade or so, by way of example.
Basically what I am trying to say is that oil fields probably have a statistically predictable
life span, and that most of the really big ones are probably all roughly about the same age, in
terms of being produced. Nearly all of them will probably peak with in ten to fifteen more years,
since all of them are getting to be up around thirty or forty years of production history.
IIRC, it's been a hell of a long time since somebody discovered a new super giant or giant
field.
Somebody like Fernando ought to be able to take this observation and run with it.
"Fields discovered and first produced in the fifties, if I am right about this, will probably
mostly all go into decline together over a period of about a decade or so, by way of example."
All of them are already in decline, as well as fields discovered in the sixties and seventies.
There are a few exception – fields discovered several decades ago, but developed only recently
(Manifa in Saudi Arabia, Kashagan in Kazakhstan).
As I understand, the main sources of growth in global proved oil reserves in the past 10 years
were:
1) Rising oil prices, which enabled to include Venezuela's ultra-heavy oil from the Orinoco
belt and some other high-cost resources into proved reserve category;
2) New discoveries (which, as you say, are now much smaller than in previous decades);
3) Upward revisions of reserve estimate of the already developed fields due to reserves extension,
new reservoir discoveries in old fields, use of improved recovery techniques or equipment, etc.;
4) Inclusion of part of LTO resources into proved reserve category.
The contribution of new discoveries was actually a secondary factor.
The year 2015 was a global all-time low in terms of conventional oil and gas discoveries, says
Nils-Henrik Bjurstrřm in Rystad Energy.
Rystad Energy estimates that only 9 Billion boe were discovered during 2015. This is 30%
down from 2014 which was an all-time low. For comparison, world oil production is in the order
of 30+ billion barrels each year.
– As a result, only 19% of the produced conventional resources were replaced by new discovered
volumes last year, says Nils-Henrik Bjurstrřm, Senior Project Manager, in Rystad Energy ,
to geo365.no.
Regrettably, the negative trend continues. In January 2016, only 250 million boe were discovered
(in comparison, the Goliath field in the Barents Sea has reserves of approximately 200 MMbo),
indicating a possibility for an even lower exploration result in 2016, says Bjurstrřm.
Note: 9 Billion boe discovered during 2015 and 250 mboe discovered in 1Q16 are oil and gas.
And the discovered volumes are not immediately included in proved reserve category
So potentially going from just 9 billion BOE in 2015 to maybe 3 billion BOE in 2016. When
will the oil markets take notice of this? Also, wonder how much of that is natural gas and condensate?
Note: XOM produces over 4 million BOEPD. In 2015 proved reserves fell 24%. First time they
didn't replace 100% of reserves since 1990s.
Yes, I understand price has something to do with that. But still?
Exxon's total liquids proved reserves actually increased from 13713 million barrels on December
31, 2014 to 14724 million barrels on December 31, 2015
(source: 10-k)
There was a sharp downward revision in nat gas proved reserves, reflecting lower gas prices.
ExxonMobil Corp. added 1 billion boe of proved oil and gas reserves in 2015, replacing just
67% of production during the year compared with 115% over the past 10 years.
In 2014, the firm replaced 104% of its production by adding proved oil and gas reserves totaling
1.5 billion boe.
The 2015 total includes a 219% replacement ratio for crude oil and other liquids.
However, proved reserves of natural gas were reduced by 834 million boe primarily in the US, reflecting
the change in gas prices. The company expects this gas to be developed and booked as proved reserves
in the future.
At yearend, ExxonMobil's proved reserves totaled 24.8 billion boe. Liquids represented 59% of
proved reserves, up from 54% in 2014. ExxonMobil's reserves life at current production rates is
16 years.
Reserves during the year were added in Abu Dhabi, Canada, Kazakhstan, and Angola. Liquid additions
totaled 1.9 billion bbl.
ExxonMobil added 1.4 billion boe to its resource base through by-the-bit exploration discoveries,
undeveloped resource additions, and strategic acquisitions.
The firm's exploration activity in 2015 included the Liza oil discovery offshore Guyana (OGJ
Online, May 20, 2015), and additional discoveries in Iraq, Australia, Romania, and Nigeria. Strategic
unconventional resource additions were made in the Permian basin, Canada, and Argentina.
Overall, the company's resource base totaled more than 91 billion boe at yearend 2015, taking
into account field revisions, production, and asset sales. The resource base includes proved reserves,
plus other discovered resources that are expected to be ultimately recovered.
Really Dennis? From a statistics perspective? Assuming what probability distribution and correlation
matrix?
Nobody is arguing that "all the supergiants" will come off their plateaus at the same time.
That's a cheap straw man argument. Plus it's meaningless because there's no sense of that "at
the same time" means.
We don't need all of the super giants to go into decline all at the same time - two or
three going into decline within a five year period would suffice. Or just one - Gawhar - would
do. I think the probability of several super giants going into decline more or less at the same
time is quite possible. But since nobody knows what the probabilities are, making any statements
about the probabilities is pointless.
I agree. Furthermore, I think everyone here realizes most oil comes from oilfields discovered
prior to 1970 and almost all oilfields that still produce an average of over 500,000 barrels per
day are 70-ish years old. So, ignoring Ghawar, Burgan and Daquing, oilfields that HAD a productive
capacity exceeding one million barrels a day include Samotlor (1965), Prudhoe Bay (1968) and Cantarell
(1976). That's not a flush but it is three of a kind.
I was responding to a comment by George Kaplan, he said:
…all the supergiants have been developed with extensive IOR/EOR methods and may come off
plateau and collapse production at about the same time (for me this sudden high decline rate,
more than the actual peak is what is going to destroy the world economy if we don't do something
– in fact a lot – beforehand).
So based on the excellent comments by AlexS and Rune Likvern, we know that most of the supergiant
fields are already declining, but the question would be is it very likely they all begin a "collapse
in production" at about the same time time.
I believe the probability is low and I interpret "about the same time" as within 5 years and
"collapse in production" as a field decline of 10% or more.
It would be interesting in hearing other opinions on how likely this scenario is, I would guess
it is less than 5%.
Hi Doug,
Using the Wikipedia list of giant oil fields there are 59 fields that have a URR of 5 Gb or
more. The point is that the most notable "collapse" has been Cantarell, as long as the "collapse"
doesn't happen "at about the same time" in all 59 fields we are unlikely to see a steep decline
in World output, as long as there is adequate demand for oil to keep oil prices at a level where
it continues to be profitable to develop reserves.
If there is an economic collapse due to excessive debt, or some other reason (high oil prices
maybe), then decline might be steeper, essentially this will depend on the extent of the economic
downturn. That is difficult to predict.
"... Oil discoveries have dropped to being almost insignificant over the last 5 years, ..."
"... There is very little reserve growth on discoveries over the last 10 years ..."
"... The arctic is at least 25 years away or never the Atlantic and Pacific coasts are off limits, ..."
"... The current CAPEX collapse is going to be extremely disruptive ..."
"... Once investors see oil companies repeatedly unable to replace reserves they will pull all their money, ..."
"... All the supergiants have been developed with extensive IOR/EOR methods and may come off plateau and collapse production at about the same time ..."
"... Spot on George. The only thing I might have included in your list is Reservoir Creaming whereby horizontal production holes are put across the caps of oil pools to maintain high production rates at the expense of increasing depletion rates. This seems to have become standard practice ..."
"... All your six points are true (although point 5 needs clarification - you need stable oil price and diminishing reserves for this to happen; otherwise speculative forces will drive stock prices up in anticipation of higher oil prices). ..."
I think things will be worse than Jeffersons study indicates for several
reasons:
Oil discoveries have dropped to being almost insignificant over
the last 5 years,
There is very little reserve growth on discoveries over the
last 10 years (technology is so good now at estimating the oil
in place, projects are so expensive that the operators need to know
exactly what they will recover before investing, and putative drilling
in deep sea is too expensive),
The arctic is at least 25 years away or never the Atlantic and
Pacific coasts are off limits,
The current CAPEX collapse is going to be extremely disruptive
(the GoM curve above stops just at the point when production is going
to collapse as there will be very few new projects being completed and
the surge of projects that came online over the last 2 to 3 years will
suddenly come off their short plateaus and go into 10% plus decline
rates,
Once investors see oil companies repeatedly unable to replace
reserves they will pull all their money,
All the supergiants have been developed with extensive IOR/EOR
methods and may come off plateau and collapse production at about the
same time (for me this sudden high decline rate, more than the
actual peak is what is going to destroy the world economy if we don't
do something – in fact a lot – beforehand).
Spot on George. The only thing I might have included in your list is
Reservoir Creaming whereby horizontal production holes are put across the
caps of oil pools to maintain high production rates at the expense of increasing
depletion rates. This seems to have become standard practice.
All your six points are true (although point 5 needs clarification
- you need stable oil price and diminishing reserves for this to happen;
otherwise speculative forces will drive stock prices up in anticipation
of higher oil prices).
So the main efforts now should be in oil conservation area and to start
those we heed high (as in over $100 per barrel) oil price. And I think it
is coming.
"... As for OPEC reserves, I have no clue how those are arrived at, same as I seriously doubt Kuwait is producing almost 3 million BOPD from less than 2,000 oil wells, especially as the major field, Burgan, had first production 70 years ago. ..."
"... I would note your chart ends in 2014. The average oil price in 2014 was about $95 WTI. ..."
"... As Warren Buffet is fond of saying, it's only when the tide goes out that you find out who's been swimming naked. It should be obvious to anyone that countries with static reserve numbers are not being truthful. But there is a willingness among analysts and news providers to accept the published numbers. What else can they do? They can't make up their own numbers or rely on guesses from gadfly oil watchers. When production from these coutries starts going into steady decline, the truth will be known. ..."
"... Venezuela Orinoco Belt accounted for 68% of the increase in the world proved oil reserves between 2005-14, according to BP's estimate. This is entirely due to higher oil prices. Interestingly, according to BP's estimate, Canada' oil reserves actually declined in the past 10 years. ..."
Given that proved reserves are largely a function of price it is inevitable that reserves would
significantly drop as price dropped. The only reasons proved reserves have grown over the last
ten years when very few new discoveries have been made has been refined drilling techniques (fracking)
and high prices.
Andrew, although proven reserves are reserves that must be "economically recoverable" and that
would change somewhat if the price of oil changes drastically, you will find that no oil company
or nation changes their reserves up or down with the price of oil. It is assumed that what is
economically recoverable will average out as the oil price moves up and down over the years.
So no, proven reserves are not largely a function of the price of oil as you put it.
Proven reserves should decline as the oil is extracted and only about one fourth of the extracted
oil is replaced with new discoveries. But neither nations nor oil companies change their stated
proven reserves in response to the changes in the price of oil.
Publically traded oil companies are obliged to change the value of their proven reserves
up or down according to the price of oil however, but not the amount in barrels.
Ron: SEC rules do require reserve changes as oil prices change. This is reflected in the standard
measure forms. However, we can change opex and do have other considerations….for example, when
prices drop we cover the required reserve drop with performance increases (if we can back it up).
It's all done in a back office ceremony we do while wearing black robes and golden masks. So I
can't discuss it any more.
Reserves calculated per SEC guidelines definitely are affected by oil prices, although as Fernando
seems to imply, especially when there has been such a large crash in price, some magic is performed.
As for OPEC reserves, I have no clue how those are arrived at, same as I seriously doubt
Kuwait is producing almost 3 million BOPD from less than 2,000 oil wells, especially as the major
field, Burgan, had first production 70 years ago.
I would note your chart ends in 2014. The average oil price in 2014 was about $95 WTI.
As Warren Buffet is fond of saying, it's only when the tide goes out that you find out who's
been swimming naked. It should be obvious to anyone that countries with static reserve numbers
are not being truthful. But there is a willingness among analysts and news providers to accept
the published numbers. What else can they do? They can't make up their own numbers or rely on
guesses from gadfly oil watchers. When production from these coutries starts going into steady
decline, the truth will be known.
Venezuela Orinoco Belt accounted for 68% of the increase in the world proved oil reserves
between 2005-14, according to BP's estimate. This is entirely due to higher oil prices. Interestingly,
according to BP's estimate, Canada' oil reserves actually declined in the past 10 years.
World proved oil reserves (billion barrels)
source: BP Statistical Review of World Energy 2015
"... So when you read about the Dallas Fed telling wildcatters with billions in outstanding high yield debt to hide their losses the implication of this is that the Fed has their back. It's choreography. Eduardo Quince , April 23, 2016 at 12:29 pm I think you give the Fed way too much credit. The Fed is a one-trick pony with tunnel vision, blind to the fact that it's policies are deflationary. So when you read about the Dallas Fed telling wildcatters with billions in outstanding high yield debt to hide their losses the implication of this is that the Fed has their back. No, I'd say that the implication is that the Fed is trying to maintain confidence in the Potemkin economy. ..."
The author blames the oil patch bust on a geophysical crisis. There is some truth to this argument
but by far the biggest driver of the bust is Fed policy. Artificially cheap debt financing led
to overcapacity and a vicious cycle of continued overproduction as drillers desperately try to
avoid defaulting.
There is method to central bank madness. It has been apparent for 40 years that we were on
a collision course with survival. Exxon knew it in the 70s. This article raises the question,
Will the end of fossil fuels take down the economy? The answer is no. Because the economy came
to a screeching halt in 2007 already. Everything since then is ersatz – not based on fossil fueled
capitalism at all. And as we can see it is working, albeit it to most people's frustration.
As Hillary said, "We are taking down coal and oil" and using natgas as a bridge fuel until
renewables replace natgas too. Is it possible that the Fed doesn't know this? What a funny thought.
So when you read about the Dallas Fed telling wildcatters with billions in outstanding high
yield debt to hide their losses the implication of this is that the Fed has their back. It's choreography.
I think you give the Fed way too much credit. The Fed is a one-trick pony with tunnel vision,
blind to the fact that it's policies are deflationary.
So when you read about the Dallas Fed telling wildcatters with billions in outstanding
high yield debt to hide their losses the implication of this is that the Fed has their back.
No, I'd say that the implication is that the Fed is trying to maintain confidence in the Potemkin
economy.
"... By Nafeez Ahmed,s an investigative journalist and international security
scholar. He writes the System Shift column for VICE's Motherboard, and is the winner
of a 2015 Project Censored Award for Outstanding Investigative Journalism for his
former work at the Guardian. He is the author of A User's Guide to the Crisis of
Civilization: And How to Save It (2010), and the scifi thriller novel Zero Point,
among other books. Originally published at AlterNet ..."
"... I'm not a huge Rolling Stones fan, but whenever I see a complex economic
analysis like this, I'm reminded of what Mick Jagger said when they asked him why
he dropped out of the London School of Economics: "There's too many variables."
..."
"... It's a lot more complicated even than that, it really depends on where
you draw the boundaries of the system. Prieto and Hall did an analysis of Spanish
solar that was probably the most comprehensive yet, including things like the truck
trips to lay the gravel for the surface roads, maintenance trips to clean the panels,
etc, and got a much lower EROEI figure than is typically given for solar. ..."
"... The carbon-energy situation needs to be placed in a context of the slow
burn debt deflation we are experiencing, which at a minimum is usually death for
the financial performance of commodities and any long term debt supported business.
NC has well documented the issues this poses for actuarial based investments (life
insurance, think Japan in the early '90s, pensions, etc.). ..."
"... Last thought, the debt situation is likely much worse in the short run
as the decline in oil revenues are likely already causing local and regional recessions
(e.g., Bakken, Houston) and correlated impact on commercial real estate, home values,
mortgages, etc. plus are we facing a sovereign debt crisis in such countries as
Venezuela (which used PDVSA to massively borrow on the countries behalf), Brazil,
Russia, etc. ..."
"... This short term glut will probably accentuate the coming problems because
it gives the impression that there is no peak oil. People have trouble understanding
that there are short-term cycles within a long-term cycle. This bad signal is giving
us the impetus to continue investing in energy intensive projects instead of reshaping
our economy. And this will make things even worse in 5-10 years. ..."
"... If the total cost of extraction is more than 40$ and consumers are paying
$40 or less, then somewhere along the way, someone is subsidizing the cost. It could
be low tax rates, eZ money, growing deficits, underfunded pensions, underfunded
restoration funds, etc. ..."
"... There is no glut. All the oil is being bought. The problem is that there
in not yet enough of a shortage to drive the price up. A small distinction but huge
ramifications if you understand it. And by the way higher prices is not a solution
to what ails us. ..."
"... The way I see it is that you have convinced yourself that you will be on
the winning side when calamity strikes. Whether you are is another matter… just
like the slowest bug does not get to the field on time to get exterminated by the
sprayed pesticides, work and efficiency do not guarantee anything. ..."
"... The author blames the oil patch bust on a geophysical crisis. There is
some truth to this argument but by far the biggest driver of the bust is Fed policy.
Artificially cheap debt financing led to overcapacity and a vicious cycle of continued
overproduction as drillers desperately try to avoid defaulting. ..."
Yves here. The strength and weakness of this article is the range of information
it covers. That comes at points at the expense of providing context. For instance,
it describes how 65% of the independent oil and gas companies are at risk of
going bankrupt. But it doesn't tell you how large the independents are relative
to the "majors". Similarly, it appears to switch two paragraphs later to the
total debt of oil and gas companies, which is $2.5 trillion. So one should read
this with some attention to definitions and context.
By Nafeez Ahmed,s an investigative journalist and international
security scholar. He writes the System Shift column for VICE's Motherboard,
and is the winner of a 2015 Project Censored Award for Outstanding Investigative
Journalism for his former work at the Guardian. He is the author of A User's
Guide to the Crisis of Civilization: And How to Save It (2010), and the scifi
thriller novel Zero Point, among other books. Originally published at
AlterNet
It's not looking good for the global fossil fuel industry. Although the world
remains heavily dependent on oil, coal and natural gas-which today supply around
80 percent of our primary energy needs-the industry is rapidly crumbling.
This is not merely a temporary blip, but a symptom of a deeper, long-term
process related to global capitalism's escalating overconsumption of planetary
resources and raw materials.
New scientific research shows that the growing crisis of profitability facing
fossil fuel industries is part of an inevitable period of transition to a post-carbon
era.
But ongoing denialism has led powerful vested interests to continue clinging
blindly to their faith in fossil fuels, with increasingly devastating and unpredictable
consequences for the environment.
Bankruptcy Epidemic
In February, the financial services firm Deloitte
predicted [3] that over 35 percent of independent oil companies worldwide
are likely to declare bankruptcy, potentially followed by a further 30 percent
next year-a total of 65 percent of oil firms around the world. Since early last
year, already 50 North American oil and gas producers have filed bankruptcy.
The cause of the crisis is the dramatic drop in oil prices-down by two-thirds
since 2014-which are so low that oil companies are finding it difficult to generate
enough revenue to cover the high costs of production, while also repaying their
loans.
Oil and gas companies most at risk are those with the largest debt burden.
And that burden is huge-as much as
$2.5 trillion [4] , according to The Economist. The real figure is probably
higher.
At a speech at the London School of Economics in February, Jaime Caruana
of the Bank for International Settlements
said [5] that outstanding loans and bonds for the oil and gas industry had
almost tripled between 2006 and 2014 to a total of $3 trillion.
This massive debt burden, he explained, has put the industry in a double-bind:
In order to service the debt, they are continuing to produce more oil for sale,
but that only contributes to lower market prices. Decreased oil revenues means
less capacity to repay the debt, thus increasing the likelihood of default.
Stranded Assets
This $3 trillion of debt is at risk because it was supposed to generate a
3-to-1 increase in value, but
instead [6] -thanks to the oil price decline-represents a value of less
than half of this.
Worse, according to a Goldman Sachs
study [7] quietly published in December last year, as much as $1 trillion
of investments in future oil projects around the world are unprofitable; i.e.,
effectively stranded.
Examining 400 of the world's largest new oil and gas fields (except U.S.
shale), the Goldman study found that $930 billion worth of projects (more than
two-thirds) are unprofitable at Brent crude prices below $70. (Prices are now
well below that.)
The collapse of these projects due to unprofitability would result in the
loss of oil and gas production equivalent to a colossal 8 percent of current
global demand. If that happens, suddenly or otherwise, it would wreck the global
economy.
The Goldman analysis was based purely on the internal dynamics of the industry.
A further issue is that internationally-recognized climate change risks mean
that to avert dangerous global warming, much of the world's remaining fossil
fuel resources cannot be burned.
All of this is leading investors to question the wisdom of their investments,
given fears that much of the assets that the oil, gas and coal industries use
to estimate their own worth could consist of resources that will never ultimately
be used.
The Carbon Tracker Initiative, which analyzes carbon investment risks, points
out that over the next decade, fossil fuel companies risk wasting up to $2.2
trillion of investments in new projects that could turn out to be "uneconomic"
in the face of international climate mitigation policies.
More and more fossil fuel industry shareholders are pressuring energy companies
to stop investing in exploration for fear that new projects could become worthless
due to climate risks.
"Clean technology and climate policy are already reducing fossil fuel demand,"
said James Leaton, head of research at Carbon Tracker. "Misreading these trends
will destroy shareholder value. Companies need to apply 2C stress tests to their
business models now."
In a prescient report published last November, Carbon Tracker identified
the energy majors with the greatest exposures-and thus facing the greatest risks-from
stranded assets: Royal Dutch Shell, Pemex, Exxon Mobil, Peabody Energy, Coal
India and Glencore.
At the time, the industry scoffed at such a bold pronouncement. Six months
after this report was released-a week ago-Peabody went bankrupt. Who's next?
The Carbon Tracker analysis may underestimate the extent of potential losses.
A new paper just out in the journal Applied Energy, from a team at Oxford University's
Institute for New Economic Thinking,
shows [8] that the "stranded assets" concept applies not just to unburnable
fossil fuel reserves, but also to a vast global carbon-intensive electricity
infrastructure, which could be rendered as defunct as the fossil fuels it burns
and supplies to market.
The Coming Debt Spiral
Some analysts believe the hidden trillion-dollar black hole at the heart
of the oil industry is set to trigger another global financial crisis, similar
in scale to the Dot-Com crash.
Jason Schenker, president and chief economist at Prestige Economics,
says [9] : "Oil prices simply aren't going to rise fast enough to keep oil
and energy companies from defaulting. Then there is a real contagion risk to
financial companies and from there to the rest of the economy."
Schenker has been ranked by Bloomberg News as one of the most accurate financial
forecasters in the world since 2010. The US economy, he forecasts, will dip
into recession at the end of 2016 or early 2017.
Mark Harrington, an oil industry consultant, goes further. He believes the
resulting economic crisis from cascading debt defaults in the industry could
make the 2007-8 financial crash look like a cakewalk. "Oil and gas companies
borrowed heavily when oil prices were soaring above $70 a barrel," he
wrote [6] on CNBC in January.
"But in the past 24 months, they've seen their values and cash flows erode
ferociously as oil prices plunge-and that's made it hard for some to pay back
that debt. This could lead to a massive credit crunch like the one we saw in
2008. With our economy just getting back on its feet from the global 2008 financial
crisis, timing could not be worse."
Ratings agency Standard & Poor (S&P) reported this week that 46 companies
have defaulted on their debt this year-the highest levels since the depths of
the financial crisis in 2009. The total quantity in defaults so far is $50 billion.
Half this year's defaults are from the oil and gas industry, according to
S&P, followed by the metals, mining and the steel sector. Among them was coal
giant Peabody Energy.
Despite public reassurances, bank exposure to these energy risks from unfunded
loan facilities remains high. Officially, only 2.5 percent of bank assets are
exposed to energy risks.
But it's probably worse. Confidential Wall Street sources
claim [10] that the Federal Reserve in Dallas has secretly advised major
U.S. banks in closed-door meetings to cover-up potential energy-related losses.
The Federal Reserve denies the allegations, but refuses to respond to Freedom
of Information requests on internal meetings, on the obviously false pretext
that it keeps no records of any of its meetings.
According to Bronka Rzepkoswki of the financial advisory firm Oxford Economics,
over a third of the entire U.S. high yield bond index is vulnerable to low oil
prices, increasing the risk of a tidal wave of corporate bankruptcies: "Conditions
that usually pave the way for mounting defaults-such as growing bad debt, tightening
monetary conditions, tightening of corporate credit standards and volatility
spikes – are currently met in the U.S."
The End of Cheap Oil
Behind the crisis of oil's profitability that threatens the entire global
economy is a geophysical crisis in the availability of cheap oil. Cheap here
does not refer simply to the market price of oil, but the total cost of production.
More specifically, it refers to the value of energy.
There is a precise scientific measure for this, virtually unknown in conventional
economic and financial circles, known as Energy Return on Investment-which essentially
quantifies the amount of energy extracted, compared to the inputs of energy
needed to conduct the extraction. The concept of EROI was first proposed and
developed by Professor Charles A. Hall of the Department of Environmental and
Forest Biology at the State University of New York. He found that an approximate
EROI value for any energy source could be calculated by dividing the quantity
of energy produced by the amount of energy inputted into the production process.
Therefore, the higher the EROI, the more energy that a particular source
and technology is capable of producing. The lower the EROI, the less energy
this source and technology is actually producing.
A new peer-reviewed
study [11] led by the Institute of Physics at the National Autonomous University
of Mexico has undertaken a comparative review of the EROI of all the major sources
of energy that currently underpin industrial civilization-namely oil, gas, coal,
and uranium.
Published in the journal Perspectives on Global Development and Technology,
the scientists note that the EROI for fossil fuels has inexorably declined over
a relatively short period of time: "Nowadays, the world average value EROI for
hydrocarbons in the world has gone from a value of 35 to a value of 15 between
1960 and 1980."
In other words, in just two decades, the total value of the energy being
produced via fossil fuel extraction has plummeted by more than half. And it
continues to decline.
This is because the more fossil fuel resources that we exploit, the more
we have used up those resources that are easiest and cheapest to extract. This
compels the industry to rely increasingly on resources that are more difficult
and expensive to get out of the ground, and bring to market.
The EROI for conventional oil, according to the Mexican scientists, is 18.
They estimate, optimistically, that: "World reserves could last for 35 or 45
years at current consumption rates." For gas, the EROI is 10, and world reserves
will last around "45 or 55 years." Nuclear's EROI is 6.5, and according to the
study authors, "The peak in world production of uranium will be reached by 2045."
The problem is that although we are not running out of oil, we are running
out of the cheapest, easiest to extract form of oil and gas. Increasingly, the
industry is making up for the shortfall by turning to unconventional forms of
oil and gas-but these have very little energy value from an EROI perspective.
The Mexico team examine the EROI values of these unconventional sources,
tar sands, shale oil, and shale gas: "The average value for EROI of tar sands
is four. Only ten percent of that amount is economically profitable with current
technology."
For shale oil and gas, the situation is even more dire: "The EROI varies
between 1.5 and 4, with an average value of 2.8. Shale oil is very similar to
the tar sands; being both oil sources of very low quality. The shale gas revolution
did not start because its exploitation was a very good idea; but because the
most attractive economic opportunities were previously exploited and exhausted."
In effect, the growing reliance on unconventional oil and gas has meant that,
overall, the costs and inputs into energy production to keep industrial civilization
moving are rising inexorably.
It's not that governments don't know. It's that decisions have already been
made to protect the vested interests that have effectively captured government
policymaking through lobbying, networking and donations.
Three years ago, the British government's Department for International Development
(DFID) commissioned and published an in-depth
report [12] , "EROI of Global Energy Resources: Status, Trends and Social
Implications." The report went completely unnoticed by the media.
Its findings are instructive: "We find the EROI for each major fossil fuel
resource (except coal) has declined substantially over the last century. Most
renewable and non-conventional energy alternatives have substantially lower
EROI values than conventional fossil fuels."
The decline in EROI has meant that an increasing amount of the energy we
extract is having to be diverted back into getting new energy out, leaving less
for other social investments.
This means that the global economic slowdown is directly related to the declining
resource quality of fossil fuels. The DFID report warns: "The declining EROI
of traditional fossil fuel energy sources and its eventual effect on the world
economy are likely to result in a myriad of unforeseen consequences."
Shortly after this report was released, I met with a senior civil servant
at DFID familiar with its findings, who spoke to me on condition of anonymity.
I asked him whether this important research had actually impacted policymaking
in the department.
"Unfortunately, no," he told me, shrugging. "Most of my colleagues, except
perhaps a handful, simply don't have a clue about these issues. And of course,
despite the report being circulated widely within the department, and shared
with other relevant government departments, there is little interest from ministers
who appear to be ideologically pre-committed to fracking."
Peak Oil
The driving force behind the accelerating decline in resource quality, hotly
denied in the industry, is 'peak oil.'
An extensive
scientific analysis [13] published in February in Wiley Interdisciplinary
Reviews: Energy & Environment lays bare the extent of industry denialism. Wiley
Interdisciplinary Reviews (WIRES) is a series of high-quality peer-reviewed
publications which runs authoritative reviews of the literature across relevant
academic disciplines.
The new WIRES paper is authored by Professor Michael Jefferson of the ESCP
Europe Business School, a former chief economist at oil major Royal Dutch/Shell
Group, where he spent nearly 20 years in various senior roles from Head of Planning
in Europe to Director of Oil Supply and Trading. He later became Deputy Secretary-General
of the World Energy Council, and is editor of the leading Elsevier science journal
Energy Policy.
In his new study, Jefferson examines a recent 1865-page "global energy assessment"
(GES) published by the International Institute of Applied Systems Analysis.
But he criticized the GES for essentially ducking the issue of 'peak oil."
"This was rather odd," he wrote. "First, because the evidence suggests that
the global production of conventional oil plateaued and may have begun to decline
from 2005."
He went on to explain that standard industry assessments of the size of global
conventional oil reserves have been dramatically inflated, noting how "the five
major Middle East oil exporters altered the basis of their definition of 'proved'
conventional oil reserves from a 90 percent probability down to a 50 percent
probability from 1984. The result has been an apparent (but not real) increase
in their 'proved' conventional oil reserves of some 435 billion barrels."
Added to those estimates are reserve figures from Venezuelan heavy oil and
Canadian tar sands, bringing up global reserve estimates by a further 440 billion
barrels, despite the fact that they are "more difficult and costly to extract"
and generally of "poorer quality" than conventional oil.
"Put bluntly, the standard claim that the world has proved conventional oil
reserves of nearly 1.7 trillion barrels is overstated by about 875 billion barrels.
Thus, despite the fall in crude oil prices from a new peak in June, 2014, after
that of July, 2008, the 'peak oil' issue remains with us."
Jefferson believes that a nominal economic recovery, combined with cutbacks
in production as the industry reacts to its internal crises, will eventually
put the current oil supply glut in reverse. This will pave the way for "further
major oil price rises" in years to come.
It's not entirely clear if this will happen. If the oil crisis hits the economy
hard, then the prolonged recession that results could dampen the rising demand
that everyone projects. If oil prices thus remain relatively depressed for longer
than expected, this could hemorrhage the industry beyond repair.
Eventually, the loss of production may allow prices to rise again. OPEC estimates
that investments in oil exploration and development are at their lowest level
in six years. As bankruptcies escalate, the accompanying drop in investments
will eventually lead world oil production to fall, even as global demand begins
to rise.
This could lead oil prices to climb much higher, as rocketing demand-projected
to grow 50 percent by 2035-hits the scarcity of production. Such a price spike,
ironically, would also be incredibly bad for the global economy, and as happened
with the 2007-8 financial crash, could feed into inflation and
trigger another spate [14] of consumer debt-defaults in the housing markets.
Even if that happens, the assumption-the hope-is that oil industry majors
will somehow survive the preceding cascade of debt-defaults. The other assumption,
is that demand for oil will rise.
But as new sources of renewable energy come online at a faster and faster
pace, as innovation in clean technologies accelerates, old fossil fuel-centric
projections of future rising demand for oil may need to be jettisoned.
Clean Energy
According to another
new study [15] released in March in Energy Policy by two scientists at Texas
A&M University, "Non-renewable energy"-that is "fossil fuels and nuclear power"-"are
projected to peak around mid-century … Subsequent declining non-renewable production
will require a rapid expansion in the renewable energy sources (RES) if either
population and/or economic growth is to continue."
The demise of the fossil fuel empire, the study forecasts, is inevitable.
Whichever model run the scientists used, the end output was the same: the almost
total displacement of fossil fuels by renewable energy sources by the end of
the century; and, as a result, the transformation and localisation of economic
activity.
But the paper adds that to avoid a rise in global average temperatures of
2C, which would tip climate change into the danger zone, 50 percent or more
of existing fossil fuel reserves must remain unused.
The imperative to transition away from fossil fuels is, therefore, both geophysical
and environmental. On the one hand, by mid-century, fossil fuels and nuclear
power will become obsolete as a viable source of energy due to their increasingly
high costs and low quality. On the other, even before then, to maintain what
scientists describe as a 'safe operating space' for human survival, we cannot
permit the planet to warm a further 2C without risking disastrous climate impacts.
Staying below 2C, the study finds, will require renewable energy to supply
more than 50 percent of total global energy by 2028, "a 37-fold increase in
the annual rate of supplying renewable energy in only 13 years."
While this appears to be a herculean task by any standard, the Texas A&M
scientists conclude that by century's end, the demise of fossil fuels is going
to happen anyway, with or without considerations over climate risks:
… the 'ambitious' end-of-century decarbonisation goals set by the G7
leaders will be achieved due to economic and geologic fossil fuel limitations
within even the unconstrained scenario in which little-to-no pro-active
commitment to decarbonise is required… Our model results indicate that,
with or without climate considerations, RES [renewable energy sources] will
comprise 87–94 percent of total energy demand by the end of the century.
But as renewables have a much lower EROI than fossil fuels, this will "quickly
reduce the share of net energy available for societal use." With less energy
available to societies, "it is speculated that there will have to be a reprioritization
of societal energetic needs"-in other words, a very different kind of economy
in which unlimited material growth underpinned by endless inputs of cheap fossil
fuel energy are a relic of the early 21st century.
The 37-fold annual rate of increase in the renewable energy supply seems
unachievable at first glance, but new data just released from the Abu Dhabi-based
International Renewable Energy Agency shows that clean power is well on its
way, despite lacking the massive subsidies behind fossil fuels.
The data reveals that last year, solar power capacity rose by 37 percent.
Wind power grew by 17 percent, geothermal by 5 percent and hydropower by 3 percent.
So far, the growth rate for solar power has been exponential. A Deloitte
Center for Energy Solutions
report [16] from September 2015 noted that the speed and spread of solar
energy had consistently outpaced conventional linear projections, and continues
to do so.
While the costs of solar power is consistently declining, solar power generation
has doubled every year for the last 20 years. With every doubling of solar infrastructure,
the production costs of solar photovoltaic (PV) has dropped by 22 percent.
At this rate, according to analysts like Tony Seba-a lecturer in business
entrepreneurship, disruption and clean energy at Stanford University-the growth
of solar is already on track to go global. With eight more doublings, that's
by 2030, solar power would be capable of supplying 100 percent of the world's
energy needs. And that's even without the right mix of government policies in
place to support renewables.
According to Deloitte, while Seba's forecast is endorsed by a minority of
experts, it remains a real possibility that should be taken seriously. But the
firm points out that obstacles remain:
"It would not make economic sense for utility planners to shutter thousands
of megawatts of existing generating capacity before the end of its economic
life and replace it with new solar generation."
Yet Deloitte's study did not account for the escalating crisis in profitability
already engulfing the fossil fuel industries, and the looming pressure of stranded
assets due to climate risks. As the uneconomic nature of fossil fuels becomes
evermore obvious, so too will the economic appeal of clean energy.
Race against time
The question is whether the transition to a post-carbon energy system-the
acceptance of the inevitable death of the oil economy-will occur fast enough
to avoid climate catastrophe.
Given that the 2C target for a safe climate is widely recognized to be inadequate-scientists
increasingly argue that even a 1C rise in global average temperatures would
be sufficient to trigger dangerous, irreversible changes to the earth's climate.
According to a 2011 report by the National Academy of Sciences, the scientific
consensus
shows [17] conservatively that for every degree of warming, we will see
the following impacts: 5-15 percent reductions in crop yields; 3-10 percent
increases in rainfall in some regions contributing to flooding; 5-10 percent
decreases in stream-flow in some river basins, including the Arkansas and the
Rio Grande, contributing to scarcity of potable water; 200-400 percent increases
in the area burned by wildfire in the US; 15 percent decreases in annual average
Arctic sea ice, with 25 percent decreases in the yearly minimum extent in September.
Even if all CO2 emissions stopped, the climate would continue to warm for
several more centuries. Over thousands of years, the National Academy warns,
this could unleash amplifying feedbacks leading to the disappearance of the
polar ice sheets and other dramatic changes. In the meantime, the risk of catastrophic
wild cards "such as the potential large-scale release of methane from deep-sea
sediments" or permafrost, is impossible to quantify.
In this context, even if the solar-driven clean energy revolution had every
success, we still need to remove carbon that has already accumulated in the
atmosphere, to return the climate to safety.
The idea of removing carbon from the atmosphere sounds technologically difficult
and insanely expensive. It's not. In reality, it is relatively simple and cheap.
A new book by Eric Toensmeier, a lecturer at Yale University's School of
Forestry and Environmental Studies, The Carbon Farming Solution, sets out in
stunningly accessible fashion how 'regenerative farming' provides the ultimate
carbon-sequestration solution.
Regenerative farming is a form of small-scale, localised, community-centred
organic agriculture which uses techniques that remove carbon from the atmosphere,
and sequester it in plant material or soil.
Using an array of land management and conservation practices, many of which
have been tried and tested by indigenous communities, it's theoretically possible
to scale up regenerative farming methods in a way that dramatically offsets
global carbon emissions.
Toensmeier's valuable book discusses these techniques, and unlike other science-minded
tomes, offers a practical toolkit for communities to begin exploring how they
can adopt regenerative farming practices for themselves.
According to the
Rodale Institute [18] , the application of regenerative farming on a global
scale could have revolutionary results:
Simply put, recent data from farming systems and pasture trials around
the globe show that we could sequester more than 100 percent of current
annual CO2 emissions with a switch to widely available and inexpensive organic
management practices, which we term 'regenerative organic agriculture'…
These practices work to maximize carbon fixation while minimizing the loss
of that carbon once returned to the soil, reversing the greenhouse effect.
This has been widely corroborated. For instance, a 2015
study [19] part-funded by the Chinese Academy of Sciences found that "replacing
chemical fertilizer with organic manure significantly decreased the emission
of GHGs [greenhouse gases]. Yields of wheat and corn also increased as the soil
fertility was improved by the application of cattle manure. Totally replacing
chemical fertilizer with organic manure decreased GHG emissions, which reversed
the agriculture ecosystem from a carbon source… to a carbon sink."
Governments are catching on, if slowly. At the Paris climate talks, 25 countries
and over 50 NGOs signed up to the French government's '4 per 1000' initiative,
a
global agreement [20] to promote regenerative farming as a solution for
food security and climate disaster.
The Birth of Post-Capitalism
There can be no doubt, then, that by the end of this century, life as we
know it on planet earth will be very different. Fossil fueled predatory capitalism
will be dead. In its place, human civilization will have little choice but to
rely on a diversity of clean, renewable energy sources.
Whatever choices we make this century, the coming generations in the post-carbon
future will have to deal with the realities of an overall warmer, and therefore
more unpredictable, climate. Even if regenerative processes are in place to
draw-down carbon from the atmosphere, this takes time-and in the process, some
of the damage climate change will wreak on our oceans, our forests, our waterways,
our coasts, and our soils will be irreversible.
It could take centuries, if not millennia, for the planet to reach a new,
stable equilibrium.
But either way, the work of repairing and mitigating at least some of the
damage done will be the task of our childrens' children, and their children,
and on.
Economic activity in this global society will of necessity be very different
to the endless growth juggernaut we have experienced since the industrial revolution.
In this post-carbon future, material production and consumption, and technological
innovation, will only be sustainable through a participatory 'circular economy'
in which scarce minerals and raw materials are carefully managed.
The fast-paced consumerism that we take for granted today simply won't work
in these circumstances.
Large top-down national and transnational structures will begin to become
obsolete due to the large costs of maintenance, the unsustainability of the
energy inputs needed for their survival, and the shift in power to new decentralized
producers of energy and food.
In the place of such top-down structures, smaller-scale, networked forms
of political, social and economic organization, connected through revolutionary
information technologies, will be most likely to succeed. For communities to
not just survive, but thrive, they will need to work together, sharing technology,
expertise and knowledge on the basis of a new culture of human parity and cooperation.
Of course, before we get to this point, there will be upheaval. Today's fossil
fuel incumbency remains in denial, and is unlikely to accept the reality of
its inevitable demise until it really does drop dead.
The escalation of resource wars, domestic unrest, xenophobia, state-militarism,
and corporate totalitarianism is to be expected. These are the death throes
of a system that has run its course.
The outcomes of the struggles which emerge in coming decades-struggles between
people and power, but also futile geopolitical struggles within the old centers
of power (paralleled by misguided struggles between peoples)-is yet to be written.
Eager to cling to the last vestiges of existence, the old centers of power
will still try to self-maximize within the framework of the old paradigm, at
the expense of competing power-centers, and even their own populations.
And they will deflect from the root causes of the problem as much as possible,
by encouraging their constituents to blame other power-centers, or worse, some
of their fellow citizens, along the lines of all manner of 'Otherizing' constructs,
race, ethnicity, nationality, color, religion and even class.
Have no doubt. In coming decades, we will watch the old paradigm cannibalize
itself to death on our TV screens, tablets and cell phones. Many of us will
do more than watch. We will be participant observers, victims or perpetrators,
or both at once.
The only question that counts, is as follows: amidst this unfolding maelstrom,
are we going to join with others to plant the seeds of viable post-carbon societies
for the next generations of human-beings, or are we going to stand in the way
of that viable future by giving ourselves entirely to defending our 'interests'
in the framework of the old paradigm?
Whatever happens over coming decades, it will be the choices each of us make
that will ultimately determine the nature of what survives by the end of this
pivotal, transitional century.
And one such solution is at hand. People. Too many people to subsist
in a crazed-fossil-fueled capitalists world means there will be changes.
If the MIT professor is correct and the solution is decentralized regenerative
farming, aka organic farming on a vast scope, then we've certainly got the
people power to do it. It's always good to hear that China understands these
things. I'm sure India does too.
Thanks, Yves, for posting this information rich and pertinent article.
Your curation is impeccable.
The cited documents are lengthy and I intend to read further. At a glance,
I was surprised to learn that, despite years of Peak Oil investigations:
1) EROI is virtually unknown in conventional economic and financial circles.
2) Lack of institutional awareness and disinterest at DFID is widespread,
such that research isn't influencing policy. The essence of irony!
3) Experts remain focused on comparitively high energy solutions (such as
underground carbon capture technologies) over low energy biological solutions
(such as carbon sequestration by soil organisms, trees and plants).
I'm heartened, though, to see some regenerative farming citations. Eric
Toensmeier and the Rodale Institute are wonderful. Bill Mollison, David
Holmgren, Brad Lancaster, Geoff Lawton and Darren J. Doherty are also excellent
resources. BTW, the 60999 EROI Global Energy Resources pdf cites a Lambert,
et al 2013. Is that THE Lambert?
A broader understanding of energy is and will remain critical in a post-capitalism,
post-carbon future. Currently, work is neglected because "it doesn't pay"
to do it. That is a tragic squandering of available resources. By any meaningful
metric, it pays to liberate latent energy to do the work of restoring the
environment.
There was a lively discussion this week about community building. I'm
happy to spend my days installing earthworks, natural building, growing
yummy stuff…
Thx for highlighting the regenerative agriculture references. An important
resource I'd add to the list regarding regenerative agriculture and large
scale carbon sink benefits is the
Savory Institute . Their
website is constantly adding links to recent research.
I'm not a huge Rolling Stones fan, but whenever I see a complex economic
analysis like this, I'm reminded of what Mick Jagger said when they asked
him why he dropped out of the London School of Economics: "There's too many
variables."
Fascinating article. One niggling question about EROI. I get how it's
relatively easy to calculate the EROI of a barrel of oil - the barrel holds
a specific number of gallons and each gallon is capable of producing X amount
of energy. But what about renewables? You know the production cost of a
wind turbine, for instance, but the energy it produces over its lifetime
is much more open-ended. So the Energy Return for it must be the total expected
energy returned over the turbine's projected service life, right? If so,
the longer it lasts, the higher it's EROI.
It's a lot more complicated even than that, it really depends on
where you draw the boundaries of the system. Prieto and Hall did an analysis
of Spanish solar that was probably the most comprehensive yet, including
things like the truck trips to lay the gravel for the surface roads, maintenance
trips to clean the panels, etc, and got a much lower EROEI figure than is
typically given for solar. As far as wind goes, turbines tend to fail
at a higher frequency than manufacturers estimate (go figure) so the best
way to measure things like turbine lifespan is to look at those in the field.
The article is generally correct that renewable EROEI tends to be lower
than that of fossil fuels, although it seems not to contemplate that there
is a lower bound on EROEI beyond which these systems can't/won't be sustained
anyway. It's not just that less energy is available for non-energy production
use but that there is an EROEI return below which you probably can't operate
the infrastructure necessary to mine/smelt materials for renewables on the
scale being contemplated here (total replacement of FF-burning infrastructure)
It's best to think of these as order-of-magnitude comparisons with each
other. Local conditions provide huge variability on energy generated by
renewables. Likewise fossil fuel extraction.
I've invested in LED lighting for a long time. Output per unit increases
by a rule-of-thumb called Haitz's law, about a factor of 20 per decade.
Many bulbs tout a lifetime of 20 years, but haven't been around that long,
so that's an extrapolation, and I have the dead bulbs to prove the point.
So when someone talks about LED efficiency, it's not a static number, but
it's still useful for discussion.
A factor that I believe is missing from EROI is cost of clean up or,
lacking clean up, the cost of consequences, which should be determined taking
into account the negative effects of our propensity for corruption, personal
gain at the expense of the whole, (which is why nuclear should have a stratosphericly
high cost, for ex.). For oil, coal and uranium, this is a high cost that
should be subtracted from EROI. For solar and wind, the cost is
much less, except possibly in the manufacture of components that convert
sun/wind into electricity. Life span is supposed to be around 30 years so
the clean up/consequence cost of manufacture should be divided by that number.
I am quite a bit disappointed with this "article". First off, we have
to acknowledge that other than meteorologists (and yes demographics) we
have we skill at forecasting the future. So to me this article reads as
though it started from a future condition than constructed a series of facts
and thesis that get you there. The reality is we don't know and one may
as well flip a coin.
That said, there is clearly right now much to be concerned about. Humans
seem to be internally wired to be short-term based. "Tell me where my next
meal is coming from is all I care about". So, tackling issues like climate
change is not something we're good at; and there is no historic precedent
I can think of for all of mankind collaborating to solve a problem.
The carbon-energy situation needs to be placed in a context of the
slow burn debt deflation we are experiencing, which at a minimum is usually
death for the financial performance of commodities and any long term debt
supported business. NC has well documented the issues this poses for actuarial
based investments (life insurance, think Japan in the early '90s, pensions,
etc.).
Last thought, the debt situation is likely much worse in the short
run as the decline in oil revenues are likely already causing local and
regional recessions (e.g., Bakken, Houston) and correlated impact on commercial
real estate, home values, mortgages, etc. plus are we facing a sovereign
debt crisis in such countries as Venezuela (which used PDVSA to massively
borrow on the countries behalf), Brazil, Russia, etc.
This short term glut will probably accentuate the coming problems
because it gives the impression that there is no peak oil. People have trouble
understanding that there are short-term cycles within a long-term cycle.
This bad signal is giving us the impetus to continue investing in energy
intensive projects instead of reshaping our economy. And this will make
things even worse in 5-10 years.
If the total cost of extraction is more than 40$ and consumers are
paying $40 or less, then somewhere along the way, someone is subsidizing
the cost. It could be low tax rates, eZ money, growing deficits, underfunded
pensions, underfunded restoration funds, etc.
A country's most important asset is energy and historically, countries
have never willingly cut total energy consumption. They might increase efficiencies
but the total does not drop. This means that most countries, as long as
there exist other sectors that can be squeezed, will continue to subsidize
the energy sector squeezing out these sectors that are deemed less important
or simply those with less clout.
It is quite obvious that our lives are even more energy dependent than
they were when this monetary cycle started in the early 70s. And our system
is still based on growing this even more. With NIRP, we are getting very
close to the end of this cycle.
There is no glut. All the oil is being bought. The problem is that
there in not yet enough of a shortage to drive the price up. A small distinction
but huge ramifications if you understand it. And by the way higher prices
is not a solution to what ails us.
A few thoughts:
-time scale – this thing we are in will roll on for thousands of years –
the K-T mass extinction took 2-3 million years before species started to
increase again;
-They (we) will keep the oil flowing as long as they can – look how ugly
the coal industry's slow death is getting – until climate events are overwhelming
and require extraordinary efforts just to mitigate. My money's on sea level
rise focusing all attention;
-billions of humans will die – many in climate change-triggered wars
and famines – the Four Horsemen are saddling up;
-like it or not, people in the developed world, less densely populated
parts, anyway (USA, Canada, e.g.) once they are over the necessities like
lower standards of living (no more trinkets and geegaws ) and hard physical
labor in sustainable agriculture, are way better off than over-populated
places. However, it will get ugly at the borders, as Europe is experiencing
right now.
-expect more authoritarian governments – the human response to crisis.
Tribalism will rule.
-and the doom-and-gloomers can fuck off they are useless, unable to adapt
or evolve, and are just scaring the stupid unnecessarily. The living planet
will adapt and evolve as it has always done – and humans in some form or
other also. DO you really think the most adaptable species, inhabiting every
biome, will not?
No my strategy is hard work. Respectful of the planet's living processes.
And honesty.
Most doomers are at an early stage of consciousness of the magnitude
of our society's death spiral. My aim is to shake them out of their (totally
understandable) depression – work is the cure. COllective efforts on a large
scale but managed locally – resilient ecology requires complexity – monocultures
are doomed.
The way I see it is that you have convinced yourself that you will
be on the winning side when calamity strikes. Whether you are is another
matter… just like the slowest bug does not get to the field on time to get
exterminated by the sprayed pesticides, work and efficiency do not guarantee
anything.
The doomers are those who are not convinced they will be spared. Maybe
they can place themselves in the winning group with positive thinking and
hard work, but maybe not so in such a case they need help deluding themselves
so they can become perma-optimists.
Well I'm glad you have that insight into my thinking! Not!
I see it rather that my own death is inevitable, and that of my lineage
and tribe as having a probability of greater than 0. Luck (divine providence?)
counts for a lot, as you note.
Deluded optimists can be organized to do useful work. Better than idle
pessimists.
I utterly reject the "winning side" as a useful concept – there is only
living struggle through the generations.
I have to wonder, if it is really so easy to clean up the carbon and
other toxins we have polluted the atmosphere and oceans with, then why bother
to stop producing oil, coal and nuclear other than that they come to be
less economical?
i strongly doubt the projected ease of such a clean up whether it be
the biological feasibility or the willingness of humans to work together
for common goals – extinction seem to be almost an afterthought – (or conversely,
the more realistic "Hillary" element in people to work feverishly for personal
gain at the expense of others). Going from coal to sunlight is easy. Going
from Clinton to Sanders, not so much.
Well President Trump will make the thing go faster and expose the failings
of fossil-fueled society as he has the corruption of our fundamentally racist
nation. By being the bad thing.
All major cultures are in terminal decline, which should be expected,
and is not to say that they will not be replaced or that some will not recover,
which is neither good nor bad.
The geneticists and psychologists are snakeoil salesmen. All the geneticists
have proven is that you have the same basic gene set as a worm, making up
about 2% of your DNA. They haven't begun to decipher the 98% if then feedback
code. Science tells you that the last thing you want to do is inject everyone
with the same mitochondrial DNA, but medicine isn't about science; its about
printing money on fear.
What the psychologists learned is that an irrational majority can be
conditioned to do whatever you want. Ironically, in America you are an unfit
parent if you have a scientific mind or believe in others, as a Christian,
leaving the majority, which lives in fear, to raise children, which doesn't
bode well except for the morons running the show, for now.
Projecting the future on biased data is a waste of time, the status quo.
Too funny, critters who have never developed seed debating corporate versus
yuppie farming techniques.
Medicine will never understand synaptic response, immunological adaptation,
intercellular signalling or blood clotting / mRNA feedback, because it is
not paid to do so. You are nature's test tube, and the majority fears the
unknown, as conditioned by the cave people running public education.
As a carbon based life form, it is in your interest to learn how that
carbon chain is popped on and off the stack to maintain event horizons.
That last line is too funny, but I agree with you.
Getting out there and doing something now that we understand what is
going on is probably a better use of our time than trying to protect the
current economic structure. Build a new energy paradigm that better fits
our ecosystem and see what kind of economic, social, and political structures
begin to develop around that.
Surely, whatever develops will model what has come before it but it needs
to be rooted in the physical environment, which clearly it is not currently.
The author blames the oil patch bust on a geophysical crisis. There
is some truth to this argument but by far the biggest driver of the bust
is Fed policy. Artificially cheap debt financing led to overcapacity and
a vicious cycle of continued overproduction as drillers desperately try
to avoid defaulting.
"... Jean Laherrere's graph confirms that inflection point happened around 1980, roughly 20 years after the peak in discoveries. This puts a 40 year lag between the peak in discoveries and the peak in production, the latter being scheduled for about the year 2000. ..."
"... We are now at the peak of that much broader and flatter curve (which has been frequently mis-characterized as an "undulating plateau") with conventional global annual production well below 40 Gb and looking very much like it is finally on its way down. This despite the giant pump and dump scheme otherwise known as the "shale revolution". ..."
Jean Laherrere's graph is particularly interesting.
Anyone familiar with Hubbert's full statistical analysis knows that the peak of proved reserves
roughly corresponds to the same point in time when the production curve crosses the discovery
curve (also backdated), which is roughly the halfway point between the peaks of the discovery
and production curves.
Jean Laherrere's graph confirms that inflection point happened around 1980, roughly 20 years
after the peak in discoveries. This puts a 40 year lag between the peak in discoveries and the
peak in production, the latter being scheduled for about the year 2000.
All of which is perfectly consistent with Hubbert's 1972 Congressional analysis of global discoveries
and production which he put at about 2 trillion bbl URR and a production peak of about 40 Gb per
year in 1995 or thereabouts.
What happened, you may ask, to the production peak? The years 1995 and 2000 have come and gone.
Simple, the global geopolitics of oil. The Arab oil embargo and Iranian revolution of the 70's
but a huge crimp in the global production curve and pushed a significant portion of the area under
the curve into the future by a decade or two.
In Jean Laherrere's world discoveries and production graph above you can clearly see the inflection
point in 1980, before which the world was clearly on the "ideal" Hubbert curve that would have
reached 40 Gb per year in 2000. After 1980 the reality of the geopolitics of oil and energy set
in and constrained global production which visibly flattened out the curve.
Something which Hubbert himself fully acknowledged could happen, both in his analysis and in
subsequent interviews.
We are now at the peak of that much broader and flatter curve (which has been frequently mis-characterized
as an "undulating plateau") with conventional global annual production well below 40 Gb and looking
very much like it is finally on its way down. This despite the giant pump and dump scheme otherwise
known as the "shale revolution".
"... The increase of 4 has not been paid for yet. America has its entire energy future invested in the worse rock imaginable; shale decline rate is horrific and it costs upwards (CLR and Concho) of 90 dollars a barrel to find it. It is unprofitable to produce at anything less than about 60 dollars a barrel. If anyone thinks unconventional shale resources can ultimately go to 20 MBOPD, and another 65,000 shale wells drilled… cut the BS and tell us how it's going to get paid for. ..."
"... Because the shale industry cannot stand on it's own two feet. It is totally reliant on credit. To all of you oil analysts out there so intent on predicting the future, stop ignoring the reality of unprofitability and debt that can never be paid back. Who is going to PAY for the shale oil abundance miracle? ..."
"... With Globalization enabling nothing but poverty for everyone except for the 1%ers, the jobless "consumer" cannot afford anything so your question is silly. ..."
"... The answer: The Fed. So you don't pay it back? As long as people get food shipped, who would declare it a failure? ..."
"... So we would need to multiply by how many factors the number of rigs and fracking crews to get the USA to 20 million barrels per day? I suppose we need $300 WTI sustained for that to occur? ..."
"... He has at least admitted they don't have 2 mmbpd spare capacity immediately available, contrary to usually quoted figures. With enough money and stupidity you could get 20 mmbpd out of a 20 million barrel reservoir, but next day there would be a lot of expensive scrap metal around. To add enough to get there for Saudi would cost all of their remaining wealth fund as of today (and which only has three years left at current draw rate anyway). ..."
I can't believe I agree with you. If the USA can go from 5 million to 9 million in less than 5
years. I wouldn't be surprised if 20 mbd with time and investmentime was possible.
The increase of 4 has not been paid for yet. America has its entire energy future invested
in the worse rock imaginable; shale decline rate is horrific and it costs upwards (CLR and Concho)
of 90 dollars a barrel to find it. It is unprofitable to produce at anything less than about 60
dollars a barrel. If anyone thinks unconventional shale resources can ultimately go to 20 MBOPD,
and another 65,000 shale wells drilled… cut the BS and tell us how it's going to get paid for.
Because the shale industry cannot stand on it's own two feet. It is totally reliant on
credit. To all of you oil analysts out there so intent on predicting the future, stop ignoring
the reality of unprofitability and debt that can never be paid back. Who is going to PAY for the
shale oil abundance miracle?
With Globalization enabling nothing but poverty for everyone except for the 1%ers, the jobless
"consumer" cannot afford anything so your question is silly.
In the short run the fed can play money games. When the laws of physics show up, they are in
trouble. I agree that desperation would lead to money printing from a bunch of clueless apes (humans).
I won't be lending my pitiful money at 1% interest if peak oil strikes. If that basic commonsense
idea is accurate, than where is the capital to run the economy going to come from???
So we would need to multiply by how many factors the number of rigs and fracking crews
to get the USA to 20 million barrels per day? I suppose we need $300 WTI sustained for that
to occur?
It took close to $100 sustained from 2007 to 2014, with a financial crisis and $100+ drop
in the price, followed by a remarkably quick run up, to get USA from 5 million to 9.7 million.
I figure $300 sustained for 8-10 years could get us to 15-17 million, for a short time. Drill
the heck out of everything, everywhere. LOL!! Please note, I am not serious. Just trying to
get real on this 20 million bopd idea.
He has at least admitted they don't have 2 mmbpd spare capacity immediately available,
contrary to usually quoted figures. With enough money and stupidity you could get 20 mmbpd
out of a 20 million barrel reservoir, but next day there would be a lot of expensive scrap
metal around. To add enough to get there for Saudi would cost all of their remaining wealth
fund as of today (and which only has three years left at current draw rate anyway).
Dennis, I did not read the referenced link; I thought the discussion was relative to the BP
bunk. My apologies. That the KSA could increase its daily production to 20 MBOPD is almost
as absurd as the US LTO industry finding some place to drill another 65,000 shale wells. We
just had over 31,000 shale wells drilled in the US and the LTO industry has not made a dime
of profit yet.
I agree KSA will never get to 20 Mb/d, but it is more likely than the US ever getting to
that level.
On the shale wells, the NDIC has forecast between 40,000 and 55,000 shale wells in the North
Dakota Bakken/Three Forks, lets be conservative and say it will be 35k, there have been 11,000
wells drilled already so that gives us 24,000 wells, if we assume another 19,000 wells in the
Eagle Ford (30,000 total) and 19,000 in the Permian basin, that is about 62,000 wells in the
big 3 plays. I agree that sounds like too many, it may be only half that number. Most of the
30k wells have been drilled over a 5 year period at roughly 6000 wells per year.
So 5 more years at that rate (when oil prices are over $90/b) gets us to 30k wells and 10 years
to 60 k. I think the real number will be somewhere between 30k and 60k and will depend on all
the factors you list, if demand is low and supply high it will be closer to 30k due to low
oil prices and if the reverse is true it will be closer to 60k.
What is your guess for future LTO wells completed, as I assume you don't expect that there
will be no more LTO wells completed (we have an LTO DUC count of 3000 to 4000, so I would think
this would be the minimum)?
At higher oil prices the debt can be paid back. If oil prices remain low forever, there
will be defaults. If the assumption by me and many others that oil prices will rise is incorrect,
there will not be 50,000 more wells drilled in the Bakken and Eagle Ford.
Looking at Rune Likvern's work, it seems cash flow was positive just before the crash in
oil prices. Since that time well costs have fallen, so perhaps $90/b will be enough to make
the LTO plays profitable (so that the annual rate of return is 10% or higher). Higher rates
would be better, if oil supply is short oil prices may be north of $115/b. In that case the
economics will work and we will see 50,000 more stinking shale wells in the Bakken and Eagle
Ford (and maybe another 30,000 combined in other plays such as the Permian and Niobrara).
It all depends on oil prices, and nobody knows what they will be.
It is possible the debt will not be paid back. If that is the case, I would expect interest
rates for shale drilling will rise or it will not be available.
Let us assume that by 2018 that peak oil has arrived (if it has not already), under those
conditions oil prices will rise to $120/b or more. The cash flow for the average LTO well gets
pretty high at those oil prices, perhaps the oil companies that are still operating will be
a little smarter about how fast they accumulate debt in the next boom phase.
You do think there will be a peak, I assume.
What do you think will happen to oil prices?
You may assume there would be an immediate recession, but from 2011 to 2014 we had high
oil prices with slow World growth (2 to 3% per year in constant dollars).
A combination of slow supply growth (or a plateau in output) with reduced demand through
better fuel efficiency might keep prices from rising to a point that causes a recession, at
least for a couple of years. Eventually output will start to fall and the economy will not
be able to adjust and there will be an economic crisis.
My WAG is that this arrives between 2025 and 2030.
DC Wrote:
"Let us assume that by 2018 that peak oil has arrived (if it has not already), under those
conditions oil prices will rise to $120/b or more."
Its extremely unlikely that the world could support sustained prices above $100. From roughly
2005 to 2008 (Western economic debt bubble) and from roughly 2010 to 2015 (Asian/BRIC debt
bubble) it could temporarily support higher energy prices. During both periods credit became
very cheap and available.
At this point both the East and West are saturated in debt and deflation is the dominate
economic factor in the global economy. The cheap and easy credit days are gone for at least
a generation.
Perhaps at some point the world's central banks will collaborate, or currency war, to induce
a global currency devaluation (race to the bottom) that results in a commodity price rebound.
Short of a global wide currency devaluation, its unlikely that Oil will bounce anywhere near
$120/bbl because of deflationary forces. Even if Oil does breach $120/bbl I doubt it would
trigger another drilling boom, since the costs for everything else will also be very expensive:
very high interest rates for most borrowers, expensive materials (ie steel, pipe). High energy
prices will also lead to demand destruction. Consider that QE and currency devaluation almost
always results in wage reductions (adjusted for inflation). The QE in the US/EU, never trickled
down to the working class. All we ended up is asset & commodity price inflation.
I also think global demand for oil will decline, due to a combination of demographics (boomers
retiring), declining wages (wages & worker hours per employer are falling), and much more automation
(leading to the elimination of jobs). Most of the replacement jobs after 2009 have been part-time
and are low-wage service jobs. There is already an over capacity of factories, housing, etc,
leading to less construction demand for perhaps a generation or more.
My guess is that Oil prices will likely be very unstable, with dramatic swings been high
prices and very low prices. In this environment, Drillers are unlikely to make any long term
investments, as they fear the bottom could fall out at any time.
Possibly demand will fall faster than supply, but I doubt it.
Why do interest rates rise in your scenario.
In a deflationary scenario with lower aggregate demand, not a lot of demand for liquidity.
So basic theory suggests low interest rates will continue in the scenario you present.
DC asked:
"Why do interest rates rise in your scenario"
Gov't bonds will never rise except for small weak nations (ie Brazil) or nations that can't
borrow in their own currencies. I think Interest rates on US bonds, Japan and a select few
EU nations will remain low to negative for quite some time.
On the flip side, I expect borrowing cost for weak nations such as Brazil and other So.
American nations, EU PIGS (portugal, Spain, etc) to rise.
Borrowing costs for consumers will rise as the the risk of defaults increase, even in the
EU and the US. (ie the default premium). More and more business and consumers will be downgraded
to subprime borrowers forcing them to pay for much higher rates if they choose to borrow.
DC wrote:
"Possibly demand will fall faster than supply, but I doubt it."
I suspect demand will become volatile, swinging between a tight market (rising prices) and
demand destruction. To unstable for driller to make long term investments. The Oil production
will likely adjust to falling demand.
Supply is unlikely to ever outpace demand, except for short periods during periods of economic
contraction (ie the economy falls faster than the Oil market can adjust).
Dennis, the future of shale oil development does not simply depend on oil prices. It will depend
on hydrocarbon demand, the role the KSA will have in the future in manipulating oil prices
to keep the US shale industry on the floor and not let it back up, it will depend on rising
extraction costs, public sentiment, politics (anti-frac'ing, climate change, fresh water usage),
the availability of financing and what the new costs will be for that financing. And finally
it will depend on Mother Nature says about it all. Do not confuse technically recoverable with
recoverable; it is naive of you are anybody else to assume that all unconventional resource
plays are one big homogenous ATM machine.
Jeffrey Brown and I once decided that fewer than 35% of LTO wells in the US would ever pay
back drilling and completion costs. After reviewing Enno's 114,000 average BO per shale oil
well drilled since 2007, I think we were being far too optimistic. Shallow is correct, most
of the outstanding debt now owned by the shale oil industry will never be paid back.
Making predictions based on the "hope" crude oil prices will rise, and stay high, is a mistake.
If you need an example of that, we're in the middle of it.
Adios from S. Texas where the Eagle Ford shale play is in hospice care now. Watch what happens
to rig counts, and production, the next 8 weeks and don't get caught standing behind it. It
will suck you plumb off your feet.
As I said if oil prices remain low forever, you will be correct.
I wouldn't bet on that. Let's say oil prices remain at $60/b or less forever as shallow
sand hopes for.
Do you think there will be adequate oil supply at that price?
I have serious doubts that oil supply will meet demand in 2020 if oil prices remain $60/b
or less from 2016 to 2020.
There certainly won't be a lot of LTO wells drilled at those prices, probably about 2400
wells per year in Bakken, Eagle Ford and Permian combined or roughly 10,000 wells over that
4 year period.
It will be interesting to see what happens, maybe oil demand growth will be more modest
than the EIA and IEA believe and supply will be more resilient.
No not 2400 in the Bakken, that is the total for all three plays and is an assumed average
over a 4 year period if oil prices average $60/b, is too optimistic. I was thinking 60 wells
per month in the Bakken and 70 wells per month in both the Eagle Ford and Permian basin, for
200 wells per month for all 3 plays.
720 wells per year is too high, thank you for pointing out this error.
If we maintain a rig count of 25 rigs and get 1.3 wells drilled per rig each month, that
would be 32 wells per month, if we take the SPUC count of 1000 and divide by 48 months we would
have 20 wells per month, probably 10 per month would be more reasonable as this count may not
approach zero, so maybe 42 wells per month or 500 wells completed per year is more reasonable.
1500 wells completed per year for all of the US LTO sector at oil prices of $60/b or less
would be my minimum guess and 2400 wells completed per year for all of the US is not realistic.
Looking at your recent post it seems 35 to 45 wells per month can be financed, if we call
it 40, that would be only 480 new wells per year so 1500 wells for the total US LTO sector
might be reasonable (or at least closer to a reasonable number).
Thanks for your insight.
The $60/b was WTI, I think this was shallow sand's number and the 720 wells was the number
completed only (some of these would be wells that had already been drilled but had not yet
been completed.
Dennis. I hope I didn't say forever. I think I said a long time. I'll clarify a long time by
it being 2-3 years.
And I didn't mean less. A $55-65 WTI price range would be just fine for 2016, 2017 and 2018.
Maybe longer if costs do not increase substantially.
A $55-65 WTI price band puts Bakken oil around $50 for an average? So if an average well,
net of royalties, generates 120K barrels of oil in 3 years, that is just $6 million of revenue,
not to mention the taxes, LOE, G & A, transport and interest expense.
So, I'm with Rune. Who would be loaning on that, especially to companies already several
billion in debt?
No you did not say forever, you didn't say how long. The average Bakken/Three forks well
has cumulative output of 152 kbo in 3 years (2008-2013 average well), so that is 7.6 million
in revenue just from the oil.
Now let's say I have some DUCs which will cost 5 million for completion. I get 100 kbo in
the first year, maybe I complete the DUCs to keep the lights on, as I have already spent 2.7
million to drill the well and its not helping me at all to leave it uncompleted. I would think
those that are cash strapped would stop drilling and focus on their DUCs, Enno estimates there
are 1000 wells that have been spud but not completed, at 500 per year that would be two years
worth of wells (if the SPUC count can ever go to zero). Also lease costs have been spent and
G+A will not change much by completing another well, the question is will the company have
more money by completing these SPUCs or not. If they will have less money, they should leave
the well as is (as a DUC).
For some reason wells continue to be completed, so perhaps these businesses think it is
in their interest to do so. Or there is some other explanation I have not heard.
"No you did not say forever, you didn't say how long. The average Bakken/Three forks well
has cumulative output of 152 kbo in 3 years (2008-2013 average well), so that is 7.6 million
in revenue just from the oil."
Is 152 kbo gross extracted?
Is the $7.6 M based on $50/bo gross at the wellhead?
Dennis, I said net of royalty, so I was off by less than you note.
156 x .80 NRI (assumed) is 124.8K barrels.
So $6.248 million.
However there would also likely be another $200-300K of natural gas revenue?
I would say wells continue to "keep the lights on". If all wells stop, frack companies shutter
their offices. If all wells stop, company exploration personnel are laid off. If there is absolutely
any money to keep doing something, these last few companies are going to do it, even if it
is a money loser. I assume shutting down the in house exploration unit in the Bakken results
in a much larger writedown than losing on a few wells? Add to that none of the companies can
believe this is a permanent situation, $30 oil or lower, so they are going to keep doing the
minimum in hopes for a rebound.
The problem, of course, is the rebound needs to be more than $55-$65 WTI for the business
model to be valid, as Mike, Rune and I (and many others) have argued for quite awhile.
Sorry, I missed "the net of royalties", which I guess is 20%, so yes 122 net barrels, if
we figure 9% taxes as well, we would be at 108 kb net. So at WH we would have about $45/b,
if the price you suggest is WTI. If LOE is $9/b, we are left with $36/b and net revenue of
$3.9 million, if we assume interest expense and G+A are covered by wells already completed.
So this well would not meet the 36 month payout standard (not even close).
I agree $60/b is not enough, probably $85/b is needed. I am surprised that there has been
as many wells completed in the past year as there has been. At the oil price it doesn't seem
to make sense.
Dennis wrote; "….if we assume interest expense and G+A are covered by wells already completed."
Dennis, can you point to any company where such a thing (assume interest expense and G&A
are covered by wells already completed) is SOP (Standard Operating Procedure)?
FWIIW, estimates show that in aggregate for Bakken $0,4 – $0.5B above cash flow was used
in Bakken in both Jan and Feb-16.
Dennis, there is no net cash flow anymore to drill 200 wells a month, in any shale play, anywhere.
There is no more deferring interest payments, there is no more chingling service providers
and suppliers on 120-180 day terms; how many more reverse splits do you think these public
shale companies can undertake? CLR is the jefe of shale oil development; as Shallow so poignantly
points out, at the end of 2015 CLR had only enough liquidity to drill 1 1/2 more shale wells.
There is no more money, Dennis. Its gone.
Respectfully, may I suggest you read the little words at the bottom of every shale oil earnings
report, or stock tout, that goes something like past performance is not an indication of future
results.
I am simply trying to understand how wells continue to be completed at such low oil prices.
At $50/b at the well head and borrowing for 15 years at 12 % interest an equal number of SPUCs
and drilled and completed wells will have a NPV of $63,000 at a discount rate of 14% over the
20 year life of the well.
If the Bakken continues at 60 wells per month with half coming from SPUCs, the SPUC inventory
falls to 500 if 30 wells are spud each month. Although not very profitable, it keeps the lights
on.
Maybe this kind of thinking is the reason wells continue to be completed at a low rate.
Do you want to make accurate oil price predictions?
(1) The oil price *floor* is set by the marginal cost of production. This varies by volume
transacted, of course. Excursions below the floor are possible but will last less than two
years, as they end when companies run out of cash to sink into a money-losing business.
(2) The oil price *ceiling* is set by the cost of alternatives, such as electricity for electric
cars or heating, or natgas for industrial processes. Excursions above the ceiling are possible
but won't last more than a few months - that's how long it takes industries to retool, how
long it takes for people to buy new cars, etc.
If you want to know the ceiling you need to look at the price of alternatives. In 2018,
electric cars will have purchase-price parity in the upper half of the US car market. Electricity
averages 12 cents per kwh and the cars average 300-350 wh/mile. This is 3.6 to 4.2 cents per
mile.
In very expensive electricity markets, the price of electriciy is being capped by the price
of home solar panels - which of course also varies geographically by amount of sunlight, but
it's under 12 cents per kwh in most of the expensive-electricity markets I know about.
The most efficient gasoline cars are hybrids which get 50 mpg. For these to be cost-effective
vs. an electric car with purchase price parity, given the above electricity prices, gasoline
has to be below $1.80/gallon. (Technically the best are 55 mpg, and this seems to be the theoretical
limit - this would give a gas price of $1.98/gallon.)
This sets a… fairly aggressive ceiling on oil prices. Using a rough calculator to convert
gas price to oil price, basically they can't rise above $55/bbl or maybe $60/bbl for very long.
They could rise higher prior to 2018 (because electric cars don't reach purchase price parity
until then). They could rise higher because electric cars will have trouble manufacturing fast
enough to meet customer demand, but that would be a very short-lived phenomenon.
Or oil prices could rise higher *after automobiles are no longer the main users of crude
oil*, at which point a different calculation applies (what alternatives are there for oil for
airplanes? for factories? how much do they cost?) But at that point, the volume of crude oil
sold would have dropped so massively that all the shale plays would be dead - the volume would
presumably be supplied by easier fields.
In fact, since most gasoline cars do not get 50 mpg and the ones which do carry a price
premium, I expect that the effective cap on the price of oil will actually be below $55, though
I expect excursions as high as $65 due to the lag times involved (several months) for consumers
to respond to oil prices by buying different cars, etc.
Oil's currently around $45; at this price, only hybrids with 41+ mpg can compete on fuel
costs with electric cars (non-hybrids basically can't get better than 40 mpg). Even switching
to hybrids will cut oil usage. The result is that the gasoline car will die quite fast and
the reduction in sales volume for oil will keep pushing the price down. But not until 2018.
I'm going to stake a solid prediction here, and I'm going to be conservative about it. We
will not see oil prices above $60/bbl for more than 9 months at a time, starting in April of
2018 (by which time the electric cars will be very firmly on the market and mass produced).
You can rely on that oil price ceiling prediction until automotive use stops being the major
demand for oil.
The shale producers claim to have breakevens below $45, but most of them are lying - they're
lying in order to try to get more funding, I suspect. A few sweet spots do seem to have lower
breakevens. The drilled-but-uncompleted wells probably have cheaper breakevens (considering
the drilling a sunk cost) so they'll probably be completed.
As oil demand drops, the most expensive marginal producers disappear first (typically) which
lowers the floor on oil prices.
"If the USA can go from 5 million to 9 million in less than 5 years. I wouldn't be surprised
if 20 mbd with time and investmentime was possible."
To add to Mike's Financial description of the problem which is spot on, there is also the
problem of availability. There are only a few locations where shale drilling is possible (sweet
spots). The current locations have been know for a long time in some cases more than 50 years.
Shale drilling is likely a one time deal since they will eventually be depleted.
There is also the problem of the "Red Queen" factor, which would likely have been breached
either this year or in 2017, if the price of Oil hadn't collapsed. Since Shale Wells decline
quickly drillers have to ever increase the pace and the number of wells they drill to continue
expanding production. At some point it becomes physically impossible to drill fast enough to
continue expanding production.
So far EUR has not decreased. It will at some point we do not know when.
At 150 wells completed per month the Bakken would still be increasing. The only problem
is low oil prices. Your basic description is correct but at $100/b oil the peak occurs in 2022
and decline begins due to decreasing EUR.
"Your basic description is correct but at $100/b oil the peak occurs in 2022"
I have doubts we will see Oil back up near $100 anytime soon. Nearly the entire globe has
reached debt saturate, unable to take on more debt. Thus limiting the economy to supporting
much higher energy prices. As I stated in a previous post. High Oil prices occured during the
two recent debt bubbles. The first being the US housing bubble, and the latter, the BRICs Debt
bubble.
Can you foresee another debt bubble happening anytime soon?
There will be another debt bubble (there always is one!) but it's going to be in renewable
energy (the hot new sector!) and it'll give precisely *no money at all* to fossil fuel companies.
"... The level of effort dedicated to overcoming challenges will depend in part on sustained high oil prices to encourage sufficient investment in and demand for alternatives. ..."
The U.S. economy depends heavily on oil, particularly in the transportation sector. World oil production
has been running at near capacity to meet demand, pushing prices upward. Concerns about meeting increasing
demand with finite resources have renewed interest in an old question: How long can the oil supply
expand before reaching a maximum level of production--a peak--from which it can only decline? GAO
(1) examined when oil production could peak, (2) assessed the potential for transportation technologies
to mitigate the consequences of a peak in oil production, and (3) examined federal agency efforts
that could reduce uncertainty about the timing of a peak or mitigate the consequences. To address
these objectives, GAO reviewed studies, convened an expert panel, and consulted agency officials.
Most studies estimate that oil production will peak sometime between now and 2040. This range of
estimates is wide because the timing of the peak depends on multiple, uncertain factors that will
help determine how quickly the oil remaining in the ground is used, including the amount of oil still
in the ground; how much of that oil can ultimately be produced given technological, cost, and environmental
challenges as well as potentially unfavorable political and investment conditions in some countries
where oil is located; and future global demand for oil. Demand for oil will, in turn, be influenced
by global economic growth and may be affected by government policies on the environment and climate
change and consumer choices about conservation. In the United States, alternative fuels and transportation
technologies face challenges that could impede their ability to mitigate the consequences of a peak
and decline in oil production, unless sufficient time and effort are brought to bear. For example,
although corn ethanol production is technically feasible, it is more expensive to produce than gasoline
and will require costly investments in infrastructure, such as pipelines and storage tanks, before
it can become widely available as a primary fuel.
Key alternative technologies currently supply the
equivalent of only about 1 percent of U.S. consumption of petroleum products, and the Department
of Energy (DOE) projects that even by 2015, they could displace only the equivalent of 4 percent
of projected U.S. annual consumption. In such circumstances, an imminent peak and sharp decline in
oil production could cause a worldwide recession. If the peak is delayed, however, these technologies
have a greater potential to mitigate the consequences. DOE projects that the technologies could displace
up to 34 percent of U.S. consumption in the 2025 through 2030 time frame, if the challenges are met.
The level of effort dedicated to overcoming challenges will depend in part on sustained high oil
prices to encourage sufficient investment in and demand for alternatives. Federal agency efforts
that could reduce uncertainty about the timing of peak oil production or mitigate its consequences
are spread across multiple agencies and are generally not focused explicitly on peak oil. Federally
sponsored studies have expressed concern over the potential for a peak, and agency officials have
identified actions that could be taken to address this issue.
For example, DOE and United States
Geological Survey officials said uncertainty about the peak's timing could be reduced through better
information about worldwide demand and supply, and agency officials said they could step up efforts
to promote alternative fuels and transportation technologies. However, there is no coordinated federal
strategy for reducing uncertainty about the peak's timing or mitigating its consequences.
"... I recall a geophysics professor equating what he called the "Red Queen Effect" to self-organized criticality, a property of certain dynamical systems that have a critical point as an attractor ..."
"... There is also another element to the Red Queen effect (also caused by the rapid decline in extraction and over time poorer acreage [story of lowest hanging fruits]) and that is funding [and profitability, but I will leave this now]. ..."
"... What I did not expect/foresee back in late 2012, was the extensive use of external funding, primarily debt. The model used a funding feedback and constrained debt leverage. ..."
"... Most of the oil companies went on a debt fueled spending spree expecting the oil price to have reached a permanent high level. And few of these oil companies acknowledge anything about peak oil. Financial dynamics and realities also apply to shale activities. The near future developments in the shales are now all about financials and debt service and many companies will find this reality much harsher than most of the physical realities they so far has encountered. ..."
"Bakken Three/Forks data shown in chart above (NDIC Data) with a Red Queen Model (based
on Rune Likvern's original work) using data gathered from the NDIC by Enno Peters to develop
well profiles."
Was that the first reference to Red Queen in Sep 2012 by Rune?
Unfortunately I did not call it Red Queen, but the more historically accepted terms of Gold
Rush and boom-bust cycle. These things have happened in the past with respect to other resources,
but the only difference with the Bakken is that it now has a different name. Yet the name is just
a name and what is important is the mathematics and physics behind the behavior.
I recall a geophysics professor equating what he called the "Red Queen Effect" to self-organized
criticality, a property of certain dynamical systems that have a critical point as an attractor.
That would've been in the mid-1960s. However, other than when reading Lewis Carroll's Through
the Looking-Glass to my kids I haven't heard the phrase used regularly until encountering Rune
employing the expression here. Googling it, apparently biologist Van Valen developed a "Red Queen
Effect" hypothesis whereby species have to "run" or evolve in order to stay in the same place
or remain extant. That was in the early 1970s. Whatever, it's a rather nice metaphor that seems
to fit LTO production perfectly.
Doug – There's a pretty good book called 'The Red Queen Effect: Sex and the Evolution of Human
Nature', although I'm not that keen on the author, Matt Ridley, who owns the last open cast coal
mine in UK and writes the most condescending op-ed crap in the Times.
WebHubbleTelescope – Red Queen, as I understand it, is having to run faster and faster to stay
in the same place, that doesn't conjure up the same image as boom-bust (moving up and then down)
or gold rush (which I've never heard as a metaphor for anything except what it was, the madness
of crowds attracted to a new resource play).
The Red Queen effect was in reference only to shale oil drilling. Because the wells
decline so fast they must keep drilling faster and faster to stay in the same place. At some point,
not yet reached when the term was first used, the decline will be so great that drillers will
not be able to even stay in the same place. That was the point Rune was making even though that
point had not been reached then . But his point was that point would eventually be reached.
And that is the case even if the bust had never happened.
You are correct. As far as the Bakken and applying the idea of an average well profile multiplied
by the number of completed wells,
there is Mason in Feb 2012, your work in May and July 2012,and then Rune Likvern's work.
Sorry for not giving you credit, I got mixed up because I read Rune Likvern's work before finding
yours and I wrote up this post too quickly without checking back. My mistake.
There is also another element to the Red Queen effect (also caused by the rapid decline
in extraction and over time poorer acreage [story of lowest hanging fruits]) and that is funding
[and profitability, but I will leave this now].
In one piece I alluded to that a slower pace of shale developments would also reduce risk of
exposure to lower prices, reduce cost inflation and as we have learnt, better support a higher
oil price by better balancing supplies and demand [shales are very responsive].
What I did not expect/foresee back in late 2012, was the extensive use of external funding,
primarily debt. The model used a funding feedback and constrained debt leverage.
Most of the oil companies went on a debt fueled spending spree expecting the oil price
to have reached a permanent high level. And few of these oil companies acknowledge anything about
peak oil. Financial dynamics and realities also apply to shale activities. The near future developments
in the shales are now all about financials and debt service and many companies will find this
reality much harsher than most of the physical realities they so far has encountered.
Rune's was the first study I saw that used actual well by well data to develop a well profile
along with the number of new wells added per month. I guess I tend to remember Rune Likvern's
work because he made this rather famous with his work at the Oil Drum.
There was a piece by James Mason in Feb 2012, your piece in May 2012 and a follow up in July
2012, Rune Likvern's work was first published in Norwegian in early Sept 2012.
My apologies to James Mason and Webhubbletelescope, the "Red Queen" name is very catchy, but
the original idea for modelling the Bakken/Three Forks in this way was in James Mason's work.
Dennis, You are right. James Mason was the first. From Mason's PDF "Oil Production Potential
of the North Dakota Bakken":
"Attention is now turned to an evaluation of North Dakota Bakken oil production rates. Because
of the continuous declines in well production over time, new wells have to be brought into
production to make-up the production declines in order to maintain a constant oil production
level. Based on an average well production profile for wells with a 500 Mbbl EUR, the number
of wells to sustain 1.0, 1.5, and 2.0 MMbbl/d oil production rates for thirty years is 27,000
wells, 41,000 wells, and 55,000 wells respectively. The question explored is the timing of
when the land development area becomes saturated with well development."
It's important to cite previous work and give credit where credit is due, otherwise repetition
will work to rewrite history … like I just about did, forgetting that I missed Mason's work the
first time through.
You did cite Mason in your July 2012 blog post and perhaps you had not seen Mason's work before
your May 2012 blog post (it was accepted for publication in Feb 2012, but was published in April
2012).
I always had trouble commenting at The Oil Drum. I think the moderator ( Leanne?) was very
capricious about what comments of mine she would decide to delete. And if I ever complained about
her moderating policies, that was it and I would be banned from commenting for a period of time.
"... In response to continued low oil prices, onshore crude oil production in the Lower 48 states is expected to decline from an average of 7.41 million barrels per day (b/d) in 2015 to 6.46 million b/d in 2016 and to 5.76 million b/d in 2017. ..."
"... In my view we will see actually a massive decline in wells due to plugging of wells. ..."
"... So, a 33% decline of production is realistic and probably even too conservative. ..."
"... It is difficult for me to check how big these wells are. However, the main point here is about a huge sea change (see below chart) in net wells. Add the dramatic decline in use of proppant, the drop in rig counts (natural gas rigs are just at 88 versus 1600 in 2008)….. I can see the writing on the wall. ..."
"... US production will be declining dramatically over the next months. Even the CEO of Pioneer and the IEA admit the decline. The only difference is that I think the decline will last much farther than Sep 2016 and will last well into 2017. ..."
"... Looking at the Bakken, the decline rate from June 2015 to July 2016 will be close to 20% per year if the completed wells fall to 50 new wells per month on average for the rest of 2016, so decline is pretty steep, just not 33%/year. After July 2016 if the completion rate levels off at about 40 completions per month the decline rate moderates to about 10% per year for July 2016 to July 2017. ..."
"... I do think, however, US conventional will continue to drop because there are very few vertical oil rigs running, far lower than even in 1998-1999. Also, I do not think a price increase will result in many conventional rigs coming back to the field this year. Balance sheets must be healed first. Conventional producers do not have a shocking decline like the LTO companies, so skipping another year of new wells is not as big of a problem. ..."
In response to continued low oil prices, onshore crude oil production in the Lower 48 states
is expected to decline from an average of 7.41 million barrels per day (b/d) in 2015 to 6.46 million
b/d in 2016 and to 5.76 million b/d in 2017.
The number of active onshore drilling rigs in the Lower 48 states fell 78% (from 1,876 to 412)
between the weeks ending on October 31, 2014, and April 15, 2016. The decline in active rigs and
well completions is projected to result in month-over-month onshore oil production declines of
120,000 b/d through September 2016.
EIA projects that the number of operating rigs in the Lower 48 states will continue to decrease
through mid-2016 before beginning to slowly increase. However, expected Lower 48 production will
continue to decline-although at a slowing rate-throughout 2017.
EIA's April STEO forecasts Brent crude oil prices averaging $35/b in 2016 and $41/b in 2017,
with the December 2017 price averaging $45/b.
In contrast to the forecast of declining Lower 48 onshore production through 2017, federal
Gulf of Mexico oil production is projected to increase from 1.54 million b/d in 2015 to 1.66 million
b/d and to 1.82 million b/d in 2016 and 2017, respectively. Alaska's oil production is projected
to slightly decrease from 0.48 million b/d in 2015 to 0.47 million b/d in 2016 and to 0.46 million
b/d in 2017.
Increased production from the federal Gulf of Mexico (GOM) is not enough to offset those declines,
with total projected U.S. production falling from 9.43 million b/d in 2015 to 8.04 million b/d
in 2017.
Eyeballing the decline of Q1 2015, onshore : it appears to drop from about 7.5 to 5.0 in 1
year time (33%). That's an even higher decline rate than I expected. Looks like not only the production
I'm tracking is declining at a rapid rate.
I'm curious to see if we indeed will see the projected pick up in rig count this summer already.
Your charts for the Bakken and some other sources show that LTO output drops by some 35% in
12 months if no new wells are completed.
Given that the EIA chart for Lower 48 onshore includes conventional production and still assumes
that new wells are drilled and completed, a 33% decline indeed looks too big.
Apparently, they assume continuing decline in conventional output, primarily due to shut-down
of the stripper wells. BTW, according to the EIA, between April 2015 and January 2016, US conventional
onshore production was down 300 kb/d (bigger in relative terms than the drop in LTO output).
In addition, the EIA's oil projections are too low, in my view. Therefore, they may assume
a small number of well completions
The plugged wells are stripper wells with output of 5 b/d or less.
So if 1000 of these wells are plugged each month that's 5 kb/d lower output each month or a 60
kb/d total decrease over 12 months. Not really much of a factor.
It is difficult for me to check how big these wells are. However, the main point here is
about a huge sea change (see below chart) in net wells. Add the dramatic decline in use of proppant,
the drop in rig counts (natural gas rigs are just at 88 versus 1600 in 2008)….. I can see the
writing on the wall.
US production will be declining dramatically over the next months. Even the CEO of Pioneer
and the IEA admit the decline. The only difference is that I think the decline will last much
farther than Sep 2016 and will last well into 2017.
So far decline in Texas has been relatively modest at an annual decline rate of 8%.
There are still a lot of horizontal oil rigs operating in the Texas Permian Basin (over 100),
and the horizontal wells produce much more oil than the vertical wells in that Basin.
I am talking about oil only here, I don't follow natural gas as closely, at some point gas
output will fall and natural gas prices will rise, no idea when that will happen though.
The permits minus plugged is not really very useful. Oil wells completed relative to wells
plugged is of greater interest. Every well completed (average of about 250 kb/d for first year)
covers about 50 plugged stripper wells (with an average of under 5 b/d). So about 20 completed
wells will make up for 1000 plugged wells.
The first 3 months of 2016 there were 2482 new drill oil completions in Texas and 1453 oil
wells plugged. The plugged wells are equivalent to taking away 29 of the new wells drilled, so
the net new wells would be 2453 new wells or about 818 new wells per month for the first 3 months
of the year. In March about 300 of these wells were in districts 1 and 2 (Eagle Ford most likely)
and about 450 wells in Districts 7C, 8 and 8A (Permian Basin).
There has continued to be quite a lot of activity in Texas at least through March 2016.
Are you accounting for possible incomplete data in Texas?
Are you seeing 33% decline rates outside of Texas?
I am talking at the field level, rather than individual wells or counties. So for the Niobrara,
or New Mexico Permian, the decline is certainly not 33% in the north Dakota Bakken, or not through
February at least. Based on Dean's data for Texas and even the EIA data for Texas, the statewide
decline rate is not anywhere close to 33% per year.
Using EIA data, TX decline rate is 9% from March to Jan 2015. Using Dean's data from March
2015 to Dec 2015 the decline is 6.1% (Jan was anomalous so I threw it out, if it is included the
decline rate is 4.2%)
Looking at the Bakken, the decline rate from June 2015 to July 2016 will be close to 20% per
year if the completed wells fall to 50 new wells per month on average for the rest of 2016, so
decline is pretty steep, just not 33%/year. After July 2016 if the completion rate levels off
at about 40 completions per month the decline rate moderates to about 10% per year for July 2016
to July 2017.
I think the EIA is overestimating the decline because they are underestimating the oil price.
With the DUCs available, the decline for the rest of 2016 in the LTO plays could be as little
as 350 kb/d. The EIA is estimating almost a 1 Mb/d drop for the rest of 2016, the conventional
L48 onshore was about 3300 kb/d in Jan 2016, a 650 kb/d drop in output from L48 onshore conventional
would be a 20% drop, if we assume an 8% drop, that would be about 270 kb/d, for a total of 620
Kb. The EIA is also underestimating Texas output, if Dean's estimates are correct. If we assume
no acceleration in the decline rate for L48 onshore, we get the following, with 2017 output about
6200 kb/d for L48 onshore.
The EIA has a long record of underestimating US oil production, not only during the shale boom,
but also during the current downturn. In particular, they have been underestimating volumes produced
in Texas. But I think that the most recent Dean's estimate for Texas may be too high.
TRRC is now receiving production data from operators in electronic form, which may have shortened
the reporting time. Hence, the underreported volumes for the most recent months are probably less
in relative terms than previously. My conclusion is that historical numbers are somewhere in between
Dean's and the EIA's estimates.
As regards projections for the rest of this year and 2017, I agree that the EIA's price assumptions
are too low. Higher prices may result in higher volumes.
That said, I do not expect a quick rebound in drilling/completion activity as most shale companies
are in a difficult financial situation and will not rush to increase capex. And even in the shale
industry, with its short investment cycle, there is a time lag between a decision to increase
capex and first production.
The EIA's projections may be too low, but I still do not expect a quick rebound in the US C+C
output.
Although maybe not moving the needle much, I think US stripper well production may not decline
as much as it has recently because of:
A. If prices continue to stay above $40 WTI, wells shut in may be put back on production.
B. As winter is over, it is more likely that low volume wells will be returned to production.
Actually many times both A. & B. apply. We have some wells that must be shut in when the temperature
drops below a certain level. Shutting in requires some work, as does resumption of production.
When oil prices were high, we would only shut in during the cold weather. This past winter, we
just shut in at the first sign of cold weather, and did not start up until winter was over.
I do think, however, US conventional will continue to drop because there are very few vertical
oil rigs running, far lower than even in 1998-1999. Also, I do not think a price increase will
result in many conventional rigs coming back to the field this year. Balance sheets must be healed
first. Conventional producers do not have a shocking decline like the LTO companies, so skipping
another year of new wells is not as big of a problem.
"... "There can be no doubt, then, that by the end of this century, life as we know it on planet earth will be very different. Fossil fueled predatory capitalism will be dead. In its place, human civilization will have little choice but to rely on a diversity of clean, renewable energy sources." ..."
"... My quibble is that predatory capitalism will be dead. The Machiavellian ideology arrived prior to fossil fuels of any sort, and I think likely will be around quite a bit longer. ..."
"... Large top-down national and transnational structures will begin to become obsolete due to the large costs of maintenance, the unsustainability of the energy inputs needed for their survival, and the shift in power to new decentralized producers of energy and food. ..."
"... The end of cheap oil probably means end of neoliberalism. It is still unclear what will replace it as a dominant social system. ..."
This article seems to me to be an attempt at taking a long term look at a huge issue – humanities
future over the next 85-years or so. Given the available text space (no doubt many volumes could
cover a small fraction of the subject) Ahmed does a great job of summarizing and provides some
promising links to sources.
One quick quibble, Ahmed writes,
"There can be no doubt, then, that by the end of this century, life as we know it on
planet earth will be very different. Fossil fueled predatory capitalism will be dead. In its
place, human civilization will have little choice but to rely on a diversity of clean, renewable
energy sources."
Of course, I agree life will be different in 2100. I also agree that we are witnessing the
fossil fuel end game (as Amory Lovins at RMI would say), and certainty if one looks at current
rates of investment in various energy technologies, renewable sources are the future. My quibble
is that predatory capitalism will be dead. The Machiavellian ideology arrived prior to fossil
fuels of any sort, and I think likely will be around quite a bit longer.
Granted, Ahmed makes some caveats in the article about how difficult the next few decades will
be. He then writes,
" Large top-down national and transnational structures will begin to become obsolete
due to the large costs of maintenance, the unsustainability of the energy inputs needed for
their survival, and the shift in power to new decentralized producers of energy and food.
In the place of such top-down structures, smaller-scale, networked forms of political, social
and economic organization, connected through revolutionary information technologies, will be
most likely to succeed. For communities to not just survive, but thrive, they will need to
work together, sharing technology, expertise and knowledge on the basis of a new culture of
human parity and cooperation."
Imagine the Sanders campaign working on issues outside electoral politics, run by occupy wall
street organizers for example. I suspect there is some truth in Ahmed's speculations. Enough to
be hopeful about. It may just come down to a choice – despair in business as usual, or taking
a leap to hope, and work for, the success of some rational changes for the better.
likbez, April 23, 2016 at 3:51 pm
The end of cheap oil probably means end of neoliberalism. It is still unclear what will
replace it as a dominant social system.
"... My guess at this point is sometime between 2018 & 2020 we will begin to see substantial declines of 3% to 7% per year (slow at first, but increasing over time). The current investment in CapEx isn't sufficient to prevent much higher depletion rates. ..."
"The scenario I think most likely is and undulating plateau in C+C output to about 2021 and then
gradual decline of under 1.5% though about 2027 and by 2030 that declining output will cause an
economic crisis and a World recession."
I have serious doubts that infill drilling will hold
out anywhere near that long. if it wasn't for infill drilling scraping the bottom of depleted
fields, we would already be in a serious decline, even with the shale bubble. How long can infill
drilling last, I don't know, but its not-sustainable.
My guess at this point is sometime between 2018 & 2020 we will begin to see substantial declines
of 3% to 7% per year (slow at first, but increasing over time). The current investment in CapEx
isn't sufficient to prevent much higher depletion rates.
DC Wrote:
"By that time it will be clear that peak oil has been reached and perhaps policy measures will
be aggressively implemented to alleviate the problem."
It will be to late by then. Its already too late now. I expect when production problems develop.
the World gov't will turn to the same old tactics that make the problems worse: Price Controls,
Rationing, even more excessive gov't regulation, cronyism, and of course, more war.
DC wrote:
"An economic crisis (such as the 1930s in some parts of the World) can lead to positive social
changes, they can also be very negative."
I cannot recall a single period in history that an economic crisis lead to positive social
change. Its only after a wave of bloodshed and destruction that civilization makes a change. However,
never in history did the world experience a economic collapse rife with revolution/social change,
armed with nuclear weapons and nuclear power plants. Whatever remains of humanity in the aftermath,
will likely be another 1000 years of the dark ages (ie the fall of Rome)
Also consider in most cases it was war that made the economy better. Since the beginning of
the industrial revolution, war has create a rapid progress in technology. For instance, WW1 paved
the way for rapid use of machinery (farm tractors, trucks, cars, etc). The factories built to
make tanks, trucks, etc during the war, started mass producing consumer goods after the war, and
increase worker productivity. WW2 create the electronic revolution (computers, development of
broad antibiotics, new materials: Plastics, etc).
Unfortunately nuclear weapons rules out future tech revolutions since our weapons can now destroy
civilization and damage the global environment for hundreds to thousands of years. A nuclear war
will be over in a matter of a few days perhaps as long as few weeks, killing billions and there
will be no time to develop new technologies. Nuclear weapons are the Apex of war developed tech.
We've become the Suicide race.
DC Wrote:
"Hopefully we will not forget our history."
We already did! See the rise of socialism in the West as a prime example. The lessons of war and
politcican follies are lost after the last generation that suffered the horrors dies off. The
WW 2 generation is nearly gone, Thus ushering in a new wave of folly.
Another myth is the drilling efficiencies being touted by E&Ps. Yes,
drilling has gotten better, but most of the price gains touted by E&P management
are related to pricing concessions extracted from the OFS sector. OFS operators
simply are fighting for survival and are doing what it takes to keep customers
- cutting prices as much as they can and even taking losses. Once activity
begins to pick up, OFS pricing mostly will reverse, he said.
"The fact remains that the industry's technical and financial performance
was already challenged with oil prices at $100/bbl, as seen by the fading
cash flow and profitability of both the IOCs and independents in recent
years," Kibsgaard said.
"Over the past decade, our industry has simply not progressed sufficiently
in terms of total system performance to enable cost-effective development
of increasingly complex hydrocarbon resources. This can be seen by the escalating
industry cost per barrel."
The U.S. land rig count peaked in October 2014, and the "rate of disruption"
across the energy sector has led to a "full-scale cash crisis."
"The latest data points have, in recent weeks, sent the oil price up
toward $40/bbl, and we would expect the upward trend to continue as the
physical balances tighten further in the coming quarters," said Kibsgaard.
"In spite of this, we maintain our view that there will be a noticeable
lag between higher oil prices and higher E&P investments given the fragile
financial state of our customer base, which means that there will be no
meaningful improvement in our activity until 2017" .
"... In any case, the USA shale industry is now against the wall and without government intervention they will be decimated no matter what will be the form of price curve in 2016 and 2017. The forces that try to prolong "low oil price forever" regime are still quite strong and will not give up without a fight. ..."
"... Shale is in a position of zugzwang, as they say in chess since November 2014. That is, whatever action it takes it will be wrong. ..."
"... Their "race to sweet spots" is mainly prolonging agony for everyone else and not solving their model if it ever existed. ..."
"... The deflation of a bubble is clearly a zugzwang style situation. Great insight -- Thank you. ..."
Looks like you discovered a yet another variant of Red Queen race: race for sweet spots :-)
In any case, the USA shale industry is now against the wall and without government intervention
they will be decimated no matter what will be the form of price curve in 2016 and 2017. The forces
that try to prolong "low oil price forever" regime are still quite strong and will not give up
without a fight.
"... So by the end of this year or beginning of next year when the price is $50-55 the wells that could have been drilled at that price are already have been drilled. At that time they will announce the next target of $70 when they will pull the rigs from the yard and so on. So they will never reach the desirable price where the rigs will be back because target price will always be ahead of prospective wells that are available. ..."
"... At this point it is hard for them to do anything with such high declining wells. ..."
"... Looks like you discovered a yet another variant of Red Queen race: race for sweet spots :-) ..."
"... In any case, the USA shale industry is now against the wall and without government intervention they will be decimated no matter what will be the form of price curve in 2016 and 2017. The forces that try to prolong "low oil price forever" regime are still quite strong and will not give up without a fight. ..."
"But they are very cautious: the price trigger is $50, not $40-45, like many experts were predicting."
Alex,
I think what is happening is that wells that were borderline at $40-45 have been relentlessly
drilled in the last 2 years when we had oil between $26-$40. And that wells are gone now, so now
they are progressively moving drilling target between $50-60. But as of now someone is still drilling
these $50-60 borderline wells when price barely reached $42 and with significant help of freeze
talk.
So by the end of this year or beginning of next year when the price is $50-55 the wells
that could have been drilled at that price are already have been drilled. At that time they will
announce the next target of $70 when they will pull the rigs from the yard and so on. So they
will never reach the desirable price where the rigs will be back because target price will always
be ahead of prospective wells that are available.
But what else they can say to the gullible investors during investors call or conference except
we are cautious because we know what we are doing :-)
At this point it is hard for them to do anything with such high declining wells.
Looks like you discovered a yet another variant of Red Queen race: race for sweet spots :-)
In any case, the USA shale industry is now against the wall and without government intervention they
will be decimated no matter what will be the form of price curve in 2016 and 2017. The forces
that try to prolong "low oil price forever" regime are still quite strong and will not give up
without a fight.
"... The weekly decline stands now at -31 kb/d which is annualized 1.6 mill b/d. In my view decline rates will now accelerate until oil prices – and more importantly drilling – are up. So, it is also my opinion that the next rise in US liquid hydrocarbon production will not be up before summer 2017. ..."
The weekly decline stands now at -31 kb/d which is annualized 1.6 mill b/d. In my view
decline rates will now accelerate until oil prices – and more importantly drilling – are up. So,
it is also my opinion that the next rise in US liquid hydrocarbon production will not be up before
summer 2017.
Interesting also that 'other supply' (including fuel ethanol and processing gains) is down
70 kb/d. So, the market works and lays the foundation of a price recovery.
The EIA's latest
Drilling Productivity Report has US shale oil production down by 114,000
barrels per day in May. On an annualized basis that is 1,368,000 barrels
per day. That is huge.
Notice that the rate of decline is now increasing every month. It took
a while, until December 2015, for the decline to really get started in earnest.
But now it is clearly underway. It appears that the decline will now clearly
be far greater than a lot of people estimated. Well, that is if the EIA
has any idea of what they are talking about.
I more and more suspect that geology is a significant part of the LTO production
decline. The production curves for each major shale and total of all US
LTO play (ref. Enno Peter's
http://shaleprofile.com/
) are starting to look like bell curves. Also, top producer EOG seemed
to stop its growth in June 2014 and that's before the oil price decline.
Rune Likvern in his recent post @ fractionalflow mentions that some sweet
spots in Bakken are becoming satured with wells. In fact it looks like Bakken
stopped the production increase between July – Nov 2015 which in my eyes
is a bit too early to blame it solely on the oil price.
Maybe Verwimp and Paztec are right? Now it is probably a combination
of oil price and geology, but to me it seems that geology is a significant
part of it.
"... KSA is the primary driver into the turmoil in Syria. KSA is sitting on vast NatGas fields underneath their oil fields. However, producing NatGas from these fields would cause severe Oil production issues, so they won't tap the NatGas until their Oil fields are tapped out. KSA needs to path to get its NatGas into Europe, which requires a pipeline through Syria. So if they are pressing to remove Assad from power, I suspect that KSA production problems aren't too far into the future. ..."
"... Iran & KSA appear to be gearing up for war. Both nations are buying military equipment and are running multiple proxy wars. I believe KSA is now has the 4 or 5 biggest military budget for 2016. Both KSA and Iran also have a limited number of nuclear weapons. Should the proxy wars turn into a hot war, then it really doesn't matter how much oil is left to be produced. ..."
"... I have wondered this for awhile too. They appear to handle so much water. As I have stated, handling water is a major expense in producing oil. I wonder how much chemical KSA has to use and as well how much electricity. I also wonder what pressure is required on the injected water. There are very few water floods in the US with LOE much under $15 per BOE. Most are well over $20. Same applies to steam floods, CO2 and polymer floods. ..."
"... What happens as the "old" big fields that provided decades of oil comes to an end of their economic life, shortened by the collapse in the oil price and the lasting low oil price? Generally the discoveries that wait in line for development are smaller, so to keep the level and/or grow becomes THE Red Queen race. Then throw in that several of the majors have had a Reserves Replacement Ratio (RRR) of less than 100%, meaning reserves are depleted faster than they are being replaced. ..."
"... Let's say Ghawar begins to decline, that is one field, I imagine that you believe it is unlikely that all the large fields in the World will begin their decline phase simultaneously. So let's assume they do not. For simplicity we will assume Ghawar produces about 5 Mb/d and that it will decline at 3%/ year (similar to US before LTO production started from 1985-2004), we will also assume each year the equivalent of one Ghawar begins to decline until all World production is eventually declining at 3% per year. For simplicity we will assume all fields decline at 3% (in reality some will be more than this and some will be less and the rate won't be constant over time. This is a very simple model. ..."
"... I expect than when the Oil column dips some where between 10 feet and 3 feet, Production is going to collapse at a much faster rate than 3% per year, Perhaps as high 10 to 20% per year. I think as the remaining Oil column shrinks its going to be much harder to extract oil since it will be difficult to steer laterals to follow the uneven remaining oil column. The water cut will grow increasing problematic, and drilling will need to increase to keep laterals on near the top of the oil column. ..."
"... My understanding average large fields are declining at a rate of 5% to 7% per year. Horizontal and other advance drilling\extraction tech has prevented significant production declines so far, but this trend isn't sustainable. At some point I believe we will see shocking decline rates no matter what tech is developed, or how much the Price of Oil increases into. ..."
"... Yes. But I think KSA would likely go to war first as a diversion to internal unrest. Ron Patternson would be a better source than me, since I never visited or worked in KSA. Ron has. So far KSA is using brutal tactics to prevent protests and uprisings. ..."
"... Will economic and social problems become a crisis before Oil production collapses begin? Lots of nations are downing in debt, have aging population with no or inadequate retirement savings, and younger labor pools unequipped (educated/skilled) to meet the needs of businesses. I can't image that the global economy can be sustained for much longer (EU, Asia & South America in recession & the US teetering on the end of another recession). Since when in history have major industrial powers have negative interest rates? ..."
"... I believe the most of the Ghawar formation has a profile where its narrow at the bottom and much wider at the top. There is more volume at the top of the formation than at the bottom. So the decline in oil column depth is not linear. ..."
"... "The 2009 study focused on 331 giant oil fields from a database previously created for the groundbreaking work of Robelius mentioned above. Of those, 261 or 79 percent are considered past their peak and in decline." "The average annual production decline for those 261 fields has been 6.5 percent. " ..."
"... "Now, here's the key insight from the study. An evaluation of giant fields by date of peak shows that new technologies applied to those fields have kept their production higher for longer only to lead to more rapid declines later. As the world's giant fields continue to age and more start to decline, we can therefore expect the annual decline in their rate of production to worsen. Land-based and offshore giants that went into decline in the last decade showed annual production declines on average above 10 percent." ..."
"... The increased use of in-fill drilling (e.g. moving horizontal producers up dip) and IOR/EOR techniques was foreseen with it's effect on prolonging the plateau, we are yet to see if the sudden collapse that was also predicted. The thing that was missed in the predictions around 2009 to 2013 was a flood of free money and with it the ability of the oil industry to ramp up non-conventional production, and I'd also say for Iraq. ..."
"... Great post George: an excellent summary of PO describing rapid ongoing production decline from most key fields that has been temporarily deferred by enormous pulse of infill drilling and EOR paid for via free money leading to current situation. What else do we need to know? ..."
"... As I have repeated many times on this blog, Saudi has been able to mask the decline of its old giant oil fields by bringing old oil previously mothballed fields back on line. These fields are Shaybah, Khurais and Manifa. ..."
"... to even suggest that Ghawar might go into decline is preposterous. Ghawar has long been into decline. I am shocked that you are ignorant of that fact. ..."
"... I have no idea what Ghawar's current production numbers are because it is a Saudi state secret. But I would guess somewhere in the neighborhood of 3 million barrels per day. But if it were not a state secret and Saudi were proud of the numbers, then it would be in the neighborhood of 5 million barrels per day. ..."
"... "Although Saudi Arabia has about 100 major oil and gas fields, more than half of its oil reserves are contained in eight fields in the northeast portion of the country…The Ghawar field has estimated remaining proved oil reserves of 75 billion barrels" ..."
"... The EIA estimates Saudi Arabia's oil production capacity (ex NGLs) at around 12 mb/d, including ~300kb/d in the Saudi part of the Neutral zone. The latest estimate by the IEA is 12.26 mb/d ..."
"... Alex, Ghawar can in no way produce anywhere near 5.8 million barrels per day. But then if you believe anything that is printed on the internet then….. ..."
"... Incidentally, the EIA agrees with Saudi Arabia on their proven reserves of 266 billion barrels. Which says nothing other than "We take Saudi's word for everything. ..."
"... The recent increase in Saudi Arabia's oil production was largely due to higher utilization of production capacity. The last large increase in capacity was in 2009, when Khurais field capacity was increased to 1.2 mb/d. The start of the Manifa field in 2013 and its ramp-up in 2014 largely offset declining production at the mature fields. ..."
"... If we assume a 6.5% annual decline rate since 2009 we would be at 3.4 Mb/d in 2015. At some point Saudi Arabia as a whole will begin to decline, when this will happen I do not know. Just as in the US where there has been extensive infill drilling and secondary, tertiary recovery methods employed and decline rates have remained under a 3% annual rate, the same is likely to be true of other large producing nations with a combination of on shore and offshore projects. ..."
"... The best analogy for Ghawar is probably Cantarell, they have both been developed with the best available secondary and tertiary recovery methods. Cantarell production dropped like a stone once those techniques were exhausted (about 15% per year in 2006 to 2008). My guess is Ghawar will go (or is going) even faster as the IOR/EOR techniques and software models available for its development are more advanced and it is onshore, making their application easier. Daqing might go the same way. Samotlor has been declining at around 5%. ..."
"... I know this is probably an impossible question but how long do you think it will take to deplete the remaining oil column? If it is correct that it took 10 years to drop from 100 to 25 feet (assuming this is correct too) then that doesn't bode well for future production from Ghawar over the next decade. ..."
"... The next five years should tell a lot if the oil column is now that thin. 5 mbopd can't continue forever, nor can 3% decline in a permeable reservoir under water flood. When the water mostly reaches the top, the oil stained water becomes too expensive to separate out and production stops at greater than a 3% rate. ..."
1. Ghawar started with a Oil column of ~1300. I believe by 2005, the Oil column shrunk to about
100 feet. Today its about 20-25 feet. The remaining Oil is floating on water and KSA is using
horizontal drilling to extract it. In some regions of Ghawar they are on their second or third
string of horizontal wells as the water column flood above the wells, and they had to drill above
to get back into the Oil column.
2. KSA restarted production in existing wells that have already been depleted decades ago.
Better tech and mapping information permitted them to sweep up trapped oil in these wells.
3. KSA is now using advanced Oil recovery in Ghawar and other fields (CO2/Nitrogen injection)
in order to free up trapped oil.
4. Saudi Americo, posts tech articles (quarterly) on their website. They usually don't include
which fields they are discussing, but with a little bit of effort, its not to difficult to determine
which fields discussed. This is where I found the three above items. I posted excerpts on this
blog over the past couple of years from SA tech articles.
5. KSA is the primary driver into the turmoil in Syria. KSA is sitting on vast NatGas fields
underneath their oil fields. However, producing NatGas from these fields would cause severe Oil
production issues, so they won't tap the NatGas until their Oil fields are tapped out. KSA needs
to path to get its NatGas into Europe, which requires a pipeline through Syria. So if they are
pressing to remove Assad from power, I suspect that KSA production problems aren't too far into
the future.
FWIW: Its just not KSA that is the problem. Most of the global production has been maintained
from old depeleted wells, using new tech to sweep up trapped oil. Obviously this can't be continued
indefinitely. I fear that at some point all of the major fields will begin to see sharp declines
as remains of trap oil is extracted, an newer technology isn't going to extract Oil that doesn't
exist. With the extremely low oil prices, no one is developing any new fields (deep water, arctic,
etc). By the time oil prices recover that makes it profitable resume these expensive projects
it will be too late and there will likely be permanent crisis. It may take 5 to 7 years to develop
new project to produce Oil. 5 to 7 years is a long lag time, which depletion continues to march
on.
That said, its possible that other problems trump Oil production problems, such as, the Debt
crisis or the demographic crisis (aging populations). We are very close to another major debt
crisis as gov'ts start going bankrupt (ie rest of the PIGS – Portugal, Spain, Italy), China, Japan,
Most of South America, and perhaps a lot of US cities and even US states (Puerto Rico, Illinois,
Pennsylvania, West Virginia, and perhaps California).
Iran & KSA appear to be gearing up for war. Both nations are buying military equipment
and are running multiple proxy wars. I believe KSA is now has the 4 or 5 biggest military budget
for 2016. Both KSA and Iran also have a limited number of nuclear weapons. Should the proxy wars
turn into a hot war, then it really doesn't matter how much oil is left to be produced.
I have wondered this for awhile too. They appear to handle so much water. As I have stated,
handling water is a major expense in producing oil. I wonder how much chemical KSA has to use
and as well how much electricity. I also wonder what pressure is required on the injected water.
There are very few water floods in the US with LOE much under $15 per BOE. Most are well over
$20. Same applies to steam floods, CO2 and polymer floods.
What happens as the "old" big fields that provided decades of oil comes to an end of their
economic life, shortened by the collapse in the oil price and the lasting low oil price? Generally
the discoveries that wait in line for development are smaller, so to keep the level and/or grow
becomes THE Red Queen race. Then throw in that several of the majors have had a Reserves Replacement
Ratio (RRR) of less than 100%, meaning reserves are depleted faster than they are being replaced.
Let's say Ghawar begins to decline, that is one field, I imagine that you believe it is
unlikely that all the large fields in the World will begin their decline phase simultaneously.
So let's assume they do not. For simplicity we will assume Ghawar produces about 5 Mb/d and that
it will decline at 3%/ year (similar to US before LTO production started from 1985-2004), we will
also assume each year the equivalent of one Ghawar begins to decline until all World production
is eventually declining at 3% per year. For simplicity we will assume all fields decline at 3%
(in reality some will be more than this and some will be less and the rate won't be constant over
time. This is a very simple model.
Chart below has World C+C output in Mb/d on left axis and annual decline rate (dashed line)
on right axis. It is assumed in this scenario that a nuclear war in the middle east does not occur.
I expect than when the Oil column dips some where between 10 feet and 3 feet, Production
is going to collapse at a much faster rate than 3% per year, Perhaps as high 10 to 20% per year.
I think as the remaining Oil column shrinks its going to be much harder to extract oil since it
will be difficult to steer laterals to follow the uneven remaining oil column. The water cut will
grow increasing problematic, and drilling will need to increase to keep laterals on near the top
of the oil column.
My understanding average large fields are declining at a rate of 5% to 7% per year. Horizontal
and other advance drilling\extraction tech has prevented significant production declines so far,
but this trend isn't sustainable. At some point I believe we will see shocking decline rates no
matter what tech is developed, or how much the Price of Oil increases into.
That said I don't have a crystal ball or a time machine that shows me what is going to happen.
George Kaplan Asked:
"Do you think there is a significant risk of internal disruption"
Yes. But I think KSA would likely go to war first as a diversion to internal unrest. Ron
Patternson would be a better source than me, since I never visited or worked in KSA. Ron has.
So far KSA is using brutal tactics to prevent protests and uprisings.
"Based upon your thoughts, what do you think that the average cost per barrel is for KSA oil?"
I don't have a clue. I would imagine production costs are constantly rising.
Rune rhetorically asked:
"What happens as the "old" big fields that provided decades of oil comes to an end of their
economic life, shortened by the collapse in the oil price and the lasting low oil price?
yes, that was the point I was leading to. That said: Will economic and social problems
become a crisis before Oil production collapses begin? Lots of nations are downing in debt, have
aging population with no or inadequate retirement savings, and younger labor pools unequipped
(educated/skilled) to meet the needs of businesses. I can't image that the global economy can
be sustained for much longer (EU, Asia & South America in recession & the US teetering on the
end of another recession). Since when in history have major industrial powers have negative interest
rates?
Dave P asked:
"I know this is probably an impossible question but how long do you think it will take to deplete
the remaining oil column?"
I don't' have a clue. I believe the most of the Ghawar formation has a profile where its
narrow at the bottom and much wider at the top. There is more volume at the top of the formation
than at the bottom. So the decline in oil column depth is not linear.
"The 2009 study focused on 331 giant oil fields from a database previously created for
the groundbreaking work of Robelius mentioned above. Of those, 261 or 79 percent are considered
past their peak and in decline." "The average annual production decline for those 261 fields has
been 6.5 percent. "
"Now, here's the key insight from the study. An evaluation of giant fields by date of peak
shows that new technologies applied to those fields have kept their production higher for longer
only to lead to more rapid declines later. As the world's giant fields continue to age and more
start to decline, we can therefore expect the annual decline in their rate of production to worsen.
Land-based and offshore giants that went into decline in the last decade showed annual production
declines on average above 10 percent."
The increased use of in-fill drilling (e.g. moving horizontal producers up dip) and IOR/EOR
techniques was foreseen with it's effect on prolonging the plateau, we are yet to see if the sudden
collapse that was also predicted. The thing that was missed in the predictions around 2009 to
2013 was a flood of free money and with it the ability of the oil industry to ramp up non-conventional
production, and I'd also say for Iraq.
Great post George: an excellent summary of PO describing rapid ongoing production decline
from most key fields that has been temporarily deferred by enormous pulse of infill drilling and
EOR paid for via free money leading to current situation. What else do we need to know?
Dennis, Ghawar is not one oil field, it is five. That is not even counting Fazran. There are
Ain Dar, Shedgum, Uthmaniyah,
Hawiyah, and Haradh. Four of the five Gahwar fields are in decline and the fifth, Haradh,
is on a plateau.
To even suggest that Ghawar "might" begin to decline shows an astonishing ignorance of Saudi
oil production capabilities.
As I have repeated many times on this blog, Saudi has been able to mask the decline of
its old giant oil fields by bringing old oil previously mothballed fields back on line. These
fields are Shaybah, Khurais and Manifa.
Dennis, for God's sake, to even suggest that Ghawar might go into decline is preposterous.
Ghawar has long been into decline. I am shocked that you are ignorant of that fact.
I have no idea what Ghawar's current production numbers are because it is a Saudi state
secret. But I would guess somewhere in the neighborhood of 3 million barrels per day. But if it
were not a state secret and Saudi were proud of the numbers, then it would be in the neighborhood
of 5 million barrels per day.
But it is a state secret and it is not, in my estimation, anywhere near 5 million barrels
per day.
"Although Saudi Arabia has about 100 major oil and gas fields, more than half of its oil
reserves are contained in eight fields in the northeast portion of the country…The Ghawar field
has estimated remaining proved oil reserves of 75 billion barrels"
The EIA estimates Saudi Arabia's oil production capacity (ex NGLs) at around 12 mb/d, including
~300kb/d in the Saudi part of the Neutral zone.
The latest estimate by the IEA is 12.26 mb/d
more than half of its oil reserves are contained in eight fields in the northeast portion of
the country
More than half no less. Well hell, I cannot argue with that.
Alex, all your listed fields come to 11.75 million barrels per day. And that is more than
half. Wow! Alex, do you really believe that shit?
That does not include Berri? How could they not count Berri? Or Safah? Or any of the
other fields that would be giant fields in any other country? If you add them all up it would
likely come to at least 15 to 20 million barrels per day. Which is a joke of course. Saudi is
now producing flat out.
Alex, Ghawar can in no way produce anywhere near 5.8 million barrels per day. But then
if you believe anything that is printed on the internet then…..
If 11.75 is more than half then they likely figure around 20 million barrels per day
is possible. Yeah right!
Incidentally, the EIA agrees with Saudi Arabia on their proven reserves of 266 billion
barrels. Which says nothing other than "We take Saudi's word for everything.
Ron, I am actually rather skeptical about EIA's international statistics. Obviously, I'm not saying
that those numbers are correct.
Do you think they may have included NGLs (given that KSA produces more than 2 mb/d of NGLs)?
Alex, the EIA does have a tendency to include NGLs in their estimates. That is likely here since
Saudi is producing nowhere near what they say their their major fields are capable of.
But no one has any idea what each individual field in Saudi is producing. They have only Saudi's
word for it. Which is worth about the same as a bucket of warm spit.
The recent increase in Saudi Arabia's oil production was largely due to higher utilization
of production capacity. The last large increase in capacity was in 2009, when Khurais field capacity
was increased to 1.2 mb/d. The start of the Manifa field in 2013 and its ramp-up in 2014 largely
offset declining production at the mature fields.
Saudi Arabia's oil production and capacity (mb/d)
source: IEA (capacity), JODI (production)
I do not know the output of Ghawar, nor it's decline rate as we have no data. If the output
is 3 Mb/d, it is less of a factor than if output was 5 Mb/d. Yes there are several fields that
are grouped together and called Ghawar. All fields will decline eventually, the "might" is only
about when those declines occur. The simple illustrative model is to show what happens
when all fields don't start their decline at one moment in time. The 5 Mb/d was chosen simply
because at one time "Ghawar" supposedly produced 5 Mb/d in 2009 (according to the Wikipedia article).
What is your source for your 3 Mb/d estimate?
If we assume a 6.5% annual decline rate since 2009 we would be at 3.4 Mb/d in 2015. At
some point Saudi Arabia as a whole will begin to decline, when this will happen I do not
know. Just as in the US where there has been extensive infill drilling and secondary, tertiary
recovery methods employed and decline rates have remained under a 3% annual rate, the same is
likely to be true of other large producing nations with a combination of on shore and offshore
projects.
A lower URR oil shock model (3000 Gb including 500 Gb oil sands) still has an annual decline
rate under 2%/year.
Your analogy of the USA with Ghawar is not applicable. Aggregates of differently aged individuals
do not behave like an oversized average of those individuals. A country does not represent a basin,
a basin does not represent a field and a field does not represent an individual well.
The best analogy for Ghawar is probably Cantarell, they have both been developed with the
best available secondary and tertiary recovery methods. Cantarell production dropped like a stone
once those techniques were exhausted (about 15% per year in 2006 to 2008). My guess is Ghawar
will go (or is going) even faster as the IOR/EOR techniques and software models available for
its development are more advanced and it is onshore, making their application easier. Daqing might
go the same way. Samotlor has been declining at around 5%.
Burgan is probably the best placed of the super giants as it has natural water drive and didn't
use secondary recovery until 2010, and still not much, so there is a lot of potential to accelerate
production and arrest the decline (at the expense of rapid decline later of course). Note however
that wiki indicates 14% decline there, but with no citation so maybe just a guess.
I am comparing US with Saudi Arabia. I expect when Saudi Arabia begins to decline the annual
rate of decline will be 3% per year or less.
Cantarell was pushed much harder than Ghawar, relative to reserves and is an exceptional case.
In any case I do not know what will happen to the fields that make up Ghawar, I don't have any
data so I will not speculate any further. World output will be determined by the output of all
fields, Ghawar is important, but if Ron's estimate is correct, it is 4% of World output.
The 3000 Gb scenario above with 2500 Gb of C+C less oil sands (or extra heavy oil) and 500
Gb of extra heavy (XH) oil is based on Jean Laherrere's 2013 estimate of XH oil and a Hubbert
Linearization of C+C-XH from 1993 to 2015 in chart below.
Dennis – you state "For simplicity we will assume Ghawar produces about 5 Mb/d and that it will
decline at 3%/ year (similar to US before LTO production started from 1985-2004)", and then say
"I am comparing US with Saudi Arabia. I expect when Saudi Arabia begins to decline the annual
rate of decline will be 3% per year or less.". Which one is it, because they aren't both correct?
"Cantarell was pushed much harder than Ghawar" Please provide details of how you know this.
Thanks Techguy, that was an interesting post. I know this is probably an impossible question
but how long do you think it will take to deplete the remaining oil column? If it is correct that
it took 10 years to drop from 100 to 25 feet (assuming this is correct too) then that doesn't
bode well for future production from Ghawar over the next decade.
Much as I love Dennis' charts, I just don't see his 3% continuing very long, if Ghawar is indeed
down to a thin layer of oil over water. There could just be a clunk as the field is shut down
after a short period of steeper decline.
The next five years should tell a lot if the oil column is now that thin. 5 mbopd can't
continue forever, nor can 3% decline in a permeable reservoir under water flood. When the water
mostly reaches the top, the oil stained water becomes too expensive to separate out and production
stops at greater than a 3% rate.
There will be fields that decline more than 3% and fields that will decline less, the average
will roughly match the US decline (the most mature large oil producing nation) from 1986 to 2004
which was less than 3% per year.
Ghawar is several fields, Tech Guy's comments probably do not apply to all the fields of Ghawar.
People also seem to forget that new fields will continue to be developed and infill drilling
and EOR will continue in many fields. These factors will reduce the rate of decline for overall
World C+C output.
5. KSA is the primary driver into the turmoil in Syria. KSA is sitting on vast NatGas fields
underneath their oil fields. However, producing NatGas from these fields would cause severe Oil
production issues,
I assume you are referring to the Kluff nat gas field under lying the Ghawar oil field. I know
the Kluff field was being produced, but not sure if it was near its potential or very restricted
flow. I remember a discussion with some Exxon reservoir people, on the liquids being produced,
and how to define them. Oil or condensate. The Saudis chose condensate as they were not counted
in the export quotas at the time.
Are you saying that Kluff is in communication the Ghawar? If they were surely there would be
pressure issues in the upper field.
I believe there is communication in the water table between Burgan and Safaniya, but that is
a different issue.
It is hard to see where the production of an under lying gas field would affect an over lying
oilfield, apart from a few drilling issues of under pressure thief zones, which can be dealt with
by casing design, mud properties, and maybe even a little managed pressure drilling if required.
"Are you saying that Kluff is in communication the Ghawar? If they were surely there would
be pressure issues in the upper field."
I was just referred to what I read in Saudi Americo's tech articles. If I recall, correctly,
several fields in KSA had NatGas reserves. The article(s) I recall reading referred to delaying
production of NatGas to avoid impacting Oil production. I don't recall the exact details, and
I don't believe that the article(s) mention which fields they are delaying NatGas Production.
These Saudi Americo tech articles do not disclose which fields they are about.
Toolpush wrote:
"It is hard to see where the production of an under lying gas field would affect an over
lying oilfield, apart from a few drilling issues of under pressure thief zones"
I would image drawing down the NatGas would alter the levels were the Oil is located. Since
most of the Oil is now extracted via horizontal wells. I am speculating on how it impacts production.
Perhaps there are more details in the articles than I recall. You can read them as the are publicly
available on SA's website.
Thanks for the feedback. Do you have a link to where these reports are located?
As for gas communication. If the reservoir has a gas cap, then this gas cap can't be drawn
down without effecting the pressure in the reservoir, and therefore oil production. The fact that
most if not all the fields have water injection to maintain well bore pressure, we can assume
pressure maintenance is at a premium.
Now if as you described and I know the Kluff field conforms to this line. The gas is in a separate
trap, separated by it's own cap rock from the oil, then there can't be any communication. If there
was, the gas would ride to the high oil reservoir, and as the gas in at a greater depth than the
oil, is will also have a pressure. If this higher pressure was allowed to communicate with the
upper reservoir, then the upper reservoir would become over pressured, and this over pressure
would have been discovered in the exploration wells.
So I will be very interested to read their explanation to gas production being held back from
under lying gas reserves, rather than any gas bubbles sitting on top of the oil currently being
produced.
Regarding ToolPush Question about NatGas reserves in Oil Fields:
Yes, you have the correct link. I don't recall which article had discuss delaying natGas production
from their oil fields, I read through over a dozen their Tech Publications.
I have found where Kluff has been widely discussed, but not other gas fields, though I have
only scratched the surface. I can see I have a lot of reading to do, but I know I will learn a
lot by the time i am finished.
One little point I noticed. The unconventional gas they talk about, seems to be in carbonates!
Yet to see any shale mentioned, but i will keep going. Closer to Austin Chalk than Eagle Ford.
"... I don't get Dennis' contention that only an outside event such as a world
war can create a Seneca cliff. Of course, a definition of what comprises a Seneca
cliff would be useful. Let's get away from that and just talk about what rate of
decline in oil production would be sufficient to throw the world into a tizzy. I
think something as low as 3% annually would be enough. After a few years at that
rate we would be in a bad situation. Doesn't require a huge drop. ..."
"... I believe we have entered the end game. ..."
"... Geology – drillers need prospects and as more and more fields go dry they
aren't going to drill them again. It took $100 oil to get Bakken going, I think
it will take even more than that as sweet spots are tapped out. And once oil gets
to that level, the economy will push demand back down. ..."
"... It's hard for me to imagine money flowing back into drilling the way it
did in the past few years. Wall Street follows fads and the tight oil fad has run
its course. There will still be money for selected investments, but the terms will
be tougher, the scrutiny will be greater, and the opportunities fewer. ..."
"... Exactly. "Carpet drilling" can't return without return of "loan abundance"
regime. And the latter is gone for good. The trend in production is not their friend
anymore. As Arthur Berman said "EIA forecasts that [natural] gas prices will increase
to $3.31 by the end of 2017 but that is overly conservative because it assumes an
immediate and improbable return to production growth once the supply deficit and
higher prices are established. " ..."
"... The same thinking is applicable to subprime oil. ..."
Also, I don't get Dennis' contention that only an outside event such
as a world war can create a Seneca cliff. Of course, a definition of what
comprises a Seneca cliff would be useful. Let's get away from that and just
talk about what rate of decline in oil production would be sufficient to
throw the world into a tizzy. I think something as low as 3% annually would
be enough. After a few years at that rate we would be in a bad situation.
Doesn't require a huge drop.
And with rig counts declining as fast as they are, I could imagine such
a drop. And furthermore, I don't see the rigs coming back as quickly as
they are being dropped even if prices do recover to the $100 level.
I can't see any compelling that drilling wouldn't pick up quickly again
if oil went back to a hundred bucks and supplies got chancy with inventories
declining fast.
The biggest two problems would be the hands on guys retiring, but enough
money will entice them to work again, if not actually pulling levers and
turning wrenches, then standing over trainees, one on one if necessary.
The other thing would be the money. In a real pinch, governments will provide
emergency financing or loan guarantees to drillers and steam roller some
environmental regs.
But I do think peak oil is either here now, or will be here within the
next two or three years.
It might take a while for exploratory drilling to pick up again, I am
thinking about new wells in producing fields and fields already explored
but not yet well developed.
Drilling will increase at higher prices, no argument there. But I don't
see rig counts going up as fast as they are now coming down. Two reasons:
1. Geology – drillers need prospects and as more and more fields
go dry they aren't going to drill them again. It took $100 oil to get Bakken
going, I think it will take even more than that as sweet spots are tapped
out. And once oil gets to that level, the economy will push demand back
down.
2. Finances – It's hard for me to imagine money flowing back into
drilling the way it did in the past few years. Wall Street follows fads
and the tight oil fad has run its course. There will still be money for
selected investments, but the terms will be tougher, the scrutiny will be
greater, and the opportunities fewer.
There will still be money for selected investments, but the terms
will be tougher, the scrutiny will be greater, and the opportunities
fewer.
Exactly. "Carpet drilling" can't return without return of "loan abundance"
regime. And the latter is gone for good. The trend in production is not
their friend anymore. As Arthur Berman said "EIA forecasts that [natural]
gas prices will increase to $3.31 by the end of 2017 but that is overly
conservative because it assumes an immediate and improbable return to production
growth once the supply deficit and higher prices are established. "
There are too few new projects being sanctioned by non-state oil companies to offset the
inevitable decline in output from existing fields and to meet additional demand. This is expected
to increase by 1.2 million barrels a day each year for the rest of the decade. New fields due to
start producing this year and next are the result of investment decisions taken when oil was
about $100 and expected to stay there.
The collapse in company spending is illustrated perfectly by the level of drilling activity.
After all, if you don't drill, you can't get the oil out of the ground.
Baker Hughes updated its monthly international drilling statistics last week. Unsurprisingly,
they showed another steep drop in rigs drilling for oil, a 12 percent decline between February
and March. There were 1,551 rigs active last month in the countries covered by Baker Hughes, the
least since September 1999 and down nearly 60 percent in little more than a year.
"... Looks like China is importing a lot of oil as there is also a traffic jam in Qingdao, China. ..."
"... A surge in oil buying by China's newest crude importers has created delays of up to a month for vessels to offload cargoes at Qingdao port, imposing costly fees and complicating efforts to sell to the world's hottest new buyers. ..."
"... China's independent refiners, freed of government constraints after securing permission to import just last year, have gorged on plentiful low-cost crude in 2016. This has created delays for tankers that have quadrupled to between 20 to 30 days at Qingdao port in Shandong province, the key import hub for the plants, known as teapots, according to port agents and ship-tracking data. ..."
China has recently allowed imports of crude oil by small independent "teapot"
refineries. So tanker jams do not necessarily mean an increase in final
demand.
From Reuters:
China teapot refiner oil buying spree creates tanker jam at Qingdao
A surge in oil buying by China's newest crude importers has created
delays of up to a month for vessels to offload cargoes at Qingdao port,
imposing costly fees and complicating efforts to sell to the world's hottest
new buyers.
China's independent refiners, freed of government constraints after
securing permission to import just last year, have gorged on plentiful low-cost
crude in 2016. This has created delays for tankers that have quadrupled
to between 20 to 30 days at Qingdao port in Shandong province, the key import
hub for the plants, known as teapots, according to port agents and ship-tracking
data.
"... Your point on the Marcellus displacing production from the other less productive basins is fair enough. That said I don't really see how anyone is making money in the Marcellus. ..."
"... I am reminded of what Rex Tillerson said about gas producers a number of years ago, "Everyone is losing their shirts. It's all in the red." ..."
"... As a conventional oil and natural gas producer who is suffering financially at the moment because of overleveraged shale oversupply, Mr. Coffee might rightfully suggest that I am bias against the shale industry. Truthfully, I want the shale industry to succeed but it must do so by standing on it's own feet, without borrowing money from outside sources it cannot pay back. It must develop it's remaining reserves from net cash flow, in a manner that is commensurate with worldwide supply/ demand fundamentals, at a reasonable, rational pace that will ensure price stability, not price volatility. It must find a way to do that AND pay back it's indebtedness. ..."
"... America has 2.8 million BOPD of conventional oil production that is getting hammered right now largely because of an LTO industry who has had, for the most part, no finding costs the past nine years. There are thousands of shale gas wells in the App Basin that were drilled with borrowed money that have been shut in for years with no takeaway capacity. I can find no success story in that kind of stupidity. ..."
"... Another summary on the investing disaster in shale here, it all comes down greed, corruption and stupidity in the end: ..."
"... My main argument that production potential of all shale plays in the U.S. has been vastly exaggerated for political and propaganda reasons is unchanged and now supported by sufficient data. ..."
"... And for economic reasons too. The principal question here is "Whether deferred adjustment to higher oil prices is beneficial to the USA economy in a long run?". They were definitely beneficial to "team Obama", but this might well be "after us deluge" type of thinking. ..."
Tad Patzek makes a wise point in a
reply to Coffeeguyzz in his post above.
My main argument that production potential of all shale plays in
the U.S. has been vastly exaggerated for political and propaganda reasons
is unchanged and now supported by sufficient data. While the overall
resource is giant, the recovered fraction will remain small because
of the generally poor quality of this resource. For the record, let
me restate the obvious: Some operators in the small sweet spots in all
plays will make a lot of money; most others will lose money and go bankrupt.
In the old fashioned reservoir engineering practiced by people of
my age, these sweet spots are called reservoirs.
I think the most 'agreeable' point Mr. Patzek and I may hold is the inclination
to embrace, promote and disseminate data that reinforces our already held
positions.
If you read Mr. Patzek's piece, and the comments I made in reply on his
blog site, you would see how I questioned virtually everything he presented
as being , at best, skewed.
Now, anyone following would be strongly inclined to favor a professional,
published-numerous-times and highly regarded in his field such as Mr. Patzek,
over some anonymous commenter.
That's natural.
But how in the heck could Mr. Patzek virtually dismiss the Marcellus'
output, ignore the Utica, mischaracterize the current Pennsylvania reporting
parameters and MOST importantly, NOT recognize that the decline in output
from the other formations is a direct consequence of being displaced by
the much bigger, more economic Appalachian Basin?
I claim no special insight. I acknowledge my partiality to fossil fuel
use/consumption now and for the foreseeable future. I would suggest that
those who feel/think otherwise are not so immune from cognitive bias as
they would wish to be.
What prompted me to post was how Patzek characterized sweet spots. From
what I understood in Patzek's post was that he felt there really wasn't
enough data to honestly assess the Marcellus. Which is why he gave it an
optimistic fudge factor. Your point on the Marcellus displacing production
from the other less productive basins is fair enough. That said I don't
really see how anyone is making money in the Marcellus.
I am reminded of what Rex Tillerson said about gas producers a number
of years ago, "Everyone is losing their shirts. It's all in the red."
Btw, you may have a pseudonym, but I don't consider you anonymous. You
are familiar enough to no longer appear anonymous. :-)
Coffee, it took nuts to stir up Tad Patsek's oatmeal on some stinking shale
gas play; I'll give you that. He is a renown reservoir engineer having taught
at one of the best, if not THE best petroleum engineering schools in the
entire world. He is a "distinguished" member of the Society of Petroleum
Engineers. The SPE does not hand those out to anyone. I have set in on his
lectures, and his talks; he is a good man and I can assure you he has only
the need for truth in his heart about the future of hydrocarbons.
You, on the other hand, are anonymous and won't say why exactly you are
such a adamant cheerleader for the shale industry. You "claim no special
insight" in shale matters yet you are willing to go toe to toe with a reservoir
engineer who taught tens of thousands of petroleum engineers to deal with
facts, the science of the rock and how to extract the hydrocarbons from
that rock…profitably. Forgive me, but you appear to simply be using stuff
you glean from the internet, most of which is put there by shale companies
themselves.
You cannot credibly root for an industry based on MCF's, or monster IP's,
and not dollars, sir. It has to make money. For instance, 16.5 BCF wells
in 3 years are war horses, for sure; at 5 dollar gas. At 70 cent gas those
cherry picked wells of yours still have not paid out and might themselves,
in yet another 3-4 years, but won't ever help pay back the sorry wells the
same company drilled nearby. Tight shale gas formations in the App basin
are displacing other gas production in the US by natural decline, not because
they are more economic. That statement put the b in bias.
For instance, 16.5 BCF wells in 3 years are war horses, for sure; at
5 dollar gas. At 70 cent gas those cherry picked wells of yours still have
not paid out and might [pay] themselves in yet another 3-4 years, but won't
ever help [to] pay back the sorry wells the same company drilled nearby
The issue of "ultimate profitability" brings us back to the "cheap, abundant
money supply" theme. Or more correctly the Feb induced regime of "cheap
credit for shale" that existed for the last 7 years. When anybody with a
rig could get loans or sell bonds because banks were flush with the Fed
money and wanted to put them to work somewhere, even if this "somewhere"
was extremely risky (somewhat similar to subprime mortgages). Add to this
the political pressure from Obama administration (energy independence theme)
and we get a unique environment for shale producers that existed probably
until the second half of 2015. This regime of abundant credit lines and
junk bond issuance for now is over.
With enough money you can make pigs fly, but you better do not stand
at the place where they are going to land.
This is the issue that Coffeeguyzz and Co fail to understand.
As a conventional oil and natural gas producer who is suffering financially
at the moment because of overleveraged shale oversupply, Mr. Coffee might
rightfully suggest that I am bias against the shale industry. Truthfully,
I want the shale industry to succeed but it must do so by standing on it's
own feet, without borrowing money from outside sources it cannot pay back.
It must develop it's remaining reserves from net cash flow, in a manner
that is commensurate with worldwide supply/ demand fundamentals, at a reasonable,
rational pace that will ensure price stability, not price volatility. It
must find a way to do that AND pay back it's indebtedness.
America has 2.8 million BOPD of conventional oil production that
is getting hammered right now largely because of an LTO industry who has
had, for the most part, no finding costs the past nine years. There are
thousands of shale gas wells in the App Basin that were drilled with borrowed
money that have been shut in for years with no takeaway capacity. I can
find no success story in that kind of stupidity.
The shale industry must find a way to make shale oil and shale gas extraction
profitable or it will play NO role in the energy future of America. The
first place to start, in my humble opinion, is to quit lying to the America
public about it's sustainability. I detest that BS. As I do cheerleading
for an industry who is about to financially implode. Thank you likbiz, and
Mr. Leopold.
I really hope that in a year or 2, we can climb out of the bunker, pat
one another on the back and say we made it through this mess. If we do…..adult
beverages are on me. Anywhere in Texas that is.
I'd just like to get to $55 WTI, because then we can go back to normal
and we could see how well LTO will do at that price.
I suspect that would not do them any good other than get some more money
out of investors, especially into the Permian companies. Share issuance,
but likely not much more debt issuance.
I hope $55 works for you. I don't think it will be enough to save the
debtor class in the oil patch. $55 won't be enough to make the PE/HF crowd
whole so I think you are right. Those days are gone.
It is going to be fascinating to watch the secured and unsecured creditors
carve up the carcasses in the LTO & shale gas. Where is all that off balance
sheet financing going to land?
Carrion and dead carcasses everywhere. We are going to need a lot of
vultures to clean up the dead and dying.
The IRS is standing at the head of the line to get its cut. A lot of
liens are going to be filed and bank accounts frozen.
As I peck away here, creditors are putting in lock boxes to intercept
account receivable payments. Debtors are intercepting the lock boxes to
keep funds away from creditors. Local bank accounts are being closed and
funds are redirected to the home office (some out of the country)
Ever tried to secure a place in line with the other creditors when the
debtor files for bankruptcy outside the USA?
My main argument that production potential of all shale plays
in the U.S. has been vastly exaggerated for political and propaganda
reasons is unchanged and now supported by sufficient data.
And for economic reasons too. The principal question here is "Whether
deferred adjustment to higher oil prices is beneficial to the USA economy
in a long run?". They were definitely beneficial to "team Obama", but this
might well be "after us deluge" type of thinking.
"... What matters for a company's bottom line is the average output of all there wells. I imagine if you take a close look at the 10k you can determine how many producing wells they have and what their total output is, pretty sure it is going to be about 5 to 10% of that monster well, maybe less. Talk of the best well is a red herring. ..."
"... Don't understand why they don't recognize this and just complete their DUCs (if it will not result in cash burn, at current oil prices it will) once prices make it profitable to do so. Enno Peters has more data so perhaps he sees something that I do not. ..."
"... According to Enno, the average productivity for Pioneer's wells in the Permian is much lower than what the company shows in the presentation. ..."
"... Enno Peters' numbers for 629 Pioneer's wells that started production in Spraberry formation in 2015 show ~34 kbo average cumulative production for the first 3 months. Pioneers's numbers for 11 wells in 4Q15 show ~60kboed (48 kbo, assuming 80% oil)As in all shale companies' presentations, the numbers for individual wells is simply cherry picking ..."
"... Anyway, a likely reason for the increased productivity for the well is much due to the fact the the wells are drilled longer. I have a source (unfortunately not in English) saying that 1st generation fracking wells were 200-300m long, second generation wells up to 2-3km, with increased number of explosions. No wonder the well productivity goes up. ..."
"... I suspect that the parameter "Production/area" would be more meaningful and most likely not show such a large an increase, maybe even a decrease. ..."
"... Remember an oil man really doesn't care about the oil produced, it is the dollars produced that is the aim. So to the oil company oil per unit area is not something they would really consider. They are really interested in the oil produced per dollar spent, but most interested in the profits produced. Often the higher productivity wells are more expensive to complete (more frack stages, more proppant, or longer laterals), if they spend 10% more on the D+C and get 15% more output from the well (especially if the extra output happens early in the life of the well) that is money worth spending. ..."
"... Usually they figure out the optimum setup after 2 or 3 years, eventually sweet spots will run out of room and well productivity will decrease, so far there is little evidence of well productivity decrease in the Bakken or Eagle Ford. ..."
"... I still think the 2015 average Permian well will have an EUR over 180 months of under 210 kb, similar to the average Eagle Ford well and at $8 million per well and current oil prices, these wells should not be drilled. ..."
"... Pioneer does have a few big Sprayberry wells, but most will never produce more than 300-400K barrels of oil, absent refracks or EOR breakthroughs. Most seem to really tail off after hitting 75-150K BO, and will produce the remainder over the next 20-40 years. At least that is what I see generally. ..."
Richard Zeits raised some eyebrows with his latest Seeking Alpha post
projecting Cabot's Susquehanna county wells (northeast PA) with putting
out 27 Bcf EUR … a seemingly preposterous number for an $8 million well.
Thing is, their #1 producer in the Marcellus, the T Flower 2, has ALREADY
produced 16 1/2 Bcf in three years time.
What matters for a company's bottom line is the average output of
all there wells. I imagine if you take a close look at the 10k you can determine
how many producing wells they have and what their total output is, pretty
sure it is going to be about 5 to 10% of that monster well, maybe less.
Talk of the best well is a red herring.
Pioneer's average well in 2015 looks like it has high output for 10 months
and then looks like it will revert to the average 2011 well profile from
months 12 to shut in. I would estimate the EUR on these wells is about 160
kbo at most, adding in 20% natural gas would get the well to maybe 200 kboe
of oil, NGL, and natural gas (in boe) for a URR. The return on these wells
will be negative.
Don't understand why they don't recognize this and just complete
their DUCs (if it will not result in cash burn, at current oil prices it
will) once prices make it profitable to do so. Enno Peters has more data
so perhaps he sees something that I do not.
I have also looked at Enno Peters' recent post on the Permian.
According to Enno, the average productivity for Pioneer's wells in
the Permian is much lower than what the company shows in the presentation.
Enno's numbers are for total wells, and the presentation mentions only
those wells that were completed in 2015. There were obviously improvements
in average productivity in the past few years, but I doubt that they were
that big.
I know Enno cautions on reading too much into the the last couple months
data, as it can wriggle around a bit, but if PDX's 2015 wells continue as
shown in your graph, it may just mean that PDX were just trying a little
too hard to get good production figure from the Sprayberry, and potentially
are going to pay the price for this over production with long under performance
of the well.
Enno Peters' numbers for 629 Pioneer's wells that started production
in Spraberry formation in 2015 show ~34 kbo average cumulative production
for the first 3 months. Pioneers's numbers for 11 wells in 4Q15 show ~60kboed
(48 kbo, assuming 80% oil)As in all shale companies' presentations, the
numbers for individual wells is simply cherry picking
Anyway, a likely reason for the increased productivity for the well
is much due to the fact the the wells are drilled longer. I have a source
(unfortunately not in English) saying that 1st generation fracking wells
were 200-300m long, second generation wells up to 2-3km, with increased
number of explosions. No wonder the well productivity goes up.
But I wonder how meaningful this parameter is. I suspect that the
parameter "Production/area" would be more meaningful and most likely not
show such a large an increase, maybe even a decrease.
Remember an oil man really doesn't care about the oil produced, it
is the dollars produced that is the aim. So to the oil company oil per unit
area is not something they would really consider. They are really interested
in the oil produced per dollar spent, but most interested in the profits
produced. Often the higher productivity wells are more expensive to complete
(more frack stages, more proppant, or longer laterals), if they spend 10%
more on the D+C and get 15% more output from the well (especially if the
extra output happens early in the life of the well) that is money worth
spending.
Usually they figure out the optimum setup after 2 or 3 years, eventually
sweet spots will run out of room and well productivity will decrease, so
far there is little evidence of well productivity decrease in the Bakken
or Eagle Ford. In the Permian in 2015 it looks like high output in
the first 13 months has hurt the well productivity for months 15 and later
bringing the well to the level of the 2011 or 2012 wells after month 13.
It is also possible that the last data point (month 13 for the 2015 wells)
is based on too few wells to be reliable and may be statistical noise.
I still think the 2015 average Permian well will have an EUR over
180 months of under 210 kb, similar to the average Eagle Ford well and at
$8 million per well and current oil prices, these wells should not be drilled.
I have a data subscription and have finally broken down and paid a little
$$ to satisfy myself about both the Permian hz wells, and also the OK hz
wells.
I cannot legally reproduce the data, but my view is:
A. Enno's data is trustworthy re Permian.
B. The OK hz wells are generally gas wells, with associated liquids,
which rapidly deplete. Will not impact US oil production in a meaningful
way. Some prolific gas wells, however.
Pioneer does have a few big Sprayberry wells, but most will never
produce more than 300-400K barrels of oil, absent refracks or EOR breakthroughs.
Most seem to really tail off after hitting 75-150K BO, and will produce
the remainder over the next 20-40 years. At least that is what I see generally.
Now compare what is said about those excellent wells IPs, EURs and D&C costs
with Pioneer's actual 2015 results.
With annual average WTI oil price of $48.66 + hedges, the company posted
net loss of $273 million.
Oil and gas revenues were $2 178 million,
Net derivative gains: $ 879 million;
Net gain on disposition of assets: $782 million.
So, without hedges and gains on asset sales, Pioneer's net loss would be
much bigger.
Now look at their cash flow statement:
Net cash provided by operating activities: $1 248 million
Cash capex: $2 393 million;
Negative free cashflow: $1 145 million.
Not surprisingly, they had to borrow almost $1bn and sell assets for
$553 miilion.
And this is one of the leaders in the shale sector!
CLR and WLL have ceased completing oil wells. They are projected to lose
major $$.
BTW, it looks like CLR Red River wells will wind up being a much better
investment at $30 oil than their Bakken and TFS wells are. Those Red River
wells cost a fraction of the Bakken/TFS and will wind up producing similar,
if not superior cumulative oil per well.
What happens if it is nationalized? The shareholders might get, say,
a 10% premium over market price for their shares (making them happy), paid
for with printed money.
The employees get gov't benefit packages and the executives even have
a bonus plan like AMTRAK or USPS.
"... The shale industry must find a way to make shale oil and shale gas extraction profitable or it will play NO role in the energy future of America. The first place to start, in my humble opinion, is to quit lying to the America public about it's sustainability. I detest that BS. As I do cheerleading for an industry who is about to financially implode. Thank you likbiz, and Mr. Leopold. ..."
As a conventional oil and natural gas producer who is suffering financially at the moment because
of overleveraged shale oversupply, Mr. Coffee might rightfully suggest that I am bias against
the shale industry. Truthfully, I want the shale industry to succeed but it must do so by standing
on it's own feet, without borrowing money from outside sources it cannot pay back. It must develop
it's remaining reserves from net cash flow, in a manner that is commensurate with worldwide supply/
demand fundamentals, at a reasonable, rational pace that will ensure price stability, not price
volatility. It must find a way to do that AND pay back it's indebtedness.
America has 2.8 million BOPD of conventional oil production that is getting hammered right
now largely because of an LTO industry who has had, for the most part, no finding costs the past
nine years. There are thousands of shale gas wells in the App Basin that were drilled with borrowed
money that have been shut in for years with no takeaway capacity. I can find no success story
in that kind of stupidity.
The shale industry must find a way to make shale oil and shale gas extraction profitable or
it will play NO role in the energy future of America. The first place to start, in my humble opinion,
is to quit lying to the America public about it's sustainability. I detest that BS. As I do cheerleading
for an industry who is about to financially implode. Thank you likbiz, and Mr. Leopold.
I really hope that in a year or 2, we can climb out of the bunker, pat one another on the back
and say we made it through this mess. If we do…..adult beverages are on me. Anywhere in Texas
that is.
I'd just like to get to $55 WTI, because then we can go back to normal and we could see how
well LTO will do at that price.
I suspect that would not do them any good other than get some more money out of investors,
especially into the Permian companies. Share issuance, but likely not much more debt issuance.
I hope $55 works for you. I don't think it will be enough to save the debtor class in the oil
patch. $55 won't be enough to make the PE/HF crowd whole so I think you are right. Those days
are gone.
It is going to be fascinating to watch the secured and unsecured creditors carve up the carcasses
in the LTO & shale gas. Where is all that off balance sheet financing going to land?
Carrion and dead carcasses everywhere. We are going to need a lot of vultures to clean up the
dead and dying.
The IRS is standing at the head of the line to get its cut. A lot of liens are going to be
filed and bank accounts frozen.
As I peck away here, creditors are putting in lock boxes to intercept account receivable payments.
Debtors are intercepting the lock boxes to keep funds away from creditors. Local bank accounts
are being closed and funds are redirected to the home office (some out of the country)
Ever tried to secure a place in line with the other creditors when the debtor files for bankruptcy
outside the USA?
My main argument that production potential of all shale plays in the U.S. has been vastly exaggerated
for political and propaganda reasons is unchanged and now supported by sufficient data.
And for economic reasons too. The principal question here is "Whether deferred adjustment to
higher oil prices is beneficial to the USA economy in a long run?". They were definitely beneficial
to "team Obama", but this might well be "after us deluge" type of thinking.
"... Oil price collapse basically ended. Oil price recovery started. Shale industry collapse just started. ..."
"... I'm not so sure the oil price collapse has ended. I agree the shale industry collapse has started and it will continue to snowball. ..."
"... In any market, when the top is in, it is hard to see. Also, when the bottom is in it is hard to see. I always read financial "news" with a skeptical view. Tonight, Bloomberg says the number of oil shorts is up – probably because the proposed production "freeze" will not work. ..."
"... So, where is any net increase in production going to come from? Score one for Iran. But, how about the rest? Such as USA, SA, Russia, Iraq, Canada, Angola, Nigeria, Venezuela, Libya, North Sea, Brazil, Mexico, Kuwait. So, a production "freeze" agreement is pointless anyway. ..."
"... Oil shorts have life so good. Iran, KSA and Russia just keep taking turns saying unhelpful things. Where does it end? ..."
"... We are reading Western MSM which tend to distort things that those countries representatives are saying. This is especially true for Iran. ..."
"Of course there is going to be much more carnage in the oil patch. After all, a decade
of coordinated money printing by most of the world's central bank eventually generated spectacular
levels of excess capacity and malinvestment in the global oil and gas patch."
"Instead, the current massive overhang of surplus stocks and excess production capacity
is owing to the drastic mispricing of capital and the temporary bubble in petroleum demand
that pushed prices into an artificial and unsustainable triple digit range.
Accordingly, the present oil price collapse is just getting started. It will be subtracting
from CapEx and production levels in the US and around the world for years to come."
In any market, when the top is in, it is hard to see. Also, when the bottom is in it is hard to
see.
I always read financial "news" with a skeptical view. Tonight, Bloomberg says the number of oil
shorts is up – probably because the proposed production "freeze" will not work. So, let's all
agree that a production freeze is not going to be agreed to.
So, where is any net increase in
production going to come from? Score one for Iran. But, how about the rest? Such as USA, SA, Russia,
Iraq, Canada, Angola, Nigeria, Venezuela, Libya, North Sea, Brazil, Mexico, Kuwait. So, a production
"freeze" agreement is pointless anyway.
"... Thanks for the analysis and forecast of Norwegian crude oil production. Figure 01 shows that combined output of the currently producing fields will drop from 1.57mb/d in 2015 to around 250 kb/d in 2030. That implies an average annual decline rate of 11.5%. ..."
"... Looking at the total production from fields started as of 2004 and 2012 these had a year over year decline of more than 15% from 2014 to 2015. ..."
"... This illustrates how many smaller fields with short plateaus and steep declines influences the total decline rate and until Johan Sverdrup starts to flow, these smaller fields' portion of total extraction will grow. ..."
"... The low oil price recently caused the Vette development to be scrapped. All things equal this makes for a steeper decline in total extraction than what is now reflected in my forecast. ..."
"... I am [and have for some years been] firmly in the camp that think it will take a loooooong time before we again see a sustained $100+/b [$2016], even as the present supply overhang from whatever reasons comes to an end. ..."
Thanks for the analysis and forecast of Norwegian crude oil production.
Figure 01 shows that combined output of the currently producing fields will
drop from 1.57mb/d in 2015 to around 250 kb/d in 2030. That implies an average
annual decline rate of 11.5%.
Decline for the fields that were producing in 2001 during the period
to 2013 was about 9% per year. Is this projected acceleration due to the
rising share of the small deepwater fields with higher decline rates? What
are combined decline rates for the old mature fields?
What are your oil price assumptions? Do you think that potential sharp
increase in oil prices after 2020 may slow production decline, like in 2014-15?
For several of the mature fields that still contributes meaningfully,
the developments of discoveries within their business areas (like Gullfaks,
Oseberg) and infill drilling [made commercial/profitable from a higher oil
price] makes it now difficult to pull out/estimate their [call it "underlying"]
decline rates [from data in the public domain] post these developments.
The reserves added from these developments and infill drilling are reported
within the business areas [reserve growth].
For all fields started before 2002;
From 2012 to 2013 the decline slowed to 2 %/a.
From 2013 to 2014 extraction grew about 3%/a.
From 2014 to 2015 extraction grew about 2%/a.
Several of the decisions that led to this reversal was made while the oil
price was high and thus funding available.
Looking at the total production from fields started as of 2004 and
2012 these had a year over year decline of more than 15% from 2014 to 2015.
(Grane [reserves 900+Mb] started in 2003 and saw a slowdown in its decline
in 2015.) This illustrates how many smaller fields with short plateaus
and steep declines influences the total decline rate and until Johan Sverdrup
starts to flow, these smaller fields' portion of total extraction will grow.
As alluded to in the text I have not made any oil price assumptions for
the forecast [which is based on sanctioned developments]. Presently, several
fields are planned plugged and abandoned (P&A) as the lasting, low oil price
has shortened their economic life. Plans now call for Jette, Varg, Volve
to be P&A later this year.
More will follow according to various sources.
The low oil price recently caused the Vette development to be scrapped.
All things equal this makes for a steeper decline in total extraction than
what is now reflected in my forecast.
I am [and have for some years been] firmly in the camp that think
it will take a loooooong time before we again see a sustained $100+/b [$2016],
even as the present supply overhang from whatever reasons comes to an end.
"... At some point people realize that the emperor has no clothing. ..."
"... And that also gives an explanation to Dennis' supposition that rigs will fly at $50 oil (or maybe pigs will fly). Using the same numbers at $50, you get a negative return on a well that produces 148k over 36 months. Who can afford to wait 36 months in this environment, anyway? ..."
"... They have been completing wells at $40/b or less, I agree nobody is making money at these prices, but if you have already spent $2 million to drill and case a well, that horse has left the barn. Now the question is do you spend another $3.5 million to frack and complete the well so you can generate some cash flow to keep the lights on. ..."
"... When these companies are losing money, which I am confident was the case in 2015, and will likely be the case in 2016 also, income tax is zero, I think. Perhaps 30% would be a better number for royalties and taxes in Texas, 27% was a guess on my part. ..."
"... Note that 148 kb is the average cumulative output over the first 36 months of the average 2013 to 2015 Eagle Ford Shale(EFS) oil well. ..."
"... I think the rule of thumb is that the payout in 36 months means the well is acceptable for Mike who is conservative, the shale players are not very conservative financially so 36 months would be outstanding as far as they were concerned. If the well cost was $6.5 million simple interest would be $325,000 at 5% and would be covered by the well in our example above, land and development costs might be covered by associated gas, I don't have numbers on that. ..."
"... Let's assume no associated gas (unlikely to be the case) and using Reno's land numbers from below say land and development costs are $350k/well, then we would need $83/b for the well to pay out in 36 months for the average well. ..."
"... So if we need $83 to payout in 36 months, the current price is $38 and the NYMEX strip for 36 months is well below $50 WTI, why are there any wells being drilled and completed in the EFS? ..."
"... Commodity markets can remain irrational longer than many can stay solvent, unfortunately. ..."
"... I am getting a little more conservative in my price predictions seeing maybe $50/b by Dec 2016 and maybe $80/b by Dec 2017, but the faster output falls the quicker the turnaround in oil prices will be. ..."
"... The main and probably only reason they are drilling in non-sweet spots in the Eagle Ford, now, is to hold the lease. I think, even the DUCs that are being completed now fall into that category. Or, in some cases, like Dennis says, the completion cost as current year capex would be covered. The only reason a company would drill with a three year payout, is if they had adequate lending or capital resources. Otherwise, they well should mainly pay for itself the first year, or they lose the capex for next year in cash flow loss. ..."
"... Most of the revenue is in the first year, about 63% of the oil flows in the first year. For the well to pay out in the first year would take an oil price of $117/b, but after a few years of wells you have cash flow not just from this years wells but the cash flow from previous years as well, this is why the 36 month rule probably works, to get the operation started you would need to borrow some money, but if you do it right you pay off those loans after 5 years or so and then work from cash flow and never need to borrow money, if you do it right and don't have oil prices in the toilet for a couple of years. ..."
"... Why are the shale guys given massive lines of credit based on the" assets" that are still in the ground and essentially worthless in today's market? ..."
"... "Analysts" are projecting a 30% haircut on the shale guys lines of credit in April, why only 30%? How about 100%? ..."
"... I just don't see the hyped OK plays adding much crude, based on available data. Would be neat if all states had ND data. ..."
At some point people realize that the emperor has no clothing.
Quick question on Eagle Ford.
Assume
transport cost= $5/b
royalty and taxes=27% of wellhead revenue
OPEX+ water disposal=$6/b
downhole maintenance+repair=$10,000/month
cumulative output=148 kb over 36 months
well cost=$6.5 million
refinery gate oil price=$77/b
With the assumptions above the net revenue per barrel is $44.13/b and
the cost of the well is covered in 36 months (with no discounting).
Mike has often said he wants his wells to "pay out" in 36 months at minimum
(he prefers 24 months, I would prefer 12 months :- ). At $77/b at the refinery
gate and 148 kb cumulative in 36 months, does the well meet those requirements
under the assumptions I have given?
How might you revise the assumptions to make them more realistic? What
am I missing, if it does not require a book length answer :-) ?
Assume $11 LOE, water disposal, transport cost = $1,302,400.00
Assume $10K per month of "maintenance CAPEX" = $360,000.00
Subtract those two figures from our net oil = $6,816,224.00
You payout in 36 months, assuming no interest expense. Also, need to
allocate lease acquisition cost, seismic, permitting etc., to our well.
On the plus side, we need to also figure in the gas/natural gas liquid revenues.
Also, need to see how income taxes figure in. Also, not sure if LOE is correct,
does it include county ad valorem taxes?
So in 36 months, we still need to pay our interest expense, our up front
land and development costs. Maybe some income tax, maybe we need to add
ad valorem taxes.
Oh, also, where is our G & A allocation? Or is that included up there
somewhere? That seems to be running about $2-4 per BOE (note not BO, and
likewise, all other expenses are always set forth as BOE, so we need to
know our GOR to adjust for that maybe?)
Finally, should we factor in time value of money, or if we add actual
interest expense does that solve the problem? I agree interest rates are
super low, maybe we should us PV8 or PV7? Rune and I have discussed this
some.
I assume this is a pretty darn good EFS well? I guess just need to look
at shaleprofile.com don't we?
Dennis. I suppose your example is close to what will be the "average" EFS
well in 2016.
One thing to remember, the EFS has different "windows" and many areas produce
all, or mostly gas.
Sánchez Energy is a prime example. Only 37% of 2015 production was oil.
Their Catarina area is mostly gas and natural gas liquids, yet it is their
primary field, and well costs are much lower.
Sánchez plans on completing 55 net wells, 36 in Catarina. This compares
to 116 well completions in 2015, companywide. Cost for all wells will be
$180-220 million, only 3 net DUC wells from 15, rest are new drills. Plan
on spending another $20-30 million on facilities.
Just some EFS company info that might interest some.
I suggest looking at Sánchez Energy's 2015 10K. Very detailed.
One area they reported was royalty burdens. Those range from 20.9% to
30.5%. I think royalty burdens are more onerous in EFS than Bakken, I think
25% is very common, and 30+% is not unheard of.
Despite a high percentage of gas, Sánchez production expenses (which
appear to include gathering and transport) were $8.16 per BOE. Production
and ad valorem taxes were$1.40 per BOE on realized per BOE of $24.80. DD
&A was $17.96 per BOE, interest expense was $6.60 per BOE, G & A $2.89 per
BOE, and impairments were $71.15 per BOE.
Sánchez has $435 million of cash, $1.75 billion of long term debt, PV10
of $593.5 billion, PDP PV10 of $465.5 billion.
They have two large acreage areas where they have no present plans for
new wells, very few currently producing wells, and almost no PV10, being
EFS Marquis area, and in the Tuscaloosa Marine Shale.
To achieve the above stated PV10, future production cost estimates were
slashed from $2.635 billion as of 12/31/14 to $1.745 billion as of 12/31/15.
Another interesting thing I noted that Sánchez reported, that few others
do, is that they have a NOL carry forward of $765.9 million. More interesting
is they adopted some type of plan to keep a hostile acquirer from obtaining
benefits of this NOL. Clueless, if you are out there, would love to hear
your comments on this.
Sánchez has an interest in 621 gross, 504.6 net wells.
Despite being in EFS, their oil sold for an average price of $42.98 per
barrel, well below WTI.
Their production really increased, from 43,893 boepd in Q4 14 to 58,115
boepd in Q4 15. They completed more wells in 2015 than in any prior year,
and do not appear to have DUC's.
And that also gives an explanation to Dennis' supposition that rigs
will fly at $50 oil (or maybe pigs will fly). Using the same numbers at
$50, you get a negative return on a well that produces 148k over 36 months.
Who can afford to wait 36 months in this environment, anyway?
They have been completing wells at $40/b or less, I agree nobody
is making money at these prices, but if you have already spent $2 million
to drill and case a well, that horse has left the barn. Now the question
is do you spend another $3.5 million to frack and complete the well so you
can generate some cash flow to keep the lights on.
All the G&A, land acquisition and development costs and so forth have
been allocated to other producing wells, income tax is not an issue because
last I checked you don't pay taxes when you are losing money.
When we do the calculation using all the same assumptions as before and
look only at the fracking and completion cost of $3.5 million, that cost
is paid in 36 months at $50/b.
Perhaps that is why some wells continue to be completed at $50/b, the
$40/b completions may be the best well locations that have higher than average
EUR.
EFS is tougher to get a handle on, because it is much more variable than
the Bakken in terms of GOR and well depth.
I would note SM Energy still has two rigs going in Divide Co., ND. Apparently
the wells there aren't as costly as in the core of McKenzie Co. Other than
that, seems like Bakken activity right now is centered in one area, where
things are similar.
I don't know a whole lot about EFS, but do know that some areas, like
Catarina, are almost all gas and liquids, little to no oil. Pioneer seems
to have the gassy acreage, thus zero rigs running.
I have focused on oil wells and ignore the gas and condensate wells.
In the most recent 12 months about 80% of the C+C output is from oil wells
and 20% is condensate from gas wells.
When these companies are losing money, which I am confident was the
case in 2015, and will likely be the case in 2016 also, income tax is zero,
I think. Perhaps 30% would be a better number for royalties and taxes in
Texas, 27% was a guess on my part.
The 36 month payout rule that Mike uses, would be a company that operates
by using cash flow, so interest expense would be zero, the associated gas
of the average oil well in the EFS I am not sure about, but the gas and
NGL might offset some of the LOE. I was assuming all taxes and royalties
would be covered by the 27% of wellhead revenue, does that seem too low,
maybe 30% would be more realistic?
Note that 148 kb is the average cumulative output over the
first 36 months of the average 2013 to 2015 Eagle Ford Shale(EFS) oil well.
When the 36 month payout rule is used, I thought the discount rate was
left out of the calculation. Also note that the land and development costs
is spread over many wells, what would your estimate be for these costs per
well, I have no clue.
See my Sánchez Energy post re their royalty burden and production and
ad valorem taxes per bbl.
Some acreage went for over $50K per acre. So if we are on 100 acre spacing,
that would be $5 million per well? I agree, that is extreme. So use $10K
per acre, 60 acre spacing, still $600K per well. Not insignificant. I do
not know what seismic shoots were costing, you have the bill to the land
man, and the attorney. So much of the shale plays have severed minerals,
so landowner had to be paid. Plus, look at the division of interests on
some of these shale units, usually over 100 separate mineral owners, all
have to be contacted to sign. And the land men had to run the records in
the remote county court houses to figure all of this out, very costly, leasing.
Just because Mike doesn't borrow doesn't mean shale doesn't. Wouldn't
the fact that shale borrows means they need a quicker payout than Mike,
who pays cash?
The gas in EFS is much more relevant than Bakken.
Dennis, would really help you to read some 10K. On EFS, I highly recommend
Sánchez for starters, as they are solely EFS (TMS insignificant) and have
acreage in different EFS windows, yet they break out a lot of detail on
each.
I think the rule of thumb is that the payout in 36 months means the
well is acceptable for Mike who is conservative, the shale players are not
very conservative financially so 36 months would be outstanding as far as
they were concerned. If the well cost was $6.5 million simple interest would
be $325,000 at 5% and would be covered by the well in our example above,
land and development costs might be covered by associated gas, I don't have
numbers on that.
Let's assume no associated gas (unlikely to be the case) and using
Reno's land numbers from below say land and development costs are $350k/well,
then we would need $83/b for the well to pay out in 36 months for the average
well.
Dennis, sounds good. And right now the app on my phone says WTI is $38.51.
So if we need $83 to payout in 36 months, the current price is $38
and the NYMEX strip for 36 months is well below $50 WTI, why are there any
wells being drilled and completed in the EFS?
For example, Sanchez, who has $1.75 billion of long term debt with PDP
PV10 of just $450 million, plans on spending over $200 million of CAPEX
in the EFS in 2016. They do have hedges, but they really do not help much.
See why this stuff frustrates the heck out of people like Mike and me?
It is like throwing cash in a burn barrel.
I gave an example above for why someone might complete a DUC at $50/b
for an average well.
So find your better DUCs that might produce in the 75th percentile and
maybe completing the well makes sense at $38/b, I really don't know desperate
times call for desperate measures I guess. Every oil company is secretly
hoping they can outlast the other company so that output goes down and prices
go up, this is a game of last man standing as far as I can tell.
Dennis. Pretty much all are in dire straits, I agree.
Looks like ND rig count is ready to drop below 30, at 30 today with one
to stack.
I like that you see a quick rebound in oil prices, but I think you have
been saying that for awhile.
Commodity markets can remain irrational longer than many can stay
solvent, unfortunately.
The same game is going on in the grains, there is supposedly a glut there
too, but, like oil, a world wide price trades heavily on US government inventory
estimates, with little data on stocks in huge chunks of the world.
Unfortunately, sentiment is so much more important than it should be
in the commodity markets.
I am getting a little more conservative in my price predictions seeing
maybe $50/b by Dec 2016 and maybe $80/b by Dec 2017, but the faster output
falls the quicker the turnaround in oil prices will be.
I hope for the sake of the oil guys and the environment, that oil prices
get to $85/b sooner rather than later, but you are correct that I am wrong
on oil prices more than I am right.
The reason I have been wrong is that I have expected a steep decline
in LTO output that has not occurred, when it finally happens then within
6 to 12 months we will see oil prices rise, perhaps very quickly.
Nobody knows what oil prices will be unless a huge range is chosen ($10
to $200/b for the next 5 years would probably be right, but far from useful).
The internal accounting standards that I use to drill wells, for instance
ROI and time to payout, were actually taught to me nearly a half century
ago by numerous oilmen before me. I think there is a reason that those standards
have been passed down over generations. They work. They essentially enable
an operator to be, for lack of a better term, "self sufficient." By that
I mean reserve inventory that is being liquidated can be replaced with net
cash flow, and not borrowed funds. Well costs, oil prices and risk affect
those accounting standards and when and if to pull the trigger, sure. The
same standards SHOULD apply to the shale oil industry but of course they
haven't and profitability has taken a back seat to reserve growth, which
now of course, has proven to be a dumb mistake also. Along with a half dozen
other dumb mistakes.
I won't speculate on DUC wells and when and why they would become profitable
to complete; I think perhaps it might be a mistake to assume there will
be enough money to borrow to complete those wells. I see a lot of DUC wells
being completed in the EF; in fact that is all I see being done in the EF.
Myself and others believe the rig count in the EF is grossly over exaggerated.
EF production is going to nose dive now to the rest of the year.
S. Texas is a very mature producing province and mineral owners very
savvy; 25% royalty burdens are the norm and many of those leases are burdened
with additional ORRI's. Severance taxes are 4.6% of gross revenue and ad
valorem taxes generally another 2.4% of net revenue to the WI.
Sanchez put all of its eggs in the Catarina basket several years ago
and they are under one of the most onerous drilling commitment provisions
I have ever seen. They drill it, or they lose it. That stuff is in the liquids
rich gas interface window, and close to Mexico; they appear to have a plan
of some kind. Others still drilling anything unconventional right now, anywhere,
have no plan whatsoever. They are doing stupid things with borrowed money
they will never be able to pay back at anything less than 100 dollar oil
prices, sustained. The "breakeven" metric is now even more irrelevant because
for a shale oil company to survive they must generate sufficient cash flow
to replace very high decline rate wells… AND pay back massive amounts of
accumulated debt. That ain't gonna happen and all of them, with few exceptions,
are now in Hospice care.
Not sure how to translate 2.4% of net revenue of working interest for
the ad valorem tax.
Lets take the example where Mike owns the well with a 25% royalty and
gets $40/b at the wellhead for any oil he sells, lets assume the well produced
1000 barrels yesterday and OPEX+ water disposal+ G+A+ land and development
costs + the stuff I don't know about is $15/b.
How much money does Mike take home in this example (I am unsure about
how the ad valorem tax works)?
Before taxes it looks like $25/b times 750 barrels so $18,750 of revenue,
the severance tax would be $1380, is the ad valorem only on the $15,000
of net revenue? That would be $360 at 2.4% of $15,000 net revenue. So I
think the take home (before income taxes) would be $17,010.
Probably that is wrong, I am not good at accounting.
The net revenue would be $25/b times 750 barrels or 18750 and at 2.4%
that would be $450 for the ad valorum tax, so taxes would be 1380+450=$1830
and before income tax the take home would be $16920. If the marginal income
is taxed at 35%, then the take home pay would be $10,998 if I did it correctly
this time. :-)
On that nosedive in the Eagle Ford, does Enno Peters estimate of about
60 completions per month in the Eagle Ford in 2016 sound right? The past
3 months (Nov to Jan) the completion rate has been about 145 wells per month
and for all of 2015 it was about 185 wells completed per month. So a rate
of 60 per month in 2016 would be about 1/3 of the 2015 completion rate.
I expect something like 90 wells per month, but my guesses are usually not
very good.
From your comment above I am thinking that you might choose something
like 40 completions per month, maybe lower.
The main and probably only reason they are drilling in non-sweet spots
in the Eagle Ford, now, is to hold the lease. I think, even the DUCs that
are being completed now fall into that category. Or, in some cases, like
Dennis says, the completion cost as current year capex would be covered.
The only reason a company would drill with a three year payout, is if they
had adequate lending or capital resources. Otherwise, they well should mainly
pay for itself the first year, or they lose the capex for next year in cash
flow loss.
Most of the revenue is in the first year, about 63% of the oil flows
in the first year. For the well to pay out in the first year would take
an oil price of $117/b, but after a few years of wells you have cash flow
not just from this years wells but the cash flow from previous years as
well, this is why the 36 month rule probably works, to get the operation
started you would need to borrow some money, but if you do it right you
pay off those loans after 5 years or so and then work from cash flow and
never need to borrow money, if you do it right and don't have oil prices
in the toilet for a couple of years.
Maybe Hamm has better contacts on Wall Street? That's all it takes, remember
that there are different rules and laws for the regular citizens and for
those that fund campaigns. It is what it is.
Why are the shale guys given massive lines of credit based on the"
assets" that are still in the ground and essentially worthless in today's
market?
Why did the federal reserve step in during the redetermination period
last year and tell the bankers to encourage the sale of assets rather than
call the loans?
Why are some people forced to mark to market while others skate?
Why aren't guys like me and you given say a 20 million line of credit?
I wouldn't sell my soul to those assholes anyway, so no need to answer that.
"Analysts" are projecting a 30% haircut on the shale guys lines of
credit in April, why only 30%? How about 100%?
If you and I were running a pretend business, would they loan us a lot
of money and then look the other way when it all heads south on us? They
would if Wall Street has figured out how to make big bucks and on it.
One thing some argue is that CLR has so much acreage that they got so cheap.
My response to that is go look at how much they have expiring. They are
not completing any wells in Bakken, meaning all of their acreage in ND and
MT is very uneconomic at Q1 prices.
So we are left with the mostly gassy OK acreage, with wells that are
more costly than, but far less productive than the Marcellus. Again, we
really need better info, but CLR companywide went from 70% oil 30% gas in
2014 to projected 60%/40% in 2016.
Their BOE is poised to drop 10% in 2016, but oil will drop much more
steeply.
I just don't see how under $2 gas works, although they do have some gas
hedged, unlike oil.
So if an OK well produces 70% gas and ngls, hypothetically, with wellhead
oil of $35 and gas of $1.75, per BOE is just $17.85. Over the life of the
well, ignoring all other expenses, you are looking at just under $20 million
of gross revenue using their EUR of 1.1 million BOE. That is over 30 plus
years, I assume.
I don't get SCOOP and STACK attractiveness. Devon did pay big $$ for
acreage there recently, another head scratcher, especially given their enormous
Barnett shale exposure, which right now is likely negative on an operating
basis. DVN used to be cream of the crop independent, but have to wonder?
OK C + C production per day per EIA has fallen from a peak of 473K in
3/15 to 400K in 12/15, very steep, and even steeper when you consider there
is a stripper production C + C base of 130-150K per day (although it likely
declined at least 10% as well during the same timeframe).
I do agree, part of the collapse is due to Mississippian activity falling
off the table. See SD and CHK, for example.
I just don't see the hyped OK plays adding much crude, based on available
data. Would be neat if all states had ND data.
"... The last few years have shown declining oil discoveries since 2010. What has been found is more often than not deep water and relatively small. Such fields generally have short plateaus and steep decline rates (not much better of those seen in LTO for fields less than about 150 million barrels). The larger basins found offshore have been in the 5 to 10 mmboe range rather than around 50 found in the earlier days. ..."
"... There has been a noticeable reduction in development times for projects in GoM and North Sea in recent years from around 7 years down to as low as 3. That to me indicates a dearth of good, large projects to choose from. ..."
In terms of a C&C peak pushed out for 10 years my question would be "Where's the oil?" even at
$120 per barrel.
Apologies that the following is too long, with no charts for many (or any) to read all the
way but some parts may be of interest.
The last few years have shown declining oil discoveries since 2010. What has been found is
more often than not deep water and relatively small. Such fields generally have short plateaus
and steep decline rates (not much better of those seen in LTO for fields less than about 150 million
barrels). The larger basins found offshore have been in the 5 to 10 mmboe range rather than around
50 found in the earlier days.
I don't have access to IHS or Rystad databases but picking amongst recent press releases I'd
say 2013 was about eight billion, 2014 nine or so and 2015 four or five. This year maybe only
three discoveries with a significant amount of oil – Kuwait might be significant. More gas than
oil is being found
There has been a noticeable reduction in development times for projects in GoM and North Sea
in recent years from around 7 years down to as low as 3. That to me indicates a dearth of good,
large projects to choose from.
Of some of the main producers:
Saudi; 50% increase in rig count since 2012 to keep production just about steady, announced
"the most fields discovered" in 2012 or 2013 but a combination of oil and gas and they didn't
give quantities, have spoken of developing tight gas and solar to allow increased oil exports.
Russia; some conflicting announcements but it looks like a decline next year, largest recent
find was by Repsol at about 240 mmboe. Sanctions have had an impact and may continue to do so,
especially offshore.
http://uk.reuters.com/article/uk-russia-oil-rosneft-idUKKCN0WV1I3
Canada; very little drilling activity, four fields coming on over the next 2 to 3 years will
add up to 400,000 bpd, but then nothing planned and at least 4 year lead times for tar sands projects.
Tar sands projects have long plateaus but it appears some of the earliest mining operations are
starting to see thinner seams so decline will become more evident.
Brazil; cut backs in developments and may start to decline next year, they have mostly deep
water production with high decline rates and rely on continuous stream of new projects to maintain
production – the oil price, 'carwash' scandal, debt/bankruptcy problems and (maybe) just running
out of suitable projects have stopped this, expect 6 to 10% decline through 2017.
http://oilprice.com/Energy/Crude-Oil/Future-Of-Brazils-Oil-Industry-In-Serious-Doubt.html
USA; discussed a lot here, some expansion in GoM through 2017, unknown response to LTO drillers
depending on price and credit availability, liquids from gas have been another significant and
rapid boost to production recently which EIA indicate are still rising (mostly for NGLs), but
surely must run out of steam sometime soon. Possibly some shut in stripper wells won't be worth
restarting.
http://www.theenergycollective.com/u-s-production-of-hydrocarbon-gas-liquids-expected-to-increase-through-2017/
China; reliant on EOR recently to maintain plateau (including a lot of steam flood from the
EIA report) but predicting 5% decline next year, no great success on offshore discoveries.
North Sea; saw a spate of projects recently, mostly heavy oil, with a few more to come over
the next two years and then Johan Sverdrup and Johan Castberg but these only delay decline for
2 or 3 years, recent discoveries especially in UK sector have been very poor.
Offshore Africa; Nigeria and Angola have a number of projects this year and next ( a bit more
oil than gas), but after that I'm not clear, political unrest might be particularly important
here as well. That said recent exploration success has been relatively good in Africa overall
(e.g. Kenya, Ghana).
http://www.offshore-technology.com/projects/region/africa/
Venezuela; not sure if their numbers can be trusted but they seem to be in decline, I know
little of their particular technical issues but assume that in order to increase extra heavy oil
production they would need new upgraders and possibly a source of natural gas, like Canada, and
possibly dedicated refineries to handle the heavy metal content (and assuming they can find willing
creditors and EPC partners).
Iran and, possibly, Iraq and Kuwait look like the only likely areas that can show some increase,
but Iran is developing South Pars gas field more than oil and Iraq/Kurdistan might have run out
of impetus. Burgan field in Kuwait looks in better shape than other aging super giants and Kuwait
has an active exploration and development program. And of course maybe US LTO takes off again,
$80 appears a threshold but that is for WTI, ND oil has a $10 discount, the lighter LTO oil everywhere
may be lower still and overall away from the sweet spots above $100 might be nearer the mark.
The seven largest oil majors have shown declining reserves of 1 and then 2 billion barrel equivalent
over the last two years – this may be purely price related, but I'm not so sure especially with
BP, Shell and Chevron looking to sell assets, also I don't have the figures but I'd guess that
they have lost more in oil reserves as some of their big finds have been for gas.
To ramp up of production is going to be dependent on a work force which was aging and retiring
in 2014 and now has been decimated by layoffs and recruitment cut backs. Increasing prominence
of environmental issues may hinder both future recruitment efforts and the pace at which projects
can be developed. Significant new oil, including reserve growth, has to come from deep water –
those rigs are complicated and very expensive to run, a lot are currently being stacked.
Ramp up also needs the main stakeholders to regain their acceptance of financial risk, which
is currently as low as I can remember, and significantly higher sustained prices. The other side
to the equation for prices is demand. The world economy doesn't look great to me, we're due a
recession based on approximate 8 year cycles, TPTB have chucked everything but the kitchen sink
at it and industrial output is definitely in decline or growing only slowly (I don't know how
energy use is split for service versus manufacturing but I'd guess it's of smaller relative importance
in the service sector). A relatively small oil price increase might be enough to kick a recession
off properly.
Hubbert Linearization of C+C less oil sands suggests about 2500 Gb for a URR, in the past this
method has tended to underestimate the URR, we have produced about half of this so far. There
is also about 600 Gb of URR in the oil sands of Canada and Venezuela. The USGS estimates TRR of
C+C less oil sands at about 3100 Gb, I use the average of the HL estimate and USGS estimate with
a URR of 2800 for C+C less oil sands and oil sands URR of 600 Gb. Total C+C URR is 3400 Gb in
my medium scenario. If extraction rates continue to grow at the rate of the past 6 years and then
level off we get the scenario below.
Model based on Webhubbletelescope's Oil Shock Model.
The collapse in oil prices has demolished investment in new projects,
the results of which will be felt in the 2018 to 2021 timeframe, due to
multiyear lead times
Oil production in the UK actually
increased a bit in 2015, after about two decades of steady declines.
The additional 100,000 barrels per day came from new offshore oil projects
that were initiated in 2012 when oil prices were much higher, plus extra
oil squeezed out from existing fields.
The collapse in oil prices has demolished investment in new projects,
the results of which will be felt in the 2018 to 2021 timeframe, due to
multiyear lead times. The number of new projects greenlighted in 2015 was
less than half of the level seen in 2013 and 2014.
As a result, beginning in 2018, the UK could see more severe production
declines.
Oil prices have hovered at $40 per barrel for much of the last week, as the
markets try to avoid falling back after the strong rally since February.
Investors
see shale production falling and demand continuing to rise, which point to the
ongoing oil market balancing.
But it is unclear at this point if the rally from
$27 per barrel in February to today's price just below $40 per barrel is here
to stay. Fundamentals, while trending in the right direction, are still weak.
India consumed 4.2 million barrels per day (mb/d) in 2016, overtaking Japan as the world's third largest oil consumer. The Indian
government is hoping to incentivize domestic oil production to help meet rising demand.
Shale Euphoria: The Boom and Bust of Sub Prime Oil and Natural Gas
Introduction
The aim of this article is to show that the shale industry, whether extracting oil or gas,
has never been financially sustainable. All around the world it has consistently disappointed
profit expectations. Even though it has produced considerable quantities of oil and gas, and enough
to influence oil and gas prices, the industry has mostly been unprofitable and has only been able
to continue by running up more and more debt. How could this be? It seems paradoxical and defies
ordinary economic logic. The answer is to be found in the way that the shale gas sector has been
funded. It is part of a bubble economy inflated by monetary policy that has kept down interest
rates. This has made investors "hunt for yield". These investors believed that they had found
a paying investment in shale companies – but they were really proving that they were susceptible
to wishful thinking, vulnerable to hype and highly unethical practices that enabled Wall Street
and other bankers to do very nicely. Those who invested in fracking are going to lose a lot of
money.
"America's tradition of anti-intellectualism puts a low premium on careful thinking, allowing
the substitution of slogans for analysis. The current presidential campaign should be evidence
enough of how true this is.
But there is another reason for resistance to careful thinking; it can be difficult and distressing,
especially if it leads to conclusions that are uncomfortable or contrary to our current beliefs.
Which brings us back to John Kenneth Galbraith who once said: "The conventional view serves to
protect us from the painful job of thinking."
Conventional thinking is all we are likely to get out of polls and explains why serious energy
policy thinkers continue to run up against opposition to what for a long time has been sensible
energy policy, namely, dramatically reducing energy use through efficiency and conservation measures
and rapidly switching to renewable sources such as wind and solar–sources that do not create the
triple threat of depletion, pollution and climate change posed by fossil fuels."
"In 2015, the seven biggest publicly traded Western energy companies, including Exxon Mobil Corp.
and Royal Dutch Shell PLC, replaced just 75% of the oil and natural gas they pumped, on average,
according to a Wall Street Journal analysis of company data. It was the biggest combined drop
in inventory that companies have reported in at least a decade."
"... I have grave reservations about the alleged spare capacity of Iran. The assumption is that the big, bad sanctions resulted in a huge drop in Iran's oil production. I am not buying it. I think the sanctions were a joke. For starters many nations refused to take part in the sanctions. Nations like India, china, japan and South Korea for starters. It would not be difficult to then reexport this oil to the rest of the world on the sly. ..."
2) select the "Well quality" tab and compare CLR vs all operators for
each year.
From the map there ("Top companies" tab), I see that CLR has a lot of poor
acreage scattered around the Bakken, but not much acreage in real sweet
spots, like Whiting and EOG had in the past in Mountrail. I was therefore
wondering at which WTI price do you think that CLR can drill profitable
wells in the Bakken? In my estimation they need over $50 WTI to just pay
back the cost of the well within 5 years. I come to this figure by
1) taking a rather optimistic 200k barrels of oil output within 5 years,
for their average well.
2) subtracting a rough 30% for royalties & production taxes: 200kbo -30%
= 140kbo. $6.7m per well / 140kbo = $48 of well cost for each barrel of
oil.
3) and adding a WTI differential.
If you then add all other costs, such as lifting costs, extra CAPEX later
in the well life for pumps etc, G&A, interest, income taxes, etc, wouldn't
they need WTI to be much higher than $70-80 to be profitable on these wells?
I know non-shale operators who want to see their money back within 3 years,
so the 5 years payback time I took above is still rather risky, especially
given the faster decline of shale wells.
You mentioned that you like them
because of STACK/SCOOP, about which I don't have much info. I just hoped
you can share your thoughts on the above, as they are still big in the Bakken.
As a member of the oil fraternity for the last 45 years it is refreshing
to read a post from someone who really understands the economics of production
and the cost/benefits of today's price environment.
I don't do average payback times for companies like CLR because much
of the marginal areas wont see any development at all (unless oil prices
head much higher, which we don't see happening in the near term).
Operators will focus on core areas and this plus well design improvements
are why we have seen EURs drive higher. We probably have different estimates
as to the number of bbls produced over the first five years which would
cloud the results some.
Working core acreage and switching to slickwater, we believe these wells
will produce about 360K BO over the first five years.
$40 WTI minus approximately $13 in costs
$27 minus $7 differential
$20 x 360000 BO
7.2 million minus 6.7 million in D&C
$500K
This is probably the biggest issue right now with those bearish and bullish,
its estimates. Not saying you are wrong or that I am for that matter, just
that we will have to wait and see. To your point on acreage, it does have
a pretty decent footprint in NE McKenzie County or in the southern part
of the Nesson Anticline and those wells could produce about 450K BO in the
first five years depending on estimates. Now if we look at its acreage in
Burke, N Williams or Montana the well results are no where near as good
and that acreage will need considerably higher WTI to develop. I would also
say that you are right about 5 year payback times being way too long and
that operators use to think at least 18 months was adequate.
We are definitely in interesting times. I don't have time to do it right
now, I am heading to the gym but will try to put some quick thoughts in
on the STACK/SCOOP this evening. The reason we like CLR isn't the Bakken
and we do see production in ND dropping here more than in Texas and Oklahoma.
We actually think that we could continue to see the Permian and SCOOP increase
production while the Bakken and Eagle Ford roll over a bit. Thanks again,
real good questions and I always appreciate our conversations. Unlike some
here you are always respectful and that only adds to the current debate
on some of these names.
Re Continental's historic underperformance in its Bakken wells compared
to peers ...
1). They were VERY early movers in this play and accumulated vast acreage
at rock bottom prices.
2). This 'Land Grab' phase generally only offered 36 months in which
to get a producing well in place so as to HPB.
3). A significant portion of this acreage is now recognized as being
outside the sweet spots.
4). CLR purposefully chose a cookie cutter approach to completions, namely,
30 stage and sliding sleeve. Reasons for this were speed through repetition
(they were racing the HPB clock), relative cost reduction with operational
familiarity, and - ALSO - having a position-wide identical well design so
as to evaluate the differing resource potentials throughout their vast holdings.
The future of their Bakken wells is apt to be far more productive than their
past.
Great work gentlemen - it is indeed awesome to see experts on here. Couple
of points that might be of interest: -In case you wanted a real data point,
avg. well head price for *cough* was ~$16.86/bbl last month, probably +$3
now based on the flat price. -I saw Jim Volker two weeks ago and he said
his research lab in Denver had found "the holy grail" of shale rock oil
extraction technology.
Interesting for whiting...perhaps CLR isn't far behind. -The production
math from ND DMR does not add up to CLR's type curve slides. I'm still trying
to figure out why. Do you think reworks are baked into type curves? I thought
not. -I would attribute the lower than expected IP rates to the choke...only
a few people like Statoil like to blow their wells out (although there are
a couple of exceptions) Option B: go the classic route of rocks are bad
or poor frac design.
Michael, Thanks for your elaborate response. I also enjoy these civil debates
with you, and I appreciate your comments on my site. You do got me very
surprised by the estimates you mentioned: 360 kbo & 450 kbo in 5 years.
Those are really exceptional numbers, that so far only a few companies
been able to get in highly prolific spots in the Bakken. 360 kbo is more
than double the results of CLRs wells that already reached 5 years.
You don't expect the average well of CLR in 2015 or 2016 in the Bakken
to come close to that, right? But if you're not, then that means that your
example should be adjusted if we look at the economic performance of CLR
in ND, and that would then show that CLR would not be able to expect its
money back on all wells drilled under current conditions within 5 years
(even though we both agree that to be a very long time already), right?
Phaedrus, "The future of their Bakken wells is apt to be far more productive
than their past." Can you be more specific, e.g. indicate using ranges what
you expect, and when, from the average wells from CLR in the Bakken? Note
that it is not a given that companies improve their results in the Bakken
every year. Whiting, and EOG already have shown several years of declining
well results, as is what we can see in several locations. So far, on the
aggregate, this has been compensated elsewhere. Also, what I think is very
clearly shown on my site, on average, the main improvements have been during
the initial months of production, but not in the long production phase after
12 months. You expect CLR to buck these trends?
alpha, We have a current target of WTI to 41.80 or so, so would add to
the DWTI position into that number. $40 will be very difficult to breach
and some traders think momentum could take us to $49 in the short term,
so this trade does have significant risk. We would close this trade in the
$32 to $34 range. But if we breach $30 may climb back in. Have a great day!
It is interesting to note the following from CLR's 2015 10K: CLR suffered
from a rather large discount concerning realized oil prices. 2015 SEC oil
price was $50.28, but CLR had to discount that to $41.63 per barrel. The
gas discount resulted in utilizing $2.35 per mcf. CLR's proved reserves
dropped 9% from 12/31/14 to 12/31/15.
More importantly, however, they became much more gas weighted, as 43%
of proved reserves are gas on a BOE basis. Therefore, analysis of gas production
and future gas prices is required in analysis of CLR. A look at CLR's statement
of future cash flows is also important. In 2014, CLR's estimate of future
cash inflows was $90.9 billion.
This dropped to $35.6 billion in 2015. This is largely the result of
the commodity crash, so it is very important if a lower for longer scenario
is correct. In 2014 the estimated future production costs were $25.8 billion.
In 2015 that fell by 60% to $10.9 billion. That is a very large drop, and
I hope analysts are able to get CLR management to walk through the steps
that they undertook to achieve such a large drop in future production costs,
but yet not a similar drop in proved reserves.
I compared these results to industry leader, ExxonMobil, and CLR knocks
it out of the park, as ExxonMobil suffered about a 24% drop in proved reserves
while cutting future production costs about 29% during the same period.
CLR also cut future development cost and abandonment cost estimates from
$12.8 billion in 2014 to $6.9 billion in 2015.
These production, development and abandonment cost cuts are critical,
had they not been achieved, CLR would have negative $1 billion in estimated
net future cash flows. Estimated net future cash flows from 2014 to 2015
fell from $38.4 billion to $15 billion. Standard measure PV10 fell from
2014 $18.433 billion to 2015 $6.476 billion. CLR has never carried much
cash, 2014 $24.4 million, 2015 $11.5 million.
Long term debt increased from $5.927 billion to $7.116 billion. CLR's
traded enterprise value continues to greatly exceed its peers.
I think it would be interesting to know if there are any other industries,
besides E&P, where such a high market capitalization could be achieved,
with such a low amount of cash, such a high long term level of debt, and
with future net cash flows, utilizing a discount rate of 10%, below the
amount of long term debt. Tesla comes to mind.
Michael. Is CLR's high density Poteet Unit a good representation of the
productivity of its SCOOP assets? Are there some other wells/units you could
recommend. I have an IHS Global subscription, would like some guidance on
assets you feel would be best to review.
Good article Iran doesn't have 50 million barrels on ships anymore though.
They started selling those shortly before sanctions were lifted late last
year and have been gradually selling those takers this year not sure there
is that much left to sell. of those at this point.
22023171, Where did you get that information? As of March 17th Iran had
an estimated 51.6 million bbls in floating storage including condensate.
It has steadily increased since Oct of last year when it had 42.02 million
bbls
Bison, Production taxes in ND dropped from 11.5% to 10% since Jan 1st this
year. E.g. link at http://bit.ly/1WApDmP
Royalties : I have seen many numbers & estimates in the range of 18%-24%.
For convenience, I took 20%. Together this means that companies have to
turn over a 30% or so of production before subtracting their own costs.
Enno: I think the royalties and excise taxes are off the wellhead price,
not off of the WTI reference. So, that adds about $3 per barrel back to
the margin. (WTI-BD)*0.7 > WT*0.7-BD Because [(WTI-BD)*0.7] - (WT*0.7-BD)
= 0.3*BD ~ 0.3*10 = 3
Please review my calculation again. I didn't take the severance taxes
& royalties from the WTI reference, I took them straight off the gross production
volume.
200 kbo gross oil production volume from an average CLR well within the
first 5 years means (subtracting production taxes & royalties of 30% or
so) about 140 kbo net oil production volume for CLR, right?
Besides, my calculation wasn't meant to be ultra-precise. I also didn't
add land costs, seismic & other CAPEX, stock-based compensation, time value
of money (discount factor), or the positive contribution from some gas.
I just wanted to show that oil prices have to be materially higher than
the strip prices in order for CLR to have its money back on these kind of
wells within a reasonable time frame. I'd love it if someone could point
out to me where I am wrong on this.
Thanks. I have one comment on royalties. Most of the early drillers got
in for a lot less than the 20% you estimated. My mineral acres are 13% and
I know several others that are in the 16% range. The reason for the low
royalties is that a lot of the mineral rights owners didn't know what they
had and in hindsight got rooked out of a lot of money.
1. If you subtracted the barrels explicitly, than that would seem to make
sense so my comment is wrong.
2. I wasn't trying to nitpick one thing to shoot down an overall argument.
Just to note the one place I (thought I) saw an error. Chill. I thought
you were doing well and just wanted to hone it better.
3. Since your discussion was already about simple payback, no reason
to model time value of money. It's already understood that this not an NPV.
4. I would treat the land costs as sunk. We are trying to think about
what price of oil it takes to drill now. (Similar for long ago seismic or
infrastructure buildout.) Obviously this is a judgment call and if you acquire
new acres or build new infrastructure than you need to charge the drill-or-not
decisions with the cost. Similarly stock costs and the corporate center
G&A are a little bit of a question.
I would probably keep them clear from the project decision (if you don't
drill, do you recover those costs? Maybe, if you do a layoff like SWN did...)
Bison. I have reviewed many non-operated working interests for sale on energynet.com
located in the Williston Basin. 1/8 royalties are rare. I have seen 72-83.3%
NRI.
My understanding is land men and others were able to latch onto significant
ORI. However, go ahead and do Enno's calculation with 87.5 NRI. You still
don't get there. We stay under $50 for awhile, eventually CLR will be bankrupt.
Too much debt, not enough future net cash flow.
This is supported by the numbers in their own 10K submitted to the SEC.
It is now almost a year and a half into the worst bust my family has endured,
yet shale proponents are still in denial.
I do not deny shale is a game changer, is very important for our country,
has had many technical breakthroughs, etc. I only deny it works broadly
sub $50, or even sub $70 oil as a good, or even marginal investment.
We have enough well histories and cost statistics, including horrific
2015 earnings, massive layoffs and depressed and wildly volatile stock prices
to know that. So please acknowledge this and join me in praying shale will
stop completing wells and fibbing about $30 break even. I unfortunately
own shares in two previously good companies COP and EGN, who got caught
up in the allure of shale. One has cut its dividend and the other eliminated
it. The shares are way down, and very volatile. They only go back up if
oil prices recover.
Rig count has crashed to below 400. It continues to go down as rigs come
off contract or as projects complete. How much less drilling do you need?
Seems like they have laid the drill bit down.
I hope you are right, but what happens if WTI hits $50? I don't want a repeat
of the spring of 2015, and the resulting price crash. Look at what happened
Friday. Add one stinking oil rig, and WTI turns lower.
shallow sand, Oil price forecasts are never concrete
but some analysts think oil will see $60/bbl this year (this means we see
it, not average it), or early next year. Lets hope oil prices are much higher
next year, as it could be a tough 6 months, but if things go well the oil
markets will balance at that point.
We have discussed this before. $20 long term = destruction of the US oil
industry, which will be followed by a massive oil super spike. Commodity
volatility is not good for the world economy. What is not good for the world
economy is not good for the US economy, generally. $100 is not good. $20
is not good. But we are all entitled to our own opinions.
Very good point, Michael. I would rather see the DUC wells completed, before
rigs are added, as there is no good DUC count quoted, and it seems traders
aren't trading off that. It seems more logical to complete all DUCS, than
add rigs, if prices rise.
But, there were some long rig agreements entered
into, compared to completion agreements. I hope you are right about $60.
I hope you know my primary beef with the shale industry is the failure,
a long time ago, to acknowledge they cannot win a "to the death" price war
with Russia and Saudi Arabia. In retrospect, had this been acknowledged,
with activity limited to establishing HBP, I doubt prices would have stayed
so low. I note that prices jumped almost immediately after 10K came out,
showing there are no future net cash flows for these companies at sub $30
WTI. However, when shale continues at it, claiming massive cost and production
improvements that will make $30 work, it sends the wrong signals to the
market concerning where prices should be, IMO. What shale has done is truly
remarkable on the production side, but the companies seem to forget they
are in business to make money first. This is why EOG's $30 competition with
OPEC statement surprised me. I had viewed them as disciplined, they stated
as much, then came out with that presentation. Very confusing. In summary,
we own production in a very shallow, old field.
The field was old in the 1970s, annual decline is less than 2%. Since
1997, when I started, I have lost $$ two years, 1998 and 2015. 2015 was
worse than 1998. 2016 is setting up to be worse than 2015. An example I
use is Coca Cola. What happens to them if top line revenues drop 70%? In
one year? Or Apple, or any other company in any industry.
I agree with Mike about tracking completion crews. CLR has 135 DUCs and
expects to exit 2016 with 195. EOG has some 300. HAL and many other sources
estimate as many as 4,000 DUCs. However this includes wells on pads just
waiting for crew not higher oil price. Maybe 2,000 waiting on higher oil???
shallow sand, It would seem that many of the "better" rigs were kept on
contract and instead of paying to end the contract early they just kept
drilling for wells to be completed at a later date. I would agree with you
in that this is not a great way to run business. Spending investor money
to do work that may or may not get done depending on oil prices isn't the
best way to run a business.
Normally EOG is one of the more disciplined operators, but I would guess
everyone is a little scared, and fear does a better job than anything of
getting people to make poor decision choices. Not saying it is right, especially
since some investors don't know what is meant by such statements. Operators
seem more scared what a production decrease announcement would do to stock
prices than working for a profit. 2016 could still have significant pain
ahead. Since supply and demand is only off by a couple percent, it has just
taken way too long to correct. Something to be said for massive overproduction,
at least the bottom is hit hard and fast.
Pablomike, More importantly, how many of those are in marginal areas that
will need $70 or $80 oil to complete? Some operators were still drilling
marginal wells when this all started and then just decided to sit on those
holes and wait. I am guessing the newer DUCs are probably in core or Tier
2 type acreage, but some of this overhang could end up sitting for a while
(while some operators will go out of business and never complete). I would
say somewhere in between 4000 and 2000 is a good number, but that one I
don't know for sure.
EOG had a hefty rig penalty if they stopped all drilling. They were clear
about this on the call and that is why they are drilling DUCs. The money
is effectively gone already. Sunk cost.
They would be drilling less (maybe not at all) in the Bakken if it were
not for the rig contracts. I suspect same is true for CLR although details
were not pinned down as well in their conf call. The meme of crazy E&P companies
is overdone by the peak oilers.
Remember these are the same critics who complained about growth when
oil was at 100+. These E&Ps are very NPV oriented and they have CRASHED
the amount of drilling down. There is a limit to how fast rigs can roll
off. But we are already down to sub 400.
The backlog of DUCs is already shrinking. Wolfcamp/Bone Spring and Eagle
Ford formations - in each of those formations, the excess has fallen by
about 150-175 over the past six months, bringing the surplus to around 300
wells in each.
In North Dakota, it might not be economic. There, the number
of DUCs climbed above 1,000 in September before falling to 945 in December,
according to the latest data from the state's energy regulator.
Wood Mackenzie reckons that the backlog of excess DUCs will decline over
the next two years and return to normal levels by the end of 2017. It is
expected to fall 35% from current levels in the Bakken and 85% in the Eagle
Ford by the end of 2016.
These are excerpts from the following article released today:
So, Bakken 1,000, 300 each Permian and Eagle Ford = 1,600. Other formations?
If one excludes NG Marcellus/Utica etc, perhaps other primary oil formations
would bring total to 2,000?
Good point. I suppose we need to categorize DUCs. Some operators realize
they have poked holes in some really lousy rock and won't complete without
much higher prices. Some like WLL, while in their best core acreage, will
keep poking holes but won't complete ANY wells until prices rise. Then there
is EOG which claims profit at $30 oil but has as many DUCs as anybody.
re: DUCs. I wanted to update my previous post. After reading again the cited
Reuters article, I realize one has to differentiate between their talking
about 'excess' DUCs (above average) and actual nominal DUCs.
So, consider
the following excerpt: "Typically, average DUC inventory is around 550 in
the Wolfcamp/Bone Spring formations and around 300 in the Eagle Ford....In
each of those formations, the excess has fallen by about 150-175 over the
past six months, bringing the surplus to around 300 wells in each." So if
the surplus is 300 each, then the total DUCs would be 850 in Wolfcamp/Bone
Spring and 600 in Eagle Ford. So formation totals would = ~1,000 Bakken
+ 850 Permian + 600 Eagle Ford = 2,450 for these three formations. Anyone
have any insight on where the remaining oil primary formations currently
sit at regarding their DUCs?
I have grave reservations about the alleged spare capacity of Iran.
The assumption is that the big, bad sanctions resulted in a huge drop in
Iran's oil production. I am not buying it. I think the sanctions were a
joke. For starters many nations refused to take part in the sanctions. Nations
like India, china, japan and South Korea for starters. It would not be difficult
to then reexport this oil to the rest of the world on the sly.
Would you please comment on this important matter. Does anyone have any
inside information about this?
Agree, most of us follow news as herd effect, but devil is in the detail.
Before the sanction, Iran was export 2.5 million barrels of oil per day
but had to import almost 0.5million barrels of processed fuel, gasoline
and diesel.
Now, 4 years after the sanction starts, Iran already built up the refinery
capacity, so it will no longer need import of refined fuels; instead it
will be exporting, how much is yet to be decided. So, right there, we will
see over 0.5 million barrels of reduction in the oil to be exported from
Iran. Yes, the sanction reduced the Iranian oil export from 2.5million to
1.5million per day, but the net effect after sanction now will be less than
0.5 million per day to the world market.
40 years, I would be surprised if you didn't have reservations. You aren't
the only one. Iran's infrastructure wasn't that great before the sanctions
so I would guess they are abysmal now. I don't think they can get to 4 million
this year, but the problem with that is I am speculating so we will just
have to track its exports and see what happens. Right now, I think it would
be ok to reduce that number by 400K BO/d. I think the biggest issue is Iran
thinks its possible, so maybe there is something going on we haven't thought
about. Probably not, but it is still something to consider. I wasn't a big
fan of the sanctions either, but some politicians would say they worked.
I think it is very possible to re-export the oil the only problem is the
very large volumes Iran can produce. If this was a small producer it is
probably easy if you sell it cheap enough (like ISIS does).
FracDaddy, I agree on EOG, but I wouldn't say they are really Bakken focused.
I think they like the Eagle Ford and Delaware Basin better. I would probably
call them a top Eagle Ford pick though. Hess has done a great job with costs
and has excellent margins, but they are still doing sleeves for the most
part, and I don't think they offer as much from a growth in production per
foot perspective. I probably like EOG more and HES less than CLR but I wouldn't
say I dislike any of them.
Do you know why CLR drilled much less number of wells in the
Springer than the Woodford below? If the economics for Springer is much
better than Woodford as CLR said before (such hype like "3X better" is no
longer in their latest PPT), they should be targeting Springer, like they
are targeting STACK? The 300K curve in 240days in Woodford is for wet gas
or NGL, probably not even light condensate.
Looking at CLR's 2016 plan, they will drill almost zero wells in Springer.
Is it possible Springer actually is hard to drill? Studying the Springer/STACK/Meramec
and found that these stacks,although quite thick, i.e. >400', they are not
homogeneous, meaning the sweetspot layers could be hard to locate within
<50'. This is different than the Woodford shale below, where the target
is well defined, i.e. the core is in the shale. It is easy to do geosteering
using gamma.
nuassembly, I think it has much to do with what you said. They are still
getting comfortable with the Springer geology while the Woodford is already
seeing pilot projects. The Springer definitely looks better though. I cant
comment on the wetgas/NGL versus light condensate comment, as Im not sure
about that.
It is possible that right now CLR doesn't want any failures given the
current economic conditions (especially with no hedge book). Thank you for
sharing your knowledge with respect to the Springer/STACK/Meramec.
You are using old info - at lot of SAGD oil sand production has half the
costs indicated in your chart. To may authors just scrape up the old obsolete
charts that are out there and use them in their articles.
marpy, Sorry if you didnt like the chart. Feel free to share links to any
charts you feel are appropriate. The article had little to do with oil sands,
but if you think PIRA's data is off feel free to correct it in future comments.
Have a good day!
Is this article a joke? Discussion the investment value of an oil company
that does not pay a dividend! Executives may be getting fat on this company,
but I doubt this result for stockholders.
Bruce909, No joke and no one is getting fat of any oil companies right now.
When investing we generally try to estimate where companies and oil prices
are going not where they are right now. I don't know what the plans are
for a dividend, but CLR and most unconventional producers aren't in a position
to do much. Thanks for the comments, and glad I could make you laugh :)
I don't see why HBP drilling a couple years ago was such a great decision.
After all, the costs were higher at that time, then they are now.
Also, the value of the acreage has dropped. Would seem to have been better
to keep the cash and wait to HBP (or let leases lapse even) now. The one
possible benefit from CLR's approach might be that they have stuck to a
plan and done a huge Design of Experiments assessment of geology and completion
techniques across the basin. And then there is some value of that. I don't
really buy that though. Don't think that kind of knowledge has as much value
in the world where marginal acreage doesn't get drilled, in a world where
downspacing is less. (Because oil is worth less.)
For that matter, I have read that many companies put too much value on
data points that they acquire themselves and too little value on the data
that is easily acquired on wells that competitors did (from logs, cores,
NDIC database, DrillingInfo, etc.). So, I don't really buy it as a rationale.
But just listing it as a possibility.
21793061, Thanks for the comment. In hind sight you are definitely correct.
I bet the mineral rights owners are happy they got the royalties they did
(and I am happy for them too, but wish Bison73 would have gotten more).
I think many thought we would have high oil prices for a long time, as not
too many thought it would be possible for unconventional production to grow
enough to cause a glut. That said, you are correct. Bigger names with some
cash will make out like bandits, as they are able to add acreage at what
will look like great deals in a year or two.
217930681 CLR actually has small working interests in a great many of the
wells that their peers drilled with operational control. Hamm has said repeatedly
that CLR studied and learned just about everything that occurred with these
non operated wells.
They have a huge amount of acreage with minimal second
and third bench TF development ... to say nothing about the almost nonexistent
delineation of the fourth bench.
CLR has made an enormous investment very early on in the Bakken.
When
prices recover, they are apt to reap significant benefits.
Mike - my mother signed the rights for that royalty although her initial
rate was 12 and 1/2%. She is 91 years old and when they came and initially
got the rights (back in 1985 or so) it was considered a good rate. That's
why I sometimes laugh at everyone who thinks that mineral owners in the
Bakken got 20% especially in the Parshall area (EOG prime area).
And my mineral acres are between Van Hook and New Town! I am not complaining
by the way. Some people unknowingly sold their mineral rights when they
sold their land and when the reservoir was created the Corp of Engineers
bought a lot of land and a lot of people lost their mineral rights but I
digress!
Bison, I am guessing any rate in that area would be pretty good. When people
start talking about royalty payments the number always seems to get bigger
as each person passes the rumor around. When the deals were signed in Parshall
Field no one new the volumes of oil the operators would get out of the ground,
or how high oil prices would go.
Thanks for the comment. Since Parshall is my hometown I know quite a
bit about what happened during the run up to the Bakken boom. Landmen were
throwing money (what people in the area thought was a lot) around and they
signed on the dotted line very quickly. I remember bonuses being paid in
2010 in the thousands of dollars/acre range which in hindsight was insane.
Michael - nice article, some really good data here. I'd like your opinion
on something, if I may. Shale plays have completely changed the game over
the past few years. Their startup economics is pennies on the dollar compared
to say, deepwater, where only the biggest players could play and the investment
costs were enormous before even a single barrel of oil was produced. Relatively
cheap to get into = lots of potential players. Now one of the things I've
only seen mentioned in one or two SA articles is this business of "producer
discipline".
There was a recent quote by the CEO of EOG saying something to the effect
that US operators had "learned their lesson" (I'm paraphrasing) and that
producer discipline would definitely be an active concern going forward
once the recovery comes. You appear to know the players in the unconventional
space pretty well. Given the current operators and any new we may see once
a recovery does come, is "producer discipline" even a remote possibility?
I personally have my doubts but would like to know what you think. Thanks.
In a free market (non collusion), then the only thing that enforces "discipline"
is the marginal producer effect. If there are operators who produce below
cost of capital (irrational), then eventually the market disciplines them.
Conversely if there is irrational hesitation to invest, then other entrants
will come and take the opportunities. It makes me cringe to hear all this
talk about "discipline". Reminds me of Dick Cheney talking about reducing
volatility.
These are code words for collusion. Fortunately this is against the law
and also difficult to achieve, given all the small producers. Well...fortunate
for consumers. For producers, they would love to have them some collusion.
Even better if OPEC will do the job for them.
Devon paid 1.6Billion in the past December， 3 months ago, for Felix acreage.
It is $20K/acre!!! while oil price dipped below $40!!
According to CLR STACK PPT, more than half of the Felix acreage is outside
(east) the so called "Pressurized zone", which means under par?
According to CLR's initial Springer story, it is over 200' thick, while
Newfield claimed it is as thick as 700'. Boy, that means everywhere you
drill there is oil--- it can not be that easy, you need to be able to geosteer
in the sweet stack, e.g. within 50' of the 700' possible. Do you see that
CLR is no longer mentioning its Springer in their latest report?
My speculation is that they will have similar challenges in Springer, or
even greater challenges, in the STACK than in Springer.
Not sure how CLR and Felix compare in sweetness (or
in wells dug and producing, i.e. steel in the ground.) But just looking
at the latest CLR conf call powerpoint, they have 595,000 acres of STACK
& SCOOP. If you make simplest assumption and say same price as Felix than
that gives you $14.1 billion for their OK acreage.
2. I agree that they don't seem to be pushing the Springer as much as earlier.
That said, it was still in several pages of their PowerPoint and in the
10-K. So not sure what you mean when you say "no longer mentioning". And
which CLR report are you referring to?
Michael, Thanks for all the work you put in for this article. Lots of good
information.
The one problem I have with most oil companies, is using BOE. It was
refreshing to see CLR state actual bbls /day in their presentation. Look
like decent wells but they are going to have to reduce their CWC to make
it a great play. I expect a year from this time, these well cost will have
decreased significantly.
Excellent article, but my question is one of changing the oil curve. Most
of CLR's success had been as oil stayed above $80.BBL from 2003 until 2014.
If we are resetting the standard price based on supply and demand oil could
end up between $15-$45 for the next 2-4 years. How can CLR sustain a longer
period of lower prices with the amount of debt currently to equity, and
taking into consideration the low float? I cannot recall a time when they
were as cash strapped as they are now and debt ridden.
If I understand your theory oil would have to be $40-$80 and if you compare
current supply to that of 1985 I believe too many investors are forgetting
how long we can stay in the lower end of $25 BBL.
green law. If you have the time, go to the section near the back of CLR
10K where is contained future cash flow estimates for the years 2013, 2014
and 2015. Reduce the estimate of future cash flows to $25 billion and estimated
future income taxes to zero for 2015.
Undiscounted future net cash flows fall to $7 billion under your pricing
scenario, which means trouble given company debt levels.
"... A lot is written at the moment about shale break even prices of 24 to 40 usd. Every time i try to calculate those numbers, even when using best wells as per shaleprofile.com i cannot get even close to those numbers. Does somebody have the basics behind the above break-evens? ..."
"... There are outlier wells that work, but Enno's shale profile.com site is an excellent resource which shows that really no company can make these wells work at prices under $50 WTI, and really that $80+ is needed to have a good business. Remember when CLR cashed their hedges, they said they saw prices returning to $80-$90 soon. They did not. CLR and all others have cut to the bone on costs, but it is impossible to cut enough to overcome a 60-70% loss of gross revenue. ..."
"... Daniel, in 50 years of being an oil producer I had never heard the term "breakeven" until the shale oil industry came along; it is a meaningless, much overused metric. The oil industry drills wells to make money, so we can drill more new wells with net cash flow from old wells. Profitability is all that matters. Reserve growth cannot occur without profitability; unless of course you are in the shale oil business, in which case you simply borrow enough money to grow, in spite of unprofitability, and suffer the consequences down the road. Which is precisely what is happening now. ..."
"... I don't borrow money to drill wells (that is a well known no-no) so I can't wait 60 months to get my money back on a well I've drilled and completed. Thirty six months is the maximum and even that is too long. The 150% ROI numbers the shale industry use to throw around regarding "profitability" (but certainly can't any longer!!) is insufficient return on investment to keep moving forward, at least to me. I need at least 300% ROI. If my CAPEX is risked I need even higher ROI. If I can't achieve that, I don't drill the well. I was taught these standards by many before me and they still apply today. ..."
"... With great respect for my friend Shallow sand, I think it would actually require in excess of 120 dollar oil prices for the shale industry to be able to drill wells off net cash flow, in other words, to live within its means and not borrow money it can't pay back. As far as I am concerned the hundreds of billions of dollars it has already borrowed…we'll never see that. It's gone. ..."
A lot is written at the moment about shale break even prices of 24 to
40 usd. Every time i try to calculate those numbers, even when using best
wells as per shaleprofile.com i cannot get even close to those numbers.
Does somebody have the basics behind the above break-evens?
Enno and Daniel. The simple, undiscounted 60 month payout calculation has
not been refuted, with really even no attempt to, since I first used it
in early 2015 on LTO.
The only real criticism that has been valid has been from Mike, and a
few other oil producers, who say 60 months is too long. Mike is probably
right, but I am trying to give the companies the benefit of the doubt.
There are outlier wells that work, but Enno's shale profile.com site
is an excellent resource which shows that really no company can make these
wells work at prices under $50 WTI, and really that $80+ is needed to have
a good business. Remember when CLR cashed their hedges, they said they saw
prices returning to $80-$90 soon. They did not. CLR and all others have
cut to the bone on costs, but it is impossible to cut enough to overcome
a 60-70% loss of gross revenue.
I have posted this model on seeking alpha several times. No successful
attacks of my fifth grade math that I am aware of.
Enno, I think you made a good point with me awhile ago that the audience
needs it dumbed down. Given few can understand the 60 month payout, let
alone discounting future net cash flows, I wholeheartedly agree.
I encourage all to visit Enno's site. It exposes the 900K EUR fallacy
very well. Of course, the 900K is routinely half or more BOE gas, which
has been selling below $12 per BOE for months.
There is a producer who posts on Oilpro.com named Jackie, whose posts
I really enjoy. He keeps it simple, and I agree with him. If there is less
money coming in the bank account than going out, you are losing money. No
amount of slick investor presentations can refute that.
Daniel, in 50 years of being an oil producer I had never heard the term
"breakeven" until the shale oil industry came along; it is a meaningless,
much overused metric. The oil industry drills wells to make money, so we
can drill more new wells with net cash flow from old wells. Profitability
is all that matters. Reserve growth cannot occur without profitability;
unless of course you are in the shale oil business, in which case you simply
borrow enough money to grow, in spite of unprofitability, and suffer the
consequences down the road. Which is precisely what is happening now.
I don't borrow money to drill wells (that is a well known no-no)
so I can't wait 60 months to get my money back on a well I've drilled and
completed. Thirty six months is the maximum and even that is too long. The
150% ROI numbers the shale industry use to throw around regarding "profitability"
(but certainly can't any longer!!) is insufficient return on investment
to keep moving forward, at least to me. I need at least 300% ROI. If my
CAPEX is risked I need even higher ROI. If I can't achieve that, I don't
drill the well. I was taught these standards by many before me and they
still apply today.
And by the way, anybody claiming that shale oil CAPEX is not highly "risked"
I submit to you that the price of oil has fallen 70% in the past 16 months.
With great respect for my friend Shallow sand, I think it would actually
require in excess of 120 dollar oil prices for the shale industry to be
able to drill wells off net cash flow, in other words, to live within its
means and not borrow money it can't pay back. As far as I am concerned the
hundreds of billions of dollars it has already borrowed…we'll never see
that. It's gone.
Shallow you and Enno did great yesterday on Alpha; Filloon is a big time
Bakken cheerleader. Those guys are getting desperate with their we're OK
rhetoric now. Its not about big IP's and EUR's, it's not barrels and mcf's…its
about dollars and cents, nothing else. Keep up the good work, y'all.
As always, it is a pleasure to read your "no B.S." comments. Cut to the
chase and tell us like it is. Nice to have people in the reality based world
weigh in on the madness.
"Filloon is a big time Bakken cheerleader. Those guys are getting
desperate with their we're OK rhetoric now." ~ Mike
"My husband's company has it's own studies saying to expect 2 million
barrels a day from this state in 2019 and staying at that level until
around 2030." ~ dn_girl
"We had a proud young woman post yesterday about her… optimism about…
future in the oilfields of North Dakota. It is a powerful message that
we should have all embraced…" ~ Mike
"I gotta go let some good kids go. Damn, I hate that…" ~ Mike
"As always, it is a pleasure to read your 'no B.S.' comments. Cut
to the chase and tell us like it is. Nice to have people in the reality
based world weigh in on the madness." ~ islandboy
"I mix with professional people and and I know i have earnt up to
double their pay scale…" ~ toolpush
I believe that $100 plus oil prices was the real fuel that fed the growth
in LTO production. At that price a very good ROR was made and fund were
provided.
It was simply the situation in which Wall Street needed
a place to dump money provided by Fed and shale came quite handy.
According to Art Berman, during the 5 year period (2008-2012), Chesapeake,
Southwestern, EOG, and Devon spent over 50 billion dollars more than they
took in. Such a great profitability.
"... You also may be interested in the discussion (in the comment section) I had yesterday with Michael Filloon (a writer on Seeking Alpha), in which also a few calculations were presented: http://seekingalpha.com/article/3959718-bakken-update-continental-resources-top-bakken-player-2016 ..."
"... There are outlier wells that work, but Enno's shale profile.com site is an excellent resource which shows that really no company can make these wells work at prices under $50 WTI, and really that $80+ is needed to have a good business. Remember when CLR cashed their hedges, they said they saw prices returning to $80-$90 soon. They did not. CLR and all others have cut to the bone on costs, but it is impossible to cut enough to overcome a 60-70% loss of gross revenue. ..."
"... I encourage all to visit Enno's site. It exposes the 900K EUR fallacy very well. Of course, the 900K is routinely half or more BOE gas, which has been selling below $12 per BOE for months. ..."
"... There is a producer who posts on Oilpro.com named Jackie, whose posts I really enjoy. He keeps it simple, and I agree with him. If there is less money coming in the bank account than going out, you are losing money. No amount of slick investor presentations can refute that. ..."
A lot is written at the moment about shale break even prices of 24 to 40
usd. Every time i try to calculate those numbers, even when using best wells
as per shaleprofile.com i cannot get even close to those numbers. Does somebody
have the basics behind the above break-evens?
Enno and Daniel. The simple, undiscounted 60 month payout calculation has
not been refuted, with really even no attempt to, since I first used it
in early 2015 on LTO.
The only real criticism that has been valid has been from Mike, and a
few other oil producers, who say 60 months is too long. Mike is probably
right, but I am trying to give the companies the benefit of the doubt.
There are outlier wells that work, but Enno's shale profile.com site
is an excellent resource which shows that really no company can make these
wells work at prices under $50 WTI, and really that $80+ is needed to have
a good business. Remember when CLR cashed their hedges, they said they saw
prices returning to $80-$90 soon. They did not. CLR and all others have
cut to the bone on costs, but it is impossible to cut enough to overcome
a 60-70% loss of gross revenue.
I have posted this model on seeking alpha several times. No successful
attacks of my fifth grade math that I am aware of.
Enno, I think you made a good point with me awhile ago that the audience
needs it dumbed down. Given few can understand the 60 month payout, let
alone discounting future net cash flows, I wholeheartedly agree.
I encourage all to visit Enno's site. It exposes the 900K EUR fallacy
very well. Of course, the 900K is routinely half or more BOE gas, which
has been selling below $12 per BOE for months.
There is a producer who posts on Oilpro.com named Jackie, whose posts
I really enjoy. He keeps it simple, and I agree with him. If there is less
money coming in the bank account than going out, you are losing money. No
amount of slick investor presentations can refute that.
"... I have read all about the sweet spot and certainly understood the concepts, but maybe I put a little too much belief in the corporate presentations. It is had to find a good balance, with so much information at hand, but it is also hard to come to any other conclusion with EOG, that their sweet spots are just not so sweet these days! ..."
"... Look at Whiting. Another early entrant. 2008, 2009 and 2010 far superior to all years thereafter. Look at these two in Niobrara also. ..."
"... I love Whiting Niobrara, 2015 well productivity. So much for all the "productivity" improvements. lol These graphs, really cut though the gloss put out by the companies. ..."
"... I also found the EOG results quite shocking. Do note though that their average well is still performing nicely compared with other operators. I get the strong impression that EOG is only interested in clearly profitable operations, and not the unprofitable/marginal stuff. EOG has also hardly drilled into the Three Forks formation, which is clearly (>15%) performing worse than the Middle Bakken, while other operators have shifted new wells to a great extent (up to 50%) to the Three Forks. The annual total number of new wells in the Middle Bakken formation already peaked in 2012. ..."
"... EOG was the first big operator to rapidly pull back from Bakken in 2014, and its production has halved by now since Sep 2014. ..."
"... Although we don't yet see a major deterioration of new wells in ND overall yet, there are several areas within the Bakken where this can be found – so far this effect gets compensated in other areas. It is also striking to me that despite a drop in completions of > 30% from 2014 to 2015, there has not been a marked improvement in well productivity which you would expect as operations shifted to better areas. ..."
"... If the meme of retreating to the sweet spots and bigger better completions was true, then we should be seeing an increase in well productivity during 2015. Certainly across some of the major companies, this is shown not to be true. This must bring doubt upon the validity of closer well spacings, that have been the flavour of the day, and allowed high intensity well pad drilling. ..."
Firstly, I love Enno's graphs. I know they have been up for a while, but today is the day I have
really had a chance to explore.
I got a shock when I looked at EOG well quality. 2013, was obviously a high water mark for
well quality. But it is the poor performance of 2014 and 2015, that caught my eye. I do know EOG
were one of the first to cut back drilling, and also made even deeper cuts in completions. I can
understand the severe cut backs, and EOG could afford them, but I don't understand any reason
why they would be selectively completing their poorer wells, especially when the drop in productivity
starts in 2014. It is not just the initial production that is down. The 2014/15 continue dropping,
with both about to fall below the 2010 line, which is the lowest water mark.
I have read all about the sweet spot and certainly understood the concepts, but maybe I put
a little too much belief in the corporate presentations. It is had to find a good balance, with
so much information at hand, but it is also hard to come to any other conclusion with EOG, that
their sweet spots are just not so sweet these days!
EOG were the first in, and maybe the first to show the longer term future, or lack of it?
I love Whiting Niobrara, 2015 well productivity. So much for all the "productivity" improvements.
lol These graphs, really cut though the gloss put out by the companies.
I also found the EOG results quite shocking. Do note though that their average well is still
performing nicely compared with other operators. I get the strong impression that EOG is only
interested in clearly profitable operations, and not the unprofitable/marginal stuff. EOG has
also hardly drilled into the Three Forks formation, which is clearly (>15%) performing worse than
the Middle Bakken, while other operators have shifted new wells to a great extent (up to 50%)
to the Three Forks. The annual total number of new wells in the Middle Bakken formation already
peaked in 2012.
EOG was the first big operator to rapidly pull back from Bakken in 2014, and its production
has halved by now since Sep 2014.
Although we don't yet see a major deterioration of new wells in ND overall yet, there are several
areas within the Bakken where this can be found – so far this effect gets compensated in other
areas. It is also striking to me that despite a drop in completions of > 30% from 2014 to 2015,
there has not been a marked improvement in well productivity which you would expect as operations
shifted to better areas.
If the meme of retreating to the sweet spots and bigger better completions was true, then we
should be seeing an increase in well productivity during 2015. Certainly across some of the major
companies, this is shown not to be true. This must bring doubt upon the validity of closer well
spacings, that have been the flavour of the day, and allowed high intensity well pad drilling.
That a company with the technical ability and cash of
Shell would find production from fracked shale had not "play(ed) out as
planned" should give pause to the investors and commentators who have become
believers in the shale miracle.
Mr
Voser commendably took responsibility in August for a
$2.1bn writedown on the value of the company's US shale assets – particularly
since I also misestimated the productivity of some US unconventional gas reserves,
although in a different direction.
I had thought, when the benchmark US Henry Hub gas price bottomed at the
beginning of last year,
that a decline in gas drilling forced by a shortage of exploration and production
sector cash flows would result in a very rapid rise in price to cover the full
cost of production.
Well, prices have risen, but not as fast as I imagined.
That is due to high production from two sources that increased at greater
rates than most industry people – and I – expected: "associated" gas, from oil
or gas-liquids directed drilling, and gas wells in the
Marcellus Shale .
The Marcellus is a huge "play" of sedimentary rock across much of the northeastern
US, with gas and liquids production concentrated in western Pennsylvania, Ohio
and West Virginia. There are also a lot of Marcellus reserves in New York state,
but there is effective political opposition to developing them.
Without new production from the Marcellus, US gas supplies would probably
have declined since President Obama hailed
the shale revolution in his January 2012 State of the Union address. From
a technical point of view, the strength of Marcellus production has been driven
by shallow depth and short lead times, along with the industry's rapid productivity
increases.
Even so, there are some reasonable questions that can be raised about the
Marcellus miracle, setting aside any tightening of federal, state or local
regulation of shale gas drilling .
To begin with, despite the extraordinary success of the exploration and production
effort, not a lot of money is being made. Consider
Cabot Oil and Gas , which has an excellent reputation for management, reserve
quality and technical ability, especially in the Marcellus region.
Last year, it chalked up a return on equity of about 9.5 per cent.
That is good; if it were a European bank, COG would be at the head of the
class, but it is not at the lighting-cigars-with-$100-bills end of capitalism.
As Mr Voser told the FT: "[Shale well] decline rates are very high, so after
18 months your production drops very sharply, which means you have a business
model of constant investment."
That is demanding enough for a highly diversified investment grade company
such as Shell; if your company is junk-rated, it is much harder.
Also, rising Henry Hub prices overstate how much Marcellus producers have
benefited from their hard work and good luck. Ryan Smith, an analyst at Bentek,
an energy research firm that recently published a report on the Marcellus and
Utica shale plays, points to the "basis", or discount, that Marcellus gas is
getting. "Producers are constrained by pipeline capacity, which is vital. When
[one of two new pipelines comes on line] in November, that will be filled up
within a month. Drilling is backlogged."
Beyond next year , though, there is a steep wall of capital demands for
new pipelines, reversals of existing pipelines, export terminals, nearby chemical
plants, and gas-fired power plants.
What really surprised the industry was the continuing supply of new capital
from lenders and return-short investors. This interrupted what would have been
a typical oil and gas drilling cutback phase.
In other words, yes, there is a big Marcellus effect, but it may turn out
to have been superhyped by quantitative easing. We will see what happens if
the oil price falls and interest rates ever rise.
John Kemp: Why shale skeptics are wrong: http://www.reuters.com/article/2013/10/17/shale-idUSL6N0I72FD20131017?feedType=RSS&feedName=everything&virtualBrandChannel=11563
The UK has over 2,000 years of shale gas. This is a proven fact. Shale
gas is incredibly cheap (the price of gas in the US has plummeted) and abundant.
We could add many percentage points to our growth if we embraced shale
gas 100%. Brush aside the useless hippies and enviro-wack-jobs and get drilling.
In an instant we would become 100% energy independent, household energy
bills - including electric - would plummet to about only 10% of what they
are now which would free up a tidal wave of money to be spent into the economy.
Also, about 500,000 new jobs would be created in the shale gas industry.
This is a no brainer! Frankly the naysayers should be arrested for treason.
Did anyone read Dr. Tim Morgan's piece from earlier this year saying
shale gas is the next big popular delusion? It was on FT Alphaville.
He says that the whole global growth story of the last century boiled
down to a "surplus energy equation": in the past, one unit of energy used
could extract fuel that created 100 units of energy. But now this ratio
is declining and will continue to do so.
If it now takes 20 people to extract X amount of fuel whereas in the
past it used to take 1, then that's 19 people who can't be deployed elsewhere
to do other useful stuff. And it costs more to extract energy, in line with
the thesis above.
A FT front page image from about 6 months ago seemed to support this
point. The FT published a "heat map" photo from space showing fracking sites
in the US. They were all aglow - much more so than other production sites
or towns and cities!
Please - Try accrual accounting and you get a different picture - unfunded
entitlements and lets not forget promises that pols will make to voters
at the expense of those yet to be born.
The depletion rate for a well has been given as 80% in two years The
well can be re-stimulated and will produce some more , any further efforts
bring decreasing yield .
an operating company must then drill one new well for each older than one
year old , this just to keep their flow rate .
there is good money but not a given, each well pan out differently
If it costs $5mm per well and you recover $10mm PV over the life of the
well, then it appears to be a good investment. Wash, rinse and repeat. If
you spent too much on the leases and your all in cost of each well is higher
than PV production values (Shell), then wind it up. One real issue for these
properties is their nature as a depleting asset, an asset the rarely gets
valued correctly in the markets. And one real offset for this risk is the
potential for stacked plays (layer upon layer of frackable gas under the
same piece of land) - for COG it's the Utica under the Marcellus, and for
Bakken, Permian and Niobrara players it's multiple stacked layers. Hence
the recent conclusion by analysts that the Permian basin is still one of
the largest oilfields in world with future production numbers that are expected
to massively surprise on the upside. FT, don't make us do your work.
Analysis seems a bit limited in its understanding of the drilling business
model - need to drill land to hold reserves requires lots of upfront expenses,
etc. As always, the FT seems to dig enough for our attention, but not enough
for conclusions worth the read.
Thank you for an article which mentions depletion - "decline rates" in
a serious way. The fact is that the only people who have made serious money
in this game were the people who speculated in "prime acreage" and sold
it on to the big boys like Shell and BHP.
Of course, the best acreage is that which is used early on so the idea
that the productivity will always increase is at variance with geological
reality. The document below shows that in the 12 months to July 2013, the
number of wells in the Bakken increased by 1,628 (36%) - and the oil produced
increased by 172,643 barrels per day (27%). So much for the much touted
"the industry's rapid productivity increases.". True, these figures are
for oil, but there is little reason to think they are dramatically different
for gas.
I think the Red Queen understood it well: "Now, here, you see, it takes
all the running you can do, to keep in the same place. If you want to get
somewhere else, you must run at least twice as fast as that!"
@Felix Drost: You are quite right when you say "Shale is only profitable
in a world where energy prices are high". What people tend to forget is
that the shale plays were known about decades ago, and the first fracking
of a well happened in the 1940's. Clearly we are only exploiting these expensive
resources because all the cheap resources have been exploited and are in
production decline. It's not as if they are a bonus for some great new technological
achievement!
truth serum | October 13 12:28am
thank you for your reply.
"you look into statistics on the time to drill wells, you'll see that in
each emerging play, the time taken to drill and complete wells decreases
over time. "
Those would be really interesting data.
I googled the expressions you suggested, namely Fayetteville Shale, Eagle
Ford and Barnett Shale, and there comes out a flood of references.
Would you please be more specific ? I would really appreciate.
Is there a website where those data are available beyond anectodical evidence
?
Shell paid far too much to get into the market, that's the main reason
why it has a substantial write off. It bought into shale during the heady
days when it seemed "There's gold in them thar hills." They took a large
risk. But right now they have expanded the expertise to explore shale and
are increasingly good at it.
Shale is only profitable in a world where energy prices are high, it
is simply too costly to exploit otherwise. That returns are around 10% and
will probably stabilize around there isn't odd, returns never would have
reached Saudi-levels, that was plain from the start. Neither do oil majors
earn much from easy to access resources, the host countries typically do.
10% ROI sounds pretty good in an industry that must continue risky investments
to exploit smaller and harder to access fields.
What's great about shale in the US is the huge investments required which
translate into jobs jobs jobs, powering a recovery in many states. The low
ROI and high costs ensures a more equitable spread of the proceeds in the
economy when compared to e.g. Saudi Arabia.
During the 5 year period (2008-2012), Chesapeake, Southwestern, EOG,
and Devon spent over 50 billion dollars more than they took in according
the Houston consulting geologist Art Berman. Rapidly declining very low
productivity "shale" gas wells are the culprit. The operators have to keep
drilling or their production drops like a rock! The smaller public companies
cannot allow this to happen or their stock tumbles and it is curtains for
the company. Shell's Voser explained what many oil & gas folks in the U.S.
determined two or three ago. The "shale players" over-estimated the productivity
and under-estimated cost by a factor of two or more. Add the low natural
gas prices and most shale plays will be gone in a few more years. Raise
natural gas prices to $8 or more and the fragile U.S. economy heads south
again.
Five other operators - EOG Resources, ConocoPhillips, Continental Resources,
Oasis, Pioneer. Hess, Apache are two others. Of course, not all of these
are PURE unconventional plays. Petrohawk was another one but they were acquired
by BHP. Don't have time to look up the stats right now. Look, if these plays
were unprofitable why would companies continue to pour resources into them?
I think it you look into statistics on the time to drill wells, you'll see
that in each emerging play, the time taken to drill and complete wells decreases
over time. Look to Fayetteville Shale, Eagle Ford and Barnett Shale for
evidence.
Would you turn to the CEO of Blackberry for an assessment of the profitability
of smartphones in 2013, and future market trends? I didn't think so. Ask
Ryan Lance (ConocoPhillips), Mark Papa (EOG) and Harold Hamm (Continental)
what they think of unconventionals' profitability.
The reason Shell lost money is hey did not appreciate gas was so abundant
and costs to produce it would fall so much. We have hundreds of years worth
of gas
Great Article.
@truth serum | October 12 2:17am
great remarks.
"Shell is unwilling or unable to learn from successful operators"
would you please list five of them ? it would be a very interesting counter
evidence. Especially if you manage to mention their ROE and their Free Cash
Flow.
If I have understood well what the article means, shale gas extraction is
in a profitable stage of its life cycle but, at the same time, in a negative
Free Cash Flow one, because competitors need to invest a lot to keep the
pace of a constant decrease of extraction costs coupling it with pre-emptive
strategies on prime acreage.
Those are the strategic business units which many years ago used to be called
"stars" in the Boston Consulting Group Matrix, see http://bit.ly/1g9n21U
moreover,
"cutting costs in manufacturing mode while ascending a steep learning curve"
do you mean that shale gas/oil costs are decreasing rapidly for those who
keep investing? a sort of "learning by doing" (and investing)?
again, do you have any evidence for that ?
My interest is purely academic. Shale gas extraction industry would be worth
setting up a case study and some research papers.
Just because Peter Voser's Shell cannot figure out a way to produce unconventional
gas and oil profitably, this does not mean that the industry as a whole
has not figured out a way to produce unconventional gas and oil profitably.
Alas, Shell is unwilling or unable to learn from successful operators. It's
all about 1) getting prime acreage early and 2) cutting costs in manufacturing
mode while ascending a steep learning curve to optimize well completions
and spacing. Ask Harold Hamm if he thinks the Bakken Shale is unprofitable.
My colleague Tim Morgan clearly highlighted shale's poor energy return on
energy invested, which is the root of the problem, in his publication
Dangerous Exponentials in June 2010.
Of course his warnings about this troublesome equation have been universally
ignored by the cheerleaders for the "US shale miracle", so I suppose to them
this disappointment is surprising.
T C Smith, Chief Executive, Tullett Prebon, Chief Executive, Fundsmith,
UK
"... Do Permian basin drillers and oil service companies get paid in pesos, $CND, or roubles considering the high level of active rigs compared to Bakken/EF from year ago? Or more likely Bakken/EF simply run out of sweet spots by end of 2015? ..."
"... It does not matter how drillers are paid. What matters is how bonuses to the top brass are calculated: The Wall Street Journal reported that the bonuses earned by the CEO's of the major shale oil producers were tied to the level of production, not profits. ..."
"... But have a look: Oil price bust started 1.5 ago. ..."
"... Does that sound like business decision? No. It is political. The whole shale is political boondoggle camouflaged as new technology/energy independence narrative. ..."
"... Oil rig count in the Permian basin is now down 73% from the peak reached on October 24, 2014 (150 vs. 562) A 73% decline is less than 84% for the Bakken or 82% for the Eagle Ford, but this is still a huge decline. ..."
"... I don't agree that is not correct comparison. You provide 2 yardsticks: 1) bigger area and 2) there are lots of conventional fields that are in my opinion completely irrelevant. These two yardsticks are irrelevant because the price is $37 and you can't make money at $37. And you could not make money for the whole last year. The profit has always been the bottom line yardstick before shale entered the picture. ..."
"... Look Canada is waaaayy bigger field than Permian basin and we have to agree on that. How many active rigs do you have in Canada? 50 rigs. Why do you think Permian basin is "exceptional" that justify 152 rigs at this very moment? It is not bigger than the whole Canada. ..."
"... The Permian companies are not generally as debt burdened, having been more likely to have raised funds through stock issuance. ..."
"... Keep in mind history, too. The Williston Basin has had times where the rig count fell to zero. Not sure what 40 year low is for Permian, but pretty sure its never been zero. It looks like in 1999 the rig count in the Permian Basin dropped as low as 51. That is for TX only. ..."
Do Permian basin drillers and oil service companies get paid in pesos, $CND, or roubles considering
the high level of active rigs compared to Bakken/EF from year ago? Or more likely Bakken/EF simply
run out of sweet spots by end of 2015?
It does not matter how drillers are paid. What matters is how bonuses to the top brass are
calculated: The Wall Street Journal reported that the bonuses earned by the CEO's of the major shale
oil producers were tied to the level of production, not profits.
You are right about top brass, but let's not forget that even in the church their top brass justify
that they deserve more bonuses let alone oil capitalistic business.
I was being sarcastic with in what currency drillers and oil services are paid in Permian basin
just to provoke some thoughts intrigued on that model that Verwimp posted.
But have a look: Oil price bust started 1.5 ago. Numbers of rigs in Permian basin
are 8 TIMES higher now when oil price is 40-50% lower than year ago!! Does that sound like
business decision? No. It is political. The whole shale is political boondoggle camouflaged as
new technology/energy independence narrative.
But what is interesting now in 2016 to see is huge decline in the number of rigs in EF and
Bakken that actually supposed to happen in early in 2015 if this shale business was to be credible
business venture. But it did not happen in 2015. It did not happen in 2015 because it was political.
Well the reason it is happening today is probably they are running out of sweet spots. What they
are going to do until price reach $80? It is them the reason that price is not at higher level
today. Drilling marginal spots that are left in EF/Bakken is like drilling in downtown New York.
"Drill Baby Drill" only is applicable if there is something to drill for. The only shale game
in town now is Permian simply because of timing. They were the last that joined the game. Banks
will allow them to drill the the sweet spots at ANY price and then they will pull the plug.
"Numbers of rigs in Permian basin are 8 TIMES higher now when oil price is 40-50% lower than year
ago!! "
????!!!!! Oil rig count in the Permian basin is now down 73% from the peak reached on October 24, 2014 (150
vs. 562)
A 73% decline is less than 84% for the Bakken or 82% for the Eagle Ford, but this is still a huge
decline.
My bad interpreting graph from oilpro regarding the rig count. But the question is still valid:
At $35 WTI why Permian has 5 times more active rigs than Bakken today drilling unprofitable oil
for every single barrel that they produce for over year and half? I think is just matter of how
much sweet spots are left in each of the shale basin regardless of the actual price.
The comparison is incorrect. Permian basin is much bigger than Bakken and includes numerous conventional
fields. It always had much bigger number of drilling rigs than any other basin in the U.S.
I don't agree that is not correct comparison. You provide 2 yardsticks: 1) bigger area and 2)
there are lots of conventional fields that are in my opinion completely irrelevant. These two
yardsticks are irrelevant because the price is $37 and you can't make money at $37. And you could
not make money for the whole last year. The profit has always been the bottom line yardstick before
shale entered the picture.
Look Canada is waaaayy bigger field than Permian basin and we have to agree on that. How many
active rigs do you have in Canada? 50 rigs. Why do you think Permian basin is "exceptional" that
justify 152 rigs at this very moment? It is not bigger than the whole Canada.
Regarding yardstick that Permian is partly conventional also does not make sense because conventional
does not make money either at $37 and half of Canadian production is conventional and nobody is
drilling.
This shale "revolution" is political boondoggle that will have huge repercussions on US conventional
in the first place and then the rest of world's high cost and mature oil production like North
Sea and Alaska. But ultimately it will be US consumer that will pay the highest price as the biggest
consumer per capita in the world.
One reason there is more activity could be there is a larger area. Also, the severance taxes
are lower and the discounts for both oil and natural gas are lower. There could also be conventional
rigs drilling in the Permian, as well as rigs drilling wells besides producers (injection, disposal,
supply, observation)
It could also be that some rigs are deepening conventional wells to explore different and deeper
zones. The Permian is well known for may productive formations.
The Permian companies are not generally as debt burdened, having been more likely to have raised
funds through stock issuance.
Keep in mind history, too. The Williston Basin has had times where the rig count fell to zero.
Not sure what 40 year low is for Permian, but pretty sure its never been zero. It looks like in
1999 the rig count in the Permian Basin dropped as low as 51. That is for TX only.
Yes we are, I would direct people to Enno Peters website.
He does a fine job on this,
Based on the latest NDIC data, total oil production in North Dakota fell to 1122 kbo/d
in January, again a monthly drop of 30 kbo/d. This decline was slightly higher than I expected.
The number of new wells producing dropped to 70.
"... Seems to be the possibility of a decrease of 200K-400K in one state over a two year period is noteworthy. ..."
"... I think that ND production could decline to 800 kb/d by year-end only if very few new wells are drilled and completed. ..."
"... I actually expect ND rig count and completion activity to rebound in the second half of the year. Therefore, oil production is unlikely to drop to 800 kb/d, in my view. ..."
Dennis: Not to steal your thunder concerning your post, but the last two months' ND data indicate
an annualized decline of approximately 30%.
Way too early to tell, but if that rate held up throughout 2016, by year end ND production
would be in the low 800K range, by my math at least.
If that occurs, I question whether the 12/14 peak could be surpassed. I suppose if operators
work through their DUC inventories this year, assuming prices rebound enough, 800K range is out
of question, but I think below 1 million is very likely.
Seems to be the possibility of a decrease of 200K-400K in one state over a two year period
is noteworthy.
I think that ND production could decline to 800 kb/d by year-end only if very few new wells
are drilled and completed.
Theoretically, the December 2014 peak could be surpassed, but only several years from now,
and only if oil prices stay at relatively high levels (above $70) for at least 2-3 years.
I actually expect ND rig count and completion activity to rebound in the second half of
the year. Therefore, oil production is unlikely to drop to 800 kb/d, in my view.
This author was probably one year early in his forecasts, but the direction was right -- we might
face oil shortages in 2017.
Notable quotes:
"... "In permitting low oil prices, the Saudis seek to bring the market back into equilibrium. At present, our calculation of break-even system-wide is in the $85–$100 a barrel range on a Brent basis." ..."
Low oil prices today may be setting the world up for an oil shortage as early as 2016. Today we
have just 2% more crude oil supply than demand and the price of gasoline is under $2.00/gallon in
Texas. If oil supply falls too far, we could see gasoline prices doubling within 18 months. For a
commodity as critical to our standard of living as oil is, it only takes a small shortage to drive
up the price.
On Thanksgiving Day, 2014 Saudi Arabia decided to maintain their crude oil output of approximately
9.5 million barrels per day. They've taken this action despite the fact that they know the world's
oil markets are currently over-supplied by an estimated 1.5 million barrels per day and the severe
financial pain it is causing many of the other OPEC nations. By now you are all aware this has caused
a sharp drop in global crude oil prices and has a dark cloud hanging over the energy sector. I believe
this will be a short-lived dip in the long history of crude oil price cycles. Oil prices have always
bounced back and this is not going to be an exception.
To put this in prospective, the world currently consumes about 93.5 million barrels per day of
liquid fuels, not all of which are made from crude oil. About 17% of the world's total fuel supply
comes from natural gas liquids ("NGLs") and biofuels.
One thing that drives the Bears opinion that oil prices will go lower during the first half of
2015 is that demand does decline during the first half of each year. Since most humans live in the
northern hemisphere, weather does have an impact on demand. I agree that this fact will play a part
in keeping oil prices depressed for the next few months. However, low gasoline prices in the U.S.
are certain to play a part in the fuel demand outlook for this year's vacation driving season.
Brent oil prices are now hovering around $60 a barrel. In my opinion, this is quite a bit lower
than Saudi Arabia thought the price would go and may lead to an "Emergency" OPEC meeting during the
first quarter. But for now, I am assuming that Saudi Arabia is willing to let the other OPEC members
suffer until the next scheduled OPEC meeting in June.
The commonly held belief is that Saudi Arabia is doing this to put a stop to the rapid growth
of production from the U.S. shale oil plays. Others believe it is their goal to crush the Russian
and Iranian economies. If the oil price remains at the current level for a few months longer it will
do all of the above.
My forecast models for 2015 assume that crude oil prices will remain depressed during the first
quarter, then slowly ramp up and accelerate as next winter approaches. I believe that by December
we will see a much tighter oil market and significantly higher prices. In a December 24, 2014 article
in The National, Steven Kopits managing director of Princeton Energy Advisors states that, "In
permitting low oil prices, the Saudis seek to bring the market back into equilibrium. At present,
our calculation of break-even system-wide is in the $85–$100 a barrel range on a Brent basis."
Mark Mobius, an economist and regular guest on Bloomberg TV recently said he sees Brent rebounding
to $90/bbl by the end of 2015.
Since 2005, only North America has been able to add meaningful crude oil supply. Outside of Canada
and the United States (including the Gulf of Mexico), the rest of the world's crude oil production
netted to a decline of a million barrels per day from December, 2010 to December, 2013. More than
half of the OPEC nations are now in decline. We've been able to supplement our fuel supply during
the last ten years with biofuels, but that is limited since we need the farmland for food supply.
I believe the current low crude oil price could be overkill and result in the next "Energy Crisis"
by early 2016. Enjoy these low gasoline prices while they last.
The upstream U.S. oil companies we follow closely are all announcing 20% to 50% cuts in capital
spending for 2015. We will start seeing the impact on supply at the same time the annual increase
in demand kicks in. Our model portfolio companies are all expected to report year-over-year increases
in production, but at a much slower pace than the last few years.
The current market turmoil has created a once in a generation opportunity for savvy energy
investors.
Whilst the mainstream media prints scare stories of oil prices falling through the floor
smart investors are setting up their next winning oil plays.
A study released by Credit Suisse two weeks ago shows that U.S. independents expect capital-expenditure
(Capex) cuts of one-third against production gains of 10 per cent next year. This would imply production
growth of 600,000 bpd of shale liquids, and perhaps another 200,000 bpd from Gulf of Mexico deepwater
projects. At the same time, U.S. conventional onshore production continues to fall. I have seen estimates
of 500,000 to 700,000 bpd declines within twelve months. If these forecasts are accurate, U.S. oil
production growth would be barely positive next year and headed for a material downturn in 2016.
North American unconventionals (oil sands, shale and other tight formations) have been almost
all of net global supply growth since 2005. If unconventional growth grinds to zero and conventional
growth is falling outright, the supply side heading into 2016 looks highly compromised. At today's
oil price, only the "Sweet Spots" in the North American Shale Plays and the Canadian Oil Sands generate
decent financial returns to justify the massive capital requirements needed to continue development.
Global deepwater exploration is rapidly coming to a halt.
Were demand growth muted, this might not matter. Demand for liquid fuels goes up year-after-year.
It even increased in 2008 during the "Great Recession" and ramped up sharply during 2009 and 2010
despite a sluggish global economy. Low fuel prices are increasing demand today and my guess is that,
with U.S. GDP growth now forecast at 5% in 2015, we could see demand for fuels increase by close
to 1.5 million barrels per day this year. The current IEA forecast is for oil demand to increase
by 900,000 bpd in 2015.
If this plays out, the oil markets will be heading into a significant squeeze in the first half
of 2016.
The last extended period of low oil prices was 1985 to 1990. In 1985, when oil prices collapsed
similar to what's happening now, the world had 13 million bpd of spare capacity, with 7 million bpd
in Saudi Arabia alone. OPEC was well-positioned to comfortably meet any increase in demand.
Today, just about all of the world's discretionary spare capacity resides in Saudi Arabia and
amounts to an estimate 2 million bpd. Lou Powers, an EPG member and author of "The
World Energy Dilemma," has said that Saudi Arabia will have difficulty maintaining production
at over 10 million bpd for an extended period. If we do swing to a supply shortage, Saudi Arabia
may find itself in the position of needing to run the taps full out for much of 2016. In such an
event, the world will be headed right back into an oil shock and we will see much higher oil prices
than $100/bbl.
Based on the latest NDIC data, total oil production in North Dakota fell to 1122 kbo/d in January,
again a monthly drop of 30 kbo/d. This decline was slightly higher than I expected. The number of
new wells producing dropped to 70.
I have added 2 tabs in the above presentation; one that shows
the top operators, and another one that shows the gas and water production that is produced together
with the oil, in North Dakota. By using the arrows you can browse through the 5 tabs.
Drilling activity has continued to drop sharply during the last months. There were 88 wells spudded
in December, 61 in January, and based on preliminary data it looks like just 30 wells were spudded
in February. This sharp drop surprised me, as the drop is even more steep than the drop in rigs.
This indicates that the drilling efficiency has dropped again these months.
"... If consumption is 10 million metric tons burned each day, it is 3,652,500,000 tonnes per year consumed by the gaping maws of industry to allow civilization be in the gluttony mode, with half of it gone, 150,000,000,000 tonnes to go, then there is a fifty year supply in the ground and under the seas and oceans. ..."
"The two basic factors of the world's oil supply are (1) geologic (discoveries) and (2) economic
(distribution). Petroleum geologists have done such a good job of finding oil that it looks as
easy as growing crops, and our engineers deliver the petroleum like clockwork. Consequently, the
public and many planners consider global distribution to be the only supply problem and attribute
all price swings to simple economics. They erroneously ignore critical long-term geological facts
and assume that cash spent = oil found. This premise is invalid where no oil exists or where prospects
are poor. Most people are unaware that the global quality of geological/oil prospects has declined
so much that the amount of new oil found per wildcat well has dropped 50% since a 1969 peak. Discoveries
of the most critical but easiest to find giant fields (each with over 500 million bbl of recoverable
oil) are now stalled at 315 known worldwide. We are simply no longer finding enough new crude
oil to replace the world's huge consumption of 20 billion bbl (840 billion gal) per year."
2,200,000,000,000/7.3=301,369,863,014 metric tons
of total oil extracted, yet of be extracted, past production and future production.
If consumption is 10 million metric tons burned each day, it is 3,652,500,000 tonnes per year
consumed by the gaping maws of industry to allow civilization be in the gluttony mode, with half
of it gone, 150,000,000,000 tonnes to go, then there is a fifty year supply in the ground and
under the seas and oceans.
The metric system is of an advantage when calculating the numbers, IMO.
Thanks to Robert Wilson for the links to L.F. Ivanhoe's findings and conclusions, appreciate
it.
2,200,000,000,000/7.3=301,369,863,014 metric tons
of total oil extracted, yet of be extracted, past production and future production.
If consumption is 10 million metric tons burned each day, it is 3,652,500,000 tonnes per year
consumed by the gaping maws of industry to allow civilization be in the gluttony mode, with half
of it gone, 150,000,000,000 tonnes to go, then there is a fifty year supply in the ground and
under the seas and oceans.
The metric system is of an advantage when calculating the numbers, IMO.
Thanks to Robert Wilson for the links to L.F. Ivanhoe's findings and conclusions, appreciate
it.
Global debt has grown some $57 trillion since the collapse of Lehman Brothers in 2008, reaching
a back-breaking $199 trillion in 2014, more than 2.5 times global GDP, according to the McKinsey
Global Institute. Servicing these debts will most likely become increasingly difficult over
the coming years, especially if growth continues to stagnate, interest rates begin to rise,
export opportunities remain subdued, and the collapse in commodity prices persists.
Much of the concern about debt has been focused on the potential for defaults in the eurozone.
But heavily indebted companies in emerging markets may be an even greater danger. Corporate
debt in the developing world is
estimated to have reached more than $18 trillion dollars, with as much as $2 trillion of it
in foreign currencies. The risk is that – as in Latin America in the 1980s and Asia in the
1990s – private-sector defaults will infect public-sector balance sheets.
If global growth stagnates, interest rates won't rise by much. So high interest
rates and low GDP growth is not a very realistic scenario. Very poor monetary policy could accomplish
it (like Volcker in the 80s), but we may have learned something since then about monetary policy.
"... A number of signs point to the decline in production continuing during the rest of 2016 unless there is an extended oil price recovery. For a start, the number of new permits to drill wells in North Dakota is at a seven year low – indicating a low appetite for drilling (more on that in a minute). Second, there were 1183 inactive wells in the state in December - about 30% above normal for this time of year. The operators have essentially abandoned these inactive wells – usually because they are losing money. Many of these inactive wells are older and had very low production rates - less than 35 b/d. Such older wells are known as "stripper" wells and their costs are long ago written off – so operators usually keep them running unless transport and maintenance costs exceed the value of the crude – i.e. prices get too low. ..."
"... The strongest indicators of a slowdown in Bakken production come in the reduction in drilling rigs operating in North Dakota and a parallel decline in the number of well completions. We'll look at the rig count first then get to completions. ..."
"... The combination of the potential tax incentive early in 2015 and the extension of the one year limit in October led to a growing backlog of DUC wells in North Dakota that is now having an impact on production forecasts ..."
"... It seems that those producers who can afford to are increasingly opting not to complete Bakken wells but instead to leave DUC wells "on the shelf" as a kind of storage play – waiting for prices to improve. ..."
"... Many smaller companies do not have the luxury of waiting and many of these are likely to be either already casualties of the price crash or living on borrowed time (see Zombies ). ..."
"... The summary chart shows that at $30/Bbl - to achieve a consistent IRR above 20% (for even the highest cost wells) - producers need to target wells with an IP of at least 1500 b/d. Looking at historic drilling and production records, NDPA found only 63 wells – concentrated in McKenzie, Mountrail and Dunn Counties that had IP rates of 1500 b/d or higher. Those 63 wells represent just 1% of the 6000 Bakken wells that would breakeven if wellhead prices were between $55 and $70/Bbl. In short the analysis makes clear that only a fraction of existing wells would breakeven or produce an acceptable IRR at today's low crude prices. ..."
"... The expectation that oil prices might remain low for a long time is rapidly sinking in for U.S. shale producers. Many smaller operators have already fallen victim to bankruptcy but now even those with a strong balance sheet are recognizing that continued drilling and production no longer make financial sense. As a result all expectations are that U.S. shale production will tumble this year (although despite the suggestion in today's title it is not quite "all over" yet). The situation on the ground in North Dakota that we have reviewed today indicates that the slowdown is gaining momentum. The extent of any decline in production is still hard to forecast accurately – clouded as it is by the unknown impact of an increase in DUCs. As 2016 progresses you can be sure that we'll be keeping a close track on the trends for you. ..."
For the past, year many shale oil producers have defied the expectations of many and kept output
at or near to record levels in the face of falling oil prices and much tougher economics. Improvements
in productivity, cost cutting and a concentration on "sweet spot" wells that generate high initial
production (IP) rates have all helped cash strapped producers survive. But with oil prices so far
in 2016 stuck in the $35/Bbl and lower range and with the worldwide crude storage glut still weighing
on the market – producers are finally pulling back. Today we look at how increased pressure on North
Dakota producers is putting the brakes on Bakken crude production.
In December 2015, crude production in North Dakota Bakken fell by 2.5% to 1,152 Mb/d (from 1,182
Mb/d in November). That December output is down 6% from the record 1,227 Mb/d produced a year earlier
in December 2014. Lynn Helms – Director of the North Dakota Industrial Commission (NDIC) Department
of Mineral Resources commented in a February 2016 press conference that the December 2015 drop in
production was the first significant decline in North Dakota crude output not explained by other
factors such as weather. A number of signs point to the decline in production continuing during
the rest of 2016 unless there is an extended oil price recovery. For a start, the number of new permits
to drill wells in North Dakota is at a seven year low – indicating a low appetite for drilling (more
on that in a minute). Second, there were 1183 inactive wells in the state in December - about 30%
above normal for this time of year. The operators have essentially abandoned these inactive wells
– usually because they are losing money. Many of these inactive wells are older and had very low
production rates - less than 35 b/d. Such older wells are known as "stripper" wells and their costs
are long ago written off – so operators usually keep them running unless transport and maintenance
costs exceed the value of the crude – i.e. prices get too low. A third indicator of declining
producer interest in the Bakken is the large number of producing wells in North Dakota currently
being transferred (sold) by one operator to another – 697 wells as of February 17, 2016 according
to Helms. Some large producers such as Occidental Petroleum that is selling 346 wells - are leaving
the North Dakota Bakken oil patch altogether. Others that are staying in the Bakken have sold off
wells to other operators to raise cash – including Whiting Petroleum Corp (the largest Bakken producer
– selling 331 wells) and EOG Resources, grandfather of the crude-by-rail phenomenon.
The strongest indicators of a slowdown in Bakken production come in the reduction in drilling
rigs operating in North Dakota and a parallel decline in the number of well completions. We'll look
at the rig count first then get to completions. As of March 8, 2016 the rig count in North Dakota
stood at 33 – down 85% from the all time high (218) in May 2012. The green shaded area in Figure
#1 shows the North Dakota rig count since January 2013 (right axis). The number of rigs operating
hovered between 180 and 195 from January 2013 to December 2014 before dropping off a cliff from January
2015 onwards. By the end of 2015 the average rig count was down to 64 and the number fell to an average
of 52 in January 2016. The NDIC has not released the February average rig count yet – but their daily
count was down to 35 at the end of February. Just 16 producers operated those 35 rigs with only eight
companies operating more than one rig – headed by ExxonMobil affiliate XTO who still had 5 rigs and
followed by Continental Resources, Hess and Conoco Phillips running 4 each. In the past week XTO
and Hess have each dropped one more rig.
Figure #1 Source NDIC, RBN Energy (Click to Enlarge)
Turning now to completions – by which we mean when the first oil is produced through wellhead
equipment into tanks from a new well. As we have described previously – completion occurs in shale
wells after the well is drilled and the hydrocarbons are stimulated to flow by hydraulic fracturing
(see
I Cannot Complete With Your Tax Scheme). When oil prices were riding high any delays in completions
were usually practical rather than deliberate – caused by a lack of fracking crews able to complete
new wells. Producers had every incentive to complete wells to get cash flowing to help finance more
new drilling. But in an era of falling oil prices completion timing has become a big deal for
producers because waiting for a hoped for increase in prices before producing oil has become a strategy
for protecting future revenue. In North Dakota that strategy has led to a steady increase in wells
that are drilled but uncompleted (the DUCs) since the start of 2015. We previously discussed how
the North Dakota Legislature provided incentives for producers to hold off completions in the first
half of 2015 while they waited for low prices to trigger a tax break (see
Tax Scheme). Those tax incentives did not pan out due to a jump in oil prices in May 2015. However
the issue of completions in North Dakota stayed on the front burner when producers began to ask for
waivers from State mandated completions one-year after drilling (see
Incomplete).
In October 2015 the NDIC decided to issue waivers to allow producers to delay completions by up to
two years from drilling. The combination of the potential tax incentive early in 2015 and the
extension of the one year limit in October led to a growing backlog of DUC wells in North Dakota
that is now having an impact on production forecasts in 2016. Figure #1 shows NDIC data for
well completions - that have been falling (blue line left axis) and wells waiting on completion
that have been increasing since mid-2014 (red line left axis). As of the end of December 2015 there
were 945 DUC wells in North Dakota – down from an all time high of 1080 in September 2015 but 26%
higher than the 750 DUCs the previous December (2014).
It seems that those producers who can afford to are increasingly opting not to complete Bakken
wells but instead to leave DUC wells "on the shelf" as a kind of storage play – waiting for prices
to improve. A couple of weeks ago (February 27, 2016) the largest Bakken producer - Whiting
Petroleum - stated in an earnings report that they would suspend well completions in the Bakken in
April 2016 until prices rebound. In the meantime they will maintain 2 drilling rigs in North Dakota
– basically increasing their DUC inventory with no new production. Another large Bakken producer
Continental Resources announced plans in their January 2016 guidance to defer completing most Bakken
wells in 2016 - increasing DUC inventory from 135 at year-end 2015 to 195 at year-end 2016. Note
that we are just highlighting DUCs in North Dakota here but this phenomenon is widespread in the
oil shale sector and has also impacted natural gas drilling in the Northeast. The strategy is only
feasible for those production companies that have reasonably robust balance sheets and can afford
to wait before completing wells. Many smaller companies do not have the luxury of waiting and
many of these are likely to be either already casualties of the price crash or living on borrowed
time (see
Zombies). It remains to be seen to what extent large increases in DUCs during 2016 will
accelerate expected declines in output that have been forecast based on ever lower rig counts and
low prices.
The economic realities that are pushing operators to withdraw rigs and avoid completions in once
bustling plays like the Bakken are aptly illustrated by a video
presentation from the Director of the
North Dakota Pipeline Authority (NDPA) Justin Kringstad at the end of December 2015. The presentation
is an update on analysis Justin provided earlier in the year that is designed to show how lower oil
prices impact the number of wells in North Dakota that would produce an internal rate of return (IRR)
between 10 and 20% based on different drilling cost scenarios. The analysis is specific to the Bakken
but otherwise similar to the models RBN uses for production forecasting that were explained in detail
in out January 2015 Drill Down Report "It
Don't Come Easy" available to our Backstage Pass
subscribers. We are in the process of updating this analysis to reflect current drilling economics.
The chart in Figure #2 shows a summary of the NDPA's December analysis with Bakken wellhead crude
priced at $30/Bbl. That equates roughly to a West Texas Intermediate (WTI - the U.S. Domestic benchmark)
price of $35/Bbl less transportation discounts to get crude to market from North Dakota. As
of yesterday (March 8, 2016) WTI prices on the CME/NYMEX futures exchange closed at $36.50/Bbl. The
blue bars on the chart indicate the % IRR that a producer might expect based on a range of 30-day
average initial production (IP) scenarios between 400 B/d and 1500 b/d (numbers along the top of
the chart). For each IP scenario there are 3 alternate well drilling and completion cost cases -
$6 Million, $7 Million and $8 Million (indicated on the bottom axis).
Figure #2; Source: NDPA (Click to Enlarge)
As you can see the blue bars get higher from left to right as the well IP increases – because
the higher the IP rate the faster the oil revenues accrue towards the IRR. The IRR rates are also
higher when the drilling and completion costs are lower. The summary chart shows that at $30/Bbl
- to achieve a consistent IRR above 20% (for even the highest cost wells) - producers need to target
wells with an IP of at least 1500 b/d. Looking at historic drilling and production records, NDPA
found only 63 wells – concentrated in McKenzie, Mountrail and Dunn Counties that had IP rates of
1500 b/d or higher. Those 63 wells represent just 1% of the 6000 Bakken wells that would breakeven
if wellhead prices were between $55 and $70/Bbl. In short the analysis makes clear that only
a fraction of existing wells would breakeven or produce an acceptable IRR at today's low crude prices.
The expectation that oil prices might remain low for a long time is rapidly sinking in for
U.S. shale producers. Many smaller operators have already fallen victim to bankruptcy but now even
those with a strong balance sheet are recognizing that continued drilling and production no longer
make financial sense. As a result all expectations are that U.S. shale production will tumble this
year (although despite the suggestion in today's title it is not quite "all over" yet). The situation
on the ground in North Dakota that we have reviewed today indicates that the slowdown is gaining
momentum. The extent of any decline in production is still hard to forecast accurately – clouded
as it is by the unknown impact of an increase in DUCs. As 2016 progresses you can be sure that we'll
be keeping a close track on the trends for you.
"It's All Over Now" was written by Bobby
and Shirley Womack and first released by The Valentinos in 1964. The Rolling Stones had their first
number-one hit (in the U.K.) with a cover version in July 1964 – also a hit for the band worldwide.
"... As the winter '15/16 season winds down, the Northeast is set to experience lower seasonal demand, putting into question whether or not current production levels are sustainable with the amount of capacity leaving the producing states – Ohio, Pennsylvania, and West Virginia. ..."
"... This feature will look into whether or not production can find a home from the combined OH, PA, and WV "Tri-State" area, considering the seasonal swing in demand, and high storage levels reducing injection demand. It will also explore whether maxed-out outflow corridors can handle an incremental supply surplus. ..."
It seems Bentek agree with Art Berman that US or at least the NE gas production will fall by the
end of the year, just for slightly different reasons.
Risk to Northeast Production this
Summer
Wednesday, March 09, 2016 – 4:17 PM
As the winter '15/16 season winds down, the Northeast is set to experience lower seasonal demand,
putting into question whether or not current production levels are sustainable with the amount
of capacity leaving the producing states – Ohio, Pennsylvania, and West Virginia. Bentek's latest
CellCAST shows production averaging 23.5 Bcf/d for the remainder of 2016, about a 1 Bcf/d increase
from the current year-to-date average of 22.4 Bcf/d.
This feature will look into whether or not
production can find a home from the combined OH, PA, and WV "Tri-State" area, considering the
seasonal swing in demand, and high storage levels reducing injection demand. It will also explore
whether maxed-out outflow corridors can handle an incremental supply surplus.
Please continue
to read on page two for further analysis.
number and intensity of earthquakes in Oklahoma have risen dramatically in recent years
with the underground disposal of wastes from oil and gas drilling.
The state has asked energy companies to reduce wastewater disposal by 40 percent.
The new guidelines cover more than 400 wells located in a 5,000-square-mile area.
Oklahoma officials on Monday told oil and gas producers to dramatically scale back underground
disposal of wastewater that has led to a dramatic surge in the number and intensity of earthquakes.
The
new restrictions, imposed by the Oklahoma Corporation Commission, will require drillers to cut
the amount of underground-injected wastewater by 40 percent from the peak in 2014. The move represents
a shift in strategy for the state, which had initially targeted individual wells linked to seismic
activity, said Matt Skinner, a spokesman for the commission.
"We've built the case we need based on broad correlations rather than specific," Skinner said.
"We can't look at a single well and say, 'You did this.'"
The New York Times notes the restrictions are
technically recommendations that may force energy companies to produce less oil and gas. They
follow
a similar move for wells in northwest Oklahoma imposed by the state last month.
Earthquakes in the industry-friendly state, recently
linked to drillers' injection of wastewater deep underground, have risen from a few dozen annually
in the mid-2000s to
more
than 6,000 last year. The waste is a byproduct of petroleum production, forced from the ground
with oil and gas. Energy companies have been injecting the material thousands of feet underground
into an area called the Arbuckle formation.
Skinner said the restrictions are a proactive approach by the state. The 5,000-square-mile area
in central Oklahoma covered by the new rules includes areas where earthquakes aren't happening.
Skinner said the injections aren't directly caused by the method of producing oil and gas called
fracking. The U.S. Environmental Protection Agency says Oklahoma's massive energy business can
produce up to
2 billion
gallons of wastewater a day.
Gov. Fallin, maintained that the cause of the tremors was unclear, and the state Legislature refused
to consider legislation, but she abandoned her position as the number of quakes rapidly increased.
The political leadership was not jolted into action until January, however, when a series of small
earthquakes damaged homes and interrupted power in Edmond, an Oklahoma City suburb home to many in
the state's political and financial elite - from the NYT
People in Oklahoma will not wise up until it's too late and.they get a massive earthquake that destroys
most of their major cities. They blindly listen to the republican leaders who like the ones in flint
michigan tell them there is nothing to worry about meanwhile their leaders are getting enormous kickbacks
from the oil and gas company. GOP= greed over people.
Shirl Hopkins
lol, a friend's daughter moved there. now my friend is a nervous wreck wiith her daughter constantly
on the phone, scared cuz of the earthquakes. she moved there cus okla is a really religuous state.
lol
Never ceases to amaze me. For years people stated that fracking causes earthquakes. Coincidence the
big oil companies said. Totally unrelated. Yeah, right. The more fracking, the more earthquakes.
What does one expect when the one thing that is allowing the earth to move on itself without friction
is being sucked out, processed, and put into our engines. Don't know what is worse, trying to figure
out what to do with the toxic byproducts above the ground or the crap left below it and is leeching
down to our aquifers. Lovely what we are doing to ourselves.
It's not like this issue wasn't known for decades. The USGS report on the cluster earthquakes in
the Denver area in the '60's, were a direct result of wastewater injection into a 12,000 foot well
at the Rocky Mountain Arsenal. When the injection pumping stopped, so did the earthquakes.
http://earthquake.usgs.gov/.../states/colorado/history.php
Beyond stupid, when you're screwing up the earth so bad you're causing EARTHQUAKES! don't you think
it's time to stop! Fools won't get the hint until Oklahoma is just a hole in the ground.
Oklahoma has never been a very logical place. One resource Oklahoma has plenty of is wind, and the
state contains the headquarters and plants for two manufacturers of wind generation systems. Yet
the state government for years has favored oil and gas over wind energy to the point that it allows
utilities to charge monthly hookup rates to homes with personal wind- and solar-generation equipment
that negate any savings from using those systems.
"The new restrictions, imposed by the Oklahoma Corporation
Commission, will require drillers to cut the amount of underground-injected wastewater by 40 percent
from the peak in 2014"
Do we even know if its wastewater they are pumping back into the ground?
Whats to stop them from pumping other checmicals back into the ground?
The wastewater also contains the chemicals in that were used in the fracking
fluid. The well is fractured with a sandy, saline/chemical solution. Those specific chemicals will
depend in part on what, if any, clays were present in the reservoir rock that the company will want
to disolve to increase the ability of the oil to migrate through the reservoir rock. Depending on
the clays present, the particular chemicals used can be pretty nasty. As far as chemical contamination
goes, the top of the Anadarko Basin, where the waste is injected, is over three miles below the surface.
Fresh water is generally very near the surface. I have not seen any research that suggests that the
waste water in the Anadarko could migrate upwards. It is very saline, so its density should restrict
its ability to move upwards. That is why fresh groundwater is near the surface and very deep ground
water tends to be saline. That is not to say that I am comfortable with the waste water being there.
Wait... What!!???? Republicans putting new regulations on businesses? What happened
to "If the government would just take the handcuffs off of American businesses, it would be a perfect
world?" What, Oklahoma? Didn't get quite the perfect world you thought you would? Maybe you ought
to consider suing Ayn Rand... (You know, the fiction writer who wrote your instructions on how to
govern...)
These aren't actual regulations. This is the part where conservative pols ask the
industry to play nicely. If you thought they were actually going to create standards and rules and
consequences for bad behavior you can stop being suprised now. This "ask" of theirs has fewer teeth
than the tooth fairy.
I wonder how they cam to the conclusion that 40% would do the trick. That only a 40% reduction of
the 100% of waste water shoved and pumped into the underground rocks and soil would be enough to
completely stop the damage they are doing - the earthquakes they are causing.
But, "The New York Times notes the restrictions are technically recommendations that may force energy
companies to produce less oil and gas."...OR, the oil companies may just simply ignore those "recommendations"
and just keep doing what they are doing in the "industry-friendly state".
if companies like Sandridge didnt bring in all the disposal water from Arkansas
and try and dispose of it here, there wouldnt be a problem.
The earthquakes started when Arkansas banned disposal wells and companies built disposal wells in
Oklahoma on known fault lines (with the theory that its already a big crack, just fill it with water)
and try and force two states salt water into the area of one state.
Since the disposal wells that were on known fault lines (just took the closer of 10), earthquakes
dropped significantly.
Just "guidlines" no consequences for not following them. Where do they expect frackers to dispose
of the poison? Simple they'll just dispose of it in some other unregulated fashion... problem solved,
eh? How about banning the release of benzene, toluene and the dozens of other carcinogens used in
fracking into the environment. That apparently is too much to ask in a country that kisses corporate
*ss the way we do.
"Skinner said the injections aren't directly caused by the method of producing
oil and gas called fracking."
He's technically right, but the fact of the matter is that the saltwater is coming from formations
that can only be targeted by fracking. It's like saying drilling for oil doesn't directly cause global
warming.
Of course they
do it NOW............
Now that the price of oil is in the toilet........
They were content to do nothing before.......
I guess money really IS more important than anything, INCLUDING common sense........
Oklahoma and Texas will be uninhabitable wastelands in another 20
years from fracking. Their water supplies will be so poisoned they won't be able to drink the tap
water. Hope it was worth it. But don't be crying to Federal Government yo bail you out.
The USGS is quite clear on the damages from cluster earthquakes in the Denver area as a direct result
of wastewater injection wells from the 1960's at the Army's Rocky Mountain Aresenal.
The main damage occurred in Northglenn, a northern suburb of Denver, but minor damage occurred in
many area towns. At Northglenn, concrete pillars were damaged at a church; foundations, concrete
floors, and walls cracked; windows broke; and tile fell at a school. This was the largest of a series
of earthquakes in the northeast Denver area that were believed to be induced by pumping of waste
fluids into a deep disposal well at the Rocky Mountain Arsenal. The Colorado School of Mines recorded
more than 300 earthquakes from this zone during 1967. Felt north to Laramie, Wyoming, south to Pueblo,
west to Vail, and east to Sterling.
That's the verdict from Daniel Fine, one of Gov. Susana Martinez's senior advisers on energy
policy. The U.S. oil and gas industry - and the San Juan Basin - is in a "bust" period, Fine said
Tuesday at an inter-tribal energy conference at San Juan College's School of Energy.
"This is what a bust is. You lose the workforce," said Fine, who is associate director at New
Mexico Center for Energy Policy at New Mexico Tech. "Loss to the country and to the Southwest
will be the workforce. It will be decimated at levels of less than $30 a barrel (of crude oil)."
And 2015 was a year of layoffs and cutbacks.
Since the collapse of oil prices on the commodities market in fall of 2014, the number of workers
laid off from local oil and gas companies - from the large corporations to the smaller
independents - has been in the thousands.
"We're in a 'bust.' So be ahead of the curve, and think ahead in this business by at least six
months," Fine told the Native American and non-tribal energy leaders and business people in the
Merrion conference room at the new $15.8 million school.
He said looming federal regulations such as the the U.S. Bureau of Land Management's proposed
Onshore Oil and Gas Orders Nos. 3, 4 and 5 along with proposed updates to its rule aimed at
reducing "fugitive" atmospheric methane from oil and gas operations were doubling the pain
already caused by low crude oil prices. He said that a third of all U.S. oil and gas producers -
especially those burdened with debt - will inevitably go bankrupt.
But Fine's sobering analysis wasn't without one ray of hope for the industry.
He said that if the Organization of the Petroleum Exporting Countries, or OPEC, decides to reduce
the supply of crude oil at its June 2 meeting in Vienna, crude oil prices could climb back up to
the $50 a barrel. Commodities prices, he said, were now solely driven by foreign markets and out
of the hands of U.S. operators.
And to help ease the impending pain to tribal energy companies - and establish a precedent for
others - Fine suggested tribal energy leaders request exemptions from the federal government over
the proposed new rules.
With just two rigs drilling in the San Juan Basin, Fine said that people might find a modicum of
comfort by taking the long view.
He recommended everyone in the room read the 2002 book, "Gas: The Adventures into the History of
one of the World's Largest Gas Fields - The San Juan Basin of New Mexico."
Written by local independent oilman Tom Dugan and geologist Emery Arnold, the book takes readers
on a journey forward from the basin's first commercial oil and gas wells in the early 1920s and
through major boom-and-bust cycles in the 20th Century.
Dugan, president of the Dugan Production Corp. in Farmington, said he agrees with Fine on the
current state of the industry.
"Definitely it's a bust," Dugan said. "What I'm saying is that it's the worst of them all. It's
the hardest bust I've been through and I have been in this business for 57 years."
Never before have multiple agencies of the federal government proposed new oil and gas rules
during a "bust" period, he said. Complying, he added, would be a lot more feasible if those rules
had come along when natural gas was around $5 per million BTU and a barrel of crude oil was
selling near $100.
Dugan said the dovetailing of low commodities prices and the new federal rules - along with the
advent of horizontal drilling - have spurred him to consider picking up his pen to write a new
edition of "Gas."
He said he still stands by a prediction he first made in his book that the San Juan Basin will
deliver salable natural gas for another 100 years.
And that, eventually, a "boom" is bound to happen.
"It will come back," he said. "I just wish I knew when."
James Fenton is the business editor of The Daily Times. He can be reached at 505-564-4621.
Looks like the range of oil prices below $70 which represents the "death valley" for US LTO production
also exists for UK North Sea fields.
Most fields might degrade at natural depletion rate already
in 2016. Which is up to 22%.
Investment in the UK's embattled oil and gas industry is expected to fall by almost 90 per
cent this year, raising urgent industry calls for the Government to reform its North Sea tax
regime to safeguard the industry's future, reports
RT reports that if Brent price in 2016 stays in 0-70 range capex in the North Sea fields might
be reduced by almost 90%.
According to the report of the British Association of oil and gas industry, with current prices,
almost half of the oil fields in the UK produce oil at a loss.
The fall in oil prices has a negative impact on the UK economy. According to the report
of the British Association of oil and gas industry, the country plans to reduce by 90% investments
in the development of offshore fields in the North Sea. According to the expert in the field
of oil industry of Mamdouh Salamah, for the United Kingdom will be cheaper to import crude,
not to invest in new projects.
With current prices, almost half of the oil fields in the UK produce oil at a loss.
An expert in the field of oil industry Mamdouh Salama believes that in this situation for
the United Kingdom would be more profitable to import oil, not to invest in new projects. According
to him, for resumption of capital investments, the level of oil prices should be higher than
$60-70 per barrel.
"Given the fall in oil prices it's more profitable for the UK to import crude oil and refine
it locally, rather than invest in the North sea fields" said Salam.
"... I do not agree that $55 (assume WTI) is enough to keep the basins flat or grow production, without significantly more cost reductions. The company 10K, demonstrate that. Not enough future net cash flow. Especially as those calculations are sans interest and g & a. ..."
"... the average Bakken well produces 190K in 60 months. 152K is assumed 80% NRI. ..."
"... These guys just throw out prices, never any substance behind what they say. For once I would like to see an article that walks through the numbers and proves us wrong, but they can't, so they won't. ..."
I do not agree that $55 (assume WTI) is enough to keep the basins flat
or grow production, without significantly more cost reductions. The company
10K, demonstrate that. Not enough future net cash flow. Especially as those
calculations are sans interest and g & a.
Again, the average
Bakken well produces 190K in 60 months. 152K is assumed 80% NRI.
152,000 x $48 per barrel (assumed $7 basis discount) is $7,296,000.00
$7,296,000.00 less 10% severance = $6,566,400.00
Subtract gathering of $1.50, LOE of $8 and G &A of $2.50. We are now
at $4,742,000.00. This isn't enough in 60 months for a well that costs $6.5-8
million.
These guys just throw out prices, never any substance behind what
they say. For once I would like to see an article that walks through the
numbers and proves us wrong, but they can't, so they won't.
Sure, a standout well can work. Our standout wells work at $20. No one
has only standouts, unless they are fairly small.
Actually that's just a wild ass guess. It takes about a month, I am told,
do drill a horizontal well, a lot shorter for a vertical well. But I may
be wrong. Mike or some other oilman may chime in and tell me how wrong I
am. I found this so it looks I was pretty close.
While there have been instances when wells were drilled in as little
as 15 days, a reasonable expectation for the time required to drill a well
in the Eagle Ford is around one month.
How long does it take to drill a well and begin producing natural
gas?
Horizontal drilling currently takes approximately 18-25 days from start
to finish. Then, the well needs to be fracture stimulated in order to release
the gas. It is then connected to a pipeline, which transports the gas to
the market. From drilling to marketplace, the entire process can take up
to 3-4 months. Mike ,
07/27/2014 at 1:08 pm
Mr. Patterson, I enjoyed this post and sent it immediately to my employees
and my family with a beware or be square header; I can't give you a
bigger compliment than that. I hope it gets attention outside the peak
community.
A typical 14,000 ft. TMD well in unconventional shale takes about
3 weeks, spud to TD, you are correct. They can blow them down these
days because there are no intermediate casing strings to set, or logging
or evaluating to do going down, and the top drives they use now, instead
of rotary tables, makes the radius and lateral a piece of cake. To reach
some economy of scale, as we now know, they drill multiple wells on
long pads simply being able to walk the rig from well to well; that
is where the 2 1/2 to 3 weeks per well number comes from, IMO. It takes
a good week to tear down a big rig, load it out (35-50 loads), get it
down the highway, unload it, put it all back together again and ready
to turn to the right. In that case, 4 weeks, plus.
I think we can't use unconventional shale data for well time or costs
in Russia, however. That's all typical conventional reservoirs, many
of which are under pressured, and over pressured, require several casing
strings and everything in Russia happens in very slow motion. Many big
fields in Russia range greatly in depth too.
While I am on, I always get a kick out of the notion that other shale
resources throughout the rest of the world will save the day. The maps
sure look perddy. But no other country in the world will have the ability
to develop its shale resources as efficiently, and cheaply, as N. America
can, IMO.
And by the by, here in the US all we can hope for from shale is internal
rates of return of 70-80% of total CAPEX, over 20 years, so the shale
industry hopes.
Can the rest of the world find the money to get on the shale treadmill,
for only those kinds of returns? No way, Jose. I always like to remind
folks who look forward to abundant shale production from the rest of
the world…of Poland.
"... Offshore oil exploration success has not been good recently. Admittedly there was a hit in the GoM from the BP disaster and now the price collapse, but in the past some of the best quality finds occurred in slow down periods. ..."
"... The decline rates for deep water are very high, not quite in the LTO league but requiring a lot of drilling to keep the production facilities at high capacity ..."
"... For me that would present much higher risk to future price volatility than for what I would think of as "conventional" developments, so requiring bigger resources and/or guaranteed higher prices for FID decisions. ..."
"... George, US is NOT the world. Canadian conventional drilling slowed greatly already a year ago. Deep water drilling plans off the cost of Africa and North Sea are also cancelled. Shell Arctic drilling is cancelled. Are you telling me that all these worldwide projects are equivalent to 3 mediocre Shale plays in US? ..."
"... Well said -- Simultaneous production of junk bonds and shale oil was probably the most recent of Wall Street "innovations". Which under close look are always reincarnations of some old financial scam. In this case, in price range 0-70 per bbl it is just a Ponzi scheme or, at best, a speculative investment which fully relies on "evergreen" loans. ..."
As long as shale corps. will find any kind of financing, then they will keep drilling. The only
reason that they have decreased drilling by so much recently is because their access to loans
has been slashed. Their last line of defense is that they have managed to issue shares on Wall
Street.
But at the end of the day there is way more conventional, deep water around the world that will
not be drilled at these prices so on the global scale shale is just too small to make up a difference
and eventually they will run out of sweet spots anyway. Shale is like one hit wonder like "99
Luftbaloons" from Nena in the 80's :-)
The long-term for US shale oil production is definitely down, also of US oil production in general.
For that there can be no doubt. But there will be ups and downs along the way.
"conventional, deep water" is a bit close to an oxymoron for me. And is there really "way more"
of it or has that just been wishful thinking as we've run out of other plays?
Offshore oil exploration success has not been good recently. Admittedly there was a hit
in the GoM from the BP disaster and now the price collapse, but in the past some of the best quality
finds occurred in slow down periods.
The discoveries I've seen recently have mostly been small gas fields. But Marathon and
COP look to have lost interest. The decline rates for deep water are very high, not quite
in the LTO league but requiring a lot of drilling to keep the production facilities at high capacity
.
For me that would present much higher risk to future price volatility than for what I would
think of as "conventional" developments, so requiring bigger resources and/or guaranteed higher
prices for FID decisions.
George, US is NOT the world. Canadian conventional drilling slowed greatly already a year
ago. Deep water drilling plans off the cost of Africa and North Sea are also cancelled. Shell
Arctic drilling is cancelled. Are you telling me that all these worldwide projects are equivalent
to 3 mediocre Shale plays in US?
Volatility? Shale is synonym for volatility. So the rest of the higher cost world oil industry
said "Let the Shale pump what it has to pump and then we will get back to oil business again"
George, I can assure you that the rest of the world, including US conventional, pumps oil not
for the sake of practice but for the sake of profit.
So they will let Wall Street run their shale pet project to the ground and go back to business
later.
let Wall Street run their shale pet project to the ground and go back to business later.
Well said -- Simultaneous production of junk bonds and shale oil was probably the most recent
of Wall Street "innovations". Which under close look are always reincarnations of some old financial
scam. In this case, in price range 0-70 per bbl it is just a Ponzi scheme or, at best, a
speculative investment which fully relies on "evergreen" loans.
In a Ponzi scheme the operator pays returns to its investors from new capital,
rather than from profit earned by the operator in the expectation of oil price rise. This is
were "unlimited" Wall Street financing of shale bubble played the crucial role. It allowed
carpet bombing of shale plays with wells and eventually led to the current oil price crash.
And new profits to Wall Street. A new redistribution of wealth up.
As John Kenneth Galbraith said: "Financial operations do not lend themselves to innovation. What is recurrently so described and
celebrated is, without exception, a small variation on an established design . . . The world of
finance hails the invention of the wheel over and over again, often in a slightly more unstable
version."
It will be very interesting to see the situation in oil market three years from now.
Hedging only gets the job done if you can hedge at a price higher than
breakeven. If the spot price is $50/b. You would need to be able to hedge
at $75/b or more for the average well to break even, in practice this is
not likely to happen.
Currently the futures price in Dec 2018 is $10/b above the April 2016
futures price.
So possibly if oil prices reach $65/b hedging might be an option, below
this maybe not. (I have ignored transaction costs in this example.)
"It was a tumultuous week in the world of hydraulic fracturing ("fracking")
for shale oil and gas, with a few of the biggest companies in the U.S. announcing
temporary shutdowns at their drilling operations in various areas until
oil prices rise again from the ashes."
And if the sordid news for the frackers were not bleak enough on the bottoming
out of oil prices, David Hughes - a former oil industry geoscientist and
current fellow with the Post Carbon Institute - recently delivered sworn
testimony to the North Carolina Utilities Commission that shale gas production
will peak in 2017 nationwide and then begin a rapid productivity decline.
"... And the number of DUCs reached their peak while prices were still high. There are DUCs because there is always a delay between when the drillers finish their work and when the frackers start their work. And the number of DUCs grew, during high prices, because there were more wells being drilled than wells fracked. ..."
"... higher prices will only bring on more completions if there is money to pay for them, which is not a given. ..."
"... You don't have to be an economist or a CPA to figure out how difficult it will be for oil companies to again be growing at this point. ..."
There are always DUCs. There have always been DUCs, even when the price
was well above $100 a barrel. In fact the inventory of DUCs grew every year
that the price of oil was in the $100 range. And the number of DUCs
reached their peak while prices were still high. There are DUCs because
there is always a delay between when the drillers finish their work and
when the frackers start their work. And the number of DUCs grew, during
high prices, because there were more wells being drilled than wells fracked.
Higher prices will bring on more completions, bringing on more production,
knocking prices back down again, keeping prices lower for longer. Right
or wrong, that is simple logic. It is not nonsense.
That interrupts the logic, and is not to be considered. It is not important
that upstream companies are out of bucks, and nobody will lend them any.
Drilling will continue to be done with cash available until which time,
the coffers start filling. May take some time to put into completing those
wells that are only profitable at 80. Be quacking for quite a while. However,
that interrupts the logic of lower for longer, so it is not to be considered.
You don't have to be an economist or a CPA to figure out how difficult
it will be for oil companies to again be growing at this point. It
is mostly going to be funded by internal cash flow. Let's assume that EIA'S
estimate of the average Eagle Ford's EUR to be 168,000 bbls, and somewhat
meaningful. So, maybe the average first year's production to be 75,000 bbls.
At 100 a barrel, they recover the cost of the capex, plus a little more.
They can drill another well with positive cash flow. Probably describes
the average DUC. At 80 a barrel, they are in negative cash flow. Probably,
a profitable well, but negative cash flow. They did not make back enough
money to drill a new well the first year. Later, next year, but not by the
end of the year. So amount available for capex goes down. At 40, they may,
or may not recover the cost of the well. If the DUC is an average Eagle
Ford EUR, then it could sit for quite a while if lower for longer is the
logic.
That is the main reason you won't see large scale ramp ups on production
until it stays over 70 for a while. A large percentage of the area is average,
or less than average.
"... Another reason why production hasn't fallen as rapidly as some expected was that newer wells produce a bit more in the first couple of months, followed by a steeper decline. This can be seen from the production profiles from the different shale areas. This is more like a one-time gain however. ..."
"... Completion is about 2/3 of the total well cost. ..."
"... If production for a group of wells (not my model wells) completed in 2010 declines by 80% from 2010 to 2015, while the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015, are you seriously asserting that there is not a survivor bias issue? Or for that matter, if the percentage of plugged/inactive wells increases from 0% in 2010 to 1% in 2015. ..."
"... The average 2008 to 2012 well will be shut in at about year 15 if they are profitable to produce at up to 7 b/d of output. This will depend on oil prices in 2023, which are hard to predict. ..."
"... "the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015" This is a hypothetical assumption. The real number of plugged wells is low and therefore it can be ignored ..."
"... The 50% abandonment number in five years was based on a real life case history in the Barnett Shale Play, the 2007 vintage wells on the DFW Airport Lease that Chesapeake asserted would produce "for at least 50 years." ..."
"... So I don't see any survivorship bias. As long as we include all the wells in the data (including those abandoned) survivorship bias is eliminated. ..."
Couple of comments:
– I think the rig count is an important metric to follow. However, some
adjustment is needed to correct for the fact that rigs are more efficient
now in drilling wells. Probably several reasons for this (better rigs, crews,
methods, pad drilling, drilling in a closer area, etc). E.g., in ND in 2012
every rig on average drilled 0.8 well per month. In 2014 this was 1.1, and
in the last few months it was 1.4. I agree with you that the rig count eventually
has to impact production (it will be with some delay, and corrected with
the above factor).
– Shallow showed a comment from the Hess CEO that another reason to keep
drilling was to keep at least some experienced production staff in the company.
– Another reason why production hasn't fallen as rapidly as some
expected was that newer wells produce a bit more in the first couple of
months, followed by a steeper decline. This can be seen from the production
profiles from the different shale areas. This is more like a one-time gain
however.
– Some companies apparently do intend to drill more wells than complete
them in 2016. Continental Resources plans to drill 73 wells, and complete
26 (net) wells in 2016. Note that in 2015 they actually reduced the number
of wells waiting for completion by 35. Completion is about 2/3 of the
total well cost.
Imagine the production profile if they could complete every single well
in the fracklog on the same day, vs if they complete one a day for the next
11 years.
These are obviously absurd examples, but just to make the point that
really what we would like in order to accurately predict production is a
'frac crew count' rather than a rig count, and to agree with what you say
above.
Following is a link to, an excerpt from, a question I posed on a prior
thread. It's my understanding that you are attempting to correct for survivor
bias, in regard to decline rates, by dividing annual production by the original
number of producing wells. I constructed a simple model which seems to show
that this makes no difference. It seems to me that one is calculating rates
of change in total production in both cases (total production or total production
divided by original number of wells).
As my example model shows, one can produce a year over year rate
of change chart that looks a lot like the Bakken year over year rates
of change, but by the time that the decline has settled down to 10%
per year, 90% of the wells completed in year one of the model (2010)
are no longer producing.
I don't know what the percentage of inactive wells is for the Bakken
Play by year, for example, the percentage of Bakken wells completed
in 2007 that are no longer producing, and I don't know whether the percentages
are material, but there are numerous examples of very high abandonment
rates in other shale plays.
For example, Chesapeake claimed that their 2007 vintage wells on
the DFW Airport Lease, in the Barnett Shale Play, would produce "For
at least 50 years." Five years later, about half of the 2007 wells had
already been plugged and abandoned.
I don't use the well count. For each vintage group, for each exact year
on production, I sum the latest 12 months production, and compare it with
the total (again over all relevant wells) 12 months production of the prior
year on production.
For example, to calculate the decline rate of the 2008 vintage group,
in year 4, I calculate the total production these wells had in their 4th
year of production, and compared it to the total production from the same
wells in year 3 on production.
I have excluded wells that appear to have been refracked from the whole
set, to try to establish the natural rate of decline.
As I noted in my comment, I agree that this works for volumes, but not for
rates of decline, i.e., there is no difference between rates of change for
total production by vintage year versus total production by vintage year,
divided by the original number of wells.
Following is an excerpt from my comment linked above:
Following is a model with more relevant (hyperbolic) simple percentage
decline rates. I assume a fully developed lease with 10 producing wells,
all completed in 2010. There is one very good well, with 9 relatively
poor wells. Production drops by 40%, then 30%, then 20% and then settles
down to a 10%/year decline rate. The lease loses three wells per year,
until it is down to the one good producing well. Here is the model:
From 2014 on, production declines at 10%/year, from one well.
The exponential year over year rate of decline in total production from
2012 to 2013 was 22%/year (natural log of 336/420).
If we divide the 2012 and 2013 production by 10, i.e., the original number
of wells completed in 2010, the exponential year over year rate of decline
in production was also 22%/year (natural log of 33.6/42.0)–as the number
of producing wells on the lease fell by 75%.
So, again, unless I am missing something, it seems to me that the rates
of decline chart you showed reflects the rates of decline in total production
by year, without any weight given to survivor bias.
Are you disputing this?
The only way I see to address the survivor bias issue is to show the
number or percentage of plugged/inactive wells by year, on the same chart
as the year over year rates of decline chart. On the example I showed, the
plugged/inactive percentage would be 0% in 2010, rising to 90% in 2013.
I understand your example, but I don't see an issue regarding survivor
bias. The 22% is the decline number I am interested in, as it reflects the
total decline that can be expected for that group, for that year.
In any case, it's a non-issue for now, as not many wells are dropping
out yet (about 1% of wells a year). Let's leave it at this.
I understand your example, but I don't see an issue regarding
survivor bias. The 22% is the decline number I am interested in,
as it reflects the total decline that can be expected for that group,
for that year.
I agree that the 22% decline number reflects the decline from the wells
still producing, and the percentage of plugged/inactive wells may or may
not be material in regard to survivor bias. But that is not the issue. It
doesn't matter whether 1% of the original producing wells or 50% of the
original producing wells are plugged/abandoned at a given point in time.
This is a math question.
If production for a group of wells (not my model wells) completed
in 2010 declines by 80% from 2010 to 2015, while the percentage of plugged/inactive
wells (completed in 2010) increases from 0% in 2010 to 50% in 2015, are
you seriously asserting that there is not a survivor bias issue? Or
for that matter, if the percentage of plugged/inactive wells increases from
0% in 2010 to 1% in 2015.
In any case, why not include a chart showing the percentage, by year,
for the plugged/inactive wells along with the chart showing decline rates
by year? For example, 100% of the wells completed as oil wells in 2010 had
some level of production, and what percentage of those 2010 wells were plugged/inactive
by year, as time goes on?
Probably the best way to show a survivor bias chart is to show the number
of wells showing some level of production as time goes on, expressed as
a percentage of total number of wells with reported production in the reference
year. That way, the slope of the curve would be in the same direction as
the slopes of the decline rates. For my example, the survivor percentage
by year for my 10 well model would be:
2010: 100%
2011: 70%
2012: 40%
2013: 10%*
*2013 and subsequent years until last producing well is plugged.
Of course, when the survivor percentage hits 0%, production = zero.
An interesting question would be projected half-life, to-wit, how many
years would it take for the survivors among a group of wells completed in
a given year, e.g., 2010, to be reduced to 50% of the original number?
As noted above, the observed half-life for the 2007 vintage wells completed
on the DFW Airport Lease in the Barnett Shale Play–the wells that Chesapeake
asserted would produce "for at least 50 years–was about five years.
As Enno points out for the Bakken/Three Forks after 8 years about 1%
of 2007 wells that were not refracked have been permanently abandoned.
The average 2008 to 2012 well will be shut in at about year 15 if they
are profitable to produce at up to 7 b/d of output. This will depend on
oil prices in 2023, which are hard to predict.
Are you now arguing that the survivor bias is not material, whereas you
previously, and repeatedly, asserted that there was no survivor bias in
regard to rates of change calculations? Following is a link to the original
question, followed by three of your comments:
I have given you that data in the past. The well profiles do not
have survivorship bias as long as a zero is entered for output for abandoned
wells.
That is what Enno does.
I can send you Enno's spreadsheet or Ron can, just email and ask.
Dennis Coyne ,
02/24/2016 AT 7:11 AM
Hi Jeffrey,
To me (and possibly Enno), using the original 10 wells in the denominator*
is adequate to calculate the average well profile. Note that in the
first five years the wells abandoned are very low (probably less than
1% per year). As I said before, request Enno Peter's data from Ron and
make any chart you would like. Oh and it would be nice if you stop claiming
survivorship bias when both Enno and I have repeated this several times,
but you continue to bring it up.
Dennis Coyne ,
02/24/2016 AT 1:36 PM
As I said before get the spreadsheet and do what you like.
There is no survivorship bias in the average well profiles published
by Enno Peters.
Following is my original question, followed by Enno's response. My point
was and is that Enno's approach is a pointless exercise in regard to rates
of change, since he is, in both cases (with or without attempted survivor
bias adjustments) simply calculating rates of change in total production.
Jeffrey J. Brown ,
02/23/2016 AT 11:47 AM
Is there a provision for "Survivor bias?"
In other words, how many wells that were put on line in 2007, 2008,
etc. are plugged & abandoned or temporarily abandoned?
REPLY
Enno ,
02/23/2016 AT 11:57 AM
Jeffrey,
Yes, in my ND data I always add 0 production months after the last
reported month by the NDIC. So no survivor bias in the info I present.
And here is the question that Enno has still refused to address:
If production for a group of wells (not my model wells) completed
in 2010 declines by 80% from 2010 to 2015, while the percentage of plugged/inactive
wells (completed in 2010) increases from 0% in 2010 to 50% in 2015,
are you seriously asserting that there is not a survivor bias issue?
Or for that matter, if the percentage of plugged/inactive wells increases
from 0% in 2010 to 1% in 2015.
"the percentage of plugged/inactive wells (completed in 2010) increases
from 0% in 2010 to 50% in 2015" This is a hypothetical assumption. The real
number of plugged wells is low and therefore it can be ignored
The 50% abandonment number in five years was based on a real life case
history in the Barnett Shale Play, the 2007 vintage wells on the DFW Airport
Lease that Chesapeake asserted would produce "for at least 50 years."
As I said, it doesn't matter whether one assumes a 50% or a 1%
abandonment percentage in five years, this is a math question.
Are you guys incapable of answering a math question?
Enno and Dennis have repeatedly asserted that that there is NO survivor
bias.
In any case, at least for people who do not reject fundamental mathematical
principles, it's when, not if, that survivor bias becomes a factor in regard
to year over year rates of change calculations.
Lets say output was 500 kb/d in 2010 from 500 wells and in 2015 these
same 500 wells were producing 100 kb/d, but only 250 of the wells were producing.
If I use 250 wells in the denominator for both 2010 and 2015 to find the
output of the "average" well then in 2010 the average well produced 1000
b/d and in 2015 the average well produced 200 b/d.
There would be survivorship bias if I claimed the "average" well produced
200 b/d in 2015 and that is not what I do.
So I don't see any survivorship bias. As long as we include all the
wells in the data (including those abandoned) survivorship bias is eliminated.
Perhaps Enno and I understand this term differently from you.
Enno and I consider output from the entire play or in my case I will
often construct a hypothetical "average well" where the average well profile
is equal to total output divided by the total wells completed.
You are correct that this is a question of arithmetic.
Let's say 50% of the wells were abandoned and initially there were 100
wells completed. If we take total output and divide by 100 to find the average
well profile, then for this hypothetical average well there is no survivorship
bias.
There would be survivorship bias if I divided output by the number of
producing wells to find the average well profile, but that is not
what is done, I use 100 in the denominator even if there are only 50 wells
producing (in the example above.)
I agree that the 22% decline number reflects the decline from the
wells still producing, and the percentage of plugged/inactive wells may
or may not be material in regard to survivor bias.
The 22% decline rate reflects the decline rate of all wells completed
not only the wells still producing.
Let's say 1000 wells were completed and output was
100 kb/d (example chosen for simple arithmetic rather than realism) in the
first year, let's also assume that 1 year later output fell to 80 kb/d from
the initial 1000 wells, but that 100 wells were plugged and abandoned.
No survivorship bias
year 1 output is 100 b/d for average well
year 2 output is 80 b/d for average well
a decline of 20% for first year
Survivorship bias
year 1 100 b/d for avg well
year 2 89 b/d for avg well (80,000b/900 producing wells)
a decline of 11% for first year
I don't use the number of producing wells, I use the total wells completed
in the denominator no matter how many wells are producing, that eliminates
any survivorship bias.
The answer to your question in bold is yes that is exactly what
I am asserting.
As long as one uses 10 wells in the denominator for all years to construct
an "average" well profile there is no survivorship bias, if one used the
number of producing wells in the denominator there would be survivorship
bias.
I use your model above to find a NSB (no survivorship bias) average well
profile and an SB (survivorship bias) average well profile. Chart below.
As noted up the thread, I showed that dividing annual production by the
original number of producing wells (10 wells in the model I showed) to correct
for survivor bias has no effect on rates of change calculations. In both
cases, one is simply calculating the year over year rates of change in total
production from surviving wells , and as noted, it's when, not if
that it becomes a material factor.
Dennis had the following response in one of his previous comments:
To me (and possibly Enno), using the original 10 wells in the denominator
is adequate to calculate the average well profile.
How does one respond to people who reject fundamental mathematical principles?
More importantly perhaps, why should one waste one's time responding to
people who reject fundamental mathematical principles?
I think it's time for another grizzled oil patch veteran to bid you guys
adieu. Good luck with your continuing efforts to, in effect, to assert that
1 + 1 = 3, because it feels like a better answer.
Jean Laherrere had a post on POB that indicated a 20 to 30 month lag between
rig count and production, during the expansion phase. Empirically the curves
seemed to match but I don't get why the delay is that high or the correlation
so close. However if true it would suggest production is going to fall off
of a cliff over the next 2 to 6 months.
"Another reason why production hasn't fallen as rapidly as some expected"
Rats can chew thru a PV Source circuit and you have barbecue but Future
Energy Production is not Jeopardized. With an unconventional well It's my
understanding that the Resource may be affected if shut in or altered. Perhaps
in the environment, E&P's "can not afford" to take this risk (??)
Baker Bughes in 2012-2014 issued well count for key U.S. oil and gas
basins.
Using the well count and rig count, they have calculated the number of wells
drilled per 1 rig per 1 quarter and year.
Unfortunately, this product was discontinued in 2015.
I was wondering about my claim (which may be incorrect), that during
a bust the less qualified or hard working people get laid off and a company
is left with their best workers.
If that is correct it would seem that the elite crew that remains would
make fewer mistakes and get more accomplished on average on any given day.
This would tend to increase rig efficiency (number of wells drilled per
month per rig) if we assume everything else is unchanged (which is never
correct in the real world.)
Dennis, company men (middle management, on site supervisors) get comfortable
with certain rigs and the personal on those rigs. If Dennis is given 14
wells to drill in 2015 he will stick with H&P 395, if he can, because he
is on a first name basis with the toolpusher and everyone else and they
all work in 3 part harmony; hands will stay with a rig and the rig boss
(toolpusher). There might be some inner rig contractor personal movement
based on time with the company, etc., I don't know anymore. If Nabors 419
gets stacked, most of the hands on that rig will go to the house. When I
roughnecked, and was a driller, when my rig got stacked I went mostly to
the wine shop and waited it out. Certain companies generally ask for certain
rigs if they can.
Again, I don't think rig efficiency can improve much; I think I have
already said as much. Those shale rigs get it and go. Its like tire manufacturing,
almost. There is always a problem that comes up. Think of all the wells
they have drilled in the past 7 years; everyone on a rig, and steering,
and running casing, and cementing and frac'ing know what the drill is now.
Fourteen wells per rig per year is what I guess, maybe 15 depending on pad
stuff. Costs will not go down based on efficiency as much as competition
between rig and pumping services vying for limited work.
I read that CLR will return to activity if prices reach $45. At least that is the headline.
Assuming 200K gross barrels of oil from a CLR Bakken well in 60 months, 160K net with 20% royalty,
with a $7 discount to WTI, per CLR recent 10K, such a well will only gross $6 million dollars
in 60 months.
So after 60 months CLR will still be over $1 million short of reaching the cost of the well,
BEFORE, considering 10% severance tax, OPEX, G & A and interest. Also, none of the land acquisition,
permitting , seismic, etc is considered.
Why do the MSM ignore this. It seems so elementary to me.
Bakken LTO needs $80 WTI, minimum, to be a good investment. Just do my 5th grade math. Don't
need any exotic presentations to figure this out.
SS,
Don't pay attention to headline. They are just part of deception game. Shale production is adjusting,
US on shore is adjusting. Today I have briefly scanned that Russian paper is stating that Russian
big oil have a meeting today where among the topics are "freeze" (previously discussed with Saudis,
Qataris) and even some possible cuts. Pieces are coming together although it looks like at snail
pace from the perspective of someone like you that is caught in this bullshit politics. But it
is coming.
Bakken LTO needs $80 WTI, minimum, to be a good investment. Just do my 5th grade math. Don't
need any exotic presentations to figure this out.
Exactly!
Bakken oil production is more like mining coal than it is drilling for oil ("Red Queen effect").
All company operating in this areas have crushing debt levels. Obtaining revolving credit line
when prices are below $80 might become very difficult as Bakken has the highest marginal cost
of production. So this slump will last longer for Bakken then for other plays.
Also "carpet bombing" drilling is new and might have some additional effects that we now can't
predict. I would give three years on restoring investor confidence.
Click to Edit
Request Deletion (56 minutes and 59 seconds)
Thanks Shallow for digging thru these filings and Uncovering what should be clear --
Fernando posted this yearly cash flow matrix ROI for the Powerwall which shows that Energy stored
via Electro-Chem can not compete yet with the Delta of baseline vs peak power rates. When I point
this out to people this they think I'm clueless. Anyway – Need something like this for wells in
different plays or companies to point out the Insanity. Perhaps I missed it or i'm actually clueless.
Three Big Shale Plays Decline Rate Going To a More Than One Million Barrels A Day!
Using Ron Patterson's updated rig counts per play, I used that data along with production data
from the EIA Productivity Report to calculate the expected overall decline rate per play.
All data is per month.
The Bakken has 36 rig running, and has a "New Well Production Per a rig" of 725 barrels per
day, and a decline rate ("Legacy Production Change) of 58,000 b/d.
New production (rig times rate) is 26,000 b/d so the net decline rate (new – decline rate)
is 32,000 b/d
Doing the same calculation for the Eagle Ford
Rig = 41
Production per rig = 800
Baseline Decline rate = 110,000
Net decline rate = 77,000'b/d per month
Permian
Rigs = 162
Production per rig = 425
Baseline decline rate = 83,000 b/d
Net decline rate = 14,000 b/d per month
Adding the net decline rate for the three plays we have an overall decline rate of 123,000'barrels
a day per month.
That comes out to a yearly rate of 1.47 million barrels a day.
We are not at that rate today as it takes time for dropping a rig to effect production rates.
I would expect to see thus overall rate by some time this summer. It is much larger than anyone
is expecting.
"... consider Ilambiquateds previous mention of what I call, The Shopper-Shafter, for apparent programmatic-mining of reciepts for patterns to optimize prices as high as possible to help shift the baselines in the race to the bottom. Have I got that right, Il? May I suggest you somehow incorporate Kardashian as spokesperson and have her riding the new bigger/better/badder Toyota Priapus in a Race to the Bottom Sweepstakes! ..."
Carl Martin: Is an average EUR of 750,000 net bbl of oil per well accurate in the Bakken? It doesn't
appear that it is when one looks through the public information put out by the State of North
Dakota. Further, it doesn't appear generally that Continental has the wells capable of hitting
this figure. EOG and Whiting are the primary companies to have the wells capable of 750,000 net
bbl EUR, based upon public data.
I have read on this site that 320,ooo gross bbl EUR is more probable overall in the Bakken,
although I am sure if people have agendas they can skew the numbers. I think at least a few of
the people who post here appear to have strong enough math/science/engineering backgrounds to
make some pretty reasonable calculations and are making an unbiased attempt to be as accurate
as possible.
Trying to figure out what is accurate and what is not is more difficult than what you let on,
IMO. It does appear that substantially lower oil prices may provide some answers.
There is that. 2.7 Billion at $10 million/well, from the CLR Nov investor briefing, is 270 wells.
For the whole year.
Avg flow year 1 is about 450 bpd? So incremental revs in 2015 would be 270 X 450 X $30 (net
of Bakken Sweet minus royalties, taxes) = $3.65 million, for the whole field for the whole year
from new wells.
Maybe Warren Buffett will do what he did for BoA. They created a special preferred issue for
him to buy $5 B of. Paid 8% dividend or something. Hell, he may get more of Harold's money than
the ex.
"Avg flow year 1 is about 450 bpd? So incremental revs in 2015 would be 270 X 450 X $30 (net of
Bakken Sweet minus royalties, taxes) = $3.65 million, for the whole field for the whole year from
new wells."
err I think you forgot that a year has 365 days? That comes out to more than 1.3 billion dollars
even at these depressed prices!
The average well flow for the first year is about 233 b/d, not 450 b/d (second month output is
usually highest at about 400 b/d), the average well produces roughly 85 kb in year 1.
Using Watcher's figure of 270 wells and call refinery gate oil prices $60/b, transport costs
$12/b, OPEX plus other costs $8/b leaving $40/b, then we need to pay taxes and royalties of roughly
25% on wellhead revenue of $48/b, so we need to subtract another $12/b and we get to $36/b net.
If 270 average wells are drilled we get about 23 million barrels of oil in year 1 for a net of
$826 million. The wells cost about $9 million each for a total of $2.4 billion. Looking at a single
well, we need 250 kb for simple payback (ignoring the time value of money), but the average Bakken
well takes at least 8 years to reach 250 kb of output, typically a "good well" pays out in 18
months or less. At two years the average Bakken/Three Forks well in North Dakota produces about
130 kb which is about $4.3 million in net revenue and far short of a $9 million payout level.
No, the 750,000 boe is just a reference to CLR's claim, that they have eight years of drilling
activities, that can produce that much per well. TRANSLATION: The current low oil price environment
is easily weathered by simply high grading. Any company with similar property can do the same.
But, many of the newer, smaller Bakken dotcoms have no such property, so their very existence
is in great danger.
It is nowhere near the average Bakken EUR.
By the way, unlike so many others here, I don't guess anything, and have very few opinions
of my own. I mostly just repeat what is generally accepted knowledge about the shale industry,
because no one has so far been able to prove any of it to be wrong.
It's just that none of my researched information supports any PO theory at all. That's the
rub.
So at what cost does oil have to be produced in the future? Where are we find this oil? And are
you so negative about renewables you think they won't be competitive with oil at $500 per barrel
in today's dollars?
Enno Peters collects data on all North Dakota wells from the NDIC, the EUR of the average Bakken
well between 2011 and 2014 is about 325 kb of oil, if you add in natural gas and convert to barrels
of oil equivalent(boe), it increases to 406 kboe, but note that the extra 80 kboe is very low
value relative to crude.
Note that the typical well in an investor presentation is not the same as an average well.
Maybe CLR only drills above average wells.
I don't dispute your average EUR numbers, as I don't have the neccesary info to do so. Besides
that, they sound about right to me. But you need to be careful about getting too hung up in
the word or concept of average. After all, what do you think is the average gender in the US
in Dec. 2014?
Investor presentations ALWAYS show their best results, and almost never reveal all the failures,
that bring their averages down. This is just business as usual. But, it is okay because they
are always moving up the learning curve, so by showing their best results now, they are giving
a clear indication of where they expect their average results to one day be.
Also, if you want to understand this industry, it does no good to focus on average companies,
you need to look at the leaders, because they are the trend setters. Ultimately everything
is based upon best practices, and EOG is presently the undisputed best at everything. They
just don't keep investors very well informed. Therefore, I still get most of my info from CLR.
This sentence of yours is not as silly as you might think. "Maybe CLR only drills above
average wells." In a sense, "they do." That is to say, that they have no monster wells, that
I know of, they choke a lot more than others, and they have used their standard 10,000 foot
lateral and 30 frack stages well design over most of the Bakken, even when it didn't make economic
sense to use it. It is because they use their standard well as a measuring stick. Now they
have a fixed point for reference to compare different areas of the Bakken.
That's why they know exactly what they are talking about, and why I accept most everything
they say. You obviously don't. But, you have never given a good reason for not doing so, other
than the results they are claiming don't show up in the data bases you are using. Why don't
you just send them an email and try to clear up a major misunderstanding on your part? Then
everyone at this website will be able to move forward.
Continental wells with first month of output between Jan 2009 and Oct 2014 have an average
cumulative output over 70 months of 186 kb, this is slightly below the average Bakken well
over the same period for all wells completed(925 wells).
There is a lot of hype in investor presentations.
The Continental wells will produce considerably less oil that the 480 kb claimed (only 80%
of the 600 boe EUR is oil) in investor presentations. The EUR is more in the 250- 300 kb range
for the average Continental well.
I wonder if they have run flow meters to check how much flow they get from the toe of a 10
thousand foot lateral. You seem to follow this closely, are those wells slugging?
Dennis, sometimes very long wells in three phase flow can have phase segregation in the horizontal
section. This causes liquid slugs to accumulate, which tend to move up the well in slug flow.
This can be avoided by placing the heel higher than the toe. But I've never worked with a 10
thousand foot well. And I was wondering if they had sensors to confirm the toe is producing.
I came to the same conclusion as you Dennis. The Continental wells are actually bellow average.
I have attached a graph showing the production profile for Continental wells from January 2010
to October 2014. I also included the average Bakken well profile for 2010 for reference. The
first 3 year cumulative oil + gas production for an average Continental well is about 170.000
boe. No one knows what the EUR will be, but EIA suggests that 50% of the oil has been produced
during that time (
http://www.eia.gov/forecasts/aeo/tight_oil.cfm ) which gives an EUR of about 340.000 boe.
Carl, you are saying yourself that they only show the best results and don´t tell about
their failures. So why should we then believe in anything they tell us? I have learned that
you should never ever trust in what companies tell in their presentations. Especially not smaller
companies which are dependent on cheap credits. It is actually quite disturbing that companies
can make such exaggerations and get away with it.
I however agree with you Carl that there are still drillable locations left in sweetspots.
But perhaps some companies start to run out of them. That would affect total Bakken output,
which I am mostly interested in.
I posted a chart for average Bakken cumulative output per well by company for four large companies
over the Jan 2009 to Oct 2014 period( about 1/3 of all ND bakken/Three Forks wells drilled(3462
wells).
The "avg" well is for all Bakken/Three Forks wells in North Dakota over the same period with
a cumulative of 197 kb per well over the first 58 months of output.
Chart came out a little small the first time so I will try it again.
I put together data for more companies, about 75% of total wells, too many for a clear well
profile so I am using a bar chart with 54 month (4.5 year) cumulative output for the average
well for each company over the Jan 2009 to Oct 2014 period. The average Bakken well is shown
for comparison. Companies with more than 200 wells over the chosen period are presented below.
Surprised by QEP, they don't get the hype the others do. Always assumed EOG had the most
productive wells in the Balkan due to Parshall. Must have wells in other areas which bring
the average way down.
I wish TX reported by well as opposed to by lease. Would be really interesting to see the
same info for EFS and Permian horizontal wells.
Really seems irresponsible for these companies to claim EUR oil at 600,000+. I guess they
assume the wells will produce 40-60 bbl per day for 25 years. Will be interesting to see if
they do.
It looks like the quote from the other day, "Continental must drill all above average wells",
may need some adjustment. To "Continental must drill all below average wells"?
I show the North Dakota Bakken/Three Forks cumulative average well profiles by company for
the Jan 2009 to Oct 2014 period, total wells for this set of companies is 6472 wells of about
8054 wells completed (drilled and fracked) for all companies operating in the North Dakota
Bakken/Three Forks (80%). This is where I got the data for the bar chart. QEP energy is the
high well profile and OXY is the low well profile, the middle dashed line is the average well
profile for all companies (including those not presented in the chart).
Exactly, Mr. Walter. If one uses the ND DMR Gis map to get a micro view, then glance at 'bigger
picture' using either Mr. Hughes' colored dots or – more informatively – the aforementioned
ND slides, it should be clear that the high productive/sweet spots (red – Hughes, yellow/white
– DMR) have a lot of drilling yet to go.
That's a great graphic that shows many things. The spacing on virtually every one of those
wells is st least 1,200′ apart. The successful down spacing will prompt a near doubling of
those wells if the 700′ spacing proves widely workable. The designs of the fracs are more and
more purposefully geared to extend no farther than 300′ or so from the wellbore.
The underlying Three Forks formation has at least two or three productive layers that the USGS
actually claims to be larger in recoverable hydrocarbons than even the middle Bakken.
Crowded dance floor? If Shania walked in, room would be made garonteeed.
I have a geologic theory to propose on the basis of no evidence. Doug, listen up. Mike, ditto.
So we drilled and fracked a lot of laterals. Then we are going to shut down. For a year
or three. We're going to near zero output. Loss of 3.5 mbpd, up the imports to keep people
fed, etc.
People come back and say, the price is up. Let's get going again.
But down there 10,000 feet we have four counties that have been pin cushioned and nanopores
down there having been subjected to 3-5 yrs of explosion type vibrations. And there are lots
and lots of empty pores now, from wells drilled and emptied.
If we give the nanopores in the undrilled places long enough, with very poor natural permeability,
and lets say long enough isn't a million years, lets say it's just 3, might that oil flow over
to the empty pores?
Then you have drilled and fracked wells that refilled, but only about 1/8th of what they
had. The pressure is gone. Much more important, those areas not yet drilled are losing their
oil. It's flowing to the already drained wells.
I *think* this makes the whole field uneconomic pretty much forever? No one well will have
enough in it to warrant going after it?
Heh Watcher, I'm currently "in transit" and, damn it, I left my crystal ball on the mantle.
Truth is I have no idea. My gut feeling is you could come back and carry on. Perhaps the areas
drilled like Swiss cheese would be degraded on some scenario like you suggest, BUT, in general,
tight formations are tight and fracked "cylinders" could (should) be independent (new) structures
- I imagine. But your opinion is as good as mine. And although I've some geological savvy I've
zero LTO experience. I'll think about your question on our next flight leg but main concern
right now is Christmas presents getting to Norway (Bergen) in one piece. Meanwhile keep doing
your stuff. Cheers.
Watcher, one quick comment before I go to work, its never good to frac a well then shut it
in. I know that is true in fractured carbonates and other tight sandstones, it must be true
for shale also. As you elude to, the frac "energy" is lost over time (like blowing up a balloon
and the letting it squeal out the outlet). Natural micro fractures in shale are expanded and
filled with proppant during the frac process; they will closed back if the well is not produced.
At that depth there is over burden forces that cause proppant to embed into the shale also
closing the fractures.
Well, I don't know what the scale is on that map and neither to you. Lets assume you are right,
they'll go back in between those wells and drill more wells, when the price of oil is 119.oo
dollars a barrel. But to accommodate that, spend more money and get even more in debt, they'll
re-tweak the frac-radiuses on those wells so they DON'T interfere with each other; less sand,
less rates, fewer stages?
But wait, I thought they were doing just the opposite, they were using more sand, more water,
bigger rates, more stages, super-hero, big-boy frac's…no? Might they be doing that to increase
frac radiuses and URR on a given unit…to keep from having to drill in between wells? I am confused.
Whooptie to doo on the stacked horizon thing. Not so good, I hear. And the USGS, well, the
boat done left the dock without them out there in California, uh?
Time to give up the ghost. Time for the shale oil biz to tell it like it is. They'll win
friends and influence more people by telling the damn truth!
Mike, both you, I and anyone can get precise scaling from your graphic by clicking on the above
(Mr. Walters) link which takes you to the North Dakota DMR Gis map. It contains a ton of info
– including physical locations – of every well drilled in the state going back to the fifties.
The one sq. mile rectangles are formed into 1,280 sq. acre/2 sq. mile Drilling Spacing Units.
The issue of mimimally effective spacing between wells is an ongoing quest with companies like
Carrizo claiming success with 300 foot spacing in the Niobrara.
Gotta go. Best wishes and best of luck to you all.
Just curious as to why you (apparently) think that oil companies don't actually want well
communication ( well interference/ pirating) between wells in the same zone?
The actual production of oil wells is highly influenced by all the natural low grade seismic
activity going on in their area. Fracking is just artificial low grade seismic activity, and
there is considerable evidence out there, that fracking actually improves overall oil production,
if there is well communication going on within specific zones. That's why nearby wells are
temporarily shut in during fracking operations. But, so far no one wants well communication
going on between two different zones, because it would be too difficult to monitor and control.
If done correctly very close down spacing can result in greater overall productivity, and
at a lower cost. That is, after all, why it is done. Would you consider doing some homework
on this issue?
The actual production of oil wells is highly influenced by all the natural low grade seismic
activity going on in their area.
Uh?
I am sitting on a rig right now trying to get home to see my family for Christmas, Mr. Martin.
I don't have the time, nor the inclination to engage with you, or whomever, about lofty shale
oil EUR's and years of drillable locations, nor do I seek to debate you the merits of zipper
frac'ing, interlacing frac tips and the economics of infield development. Whatever you have
to say about it comes straight off a shale oil website, or quarterly report, anyway. I have
heard it all before. There must be a press package to download somewhere.
The point that you wish to make, I think, is that I have it all wrong, as do a lot of people
that post here often, about shale oil. It is everything shale oil companies say it is, that
you say it is, and much more. Got it!
It is geology 101 and has nothing to do with shale oil companies. All the rocks on planet
earth are in constant (slow) motion. The proof of this can be seen in oil production. In any
given area, or well, it is not at all steady. You can easily see how oil production jumps in
all the wells in a given area, when a minor seismic event occurs nearby. Why don't you ask
a geologist in the company you work for about this phenomenom?
I've been here and done this before with another oil field worker. Just because you happen
to work in an oil field doesn't mean that you know much about the business. What you know,
or don't know, certainly gets revealed pretty quickly in a forum like this.
You are basically saying that you won't prove me wrong, because you don't have time to do
so. That's just a cover up. You won't attempt to prove me wrong, because you simply can't,
but your hurt pride won't allow you to admit it.
We are all witness to what coffeeguyzz has said to you, and you wern't left with a leg to
stand on. Sorry, but I've yet to meet a PO believer who has not revealed himself to be anything
other than a hot bag of air.
If that shoe doesn't fit you, then I'd sure be interested in anything further you have to
say.
Carl: "The actual production of oil wells is highly influenced by all the natural low grade
seismic activity going on in their area." What's your point? Are you suggesting micro seismic
events increase or decrease well productivity? I've never heard anyone suggest micro seismic
activity correlated with oil flow rate increases. I've no doubt strong events affect rock permeability,
in various ways, but would be loath to say it was working in one direction. Of course there
is always background activity (as well as diurnal (tidal) rock formation flexing). If you wish
to pursue this I recommend: Stress Waves in Solids by Kolsky, a readable work on wave propagation
in non-elastic solids.
Doug, I can't get too detailed about it here…in some cases we have both lab, and field, data
showing vibrations and pressure pulses increase recovery. I have a theoretical outline for
pressure pulse effects in heavy oil displacement I may publish one of these days. I haven't
seen data for fractured tight zones, therefore I can't say anything about it, but I wouldn't
toss ideas in the waste basket so fast.
Mr. Leanme, the comment above implied "natural" seismic activity in the earth "highly" effects
the consistency of oil production (everywhere). Oil pressure "jumps" in areas of seismic activity,
that sediments are constantly moving. I don't buy that, not to the effect they change production.
I have not seen that in 50 years of doing this stuff. We were not talking about induced seismic
pulsation or vibration down casing, that sort of thing. I have experienced that theory; in
clastic sands and fractured carbonates it did not work.
Mr. Martin, by the way, you have the manners of a goat. My trying to get home from a well
to see my family for Christmas was not a "cover up." I wished you a Merry Christmas and you
then insulted me. I am not retired (at 65), nor am I an "oilfield worker." I am still actively
engaged in exploration and production, from developing the prospect to seeing the end result
into the tanks and managing the production over the ensuing years. That is how I feed my family
and the families of my employees. In other words, I have to invest my money into my beliefs,
my money where my mouth is, so to speak. How 'bout you? That does not make me an expert on
anything, on the other hand I don't like to be insulted by kids on computers who develop ideas
based on website dribble. I think clearly your ideas about 750K EUR's is BS. You just got embarrassed
with some real data.
Indeed there are lots of straws to still get stuck in sweet spots, big deal. I believe,
and several very smart people believe, that sweet spots are being depleted. Production data,
declining IP's, increasing GOR and increasing WOR all indicate that, clearly. The bottom line
in all discussions of oil development, past, present and future, is based on the ECONOMIC sustainability
of that development. The numbers and fluff don't mean nada; its about the money. I am still
waiting on the shale industry to sho' me some money.
In the Eagle Ford, lateral orientation is generally dip oriented, heel to toe from NW to SE
or vice versa. I think this corresponds to stress fractures in the rock. The shale guys down
here like to drill two laterals parallel to each other, not perpendicular, and frac both laterals
at the same time, something they call zipper frac'ing. The frac's are designed so that the
tips interlace with each other to achieve better URR; that is their "downsizing" MO. Having
said that, the shale oil folks are now touting bigger frac's; more stages, tons of sand pumped
at enormous rates, to achieve greater frac radiuses to get those highly sought after IP's,
that translate into big EUR's, that translate into booked reserves that translate into happy
bankers. I don't why they would then want to drill 9 million dollar in between wells, just
to say they can, inside the partially drained radius of a nearby well but hey, if its on the
internet, it must be true.
Mike, that sure makes sense for the Eagle Ford. I was referring to the Bakken well layouts.
Some operators hace wells drilled perpendicular to the "normal" direction.
Reference the vibes and pulsing, I think it depends on the reservoir. Pulsing works with
highly viscous oils if the reservoir is being flooded. It works much better if the producers
aren't cutting a lot of water. I saw some odd results for vibration but that may have been
fake data put out by a promoter. But none of this is from natural seismicity.
Fernando, "but I wouldn't toss ideas in the waste basket so fast". I'm not sure how saying:
"I've never heard anyone suggest micro seismic activity correlated with oil flow rate increases.."
is tossing anything in a basket. I understood Carl's comments as being directed at NATURAL
micro seismic activity. Pulsing (something that you introduced) doesn't seem relevant to Carl's
(or my) remarks.
A few people have mentioned higher density drilling in the Bakken and the layers of the
Three Forks which might be exploited.
The Continental Hawkinson well data is available which is a poster child for higher well
density (more wells per square mile).
Note that the first Hawkinson well was drilled in the three Forks and started producing
in Feb 2010 and was very productive (356 kb over first 24 months), two more wells started producing
in Sept 2011 (one in middle Bakken and one in Three Forks). All three of these wells look like
they were refracked by Sept 2013 when 11 more wells started producing as part of the high density
experiment. Early wells were averaged together by month from first output, the early wells
are the first 3 wells which started producing Sept 2011 or earlier.
Later wells are the 11 wells which started producing in Sept 2013 (7 are Three Forks wells,
3 are middle Bakken, and one is not labelled). The later wells produce an average cumulative
output about 40% lower than the first 3 "early" wells.
Chart with individual Hawkinson wells, the indication is that higher density drilling will
reduce the average well output, despite what the investor presentations might suggest.
Another point, is that sometimes people claim that with low prices the oil companies will
just drill in the "sweet spots". As the Hawkinson wells show, even in a sweet spot, as the
first three wells clearly were, further drilling does not always produce high EUR wells, you
don't really know what you will get until you drill and frack and then start producing.
Seems to me the key to this business is to batch drill and complete multiwell pads, use liners,
gas lift, design surface systems for 700 Barrels of fluid per day, keep things simple, automate,
keep things simp,e, widen spacing and negotiate hard to lower costs. They also need pipelines.
And this wouldn't be such a critical decision if the state used its brains and paced development
to hold state production flat at say 700 thousand BOPd. It's a shame they allowed the play
to go wild, it causes a lot of human suffering.
"…can you give any examples anywhere or anytime of what you're talking about??" ~ Nick
G
You.
And/or some of your comments, what they seem to suggest, and how they sometimes read– like
a corporate commercial shill … Maybe that G is actually a 6? …Looks a little funny
over here on my screen… Maybe there're attempts being made to assimilate/upsell me as well…
Should I upgrade to the new Nissan Leaf-blower or the Toyota Priapus?
"Permaculture and relocating to the land may solve most of fossil fuel lack of supply."
~ Rita
" Those are unrealistic . Electric transportation, biofuels and synthetic fuels
would work just fine…
A Nissan Leaf is the cheapest vehicle on the road to own and operate (with the tax credit!),
and it'll get you to any job within 40 miles (and 80 miles, if you can charge at work).
A Chevy Volt is among the cheapest vehicles, and it'll take you anywhere…" ~ Nick 6
' With the tax credit! '.
…Examples ostensibly suggestive of those caught in the Matrix/Plato's Cave, and upholding
it while subverting their own foundations, lives, freedoms, fellow creatures. The ultimate
prisoners perhaps, ones that don't believe they are, and that resist reasonable attempts at
being freed.
"In The Decline of the West, Spengler noted that the last phases of every civilization are
marked by increasing technological complexity. This is strikingly true of planetary culture
today…
…'Why Civilizations Fail' outlines quite ably the reasons why civilizational failure is
inevitable, why the grasping control ethos of domestication comes to its self-defeating end.
The book's first sentence also serves very well to announce the fatal illusion that prevails
today: 'Modern civilization believes it commands the historical process with technological
power.'
The fallacy of this belief is becoming clearer to more people. After all, as Jared Diamond
puts it, 'All of our current problems are unintended consequences of our existing technology.'
In fact, civilization is failing on every level, in every sphere, and its failure equates so
largely with the failure of technology. More and more, this is what people understand as collapse…
Despite this reach and height, the rule of civilization is based on less and less [
consider Ilambiquated's previous mention of what I call, 'The Shopper-Shafter', for apparent
programmatic-mining of reciepts for patterns to optimize prices as high as possible to help
shift the baselines in the race to the bottom. Have I got that right, Il? May I suggest you
somehow incorporate Kardashian as spokesperson and have her riding the new bigger/better/badder
Toyota Priapus in a Race to the Bottom Sweepstakes! ]. Inner nature is as ravaged as outer
nature. The collapse of human connectedness has opened the door to unimaginable phenomena among
lonely human populations. The extinction of species, melting polar ice, vanishing ecosystems,
etc., proceed without slowing.
Fukushima, acidifying oceans, Monsanto, fracking, disappearing bees, ad infinitum. Even
rather more prosaic aspects of civilization are in decline." ~ John Zerzan
In fact, civilization is failing on every level, in every sphere, and its failure equates
so largely with the failure of technology. More and more, this is what people understand as
collapse…
You and the peak oil doomers keep saying the same thing, and I'm not sure what value it
contributes. They, like you, expect total collapse.
No solutions whatsoever. If that is the case, I might as well not bother wasting whatever
time I have left to read what you guys write. If I can't do a thing about it, why should I
care what you have to say?
I have also already mentioned
permaculture . But that depends on many things.
"I might as well not bother wasting whatever time I have left to read what you guys write…"
~ Boomer II
For a second, I thought you already started not doing so. But I don't necessarily write
for you, babycakes. Nevertheless, if you like to blow the praises of Nissan Leaf-blowers or
'Shopper-Shafters', I wouldn't blame your response.
"You and the peak oil doomers keep saying the same thing…" ~ Boomer II
The same thing is BAU/BAU-lite or somesuch eat-cake-and-have-it-too/technofixes-for-technoproblems/doing-same-thing-over-and-over
thinking and manifestations… Geoengineering, wage-slave jobs for tax-theft for Nissan Leaf-blower
tax credits, etc. That's baked-in doom. You don't need your so-called 'peak oilers' for that.
Peak oil is, in a sense, almost small potatoes.
The peak oil doomers are just an example of another group of people who think we are all doomed.
I'm not sure why either of you posts. If the world collapses, what is your point? You're
snarky enough that I suspect you're doing it mostly as a troll.
At any rate, if you guys believe there is nothing to do, you are all kind of irrelevant
because we can ignore you and still face the same outcome.
Perhaps we should just let you post and ignore you.
I could argue that you're trolling me. Too easy.
The fact that we are even currently concerning ourselves with peak oil/FF depletion and effects
is precisely what I am and have been writing about– doing things ass-backwards in a nutshell.
So it is highly relevant, even if you want to pretend it isn't and want to– what is this, kindergarten?–
appeal to consensus (' we should' threat rather than ' I should') suck your
thumb in front of ' us ' about it and call me names like, "You baaad troll…
I– no, we - not want talk to you no more! (bad troll… so bad… *sniff*…)
"This is the time for our species to 'turn 21′: to transition from adolescence to responsible
adulthood as citizens of the planet, before we destroy our own future." ~ Culture Change
This is meaningless.
So what are you planning? A military revolution? A peaceful economic transition?
Growing up, smartening up , and permaculture for starters.
And suggesting some for us, yourself. Have you? If so, I'd be happy to take a look.
I might crap on this Dystem, but I do endeavor to walk the talk.
Great. Do permaculture. Get other people to do permaculture.
How do you plan to introduce it beyond where it is already being done? How do you plan to
phase out both fossil fuels and renewable energy projects and what timetable are you shooting
for?
I'm glad to see you clarify that you support a specific improved technical approach.
Make no mistake – this is simply a more sophisticated approach to agriculture. It's part
of what you might call "general progress", and is in no way in conflict with electric transportation
or other improved technical approaches to "getting stuff done".
In other words, there's no conflict between permaculture and "technofixes". Permaculture
*is* a technofix.
"Permaculture and relocating to the land may solve most of fossil fuel lack of supply."
~ Rita
"Those are unrealistic. Electric transportation, biofuels and synthetic fuels would work
just fine." ~ Nick G
"I'm glad to see you clarify that you support a specific improved technical approach."
~ Nick G
You seem to think now that permaculture is more 'realistic', despite perhaps being overly
simplistic and/or appearing less informed about what permaculture is.
But it's a start, and in any case, I did write 'for starters'. My personal verdict is not
yet out, and probably never will be, with regard to permaculture, nor with the human species.
Time will tell, outside of my own ephemeral lifespan.
You seem to think now that permaculture is more 'realistic', despite perhaps being overly
simplistic and/or appearing less informed about what permaculture is
Well, a couple of thoughts, FWIW.
1st, insults don't convince anyone, they just reduce your credibility.
2nd, I'm not trying to present an evaluaation of permaculture: I'm just pointing out that
there's nothing mystical about it – it's an improved "technique" of agriculture (yes, it's
primarily oriented towards ag). I think improved emotional health/spirituality/egalitarian
living is a very good idea, but permaculture wasn't developed by mystics, it was developed
by practical people trying to make everyday life work better.
Now, it certainly has developed into a system that's intended to promote a holistic approach
to life, and respect for all living things.
Which brings us to a basic question: is it possible to approach things through an empirical,
rational basis and come to something that is emotionally healthy, even profound?
Sure. You might want to take a look at Sam Harris' latest book: "Waking up – A guide to
spiruality without religion".
"What was even nuttier than peak oil was peak gas. The Oil Drum looked truly deluded with
the posts by Art Berman who was telling us in 08 through even last year how shale gas was declining
so much that it would go bust at less than $8."
"Probably best not to reply to him Ghung.
Gail ignores him. He attacks her at every opportunity as she refutes everything he denies.
For the last six years he's been saying things are getting better and we need to 'just buy
a Prius'." ~ Bandits
Seeing as my time is more limited than yours seems to be (paid? how? I'm envious.), I'll
leave it at that with the it-goes-both-ways-caveat, since we're on about insults…
"Never argue with a fool, onlookers may not be able to tell the difference." ~ Mark Twain
So no lightening-up or kisses? Awww… But it's almost 2015! But hostility? Moi?! Mais, cherie!
Perhaps Freud would think you were projecting? Juste un peut? Hm? 'u'
…As long I guess as you understand that not everyone has to have a grey, dull, humorless, imprisoning
approach to life. I mean, we can leave that to maybe you and the office drones on the way,
in their fossil-fuel-constructed-large-scale-centralized-governpimp-controlled-on-rolling-blackout-grid-powered
shit-box Toyota Priapuses (or is that Priapi?), to their tax-theft-for-the-governpimps wage-slave
jobs? That's what you want, isn't it? Technocracy? Plutarchic Technocracy?
Well, if so, there's a one-way-trip to Mars that might still be taking signups.
Oh yes, I got you another quote-prezzie, since you seemed less than enthused by Twain. Try
this on, see if it fits:
"If you can't dazzle them with brilliance, baffle them with bullshit." ~ ?
Cuddles,
~ Your contrived-credibility-free Cae
(…Puts down the vodka-and-green-tea-egg-nog for a moment…)
PS, Crony-capitalist-cum-governpimp-managed anything will not give us what you seem to want,
unless what you want is to live in a kind of freedom-restricted prison and to continue to wreck
our communities and planet. That's the ultimate insult, and yes, my hostility there is in abundance,
along with resentment and contempt.
But as you now seem to be conceding, it's a social problem, but 'social problem' is a loaded
term that needs to be evaluated.
PS2: All the energy developments and technical details in the world, and their discussions,
aren't worth shit (although shit's looking pretty good these days) if they disclude real, direct-democratic
community control.
PS3: Horses didn't build coal mines, humans did! (They do build usable manure though, unlike
one-trick-pony Nissan Leaf-blowers, and you can get around on them, even when the governpimps
and their pimped-out infrastructures fade into the anals of history.) 'u^
"At any rate, if you guys believe there is nothing to do…" ~ Boomer II
I had already posted 'permaculture' as well as clarified for you ( twice ) my sence
of how collapse may go ('fractal') both links of which I went through the trouble of locating
for you as well.
But we can only do so much for those who insist on being neglectful and/or willfully ignorant
or whatever…
"This is the time for our species to 'turn 21': to transition from adolescence to responsible
adulthood as citizens of the planet, before we destroy our own future." ~
Culture Change
I have already mentioned on TOD that we live in an infantilistic culture where we don't
know how in general to do much of the basics for ourselves anymore, such as with regard to
growing our own food, making our own clothes, or building our own homes. There's another clue
for you, sweetcheeks, but I can't hold your hand for you all the time, especially if you don't
want to follow and/or have your own foregone conclusions about those 'bad snarky peak oil doomers'
anyway.
Do you believe there are too many of us to go without the inputs of fossil fuels and the technology
which boosts agricultural production? We are also draining aquifers awfully fast to feed everyone.
Most of our farmland may have already been degraded beyond the ability for permaculture to
substitute for existing practices.
Permaculture is something and among what we will probably have to try anyway, like
a life-preserver thrown to us.
Its practitioners seem to think that good, healthy soil can be regenerated from despoiled with
some proper care, insight, understanding, knowledge and wisdom.
Like, Nick G's mention of 'indoor plumbing' might have to be kind of modified with
the keepsake turd in mind.
We are not all doomed. But I was wondering where you think we will be getting 100 million barrels
of oil per day in 2064? Just list a few locations, please.
I believe we ARE running out of oil. And I don't have that innocent outlook about energy sources
appearing in thin air to solve our problems. Producing oil requires an enormous effort, and
it's getting more and more difficult and expensive. This means we probably shouldn't expect
to be producing oil at the very high prices we would require in the future. On the other hand
renewables as we have today are much more expensive. This tells me we ought to be more efficient
using oil, and put more cash into renewable energy research and development. Right now I have
no idea if a solution will be found.
My assumption is that people will do something. It may not be the best solution, but I don't
think people will give up. So talking about alternatives is a reasonable thing to do.
As I have said, I get frustrated with people who are so focused on THE END that they won't
allow any talk of potential solutions or work-arounds. No matter what people toss out, if it
isn't oil, the collapse is coming and ALL people will die.
I don't believe that, so I find talk of conservation, downsizing, and alternative energy
thought-provoking. Of course it won't all work, and no, I don't think the world will support
everyone, particularly in a middle class lifestyle, but I think the world will continue to
support a percentage of the world's population.
The USGS 2000 assessment estimated 3 trillion URR, and upgraded Venezuela in 2009 to 513
billion barrels. The EIA recently estimated an additional 345 billion barrels of tight oil.
That's enough oil to last another 100 years. I wouldn't call that "running out".
With regards to renewables, Solar has already reached "grid parity", not only with oil,
but also gas and coal, in several US states. Solar will reach grid parity in all US states
in a few years.
With regards to transportation, the US has now replaced 10% of it's gasoline supply with
Ethanol. With an increasing number of electric, and hybrid electric vehicles also reducing
demand.
Worldwide, renewables provide 20% of the energy for the power grid.
These are huge gains for renewables over just a few years ago. If you were to graph out
the growth of renewables and alt vehicles, you would see that fossil fuels will be replaced
long before the supply "runs out".
renewables as we have today are much more expensive. This tells me we ought to be more efficient
using oil, and put more cash into renewable energy research and development.
This is unrealistic – renewables are *not* much more expensive. They are competitive in
many places on a marketplace basis, and less expensive if you include external costs.
Sadly, it's clear you've been reading talking points created by industries opposed to competition.
You're going to die, no solutions to that, why bother? So are all your friends, relatives,
etc. Yet still people do bother. Seems to me death should bother people more than collapse.
More inevitable and more final.
I'm not sure if this is directed to me or to the collapse people.
I believe we should be working on options other than fossil fuels, both for resource limitations
and pollution/carbon dioxide reasons.
So rather than focusing on the "this won't work," "that won't work," "collapse is coming
and we can't stop it," and so on, I like to hear how we might cope with the end of the oil
era, and what we do to slow down global warming, and how to cope if we cannot.
I get frustrated with people who shoot down all ideas and only want to focus on collapse.
In which case, I think, "What's the point?"
It's like being born and the only conversations you are allowed to have are about your death.
Boomer – I suspect you're missing the point. Collapse IS the answer to the predicament humans
currently find themselves in. BAU cannot continue without the concentrated energy that fossil
fuels provide. Thermodynamics say so, and their word tends to be pretty final.
I focus on collapse so that those around me might mentally prepare themselves for a massively
lower quality of life – lessen the shock to the system as it were. Men in particular cope badly
with a sudden reduction in circumstances; if I can prevent a few suicides by mentally preparing
folks then all the better.
We slow down global warming by collapsing the economy – it might still be too little too late
though.
IIRC the old Byzantium empire collapsed gradually in a managed way (maybe they actually listened
to their Cassandras
) –
perhaps there are lessons to be learned?
Maybe you should show how 100,000 terawatts could have built the world (without fossil fuels),
7.3 million humans occupy and by that extrapolation it will show how it will support that many
people now. If you can't then you had better look for another blog to confound with your abstract
assertions.
I won't mention that you are the same old shill Nick from TOD and still claiming electric cars,
wind mills and solar are the answer to all our woes. At one stage your answer to everything
including over population was "just buy a Prius".
Yes and he could have said the moon was made of green cheese too, so what. He claimed nuclear
was the answer. Do you say he was wrong about that? Solar power "could", you get a large amount
of "could's" from the cornucopian dreamers.
Well, sure, I was having a little bit of fun, like Watcher often does. Really, when the US
could reduce it's fuel consumption by 25% without any sacrifice at all just by switching to
hybrids, how can you not say things like that occasionally?
Uhhmmm…how could the world run on 100,000TW? Well, transportation could run on electricity
pretty well. Long range driving, seasonal ag, long distance water transport and aviation would
probably work best with liquid fuel, but that's less than 20% of our current liquid fuel consumption,
and the tech to synthesize portable fuels is here, right now. Ethanol can provide some, as
well. Synthetic fuel would be rather more expensive (at least out of pocket), but the scale
would be much smaller, so it would be affordable.
Coal and gas, of course, are mostly used for electricity these days, so replacing it with
renewable electricity would be pretty straightforward (yes, I know it's more variable, but
there are affordable solutions for that – ask, and I'll expand on it).
Well, take 100,000 TW and reduce by 99% to identify the land area that we could use without
too much inconvenience (starting with commercial rooftops). That gives us 1,000 TW. Now, divide
1,000 TW by 7B people, and you get one megawatt.
Now, compare that to the roughly .005 megawatts used by the average US resident (including
all energy sources).
The extreme boomers believe at as soon as BAU ends, homo sapiens face extinction. They believe
homo sapiens can't survive no matter what changes they make.
I see no reason to believe that. Because I expect that hardships to hit different areas
and different groups of people at different rates and levels of severity, I think some people
will survive.
I think life will be different when oil becomes so expensive that it can't be freely used.
But I don't necessarily see that as the collapse to end all collapses.
Again, what frustrates me are doomers who are so locked into the idea that the world can't
survive without oil that they refuse to consider any scenarios where oil is phased out or greatly
reduced in consumption.
I think it is reasonable to consider alternatives to an oil-fueled lifestyle. When people
won't consider alternatives of any kind, I get frustrated with them and figure they only want
to talk about total collapse, rather than talking about what can and will survive, and how.
I see no reason to believe that. Because I expect that hardships to hit different areas
and different groups of people at different rates and levels of severity, I think some people
will survive.
That is, of course, cold comfort to the billions who will die.
This extinction/not extinction dichotomy is a strawman. I suspect that most of us doomers
look at the megadeaths involved in an energy constrained future the way I do: I see the suffering
and shortened lives of billions of people. No people left, a billion people left…it's still
7 or 8 billion people who will live short lives that will probably end really unpleasantly.
I don't see a coming together to distribute the resources of the world and spread the suffering
evenly- mainly because we don't spread it evenly now .
I see a continuation of the system we have- because it means years more life for those who
can play the system. My dad is 90, and my father-in-law is 95. The average life expectancy
in 1900: 46 years. Industrial society has essentially given them 2 lifetimes.
North Americans and Europeans have a 35% greater life expectancy than Africans. Leveling
the playing field (if it were even possible, because North American infrastructure is essentially
200 years of embedded energy and the associated environmental costs) would mean giving this
up; if we didn't, why would anyone negotiate things like carbon reduction and energy use with
us?
So you can argue the extinction thing all you want- it's a mug's game. The real issue, as
far as broad social change to meet an energy-constrained future in an equitable way globally,
is whether you can persuade a majority of North Americans that they should live shorter
lives.
First, low-CO2 energy is very affordable – recent German analysis showed that 80% reduction
of CO2 emissions from their grid would pay for itself.
Second, the feedbacks from energy shortages are very immediate. Prices go up, marginally
useful consumption goes down immediately.
The real problem is the long lag times from CO2 emissions, combined with determined resistance
from the investors who would lose a great deal of money if carbon in the ground became worthless
Germany tried the solar/wind renewable energy boondoggle and all it did was astronomically
increase energy prices to their businesses and profit-makers while creating real energy poverty
for the middle class and the poor. Hundreds of thousands have had their electricity turned
off because they can no longer afford it.
Now Germany seems to finally "get" the sham that is renewable energy and global warming
(which ended 18 years ago, btw) and has been REDUCING solar/wind subsidies while also building
23 BRAND NEW Coal Fired Plants.
Meanwhile also look at Australia. The people there dumped their GREENIE-WEENIE government
and replaced it with a government that reversed the destructive carbon tax responsible for
damaging their economy and prosperity nearly beyond repair.
What's the matter Mark? Despite all the resources you have at the American Enterprise Institute
you still can't muster a single reference to support your assertions.
So you can argue the extinction thing all you want- it's a mug's game. The real issue, as
far as broad social change to meet an energy-constrained future in an equitable way globally,
is whether you can persuade a majority of North Americans that they should live shorter lives.
But that is my point. Life will change. Those changes won't affect people equally. Some
people won't make it. But for others to make it, they will have to adjust. And I think they
will. If not by choice, then by necessity.
And as those adjustments are made, it will help some survive.
I don't think any actions will be taken to give everyone in the world an equal life. So
saying that as BAU ends, everyone will suffer equally doesn't strike me as likely.
In other words, adjustments will be made, but the results won't be evenly shared. The advantage
localization is that if we show there are benefits within a local area, we might be able to
persuade those people to make changes for themselves, if not the world.
For example, the advantage of solar is that one becomes less dependent on centralized power
generation and transmission. There are benefits for individual communities, so they might be
persuaded to pursue that path. Not because it reduces global warming. But because it allows
local communities to become more self-sufficient.
I think is great if some of you think you can transform the world economy to make it more
fair. Or if you think the world economy will become more fair after peak oil. I certainly won't
stop you from carrying out your plans.
But I don't see anything accomplished by pooh-poohing some of the alternative energy ideas
proposed here. How does that advance your cause?
In case you haven't heard the news yet we live in a Darwinian world.
Now explain to ME why I should give a hoot about the eight billion who are indeed at risk
of dying young?
I a was born with a brain programmed by a hundreds of millions of years of evolution to
give a damn about me and mine.
The ones who are going to die a horrible early death are just going to die a horrible early
death. There is nothing at all intrinsically special about naked apes.
A meteor or something along that line took out most of the life on this ball of rocks a
couple of times and the interactions of volcanos and microbes inter tangled with the Milankovich
cycles of our planetary orbit wiped out most live a few other times.
I am only half serious. Only half sarcastic.
JUST a realist. Go ahead and grieve for the billions that are going to die because of overshoot.
Maybe you will feel better.
In the meantime the survivors will be eating and drinking and dancing and screwing and having
a good old time in general.
I am more soft hearted and sentimental than most people when you get right down to it but
you know what Comrade Stalin said ?
ONE death is a tragedy. A million is a statistic.
I would gladly condemn a hundred African or Chinese or Vietnamese kids I have never seen
to death in order to save the life of a child of my own. Failure to do so would eliminate my
own existence in the form of my child. I have NO doubt the average Chinese or African parent
would make the same decision. Suicide is for losers.Life is about winners. Winners write the
history books.
If all this sounds sort of cynical – well that is because being a realist I am also quite
a cynic.
There are many places where far less energy per capita is used than North America where
life expectancy is similar.
The second point is that we should transition to other forms of energy because fossil fuels
will eventually deplete. If we wait too long then energy will be constrained and this could
lead to great suffering.
The basic problem is that many think the party can go on forever, hopefully soon higher
fossil fuel prices will become a reality.
Total World URR for crude plus condensate will likely be between 2700 Gb and 3700 Gb (not
including NGL output of about 300 to 500 Gb). My best guess is about 3000 Gb of C+C (including
extra heavy oil from oil sands in Canada and Venezuela) and about 3400 Gboe when NGL is included.
Reasonable estimates of US LTO output are in the 15 to 25 Gb range and significant production
of LTO outside North America is unlikely. Basically LTO is a drop in the bucket and a World
wide peak in C+C output will be apparent within 5 years (I would guess 2015 to 2020 with early
2018 my best guess).
Maybe when peak oil is more widely recognized, people will realize that coal and natural
gas will peak as well (I think total fossil fuels will peak by 2025, possibly as late as 2030,
depending on what happens to the World economy when peak oil is apparent.)
Bottom line, by not changing our economy to run on less fossil fuel we may be trading high
life expectancy now with lower future life expectancy due to energy constraints, unless we
act.
It's not just me that thinks Peak Oil is pretty straightforward to fix. Heck, how hard is
it to buy a hybrid or plug-in? That takes you 50% of the way, right there (yes, I know, some
people depend on used vehicles, but look at China: they sell about 25M electric bikes per year,
more than ICE vehicles. And, there's always carpooling – the average US light vehicle has 1.15
passengers, and gets 22MPG – I think the possibilities for improvement are pretty obvious…).
And, Germany is pretty well know for it's hard headed engineers. They think CO2 emissions
can be reduced dramatically, which is a lot harder than fixing PO (but tehir plan just happens
to accomplish that along the way).
"The extreme boomers believe at as soon as BAU ends, homo sapiens face extinction. " ~ Boomer
II
Don't you mean, doomers? 'u^
But we are already in doom-mode anyway, half-dead, so it's a moot point in a way. The doom/zombification
is taxes. governpimps and their thugs– crony-capitalist plutarchies, I guess.
On top of permaculture there's also the re-wilding set, as well as ecovillages and intentional
communities. Just people getting it that we need to get out from under this dystopic system's
crushing heel.
Price optimization is about keeping ahead of the collapse in prices for goods across the board
due to globalization and the drumbeat of innovation in production and distribution. It is an
attempt to de-commoditize products. That reduces price pressure caused by competition. Another
way to look at it to say "marketing" should be called "market destruction", because market
competition reduces profit. There is nothing new about this, but it is getting more and more
urgent.
Backing EVs is unrelated. It is just the government pushing innovation, like the government
land handout to the railroads after the American Civil War so they could build a transcontinental
railroad. You can argue that EVs are a bad bet, but they are hardly the end of civilization.
Also I wonder what you mean by simple. EVs are simpler than ICEs. The engine has one moving
part. We are shifting to solid state technology in many areas. Of course at the molecular level
solid state devices are pretty complex, but nothing manmade come close to the complexity of
a potato (yet). so I think mechanical complexity is all that counts.
I remember talking to Germans the early 80s. It was popular to say we shouldn't use them
because all would be lost if the electricity goes out. Is that what you're getting at? No doubt
the cuneiform scribes bemoaned the introduction of paper as the end of permanent record keeping
and beginning of dependence on paper makers. They were right I guess. But civilization didn't
end.
Also you may be able to browbeat your niece during Thanksgiving Dinner by using funny names
for things Republicans don't like, but I wouldn't try to be that uncle on line. It just
makes you look like a Rush Limbaugh fan.
"Also you may be able to browbeat your niece during Thanksgiving Dinner by using funny
names for things Republicans don't like, but I wouldn't try to be that uncle on line. It
just makes you look like a Rush Limbaugh fan." ~ Ilambiquated
That was the point. ^u^
I even hyperlinked to 'Leaf Blower' and 'Priapus' on Wikipedia to make it even more ridiculous
as part of the 'happy motoring' scenario, with of course some flourish with the association
of Kardashian and the 'race to the bottom'. (I just used that one– invented hereon and somewhat
to your credit– with some folks in person to some chuckles.)
While I'm relatively unfamiliar with Rush Limbaugh, from what is understood, a 'Rush Limbaugh
culture' sounds about right, what do you think? I mean, what inspired my comment that day was
also a crossing of the road during Rush hour and a notice of the overwhelming majority
of vehicles that had only one person inside… Think of all that energy for all that metal and
plastic, etc., being dragged along for just that one person… Meanwhile or nevertheless, some
people still want EV's… presumably for the majority of those one-person V's?
But to get back to our hypothetical niece, let's say I'm yours: How would you explain your
job or at least that price
optimization bit to me? And/Or does it shaft shoppers?
In a previous article "
The Real Natural Gas Production Decline ", I discussed a simple and effective way of estimating
the real declines and realistic EURs (Estimated Ultimate Recovery) of shale wells based on two things
that shale gas and oil producers can not lie about: number of wells added during a period of time,
and the total daily productions.
The Simple and Effective Method of Estimating EUR
The idea is simple. All shale wells are in steep decline. Thus as the producers put new wells
into production, a considerable portion of the new production merely compensates the decline of existing
wells. If we assume producers add just enough wells to exactly compensate for the decline, then the
EUR times number of wells added equals the amount of production during the same period.
Let me explain in formulas. Let the combined daily decline of existing wells be D, and IP being
the Initial Production rate per well:
Total_Production * D = IP * Well_Additions
EUR = Total_Production/Well_Additions = IP/D
In surveying several different shale plays, I found that all of them have a combined decline rate
of 0.2% per day. Combined decline rate means the decline of the total production from existing wells.
For example if the total production is 500 MMCF one day and 499 MMCF the next day, the 499-500)/500
= -0.2%/day.
Thus, a rough estimate of EUR equals to IP/D = IP/0.2% = 500 IP, or roughly 500 days worth of
production at the IP rate.
Estimating the Bakken Shale Well Productions
The North Dakota Mineral Resource Commission has a
web site
that publishes the shale well counts and monthly productions of Bakken.
I decide to crunch some numbers to see the real productivity of the Bakken oil wells, using the
idea discussed above. Let's start from the oil productions of the latest two months:
Aug-2012: 635,177 Barrels/Day
Sep-2012: 662,428 Barrels/Day
Wells added: 170
Let's do the calculation using the above numbers. The production rate increased by 27251 Barrel/Day
in 30 days. So the daily increase was 908.4 Barrel/Day. Daily well addition is 170/30 = 5.67 wells/day.
Let's assume the combined decline rate of D=-0.2% also applied in Bakken. The median production rate
during the 30 days from mid Aug. to mid Sep. was 648,660 Barrels/Day. So the natural decline would
have been 0.2% * 648,660 BPD = 1297.320 BPD. So 5.67 new wells per day not only compensates for loss
of 1297.320 BPD, but also boost the production by 908.4 BPD. Thus:
So that's the IP per well that I estimates, 389 Barrels/Day. The EUR then would be EUR = IP/D
= IP/0.2% = 500*IP = 0.1945M barrels.
Consider that there are so far 4629 wells in d the accumulative oil production is 458.860M barrels,
averaging 0.099M per well. My EUR estimate is roughly twice the accumulative oil production per well.
So I think my estimate is pretty good.
A good thing of my method is it is pretty fair. Let's say I over-estimated the D. Let's say the
combined decline rate is less than I thought, repeating the same calculation, it results in a less
IP as well. Since EUR = IP/D, a less value divided by a less value, gives you a result that is about
the same.
Let's try a D = -0.15% instead of -0.2% and see what I get:
Thus, knowing the previous month's production rate, we can calculate what the next month's production
rate should be, by subtracting the decline, then add number of new wells times IP.
Let me assume D = -0.2%/Day. I assume IP = 365 Barrels/Day. I further assume that in 2005, 2006,
2007, 2008, 2009, the IP was only 30%, 50%, 70%, 80%, 90% of the current IP level, as the technology
was less sophisticated than today, and well productivity was less than what we get today. Let's see
how my calculation looks like compare with actual production:
click to enlarge)
It looks like a perfect match. Thus my assumed values, D=-0.2% and IP = 365 Barrels/Day, a good
numbers that give perfect fit. Had I used an IP higher or lower, my projection would not match the
data.
So based on that, the average Bakken shale well EUR is
My EUR estimate is far below what producers have been pitching.
Case Study on Continental Resources Shale Wells
Let's have a look at Continental Resources (NYSE:
CLR ), who is considered the most
successful developer of the Bakken shale oil resources.
I pulled out CLR's most recent
quarterly report . Here are a few relevant numbers:
Oil and gas revenue received in the quarter was $617.93M
Oil and gas production was 0.103M BOE/day in the quarter.
Oil and gas production was 0.095M BOE/day in last quarter.
In 3 quarters, CLR participated completion of 541 wells, net 222 that belongs to CLR. So that's
74 per quarter.
Capital spending for 3 quarters totaled $2584.434M
First the capital spending of %2584.434M divided by 222 net wells completed is $11.64M
per well. This is the per well capital cost, not including the production cost yet.
What is the per well IP, and the combined decline rate D? Note that production rate increased
from 0.095M to 0.103M barrels in 92 days. That's a daily increase of 86.96 Barrels/Day. If D=0.2%,
the daily decline would be roughly 0.2%*0.1M/Day = 200 Barrels/Day. So the daily production increase
due to new wells is 200+86.96 = 287 BPD. Daily well addition is 74 wells / 92 days = 0.804 wells/Day.
Thus:
IP = 287 BPD / 0.804 = 357 Barrels/Day
EUR = IP / D = 357 BPD / 0.2% = 0.1785M Barrels
These numbers look lower than the average of the whole Bakken, or IP = 365 BPD and EUR = 0.1825M
Barrels.
What is CLR's profitability outlook under these numbers? From CLR's Q3 revenue and production
volume, I calculated that the unit price they fetched on the oil and gas was about $65/BOE
.
So a CLR well's expected EUR=0.1785M BOE would fetch a revenue of $65*0.1785M = $11.60M per well.
But as discussed above, the per well capital spending was $11.65M. So CLR barely breaks even for
the well capital spending. But the capital spending is not the only cost. We have not calculated
the production and maintenance costs, the G&A costs. Thus, at the current oil price, CLR is not making
any real profit in developing Bakken shale wells.
Discussions and Investment Implications?
So then, how could CLR manage to report positive profits for the quarters? Let me explain how
it works out for them.
Just like other shale oil and gas producers, CLR does not record well drilling capital spending
as cost directly. Instead, they first record it as investment activity. The the capital cost is recognized
in each quarter as depletion and armortization costs.
I discovered that as producers tend to over-estimate the EURs and over-estimate the life span
of shale wells, they end up armortizing the cost way below the fair amount of armortization they
should calculated. Thus, as they under-estimate the costs, they end up over-estimate the profitability
of the operations.
But one thing they could not hide is that in quarters after quarters, the producers have consistently
spend several times higher on capital spending, than the revenue they take in. Producers continue
to borrow more and more on debts in order to continue their well drilling programs.
Is a business profitable, if it continues to borrow more debts quarter after quarter, and it continue
to spend several times more on capital spending, than the revenue it takes in? This is neither profitable,
nor sustainable. I can see that when the banks get suspicious and stop lending money, then the shale
industry will collapse.
As I stated many times. The shale gas and oil adventure is deeply un-profitable. The "cheap natural
gas replacing coal" is a pipe dream. Investors should bet their money on the rebound of the coal
sector, not on the false promise of shale gas or shale oil.
Full disclosure: I have no vested interest in CLR but I may consider a short position in the near
future. I have heavy long positions in coal stocks like James River Coal (JRCC), Alpha Natural Resources
(ANR), Arch Coal (NYSE: ACI ) and
Peabody Energy (NYSE: BTU ).
Gaucho , contributor
,
premium contributor
Comments (879) | + Follow Following - Unfollow | Send Message But not to worry. With the US government support they are now planning on selling all of our
gas overseas. That way we will be out of fuel much sooner than other wise. It will also drive
the prices up here so we can be less competitive. Great planning once again by the US government.
Or should I say by the corporations that control the US government. 10 Dec 2012, 08:48 AM
Reply Like 1
Carl Martin
, contributor ,
premium contributor Comments (1530)
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Why are you simply making this assumption?
"Let's assume the combined decline rate of D=-0.2% also applied in Bakken."
Because, if your assumption is wrong, then the direction of your whole article/blog is wrong.
I believe that decline rates for shale gas are far steeper then for shale oil.
But, do you happen to have any proof to offer to back up your assumption?
Meanwhile, I will put some effort into finding some proof for my belief. But, I have noticed over
at TOD, that most PO believers also assume that shale oil behaves exactly like shale gas. That's
where I think you are going all wrong, but we'll see... 11 Dec 2012, 03:24 PM
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Mark Anthony
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" Carl Martin:
The D=-0.2%/Day combined decline rate is a very reasonable assumption. The proof is right in my
article and in the chart. My projection based on that value matches the actual production. Had
I used a less steep (smaller) decline rate, the calculation will be much higher than the actual
data. Likewise, had I used a higher IP value, the calculation will also come out to be higher
than actual.
You simply have to use IP = 365 BPD, and not any higher, and D = 0.2%/Day, and not any lower,
to project the correct total Bakken production rate as reported.
Now I do have actual proof that Bakken shale wells actuall DO decline that fast. Look at this
on page 63:
http://bit.ly/VAYoHb
The CLR chart shows the cumulative production of Charlotte 2-22H well. They claim the IP was 1396
BPD and at the end of 9.8 months (295 days), it dropped to 167 BPD and accumulative production
was 87 MBOE. Going from 1396 to 167 is a loss of 88%, and in only 295 days. That is an average
decline of -0.72% per day. Much higher than the -0.2%/Day I used. Of course I am talking the combined
decline of all wells, old and new. That's an annualized rate of -51.8% decline/year. I think that
is reasonable. 11 Dec 2012, 04:46 PM
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Mark Anthony
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" I forget to embed the link to the ND statistics of historic Bakken shale oil productions, which
is indicated in the graph any way. The link is:
http://1.usa.gov/VCJyQv
The DMR of ND has a good collection of all sorts of data. I will continue to study and analysis
data related to Bakken shale wells. 12 Dec 2012, 04:06 PM
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My name is Zoltan Ban, I have a double honors degree in history and anthropology, as well as a
BA in economics. I am the author of the book "Sustainable Trade"
Latest StockTalk With Oil Under $60/Barrel, Shale Oil Revolution May Be Over (Permanently)
http://seekingalpha.com/a/1nf8x
Dec 22, 2014 Latest articles & Instablog posts
Here is another, much simpler calculation, which shows that there is a reasonable chance that
the whole Eagle Ford field will ultimately prove to be unprofitable. http://bit.ly/V7dtqs
"... If you dont believe what the industry is saying, then you just admitted that your point of view is based upon BELIEF, not facts. Therefore, PO is a religion. If you want it to be a science, then you have to first disprove what the industry is saying. I have noticed, that no one here is actually doing that. ..."
"... All the recent mega activity at this site just seems to be one big cover up of the fact, that all your great PO theories got shot to shit with the recent fall in oil price due to over production from US shale. The latest figures from the EIA show that 9,137,000 bpd were being produced in the US as of 12/12/14, and that is an increase. Sorry, but that is not how terminal decline plays out in the world of reality. ..."
"... CLR was $30 a few days ago. $80 a few months ago. Maybe theyll go bankrupt. That will really mess up Mrs. Hamms lawyers. ..."
But I'm having an extremely difficult time even believing, that these PO discussions about
Bakken sweet spots supposedly being tapped out are still going on….AFTER ALL THESE YEARS!!!!!
All you had to do was to look at the maps KOG was putting on their website, which show exactly
where each Bakken well is drilled. Then you compare that drilling pattern to CLR's maps, which
show you where all the sweet spots are. Even Rune is now "aware" that the sweet spots are largely
determined by pressure gradients, which is what CLR's maps shows. I found out about all this,
MORE THAN FOUR YEARS AGO !!! by simply writing an email to CLR and asking why they choked back
their wells so much.
CLR also presently claims to have more than eight years of future drilling sites available
in the Bakken (at their present rate of drilling) which they say will yield more than 750,000
boe in EUR's per well. As CLR is a good proxy for the entire Bakken, what does that tell you about
the future of the entire Bakken?
I might mention that "the best" definition of a Bakken sweet spot given at this website by
a true believer, "Watcher", was that sweet spots were defined by latitude and longitude, not EUR's.
How pathetic.
If you don't believe what the industry is saying, then you just admitted that your point of
view is based upon BELIEF, not facts. Therefore, PO is a religion. If you want it to be a science,
then you have to first disprove what the industry is saying. I have noticed, that no one here
is actually doing that.
As for this sentence from the above "article"…… " The first measured 24 hour production from
Bakken wells is a very good predictor of the future production of that well." The truth is exactly
the opposite, for among many other reasons, the choking history is not even taken into account.
All the recent mega activity at this site just seems to be one big cover up of the fact, that
all your great PO theories got shot to shit with the recent fall in oil price due to over production
from US shale. The latest figures from the EIA show that 9,137,000 bpd were being produced in
the US as of 12/12/14, and that is an increase. Sorry, but that is not how terminal decline plays
out in the world of reality.
8 yrs. 750K barrels EUR per well. At current 175ish/month well addition rate that's 16000ish wells
added in 8 years.
Current total 11,000ish. So 27000 wells total then. X 750K =
about 2 Trillion barrels of oil. Don't think even CLR expects more than 50 billion, and they
are bizarre. But hey, at $40 barrel Bakken sweet prices, that's a lot of money. $80 Trillion.
What a bonanza.
CLR was $30 a few days ago. $80 a few months ago. Maybe they'll go bankrupt. That will really
mess up Mrs. Hamm's lawyers.
I'm not going to even bother to check your math. Your numbers are way too far out for me. But,
more than four years ago, CLR estimated 24 billion boe recoverable. That was recently upped to
62-96 billion boe "recoverable" (@$100) Call it less, if you like at today's prices. But, the
Bakken is still Ghawar sized, so you can eventually expect Ghawar sized production.
As to the number of eventual wells, try starting at 100,000, and go up from there. In the 4,000
square mile CLR designated sweet spot, their plan is for 16 wells per square mile (in four different
zones) which means 160 acre spacing. That's 64,000 wells right there.
How about Y-O-U defining what constitutes a PO Bakken sweet spot in EUR's, instead. Then, we
can start communicating. (maybe).
Carl Martin: Is an average EUR of 750,000 net bbl of oil per well accurate in the Bakken? It doesn't
appear that it is when one looks through the public information put out by the State of North
Dakota. Further, it doesn't appear generally that Continental has the wells capable of hitting
this figure. EOG and Whiting are the primary companies to have the wells capable of 750,000 net
bbl EUR, based upon public data.
I have read on this site that 320,000 gross bbl EUR is more probable overall in the Bakken,
although I am sure if people have agendas they can skew the numbers. I think at least a few of
the people who post here appear to have strong enough math/science/engineering backgrounds to
make some pretty reasonable calculations and are making an unbiased attempt to be as accurate
as possible.
Trying to figure out what is accurate and what is not is more difficult than what you let on,
IMO. It does appear that substantially lower oil prices may provide some answers.
There is that. 2.7 Billion at $10 million/well, from the CLR Nov investor briefing, is 270 wells.
For the whole year.
Avg flow year 1 is about 450 bpd? So incremental revs in 2015 would be 270 X 450 X $30 (net
of Bakken Sweet minus royalties, taxes) = $3.65 million, for the whole field for the whole year
from new wells.
Maybe Warren Buffett will do what he did for BoA. They created a special preferred issue for
him to buy $5 B of. Paid 8% dividend or something. Hell, he may get more of Harold's money than
the ex.
"Avg flow year 1 is about 450 bpd? So incremental revs in 2015 would be 270 X 450 X $30 (net of
Bakken Sweet minus royalties, taxes) = $3.65 million, for the whole field for the whole year from
new wells."
err I think you forgot that a year has 365 days? That comes out to more than 1.3 billion dollars
even at these depressed prices!
The average well flow for the first year is about 233 b/d, not 450 b/d (second month output is
usually highest at about 400 b/d), the average well produces roughly 85 kb in year 1.
Using Watcher's figure of 270 wells and call refinery gate oil prices $60/b, transport costs
$12/b, OPEX plus other costs $8/b leaving $40/b, then we need to pay taxes and royalties of roughly
25% on wellhead revenue of $48/b, so we need to subtract another $12/b and we get to $36/b net.
If 270 average wells are drilled we get about 23 million barrels of oil in year 1 for a net of
$826 million. The wells cost about $9 million each for a total of $2.4 billion. Looking at a single
well, we need 250 kb for simple payback (ignoring the time value of money), but the average Bakken
well takes at least 8 years to reach 250 kb of output, typically a "good well" pays out in 18
months or less. At two years the average Bakken/Three Forks well in North Dakota produces about
130 kb which is about $4.3 million in net revenue and far short of a $9 million payout level.
No, the 750,000 boe is just a reference to CLR's claim, that they have eight years of drilling
activities, that can produce that much per well. TRANSLATION: The current low oil price environment
is easily weathered by simply high grading. Any company with similar property can do the same.
But, many of the newer, smaller Bakken dotcoms have no such property, so their very existence
is in great danger.
It is nowhere near the average Bakken EUR.
By the way, unlike so many others here, I don't guess anything, and have very few opinions
of my own. I mostly just repeat what is generally accepted knowledge about the shale industry,
because no one has so far been able to prove any of it to be wrong.
It's just that none of my researched information supports any PO theory at all. That's the
rub.
So at what cost does oil have to be produced in the future? Where are we find this oil? And are
you so negative about renewables you think they won't be competitive with oil at $500 per barrel
in today's dollars?
Enno Peters collects data on all North Dakota wells from the NDIC, the EUR of the average Bakken
well between 2011 and 2014 is about 325 kb of oil, if you add in natural gas and convert to barrels
of oil equivalent(boe), it increases to 406 kboe, but note that the extra 80 kboe is very low
value relative to crude.
Note that the typical well in an investor presentation is not the same as an average well.
Maybe CLR only drills above average wells.
I don't dispute your average EUR numbers, as I don't have the neccesary info to do so. Besides
that, they sound about right to me. But you need to be careful about getting too hung up in the
word or concept of average. After all, what do you think is the average gender in the US in Dec.
2014?
Investor presentations ALWAYS show their best results, and almost never reveal all the failures,
that bring their averages down. This is just business as usual. But, it is okay because they are
always moving up the learning curve, so by showing their best results now, they are giving a clear
indication of where they expect their average results to one day be.
Also, if you want to understand this industry, it does no good to focus on average companies,
you need to look at the leaders, because they are the trend setters. Ultimately everything is
based upon best practices, and EOG is presently the undisputed best at everything. They just don't
keep investors very well informed. Therefore, I still get most of my info from CLR.
This sentence of yours is not as silly as you might think. "Maybe CLR only drills above average
wells." In a sense, "they do." That is to say, that they have no monster wells, that I know of,
they choke a lot more than others, and they have used their standard 10,000 foot lateral and 30
frack stages well design over most of the Bakken, even when it didn't make economic sense to use
it. It is because they use their standard well as a measuring stick. Now they have a fixed point
for reference to compare different areas of the Bakken.
That's why they know exactly what they are talking about, and why I accept most everything
they say. You obviously don't. But, you have never given a good reason for not doing so, other
than the results they are claiming don't show up in the data bases you are using. Why don't you
just send them an email and try to clear up a major misunderstanding on your part? Then everyone
at this website will be able to move forward.
Continental wells with first month of output between Jan 2009 and Oct 2014 have an average
cumulative output over 70 months of 186 kb, this is slightly below the average Bakken well over
the same period for all wells completed(925 wells).
There is a lot of hype in investor presentations.
The Continental wells will produce considerably less oil that the 480 kb claimed (only 80%
of the 600 boe EUR is oil) in investor presentations. The EUR is more in the 250- 300 kb range
for the average Continental well.
I wonder if they have run flow meters to check how much flow they get from the toe of a 10 thousand
foot lateral. You seem to follow this closely, are those wells slugging?
Dennis, sometimes very long wells in three phase flow can have phase segregation in the horizontal
section. This causes liquid slugs to accumulate, which tend to move up the well in slug flow.
This can be avoided by placing the heel higher than the toe. But I've never worked with a 10 thousand
foot well. And I was wondering if they had sensors to confirm the toe is producing.
I came to the same conclusion as you Dennis. The Continental wells are actually bellow average.
I have attached a graph showing the production profile for Continental wells from January 2010
to October 2014. I also included the average Bakken well profile for 2010 for reference. The first
3 year cumulative oil + gas production for an average Continental well is about 170.000 boe. No
one knows what the EUR will be, but EIA suggests that 50% of the oil has been produced during
that time ( http://www.eia.gov/forecasts/aeo/tight_oil.cfm
) which gives an EUR of about 340.000 boe.
Carl, you are saying yourself that they only show the best results and don´t tell about their
failures. So why should we then believe in anything they tell us? I have learned that you should
never ever trust in what companies tell in their presentations. Especially not smaller companies
which are dependent on cheap credits. It is actually quite disturbing that companies can make
such exaggerations and get away with it.
I however agree with you Carl that there are still drillable locations left in sweetspots.
But perhaps some companies start to run out of them. That would affect total Bakken output, which
I am mostly interested in.
I posted a chart for average Bakken cumulative output per well by company for four large companies
over the Jan 2009 to Oct 2014 period( about 1/3 of all ND bakken/Three Forks wells drilled(3462
wells).
The "avg" well is for all Bakken/Three Forks wells in North Dakota over the same period with a
cumulative of 197 kb per well over the first 58 months of output.
Chart came out a little small the first time so I will try it again.
I put together data for more companies, about 75% of total wells, too many for a clear well profile
so I am using a bar chart with 54 month (4.5 year) cumulative output for the average well for
each company over the Jan 2009 to Oct 2014 period. The average Bakken well is shown for comparison.
Companies with more than 200 wells over the chosen period are presented below.
Surprised by QEP, they don't get the hype the others do. Always assumed EOG had the most productive
wells in the Balkan due to Parshall. Must have wells in other areas which bring the average way
down.
I wish TX reported by well as opposed to by lease. Would be really interesting to see the same
info for EFS and Permian horizontal wells.
Really seems irresponsible for these companies to claim EUR oil at 600,000+. I guess they assume
the wells will produce 40-60 bbl per day for 25 years. Will be interesting to see if they do.
It looks like the quote from the other day, "Continental must drill all above average wells",
may need some adjustment. To "Continental must drill all below average wells"?
I show the North Dakota Bakken/Three Forks cumulative average well profiles by company for
the Jan 2009 to Oct 2014 period, total wells for this set of companies is 6472 wells of about
8054 wells completed (drilled and fracked) for all companies operating in the North Dakota Bakken/Three
Forks (80%). This is where I got the data for the bar chart. QEP energy is the high well profile
and OXY is the low well profile, the middle dashed line is the average well profile for all companies
(including those not presented in the chart).
Reuters' summary of U.S. shale companies production guidance for 2016.
Note that this is oil & gas production in boe.
I guess that the decline in oil production will be steeper.
Factbox: U.S. shale firms see 5.6 percent decline in 2016 oil, gas output
For the first time in two years, U.S. oil companies are beginning to forecast stagnating, or
even lower, production. Still, their forecasts are less severe than most estimates.
According to a Reuters analysis, based on forecasts from 18 shale oil-oriented firms released
over the past several weeks, oil and gas output is expected to fall 300,000 barrels or equivalent
per day (boepd) this year, which equates to a 5.6 percent decline from 2015.
The U.S. Energy Information Administration expects overall U.S. crude oil production to decrease
by 700,000 barrels per day, or 7.5 percent from 2015 levels.
Not accounting for production from Alaska and the Gulf of Mexico, EIA expects overall production
to fall nearly 11 percent.
Reuters calculations show that production is expected to decline by about 6 percent if
eight of the 18 companies that have operations outside the shale patch are excluded.
Only two of the 18 firms analyzed by Reuters expect to produce more in 2016. This is in sharp
contrast to last year, when increased efficiencies and lower service costs helped companies ramp
up output even at lower levels of spending.
Production at the same companies rose nearly 10 percent on average in 2015, after factoring
in a fall in output at 7 companies.
Below is a compilation of the 18 companies' production forecasts for the year.
All figures are Reuters estimates or calculations based on company data. Midpoints were used
in cases where company disclosed a forecast range. Most companies forecast percentage change for
2016; Reuters calculated 2016 output estimates based on reported 2015 data.
Apache Corp (APA.N) would "rather leave those barrels in the ground" and wait for prices to
rebound than finish the fracking process, Chief Executive John Christmann said last week. Apache
expects production, nearly two-thirds of which is onshore in North America, to fall by 7 to 11
percent.
Yet the overall declines may still appear unusually shallow given the scale of spending cuts.
Many producers are still managing to coax ever-more oil from each new well, tempering the reversal
in production even with only 400 drilling rigs deployed nationwide, one-quarter of the peak of
2014, according to Baker Hughes data.
EOG Resources Inc (EOG.N) expects to boost output from new wells in the first four months by
50 percent for each foot it drills, chairman and CEO Bill Thomas told analysts on Friday. EOG
expects its oil production to dip by only about 7.6 percent this year.
"The resilience (of U.S. shale) has been extraordinary, a tribute to technical expertise," Neil
Atkinson, head of the International Energy Agency's benchmark Oil Market Report, said last week.
The agency expects U.S. production to rebound to record highs within just a few years. "Anyone
who believes the U.S. revolution has stalled should think again."
Until this year, energy firms have been able to sustain output thanks to increased efficiencies
and more targeted drilling. In December, shale powerhouse North Dakota pumped some 1.15 million
barrels per day, barely 2 percent below its April 2015 peak.
Now, the "precipitous" fall in rig count is beginning to outpace efficiency gains, said Brian
Kessens, Portfolio Manager at Tortoise Capital Advisors. The anticipated declines show that there
is a limit to how much companies can squeeze out of their oilfields without drilling and completing
new wells.
Whiting Petroleum (WLL.N), the biggest producer in North Dakota, last week forecast its output
would drop by over 18 percent, the most among the surveyed firms, as it set out to cut well completions
and slash its capital budget by 80 percent.
The only driller to anticipate an increase this year, Pioneer Natural Resources (PXD.N), can
do so largely because of its most extensive hedging among shale firms. Concho Resources (CXO.N)
and Halcon Resources Corp (HK.N), which have also hedged substantial parts of their production,
both see output slipping by less than 5 percent.
All in all, output data so far and forecasts suggest this year's declines will be relatively
modest, raising questions whether the retreat will be deep and long enough to support a sustained
recovery in oil prices.
"Non-OPEC supply needs to fall more broadly before the market gets rebalanced and prices recover
in a durable way," Raymond James analyst Pavel Molchanov said.
While individual company forecasts offer the clearest view of supply from those closest to
the oil wells, in sum they are a less than perfect gauge.
The companies in the survey represent only a portion of U.S. crude production, which reached
a near record of 10 million bpd last year, and most offer no separate forecasts for crude oil,
natural gas or other related liquids. Privately-held companies, which do not report forecasts,
may get hit harder.
Projections from the half-dozen larger firms in the group are bolstered by other large overseas
or offshore non-shale projects, which often produce crude for years without the need for new wells.
Marathon Oil Corp (MRO.N), for instance, sees a 6-8 percent decline in overall output, but
warned its big shale plays in the Bakken, Eagle Ford and SCOOP areas would drop by the "low teens".
Occidental expects a 2-4 percent rise this year as overseas projects offset a "slight" decline
from domestic wells.
Yet its oil-rich Permian Basin shale properties, source of one-sixth of its output, are still
expected to pump more this year – even as it cuts back to only two to four rigs.
Dec 10, 2012 5:39 AM | about stocks:
CLR
,
CHK
,
UNG
,
EOG
,
COGQZQ
,
ACI
,
BTU
In a previous article "
The
Real Natural Gas Production Decline
", I discussed a simple and effective
way of estimating the real declines and realistic EURs (Estimated Ultimate
Recovery) of shale wells based on two things that shale gas and oil
producers can not lie about: number of wells added during a period of time,
and the total daily productions.
The Simple and Effective Method
of Estimating EUR
The idea is simple. All shale wells are in steep decline. Thus as the
producers put new wells into production, a considerable portion of the new
production merely compensates the decline of existing wells. If we assume
producers add just enough wells to exactly compensate for the decline, then
the EUR times number of wells added equals the amount of production during
the same period.
Let me explain in formulas. Let the combined daily decline of existing
wells be D, and IP being the Initial Production rate per well:
Total_Production * D = IP * Well_Additions
EUR = Total_Production/Well_Additions = IP/D
In surveying several different shale plays, I found that all of them have
a combined decline rate of 0.2% per day. Combined decline rate means the
decline of the total production from existing wells. For example if the
total production is 500 MMCF one day and 499 MMCF the next day, the
499-500)/500 = -0.2%/day.
Thus, a rough estimate of EUR equals to IP/D = IP/0.2% = 500 IP, or
roughly 500 days worth of production at the IP rate.
Estimating the Bakken Shale Well Productions
The North Dakota Mineral Resource Commission has a
web site
that publishes the shale well counts and monthly productions of
Bakken.
I decide to crunch some numbers to see the real productivity of the
Bakken oil wells, using the idea discussed above. Let's start from the oil
productions of the latest two months:
Aug-2012: 635,177 Barrels/Day
Sep-2012: 662,428 Barrels/Day
Wells added: 170
Let's do the calculation using the above numbers. The production rate
increased by 27251 Barrel/Day in 30 days. So the daily increase was 908.4
Barrel/Day. Daily well addition is 170/30 = 5.67 wells/day. Let's assume the
combined decline rate of D=-0.2% also applied in Bakken. The median
production rate during the 30 days from mid Aug. to mid Sep. was 648,660
Barrels/Day. So the natural decline would have been 0.2% * 648,660 BPD =
1297.320 BPD. So 5.67 new wells per day not only compensates for loss of
1297.320 BPD, but also boost the production by 908.4 BPD. Thus:
So that's the IP per well that I estimates, 389 Barrels/Day. The EUR then
would be EUR = IP/D = IP/0.2% = 500*IP = 0.1945M barrels.
Consider that there are so far 4629 wells in d the accumulative oil
production is 458.860M barrels, averaging 0.099M per well. My EUR estimate
is roughly twice the accumulative oil production per well. So I think my
estimate is pretty good.
A good thing of my method is it is pretty fair. Let's say I
over-estimated the D. Let's say the combined decline rate is less than I
thought, repeating the same calculation, it results in a less IP as well.
Since EUR = IP/D, a less value divided by a less value, gives you a result
that is about the same.
Let's try a D = -0.15% instead of -0.2% and see what I get:
Thus, knowing the previous month's production rate, we can calculate what
the next month's production rate should be, by subtracting the decline, then
add number of new wells times IP.
Let me assume D = -0.2%/Day. I assume IP = 365 Barrels/Day. I further
assume that in 2005, 2006, 2007, 2008, 2009, the IP was only 30%, 50%, 70%,
80%, 90% of the current IP level, as the technology was less sophisticated
than today, and well productivity was less than what we get today. Let's see
how my calculation looks like compare with actual production:
click to enlarge)
It looks like a perfect match. Thus my assumed values, D=-0.2% and IP =
365 Barrels/Day, a good numbers that give perfect fit. Had I used an IP
higher or lower, my projection would not match the data.
So based on that, the average Bakken shale well EUR is
My EUR estimate is far below what producers have been pitching.
Case Study on Continental Resources Shale Wells
Let's have a look at Continental Resources (NYSE:
CLR
),
who is considered the most successful developer of the Bakken shale oil
resources.
I pulled out CLR's most recent
quarterly report
. Here are a few relevant numbers:
Oil and gas revenue received in the quarter was $617.93M
Oil and gas production was 0.103M BOE/day in the quarter.
Oil and gas production was 0.095M BOE/day in last quarter.
In 3 quarters, CLR participated completion of 541 wells, net 222 that
belongs to CLR. So that's 74 per quarter.
Capital spending for 3 quarters totaled $2584.434M
First the capital spending of %2584.434M divided by 222 net wells
completed is
$11.64M
per well. This is the per well capital
cost, not including the production cost yet.
What is the per well IP, and the combined decline rate D? Note that
production rate increased from 0.095M to 0.103M barrels in 92 days. That's a
daily increase of 86.96 Barrels/Day. If D=0.2%, the daily decline would be
roughly 0.2%*0.1M/Day = 200 Barrels/Day. So the daily production increase
due to new wells is 200+86.96 = 287 BPD. Daily well addition is 74 wells /
92 days = 0.804 wells/Day. Thus:
IP = 287 BPD / 0.804 =
357 Barrels/Day
EUR = IP / D = 357 BPD / 0.2% =
0.1785M Barrels
These numbers look lower than the average of the whole Bakken, or IP =
365 BPD and EUR = 0.1825M Barrels.
What is CLR's profitability outlook under these numbers? From CLR's Q3
revenue and production volume, I calculated that the unit price they fetched
on the oil and gas was about
$65/BOE
.
So a CLR well's expected EUR=0.1785M BOE would fetch a revenue of
$65*0.1785M = $11.60M per well. But as discussed above, the per well capital
spending was $11.65M. So CLR barely breaks even for the well capital
spending. But the capital spending is not the only cost. We have not
calculated the production and maintenance costs, the G&A costs. Thus, at the
current oil price, CLR is not making any real profit in developing Bakken
shale wells.
Discussions and Investment Implications?
So then, how could CLR manage to report positive profits for the
quarters? Let me explain how it works out for them.
Just like other shale oil and gas producers, CLR does not record well
drilling capital spending as cost directly. Instead, they first record it as
investment activity. The the capital cost is recognized in each quarter as
depletion and armortization costs.
I discovered that as producers tend to over-estimate the EURs and
over-estimate the life span of shale wells, they end up armortizing the cost
way below the fair amount of armortization they should calculated. Thus, as
they under-estimate the costs, they end up over-estimate the profitability
of the operations.
But one thing they could not hide is that in quarters after quarters, the
producers have consistently spend several times higher on capital spending,
than the revenue they take in. Producers continue to borrow more and more on
debts in order to continue their well drilling programs.
Is a business profitable, if it continues to borrow more debts quarter
after quarter, and it continue to spend several times more on capital
spending, than the revenue it takes in? This is neither profitable, nor
sustainable. I can see that when the banks get suspicious and stop lending
money, then the shale industry will collapse.
As I stated many times. The shale gas and oil adventure is deeply
un-profitable. The "cheap natural gas replacing coal" is a pipe dream.
Investors should bet their money on the rebound of the coal sector, not on
the false promise of shale gas or shale oil.
Full disclosure: I have no vested interest in CLR but I may consider a
short position in the near future. I have heavy long positions in coal
stocks like James River Coal (JRCC), Alpha Natural Resources (ANR), Arch
Coal (NYSE:
ACI
)
and Peabody Energy (NYSE:
BTU
).
Instablogs
are blogs which are instantly set up and networked within the Seeking Alpha
community. Instablog posts are not selected, edited or screened by Seeking
Alpha editors, in contrast to contributors' articles.
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Gaucho
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But not to worry. With the
US government support they are now planning on selling all of our gas
overseas. That way we will be out of fuel much sooner than other wise.
It will also drive the prices up here so we can be less competitive.
Great planning once again by the US government. Or should I say by the
corporations that control the US government.
10 Dec 2012,
08:48 AM
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1
"Let's assume the combined decline rate of D=-0.2% also applied in
Bakken."
Because, if your assumption is wrong, then the direction of your whole
article/blog is wrong.
I believe that decline rates for shale gas are far steeper then for
shale oil.
But, do you happen to have any proof to offer to back up your
assumption?
Meanwhile, I will put some effort into finding some proof for my
belief. But, I have noticed over at TOD, that most PO believers also
assume that shale oil behaves exactly like shale gas. That's where I
think you are going all wrong, but we'll see...
11 Dec 2012,
03:24 PM
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0
The D=-0.2%/Day combined decline rate is a very reasonable assumption.
The proof is right in my article and in the chart. My projection based
on that value matches the actual production. Had I used a less steep
(smaller) decline rate, the calculation will be much higher than the
actual data. Likewise, had I used a higher IP value, the calculation
will also come out to be higher than actual.
You simply have to use IP = 365 BPD, and not any higher, and D =
0.2%/Day, and not any lower, to project the correct total Bakken
production rate as reported.
Now I do have actual proof that Bakken shale wells actuall DO decline
that fast. Look at this on page 63:
The CLR chart shows the cumulative production of Charlotte 2-22H well.
They claim the IP was 1396 BPD and at the end of 9.8 months (295
days), it dropped to 167 BPD and accumulative production was 87 MBOE.
Going from 1396 to 167 is a loss of 88%, and in only 295 days. That is
an average decline of -0.72% per day. Much higher than the -0.2%/Day I
used. Of course I am talking the combined decline of all wells, old
and new. That's an annualized rate of -51.8% decline/year. I think
that is reasonable.
11 Dec 2012,
04:46 PM
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Mark Anthony
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Author's reply "
I forget to embed the link
to the ND statistics of historic Bakken shale oil productions, which
is indicated in the graph any way. The link is:
The DMR of ND has a good collection of all sorts of data. I will
continue to study and analysis data related to Bakken shale wells.
12 Dec 2012,
04:06 PM
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My name is Zoltan Ban, I have a double honors degree in
history and anthropology, as well as a BA in economics.
I am the author of the book "Sustainable Trade"
Latest StockTalk
With Oil Under $60/Barrel, Shale Oil Revolution
May Be Over (Permanently)
http://seekingalpha.com/a/1nf8x
Dec 22, 2014
Latest articles & Instablog posts
Here is another, much
simpler calculation, which shows that there is a reasonable chance
that the whole Eagle Ford field will ultimately prove to be
unprofitable.
http://bit.ly/V7dtqs
"... In the USA we use crude for various purposes. Based on old data of 2007 we use close to half for passenger travel, and only
2% for on farm use, for example. Probably hasn't changed much. How much of the passenger travel is important to GDP, or is "productive"
vs "frivolous"? ..."
"... An even better question is how much of GDP itself is "productive" or "frivolous"? ..."
"... Households spent $306 billion on gasoline in 2015 which is ~1.7% of ~$18 trillion of GDP. If 2016 gasoline prices average $1.98
per gallon (EIA February STEO report), household spending on gasoline relative to total household spending will be the lowest in the
69 year history of the data set. ..."
"... Gasoline on its own it is pretty much useless unless you want just to start camp fire for marshmallows. If you want to include
the true cost of using gasoline in the household you have to include the cost of vehicles that have never been higher in the history,
you have to include the cost of insurance that is also marching higher every year. And let's not even go into ever increasing cost of
building and maintaining each mile of highway network. So you have to look at built in price inflation in today's monetary system to
realize the true costs. And anyway example that you provide for 2016 that "gasoline relative to total household spending will be the
lowest in the 69 year history" is anomaly. Do you understand why it is anomaly? It is anomaly because at that price nobody in oil industry
makes any profit. So you won't have this anomaly for very long. ..."
In the USA we use crude for various purposes. Based on old data of 2007 we use close to half for passenger travel, and only
2% for on farm use, for example. Probably hasn't changed much. How much of the passenger travel is important to GDP, or is "productive"
vs "frivolous"?
Households spent $306 billion on gasoline in 2015 which is ~1.7% of ~$18 trillion of GDP. If 2016 gasoline prices average
$1.98 per gallon (EIA February STEO report), household spending on gasoline relative to total household spending will be the lowest
in the 69 year history of the data set.
Gasoline on its own it is pretty much useless unless you want just to start camp fire for marshmallows. If you want to include
the true cost of using gasoline in the household you have to include the cost of vehicles that have never been higher in the history,
you have to include the cost of insurance that is also marching higher every year. And let's not even go into ever increasing
cost of building and maintaining each mile of highway network. So you have to look at built in price inflation in today's monetary
system to realize the true costs. And anyway example that you provide for 2016 that "gasoline relative to total household spending
will be the lowest in the 69 year history" is anomaly. Do you understand why it is anomaly? It is anomaly because at that price
nobody in oil industry makes any profit. So you won't have this anomaly for very long.
"... Jeb Armstrong, Vice President of Energy Research for the Marwood Group, doesnt expect most producers to have a large inventory of DUCs. Instead, he sees the backlog as a matter of circumstance rather than a way of loading up on potential volumes. The only reason why I can see a company willingly drilling DUCs is because they have a rig contract thats too expensive to cancel, he said in an email to Oil Gas 360®. Might as well keep the rig operating and plow the capital into the ground than pay a penalty to the rig owner. ..."
"... Raymond James analysts shared a similar viewpoint, noting a certain dynamic on the oilservice industry. Lower returns and crimped cash flow lead operators to slow activity and conserve cash in any way possible, the note said. Since many of the land rigs had longer-term contracts and the frac crews didnt, the quickest way to conserve cash is to drill but not complete. ..."
"... Many prognosticators of oil and gas markets have found themselves on the wrong side of US production calls throughout the shale era after failing to understand and model the risks associated with operational momentum. Increases in well productivity brought higher potential returns, and every company in the oil patch scrambled to gain the assets, people, and infrastructure to grow production (and hopefully cash) in the future. As supply growth outpaced demand, prices sank, but production hasnt responded with an equal intensity. Why doesnt production respond accordingly? The same reason you cant turn around an aircraft carrier on a dime, momentum. ..."
"... The momentum of the shale boom can be seen in the large overhang of drilled but uncompleted wells (DUCs) sitting out in the field today, ..."
"... looming over the market and weighing on any potential oil price recovery… ..."
"... Until the number of DUCs returns to levels more aligned with historical working inventory levels (3-6 months of drilling), we expect their threat to loom large over the market and have a dampening effect on any near-term price recovery. But their longer term impact could loom just as large. If producers steer too much capital away from drilling, and instead harvest DUCs to maintain production and cash flow in 2016, the human capital behind the rig fleet could be lost to other industries, making service cost inflation all but guaranteed when US supply growth is again needed. It looks like this hangover will be felt for years to come. ..."
"... This sharp downward trend has to have a direct effect on the Bakken oil production, in the shorter time frame, rather than the longer term. ..."
Bakken October 10, 2014 198 rigs February 26, 2016 36 rigs Percent decline 82%
Eagle Ford October 10, 2014 202 rigs February 26, 2016 41 rigs Percent decline 80%
Total rigs outside shale basins:
October 10, 2014 581 rigs .
February 26, 2016 143 rigs.Percent decline 75%
In the shale plays a drop in the rig count does not mean a drop in well completions. And except
for the Bakken, we have only a vague idea how many wells are being completed each month. We know
that the inventory of DUCs, (drilled but uncompleted wells), is quite high. But if so, why are any
shale wells being drilled at all? Well here is one reason:
Jeb Armstrong, Vice President of Energy Research for the Marwood Group, doesn't expect most
producers to have a large inventory of DUCs. Instead, he sees the backlog as a matter of circumstance
rather than a way of loading up on potential volumes. "The only reason why I can see a company willingly
drilling DUCs is because they have a rig contract that's too expensive to cancel," he said in an
email to Oil & Gas 360®. "Might as well keep the rig operating and plow the capital into the ground
than pay a penalty to the rig owner."
Raymond James analysts shared a similar viewpoint, noting a certain dynamic on the oilservice
industry. "Lower returns and crimped cash flow lead operators to slow activity and conserve cash
in any way possible," the note said. "Since many of the land rigs had longer-term contracts and the
frac crews didn't, the quickest way to conserve cash is to drill but not complete."
But wells are obviously being completed. In fact more wells are being completed than being drilled
but we obviously don't know just how many. And…
Many prognosticators of oil and gas markets have found themselves on the wrong side of US
production calls throughout the shale era after failing to understand and model the risks associated
with operational momentum. Increases in well productivity brought higher potential returns, and every
company in the oil patch scrambled to gain the assets, people, and infrastructure to grow production
(and hopefully cash) in the future. As supply growth outpaced demand, prices sank, but production
hasn't responded with an equal intensity. Why doesn't production respond accordingly? The same reason
you can't turn around an aircraft carrier on a dime, momentum.
The momentum of the shale boom can be seen in the large overhang of drilled but uncompleted
wells (DUCs) sitting out in the field today, looming over the market and weighing
on any potential oil price recovery…
Until the number of DUCs returns to levels more aligned with historical working inventory
levels (3-6 months of drilling), we expect their threat to loom large over the market and
have a dampening effect on any near-term price recovery. But their longer term impact could
loom just as large. If producers steer too much capital away from drilling, and instead harvest DUCs
to maintain production and cash flow in 2016, the human capital behind the rig fleet could be lost
to other industries, making service cost inflation all but guaranteed when US supply growth is again
needed. It looks like this hangover will be felt for years to come.
Conclusion
The decline in the oil rig count cannot, in the near term, be directly linked to a decline in
oil production due to so many DUCs. But eventually it must. Steep declines in oil production must
eventually follow steep declines in the rig count. And as we see a drop in production we will see
a corresponding rise in prices. This, in turn, will cause an increase in well completions, knocking
the price back down again.
So don't expect any quick recovery of either oil prices or production. Yes, it looks like the
hangover will be felt for years to come. And in the meantime peak oil will be in the rear view mirror.
But no one will notice for years to come.
This chart from Rystad Energy indeed shows that the number of DUCs was rapidly increasing during
the shale boom, when oil prices were around $100. It has peaked in late 2014 and was decreasing
since then
If the number of DUCs is almost unchanged for the last 9 months it implies the number of completions
is falling in lock step with the number of wells being drilled. Drill rigs are becoming more efficient
on average, but it still implies a very rapid fall-off in production in the coming months.
If no wells are completed in 2016, output in the Bakken drops by roughly 40%per year in the first
year. Not a very realistic scenario, though. If an average of 35 wells per month are completed,
the drop is about 25%/year. If 60 wells per month are completed, output drops about 20%/year and
70 wells completed per month results in about a 15% drop in Bakken/Three Forks output.
I have no guess about how many wells will be completed, but somewhere between 0 and 70 new
wells per month on average for 2016 will probably cover it.
Bakken rigs down to 35, with one to lay down/stack.
McKenzie county, makes up 19 of those 35 rigs.
Mountrail and Williams are at 5 and 4 respectively, with Williams about to go to 3!
Dunn Co at 6.
I have to agree with Ron. This sharp downward trend has to have a direct effect on the Bakken
oil production, in the shorter time frame, rather than the longer term.
The number of drilling rigs working in the Eagle Ford Shale is a fraction of what it was a year
ago, down 70 percent. There are 47 drilling rigs still working in the South Texas field, which
arcs from the border near Laredo toward the College Station area on the eastern edge of the field.
"... Whiting Petroleum Corp. (NYSE:WLL), the largest oil producer in North Dakota, has announced that it will suspend all fracking in the state and cut its budget for this year by 80% ..."
"... As of 1 April, Whiting will halt all fracking and stop completing its wells at 20 Bakken and three Forks sites. By this summer it will cut spending to $160 million for the rest of year to fund maintenance. ..."
"... The news comes along with Whiting's fourth-quarter results, which posted a net loss of $0.80 per share and revenues of $2.05 billion compared with 2014 EPS of $4.15 and revenues of $3.09 billion. ..."
"... It's also in a better position despite all the setbacks because it doesn't have any bonds maturing until 2019 ..."
Whiting Petroleum Corp. (NYSE:WLL), the largest oil producer in North Dakota, has
announced that it will suspend all fracking in the state and cut its budget for this year by 80%
in a move that sent its shares up 9% on Wednesday, back down to a record low on Thursday, and
$4.02 this morning.
... ... ...
As of 1 April, Whiting will halt all fracking and stop completing its wells at 20 Bakken
and three Forks sites. By this summer it will cut spending to $160 million for the rest of year
to fund maintenance.
... ... ...
The news comes along with Whiting's fourth-quarter results, which posted a net loss of
$0.80 per share and revenues of $2.05 billion compared with 2014 EPS of $4.15 and revenues of
$3.09 billion.
In an earnings call on 25 February, Whiting noted that its production for the fourth quarter
averaged 155,210 barrels of oil equivalent per day, and that enhanced completion designs in the
Williston Basin drove performance by delivering 22% production increases quarter over quarter on
a per well basis.
"Despite the sharp drop in commodity prices, our proved reserves increased 5% to 821 million
barrels of oil equivalent, even after 53 million barrels of oil equivalent of asset sales which
equated to almost 7% of our year-end 2014 reserves," Whiting executives noted.
The company sold $512 million of assets last year, ending the year with $2.7 billion of
liquidity. It's also in a better position despite all the setbacks because it doesn't have
any bonds maturing until 2019, and will not be negatively affected by the "March madness"
that is threatening other producers.
"... Once this project is completed DECC will be able to better quantify system costs to inform policy decisions. Any future policy development, such as future renewable support, will be informed by the improved evidence base developed through this project . ..."
"... The additional costs of having variable generation on the system are low and for the most part renewable generators already pay these costs, said Renewable UKs director of policy, Dr Gordon Edge. If were going to talk about system costs, then we also need to talk about the undoubted economic benefits that wind generators also bring, he added. ..."
"... At a White House meeting between the CIAs director of plans, Frank Wisner, and John Foster Dulles, in September 1957, Eisenhower advised the agency, We should do everything possible to stress the holy war aspect, according to a memo recorded by his staff secretary, Gen. Andrew J. Goodpaster. ..."
"... When oil is selling for below its full life cycle production cost; when the industrys revenue has fallen by $2.3 trillion per year in the last two years; when the Saudis are borrowing money to pay their bills; when the nation with the largest petroleum resource on the planet cant afford toilet paper for its citizens; when hundreds of US producers are going out of business; when the world is using petroleum eight times faster than it is finding it; when the Etp Model said that this was going to happen years ago -– yep, I believe it. ..."
Nor, for that matter, of peak coal or gas. Fossil fuels, said to be on the path for an effective
demise in the rich world later this century, will actually continue to fulfil the major part of our
energy needs for the foreseeable future. So says the latest
BP Energy Outlook
.
... ... ...
...As oil prices dropped steeply in 2014, the once-dominant OPEC producers kept the taps open,
looking to maintain market share in the face of surging US competition, rather than cutting production
to force prices up. However, the forecasters were wrong in this case as well. Rather than decimating
the North American shale oil producers, the weaker ones went to the wall but many carried on pumping.
The costs of fracking (and re-fracking) and drilling multiple horizontal wells from a single well-head
had come down to a point at which losses were bearable, albeit further drilling was discouraged.
Breakeven cost for US oil in general is about $36 per barrel, although the average for shale is around
$58 (see
breakeven cost for top oil exporters
). The figure for Saudi Arabia, in contrast, is just $9.90.
Nevertheless, the consequences of continuing low oil prices are worse for Middle Eastern countries
and other 'cheap' oil producers because their economies are also heavily dependent on oil exports.
So, while a single industrial sector may take a hammering in the USA, Saudi Arabia needs about $105/barrel
to balance its budget (
Fiscal breakeven cost for the top oil-dependent economies
). For such countries, the economic
and social costs could be severe, while shale oil production can be scaled back but then quickly
revived when the market picks up.
On a more parochial note, plans in EU member states for continued expansion of renewable energy
were based on a projected reducing need for subsidies as conventional energy prices rose steadily.
Now, however, it begins to look as though subsidies will escalate for the foreseeable future. In
the UK, for example, the realities of photovoltaics having very limited potential at such a high
latitude and the building of more onshore wind farms meeting continued resistance from local communities
has made offshore wind an increasingly attractive proposition politically.
Politically attractive maybe, but hardly so economically. As last week's newsletter pointed out,
offshore wind farm operators are being offered energy prices of at least Ł115 per MWh, over Ł20 more
than the much-criticised strike price for electricity from the proposed Hinkley C nuclear plant (
(Guaranteed) power to the people
). Even these inflated prices, paid for by consumers, don't take account of the additional costs
of transmission, grid strengthening and conventional backup.
The result is a rethink of at least some aspects of the subsidy regime and a somewhat lukewarm
attitude to renewables in the UK (although Germany seemingly is set to push ahead with yet more wind
and solar, seemingly oblivious to the negative consequences of the policy instruments chosen: replacement
of clean and flexible gas by new lignite stations). The much-vaunted prospects of carbon capture
and storage (CCS), always just over the horizon and apparently destined to remain so, has had yet
another false start as funding for a demonstration project has been pulled.
Even the renewable energy industry itself if not united.
Power firm Drax urges biomass
subsidy rethink puts the case for biomass being a more cost-effective option than other renewables,
taking into account additional costs not normally included in the headline figures. The Ł105 per
MWh paid to Drax for energy generated mainly from imported American wood pellets is certainly higher
than the maximum of Ł82.50 paid for the latest onshore wind farms. However, an analysis conducted
for the energy generator by NERA Economic Consulting and Imperial College argues that the overall
cost to consumers of decarbonisation could be Ł2bn lower if biomass power stations were allowed to
bid for new renewable energy contracts.
The precise figures can be criticised, but the thrust of the argument is undeniable: the only
valid way of comparing competing technologies is to analyse the overall system cost. The Department
of Energy and Climate Change is said to be looking into the use of whole system costing, with work
due to finish shortly. According to energy minister Angela Leadsom, "Once this project is completed
DECC will be able to better quantify system costs to inform policy decisions. Any future policy development,
such as future renewable support, will be informed by the improved evidence base developed through
this project".
Let's hope so. The wind and solar industries will doubtless put up strong resistance, because
the higher-than-reported overall costs of their technologies is a secret they would rather was not
made public. We can expect to hear much more of this kind of thing: "The additional costs of
having variable generation on the system are low and for the most part renewable generators already
pay these costs," said Renewable UK's director of policy, Dr Gordon Edge. "If we're going to talk
about system costs, then we also need to talk about the undoubted economic benefits that wind generators
also bring," he added.
What those 'undoubted economic benefits may be to those other than the foreign-owned suppliers
of wind turbines and photovoltaic panels, we wait to find out.
The massive global debt bubble is the surest sign yet that we have reached peak oil. Without
growth in oil production, there can not be economic growth.
Debt was used to buy today's oil yesterday. Facilitated by cheap credit, we are currently producing
tomorrow's oil today. Tomorrow's oil, the last of the easy stuff, will have been depleted and
the debts will not only have not been paid but, will have gotten bigger.
Peak oil mates, peak oil. This is it. We are living it now. As I have stated previously, those
that deny peak oil do not understand it.
Plantagenet on Sat, 27th Feb 2016 8:48 pm
As long as global oil production continues to go up, we are not at peak oil.
We'll see a global peak in oil production sometime in the next 10 years, but we aren't quite
there yet.
CHEERS!
Harquebus on Sat, 27th Feb 2016 9:32 pm
Yeah but, oils ain't necessarily oils.
A lot of oil production is called oil but, it isn't sold on the oil market so, it isn't really
oil.
Truth Has A Liberal Bias on Sat, 27th Feb 2016 9:45 pm
Global oil production is down. July 2015 exceeds January 2016. And it will continue to decline
as we go forward.
Apneaman on Sat, 27th Feb 2016 9:53 pm
Yergin's a fuctard cheerleader and any prize can be bought. Pulitzer – Big fucking deal. Obama
has a Nobel and drone bombs babies and their mommas daily.
Apneaman on Sat, 27th Feb 2016 10:01 pm
Middle Eastern Wars Have ALWAYS Been about Oil
"Robert Kennedy Jr. notes:
For Americans to really understand what's going on, it's important to review some details about
this sordid but little-remembered history. During the 1950s, President Eisenhower and the Dulles
brothers - CIA Director Allen Dulles and Secretary of State John Foster Dulles - rebuffed Soviet
treaty proposals to leave the Middle East a neutral zone in the Cold War and let Arabs rule Arabia.
Instead, they mounted a clandestine war against Arab nationalism - which Allen Dulles equated
with communism - particularly when Arab self-rule threatened oil concessions.
They pumped secret
American military aid to tyrants in Saudi Arabia, Jordan, Iraq and Lebanon favoring puppets with
conservative Jihadist ideologies that they regarded as a reliable antidote to Soviet Marxism [and
those that possess a lot of oil].
At a White House meeting between the CIA's director of plans,
Frank Wisner, and John Foster Dulles, in September 1957, Eisenhower advised the agency, "We should
do everything possible to stress the 'holy war' aspect," according to a memo recorded by his staff
secretary, Gen. Andrew J. Goodpaster."
Rising debt might be a sign of approaching peak oil – excess energy is diminishing and therefore
unable to general excess capital production in society in order to pay interest and principal.
But in and of itself Debt is not definitive. Even if the return on energy were between 1 and
0 (costs more input than you get out), which would result in ginormous debts, but we could still
produce more total volume on a consistent basis, by the standard definition, no peakum oilum.
Now, its been at least six years that many have suggested we need to change the definition
of peak oil to mean: amount of Net Energy Available (from oil) to Society (nate hagens, et al).
And from that perspective, we've almost certainly reached peak net available energy or peak oil.
the question also about the different "liquids" going into the number is a solid question.
Will any of these questions make a difference to the MSM or doubters on this site? No.
rockman on Sat, 27th Feb 2016 10:53 pm
And again if folks keep allowing themselves to be baited into debates about PO dates and the
silly position that supply won't always meet demand (which it will thanks to the modulation effect
of pricing) then the reality of the complexity of the Peak Oil Dynamic will be ignored.
Just consider how few citizens don't understand that the current low oil prices are a result
of the diminishing capacity to develop meaningful new long term reserves.
shortonoil on Sun, 28th Feb 2016 7:07 am
"Breakeven cost for US oil in general is about $36 per barrel, although the average for
shale is around $58 (see breakeven cost for top oil exporters). The figure for Saudi Arabia, in
contrast, is just $9.90."
Crude stayed in the $100 range for almost four years. According to the quote above the industry
was making incredible profits during that period; so incredible that one would have to be an absolute
idiot to believe it? At $36 the profit margin on gross sales would have been 278%. On $58 it would
have been 172%, and on $9.90 it would have been 1010%.
That very easily explains how the Shale industry managed to accumulate over a $1 trillion in
debt to build annual sales of $360 billion. A 172% profit margin on gross sales will do that using
a combination of the New Math, and some very creative accounting. These guys are quoting EBITDA
numbers, not break even numbers. Of course, they think they have enough stupid, credulous readers
that they can get away with it.
Put it in print, and someone is dumb enough to believe it!
eugene on Sun, 28th Feb 2016 9:31 am
Another of the endless debates amongst people with little or no knowledge of the energy situation
but lots of opinions with each convinced their opinion is absolutely the correct one. I'd add
mine but I'm just an old man sitting in the woods with an "opinion" based on very limited knowledge.
One thing I do "know", oil is vital to our lifestyle and is a finite resource of which we have
extracted most of the cheap, easy stuff so will have to produce ever more expensive stuff. I like
the word "stuff" as it appears to me the definition of oil is changing according to the agenda
of the person speaking.
onlooker on Sun, 28th Feb 2016 11:21 am
"Just consider how few citizens don't understand that the current low oil prices are a result
of the diminishing capacity to develop meaningful new long term reserves." But some even here
say it is a glut. Hahaha. Funny isn't Rockman. Oh and for those who may not know Rockman is in
the Oil business he is not just some armchair pundit.
shortonoil on Sun, 28th Feb 2016 11:49 am
When the world is burning 32 Gb per year, and discovering 4Gb to replace the 32 it just used,
you apparently have a "glut". Is that the result of how you use your Facebook account? Maybe its
a Twitter brain thing?
onlooker on Sun, 28th Feb 2016 12:09 pm
Short thanks. Another person in the trenches. Not some denier, BAU cheerleader or shill. Because
they are the only ones harping on how Shale/Tar will bring about a revolution of new energy. Of
those 4Gb, I wonder now much of that per year we will even be able to bring to market. I think
depletion and the fizziling out of LTO will make in short term a mockery of the so called glut
and its advocates.
"The Cambridge Network is a commercial business networking organisation for business people
and academics[1][2] working in technology fields in the Cambridge area of the UK."
"Activities[edit] The organisation's mission is "We raise the game for business in Cambridge, and through that we
try to raise the game for economic growth in the UK."
Looker – I wish I didn't have to result to an worn anology but it works so perfectly: the blind
men trying to ID an elephant by each analyzing individual parts of the critter. PO (or more correctly
the POD…peak oil dynamic) is more than the date of global max oil production, storage volumes
at Cushing, KSA production levels, debt incurred by the US shale players, frac'ng costs, US oil
exports, a lot of dilbit made with Eagle Ford condensate, etc, etc, etc.
It's no different the
arguing that critter is a snake because only it's trunk has been analyzed. We see the same approach
here: PO isn't a factors because we see XXX or PO is the end of life as we know it because YYY
is happening.
Some don't like the POD because it's to inclusive. Which is the same as saying we shouldn't
study the entire anatomy of the elephant in order to ID it because that data is "too inclusive".
As I've stated before: the oil price spike which lead to the shale boom which led to increased
US oil production while cooling the global economy and leading to consumers who were unable/unwilling
to pay more then $40 per bbl which led to a drastic decline of shale rigs and a slew of oil companies
pushed to and over the brink of failure: collectively these events along with others indicate
to true nature of the PO dynamic.
At this point if one can't grasp the entire picture I doubt
they ever will.
IOW it's a f*cking elephant. LOL.
onlooker on Sun, 28th Feb 2016 2:58 pm
Thanks for the clear explanation of recent peak oil dynamics Rock. I being a layman have tried
to understand what is going on relative to PO and other matters affecting the planet as the least
we can do is know what the heck is really going on in the world we live. Now if they still don't
understand then they are dense or have an agenda.
shortonoil on Sun, 28th Feb 2016 3:17 pm
"Short thanks. Another person in the trenches."
When oil is selling for below its full life cycle production cost; when the industry's revenue
has fallen by $2.3 trillion per year in the last two years; when the Saudis are borrowing money
to pay their bills; when the nation with the largest petroleum resource on the planet can't afford
toilet paper for its citizens; when hundreds of US producers are going out of business; when the
world is using petroleum eight times faster than it is finding it; when the Etp Model said that
this was going to happen years ago -– yep, I believe it.
It's not that hard to get your head wrapped around, unless your head is made out of concrete.
Anonymous on Sun, 28th Feb 2016 3:37 pm
That was my point Ape
The word 'Cambridge' is intended to be associated with Cambridge University. Thus=Academic,
credible source.
And 'Science' of course, is pretty self explanatory. It is there to reinforce the 'Cambridge'
association.
Sort of doubling up on the implications that this source is a credible, rational, impartical
scientific org. (LOL). And not,(its hopeed) as you point out, basically, a high sounding cheerleader
for UK commercial energy corporations. And others I am sure…
makati1 on Sun, 28th Feb 2016 7:01 pm
Recent signs of oil's peak…
"Global Trade Is Collapsing--Chinese Exports To Brazil Down 60% In January Y/Y; All Containerized
Shipments To LatAm Down 50%" "Bond Vigilantes Push $258 Billion of Oil Debt Past Junk"
"Halliburton to cut 5,000 jobs in new round of layoffs" "Slashing Start for European Energy Sector"
"Apache Slashes 2016 Budget By More Than Half, Sees Lower Output" "World outside US and Canada doesn't produce more crude oil than in 2005"
"Shale Oil Architect Predicts Doom for Some Drillers Amid Slump" "UK Oil Industry At The "Edge Of A Chasm"
"Mansion sales and discount dining: oil rout hits Houston's rich" "Watch Five Years of Oil Drilling Collapse in Seconds"
And for chuckles: " Former Mexican President To Donald Trump: 'I'm Not Gonna Pay For That [Expletive] Wall,' Vicente
Fox Says" "Clinton Defends Ongoing Anarchy In Libya: We Are Still In Korea, We Are Still In Germany"
The shale bust and the fallout from $30 per barrel oil claimed another 13 rigs this week,
Baker Hughes announced Friday.
The oilfield service company's rig count showed only 400 rigs drilling for oil across the
U.S., down 75 percent from the October 2014 peak of 1,609. Over the past year, the count has
fallen by nearly 60 percent.
The total rig count - including both oil and gas rigs - now stands at 502 rigs. Natural gas rigs
were up one this week to 102.
The combined count is only 14 rigs above the lowest point since Baker Hughes began recording. The
record low was reached in 1999.
The crash in oil prices has taken its toll. The number of rigs drilling for oil and gas in the
U.S. is plunging toward the lowest level in more than 75 years of records. The animation below
shows the deployment of rigs over five years, culminating in the collapse of almost 75 percent of
the rig count.
... ... ...
These five years represent the fastest expansion of oil production in U.S. history. New
technology drove this boom-particularly the deployment of horizontal drilling through shale rock.
The three biggest oil-producing shale regions are the Permian basin in West Texas, the Eagle Ford
in Southern Texas, and the Bakken in North Dakota.
After the plunge in oil prices kicked off in late 2014, producers started shutting down rigs at
an unprecedented rate. The number of active rigs is approaching the lowest level since Baker
Hughes started tracking rig counts in 1940. The rig count fell by 12 to 502 in the latest week of
data. The lowest rig count on record was 488, in April 1999.
"... Once that pressure is down the dribbles that gravity will draw through those tiny cracks will still be tiny dribbles with twice as many cracks. Refracking wont do much to increase the gas pressure around a gas depleted horizontal run. ..."
This is a guest post from
WebHubbleTelescope
. Here he provides a simplified explanation of his Oil Shock Model as applied to oil production
from the Bakken formation. Previous contributions to THe Oil Drum from WHT can be found
here and
here .
My premise for participating was that I wanted to see how far I could get in understanding our
fossil fuel predicament by applying the mathematics of probability and statistics. There were enough
like-minded individuals that it turned out to be a productive exercise, and I found that even the
contrarian and cornucopian viewpoints could add value.
This was an ongoing process and I documented my progress with occasional posts on TOD and regular
posts on my blog http://mobjectivist.blogspot.com
. I treated the process as an experiment and as I collected more pieces of the puzzle, I realized
that I had collected enough information to aggregate it into a more comprehensive format.
After I finished the book (which incidentally I titled The Oil ConunDRUM as a nod to The Oil Drum)
the mobjectivist blog went dormant. I essentially treated that bog as a lab notebook, and I considered
that notebook was complete and finished as a historical record of what went into the book. So everyone
that mourns the closing of The Oil Drum has to remember that progress marches on, and something else
will spring from the analysis and research that went on here.
In passing, and as a short note to what one can do with some of the research that went into The
Oil Conundrum book, I thought to consider explaining how we can apply the Oil Shock Model to projecting
future Bakken formation production rates. Several TOD commenters have asked for a simple and intuitive
definition for how the shock model works, and it has always been a challenge to express it concisely.
In mathematical terms, it is simply the application of the convolution function to a model
of the statistical flow rate operating on the reserve potential of the reservoirs of interest.
The problem in casting it in this stark a mathematical form has been that the concept of convolution
is neither intuitive nor readily available to the layman. For example, the Excel spreadsheet application
does not have a convolution function in its toolbox of statistical operators. This is odd considering
that the great statistician William Feller once remarked that "It is difficult to exaggerate the
importance of convolutions in many branches of mathematics."
The best intuitive explanation that I can come up with is that a convolution (in the oil production
context) is a "sliding" summation of extraction applied to reserves.
Thus, the convolution algorithm automatically keeps track of older reserves as well as new reserves
as the total production accumulates with varying levels of extraction over time. Whether this is
completely intuitive to the layperson, we can always remember that a convolution is largely a cookbook
accounting exercise and once the form of the two inputs are known, a simple algorithm can be applied
to obtain a result.
For modeling the Bakken ala the convolution-based shock model, the inputs are two time-series.
The forced input is the time series of newly available wells.
The response input is the time series of expected decline from a single well.
The convolution function takes the forced input and applies the response input and generates the
expected aggregate oil production over time.
DC at his blog http://OilPeakClimate.blogspot.com/
has used this approach to good effect in modeling historical and projecting future Bakken production.
I apply a slightly different response function than DC and get this shock model output:
The two curves correspond to (1) the actual production data and (2) that which is modeled after
applying the convolution-based shock model to the well build-up, assuming a fairly rapid decline
response per well. The decline after month 714 would show what would happen if no new wells were
added. That of course won't happen, but it illustrates the Red Queen effect that Rune Likvern
has argued on these pages. The Red Queen hypothesis is that production will continue to increase
as long as a fresh supply of new wells with nominal reserve potential comes on line at a good pace.
As a detail, where DC and I differ is in how we apply the response model for the average well.
I have been applying a diffusional model based on the physics of flow, whereas DC has been using
a hyperbolic decline model which is favored by reservoir engineers. Not much of a difference between
the two, apart from gaining an understanding of what is actually happening underground, which is
likely an initially rapid diffusional flow followed by a the long tails of a diffusional decline.
As a caveat, the model would likely work even better if the North Dakota Department of Mineral
Resources had kept a cumulative total instead of an active count in their PDF table --
but as is the case with most of the data, you use what you can get.
The take-home point is that analysis approaches do exist outside of the insider oil patch knowledge-base.
Us mere mortals can formulate and apply these simple models to at least try to get a handle on future
fossil fuel supplies. That was the objective that I had when I started my blog and followed along
with TOD as we watched crude oil production plateau the last 9 years.
---
Doing this work on applying probability and statistics to the energy predicament has opened up
other possibilities which I have since pursued. Recently I have started up another blog on general
environmental modeling called http://ContextEarth.com
. This has an associated interactive modeling web server called the Dynamic Context Server, which
builds up from a semantically-organized knowledge-base of land, water, and atmospheric information.
I have incorporated the shock model as one of the functionalities in the server and intend to
maintain other capabilities to make it useful for environmental model activities, such as wind, solar,
and transportation simulations. Comments and collaboration opportunities are welcomed.
As you can see, The Oil Drum is only a start to the on-going energy transformation that we are
going through.
Any thoughts on how to incorporate price effects - e.g., the effect of the recent price hike,
which took Bakken production from it's former peak to a new growth phase?
The thinking is that the profit margin isn't that great and some have even speculated that
many operators will lose money. It sounds very similar to making a Hollywood movie -- all the
costs are eaten up during production with few films actually making money.
The early days include some wells that were borderline conventional wells, which made them
more competitive with other conventional wells in that timeframe. But there weren't many like
that, and it took the price increases to open up the rest to hydrofracturing technology.
Correction, in the last sentence: "But there weren't many like that".
I didn't want to edit and send it back into moderation. Sorry for delays in responding if I
include links. I have today off from work so can respond to questions quickly if no links are
involved.
In an ideal world, we'd have a single model that could project production for multiple price levels.
That is to say, something that in 1980 would have projected a ND peak of around 150k bpd under
a regime of $25 oil, and in 2007 would have projected a peak above 800k bpd for $90 oil.
My suggestion for these Bakken wells is to have a good model for when they get shut-in. That would
suggest the minimum level of production while still maintaining profitability.
You had the right scent when you brought up price but lost the trail with this last question.
It is the strong gas drive that makes these Bakken wells pay off quickly. Once that pressure
is down the dribbles that gravity will draw through those tiny cracks will still be tiny dribbles
with twice as many cracks. Refracking won't do much to increase the gas pressure around a gas
depleted horizontal run.
On the price thing, we can certainly evision that once a certain price threshold is achieved
somewhat less sweet spots will begin to pay and that those less and less sweet spots will encompass
greater acreage. More or less an inverse relationship between sweetness and area...but what we
can envision and the real facts under the ground might diverge wildly.
Oh and Web's diffusion light bulb came on when I posted this chart from the Great Bear site
Rock's comment on the chart was more or less that is was a crock as below a certain size crack
oil just wasn't going to have a significant increase in flow...but he kind of skipped mentioning
that gas flowed through those smaller cracks quite readily and that the increased gas drive those
cracks create might be the the real pay off.
This is a representation I made of the diffusional model:
The fissures are truly random pathways and the oil randomly walks to the collection point as
shown. They could just as easily travel away from the intended direction. It is true that the
pressure release enhances the flow but this flow is not as direct as a straight line. There is
really no control over the fissure formation.
The substantiation of this model is that the production follows a type of inverse square root
of time dependence, which is the signature of Fickian diffusion.
Look at the diffusion paper on the ContextEarth blog linked to above (go to Figure 17 shown
above to find the right section). Diffusional models are fairly general and can be used to describe
lots of applications. One of my favorite recent ones is that of Lithium ion battery charge and
discharge.
The math is very similar to oil flow, ions in the Lithium composite have to follow a random
walk to move between the anode and cathode. The random walk helps prevent the battery from discharging
(or charging) all at once.
It is really diminishing returns after the first fracturing attempt.
The model is one of diffusive flow, so if the volume is fractured one time, the second time
the fluid gets even more dispersed to points even further away from the collection points.
I have a paper describing diffusive flow on the ContextEarth server linked above that describes
the math.
They do refrac in some cases. While it is "diminishing returns", sometimes a refrac can increase
production enough to be worth the expense to the operator. However refracs probably won't change
the "big picture" of Bakken production all that much.
The technology of controlling fracs has become sophisiticated enough that in some cases the
refrac can open up new rock that wasn't fractured in the initial job. Or a refrac may help when
the original frac wasn't optimally done. See for example
Restimulating
the Bakken: What have we learned?
The model is one of diffusive flow, so if the volume is fractured one time, the second time
the fluid gets even more dispersed to points even further away from the collection points.
Your model may be diffusive flow and it may well mirror the actual oil and gas flow rates,
but what you must realize is the diffusion in fracking is the creation of the fractures themselves.
Once the big frac pumps shut down the fluids are not diffusing anymore, they are all following
the path of least resistance from a high pressure environment to a low pressure environment. And
that path is always little cracks feeding bigger cracks because bigger cracks relieve pressure
faster...as long as they stay open.
Wouldn't that be more like the reverse of diffusive flow just as much as tributary springs
flowing into brooks and creeks creeks, flowing into rivers and ultimately into the ocean is the
reverse of diffusive flow. Of course evaporation from those water courses and bodies is diffusive
flow and it does keep the cycle going but that is another story and is not what is happening in
a fracked well.
The pressure from the over burden is relentless and is always closing down fizzures pores that
no longer have enough fluid in them to push back. Its always a big squeeze out of any fluid that
can escape to low pressure areas just as long as the channels stay propped open. Refracking will
still have the liberated fluids attempt to leave high pressure environment for the low not disperse
them away from collection points for just as long as the refracking leaves open paths to the low
pressure zone.
I responded yesterday with an image from my paper but that got held up in moderation, so this
is what I said without the Figure 17 from the paper.
The fissures are truly random pathways and the oil randomly walks to the collection points.
They could just as easily travel away from the intended direction. It is true that the pressure
release enhances the flow but this flow is not as direct as a straight line. There is really no
control over the fissure formation.
The substantiation of this model is that the production follows a type of inverse square root
of time dependence, which is the signature of Fickian diffusion. I add an element of dispersion
to the flow which allows a range of diffusivities to the mix.
Look at the diffusion paper on the ContextEarth blog linked to above (go to Figure 17 to find
the right section). Diffusional models are fairly general and can be used to describe lots of
applications. One of my favorite recent ones is that of Lithium ion battery charge and discharge.
The math is very similar to oil flow, ions in the Lithium composite have to follow a random
walk to move between the anode and cathode. The random walk helps prevent the battery from discharging
(or charging) all at once.
"Wouldn't that be more like the reverse of diffusive flow just as much as tributary springs
flowing into brooks and creeks creeks, flowing into rivers and ultimately into the ocean is
the reverse of diffusive flow."
Once it gets to a river, that is definitely a gravity-fed flow. However, for tracing of flow
through porous media, hydrologists measure what are called breakthrough curves, and these are
largely diffusional flow with some gravity feed as well. I solved these dispersive transport equations
in The Oil Conundrum, and that is why it was fairly easy to make the connection to the Bakken
flow rates.
The Bakken flow is extremely diffusional because it has the strong diffusional spike at the
beginning followed by the fat-tails. Reservoir engineers use a heuristic curve called hyperbolic
decline, which happens to match the dispersive diffusional flow for a specific set of heuristic
parameters.
I could post some diagrams, but that would just go back in moderation, so I suggest you look
at the diffusional paper on the ContextEarth site and also The Oil Conundrum book where I have
a chapter on porous media dispersive diffusional flow.
The fissures are truly random pathways and the oil randomly walks to the collection points.
They could just as easily travel away from the intended direction. It is true that the pressure
release enhances the flow but this flow is not as direct as a straight line. There is really no
control over the fissure formation.
I never claimed the flow to be a straight line, the randomness of fissure direction is what
makes your diffusional flow math work, however the flow is not truly random. The fluids are moving
from high pressure to low pressure zones following the path of least resistance through open pathways
many of which only remain open because of the propant injected into the them.
The high initial flow after the first frac' job is generally very dependent on the gas drive.
That was my quibble when you described the diminishing returns of a refrac job to Nick. The first
frac' job will have found most of the larger natural fissures thus the bulk of the mobile fluids
in the horizontal well's sphere of influence. That is the main reason a second frac' would have
diminishing returns--there just won't be that much mobile gas and oil left for the horizontal
run to liberate--it wouldn't be because the new pathways opened will offer even longer routes
from high to low pressure zones or even that some of those longer routes lower pressure zones
will lead to already drained dead ends--though both are likely results of a second frac' job.
Unlike near surface water moving through porous medium fluids trapped in the Bakken medium
won't move much at all until a pressure differential is made available to them--a pressure differential
like the one created by frac'ed pathways leading to the horizontal collection pipe. As long the
pathways from higher to lower pressure remain open, the fluids will be travelling to low pressure
from high regardless how random the the direction of the pathway looks.
Without direct evidence that the flow is not random, the best we can do is look at the empirical
flow rates of a typical well. This seems to fit best either a diffusional flow profile or a hyperbolic
profile with a tuned exponent. The former is based on physics while the latter is a heuristic.
That essentially describes my model of the initial fracturing attempt.
Perhaps what happens on successive fracturing attempts is a moot point. The speculation is
the amount of oil rapidly diminishes -- but without some data to analyze, we are guessing as to
what the flow actually looks like.
I guess the next logical question is: is there a price for oil at which it would be worth drilling
new wells in between the old ones – In other words is there a price point at which well spacing
changes?
I'd argue that production is driven by profit rather than price. Consumption however is likely
pretty much a function of price.
If one assumes a required minimum return on capital OVER TIME profit and price then should be
causal but certainly not in the shorter run. What constitutes short run vs long run is related
to the nature of the project. Short run for somebody selling oysters is different from somebody
developing oil fields.
Correct me if I am wrong, but convolution is a cookbook technique for doing mathematically
what could be done with a lot of patience and a spreadsheet.
I produced this graph with a spreadsheet. Assume a well like the red line with production of
100, 60, 40, 30, 25, 20, ... in succeeding years (these numbers are just a guess for illustration,
not based on any real well), and open one new well a year. Then production will be as follows:
Yr 1: 100 total Yr 2: 60 + 100 = 160 total Yr 3: 40 + 60 + 100 = 200 total etc etc.
If I could do convolutions I could produce the totals 100, 160, 200, ... mathematically without
having to draw up a spreadsheet.
The accuracy of the model depends on two factors:
1. The correct shape of the well depletion curve.
2. The correct prediction of the number of wells drilled.
If sweet spots are drilled first one would expect individual wells to become less productive
with time, and the number of wells drilled to decrease. I presume these changes over time can
be modelled mathematically as well.
So, assuming WHT has done his sums correctly, and I believe he has, one's assessment of the
model must depend on one's assessment of how closely the depletion curves and drilling numbers
match reality.
I think these input factors should always be shown along with the final output curve.
Aa, you have the algorithm down about right for convolution.
In the context server that I mentioned, the calculation uses an expressive language whereby one
only has to write the phrase, A convolve B, to invoke a convolution. It is commutative so that
the order does not matter.
It is called the shock model since one can add perturbations, or slight shocks, to the extraction
rate as a final step. This is normally used for significant geopoltical shocks, as described in
Stuart Staniford's last post.
I am glad you got this piece written and my thanks to you and Joule for posting.
I find it helpful and will be pleased to follow your future 'experiments' with data in a variety
of fields!
That DC and Rune take a very similar approach to data is encouraging.
I await developments.
Even if I can 'follow' your logic, it does not mean that I could engage in creative or critical
discussion of methodology (!) but I am personally encouraged that you engage with 'entropy' as
a basis for your logic concerning probability, and that you appeal to known physical processes
such as diffusion in the case of tight-oil. All of which does indeed seem fundamental for the
outcomes we are interested in, if and when as you say the numbers are available.
Thanks again
Phil H
PS Can the 'shock' approach be used to test historical data retrospectively - e.g. perhaps
looking at USSR oil production, to test assumptions about industrial / technological / political
continuity, or indeed somewhat differently, effects of technology innovation? Perhaps to get a
handle on the size of 'shocks' and their effects? For the latter there is the example of USA tight-oil
extraction emerging during extraction from 'almost-conventional' oil-bearing formations, and then
expanding into a new phase with a new territory of opportunity. This was itself a 'shock', no?
"Can the 'shock' approach be used to test historical data retrospectively "
Certainly. In the book that I linked to, "The Oil Conundrum", I have more thorough examples
of how the shock model applies to historical geopolitical situations.
The Bakken example of this post is the simplest case of the convolution approach and so does
not incorporate the shocks of sudden changes to production levels.
A good example of a simple shock is looking at the historical UK North Sea production and then
consider the Piper Alpha incident. This caused a depression in extraction levels that the shock
model can approximate, resulting in the "dual hump" of UK oil production levels. This is also
described in the book.
This is an example of the shock applied to the UK production using the convolution-based shock
model:
The lower left is an extraction rate profile, which models the actual production level on the
upper right. The main point is that relatively small perturbations on the extraction rate leads
to noticeable changes in the production. The Piper Alpha caused both a reduction in that platform,
but also an overall reduction in the North Sea extraction as safety concerns propagated down the
line to other platforms.
As a caveat, the model would likely work even better if the North Dakota Department of Mineral
Resources had kept a cumulative total instead of an active count in their PDF table --
but as is the case with most of the data, you use what you can get.
I'm puzzled by this - do you mean cumulative production, or something else?
When a well stops producing it no longer shows up in the statistics. That makes it hard to tell
what the true cumulative is and how many new wells are being added. In other words, the running
total is new wells minus those removed, with no distinguishing between the two.
If you pay the N Dakota Department of Mineral Resources you can get the detailed records from
what I understand.
The given link did not bring me to a pdf file of the book.
(My books are free on line, but I'm a long ways up stream from you guys.)
To find my books, Google for Jon Claerbout books
Go to the menu item labeled The Oil Conundrum and that will take you to the PDF.
"The aim of every political constitution is, or ought to be, first to obtain for rulers men
who possess most wisdom to discern, and most virtue to pursue, the common good of the society;
and in the next place, to take the most effectual precautions for keeping them virtuous whilst
they continue to hold their public trust." -James Madison, FEDERALIST #57 (1787)
"... When Bubbles pop it almost always takes a full generation for investors to get interested again. It takes a new generation of suckers to buy into the next bubble. 2015-2014 was the peak in energy investment (adjusting for inflation of course). ..."
"... We very well will see Oil prices much higher in the future, but its not liking to influence CapEx as it did over the past decade. Most investors now see investing in energy too risky. We are likely to see some another round of banking trouble. ..."
"... This is like the Gold rush of the 19th century that lead to ghost towns. Banks will be holding on to retail and homes in oil boom towns that they won't be able to sell at virtually any price. ..."
"... I think the biggest losers in the Shale boondoggle is going to be pension funds, that were desperate for yield after they got clobbered in the 2008 housing bubble and the extreme low interest rates of the Bernanke years. They piled into energy hoping to make up for decades of losses. Now they will need to go ultra-conservate as boomers are now retiring and withdrawing thier pensions. ..."
"... We are already now on a permanent decline trajectory, really it was the US drilling that permitted global oil production to rise. Now we are 7 years further down the depletion road, and no mitigation plans in place. At some point in-fill drilling at the super-giants is going to come to end, and Oil majors will no longer be able to maintain output. Once these large fields rollover, no amount of drilling is going to prevent a global decline. I am sure that at or before 2020 arrives the majority of the super-giants be rolling over into significant declines. ..."
"... We are now in a permanent economic decline. The world economy had been propped up by developing nation borrowing (ie Brazil, China, India) and now they reached Peak Debt. Trying to add more debt, is just pushing on strings and lead to greater deflation & economic contraction. There is no more Chinas, Brazils, or Indias to kick off more infrastructure spending. The West is rapidly sinking as it can no longer stimulate economic growth and can no longer export goods and services to the BRICs. ..."
"... They are not going to like their increased living standards taken from them during the same lifetime that saw the increase. Brazil should be the poster child for this situation as the fall in its industrial production since the price crisis is nothing short of horrific. ..."
"... Time always answers these questions, but if 2015 is the peak, we will not see significant decline (more than 2 Mb/d) before 2030 unless there is a shock ..."
"When the oil price rises we will return to 2015 output levels
or higher by 2022 to 2025."
When Bubbles pop it almost always takes a full generation for investors
to get interested again. It takes a new generation of suckers to buy into
the next bubble. 2015-2014 was the peak in energy investment (adjusting
for inflation of course).
We very well will see Oil prices much higher in the future, but its
not liking to influence CapEx as it did over the past decade. Most investors
now see investing in energy too risky. We are likely to see some another
round of banking trouble. Even if banks have limited exposure to Oil&Gas
debt, they still likely loaned out money to workers that bought homes, or
business that started in the Boom towns. This is like the Gold rush
of the 19th century that lead to ghost towns. Banks will be holding on to
retail and homes in oil boom towns that they won't be able to sell at virtually
any price.
I think the biggest losers in the Shale boondoggle is going to be
pension funds, that were desperate for yield after they got clobbered in
the 2008 housing bubble and the extreme low interest rates of the Bernanke
years. They piled into energy hoping to make up for decades of losses. Now
they will need to go ultra-conservate as boomers are now retiring and withdrawing
thier pensions.
[US Auto workers, FedEx/UPS, Teacher Unions, Trucking Unions, State and
City workers across the country are facing severe pension cuts soon]
We are already now on a permanent decline trajectory, really it was
the US drilling that permitted global oil production to rise. Now we are
7 years further down the depletion road, and no mitigation plans in place.
At some point in-fill drilling at the super-giants is going to come to end,
and Oil majors will no longer be able to maintain output. Once these large
fields rollover, no amount of drilling is going to prevent a global decline.
I am sure that at or before 2020 arrives the majority of the super-giants
be rolling over into significant declines.
We are now in a permanent economic decline. The world economy had
been propped up by developing nation borrowing (ie Brazil, China, India)
and now they reached Peak Debt. Trying to add more debt, is just pushing
on strings and lead to greater deflation & economic contraction. There is
no more Chinas, Brazils, or Indias to kick off more infrastructure spending.
The West is rapidly sinking as it can no longer stimulate economic growth
and can no longer export goods and services to the BRICs.
At best the Worlds Central banks may turn to global scale QE, but that
won't fix the the mounting problems. Eventually we all become Venezuelans
& Greeks.
I harbor similar sensibilities about the global outlook, but then again
I tend to just look at things that way.
However, there is another way
of looking at things. For example, to many Indians the world has never looked
brighter. For many, they are just now starting to achieve what we might
consider middle class. The number of people who can afford to purchase a
gallon of gasoline each week has mushroomed over the past 20 years.
Here is an interesting graphic illustrating that trend from Reuters (2012)
"For example, to many Indians the world has never looked
brighter. For many, they are just now starting to achieve what we might
consider middle class."
Unfortunately I don't think is sustainable. I think there is a lot of
debt that is going to burn them. Same store in Brazil and China too. All
of them have seen some increased living standards. but is it sustainable?
no.
They are not going to like their increased living standards taken from
them during the same lifetime that saw the increase. Brazil should be the
poster child for this situation as the fall in its industrial production
since the price crisis is nothing short of horrific.
We should expect
civil unrest met with military repression during the upcoming 2016 Rio Olympics.
Graph of Brazil industrial production from Dr. Ed's blog
There have been bubbles in the past in the oil industry, but
with the exception of 1979 to 1983 (not a bubble, but a War) the declines
have been relatively short with sometimes a plateau of a few years. I believe
we will see a plateau for 5 years or so and then C+C output will rise by
1 to 6 Mb/d with a peak between 2020 and 2030 (2024-2026 is my best guess).
How much output rises will depend on oil prices and how consumers react
to the increase in prices. Higher oil prices will result in higher supply,
but those high prices may also destroy some demand.
Time always answers these questions, but if 2015 is the peak, we
will not see significant decline (more than 2 Mb/d) before 2030 unless there
is a shock (financial crisis or major war between Saudi Arabia and
Iran and/or Iraq). I cannot predict future shocks, but if someone wants
to go out on a limb and predict one, it can be modeled.
"... Lest anyone forget, if the number of additional wells does not increase in Bakken year-over-year, then the result will be as we showed in the last of The Oil Drum posts http://www.theoildrum.com/node/10221 ..."
Lest anyone forget, if the number of additional wells does not increase in Bakken year-over-year,
then the result will be as we showed in the last of The Oil Drum posts
http://www.theoildrum.com/node/10221
Individual Bakken wells have little long-term capacity, so that the decline effects are seen almost
immediately.
"... My level of knowledge in the oil world is too low, but from what I have seen in this blog we might be seeing a loss of 1 to 1.5 mbpd in 2016, depending on how much Iran is able to increase production. ..."
"... I guess then between 1 and 2 mbpd defines the possible loss of oil production in 2016. Is this a reasonable estimate? ..."
"... If Oil prices remain low 2015 will be the peak. I doubt oil prices will remain low after 2018. ..."
"... Not just discovery shortages, but the oil industry will have a severally compromised development capacity. It could barely overcome decline rates for conventional oil over the past 10 years, the LTO got developed at a loss, and about 30 to 40% of the industry is currently being laid off or shut down. ..."
"... I would love to see your rational for this. Who will return to 2015 output levels or higher? Obviously not everyone because so many nations have already peaked and are in decline. So for production to return to 2015 levels, and higher since you are not predicting peak oil until a decade or so from now, who will increase their production to well above 2015 levels? We know this will have to happen, for your scenario to be correct, because post peak nations will continue to decline regardless of price. ..."
Yes, OFM, I also shared Ron's opinion by late 2014 that 2015 was going to
be the year of Peak Oil.
But this is now a fact. Summer of 2015 (July for C+C, August for all
liquids) is a peak oil for everybody for as long as production doesn't start
increasing again. Since nobody is predicting an increase in production for
2016, the most fundamental issue in the oil world right now is how fast
is production going to fall and for how long.
My level of knowledge in the oil world is too low, but from what
I have seen in this blog we might be seeing a loss of 1 to 1.5 mbpd in 2016,
depending on how much Iran is able to increase production.
On the other hand people usually talk about a level of annual depletion
of around 6%. That's about 4.5 mbpd for the entire world, so if only half
of the world depletes at those rates we are talking upwards of a fall of
2 mbpd.
I guess then between 1 and 2 mbpd defines the possible loss of oil
production in 2016. Is this a reasonable estimate?
Not just discovery shortages, but the oil industry will have a severally
compromised development capacity. It could barely overcome decline rates
for conventional oil over the past 10 years, the LTO got developed at a
loss, and about 30 to 40% of the industry is currently being laid off or
shut down. There is no way it will be able to ramp up to about 150% of the
capacity it had say in 2013 to overcome accelerating decline rates and add
production on what will be ever more complex new fields (i.e. small, heavy,
deep water etc.)
When the oil price rises we will return to 2015 output levels or higher
by 2022 to 2025.
I would love to see your rational for this. Who will return to 2015 output
levels or higher? Obviously not everyone because so many nations have already
peaked and are in decline. So for production to return to 2015 levels, and
higher since you are not predicting peak oil until a decade or so from now,
who will increase their production to well above 2015 levels? We know this
will have to happen, for your scenario to be correct, because post peak
nations will continue to decline regardless of price.
So who will it be Dennis? Where will all this new production come from?
"... With those sort or numbers, we will nearly be able to count the number of rigs drilling in the Bakken, on our fingers and toes! And if XTO cut their 5 rigs to similar to their competitors, we will! ..."
"... If these numbers hold, looking at as low a 900K bopd this summer from ND. ..."
With Halcon and EOG releasing 2016 guidance, estimate the following companies:
QEP, SM Energy, Enerplus, Continental, Marathon, Oasis, Hess, WPX, Whiting, Newfield, HRC Operating
(Halcon) and EOG…
will complete in between 200-250 Middle Bakken and/or Three Forks wells in 2016. This is just
an ESTIMATE, as the companies report this guidance in many different formats, and in gross and/or
net wells.
The remaining companies with rigs running are XTO, Burlington, Statoil, Liberty and PetroHunt.
I cannot find Bakken specific 2016 guidance for XTO (ExxonMobil) Burlington(COP) and Statoil.
If anyone finds this, please post it.
PetroHunt and Liberty Resources, I believe, are private companies. They each have just one
rig running.
The above companies, I believe, are the only ones running rigs in the Williston Basin at present.
Clearly, there are other companies that have, and that could have DUCS to complete in 2016. Anyone
with any information on those, please post.
FYI, it appears the bulk of the completions will occur in Q1.
With those sort or numbers, we will nearly be able to count the number of rigs drilling in
the Bakken, on our fingers and toes! And if XTO cut their 5 rigs to similar to their competitors,
we will!
Toolpush. Went over those numbers with Rune, he came up with a little higher number than me, so
I will revise that to 250-325. Still a very low number for the large number of companies involved.
If these numbers hold, looking at as low a 900K bopd this summer from ND.
"... While the Saudis said Tuesday they don't plan to cut production, Pursell said the excess Saudi capacity is smaller than they claim. It's not "remotely possible" that Saudi Arabia is accurately reporting 12.5 million barrels of daily capacity, he said. In reality, it's likely no more than 11.5 million barrels. ..."
The price of oil may rebound to at least more than $40 a barrel relatively soon as supply and
demand come closer to balance, said EIA Administrator Adam Sieminski.
"I don't think we're that far away from it," he said.
David Pursell, managing director of Tudor, Pickering, Holt & Co. investment banking firm in Houston,
is particularly bullish. Companies are borrowing money to keep paying dividends to investors and,
in the process, they're canceling future projects. That leaves a big hole in future production, he
said.
... ... ...
While the Saudis said Tuesday they don't plan to cut production, Pursell said the excess Saudi
capacity is smaller than they claim. It's not "remotely possible" that Saudi Arabia is accurately
reporting 12.5 million barrels of daily capacity, he said. In reality, it's likely no more than 11.5
million barrels.
Jamie Webster, the senior director for global oil markets at IHS, said the oil crash was actually
expected to occur sooner than 2014. The Iranian sanctions and a sharp decline in Libyan production
simply delayed it, he said.
The next big question is what happens in April when a lot of energy companies go back to the banks
to negotiate debts and borrowing, Webster said. He expects banks to become much stingier.
'Within weeks, two low-profile legal disputes may determine whether an
unprecedented wave of bankruptcies expected to hit U.S. oil and gas producers
this year will imperil the $500 billion pipeline sector as well.
"... So far, relatively few oil and gas producers have entered bankruptcy, and most were smaller firms. But with oil prices down 70 percent since mid-2014 and natural gas prices in a prolonged slump, up to a third of them are at risk of bankruptcy this year, consultancy Deloitte said in a Feb. 16 report. ..."
"... Midstream operators have been considered relatively secure as investors and analysts focus on risks to the hundreds of billions of dollars in equity and debt of firms most directly exposed to commodity prices. ..."
"... Now, with U.S. oil output shrinking and gas production stalling, many of the cash-strapped producers entering bankruptcy will be seeking to rid themselves of pricey agreements, particularly those with so-called minimum volume commitments that require paying for space even if it is not used. ..."
So far, relatively few oil and gas producers have entered bankruptcy, and
most were smaller firms. But with oil prices down 70 percent since mid-2014 and natural gas prices
in a prolonged slump, up to a third of them are at risk of bankruptcy this year, consultancy Deloitte
said in a Feb. 16 report.
Midstream operators have been considered relatively secure as investors and analysts focus on
risks to the hundreds of billions of dollars in equity and debt of firms most directly exposed to
commodity prices.
That's because firms such as Enterprise Products ( EPD.N ),
Kinder Morgan KM.N and Plains All American ( PAA.N )
relied upon multi-year contracts -- the kind targeted in the two bankruptcies -- that guarantee pipeline
operators fixed fees to transport minimum volumes of oil or gas.
Now, with U.S. oil output shrinking and gas production stalling, many of the cash-strapped producers
entering bankruptcy will be seeking to rid themselves of pricey agreements, particularly those with
so-called minimum volume commitments that require paying for space even if it is not used.
"They will be probably among the first things thrown out," said Michael Grande, director for U.S.
midstream energy and infrastructure at Standard & Poor's.
Still, the pain is accruing already. Plains All American said this month that it expected a default
from one unidentified customer who contracted for 10 percent of its BridgeTex pipeline, which transports
crude from west Texas to the Houston area. Reuters later identified the customers as a little-known,
privately held merchant called Stampede Energy. [IL2N15W14Z]
'Within weeks, two low-profile legal disputes may determine whether an unprecedented wave of bankruptcies
expected to hit U.S. oil and gas producers this year will imperil the $500 billion pipeline sector
as well.
Shale explorers will be "decimated" in coming months amid a wave of restructurings and bankruptcies,
fallout from the 70 percent drop in oil prices since mid-2014, Papa, who is now a partner at private-equity
firm Riverstone Holdings LLC, said during a panel discussion at the IHS CERAWeek event in Houston
on Tuesday. Low prices probably will linger for another 16 to 24 months before supply cuts cause
a rebound, he said.
"... Consumption of natural gas for power generation (power burn) in Texas is at a record high,
according to data from Bentek Energy. Daily consumption in 2015, through August 11, has averaged 4.5
billion cubic feet per day ..."
Consumption of natural gas for power generation (power burn) in Texas is at a record
high, according to data from Bentek Energy. Daily consumption in 2015, through August 11, has
averaged 4.5 billion cubic feet per day (Bcf/d). The next-highest level was 4.4 Bcf/d,
for the same period in 2012.
"... The next six to 12 months is going to be a decimation for that industry – bodies all over the place, ..."
"... From those ashes you're going to see the companies that survive, are going to come out of it a lot more conservative as they go forward. They're not going to stretch their balance sheets so much and make acquisitions based on false premises ..."
"... "Where is the supply going to come from, particularly when you see capital spending on the mega projects has stopped cold," he said. "I can foresee a case where the biggest supplier in 2020 is the U.S. shale producers, because the world needs that incremental production." ..."
"The next six to 12 months is going to be a decimation for that industry – bodies all over the
place," he said at the IHS CERAWeek conference. "From those ashes you're going to see the companies
that survive, are going to come out of it a lot more conservative as they go forward. They're not
going to stretch their balance sheets so much and make acquisitions based on false premises."
... ... ...
Still, if forecasts that world demand will grow 1 million barrels a day annually for the next
five years hold true, Papa said he was bullish on the U.S. sector.
"Where is the supply going to come from, particularly when you see capital spending on the mega
projects has stopped cold," he said. "I can foresee a case where the biggest supplier in 2020 is
the U.S. shale producers, because the world needs that incremental production."
A drop of natural gas production also means drop in condensate production. "Production in the
Utica and Woodford plays is increasing but it is largely offset by declining associated gas from the
Eagle Ford, Bakken and other tight oil plays."
Notable quotes:
"... Every week, the EIA proclaims a new record for natural gas production. But their own forecasts show that the U.S. will be short on supply by October of this year. A price increase is inevitable beginning later in 2016. ..."
"... The popular myth is that gas production will continue to increase and that prices will remain low for years. In the myth, price has no effect on production. The reality is that price matters and production is down 1.2 bcfd 1 since September 2015 ..."
"... Hedges made when prices were in the $5-range carried many companies through falling prices as they continued to produce like there was no tomorrow. Tomorrow has arrived and the hedges are gone. ..."
"... A supply deficit does not mean that there won't be enough gas. There is ample gas presently in storage to cover a supply shortfall for awhile. That is what happened during the supply deficit in 2013-2014 (Figure 5). That deficit was created by flat production similar to what EIA predicts for the first 3 quarters of 2016. ..."
"... What is different this time, however, is that net imports will reach zero in early 2017 because of decreasing imports from Canada and increasing exports. Add to that the challenge of replacing conventional gas depletion, and there is a much more serious supply problem than EIA's already questionable forecast suggests. ..."
Every week, the EIA proclaims a new record for natural
gas production. But their own forecasts show that the U.S. will be short on supply
by October of this year. A price increase is inevitable beginning later in 2016.
Popular Myth vs Reality
The popular myth is that gas production will continue to
increase and that prices will remain low for years. In the myth, price has no effect on
production. The reality is that price matters and production is down 1.2 bcfd1
since September 2015 (Figure 1).
The production increases reported by EIA are year-over-year comparisons that don't reflect
declines during the last 4 months.
Prices have fallen to less than half what they were in early
2014. The average price for the first quarter of 2016 is only $2.25 per MBTU2 (Figure 2).
Hedges made when prices were in the $5-range carried many companies through falling prices as
they continued to produce like there was no tomorrow. Tomorrow has arrived and the hedges are
gone.
Over-production in the Marcellus Shale means that producers have to compete for limited pipeline
capacity by deeply discounting their sales price. The best core area locations are commercial at
$4 per mcf3 but wellhead prices averaged only $1.75 per mcf in 2015.
... ... ...
There is no
simple solution to falling supply. That's because almost half of U.S. supply is conventional gas
and it is in terminal decline. Now, shale gas is also in decline (Figure 3).
... ... ...
The
EIA forecasts that net dry gas production will increase 1.4 bcfd in 2016 and 1.6 bcfd 2017. Even
with that optimistic forecast, their data still shows that the U.S. will have a supply deficit
beginning in the last quarter of 2016 (Figure 5). A more realistic forecast implies a much
greater deficit that begins sooner.
... ... ...
A supply deficit does not mean that there
won't be enough gas. There is ample gas presently in storage to cover a supply shortfall for
awhile. That is what happened during the supply deficit in 2013-2014 (Figure 5). That deficit was
created by flat production similar to what EIA predicts for the first 3 quarters of 2016.
What is different this time, however, is that net imports will reach zero in early 2017
because of decreasing imports from Canada and increasing exports. Add to that the challenge of
replacing conventional gas depletion, and there is a much more serious supply problem than EIA's
already questionable forecast suggests.
Another big difference is that in 2013-2014,
capital was freely available with average oil prices above $90 per barrel and average gas prices
more than $4 per MBTU. Today, the oil and gas industry is in financial shambles with both oil and
gas prices at very low levels, and it is unlikely that companies can raise the capital necessary
to ramp up gas drilling quickly if at all.
"... Still, at current prices PXD is trading at 20 times EV/EBITDA inclusive of hedges. I have been saying this for a long time – the market is pricing ALL shale companies as if the price of oil is $70 per barrel. ..."
PXD's net debt is lower because they expect $1.6 billion in cash from the stock offering
and $500 million in cash from the sale of the pipeline.
Still, at current prices PXD is trading at 20 times EV/EBITDA inclusive of hedges. I have
been saying this for a long time – the market is pricing ALL shale companies as if the price of
oil is $70 per barrel.
I'm curious what are low decline vertical waterflood properties selling for in this
environment? Aren't these in general better in a lower priced environment (say $50ish) than the
shale plays? I can't really figure out why horizontal permian gets so much hype in this environment.
I've found 2 permian players that seem to make money at 50 and below, RSP permian and Callon Petroleum,
but they are valued as if oil is +80 trading at over $100k per flowing barrel. The lowest cost
producers I've found are all vertical producers and MLPs. MCEP is probably the lowest cost producer
in the U.S. and they do pure low decline waterfloods. They have quite a bit of debt but even with
that they're trading at $40k per flowing barrel including all debt.
Kelly b. Right now, unhedged, 2/16 price looks to be $16-$26 depending on location.
I sincerely
doubt there are many secondary projects will all in costs (excluding interest) under $20. Just
look at MCEP.
How do you price assets that are barely making money, breaking even, or losing money?
Likewise, re shale. PXD values PUD PV10 at about $350 million. It isn't too economic. They
are saying that, not me. Some 600,000 acres in the Permian with PUD PV 10 of $350 million at $50
WTI.
The only value in lower 48 onshore is that prices rise substantially in 2016. It is practically
all an option at current levels. The PV10 values tell us that.
What happens to GM, for example, if they can suddenly only sell new vehicles for $5-15K?
One company you mention is Mid-Con. In 2014 PV10 was $664 million. But look at costs. LOE $22.93,
production taxes $5.56, G & A $12.58. LT debt $205 million.
Granted, in Q3 2015 they had hammered costs down to $19.60 LOE, $.46 production taxes and $5.04
G & A. At $25 wellhead there is $0 PV.
Yes, Mid-Con is hedged. Only way they may survive. I'd say almost secondary and tertiary projects
are underwater at $30 WTI in lower 48, when G & A is included.
Shale oil LOE is only low due to a high number of new wells. I think 5+ year old wells have
LOE $15-$30 for the most part, with outliers of course.
"... In west-central Alberta, the ballpark cost of a vertical well is probably $1-2 million. The cost of a horizontal multi-stage hydraulically fractured well is more like $5-10 million (I didn't research these numbers. I'm just basing them on what I've seen in the past). ..."
"... Did multi-stage horizontals make producing from unconventional reservoirs possible? Of course. Did they make it economic? For a while, when oil was $100 per barrel. Did they make production predictable? Not even close. ..."
In west-central Alberta, the ballpark cost of a vertical well is probably $1-2 million.
The cost of a horizontal multi-stage hydraulically fractured well is more like $5-10 million
(I didn't research these numbers. I'm just basing them on what I've seen in the past).
Did multi-stage horizontals make producing from unconventional reservoirs possible?
Of course. Did they make it economic? For a while, when oil was $100 per barrel. Did they make
production predictable? Not even close.
"... There are 3100 wells in the Williston Basin that are producing 40 bpd and less, if they all are producing close to the forty barrels per day, the shutting of those wells will reduce the production by some 120,000 bpd, maybe. Daily production would fall to one million bpd and maybe even close in on 900,000 bpd with decline. ..."
"... Bakken well horizontals are known to fill up with sand, so you have to keep pumping oil to prevent plugging the horizontal. ..."
"... Madison Formation oil is a heavier oil than Bakken oil, the classic dark green gray color of the oil is there, it is oily oil, clings to the side of the jar, not the light stuff like Bakken crude. A distinct color difference between the two oils. ..."
There are 3100 wells in the Williston Basin that are producing 40 bpd and less, if they all
are producing close to the forty barrels per day, the shutting of those wells will reduce the
production by some 120,000 bpd, maybe. Daily production would fall to one million bpd and maybe
even close in on 900,000 bpd with decline.
Madison Formation wells and Red River Formations have produced plenty of oil over the years,
nothing like the Bakken though. If you view the pdf, the production for each formation is right
there. Bakken well horizontals are known to fill up with sand, so you have to keep pumping oil
to prevent plugging the horizontal. You will need two hamsters in the wheel to make it go faster.
Madison Formation oil is a heavier oil than Bakken oil, the classic dark green gray color of
the oil is there, it is oily oil, clings to the side of the jar, not the light stuff like Bakken
crude. A distinct color difference between the two oils.
Something similar to GNE is happening within the US, which I would call "local net oil exports"
The horizontal drilling and fracturing in the Bakken formation, Eagle Ford, and areas of similar
oil bearing strata uses a lot of energy in the process. I have mentioned before about how Tesoro's
Mandan, ND refinery (70,000 bpd being expanded to 110,000 bpd) cannot produce enought diesel fuel
for the local market. This is mainly due to the Bakken oil production requiring HUGE amounts of
diesel fuel, besides the transport system (both trucks and railroads) being fueled to keep the
oil and supplies moving. My customer each month moves millions of gallons of diesel from the Fargo
ND pipeline (fed by St. Paul, MN refinery) every month to Bismark, ND. This "imported " diesel
keeps trucks fueled in the Bakken formation area.
So as EROEI decreases for oil production regions like the Bakken, less percentage of that oil
will ever be "exported" to other areas of the US. Tesoro's increase in refinery capacity will
not help lower diesel prices in ND, now near $5/gallon, since most of the new diesel produced
will be used locally for Bakken region users, IMO.
1,000 truck trips per constructed pad site, with maybe 5,000 pads to be built in the 50,000
well drill plan. That's a lot of diesel....especially since trucks keep running after the pad
is built too.
The EROEI of oil sands production ranges from 12:1 for the most efficient mining operations
to about 4:1 for the least efficient steam injection projects. I tend to use 6:1 as an arbitrary
number for discussion purposes.
However, the Bakken probably has an EROEI in the same range once all the fuel consumption for
drilling, fracing, and trucking the product are factored in. The oil industry is indeed a very
intensive user of diesel fuel.
In the case of oil sands, though, the fuel is natural gas, which is trading far below its fuel
value on an energy equivalence basis, so in money terms it works out rather well for the companies
in the long term. OTOH, the Bakken wells may not have a long term given their very steep production
decline rates.
I found a source earlier this year where nat gas consumption for Canadian tar sands was published
and this led to an ERoEI estimate of 3. When ERoEI approaches one we are really dealing with energy
conversion as opposed to energy "production", and as you point out with nat gas cheap in N America,
this is currently an attractive proposition.
We are happy to do energy conversions of coal and gas to electricity with significant energy
losses along the way. Upgrading energy quality is a vital component of our energy system.
The thing that gets me right now in N America is how expensive shale gas has dumped nat gas
prices making the oil sands more attractive.
I was working from industry numbers. Companies don't generally calculate EROEI, but you can
calculate it from their oil production and gas consumption data. It's important to realize they
are steadily improving the EROEI as they make improvements in the technology. A lot of the technology
is very new, so an EROEI of 3 is probably from old data.
However, the low price of NG certainly makes the industry's bottom line look better. There
are NG fields near and directly underneath the oil sands. A lot of the oil sands companies have
their own NG wells, and no economic market for the NG other than to feed it into their own oil
sands plants.
There are also shale gas fields nearby that recent studies have determined are as big as those
in the US, but they are definitely uneconomic at current prices.
The Bakken region sounds to be a perfect place for CNG/LNG for truck/train haulage. They are
currently flaring Nat gas due to lack of market, and needing to invest heaps to import diesel.
Kill two birds with the one stone. Use the waste nat gas instead of expensive diesel. The drilling
rigs and maybe even the frac trucks could also be converted. The technology is there, just need
managers to start thinking outside the box, and start making use of all the resources available
to them. This seems the easy way to decrease the amount of liquid fuel inputs into high cost oil
production.
It takes more than managers thinking about it, it requires government regulation to prevent
flaring.
This is an obscure historical point, but it was NG flaring that led to provincial regulation
of the oil industry in Alberta. Oil companies flared off about $20 billion worth of NG (at today's
prices) and permanently damaged the reservoir drive on the old Turner Valley field. It was quite
obvious what was going on because people in Calgary, 100 miles away, could see the flares lighting
up the night skies and smell the sulfur from the burning gas. Ducks stopped going south for the
winter and people used to hunt rabbits at night with the light from the flares.
The oil companies and the federal government rejected provincial government regulation of flaring,
and the supreme court stuck down several laws, but the Alberta government proved it could be very
innovative at inventing new laws, it could pass them faster than the courts could strike them
down, and things could turn very ugly at election time - the opposing parties were not just defeated
but completely wiped out in Alberta.
Eventually the companies, the Feds, and courts agreed that it was easier to let the Alberta
government regulate NG production, and it has done so very positively ever since. This was the
origin of the Alberta Energy Resources Conservation Board.
…Enerplus delivered fourth quarter production of 106,905 BOE per day, contributing to annual
average production of 106,524 BOE per day, approximately 3% higher than 2014 and above guidance
of 106,000 BOE per day. This strong production was despite a 39% reduction in capital spending
year-over-year and over 6,000 BOE per day of production divested during the year which,
given the timing of the divestments, reduced annual average volumes by approximately 1,300
BOE per day.
…Fourth quarter funds flow was $103 million ($0.50 per share), down approximately 15% from
the previous quarter primarily as a result of lower commodity prices and production volumes.
Full year funds flow was $493 million ($2.39 per share), down approximately 43% primarily
due to significantly lower crude oil and natural gas prices relative to 2014. Commodity hedging
helped support funds flow during 2015 with cash gains of $288 million.
…Enerplus reported a net loss of $625 million in the fourth quarter as it incurred
non-cash charges including $266 million related to an asset impairment and a $426 million valuation
allowance for deferred tax assets.
Enerplus has also reduced its 2016 capital budget a further 43% to $200 million. This
represents a 60% reduction from 2015 spending levels. The reduced budget is focused on
balance sheet preservation and maximizing the long-term value of the Company's assets. The
revised 2016 capital program comprises drilling 25.9 net wells (18.5 in North Dakota, 1.5 in
the Marcellus and 6.0 in the Canadian waterfloods) and bringing on-stream 24.2 net wells (13.6
in North Dakota, 4.6 in the Marcellus and 6.0 in the Canadian waterfloods).
Taking into account the reduced capital program, and the approximately 8,000 BOE per
day of production divested since Enerplus released its original 2016 guidance, the revised
production guidance for 2016 is 90,000 – 94,000 BOE per day. Expected crude oil and natural
gas liquids production is modestly lower at 43,000 – 45,000 barrels per day, now representing
48% of total 2016 production at the midpoint (versus 44% previously).
Note assets sales and 10% drop in production forecasted for 2016.
mbnewtrain
on November 22, 2012 - 12:27am
Permalink
Something similar to GNE is happening within the US, which I would call "local net oil exports"
The horizontal drilling and fracturing in the Bakken formation, Eagle Ford, and areas of similar
oil bearing strata uses a lot of energy in the process. I have mentioned before about how Tesoro's
Mandan, ND refinery (70,000 bpd being expanded to 110,000 bpd) cannot produce enought diesel fuel
for the local market. This is mainly due to the Bakken oil production requiring HUGE amounts of
diesel fuel, besides the transport system (both trucks and railroads) being fueled to keep the
oil and supplies moving. My customer each month moves millions of gallons of diesel from the Fargo
ND pipeline (fed by St. Paul, MN refinery) every month to Bismark, ND. This "imported " diesel
keeps trucks fueled in the Bakken formation area.
So as EROEI decreases for oil production regions like the Bakken, less percentage of that oil
will ever be "exported" to other areas of the US. Tesoro's increase in refinery capacity will
not help lower diesel prices in ND, now near $5/gallon, since most of the new diesel produced
will be used locally for Bakken region users, IMO.
Paleocon
on November 22, 2012 - 12:55am
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1,000 truck trips per constructed pad site, with maybe 5,000 pads to be built
in the 50,000 well drill plan. That's a lot of diesel....especially since trucks
keep running after the pad is built too.
RockyMtnGuy
on November 22, 2012 - 9:00pm
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The EROEI of oil sands production ranges from 12:1 for the most efficient
mining operations to about 4:1 for the least efficient steam injection projects.
I tend to use 6:1 as an arbitrary number for discussion purposes.
However,
the Bakken probably has an EROEI in the same range once all the fuel consumption
for drilling, fracing, and trucking the product are factored in. The oil
industry is indeed a very intensive user of diesel fuel.
In the case of oil sands, though, the fuel is natural gas, which is trading
far below its fuel value on an energy equivalence basis, so in money terms
it works out rather well for the companies in the long term. OTOH, the Bakken
wells may not have a long term given their very steep production decline
rates.
Euan Mearns
on November 23, 2012 - 5:10am
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I found a source earlier this year where nat gas consumption for Canadian
tar sands was published and this led to an ERoEI estimate of 3. When ERoEI
approaches one we are really dealing with energy conversion as opposed
to energy "production", and as you point out with nat gas cheap in N America,
this is currently an attractive proposition.
We are happy to do energy
conversions of coal and gas to electricity with significant energy losses
along the way. Upgrading energy quality is a vital component of our energy
system.
The thing that gets me right now in N America is how expensive shale
gas has dumped nat gas prices making the oil sands more attractive.
RockyMtnGuy
on November 23, 2012 - 10:35am
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I was working from industry numbers. Companies don't generally calculate
EROEI, but you can calculate it from their oil production and gas consumption
data. It's important to realize they are steadily improving the EROEI
as they make improvements in the technology. A lot of the technology
is very new, so an EROEI of 3 is probably from old data.
However, the low price of NG certainly makes the industry's bottom
line look better. There are NG fields near and directly underneath
the oil sands. A lot of the oil sands companies have their own NG wells,
and no economic market for the NG other than to feed it into their
own oil sands plants.
There are also shale gas fields nearby that recent studies have
determined are as big as those in the US, but they are definitely uneconomic
at current prices.
The Bakken region sounds to be a perfect place for CNG/LNG for truck/train
haulage. They are currently flaring Nat gas due to lack of market, and needing
to invest heaps to import diesel. Kill two birds with the one stone. Use the
waste nat gas instead of expensive diesel. The drilling rigs and maybe even
the frac trucks could also be converted. The technology is there, just need
managers to start thinking outside the box, and start making use of all the
resources available to them. This seems the easy way to decrease the amount
of liquid fuel inputs into high cost oil production.
This is an obscure historical point, but it was NG
flaring that led to provincial regulation of the oil industry in Alberta.
Oil companies flared off about $20 billion worth of NG (at today's prices)
and permanently damaged the reservoir drive on the old Turner Valley field.
It was quite obvious what was going on because people in Calgary, 100 miles
away, could see the flares lighting up the night skies and smell the sulfur
from the burning gas. Ducks stopped going south for the winter and people
used to hunt rabbits at night with the light from the flares.
The oil companies and the federal government rejected provincial government
regulation of flaring, and the supreme court stuck down several laws, but
the Alberta government proved it could be very innovative at inventing new
laws, it could pass them faster than the courts could strike them down, and
things could turn very ugly at election time - the opposing parties were
not just defeated but completely wiped out in Alberta.
Eventually the companies, the Feds, and courts agreed that it was easier
to let the Alberta government regulate NG production, and it has done so
very positively ever since. This was the origin of the Alberta Energy Resources
Conservation Board.
"... The CEO of Devon [which cut 75% of their drilling budget] essentially asked: Who would ever drill for new production at these prices. Then Marathon came out with essentially the same thing with their budget. And, EOG will not have any rigs running in ND. I think that Harold Hamm finally got religion over at CLR. ..."
"... I am sensing an emerging consensus to just bite the bullet and bring production down as fast as possible unless a lender forces the issue. ..."
Does anyone know what the status of crude pipelines to haul Bakken oil is? I ask because I believe
that the decline in rail car loading is greater than any decline in production. So, I am curious
how much of the Bakken oil is now avoiding the extra cost that rail shipment incurs.
The CEO of Devon [which cut 75% of their drilling budget] essentially asked: "Who would
ever drill for new production at these prices." Then Marathon came out with essentially the same
thing with their budget. And, EOG will not have any rigs running in ND. I think that Harold Hamm
finally got religion over at CLR.
So, the big unknown now seems to be how fast they will complete the inventory of drilled but
uncompleted wells. I am sensing an emerging consensus to just bite the bullet and bring production
down as fast as possible unless a lender forces the issue.
Does anyone know what the status of crude pipelines to haul Bakken oil is? I ask because I believe
that the decline in rail car loading is greater than any decline in production. So, I am curious
how much of the Bakken oil is now avoiding the extra cost that rail shipment incurs.
The CEO of Devon [which cut 75% of their drilling budget] essentially asked: "Who would ever
drill for new production at these prices." Then Marathon came out with essentially the same thing
with their budget. And, EOG will not have any rigs running in ND. I think that Harold Hamm finally
got religion over at CLR.
So, the big unknown now seems to be how fast they will complete the inventory of drilled but
uncompleted wells. I am sensing an emerging consensus to just bite the bullet and bring production
down as fast as possible unless a lender forces the issue.
"... Wells in the Williston Basin that produce 40 barrels per day and less are going to be shut. I think it is about a thousand of them, if they have been shut already, it would explain the 29,000 bpd drop. Shut wells will result in an increase of daily production per well. ..."
Wells in the Williston Basin that produce 40 barrels per day and less are going to be shut. I
think it is about a thousand of them, if they have been shut already, it would explain the 29,000
bpd drop. Shut wells will result in an increase of daily production per well.
When the price of oil increases, the wells will recommence pumping.
"... Winter just started affecting the North Dakota production numbers. There is more decline to be expected the coming months. Consider seasonal conditions combined with the maturity of the field and with low prices. The peak is behind us. ..."
"... The accuracy of your curve would suggest that the drop in oil price hasnt had as marked an impact as would be expected – i.e. the decline was going to happen anyway, no matter what. Can you comment on that? ..."
"... basically, I believe ND Bakken is producing every barrel it can, from a geology point of view – despite the low prices. ..."
"... for the coming year we agree. Down down down. Prices may (and will) rise again. But I do not see another 27k wells being drilled in that North Dakota landscape. Just look at it on Google Maps. There are wells everywhere! Where are the North Dakotans going to drill 27k new wells? The USGS is an important institution, but I believe they overestimate Bakken URR greatly. ..."
"... the number of potential well locations is still high. Many of them are outside the sweet spots, but if and when oil prices rebound, a large part of potential B-TF wells may be economically viable. ..."
"... And how many loans are created in consumer/real estate economy based on oil being $100 where was incentive to provide enough liquids at that price for our endless car circling that we call GDP. That debt is no different than E P debt and will be crashing down at same time. ..."
Winter just started affecting the North Dakota production numbers. There is more decline to
be expected the coming months. Consider seasonal conditions combined with the maturity of the
field and with low prices. The peak is behind us.
The accuracy of your curve would suggest that the drop in oil price hasn't had as marked an impact
as would be expected – i.e. the decline was going to happen anyway, no matter what. Can you comment
on that?
I am, honestly, stupified myself by the accuracy of the curve, that is 25 months old now without
ever tinkering the parameters of the model. It was based on Hubbert analysis, adding a seasonal
effect on it. So basically it is pure geology, no impact of price whatsoever. Besides that, one
needs to aware of the price collapse and the possible impact on the industry. So I might be just
"lucky" to be right with my prediction, because the price collapse happened to coincide with the
predicted decline in production.
For that reason I added the other set of curves: the first derivative of the model and the
change in production (5 month moving average). The cool thing is: there is basically no disturbance
of the expected/predicted changes in the data. The changes in the data do follow the first derivative
of the model too. Would there have been a sudden policy change (due to lower prices) there would
occur a mismatch between the first derivative of the model and the change in the data. That did
not happen.
So, basically, I believe ND Bakken is producing every barrel it can, from a geology point
of view – despite the low prices.
Can you remind us what the URR of your Hubbert model is?
I ask because Proved plus probable reserves at the end of 2014 were about 9.3 Gb, cumulative
production was about 1.2 Gb at the end of 2014,which suggests a URR of 10.5 Gb, if no new reserves
are added from possible reserves or contingent resources in the future .
The decline has very little to do with geology and much to do with the oil price.
If new wells were being added at a rate of 150 new wells per month in a scenario where oil
prices only fell to $80/b instead of $50/b in 2015 and then gradually rose from $80/b in June
2017 to $160/b in Oct 2020, then output would increase until mid 2020 and then gradually decrease.
If we assume profitable well locations run out at about 40,000 total wells drilled, we get
the scenario below when 150 new wells per month are added from May 2015 to Sept 2031.
An alternative to Bruno Verwimp's model where the wells added decreases due to low oil prices
and then increase when oil prices increase in the future. The URR is consistent with USGS estimates
of about 10 Gb for the Bakken Three Forks.
Nice to meet you again, Dennis! I was waiting for you. :-)
The future will tell who had the
best idea. Reality may turn out to be something in between our ideas. At least I understand
for the coming year we agree. Down down down. Prices may (and will) rise again. But I do not
see another 27k wells being drilled in that North Dakota landscape. Just look at it on Google
Maps. There are wells everywhere! Where are the North Dakotans going to drill 27k new wells? The
USGS is an important institution, but I believe they overestimate Bakken URR greatly.
There are currently 10,756 producing unconventional Bakken–Three forks wells. Even including
the shut-in wells, the total number of drilled Bakken-TF wells unlikely exceeds 12-13 k.
So the number of potential well locations is still high. Many of them are outside the sweet
spots, but if and when oil prices rebound, a large part of potential B-TF wells may be economically
viable.
"Citing up-to-date analysis of production data and cash costs from over 10,000 oil fields,
Wood Mac said it believes 3.4 million b/d, or less than 4% of global oil supply, is unprofitable
at oil prices below $35/b.
Even the majority of US shale and tight oil, which has been under the spotlight due to higher-than-average
production costs, only becomes cash negative at Brent prices "well-below" $30/b, according to
the study."
So why are so many producers struggling and/or going broke?
That $30 to $35 mark must be well-head costs of production without overheads?
The present ND price is $16.50 for one thing. The analysis is for operating fields and does not
include exploration or new developments, without which oil companies would have a short lifetime.
I think they are only including OPEX or what I call LOE.
As I have mentioned previously, these expenses typically include only the electricity or other
power costs to operate the wells, the chemicals used on a regular basis down hole, minor repairs,
and direct lease labor. At least that is the way the shale guys report it. Otherwise, why do they
always report $4-$8 per BOE in company reports, yet I see much higher than that on the lease operating
statements sent to non-operated working interest owners for interests for sale on the auction?
I have my doubts as to whether they are including in OPEX finding and development costs, including
the costs to lease the land, permit the well, drill the well, complete the well, equip the well,
any subsequent equipment that is capitalized and not expensed, including replacement of tubulars,
rods, down hole pumps, etc. over the life of the well, both ordinary work overs such as repair
of tubing leaks and replacement of down hole pumps, as well as work overs such as sand pumping,
acid, re-perforation, re-fracking, all transportation costs, all general and administrative expenses,
all severance, extraction, production, income, ad valorem, etc. taxes, and interest payments on
debt.
In the real oilfield, not the one displayed by the shale cos. in their Urban skyscrapers, what
is most important is what goes in the checkbook, what goes out of the checkbook and the current
balance in the checkbook. Classifying a rod job as CAPEX does not change the fact that a check
has to be written within 30 days (apparently 180+ days for shale) to the contract company who
pulled the pump.
Due to the skyrocketing of costs in the industry from 2005-2014, I believe this crash is more
severe than 1998-1999, despite Brent and WTI oil prices not quite falling to the inflation adjusted
lows of that period, as well as the fact the basis spreads are much wider for certain crudes (think
Bakken, Western Canadian Select, etc.) than they were in that era.
We are suffering much more than in 1998-1999 for sure, on the very same leases. The combination
of cost inflation, reserves that are tougher to produce, and in the case of marginal producers
like us, natural decline, makes dropping into the $20s (or below) brutal.
The vast majority of US publicly traded E & P have PDP PV10 reserve values LESS than long term
debt at $50 WTI. At least I suspect the 10K will show that in the next 15-45 days as they are
released.
Keep in mind we have been hovering around $30 WTI in 2016, after hovering around $40 WTI since
last fall. I imagine PDP PV10 is less than half at $30 WTI as opposed to $50 WTI. I further suspect
that PUD PV10 in almost non-existent in the US onshore lower 48 fields at $30 WTI.
Remember that reserve based lending standards typically do not allow for a borrowing base in
excess of 65% of PDP PV10 (recently PV9 due to historically low interest rates). This includes
not only first lien bank debt, but any other types of second lien or junior debt.
Therefore, at $50 WTI, almost all US onshore based E & P DO NOT qualify for reserve based credit
with US banks. And we are at $30 and change today.
In reality, any equity value these companies have is purely a bet that the current WTI and
HH futures will not hold, but will go substantially higher in the near future (yet this year).
I know I and others have been beating this drum for a long time, but dang it the truth has
to be said. Just because 1% of wells in the Sprayberry Wolfcamp play in Midland Co., TX are worth
drilling and completing at $30 WTI does negate the fact that the entire industry is in jeopardy
without a significant price spike.
I would really like to know how much industry debt to banks is delinquent. I bet there is still
a lot of pretending going on by the banks with regard to provisioning energy loan losses.
Make no mistake about it, this has been a price crash of epic proportions.
"I think they are only including OPEX or what I call LOE. "
Woodmac mentions cash operating costs, not full-cycle costs
Cash operating costs include not only LOE, but also taxes, G&A.
Not sure if they include interest expense.
As regards LTO full cycle costs:
"full life cycle economics require an oil price in the range of $40-$60," Wood Mackenzie said.
AlexS. They may include taxes and interest, but I bet a lot of costs that are necessary to keep
the lease producing are put in CAPEX and not included.
For example, I look at a lot of LOS for shale wells.
LOE runs $10-20K routinely per well in the Williston Basin, with newer wells tending to be
more costly due to higher produced water disposal costs.
Invariably, however, there will be a monthly LOS with an extraordinary charge, some times in
excess of 5 times the routine monthly LOE. Sometimes it is not readily apparent what these charges
are for. Sometimes they are routine work overs, pump changes, tubing leaks. In any event, I believe
at least some of these costs are being capitalized. Anything permissible to reduce the per BOE
cost of LOE in company reports will be taken advantage of, and likely even required by GAAP, and
reported differently for income tax purposes.
It appears ND is granting operators the ability to idle wells producing 40 bopd or less for
up to 24 months.
Based on Enno Peters shale profile website, it is apparent many wells fall below 40 bopd within
60 months of first production. I suspect most wells under 40 gross bopd in the Williston Basin
cost $25 per BOE+ to keep online. Given the differential to WTI in that basin, I suspect they
generally are in the negative at current prices.
Regardless, if a 3-4 million bopd cut were announced by Russia and OPEC, I suspect prices would
rally significantly. So even if Wood Mac is including all the necessary expenses to keep production
online, 3-4 million bopd underwater is a big deal.
"The vast majority of US publicly traded E & P have PDP PV10 reserve values LESS than long term
debt at $50 WTI."
SS,
It is no different in District XI aka Canada :-)
And how many loans are created in consumer/real estate economy based on oil being $100
where was incentive to provide enough liquids at that price for our endless car circling that
we call GDP. That debt is no different than E&P debt and will be crashing down at same time.
Thank you, Ron, for this update. Assuming Bakken decline follows Bruno Verwimp's predicted curve
we are going to see an increase in the rate of fall over coming months. Noting that the model
is Hubbert, seasonally adjusted, implies that it is price insensitive; we shall see.
This will focus minds on the reality of the Red Queen and, to use another fairy tale analogy,
demonstrate that the Emperor has few clothes.
I read an article on Bloomberg a couple of days ago, saying that if oil gets to $50/bbl, that
the US oil companies will sell forward contracts and flood the market with oil.
I hope that Ron comments on this. But, I see some problems. The first problem is that the average
oil company has PROVED [with $100's billion of write-offs and worthless junk bonds] that they
cannot make a profit at $49 oil [2015 PV-10].
The second problem is: Suppose, at $50 oil, a company could sell forward 2 years of production
at $55. They cannot. Why not? Because they have no collateral. All of their assets are pledged
to existing loans. Why do they need collateral? Because, what if the price rises – to let's say
to $85. In that hypothetical, they need $30/bbl of margin CASH. I believe that Ron will confirm
that you HAVE to make margin calls within 24 hours or your position is sold out.
Well, how did companies like Chesapeake Energy do it. Well, at the time [several years ago],
they had enough reserves that were not pledged on any loans, even though they were highly leveraged.
So they pledged that collateral to, like Goldman Sachs, to cover any margin calls. So GS would
put up the margin calls, if needed.
Today is different. Most to these companies do not have any unpledged collateral. So, it is
a catch 22. They will not be able to sell forward contracts.
The the nine hundred forty five wells awaiting completion is in ND is probably an accurate number,
plus or minus maybe a couple of dozen, depending on how up to date the data is.
I read somewhere a couple of days ago that there are about four thousand wells awaiting completion,
in total, in the USA.
"... I am not going to mention any names publically but I know of one operator based in Midland in the Wolfcamp Bone Spring plays whose bankers are making him liquidate his acreage position. They loaned the operator $300 million for acreage and it is doubtful in my mind that they will recoup 1/2 of the cost. ..."
I am not going to mention any names publically but I know of one operator based in Midland
in the Wolfcamp & Bone Spring plays whose bankers are making him liquidate his acreage position.
They loaned the operator $300 million for acreage and it is doubtful in my mind that they will
recoup 1/2 of the cost.
Also, a lot of acreage is probably going to be surrendered this year in the Permian.
[Feb 17, 2016] Fracking wastewater causes cancer
Notable quotes:
"... fracking wastewater causes cancer. ..."
"... Using human bronchial epithelial cells, which are commonly used to measure the carcinogenesis of toxicants, researchers confirmed fracking flowback water from the Marcellus Shale caused the formation of malignancies. ..."
Additional buried costs of Unconventional extraction are surfacing. Fracking and production liquids
are live costs – how often is liquids disposal cost breaken out for the life of the well?
"Though fracking industry proponents scoff at any intimation their so-called vital industry
poses even scant risks to the public, a new study published in Toxicology and Applied Pharmacology
just proved those critics right - fracking wastewater causes cancer.
"... LOE runs $10-20K routinely per well in the Williston Basin, with newer wells tending to be more costly due to higher produced water disposal costs. ..."
"... I suspect most wells under 40 gross bopd in the Williston Basin cost $25 per BOE+ to keep online. Given the differential to WTI in that basin, I suspect they generally are in the negative at current prices. ..."
"... in any case, if the current wellhead price in the Bakken is $16.5, they are all in the red (ex hedges) ..."
AlexS. They may include taxes and interest, but I bet a lot of costs that are necessary to keep
the lease producing are put in CAPEX and not included.
For example, I look at a lot of LOS for shale wells.
LOE runs $10-20K routinely per well in the Williston Basin, with newer wells tending to be
more costly due to higher produced water disposal costs.
Invariably, however, there will be a monthly LOS with an extraordinary charge, some times in
excess of 5 times the routine monthly LOE. Sometimes it is not readily apparent what these charges
are for. Sometimes they are routine work overs, pump changes, tubing leaks. In any event, I believe
at least some of these costs are being capitalized. Anything permissible to reduce the per BOE
cost of LOE in company reports will be taken advantage of, and likely even required by GAAP, and
reported differently for income tax purposes.
It appears ND is granting operators the ability to idle wells producing 40 bopd or less for
up to 24 months.
Based on Enno Peters shale profile website, it is apparent many wells fall below 40 bopd within
60 months of first production. I suspect most wells under 40 gross bopd in the Williston Basin
cost $25 per BOE+ to keep online. Given the differential to WTI in that basin, I suspect they
generally are in the negative at current prices.
Regardless, if a 3-4 million bopd cut were announced by Russia and OPEC, I suspect prices would
rally significantly. So even if Wood Mac is including all the necessary expenses to keep production
online, 3-4 million bopd underwater is a big deal.
"... At least I understand for the coming year we agree. Down down down. Prices may (and will) rise again. But I do not see another 27k wells being drilled in that North Dakota landscape. Just look at it on Google Maps. There are wells everywhere! ..."
"... Where are the North Dakotans going to drill 27k new wells? The USGS is an important institution, but I believe they overestimate Bakken URR greatly. ..."
"... There are currently 10,756 producing unconventional Bakken–Three forks wells. Even including the shut-in wells, the total number of drilled Bakken-TF wells unlikely exceeds 12-13 k. ..."
"... So the number of potential well locations is still high. Many of them are outside the sweet spots, but if and when oil prices rebound, a large part of potential B-TF wells may be economically viable. ..."
Nice to meet you again, Dennis! I was waiting for you. :-) The future will tell who had the best
idea. Reality may turn out to be something in between our ideas.
At least I understand for the
coming year we agree. Down down down. Prices may (and will) rise again. But I do not see another
27k wells being drilled in that North Dakota landscape. Just look at it on Google Maps. There
are wells everywhere!
Where are the North Dakotans going to drill 27k new wells? The USGS is an
important institution, but I believe they overestimate Bakken URR greatly.
There are currently 10,756 producing unconventional Bakken–Three forks wells. Even including
the shut-in wells, the total number of drilled Bakken-TF wells unlikely exceeds 12-13 k.
So the number of potential well locations is still high. Many of them are outside the sweet spots, but if and when oil prices rebound, a large part
of potential B-TF wells may be economically viable.
A record-breaking 5.1-magnitude earthquake struck Oklahoma early Saturday morning
… … …
"We have no reports of damage as of yet, but we did get a good rock n' roll," Cheryl Landis
with the Major County Sheriff's Department tells CNN.
The earthquake occurred at 12:07 a.m. (1:07 a.m. Friday ET) at a depth of 1 kilometer, the
USGS said.
A 3.9 magnitude earthquake around11:17 a.m., a 2.5 around 11:40 a.m. and a 3.5 around 12:21
p.m. were also recorded in the same area, according to KFOR.
This is the strongest quake to rattle the state since 2011, the Survey says.
… … …
The USGS says waste water injected into deep geologic formations is a likely contributing
factor to the seismic activity increase. This method of retrieving oil and natural gas is known
as hydraulic fracturing, or fracking.
Fracking water in OK is pristine compared to the brine that comes up with the oil production.
Further, most new wells in OK will produce more brine wastewater in their first 30 days of oil
production [not counting the frac water] than the total amount of frac water retrieved.
"... All the three bubbles of the last decade – internet bubble, housing bubble and now the shale bubble – reflect deeply the American approach how to respond to challenges in the economy and society: It is better to ask for forgiveness than to ask for permission. ..."
"... The lesson for investors is to recognize and understand the thinking behind Wall Street's motivation and adjust the investment strategy accordingly. As the bond collapse is far from over, we have not yet seen the bottom of the production decline. The bond market is the major driver of oil and gas production. Any forecast which ignores changes of capital markets is very likely irrelevant. ..."
"... Yes, access to cheap money (not only bonds, but also bank loans) was one of the key factors that contributed to the shale boom. ..."
"... we will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat. ..."
"... I agree if you are talking about the money the bankers and investors already have invested in shale. But the bankers and investors will not likely be looking for ways to lose more money. New investment in shale will be difficult to come by. ..."
"... Nationalize it and this annoying little issue of profit pursuit disappears. ..."
"... US banks were not "nationalized" during the 2008-2009 crisis. I very much doubt the gov't will nationalize the Oil industry, unless there is a very drastic event that cause the price to skyrocket suddenly (ie above $200). A KSA/Iran hot war would probably do that. ..."
"... Collapsing Oil prices is just a symptom of a mounting global economic crisis. Even if the US nationalized its Oil industry it still not going to fix problems overseas: The Middle East, China and Europe. ..."
"... The period of kicking the can with ease has reached its end. ..."
"... Maybe they start investor focused campaign "World is running out of oil" meme :-) LOL … similar to "We are running out of land" meme during Housing bubble :-) Just kidding. :-) ..."
An analyst on CNBC had an interesting quote, which he attributed to John D. Rockefeller, to-wit,
there has been more money lost to the ill advised search for yield, than in all of the bank robberies
in recorded history.
All the three bubbles of the last decade – internet bubble, housing bubble and now the shale
bubble – reflect deeply the American approach how to respond to challenges in the economy and
society: It is better to ask for forgiveness than to ask for permission. Greenspan famously said when the internet bubble burst: You can only recognize a bubble when
the bubble has burst. This approach has probably avoided also some damage ( for instance an escalating oil price
surge), yet has also done some huge damage to investors.
The lesson for investors is to recognize and understand the thinking behind Wall Street's motivation
and adjust the investment strategy accordingly. As the bond collapse is far from over, we have
not yet seen the bottom of the production decline. The bond market is the major driver of oil
and gas production. Any forecast which ignores changes of capital markets is very likely irrelevant.
Yes, access to cheap money (not only bonds, but also bank loans) was one of the key factors
that contributed to the shale boom.
As regards the 'black swan' event on the downside of production, we will see which financial
tricks the shale guys, their bankers and investors will invent to keep shale production afloat.
we will see which financial tricks the shale guys, their bankers and investors will invent
to keep shale production afloat.
I agree if you are talking about the money the bankers and investors already have invested
in shale. But the bankers and investors will not likely be looking for ways to lose more money.
New investment in shale will be difficult to come by.
"Nationalize it and this annoying little issue of profit pursuit disappears."
US banks were not "nationalized" during the 2008-2009 crisis. I very much doubt the gov't will
nationalize the Oil industry, unless there is a very drastic event that cause the price to skyrocket
suddenly (ie above $200). A KSA/Iran hot war would probably do that.
Collapsing Oil prices is just a symptom of a mounting global economic crisis. Even if the US
nationalized its Oil industry it still not going to fix problems overseas: The Middle East, China
and Europe.
The period of kicking the can with ease has reached its end. Now the World's gov't will need
to resort to ever increasing drastic actions to avoid a global depression.
"we will see which financial tricks the shale guys, their bankers and investors will invent to
keep shale production afloat."
Maybe they start investor focused campaign "World is running out of oil" meme
:-) LOL
… similar to "We are running out of land" meme during Housing bubble
:-)
Just kidding.
:-)
"... The price of shale oil on the US market has fallen by two-thirds while production by 15 percent,
according to the head of Russia's Rosneft Igor Sechin. "Shale oil production in the United States will
decline in the long-term and reach bottom by 2020," Sechin said . ..."
The price of shale oil on the US market has fallen by two-thirds while production by
15 percent, according to the head of Russia's Rosneft Igor Sechin. "Shale oil production in
the United States will decline in the long-term and reach bottom by 2020," Sechin said .
"... The price of oil is unstable right now; it can stand at $40 a barrel today and reach $80 a
barrel tomorrow… ..."
"... "Shale oil production in the United States will decline in the long-term and reach bottom by
2020," Sechin said. ..."
"... About 17,000 oil and gas workers in the US lost their jobs in 2015. ..."
"... When adding the oilfield support jobs lost in refineries and petrochemical plants, the actual
number of related layoffs grew to about 87,000, according to Michael Planet, an economist at the Dallas
Fed. ..."
"The price of oil is unstable right now; it can stand at $40 a barrel today and reach $80
a barrel tomorrow…," said Total's CEO.
The price of shale oil on the US market has fallen by two-thirds while production by 15 percent,
according to the head of Russia's Rosneft Igor Sechin. "Shale oil production in the United States
will decline in the long-term and reach bottom by 2020," Sechin said.
Falling oil prices have reduced the profitability of oil extraction which impacts drilling activity.
In the early part of last year, the US rig count was down 850 from the year before. About 17,000
oil and gas workers in the US lost their jobs in 2015.
When adding the oilfield support jobs lost in refineries and petrochemical plants, the actual
number of related layoffs grew to about 87,000, according to Michael Planet, an economist at the
Dallas Fed.
US oil and gas producers are expected to announce 2015 losses totaling over $15 billion, according
to Bloomberg analysis earlier this month. Companies have already announced huge earnings losses,
output and spending cuts.
Jacques Jacobs
Companies in the US complained that they could not effectively recruit enough people to move
to North Dakota to work in the oil industry, but many did, and bought homes, now they get laid
off and many are getting foreclosed on going into bankruptcy.
Foghorn returns
This is the only the beginning, just wait until the banksters racket starts to unravel. The
situation is a lot worse for copper. Its so bad that copper has now become a precious metal. For
real you can buy copper coins and save them in your cellar for when the whole bankster racket
falls apart.
"... UAE/OPEC cut rumor hits, DOW reverses over 250 points and oil bounces $1. Just one rumor affects
billions or trillions of market value. One question, is OPEC or US calling the shots? ..."
"... Yes. I know that. Just seeing violent moves in oil and stock market based on a one sentence
rumor can get the conspiracy juices flowing. Couple that with going from $102 to $21 in 21 months! LOL!
..."
"... Wow, the volatility Ive experienced since 1997. $18 to $8 to $140 to $26 to $105 to $21 today.
Quadrupling of costs from 1997 to 2014 and then a roughly 20% reduction from 2014 to now on service
and equipment. ..."
"... Clearly makes one question the wisdom of being invested in this sector. But .5% CDs are pretty
boring. LOL!! ..."
UAE/OPEC cut rumor hits, DOW reverses over 250 points and oil bounces $1. Just one rumor affects
billions or trillions of market value. One question, is OPEC or US calling the shots?
Sorry Ron, it was a conspiracy theory post, which I know you dislike and which I shouldn't jest
about.
Thought crossed my mind, oil tanks, stocks are very correlated to oil, so those markets tank.
Oil and gas price at these low levels are not helping, instead seem to be hurting US economy.
Does the US have enough sway with Gulf OPEC, due to military protection provided to require
them to cut production and/or not cut production?
Not a problem Shallow. I think you really know that someone in the State Department, or wherever,
could not call up the King of Saudi Arabia and tell him to cut production by a million barrels
per day. But it's fun to entertain such fantasies once in a while.
Yes. I know that. Just seeing violent moves in oil and stock market based on a one sentence
rumor can get the conspiracy juices flowing. Couple that with going from $102 to $21 in 21 months!
LOL!
It is noteworthy how much oil price seems to be on the front page. Go back and look at historical
oil prices. Nothing quite like this since 1930s.
Wow, the volatility I've experienced since 1997. $18 to $8 to $140 to $26 to $105 to $21
today. Quadrupling of costs from 1997 to 2014 and then a roughly 20% reduction from 2014 to now
on service and equipment.
Clearly makes one question the wisdom of being invested in this sector. But .5% CD's are
pretty boring. LOL!!
Thanks again for all of your work on this blog Ron. I appreciate it. I'll try not to do the
crazy talk. Oh how I'd love to be a fly on the wall when OPEC meets. I'd also love to be a fly
on the wall when the shale honchos talk turkey about what the heck they are going to do.
Seems to me that we are approaching a zero US rig count, or at least approaching a zero oil rig
count.
In any case, I previously noted, if we define the duration of the 2008 oil price decline as
the number of months below $100, until we saw a sustained oil price recovery, the slump only lasted
four months in 2008. But it took about two years for the US rig count to get back to the pre-decline
levels, with the benefit of easy financing.
Using the same oil price decline metric, we are at 17 months at counting, and easy financing
has presumably gone bye-bye.
Meanwhile, as I noted up the thread, US liquids consumption hit a seven year high last year,
and the US is becoming increasingly dependent on net crude oil imports:
... The top dogs in the oilfield services patch-Schlumberger and Halliburton-paint an even more
dismal picture.
In late January, Schlumberger (NYSE:SLB) cut 10,000 jobs after reporting losses of $1.02 billion,
with a 38 percent contraction in revenue from its peak in the third quarter of 2014 to the fourth
quarter of 2015.
As recently as 2014, Schlumberger had posted profits of $302 million, but has since fallen around
44 percent over the past year and a half. In just this past year, Schlumberger reported a 27 percent
fall in revenues, and a 39 percent drop in the fourth quarter alone.
January's job cuts bring Schlumberger's total job cuts up to 34,000-or 26 percent of its workforce-since
the third quarter of 2014. That tops Weatherford's 14 percent workforce loss.
The No. 2 player in this patch, Halliburton (NYSE:HAL), has laid off some 22,000 workers, or 25
percent of its global workforce. The most recent cuts came in the last week of January, when the
company announced it had cut an additional 4,000 jobs coming off fourth quarter 2015 reports showing
a net income loss of $28 million for the quarter, or 79 cents per share for the full year.
"The brutality and length of this down cycle has challenged the entire industry, both our customer
base as well as our peers," Weatherford's top executive Bernard J. Duroc-Danner said in a statement.
The first wave of energy industry job cuts came in January 2015, from the producers. This January
was the culmination of the snowball effect that has reached the oilfield services segment-and none
is immune, with Weatherford's story par for the course and no better or worse than its peers. This
year will be darkest for oil services because the bottom hit its customers first.
Shale economics have significantly changed over the last two years to worse
as depletion never sleeps
Notable quotes:
"... In my view shale economics have significantly changed over the last two
years. The monthly decline rate (see below chart) reached in the Eagle Ford oil
basin nearly 12%. ..."
"... Legacy decline is close to 150 kb/d and month since a few months now and
production is declining and currently stands at around 1.2 mill b/d. The above decline
rate is legacy decline divided by actual production. ..."
"... Of course the actual decline is lower as there is also production from
new wells, yet my chart shows the internal decline which has to be replaced by companies
and is just an indicator how fast the Red Queen has to run. ..."
"... It is in my view exactly the increasing demand for capital to keep oil
and gas production stable, which weakens the bond market, which then spills over
to the economy and stock market. As companies did not want to curb production voluntarily,
they are forced now to do so over a collapsing bond market. ..."
"... The real wall is when it takes 1 unit of energy to get 1 unit of energy
out. Ehh – no – that cant be. What equipment would they use to get that out? So
we need a functioning steel industry. We actually need a bit more than that. An
oil platform incorporates pretty much everything modern in this world, engines and
motors of all kinds. Computers. And we might want to get to the platform. So we
need some helicopters. A complicated machine. ..."
"... Depletion never sleeps. ..."
"... The 10% decline rate without continuous infill drilling is particularly
worrying. Mostly infill drilling accelerates production but does little for overall
capture (sometimes a bit of increase in recovery, but sometimes it can have the
opposite effect) so the more they are used the more the decline rate will increase
after the peak. I know the 10% figure is for offshore fields but a) this is not
encouraging for the prospects of deepwater development b) there have been recent
large infill drilling programs in Russia and ME – if the result is that their declines
tend towards 10% rather than 2 or 3 in the near term then look out. ..."
"... The export issue is also relevant to consider. Say a 10% reduction in production
would likely be a 20% reduction in export availability (maybe a bit more because
of EROI issues and growing domestic use, especially if wars and social unrest escalate)
– which would crush most European and a good few developing countries economies
even if they were looking reasonably healthy, which they obviously arent, and without
the ever increasing waves of refugees coming their way. ..."
In my view shale economics have significantly changed over the last
two years. The monthly decline rate (see below chart) reached in the Eagle
Ford oil basin nearly 12%.
Although Marcellus has somewhat stabilized and Utica, which is still
in its infancy, even improved, it is in my opinion just a matter of time
when decline rates increase for all shale plays.
This trend has not been baked into many economic and forecasting models
– quietly assuming constant decline rates – and comes now as a surprise
for many analysts and investors.
It comes from the EIA drilling report. Legacy decline is close to
150 kb/d and month since a few months now and production is declining and
currently stands at around 1.2 mill b/d. The above decline rate is legacy
decline divided by actual production.
Of course the actual decline is lower as there is also production
from new wells, yet my chart shows the internal decline which has to be
replaced by companies and is just an indicator how fast the 'Red Queen'
has to run.
It is in my view exactly the increasing demand for capital to keep
oil and gas production stable, which weakens the bond market, which then
spills over to the economy and stock market. As companies did not want to
curb production voluntarily, they are forced now to do so over a collapsing
bond market.
As Eagle Ford is one of the most mature plays, it serves in my opinion
as a blueprint for more recently started basins such as Marcellus and Utica.
Interested in this, as North Dakota's decline rate stalled (i.e. many years
stopped declining all together, or even grew) in October and November as
operators opened the chokes on their old wells.
This was completely predictable; I just didn't think it would slow down
by 2015/2016…I thought the head of steam might have lasted till ~ 2018-2021
or so.
Will the boom times come roaring back, bigger and crazier than ever?
None of us know.
What we do know: The Earth is finite, the amount of FFs in the ground
is finite, and depletion never sleeps, and the distribution of FF deposits
(size, frequency) seems to follow the power law…and the cost to raise each
bbl of oil and mcf of methane and ton of coal will continue to rise.
Barring a breakthrough which produces inexpensive, compact, ubiquitous
'Mr. Fusion' power reactors, the outlook looks bleak. Even with a 'Mr. Fusion'
breakthrough, other source and sink limits would end up eating humanity's
lunch if population increase was no slowed, stopped, and reversed at some
point, and the seemingly endless increase in per capita consumption slowed
and then reversed as well. But a 'Mr. Fusion' breakthrough would sure give
us some breathing room to mature as a species and figure out how to bring
our existence into some kind longer-term sustainable future, one in which
we do not exterminate many of the other species on Earth.
I would bet that Ron's "lead pipe cinch" prognosis will turn out to be
correct.
As grim as the depletion curves from Campbell et al looked like, those were
best case scenarios.
The real wall is when it takes 1 unit of energy to get 1 unit of
energy out. Ehh – no – that can't be. What equipment would they use to get
that out? So we need a functioning steel industry. We actually need a bit
more than that. An oil platform incorporates pretty much everything modern
in this world, engines and motors of all kinds. Computers. And we might
want to get to the platform. So we need some helicopters. A complicated
machine.
And even if we have all of that, we still done have any energy left for
the rest of the economy.
"As grim as the depletion curves from Campbell et al looked like, those
were best case scenarios."
That was pretty much my thought as well. This is one of the more depressing
posts here. I've been thinking we'd muddle through for a good few more years
even as oil depleted but if these figures are born out I'm not so sure.
The 10% decline rate without continuous infill drilling is particularly
worrying. Mostly infill drilling accelerates production but does little
for overall capture (sometimes a bit of increase in recovery, but sometimes
it can have the opposite effect) so the more they are used the more the
decline rate will increase after the peak. I know the 10% figure is for
offshore fields but a) this is not encouraging for the prospects of deepwater
development b) there have been recent large infill drilling programs in
Russia and ME – if the result is that their declines tend towards 10% rather
than 2 or 3 in the near term then look out.
In addition for the ME – I cannot see how the ruling regimes can be maintained
once serious decline sets in and is recognised as such by the populace (i.e.
that there will be no recovery). As the cradle to grave social programs
have to be continuously cut then there must be some kind of uprising, which
you'd expect would lead to significant, and maybe permanent, disruption
of production (and therefore less overall recovery).
The export issue is also relevant to consider. Say a 10% reduction
in production would likely be a 20% reduction in export availability (maybe
a bit more because of EROI issues and growing domestic use, especially if
wars and social unrest escalate) – which would crush most European and a
good few developing countries' economies even if they were looking reasonably
healthy, which they obviously aren't, and without the ever increasing waves
of refugees coming their way.
Signs of troubles for the USA natural gas production. This is a larger player and if it is in trouble
the whole US shale gas industry is in trouble too.
Notable quotes:
"... Keep oil at $30 and gas at $2 through summer and there will be a very long list of these. ..."
"... Note how the Dow/S P continues to trade lockstep with crude. ..."
"... Not until the executives have configured themselves to the extent possible within insider trading regs. After that, maybe theyll have plans . ..."
"... A total of 74 energy companies, including Energy XXI Gulf Coast Inc. and Halcon Resources Corp., are expected to have significant difficulties sustaining their debt, according to the report. ..."
"... BTW, Halcon is down 12.8% today, 67.5% year-to-date, and 96% in one year. ..."
The number of U.S. companies that have the highest risk of defaulting on their debt is nearing
a peak not seen since the height of the financial crisis.
With the energy industry crumbling amid record low oil prices, the number of companies with the
lowest credit ratings reached 264 as of Feb. 1, just shy of the high of 291 set in April 2009,
according to a report by Moody's Investors Service Wednesday. That's a 44 percent jump in the
past 12 months, Moody's said.
"The majority of new additions came from oil & gas ….
A total of 74 energy companies, including Energy XXI Gulf Coast Inc. and Halcon Resources
Corp., are expected to have significant difficulties sustaining their debt, according to the report."
BTW, Halcon is down 12.8% today, 67.5% year-to-date, and 96% in one year.
Roughly eight years ago, at the peak of the last recession, oil drilling began to transform these
remote corners of the plains into an economic beacon, attracting billions of dollars in new investments
and thousands of workers in search of good-paying jobs and an escape from America's economic pain.
But now, as oil prices have skidded to $30 a barrel, new drilling has dried up here, and the flood
of wealth and workers is ebbing.
... ... ...
It is hardly a bust - unemployment is low, and there are still plenty of help-wanted ads for the
area - but the slowdown opens an uncertain second chapter for a place that has spent heavily on new
roads, schools, hotels and developments over the past five years.
"We're overbuilt," said Marcus Jundt, a businessman who followed the boom to Williston and owns
several restaurants here, including the Williston Brewing Company, the place that serves the rib-eyes
and brownies. "We have too many hotel rooms, too many apartments, too many restaurants. People are
going to go broke. People are going to lose their jobs. It's going to be painful."
The slowdown has hammered governments across North Dakota, forcing some to cut spending or dip
into reserves. Williston expects $151 million in revenue this year, down about 23 percent from two
years ago. Real estate prices have come down, giving a welcome break to many renters, but agents
say there is a glut of about 300 to 400 homes for sale, with more being built. At the State Capitol,
Gov. Jack Dalrymple last Monday ordered 4 percent budget cuts and tapped $497 million from a rainy-day
fund to close a $1 billion budget shortfall.
Rural towns that spent the past years building, spending and taking on debt are now facing grim realities.
Williston, for one, has taken on $215 million in debt, and governments around the region are spending
to build infrastructure, including a sewer plant and recreation center for the growing population.
Some local officials, business owners and academics express optimism, saying the economy here
is taking a breather after years of unsustainable growth.
"Those communities out there were drinking out of a fire hose," said Nancy Hodur, a research assistant
professor at North Dakota State University who has been studying the boom. "A lot of those communities
would come right out and say that pace of growth isn't good, isn't sustainable. They're still playing
catch-up."
Local leaders say they have faith that oil will rebound and fuel decades of economic opportunity.
As evidence, they point to rising school enrollments across the Bakken oil patch and rising population
numbers statewide. New neighborhoods are filling up with full-time residents, recent arrivals who
seem to represent a vote of confidence in the staying power of an oil-based economy that also offers
a paradise for hunters and anglers.
... ... ...
North Dakota's unemployment rate is still an enviable 2.7 percent, and the jobless rate is even
lower here in Williams County - 2.2 percent, up a percentage point from a year ago.
... ... ...
They talked about how many drilling rigs were operating (46 across the state, compared with 190
two years ago), their falling overtime pay and friends who had gone elsewhere for work.
"If you get fired tomorrow, you get fired," said Scott Benson, 32, an electrical worker who was
heading out to make sure compressor parts did not freeze over in the bitter cold. "Just calm down
and go to work."
"... At peak levels in 2014 total North American E P spending was about $200bn, but this included Canada and US conventional ..."
"... If we look at the increases in yearly average output in 2014 and 2015, it was 1250 kb/d vs 730 kb/d. So decreased investment of $70 B, reduced the production gain by about 520 kb/d. ..."
"... In any case, somewhere between 96B and 132B is enough to get flat output in the US (replacing about 500 kb/d of decline at a 6% annual rate or 920 kb/d if we assume a 10% annual decline rate). ..."
"... Under most plausible oil price scenarios, 2018 US production may be flat or only slightly above 2017, and growth in 2019 will still be moderate. I now think that 2015 record level of (9.7 mb/d in April) may not be reached even in 2020. However, with higher prices, peak levels could be achieved in the next decade. ..."
"... What you consistently fail to realize is that the EIAs DPR gives a very bad estimate of legacy decline. As fewer new wells are added the legacy decline gets smaller. ..."
"... The EIAs estimate for legacy decline in the Bakken and Eagle Ford are incorrect. For the Bakken/Three Forks the legacy decline in Nov 2015 was 4 kb/d and if the rate that new wells are added remains at the Nov 2015 level the legacy decline rate falls to an average rate of 3 kb/d for Dec 2015 to Nov 2016, output only falls by 140 kb/d in this scenario. ..."
"... If no new wells are added over the next 12 months output in the North Dakota Bakken/Three Forks only falls by 350 kb/d. ..."
The decline and legacy rates are huge for shale. According to the latest drilling report, the
monthly legacy rate for all shale plays has reached nearly 400 000 b/d and month, which is annualized
over 4 mill b/d of decline. Add the legacy rate for shale natural gas, which is nearly 20 bcf/d
and year.
Together with conventional oil and gas, the US oil and gas industry has to replace every year
close to 10 mill boe/d which is 50% of capacity of oil and gas production.
And the situation gets worse every year. The decline rate for worldwide conventional oil production
is just 6%.
The cost for 1 mill b/d (either buying from the shelf or building from scratch) stands around
USD 50 bn. So the US oil and gas industry has to invest every year USD 500 bn for keeping production
stable – and gets just 250 bn revenue for this investment.
This is a financing gap of USD 250 bn every year. As the total high yield bond market adds
up to USD 1500 bn, the oil industry taps 17% of the high yield bond market.
I think this explains the high the leverage in the oil and gas market. The cost for keeping
the USD stable is now astronomical. Something has to give here. Either the dollar or the bond
market collapses or 3mill b/d come out of the market immediately.
If we look at the increases in yearly average output in 2014 and 2015, it was 1250 kb/d
vs 730 kb/d. So decreased investment of $70 B, reduced the production gain by about 520 kb/d.
The decreased investment of $45B less in 2016 vs 2015.would be expected to reduce the production
gain by 330 kb/d, so we could potentially see an increase in output of 400 kb/d (2016 average
output vs 2015 average output) if the investment spending estimates are correct and the previous
trend holds.
This simple linear model is not likely to be correct because if we assume zero investment spending
in 2016, the result is flat output, which is highly unlikely.
I would expect output will be flat at best with 96 billion investment and oil is likely to
be down by 500 to 700 kb/d.
In inherent problem with the way I have done this is investment in natural gas production has
been ignored. We don't have enough detail here to know how the investment was divided between
natural gas and oil, though we could divide it up based on gross revenue or some other metric.
In any case, somewhere between 96B and 132B is enough to get flat output in the US (replacing
about 500 kb/d of decline at a 6% annual rate or 920 kb/d if we assume a 10% annual decline rate).
1) It is important to note, that today's upstream capex will affect output levels about 6 months
from now. So high capex in 2014 resulted in relatively high production levels in 1H15.
But lower capex in 2015 will affect production in 2016, and even lower capex in 2016 will negatively
affect production in 2017.
2) Annual average growth in 2015 vs. 2014 reflects strong monthly growth in 2014.
Monthly output was declining since April 2015 and will continue to decline in 2016 and probably
for most of 2017. Furthermore, decline rates are likely to accelerate this year and may only moderate
in 2017.
The EIA expects annual average US C+C production in 2016 to be 0.7 mb/d lower than in 2015,
including a 0.8 mb/d y-o-y decline in Lower 48 onshore output.
They are projecting annual average decline of 270 kb/d for US C+C in 2017, including 380 kb/d
in Lower 48 onshore.
Even "shale optimists" like Goldman Sachs and Citi expect a decline of ~0.5 mb/d in 2016 (I do
not know their longer-term projections).
Under most plausible oil price scenarios, 2018 US production may be flat or only slightly
above 2017, and growth in 2019 will still be moderate. I now think that 2015 record level of (9.7
mb/d in April) may not be reached even in 2020. However, with higher prices, peak levels could
be achieved in the next decade.
I think the EIA may be too pessimistic. The annual decline rate trend for March to Nov 2015
is about 500 kb/d. (See chart). I think there will be some oil price rise by mid year (maybe to
$45/b) and that the decline rate will moderate towards the end of 2016 as oil prices rise further
(to over $60/b by Dec 2016). I think the average US C+C output levels will be about 400 kb/d less
in 2016 compared to average 2015 output levels.
See chart for trend (note the assumption of a linear trend which is likely to overstate the
decline).
This was 2014 when legacy declines were much lower (around 20%). I am talking about 2016, which
includes also the rest of this year (total legacy rate 50%). In addition shale represents close
to two thirds of the oil and gas market in 2016. This share has been much lower in 2014.
If the US oil and gas industry does not spend as much, production will decline accordingly.
I cannot emphasize enough how much shale has changed the dynamics of the oil market. It is important
to recognize the change in the markets and not rely on past numbers.
The Bakken and Eagle Ford Models do not rely on past numbers except as a check on the model
(the Bakken Model has actually been lower than actual output, the Eagle Ford has been a little
closer, but also on the low side).
Now I take a model which has matched actual output fairly well over time and assume well profiles
remain the same as the past two years and that the new wells are added at half the rate of recent
months (39 new wells per month rather than 78 new wells), a similar exercise is done for the Eagle
Ford.
Enno Peters work confirms what I have found for the Bakken (which is based on data gathered
from the NDIC by Enno Peters.)
What you consistently fail to realize is that the EIA's DPR gives a very bad estimate of
legacy decline. As fewer new wells are added the legacy decline gets smaller.
Think about it a moment, if 200 new wells per month are added, the legacy decline is high
and if 50 new wells per month are added the legacy decline will be lower (by roughly a factor
of 4), surely you can see this.
In the Bakken about 170 new wells per month were being added each month during 2012 to 2014,
lately only about 77 new wells have been added, so legacy decline will be smaller.
Bottom line, the DPR has Bakken legacy decline increasing and that is not correct, it will
decrease until the rate that new wells are added each month starts to increase.
The EIA's estimate for legacy decline in the Bakken and Eagle Ford are incorrect. For the
Bakken/Three Forks the legacy decline in Nov 2015 was 4 kb/d and if the rate that new wells are
added remains at the Nov 2015 level the legacy decline rate falls to an average rate of 3 kb/d
for Dec 2015 to Nov 2016, output only falls by 140 kb/d in this scenario.
If no new wells are added over the next 12 months output in the North Dakota Bakken/Three
Forks only falls by 350 kb/d. That scenario is not very likely.
If 39 new wells per month (half as many as Nov 2015) are added each month for the next 12 months
(somewhat plausible at low oil prices), ND Bakken/Three Forks output falls by 250 kb/d.
The Eagle Ford will fall a little more maybe 350 kb/d, the Permian is likely to be flat, the
rest of the US LTO might fall by 200 kb/d at most, so about 800 kb/d decline is about all we will
see for LTO decline over the next 12 months.
GOM output has been increasing lately so overall US C+C decline might be 700 kb/d from Dec
2015 to Nov 2016 (next 12 months of data).
As I have said before, your method for coming up with a 4 million barrel per day decline in
US output hits very wide of the mark, you are off by almost a factor of 6. Use the EIA's DPR at
your peril if you are an investor.
Breakeven production cost ("Lifting Costs") is not equal to positive "cash flow" as formally
production costs include only raw materials and labor. These are the costs incurred to operate
and maintain wells and related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of operating and maintaining
those wells
Production cost:
== quote ==
A cost incurred by a business when manufacturing a good or producing a service. Production
costs combine raw material and labor. To figure out the cost of production per unit, the cost
of production is divided by the number of units produced. A company that knows how much it
will cost to produce an item, or produce a service, will have a clearer picture of how to better
price the item or service and what will be the total cost to the company.
Cash flow:
== quote ==
Cash flow is the net amount of cash and cash-equivalents moving into and out of a business.
Positive cash flow indicates that a company's liquid assets are increasing, enabling it to
settle debts, reinvest in its business, return money to shareholders, pay expenses and provide
a buffer against future financial challenges. Negative cash flow indicates that a company's
liquid assets are decreasing. Net cash flow is distinguished from net income, which includes
accounts receivable and other items for which payment has not actually been received. Cash
flow is used to assess the quality of a company's income, that is, how liquid it is, which
can indicate whether the company is positioned to remain solvent.
== quote ==
In other words it was another artificially created bubble. Like in dot com book, there were
parallel technological breakthrough that enabled this bubble to inflate.
Notable quotes:
"... But your shale oil players were accumulating massive amounts of debt even before 2015. Which seems hard to understand with such economics. ..."
"... LTO production was growing very aggressively, therefore even with high oil prices, producers were outspending cash flow. This is how the mountain of debt was built, despite 2010-2014 strong oil prices. ..."
"... I think we get caught up in the idea that production in US is not falling as fast as expected, I know I do. However, if we look at the year over year change, it will likely approach 2 million bopd. Production grew 1.4 million bopd in 2014, and may have fallen as much as .6 million bopd in 2015. (Numbers off the top of my head, and 2015 is still yet to be determined). ..."
"... Also, the current price is extremely low, much lower than 2015. If this price holds for several months, look for continued decreases in production from many parts of the world. $10s and $20s is what most oil is selling for in the world at present. That is simply not economic is the majority of the producing areas of the world, and definitely not in North America, where the 2010-2014 production growth predominantly came from. ..."
"... The drillers havent been making money, they have all be losing/underwater. Even the bigs and nationals have been losing: they have been throwing away value for some useless numbers … numbers which are all borrowed. ..."
"... Producing nations are pumping like mad because they need the cashflow. They cannot make long term decisions to wait out a higher price. ..."
"... We are adding some 40-50 Million motor vehicles to the worlds fleet every year. There is a finite amount in the ground with ever increasing cost and decreasing Energy Return on Energy Invested. We also have declining net exports. ..."
How does the shale irr of 45% and payback of 2 years line up with the mountain of debt and
other info (aka bertman). Does not seem to make sense??
Ron Patterson, 02/07/2016 at 1:39 pm
Daniel, I think you missed the point. That was a year and a half ago, when it was expected
that the future price of oil, 2014 to 2020, would average about $90 a barrel. I thought I made
that clear. Things are totally different today. In fact, that chart was meant to show just how
much things have changed in a year and a half.
daniel, 02/07/2016 at 2:45 pm
Thanks Ron. I get that things are much worse now. But your shale oil players were
accumulating massive amounts of debt even before 2015. Which seems hard to understand with
such economics.
LTO production was growing very aggressively, therefore even with high oil prices, producers
were outspending cash flow. This is how the mountain of debt was built, despite 2010-2014 strong
oil prices.
I think we get caught up in the idea that production in US is not falling as fast as expected,
I know I do. However, if we look at the year over year change, it will likely approach 2 million
bopd. Production grew 1.4 million bopd in 2014, and may have fallen as much as .6 million bopd
in 2015. (Numbers off the top of my head, and 2015 is still yet to be determined).
Also, the current price is extremely low, much lower than 2015. If this price holds for several
months, look for continued decreases in production from many parts of the world. $10s and $20s
is what most oil is selling for in the world at present. That is simply not economic is the majority
of the producing areas of the world, and definitely not in North America, where the 2010-2014
production growth predominantly came from.
The drillers haven't been making money, they have all be losing/underwater.
Even the bigs and nationals have been losing: they have been throwing away value for some useless
'numbers' … numbers which are all borrowed.
Don't forget Jeffrey Brown: when you ask the price, you get the price of top sirloin, when you
ask the quantity you get the amount of meat. Not all oil sells for the price of Brent or WTI.
I would like to know how much oversupply or undersupply causes how much price change. Is a 5%
oversupply enough to get a price drop like this or is it 10%? And looking forward, how much would
a short supply of 10% mean in price hike?
We know that our civilization needs oil to function, in fact it exists because of oil. Much
of our consumption is inelastic. I think the current oversupply is relatively small. Producing
nations are pumping like mad because they need the cashflow. They cannot make long term decisions
to wait out a higher price.
We are adding some 40-50 Million motor vehicles to the world's fleet every year. There is a
finite amount in the ground with ever increasing cost and decreasing Energy Return on Energy Invested.
We also have declining net exports.
Ron, very interesting, thank you. Reading your conclusion, we then can expect that markets will
do all possible to cause the collapse of one or more countries. So, Oil production will peak,
while our economies (US and Europe) could not to.
Daniel, I think you missed the point. That was a year and a half ago, when it was expected that
the future price of oil, 2014 to 2020, would average about $90 a barrel. I thought I made that
clear. Things are totally different today. In fact, that chart was meant to show just how much
things have changed in a year and a half.
Thanks ron. I get that things are much worse now. But your shale oil players were accumulating
massive amounys of debt even before 2015. Which seems hard to understand with such economics.
The reason for the greatly different OE for the UK and Norway is simply due to geology. Although
they share the same basin and the reserves for each nation are very similar UK oil sits in many
fields and Norway's oil is concentrated in fewer large fields.
One thing is for damned sure. The oil biz must have been generating UNGODLY UNIMAGINABLE PROFITS
up until a year ago, if the figures Ron just posted are even ball park accurate.
Have they really been making that much money,as a percentage of revenues, even before taxes,
royalties, etc?
It has been my belief , as the result of reading this site, and the old TOD, etc, that it costs
a hell of a lot more than the figures listed, to produce oil, as a general thing.
We all know that tax lawyers and accountants can work miracles, and that the oil industry can
afford the best, but ………….?????
If the oil industry has TRULY been making this kind of money, how is it that oil stocks weren't
going up FAST?
My seat of the pants impression is that the production cost figures given are highly slanted
so as to make the industry look better during this downturn, and keep people for selling oil stocks,
etc.
Don't forget Jeffrey Brown: when you ask the price, you get the price of top sirloin, when you
ask the quantity you get the amount of meat. Not all oil sells for the price of Brent or WTI.
"... Rystad Energy's analysis makes a lot more sense, that the shale drillers were completing more than they drilled, to conserve current cash, then the often stated line saving DUCs for the future . Especially when the shale players are fighting for a future that may not exist for them. ..."
Data from Rystad Energy show the number of completed wells
have by far outpaced the number of wells spudded (drilled) since 4Q14. Indeed,
the number of well completions per month continued to increase several months
after the rig count started to drop off, peaking at more than 1,600 wells in
December 2014. The number of completions are still outpacing the number of new
wells drilled, and as a result, the number of uncompleted wells, or the
frack-log, has been cut down from its peak of around 4,600 wells hit at the end
of 2014 to around 3,700 wells currently.
This seems to make a total mockery of all the claims in the media, that they
were drilling cheaper wells, and saving them for future production, with an
ever increasing number of DUCs.
Rystad Energy's analysis makes a lot more sense, that the shale drillers were
completing more than they drilled, to conserve current cash, then the often
stated line saving DUCs for the future . Especially when the shale players are
fighting for a future that may not exist for them.
"... Have heard from someone who I believe knows better than the Bloomberg writer that "there are likely little to no Wolfbone wells in Reeves country that are even close to being economic at $45 dollar oil." ..."
"... I'm ready to give up. If the massive losses experienced in 2015 do not make believers out of anyone, neither will the upcoming even greater 2016 losses. ..."
"... Funny how we get this Bloomberg report at the same time both oxy and apache are trying to bail on wells and large undeveloped acreage positions in the same freaking location. I also recently pointed out another oxy package in Loving Co., with one strong well and two weak ones. Bloomberg touts it as low cost too. ..."
"... the operational aspects that are enabling far higher resource recovery at far shorter time frames is not open to debate. ..."
"... Bringing 11 wells from one pad online at an average cost way less than $3 million, like PDC just did in the Niobrara, will become the norm in certain areas, not the exception. ..."
"... Drilling two laterals 500 apart, and having each well produce almost 500 MMcf of natgas per month, like Rice's Blue Thunder wells, is becoming the standard in eastern Ohio. ..."
"... Employing far more effective fracs via proppant type, amount, and precise placement not only is boosting initial output, it is enabling more long lasting conductivity to the wellbore. ..."
"... EOG and Whiting are leading the way, along with a handful of smaller, entrepreneurial Canadian operators. ..."
"... I attended a dinner tonight at the Midland Petroleum Club. My wife and I sat next to a former local banker. He told us that one of the banks in town has 26 bank examiners in its office this week. ..."
"... no amount of talk can change the fact that the US E P industry is completely toast if $30 WTI and $2 natural gas persist. ..."
"... I am starting to think many desire that very result, including the current White House occupant. ..."
Texas has a message for $30 crude doomsayers: Bring it on.
A handful of shale patches in the state, which would be the world's sixth-largest oil producer
if it were a country, are profitable with crude below $30 a barrel, according to an analysis
by Bloomberg Intelligence. In the Eagle Ford's DeWitt County, which produced more than 100,000
barrels a day in November, the average well can be profitable with U.S. benchmark crude at
$22.52 a barrel, $4 below the lowest level this year.
Drive 200 miles southwest to Dimmit County, and drillers need $58 oil. The wide range of
break-evens, a term for the price at which a well goes from profitable to unprofitable, illustrates
one reason why shale production from exploration and production companies has been more resilient
than expected.
"It may be harder to kill many U.S. E&Ps than analysts originally thought," Bloomberg Intelligence
analyst William Foiles said in the presentation. "The wide range of break-evens undermines
efforts to come up with a single threshold for U.S. shale producers."
It's easier to survive low oil in some places than in others. Bloomberg Intelligence analyzed
everything from the average well output to the amount of local school taxes to learn the average
break-even cost for drilling in different rock formations in counties across Texas's two big
shale regions, the Eagle Ford in south Texas and the Permian Basin.
Nine areas had break-even costs at $30 or below, including some of the biggest oil-producing
counties in Texas, such as DeWitt, Midland, Martin and Reeves, with had combined output of
430,000 barrels a day in November, according to the Texas Railroad Commission.
Oil prices can be even lower to justify completing wells that have already been drilled
but haven't yet been hydraulically fractured, or fracked. Companies have built up a fracklog
of more than 4,000 of those wells in the U.S. It's economic to complete wells in 18 different
areas in the Permian and Eagle Ford at sub-$30 oil. In Reeves County in the Permian, oil prices
above $14 justify fracking an already-drilled well.
Even within one county, break-even costs can vary widely depending on which company is drilling
and the richness of the rocks they're tapping, said Kathryn Downey Miller, a principal at Lakewood,
Colorado-based energy research firm BTU Analytics LLC. In DeWitt, for example, about 45 percent
of wells drilled in 2014 would have been profitable with oil below $20, but another 5 percent
needed $70 oil.
"You see a great amount of variability between operators, even in a small geographic area like
a county," she said by phone.
That variability makes it difficult to tell when companies will give up drilling. For instance,
while companies reduced the number of new wells coming online in Dimmitt County to 65 in the
third quarter last year from 226 in the first quarter, they increased activity in DeWitt County
by 77 percent.
"The good news is we're primed and ready for when we need to see a return to activity in
North America," Miller said. "This lower price environment is making companies defer big oil
projects, so there will be an opportunity for U.S. shale producers to contribute to production
growth, and they'll be better able to compete than they've ever been."
Have heard from someone who I believe knows better than the Bloomberg writer that "there are
likely little to no Wolfbone wells in Reeves country that are even close to being economic at
$45 dollar oil."
"Oil prices can be even lower to justify completing wells that have already been drilled
but haven't yet been hydraulically fractured, or fracked.
Companies have built up a fracklog of more than 4,000 of those wells in the U.S. It's
economic to complete wells in 18 different areas in the Permian and Eagle Ford at sub-$30 oil.
In Reeves County in the Permian, oil prices above $14 justify fracking an already-drilled well."
Probably this amazing insight was discovered after a field trip to a local bar and in-depth communication
with locals. As if money spend on initial drilling can just be written off and does not hang on
the company balance sheet.
OXY has a 19 well Wolfbone package for sale in Pecos Co., which shares a border with Reeves Co.
100% GWI, 75% NRI. 16 producing, 1 SWD, 2 already plugged. 8/8 production is 300 bopd, 496 mcfpd.
Wells completed 2014-2015.
So I suppose for OXY and the rest we ignore wells like the above, and continue with the $22 break
even BS because someone hit a few good wells the next county over?
I'm ready to give up. If the massive losses experienced in 2015 do not make believers out
of anyone, neither will the upcoming even greater 2016 losses.
shallow sand, 02/05/2016 at 1:01 am
Ironically, just after posting this I see a flyer in my email. Apache has 6 Wolf bone wells
plus large acreage tract for sale in Reeves and Pecos counties.
The 6 wells are producing 220 bopd gross, 165 net. Those likely don't break even at $92, let alone
$22.
Funny how we get this Bloomberg report at the same time both oxy and apache are trying to
bail on wells and large undeveloped acreage positions in the same freaking location. I also recently
pointed out another oxy package in Loving Co., with one strong well and two weak ones. Bloomberg
touts it as low cost too.
The break even price point can seem sometimes like an endless discussion, but the operational
aspects that are enabling far higher resource recovery at far shorter time frames is not open
to debate.
It is happening and will continue to happen. Bringing 11 wells from one pad online at an
average cost way less than $3 million, like PDC just did in the Niobrara, will become the norm
in certain areas, not the exception.
Drilling two laterals 500′ apart, and having each well produce almost 500 MMcf of natgas
per month, like Rice's Blue Thunder wells, is becoming the standard in eastern Ohio.
Employing far more effective fracs via proppant type, amount, and precise placement not
only is boosting initial output, it is enabling more long lasting conductivity to the wellbore.
EOG and Whiting are leading the way, along with a handful of smaller, entrepreneurial Canadian
operators.
While the attention may be drawn to the financials, the underlying 'how it's getting done'
continues, IMHO, to be the big story.
I attended a dinner tonight at the Midland Petroleum Club.
My wife and I sat next to a former local banker. He told us that one of the banks in town has
26 bank examiners in its office this week.
Data from Rystad Energy show the number of completed wells have by far outpaced
the number of wells spudded (drilled) since 4Q14. Indeed, the number of well completions per month
continued to increase several months after the rig count started to drop off, peaking at more
than 1,600 wells in December 2014. The number of completions are still outpacing the number of
new wells drilled, and as a result, the number of uncompleted wells, or the frack-log, has been
cut down from its peak of around 4,600 wells hit at the end of 2014 to around 3,700 wells currently.
This seems to make a total mockery of all the claims in the media, that they were drilling
cheaper wells, and saving them for future production, with an ever increasing number of DUCs.
Rystad Energy's analysis makes a lot more sense, that the shale drillers were completing more
than they drilled, to conserve current cash, then the often stated line saving DUCs for the future
. Especially when the shale players are fighting for a future that may not exist for them.
"... The production life indicator shows the production months left if there are no new wells drilled. So, in 2014 companies had to replace the current production within 13 months through new production. However, during 2015 this indicator shows that production has to be replaced within 8.5 months, which is 40% faster. ..."
"... The 'Red Queen' had to run 40% faster just to keep production stable – and needs therefore also 40% more capex – just to keep production even. ..."
"... Capex for oil and gas has been around USD 200 bn in 2014, yet with the strong declines in 2016 close to USD 500 bn are required to keep production stable. The huge capital required significantly weakened the US bond market by end of last year and threatens to bring down the whole US economy. ..."
"... Something has to give now: either the dollar falls or the bond market weakens even further or at least 3mill bbl/d will come out of the market and oil will rise again. ..."
In my view Wall Street has been surprised by the recent dynamics of shale economics.
In below chart I have tried to develop an indicator which depicts at which speed the 'Red Queen'
has to run.
The production life indicator shows the production months left if there are no new wells
drilled. So, in 2014 companies had to replace the current production within 13 months through
new production. However, during 2015 this indicator shows that production has to be replaced within
8.5 months, which is 40% faster.
The 'Red Queen' had to run 40% faster just to keep production stable – and needs therefore
also 40% more capex – just to keep production even.
Below chart also shows that this trend accelerates and it is very likely that the time for
replacement of current production sinks to 5 months this year. In other words companies in the
Eagle Ford have to replace current production twice every year, which is an enormous task and
requires much more capital than in previous years.
Capex for oil and gas has been around USD 200 bn in 2014, yet with the strong declines
in 2016 close to USD 500 bn are required to keep production stable. The huge capital required
significantly weakened the US bond market by end of last year and threatens to bring down the
whole US economy.
Something has to give now: either the dollar falls or the bond market weakens even further
or at least 3mill bbl/d will come out of the market and oil will rise again.
This article is purely stupid. Nobody can lower the cost so much. The best way is to lay off
people but it will impact the production soon. I was laid off last year from an oil company. But
the cost only drops marginally. It makes the company easier to borrow though. That is it. This
article sounds like whistling while through the graveyard. They are lying. The secret is piling
on dedt. This is a race who can borrow more.
This guy must be kidding or telling a straight-faced lie. US rig count has dropped from an
average 1600s to 500s and canadian number from nearly 600 to 250. Does this mean lower than spot
break even cost? What bunch of BS. US production has come down 600k barrels a day.
This is horseshit... all of a sudden they're profitable at sub 30? I smell horseshit. More
likely that one or more of the primary dealers is financing this scam with fresh Yellenbucks to
keep this train rolling until "someone" across the pond folds like a cheap suit... there's no
fucking way these guys are "profitable" sub 30... just another fucking tall tale...put it on the
pile with the others...
"... The decline and legacy rates are huge for shale. According to the latest drilling report, the monthly legacy rate for all shale plays has reached nearly 400 000 b/d and month, which is annualized over 4 mill b/d of decline. Add the legacy rate for shale natural gas, which is nearly 20 bcf/d and year. ..."
"... At peak levels in 2014 total North American E P spending was about $200bn, but this included Canada and US conventional ..."
"... If we look at the increases in yearly average output in 2014 and 2015, it was 1250 kb/d vs 730 kb/d. So decreased investment of $70 B, reduced the production gain by about 520 kb/d. ..."
"... In any case, somewhere between 96B and 132B is enough to get flat output in the US (replacing about 500 kb/d of decline at a 6% annual rate or 920 kb/d if we assume a 10% annual decline rate). ..."
"... Under most plausible oil price scenarios, 2018 US production may be flat or only slightly above 2017, and growth in 2019 will still be moderate. I now think that 2015 record level of (9.7 mb/d in April) may not be reached even in 2020. However, with higher prices, peak levels could be achieved in the next decade. ..."
"... I think the average US C+C output levels will be about 400 kb/d less in 2016 compared to average 2015 output levels. ..."
"... For the Bakken/Three Forks the legacy decline in Nov 2015 was 4 kb/d and if the rate that new wells are added remains at the Nov 2015 level the legacy decline rate falls to an average rate of 3 kb/d for Dec 2015 to Nov 2016, output only falls by 140 kb/d in this scenario. ..."
"... If no new wells are added over the next 12 months output in the North Dakota Bakken/Three Forks only falls by 350 kb/d. That scenario is not very likely. ..."
"... If 39 new wells per month (half as many as Nov 2015) are added each month for the next 12 months (somewhat plausible at low oil prices), ND Bakken/Three Forks output falls by 250 kb/d. ..."
"... The Eagle Ford will fall a little more maybe 350 kb/d, the Permian is likely to be flat, the rest of the US LTO might fall by 200 kb/d at most, so about 800 kb/d decline is about all we will see for LTO decline over the next 12 months. ..."
"... GOM output has been increasing lately so overall US C+C decline might be 700 kb/d from Dec 2015 to Nov 2016 (next 12 months of data). ..."
The decline and legacy rates are huge for shale. According to the latest drilling report, the
monthly legacy rate for all shale plays has reached nearly 400 000 b/d and month, which is annualized
over 4 mill b/d of decline. Add the legacy rate for shale natural gas, which is nearly 20 bcf/d
and year.
Together with conventional oil and gas, the US oil and gas industry has to replace every year
close to 10 mill boe/d which is 50% of capacity of oil and gas production.
And the situation gets worse every year. The decline rate for worldwide conventional oil production
is just 6%.
The cost for 1 mill b/d (either buying from the shelf or building from scratch) stands around
USD 50 bn. So the US oil and gas industry has to invest every year USD 500 bn for keeping production
stable – and gets just 250 bn revenue for this investment.
This is a financing gap of USD 250 bn every year. As the total high yield bond market adds
up to USD 1500 bn, the oil industry taps 17% of the high yield bond market.
I think this explains the high the leverage in the oil and gas market. The cost for keeping
the USD stable is now astronomical. Something has to give here. Either the dollar or the bond
market collapses or 3mill b/d come out of the market immediately.
If we look at the increases in yearly average output in 2014 and 2015, it was 1250 kb/d
vs 730 kb/d. So decreased investment of $70 B, reduced the production gain by about 520 kb/d.
The decreased investment of $45B less in 2016 vs 2015.would be expected to reduce the production
gain by 330 kb/d, so we could potentially see an increase in output of 400 kb/d (2016 average
output vs 2015 average output) if the investment spending estimates are correct and the previous
trend holds.
This simple linear model is not likely to be correct because if we assume zero investment spending
in 2016, the result is flat output, which is highly unlikely.
I would expect output will be flat at best with 96 billion investment and oil is likely to
be down by 500 to 700 kb/d.
In inherent problem with the way I have done this is investment in natural gas production has
been ignored. We don't have enough detail here to know how the investment was divided between
natural gas and oil, though we could divide it up based on gross revenue or some other metric.
In any case, somewhere between 96B and 132B is enough to get flat output in the US (replacing
about 500 kb/d of decline at a 6% annual rate or 920 kb/d if we assume a 10% annual decline rate).
1) It is important to note, that today's upstream capex will affect output levels about 6 months
from now. So high capex in 2014 resulted in relatively high production levels in 1H15.
But lower capex in 2015 will affect production in 2016, and even lower capex in 2016 will negatively
affect production in 2017.
2) Annual average growth in 2015 vs. 2014 reflects strong monthly growth in 2014.
Monthly output was declining since April 2015 and will continue to decline in 2016 and probably
for most of 2017. Furthermore, decline rates are likely to accelerate this year and may only moderate
in 2017.
The EIA expects annual average US C+C production in 2016 to be 0.7 mb/d lower than in 2015,
including a 0.8 mb/d y-o-y decline in Lower 48 onshore output.
They are projecting annual average decline of 270 kb/d for US C+C in 2017, including 380 kb/d
in Lower 48 onshore.
Even "shale optimists" like Goldman Sachs and Citi expect a decline of ~0.5 mb/d in 2016 (I do
not know their longer-term projections).
Under most plausible oil price scenarios, 2018 US production may be flat or only slightly
above 2017, and growth in 2019 will still be moderate. I now think that 2015 record level of (9.7
mb/d in April) may not be reached even in 2020. However, with higher prices, peak levels could
be achieved in the next decade.
I think the EIA may be too pessimistic. The annual decline rate trend for March to Nov 2015
is about 500 kb/d. (See chart). I think there will be some oil price rise by mid year (maybe to
$45/b) and that the decline rate will moderate towards the end of 2016 as oil prices rise further
(to over $60/b by Dec 2016). I think the average US C+C output levels will be about 400 kb/d
less in 2016 compared to average 2015 output levels.
See chart for trend (note the assumption of a linear trend which is likely to overstate the
decline).
This was 2014 when legacy declines were much lower (around 20%). I am talking about 2016, which
includes also the rest of this year (total legacy rate 50%). In addition shale represents close
to two thirds of the oil and gas market in 2016. This share has been much lower in 2014.
If the US oil and gas industry does not spend as much, production will decline accordingly.
I cannot emphasize enough how much shale has changed the dynamics of the oil market. It is important
to recognize the change in the markets and not rely on past numbers.
The Bakken and Eagle Ford Models do not rely on past numbers except as a check on the model
(the Bakken Model has actually been lower than actual output, the Eagle Ford has been a little
closer, but also on the low side).
Now I take a model which has matched actual output fairly well over time and assume well profiles
remain the same as the past two years and that the new wells are added at half the rate of recent
months (39 new wells per month rather than 78 new wells), a similar exercise is done for the Eagle
Ford.
Enno Peters work confirms what I have found for the Bakken (which is based on data gathered
from the NDIC by Enno Peters.)
What you consistently fail to realize is that the EIA's DPR gives a very bad estimate of legacy
decline.
As fewer new wells are added the legacy decline gets smaller.
Think about it a moment, if 200 new wells per month are added, the legacy decline is high and
if 50 new wells per month are added the legacy decline will be lower (by roughly a factor of 4),
surely you can see this.
In the Bakken about 170 new wells per month were being added each month during 2012 to 2014,
lately only about 77 new wells have been added, so legacy decline will be smaller.
Bottom line, the DPR has Bakken legacy decline increasing and that is not correct, it will
decrease until the rate that new wells are added each month starts to increase.
The EIA's estimate for legacy decline in the Bakken and Eagle Ford are incorrect.
For the Bakken/Three Forks the legacy decline in Nov 2015 was 4 kb/d and if the rate that
new wells are added remains at the Nov 2015 level the legacy decline rate falls to an average
rate of 3 kb/d for Dec 2015 to Nov 2016, output only falls by 140 kb/d in this scenario.
If no new wells are added over the next 12 months output in the North Dakota Bakken/Three
Forks only falls by 350 kb/d. That scenario is not very likely.
If 39 new wells per month (half as many as Nov 2015) are added each month for the next
12 months (somewhat plausible at low oil prices), ND Bakken/Three Forks output falls by 250 kb/d.
The Eagle Ford will fall a little more maybe 350 kb/d, the Permian is likely to be flat,
the rest of the US LTO might fall by 200 kb/d at most, so about 800 kb/d decline is about all
we will see for LTO decline over the next 12 months.
GOM output has been increasing lately so overall US C+C decline might be 700 kb/d from
Dec 2015 to Nov 2016 (next 12 months of data).
As I have said before, your method for coming up with a 4 million barrel per day decline in
US output hits very wide of the mark, you are off by almost a factor of 6. Use the EIA's DPR at
your peril if you are an investor.
Heinrich Leopold considerations are very interesting but probably wrong. As Dennis Coyne pointed
out shale/ight oil production in the USA is very resilient due to huge amount of wells drilled.
Notable quotes:
"... However, after an initial phase of economic weakness, lower US production will drive the USD down and increase worldwide economic activity again. The question remains how far the USD will fall and as a consequence volatility will rise. So, shale production does not mean the end of the world, yet increased volatility and the challenge how to control it. ..."
"... Together with conventional oil and gas, the US oil and gas industry has to replace every year close to 10 mill boe/d which is 50% of capacity of oil and gas production. And the situation gets worse every year. The decline rate for worldwide conventional oil production is just 6%. ..."
"... In any case, somewhere between 96B and 132B is enough to get flat output in the US (replacing about 500 kb/d of decline at a 6% annual rate or 920 kb/d if we assume a 10% annual decline rate). ..."
"... But lower capex in 2015 will affect production in 2016, and even lower capex in 2016 will negatively affect production in 2017. ..."
"... The EIA expects annual average US C+C production in 2016 to be 0.7 mb/d lower than in 2015, including a 0.8 mb/d y-o-y decline in Lower 48 onshore output. They are projecting annual average decline of 270 kb/d for US C+C in 2017, including 380 kb/d in Lower 48 onshore. Even shale optimists like Goldman Sachs and Citi expect a decline of ~0.5 mb/d in 2016 (I do not know their longer-term projections). ..."
"... Under most plausible oil price scenarios, 2018 US production may be flat or only slightly above 2017, and growth in 2019 will still be moderate. I now think that 2015 record level of (9.7 mb/d in April) may not be reached even in 2020. However, with higher prices, peak levels could be achieved in the next decade. ..."
"... I think the EIA may be too pessimistic. The annual decline rate trend for March to Nov 2015 is about 500 kb/d. (See chart). I think there will be some oil price rise by mid year (maybe to $45/b) and that the decline rate will moderate towards the end of 2016 as oil prices rise further (to over $60/b by Dec 2016). I think the average US C+C output levels will be about 400 kb/d less in 2016 compared to average 2015 output levels. ..."
"... If no new wells are added over the next 12 months output in the North Dakota Bakken/Three Forks only falls by 350 kb/d. That scenario is not very likely. ..."
"... If 39 new wells per month (half as many as Nov 2015) are added each month for the next 12 months (somewhat plausible at low oil prices), ND Bakken/Three Forks output falls by 250 kb/d. ..."
"... The Eagle Ford will fall a little more maybe 350 kb/d, the Permian is likely to be flat, the rest of the US LTO might fall by 200 kb/d at most, so about 800 kb/d decline is about all we will see for LTO decline over the next 12 months. ..."
"... Enno Peters charts for ND Bakken show a similar decline of ~1/3 in combined output if no new wells are drilled ..."
"... Yes, the US is very energy intensive. Yes, I also believe oil and gas production will decline (and not only in the US). A few energy companies will default. Maybe we will have another recession – it is about time. But in the end, yes, you are going to die. Okay, tell us something new here! ..."
"... I would think that Daniel is noting that the laterals are longer and that they have gone to staged fracking. With staged fracking, instead of doing one frack per lateral, they are doing like 30 or more separate fracs in stages of a few hundred feet each in each lateral. If not, Daniel can tell us. ..."
Agree with the article about shale gas. However, after an initial phase of economic weakness,
lower US production will drive the USD down and increase worldwide economic activity again. The
question remains how far the USD will fall and as a consequence volatility will rise. So, shale
production does not mean the end of the world, yet increased volatility and the challenge how
to control it.
What has changed to make natural gas prices more volatile than in the past?
In the case of oil we can point to a major change in the behavior of OPEC, do you think the
volatility in oil prices will filter through to the natural gas market through the bond market?
The energy companies produce both oil and natural gas so there is certainly the financial tie
in as far as oil price volatility affecting the oil and gas industry in general.
The decline and legacy rates are huge for shale. According to the latest drilling report, the
monthly legacy rate for all shale plays has reached nearly 400 000 b/d and month, which is annualized
over 4 mill b/d of decline. Add the legacy rate for shale natural gas, which is nearly 20 bcf/d
and year.
Together with conventional oil and gas, the US oil and gas industry has to replace every year
close to 10 mill boe/d which is 50% of capacity of oil and gas production. And the situation gets
worse every year. The decline rate for worldwide conventional oil production is just 6%.
The cost for 1 mill b/d (either buying from the shelf or building from scratch) stands around
USD 50 bn. So the US oil and gas industry has to invest every year USD 500 bn for keeping production
stable – and gets just 250 bn revenue for this investment.
This is a financing gap of USD 250 bn every year. As the total high yield bond market adds
up to USD 1500 bn, the oil industry taps 17% of the high yield bond market. I think this explains
the high the leverage in the oil and gas market. The cost for keeping the USD stable is now astronomical.
Something has to give here. Either the dollar or the bond market collapses or 3mill b/d come out
of the market immediately.
If we look at the increases in yearly average output in 2014 and 2015, it was 1250 kb/d vs
730 kb/d. So decreased investment of $70 B, reduced the production gain by about 520 kb/d.
The decreased investment of $45B less in 2016 vs 2015.would be expected to reduce the production
gain by 330 kb/d, so we could potentially see an increase in output of 400 kb/d (2016 average
output vs 2015 average output) if the investment spending estimates are correct and the previous
trend holds.
This simple linear model is not likely to be correct because if we assume zero investment spending
in 2016, the result is flat output, which is highly unlikely.
I would expect output will be flat at best with 96 billion investment and oil is likely to
be down by 500 to 700 kb/d.
In inherent problem with the way I have done this is investment in natural gas production has
been ignored. We don't have enough detail here to know how the investment was divided between
natural gas and oil, though we could divide it up based on gross revenue or some other metric.
In any case, somewhere between 96B and 132B is enough to get flat output in the US (replacing
about 500 kb/d of decline at a 6% annual rate or 920 kb/d if we assume a 10% annual decline rate).
1) It is important to note, that today's upstream capex will affect output levels about
6 months from now. So high capex in 2014 resulted in relatively high production levels in
1H15. But lower capex in 2015 will affect production in 2016, and even lower capex in 2016
will negatively affect production in 2017.
2) Annual average growth in 2015 vs. 2014 reflects strong monthly growth in 2014.
Monthly output was declining since April 2015 and will continue to decline in 2016 and probably
for most of 2017. Furthermore, decline rates are likely to accelerate this year and may only moderate
in 2017.
The EIA expects annual average US C+C production in 2016 to be 0.7 mb/d lower than in 2015,
including a 0.8 mb/d y-o-y decline in Lower 48 onshore output. They are projecting annual average
decline of 270 kb/d for US C+C in 2017, including 380 kb/d in Lower 48 onshore. Even "shale optimists"
like Goldman Sachs and Citi expect a decline of ~0.5 mb/d in 2016 (I do not know their longer-term
projections).
Under most plausible oil price scenarios, 2018 US production may be flat or only slightly
above 2017, and growth in 2019 will still be moderate. I now think that 2015 record level of (9.7
mb/d in April) may not be reached even in 2020. However, with higher prices, peak levels could
be achieved in the next decade.
I think the EIA may be too pessimistic. The annual decline rate trend for March to Nov
2015 is about 500 kb/d. (See chart). I think there will be some oil price rise by mid year (maybe
to $45/b) and that the decline rate will moderate towards the end of 2016 as oil prices rise further
(to over $60/b by Dec 2016). I think the average US C+C output levels will be about 400 kb/d less
in 2016 compared to average 2015 output levels.
See chart for trend (note the assumption of a linear trend which is likely to overstate the
decline).
This was 2014 when legacy declines were much lower (around 20%). I am talking about 2016, which
includes also the rest of this year (total legacy rate 50%). In addition shale represents close
to two thirds of the oil and gas market in 2016. This share has been much lower in 2014. If the
US oil and gas industry does not spend as much, production will decline accordingly. I cannot
emphasize enough how much shale has changed the dynamics of the oil market. It is important to
recognize the change in the markets and not rely on past numbers.
The Bakken and Eagle Ford Models do not rely on past numbers except as a check on the model
(the Bakken Model has actually been lower than actual output, the Eagle Ford has been a little
closer, but also on the low side).
Now I take a model which has matched actual output fairly well over time and assume well profiles
remain the same as the past two years and that the new wells are added at half the rate of recent
months (39 new wells per month rather than 78 new wells), a similar exercise is done for the Eagle
Ford.
Enno Peters work confirms what I have found for the Bakken (which is based on data gathered
from the NDIC by Enno Peters.)
What you consistently fail to realize is that the EIA's DPR gives a very bad estimate of legacy
decline.
As fewer new wells are added the legacy decline gets smaller.
Think about it a moment, if 200 new wells per month are added, the legacy decline is high and
if 50 new wells per month are added the legacy decline will be lower (by roughly a factor of 4),
surely you can see this.
In the Bakken about 170 new wells per month were being added each month during 2012 to 2014,
lately only about 77 new wells have been added, so legacy decline will be smaller.
Bottom line, the DPR has Bakken legacy decline increasing and that is not correct, it will
decrease until the rate that new wells are added each month starts to increase.
"As fewer new wells are added the legacy decline gets smaller."
This is an interesting (and counterintuitive) paradox. Like you pointed out it is based on
the fact that the total number of wells is large and the decline curve flattens with years (after
the third year of production).
So paradoxically if you do not drill for three years you will get almost zero decline in output
during the forth year as all your wells will be "legacy wells".
In other words even with minimal drilling Bakken and other shale/tight oil plays in aggregate
are much more resilient output-wise that the decline of the production curve for a single well
suggests. See
http://peakoilbarrel.com/bakken-single-well-economics/
So companies will have substantial financial losses but total output decline will be not that
pronounced as each well produces oil for, say, 8 years.
If it was Saudis gamble to drop oil price to eliminate the US shale production, they badly
miscalculated. They need nearly a decade of low prices to eliminate substantial part of the USA
shale output.
Other factors such as exhaustion of "sweet spots" are probably more important in the future
drop of production.
Your above table confirms my view about a strong production decline in 2016. USD 500 bn are
necessary to keep production flat and compensate for future decline rates in 2016. If just USD
100 bn are spent in 2016, production of oil and gas will decline by 6 to 8 mill boe/d (more than
3 mill b/d of oil and the rest in natgas).
The EIA's estimate for legacy decline in the Bakken and Eagle Ford are incorrect.
For the Bakken/Three Forks the legacy decline in Nov 2015 was 4 kb/d and if the rate that new
wells are added remains at the Nov 2015 level the legacy decline rate falls to an average rate
of 3 kb/d for Dec 2015 to Nov 2016, output only falls by 140 kb/d in this scenario.
If no new wells are added over the next 12 months output in the North Dakota Bakken/Three
Forks only falls by 350 kb/d. That scenario is not very likely.
If 39 new wells per month (half as many as Nov 2015) are added each month for the next
12 months (somewhat plausible at low oil prices), ND Bakken/Three Forks output falls by 250 kb/d.
The Eagle Ford will fall a little more maybe 350 kb/d, the Permian is likely to be flat,
the rest of the US LTO might fall by 200 kb/d at most, so about 800 kb/d decline is about all
we will see for LTO decline over the next 12 months.
GOM output has been increasing lately so overall US C+C decline might be 700 kb/d from Dec
2015 to Nov 2016 (next 12 months of data).
As I have said before, your method for coming up with a 4 million barrel per day decline in
US output hits very wide of the mark, you are off by almost a factor of 6. Use the EIA's DPR at
your peril if you are an investor.
Well, please, stop this dramatic "we all going to die. Gold and silver will save you."! What are
you going to do with your gold and silver (when the economy has ground to a halt)? Eat it? Fill
it in your car? Who wants to trade it against really useful stuff in this situation?
Yes, the US is very energy intensive. Yes, I also believe oil and gas production will decline
(and not only in the US). A few energy companies will default. Maybe we will have another recession
– it is about time. But in the end, yes, you are going to die. Okay, tell us something new here!
Be careful with rig counts: one rig 5y ago was very different than today (today they are longer,
being fracked several times etc.)
Daniel may think the rig and well are the same thing. Many people think of old pictures of
well blowouts where the old wooden rigs are in place and think that the rig remains in place after
the well has been drilled.
Personally the only rig I have seen in person was a small rig used to drill a water well on
my property. (A toy relative to the rigs used for 20,000 foot wells in the Bakken.)
I believe you have pointed out that the average rig in service in the US is more efficient
at present because it is mostly the older rigs that have been stacked.
So we are probably seeing more feet drilled per rig today than 3 years ago.
Also Jeffrey Brown's point that there is more associated gas from oil wells (particularly in
the Eagle Ford) and more liquids focused gas drilling (aiming for gas with a lot of NGL) to improve
profitability.
US natural Gas output will decline a bit until natural gas prices and oil prices rise and make
increased drilling profitable.
This is really a problem of oversupply driving prices down and now the supply will decrease
and prices will rise, eventually (after a 6 to 12 month delay) supply will increase.
I would think that Daniel is noting that the "laterals" are longer and that they have gone
to "staged" fracking. With staged fracking, instead of doing one frack per lateral, they are doing
like 30 or more separate fracs in stages of a few hundred feet each in each lateral.
If not, Daniel can tell us.
"... Basically, the overwhelming majority of the shale gas extracted at the Haynesville was done so at a complete loss. So, why do they continue drilling and producing gas in the Haynesville? ..."
"... What we see in the Haynesville Shale play are companies that blindly seek production volumes rather than value, and that care nothing for the interests of their shareholders . The business model is broken. It is time for investors to finally start asking serious questions. ..."
"... Chesapeake is one of the larger shale gas producers in the Haynesville as well as in the United States. According to its recent financial reports, Chesapeake received $1.05 billion in operating cash in the first three-quarters of 2015, but spent $3.2 on capital expenditures to continue drilling. Thus, its free cash flow was a negative $2.1 billion in the first nine months of 2015 . And this doesnt include what it paid out in dividends. ..."
"... The reason these companies continue to produce shale gas at a loss is to keep generating revenue and cash flow to service their debt. If they cut back significantly on drilling activity, their production would plummet. This would cause cash flow to drop like a rock, including their stock price, and they would go bankrupt as they couldnt continue servicing their debt. ..."
"... Basically, the U.S. Shale Gas Industry is nothing more than a Ponzi Scheme. ..."
"... Now that the major shale gas producers are saddled with debt and many of the sweet spots in these shale gas fields have already been drilled, I believe U.S. shale gas production will collapse going forward. If we look at the Haynesville Shale Gas Field production profile, a 50% decline in 4 years represents a collapse in my book. ..."
"... As I stated in several articles and interviews, ENERGY DRIVES THE ECONOMY, not finance. So, energy is the key to economic activity. Which means, energy output and the control of energy are the keys to economic prosperity. ..."
"... The collapse of U.S. shale oil and gas production are two nails in the U.S. Empire coffin. Why? Because U.S. will have to rely on growing oil and gas imports in the future as the strength and faith of the Dollar weakens. I see a time when oil exporting countries will no longer take Dollars or U.S. Treasuries for oil. Which means… we are going to have to actually trade something of real value other than paper promises. ..."
"... Berman has been yelling Ponzi Scheme for years. In his view, all extractive businesses must be Ponzi Schemes. His claims had nothing to do with a prediction of lower NG prices, just lack of reserves. While producers may have been off on the price forecasts, it is obvious from the production numbers that they did a great job in reducing costs and delivering the reserves. ..."
"... I live in PA and drilling is all around me; but the gas companies have stopped opening up new wells because the price of gas fell so low. Meanwhile, a geologist friend says theres enough gas in the Marcellus to last several decades, and theres oil under that. I cant see production coming to a complete halt but, yes, my royalties are also dropping because production fell. ..."
"... I imagine in 10 years from now ZH will still be babbling about the demise of USA. Hell, we managed before shale so whats the big deal. TD gets his rocks from hyperventilating from his fever dreams of US destruction. ..."
"... All that is needed is for the petrodollar to disappear, and believe me, things will get very difficult in the States. Now having said that, the US still has the best innovators in the world, and all that is needed is to bring back manufacturing and scale back globalization a bit. ..."
"... It will be a multi-polar world. Already is to a degree. The only problem I see is if only one country cuts the cake. Regardless, I know that the US has the best innovation and only needs to bring back manufacturing and protect its economy a bit and it will still be a large power. ..."
The U.S. Empire is in serious trouble as the collapse of its domestic shale gas production has begun.
This is just another nail in a series of nails that have been driven into the U.S. Empire coffin.
Unfortunately, most investors don't pay attention to what is taking place in the U.S. Energy Industry.
Without energy, the U.S. economy would grind to a halt. All the trillions of Dollars in financial
assets mean nothing without oil, natural gas or coal. Energy drives the economy and finance steers
it. As I stated several times before, the financial industry is driving us over the cliff.
The Great U.S. Shale Gas Boom Is Likely Over For Good
Very few Americans noticed that the top four shale gas fields combined production peaked back
in July 2015. Total shale gas production from the Barnett, Eagle Ford, Haynesville and Marcellus
peaked at 27.9 billion cubic feet per day (Bcf/d) in July and fell to 26.7 Bcf/d by December 2015:
As we can see from the chart, the Barnett and Haynesville peaked four years ago at the end of
2011. Here are the production profiles for each shale gas field:
According to the U.S. Energy Information Agency (EIA), the Barnett shale gas production peaked
on November 2011 and is down 32% from its high . The Barnett produced a record 5 Bcf/d of shale gas
in 2011 and is currently producing only 3.4 Bcf/d. Furthermore, the drilling rig count in the Barnett
is down a stunning 84% in over the past year.
The Haynesville was the second to peak on Jan 2012 at 7.2 Bcf/d per day and is currently producing
3.6 Bcf/d. This was a huge 50% decline from its peak . Not only is the drilling rig count in the
Haynesville down 57% in a year, it fell another five rigs this past week. There are only 18 drilling
rigs currently working in the Haynesville.
The EIA reports that shale gas production from the Eagle ford peaked in July 2015 at 5 Bcf/d and
is now down 6% at 4.7 Bcf/d. As we can see, total drilling rigs at the Eagle Ford declined the most
at 117 since last year. The reason the falling drilling rig count is so high is due to the fact that
the Eagle Ford is the largest shale oil-producing field in the United States.
Lastly, the Mighty Marcellus also peaked in July 2015 at a staggering 15.5 Bcf/d and is now down
3% producing 15.0 Bcf/d currently. The Marcellus is producing more gas (15 Bcf/d) than the other
top three shale gas fields combined (12.1 Bcf/d).
I have posted the Haynesville shale gas production chart below to discuss why U.S. Shale Gas production
will likely collapse going forward:
What is interesting about the Haynesville shale gas field, located in Louisiana and Texas, is
the steep decline of production from its peak. On the other hand, the Barnett (chart above in red)
had a much different profile as its production peak was more rounded and slow. Not so with the Haynesville.
The decline of shale gas production at the Haynesville was more rapid and sudden. I believe the Eagle
Ford and Marcellus shale gas production declines will resemble what took place in the Haynesville.
All you have to do is look at how the Eagle Ford and Marcellus ramped up production. Their production
profiles are more similar to the Haynesville than the Barnett. Thus, the declines will likely behave
in the same fashion. Furthermore drilling and extracting shale gas from the Haynesville was a "Commercial
Failure" as stated by energy analyst Art Berman in his
Forbes article on Nov 22 2015 :
The Haynesville Shale play needs $6.50 gas prices to break even. With natural
gas prices just above $2/Mcf (thousand cubic feet), we question the shale gas business model that
has 31 rigs drilling wells in that play that cost $8-10 million apiece to sell gas at a loss into
a over-supplied market.
At $6 gas prices, only 17% of Haynesville wells break even (Table 3) and approximately
115,000 acres are commercial (Figure 2) out the approximately 3.8 million acres that comprise
the drilled area of the play.
The Haynesville Shale play is a commercial failure. Encana exited the play in late August.
Chesapeake and Exco, the two leading producers in the play, both announced significant write-downs
in the 3rd quarter of 2015.
Basically, the overwhelming majority of the shale gas extracted at the Haynesville was done
so at a complete loss. So, why do they continue drilling and producing gas in the Haynesville?
The reason Art Berman states is this:
What we see in the Haynesville Shale play are companies that blindly seek production volumes
rather than value, and that care nothing for the interests of their shareholders . The business
model is broken. It is time for investors to finally start asking serious questions.
Chesapeake is one of the larger shale gas producers in the Haynesville as well as in the United
States. According to its recent financial reports, Chesapeake received $1.05 billion in operating
cash in the first three-quarters of 2015, but spent $3.2 on capital expenditures to continue drilling.
Thus, its free cash flow was a negative $2.1 billion in the first nine months of 2015 . And this
doesn't include what it paid out in dividends.
The same phenomenon is taking place in other companies drilling for shale gas in the other fields
in the U.S. This insanity has Berman perplexed as he states this in
another article
from his site :
This has puzzled me because the shale gas plays are not commercial at less than about $6/mmBtu
except in small parts of the Marcellus core areas where $4 prices break even. Natural gas prices
have averaged less than $3/mmBtu for the first quarter of 2015 and are currently at their lowest
levels in more than 2 years.
The reason these companies continue to produce shale gas at a loss is to keep generating revenue
and cash flow to service their debt. If they cut back significantly on drilling activity, their production
would plummet. This would cause cash flow to drop like a rock, including their stock price, and they
would go bankrupt as they couldn't continue servicing their debt.
Basically, the U.S. Shale Gas Industry is nothing more than a Ponzi Scheme.
The Collapse Of U.S. Shale Gas Production Even At Higher Prices
I believe the collapse of U.S. shale gas production will occur even at higher prices Why? Because
the price of natural gas increased from $2.75 mmBtu in 2012 to $4.37 mmBtu in 2014, but the drilling
rig count continued to fall:
As the price of natural gas increased from 2012 to 2014, gas drilling rigs fell 40% from 556 to
333. Furthermore, drilling rigs continued to decline and now are at a record low of 127 . Just as
Art Berman stated, the average break-even for most shale gas plays are $6 mmBtu, while only a small
percentage of the Marcellus is profitable at $4 mmBtu.
Looking at the chart again, we can see that the price of natural gas never got close to $6 mmtu..
the highest was $4.37 mmBtu. Thus, the U.S. Shale Gas Industry has been a commercial failure.
Now that the major shale gas producers are saddled with debt and many of the sweet spots in
these shale gas fields have already been drilled, I believe U.S. shale gas production will collapse
going forward. If we look at the Haynesville Shale Gas Field production profile, a 50% decline in
4 years represents a collapse in my book.
The Two Nails In The U.S. Empire Coffin
As I stated in several articles and interviews, ENERGY DRIVES THE ECONOMY, not finance. So,
energy is the key to economic activity. Which means, energy output and the control of energy are
the keys to economic prosperity.
While the collapse of U.S. shale gas production is one nail in the U.S. Empire Coffin, the other
is Shale Oil. U.S. shale oil production peaked before shale gas production:
This chart is a few months out of date, but according to the EIA's Productivity Reports, domestic
oil production from the top four shale oil fields peaked in April of 2015… three months before the
major shale gas fields (July 2015).
Unfortunately for the United States, it was never going to become energy independent. The notion
of U.S. energy independence was built on hype, hope and cow excrement. Instead, we are now going
to witness the collapse of U.S. shale oil and gas production.
The collapse of U.S. shale oil and gas production are two nails in the U.S. Empire coffin.
Why? Because U.S. will have to rely on growing oil and gas imports in the future as the strength
and faith of the Dollar weakens. I see a time when oil exporting countries will no longer take Dollars
or U.S. Treasuries for oil. Which means… we are going to have to actually trade something of real
value other than paper promises.
I believe U.S. oil production will decline 30-40% from its peak (9.6 million barrels per day July
2015) by 2020 and 60-75% by 2025. The U.S. Empire is a suburban sprawl economy that needs a lot of
oil to keep trains, trucks and cars moving. A collapse in oil production will also mean a collapse
of economic activity.
Thus, a collapse of economic activity means skyrocketing debt defaults, massive bankruptcies and
plunging tax revenue. This will be a disaster for the U.S. Empire.
Papa Roach is correct. Just look at this quote from the article:
As the price of natural gas increased from 2012 to 2014, gas drilling rigs fell 40%
from 556 to 333.
Price has an increase, # rigs falls, but volumes continue with the big increases. The fewer
rigs replaced production declines and increased deliveries. That happened because the tech improved
to get much more hole drilled for the same rig time. Also latterals were able to be extended,
requiring less verticle hole and with the use of the same pad to drill multiple wells. Berman
fails to consider the cost reductions and productivity improvements. Frac jobs that once took
over a week are not done in a few days.
Berman has been yelling Ponzi Scheme for years. In his view, all extractive businesses
must be Ponzi Schemes. His claims had nothing to do with a prediction of lower NG prices, just
lack of reserves. While producers may have been off on the price forecasts, it is obvious from
the production numbers that they did a great job in reducing costs and delivering the reserves.
A NG price in the $4 range makes it pretty profitable for the producers. Relatively affordable
for consumer and energy equiv. to oil at < $30.
Gas has peaked because the number of rigs is off. Most of the gas in North Dakota is still
flared off because it is too cheap to make it worth transporting it. When we start exporting it
in bulk, the price will go up and the supply will go up.
I live in PA and drilling is all around me; but the gas companies have stopped opening
up new wells because the price of gas fell so low. Meanwhile, a geologist friend says there's
enough gas in the Marcellus to last several decades, and there's oil under that. I can't see production
coming to a complete halt but, yes, my royalties are also dropping because production fell.
Exactly. When the market price is below production cost, and even capture cost from wells drilled
primarily for oil, there will be less gas produced. Even in 2014 when the market price for gas
was $2 higher than it is now, it was more cost effective for most wells in the Permian to just
flare it off.
I imagine in 10 years from now ZH will still be babbling about the demise of USA. Hell,
we managed before shale so what's the big deal. TD gets his rocks from hyperventilating from his
fever dreams of US destruction.
All that is needed is for the petrodollar to disappear, and believe me, things will get
very difficult in the States. Now having said that, the US still has the best innovators in the
world, and all that is needed is to bring back manufacturing and scale back globalization a bit.
It will be a multi-polar world. Already is to a degree. The only problem I see is if only
one country cuts the cake. Regardless, I know that the US has the best innovation and only needs
to bring back manufacturing and protect its economy a bit and it will still be a large power.
Are you an anti-commie? Using the term commie as your username is really out of touch.
Maybe only North Korea is communist these days.
It seems to me the story here is that peak was avoided because 100s of billions in mal-investment
opened up some new production and allowed expensive production to continue. In fact the true total
is in the trillions when you include the global QE that was necessary because of economic collapse
related to FF peak.
ALL the optimist here seem to ignore this fact and believe that high prices
will get things going again and the march toward global growth will resume, "renewables" will
ramp up and the transition will occur.
Can anyone flesh out this fantasy world a bit more? How does a more expensive everything world
translate to an economy that can thrive and in fact transition? There is simply no historical
precedent for this and indeed the physical world guarantees it can't happen. Has everyone just
read too many sic-fi novels and are unable to see things any other way?
More likely is massive deflation where everything doesn't get more expensive. In fact it gets
less expensive but no one can afford it. How in this kind of reality does everything just cruz
along and eventually transition? None of you flesh this out in any realistic way that holds water.
likbez,
Jef,
"It seems to me the story here is that peak was avoided because 100s of billions in mal-investment
opened up some new production and allowed expensive production to continue. In fact the true total
is in the trillions when you include the global QE that was necessary because of economic collapse
related to FF peak. "
Good point. Thank you --
As Arthur Berman aptly said: "Shale is not a revolution, it's a retirement party".
But some new technologies were also developed as they should such as continental fracking and long
horizontal drilling as well as deep sea subsurface pumps, better platforms, etc), a better prediction
where oil can be, which cuts the number of dry holes and allow finding small deposits.
So there was some technological progress too out of this financing bonanza. Not all those billions
of "unlimited financing bonanza" were wasted.
IMHO it was like a mini-replay of subprime mortgages in "subprime oil" domain. When any company "with
live breath" could get a loan or sell junk bonds.
That definitely alloed the USA "prolong the agony" and postpone the next recession. But on a negative
side it destroyed conservation efforts creating an SUV boom in the USA, drop of sales of EV and hybrids
cars, almost completely stop of transitioning to natural gas of city public transportation (buses)
and other negative for oil conservation developments.
In this sense current dramatic drop of oil prices due to condensate glut , Saudis, Wall Street games,
or whatever was a the "Last Hurrah", just postponed facing cruel reality for, most probably, three
years or so (AlexS now thinks that more then that).
"... It's not just oil companies that are exposed, however. Regional banks that lend to the energy industry could suffer as a result of a default wave, the OFR report noted, adding that "the ultimate magnitude of losses in these industries and regions is uncertain. ..."
"... The real pain will come when these firms need to refinance debt. Chesapeake, for example, has $2 billion in liabilities coming due in 2017 (against a current market capitalization of just $2.1 billion)… ..."
A financial watchdog set off the alarm bells on corporate debt Wednesday in its
annual report to Congress. With companies feeling growing pressure from painful
exchange rates and energy prices, the U.S. is at a higher risk of seeing a wave
of corporate defaults, the report said.
The report from the Office of Financial Research, a division of the Treasury
Department, listed credit risk as one of the top three financial stability
dangers facing the economy in 2016….
It's not just oil companies that are exposed, however. Regional banks that
lend to the energy industry could suffer as a result of a default wave, the OFR
report noted, adding that "the ultimate magnitude of losses in these industries
and regions is uncertain."
S&P said Monday it has cut its 2016 and 2017 forecast for WTI crude by 20
percent. And also dropped its forecast price for Henry Hub natural gas by 15
percent for the next two years.
That prompted S&P to issue an immediate credit downgrade on one major oil
and gas player: shale specialists Chesapeake Energy. A move that caused a
single-day, 16 percent fall in Chesapeake's share price….
The real pain will come when these firms need to refinance debt. Chesapeake,
for example, has $2 billion in liabilities coming due in 2017 (against a
current market capitalization of just $2.1 billion)…
"... This week, the Permian basin horizontal rig count fell by 13 while the Bakken and Eagle Ford were unchanged. ..."
"... I have shown that those plays are commercially less attractive than the Bakken and Eagle Ford because of lower EUR and comparable costs. A positive aspect of the plays is higher early flow rates and, therefore, more cash flow. ..."
The U.S. land rig count fell 17 to 590 and the horizontal land rig count fell 13 to 487.
This week, the Permian basin horizontal rig count fell by 13 while the Bakken and Eagle Ford were
unchanged.
Is this a moment of truth for the Permian basin plays?
I have shown that those plays are commercially less attractive than the Bakken and Eagle
Ford because of lower EUR and comparable costs. A positive aspect of the plays is higher early
flow rates and, therefore, more cash flow.
"... In North Dakota, abandoned wells not plugged and the landscape not restored, equipment remaining
at the site, not producing paying production, the well is forfeited to the state. No longer property
of the producer, there it was gone. The State of North Dakota has rules, you must abide by them or lose
your assets. ..."
"... After a well has been in abandoned-well status for one year, the wells equipment, all well-related
equipment at the well site, and salable oil at the well site are subject to forfeiture by the commission.
..."
"... As I previously noted, the 2008 oil price decline was, compared to this one, a micro-decline.
If we define the price slump as the number of months since an average monthly price of $100–before seeing
a sustained price increase–prices only fell for four months in 2008, before starting a sustained price
increase (monthly Brent prices). Based on same metric, we are at 17 months and counting. ..."
"... I suspect that the US needs to put on line around 1.5 million bpd of new C+C production and
around 17 BCF/day of new dry gas production this year, just to offset declines from existing wells,
with a total rig count that is currently in the low 600s versus 1,700 to 2,000 in recent years. ..."
In North Dakota, abandoned wells not plugged and the landscape not restored, equipment remaining
at the site, not producing paying production, the well is forfeited to the state. No longer property
of the producer, there it was gone. The State of North Dakota has rules, you must abide by them
or lose your assets.
Drilling is probably going to go to zero as soon as all leases expire. Just a hunch, nothing
else.
2017 is the best guess when it will all come to a screeching halt.
Page 12: N.D.C.C. 38-08-04.1L – The placing of wells in abandoned-well status which have not
produced oil or natural gas in paying quantities for one year. A well in abandoned-well status
must be promptly returned to production in paying quantities, approved by the commission for temporarily
abandoned status, or plugged and reclaimed within six months. If none of the three preceding conditions
are met, the industrial commission may require the well to be placed immediately on a single-well
bond in an amount equal to the cost of plugging the well and reclaiming the well site. In setting
the bond amount, the commission shall use information from recent plugging and reclamation operations.
After a well has been in abandoned-well status for one year, the well's equipment, all well-related
equipment at the well site, and salable oil at the well site are subject to forfeiture by the
commission. If the commission exercises this authority, section 38-08-04.9 applies. After
a well has been in abandoned-well status for one year, the single-well bond referred to above,
or any other bond covering the well if the single-well bond has not been obtained, is subject
to forfeiture by the commission.
2017 is the best guess when it will all come to a screeching halt.
Not likely. Prices are already starting to rise and by 2017 they will likely be high enough
for activity to continue. I would not venture a guess as to what that price may be however, or
just how much activity will continue.
As I previously noted, the 2008 oil price decline was, compared to this one, a micro-decline.
If we define the price slump as the number of months since an average monthly price of $100–before
seeing a sustained price increase–prices only fell for four months in 2008, before starting a
sustained price increase (monthly Brent prices). Based on same metric, we are at 17 months and
counting.
Note that it took about two years for the US total rig count to return to prior levels, after
the "V" shaped 2008 oil price decline (even with the benefit of very easy financing).
And as I have also previously noted, I suspect that the US needs to put on line around
1.5 million bpd of new C+C production and around 17 BCF/day of new dry gas production this year,
just to offset declines from existing wells, with a total rig count that is currently in the low
600's versus 1,700 to 2,000 in recent years.
[Jan 29, 2016] US rigs down 18, oil rigs down 12, gas rigs down 6, Texas down 13
The
Baker
Hughes Rig Count is out. US rigs down 18, oil rigs down 12, gas rigs down 6. Texas down 13. Canadan
rigs down when they should be going up. They usually peak in February.
"... A year-and-a-half on from the start of the worst crude-oil price crash in a generation, the biggest U.S. and European energy companies have delayed projects and made such deep budget cuts that they will soon struggle to replace the oil they pump out of the ground with new reserves. ..."
"... Exxon and its peers are set to begin reporting fourth-quarter earnings this week, starting with Chevron on Friday. Analysts estimate that combined profits at the four biggest publicly traded Western oil companies will be about $22 billion, the weakest results since 1998, according to S P Capital IQ. Shell, Chevron, Exxon and BP declined to comment. ..."
"... "With the low price environment, you will see the economics around drilling getting worse and worse," he said. "More companies will be buying assets rather than continuing to develop." ..."
"... In round numbers, I suspect that the annual loss of US C+C production from existing wells has skyrocketed, from about 0.25 million bpd in 2008 to probably around 1.5 million bpd this year, and I don't think that changing the ownership of proven producing properties will have a material impact. ..."
A year-and-a-half on from the start of the worst crude-oil price crash in a generation,
the biggest U.S. and European energy companies have delayed projects and made such deep budget
cuts that they will soon struggle to replace the oil they pump out of the ground with new reserves.
That conundrum could have serious implications for Exxon Mobil Corp. , BP PLC, Chevron Corp.
and Royal Dutch Shell PLC because oil-and-gas reserves are critical to evaluating their growth
prospects.
Exxon and its peers are set to begin reporting fourth-quarter earnings this week, starting
with Chevron on Friday. Analysts estimate that combined profits at the four biggest publicly
traded Western oil companies will be about $22 billion, the weakest results since 1998, according
to S&P Capital IQ. Shell, Chevron, Exxon and BP declined to comment.
Facing poor returns for drilling and severe challenges to long-term growth, some big oil
companies have little choice but to turn to deals, said Anish Kapadia, an energy analyst at
Tudor Pickering Holt & Co. . . .
At current prices U.S. shale producers are losing more than $2 billion a week, according
to consulting firm AlixPartners LLP. That means as oil's crash grinds on, some shale companies
may be forced to fall into the arms of a willing buyer this year.
Oil-patch deals now look more attractive than they have in years, said Robin Bertram, the
oil-and-gas resource evaluation leader at Deloitte LLP. That is especially true for some of
the biggest oil companies, which largely sat on the sidelines during the U.S. shale boom.
"With the low price environment, you will see the economics around drilling getting
worse and worse," he said. "More companies will be buying assets rather than continuing to
develop."
Of course, changing the ownership of proven producing properties does not materially change
remaining recoverable reserves (the only positive effect might be that the acquiring party has
more money to put into enhancing existing production).
In round numbers, I suspect that the annual loss of US C+C production from existing wells
has skyrocketed, from about 0.25 million bpd in 2008 to probably around 1.5 million bpd this year,
and I don't think that changing the ownership of proven producing properties will have a material
impact.
By drilling new wells is what I assume you meant, but my point is that I don't expect to see
changes in ownership having a material impact on the remaining recoverable reserves from existing
producing wells.
Years ago at the Oil Drum, one article posted a chart that predicted Norway would decline, then
halt for a while around 2014, then after a few years begin declining again.
The zero hedge article stoked my interest as pertains to American Eagle Energy.
What reasons will the same fate not befall the other primarily Bakken players, assuming the
financing dries up?
Clearly American Eagle Energy's metrics were worse than their Bakken peers, but not maybe as
bad as might be expected.
The thing that I keep wonder is when do we see the M &A in the Bakken, or any of the LTO plays,
for that matter?
Why not a hostile bid for WLL, trading at $6, or OAS at $4, etc? What, if anything, do the
supermajors know? Or are they just as scared as the rest of us, not knowing what to think?
AlexS, why wouldn't a Russian supermajor take a shot at one of the US LTO companies? They might
be able through that to get a leg up on the tech needed to exploit Russian LTO later on, when
the price of oil makes sense to do so?
Due to the high legacy decline rate, shale companies are not backed by worthwhile assets (long
term producing wells). It is better for big companies to start a shale operation from scratch
– if they think it is a good option. In the recent shale bankruptcies bondholders have got a maximum
of 15 cents on the dollar, which is in many cases not enough to cover legal fees. This explains
also the extreme nervousness of bondholders as their holdings are backed basically by nothing.
Slowly investors are waking up to this fact. It still takes time, yet it turns increasingly into
a panic. Men go mad in herds, yet recover their senses one by one.
debt is the reason nobody wants to buy these companies out. Quicksilver just sold itself for
$250 million. Company debt was in excess of $2.35 billion, so debt holders recovered 10-12% of
invested money. That is a really horrific recovery level for debt. The company claimed its assets
were worth $1.2 billion when initially filing for bankruptcy in March of 2015. American Eagle
sold for $45 million with debt at $215 million, so a slightly better recovery, but keep in mind
those properties sold in October when oil was in mid-to-high $40s.
WLL, OAS, and a number of other names have too much debt, which would need to be made whole
if somebody purchases companies outright. Nobody would step up to the plate until these guys are
bankrupt. Once bankruptcies take place buyers will emerge.
I agree with Dan's assessment. Why buy the company, saddled as it is with catastrophic debt levels,
when you can either buy bonds at very low prices to get the assets, or alternatively wait for
BK and buy the assets at knock-down prices in an auction? And regarding tech, again, wait for
BK and snap up the newly unemployed star engineers.
So do you think all of the LTO companies will go BK? Is Wall Street still overvaluing these companies?
I completely understand the responses to my question. However, look at where companies such
as Marathon Oil, Anadarko, Apache, Hess and ConocoPhilips are trading. Yet little merger talk,
other than Anadarko/Apache recently.
equity in all of these names is priced as if oil is at $60. All shale companies are technically
bankrupt as none have full-cycle costs below $60. Drilling within cash flows (without hedges)
would result in declining production unless prices go back to $60-65 range. Even then, drilling
within cash flows would allow for flat production for less levered Permian names and maybe EOG,
while the rest would still witness declining production.
MRO, APC, APA, HES, and COP are considerably leveraged and in COP's case management is stubbornly
keeping that hefty dividend payout.
Considering where equity is still priced for these names, I have to believe that market expects
oil prices to double in a very short time. In October they were pricing oil at $70-75, now they
are down considerably and are pricing WTI around $60. Of course, we are nowhere close to those
levels, thus equity is still way overpriced.
Hess Corp. announced Fourth quarter 2015 production today.
BOEPD increased from 362K in Q4 2014 to 368K in 2015.
HOWEVER.
All of the below are in terms of BOEPD for Q4, 2014 and 2015
Crude oil in 2014 was 241K. In 2015 DROPPED to 233K.
Natural gas liquids was 32K in 2014. INCREASED to 40K in 2015.
Natural gas was 89K in 2014, INCREASED to 95K in 2015
Furthermore, there was a substantial drop in US crude oil production Q3 to Q 4. 152K to 141K.
That is a big quarter over quarter drop. Can someone with better math skills than I annualize that
one?
I think these numbers should be of particular interest to Jeffrey J. Brown, who is constantly
pilloried by the CC crowd, as he has dubbed them.
Further, there are many others here who I am sure will take note of the increasing GOR (Rune,
are you still out there?)
I further note that the product mix for Continental Resources was 70% oil 30 gas and NGLs for
2014. It went 65/35 in 2015 and company guidance for 2016 is 60/40.
Will be interesting to see what other companies report in the next 30 or so days.
Looks like about a 28% annualized decline for HES U.S. oil production. Applied to
the entire U.S. that will put us under 7 million by next january. Wow!! And HES just reduced capex
another 25% I believe.
It would great to see charts of production per well over time. My own analysis has shown Bakken
per well productivity has been dropping for a good few years. More wells to produce the same amount
of oil is not a good sign.
Meanwhile, here are excerpts from an article in Platts':
"When North Dakota oil production broke above 1 million b/d for the first time in April 2014,
many expected that the 2 million b/d threshold would be breached in relatively short order.
Now, rather than striving for 2 million b/d, state officials are hoping to maintain production
above 1 million b/d.
And there are indications that a significant drop in Bakken supply may already be underway.
While Lynn Helms, the state's top oil regulator, called recent production numbers "quite a
surprise" amidst market shifts largely unsupportive of domestic production, he indicated the relative
success would be short lived.
While North Dakota supply has remained steady amid falling prices, it's unclear what has happened
since the end of November as prices began their steady dip below $40/b and, eventually, $30/b,
a pricing environment where Helms believes the majority of Bakken producers cannot survive.
"We cannot sustain production at sub-$30/b prices," Helms told reporters following the release
of the latest state supply data.
Helms believes that WTI spot prices will need to average roughly $50/b in order for current production
to be maintained. If prices return to the $30-$40/b range, production will likely stay above 1
million b/d, but will likely stay just above that level and will fall steadily, by about 10,000
b/d each month, if prices do not climb above $40/b in the near term, Helms said."
"... For instance, in 2014, as the U.S. added some million barrels of daily production, it had to produce 2.2 million new barrels of production to do so. The slope of that foundation required 1.2 million new barrels to just flatten it out. ..."
"... First year production in the U.S. has had a blended annual decline that has increased from 41 percent in for 2010 era wells to 47 percent for 2013 era wells. Therefore, 2014 era wells were likely to have declined 49 percent and 2015 by 51 percent in their first year. ..."
"... Depending on the variability of the second year declines, this could range from 400 mbpd to well over 1MM bpd. ..."
First, people will produce existing wells at rates that aren't sustainable to preserve cash flow
or compete for market share, because the cost to drill and bring online is already sunk. Second,
new wells will not be drilled if there isn't at least an outlook to breakeven producing them. That
means an expectation of a sustained price over 1-3 years or until the well has been paid out.
U.S. Production Rates
Image Source: Drillinginfo Production Report for Unconventional U.S. Onshore Plays (Combined
MBOE 20:1) over last six years. Note the lag in production reporting means Q42015 and even some Q32015
reports are not finalized.
First, let's look at the U.S., the simplest and most transparent of the "Pick 6" issues bandied
about as a price driver. Certainly the unconventional revolution has been a huge factor in global
production increases over the last 6 years. The item NOT generally recognized is that production
typically lags drilling by some 5 months, thus the drilling in December 2014 is discernible in production
records in April 2015. That analysts were alarmed at increasing production and supply during the
1st half of the year suggested that they did not understand this dynamic, nor did the business press.
We predicted in April that monthly production would peak in May and then jump around between
-100 mbpd and -350 mbpd for the rest of the year. When looking at additional production month over
month, it is important to remember that it is building on a sloping foundation of natural decline.
For instance, in 2014, as the U.S. added some million barrels of daily production, it had
to produce 2.2 million new barrels of production to do so. The slope of that foundation required
1.2 million new barrels to just flatten it out.
First year production in the U.S. has had a blended annual decline that has increased from
41 percent in for 2010 era wells to 47 percent for 2013 era wells. Therefore, 2014 era wells were
likely to have declined 49 percent and 2015 by 51 percent in their first year.
Second year declines show less of a pattern, ranging from 10-20 percent decline from the end of
the prior year.
Depending on the variability of the second year declines, this could range from 400 mbpd to
well over 1MM bpd.
So, the U.S. isn't going to be the bringer of oil glut news going forward. In fact, the U.S. oil
patch has severely damaged its capacity to rebound from an oil field services point of view, with
companies foregoing normal maintenance to just survive. This deferred maintenance will have permanent
consequences.
"... This is the worst oil bust in USA, post Great Depression. The benefit of $1.50 gasoline v. $2.50 gasoline is outweighed by the massive business failures at $15-25 well head oil, v. $55-65 well head oil. ..."
"... even with the massive CAPEX cuts announce, LTO companies will STILL be cash flow negative. Why are creditors not demanding all cash flow go to debt principal reduction? Dont they see how little these assets are worth, based on the BK sales? ..."
"... Continental Resources Inc., Oklahoma City, has reported a capital expenditures budget for 2016 of $920 million, a 66% reduction from the planned $2.7 billion for 2015 ..."
"... Hess Corporation is planning a 2016 capital and exploratory budget of $2.4 billion, a 40% reduction from its 2015 actual spend of $4 billion ..."
"... From CLR release. ..."
"... Production exit 2016 at 180K BOEPD. Down from 220K in 2015. Oil decline much worse, by my math 145 bopd to 108 bopd. ..."
Longtimber, the reason low oil prices are not helping is the low prices are too extreme, IMO.
This is the worst oil bust in USA, post Great Depression. The benefit of $1.50 gasoline v.
$2.50 gasoline is outweighed by the massive business failures at $15-25 well head oil, v. $55-65
well head oil.
Yet, despite the stories of massive CAPEX cuts, there is apparently too much oil. And, even
with the massive CAPEX cuts announce, LTO companies will STILL be cash flow negative. Why are
creditors not demanding all cash flow go to debt principal reduction? Don't they see how little
these assets are worth, based on the BK sales?
Kind of like there is supposedly too much corn, yet local grain elevators began paying .30
ABOVE big board prices, because they are low on corn.
More CAPEX cuts in USA tight oil and gas (from Oil and Gas Journal):
Continental Resources Inc., Oklahoma City, has reported a capital expenditures budget for 2016
of $920 million, a 66% reduction from the planned $2.7 billion for 2015
Hess Corporation is planning a 2016 capital and exploratory budget of $2.4 billion, a 40% reduction
from its 2015 actual spend of $4 billion and 20% below its preliminary 2016 guidance of $2.9-3.1
billion provided in October:
"... Estimated total U.S. oil and natural gas well completions fell by 51 percent in the fourth quarter of 2015 compared to year-ago levels, according to API's 2015 Quarterly Well Completion Report, Fourth Quarter. ..."
"... For 2015, total well completions decreased 35 percent overall compared to 2014 levels. Oil completions were down 37 percent and natural gas completions were down 28 percent). Total footage drilled was down 27 percent overall. ..."
"... I never had much doubt drilling and deferring completions was a viable option. Companies with deep pockets can do it and hold completions for up to three years as long as they get all the required permits and approvals to do so. ..."
WASHINGTON, January 19, 2016 – Estimated total U.S. oil and natural gas well completions fell
by 51 percent in the fourth quarter of 2015 compared to year-ago levels, according to API's 2015
Quarterly Well Completion Report, Fourth Quarter.
Estimated development oil well completions in 2015 fourth quarter fell 55 percent compared
to 2014 fourth quarter estimates. Estimated development gas completions decreased 37 percent over
the same period.
For 2015, total well completions decreased 35 percent overall compared to 2014 levels. Oil
completions were down 37 percent and natural gas completions were down 28 percent). Total footage
drilled was down 27 percent overall.
I never had much doubt drilling and deferring completions was a viable option. Companies with
deep pockets can do it and hold completions for up to three years as long as they get all the
required permits and approvals to do so.
"... I think the shorts, etc have hit critical mass on what they wanted to accomplish. As the oil market and stock market are now highly correlated, I am looking for the tide to turn. $26 was just too far. ..."
"... I don't think OPEC or Russia want to deal with a year or two of $30 oil. Given the connectivity of the global financial markets, I have a feeling we are going to see some big short covering. ..."
"... I also think if we have any decent recovery, the banks are going to insist shale live within cash flows for awhile. ..."
"... So, it would seem to me regardless of where prices go, a shale well earns less money on a per barrel basis over time because these costs are spread over fewer and fewer barrels every year. It is no wonder that shalies kept borrowing to drills. The new production provided high margin barrels in the early years to offset the worsening margins of legacy production. Am I looking at this correctly? ..."
"... If so, I think the upcoming numbers for the shalies will be horrific. With less new drilling, production will decline. Producers will be producing less barrels and earning a lower margin on each barrel produced as production from legacy wells makes up a larger percentage of production. Add in lower oil prices and the hemorrhaging could be quite bad. ..."
"... LOE varies greatly, but many range $10-$18,000 per month, not including down hole repairs. This comes straight from joint interest billings I have reviewed. Granted, there is some G A in those, some are tough to decipher. However, I have noticed as wells get down under 1000 BO per month, water hauling decreases, and LOE tends to be around $10-12,000 per month. ..."
"... I agree that Q4 will be horrible. But, if we stay around $30 WTI in Q1, it will really open some eyes. Right now there is very little cash flow with BOE realized being $18-22 in the Bakken, worse in more gassy areas. ..."
"... I am hoping for either a flush down to $10, which will force OPEC and Russia's hand, or a shift takes hold in the money center banks, where they decide oil shorting needs to stop. This slow drift since July has been horrible. ..."
"... Look at Parshall field. 6-8 year old wells making mostly 10-30 barrels per day. This is North Dakotas best. Not much cash flow, yet the wells really are not that old in my view. ..."
"... This implies a tremendous mismatch between debt levels and remaining cumulative net cash flow from production. ..."
"... The way the companies stay alive at these levels is through under the table bank bailouts (i.e. ignoring reserve based lending standards). ..."
"... In its 2014 10K, CLR noted that its PV10 all categories fell from $22 billion to $9 billion, simply by replacing 2014 SEC product pricing with 2/15/15 product pricing. 2/15/15 product pricing was SUSTANTIALLY better than present. ..."
Looking at year end reports here, comparing to past years. Really puts into
perspective how much 2015 deviated from prior years in the P & L, which is what
matters.
Plugging in average price thus far in 2016, using 2015 expenses is yet another
pretty stark reminder of just how low we are. It makes 2015 look good.
I think the shorts, etc have hit critical mass on what they wanted to accomplish.
As the oil market and stock market are now highly correlated, I am looking for
the tide to turn. $26 was just too far.
I don't think OPEC or Russia want to deal with a year or two of $30 oil. Given
the connectivity of the global financial markets, I have a feeling we are going
to see some big short covering.
I also think if we have any decent recovery, the banks are going to insist shale
live within cash flows for awhile.
You've written much before on well economics. Would you say that
most operating expenses for operating a well are mainly fixed? Electricity,
fuel and other expenses would seem to be the same regardless of whether the
well was producing 50 barrels per day or 25 b/day. Workovers and repairs seem
to be needed to be conducted regularly enough that in a sense they are fixed
costs as well.
So, it would seem to me regardless of where prices go, a shale well earns
less money on a per barrel basis over time because these costs are spread over
fewer and fewer barrels every year. It is no wonder that shalies kept borrowing
to drills. The new production provided high margin barrels in the early years
to offset the worsening margins of legacy production. Am I looking at this correctly?
If so, I think the upcoming numbers for the shalies will be horrific. With
less new drilling, production will decline. Producers will be producing less
barrels and earning a lower margin on each barrel produced as production from
legacy wells makes up a larger percentage of production. Add in lower oil prices
and the hemorrhaging could be quite bad.
John Keller. I do not know how quickly we will see this effect, but it will
be there.
Below are my views of Bakken wells.
LOE varies greatly, but many range $10-$18,000 per month, not including
down hole repairs. This comes straight from joint interest billings I have
reviewed. Granted, there is some G &A in those, some are tough to decipher.
However, I have noticed as wells get down under 1000 BO per month, water
hauling decreases, and LOE tends to be around $10-12,000 per month.
A year ago, tubing leaks were costing in the $70,000 range to repair,
down hole pump changes around $30,000. This was on rod lift wells.
A year ago I looked at several wells operated by Marathon Oil. Wells completed
2008-2010 ranged from $13-$55 per BOE to operate per the joint interest billings.
There were some re fracked wells, that were running under $3 per BOE, as
I recall. I did a post on this information.
I agree that Q4 will be horrible. But, if we stay around $30 WTI in Q1,
it will really open some eyes. Right now there is very little cash flow with
BOE realized being $18-22 in the Bakken, worse in more gassy areas.
We have shut in a lot of wells. We are just running water floods, plus
a few low cost wells that make almost straight oil. $20s in the field is
devastating for the US industry. For conventional producers, few are operating
at a profit.
I am hoping for either a flush down to $10, which will force OPEC and
Russia's hand, or a shift takes hold in the money center banks, where they
decide oil shorting needs to stop. This slow drift since July has been horrible.
Look at Parshall field. 6-8 year old wells making mostly 10-30 barrels
per day. This is North Dakotas best. Not much cash flow, yet the wells really
are not that old in my view.
As I have previously noted, given an ongoing decline in wellhead revenue,
due to falling production and/or falling product prices, unless total operating
costs (LOE and pro-rated G&A) fall at the same rate as, or at a rate faster
than, the rate of decline in wellhead revenue, the resulting rate of decline
in net cash flow from a given lease will decline at a rate faster than the
rate of decline in wellhead revenue, and the rate of decline in net cash
flow will accelerate with time.
This implies a tremendous mismatch between debt levels and remaining cumulative
net cash flow from production.
Jeffrey. Yes, thus my constant harping regarding PDP PV10. I would wager
up to 25% of all Bakken/Three Forks wells drilled and completed since
the year 2007 are losing money on an operating basis at today's prices,
and thus are not assets, but liabilities.
I suspect at $30 WTI and $2
Henry Hub, PDP PV10 of $10 million based on 2014 product pricing falls
to maybe $1 million at present product pricing in the Williston basin,
for Bakken/Three Forks wells completed since 2007.
At 2014 pricing, a 100 BOEPD well was likely netting 8-9 times what
a 100 BOEPD well is netting under current product pricing.
The way the companies stay alive at these levels is through under the
table bank bailouts (i.e. ignoring reserve based lending standards).
Almost NONE of the LTO companies in the United States are in a position
to have ANY further credit extended to them under traditional reserve
based lending standards. Almost ALL of them have total debt exceeding
65% of PDP PV10 at the current futures strips for WTI and Henry Hub. MANY
have total debt which exceeds PDP PV10, which, in my book, makes them
technically insolvent.
In its 2014 10K, CLR noted that its PV10 all categories fell from $22
billion to $9 billion, simply by replacing 2014 SEC product pricing with
2/15/15 product pricing. 2/15/15 product pricing was SUSTANTIALLY better
than present.
"... Greg Valliere, chief global strategist at Horizon Investments, is surprised Congress hasnt seemed to notice the oil crash, calling it a looming crisis. ..."
"... The shocking drop in the price of oil will soon get Washingtons attention, as unemployment spikes in Texas, Oklahoma, the Dakotas -- and as bankruptcies threaten to spiral out of control, Valliere wrote in a recent client note. ..."
"... John Kilduff, founding partner of energy hedge fund Again Capital, wrote a CNBC column making the case for a bailout. He said it should include payments to oil producers that shut down production, loan guarantees, revamping the bankruptcy code and having government agencies buy land with drilled-but-uncompleted wells. ..."
"... It is time to send out an S.O.S., before its too late, Kilduff wrote, adding that his version of S.O.S. stands for Save Our Shale industry. ..."
"... Unlike the collapse of the financial and auto industries in 2008/2009, a collapse of the oil industry here would not threaten the entire economy. That's because it's only a part of the oil industry that is affected...oil producers. Oil transportation, storage and refining are largely unaffected by this drop in the price of oil. ..."
"... It's a very curious stance and one that makes me wonder who backs the PPA. The bottom line is that an average barrel of oil in the U.S. costs about $ 70 for an energy company to produce. In OPEC nations, that number is around $ 20. That means on every barrel of oil a U.S. producer sells, they are losing more than half their money right now. Unfortunately, because so many of the newer, smaller producers are so highly leveraged, they don't have the option to sit on production until the price of oil increases. ..."
"... At that point, those larger companies will gobble their smaller counterparts up for pennies on the dollar, and trigger an increase in oil prices when they slow production. ..."
Greg Valliere, chief global strategist at Horizon Investments, is surprised Congress hasn't
seemed to notice the oil crash, calling it a looming crisis.
"The shocking drop in the price of oil will soon get Washington's attention, as unemployment
spikes in Texas, Oklahoma, the Dakotas -- and as bankruptcies threaten to spiral out of control,"
Valliere wrote in a recent client note.
To be sure, there doesn't appear to be an actual bailout in the works for the oil industry to
turn down. But talk about a federal rescue grew louder this month as crude oil crashed below $35
a barrel to as low as $26 this week.
John Kilduff, founding partner of energy hedge fund Again Capital, wrote a
CNBC column making the case for a bailout. He said it should include payments to oil producers
that shut down production, loan guarantees, revamping the bankruptcy code and having government agencies
buy land with drilled-but-uncompleted wells.
It is time to send out an S.O.S., before it's too late," Kilduff wrote, adding that his version
of S.O.S. stands for "Save Our Shale" industry.
However, many lawmakers don't want to be viewed as helping Big Oil -- especially not when a presidential
election hangs in the balance. There may also be bailout fatigue given the unpopular rescues of the
banking and auto industries in 2008 and 2009.
splifferton
Taxpayers currently subsidize the oil industry by as much as $4.8 billion a year, with
about half of that going to the big five oil companies-ExxonMobil, Shell, Chevron, BP, and
ConocoPhillips-which get an average tax break of $3.34 on every barrel of domestic crude they
produce.
I'm thinking they get enough already...
lmacmil
Funny, I hadn't read about anyone calling for a bailout of any energy-industry related
companies until I read this article. In fact, haven't really heard about any looking at
bankruptcy either (except Freeport-McRoRan in today's NY Times.) Where did this even come
from? It's not even close to what we were looking at in 2008. Must be a slow news day.
boatnmaniac
Unlike the collapse of the financial and auto industries in 2008/2009, a collapse of
the oil industry here would not threaten the entire economy. That's because it's only a part
of the oil industry that is affected...oil producers. Oil transportation, storage and refining
are largely unaffected by this drop in the price of oil.
Let the market forces work here. Those producers who lack the cash to stay in business will
go out of business and their assets will be bought up on the cheap by producers who are more
financially stable.
boatnmaniac
@chriss747 @boatnmaniac The problem with the auto industry was 2-fold. Unlike with oil
producers which have a lot of competition and where the healthier companies would be more than
willing to pick up failed producers' assets on the cheap, the auto companies could find no
buyers...nada.
The 2nd part of that is that an auto industry collapse would have had a large ripple effect
on all the down-stream suppliers which is a huge segment of our country's manufacturing
capacity. That would have been not only a huge risk to the economy but it was a huge risk to
national security because the auto industry supply chain industrial complex is extremely
critical to our country's ability to support the military.
There's simply no way the Fed Gov't could permit the auto industry to fail because of this.
evilbravoman
"We're asking the federal government to get out of the way and allow America's free-market
principles to work," the group said, referring to government support for competitors like
renewable energy sources like solar and wind.
Translation - we have a monopoly on energy here and we don't want anything else to affect
that!! We want everyone to stay on oil until the last drop is pumped out of the ground!!!
Typical short sited greed of Wall Street...
bzscorpio
It's a very curious stance and one that makes me wonder who backs the PPA. The bottom
line is that an average barrel of oil in the U.S. costs about $ 70 for an energy company to
produce. In OPEC nations, that number is around $ 20. That means on every barrel of oil a U.S.
producer sells, they are losing more than half their money right now. Unfortunately, because
so many of the newer, smaller producers are so highly leveraged, they don't have the option to
sit on production until the price of oil increases.
My guess is the PPA is mostly backed by large energy companies (like Exxon, BP, Shell, etc.)
who realize it's only a matter of time before the smaller oil producers in the U.S. go
bankrupt when oil doesn't rebound to 2014 levels and they run out of money. At that point,
those larger companies will gobble their smaller counterparts up for pennies on the dollar,
and trigger an increase in oil prices when they slow production. While I am certainly not
a fan of bailouts, I do understand when they are necessary, and I certainly think the
government bailing out small oil companies (whether it be with interest-free loans, subsidies,
etc) would be a worthwhile investment, if for no other reason than the wide-ranging economic
benefits of maintaining lower oil prices. Low gas prices help every American consumer, a very
wide-range of American companies (couriers, car manufacturers, airlines, etc), and also help
our trade deficit by keeping our dollar strong, not to mention protecting the jobs of
employees of these small oil companies.
Of course, the PPA doesn't want these small companies to remain in business because it would
prevent the large oil producers to buy them out on the cheap when they go bankrupt, which
almost every economist who follows the energy industry is predicting will start happening on a
large scale within the next 12-18 months, if not sooner.
mitchgam
The pain on the downswing is not only to the oil corporations but to the workers,
homeowners and business people in the communities effected.
When the prices go up, the pain is to the consumers across the nation.
Maybe now is the time to apply the same principals and solution that the GOP applies to
domestic farmers to the oil industry. (Price supports)
And if you, like me disagree with doing so, why do we do it for some industries and not
others?
Tom Evans
We use oil primarily for transportation in the US. Transitioning to electric vehicles will
be a long process that will be prolonged by cheap oil. I don't see airlines, railroads or
trucking transitioning from oil for a very long time, if ever.
Broncos2014
@mitchgam @Broncos2014 @Rektm
2. Chevron
The oil giant pay among the highest tax rates because of overseas royalties that float with
the price of oil.
Income tax expense: $20 billion
Net income: $26 billion
Effective tax rate: 43%
7. ConocoPhillips
Conoco paid the highest effective tax rate of any company on the list.
Income tax expense: $7.9 billion
Net income: $8.4 billion
Effective tax rate: 51.5%
Econimica
Iteresting to note it was the Fed's implementation of QE and ZIRP that was the underlying
premise for the oil price from Dec '08 til now...and it was the Fed's cheap money (lower for
longer) which created the massive overcapacity in global oil by providing credit to US /
Canadian "marginal" shale and tar sands producers who brought 90% of all new oil to the global
market from '09 til now...this is what created the massive over supply to the
market...consider:
---Oil prices bottomed in Dec '08...the same month QE was implemented
---Oil began it's fall in Aug '14...as QE was tapering out and oil was tumbling by the time QE
terminated Oct '14...and oil has collapsed since.
---When the Fed stopped accumulating Treasury's via QE in late 2014...why did foreigners do
likewise (stop accumulating)??? What is the impact on the US markets and economy of all
Treasury buying shifting to domestic sources?
---What is the linkage of QE, the dollar, Treasury's, and oil?
---What is the likelihood of a Fed U-turn in 2nd half of 2016 and re-implementing QE to weaken
the dollar and offer a whole lot of support for oil?
A look at the correlation and/or causation in the links. http://bit.ly/20hKX2W
When one adds in the fact that the days of a growing pie for everybody are nearly over...many
pieces to be considered. http://bit.ly/1mS9Of0
"... I keep reading paragraphs in various articles that point out how easy it will be for the drillers to turn it on if prices "spike" over $40. I know that most here would agree that is not going to happen. The money will be a killer. And, we have all seen this movie before, only in a different industry. ..."
"... If oil prices rise to $60 by year end, we all know that the drillers will be clamoring for money to let them gear back up. The drillers will throw out rosy price forecasts. However, human nature will put an end to that. The employees at the banks who are in charge of establishing "price decks" for their bank will probably raise their deck to something like $40. ..."
"... They are not going to have their job threatened by another plunge in prices. ..."
"... In my opinion, absent some sort of energy emergency (e.g., a real war), it will be 3 or 4 years before the banks will have relatively the same price expectations that the drillers will have. ..."
I keep reading paragraphs in various articles that point out how easy it will be for the drillers
to turn it on if prices "spike" over $40. I know that most here would agree that is not going
to happen. The money will be a killer. And, we have all seen this movie before, only in a different
industry.
When the housing bubble burst, for at least the next 4 years, I read dozens of stories
about how people could not buy a house because it would not appraise for the price that both the
seller and buyer had agreed to. Appraisers were petrified of sticking their necks out. No way
were they going to go along with a "V" shaped housing price recovery.
If oil prices rise to $60 by year end, we all know that the drillers will be clamoring for
money to let them gear back up. The drillers will throw out rosy price forecasts. However, human
nature will put an end to that. The employees at the banks who are in charge of establishing "price
decks" for their bank will probably raise their deck to something like $40.
They are not going to have their job threatened by another plunge in prices. And, there will
not be one single bank that will want to become known as the "go to bank" because they have a
higher price deck than the other banks. In my opinion, absent some sort of energy emergency (e.g.,
a real war), it will be 3 or 4 years before the banks will have relatively the same price expectations
that the drillers will have.
Yup. But we already knew where this is heading 8-9 months ago. You can see how broad market reacted
with sudden enlightenment of very low prices for longer than it was hoped.
I picked this up out of a Seeking Alpha article by Traveling Investor.
2003, ConocoPhillips average oil price was $27.47 and gas price $4.07. Production costs
were $4.98 per BOE.
2014, production costs for ConocoPhillips were $15.52, per BOE.
Excepting international gas, which I am not sure of re pricing, COP is likely grossing less
than $20 per BOE today. I am sure production costs are down from 2014, however, triple from 2003
is in line with our experience.
As crude oil prices collapse below $30 per barrel and metals trade near record lows, Goldman
Sachs (GS) forecasts that 2016 will nonetheless bring a "new bull market" for commodities.
"... Rystad energy had a press release on Dec. 1,2015 where they estimated 3500 remaining at year-end.
..."
"... If the cost of completion really IS in the neighborhood of four or five million bucks, including
the frack job, and all the other smaller items, it does not seem likely- unless the completion money
is borrowed from idiots at a couple of percent, and the idiots lose their asses, unless Uncle Sam bails
them out. ..."
"... With the industry in such a bad slump, the cost of completion is no doubt down substantially,
but it is hard to imagine it falling by more than maybe a quarter or a third, max. ..."
Rystad energy had a press release
on Dec. 1,2015 where they estimated 3500 remaining at year-end. They have some tracking system
but its normally behind their pay wall. Go to their website, press release, Dec. 1, 2015. That
the best info I've seen.
This is the first time I have visited Rystad. I am impressed with the quality of the interviews
and press releases.
Now I am wondering if the owners of these wells can generate any cash, short term, by putting
them into production. If the cost of completion really IS in the neighborhood of four or five
million bucks, including the frack job, and all the other smaller items, it does not seem likely-
unless the completion money is borrowed from idiots at a couple of percent, and the idiots lose
their asses, unless Uncle Sam bails them out.
With the industry in such a bad slump, the cost of completion is no doubt down substantially,
but it is hard to imagine it falling by more than maybe a quarter or a third, max.
Does anybody have a current figure for completion costs?
reported exclusively how the Dallas Fed is pulling strings behind the scenes to conceal the fallout
from the oil market crash.
As Dark-Bid.com's
Daniel Drew notes, by suspending mark-to-market on energy loans and distorting the accounting,
they are postponing the inevitable as long as possible. The current situation is eerily reminiscent
to the heyday of the mortgage market in 2007, when mortgage defaults started to pick up, and yet
the credit default swaps that tracked them continued to decline, bringing losses to those brave enough
to trade against the crowd.
Amidst the market chaos on Friday, a trader brought something strange to my attention. He asked
me exactly what the hell was going on with this ETN he was watching . I took a closer look and was
baffled. It took me awhile to put the pieces together. Then when I saw the story about mark-to-market
being suspended, it all made sense.
Here is the daily premium for the last 6 months on the
Barclays
iPath ETN that tracks oil :
Initially, Dark-Bid.com's
Daniel Drew thought this was merely a sign of retail desperation. As they faced devastating losses
on their oil stocks, small investors turned to products like oil ETNs as they tried to grasp the
elusive oil profits their financial adviser promised them a year ago. Oblivious to the cruel mechanics
of ETNs, they piled in head first, in spite of the soaring premium to fair value. After all, Larry
Fink is
making the rounds to convince the small investor that ETFs are indeed safer than mutual funds.
Because nothing says "safe" like buying an ETN that is 36% above its fair value.
Sure, there are differences between ETFs and ETNs, particularly regarding their solvency in the
event of an issuer default, but the premium/discount problem plagues ETFs and ETNs alike. Nonetheless,
widely trusted retail sources of investment information perpetuate the myth that ETNs do not
have tracking errors.
But was it just retail ignorance?
Something remarkable happened in the last hour of trading on Friday which sparked the massive
decoupling in OIL from its NAV...
Making us wonder, was an 'invisible hand' at play? Or was this just more evidence of OPEX-inspired
broken markets?
I hear that the OCC finally had some wells shut down due to Deep Waste Water Injection issues.
There seems to be studies now being looked at seriously by the OCC – Oklahoma Corporation Commission
on Deep Water Injection and its impact on Earthquake activity. If a precedent is shown to exist…
WATCH THE F*CK OUT.
From what I understand, there are huge lawsuits in the pipeline if (once) a precedent is found.
I also hear that the TRRC is watching closely the OCC hearings and meetings. If a precedent is
found to exist and is made official by the OCC, the TRRC will likely follow.
This could shut in a lot of Resource Oil & Gas Wells due to the liability and deep water injection
issues. I have been doing some reading on Earthquake damage to homes, buildings and infrastructure
and it is much worse than MSM has reported. There's one hell of a lot of very angry and pissed
off people in Oklahoma and Texas that have suffered damage from earthquakes.
You add this to the recent Dallas Fed decision to keep the Banks from MARK TO MARKET their
energy assets (LOL… Liabilities), and looks like we are going to see one hell of a BLOOD BATH
in the U.S. energy industry this year.
My brother is having a problem with that around Edmond, Okla. 50% of the wells in Texas, they
just use surface ponds to allow them to dry OU. The better alternative they are starting to use
is centralized wastewater treatment plants that they can reuse the water from. If it becomes a
huge issue, then I hope they gravitate that way.
"... Without ongoing oil investment decline rates everywhere will increase, so the 1.2 Mb/d decline
estimate at the World level for 2016 compared to 2015 ..."
"... Note 2015 was about 9.4 Mb/d average, so this would be an average 2016 level of about 8.2 Mb,
with output falling from 9.2 Mb/d in Dec 2015 to 7.2 Mb/d in Dec 2016 (we will assume a linear decline).
..."
"... Any guesses out there for the average oil price for 2016? Mine is more than $50/b average for
the year for WTI. The EIA guess is $39/b for WTI in 2016 (average price). Note that they also have very
wide error bars around this estimate (from $22/b to $82/b for the 95% confidence interval in Dec 2016.)
..."
"... If we take the average of the high and low estimates for the 95% confidence intervals for March
to Dec 2016 and than average these with futures prices for Jan and Feb 2016 we get an average price
of $45/b. ..."
"... I think the futures market will be wrong on the low side by at least $5/b. ..."
"... Even if we assume $40 for 2016 as the average, at $29 oil is more then 25% below the expected
(low) annual average pushed by IEA. Which is almost 4 times of annual return on junk bonds. ..."
"... My impression is that this show with sliding oil prices went a little bit too long. The price
of oil is now like compressed spring. So with the appropriate trigger event there will be a strong bounce
if only because of short squeeze ..."
Others have probably pointed this out, but a couple of articles I have just read suggest
the strengthening of the US dollar may drive oil prices lower, to possibly $20/b. I still am skeptical,
but let's consider what this might do to US output. I expect we would see turmoil from the LTO
sector and a lot of conventional stripper wells might get temporarily abandoned. Let's assume
the worst and assume a 30% annual decrease in all US onshore output from the lower 48. I believe
this is about 7 Mb/d in 2015 (roughly), so this would mean the average output in 2016 would drop
by 2 Mb/d from 2015 average output levels (this is C+C output.)
If that estimate is correct for an oil price at $20/b, I believe this would bring the oil market
back into balance pretty quickly and this does not consider the effect on other oil producers,
prices this low might make OPEC take action or at least reduce investment throughout the World.
Without ongoing oil investment decline rates everywhere will increase, so the 1.2 Mb/d decline
estimate at the World level for 2016 compared to 2015 (yearly average CC output levels) may
be conservative at an oil price of $20/b. Note 2015 was about 9.4 Mb/d average, so this would be an average 2016 level of about 8.2
Mb, with output falling from 9.2 Mb/d in Dec 2015 to 7.2 Mb/d in Dec 2016 (we will assume a linear
decline).
Any guesses out there for the average oil price for 2016? Mine is more than $50/b average
for the year for WTI. The EIA guess is $39/b for WTI in 2016 (average price). Note that they also
have very wide error bars around this estimate (from $22/b to $82/b for the 95% confidence interval
in Dec 2016.)
If we take the average of the high and low estimates for the 95% confidence intervals for
March to Dec 2016 and than average these with futures prices for Jan and Feb 2016 we get an average
price of $45/b.
I think the futures market will be wrong on the low side by at least $5/b.
After that it depends on how resilient the US producers are and what OPEC does.
I think oil could go as low as high teens this quarter and then recover to about $40 by year end
as US production falls below Iran and Iraq increases.
We just know them oil cos keep ripping us consumers off again … ;-)
"most barrels of oil sold
around the world garner even less than the benchmark price, Nicole Friedman reports. A basket
of crude oils sold by members of the Organization of the Petroleum Exporting Countries has fallen
to $25.69 a barrel. In Canada, some of the cheapest crude oil in the world costs less than $15."
Much depends on how Wall street will play Iranian card and whether OPEC can agree on cuts in
June (or at the emergency meeting in March, if any), or Saudis will block this move. Those are
trigger events for 2016. The key issue is that the system is destabilized, so I would expect wild
oscillations. We might be observing one right now.
Even if we assume $40 for 2016 as the average, at $29 oil is more then 25% below the expected
(low) annual average pushed by IEA. Which is almost 4 times of annual return on junk bonds.
That does not mean that you need to put your money (oil speculation is only for big sharks
like Vitol and Mercuria able to buy real oil and store it in tanks while selling futures ), but
still this is quite a big deviation from expected for 2016 or multiyear average. Almost like in
2008.
My impression is that this show with sliding oil prices went a little bit too long. The
price of oil is now like compressed spring. So with the appropriate trigger event there will be
a strong bounce if only because of short squeeze.
We now also can say that all those shale/tight oil propagandists (including EIA) and financiers
did a very bad service for the country. The bet was that the price will go above $100 and stay
above it forever. Now they are losing tons of "other people money" along with the destruction
of the US oil infrastructure including conventional wells, as well as oil industry employment.
Which is especially sad.
When I am thinking how many people lost jobs because of this crazy and generally unnecessary
and harmful for energy conservation efforts price slide I became really angry at Obama administration.
They have had money to save banks in 2008, but no money to help the US oil industry in 2015-2016.
They definitely could buy oil for the US strategic reserve on a monthly basis. At this price level
around half of it is essentially free, as you can sell the other half at high prices later. So,
in essence, it is like short to medium term loan which will be repaid with interest.
I still wonder who benefits from such low prices ( say, below $50 ) other then Wall Street
honchos. It's not the consumers as difference in gas prices is minimal and gas expenditures are
not that big part of a family budget in the USA. It's not even trucking companies and retailers
transporting Chinese goods from ports. Both are still shrinking. WalMart just announced that it
is closing 154 stores (http://www.foxnews.com/us/2016/01/15/walmart-to-close-154-stores-in-us-10000-workers-affected.html).
Even chemical companies are cutting personnel like crazy.
One interesting thing the emerged from this episode is that the laws of supply and demand does
not work in heavily indebted environment. Producers can't cut production despite the price dropping
below profitability because they need to pay interest on debt. Such a Catch 22.
BTW according to Reiter in the USA "onshore tanks are barely a third full, with less than 150
million barrels of the nation's total 439 million barrels of shell storage capacity occupied as
recently as October, according to a Reuters analysis of U.S. data." (http://www.reuters.com/article/us-oil-tanks-analysis-idUSKBN0KL0AZ20150112)
"Almost 40 percent of total tank farm capacity was leased to third parties as of last September,
up from a low of just 28 percent in 2012"
This is a bearish news. Somehow shale drillers managed to preserve the total amount of oil produced
despite negative cash flow.
Notable quotes:
"... There were 77 new wells producing (72 in Sep), while 93 new wells were spud (122 in Oct). These
newly producing wells do seem to have had a good first month on average. ..."
"... Still, the biggest surprise is that the decline in older wells ( 2 months) was not more – they
should typically decline by about 50 kbo/d per month (for the front month), but in November they just
declined by 25 kbo/d. ..."
Total oil production is up in ND from 1171 kbo/d (Oct) to
1176 kbo/d (Nov). There were 77 new wells producing (72 in Sep), while 93 new wells were spud
(122 in Oct). These newly producing wells do seem to have had a good first month on average.
Still, the biggest surprise is that the decline in older wells (> 2 months) was not more
– they should typically decline by about 50 kbo/d per month (for the front month), but in November
they just declined by 25 kbo/d.
I suspect that the reason is, as Lynn Helms mentioned during the webcast last month, that operators
tried to produce as much as possible before the feared OPEC meeting early December. There was
a similar low decline in older wells the month before (Oct), while the decline was above 50 kbo/d
in every earlier month this year, except in May (30 kbo/d).
Below a graph that shows this. The difference between the green and red line represents the
total growth/decline of oil production in ND.
If this interpretation is correct, we may see bigger declines in the following months.
"... At a packed town hall meeting yesterday, it was VERY clear. The public wants all of the disposal
wells shut down immediately. Lawsuits are being filed as fast as the attorneys are able to file them.
If an oil executive had been there, it would have been like the old western movies with the mob scene:
"let's hang-em!" ..."
I believe that Shallow Sand referred to this a few weeks ago. Maybe everyone does not know, but
Oklahoma has gone from one of the least earthquake prone areas in the country, to the MOST earthquake
prone area in the entire world in the last 5 years. Earthquakes are now significantly impacting
populated, wealthy, heavily Republican suburbs just north of OKC. Since the first barrel of oil
came out of Oklahoma over 100 years ago, salt water has also come up that has to be disposed of.
It is now coming up at more than 10 bbl of salt water for every bbl of water. This is being reinjected
back into the ground in disposal wells. Fracking has brought more production and more salt water.
Billions of gallons are being reinjected each year. The salt water disposal wells [but, not fracking]
have been linked to the earthquakes by the USGS.
At a packed town hall meeting yesterday,
it was VERY clear. The public wants all of the disposal wells shut down immediately. Lawsuits
are being filed as fast as the attorneys are able to file them. If an oil executive had been there,
it would have been like the old western movies with the mob scene: "let's hang-em!"
Of course, the problem is that our salt water is like brine – 10 times as much salt as sea
water. Not easy to figure out what else to do with it. The largest element of Oklahoma's economy
is the oil and gas industry.
Oklahoma is the only state in the nation where in both 2008 and 2012, not a single county voted
for Obama. But, they are ready to change if the the earthquakes do not stop. The legislative representatives
promised early action to pass a law, in the first week of the session that starts February 1,
if possible, to give the state Corporation Commission the power to shut them all down, at least
for a short period of time to monitor for changes in the earthquakes.
So, back to Shallow Sand and operating expenses. It would be reasonable at this point to
expect an immediate adverse effect on oil production in most of the state. At a minimum, even
with just tinkering, it is going to become MUCH more expensive to dispose of the salt water. This
is going to push a lot of people over the edge – possibly including Sandridge which has been delisted
and is trading pink sheets at $.06/share.
"... In the wake of the collapse in oil prices over the past year, BHP has sharply cut its operating costs and capital spending at its U.S. onshore operations, reducing the number of rigs from 26 to five. ..."
"... previous management significantly overpaid for these assets ..."
In the wake of the collapse in oil prices over the past year, BHP has sharply cut its
operating costs and capital spending at its U.S. onshore operations, reducing the number of rigs
from 26 to five.
... ... ...
BHP previously booked impairments on its U.S. onshore assets of $2.8 billion in 2012 and a
further $2.8 billion in 2015, due to sliding gas prices and the lower-than-expected quality of
one of the fields it acquired.
"For some time, the market has been of the view that previous management significantly
overpaid for these assets," Lyons said.
BHP's shares, which sank to a 10-1/2 year low this week, jumped 5 percent on Friday, in line
with other miners in what is seen as an oversold market.
... The argument that the U.S. dollar is a flawed currency is
gaining ground. According to
commodity guru Jim Rogers, this is illustrated by a string of
Quantitative Easings by the U.S. Fed, an ultra-low interest rate
policy and ever-increasing U.S. debt. Demand for the U.S. dollar
has remained high despite this because of the world's reliance on
it to fund crude oil purchases.
But this paints a false picture.
Over the past few years, countries such as China, Russia, Iran,
and Brazile, Russia, India, and China, and South Africa (the BRICS
nations) have begun to pose
a challenge to the current system, forming pacts to transact
oil in local currencies, bypassing the petro-dollar.
So are we witnessing the beginning of the end of the
petro-dollar? Not quite yet.
The U.S. has dealt with all earlier challenges to its
petro-dollar system with a strong hand. A key reason for the wars
in Iraq, Syria, and Libya, was in response to an attempt to find an
alternative to the petrol-dollar. With China and Russia leading the
most recent attack on the U.S. dollar throne, the battlefield is
moving to a new and much broader front.
The U.S. and Russia are already engaged in proxy wars in the
Gulf region, but any escalation or a direct altercation could sow
the seeds of a dreaded WWIII.
... shale regions in the U.S. will drop by 116,000 bopd in February, contributing to a drop of
about 640,000 bopd since the end of last March, according to the U.S. Energy Information Administration.
That's more oil than either Ecuador or Libya produced last year on average.
"We're really starting to hit the steepest part of the decline curve," said Christopher Kopczynski,
a senior analyst for Wood Mackenzie Ltd. in Houston. "There's a lot more that the U.S. will contribute
to bringing barrels off the market."
Shale production has dropped as crude prices collapsed amid a global supply glut, causing drilling
companies to idle 64% of the oil rigs that were in service a year ago. West Texas Intermediate crude,
the U.S. benchmark, fell $1.75 to $31.41 Monday on the New York Mercantile Exchange, the lowest settlement
since Dec. 5, 2003.
The biggest projected decline is in the Eagle Ford in south Texas, where output is expected to
drop 72,000 bopd to 1.15 MMbopd, according to the EIA. The Bakken in North Dakota will lose 24,000
bopd to 1.1 MMbopd. The Permian basin in west Texas will boost production to 2.04 MMbopd.
Kopczynski said U.S. production will fall by another 500,000 bopd as output from existing wells
declines and fewer new wells come online to replace it. The biggest declines happen soon after a
well is tapped, though, so by the end of this summer the production curve should flatten out, and
the U.S. could begin to increase production in 2017 even with a low rig count, he said.
"... A half a million barrels WOULD be enough to influence prices. An individual company does not
expect its OWN production to influence the market price- unless maybe the company is a REALLY big one
maybe. If any given company drills say fifty such wells, that would be only twenty thousand barrels
a day, maybe less- most definitely not enough to move the market price needle. ..."
"... What you say may make sense of you are using cash and have little to no debt. It may make sense
for ExxonMobil. Most LTO companies dont have cash. Most have a gob of debt. I dont think sinking cash
into wells that will generate $0 revenue for a year or two is a good idea, especially given the financial
shape LTO is in already. ..."
"... There is no sense in drilling but not completing wells, especially as they are spending borrowed
money. ..."
"... When any company in any industry runs cash flow negative, one of two things inevitably occurs
… they get better or they get gone. ..."
"... In the US unconventional field, the get gones are lining up at the exit doors with their list
of assets to sell to the get better, who are in the process of emerging from this downturn with a ferocious
degree of resilience that will shock many, especially the far off be-robed sheiks who will be fortunate
to not have their own heads lopped off as well as worldwide ideologues pining for an emergence of their
inner peasants (h/t to Fernando for that apt phrase). ..."
Their well, one of hundreds drilled by Anadarko Petroleum in eastern Colorado's Wattenberg
field this year, could someday gush as many as 800 barrels of crude oil a day. But Anadarko is
not planning to produce a drop of crude from the well for at least another year because the price
of oil is now so pitifully low.
The well here is just one of more than 4,000 drilled oil and natural gas wells across the country
producing nothing, but ready to be tapped quickly……….
But the incomplete wells are also another reason many analysts say a recovery in the oil price
is nowhere in sight. Together the well backlog could produce as many as 500,000 barrels of oil
a day, about the same amount of oil that Iran is expected to add to the glutted global market
after it complies with the recent nuclear deal by the end of next year.
Some analysts say oil companies like Anadarko, EOG Resources and Continental Resources may
collectively risk suffocating the very price revival they anticipate by releasing abundant new
supplies once prices inch up. Others say the eventual impact would be small and short-lived, but
since the industry has never used this strategy before, no one can be sure……….
On the completion side, fracking crews are easier to come by and their contracts tend to
be more fluid. Now those completion costs have also come down - meaning that the uncompleted wells
will eventually be brought on line at a lower cost, executives say.
If you have or can raise the cash, it makes sense to drill now and produce a year or two down
the road-IF you believe prices will be up. According to what I read here, the costs of drilling
a well may be down by a third, due to so many men and machines and so much steel and sand etc
, "looking for a home".
I don't know if this is "one third off" drilling sales event is totally for real, it might
be only a quarter or a fifth off. Hopefully somebody who crunches tight oil numbers will have
something to say about it.
Tight oil production brought on by drilling now and producing later is not going to noticeably
affect the price later.
Tight oil production brought on by drilling now and producing later is not going to noticeably
affect the price later.
By what logic did you arrive at that conclusion?
The article states: But the incomplete wells are also another reason many analysts say a
recovery in the oil price is nowhere in sight. Together the well backlog could produce as many
as 500,000 barrels of oil a day, …
Now I think an extra half a million barrels per day would noticeably affect the price.
A half a million barrels WOULD be enough to influence prices. An individual company does not
expect it's OWN production to influence the market price- unless maybe the company is a REALLY
big one maybe. If any given company drills say fifty such wells, that would be only twenty thousand
barrels a day, maybe less- most definitely not enough to move the market price needle.
It's not the industry as whole, but individual companies that make the decision.
What you say may make sense of you are using cash and have little to no debt. It may make
sense for ExxonMobil. Most LTO companies don't have cash. Most have a gob of debt. I don't think
sinking cash into wells that will generate $0 revenue for a year or two is a good idea, especially
given the financial shape LTO is in already.
Also, the entire premise is that there will soon be a steep rise in the price of oil. That
is a total crap shoot.
So they are strictly gambling that oil prices will rise steeply in the next couple years? Is
that a good business strategy for multi-billion dollar corporations to undertake, especially when
the futures market says otherwise?
Ask Harold Hamm how easy it is to predict the future price of oil.
Assuming 4,800 operated wells, by my math the average well is producing 23 barrels of oil and
112 mcf of gas per day, gross.
Assuming 25% royalty burden, and remembering the basis spread in CO for both oil and gas is
horrible, it looks like GROSS revenue per well at current price would be in the neighborhood of
$200K per year.
I keep begging, and will again. Someone come on here and explain how drilling, but not completing
13,000′ horizontal wells that won't cum. 100,000 BO in 40 years makes one lick of sense?
When any company in any industry runs cash flow negative, one of two things inevitably
occurs … they get better or they get gone.
In the US unconventional field, the 'get gones' are lining up at the exit doors with their
list of assets to sell to the 'get better', who are in the process of emerging from this downturn
with a ferocious degree of resilience that will shock many, especially the far off be-robed sheiks
who will be fortunate to not have their own heads lopped off as well as worldwide ideologues pining
for an emergence of their 'inner peasants' (h/t to Fernando for that apt phrase).
As for future reserves, see my response below to shallow re the Riverview well, and apply the
principal to hydrocarbon bearing shales and 'tight rocks' on a global scale.
"... The rig count continues to fall sharply in these plays and that will keep undermining the levels of shale production in months to come. ..."
"... The experts say that there are a million barrels per day of stripper well production that just isnt economic at todays prices but folks are reluctant to shut in the oil well in their back yard ..."
"... But for sure U.S. shale is declining, it is already down by 640,000 barrels per day from its peak in March 2015. It seems likely that these four regions will be producing about 4.1 to 4.2 million barrels per day by the end of year... ..."
...
The rig count continues to fall sharply in these plays and that will keep undermining
the levels of shale production in months to come.
...
The experts say that there
are a million barrels per day of stripper well production that just isn't economic at today's prices
but folks are reluctant to shut in the oil well in their back yard
and I suspect that will remain
sticky for a few months to come, and of course there should be some natural decline in these conventional
plays. Counterbalancing that trend there are a number of big offshore projects scheduled to start
up in the third and fourth quarters of 2016 so the "Other" line might actually rise.
But for
sure U.S. shale is declining, it is already down by 640,000 barrels per day from its peak in March
2015. It seems likely that these four regions will be producing about 4.1 to 4.2 million barrels
per day by the end of year...
"... Eagle Ford crude oil production declines 30% year over year and will fall below 1 mill bbl/d by spring 2016 and by late summer 2016, production will be likely around 0.5 mill bbl/d. ..."
January EIA Drilling Report came out and confirms the steep decline of US shale production (see
below chart).
Eagle Ford crude oil production declines 30% year over year and will fall below
1 mill bbl/d by spring 2016 and by late summer 2016, production will be likely around 0.5 mill
bbl/d.
As legacy declines are still very steep in Eagle Ford and Bakken, shale oil production
is on track to be around 2 mill bbl/d lower by fall 2016.
This will finally pave the way
for a price recovery during the end of 2016.
"... Third, unless existing production drops to less than 85% of its 2015 level, which is the amount the author says is hedged, the barrels from new (2016) production will be unhedged, and sold at the market, which is currently around $30 for oil for PXD. ..."
"... Fourth, does PXD think $52 or below is the best they can do in the next several years? ..."
"... I agree PXD is better hedged than most. But there are some issues. ..."
"... The final problem is that all of these shale guys are forgetting how much perception is driving the crude market. The bankers are screaming to the shale guys, "do not grow supply until the market balances.". The shale guys are ignoring, thus the price of crude continues to sink like a stone thrown in the deep end of the pool. And the pool apparently is pretty freaking deep. ..."
"... Conventional is cutting production, they can't and/or won't do what shale is doing because they are playing with their own money. ..."
"... How many shale CEO's and upper management took a pay cut in 2015? How many Chapter 11's are resulting in the same management keeping their jobs? ..."
"... Drilling now is really a lot about ego and impressing a bunch of young, macho analysts. I can attest to the ego part. I have seen it first hand. ..."
"... I have never owned or even been in Gulfstream, nor have I done much of the other extreme stuff these shale guys have done. They are true gamblers, wouldn't be where they are if they weren't. So I am not surprised they will ride it to the bitter end, even keep drilling at $10 WTI. But it is tough not to be upset about it. ..."
"... On a further note, I read where PXD says the $2.5 billion of 2016 CAPEX will grow production 20-25,000 BOEPD. So, clearly not cheap. ..."
Except that aren't hedges and drilling programs separate profit and loss centers?
Or, to put it another way, the question is, how do they deploy the profits from hedges against
falling oil prices? Apparently, they decided to put the profits from hedges, plus additional new
capital and cash flow from operations, into drilling.
I ain't buying it, Greenbub. First off, the author transposed a number when he attempted to show
how much net income would be derived in year one, after figuring in the hedges.
Secondly, I believe he ignored royalties. Does PXD drill a fee acreage.
Third, unless existing production drops to less than 85% of its 2015 level, which is the
amount the author says is hedged, the barrels from new (2016) production will be unhedged, and
sold at the market, which is currently around $30 for oil for PXD.
Fourth, does PXD think $52 or below is the best they can do in the next several years?
Unless it is, shouldn't they just wait a little while, absent lease requirements of course? If
I am sitting on a 1000′ location that I am sure will cumulative net to me 30K bold in year one,
and it costs me $70K to D &C, yes, I will get a quick payout, but I could be foregoing $150K if
we get a spike in a year or two. That makes some assumptions that we really can't make, but you
get the drift.
I agree PXD is better hedged than most. But there are some issues.
The final problem is that all of these shale guys are forgetting how much perception is
driving the crude market. The bankers are screaming to the shale guys, "do not grow supply until
the market balances.". The shale guys are ignoring, thus the price of crude continues to sink
like a stone thrown in the deep end of the pool. And the pool apparently is pretty freaking deep.
Conventional is cutting production, they can't and/or won't do what shale is doing because
they are playing with their own money.
How many shale CEO's and upper management took a pay cut in 2015? How many Chapter 11's
are resulting in the same management keeping their jobs?
Obviously, a mom and pop cannot file a Chapter 11 that would be confirmed, at least few could.
They will have to go the liquidation route. So, instead, mom and pops will shut in, and try to
wait it out like in 1986 and 1998-99. Lots of issues with that approach, but it is usually mom
and pops only choice. Get a job in town, pump the wells on the weekends.
Drilling now is really a lot about ego and impressing a bunch of young, macho analysts.
I can attest to the ego part. I have seen it first hand.
Its kind of like HH making fun of OPEC, the "toothless tiger" comment. OPEC saved HH bacon
when they cut in March, 1999. They saved it again with the cuts in 2008-2009.
I have never owned or even been in Gulfstream, nor have I done much of the other extreme
stuff these shale guys have done. They are true gamblers, wouldn't be where they are if they weren't.
So I am not surprised they will ride it to the bitter end, even keep drilling at $10 WTI. But
it is tough not to be upset about it.
Simple analogy. Me driving 5 year old paid for generic truck. Neighbors all around borrowing
$70K for the latest tricked out model, on 96 month loan.
Hey, what the shale boys are doing is the American way. OPEC doesn't understand the American
way, thus the $1 trillion they are/will be short in oil revenues in 2015-16.
On a further note, I read where PXD says the $2.5 billion of 2016 CAPEX will grow production
20-25,000 BOEPD. So, clearly not cheap.
Since we are at 2003 oil and even lower than 2003 natural gas and liquids levels, with higher
OPEX, tell me who in 2003 was spending that kind of money to increase production by that small
amount? I bet no one. Those extra 20-25K boepd will be sold at 2003 levels, should they persist.
And onto perception, should the fact that PXD is going to grow production by 20-25K boepd make
a shred of difference to the crude oil market? No, but by golly look at what Goldman is saying
about it, and the crude price dropped 10% in a week.
For that matter, no one expected an OPEC cut, inventories appear the same as 12/4/15, yet we
have lost around 25% since OPEC said no cut. Its all a perception trade.
Long ago I said shale should have came out the week after Thanksgiving and told the truth,
this business isn't a growth business below $75 WTI. We are going to defer until we rebound. It
would have put lots out of work immediately, more than were actually let go, but a drop below
8 million bopd by now would have done the trick, Saudi would have been impressed and maintained
at 9.6. We might be at $80 and might have companies in better shape.
I guess US onshore conventional needs to die. That seems to be the message.
Shallow, you are much wiser than me in these affairs, but if you are hedged well and expecting
a dramatic turnaround in prices, this is what to do. Also retains your workforce. Question is
the timing of the turnaround.
"On a further note, I read where PXD says the $2.5 billion of 2016 CAPEX will grow production
20-25,000 BOEPD. So, clearly not cheap."
Assuming 25,000 bbl/day and that this increase in production will last for five years after
capex "injection" you need $54.79 bbl "net" to break even without interest payments. Given the
rate of decline of fracked wells, five years is a pretty optimistic assumption. This makes sense
only if they expect return to $70-80 price range in late 2016 and $100 thereafter.
In a way Pioneer no longer should be viewed as an oil producing company but as a hedge fund
with a side oil production business and as such belongs more to Wall Street then to the shale
patch.
Also they need to be well connected with major financial players as to refinance notes for
a shale company now is not that easy. This is essentially a vote that the company will exists
in 5 years. Mutual funds like Vanguard probably will no longer participate despite their Baa3
(Placed on Review for Downgrade) Moody rating.
"... Hedging has been a crucial part of PXDs strategy all along. Looking at the Q3 EPS report, we can see the company earned net income of $4.27/share despite the very low average oil price of $42.46/bbl. This is due in large part to the strong hedging program in place throughout the quarter. ..."
"... Lots of debt looking at balance sheet and if Oil stays lower for 1 more year liquidity problems will arise, ..."
First off, let's take a closer look at the recent Senior Note offering, which
consisted of:
$500 million of 3.45% Senior Notes maturing in January 2021.
$500 million of 4.45% Senior Notes maturing in January 2026.
Considering the current market environment, those are some very attractive rates. Even better,
management said it will use the proceeds to repay or repurchase Pioneer's 5.875% Senior Notes due
2016 and/or its 6.65% Senior Notes due 2017.
... ... ...
Hedging has been a crucial part of PXD's strategy all along. Looking at the Q3 EPS report,
we can see the company earned net income of $4.27/share despite the very low average oil price of
$42.46/bbl. This is due in large part to the strong hedging program in place throughout the quarter.
21793061
I don't think speculating on price makes much sense. Companies should base their decisions off
of the strip. Of course with some time element (planning and the like) meaning that they can't
change plans every time it drops or goes up a dollar. But definitely planning off the strip as
of the time of their plan.
To the extent that their is a learning curve that stays in house or that there is critical mass
or key infrastructure (e.g. the water gathering) that lowers cost, than perhaps the PXD strategy
makes sense.
I really get the impression that have sweet rock and had a reasonable strategy when oil was at
$45 (and strip going up). That is a far cry when the prompt month is down $10 and the strip down
$5. There becomes a point where they have to back off the drilling plan or face a danger of exhausting
their cash to early (and of drilling negative NPV projects).
I don't care about the dilution as such. It's the use of the cash that is in question.
The hedges don't justify drilling negative NPV wells. that is silly talk and you should know better,
Mike. They can sell those hedges or if need be, buy crude on the market for physical delivery.
They are just a financial option and are in the money. But that doesn't justify drilling a well
or not.
shallow sand
In your article you may have made an error. You go from $52.41 to $54.21 with regard to the
1/8/16 hedged oil price.
Also does PXD obtain WTI price per barrel in the Permian, or is there a discount?
Also, you did not mention royalties. How does that factor in. I assume not all acreage is fee.
What is the royalty burden?
They still have four rigs running in EFS, how does this factor into your calculations?
Also, I wonder about NPV on these wells. So, assume we factor in the hedges and then use the
strips as quoted on the CME website for oil, natural gas and NGLs.
What is PV10 for the representative well?
Have you seen any lease operating statements for any of these wells? How much water do they
make, what kind of disposal system do they have?
Isn't the growth in produced oil sold at the market? The CAPEX program calls for same increasing
companywide BOEPD 20-25K. Since volumes currently are hedged less than 100%, why should we not
use the strip for any production in excess of that hedged?
I'm very curious about all of the above. Full disclosure, I am biased against LTO given it
has rained on my family's parade, which commenced in 2004 and ended on Thanksgiving 2014, a day
which will live in infamy to ever stripper well owner in the United States.
Sorry if this comes across as rude, I am not aiming at anyone really. Just frustrated to be
operating in the red at $28 in the field, with chemical 3x 2003 prices and electricity 70% higher
than in 2003 as well. Add in higher wages, worker's comp., health insurance premiums, all other
premiums of insurance, etc., its not pretty.
I do not recall anyone spending $2.5 billion to increase production 25K boepd in 2003, nor in
early 2005 when WTI was in the high 50s to low 60s. How is the financial aspect different now?
As I recall, low decline production was selling for $15-20,000 per barrel in 2003 with LOE of
$10-15 per barrel. Why is PXD's worth over $100K, given half is gas and NGLs, the hedges are only
through 2016 and the decline is steep. Must be oil is headed back to $90 soon, yes we have nothing
to worry about.
I will agree that among LTO, PXD is a standout. Just not much $$ to be made in LTO at $33 or
even $53 WTI, IMO, even if you are a standout.
Gayle Gregory Goodman
Lots of debt looking at balance sheet and if Oil stays lower for 1 more year liquidity
problems will arise,
JD TX
All very good points. My premise for a buy of an oil company would be the assumption (hence
where things could go wrong) that oil prices would not stay this low into 2017 and beyond. I know
these cycles can last years, however there is not seeming to be a massive global slowdown in demand.
Assuming demand stays steady (again, another assumption for my premise) and all countries with
their pumps wide open, it seems to me that as current wells decline (some rapidly) and absence
of sector exploration investment that oil should head much higher after the bottom is found. Add
in a geopolitical rift and this happens sooner.
I want to capitalize on the current decline and was looking at Exxon and Shell, but I
feel that their downstream success has kept the stock prices at too much of a premium. I think
(based on my possibly dangerous assumptions) that a company like pioneer who is growing their
barrels per day when everyone else is relying on declining wells could offer more upside to increasing
crude prices than a company with larger downstream operations. Thoughts?
cschwab
In your view, How does one important fact affect your conclusions? That the company sold short
puts at $46.08, which I believe means the company has to pay if oil is below that threshold. Therefore,
the $19.12 the company receives is reduced by the amount by which oil falls below $46.08. As an
example, if oil falls to $33, then the company's hedges result in the company earning on those
barrels that are hedged: $33+$19.12-13.08= $39.04. (If oil falls to $27, the company earns $33.04/barrel
that is hedged, the same as being unhedged)
Pablomike
That goes right to my question. In a perfect world for Pioneer wouldn't it be best if oil rebounded
to just under the short put; like $44-$45???
I thought the straight swaps were actually better. The difference between Avg. price for the Q
and $71.18 -$42.46 =$28.72. Better than the $19.22 gained on the 3-way.
Michael Fitzsimmons,
Author's reply " Hello cschwab: as pointed out in the article, with WTI at $33.19/bbl, and
supposing it stays there throughout 2016, we have the case where that NYMEX price ($33.19/bbl)
is less than the short put price ($46.08/bbl). In this case, Pioneer will receive the NYMEX price
($33.19/bbl) plus the difference between the put price ($65.30/bbl) and the short put price ($46.08/bbl),
or $33.19 + $19.22 = $52.41/bbl.
The way the 3-way collars work is explained in the fine print at the bottom of slide 23 and
further on slide 26 of the December presentation I referenced in the article. Thx for reading.
"... After last week's moderate drop in rig count, the amount of horizontal oil rigs seems to implode this week. The U.S. land rig count was down 37 this week and the land horizontal rig count was down 30. Is this capitulation? Hard to say but it's the biggest drop since March 2015. ..."
"... The tight oil horizontal rig count was down by 20 and the key Bakken-Eagle Ford-Permian HRZ rig count was down by 14. ..."
After last week's
moderate drop in rig count, the amount of horizontal oil rigs seems
to implode this week. The U.S. land rig count was down 37
this week and the land horizontal rig count was down 30. Is this capitulation? Hard to say but it's the biggest drop
since March 2015.
And, the Fayetteville Shale play officially bit
the dust this week with zero rigs for the first time since the play
began in 2005.
The tight oil horizontal rig count was down by 20 and the key
Bakken-Eagle Ford-Permian HRZ rig count was down by 14.
The Bakken
lost 3 rigs, the Eagle Ford, 4, and the Permian, 7.
Shale gas lost 8 HRZ rigs. The Haynesville lost 2, the
Marcellus, 6, the Utica 1, the Fayetteville, 1. The Woodford and
Barnett each gained 1 rig.
"... The collapse of oil prices has forced drillers to become more efficient, adding more wells per well pad, drilling longer laterals, adding more sand per frac job, etc. That allowed companies to continue to post gains in output despite using fewer and fewer rigs. ..."
"... However, the efficiency gains may have been illusory, or at best, incremental progress instead of revolutionary change. Rather than huge innovations in drilling performance, companies were likely just trimming down on staff, squeezing suppliers, and drilling in the best spots – perhaps all sensible stuff for companies dealing with shrinking revenues, but nothing to suggest that drilling has leaped to a new level of efficiency. Reuters outlined this phenomenon in detail in a great October 21 article. ..."
"... drilling productivity flat lining in the Bakken, the Eagle Ford, and the Permian. ..."
Much has been made about the impressive gains in efficiency and productivity in the shale patch,
as new drilling techniques squeeze ever more oil and gas out of new wells. But the limits to such
an approach are becoming increasingly visible. The U.S. shale revolution is running out of steam.
The collapse of oil prices has forced drillers to become more efficient, adding more wells
per well pad, drilling longer laterals, adding more sand per frac job, etc. That allowed companies
to continue to post gains in output despite using fewer and fewer rigs.
However, the efficiency gains may have been illusory, or at best, incremental progress instead
of revolutionary change. Rather than huge innovations in drilling performance, companies were likely
just trimming down on staff, squeezing suppliers, and drilling in the best spots – perhaps all sensible
stuff for companies dealing with shrinking revenues, but nothing to suggest that drilling has leaped
to a new level of efficiency. Reuters outlined this phenomenon in detail in a great
October 21 article.
For evidence that the productivity gains have run their course, take a look at the latest
Drilling Productivity
Report
from the EIA. Production gains from new rigs – which have increased steadily over the
past three years – have run into a wall in the major U.S. shale basins. Drillers are starting to
run out of ways to squeeze more oil out of wells from their rigs. Take a look at the below charts,
which show
drilling productivity flat lining in the Bakken, the Eagle Ford, and the Permian.
Shale drillers run out of places to cut. Now shale companies played all their best cards. there
is almost no scope for further production price reduction but the current price is so low that each
barrel is produced at a loss. Essentially debt keeps then by the throat and force to produce barrels
at a loss: as of December 2015, the US oil production remained within 4% of a 43 years high. But the
decline of oil prices below $50 is devastating for shale drillers financially and it is unclear how
long they can survive in such a mode. "Sweet spots" are running out.
Notable quotes:
"... While technological and efficiency improvements may continue gradually, oil company renegotiations with contractors are essentially done, and so is the rapid shift to focus only on core areas. ..."
"... ... Most companies have gone into shrinkage mode, saying their goal is to stay flat and make it through this market, Raoul LeBlanc, an analyst with IHS Inc. in Houston, said. The current price is unsustainable. ..."
About $99 billion in face value of high-yield energy bonds are trading at distressed prices, according
to Bloomberg Intelligence analyst Spencer Cutter. The BofA Merrill Lynch U.S. High Yield Energy Index
has given up almost all of its outperformance since 2001, with the yield reaching its highest level
relative to the broader market in at least 10 years.
... ... ...
"There is limited scope for further production cost reductions," Mike Wittner, head of oil-market
research for Societe Generale, said in a note to clients.
"While technological and efficiency improvements
may continue gradually, oil company renegotiations with contractors are essentially done, and so
is the rapid shift to focus only on core areas."
... ... ...
... "Most companies have gone into shrinkage mode, saying their goal is to stay flat and make it through
this market," Raoul LeBlanc, an analyst with IHS Inc. in Houston, said. "The current price
is unsustainable.
Unfortunately, we have to sustain it for a while longer."
"... So, a massive loss, and still CAPEX is 150% of total revenue. Their wells are worse than the average Niobrara well, I think they will do on average probably less than 120 kbo (stated EURs are 350kboe – 750 kboe) , and have an average life of about 5 years. ..."
"... So this thoroughly loss-making operation is completely funded by investors . It really makes you wonder who is buying into this. Oh, and the CEO just left. ..."
Synergy Resources just released their Q1 for FY 2016. I think you will find it interesting
(in $m for the quarter):
– revenue : 26
– total expenses (excl impairment) : 36.4 (incl GA of 14 )
– impairment : 125
– total loss : -135
– well costs & other capex : 39 (excl acquisition capex of 35)
So, a massive loss, and still CAPEX is 150% of total revenue. Their wells are worse than
the average Niobrara well, I think they will do on average probably less than 120 kbo (stated
EURs are 350kboe – 750 kboe) , and have an average life of about 5 years.
They don't have much debt, but doubled the outstanding share count over the last 3 years, and
just increased the authorized # of shares by another 50%. In 2015 they already increased the share
count by 35% (stock issued at 10.75, which is now just above 7).
So this thoroughly loss-making operation is completely funded by "investors". It really
makes you wonder who is buying into this. Oh, and the CEO just left.
Important info: r
ig efficiency has more than doubled compared with a couple of years ago, and
is about 50% higher than just a year ago. It's not enough to keep production up, but it helps.
Notable quotes:
"... Net Cash Flow math is actually quite similar to Net Oil Export math, to-wit, given an ongoing decline in gross cash flow from production sales, unless total costs (lease operating expenses plus G A overhead) fall at the same rate as, or at a faster rate than, the rate of decline in gross cash flow, the resulting rate of decline in net cash flow will exceed the rate of decline in gross cash flow and the rate of decline in net cash flow will accelerate with time. ..."
"... This implies a tremendous mismatch between remaining cumulative net cash flow and debt levels (especially for tight/shale players). ..."
"... rig efficiency has more than doubled compared with a couple of years ago, and is about 50% higher than just a year ago. Its not enough to keep production up, but it helps. ..."
"... a further rig count drop may be more noticeable, as we then may see also the high-powered rigs leaving. During the last webcast in December, Helms mentioned that there were 65 rigs drilling, but that in the first half of 2016 it could drop to 55. Currently with 57 rigs drilling, and 3 up for stacking, that may come sooner than he expected. ..."
"... As we can see from yours and Ciaran Nolans charts, there was only a very modest increase in average well productivity in the Bakken. So the key factor supporting output levels was more efficient drilling: more wells per rig ..."
...a reasonable estimate is that the US oil industry had to put on line about 0.25 million
bpd of new C+C production in 2008, just to offset declines from exiting wells, whereas they probably
now have to put on line somewhere around 1.4 million bpd of new C+C production per year, just
to offset declines from existing wells.
"It is these companies which find themselves inside this toxic feedback loop of declining liquidity,
which forces them to utilize assets even faster, thus even further shrinking the borrowing base
against which their banks have lent them money, that will be at the forefront of the epic bankruptcy
wave that is waiting to be unleashed across the US.
Net Cash Flow math is actually quite similar to Net Oil Export math, to-wit, given an ongoing
decline in gross cash flow from production sales, unless total costs (lease operating expenses
plus G&A overhead) fall at the same rate as, or at a faster rate than, the rate of decline
in gross cash flow, the resulting rate of decline in net cash flow will exceed the rate of
decline in gross cash flow and the rate of decline in net cash flow will accelerate with time.
This has "Interesting" implications for the remaining cumulative net cash flow from developed
producing properties. Of course, the gross cash flow from producing properties can decline
when (not if) that production declines and/or if the price declines.
This implies a tremendous
mismatch between remaining cumulative net cash flow and debt levels (especially for tight/shale
players).
Enno Peters,
01/06/2016 at 2:11 pm
Alex,
Exactly. This is why the # wells drilled has fallen off much slower than the rig count. See
the graph from ND, which shows the rapid increase in efficiency over the last months, as less
efficient rigs/crews/methods were dropped:
rig efficiency has more than doubled compared with
a couple of years ago, and is about 50% higher than just a year ago. It's not enough to keep production
up, but it helps.
I think it also means that
a further rig count drop may be more noticeable, as we then may see
also the high-powered rigs leaving. During the last webcast in December, Helms mentioned that
there were 65 rigs drilling, but that in the first half of 2016 it could drop to 55. Currently
with 57 rigs drilling, and 3 up for stacking, that may come sooner than he expected.
AlexS,
01/06/2016 at 2:25 pm
Thank you, Enno.
As we can see from yours and Ciaran Nolan's charts, there was only a very modest increase in
average well productivity in the Bakken. So the key factor supporting output levels was more efficient
drilling: more wells per rig
BTW, many thanks for your excellent post on refracking in ND!
"... Price per barrel should reach $100 shortly after most of the shale players are out of money or bankrupt. ..."
"... The vulture capital money is waiting in the wings to buy up the better assets for pennies on the dollar. Brand new, debt-free companies will be formed and they will be ready to go public just as the price of oil starts to rise. Rinse and repeat. ..."
"... Most of those folks who invested in shale drillers when oil was around $100 a barrel lost most of their investment. ..."
"... Public or private, the pricing must be absolutely crushing. ..."
"... I wish the bankruptcies would hurry up because the paranoid corner of my brain tells me that when the almighty money almagamations like the Carlyle Group swoop in and buy up all the distressed assets, we just might see oil prices rebound. The vultures wont have the motive to short the heck out of oil, like they are now. ..."
"debt fueled financing boom in the shale space will most likely never return."
As a result, the industry will likely move to self-funding capital expenditures through free
cash flow generation in an attempt to significantly reduce its reliance on leverage. Debt levels
will initially have to be reduced, significantly fueling a cycle of dramatically lower capital
expenditures and consolidation. This process is already underway, but still has a long way to
go."
Price per barrel should reach $100 shortly after most of the shale players are out of money
or bankrupt.
Arceus
, 01/05/2016 at 4:32 pm
OFM said: "There will be plenty of money available to put the tight oil industry back on its
feet when prices get high enough."
Yes, that is true.
The "vulture capital" money is waiting in the wings to buy up the better
assets for pennies on the dollar. Brand new, debt-free companies will be formed and they will
be ready to go public just as the price of oil starts to rise. Rinse and repeat.
There will be plenty of money available to put the tight oil industry back on its feet when
prices get high enough to generate profits. If the banks won't loan to the industry, people
with money will finance it personally.
Don't be too sure about that.
Most of those folks who invested in shale drillers when oil
was around $100 a barrel lost most of their investment.
If oil gets high again, what guarantee
will investors have that oil prices will not collapse again? Once bitten, twice shy.
The difference this time is that private equity will be buying prime assets at the bottom of a
commodity cycle that is essentially a turn-key operation with experienced management in place
and with hundreds of drilled but uncompleted wells. They'll make a killing, I imagine, then go
public.
Just a few days ago, Hilcorp – one of the more successful, privately owned E&P companies – just
entered into a partnership of sorts with the Carlyle Group in order to acquire assets.
Carlyle is putting up one and a quarter billion bucks and Hilcorp will be providing the operational
expertise.
In addition to just dispensing $100,000 bonuses to each of its several thousand employees,
Hilcorp is somehow managing to operate profitably in the northwest corner of the Pennsylvania
… something pretty much unheard of.
Arceus,
01/05/2016 at 5:07 pm
I have heard, and perhaps you can verify, that the typical privately owned e&p companies have
far superior assets to the typical small-cap, publicly traded e&p company.
coffeeguyzz,
01/05/2016 at 5:32 pm
Arceus
Sorry, don't know too much about that end of this business.
Public or private, the pricing
must be absolutely crushing.
shallow sand,
01/05/2016 at 7:47 pm
I wish the bankruptcies would hurry up because the paranoid corner of my brain tells me
that when the almighty money almagamations like the Carlyle Group swoop in and buy up all the
distressed assets, we just might see oil prices rebound. The vultures won't have the motive to
short the heck out of oil, like they are now.
Keep in mind, just the paranoid part of me talking here, don't know to what extent I believe
this to be true.
Arceus,
01/05/2016 at 6:45 pm
Here is the money quote from Pioneer in explaining why they are doing a secondary offering
despite outperforming expectations: "Capital spending will range from $2.4 billion to $2.6 billion
this year, up from about $2.2 billion in 2015, in part because oil wells in the Permian Basin
in West Texas have outperformed expectations, Pioneer said in a separate statement Tuesday. In
other words, better production results means the company needs more money.
shallow sand,
01/06/2016 at 12:23 am
Need to eat a little humble pie re PXD. They are better hedged than most in 2016. They do have
some monster Sprayberry leases. Just can't tell how many wells are on those.
However, the additional barrels/mcf aren't hedged, so seems odd to dilute shareholders to grow
production past the volumes hedged.
In October 2015, the World Bank lowered its 2016 forecast for crude oil prices
from $57 a barrel to $52 a barrel, due in part to expectations that Iranian oil
exports would rise once international sanctions were lifted.
"Crude oil oversupply is still in play; however the deficit between demand
and supply is getting smaller," said Daniel Ang, an investment analyst at Phillip
Futures, in a note on Wednesday. "Possible changes to global supply should come
from the U.S. and Iran."
Iranian oil exports are widely expected to increase in 2016 as Western sanctions
against the country for its alleged nuclear weapons program are likely to be
lifted.
Still, a senior Iranian oil official said the country could moderate oil
output and exports once the sanctions are lifted to avoid putting prices under
further pressure.
"We don't want to start a sort of a price war," Mohsen Qamsari, director
general for international affairs of the National Iranian Oil Company (NIOC),
told Reuters in an interview.
"We will be more subtle in our approach and may gradually increase output,"
Qamsari said. "I have to say that there is no room to push prices down any further,
given the level where they are."
Before the sharp drop in oil prices, most LTO and shale gas producers were profitable, but only
a few of them were cash-positive is a sense that they had profits in the profit & loss account, but
their capex exceeded cashflow from operating activities. Now prices are $25 for oil and $1.75 for
gas. So even though well costs are way down, the wells wont payout. Mass extinction of
shale/tight oil players is expected if low prices stay for 2016. Huge damage to US oil
exploration and production infrastructure is also in cards. I don't think cash flow negative
oil companies are drilling to hold a lease. They are drilling because they would be
officially bankrupt if they stop. As long they are drilling extend and pretend game can continue for
a little longer. If banks are realistic, almost all LTO is insolvent and should not qualify for any
more debt. Given that none have significant cash, this should spell trouble.
When we see an oil and gas price recovery, and presumably an attempt to increase drilling and
completion efforts, one wonders how many service companies will still be in business, when E&P
companies start calling about drilling and completing new wells.
It seems to be an article of faith among most analysts that US oil & gas companies can increase
production on a very short notice, but I think that a point that almost all analysts are missing
is that the US rig count number in 2014 was the result of about a 10 year plus increase in US
Lower 48 service company infrastructure and personnel.
That service company infrastructure and personnel base, which took 10 years or more year to
build up, is fading away now, literally on a daily basis. And of course, as many people have pointed
out, it's going to be much, much more difficult for tight/shale players to get debt financing
going forward.
Also, the annual volumetric loss of production from existing wells, due to depletion, increases
as total production increases and we have also seen an increase in the annual volumetric loss
of production due to the huge increase in the underlying decline rate from existing wells. Let's
assume existing US wells lost 0.25 million bpd of C+C production in 2008 (5% of 5 million bpd).
At a 15% annual loss from a production base of 9.1 million bpd, the industry would have to put
on line about 1.4 million bpd of new C+C production every year, just to offset declines from existing
wells.
US drilling rig fleet is sufficient to support a significant increase in drilling activity. While
a number of older rigs were scrapped, most of the rigs are idled and ready to restart the work.
And, in general, drilling rig fleet is now much more efficient than 5-7 years ago.
Getting debt
financing should indeed be a big problem for shale players.
While debt levels are generally manageable, debt ratios are not too high, and most of the debt
is maturing beyond 2020, shale players need large amounts of new financing just to keep flat production.
Although banks have refinanced most of US E&Ps' credit facilities in 2015, they did not provide
new loans.
There was a lot of new bonds and equity issues in 1Q-2Q15, but this source of funding started
to dry up in the second half of the year as investors understood that low oil prices are likely
to stay for longer.
My guess is that even when oil prices start to recover, both shale players and their lenders will
be much more cautious than in the years of the shale boom.
LTO output is likely to recover, but its growth rates will be relatively modest (a few hundred
kb/d per year, rather than 1 mb/d on average in 2012-14).
And by the end of this decade we will likely see the effects of declining productivity in the
sweet spots.
We shall see. But a lot of equipment is rusting away and literally degrading on a daily basis,
inclusive of everything from drilling rigs to frac units to workover rigs. On the personnel side,
many people that have been laid off won't come back, and many older workers have retired, or are
retiring or passing away, or have become unable to work. In regard to field work, many of those
that do come back will have to be retrained and pass drug tests.
"US drilling rig fleet is sufficient to support a significant increase in drilling activity. While
a number of older rigs were scrapped, most of the rigs are idled and ready to restart the work.
And, in general, drilling rig fleet is now much more efficient than 5-7 years ago."
Totally
agree. Having gone through several "cycles" the mechanical part of any business is never a significant
constraint on a rebound. Any "restraint" is related almost entirely to financing with a small
component attributable to availability of skilled labor - which never lasts long. Even state of
the art offshore rigs can be assembled fairly quickly.
US Rotary Rig Count (oil & gas) Versus WTI Crude Oil Price Chart
Note that it took about five
years to go from around 1,000 rigs to around 2,000 rigs, circa 2003 to 2008, and it looks like
the rotary rig count, except for the 2009 "V" shaped oil and rig count crash, has been around
1,800 to 2,000, until the recent oil price decline, which is much more extended than the 2008
oil price decline (which bottomed out in December, 2008).
In any case, note that even during the "V" shaped decline in 2009 it looks like it took about
two years to get back to around 2,000 rigs, from a low of less than 1,000 rigs.
As noted above, a lot of rigs that were in dry gas plays, like the Barnett, moved to oil and
liquids rich plays, starting in 2008. As also noted above, a reasonable estimate is that the US
oil industry had to put on line about 0.25 million bpd of new C+C production in 2008, just to
offset declines from exiting wells, whereas they probably now have to put on line somewhere around
1.4 million bpd of new C+C production per year, just to offset declines from existing wells.
In any case, my guess is that, for all the reasons discussed above, even given a rising oil
price environment, the increase in the rig count will look more like the 2003 to 2008 rig count
increase, rather than the 2009 to 2011 rig count increase.
"... Clearly oil and natural gas wells are causing the problems as the second to last paragraph points away from disposal wells. ..."
"... The only thing which has changed is the new process of hydraulic fracturing in shale which began in the state in 2008, the same time as earthquake numbers rapidly increased. Weird coincidence dont you think? ..."
A 4.2 magnitude earthquake struck north Oklahoma City early on New Year's Day, the latest in a
series of temblors in the area in recent days that has prompted state regulators to call for more
restrictions on oil and gas operators.
... ... ...
The temblor is the latest of at least a dozen since Tuesday, when a 4.3 magnitude earthquake was
recorded. Oklahoma has become one of the most earthquake-prone areas in the world, with the number
of quakes magnitude 3.0 or greater skyrocketing from a few dozen in 2012 to more than 800 in 2015.
Many of the earthquakes are occurring in swarms in areas where injection wells pump salty wastewater
– a byproduct of oil and gas production – deep into the earth. As a result, state regulators have
begun reducing the volume or shutting down disposal wells in response.
However, the Edmond area has not previously been associated with the activity.
The Oklahoma Corporation Commission issued a statement on Friday saying its Oil and Gas Division
staff were taking action in response to the earthquakes in Edmond and that details should be available
on Monday.
OnthePlains -> riveness
4 Jan 2016 06:31
Yes but what wells are causing the problems? The second last paragraph points away from
oil and gas wells.
Pay attention to the words and the answer is in front of you.
Clearly oil and natural gas wells are causing the problems as the second to last paragraph
points away from disposal wells.
Nowhere in the state of Oklahoma is more than 15 miles from oil or natural gas wells. My daily
newspaper tells me wells were completed in all the counties surrounding and close to the city
of Edmond in the last week.
As a result of the earthquakes and further study of the three dimensional seismic surveys produced
by the oil companies they discovered a previously unknown fault line running under the area where
the earthquakes occurred. It runs parallel to the Nemaha uplift and Interstate 35.
OnthePlains -> CETOo6
4 Jan 2016 06:18
Fracking explodes the rock under huge pressure to release oil. Old school they just drilled
in and let come what may. The fracking leaves voids and allows ground to move.
Not exactly.
What it does it create a micro-earthquake to fracture the shale layer spread over distances
of up to 12 square miles at a time underground. That fracture then releases hydrocarbons trapped
in the pores of the rock.
What then happens is previously unknown faults in the rock strata from the time of the dinosaurs
are reactivated creating bigger earth movements.
CETOo6 -> CETOo6
4 Jan 2016 05:14
Check out the Netherlands. 50,000 peoples homes affected. Cracking. Falling down. From years
of gas extraction. Oil company turn a blind eye lead them down the garden path for years. Government
steps in to order demolition of the home. This world we live in is fubar! Imagine its your home....
CETOo6 -> OnthePlains
4 Jan 2016 04:46
Old mate. Fracking explodes the rock under huge pressure to release oil. Old school they just
drilled in and let come what may. The fracking leaves voids and allows ground to move. Reinjecting
(SUPER TOXIC) water lubricates soils again.
Fracking is idiotic. Anyone who believes in it is an idiot. Anyone who supports oil is an idiot.
Google nigeria oil deltas. You look hard enough you will see the undercover messes the oil companys
have made.....
dphaynes -> iOpenerLo114Lat51
3 Jan 2016 19:11
Is there any denial too absurd for the anti-science global conspiracy nutcases to make?
Frank - this data shows the # of earthquakes in Oklahoma corresponds directly to the
waste water injection.
I have to take issue with the waste water injection theory.
The earthquakes began in rapidly increasing numbers in 2008, the same year as they started
fracking in shale.
Oklahoma has used deep injection wells for salt water disposal since 1907. Peak oil production
occurred in 1927 and more oil was produced right up to the 1980's price crash than today.
If more water was produced and disposed of in the past why did the earthquakes only begin in
such increasing numbers after the advent of a new extraction technique?
Yetypu -> OnthePlains
2 Jan 2016 10:25
Typically in Oklahoma 10 barrels of "fossil" water are produced with every barrel of
oil so that's a heck of a lot of waste produced by fracking and conventional well
That ten to one ratio is for old water-drive sandstone & limestone wells - you have previously
had it pointed out to you that it is one tenth to one half of a barrel of water to one of oil
in a fracced shale well.
the earthquake swarms only started in 2008 when ...
... the high oil price led to a surge in production from high water-cut sandstone & limestone
wells.
more oil was produced up to 1985 than it is today
But at a far lower water-cut, meaning that far more water is produced 'today'.
OnthePlains -> raggedbandman
2 Jan 2016 10:07
Yet here we are with one small earthquake that admittedly is probably from deep-well
injection but all the greenies are screaming FRACKING!
Probably not from deep well injection because there aren't any in that area, but there is fracking
around 300 million year old fault lines they didn't previously know were there.
Only a fraction of the waste generated by the oil and gas industries is from the well
fracking process.
Typically in Oklahoma 10 barrels of "fossil" water are produced with every barrel of oil so
that's a heck of a lot of waste produced by fracking and conventional wells.
The odd thing is the earthquake swarms only started in 2008 when they started fracking in shale.
There were always naturally occurring earthquakes, about 1 a decade over magnitude 4.0 and
an average of less than three a year over 3.0. A small cluster took place in the 1950's when Oklahoma
was in the process of damming rivers and constructing lakes after the dust bowl.
Last year Oklahoma had almost 900 earthquakes over magnitude 3.0 (about three to four times
as many as California) and 26 over 4.0.
The state has used disposal wells for salt water produced with oil since 1907, peak oil production
in the state was in 1927, more oil was produced up to 1985 than it is today, therefore much more
water was injected underground in disposal wells in the past without producing thousands of earthquakes.
The only thing which has changed is the new process of hydraulic fracturing in shale which
began in the state in 2008, the same time as earthquake numbers rapidly increased. Weird coincidence
don't you think?
Steven Pope -> franksw
2 Jan 2016 09:54
Frank - this data shows the # of earthquakes in Oklahoma corresponds directly to the waste
water injection. We went from 2 earthquakes a year to more than 800 last year, which was more
than any other state in the USA combined:
"... My guess is that onshore US conventional dropped from 2.6 million 1/15 to around 2.1-2.2 million
12/15, and it will go below 2 million before the middle of 2016. ..."
SS, separating the onshore production from the G of M provide a better understanding of what is
happening in the US. Using the latest October PSM data, one can see the steady decline in onshore
production from May to October, 303 kb/d. However, from June to September, Gulf production increased
by 251 kb/d. October saw a drop of 80 kb/d from September. Would this be the result of a platform
shutting down for maintenance?
I think that many, myself included, thought that the LTO was not dropping off as fast as expected.
However, I also suspect that onshore conventional has dropped more in percentage terms than
onshore horizontal.
My guess is that onshore US conventional dropped from 2.6 million 1/15 to around 2.1-2.2
million 12/15, and it will go below 2 million before the middle of 2016.
This is "blast from the past (2012) well inside period when shale/tight oil prices were close or
above $100. Even at those time shale/tight oil companies have difficulties of creating sizable cash
flow and were forced to borrow heavily on junk bond market. Occidental Petroleum was driven out
of Bakken in 2012 because of costs.
average well costs vary from $6 million in the sweet spots of the Sanish field in central Bakken
to $7 million elsewhere in North Dakota. The company says its well costs in the south Texas play average
$5.5 million per well, giving it a $1.5 million edge over other operators there. ...
Houston-based
driller Marathon Oil said its first-quarter well costs in the Eagle Ford were unchanged at $8.5 million
a well because of such contracts, which the company's Chief Operating Officer, David Roberts, said are
keeping his firm from "as much price relief, potentially, as we would like.
Notable quotes:
"... The cost of bringing one Bakken well into production has grown from an average $6.5 million in 2010 to $8.5 million in the first quarter this year, data from company reports and the state regulator show. ..."
"... Bakken crude for June delivery at the Clearbrook, Minnesota hub was bid as low as $85.24 a barrel on Wednesday and offered at $93.69, down 6.5 percent from October levels, according to traders. For now, prices are comfortably above the $68 a barrel breakeven point for a 15 percent rate of return, according to Credit Suisse analysis. ..."
"... He says Whitings average well costs vary from $6 million in the sweet spots of the Sanish field in central Bakken to $7 million elsewhere in North Dakota. ..."
"... The company says its well costs in the south Texas play average $5.5 million per well, giving it a $1.5 million edge over other operators there. ..."
"... New state regulations in North Dakota, put in effect at the start of April, could add up to $400,000 to the cost of each well, since they proscribe the use of reserve pits to store discarded drilling fluids, according to the state Petroleum Council, which represents producers. ..."
"... Houston-based driller Marathon Oil said its first-quarter well costs in the Eagle Ford were unchanged at $8.5 million a well because of such contracts, which the companys Chief Operating Officer, David Roberts, said are keeping his firm from as much price relief, potentially, as we would like. ..."
Occidental Petroleum was among the first major U.S. oil drillers to make a big bet on the resurgence
of domestic production, spending billions to grab oil patches from Texas to North Dakota. Now, as
it bemoans steep costs and moves its rigs out of the Bakken shale oil fields, some analysts wonder
if the company has lost its clairvoyance. After two years of unyielding gains, costs are bound to
fall, they say.
The California-based energy giant is beset by escalating labor costs in North Dakota, which has
the lowest unemployment rate in the country. Other material costs have surged and new environmental
regulations could add to the burden.
The cost of bringing one Bakken well into production has
grown from an average $6.5 million in 2010 to $8.5 million in the first quarter this year, data from
company reports and the state regulator show.
"We got a lot better places to put money right now than the Bakken," Occidental CEO Stephen Chazen
said on a conference call with analysts late last month. "That's why I'm slowing it down."
But if some analysts are right, Occidental's pullout may prove ill-timed. The costs to complete
a well by injecting it with water, sand and other chemicals -- the hydraulic fracturing or "fracking"
process -- is falling as natural gas firms pare back on new drilling.
Pressure pumping prices, which cover a range of costs associated with fracking a well, have already
dipped by up to 25 percent in natural gas-rich basins, with signs of a knock-on effect emerging in
the Bakken, according to Barclays analysts. Within the next six months, these costs could fall by
as much as 10 percent in the Bakken shale, analysts at Bernstein Research estimate.
Efficient forms of fracking are also helping companies extract more oil from each well, lowering
the break-even cost of production, now estimated between $55 and $70 a barrel.
The push and pull of production costs in the world's fastest-growing oil frontier is adding uncertainty
to the outlook for U.S. oil prices. The issue is already in the limelight this election year, with
both political parties touting shale oil as a step toward energy independence, even as environmentalists
fret over the controversial fracking process, which has been blamed for the pollution of water supplies
and minor earthquakes.
If costs start to slip, the explosive output growth could keep a lid on U.S. oil prices, regardless
of tensions with Iran that have threatened global supply. If they continue to rise, breakneck output
growth may stall as more companies follow Occidental's lead and begin to pare back drilling and investment.
The two biggest plays -- the Williston basin in North Dakota and Eagle Ford in Texas -- produced
an estimated 1.2 million barrels per day (bpd) in April, close to the output from OPEC member Algeria,
according to data from analytics company Bentek Energy. A year ago, they were producing only a third
as much.
ON THE RISE
Over the past three years, drilling in U.S. shale patches has become an expensive affair, even
as producers got better acquainted with the shale rock they mined. Service firms could name their
price while the producers scrambled to drill.
Sand and ceramics, which companies pump into deep wells in a water and chemical mix to frack a
well, were in scant supply. The spot price of guar -- a gum processed from tiny seeds and used to
thicken fracking water -- has ballooned by 10-fold since January 2011 and doubled since the start
of this year, according to data from Agra Informa, an agricultural consultancy.
The nationwide cost of drilling and other well services for oil and gas wells has risen 22.5 percent
since October 2009, hitting a five-year high in March, according to the Bureau of Labor Statistics'
Producer Price Index (PPI).
Meanwhile, prices for shale oil, particularly from the Bakken, fell as the glut of new crude supplies
in the Midwest led to deep discounts for U.S. benchmark crude.
Bakken crude for June delivery at the Clearbrook, Minnesota hub was bid as low as $85.24 a
barrel on Wednesday and offered at $93.69, down 6.5 percent from October levels, according to traders.
For now, prices are comfortably above the $68 a barrel breakeven point for a 15 percent rate of return,
according to Credit Suisse analysis.
TABLES TURNED
But this year's slump in natural gas prices to a 10-year low is beginning to change the game.
Pricing power is shifting from service companies to drillers, possibly capping costs, as energy firms
slash gas-directed drilling rigs by 23 percent.
Houston-based oil services firm Baker Hughes projects the number of rigs drilling for both oil
and gas at the end of 2012 will be just under 2,000, only one percent higher than last year.
At the same time, total U.S. pressure-pumping capacity is expected to grow to 19 million horsepower
this year, two-and-a-half times the levels three years ago, according to research firm Tudor, Pickering,
Holt & Co.
Some of this new capacity is operated by small fracking firms that are mushrooming across North
America who are willing to take on projects for a fraction of what the big firms charge.
What is more, fracking crews, previously engaged in dry-gas outposts, are already moving out of
east Texas and Louisiana and into the hyperactive Eagle Ford shale in south Texas or the Bakken up
north.
Bad news for oil-services firms also highlights the trend. Halliburton, the market leader in pressure
pumping, lost 5 percent of its operating income in North America in the first quarter of 2012, compared
with the previous quarter, as the price it charged for pressure pumping slumped.
The company said its North American margins will fall into the low 20 percent range by the end
of 2012, down from about 25 percent at present.
SET TO SLIDE?
Efficiency is also improving. Whiting Petroleum, one of the largest producers in the Bakken, says
it has cut the days it spends drilling wells to 15, which shaves off about $1.5 million in costs.
The company also uses a fracking method called sliding sleeves that adds another $1.5 million in
savings, according to CEO Jim Volker.
He says Whiting's average well costs vary from $6 million in the sweet spots of the Sanish
field in central Bakken to $7 million elsewhere in North Dakota.
Other input costs may also be poised to decline.
EOG Resources says it is spending $500,000 less on each Eagle Ford well after it started using
sand from its own mines in north-central Texas and Wisconsin.
The company says its well costs
in the south Texas play average $5.5 million per well, giving it a $1.5 million edge over other operators
there.
EOG's Wisconsin mine, which started operating in January, is one of the 20 new sand mines that
popped up in the state since last year. Neighboring Minnesota has 13 pending applications for new
mines but most of these were stopped short by county-level moratoriums that will be in effect well
into next winter, according to Tony Runckel, the state's chief geologist.
While sand or "proppant" prices haven't fallen yet, input prices are likely to decline later this
year, according to Barclays analysts James West.
US Silica, one of the largest frack sand producers in the United States, is tying up more long-term
contracts, a sign that it is also anticipating a possible downturn in prices.
Guar supply is another issue. Indian farmers, who cater to 80 percent of worldwide guar demand,
are sowing record volumes of the seed this season but it is not entirely clear if this autumn's harvest
will meet growing U.S. demand.
UNEVEN BURDEN
Even though cost declines are on the horizon, they may be slow to arrive.
New state regulations in North Dakota, put in effect at the start of April, could add up to
$400,000 to the cost of each well, since they proscribe the use of reserve pits to store discarded
drilling fluids, according to the state Petroleum Council, which represents producers.
The long-term contracts that many developers have with the oil services firms will also stand
in the way. Those contracts, which ensured steady prices when costs were on the up, are a long way
from their end and, in most cases, are unlikely to be renegotiated soon.
Houston-based driller Marathon Oil said its first-quarter well costs in the Eagle Ford were
unchanged at $8.5 million a well because of such contracts, which the company's Chief Operating Officer,
David Roberts, said are keeping his firm from "as much price relief, potentially, as we would like."
Halliburton, in fact, says it is going back to producers, with steeper price schedules in tow,
so it can pass on some of the lofty raw material costs, its CEO David Lesar said in April.
"I suspect the pressure will come when they start to roll over" the contracts, Lesar told analysts
last month.
In the Bakken shale, that could be as far out as eighteen months into the future, according to
James Crandell, global head of oilfield services research at Dahlman Rose in New York. Even then,
Crandell says, contracts will be renewed at "modestly lower" prices in North Dakota.
"In other regions, particularly natural gas (fields), I expect larger reductions when the contracts
end," he added.
Still, even Occidental does not intend to fully move out of oil-rich shale plays like the Bakken.
"This is the Willie Sutton discussion," CEO Chazen said, comparing his strategy with that of the
slick bank robber from Brooklyn. "Why are we there? Because that's where the oil is."
(This version of the story has been corrected to fix the name of Occidental's CEO)
"... Its not matter is im optimistic or pessimistic, it is not mathematically possible. I dont speak about geology, steep decline of wells etc. I talk about reading chart which EIA presented. If there is 40 billion LTO recoverable reserves on $60-70 barrel(EIA in 2013 put 14 billion, on $100, so i put numbers nearly 3 times greater because of technology, costs squeeze etc.) it is not possible be on 4-4.5 mb/d on average 2015-2040. 4.5mb/d x 365 d x 25 years= 41 billion barrels. ..."
"... The EIA seems to base their TRR estimates on investor presentations, their LTO TRR estimates are very optimistic. Probably 20 Gb total from Bakken and Eagle Ford and about 20 Gb from the Permian LTO and other US LTO plays for a total of 40 Gb is reasonable. The 80 Gb TRR estimates are likely to be high by roughly a factor of 2 in my opinion. ..."
"... the EIAs EUR estimates for all tight oil plays are much more conservative than in companies presentations. It seems that the increase in TRR estimate was due to tighter assumed well spacing. But the actual well spacing in currently producing subplays is in many cases even tighter than the EIA assumptions. ..."
It's not matter is i'm optimistic or pessimistic, it is not mathematically possible. I don't
speak about geology, steep decline of wells etc. I talk about reading chart which EIA presented.
If there is 40 billion LTO recoverable reserves on $60-70 barrel(EIA in 2013 put 14 billion, on
$100, so i put numbers nearly 3 times greater because of technology, costs squeeze etc.) it is
not possible be on 4-4.5 mb/d on average 2015-2040.
4.5mb/d x 365 d x 25 years= 41 billion barrels.
According to the EIA Annual Energy Outlook 2015 (base case), technically recoverable
resources (TRR) of LTO in the U.S. are 78.2 billion barrels (+35.8 bbls of NGPLs).
In AEO 2014, these estimates were 59.2 billion barrels and 27.6 billion, respectively;
In AEO 2013: 47.1 billion barrels of LTO.
I do not know where your number of 14 billion comes from?
To note, estimates of technically recoverable resources do not depend on the price of oil,
and the EIA does not provide estimates of economically recoverable resources.
I am not saying that the EIA projections are correct, but at least their LTO production forecasts
correspond to their TRR estimates.
And yes they claim resources on 78.2Gb(until this year was 58 Gb, how is possible so much growth
on resources in this price environment is mystery for me), but that is potential resources no
proven reserves which for now stood on 13. 365 GB.
But in end it is not matter what they claim for potential resources, they can claim 1 trillion
barrels but what is matter reserves and for now they are 13.3 GB, i put 3 times greater number
and 4-4.5 mb/d average 2015-2040 is mathematically not possible in that case.
OK. Thank you for that clarification. Also, i use data which Dennis Coyne put on 30-40 Gb, which
is pretty optimistic for proven reserves, you must admitted that.
That is Hamm 24 Gb projections in Bakken, plus 100% growth proven reserves in Eagle Ford plus
4 times greater reserves in Niobara and other plays(outside of Bakken and EF) than now. Pretty
good.
Dennis' numbers are for TRR as well. He says that his "guess for LTO is based on USGS and David
Hughes work"
But, unlike the EIA, USGS updates estimates for shale plays resources relatively
seldom. And David Hughes' past forecasts of LTO production have proved too conservative.
"how is possible so much growth on resources in this price environment is mystery for me"
TRR estimate is not dependent on price. It is calculated based on the "Area with Potential"
(in sq. miles), average well spacing (wells/per sq mile) and average estimated ultimate recovery
(EUR) per well
The EIA seems to base their TRR estimates on investor presentations, their LTO
TRR estimates are
very
optimistic. Probably 20 Gb total from Bakken and Eagle Ford and
about 20 Gb from the Permian LTO and other US LTO plays for a total of 40 Gb is reasonable. The
80 Gb TRR estimates are likely to be high by roughly a factor of 2 in my opinion.
We will see a steep decline in US LTO output between 2020 and 2025.
the EIA's EUR estimates for all tight oil plays are much more conservative than
in companies' presentations. It seems that the increase in TRR estimate was due to tighter assumed
well spacing. But the actual well spacing in currently producing subplays is in many cases even
tighter than the EIA assumptions.
I don't want to guess what is the right number of TRR because of too many uncertainties (including
potential impact of technologies on LTO recovery rates).
What may have a negative impact on LTO production is not TRR, but low oil prices + poor economics
of shale companies.
See EIA
Crude
Oil Production
. US production was surprisingly stable in 2015. Since May the figures are 9,479 (May)
9,315 (June) 9,433 (July) 9,407 (August) 9,460 (Sep) 9,347 (Oct)
Notable quotes:
"... US #crudeoil production down to 9.347mbpd in Oct15 from an upward revised 9.460 in Sep15 ..."
"... Texas #crude production down to 3391000 b/day in Oct15 from a revised down 3417000 b/day in Sep15 ..."
"... The write-offs, known officially as impairments, represent a recognition that many wells will have shorter productive lives than initially anticipated, analysts said. It also reflects an acknowledgement that companies may have to pay for the cost of plugging and abandoning wells sooner than they expected, they noted. ..."
"... Chesapeake Energy, Wyomings fourth-largest oil producer, reported impairments of $15.4 billion through the first three quarters of 2015. The Oklahoma City-based producers woes are primarily tied to natural gas. ..."
"... Oil patch bankruptcies have accelerated in the fourth quarter of 2015 as a supply glut keeps prices stuck below $40 a barrel. Ten firms, with more than $2 billion in debt, have closed their doors since October, according to the Federal Reserve Bank of Dallas. ..."
"... Capital spending has fallen 51 percent since the third quarter, the bank said ..."
"
The write-offs, known officially as impairments, represent a recognition that many
wells will have shorter productive lives than initially anticipated, analysts said. It also
reflects an acknowledgement that companies may have to pay for the cost of plugging and abandoning
wells sooner than they expected, they noted.
"
"
Chesapeake Energy, Wyoming's fourth-largest oil producer, reported impairments of $15.4
billion through the first three quarters of 2015. The Oklahoma City-based producer's woes are
primarily tied to natural gas.
"
"
Oil patch bankruptcies have accelerated in the fourth quarter of 2015 as a supply glut
keeps prices stuck below $40 a barrel. Ten firms, with more than $2 billion in debt, have closed
their doors since October, according to the Federal Reserve Bank of Dallas.
Capital spending has fallen 51 percent since the third quarter, the bank said
.
And the global supply glut may linger into 2017, it noted, pointing to estimates that production
will outpace demand by 600,000 barrels per day through 2016."
"... If you have or can raise the cash, it makes sense to drill now and produce a year or two down the road-IF you believe prices will be up. According to what I read here, the costs of drilling a well may be down by a third, due to so many men and machines and so much steel and sand etc , "looking for a home". ..."
"... Most LTO companies don't have cash. Most have a gob of debt. I don't think sinking cash into wells that will generate $0 revenue for a year or two is a good idea, especially given the financial shape LTO is in already. ..."
"... So they are strictly gambling that oil prices will rise steeply in the next couple years? Is that a good business strategy for multi-billion dollar corporations to undertake, especially when the futures market says otherwise? ..."
"... The size of the gamble is offset by the size of the potential winnings. ..."
"... Someone come on here and explain how drilling, but not completing 13,000 horizontal wells that won't cum. 100,000 BO in 40 years makes one lick of sense? ..."
Their well, one of hundreds drilled by Anadarko Petroleum in eastern Colorado's Wattenberg
field this year, could someday gush as many as 800 barrels of crude oil a day. But Anadarko
is not planning to produce a drop of crude from the well for at least another year because
the price of oil is now so pitifully low.
The well here is just one of more than 4,000 drilled oil and natural gas wells across
the country producing nothing, but ready to be tapped quickly
……….
But the incomplete wells are also another reason many analysts say a recovery in the
oil price is nowhere in sight. Together the well backlog could produce as many as 500,000 barrels
of oil a day, about the same amount of oil that Iran is expected to add to the glutted global
market after it complies with the recent nuclear deal by the end of next year.
Some analysts say oil companies like Anadarko, EOG Resources and Continental Resources
may collectively risk suffocating the very price revival they anticipate by releasing abundant
new supplies once prices inch up. Others say the eventual impact would be small and short-lived,
but since the industry has never used this strategy before, no one can be sure……….
On the completion side, fracking crews are easier to come by and their contracts tend
to be more fluid. Now those completion costs have also come down - meaning that the uncompleted
wells will eventually be brought on line at a lower cost, executives say.
If you have or can raise the cash, it makes sense to drill now and produce a year or two down
the road-IF you believe prices will be up. According to what I read here, the costs of drilling
a well may be down by a third, due to so many men and machines and so much steel and sand etc
, "looking for a home".
I don't know if this is "one third off" drilling sales event is totally for real, it might
be only a quarter or a fifth off. Hopefully somebody who crunches tight oil numbers will have
something to say about it.
Tight oil production brought on by drilling now and producing later is not going to noticeably
affect the price later.
Tight oil production brought on by drilling now and producing later is not going to noticeably
affect the price later.
By what logic did you arrive at that conclusion?
The article states: But the incomplete wells are also another reason many analysts say a
recovery in the oil price is nowhere in sight. Together the well backlog could produce as many
as 500,000 barrels of oil a day, …
Now I think an extra half a million barrels per day would noticeably affect the price.
A half a million barrels WOULD be enough to influence prices.
An individual company does not expect it's OWN production to influence the market price- unless
maybe the company is a REALLY big one maybe.
If any given company drills say fifty such wells, that would be only twenty thousand barrels
a day, maybe less -- most definitely not enough to move the market price needle. It's not the industry as whole, but individual companies that make the decision.
I DID not go into Christmas trees, personally, for fear the industry was setting itself up
to CHOKE itself on excess production. I was wrong about that, I could have made a LOT of money
in Christmas trees, not enough people took the gamble to glut the market.
Wine grape growers took the gamble and are asshole deep in grapes that won't sell for enough
to cover production costs in a lot of places these days, including my neighborhood.
What you say may make sense of you are using cash and have little to no debt. It may make sense
for ExxonMobil.
Most LTO companies don't have cash. Most have a gob of debt. I don't think sinking cash into
wells that will generate $0 revenue for a year or two is a good idea, especially given the financial
shape LTO is in already.
Also, the entire premise is that there will soon be a steep rise in the price of oil. That
is a total crap shoot.
So they are strictly gambling that oil prices will rise steeply in the next couple years? Is
that a good business strategy for multi-billion dollar corporations to undertake, especially when
the futures market says otherwise?
Ask Harold Hamm how easy it is to predict the future price of oil.
I am not an expert, but I HAVE read a representative sample of the books you read to
get your MBA. Read me for insight, or comic relief, but DON'T bet more than beer and cigarette money on MY
opinions.
Things DON'T always make sense. Under their suits and hats, corporate managers are just naked
apes.
Since you are a hands on guy, I expect at some point you have gotten into some soft ground
off the highway with a truck, and realized you are were in trouble and that IF YOU STOPPED, you
would be walking out for SURE.
SO – you put the pedal to the metal, and hopefully got thru. If not, you were STUCK ANYWAY.
This could be thought of as a NO DOWNSIDE BET-IF you are convinced you are apt to go broke
anyway.Win, you get to keep it all, lose, you are not going to pay ANY OF IT back anyway, it's
somebody else's money, and your company is in bk court.
The size of the gamble is offset by the size of the potential winnings.
I looked up Anadarko on CO state website.
Operate under Kerr McGee. Assuming 4,800 operated wells, by my math the average well is producing 23 barrels of oil and
112 mcf of gas per day, gross.
Assuming 25% royalty burden, and remembering the basis spread in CO for both oil and gas is
horrible, it looks like GROSS revenue per well at current price would be in the neighborhood of
$200K per year.
I keep begging, and will again. Someone come on here and explain how drilling, but not
completing 13,000′ horizontal wells that won't cum. 100,000 BO in 40 years makes one lick of sense?
Lifting of export ban solved this problem and now such crude can be exported to refineries which
are tunes to lighter sorts of oil. that might mean that the USA glut is over.
"... I suspect that most of the 2015 build in US and global C+C inventories consists of condensate,
and I frequently cite a Reuters article earlier this year that documented case histories of refiners
increasingly rejecting blends of heavy crude and condensate that technically meet the upper API
limit for WTI crude (42 API gravity*), but that are deficient in distillates. ..."
There has been a lot of talk regarding the oil glut, but according to eia crude inventories
there is only 105.1 million more barrils of crude than a year ago
What the EIA calls "Crude oil" is actually Crude + Condensate (C+C).
I suspect that most of the 2015 build in US and global C+C inventories consists of condensate,
and I frequently cite a Reuters article earlier this year that documented case histories of refiners
increasingly rejecting blends of heavy crude and condensate that technically meet the upper API
limit for WTI crude (42 API gravity*), but that are deficient in distillates.
In any case, based on the most recent four week running average data, US refineries were dependent
on net crude oil imports for 43% of the C+C processed in US refineries (7.1/16.5) versus 44% a
year ago (7.1/16.2). If we had so much (generally cheaper than imported) actual crude oil on hand
in the US, why are refiners importing the same amount of crude oil as they did last year?
*Most common overall dividing line between crude & condensate is 45 API
As time passes, more and more hedges are expiring, leaving oil companies fully exposed to the
painfully low oil price environment. "A lot of these smaller guys who had bad balance sheets have
pretty good hedge books through full-year 2015," Andrew Byrne, an analyst with IHS, told the Houston
Chronicle. "You can't say that about 2016."
In fact, about one-fifth of North American production is hedged at a median price of $87.51 per
barrel. Smaller companies rely much more heavily upon hedging as they are more vulnerable to price
swings and are not diversified with downstream assets. Across the industry, IHS estimates that smaller
companies had about half of their production hedged at a median oil price of $89.86 per barrel in
2015.
... ... ...
More worrying for the oil and gas companies that are struggling to keep their lights on is the
forthcoming credit redeterminations, which typically take place in April and September. Banks recalculate
credit lines for drillers, using oil prices as a key determinant of an individual company's viability.
With oil prices bouncing around near six-year lows, more companies will find themselves on the wrong
side of that equation.
Banks were more lenient in April when oil prices were a bit higher and many analysts expected
prices to rise. This time around the pain is mounting and there will be a lot less leeway. Somewhere
around
10 to 15 percent credit offered to drillers could be cut back on average, a move that could slash
$15 billion in credit capacity, according to CreditSights Inc.
... ... ...
According to the FT, banking regulators are pushing banks to take a more conservative approach
to their energy loans.
"... The EIAs 2015 Annual Energy Outlook is even more optimistic about tight oil than the AEO2014, which we showed in Drilling Deeper suffered from a great deal of questionable optimism. ..."
"... The recent drop in oil prices has already hit tight oil production growth hard. The steep decline rates of wells and the fact that the best wells are typically drilled off first means that it will become increasingly difficult for these production forecasts to be met, especially at relatively low prices. ..."
"... As it has acknowledged, the EIAs track record in estimating resources and projecting future production and prices has historically been poor. ..."
"... How can overall tight oil production increase by 15% in AEO2015 compared to AEO2014 while assuming oil prices are $20/barrel lower over the 2015-2030 period? ..."
"... Americas energy future is largely determined by the assumptions and expectations we have today. And because energy plays such a critical role in the health of our economy, environment, and people, the importance of getting it right on energy cant be overstated. Its for this reason that we encourage everyone-citizens, policymakers, and the media-to not take the EIAs rosy projections at face value but rather to drill deeper. ..."
In
Drilling Deeper
,
PCI Fellow
David Hughes
took a hard look at the EIA's AEO2014 and found that its projections for future production and prices
suffered from a worrisome level of optimism.
Recently, the EIA released its
Annual Energy Outlook 2015
and so
we asked David Hughes to see how the EIA's projections and assumptions have changed over the last
year, and to assess the AEO2015 against both
Drilling Deeper
and up-to-date production data
from key shale gas and tight oil plays.
Key Conclusions
The EIA's 2015 Annual Energy Outlook is even more optimistic about tight oil than the AEO2014,
which we showed in Drilling Deeper suffered from a great deal of questionable optimism.
The
AEO2015 reference case projection of total tight oil production through 2040 has increased by
6.5 billion barrels, or 15%, compared to AEO2014.
The EIA assumes West Texas Intermediate (WTI) oil prices will remain low and not exceed $100/barrel
until 2031.
At the same time, the EIA assumes that overall U.S. oil production will experience a very
gradual decline following a peak in 2020.
These assumptions-low prices, continued growth through this decade, and a gradual decline
in production thereafter - are belied by the geological and economic realities of shale plays.
The recent drop in oil prices has already hit tight oil production growth hard. The steep
decline rates of wells and the fact that the best wells are typically drilled off first means
that it will become increasingly difficult for these production forecasts to be met, especially
at relatively low prices.
Perhaps the most striking change from AEO2014 to AEO2015 is the EIA's optimism about the Bakken,
the projected recovery of which was raised by a whopping 85%
.
As it has acknowledged, the EIA's track record in estimating resources and projecting
future production and prices has historically been poor.
Admittedly, forecasting such things
is very challenging, especially as it relates to shifting economic and technological realities.
But the below ground fundamentals- the geology of these plays and how well they are understood-don't
change wildly from year to year. And yet the AEO2015 and AEO2014 reference cases have major differences
between them. As Figure 13 shows, with the exception of the Eagle Ford, the EIA's projections
for the major tight oil plays have shifted up or down significantly.
After closely reviewing the Annual Energy Outlook 2015, David Hughes raises some important, substantive
questions:
Why is there so much difference at the play level between AEO2014 and AEO2015?
Why does Bakken production rise 40% from current levels, recover more than twice as much oil
by 2040 as the latest USGS mean estimate of technically recoverable resources, and exit 2040 at
production levels considerably above current levels?
How can the Niobrara recover twice as much oil in AEO2015 as was assumed just a year ago in
AEO 2014?
What was the thinking behind the wildly optimistic forecast for the Austin Chalk in AEO2014
that required a 78% reduction in estimated cumulative recovery in AEO2015?
How can overall tight oil production increase by 15% in AEO2015 compared to AEO2014 while
assuming oil prices are $20/barrel lower over the 2015-2030 period?
America's energy future is largely determined by the assumptions and expectations we have
today. And because energy plays such a critical role in the health of our economy, environment, and
people, the importance of getting it right on energy can't be overstated. It's for this reason that
we encourage everyone-citizens, policymakers, and the media-to not take the EIA's rosy projections
at face value but rather to drill deeper.
The Last but not LeastTechnology is dominated by
two types of people: those who understand what they do not manage and those who manage what they do not understand ~Archibald Putt.
Ph.D
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but your last sentence may hold some
validity. For that matter, I don't think shale has given up completely after the first go
round, if the price is right. Would that delay peak to another date? Quien sabe. Money talks.
What price? I know I would keep an ICE around for long trips at $200 a barrel for the
convenience. Food may be higher, though.
US sanctions
against Iran could give oil a boost to $100 amid dramatic shortfall in supplies
Oil surges to
4-year high as investors see no sign of production rise amid Iran sanctions
15 ·
11 hrs
) –
perhaps there are lessons to be learned?
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