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Subprime oil: Deflation of the USA shale oil bubble

News Peak Cheap Energy and Oil Price Slump Recommended Links Energy Bookshelf Secular Stagnation Energy returned on energy invested (ERoEI) A note of ERoEI decline
MSM propagated myth about Saudis defending this market share Deflation of the USA shale oil bubble Oil glut fallacy Why Peak Oil Threatens the Casino Capitalism Energy and the Economy Bakken Reality Check Shale Well Economics and cost of production estimates
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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:

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.

Rodster  August 14, 2014 at 4:43 pm

“CONDITION RED: Fracking Shale Is Destroying Oil & Gas Companies Balance Sheets”

http://srsroccoreport.com/condition-red-fracking-is-destroying-oil-gas-companies-balance-sheets/condition-red-fracking-is-destroying-oil-gas-companies-balance-sheets/

“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”

sunnnv, 11/06/2015 at 12:52 am

Thanks for that post by Art Berman, Matt. The fuller post in now up on Forbes, and is way more detailed and interesting than the preview.

http://www.forbes.com/sites/arthurberman/2015/11/03/only-1-of-the-bakken-play-breaks-even-at-current-oil-prices/

note it goes on for 6 pages…

From About Oil Shale

Oil Shale Resources

   

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.

   
  Major Process Steps in Mining and Surface Retorting  
   

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.

   
  Major Process Steps in in-situ conversion process (ICP)  
   
   
  The Shell In-Situ Conversion Process  
   

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.

1 RAND 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.


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Old News ;-)

[Jun 21, 2018] Increases in the US shale production are limited by available transport

Notable quotes:
"... 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. ..."
Jun 21, 2018 | peakoilbarrel.com

Energy News, 06/12/2018 at 5:11 pm

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
https://www.argusmedia.com/pages/NewsBody.aspx?id=1696409&menu=yes?utm_source=rss%20Free&utm_medium=sendible&utm_campaign=RSS
Guym , 06/12/2018 at 5:53 pm
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.

George Kaplan , 06/12/2018 at 11:36 pm
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.
Dan Goudreault , 06/13/2018 at 3:05 am
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.

https://www.dmr.nd.gov/oilgas/presentations/WBPC052418_2400.pdf

Guym , 06/13/2018 at 8:10 am
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.

[Jun 21, 2018] There is a narrative that oil demand will soon begin dropping due to widespread use of EV.

Jun 21, 2018 | peakoilbarrel.com

shallow sand x Ignored says: 06/18/2018 at 2:36 pm

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?

I'd like to see some explanation with numbers.

GoneFishing x Ignored says: 06/18/2018 at 3:28 pm
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.

https://www.nanalyze.com/2017/03/electric-cars-usa/

Dennis Coyne x Ignored says: 06/18/2018 at 6:04 pm
Shallow sand,

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.

[Jun 21, 2018] Strange consumption growth in Eastern Europe

Jun 21, 2018 | peakoilbarrel.com

Watcher, 06/17/2018 at 11:37 pm

Got time to go thru the bible more carefully.

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.

World oil consumption growth 1.8%.

(population in africa . . . . . .)

Ktoś, 06/18/2018 at 8:44 am

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.
Strummer, 06/18/2018 at 2:00 pm
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
Watcher, 06/19/2018 at 12:04 am
South Africa grew at 0.6%.

Middle Africa is listed as growing at 0.4%. North Africa is divided up Egypt, Morocco and "Other North Africa". Other was +4.7% consumption growth.

It's gotta be Nigeria west and Angola east.

Watcher, 06/18/2018 at 2:43 pm
Pssssst.

Oil consumption 2017 increased 1.8% from 2016.

Oil price 2016 about $41/b. Oil price 2017 about $55/b.

hahahahhaa

Dennis Coyne, 06/19/2018 at 6:41 am
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.

[Jun 21, 2018] The idea behind peak demand fallacy is simply that oil supply may at some point become relatively abundant relative to demand in the future (date unknown).

Jun 21, 2018 | peakoilbarrel.com

Dennis Coyne x Ignored says: 06/18/2018 at 5:54 pm

Hi George,

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.

Eulenspiegel x Ignored says: 06/19/2018 at 3:56 am
Why making a fire sale?

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).

Dennis Coyne x Ignored says: 06/20/2018 at 8:00 am
Eulenspeigel,

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.

[Jun 21, 2018] Older wells are declining at about 8% per year

Jun 21, 2018 | peakoilbarrel.com

Fernando Leanme , 06/19/2018 at 2:17 pm

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.
Dennis Coyne , 06/20/2018 at 7:53 am
Hi Fernando,

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.

Chart below from

https://shaleprofile.com/index.php/2018/06/19/north-dakota-update-through-april-2018/

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.

Fernando Leanme , 06/20/2018 at 9:08 am
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.

[Jun 21, 2018] Norwegian production is down

Jun 21, 2018 | peakoilbarrel.com

Energy News, 06/19/2018 at 3:47 am 2018-06-19

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

George Kaplan , 06/19/2018 at 4:01 am

Big unplanned outages coming on the gas side for June numbers as well.
Kolbeinh , 06/19/2018 at 4:26 am
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.
George Kaplan, 06/19/2018 at 4:39 am
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"?

[Jun 21, 2018] Personally I think all the conventional oil in the ground will eventually be used, it's just too useful. It's just a matter of how long it takes. It would be better if it was used for chemicals and something else used for fuel

Jun 21, 2018 | peakoilbarrel.com

dclonghorn, 06/17/2018 at 10:57 pm

Here's a link to an interesting oil market assessment from 9 point energy.

http://www.ninepoint.com/commentary/commentaries/052018/energy-strategy-052018/

They come up with a projection of 100 oil by 2020 using some conservative assumptions.

George Kaplan , 06/18/2018 at 1:35 am
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.

Guym , 06/18/2018 at 8:55 am
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.
George Kaplan , 06/18/2018 at 4:47 am
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.
Energy News , 06/18/2018 at 5:40 am
SLB seems to agree with Simmons, that outside of OPEC & the USA overall World oil production is going to continue falling

2018-06-12 Schlumberger Investor Presentations – Wells Fargo West Coast Energy Conference
aggregate base decline, which increased from approx 5% in 2015 to around 7% in 2017. Given this acceleration, it is probably not realistic to expect the new projects slated to come online during the next few years to be enough to reverse production decline outside of the US and Middle East.
Some slides on Twitter
https://pbs.twimg.com/media/DfgLlUHV4AEqYOl.jpg
https://pbs.twimg.com/media/DfgLlUHVAAAx_l8.jpg
Simmons charts https://pbs.twimg.com/media/DfcPDiBV4AMwNH2.jpg

Guym , 06/18/2018 at 9:06 am
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.
Dennis Coyne , 06/18/2018 at 11:19 am
Guym,

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.

Hopefully the former course will be chosen.

[Jun 21, 2018] BP's Proven Reserves tab, historical says some interesting things

Jun 21, 2018 | peakoilbarrel.com

Watcher x Ignored says: 06/19/2018 at 12:15 am

BP's Proven Reserves tab, historical says some interesting things:

US reserves did not grow or shrink last year 50B.

Canada reserves shrank about 1%. Weird.

Brazil reserves grew 1% but are down a lot from 2014.

KSA flat. Venezuela Orinoco reserves slight uptick 0.4%.

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.

[Jun 21, 2018] What? Me worry? Rystadt says US has 79 more years of oil still available.

Jun 21, 2018 | peakoilbarrel.com

Guym

x Ignored says: 06/19/2018 at 11:46 am
https://oilprice.com/Energy/Crude-Oil/US-Outstrips-Saudis-In-Largest-Recoverable-Oil-Reserves.html

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?

[Jun 20, 2018] Consumption of oil continues to grow in 2018

Jun 20, 2018 | peakoilbarrel.com

Watcher, 06/13/2018 at 12:54 pm

The bible is out. A few surprises.

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.

[Jun 20, 2018] Excellent write-up on peak oil supply

Images removes
Jun 20, 2018 | crudeoilpeak.info

Peak oil in Asia Pacific (part 1)

This post uses data released by the BP Statistical Review in June 2018

https://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html

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.

In part 2 we look at the oil balance in each country. Tags: BP Statistical Review , China oil demand , china peak oil , Middle East , South China Sea , South East Asia

[Jun 20, 2018] 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.

Jun 20, 2018 | peakoilbarrel.com

Kolbeinh, 06/18/2018 at 6:21 am

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.

[Jun 09, 2018] Shale Is a Debt-Fueled Mirage, and We re Running Out of Energy - Forget Your Flying Teslas by James Howard Kunstler

Notable quotes:
"... 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. ..."
"... If you like his work, please consider supporting him on Patreon . ..."
"... 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. ..."
Jun 09, 2018 | russia-insider.com

"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.

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.

If you like his work, please consider supporting him on Patreon .


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.


Source: Kunstler.com

[Jun 03, 2018] The Unbelievable Amount Of Frac Sand Consumed By U.S. Shale Oil Industry

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.
Jun 03, 2018 | www.zerohedge.com

By the SRSrocco Report ,

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.

To get an idea of the U.S. top shale oil fields, here is a chart from my recent video, The U.S. Shale Oil Ponzi Scheme Explained :

(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):

https://www.youtube.com/embed/PQKjLFY5YEY?rel=0

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 .


Gusher -> Stuck on Zero Sun, 06/03/2018 - 13:02 Permalink

Yawn is right. 64 trainloads a year is nothing. One large coal fired electric generation plant uses that much coal every month.

Juggernaut x2 -> Gusher Sun, 06/03/2018 - 14:07 Permalink

Fracking is a capital-intensive scam and fueled by cheap $ from the Fed.

jmack Sun, 06/03/2018 - 13:48 Permalink

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.

hannah -> jmack Sun, 06/03/2018 - 19:17 Permalink

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.....

webmatex Sun, 06/03/2018 - 14:45 Permalink

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.

What you think?

jmack -> webmatex Sun, 06/03/2018 - 15:00 Permalink

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.

snblitz -> webmatex Sun, 06/03/2018 - 15:46 Permalink

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.

Angry Plant -> snblitz Sun, 06/03/2018 - 19:13 Permalink

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.

Red Raspberry -> webmatex Sun, 06/03/2018 - 17:07 Permalink

You left out the volcanoes...

OCnStiggs -> webmatex Sun, 06/03/2018 - 17:15 Permalink

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!

[May 15, 2018] Oil Prices The Long-Term Debt Cycle by Art Berman

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.
May 15, 2018 | www.artberman.com

Labyrinth Consulting Services, Inc. artberman.com

... ... ...

SLIDE 4: Oil Prices & The Long-Term Debt Cycle

SLIDE 5: Low Interest Rates Created A Capital Bubble For Tight Oil & The Permian Basin

SLIDE 6: The False Premise that Tight Oil Plays Are the New Swing Producer

SLIDE 7: Shale Cost Reductions 90% Industry Bust, 10% Innovation and Efficiency

SLIDE 8: Two of the Largest Tight Oil Plays are in Texas: Eagle Ford & Permian

[May 14, 2018] Skeptical Geologist Warns Permian's Best Years Are Behind Us

May 14, 2018 | www.zerohedge.com

Authored by Tsvetana Paraskova via OilPrice.com,

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.

[Mar 09, 2018] Is US Energy Dominance Overhyped Top Experts Doubts Claims About Future Net Energy Exports naked capitalism

Notable quotes:
"... 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. ..."
Mar 09, 2018 | www.nakedcapitalism.com

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.


Expat , March 7, 2018 at 7:58 am

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.

Max4241 , March 7, 2018 at 9:21 pm

"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.

The Rev Kev , March 7, 2018 at 8:17 am

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.

PlutoniumKun , March 7, 2018 at 9:12 am

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.

Scott , March 7, 2018 at 12:13 pm

Three years ago, a new refinery opened in North Dakota. A year later it sold for a loss http://www.thedickinsonpress.com/business/energy-and-mining/4063779-dakota-prairie-refinery-sold-tesoro-loss-hurt-oil-price-slump

The primary reason was the collapse of oil prices and the associated decreased demand for diesel.

Synoia , March 7, 2018 at 1:00 pm

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.

Amfortas the Hippie , March 7, 2018 at 7:07 pm

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. )

rjs , March 7, 2018 at 9:29 am

looking at the actual numbers involved might help

natural gas imports, mostly from Canada: https://www.eia.gov/dnav/ng/hist/n9100us2m.htm
natural gas exports, still mostly to Mexico: https://www.eia.gov/dnav/ng/hist/n9130us2m.htm
oil imports: http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCRIMUS2&f=W
oil exports: https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCREXUS2&f=W

Anand shah , March 7, 2018 at 11:27 am

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

Chauncey Gardiner , March 7, 2018 at 7:12 pm

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.

John k , March 7, 2018 at 11:59 am

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.

RBHoughton , March 7, 2018 at 8:38 pm

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.

[Feb 23, 2018] What Is The Right Price For Oil In A Balanced Market OilPrice.com

Notable quotes:
"... "What is the Right Price for oil in a balanced market?" ..."
Feb 23, 2018 | oilprice.com

What Is The Right Price For Oil In A Balanced Market? By Dan Steffens - Feb 21, 2018, 6:00 PM CST fracking crew 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

[Feb 23, 2018] At 100 plus dollar per barrel shale oil might work. Just a big risk.

Feb 23, 2018 | peakoilbarrel.com

Mike x Ignored says: 02/21/2018 at 4:56 pm

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.

shallow sand x Ignored says: 02/21/2018 at 7:55 pm
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.

Mike x Ignored says: 02/21/2018 at 8:14 pm
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.

Eulenspiegel x Ignored says: 02/22/2018 at 4:38 am
So it looks like shale oil is all about getting as much as you can in the first 3 years – the rest is pure luck before equipment breaks down?
shallow sand x Ignored says: 02/22/2018 at 6:35 am
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.

[Feb 23, 2018] U.S. Vastly Overstates Oil Output Forecasts, MIT Study Suggests

Feb 23, 2018 | peakoilbarrel.com

Hightrekker

x Ignored says: 02/22/2018 at 3:32 pm
Well, they are academics, so we can discount this a bit:

U.S. Vastly Overstates Oil Output Forecasts, MIT Study Suggests
https://www.bloomberg.com/news/articles/2017-12-01/mit-study-suggests-u-s-vastly-overstates-oil-output-forecasts

[Feb 02, 2018] Why Is The Shale Industry Still Not Profitable by Nick Cunningham

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. ..."
Feb 02, 2018 | oilprice.com
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.

[Jan 30, 2018] Why Is The Shale Industry Still Not Profitable

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 ..."
Jan 30, 2018 | www.nakedcapitalism.com

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.

[Jan 30, 2018] The Dark Side of America's Rise to Oil Superpower

Jan 30, 2018 | peakoilbarrel.com

Cats@Home x Ignored says: 01/25/2018 at 7:53 pm

The Dark Side of America's Rise to Oil Superpower
By Javier Blas

https://www.bloomberg.com/news/articles/2018-01-25/the-dark-side-of-america-s-rise-to-oil-superpower

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."

Robert G. Valiant x Ignored says: 01/25/2018 at 8:38 pm
To infinity, and beyond.
Mike x Ignored says: 01/25/2018 at 9:18 pm
This feller used 'hype' because there is likely no word for bullshit in Farsi: https://oilprice.com/Energy/Energy-General/Saudi-Oil-Minister-Tired-Of-Shale-Hype.html .

https://www.oilystuffblog.com/single-post/2018/01/25/Cartoon-Of-the-Week

shallow sand x Ignored says: 01/25/2018 at 11:34 pm
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!

[Jan 21, 2018] Wells that they drilled last year will produce the biggest rates of decline, well over 50 percent. So, how many wells would need to be completed to increase production over a million barrels in 2018?

Jan 21, 2018 | peakoilbarrel.com

John x Ignored says: 01/18/2018 at 9:12 pm

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.
Guym x Ignored says: 01/19/2018 at 5:20 pm
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.
Dennis Coyne x Ignored says: 01/19/2018 at 6:40 pm
Hi Guym,

I agree.

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).

Guym x Ignored says: 01/19/2018 at 7:48 pm
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.

[Jan 21, 2018] Possible Seneca cliff of oil production due to technological enhancements of extraction of oil from depleting fields. And first of all KSA

Notable quotes:
"... 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. ..."
Jan 19, 2018 | peakoilbarrel.com

x says: 01/19/2018 at 9:55 am

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.

Michael says: 01/19/2018 at 10:12 am

"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.

(I like the new editing feature on this site.)

[Jan 16, 2018] GOM oil and gas production in decline from now on

Jan 16, 2018 | peakoilbarrel.com

SouthLaGeo

x Ignored says: 01/12/2018 at 7:11 pm
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.

https://www.boem.gov/BOEM-2017-082/

George Kaplan x Ignored says: 01/13/2018 at 3:14 am
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.

SouthLaGeo x Ignored says: 01/13/2018 at 8:47 am
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.

George Kaplan x Ignored says: 01/13/2018 at 11:53 am
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.

Fernando Leanme x Ignored says: 01/15/2018 at 4:49 am
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.
Dennis Coyne x Ignored says: 01/15/2018 at 10:28 am
https://www.eia.gov/outlooks/aeo/data/browser/#/?id=12-AEO2017&region=0-0&cases=ref2017&start=2015&end=2030&f=A&linechart=ref2017-d120816a.3-12-AEO2017&sourcekey=0 \

The BOEM probably uses the EIA AEO 2017 reference price forecast.

[Jan 09, 2018] Oil prices are volatile because of the fiscally irresponsible, short investment nature of the shale oil industry and offshore development takes years and years to bring to market

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. ..."
Jan 09, 2018 | peakoilbarrel.com

Mike: 01/08/2018 at 7:34 am

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

Anadarko's Al Walker Says US Shale Is An Alcoholic And Investors Are 'A Problem'

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.

[Jan 08, 2018] To what extent shale companies are just prostitutes of Wall Street and to what extent they are independent oil production companies?

Jan 08, 2018 | peakoilbarrel.com

shallow sand x Ignored says: 01/05/2018 at 6:36 am

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.

So, we will see.

Mike x Ignored says: 01/05/2018 at 6:47 am
Shallow, here you go: https://www.forbes.com/sites/daneberhart/2018/01/04/revenge-of-the-oil-services-sector-in-2018/#25e1060569e9 maybe this, rising interest rates, and fresh water issues in 2018 in arid West Texas will slow the bastards down a little and help give us some price stability.
Longtimber x Ignored says: 01/05/2018 at 2:14 pm
"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."

http://peakoil.com/production/america-could-become-oil-king-of-the-world-in-2018
http://money.cnn.com/2018/01/03/investing/oil-us-russia-saudi-arabia-shale/index.html
y MAD MAD MAD Mad 2018 world. Just drive down and dig it up, dig it all up.
https://www.youtube.com/watch?v=w00Kab17aeI

Guym x Ignored says: 01/05/2018 at 7:11 pm
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.
likbez says: 01/07/2018 at 7:30 pm
shallow sand,

>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.

[Jan 05, 2018] Oil And Gas Run Low As East Coast Sees Record Snowfall

Jan 05, 2018 | oilprice.com

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.

[Jan 03, 2018] Oil production in the USA remains flat

Notable quotes:
"... At this point the only (legal) reason left to explain the divergence is that the EIA has started including NGL into their numbers ..."
Dec 29, 2017 | peakoilbarrel.com

Energy News says: 12/29/2017 at 11:54 am

EIA 914 Survey, October crude oil production 9,637 kb/day, +167 kb/day m/m. September revised down -11 kb/d to 9,470 kb/day

Texas October 3,767 kb/day, September 3,561 kb/day revised down -13 kb/d

Gulf of Mexico October (Hurricane Nate) 1,449 kb/day, September 1,649 kb/day, revised -1 kb/d

https://www.eia.gov/petroleum/production/#oil-tab

dclonghorn says: 12/29/2017 at 12:00 pm
EIA estimated Texas production at 3767000 bpd vs Dr Dean's above estimate of 3305000 bpd a difference of 462000 bpd. Wow that is a big difference.
Dean says: 12/29/2017 at 12:13 pm
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.

Dean says: 12/29/2017 at 1:55 pm
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:

https://twitter.com/ZmansEnrgyBrain/status/946796541406208000

[Jan 03, 2018] No major discoveries in 2017

Notable quotes:
"... 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. ..."
Dec 21, 2017 | peakoilbarrel.com

George Kaplan, says: 12/21/2017 at 6:55 am

https://www.rystadenergy.com/NewsEvents/PressReleases/all-time-low-discovered-resources-2017

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.

Dennis Coyne, says: 12/21/2017 at 8:14 am
Thanks George.

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.)

SouthLaGeo, says: 12/21/2017 at 8:38 am
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.
George Kaplan, says: 12/21/2017 at 8:50 am
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.

George Kaplan, says: 12/21/2017 at 8:50 am
And EF.

George Kaplan, says: 12/21/2017 at 8:54 am
About 50/50, maybe slightly more gas because of the big BP find, which I thought was 2.5Gboe but they have as 2.
Dennis Coyne, says: 12/21/2017 at 10:54 am
Thanks George,

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.

George Kaplan, says: 12/22/2017 at 3:22 am
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.
Dennis Coyne, says: 12/22/2017 at 8:59 am
Hi George,

I am not sure exactly how it works.

I found this:

https://sprioilgas.com/sec-oil-and-gas-reserve-reporting/

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.

George Kaplan, says: 12/21/2017 at 6:56 am
EIA reserve estimates were due at the end of November, but still haven't appeared, maybe they don't look so good?
Dennis Coyne, says: 12/21/2017 at 8:15 am
Hi George,

Last year it was mid Dec, maybe at the end of the year. Not sure why it takes so long as these are 2016 reserves as of Dec 31, 2016.

George Kaplan, says: 12/21/2017 at 6:59 am
https://www.rystadenergy.com/NewsEvents/Newsletters/UsArchive/shale-newsletter-december-2017

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.

Fernando Leanme, says: 12/21/2017 at 10:14 am
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.
Dennis Coyne, says: 12/22/2017 at 2:38 pm
Hi George,

Great article, thanks.

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.

Ron Patterson, says: 12/25/2017 at 7:00 am
Another article citing that same Rystad report:

Shale Growth Hides Underlying Problems

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.

George Kaplan, says: 12/21/2017 at 7:16 am
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.

FreddyW, says: 12/23/2017 at 5:31 am
Dennis,

"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."

US LTO increased production. But conventional prioduction not so much (outside OPEC). Remember this?
https://www.ft.com/content/35950e2a-a4be-11e3-9313-00144feab7de
(google for "ExxonMobil targets $5.5bn spending cuts")

"There's also rail, ridesharing, telecommuting, public transportation etc. High oil prices will lead to changes."

Yes I agree on that. Changes will have to happen.

Dennis Coyne, says: 12/26/2017 at 2:20 pm
Hi Tech guy,

http://www.imf.org/external/datamapper/NGDP_RPCH@WEO/WEOWORLD

World real economic growth has been about 3.5% per year since 2012.

https://www.bis.org/statistics/totcredit.htm?m=6%7C380%7C669

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.

Dennis Coyne, says: 12/27/2017 at 5:12 pm
Hi Techguy,

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.

That's a lower level than 2014.

George Kaplan, says: 12/21/2017 at 7:25 am
https://www.eia.gov/petroleum/weekly/

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?

Jeff, says: 12/21/2017 at 9:05 am
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.

Heinrich Leopold, says: 12/21/2017 at 4:49 pm
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.
George Kaplan, says: 12/22/2017 at 3:26 am
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.
FreddyW says: 12/22/2017 at 5:39 am
You are wrong on this point. See
https://www.reuters.com/article/us-oil-storage-kemp/should-we-worry-as-oil-stocks-hit-3-billion-barrels-kemp-idUSKCN0T92PP20151120

The lowest value the commercial oil stocks have been since 1982 was 247 mb in 2004:
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCESTUS1&f=W

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.

George Kaplan, says: 12/22/2017 at 3:26 am
I was speculating about future undershoot, not current conditions.
Dennis Coyne, says: 12/22/2017 at 9:34 am
Hi George,

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.

Longtimber, says: 12/21/2017 at 4:17 pm
http://www.zerohedge.com/news/2017-12-20/another-governor-demands-state-pension-abandon-fiduciary-duties-sell-fossil-fuel-inv
A factor in Future production if Pension Shale Patch backing is reduced? A sample position breakout in there.
texas tea, says: 12/22/2017 at 8:03 am
"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 😜
twocats, says: 12/22/2017 at 2:03 pm
"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.

Boomer II, says: 12/22/2017 at 6:40 pm
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.

Dennis Coyne, says: 12/24/2017 at 8:44 am
Hi Boomer II,

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.

David Archibald, says: 12/21/2017 at 10:10 pm
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.

Paul Pukite (@WHUT), says: 12/21/2017 at 10:57 pm

David Archibald says

https://www.mediamatters.org/blog/2014/04/14/meet-david-archibald-the-fringe-scientist-predi/198886

Hickory, says: 12/22/2017 at 11:30 pm
Thanks Paul. Good to know the bias of the author.
Watcher, says: 12/22/2017 at 2:11 am
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.

Watcher, says: 12/23/2017 at 2:24 am
https://fred.stlouisfed.org/series/M12MTVUSM227NFWA/

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.

OFM, says: 12/23/2017 at 8:23 am
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.

Krisvis says: 12/23/2017 at 10:04 am
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.

https://www.businesswire.com/news/home/20171206005367/en/Wolf-Midstream-Partners-Plans-New-Permian-Basin#.Wik_YewJKuc.twitter
https://www.upi.com/More-US-oil-export-capacity-in-the-works/8051512568297/?spt=su&or=btn_tw
https://www.businesswire.com/news/home/20171222005375/en/EPIC-Announces-Approval-New-Build-730-mile-Permian

HuntingtonBeach, says: 12/24/2017 at 2:34 am
"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."

http://www.saudigazette.com.sa/article/524652/Opinion/OP-ED/Dont-be-taken-in-by-the-surge-in-oil-prices

Heinrich Leopold, says: 12/27/2017 at 10:04 am
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.

The next weeks could now be very interesting.

coffeeguyzz, says: 12/27/2017 at 11:07 am
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.

Heinrich Leopold, says: 12/27/2017 at 11:47 am
Coffee,

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.

coffeeguyzz, says: 12/27/2017 at 12:35 pm
Mr. Leopold

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.

[Jan 03, 2018] Is fracking gas production in the USA is sustainable, or this is yet another "subprime" bubble?

Jan 03, 2018 | www.nakedcapitalism.com

likbez , January 3, 2018 at 5:10 pm

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,

[Jan 03, 2018] Quick rump up of oil production is impossible. There will no the second shale revolution in the current range of oil prices, or may be ever

Jan 03, 2018 | peakoilbarrel.com

says: 12/27/2017 at 8:37 pm

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!

Heinrich Leopold x Ignored says: 12/30/2017 at 8:12 am
Shallow sand,

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.

Energy News x Ignored says: 12/28/2017 at 4:36 am
INEOS Forties Pipeline System Media Update – 28/12/2017
All restrictions on the flow of oil and gas from platforms feeding into the pipeline system have been fully lifted. All customers and control rooms have now been informed.
https://www.ineos.com/businesses/ineos-fps/news/ineos-forties-pipeline-system-media-update/
https://uk.reuters.com/article/forties-oil/update-1-ineos-sees-forties-oil-flows-back-to-normal-around-new-year-idUKL8N1OS0VU
Stephen Hren x Ignored says: 12/28/2017 at 12:59 pm
https://mobile.nytimes.com/2017/12/27/world/americas/venezuela-oil-pdvsa.html?action=click&module=Top%20Stories&pgtype=Homepage

Oil production in Venezuela appears to be in free fall.

Mushalik x Ignored says: 12/28/2017 at 4:37 am
Shale gas revolution did not last long for BHP – the Fayetteville story
http://crudeoilpeak.info/shale-gas-revolution-did-not-last-long-for-bhp-the-fayetteville-story
Heinrich Leopold x Ignored says: 12/30/2017 at 6:37 am
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 ?
Energy News x Ignored says: 12/28/2017 at 7:31 am
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
Dennis Coyne x Ignored says: 12/28/2017 at 7:33 am
https://www.bloomberg.com/news/articles/2017-12-27/all-that-new-shale-oil-may-not-be-enough-as-big-discoveries-drop

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.

George Kaplan x Ignored says: 12/28/2017 at 9:39 am
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).
George Kaplan x Ignored says: 12/29/2017 at 5:00 am
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).
Dennis Coyne x Ignored says: 12/30/2017 at 7:37 am
Hi George,

Headlines are almost always not quite right.

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.

George Kaplan x Ignored says: 12/28/2017 at 9:50 am
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.

(Apologies if this has already been posted)

George Kaplan x Ignored says: 12/28/2017 at 9:53 am
ps – for numbers: last month C&C was down 35 kbpd, and overall 210 kbpd y-o-y (almost exactly 10%).
Lightsout x Ignored says: 12/28/2017 at 10:11 am
Hi George

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.

George Kaplan x Ignored says: 12/28/2017 at 11:27 am
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)?
George Kaplan x Ignored says: 12/29/2017 at 10:19 am
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.

Greenbub x Ignored says: 12/30/2017 at 1:26 am
thanks, George
Energy News x Ignored says: 12/28/2017 at 1:04 pm
Dallas Fed Energy Survey – December 28, 2017 – At what West Texas Intermediate (WTI) crude oil price would you expect the U.S. oil rig count to substantially increase?
Above $60, chart on Twitter: https://pbs.twimg.com/media/DSJdl-zX0AAUwD4.jpg
https://www.dallasfed.org/research/surveys/des/2017/1704.aspx#tab-questions
Frugal x Ignored says: 12/28/2017 at 11:11 pm
$16B Mackenzie pipeline project cancelled

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.

George Kaplan x Ignored says: 12/29/2017 at 6:50 am
IRAQ FORMS PANEL TO OPERATE MAJNOON FIELD

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.

http://www.ogj.com/articles/2017/12/iraq-forms-panel-to-operate-majnoon-field.html

Heinrich Leopold x Ignored says: 12/29/2017 at 9:28 am
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.
Ian H x Ignored says: 12/29/2017 at 7:25 am
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.

[Dec 16, 2017] Is The Oil Glut Set To Return

Notable quotes:
"... 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. ..."
Dec 16, 2017 | www.nakedcapitalism.com

likbez , , December 17, 7935 at 3:13 pm

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).

Jim Haygood , December 15, 2017 at 7:07 am

' The surplus will be front-loaded – the first half of the year will see a glut of about 200,000 bpd. '

That don't square at all with WTI futures being backwardated from Feb 2018 ($57.08) to Dec 2022 ($49.79).

http://data.tradingcharts.com/futures/quotes/cl.html

Me so bullish

ChrisFromGeorgia , December 15, 2017 at 7:46 am

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

nonsense factory , December 15, 2017 at 11:19 am

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. . .

Octopii , December 15, 2017 at 8:14 am

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.

[Dec 04, 2017] End of cheap oil will probably bring more wars as nations will try to get to remaning reserves

Notable quotes:
"... 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. ..."
Dec 04, 2017 | www.unz.com

@Vidi

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.
@Erebus

"(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.

[Nov 30, 2017] Venezuela Could Lose A Lot More Oil Production

Nov 30, 2017 | oilprice.com

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.

[Nov 30, 2017] Venezuela Could Lose A Lot More Oil Production

Nov 30, 2017 | oilprice.com

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.

[Nov 27, 2017] 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.

Notable quotes:
"... 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. ..."
Nov 27, 2017 | peakoilbarrel.com

Mike says: 11/16/2017 at 9:41 am

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.

[Nov 25, 2017] Looks like someone hasnt been honest about its production figures for Bakken

Notable quotes:
"... 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. ..."
Nov 25, 2017 | peakoilbarrel.com

SRSrocco says: 11/15/2017 at 7:20 pm

shallow,

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.

steve

shallow sand says: 11/15/2017 at 7:28 pm
Any hints?

Company or government?

SRSrocco says: 11/15/2017 at 7:39 pm
shallow,

I probably said too much already. However, I just spoke with the ex-senior person from the company. He is going public before the end of the year.

If this news spreads as far and wide as I imagine oh well, we are going to see investors FLEE the Shale Oil Ponzi.

steve

SRSrocco says: 11/18/2017 at 1:09 pm
shallow,

If you get this, why don't you respond to me at my contact info below:

SRSrocco@gmail.com .

[Nov 25, 2017] The amount of capital being burned on energy in the USA is truly remarkable.

Nov 25, 2017 | peakoilbarrel.com

Dennis Coyne says: 11/15/2017 at 6:12 pm

Bakken stats

https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf

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.

Director's cut at link below

https://www.dmr.nd.gov/oilgas/directorscut/directorscut-2017-11-15.pdf

shallow sand says: 11/15/2017 at 6:39 pm
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.

[Nov 25, 2017] As we moved closer to oil deficit, suddenly, an extra outage will cause meaningful rallies instead of being mostly written off

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. ..."
May 20, 2016 | peakoilbarrel.com

Brian Rose , 05/19/2016 at 11:04 pm

Big news from Canada today:

http://www.reuters.com/article/us-canada-wildfire-idUSKCN0YA0Z1

"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.

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".

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.

George Kaplan , 05/20/2016 at 1:36 am
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.

[Nov 10, 2017] OPEC World Oil Outlook 2017

Nov 10, 2017 | peakoilbarrel.com

George Kaplan

says: 11/08/2017 at 7:08 am
OPEC World Oil Outlook 2017 (just released):

https://woo.opec.org

Jeff says: 11/08/2017 at 7:59 am
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"

George Kaplan says: 11/08/2017 at 8:13 am
"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.

George Kaplan says: 11/08/2017 at 7:59 am
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.

[Oct 29, 2017] 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.

Notable quotes:
"... 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. ..."
Oct 29, 2017 | peakoilbarrel.com

FreddyW says: 10/28/2017 at 6:13 am

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.

coffeeguyzz says: 10/28/2017 at 9:48 am
Freddy

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.

This will skew historical WOR computations.

[Oct 28, 2017] Aramco CEO Warns Of Imminent Oil Supply Crunch by Tsvetana Paraskova

Oct 24, 2017 | oilprice.com

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.

[Oct 25, 2017] As oil is depleted major companioes need to find new niche to continue to exist

Oct 25, 2017 | peakoilbarrel.com

Fred Magyar says: 10/25/2017 at 9:03 am

The decisions to not develop these discoveries were made either because of disappointing appraisal, or low oil prices, or a combination the two.

Wonder if that might have something to do with this as well?
http://money.cnn.com/2017/10/12/investing/shell-oil-buys-electric-car-charging/index.html

Oil giant Shell bets on electric cars

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.

George Kaplan says: 10/25/2017 at 9:15 am
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.
SRSrocco says: 10/25/2017 at 4:15 pm
George Kaplan,

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.

Regardless I just posted a new article titled U.S. DEEPWATER OFFSHORE OIL INDUSTRY TRAINWRECK APPROACHING: https://srsroccoreport.com/u-s-deep-water-offshore-oil-industry-trainwreck-approaching/

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.

Steve

SRSrocco says: 10/25/2017 at 4:17 pm
Here is a link to the Chart I could not post in the comment above:

https://dj0s31cxqi9ot.cloudfront.net/wp-content/uploads/2017/10/TRANSOCEAN-Ultra-Deepwater-Rigs-Utilization-768×545.png?x65756

Guym says: 10/25/2017 at 7:11 am
Great post. Do you have any idea of the oil price that may bring back a higher level of exploration effort?
George Kaplan says: 10/25/2017 at 7:28 am
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.
Guym says: 10/25/2017 at 7:41 am
Yeah, whatever it would have to be, would have to be more stable and higher than current. So, probably no big bidders on the 97 million acres in 2018.
SouthLaGeo says: 10/25/2017 at 7:45 am
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.
George Kaplan says: 10/25/2017 at 10:38 am
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.
Watcher says: 10/25/2017 at 11:06 am
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.

[Oct 15, 2017] The global oil supply report from HSBC

Oct 15, 2017 | peakoilbarrel.com

FreddyW

says: 10/14/2017 at 10:01 am
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

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.

[Oct 15, 2017] Timing of peak global oil production

Notable quotes:
"... 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. ..."
Oct 15, 2017 | peakoilbarrel.com

Ron Patterson says: 10/14/2017 at 7:31 am

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.

Dennis Coyne says: 10/14/2017 at 11:39 am
Hi Ron,

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.

[Oct 15, 2017] US Baker Hughes Rig Count

Oct 15, 2017 | peakoilbarrel.com

Energy News: 10/13/2017 at 1:13 pm

US Baker Hughes Rig Count (Oct 13)

http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother

[Oct 15, 2017] Oil production in Iraq has increased by more then one million barrels a day since July 2014 when oil prices last averaged 100 dollars. More than any other country

Notable quotes:
"... 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. ..."
Oct 15, 2017 | peakoilbarrel.com

Energy News: 10/14/2017 at 1:02 pm

I was just having a quick look at countries that have come back from outages, sanctions, conflict, wildfires. Not sure if this list is complete?

Energy News says: 10/14/2017 at 1:55 pm
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
FreddyW says: 10/14/2017 at 10:01 am
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.

[Oct 14, 2017] The unexplainable rise in production per well in the Bakken may not be as high as the data shows

Oct 14, 2017 | peakoilbarrel.com

SRSrocco says: 10/13/2017 at 7:17 am

Verwimp,

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: SRSroccoReport@gmail.com , 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.

[Oct 14, 2017] Over half a million barrels per day are now shut down at Gulf due to hugrage season. Lost oil production due to Nate was around 8 million barrels

Oct 14, 2017 | peakoilbarrel.com

Energy News says: 10/11/2017 at 4:22 pm

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.

Also, Genscape GoM production chart: https://pbs.twimg.com/media/DL4r7v6UEAA75uK.jpg

[Oct 11, 2017] OPEC, IEA and drillers/service companies are raising the problem of the lack of investment, but they all stay away from discussing the fall in discoveries and lack of attractive prospective projects

Oct 11, 2017 | peakoilbarrel.com

George Kaplan says: 10/10/2017 at 7:28 am

OPEC SECRETARY GENERAL: 'WORLD CAN'T AFFORD SUPPLY CRUNCH'

https://www.energyvoice.com/video-2/152718/watch-opec-secretary-general-world-cant-afford-supply-crunch/

(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.

[Oct 07, 2017] 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 thesegrowth projections for their individual companies, and the EIA just totaled them up

Notable quotes:
"... 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. ..."
Oct 07, 2017 | peakoilbarrel.com

Bob Frisky

says: 09/22/2017 at 6:06 pm
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

https://www.bloomberg.com/news/articles/2017-09-21/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.

shallow sand says: 09/22/2017 at 11:38 pm
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?

George Kaplan says: 09/23/2017 at 2:08 am
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).

[Oct 07, 2017] The American public, and the politicians that govern it, have been lied to and completely deceived about shale oil and shale gas abundance.

Oct 07, 2017 | peakoilbarrel.com

Mike says: 09/23/2017 at 7:07 am

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.

shallow sand says: 09/23/2017 at 8:31 am
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.

What do you (or others) think?

[Oct 07, 2017] If you're not bringing new production and the global decline rate is 5 percent then annual loss is about four and a half million barrels per day

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. ..."
Oct 07, 2017 | peakoilbarrel.com

Watcher

says: 09/28/2017 at 1:46 am
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.

Energy News says: 09/27/2017 at 12:48 pm
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.

Karoon Gas Australia Ltd won the block with a signing bonus worth 20 million reais ($6.3 million), but the remaining 75 blocks in the basin received no bids, oil industry watchdog ANP said. Officials expected to sell up to 40 percent of the blocks, raising 500 million reais ($157 million).
http://www.reuters.com/article/brazil-oil-auction/update-2-brazils-prized-santos-basin-receives-single-bid-in-oil-auction-idUSL2N1M80O5

George Kaplan says: 09/28/2017 at 12:47 am
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.
Lightsout says: 09/30/2017 at 4:13 am
Hi George

Two more dry holes in the Barents sea.

http://www.worldoil.com/news/2017/9/28/lundin-petroleum-completes-drilling-of-boerselv-exploration-well

http://www.worldoil.com/news/2017/9/27/eni-norge-drills-dry-hole-near-goliat-field-in-the-barents-sea

George Kaplan says: 09/30/2017 at 5:04 am
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.
George Kaplan says: 09/27/2017 at 6:34 am
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.

http://www.worldoil.com/news/2017/9/26/market-should-prepare-more-for-oil-squeeze-than-opec-supply-gain-citigroup-says

Eulenspiegel says: 09/26/2017 at 10:16 am
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.

[Oct 04, 2017] U.S. Shale Isn't As Strong As It Appears by Nick Cunningham

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 ..."
Oct 02, 2017 | oilprice.com
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 ."

[Oct 04, 2017] China's Oil Demand Is Far Ahead Of Last Year's Pace by Robert Rapier

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. ..."
Oct 04, 2017 | oilprice.com
Monthly Oil Market Report which covers the global oil supply and demand picture through July.

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.

[Sep 27, 2017] Interviewed this morning, Harold Hamm calls EIA STEO projections flat out wrong. US will be lucky to achieve 9.35 million b/day by December

Sep 21, 2017 | peakoilbarrel.com

Energy News, 09/21/2017 at 3:43 pm

Interviewed this morning, Harold Hamm calls EIA STEO projections flat out wrong.

US will be lucky to achieve 9.35 million b/day by December.

https://www.bloomberg.com/news/articles/2017-09-21/shale-billionaire-hamm-slams-exaggerated-u-s-oil-projections

[Jul 23, 2017] They are all losing money. 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.

Jul 23, 2017 | peakoilbarrel.com

Watcher

says: 07/17/2017 at 8:21 am

Dood, they are all losing money.

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?

Ves

says: 07/17/2017 at 9:08 am

http://wolfstreet.com/2017/07/17/2-billion-private-equity-fund-collapses-to-almost-zero/

"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.

Boomer II

says: 07/17/2017 at 10:46 am

From the WSJ article.

"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."

Glenn E Stehle says: 07/17/2017 at 11:39 am
Ves,

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.

https://www.enervest.net/operations/locations-map.html

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. 😊

Ves says: 07/17/2017 at 12:34 pm
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?
Glenn E Stehle says: 07/18/2017 at 5:05 pm
Ves,

For me it is has been "milk and honey in the oil patch." So here's how I feel about it .

https://m.popkey.co/e975d7/JmXzE.gif

Watcher says: 07/17/2017 at 1:30 am
Anyone have info on average Bakken water disposal costs?

They are all losing money, but beyond that water costs usually determine the production level below which cap and abandon.

Watcher says: 07/21/2017 at 11:00 am
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.

shallow sand says: 07/17/2017 at 11:50 am
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.

Watcher says: 07/17/2017 at 1:22 pm
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.

There is nothing anyone can do about it.

coffeeguyzz says: 07/17/2017 at 1:30 pm
Shallow

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,

clueless says: 07/17/2017 at 3:14 pm
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.

shallow sand says: 07/17/2017 at 4:37 pm
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.

simon oaten says: 07/17/2017 at 5:57 pm
Shallow,

good paper by mr ray dalio "deleveraging" – worth the time to read .

as you say – history doesn't repeat

rgds
simon

Jeff says: 07/17/2017 at 3:17 pm
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.

Guy M says: 07/17/2017 at 5:11 pm
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.

[Jul 23, 2017] I Have Taken A Closer Look At The Data From EIA... Why Horseman Global Is Aggressively Shorting Shale

Notable quotes:
"... 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. ..."
Jul 23, 2017 | www.zerohedge.com

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...

[Jul 23, 2017] I was continually swayed by the statements from the US shale drillers that they have managed to cut breakeven prices even further.

Jul 23, 2017 | peakoilbarrel.com

Mike

says: 07/22/2017 at 6:41 pm

Here's one for the shale poodles to gnaw on:

"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)."

http://www.zerohedge.com/news/2017-07-22/i-have-taken-closer-look-data-eia-why-horseman-global-aggressively-shorting-shale

MASTERMIND says: 07/22/2017 at 8:52 am
Modern agriculture is the use of land to convert petroleum into food. Without petroleum we will not be able to feed the global population."

Professor Albert Bartlett, University of Colorado, USA

[Jul 23, 2017] Most of us have underestimated how successful light-tight frac oil has now become but what is more important we underestimated how successful MRC and associated technology has been for many gulf nations. They postponed the day of reckoning for at least a decade.

Notable quotes:
"... 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. ..."
Jul 23, 2017 | peakoilbarrel.com

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.

dclonghorn

says: 07/20/2017 at 1:05 pm

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?

coffeeguyzz says: 07/20/2017 at 1:52 pm
dclonghorn

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

Boomer II says: 07/20/2017 at 2:05 pm
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.

Glenn E Stehle says: 07/20/2017 at 2:24 pm
coffeeguyzz,

The way I understand the term Maximum Reservoir Contact (MRC) is that it refers to multiple laterals being drilled from a single vertical wellbore.

I've seen this done in the Devonian in west Texas, but that is a conventional reservoir. Has it ever been tried in US shale?

The only thing I've heard of that sounds like MRC is this project (see attached graphic), but it is still in the pilot stage.

Oxy believes it can lower cost per lateral by between $0.5 and $1.0 million, and reduce operating cost by over 50% with this technology.

https://seekingalpha.com/article/4069021-occidental-petroleum-corporation-2017-q1-results-earnings-call-slides

coffeeguyzz says: 07/20/2017 at 3:01 pm
Glenn

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.

dclonghorn says: 07/20/2017 at 3:47 pm
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.

Do you know if other areas have adopted this?

coffeeguyzz says: 07/20/2017 at 6:54 pm
dc

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.

Boomer II says: 07/20/2017 at 10:03 am
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.
MASTERMIND says: 07/20/2017 at 12:53 pm
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".

Watcher says: 07/21/2017 at 11:16 am
Bakken NGLs.
http://badlandsngls.com/uploads/1/BadlandsPresentationforBakkenConfMay16.pdf

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.

[Jun 15, 2017] Just 35 percent of the fleet – mostly large bulkers, tankers and container ships – is responsible for 80 percent of shipping's fuel consumption

Jun 14, 2017 | economistsview.typepad.com

im1dc, June 14, 2017 at 03:54 PM

The Reducing Ocean Shipping CO2 Paradox

Hey, maybe they should go back to sails...

http://maritime-executive.com/article/big-ships-account-for-most-of-shippings-co2

"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."...

libezkova - , June 14, 2017 at 05:58 PM
That's a valid observation.

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.

[Jun 03, 2017] Energy production and GDP

www.counterpunch.org

pgl , June 03, 2017 at 11:03 AM

Jun 03, 2017 | economistsview.typepad.com
Menzie Chinn:

http://econbrowser.com/archives/2017/06/why-did-the-president-rely-upon-a-consultants-report-for-his-decision-on-the-paris-accord

"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":

http://assets.accf.org/wp-content/uploads/2017/03/170316-NERA-ACCF-Full-Report.pdf

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.

libezkova - , June 03, 2017 at 01:29 PM
Any 2040 forecast of GDP needs to be based on the forecast of the price of fossil fuels.

http://corporate.exxonmobil.com/en/energy/energy-outlook

libezkova - , June 03, 2017 at 01:44 PM
They predict:

"World GDP doubles from 2015 to 2040, with non-OECD GDP increasing 175 percent and OECD GDP growing 60 percent"

im1dc - , June 03, 2017 at 02:16 PM
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)

http://oilprice.com/Energy/Energy-General/OPEC-Cuts-Send-Russias-Oil-Heartland-Into-Decline.html

"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."

libezkova - , June 03, 2017 at 04:18 PM
"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/ )

[May 30, 2017] US shale production increase scenarios at different WTI prices and cost inflation levels assuming no new debt

May 30, 2017 | peakoilbarrel.com

Energy News says: 05/29/2017 at 7:06 am

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

Jeff says: 05/29/2017 at 8:04 am
Thank you for the link.

"call on shale" – they may return the call if the price is >70 to 80 USD/bbl.
"call on OPEC" – what will it take for them to return the call?

AlexS says: 05/29/2017 at 9:14 am
Energy News,

Thanks for the link.

I particularly liked these calculations:

"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."

Eulenspiegel says: 05/29/2017 at 9:58 am
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.

Kolbeinh says: 05/29/2017 at 1:17 pm
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.

Glenn E Stehle says: 05/29/2017 at 6:34 pm
1. The areal extent of the Permian Basin shale oil plays is quite large in comparison to other plays.

http://www.shaleexperts.com/images/Permian-Basin-Geology.png

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.

http://www.aogr.com/assets/images/content/4_0616_fig3_sp16.png

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.

[May 30, 2017] In the business outlook section, the Keane Group states they are seeing higher pricing for fracking services

May 30, 2017 | peakoilbarrel.com
shallow sand says: 05/26/2017 at 7:29 am
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.

Watcher says: 05/26/2017 at 10:59 am
> 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:

http://www.businessinsider.com/youve-never-seen-anything-like-the-williston-oil-boom-2012-3#here-is-a-load-of-proppant-from-china-used-to-frac-a-well-sitting-at-the-rail-head-25

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.

[May 30, 2017] Occidental story suggest that it might be bought

peakoilbarrel.com
coffeeguyzz says: 05/29/2017 at 10:41 pm
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.

Cowboyistan.

Watcher says: 05/30/2017 at 2:25 am
That's really exciting. So was their latest earnings report.

OXY -$0.69 / share
Oh and btw, EOG -$1.08/share

The plan would be to sell the acreage to some shale operator with more expertise at achieving profit, like Continental Resources.

CLR -$0.54/share

Eulenspiegel says: 05/30/2017 at 2:55 am
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.

Glenn E Stehle says: 05/30/2017 at 9:03 am
Watcher,

Read it and weep.

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."

In Fight Against US Shale Oil, OPEC Risks Lower for Longer
http://www.rigzone.com/news/article.asp?a_id=150118

Boomer II says: 05/30/2017 at 10:38 am
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."
AlexS says: 05/30/2017 at 12:07 pm
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
AlexS says: 05/30/2017 at 1:28 pm
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.
AlexS says: 05/30/2017 at 2:56 pm
Glenn,

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.

AlexS says: 05/30/2017 at 1:39 pm
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.

That's the reality!

OXY's segment earnings
click to enlarge:

Ves says: 05/30/2017 at 5:25 pm
"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.

shallow sand says: 05/30/2017 at 1:02 pm
Oxy breaks down EPS by segments.

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.

shallow sand says: 05/30/2017 at 1:13 pm
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".

[May 30, 2017] Us shale companies ponsi

May 30, 2017 | peakoilbarrel.com
Energy News says: 05/26/2017 at 9:53 am
I've not seen any recent news on energy debt, no doubt Bloomberg will write an update sooner or later

jed says: 05/26/2017 at 5:36 pm
Had to laugh, earlier in the week I noticed zero hedge suddenly started reporting in "Lower 48 production" after US production dropped last week.

Noticed today some other guy in the comments picked it up too.

http://www.zerohedge.com/news/2017-05-26/us-crude-production-hits-21-month-highs-rig-count-rises-19th-straight-week

jed says: 05/28/2017 at 11:43 pm
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.

Dennis Coyne says: 05/30/2017 at 7:03 am
Hi Glenn,

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 $100/b (2016$).

Mike Tate says: 05/27/2017 at 6:42 am
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.

[May 30, 2017] Looks like the Chinese have been filling their SPR over the last two years

May 30, 2017 | peakoilbarrel.com
George Kaplan says: 05/24/2017 at 9:57 am
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.

Watcher says: 05/24/2017 at 6:00 pm
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.

Dennis Coyne says: 05/25/2017 at 12:30 pm
Hi Watcher,

Crude inputs to refineries and blenders was 16.2 Mb/d for the 2016 average.

https://www.eia.gov/dnav/pet/pet_pnp_inpt_dc_nus_mbblpd_a.htm

So 700/16.2 is 43 days for SPR alone. For commercial crude stocks plus SPR it is 1200 Mb so 1200/16.2=74 days.

https://www.eia.gov/dnav/pet/pet_stoc_wstk_dcu_nus_m.htm

George Kaplan says: 05/25/2017 at 2:29 pm
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.

Energy News says: 05/26/2017 at 4:26 am
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 think Zero Hedge borrowed the chart from here:
Scotiabank pdf file: http://www.gbm.scotiabank.com/scpt/gbm/scotiaeconomics63/SCPI_2017-04-12.pdf

Latest figures from Xinhua news agency
2017-05-26 Chinese oil inventories month/month April changes: crude +1.64%, oil products -7.87% (gasoline -0.27%, diesel -14.4%) – OGP/BBG

Chart showing March

Energy News says: 05/26/2017 at 8:49 am
China's April diesel stocks fall for second straight month -Xinhua
http://af.reuters.com/article/energyOilNews/idAFL4N1IS2EJ
George Kaplan says: 05/26/2017 at 1:54 pm
So are the numbers you are posting supporting or not the Zero Hedge theory and/or my projection based on it? And if not why?
Energy News says: 05/27/2017 at 1:34 pm
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 ?

[May 30, 2017] 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 doesnt appear to add anything. Unless demand tank maybe its time to be bullish?

Notable quotes:
"... 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? ..."
May 30, 2017 | peakoilbarrel.com
shallow sand says: 05/26/2017 at 10:07 pm
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?

[May 30, 2017] XOM – Potential 2nd Downgrade

Notable quotes:
"... unlike its peers such as Chevron and BP, Exxon Mobil is not targeting meaningful growth in production. ..."
"... Shell, Chevron, and BP carry debt loads of $91.6 billion, $45.3 billion and $61.8 billion, respectively. " ..."
May 30, 2017 | peakoilbarrel.com

Longtimber says: 05/30/2017 at 4:18 pm

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. "

https://seekingalpha.com/article/4077223-exxon-mobil-make-s-and-ps-warning

[Apr 17, 2017] 04/15/2017 at 9:35 am

Notable quotes:
"... 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. ..."
Apr 17, 2017 | peakoilbarrel.com
Mike 04/15/2017 at 9:35 am
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.

And this SPE paper pretty much shoots the hell out of all that "halo" bunk: https://www.spe.org/en/jpt/jpt-article-detail/?art=2819 .

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.

People do really stupid things with OPM.

George Kaplan 04/14/2017 at 10:31 am
Dennis,

... ... ...

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.

[Apr 17, 2017] Bakken average well profile from June 2015 to Dec 2017

Apr 17, 2017 | peakoilbarrel.com
Dennis Coyne, 04/14/2017 at 12:42 pm
Hi George,

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).

Dennis Coyne says: 04/14/2017 at 4:56 pm
Hi George,

That is the study I use.

https://pubs.usgs.gov/fs/2013/3013/

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).

George Kaplan says: 04/15/2017 at 2:52 am
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.

[Mar 25, 2017] The few larger, new discoveries are also in frontier, and therefore generally more expensive, regions

Mar 25, 2017 | peakoilbarrel.com
George Kaplan says: 03/23/2017 at 7:18 am
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.

[Mar 19, 2017] Good video discussion on Crude Oil production over the next 6 months from CNN

Mar 19, 2017 | economistsview.typepad.com
im1dc : March 19, 2017 at 12:41 PM , 2017 at 12:41 PM
Good video discussion on Crude Oil production over the next 6 months from CNN

http://money.cnn.com/2017/03/14/investing/opec-crude-oil-us-shale/index.html

"Is OPEC headed for a showdown with U.S. shale?"

by Ivana Kottasova...March 14, 2017...11:52 AM ET

"Is this the start of OPEC vs. American shale, round two?..."

libezkova -> im1dc... , -1
"Is this the start of OPEC vs. American shale, round two?..."

It is not.

[Mar 17, 2017] http://www.calculatedriskblog.com/2017/03/oil-another-big-rig-add.html

Mar 17, 2017 | www.calculatedriskblog.com

by Bill McBride...3/17/2017...02:47:00 PM

"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.

[Mar 05, 2017] 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

Notable quotes:
"... 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." ..."
Mar 05, 2017 | peakoilbarrel.com
Boomer II says: 03/03/2017 at 10:14 pm
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."

George Kaplan says: 03/04/2017 at 3:53 am
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.

Boomer II says: 03/04/2017 at 10:47 am
In reference to oil sands. This article came about a week ago.

Have The Majors Given Up On Canada's Oil Sands? | OilPrice.com

Boomer II says: 03/04/2017 at 10:54 am
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.

Fernando Leanme says: 03/04/2017 at 3:54 am
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.
George Kaplan says: 03/04/2017 at 3:33 am
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.
clueless says: 03/04/2017 at 12:07 pm
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.

Dennis Coyne says: 03/04/2017 at 2:24 pm
Correct that land cost is not included. I don't know what that is. This based on Rune Likverns analysis from the oil drum.
Mike says: 03/04/2017 at 2:37 pm
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/
clueless says: 03/04/2017 at 5:41 pm
Thanks Mike! That was good information and a good article.
texas tea says: 03/04/2017 at 5:35 pm
With respect to the parameters in your question:

"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.

clueless says: 03/04/2017 at 5:55 pm
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?
AlexS says: 03/04/2017 at 7:56 pm
clueless,

Current active oil and gas rig count:

OK: 98
Eagle Ford: 69
Bakken: 38

Boomer II says: 03/04/2017 at 8:27 pm
This recent analysis says: "Breakeven analysis of SCOOP and STACK shows underwhelming results compared to other major oil plays."

"Data cleaning process reduces STACK sample size for economics analysis dramatically; many 2016 wells have suspect data."

"Breakevens appear high across the greater STACK and SCOOP, however, strong economics exist within concentrated regions of the STACK and SCOOP."

"Excitement of the SCOOP and the Cana Woodford (STACK) driven by stand-out wells."

"SCOOP and STACK economics generally improving year over year, but gas focused drilling in 2016 hurts overall economics."

"SCOOP and STACK important for current operators, but limited acreage for acquisitions."

"Drilling inventory of the STACK and SCOOP plays not as extensive as other major basins."

https://btuanalytics.com/wp-content/uploads/2017/02/At-the-Center-of-it-all-SCOOP-and-STACK_Jason-Slingsby.pdf

AlexS says: 03/04/2017 at 8:37 pm
Boomer II,

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.

Watcher says: 03/04/2017 at 5:55 pm
How old is that well?
John says: 03/04/2017 at 1:53 pm
Good Morning Clueless,

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.

It could be an interesting exercise.

Boomer II says: 03/04/2017 at 2:45 pm
Split in oil-price, rig-count flows a cause for concern? Not yet. | TheHill : "That the land rig count is recovering at a stronger pace than its underlying commodity, which usually is the catalyst for changes in the rig count, does present a reason for concern."
Boomer II says: 03/04/2017 at 4:27 pm
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."
Boomer II says: 03/04/2017 at 4:33 pm
An article from February.

Third-quarter jobs down 9,000 from year before biggest decline since oil prices crashed – The Arctic Sounder : "Employment cuts across Alaska have mounted monthly since late 2015, leading to four straight quarters of job decline as Alaska remains mired in recession with the nation's worst unemployment rate.

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."

Boomer II says: 03/04/2017 at 4:39 pm
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)."

Boomer II says: 03/04/2017 at 4:50 pm
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."

[Feb 26, 2017] 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)

Feb 26, 2017 | economistsview.typepad.com
im1dc : Reply Saturday, February 25, 2017 at 10:08 AM

, February 25, 2017 at 10:08 AM
Update US Crude Oil production, market, and exports

http://maritime-executive.com/article/us-oil-exports-hit-record-levels

"U.S. Oil Exports Hit Record Levels"

By MarEx 2017-02-24

"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."...

ilsm -> im1dc... , February 25, 2017 at 01:16 PM
From the report:

The greens might not be happy US is polluting to ship gasoline and distillates out!

ilsm -> ilsm... , February 25, 2017 at 01:19 PM
See: http://www.eia.gov/petroleum/supply/weekly/

Table 1, open the .xls see data 2 for Feb 17 2017 at the bottom.

im1dc -> ilsm... , February 25, 2017 at 02:00 PM
ilsm, that is the previous week I believe.
libezkova -> ilsm... , February 25, 2017 at 04:33 PM
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.

[Feb 25, 2017] 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.

Feb 25, 2017 | economistsview.typepad.com
im1dc :

, February 25, 2017 at 10:06 AM
Gee, I can't imagine what could go wrong with this

Click and look at the map and inset to understand

Israel to become an energy, NG, superpower?

http://maritime-executive.com/article/noble-energy-sanctions-leviathan

"Noble Energy Sanctions Leviathan"

By MarEx...2017-02-24

"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."...

im1dc : , February 25, 2017 at 10:08 AM
Update US Crude Oil production, market, and exports

http://maritime-executive.com/article/us-oil-exports-hit-record-levels

"U.S. Oil Exports Hit Record Levels"

By MarEx 2017-02-24

"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."...

ilsm -> im1dc... , February 25, 2017 at 01:16 PM
From the report:

I did not see any input to the NPR.

The greens might not be happy US is polluting to ship gasoline and distillates out!

ilsm -> ilsm... , February 25, 2017 at 01:19 PM
See: http://www.eia.gov/petroleum/supply/weekly/

Table 1, open the .xls see data 2 for Feb 17 2017 at the bottom.

im1dc -> ilsm... , February 25, 2017 at 02:00 PM
ilsm, that is the previous week I believe.
libezkova -> ilsm... , February 25, 2017 at 04:33 PM
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.

[Feb 21, 2017] 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.

Feb 21, 2017 | peakoilbarrel.com
djtxyz says: 02/16/2017 at 1:44 pm
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.

George Kaplan says: 02/16/2017 at 2:17 pm
Probably too big – convert to gif or jpeg below 45 KB.
AlexS says: 02/16/2017 at 2:43 pm
FreddyW posted a chart on Bakken GOR in the previous oil thread:

http://peakoilbarrel.com/opec-january-production-data/#comment-595923

FreddyW says: 02/19/2017 at 3:53 pm
Hi,

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..

FreddyW says: 02/20/2017 at 3:02 am
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.
Fernando Leanme says: 02/16/2017 at 4:20 pm
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.
Boomer II says: 02/16/2017 at 4:51 pm
Here's a link that says in Texas there are tax advantages in reclassifying an oil well as a gas well.

http://fuelfix.com/blog/2016/11/22/pioneer-denied-request-to-reclassify-oil-wells/

Watcher says: 02/17/2017 at 1:11 pm
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.
GreenPeople's Media says: 02/16/2017 at 8:12 pm
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.

for example, this page–
http://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf

dclonghorn says: 02/16/2017 at 10:09 pm
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.

Alex K says: 02/17/2017 at 2:08 am
To dclonghorn:
Right. Another point is that more and more wells became idle so they aren't calculated in the legacy well production.
GreenPeople's Media says: 02/18/2017 at 11:28 am
Thanks. That helps clarify things for me.
Watcher says: 02/17/2017 at 2:44 am
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.

Watcher says: 02/17/2017 at 1:16 pm
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.

Watcher says: 02/17/2017 at 1:23 pm
A blast from those early days:

http://static1.businessinsider.com/image/4f5681fd69bedd0f60000048-1200/here-is-a-load-of-proppant-from-china-used-to-frac-a-well-sitting-at-the-rail-head.jpg

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).

Boomer II says: 02/17/2017 at 1:37 pm
This has been my philosophy for decades. Preserve our own resources and use up everyone else's until they run out.

Berkshire's Charlie Munger Has A Much Different Energy Plan For America Than Donald Trump | Seeking Alpha : "Munger believes that the United States should have an energy strategy that involves preserving these shale resources until some point in the future when they are much more valuable. This would be a point in time after the OPEC nations have exhausted their oil and gas reserves.

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."

Watcher says: 02/18/2017 at 12:59 pm
Sigh.

People Are Not Stupid.

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."

Boomer II says: 02/18/2017 at 3:59 pm
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.

Oldfarmermac says: 02/19/2017 at 8:11 am
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.

likbez says: 02/20/2017 at 4:51 pm
Shale oil is called subprime oil for a reason.

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:

http://www.econmatters.com/2014/11/subprime-crisis-in-shale-oil-junk-bonds.html
https://www.bloomberg.com/news/articles/2015-06-18/next-threat-to-u-s-shale-rising-interest-payments .

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.

Euan Mearns says: 02/16/2017 at 12:25 pm
BP Oil production and consumption

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.

Verwimp says: 02/17/2017 at 5:00 pm
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.

[Feb 21, 2017] Is The Bakken a Bust

Feb 21, 2017 | peakoilbarrel.com

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.

Guy M says: 02/16/2017 at 11:37 am
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.
Heinrich Leopold says: 02/17/2017 at 5:23 am
George Kaplan,

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.

GreenPeople's Media says: 02/16/2017 at 8:20 pm
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.

Is my thinking fuzzy on this?

Phil Harris says: 02/16/2017 at 12:13 pm
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.

Javier says: 02/17/2017 at 6:31 am
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.
Dennis Coyne says: 02/20/2017 at 3:22 pm
Hi Verwimp,

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.

djtxyz says: 02/16/2017 at 1:44 pm
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.

Fernando Leanme says: 02/16/2017 at 4:20 pm
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.
Boomer II says: 02/16/2017 at 4:51 pm
Here's a link that says in Texas there are tax advantages in reclassifying an oil well as a gas well.

http://fuelfix.com/blog/2016/11/22/pioneer-denied-request-to-reclassify-oil-wells/

Watcher says: 02/17/2017 at 1:11 pm
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.
Boomer II says: 02/17/2017 at 1:37 pm
This has been my philosophy for decades. Preserve our own resources and use up everyone else's until they run out.

Berkshire's Charlie Munger Has A Much Different Energy Plan For America Than Donald Trump | Seeking Alpha : "Munger believes that the United States should have an energy strategy that involves preserving these shale resources until some point in the future when they are much more valuable. This would be a point in time after the OPEC nations have exhausted their oil and gas reserves.

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."

Watcher says: 02/18/2017 at 12:59 pm
Sigh.

People Are Not Stupid.

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."

[Feb 21, 2017] To reach pay out for the wells started in 2009-2016 requires an estimated oil price of 65 dollars bbl WTI starting Jan-17. To get a return of 2.5% which can be called an inflation hedge) on the $36B requires an estimated oil price of $77 dollars bbl WTI

Notable quotes:
"... 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. ..."
Feb 21, 2017 | peakoilbarrel.com
Rune Likvern says: 02/19/2017 at 1:04 pm
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.

shallow sand says: 02/19/2017 at 4:33 pm
Rune, thank you for this post.

[Feb 20, 2017] To reach pay out for the wells started in 2009-2016 requires an estimated oil price of 65 dollars bbl WTI starting Jan-17. To get a return of two and a half percent they need 77 dollars

Notable quotes:
"... 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. ..."
Feb 20, 2017 | peakoilbarrel.com
Rune Likvern says: 02/19/2017 at 1:04 pm
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.

shallow sand says: 02/19/2017 at 4:33 pm
Rune, thank you for this post.

[Feb 20, 2017] Is The Bakken a Bust

Feb 20, 2017 | peakoilbarrel.com

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.

[Feb 20, 2017] it looks likely that the moment Dakota Access is built, there will be a pipeline capacity glut.

Feb 20, 2017 | peakoilbarrel.com
Nathanael says: 02/15/2017 at 1:15 pm
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.

https://ndpipelines.files.wordpress.com/2012/04/williston-basin-transportation-table-nov-2016.jpg

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.

[Feb 20, 2017] EUR for Bakken for new investments is assumed to be at unrealistic 980K Boe per well

Feb 20, 2017 | peakoilbarrel.com
HVACman says: 02/16/2017 at 2:04 pm
"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?

George Kaplan says: 02/16/2017 at 3:21 pm
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.
AlexS says: 02/15/2017 at 5:41 pm
Even more striking declines in drilling/completion activity for individual operators.

In December 2016, Continental had only 21 producing wells that started production in 2016, with combined output of 8.6 kb/d

In December 2015, it had 152 producing wells that were started in 2015,
with combined output of 45.1 kb/d.

In December 2014, it had 253 producing wells that were started in 2014,
with combined output of 58.9 kb/d.

So, the number of new producing wells for CLR in 2016 was 12 times less than in 2014.

AlexS says: 02/15/2017 at 6:58 pm
CLR guidance for 2017:

"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."

http://nocache-phx.corporate-ir.net/phoenix.zhtml?c=197380&p=irol-newsArticle&ID=2239817

Eulenspiegel says: 02/16/2017 at 5:39 am
Are they producing mainly gas?

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?

Questions over questions

AlexS says: 02/16/2017 at 8:21 am
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

shallow sand says: 02/16/2017 at 9:19 am
AlexS.

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.

AlexS says: 02/16/2017 at 9:24 am
shallow sand,

I agree. I think PUD estimates for tight oil formations are much more uncertain compared with conventional fields.

George Kaplan says: 02/16/2017 at 11:14 am
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).

http://www.marathonoil.com/News/Press_Releases/Press_Release/?id=1012103

[Feb 20, 2017] Bakken steep drop of production

Feb 20, 2017 | peakoilbarrel.com
Heinrich Leopold says: 02/16/2017 at 5:19 am
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.

[Feb 13, 2017] Mexican oil production is dropping

Feb 13, 2017 | peakoilbarrel.com
George Kaplan says: 02/11/2017 at 4:40 am
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.

[Feb 13, 2017] Oil industry, and particularly Shale Oil Sands part, lives in hope for the last 3 years.

Notable quotes:
"... 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. ..."
Feb 13, 2017 | peakoilbarrel.com
Ves says: 02/10/2017 at 4:16 pm
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.

[Feb 13, 2017] There is strong evidence that the US economy can survive only oil prices below 100 dollars per barrel without sliding into recession

Feb 13, 2017 | peakoilbarrel.com
Dennis Coyne says: 02/10/2017 at 9:10 am
Hi Likbez.

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.

likbez says: 02/12/2017 at 10:43 pm
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.

[Feb 12, 2017] Selling assets to pay down dividends and buy back stocks is liquidation

Feb 12, 2017 | peakoilbarrel.com
Rune Likvern says: 02/11/2017 at 4:31 pm
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.

AlexS says: 02/11/2017 at 9:43 pm
"The oil majors were not spending on CAPEX and were selling assets to pay dividends to their shareholders."

They are spending on capex (although they cut spending in 2015-16) and they are buying assets, not only selling.

[Feb 10, 2017] The twisted logic of shale propagandists assumes that investors continue to put money into shale oil companies because they believe in abiotic oil. I'm pretty sure that is

Feb 10, 2017 | peakoilbarrel.com
George Kaplan says: 02/09/2017 at 4:12 pm
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.

I like the charts though.

Rune Likvern says: 02/09/2017 at 6:02 pm
Dennis, thanks for posting this.

A few comments first of all I advise people to have a look at ExxonMobil's press release re Q4-16 , 2016 results.
http://cdn.exxonmobil.com/~/media/global/files/earnings/2016/news_release_earnings_4q16.pdf

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.

SRSrocco says: 02/09/2017 at 6:22 pm
Rune,

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.

steve

[Feb 09, 2017] 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

Notable quotes:
"... 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. ..."
Feb 09, 2017 | peakoilbarrel.com
Enno Peters says: 02/07/2017 at 8:40 am
Alex,

"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.

AlexS says: 02/07/2017 at 10:34 am
Thanks Enno,

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.

[Feb 06, 2017] Whoever holds junk bonds from Us shale operators will never get repaid. What does that mean?

Feb 06, 2017 | peakoilbarrel.com
Rune Likvern says: 02/06/2017 at 3:14 pm
From a previous post on POB.

"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.

Watcher says: 02/06/2017 at 4:11 pm
What has to happen for you guys to understand?

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.

AlexS says: 02/06/2017 at 4:46 pm
Watcher,

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.

Ron Patterson says: 02/06/2017 at 4:52 pm
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!

Rune Likvern says: 02/06/2017 at 6:45 pm
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.

[Jan 23, 2017] The US government was a big fracking cheerleader and helped to create shale oil bubble in the USA and associated smaller junk bond bubble.

Jan 23, 2017 | economistsview.typepad.com
B.T. : , January 23, 2017 at 08:44 AM
More fracking

=

Lower emissions

US C02 emissions are down 7% since 2005 thanks to natural gas from fracking displacing coal in electricity generation.

Yet backwards placing like Europe and NY ban fracking.

And don't get me started on nukes (zero emissions).

Chris G -> B.T.... , January 23, 2017 at 09:27 AM
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.
B.T. -> Chris G ... , January 23, 2017 at 09:44 AM
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.

Chris G -> B.T.... , January 23, 2017 at 09:47 AM
I'm not so sanguine re long-term ground water contamination. Agreed re other points though.
libezkova -> B.T.... , January 23, 2017 at 01:28 PM
The US government was a big fracking cheerleader and helped to create "shale oil bubble" in the USA and associated smaller "junk bond" bubble.
libezkova -> B.T.... , January 23, 2017 at 01:35 PM
B.T.

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.

-->

[Jan 23, 2017] Oil depletion might take care of the climate change

Jan 23, 2017 | economistsview.typepad.com
libezkova : January 23, 2017 at 01:26 PM , 2017 at 01:26 PM
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.

-->

[Jan 11, 2017] Cumulative total of Bakken Formation oil production.

Jan 11, 2017 | peakoilbarrel.com
R Walter says: 01/08/2017 at 11:20 pm
1,590,525,938

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.

https://www.dmr.nd.gov/oilgas/stats/statisticsvw.asp

Click on cumulative totals by formation.

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.

R Walter says: 01/09/2017 at 7:08 am
Made a mistake by a factor of ten. The 20% for royalties, it is 800,000,000 barrels for royalties, not 80,000,000.

2.8 billion barrels for the oil companies, not 3.52 billion.

[Jan 11, 2017] What percentage of US oil consumption is food transtoration

Jan 11, 2017 | peakoilbarrel.com
Watcher says: 01/10/2017 at 11:36 am
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.

Oldfarmermac says: 01/10/2017 at 12:26 pm
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.

Watcher says: 01/10/2017 at 1:58 pm
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.

Watcher says: 01/10/2017 at 3:20 pm
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.

Watcher says: 01/10/2017 at 8:07 pm
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.

Oldfarmermac says: 01/10/2017 at 5:18 pm
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, 😉

clueless says: 01/10/2017 at 2:08 pm
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.

OOPS! Of the 5.4 lbs, 30% – 40% is wasted.

Watcher says: 01/10/2017 at 3:16 pm
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.

40-50% of a steer by weight is not edible.

Oldfarmermac says: 01/10/2017 at 6:04 pm
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.

[Jan 11, 2017] Over 80- percent of convential fields are in decline!

Jan 11, 2017 | peakoilbarrel.com
BloomingDave says: 01/09/2017 at 11:30 pm
HSBC Global Research Report on Global Oil Supply
"Will Mature Field Declines Drive the Next Supply Crunch?"

Short answer: "yes."
What with 81% of conventional fields in decline!

https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view

texas tea says: 01/10/2017 at 7:23 am
I have been making the points as outlined in that piece for sometime i repeat long carbon based energy. dumb money indeed 🎉

[Jan 08, 2017] Dirty games around free cashflow and profitability of shale compnaies

Jan 08, 2017 | peakoilbarrel.com
AlexS says: 01/03/2017 at 12:23 pm
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

Watcher says: 01/03/2017 at 3:07 pm
What does independent mean?
AlexS says: 01/03/2017 at 4:04 pm
non vertically-integrated
shallow sand says: 01/03/2017 at 7:30 pm
Is interest expense included in these calculations? I am sure reduction of debt principal is not.
AlexS says: 01/03/2017 at 8:23 pm
Free cash flow = operating cash flow – capex.

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.

Free cash flow after dividends = operating cash flow – capex – dividends.

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).

Mike says: 01/03/2017 at 9:31 pm
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.

shallow sand says: 01/03/2017 at 11:38 pm
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.

Nathanael says: 01/05/2017 at 10:09 pm
"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.

Watcher says: 01/04/2017 at 11:53 am
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.

(Look familiar, OMB?)

clueless says: 01/04/2017 at 12:54 pm
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.

AlexS says: 01/04/2017 at 3:51 pm
Mike, shallow sand

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.

http://www.investopedia.com/terms/f/freecashflow.asp

AlexS says: 01/04/2017 at 5:24 pm
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.

shallow sand says: 01/04/2017 at 9:44 pm
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.

AlexS says: 01/05/2017 at 5:40 am
shallow sand,

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.

Nathanael says: 01/05/2017 at 10:13 pm
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.

clueless says: 01/05/2017 at 12:21 am
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.
shallow sand says: 01/05/2017 at 12:57 am
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.

CLR was not the only company to do this.

AlexS says: 01/05/2017 at 4:29 am
clueless,

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.

Mike says: 01/05/2017 at 8:44 am
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.

Dennis Coyne says: 01/05/2017 at 1:04 pm
Hi Mike,

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.

clueless says: 01/05/2017 at 1:12 pm
AlexS – I did not do a good job of trying to point out that I think that you have to look at more info.

If you read metric number 3 in this short article, it might be clearer.
http://www.oldschoolvalue.com/blog/investing-perspective/useless-stock-metrics/

AlexS says: 01/05/2017 at 9:26 pm
clueless,

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.

[Jan 08, 2017] Long carbon based energy perspectives

Jan 08, 2017 | peakoilbarrel.com
texas tea says: 01/05/2017 at 5:00 pm
https://wattsupwiththat.com/2017/01/05/energy-and-society-from-now-until-2040/

long carbon based energy

Key conclusions of the report:

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."

[Jan 08, 2017] High taxes create a "tax shield". The price at the pump in Europe is approx one third oil and refining and two thirds tax and duty. Consumption is therefore less responsive to the international oil market price compared to the USA. Europeians also drive smaller and more fuel efficient cars.

Jan 08, 2017 | peakoilbarrel.com
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).

Watcher says: 01/04/2017 at 11:47 am
"Most oil exporters' oil consumption/capita will probably level off and never come close to the US figure."

US per capita consumption 0.061 bpd.

Exporters:

Canada 0.066
KSA 0.135
Kuwait 0.156
Qatar 0.145
UAE 0.09

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.

Jeff says: 01/04/2017 at 2:58 pm
_most_ oil exporters.

In 2012 ( http://www.indexmundi.com/map/?v=91000 ): Ecuador (0.11), Libya (0.051), Kazakhstan (0.12), Iran (0.23), Iraq (0.22), Venezuela (0.27), Oman (0.46)

Watcher says: 01/04/2017 at 7:19 pm
mazama says Ecuador may drop to imports this year. They don't list any Libya exports. Kazakhstan and Iran are legit. And the bible doesn't track Iraq.
AlexS says: 01/04/2017 at 4:09 pm
"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.

Watcher says: 01/04/2017 at 7:11 pm
How? Will he help to increase car fleet in Russia?

Precisely.

Chris says: 01/05/2017 at 12:58 pm

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.

[Jan 08, 2017] A future oil supply trajectory

Notable quotes:
"... Desperate, broken men chase their dreams and run from their demons in the ..."
"... . A local Pastor risks everything to help them. ..."
Jan 08, 2017 | peakoilbarrel.com
George Kaplan says: 01/02/2017 at 4:43 am
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.

Nathanael says: 01/02/2017 at 5:59 pm
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.

Survivalist says: 01/03/2017 at 8:43 pm
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.
Dennis Coyne says: 01/02/2017 at 6:13 pm
Hi George,

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.

George Kaplan says: 01/03/2017 at 6:37 am
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.
Dennis Coyne says: 01/03/2017 at 11:55 am
Hi George,

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.

US lto can ramp up quickly with high oil prices.

Dennis Coyne says: 01/05/2017 at 10:42 am
Hi George,

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.

Caelan MacIntyre says: 01/01/2017 at 7:37 pm
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 )

GoneFishing says: 01/01/2017 at 7:49 pm
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.

[Jan 08, 2017] In the oil business, the long emergency is now.

Jan 08, 2017 | href="In%20the%20oil%20business,%20the%20long%20emergency%20is%20now.">