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The essence of Great condensate con was aptly formulated by Jeffrey Brown in this
econbrowser.com post (
http://econbrowser.com/archives/2016/01/world-oil-supply-and-demand#comment-194595My premise is that US (and perhaps global) refiners hit, late in 2014, the upper limit of the volume of condensate that they could process, if they wanted to maintain their distillate and heavier output–resulting in a build in condensate inventories, reflected as a year over year build of 100 million barrels in US C+C (Crude + Condensate) inventories.
Therefore, in my opinion the US and (and perhaps globally) C+C inventory data are fundamentally flawed, when it comes to actual crude oil inventory data. The most common dividing line between actual crude oil and condensate is 45 API gravity, although the distillate yield drops off considerably just going from 39 API to 42 API gravity crude, and the upper limit for WTI crude oil is 42 API. . . .
Note that (in 2015) 22% of US Lower 48 C+C production consists of condensate (45+ API gravity) and note that about 40% of US Lower 48 C+C production exceeds the maximum API gravity for WTI crude oil (42 API).
Similar observations can be found in
http://www.reuters.com/article/2015/03/23/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323In a pressing quest to secure the best possible crude, U.S. refiners are increasingly going straight to the source.
Firms such as Marathon Petroleum Corp and Delek U.S. Holdings are buying up tanker trucks and extending local pipeline networks in order to get more oil directly from the wellhead, seeking to cut back on blended crude cocktails they say can leave a foul aftertaste. . . .
Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
The blends tend to produce a higher proportion of fuel at two ends of the spectrum: light ends like gasoline, demand for which has dimmed in recent years, and lower-value heavy products like fuel oil and asphalt. What’s missing are middle distillates like diesel, where growing demand and profitability lies.
The distinction between crude and condensate is a matter of opinion. One standard the energy industry uses to compare different types of oil is called API gravity – a measure of how heavy or light petroleum is relative to water. Lighter crudes have higher gravity. For instance, West Texas Intermediate – known as WTI – is a predominant U.S. light crude and has traditionally measured an API gravity of 39 degrees on this scale. Anything above 45 degrees API can be considered condensate, depending on who you ask. Some of the stuff pouring out of wells in Texas, North Dakota, and Colorado is coming in at a range of 50 to 60 degrees API.
In the USA condensate is extracted in large quantities as a byproduct of gas producing wells from Texas to Pennsylvania. When underground condensate is mostly a gas, but it condenses into a liquid when pumped to the surface. Condensate was the natural gas production boom’s redheaded stepchild. Until natural gas production started to ramp up in U. S. shale formations, the distinction between crude and condensate didn’t matter much, and the small amounts of condensate pumped from the ground were left mixed in the crude. Now as much as 12% of daily U.S. crude production might qualify as condensate, according to energy investment bank Simmons & Co. International.
Condensate contains only around 60 – 70% of the energy content of crude oil in the same volume.
Natural-gas condensate - Wikipedia, the free encyclopedia
Natural-gas condensate is a low-density mixture of hydrocarbon liquids that are present as gaseous components in the raw natural gas produced from many natural gas fields. It condenses out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas.condensate - Schlumberger Oilfield GlossaryThe natural gas condensate is also referred to as simply condensate, or gas condensate, or sometimes natural gasoline because it contains hydrocarbons within the gasoline boiling range. Raw natural gas may come from any one of three types of gas wells:[
- Crude oil wells — Raw natural gas that comes from crude oil wells is called associated gas. This gas can exist separate from the crude oil in the underground formation, or dissolved in the crude oil. Condensate produced from oil wells is often referred to as lease condensate.[3]
- Dry gas wells —These wells typically produce only raw natural gas that does not contain any hydrocarbon liquids. Such gas is called non-associated gas. Condensate from dry gas is extracted at gas processing plants and, hence, is often referred to as plant condensate.[3]
- Condensate wells —These wells produce raw natural gas along with natural gas liquid. Such gas is also called associated gas and often referred to as wet gas.
There are many condensate sources worldwide and each has its own unique gas condensate composition. However, in general, gas condensate has a specific gravity ranging from 0.5 to 0.8, and is composed of hydrocarbons such as propane, butane, pentane, hexane, etc. Natural gas compounds with more carbon atoms (e.g. pentane, or blends of butane, pentane and other hydrocarbons with additional carbon atoms) exist as liquids at ambient temperatures.[4] Additionally, condensate may contain additional impurities such as:[5][6][7][8]
- Hydrogen sulfide (H2S)
- Thiols traditionally also called mercaptans (denoted as RSH, where R is an organic group such as methyl, ethyl, etc.)
- Carbon dioxide (CO2)
- Straight-chain alkanes having from 2 to 12 carbon atoms (denoted as C
2 to C
12)- Cyclohexane and perhaps other naphthenes
- Aromatics (benzene, toluene, xylenes, and ethylbenzene)
A low-density, high-API gravity liquid hydrocarbon phase that generally occurs in association with natural gas. Its presence as a liquid phase depends on temperature and pressure conditions in the reservoir allowing condensation of liquid from vapor. The production of condensate reservoirs can be complicated because of the pressure sensitivity of some condensates: During production, there is a risk of the condensate changing from gas to liquid if the reservoir pressure drops below the dew point during production. Reservoir pressure can be maintained by fluid injection if gas production is preferable to liquid production. Gas produced in association with condensate is called wet gas. The API gravity of condensate is typically 50 degrees to 120 degrees.
Chemical composition of condensate is different then gasoline produced by cracking and it has a lower octane number than conventional commercial distilled gasoline (Natural gasoline - Wikipedia, the free encyclopedia):
Natural gasoline is a natural gas liquid with a vapor pressure intermediate between natural gas condensate (drip gas) and liquefied petroleum gas and has a boiling point within the range of gasoline. The typical gravity of natural gasoline is around 80 API.This hydrocarbon mixture is liquid at ambient pressure and temperature. It is volatile and unstable but can be blended with other hydrocarbons to produce commercial gasoline.
The natural gas hydrocarbons mixture is mostly pentanes and heavier (smaller amounts of C6 and C6+), extracted from natural gas, that meets vapor pressure, end-point, and other specifications for natural gasoline set by the Gas Processors Association.[1] Includes isopentane which is a saturated branch-chain hydrocarbon, (C5H12), obtained by fractionation of natural gasoline or isomerization of normal pentane.[2]
Natural gasoline is often used to denature ethanol produced for E85. Natural gasoline has a lower octane content than conventional commercial distilled gasoline, so it cannot normally be used by itself for fuel for modern automobiles. However, when mixed with high concentrations of ethanol such as mid-level blends, like E50 or E85, the octane content is raised high enough to be used easily in flex-fuel vehicles. It may be sourced from production of natural gas wells (see "drip gas") or may be produced by extraction processes [3] in the field, as opposed to refinery cracking of conventional gasoline.
http://www.reuters.com/article/2015/03/23/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323
In a pressing quest to secure the best possible crude, U.S. refiners are increasingly going straight to the source.
Firms such as Marathon Petroleum Corp and Delek U.S. Holdings are buying up tanker trucks and extending local pipeline networks in order to get more oil directly from the wellhead, seeking to cut back on blended crude cocktails they say can leave a foul aftertaste. . . .
Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
The blends tend to produce a higher proportion of fuel at two ends of the spectrum: light ends like gasoline, demand for which has dimmed in recent years, and lower-value heavy products like fuel oil and asphalt. What’s missing are middle distillates like diesel, where growing demand and profitability lies.
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May 08, 2021 | peakoilbarrel.com
JEAN-FRANÇOIS FLEURY IGNORED RON PATTERSON IGNORED 05/01/2021 at 8:38 pm
Jean, I cannot get into the heads of the EIA analysis and figure out why they make the predictions they do. That is, do they really believe the shit they predict? Or do they do it as some kind of propaganda campaign to keep the shale Ponzi scheme afloat as long as possible because they think it is their civic duty to do so? I just don't know but I would imagine it is a little of both.
But we must look at the history of all the peak oil predictions. It all started around 2005 when almost everyone thought peak oil had arrived. But it did not happen. Then many thought it had arrived every couple of years since then. But the peak oil prognosticators became fewer and fewer. Now because all the predictions have been wrong in the past, it is just naturally assumed that peak oil will never happen.
So, even though almost every major producer has peak, including the three largest, the US, Russia, and Saudi Arabia, people cannot bring themselves to believe that peak oil has finally arrived, or did arrive a couple of years ago. So all we can do is shake our heads as they continue to predict that oil production will keep going up and almost forever.
But I find it rather fun to watch as finally someone else's predictions are going up in flames. 😉
There is something I don't understand. How EIA can project that the world oil production will be almost at the level of April 2020 in December 2022? If I am not wrong. KSA has apparently so much difficulties to maintain its production that they decreased their production of 1Mb/d in February to announce after a plan to decrease the domestic oil consumption of 1Mb/d to increase the amount of oil for export. And currently, they are at 8 Mb/d : in March 2020, their production was at 10 Mb/d. Russia is in oil production decline and the goal of increasing the production to the level of March 2020 (11 Mb/d) is and will be a goal for a long time as most the oil produced to compensate the loss of production (1Mb/d) will come from EOR (costly) and fracking (even more costly). For the US, I don't know how the DUC which are currently changed into completed wells and fracked will produce but as the growth of the number of operated rigs is slowing in Permian fields, I don't know how the decline of the current operated rigs will be compensated in the near future (in 6 or 12 months). I am not speaking of Baker, Eagle Ford and Niobara which are in decline. As the lower 48 states conventional oil production is in decline, as the Alaska oil production is in decline and as the GOM oil production is fairly stable, I don't know what will be the increase of US oil production in future. But I have a hunch that it won't be as glorious as the EIA can imagine (predict). Between now and December 2022, there are 6 Mb/d to compensate. If it is not coming the three main oil producers of the world, from where this will come? Iraq : no. They are sparing their oil ressources. Brazil? With pre-salt formations, they will be able to add only a maximum of 500 kb /d. Canada? They are at 5 Mb/d. I am not sure of their possibilities of production growth and even at their production growth rate, they will only add 290 kb/d or so in December 2022. Guyana will produce at most 750 kb/d in 2026. Assuming a constant rate of increase, this will give an additional 120 kb/d in December 2022. The rest of non-opec producer are, at best, only able to maintain their production. Among the rest of OPEC producers ,all are in production decline. There is only Iran which could increase its production but only 1,5 Mb/d at most. With all of this, we are a long way from increasing global oil production by 6 Mb/d until December 2022. HOLE IN HEAD IGNORED 05/02/2021 at 1:35 am
Ron , simple answer . "It is difficult to get a man to understand something, when his salary depends on his not understanding it." . –Upton Sinclair
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Mar 07, 2021 | oilprice.com
Canadian Natural Resources, Suncor Energy, and Syncrude will all idle an upgrader each, taking off 250,000 bpd, 130,000 bpd, and 70,000 bpd, respectively, from total oil sands production.
... The oil sands cut will be temporary but, according to the industry itself, even when the three companies resume operations at their upgraders, there is little upward production growth pressure in Canadian oil sands. It seems emission reduction is a bigger priority for oil sands operators than production growth.
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Apr 21, 2020 | www.moonofalabama.org
juliania , Apr 21 2020 15:43 utc | 61On the previous thread, Piotr Berman @ 417 did bring up the subject of this post by b, and had the following final comment: "...Actually, the most acute pain is among the clever folk who provided the so-called hedges, namely who sold the obligations to buy oil at a certain price. They are losing hundreds of billions -- my guess. Now they are forced to buy AND store, hence the negative price."
Thanks, Piotr. Some of what is happening makes a bit more sense to me as far as the strange dealings in the stock market are concerned.
Also, just above at 416, karlof1 had this to say: "...Was the West ever on the path to making its goal the improvement of the Common Man as advocated by Wallace and his political allies?..." His answer is NO (exclamation point.)
My answer is YES (exclamation point.) Even if you only progress as far as the creation of the UN, with the leadership of Eleanor, that is an important pivotal moment for mankind which we cannot ignore. But I will state uncategorically that the JFK administration had similar idealistic goals and would have carried them out, had it not been for divisive powers plotting against it. That such dastardly powers succeeded does not negate the previous effort.
And even the example of China proves that this is not an impossible dream for mankind in general. As also is the example of Russia. We are fortunate in this generation to have two role models instead of one.
I don't have the Frost poem at hand so I will thusly mangle the last lines (sorry)
Two paths lay in the woods, and I
Took the one less travelled by
And that has made all the difference.I've mangled it, but the meaning is there, I think. (I'll go find the correct version, and point of reference, I was a college student when Robert Frost came to Johns Hopkins and I heard him read his poems. He did so also at Kennedy's inaugural.)
gm , Apr 21 2020 10:36 utc | 8
What -$37/bbl oil means to you:arby , Apr 21 2020 12:10 utc | 17Oil futures paper contracts market (in normal times of stable->rising oil prices and plenty of tank storage capacity a simple safe "buy low, hold, sell high" investment vehicle used heavily by investment banks, hedge funds, ETFs and teachers', municipal employees', etc, retirement/pension funds) explained in 5 minutes by Chris Martenson starts at ~minute 35:00:
Emily, We may still be at or around peak oil. That does not mean that all of the heavily indebted countries and oil companies won't pump what's left as fast and hard as they can.William Gruff , Apr 21 2020 12:10 utc | 18Now you have to stir in a massive plunge in demand to the equation. Seems to me that all newer oil discoveries are deep sea or shale. All of which require much more energy to produce then say thirty years ago.
When it takes the equivalent of one barrel of energy to produce one barrel of energy it will be lights out.
dan of steele @2Emily , Apr 21 2020 12:56 utc | 24The petrodollar was not in and of itself the mechanism that the US used to "export debt" and enrich itself off global trade. Rather, the petrodollar was the mechanism used to lock-in the US$ as the global reserve currency. If you wanted oil, you needed US$. After that it was just convenient to use US$ for other internationally traded commodities as well. Of course, this made even more sense way back in the distant past of the middle of last century because most of the international trade in manufactured goods was for American products, for which you'd have to use dollars to buy anyway.
The empire fanbois will cook up all kinds of explanations for why the dollar will remain the Global Reserve Currency in order to reassure themselves of the empire's continued hegemony, but the fact is that all of the "locks" locking other countries into that regime are now gone. Countries can choose to walk away now whereas in the past that would mean giving up access to oil and no longer importing all of those awesome things that the US used to make. That is not a barrier anymore.
Arby 17.gm , Apr 21 2020 13:19 utc | 27
Thank you for taking the time to reply.
But something to ponder
Forbes
https://www.forbes.com/sites/michaellynch/2018/06/29/what-ever-happened-to-peak-oil/
Yergin
https://www.technologyreview.com/2011/09/22/191161/peak-oil-debunked/
Well good news for those of us who agree with Edgar Cayce.
'Russia is the hope of the world'.
Russia has 60 years worth left and thats with its known reserves.
Hasn't touched the Arctic yet.....
https://www.worldometers.info/oil/russia-oil/US/Western financial markets are a "musical chairs" game, where right now more chairs are being pulled out from the game faster than the FED and the central banks can 'digitally print' new chairs to keep the game going.Peter AU1 , Apr 21 2020 14:27 utc | 39Looks like energy dominance will get a bail out.juliania , Apr 21 2020 14:36 utc | 41
"We will never let the great US Oil & Gas Industry down. I have instructed the Secretary of Energy and Secretary of the Treasury to formulate a plan which will make funds available so that these very important companies and jobs will be secured long into the future!" Trump said via Twitter.
https://sputniknews.com/us/202004211079043543-trump-instructs-treasury-energy-depts-to-devise-plan-to-fund-us-oil-gas-industry/Is this a result of all the lockdowns? A sort of automotive general strike occasioned by the virus, aided and abetted by government enforcement of restrictions on industry, travel, general hulabaloo?Trisha , Apr 21 2020 15:27 utc | 56Peace has descended upon a weary world. Nature has commanded us to cease and desist from gigantic insults upon the earth. Stop digging! she says, Leave it in the ground! Cease and desist making war for oil!
What does it profit a man? It profits him nothing! I have no idea where this leads, but it is a delicious moment. Look, see the power we have to bring everything to a standstill, even when we only do it because we are forced to! What if we did it willingly?
Where are your trillions now, moghuls?
The earth has spoken. We should all listen. Me, I am going out to plant potatoes.
Peak shale has arrived. The energy inefficiency of fracking - directly related to the economic efficiency of producing shale - killed it off. This would have happened even without COVID-19.The same will (eventually) happen with oil. The global economy - already teetering - has now been pushed over the edge by COVID-19. The demand side of capitalist growth has been temporarily (and in some cases permanently) crushed - which is a good thing for the planet - as workers are idled for the foreseeable future, and many out of a job forever.
Bottom line is that we live on a finite world which capitalism treats as an infinite resource.
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Dec 21, 2019 | peakoilbarrel.com
Survivalist x Ignored says: 12/19/2019 at 3:44 pm
Energy crisis looms as forecasts ignore US shale oil qualityFreddy Gulestø x Ignored says: 12/20/2019 at 4:30 amGood article, I believe it will not only be related to US shale oil quality but also a more or less collapse in US shale , to use the shale pioneer Mark Papas words from 2019 " the best in US shale is behind " but the investors choose to not believe him as it not fits with what the shale producers had presented them. Perhaps this time wall street will learn a lesson that might be quite exspensive. I am waiting for how much Exxon will write down of their assets in Permian, that might be higher than Chevron have annonsed.Dennis Coyne x Ignored says: 12/20/2019 at 10:24 amTight oil output will not increase as much as forecast by IEA and OPEC so it is not likely a refining wall at the World level will be be reached. As to demand outrunning supply, when that occurs oil prices will rise to a level that demand is destroyed to the point that supply will equal consumption as it must over the long term. Demand (consumption) cannot be higher than supply (output) for very long as stocks cannot be less than zero plus pipeline fill and minimum storage tank levels needed to keep the overall refinery and distribution system functioning. Oil prices will rise from 2020 to 2030, of that we can be sure, unless a severe World recession occurs (I expect this to begin in 2030+/-2 years and last for 2 to 4 years if World economists remember their Keynesian economics, otherwise it could be 5 to 7 years, if nonsense like fiscal austerity in the face of severe recessions is recommended and we are foolish enough to forget the lessons of 1929-1933.)Watcher x Ignored says: 12/20/2019 at 2:05 pmOil quality is not the way to address or label the issue. Quality is a word traditionally used in oil to describe sulphur content, not a scarcity of middle distillates in the yield. Needs a different word.Further, from the article, diesel is not the consumption growth heavy constituent. It's jet fuel. Up 3.7% last year. Gasoline was up almost 1%.
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Dec 21, 2019 | peakoilbarrel.com
TonyEriksen x Ignored says: 12/18/2019 at 6:49 pm
EIA weekly supply estimates released, declining from the last two weeks of Nov at 12.9 mbd down to 12.8 mbd for the first two weeks of Dec.TonyEriksen x Ignored says: 12/20/2019 at 5:05 pm
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCRFPUS2&f=WHFIR is showing a US peak for 2019 in November of 12.7 mbd.
https://twitter.com/HFI_Research/status/1207413992848674816IHS stated that "The new IHS Markit outlook for oil market fundamentals for 2019-2021 expects total U.S. production growth to be 440,000 barrels per day in 2020 before essentially flattening out in 2021. Modest growth is expected to resume in 2022."
https://news.ihsmarkit.com/prviewer/release_only/slug/energy-base-decline-rate-oil-and-gas-output-permian-basin-has-increased-dramatically-bEIA STEO says US oil production in 2019 is 12.25 mbd. That means that IHS is forecasting 12.69 mbd in 2020. This 0.44 mbd growth is assumed to come from the 7 US shale regions on EIA DPR. In 2019, shale region production was 8.60 mbd. 2020 shale region production is forecast to be 9.04 mbd, after 0.44 mbd growth. EIA DPR says that Jan 2020 shale region production is 9.14 mbd which is greater than 9.04 mbd which means that IHS 0.44 mbd 2020 growth implies that a US peak oil is happening about now.
IHS says that modest growth is expected in 2022, but they don't quantify how much growth. I believe this sentence was added because IHS does not want to be accused of implying US oil production has peaked. Dan Yergin, vice chair of IHS, founded CERA in 1982 which is now owned by IHS. Dan Yergin "clearly doesn't care about converting peak oilers. He really wants to influence Washington." In other words, IHS says modest growth in 2022, to please Washington politicians. US shale growth might increase in 2022, even with higher oil prices, but I'm guessing it won't.
http://transitionvoice.com/2011/09/whos-afraid-of-daniel-yergin/Given decreasing money available to shale oil, declining frac spread counts and falling rig counts, I now guess that US peak oil month is Nov 2019. Permian oil production should continue increasing slowly but it's not enough to offset falling production from other shale basins and other conventional oil basins.
North American shale is expected to hit an inflection point in 2020. Our expert, Raoul LeBlanc, VP of Unconventionals, shared his insights on what's ahead for North American #shale markets.
https://ihsmarkit.com/research-analysis/video-north-american-shale-hits-an-inflection-point-in-2020.html
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Aug 22, 2019 | peakoilbarrel.com
Freddy x Ignored says: 08/19/2019 at 11:08 am
Thanks for valuable informstion Guy, in my mind from what I have read the shail oil have change some caracter espesialy in 2019. It have become more light that means lower quality. If quality goes down this will mean less profit if any at all to drill new wells after all exspensives, loan balones are payed. The good thing is it seems now low sulfur diesel demand increase because new IMO rules and prices, refinery margins in Asia increases. But it might be this will have minor Impact for WTI price as they demand more heavey oil , brent i.e for their marine diesel..
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May 13, 2019 | peakoilbarrel.com
Ignored says: 05/07/2019 at 5:04 pm Attached are the changing monthly STEO projections for February, March and April for the lower 48 production. Today's projection, April, has added 230 kb/d day by year end 2019 to the March projection and close to 300 kb/d in 2020. The April projection also shows an increase of 960 kb/d from Dec 18 to Dec 19. For Dec 19 to Dec 20, the increase is only 420 kb/d, less than half of the 18 to 19 increase. Any speculation/ideas for the lower increase for 19 to 20. The G of M drops by 70 kb/d from Dec 19 to Dec 20.
Ron Patterson x Ignored says: 05/07/2019 at 5:37 pm
Thanks, Ovi.GuyM x Ignored says: 05/07/2019 at 6:27 pmYou notice that the April 19 STEO has the lowest production numbers for Jan. Feb. and April 2019 but the highest numbers as they move into the second half of 2019 and all of 2020.
I don't know what to make of this except that I find it rather amusing.
I found it insulting to my intelligence (not an exceptionally difficult task), but now that you mention it, I can imagine some Lewis Carroll feel to it.
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Apr 27, 2019 | peakoilbarrel.com
Mike x Ignored says: 04/26/2019 at 2:30 pm
It should, don't you think? Ninety nine out of 100 people in America believe the USGS "discovered" 50 billion more barrels of oil last year in West Texas. Neither it nor the EIA go to near enough lengths to qualify these type of "surveys;" accordingly they are misleading and confusing to an uneducated public, including but not limited to, politicians in charge of implementing America's energy policies.The USGS mean average EUR in the Delaware Basin does not come close to paying out a $9MM well. How then can operators drill 244K more wells in the Delaware costing nearly $2.4 trillion dollars to recover 46.2 billion more barrels of oil? What earthly good does it do anybody to make an assessment of remaining resources over 8,000 square miles "if economics are not considered?" As stupid as the shale oil industry is, even its smart enough to know better than that.
My comment was directed at using so called unlimited, cheap shale oil resources as a foreign policy tool, not getting in a pissing match about the USGS.
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Apr 11, 2019 | peakoilbarrel.com
GuyM: 04/11/2019 at 8:44 am
EIA's projections can be taken with a grain of salt. What is happening in the US shale is becoming more apparent. Exxon and Chevron plan to gear up to supply the new additions that they will supply to their new refinery additions that will accept LTO. However, I do not see them in a massive growth campaign that will increase exports.That leaves the independents who are very much under the gun to fix financials per investors, investments firms, and the press.
I read EOG's fourth quarter discussion with the public, which was cut short due to repetitive questions on whether EOG will increase dividends.
Prices will probably rise, but I don't expect much growth, this year, from the majority of the producers, which are the independents.
At least, for this year. As the years go by, more will be gobbled up by the majors, thus providing more limits in growth.
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Apr 06, 2019 | peakoilbarrel.com
Energy News x Ignored says: 04/05/2019 at 11:19 am
Canada produced 4,524 kb/day of crude oil & equivalent products in January down -278 m/m
Exports of crude oil & equivalent products totaled a record 3,860 kb/day in January, up 9.1% from January 2018
Chart for production: https://pbs.twimg.com/media/D3ZukJvX4AASI8p.png
Chart for crude oil inventory https://pbs.twimg.com/media/D3ZuEauWsAIsGcD.png2019-04-05 Statistics Canada, press release https://www150.statcan.gc.ca/n1/daily-quotidien/190405/dq190405b-eng.htm
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Mar 27, 2019 | peakoilbarrel.com
Carlos Diaz x Ignored says: 03/24/2019 at 6:38 am
EIA projections are profoundly flawed, being the only question if they are aware of it or if they actually believe their own shit.Increased production is driven by relatively high or increasing oil prices that signal increased demand, OR by the need of producers to maintain income at the expense of other producers when prices fall as it happened between mid-2014 to late 2015.
The second case is difficult to take place when oil prices are relatively low, as now, and when there are agreements between producers to limit production to sustain prices, as now. Therefore EIA is projecting an oil price increase amid general economic weakness, a trade war, Chinese ongoing slowdown, and so on. The economy is not signaling any urgency about oil supply after the Iran sanctions have taken place without much effect. Prices are not going to sustain an increase in oil production unless something unforeseen takes place, and such event cannot be included in EIA forecast.
According to Art Berman presentation about the 2018 price collapse the markets are signalling $60/b oil for 2019-2020 with $10 price excursions. If he is correct we will not see an increase in oil production, and might even see a slight decrease as Venezuela continues its fast descent to near zero oil production. Everybody knows that a country that came to depend almost exclusively on oil will implode when its oil production collapses, the only question being how the implosion will look and what will be the final death toll.
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Mar 17, 2019 | www.rigzone.com
(Bloomberg) -- Exxon Mobil Corp. is delaying a C$2.6 billion ($1.9 billion) oil-sands project in Canada by at least a year as the nation's energy industry grapples with a shortage of pipeline space and government-mandated production cuts.
Exxon's Canadian subsidiary, Imperial Oil Ltd., had originally planned to bring the 75,000-barrel-a-day Aspen project online in 2022, but is now slowing the pace of development at the site in northern Alberta. Any decision to resume normal activity will depend on future government actions and general market conditions, Imperial said Friday.
The delay is another blow to Canada's oil-sands industry, which suffered from record low prices last year after a wave of new production overwhelmed the region's pipeline capacity. That spurred the government of Alberta, where most oil-sands projects are located, to mandate production cuts to drain a glut of crude in storage and revive prices.
The move also reflects Exxon's increased focus on projects off Guyana's coast and in the Permian Basin in Texas. The company last week increased its target for Permian production to 1 million barrels a day by 2024 and expanded its estimate for the size of its Guyana discovery to 5.5 billion barrels.
New RisksImperial, which owns refineries that were benefiting from the cheaper feedstock, has been one of the loudest critics of the curtailment policy and cited the plan again in its explanation for the Aspen delay.
"We cannot invest billions of dollars on behalf of our shareholders given the uncertainty in the current business environment," Imperial Chief Executive Officer Rich Kruger said in a statement. "That said, our goal is to ensure the work we do this year will enable us to effectively and efficiently resume planned activity levels when the time is right."
Imperial hinted at a possible slowdown at Aspen last month, saying it was re-evaluating the project after the forced production cuts introduced new risks. The company also has said previously that the curtailment policy, by boosting Canadian heavy oil prices too high, has made shipping crude by rail uneconomical, forcing Imperial to dial back its rail shipments to almost nothing last month.
Imperial sanctioned the Aspen project in November. The operation would use an extraction method called a steam-assisted gravity drainage, in which steam is pumped underground to heat up sludgy oil-sands bitumen, allowing it to flow through another pipe to the surface.
Imperial was slated to spend about C$700 million on the project this year, and the extra free cash flow stemming from the delay may be used to buy back more shares, which would be a positive for the stock, Dennis Fong, an analyst at Cannaccord Genuity, said in a note.
Imperial rose 0.5 percent to C$36.95 at 10:20 a.m. in Toronto. Exxon fell 0.3 percent to $80.21 in New York.
To contact the reporter on this story: Kevin Orland in Calgary at [email protected] To contact the editors responsible for this story: Simon Casey at [email protected] Joe Carroll
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Feb 26, 2019 | peakoilbarrel.com
nikbez x Ignored says: 02/25/2019 at 6:10 pm
Looks like a glut of condensates has developed and is getting worse.Another thing to ponder about shale oil: falling capex, but solid production growth And that's after three bad years (2015, 2016 and 2017) and low current prices.
Do the US shale oil producers want to establish some kind of "world record" and then "The last one out please turn off the lights."
How can such a miracle happen?
The US oil production is really Alice in Wonderland phenomenon.
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May 15, 2013 | rbnenergy.com
By Al Troner, President Asia Pacific Energy Consulting (APEC)U.S. production of field (lease) condensates is growing like crazy, especially in the Eagle Ford. There is way too much of this material for it to be absorbed into traditional crude blending markets. At the same time the production of plant condensate, a.k.a. natural gasoline, is also increasing along with the yield of all other products from natural gas processing plants. A glut of condensates has developed and is getting worse. Clearly this is an opportunity for new market development, and the bizdev community is hard at work coming up with concepts, projects and proposals to use all of this material in the U.S. and in export markets. But there is a problem. Condensate markets in different geographies seem to have little in common with each other. It's like walking through the looking glass. One term can have several meanings. One meaning can be ascribed to several terms. Today we launch a RBN blog series to make sense of it all.
First, let's consider a fundamental question. Are condensates in the natural gas liquids (NGL) family? Like everything about this topic, it depends. In U.S. usage, a "plant condensate" is the equivalent of products classified as "pentanes+" and natural gasoline, and these are considered NGLs. On the other hand, U.S. usage typically does not consider "field or lease condensate" as an NGL, instead classifying these commodities as crude oil. There are a variety of reasons for this distinction in the U.S. market, some rational some not so rational that we will explore a little later in this blog.
However, no such distinction exists in international markets, which consider both plant and field condensates the same thing, with both classified as natural gas liquids – since they are both liquids that come from natural gas. Of course, to further confuse things, international markets have their own labeling problems, calling some of these products "naphthas", when any refiner will tell you that term ought to be reserved for products that have been through a crude distillation tower. Are you starting to get a sense for the problem? Because all of these terms are so mixed, mingled and intertwined, the only thing we can do is "Begin at the beginning" as Alice was told in Wonderland -- and that is with the general category of products called natural gas liquids – NGLs.
NGLs, LPGs and Purity Products
NGLs seem to exist in the twilight zone between black oil, or crude, the basis of all petroleum products, and natural gas (methane) the low carbon footprint, suddenly abundant (in the U.S.) fuel source. NGLs are neither here nor there – they possess, to differing extents, characteristics of both oil and gas and have values and market drivers both similar to and distinctly separate from oil and gas.
Yet it would appear that the key factor that unites all NGLs is that they are derived from gas and that most NGLs need special containment to remain liquids. Then, "What is in a name?"
"When I use a word," Humpty Dumpty said in rather a scornful tone, "it means just what I choose it to mean -- neither more nor less." "The question is," said Alice, "whether you can make words mean so many different things." (Lewis Carroll, Through the Looking Glass, Chapter 6 )
In fact, NGLs carry ambiguity in their very name. Ethane, propane, normal butane, isobutane and (as the product is commonly called in the U.S.), natural gasoline are all found in natural gas, but are liquid hydrocarbon molecules suspended within gas. This is equally true for lease condensates, hence the classification of lease condensates as NGLs in international markets. In this survey of the products alternatively called by names such as NGLs, condensates, pentanes plus and various other monikers, we will explore the wide range of terms used to label these products and how, at times, these different labels define each NGL somewhat differently.
The products we call crude oil and natural gas are base materials – oil is the precursor of petroleum products; gas is primarily valued on its ability to create heat, i.e. calorific value. NGLs are many things simultaneously and can be defined as end-products; petrochemical feedstocks or semi-finished intermediates used to create finished oil products. This very variability - this wide range of flexibility of NGL utilization - leads to much uncertainty. To avoid confusion, it is important to define the terms used and to understand how US market terminology and definitions differ from those abroad.
- NGLs are liquid hydrocarbons suspended as particles in gas, under conditions of subterranean pressure and temperature. As noted above, in the U.S. the term NGL is usually reserved for these products produced through some form of processing (natural gas processing plants or refineries), while in international markets it also includes field or lease condensates.
- Y-Grade, also called mixed NGLs or 'raw make' is an unfractionated blend of the various purity products (see definition below) that make up the NGL product family. A Y-grade stream is typically produced by a natural gas processing plant and transported by pipeline to a central fractionation facility to be split into purity products.
- NGL Purity Products – As this term is used in the U.S., the five purity NGL products are ethane (C2), propane (C3), normal butane (NC4), isobutane (IC4) and natural gasoline (C5+). The numbers indicate how many carbon atoms are contained in each NGL molecule. While butane and isobutane both have four carbon atoms, they differ somewhat in molecular structure. As a general rule, when at least 90% of the NGL stream has only one type of carbon molecule, this NGL, whether ethane or butane, is defined as a purity product.
- Liquefied Petroleum Gas, or LPG, is a subset of the NGL family. In the U.S. the term includes propane, normal butane and isobutane and is often associated with refinery production and demand for these products. The term is also used to refer to the international trade for propane and butanes.
- Pentane+ or C5+ designations include the products that we also call condensates. We'll talk about that plus sign and the many varieties of condensates in the section below.
- Heavier NGLs: In the US market, the term Heavy NGLs refers to natural gasoline and butane/isobutane, but this definition is not universal and certainly can be misleading. The only "heavy" NGL that can be separated, stored and transported without special containment is condensate (natural gasoline), a point which we will detail further below. The term Heavy NGLs is rarely used in foreign NGL markets, and when it is occasionally used, it refers solely to condensate.
- Ethane/Propane Mix: In the US market, ethane and propane are sometimes sold as a mixed stream for use as a petrochemical feedstock. The most common is called E/P Mix, consisting of 80% ethane/20% propane. In some cases the buyers want a custom blend that differs in the proportion of these two NGLs. E/P Mix is sold in European NGL markets and is the basis of Mideast Gulf ethylene cracker feedstock supply, but is virtually unknown in Asia.
Note that most NGLs originate from gas production, whether associated with crude or solely on its own non-associated gas production. When NGLs are contained within a gas stream, it is said that they are in "vapor phase".
All natural gas contains some NGLs. Sometimes there are enough NGLs to be recovered economically, sometimes not. Sometimes NGLs must be removed (whether economic or not) for the 'residue' natural gas to meet BTU and other specifications for the take-away natural gas pipeline or LNG liquefaction facility. Regardless, for natural gas produced at the wellhead to be sold and transported in pipeline systems, various impurities like sulfur and water must be removed. When required by downstream specifications, or economically advantageous or both, the NGLs are separated from the gas in a natural gas processing plant. The mixed stream or Y-grade NGLs are then transported to a fractionator for separation into purity products. That fractionator may be at the processing plant location, but in the U.S. is usually some distance away. As discussed on many occasions in RBN blogs, by far the largest NGL fractionation center in the U.S. is at Mont Belvieu, Texas.
The table below from the Baker Institute shows NGL products, their characteristics and their markets.
Source: Baker Institute (Click to Enlarge)
Condensates, Pentanes Plus and Natural Gasoline
Now that we've cleared up NGLs, we need to turn to the far more convoluted world of condensates, and natural gasoline. But that's not the only labels we need to include. There is also naphtha, Pentanes Plus and even A-180. Each of these terms may have a slightly different meaning in different markets.
An Example of the Name Game: Pentanes Plus . For example, Pentanes Plus, as defined in the United Arab Emirates (Abu Dhabi National Oil Company, or ADNOC) produces a condensate stripped directly from the gas stream. It is a light, highly paraffinic naphtha equivalent and therefore best suited for ethylene cracking. It excludes ethane and LPG and is sold as a naphtha grade. So, this material is called pentane, which is a condensate that is sold as paraffinic naphtha. Got it?
And there still is another Pentanes Plus, this one defined by the Energy Information Agency (EIA), a unit of the US Department of Energy (DOE). EIA describes Pentanes as "a mixture of hydrocarbons, mostly pentanes and heavier, extracted from natural gas. (It) includes iso-pentane, natural gasoline, and plant condensate." Note that it excludes lease condensate, which EIA inconveniently lumps into their crude oil production statistics. Obviously ADNOC's "Pentanes Plus" is not the same stuff as EIA's Pentanes Plus.
To access the remainder of Through the Looking Glass: NGLs, Condensates and Pentanes Part 1 – U.S. versus the World you must be logged as a RBN Backstage Pass™ subscriber.
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Related Content
- Like A Box of Chocolates – The Condensate Dilemma
- Fifty Shades of Condensates – Which One Did You Mean?
- Whole Lotta Splittin' Going On – The Market for US Gulf Naphtha from Condensate Splitters
- Whole Lotta Splittin' Going On – Gulf Coast Condensate Splitter Economics
- Whole Lotta Splittin' Going On- Processing Gulf Coast Condensate
- 1-2-3- MPLX's Plan for Moving Northeast Condensate and Natural Gasoline
- Neither Fish nor Fowl – Condensates Muscle in on NGL and Crude Markets
- Fifty Shades Lighter – The Lease Condensate Export Problem
- Blinded by the Lights- Finding Markets for U.S. Field and Plant Condensate
- With or Without Splitting? Changing Lease Condensate Export Definitions
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Feb 22, 2019 | peakoilbarrel.com
dclonghorn x Ignored says: 02/21/2019 at 10:16 pm
Doc,likbez x Ignored says: 02/22/2019 at 12:57 amYou need to look at more of the report.
http://ir.eia.gov/wpsr/overview.pdf
Crude imports on line 5 as 7,522 kbpd, crude exports on line 9 are 3,607 kbpd for net crude imports on line 4 of 3,915 kbpd.
Other supply includes products and natural gas liquids. It shows net imports on line 21 of -2,809 kbpd. Total net imports of Crude and Petroleum Products on line 33 are 1,106 kbpd.This is somewhat questionable math as one barrel of oil and one barrel of condensate have different energy content (condensate is around 60% of oil).So condensate input into the USA energy balance should be multiplied by approximately 0.5 to get a more clear picture.
The USA imports heavy oil and exports condensate. Not the same liter for liter things.
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www.bp.com
In the ET scenario, global demand for liquid fuels – crude and condensates, natural gas liquids (NGLs), and other liquids – increases by 10 Mb/d, plateauing around 108 Mb/d in the 2030s.
All of the demand growth comes from developing economies, driven by the burgeoning middle class in developing Asian economies. Consumption of liquid fuels within the OECD resumes its declining trend. The growth in demand is initially met from non-OPEC producers, led by US tight oil. But as US tight oil production declines in the final decade of the Outlook, OPEC becomes the main source of incremental supply. OPEC output increases by 4 Mb/d over the Outlook, with all of this growth concentrated in the 2030s. Non-OPEC supply grows by 6 Mb/d, led by the US (5 Mb/d), Brazil (2 Mb/d) and Russia (1 Mb/d) offset by declines in higher-cost, mature basins.
Consumption of liquid fuels grows over the next decade, before broadly plateauing in the 2030s
Demand for liquid fuels looks set to expand for a period before gradually plateauing as efficiency improvements in the transport sector accelerate. In the ET scenario, consumption of liquid fuels increases by 10 Mb/d (from 98 Mb/d to 108 Mb/d), with the majority of that growth happening over the next 10 years or so. The demand for liquid fuels continues to be dominated by the transport sector, with its share of liquids consumption remaining around 55%. Transport demand for liquid fuels increases from 56 Mb/d to 61 Mb/d by 2040, with this expansion split between road (2 Mb/d) (divided broadly equally between cars, trucks, and 2/3 wheelers) and aviation/marine (3 Mb/d). But the impetus from transport demand fades over the Outlook as the pace of vehicle efficiency improvements quicken and alternative sources of energy penetrate the transport system . In contrast, efficiency gains when using oil for non-combusted uses, especially as a feedstock in petrochemicals, are more limited. As a result, the non-combusted use of oil takes over as the largest source of demand growth over the Outlook, increasing by 7 Mb/d to 22 Mb/d by 2040.
The outlook for oil demand is uncertain but looks set to play a major role in global energy out to 2040
Although the precise outlook is uncertain, the world looks set to consume significant amounts of oil (crude plus NGLs) for several decades, requiring substantial investment. This year's Energy Outlook considers a range of scenarios for oil demand, with the timing of the peak in demand varying from the next few years to beyond 2040. Despite these differences, the scenarios share two common features. First, all the scenarios suggest that oil will continue to play a significant role in the global energy system in 2040, with the level of oil demand in 2040 ranging from around 80 Mb/d to 130 Mb/d.
In all scenarios, trillions of dollars of investment in oil is neededSecond, significant levels of investment are required for there to be sufficient supplies of oil to meet demand in 2040. If future investment was limited to developing existing fields and there was no investment in new production areas, global production would decline at an average rate of around 4.5% p.a. (based on IEA's estimates), implying global oil supply would be only around 35 Mb/d in 2040. Closing the gap between this supply profile and any of the demand scenarios in the Outlook would require many trillions of dollars of investment over the next 20 years.Growth in liquids supply is initially dominated by US tight oil, with OPEC production increasing only as US tight oil declines
Growth in global liquids production is dominated in the first part of the Outlook by US tight oil, with OPEC production gaining in importance further out. In the ET scenario, total US liquids production accounts for the vast majority of the increase in global supplies out to 2030, driven by US tight oil and NGLs. US tight oil increases by almost 6 Mb/d in the next 10 years, peaking at close to 10.5 Mb/d in the late 2020s, before falling back to around 8.5 Mb/d by 2040. The strong growth in US tight oil reinforces the US's position as the world's largest producer of liquid fuels. As US tight oil declines, this space is filled by OPEC production, which more than accounts for the increase in liquid supplies in the final decade of the Outlook.
The increase in OPEC production is aided by OPEC members responding to the increasing abundance of global oil resources by reforming their economies and reducing their dependency on oil, allowing them gradually to adopt a more competitive strategy of increasing their market share. The speed and extent of this reform is a key uncertainty affecting the outlook for global oil markets (see pp 88-89).
The stalling in OPEC production during the first part of the Outlook causes OPEC's share of global liquids production to fall to its lowest level since the late 1980s before recovering towards the end of the Outlook.
Low-cost producers: Saudi Arabia, UAE, Kuwait, Iraq and Russia
Oil demand †
Download chart and data Download this chart pdf / 64.6 KB Download this data xlsx / 10.1 KB† Excluding GTLs and CTLs
The abundance of oil resources, and risk that large quantities of recoverable oil will never be extracted, may prompt low-cost producers to use their comparative advantage to expand their market share in order to help ensure their resources are produced.
The extent to which low-cost producers can sustainably adopt such a 'higher production, lower price' strategy depends on their progress in reforming their economies, reducing their dependence on oil revenues.
In the ET scenario, low-cost producers are assumed to make some progress in the second half of the Outlook, but the structure of their economies still acts as a material constraint on their ability to exploit fully their low-cost barrels.
The alternative 'Greater reform' scenario assumes a faster pace of economic reform, allowing low-cost producers to increase their market share. The extent to which low-cost producers can increase their market share depends on: the time needed to increase production capacity; and on the ability of higher-cost producers to compete, by either reducing production costs or varying fiscal terms.
The lower price environment associated with this more competitive market structure boosts demand, with the consumption of oil growing throughout the Outlook.
Growth in liquid fuels supplies is driven by NGLs and biofuels, with only limited growth in crude oil production
The increase in liquid fuels supplies is set to be dominated by increases in NGLs and biofuels, with only limited growth in crude.
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Feb 12, 2019 | Oil Sands Magazine
Global shortage of medium to heavy sour crude: Cuts from OPEC, Canada and potentially Venezuela have increased the price of medium and heavy crude oils. The Mars benchmark, a medium, sour crude produced in the Gulf of Mexico, has moved to above par with Light Louisiana Sweet.
Western Canadian Select (WCS) prices in the Gulf Coast also rose above par with the West Texas Intermediate (WTI) benchmark at the end of January. WCS trades at a US$10/bbl discount to WTI in Alberta, but now sells at a US$1.50 premium in Houston.
A similar effect is being seen globally, as several medium to heavy sour crude grades produced in the Middle East are now trading at a premium to Brent.
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Feb 15, 2019 | peakoilbarrel.com
Watcher: 02/15/2019 at 4:24 am
I have been suspicious for some time that production numbers can be corrupted by fuzzy definitions. Iran is being sanctioned, but Iran shares that enormous gas field under the Persian Gulf with Qatar. Gas production yields condensate and it yields NGLs.likbez: 02/15/2019 at 7:27 pmHigh vapor pressure NGLs get labeled liquefied petroleum gas, and that is used for transportation fuel in India. Pentane Plus is used or called something akin to natural gasoline.
You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be. Iran is using this to dodge sanctions, or they did use it when condensate was not restricted. Don't recall if that loophole was closed in the current sanctions. That would be a good thing to know.
The same thing can happen with shale. We hear all sorts of talk about how much gas is being flared and how much gas is being captured, and you know perfectly well there has to be condensate involved. There was an article a year or so ago about NGL capture in the Bakken, but I don't recall any follow-up. It shouldn't take too much of a stretch on the part of state regulators to find a way to count the high vapor pressure portion of NGL as oil.
You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be.
Exactly. And this, in turn, allows Wall Street to suppress the price of "prime oil" using fake production numbers, fake storage glut (which is essentially condensate glut) and similar tricks. Please note that the US refineries consume mainly "prime oil" while the USA mainly produces (and tries to export at a discount) "subprime oil."
Pretty polished and sophisticated racket. It might well be that shale oil companies are partially financed from those Wall Street profits as nobody in serious mind expect those loans to be ever repaid.
So OPEC cuts are the only weapon that OPEC countries have against this racket.
In any case, I think all those nice charts now need to be split into "prime oil" and subprime oil parts and analyzed separately. In the current conditions, treating "heavy oil" and condensate as a single commodity looks to me like pseudoscience.
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Feb 14, 2019 | oilprice.com
...OPEC+ production cuts could erase the supply surplus in the near future. Saudi Arabia has promised to cut more than required, lowering output in January by 350,000 bpd while also promising another 500,000 bpd cut by March.
"[C]ore-OPEC producers are adopting a 'shock and awe' strategy and exceeding their cut commitment," Goldman Sachs said in a note, predicting that Brent oil prices will average $67.50 per barrel in the second quarter.
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Feb 14, 2019 | oilprice.com
To accommodate steadily rising barrels of light oil, OPEC and its non-OPEC partners have backed out their own supplies in order to prevent a crash in prices. But many OPEC members produce medium and heavier blends.
The quantity of global supply may not be vastly different, but the quality of the crude slate has changed dramatically. Refiners cannot easily swap out one type for another. The upshot is that the world is seeing a glut of light oil at a time when supply of medium and heavier barrels are relatively tight.
... ... ...
U.S. sanctions against Venezuela and Iran are magnifying this trend, knocking even more medium and heavier barrels off of the market.
... ... ...
The IEA said that these quality differences could cause some problems this year. "In quantity terms, in 2019 the US alone will grow its crude oil production by more than Venezuela's current output," the agency wrote in its Oil Market Report published Wednesday. "In quality terms, it is more complicated. Quality matters."
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Feb 13, 2019 | news.yahoo.com
The "call" on OPEC crude is now forecast at 30.7 million bpd in 2019, down from the IEA's last estimate of 31.6 million bpd in January.
U.S. sanctions on Iran and Venezuela have choked off supply of the heavier, more sour crude that tends to yield larger volumes of higher-value distillates, as opposed to gasoline. The move has created disruption for some refiners, but has not led to a dramatic increase in the oil price in 2019.
"In terms of crude oil quantity, markets may be able to adjust after initial logistical dislocations (from Venezuela sanctions)", the Paris-based IEA said.
"Stocks in most markets are currently ample and ... there is more spare production capacity available."
Venezuela's production has almost halved in two years to 1.17 million bpd, as an economic crisis decimated its energy industry and U.S. sanctions have now crippled its exports.
Brent crude futures have risen 20 percent in 2019 to around $63 a barrel, but most of that increase took place in early January. The price has largely plateaued since then, in spite of the subsequent imposition of U.S. sanctions.
"Oil prices have not increased alarmingly because the market is still working off the surpluses built up in the second half of 2018," the IEA said.
"In quantity terms, in 2019, the U.S. alone will grow its crude oil production by more than Venezuela's current output. In quality terms, it is more complicated. Quality matters."
dlider909, 7 hours ago Story will change in 30 days.Robert, 7 hours ago ... ... ...
What this report fails to do is to pay the appropriate homage to American oilfield roughnecks...
ralf
7 hours ago Nonsense. I see military action against Venezuela soon, just because of our thirst for oil.
Talk about shale is like talk about Moon conquests, not supported by hard facts.
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Feb 02, 2019 | www.bloomberg.com
Texas and other shale-rich states are spewing a gusher of high-quality crude -- light-sweet in the industry parlance -- feeding a growing glut that's bending the global oil industry out of shape.
Refiners who invested billions to turn a profit from processing cheap low-quality crude are paying unheard of premiums to find the heavy-sour grades they need. The mismatch is better news for OPEC producers like Iraq and Saudi Arabia, who don't produce much light-sweet, but pump plenty of the dirtier stuff.
The crisis is Venezuela, together with OPEC output cuts, will exacerbate the mismatch. The South American producer exports some of the world's heaviest oil and Trump administration sanctions announced this week will make processing and exporting crude far more difficult. American refiners are scrambling for alternative supplies at very short notice.
"We still have some holes in our supply plan" over the next 30 days, Gary Simmons, a senior executive at Valero Energy Corp., the largest refiner in the U.S., told investors on Thursday. "We are not taking anything from Venezuela."
Crude isn't the same everywhere: the kind pumped from the shale wells of West Texas resembles cooking oil -- thin and easy to refine. In Venezuela's Orinoco region, it looks more like marmalade, thick and hard to process. Density isn't the only difference -- the sulfur content is also important, dividing the market into sweet and sour crude. Heavy crude tends to have more sulfur than light crude.
As Saudi Arabia, Russia and Canada cut production, and American sanctions force Venezuelan and Iranian exports lower, the market for low-quality crude is feeling the impact.
"The strength in the physical crude market continues, led by sour crude shortages," Amrita Sen, chief oil analyst at consultant Energy Aspects Ltd. in London, said echoing a widely held view within the market
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Jan 13, 2019 | finance.yahoo.com
In an attempt to combat a ballooning oil glut and dramatically plummeting prices, the premier of Alberta Rachel Notley introduced an unprecedented measure at the beginning of December when she is mandating that oil companies in her province cut production. This directive was particularly surprising in the context of Canada's free market economy, where oil production is rarely so directly regulated.
Canada's recent oil glut woes are not due to a lack of demand, but rather a severe lack of pipeline infrastructure. There is plenty of demand, and more than enough supply, but no way to get the oil flowing where it needs to go. Canada's pipelines are running at maximum capacity, storage facilities are filled to bursting, and the pipeline bottleneck has only continued to worsen . Now, in an effort to alleviate the struggling industry, Alberta's oil production has been cut 8.7 percent according to the mandate set by the province's government under Rachel Notley with the objective of cutting out around 325,000 barrels per day from the Canadian market.
Even before the government stepped in, some private oil companies had already self-imposed production caps in order to combat the ever-expanding glut and bottomed-out oil prices. Cenovus Energy, Canadian Natural Resource, Devon Energy, Athabasca Oil, and others announced curtailments that totaled around 140,000 barrels a day and Cenovus Energy, one of Canada's major producers, even went so far as to plead with the government to impose production caps late last year.
So far, the government-imposed productive caps have been extremely successful. In October Canadian oil prices were so depressed that the Canadian benchmark oil Western Canadian Select (WCS) was trading at a whopping $50 per barrel less than United States benchmark oil West Texas Intermediate (WTI). now, in the wake of production cuts, the price gap between WCS and WTI has diminished by a dramatic margin to a difference of just under $13 per barrel.
Related: The Natural Gas Crash Isn't Over
While on the surface this would seem to be a roundly glowing review of the production caps in Alberta, production cuts are not a long-term solution for Canada's oil glut woes. The current production caps in Canada are only intended to last through the middle of this year, at which point Canadian oil companies will be permitted to decrease their cutbacks to just 95,000 barrels per day fewer than the numbers from November 2018's production rates. The cuts are a just a treatment, not a cure, for oversupply in Alberta. The problem needs to be addressed at its source--the pipelines.
Unfortunately, the pipeline shortage in Alberta has no quick and easy fix. While there are multiple major pipeline projects underway, the two largest, the Keystone XL pipeline and the Trans Mountain pipeline, are stalled indefinitely thanks to legal woes and seemingly endless litigation. The Enbridge Line 3 pipeline, intended to replace one of the region's already existing pipelines, is currently under construction and projected to be up and running by the end of the year, but will not go a long way toward fixing the bottleneck.
Even if the Albertan government re-evaluates the present mid-2019 expiration date for the current stricter production cuts, extending the production caps could have enduring negative consequences in the region's oil industry. Keeping a long-term cap on production in Alberta would potentially discourage investment in future production as well as in the infrastructure the local industry so sorely needs. According to some reporting , the cuts will not be able to control the gap between Canadian and U.S. oil for much longer anyway, just another downside to drawing out what should be a short-term solution. The government will need to weigh the possible outcomes very carefully as the expiration date approaches, when the and the pipeline shortage is still a long way from being solved and the price of oil remains dangerously variable.
By Haley Zaremba for Oilprice.com
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Dec 27, 2018 | peakoilbarrel.com
shallow sand x Ignored says: 12/24/2018 at 2:33 pm
WTI $42.58GuyM x Ignored says: 12/24/2018 at 3:08 pmWTI Midland $34.34
Flint Hills posting ND Light Sweet $16.75.
Seems the break even is pretty low, as EIA has predicted about a million bpd increase out of shale in 2019Adam B x Ignored says: 12/24/2018 at 5:53 pmIt doesn't matter whether you provide storage or increase the number of refineries, shale production is relatively dead at these prices. The prices just need to stay ridiculously low for awhile to stop the EIA and IEA from producing more imaginary oil, and face reality. Yeah, that would affect my wells, but I would hope for a better price, later.
Less than $17 a barrel? Bakken is done for awhile. And there is NOBODY in the Permian breaking even at $34. Remember what happened in 2015? Yeah, production dropped by over a million barrels. These prices are as bad as 2015, and we have a bigger drop potential. Those pipeline builders gotta be really worried. But, they should be anyway. How are you going to keep the pipeline flowing if you can't take what's in there out, because there is nowhere to put it? How many mentally challenged people are working in the Permian?
The amazing part is, this time there is no glut, at all. Inventories will drop, but just let it happen. We have to forever eradicate the Permian and shale production will save the world song. It's a thousand times more irritating than listening to Bing Crosby's white Christmas on January1st. There ain't no fritzing Santa Clause, EIA!
Seems like a lot of year end liquidation of oil futures perhaps. That's the only explanation I've got for how oil is this low. Probably will bounce back to the low 50's WTI by late January. It will be interesting to see December through February US production data to see what effect this price dive has done.Financier x Ignored says: 12/25/2018 at 4:24 pmHi GuyM,GuyM x Ignored says: 12/25/2018 at 4:43 pm"Those pipeline builders gotta be really worried. But, they should be anyway."
What do you think the issues are that the pipeline companies are worried about
right now? I would appreciate your thoughts on this.Two thoughts, immediately. The price is such now, that if it stays anywhere close to that for awhile, completions won't be as expected, and there won't be enough oil to fill them. The second is, that if the E&Ps had the right price, and did produce, there is probably not enough shipping until late 2020 or 2021 to handle 2.5 million bpd extra. No place to store it, and refineries can't use high API. Unless, I am missing something. Pipelines can't make much money because a pipeline is filled, it has to be flowing.Dennis Coyne x Ignored says: 12/24/2018 at 5:47 pmIts gonna go to zero. Just kidding.GuyM x Ignored says: 12/24/2018 at 6:03 pm
Doubt these prices will be sustained.Maybe not zero, but could be a lot more. It's reacting to the stock market, now. Dow down 15% and still going. This is no simple correction, as that stops at around 10%, usually. Been a long, long time since the last bear market, and is past due. Everything dives, until they come to grips that commodities are a different animal. That may take months, or longer depending on how bad it gets. Who knows, each bear market has a different generation, and it's always new to them.Adam B x Ignored says: 12/24/2018 at 9:04 pm
Especially this one, as it has been so long. New ball game.
I think it was EN who posted how rate hikes can cause this on a historical basis. Based on that chart, we could be in a significant bear market. Bubbles are going to pop. Not sure what the derivative markets are looking like, but they can't be healthy. The derivative markets are many times bigger than the regular stock markets. Think Lehman Brothers, and margin call. Lehman didn't fail over bad home loans, they failed over the derivatives of home loans. This time, it won't be housing, but something will give. They made a big effort to control the banks after the last fiasco in 2008, but made NO effort in regulating derivatives. Brilliant. Some of the weaker oil companies may be in trouble. JMO.Right on the move from 18,000 to 27,000 in the Dow was just hot air as we are seeing now. Investors realize there isn't a fed put and are freaking out, how far will it sink before Powell and company call off the dogs and say no more rate hikes and stop quantitative tightening..cause it's on "autopilot" according to them. All I want is 4% on an 18 month CD, fat chance now.GuyM x Ignored says: 12/24/2018 at 10:07 pmThe autopilot is also the monthly selling of Bonds held by the Fed, which also acts as interest rate increases.Watcher x Ignored says: 12/24/2018 at 7:19 pmhahahahahahaahahahaGuyM x Ignored says: 12/24/2018 at 7:27 pmThe inventory nazis will be out soon with a surprise discovery that there was more in storage than they ever suspected.
Don't you worry none. In the finest traditions of capitalism and free markets, various govts will be taking action soon. To do something.
Yeah, they are convening as we speak. Never fear. Trust in your government, not your 401k.🤪TechGuy x Ignored says: 12/24/2018 at 10:20 pmA Minsky moment, day, week, month or year(s). Aka margin call on highly leveraged margin is probably the cause. Hence, duck it's hitting the fan.
https://seekingalpha.com/amp/article/4229895-something-happeningIn other words, if you have to sell those paper barrels for margin calls, and there is too few to buy, because they are selling, also; then price goes down, because there are too many paper barrels, and not enough buyers. Probably, the original paper sellers lose their butt, and have to sell something to cover their margins. Everyone now is paying homage to the margin god. Because, there was never any real money to cause the stock market to soar like an eagle.
Which reverses itself later, because when it is time to sell new paper barrels, less are sold, enabling the price to go up (if anyone has any money left). Everyone else is busy ducking Guido, because the value of what they had left in their portfolio was not enough to cover margin. Er, I think
Anyway, that's Guy's course negative 101, on the current status of oil prices.
We come full circle back to the Jan. 2009 Lows! Lowest was Jan 16 at $36.GuyM x Ignored says: 12/24/2018 at 10:35 pm
Folks, I think we hit a recession!Recession usually lags 9 months after the market crash, but, yeah. We are basically there.Dennis Coyne x Ignored says: 12/25/2018 at 7:30 amRecession is based on GDP not the stock market or price of oil.GuyM x Ignored says: 12/25/2018 at 7:47 amhttps://www.bea.gov/data/gdp/gross-domestic-product
Q3-2018 was 3.4% GDP growth. Very good for an advanced economy.Of course. But traditionally, crashes take from cash/growth after a period of time. Nine months to a year, and growth in GDP precedes bull markets by the same. It's not a fritzing law, but it's logical, and normal. Has been since I started following it in the 60's. Last crash was different, in that the GDP growth declined before the crash, due to housing. But, if the crash persists, my bet would be a lack of cash, eventually, to support growth. There are huge losses, we don't see that are happening now in the derivative market, besides the stock markets. There was something like 384 trillion just in interest rate bets in derivatives,that half are losing right now.HHH x Ignored says: 12/25/2018 at 8:04 amThis is no traditional crash. FED can stop hiking interest rates and market might pause an consolidate before going lower but lower they go. Until FED stops allowing it's balance sheet to shrink, down is the direction for markets. Back when QE was full blown stuff like gov. shutdown and trade wars were the very thing that made markets go higher because it meant more QE for longer.GuyM x Ignored says: 12/25/2018 at 8:12 amThere is nothing organic about the recovery of markets since 2008-2009. All assets and markets are mispriced. Price discovery wasn't allowed to happen after 2008-2009. Truth is true price discovery won't be allowed to happen this time either.
Fed is manufacturing a market crash so they can do the next round of QE. Fact is QE works but you can't end it and you sure as hell can't reverse it. QE creates the illusion that everything is fine. There is a credibility issue if you can't ever end QE though. That's where the Fed finds itself now.
Your right. Each crash is different. This one is just a slow meltdown. And, since I have been following it, there has never been anything organic about market growth, it's always BS. There was nothing organic about the first big market crash in the early part of last century, it was purely speculative. The tulip crash, before established markets was speculative.HHH x Ignored says: 12/25/2018 at 8:46 am
Growth in GDP and markets are two separate animals. Although, as the previous crash proves, GDP decline can affect the market, as well as market crashes affecting GDP.The stock market, and now especially derivatives, are nothing other than a gigantic Las Vegas casino. Elves in the market strive to maintain that there is a relation, but in the end, it doesn't pan out.
Well the Dow has had its largest monthly loss ever recorded this December unless market recovers some of that between now and the end of the year. Slow meltdown maybe not. It's currently at about -4,200 which tops the largest monthly drop during 2008-2009 by about 1,000 points.GuyM x Ignored says: 12/25/2018 at 8:53 amJust further to drop than the previous ones. Half would be about 10k more points. But, there is nothing magical about half, it could stop well before that.HHH x Ignored says: 12/25/2018 at 9:01 am
The analysis of the drop is still being speculated. The ones that make sense, so far, is that there was a lot of market fear (tariffs, ad nauseum). Sell offs happened, snow balling into covering margin calls. If so, that is a normal scenario, but I think the Fed raising interest rates, and continuing to unravel QE is also a major, if not the major reason. There are a bunch of other reasons that don't make a lot of sense. One blaming oil price. I think that is yet to come, but not this time.Unwinding of FED's balance sheet is also on autopilot. They don't have to have a Fed meeting to vote on it like a rate hike. Much easier to deflect the blame elsewhere for the resulting market decline.Ron Patterson x Ignored says: 12/25/2018 at 1:09 pm-4,200 which tops the largest monthly drop during 2008-2009 by about 1,000 points.GuyM x Ignored says: 12/25/2018 at 2:19 pmHey, it it's the precentage drop that counts. What was the largest monthly percentage drop in the 2008-2009 crash? I would wager it was far greater than the percentage drop this December.
This article is about the huge 1,175 one day drop last February, but the point still holds.
Dow Jones Suffers Worst Point Drop Ever, But Percentage Loss Is Not Historic
The Dow's 4.6% loss on Monday was the worst since August 2011. But it didn't even crack the top-20 of all-time losses. It was just the 25th worst loss since 1960.
The Dow's biggest one-day percentage loss was the 22.6% Black Monday crash on Oct. 19, 1987. In point terms, that was "only" 508 points. In second place, the Dow crashed 12.8% on Oct. 28, 1929.
Looks like the biggest percentage drop for a month was Feb 2009, at around 21%. Eclipsing this month. But, it had also been going down for a long time. What was this month, around 16%? But, it's just started,GuyM x Ignored says: 12/25/2018 at 11:13 amMerry Christmas from S Padre Island at 75 Degrees F.Hightrekker x Ignored says: 12/25/2018 at 12:00 pmVery white this morning in Bend Oregon.Watcher x Ignored says: 12/25/2018 at 2:18 pmSo markets look down 14ish% YTD. Still 4 days to worsen that or better that.GuyM x Ignored says: 12/25/2018 at 2:22 pmYou know, there is no law of the universe that says markets can't be down more than 10% this year, and next year, and the next, and the next for 10 years or so. Never done that before? So what? Never printed 25% of GDP before. Never API 40.6 WTI before. After 10 yrs, scarce oil, scarce life.
You have that right. The world is full of surprises.Watcher x Ignored says: 12/25/2018 at 7:09 pmAnd, I do not see QE, again. Different folks in the Fed. So, banks will lose big time on easy money, and getting more is not going to be easy like last time. Over the past two years, I have been getting endless calls and letters wanting to loan me money. Bet that slows down.
And, because bear markets have a tendency to stick around for a few years, oil supply may put a blanket on improvement. So it could be possible for continued decline, rather than a rebound. Or, one real big final decline. No end to the possibilities.
One, I really see as a possibility, is another export ban. Think about it. Gasoline prices go up due to a shortage. We could be in a recession with stagflation. The public, and the illiterate congress would not be able to comprehend API. We are just exporting oil, when gas prices are high. In a way, they would be right. Think how that would affect 2.5 million bpd pipeline expansions, and extra shipping improvements.
Or, we could elect another flawed icon for President-Elon. Who would promise a Tesla for every family, or a free trip to Mars.
Ok, this is fun, but pointless.
Wrong govts.GuyM x Ignored says: 12/25/2018 at 7:21 pmThink in terms of the big SWFs. It is they that seek action.
As for quoting indices vs their histories, this sounds like a good thing. Just be sure that you quote an index that has the same companies in it as it did historically. The Dow with Apple will be difficult data to find for 1960. But you can find GE in it for then.
Ever notice they don't add a company that is failing? And never remove one that is doing well? Similarly we should only quote WTI 39.6 API price. Difficult data to find.
SWFs? Meaning.GuyM x Ignored says: 12/25/2018 at 7:11 pmhttps://www.cnbc.com/2018/12/24/whats-a-bear-market-and-how-long-do-they-usually-last-.htmlQuick turnaround of the market from this point has no historical precedence. Although, if it does not go down much more, 3 to 5 months is possible.
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Jul 14, 2018 | peakoilbarrel.com
Tita x Ignored says: 07/11/2018 at 1:21 pm
I did a more thorough analysis of the STEO using their excel tables. Just comparing dec 18 production with dec 19 production. I just corrected some inconsistency with UK data, as dec19 had a drop of 300kb/d.Guym x Ignored says: 07/11/2018 at 2:05 pmnon-OPEC 2018 increase: 2.8 Mb/d
US increase: 2 Mb/d,
of which 1.4Mb/d of crude, 0.6Mb/d of NGL. Offshore increase of 400kb/d (to 1.89 Mb/d). Onshore increase of 1Mb/d.
Canada increase: 130 kb/d
Brazil increase: 176 kb/d
Russia increase: 211kb/dSo, indeed EIA doesn't forecast any constrains in US production. June to december growth for onshore production is forecasted at 430kb/d. The 1.4Mb/d figure comes probably from the monthly data. They are very optimistic, but there is nothing wrong.
When it says "crude" is that crude plus condensate, or is the condensate included in NGLs? The reason I ask that, is that the monthlies include crude plus condensate. 1.4 million increase does not tie into their summary page. 1 million crude per your spreadsheets does not agree to 600 to the Permian, plus 600 from the rest of the US, including the GOM. The summary analysis has 1.2 million. Adding onshore and GOM from the numbers you pulled is 1.4 million. Adding 2 million from the US plus Canada gives 2.13 million, not 2.3 per the summary. Adding 400 to the ending monthly for the GOM for 2017, gives a lot more than 1.89. Nothing jives. They are supposed to be just "optimistic" when the expect 430k to just magically appear in Cushing or Gulf coast without the aid of pipelines, trains, or trucks? No, wait, 400k of that is supposed to come from the Bakken and Eagle Ford, of which little has happened yet, nor will much. So, most of it has already figured out a way to get teleported. Or, is the optimism politically motivated.Ron Patterson x Ignored says: 07/11/2018 at 2:51 pmNo, the OPEC Monthly Oil Market Report reports crude only. Their data does not include condensate.George Kaplan x Ignored says: 07/12/2018 at 12:22 amThe EIA figures are always Crude+Condensate or Total Liquids. The EIA never reports crude only and OPEC never reports C+C.
NEB currently has Canada increase at about 250kbpd (for both yearly average and December exit rate), that may come down as they incorporate the upgrader outage and East Coast turn arounds.Guym x Ignored says: 07/12/2018 at 8:12 amThe GoM is not going to add 400 kbpd, it's more likely to be negative on average (December may be up slightly as 2017 had three major unplanned outages then (but at the moment EIA are reporting about 30 kbpd which don't come from any reported wells or leases so they may know something else). GoM has to replace about 20 kbpd per month of decline, which it isn't doing at the moment, plus overcome any planned/unplanned outages, which seem to be getting more frequent.
Brazil is going to struggle to get 180 kbpd increase. They were down 20 kbpd in May from December. They have two FPSOs ramping up but are fighting 30+ kbpd decline per month (and increasing). The are other FPSOs due but seem delayed and the ramp ups are slower than in the past, principally because of lack of drilling capacity. Probably they need two new development wells per month to keep level, given the normal delivery rate and that some are for injection, they only have 8 rigs, not all on new developments, but there may be some predrilled wells available.
Russia has more fields coming on stream, but it depends how much the mature fields decline – there must be a limit some time on how much in-fill drilling can be done.
So, replacing the EIA estimates with our own, we get for non-OPEC growth:Boomer II x Ignored says: 07/12/2018 at 1:29 pm
650. US (550 from the Permian, 100 Bakken)
Eagle Ford may drop
250. Canada
180. Brazil
300. Russia being generous1380. Total which is 1.42 short of their 2.8 million, or 2.6 (1.180) if you use their summary page. Even adding another 350 to the US still is close to 1 million short. OPEC contribution seems somewhat "optimistic", and does not factor in any Iranian drop. Yeah, should balance out.
https://www.iea.org/oilmarketreport/omrpublic/currentreport/
Their first page graph pretty much depicts serious draws without adjustment. They have a 2 million a day increase in non-OPEC production for 2018, lowered to 1.97 in this report.If the EIA is intentionally misrepresenting available supply, do they know better and are just trying to postpone some sort of economic panic?Guym x Ignored says: 07/12/2018 at 1:35 pmMisrepresenting is too strong a term. That would assume they are reporting the actual numbers wrong, which they do not do. These are projections, and they can be manipulated to serve the best purpose of keeping prices down until the elections. That's pure speculation.Ron Patterson x Ignored says: 07/12/2018 at 10:44 amAnother Chart.Guym x Ignored says: 07/12/2018 at 11:07 am
Thanks. Yeah, it's much worse. Looking at that, one could guess 1380- 400 non-OPEC (less US Canada and Russia) for 2018. But, because we were short in 2017, we've gone nowhere.George Kaplan x Ignored says: 07/12/2018 at 11:16 am180 for Brazil is a stretch. Fort Hills and Horizon have finished ramping up so 250 for Canada is also probably a stretch. US NGL may be a chunk to include but I wonder what the global decline for NGL on mature gas developments is. North Sea looks not as good as expected. The only place doing better than I thought is Mexico, and I think that could turn the other way any time.Guym x Ignored says: 07/12/2018 at 11:23 amEIA reports condensate, so does my estimate. There's about 300k extra in their detail of NGLs that I can't account for.George Kaplan x Ignored says: 07/12/2018 at 11:47 amBut i think there's a lot of NGPLs (i.e. butane and lighter) in the all liquids numbers, it's not just condensate (C5+).Guym x Ignored says: 07/12/2018 at 11:52 amAre the details of OPEC, IEA and EIA reports getting more and more focussed on short term issues, as if they have no idea how supply can meet demand longer term? Or am I missing something.
Unless, EIA is using a double standard in their STEO report for US vs Non-OPEC, I believe it would be crude plus condensate, only. It's crude plus condensate for US, for sure.Ron Patterson x Ignored says: 07/12/2018 at 12:27 pmThe STEO, table 3b, Non-OPEC, is total liquids. Table 4a, US only, is Crude plus Condensate. Table 3c, OPEC, is crude only.
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Jul 14, 2018 | peakoilbarrel.com
Tita
x Ignored says: 07/13/2018 at 7:37 am Just saw this looking for the release date of the next DPR report, on the EIA website:"NOTE:
Productivity estimates may overstate actual production which could be limited by logistical constraints."So, EIA actually acknowledge these constraints, and admit they may be overstimating production, without saying by how much. Reply Guym x Ignored says: 07/13/2018 at 9:35 am
Reliable estimates of takeaway capacity for the Permian. Similar to Genscape, current pipeline capacity is estimated to be about 2.8. Drilling info does not mention total takeaway capacity, but Genscape estimates it at 3.3. Per the article, it was at 3.2 the end of May. The ending production, the end of 2017, was 2.8 from the Permian, making the end of May increase at 400k. I gave the projected increase 550k, because Genscape said 25k of additional trucking, may happen. Note, Drilling info lists some very small additional capacity that should come online this year, and soon, so it will probably wind up to be about 50k higher. Maybe. The gathering terminal gets it from New Mexico and West Texas to the Midland terminal, only, as I understand. The rest of the articles are mostly badly written press, but I think you can rely on Genscape and Drillinginfo.Guym x Ignored says: 07/13/2018 at 10:50 am
https://info.drillinginfo.com/permian-oil-and-gas-takeaway-capacity-improvements-on-horizon/Sometime soon, there will be an odd mixture of increased production and shut ins.
Also, if I estimate Permian production at 600k (generously), it equals the new EIA estimate. The remaining 600k US C&C production will have to come from other shales and the GOM. Good luck with that, it's July, already, and prices are too up and down, to date. Contrary to the EIA's and other analysts thoughts, $65 to $70 oil is pretty ho hum to producers. Also, there is no allowance here for other declines, of which there are some.
So, an updated revision to US increases (liquids) would be:
700 c@c US (600 Permian, 100 Bakken and others, GOM 0)
400 US NGLs ? Seems real high for an increase
250 Canada
180 Brazil
300 Russia
Total 1.83 versus a projection of an increase by EIA in the non-OPEC section of the STEO of 2.6, and I think mine is very "optimistic". And, as Ron points out above, it does not include roughly about 300 to 500k in declines that may happen to non-US, Russia and Canada non-OPEC production. The EIA's STEO report can be found in the local library next to Mother Goose.According to the EIA, we are pretty much finished with inventory declines.
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Jun 27, 2018 | peakoilbarrel.com
GuyM
x Ignored says: 06/25/2018 at 9:16 am https://oilprice.com/Energy/Crude-Oil/Gulf-Of-Mexico-Production-Expected-To-Hit-Record-High.htmlI think the high is coming from the strange smell from the EIA offices, and they have been sharing their stash with Woods McKenzie:
https://www.woodmac.com/press-releases/deepwater-gulf-of-mexico-stages-a-comeback-in-2018/Four days before the Permian pacifier is removed. EIA monthly for April due out 5/29, Friday. But, then if they are really intent on keeping oil prices down until November, they can post an increase and correct it later. Or, slowly correct it until November. Do I really think the Federal Government would mislead the public? Hell, yes, they have been. They have access to much more information than I do, and they are still singing the Permian song. Reply Guym x Ignored says: 06/25/2018 at 11:16 pm
Second thought, I don't think it is possible for EIA to delay it much further. We crossed the Rubicon. Singing Permian songs when there are reports of service employers cutting back, wells shut in, and overall reports of slowdowns, creates a lot of cognitive dissonance.George Kaplan x Ignored says: 06/26/2018 at 12:28 amMust be a slow news day for OilPrice. The headline is misleading – the predicted record is only for deepwater total (oil and gas) production, not total GoM. It is almost certainly going to be wrong – if nothing else the 50 kboepd dropped from the loss of Hadrian South gas and the prolonged Enchilada and Delta house outages are impossible to make up, but even without those there probably wouldn't be enough new, plateau production through this year.As to the industry having this great revelation and deciding not to go for big, bespoke developments and use standard designs and tie backs – it's the other way round – they ran out of larger developments that were affordable, so didn't need the bigger, on-off designs. Also the standard designs come at a cost – they have less flexibility for future tie-backs or changing reservoir conditions, and probably lower availabilities. Note also the talk of ultra-deep-water and HPHT developments like Anchor, that's a switch back to expensive bespoke design (actually almost research projects).
It also references that crap EIA paper without making any effort to check the facts.
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Jun 13, 2018 | peakoilbarrel.com
Kolbeinh , 06/13/2018 at 4:02 am
IEA monthly oil market report for June is out.Jeff , 06/13/2018 at 4:10 amSelected extracts from the report follows.
About the market in general:
Rapidly rising prices in recent months have raised doubts about the strength of demand growth, and we have modestly downgraded our estimate for 2018. Prices are unlikely to increase as sharply as they did from mid-2017 onwards and thus the dampening effect on demand will be reduced.About Non-OPEC production growth:
We think that in Texas by end-2019 there will be a net 575 kb/d of additional pipeline capacity beyond our earlier number, albeit with most of it coming on line in the second half of the year. In the meantime, capacity will likely remain tight but production will still be able to grow strongly, by 1.3 mb/d this year and 0.9 mb/d in 2019. Our non-OPEC growth for 2019 includes a modest increase from Russia reflecting a possible contribution to compensating for lost production from Iran and Venezuela.About OPEC production:
To make up for the losses [from Venezuela and Iran], we estimate that Middle East OPEC countries could increase production in fairly short order by about 1.1 mb/d and there could be more output from Russia on top of the increase already built into our 2019 non-OPEC supply numbers. However, even if the Iran/Venezuela supply gap is plugged, the market will be finely balanced next year, and vulnerable to prices rising higher in the event of further disruption. It is possible that the very small number of countries with spare capacity beyond what can be activated quickly will have to go the extra mile.As usual I disagree with their views, it seems like they have a stance that the market will be in balance no matter what.
They now have an estimate ("scenario") of market balance in 2019. All assumptions are not available in the public version. Deficit (stock draw or call on Saudi et al.) is between 1-1.6 mbd assuming lower exports from Iran and Venezuela. However, current decline in Venezuela looks worse than I think they assumed and IEA continues to assume N America shale oil on full throttle. 2019 is shaping up to be interesting.George Kaplan , 06/13/2018 at 5:20 am(sorry for cross post)
The most likely trend for Venezuela is surely that it hits zero exports (or maybe total production at worst) sometime in 2019, not that it flattens out or, more miraculously, starts increasing again. Brazil is likely to take longer, and therefore have a lower peak, to ramp-up its planned Santos FPSOs. Kazakhstan looks decidedly peaky (or plateau-y, except in the past they've always shown decline after a peak); Tengiz expansion is in 2020 but I think initially it just extends the plant plateau. North Sea will be declining until J. Sverdrup. Nigeria and Angola are definitely showing signs of the big declines you get when deep water FPSOs hit end of life, and not much drilling there showing yet.It would be interesting to know how they factor in decline rates (which are accelerating); in-fill drilling (which must be running out of the best prospects); and short cycle developments of new discoveries (few to none of those at the moment). If they are using predictions based on 2005 to 2014 experience the models are going to be a long way out, but what data is available to do something better?
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Jun 20, 2018 | peakoilbarrel.com
Guym, 06/17/2018 at 8:45 am
Pollyanna speaks:
https://www.eia.gov/todayinenergy/detail.php?id=36493
Permian continues to grow when they have no capacity to move it until late 2019.Predicated on info from Pollyanna two:
https://www.iea.org/oilmarketreport/omrpublic/currentreport/Says OPEC 90 day excess capacity is 3.47 million barrels a day. EIA says Sauds part of that is 1.5 to 2. Not sure where IEA is saying the other 1.5 is coming from. Ok, we will soon see the truth in that, over the next year.
The real Pollyanna lunacy, is that the Sauds want to see oil prices in the sixties. Lip service, yes. Actually, why????
Or, come on guys, help us keep the prices down until election time, at least.
The real story:
http://www.petroleumworld.com/story18061505.htm
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Jan 30, 2018 | peakoilbarrel.com
Guym says: 01/28/2018 at 7:39 am
https://oilprice.com/Energy/Crude-Oil/US-Condensate-Output-Set-To-Increase-In-2018.htmlGuym : 01/28/2018 at 1:36 pmHeadline and story are disconnected. That is very possibly a reality, but not developed within the article. Too bad, as it was the closest thing to reality posted in awhile. Assume it is a problem with Oiprice, as garbage info is what interests them the most.
They are going to have major problems transporting this, too.Guym : 01/28/2018 at 4:10 pm
http://mobile.reuters.com/article/amp/idUSL1N0UV1YB20150116Blending it will become a problem: http://www.argusmedia.com/pages/NewsBody.aspx?id=1254610&menu=yesTimthetiny : 01/29/2018 at 5:05 amDo you really think we are going to increase production by one million barrels with primarily condensate? On second thought, if they could get to Canada, they could make a killing on condensate: http://business.financialpost.com/commodities/energy/encana-pivots-to-78-per-barrel-condensates-from-prolific-montney-basin/amp
The average eagle Ford is 45-50. Most operators won't consider anything under 40 from shale as it's too heavy. Again with the misinformation.Mike : 01/29/2018 at 6:37 amIts possible to create isopach maps for gravity of oil throughout the Eagle Ford trend; it varies. Higher initial GOR and higher gravity liquids leads to higher EURs; the best EF wells are generally in the very volatile, liquids rich gas leg in Dewitt County, for instance. Higher gravity stuff also can mean lower prices at the WH and market difficulties.Guym : 01/29/2018 at 8:05 amI don't see any blatant misinformation here. I see people trying to understand what is going on. I suggest Berman's twitter feed for some good poop on oil and condensate quality. Light tight oil IS getting lighter and it is a very serious problem with end users. We will never become hydrocarbon independent in America simply because of the quality of the stuff we now produce.
So what's the plan in America? Send LTO to Corpus and ship it to China or anyone else that will take the stuff. We can't use anymore of it in America. Instead of developing heavy markets to blend LTO with, so America can use America's oil and not export it, we have developed this stupid "isolationistic, energy dominance" plan that is shortsighted and pissing the rest of the oil producing world off.
We're trying to 'prove' something to the rest of the world. In another decade or so when we have exported all of our LTO away and OPEC and others have us entirely by the ying-yang again, we'll look back and ask, "who in the hell was in charge?"
Exporting America's oil away is stupid. But then again, less than 20% of America's population has a savings account so no sweat. Let the kids fend for themselves.
T- Then why are they producing it? Under 40 is too heavy?? That's what the frigging refiners buy. Average Eagle Ford produced now, is probably 40 to 45. I am constantly looking at completion reports, and not just re-quoting some expert. Yes, mine at 33, would be exceptional, and I didn't mean to confuse. Over 45 causes problems. Misinformation is caused by listening to experts, and not doing your own research with primary data.If all of the Eagle Ford or tight oil was at an API gravity of 33, we probably would not be importing as much oil. Nor, would we ever have had the huge inventory build.
Over 45, you have a smaller number of options. There are a few refineries in W Texas set up for this, there are a few more refineries set up, but they are small in number and production, and are hard to transport to. Blending becomes difficult, per my post. Bigger option is to export it.
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Jan 16, 2018 | peakoilbarrel.com
George Kaplan x Ignored says: 01/14/2018 at 8:26 am
One thing I haven't figured out with Canada is how they come up with the reserves estimates. If you look at the Alberta oil sands quarterly reports all the projects that are operating, in development (not many now) or approval are listed. Even given the long operating times for these projects the reserves included can't be much more than 50 Gb left. Presumably these are also the best prospects, and given some have lost quite a bit of money in the last couple of years, and often just operate as arbitrage – turning energy in gas to energy in oil – then the remaining 100 and more Gbs must be really difficult to get at. Presumably it will need even more and longer wells (i.e capital) and natural gas (which would have to come from shale now I think); and maybe the EROI cliff starts setting a real limit somewhere, no matter what the price rises to, as the deposits get deeper, thinner, harder, heavier or whatever it is that has made them less attractive.OFM x Ignored says: 01/14/2018 at 9:57 amThanks , guys.Jeff x Ignored says: 01/15/2018 at 3:32 amIn a long term emergency situation, I believe the process of permitting and getting started on construction will take place on a war time economic pace, once it becomes clear that the emergency is long term.
I don't know any more than the next layman about pipelines or railroads, other than welding, which is a minor consideration in terms of the big picture. But it seems to me that laying another pipe, or another track parallel to an existing pipeline or track could happen pretty fast, maybe within a year, or two at the longest, once the decision is made to do so on an emergency footing.
When it comes down to arbitraging gas for oil, George makes a really important point. Eventually gas is sure to get to be really expensive, given that depletion never sleeps, and when it does, this means cost of oil sands will necessarily have to go up quite a bit, maybe even to the point that it becomes necessary to burn some oil sands crude on site to continue production.
If things get to this point, the environmental camp will have a hissy fainting fit, but I doubt it will matter, because once the majority of people realize that they are going to be doing without gasoline, they will forget all about the environment and this includes the ones who don't even drive, as often as not.
The vast majority of us depend on the smooth functioning of the automobile centric economic model to make a living. Even though she doesn't drive, a waitress who lives over the restaurant where she works won't be able to pay her rent if half of her regulars cut way back on eating out due to being short out of work or working short hours themselves. Even divorce lawyers can't make much money when people don't have it to lose. Fruit's good for you, an apple a day is priceless, if it's all the fruit you can afford, but I can buy chicken and beans cheaper than I can buy apples at the nearest supermarket, and compared to chicken and beans .. apples are starvation food. If the overall economy crashes, apples will be a luxury rather than an every day item for people thrown out of work or on short hours. If growers lose even a fifth of our market, half of us will be out of business, and the other half won't be buying very many new cars.
Bottom line, environmental considerations are NOT going to stop the exploitation of the oil sands, or coal to liquids, or any other tech that will keep the economic wheels turning.
There's NOTHING that we can substitute for affordable oil in the very short term, and how fast we can switch to electrified transportation is anybody's guess.
Mine is that we are going to be utterly dependent on having pretty close to as much oil as we do now, on a daily basis, for at least another ten years, and probably closer to twenty. Maybe by then there will be enough electric vehicles on the road to offset depletion and demand growth due to growing population.
The pipeline issue is not complex at all. Canada's heavy oil is landlocked in Alberta (and Saskatchewan) and need to be transported to US or to the coast (west or east). Provinces that produce oil are pro new pipelines but British Columbia (transit and export province) is against. I fully understand landowners (especially first nations) that neither want new pipelines nor expansion of current ones. Once a pipeline has been constructed it will transport crude for many decades, enable production to increase, possibly leak and it´s uncertain what will happen when the pipe reach its end of life.Fernando Leanme x Ignored says: 01/15/2018 at 4:59 amTo some, pipelines are more than just a few bucks.
"When the last tree is cut, the last fish is caught, and the last river is polluted; when to breathe the air is sickening, you will realize, too late, that wealth is not in bank accounts and that you can't eat money."
The keystone XL pipeline and a full upgrader (by full I mean a 200,000 BOPD plant making 38 degree API syncrude) should help reduce the bottleneck. The upgrader takes about 7 years to design, permit and build. Meanwhile they'll have to make dilbit and ship that to the USA gulf coast,The situation in Venezuela is very fluid. Turning production around and raising it to 2.5 mmbopd may take ten years if the current conditions are allowed to continue during 2018. I have a difference of opinion with some youngsters I see discussing more emphasis on light oil production. Problem is I know they are mostly inexperienced MBAs well versed in PowerPoint but lack education or experience taking over an oil field, refurbishing it, and getting it to increase production. I've been doing that on and off since 1978, and it's not easy.
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Jan 08, 2018 | peakoilbarrel.com
Energy News x Ignored says: 01/06/2018 at 8:09 am
Alberta Canada – Total Production (crude oil + condensates + upgraded bitumen + bitumen)
November at 3,412 kb/day, up +304 m/m. Average production in 2017 to November, up +250 kb/day over 2016 full year.
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Jan 08, 2018 | peakoilbarrel.com
Longtimber x Ignored says: 01/07/2018 at 1:00 pm
Unexpected cargo? A million barrel of NG Condensate in a Tanker? Still afloat and burning Sunday morning 30+ missing. https://www.zerohedge.com/news/2018-01-07/iranian-oil-tanker-bursts-flames-after-colliding-chinese-ship-near-south-korea?page=1Hightrekker x Ignored says: 01/07/2018 at 1:09 pmMessy -- but this is late stage capitalism.
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Dec 21, 2017 | peakoilbarrel.com
Heinrich Leopold, says: 12/21/2017 at 10:58 am
Mr. Kaplan,Heinrich Leopold, says: 12/21/2017 at 11:20 amCondensates in a classic sense are part of light distillate group and are traded at a 20%discount to Brent. There is some demand to upgrade heavy oil, yet this comes at a cost. However, the group of light distillates includes also LPG amongst others.
The US exported last week 3 mill barrels per day of propane and other light distillates which just fetch the price of less than 20 USD per barrel.
In my estimate the US has to pay USD 60 per barrel for imports and gets on average USD 30 per barrel for exports. This is a serious mismatch and cannot be solved by an increase of Shale condensate production.
Dennis,Watcher, says: 12/22/2017 at 1:59 amHowever 45 API is still way above the specification of 38 API for WTI. In other words none of the Shale production can be sold as crude oil and must be classified as condensate or more general as light distillates earning substantial price discounts on worldwide market.
If the giant South Pars field in Iran starts up, there are gigantic capacities of these grades coming to the market, depressing prices even further. There is no doubt that Shale production experiences a significant quality problem.
This is in my view also the reason why Shale companies have such catastrophic financial difficulties: they receive not enough cash to cover the high production costs and high depletion.
I'm not gonna go back and find the links again.Heinrich Leopold, says: 12/22/2017 at 4:22 amWTI is no longer 39.6. It's well over 40. That's from the most recent assay data. Historical analysis means nothing if definitions change, and they have changed.
Can search the archives here, or can use rational thought. WTI now includes lighter oil coming out of shale in West Texas. As I recall the assay was at Cushing which also blends it with Bakken flow. The definition has changed.
My recall is officially, not just from the assay.
Watcher,Dennis Coyne, says: 12/22/2017 at 8:41 amThis is exactly the dilemma of Cushing. Officially it is a WTI trading hub, yet in reality most of the inventory cannot meet the the specifications for a WTI grade. It is therefore very difficult to reduce inventory at Cushing.
See link below 2013-2014 avg was about 41:Heinrich Leopold, says: 12/22/2017 at 9:24 amAPI Gravity-≥37 and ≤42 • Monthly averages in 40 to 42 range. Occasional values above 42. • Seasonal variation with winter being slightly higher. • December 2014 average was 41.6. • If your assay does not reflect ~41 API, it probably warrants review.
and
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRAPUS2&f=M
Dennis,Krisvis says: 12/22/2017 at 10:50 amAs far as I can see it from the data this includes all oil input including oil imports, heavy oil from Canada and conventional oil from GOM . Nevertheless, there is a clear upward trend.
Why do you think the US has still to import over 10 mill bbl per day in crude oil and products? There must be a clear reason for it, if not for quality reasons. People would not send for fun oil around the world without reason.
And the reason is that Shale does not produce crude oil, but condensate and light distillate products. It is just in the wrong market and Shale condensate and lighter products must be sold in the worldwide market at a cheap price. This is also the reason the US has still a high oil deficit, despite high condensate and light distillate products exports.
This point was well discussed by Jeff Brown who called it the great condensate con. PAA in the conference call clearly indicated export market is needed for Permian to expand. Delaware basin produces mostly condensates.Krisvis says: 12/22/2017 at 10:59 amBrown asks, "Why would refiners continue to import large–and increasing–volumes of actual crude oil, if they didn't have to–even as we saw a huge build in [U.S.] C+C [crude oil plus condensate] inventories?"
What I see now if that EPD and CME are adopting COQA recommendations and implement them in 2019.Dennis Coyne says: 12/22/2017 at 10:45 amUS refiners did not like the dumb bell crude when you mixed too light a crude with too heavy a crude. Distillation test will reveal that. Lately the Asian buyers of US crude did not like the fact it produced too much light gas. I saw EPD came up with the specs. and it was immediately followed by CME.
US light oil needs an export market or a condensate splitter is needed
Hi Watcher,The definition has not changed it has been 38-42 for a long time, but it is correct that the average WTI has increased from about 39.6 historically to about 41 in 2013 and 2014 and it has occasionally risen above 42 on a monthly basis.
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George Kaplan, says: 12/21/2017 at 7:08 amJan 03, 2018 | peakoilbarrel.com
Heinrich Leopold says: 12/21/2017 at 5:49 am
Mr. Archibald,Thank you for your report and for presenting your view about future developments. However, in my view the oil market experienced substantial structural changes besides the volume growth and increased demand from non-OECD countries. The Shale production increased oil volume growth, yet it also shifted growth towards light distillates and left the world oil market short of middle distillates.
This is best demonstrated by the dramatic change in the mix of US hydrocarbon market. As the US market is swamped by light distillates, it is actually hit by an extreme shortage of middle distillates, which is used for the production of diesel, aviation and shipping fuel, as well as heating oil. The recently EIA weekly supply estimate revealed that the US had to import 80% more distillate fuel oil than last year. Distillate fuel oil inventories are 25 mill barrels below last year and reach a multi year low. It is for this reason that the total imports surged again over 10mill bbl per day as the US has to cover the shortage of middle distillates despite a glut of light distillate production. In that sense the US has to import a growing amount of expensive conventional oil containing middle distillates and has to export the surging Shale condensate production, which does not meet the specifications of international crude oil benchmarks, at a low price.
As a consequence, the price of condensate will be falling considerably and the price of crude oil containing middle distillates will be rising in the near future.
Most of the worlds producing countries have production that is gradually getting heavier, condensate is wanted worldwide by refineries for blending and has a premium price over heavy oil grades, which is likely to continue (e.g. EF condensate $53, South Texas Heavy $48; Canadian Condensate $58, Canadian Sweet $49).
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Energy News says: 12/29/2017 at 3:43 pmJan 03, 2018 | peakoilbarrel.com
Kolbeinh says: 12/29/2017 at 2:00 pm
Politics is a major part of oil markets and keeping Russia at bay is a goal for the administration I guess.And so is the target of 3% gdp growth for the president. But the profound backwardation in the futures market for Brent at the moment tells me that reality is storage withdrawal until shortage for oil.
Especially distillates is under scrutiny because of lack of Venezuela heavy oil and too much light oil from Texas. Conventional oil worldwide is suffering from underinvestment and OPEC policy is as expected to serve their own interests. The main problem is easy oil mid API range (too much exploitation).
Liquefied Petroleum Gases (ethane+propane+butane) October production: 3 499 kb/day +281 m/mHeinrich Leopold says: 12/30/2017 at 8:26 am
https://www.eia.gov/dnav/pet/pet_pnp_gp_dc_nus_mbblpd_m.htm
Energy NewsDennis Coyne says: 12/31/2017 at 10:20 amYour posts meets exactly my point as Shale increases the supply of light distillates yet does little to cover the growing worldwide shortage of middle distillates.
As the US exports mostly cheap light distillates and imports expensive real crude oil the recent trade numbers confirm a swift deteriorating goods trade deficit and consequently a sharply falling US dollar as we have seen over the last few days. All what Shale is currently doing is to depress the price of light distillates yet it leaves the growing supply shortage of real oil unaffected.
Hi HeinrichLongtimber says: 12/29/2017 at 11:43 pmThe increased LPG is due to increased natural gas production especially "wetter" natural gas. The has less to do with LTO output and more to do with shale gas output.
It also has very little to do with condensate which is liquids that condense at the lease (it is called "lease condensate") at ambient temperature and pressure.
LPG is at either higher pressure or lower temperature than ambient conditions.
https://www.zerohedge.com/news/2017-12-29/crypto-qatar-these-are-best-worst-assets-2017Heinrich Leopold says: 12/30/2017 at 6:47 am
NG -- Ugly.. A Trainwreck for 2017.
What Coke Nose Jim Crammer use to say? time to BACK UP THE TRUCK?
As it is too early to assess the impact of the current cold on gas production the recent 40% Canadian rig count slump may serve as a harbinger for the US for next weeks . It is not only freeze offs but but also transport infrastructure and pipeline constraints.Dennis Coyne says: 12/31/2017 at 10:22 am
Hi HeinrichJeff says: 12/30/2017 at 9:00 amCanadian rig count always drops over the Christmas to New Year's holiday this is not unexpected.
Haven´t seen it posted here yet. Euan Mearns who sometimes post here has a new blog post on "oil price scenario for 2018": http://euanmearns.com/oil-price-scenario-for-2018/ . I like figure 4 think that Ian Schindler has showed something similar for longer time periods (70/80´s).Dennis Coyne says: 01/02/2018 at 2:03 pmEuan lacks at least two factors but they are more or less impossible to forecast particularly: i) economic growth (demand) ii) how much of the OPEC cuts are voluntary. Also his calculation of natural decline is wrong he assumes all legacy production is in decline.
Hi JeffWatcher says: 12/30/2017 at 9:52 amThanks. I think Euan has the price about right ($80/b at the end of 2018 for Brent) but I disagree with him on World oil output in 2018.
I think World C+C output will increase at about 600 kb/d per year over the next few years until about 2020 and then will gradually slow down as LTO output and oil sands output will not increase rapidly enough to offset declining output elsewhere in the World by 2025 potentially there could be a short plateau until 2028 or a longer plateau from 2022 to 2029 the higher World output goes the more likely that any plateau will be very short. I agree with your assessment that Euan has overestimated the World decline rate at about 8% which for C+C would be about 6.5 Mb/d not all of World C+C oil fields are in decline some are on plateau and a few are increasing output (at the field level) though if one considers individual oil wells probably 99% of oil wells currently producing (weighted by daily output) are likely to be in decline.
Euan may be looking at things from that perspective which would mean (assuming my 98% guess is correct and that those wells decline at an average annual rate of 8%) we would need 6.4 Mb/d of newly completed wells just to offset the declining wells in order to remain on a plateau.
Euan believes the World will just be able to manage this I think higher oil prices will enable 7.1 Mb/d of oil completions Worldwide over the next year with a net increase in World C+C output.
We will not really even know World C+C output for 2017 until March 2018 (I use EIA estimates) and 2018 output will be unknown until March 2019.
The most recent 12 months of World C+C output (average monthly output from Oct 2016 to Sept 2017) was 80 999 kb/d based on EIA data.
The latest numbers out of China say oil consumption growth this year 2017 will be double last year's. This year is pegged at 6.5% with a month to go. India numbers as of Oct say their 2017 growth rate will be about 8% as it was last year.Energy News says: 12/30/2017 at 12:16 pm
China's crude oil stockpiles the latest numbers: There is a big difference between China's official numbers and analysts calculated numbers (China says +90 kb/day vs IEA up to +1000 kb/day)Krisvis says: 12/30/2017 at 2:21 pmBEIJING Dec 29 (Reuters) -- China had stored 37.73 million tonnes or 275 million barrels in nine bases by mid-2017 up from 33.25 million tonnes at the end of June the previous year according to the data from the National Energy Administration (NEA).
Adding 4.48 million tonnes of crude oil over the 12 months to June 2017 is equivalent to adding 89 600 barrels of oil per day (bpd).
Reuters (December 29 2017) https://www.reuters.com/article/china-crude-reserves/update-2-china-accelerates-stockpiling-of-state-oil-reserves-over-2016-17-idUSL4N1OT2HF
China's (commercial) crude inventories in November hit a seven-year low of 26.15 million tonnes Xinhua data showed.
Reuters (December 28 2017) https://www.reuters.com/article/us-global-oil/oil-prices-stay-near-high-on-strong-u-s-refinery-runs-china-data-idUSKBN1EM04PYou'll remember this
LONDON October 12th 2017 (Reuters) -- China has built its crude oil stockpiles at a record pace in 2017 and while its purchases could tail off towards the year-end inventories could hit the billion-barrel mark in six months the International Energy Agency said.
The agency estimates that over the first half of 2017 Chinese stockbuilding hit a record 1 million b/day.
Anybody knows what the definition of crude oil by Texas RRC is? The reason I ask the question is because the production increase up to API gravity 40 is only 70K/day out of 767 K/day from November 2016 to October 2017. PAA said in the conference call that Delaware basin is producing mostly oil with APII gravity higher than 45 and needs to be exported as our US refiners will not touch it.Heinrich Leopold says: 01/02/2018 at 1:56 pm
KrisvisDennis Coyne says: 01/02/2018 at 2:19 pmThanks for posting your comment. This is exactly my point.
Shale produces mostly condensates and light distillates which are an excellent feedstock for the chemical industry. However this concerns just 15% of the oil market. At the beginning of the Shale boom Shale light distillates could substitute a lot of conventional oil which was previously used in the chemical feedstock market. This brought down the oil price.
As Shale oil has now serious troubles to enter the transportation fuel market (due to a lack of middle distillates) the US is forced to sell cheap light distillates on export markets and import on the same time expensive real oil containing middle distillates at a high price. So US imports of real oil are on the rise again. This is why we are seeing a rising oil price and US oil trade deficit again. The dollar has already reacted by a steep slump over the last days.
When one looks at the price of oil with API 40-45 it trades at a premium to heavy oil. Oil above 45 or 50 API is typically classified as condensate.Dennis Coyne says: 01/02/2018 at 2:22 pmAs George has commented repeatedly most of World output is getting heavier and is more expensive to refine. There are many customers around the World that need the lighter oil to blend with heavier crude. In fact much of the US condensate goes to Canada to blend with bitumen so it will flow through pipelines.
For net crude oil imports for the US see
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRNTUS2&f=M
Wrong chart in comment above sorry( link has updated chart)Dennis Coyne says: 01/02/2018 at 2:30 pm
This chart is from EIA (chart above used the EIA data Jan 2015-Oct 2017).texas tea says: 12/30/2017 at 5:14 pmThe US has had net imports of crude oil since 1945 (based on monthly data).
On an annual basis the last year the US was a net exporter of crude oil was 1943. Net imports of crude peaked (annual data) in 2005 at over 10 Mb/d and fell to 6.9 Mb/d in 2015 and rose slightly in 2016 (by 0.36 Mb/d) to 7.26 Mb/d in the most recent 12 months net imports have fallen to 6.99 Mb/d.
"Whatever the case nothing creates job and opportunities the way oil and natural gas exploration does at this time"Boomer II says: 12/30/2017 at 5:57 pm
https://oilprice.com/Energy/Energy-General/GOP-Tax-Bill-Is-A-Boon-For-Oil-And-Gas.htmlchoke on it boys the truth comes out making america great again not just a slogan anymore
Companies losing money don't pay income taxes anyway. A cut won't do them any good.Boomer II says: 12/30/2017 at 6:04 pm
"Given President Donald Trump's obsession with reviving the dying industry it's almost surprising that the Republican tax bill doesn't contain any new breaks or incentives that explicitly help coal. 'Energy is actually the least of the beneficiaries in this bill and the simple reason is that energy already has so many carve-outs and exemptions in the tax code that a lot of U.S. based companies just pay hardly any income tax as it is ' said Pavel Molchanov an energy research analyst at the financial firm Raymond James. 'So there is virtually no effect on energy of any kind either positive or negative and that includes coal.'"Mike says: 12/30/2017 at 6:24 pmhttps://newrepublic.com/article/146388/tax-bills-gift-big-coal
Choke on this tee tee: because the shale oil industry can't keep its MasterCard(s) in its pants its overleveraged LTO oversupply is the direct cause of low volatile oil prices that has resulted in the loss of over 440 000 oil and gas jobs around the world since 2014. https://www.rigzone.com/news/oil_gas/a/148548/More_Than_440000_Global_Oil_Gas_Jobs_Lost_During_Downturn . There are still an estimated 55 000 still out of work in America in EOR GOM and in stripper well production. Your beloved shale industry got nothing nada zip out of the new tax law except interest deduction limits which will hurt it not help it.Dennis Coyne says: 12/30/2017 at 8:30 pm
Hi MikeMike says: 12/30/2017 at 9:03 pmIf most of the LTO companies are losing money I don't think they pay federal taxes on losses so the reduction in tax deduction for interest paid would have no effect.
Am I missing something?
No but tee tee is. Its not easy you know getting thru.texas tea says: 12/31/2017 at 5:53 pmTake for instance the help the oil and gas industry is getting by opening ANWAR. Who is that going to help particularly since there is countless geological and depositional studies done that pretty much condemn the entire area? Or lets take the "roll back" of certain MMS/BSEE regulations regarding multi-string pressure and BOP testing in the GOM after the Macondo incident? That is stupid shit that dumb uninformed people buy into that has nothing to do with reality. Reality is those regulations were on the books and un-enforced. It cost BP what $80B to cut some corners? Nobody I repeat nobody is going to let that happen again. Whatever the current BS is about reducing regulations on the oil industry and helping American become great again by unleashing its hydrocarbon "might " on the rest of the world is laughable. Who is laughing all the way to the bank?
OPEC and Russia dat' who. They are watching America's energy policies get worse not better.
you can educate the ignorant but not the stupid who said that oh yea me. any one of my birddogs knows more about north slope geology than you mike. perhaps you can make a new years resolution try to be accurate at least once in 2019 gonna be hard for a "man" like you but give it a shotHuntingtonBeach says: 12/31/2017 at 7:59 pmoh yea surely you can do better than bathroom jokes after all a "man" of your intellect should oh never mind
"you can educate the ignorant but not the stupid who said that oh yea me. "shallow sand says: 12/30/2017 at 9:00 pmEnough said
I am wondering if EIA is including NGLs as I see OK production has ramped up quite a bit. A lot of OK liquids are 55+ API.Guym says: 12/31/2017 at 8:40 am
Read the post twitter link Dean posted above. Most interesting is a post by a CPA who was involved with the 914 reporting. He thinks it is double counting the M&A production. However within his post he describes that the 914 survey is actually done by a third party contractor. In his discussion with him they were using the higher of projected drilling info or operator report. To put it in my perspective I don't see the 914 having anything like the consistency of the RRC. IMG Crown Energy Services is the third party contractor. Look up their website. Not a lot of time spent on it for a heavy duty IT company so no warm fuzzies there. One could speculate that the primary income is from the EIA contract. EIA paints themselves into a corner with wild projections on Texas production. They call up the third party contractor and question the figures they think are too low. Contractor has to do something to keep the contract don't they?Dennis Coyne says: 12/31/2017 at 10:30 am
Now nobody at EIA can get fired for cooking the books because they have plausible deniability.
Hi GuymGuym says: 12/31/2017 at 11:30 amFrom May 2015 to July 2017 the 914 survey was pretty consistent (within 275 kb/d and 365 kb/d of drilling info estimate average 320 kb/d). Perhaps that has changed I would not put much weight on a Twitter comment by a CPA. We will see in a few months what the drilling info estimates are which are usually within 1% of the final output after 3 to 5 months. So by March or April we may know what Oct 2017 TX C+C output is.
As Mike says in Texas they are patient.
That CPA owns his own oil company who reports to the contractor. Do you?Dennis Coyne says: 12/31/2017 at 4:15 pm
No. Has he been reporting NGL (in the US this would be natural gas plant liquids) to the contractor as C+C?Guym says: 12/31/2017 at 4:50 pmIn any case I agree with Mike patience is needed. Perhaps the 914 survey is now covering a much higher percentage of Texas C+C output relative to the May 2015 to July 2017 (27 month long) period.
Time will tell.
"Double counting M&A production" has nothing to do with NGLs. He was admonished by the contractor for under reporting production that was sold off. Instead of using his figures they used his old wells as listed in the drilling info estimate. Hence double reporting it. But what was more interesting is the contractor part. They can send out the survey but can determine whatever they want to include.Dennis Coyne says: 01/02/2018 at 8:53 am
Hi GuymDennis Coyne says: 01/02/2018 at 8:48 amThe EIA contractor checks with operators when reported numbers are different than expected and sometimes they use the drilling info data instead if the numbers don't look right.
The numbers are revised over time as more data comes in. These are estimates nobody knows final output for many months (for the entire state of Texas or all of the US).
Hi GuymDennis Coyne says: 12/31/2017 at 10:34 amThe link below covers the 914 survey methodology. Yes mergers and acquisitions are a potential problem. The EIA does it's best to account for these to avoid double counting.
About 450 of the largest oil and gas companies that produce about 90% of US oil and gas output (of approximately 13 000 petroleum producers in the US) fill out the 914 survey.
https://www.eia.gov/petroleum/production/pdf/eia914methodology.pdf
Hi Shallow sandWatcher says: 12/31/2017 at 11:21 amNo not NGL only crude plus lease condensate. The EIA has never based C+C on API gravity just liquids produced in the oil field as far as I know.
A bit of recap for newcomers:George Kaplan says: 12/31/2017 at 11:40 amAPI gravity is a density measurement of oil. Measures how heavy it is compared to water. The higher the API number the lighter the oil. Refineries do not create "middle distillates" out of nothing. They extract them from oil. "Middle distillates" are middle heavy liquids within oil. Diesel and Kerosene. Read truck/tractor fuel and jet fuel. Gasoline is a light distillate. Heavy distillates would be something like bunker fuel or asphalt.
This is all within the same liquid called "crude oil". Traditional labels are applied as regards the word "quality". High "quality" crude oil was light and "sweet". Sweet refers to having low content of materials that cause problems in refining. Like sulphur or vanadium. But tradition has run up against the new nature of crude oil. It has gotten too light. It often lacks middle distillates.
Here is a chart posted a year or so ago by Jeffrey Brown: https://imgur.com/a/cqtvu
I have examined assays of many different oil types from all over the world. Jet fuel boils about 160 degs C and the heaviest diesel boils up around 350 degs C. So "middle distillates" that are actual fuel for things that matter are in the assay between those temps.
https://www.statoil.com/en/what-we-do/crude-oil-and-condensate-assays.html
Scroll down to their .XLS spreadsheets for various blends that they have assay'ed. I would say it does not conform to the chart. BUT. There are some caveats scattered around. "Blend". Dumbbell liquid. This means if oil from one field doesn't have what you want in it you add oil from another field to it to get the constituent parts. Assay it and declare it looks good. BP has an assay website as do others like Capline from Marathon.
All this was to address the question above -- "what is the definition of oil". Study all that and you'll see that the definition is whatever the money agenda says it should be that moment.
Crude oil is only getting lighter in the US everywhere else it's getting heavier and the light LTO is likely to be in greater demand for blending. Refineries set up for heavier oil usually have crackers -- either fluid crack crackers or hydrocrackers -- which can convert heavier components to gasoline and diesel but can only go so far and blending lighter oil allows the throughput to be maximised. There is no current problem from the oil range of oils being produced.Energy News says: 12/31/2017 at 12:22 pm
HOUSTON (Reuters) -- Several oil pipeline companies this month agreed to move ahead on multi-billion-dollar projects that would link Texas shale fields to Gulf Coast export hubs offering new outlets for burgeoning output expected in 2018.texas tea says: 12/31/2017 at 6:09 pm
That information must leave many readers here perplexed. You have pipeline companies refineries etc. building out the infrastructure to process and transport the oil but Mike tells us it's all hype not to be believed geez and even Dennis agrees with him what are we to believe? I bet they did not do their due diligence probably just read a few presentation and decided hey lets go spend a few billions of dollars for the hell of it Right Mike? I think I will follow the money on this one and not the want-to-be pretend only in cyber space oil men bloggersshallow sand says: 12/31/2017 at 8:33 pm
TT.Mike says: 12/31/2017 at 9:33 pmAll I'm worried about is you shalies killing the oil price again. 2015-17 not good for anyone actually making $$ from the commodity of oil. (Corporate management gets theirs regardless of profits so I don't count them).
And if your response is "compete" I will know you are not for real on owning oil. Because I don't know how a non-op can make $$ on wells that do not payout. Shale CEO's can but non-ops can't IMO. So I don't know how you could be happy seeing Shale getting ready to kill the oil price again?
The only thing I can see killing $55-65 WTI at this point is overproduction of US shale. And it will hurt them too if they overproduce. The shareholders not the management. But it should absolutely destroy non-ops like you if we once again have $25 oil and $1.50 gas.
Corporate shale CEO's receive enormous salaries and compensation packages based on booking fake reserves. The profitability of their corporations or shareholder equity means little to them. Midstream companies that gather shale oil and shale gas are totally reliant on the shale oil industry to continue to be able to borrow more money. They are sheep in a flock. The entire thing from the top down is a façade using OPM. Nobody borrowing this money is personally on the hook; there are no personal loan guarantees nobody is going to be ruined when the entire thing collapses. The scheme is based on getting as much as you can as fast as you can and getting out unscathed.Why promote or cheerlead for an industry that is obviously grossly unprofitable and that is going to ultimately leave hundreds upon hundreds of billions of dollars of debt for our children to deal with? Because you don't care. You don't give a rat's ass. Because exactly like a corporate shale oil CEO royalty owners receiving income from shale wells free and clear of all costs don't care about debt about profitability about depleting our nations remaining hydrocarbon resources and conservation they just care about themselves.
The Peak Oil Barrel community can decide for itself who the "pretenders" actually are.
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Mike says: 12/30/2017 at 7:06 amShallow; Hurricane Harvey disrupted some but not very much EF production. Most of the production drops were related to refinery closers along the GC that curtailed ALL producers in Texas. That storm had no affect whatsoever in Austin other than some rain and did not affect TRRC reporting. There were other electronic issues with TRRC reporting that are now back on the mend.Watcher says: 12/30/2017 at 9:39 amThe EIA like all government entities is a mess; some years back it got confused and with a snap of the finger stopped reporting on-lease production storage. Now now all of a sudden it is reporting gas liquids and anything else it can to make production appear higher than it is. Is there an intentional motivation in that? You decide. Harold already has. EIA 914 surveys are ESTIMATES too; people don't seem to get that. Otherwise this TRRC debate has reached absurd proportions; the EF is on its way down the toilet check Enno's latest post. The Permian is still growing but that rate of growth is going to slow; things out there are getting way gassier and way lighter. There is no place to put the stuff anymore.
I liked your comment about Floyd Wilson; he is a trip. Reminds me of Billy Bits at Shale R Us: https://www.linkedin.com/feed/update/urn:li:activity:6351385280427196416/
I think "our" happy price for 2018 is going to hold. Happy New Year buddy !
Mike
"The main suspect for the increasing divergence is now the inclusion of NGLs into the EIA computation" Duh. Definitions are more or less always changed to meet agenda.Lightsout says: 12/30/2017 at 2:48 pmSame trick was pulled by Russia now report total liquids.Dennis Coyne says: 12/30/2017 at 5:56 pmThe EIA estimates for Aug to Oct are probably too high by 50 to 100 kb/d.Energy News says: 12/29/2017 at 1:18 pmMike is correct that the EIA makes estimates as does drilling info based on RRC data.
The average correction factor for the most recent two months of drilling info data (Aug and Sept) is 42 and 287 kb/d respectively based on past data sets from Aug 2015 Mar 2016 May 2016 Aug 2016 May 2017 Jul 2017 Aug 2017 Sept 2017 and Oct 2017 compared to the Dec 2017 data set from drilling info. In the chart below the Dec 2017 drilling info data set is "corrected" in this way (adding 42 kb/d to August and 287 kb/d to Sept.)
An alternative is to compare the 914 survey data to the drilling info estimate from May 2015 to July 2017 the average difference was 320 kb/d over that period. So I show the 914 survey plus 320 kb/d also in the chart below.
Through July 2017 we have pretty good estimates for Texas C+C after that it is difficult to say which estimate is correct. Note that the 914 survey has differed from the drilling info estimate by as little as 275 kb/d and as much as 365 kb/d from May 2015 to July 2017 so the 914 survey plus 320 kb/d might be off by +/-50 kb/d especially for Aug to Oct 2017 period.
The latest STEO forecast from just 2 weeks agoDennis Coyne says: 01/02/2018 at 6:46 pmEIA Short-Term Energy Outlook (December 12 2017 ) Domestic Production October 9.3 million b/day
For comparison EIA estimates US output was 9637 kb/d in Oct 2017 though perhaps the Texas estimate is high by about 80 kb/d so 9560 kb/d might be a better estimate unless the estimates for other states are too low.Energy News says: 12/29/2017 at 1:01 pmLooks like the STEO expected a 180 kb/d decrease in October and instead there was roughly a 160 kb/d increase. Perhaps the correct final data will be between 9300 and 9640 kb/d. The most recent month's estimate is often revised by 1% or more.
US crude oil exports at 1 731 kb/day in October a new record highKolbeinh says: 12/29/2017 at 1:17 pm
https://www.eia.gov/dnav/pet/pet_move_expc_a_EPC0_EEX_mbblpd_m.htmI don´t know what to say but it somehow does not make sense. Something is very fishy here. Makes me very confident about my bullish oil price predictions for 2018.Kolbeinh says: 12/29/2017 at 2:00 pmPolitics is a major part of oil markets and keeping Russia at bay is a goal for the administration I guess.Energy News says: 12/29/2017 at 3:43 pmAnd so is the target of 3% gdp growth for the president. But the profound backwardation in the futures market for Brent at the moment tells me that reality is storage withdrawal until shortage for oil.
Especially distillates is under scrutiny because of lack of Venezuela heavy oil and too much light oil from Texas. Conventional oil worldwide is suffering from underinvestment and OPEC policy is as expected to serve their own interests. The main problem is easy oil mid API range (too much exploitation).
Liquefied Petroleum Gases (ethane+propane+butane) October production: 3 499 kb/day +281 m/mHeinrich Leopold says: 12/30/2017 at 8:26 am
https://www.eia.gov/dnav/pet/pet_pnp_gp_dc_nus_mbblpd_m.htm
Energy NewsDennis Coyne says: 12/31/2017 at 10:20 amYour posts meets exactly my point as Shale increases the supply of light distillates yet does little to cover the growing worldwide shortage of middle distillates.
As the US exports mostly cheap light distillates and imports expensive real crude oil the recent trade numbers confirm a swift deteriorating goods trade deficit and consequently a sharply falling US dollar as we have seen over the last few days. All what Shale is currently doing is to depress the price of light distillates yet it leaves the growing supply shortage of real oil unaffected.
Hi HeinrichLongtimber says: 12/29/2017 at 11:43 pmThe increased LPG is due to increased natural gas production especially "wetter" natural gas. The has less to do with LTO output and more to do with shale gas output.
It also has very little to do with condensate which is liquids that condense at the lease (it is called "lease condensate") at ambient temperature and pressure.
LPG is at either higher pressure or lower temperature than ambient conditions.
https://www.zerohedge.com/news/2017-12-29/crypto-qatar-these-are-best-worst-assets-2017Heinrich Leopold says: 12/30/2017 at 6:47 am
NG – Ugly.. A Trainwreck for 2017.
What Coke Nose Jim Crammer use to say? time to BACK UP THE TRUCK?As it is too early to assess the impact of the current cold on gas production the recent 40% Canadian rig count slump may serve as a harbinger for the US for next weeks . It is not only freeze offs but but also transport infrastructure and pipeline constraints.Dennis Coyne says: 12/31/2017 at 10:22 amHi HeinrichJeff says: 12/30/2017 at 9:00 amCanadian rig count always drops over the Christmas to New Year's holiday this is not unexpected.
Haven´t seen it posted here yet. Euan Mearns who sometimes post here has a new blog post on "oil price scenario for 2018": http://euanmearns.com/oil-price-scenario-for-2018/ . I like figure 4 think that Ian Schindler has showed something similar for longer time periods (70/80´s).Dennis Coyne says: 01/02/2018 at 2:03 pm
Euan lacks at least two factors but they are more or less impossible to forecast particularly: i) economic growth (demand) ii) how much of the OPEC cuts are voluntary. Also his calculation of natural decline is wrong he assumes all legacy production is in decline.Hi JeffWatcher says: 12/30/2017 at 9:52 amThanks. I think Euan has the price about right ($80/b at the end of 2018 for Brent) but I disagree with him on World oil output in 2018. I think World C+C output will increase at about 600 kb/d per year over the next few years until about 2020 and then will gradually slow down as LTO output and oil sands output will not increase rapidly enough to offset declining output elsewhere in the World by 2025 potentially there could be a short plateau until 2028 or a longer plateau from 2022 to 2029 the higher World output goes the more likely that any plateau will be very short. I agree with your assessment that Euan has overestimated the World decline rate at about 8% which for C+C would be about 6.5 Mb/d not all of World C+C oil fields are in decline some are on plateau and a few are increasing output (at the field level) though if one considers individual oil wells probably 99% of oil wells currently producing (weighted by daily output) are likely to be in decline.
Euan may be looking at things from that perspective which would mean (assuming my 98% guess is correct and that those wells decline at an average annual rate of 8%) we would need 6.4 Mb/d of newly completed wells just to offset the declining wells in order to remain on a plateau.
Euan believes the World will just be able to manage this I think higher oil prices will enable 7.1 Mb/d of oil completions Worldwide over the next year with a net increase in World C+C output.We will not really even know World C+C output for 2017 until March 2018 (I use EIA estimates) and 2018 output will be unknown until March 2019.
The most recent 12 months of World C+C output (average monthly output from Oct 2016 to Sept 2017) was 80 999 kb/d based on EIA data.
The latest numbers out of China say oil consumption growth this year 2017 will be double last year's. This year is pegged at 6.5% with a month to go. India numbers as of Oct say their 2017 growth rate will be about 8% as it was last year.Energy News says: 12/30/2017 at 12:16 pmChina's crude oil stockpiles the latest numbers: There is a big difference between China's official numbers and analysts calculated numbers (China says +90 kb/day vs IEA up to +1000 kb/day)Krisvis says: 12/30/2017 at 2:21 pmBEIJING Dec 29 (Reuters) – China had stored 37.73 million tonnes or 275 million barrels in nine bases by mid-2017 up from 33.25 million tonnes at the end of June the previous year according to the data from the National Energy Administration (NEA).
Adding 4.48 million tonnes of crude oil over the 12 months to June 2017 is equivalent to adding 89 600 barrels of oil per day (bpd).
Reuters (December 29 2017) https://www.reuters.com/article/china-crude-reserves/update-2-china-accelerates-stockpiling-of-state-oil-reserves-over-2016-17-idUSL4N1OT2HFChina's (commercial) crude inventories in November hit a seven-year low of 26.15 million tonnes Xinhua data showed.
Reuters (December 28 2017) https://www.reuters.com/article/us-global-oil/oil-prices-stay-near-high-on-strong-u-s-refinery-runs-china-data-idUSKBN1EM04PYou'll remember this
LONDON October 12th 2017 (Reuters) – China has built its crude oil stockpiles at a record pace in 2017 and while its purchases could tail off towards the year-end inventories could hit the billion-barrel mark in six months the International Energy Agency said.
The agency estimates that over the first half of 2017 Chinese stockbuilding hit a record 1 million b/day.
https://uk.reuters.com/article/oil-iea-china/chinas-crude-oil-buying-spree-looks-set-to-continue-iea-idUKL8N1MN2GOAnybody knows what the definition of crude oil by Texas RRC is? The reason I ask the question is because the production increase up to API gravity 40 is only 70K/day out of 767 K/day from November 2016 to October 2017. PAA said in the conference call that Delaware basin is producing mostly oil with APII gravity higher than 45 and needs to be exported as our US refiners will not touch it.Heinrich Leopold says: 01/02/2018 at 1:56 pmKrisvisDennis Coyne says: 01/02/2018 at 2:19 pm
Thanks for posting your comment. This is exactly my point.Shale produces mostly condensates and light distillates which are an excellent feedstock for the chemical industry. However this concerns just 15% of the oil market. At the beginning of the Shale boom Shale light distillates could substitute a lot of conventional oil which was previously used in the chemical feedstock market. This brought down the oil price.
As Shale oil has now serious troubles to enter the transportation fuel market (due to a lack of middle distillates) the US is forced to sell cheap light distillates on export markets and import on the same time expensive real oil containing middle distillates at a high price. So US imports of real oil are on the rise again. This is why we are seeing a rising oil price and US oil trade deficit again. The dollar has already reacted by a steep slump over the last days.
When one looks at the price of oil with API 40-45 it trades at a premium to heavy oil. Oil above 45 or 50 API is typically classified as condensate.Dennis Coyne says: 01/02/2018 at 2:22 pmAs George has commented repeatedly most of World output is getting heavier and is more expensive to refine. There are many customers around the World that need the lighter oil to blend with heavier crude. In fact much of the US condensate goes to Canada to blend with bitumen so it will flow through pipelines.
For net crude oil imports for the US see
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRNTUS2&f=M
Wrong chart in comment above sorry( link has updated chart)Dennis Coyne says: 01/02/2018 at 2:30 pm
This chart is from EIA (chart above used the EIA data Jan 2015-Oct 2017).texas tea says: 12/30/2017 at 5:14 pmThe US has had net imports of crude oil since 1945 (based on monthly data).
On an annual basis the last year the US was a net exporter of crude oil was 1943. Net imports of crude peaked (annual data) in 2005 at over 10 Mb/d and fell to 6.9 Mb/d in 2015 and rose slightly in 2016 (by 0.36 Mb/d) to 7.26 Mb/d in the most recent 12 months net imports have fallen to 6.99 Mb/d.
"Whatever the case nothing creates job and opportunities the way oil and natural gas exploration does at this time"Boomer II says: 12/30/2017 at 5:57 pm
https://oilprice.com/Energy/Energy-General/GOP-Tax-Bill-Is-A-Boon-For-Oil-And-Gas.htmlchoke on it boys the truth comes out making america great again not just a slogan anymore
Companies losing money don't pay income taxes anyway. A cut won't do them any good.Boomer II says: 12/30/2017 at 6:04 pm"Given President Donald Trump's obsession with reviving the dying industry it's almost surprising that the Republican tax bill doesn't contain any new breaks or incentives that explicitly help coal. 'Energy is actually the least of the beneficiaries in this bill and the simple reason is that energy already has so many carve-outs and exemptions in the tax code that a lot of U.S. based companies just pay hardly any income tax as it is ' said Pavel Molchanov an energy research analyst at the financial firm Raymond James. 'So there is virtually no effect on energy of any kind either positive or negative and that includes coal.'"Mike says: 12/30/2017 at 6:24 pmhttps://newrepublic.com/article/146388/tax-bills-gift-big-coal
Choke on this tee tee: because the shale oil industry can't keep its MasterCard(s) in its pants its overleveraged LTO oversupply is the direct cause of low volatile oil prices that has resulted in the loss of over 440 000 oil and gas jobs around the world since 2014. https://www.rigzone.com/news/oil_gas/a/148548/More_Than_440000_Global_Oil_Gas_Jobs_Lost_During_Downturn . There are still an estimated 55 000 still out of work in America in EOR GOM and in stripper well production. Your beloved shale industry got nothing nada zip out of the new tax law except interest deduction limits which will hurt it not help it.Dennis Coyne says: 12/30/2017 at 8:30 pmHi MikeMike says: 12/30/2017 at 9:03 pmIf most of the LTO companies are losing money I don't think they pay federal taxes on losses so the reduction in tax deduction for interest paid would have no effect.
Am I missing something?
No but tee tee is. Its not easy you know getting thru.texas tea says: 12/31/2017 at 5:53 pmTake for instance the help the oil and gas industry is getting by opening ANWAR. Who is that going to help particularly since there is countless geological and depositional studies done that pretty much condemn the entire area? Or lets take the "roll back" of certain MMS/BSEE regulations regarding multi-string pressure and BOP testing in the GOM after the Macondo incident? That is stupid shit that dumb uninformed people buy into that has nothing to do with reality. Reality is those regulations were on the books and un-enforced. It cost BP what $80B to cut some corners? Nobody I repeat nobody is going to let that happen again. Whatever the current BS is about reducing regulations on the oil industry and helping American become great again by unleashing its hydrocarbon "might " on the rest of the world is laughable. Who is laughing all the way to the bank?
OPEC and Russia dat' who. They are watching America's energy policies get worse not better.
you can educate the ignorant but not the stupid who said that oh yea me. any one of my birddogs knows more about north slope geology than you mike. perhaps you can make a new years resolution try to be accurate at least once in 2019 gonna be hard for a "man" like you but give it a shotHuntingtonBeach says: 12/31/2017 at 7:59 pm"you can educate the ignorant but not the stupid who said that oh yea me. "shallow sand says: 12/30/2017 at 9:00 pmEnough said
I am wondering if EIA is including NGLs as I see OK production has ramped up quite a bit.Guym says: 12/31/2017 at 8:40 amA lot of OK liquids are 55+ API.
Read the post twitter link Dean posted above. Most interesting is a post by a CPA who was involved with the 914 reporting. He thinks it is double counting the M&A production. However within his post he describes that the 914 survey is actually done by a third party contractor. In his discussion with him they were using the higher of projected drilling info or operator report. To put it in my perspective I don't see the 914 having anything like the consistency of the RRC. IMG Crown Energy Services is the third party contractor. Look up their website. Not a lot of time spent on it for a heavy duty IT company so no warm fuzzies there. One could speculate that the primary income is from the EIA contract. EIA paints themselves into a corner with wild projections on Texas production. They call up the third party contractor and question the figures they think are too low. Contractor has to do something to keep the contract don't they?Dennis Coyne says: 12/31/2017 at 10:30 am
Now nobody at EIA can get fired for cooking the books because they have plausible deniability.Hi GuymGuym says: 12/31/2017 at 11:30 amFrom May 2015 to July 2017 the 914 survey was pretty consistent (within 275 kb/d and 365 kb/d of drilling info estimate average 320 kb/d). Perhaps that has changed I would not put much weight on a Twitter comment by a CPA. We will see in a few months what the drilling info estimates are which are usually within 1% of the final output after 3 to 5 months. So by March or April we may know what Oct 2017 TX C+C output is.
As Mike says in Texas they are patient.
That CPA owns his own oil company who reports to the contractor. Do you?Dennis Coyne says: 12/31/2017 at 4:15 pmNo. Has he been reporting NGL (in the US this would be natural gas plant liquids) to the contractor as C+C?Guym says: 12/31/2017 at 4:50 pmIn any case I agree with Mike patience is needed. Perhaps the 914 survey is now covering a much higher percentage of Texas C+C output relative to the May 2015 to July 2017 (27 month long) period.
Time will tell.
"Double counting M&A production" has nothing to do with NGLs. He was admonished by the contractor for under reporting production that was sold off. Instead of using his figures they used his old wells as listed in the drilling info estimate. Hence double reporting it. But what was more interesting is the contractor part. They can send out the survey but can determine whatever they want to include.Dennis Coyne says: 01/02/2018 at 8:53 amHi GuymDennis Coyne says: 01/02/2018 at 8:48 amThe EIA contractor checks with operators when reported numbers are different than expected and sometimes they use the drilling info data instead if the numbers don't look right.
The numbers are revised over time as more data comes in. These are estimates nobody knows final output for many months (for the entire state of Texas or all of the US).
Hi GuymDennis Coyne says: 12/31/2017 at 10:34 amThe link below covers the 914 survey methodology. Yes mergers and acquisitions are a potential problem. The EIA does it's best to account for these to avoid double counting.
About 450 of the largest oil and gas companies that produce about 90% of US oil and gas output (of approximately 13 000 petroleum producers in the US) fill out the 914 survey.
https://www.eia.gov/petroleum/production/pdf/eia914methodology.pdf
Hi Shallow sandWatcher says: 12/31/2017 at 11:21 amNo not NGL only crude plus lease condensate. The EIA has never based C+C on API gravity just liquids produced in the oil field as far as I know.
A bit of recap for newcomers:George Kaplan says: 12/31/2017 at 11:40 amAPI gravity is a density measurement of oil. Measures how heavy it is compared to water. The higher the API number the lighter the oil.
Refineries do not create "middle distillates" out of nothing. They extract them from oil. "Middle distillates" are middle heavy liquids within oil. Diesel and Kerosene. Read truck/tractor fuel and jet fuel. Gasoline is a light distillate. Heavy distillates would be something like bunker fuel or asphalt.
This is all within the same liquid called "crude oil". Traditional labels are applied as regards the word "quality". High "quality" crude oil was light and "sweet". Sweet refers to having low content of materials that cause problems in refining. Like sulphur or vanadium. But tradition has run up against the new nature of crude oil. It has gotten too light. It often lacks middle distillates.
Here is a chart posted a year or so ago by Jeffrey Brown:
https://imgur.com/a/cqtvuI have examined assays of many different oil types from all over the world. Jet fuel boils about 160 degs C and the heaviest diesel boils up around 350 degs C. So "middle distillates" that are actual fuel for things that matter are in the assay between those temps.
https://www.statoil.com/en/what-we-do/crude-oil-and-condensate-assays.html
Scroll down to their .XLS spreadsheets for various blends that they have assay'ed. I would say it does not conform to the chart. BUT. There are some caveats scattered around. "Blend". Dumbbell liquid. This means if oil from one field doesn't have what you want in it you add oil from another field to it to get the constituent parts. Assay it and declare it looks good. BP has an assay website as do others like Capline from Marathon.
All this was to address the question above -- "what is the definition of oil". Study all that and you'll see that the definition is whatever the money agenda says it should be that moment.
Crude oil is only getting lighter in the US everywhere else it's getting heavier and the light LTO is likely to be in greater demand for blending. Refineries set up for heavier oil usually have crackers – either fluid crack crackers or hydrocrackers – which can convert heavier components to gasoline and diesel but can only go so far and blending lighter oil allows the throughput to be maximised. There is no current problem from the oil range of oils being produced.Energy News says: 12/31/2017 at 12:22 pmHOUSTON (Reuters) – Several oil pipeline companies this month agreed to move ahead on multi-billion-dollar projects that would link Texas shale fields to Gulf Coast export hubs offering new outlets for burgeoning output expected in 2018.texas tea says: 12/31/2017 at 6:09 pm
https://www.reuters.com/article/us-usa-oil-pipelines/pipeline-projects-move-ahead-to-tackle-rising-texas-shale-output-idUSKBN1EN1PDThat information must leave many readers here perplexed. You have pipeline companies refineries etc. building out the infrastructure to process and transport the oil but Mike tells us it's all hype not to be believed geez and even Dennis agrees with him what are we to believe? I bet they did not do their due diligence probably just read a few presentation and decided hey lets go spend a few billions of dollars for the hell of it Right Mike? I think I will follow the money on this one and not the want-to-be pretend only in cyber space oil men bloggersshallow sand says: 12/31/2017 at 8:33 pmTT.Mike says: 12/31/2017 at 9:33 pmAll I'm worried about is you shalies killing the oil price again. 2015-17 not good for anyone actually making $$ from the commodity of oil. (Corporate management gets theirs regardless of profits so I don't count them).
And if your response is "compete" I will know you are not for real on owning oil. Because I don't know how a non-op can make $$ on wells that do not payout. Shale CEO's can but non-ops can't IMO. So I don't know how you could be happy seeing Shale getting ready to kill the oil price again?
The only thing I can see killing $55-65 WTI at this point is overproduction of US shale. And it will hurt them too if they overproduce. The shareholders not the management. But it should absolutely destroy non-ops like you if we once again have $25 oil and $1.50 gas.
Corporate shale CEO's receive enormous salaries and compensation packages based on booking fake reserves. The profitability of their corporations or shareholder equity means little to them. Midstream companies that gather shale oil and shale gas are totally reliant on the shale oil industry to continue to be able to borrow more money. They are sheep in a flock. The entire thing from the top down is a façade using OPM. Nobody borrowing this money is personally on the hook; there are no personal loan guarantees nobody is going to be ruined when the entire thing collapses. The scheme is based on getting as much as you can as fast as you can and getting out unscathed.shallow sand says: 12/31/2017 at 11:20 pmWhy promote or cheerlead for an industry that is obviously grossly unprofitable and that is going to ultimately leave hundreds upon hundreds of billions of dollars of debt for our children to deal with? Because you don't care. You don't give a rat's ass. Because exactly like a corporate shale oil CEO royalty owners receiving income from shale wells free and clear of all costs don't care about debt about profitability about depleting our nations remaining hydrocarbon resources and conservation they just care about themselves.
The Peak Oil Barrel community can decide for itself who the "pretenders" actually are.
Mike.Mike says: 01/01/2018 at 7:38 amUnless I missed it I am still waiting for TT to explain how he finances the huge AFE's he must routinely get from $10+ million STACK and SCOOP wells.
Was doing some tax work earlier today and noted for June 2017 oil we got $40.71 per barrel. If 12/29/17 close holds we get $56.
$15.29 more on every barrel is huge for us as it is for everyone who operates wells Be it you XOM Harold Hamm Russia OPEC etc.
As I recall oil prices rebounded in late 2016 then shale went nuts and the price tanked. Their shares tanked too as I recall.
Say TT owns 10% of a shale monster well that cranks out 200K BO in year one. Say his NRI is 8%.
So he got billed $1 million for his part of the well. A $15 higher oil price nets him $240 000 more in year one before deducting severance tax.
So I assume TT would rather get an extra $240 000 in year one and have shale not go crazy talk and crazy drill again as opposed to being able to crow about political crap?
Mike do you know any non-op's on shale wells? How the heck do they finance them?
PS. I know you think it's cold down there in Texas but in my part of the Mid Continent it will be -5 F later tonight. 1 stinking degree F right now. Ouch!!
Happy New Year Shallow and to the rest of the POB community. We close our schools in Texas when it gets below 40 almost. We are expecting low 20's here each night for the next three nights and we are all standby in the field to deal with an array of frozen broken messes. This is not a good time of year to be in the oilfield. I don't know how you folks stand it up north.texas tea says: 01/01/2018 at 5:45 pmYou know quite well the story of tiny NPRI owners not wishing to be pooled in Bakken units and instead electing to assume WI ownership in well(s) then going non-consent in hopes of backing in after payout and becoming real oilmen. That was a disaster. Their expenses now exceed their income and they are on the hook for plugging and decommissioning costs they'd give that stuff away if they could. You have shown us all numerous of these type of WI's for sale on energy.net
In the beginning I knew numerous folks in the EF and PB who turned deals with small carried WI or reversionary back ins after payout. I also knew folks who farmed out shale rights and kept WI. They did so I believe thinking fiscal responsibility and profitability was the order of the day like it always has been in our industry but quickly found out that was not the case and were literally spent into the dirt within a year or so. They sold their WI to operators as fast as they could never to return. I am sure there are exceptions but not many. It is a big boys game now run by lenders with very onerous loan covenants. How does a 1/32nd or a 1/16th WI pay its share of 15) $10M wells that take 3 4 and 5 years to payout if ever? They don't. Not without borrowing money themselves.
If on the other hand one includes RI and ORRI in the well(s) with the NRI from your WI nd pay 1/16th of the costs for say. 0.10000 total interest then you can puff up like a rooster and say I own WI in shale oil wells and they all "make" money. The only people making money in this shale gig is royalty owners overriding royalty owners CEO's and lenders on interest income. That's just a fact.
Stay warm man.
For the life of me SS I am not sure what is so freaking confusing. I have said numerous times the world needs $70 oil. That is a price level that folks like you and most others can make enough money and produce free cash flow to fund new projects. Fact not fiction. BUT. I have also said I live and work in the real world where we actually do real work well by well section by section to find opportunities.shallow sand says: 01/01/2018 at 8:43 pm
Just to restate the facts we have conventional production in 5 states both working interest and royalty interest.(spread the risk) we do not borrow money everything we do is out of cash flow. On most of our wells we lease part of the minerals we acquired and drill a portion of the minerals we acquired. What you may not know is many operators in the better shale plays are actively buying royalty to increase their NRI but of course they are a bit late to the party. The wells we drill are at current prices very economical. freaking do the math. at $50 oil and $4.00 nat gas(btu adjusted) @2 % tax rate in the first 2 years and wells that will produce 400 000BO and 5BCFG. The gas alone pays for the wells and the oil is "free". We started thinking we might get 5-6 wells a section now that number is 15 wells per section.It is a much longer conversation most of which would be way over the heads of the readers of this blog the improvement in production numbers (new frac techniques) over the last 18 months we are seeing are out of this world. 30% at the low side at 100% at the high end increased in production with a 11 month comparison period. How this translates to ultimate EUR i am not prepared to say what I will say is that based on 35 years of experience it looks great.
A couple of takeaways. One there is a point to be made some maybe even most of the shale guys have played fast and loose with normal best practices with regard to finances. But because we have alcoholics we don't condemn the entire industry or impose prohibition which is the argument Mike like's to make.
This is a process what works and does not work will be sorted out by the market place as it should be MUCH will WORK that IS a fact. What the folks who are building pipelines and refineries and other midstream and downstream infrastructure sees is what we see their in the real world where we deal in facts and allocate our money accordingly.best wishes for 2018
TT. If you came into shale with a lot of rock solid conventional paid for in full I can see how you could come up with the money.Mike says: 01/01/2018 at 8:48 pmHowever I am then also sure that you just like us went from making a killing on low decline conventional and $90 oil to making much much less and in your case were using almost all cash to pay for new shale well AFE's.
Even if you have zero debt I assume you at least have an un drawn credit facility just in case a good big deal were to arise. And therefore I assume you were none too pleased when your borrowing base dropped by more than 2/3 from 2014 to 2015 and again another 20+% in 2016 due to shale over production crashing oil and NG prices.
If you are big enough to cash flow several shale AFE I assume you have net production of somewhere between 2 000-10 000 BOEPD?
So let us say 5 000 BOEPD. Again just hypothetical to show what shale did to a larger private independent owned by maybe 2-4 shareholders who got very rich 2005-14.
2014 say you could have cashed out for $500 million. 2016 likely cashed out for 1/3 to 1/4 of that. Quite a hit to the net worth.
Further in 2014 you maybe cleared $90+ million pre income taxes before CAPEX on that 5 000 BOEPD? 2016 that went to $18 million maybe and of course you are getting AFE and JIB on the shale that is draining that the near zero? So no shareholder dividends or distributions in 2015 and 2016 after getting big ones in prior years.
We are small and not in a shale area but we have been around the block Dad has been in since the Arab Embargo. Pretty much everyone had to fire someone in 2015-16 it's good if you didn't. Pretty much everyone had the rug pulled out from under them just like in 1986 and 1998.
Thing is I think even most of the shale guys aren't real happy about shale. They know shale overproduction will drag the price. Same bittersweet deal as farmers growing a bumper crop. Farmers made the most $$ during 2012-13 even though most places 2012 was terrible drought. US commodity producers never do good during periods of oversupply. Just the middle men do good then.
Again I'm just speculating on how you do things numbers etc. I may be all wrong. If I am I apologize.
I just know in 2015 and 2016 there were a ton of shale wells completed that won't payout. Maybe not as many in 2017 but they are still out there. Further they hurt cash flow especially when you cannot control the expense recognition time frames as a non-op.
I am so glad we did not own non-op where drilling was going on 2015-17 as it would have sucked away all our cash and then some plus sold our flush production at market lows.
I am happy to see you want $70 even higher than me. So I'll leave you alone now. Take care. I think maybe deep down you too hope US doesn't ram through 10 and then 11 million BOPD next year?
Your 2% production tax in Oklahoma is going back to 7% tee tee; you and Mr. Blackmon are definitely on the same 'mindless' page regarding the future of shale oil: https://www.forbes.com/sites/davidblackmon/2017/12/31/the-oil-and-gas-situation-a-preview-of-2018/#7b9a4fe67613Boomer II says: 01/01/2018 at 9:30 pmYou are insulting to people here who actually understand the basic arithmetic of the oil business a little better than you give them credit for. There is very clear mounting evidence that things are not getting better in your industry they are actually getting worse. You on the other hand seem to struggle with reality. Five days ago gas was trading at $2.55 per MMBTU not $4 and after royalty deductions interest expenses etc. etc. 5 BCF will not come close to paying for a $10-11M well. I understand now that even after 35 years of whatever it is you do you can't insult me anymore than you have already tried. I would have to value your opinion first.
If you want to win friends and influence people here on POB it would be helpful if you were to give us your name your company's name where these awesome wells are so we can check production data and tax roles etc. That would give you credibility and strengthen your arguments. Otherwise you are just a cute name embarrassing as that is to my beloved Texas who likes to brag about how much money he makes in the shale oil business. We're interested in the big picture here not you personally.
I still get the feeling that this is a sales job. Why tout the industry doing so great if you don't need investors and lenders?Boomer II says: 01/01/2018 at 2:56 pmI found this. It is from 2016 and it is based on privately held companies. Oil and gas extraction companies was the least profitable industry.Survivalist says: 01/01/2018 at 5:35 pmI just found the same article for 2017. Oil and gas still tops the list.
https://blogs-images.forbes.com/sageworks/files/2017/09/least-profitable-industries-ttm-07312017.png
@TTtexas tea says: 01/01/2018 at 6:01 pm
Cling to whatever makes you feel good dude. I guess when you're favorite industry produces a lot of product but can't make any profits doing so one has to find the silver lining wherever they can. Shale is a Ponzi scheme. It won't be long until the music stops and the investors lose their shirts.go f your self .what the hell are your credentials not better than most here. the totality of your experience in the "oil" business is probably limited to buying lubeSurvivalist says: 01/01/2018 at 7:01 pm
(for your bicycle chain)My credentials are irrelevant to the fact that shale oil is a profitless venture. If not for profit then what's it all about? Take a long hard suck on my ass fuck face. Fucking retard.texas tea says: 01/01/2018 at 7:19 pmwell there you go proof that many here are illiterate and ignorant. you resort to profanities when you have no facts. I bet your parents are proud of youSurvivalist says: 01/01/2018 at 7:33 pm
shale oil is a profitless venture. Deal with it fuck head.texas tea says: 01/01/2018 at 7:44 pmI have seen many folks in foreign countries tuck in the pant leg of their trouser in their socks so that it does not keep getting in the chain of their bicycle I bet you can tell us does that work for dresses too?Survivalist says: 01/01/2018 at 7:53 pmHere's one for the Texas teabagger aka the Lone Star State scrotum sucker.Lloyd says: 01/01/2018 at 11:28 pm
Im guessing it didn't go to business school.https://seekingalpha.com/article/4084591-new-darlings-wall-street-folly-oil-fracking-investing
Until you post a name and a company you can't complain about anyone else's credentials.Watcher says: 01/02/2018 at 12:39 pmWe know who Mike is. You are nameless likely lying and probably a charlatan.
And the emojis prove you are a moron.
Damn when did this start.Lloyd says: 01/02/2018 at 10:57 pmWhy is invasion of privacy a good thing? Think bitcoin.
Watcher I didn't say he had to identify himself I just pointed out that he was a hypocrite to demand other people's credentials without presenting his own.Dennis Coyne says: 01/02/2018 at 9:01 amTo the Teabagger I say "Put up or shut up."
Though I do prefer "shut up".
-Lloyd
Hi Texas Teashallow sand says: 01/01/2018 at 3:00 amI agree with Mike that LTO producers are not profitable (as a group).
I have suggested that if oil prices remain under $65/b (WTI price) that US output may increase by about 600 kb/d (average annual C+C output) in 2018 compared to 2017. If oil prices are higher output may be higher if you tell me what that average oil price will be in 2018 I can make a better output estimate.
I also agree with Mike that I do not know what the future oil price will be.
Generally higher World output levels result in lower oil prices (as in 2015-2017) and generally lower oil prices result in lower profits for oil companies ceteris paribus.
Of course I complain about -5 F. Wow much worse in Bakken.SRSrocco says: 01/01/2018 at 10:35 amMajor respect for folks working outside always but especially in the Bakken tonight.
Take care up there. Seeing -32 F in Sidney MT and -25 F in Williston ND.
Shallowtexas tea says: 01/01/2018 at 6:03 pmThe oil price may improve in 2018. However it will likely go DOWN CONSIDERABLY first before it continues higher. According to the COT REPORT (Commitment Of Traders) there is a record Commercial Short Position against oil going back 23 years.
You will notice right before oil fell from $100 in 2014 there was also a high amount of Commercial Short Positions. Today that level is even higher.
steve
Hey Steve show us how your predictions on gold prices have done over the last 5 years ooops next to mike you almost look like a genius.Survivalist says: 01/01/2018 at 7:56 pmhttps://www.marketslant.com/article/zombie-shale-oil-killing-itself-surviveDennis Coyne says: 01/02/2018 at 9:05 am
You're a living joke.
Let me know when shale turns a profit.Hi Shallow sandEnergy News says: 01/01/2018 at 3:24 amNot a lot of completion work occurs at those temperatures I would think.
Not much fun outside in this weather.
EIA Today In Energy: What are natural gas liquids and how are they used?Energy News says: 01/01/2018 at 4:38 am
Table on Twitter: https://pbs.twimg.com/media/DSarQ0wUEAACODP.jpg
https://www.eia.gov/todayinenergy/detail.php?id=5930#World demand for oil products – JODI Data – As everyone knows January is the seasonal low for demand. Comparing demand in December to January of the next year shows an average drop of -2.2 million barrels per day.Longtimber says: 01/01/2018 at 2:54 pm
Chart on Twitter: https://pbs.twimg.com/media/DScZ25HX4AAdDwB.jpgRather Crude product sort out by molecular weight: WTI is refined to 6% Diesel while global crude average is 34% Diesel.Survivalist says: 01/01/2018 at 8:06 pm
https://www.economist.com/news/christmas-specials/21732697-crude-oil-most-traded-commodity-world-what-it-made-and-where-does
http://infographics.economist.com/2017/xmas/20171223_XMC600_weblarge.pngOne more for the Texas TeabaggerWatcher says: 01/02/2018 at 12:43 pmGeorge don't want to scroll way up.George Kaplan says: 01/02/2018 at 2:32 pmDon't suppose you know if oil fields do blending prior to sending to assay? Doesn't seem too very conspiratorial. Someone could gin up a rationale and no one would complain provided the refiner gets the same blend as assayed.
Most are blends – i.e. a bunch of producers discharge into a pipeline and what comes out the end is the cargo – it varies a bit depending on the relative flows from each platform and they might have to blend further in the tank farm (e.g. Forties delivers Brent crude I think from 15 to 20 different platforms). I can only think of one time there might not be blending of some kind which is if an offshore platform with storage (e.g. FPSO) unloads as repeated cargoes which always go to one specific refinery (probably the platform operators – but even then there are usually more than one owner and they often take the cargos separately in proportion to their stake).George Kaplan says: 01/02/2018 at 3:20 pmhttps://www.researchgate.net/profile/Hassan_Harraz/publication/301842929_BENCHMARKS_OF_CRUDE_OILS/links/572a065b08aef7c7e2c4ede8/BENCHMARKS-OF-CRUDE-OILS.pdfWatcher says: 01/02/2018 at 6:26 pmThis is from 2015/2016 – but prices are still light/sweet -> expensive; heavy/sour -> cheap. The only thing that can mess that up is if there are transport bottlenecks which is why WTI is a bit cheaper than Brent (it wasn't before LTO came on line). Tapis is still the lightest and costliest although almost none of it is produced it is still a useful benchmark against which other oil can be rated. Although there are benchmark crudes I think every cargo is basically a negotiated price between the refinery and the producer (there can be penalties if it isn't quite the quality agreed on and it could even be rejected and I think there is an adjustment based on the latest benchmark prices as the contract price would have been negotiated well ahead of delivery). And that is about as much as I know about the trading business except there is a lot of money that can be made and lost on very small margins and variations.
source of interest my recall of Bakken and Eagle Ford assays of yrs ago and how with an increase in API degs reported in the new assays the middle distillate yield hasn't changed. Should not be -- well it's possible but should not be likely.Watcher says: 01/02/2018 at 1:16 pmhttps://www.zerohedge.com/news/2018-01-02/peak-mexicoEnergy News says: 01/02/2018 at 6:06 pmUS implied domestic demand monthly figures – seasonalDennis Coyne says: 01/02/2018 at 6:35 pm
(Finished Motor Gasoline + Finished Aviation Gasoline + Kerosene-Type Jet Fuel + Distillate Fuel Oil + Residual Fuel Oil + Lubricants + Asphalt) but no NGLs
From here: EIA – Finished Petroleum Products – Products Supplied: https://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_mbblpd_m_cur.htmThe January dip in demand table on Twitter
https://pbs.twimg.com/media/DSki1qFWsAAK6zX.jpg
Yearly averages & the year over year change. 2017 to Oct.
https://pbs.twimg.com/media/DSko0eLXcAEyl8L.jpg
First chart from comment aboveDennis Coyne says: 01/02/2018 at 6:36 pm
Second chart in link from energy news. Thanks!Cats@Home says: 01/02/2018 at 8:04 pm
U.S. oil production booms to start 2018
Updated 8:39 AM; Posted 8:39 AM
By The Washington Posthttp://www.nola.com/business/index.ssf/2018/01/us_oil_production_booms_to_sta.html
U.S. crude oil production is flirting with record highs heading into the new year thanks to the technological nimbleness of shale oil drillers who have unleashed the crude bonanza.
The current abundance has erased memories of 1973 gas lines which raised pump prices dramatically traumatizing the United States and reordering its economy. In the decades since presidents and politicians have mouthed platitudes calling for U.S. energy independence.
President Jimmy Carter in a televised speech even compared the energy crisis of 1977 to "the moral equivalent of war."
"It's a total turnaround from where we were in the '70s " said Frank Verrastro senior vice president at the Center for Strategic and International Studies.
Shale oil drills can now plunge deep into the earth pivot and tunnel sideways for miles hitting an oil pocket the size of a chair Verrastro said.
The United States is so awash in oil that petroleum-rich Saudi Arabia's state-owned oil and natural gas company is reportedly interested in investing in the fertile Texas Permian Basin shale oil region according to a report last month.
That is a far cry from the days when U.S. production was on what was thought to be an irreversible downward path.
"For years and years we thought we were running out of oil " Verrastro said. "It took $120 for a barrel of oil to make people experiment with technology and that has been unbelievably successful. We are the largest oil and gas producer in the world."
The resilience of U.S. oil producers has come as the price of crude rose above $60 per barrel on world markets. Many shale drillers can start and stop on a dime depending on the world oil price. The sweet spot for shale profit is in the neighborhood of $55 to $60 per barrel.
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Dec 17, 2017 | www.zerohedge.com
Uh-Oh Canada! Tyler Durden Dec 17, 2017 3:15 PM 0 SHARES Authored by Nick Cunningham via OilPrice.com,
Oil from Canada's oil sands is now selling at a $27-per-barrel discount relative to WTI, the sharpest difference in more than four years
Western Canada Select (WCS), a benchmark for oil from Alberta's oil sands, has plunged in December, falling to just $30 per barrel at the end of this past week. WCS typically trades at a discount to WTI, reflecting the differences in quality from lighter forms of oil, as well as the extra transportation costs to move oil hundreds of miles out of Alberta.
But a discount is usually something like $10 per barrel, not more than $25. A price deterioration of this magnitude has not been seen in years.
... ... ...
At the end of the day, the current $27-per-barrel discount is being acutely felt in Canada's oil industry. Kevin Birn, a director at IHS Energy in Calgary, told Bloomberg that a $25-per-barrel WCS discount translates into a loss of $20 million per day for Canada's oil producers.
Lore -> east of eden , Dec 17, 2017 6:27 PM
zebra77a -> Lore , Dec 17, 2017 7:28 PMTyler should consider doing his audience a really big favor by addressing critical market fundamentals, because it's clear that there is a lot of ignorance here, still.
There is a TEMPORARY surplus, yes, but production in domestic American formations is collapsing (no exaggeration, the entire sector is engaged in a conspiracy of silence), and the U.S. Government is about to lose its ability to pay by issuing endless mountains of debt (hence all the distractive war-mongering and pathological adventures overseas). A new civil war is coming.
America is NOT a desirable trading partner, going forward.
Prime Minister Justin Trudeau is a clueless buffoon, pandering to the Victim Industry, Progressivists and other debased groups. Somebody in Ottawa needs to give him a good shake and remind him of his priorities regarding practical matters, starting with expansion of Canadian refining capacity and port access to international markets, which ought to be considered a matter of national security.
jaxville -> zebra77a , Dec 17, 2017 9:34 PMThe big dirty secret is Saudi Arabia, THERE oil bed's are collapsing and pumped into total failure, and there was some articles they were buying oil BACK from New York. We could be sitting on the largest price swing in history.
Question is - when is Israel going into Iran...?
Rock On Roger , Dec 17, 2017 3:30 PMGet a grip! Israel is never going into Iran. They will get the USA and other "allies" to do that for them.
zebra77a -> In.Sip.ient , Dec 17, 2017 7:35 PMWe've got the same problem with gas in Alberta. Lotsa new production and not enough export capacity. Friday Alberta spot price @$1.77 Canadian dollars per gigajoule. More or less $1.35/mcf.
shitshitshit , Dec 17, 2017 3:50 PMThe reality was the oilsands never had to be profitable, just attractive.
No not visually attractive, investment attractive for stock markets and pensions.. The oilsands was always created on the coffer of the public investment. The oilsands were built off of pension funds and excess money flows from the fiat expansion of the Central Banks. It never had anything to do with profitability grant you if Oil had stayed at $100 a barrel big oil would of built plants the size of California.
More oil now goes into making plastic than goes into driving. Price of oil is completely and utterly delinked from it's availability. When is it going back to $100 / barrel ask when Israel is invading Iran..
johnnycanuck -> shitshitshit , Dec 17, 2017 4:20 PMI don't understand why would they lose money selling their production instead of stopping the production until conditions are reunited to sell at a decent price. Sometimes you have to be willing to suffer a but to make things good again otherwise they might drag on forever.
The oil market is like a masochist market. People try to be three first ones to sell at any price instead of patiently waiting for the right moment.
zebra77a -> shitshitshit , Dec 17, 2017 7:46 PMBecause you can't just stop. It takes years and enormous amounts of money to put all the pieces needed in play.
It's not like a Vietnamese food truck start up
CHX13 , Dec 17, 2017 3:58 PM-40 for weeks up there. Boiler shuts off, pipes freeze up in hours. Water expansion will crack it all apart. They don't even want air touching the inside of the pipes to prevent oxidation. The fun one is the Texans they don't know they because they think they can run a Fort Mcmurray oilsand plant like the ones they run in Texas. The only thing keeping the plant running is a pipeline of money..
Heat Trace has put many electricians kids through a lot of colleges and universities..
Profitability is not a big concern, grandmas pension money is stuck into companies like Exxon oil, it's not going anywhere, they'll pump at a loss for 3-5 years potentially before they will shut it all down..
But they'll drop the wages and lay people off in hours... Fort McMurray' s biggest export is skilled tradesmen now not oil..
johnnycanuck , Dec 17, 2017 4:12 PMThe future of the canadian oil sands stand on a slippery slope... ;-)
That's what happens when CONswervatives sell out their country's ability to control it's resources and it's means to get them to market.
They sold out Canada's publicly owned railway, then they sold out one of the last remaining Crown Jewels, the Canadian Wheat Board which not only owned it's own rail cars, but successfully managed export shipments for decades via it's reliable and well managed access to ports
Said hoakey Free Market sales pitch is just another means of screwing a country and it's citizens out of it's wealth.
The Koch bros for example, have made out like bandits at the expense of Canadian citizens right to fair profits from it's oil reserves that the likes of Koch had nothing to do with it's expensive development stage. Perhaps more appropriate description of Koch Ind is, like a Bedouin Sheik vanishing in the night with their plunder.
Said CONswervatives even went so far as to screw up Canada's grain marketing system in favor of...drum roll please.. A US hedge fund and Saudi Arabia.
But then, when their political nemisises, the Liberal Party of Canada trades off with said CONswervatives, in our times, they do nothing except extol the virtues of Free Trade. Which, all bullshit aside, means they are on the same side and what few differences there once were, like where you can stick your thingy, and into whom, are fast disappearing.
I don't expect Murikans to understand the landscape of Canadian politics, as Canada isn't a major part of the centre of their consumer society oriented Universe.
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Dec 16, 2017 | www.nakedcapitalism.com
joecostello , December 15, 2017 at 8:26 am
joecostello , December 15, 2017 at 9:23 am"OPEC production fell by 130,000 bpd in November, due to lower output in Saudi Arabia,"
There's no industry capability to put this figure as a fact. They still have people looking at tankers with binoculars figuring out how much the Sauds are putting out. Even better the WSJ printed in a story last week that the Sauds were putting out oil at $2.25 a barrel!
Anyway, all oil numbers should be taken with a grain of salt, always. Shale is meeting with increasing geological limits, going to cost even more to produce, this in an industry that's never made a profit, even at $100 and is some $280 billion in debt, which I guess its good debt doesn't mean anything.
And the band played on
this is good piece on Asia refiners having trouble with US shale as US refiners have previously.
Condensate is not the oil, "black gold, Texas tea" of old and fact is that type of oil basically peaked a decade ago in low 70s mbd. Shale fields have always produced a lot of condensate and are now producing more and increasing amounts of just gas.
Anyway "oil glut" has always been at best a nebulous term for many reasons, but then we here in the US just think, as Mr. Obama proudly stated in his last State of the Union, "$2 a gallon gas ain't bad either."
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Nov 27, 2017 | peakoilbarrel.com
steve from virginia says: 11/15/2017 at 12:22 pm
You have to wonder how much of the world's 96.7 mbpd 'crude' oil output is natural gas liquids?SRSrocco says: 11/15/2017 at 12:32 pmHard to get a handle on because non-oil liquids are not reported separately, (from 2014):
"Refiner Phillips 66 (PSX.N) and midstream giant Plains All American (PAA.N) have said condensate is oil with an API gravity of 45 or above. Meanwhile, Marathon Petroleum Corp's (MPC.N) top executive said in a recent interview he believed condensate should have an API gravity of 60 and above.
Without a universal standard, production data vary wildly. The EIA's own figures suggest that anywhere from 8 percent to 16 percent of U.S. crude oil production is condensate – a difference of more than half a million barrels a day."
Depletion of oil fields means increase in non-crude liquids with decreased energy content and decreasing percentage of motor fuel product, not just in the US but in other oil regions. If 10% of the 96.7 million barrels is non-oil gas liquids then actual crude oil output isn't really increasing as OPEC secretariat seems to suggest.
I know this has been mentioned before, I've heard it from Art Berman and others w/ energy backgrounds, but the 'good news' is constantly repeated.
steve from Virginia,Dennis Coyne says: 11/15/2017 at 1:09 pmDennis was kind enough to send me an excel spreadsheet on Global NGL production. According to his data, the world produced 92.1 mbd of C+C+NGLS in 2016. Of that total, NGL's accounted for 11.5 mbd. Thus, NGL's represents 12.5% of the total.
And yes, not only do NGL's contain approximately 55% of the energy in a typical barrel of oil, but it fetches about 55% of the market price for oil as well. So, the world is producing a lot of crappy liquids, which gives the impression to the BrainDead Layman, that we are producing a record amount of oil we are not.
We are producing a record amount of LOW-QUALITY CRAPPY PETROLEUM LIQUIDS. I would imagine if we would break it down by separating oil sands, shale and NGL's the good quality stuff peaked a while ago.
There are different ways to define "conventional oil". If we include deepwater offshore and polar oil but exclude "extra heavy" oil (API Gravity < 10 degrees) and tight oil output in our definition of "conventional" Crude plus condensate (C+C), then in 2016 annual output of conventional C+C was at a peak (annual data through the end of 2016) at 73.2 Mb/d. The previous peak in 2005 (72.1 Mb/d) was exceeded in 2015 (72.9 Mb/d). There are other definitions of conventional oil, many (like BP) include NGL, in that case the data by mass is better than volume because it approximates energy content more closely. NGL is useful for heating and petrochemicals, but less so for land transportation.
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May 20, 2016 | peakoilbarrel.com
Brian Rose , 05/19/2016 at 11:04 pm
Big news from Canada today:George Kaplan , 05/20/2016 at 1:36 amhttp://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.
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.
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Nov 10, 2017 | peakoilbarrel.com
Energy News says: 11/08/2017 at 12:18 pm
EIA weekly change in ending stocks (crude+products).George Kaplan says: 11/08/2017 at 4:26 pm
Overall stocks down 0.56%, pretty much inline with recent trends, crude up 2.2 mmbbls, gasoline down 3.3 and distillate down 3.4. But the only number that matters to the traders is the crude and because it is up price falls and it's reported we must be back in a glut. Bonkers.FreddyW says: 11/09/2017 at 3:55 amI think we are in refinery maintenance season now, so crude stocks should increase normally. Interesting to note is that gasoline and distillate stocks are back to normal levels. So they will have to draw a lot more from crude stocks going forward.Guym says: 11/09/2017 at 10:30 amSame principle drives lemmings, I think. They have to be over the cliff, before they will recognize it is there.
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Oct 11, 2017 | peakoilbarrel.com
Guym
says: 10/10/2017 at 3:58 pmI am quite sure I am not the only one, but at constantly looking at the commercial inventory number on the EIA weekly report, I am absolutely convinced it is not real. The only time I have seen it adjusted is when they decided to discontinue reporting of lease storage oil. As if they had any idea of what that amount was. In accounting, it is required to take an annual inventory. Only one other company I know of actually attempts to do a physical count of stored oil inventory, and they only do some areas. I've never heard of EIA ever doing a physical inventory of that number.
When I know the production figure is way off each week, it make me keep looking at that funky looking, stagnant number. The rest of the world's inventory is dropping fast, but we still use a decades old funky number. And calculate to its upward or downwards movement with completely false numbers.
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Oct 06, 2017 | peakoilbarrel.com
Guym: 10/02/2017 at 11:02 pm
Looked at what EIA posted for "final" numbers for Texas for July. 3474. Now, July 2016 had higher numbers for initial production than July 2017. Much higher with condensate, though I can't find the original condensate number, but they were running over 9 million at the time.Guym: 10/03/2017 at 10:26 amTexas final number for July 2016, at this point, is 3110. EIA has 3161 for July 2016. I don't need to do a lot of mathematical computations by looking backwards.
Just using EIA numbers for 2016, its over by about 313,000. Undoubtedly more.
Substituting, that puts US production at 8,925,000. Even though we had the shutdowns Aug and Sep for Harvey, EIA has production on the latest weekly at 9,547,000.
Does seem a might high, and that doesn't count a questionable increase in the GOM on the EIA July "final" numbers.
If the production is that far off, what else on the weekly report is way off? Total inputs, imports, exports, inventory draws?
At first, my thought was, why are they doing this? Then the more I thought of it, there is no nefarious intention. Any organization who uses their calculation to come up with "drilling productivity", can't have both oars in the water. Or, as a popular movie reiterates: "stupid is, as stupid does".Dennis Coyne: 10/04/2017 at 12:47 pmHi Guym,Energy News: 10/03/2017 at 11:47 amThe EIA estimates (tight oil estimate) about a 510 kb/d increase in US tight oil production from July 2016 to July 2017, about 411 kb/d was from the Permian Basin (Texas and New Mexico). See
https://www.eia.gov/petroleum/data.php#crude
Click on "Tight Oil Production Estimates".
I was thinking that the EIA's monthly Supply and Disposition numbers are more accurate that the weeklies. But even the monthly figures have an adjustment factor and it spiked up to +558 kb/day in July. So far, it seems that only the inventory figures are reliable.Guym: 10/03/2017 at 12:20 pm
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRUA_NUS_2&f=M
Inventory numbers are not a count of oil. They are a mathematical calculation of what had to be used, based upon baseless numbers. One could base an argument, that because production was really lower, more should be deducted from inventory each week. Some have made that claim. I just think all of the numbers are highly suspect. It is materially in error, and all of the numbers should be questioned.Energy News says: 10/03/2017 at 12:23 pmIt really appears to me that US production is closer to 8,900,000 barrels a day versus 9,200,000 a day.
You would imagine that Customs must know how much oil is traded per month. And that refineries must know how much oil they use. But even looking at the monthly data it's difficult to know what is accurate and what isn't.Energy News says: 10/03/2017 at 1:15 pmIf you calculate monthly production using the equation but without the adjustment you get the blue line on the chart
Refinery Input = Production + Imports – Exports + Inventory Change + Adjustment
Analysts version on Twitter: https://pbs.twimg.com/media/DLIILKvVoAE_dMS.jpg
The EIA did make some changes but looking at weekly vs monthly it is still the export/import numbers that show the largest revisions. Although also wondering how accurate the monthly data is.Energy News says: 10/04/2017 at 5:24 amMarketWatch – Aug 31, 2016 – Oil market cheers EIA changes to weekly statistics
On Wednesday, the EIA's Today in Energy report said the agency is now publishing its weekly petroleum export and consumption estimates based on "near-real-time export data" provided by U.S. Customs and Border Protection. It was previously using weekly export estimates based on monthly official export data published by the U.S. Census Bureau about six weeks following the end of each reporting month.
"Exports should be more accurate, and 'net imports' should be better, but still with uncertainty," said Michael Lynch, president of president of Strategic Energy & Economic Research.
http://www.marketwatch.com/story/oil-market-cheers-eia-changes-to-weekly-statistics-2016-08-31
(I meant to type differences rather than revisions in the post above)Energy News says: 10/04/2017 at 6:28 amIf the monthly data is accurate (?) then compared to the weeklies the USA is exporting more and importing slightly less than reported in the weeklies.
Monthly vs Weekly Trade Volumes, the average difference from Jan-2016 to Jul-2017
Exports: Monthly – Weekly = +124 kb/day (average over 19 months since Jan-2016)
Imports: Monthly – Weekly = -33 kb/day
Net Imports: Monthly – Weekly = -157 kb/day
The same exercise for refinery inputU.S. Refinery & Blender Net Input
Monthly vs Weekly, the average difference from Jan-2016 to Jul-2017
Monthly – Weekly = -32 kb/day (average over 19 months since Jan-2016)If you just look at January, for the last 4 years, the January weeklies underestimate the demand drop every year
Monthly – Weekly = -189 kb/day (average over last 4 Januarys)Monthly vs Weekly, the average difference from Feb-2016 to Jul-2017 (without Jan-2017)
Monthly – Weekly = -7 kb/day (average over 17 months since Feb-2016, without Jan-2017)
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Sep 26, 2017 | peakoilbarrel.com
Watcher
says: 09/21/2017 at 11:01 am I don't scroll much on tablets. So somewhere up above there was talk of condensate and why GOR in the Bakken meant or didn't mean something . . . for reported oil production.Condensate has definition problems. When used casually it usually means liquid that flows from an OIL well, though the proper term for that liquid would be lease condensate. Condensate from gas wells is generally NGLs and not liquid at room temp/pressure.
But Lease Condensate is liquid at room temp/pressure. Nat Gas from a crude oil well, creating or associated with a flow of NGLs AND lease condensate, will essentially mean a flow of liquid-at-roomtemp with API 45-75 added in with the crude oil liquid. That's definition for lease condensate. API 45-75. It won't have hardly any diesel or kerosene in it.
Lots of potential for fuzzing up pricing. There seems to be a glib wave of the hand and a "the higher the API, the easier it is to refine so it's more valuable." But this can't be so if a refiner has diesel and kerosene customers to serve.
The Bakken API number is higher than previous claims, per Statoil's February assay. This is all getting no attention. Reply
George Kaplan says: 09/21/2017 at 11:13 am
No, I'm afraid you have that completely wrong. Lease condensate comes from a gas well, as the pressure is let off some liquid drops out (it's a complicated process and can be due to the gas cooling as it expands and a phenomenon called retrograde condensation – it depends where the starting and finishing points are in relation to the phase envelope). That is condensate (mostly pentanes with some heavier, and lighter stuff absorbed). The gas left over goes to a gas plant and NGLs are removed (C2, C3 and C4). Associated gas from an oil well also goes to a gas plant and NGLs get removed from it as well, there may be some drop out from the gas in the pipeline which arrives at the gas plant – that is also called condensate, but it is not lease condensate as it is metered separately (i.e. it is part of the gas a far as the lease owner is concerned).Watcher says: 09/21/2017 at 4:18 pmLease condensateGeorge Kaplan says: 09/22/2017 at 1:27 am
When most people talk about condensates they are referring to lease condensates, so defined because they are produced at the lease level from oil or gas wells. These condensates can be produced along with significant volumes of natural gas and are typically recovered at atmospheric temperatures and pressures from the wellhead gas production. These "raw" condensates come out of the ground as mixtures of various hydrocarbon compounds including NGLs, pentanes (C5s, so called because they have five carbons in the molecules), C6s (hexanes), and depending on the condensate, a menagerie of heavier hydrocarbons in the C7, C8 and even heavier range.A lease condensate has an API gravity ranging between 45 to 75 degrees. Those with a high API contain lots of NGLs (including ethane, propane and butane) and not many of the heavier hydrocarbons. These condensates are clear or translucent in color. The condensates with a lower API gravity down at the 45 degree level look more like crude oil (black or near black) and have much higher concentrations of the heavier C7, C8 and heavier compounds.
The WestTexas guy posted a graph some time ago showing relative concentration of middle distillates as a function of API degree number. The amount crashes around API 42. Looking for link . . . .
Someone can find his post if they like. I stored the chart and am uploading it to imgur.
All that is correct – but to a first approximation all the condensate comes from gas wells and none from oil wells.
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May 30, 2017 | peakoilbarrel.com
Mike says: 05/30/2017 at 6:35 pmGot it tee-tee; America is still a net importer of crude oil. That's some good investigative reporting there.Look, inventory levels are still at an all time high in America and the bulk of that is light tight condensate. The export ban has been lifted in the US for over three years now; nobody afar wants to import LTO, or much of it, and we still can't lower those inventories. The price of oil is low, and volatile. In the mean time all those big wells you own in Oklahoma are just making the problem worse. And while all this is going on, hold onto your knickers .oil imports into America are going UP, not down. Google it.
Canada is the 10th largest oil consuming nation in the world, Mexico the 11th and the UK the 18th. America, on the other hand, is the largest oil consuming nation in the world, by a wide margin. We do not have the LTO resources to achieve, nor sustain, hydrocarbon independence. Forget the costs, and the additional burden that attempting to achieve hydrocarbon independence would place on our national debt, it can't be done. There is not enough of it.
I dislike the American shale oil industry, in general, because it cannot function without borrowed capital and it no longer has the ability, in my opinion, to pay back the hundreds of billions of dollars it owes. I understand that doesn't bother you, and I understand why.
I also dislike the lying the shale oil industry engages in that convinces other stupid people that we have all the shale oil we ever need in America, enough for ourselves, and anybody else in the world that wants to buy it.
Personally, I would rather sell my oil for a higher price than current prices, but then again I have to pay to get it out of the ground, unlike yourself, I am sure, who gets it free and clear of all costs.
I also embrace oil price stability as that leads to employment stability and a healthier oil industry for America's future. I also believe it is important to conserve our remaining hydrocarbon resources in America and to otherwise develop what is left of those resources at a pace that is commensurate with the world crude oil market.
Again, I understand completely why you don't get that. I can't help you.
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Feb 21, 2017 | peakoilbarrel.com
Energy News says: 02/17/2017 at 7:47 amIn their 11th annual review of oil sands supply costs, the Canadian Energy Research Institute (CERI) concludes all new oil sands projects unprofitable (at current oil prices) . . .aws. says: 02/15/2017 at 10:55 pmThe plant gate supply costs, which exclude transportation and blending costs, are C$43.31/bbl for a SAGD project and C$70.08/bbl for a stand-alone mine.
After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing for SAGD projects is US$60.52/bbl, and US$75.73/bbl for a stand-alone mine. In comparison to last year's update, the WTI equivalent costs for a greenfield SAGD project are 25 percent lower and 16 percent lower for a stand-alone mine based on lower operating costs, changes in US/CDN exchange rate assumption and a lack of premium on diluent costs. At current WTI prices of just above US$50/bbl, one can assume that these greenfield projects are not economic or have to accept a lower rate of return.
http://resources.ceri.ca/PDF/Pubs/Studies/Study_163_Executive_Summary.pdfSuncor Energy announced a scope change, construction delay and capital cost increase for its upcoming Fort Hills Oil Sands Mine. The revisions were blamed on the Alberta wildfires and design changes made to the plant's Froth Treatment facility. Despite the cost increase, Suncor says the project's capital intensity remains in-line with its sanction guidance of CAD$80,000 to $83,000 per flowing barrel, excluding foreign exchange impacts.
Partner Teck Resources put out a more cautious forecast and estimates the plant will produce 186,000 bbl/day over the life of the project. Factoring in a lower Canadian dollar (which has declined over 20% since the project was sanctioned in 2013), capital intensity could be as high as C$91,000/bbl.
As a point of comparison, capital costs for Imperial Oil's Kearl Oil Sands project (which has a comparable process and product), were estimated at $22 billion for 220,000 bbl/day of bitumen production, or C$100,000 per flowing barrel.
http://www.oilsandsmagazine.com/oilsands-weekly/2017/2/10Western Canadian Select (WCS), Jan 2017: CAD$52.3 and USD$39.6
Alberta's Growing $30-Billion Liability: Inactive Wellsaws. says: 02/15/2017 at 10:53 pmCompared to other jurisdictions, province lets oil firms off the hook when it comes to cleaning up.
By Andrew Nikiforuk 13 Feb 2017 | TheTyee.ca
No more profits to be capitalized, time to socialize the costs.Alberta orphan oil well tally jumps as Lexin licenses suspended
By Nia Williams | Reuters | CALGARY, Alberta Wed Feb 15, 2017 | 2:41pm EST
The provincial regulator ordered privately-held Lexin to cease all production, saying it failed to comply with multiple orders and lacked enough staff to manage its more than 1,600 sites.
Calgary-based Lexin also owes more than C$1 million to Alberta's orphan fund and more than C$70 million in security for its obligations to clean up its oil and gas facilities at the end of their producing life.
--
Alberta's Orphan Well Association (OWA) is responsible for cleaning up wells that have no owners financially able to deal with abandonment and decommissioning costs. It is overseen by the AER and funded by levies from the oil and gas industry.The enforcement action by the regulator means the 1,380 wells belonging to Lexin are now in the care and custody of the OWA, taking the total numbers of ownerless wells in Alberta to 2,970.
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Feb 20, 2017 | peakoilbarrel.com
Energy News says: 02/17/2017 at 3:28 pmCanadian Oil Sands – Wall Street Journal – 2017-02-17Boomer II says: 02/17/2017 at 11:27 pm
Oil sands projects can require billions of dollars in upfront investment and seven to 10 years, or more, to bring returns. Instead, companies are increasingly focusing on new sources of crude oil, such as shale, that don't require the same massive investment and that can get from development to production much more quickly.To be sure, oil output isn't expected to fall in Canada as it has in the U.S., and some projects for which money has already been spent may go forward, a sign of the resilience of oil sands investments once money has been spent. That is because the cash cost of producing barrels once projects are up and running is low.
https://www.wsj.com/articles/energy-companies-face-crude-reality-better-to-leave-it-in-the-ground-1487327406
I can't see the original article since it is behind a paywall.But this appears to be the text of the article without the above graph.
Energy Companies Face Crude Reality: Better to Leave It in the Ground | Fox Business : "Once considered a safe bet, Canada's vast deposits are emerging as among the first and most visible reserves at risk of being stranded by a combination of high costs, low prices and tough new environmental rules."
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Feb 20, 2017 | peakoilbarrel.com
Energy News says: 02/17/2017 at 7:47 amIn their 11th annual review of oil sands supply costs, the Canadian Energy Research Institute (CERI) concludes all new oil sands projects unprofitable (at current oil prices) . . .The plant gate supply costs, which exclude transportation and blending costs, are C$43.31/bbl for a SAGD project and C$70.08/bbl for a stand-alone mine.
After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing for SAGD projects is US$60.52/bbl, and US$75.73/bbl for a stand-alone mine. In comparison to last year's update, the WTI equivalent costs for a greenfield SAGD project are 25 percent lower and 16 percent lower for a stand-alone mine based on lower operating costs, changes in US/CDN exchange rate assumption and a lack of premium on diluent costs. At current WTI prices of just above US$50/bbl, one can assume that these greenfield projects are not economic or have to accept a lower rate of return.
http://resources.ceri.ca/PDF/Pubs/Studies/Study_163_Executive_Summary.pdfSuncor Energy announced a scope change, construction delay and capital cost increase for its upcoming Fort Hills Oil Sands Mine. The revisions were blamed on the Alberta wildfires and design changes made to the plant's Froth Treatment facility. Despite the cost increase, Suncor says the project's capital intensity remains in-line with its sanction guidance of CAD$80,000 to $83,000 per flowing barrel, excluding foreign exchange impacts.
Partner Teck Resources put out a more cautious forecast and estimates the plant will produce 186,000 bbl/day over the life of the project. Factoring in a lower Canadian dollar (which has declined over 20% since the project was sanctioned in 2013), capital intensity could be as high as C$91,000/bbl.
As a point of comparison, capital costs for Imperial Oil's Kearl Oil Sands project (which has a comparable process and product), were estimated at $22 billion for 220,000 bbl/day of bitumen production, or C$100,000 per flowing barrel.
http://www.oilsandsmagazine.com/oilsands-weekly/2017/2/10Western Canadian Select (WCS), Jan 2017: CAD$52.3 and USD$39.6
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Feb 10, 2017 | peakoilbarrel.com
daniel says: 02/10/2017 at 4:45 amIEA numbers out today. One jumped out to me:Jeff says: 02/10/2017 at 5:14 amOECD stocks fell 800,000 bpd in Q4/2016. This is before any OPEC cuts.
Am I the only one who thinks this is worrying? OPEC was pumping flat out at that point and we still were in a deficit?
Strange graph though. Where did the oil go? http://www.iea.org/newsroom/news/2017/february/omr-the-first-cut-is-the-deepest.html
It looks like a stock build up of ~500,000 bpd in Q4/2016 but OECD inventories are down 800,000 bpd in the same period.Some of it is probably China, but where did the rest of the 1.3 mbd go? tankers?
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Jan 24, 2017 | economistsview.typepad.com
anne : , January 24, 2017 at 09:01 AMhttps://www.nytimes.com/2017/01/24/us/politics/keystone-dakota-pipeline-trump.htmlpgl -> anne... , January 24, 2017 at 09:03 AMJanuary 24, 2017
Trump Revives Keystone Oil Pipeline That Obama Blocked
By PETER BAKER and CORAL DAVENPORTPresident Donald J. Trump continued dismantling his predecessor's policies by clearing the way for a project that stirred years of debate over the balance between energy production and preventing climate change.
Barack Obama rejected the proposed 1,179-mile pipeline in 2015, arguing that it would undercut American leadership in curbing the reliance on carbon energy.
More profits for Big Oil.libezkova -> pgl... , January 24, 2017 at 09:16 AMBig oil is in deep knockdown. They need all help they can get.pgl -> anne... , January 24, 2017 at 09:07 AMLess transportation cost to refineries is somewhat beneficial for customers too.
The key problem here is quite different: is there enough staff to transport?
"Studies showed that the pipeline would not have a momentous impact on jobs or the environment, but both sides made it into a symbolic test case of American willingness to promote energy production or curb its appetites to heal the planet."libezkova -> pgl... , January 24, 2017 at 09:38 AMIt does not require a lot of high paying jobs to build a pipeline. I have no idea about the potential risks to the environment but I do know that the owners of oil in Canada wanted to see their prices in line with prices of oil producers in the North Sea. In other words, more profits. That is really what this debate is about. Not jobs - just profits.
"the owners of oil in Canada wanted to see their prices in line with prices of oil producers in the North Sea"-->Nonsense.
The cost for Canadian oil should be higher as oil sands is a more expensive source of oil then the deep sea drilling. Also this heavy oil requires dilution.
It might well be that $55 is a minimum for them (actually depends of the method of extraction used). And average is probably around $65 or higher. And this is just "break-even" cost.
http://www.ogj.com/articles/2014/07/ceri-costs-up-for-oil-sands-production.html
== quote ==
The new estimates of plant-gate supply costs: $50.89/bbl (Can.) for SAGD, $71.81/bbl for stand-alone mining, and $107.57/bbl for integrated mining. CERI estimates the cost of stand-alone upgrading at $40.82/bbl.... ... ..
Total capital requirements during 2014-48 in the oil sands, excluding those for primary production and EOR, are $597.9 billion (Can.) in the reference case, $636.6 billion in the high case, and $590.2 billion in the low case.
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Jan 24, 2017 | seekingalpha.com
I have applied the cost model on 3 important Canadian oil sand producers: Suncor (NYSE: SU ), Imperial Oil (NYSEMKT: IMO ) and Canadian Oil Sands ( OTCQX:COSWF ). These companies were together responsible in 2013 for a production of 726k barrel oil per day from oil sands. All companies are listed on Canadian stock exchanges, therefore have to comply with accounting standards and to publish regular reports. Whenever a currency transfer was necessary, I have used CAD1 = US-$0.94. In this article, I have used the numbers from the company's annual reports for 2013.
The results can be found in the table below:
2013 Suncor Imperial Oil COS Lifting costs 45.23 32.84 59.59 Non-income related taxes 5.64 8.86 4.57 Total cost of sales 50.87 41.7 64.15 Depreciation 16 5.34 12.55 SG&A, R&D 1.28 1.78 1.08 Financial costs 0.89 0.08 1.15 Total costs 69.04 48.9 78.93 Production [kbpd] 392.5 236 98.1 Realized price per barrel 85.88 72.85 93.58
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Watcher says: 01/09/2017 at 3:02 pmJan 11, 2017 | peakoilbarrel.com
SPR Drain - Buy High – Sell Low ?
http://www.zerohedge.com/news/2017-01-09/us-sell-8-million-barrels-oil-strategic-petroleum-reserve
Why? To fund the pumps and stuff that have rusted away.Boomer II says: 01/09/2017 at 5:53 pm
Even if the money is needed for repairs and infrastructure, why sell when prices are low? Why didn't they sell when the prices were high?Watcher says: 01/09/2017 at 6:10 pm
More SPR things:Fernando Leanme says: 01/10/2017 at 9:44 am720 million barrels in the US SPR when full. It's usually not 100% full and when it is (last happened Dec 2009) it's not really full because you can't recover 100% of what you store. Oil gets into pores in the rock and won't come out. Just like less than 100% recovery of oil from an oil field.
The usual calculation is 720 / 20 mbpd US burn = 36 days of consumption storage. With US production at about 8.5 mbpd that number seems to rise to a little less than double - call it 70 days.
But not true. Maximum extraction rate is only 4.4 mbpd (takes 13 days from the word go for the first barrels to enter the system). Not 11.5. So the total embargo of imports scenario because Canada wants to save it for their grandkids means the country goes from 20 mbpd consumption to 12.9 mbpd - for 160ish days (720/4.4) and then just the 8.5 is all we have to function.
Gonna have to compute oil consumption required to haul/deliver food to stores and for people to drive to stores to get it. Tricky for the haulage from central america (fruits).
Salt dome storage caverns don't have pores. They're caverns.Fernando Leanme says: 01/10/2017 at 9:51 am
The Venezuela figure is BS. The reserves outlook gets grimmer by the year, because the current development strategy is incompatible with enhanced recovery. The areas under development are mostly the "sirloin steak" in the Orinoco heavy oil belt, and these high graded areas are now being gutted by pdvsa and partners. They are going after quick kill primary recovery, ruining the reservoirs. This means that not only is the 300 billion barrel figure a poor number, the "real number" is gradually degrading as they continue to lower reservoir pressures and allow water to penetrate the developed reservoirs.Dennis Coyne says: 01/10/2017 at 4:11 pm
Hi Fernando,Based on what you know I think your estimate for URR for Orinoco is about 100 Gb, if I remember correctly, due to the poor development you outline above.
Please correct me if I am remembering incorrectly. Thanks.
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Jan 08, 2017 | peakoilbarrel.com
Ron Patterson says: 01/02/2017 at 1:20 pmSW, just curious but what do you think will cause this turnaround. That is from the current glut to demand outstripping supply. US storage is near its all time high and OECD storage is 300 million barrels above its 5 year average.Javier says: 01/02/2017 at 8:49 pmOECD commercial inventories fell in October for the third month in a row. They have drawn 75 mb since reaching a historical high in July, but remain 300 mb above the five-year average. Product stocks have fallen twice as quickly as crude during that period. Preliminary data show stocks falling further across the OECD in November.
How much confidence do we have on oil storage accounting? According to Art Berman much of it is unaccounted for oil. Looks like a very good way to manipulate oil prices.Ron Patterson says: 01/03/2017 at 7:08 amMy take is that the powers of the world are very much afraid of what a new global recession could do to the shenanigans they have been running at the Central Banks to keep the system from imploding and are very much decided to do everything on their power to prevent a new global recession, and a very important part of it is to keep oil price affordable to prevent the economy from stalling. They cannot control neither production nor demand except by staging a war, but as price is determined by the effect of the production/demand ratio on oil storage, they can control price by rigging the storage reporting. Unaccounted for oil could be the tool to do that.
For most of the world's oil storage, there is no reporting. We have only the USA and a wild ass guess at OECD storage. We have nothing for Eastern Europe, Africa or Asia.Don Westlund says: 01/03/2017 at 12:33 pmWTI jumps up and down a few cents when the US storage figures come out each week, but that's about it. And when that happens the price very quickly reverts to what the actual supply and demand dictates.
If there were actually storage reporting for most of the world's oil, then your conspiracy theory might hold water. But there is not and it does not.
https://www.energyaspects.com/company/events/amrita-sen-ons-2016-conference-appearance?utm_medium=bannerMatt Mushalik says: 01/03/2017 at 3:33 pmThis is a presentation by Amrita Sen at Energy Aspects a few months ago. At the 4:30 minute mark she discusses worldwide crude draws. She is claiming the only place in the world we are getting builds is in the U.S. Not sure where they are getting their information.
Our post was NOT about conspiracy theories. It has number crunching on the statistical fact that there is a huge discrepancy between US crude oil production, imports, exports and refinery intakes.Javier says: 01/04/2017 at 7:28 am8/10/2016
U.S. Storage Filling Up with Unaccounted-For Oil
http://crudeoilpeak.info/u-s-storage-filling-up-with-unaccounted-for-oilMatt,AlexS says: 01/02/2017 at 9:09 pmI know the article said nothing about intentional overreporting of crude oil stocks. It just occurred to me that if intentional it could have a clear effect on oil prices.
Ron,
That USA is the only one reporting crude oil stocks makes it easier to manipulate them, not harder.
Is the following correct?:
How do we know that there is a huge global excess in crude oil?
We know there is some excess from multiple sources, but we only know that there is a large excess from USA reported oil storage.Where is that large excess in USA crude oil storage coming from?
We don't know as 4 out of 5 barrels in USA crude oil storage are from unaccounted-for oil.I think the situation demands an explanation as large unaccounted-for oil is a new phenomenon that started when oil prices were very high.
"OECD storage is 300 million barrels above its 5 year average."SW says: 01/04/2017 at 9:44 amWhen the IEA and all other oil market observers compare current storage levels with 5-year average they miss two important things:
1) Global oil demand continues to increase. Therefore, in relative terms (inventories as % of annual demand) the volume of oil in storage is not as big as if we compare absolute volumes for this year and previous years.
Thus, according to the IEA, global oil demand in 2017 should average 97.51 mb/d. This is 7.94 mb/d higher than in 2011 (89.57 mb/d) and 5.39 mb/d higher than 5-year (2011-2015) average (92.12 mb/d).
7,94 mb/d = 2898 million barrels/year
5.39 mb/d = 1966 million barrels/year
Now compare this with the 300 mbbls surplus in crude inventories vs 5-year average.2) There are two "market buffers" that were always used as a measure of over/under supply in the oil market.
The first are crude and product inventories. They are indeed above 5-year average.
The second is OPEC spare capacity, which is well below historical averages.OPEC output cuts will result in decreasing inventories, but spare capacity will increase.
I was simply commenting on the chart at the top of the post. Perhaps I misread it?
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AlexS says: 01/02/2017 at 11:51 pmJan 08, 2017 | peakoilbarrel.com
I thought it might be useful/amusing to have a look at a decade old IEA forecast (2006) to see how it panned out
I went back to the Oil Drum
http://www.theoildrum.com/story/2006/6/20/231220/551
and had a look at Stuart Staniford´s graphs
Third graph down
Eyeballing the numbers for 2016
Total liquids – a smidgeon under 100 million barrels a day (over by about 4%)
OPEC about 38-39 million barrels a day – spot on
Unconvential about 8 million barrels a day (and no one was talking about LTO then)
It's not IEA (International Energy Agency).AlexS says: 01/03/2017 at 12:16 am
It's EIA (Energy Information Administration) International Energy Outlook, 2006 edition.There is no numbers for each year, particularly for 2016. But we can compare the EIA's projections for 2015 made in 2006 with actual numbers for 2015 from the EIA Short-Term Energy Outlook, Dec. 2016.
I would say that at least the aggregate numbers from a forecast issued 10 years ago look surprisingly good:
World liquids supply in 2015: EIA IEO-2006 projections vs. actual (mb/d)
If we take into account supply outages (particularly, in Libya), which were difficult to predict 10 years ago, and the sharp drop in oil prices, which had a negative impact on non-OPEC output, the EIA's projections made in 2006 look extremely good.Stoney says: 01/03/2017 at 5:25 amI'm sure, projections made by the TOD contributors 10 years ago were much worse.
Especially funny now looks the comment to the last graph in the article:
"Note the bump in historical US production from the late 1970s on is due to the startup of Alaskan production. Apparently, the EIA has found a domestic oil source significantly better than Alaska, and production from it will be starting soon."
We now know that this domestic source was LTO, and actual U.S. total liquids (C+C+NGLs+biofuels) production is even higher than shown in the chart below from
Mr. Staniford's article:US total oil production: EIA IEO 2006 projections
source: http://www.theoildrum.com/story/2006/6/20/231220/551
The EIA forecast from 2006 must also be viewed in light of their price prediction. They assumed oil price would drop again from 60$/b at the time and hover around 50$ until 2030. What would US and world oil production be now if oil price had stayed at 50$?AlexS says: 01/03/2017 at 6:55 amAlso consider the message they were sending the time when there was a supply crunch imminent, seriously threatening the world economy. Move along, nothing to see here, everything will be back to normal.
This was most definitely not competent forecasting.
What supply crunch was imminent in 2006?
There was a temporary decline in demand during the 2008-09 global recession, and subsequent cut in OPEC supply ( >2 mb/d) in order to support prices. But between 2005 and 2015 global petroleum and other liquids supply increased by 11 mb/d. That's less than projected by the EIA, but 11 mb/d increase is not a crunch
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Dec 20, 2016 | peakoilbarrel.com
Roger Blanchard says: 12/17/2016 at 3:18 pmHow accurate are U.S. DOE/EIA Projections?Here are some projections I made in 1999 which are compared to what the EIA projected in 1999.
Author's Projections Peak Prod. Year Peak Prod. (mb/d) 2010 Projected Prod. (mb/d) % Error
Norway 2001 ..3.2 .1.6 +14.4 U.K. 1999 ..2.7 .1.5 -22.0 Sum .. 5.9 .3.1 .0.0 U.S. DOE/EIA's Projections Norway ..2005 .3.9 .3.7 +97.9 U.K. ~2006 3.3 .3.0 ..+143.9 Sum .. 7.2 .6.7 ..+116.1 Actual Production Values From U.S. DOE/EIA Norway ..2001 .3.226 1.87 U.K. .. 1999 .2.684 1.23 Sum .. 5.91 3.1The 2010 values for the US DOE/EIA are based upon an interpolation between the peak projected values and the 2020 projected values
Actual Production data is based upon data from the US DOE/EIA
Mexican Oil Production
In 2003, the U.S. DOE/EIA was projecting that total liquid hydrocarbons production (crude oil + condensate + liquefied petroleum gas + biofuels + refinery gain) for Mexico would rise above 4.2 mb/d by 2010. Specifically, here is what they stated in their International Energy Outlook 2003:
"Mexico is expected to adopt energy policies that will encourage the efficient development of its resource base. Expected production volumes in Mexico exceed 4.2 million barrels per day by the end of the decade and remain near that level through 2025."
It was clear by 2003 that Cantarell complex oil production (crude oil + condensate) would start declining in approximately 2005. Since the Cantarell complex produced about 60% of Mexico's oil production in 2002, it appeared obvious that as Cantarell complex oil production started declining, it would bring down Mexico's oil production as well as its total liquid hydrocarbons production.
Mexico's oil production peaked in 2004 at 3.48 mb/d. By 2010, it was down to 2.62 mb/d, a decline of ~860,000 b/d. In 2010, Mexico's total liquid hydrocarbons production was down to 2.98 mb/d according to US DOE/EIA data. The U.S. DOE/EIA was high by at least 1.22 mb/d for their 2010 Mexican production forecast.
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Dec 11, 2016 | peakoilbarrel.com
Verwimp says: 12/08/2016 at 5:37 pmThese EIA projections are indeed to be taken with a grain of salt, I think. Especially concerning the USA. Why would the production suddenly stabilise? There has been a -10% decrease over the course of the last 1,5 year. (= a severe decline). And now, miraculously, things will stabilise?Guy Minton says: 12/08/2016 at 6:53 pm
I think, over the course of the next 365 days, the USA will lose another million barrels per day of oil production.Wasn't going to be the first one to go that far. Pretty sure we have another half million to go by end of 2017. Including the Gulf. Still, that would be about a million barrels less than EIA is projecting.Javier says: 12/09/2016 at 6:54 amSupposedly the increase in oil price should stabilize US production that has been severely affected by low prices. It remains to be seen if OPEC+Russia cuts (no article on this?) in 2017 realize and if US production can increase to compensate for the cuts. Obviously OPEC+Russia think not or they would not be cutting production, unless it is a fake cut in the first place.
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Dec 11, 2016 | peakoilbarrel.com
Coolreit says: 12/08/2016 at 1:10 amThe EIA oil production forecast for the GOM is a complete fabrication! Here is proof:Guy Minton says: 12/08/2016 at 6:18 amNawar has a list of 2016 new projects that itemize the new GOM projects here:
http://www.investorvillage.com/groups.asp?mb=19176&mn=3794&pt=msg&mid=16582044The new projects list is derived from the leading independent energy analysts, Energy Aspects!
They include three US projects: all GOM:
Heidelberg 80k b/d
Stones 50kb/d
Julia 34k b/dHedelberg forecast directly from the operator forecasts a production rise from ~12k b/d to ~32k b/d by end of 2016:
p6 of their latest presentation:
file:///C:/Users/kopel/Downloads/Anadarko+Jefferies+Presentation.pdf
Stones: From the press release of the startup: " September 6, 2016. Shell announces today that production has started from the Stones development in the Gulf of Mexico. Stones is expected to produce around 50,000 barrels of oil equivalent per day (boe/d) when fully ramped up at the end of 2017
That would suggest a gradual ramp all the way from Sept. 2016 through December 2017. At best a 20% initial flow in September or 10k b/d
Julia: The first well came on line in April and the 2nd one was to start a few weeks later:
ExxonMobil starts up Julia oil field in the deepwater Gulf of Mexico
04/19/2016Offshore staff
IRVING, Texas – Exxon Mobil Corp. has started oil production at the Julia field in the deepwater Gulf of Mexico under budget and ahead of schedule. The first production well is now online and a second well will start production in the coming weeks.
The Julia development is located about 265 mi (426 km) southwest of New Orleans in water depths of more than 7,000 ft (2,134 m). The initial development phase uses subsea tiebacks to the Chevron-operated Jack/St. Malo production facility.
According to ExxonMobil, the development includes the use of subsea pumps that have one of the deepest applications and highest design pressures in the industry to date.
Neil W. Duffin, president of ExxonMobil Development Co., said: "Successful deepwater developments like Julia, located more than 30,000 ft [9,144 m] below the ocean's surface, benefit from ExxonMobil's disciplined project execution capabilities and commitment to developing quality resources using advanced technology.
"This initial production will provide ExxonMobil with insight into the potential future development of the reservoir."
The Maersk Viking drillship is currently drilling a third well, which is expected to come online in early 2017.
So when you consider the start dates and the companies own reports, then there is no evidence of any material GOM oil production growth from the GOM starting October 2016. Furthermore, there is not one 2017 GOM project. So, the EIA forecasting oil production growth of 500k b/d by the end of 2017 is pure fiction. To compound the error, the EIA excludes GOM depletion of what I recall is ~22% depletion in the GOM for 2017 of ~300k b/d (1.5 million b/d of production @20%).
The EIA oil production forecast for the GOM is a complete fabrication!
Thanks, Coolreit! With 15% decline rates, I can't imagine much of an increase, overall.AlexS says: 12/08/2016 at 3:54 amHere is the list of projected deepwater GoM field start-ups from February 18, 2016 issue of Today In EnergyAlexS says: 12/08/2016 at 4:00 am
http://www.eia.gov/todayinenergy/detail.php?id=25012
EIA C+C production projections for the Gulf of Mexico: STEO Dec 2016 vs. STEO January 2016George Kaplan says: 12/08/2016 at 7:36 am
This shows production from the new leases reported to BOEM since 2015, except Hadrian South which is mainly a gas field, but including Julia which EIA missed. Also missing is Gunflint (nameplate 60 kbpd) which hasn't reported any production although supposed to have started in early 2016. Son of Bluto 2 started early and looks to be watering out quickly. Dantzler also cut a lot of water early and is in decline. Silvertip was tied in as part of Great White (Perdido spar). West Boreas and Deimos South are considered part of Mars B (tied into Olympus spar I think) but I can't tell if they are operating (there are two new leases that appear to have started in 2016). Stones only started operating in September. Heidelberg has a very slow ramp up. Julia has two wells on line but is only at half nameplate (I don't know if it is limited by capacity at the Jack hub. As others I don't see where 300 kbpd of new capacity is supposed to come from, especially given high declines in mature deep water fields.George Kaplan says: 12/08/2016 at 7:46 am
I noticed I missed off Big Bend – that started up October last year hit an early plateau and looks to be in slight decline at 16 kbpd at the moment. (note the graph is stacked production, oil only – none of the leases reported condensate).SouthLaGeo says: 12/08/2016 at 7:48 amThanks George,SouthLaGeo says: 12/08/2016 at 8:14 amGunflint is probably identified by BOEM as Freedom/Gunflint – but I don't see any reported production for that either through September.
Julia production is not limited by Jack capacity. Jack capacity is around 170 kbopd, and is currently around 120 (with Jack, St. Malo and Julia).George,George Kaplan says: 12/08/2016 at 9:29 am
I think what you show as Horn Mountain Deep and Holstein Deep are actually just the base production from those fields. I don't think either Horn Mountain Deep or Holstein Deep are on production yet - I think.Agreed probably – the numbers are given by lease number only. Sometimes there can be more than one well to a lease (they give the number of completions so sometimes you can see when something starts up then), but additional complications are that BOEM sometimes use different names from the E&P company, and there are often several leases per field. Tie backs, even if given a particular name, are listed against the main filed only. I think there is a way to apportion production to particular wells and from there to a particular tie-back, but it's beyond may attention span at the moment. I was more interested in the overall shape of the curve – which shows a clear flattening. Horn Mountain Depp added two completions in March/April, I need to check further on Holstein, I might have screwed up there as the curve looks suspiciously similar to Horn Mountain Deep. I think there probably is another 150 kbpd ramp up nameplate capacity between Gunflint, Stones, Heidelberg and Julia and maybe 50000 extra tiebacks if they are drilled – but that would only just about cover decline over the next 15 to 18 months.AlexS says: 12/08/2016 at 8:25 amIt's also interesting that, though now in decline, Dantzler and Big Bend initially exceeded expected production capacity, and still do.
Another correction: Son of Bluto 2 didn't cut a lot of water, I looked at the wrong column, so I don't know why it declined so fast. I think it may have capacity for a second well there.
Interesting, that, in the Annual Energy Outlook 2016, the EIA projects further growth in the U.S. Federal offshore (ex Alaska) oil production to 1.93 mb/d in 2021.Guy M says: 12/08/2016 at 9:58 amGiven high decline rates for deepwater fields, that implies new start-ups or ramp-ups.
One of these projects is BP's Mad Dog Phase 2 . Is there anything else?
Mad Dog Phase 2 is expected to start drilling in 2021. There is no explanation for why EIA is reporting increased production, as they are.SouthLaGeo says: 12/08/2016 at 1:10 pmThe additional ones I can think of are Stampede and Big Foot, both in 2018, and Shell's Appomattox, but I don't know when that is slated to come online.AlexS says: 12/08/2016 at 1:44 pm
In addition, there will be a fair number of 1-3 well tiebacks to existing facilities. (Maybe 3-4 a year??)Guy M, SouthLaGeo,George Kaplan says: 12/08/2016 at 2:26 pmThanks
There are Thunder Horse South tie backs next year (BP, nameplate maybe 42,000 bpd), Heidelberg Phase II might add another 30,000 in 2021, small tie backs to Delta House (Odd Job next year at 5000, maybe others), Vita (c/w Power Nap) has gone out for FEED but I don't think it could get done before 2022 now, possibly Caesar/Tonga additions next year (20,000 ??), and I think Typhoon (or might be called Tornado now) might have started up recently at 13,000 tie back to Helix producer.George Kaplan says: 12/08/2016 at 3:07 pmSo I corrected Holstein Deep (I don't think there have been any new tie ins and it is in gradual decline), added Big Bend, Gunflint (though it is zero flow) and Pheonix (no change in the dates shown but Tornado has started up at 20 kbpd this month and will be choked to 13 to 16 kbpd at plateau (this used to be Typhoon I think, but all these names are quite confusing) there are other tie-back options for Phoenix, which is serviced by the Helix producer, in the future, including a second Tornado well and Motormouth.AlexS says: 12/08/2016 at 5:43 pmThe plateau through 2016 is maintained but I think there will be a jump in October and then a steady rise at least for a few months. I don't know the issue with Gunflint but if it has a lot of predrilled wells and is just waiting on getting the production facilities operating there could be another big increase then.
Also I had a thought on Julia and Horn Mountain Deep: it's possible that the completions listed by BOEM include producer and injector pairs so at the moment Julia has only one producer, but two wells, and therefore with another producer to come to give full capacity (at up to 35 kbpd).
Thanks George,George Kaplan says: 12/08/2016 at 7:26 pmDo you still think that the EIA's projections for the GoM are unrealistic?
If so, is that because of depleted resource base, or likely project delays, high costs, etc.?
Alex – I don't think there will be as high a peak as they say – I don't see where the projects ramping up or in late development stages are that could achieve that (I still go for around 1.85 mmbpd sometime in mid 2017 as peak). But equally the decline might be less steep than they show and the tail fatter. Two other projects not yet approved are Shenandoah and Kaskida. I think they would both be about 150 kbpd nameplate, but they are high temperature / high pressure and Kaskida has sand issues I think (maybe they both do), and both might need relatively many wells – so very expensive. There's also Tiber / Gila / Gibson / Guadelupe (I don't know much about that but over 100 kbpd), Anchor (also about 100 kbpd), some fields around Tahiti for tie backs and Constellation (ex-Hopkins) which used to be considered a big find with BP but know looks like a smaller tie back (30 kbpd maybe) for Anadarko. After those only bits and pieces are left, and with not much frontier exploration going on so little prospect of big finds either. Anadarko and BP have a lot of the prospects which would tend to mean they'll get spread out a bit. I've also been surprised at how long the schedules are for Appomatox and Mad Dog II (and also Trion on the Mexican side) they all are around 7 years from FID to plateau rates.
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Oct 07, 2016 | oilprice.com
U.S. crude oil storage is filling up with unaccounted-for oil. There is a lot more oil in storage than the amount that can be accounted for by domestic production and imports.That's a big problem since oil prices move up or down based on the U.S. crude oil storage report . Oil stocks in inventory represent surplus supply. Increasing or decreasing inventory levels generally push prices lower or higher because they indicate trends toward longer term over-supply or under-supply.
Why Inventories Matter
Inventory levels have reached record highs since the oil-price collapse in 2014. This surplus supply is a major factor keeping oil prices low.
Current inventories are 45 million barrels higher than 2015 levels, which were more than 100 million barrels higher than the average from 2010 through 2014 (Figure 1). Until the present surplus is reduced by almost 150 million barrels down to the 2010-2014 average, there is little technical possibility of a sustained oil-price recovery.
(Click to enlarge)
Figure 1. U.S. Crude Inventories Are ~150 Million Barrels Above Average Levels. Source: EIA, Crude Oil Peak and Labyrinth Consulting Services, Inc.
U.S. inventories are critical because stock levels are published every week by the U.S. EIA (Energy Information Administration). The IEA (International Energy Agency) publishes OECD inventories, but that data is only published monthly and it measures liquids but not crude oil. It also largely parallels U.S. stock levels that account for almost half of its volume. Inventories for the rest of the world are more speculative.
Understanding U.S. Stock Levels
Understanding U.S. stock levels should be straight-forward. Every Wednesday, EIA publishes the Weekly Petroleum Status Report which includes a table similar to Figure 2.
Figure 2. EIA publishes adjustments and defines them as "Unaccounted-for Oil." Source: EIA U.S. Petroleum Status Weekly (Week Ending September 16, 2016), Crude Oil Peak and Labyrinth Consulting Services, Inc.
The calculation to determine the expected weekly stock change is fairly simple:
Stock Change = Domestic Production + Net Imports – Crude Oil Input to Refineries
Domestic production and net imports account for crude oil supply, and refinery inputs account for the volume of oil that is refined into petroleum products. If there is a surplus, it should show up as an addition to inventory and a deficit, as a withdrawal from inventory.
But that's not how it works because EIA uses an adjustment in order to balance the books (Table 1).
Table 1. Calculation of Crude Oil Stock Change. Source: EIA Petroleum Status Weekly, Crude Oil Peak and Labyrinth Consulting Services, Inc.
The logic is that estimated stock levels in tank farms and underground storage are relatively dependable and that any imbalance must be from less reliable production, net import or refinery intake data.
Related: Nigerian Oil Anxieties Mount, Even With OPEC Exemption
There is nothing wrong with adjustment factors if they are small in comparison to what is to be balanced. In the Table 1 example from September 2016, however, the adjustment is 60 percent of the stock change–a bit too much.
A one-off perhaps? No, it's a permanent problem that has gotten worse during the last several years.
Figure 3 shows that crude oil supply and refinery intake of oil vary considerably on a weekly basis. The balance is cumulatively negative over time beginning with a zero balance in January 1983. That suggests that crude oil stocks should be falling over time but instead, they have been rising.
(Click to enlarge)
Figure 3. Difference between U.S. crude oil supply and refinery intake. Source: EIA Petroleum Status Weekly.
The vertical bars show the weekly crude supply from production and net imports either exceeding the refinery input requirements (positive, green) or not reaching these requirements (negative, red). The solid red line is the cumulative.
Between 1991 and 2002, the deficit increased to a whopping 1.3 billion barrels.
Looking at only recent history, an additional gap of nearly 200 million barrels developed as refinery intake exceeded crude oil supply for most of 2010 through 2014 (Figure 4).
(Click to enlarge)
Adjustments were introduced in late 2001 so let's look at the period starting January 2002 (Figure 5).
(Click to enlarge)
Figure 5. EIA adjustments to supply to reconcile stock changes. Source: EIA Petroleum Status Weekly, Crude Oil Peak and Labyrinth Consulting Services, Inc.
There are both upward (blue) and downward (red) adjustments. Upward adjustments resulted in a 420-million-barrel stock increase over the period January 2002 through September 2016.
All together now
Expected or implied stock changes calculated from weekly crude oil balance indicate falling inventories from May 2009 through the present. Yet, EIA makes adjustments to that balance in order to match observed inventory levels. Rising inventories result after those adjustments are added to the physical balance or implied stock changes (Figure 6).
(Click to enlarge)
Figure 6. Unaccounted-for oil in U.S. storage: the result of adjustments to the supply balance. Source: EIA Petroleum Status Weekly, Crude Oil Peak and Labyrinth Consulting Services, Inc.
The green area represents the physical balance (crude production plus net crude imports minus crude refinery intake). The gray area shows the unaccounted-for (adjusted) stocks.
The adjustment for unaccounted-for oil averaged about 15 percent from 2002 through 2010. In 2016, almost 80 percent of reported stocks are from unaccounted-for oil.
When You Have Eliminated The Impossible
There is no obvious solution for the mystery of unaccounted-for oil in U.S. inventories. Possible explanations, however, include:
1. Crude field production is underestimated
2. Net crude oil imports are underestimated
3. Refinery inputs are over-reported
4. Crude oil stocks are over-reportedor any combination of those possibilities.
Production, imports and refinery inputs are taxable transactions. It is likely that reporting errors are largely self-correcting over time because of the financial incentive for government to collect its due.
State regulatory agencies are the source of production data. Their principal objective is to assess production taxes. It is unlikely that states would consistently under-estimate production and forego substantial tax revenue.
Related: Is Russia Diversifying Away From Oil Fast Enough?
Also, producers must state crude oil production in their SEC (U.S. Securities and Exchange Commission) filings and pay federal income tax on revenues from oil sales. It seems improbable that the SEC and U.S. Treasury would consistently accept under-reported production and associated lower tax payments.
Crude oil imports are subject to both tariffs and excise taxes so it seems unlikely that the U.S. government would consistently fail to identify under-payment of those revenues.
Similarly, taxes are involved when refiners buy crude oil and sell refined products. It seems improbable that they would over-state those transactions and consistently over-pay associated taxes.
The principal components of supply balance-production, imports and refinery intake-are shown in Figure 7. In a general way, increased production and decreased imports tend to cancel each other out. Refinery intake has increased since about 2010.
Those trends determine the physical balance or implied stocks. The inescapable conclusion is that implied stocks (in light blue) are substantially less than reported stocks (in gray).
Adjustments for unaccounted-for oil are unreasonable and out of proportion to the underlying factors that determine crude oil stock levels.
(Click to enlarge)
Figure 7. Components of unaccounted-for oil in U.S. storage. Source: EIA Petroleum Status Weekly, Crude Oil Peak and Labyrinth Consulting Services, Inc.
It would be speculation to blame anyone for this apparent statistical disaster. Nevertheless, there is a problem that has major implications for oil price and the reliability of reported data.
In several of his Sherlock Holmes mystery stories, Arthur Conan-Doyle wrote, "When you have eliminated the impossible, whatever remains, however improbable, must be the truth."
We have not eliminated any impossible explanations. We have, however, eliminated the three most improbable explanations for unaccounted-for oil.
The truth-however improbable-is that inventories are probably much lower than what is reported.
By Art Berman for Oilprice.com
Lotanna on October 11 2016 said:
This does not appear good. Those reports have been driving oil price speculations for over a decade. If this is true, then the US has been gradually influencing the oil price dynamics unethically. I hope stock traders read this. The world would not be happy with the US. But then again, I expect them to point the fingers at one individual, jail him and find a new strategy to play the same game [I believe Strategic Petroleum Reserve was the last try].JACK MA on October 12 2016 said:In 2015, 800,000 BPD went missing. This was faked oversupply to drive down prices and collapse Russia. The last time this much oil was missing was 22 years ago as a ploy to collapse Russia on low oil prices and back then it worked. This time, Russia simply allied with China.Edwards on October 12 2016 said:
There is no oversupply of oil and any slight surplus that did exist in now in China's reserves on the cheap. Kerry really goofed when trying a old play-book to collapse Russia by ordering SA to flood the markets. What we will now see in 2 years is a 'absolute price shock up' on real billions in cap x cuts due to the fake oversupply driving down real prices.
This is the oil super cycle driven by the petro-dollar collapse and Dedollarization by Russia and the BRICS. Globalization is failing obviously as is the dollar. Problem is we cannot simply bomb Russia and China so easily like the ME, as these two super powers will actually shoot back and the Western war-hawks are not used to a real enemy that shoots back.Warmest regards to all, and do your own homework and seek the truth.
Must be the result of common core math, so confusing that even experts can't figure it out. What about the 6.5 TRILLION bucks that is unaccounted for at the pentagon. The last time 2.3 TYRILLION was unaccounted for we had 9/11 the next day. Is this an omen for something big to happen imminently?Ward on October 13 2016 said:What a conclusion - the 450MM barrels are not in inventory. Give me a break - ofc the physical inventory is there. Physical inventory is most reliable and verifiable parameter n calculation. You can stick a tank to know how much is in it.James Rose on October 17 2016 said:EIA (aka Obama)started underestimating "reported" production around 2011 according to figure 6. That's when the big changes start.
Big assumption in article is that crude production as as estimated from taxes and EIA report are in-sync. Seems like reasonable assumption but there's no evidence in article that is the case. They can still get their taxes and EIA under reports the production because no one sync's up the EIA data with tax data.
Its more plausible to believe the SPR is being sold into the commercial storage than that the EIA is faking reports. The reason is the if the EIA is faking reports, they've got to deputize the API to fake their reports as well. They're different, but not this different.
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Sep 12, 2016 | peakoilbarrel.com
If, as the IEA believes, oil prices average about $55/bbl in 2015 and not reach $73 until 2020, a lot of assumptions will have to be modified: Because, these prices are clearly well below those needed to justify investment in and exploitation of expensive-oil options like tar sands and Arctic oil.It seems to me as if a new reality is being signaled by the many recently stalled or cancelled mega-projects. For example, Shell has abandoned plans for a huge petrochemical plant in Qatar; Chevron shelved its plan to drill in the Beaufort; and, Statoil has turned its back on Greenland. If Majors are moving away from expensive future projects it's probably because they doubt their viability, not because they can't raise the cash.
And committing to mega-projects is committing to a predictable future. Could it be that Big Oil has decided the next decade contains too many unknowns: AGW issues, upsurge in renewables, a mega recession, you name it? Or, maybe they've just discovered Ron's Blog?<
Coolreit , 03/16/2015 at 11:58 amRon:Watcher , 03/16/2015 at 12:03 pmThe EIA lies. Your posts comparing Texas oil production vs. the EIA's report of Texas oil production highlights the growing lies from the EIA. Each month the EIA adds roughly 50k/b/d for at least the last 12 months. How can that be? Texas has been dropping rigs almost as fast as North Dakota. Their production has surely been dropping now and quite probably since January.
The EIA and IEA work for banksters trying to destroy the oil industry so they can buy it up cheap . Next month, Goldman Sacks is starting a distressed energy bond fund. How convenient that they and the media and the EIA and IEA paint a bearish picture of oil fundamentals now.
"Next month, Goldman Sacks is starting a distressed energy bond fund. "Coolreit , 03/16/2015 at 12:29 pmWhere did you get this?
http://www.nytimes.com/2015/02/25/business/dealbook/goldman-seeks-to-raise-fund-to-buy-energy-sector-debt.html?_r=0Watcher , 03/16/2015 at 12:46 pmThat's a good find. It looks like it adds up (among Goldman, Blackstone and others) to about $25 Billion and the word is energy, not shale. The Goldman offering is not all junk bonds, either.SRSrocco , 03/16/2015 at 12:07 pmThis doesn't look like the required bailout, but it's definitely money risked - maybe with people like Transocean.
EVERYONE,Petro , 03/16/2015 at 12:41 pmA Bit off topic, but thought I would share the newest interview on the Russia-Ukraine-USA-Europe situation by John Bachelor and Prof. Stephen Cohen. Normally, Prof. Cohen does a weekly interview, but was off for 10 days as he and another U.S. Professor, experts on Russia, spoke to a large group of German Bankers last week on the subject of Russia & the Ukraine.
http://www.tfmetalsreport.com/podcast/6679/batchelor-cohen-return
…indeed Steve,BC , 03/16/2015 at 7:45 pm
sadly!Listen to what a former joint chiefs of staff member, a major general- a true and utter moron, really and actually- said a few days ago:
https://www.youtube.com/watch?v=b6Nnn8S1XbESadly, he and people akin to him lead this country now…
That is the real reason I commented (in response to Dennis and Mac) in an earlier post that there will be no market for oil or anything in 2030-2050.
Oil is falling again and when, this time, what was drilled and put on line BEFORE oil reached $50-$60 peaks and starts the 40%-80% per year decline rate shale oil well "army", the morons like the general in the video will gain ground…and then power….and then russians (or chinesse, or anybody) and Putin shall be the "devil" that crushed our economy….and the false flag type of events whe marines are floating drowned in blood killed by the "evil Putin" soldiers are going to make the fat moronic masses "patriotic"…and then, the 99.99% brainwashed, fat moronic herd who think that our soldiers are fighting for our freedom will "volunteer" to go to war and defeat the ennemy.
As alwayz, they shall be blissfully ignorant of the fact that "the ennemy" this time has more nucelarweapons than us and we all shall lose.
It is an unwineable war!
And us few who say otherwise shall be the unpatriotic "spies" who must be eleminated…because "generals" like the one in the video and crowds who dump vodka on the streets (like they did with french wine in 2003 when french refused to join bush-chenney in irak) will take over.
The everlasting historic lesson:
"when all fails, govt takes you to war!"
Even your beloved gold and silver shall not save us this time….pray.The next few yoars seem to be very "interesting"
Be well and hedge accordingly!Petro
P.S.: great article Ron! Thank you for updating us.
Steve,Caelan MacIntyre , 03/17/2015 at 8:11 pmUS real after-tax income less debt service ("rentier taxes") and "illth" care (a.k.a. as "dis-ease" or "health" care) spending peaked YoY in Q1-Q2 '14 and rapidly decelerated and contracted YoY in Q3-Q4 '14.
Moreover, the oil and gas extraction and energy-related transport sectors have heavily skewed higher capital goods orders, business sales, and industrial production (IP) since 2011-12 to an unsustainable cyclical rate.
It's not surprising, therefore, that retail sales, business sales, orders, nominal real hourly earnings, and IP/IP mfg. have been falling since last summer-fall, the point at which the price of oil began crashing. This is the stuff of cyclical business cycle contractions.
And the point, Mr. BC, one might ask? The powers that be (TPTB) are keenly aware of the foregoing and know that the US economy is decelerating rapidly in response to the deflating of the shale bubble, weather and port and refinery labor strikes notwithstanding, along with the rest of the world economy. The current cyclical trajectory is not unlike that which occurred in summer 2001 (prior to 9/11) and winter-spring 2008, both instances coinciding with the US economy having already rolled over into recession.
Thus, the US is due yet another imperial war cycle in order to goose the goods-producing sector (especially the "defense" sector) in response to recession, which in turn will justify increasing fiscal deficits, maintenance of ZIRP/NIRP, and a resumption of the Fed's QEternity/QEn+1 later in the year.
IOW, economics is politics. Politics is war by other means. The business of empire is war. War is good business for imperialists. Ergo, economics is politics is war is the business of empire, and the owners and financial facilitators, i.e., Wall St. and The City, of Anglo-American-Zionist empire need another regional (or eventual world) war for business, geopolitical (say again imperial business), and domestic social control purposes.
Wall St., DC, the Saudi royals, Bibi and his thugs, and the US-UK war profiteers are maneuvering to release yet again the ravenous hounds of war for profits and power against "Radical Islam", Putin's Russia, and, if history and human nature are a guide, eventually a regional war (or Cold War- or cyberwar) in the Pacific against China.
This begs the question of what kind of "Pearl Harbor-like" event will be required this time to compel the unsuspecting American and western public to support (tacitly acquiesce to) the next phase of the never-ending war for Anglo-American-Zionist, rentier oil empire (in the post-growth, LTG era)?
Same as it ever was . . .
Parable of The Violent Tribe …Longtimber , 03/17/2015 at 1:45 pmThis is a 46 second-long video worth watching and/as it seems to put a cherry on top of BC's good comment.
Same program from JB podcast 3/10/15DuaneX , 03/17/2015 at 6:51 pm
http://johnbatchelorshow.com/podcasts/tues-31015-hr-2-jbs-stephen-f-cohen-nyu-princeton-professor-emeritus-author-soviet-fates
Don't hear about American misinformation or complete loss of confidence of american foreign policy in the MSM. West drives Putin into a corner, extremely dangerous situation.Along these lines, I found these words from Malcolm Fraser Ozzie PM '75-'83 interesting:PeakOil NOT , 03/16/2015 at 12:57 pmhere's one paragraph snip:
As painful as a reassessment of relations may be for intellectual and policy elites, there are four principal reasons why one is long overdue. First, despite much blather about a supposed unanimity of national purpose, the truth is that the United States and Australia have substantially different values systems. The idea of American exceptionalism is contrary to Australia's sense of egalitarianism. Second, we have seen the United States act in an arbitrary, imprudent and capricious fashion. It has made a number of ill-advised and ill-informed decisions concerning Eastern Europe, Russia and the Middle East. Third, at the moment, because of U.S. military installations in Australia, if America goes to war in the Pacific, it will take us to war as well-without an independent decision by Australia. Finally, under current circumstances, in any major contest in the Pacific, our relationship with America would make us a strategic target for America's enemies. It is not in Australia's interest to be in that position.
http://nationalinterest.org/feature/america-australias-dangerous-ally-11858
EIA production numbers include NGLs, Texas RRC numbers do not. Texas RRC acknowledges as much on their website:Watcher , 03/16/2015 at 1:05 pmThe production data in PDQ doesn't match the data I get from the federal Energy Information Administration. Can you explain the difference?
The Railroad Commission of Texas' crude oil production data reflects only crude oil produced from oil leases as reported by operators. The Commission's data does not include condensate, which are liquid hydrocarbons produced from a gas well. Our data comes directly from production reports filed by operators.
Who is "our"?PeakOil NOT , 03/16/2015 at 1:20 pmTexas RRC.Marcus , 03/16/2015 at 4:52 pmThere are other issues as well. (Producers not reporting, Reporting late, etc.
The website is very helpful.
PeakOil NOT does this mean you represent or are somehow affiliated to the Texas RRC?Futilitist , 03/16/2015 at 11:12 pmHi PeakOil NOT.Danlxyz , 03/18/2015 at 5:35 pmNice screen name. What made you choose it?
Peak Oil NOT,Dennis Coyne , 03/18/2015 at 6:01 pm
I agree that this web site reports only C+C unless otherwise noted. It is Ron's site and that is what he wants to report. I appreciate the effort he puts in especially the graphs.
But total liquids would seem to give a better picture of supply and production changes. After all NGLs, refinery gain, and the other differences are part of mix which make the economy produce.Hi Danlxyz,Caelan MacIntyre , 03/16/2015 at 1:19 pmOne problem with total liquids is that it is not adjusted for energy content. The typical barrel of NGL contains only 65% of the energy of crude, same is true of ethanol. So total liquids adjusted to barrels of oil equivalent is useful, also some NGL is not really used for energy (ethane is used mostly as an industrial input in plastic and cryogenic processes, rather than burned for energy). This is more work than just using C+C data. Also we can use BP data in tonnes of oil to estimate barrels f oil equivalent.
a carryover thank you …toolpush , 03/16/2015 at 6:32 pm
It read as a sort of age-targeted unemployed-wage-slave flyer/ad for the unsustainable North Dakota shale/fracking industry, complete with age, income, corrupted values, etc..
And much more in the crony-capitalist plutarchy global industrial uneconomic monster– which farts in our general direction, Gerd– and that we just can't help feeding… with our children, alive (like those two in question if they are real or part of the monster, or both), as well as with our values, future, and planet.Pushpush, toolpusher. Make 'er scream. We know abuse when we see it .
Hey Ron,Throbbing Orville Reddenbudders , 03/16/2015 at 10:27 pmAny chance of an ignore button?
That way it would avoid a lot of knee replies one is temped to write."I mix with professional people and and I know i have earnt up to double their pay scale…" ~ toolpusher
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StuckinWalkerWorld , 03/17/2015 at 10:48 amSep 12, 2016 | peakoilbarrel.com
Ron, Is it possible the EIA is intentionally trying to push oil prices down for political reasons? But has to do some back-peddling in order to try to save face and retain some credibility. EIA must fully understand how oil prices react to what they are saying. They are also a government agency there for can be used for political purposes. Do you notice a trend of misinformation coming from the EIA? Have you ever in the past noticed a trend of misinformation where maybe the incorrect numbers coming from the EIA actually pushed prices up instead of down over any given period of time?
The effects of the price collapse is beginning to take a serious bite out of Canadian tar sands exploration and extraction activity. Last week's rig count in Canada dropped by 80, according to the most recent Baker Hughes report. Imports from Canada have declined slightly in the last month, though they are still quite high. And there's the news brief (Note link to original article is broken).Watcher , 03/17/2015 at 10:56 amhttp://ieefa.org/1000-layoffs-overnight-by-tar-sands-developer
Pretty sure spring thaw is the seasonally normal time for canadian oil rig decline.Doug Leighton , 03/17/2015 at 11:16 am
Correct. Spring breakup = mud and road restrictions up here. When Western Canada thaws dirt roads/drill sites become soupy messes, drill rigs stop. Affects truck logging and mining exploration as well.Ron Patterson , 03/17/2015 at 11:24 am
Nevertheless the Canadian rig count during this same week last year stood at 522. It now stands at 220, a drop of 302 rigs, season point last year to same season point this year.Watcher , 03/17/2015 at 12:35 pm
Now that's more meaningful.Ron Patterson , 03/17/2015 at 11:15 am
Sawdust, No, I don't think the EIA is being dishonest for political reasons. Who's politics would that favor? I think they are honest and looking at their algorithm and just reporting the data is spits out. Art Berman puts it this way:Watcher , 03/17/2015 at 11:43 amEIA and IEA ultimately get their U.S. production data from the states. State reporting on oil production is lagged by at least 3 months and it takes another month or two for adjustments to be included. IEA and EIA use sampling methods of certain large producers that are then put into algorithms to approximate recent production. So, what we get from these organizations is a pretty good guess that will be revised later.
Their algorithm just gave them some bum production numbers. That's really all I think that happened. But when they saw those numbers from North Dakota they realized they had really screwed up and began to backtrack. They may very well be backtracking further however.
Ya pretty much that. If you've spent time in DC you've spent time on the Metro and it's filled in the morning with guys who got up, looked in the mirror, shaved, and went to work. They don't do that every day to make it their job to lie.Doug Leighton , 03/17/2015 at 11:52 amErrors can be systemic. They can be using a source that no longer is valid. The measurement itself may no longer matter - like the newly famous sales by refinery affiliated retail outlets. Those outlets were sold off. The number remaining is few. So retail sales of gasoline appears to have crashed. Doesn't measure the same thing anymore.
This sort of thing is likely underway with Jeffrey's API focus, and there WAS that article I posted here from the WSJ announcing a redefinition of WTI.
Back when night baseball became prominent in the late 1960s (first night game in the 30s, but prominence took time) to generate ticket sales from people who could not take off work, a recognition of pitched balls being harder to see under lights than natural sunlight led to a lowering of the mound. Baseball's org watched as pitchers became more and more dominant (1968 was "the year of the pitcher") and so they made that choice for 1969. All to make the game's historical stats still comparable (and to keep fans happy, who preferred home runs to shutouts).
The redefinition of WTI will specifically make historical stats NOT comparable, but unlike with baseball, that is going to be desirable. As will be an appearance of steady growth, the home run of oil.
Watcher, you're being strangely rational today (or, at the moment). Should we be worried?Watcher , 03/17/2015 at 12:33 pm
Making peace with our Maker. We'll all be dead soon in the die-off.Doug Leighton , 03/17/2015 at 12:44 pm
Figured it would pass; I'm breathing MUCH easier now.Watcher , 03/17/2015 at 12:55 pm
Oh don't be too glib. Lowering the mound doesn't kill people.Sam Taylor , 03/17/2015 at 12:26 pmClaiming you got BTUs you don't got will start wars.
Ron,Ron Patterson , 03/17/2015 at 12:40 pmJust how much influence does a single EIA report actually have on the direction of oil markets? I find it difficult to believe that a single report from them which might be slightly over-optimistic, could start the market in London dropping as well as New York.
Your correct, a single report, that is the Weekly Petroleum Status Report could not have that much influence. However two other EIA monthly reports gave similar bullish assessments. They were thee Short Term Energy Outlook and the Drilling Productivity ReportDennis Coyne , 03/17/2015 at 3:29 pmThen to top those three EIA reports the IEA chimed in with an even more bullish report for oil, (but bearish for prices of course). The IEA Oil Market Report .
Global supply rose by 1.3 mb/d year-on-year to an estimated 94 mb/d in February, led by a 1.4 mb/d gain in non-OPEC. Declines in the US rig count have yet to dent North American output growth. Final December and preliminary 1Q15 data show higher-than-expected US crude supply, raising the 2015 North American outlook.
Got that, non-OPEC up by 1.4 million barrels per day in February and the declining rig count is yet to dent North American output growth. That was enough to drive prices in the dirt.
Hi Ron,Jeffrey J. Brown , 03/17/2015 at 3:39 pmSeveral people, Art Berman, Steve Kopits, and Jeffrey Brown are expecting that oil prices should rebound by years end at minimum. I agree with that assessment.
Impossible to say with any confidence when prices will rise or by how much, but I still like $75/b or more before Sept 30, 2015.
Looks like my guess that oil had reached a bottom in Jan 2015 was not right, it looked good for a month and a half. It will be interesting to see if it breaks through $40/b, I doubt it, but some experts have mentioned $38/b. If we adjust the Dec 2008 bottom for inflation we get $33.65/b for the lowest price since 2003. There would be some serious resistance to oil prices less than $33/b.
In 2008 the bottom was about $30/b in nominal terms and the oil price closed below $35/b for only 4 trading days, by March 2009 the oil price was back to $45/b and by June it was up to $70/b.
Hard to say what will happen this time, but OPEC is predicting that demand will be robust, so we may see prices behave somewhat like 2009. Even without cuts by OPEC, the World economy is in much better shape in 2015, than it was in 2009, so oil demand should be higher.
For the current oil price decline, the monthly low (so far) for Brent was $48 in January. I don't think that there's any real chance that March will average below $48, since the average for the first half of March was in the high 50's.toolpush , 03/17/2015 at 9:55 pmMonthly price data for six month after the $40 monthly Brent low during the 2008/2009 decline:
12/08: $40
1/09: $43
2/09: $43
3/09: $47
4/09: $50
5/09: $57
6/09: $69
Ron,Ron Patterson , 03/17/2015 at 10:29 pmOn the Permian page, there seems to be an extremely sharp upturn in the Permian's productively, Around about 20% increase in a couple of months. Not sure if it because they are saying all the rigs that have shut down, contributed very little to production, or what? Maybe a little fudge factor to catch up on past errors?
Without that upturn, I believe their minor increase in production would be a negative number.
Toolpush, that has to be an error in their chart. If you go here:toolpush , 03/17/2015 at 11:03 pmThen click on: X Report data (aggregated by region)
That will download the Excel spreadsheet for all regions. Then you can go to the Permian page and get the data through April. Of course the last four months is just their guess as to what the Permian will produce but the data they do show shows a very sharp downturn in the last two months.
The data below is their predicted barrels per day. The chart below is the actual increase in barrels per day they are predicting.
Permian
Dec-14 1,845,634
Jan-15 1,888,536
Feb-15 1,929,450
Mar-15 1,960,259
Apr-15 1,981,512
Ron,Ron Patterson , 03/18/2015 at 7:19 amThis was on productivity per well.
The top left chart. Brown line going from around 400 bpd per well to nearly 500 bpd per well?
Well there is no data to support that. In fact there is no data at all for April because April and in fact there is no data for March. Why they would make such a wild speculation is beyond me. But this is a prediction that is beyond reason. Productivity per well could not possibly change that fast.Dennis Coyne , 03/18/2015 at 8:09 am
Hi Ron,Dennis Coyne , 03/19/2015 at 7:57 amIt may be that if a lot fewer vertical wells are completed that productivity per rig will increase. The horizontal wells in the Permian are far more productive (on a per well basis) than the vertical wells.
The EIA may be accounting for the rising percentage of horizontal rigs which will increase the productivity per rig.
I agree that this change is unlikely to happen as quickly as shown in the DPR, which was your main point.
Hi toolpush,toolpush , 03/19/2015 at 8:19 amI think you read the chart wrong, the rig productivity is on the left vertical axis and the rig count is on the right. The increase was from 202 b/d/rig in March to 240 b/d/rig in April.
This could easily be explained by the higher percentage of horizontal rigs now running in the Permian due to a lot of the vertical rigs being stacked there.
Dennis,Dennis Coyne , 03/19/2015 at 4:38 pmI stand corrected, and thanks for checking it out, but the change in slope is the stand out thing. What ever the numbers you are looking at approx 20% increase in productivity in one or two months.
It is either due to a heap of low productive vertical rigs being stacked, or a statistical error.
I believe we will just have to watch out for it next month, to see if there is any change? Though I believe this little uptick conveniently keeps the oil supply estimate in the positive side of the page. smiles
Hi Toolpush,Futilitist , 03/17/2015 at 11:39 pmYes it is a 20% increase either way, in the Bakken it seems that rig efficiency has been increasing and in the Permian the rigs are being stacked faster so the percentage of horizontal to vertical rigs has increased a lot. Currently about 71% of Permian rigs are horizontal rigs, at the rig high point it was about 62% horizontal rigs, so we have fewer vertical rigs which would tend to increase output per rig and in this price environment they may be focusing on sweet spots so that the wells that are fracked have a better chance at positive cash flow.
Hi Ron,Kam , 03/18/2015 at 6:30 am"Their algorithm just gave them some bum production numbers."
That is because their algorithms don't work any more. Not since the aggregate cost of oil production overtook our civilization's ability to pay the full cost of that production. This occurred around June of 2014. The EIA seems to be as surprised as everyone else (except me). Here is how they put it:
Steep drops in the US rig count have been a key driver of the price rebound. Yet US supply so far shows precious little sign of slowing down. Quite to the contrary, it continues to defy expectations.
Meaning that production is just not falling fast enough to raise oil prices sufficiently enough to ensure continuing oil production. This is not a temporary condition. There is simply no way to fix the problem. We have experienced a paradigm shift.
The oil industry has begun shutting down .
The cost of production continues to rise. And we don't seem to be getting richer. If the industry needs $100+ oil to maintain current production and bring on future production, then any price lower than $100 will result in the oil industry shrinking.
How could it be otherwise?
Coal industry has also started shutting down. And coal is the second source of energy for world economy. It will be fast now. Party's over (Heinberg was 12 years earlyFutilitist , 03/18/2015 at 6:50 am
Hi Kam.Kam , 03/18/2015 at 5:04 pmI did some research on the ETP model you pointed me to. It turns out that I haven't been the only person to point out what the giant wedge pattern in the price of oil meant:
"Oil prices are plunging. According to my opinion (and it seems that your theory says so), this is because now we cannot afford a functioning economy at 100 USD per barrel of oil . From now on, any price collapse will lead to the destruction of supply; and a price hike will destroy the demand (And I think that as time passes by, the ceiling at which the demand will be destroyed will only go down). It seems that both factors (supply destruction and demand destruction) have met in the graph and we just hit a collision point …"
~ Observerbrb at peakoil.comHe even made a graph just like mine!
And here is the answer to his question from one of the originators of the ETP model:
"You're right!"
~shortonoilWow. So my cute little independently arrived at theory has also occurred to many other people. Well, of course it did! It is so obvious, I think I could explain it to a 6 year old! But for some strange reason, I can't seem to be able to explain it to anyone here, except for a select few.
I wonder why?
I thought that you were familiar with the ETP model, because you sounded like you are. If you figured it out by yourself, then congratulations!Futilitist , 03/18/2015 at 8:46 pm
Also look at this (link). This chart was first made long time ago (2 years?). This is the updated version. I don't believe that you didn't see this earlier
http://www.economic-undertow.com/wp-content/uploads/2015/03/Triangle-of-Doom-030315-1024×689.png
Hi Kam.Boomer II , 03/17/2015 at 3:45 pmI just found that "traingle of doom" chart the other day, when I was looking at the link you gave me to the ETP model, and I wanted to find out more. I looked around and ended up seeing the chart at a discussion at peakoil.com. It looks like charts I was making before 2013.
I have been expecting a collapse for quite a while, so I started watching the wedge form pretty early on. I began to develop the idea that there would be an oil spike when the lines crossed!!! Ha ha. I could probably find where I posted my big prediction for a spike in June 2014!!! Right timing, wrong direction.
I really had had the wrong idea about the cost of production. I thought that would be the impossible line to breach. But that doesn't factor in heavy finance in the oil industry. The affordability line was the real problem. Of course, as soon as oil plummeted, I began to get a clearer idea of the dynamics. I started to get the idea that the price of oil would keep falling. At Thanksgiving at my moms house, I announced that the collapse of industrial civilization began in June of 2014. It was not a welcome topic. It is not welcome here, either.
The ETP model peaks in 2012. Check out this post:
http://peakoilbarrel.com/eia-confusion/comment-page-1/#comment-504805
When seen relative to interest rates, 2012 is the highest price oil ever reached (higher than 2008)! The chart "squeeled" (non-linear dynamics) at the peak. The whole thing fits together.
And that makes this next post really interesting:
http://peakoilbarrel.com/eia-confusion/comment-page-1/#comment-504784
It shows how the FED used QEx and operation twist to extend the wedge by raising the affordability line. Especially twist in 2012. Stick save.
Anyway, thanks for the link, Kam. It really helped me bring the whole thing into sharper focus in my mind. I understand collapse much better now.
I have been debating certain people on the site, and they really don't get it, or they are really pretending hard not to get it. I think I am explaining it pretty well, but…
…Anyway, check out the debate or better yet join it. I could sure use some help.
Ron, Is it possible the EIA is intentionally trying to push oil prices down for political reasons?Watcher , 03/17/2015 at 11:25 amIf there has been any intentional push to be overly optimistic, hasn't it been from the oil industry itself? The whole "energy independence" thing.
So if the net result would also drive down oil prices, wouldn't the industry, rather than government, be the one to blame?
A little bit of data reconciliation here:SAWDUST , 03/17/2015 at 11:46 amthe mazamascience.com/oilexport link puts it all on one graph by country/region and is based on BP's data. They also have a button to flip from tonnes to barrels. My personal fave.
This from BP:
Oil production data includes crude oil, tight oil, oil sands and NGLs (the liquid content of natural gas where this is recovered separately). Excludes liquid fuels from other sources such as biomass and derivatives of coal and natural gas.
World oil production tables are in both thousand barrels daily and million tonnes.
There is no mention of condensate in that. It could be called NGL, one supposes. So it's not a pure crude measure. We can't be happy about that, but it IS all on one graph (with consumption). Further, three cheers for BP, they adjust for leap years to get the extra day out for annual quotes.
So their graph for China consumption is pointing at 11+ mbpd. That includes all of the above.
This from China's official org:
China's implied oil demand will grow 3 percent this year versus last year, the country's top energy group forecast, little changed from the pace of growth in 2014 as calculated by Reuters.
State-owned China National Petroleum Corporation (CNPC) saw the nation's oil demand rising to 10.68 million barrels per day (bpd) in 2015, some 310,000 bpd higher than last year.
The forecast, in an annual report released by CNPC's research institute on Wednesday, also put the country's net crude imports up 5.4 percent at 6.49 million bpd for this year.
China, the world's second-largest oil consumer, raised crude imports by nearly 10 percent last year, or an additional 530,000 bpd, largely to boost government and commercial reserves as oil companies took advantage of the more than 50 percent fall in global benchmark prices from mid-June.
The CNPC forecast was higher than a recent report by the International Energy Agency (IEA) that put China's oil demand growth for 2015 at 2.5 percent, down from 2.7 percent last year.
No sign of reduced Chinese consumption.
I'm looking ahead to tomorrows FOMC announcement at 2:00-2:30pm ish. If Fed comes off hawkish i think we will see oil below $40 very soon if their statement is dovish we get a price rebound though it might be a short lived one. I also think if they come out hawkish the dollar will initially strengthen but when stocks roll over and bonds yields start collapsing towards zero they are going to drag the dollar down with it. Which in itself might support oil prices at least in some small manner.Watcher , 03/17/2015 at 12:31 pm
http://finance.yahoo.com/news/china–carmakers-overcharging–selling-defective-products-175034116.htmlSAWDUST , 03/17/2015 at 12:59 pmThis is mostly a vid. The audio content and the text has no value. It's Yahoo talking heads pretending they know something. Turn the audio off.
Rather watch the video. The imagery. LOOK AT THOSE CHINESE TRAFFIC JAMS, on open highways. About the 2:00 mark.
Beyond cars issues. A lot of the stuff manufactured in China eventually will be replaced by 3D printers. Combine that with China's move to De-dollarize. Setting up a alternative to SWIFT and selling US bonds. How will they be able to keep their currency pegged to the dollar? Which is what keeps those Chinese factories humming. In the long run how will they continue to keep hundreds of millions of people working?Watcher , 03/17/2015 at 2:15 pm
I don't think you embrace the theme of this blog.SAWDUST , 03/17/2015 at 3:11 pmIf the oil isn't there, people go to war and die. It doesn't matter who prints what piece of paper, you can't print oil and you can't feed 7 billion without oil.
Scarcity begets tanker seizure. Japan can't survive if the tankers going to Tokyo go to Shanghai, and outbidding doesn't matter if China HAS to have that oil.
I totally embrace the theme of this blog. But before scarcity sets in and nations start taking other nations oil supply by force. Some economic tremors will be felt which will lead nations to use force to secure oil supplies. Economic hardship is a prerequisite. We will actual need more than economic tremors. We will need some economic earthquakes. Before bombs and bullets start flying. I don't think nations will attack each other the minute oil starts get scarce. It wont be until their economies can't function properly anymore and respective governments see no other alternative. It will be when growth ceases to exist and economies can do nothing but contract. Chinese tankers can very well be seized themselves. China doesn't own the seas.Watcher , 03/17/2015 at 3:17 pm
Pretty much.hermit , 03/18/2015 at 2:37 pm
Watcher if you thought that one was bad. take a look at this oneRonald Walter , 03/17/2015 at 12:17 pmhttp://www.bbc.com/autos/story/20150317-how-smart-traffic-signals-may-ease-your-commute
In 1953 there was one well in the Bakken.Watcher , 03/17/2015 at 12:40 pmIn 1988, there were finally 99 wells.
In 2009, the number of wells in the Bakken Formation then reached 1000 plus wells.
In 2015, there is a Bakken/Three Forks well count of 9052 .
Nine thousand times more wells in a 62 years.
It is entirely possible to shut them all down and forget about the oil, but I wouldn't stand on one leg or hold my breath.
The place where Congress gets the job done.
Re systemic data issues. ZH just splashed one of their strong points, noticing inconsistency. There may be an explanation for it, but whoever is going to make it better start cracking:Fernando Leanme , 03/17/2015 at 2:45 pmhttp://www.zerohedge.com/news/2015-03-17/something-strange-going-nonfarm-payrolls
Gist is this morning's Housing Starts number was down sharply for February. But the February Non Farm Payrolls number showed a sharp increase in residential construction employment. Naturally, any time there is bad data this time of year it is attributed to winter. But it's winter for hiring too, and it didn't show there.
My opinion is the NFP measurement is taken the 3rd week of months. I suspect things have been done to take advantage of that knowledge.
What's "soon"?Watcher , 03/17/2015 at 3:18 pm
Best you not know.clueless , 03/17/2015 at 3:19 pm
Watcher – we had a small back and forth a short time ago, in which I think (do not shoot me if I am wrong) your biggest complaint about today's economics was lack of transparency. This article seems to show what I believe. Do not look for transparency, because you will never find it. People/institutions can put forth as much data and/or reasoning as anyone could possible want, but in the end it is not transparent. You just have to look at the information and decide for yourself if it is reasonable and what it means.Watcher , 03/17/2015 at 3:24 pm
I am big on analogies (in case no one noticed). Everyone watches a football game and sees what they perceive to be a stupid play call. The sportswriters cannot wait to ask the coach about it. He gives some reasoned answer. Pointless. He went brain dead at the time, but he will never give that as the reason.
So, I look at what the Fed does, and try to figure out why I think that they did what they did. I never accept their reasoning at face value. Same with about most things. I read the WSJ every day for 45 years, not necessarily to gain information, but rather trying to figure out if I agreed or not with whatever point someone was trying to make.
With respect to investing, about the only time you can make a lot of money is when almost everyone else is wrong, but you are right. Generally, pretty hard to do.
With respect to investing, about the only time you can make a lot of money is when almost everyone else is wrong, but you are right.learner2 , 03/17/2015 at 1:05 pmIf oil was the engine of all things (and it was) throughout your investing personal database, then being right was just betting on an index and letting increased BTUs assert themselves and eventually appear in macro economics. This was why "a problem delayed is a problem solved" worked pre 2008. Oil's derived growth would fix everything if you just could buy time.
That's all gone away and it's never coming back.
That sentence cannot be uttered or embraced, so money will be printed to extend and pretend and buy time for the mechanism that no longer works.
How do you guys think about the current meme that the nuclear deal with Iran (maybe even by month end) is going to result in extra 800k to 1M bpd coming to market soon? That is the reason being given for price declines.Watcher , 03/17/2015 at 3:19 pm
That stuff hits the rumor mill every time an Iranian deadline approaches.Longtimber , 03/17/2015 at 2:06 pm
Bit off Topic for Hydrocarbons. but, another reason to be prepared.sunnnv , 03/17/2015 at 4:07 pmOf all our infrastructure, the electrical power grid is the most fragile. In the 2013 Infrastructure Report Card, prepared by the American Society of Civil Engineers, Energy received a grade of D.
http://www.survivopedia.com/the-power-grid-could-collapse/Competition in Li Pak's are getting interesting.. Capacity and features evolving every few months.
Take any ratings with a grain of salt. There are no test standards. Would love to see reviews.
http://www.manufacturing.net/news/2015/03/when-oil-prices-are-down-worker-deaths-are-up-in-the-bakkenBoomer II , 03/17/2015 at 4:24 pm"Low oil prices and subsequent cutbacks in the field by drilling companies could be contributing to a rash of worker fatalities in North Dakota, according to a report in the Wall Street Journal.
The state saw eight oilfield employee deaths since October, a five-month total than exceeded the number for the previous 12-month span. October also coincided with the beginning of a decline in the number of oil rigs operating in the state.
"For those with access to WSJ:
http://www.wsj.com/articles/oil-deaths-rise-as-bakken-boom-fades-1426187062And in the same issue of manufacturing.net:
http://www.manufacturing.net/news/2015/03/dow-signs-on-to-develop-massive-wind-farm
"…The wind farm, to be complete in first quarter 2016, will span nearly 35,000 acres, and will supply Dow's Freeport Texas Manufacturing facility with 200 MW of wind power …"
Centralized power generation and distribution is going to be replaced as soon as it can be.Rune Likvern , 03/17/2015 at 4:52 pmYou Don't Need An Energy Company When You Can Buy Power From Your Friends
A couple of articles which will affect the oil priceWatcher , 03/17/2015 at 5:35 pmIran Can Add Million Barrels a Day of Oil If Sanctions Halt
http://www.bloomberg.com/news/articles/2015-03-16/iran-can-add-million-barrels-a-day-of-oil-if-sanctions-are-ended"If sanctions are lifted, we can raise our exports by one million barrels per day within a few months," Oil Minister Bijan Namdar Zanganeh said Monday in Assaluyeh, Iran. The Persian Gulf nation shipped 1.2 million barrels a day last month, the International Energy Agency said in a March 13 report.
Oil hit by stockpile fears; dollar offsets some loss
http://www.reuters.com/article/2015/03/17/us-markets-oil-idUSKBN0MC1TC20150317Industry group American Petroleum Institute (API) said after the market's settlement that crude stockpiles rose by 10.5 million barrels in the week to March 13, far ahead of the 3.8 million forecast by analysts polled by Reuters. If correct, the API number would lift total U.S. inventories to 450 million barrels.
$42.xx following the report, which is post US close pre Asia open. Some futures trading still goes on.Yetanother Mike , 03/17/2015 at 5:03 pmOf more concern, for the 2nd time this week I have seen "22 Trillion in oil derivatives". No idea where that's coming from. That's a lot of HY paper swaps plus options, one supposes. It spells Apocalypse, actually.
Found this on chron.com, along with a few other stories about the shale slowdown:Boomer II , 03/17/2015 at 6:12 pmhttp://fuelfix.com/blog/2015/03/17/oil-production-falling-in-three-big-shale-plays-eia-says/
I'm behind on reading the comments on some of the other posts. So I don't know if this has already been posted.Longtimber , 03/17/2015 at 11:11 pm
Fantastic, You can filter by play. wish you could filter horizontal and they had one for NG. Hope it's updated for all of 2015.Watcher , 03/17/2015 at 10:17 pm
Okay. What is the rationale here?Watcher , 03/17/2015 at 10:25 pmI'm seeing talk that at these price levels some number of wells will get fracked that is a lower number than used to get fracked.
Why? Why are these wells going to get fracked at these price levels and who is going to pay for them post March 31 when revaluation occurs? I thought the plan was allegedly to frack nothing until you got a better price. So . . . who is going to pay for it, and why do it if you're not getting enough price and are oh so very sure you're going to get better price upcoming aka soon? Is this all about paying your people? Are the lenders interested in paying your people, or getting their money back?
Oh, and the big guys buying the small guys theory . . . how does that work at a wellhead price of $25? The for-sale company has $XXXX in revalued assets and $YYYYYYYYYYYYYYY in debt. Who buys that company? Someone should be paying someone to take that company, not the reverse. So . . . maybe the for-sale company says psssssst, maybe I'll just sell you the assets so I can have cash to keep the doors open. Well, didn't the lenders have those assets as collateral? Can we spell fraud?
If the price stays in this ballpark for a while (and note it was around this price for FIVE SOLID YEARS 2000-2005 (which btw was in this century, not last one) all of this is going to disintegrate.
As for who thinks it's going higher, which expert says this or that, let's make this a pure experience. Show me that expert taking out extra mortgages on his house and levering up his 401K to make the bet on higher soon. If he ain't betting, then he's indulging in fantasy.
hmm never saw that before Ron. "You do not have permission to edit that comment." The edit button is there. That's the message that appears. Plenty of time left.Ron Patterson , 03/17/2015 at 10:40 pm
Try it now. I have changed the time to 2 hours. Otherwise I don't know what the problem is.Watcher , 03/17/2015 at 10:58 pm
It's not the time.Futilitist , 03/18/2015 at 12:01 amI clicked edit just now and a window appeared saying "comment loaded successfully", but it's empty, there's nothing there to edit.
Maybe it will fix itself. Give it overnight.
It is a glitch that happens every once in a while. Just hit the X, and then hit the edit button again. That works for me.Caelan MacIntyre , 03/18/2015 at 2:57 am
New and improved! Now an hour+! ^u'clueless , 03/18/2015 at 10:37 am
Who thinks it is going higher?Skywalker , 03/19/2015 at 10:46 pm
Well, just looking at the numbers "somebody" does. To my knowledge, importers of oil do not have long term contracts obligating them to buy oil and import it. So in less than a year, oil inventories are up in the US by 100 million barrels, over 9 million more last week per this mornings EIA report. We have consistently been importing over 1 million bbls/day more than we need and putting it into storage. Imported oil is probably closer to Brent in cost. So let's guess that somebody has put 100 million barrels into storage at an average cost of $55/bbl. That cost somebody $5.5 billion plus monthly storage fees, plus cost of money. I doubt that whoever "somebody" is, is looking for an opportunity to sell it all for $40 and lose close to $2 billion on all in costs. So, if not, then they must think that they will make money at some reasonable time in the future.
This is also somewhat puzzling to me. I know that the majors have access to that kind of money, but after not seeing US oil imports back off one bit since the plunge started, I have concluded that it is above my pay grade to try to figure it out.
Current oil future curve is in contango, which means future price is higher than spot price. If the spread between spot and future prices is large enough to cover the storage costs, many people will try to take advantage of that "free" money by buying the oil at spot price, putting them into storage and then shorting the oil future 3 or 6 months out, which enables them to fix the selling price in the future.Futilitist , 03/19/2015 at 11:21 pmMany people are doing this kind of arbitrage right now. Some are even leasing the whole oil tanker as the storage and that is why the tanker rate has been skyrocketing.
Desperate measures and a product of the optimism bias in all humans.Skywalker , 03/20/2015 at 12:54 am
It has nothing to do with biases but everything to do with making risk-free profits. The arbitragers may not have a view as of where the oil price will be in 3 or 6 months time. They simply make money from the spread.WeekendPeak , 03/20/2015 at 8:47 amI would do the same if I have the resources.
that's exactly what it is.Fernando Leanme , 03/18/2015 at 5:58 pm
rgds
WP
Watcher, properties will be purchased by those who have a price forecast high enough to deliver a solid risk weighed return. The evaluation is fairly straightforward. We look at the cash flow from existing wells, perform an estimate for wells being drilled, but consider delaying the completion until prices increase. We also look at undrilled well locations and prepare an estimate for those as well. If it's an outright company purchase we have to look at other topics, for example environental liabilities, pending lawsuits, and labor issues.Andy Hamilton , 03/17/2015 at 11:07 pmI can't go beyond this basic outline. But I assume you do realize there are plenty of players who have very large amounts of cash to buy. If the sales don't go through is because the seller has a really inflated view of what the property is worth. Or is one of those ego driven types who wants to be an oil tycoon and just doesn't want to sell. I ran into one not too long ago. He didn't want to discuss business, was mostly interested in discussing politics, so the sale fell through. I bet right now he's a bit shook up.
Investors in US shale oil junk bonds take yet another bath:Caelan MacIntyre , 03/18/2015 at 2:15 am
http://www.bloomberg.com/news/articles/2015-03-17/energy-junk-bond-revival-cut-short-as-7-billion-lost-in-10-days
"'Oil prices have fallen more than 15 percent since March 4 to a six-year low of $43.5, wiping out $7 billion of market value of high-yield debt issued by energy companies. Prices on $1.45 billion of notes sold less than two weeks ago by Energy XXI Ltd., an oil producer that was being squeezed by its lenders, have fallen by as much as 10 percent. Comstock Resources Inc.'s $700 million of securities have declined by more than 7 percent since March 6.The latest slump in crude is rekindling concern that oil companies will struggle to service the $120 billion of high-yield, high-risk debt they took on in the past three years amid the U.S. shale boom. That's a sharp reversal from February when yield-starved bond investors were loading up on the debt again, pushing down borrowing costs to a two-month low. "'
Yalza!
"I find it curious that anybody would chose a peak oil blog to tout the merits of shale oil, or shale gas, particularly now, when it has its pants down around its knees, its hands overs its privates , but so be it…shallow sand , 03/18/2015 at 6:14 amThe real oil and gas business… is very difficult at the moment; we are all working 24/7, confused about the direction of prices, and having to watch every penny we spend, right down to washing poka dot gloves every evening to wear them again the next day… I have had 50 good men ask me for work the past 3 weeks , all coming out of the stinking shale business, with little hope for the future…
As you can clearly (lol) tell, I am not a fan of the stinking shale business … I think [it] …has mismanaged my countries limited hydrocarbon resources in a very bad way. It took advantage of cheap money, little risk, absolutely no regard for conservation practices, and drilled itself into a 9 line bind, in my learned opinion. It lied to the American public, misled its work force , borrowed money it cannot pay back and helped drive the price of both oil and natural gas down to levels that will ultimately hurt, not help Americans. Now its all unraveling…
Dickheads in the Bakken and Eagle Ford want to export condensate to stay on their drilling hamster wheels; how does selling American resources, cheap, to buy them back tomorrow, from people that hate our guts and want to kill us, help America? It doesn't. It is stupid…
I am reminded of numerous times in the history of oil and gas in the United States where an unregulated industry drilled itself literally into oblivion… More recently, the shale gas industry imploded from over drilling and the corresponding collapse of gas prices. My industry cannot seem to keep from making the same mistakes again, over and over. It gets caught up in it own bullshit far too often…
I have to lay off a couple of kids today that have been with me for 5 years, one just got married …
Is shale oil extraction a resounding success story in America, a benchmark for free-market enterprise? Bullshit . The debt those guys has accumulated would choke a big horse; its begged, borrowed and essentially stole money from grandma's all around the county that bought their stock based on propaganda. It has not made a dime of profit yet. The wealth of retired people who invested in the shale oil business, even people that didn't, is now being decimated because of the shale oil industry. Every stinking shale well drilled uses sufficient fresh water for 168,000 humans to consume in one day and nearly 400 tons of steel. The crop and ranch land that is lost to shale well pads and roads is heart wrenching. All that for a couple of months of $ 2.00 gasoline? …
The shale oil industry shot itself in the foot. Along the way it shot me, and thousands of other operators in America, in the back. It is helping to facilitate a train wreck around the world, actually . I have been to West Africa, the ME, all over S. America, everywhere in the world there is oil production and I am telling you straight away, there are now lots of very, very afraid people out there in the world. Hungry, thirsty, sick people whose countries cannot help them any longer. Why? In part because of stinkin' shale oil industry greed. I am mad at them sumbitches this morning…
I gotta go let some good kids go . Damn, I hate that…
The shale oil industry will not survive 50 dollar oil …Now oil prices are low, and getting lower, and the money tree is going to fall over. Anybody promoting the shale oil industry at this point must be getting paid to do so. …"
~ Mike @ The POB
--
"So long story short don't believe all the negative people saying you should go home now because there are still plenty of jobs around you can get in the Bakken and be making six figures in no time ." ~ dn_girl
"We had a proud young woman post yesterday about her… optimism about… future in the oilfields of North Dakota. It is a powerful message that we should have all embraced …
She probably won't be back…" ~ Mike"Things are getting tough out here in the oilfield right now, its time for me to get tougher… But this is going to be my last post for awhile." [January 10, 2015 at 12:41 pm] ~ Mike
"Mike,
I hope my comments didn't tick you off and that's the reason your going to cut back on posting… If I did say something that ticked you off, I am sorry." ~ TechGuy
I said I wasn't going to post awhile, and am still going to limit my posts because I really need to focus on much more important things than the internet, no offense to Ron's blog, which I appreciate very much.Futilitist , 03/18/2015 at 6:27 amAssuming the young lady from ND is real, which we know is always an issue on the net, I do not understand attacking her. It is like attacking the soldiers in Iraq because you don't like the lies that caused them to be there.
Living in a place like ND is not easy. Working outdoors in the winter there is not easy. Working in the oilfield is not easy. I do not understand why there would be lack of respect for people who have little to nothing, who move up there to bust their butt to make a living.
While I'm here, I know us small producers are upset with shale overproduction. However, I think the real culprit is our unregulated financial system. No good reason for oil to have hit $147 in 2008, which contributed to crashing the economy and putting millions out of work. Now, no good reason for oil to fall below $40, which means $20-30 at the well. It is so far below the cost of developing new production, its almost a joke. It is also below the cost of most US production too, when you figure in all the costs. Add in the bubble financing, and here we are.
If you are going to attack people, at least try to focus on those who are responsible for this shale mess, not people who are trying to avoid the destruction hitting our middle class by going to work a thousand miles from home in the elements to make a buck.
Hi shallow sand,Ronald Walter , 03/18/2015 at 7:24 amGood to see you again.
Since you dropped by, I would like to ask you a question, if you have time.
How much do you know about the Petroleum Price Curve and the ETP model?
You're getting close on the 'unregulated financial system' part.Futilitist , 03/18/2015 at 7:27 amAt the heart of it all, there is no financial system, it fell down years ago.
What is there is but a vestige of what it really once was, it is now a shriveled carcass. Probably by design and plan, but that will probably never be known and remains to be seen.
Still, somehow, it all trudges on through the dreaded drudgery.
Not for much longer, I think.Caelan MacIntyre , 03/18/2015 at 8:01 am
"It is like attacking the soldiers in Iraq because you don't like the lies that caused them to be there." ~ shallow sandCaelan MacIntyre , 03/18/2015 at 8:47 amWhich is precisely why you need to short circuit those lies bloody fast, shallow sand, and sometimes tell the kids what they don't want to hear. My kid would not be on here like that, singing the praises of ND, etc., nor part of the bombing the tar out of Iraq, that's for sure.
We don't like our children very much, nor ourselves, nor our planet, nor the creatures on it.
If you are in this industry– one of the reprehensible attacks on the aforementioned– your shallow sand seems to be turning to quicksand. I hope so. May your work sink hard and fast along with it.
And this is spot on topic too. If low prices hurt the fracking, etc., industries, you have my 'opinion piece' right here.
Oh, and ironically, as if you hadn't noticed, Mike is, in a sense, with me all the way on this and makes many of my points for me. Have you read it?
And if dn_girl is real, save her and girls and boys like her! Risk pissing them off about their attitudes and choices if you don't agree with them.
If an arm is gangrenous, sometimes you have to hack it off, possibly to the protest of someone you love. I love my planet and some industries need to be hacked off fast.
By the way, Mike may not realize it, may be grappling with it, but he is perched on the precipice of anarchy:Paulo , 03/18/2015 at 8:38 am
He clearly despises his industry, but it is merely a manifestation of the larger crony-capitalist plutarchy; the violence-based governance structure; the parable of the violent tribe gone large-scale, overcomplex, global, amok.
Push him off!"…all forms of organization, regardless of how democratic they may be at the start, will eventually and inevitably develop oligarchic tendencies, thus making true democracy practically and theoretically impossible, especially in large groups and complex organizations. The relative structural fluidity in a small-scale democracy succumbs to 'social viscosity' in a large-scale organization. [Accordingly] …democracy and large-scale organization are incompatible." ~ Wikipedia
Nicely said, Shallow. I have always subscribed to the theory that most folks are doing the best that they can with what they have. The villians are the manipulators of finance and people who do so for their own gain, not the workers who have limited opportunities and influence.John B , 03/19/2015 at 3:34 amregards
"I do not understand attacking her."Caelan MacIntyre , 03/19/2015 at 7:44 amTry thinking in terms of a hopeless misogynistic psychotic.
Then you'll understand.
Way to go, Father John B.John B , 03/19/2015 at 3:14 pm
Show us how it's done. Give your 'hopeless misogynistic psychotics' a few pointers. 'u^"The shale oil industry shot itself in the foot. Along the way it shot me, and thousands of other operators in America, in the back. It is helping to facilitate a train wreck around the world, actually…
I gotta go let some good kids go. Damn, I hate that…
Anybody promoting the shale oil industry at this point must be getting paid to do so …"
~ Mike @ The POB
--
"So long story short don't believe all the negative people saying you should go home now because there are still plenty of jobs around you can get in the Bakken and be making six figures in no time ." ~ dn_girl
"We had a proud young woman post yesterday about her… optimism about… future in the oilfields of North Dakota. It is a powerful message that we should have all embraced …
She probably won't be back…" ~ Mike"The culture as a whole and most of its members are insane." ~ Derrick Jensen
People, I call upon you today to embrace that powerful message … Because, well, assuming it is, it is a message that appears like it came from a female … and one must always embrace and never be cheeky or sarcastic with a message that might come from a female . Good god no, because then… then that is just plain attacking … and misogynistic , no if and or buts about it. And will land you in hell. Or you will become blind if you do it too much. ^u^
BTW, John B, I get along very well with women (and men and even those in-between); the willfully-ignorant ones, less so. It's not about gender, but about deliberate stupidity.
(Another fine on-the-fly comment crafted with the Patterson Press™ Comment Editor)
Maybe it's about gender identification, and envy?Futilitist , 03/19/2015 at 3:50 pm
John B,Skywalker , 03/20/2015 at 1:55 am"Homosexuals are hardly better than criminals and ought to be severely punished."
1) Disagree Strongly
2) Disagree Mostly
3) Disagree Somewhat
4) Agree Somewhat
5) Agree Mostly
6) Agree Strongly
Very well said. Those working in the oil industry are not the ones to blame. They are just earning their livings by honest work. The biggest culprit, in my view, is the Fed, whose QEs and ZIRP encourage over risk-taking, which helped fuel the frenzy in the shale business.Futilitist , 03/20/2015 at 3:41 am
If the FED had not done what they did, with ZIRP, NIRP, endless QE's, and operation twist, we would all be dead already.Futilitist , 03/18/2015 at 10:36 amSo, unfortunately, the FED is not the culprit, either. We all are. The FED was just giving us what we wanted.
And since June of 2014, the FED has pretty much lost all of it's effectiveness. They are out of ammo. Physics is in charge now.
Hey Caelan.Caelan MacIntyre , 03/19/2015 at 10:48 am+100
I didn't mean to seem harsh on your style earlier (referencing the chicken and the dn_girl). And I obviously spoke *WAY* too soon. Forgive me. Now I think I understand. I had no idea you were building up to this! Your post above is an absolute work of art. The three posts together now form a kind of tryptic masterpiece.
And I do now think you may have uncovered something profoundly important, in terms of elephants in rooms. Bravo.
By the way, what did you make of my "The Mask of the Red Death" allegory post?
http://peakoilbarrel.com/opec-crude-plus-more-on-eia-estimates/comment-page-1/#comment-504992
Who is Prince Prospero? Who is The Red Death?
It's 'laughable' and kind of curious, the hypocrisy and fairly misplaced self-righteous net-nannyism of some.Caelan MacIntyre , 03/19/2015 at 11:52 amI think it had less to do with this dn_girl and more that I stepped on Mike's tail, maybe a few others'; the wish of $110 oil. I mean, what if you lost ~50% of the value of something overnight? Well that's what happened of course. (Many in certain situations might well come to this blog for insights and answers; some in less than the best of moods and frames of mind– and as time goes on. I think we should reflect on this. . This is the time of peak oil; of the decline of global industrial civilization. A New Era. How often do new eras occur? In the middle of single lifetimes?)
I hear many men, especially, more than women, if we want to talk sex, are prone to greater difficulty when it comes to work issues. Like, work is 'everything' to some of them.The thought did occur that if dn_girl is/was not a 'writeup', then maybe she is related to someone on here, even Mike, himself. In which case she might as well be a writeup.
I mean, aside from the vitriol he laid down about his own industry, he did seem desperate in some of his comments. 'Stabbed me in the back'?…
If your business is literally hemorrhaging, would you want to, somewhat less mindfully even, given your state, attempt to drum up business in any way you can? I would.In any case, if Mike read some of my comments, he might have got a sense that I am against wage-slavery ('the jobemployee') and against certain forms of industry (like Mike's), against hierarchy ('boss/employee') and my comments with the girl, of course, making fun of company-ownership (Mike has one?). So I think it was less about the girl and simply that, over time, Mike's head was pumped and pumped by his work and my commentary until it exploded.
Everything But The Girl (for Mike)
"By the way, what did you make of my "The Mask of the Red Death" allegory post?" ~ FutilitistOh ya, that one. And you think my chicken was over the top?! 'u^
In these Times of Twitter Texts, it is a long read, but I do like Poe who died way to young for my taste.
I am heading out but will grab a nice warm tea and read it over candlelight later tonight. Maybe prop my laptop half on the closed toilet seat and half on the bathtub edge and read it and its original reference in the bath after Russia Today.до свидания
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naked capitalism
Robert HahltegnostPerhaps the true purpose of financial austerity is to reduce oil consumption world wide.
Robert Hahlindeed perhaps, as our financial overlords have such clear benevolent foresight and care about people, not profits or perhaps demand has never recovered from $4/gal gas in 2007 and it's much simpier than that but perhaps the $4/gal gas was done on purpose in order to kill demand and reduce oil consumption, first by high price and then by austerity, perhaps they just wanted to find out what price of gas (apparently $4/gal) would crash the economy so they could save the world through austerity, but first they wanted to get some money in the bank so they could survive his "austerity period" because their kids can't take out student loans because they create an austerity rich environment that the children of the world benefit from but their kids were brought up right so they don't need austerity to be good global citizens, or perhaps crows communicate through quantum vibration and that's why we can't understand the meanings in their throaty calls .
rjsIf peak oil is a problem, austerity is a solution.
ambritit's not a demand side problem; it's supply, which built up as refinery margins were near record highs and contango made it profitable to store products
Isotope_C14Local fuel prices show a more 'nuanced,' which is business speak for rent extraction oriented, situation. Sunday, we went to Laurel, a town some twenty miles north of Hattiesburg. The cheapest gasoline in Hattiesburg cost $1.99 per gallon. Laurel had gasoline selling for $1.76 per gallon, all over town, not in isolated pockets. This price disparity was consistent across brands and types of location. Laurel does not have it's own refineries.
The Oil business has a few rules of it's own, which lowly consumers are not privy to.MLSSeeing as Hattiesburg is in the northern part of Forrest County, and Laurel is in Jones County, could the price disparity be a component of county taxes?
Also, EPA requirements include a variety of fuel formulations depending on desired pollutant reduction in a given air-space. Some formulations are for reduced volatile organics and they may have varying prices.
Chauncey Gardinerday-to-day fuel prices are heavily influenced by all sorts of factors like local tax rates, the cost of operating any convenience store or auto service on premises (local ordinances regarding wages, for example), the volume of business they do, whether a particular city or county has a specific ordinance relating to gasoline formulations, the cost of transporting the fuel from refinery to the station (generally speaking farther = more expensive), and so on. That you're seeing different prices 20 miles apart is not necessarily evidence of rent extraction.
NeqNeqPuzzling that the price of ethanol, a lower btu and more corrosive fuel that is added to and blended with petroleum-based gasoline by refineries, has been maintained in a tight price range since late 2015 and is currently priced near its all-time highs. This while the price of gasoline has fallen. Why?
ambritWasn't there a post a few days ago which showed the US EIA' weekly data was not lining up with actual monthly numbers? Meaning that there were large revisions being made to prior (2) month volumes?
Why should last weeks EIA inventory numbers be considered as anything but a noisy estimate subject to lots of revisions?
NeqNeqThe more cynical among us wonder in what direction the 'revisions' should really go.
PwelderI get that. And I am sympathetic. That doesn't change the fact that any prognostication (on the supplied info) is mood affiliation. Using your gut is fine. Hell, it might be instrumentally better than reasoned argument in certain situations. No need to claim its something other than your gut though. Unless, you are trying to sell something. Then its probably useful to engage in post-hoc rationalization.
a different chrisTwo points to remember about "glut" chatter in the Oil and Gas space:
1) The IEA – and to a lesser extent, the EIA – work for governments of nations which are net importers of crude and products. These governments prefer low prices. This doesn't mean that their published data is deliberately bad. It does mean that if there's a number that lends itself to a bearish interpretation, they'll make sure you know about it.
2) One way to generate such numbers is to shift inventories from jurisdictions with low transparency on storage levels (e.g. the Persian Gulf) to jurisdictions where reporting is somewhat better (US, Western Europe.) The Saudis have been doing quite a bit of this, as part of their war on Iranian/Russian oil revenues. This will be coming to an end within a year or so, as realities of supply and demand overwhelm operations aimed at "painting the tape".
>The Saudis have been doing quite a bit of this
Funny how oil has gotten so messed up – the major producers want to broadcast the fact that there is a glut. Ah Capitalism in all its contradictions
Something to point out to the goldish bugs – the people who just have to have currency attached to something physical, since gold is a hilarious currency anchor in this day and age* they have been switching to recommending oil as the baseline. Wonder how they will spin this?
*think about explaining to an intelligent and even sympathetic-to-backed-currency alien, without any historical reference, why you would pick gold
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Jun 14, 2016 | Bloomberg
Crude inventories fell by 933,000 barrels last week, according to the U.S. Energy Information Administration. A 2.33 million barrel decline had been projected by analysts in a Bloomberg survey ahead of the release. The American Petroleum Institute was said to report Tuesday that inventories rose 1.16 million barrels.
Crude output dropped to the lowest level since September 2014, the EIA data show
... ... ...
Nationwide crude supplies fell to 531.5 million barrels in the week ended June 10, according to the EIA. Stockpiles climbed to an 87-year high of 543.4 million barrels in the last week of April, EIA data show.
Oil-market news:
- Completion of drilled but uncompleted wells in the U.S. will accelerate at a WTI price of $50 a barrel, while $60 oil will trigger an increase in the rig count, according to a report from Citigroup Inc.
- The global market will be almost balanced next year as demand continues to rise faster than output, while the current glut is much smaller than previously thought, the International Energy Agency said.
- Venezuela and the U.S. will begin talks to normalize relations as President Nicolas Maduro said he's ready to exchange ambassadors.
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OilPrice.com
Official data released early on Wednesday confirms expectations of a U.S. crude oil inventory draw, with the Energy Information Administration (EIA) showing inventories down by over 3.2 million barrels for the week ending 3 June.
The EIA's latest weekly status report, released at 10:30am EST, reported a 3.226-million draw on U.S. crude inventories, while the consensus had called for a drop between 2.7 million to 3.4 million barrels. The new data puts U.S. crude oil inventories at 532.5 million barrels-a figure that is still historically high for this time of year.
The EIA's report follows Tuesday's inventory report from the American Petroleum Institute (API), which shows a draw of 3.56 million barrels, slightly more than the official figures just released.
Oil rose above $50 on Tuesday, following the API report, and was holding steady, close to $52 in early Wednesday trading prior to the EIA's weekly status report release.
The Weekly Petroleum Status Report showed gasoline inventories with a build of +1.01 million and distillate inventories with a build of +1.754 million.
U.S. Crude refinery inputs averaged 16.4 barrels per day, according to Wednesday's numbers. That number is 211,000 barrels per day more than the previous week's average. Refineries were at 90.9% of their operable capacity this past week, and gasoline production increased, averaging over 10.1 million barrels per day.
Related: India Putting Floor Beneath Oil Prices As Demand Continues To Soar
U.S. crude oil imports averaged 7.7 million barrels per day last week, which was down by 134,000 barrels per day from the week before. Total motor gasoline imports averaged 815,000 barrels per day. Distillate fuel imports averaged 167,000 barrels per day last week.
Total commercial petroleum inventories increased by 3.2 million barrels.
The EIA notes that total motor gasoline inventories increased by 1.0 million barrels last week, and are well above the upper limit of the average range.
By Lincoln Brown for Oilprice.com
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peakoilbarrel.com
Well hell, if you can cut capex by 62% and continue to produce at record highs, then I say go for it.
...In November 2014 the [rig] count stood at 3,570 rigs. Last month the count was 1,405, a drop of 2,165 rigs or 61%.
...If my prediction of 2015 as the year crude oil peaked is to be proven wrong, it looks like those making that claim will have to wait a few years to make their case. I know, there is nothing about OPEC in this report but OPEC is looking pretty shaky right now.
Brian Rose, 06/07/2016 at 4:38 pm
Dennis,
When would you expect it to become clear to the markets that U.S. production has been higher than forecast for several months?
The EIA's weekly inventory and production data comes out tomorrow morning. Any chance that they will start moderating their weekly production decline estimates tomorrow, or even say production increased to make up the gap?
Anyone here know what the time lag is likely to be?
I mean, the gap has become wide enough that they must be aware that their stated production is too low, right?
The longer it takes the EIA to correct this the more dramatic the market reaction will be. I could see a severe price reaction since WTI is now firmly above $50, and the overwhelming sentiment/fear is that frackers will all instantly completing thousands of wells at that price.
It would be an incorrect conclusion, but the timing between $50 WTI and revisions that show increased production would match the sentiment perfectly and oil prices would surely experience a significant correction.
learner2, 06/07/2016 at 6:01 pm
If the EIA comes out saying production had increased to fill the gap, I would think the market will see that the price went up in real time, meaning supply and demand already balancing, implying that demand must be really high to soak up all the supply. I don't think thats a reason to sell, quite the opposite in fact.
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U.S. Energy Information Administration (EIA)
U.S. crude oil production averaged 9.4 million barrels per day (b/d) in 2015. Production is forecast to average 8.6 million b/d in 2016 and 8.2 million b/d in 2017, both unchanged from last month's STEO.
EIA estimates that crude oil production for May 2016 averaged 8.7 million b/d, which is more than 0.2 million b/d below the April 2016 level, and approximately 1 million b/d below the 9.7 million b/d level reached in April 2015.
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peakoilbarrel.com
R Walter , 06/04/2016 at 7:10 amhttps://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MTTIMUSCA1&f=MExported oil from Canada totals 120,000,000 barrels per month, 4,000,000 bpd.
Imported oil from Canada included in the net import numbers?
11 cars of crude from the Bakken derailed in Oregon today and caught fire. likbez , 06/04/2016 at 12:41 pm
There is another nuance here that was discussed before: It looks like EIA does not subtract imported from the USA dilutant in the total volume of oil exports from Canada overstating the total heavy oil production by this amount (double counting).Dennis Coyne , 06/04/2016 at 1:45 pmRaw bitumen must be blended with around 30% of diluent. At the moment Canada uses for diluent about 200,000 to 250,000 bpd of condensate, most of that imported from the United States. Much of it travels from the U.S. Gulf Coast, where supply is abundant so there are significant transportation costs involved.
http://www.reuters.com/article/us-canada-oil-condensate-idUSKBN0EH18420140606
Hi likbezThis might effect net exports, but if done properly it does not.
First and barrel of condensate is exported then it is imported, the net is zero.
likbez , 06/05/2016 at 10:58 pm
It overstates the world total production by the amount of condensate used for dilution, is not it?Dennis Coyne, 06/06/2016 at 10:25 amIn this case EIA adds production numbers from all countries, but it do not take into account that part of Canadian oil and Venezuelan oil was "already produced" and accounted in the USA production stats.
So Dennis your world production figures are fudged :=)
Hi Likbez,The production statistics include the oil produced, not the oil shipped.
So no the production statistics may not be overstated.
Canadians are pretty smart, I believe they know how much oil they produce and are not counting the condensate imported to ship the bitumen as "produced oil".
My guess is that the secondary sources that estimate Venezuelan output also know they should not count imported condensate as oil production.
The calculation is really quite simple, if one counts production by what flows through the pipeline, just deduct the imported condensate used to create the dilbit.
The World numbers are not that accurate so any number reported is no more than a rough guess (+/- 1 Mb/d).
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finance.yahoo.com
The United States Energy Information Administration (EIA) reported a draw of 1.366 million barrels of crude oil on Wednesday, falling short of what experts predicted would be a 3.1-million barrel decrease in US crude oil supplies.
Last week, crude oil inventories reported by the EIA decreased by 1.4 million barrels, but still represented "historically high levels for this time of year," an official document read. Tuesday's American Petroleum Institute (API) figures said crude inventories increased by 2.35 million barrels, once gain contradicting the EIA's numbers, but also defying its own forecasts.
The decrease suggests a greater demand for oil in the United States, according to the source's analysis.
Last week's API report said supplies of the unrefined substance experienced a 5.1 million barrel drop - the largest such event since December. The market responded to the decrease and Brent oil prices almost hit $50 a barrel - a seven month high.
On June 2nd, the barrel price of oil reached $50.10 cents as the OPEC meeting commenced in Vienna, according to NASDAQ's estimates.
Gasoline inventories also faced a draw of 1.492 million barrels after enjoying a two million barrel EIA-reported increase during the week ending on May 27th.
The agency's monthly report released earlier this week said many of the U.S.' major energy producing states saw slightly lower production rates during May, including Texas and North Dakota. Offshore drilling sites in the Gulf of Mexico represented a notable exception, which saw a month-over-month increase of 4.1 percent in crude oil production.
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AlexS , 05/17/2016 at 1:31 pmpeakoilbarrel.com
Sorry for posting this down here instead of replying to one or the other AEO 2016 comments but I wanted to get it wide enough.Just looking at the difference in C+C predictions for each year leaves one to believe that the EIA has not a clue as to what US C+C production will be down the road.
Ron,Dennis Coyne , 05/17/2016 at 2:10 pmBasically, the EIA is projecting much higher LTO production from mid-2020s, with continuing rising trend, instead of the peak in 2020 in AEO-2015.
Projected conventional production is lower than in AEO-2015
LTO was a "black swan" in 2010-14, and it remains one of the biggest uncertainties for future global oil production
-------–
In the early release, the EIA does not explain its assumptions for the LTO output. All they say is:"Lower prices through 2017 has the greatest impact on tight oil
production, which drops to 4.2 million b/d in 2017 before
increasing to 7.1 million b/d in 2040. The general increase in
tight oil production is largely attributed to the higher oil prices
and the ongoing exploration and development programs that
expand operator knowledge about producing reservoirs."
Hi Ron and AlexS,Stoney , 05/18/2016 at 9:38 am[According to EIA forecast] The cumulative tight oil output for the reference case from 2015 to 2040 is 57 Gb. I think that is too optimistic by a factor of 2 at least. My guess, based on the USGS 2013 study of the Bakken/Three Forks and work by David Hughes on other LTO plays in Drilling Deeper is about 30 Gb for US LTO output (2005 to 2050) if prices go to over $100/b and remain close to the AEO reference oil price scenario for 2020 to 2040. Those prices might not even be high enough (in other words 30 Gb is an optimistic estimate, or pessimistic if one believes very high oil prices will be needed for a transition to alternatives).
I think we may reach a peak that is 10% to 20% higher than the March 2015 peak in LTO output in 2021 and then output will start to decline rapidly by 2025, the maximum decline rate will be about 12% per year in 2027 and by 2032 decline will become more moderate at about 7%/year (this is US LTO output only).
In addition to the 57 Gb of cumulative LTO production until 2040 they project 7 mb/d production on an upward trend at that point implying at least 50 Gb remains to be produced after that. So it's more like optimistic by a factor of 4 since you and Hughes rightly predict that LTO production will have declined to a low level by 2040-50.Dennis Coyne , 05/18/2016 at 1:03 pm
Hi Stoney,Caelan MacIntyre , 05/17/2016 at 2:49 pmIf we assume the decline has a similar slope of opposite sign, you would be correct, in the case of LTO I expect a pretty steep decline for 2 or 3 years (maybe a 15% overage decline rate over that period.)
So maybe a factor of 3 too high, but I agree more than a factor of 2 is definitely correct (if my 30 Gb estimate is roughly correct.)
Ron, your comment and that graph made me chuckle.
islandboy , 05/17/2016 at 3:13 pm
Just looking at the difference in C+C predictions for each year leaves one to believe that the EIA has not a clue as to what US C+C production will be down the road.It ain't just what US C+C production will be down the road. See my post further up. Hint, some observers think they are way out of left field on renewables as well.
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peakoilbarrel.com
Duncan Idaho , 05/16/2016 at 10:22 pmoops!
dependent origination:
Fire Nears Enbridge Oil-Sands Tanks, Workers Removed From Camps
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permianshale.com
Some 8,000 workers at oil camps north of the fire-ravaged Canadian city of Fort McMurray were ordered to evacuate late Monday as authorities continued the battle to bring wildfires under control.
...Suncor, one of the major operators working on Canada's oil sands, issued a news release late Monday confirming it had "started a staged and orderly shutdown of our base plant operations" and that personnel were being transported to work camps further north. It stressed there has been no damage to Suncor infrastructure.
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peakoilbarrel.com
islandboy , 05/13/2016 at 3:32 pmThe U.S. Department of Energy's EIA projections continue to miss the mark.Much ink has been spilled over the vast difference between the scenarios put forward by the U.S. Department of Energy's Energy Information Administration (EIA) and reality. And whatever the arcane arguments made by EIA, the fact remains that even without the impact of new policies, the agency's scenarios remain utterly incongruent to current reality.
Unlike the agency's Annual Energy Outlook (AEO), International Energy Outlook focuses on global trends. But like AEO, the report misses the boat on renewable energy and makes projections about the fossil fuel industry which run counter to facts on the ground.
International Energy Outlook 2016's section on electricity forecasts that total generation from renewable energy sources will rise 2.9% annually under the baseline scenario to reach 29% in 2040, driven by non-hydro renewable energy rising 5.7% annually. By contrast, EIA expects global coal use to rise 0.8% annually, and for coal to still represent 29% of global electricity generation in 2040, the same amount as renewable energy.
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thetyee.ca
by Andrew NikiforukAt the end of the day the $10-billion wildfire that consumed 2400 homes and buildings in Fort McMurray may be the least of the region's problems.
Although the chaotic evacuation of 80,000 people through walls of flame will likely haunt its brave participants for years, a slow global economic burn has already taken a nasty toll on the region's workers.
That fire began last year when global oil prices crashed by 40 percent and evaporated billions of investment capital in the tarsands.
As the project's most hight cost producers started to bleed cash, corporations laid off 40,000 engineers, labourers, cleaners, welders, mechanics and trades people with little fanfare and even less thanks.
Many of these human "stranded assets" endured home foreclosures and lineups at the food bank.
Worker flights to Red Deer and Kelowna got cancelled and traffic at the city's new airport declined by 16 per cent. Unemployment in Canada's so-called economic engine soared to nearly nine percent.
In fact bitumen has lost so much of its global investment lustre that, even before the Fort Mac blaze, Bloomberg reported that no new supplies of low-grade bitumen will enter the market in 2018.
This would mark the first time in more than a decade that the rate of bitumen extraction, now at 2.4 million barrels a day, will not increase.
... ... ...
Since the 1980s Koch Industries has been buying Canada's bitumen crude and turning it into high value jet fuel and gasoline at their Pine Bend refinery. In fact Koch Industries now gobbles up 300,000 barrels of bitumen a day and remains the single largest buyer of Canada's dirtiest crude. To the Kochs it's a no brainer: bitumen offers some of the most attractive refinery margins in the world.
Up in smoke? Even before the Fort Mac blaze, Bloomberg reported that no new supplies of low-grade bitumen will enter the market in 2018.
With the oil price collapse the Kochs keep on making more money, while Alberta gets poorer.In February the Alberta government set a minimum value for bitumen at $10 per cubic metre. That equates to a value of about $1.50 per barrel of bitumen. But in 2014 the government's monthly report valued bitumen at $421 per cubic metre. The data suggests that bitumen has lost 97 per cent of its value during the price collapse. In other words companies once worth billions are now worth millions.
... ... ...
When oil prices stood at $100, rash bitumen development made some sense. But when prices fell below $45 the gamble turned into Russian roulette. Unlike Saudi oil, most bitumen projects require prices of at least $60 to $70 a barrel to survive.
And so most tar sands extractors (except those who own refineries) are now bleeding cash; many banks have developed nervous twitches; and thousands of workers have found themselves unemployed. The overproduction of bitumen explains why, says Rubin, "the oilsands morphed from an engine of economic growth into the epicenter of a made-in-Canada recession."
Selected Skeptical Comments
Kevin Logan
bruce kay > Kevin LoganOil is currently over 45 bucks a barrel, but as Nikiforuk points out the values - especially related to raw bitumen - are insanely low and are simply cannon fodder for the Koch brothers war chest to unseat the Democrats.
The business case in the tarpit was always very dependent on massive subsidy, low royalty and political interference. Now that Alberta is just another Province with an NDP government and not the conservative mecca that rules the land from coast to coast, I suspect they will dole out much more pain for average folks.
Once the NDP there instills a massive tax regime with carbon taxes, sales tax and fees etc, to balance the budget on the backs of the people the conservatives will once again take back power and upscale the fleecing of the natural resource.
BC is on the same path, right now its the land of milk and honey because they need to build out the infrastructure to fleece us, but once the LNG facilities are in and the pipes are pumping, the pain will come. Fortunately for us they already are taxing us into the ground and hydro, fees licensing etc is already in place, so the fleecing of our natural resource wealth will result in less volatile boom and bust but no less of a complete fleecing - to be sure.
Kevin Logan > bruce kayNo one in Canada is being "taxed into the ground". that is an entirely fallacious statement, especially Alberta. Now you can certainly argue that the Tax regime is not particularly progresive in that the wealthier are proportionally under taxed but there is no doubt, particularly if one simply views other (generally more socially successful) countries, that taxation is a key element in creating opportunity where otherwise it does not exist.
That is at least one element that perpetuates the corporate dominance of our public policy that you talk about
Trust me, for Alberta to fix their woes, the plebes will feel as if they have been taxed into the ground. For decades the low tax environment of Alberta was its single pride and joy - the Alberta Advantage. Which is why the Cons would not mess with new taxes. The NDP was elected to get fair returns from the industry, but instead they capitulated and implemented a carbon tax they did not run on that only average folk pay as oil companies can write it off against their royalties. Bizarrely the new government plans to take that new 3 billion in annual revenue from average folk and hand it to industry to green up and what not, as there is no specifics released yet.
Letting off the oil companies, leaving royalty structures in tact and balancing the budget with new taxes on average Albertans was not what they ran on, but its what they delivered and its why the wildrose now polls first place way ahead of the NDP at some 25% in the polls.
bruce kay > Kevin Logan
Maybe I missunderstood your intent. I can't argue with that, on both counts. I'm not familiar with how the carbon tax revenue will be directed but certainly, lower income taxpayers need to avoid punitive costs simply because they can't avoid driving.
Otherwise, as you say the fury of populist revolt will sabotage whatever gains are made and the Trumps will fill the power void
RiversidePaulo > Kevin Logan
You'll never see an LNG plant built in BC. That ship sailed long ago.
WWallace Mud > Kevin Logan
Hi Kevin,
It seems to me another aspect of this is how quarterly profit driven short term thinking has ruled the day so completely that the reality that the solar energy bound up and stored in the tar-sands isn't going to evaporate is overlooked by the bean counters. One day, hopefully, someone will invent a technology that can harvest this energy without causing all the various pollution problems our current technologies create.
Future Canadians, our kids and grand-kids or theirs, will need energy to power whatever industries exist in the future, industries that will create their jobs and their future weal.
i say leave it in the ground, it'll only be worth more in the future. For sure this isn't the best plan from the banker's and shareholder's perspective, but it's the best plan for Canada and Canadians in the long term.
Tierra y Liberdad
I really enjoy reading Mr. Nikoruk's research on the future of oil. Clearly the numbers do not lie. The reality of certain laws are coming home to roost: the law of supply and demand, as well as the law of diminishing returns means bad news for the oil industry....and Canada thanks to past government's myopic, narrow oil-orgy led policies.
political ranger > Tierra y Liberdad
Read Rubin's report for a very sobering look at our near-term future.
cliche guevera > political ranger
I think people either get it or they don't want to get it.
WAC
If I was an unemployed homeowner in McMurray, I would take the insurance money and run!
cliche guevera > WAC
MindcraftAnd the 72 week E.I.Program Trudeau announced today, to re-train and get a new job skill that might even pay better than the Fort Mac daily grind.
Eduard Hiebert > MindcraftThank you Andrew Nikiforuk you have brought to light all the questions missing yet again in the mainstream media my wife has been spouting. It is unfortunately a gold rush town.
Mindcraft > Eduard HiebertIf "gold rush" is an appropriate metaphor, in view of recent federal and provincial politics is it anywhere appropriate to limit this "rush" to an image of a "gold rush town"?
Mindcraft > Eduard Hieberthttp://movies.netflixable.com/ ...
It's all in Canadian History, repeat, delete, repeat.
I have agonized over making examples from the beginning of the 1990's
If an industry creates waste, including premature death, it must invest in building ways to remedy the fallout and not employ a cover up team to continue the self distructive end game which is the lateral part of corporate un sustainability. The pulp mill near me has many fine hands on tech people all willing to address problems in their own time as a community yet they are constantly seen as a threat to shareholders achieving monetary gain from experimenting with the unknown in diversifying into creative sub groups.
No different than the Lego (before its forecasted demise many years ago) company letting parents decide, explore products of reality and culture. We have silo's of control in every level of governance.
Eduard HiebertIts easy to understand why the Koch brothers as but one of several parties are happy to oblige Alberta by buying low and selling high as Andrew Nikiforuk details.
However none of the analyses exposes by what process are "Most Albertans and most Fort McMurray residents" silenced into the Koch brothers serfdom when Nikiforuk concludes "Most Albertans and most Fort McMurray residents never wanted reckless growth. In a heartbeat they would have voted to slow down the tarsands years ago with higher royalties and better regulations, but their political masters refused to put on the brakes"?
def > Eduard Hiebert
The processes you refer to include the pathologies of capitalism and corporate 'democracy'. The therapy includes 'economic democracy' in which economic decision are based upon the control of all people effected by any given economic decision.
However, after decade after decade of corporate brainwashing such thoughts are not sufficiently sophisticated for serious consideration by present media, thoughtless talking heads, political propagandists, or god forbid, being explored in the curricula of the education system. It has proved to be a voracious and merciless process that shows few if any signs of relenting.
Eduard Hiebert > def
Since its the many who bear the costs of what the few impose on us, from beginning to your end agreed that "It has proved to be a voracious and merciless process that shows few if any signs of relenting."
Surely you are not suggesting say the Koch brothers initiate and do the necessary change for us as in to us when you yourself see that the answer involves "The therapy includes 'economic democracy' in which economic decision are based upon the control of all people effected by any given economic decision"?
Mindcraft > ScottyonDenman
6 hours agoIt is a mining camp that is sustained by federal gambling, how shrinkable is any gambling. Sustainability starts with no waste. Corporatists start with abuse and suckers to trample on, ie the ignoramus conmunitas.
disqus_Wf91wKMTsJ
Jeff Rubin, CIBC's former chief economist, notes that the world economy is stagnating; but the shrinking demand for tar sands oil is just part of the reason.
Rubin, along with most folks pushing for "green" energy, are being overly optimistic if they believe "an orderly transition that protects communities and oilsands workers, and rewards them for the economic contributions they've made by providing funds for retraining and industry diversification", will allow folks to avoid the economic pain that accompanies global resource scarcity.
Aside from nuclear energy, which has its own unique problems, there isn't another source of energy that has the same energy density and the same portability that fossil fuels provide.
political ranger > Eduard Hiebert6 hours agoIn Klein's world there was no planning, no short & long term, only the here and now. They had, the PC's and wild-rosecrucian's still have, a rigid belief in their ideology, much like the religious zealots in the far east, or anywhere. Their beliefs included 'big government is bad; the only good government is a small government' and 'self-regulation' and 'private industry always does it best'. Even after more than 35 years of spectacular failures these nutjobs still think they are on to something grand.
Nobody cared when the riches were just flowing out of the ground. Now, as you say, the blindfolds are not working so well.Eduard Hiebert > political ranger
I quite appreciate how you observe what the problem politic is when you say "Their beliefs included 'big government is bad; the only good government
is a small government' and 'self-regulation' and 'private industry always does it best'. Even after more than 35 years of spectacular failures these nutjobs still think they are on to something grand."I not that by defining the ones who are doing this to us as "they" you too are not part of that group. So how instead of us the masses being silence, do we get to have our say and not be beholden tho the relatively few you refer to as "they"?
political ranger > Eduard Hiebert
2 hours agoanthony roseSorry Ed, I don't know what you've written. Extensively or otherwise. Please state your thesis, perhaps not so extensively.
I'm not advocating bloodshed, nor to be clear, do I advocate more of the status quo. We quite clearly need a more immediate method of making culture-wide change.
How? I don't have The Solution, I'm afraid. I have advocated for a strong, aggressive and activist government. It would likely be their one and only time at bat but perhaps they might start the change (for the better) process.Chris Hedges, from the US, a much more dysfunctional society than ours, sees violent revolution as the only way forward with many, many losers and his side being the winner. I'm in favour of that outcome but I fear it's far from certain who will be the winner while it is absolutely certain that there will be many losers.
Without some immediate and significant change to our way of life both the natural environment and the social environment will soon reach a tipping point. Then there will no end to the missing people and carnage and wasted resources.5 hours agoIn my opinion:
I see what is going on at the Tyee. Any one who has anything that does not fit the pr-ordained narrative regarding Jeff Rubin, is deleted. Why?
Jeff Rubin is a man who predicted peak oil of $200 USD 10 years ago. He was wrong then and he is likely wrong now. Why do you accept his ideas as correct all the time? What happened to journalistic ethics and objectivity? So sad.
political ranger > anthony rose
5 hours agoread his report. It's chock full of facts, figures and statistics about all kinds of things that in his OPINION leads to a decline in the petro-biz in Albaturda.
If you disagree with any of the aforementioned facts, figures and statistics; well let fly, we'd love to hear about it. Some of us are, after all, here in the Tyee, data junkies and logic zombies always looking for our next fix. Tell us what data is deficient and what should replace it or what flaw in the argument could lead to a different conclusion.
If you have a different opinion, don't hold back. We've heard just about everything from your kind. There is always a chance that one of you will actually make some sense.anthony rose > political ranger
2 hours agoIn my opinion:
Here is a link to an article entitled: Jeff Rubin gets peak oil wrong from Canadian Business: www.canadianbusiness.co by the way what do you mean by the phrase : " from your kind"?
anthony rose > political ranger
an hour agoJack LumberIn my opinion:
My point is that I bought into Mr. Rubin's $200 dollar peak oil forecast. He had lots of facts and figures then too. He was still completely wrong.
He may be completely wrong again today.Again I ask what you meant by your phrase " From your kind?" ›
Oil will boom again. Global consumption continues to rise, but the global glut has stalled investment on new extraction. So our extraction levels will flatten out, but consumption will still rise. Eventually it will catch up. Hopefully it does so slowly, or there could be a future energy crisis.
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Enno Peters , 05/13/2016 at 4:58 amThanks for the post Ron.
@Alex,
coming back to your comment at the end of last post:
" The chart below shows that both the EIA Drilling Productivity Report and the EIA/DrillingInfo monthly LTO production statistics tend to underestimate the resilience of tight oil production, at least in the case of the Bakken. The EIA estimates for February and March will likely be revised upward. I think that even bigger upward revisions will be done for the Eagle Ford."
The small declines in Feb & March is indeed surprising. Based on the new well count, and on 2015 1H well profiles, I expected declines around 20-25kbo/d. It does appear that the average well that started in the 2nd half of 2015 behaves quite differently, peaking for a few months longer than usual. This is caused for a large part by wells from Burlington, XTO, CLR & QEP. That has messed a bit with my projections, and probably also the EIA. If those wells had behaved more like earlier wells, ND production would be at least 20 kbo/d lower in March.
Questions in my mind now are:
- How will these "higher for longer" flow rates behave over the next couple of months?
- Will we see the same behavior in all new wells?
- Will we see something similar in other basins?
I think you could be right about those upward revisions. To me it shows that there is quite some new uncertainty caused by these changing dynamics.
AlexS says: 05/13/2016 at 5:38 am
Enno,
Thanks very much, that's really surprising. Perhaps they are using some new completion techniques? Will try to find something in companies' presentations.
gwalke says: 05/13/2016 at 5:47 am
Great comment, Enno, as ever. It's important to remember that the EIA's forecasts seem to generally be very "smooth", and their models are mostly done at an economic level, meaning they aren't working from number of wells upwards. This meant they completely missed the beginning of the production decline – their initial forecasts kept on adding ~30kbpd a month to Bakken until April15, for example. Now they are a little to heavy to the downside.
We just did some work on the EIA/IHS report on well costs that came out a little while ago. We suspect that these longer peaking wells may be possible due to lower service costs. Operators have switched to natural sand, and lots of it. Not being an engineer, this is only an educated guess, but the general gist I can gather is that natural sand crushes more easily than artificial ceramic proppant, but is significantly cheaper.
Our assumption on the interests of operators like CLR and WLL is that they currently want to maximise short-term production to boost revenue, and they care significantly less about maximising recovery. Using lots of natural sand fits in with that – though the sand will be crushed more quickly than if artificial proppant will be used, more fractures will be propped open in the short term.
Many of these short term production gains may be given up shortly after any price increase, as the service costs will also rise, and the short term revenue considerations will become less important. That's the theory we're working under currently, anyway…
The decline after peak of new wells appears to be significantly steeper than previous years, so when companies claim 40% IP increase = 40% EUR increase, one should be extremely skeptical. By month 7 of production, the average 2014 well had produced 18% more oil than the average 2010 well at the same stage of its life – but by month 26, that difference was down to 7.6%. In month 3, the average 2014 well had produced nearly 9% more than the average 2013 well – by month 26, that was down to 2%. Those are total cumulative oil produced figures, btw.
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The EIA's International Energy Outlook 2016 is out todayThe new projections imply 1% annual-average growth in global liquids consumption for the period 2012-2040, including virtually zero growth in the OECD countries and 1.9% annual average growth in non-OECD countries.
World liquids consumption by region, Reference case (mb/d)
AlexS , 05/11/2016 at 9:37 am
World total energy consumption by source, Reference caseAlexS , 05/11/2016 at 9:51 am
(Quadrillion Btu)
Share of various sources in total world energy consumption (%)Ron Patterson , 05/11/2016 at 11:56 am
Thanks for the chart Alex. I fail to see any exponential growth in renewables, (other in this case and that includes hydro and geothermal), or any exponential shrinkage in liquids. I think the EIA would have a strong disagreement with Dennis. :-)AlexS , 05/11/2016 at 12:17 pmRon,
Assuming that growth in hydro is very low, other renewables are likely to increase at a high rate, but from a very low base. So fossil fuels will retain their dominating position in total energy consumption. That's a common view among all key energy forecasting agencies"I think the EIA would have a strong disagreement with Dennis."
And with many other contributors to this blog :-)
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www.theguardian.com
Unseasonably hot temperatures, extremely dry conditions and winds of up to 70km/h (44mph) helped fuel the fire's spectacular growth to 101,000 hectares on Friday – an area more than 10 times the size of Manhattan – up from just 10,000ha earlier in the week.
With temperatures expected to hit 27C (80F) on Saturday, officials said the fire could double in size by end of the day.
On Friday, Rachel Notley, the premier of Alberta, said Fort McMurray was still trapped in the grip of the inferno. "The city of Fort McMurray is not safe to return to and this will be true for a significant period of time," she told the thousands of evacuees scattered across the province.
The extent of the destruction wreaked by the fire was evident in a video uploaded to YouTube on Thursday . Apparently shot by a firefighter, the footage shows a devastated landscape dotted with piles of blackened rubble and the burned out frames of pickup trucks. A thick haze of smoke still hangs overhead, while small fires flare among the ruins.
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OilPrice.com
"As more information comes in, it appears that the impact on production of the wildfires in Alberta will be significant," said analysts at JBC Energy in Austria. Analysts noted that Shell shut its Albian Sands mine and Suncor shut its base plant, while producers Syncrude Canada and Connacher Oil & also reduced output in the region."Taken together this amounts to some 0.5 million b/d of capacity that is currently offline. Infrastructure is being affected too, with the 560,000 b/d Corridor pipeline shut down and movement along the 140,000 b/d Polaris pipeline significantly curtailed. On top of that, trains are not operating near Fort McMurray, according to the Canadian National Railway," said the analysts.
But the most comprehensive answer so far comes from Morgan Stanley's Benny Wong who estimates that the total number of offline capacity will be anywhere between 400 and 500 mbbl/d, with the shut-in expected to last about 10 days, potentially reducing total market output by as much as 5 million barrels.
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Reuters
Alberta is racing to evacuate thousands of people as an uncontrolled wildfire burns near Fort McMurray, in the heart of Canada's oil sands region, forcing residents to flee north to safety on Tuesday.Alberta appealed for help from other provinces and Ottawa to help fight the fire and airlift people from the city. Authorities issued a mandatory evacuation order for all of Fort McMurray, which affects the city's 80,000 residents.
The 2,650-hectare (6,540-acre) fire, which was discovered on May 1, shifted aggressively with the wind on Tuesday afternoon to breach city limits. The blaze closed off the main southern exit from the city, prompting residents to head north towards the oil sands camps
... ... ...
Suncor Energy (SU.TO), whose oil sands operations are closest to the city, said its main plant, 25 km (16 miles) north of Fort McMurray, was safe, but it was reducing crude production in the region to allow employees and families to get to safety.
Suncor said evacuees were welcome at its Firebag oil sands facility, while Canadian Natural Resources Ltd (CNQ.TO) said it was working to ensure any affected CNRL workers and their families could use its camps.
Shell Canada (RDSa.L) also said it would open its oil sands camp to evacuees and was looking to use its airstrip to fly out non-essential staff and accommodate displaced residents.
... ... ...
Suncor said evacuees were welcome at its Firebag oil sands facility, while Canadian Natural Resources Ltd (CNQ.TO) said it was working to ensure any affected CNRL workers and their families could use its camps.
Shell Canada (RDSa.L) also said it would open its oil sands camp to evacuees and was looking to use its airstrip to fly out non-essential staff and accommodate displaced residents.... ... ...
Most oil sands facilities are to the north and east of the city. Representatives of Syncrude, CNOOC (0883.HK) subsidiary Nexen Energy and pipeline company Enbridge all said their operations were unaffected.
The fire is the second major one in the oil sands region in less than a year. Last May, wildfires led to the evacuation of hundreds of workers from the region, and a 9 percent cut in Alberta's oil sands output.
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Alberta Oil Magazine
PetroLMI, a division of Calgary-based Enform, projects the industry will lose between 16,530 and 24,425 jobs in 2016 alone due to the economic slowdown. That's on top of the 28,145 jobs, or 12 per cent, the firm says the industry lost in 2015.
... ... ...
The report blames the drop in capital spending in the industry, which it says is due to the low oil price environment, for the decline in jobs. Capital spending in the industry has fallen from around $35.7 billion in 2014 to $25 billion in 2015. The report says the only reason capital spending has remained as high as it has is because companies are focused on completing late-stage mining projects. It expects capital spending to drop off even further after 2018 once those projects are completed, with a forecast for 2010 of $17.9 billion. That's a decline of more than 50 per cent.
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OilPrice.com
Canada Down But Not Out
Canada produces 7 million barrels of oil equivalent per day of bitumen, crude oil, natural gas liquids and natural gas, making it the fifth largest hydrocarbon-producing jurisdiction in the world. The country won't be going off the oil and gas business anytime soon, so keeping it going will remain good business and the largest resource industry in Canada.
But the current mantra of "lower for longer" is wrong. This is only the price of oil. In terms of the Canadian oil and gas industry [oil production] there are multiple reasons it could be "lower for a long time, possibly forever." For a country that performs all elements of producing still-essential hydrocarbons as well or better than anyone else in the world – everything from broad economic participation to worker safety to environmental protection – that is a tragedy.
... One of the attractions of Canada in recent years is foreign capital was welcome to develop massive, if expensive, oil reserves. Now Iran is said to be open for business. As is Mexico. Saudi Arabia wants to diversify its economy away from oil and sell its refining operations to global investors. The Saudis are talking bravely about an economy no longer dependent upon oil profits as soon as 2030.
Western Canada is not the only oil-producing jurisdiction wondering about its future. It is, however, the highest cost oil-producing jurisdiction wondering about its future.
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peakoilbarrel.com
EIA's US C+C output projections for 2016-17.AlexS , 04/21/2016 at 1:45 pm
The numbers are from the April STEO, but with some additional details.Source: http://www.eia.gov/todayinenergy/detail.cfm?id=25892
In response to continued low oil prices, onshore crude oil production in the Lower 48 states is expected to decline from an average of 7.41 million barrels per day (b/d) in 2015 to 6.46 million b/d in 2016 and to 5.76 million b/d in 2017.
The number of active onshore drilling rigs in the Lower 48 states fell 78% (from 1,876 to 412) between the weeks ending on October 31, 2014, and April 15, 2016. The decline in active rigs and well completions is projected to result in month-over-month onshore oil production declines of 120,000 b/d through September 2016.
EIA projects that the number of operating rigs in the Lower 48 states will continue to decrease through mid-2016 before beginning to slowly increase. However, expected Lower 48 production will continue to decline-although at a slowing rate-throughout 2017.
EIA's April STEO forecasts Brent crude oil prices averaging $35/b in 2016 and $41/b in 2017, with the December 2017 price averaging $45/b.
continuedEnno Peters , 04/21/2016 at 2:09 pmIn contrast to the forecast of declining Lower 48 onshore production through 2017, federal Gulf of Mexico oil production is projected to increase from 1.54 million b/d in 2015 to 1.66 million b/d and to 1.82 million b/d in 2016 and 2017, respectively. Alaska's oil production is projected to slightly decrease from 0.48 million b/d in 2015 to 0.47 million b/d in 2016 and to 0.46 million b/d in 2017.
Increased production from the federal Gulf of Mexico (GOM) is not enough to offset those declines, with total projected U.S. production falling from 9.43 million b/d in 2015 to 8.04 million b/d in 2017.
Great intel Alex, thanks for posting.AlexS , 04/21/2016 at 2:26 pmEyeballing the decline of Q1 2015, onshore : it appears to drop from about 7.5 to 5.0 in 1 year time (33%). That's an even higher decline rate than I expected. Looks like not only the production I'm tracking is declining at a rapid rate.
I'm curious to see if we indeed will see the projected pick up in rig count this summer already.
Enno,Heinrich Leopold , 04/22/2016 at 12:47 amYour charts for the Bakken and some other sources show that LTO output drops by some 35% in 12 months if no new wells are completed.
Given that the EIA chart for Lower 48 onshore includes conventional production and still assumes that new wells are drilled and completed, a 33% decline indeed looks too big.Apparently, they assume continuing decline in conventional output, primarily due to shut-down of the stripper wells. BTW, according to the EIA, between April 2015 and January 2016, US conventional onshore production was down 300 kb/d (bigger in relative terms than the drop in LTO output).
In addition, the EIA's oil projections are too low, in my view. Therefore, they may assume a small number of well completions
AlexS,Dennis Coyne , 04/22/2016 at 9:13 amIn my view we will see actually a massive decline in wells due to plugging of wells. The latest RRC report for March 2016: http://www.rrc.state.tx.us/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/ shows already a net decline of 1000 wells per month. So, a 33% decline of production is realistic and probably even too conservative.
Hi Heinrich,Heinrich Leopold , 04/22/2016 at 12:52 pmThe plugged wells are stripper wells with output of 5 b/d or less. So if 1000 of these wells are plugged each month that's 5 kb/d lower output each month or a 60 kb/d total decrease over 12 months. Not really much of a factor.
Dennis,Dennis Coyne , 04/22/2016 at 2:52 pmIt is difficult for me to check how big these wells are. However, the main point here is about a huge sea change (see below chart) in net wells. Add the dramatic decline in use of proppant, the drop in rig counts (natural gas rigs are just at 88 versus 1600 in 2008)….. I can see the writing on the wall.
US production will be declining dramatically over the next months. Even the CEO of Pioneer and the IEA admit the decline. The only difference is that I think the decline will last much farther than Sep 2016 and will last well into 2017.
Hi Heinrich,Dennis Coyne , 04/21/2016 at 2:44 pmEveryone agrees there will be some decline. Some estimates are more reasonable than others. So far decline in Texas has been relatively modest at an annual decline rate of 8%. There are still a lot of horizontal oil rigs operating in the Texas Permian Basin (over 100), and the horizontal wells produce much more oil than the vertical wells in that Basin. I am talking about oil only here, I don't follow natural gas as closely, at some point gas output will fall and natural gas prices will rise, no idea when that will happen though.
The permits minus plugged is not really very useful. Oil wells completed relative to wells plugged is of greater interest. Every well completed (average of about 250 kb/d for first year) covers about 50 plugged stripper wells (with an average of under 5 b/d). So about 20 completed wells will make up for 1000 plugged wells.
The first 3 months of 2016 there were 2482 new drill oil completions in Texas and 1453 oil wells plugged. The plugged wells are equivalent to taking away 29 of the new wells drilled, so the net new wells would be 2453 new wells or about 818 new wells per month for the first 3 months of the year. In March about 300 of these wells were in districts 1 and 2 (Eagle Ford most likely) and about 450 wells in Districts 7C, 8 and 8A (Permian Basin).
There has continued to be quite a lot of activity in Texas at least through March 2016.
Hi Enno,Dennis Coyne , 04/22/2016 at 9:17 amAre you accounting for possible incomplete data in Texas? Are you seeing 33% decline rates outside of Texas? I am talking at the field level, rather than individual wells or counties. So for the Niobrara, or New Mexico Permian, the decline is certainly not 33% in the north Dakota Bakken, or not through February at least. Based on Dean's data for Texas and even the EIA data for Texas, the statewide decline rate is not anywhere close to 33% per year.
Using EIA data, TX decline rate is 9% from March to Jan 2015. Using Dean's data from March 2015 to Dec 2015 the decline is 6.1% (Jan was anomalous so I threw it out, if it is included the decline rate is 4.2%)
Looking at the Bakken, the decline rate from June 2015 to July 2016 will be close to 20% per year if the completed wells fall to 50 new wells per month on average for the rest of 2016, so decline is pretty steep, just not 33%/year. After July 2016 if the completion rate levels off at about 40 completions per month the decline rate moderates to about 10% per year for July 2016 to July 2017.Dennis Coyne , 04/21/2016 at 2:22 pmHi AlexS,AlexS , 04/21/2016 at 2:46 pmI think the EIA is overestimating the decline because they are underestimating the oil price. With the DUCs available, the decline for the rest of 2016 in the LTO plays could be as little as 350 kb/d. The EIA is estimating almost a 1 Mb/d drop for the rest of 2016, the conventional L48 onshore was about 3300 kb/d in Jan 2016, a 650 kb/d drop in output from L48 onshore conventional would be a 20% drop, if we assume an 8% drop, that would be about 270 kb/d, for a total of 620 Kb. The EIA is also underestimating Texas output, if Dean's estimates are correct. If we assume no acceleration in the decline rate for L48 onshore, we get the following, with 2017 output about 6200 kb/d for L48 onshore.
Dennis,shallow sand , 04/21/2016 at 3:51 pmThe EIA has a long record of underestimating US oil production, not only during the shale boom, but also during the current downturn. In particular, they have been underestimating volumes produced in Texas. But I think that the most recent Dean's estimate for Texas may be too high. TRRC is now receiving production data from operators in electronic form, which may have shortened the reporting time. Hence, the underreported volumes for the most recent months are probably less in relative terms than previously. My conclusion is that historical numbers are somewhere in between Dean's and the EIA's estimates.
As regards projections for the rest of this year and 2017, I agree that the EIA's price assumptions are too low. Higher prices may result in higher volumes. That said, I do not expect a quick rebound in drilling/completion activity as most shale companies are in a difficult financial situation and will not rush to increase capex. And even in the shale industry, with its short investment cycle, there is a time lag between a decision to increase capex and first production.
The EIA's projections may be too low, but I still do not expect a quick rebound in the US C+C output.
AlexS. Although maybe not moving the needle much, I think US stripper well production may not decline as much as it has recently because of:AlexS , 04/21/2016 at 3:59 pm
- A. If prices continue to stay above $40 WTI, wells shut in may be put back on production.
- B. As winter is over, it is more likely that low volume wells will be returned to production.
Actually many times both A. & B. apply. We have some wells that must be shut in when the temperature drops below a certain level. Shutting in requires some work, as does resumption of production. When oil prices were high, we would only shut in during the cold weather. This past winter, we just shut in at the first sign of cold weather, and did not start up until winter was over.
I do think, however, US conventional will continue to drop because there are very few vertical oil rigs running, far lower than even in 1998-1999. Also, I do not think a price increase will result in many conventional rigs coming back to the field this year. Balance sheets must be healed first. Conventional producers do not have a shocking decline like the LTO companies, so skipping another year of new wells is not as big of a problem.
Thank you shallow sand,I actually wanted to ask you if you expect a return of shut-in stripper wells with higher oil prices
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oilprice.com
- 17 Apr 2016
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peakoilbarrel.com
Heinrich Leopold , 04/14/2016 at 10:15 am
The sharp reduction of drilling activity shows already some effect on oil production and there are tentative signs of market stabilization:Watcher , 04/15/2016 at 2:54 am
https://www.iea.org/oilmarketreport/omrpublic/
http://oilpro.com/post/23776/falling-us-production-not-doha-move-oil-markets-to-start-stabilizA new definition. Stabilization now means increase. A $1 drop would be market devastating volatility.
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January 17, 2016 | Resource Insights
My favorite Texas oilman Jeffrey Brown is at it again. In a recent email he's pointing out to everyone who will listen that the supposed oversupply of crude oil isn't quite what it seems. Yes, there is a large overhang of excess oil in the market. But how much of that oversupply is honest-to-god oil and how much is so-called
lease condensate which gets carelessly lumped in with crude oil? And, why is this important to understanding the true state of world oil supplies?In order to answer these questions we need to get some preliminaries out of the way.
Lease condensate consists of very light hydrocarbons which condense from gaseous into liquid form when they leave the high pressure of oil reservoirs and exit through the top of an oil well. This condensate is less dense than oil and can interfere with optimal refining if too much is mixed with actual crude oil. The oil industry's own engineers classify oil as hydrocarbons having an API gravity of less than 45--the higher the number, the lower the density and the "lighter" the substance. Lease condensate is defined as hydrocarbons having an API gravity between 45 and 70. (For a good discussion about condensates and their place in the marketplace, read "Neither Fish nor Fowl – Condensates Muscle in on NGL and Crude Markets.")
Refiners are already complaining that so-called "blended crudes" contain too much lease condensate, and they are seeking out better crudes straight from the wellhead. Brown has dubbed all of this the great condensate con.
Brown points out that U.S. net crude oil imports for December 2015 grew from the previous December, according to the U.S. Energy Information Administration (EIA), the statistical arm of the U.S. Department of Energy. U.S. statistics for crude oil imports include condensate, but don't break out condensate separately. Brown believes that with America already awash in condensate, almost all of those imports must have been crude oil proper.
Brown asks, "Why would refiners continue to import large--and increasing--volumes of actual crude oil, if they didn't have to--even as we saw a huge build in [U.S.] C+C [crude oil plus condensate] inventories?"
Part of the answer is that U.S. production of crude oil has been declining since mid-2015. But another part of the answer is that what the EIA calls crude oil is actually crude plus lease condensate. With huge new amounts of lease condensate coming from America's condensate-rich tight oil fields--the ones tapped by hydraulic fracturing or fracking--the United States isn't producing quite as much actual crude oil as the raw numbers would lead us to believe. This EIA chart breaking down the API gravity of U.S. crude production supports this view.
Exactly how much of America's and the world's presumed crude oil production is actually condensate remains a mystery. The data just aren't sufficient to separate condensate production from crude oil in most instances.
Brown explains: "My premise is that U.S. (and probably global) refiners hit in late 2014 the upper limit of the volume of condensate that they could process" and still maintain the product mix they want to produce. That would imply that condensate inventories have been building faster than crude inventories and that the condensate is looking for an outlet.
That outlet has been in blended crudes, that is heavier crude oil that is blended with condensates to make it lighter and therefore something that fits the definition of light crude. Light crude is generally easier to refine and thus more valuable.
Trouble is, the blends lack the characteristics of nonblended crudes of comparable density (that is, the same API gravity), and refiners are discovering to their chagrin that the mix of products they can get out of blended crudes isn't what they expect.
So, now we can try to answer our questions. Brown believes that worldwide production of condensate "accounts for virtually all of the post-2005 increase in C+C [crude plus condensate] production." What this implies is that almost all of the 4 million-barrel-per-day increase in world "oil" production from 2005 through 2014 may actually be lease condensate. And that would mean crude oil production proper has been nearly flat during this period--a conjecture supported by record and near record average daily prices for crude oil from 2011 through 2014. Only when demand softened in late 2014 did prices begin to drop.
Here it is worth mentioning that when oil companies talk about the price of oil, they are referring to the price quoted on popular futures exchanges--prices which reflect only the price of crude oil itself. The exchanges do not allow other products such as condensates to be mixed with the oil that is delivered to holders of exchange contracts. But when oil companies (and governments) talk about oil supply, they include all sorts of things that cannot be sold as oil on the world market including biofuels, refinery gains and natural gas plant liquids as well as lease condensate. Which leads to a simple rule coined by Brown: If what you're selling cannot be sold on the world market as crude oil, then it's not crude oil.
The glut that developed in 2015 may ultimately be tied to some increases in actual, honest-to-god crude oil production. The accepted story from 2005 through 2014 has been that crude oil production has been growing, albeit at a significantly slower rate than the previous nine-year period--15.7 percent from 1996 through 2005 versus 5.4 percent from 2005 through 2014 according to the EIA. If Brown is right, we have all been victims of the great condensate con which has lulled the world into a sense of complacency with regard to actual oil supplies--supplies he believes have been barely growing or stagnant since 2005.
"Oil traders are acting on fundamentally flawed data," Brown told me by phone. Often a contrarian, Brown added: "The time to invest is when there's blood in the streets. And, there's blood in the streets."
He explained: "Who of us in January of 2014 believed that prices would be below $30 in January of 2016? If the conventional wisdom was wrong in 2014, maybe it's similarly wrong in 2016" that prices will remain low for a long time.
Brown points out that it took trillions of dollars of investment from 2005 through today just to maintain what he believes is almost flat production in oil. With oil companies slashing exploration budgets in the face of low oil prices and production declining at an estimated 4.5 and 6.7 percent per year for existing wells worldwide, a recovery in oil demand might push oil prices much higher very quickly.
That possibility is being obscured by the supposed rise in crude oil production in recent years that may just turn out to be an artifact of the great condensate con.
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shallow sand , 04/04/2016 at 12:12 amAlthough it makes little sense, US stocks make a huge impact on the worldwide oil price. Until US inventories meaningfully drop, the oil price will stay low, sub $50.Dennis Coyne , 04/04/2016 at 11:05 amNot seeing a sign of that happening yet. Hopefully will soon.
Hi Shallow sands,Ovi , 04/04/2016 at 8:19 pmIt is strange that anybody pays attention to US crude stocks, for the past 4 weeks average net imports of crude have been about 7.6 Mb/d, there are about 200 Mb of excess crude stocks (above normal levels), reduce imports by 1.6 Mb/d and the excess stocks are drawn down to normal levels in 125 days (about 4 months).
It would make more sense to look at the change in refinery inputs and US crude output.
I also do not understand the focus on inventory. Inventory change is a function of "Crude in less crude out". Inventory can be manipulated by importing more and as a consequence keep pressure on price.likbez , 04/04/2016 at 11:15 amWhy does inventory keep going up? It is related to the contango in the oil futures market. In the attached table the front month contango is $1.34, today. If an investor owns storage, he can take delivery today and sell one month forward for a gain of $1.34 less about 50¢ for storage costs. As long as the front month contango stays above $1, inventory will continue to grow.
Although it makes little sense, US stocks make a huge impact on the worldwide oil price.Very true.
At this stage of oil price cycle I do not think that the size of inventories is a material factor, affecting the oil price. It is played as such by Wall Street, but that's just reflects the power of "paper oil" producers. They can choose something else (S&P transportation index readings, for example) and use it to depress the oil price.
What it probably reflects at this stage of the cycle is the level of pure greed.
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oilprice.com
By Irina Slav
Posted on Sat, 26 March 2016 00:00 | 0 After the slow and painful death of Canadian oil exports - helped along by crashing oil prices, a global supply glut, and the languishing Keystone XL Pipeline - Canada has opened up some other outlets for exporting its crude oil to refineries on the U.S. Gulf Coast, experiencing a two-fold increase since 2014.According to new data, Canadian crude oil exports to U.S. Gulf Coast refineries topped 389,000 barrels per day last year-double the amount in 2014-and it was all made possible by new pipelines that came on stream over the course of last year.
The three new pipelines to the Gulf Coast-Seaway, Southern Access, and Cushing Marketlink-added a combined throughput capacity of 1.85 million bpd to the transport system for crude between Canada and the U.S., said Canada's National Energy Board's market analyst Melissa Merrick.
Related: Offshore Lease Sale Disrupted by Protestors Shouting "Shut it Down"
All in all, Canada exported most of its 3.87 million bpd output, or 3.035 million barrels. Of this, 3.009 million barrels went to the U.S.
In the first week of January , Canadian crude oil exports to the U.S. reached an all-time record of 3.4 million barrels per day, according to preliminary data from the U.S. Energy Information Administration (EIA).
However, while this is good news for Canada, the figures aren't quite as sensational as the headlines tend to be. The actual amount heading to the U.S. Gulf Coast is a relatively small portion of overall Canadian crude exports to its southern neighbor. The bulk goes to the U.S. Midwest, which received 1.916 million bpd last year from Canada.
At the same time, oil imports also increased , to 736,000 bpd, of which crude from down south accounted for 62.4 percent, or almost 500,000 bpd, up from around 340,000 bpd in 2014.
What's more, according to Beth Lau from the Canadian Association of Petroleum Producers, the twofold increase is unlikely to be repeated this year because there is not enough throughput capacity.
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This brings us back around to Keystone XL, which could have added 830,000 bpd of throughput capacity to the pipelines carrying crude to the Gulf Coast refineries had it not been cancelled by the Obama administration in November 2015. That's not an insignificant amount of oil capacity, given the fact that Western Canadian Select (WCS) is trading at a substantial discount to WTI. The May contract for the Canadian crude closed at a bit over $13 per barrel on March 24, while WTI is well over $30 at the moment.
$80 Oil By June – Do NOT Be Fooled By The Mainstream MediaThe current market turmoil has created a once in a generation opportunity for savvy energy investors.
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WCS is a real bargain for U.S. refineries. But it's not going to come through Keystone.
But the absence of Keystone simply means that Canadian crude has to find other routes, both rail and alternative pipelines.
TransCanada , the would-be operator of Keystone XL, has now agreed to buy Houston-based Columbia Pipeline Group Inc. for $10.2 billion, which owns some 15,000 miles of gas pipeline running from New York to the Gulf of Mexico, along with one of the biggest underground storage systems in the U.S.
Related: $40 Billion LNG Project In Australia Cancelled Amid Low Prices
At the end of the day, some believe that Canadian export figures indicate that Canada is gaining U.S. market share as a result of the oil price crisis, and as U.S. shale production gets shut in, waiting for better days.
"That's the one piece of puzzle you don't hear too much about - the market share Canada is gaining in the U.S.," said Carl Evans, senior crude oil analyst at energy research firm Genscape, told the Financial Post .
But you don't hear too much about it because it's a bit of a red herring. According to Platts , Alberta's crude is selling at a major discount because it doesn't have enough export outlets. That means that if it wants to get overseas, it's got to go through the U.S. for the most part, and even then, pipeline space is limited and more expensive (and dangerous) rail is often the only option.
By Irina Slav of Oilprice.com
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fuelfix.com
4) The drop of 4.5 million barrels for gasoline inventories was split betwixt PADD 1 (East Coast) and PADD 3 (Gulf Coast). While the drop can in part be attributed to winter blend stocks being drawn down, the driving force (pardon the pun) has been rising demand. On the more-reliable, less-noisy four-week moving average, gasoline product supplied is up 7% year-on-year. Robust.
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RBN Energy
5. It is nice that condensate exports are legal, but the economics of condensate exports don't make much sense.We hated to disappoint all those hopeful condensate exporters last year, but the handwriting was on the wall. Regardless of unfettered export regs, if it is worth more here than it is there, then you ought to keep it here. Only about 100 Mb/d of newly legal condensate exports left U.S shores in 2015, because the economics were upside down. A harbinger of things to come for crude exports? Absolutely.
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oilprice.com
March 09, 2016 | OilPrice.comIf any of you have seen my early writings on OilPrice.com, you would know I have been steadfast in my criticism of the media exaggerating the extent of the oil glut. Furthermore, I have also documented the pattern of exaggeration from both the EIA/IEA with their statistics.
I realize that no one is perfect, forecasting the future is notoriously difficult, and these entities have their difficulties in obtaining reliable and timely data to make accurate predictions. However, the IEA in particular has a track record of overstating oil supplies – even back in 1999 the agency was questioned for exaggerating a supply glut, and now it seems to have occurred again.
Related: Chevron Protects Dividend, Cuts Another 36 Percent Off Spending
(Click to enlarge)
The chart above shows the "missing barrels," unexplained oil volumes that have shown up in IEA data over time. John Kemp from Reuters, who has done some of the best coverage of the market, put together this data to illustrate the problem with the reported data. He recently wrote this piece, confirming all my suspicions of the past. In it he states the following:
"Of the 1 billion barrels reportedly produced but not consumed, roughly 420 million are being stored on land in member countries of the Organization for Economic Cooperation and Development (OECD). Another 75 million barrels are thought to be stored at sea or in transit by tanker somewhere from the oil fields to the refineries. That leaves 550 million "missing barrels" unaccounted for, apparently produced but not consumed and not visible in the inventory statistics..."
Related: Six Reasons The Current Oil Short Covering May Have Legs
$80 Oil By June – Do NOT Be Fooled By The Mainstream MediaThe current market turmoil has created a once in a generation opportunity for savvy energy investors.
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So, in other words, OVER HALF of the supposed glut that the IEA has reported is unaccounted for. Not 5 or 10 percent, but greater than a whopping 50 percent. Does anyone believe that half of the glut is just missing?
In the article John explains that it could be in hidden or unaccountable locations. But that doesn't seem credible. It is hard to believe that HALF of the entire world's excess supply cannot be justified with the data? At $40 oil, that is some $22 billion in oil that is squirreled away somewhere that millions of people simply don't know where it is?
Related: How Algorithmic Trading Makes Money On Energy
Yet does anyone care to even question such non-sense? No, of course not, just like every other government statistic that is taken at face value and traded on by headline-driven algorithms. There used to be a time when Wall Street did real research, but that appears to be gone now. Either demand has been understated by the IEA, or supply has been vastly overstated...any rational person would conclude the same.
Please view my video channel for further insight on this topic: https://www.youtube.com/channel/UCkA46F9sbOLfDVM0V17sZcw
By Leonard Brecken for Oilprice.com
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Mar 08, 2016 | Reuters.com
Where has the oil gone? Missing barrels and market rebalancing: Kemp Fuel pumps are pictured at a gas station in Sidi Allal El Bahraoui, Morocco, February 7, 2016. REUTERS/Youssef Boudlal Fuel pumps are pictured at a gas station in Sidi Allal El Bahraoui, Morocco, February 7, 2016. Reuters/Youssef Boudlal Where has the oil gone? Missing barrels and market...X By John Kemp LONDON (Reuters) - Global oil production exceeded consumption by just over 1 billion barrels in 2014/15, according to the International Energy Agency (IEA).Production exceeded consumption by an average of 0.9 million barrels per day in 2014 and 2.0 million bpd in 2015 (tmsnrt.rs/1pvIEw8).
Of the 1 billion barrels reportedly produced but not consumed, roughly 420 million are being stored on land in member countries of the Organisation for Economic Cooperation and Development (OECD). Another 75 million barrels are thought to be stored at sea or in transit by tanker somewhere from the oil fields to the refineries.
That leaves 550 million "missing barrels" unaccounted for, apparently produced but not consumed and not visible in the inventory statistics ("Oil Market Report", IEA, Feb. 2016).
Missing barrels are recorded in the "miscellaneous to balance" line of the IEA's monthly Oil Market Report as the difference between production, consumption and reported stock changes. The miscellaneous item reflects errors in data from OECD countries, errors in the agency's estimates for supply and demand in non-OECD countries, and stockpile changes outside the OECD that go unrecorded. IEA data currently shows a miscellaneous to balance item of 0.5 million barrels per day in 2014 and 1.0 million barrels per day in 2015. Missing barrels have been a feature of IEA statistics since the 1970s ("International Energy Agency: How the Agency Prepares its World Oil Market Statistics", U.S. General Accounting Office, 1999).
Over time, errors have occurred in both directions, and have ranged up to 1 million or even 2 million barrels per day (tmsnrt.rs/1pvIBjQ). Most of the time, the oil market ignores the miscellaneous to balance item, but it tends to become controversial when it becomes very large, either positive or negative.
ERRORS AND OMISSIONS
The last time the miscellaneous to balance item was this large and positive (implying an oversupplied market) was in 1997/98 when the issue triggered fierce criticism of the IEA's statistics. Critics accused the IEA of over-estimating supply, under-estimating demand, contributing to perception of a glut, depressing prices, and causing unnecessary hardship to the oil industry ("There Are No Missing Barrels", Simmons, 1999). Senator Pete Domenici, chairman of the U.S. Senate Budget Committee, asked the General Accounting Office to investigate the IEA's statistics and the question of missing barrels. In a report published in May 1999, GAO concluded "missing barrels are not a new condition, and the amount and direction of missing barrels have fluctuated over time". "At any point in time, the historical oil supply and demand as well as the stock data reported by IEA could be overstated or understated by an unknown magnitude." It was not possible to "quantify how much of the missing barrels are due to statistical limitations and how much are the result of physical oil storage in unreported stocks". In 1997/98 episode, the IEA concluded most of the missing barrels went into non-OECD storage and uncounted OECD inventories ("Oil Market Report", IEA, June 1999).
In the current episode, it is also very likely some of the 550 million barrels unaccounted for in 2014/15 have gone into unreported storage outside the OECD. China's government is known to have been filling its Strategic Petroleum Reserve. More barrels are likely to have gone into commercial storage in China and in other countries outside the OECD. But it is at least possible some of the missing barrels have been caused by the IEA over-estimating oil supplies or under-estimating demand.
CLEARING THE OVERHANG
The question of what has happened to the missing barrels, and whether some of them exist at all, is critical because it could affect how quickly the oil market rebalances. The IEA and most other forecasters predict the oil market will remain oversupplied throughout 2016 and the first half of 2017, ensuring stockpiles continue growing. In its "Medium-Term Oil Market Report", published last month, the IEA predicted consumption would not exceed supply on a full-year basis until 2018. Some analysts argue the market will need to eliminate the excess supply and work down some proportion of the inherited stocks before oil prices can rise sustainably. With the oil market expected to remain in surplus throughout 2016 and "already awash in oil" the IEA has said that "it is very hard to see how oil prices can rise significantly in the short term." To the extent the miscellaneous to balance item reflects oil that has gone into unreported storage, it will take longer to clear the overhang of stocks that built up in 2014/15 and continue to build in 2016. But to the extent the missing barrels are the result of over-estimating supply and under-estimating demand, or have been absorbed into China's strategic stocks, the overhang could clear more quickly.
POSSIBLE PRODUCTION FREEZE
Following the 1997/98 episode, the missing barrels that accumulated in unreported non-OECD storage were drawn down in 1999, according to the IEA ("Oil Market Report", IEA, Dec 1999). In December 1999, the IEA wrote: "The weight of (the) evidence is that the missing barrels did exist and that they have now returned to the market." "The return was triggered by the reversal in the shape of the forward price curve and the need for additional barrels following OPEC's effective production limitation" which began in March 1999. By the end of 1999, the oil market was seeing excess demand and prices were rising. But the rapid recovery depended on very strong economic growth in North America and Asia (after the East Asian financial crisis in 1997/98). It also depended on substantial production cuts by OPEC in conjunction with production restraint from non-OPEC countries.
And it was both heralded and caused by a shift in the forward price curve from contango to a state of backwardation (which made oil less profitable to store). The events of 1999 illustrate the factors needed to clear an inherited glut of oil (strong demand, production restraint and a shift in the shape of the forward price curve). Current circumstances share some similarities with 1998/99 but there are also important differences which should not be overlooked. The current stock build has been caused by oversupply thanks to the shale revolution rather than a slowdown in demand as in the 1997/98 Asian financial crisis. The winter of 1997/98 also saw a strong El Nino, which suppressed oil demand as it has this winter.
The current oversupply is not as bad as it was in the earlier episode, and the missing barrels problem is much smaller. The smaller (relative) surplus should make rebalancing faster this time around. In 1997/98, the market was oversupplied by 2.1 million barrels per day compared with total demand of around 74 million barrels per day, according to the IEA. In 2015, the oil market was also oversupplied by 2.0 million barrels per day but consumption was running at more than 94 million barrels per day, around 25 percent higher. At present, oil demand is growing strongly, just as it was in 1999, though there are concerns about the health of the global economy.
The major oil exporting countries have not so far agreed to cut production, unlike 1998/99, but there has been discussion about a possible production freeze. Futures prices remain resolutely in contango, which is both a symptom of excess stockpiles and creates a financial incentive to continue holding them. There is no sign of the market moving into backwardation yet, which would indicate the supply-demand balance was shifting and would also create a financial incentive to release oil from storage. Several key OPEC and non-OPEC producers have announced a provisional production freeze which could speed up the rebalancing, assuming it is implemented. But it might not be enough to eliminate the glut quickly; outright production cuts may be needed to accelerate the process, depending on what happens to demand and production from other countries.
(Editing by David Evans)
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peakoilbarrel.com
AlexS, 03/09/2016 at 9:23 amAlexS, 03/09/2016 at 9:36 amThe EIA has further reduced its forecast for U.S. oil production in 2016-17 (by 200-300 kb/d for 2017).
Apparently this is related with lower oil price assumptions, which are based on futures prices, and the recent cuts in E&P companies capex guidance.From the report (STEO, March 2016):
"U.S. crude oil production is projected to decrease from an average of 9.4 million b/d in 2015 to 8.7 million b/d in 2016 and to 8.2 million b/d in 2017. The forecast reflects an extended decline in Lower 48 onshore production driven by persistently low oil prices that is partially offset by growing production in the federal Gulf of Mexico.
EIA estimates total U.S. production has fallen 0.6 million b/d since April 2015, to an average of 9.1 million b/d in February, with the entire production decline coming from Lower 48 onshore. With WTI prices currently below $40/b and projected to remain below that level through the first half of 2017, EIA expects oil production to decline in most Lower 48 onshore oil production regions.The expectation of reduced cash flows in 2016 and 2017 has prompted many companies to scale back investment programs, deferring major new undertakings until a sustained price recovery occurs. The prospect of higher interest rates and tighter lending conditions will likely limit the availability of capital for many smaller producers, giving rise to distressed asset sales and consolidation of acreage holdings by more financially sound firms.
EIA expects U.S. crude oil production to decline from 9.1 million b/d in the first quarter of 2016 to an average of 8.0 million b/d in the third quarter of 2017. Production of 8.0 million b/d would be 1.7 million b/d below the April 2015 level, which was the highest monthly production since April 1971. Production is expected to begin increasing modestly in the fourth quarter of 2017, as productivity improvements, lower breakeven costs, and anticipated oil price increases are expected to end more than two years of declines in the Lower 48. The forecast remains sensitive to actual wellhead prices and rapidly changing drilling economics that vary across regions and operators.
Projected crude oil production in the Gulf of Mexico rises during the forecast period, and oil production in Alaska falls."
U.S. C+C production: STEO March 2016 vs. Feb. 2016
AlexS, 03/09/2016 at 9:40 amProjections for Lower 48 states (ex GoM) production in 2017 were revised down by 310 kb/d in 2017,
including a 350 kb/d revision for 4Q17.
EIA now expects Lower 48 output to decline from the peak of 7.73 kb/d in March 2015 to 5.84 kb/d in October 2017 (-1.88 kb/d)Lower 28 states (excl. GoM) C+C production: STEO March 2016 vs. Feb. 2016
shallow sand, 03/09/2016 at 10:02 amWTI oil price assumptions (based of futures prices)
ND rigs at 33. Burlington has one to stack. My estimate is rigs will bottom at 26-27.
EIA oil price projections are unrealisticly low IMO. Removing 1.5 million bopd from USA, plus world wide demand growth of 1-1.2 in 2016, plus other worldwide declines that Ron has illustrated, add up to more than Iraq and Iran can boost production. KSA appears to be incapable of going past 10.5 million. Russia cannot quickly increase production.
Things can change fast regarding oil prices, witness the volatility since 1/1/16. We are hearing there could be a real supply squeeze coming and are seeing real evidence of that anticipation based upon some long term offers to hedge well above the current strip, sharply increased local basis and refinery planning chatter. All are anecdotal, but are not signifying worries of tanks topping.
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www.eia.gov
Brent crude oil spot prices increased by $1/b in February to a monthly average of $32/b. Accelerating reductions in the U.S. rig count and market reactions to news of a potential OPEC/non-OPEC supply freeze gave support to oil prices in February that offset the downward price pressure from ongoing growth in global oil inventories and uncertainty over the strength of global oil demand growth.With large global oil inventory builds expected to continue in 2016, oil prices are expected to remain near current levels. Forecast Brent prices average $34/b in 2016, $3/b lower than forecast in last month's STEO.
Global oil inventories are expected to grow by an average of 1.6 million b/d in 2016 and by 0.6 million b/d in 2017, both higher than in last month's STEO. Inventory builds are higher in this month's STEO as a result of recent updates to historical data showing continued resilience from non-OPEC oil producers in the current low-price environment and as a result of a reduction in forecast global oil demand growth. Higher forecast inventory builds and slower market rebalancing contribute to a more limited price recovery in 2017 than previously forecast, with Brent prices forecast to average $40/b, $10/b lower than in last month's STEO. Prices reach an average of $45/b in the fourth quarter of 2017, as the oil market becomes relatively balanced at that point, with the potential for inventory draws beyond the forecast period.
Forecast West Texas Intermediate (WTI) crude oil prices average the same as Brent crude oil prices through the forecast period. The price parity of WTI with Brent in the forecast period is based on the assumption of competition between the two crudes in the U.S. Gulf Coast refinery market, as transportation differentials are similar to move the crudes from their respective pricing points to that market.
The expectation of continuing large inventory builds is a major source of uncertainty in the price forecast, as the capacity of global oil storage to absorb builds of the forecast magnitude is unknown. If global storage capacity becomes stressed, the cost of storage will rise to reflect more expensive marginal storage options such as floating inventories on crude oil tankers. The higher storage costs would lower near-month crude oil prices. Additional uncertainty stems from the pace of global economic growth and its contribution to oil demand growth, and also from the responsiveness of oil producers to sustained low oil prices.
The current values of futures and options contracts highlight the heightened volatility and high uncertainty in the price outlook (Market Prices and Uncertainty Report) . WTI futures contracts for June 2016 delivery, traded during the five-day period ending March 3, averaged $37/b, while implied volatility averaged 50%. These levels established the lower and upper limits of the 95% confidence interval for the market's expectations of monthly average WTI prices in June 2016 at $24/b and $58/b, respectively.
The 95% confidence interval for market expectations widens over time, with lower and upper limits of $20/b and $81/b for prices in December 2016. At this time last year, WTI for June 2015 delivery averaged $54/b, and implied volatility averaged 46%. The corresponding lower and upper limits of the 95% confidence interval were $36/b and $80/b.
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peakoilbarrel.com
Rush of demand for oil storage while oil is available at below $40 prices:With available storage facilities for oil filling up in Houston, Fairway Energy Partners said the time is right for the 11 million barrels of crude storage space it's currently developing.
Fairway Energy Partners plans to convert three salt dome caverns more than 2,000 feet under Southwest Houston into crude oil storage. The company, which is backed by Haddington Ventures, is targeting a completion date of late 2016.
… … …
The Texas Gulf Coast has about 128 million barrels stored at refineries and terminals. It's also about 60 percent full, Genscape said.
… … …
"We're seeing storage levels that we've never seen across the U.S.," Hilgert said. "Crude is piling up everywhere, Cushing is effectively full, and that's started to domino down to the Gulf Coast."
I think frenzied hoarding of oil in anticipation of higher prices is the phenomenon that MSM does not cover. They try to sell it under "oil glut" banner.
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www.eia.gov
The Drilling Productivity Report uses recent data on the total number of drilling rigs in operation along with estimates of drilling productivity and estimated changes in production from existing oil and natural gas wells to provide estimated changes in oil and natural gas production for seven key regions. EIA's approach does not distinguish between oil-directed rigs and gas-directed rigs because once a well is completed it may produce both oil and gas; more than half of the wells produce both.While shale resources and production are found in many U.S. regions, at this time EIA is focusing on the seven most prolific areas, which are located in the Lower 48 states. These seven regions accounted for 92% of domestic oil production growth and all domestic natural gas production growth during 2011-14.
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peakoilbarrel.com
Gaurav , 03/06/2016 at 11:29 pmRon, I am a regular reader of your blog and find it very insightful. I have not seen much written about Oil super contango and reasons for oil storage at multi decade high so would like to highlight below.When there is a temporary over supply, it fills up storage, as more and more storage get filled up it leads to an increase in storage cost. This in turn lead to a contango, meaning future oil prices being at premium. Currently premium stands at 20% for 1 year forward contract. This is super contango and a bonanza for oil traders. If you can find a place to store oil you can make risk free returns of 20% – (storage cost). So, why storage space are filling up so fast its because commodity traders are scrambling to make this trade. It's a positive feedback loop. It can only end when supply falls below the consumer demand.
So, bottom line is, filling up of oil storage early in the cycle is an indicator of oversupply. But in the current late cycle of low oil prices [1.5 yrs already] it is a useless indicator of future oil price movement, oil demand or supply.
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January 20, 2015 | finance.yahoo.com
Traders are in a mad dash to rent some of the world's biggest oil tankers so they can store crude while prices remains in record-low territory.
The Wall Street Journal reports that TI Oceania, which has been booked by oil traders Vitol, is stationed off Singapore and is likely to remain there for most of 2015.
China's Unipec booked Oceania's sister ship, TI Europe, way back in September, when oil prices dropped below $100 per barrel (let's hope they didn't buy the oil then).
The ships are giant. Here's the TI Europe, for example:
Christelle Hall, YouTube
As oil prices continue to plunge amid a supply glut and weaker demand, companies reckon they can make more money from simply hoarding the oil and selling it at later date, when prices rebound.
This phenomenon is known as "contango," a term for when the price of commodity futures is higher than the current price. In this case, traders believe there is more money to be made from simply sitting on oil, if they can bear the costs of storing it.
Euronav
Oil prices will stay low if there continues to be space to store it. However, once storage is full, producers will finally be forced to slow output because there will not be anywhere to put the surplus. From that point, the price has a chance to rebound, assuming demand doesn't keep falling.
According to Goldman Sachs, however, that turnaround probably won't happen as quickly while more firms decide to store rather than sell oil. The investment bank is expecting a slow "u-shaped" recovery, rather than a rapid "v-shaped" bounce in prices:
Not only has the US expanded storage capacity significantly, but Europe has also shuttered refining capacity that can be used as storage, and the global crude tanker fleet has grown by 100 million dwt since 2008 - while oil at sea has remained stagnant given the dominance of onshore drilling. We believe at least a 1.0 million barrel per day surplus can be maintained for a year before any significant problems would arise.
Goldman Sachs
NOW WATCH: This Video Of The Largest Breakage Of Ice From A Glacier Ever Filmed Is Absolutely Frightening
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peakoilbarrel.com
kamakiri , 03/01/2016 at 4:54 am
"The EIA continues to underestimate US oil production in its forecasts."I think they have a tendency to underestimate in rising conditions, but will overestimate in falling conditions.
http://cdn.oilprice.com/images/tinymce/2016/ThisSC2.jpg
from this article:
http://oilprice.com/Energy/Energy-General/Is-The-EIA-Too-Optimistic-On-US-Oil-Output.htmlTheir weekly estimates appear to lag actual inflections by 2-3 months.
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peakoilbarrel.com
likbez , 03/01/2016 at 9:49 am
If we assume error margin 1% for EIA data that means that EIA data should be rounded to two meaningful digits before making any conclusions.Jeffrey J. Brown , 03/01/2016 at 9:54 amThat makes minimum meaningful difference 100,000 bbl. Everything below that should be considered to be statistical noise.
In other words EIA operating with four meaningful digit on the data with error margin at or above 1% is just a sophisticated form of deception of (mathematically challenged) public creating an impression of precision were it does not exist.
And if the addition is below the error margin it can't be considered statistically meaningful because the value 9,262 is in reality an interval from 9.162 to 9.362 within which the precise value lies.
I generally try to use two significant figures, e.g., global C+C production increased from 74 million bpd in 2005 to 78 million bpd in 2014.
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peakoilbarrel.com
likbez , 02/29/2016 at 4:31 pmAlex,AlexS , 02/29/2016 at 6:01 pmU.S. oil production in December 2015 was 9,262 kb/d,
65 kb/d higher than the EIA's forecast in the February Short-Term Energy Outlook (9,197 kb/d)One percent (probably the most charitable estimate of error margin for EIA STEO ) for 9,262 kb/d will be 93 kb/d
From this point of view your statement does not make any sense. Those two values are equal within the margin or error +-93.
likbez,likbez , 02/29/2016 at 11:17 pmThe 65 kb/d difference between the most recent estimate for December 2015 published on Feb 29 and previous estimate issued on Feb 12 is a fact
How can a fact make no sense?My statement is that the EIA has been constantly underestimating US oil production volumes and therefore had to revise upwards its previous forecasts.
Thus, the estimate for September 2015 has been revised by 480 kb/d between September STEO and today's Monthly Production Report (MPR).
Compared to 480 kb/d, 65 kb/d is not much, but there might be further revisions.EIA's US monthly oil production estimates for 2015: from STEO Sep.15 to MPR Feb.16
Alex,My statement is that the EIA has been constantly underestimating US oil production
IMHO you are missing possible correlation of "misunderestimation" of US oil production with "cheerleading" of oil price slump. Please note that this is not about some "wild" conspiracy theory :-)
As unforgettable Bush II said "I've been misunderestimated most of my life." North Charleston, South Carolina; February 15, 2016
and
"There's an old saying in Tennessee-I know it's in Texas, probably in Tennessee-that says, 'Fool me once, shame on…shame on you. Fool me - you can't get fooled again.'"[12] - Nashville, Tennessee; September 17, 2002
The same is true about EIA estimates of the USA oil production :-)
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peakoilbarrel.com
Amatoori, 02/28/2016 at 11:31 amA good but long podcast with Art Berman, not so much new stuff for the people here but gives a great over all picture on the oil market right now.http://www.macrovoices.com/podcasts/MacroVoices-2016-02-25-Art-Berman.mp3
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peakoilbarrel.com
Amatoori , 02/25/2016 at 11:40 am
http://in.reuters.com/article/oil-demand-kemp-idINL8N1644QUJef , 02/25/2016 at 6:28 pmNice piece of the puzzle Amat. Distillates is the glut.likbez , 02/25/2016 at 8:25 pmSO diesel demand has been tanking but gas remains strong. The economy is tanking but people are still driving around in circles.
Amatoori,Toolpush , 02/25/2016 at 10:40 pmVery good --
Some (albeit vague) support for a growing day-by-day "glut deniers" movement :-) . The newer part of the the argument revolves on fixed ratio of gasoline to distillate in refining process. Which supposedly caused a growth of distillate inventories due to weather induced low demand :
In the last year, U.S. refiners have been fairly successful in matching gasoline production and stockpiles with demand. Gasoline production remains at the centre of their operational planning.
Crude stocks have continued to increase, reflecting worldwide oversupply, though stockpiles are rising somewhat more slowly than at the start of 2015.But refiners lost control of distillate stocks in the second half of 2015 as freight demand slowed and El Nino ensured a warmer than normal winter across the United States and other parts of the northern hemisphere.
Winter heating demand across the United States has been around 17 percent below average, according to the National Oceanic and Atmospheric Administration.
And by the end of 2015, the volume of freight being moved across the United States by road, rail, pipeline, barge and air had fallen by more than 2 percent compared with the same period at year earlier.
Over the last four weeks, U.S. implied distillate consumption has averaged just 3.5 million barrels per day, which is 12 percent below the long-term average and 16 percent below the same period in 2015.
The fact that refiners have lost control of distillate stocks should come as no surprise because distillate is essentially a by-product of gasoline production.
Refineries have operated to maximise gasoline production but in the process created an enormous and growing oversupply of distillate.
There is some limited flexibility in the refining system to switch from distillate production to gasoline but it is typically only on the order of a few percentage points.
Massive overproduction of distillate has pushed gross refining margins for the fuel to the lowest level since 2010.
But refining margins for gasoline have been much healthier, at least until recently, which has encouraged refiners to continue maximising crude throughput.
As long as gasoline demand remains strong, refiners will continue to meet it, which is why the outlook for U.S. gasoline consumption is so critical for the oil market in 2016.
Amatoori,likbez , 02/25/2016 at 11:46 pmIt always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
I would have thought, the EROI boys would be all over it. As I feel this is where the theory of EROI being very low for unconventional oil and gas, actually starts to show up in day to day numbers.
Hi Toolpush,It always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
You made a very good point -- Thank you.
As EROEI boys are lazy bunch let me fill in. Let's assuming EROEI 10 for shale oil (which might be charitable; some sources claim 3-5)
https://en.wikipedia.org/wiki/Oil_shale_economics#Energy_usageA 1984 study estimated the EROEI of the different oil shale deposits to vary between 0.7–13.3:1.[21] More recent studies estimates the EROEI of oil shales to be 1–2:1 or 2–16:1 – depending on if self-energy is counted as a cost or internal energy is excluded and only purchased energy is counted as input.[20][22] According to the World Energy Outlook 2010, the EROEI of ex-situ processing is typically 4–5:1
So we need 4.2 gallon per bbl.
The EIA estimates in the Annual Energy Outlook 2015, that about 4.2 million barrels per day of crude oil were produced directly from tight oil resources in the United States in 2014.
So we are talking about 0.4 Mb/day of diesel consumption. Which is respectable 10% out of 4 Mb/d total US distillates consumption. So 2% drop (which amount to 20% drop of diesel consumption in oil patch) might be fully attributable to the lower activity of shale patch.
In other words you are right --
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Amatoori , 02/25/2016 at 11:40 am
http://in.reuters.com/article/oil-demand-kemp-idINL8N1644QUJef, 02/25/2016 at 6:28 pmNice piece of the puzzle Amat. Distillates is the glut.likbez, 02/25/2016 at 8:25 pmSO diesel demand has been tanking but gas remains strong. The economy is tanking but people are still driving around in circles.
Amatoori,Very good --
Some (albeit vague) support for a growing day-by-day "glut deniers" movement :-) . The newer part of the argument revolves around the fixed ratio of gasoline to distillate in refining process. Which supposedly caused a growth of distillate inventories due to the weather induced low demand :
In the last year, U.S. refiners have been fairly successful in matching gasoline production and stockpiles with demand. Gasoline production remains at the centre of their operational planning.
Crude stocks have continued to increase, reflecting worldwide oversupply, though stockpiles are rising somewhat more slowly than at the start of 2015.But refiners lost control of distillate stocks in the second half of 2015 as freight demand slowed and El Nino ensured a warmer than normal winter across the United States and other parts of the northern hemisphere.
Winter heating demand across the United States has been around 17 percent below average, according to the National Oceanic and Atmospheric Administration.
And by the end of 2015, the volume of freight being moved across the United States by road, rail, pipeline, barge and air had fallen by more than 2 percent compared with the same period at year earlier.
Over the last four weeks, U.S. implied distillate consumption has averaged just 3.5 million barrels per day, which is 12 percent below the long-term average and 16 percent below the same period in 2015.
The fact that refiners have lost control of distillate stocks should come as no surprise because distillate is essentially a by-product of gasoline production.
Refineries have operated to maximise gasoline production but in the process created an enormous and growing oversupply of distillate.
There is some limited flexibility in the refining system to switch from distillate production to gasoline but it is typically only on the order of a few percentage points.
Massive overproduction of distillate has pushed gross refining margins for the fuel to the lowest level since 2010.
But refining margins for gasoline have been much healthier, at least until recently, which has encouraged refiners to continue maximising crude throughput.
As long as gasoline demand remains strong, refiners will continue to meet it, which is why the outlook for U.S. gasoline consumption is so critical for the oil market in 2016.
Toolpush, 02/25/2016 at 10:40 pm
likbez, 02/25/2016 at 11:46 pmAmatoori,
It always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
I would have thought, the EROI boys would be all over it. As I feel this is where the theory of EROI being very low for unconventional oil and gas, actually starts to show up in day to day numbers.
Hi Toolpush,It always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
You made a very good point -- Thank you.
As EROEI boys are lazy bunch let me fill in. Let's assuming EROEI 10 for shale oil (which might be charitable; some sources claim 3-5)
https://en.wikipedia.org/wiki/Oil_shale_economics#Energy_usageA 1984 study estimated the EROEI of the different oil shale deposits to vary between 0.7–13.3:1.[21] More recent studies estimates the EROEI of oil shales to be 1–2:1 or 2–16:1 – depending on if self-energy is counted as a cost or internal energy is excluded and only purchased energy is counted as input.[20][22] According to the World Energy Outlook 2010, the EROEI of ex-situ processing is typically 4–5:1
So we need 4.2 gallon per bbl.
The EIA estimates in the Annual Energy Outlook 2015, that about 4.2 million barrels per day of crude oil were produced directly from tight oil resources in the United States in 2014.
So we are talking about 0.4 Mb/day of diesel consumption. Which is respectable 10% out of 4 Mb/d of the total US distillates consumption. So 2% drop (which amount to 20% drop of diesel consumption in oil patch) might be fully attributable to the lower activity of shale patch.
In other words you are right --
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Watcher, 02/23/2016 at 3:02 pmYes, has anyone noticed swimming pools filled with oil in their neighborhood?Dennis Coyne , 02/23/2016 at 3:41 pmI haven't.
Why would anyone let oil go on a tanker and leave port unless they were paid for it? Answer: They wouldn't. They get paid for it because they had an order for it and filled the order. Why would they cut output and refuse to fill customer orders?
So who placed an order for oil they weren't going to sell to someone else who would then burn it? Answer: No one did. They had customers and the customers placed orders for it because they needed to burn it, and then took possession of it and burned it.
Why contort thinking on this? It's simple and clear.
Hi Watcher,AlexS , 02/23/2016 at 4:05 pmYes it is very clear that there is an excess of oil being produced and that is why prices are so low, to everyone except you.
Watcher , 02/23/2016 at 5:22 pm"Why would anyone let oil go on a tanker and leave port unless they were paid for it? "This is a common practice. The tankers leave ports and can several times change directions as the owner/seller of oil is trying to find the best buyer.
Interesting. How about offloading? That ever happen without paying the producer? Because if the theory proposed here is all the storage is in tankers, you're going to have to find about a billion barrels sitting unpaid for - all whilst KSA says they produce what they have orders for.AlexS , 02/23/2016 at 5:46 pmRead, for example, this article:Watcher , 02/23/2016 at 6:18 pmWhy oil speculators are turning to ships as floating storage
The Globe and Mail, Monday, Feb. 22, 2016
http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/why-oil-speculators-are-turning-to-ships-as-floating-storage/article28846311/Other recommended reading:
IEA Oil Market Report, January 2016, p.33
AlexS , 02/23/2016 at 7:14 pmAbout 20 to 25 of the world's 650 supertankers, which can hold two million barrels and are called very large crude carriers, are in use as floating storage,That's 2 X 25 = 50 million barrels. The alleged oversupply of 3 mbpd for 20 mos (since June 2014) is 20 X 30 X 3 = 1.8 billion barrels.
Do they offload without paying the producer?
There was never 3 mb/d oversupply, not to say for 20 months. The oversupply peaked at 2.2-2.4mb/d in 2Q15, according to various estimates (see the chart below).Watcher , 02/23/2016 at 9:52 pmFrom IEA OMR, January 2016:
"A notional 1 billion barrels of oil was added to global inventories over 2014 – 2015 and our latest supply and demand balances suggest builds will persist with up to 285 mb expected to be added to stocks over the course of 2016. Despite estimations of current space storage capacity and the outlook for significant capacity expansions over 2016, this stock build will likely put midstream infrastructure under pressure and could see floating storage become profitable. "
The volume in floating storage is a small part of total global inventories. It can belong to producers (particularly, the NOCs) or to large traders.
One more time. Do they offload without paying the producer? "I don't know" is an entirely solid answer.AlexS , 02/23/2016 at 10:41 pmWho "they"?likbez , 02/23/2016 at 10:50 pmOil stored in tankers may belong to:
- Oil producers, particularly the NOCs (national oil companies). For example, Iran's ~40 million barrels of crude and condensate stored in tankers belongs to the Iranian national oil company.
- Oil traders, who have bought that oil and are storing it in tankers in a hope that they could sell it later at a higher price.
Alex,AlexS , 02/23/2016 at 11:35 pmCan you please explain how in oversupplied Europe Iran suddenly found customers for more then 0.3 Mb/d (Italy, Greece and France; Spain is next).
You should see inventories rising by the same amount because according to the "oil glut" theory this oil can't be consumed, don't you ? And 0.3Mb/d is 9 Mb/month. Most large oil contracts are long term and you can't break them without penalties.
Also in the USA no producer with reasonably good quality oil ("sweet" with reasonable API gravity) has any difficulties selling any volume he can produce. Moreover buyers ask for additional volumes. Note the word "selling", not putting in storage at his own expense.
Theoretically within "oil glut" framework there is no place for this oil to go other then in storage. And storage costs now are very high in Continental US so there should be reasonable attempts to minimize losses due to large amount of stored oil, which should limit "new" oil buying.
So it looks like "glut theory" (which is essentially an extension of neoclassical supply/demand model) has some serious holes in it.
Ves , 02/24/2016 at 12:12 am"Can you please explain how in oversupplied Europe Iran suddenly found customers for more then 0.3 Mb/d (Italy, Greece and France; Spain is next). "Iran is selling its oil in Europe at a big discount trying to regain its market share in this region. The customers are happy to buy Iranian oil at a lower price than the Saudi or Russian oil. The market is oversupplied, therefore part of oil supplies goes to storage.
"You should see inventories rising by the same amount because according to the "oil glut" theory this oil can't be consumed, don't you ? And 0.3Mb/d is 9 Mb/month."
1) Inventories in Europe are rising. Thus, according to the IEA, in December, even prior to the restart of Iranian exports, they have increased by 0.29 mb/d, or 9 million barrels.
2) Oil exporters are constantly adjusting their geographical mix of oil supplies. So with increasing volume of Iranian oil directed to Europe, Russia and others may have redirected part of their supplies to China.
"Most large oil contracts are long term and you can't break them without penalties."
Oil is not natural gas. Contracts are much shorter than typical take-or-pay contracts for gas supplies. A lot of oil is sold in the spot market. In general, the oil market is very flexible.
"Also in the USA no producer with reasonably good quality oil ("sweet" with reasonable API gravity) has any difficulties selling any volume he can produce. Moreover buyers ask for additional volumes. Note the word "selling", not putting in storage at his own expense."
When a customer in US or any other country buys oil, it may consume (process) it or put in storage. With the current low price of oil and a steep contango, it makes sense to put oil (or refined products) in storage. Therefore, oil and product stocks in the US are increasing.
"Theoretically within "oil glut" framework there is no place for this oil to go other then in storage. And storage costs now are very high in Continental US so there should be reasonable attempts to minimize losses due to large amount of stored oil, which should limit "new" oil buying."
The contango in the oil market justifies storing oil even at a high cost. If not, customers are ready to buy oil only at a lower price. That explains the current downward pressures on the oil price.
"So it looks like "glut theory" (which is essentially an extension of neoclassical supply/demand model) has some serious holes in it."
The oil glut in the market is empirical reality and has nothing to do with the neoclassical theories. You and Watcher are the only ones who deny this.
@likbezSynapsid , 02/24/2016 at 12:44 am"Glut" is emotional word and it is has negative connotation if you are oil producers and very likely it is misused in the press in order to provide certain perception of abundance.
or pick word "Oligarch" or "Businessman" which is more emotional to you?
Better word would be "over-supply" of oil. But the real question is how much of over-supply there is?
AlexS,Watcher , 02/24/2016 at 2:19 amSome of the tankers being used for storage hold gasoline, not crude. (You may already have mentioned this elsewhere.)
This is going circular, despite some good procedural information. The issue is this. Does KSA put oil on a tanker and send it to . . . whatever destination with no order for it. Now that's rhetorical in that the correct question could be Does KSA let oil leave that tanker without being a promise of payment.Dennis Coyne , 02/24/2016 at 11:51 amSimply that, and you seem to be dodging. Is oil coming out of the ground - or if you're happier, coming out of the tanker, without agreement to pay. And again, your reference made clear you're talking about 50 and only 50 lousy million barrels. The decline in prices started June 2014. Quotes of oversupply have been up to 3 mbpd. Even that graph you posted would add up to hundreds upon hundreds of millions of barrels.
You're not making your point. Are you saying KSA and other exporters pumped that much oil out without being paid for it?
Hi guys,The oil of course is paid for, but the price is very low. A "glut" means an oversupply, how do we know there is an oversupply? Because many producers are selling their product at a loss.
For a commodity like oil which does not deteriorate in storage (like apples) there can be oil traders that buy and store oil in hopes of selling later for a higher price.
To make things simple glut=low price.
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Alberto, 02/24/2016 at 1:36 pm
Every single business in the world must increase its inventory when it increases it sales unless it is somehow able to get more efficient with its inventory turns. When growth is very fast like it has been in the US oil industry over the past few years, inventory turns almost always get less efficient, particularly if there are bottlenecks in product flows due to insufficient infrastructure or logistics which struggles to catch up with that growth. So when you are producing and selling record or near record amounts of a good then your inventory of that good should be at or near record levels. Also, when you build more inventory capacity you are going to carry more inventory particularly if you don't like the price that you can sell that inventory now as is the case in the oil business.The inventory in the US will turn much quicker than people think as the production declines accelerate or more importantly the price goes up. Assuming either of those things ever happen again….
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Ron Patterson , 02/24/2016 at 12:45 pmThe Weekly Petroleum Status Report came out earlier today. The biggest news is that oil inventory levels increased by another 3.5 million barrels. They are at an all time high.Jeffrey J. Brown , 02/24/2016 at 1:41 pmI understand that there are some folks out there who do not believe that there is currently a glut in the oil supply. I wonder how they would explain this record in stored oil. Of course this is just not in the US, there are similar stories around the world. We are running out of places to store oil. That's not a glut? Then what the hell would you call it.
US crude oil production dropped by 33,000 barrels last week, according to the EIA's algorithm that tries to track production. Understand that this is not an actual measurement of oil produced but a mathematical equation that tries to figure it out.
A glut of condensate?shallow sand , 02/24/2016 at 1:54 pmAs US C+C inventories increased by 100 million barrels from late 2014 to late 2015, US net crude oil imports increased:
http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
The most recent four week running average data (through Mid-February), show that US net crude oil imports increased year over year, from 6.8 million bpd in 2/15 to 7.4 million bpd in 2/16. And US net crude oil imports, as a percentage of C+C inputs into refineries, rose year over year from 44% last year to 47% this year (four week running average data).
And links to articles from last year and this year that discuss refiners' unhappiness with "Synthetic WTI" blends of heavy crude and condensate:
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323
https://rbnenergy.com/just-my-imagination-how-full-is-cushing-crude-oil-storage-capacity-really
Ron, do we know what worldwide C + C storage levels have done since 2013?Ron Patterson , 02/24/2016 at 2:29 pmIf I am a US refiner, I would be filling every available inch of storage at sub $30 oil.
Are oil exporters doing the same?
Well we have the OECD storage levels for the last 6 years, courtesy of the IEA Oil Market Report And, as you can see they are at a high since January 2010.Chris , 02/24/2016 at 4:06 pm
If you substract US storage increase from OECD numbers, I think you should see a plateau. So the majority of the increase in oil storage is in the US, at least for OECD.shallow sand , 02/24/2016 at 4:33 pmI have tried in the past to find information about non-OCED and OPEC storage. I have been unable to do so. If anyone has this information (AlexS?) I would appreciate it very much.Urs, 02/24/2016 at 2:54 pmPer IEA, total supply, including refinery gains and biofuels stood at 97.1 million bopd. Of that, OCED was 24 million bopd, with refinery gains and biofuels in OCED making up another 4.6 million bopd.
This means that a little over 70% of world wide supply (production) is non-OCED and OPEC. So, without storage information for non-OCED and OPEC, seems it is a little difficult to obtain a clear picture of how much higher worldwide storage is now than it has been in the past?
It would seem if non-OCED exporters and OPEC desired to sell into this market and draw down crude oil storage inventories, they very well could do so, as refiners in importing countries would be inclined to buy as much oil as they could store, assuming that low prices will not remain forever. OTOH, when oil shot up to $140, clearly refiners in importing countries tried to keep from buying anymore crude than necessary, as there is much more risk in storing $140 oil losing value than $30 losing value.
Also, when we get right down to it, strategic petroleum reserves should be included into the mix. However, what weight they should be given is difficult, given the uncertainty of if and when they would be accessed.
The inventories for countries producing 29.5% of C + C, including refining gains and biofuels, have increased from about a five year average of 58 days, to 65 days supply. I wonder what has happened with regard to storage for the remaining 70.5% of world wide production?
I will give you an example of what I mean through a stripper well oil producer. Stripper well production is separated from water and goes into a stock tank. When the stock tank is full, the tank is picked up by a tanker truck and driven to a refinery.
In January, a stripper well operator may start with 1,000 barrels of oil on hand, produce 1,000 barrels in the month, sell 1,200 barrels in the month, and end the month with 800 barrels on hand. The next month, the operator may start with the 800 barrels, produce another 1,000 barrels, sell just 600 barrels, and end the month with 1,200 barrels on hand.
We know the operator produced 1,000 barrels each month. However, if I had not told you that, you might very well think the operator produced 1,200 barrels in January and 600 barrels in February.
Is it not possible that this game is occurring with regard to large producers for which we have no storage data?
For example, I sincerely doubt KSA suddenly shuts in wells to cut production, or opens up wells to increase production. I assume they have considerable storage, and when they ramped up production greatly, they really didn't, they put a lot of stored oil on the market. I think it would be tough to suddenly increase or decrease production by 1 million bopd. Maybe they do, but I doubt it happens immediately.
Of course, I really do not know the above re KSA for a fact. However, it would be much easier for them, or any other producer, to manage supply, at least in part, through the use of storage.
Please understand, I have no idea what is really going on with worldwide oil storage. But that is my point, unless someone can point me to some good data, no one does. For all we know, storage levels in non-OCED and OPEC could be low?
Hi
Thanks for the weekly graph – always great to see your data presentation.Careful with the increase in crude stocks, because, as you surely know gasoline, distillates (the low sulphur part) and the propane are all down the double,
so that total stocks (bottom line in top part of "data overview table 1" EIA) are DOWN 5 mb last week!I think people are gonna start reacting, 4 week averages are down, yearly cumulative production is down, the tide is turning. And as Mr Brown writes, imports are up too. The show goes on…
Best,
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Reuters
According to the U.S. government, there are over 1.3 billion barrels of crude oil and refined products in commercial storage around the United States, an increase of more than 300 million barrels in the last two years.There is a tendency to assume all these barrels of crude and products are "excess" inventories, the result of overproduction, but most of them are held for operational reasons.
The best way to distinguish excess inventories from normal operational stocks is to adjust reported inventories for time of year, consumption of crude by refineries, and consumption of products by end customers.
Other things being equal, the more crude refineries process every day, the more crude they need to hold on site, at tank farms or en route to the refinery in pipelines and on ships to keep their distillation towers supplied.
And the more fuel supplied to customers, the more refined stock refineries, blenders and distributors need to keep on hand to deal with seasonal swings, maintenance and unexpected disruptions in the supply system.
Since the start of 2015, U.S. refineries have been processing record amounts of crude to meet strong demand for gasoline as continued growth, rising employment and cheap fuel prices have encouraged increased driving.
U.S. crude stockpiles are currently 47 percent higher than the average over the last 10 years but if stocks are adjusted for the higher rate of processing the surplus falls to around 34 percent.
The reported surplus in crude stocks over the long-term average is around 162 million barrels but if stocks are adjusted for higher processing the surplus falls to around 128 million barrels (tmsnrt.rs/20WQt9F).
U.S. gasoline stockpiles are currently 11 percent higher than normal for the time of year but if they are adjusted for strong gasoline demand then the surplus shrinks to 7 percent.
The reported surplus in gasoline stocks over the long-term average is 26 million barrels but adjusted for higher demand falls to 17 million barrels (tmsnrt.rs/20WQzhl).
Crude and gasoline stocks are somewhat less excessive than the unadjusted data suggests because refinery processing and gasoline consumption have been so strong.
But distillate demand has been much weaker than normal thanks to sluggish demand from the freight sector and El Nino.
Distillate stocks are much higher than the raw numbers suggest, once they are adjusted for the current weakness in demand.
Distillate stockpiles are currently 24 percent higher than the long-term average but once adjusted for weak consumption they are 43 percent higher than normal for the time of year.
The reported surplus in distillate stocks over the long-term average is 31 million barrels but adjusted for weak demand the surplus surges to 48 million barrels (tmsnrt.rs/20WQE4M).
At this time of year, U.S. gasoline stocks are normally around 26 days worth of consumption, and they are currently a bit higher at 28 days.
Distillate stocks should be around 32 days worth of consumption but are currently at a massive 46 days worth of demand.
CONTINUOUS PROCESSING
Early U.S. oil refineries processed crude in batches, with each batch of oil loaded separately into a still, where it was heated until the distillates were boiled off, condensed and collected for sale.
Early refineries were really just simple distilleries: the equipment would be instantly recognisable to anyone who has been on a tour of a whisky distillery ("A practical treatise on coal, petroleum and other distilled oils", Gesner, 1865).
The first U.S. refineries established during the 1860s and 1870s processed up to 2,000 barrels per day, though most were much smaller and produced less than 1,000 barrels per day ("Early and later history of petroleum", Henry, 1873).
Refineries were geared to produce a middle distillate boiling around 300-600 degrees Fahrenheit which was sold as kerosene or paraffin oil and used for illumination.
Gasoline, with its lower boiling point, was too volatile to be used safely as lamp fuel and was mostly considered a nuisance and waste product.
U.S. oil refineries eventually switched from processing crude in discrete batches to feeding oil into distillation towers and drawing off the fractions in a continuous process.
Modern U.S. refineries process up to 600,000 barrels per day, 300-1200 times as much as the first batch-based plants, though a more typical refinery has capacity of around 100,000 to 200,000 bpd.
The objective has switched from producing kerosene for lighting to producing gasoline for use as a transportation fuel.
In the first decades of the 20th century, electric lighting began to reduce demand for kerosene while the massive expansion in car ownership stimulated consumption of gasoline.
From 1915-1920 onwards, refineries were increasingly geared to produce gasoline as the main product, while middle distillates became a by-product.
With the shift to continuous processing and the prodigious growth in demand for gasoline as a road fuel, the oil industry's need to hold stocks of unrefined crude and refined products surged.
To ensure an uninterrupted flow of oil from the wellhead to the refinery and the end customer, stocks of crude and refined fuels are held at every stage along the supply chain.
Refineries hold substantial stocks of crude to ensure a continuous flow of carefully prepared (de-watered and de-salted) as well as blended crude into their distillation towers.
The industry also needs substantial stocks of refined fuels, lubricants and petrochemicals to ensure a continuous supply to distributors and end users.
Refineries hold crude and refined products to meet routine operational requirements as well as to deal seasonal variations in demand, planned maintenance and unexpected disruptions.
The amount of oil involved is enormous.
At the end of 2013, with the oil market more less balanced, more than 1.05 billion barrels of crude and refined products were being stored at refineries, distributors and oilfields as well as in pipelines and on tank farms.
By February 2015, with the oil market clearly oversupplied, crude and refined products in storage had climbed to more than 1.33 million barrels, according to the U.S. Energy Information Administration ("Weekly Petroleum Status Report", EIA, Feb. 24).
OPERATIONAL PLANNING
In the last year, U.S. refiners have been fairly successful in matching gasoline production and stockpiles with demand. Gasoline production remains at the centre of their operational planning.
Crude stocks have continued to increase, reflecting worldwide oversupply, though stockpiles are rising somewhat more slowly than at the start of 2015.
But refiners lost control of distillate stocks in the second half of 2015 as freight demand slowed and El Nino ensured a warmer than normal winter across the United States and other parts of the northern hemisphere.
Winter heating demand across the United States has been around 17 percent below average, according to the National Oceanic and Atmospheric Administration.
And by the end of 2015, the volume of freight being moved across the United States by road, rail, pipeline, barge and air had fallen by more than 2 percent compared with the same period at year earlier.
Over the last four weeks, U.S. implied distillate consumption has averaged just 3.5 million barrels per day, which is 12 percent below the long-term average and 16 percent below the same period in 2015.
The fact that refiners have lost control of distillate stocks should come as no surprise because distillate is essentially a by-product of gasoline production.
Refineries have operated to maximise gasoline production but in the process created an enormous and growing oversupply of distillate.
There is some limited flexibility in the refining system to switch from distillate production to gasoline but it is typically only on the order of a few percentage points.
Massive overproduction of distillate has pushed gross refining margins for the fuel to the lowest level since 2010.
But refining margins for gasoline have been much healthier, at least until recently, which has encouraged refiners to continue maximising crude throughput.
As long as gasoline demand remains strong, refiners will continue to meet it, which is why the outlook for U.S. gasoline consumption is so critical for the oil market in 2016.
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Jeffrey J. Brown, 02/24/2016 at 1:41 pm
A glut of condensate?As US C+C inventories increased by 100 million barrels from late 2014 to late 2015, US net crude oil imports increased:
http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
The most recent four week running average data (through Mid-February), show that US net crude oil imports increased year over year, from 6.8 million bpd in 2/15 to 7.4 million bpd in 2/16. And US net crude oil imports, as a percentage of C+C inputs into refineries, rose year over year from 44% last year to 47% this year (four week running average data).
And links to articles from last year and this year that discuss refiners' unhappiness with "Synthetic WTI" blends of heavy crude and condensate:
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323
https://rbnenergy.com/just-my-imagination-how-full-is-cushing-crude-oil-storage-capacity-really
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Watcher, 02/24/2016 at 6:39 pm
WTI definition was changed to allow more shale output flow into Cushing. Inventory definition similarly changes and loses all valid comparison to history. There's no valid data on most of what's going on.clueless, 02/24/2016 at 10:17 pmWatcher: "There's no valid data on most of what's going on."One of your best observations.
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Bloomberg Business
The growth engine of Canada's energy industry is poised to shut off next decade, according to the International Energy Agency.
Production gains from the oil sands in northern Alberta will slow dramatically or come to a halt as crude prices remain low and costs too high for one of the world's most expensive sources of oil, the agency forecast Monday in a report on the global medium-term crude market. Environmental concerns, a lack of new oil pipelines and uncertainty about policy in Alberta are also causing companies to slow development work, the report said.
... ... ...
The outlook for slowing oil-sands growth next decade comes as Canadian energy companies report quarterly earnings results that display the full brunt of the market collapse. Narrowing refining margins are no longer shielding producers such as Cenovus Energy Inc. from losses in their upstream divisions. Companies are further lowering dividends, cutting jobs and setting aside drilling rigs to contend with what Cenovus Chief Executive Officer Brian Ferguson earlier this month called "hurricane-force" winds.
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February 10, 2016 | Griz's Trading Blog
It seems that EIA is doubling down on their faulty model for weekly US oil production estimates. EIA continues to drive monthly production estimates up, at least through February, and in turn this is supporting weekly overestimates of US production. In fact their latest monthly report estimates production in the major US shale basins will exceed their previous January production estimate by 68k bbl/day. This is in direct conflict with dropping rig counts and more importantly falling well completion rates reported by the states of Texas and North Dakota.
... ... ...
The conclusion is US shale production is far less robust than the world of oil traders currently believes. If we have now moved into a mode where Unaccounted for Oil tends to be negative, say -150k bbl/day every week, opposed to the normal +150k bbl/day every week, and this is just week 2 of a much longer streak of back to back negative values for Unaccounted for Oil, US production could already be well under 9MM bbl/day and very rapidly falling toward 8MM bbl/day.
Below I'm including my updated 2016 US production + Unaccounted for Oil projection. I've included a couple of my own linear projections as well as a couple polynomial trend lines. My belief is US production is declining at a rate best described by Projection 2. This means the decline is trending in the lower channel and possibly the lower half of the upper channel. The less steep poly trend line also likely describes the situation well.
Unknown, February 11, 2016 at 5:13 AM<
I think you are correct. When I look at how some of the upstream mlps have now entered panic mode even with good hedging this yr is telling
Kirt
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peakoilbarrel.com
George Kaplan, 02/23/2016 at 3:14 amIn the discussions here and concerning Bakken LTO has either of these two articles been mentioned? They are by David Hughes and Jean Laherrere.Heinrich Leopold, 02/23/2016 at 5:00 amThe David Hughes one in particular looks to have predictions close to what has been happening. They both question EIA estimates of the amount of oil recoverable. For example from Hughes:
"The U.S. Energy Information Administration's (EIA) forecasts regarding tight oil production-published in its Annual Energy Outlook (AEO)-are commonly viewed by industry and government as the best available assessment of what to expect in the longer-term, with the EIA's reference case typically viewed as the most likely scenario for future production. In my Drilling Deeper1 report published last October, I developed alternate production forecasts for two major tight oil plays, the Bakken and Eagle Ford, and reviewed the credibility of EIA AEO20142 forecasts for other major plays based on the fundamental geological characteristics of each play. In most plays the AEO2014 production projections were found to be highly to extremely optimistic when reviewed in the light of play fundamentals. For the Bakken and Eagle Ford plays, AEO2014 overestimated the likely recovery of oil by 2040 by 42% compared to my "Most Likely" drilling rate case found in Drilling Deeper."
http://www.postcarbon.org/wp-content/uploads/2015/09/Hughes_Tight-Oil-Reality-Check.pdf
This is from the Laherrere article (posted at POB) and looks, for something 18 months ago, as prescient as anything I've seen in the light of subsequent events:
"It seems that most oil companies are spending more than their revenues by increasing their debts. Countries can live for a long time with huge debt increase, not companies. They count on the stock market by delivering optimistic reports and keep drilling to avoid the production to decline. With shale oil or shale play, in contrary with conventional where wells are dry or producing, oil can be produced even for a while if not economical.
Such behavior explains why most peak forecasts are wrong. But the main question is about the slope of the decline after the peak. EIA forecast a LTO (light tight oil = shale oil) peak in 2017 it is not too far after my forecast, the big difference is the slow EIA LTO decline."George KaplanGeorge Kaplan, 02/23/2016 at 5:48 amAlthough these reports are very interesting, they ignore in my opinion financial conditions – mainly the bond market – and oil prices as major drivers for oil production. Jean Laherrere is fully aware of this fact, yet does not provide oil production scenarios at different oil price and bond market conditions.
So, if oil prices would fall below 20 USD per barrel for a long period I am pretty sure, oil production for Bakken and Eagle Ford would tend to zero within a short time and all above production scenarios would be irrelevant.
If oil prices would recover, production will start again.
Yet it is in my view not possible to sustain horrendous losses for a long time. Somebody has to pay the bill. It is already clear now that high US oil production supports the US dollar, yet brings the bond market to its knees. The bond – and equity holders are paying currently the bill, yet for how long?
This comes especially on the background of the US bond market facing a maturity wall of USD 4.1 trn over the next four years. http://www.highyieldbond.com/the-2020-maturity-wall-4-1t-of-bonds-to-mature-and-13-of-that-is-high-yield/.
Companies can roll over the debt, yet at much higher interest rates.
Might be so. If the production continues to follow the Hughes predictions though, I'd say that will cast a lot of doubts over how much impact short term price swings have had. Possibly the availability of cheap money through most of 2015 overrode any price signals and they just kept on drilling no matter how much losses they incurred. You talking about a maturity wall now – how would that have impacted production in the past, especially when in the beginning of the price fall producers were expecting prices to recover at any time and later were concentrating solely in staying alive for the next month and couldn't afford to look much further ahead.With data currently available the main message I've got from this is that there is probably a lot less oil in the Bakken and Eagle Ford than EIA are saying – at any price.
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peakoilbarrel.com
AlexS, 02/22/2016 at 12:04 pmThe IEA has actually increased its medium-term global demand projections compared with the previous year's report. This reflects a much higher 2015 base, but also slightly higher growth rates in 2016-2020.AlexS, 02/22/2016 at 12:44 pm
As a result, projected demand in 2020 is now almost 1.5 mb/d higher than in MTOMR-2015 (100.5mb/d vs. 99.05mb/d).From the new report:
"…our forecast for oil demand to 2021 is for annual average growth of 1.2 mb/d (1.2%) which represents a very solid outlook in historical terms. Oil demand breaks through the 100 mb/d barrier at some point in 2019 or 2020. A major change from the 2015 MTOMR is the higher base from which our forecast begins. In 2015 world oil demand increased by 1.6 mb/d (1.7%), one of the biggest increases in recent years stimulated to a large extent by the rapid fall in oil prices that began in the second half of 2014 and gained momentum in 2015. However, any expectations that the most recent fall in oil prices to USD 30/bbl oil will provide further stimulus to oil demand in the early years of our forecast and send annual rates of growth above 1.2 mb/d are likely to be dashed. In the first part of 2016 we have seen major turmoil in financial markets and clear signs that almost any economy you care to look at could see its GDP growth prospects downgraded.
Since 2014 the non-OECD countries have used more oil than OECD countries and the gap will widen in years to come. However, the rate of demand growth in the non-OECD countries is vulnerable to being pared back as the cost of energy subsidies becomes a major burden and governments take action. This will probably not have an immediate impact on demand in the early part of this forecast, but later on we might see that the reduction in expensive fuel subsidies in many countries, including the fast-growing Middle East, does have a significant effect on growth. Also, rising energy use has brought with it terrible environmental degradation, particularly in the fast-growing Asian economies, and oil's part in this is recognised by measures to limit vehicle registrations and use. Although reducing subsidies and tackling pollution will affect the rate of demand growth, it should be stressed that non-OECD Asia will still remain the major source of oil demand growth with volumes increasing from 23.7 mb/d in 2015 to 28.9 mb/d in 2021."Global liquids demand (mb/d): IEA Medium-Term Market Reports 2016 vs. 2015
The IEA's non-OPEC C+C+NGLs production estimate for 2015 in last year's MTOMR proved too pessimistic. They have underestimated the resilience of high cost oil production, particularly that of the US LTO. As a result, actual non-OPEC production was 1.1 mb/d higher than in last year's report.AlexS, 02/22/2016 at 1:07 pmStill, the agency expects non-OPEC production to decline by 0.6mb/d in 2016 and 0.1mb/d in 2017 before a gradual recovery from 2018. Projected decline in 2016-17 should be mainly driven by LTO. Expected non-OPEC production in 2020 is 0.4mb/d lower than in the MTOMR-2015.
From the new report:
In the year since the 2015 MTOMR was published, the supply side has provided many surprises. By far the most significant has been the resilience of high cost oil production and in particular that of light, tight, oil (LTO) output in the US. As oil prices cascaded down from more than USD 100/bbl it was widely predicted at various milestones that the extraordinary growth in total US crude oil production from 5 mb/d in 2008 to 9.4 mb/d in 2015 would grind to a halt and move rapidly into reverse. Growth certainly ceased in mid-2015 but the intervening period has seen a relatively modest pull-back and total US crude oil production in early February 2016 was still close to 9.0 mb/d, aided by expanding production in the Gulf of Mexico.
In our base case outlook, there is an element of the "straw breaking the camel's back" and we expect US LTO production to fall back by 600 kb/d this year and by a further 200 kb/d in 2017 before a gradual recovery in oil prices, working in step with further improvements in operational efficiencies and cost cutting, allows a gradual recovery. Anybody who believes that we have seen the last of rising LTO production in the United States should think again; by the end of our forecast in 2021, total US liquids production will have increased by a net 1.3 mb/d compared to 2015. Such has been the element of surprise provided by the resilience of US oil production, and the wide divergence of views as to the future, that we have added a High and Low Case to our non-OPEC production analysis and plotted the impact on the global oil market balance of US LTO production falling by more than in our base case or, conversely, less. The eventual outturn is one of the most important factors – if not the most important – in assessing when the oil market will re-balance.
Non-OPEC liquids production (ex biofuels) (mb/d): IEA Medium-Term Market Reports 2016 vs. 2015
(Note: excludes Indonesia)
The IEA expects the oil market to re-balance in 2017, which is in line with the EIA's and many other forecasts. However the accumulated excess inventories will return to long-term normal levels only by 2021, which should dampen the recovery in oil prices.From the report:
For some time now analysts have tried to understand when the oil market will return to balance. A year ago it was widely believed that this would happen by the end of 2015 but that view has proved to be very wide of the mark. In 2014 and again in 2015 supply exceeded demand by massive margins, 0.9 mb/d and 2 mb/d respectively, and for 2016 we expect a further build of 1.1 mb/d. Only in 2017 will we finally see oil supply and demand aligned but the enormous stocks being accumulated will act as a dampener on the pace of recovery in oil prices when the market, having balanced, then starts to draw down those stocks. Unless we see an even larger than expected fall in non-OPEC oil production in 2016 and/or a major demand growth spurt it is hard to see oil prices recovering significantly in the short term from the low levels prevailing at the time of publication of this report.
It is very tempting, but also very dangerous, to declare that we are in a new era of lower oil prices. But at the risk of tempting fate, we must say that today's oil market conditions do not suggest that prices can recover sharply in the immediate future – unless, of course, there is a major geopolitical event.
Global balance base case: IEA MTOMR-2016
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February 18, 2016 | Griz's Trading Blog
The EIA weekly estimate of production is still too high as indicated by Unaccounted for Oil and production estimates based on well completion rates. However, the weekly estimate is starting to move down in a big way. Last week down 30k bbl/day, this week 50k bbl/day. 50k bbl/day is huge, that is 200k bbl/day/month The reality is US production has been falling 20k-30k bbl/day for weeks or even months already, now it is likely falling 30-37k bbl/day/week not 50k bbl/day/week. 50k bbl/day/week would imply almost zero well completions, when around half of each months shale decline is currently being replaced monthly. But EIA is so far behind, with likely production levels already below 9 MM bbl/day compared to the official estimate of 9.135 MM bbl/day, that they are being forced and will continue to be forced to show huge weekly declines for awhile to catch up. Won't be surprised to see 100k bbl/day cut reported next week and potentially the week after as well.
Unaccounted for oil has been running dramatically negative since Dec. 4. We have now just seen 3 back to back weeks with negative unaccounted for oil. This week it was -500k bbl/day or 3.5MM bbl for the week. Imagine what happens when -500k bbl/day in Unaccounted is zeroed out and put in production instead.
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www.bbc.com
The International Energy Agency (IEA) is warning consumers not to let cheap oil lull them into a false sense of security amid forecasts of a price spike by 2021.
In a report, the IEA said it expects prices to start recovering in 2017. But it forecasts that will be followed by a sharp jump in price as supply shrinks following under-investment by struggling producers.
Brent crude touched a 13-year low of $28.88 a barrel in January. It has since recovered somewhat, but is still far below a high of $115 in June 2014.
On Monday the price was up around 4.9% at $34.62.
Fatih Birol, executive director of the IEA, said: "It is easy for consumers to be lulled into complacency by ample stocks and low prices today, but they should heed the writing on the wall: the historic investment cuts we are seeing raise the odds of unpleasant oil-security surprises in the not-too-distant-future."
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The policy advisor expects global oil supply will grow by 4.1 million barrels of oil per day between 2015 and 2021, down from an increase of 11 million barrels of oil per day between 2009 and 2015.
It also expects investment in oil exploration and production to fall by 17% in 2016 following a 24% decline last year.
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peakoilbarrel.com
Daniel, 02/22/2016 at 8:00 amFrom IEA medium-term oil market report 2016:Jeffrey J. Brown, 02/22/2016 at 8:46 amFurther, it is becoming even more obvious that the prevailing wisdom of just a few years ago that "peak oil supply" would cause oil prices to rise relentlessly as output struggled to keep pace with ever-rising demand was wrong. Today we are seeing not just an abundance of resources in the ground but also tremendous technical innovation that enables companies to bring oil to the market.
Added to this is a remorseless downward pressure on costs and, although we are currently seeing major cutbacks in oil investments, there is no doubt that many projects currently on hold will be re-evaluated and will see the light of day at lower costs than were thought possible just a few years ago. The world of peak oil supply has been turned on its head, due to structural changes in the economies of key developing countries and major efforts to improve energy efficiency everywhere.
I fear that there will be a rude awakening for some in the next few years.
The WSJ has an article on the IEA outlook, with an interesting chart (do Google Search for access):Jeffrey J. Brown, 02/22/2016 at 11:53 amWSJ: IEA Sees Global Oil Markets Rebalancing Next Year
IEA says 'supply and demand will gradually rebalance by 2017, with a corresponding recovery in oil prices from around $30 a barrel'Copy of an email I sent to some Oil Patch folks:Frugal, 02/22/2016 at 8:52 amAttached is an article in today's WSJ about the IEA's most recent outlook, for the balance between global total liquids supply & demand. There is a very interesting chart in the article. Apparently, oil prices were trading up today, because of the report.
However, the IEA outlook does not take into account two critical factors: (1) The composition of the global Crude + Condensate (C+C) inventory oversupply (mostly condensate, in my opinion) and (2) Even as production increases, net exports can fall, because of domestic consumption in net oil exporting countries.
Some of my comments on net oil exports:
Following is a link to a discussion, in three sequential comments, of the Export Land Model (ELM, a simple mathematical model which assumes a 5%/year rate of decline in production and a 2.5%/year rate of increase in consumption, in a net oil exporting country), the Six Country Case History (major net exporters that hit or approached zero net exports from 1980 to 2010, excluding China) and the (2005) Top 33 Net Exporters, with graphics for each item:
http://peakoilbarrel.com/opec-except-iran-has-peaked/#comment-556985
Note that what I define as the ECI Ratio (Export Capacity Index) is the ratio of production to consumption, and CNE = Cumulative Net Exports (for a defined time period).
Based on the mathematical model, which is confirmed by the empirical data (Six Country Case History), a declining ECI Ratio tends to correlate with an accelerating rate of depletion in remaining CNE.
For example, about the only metric that most analysts focus on is the top line production number in a net oil exporting country, and from 1995 to 1999, Six Country production rose by 2%, but in only four years they had already shipped 54% of their post-1995 CNE.
I estimate that Saudi Arabia may have already shipped in the vicinity of half of their post-2005 CNE. Note that annual Saudi net oil exports fell from 9.5 million bpd in 2005 to 8.4 million bpd in 2014 (probably remaining at about 8.7 mililon bpd in 2015, EIA + BP data). In other words, Saudi net exports, after increasing very rapidly from 2002 to 2005, have almost certainly been below their 2005 rate for 10 straight years. But the hidden danger, which almost no one is focused on, is the ongoing–and accelerating–rate of depletion in remaining volume of post-2005 Saudi and Global Cumulative Net Exports of oil.
Regards,
Jeffrey Brown
Jef, 02/22/2016 at 11:02 amThe world of peak oil supply has been turned on its head, due to structural changes in the economies of key developing countries and major efforts to improve energy efficiency everywhere.Increasing the extraction rate simply increases the depletion rate. I can't see how anything humans do can change that fact. In other words, nothing can turn peak oil on its head.
"… structural changes in the economies…"Dennis Coyne, 02/22/2016 at 11:50 amYea, its called tanking.
Hi Frugal,Correct. I think what has surprised many, including the IEA is that a few years ago they worried that high oil prices would be a problem as oil supply growth would struggle to keep up oil demand growth.
That has not proven to be the case from late 2014 until today as oil supply growth has outpaced oil demand growth. This is mostly due to a change in strategy by OPEC to focus on market share rather than oil revenue.
I believe that high oil prices will be back, but have been convinced by AlexS that it will not be as soon as I have been predicting. Long term projects that will come on line and be ramping up in 2016 and 2017 may keep oil prices under $80/b through mid 2018, we may not see prices rise to $100/b or more (2015$) until 2019, when the current delays in long term oil investment will start to affect oil output in a big way (2 to 3 Mb/d less output than if the projects deferred had been completed).
To me the undulating plateau scenario looks somewhat plausible, unless there is a financial crisis, in which case demand and price will fall along with output. I have no prediction for when such a crisis might occur, but the scenario below ignores that possibility.
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peakoilbarrel.com
Coolreit, 02/21/2016 at 11:23 am
Why wouldn't we call the EIA liars in reporting far more Texas oil production than the RRC?Critics say they are not lying as their difference with the RRC is initial reporting vs. final estimated reporting. If that critique were valid, then why is the oil production drop by the RRC from peak triple the fall that the EIA reports for Texas?
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www.theoildrum.com
RockyMtnGuy on November 22, 2012 - 8:49pm Permalink
Well, apparently the EIA and IEA are counting only liquid fuels, but it's not a legitimate accounting technique. They should be doing a mass and/or energy balance. There is quite a lot of mass and energy in the coke a refinery produces, and they don't actually throw it away, they sell it as fuel. Looking at only liquid fuels is really a very simplistic approach which gives a misleading picture.Black_Dog on November 22, 2012 - 10:09am Permalink | Subthread | Parent | Parent subthread | Comments top As you note, "processing gains" aren't something which one can measure directly. The markets deal in volumes and as a result, governmental reports (such as those from the EIA and the IEA) present data in volumes, not energy content or mass. Processing gain only serves to keep the "green eye shade" crowd of corporate and financial types happy, since they are trained to look at various balance sheets in which every thing neatly adds up. In reality, "processing gain" is simply the calculated difference between the volume of product and the volume of input liquids.
The volumes reported on both sides of the calculation have numerous sources of error, not to forget the non-technical situations, such as the Saudis, where production is a state secret and various unauthorized diversions, such often reported in Nigeria. For countries (and companies) with a larger fraction of such gains, the cause might be more efficient refining or differences in the output fraction of each product type. Refiners which have access to natural gas may use that instead of crude to provide the thermal or electrical energy to run the refinery, resulting in more product output. The results might also reflect differences in emissions where a country which has strict standards and enforcement might end up with more product actually making it to market. Then too, it's always going to be difficult to contain these liquid and gaseous materials, especially in countries with warmer climates. There's also the possibility that "processing gains" might turn out to be negative, if losses are extreme.
Ideally, from a scientific or thermodynamic point of view, the accounting should be carried out in energy terms, presenting the information rather like that found in the various markets for natural gas or electricity. With such accounting, there would not be any "processing gain", only the losses during extraction, refining and distribution. The efficiency of each link in the processing and delivery chain would be clearly apparent and the market(s) would be able to include this information in various corporate valuations. Sad to say, our markets don't work that way...
E. Swanson
The former tells us that after the Shale bump 'native' production will go back to decline, and the later shows us that replacing it with imported oil is going to get harder, or at least more expensive.
So. Be nice to Canada now, and/or probably better sabotage any attempts by those pesky northerners to build infrastructure that liberates the Alberta resource either east or west and onto the global market.
Related: Is the Alberta product dependent on US inputs to lighten it? If so that is a way that that Bitumen, once it hits the station forecourt, could at least in part accurately be described as a 'North American' product?
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www.theoildrum.com
energyblues on November 22, 2012 - 5:44am PermalinkLet's suppose that one accepts the premise that obtaining accurate figures for total world crude production is going to be problematic at best, and that we are dealing with ballpark figures, to use that term lightly. And this premise is based on the idea that statistics on oil production are undoubtedly politically motivated, and that even if transparency was as good as former American standards, we would still be dealing with rough estimates.Alright, if one accepts this premise, then one must conclude that dealing now with "world total liquids" will be even more problematic, especially in an era of permanent economic contraction and what will inevitably be defunding of areas thought to be secondary or academic.
I suspect this is largely true now. I do enjoy these posts, but what we should admit is that only country by country production and import/export stats have any meaning now, and even those may be largely tampered with.
It is possible and in fact likely that world production could soar while entire countries find themselves out of the market, or that world production could plummet even while a select few are always able to fill their cars and jets.
This was always the danger of peak oil, wasn't it? That the forces it would unleash would in fact undermine any attempts to properly categorize, understand, and deal with it.
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peakoilbarrel.com
Jeffrey J. Brown , 02/13/2016 at 3:54 pm
I'm estimating that global crude oil production* was about 69 million bpd in 2005 and 68 million bpd in 2014. I would assume around 69 million bpd for 2015. Global total liquids production was 85 million bpd in 2005 and apparently about 96 million bpd in 2015.Oldfarmermac , 02/13/2016 at 6:49 pmSo, I estimate that actual global crude oil production, as a percentage of total liquids, fell from about 81% in 2005 to about 72% in 2015.
In regard to the US, I estimate that actual crude oil as a percentage of total liquids fell from about 57% in 2005 (4.7/8.3) to about 49% in 2015 (7.3/14.8).
*45 API Gravity & Lower Crude Oil
If the collective or average energy content of "other liquids" IS only seventy percent of the energy content per barrel of conventional crude oil, then ten million barrels of conventional are worth about twelve and a half barrels of "other liquids".If it turns out that conventional crude HAS hit it's ultimate upper limit, as indicated by the plateau in production of it, for the last decade, even with the price skyrocketing, then each MILLION new barrels of "other liquids" are will be worth be worth only seven tenths of a million barrels of actual OIL.
Of course the impact will not be quite so bad , in terms of the energy of the total liquid fuel supply, because the total supply already consists of about twenty eight percent "other " according to JBB's estimate.
Something tells me net energy per capita per barrel of liquid fuel is in the rear view mirror and receding from view at a steady clip, given the growth of population.
That might not matter as much, except at a moral and humanitarian level, as we think however, because most of the poor people of the world are never going to own and drive automobiles.
But it is reasonable to assume that even the poorest parts of the world will see substantial percentage point increases in oil consumption, so long as oil can be bought at any price, because the less oil you use, the greater the utility of each barrel.
A gallon burnt in a heavy truck delivering food from country side to city is worth twenty or thirty or even forty or fifty bucks, once the truck and the road are in existence, in comparison to the alternative of hauling it with draft animals or human muscle power.
It could turn out that the world wide economy will go downhill FASTER than the available supply of oil, even as high cost producers drop out. If NO new oil is brought into production, the supply will decline at somewhere between four and eight percent annually, according to all the estimates I have seen.
Personally I find it hard to imagine the world wide economy WILL go downhill FASTER than oil supply,barring global level Black Swan events, so I am convinced the price of oil will go up.
This is not to say the economy can't go downhill faster than oil production in the SHORT term . It might, and so the price of oil might stay low for some time yet, until depletion takes it's toll.
Oil producers are stubborn bastards, and will give up no faster than they go broke. Some of them can generate some cash for decades yet to come, even at thirty or forty bucks per barrel. If they go broke,due to not being able to pay off loans, whoever buys their wells will buy them cheap enough to continue to produce them.
I will personally gladly pay twenty bucks per gallon, so long as I can get diesel fuel, before I even CONSIDER going back to horses and mules.
Ya feed a car or truck PER MILE you drive it, and a farm tractor PER HOUR you run it. Ya feed draft animals three hundred sixty five days per year. NO CONTEST, unless you CANNOT buy diesel and gasoline at any price.
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likbez, 02/15/2016 at 1:36 pm
Some questions about accuracy of EIA statistics. My impression is that in certain areas they has been playing fast and loose. I might be wrong. Among areas of some concern:Ron Patterson, 02/15/2016 at 2:26 pm1. Is not the net effect of usage of volume instead of weight result in approximately 6% inflation of gross totals (which include all types f fuels) and thus EIA is distorting the "peak oil" situation? ("Great Condensate Con")
2. Is not the same concern true about accounting of gasoline in those EIA totals which include both oil and refined products ?
3. Is not (1) and (2) make EIA "mixed totals" statistics completely bogus (inflating the data by up to 12%) ?
4. Is EIA accounting of refiner gains just an artifact of usage of volume as the metric?
a. The whole concept might be viewed as a mirage created by usage of volume as a metric (the first law of thermodynamics).
b. How refiner gains on imported oil should be accounted? Should they be classified as domestic production like EIA does?5. Is EIA usage of volume acceptable in case of ethanol production? A unit of volume of ethanol contains approximately 55% of energy in BTUs in comparison with WTI. Huge difference: 76,000 Btu/gal vs. 138,000 BTU/gal. That affects mileage and all other usage metrics.
6. How dilutants for Canadian tar sands imported to Canada from the USA are accounted by EIA. They are first exported to Canada and then imported as a part of Canadian oil import? So part of the volume of Canada production was already "produced" in the USA.
7. The same question about Venezuela heavy crude.
IMHO Ron's graphs would be definitely twice more convincing if they were constructed in weight metric instead of volume.
Well, volume is all that I have so my charts are in volume. But I am not really concerned with NGLs, process gain or biofuels. In fact I would never post "total liquids" if I had crude, or C+C for that data.But all that being said, C+C is a pretty good indicator, even though it is not perfect. It will tell us when the peak occurs, or more correctly, it will tell us when the peak occurred in the past.
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peakoilbarrel.com
Javier, 02/13/2016 at 8:11 pmHi Ron,AlexS, 02/13/2016 at 9:22 pmOn the issue of EIA's predictions accuracy, I updated this graph from Mason Inman and added actual oil US production.
What this graph shows is a typical very conservative estimate system. This means that on the way up, they greatly underestimate production and on the way down, they are going to greatly overestimate production.
This clearly shows how credible their predictions are. Although the graph is only for the US, clearly they are going to be equally conservative (and thus equally wrong) about world oil production.
Javier,Javier, 02/13/2016 at 9:56 pmThe long-term projections of U.S. LTO production are from various issues of the EIA Annual Energy Outlook. They indeed were very conservative, even though none of them (even the AEO-2015) did not assume such a big drop in oil prices.
As regards the actual production data (the black line), it is from the Drilling Productivity Report and include almost 1 mb/d of conventional output, primarily from the Permian basin.
U.S. LTO production had never reached 5.5 mb/d, as the black line shows. According to the most recent EIA presentation, the local peak (In March 2015) was around 4.6 mb/d
OK, thanks. The black curve needs correction.But the issue continues being that EIA underestimated production so much that it had to raise its predictions by about 100% each year.
Look at the prediction for 2020:
AEO 2012: 1.3 mbpd
AEO 2013: 2.8 mbpd
AEO 2014: 4.7 mbpd
And all this without any significant change in oil price.So if the question is, as Ron is posting, how much value have EIA predictions? The answer clearly is none. EIA predictions are useless. Evidence indicates that they are going to overestimate production by a large amount for as long as production goes down.
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Guy Minton, 02/13/2016 at 5:47 pmThe big deals against oil prices are, now, the drop in (the increase) in future demand from 1.6 to 1.2%, per IEA, and the massive amount of oil that Iran is getting to lay out with unknown capital input. Supposedly glutting the market with 1.5 million more barrels with magic, I presume. However, I figure it, the drop in demand seems to indicate only about a 300k to 350k difference.Jimmy, 02/13/2016 at 6:37 pmAh, the magic of OPEC will prevail, then. Even though to fully ramp up more, Saudi has to drill in the offshore area, which I am sure is NOT $10 barrel cost of production. Iraq has to end their internal strife to gain some traction. Venezuela is sucking wind, badly. Ecuador, while not the massive producer of other OPEC members, currently has only one well drilling from 50 something rigs. It is hard to keep up with the news from every country, and it is clear that neither EIA nor IEA are really putting much effort into real data accumulation. I think OPEC is strapped for production for the next two years, with the exception of the magical production from Iran.
On the other hand, I read Canada has some smaller oil sands shut in, while larger ones are scheduling to cut back, or have extended periods of overhaul on production equipment. As rigs for conventional oil have dropped significantly, I fail to see were Canada will not have a decrease in production in 2016. Over a year ago, I said the shale production could drop by over one million, but didn't anticipate the increase before the drop. Still from the high in March of last year, it is still projected to drop by 1.2 million by 2017 by EIA. I still thing they are low in their estimate of the drop, but not as much as they used to be.
I read where China's production is expected to drop from 100k to 200k in 2016, base upon the current prices and capex. A recent post by the author indicates that up to 1.5 million barrels may be lost from in field drilling of offshore wells in 2016. All of South America, Africa, and Asia, including Russia, expect drops in 2016, and 2016 is just the tip of the iceberg.
Where are all of these figures in the garbage the EIA and IEA put out? Far as I can tell, the magical numbers put out for Iran, roughly match the drop in infield drilling offshore. But then I am not an expert, because I am not paid by a highly efficient and omniscient government entity.
While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea!Jimmy, 02/13/2016 at 7:49 pmIt seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
Intro sentence should have read: "While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption. "Jimmy, 02/13/2016 at 6:37 pmWhile what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the non-OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea!Adam Ash, 02/13/2016 at 6:51 pmIt seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
With tank farms, strategic storage, rows of rail tankers and flotillas of super tankers filling up all over the planet, producers will now have to match production to demand much more closely, else they will have to 'spill their seed upon the ground'. And there is not much money to be made doing that.Watcher, 02/14/2016 at 3:29 amSome producers with no where to deliver their oil to must be in very difficult positions; going from normal production to zero in a day. From cashflow positive yesterday to being the proud owner of a pile of useless junk and pipes wth zero income today.
Interesting times.
Try this.Adam Ash, 02/14/2016 at 5:38 amTry listening to what is said by KSA. "We are not going to produce oil out of the ground for which we have no orders."
This has been policy all along. Now think about what you just said, and about where you heard it.
Yes Watcher. The interesting moment arriving herewith is that we will now discover actual global consumption without the smoke n mirrors of production filling tanks somewhere.Watcher, 02/14/2016 at 12:31 pmI would imagine that the impacts will be neither selective or nice. Some good paying fields may have to be shut in if the tanks at the end of the pipe are full. Or it could be the final straw that pricks the light tight oil bubble. We shall see.
Tanks aren't filling. No one is placing orders for oil they would put in a tank. That makes no sense. And note, btw, that filling a tank is demand itself and thus would not justify a price decline if you're a supply/demand disciple.Adam Ash, 02/15/2016 at 1:49 amThe price is low because sellers are willing to sell for that lower price. Period. Even if buyers would pay more, the seller insists on less.
Wrap your mind around that and you understand pursuit of victory.
Oh! Silly me. A helpful piece re Cushing storage:-Jeffrey J. Brown, 02/15/2016 at 8:22 amhttps://rbnenergy.com/just-my-imagination-how-full-is-cushing-crude-oil-storage-capacity-really
'… many storage operators [at Cushing] may be turning prospective customers away. Not because they don't have available capacity but because they don't have enough heavier crude to make WTI lookalike blends with incoming light shale grades.'
Do those full-to-the-brim mega-tankers slow-steaming in circles in the Sargasso Sea and swinging at anchor off Singapore and Malaysia with no where to go waiting for a better time to sell into the market in the face of rising production and exports from Iran make sense?
http://abcnews.go.com/International/wireStory/iran-exports-oil-shipment-europe-nuclear-deal-36929921
Not to me…
Producer-sellers are desperate for cashflow at any price, and the glut in supply means the competition to be the one who gets the sale is intense. Yet at the same time the near capacity storage available to some producers makes the potential for an individual field to be locked in because it has nowhere to send its product to much higher, no matter how hysterical the bean counters get.
The low price of crude is cutting the throat of many producers, who will not easily come back on line even if the price recovers. Its going to be an interesting year
Interesting article on the RBN Energy website, about Cushing. Note that the author touches on two key issues: (1) Insufficient heavy crude to offset the flood of condensate, thus making it more difficult to create their "Synthetic WTI" blend and (2) Weak demand for the Synthetic WTI blend itself.Jimmy, 02/14/2016 at 10:09 pmThe Reuters article from last year discusses the second point:
U.S. refiners turn to tanker trucks to avoid 'dumbbell' crudes (March, 2015)
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
Link to my Oilpro.com article on crude versus condensate: http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
As I have previously stated, IMO the global total liquids oversupply is a house of cards, built on an unstable foundation of actual global crude oil production* that requires vast amount of capital every year, in order to keep global crude oil production from crashing.
Up the thread, I noted that a plausible estimate is that it may have taken about a trillion dollars in 2014 and 2015 combined to keep global crude oil production around 68 to 69 million bpd, versus my estimate of 69 million bpd in 2005.
*45 API Gravity and lower crude oil
Maybe KSA is FOS? Maybe that statement is not true.Heinrich Leopold, 02/14/2016 at 10:25 amAlexS,Jeffrey J. Brown, 02/14/2016 at 10:31 amIn my view the past surge in shale production was based on the favorable conditions of the bond market ('search for yield'). As long as the bond market has been liquid, production could surge. However, as the recent collapse of the bond market starts affecting production (see below chart) we could see another 'black swan' event on the downside of production.
An analyst on CNBC had an interesting quote, which he attributed to John D. Rockefeller, to-wit, there has been more money lost to the ill advised search for yield, than in all of the bank robberies in recorded history.Heinrich Leopold, 02/15/2016 at 12:56 amJeffrey,AlexS, 02/14/2016 at 11:26 amAll the three bubbles of the last decade – internet bubble, housing bubble and now the shale bubble – reflect deeply the American approach how to respond to challenges in the economy and society: It is better to ask for forgiveness than to ask for permission. Greenspan famously said when the internet bubble burst: You can only recognize a bubble when the bubble has burst. This approach has probably avoided also some damage ( for instance an escalating oil price surge), yet has also done some huge damage to investors.
The lesson for investors is to recognize and understand the thinking behind Wall Street's motivation and adjust the investment strategy accordingly. As the bond collapse is far from over, we have not yet seen the bottom of the production decline. The bond market is the major driver of oil and gas production. Any forecast which ignores changes of capital markets is very likely irrelevant.
Heinrich,Ron Patterson, 02/14/2016 at 12:14 pmYes, access to cheap money (not only bonds, but also bank loans) was one of the key factors that contributed to the shale boom.
As regards the 'black swan' event on the downside of production, we will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat.
TechGuy, 02/15/2016 at 3:27 amwe will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat.I agree if you are talking about the money the bankers and investors already have invested in shale. But the bankers and investors will not likely be looking for ways to lose more money. New investment in shale will be difficult to come by.
Ves, 02/14/2016 at 12:23 pm"Nationalize it and this annoying little issue of profit pursuit disappears."US banks were not "nationalized" during the 2008-2009 crisis. I very much doubt the gov't will nationalize the Oil industry, unless there is a very drastic event that cause the price to skyrocket suddenly (ie above $200). A KSA/Iran hot war would probably do that.
Collapsing Oil prices is just a symptom of a mounting global economic crisis. Even if the US nationalized its Oil industry it still not going to fix problems overseas: The Middle East, China and Europe.
The period of kicking the can with ease has reached its end. Now the World's gov't will need to resort to ever increasing drastic actions to avoid a global depression.
likbez, 02/14/2016 at 1:03 pm"we will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat."Maybe they start investor focused campaign "World is running out of oil" meme :-) LOL … similar to "We are running out of land" meme during Housing bubble :-) Just kidding. :-)
Heinrich,Heinrich Leopold, 02/15/2016 at 2:56 amI think we should view "surge in shale production" not as something "based on the favorable conditions of the bond market" but as yet another "boom and bust" cycle which is the hallmark of neoliberal economy. Third in the sequence dot.com-real estate-shale oil, if you wish.
In all three cases it was reckless financing using new instruments which became available after deregulation which initiated the bubble. In this case covenant-light loans -- the crappiest kind of junk.
Like in all previous bubbles the deflation of the shale bubble might take some banks (this time regional) with it and result in a real extinction of shale companies. Technological progress achieved will remain intact and will be picked up by survivors.
The wave of bankruptcies will depress new drilling and might serve as another catalyst of the decline of shale oil production in 2016 and 2017 (despite takeover of properties). The decline that was not accounted for in the current forecasts.
Unlike two previous bubbles, this is a more localized disturbance and the size of CCC and lower junk bond market is just around one and a half trillion, but it will likely spread to the broader economy at least in six affected states due to links to mortgages, commercial real estate, municipal bonds, etc.
And it coincides with the weakening of the US economy.
likbez,Dennis Coyne, 02/14/2016 at 10:39 amCCC and lower is just the canary in the mine. It is a sign of strength or weakness in the sector. It affects also private equity, loans….
The big question now is: How far will this go? Can it escalate? As this is impossible to predict, it is also impossible to make an accurate production forecast – even for the next two years.
It is ironic that even the FED -- having thousands of economists on its payroll -- has been a very bad forecaster. Greenspan did not recognize the internet bubble, Bernanke had to deal with the housing bubble ( the housing crisis is contained) and now Yellen has to face the shale bubble, which she did not foresee (in December there was still talk about escape velocity and inflation).
It is still open how deeply the burst of the shale bubble will affect the US economy. There could be some political events which brings out some oil production worldwide and the shale industry will be saved for a while. However, my gut feeling tells me that this will go very deeply. It looks like the FED has painted itself into a corner again.
Hi AlexS,R Walter, 02/14/2016 at 10:51 amI agree. Also your point about oil prices is important, oil prices are very difficult to predict and eventually they will affect output, though there is a significant time lag (maybe 18 to 36 months) between a change in oil prices and a change in the oil supply. I have not yet figured out what this time lag is, but my current guess is about 24 months on average.
This will vary depending on the oil field (deep water projects have a longer lag and onshore conventional and LTO may be somewhat shorter than the global average).
http://www.theoildrum.com/files/PeakOil1.pngAlexS, 02/14/2016 at 11:28 amAnother forecast that was incorrect.
Who were the authors of those forecasts?R Walter, 02/14/2016 at 1:44 pmRon Patterson, 02/14/2016 at 2:12 pmEdit
So Ace got it wrong. We have been knowing that for a long time. That's history. What's your point?likbez, 02/14/2016 at 7:02 pmOil production will definitely, one day, peak. The fact that past predictions of peak oil were wrong only means they were too early. People who are predicting peak oil now, or at any time in the future, will be 8 years closer to hitting the date than Ace did.
I am reminded of insider traders in the stock market. That is company executives buying or selling stock in their own companies. The saying is, They are almost always right. But… They are almost always too early.
That is, they see that something is definitely happening so they act. But they just expect it to happen way before it really does. The same can be said about peak oil prognosticators. We saw that peak oil was definitely going to happen. But most of us were way too early with our prognostications, about 8 years too early. :-)
Ron,AlexS, 02/14/2016 at 11:44 amI am reminded of insider traders in the stock market. That is company executives buying or selling stock in their own companies. The saying is, They are almost always right. But… They are almost always too early.
An excellent point --
Dennis,George Kaplan, 02/14/2016 at 4:26 pmYes the time lag is different for different type of resource, different type of projects, different producing fields, different countries and different companies.
A big question is how to calculate this time lag.LTO was expected to be the first to react, and it indeed reacted the most. But I was expecting much bigger declines last year.
Conventional output was almost unaffected last year (low short-term price elasticity). There will be some negative supply-side impact this year, but the biggest cumulative impact from low prices should be felt by 2020.
With LTO the production was accelerating y-o-y at a high rate, more in percentage terms than has been seen in fields before, at least since the very early days of the industry. The cut has been from that high rate to a slow decline. If the LTO production had been steady or a growth rate that was more representative of previous new fields then the decline would have been pretty steep by now. That and the different impact, and decoupled timing, of drilling and completions compared to conventional fields is what through off a lot of the predictions in my opinion.Dennis Coyne , 02/14/2016 at 7:11 pmHi AlexS,AlexS, 02/14/2016 at 8:00 pmI read your reply on the previous thread and I appreciate your insight. I think I mostly agree with your take.
One place that I may not agree is that you think $45/b is high enough to keep output flat. I think that in the LTO plays $45/b is not enough to make the completion of drilled uncompleted (DUC) wells financially viable so we will see a fairly steep decline in LTO output if the EIA oil price forecast is correct.
In addition there are no doubt fields throughout the World where there are few long term projects in the works, but have continual infill drilling that either maintains a plateau or reduces the overall field decline rate. I would expect that even $45/b may not be enough to justify the continued drilling of new wells in many fields.
Note that the EIA STEO predicts Brent at $46/b in the fourth quarter of 2016. This is the reason that I believe the EIA's oil supply forecast is too high (assuming their price forecast is correct). I would expect at least a 1 Mb/d drop in 2016 average annual World C+C output compared to 2015 average output levels if the EIA's most recent oil price forecast for Brent crude is correct.
Dennis,Dennis Coyne , 02/14/2016 at 8:20 pmI didn't say that "$45/b is high enough to keep output flat". I said that $40-45/b is enough to cover operating costs and maintenance capex in a vast majority of the world's currently producing conventional fields (as well as oil sands operations).
That doesn't mean keeping production flat. Where production was falling due to natural declines at $90-100, it will continue to decline (probably, at higher rates) at $40-45.
Project delays and lower upstream capex will also have a negative impact on new conventional production. But as project start-ups scheduled for 2015-17 are generally not postponed, the overall impact on global conventional production will be relatively modest this year. However the effects of low prices will gradually increase in the next few years and peak by 2020, even if oil prices recover by that time.
As regards LTO, I agree that $45 is not enough to keep production flat. I guess the required price is closer to $60.
Finally, I certainly do not expect global C+C production to drop by 1 mb/d y-o-y in 2016. Barring unlikely OPEC cuts and unexpected large-scale supply outages, the increase in OPEC output (Iran) should partially offset declines in non-OPEC production.
Hi AlexS,Ron Patterson, 02/14/2016 at 10:27 pmSorry I misunderstood. Let's assume the EIA STEO oil price predictions are correct.
What would you expect for the average annual C+C output level in 2016, if that assumption were correct?
Note that I also do not expect C+C output will fall by 1 Mb/d, but the reason will be that the EIA's oil price prediction will be too low. I expect an average annual Brent price level for 2016 of about $55/b+/-$5/b and at that price level average annual C+C output will decline by about 500 kb/d in 2016 (about 79 Mb/d for an average output level) relative to the average 2015 output level (about 79.5 Mb/d).
average annual C+C output will decline by about 500 kb/d in 2016 (about 79 Mb/d for an average output level) relative to the average 2015 output level (about 79.5 Mb/d).likbez, 02/14/2016 at 1:07 pmThrough the first ten months f 2015, world C+C production has averaged 79.94 Mb/d. If we have the decline that I expect in November and December, I believe the average for 2015 will be around 79.85 to 79.9 Mb/d.
I expect 2016 C+C production to be about 78.9 Mb/d or a decline of about 1 million barrels per day.
Below is the 2015 C+C production, through October, according to the the EIA. The Peak so far, was in July 2015 at 80,525,000 million barrels per day.
Jan-15 Feb-15 Mar-15 Apr-15 May-15 79,379 79,371 80,175 79,988 79,369 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 80,038 80,525 80,439 80,038 80,071
The time lag probably also depends on when financial spigot that inflates the bubble is shut down.clueless, 02/14/2016 at 6:44 amFuture accounting problems – There have been many posts here over the past 2 years analyzing the cost incurred by the O & G companies to produce LTO. In my opinion, some of the ability to do that may go away.Enno, 02/14/2016 at 8:18 amMost companies have had to write down the balance sheet value of their LTO reserves (costs incurred) in 2014, 2015 and probably will again in 2016. If the price of oil increases, write ups to reinstate the value back to where it was are not permitted. So the true costs become invisible. So, if in 2017, if the price of oil is back to $50, companies could produce income statements that show a profit. But, some of that will be because much of the cost was written off in previous years due to "one time, extraordinary valuation write offs."
The companies offset the oil being sold with a DD&A [depletion, depreciation and amortization] cost. In general, that means that they ratably deduct their capitalized costs over each barrel of oil produced. But, if they have already written off half of their capitalized cost due to a valuation write off, then future DD&A will be one half of what it would have been without the write off.
And, it will likely be very difficult in 2017 to separate out their 2017 operations.
Clueless,shallow sand, 02/14/2016 at 11:15 amExcellent point. That is why careful investors, like e.g. Warren Buffett, don't accept accounting profit.
They calculate something like "owner earnings", in which you ignore accounting DDA and include your own conservative estimate of the depletion/depreciation of assets.In my opinion, there is a seriously flaw in the calculation of the accounting profit for LTO companies. The depletion/depreciation amount doesn't fully reflect the actual reduction of the NPV of the assets over a year. In other words, the very fast decline in production of shale wells, and the larger variable costs later in the life of a well, are not fully accounted for. LTO companies are in general getting away with a much smaller DDA amount, and therefore front loading profits. Normally lowering DDA is a bad corporate strategy, because it leads to more corporate taxes, but these companies in general also benefit from major tax deductions to compensate for this. I think this accounting flaw has played a big role in the shale boom.
Most retail investors unfortunately take book profits and book value too seriously. Like Shallow sand, you, and others have shown, there are much better ways to make value estimates.
Good points, as we have discussed previously. If oil prices don't return to 2011-14 levels, tough to see how loan principal gets paid.clueless, 02/14/2016 at 1:18 pmAsset sales to pay principal are self defeating. Due to IDC elections, depletion and depreciation, would seem that shale asset sales would generate a lot of tax liability. A $1 billion sale may generate only $600 million after tax?
Also, assets sales cause company wide production to fall.
Interesting how all of the companies in 2015 are reporting year over year production growth AFTER excluding the effects of asset divestures. So we are selling production to drill more wells to grow production. Our production is falling, but by gosh we have more new wells with 1 million EUR.
The production they are selling tends to have higher OPEX, but lower decline, and therefore, despite the higher OPEX, more PV per BOE.
A prime example would be Whiting, who last summer tried to sell its North Ward Estes CO2 flood.
As I recall, NWE accounted for less than 10% of company wide BOE in 2014, yet almost 20% of PDP PV10. This despite having much higher current OPEX than the Bakken and Nirobrara assets.
I have never understood how long term value is being created by these companies. One thousand 200 BOE average wells will be 40 BOE average in 5 years, for example, yet little to no ability to pay down debt principal.
PV10, 9, 8, or whatever discount value is appropriate does matter. Now that PDP PV10 is greatly less than long term debt, I hope some investors pay attention to it.
SS – I believe that current asset sales generally are unlikely to result in any cash taxes being paid. Especially since prices have fallen so much in the last year and a half. Further information below, for those who might want to delve a little deeper, but not fully into the complexities.shallow sand, 02/14/2016 at 2:44 pmAs you know, the companies deduct most of their drilling/fracking costs on their tax returns in the year that the money is spent. But, for their financial presentation books, following the GAAP principle to match expenses with revenue, these expenses are capitalized and included in their Oil & Gas Assets. For the financial statements these costs are rateably amortized as production occurs as DD&A expense.
Generally speaking, the companies create significant net operating losses on their tax returns because of those deductions. However, because in the future they will eventually deduct the costs [DD&A], but they cannot again deduct them for tax purposes, they are required to book deferred taxes payable as a liability.
Looking at PXD. At year end they have a $1.776 billion long term deferred tax liability. Using a 32% tax rate, this can imply a tax net operating loss of up to $5.55 billion. Assume that they have a producing field on the books at $500 million [GAAP using $49/bbl], with future drilling prospects, and a zero tax basis. They sell it for $1 billion, a $500 million book profit. A 32% tax on the book profit is $160 million, which is recorded in the income statement, but, which does not have to be paid. It offsets some of the net operating losses. The tax return shows a gain of $1 billion, an extra $500 million. The 32% tax on that extra $500 million offsets their deferred tax liability of $1.776 billion, reducing their deferred tax liability to $1.616 billion.
Clueless. Yes, have to work it through to get a clear picture.simon oaten, 02/15/2016 at 7:23 amEnnoR Walter, 02/14/2016 at 7:59 amone of the "things" that the shale industry has given the oil industry is lower "finding costs" ……at the "expense" of greater variability in outcomes (EUR / IP / PV10). Again – thankyou for your site – outstanding work
rgds
simonMore accurate than this one:Matt Mushalik, 02/14/2016 at 8:08 amMy latest graphs using EIA update to October 2015clueless, 02/14/2016 at 12:26 pm15/2/2016
World outside US and Canada doesn't produce more oil than in 2005
http://crudeoilpeak.info/world-outside-us-and-canada-doesnt-produce-more-crude-oil-than-in-2005Thanks! Much more than an excellent presentation!Jimmy, 02/14/2016 at 4:34 pmAwesome article Matt! Thanks for fleshing out the EIA report data!!Hickory, 02/14/2016 at 5:37 pmExcellent site Matt!clueless, 02/14/2016 at 12:12 pm
http://crudeoilpeak.info/One question- I see that you have US crude imports at about 7Mbpd, where as Jan data from iea have US net liquids import at about 5 Mbpd.
Is this difference because we export things like refined product and condensate?A big 2 page story in the business section of today's Daily Oklahoman. Oklahoma's oil production is up over 100,000 bbl/day starting in December – over 25%. Well, actual production is not up, but the EIA started doing their surveys last year to get more accurate production numbers. After months of consultation with the Oklahoma Tax Commission, they agreed that the EIA #'s are the correct ones. The OK Tax Comm claims that they have been collecting the right amount of tax.Ron Patterson, 02/14/2016 at 12:30 pmApparently, the data is loaded into a 30 year old mainframe system and computer program. Any data that does not match is kicked out of the system. That data is then processed manually but, has never been able to be loaded back into the existing computer system. So, numbers from Oklahoma have been understated for a long time. The Tax Comm says that they have one year left [estimate] on a four year project to put in a new computer system that will fix their problem. Meanwhile, the EIA is going with their survey.
Is this really the 21st century?
The EIA explains their new methodology here:StuckinWalkerWorld, 02/14/2016 at 2:09 pmUpdating Monthly EIA Crude Oil Production Estimates for Oklahoma to Use Survey Data
Good afternoon–JAt the risk of hijacking of this thread, I have several questions to pose to this group, starting with why are petroleum imports from Canada continuing to increase? (See link to EIA below). Is it caused in part by the anemic Canadian dollar, the need to keep pumping because cash flow generation trumps all other considerations, or something else? Which leads to another question How much further must the price of petroleum decline before petroleum imports from Canada start to dwindle? Until it does–and who knows when that will happen -- I have a hard time believing that oil prices will move higher in the current cycle.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=W_EPC0_IM0_NUS-NCA_MBBLD&f=W
George Kaplan, 02/14/2016 at 3:54 pm
I haven't seen this discussed, but my apologies if it is a duplicate. Paragon Offshore to file Chapter 11 – is this the largest bankruptcy for offshore drillers so far?Frugal, 02/14/2016 at 7:12 pmhttp://splash247.com/paragon-offshore-set-declare-chapter-11-bankruptcy/
Oil crisis leaves the East barrelling out of controllikbez, 02/14/2016 at 9:11 pm"It's sad. These people never thought the day would come where a barrel of oil would be below $30 (U.S.)," he said. "They were just living for the moment and they were making a huge amount of money and just thought it would continue on."
The oil price collapse is also hitting the opposite side of Canada.
A very good article. Thank you!Frugal, 02/14/2016 at 10:27 pmThe fallout from the oil crisis - compounded by potential government job cuts - could hit the province worse than the infamous cod moratorium of the 1990s, said Wade Locke, an economics professor at Memorial University.
"A 30 per cent cut in government expenditures over three years at a time when the economy is weak because of oil prices and less remittance income from people working in the oilfields in Alberta?
"Yes, it's fair to say it could be harder than the moratorium," he said.
Those affects are being felt now. Fewer blue and orange ice-class cargo ships leave the narrow entry to the St. John's harbour, loaded with supplies for the rigs 350-kilometres offshore.
And with declining output from the three producing rigs and two of four exploration rigs temporarily shut down - two more are scheduled for shutdown in July - helicopters are bringing fewer workers back and forth right now.
Still, resilient Newfoundlanders are quick to list off the reasons they believe the downturn could be relatively short-term; that this is the bottom of a typical, albeit particularly painful, commodity cycle.
After all, there's still a great deal of interest in Newfoundland's offshore oil, which is cheaper and cleaner to extract than oilsands crude. A government land sale in the Flemish Pass basin took in a record $1.2 billion of new oil company spending commitments. There are an estimated 12 billion barrels of oil reserves in that area alone. The province believes the number of job openings will increase beginning in 2019, when it anticipates major project expansion will resume.
… … …
….new home construction has dropped by 20 per cent.
…Insolvency filings are up 22 per cent over the last year at accounting and insolvency firm Noseworthy Chapman.
…Two of the seven offshore rigs that the base supplied in 2014 have shut down temporarily. The marine base is taking a revenue hit, but so far there have only been a few layoffs, he said.
…Food banks in the province provide food to nearly five per cent of people in the province, the second highest level in the country.
…8.2% - Percentage of Newfoundland workers projected to lose their jobs in next three years, amounting to 24,000 job losses
… $1.9B - Deficit projection in 2015-2016 fiscal update, nearly twice what was expected in the budget
… $12.4B - Newfoundland's net debtLooks like everything is connected those days. Or "over connected". A lot of common people suffer consequences of those big boys games. Business bankruptcies lead to personal bankruptcies.
I wonder where they got the 12 billion barrels of reserves from. Wikipedia gives the following numbers for the estimated oil in place:Doug Leighton, 02/14/2016 at 11:36 pm
Hibernia = 2.1 billion barrels with 700 million already produced by 2010
Terra Nova = 400 million barrels
White Rose = 440 million barrelsAs far as I can tell, these are the only major oil fields off Canada's east coast.
Dead on Frugal,George Kaplan, 02/15/2016 at 8:42 am"A government land sale in the Flemish Pass basin took in a record $1.2 billion of new oil company spending commitments. There are an estimated 12 billion barrels of oil reserves in that area alone."
So what is it, 12 billion barrels or 300 to 600 million barrels? Total production 1977-2005 at Prudhoe Bay = 11 billion barrels with perhaps two billion barrels of recoverable oil remaining. Let's be generous and say 0.5 billion barrels total in the Flemish Pass Basin; 12 billion, no bloody way.
"In late September 2013, Statoil ASA and its 35 per cent joint-venture partner, Husky Energy Inc., announced two back-to-back light crude discoveries in the deepwater Flemish Pass Basin, offshore Newfoundland. The larger of the two discoveries, the Bay du Nord exploration well, confirmed the existence of 300 to 600 million barrels of 34 degree API oil recoverable."
http://www.albertaoilmagazine.com/2014/01/light-crude-discovery-newfoundland/
Hebron – comes on line 2017, maybe 700 million barrels or more of heavy oil. BP and Shell each paid about $1 billion for exploration rights offshore Nova Scotia. Shell is drilling at the moment The author might also be considering 'equivalent' oil offshore Labrador which might have a lot of gas (but very difficult to develop). There are a couple of areas on the border with USA which are off limits at the moment. Against this Terra Nova and WhiteRose are well into their run down phases and don't have much left.Green People's Media , 02/14/2016 at 11:30 pmSay, Ron, have you looked at the most recent Drilling Productivity Reports? A couple days ago, they showed the major frack-oil fields having a reversal of legacy well declines. Bakken, Eagle Ford, etc. all show an UPWARD move in the legacy graphs (in other words, they're losing less production monthly than they were previous few months).Econ, 02/15/2016 at 2:47 amI thought that looked really odd.
What is your thinking on this?
Bobby G,
at the GPM
I think that is due to the decline rate being very high initially for new wells followed by a long period of slower decline and more steady production over the course of a well's life. As new producing wells were only enough in quantity to keep production flat (rather than increase it like previous years), there was less proportionally of this initial production spike and steep decline, and more proportionally of the slower more gradual declining production due – the composition of the wells now being mostly older rather than many new wells.AlexS, 02/15/2016 at 3:33 amAlso as production had fallen a bit, the decline should naturally be smaller even at the same decline rates. For instance a 10% decline on 1,000,000 mbpd will be higher than the decline at 10% on 900,000 mbpd
New shale wells have much higher decline rates than the old ones.Ron Patterson, 02/15/2016 at 8:32 am
The less the number of new producing wells, the lower is the average decline rateIt does not look odd at all. That is exactly what you would expect, as Alex and Econ pointed out. Production is declining and therefore you have less oil to decline. And fewer wells are coming on line and older wells have a slower decline rate than new wells.Oldfarmermac, 02/15/2016 at 9:37 amI didn't get back to say thanks for the answers to my question about condensate energy content yesterday, or day before but thanks everybody.Ron Patterson, 02/15/2016 at 9:49 amMaybe somebody who can still remember their math will calculate the loss of energy per average barrel of so called total liquids as the percentage of condensates increases, with the quantity of conventional crude decreasing.
At first glance it looks as if the rising percentage of condensate is cutting significantly into the energy of an "average" total liquid barrel.
I have not run across any research yet performed with the intent of designing internal combustion engines to run mostly or entirely on condensates, but it would appear at first glance that using straight condensate, or a very high percentage of condensate as ice fuel would be practical and economic, so long as it continues to sell for substantially less than ordinary crude- at least in the case of large stationary engines, or engines powering equipment that mostly stays very close to a home base, such as farm machinery and heavy construction equipment. The condensate could probably be hauled to a big construction job or large farm at no more trouble and expense than LP .
Why blocking Obama's pick to replace Scalia could cost Republicans their Senate majorityshallow sand, 02/15/2016 at 11:21 amAssuming the president picks a Hispanic, African American or Asian American – bonus points if she's a woman – this could be exactly what Democrats need to re-activate the Obama coalition that fueled his victories in 2008 and 2012. Even if he does not go with a minority candidate, the cases on the docket will galvanize voters who are traditionally less likely to turn out.
That is exactly what I have been saying.
Keep in mind that a quarter of Nevada's population is Hispanic. Beyond being a battleground in the presidential race, there is also an open Senate race to succeed Harry Reid. Democrats will nominate a Latina and Republicans will nominate a white guy who is already in Congress.
This will absolutely assure that Harry Reid's seat will stay in Democratic hands.
More broadly, this could also undermine efforts by Senate Republicans to show that they are capable of governing and not just "the party of no."
Ron, looks like a leading choice is Sri Srinivasan. I know nothing about him, other than what I have just read. 48. Born in India, raised in Kansas, Stanford graduate. Was appointed to DC circuit and confirmed by senate 97-0, in 2012.Ron Patterson, 02/15/2016 at 11:27 amGood question shallow. But I don't think he will be shot down. Even if he is the nominee McConnell will not allow it to come up for a vote. He will just sit on it until the next president is elected. And sit on it longer if a Republican is elected. Which is not likely.clueless, 02/15/2016 at 4:59 pmThat is just what they do. They are the party of NO!
I know that this is useless to point out, but Harry Reid said "no vote" to almost every single proposal passed out of the Republican controlled House.Fernando Leanme , 02/15/2016 at 1:55 pmThe question is how many of those Hispanic "Nevadans" have the right to vote. I bet less than less than half of that quarter.shallow sand, 02/15/2016 at 11:32 amAnd my guess is you'll see republicans very motivated to avoid an imperial presidency ruling by decree backed by an activist court. That reminds me of Venezuela.
I think a post of mine might have been lost.shallow sand, 02/15/2016 at 12:40 pmIn summary, I was comparing PXD (Pioneer) with CLR (Continental).
PXD produced 204K BOEPD in 2015, 53% oil. PV 10 12/31/15 $3.2 billion at $50 WTI, 89% PDP.
CLR produced 222K BOEPD in 2015, 63% oil, PV10 12/31/15 $8 billion at $50 WTI, 43% of proved reserves are PDP.
PXD enterprise value much greater, plans to grow BOEPD in 2016.
CLR enterprise value less, plans to shrink BOEPD in 2016.
Big difference, PXD well hedged, CLR is not.
Why the great disparity in PUD PV10? PXD supposedly has the most core acreage in Permian?
I really would like to see these reserves reports. I don't see how CLR has much in the way of PUD PV10.
Note, proved reserves % PDP doesn't necessarily equal % of PV10 that is PDP.dclonghorn, 02/15/2016 at 2:57 pmI will wait for 10K. I think we will find at $50 WTI, almost all have less PDP PV10 than long term debt.
Further, I hope we get indication in 10K what PV10 is at $30 WTI.
Something has looked fishy to me with CLR reserves and production every time I looked at it. I just stay away from that one.shallow sand, 02/15/2016 at 5:58 pmdclonghorn.dclonghorn, 02/15/2016 at 7:16 pmIronically I used the "fishy" word too discussing CLR today.
Don't know anything they report is not correct, just seems OPEX is always very low compared to peers operating in the same areas.
Seems odd that PUD BOE would be 57% given terrible economics for new wells.
Again, BOE reserve category percentages do not equal PV10 value percentages, but 2/3 of OAS BOE reserves are PDP. Assume PXD is high % PDP reserves, given almost 90% of PV10 is PDP.
Also, never have figured out why all the $10+ million non core wells in places like Divide, Stark, Elm Coulee, etc, haven't caught up with CLR. EOG, WLL, QEP and others seem to have better wells/ locations companywide in Bakken.
Oh well, it's just speculation. Maybe the 10K's will give us more clues.
If you look at Enno's shaleprofile.com, you can get actual production curves for them and compare them with their presentation production. I made that comparison when Enno's site first came up. It is a remarkable difference. I don't know how much NPV they assign to any of their reserves, but I've seen enough to know that I don't trust their reserves for volumes or dollars.dclonghorn, 02/15/2016 at 3:27 pmNorth Dakota should be releasing their December production numbers soon. A lot of people consider North Dakota's reporting as an indicator of the trends for all shale oil. Their reporting is much more timely than waiting 8 months to see what Texas looks like after revisions.Oskar DiSilvo, 02/15/2016 at 6:28 pmNorth Dakota surprised with small production gains for October and November. The EIA's November Drilling Productivity Report forecast a 27 kbopd decline from November's estimated 1137 kbopd to December's estimate of 1110 kbopd. North Dakota's report for November was 1119 kbopd. It may be that they trade some accuracy for timeliness as their monthly numbers seem to be very erratic. That said, I think they are due for a decline of over the forecast 27 kbopd.
Is KSA's strategy succeeding?http://fivethirtyeight.com/features/saudi-arabia-is-winning-its-war-against-the-u-s-oil-industry/
This article from Quartz is much more in-depth:
I have given up any pretense of trying to understand what will happen next, then further down the road. Except to understand, that at some point, depletion becomes unequivocally evident to all…then it will get 'interesting'.
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Javier, 02/13/2016 at 8:11 pmHi Ron,AlexS, 02/13/2016 at 9:22 pmOn the issue of EIA's predictions accuracy, I updated this graph from Mason Inman and added actual oil US production.
What this graph shows is a typical very conservative estimate system. This means that on the way up, they greatly underestimate production and on the way down, they are going to greatly overestimate production.
This clearly shows how credible their predictions are. Although the graph is only for the US, clearly they are going to be equally conservative (and thus equally wrong) about world oil production.
Javier,Javier, 02/13/2016 at 9:56 pmThe long-term projections of U.S. LTO production are from various issues of the EIA Annual Energy Outlook. They indeed were very conservative, even though none of them (even the AEO-2015) did not assume such a big drop in oil prices.
As regards the actual production data (the black line), it is from the Drilling Productivity Report and include almost 1 mb/d of conventional output, primarily from the Permian basin.
U.S. LTO production had never reached 5.5 mb/d, as the black line shows. According to the most recent EIA presentation, the local peak (In March 2015) was around 4.6 mb/d
OK, thanks. The black curve needs correction.AlexS, 02/13/2016 at 10:27 pmBut the issue continues being that EIA underestimated production so much that it had to raise its predictions by about 100% each year.
Look at the prediction for 2020:
AEO 2012: 1.3 mbpd AEO 2013: 2.8 mbpd AEO 2014: 4.7 mbpdAnd all this without any significant change in oil price.
So if the question is, as Ron is posting, how much value have EIA predictions? The answer clearly is none. EIA predictions are useless. Evidence indicates that they are going to overestimate production by a large amount for as long as production goes down.
These are projections for LTO, a new resource type. Its emergence as a new important source of global supply and its rapid growth was a "black swan" event, which nobody could predict.This is a good example why all such projections are just a snapshot that reflects our current knowledge of geology, technology and other factors affecting energy supply
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Jeffrey J. Brown, 02/15/2016 at 8:22 am
Interesting article on the RBN Energy website, about Cushing. Note that the author touches on two key issues: (1) Insufficient heavy crude to offset the flood of condensate, thus making it more difficult to create their "Synthetic WTI" blend and (2) Weak demand for the Synthetic WTI blend itself.The Reuters article from last year discusses the second point:
U.S. refiners turn to tanker trucks to avoid 'dumbbell' crudes (March, 2015)
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
Link to my Oilpro.com article on crude versus condensate:
http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
As I have previously stated, IMO the global total liquids oversupply is a house of cards, built on an unstable foundation of actual global crude oil production* that requires vast amount of capital every year, in order to keep global crude oil production from crashing.
Up the thread, I noted that a plausible estimate is that it may have taken about a trillion dollars in 2014 and 2015 combined to keep global crude oil production around 68 to 69 million bpd, versus my estimate of 69 million bpd in 2005.
*45 API Gravity and lower crude oil
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November 19, 2012 | The Oil Drum
Black_Dog on November 19, 2012
I think the EIA has been playing fast and loose with the petroleum statistics. As noted last week, the EIA Annual Review for 2010 states that the US produced a total of 9,443 mbbls/d, of which US crude production at 5,512 mbbls/day (which includes lease condensate), NGPL's at 2,001 mbbls/d and processing gain of 1,064 mbbls/d. The difference of 866 mbbls/d appears to be made up by biofuels.
Total product supplied is said to have been 19,148 mbbls/d, with imports minus exports totaling 9,434 mbbls/d of that. The amount of crude imported was 9,163 mbbls/d. From these data, the total crude supplied to the refineries was 14,675 mbbls/d, of which 62% is imported.
I've previously suggested that assigning all the processing gains to US production is factually incorrect, instead the processing gains resulting from refining imported crude should be added to the total for imports. For a rough guess, using the fraction of crude imported given above, 664 mbbls/d should be subtracted from the US production and added to the import side of the accounting. This revision reduces US production to 8,779 mbbls/d and increases imports to 10,098 mbbls/d, increasing the fraction imported from 49% to 53%.
Of course, the EIA misses the whole discussion about biofuels, especially ethanol, which require a large input of fossil fuels to produce the final product. The EIA ignores this fuel input, showing biofuels as an input to the front end of the refining process. With ethanol production now using about 40% of the US corn crop, it would be more accurate to consider this portion of the US agricultural system to have been added to the energy supply system and the energy used would thus become an internal consumption which would be subtracted from the petroleum energy available to the rest of society. Doing this calculation would increase the fraction of energy imported, which would give a more realistic picture of our situation...
E. Swanson
carnot on November 22, 2012
xoddam on November 20, 2012 - 7:21amSorry Guys but you have missed the point on refinery gains. It is a mirage. Remember the 1st law of thermodynamics.
Energy cannot be created or destroyed. US refiners continue to quote their refining capacities and products in barrels - a unit of volume which is meaningless unless a density unit is also quoted. What you should consider is the mass unit. In ALL refineries if you measure in units of mass it should add up to 100% plus the mass of hydrogen and other inputs added which increase the mass. ( methanol for an MTBE unit for instance).
When the crude is distiller in the crude unit it will produce a number of products with different densities and therefore different mass per barrel. Measure the products in barrels and you will have the following barrels per tonne.
Butane. 11
Naphtha 9
Gasoline 8.7
Jet 8
Diesel 7.5
Vacuum gas oil 6.8
Fuel oil 6.5In a cat cracker, with no hydrogen addition the mass of products is constant but because the volume of LESS dense light products exceed the total volume of HEAVY dense products , hey presto there is a refinery gain - in volume but not in mass.
Some refinery gain is due to the addition of hydrogen but typically this is 2-3% of the overall mass flow. Refiners love to sell in units of volume as they can benefit form the sleight of hand of selling a less dense and lower energy product to unsuspecting drivers. When energy density is compared in mass units there is NO significant difference between gasoline, jet or diesel. It is about 42-44 MJ per Kg but very different in volume units.
That is why diesels appear 30% more fuel efficient on volumetric terms but in reality the difference is much less.
A number of people have posted the same argument each time "refinery gains" are mentioned, but it does not universally hold true.Cracking can be done without addition of hydrogen, either by separately coking the heavier fractions of the crude before cracking (producing large volumes of solid carbon-rich petroleum coke, frequently a desirable byproduct which is further improved for use in metallurgy), or coking by deposition on the catalytic cracker unit itself (usually simply burned off in batches).
In neither case does any non-crude-oil energy input contribute to the increased volume of the light hydrocarbon products. Indeed the liquid products are of considerably less mass and energy than the input crude petroleum.
Indeed to the best of my knowledge hydrogenation in cracking units is not the norm. The main use of hydrogen in petroleum processing is in fact to remove sulfur and nitrogen from the fuel -- in which process it does not add energy to the desulfurised fuel product, but rather to the sulfuric and nitric acid byproducts.
http://en.wikipedia.org/wiki/Hydrodesulfurization
The hydrogen may be generated by steam reformation of natural gas, but coke from crude oil is also used as feedstock for steam reformation.
mbnewtrain on November 20, 2012 - 10:42am PermalinkYes, thank you for clarifying that. I've tried to clarify it for people before, but your explanation is much better. People tend to assume that "refinery gain" comes from adding hydrogen, but that's not generally true - in most cases it comes from removing carbon, ie "coking". Refineries prefer to do it that way because hydrogen is very expensive, and petroleum coke is a valuable product. In either case, the EROEI is much less than unity - in the case of coking, it is less than zero.
Darwinian on November 20, 2012 - 9:18am PermalinkFrom a chemistry standpoint:
If the refinery is breaking H-C bonds in the hydrocarbon chain molecule and producing free C (which you call coke), then the liquids produced have shorter chain molecules (total number of carbons reduced). Fewer H-C bonds mean lower energy. So using catalytic cracker that produces coke removes energy from the resulting liquid.
My claim of lower net energy in the oil product still stands regardless of refining method. In either case refinery gains should not be counted as energy production.
The US has refinery process gains of over one million barrels per day. That is almost as much as the rest of the world combined. They have to be counting refinery process gains on imported oil.
Black_Dog on November 20, 2012 - 10:59am PermalinkThat is correct. The EIA is counting "refinery gain" on imported oil as "US oil production". It is a totally bogus product by any standard, and the only reason I can imagine them doing it is to artificially inflate US oil production statistics. This has to be politically motivated.
RockyMtnGuy on November 20, 2012 - 12:18pm PermalinkAnd the IEA bought into the EIA's misinformation (call it a lie) with their latest report, which means either that they don't understand the EIA's reporting or they are complicit in the act of overstating US production. Your choice...
E. Swanson
Black_Dog on November 20, 2012 - 1:08pm PermalinkThere is an addition factor which the EIA is not going to want to make clear. US oil imports are increasingly coming from Canada, and most Canadian oil production is now from the oil sands as Canadian conventional oil production declines and oil sands production increases. Canada now exports more oil to the US than it consumes itself.
The product which is exported is mostly bitumen, which is not "tar" as some people would have you believe, but it is about the heaviest grade of oil you can buy. Midwest oil refineries no longer have sufficient domestic oil to keep running, but there is lots of Canadian bitumen and it is very cheap to buy (although not to produce). They upgrade it using coking, and make a ton of money turning it into gasoline.
Despite the fact that the EROEI of coking is negative (there is an energy loss), there is a huge refinery gain in going from very heavy bitumen to much lighter gasoline. The EIA counts this as "US oil production" despite the fact it comes from the Canadian oil sands and involves a net loss of energy.
That's another factor in the huge "refinery gain" the EIA and therefore the IEA is counting in predicting the US will exceed Saudi oil production. It's not really oil, in physical terms it's some kind of an extreme vacuum, or a form of negative energy.
Furthermore, importing extra heavy oil from Canadian bitumen (aka, tar for those who don't understand that tar is derived from coal) sands requires the addition of some dilutant to the mix to reduce the viscosity enough to allow the mix to flow thru pipelines. Looking quickly at the EIS for the Keystone XL pipeline from the US State Department, one learns that the chemical makeup of those dilutants are company proprietary information. It's likely that these are made up of lighter fractions of crude oil, such as naphtha or even some NGPLs. The fractions with the lowest boiling point temperature would most likely be mixed in during the coldest months of the year when the oil would be most viscous.
The source of those dilutants is unknown, but there have been comments about building a pipeline from the US to Alberta to provide those chemicals. If this is done, the dilutants would be (are?) added to the export column of the EIA data, but would then be returned to the US along with the heavy oil and then recovered at some point during the refining process. The result could be like a loop within which (almost) no change in the total quantity of material occurs, but which appears as a reduction in total imports due to double counting in the EIA volume based data...
E. Swanson
Looking quickly at the EIS for the Keystone XL pipeline from the US State Department, one learns that the chemical makeup of those dilutants are company proprietary information.
Proprietary, shmoprietary, it's only the State Deparment that doesn't know what's in it. If you Google, "Western Canadian Select", you'll find out more than you ever wanted to know about it. They're trying to sell it, after all.
speculawyer on November 20, 2012 - 10:08pm PermalinkWhat is Western Canadian Select crude?
Western Canadian Select is a Hardisty based blend of conventional and oilsands production managed by Canadian Natural Resources, Cenovus Energy, Suncor Energy, and Talisman Energy. Argus has launched daily volume-weighted average price indexes for Western Canadian Select (WCS) and will publish this index in the daily Argus Crude and Argus Americas Crude publications.
...followed by a chemical analysis of the most recent sample of it.
What is going down the pipelines is a mixture of oil sands bitumen, conventional heavy oil, synthetic crude oil, condensate, and pentanes plus. The mixture varies from day to day. The buyers don't really care where it came from or how it was mixed, they only care that it meets specs, i.e. the chemical analysis is right.
There are pipelines carrying diluent from the US to Canada, and it is getting to be a big business with the increase in Canadian bitumen and heavy oil production. There are also rail cars full of bitumen going south, and carrying condensate and pentanes plus on the backhaul.
"Refinery gain" is definitely a misleading statistic but there is a point there. It is good to do your own refining. Jobs, value-add, refinery gain, etc.
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Guy Minton, 02/13/2016 at 5:47 pm
The big deals against oil prices are, now, the drop in (the increase) in future demand from 1.6 to 1.2%, per IEA, and the massive amount of oil that Iran is getting to lay out with unknown capital input. Supposedly glutting the market with 1.5 million more barrels with magic, I presume. However, I figure it, the drop in demand seems to indicate only about a 300k to 350k difference.Jimmy, 02/13/2016 at 6:37 pm
Ah, the magic of OPEC will prevail, then. Even though to fully ramp up more, Saudi has to drill in the offshore area, which I am sure is NOT $10 barrel cost of production. Iraq has to end their internal strife to gain some traction. Venezuela is sucking wind, badly. Ecuador, while not the massive producer of other OPEC members, currently has only one well drilling from 50 something rigs. It is hard to keep up with the news from every country, and it is clear that neither EIA nor IEA are really putting much effort into real data accumulation. I think OPEC is strapped for production for the next two years, with the exception of the magical production from Iran.
On the other hand, I read Canada has some smaller oil sands shut in, while larger ones are scheduling to cut back, or have extended periods of overhaul on production equipment. As rigs for conventional oil have dropped significantly, I fail to see were Canada will not have a decrease in production in 2016. Over a year ago, I said the shale production could drop by over one million, but didn't anticipate the increase before the drop. Still from the high in March of last year, it is still projected to drop by 1.2 million by 2017 by EIA. I still thing they are low in their estimate of the drop, but not as much as they used to be.
I read where China's production is expected to drop from 100k to 200k in 2016, base upon the current prices and capex. A recent post by the author indicates that up to 1.5 million barrels may be lost from in field drilling of offshore wells in 2016. All of South America, Africa, and Asia, including Russia, expect drops in 2016, and 2016 is just the tip of the iceberg.
Where are all of these figures in the garbage the EIA and IEA put out? Far as I can tell, the magical numbers put out for Iran, roughly match the drop in infield drilling offshore. But then I am not an expert, because I am not paid by a highly efficient and omniscient government entity.While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea!Jimmy, 02/13/2016 at 7:49 pmIt seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
Intro sentence should have read:While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption.
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Jimmy says: 02/13/2016 at 6:37 pm While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the non-OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea! It seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
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Oldfarmermac, 02/13/2016 at 3:46 pmHopefully somebody handy with a calculator will try to figure out roughly how much of total world production consists of condensates, natural gas liquids biofuels, etc.... ... ...
Jeffrey J. Brown, 02/13/2016 at 3:54 pm
I'm estimating that global crude oil production* was about 69 million bpd in 2005 and 68 million bpd in 2014. I would assume around 69 million bpd for 2015. Global total liquids production was 85 million bpd in 2005 and apparently about 96 million bpd in 2015.Doug Leighton, 02/13/2016 at 7:27 pmSo, I estimate that actual global crude oil production, as a percentage of total liquids, fell from about 81% in 2005 to about 72% in 2015.
In regard to the US, I estimate that actual crude oil as a percentage of total liquids fell from about 57% in 2005 (4.7/8.3) to about 49% in 2015 (7.3/14.8).
*45 API Gravity & Lower Crude Oil
Mac,likbez , 02/13/2016 at 8:34 pmI was chatting with my Norway niece (Nicole/Nikki) this morning and, I recalled, you were asking about the distinction between "oils" and their relative energy value. Remember, I'm 75 now and the grey cells are evaporating rapidly but we had a decent connection so this is (basically) her comment: all errors mine.
She said that any distinction between oil and condensate is artificial and arbitrary. They're both crude in that compositions are whatever came from the well with no processing other than simple separation. Apparently some oil people simply use five classifications for reservoir fluids: black oil, volatile oil, retrograde gas-condensate, wet gas, and dry gas. And, since most hydrocarbon liquids are close to the (CH2)n formula, the energy content/pound is fairly constant (roughly 17,000 BTU/lb).
Really heavy crudes can be difficult to refine because they're more likely to be contaminated with sulfur and heavy metals that can poison refinery catalysts, they're hard to pump, they can leave fouling on the process equipment, and they need more processing (cracking, reforming, alkylation) to produce light fuels (gasoline, diesel, jet fuel). According to her, the bigger concern would be the percentage of heavy industrial gunk which is useful only for big power plants, ships, and industrial furnaces or even road asphalt.
When she got into C12+ hydrocarbons, aromatics, benzene rings, alkenes and branched isomers I got bored and asked about her new boyfriend. Is that any use?
Doug,Dennis Coyne, 02/13/2016 at 8:35 pmThis actually is a pretty complex topic.
Please note that while the number of BTUs per unit of weight is equal for condensate and oil, the energy content per unit of volume (barrel) is not. It is approximately 12% lower for condensate (on average). So when you measure total production in volume units not weight units, and most of your production is condensate you inflate the amount of energy extracted. With 50/50 mix of oil and condensate the inflation is around 6%. That means that to get proper comparison with, for example, Europeans data where most production is Brent crude or heavier, you need to multiply US data with factor 0.96 or so to equalize the energy content. That also imply that any claim of world petroleum liquids production glut using volume comparison is unscientific. And any claim about "oil glut" which is less then 1% of total volume of petroleum liquids produced (around 1 Mb/d) is pure propaganda.
As Steve from Virginia aptly noted
http://peakoilbarrel.com/opec-january-production/#comment-559218What Jeffrey Brown points out over and over is the so-called 'glut' is simply another finance industry -slash- media narrative, a pleasant lie that glosses over the fact that fuel supply is declining, that purchasing power is declining along with it and that no easy solutions to these declines exist. The only solution is stringent conservation…
Repeating after Steve: "so-called 'glut' is simply another finance industry/media narrative". Or, if you wish, another noble lie in Leo Strauss style. See http://peakoilbarrel.com/collapse-of-shale-gas-production-has-begun/#comment-558479
Looks like the US elite is afraid to go full force into oil conservation mode and was unhappy with "secular stagnation" of the economy. It preferred to drop oil price to solve the problem of "secular stagnation" or at least to postpone the day of reckoning: yet another financial crash which is immanent under neoliberalism, but which might undermine their political power.
Instead, Obama administration adopted Madame de Pompadour "Après nous le deluge" ("after us deluge") mentality…
Also the mix of refined products you get from the unit of weight of each type of oil is different and you can never get even close in the amount of aviation kerosene and diesel from condensate as from WTI or Brent.
See Jeffrey Brown's post about rejection of some blends by US refineries for details.
Hi Doug,Fred Magyar, 02/13/2016 at 8:42 pmThanks that is very useful.
Below I show World liquids consumption in Mb/d and Mboe/d using BP data from the Statistical Review of World Energy.
To find Mboe/d I took world consumption in metric tonnes and assumed 7.33 b per metric tonne. Sorry about the typo on the chart, too late to correct.
We hit the peak in World output per capita in 1979.
When she got into C12+ hydrocarbons, aromatics, benzene rings, alkenes and branched isomers I got bored and asked about her new boyfriend. Is that any use?Watcher, 02/14/2016 at 1:25 amWell, compared to colliding black holes and gravitational waves, and E=MC^2, organic chemistry is pretty cut and dried…
Got a small problem with this.Fernando Leanme, 02/14/2016 at 6:26 amDiesel became used for a reason. Ditto jet fuel. Problems arose that were only solvable by changing to that fuel. There's a sort of overly glib presumption that energy content for condensate is only down and not zero, applied to . . . not a diesel engine but to the problem addressed by the diesel engine.
The volume/weight thing is a pretty big deal, too. Fuel tank capacity is not defined by weight.
Sorry, but Nicole is wrong. Oil is found as a liquid phase fluid in the reservoir, while condensate is found in the gas phase in the reservoir under static conditions. "Some oil people" isn't the right description. Petroleum engineers consider the initial conditions and composition of the hydrocarbon system to define how it would behave under different development and operating schemes. These groupings you listed are a very sensible and technically sound system to describe system behavior as the reservoir is produced.Doug Leighton, 02/14/2016 at 10:14 amFor the non specialist the separation of the crudes by API will do. Use 45 degrees, it seems to do the job. And don't worry too much about the other details. As we can see, even petroleum engineers can get s bit lost in this area, which is mostly the purview of hard core reservoir engineers and process equipment designers.
Nicole responds: "With respect, the term black oil is particularly imprecise and context-dependent; to a reservoir simulation engineer like me, that means the simplifying assumption that the fluid can be characterized by only two components, one of which can exist in only one phase whose properties we can characterize the other component dissolves in that phase; that phase is black as in "black box", not color. Usually the non-partitioning phase is the heavy component (separator oil may contain dissolved gas, but the gas phase contains no oil), but it works the other way, too (separator gas can contain condensate vapor, but condensate can dissolve no gas). When it's applicable, the black-oil assumption saves "lots" of computational effort."Dennis Coyne, 02/14/2016 at 11:09 amThank you Nicole and Doug for the information.Doug Leighton , 02/14/2016 at 12:16 pmIt seems if we are interested in the amount of liquid energy produced in terms of exajoules we would pay attention to the tonnes of liquids produced and just convert to Exajoules.
So for oil consumption data in BP's Statistical Review of World energy we would focus on the data by weight and use a conversion to Joules (or Exajoules).
One billion metric tonnes of oil equivalent are about 41.87 EJ.
Chart below with World Liquids consumption in Exajoules per year using BP Statistical Review of World Energy 2015.
Nicole left for her bi-monthly platform tour so I'll say if you stick to weight when doing your rough oil/condensate energy conversions your numbers will be OK. My Proviso: I'm NOT an oil guy. Don't include NG though, which is mostly methane (22,000 BTU/lb) ????Dennis Coyne, 02/14/2016 at 6:42 pmThanks Doug,Longtimber, 02/14/2016 at 12:59 pmYou know far more than me, just from your conversations with Nicole, and I believe you are also a geophysicist, and have worked in the industry. You may not be up to date on the latest oilfield tech, but you are very knowledgeable nonetheless.
The "liquids" are biofuels, NGL, and C+C in my chart. Methane is not included.
Barrels, BTU's, mcf, CMO, enough dungpiles -- Save us. Remember http://www.theoildrum.com/node/2320.Fernando Leanm, 02/15/2016 at 10:22 am
Real Energy, as in MT, Calories, EJ would be so clear.Nicole is still wrong. She answered the point I made with a rather pedantic point which failed to address my comment: the distinction between oil and condensate is whether they are found in the liquid or gas phase in the reservoir. Condensate is found as a gas in the reservoir. The distinction isn't artificial nor is it arbitrary. She has a bit to learn, probably because she's too much into her specific experience. Comments in a blog have to teach the audience whenever possible. Hers didn't.Doug Leighton , 02/15/2016 at 10:59 amRight, I'll suggest she forgo future comments. Nicole lacks confidence in her English anyway so it won't be difficult to muzzle her.Dennis Coyne, 02/15/2016 at 12:06 pmI disagree.notanoilman, 02/15/2016 at 3:06 amThe important point was energy per unit mass is the same. In Nicolas view if we are concerned about energy just look at mass produced. I agree.
Please keep the comments coming Douglas
Fernando knows more than me but not more than your niece.
I am a little puzzled over condensate. If it exists in the gas phase, in the reservoir with, presumably, high pressure, how does it condense to liquid when extracted and the pressure is reduced? I would have expected the reverse. Am I mis-understanding something, confused or just lost the thread?George Kaplan, 02/15/2016 at 4:04 amNAOM
At high pressures, as found in gas reservoirs, things don't work the same as at atmospheric pressure on the earth's surface. There is a phenomena known as retrograde condensation where as the pressure is reduced at constant temperature, liquid condenses out of the gas (.e. condensate). If the pressure is further reduced then it will start evaporating again (which is what we are used to seeing).Fernando Leanme, 02/15/2016 at 10:27 amIf the gas is cooled at the same time (which happens naturally when gas is let down in pressure with no heat source present, or if it cools from the hotter reservoir to ambient conditions, say in a pipeline) then there is relatively more liquid formed. In the past condensate was sometimes called drip gas as it dripped out of pipelines from a combination of these effects.
http://www.jmcampbell.com/tip-of-the-month/2007/06/why-do-i-care-about-phase-diagrams/
That was a pretty good explanation. Several years ago I had to explain the way this works to my boss, and I resorted to explaining that a multi component system had molecules bouncing around, and that at high pressure we saw the lighter molecules kicking the heavier ones into the gas phase if they ever decided to settle down into a liquid. It worked.George Kaplan , 02/15/2016 at 4:09 amI posted a long explanation that seems to have got lost, so try this:Forbin, 02/15/2016 at 5:36 amhttp://www.jmcampbell.com/tip-of-the-month/2007/06/why-do-i-care-about-phase-diagrams/
because it also hot and will exist as liquid at ambient temperatures.http://www.naturalhub.com/slweb/defin_oil_and_natural_gas.html
forbin
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Feb 12, 2016 | Oilpro
Global Condensate Versus Crude Oil Production EstimatesGlobal dry natural gas production rose from 270 BCF/day in 2005 to 335 BCF/day in 2014. In 2014, combined US + OPEC gas production accounted for 41% of global gas production in 2014.
If the US + OPEC condensate production estimates per BCF of dry gas production are similar to global values, it implies that global condensate production rose from about about 5 million bpd in 2005 to about 10 million bpd in 2014, an increase of about 5 million bpd. Note that global C+C production increased from 74 million bpd in 2005 to 78 million bpd in 2014, an increase of 4 million bpd.
Of course, the foregoing implies that actual global crude oil production (45 API Gravity and lower crude oil) declined from about 69 million bpd in 2005 to about 68 million bpd in 2014, as annual Brent crude oil prices doubled from $55 in 2005 to $110 for 2011 to 2013 inclusive (remaining at $99 in 2014).
Note that the global oil and gas industry spent trillions of dollars on global upstream capex after 2005, for 2006 to 2014 inclusive (on both oil and gas projects). But if it took trillions of dollars to keep us on a post-2005 "Undulating plateau" in actual global crude oil production, what happens to global crude oil production given the large and ongoing cutbacks in global upstream capex?
What's Actually in Those Storage Tanks?
We have seen a large year over year increase in US and global Crude + Condensate (C+C) inventories. For example, EIA data show that US C+C inventories increased by 100 million barrels from late 2014 to late 2015, and this inventory build has contributed significantly to the sharp decline in oil prices.
The question is, what percentage of the increase in US and global C+C inventories consists of condensate?
Four week running average data showed that US net crude oil imports for the last four weeks of December increased from 6.9 million bpd in 2014 to 7.3 million bpd in 2015. Why would US refiners continue to import large–and increasing–volumes of actual crude oil, if they didn't have to, even as we saw a huge build in US C+C inventories? And again, what the EIA calls "Crude oil" is actually C+C. And as noted above, based on the EIA analysis it appears that about 40% of US Lower 48 C+C production in 2015 exceeded the maximum API Gravity for WTI crude oil, 42 API Gravity.
The most recent four week running average EIA data shows US net crude oil imports remained at 7.3 million bpd, with net total liquids imports at 5.5 million bpd, up 17% from the 2015 average annual value of 4.7 million bpd.
I frequently cite a 2015 Reuters article that discussed case histories of refiners increasingly rejecting blends of heavy crude and condensate that technically meet the upper limit for WTI crude (42 API gravity), but that are deficient in distillates. Of course, what the refiners are rejecting is the condensate component, i.e., they are in effect saying that "We don't want any more stinkin' condensate." Following is an excerpt from the article:
U.S. refiners turn to tanker trucks to avoid 'dumbbell' crudes (March, 2015)
In a pressing quest to secure the best possible crude, U.S. refiners are increasingly going straight to the source.
Firms such as Marathon Petroleum Corp and Delek U.S. Holdings are buying up tanker trucks and extending local pipeline networks in order to get more oil directly from the wellhead, seeking to cut back on blended crude cocktails they say can leave a foul aftertaste. . . .
Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
My premise is that US (and perhaps global) refiners hit - late in 2014 - the upper limit of the volume of condensate that they could process if they wanted to maintain their distillate and heavier output. This resulted in a build in condensate inventories, reflected as a year over year build of 100 million barrels in US C+C inventories.
Therefore, in my opinion the US and (and perhaps global) C+C inventory data are fundamentally flawed when it comes to actual crude oil inventory data. Note that according to Iranian sources, the bulk of their floating offshore storage consists of condensate, which they were permitted to export under the sanctions. In my opinion, this suggests that we may be seeing both a US and a global glut of condensate in storage.
In any case, here is the critical point: If it took trillions of dollars to keep us on a post-2005 "Undulating plateau" in actual global crude oil production, what happens to global crude oil production given the large and ongoing cutbacks in global upstream capex?
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Daniel , 02/12/2016 at 7:44 am
Not sure how reliable this is, but drillinginfo index has the "new US production capacity" (oil and gas) dropping by 24% from January to February; which would be biggest drop since the collapse of the oilpriceRon Patterson . 02/12/2016 at 8:44 amThis headline shocked me: The Oil Industry Got Together and Agreed Things May Never Get BetterSW , 02/12/2016 at 9:10 amThousands of industry participants gathered in London for their annual get-together, only to find a world awash in crude and hardly a life jacket in sight.
The thousands of attendees seeking reasons for optimism didn't find them at the annual International Petroleum Week . Instead they were greeted by a cacophony of voices from some of the largest oil producers, refiners and traders delivering the same message:
There are few reasons for optimism. The world is awash with oil. The market is overwhelmingly bearish.
No Hope
Producers are bracing for a tough year. Prices will stay low for up to a decade as Chinese economic growth slows and the U.S. shale industry acts as a cap on any rally, according to Ian Taylor, chief executive officer of Vitol Group, the world's largest independent oil trader. Even refiners, whose profits have held up better than expected, are seeing a worsening outlook.
Perhaps their only hope is depletion?likbez , 02/12/2016 at 1:51 pmIs not Bloomberg simply a GS propaganda arm ?Jeffrey J. Brown , 02/12/2016 at 9:41 amI especially enjoyed the following statement
"As the world runs out of places to store oil, "I wouldn't be surprised if this market goes into the teens," said Jeff Currie, head of commodities research at Goldman Sachs Group Inc."
I think there should be is a special place in hell for Goldman commodity traders.
IMO, the global oversupply is a house of cards built on an unstable foundation of actual global crude oil production* that requires massive capital investments to keep crude oil production from crashing.Doug Leighton , 02/12/2016 at 10:00 amQatar is basically the poster child for post-2005 production. OPEC 12 data show that Qatar's reported crude oil production, despite billions of dollars spent on enhanced oil recovery, fell from 0.8 million bpd in 2005 to 0.7 million bpd in 2014 (OPEC crude only data), while EIA data show that Qatar's C+C production increased from 1.0 million bpd in 2005 to 1.5 million bpd in 2014.
Production of condensates rising in Qatar http://www.oxfordbusinessgroup.com/analysis/production-condensates-rising-qatar
*45 API Gravity and lower crude oil
Jeffrey J. Brown , 02/12/2016 at 10:32 am"IMO, the global oversupply is a house of cards built on an unstable foundation of actual global crude oil production* that requires massive levels of investments to keep crude oil production from crashing."Please provide a scale Jeff. Not that I don't agree with you; my buddy (petroleum engineer) who works in Kuwait from time-to-time insists their production rate is maintained by massive infill drilling BUT how long will the party last: a decade? Longer? Shorter?
I would think the second half of 2016 for a price recovery, but I thought we were in a price recovery phase this time last year. As for the duration of a price recovery, I don't have the foggiest.Ron Patterson , 02/12/2016 at 11:16 amAs an example of low probability events, two years ago if someone had asked us what we thought the chances were that Donald Trump, in early 2016, would be the most likely GOP nominee, and that oil prices would be in the 20's to low 30's, I wonder what we would have said.
Incidentally as noted up the thread, an interesting difference between the last oil price decline and the current (much more protracted) decline: Global liquids consumption fell by 2 million bpd from 2007 to 2009, whereas global liquids production reportedly rose by 3 million bpd from 2013 to 2015.
my buddy (petroleum engineer) who works in Kuwait from time-to-time insists their production rate is maintained by massive infill drilling…That is what is keeping two thirds of the world's oil fields from a 5 to 6 percent decline rate. Massive infill drilling is happening in Kuwait, Saudi, the UAE, Russia, the Gulf of Mexico and just about everywhere else in the world.
Normally the production profile of a field would resemble a bell curve with the top of the curve being the 50% depletion point. But with massive infill drilling, the top of the bell just levels out with only a slight decline, if any. But the depletion curve, if you could see it, would be dropping like a rock.
What infill drilling does is delay the decline curve until it too starts dropping like a rock.
BUT how long will the party last: a decade? Longer? Shorter?
My guess is about a decade. Saudi began their infill drilling projects over a decade ago and I believe the fields where this began is already dropping fast. But they have managed to keep production up by bringing on three giant fields, Khurais, Manifa and Shaybah.
But it depends entirely on the size of the field. Giant and super giant fields can maintain infill drilling and keep production up much longer than smaller fields, like those in the GOM.
But Kuwait's production has already started to drop and UAE production is just on the cusp. Russia also has, for almost a decade, had a program of massive infill drilling in their Western Siberia fields where about 60% of their oil is produced.
And folks wonder why I think peak oil is at hand. Geeze, isn't it obvious?
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Reuters
Faced with record low prices for heavy crude, Canadian energy companies are sacrificing other parts of their business to keep higher-cost oil sands production going and safeguard the billions already invested in these multi-decade projects.Companies including Husky Energy Inc HSE.TO, MEG Energy Corp MEG.TO and Pengrowth Energy Corp PGF.TO are selling assets or slowing light and conventional oil exploration and production, even as they forge ahead with oil sands projects that are in many cases bleeding money on every barrel.
... ... ...
Producers are also betting that oil prices will eventually recover. The latest Reuters poll of oil analysts forecasts the U.S. benchmark CLc1 will average $41 a barrel in 2016, a level where most Canadian oil sands projects can break even. [OILPOLL]
Bankers say the need to bolster balance sheets and cover oil sands losses will boost the number of Canadian energy deals this year, particularly sales of pipelines, and storage and processing facilities.
According to a recent TD Securities report, virtually no oil sands projects can cover overall costs, including production, transportation, royalties, and sustaining capital, with U.S. benchmark crude below $30 a barrel CLc1.The benchmark heavy Canadian blend, Western Canada Select (WCS), now trades around $16.30 a barrel, just a few dollars above record lows hit in January.
... ... ...
Bankers say that midstream assets - pipelines, storage and processing facilities - prove popular with buyers such as pension funds and private equity firms, which favor investments with stable cash flows that are relatively easy to value."They're to a certain extent the jewels in the crown. These companies would not be looking to sell them if they could get away with not doing it," said Citi's Kernaghan.
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AlexS , 02/09/2016 at 6:32 pm
It is interesting to compare the numbers from the recently released EIA Short-Term Energy Outlook (STEO) and Drilling Productivity Report (DPR).AlexS , 02/09/2016 at 6:44 pmIn today's STEO, the EIA did not change its forecast of C+C production in the Lower 48 states (excl. GoM) for 2016-17, although projected output in the Gulf of Mexico was slightly revised down.
By contrast, in the DPR released Monday the EIA predicts the seven major shale plays to produce 5.02 mb/d in February, 185 kb/d higher than in last month's forecast of 4.83 mb/d. The anticipated decline between the March 2015 peak levels and February 2016 is now 453 k/d compared with 638 k/d in January DPR. In general, the comparison between the EIA's DPRs of the past several months shows that the agency has been constantly underestimating the resilience of the LTO production.
The EIA still projects the monthly decline in 7 key shales oil production to accelerate from 73 kb/d in February to 93 kb/d in March.
Oil production in 7 major U.S. shales: EIA DPR Feb 2016 vs. Jan 2016 vs. Dec 2015
The biggest upward revisions were for the Eagle Ford (+77 kb/d for December, +100 kb/d for January, and +127 k/d for February). The EIA's estimates for the Eagle Ford remain lower than those from other sources, in particular, from Bentek Energy.Oil production in the Eagle Ford shale: EIA DPR Feb 2016 vs. Jan 2016 vs. Dec 2015
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crudeoilpeak.info
This recent forum was about how to transition away from fossil fuels, after the UN conference on climate change in Paris in November 2015. Moderator Yergin – who is a known peak oil denier – started by asking Fatih Birol what low oil and gas prices mean for the development of renewable energies. Fatih responded by first warning about the impact of lower oil prices on investments in the oil and gas sector:
(video 3:24)
Fatih Birol: "For the oil markets what worries me the most is that: last year we have seen oil investments in 2015 decline more than 20%, compared to 2014, for the new projects. And this was the largest drop we have ever seen in the history of oil. And, moreover, in 2016, this year, with the $30 price environment, we expect an additional 16% decline in the oil projects, investments. So, we have never seen 2 years in a row oil investments declining. If there was a decline 1 year, which was very rare, the next year there was a rebound"Daniel Yergin: "What does that lead you to?"
Fatih Birol: "this leads me to the very fact that in a few years of time, when the global demand gets a bit stronger, when we see that the high cost areas such as the United States start to decline, we may well see and upward pressure on the prices as a result of market tightness. So my message, my 1st message is: don't be misled that the low oil prices will have an impact on the oil prices in the market in a few years' time"
Daniel Yergin: "Just to put a number on that. Our numbers at IHS, 2015-2020 we see a 1.8 trillion dollar decline in upstream oil and gas investment"
... ... ...
The graph shows that conventional crude oil production is supposed to be basically flat. This is designed by adjusting the yet-to-be-found wedge. Unconventional tight (shale) oil and heavy oil/bitumen increase only slightly up to 2020. NGLs go up but these don't play a big role for transport fuels (except LPG).
If 80% of investments are needed just to offset decline, then the additional 2016 drop leads to such a low investment level that yet-to-be-developed projects are in danger, not to mention the assumed production from yet-to-be-found fields. An example of the latter is Shell ending its exploration in the Chukchi sea.
ConclusionChanges in investment projections were already underway before the 2014 oil price drop. To the extent that oversupply of US shale oil (including condensate filling up US inventories) has contributed to currently low oil prices, the drama evolving now is that unconventional oil – which was originally intended to be added to stagnating conventional supplies in the 1st phase of peaking oil production (2005-2008) – is now endangering this much larger conventional base production, including higher cost offshore fields.
Even if oil prices go up again US shale oil has already destabilized global oil markets by increasing volatility. Is that what we call a swing producer? Yes, swinging oil prices and investments. And for those who hope that oil markets will "rebalance" at $60-$70 there is no statistical evidence in the last 10 years that oil prices stayed for very long at these levels.
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Doug Leighton , 02/09/2016 at 12:03 pm
OIL PRICE RECOVERY WILL BE SHORT-LIVED, SAYS IEAdaniel , 02/09/2016 at 12:41 pm"A recent rise in oil prices is a "false dawn" and the oversupply of crude is set to worsen, according to the International Energy Agency (IEA)….
The IEA forecast that stock building could continue in the second half of 2016 at a rate of 300 million barrels a day. It said: If these numbers prove to be accurate, and with the market already awash in oil, it is very hard to see how oil prices can rise significantly in the short term."
300 mm bbp per day – wow :-)Watcher, 02/09/2016 at 1:04 pmThis is what happens when a theory is accepted as fact.If there's too much oversupply for storage to exist, well then, the oversupply must have been less than thought. In fact, find how much storage capacity there is, and essentially manufacture that number too, and then derive backwards how much is required to fill it, and then subtract another essentially imaginary number as to how much of the capacity was already filled on some arbitrary date - and you can declare how much oversupply "there must be".
They would be laughed out of the room at any physics seminar.
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U.S. Energy Information Administration
- North Sea Brent crude oil prices averaged $31/barrel (b) in January, a $7/b decrease from December and the lowest monthly average price since December 2003. Brent crude oil prices averaged $52/b in 2015, down $47/b from the average in 2014. Growth in global liquids inventories, which averaged 1.8 million barrels per day (b/d) in 2015, continues to put downward pressure on Brent prices.
- Brent crude oil prices are forecast to average $38/b in 2016 and $50/b in 2017. Forecast West Texas Intermediate (WTI) crude oil prices are expected to average the same as Brent in both years. However, the current values of futures and options contracts continue to suggest high uncertainty in the price outlook. For example, EIA's forecast for the average WTI price in May 2016 of $36/b should be considered in the context of recent Nymex contract values for May 2016 delivery (Market Prices and Uncertainty Report) suggesting that the market expects WTI prices to range from $21/b to $58/b (at the 95% confidence interval).
- The U.S. retail regular gasoline price is forecast to average $1.98/gallon (gal) in 2016 and $2.21/gal in 2017, compared with $2.43/gal in 2015. In January, the average retail regular gasoline price was $1.95/gal, a decrease of 9 cents/gal from December and the first time monthly gasoline prices averaged below $2/gal since March 2009. EIA expects the monthly average retail price of U.S. regular gasoline to reach a seven-year low of $1.82/gal in February 2016, before rising during the spring.
- U.S. crude oil production averaged an estimated 9.4 million b/d in 2015, and it is forecast to average 8.7 million b/d in 2016 and 8.5 million b/d in 2017. EIA estimates that crude oil production in January was 70,000 b/d below the December level, which was 9.2 million b/d.
- Natural gas working inventories were 2,934 billion cubic feet (Bcf) on January 29, 20% higher than during the same week last year and 18% higher than the previous five-year average (2011-15) for that week. EIA forecasts that inventories will end the winter heating season (March 31) at 2,096 Bcf, which would be 41% above the level at the same time last year. Henry Hub spot prices are forecast to average $2.64/million British thermal units (MMBtu) in 2016 and $3.22/MMBtu in 2017, compared with an average of $2.63/MMBtu in 2015.
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www.iea.org
Price forecast:
2014 2015 2016 projected 2017 projected WTI Crude Oila (dollars per barrel) 93.17 48.67 37.59 50.00
Having peaked, at a five-year high of 1.6 million barrels per day (mb/d) in 2015, global oil demand growth is forecast to ease back considerably in 2016, to 1.2 mb/d, pulled down by notable slowdowns in Europe, China and the United States, the newly released IEA Oil Market Report (OMR) for February informs subscribers. Early elements of the projected slowdown surfaced in the last quarter of 2015.
Global oil supply dropped 0.2 mb/d to 96.5 mb/d in January, as higher OPEC output only partly offset lower non-OPEC production. Non-OPEC supplies slipped 0.5 mb/d from a month earlier to stand close to levels of a year ago. For 2016 as a whole, non-OPEC output is expected to decline by 0.6 mb/d, to 57.1 mb/d.
OPEC crude oil output rose by 280 000 barrels per day in January to 32.63 mb/d as Saudi Arabia, Iraq and a sanctions-free Iran all turned up the taps. Supplies from the group during January stood nearly 1.7 mb/d higher year-on-year.
OECD commercial stocks built counterseasonally by 7.6 mb in December to stand at 3 012 mb at month end, 350 mb above average. Refined products covered 32.3 days of forward demand, 0.1 day above the level at end-November. Preliminary information indicates that inventories have continued building into January.
Global refinery runs fell by 1.3 mb/d in January to 79.8 mb/d, as the onset of seasonal maintenance in the United States and weakening refinery margins curbed runs. Global throughputs nevertheless stood more than 1.7 mb/d above a year earlier, with gains particularly strong in the United States and the Middle East.
Global Crude Oil Prices
Brent crude oil spot prices decreased by $7/b in January to a monthly average of $31/b, the lowest monthly average price since December 2003. Ongoing growth in global oil inventories and uncertainty over future global demand growth continued to put downward pressure on oil prices during January. After growing by an estimated 1.8 million b/d in 2015, global oil inventories are forecast to grow by 1.4 million b/d in the first quarter of 2016.
During January, daily changes in crude oil prices were highly correlated with daily changes in global equity indexes. The increased co-movement and higher volatility likely reflect increased uncertainty about future global economic growth. Changes in overall demand for risk assets, such as commodities and equities, by investors and market participants may also be playing a larger role in price discovery across global asset markets compared with previous months.
With global oil inventory builds expected to continue in 2016, upward pressure on crude oil prices will be limited. Forecast Brent prices will average $38/b in 2016, $3/b lower than forecast in last month's STEO. The largest inventory builds occur in the first half of 2016, helping keep Brent prices below $40/b through August.
Brent prices are forecast to average $50/b in 2017, with upward price pressure concentrated later in that year. At that point, the market is expected to experience small inventory draws, with the possibility of further draws beyond the forecast period. Brent prices are forecast to average $56/b in the fourth quarter of 2017.
Forecast West Texas Intermediate (WTI) crude oil prices average the same as Brent crude oil prices through the forecast period, compared with $2/b lower than Brent in 2016 and $3/b lower in 2017 in the prior STEO. The price parity of WTI with Brent in the forecast period is based on the assumption of competition between the two crudes in the U.S. Gulf Coast refinery market, as transportation differentials are similar to move the crudes from their respective pricing points to that market.
The current values of futures and options contracts continue to suggest both heightened volatility and high uncertainty in the price outlook (Market Prices and Uncertainty Report). WTI futures contracts for May 2016 delivery, traded during the five-day period ending February 4, averaged $35/b, while implied volatility averaged 57%. These levels established the lower and upper limits of the 95% confidence interval for the market's expectations of monthly average WTI prices in May 2016 at $21/b and $58/b, respectively. The 95% confidence interval for market expectations widens over time, with lower and upper limits of $19/b and $85/b for prices in December 2016. At this time last year, WTI for May 2015 delivery averaged $52/b, and implied volatility averaged 52%. The corresponding lower and upper limits of the 95% confidence interval were $33/b and $81/b.
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Jeffrey J. Brown, 02/08/2016 at 9:27 amHere's the link to the EIA's Annual (US) Energy Review data, through 12/15:http://www.eia.gov/totalenergy/data/monthly/pdf/sec3_3.pdf
Note that total product supplied for 2015, 19.5 million bpd, was up by a million bpd from 2012 and it was the highest since 2008 (also 19.5 million bpd).
Annual total liquids net imports were down year over year, from 2014 to 2015, but monthly total liquids net imports were up from 4.5 million bpd in 12/14 to 5.1 million bpd in 12/15 (as we saw a 100 million barrel increase in US C+C inventories).
US net crude oil imports rose from 6.9 million bpd at the end of 2014 (four week running average data) to 7.3 million bpd at the end of 12/15.
Here's a link to the most recent four week running average Weekly Supply Data (ending 1/29/16):
http://www.eia.gov/dnav/pet/pet_sum_sndw_dcus_nus_4.htm
Based on the four week running average weekly data (through end of January, 2016), total product supplied was up to 19.7 million bpd, and the pattern of increasing net imports continued. Net crude oil imports were up to 7.5 million bpd, and total liquids net imports were up to 5.7 million bpd.
In other words, it would appear that the US is becoming increasingly dependent on imported oil, especially imports of actual crude oil, as total product supplied last year was at a seven year high.
As I have occasionally opined, I suspect that US refiners (and perhaps global refiners too) in late 2014 hit the upper limit of how much additional condensate that they could process, if they wanted to maintain their output of distillates and of heavier products.
And I suspect that much, if not all, of the build in US and global C+C inventories in 2015 consisted of condensate. Therefore, IMO, oil traders are acting on fundamentally flawed data when it comes to the inventories of the product that actually corresponds to the price indexes, i.e., WTI and Brent crude oil.
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Jeffrey J. Brown, 02/05/2016 at 10:16 amOf course, the big production decline will come from investments not made. However, as I have once, or twice, or thrice noted, it seems very likely that despite trillions of dollars in upstream (oil & gas) global capex since 2005, we have seen little or no increase in actual global crude oil production (45 API and lower crude).An except from a memo I'm preparing for some industry guys:
Perpetually Low Oil Prices Versus The Laws of Physics
Some of you may recall the Economist Magazine cover story, published in early 1999, which predicted–because of advances in technology and productivity gains (sound familiar?)–that we were looking at an extended long term period with oil prices in the $5 to $10 range.
While I suppose it's possible that this time the conventional wisdom is right, i.e., that we are looking at perpetually low oil prices, my bet is that the laws of physics will prevail, especially in regard to the high, and rising, rates of decline in existing US oil & gas production.
In any case, here is an excerpt from the March, 1999 Economist Magazine cover story on oil prices:
Here is a thought: $10 might actually be too optimistic. We may be heading for $5. Thanks to new technology and productivity gains, you might expect the price of oil, like that of most other commodities, to fall slowly over the years. Judging by the oil market in the pre-OPEC era, a "normal" market price might now be in the $5-10 range. Factor in the current slow growth of the world economy and the normal price drops to the bottom of that range.
Enclosed is a chart* showing constant dollar monthly WTI Crude oil prices, in 2016 dollars. Note that the March, 1999 Economist Magazine article corresponded pretty much to the all time record low constant dollar oil price for the past 40 years.
I think that I have made a strong case that the trillions of dollars spent on upstream global oil & gas capex since 2005 have only been sufficient to keep us on an undulating plateau in actual global crude oil production (45 API Gravity and lower crude oil), and because of the large and ongoing declines in global upstream capex, even the Wall Street Journal is expressing concerns about a future oil price spike, as supply falls.
The Cornucopian Crowd, which is basically making the same argument as the Economist Magazine writer in 1999, is arguing that advances in technology have indefinitely postponed any kind of production peak to the distant future.
I think that the reality is much more prosaic.
In my opinion, the reality is that global crude oil production has probably effectively peaked, while global natural gas production and associated liquids (condensate and natural gas liquids) have so far continued to increase.
Furthermore, I suspect that all, or virtually all, of the large build in US (and probably global) Crude + Condensate (C+C) inventories in 2015 consists of condensate, and therefore oil traders are trading on fundamentally flawed data when it comes to the inventories of the product that actually correspond to the index prices.
In the case of WTI (light/sweet) crude oil contracts, the maximum API gravity is 42, and recent EIA data suggest that about 40% of US Lower 48 C+C production in 2015 exceeded the maximum API limit for WTI crude oil, i.e., 42 API Gravity.
Last year, Reuters ran a story about US refiners increasingly rejecting "foul" blends of heavy crude and condensate that technically fell below the upper API limit for WTI crude oil, but that were deficient in distillate content.
In my opinion, these two items, i.e., the estimate that about 40% of US Lower 48 C+C production exceeded the maximum API Gravity limit for WTI crude oil in 2015 and case histories of US refiners increasingly rejecting blends of heavy crude and condensate, go a long way toward explaining why US refiners increased their net oil imports (from 12/14 to 12/15) as we saw 100 million barrel build in US C+C inventories from late 2014 to late 2015.
Furthermore, Iranian sources claim that the majority of their floating storage consists of condensate, which they were permitted to export under the sanctions. This of course suggests that we might be seeing both a US and a global oversupply of condensate–but not necessarily of actual crude oil (less than 45 API gravity crude oil).
*Prepared by AlexS
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Watcher, 02/05/2016 at 2:03 pmUseful to remember that accuracy is not the goal of reports reported by . . . almost anyone. If a study says something that suggests a client company is going to be destroyed, do you really think such a study is going to see the light of day? That's like expecting a management consultant to come in and tell management they are incompetent.No more contracts for that consultant.
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AlexS, 02/03/2016 at 8:05 pmLikbez,While in 2016 the supply-side response to low oil prices should be quite significant in the U.S. LTO sector, it will be more limited outside U.S.
2. "All deep water developments will also lose money this year and the exploration activity might grind to a halt as discrepancy between the current price and the price of production is too extreme. That spells troubles for future GOM production. "
A large number of new deep water projects were delayed in 2014-15, but this will impact production levels several years from now. Existing deep water production will continue as opex does not exceed $30-35. Most of the projects at final stages of development will not be postponed and will start production in time, like they did in 2015. One important exception may be Brazil, where some project start-ups could be postponed by 1 or 2 years. Also note, that outside Brazil, deepwater projects are operated by the oil majors, which have much stronger balance sheets than the US E&Ps or Petrobras.
3."Carnage in Canadian oil sands."
Some projects were delayed, but oil sands production will slightly increase this year, according to all forecasts.
5. "Several oil producing countries with higher costs or large budget deficit in 2015 will be on the wedge of bankruptcy at the end of the year. "
That does not mean that they will decrease oil production, the key source of fiscal revenues.
6. "KSA will lose another hundred billions and might lose its current credit rating."
KSA's foreign reserves decreased by some $100 bn last year, they might lose another $100 billion in 2016, but they will still have more than $500 billion. And how declining FX reserves should impact oil production?
Russia's credit rating was lowered in 2014, but production continued to increase in 2014 and 2015.8. "Losses of investors might well black mark this area of investment for the next three years. Energy funds and ETFs shrink as "naïve" investors simply flee."
Again, you mention what might happen in the future. How this can impact oil production volumes this year? And as soon as oil prices start to recover, investors will return. We have seen this many times in the past.
In general, those who expect a quick supply-side response to lower oil prices ignore the fact that lower prices and lower investments tend to have a much delayed impact on production levels.
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Peak Oil News and Message Boards
shortonoil on Thu, 4th Feb 2016 4:18 pm"A deal is not only "highly unlikely," in the estimation of Goldman Sachs, but "self-defeating" for the Saudis. By cutting production now and boosting prices, Saudi Arabia would effectively bail out U.S. shale producers just as the Saudi strategy of keeping prices low to squeeze them out of the market is beginning to work, Goldman's Jeff Currie argues."
The media puts forth a continuous stream of completely unadulterated crap to its readership. Saudi Arabia is not going to spend $175 billion per year to put out of business producers that produce an entirely different product, and which sells to an entirely different market. LTO is as much like Saudi crude as Shetland Ponies are to an Arabian race horses. The similarities stop at horse.
LTO is a very light hydrocarbon that is used as a diluent, and feed stock. Its API is > 45. It is used to thin heavier hydrocarbons like Canadian bitumen to allow it to be transported by pipe. It is used as a feedstock to make hundreds of different products from paint to plastic pipe.
Saudi's light sweet crude has an API 45, and the heavier ones, API < 40, deliver entirely different products as show in the graph below:
Saudi's light sweet crude, and LTO are entirely different products that sell to entirely different markets. Saudi's crude is no competition to LTO and LTO is no competition for Saudi's crude.
Goldman Sachs is an unscrupulous pack of thieves who have no qualms about lying to their clients, or the public if it serves their purposes. They, and others in the shale financing business will continue to push the Saudi/ US LTO myth for as long as they can find investors that are credulous enough to believe them.
makati1 on Thu, 4th Feb 2016 7:59 pm
Some see only what they want to see. Others see the whole forest. Bloomberg and Goldman are both habitual liars and thieves. Goldman says it and Bloomberg backs it up, as if either have any credibility left.
Short has it correct. All you see in the US MSM is bullshit in ever higher and smellier piles. As we approach the end, the cries will be louder, shriller and continuous. Wait and see.
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The IEA Oil Market Report, full issue, is now available to the public. Some interesting observations:Non-OPEC oil supplies are nevertheless seen sharply lower in December. Overall supplies are estimated to have slipped by more than 0.6 mb/d from the month prior, to 57.4 mb/d. A seasonal decline in biofuel production, largely due to the Brazilian sugar cane harvest, of nearly 0.4 mb/d was the largest contributor to December's drop. Production in Vietnam, Kazakhstan, Azerbaijan and the US was also seen easing from both November's level and compared with a year earlier. Persistently low production in Mexico and Yemen were other contributors to the year-on-year decline.As such, total non-OPEC liquids output slipped below the year earlier level for the first time since September 2012. A production surge in December 2014 inflates the annual decline rate, but the drop is nevertheless significant should these estimates be confirmed by firm data. Already in November, growth in non-OPEC supply had slipped to 640 kb/d, from as much as 2.9 mb/d at the end of 2014, and 2.4 mb/d for 2014 as a whole. For 2015, supplies look likely to post an increase of 1.4 mb/d for the year, before contracting by nearly 0.6 mb/d in 2016. A prolonged period of oil at sub-$30/bbl puts additional volumes at risk of shut in as realised prices fall close to operating costs for some producers.
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Fernando Leanm, 02/04/2016 at 9:34 amThey insist on lumping biofuels with crude oil etc. I would call them the Energy Disinformation Agency.AlexS, 02/04/2016 at 4:22 pmFernando,Fernando Leanm, 02/05/2016 at 6:47 amThey include separate numbers for biofuels production and refinery processing gains
Alex, they lump everything in the discussions and most tables intended for public distribution. I spend a lot of time explaining to people their graphs and most data tables are covering up what happens to crude oil and condensate. I consider their practices to be deceitful.shortonoil on Thu, 4th Feb 2016 2:27 pm
Some of this data looks very anomalous. For instance, if one looks at the US rig count vs Us C+C production between June '09 and Sept '11, rig count increased by 800 or 500%.
During that same period US C+C production stayed flat.
What were these guys doing, playing poker for 26 months? From spud to IP was no more than 8 months even back in the dark ages (2009) of shale production.
Assuming 4 wells per year per rig that would have been about 1500 new wells.
The decline rate of conventional US wells was probably about 5% or 250,000 b/d per year. Without some kind of explanation it is hard to take this data seriously.
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OilVoice
The changes can be very big. Look at the line that comes to a halt in April 2015, these are the numbers from the May 2015 Short Term Energy Outlook, those estimates were about 340,000 bbls per day less than what the EIA now think. About as much as people are estimating Iran might be able to add to the market and which is now causing fear and trepidation amongst oil bulls. On that point I am a tad sceptical, not having been born under a gooseberry tree.
The same then happened on the way down. As the oil price collapsed and rigs were stacked, it seemed in September that the decline was well established and that the US would soon be producing less than 9 million barrels per day. I confidently tweeted that projection, but I was dead wrong. Month after month the previous estimates were raised and the impending collapse was deferred. This continued right up to the last estimate of historic monthly production, published at the end of December, and used in the January 2016 Short Term Energy Outlook, the pale blue line on the graph. At that time, virtually the whole of 2015 was revised upwards by nearly 100,000 bbls per day.
But on the 27th January the EIA published a revision to the numbers (which will be used in the February 2016 STEO) which bucked that trend and started to revise the past downwards. That is the dark blue line on the chart, which tracks the pale blue line for most of the year but includes a 140,000 bbls per day reduction in the estimate of November 2015 production.
We can be confident of one thing the revisions to the past aren't finished, and given the dramatic fall in the oil price from November to January, and the drastic cuts in US operators budgets for 2016 it seems to me that US production will soon decline below 9 million barrels per day, my estimate is that that threshold will be crossed in February and that the US will exit 2016 producing about 8.4 mmbbls/day.
But take that all with a pinch of salt. It is hard enough estimating the past let alone, predicting the future.
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Ron Patterson , 02/02/2016 at 8:34 am
Crude oil peaked ~2005: ExxonMobilJeffrey J. Brown , 02/02/2016 at 8:59 amDavid Hagen has posted a great commentary on ExxonMobil's The Outlook for Energy: A View to 2040
ExxonMobil released its 2016 Outlook for Energy: A View to 2040. Buried on page 62, its Liquids Outlook by Type clearly shows conventional crude oil ("Crude + Condensate") peaked about 2005. Global conventional oil ("Crude + Condensate") declines through 2040. ExxonMobil asserts "Growth comes mostly from non-conventional supply" but actually shows declining conventional supply – even after including "Deepwater" production.
Only increasing use of higher priced Nonconventional hydrocarbons shows some global growth – but much lower than historical growth. Only by adding Bitumen (aka "Oil Sands"),"tight oil", natural gas liquids (NGL), "other" and biofuels does ExxonMobil project about 20% total growth over 25 years (from the current 93 million bbl/day to about 112 million bbl/day.)
I think ExxonMobil's estimate of future tight oil production is way overly optimistic. But not nearly as overly optimistic as their estimate of "new conventional crude and condensate development".
Here's a somewhat different approach to my attempts, using available data, to differentiate between actual crude oil, generally defined as 45 API Gravity and lower crude oil, from condensate, generally defined as Crude + Condensate (C+C) with an API Gravity greater than 45.Jeffrey J. Brown , 02/02/2016 at 10:12 amSince condensate, like Natural Gas Liquids (NGL), is a byproduct of natural gas production, it occurred to me that what is important is the estimated condensate yield per BCF of global dry natural gas production.
US & OPEC 12 Condensate Production Estimates as Indicators of Global Condensate Production, 2005 to 2014
Natural Gas Data
US Natural Gas Production (BP):
2005: 50 BCF/day
2012: 71 BCF/dayOPEC 12 Natural Gas Production (BP):
2005: 42 BCF/day
2014: 68 BCF/dayUS + OPEC 12 Natural Gas Production (BP):
2005: 92 BCF/day
2014: 139 BCFdayGlobal Natural Gas Production (BP):
2005: 270 BCF/day
2014: 335 BCF/dayCondensate Data & Estimates
Implied OPEC 12 Condensate Production
(EIA OPEC 12 C+C less OPEC Crude Only)
2005: 1.2 million bpd
2014: 2.4 million bpdEstimated US Condensate Production (45+ API Gravity C+C Production)
2005: 0.5 million bpd
2014: 1.7 million bpd
(EIA puts US Lower 48 45+ API C+C production at 2 million bpd in 2015, and they estimated that US 45+ API Gravity C+C production increased by about one million bpd from 2011 to 2014)Implied OPEC 12 Condensate + Estimated US Condensate Production
2005: 1.7 million bpd
2014: 4.1 million bpdOPEC 12 + US Condensate Estimates Per BCF of Dry Gas Production
2005: 18,000 barrels/BCF
2014: 29,000 barrels/BCF
(In terms of gallons of condensate per MCF of dry gas, it would be 0.8 gallons/MCF in 2005, rising to 1.2 gallons per MCF in 2014, if my math is correct.)Condensate, like natural gas liquids, is a byproduct of natural gas production. The US and OPEC 12 countries accounted for 41% of global dry gas production in 2014.
If US + OPEC 12 estimated condensate production numbers per BCF of dry gas production from 2005 to 2014 are approximately indicative of world trends, estimated global condensate production in 2005 would be 4.9 million bpd (rounded off to 5 million bpd), and estimated global condensate production in 2014 would be 9.7 million bpd (rounded off to 10 million bpd), an estimated increase of about 5 million bpd in global condensate production from 2005 to 2014.
Note that the increase in global C+C production from 2005 to 2014 was 4 million bpd (74 to 78 million bpd, rounded off to the nearest one million bpd).
The foregoing analysis would of course suggest that actual global crude oil production (45 API and lower gravity crude oil) was down slightly from 2005 to 2014, down from about 69 million bpd in 2005 to about 68 million bpd in 2014–as annual Brent crude oil prices doubled from $55 in 2005 to $110 for 2011 to 2013 inclusive, remaining at $99 in 2014.
Note that I am estimating that US + OPEC 12 condensate production increased by about 2.4 million bpd from 2005 to 2014 (from 1.7 to 4.1 million bpd), with an estimated condensate yield of about 18,000 barrels per BCF of dry gas in 2005 and 29,000 barrels per BCF of dry gas in 2014 (note that the condensate yield per BCF of wet gas would of course be lower).likbez , 02/02/2016 at 1:19 pmIn any case, if the condensate yield for non-US + non-OPEC gas was the 18,000 barrels per BCF in 2005, but only rose to 24,000 barrels per BCF in 2014 (versus 29,000 barrels per BCF for US + OPEC), non-US + non-OPEC condensate production would have increased from about 3.2 million bpd in 2005 to about 4.7 million bpd in 2014 (again, if my math is correct).
Based on the foregoing scenario, total global condensate production would have increased from about 4.9 million bpd in 2005 (call it 5 million bpd) to about 8.8 million bpd in 2014 (call it 9 million bpd), in implied increase of 4 million bpd, which would of course mean that rising condensate production accounted for virtually all of the 2005 to 2014 increase in global C+C production.
In any case, note that the doubling in annual Brent crude oil prices from $55 in 2005 to $110 for 2011 to 2013 inclusive (remaining at $99 in 2014) provided an enormous incentive for global oil and gas producers to increase their liquids production, wherever and however they could. My principal point is that the available data strongly suggest that they weren't able to show a material increase in actual global crude oil production (45 API and lower gravity crude oil)–despite trillions of dollars spent post-2005 on global upstream oil and gas projects, Qater being a perfect example.
Jeffrey,Here is another argument supporting your position about distinguishing crude and condensate. They really should be reported separately in oil production statistics.
Condensate energy content per unit of volume is less that oil as API gravity is an inverse measure of a petroleum liquid's density relative to that of water.
In other words a barrel of, say, 60 API condensate (average of a typical 45-75 range) has less energy (in BTU) than a barrel of 39.6 API oil (WTI). Using standard formula for number of barrels in metric ton (API+131.5)/(141.5*0.159) we will get 8.5 barrels and 7.6 barrels per metric ton, respectively.
As the amount of BTUs per unit of weight is probably close to constant that means that energy-wise condensate with API 60 contains approximately 12% less of energy then oil with API 40.
In other words, mixing them in statistics inflates the total amount of energy produced. If uniform statistics is desirable they should be counted using factor 0.9. This recalculation will make peak oil phenomenon more visible in all graphs of world and countries production.
That also mean that countries and agencies reporting production in metric tons are doing better job then countries reporting production in volume measures such as barrels. In other words EIA sucks :-)
Jeffrey J. Brown , 02/02/2016 at 9:17 am
Here is an interesting article, I think that was published in 2015, on crude oil versus condensate production in Qatar (of course, Qater is a member of OPEC). As I have previously discussed, the crude oil versus condensate quality issue is not my principal point.My principal point is that the available data strongly suggest that actual global crude oil production has been on an "Undulating Plateau" since 2005, while global natural gas production and associated liquids, condensate and NGL, have so far continued to increase.
Note that the OPEC 12 data that Ron compiled for me show that Qatar's reported crude oil production fell from 0.8 million bpd in 2005 to 0.7 million bpd in 2014 (OPEC crude only data), while EIA data show that Qatar's C+C production increased from 1.0 million bpd in 2005 to 1.5 million bpd in 2014.
Production of condensates rising in Qatar
http://www.oxfordbusinessgroup.com/analysis/production-condensates-rising-qatarThe global market is far more competitive these days, and 2014 saw a dramatic decline in oil prices, which continued into 2015. In March 2015 Brent Crude was retailing at $57 per barrel. Behind this is a global oversupply – Bloomberg reported that the UAE and Qatar estimated this to be in the region of 2m barrels per day (bpd) in mid-January 2015. This is primarily the result of surging US output, which was at a three-decade high. However, this output seems likely to taper off, as falling prices make some of the fracking on which US production is based no longer economically feasible. Furthermore, in 2014 Washington decided to allow exports of condensates for the first time – oil exports having been banned since the 1970s oil crisis. Thus, the global condensates market is also seeing a major supply surge, with press reports suggesting that the US could add up to 1m bpd of these light oils to the export market during the next 10 years. This is particularly relevant to Qatar, as condensates have come to represent a larger proportion of the state's output than crude.
DEPLETION OF RESERVES: This has been for two main reasons. First, there is the depletion of existing oilfields. Qatar Petroleum's (QP's) Dukhan field, the oldest, sent out its first export cargo in 1939, although it remains one of the two largest fields in the country, along with Maersk Oil's Al Shaheen. Qatar National Bank (QNB) figures show that total output has declined continuously in recent years, from a peak of 845,000 bpd in 2007 to 733,000 bpd in 2010, 724,000 bpd in 2013 and 681,000 bpd in November 2014.
This is despite major investment in enhanced oil recovery (EOR). Some $6.6bn has been invested in crude oil projects under Qatar's 2010-14 development plan, with much of this going into EOR. At the same time, reports in local media state that Occidental is investing $3bn in water injection to sustain production at the Idd Al Sharqi field, while ExxonMobil has made further investments in Dukhan. Indeed, most of the investments currently ongoing in the oilfields are of this kind, with the aim of maintaining and stabilising production.
"Our overall objective for the field is more to minimise production decline," Guillaume Chalmin, the managing director and group representative of Total E&P Qatar, told OBG, referring to his group's Al Khalij field. "This takes priority over increasing production."
. . . . CONDENSATES: The second factor affecting the condensates/crude balance is the huge North Field, and the consequent expansion of natural gas output in the country. This has led to a surge in the production of condensates on the back of new wells and projects aimed at feeding Qatar's liquefied natural gas and gas-to-liquids sectors. Indeed, if the QNB figure of 724,000 bpd of crude is compared with the BP figure of 1.995m bpd of total oil production – which includes crude oil, light oil (from condensates), oil sands and natural gas liquids – then condensates are likely responsible for over 1m bpd of Qatar's oil production. QNB figures quoted by Business Quartermagazine in 2013 stated that while crude oil reserves were an estimated 2.3bn barrels in 2011, condensate reserves were an estimated 22.3bn barrels, with condensate production exceeding crude oil production in 2012, when it hit 900,000 bpd. . . .
HIGH-VALUE PRODUCTS: Condensates are hydrocarbons that exist in a gaseous state underground, but which liquefy during the production process. They are thus a low-density mixture of hydrocarbons and come from both oil wells, as associated gas, and from natural gas wells, where they exist alongside raw natural gas and are known as non-associated or wet gas. Condensates can also be produced from dry gas – natural gas that has no associated component – in gas processing plants; this variety is known as plant condensate.
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AlexS , 02/01/2016 at 3:52 pmShale Oil Production in Bakken, Eagle Ford Little Changed in December: Platts Bentek
Year Over Year, Output from These Two Prolific Shale Plays Fell More Than 6% from December 2014
Thursday, January 28, 2016
http://www.oilvoice.com/n/Shale-Oil-Production-in-Bakken-Eagle-Ford-Little-Changed-in-December-Platts-Bentek/459c3fe97203.aspxOil production from key shale formations in North Dakota and Texas dropped slightly in December versus November, according to Platts Bentek, an analytics and forecasting unit of Platts, a leading global provider of energy, petrochemicals, metals and agriculture information.
Oil production from the Eagle Ford was relatively unchanged in December, increasing about 11,000 barrels per day (b/d), or less than 1%, versus the previous month, the latest analysis showed. This marks the first time since March 2015 that the Eagle Ford shale did not decline. Conversely, crude oil production in the North Dakota section of the Bakken shale formation of the Williston Basin dipped by less than 1% month over month in December, or about 9,000 b/d, continuing the trend of marginal decline that began in the summer.
The average oil production from the Eagle Ford basin in December was 1.5 million barrels per day. On a year-over-year basis, that is down about 7%, or about 110,000 barrels per day, from December 2014, according to Sami Yahya, Platts Bentek energy analyst. The average crude oil production from the North Dakota section of the Bakken in November was 1.2 million b/d, about 6% lower than year ago levels.
'The small increase in crude production in the Eagle Ford shale is attributed to a slight resurgence in drilling activity in the region,' said Yahya. 'In December, the number of active rigs in the Eagle Ford reached 80, an increase of five rigs over the previous month. The brief rebound of active rigs is likely due to producers balancing their drilling programs and budgets for the fourth quarter and meeting their goals for wells drilled for the year.'
Recapping the year-on-year production drop in the Eagle Ford shale, Yahya emphasized the importance of efficiency gains realized in 2015. Back in January of 2015, the Eagle Ford shale utilized over 200 rigs, while now, in January of 2016, the number of active rigs shrunk to under 70 rigs, a drop of over 65%. And yet, production did not meet a similar fate. Producers back in January of 2015 could drill less than two wells per rig per month, compared to nearly three wells per month currently.
'It is survival of the fittest: the best and most efficient rigs and crews remain standing on the field,' Yahya noted. 'The number of active rigs in the Bakken shale formation of the Williston Basin went from nearly 150 rigs in early 2015 to around 50 rigs currently. At the same time, producers were able to increase their drilling rates from about 1.5 wells per rig per month to about 2.2 wells per rig per month.'
However, Yahya explained that going forward, crude production would need more than just efficiency gains to grow.
'Last year, optimization and hedging programs helped production stay largely afloat. But unless the pricing of the oil barrel improve, producers are in for a difficult year ahead. Based on latest Platts Bentek forecast data, both the Eagle Ford and the Bakken shales are expected to continue declining throughout most of the year. Certainly, the availability of wells in backlog inventory where drilling cost is already sunk would be a helpful factor in partially sustaining production volumes in both shales.'
'If prices remain sub-$40/barrel and producers are unable to further bring down completion costs, then they might defer completions until the pricing market makes a comeback,' said Yahya.
Platts Bentek analysis shows that from November 2014 to November 2015, total U.S. crude oil production has increased by about 265,000 b/d.
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It is interesting to compare Bentek data with the latest EIA Drilling productivity report.
According to Bentek, oil production from the Eagle Ford increased 11kb/d versus the previous month.
According to the DPR, it declined 71 kb/d.Bentek: "The average oil production from the Eagle Ford in December was 1.5 million barrels per day. On a year-over-year basis, that is down about 7%, or about 110,000 barrels per day, from December 2014.
EIA DPR: The average oil production from the Eagle Ford in December was 1.29 mb/d. That is down 22,4%, or 374 kb/d, from December 2014.
According to Bentek, "crude oil production in the North Dakota section of the Bakken shale formation of the Williston Basin dipped by less than 1% month over month in December, or about 9,000 b/d"
According to the EIA DPR, the decline in the Bakken was 19 kb/d .
The y-o-y decline, according to bentek was 6% vs. 9.6% in the EIA DPR statistics.
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Ron Patterson, 02/01/2016 at 2:30 pmHey, great article on the EIA. Revising the Past – US Oil Production DataAlexS, 02/01/2016 at 2:51 pmThis article is based on the EIA's Monthly Energy Review which was released on 27th January and which states November 2015 production was 9,181,000 bbls/day. Oddly, the Petroleum & Other Liquids monthly data which was released on 29th January says November 2015 production was 9,318,000 bbls/day. Which one is the one the EIA intend us to use?
As I have said before the US Energy Information Agency (the EIA) has a thankless task, compiling data from thousands of oilfields and operators to come up with an estimate of how much oil the USA actually produces. Some data is timely and accurate, Alaska is a case in point, some, not so much.
So every month as well as giving us a new estimate for the month just passed, we get revisions of the historic data. It is instructive to take a look at that data to see how far off the early estimates were. Big revisions are a sign of a dislocation in the system, a sign that the old rules of thumb aren't working any more. The EIA has suffered from this phenomenon on the way up, as US shale output outstripped any reasonable estimates of how it might perform; and now on the way down, as somehow the whole US oil industry did a passable impersonation of Wile E. Coyote, well beyond the edge of the cliff but somehow defying gravity.
Monthly Energy Review data for November and December is forecast. MER data for the most recent 2 month has never been reliable. By contrast, Petroleum Supply Monthly numbers released on January 29th are more correct, in my view.There were some revisions compared with the previous PSM: September 2015 -11 kb/d;
October 2015 +23 kb/d.The data for November was only -2 kb/d compared with the January STEO estimate.
In general, the EIA has been making mostly upwards revisions for 2015 C+C production
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Watcher, 01/31/2016 at 4:43 pm
Re: Ron's Ronpost . . . anyone have a source for NGL prices?Previous Ronpost - Doug noted that in his experience every geologist in China doesn't have their words filtered by Beijing. So there is truth to be found in provincial quotes of things oil related. If the matter became more overtly national security related, of course that would change.
I'm reminded of how often EIA and NoDak's DMR have quoted numbers in conflict with each other of late. Not that this need be conspiratorial. We somewhat know EIA numbers come from a model that likely is as worthless as most. This would be a case of provincial data having not been . . . filtered, or smoothed, or seasonally adjusted or whatever else is the change mechanism du jour.
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Patrick R, 01/30/2016 at 4:29 pmOf course the forecasts by WoodMac, IEA, EIA, etc are little more than posturing. Predictions, after all, are claims on the present, not information from the future. Whoever controls the image of the future controls resources now. Conservatives want you only to fear terrorism and not pollution, and Conservationists the reverse [I like those two words; they have the same root of course].likbez, 01/30/2016 at 8:06 pmHere for example are driving predictions from English Department for Transport and Washington State DoT. Like every single Transportation Dept [read; road builders] they constantly predict more driving for ever and ever. No matter how many years they get this wrong, they've got to predict more because these predictions set their budgets for ever more fancy-arsed road projects.
Are WoodMac really going to say growth in the sector is over? Haha. And the alphabet institutions [EEEEEIIIIAAA] are extrapolationists, they're never going to catch discontinuity.
Dang, won't accept the attachments again; here's the link:
http://transportblog.co.nz/2014/02/19/our-insane-traffic-projections/
Patrick,Patrick R, 01/30/2016 at 5:44 pm"Of course the forecasts by WoodMac, IEA, EIA, etc are little more than posturing. Predictions, after all, are claims on the present, not information from the future. Whoever controls the image of the future controls resources now. "
Well said. Thank you!
"Whoever controls the image of the future controls resources now. "
That's what propaganda is about. Agencies such as EIA and IEA are as much propaganda outlets as they are statistics gathering bodies. As we all know there are three types of lies: "Lies, damned lies, and statistics".
As Watcher observed: "Countries strive for victory over their enemies. They have nothing to gain by providing accurate information."
Always the argument is between the trend and the status quo. BAUists will insist we look backwards by demanding data which of course can only be historical. This is an important corrective to theory but never shows the whole picture, because it always of course supports no change, or at most an extrapolation of the past. Never fundamental change.likbez, 01/30/2016 at 8:27 pmWhy won't oil's future follow where coal is now? I find this at least a highly plausible possibility. It is not unlikely that a combination of electric supply and climate policies will strand a great deal of oil at any price. How, economics of course:
What is always less clear is how long this takes, if I have learnt anything following global change is that it usually both takes way longer than I first think, and then can also happen very suddenly: Straws do break camels' backs.
"Why won't oil's future follow where coal is now?"Because predictions are difficult, especially about the future. So far coal was partially replaced in the only role where new technologies are somewhat competitive - electrical power generation - and this happened not only because the rise of wind and solar, but also because the price of natural gas dropped so substantially. Without the last factor the situation might reverse itself. Not everywhere coal is replaced. High quality coal is indispensable in metallurgy.
Everything depends on technologies available. Actually the initial idea of diesel engine was to run it on coal powder. It failed. But now with the new level of technology achieved I wonder if something along those lines ("nanoparticles") might be feasible at least for large ships.
At some level of oil prices coal might also be used to produce liquid fuels for transportation like Germany did during the WWII.
Natural gas is also well positioned to penetrate heavy truck and marine fuel markets if the price remains low.
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AlexS, 01/30/2016 at 2:06 amOoops, wrong numbers!Ron Patterson, 01/29/2016 at 10:41 pmBelow is the corrected chart and numbers:
EIA Annual Energy Outlook 2015
Total global liquids supply in 2040: 121.7 mb/d,
or 118,8 mb/d excluding refinery processing gains.
or 114.5 mb/d ex. proc. gains and biofuels.Note, that AEO 2015 was issued in early 2015 and apparently prepared in late 2014, when oil prices were significantly higher.
The AEO 2015 projects Brent price at $71 in 2016 gradually rising to $141 (in $2013) by 2040.
I expect AEO 2016 global liquids supply projections to be lower than in last year's issue.
Enhanced recovery don't seem to get much credit here. ;-)AlexS, 01/30/2016 at 2:24 amNotice that the IEA don't have us reaching 80 mbd, C+C, until 2030, a point that the EIA says we are at today. They, the IEA, has us at about 75 million barrels per day today. My guess is that is about right.
Ron,Dennis Coyne, 01/30/2016 at 10:52 amThe IEA has conventional oil + tight oil+oil sands + GTL and CTL at ~75 mb/d and NGLs at @ 15 mb/d in 2014
Total (ex. biofuels and processing gains) ~ 90 mbThe EIA has conventional oil + tight oil+oil sands + GTL and CTL at ~79.4 mb/d and NGLs at @ 9.5 mb/d in 2014
Total (ex. biofuels and processing gains) ~ 89 mbThe IEA has included all OPEC NGLs and condensate in global NGLs number.
The EIA apparently classifies large part of OPEC NGLs and condensate as condensate (part of global conventional C+C).(Total OPEC NGLs and condensate production in 2014 was 6.36mb/d)
Same condensate vs. NGLs shit :-)
Hi AlexS,Thanks for the clarification. Looks like about 4-5 Mb/d of condensate is produced in the World. As long as this can be easily blended into liquid fuels (such as gasoline) at refineries, it makes sense to call it "oil" as there is a wide range of stuff we are willing to call oil (such as bitumen).
We have been counting crude plus condensate for a long time, excluding C2, C3, and C4 makes sense to me, but excluding C5 does not. Just one person's opinion.
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oldfarmermac, 01/30/2016 at 10:05 amAt times there are numerous comments questioning the reliability of oil production figures reported by various countries and by different outfits sucth as the IEA etc.AlexS, 01/30/2016 at 10:57 amNo doubt there are serious errors.
What I would like to know, is this.
How big do you guys who crunch a lot of numbers think the errors are ?
How much higher, or lower might the true total world wide production of C plus C be , if it were possible to know?
How big might the errors be in the worst case countries?
OFM,clueless, 01/30/2016 at 11:07 amThe errors can be very big.
In the World Energy Outlook 2008, the IEA projected global total liquids demand at 106.4 mb/d by 2030.
In the latest WEO-2015, they are projecting 103.5 mb/d by 2040.The trend in the past 10 years was towards lower medium and long-term supply and demand projections
Generally speaking, when dealing with massive amounts of data, the "errors" largely offset each other. That is, if almost every figure is subject to being either to high or too low, after adding them all up, the total is surprisingly close to what the "real" total should be. Obviously, if you could posit a situation in which every number is likely to be too high (or too low) that would not be the case.AlexS, 01/30/2016 at 11:19 amSo, with an individual country, like say Venezuela, maybe it is off by a significant amount.
clueless,Watcher, 01/30/2016 at 11:38 amAs regards global oil (liquids) supply and demand projections, there were not just statistical errors, but very significant conceptual errors. All agencies have been significantly overestimating global demand and supply.
These are the most important data points on earth, and they are not known to high confidence. This is what one would expect. Countries strive for victory over their enemies. They have nothing to gain by providing accurate information.Doug Leighton, 01/30/2016 at 1:16 pmIf I were China, I'd make oil production a state secret, too.
Hi Watcher,oldfarmermac, 01/30/2016 at 11:42 amI doubt China is playing games with reported oil production capability. I had an office in Harbin for many years where most of my time was spend assessing reserves for NA oil companies who wanted access to Chinese oil. As such I was in contact with numerous local oilmen who freely gave me access to their reservoir data. The Chinese were duplicitous in one respect, in my opinion, by leading American companies into believing they were entertaining potential JV partners when, in fact, they simply wanted to massage business contacts in general. On China's production I expect the following is accurate:
"… China's crude oil output has stagnated for the past two years despite intense drilling activity on land and offshore. In late 2014, CNPC essentially threw in the towel on its workhorse field, Daqing, announcing that it would allow the field to essentially enter a phase of managed decline over the next five years. Under this new approach, the field's oil production will fall from 800,000 barrels per day (kbd) in 2014 to 640 kbd by 2020: a 20 percent decrease. To highlight the importance of PetroChina's decision, consider that Daqing currently accounts for approximately one in every five barrels of oil currently pumped in China – on par with the role Alaska's massive Prudhoe Bay field has played in US oil production…"
http://thediplomat.com/2015/07/china-peak-oil-2015-is-the-year/
Thanks guys, but I did not mean to ask about PREDICTED oil production but rather about ACTUAL production, this year, and in past years.AlexS, 01/30/2016 at 11:58 amIf for instance Saudi Arabia says last years production was ten million barrels per day average, exactly, how far off do you think that might be, one tenth of a percent? two percent?
Some countries are going to be notorious liars of course, and their figures might be off by ten percent or more.
But even though the total reported world production might be wrong by a percent or more, in either direction, up or down, the TREND in reported production still ought to be accurate.
The trend in the reported quantity of oil available on international markets ought to be likewise accurate, even though the actual reported quantity of oil available on world markets might have been off by a percent or even two percent or more.
Historical demand and supply numbers are constantly revised, but in most cases revisions are not too big.likbez , 01/30/2016 at 2:21 pmRevisions of the US oil production numbers were relatively big in 2015.
I would assume that EIA has error margin close or above 100,000 bbls/day. So the accuracy of EIA data is just two significant digits maximum. The fact that they provide more digits is just an attempt to be a better Catholic then Pope, if you wish ;-).Generally they should have strong institutional bias toward lower oil prices and that bias can influence their oil production and consumption numbers. So it is rational to assume that they tend to overestimate the production and underestimate consumption growth. In other words they are predisposed to "revealing" oil glut even if it does not exists.
The margin or error is different for different types of oil with those areas that are served by pipelines more precise (offshore is one example here).
Some people like Steve Brown recommend reducing their production numbers by 100,000 bbl/day just in case :-)
http://oilprice.com/Energy/Energy-General/Is-The-EIA-Too-Optimistic-On-US-Oil-Output.html
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Jeffrey J. Brown, 01/28/2016 at 3:42 pmAPI: US December, 2015 Petroleum Demand Highest in Five Yearslikbez, 01/29/2016 at 1:12 pmEIA Annual Energy Review data complete for 2015 (subject to revision):
http://www.eia.gov/totalenergy/data/monthly/pdf/sec3_3.pdf
Based on foregoing, annual 2015 US net total liquids imports were still down in 2015, versus 2014, but US net total liquids imports rose from 4.5 million bpd in December, 2014 to 5.1 million bpd in December, 2015.
Note that US C+C inventories rose by 100 million barrels from late 2014 to late 2015. So, as we saw a 100 million barrel increase in US C+C inventories, US net total liquids were up by 13%, from 12/14 to 12/15? Almost makes one think that most, if not all, of the C+C build consists of something besides actual crude oil.
(As usual, there appear to be some discrepancies between the EIA Weekly Supply data and the Annual Energy Review data in regard to total liquids net imports. In any case, the four week running average data show that US net crude oil imports rose from 6.9 million bpd in December, 2014 to 7.3 million bpd in December, 2015. Net crude oil imports are not broken down separately in Annual Energy Review.)
This is yet another indirect confirmation of "Great Condensate Con" hypothesis.
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dmg555, 01/25/2016 at 1:43 pm
Dear Mr. Jeffrey Brown:Watcher , 01/25/2016 at 3:40 pmOf all the contributors on this site, you have highlighted the problems inherent in counting condensates as crude. I am not a petroleum chemist so am not so familiar with the limitations of condensates. Could you briefly tell me what you can and can not use condensates for? I get that one can refine 30-45 WTI into gasoline and other useful fuels like jet fuel, but: Can you drive on condensates? or am I correct in believing the condensates can only be turned into heating fuels.
Thanks for your answer in advance
Yeah, distillate yield is the big deal. Gasoline doesn't move food.likbez , 01/25/2016 at 5:18 pm> "Can you drive on condensates?"Yes, but it's illegal in most states (https://en.wikipedia.org/wiki/Natural-gas_condensate)
It is also harmful to modern engines due to its low octane rating ( about 30 to 50) and possible presence of cancerogenius additives (benzene) and sulfur. Before 1930 it was used as an ICE fuel in low RPM, low compression engines. Both Karl Benz engines, and early Wright brothers aircraft engines used it. It has a distinctive smell when used as a fuel, which allows police to catch people using condensate illegally.
The white gas sold today as a fuel for stoves is a condensate with the benzene and sulfur removed.
Adding ethanol improves the octane number (https://en.wikipedia.org/wiki/Octane_rating) and makes it possible to drive regular cars on distillate. You need E85 mix for that.
My impression is that the drive to blend ethanol with gasoline (most of the gasoline now sold in the United States contains some ethanol) and introduction of E10, E15, and E85 that happened in the USA was at least partially dictated by the desire to blend condensate (as a substitute for gasoline) with ethanol killing two birds with one stone. Moreover denaturized ethanol contains at least 2% of condensate. All gasoline engine vehicles can use E10 so some amount of condensate is present in US gasoline almost by definition.
E85 (used only in flexible-fuel vehicles (FFV) ) allows blending of considerable amount of reprocessed condensate (probably 40-50%) with ethanol and still getting acceptable octane number. E85 is an abbreviation for an ethanol fuel blend of 85% denatured ethanol fuel and 15% gasoline or other hydrocarbons by volume, although the exact ratio of fuel ethanol to hydrocarbons can vary considerably while still carrying the E85 label. The ethanol content is adjusted according to the local climate to maximize engine performance. ASTM 5798 specifies the allowable fuel ethanol content in E85 as ranging from 51% to 83%.
Condensate has a very low viscosity and often used to dilute highly viscous heavier oils that cannot otherwise be efficiently transported via pipelines.
Jeffrey J. Brown , 01/25/2016 at 1:55 pm
I'm actually not anywhere close to be a refining expert, and I think that Fernando can give you more detailed answers, but insofar as condensate is concerned, the biggest problem with too much condensate as a percentage of Crude + Condensate (C+C) refining feedstock is that condensate is deficient in distillate (jet fuel, heating oil, diesel, etc.) plus heavier components.Jeffrey J. Brown , 01/25/2016 at 2:00 pmHowever, the quality issue, in my opinion, is something of a Red Herring.
My principal point is not that the liquid partial substitutes for crude oil, i.e., condensate, natural gas liquids (NGL) and biofuels, are deficient in quality compared to crude oil; my principal point is that the available data, at least in my opinion, strongly suggest that we have been on an "Undulating Plateau" in actual global crude oil production (45 API and lower crude oil) since 2005, while global natural gas production and associated liquids, condensate and NGL, have (so far) continued to increase.
The obvious question is that if it took trillions of dollars in post-2005 global upstream capex (spent on oil & gas projects) to keep us on an undulating plateau in actual global crude oil production, what happens to global crude oil production given the large, and ongoing, cutbacks in global upstream capex?
But in regard to refinery yields, here is a chart of refinery yields by API Gravity. Note that Cat Feed + Distillate Yield drops from about 55% at 39 API gravity (approximately the average API value for Brent & WTI) to about 20% at 42 API Gravity (which is the maximum upper limit for WTI crude oil).Here's a link to, and an excerpt from, the source document for the chart:
http://www.nrcan.gc.ca/energy/crude-petroleum/4561
The figure below illustrates the product yield for six typical types of crude oil processed in Canada. It includes both light and heavy as well as sweet and sour crude oils. A very light condensate* (42 API) and a synthetic crude oil are also included. The chart compares the different output when each crude type is processed in a simple distillation refinery. The output is broken down into five main product groups: gasoline, propane and butane (C3/C4), Cat feed (a partially processed material that requires further refining to make usable products), distillate (which includes diesel oil and furnace oil) and residual fuel (the heaviest and lowest-valued part of the product output, used to make heavy fuel oil and asphalt).
As I have previously discussed, I suspect that US (and perhaps global) refiners hit, in late 2014, the upper limit of how much condensate that they could process if they wanted to maintain their output of distillates and heavier products, which plausibly contributed to the 100 million barrel build in US C+C inventories, from late 2014 to late 2015, as US refiners increased their net crude oil imports from December, 2014 to December, 2015.
*The more common dividing line between crude & condensate is 45 API Gravity, but EIA data indicate that about 40% of US Lower 48 C+C production in 2015 exceeded 42 API Gravity, which is the maximum upper limit for WTI crude oil.
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AlexS, 01/24/2016 at 10:54 am
There are still significant discrepancies between the EIA monthly and weekly data for U.S. C+C production.
Weekly numbers show an increase of 139 kb/d from September 25 to January 15, including an uninterrupted growth (of 71 kb/d) over the past 6 weeks from December 4.
likbez , 01/24/2016 at 3:07 pm
Alex,AlexS, 01/24/2016 at 7:04 pmThank you --
This large discrepancy between weekly and monthly data suggests that sources are at least partially different and somewhat incompatible. This also puts a shadow on the accuracy of EIA data in general, especially provided by the monthly short term energy outlook.
I think similar problems exist in other statistical data that EIA the short term energy outlook provides.
Previously I asked a similar question about reliability of their world C+C production and consumption data, but I did this from the point of view of accuracy individual country data (which are probably less then 1%):
http://peakoilbarrel.com/opec-except-iran-has-peaked/#comment-557103
It is well known that OPEC countries used to cheat on their production data as their quotas depend on the current volume of production.
Amatoori also provided a link for the following article which is relevant to this discussion: http://www.reuters.com/article/us-oil-prices-kemp-idUSKCN0V0276?feedType=RSS&feedName=GCA-Commodities&utm_source=dlvr.it&utm_medium=twitter&dlvrit=1391616
See also response of Watcher to his comment:
http://peakoilbarrel.com/opec-except-iran-has-peaked/#comment-557074likbez,likbez, 01/25/2016 at 10:01 amWe have many times discussed the [un]reliability of the EIA U.S. oil production statistics. They have previously relied on the state-level data, which in many cases is uncomplete, with few exceptions (like North Dakota). The EIA was adjusting these numbers according to their old methodology. But their numbers were still inaccurate and had to be revised many times during the next 12 months.
The EIA now has a new methodology: they get production data directly from the largest companies, which account for about 90% of total output in each state. This survey-based approach now covers 15 individual states and the federal Gulf of Mexico, where the bulk of U.S. C+C is produced. The EIA claims that the new methodology has improved the quality of their estimates. But, as can be seen from the chart below, the numbers still need to be revised, and all of the revisions over the past 4 months were upward (see the chart below).
In 2015, the EIA has not only underestimated U.S. oil production numbers for the past months, but its predictions for the next several months were also too low. As a result, the most recent numbers for some months are up to 0.5 mb/d higher than earlier estimates.
The EIA weekly numbers are based on completely different methodology, and they were always seen as very inaccurate. Furthermore, unlike monthly statistics, weekly numbers are never revised.
What is interesting, weekly statistics from my chart above show a rising trend in U.S. oil production from October to January, while monthly numbers suggest a declining trend. But monthly numbers for October may again be revised upward, while the numbers from November are forecast, rather than estimate. We may not know the more or less exact numbers for end-2015 until mid-2016.
U.S. C+C production estimates from the last 5 issues of the EIA Short-Term Energy Outlook
There are several hypothesis that can be advanced based on the data accuracy and a huge lag of EIA and IEA data (as somebody aptly noted: the main purpose of IEA data is to please Americans):1. Any talk about world glut below 1 Mb/d should be dismissed as statistical noise as the accuracy of supply/demand data for most countries does not allow to defect such a glut or oil shortage.
2. EIA is not only statistical outlet but also a propaganda outlet as well providing (sometimes false) signals to Wall street traders and as such having outsize influence on the dynamic of oil prices. They literally can move oil up or down.
3. "The Great Condensate Con" was probably intentional and essentially is equal to creating an artificial additional pressure on oil prices via manipulated statistics.
4. The only data that can counterbalance EIA/IEA bias can come from OPEC, but taking into account outsize influence of Saudis within the organization chances are slim.
5. Rebound of prices, if any, can be pretty abrupt as lack of supplies will be detected only when it becomes acute.
6. Repeating Watcher "It is indeed astounding that oil numbers, the most important numbers for all civilization, are not reliable."
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dmg555, 01/25/2016 at 1:43 pm
Dear Mr. Jeffrey Brown:Watcher , 01/25/2016 at 3:40 pmOf all the contributors on this site, you have highlighted the problems inherent in counting condensates as crude. I am not a petroleum chemist so am not so familiar with the limitations of condensates. Could you briefly tell me what you can and can not use condensates for? I get that one can refine 30-45 WTI into gasoline and other useful fuels like jet fuel, but: Can you drive on condensates? or am I correct in believing the condensates can only be turned into heating fuels.
Thanks for your answer in advance
Yeah, distillate yield is the big deal. Gasoline doesn't move food.likbez , 01/25/2016 at 5:18 pm> "Can you drive on condensates?"Yes, but it's illegal in most states (https://en.wikipedia.org/wiki/Natural-gas_condensate)
It is also harmful to modern engines due to its low octane rating ( about 30 to 50) and possible presence of cancerogenius additives (benzene) and sulfur. Before 1930 it was used as an ICE fuel in low RPM, low compression engines. Both Karl Benz engines, and early Wright brothers aircraft engines used it. It has a distinctive smell when used as a fuel, which allows police to catch people using condensate illegally.
The white gas sold today as a fuel for stoves is a condensate with the benzene and sulfur removed.
Adding ethanol improves the octane number (https://en.wikipedia.org/wiki/Octane_rating) and makes it possible to drive regular cars on distillate. You need E85 mix for that.
My impression is that the drive to blend ethanol with gasoline (most of the gasoline now sold in the United States contains some ethanol) and introduction of E10, E15, and E85 that happened in the USA was at least partially dictated by the desire to blend condensate (as a substitute for gasoline) with ethanol killing two birds with one stone. Moreover denaturized ethanol contains at least 2% of condensate. All gasoline engine vehicles can use E10 so some amount of condensate is present in US gasoline almost by definition.
E85 (used only in flexible-fuel vehicles (FFV) ) allows blending of considerable amount of reprocessed condensate (probably 40-50%) with ethanol and still getting acceptable octane number. E85 is an abbreviation for an ethanol fuel blend of 85% denatured ethanol fuel and 15% gasoline or other hydrocarbons by volume, although the exact ratio of fuel ethanol to hydrocarbons can vary considerably while still carrying the E85 label. The ethanol content is adjusted according to the local climate to maximize engine performance. ASTM 5798 specifies the allowable fuel ethanol content in E85 as ranging from 51% to 83%.
Condensate has a very low viscosity and often used to dilute highly viscous heavier oils that cannot otherwise be efficiently transported via pipelines.
Jeffrey J. Brown , 01/25/2016 at 1:55 pm
I'm actually not anywhere close to be a refining expert, and I think that Fernando can give you more detailed answers, but insofar as condensate is concerned, the biggest problem with too much condensate as a percentage of Crude + Condensate (C+C) refining feedstock is that condensate is deficient in distillate (jet fuel, heating oil, diesel, etc.) plus heavier components.Jeffrey J. Brown , 01/25/2016 at 2:00 pmHowever, the quality issue, in my opinion, is something of a Red Herring.
My principal point is not that the liquid partial substitutes for crude oil, i.e., condensate, natural gas liquids (NGL) and biofuels, are deficient in quality compared to crude oil; my principal point is that the available data, at least in my opinion, strongly suggest that we have been on an "Undulating Plateau" in actual global crude oil production (45 API and lower crude oil) since 2005, while global natural gas production and associated liquids, condensate and NGL, have (so far) continued to increase.
The obvious question is that if it took trillions of dollars in post-2005 global upstream capex (spent on oil & gas projects) to keep us on an undulating plateau in actual global crude oil production, what happens to global crude oil production given the large, and ongoing, cutbacks in global upstream capex?
But in regard to refinery yields, here is a chart of refinery yields by API Gravity. Note that Cat Feed + Distillate Yield drops from about 55% at 39 API gravity (approximately the average API value for Brent & WTI) to about 20% at 42 API Gravity (which is the maximum upper limit for WTI crude oil).Here's a link to, and an excerpt from, the source document for the chart:
http://www.nrcan.gc.ca/energy/crude-petroleum/4561
The figure below illustrates the product yield for six typical types of crude oil processed in Canada. It includes both light and heavy as well as sweet and sour crude oils. A very light condensate* (42 API) and a synthetic crude oil are also included. The chart compares the different output when each crude type is processed in a simple distillation refinery. The output is broken down into five main product groups: gasoline, propane and butane (C3/C4), Cat feed (a partially processed material that requires further refining to make usable products), distillate (which includes diesel oil and furnace oil) and residual fuel (the heaviest and lowest-valued part of the product output, used to make heavy fuel oil and asphalt).
As I have previously discussed, I suspect that US (and perhaps global) refiners hit, in late 2014, the upper limit of how much condensate that they could process if they wanted to maintain their output of distillates and heavier products, which plausibly contributed to the 100 million barrel build in US C+C inventories, from late 2014 to late 2015, as US refiners increased their net crude oil imports from December, 2014 to December, 2015.
*The more common dividing line between crude & condensate is 45 API Gravity, but EIA data indicate that about 40% of US Lower 48 C+C production in 2015 exceeded 42 API Gravity, which is the maximum upper limit for WTI crude oil.
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peakoilbarrel.com
Jimmy 01/23/2016 at 7:02 pmA new post from Aleklettlikbez , 01/23/2016 at 7:37 pmHe does not ask himself an important question, what all those tankers contain. Is this crude or condensate? Or some refined products like heating oil too.Jeffrey J. Brown , 01/23/2016 at 7:52 pmFor what it's worth, Iranian sources say it's condensate and fuel oil. I guess we will find out.Matt Mushalik , 01/24/2016 at 5:09 amhttp://www.reuters.com/article/iran-oil-idUSL3N1021Z120150723
For comparisonJeffrey J. Brown , 01/24/2016 at 8:31 amUS condensate production increased from 231 mb in 2011 (start of shale oil boom) to 326 mb in 2014
https://www.eia.gov/dnav/ng/hist/rl2r57nus_1a.htmSo IEA's estimate of 36 mb x 0.67 = 24 mb would be 7.4 % of 2014 US condensate production
There are some reporting issues regarding "Lease condensate," i.e., I suspect that a good deal of condensate production is reported as crude oil production. And in fact, the EIA refers to Crude + Condensate (C+C) as "Crude oil."Synapsid , 01/24/2016 at 7:07 pmA survey that the EIA did last year estimated that 22%, or about 2 million bpd, of US Lower 48 C+C production consists of condensate (45 API +). And about 40% of US Lower 48 C+C production exceeded the maximum API Gravity for WTI crude oil (42 API Gravity).
My "Condensate Con" comment:
http://econbrowser.com/archives/2016/01/world-oil-supply-and-demand#comment-194595
Matt Mushalik,AlexS , 01/23/2016 at 8:27 pmI'm a little uncertain about the figures because your link takes you to a page, under the heading Natural Gas, titled Natural Gas Liquids Lease Condensate. To me, "lease condensate" means wellhead condensate and that is not associated with NGLs; condensate also comes out at the NGL-separation stage down the line. If it is the latter that the chart refers to, then the figure is not total production of condensate but only that recovered from the NGL stream.
Somebody help?
"At the end of November, roughly 36 mb of oil, of which 67% was condensates, was floating in 18 tankers."AlexS , 01/23/2016 at 8:37 pm
Source: IEA Oil Market Report, December 2015Iranian oil in floating storage
source: http://money.cnn.com/2016/01/18/investing/iran-sanctions-hoarding-oil-prices/index.html
"With no clear timeline for a restart at petrochemicals producer Dragon Aromatics, one of Tehran's key condensate buyers, after its April fire, Iran hoped new buyers in South Korea, Japan as well as in China would pick up the slack, traders said.The CNOOC-Shell petrochemical plant in southeastern Guangdong province could also be a replacement buyer for condensate, they said. The plant was forced to drop a regular supply pact in mid-2012 when the European Union put an embargo on trading Iranian oil."
http://www.reuters.com/article/2015/12/03/us-china-iran-oil-idUSKBN0TM0CN20151203
"Iran may roil global oil markets with plans to sell about 45 million barrels of fuel stored in tankers in the Persian Gulf within three months of the removal of sanctions on its economy, according to analysts.
Most of the stored oil is condensate that contains a sulfur compound, which complicates sales because many refineries can't process it, said Victor Shum of IHS Inc. and Robin Mills at Dubai-based Manaar Energy Consulting. To market this large amount of oil within three months - the equivalent of about half a million barrels a day - Iran will have to resort to offering deep discounts, they said."
The condensate … is pumped from the offshore South Pars natural gas deposit.
Iran may need to spur sales of its sulfur-heavy condensate by offering discounts of at least 10 to 15 percent, Shum said. Its main condensate customer, Dragon Aromatics Zhangzhou Co. of China, stopped buying after a fire at its plant in April and an Iranian refinery designed to use it won't be ready until 2017, causing stockpiles to build, he said.
"There will have to be a major impact on the market of selling that condensate," said Manaar Energy's Mills, who worked for Royal Dutch Shell Plc on projects in Iran from 1998 to 2003. "If they're already having difficulty shifting it, adding another half million barrels will be even more difficult," he said by phone. "They'll manage, but at what discount?"
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peakoilbarrel.com
Jeffrey J. Brown, 01/21/2016 at 6:56 amhttp://econbrowser.com/archives/2016/01/world-oil-supply-and-demand#comment-194595Huckleberry Finn, 01/21/2016 at 1:34 pmMy premise is that US (and perhaps global) refiners hit, late in 2014, the upper limit of the volume of condensate that they could process, if they wanted to maintain their distillate and heavier output–resulting in a build in condensate inventories, reflected as a year over year build of 100 million barrels in US C+C (Crude + Condensate) inventories.
Therefore, in my opinion the US and (and perhaps globally) C+C inventory data are fundamentally flawed, when it comes to actual crude oil inventory data. The most common dividing line between actual crude oil and condensate is 45 API gravity, although the distillate yield drops off considerably just going from 39 API to 42 API gravity crude, and the upper limit for WTI crude oil is 42 API. . . .
Note that (in 2015) 22% of US Lower 48 C+C production consists of condensate (45+ API gravity) and note that about 40% of US Lower 48 C+C production exceeds the maximum API gravity for WTI crude oil (42 API).
Mr. Brown,Just so I understand what you are saying: Crude plus Condensate Inventory build have been higher because mainly of Condensate as EIA is no longer properly distinguishing the difference?
If that 100 Million number is true, we might see $100 oil this year I think.
BTW the last two weeks saw some massive builds in "Blending components for gasoline" while the market went wild because it looked like actual products were building.
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resourceinsights.blogspot.com
- Joe said...
- My guess is that the surplus of condensate and blended "dumbell crudes" has been stacking up in storage tanks, especially in the US, cutting the amount of working storage available to purchasers. Lack of storage increases the sensitivity of the market price to supply/demand imbalance magnitude. If a purchaser of oil has plenty of cheap storage, they might purchase oil they can't use today at a slight discount and save it for future use. If they have no storage they won't buy it at all, no matter how low the price.
- 9:42 AM
- energyskeptic said...
- Kurt, are you saying that the apparent oil glut is mostly NGL's and not oil? Also, are NGL's what make it appear that oil storage is full? I never could understand why NGL's are included in oil production in the EIA stats, since only 13% of NGL's can be blended with gasoline (the pentane).
The rest is ethane, butane, propane, and isobutane -- mainly useful for petrochemicals, plastics, and heating (propane).
By the way, I've just written a book for Charlie Hall's Springer Energy Briefs series called "When Trucks stop running: Energy and the Future of Transportation" where I look at all the possible ways trucks, rail, and ships could keep moving as oil declines, including NGL's, CNG, LNG, coal-to-liquids, biofuels, hydrogen, electrification, etc. More info at http://www.springer.com/us/book/9783319263731
or
http://energyskeptic.com/2016/when-trucks-stop-running-so-does-civilization/I think all the endless electric car nonsense is effective at distracting people from the heavy-duty transportation that really matters. Virtually everything in our homes, everything in our stores, got there on a truck. Prior to that, 90 percent of those items were transported on a ship and/or a train, which all run on finite oil. If trucks, trains, and ships stopped running, our global economy and way of life would stop too.
- 5:02 PM
- Kurt Cobb said...
- Alice,
First, I find myself hitting your site regularly since so many people refer to your work. So, thanks for the great work you are doing.
As for condensates and NGLs, terminology in this case is the enemy of clarity. For a good treatment of this problem How the changing definition of oil has deceived both policymakers and the public . NGLs generally refer to both natural gas plant liquids and lease condensate which originate from two different sources, i.e. gas wells vs. oil wells. And, yes, part of the storage issue is the storage of lease condensate since it is often, as indicated, mixed with crude oil. Natural gas plant liquids come from natural gas processing plants and so are not typically stored in combination with crude oil (though in gasoline refining, butane is usually mixed in with gasoline).
Yes, propane and butane, are used for transportation fuels. But their supply is limited by the amount of natural gas demand. No one withdraws natural gas from wells solely for the propane or butane it contains. There are practical limits to how many propane-powered vehicles we can have.
Now, if we didn't make certain chemicals from natural gas plant liquids, we would be making them from oil, and so in an indirect way this keeps more oil in the liquid fuels market rather than the petrochemical market. But I think the substitution effect here is exaggerated by those saying we should consider all liquids as part of the oil supply. As I said in the piece, the marketplace certainly makes distinctions between these products.
I think you are right about truck freight being crucial to our current way of living. I remember an exchange with an Italian reader who explained that while European passenger rail is far superior to that of the United States, one reason for this is often not understood. Much of the freight in the United States moves by rail at some point and so our tracks are filled with freight trains that delay passenger travel. In Europe 80 percent of the freight moves by truck. The rails are not so burdened with freight and so passenger trains move with fewer delays and at higher speeds.
But in both places truck freight remains crucial. Best of luck with your new book.
- 5:37 PM
- westexas said...
- Condensate is basically natural gasoline, and it is a byproduct of natural gas production. However, the issue of relative quality, between crude and condensate, is a little bit of a red herring.
The CC's (Cornucopian Crowd) argue that there is no sign of any kind of peak in sight. I would argue that this assertion is manifestly false when it comes to actual crude oil production (45 API and lower crude oil). In my opinion, the available data strongly suggest that we have been on an "Undulating Plateau" in actual global crude oil production since 2005, while global natural gas production and associated liquids, condensate & natural gas liquids, have so far continued to increase.
Again, what the EIA calls "Crude oil" is actually Crude + Condensate (C+C), and based on EIA data 22% of Lower 48 C+C production in 2015 exceeded 45 API gravity and about 40% of US Lower 48 C+C production exceeded the maximum API limit for WTI crude (42 API Gravity).
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finance.yahoo.com
Crude Oil Rally Short-Lived: Fundamentals Still Feeding the Bears
EIA's gasoline and distillate inventoriesThe EIA (U.S. Energy Information Administration) reported that the US gasoline inventory rose by 8.4 MMbbls to 240.4 MMbbls for the week ending January 8, 2016. This rise was less than the rise of 10.6 MMbbls during the week ending January 1, 2016. Similarly, the US distillate inventory rose by 6.1 MMbbls to 165.6 MMbbls for the week ending January 8, 2016.
EIA's gasoline and distillate inventories by region
The EIA added that of the five major US storage hubs, the Gulf Coast, the Midwest, and the East Coast recorded the highest gasoline inventories for the week ending January 8, 2016. To learn more about the US storage hubs, read the previous part of this series. Gasoline inventories in these regions came in at 82.6 MMbbls, 57.6 MMbbls, and 62.9 MMbbls, respectively.
Similarly, distillate inventories were highest in the Gulf Coast, the Midwest, and the East Coast regions. The US distillate inventories were 48.1 MMbbls, 33.3 MMbbls, and 64.9 MMbbls, respectively, in these three regions.
EIA's gasoline and distillate inventory estimates and impact
Reuters' surveys estimated that the US gasoline inventory would rise by 2.7 MMbbls and the US distillate inventory would rise by 2 MMbbls for the week ending January 8, 2016. The greater-than-expected rise in refined products inventories weighed on crude oil prices. Lower crude oil prices benefit US refiners like Phillips 66 (PSX), Western Refining (WNR), Alon USA Partners (ALDW), and Northern Tier Energy (NTI). On the other hand, higher refined products inventories put pressure on refiners. The refined products inventories rose due to the fall in retail demand this winter season. Read about refinery demand in the fifth part of this series.
The fall in retail and refinery demand also affects crude oil prices and oil producers like Chevron (CVX), Whiting Petroleum (WLL), and Continental Resources (CLR). ETFs like the ProShares UltraShort Bloomberg Crude Oil ETF (SCO), the Vanguard Energy ETF (VDE), and the First Trust Energy AlphaDEX Fund (FXN) are also affected by the ups and down in the oil market.
Read why US crude oil production is crucial for the global crude oil market in the next part of this series.
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Jan 19, 2016 | OilPrice.com
My favorite Texas oilman is at it again. In a recent email he's pointing out to everyone who will listen that the supposed oversupply of crude oil isn't quite what it seems. Yes, there is a large overhang of excess oil in the market. But how much of that oversupply is honest-to-god oil and how much is so-called lease condensate which gets carelessly lumped in with crude oil? And, why is this important to understanding the true state of world oil supplies?In order to answer these questions we need to get some preliminaries out of the way.
Lease condensate consists of very light hydrocarbons which condense from gaseous into liquid form when they leave the high pressure of oil reservoirs and exit through the top of an oil well. This condensate is less dense than oil and can interfere with optimal refining if too much is mixed with actual crude oil. The oil industry's own engineers classify oil as hydrocarbons having an API gravity of less than 45--the higher the number, the lower the density and the "lighter" the substance. Lease condensate is defined as hydrocarbons having an API gravity between 45 and 70. (For a good discussion about condensates and their place in the marketplace, read "Neither Fish nor Fowl – Condensates Muscle in on NGL and Crude Markets.")
Refiners are already complaining that so-called "blended crudes" contain too much lease condensate, and they are seeking out better crudes straight from the wellhead. Brown has dubbed all of this the great condensate con.
Brown points out that U.S. net crude oil imports for December 2015 grew from the previous December, according to the U.S. Energy Information Administration (EIA), the statistical arm of the U.S. Department of Energy. U.S. statistics for crude oil imports include condensate, but don't break out condensate separately. Brown believes that with America already awash in condensate, almost all of those imports must have been crude oil proper.
Brown asks, "Why would refiners continue to import large--and increasing--volumes of actual crude oil, if they didn't have to--even as we saw a huge build in [U.S.] C+C [crude oil plus condensate] inventories?"
Part of the answer is that U.S. production of crude oil has been declining since mid-2015. But another part of the answer is that what the EIA calls crude oil is actually crude plus lease condensate. With huge new amounts of lease condensate coming from America's condensate-rich tight oil fields -- the ones tapped by hydraulic fracturing or fracking -- the United States isn't producing quite as much actual crude oil as the raw numbers would lead us to believe. This EIA chart breaking down the API gravity of U.S. crude production supports this view.
Exactly how much of America's and the world's presumed crude oil production is actually condensate remains a mystery. The data just aren't sufficient to separate condensate production from crude oil in most instances.
Brown explains: "My premise is that U.S. (and probably global) refiners hit in late 2014 the upper limit of the volume of condensate that they could process" and still maintain the product mix they want to produce. That would imply that condensate inventories have been building faster than crude inventories and that the condensate is looking for an outlet.
That outlet has been in blended crudes, that is heavier crude oil that is blended with condensates to make it lighter and therefore something that fits the definition of light crude. Light crude is generally easier to refine and thus more valuable.
The trouble is, the blends lack the characteristics of nonblended crudes of comparable density (that is, the same API gravity), and refiners are discovering to their chagrin that the mix of products they can get out of blended crudes isn't what they expect.
So, now we can try to answer our questions. Brown believes that worldwide production of condensate "accounts for virtually all of the post-2005 increase in C+C [crude plus condensate] production." What this implies is that almost all of the 4 million-barrel-per-day increase in world "oil" production from 2005 through 2014 may actually be lease condensate. And that would mean crude oil production proper has been nearly flat during this period -- a conjecture supported by record and near record average daily prices for crude oil from 2011 through 2014. Only when demand softened in late 2014 did prices begin to drop.
Here it is worth mentioning that when oil companies talk about the price of oil, they are referring to the price quoted on popular futures exchanges -- prices which reflect only the price of crude oil itself. The exchanges do not allow other products such as condensates to be mixed with the oil that is delivered to holders of exchange contracts.
But when oil companies (and governments) talk about oil supply, they include all sorts of things that cannot be sold as oil on the world market including biofuels, refinery gains and natural gas plant liquids as well as lease condensate. Which leads to a simple rule coined by Brown: If what you're selling cannot be sold on the world market as crude oil, then it's not crude oil.
The glut that developed in 2015 may ultimately be tied to some increases in actual, honest-to-god crude oil production. The accepted story from 2005 through 2014 has been that crude oil production has been growing, albeit at a significantly slower rate than the previous nine-year period--15.7 percent from 1996 through 2005 versus 5.4 percent from 2005 through 2014 according to the EIA. If Brown is right, we have all been victims of the great condensate con which has lulled the world into a sense of complacency with regard to actual oil supplies--supplies he believes have been barely growing or stagnant since 2005.
"Oil traders are acting on fundamentally flawed data," Brown told me by phone. Often a contrarian, Brown added: "The time to invest is when there's blood in the streets. And, there's blood in the streets."
He explained: "Who of us in January of 2014 believed that prices would be below $30 in January of 2016? If the conventional wisdom was wrong in 2014, maybe it's similarly wrong in 2016" that prices will remain low for a long time.
Brown points out that it took trillions of dollars of investment from 2005 through today just to maintain what he believes is almost flat production in oil. With oil companies slashing exploration budgets in the face of low oil prices and production declining at an estimated 4.5 and 6.7 percent per year for existing wells worldwide, a recovery in oil demand might push oil prices much higher very quickly.
That possibility is being obscured by the supposed rise in crude oil production in recent years that may just turn out to be an artifact of the great condensate con.
By Kurt Cobb
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Huckleberry Finn, 12/25/2015 at 8:32 am
Does a barrel of NGL have the same BTU as a Barrel of Crude or Condensate?Ron Patterson, 12/25/2015 at 9:06 amIf not, converting all into BTU would show whether total BTUs provided are increasing or static.
Rune Likvern says: NGLs have around 60 – 70% of the volumetric energy (heat) content of crude oil.Jeffrey J. Brown, 12/25/2015 at 10:05 amHowever peak oil will happen when oil peaks, not NGLs. Liquid transportation BTUs should not be mixed with other types of BTUs. Otherwise we would need to count BTUs from coal as well.
Some EIA million BTU (MMBTU) conversion factors:Anton Koffield, 12/26/2015 at 12:49 pmhttps://www.eia.gov/forecasts/aeo/pdf/appg.pdf
Of course, what the EIA calls "Crude oil" is actually Crude + Condensate (C+C), and condensate can't be used to meet crude oil contractual obligations at Cushing. I assume that the listed value for gasoline, 5.2 MMBTU, is a pretty good approximation for an average value for condensate.
For the first nine months of 2015, the EIA estimates that the ratio of US Lower 48 condensate* to US Lower 48 "Crude oil" Production, i.e., C+C, was 22%, or 2 million bpd of Lower 48 condensate production:
EIA expands monthly reporting of crude oil production (i.e., C+C) with new data on API gravity:
https://www.eia.gov/todayinenergy/detail.cfm?id=23952These numbers are consistent with some estimates that I used in the following comment, where I tried to come up with an estimate of actual global crude oil production (45 API and lower crude oil, i.e., the stuff that corresponds to the global price indexes), versus global condensate production, using the only available data, some EIA API gravity estimates for the US and EIA/OPEC data for the OPEC countries.
My premie was and is that we have been on an "Undulating plateau" in actual global crude oil production, while global natural gas production and associated liquids, condensate and NGL, have so far continued to increase:
http://peakoilbarrel.com/jean-laherreres-bakken-update/comment-page-1/#comment-534101
After showing similar rates of increase from 2002 to 2005, global NGL production was up by 26% from 2005 to 2014, while global C+C production was up by only 6% over the same time period (EIA).
*Condensate with API gravity of 45 degrees or more
What is condensate used for?AlexS. 12/26/2015 at 12:55 pmmost of condensate is mixed with crude oils as a refinery input; some is used as petrochemical feedstockJeffrey J. Brown, 12/26/2015 at 8:17 pmCondensate is basically natural gasoline.Anton Koffield. 12/27/2015 at 1:57 pmMy principal point is not that condensate doesn't produce the full spectrum of refined products that we get from 38 API gravity crude oil; my principal point is that the available data strongly suggest that actual global crude oil production (45 API and lower gravity crude oil) has been on an undulating plateau since 2005, as annual Brent crude oil prices doubled from $55 in 2005 to the $110 range for 2011 to 2013 (remaining at $99 in 2014).
In other words, I think that actual global crude oil production effectively peaked in 2005, while global gas production and associated liquids, condensate and NGL, have so far continued to increase.
Note that based on the following chart, it's very likely that about 40% of 2015 US Crude + Condensate (C+C) production exceeds the upper limit for WTI crude oil (which has an API ceiling of 42):
I take your points.Jeffrey J. Brown , 12/27/2015 at 2:00 pmIf Condensate is basically natural gasoline, can one infer that the amount/effort of refining required to produce retail gasoline is fairly 'easy'?
If this is so, and if gasoline is the primary refined product from crude oil (measured in volume, sales price, and/or 'importance' to the economy) then is this not a 'good' thing? And does this help explain why gasoline prices are rather low in the U.S. presently? Is it not preferable to refine 'natural gasoline'; in to 'retail gasoline' rather than process heavy oils, some perhaps contaminated with sulfur and vanadium or whatnot?
Of course I don't posit that this situation will go on for the long term, not that it is a 'good' thing wrt long-term energy planning (or lack thereof due to short-term thinking referencing current low price signals).
As noted above, my principal point is not that condensate doesn't produce the full spectrum of refined products that we get from 38 API gravity crude oil; my principal point is that the available data strongly suggest that actual global crude oil production (45 API and lower gravity crude oil) has been on an undulating plateau since 2005, as annual Brent crude oil prices doubled from $55 in 2005 to the $110 range for 2011 to 2013 (remaining at $99 in 2014).Anton Koffield . 12/27/2015 at 3:48 pmI take your point.Ron Patterson , 12/27/2015 at 4:41 pmPerhaps either or both of these things have happened since mid-2014:
- The 'system' has adjusted somehow to effective use the current crude + condensate + NGL ratios being produced at the wellhead.
- The World economy has become unsound/fragile enough that it cannot support a crude oil price, not for long without lurching into recession or worse, than the current Brent market price of $37.89/bbl.
Perhaps since gasoline comprises some 53% of U.S. finished products from crude oil, then having a goodly amount of condensate which is 'natural gasoline' has contributed to the rather low prices for retail gasoline seen in the U.S. over the past year.
I wonder what the price trends have been over the past years for distillate fuel oil and kerosene and other non-gasoline products? Have they gone up in price (as opposed to gasoline)?
U.S. Petroleum & Other Liquids Product Supplied:
http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_mbblpd_a.htm
The bumpy price plateau for Brent (which I take it as a marker for Brent production in your example?) has been a bumpy plateau from Q1 2011 through nmid-2014, after which it nosed-dived to the current $37.89 price.
http://www.nasdaq.com/markets/crude-oil-brent.aspx?timeframe=10y
Surely the actual global crude oil production (45 API and lower gravity crude oil) has not spiked since early 2014, has it? If not, then the Brent price is not a reliable proxy for such production. See my conjectures (#1 & #2) above. There may be other conjectures which may be valid. Of course none of these ideas may be mutually exclusive.
Please note that I am scoping much of my commentary to the U.S. situation…although Brent and WTI and other price constructs are supposedly indicative of the World's supply and demand situation, yes?
Perhaps since gasoline comprises some 53% of U.S. finished products from crude oil, then having a goodly amount of condensate which is 'natural gasoline' has contributed to the rather low prices for retail gasoline seen in the U.S. over the past year.53% is little high.
How many gallons of diesel fuel and gasoline are made from one barrel of oil?Refineries in the United States produced an average of about 12 gallons of diesel fuel and 19 gallons of gasoline from one barrel (42 gallons) of crude oil in 2014. Many other petroleum products are also refined from crude oil. Refinery yields of individual products vary from month to month as refiners focus operations to meet demand for different products and to maximize profits.
However condensate, or naphtha, or natural gasoline, three names for the same thing, is not really gasoline. Gasoline is primarily octane or C8H18. Naphtha is primarily pentane, or C5H12. (Though naphtha does contain a lot of other hydrocarbons.)
Condensate is the lightest liquid petroleum product. That is it is a liquid at sea level pressures and room temperature. You can burn it in your car like gasoline. But your car will knock terribly, and your motor will not likely last very long.
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Fifty glorious years (1950-2000): the triumph of the US computer engineering : Donald Knuth : TAoCP and its Influence of Computer Science : Richard Stallman : Linus Torvalds : Larry Wall : John K. Ousterhout : CTSS : Multix OS Unix History : Unix shell history : VI editor : History of pipes concept : Solaris : MS DOS : Programming Languages History : PL/1 : Simula 67 : C : History of GCC development : Scripting Languages : Perl history : OS History : Mail : DNS : SSH : CPU Instruction Sets : SPARC systems 1987-2006 : Norton Commander : Norton Utilities : Norton Ghost : Frontpage history : Malware Defense History : GNU Screen : OSS early history
Classic books:
The Peter Principle : Parkinson Law : 1984 : The Mythical Man-Month : How to Solve It by George Polya : The Art of Computer Programming : The Elements of Programming Style : The Unix Hater’s Handbook : The Jargon file : The True Believer : Programming Pearls : The Good Soldier Svejk : The Power Elite
Most popular humor pages:
Manifest of the Softpanorama IT Slacker Society : Ten Commandments of the IT Slackers Society : Computer Humor Collection : BSD Logo Story : The Cuckoo's Egg : IT Slang : C++ Humor : ARE YOU A BBS ADDICT? : The Perl Purity Test : Object oriented programmers of all nations : Financial Humor : Financial Humor Bulletin, 2008 : Financial Humor Bulletin, 2010 : The Most Comprehensive Collection of Editor-related Humor : Programming Language Humor : Goldman Sachs related humor : Greenspan humor : C Humor : Scripting Humor : Real Programmers Humor : Web Humor : GPL-related Humor : OFM Humor : Politically Incorrect Humor : IDS Humor : "Linux Sucks" Humor : Russian Musical Humor : Best Russian Programmer Humor : Microsoft plans to buy Catholic Church : Richard Stallman Related Humor : Admin Humor : Perl-related Humor : Linus Torvalds Related humor : PseudoScience Related Humor : Networking Humor : Shell Humor : Financial Humor Bulletin, 2011 : Financial Humor Bulletin, 2012 : Financial Humor Bulletin, 2013 : Java Humor : Software Engineering Humor : Sun Solaris Related Humor : Education Humor : IBM Humor : Assembler-related Humor : VIM Humor : Computer Viruses Humor : Bright tomorrow is rescheduled to a day after tomorrow : Classic Computer Humor
The Last but not Least Technology is dominated by two types of people: those who understand what they do not manage and those who manage what they do not understand ~Archibald Putt. Ph.D
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Last modified: May, 08, 2021
