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Contents Bulletin Scripting in shell and Perl Network troubleshooting History Humor

Subprime oil: Deflation of the USA shale oil bubble

News Peak Cheap Energy and Oil Price Slump Recommended Links Energy Bookshelf Secular Stagnation Energy returned on energy invested (ERoEI) A note of ERoEI decline
MSM propagated myth about Saudis defending this market share Deflation of the USA shale oil bubble Oil glut fallacy Why Peak Oil Threatens the Casino Capitalism Energy and the Economy Bakken Reality Check Shale Well Economics and cost of production estimates
Energy Geopolitics Ukraine: From EuroMaidan to EuroAnschluss Russian Ukrainian Gas wars The fiasco of suburbia Fiat money, gold and petrodollar The Great Stagnation Big Fukushima Debate
Casino Capitalism Inflation, Deflation and Confiscation All wars are bankers wars Why Peak Oil Threatens the International Monetary System Financial Quotes Financial Humor Etc

In recent years Americans have been hearing that the United States is poised to regain its role as the world’s premier oil and natural gas producer, thanks to the widespread use of horizontal drilling and hydraulic fracturing (“fracking”). This “shale revolution,” we’re told, will fundamentally change the U.S. energy picture for decades to come—leading to energy independence, a rebirth of U.S. manufacturing, and a surplus supply of both oil and natural gas that can be exported to allies around the world. This promise of oil and natural gas abundance is influencing climate policy, foreign policy, and investments in alternative energy sources.

The term "shale bubble" is about the idea that the United States is poised to regain "energy independence"  becoming again net exporter instead of major importer of oil and natural gas. The primary driver of the propaganda campaign was the U.S. Department of Energy’s Energy Information Administration (EIA). The key technologies that were enabler of shell boom were:

This fake promise of oil and natural gas abundance affected both domestic government priorities and foreign policy. Domestically it slowed down rising of private car fleet efficiency d as well as  investments in alternative energy sources. The implications of this are profound. If the “shale revolution” is nothing more than a temporary respite from the inevitable decline in US oil and gas production (not a revolution but a retirement party), then why are there is such a rush to rewrite our domestic and foreign policy as if we’re going to be “Saudi America” for the rest of the century?

In 2015 U.S. shale oil production has peaked, productivity gains have flatlined and the cheap money has all but disappeared. Has the U.S. shale game finally blown over? (Alberta Oil Magazine, Jan 7, 2016):

To summarize the damage: output has peaked, the cheap money and easy private equity are gone, the gains in per-rig productivity have slowed and the 20 to 30 per cent break that E&P companies were getting from contractors for labor costs won’t go on much longer. By all metrics, the shale party is nearly over. The question now is whether the 2015 production peak will forever be the high-water mark for this uniquely North American industry.

There are three major sources of   "subprime" oil: tight oil, shale oil and tar sands.

The term oil shale generally refers to any sedimentary rock that contains solid bituminous materials (called kerogen) that are released as petroleum-like liquids when the rock is heated in the chemical process of pyrolysis. Oil shale was formed millions of years ago by deposition of silt and organic debris on lake beds and sea bottoms. Over long periods of time, heat and pressure transformed the materials into oil shale in a process similar to the process that forms oil; however, the heat and pressure were not as great. Oil shale generally contains enough oil that it will burn without any additional processing, and it is known as "the rock that burns".

Oil shale can be mined and processed to generate oil similar to oil pumped from conventional oil wells; however, extracting oil from oil shale is more complex than conventional oil recovery and currently is more expensive. The oil substances in oil shale are solid and cannot be pumped directly out of the ground. The oil shale must first be mined and then heated to a high temperature (a process called retorting); the resultant liquid must then be separated and collected. An alternative but currently experimental process referred to as in situ retorting involves heating the oil shale while it is still underground, and then pumping the resulting liquid to the surface.

What bother many observers is the amount of  unprofitable (supported by junk bonds) shale oil that come to the market in the relatively short period of time.

Rodster  August 14, 2014 at 4:43 pm

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

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

“There is this huge myth propagated by the MSM as well as several of the well-known names in the alternative analyst community about the wonders of SHALE ENERGY. I can’t tell you how many readers send me articles from some of these analysts stating how the United States will become energy independent while pumping some of these shale energy stocks. Nothing has changed in America….. there’s always another sucker born every minute.

It is extremely frustrating to see the continued GARBAGE called analysis on the SHALE ENERGY INDUSTRY. I have written several articles listing the energy analysts that I believe truly understand what is taking place in U.S. energy industry. They are, Art Berman, Bill Powers, David Hughes, Jeffrey Brown and Rune Likvern.”

While this conversion of junk bonds into oil has features of classic bubble (excessive greed) but it was also different in some major aspects. We know that bankers like bubbles because they always make money on swings, either going up or down. We can accept that that is how things work on this planet under neoliberalism but that does not turn them less crazy. 

At the beginning this was about shale gas, only later it became about shale and tight oil production. But shale oil production did has major elements of a bubble. And greed was present in large qualities. Special financial instruments like ETN were created to exploit this greed. MSM staged a compaign of how the wonders of technology, specifically horizontal drilling and hydraulic fracturing, have unleashed a new era for energy supplies. Without mentioning that for each dollar shale industry recovered 1.5 dollar of junk bonds was created.

If we think about it in bubble terms that the key selling point of this bubble was that it will lead to America’s energy independence, a manufacturing renaissance, and will lower gas bills for everyone. The estimates (based on past reservoir dynamics) were grossly over represented. The factor that is present is bubbles is that they create excess production that at some point far outpace the demand.

North American crude oil producers are not cash flow positive, and they haven’t been since the beginning of the shale boom. Capital expenses of shale companies has consistently exceeded cash flow even at $100 per barrel oil price. So essentially this was a risky gamble that oil will go higher, and this gamble failed. At least for now.

Most experts and analysts agree that, at current oil prices, the shale oil sector will need to dramatically reduce per-barrel costs in order to make the vast majority of North American plays viable. “The minimum price I’ve seen [to make production worthwhile] is $50 a barrel in the very best possible scenarios and with the very best technology,” says Farouq Ali, a chemical and petroleum engineer at the University of Calgary. “But most of the time they need $65 oil. So the 5.5 million shale barrels we see right now will all decline, but they will decline over time because there are still thousands of wells. Even if oil prices go to $60 they will still decline because that’s just not enough profit to operate.”

Of course, those returns aren’t just diminishing on the production side, but in the pocketbooks of investors, too. Wunderlich Securities senior vice-president Jason Wangler describes the rise of U.S. shales as a “perfect storm” of cheap money, seemingly limitless production potential and rapidly advancing technologies. “Now the money is hard to come by,” Wangler says over the phone from the firm’s Houston office. “With oil at $90 or $100 it was pretty hard not to be economic.” But that old high-price environment, he says, caused significant overinvestment in shale assets, including in risky bets on barely marginal plays like the Tuscaloosa Marine Shale formation that spans parts of Louisiana and Mississippi. “But if you look at the last year or so, you’ve seen a lot of folks really focus on the Permian and on the Niobrara,” Wangler says. “Meanwhile you’ve seen the Bakken really fall off very, very hard, as well as the Eagle Ford and the mid-continent area.”

The decreasing viability of the Bakken region is especially significant. Houston-based shale expert and petroleum geologist Arthur Berman estimates that with West Texas oil trading at $46, a mere one per cent of the massive Bakken shale play is profitable. At those prices, just four per cent of the horizontal wells that have been drilled in the Bakken since 2000 would recover their costs for drilling, completion and operations, according to Berman. Add to that the competition from Western Canadian crude oil, which continues to travel down through the U.S. Midwest via rail and pipeline, and one can assume that a lot of Bakken production will remain economically underwater without a significant price correction or some breakthrough in cost savings. “In the Bakken, you’ve got a long way to transport to get that oil to market,” Wangler says. “Obviously you’re fighting with all that Canadian crude coming down, which makes the price more difficult. It’s also expensive to [transport oil out of] North Dakota, whether you’re going to the Gulf Coast or you’re going east or west.”

Due to the dramatic drop of oil prices shale bubble start deflation. Several bankruptcies occurred in 2015. More expected in 2016 if the price not recover.

Some critics to argue the business model of shale production is fundamentally unsustainable. Before the oil rice collapse, which started at mid 2014, immediately after signing Iran deal (strange coincidence)   it was expected that producers would have positive returns for the first time in 2015”

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

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

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

note it goes on for 6 pages…

From About Oil Shale

Oil Shale Resources

   

While oil shale is found in many places worldwide, by far the largest deposits in the world are found in the United States in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming. Estimates of the oil resource in place within the Green River Formation range from 1.2 to 1.8 trillion barrels. Not all resources in place are recoverable; however, even a moderate estimate of 800 billion barrels of recoverable oil from oil shale in the Green River Formation is three times greater than the proven oil reserves of Saudi Arabia. Present U.S. demand for petroleum products is about 20 million barrels per day. If oil shale could be used to meet a quarter of that demand, the estimated 800 billion barrels of recoverable oil from the Green River Formation would last for more than 400 years1.

More than 70% of the total oil shale acreage in the Green River Formation, including the richest and thickest oil shale deposits, is under federally owned and managed lands. Thus, the federal government directly controls access to the most commercially attractive portions of the oil shale resource base.

See the Maps page for additional maps of oil shale resources in the Green River Formation.

The Oil Shale Industry

While oil shale has been used as fuel and as a source of oil in small quantities for many years, few countries currently produce oil from oil shale on a significant commercial level. Many countries do not have significant oil shale resources, but in those countries that do have significant oil shale resources, the oil shale industry has not developed because historically, the cost of oil derived from oil shale has been significantly higher than conventional pumped oil. The lack of commercial viability of oil shale-derived oil has in turn inhibited the development of better technologies that might reduce its cost.

Relatively high prices for conventional oil in the 1970s and 1980s stimulated interest and some development of better oil shale technology, but oil prices eventually fell, and major research and development activities largely ceased. More recently, prices for crude oil have again risen to levels that may make oil shale-based oil production commercially viable, and both governments and industry are interested in pursuing the development of oil shale as an alternative to conventional oil.

Oil Shale Mining and Processing

Oil shale can be mined using one of two methods: underground mining using the room-and-pillar method or surface mining. After mining, the oil shale is transported to a facility for retorting, a heating process that separates the oil fractions of oil shale from the mineral fraction.. The vessel in which retorting takes place is known as a retort. After retorting, the oil must be upgraded by further processing before it can be sent to a refinery, and the spent shale must be disposed of. Spent shale may be disposed of in surface impoundments, or as fill in graded areas; it may also be disposed of in previously mined areas. Eventually, the mined land is reclaimed. Both mining and processing of oil shale involve a variety of environmental impacts, such as global warming and greenhouse gas emissions, disturbance of mined land, disposal of spent shale, use of water resources, and impacts on air and water quality. The development of a commercial oil shale industry in the United States would also have significant social and economic impacts on local communities. Other impediments to development of the oil shale industry in the United States include the relatively high cost of producing oil from oil shale (currently greater than $60 per barrel), and the lack of regulations to lease oil shale.

   
  Major Process Steps in Mining and Surface Retorting  
   

Surface Retorting

While current technologies are adequate for oil shale mining, the technology for surface retorting has not been successfully applied at a commercially viable level in the United States, although technical viability has been demonstrated. Further development and testing of surface retorting technology is needed before the method is likely to succeed on a commercial scale.

In Situ Retorting

Shell Oil is currently developing an in situ conversion process (ICP). The process involves heating underground oil shale, using electric heaters placed in deep vertical holes drilled through a section of oil shale. The volume of oil shale is heated over a period of two to three years, until it reaches 650–700 °F, at which point oil is released from the shale. The released product is gathered in collection wells positioned within the heated zone.

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

Shell's current plan involves use of ground-freezing technology to establish an underground barrier called a "freeze wall" around the perimeter of the extraction zone. The freeze wall is created by pumping refrigerated fluid through a series of wells drilled around the extraction zone. The freeze wall prevents groundwater from entering the extraction zone, and keeps hydrocarbons and other products generated by the in-situ retorting from leaving the project perimeter.

Shell's process is currently unproven at a commercial scale, but is regarded by the U.S. Department of Energy as a very promising technology. Confirmation of the technical feasibility of the concept, however, hinges on the resolution of two major technical issues: controlling groundwater during production and preventing subsurface environmental problems, including groundwater impacts.1

Both mining and processing of oil shale involve a variety of environmental impacts, such as global warming and greenhouse gas emissions, disturbance of mined land; impacts on wildlife and air and water quality. The development of a commercial oil shale industry in the U.S. would also have significant social and economic impacts on local communities. Of special concern in the relatively arid western United States is the large amount of water required for oil shale processing; currently, oil shale extraction and processing require several barrels of water for each barrel of oil produced, though some of the water can be recycled.

1 RAND Corporation Oil Shale Development in the United States Prospects and Policy Issues. J. T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson, and G. Cecchine, MG-414-NETL, 2005.

For More Information

Additional information on oil shale is available through the Web. Visit the Links page to access sites with more information.


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Old News ;-)

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

Oct 15, 2017 | peakoilbarrel.com

FreddyW

says: 10/14/2017 at 10:01 am
A bit old so you may have seen it already. But if you haven´t then I highly recommend you to read the global oil supply report from HSBC:

YouTube clip:
https://www.youtube.com/watch?v=7KfVJBNX2U4

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

It contains a lot of interesting information. For example on page 15 we can see that oil field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has fallen of a cliff is not an exaggeration.

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

Notable quotes:
"... I already picked the peak, 2015. So I was slightly off, but not by all that much as you can clearly see by the chart. I think we are on the peak plateau right now. ..."
Oct 15, 2017 | peakoilbarrel.com

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

I already picked the peak, 2015. So I was slightly off, but not by all that much as you can clearly see by the chart. I think we are on the peak plateau right now.

The actual 12-month peak could be anywhere from 2017 to 2019 but no later than that. Well, in my humble opinion anyway.

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

The question was about US LTO, you have picked the World C+C peak, but as far as I remember you have not said anything recently about US LTO except that it will be before 2025.

So far the 12 month centered average for US LTO peaked in June 2015.

If US LTO output continues at the August output level (4750 kb/d) for 5 months, then a new 12 month centered average peak will be reached by Aug 2017 (average output from Feb 2017 to Jan 2018). US LTO output has risen about 600 kb/d over the past 12 months so an assumption of no further US LTO output increases over the next 5 months is a conservative estimate in my view.

[Oct 15, 2017] US Baker Hughes Rig Count

Oct 15, 2017 | peakoilbarrel.com

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

US Baker Hughes Rig Count (Oct 13)

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

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

Notable quotes:
"... A bit old so you may have seen it already. But if you haven´t then I highly recommend you to read the global oil supply report from HSBC: YouTube clip: https://www.youtube.com/watch?v=7KfVJBNX2U4 The report: https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view contains a lot of interesting information. For example on page 15 we can see that oil field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has fallen of a cliff is not an exaggeration. ..."
Oct 15, 2017 | peakoilbarrel.com

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

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

Energy News says: 10/14/2017 at 1:55 pm
Iraq's oil production has increased by 1.4 million b/day since oil prices last averaged $100 in July 2014. More than any other country
Chart on Twitter: https://pbs.twimg.com/media/DMHrqLZXkAAFiro.jpg
FreddyW says: 10/14/2017 at 10:01 am
A bit old so you may have seen it already. But if you haven´t then I highly recommend you to read the global oil supply report from HSBC:

YouTube clip:
https://www.youtube.com/watch?v=7KfVJBNX2U4

The report: https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view contains a lot of interesting information. For example on page 15 we can see that oil field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has fallen of a cliff is not an exaggeration.

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

Oct 14, 2017 | peakoilbarrel.com

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

Verwimp,

Great to see you posting an update. I can honestly tell you that the "WEIRD" rise in production per well in the Bakken may not be as high as the data shows. Unfortunately, I can't publicly state the reason I know this. If you contact me via my email address: SRSroccoReport@gmail.com , I can provide a few more clues.

However, the SHITE is going to hit the fan in the U.S. Shale Oil Industry once this news gets out which will likely be made public shortly.

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

Oct 14, 2017 | peakoilbarrel.com

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

2017-10-11 BSEEgov: From operator reports, it is estimated that approximately 32.68 percent of the current oil production in the Gulf of Mexico remains shut-in, which equates to 571,854 barrels of oil per day. It is also estimated that approximately 20.51 percent of the natural gas production, or 660.55 million cubic feet per day in the Gulf of Mexico is shut-in.
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-tropical-storm-nate-activity-4
Estimate of "Lost" Gulf of Mexico crude production due to Hurricane Nate is 7.82 million barrels of oil.

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

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

Oct 11, 2017 | peakoilbarrel.com

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

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

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

(Possible paywall, I can't quite figure out how it works on Energy Voice)

"This is particularly evident when we look at investment. While investments are expected to pick up slightly this year and in 2018, it is clear that this is not anywhere close to past levels and it is more evident in short-cycle, rather than long-cycle projects, which are the industry's baseload.

"The issue of a potential investment shortfall was a recurring theme at last week's Russia Energy Week conference, with President Vladimir Putin, as well as many oil and energy ministers making reference to the critical investment challenge.

"As we have all learned from previous price cycles, such pronounced and long-term declines in investments are a serious threat to future supply. But given our projected future demand for oil, with our upcoming World Oil Outlook 2017 expecting demand to reach over 111 million barrels a day by 2040, an increase of almost 16 million barrels a day, the world simply cannot afford a supply crunch."

It's noticeable that OPEC, IEA and drillers/service companies, even the Aramco CEO are raising the lack of investment more and more, but they all stay away from discussing the fall in discoveries and lack of attractive prospective projects. Part of it is real concern, though it's noticeable they don't offer much in the way of solutions, and definitely none that might impact their bottom lines in the short term, but part is pre-emptive arse-coverage.

A lot of factors seem to be lining up for an economic bust next year, but then they have looked like that for a few years (maybe the low oil price has contributed to staving off the problem), if it happens a supply crunch might go unnoticed for some time, and only come appear as the real problem it will be when there is some sort of recovery expected.

[Oct 07, 2017] The EIA is making these projections because knuckleheads in the C suite at US shale companies went hog wild at the first sign of oil price improvement and made thesegrowth projections for their individual companies, and the EIA just totaled them up

Notable quotes:
"... This year's rise is likely to be closer to about 500,000 barrels, far off an initial forecast by the U.S. Energy Information Administration, according to Hamm, the chairman of Continental Resources Inc. and a pioneer in the shale industry. ..."
"... The EIA projection is "just flat wrong," failing to take into account a new discipline among U.S. drillers, Hamm said in an interview Thursday on Bloomberg TV. "We have capability of producing a whole lot, but you have to get a return on investment," he said, adding, "that's where people have been this last quarter and this year." ..."
"... . "When we're lagging the Brent world price by $6 a barrel, that's not putting America first, that's putting America last. And that's the result of this exaggerated amount that EIA has out there." ..."
"... Once it's clear the EIA is off base, prices could rise to $60 a barrel from around $50 now, Hamm said. ..."
Oct 07, 2017 | peakoilbarrel.com

Bob Frisky

says: 09/22/2017 at 6:06 pm
Shale oil entrepreneur Harold Hamm is back doing interviews on the business networks again. Now he is speaking out against how the oil prices are low due to the EIA.

Shale Billionaire Hamm Slams 'Exaggerated' U.S. Oil Projections

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

Billionaire oilman Harold Hamm says the government was way too optimistic with its prediction of more than 1 million new barrels a day in U.S. production, and the snafu is "distorting" global crude prices.

This year's rise is likely to be closer to about 500,000 barrels, far off an initial forecast by the U.S. Energy Information Administration, according to Hamm, the chairman of Continental Resources Inc. and a pioneer in the shale industry.

The EIA projection is "just flat wrong," failing to take into account a new discipline among U.S. drillers, Hamm said in an interview Thursday on Bloomberg TV. "We have capability of producing a whole lot, but you have to get a return on investment," he said, adding, "that's where people have been this last quarter and this year."

The government scenario has contributed to worries about an oversupply that puts U.S. oil at a steep discount to international crude, according to Hamm. "It's distorting," he said . "When we're lagging the Brent world price by $6 a barrel, that's not putting America first, that's putting America last. And that's the result of this exaggerated amount that EIA has out there."

Once it's clear the EIA is off base, prices could rise to $60 a barrel from around $50 now, Hamm said.

shallow sand says: 09/22/2017 at 11:38 pm
The EIA is making these projections because knuckleheads in the C suite at US shale companies went hog wild at the first sign of oil price improvement and made these growth projections for their individual companies, and the EIA just totaled them up.

Every Shale CEO bashes OPEC. OPEC tried to give shale a break by cutting production, and shale absolutely blew it, just like shale absolutely blew it in late 2014 by not pretty much shutting down. Instead, shale has lied about profitability for 3 years, and the world E & P industry has paid the price.

Too bad Oilpro shut down. Lots of non-US E & P Industry folks posted there. They absolutely could not stand US shale and the US shale CEO smack talk. Hundreds of thousands out of work, because of shale smack talk and Wall Street encouragement of same, which crashed oil prices below $30.

Shale better come through. No one seems to be taking serious the possibility of a supply shock if it cannot.

When shale clearly peaks, what is to keep OPEC and Russia from suddenly making a big cut, driving prices past $200 and crashing Western economies? Why wouldn't they afterthe hubris of US shale CEO's, the Wall Street guys who pull their strings, and the US business media who report everything they say as gospel?

George Kaplan says: 09/23/2017 at 2:08 am
I'd guess a lot of the non-US E&P people complaining about LTO would by from offshore, and I think that side has been just as much to blame for boom and bust mentality with rose tinted specs. (see below the UK investment which went nuts when oil went above $100 and now they have nothing much left). I'd question with the jobs are going to come back offshore even with a big price rise. As I keep pointing out, there have to be discoveries before development, and there have to be lease sales before that. We're not seeing either, and though exploration is down compared with 2011 to 2014, there's still a significant amount going on, but wildcat, frontier success rates are what have fallen the most (even with the best seismic methods and computer models we have ever had).

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

Oct 07, 2017 | peakoilbarrel.com

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

Shallow, I too miss the hell out of Oilpro. That community could debate the unconventional shale phenomena without bias and with a clear understanding of how it has completely changed the world oil order.

American's, on the other hand, simply enjoy cheap gasoline; they don't care how they get it, what it costs, who ultimately pays for it or that it will not last forever. The American public, and the politicians that govern it, have been lied to and completely deceived about shale oil and shale gas abundance. It is a matter of American nationalistic pride to believe what one reads on the internet and to otherwise be stupid about our hydrocarbon future.

I suggested to you several years ago that OPEC and the rest of the world's producing oil countries were not dumb; they read shale oil K's and Q's and have the same access to SEC filings we do. They know the shale oil phenomena is failing financially and that in the process America is drilling the snot out of its last remaining, bottom of the barrel oil resources. OPEC's production cuts in late 2016, in my opinion, were an effort to give the US shale oil industry just enough rope to eventually hang itself. It has done just that; in the past 24 months it has bankrupted out on another $50B, borrowed yet another $50B and is now back over $300B of upstream long term debt with no current ability to pay that back. Hope (for higher oil prices) is not a plan. The Bakken and the Eagle Ford have peaked and now well productivity in the Permian is starting to fade. In a few more years the rest of the world will have the US right back it its teet and will dictate what the price of oil well be. I think in the next 12-18 months we are going to see big reserve impairments in the US, again, and a pretty big shale oil company will end up the toilet, bankrupt. They'll be a bunch of fist pumping going around the world when that happens.

Harold Hamm is whiner; he has always blamed OPEC for lower oil prices, demanded that OPEC cut more production, he needs more pipelines, fewer regulations (where are those, by the way?), needs to be able to export his oil, warned OTHER shale oil companies in the Permian not to overproduce and drive the price of HIS oil down, the sun is always in his eyes now its the EIA's fault. He, like the rest of America's shale oil industry, is desperate for attention and desperate for help. Once again, Shallow, you are spot on.

shallow sand says: 09/23/2017 at 8:31 am
Mike. It might be worth mentioning here the recent judgment a small OK producer won against Devon Energy.

Apparently one of Devon's high volume fracs destroyed one of the the conventional producers' wells.

When I read about these frac hits, I really worry that US is not properly managing these shale oil resources.

From some reading it appears frac hits are a big deal in PB, and that just a few years in, PB shale could wind up unperformimg due to reservoir damage from these massive fracs.

What do you (or others) think?

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

So if we assume that since 2014 at least 8 million barrels per day were lost due to aging fields. Who provided additional supply to keep it steady. Something is fishy here.
Notable quotes:
"... If you're not bringing new production online and the global decline rate is call it 5% then each year from now until 2020 we should see a loss of about four and a half million barrels per day off of supply ..."
"... And in 3 years that's 13 million barrels per day supply reduction and there is no way countries can feed themselves with that quick level of scarcity. ..."
"... Venezuela dropping to 0 while the Lybian civil war flames up again – and there isn't 3 MB/D spare capacity left. Nobody besides SA perhaps does frenetic infill drilling for capacity he don't need and use. Or develops fields and put them on idle. ..."
"... Venezuela is the best example of low oil prices making high one – the production will halt sooner or later. ..."
Oct 07, 2017 | peakoilbarrel.com

Watcher

says: 09/28/2017 at 1:46 am
Way too glib a presumption of supply shortage in the 2020 time frame.

If you're not bringing new production online and the global decline rate is call it 5% then each year from now until 2020 we should see a loss of about four and a half million barrels per day off of supply

And in 3 years that's 13 million barrels per day supply reduction and there is no way countries can feed themselves with that quick level of scarcity.

When one says "supply shortage" the consequence of significance is not higher prices; the consequence is unfilled orders.

Energy News says: 09/27/2017 at 12:48 pm
RIO DE JANEIRO, Sept 27 (Reuters) – Only one block in Brazil's prized offshore Santos basin received a bid in the country's 14th oil round on Wednesday, a sign low global oil prices may have reduced the allure of potential new crude and gas investments in Latin America's largest economy.

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

George Kaplan says: 09/28/2017 at 12:47 am
A lot more interest in the other basins though, especially Campos. It can't be just oil price that is against Santos, maybe it's similar to the mirror province in Angola, Kwamza, and it's turning out to be a bust.
Lightsout says: 09/30/2017 at 4:13 am
Hi George

Two more dry holes in the Barents sea.

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

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

George Kaplan says: 09/30/2017 at 5:04 am
I think this year has killed off a few of the promising frontier basins now – Kwanza in Angola – bust, deep water offshore Canada – mostly bust, Barents – mostly bust, Santos – looks bust, ultra deep US GoM – mostly played out or uncommercial, offshore Colombia – looks bust for oil, couple of West Africa areas – dry holes, offshore Ireland – half way to bust, UK North Sea – very poor lease sale, also one other lease sale (maybe Oman?) I think didn't do very well from memory.
George Kaplan says: 09/27/2017 at 6:34 am
MARKET SHOULD PREPARE MORE FOR OIL SQUEEZE THAN OPEC SUPPLY GAIN, CITIGROUP SAYS

Those in the oil market fearing a flood of OPEC supply next year will probably be better off preparing for a shortage, according to Citigroup Inc.

Five countries in the group -- Libya, Nigeria, Venezuela, Iran and Iraq -- may already be pumping at their maximum capacity this year, Ed Morse, the bank's global head of commodities research, said in an interview. Rather than a surge in output, there's a risk of a market squeeze emerging as early as 2018, driven by those nations because of weaker investment in exploration and development, he said.

"Fear in the market has been that OPEC production will rise dramatically," said Morse. However, "there could be a supply gap emerging, which could point to a tighter market," he said in Singapore on the sidelines of the S&P Global Platts APPEC Conference.

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

Eulenspiegel says: 09/26/2017 at 10:16 am
Geology has to do a lot with oil prices – the run up in price the last 40 years is mostly due to geology.

Why? The original oil was the kind of very conventional land based oil. Once discovered, the most costly thing was the infrastructure to transport it away.

This came to a limit in the 70s. After this, more and more expensive projects where necessary.

Off shore oil, deep sea oil, small spots on land, arctic oil and last fracking oil. And old fields with injections, infill, pressure control.

All things with big investments – much more than "we build an oil terminal for supertankers and drill a few holes".

And so the market gets more and more unstable – these big investments have to pay out, even when done by a state. And you have bigger and bigger planning time lags, so the classical pork cycle can get investors in the false moment.

US fracking oil adds to the chaos – it's expensive, but fast rampup – but not able to replace deep sea oil due to it's pure size.

Old cheap fields are in decline, or not longer cheap as the chinese giants on secondary or tertiary recovery enhancements. So more and more expensive technology with long planing horizonts comes to a short paced market, together with the political chaos describes by you.

And geology gets more complicated, so the long project times you describe will get longer.

I, without a mathematically model, expect a chaotic market in the future until oil gets (hopeful) phased out and put in the steam engine age.

Low oil prices make high oil prices, and high ones low. The demand is very inelastic on the short term, trucks have to drive and people have to drive to work (and the aunt wants the chrismas visit). Only mid way demand gets flexible, a japanese car instead a SUV next or a house nearer at the job. Or a company reduces work travelling.

Many 3rd world countries have regulated gas prices – so a price spike don't reduce demand here on the short term. That makes things even more scary when something happens on the political scale.

Venezuela dropping to 0 while the Lybian civil war flames up again – and there isn't 3 MB/D spare capacity left. Nobody besides SA perhaps does frenetic infill drilling for capacity he don't need and use. Or develops fields and put them on idle.

Venezuela is the best example of low oil prices making high one – the production will halt sooner or later.

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

Higher than $50 per barrel WTI essential for a meaningful return on capital. May be even higher then $65 per barrel. right now shale oil production is possible only by simultaneous generation of junk bonds.
Notable quotes:
"... Higher than $50 per barrel WTI essential for a meaningful return on capital ..."
"... if WTI remains stuck at about $50 per barrel, U.S. shale drillers might be forced to reign in their ambitions, because they won't generate enough cash to reinvest in growth. Second, shale drillers might actually worsen their financial position if they pursue growth. Spending more to produce more -- while that could lead to more oil sales -- might not necessarily be the wisest strategy. ..."
"... For similar reasons, Jim Chanos, short-seller and founder of Kynikos Associates, has made some headlines shorting Continental Resources. He argues that shale companies simply have to spend too much to keep production going. Shale drillers "are creatures of the capital markets," he told Bloomberg . "Because the wells deplete so quickly, they constantly need to raise money to replace the assets. And this is the crux of the story." ..."
"... Another significant observation is that the shaky financial position for some shale drillers also suggests that the downside risk to oil prices might not be as serious as once thought. ..."
"... "The market may well discover it has been asleep at the wheel and far too relaxed about shale keeping a ceiling on prices forever," Ben Luckock, a senior executive at oil trader Trafigura, told an industry conference in Singapore last week. ..."
"... All of the highly-touted cost reductions and efficiency gains have already been "realized." Moody's lowered its outlook for these large oil companies in 2018 from "positive" to simply "stable ..."
Oct 02, 2017 | oilprice.com
The extraordinary cost reductions achieved by North American oil and gas companies have likely reached their limit, and any boost in profitability for much of the U.S. shale and Canadian oil sands industries will have to come from higher oil prices, according to a new report from Moody's Investors Service.

Moody's studied 37 oil and gas companies in Canada and the U.S., concluding that although the oil industry has dramatically slashed its cost of production in the past three years and is currently in the midst of posting much better financials this year, there is little room left for more progress.

"After substantially improving their cost structures through 2015 and 2016, North American exploration and production (E&P) companies will demonstrate meaningful capital efficiency to the extent the West Texas Intermediate (WTI) oil price is above $50 per barrel and the Henry Hub natural gas price is at least $3.00 per MMBtu," Moody's said . In other words, WTI will need to rise further if the industry is to improve its financial position.

The report is another piece of evidence that suggests the U.S. shale industry is perhaps struggling a bit more than is commonly thought. U.S. shale has been portrayed as nimble, lean and quick to respond to oil price changes. And while that is largely true, strong profits remain elusive, despite the huge uptick in production.

Shale drillers have substantially lowered their breakeven prices, but further reductions will be difficult to achieve, Moody's Vice President Sreedhar Kona said in a statement.

" Higher than $50 per barrel WTI essential for a meaningful return on capital ," Moody's said.

The findings are important for a few reasons. First, it suggests that if WTI remains stuck at about $50 per barrel, U.S. shale drillers might be forced to reign in their ambitions, because they won't generate enough cash to reinvest in growth. Second, shale drillers might actually worsen their financial position if they pursue growth. Spending more to produce more -- while that could lead to more oil sales -- might not necessarily be the wisest strategy.

For similar reasons, Jim Chanos, short-seller and founder of Kynikos Associates, has made some headlines shorting Continental Resources. He argues that shale companies simply have to spend too much to keep production going. Shale drillers "are creatures of the capital markets," he told Bloomberg . "Because the wells deplete so quickly, they constantly need to raise money to replace the assets. And this is the crux of the story."

Another significant observation is that the shaky financial position for some shale drillers also suggests that the downside risk to oil prices might not be as serious as once thought. The oil market has tried to assess how quickly shale production would come roaring back. Reports that shale companies were posting juicy profits at very low oil prices has likely factored into heady projections for shale output. The EIA has repeatedly projected that shale output would average 10 million barrels per day next year (although they have revised that down recently to just 9.8 mb/d).

But that might be overly optimistic if a long list of shale companies are not posting "meaningful" returns on capital.

"The market may well discover it has been asleep at the wheel and far too relaxed about shale keeping a ceiling on prices forever," Ben Luckock, a senior executive at oil trader Trafigura, told an industry conference in Singapore last week. Bloomberg surveyed a bunch of oil traders and energy executives at the conference, and the general sense was that oil would trade between $50 and $60 per barrel, up from an informal consensus of between $40 and $60 last year. While there are many reasons for the newfound bullishness, more modest expectations about shale growth is certainly one of them.

In a separate report focusing on larger integrated oil companies, Moody's came to a similar conclusion -- that the substantial improvement in the financial position of the oil industry over the past year is poised to slow down. All of the highly-touted cost reductions and efficiency gains have already been "realized." Moody's lowered its outlook for these large oil companies in 2018 from "positive" to simply "stable ."

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

How comes? Annual world demand raises around 1.5 million BPD per year. So since 2014 it rose probably 4 million BPD. And there is no sizable new discoveries. Iran and Libya cards were already played and total from them is less then 4 million barrel per day. US output is stagnant. Canadian is down. Where all this additional oil is coming from ?
Iran is currently exporting about 3 million BPD of crude and condensate vs. less than 1 million BPD when the sanctions were in place.
Libya and Nigeria have increased production by about 0.5 BPD undercutting the 1.2 million BPD OPEC production cut.
Turkey already threatened to close their border with Iraqi Kurdistan, halting the 0.6 BPD of oil that the Kurds are exporting through Turkey.
Venezuela problems might take another million BPD off the global market.
KSA has recently been forced to borrow $12.5 billion after borrowing $17.5 billion last year.
Notable quotes:
"... The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day (BPD) to 1.42 million BPD. ..."
"... China's oil demand rose by 690,000 BPD in July, marking a 6 percent year-over-year (YOY) increase. China's total oil demand reached 11.67 million BPD in July. Year-to-date data indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded during the same period in 2016. ..."
Oct 04, 2017 | oilprice.com
Monthly Oil Market Report which covers the global oil supply and demand picture through July.

OPEC crude oil production decreased by 79,000 BPD in August to average 32.8 million BPD. This marks the first OPEC production decline since April and was primarily driven by sizable outages in Libya.

The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day (BPD) to 1.42 million BPD. The group reports strong growth from the OECD Americas, Europe, and China. Global oil demand for 2018 is expected to grow by 1.35 million BPD, an upward revision of 70,000 BPD from the previous report. Growth next year is expected to be driven by OECD Europe and China.

China's oil demand rose by 690,000 BPD in July, marking a 6 percent year-over-year (YOY) increase. China's total oil demand reached 11.67 million BPD in July. Year-to-date data indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded during the same period in 2016.

China's gasoline demand was higher by around 0.10 million BPD YOY, driven by robust sports utility vehicle (SUV) sales, which were around 17 percent higher than one year ago. China's overall vehicle sales in July rose by 4 percent YOY, with total sales reaching 1.7 million units.

The numbers from China are interesting given the constant refrain of weakening Chinese demand. This seems to be wishful thinking based on China's investments in clean technology.

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

Sep 21, 2017 | peakoilbarrel.com

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

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

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

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

[Jul 23, 2017] They are all losing money. Proppant isn"t free. If you use more of it, it costs more. If you add a different kind it costs more. And the executive bonuses are production based, not profit based. If they can get other people to fund via loans those bonuses then of course they will do it.

Jul 23, 2017 | peakoilbarrel.com

Watcher

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

Dood, they are all losing money.

Proppant isn"t free. If you use more of it, it costs more. If you add a different kind it costs more.

And the executive bonuses are production based, not profit based. If they can get other people to fund via loans those bonuses then of course they will do it.

You want evidence the proppant pays for itself in production? You can find it. It appears in the earnings per share number. If it doesn't then there is no evidence.

This is no different than drilling holes to recover pores of oil amounting to 20 barrels, total. At $45/b you get $900 from that. If someone else pays the $7 million for the hole, why not drill?

Ves

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

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

"Investors who'd plowed $2 billion four years ago into a private equity fund that had also borrowed $1.3 billion to lever up may receive "at most, pennies for every dollar they invested," people familiar with the matter told the Wall Street Journal."

It is the same WSJ that last 4 years were writing about "resilience of shale" like parrots, every day. Of course it is resilient with Gran Ma and Gran Pa money if you look that it was mostly pension funds that are invested.

Boomer II

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

From the WSJ article.

"Only seven private-equity funds larger than $1 billion have ever lost money for investors, according to investment firm Cambridge Associates LLC. Among those of any size to end in the red, losses greater than 25% or so are almost unheard of, though there are several energy-focused funds in danger of doing so, according to public pension records."

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

So now those evil shale people are screwing Grand Pa and Grand Ma out of their hard-earned savings?

After all, we have it straight from WolfStreet. Wolf Richter blasts the unscrupulous shale industry when he writes:

" The renewed hype about shale oil – which is curiously similar to the prior hype about shale oil that ended in the oil bust – and the new drilling boom it has engendered, with tens of billions of dollars being once again thrown at it by institutional investors, has skillfully covered up the other reality: The damage from the oil bust is far from over, losses continue to percolate through portfolios and retirement savings, and in many cases – as with pensions funds – the ultimate losers, whose money this is, are blissfully unaware of it."

There's a problem, however, with using EnerVest to bash the shale industry. And the problem is very easy to spot for anyone who has even the most rudimentary knowledge of the oil and gas industry (which of course leaves Richter out): EnerVest's portfolio has very few shale assets.

• EnerVest is the largest conventional oil and natural gas operator in Ohio

• EnerVest is the largest producer in the Austin Chalk, another conventional field.

• EnerVest is the fifth largest producer in the Barnett Shale, which is the only shale holding listed in the company's list of core areas.

• EnerVest has spent $1.5 billion purchasing assets in the Anadarko Basin since 2013, again in conventional fields.

• EnerVest is a top 20 producer in the San Juan Basin, again a conventional field.

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

So Richter uses the implosion of EnerVest, a company that is predominately a conventonal oil and gas producer, to bash shale? That really makes a lot of sense. 😊

Ves says: 07/17/2017 at 12:34 pm
Glenn,
shale/no shale, they lost every single penny. and btw wsj lied to you every single day for the last 4 years about milk & honey in oil patch. how do you feel about it?
Glenn E Stehle says: 07/18/2017 at 5:05 pm
Ves,

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

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

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

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

Watcher says: 07/21/2017 at 11:00 am
Freddy, I doubt you can get this data, but a gassy geology flows liquid that isn't oil. The relentless march upward of API speaks of NGLs rather than oil. If people just ignore API degrees and flow liquid that is API 47 or even 51, but still call it oil, the numbers will all be corrupted and no one will know.

I gotta go research NoDak's taxation regulation on liquids that are not crude.

shallow sand says: 07/17/2017 at 11:50 am
coffee: Thanks for the heads up on Rockman BK discussion on PeakOil.com. I had quit looking at that site because it seemed to have become very radical. Rockman is a good poster, however, lots of knowledge, and a down to earth guy too.

What he describes there is why this is probably going to play out like 1986-1999. Takes years for US onshore upstream to be placed in the category of "not investible". So $40s or lower, on average, until mid-2020's, unless there is a prolonged major supply disruption, which necessarily means a major Middle Eastern war lasting for years.

The possibility of $90 WTI has to be erased from memory, just like $30 WTI had to be erased from memory from 1986-1998.

Watcher says: 07/17/2017 at 1:22 pm
Over the course of the history of mankind, more assets have changed hands at a price completely absent any effect of supply and demand than those that might have cared about such things. Vastly more. Let's count a few.

1) Every single inheritance. In the history of mankind, every single inheritance.

2) All gifts.

3) All conquests.

4) All manifestations of economic predation. Predatory pricing established those levels.

5) All monopolies

6) All thefts

7) All taxation

8) All govt decreed excise or tarrif

Want more proof? How about the ultimate:

The purchase of about 2 Trillion dollars of mortgage backed securities by the Federal Reserve from 2009 to 2015. The pricing of those securities was 0 at mark to market, so mark to market was disallowed, but even with that, the Fed specified the price to be whatever they wished, and the sellers didn't have any reason to complain. The price paid was far above supply and demand (aka 0). $2 Trillion. That probably exceeds amounts for assets from all history that someone imagined was taking place at a free market price. Not to mention the ongoing buys from the ECB in progress today.

So the price of oil will be what the lowest priced large sellers want it to be, and they have no reason to imagine that their victory should be measured in a whimsically created substance.

There is nothing anyone can do about it.

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

The upside potential might be stronger than appears at present for many reasons.

Although the Enervest situation has been conflated with the shale industry, the exact opposite reality might prove to your (smaller operators) collective benefit as you ride out this current storm.

Time was, ss, that some camel upwind in the desert somewhere would fart and global oil markets would reverberate for days.

Now, in hydrocarbon producing countries from Nigeria to the Philippines, including Iraq, Libya, Yemen, Syria, KSA and others there is conflict raging from low level to all out warfare. Heck, there were reports the other day of a thwarted attack on a Saudi offshore facility.

Qatar is virtually quarantined.
Russia is battling international sanctions.

And $46 WTI???
You kidding me???

We ain't in Denmark (most of us), but something's sure is rotten,

clueless says: 07/17/2017 at 3:14 pm
SS – It has been my experience that concerning financial matters, nothing "plays out" like the past. Consider the period 1986-1999: No one was concerned that the world was near peak oil. OPEC spare capacity was at least 4 times what it is today, [ask Ron], at a time when final demand was much less. Iraq invaded Kuwait, and then we went to war to get them out – remember the oil well fires. Russia collapsed. The "BRIC" countries [Brazil, Russia, India and China] were inconsequential. The Dow Jones was down 22.6% in ONE DAY in 1987. The International Monetary system almost collapsed in 1997. The world was transitioning from a period of high inflation to much lower inflation. Japan was booming [until 1990].

You can probably add a dozen significant happenings to the list without thinking too hard. The point is, so many variables have changed that something as significant as oil is going to "play out" based upon today's factors, not "like" 1986-1999. Some people are still trying to analog to the 1930's in order to predict the next great depression in the stock market – do not listen to them.

shallow sand says: 07/17/2017 at 4:37 pm
I know things never play out exactly as in the past.

However, one has to prepare for the worst, and prices will be low for awhile IMO.

The Rockman BK discussion helped put it in focus for me. The wells will be drilled, and only when it is clear all large US shale oil basins have hit their limit, will prices begin to rise. That might not take 12 years, but I think at least 5 is likely.

The only intervenor would be a supply shock from the Middle East.

Another poster on another site also has given me some clarity. He states there has not been enough suffering experienced yet in the US oil patch by those responsible for the production boom.

We just went through two bad years of prices in 2015-2016, and at the first sign of light, the industry was able to raise a ton of cash and go back with guns a blazing. There were no consequences to the powers that be from the 2015-2016 low prices. Heck, the strip was higher this time last year, yet we are still adding rigs.

It will take a minimum of five years, until it is universally believed that prices will be low forever, that supply will be abundant forever, and that the sector is a bad investment.

Once that happens, look out, price could rocket. But it will be awhile IMO.

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

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

as you say – history doesn't repeat

rgds
simon

Jeff says: 07/17/2017 at 3:17 pm
Some difference between now and 86-99: i) decline rates are higher, ii) Spare capacity is _much_ lower (oil stocks are high which apparently is what traders observe) – back in 86 KSA could flood the market, iii) not much new big projects in the pipe after 2019 and North Sea is declining this time while it was increasing back then.

Rebalancing should go faster this time if (!) demand continues to increase.

Guy M says: 07/17/2017 at 5:11 pm
EIA numbers are basically worthless, as far as the Permian goes. To analyze it like they are trying to do, you would have to separate conventional production from horizontal production. Take more gathering tools than they are using to accomplish that. Until 2015, they were still drilling 800 a month or so vertical wells, which dropped down to 100 to 150 a month since then. Looking at district 8A, that production is dropping like a rock. Combining the two, production appears to be pretty flat for Texas since the first of the year.

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

Notable quotes:
"... Intensive drilling is causing a problem called 'frac-hits', which are cross-well interferences. These happen when fracking pressure is accidently transferred to adjacent wells that have less pressure integrity. As a result a failure of pressure control occurs, which reduces production flow. ..."
"... as the following chart from Goldman shows, the number of horizontal rigs funded by public junk bond issuance has not changed in the past 3 months. Is the funding market about to cool dramatically on US shale, and if so, just how high will oil surge? ..."
"... They want control of Russian oil and resources, so it may be cheap for a long, long time. This means the banksters will fund shale production 'til hell freezes over. They want another Russian revolution. ..."
"... Outside of Shale is DeepWater, Artic and Oil Sands. None of these are much better, and I think it will be harder this time for Oil prices to increase to make these non-convensional oil projects profitable. ..."
Jul 23, 2017 | www.zerohedge.com

From Horseman Capital Management's July Monthly Newsleter

...Having grown up, and spent my entire investing career in periods of bubble inflation and deflation , I am constantly minded to look for where the market is deceiving itself, and then positioning the fund to benefit from the process of realisation. Many years ago, I could see that the commodity bubble was ending, and Chinese growth was peaking. This meant that commodities would be weaker and inflation lower, making a short commodities, long bond position very effective. It was a great strategy, but its effectiveness ended early last year.

The good news is that new market delusion is now apparent to me. When I moved long emerging markets, and short developed markets, the one commodity I could not give detailed bullish reasons for was oil. Unlike most other commodities, the oil industry, in the form of US shale drillers has continued to receive investment flows throughout the entire downturn

I had shorted shale producers and the related MLP stocks before, and I knew there was something wrong with the industry, but I failed to find the trigger for the US shale industry to fail. And like most other investors I was continually swayed by the statements from the US shale drillers that they have managed to cut breakeven prices even further. However, I have taken a closer look at the data from EIA and from the company presentations. The rising decline rates of major US shale basins, and the increasing incidents of frac hits (also a cause of rising decline rates) have convinced me that US shale producers are not only losing competitiveness against other oil drillers, but they will find it hard to make money . If US rates continue to stay low, then it is possible that the high yield markets may continue to supply these drillers with capital, but I think that this is unlikely. More likely is that at some point debt investors start to worry that they will not get their capital back and cut lending to the industry. Even a small reduction in capital, would likely lead to a steep fall in US oil production. If new drilling stopped today, daily US oil production would fall by 350 thousand barrels a day over the

next month (Source: EIA).

What I also find extraordinary, is that it seems to me shale drilling is a very unprofitable industry, and becoming more so. And yet, many businesses in the US have expended large amounts of capital on the basis that US oil will always be cheap and plentiful. I am thinking of pipelines, refineries, LNG exporters, chemical plants to name the most obvious. Even more amazing is that other oil sources have become more cost competitive but have been starved of resources. If US oil production declines, the rest of the world will struggle to increase output. An oil squeeze looks more likely to me. A broader commodity squeeze also looks likely to me.

In the latest letter's sector allocation, Clark also added the following section providing a more detailed explanation why he has boosted his shale short to 15.5%:

We are negative on the US shale sector, during the month we increased the short exposure to oil exploration and MLPs to about 15.5%. Conventional oil wells typically produce in 3 stages: the start-up rising production stage lasts 2 to 3 years, it is followed by a plateau stage which lasts another 2-3 years and a long declining stage, during which production declines at rates of 1% to 10% per year. These wells generally produce over 15 to 30 years ( Source: Planete energies).

In contrast, production from unconventional / shale wells peaks within a few months after it starts and decreases by about 75% after one year and by about 85% after two years (Source Permian basin, Goldman Sachs). This means that, in order to keep producing, shale producers need to constantly drill new wells.

Shale drilling is characterised by drilling horizontally into the layers of rock where hydrocarbons lie. Then hydraulic fracturing which consists of pumping a mixture of water, proppant (sand) and chemicals into the rock at high pressure, allows hydrocarbons to be extracted out to the head of the well.

Since 2016, as oil prices rallied, the number of rigs in the Permian basin, which is currently the most sought after drilling area in the US, rose from about 150 to almost 400 . Furthermore, operations have moved into a high intensity phase as wells are drilled closer together, average lateral lengths increased over 80% from 2,687 ft in early 2012 to 4,875 ft in 2016 and the average volume of proppant per lateral foot more has than doubled (Source: Stratas Advisors).

Intensive drilling is causing a problem called 'frac-hits', which are cross-well interferences. These happen when fracking pressure is accidently transferred to adjacent wells that have less pressure integrity. As a result a failure of pressure control occurs, which reduces production flow. In the worst cases, pressure losses can result in a total loss of production that never returns. According to a senior reservoir engineer at CNOOC Nexen, frac-hits have now become a top concern, they can affect several wells on a pad along with those on nearby pads (Sources: Journal of Petroleum Technology).

A former engineer for Southwestern Energy said that frac-hits are very difficult to predict, the best way to respond is with trial and error and experimenting with well spacing and frac sizes to find the optimal combination.

In May Range Resources reported that it was forced to shut wells in order to minimise the impact of frac-hits. This month Abbraxas Petroleum said it will be shutting in several high-volume wells for about a month (Source: Upstream).

In the Permian basin new well production per rig continued to decline in June, from 617 barrels per day down to 602 . In the meantime , legacy oil production, which is a function of the number of wells, depletion rates and production outages such as frac hits, is continuing to rise . (Source: EIA)

In light of the above growing short bet on shale, this is how Clark is positioned:

The analysis leads me to be potentially bearish on bonds, bearish on US shale drillers, but bullish on commodities. Over the month, we have added to US shale shorts, while also selling our US housebuilder longs . We continue to build our US consumer shorts, where the combination of higher oil prices and higher interest rates should devastate an industry already dealing with oversupply and the entry of Amazon into ever more areas . The combination of long mining and short shale drillers has the nice effect of reducing volatility, but ultimately offering high returns. The combination of portfolio changes has taken us back to a net short of over 40%. I find market action is supporting my thesis, and the research and analysis is compelling. Your fund remains short developed markets, long emerging markets.

While we will have more to say on this, Clark may be on to something: as the following chart from Goldman shows, the number of horizontal rigs funded by public junk bond issuance has not changed in the past 3 months. Is the funding market about to cool dramatically on US shale, and if so, just how high will oil surge?

LetThemEatRand •Jul 22, 2017 5:44 PM

A short bet on shale is also a bet on no war that disrupts supply/increases demand. It is also a bet against any kind of crisis in the dollar. As it stands now, that seems pretty risky to me.

NoWayJose -> LetThemEatRand •Jul 22, 2017 6:12 PM

I'd rather be long oil services - the inevitable conclusion of the author is that fracked oil depletes faster, the quality drops, that they cannot get more financing and that production will fall? And you want to be 'short' when all this happens?

LetThemEatRand -> NoWayJose •Jul 22, 2017 6:31 PM

Agreed. A lot of people have already forgotten that oil dropped massively after the US decided (under zero) that it wanted to punish Russia because "Russia invaded Crimea."

I didn't fully believe that TPTB had so much control over the price of oil before it happened, but the timing could not have been coincidental. When they want oil to go back up, it will.

When that happens is anyone's guess for those of us not in the Big Club, but the idea that oil is in a new normal price range is not supported by history. Oil was double or almost triple its current price under similar economic conditions in the past.

daveO -> LetThemEatRand •Jul 22, 2017 10:10 PM

They want control of Russian oil and resources, so it may be cheap for a long, long time. This means the banksters will fund shale production 'til hell freezes over. They want another Russian revolution.

AGuy -> NoWayJose •Jul 23, 2017 2:43 AM

"I'd rather be long oil services"

Seems likely oil services will get hit hard when the shale bubble pops. Its likely they are owed money by shale drillers.

Outside of Shale is DeepWater, Artic and Oil Sands. None of these are much better, and I think it will be harder this time for Oil prices to increase to make these non-convensional oil projects profitable. Consumers and business are even deeper debt than they were in 2008-2009. With the Boomers entering retirement, Companies moving to automation and technology reducing the need for travel, its likely that Oil consumption will start to decline. Hire energy prices would accelerate the declines via demand destruction

Deep Snorkeler •Jul 22, 2017 6:00 PM

1. Fracked fields deplete fast.

2. Frackers need low interest financing for more fracking.

3. Increased fracking density depletes fields even faster.

4. Fracked wells produce ever poorer oil quality.

EROI is against all you frickn fracking f**kers. There is no economic theory that addresses resource depletion.

fattail -> Deep Snorkeler •Jul 23, 2017 8:08 AM

There is no economic theory that addresses resource depletion.

How about printing a fiat currency so that you can buy them all up? Backed by nothing..... Except.... 11 carrier groups and 18 submarines loaded with nuclear missles?

TeraByte •Jul 22, 2017 10:18 PM

This is not at all that black and white. Dirty and expensive shale extraction however had advantages and saved trillions dollars in war expense now required to keep the "cheap" ME oil flowing...

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

Jul 23, 2017 | peakoilbarrel.com

Mike

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

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

"I had shorted shale producers and the related MLP stocks before, and I knew there was something wrong with the industry, but I failed to find the trigger for the US shale industry to fail.

And like most other investors I was continually swayed by the statements from the US shale drillers that they have managed to cut breakeven prices even further. However, I have taken a closer look at the data from EIA and from the company presentations.

The rising decline rates of major US shale basins, and the increasing incidents of frac hits (also a cause of rising decline rates) have convinced me that US shale producers are not only losing competitiveness against other oil drillers, but they will find it hard to make money.

If US rates continue to stay low, then it is possible that the high yield markets may continue to supply these drillers with capital, but I think that this is unlikely.

More likely is that at some point debt investors start to worry that they will not get their capital back and cut lending to the industry. Even a small reduction in capital, would likely lead to a steep fall in US oil production. If new drilling stopped today, daily US oil production would fall by 350 thousand barrels a day over the next month. (Source: EIA)."

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

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

Professor Albert Bartlett, University of Colorado, USA

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

Notable quotes:
"... Not only will enhanced recovery affect the economics of present unconventional operations, it has the potential to greatly expand the application to numerous, older conventional sources as well as undeveloped – yet recognized – formations with hydrocarbons within them ..."
"... But the problem isn't so much whether oil is still in the ground, but how much it costs to get it out. ..."
"... New technologies that don't reduce costs to make oil profitable to drill aren't all that helpful in keeping the oil flowing. Right now we have LTO because the system accepts financial loss. That could change if alternatives promise a better financial return. ..."
"... The way I understand the term Maximum Reservoir Contact (MRC) is that it refers to multiple laterals being drilled from a single vertical wellbore. ..."
"... From what I have read MRC technology is a great fit for a number of fields in the gulf countries and may be practical in other places including USA. Of course one of the problems applying it here is that I think you need a unitized field, or at least a very large area to be implemented. ..."
"... At that time, I was amazed to learn of the multi lateral, extended reach drilling using ultra sophisticated whipstocks in the mid east, offshore, and – if memory serves – Sakhalin. Probably do need large reservoir to be viable. ..."
"... The article says this: "On the supply side, global oil production advanced by 0.5 percent to reach 92.2 million BPD." You know, factoring in both population growth and world economic growth, this isn't much. There might be a crunch coming. ..."
Jul 23, 2017 | peakoilbarrel.com

New technologies did postoned the day f reconing, but they can't increase the total amount of oil availble so the effects are temporary. Adn they are costly. right now low oil price is financial scam.

dclonghorn

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

I agree with George that getting stuff wrong is no reason to quit trying. To do so would be stupid. To look back at why projections were wrong is a much more interesting thing. To that end, I have been looking back at predictions from the 2005 to 2010 period, starting with Simmons and progressing to the oil drum and some others. I do not have the technical expertise that many of these people had, but looking back is a lot easier than looking forward.

In my opinion, there are two big reasons the projected decline hasn't come about yet. First, most of the work done was based upon inferred data. Because, the GCC countries don't release much, most of the folks making these projections took whatever info was available and ran with it. I don't blame them for this, as I believe they did what they could with what was out there, but I think they went too far in some instances, and confirmation bias is evident.

A part of Mr Simmon's efforts to deal with the lack of hard data was his review of many SPE papers dealing with various issues. I believe one of these papers is a key to understanding how KSA and others have exceeded projected production. Paper (SPE 88986) deals with well "Shaybah-220 A Maximum Reservoir Contact (MRC) Well and its implications for developing tight-facies reservoirs." https://www.onepetro.org/download/journal-paper/SPE-88986-PA?id=journal-paper%2FSPE-88986-PA

This paper by N.G. Saleri describes the efforts to develop the Shaybah Field. After some initial efforts to produce there were unsatisfactory, Aramco kept on trying and came up with the Shaybah 220, a well with eight laterals of around 40,000 feet of reservoir contact, and producing around 12,000 bbls per day for its first year. Saleri describes this as a "disruptive technology".

Simmons devoted a lot of attention to Shaybah, calling it "The difficult last Giant". He included a discussion of horizontal and MRC wells including the aforementioned paper, but I don't think he fully appreciated these MRC wells. They have allowed KSA to produce lots of oil in many fields that were in decline. Another example is shown by the 2008 paper by Mr Asaad Al-Towalib on "Advanced completion technologies in successful extraction of attic oil reserves in a mature giant carbonate field." In this paper they describe how this technology was adapted to produce the attic oil of Abqaiq, KSA's oldest giant. To summarize, Abqaiq had been produced since the 40's, and had produced about 57% of the original oil, but had around 25 feet of attic oil in poorer reservoir that they had not been able to produce. They tried to produce this attic oil via vertical and conventional horizontal wells with little success. They improved their technology and eventually completed many successful MRC wells with geosteering which allowed them to follow structure, and intelligent completions which delay the effects of coning.

So, much as most of us would have underestimated how successful our light-tight frac oil has now become, many underestimated how successful MRC, and associated technology has been for many gulf nations.

I think the next question is what happens next, so using Abqaiq as an example, after successfully producing that attic oil is there another encore or does it become just a depleted field? They have also used this technology to get more out of Ghawar and many other fields, do they have room to run, or are they done?

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

That is simply an outstanding display of, and description of, a serious effort in understanding what is unfolding in the world of hydrocarbon production.

I would suggest that the entire concept of MRC is being currently applied in this 'shale revolution' primarily in the area of maximizing recovery rates, aka better fracturing/completion processes.

Not only will enhanced recovery affect the economics of present unconventional operations, it has the potential to greatly expand the application to numerous, older conventional sources as well as undeveloped – yet recognized – formations with hydrocarbons within them

Boomer II says: 07/20/2017 at 2:05 pm
But the problem isn't so much whether oil is still in the ground, but how much it costs to get it out.

New technologies that don't reduce costs to make oil profitable to drill aren't all that helpful in keeping the oil flowing. Right now we have LTO because the system accepts financial loss. That could change if alternatives promise a better financial return.

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

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

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

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

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

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

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

I kind of 'flipped' the MRC concept in dc's post of 'more iron meeting' oil to 'more oil meeting iron' via the greatly enhanced fracturing/conductivity recently taking place in the shales.

Regarding multilaterals, the early (2007-2009) Bakken wells regularly contained 2 or 3 lateral from one vertical.
They used the term "turkey legs' and can still be easily seen on the ND DMR Gis map.

Virtually no one except Slawson still does this and even then, only rarely.

(Correction, might still be done in Madison formation, especially Bottineau county. Would have to check. Gis map is easiest way to literally see this).

BHP said a year ago that they would attempt to try this in the future, but I've not kept close track of their efforts.

dclonghorn says: 07/20/2017 at 3:47 pm
Thank you very much coffee, I appreciate your kind words. From what I have read MRC technology is a great fit for a number of fields in the gulf countries and may be practical in other places including USA. Of course one of the problems applying it here is that I think you need a unitized field, or at least a very large area to be implemented.

Do you know if other areas have adopted this?

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

I'm pretty sure you know a whole lot more about this stuff than I do.

I started digging into it a few years back when the series of stunningly high IPs started to emerge from the Deep Utica.
Big buzz developed about feasibility of sharing hardware/facilities to develop Marcellus and Utica together.

At that time, I was amazed to learn of the multi lateral, extended reach drilling using ultra sophisticated whipstocks in the mid east, offshore, and – if memory serves – Sakhalin. Probably do need large reservoir to be viable.

Time will tell if this approach makes sense in the shales. Like everything else, economics will be the ultimate determinator.

Boomer II says: 07/20/2017 at 10:03 am
The article says this: "On the supply side, global oil production advanced by 0.5 percent to reach 92.2 million BPD." You know, factoring in both population growth and world economic growth, this isn't much. There might be a crunch coming.
MASTERMIND says: 07/20/2017 at 12:53 pm
The 1973 so-called "oil embargo" which reduced oil supply to the USA by somewhere around 3% or 4%. It slammed the US economy, caused the largest stock market crash since the great depression, doubled gasoline prices, severely damaged US industry and caused a 55 MPH national speed limit which remained in effect for ten years.

Just wait until we experience a 10% or 20% drop in oil supplies. In a few years or sooner we certainly will. When it hits the economic and social damage will be catastrophic.

The end of Western Civilization, from China to Europe, to the US, will not occur when oil runs out. The economic and social chaos will occur when supplies are merely reduced sufficiently. As former Saudi Oil Minister Sheikh Yamani once said "The Oil Age may come to an end for a shortage of oil".

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

They are talking about 25-30% and the verbage talks about it being in railcars . . . the suggestion is it's part of the total Bakken flow of 1 million bpd. 25-30% of that is ethane? What a scam this would be.

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

Jun 14, 2017 | economistsview.typepad.com

im1dc, June 14, 2017 at 03:54 PM

The Reducing Ocean Shipping CO2 Paradox

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

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

"Big Ships Account for 80 Percent of Shipping's CO2"

By Paul Benecki...2017-06-13...20:16:44

"At Nor-Shipping 2017, researchers with DNV GL released a study that points to the difficulty of reducing the industry's CO2 output below current levels. The problem is structural: big cargo vessels emit 80 percent of shipping's greenhouse gases, but they're also the industry's most efficient ships, and squeezing out additional improvements may be a challenge.

Just 35 percent of the fleet – mostly large bulkers, tankers and container ships – is responsible for 80 percent of shipping's fuel consumption, according to Christos Chryssakis, DNV GL's group leader for greener shipping. Unfortunately, these are already the fleet's most efficient vessels per ton-mile. "This is a paradox, but if we want to reduce our greenhouse gas emissions, we actually have to improve the best performers," Chryssakis says."...

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

Similar situation with trucking, but in the USA around one half of gas consumption goes into private cars. So by improving efficiency of private fleet by 100% you can cut total consumption only by 25%. All this talk about electrical cars like Tesla Model 3 right now is mostly cheap talk. They by-and-large belong to the luxury segment.

[Jun 03, 2017] Energy production and GDP

www.counterpunch.org

pgl , June 03, 2017 at 11:03 AM

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

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

"the President cited this NERA study, commissioned by the American Council for Capital Formation, and the U.S. Chamber of Commerce. Why didn't the President rely upon his own experts within the White House?"

Because his CEA is not yet staffed. The NERA "study":

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

NERA uses its "model" to forecast that the cost to real GDP by2040 will be a 9% shortfall and the cost to employment will by 31.6 million jobs. Now that sounds BAD, BAD. But it sort of reminds me of the kind of "quality analysis" we might expect from the Heritage Foundation. Of course that is what the American Council for Capital Formation, and the U.S. Chamber of Commerce paid NERA to do.

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

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

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

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

im1dc - , June 03, 2017 at 02:16 PM
I learned much reading this about Russia's taxing of its crude oil...you may find it interesting as well...

Careful though, Irina Slav neglected to mention that Russia never stopped producing as much oil as it could during OPEC's deal to cut production so this is hardly a balanced article

Putin and the Russian Oligarchs are not going to cut production, Mother Russia (Putin) needs the cash flow (as do the other OPEC cheaters)

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

"OPEC Cuts Send Russia's Oil Heartland Into Decline"

By Irina Slav...Jun 03, 2017,...2:00 PM CDT

"Western Siberia is to Russia what the Permian is to the U.S. Well, kind of. Kind of in a sense that it's one of the longest-producing oil regions and there's still a lot of oil in it. Yet, thanks to the production cut deal with OPEC, Russian companies have had additional motivation to move to new territories in the east and the north, where taxes are lower.

In Russia, the older the fields, the higher the taxes operators have to pay. Now that the country has pledged to continue cutting 300,000 bpd for another nine months, the most obvious choices for the cut are the mature Western Siberian fields. In the first quarter of 2017, for example, output at Rosneft's Yugansk field fell by 4.2 percent, Bloomberg reported.

Production at other Western Siberian fields is set for a decline as well, with the daily output rate from lower-tax deposits in the Caspian Sea, Eastern Siberia, and the North seen to rise to 866,000 bpd by the end of the year, or 74 percent on the year. The shift away from mature fields to new ones will continue over the medium term, according to BofA analyst Karen Kostanian, as overall Russian output grows. No wonder, as tax relief on new projects sometimes reaches 90 percent.

Lukoil's output from the Filanovsky field in the Caspian, for instance, is taxed at 15 percent at a price per barrel of US$50. The average for mature fields is 58.1 percent, in a combination of mineral resource tax and export duty.

And this is not the end of it: in 2018, the Kremlin will test a new tax regime for the oil industry as it seeks to maintain production growth and the respective revenues, contributing a solid chunk of federal budget revenues. The new regime, Deputy Energy Minister Alexei Texler told Reuters, will first be introduced for a selection of 21 fields with a combined output of 300,000 bpd for a period of five years.

In case the government is happy with the results from the test, the new regime would be expanded to the whole industry. Hopes are for a substantial increase in output thanks to the new tax regime: up to 20 percent over the five-year period. These hopes seem to be limited to the Energy Ministry, however, the Finance Ministry worries that the new regime will make it harder to control the flow of tax money. The treasury is also against combining the new regime with already existing tax incentives for the industry.

So, the move away from what Bloomberg calls the oil heartland of the world's top producer is all but inevitable. It will come at a cost for the state coffers of some US$25 a barrel of Western Siberian oil, or US$2.7 billion annually, according to a Renaissance Capital analyst, but the cost will be worth it. The cost would increase, too, if the current output cut arrangement with OPEC fails to push up prices, which for now is exactly what we are seeing, while the ramp-up in the U.S. oil heartland continues."

libezkova - , June 03, 2017 at 04:18 PM
"With enough thrusts pigs can fly. It is just dangerous to stand were they are going to land." This quote is perfectly applicable to OPEC and Russia oil production now.

Neglecting maintenances and using "in fill" drilling just shorten the life of the traditional oil fields. And new large oil fields are difficult to come by.

My impression is that most of "cuts" in production by Russia and OPEC are "forced moves". Production was declining from mid 2016 when old investment were already all put into production and few new investments were made since late 2014.

If we assume the lag period of two years, than in mid 2018 we will feel the results of decisions to cut investments made in 2016.

In this situation announcing cuts allow to save face.

The net result is the same -- the oil price should rise to the level when it is economical to develop "more expensive oil" (deep see drilling, Arctic oil and such) as replacement rate in traditional fields is insufficient to maintain the production.

As long as The US government allow shale companies to generate junk bonds (which will never be repaid representing kind of hidden subsidy) along with "subprime oil", shale can slightly compensate the decline in production, but my impression is that this card was already played. Despite all hoopla from WSJ and other major MSM.

The fact that oil production for some time was artificially kept flat or slightly rising is strange and might be politically motivated (Saudi) which put other producers in situation when they were force to follow Saudi lead or lose customers. China played Russians against Saudi pretty well and got what they want at lower prices.

Those "intensification of production" were short term measures which in a long run are detrimental to old oil fields output.

They might even lessen the total amount of oil that can be extracted from a given field.

The key question here is: Does Russian oil firms has the amount of money needed to maintain production on the current level (at the current oil price levels ) or not.

Obama has a chance to move the US personal fleet to hybrid and more economical cars. He lost this chance. SUV is now dominant type of personal cars int he USA, the trend opposite to what it should be. Even hybrid SUVs like RAV4 hybrid get only around 33 miles highway, less in city traffic.

Transition to Prius type cars (with their around 50 miles per gallon) would allow US consumers to save almost half of oil spend on personal transportation (which probably represent around 60% of total US consumption http://needtoknow.nas.edu/energy/energy-use/transportation/ )

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

May 30, 2017 | peakoilbarrel.com

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

US shale production increase scenarios at different $WTI prices and cost inflation levels assuming no new debt (no mention of paying down existing debt?)

May 24, 2017 – Leslie Wei – Rystad Energy
Figure 3 shows the estimated Y/Y growth in NA liquids shale production for different WTI oil prices and cost inflation scenarios compared to 2016 cost levels. The "Call on shale" highlighted section represents the 1.3 million bbl/d average taken from figure 2. The key assumption for this analysis is that the E&P companies will balance the investments with operational free cash flow (cash neutrality). For example, in a 70 USD/bbl oil price range, cost inflation within the range of 0% to 25% is required to meet the 1.3 million bbl/d y/y growth in the "call on shale." In a 50 USD/bbl scenario, the liquids production may only grow as much as 0.5 million bbl/d on a yearly basis even if the costs remain flat. To reach the call on shale of a yearly growth of about 1.3 million bbl/d, the oil price needs to move into the range of 70 to 80 USD/bbl for the companies to stay cash flow neutral.
https://www.rystadenergy.com/NewsEvents/PressReleases/the-call-on-shale

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

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

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

Thanks for the link.

I particularly liked these calculations:

"Figure 2 shows the necessary yearly growth in shale production to balance supply and demand from 2017 to 2021. To achieve this, shale has to grow by 1.6 million bbl/d in 2017, and more than 2 million bbl/d in 2021. This implies a total shale oil production of 14.1 million bbl/d in 2021. To achieve such growth in shale production, the number of spudded shale oil wells has to reach ~20,000 wells in 2021, or two times the number of spudded wells in 2016."

Eulenspiegel says: 05/29/2017 at 9:58 am
Now we have roundabout 4-5 million b/d shale production – how can only the double number of new wells bring the triple production?

On the other hand, is shale now unlimited in resources and can supply the whole world with oil, enough wallstreet silly money (TM) provided?

Oh, and another thing: Do the shale oil wells no more decline rapidly after drilled, but add up nice to such production numbers.

PS: Here in financtial newspapers the typical shale break even price is now at 23$/barrel. There are only a few oil wells left production cheaper than US shale oil.

Kolbeinh says: 05/29/2017 at 1:17 pm
Let us see the well completion numbers from Texas for May first (RRC), and step by step judge if enough wells are actually completed. The trend is not going right through the roof when looking at the April oil well completion numbers tbh.

I don´t like the expression "call on shale" as it implies that there is a vast base of resources there to be exploited, which could turn out to not be true. I also do not like the term "call on OPEC" as it implies the same.

The countries in OPEC are very different and just some of them can ramp up I can imagine. Who knows actually with all the secrecy and lack of accurate oil field data coming from some of the participants in the organisation.

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

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

2. The shale column in the Permian Basin is about 4,000 feet thick, whereas in the Eagle Ford and Williston Basin it is only a few tens or hundreds of feet thick.

3. There are at least seven productive shale zones (which have already been tested), and several more that have not been tested, stacked like pancakes, one right on top of the other, in the Permian Basin.

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

4. The stacked plays in the Permian Basin allow for economies of scale not offered by the other shale plays.

5. Improved drilling techniques have cut the number of drilling rig days needed from spud to finishing of drilling operations (that is, the cementing of production casing) substantially.

6. Post-2015 fracking techniques (Fracking 2.0 and Fracking 3.0) are producing far more prolific wells. Offsetting wells, with identical lateral lengths, and completed with Fracking 3.0 are producing almost twice as much oil as the pre-2015 wells completed with Fracking 1.0.

7. The Permian Basin, being a mature oil and gas basin, already has a great deal of existing infrastructure already in place, and is not too terribly far from the refinery complex on the Gulf Coast, as the Williston Basin is.

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

May 30, 2017 | peakoilbarrel.com
shallow sand says: 05/26/2017 at 7:29 am
The only public company that is solely focused on fracking services in the US shale basins in Keane Group, ticker symbol FRAC. The company just went public at the end of 2016.

Keane's 10Q for 1/17 is interesting. The company lost $72 million. Their costs of services, which excludes depreciation, selling, general and administrative expenses and interest, was just $16 million less than revenues. The margin between revenues and costs of services was just 6%. This was an improvement over 2016, where costs of services were actually more than revenues.

In the business outlook section, the company states they are seeing higher pricing for services. In particular, due to greatly increasing volumes of sand per well, the company has seen certain grades of sand doubling in price since the second half of 2016.

This is not a small company, they are in all shale basins and do work for some of the big names. Clearly, as more fracking crews are utilized, costs are headed up.

Of course, they still do not have all of their frack crews working. There is still overcapacity in all service areas, as active rigs are still far below the peak in 2014. Well costs have fallen several million dollars since 2014. It is interesting that even with the price recovery in Q1, 2017, most upstream US shale companies showed losses or small earnings per share. ExxonMobil, Chevron, Pioneer, Marathon and EOG all either showed small positive or negative EPS in Q1 from US upstream.

There were outliers, such as Diamondback(FANG), which showed high EPS. However, a close look shows FANG's CAPEX is still significantly higher than D,D&A.

Looking back since 2014, very interesting how the US shale industry battled to maintain production. Saudi Arabia surely didn't anticipate the ability of US firms to operate at a loss for such a long time. 2 1/2 years later, US service firms are still operating at a loss, if Keane's example is accurate. US financial markets are very deep, interest rates remain very low on a historic basis, and executives earning 7-8 figures annually are not simply going to shut down, as no growth equals lower bonuses.

The numbers reported in 2015 and 2016 in aggregate by US shale firms clearly show that the vast majority of 2015 and 2016 shale oil wells were operated at a loss. Almost all will not reach payout in 36-60 months at the current futures strip. Hopefully, when this shale phenomenon has concluded, there will be some in depth studies conducted of the financial side. Those reports should make for very interesting reading.

Our small family business was not immune from cutting, such that 2016 was in the black, despite well head prices for the year it just $36. True, we are not drilling still, and production is slowly declining. This will continue until prices solidly rise into the $55-65 WTI band we desire. However, we can take several more years of $45-53 WTI, if that is what the future holds. The consensus in our small oil patch is that we need to be more worried about future demand, than future supply. As US shale continues to climb the wall, taking total US C+C to 10, 11 or even 12 million BOPD, that climb will get tougher, and more expensive per barrel. Maintaining 10-12 million BOPD for a few years will take more CAPEX than is currently being spent. Maybe Dennis knows how much more?

It seems more of the public is pushing for EV, ride sharing, autonomous vehicles, etc. I have tough time envisioning this, living in the middle of nowhere, in the middle of "fly over territory". But, even though these initiatives are also generally hemorrhaging cash, just as shale has, dollars and cents do not seem to matter. Kind of like how a company like Facebook can be worth $450 billion, yet I have not used it once and see it as nothing but online gossip and a complete waste of time. I can't understand it, but it is reality.

Watcher says: 05/26/2017 at 10:59 am
> In particular, due to greatly increasing volumes of sand per well, the company has seen certain grades of sand doubling in price since the second half of 2016.

Son of a gun. Imagine that. Here's my fave photo of fracking in the Bakken. It's from 2012:

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

Look real careful. Bags of ceramic proppant. From China. It's better at holding fractures open than sand. Sand was the downshift because of cost. hahahahahaha

We never do hear about the lower ultimate recoveries simply accepted from use of inferior proppant. Not part of the narrative.

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

peakoilbarrel.com
coffeeguyzz says: 05/29/2017 at 10:41 pm
There seems to be increasing mention of Occidental being bought out by someone with extremely deep pockets. Owning over 2 million net acres, Oxy is the biggest leaseholder in the Permian.

Two points in following up on Glen's post
The productive footprint of the Permian continues to expand up into New Mexico.
The output from wells in many of the basins has significantly increased in the past 12 months.
More precise targeting, staying in zone near 100%, and diversion processes are the biggest reasons.

aaannd, speaking of Oxy, they just loaded the first VLCC – Very Large Crude Carrier, capacity 2.2 million barrels – at their dock at Corpus Christi.
66 foot draft is too deep, presently, for the channel so 60% loading at dock and balance from smaller vessel when out in deeper water.

Cowboyistan.

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

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

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

CLR -$0.54/share

Eulenspiegel says: 05/30/2017 at 2:55 am
Red balance sheet ink doesn't matter for shale companies – as long as there is a story. They'll get new loans, or enough investors buying new stock.

Shale companies are like .coms in the 2000s – they are about the story, not paying big dividents. That's what old oil is for.

If now everyone of big oil drills in perminal and abandones deep water and other long run projects – it's a 0 sum game in global supply. Perhaps permian can get really 15 millions or more barrels a day, but without deep see and Alaska + other difficult projects, that's not 1 barrel more in global supply.

And it will be the mother of all oil rushes, with not being able to see a piece of Texas without drilling towers.

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

Read it and weep.

HOUSTON - May 4, 2017 - Occidental Petroleum Corporation (NYSE:OXY) today announced reported net income of $117 million, or $0.15 per diluted share, compared with a reported loss of $272 million, or $0.36 per diluted share, for the fourth quarter of 2016 .

"Our focus remains on areas that generate the best returns and we are seeing improvements in margins across all of our businesses," said President and Chief Executive Officer Vicki Hollub.

"Permian Resources continues to be a growth engine for our company, with a 5 percent improvement in production this quarter, reflecting increased drilling activity and well productivity in the Delaware Basin."

I know the information I am providing is anathema for those who have been waiting around with baited breath for the last forty years, hoping to see the last gasps of the Age of Oil. But it looks like you might have to wait a bit longer for that longed-for event, maybe quite a bit longer.

It is also anathema to those like Mike and shallow sands, and OPEC and Russia, who with their conventional oil portfolios had hoped for the quick demise of shale. After all, if the cost to produce that marginal barrel is now $50 to $60, and it remains at that cost, there is little hope for an oil price recovery much above that price. Shale killed the price of oil, and may continue to do so for some time in the future. This is not what those vested in conventional oil had hoped for, and continue to hope for.

When Khalid Al-Falih arrived at Davos in late January, the Saudi oil minister was exultant .

Almost five months later, U.S. production is rising faster than anyone predicted and his plan has been shredded .

[S]hale has defied the naysayers. By the time OPEC meets in Vienna on May 25, U.S. output will be approaching the 9.5 million barrels a day mark - higher than in November 2014 when OPEC started a two-year price war. The rebound has been powered by turbocharged output in the Permian basin straddling Texas and New Mexico.

Forced to adjust to lower prices, shale firms reshaped themselves into leaner operations that can thrive with oil just above $50 a barrel.

Since OPEC agreed to cut output six months ago, U.S. shale production has risen by about 600,000 barrels a day, wiping out half of the cartel's cut of 1.2 million barrels a day and turning the rapid victory Saudi Arabia foresaw is turning into a stalemate .

On Thursday, OPEC's own monthly oil market report said that production from non-members would rise 64 percent faster than previously forecast this year, driven mainly by U.S. shale fields.

So far, OPEC hasn't been able to "cut supplies faster than shale oil can increase," said Olivier Jakob of consultant Petromatrix GmbH .

[T]he cartel faces big risks. The most prominent is that extending cuts lifts the oil price high enough for shale to hedge again, as it did earlier this year .

Increasingly, the oil market believes the real battle between OPEC and Russia, on one side, and shale, on the other, will take place in 2018, when an increasing number of observers predict U.S. production will flood the market as it did in 2014 .

U.S. shale producers used the price spike that OPEC triggered earlier this year to lock-in revenues for 2017, 2018 and, in some cases, even 2019. With their financial future relatively secure, they started deploying rigs. Since the count of active rigs in the U.S. reached a low last, producers have added an average seven units per week, the strongest recovery in 30 years .

According to the U.S. Energy Information Administration, American crude production will surpass the 10 million barrel a day mark by late next year, breaching the record high set in 1970. The shale boom will propel non-OPEC output up 1.3 million barrels a day next year, effectively filling up almost all the expected growth in demand.

"The supply and demand balance for 2018 looks very bad," said Fared Mohamedi, chief economist at consultant The Rapidan Group in Washington. "That's when the big fight is going to happen."

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

Boomer II says: 05/30/2017 at 10:38 am
Occidental profit beats; shares fall on weak output forecast | Reuters : "Occidental Petroleum Corp's quarterly profit beat estimates on Thursday but the company's shares fell to a near eight-year low as the oil and gas producer forecast lower-than-expected production for the current quarter."
AlexS says: 05/30/2017 at 12:07 pm
Oxy is still largely a conventional producer.
Permian EOR is conventional, not sure about South Texas. Non-US accounts for almost half of total output.
So Oxy's 1Q results are not representative for the shale sector in general
AlexS says: 05/30/2017 at 1:28 pm
In fact, during the years of the shale boom, in 2011-14, OXY was one of the very few publicly traded U.S. E&Ps with positive free cash flow. All of those 3 or 4 companies had large non-shale operations. On the contrary, all pure shale players had significant negative free cash flows.
AlexS says: 05/30/2017 at 2:56 pm
Glenn,

I agree that "negative free cash flow is not bad in itself". The question is for how long
negative free cash flow is not bad?
Most shale companies had negative free cash flows since 2011 (already 6 years), having accumulated large debts. There was a short period in 2H16 when, due to sharply reduced capex, the shale sector was
free cash flow neutral. But recovering investments since 2017 will result in renewed period of burning cash (as evident from 1Q17 results). So how many more years the markets will tolerate shale companies' negative free cash flows?

I personally think that the shale sector could remain cash flow neutral or even slightly free cash flow positive, especially with gradually rising oil prices. But that would imply very modest growth in capex, and hence in production. And that still does not solve the problem of repaying accumulated debt, unless shale companies sell part of their assets and/or issue new shares, diluting existing shareholders.

AlexS says: 05/30/2017 at 1:39 pm
Exposure to shale operations has actually proven a burden for the U.S. oil companies' financials

In Oxy's case,from 2014 to 1Q17, domestic upstream operations were a negative contributor to the company's earnings (unlike international oil and gas). Positive 1Q17 earnings were due to non-shale operations that offset a $122 million loss from the US oil and gas segment. For 2016 as a whole, U.S. oil and gas had a net loss of $999 million, while all other segments, combined, have shown net earnings of $493 million. The same is true for the large US integrateds, like Exxon, which consistently had negative earnings in its US upstream segment in the past few years due to shale exposure.

That's the reality!

OXY's segment earnings
click to enlarge:

Ves says: 05/30/2017 at 5:25 pm
"Most of the giant oil companies seem to think they're not, as they write off or sell their crown jewels of 2011 – 2014 (Shell, Conoco and Exxon have all done so with their Canadian sands, and as you point out Oxy did with its Bakken shale) and pivot towards the Permian shale. It's called creative destruction, as older producing properties and techniques can no longer compete with the new ones."

Glenn,
To make a sale someone must buy. Logic does not apply that the sellers are smart and the buyers are dumb at this point. There was a seller and there was a buyer and that is all that we can say about oil sand deals. We don't know the real reasons for these sales. It is just interesting that all deals with oil sands with majors happened in downturn and that all buyers are Canadian companies.
And there is nothing creative about Shell, Exxon, Conoco acquiring all these oil sands properties at inflated prices when oil was at north of $100 during 10 years span and selling all at ultimate bottom when price at one point was $26.

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

For Q1, 2017:
US upstream -$191 million
Foreign upstream $418 million
Chemicals $170 million
Marketing and Midstream -$47 million.

The above are pre-interest and pre-tax. Oxy paid quite a bit in foreign taxes, received a large US tax benefit due to US losses, and paid over $70 million in interest, a good chunk being on debt incurred by spending in excess of cash flow on US unconventional in 2010-2014. OXY lost a good chunk of change in the Bakken and completely left the area including a multi-million $ regional headquarters they had just built in Dickinson, ND. Took a big write down on it.

I have looked a OXY Permian unconventional wells. Many pre-2016 were bad, sub 100K BO to date. I assume they are getting better, like the rest of the Permian.

shallow sand says: 05/30/2017 at 1:13 pm
If I am not mistaken, XOM, CVX and COP made positive EPS other than in US upstream in Q1, 2017. CLR broke even, PXD posted a small loss, EOG posted small net income.

FANG and XEC were outliers with strong EPS, but upon closer look, these numbers were aided greatly by low DD&A per BOE, as both elected to not place substantial CAPEX on DD&A yet.

Although I'd like $55-65 WTI, can live with $45-53. We will see how many years it takes for Permian to top out, akin to Bakken and EFS. Could take awhile, given land area. Will take awhile to see how much of the Permian is "good".

[May 30, 2017] Us shale companies ponsi

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

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

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

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

jed says: 05/28/2017 at 11:43 pm
My issue isn't about production. It's the underhanded methods to switch from one measurement to another to suit their narrative.

When US production was declining last year they stopped posting US production charts. The moment that changed and production had consistent increases the charts reappeared. I don't understand their issue with being honest.

They have some good stuff there, but for anyone paying attention it really detracts and casts a dark light on them.

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

The EIA makes lots of predictions and many of them are wrong. Conventional output will decline, GOM will be flat or declining and LTO may increase by as much as 2 Mb/d from the previous peak by 2023 and will then decline sharply (peak LTO will be about 6.5 Mb/d at most, but other US C+C output will decrease by 1 Mb/d at 3%/year annual decline). US output might reach 10.5 Mb/d, but not until 2022 rather than 2018, note that this does not satisfy 2016 crude inputs to refineries and blenders which was about 16 Mb/d, unless demand decreases by 5 Mb/d from 2017 to 2022.

I doubt that will be the case, by June 2019 we will probably see $80/b (2016$) for Brent crude. and by June 2020 the price may be North of $100/b (2016$).

Mike Tate says: 05/27/2017 at 6:42 am
Texas oil production has increased in Districts 5,7c,and 8 since October 2014. All the other 10 districts have dropped by a total of 714,406 bbls per day. I am using Texas RRC District production October 14 to January 17.

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

May 30, 2017 | peakoilbarrel.com
George Kaplan says: 05/24/2017 at 9:57 am
There's a plausible sounding theory, even though posted on Zero Hedge, that the Chinese have been filling their SPR over the last two years, and that is about to stop. This would mostly account for why OECD storage levels only took about 35% of the supply-demand imbalance. If they do stop then about 1 mmbpd of demand would suddenly be lost, but it might also imply that the real economy demand growth in the period since January 2015 has only been half what it looks to have been. Taking account of the sudden drop and a slower growth in demand would mean a longer time would be needed to draw down OECD stocks. However if the China SPR scenario is correct then almost all the drawdown would come from OECD. By my reckoning this would push a balancing out to late 2018 (although by then we may be seeing some bigger supply drops as the pipeline for new project start-ups will be drying up). But if the balancing is pushed out then the chances of many FIDs this year or next will decline and the possibility of a sudden supply crunch in 2019 through 2022 would be greater. The green curve below gives possible drawdown under this scenario. The red one was a previous assumption that the OECD stocks would be drawn down at only about 35% of the imbalance (as happened when they were rising). I seemed a bit iffy when I fitted it that way, and I think the China SPR filling is a better explanation.

Watcher says: 05/24/2017 at 6:00 pm
SPRs in general try to have 90 days of domestic consumption in them. This was a standard put into place mostly in Europe. China has embraced it.

The US at 750ish million barrels and having a consumption (net of production) of about 11 million bpd (remember, this is real stuff . . . consumption, no refinery gain BS allowed) and so not quite 70 days domestic consumption.

China, at net consumption of about 7 million bpd X 90 needs an SPR of 630 million barrels. That's about what they have, but of course with 5% consumption growth they'll have to adjust up, but for now . . . all is well.

There probably is no flow in or out of China for SPR reasons. Already full. Have been for a while.

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

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

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

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

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

George Kaplan says: 05/25/2017 at 2:29 pm
This is the chart Zero Hedge had, or linked to – the key is Xinhua CFC, who have Chinese data not otherwise available and charge a lot of money for it. I don't know how you'd go about checking if it's correct.

Energy News says: 05/26/2017 at 4:26 am
Hello, don't forget that Xinhua doesn't publish China's SPR figures. The SPR figure in the chart is an estimate based on (Production + Imports – Refinery Inputs). I'm not sure if all the teapots are included in the official refinery data.

I think Zero Hedge borrowed the chart from here:
Scotiabank pdf file: http://www.gbm.scotiabank.com/scpt/gbm/scotiaeconomics63/SCPI_2017-04-12.pdf

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

Chart showing March

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

Bloomberg – October 11th 2016
China's appetite for oil.
Fuel use grew by about 5 percent in the first half of 2016, according to China's biggest oil refiner, faster than the 0.4 percent derived from government data. That "official" number is clouded by rising gasoline exports - blends that don't show up in official figures, according to the International Energy Agency, Sinopec Group and Energy Aspects Ltd.
Chinese authorities are also having trouble tracking refinery activity because of the surge of processing by independent refiners, known as teapots, according to Energy Aspects' Meidan.
http://www.bloomberg.com/news/articles/2016-10-10/gasoline-cocktails-mix-with-gaps-in-data-to-cloud-china-oil-view ?

[May 30, 2017] Soon, GOM will start declining. Onshore conventional is like the sun setting. Just 60 or so straight hole rigs active, half of the 1998-99 trough. Alaska doesnt appear to add anything. Unless demand tank maybe its time to be bullish?

Notable quotes:
"... Unless demand tanks, per Tony Seba's theories, maybe its time to be bullish? When it is clear US shale has hit the wall, price could sky? ..."
May 30, 2017 | peakoilbarrel.com
shallow sand says: 05/26/2017 at 10:07 pm
Enno's shaleprofile.com is full of facts. I went back and looked at his 1/17 summary of all US oil producing shale fields. Interesting that despite adding over 13,000 new wells since the peak in 3/15, US as of 1/17 was still 600K bopd below the 3/15 peak.

I do realize data is somewhat incomplete due to TX. I also realize not all wells are included. Still, going to take a lot of CAPEX to climb the ladder back to 5, 6 and maybe 7 million bopd from the shale fields.

Soon, GOM will start declining. Onshore conventional is like the sun setting. Just 60 or so straight hole rigs active, half of the 1998-99 trough. Alaska doesn't appear to add anything.

Unless demand tanks, per Tony Seba's theories, maybe its time to be bullish? When it is clear US shale has hit the wall, price could sky?

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

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

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

XOM – Potential 2nd Downgrade – unless APPL or Bazos jumps to the rescue. / sarc

"However, unlike its peers such as Chevron and BP, Exxon Mobil is not targeting meaningful growth in production.

Although Exxon Mobil is working on a number of shale oil, conventional oil and LNG projects which will come online in the near term, they will largely help the company in offsetting the negative impact of field declines and asset sales - Shell, Chevron, and BP carry debt loads of $91.6 billion, $45.3 billion and $61.8 billion, respectively. "

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

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

Notable quotes:
"... Hopefully everyone involved in defending Bakken production upswings will not disappear into the woodwork next month, or the month after, when production drops again. ..."
"... Of course marginal shale oil wells that are at or below economic limits get shut in during winter, or get shut in and stay shut in because workover costs to restore production simply do not make economic sense. ..."
"... Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack thereof); in the end the latter always wins out. ..."
"... A little more time and realized production data will prove that downsizing actually reduced UR per incremental well and was yet another economic disaster in a string of economic disasters for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices. ..."
Apr 17, 2017 | peakoilbarrel.com
Mike 04/15/2017 at 9:35 am
Hopefully everyone involved in defending Bakken production upswings will not disappear into the woodwork next month, or the month after, when production drops again.

Of course marginal shale oil wells that are at or below economic limits get shut in during winter, or get shut in and stay shut in because workover costs to restore production simply do not make economic sense. There are gazillions of those kinds of well in all three of America's shale oil basins. There need not be a flush 'uptick' of production when those wells come back on line (that's investor presentation dribble), in fact it can be just the opposite because of bubble point/higher water saturations.

Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack thereof); in the end the latter always wins out.

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

Imagine a situation where you are drilling these $6.5M wells so close together (Marathon at 330 feet, toe to toe) that you have to "protect" them by shutting them in for prolonged periods of time while you frac a new well 3000 feet away. That makes a lot of sense, doesn't it?

A little more time and realized production data will prove that downsizing actually reduced UR per incremental well and was yet another economic disaster in a string of economic disasters for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices.

People do really stupid things with OPM.

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

... ... ...

The actual reserve that is being produced in the Bakken was "discovered, undeveloped and developed" in 2013, and not covered by the USGS. It's difficult to find break out information for individual areas in most companies reports but I don't think there was more than about 5 Gb developed and undeveloped reserves in 2013, and it might have declined a bit since then, even including actual production.

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

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

When I give the cumulative output of the scenarios, it is from the start of production in the Bakken/TF in ND, about 1.6 Gb had been produced at the end of 2015 and Bakken Three Forks proved reserves were about 5 Gb at the end of 2015, that gets us to 6.6 Gb, typically there are probable reserves as well, though we would have to guess at how much. Also as oil prices increase in the future 2P reserves are likely to increase.

Note that the F95 USGS TRR estimate for the ND Bakken Three Forks is about 7.2 Gb, if we assume probable reserves at the end of 2012 were zero (in my view not a very good assumption). What do you think is a reasonable estimate for probable reserves if proved reserves are 5 Gb? Your guess would be better than mine. For UK North Sea a typical number would be 3 Gb of probable for 5 Gb of proved (all UK North Sea reserves). For the Bakken it would likely be lower, maybe 1 Gb of probable for 5 Gb of proved reserves might be a reasonable guess.

Bakken average well profile from June 2015 to Dec 2017 shown below (after that the EUR decreases).

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

That is the study I use.

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

If you pull up data at shaleprofile.com
and look at wells from 2014 to 2017, there are 1388 Three Forks wells that have been producing for 20 months (cumulative is 118kb) and there are 1689 Middle Bakken wells (cumulative is 143kb@20 months). So lately (past 3 years) a fairly large proportion of wells have been Three Forks wells (about 45%). After 36 months the difference in cumulative output is about 30 kb (TF is lower at 155kb@36 mo, Bakken is 185 kb at 36 months).

George Kaplan says: 04/15/2017 at 2:52 am
I think you are mixing proved reserves from EIA with the undiscovered numbers from USGS. The proved reserves might have some basis and 5 to 6 might be right, I haven't sen any kind of detail of how they are arrived at. But that is not the same oil as in the USGS report – it was mostly already known about in 2012 when the E&Ps stopped drilling wildcats. Since then they have been converting probable to proven, and in some cases writing off some of the reserves. If you want to include the USGS data then it should be added to whatever there was as 2P in 2012 as a final recovery.

I don't know where there 1300+ Three Forks wells come from – the ND production wells for January shows only 1 well in the Three Forks and 45 Three Forks / Bakken. There are other pool's like Sanish and Madison. Madison is a big producer so maybe that is counted as Three Forks in USGS. The ND DMR overall production up to 2015 gives 10 million for Three Forks / Bakken, 1600 for Bakken, 950 for Madison and < 1 for Three Forks alone.

The 220,000 EUR I quoted was for the Three Forks alone from USGS, not Bakken.

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

Mar 25, 2017 | peakoilbarrel.com
George Kaplan says: 03/23/2017 at 7:18 am
It's looking like the shorter cycle times for LTO just means the the volatility acts over higher frequency but doesn't go away. A fundamental problem remains that all the E&Ps use basically the same model, and therefore they all make essentially the same decisions at around the same time, and therefore you get boom and bust. Volatility may be the biggest contribution to delaying or preventing long term investment in bigger (principally deep water and oil sand) projects, but I think the impact of the big drop off in discoveries is significant, and not being fully appreciated.

The backlog of discoveries are mostly difficult and expensive developments that were not considered as top prospects when oil was over $100.

The few larger, new discoveries are also in frontier, and therefore generally more expensive, regions. E&Ps are turning to gas, or near field developments, or are giving up on offshore altogether. Much higher, and stable, prices might be needed to get these big projects going. If high prices cause a fast demand collapse, by whatever mix of mechanisms, then they might well not get done.

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

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

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

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

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

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

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

It is not.

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

Mar 17, 2017 | www.calculatedriskblog.com

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

"A few comments from Steven Kopits of Princeton Energy Advisors LLC"

Mar 17, 2017:

• The US oil rig count was up by 14 this week to 631

• US horizontal oil rigs were up by 14 to 530
...

• This was another very aggressive rig add, but curiously came from outside the major plays. This suggests that either the business is spreading beyond its historical boundaries, or that some technical and non-recurring issues may be at play.

[Mar 05, 2017] The supermajors spent 66 percent more on development costs in 2015 than they did in 2011, despite the widely-touted 'efficiency gains' implemented during the worst of the market slump

Notable quotes:
"... A large part of the problem is, as is often repeated, "the cheap oil is gone". How are prices going to fall no matter how efficient things get ("work smart not hard" the project managers used to say when budgets got bust – complete cobblers) when you need to use 15000# Duplex piping instead of 600# mild steel, use latest generation (is it 5th now?) ultra deep water rigs which still only hit one in twenty exploration successes, have miles and miles of anchor cables and riser tubing instead of a short jacket etc. ..."
"... Looking at what Exxon is doing to make itself look good to investors, and then reading articles like this, I wonder if we are seeing the decline of the majors, but people aren't openly saying that yet. They keep hedging their bets by saying the oil business is cyclical, but we are talking about not only lower oil prices, but also declining reserves and higher production costs. ..."
"... The title should be "cost per barrel developed increase 66%". Adjusting for inflation we see that each dollar develops about 70% of the oil it did before. This is reasonable when we consider deep water developments don't have such good wells anymore, and that other areas are mostly limited to pounding increasingly poorer reservoirs or implementing EOR in known fields. ..."
"... Successful efforts accounting methods, as opposed to full cost, are preferred by the shale oil industry because, in my opinion, it helps distort the economic picture and makes them look better than they actually are. Hardly ever is lease acquisition costs (lease bonuses), land work, curative title work, geophysical or infrastructure costs (upstream to midstream gathering systems) used when quoting well costs to the public. This might help answer your question in the Permian: http://info.drillinginfo.com/permian-premium-are-high-prices-justified/ ..."
"... I would say in OKLA the EUR is much to low by a factor of 2-4 for a single horizon, in other words a ~100 acres can be expected to produce any where from 400,000 to 800,000 BO and can have 3 or more productive horizons each capable of those types of production numbers. So for example a ~100 acres can produce 1,500,000BO or more. ..."
"... "Several companies which were early adopters of enhanced completion techniques and have their acreage concentrated in sweet spots have seen significant declines of their IP30 values of new wells, indicating an exhaustion of their acreage. More recent adopters of enhanced completion methods, by limiting drilling to their best acreage, have seen a boost of IP30 of new wells since 2014 but will sooner or later face the same exhaustion problems." ..."
"... The oil and gas sector was particularly hammered in the three-month period, according to the report. The industry employed 3,640 fewer jobs compared to third quarter 2015, a 26 percent drop." ..."
Mar 05, 2017 | peakoilbarrel.com
Boomer II says: 03/03/2017 at 10:14 pm
This could probably go into the previous post about petroleum, but I will put it here.

Oil Majors' Costs Have Risen 66% Since 2011 | OilPrice.com : "According to new research from Apex Consulting Ltd., the oil majors are still spending more to develop a barrel of oil equivalent than they were before the downturn in prices – in fact, much more. Apex put together a proprietary index that measures cost pressure for the 'supermajors' – ExxonMobil, Royal Dutch Shell, Chevron, Eni, Total and ConocoPhillips. Dubbed the 'Supermajors' Cost Index,' Apex concludes that the supermajors spent 66 percent more on development costs in 2015 than they did in 2011, despite the widely-touted 'efficiency gains' implemented during the worst of the market slump. It is important to note that this measures 'development costs,' and not exploration or operational costs."

George Kaplan says: 03/04/2017 at 3:53 am
Interesting article and so was the Reuters one it referenced. One thing I missed was a discussion of gas versus oil versus oil sands, I assume the figures are for all combined, but it would be interesting to see how things changed for each section (though probably the data is only available internally to the companies or at a big cost from IHS or Rystad). 2011 was an era of mega projects though especially for some huge LNG (many of which ran way over budget) and oil sands, and would also include the cost overruns from the Kashagan debacle.

He concludes:

"In other words, the decline in costs post-2014 are, at least in part, cyclical. Costs will rise again as activity picks up unless oil producers work with their suppliers to address the underlying structural costs of oil production."

But is that possible? A large part of the problem is, as is often repeated, "the cheap oil is gone". How are prices going to fall no matter how efficient things get ("work smart not hard" the project managers used to say when budgets got bust – complete cobblers) when you need to use 15000# Duplex piping instead of 600# mild steel, use latest generation (is it 5th now?) ultra deep water rigs which still only hit one in twenty exploration successes, have miles and miles of anchor cables and riser tubing instead of a short jacket etc.

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

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

Boomer II says: 03/04/2017 at 10:54 am
Looking at what Exxon is doing to make itself look good to investors, and then reading articles like this, I wonder if we are seeing the decline of the majors, but people aren't openly saying that yet. They keep hedging their bets by saying the oil business is cyclical, but we are talking about not only lower oil prices, but also declining reserves and higher production costs.

Just as coal has seen its best days come and go, I think that is happening with oil, too, but there is a reluctance to call it.

Fernando Leanme says: 03/04/2017 at 3:54 am
The title should be "cost per barrel developed increase 66%". Adjusting for inflation we see that each dollar develops about 70% of the oil it did before. This is reasonable when we consider deep water developments don't have such good wells anymore, and that other areas are mostly limited to pounding increasingly poorer reservoirs or implementing EOR in known fields.
George Kaplan says: 03/04/2017 at 3:33 am
For LTO it's interesting how EagleFord are piling on rigs (5 more this week) and the permitting seems to have increased dramatically, whereas the Bakken is steady to maybe slightly down, certainly for permitting at the moment. I don't know where the difference for this is and I expected the opposite, but it seems EIA knows something as their predicted flattening in the EFS decline rate is looking pretty likely know, while Bakken is looking increasingly weary, with only the outstanding DUCs as a big potential source of new oil.
clueless says: 03/04/2017 at 12:07 pm
During the past 2 years, there has been a tremendous amount of great quality work concerning the economics of onshore LTO production. Much of it has been done by those who post here.

But, although I may have missed it, I still have a question that I do not recall being discussed. Buried in each of these economic models, is there a land resource cost?

For example what I would like to see separated out for each model is information such as this (a hypothetical by me, for illustrative purposes only): "The 60 Gb scenario assumes that each average onshore LTO well utilizes 100 acres of oil resource; has an average EUR of 200,000 bbl of oil; at an average leasehold cost of $10,000 per acre. So each average well has an upfront leasehold cost of $1 million, and that cost is [or is not] included in the cost per well shown.

However, let me be clear: if that information is not available, I am not asking anyone to go get it. Just state that it is up to the reader to make their own assumptions of what the leasehold cost is for an average onshore LTO well. But, in that regard, it would be usefull to know how many acres are being used for an average well.

Dennis Coyne says: 03/04/2017 at 2:24 pm
Correct that land cost is not included. I don't know what that is. This based on Rune Likverns analysis from the oil drum.
Mike says: 03/04/2017 at 2:37 pm
Successful efforts accounting methods, as opposed to full cost, are preferred by the shale oil industry because, in my opinion, it helps distort the economic picture and makes them look better than they actually are. Hardly ever is lease acquisition costs (lease bonuses), land work, curative title work, geophysical or infrastructure costs (upstream to midstream gathering systems) used when quoting well costs to the public. This might help answer your question in the Permian: http://info.drillinginfo.com/permian-premium-are-high-prices-justified/
clueless says: 03/04/2017 at 5:41 pm
Thanks Mike! That was good information and a good article.
texas tea says: 03/04/2017 at 5:35 pm
With respect to the parameters in your question:

"The 60 Gb scenario assumes that each average onshore LTO well utilizes 100 acres of oil resource; has an average EUR of 200,000 bbl of oil; at an average leasehold cost of $10,000 per acre."

I would say in OKLA the EUR is much to low by a factor of 2-4 for a single horizon, in other words a ~100 acres can be expected to produce any where from 400,000 to 800,000 BO and can have 3 or more productive horizons each capable of those types of production numbers. So for example a ~100 acres can produce 1,500,000BO or more.

Current density plots indicate 113 acre drainage will be achieved with a 7500′ lateral with 660′ between wells. A 10,000′ lateral would be 151 acres. I can also say, because of government interference, "forced pooling" the average leasehold cost is something under $2000 an acre. Leasehold cost are usually added to the first producing well as part of the "full cycle" cost and are a one time expense.

Any given unit may ultimately have 10-15 wells. Once the Unit is HBP and the primary term of the leases have expired the full land cost will have been expensed.

My oldest well LTO well in SCOOP has produced over 300,000 barrels of liquids from approximately 51 acres.

clueless says: 03/04/2017 at 5:55 pm
Thanks TT! Since I live in OK, your information appears to be very positive information for OK – which currently is in a poor economic environment due to low oil [and gas] prices. However, based upon your information, why, in your opinion, has this OK play not attracted nearly as much "hype" as the Permian [or Baaken or Eagle Ford]? Is the long-term potential [ultimate oil to be extracted from the entire play] much less?
AlexS says: 03/04/2017 at 7:56 pm
clueless,

Current active oil and gas rig count:

OK: 98
Eagle Ford: 69
Bakken: 38

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

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

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

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

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

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

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

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

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

Good presentation by BTU Analytics. And it shows that SCOOP and STACK are not a new Bakken, Eagle Ford or Permian in terms of oil production potential.

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

In Texas and New Mexico, there is private fee land and state land. New Mexico also has federal land ownership. Texas has very little Federal ownership but there are Relinquishment Act Lands, University Lands, and School Lands, and Stare Fee Lands which would have public records available to review.

The state and federal agencies are mandated to seek competitive fair market prices for land leased for oil and gas exploration. If one obtained the lease sale results from the appropriate state and federal agencies for each scheduled lease sale for the last ten years you might approximately determine an average lease bonus by year that the oil and gas industry paid for both private fee and state lands in an area.

This would not help with acreage acquired early in a play and then flipped to a subsequent purchaser but I think it would be a reasonable number to work with for example the Eagle Ford, Delaware Permian or New Mexico Permian. Colorado, South Dakota, Oklahoma all contain a combination of private and state or federal lands.

It could be an interesting exercise.

Boomer II says: 03/04/2017 at 2:45 pm
Split in oil-price, rig-count flows a cause for concern? Not yet. | TheHill : "That the land rig count is recovering at a stronger pace than its underlying commodity, which usually is the catalyst for changes in the rig count, does present a reason for concern."
Boomer II says: 03/04/2017 at 4:27 pm
Bakken Oil Producers: IP30 And Well Decline Rate Trends Since 2014 | Seeking Alpha : "Several companies which were early adopters of enhanced completion techniques and have their acreage concentrated in sweet spots have seen significant declines of their IP30 values of new wells, indicating an exhaustion of their acreage. More recent adopters of enhanced completion methods, by limiting drilling to their best acreage, have seen a boost of IP30 of new wells since 2014 but will sooner or later face the same exhaustion problems."
Boomer II says: 03/04/2017 at 4:33 pm
An article from February.

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

The oil and gas sector was particularly hammered in the three-month period, according to the report. The industry employed 3,640 fewer jobs compared to third quarter 2015, a 26 percent drop."

Boomer II says: 03/04/2017 at 4:39 pm
Unburnable Wealth of Nations - Finance & Development, March 2017 : "[Poor countries] face three special challenges. First, they have a higher proportion of their national wealth at risk than do wealthier countries and on average more years of reserves than major oil and gas companies. Second, they have limited ability to diversify their economies and sources of government revenues-and it would take them longer to do so than countries less dependent on fossil fuel deposits.

Last, economic and political forces in many of these countries create pressure to invest in industries, national companies, and projects based on fossil fuels-in essence doubling down on the risk and exacerbating the ultimate consequences of a decline in demand for their natural resources (see map)."

Boomer II says: 03/04/2017 at 4:50 pm
This article gives a good overview of what is happening in Colorado.

There is activity, but it is unlikely Colorado will have any sort of boom, like was talked about a few years ago.

Rebound predicted for Weld crude oil production | GreeleyTribune.com : "DJ Basin crude oil sells at a discount of $2 to $3 per barrel to benchmark West Texas Intermediate oil from the Permian Basin. 'Companies here still need prices to go a bit higher before we will see a significant increase in activity,' she said."

[Feb 26, 2017] Militarists from Obama administration essentially continued Bush II policies and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating conversion of passenger cards to hybrids (and electrical for short commutes)

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

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

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

"U.S. Oil Exports Hit Record Levels"

By MarEx 2017-02-24

"U.S. oil exporters set a new record last week: shipments leaving the country averaged 1.2 million barrels of crude per day, roughly double the levels seen at the end of last year.

Analysts told Bloomberg that the rising American exports are driven in large part by falling domestic prices. West Texas Intermediate futures (the domestic benchmark) are trading below the international Brent standard by $2 per barrel or more, and are now cheaper than some Middle Eastern grades of lesser quality. This makes American crude more attractive to Asian buyers.

There is also an incentive for traders to sell their oil abroad: U.S. storage is costly. If the price of crude is not expected to rise, brokers have no incentive to hang on to their supply and pay rent on a tank to put it in."...

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

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

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

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

im1dc -> ilsm... , February 25, 2017 at 02:00 PM
ilsm, that is the previous week I believe.
libezkova -> ilsm... , February 25, 2017 at 04:33 PM
You are just regular incompetent chichenhawk. And it shows. Try to read something about US oil industry before positing. It is actually a very fascinating topic. That's where the battle for survival of neoliberalism in the USA (with its rampant militarism and impoverishment of lower 50% of population) is now fought.

If you list also domestic consumption, you will understand that you are completely misunderstanding and misrepresenting the situation. The USA is a huge oil importer (Net Imports: 6.075 Mbbl; see ilsm post), not an exporter. You can consider it to be exported only after drinking something really strong.

It refines and re-export refined products and also export condensate and shale light oil that is used for dilution of heavy oils in Canada and Latin America. That's it.

US shale can't be profitable below, say, $65 per barrel (so called "break-even" price for well started in 2009-2016), and if interest on already existing loans (all shale industry is deeply in debt; ) and minimum profitability (2.5%) is factored in, probably $77.

That's why production is declining and will decline further is prices stay low because there is only fixed amount of "sweet spots" which can produce oil profitably at lower prices. In 2017 they are mostly gone, so what's left is not so attractive at the current prices. And this is an understatement.

The same is true to Canadian sands. Plans for expansion are now revised down and investments postponed.

So in order to sustain the US shale industry prices need to grow at least over $65 this year

And those war-crazy militarists from Obama administration essentially continued Bush II policies and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating conversion of passenger cards to hybrids (and electrical for short commutes).

The US as a country waisted its time and now is completely unprepared for down of oil age.

The net result of Obama policies is that SUVs became that most popular type of passenger cars in the USA. That can be called Iran revenge on the USA.

The conflict between Donald Trump and the US Deep State can be explained that deep state can't allow Trump détente with Russia and stopping wars on neoliberal expansion at Middle East. That's why they torpedoed General Flynn. It is not about Flynn, it was about Trump. To show him who is the boss and warn "You can be fired".

Due to "overconsumption" of oil inherent in neoliberalism with its crazy goods flows that might cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism as social system) can well go off the cliff when cheap oil is gone.

The only question is when it happens and estimates vary from 10 to 50 years.

So in the best case neoliberalism might be able to outlive Bolshevism which lasted 74 years (1917-1991) by only something like 15 years.

[Feb 25, 2017] Due to overconsumption of oil inherent in neoliberalism with its crazy goods flows that might cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism as social system) can well go off the cliff when cheap oil is gone.

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

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

Click and look at the map and inset to understand

Israel to become an energy, NG, superpower?

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

"Noble Energy Sanctions Leviathan"

By MarEx...2017-02-24

"Noble Energy has sanctioned the first phase of the Leviathan natural gas project offshore Israel, with first gas targeted for the end of 2019.

Noble Energy is the operator of the Leviathan Field, which contains 22 trillion cubic feet (Tcf) of gross recoverable natural gas resources.

The announcement was hailed by Israeli Prime Minister Benjamin Netanyahu who has played a key role in negotiations with Noble. Netanyahu says the discovery of large reserves will bring energy self-sufficiency and billions of dollars in tax revenues, reports The Times of Israel, but critics say the deal gave excessively favorable terms to the government's corporate partners...

Production will be gathered at the field and delivered via two 73-mile flowlines to a fixed platform, with full processing capabilities, located approximately six miles offshore."...

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

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

"U.S. Oil Exports Hit Record Levels"

By MarEx 2017-02-24

"U.S. oil exporters set a new record last week: shipments leaving the country averaged 1.2 million barrels of crude per day, roughly double the levels seen at the end of last year.

Analysts told Bloomberg that the rising American exports are driven in large part by falling domestic prices. West Texas Intermediate futures (the domestic benchmark) are trading below the international Brent standard by $2 per barrel or more, and are now cheaper than some Middle Eastern grades of lesser quality. This makes American crude more attractive to Asian buyers.

There is also an incentive for traders to sell their oil abroad: U.S. storage is costly. If the price of crude is not expected to rise, brokers have no incentive to hang on to their supply and pay rent on a tank to put it in."...

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

I did not see any input to the NPR.

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

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

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

im1dc -> ilsm... , February 25, 2017 at 02:00 PM
ilsm, that is the previous week I believe.
libezkova -> ilsm... , February 25, 2017 at 04:33 PM
You are just regular incompetent chichenhawk. And it shows. Try to read something about US oil industry before positing. It is actually a very fascinating topic. That's where the battle for survival of neoliberalism in the USA (with its rampant militarism and impoverishment of lower 50% of population) is now fought.

If you list also domestic consumption, you will understand that you are completely misunderstanding and misrepresenting the situation. The USA is a huge oil importer (Net Imports: 6.075 Mbbl; see ilsm post), not an exporter. You can consider it to be exported only after drinking something really strong.

It refines and re-export refined products and also export condensate and shale light oil that is used for dilution of heavy oils in Canada and Latin America. That's it.

US shale can't be profitable below, say, $65 per barrel (so called "break-even" price for well started in 2009-2016), and if interest on already existing loans (all shale industry is deeply in debt; ) and minimum profitability (2.5% is factored in, probably $77.

That's why production is declining and will decline further is prices stay low because there is only fixed amount of "sweet spots" which can produce oil profitably at lower prices. In 2017 they are mostly gone, so what's left is not so attractive at the current prices. And this is an understatement.

The same is true to Canadian sands. Plans for expansion are now revised down and investments postponed.

So in order to sustain the US shale industry prices need to grow at least over $65 this year

And those war-crazy militarists from Obama administration essentially continued Bush II policies and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating conversion of passenger cards to hybrids (and electrical for short commutes).

The US as a country wasted its time and now is completely unprepared for down of oil age.

The net result of Obama policies is that SUVs became that most popular type of passenger cars in the USA. That can be called Iran revenge on the USA.

The conflict between Donald Trump and the US Deep State can be explained that deep state can't allow Trump détente with Russia and stopping wars on neoliberal expansion at Middle East. That's why they torpedoed General Flynn. It is not about Flynn, it was about Trump. To show him who is the boss and warn "You can be fired".

Due to "overconsumption" of oil inherent in neoliberalism with its crazy goods flows that might cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism as social system) can well go off the cliff when cheap oil is gone.

The only question is when it happens and estimates vary from 10 to 50 years.

So in the best case neoliberalism might be able to outlive Bolshevism which lasted 74 years (1917-1991) by only something like 15 years.

[Feb 21, 2017] A big contributor to the legacy oil decline is the unrelenting physics of fluid phase behavior, with gas becoming more prevalent in the production stream.

Feb 21, 2017 | peakoilbarrel.com
djtxyz says: 02/16/2017 at 1:44 pm
A big contributor to the legacy oil decline is the unrelenting physics of fluid phase behavior, with gas becoming more prevalent in the production stream. Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The legacy wells will be worse (i.e. the newer wells dampen the effect, which have an initial GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is considered a "gas" well or field.

Most of these LTO fields will eventually be abandoned as gas fields.

note – I tried to post a *.png graph, but the reply tool failed.

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

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

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

I missed to take into account the number of days in the month for total producing days in my last post. I wanted to investigate this more. So I did a bit of programing and adjusted each individual well for the number of days it was in production in December to see what the production would have been if it produced as many days as it did in November (adjusted for number of days in that month). I looked at wells that started production in 2014 and wells that started production in 2010. In short, both groups looked very similar and it turned out that about 86% of the increase in decline rate, for both 2014 and 2010, were because of fewer producing days and the rest for other reasons. However there is more to it than that. First of all, adjusted for number of producing days, the decline rate should stay the same or decrease a little every month, not increase. Secondly wells that are of the same age as the 2014 wells have historically had a monthly decline rate of around 3%. The decline rate in November (days adjusted) was 6,9% and in December 8,1. For the 2010 wells, monthly decline rates should have been around 1,5% but were 5,6% in November and 6,9% in December. So the decline rates are currently very very high. The huge drop in December could not have been that huge if the underlying decline rates would not have been that large.

I think the decline in GOR has something to do with it. If the reason for the increase in decline rates are that they are choking the wells, then I expect these high decline rates to be rather temporary, because I would guess that they adjust the choke only once per well. It may take some time to adjust all wells they have planned to adjust, but when that is done then decline rates should normalize. So if that is the reason then maybe it will take a few months to normalize. If the decline rates are still very high in a few months, then it doesn´t look good for Bakken..

FreddyW says: 02/20/2017 at 3:02 am
I found a bug in my code. For 2014 about 100% of the increase in decline rates from November to December was because of fewer production days and decline rate in November was 6,43% and December 6,35% (a bit conservative). For 2010 the numbers are 86%, 4,16% and 5,16%. So lower underlying decline rates, but still very high. Sorry about that.
Fernando Leanme says: 02/16/2017 at 4:20 pm
Is the 2000 GOR a North Dakota convention? There's no reservoir engineering reason to designate a depleted well as a gas well when GOR increases to 2000 scf/bo. Depleted oil wells under depletion drive do experience very high GORs, but they remain oil wells.
Boomer II says: 02/16/2017 at 4:51 pm
Here's a link that says in Texas there are tax advantages in reclassifying an oil well as a gas well.

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

Watcher says: 02/17/2017 at 1:11 pm
My recall is there's a regulation in Texas that classifies liquids from a gas well as condensate vs oil from an oil well. Almost certainly has some tax consequence.
GreenPeople's Media says: 02/16/2017 at 8:12 pm
Can any of you professional fellows explain the upsurge in "Legacy Oil Well" production shown in the monthly EIA Drilling Productivity Reports? The major fields, except. Permian, show that the legacy wells are rising after having been on seemingly steady downslopes for the years leading up to about early 2015. Are they reworking old wells? What's the industry practice that has reversed the declines.

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

dclonghorn says: 02/16/2017 at 10:09 pm
The legacy well production graph represents the monthly expected change in production.

In the example you referenced monthly legacy decline was about 140,000 bopd at the beginning of 2015. This legacy decline represents the decline of wells producing in the prior month. This decline was large because there were many recently drilled legacy wells, and the recently drilled wells decline more than wells which have produced for a longer period.

By the beginning of 2017 the legacy decline had decreased to about 80,000 bopd per month because there hadn't been as many wells drilled recently.

Alex K says: 02/17/2017 at 2:08 am
To dclonghorn:
Right. Another point is that more and more wells became idle so they aren't calculated in the legacy well production.
GreenPeople's Media says: 02/18/2017 at 11:28 am
Thanks. That helps clarify things for me.
Watcher says: 02/17/2017 at 2:44 am
Some of y'all are newishcomers and cannot remember how very many times monthly production reports would report completely inconsistent with new completions totals and weather and more or less 15 gazillion other factors we'd throw in.

Point being, don't think you have why the big recent increase or why this big decrease understood. Your odds on this are poor.

Reminder from last thread:. That Enno chart color coded by year - look at how shallow the post Peak descent slope 2010, 2011, 2012 is vs 2014. Damn near vertical. That would be the last non price smash year.

This speaks to EUR, but not loudly because of . . . Wait, do we have proof these recompletions are happening? Or is this presumption.

Also suggest a read thru of the new rule making paras of the directors cut.

Watcher says: 02/17/2017 at 1:16 pm
I can remember months when new completions and new wells operating numbers completely failed to explain a change in quoted oil production that month . . . and I embarked on chasing down traffic reports and stop light failures at intersections because trucks hauling oil having been slowed down could conceivably have been the explanation for the numbers. Nada.

What we DID conclude was negative - zero explanation for oil output quotes from the number of wells completed in a month. Number of days of bad weather preventing completions also failed to explain. Bad weather slowing down trucks remained a maybe, but for trucks hauling oil, not trucks hauling proppant.

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

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

Ceramic proppant for Bakken. From China. Soon after this it was magically discovered that special sand from the US was "superior" (meaning cheaper, but didn't hold the fractures open as well).

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

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

Munger would have us import oil and gas now from OPEC so that we can save our oil and gas for the future when the world is going to have major shortages."

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

People Are Not Stupid.

The day comes when a firebrand is in control and dares to rock the societal systemic boat by declaring the price of oil will be non monetary. You want oil from Russia, America? Disarm. You want oil from KSA, America? Convert to Islam.

"We have enough of your dollars created from thin air. Let's have something of real value to us before we send you oil. The price is described above."

Boomer II says: 02/18/2017 at 3:59 pm
But if we haven't wasted our own oil, we'll still have it. And then if other countries want to give us terms we won't accept, then we don't use their oil.

Of course, without imports, we won't have enough to run our country business as usual. But we're going to head that way anyway, as global supplies become more scarce and/or expensive.

Oldfarmermac says: 02/19/2017 at 8:11 am
When the shit is well and truly in the fan, in terms of oil available for import to the USA, which will probably come to pass within the next couple of decades, barring the technocopians being right in predicting electricity displacing oil, well

We have both economic and military muscle enough , assuming we wise up about globalization , and don't export the rest of our industrial base, to INSIST on oil being sold to us , although getting it for dollars will be harder from year to year.

Saudia Arabia will never be self sufficient in food until the population there falls by what, eighty percent or better? If anybody will have the capacity to export food on the grand scale, it will be the USA.

And if anybody has a military umbrella under which smaller and less powerful countries can shelter at relatively low risk of the people there being treated like convicts, it will be the USA.

This is not to say we have been or are altogether NICE about the way we treat our allies, but compared to other countries, we stack up pretty well in this respect.

Nothing will move on the world ocean for quite some time if Uncle Sam finds himself in a corner where in his own interests indicate that nothing moves.

Of course considering that ninety percent of the leadership in China consists of engineers and scientists, where as ninety percent plus of western leadership consists of lawyers and other mostly parasitic types, it 's only a question of WHEN, rather than IF China will be a military superpower, and maybe the SOLE super power.

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

We need to account for the fact that shale oil production was supported by junk bond issuance. The loss on shale oil junk bonds is not that big: the U.S. energy companies have defaulted on ~$40 billion in high-yield bonds in 2016, more then doubling the $15 billion for 2015 according to Fitch. But they do affect future junk bond issuance

What is interesting is that MSM stopped talking about shale junk bonds in 2015 as if they got some order from above 🙂 Most warnings are from 2014, some from 2015:

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

In this sense, even $ 63 might be too low, if loans became more expensive and well servicing costs continue t0 rise. Printing junk bonds is a necessary side effect of shale oil production and this is now definitely more expensive activity then before.

I think that the return to profitability for shale at oil prices below $70 bbl is very problematic.

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

We have now graphed the whole of BP oil production and consumption and calculated the net export balance which is not in decline but it has been flat since 2005.

Verwimp says: 02/17/2017 at 5:00 pm
Nice, Thanks!
The net exports available on the global oil markets are some 60% of the total production. In the case of dropping global oil production it will take a while for the markets to dry out. If you make this same exercise on coal and gas, you get different numbers. Only a tiny fraction of global coal and gas production is available on the global markets. Dwindling global production will result in disappearing global markets in a very short time frame.

[Feb 21, 2017] Is The Bakken a Bust

Feb 21, 2017 | peakoilbarrel.com

Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production down 92,029 bpd to 942,455 bpd. It was noted that this the largest decline ever in North Dakota production. But it should not be overlooked that the October in crease in production was also the largest ever increase in North Dakota production.

Guy M says: 02/16/2017 at 11:37 am
EIA wildly optimistic in Bakken, Gulf and Texas. Their current numbers have to be way high in relation to what is actually happening. Even Texas RRC site is not predicting an upturn until current permits and completions get a lot higher. At $53 oil, it is not happening, or going to happen.
Heinrich Leopold says: 02/17/2017 at 5:23 am
George Kaplan,

In my view there is simply a cost issue here. If a well goes from 100 barrels to 20 barrels per day, the mainenance, operating and transport costs go up fivefold per barrel, even if they are the same for the well. So, it might not pay off to send a crew there and pay for transport. Unless, the oil price does not go up, these wells and many more wells are likely to shut down for a while.

GreenPeople's Media says: 02/16/2017 at 8:20 pm
I saw a recent story about the rise in the cost of fracking to completion for these DUC wells. Costs are said to have risen to something like $3.2 million in some of the areas where wells need completion. I believe the Director's Cut said last month there were 86o wells awaiting completion. If the story I read was true, then it will be around $2.8 billion to frack those 860 wells. I don't know what the cost of getting a well to the DUC stage is, but it sure seems a lot of money to have sunk in the ground for wells that will be outputting just 100 barrel a day after their first 24 months.

Is my thinking fuzzy on this?

Phil Harris says: 02/16/2017 at 12:13 pm
Bruno Verwimp wrote back in 2016, September 16th, " .Hold your breath for the next winter. It might bring severe decline in oil production in ND Bakken ."

I wrote at the same time: " FWIW my 'money' is on Verwimp's observation and model for the Bakken. I for one will be interested to see your chart next spring!"

Another 3 months will be interesting. By the look of it, it might well be down to 700,000 bpd in a year if the uncanny accuracy continues. As I understand it, his chart has nothing in it derived from price.

Javier says: 02/17/2017 at 6:31 am
That is correct. Verwimp's model has no oil price input. This is a serious problem since everybody recognizes that oil price has been determinant in the current oil situation. Therefore one can only conclude that Verwimp's model is accurate due to chance, and therefore has no predicting capability. It will continue to be accurate until it doesn't. It probably represents oil production decay in the absence of sufficient economical incentive.
Dennis Coyne says: 02/20/2017 at 3:22 pm
Hi Verwimp,

Geology absolutely plays a role, especially when oil prices are relatively high it is clear which fields are constrained by geology. When oil prices fall by a factor of 3 or 4 fields that are not constrained by geology will decline due to economic constraints (poor profitability.) The Bakken only increased in output due to high oil prices and a high well completion rate. Eventually geology will be the reason for Bakken decline, low oil prices clearly are the reason at present.

In Jan 2018 your model predicts about 680 kb/d for ND Bakken/TF output. My 61 well model predicts about 818 kb/d in Jan 2018 and the 85 well model predicts 900 kb/d in Jan 2018, I expect ND Bakken/Three Forks output will be around 825 to 900 kb/d in Jan 2018, with a best guess of 866 kb/d (847 kb/d in Dec 2018). This corresponds to a 75 well model, chart below.

djtxyz says: 02/16/2017 at 1:44 pm
A big contributor to the legacy oil decline is the unrelenting physics of fluid phase behavior, with gas becoming more prevalent in the production stream. Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The legacy wells will be worse (i.e. the newer wells dampen the effect, which have an initial GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is considered a "gas" well or field.

Most of these LTO fields will eventually be abandoned as gas fields.

note – I tried to post a *.png graph, but the reply tool failed.

Fernando Leanme says: 02/16/2017 at 4:20 pm
Is the 2000 GOR a North Dakota convention? There's no reservoir engineering reason to designate a depleted well as a gas well when GOR increases to 2000 scf/bo. Depleted oil wells under depletion drive do experience very high GORs, but they remain oil wells.
Boomer II says: 02/16/2017 at 4:51 pm
Here's a link that says in Texas there are tax advantages in reclassifying an oil well as a gas well.

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

Watcher says: 02/17/2017 at 1:11 pm
My recall is there's a regulation in Texas that classifies liquids from a gas well as condensate vs oil from an oil well. Almost certainly has some tax consequence.
Boomer II says: 02/17/2017 at 1:37 pm
This has been my philosophy for decades. Preserve our own resources and use up everyone else's until they run out.

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

Munger would have us import oil and gas now from OPEC so that we can save our oil and gas for the future when the world is going to have major shortages."

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

People Are Not Stupid.

The day comes when a firebrand is in control and dares to rock the societal systemic boat by declaring the price of oil will be non monetary. You want oil from Russia, America? Disarm. You want oil from KSA, America? Convert to Islam.

"We have enough of your dollars created from thin air. Let's have something of real value to us before we send you oil. The price is described above."

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

Notable quotes:
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
Feb 21, 2017 | peakoilbarrel.com
Rune Likvern says: 02/19/2017 at 1:04 pm
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require the addition of an average of about 95 wells/month (61 wells/month were added through 2016).

In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent. This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus a steeper decline in production.

Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI).

To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return.

Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B.

Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets.

At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells.

For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations.

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

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

Notable quotes:
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
Feb 20, 2017 | peakoilbarrel.com
Rune Likvern says: 02/19/2017 at 1:04 pm
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require the addition of an average of about 95 wells/month (61 wells/month were added through 2016).

In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent. This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus a steeper decline in production.

Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI).

To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return.

Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B.

Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets.

At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells.

For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations.

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

[Feb 20, 2017] Is The Bakken a Bust

Feb 20, 2017 | peakoilbarrel.com

Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production down 92,029 bpd to 942,455 bpd. It was noted that this the largest decline ever in North Dakota production. But it should not be overlooked that the October in crease in production was also the largest ever increase in North Dakota production.

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

Feb 20, 2017 | peakoilbarrel.com
Nathanael says: 02/15/2017 at 1:15 pm
If I'm not mistaken, this means that the North Dakota production (BPD) is now only slightly more than than the existing pipeline capacity leading out of North Dakota (BPD), which is 851,000 at the end of 2016. Production will probably be down to the existing pipeline capacity by March.

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

Now this isn't quite comparable because part of the Williston isn't in North Dakota, so I'd have to look at the Montana numbers. But still, it looks likely that the moment Dakota Access is built, there will be a pipeline capacity glut.

So is the Dakota Access Pipeline going to be half-empty, or will some of the other pipelines be empty and go bankrupt? They're fighting over market share in a surplus-capacity environment.

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

Feb 20, 2017 | peakoilbarrel.com
HVACman says: 02/16/2017 at 2:04 pm
"The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%"

The estimated EUR's appear VERY high for Bakken wells by my untrained eye. Any thoughts from the resident experts?

George Kaplan says: 02/16/2017 at 3:21 pm
I am certainly not an expert on tight oil but see above. If they get 30 to 40% extra from gas I think they might make it (GOR of 1500 adds 25% I think, and it looks like it will be more than that for most wells). What I don't get is a 'previous average' of 850,000. There's not even one well that looks like that at the moment, based on Enno Peters' charts.
AlexS says: 02/15/2017 at 5:41 pm
Even more striking declines in drilling/completion activity for individual operators.

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

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

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

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

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

"The Company plans to complete 131 gross (100 net) operated wells out of its Bakken uncompleted well inventory with first production commencing by year end. In addition, Continental plans to complete with first production approximately 17 gross (8 net) newly drilled Bakken wells in 2017. At year-end 2017, the Company expects to have 140 Bakken wells in inventory, of which 72 gross (40 net) wells will have been completed but waiting on first sales and 68 gross (47 net) operated wells will be waiting on completion.

The Company also plans to participate in completing 40 net non-operated wells in 2017, 35 of which will be in the Bakken.

Continental expects to grow Bakken production by approximately 26% in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.

Approximately $550 million, or 70%, of the operated Bakken capital investment in 2017 will be focused on completing wells from the Company's uncompleted well inventory. The Company has five stimulation crews working currently and plans to average seven crews for 2017 as a whole.

Continental plans to apply various enhanced stimulation techniques on all Bakken completions in 2017 to define the optimum designs for future completions. This includes larger proppant loads, diverter technology, shorter stage lengths and shorter cluster spacing. The Company is also applying high-rate production lift technology to accelerate fluid recovery and early production rates. Combined, these techniques add an average of approximately $1.4 million to the previous standard enhanced completion cost of $3.5 million.

For the uncompleted well inventory, the average budgeted completion cost for the larger enhanced completion is approximately $4.9 million per well. The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of 980,000 Boe per well, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%.

The Company also plans to maintain four operated drilling rigs in the Bakken throughout 2017 and drill 101 gross (57 net) operated wells, with 17 gross (8 net) of these wells completed in 2017 with first production. The 17 gross wells will have an average budgeted well cost of approximately $7.0 million. The average EUR for wells drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price of $55 per barrel, these wells should generate over a 40% rate of return."

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

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

According to Enno, an average Bakken well gives about 200k+ of oil, not 900k. It looks like it's much more gas than oil, or the numbers are completely bogus. Or they have bought the sweetest center of all sweet spots in Bakken?

Questions over questions

AlexS says: 02/16/2017 at 8:21 am
As of 3Q16, oil accounted for 61% of total CLR output.
Apparently, oil's share in CLR production in the Bakken is higher.

According to Enno, CLR Bakken wells with the first flow in 2014 have on average already produced > 200kb of oil. Their average EUR may exceed 400 kb and probably reach 500 kb.
Wells with first flow in 2015 and 2016 perform better.

That said, even including gas, EURs of 900 kboe look unrealistic

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

I have mentioned company proved reserves and PV10 quite a bit here in the past two years.

I am coming to the opinion that these numbers, required by the SEC, have too many uncertainties to make them worthwhile, at least as to PUD. PDP may be useful.

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

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

George Kaplan says: 02/16/2017 at 11:14 am
They appear to have been increasing well performance since 2014, maybe getting above 400k for oil if the curves continue (as below). It looks like they recomplete after some time. It will be interesting to see how the two 2016 curves go – started high and then the first took a dive. The late 2015 wells did the same and then jumped up, which looks like a re-completion. How much area does one of their new wells drain? Presumably the savings must mostly be on reduced drilling and completions cost, and maybe front loading the returns with higher initial production, not overall additional recovery.

Marathon announced today they'd have six rigs average this year – up one – not sure if that is enough to hold the decline near present levels, mostly that depends on completions rather than rigs though, but they are going for "multiple enhanced completion trials" and expect to increase overall USA production by up to 20% (also six rigs in Eagle Ford).

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

[Feb 20, 2017] Bakken steep drop of production

Feb 20, 2017 | peakoilbarrel.com
Heinrich Leopold says: 02/16/2017 at 5:19 am
Bakken data were out yesterday and we have seen a steep drop below 900 000 bbl/d nearly 300 000 bbl/d below its peak of 1.164 mill bbl/d in December (see below chart). Well performance (new and existing wells) is down to a five year low of 83 bbl per well and falling -20% year over year. This means a cost increase per produced barrel of 20%, even if new wells are performing better and costs per rig are down.

Since the well production declines by -20% over two years now, costs per produced barrel are up 40% and rising fast. No wonder companies seem to abandon Bakken for less mature fields such as the Permian. New permits are at five year low and rig count is also grinding down slowly. Inerestingly, number of wells are also falling – down 100 wells in December – which has been deemed as impossible in some forecasting models.

[Feb 13, 2017] Mexican oil production is dropping

Feb 13, 2017 | peakoilbarrel.com
George Kaplan says: 02/11/2017 at 4:40 am
I looked at Mexico production by area as below. The numbers in brackets show percentage year on year change for exit rate 2016 to 2017. Only the small area in northern offshore, which is not LMZ or Cantarell, is not declining. Even KMZ looks like it might be turning over. If it goes like Cantarell as Nitrogen and or water start hitting the producers then the will be a big acceleration, if not then the decline might flatten out as the other fields make up increasingly less of the mix. The plateau that KMZ achieved after N2 injection was started is now quite long for an offshore field.

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

Notable quotes:
"... For the past eight years we were fed the constant stream of stories of mythical economic "recovery" and all the wealth created in this period from the bankers and economist. And as a result of all that illusory "wealth" retail sector was able to sell goods to consumers with empty wallets and maxed credit cards only by smashing prices to the bone – leaving almost nothing for the profit. ..."
"... Imagine the state of economy without this extra unconventional 5-6 mbd and $100 per barrel as a consequence. ..."
Feb 13, 2017 | peakoilbarrel.com
Ves says: 02/10/2017 at 4:16 pm
Steve,
Oil industry, and particularly Shale & Oil Sands part, lives in hope for the last 3 years. And that is not reality, because hope means dream. Unless someone's live in reality, here and now, they are dreaming. They are dead weight, and tomorrow which will fulfill all their hopes is never to come.

Shale and Oil Sands are mostly North American origin of production with 5-6 mbd. where we have the most consumption per capita in the entire world.

For the past eight years we were fed the constant stream of stories of mythical economic "recovery" and all the wealth created in this period from the bankers and economist. And as a result of all that illusory "wealth" retail sector was able to sell goods to consumers with empty wallets and maxed credit cards only by smashing prices to the bone – leaving almost nothing for the profit.

Imagine the state of economy without this extra unconventional 5-6 mbd and $100 per barrel as a consequence.

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

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

I disagree that it implies subsidies. What is implied is that when oil is scarce, the price of oil will increase and more of the expensive oil will be profitable to produce. Eventually the high oil price will lead to greater efficiency in the use of oil (as measured by real World GDP per barrel of oil consumed) and also some substitution of natural gas, and electricity for oil in the transportation sector and after 10 to 20 years demand for oil might fall below the supply of oil and lead to lower prices.

My main point is that the supply of oil depends on profits, not on net energy or exergy of the oil produced. Profits will depend on revenue minus costs and revenue will be determined by the oil price which is a function of both supply and demand for oil.

likbez says: 02/12/2017 at 10:43 pm
There is strong evidence that the US economy can survive only oil prices below $100 per barrel without sliding into recession. Some researchers put this magic "perma-stagnation" oil price as low as $60 per barrel. I think understanding of this fact is partially behind this prolonged "oil price crush".

So it might well be that we do not have the freedom of "arbitrary" oil prices in the US economy. and in worst case scenario we have oil prices already close to the celling, unless the economy is restructured.

That's why your line of thinking about this problem might be wrong. In other words, this is a very serious situation for the USA. "The long emergency" as James Howard Kunstler aptly called it (not that I agree with his line of thinking or endorse his book).

Meanwhile the US is wasting time and money on the wars of neoliberal expansion, which partially is "brut force" way of securing privileged access to remaining oil deposits. Around 5 trillion was spent so far, or 167 millions of Toyota Priuses at $30K per car, or half of the US passenger fleet (there were 260 million registered passenger vehicles in the United States in 2014)

So instead on concentrating on this fundamental problem that nation is facing, the USA is just "waiving dead chicken" with the military force. If we add the possibility of Seneca cliff that situation might be even worse then I described. The nation does need radically cut the amount of oil spend on personal transportation. Using all ways for this that are technologically feasible. Because this is the lowest hanging fruit. But very little was done in this direction on both federal and state levels.

Meanwhile we expanded the fleet of SUVs for personal transportation - this is now the most popular "form factor" for personal car, which overtook sedans. Growth of the fleet of hybrid cars is unacceptably slow (over 4 million units sold through April 2016; Japan, a much smaller and compact nation, sold 5 millions).

Even such a symbolic act as switching of all personal government cars to hybrids was not done by Obama administration, which preferred only talk about the problem and opened spigot for shale junk bond. The only their "real" achievement was "Iran deal" which probably was instrumental in crashing oil prices. Which probably helped Obama much more than it helped the USA economy as whole, but we should not inspect the teeth of the horse that was given as a gift, as old saying goes.

Also attempts to lessen huge traffic jams in large cities like NY and SF are feeble, despite the fact that the technology is available both to reroute the cars and to optimize traffic lights.

Converting existing roads network into "one way" network is almost unheard outside the city center, even when two more or less adequate parallel roads exists with the short distance of each other.

Variation of the number of lines each way is practiced very rarely, in some city centers and selected bridges.

Green wave for traffic using Wifi connections between traffic lights and cameras is in a very rudimentary stage.

The only progress that I noticed is that more and more traffic lights at night autodetect the presence of the car on intersection and switch to green light if there is not traffic in "main" direction.

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

Feb 12, 2017 | peakoilbarrel.com
Rune Likvern says: 02/11/2017 at 4:31 pm
From what I have seen it is generally accepted that EROEI for FF has been and will continue (lots of peer reviewed papers documenting this) to be in a downward trend. Then it is open for projections how fast this downward trend will develop and its consequences.

What matters is net affordable energy that will be made available for societies.
In the short term it is about flows, longer term; size and quality of remaining stocks.

Selling assets to pay down dividends/buy back stocks is liquidation.

Further up in this post Nathanel shared some great insights;

"Personally, from my background in general financial analysis, the two really big metrics I've been watching lately: Dividends in excess of current earnings mean a company in decline. Borrowing money to pay the dividend means a company which is in unmanaged, uncontrolled decline. (Managed decline would involve liquidating assets to pay dividends, and *paying off* debt.) "

"Look at what they do and not what they say."

Several big oil companies have used money for stock buy backs, but another trend I found interesting is also how they move into renewable (solar and wind). This should be an indicator about what these companies find profitable.
Just to be clear, I think renewables are great, but we also need to recognize the dominant role of FF.

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

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

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

Feb 10, 2017 | peakoilbarrel.com
George Kaplan says: 02/09/2017 at 4:12 pm
I had trouble following the logic – one line seems to be that investors continue to put money into oil companies because they (the investors) believe in abiotic oil. I'm pretty sure that is wholly incorrect.

I don't get why the recent uptick in USA production (much of which was due to GoM projects that had been started several years ago, not just from shale drilling) has got anything really to do with the losses of the companies highlighted. Is the suggestion that without that uptick investors would have suddenly realised that all the oil companies are going down the toilet? I'm pretty sure that's wrong as well.

LTO is still a relatively small part of ExxonMobil and Chevrons portfolio (note if you look only at the upstream parts of those companies the losses actually have been worse than shown, they were saved by downstream profits). The losses are because of over investment leading to a supply glut. There has been almost no impact from falling global demand. The over investment was in all sections not just in LTO. LTO stands out because the supply can be seen to clearly increase over the past few years, but it had not much more impact than oil sands (also showing a clear increase) or in fill drilling in Russia and Opec ME, which just acted to stop decline, and therefore doesn't stand out so much.

That ETP thing gets thrown in but, apart from being wrong in many different ways, doesn't seem to be linked to any of the other observations or conclusions.

I like the charts though.

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

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

Negative cash flow does not automatically translate into unprofitably if CAPEX is a big portion of it.
There are no doubts that oil companies have taken on more debts, but it would be more helpful if debts were presented on a specific basis that is $$ of debt per barrel of oil (or oil equivalent) of reserves.

So far I cannot see the author has made any real attempts to explain the thermodynamic oil collapse.

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

Good to see you woke up from the DEAD. Haven't seen you posting much. Glad to know I am able to get you out of BED once in a while.

Anyhow . I would imagine we can use any financial metric to show how profitable or unprofitable a company is by relating it to this or that metric, but in the end the figures speak for themselves. The U.S. Major Oil Industry is in big trouble. Hell, the majority of the economy and financial system is one big BUBBLE looking for a PIN.

Regardless, ExxonMobil and the rest of the U.S. energy sector is in serious trouble. While ExxonMobil only has $29 billion in long term debt, their total liabilities are $169 billion.

There's lots of garbage hidden in these companies that most investors tend to overlook.

steve

[Feb 09, 2017] Comparing well performance in the Permian and the Eagle Ford, it seems that average IP rates are not that different (582 b/d and 510 b/d, respectively, in the second month of production), but declines in the EFS are much steeper

Notable quotes:
"... Furthermore, well productivity in the Eagle Ford is detereorating over time compared to the wells drilled in previous years, which may suggest that longer laterals and bigger fracs result in only slightly higher IPs but much steeper declines. ..."
"... By contrast, new wells in the Permian continue to perform better than older wells. ..."
"... That may explain why drilling/completion activity and LTO production in the Permian have remained more resilient and are quickly recovering; while EFS has seen the biggest decline in production among the key LTO plays. ..."
Feb 09, 2017 | peakoilbarrel.com
Enno Peters says: 02/07/2017 at 8:40 am
Alex,

"There is no data on average well quality for the wells that started production in 2016. Is that because the data for last year is incomplete?"

If you go to the "Well quality" tab in the first presentation, you'll see 2016 profiles as well.

The "Ultimate Recovery" overview only supports displaying production histories for wells of the same age. As there are still 2016 vintage wells on which I have no data (the ones that started in Nov/Dec), 2016 is not yet shown if you display it by "Year of first flow".

However, if you change the selection to "Quarter of first flow", or "Month of first flow", then you will see more recent data as well, incl 2016.

You may remember past discussions here where we discussed displaying or omitting incomplete tails in the well profile graphs. The Well Quality tab can show incomplete tails, while the Ultimate Recover tab can't.

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

I just found that the number 2016 in the legend was hidden.

Comparing well performance in the Permian and the Eagle Ford, it seems that average IP rates are not that different (582 b/d and 510 b/d, respectively, in the second month of production), but declines in the EFS are much steeper.

As a result, by the tenth month, average well in the Permian produces 210.7 b/d, and in the EFS only 122.6 b/d.

Furthermore, well productivity in the Eagle Ford is detereorating over time compared to the wells drilled in previous years, which may suggest that
longer laterals and bigger fracs result in only slightly higher IPs but much steeper declines.

By contrast, new wells in the Permian continue to perform better than older wells.

That may explain why drilling/completion activity and LTO production in the Permian have remained more resilient and are quickly recovering; while EFS has seen the biggest decline in production among the key LTO plays.

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

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

"In a somewhat related aspect, I've not seen an updated graphic from Rune on the cash flow from major Bakken operators.
I've always felt that single frame told a very powerful tale, but not so much pessimistic as one might think."

The chart likely referred to looks at Bakken(ND) as one entity and below is an updated chart as per November 2016 and instead of monthly free net cash flow it has now been annualized (last 12 months total free net cash flow) to enable the same units on both axis.
For all 2016 the companies in Bakken will use about $2,500 Million more than their free cash flow from operations (this is by not including the effects from natural gas sales).

Using Billions = 1,000 Millions on one axis and Millions on the other may be deceptive.
Average gross specific interest cost is now at an estimated $7/bo.

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

Whoever holds that debt doesn't get repaid. What does that mean?

Nothing. If they are systemically vital to the global financial structure, the central banks (plural) will create the necessary money and GIVE IT TO THEM.

It doesn't have to mean anything. And further . . . if YOU were in charge of the situation . . . YOU would do exactly the same thing. You would create the money and GIVE IT TO THEM.

How could you not?

There's also another conceptual leap pending.

If that debt is NOT systemically vital to the global financial system, but IS systemically vital to flowing enough oil for civilization to function - that gets those debt holders bailed out, too.

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

whatever is the primary source of funds that flow to the LTO industry, if they still flow, LTO production will continue. The recent data suggest that inflows (in the form of IPOs, secondary share issuances, proceeds from asset sales, acquisitions by the oil majors and private equity firms, etc.) are again increasing. That means that investments in shale oil and gas will rise in 2017 and the next several years, and LTO production will rebound. And that will have an impact on the global oil market.

As regards (excess) money printing by central banks, it affects all parts of the economy, not just oil and gas industry. If there were no money printing, people would not be able to spend thousands of dollars on electronic gadgets; cars, including EVs; solar panels, wind turbines, etc.

Ron Patterson says: 02/06/2017 at 4:52 pm
If they are systemically vital to the global financial structure, the central banks (plural) will create the necessary money and GIVE IT TO THEM.

I guess that's what happened to the sub-prime mortgage crisis. The banks were "systemically vital to the global financial structure". They all got bailed out. But the purchasers of those sub-prime mortgages, mostly pension funds and such, were not considered vital. They got nothing!

Rune Likvern says: 02/06/2017 at 6:45 pm
Watcher,
You should write a post and ask for it to be posted on POB where you lay out what it is we do not get.
I for one did not get the memo on central banks omnipotence.

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

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

=

Lower emissions

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

Yet backwards placing like Europe and NY ban fracking.

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

Chris G -> B.T.... , January 23, 2017 at 09:27 AM
Setting aside ground water contamination issues associated with fracking, barring a major reduction in per capita energy use even if (when) you replace coal with natural gas the CO2 emission rate is still a problem. Switching to non-fossil fuel sources needs to be on the to-do list.
B.T. -> Chris G ... , January 23, 2017 at 09:44 AM
EPA said fracking isn't having "widespread, systematic impacts on drinking water."

Even with non-fossil fuel sources, C02 emissions rate will still be a problem. You still need to build the wind turbines and transport them to locations, you can't get do that until the transportation sector reduces emissions.

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

My impression is that the current price of natural gas in the USA is unsustainable. It is a kind of "subprime gas".

A side effect (externality if you wish) of fracking is junk bonds bubble. At one point anybody with a lease can get a loan to drill. Not that different from subprime, just much smaller. Many people are not aware about it.

-->

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

Jan 23, 2017 | economistsview.typepad.com
libezkova : January 23, 2017 at 01:26 PM , 2017 at 01:26 PM
It might well be that "human induced climate change" enthusiasts are barking to the wrong tree.

Oil depletion might take care of the "climate change" (as well as "excessive" humans) even without Trump or and other politician. This is probably a matter of a decade or two.

The key here is proactive switching the use private car fleet to more economical model and without draconian measures such as $4 per gallon gas or $1K per cubic centimeter of engine volume tax the process is very slow.

Obama administration was pretty inactive in this area, despite all rhetoric.

There is no justification of using full size SUV or light truck for communizing to work unless you agree to pay extra for this privilege.

-->

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

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

Cumulative total of Bakken Formation oil production.

One billion of those barrels produced in the past five years, four billion barrels to go with the projected 5.7 billion recoverable, another 20 years of production in the pipeline to go.

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

Click on cumulative totals by formation.

By 2035, the Bakken oil will be about done, can't get anymore.

75 new wells per month, 12×20, 240×75=18,000 more wells over twenty years time.

The price of oil at 50, 4.5 billion barrels of oil, 225 billion dollars.

5,000,000 dollars of cost per well, 90,000,000,000 dollars invested in drilling those 18,000 new wells, 400,000,000 barrels for the extraction taxes, money for the state, 20% for royalties, 80,000,000 barrels for mineral owners, 480,000,000 barrels to keep everyone happy all of those years.

The oil companies can keep 3.52 billion barrels to sell to get them some money.

Times 50 USD per barrel to assess a value, 160,000,000,000 dollars in future income to pay the 90,000,000,000 dollars owed for oil wells drilled. After twenty years of production you will have 70,000,000,000 dollars left over for the buzzards to pick clean.

A measly 3,500,000,000 dollars per year for the oil companies to share. 350 oil companies working, ten million dollars to share amongst stockholders and employees.

The price of oil has to be more or the Bakken will slow to a crawl, then an end.

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

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

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

Jan 11, 2017 | peakoilbarrel.com
Watcher says: 01/10/2017 at 11:36 am
What % of US oil consumption is food transport? This got tricky quickly.

Average US person eats about 5.4 pounds of food a day. That's just the food. Average meal travels 1500 miles to reach your mouth.

First tricky item - packaging. It has to transport, too. Amazing variance on this. Glass jar of pickles vs paper around candy bars. The only estimate out there is numbers for municipal solid waste and estimates of % of that is food packaging. Year 2000 US waste generation 4.5 pounds/day/person, and growing. Probably over 6 by now based on the curve, but will use 5 lbs/day cuz round number.

31% of that is packaging and half of that number is food packaging. Some 2006 study. So 15% of 5 lbs a day is 0.75 pounds added to the 5.4 pounds of food is 6.15 pounds shipped a day per person.

For 1500 miles.

Eyeballing some charts looks like typical/average truck hauling weight for stuff hauled is 60,000 lbs. Typical diesel mileage 6 miles/gallon.

6.15 pounds X 320 million mouths = about 2 billion pounds of food moved each day
1500 miles / 6 = 250 gallons truck burned
2 billion lbs / 60,000 lbs = 33,333 truck trips X 250 gallons/truck trip = 198.4K bpd to move food.

Ain't much. Maybe there's an error in there. Top of my head . . . things not included, hauling spare parts for the food moving trucks, spare parts for the packaging gizmos, plastic packaging, agricultural consumption itself.

[Edit] Blurb says 17% of total US oil use is agricultural, up and downstream (fertilizer plus fuel). This would be far more than food transport.

Oldfarmermac says: 01/10/2017 at 12:26 pm
I am suspicious of that fifteen hundred mile figure, but it may be accurate. Or it may have assumed a life of it's own, after being tossed out by one or two people who really just guessed at it.

Most of the food that is produced in truly huge amounts, staple food, is shipped by water, and or by rail, if it travels a LONG way. A VERY limited amount of food, in relation to the total amount, is air freighted.

Here in the USA, it's not too likely that very much in the way of unprocessed or processed staple food is shipped more than a thousand miles by truck. Exceptions will be mostly fresh high retail value produce, shipped as directly and quickly as possible from grower to retailer.

The REAL food miles come at the very tail end of the distribution chain. I never owned an eighteen wheeler, but I did once own a C70 Chevy which would legally haul about sixteen thousand pounds of apples to market. The farthest local growers usually go with their own truck of this sort is about a hundred miles, one way. Thirty gallons of diesel would take me that far, and home again.

The people who actually bought my apples at retail, after they were picked up at the wholesale market and delivered around town in smaller trucks, usually bought no more than five pounds at a time.

I'm guessing, pulling numbers out of my hat, but I suppose a typical shoppers average grocery purchase weighs from about twenty five to thirty pounds, up to a hundred pounds,depending on family size, and is made on roughly a weekly basis, on average.

And I'm guessing that the average trip to the super market is at least six to ten miles, round trip. THAT's where the food miles really pile up. A liter of gasoline burnt to get fifty pounds home, the last five miles, times around a hundred million households, times fifty weeks, adds up. FAST.

Watcher says: 01/10/2017 at 1:58 pm
Maybe. The pickle jar weighs a LOT and there's not much food weight part of that. The whole packaging thing is a significant thing, and that's another food item I didn't include, disposal of it.

I'm going to guess the 1500 mile thing came from the coasts' pop centers and their daily bread from Iowa and Nebraska. The various websites talking about this like to talk about a head of Imperial Valley California lettuce going to England. X calories burned for 1 or two calories delivered to the mouth. But that sort of thing definitely would drag the average up. 1500 miles maybe is legit.

I am surprised the total transport is south of 1 mbpd, if it truly is. As for shipping, I can't see Iowa bread going to NYC any way but by truck. Not going to fly it there. And the canals don't reach.

Everybody driving the last 5 miles to the store . . . maybe that really doesn't show in the diesel calc. Oh! Of course. The issue is not diesel. It's the 60,000 pounds per trip. A car is carrying the much lower weight per your estimate. Will redo.

Watcher says: 01/10/2017 at 3:20 pm
14 billion pounds of food move the last 5 miles by car per week, probably at 150 lbs per weekly load (family of 4 at 6 lbs/day/mouth incl packaging)

14 billion / 150 lbs = 93 million car trips per week.

5 miles in a 25 mpg car is 0.2 gallons. X 93 million /7 and /42 = an additional 63,000 bpd from the car trips added to the trucks above. About 260K bpd for food transport.

Hmmm of course if it's 5 miles each way that's a X 2 on the 63K. And SUVs for that trip, not a Datsun. Might be up nudging 400K.

Watcher says: 01/10/2017 at 8:07 pm
It occurs to me that Pepsi and Coke may not be food, and they are heavy.

I'm having problems with this 400ish K number because the famous 2004 pie chart of US oil consumption said 65% transportation, and of that 65% it was only 37% passenger cars, 18% heavy trucks and 27% light trucks (sums to 45%), and that was before SUVs (called light trucks) had swept up sales. Though F-150s may have arrived.

0.37 X 0.65 is only 24% of consumption. Trucks light and heavy rather more. So what are they hauling. Food as a daily consumable would seem to be the dominant hauled stuff, but apparently not.

Oldfarmermac says: 01/10/2017 at 5:18 pm
Most of the grain or flour that goes from the midwest to the northeast probably gets there by rail, where it will then be baked into bread, packaged, and shipped by truck to food distribution centers, or directly to supermarkets. But the distribution center food warehouse seems to rule these days, because it's better to load a truck up to the doors with a variety of stuff all destined for one address or maybe two or three, than it is to have a truck stop to deliver bread and nothing but bread to a bunch of different stores. That means a lot more total time and miles invested in stop and go driving, compared to the one stop load. That still happens, but not as often as in the past.

Grain is milled into flour near where it's grown, when possible, because this reduces total shipping costs, being that the weight and volume of flour is less than the weight of whole unprocessed grain, plus the tailings are used mostly in livestock rations, and customer for that product is most definitely NOT in NYC, lol.

Most of the cows,hogs and chickens we eat are raised in confinement, and are raised in the mid west and southeast, closer to the feed supply, and where land and water are cheaper, and neighbors less fussy, and mostly in localities where neighbors are relatively few in number.

Nobody's ever going to operate a modern supersize hog farm anywhere close to the BIG APPLE, 😉

clueless says: 01/10/2017 at 2:08 pm
Watcher's conclusion is probably right – not much fuel used to transport food compared to the total available. On the other hand, some random thoughts. 5.4 pounds/day/person is too high. Babies, young children, seniors, etc. Second, the 1500 miles is too high. Some of the basics make up a significant amount of the weight – like liquid milk, along with other dairy products, cheese and eggs. These products generally will never go 1500 miles. Vegetables, seafood, fruit, etc yes. But, chicken, pork and beef – I think that 1500 miles is too high.

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

Watcher says: 01/10/2017 at 3:16 pm
Pre oil, railroad cars had no refrigeration to speak of in summer months. That's where the term cattle car came from. Had to ship beef alive to the cities.

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

Oldfarmermac says: 01/10/2017 at 6:04 pm
I am not at all sure just HOW much of a cow winds up as nekkid ape chow these days, but YOU most definitely don't WANT to know much about what goes into processed meat products, if you plan on eating them.

Fifty years ago when I had the "insider tour" of a huge and extremely famous hog slaugher plant that you get only by personal invitation from management,even back then, they bragged about selling everything but the squeal.

I'm pretty sure that well over fifty percent of the live weight of a cow winds up as nekkid ape chow these days, but how much over I can't say. Fifty to fifty five percent would be a reasonable guess. Farmers have been breeding cows for more milk and meat, and less waste, since the beginning. For the last seventy five years or so, this breeding has been based on high tech such as artificial insemination, a solid understanding of genetics, and very sharp pencils. So a typical cow TODAY is going to yield significantly more more than she did a decade or two back.

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

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

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

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

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

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

Jan 08, 2017 | peakoilbarrel.com
AlexS says: 01/03/2017 at 12:23 pm
U.S. independent shale oil and gas producers are now cash flow neutral

From the IEA Oil Market Report:

"So far, the shale and tight oil industry has always been characterized by spending levels exceeding cash flow generated. Benefitting from the improved price environment (including a 50% natural gas price increase over the last six months), increased activity and enhanced cost efficiency, the US shale industry is now closer to being able to fund capex programs within operational cash flows. During 3Q16, for the first time in its history, the sector reached free cash flow neutrality. In other words, after more two years of very difficult times, the US shale business model seems on a much more sustainable path. Nonetheless, it remains to be seen whether companies can remain cash flow positive when the industry scales up activity and capital spending and as upward pressure on costs once again takes hold."

Free Cash FLow for US Independents* (USD billion)

* / Free Cash Flow has been calculated analyzing balance sheets of about 50 US shale operators, having more than 80% of their revenues coming from shale activities and covering over 60% of US tight oil and shale gas production

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

Operating cashflow = net income excluding all non-cash items: depreciation and amortization; asset writedowns; gains and losses on asset sales, etc.
Operating cashflow includes only those interest expenses and taxes that were actually paid during a certain period and differ from "nominal" interest expenses and taxes that are shown in income statement (as interest can be capitalized, tax payments can be delayed, etc.).

In my view, operating cashflow is a better metric of oil and gas companies' operating results than net income.

Free cashflow shows what is left in a company's coffer after it has spent part of its cash on organic (non-acquisition) capex.
Negative free cashflow means that the company has to borrow money to cover its expenses.
Positive free cashflow means that the company can pay down part of its debt or keep free cash on its accounts.

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

Unlike oil majors, which tend to spend a significant part of their cash on dividends and repurchase of their own shares, U.S. E&Ps normally do not pay or pay relatively small dividends.

The above chart from the IEA monthly report shows that the group of 50 largest shale companies have finally achieved free cash flow neutrality in 3Q2016, which means their quarterly operating cashflow is roughly equal to the sum of their capex and dividends.

That was due to a sharp reduction in capex and lower costs.

I came to similar conclusions, as the IEA, after looking at 2Q and 3Q results from a few large U.S. shale companies.(Of course, my sample group was much narrower than 50 companies).

Mike says: 01/03/2017 at 9:31 pm
The shale oil industry has been in positive cash flow situation since prices got above 40 dollars a barrel. Sorry, this is a meaningless assessment of a meaningless article. Positive cash flow basis to what extent, exactly?

"Free cash flow (two words) shows what is left in a company's coffer after it has spent part of its cash on organic (non-acquisition) capex." Negative. This implies that all wells being drilled by the 50 shale oil companies referenced are now being paid for out of positive cash flow. I don't think so. If so, at the expense of deleveraging, so what?

"Negative free cash flow (two words) means that the company has to borrow money to cover its expenses." Define expenses, please. Including developmental CAPEX?

"Positive free cash flow (two words) means that the company can pay down part of its debt or keep free cash on its accounts." Right. Give me a percentage of the total 50 shale companies surveyed that paid down debt in 2016 and to what extent, please. Last I looked even EOG did not have COH to cover this years maturities.

"The above chart from the IEA monthly report shows that the group of 50 largest shale companies have finally achieved free cash flow neutrality in 3Q2016, which means their quarterly operating cash flow (two words) is roughly equal to the sum of their capex and dividends." How many of these stinking shale oil companies even pay dividends? Come on, Alex. That's BS and you know it. List the 50 and show their losses for 3Q16.

Shallow is right, positive cash flow fills the coke machine down the hall, for the first time in 25 months, that's it. If these shale guys are using cash flow to drill more stinking wells, they are doing so at the expense of deleveraging legacy debt. The marginal price per barrel of shale oil is a meaningless metric now. All of these guys are up to their asses in debt. Folks have got to let this ridiculous IEA, EIA, SPCA and NCAA bunk go and get planted on earth about this shale oil stuff. Nothing has changed in the past 5 months except that OPEC added 5 dollars a barrel to the bottom line. Temporarily.

shallow sand says: 01/03/2017 at 11:38 pm
I guess our goal every time we have borrowed money to buy an asset, be it an oil lease or otherwise, was to pay down the loan principal to zero.

Further, we have not borrowed money to drill or work over wells.

Currently, in the commodity spaces I am familiar with, most asset values are still high, despite much lower commodity prices (grains, oil and natural gas).

I assume increasing interest rates may change this, but maybe not?

We looked at a small oil lease recently. It was priced as if the price of oil was a steady $80. It sold for the asking price. In the first quarter of 2016 the lease lost money on an operating basis. It was barely cash flow positive for 2016. Fifteen years ago, the same lease, being also barely cash flow positive in 2001, would have sold for 1/10 of the current sale price, IMO.

Witness record acreage prices paid in the Permian earlier this year.

Farmland is the same. Grain prices are down for the third year, yet land is barely off highs. Net cash rental income, after payment of real estate taxes, is 2.5% or less. This is pre-income tax returns.

I am not smart enough to know what this means, or what one should do in this situation, unfortunately.

I will say, however, I believe few now have the goal of buying assets and paying the debt down to zero. It appears commodity assets are now about leverage, churn and other ways to make money from them, besides from the income produced by the assets themselves.

One area that I think will only get worse is commodity price volatility. I read a long article recently about this with regard to grain prices, written by a large, well respected farm management company. They have really put an emphasis on marketing, they say farmers that don't aggressively hedge will have a tough time.

This I believe is true for oil and gas too. Unfortunately, the cost to hedge has risen dramatically. I recall buying put options near the market for under a buck a barrel around 12-14 years ago. Those now go for $4+.

AlexS, I do not think operating cash flow is the only metric to look at. If we had paid $150K per barrel in 2013 with borrowed funds, the fact that we have had positive operating cash flow in 2016 would be of little solace.

I contend there is mucho debt in the industry that will continue to be "rolled", little will be paid through net operating income. However, much may be paid through equity issuance.

I sure hope the upstream oil and gas industry is not a microcosm for the whole economy. I'm not smart enough to know that either.

Nathanael says: 01/05/2017 at 10:09 pm
"I am not smart enough to know what this means, or what one should do in this situation, unfortunately."

That's fascinating data, "shallow sand". This is the sort of information I love to get so that I can analyze it, so I'll give it a shot. This is first pass.

I think we're watching a bubble. This smells like bubble.

(1) There is too much money among very rich people chasing too few good investments. Accordingly, the prices of investment products are getting bid up in a bubble.
(2) The bubble in oil, in particular, will burst as they see how terrible the rates of return are.
(3) The middlemen and speculators are of course exacerbating the bubble; they always do.
(4) When the bubble bursts, a lot of wealth will "vanish" overnight. It is best to be out of it before it bursts - sell at the top of the bubble if you can, and switch to something which is selling with less inflated prices.
(5) Farmland might be the same sort of bubble. The other possibility is that it might not have the same bubble behavior: its value might increase - if you get the right farmland, farmland which is likely to continue to do well despite climate change - as there are definitely predictions of droughts and crop failures coming in the next few years.
(6) Because of the excess of investment money, it may be impossible to find anything you're comfortable with which isn't selling at inflated prices, sadly. Paying off debt is an option if you have debt. Or insuring yourself against liabilities (are all your well capping and clean-shutdown costs prepaid?). That sort of thing.

Watcher says: 01/04/2017 at 11:53 am
Clueless should weigh in. I've seen the definition get massaged here and there.

Cash flow is inputs and outputs, and while SS is asking about interest above, that's not the debt focus. New borrowing can be called a cash influx. I've seen it done. New borrowing improves cash flow over a period measured. If you define it that way, you can borrow your way to prosperity.

(Look familiar, OMB?)

clueless says: 01/04/2017 at 12:54 pm
Watcher is mostly right. For example, there are only a small minority of companies that use GAAP earnings as their primary earnings measure. They all must report GAAP earnings, but usually tout some other earnings measure as their earnings that "are more useful for investors to understand the company's financial performance." The GAAP earnings for the most part are standardized. The "more useful" numbers are based upon each company determining for themselves what they will include/exclude. In many cases, totally self-serving. However, they must provide a reconciliation between GAAP earnings and the "more useful" earnings.

With respect to cash flow, each 10-K (annual) report and 10-Q (quarterly) report includes a GAAP standardized statement of cash flow. You may not be able to glean the information that you seek from that report, but it is the only one that I would trust.

Other statements that a company may make in presentations, discussions, etc about "cash flow" I would not trust without a complete detailed discussion of what they were including/excluding in the calculation.

I used the term for GAAP earnings as being "somewhat" standardized. With respect to oil and gas exploration companies, there are 2 different acceptable GAAP standards: successful efforts and full cost. Successful efforts expenses dry holes. Full cost capitalizes them into the pool of depletable costs and expenses them as the reserves are depleted. [Kind of like a manufacturer. Say that quality control finds one out of every 500 circuit boards to be defective. The company does not immediately expense that circuit board. The total manufacturing costs are allocated to the inventory of 499 circuit boards.] But, in the event of significant oil/gas price plunges, the calculation of the amount of write-downs of capitalized/depletable property is also different, depending on which method is used. That becomes a big deal if prices fully recover, because the write-downs are never reinstated.

Not very busy at this moment, so you got a lot of rambling, which I hope is mostly correct.

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

Free cash flow is a widely used measure of a company's financial performance.
Unlike breakeven price and similar indicators which everyone calculates using its own methodology (and nobody discloses this methodology), free cash flow can be easily calculated using the data from company's SEC fillings.

Below is a definition of free cash flow from investopedia:

Free cash flow (FCF) is a measure of a company's financial performance, calculated as operating cash flow minus capital expenditures. FCF represents the cash that a company is able to generate after spending the money required to maintain or expand its asset base.

FCF is an assessment of the amount of cash a company generates after accounting for all capital expenditures. The excess cash is used to expand production, develop new products, make acquisitions, pay dividends and reduce debt.

Some believe that Wall Street focuses only on earnings while ignoring the real cash that a firm generates. Earnings can often be adjusted by various accounting practices, but it's tougher to fake cash flow. For this reason, some investors believe that FCF gives a much clearer view of a company's ability to generate cash and profits.
However, it is important to note that negative free cash flow is not bad in itself. If free cash flow is negative, it could be a sign that a company is making large investments. If these investments earn a high return, the strategy has the potential to pay off in the long run. FCF is also better indicator than the P/E ratio.

FCF is a good indicator of the performance of a public company. Many investors base their investment decisions on the free cash generated by a company or its equity price to FCF ratio.

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

AlexS says: 01/04/2017 at 5:24 pm
It may seem strange that shale companies had negative free cash flow when oil prices were around $100, but achieved FCF neutrality in 3Q16 when WTI averaged only about $45.

The explanation is very simple. In 2010-14, shale companies were heavily investing, which helped them to achieve double-digit growth in production and to increase overall U.S. LTO output by ~1 mb/d each year in 2012-14.

While negative FCF is not necessarily negative, in this particular case, shale companies' strategies proved self-destroying.

1) Negative FCF led to accumulation of very high debt;
2) High demand from shale companies resulted in a sharp increase in unit costs for oil services and other inputs;
3) Rapid growth in LTO production caused the glut in the the global oil market and consequent drop in oil prices.

Lower oil prices led to a sharp reduction in shale companies' operating cash flows. But these companies even more sharply reduced their capex.
Finally, in 3Q2016 their combined capex was roughly equal to combined operating cash flow.

The above chart from the IEA Oil Market Report shows it very clearly.

shallow sand says: 01/04/2017 at 9:44 pm
AlexS. I do not disagree with you that the metrics you are explaining (very well, I might add) are very important.

However, I assume you agree that balance sheets and estimates of future cash flows are also important to look at.

In reality, all can be reviewed in SEC filings, which are the only numbers that are reliable. Company power point presentations are meant to be promotional material.

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

FCF is a good shapshot of a company's financial performance in a particular period. Of course, it is not sufficient for understanding of this company's whole financial situation and its future prospects.

FCF neutrality in 3Q2016 means that the group of 50 companies didn't have to increase their debt, but debt accumulated over the previous years remains on their balance sheets and is a heavy burden for future development.

Furthermore, FCF neutrality was achieved thanks to lower capex which resulted in declining oil production.

Higher oil and gas prices expected for 2017 should improve oil companies' operating cash flows. A number of shale players have already announced planned increases in capex of 10-50% for next year. That will likely reverse the decline in LTO output. But higher capex will not allow shale companies to achieve significant positive FCF, and hence to start repaying their debt.

At $55-60 they will be able to only slightly increase output by year-end 2017 vs. year-end 2016, while maintaining FCF neutrality. A more aggressive increase in capex would result again in negative FCF and increase in debt.

Furthermore, increase in shale companies' spending will reverse oil service cost deflation, which was the main contributor to declining unit costs in 2015-16.

In my view, a conservative financial and operational strategy, with gradual and modest increases in capex, should allow a moderate growth in LTO production over the next few years without significant increase in debt levels.

But a return to previous growth rates of 1 mb/d p.a. anticipated by some experts (including Rystad Energy) from 2018, would result in further deterioration of shale companies' financial situation. And it would have a negative impact on oil prices.

Nathanael says: 01/05/2017 at 10:13 pm
Yeah, something critically important in addition to free cash flow is the growth (or, in *this* industry, decline) trajectory. It's great to have free cash flow this year, but if your wells all run out in two years and you haven't drilled more, well, your free cash flow this year and next *is the total value of the company*, because there won't be any free cash flow in year three.

Well, actually, it's not even that good: liabilities also have to be considered.

clueless says: 01/05/2017 at 12:21 am
Easier said than done. Look at the latest 10-Q for CLR. It seems to me that there would be a lot of questions about their results, especially when you look at their operating cash flow and notice the large impairment charge that is added back, thereby not affecting cash flow from operations negatively. But they lost that cash almost as surely as if they drilled a dry hole.
shallow sand says: 01/05/2017 at 12:57 am
clueless. Regarding CLR and SEC filings, I have brought up several times that the company managed to reduce its estimate of future production costs by 60% from 2014 to 2015, while only reducing all categories of proved reserves by just 9% during the same period.

I believe there were some things pulled to keep PV10 above long term debt in 2015 and I expect the same for year end 2016.

CLR was not the only company to do this.

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

the large property impairment charge in CLR accounts for 3Q2016 ( $57 million for 3Q and $203 million for 9 months of 2016) is the result of negative revaluation of their reserves (due to lower oil price). It is reflected in the balance sheet as lower net property and equipment (compared with previous period) and as lower shareholers equity.
It is also shown in the income statement, but added back in cash flow statement as that's not real cash paid by the company.
It's a paper loss.

Dry hole cost is very small ( $27 thousands for 3Q and $233 thousands for 9 months of 2016). The cost of drilling wells was already accounted as capex. Then the cost of of successful wells was capitalized (and added to PP&E in the balance sheet) and dry hole costs are expensed and appear in the income statement as expenses. But they are added back in cash flow statement as cash paid for both succesful and dry wells was already included in capex.

Mike says: 01/05/2017 at 8:44 am
Alex, thank you for your detailed explanation of free cash flow. After 40 years of operating oil and gas wells I understand the definition very well. It can indeed be used, as you have said, as a snapshot of financial activity within in a brief period of time. As I have said, and Shallow, I believe, it is of little importance in the grand scheme of things. The shale oil industry is in serious financial trouble and 5 dollars a barrel on the "hope" of OPEC cuts has not changed that.

Its curious to me this intense need for some folks to make predictions about the future. Predicting the role shale oil might play in that future over the next decade, or decades, without understanding the financial condition of those companies extracting it, is a big mistake in my opinion. The shale oil phenomena has not been paid for yet, nevertheless you and others are counting on it decades thirty years from now. I do not understand that, sorry. I really don't have much to contribute here, it seems.

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

I agree LTO will contribute very little in the grand scheme.

Lots of agencies and companies provide outlooks of the future. The Chart below shows the BP Outlook 2016 for C+C+NGL and my "medium" scenario for C+C+NGL with URR=3600 Gb for 2015 to 2035.

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

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

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

I don't know who is the author of that article, but the very first phrase about operating cash flow is a complete nonsense:

"The way Cash Flow from Operations is calculated is by starting with net income (equity earnings) which doesn't include interest paid to debt holders."

Of course, net income includes "Interest expense".
See CLR's 3Q accounts; income statement.
Net interest expense for the quarter was $82 million.

[Jan 08, 2017] Long carbon based energy perspectives

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

long carbon based energy

Key conclusions of the report:

Developing countries, like China and India are urbanizing and their populations are becoming more affluent, this will increase global energy demand 24% by 2040. This includes the ExxonMobil prediction that energy use efficiency will double (figure 4).

The world population will increase from 7.3 billion today to over 9 billion in 2040, with a much larger middle class population (defined as >$14,600 and <$29,200 yearly for a family of 4) using energy than today. World GDP will effectively double by 2040. Living standards will rise dramatically, especially in the developing world.

Natural gas consumption will increase 54 quadrillion BTUs by 2040. Nuclear and renewables will increase 24 and 20 quadrillion BTUs, respectively. The 2040 energy mix will remain about the same as today (figure 5 and Table 1).

Rising electricity demand will drive the growth in global energy between now and 2040. The increase in the number of homes with electricity, industrialization of the developing world and our increasingly digital and plugged-in lifestyles will drive this growth. Half of global electricity demand is from industrial activity; thus good jobs can be lost if electricity costs are too high. Jobs will move to locations where electricity is cheap, an example is the new Voestalpine steel plant in Corpus Christi, Texas.

Crude oil and natural gas will remain the world's primary energy source. Even in 2040 oil and natural gas will supply 57% of all energy demand, this is an increase from 56% today. Oil demand will grow 18% through 2040 and natural gas demand will grow 44%. The developing world will account for the largest increases. Unconventional ("fracked") oil and gas, oil ("tar") sands, and deep water oil production will account for over 25% of the liquid supply in 2040.
Carbon dioxide emissions will increase, at least until 2030."

[Jan 08, 2017] 01/04/2017 at 8:58 am

Jan 08, 2017 | peakoilbarrel.com
High taxes create a "tax shield". The price at the pump in Europe is approx. 1/3 oil and refining and 2/3 tax and duty (see http://euanmearns.com/energy-prices-in-europe/ ). Consumption is therefore less responsive (inelastic) to the international oil market price compared to the USA. Also, Europeans have adapted to this over time and drive smaller and more fuel efficient cars.

Several oil producers have cut back on subsidies during the last couple of years. This should restrict domestic demand increase. Most oil exporters' oil consumption/capita will probably level off and never come close to the US figure. However, given the level of population growth and demographics (young people) in MENA their domestic consumption is unlikely to reduce significantly (slight increase seems more likely).

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

US per capita consumption 0.061 bpd.

Exporters:
Canada 0.066
KSA 0.135
Kuwait 0.156
Qatar 0.145
UAE 0.09

The only major exporter not there is Russia at 0.02, but President Trump will help them increase.

Not an exporter but FYI Singapore is highest I've seen at 0.24.

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

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

Watcher says: 01/04/2017 at 7:19 pm
mazama says ecuador may drop to imports this year. They don't list any Libya exports. Kazakhstan and Iran are legit. And the bible doesn't track Iraq.
AlexS says: 01/04/2017 at 4:09 pm
"The only major exporter not there is Russia at 0.02, but President Trump will help them increase."

How? Will he help to increase car fleet in Russia?

KSA and its neighbours use a lot of oil for electricity generation.
Russia uses natural gas, nuclear, hydro and coal.

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

Precisely.

Chris says: 01/05/2017 at 12:58 pm
Just to add information, in Europe, taxes are split in two parts: excise (typically fixed amount) and VAT (variable amount). For gas in Belgium, excise are about 0.60 per litre or half the price of gas. So price variations due to oil international prices are attenuated. Add to these that taxes decreases when oil price increase and increase when oil price decrease. This is a way to guarantee revenue for the State when oil prices decrease.

[Jan 08, 2017] A future oil supply trajectory

Notable quotes:
"... Desperate, broken men chase their dreams and run from their demons in the ..."
"... . A local Pastor risks everything to help them. ..."
Jan 08, 2017 | peakoilbarrel.com
George Kaplan says: 01/02/2017 at 4:43 am
After the Jean Laherrere post on global reserves I had a go at predicting a future supply trajectory myself. It is based on 620 Gb developed declining at 4.35% annually; 150 Gb discovered and undeveloped with about 120 identified from identified conventional projects on companies' books and 30 from shale; and 25 Gb undiscovered represented by a linear decline from current discovery numbers over twenty years. That gives 795 Gb reserves remaining – about what he had.

Note the figures in the legend give the overall production in the years shown on the chart.

Extra heavy oil is given as 30 kbpd coming on stream every year until 2023 representing the drop off in tar sands development and probable falls in Venezuela production, and then 200 kbpd added for every year after. As the projects take about 5 years to complete this would represent about 8 in development at any one time, but also requiring projects for 3 or 4 upgraders, 1 or 2 pipelines and a new refinery to be ongoing in parallel.

For new conventional projects I assumed a one-year ramp up, a ten-year plateau and 10% yearly decline to shut down after 25 years. The numbers coming on line until 2022 I've taken from what is currently on the E&Ps books with some probable short-term projects that could be developed in time. After that I just made reasonable guesses, assuming an extra three-year development time from discoveries for ne fields.

The results aren't very different from Dennis Coyne's except there isn't a new peak (in 2018 which he is predicting – I don't know where that extra production could come from based on current development activity) and there is a big gap in 2019 to 2022 reflecting the capital cuts over the past 3 years.

The biggest issue for me is that, assuming exporter countries maintain the same overall internal demand at about half current production, then net exports would fall by 50% in 2032 and to zero by 2041. There is also a 20% decline in available exports between 2018 and 2023. Things wouldn't be quite so clear cut as some countries will continue to export while other producers become net importers.

If this is close to reality I don't see it making transition very easy. Apart from added renewables and nuclear, and increasing efficiencies there will be a turn to gas if there is sufficient easily available, a loss in demand from recession (depression in a lot of places I suspect), and I think also an inevitable turn back to coal maybe with another push to in-situ gasification.

Nathanael says: 01/02/2017 at 5:59 pm
OK, I have to bring in a not-directly-oil-related comment, because it's related to demand. My non-oil projections for growth of electric cars - which are the key technology displacing oil usage. I believe since they are superior technology, they are essentially production-limited. I believe price issues will be automatically addressed by economies of scale as production increases.

So my production projections see a big increase in electric car sales in 2018 (thanks to models we already know about). I believe the high sales in 2018 cause much, much more capital , which causes much more investment by car companies. This takes 2-5 years to pay off. So I see a huge increase in production (and therefore sales) in the 2020-2023 time range.

Specifically - to get back to oil - I believe sometime in that time range, 2020-2023, is when electric car sales per year become large enough to displace an amount of oil exceeded the natural decline rate of oil fields (I've seen different estimates for that rate, but it's a close enough range that it doesn't matter for this projection). This is still well before market saturation is reached.

So combine this with your projection out to 2022, along with Laherrere's and Coyne's projections out to 2022, all of which are similar. Before sometime in the 2020-2023 range, we can expect petroleum demand to remain solid. But after that, demand will be dropping faster than the natural drop in supply. There will be a *glut* of oil. There will be no new drilling, or at least not profitably.

If a bunch of oil projects are started in the 2016-2023 period which start producing after 2023, they won't pay off, they'll be big money-losers and make the glut worse. (With a three-year project time, the glut will remain brutal for three years afterwards as old projects go online.)

At that point, low oil prices become the determining factor in the size of reserves. High-priced producers go bankrupt and shut down. Refineries, now with excess capacity, go bankrupt and shut down. Refineries have to retool to optimize for aircraft kerosene production instead of gasoline production. I think it's about this time - after a bunch of bankruptcies which leave wells in a derelict state - that the regulators start going after the survivors to cover their environmental liabilities preemptively, making them plug wells properly. I'm not exactly sure how the rest of the shakeout happens, but I'm glad to be totally out of the industry before then.

Survivalist says: 01/03/2017 at 8:43 pm
Thanks George. That's a fascinating chart. Thanks for breaking out the different production sources. How the world is going to get by on 20% less available exports by 2018 to 2023 is going to be interesting. Zero available exports by 2041! That's gonna be a damned mess.
Dennis Coyne says: 01/02/2017 at 6:13 pm
Hi George,

When oil prices rise in 2017 and 2018 there will be increased output from Russia and OPEC, in my view.

A lot of output in those nations has relatively short time for development, they just need to develop already discovered reserves, there will also be some increase in US LTO output and Canadian oil sands output with higher oil prices. Possibly the peak will be lower, but I expect a at least a 50% probability that the 2015 peak will be surpassed.

George Kaplan says: 01/03/2017 at 6:37 am
Dennis – can you say what those resources are – i.e. field names, expected production, time to develop. Because I know of nothing like that, and can't think of anything in the past where 1 or 2 mmbpd has been bought on line from FEED to plateau in 18 months, which is what you seem to be assuming. I can only think of Iran as a possible source – but most of their stuff is gas flood, that needs big compressors to provide the injected gas – it is impossible to go through a design, procurement and start-up cycle on such systems in under 24 months.
Dennis Coyne says: 01/03/2017 at 11:55 am
Hi George,

There are combined cuts of 1.7 Mb/d. That production from OPEC and Russia can be brought online in June 2017. Also infill drilling will increase in other nations as oil prices increase.. My scenario is pretty conservative relative to IEA and EIA Outlooks.

US lto can ramp up quickly with high oil prices.

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

I do not have information on specific fields and developments.

The IEA and EIA do have this information and their future outlooks are quite a bit more optimistic than what I have presented. I believe that those estimates are too optimistic and yours may be too pessimistic.

A problem with your analysis is that you seem to assume no reserve growth just as Jean Laherrere does. I believe an assumption of no future reserve growth leads to too pessimistic an outlook.

US reserve growth from 1980 to 2005 was about 63%. I have assumed C+C minus extra heavy reserves will grow by about 300 Gb from 2010 to 2060 or 300/850=35% over 50 years. Perhaps that is too optimistic, time will tell. Also I assume LTO resources in the US are only about 40 to 50 Gb, possibly too optimistic, but less so than the EIA.

Caelan MacIntyre says: 01/01/2017 at 7:37 pm
Oil price appears to be shyly creeping up maybe because it's testing the ceiling at where the economic engine starts sputtering and backfiring?

A little late, but, just-viewed (and recommended)

The Overnighters
Desperate, broken men chase their dreams and run from their demons in the North Dakota oil fields . A local Pastor risks everything to help them.

"The Overnighters is a feature documentary produced, directed and photographed by Jesse Moss was awarded the Special Jury Prize for Intuitive Filmmaking [etc.]

'The director, Jesse Moss, plays it as it lays. An observational, near-invisible presence, he fills the frame with the faces of economic deprivation and bad choices, neither judging nor sugarcoating. What emerges is a blue-collar meditation on the meaning of community and the imperative of compassion.' ~ The New York Times, Critics' Pick, Jeanette Catsoulis

'A remarkable nonfiction essay on golden rules and grand intentions and oil booms that do not pay off for everyone a rich and troubling documentary highlight of the year.' ~ The Chicago Tribune, Michael Phillips

'Like a punch in the gut. I can't remember the last time a documentary hit me so hard layered, provocative, and surprisingly intimate" ~ Leonard Maltin

'If John Steinbeck were writing in the second decade of the 21st century, 'The Overnighters' is precisely the story he'd want to tell' ~ Salon, Andrew O'Hehir

Another year; another section of the Russian-roulette rollercoaster ride (where corkscrews could mean missing rivets )

GoneFishing says: 01/01/2017 at 7:49 pm
A ten percent drop in oil production over 12 years appears quite manageable. All we need is a twenty percent efficiency gain in that time to handle it easily. It will help push EV production.

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

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

[Jan 08, 2017] the coming bust in supply might be a bit different from previously – something changed in the oil industry in December 2014

Jan 08, 2017 | peakoilbarrel.com
George Kaplan says: 01/04/2017 at 8:11 am
The EIA market and finance report for 3Q2016 is out today.

https://www.eia.gov/finance/review/pdf/financial_q32016.pdf

Oil and gas supply is now falling. The chart below shows pretty clearly why there was a glut: over investment leading to over supply, which is now correcting. Nothing much to do with demand reduction that I can see. One thing I haven't seen discussed, and can't find find a lot of analysis on, is how much either direct motor fuel subsidies (e.g. in producer countries and some other developing countries) or high taxes in Europe tend to reduce the impact of prices on demand changes. I'd be interested in any opinions or references.

George Kaplan says: 01/04/2017 at 8:14 am
This is the a boom and bust cycle combined with the end of life in a mature basin looks like (for the UK – only one new field approval this year to September).

George Kaplan says: 01/04/2017 at 8:17 am
And this is why the coming bust in supply might be a bit different from previously – something changed in the oil industry in December 2014 and I don't think things will play out quite as they have previously, even with rapidly rising prices, given the debt load.

[Jan 08, 2017] Mexico might flip from being a net exporter of petroleum products to a net importer of petroleum products in 2016

Jan 08, 2017 | peakoilbarrel.com
Ron Patterson says: 01/02/2017 at 4:53 pm
According to the Energy Export Databrowser they were still exporting about 600,000 bpd in 2015. That year their exports dropped by 21%. It is entirely possible that export dropped past zero in 2016 and they became a net importer.

However I guess we will just have to wait until we have the total 2016 data. But if anyone else has any further data I would love to hear it.

AlexS says: 01/03/2017 at 1:01 am
"I had read somewhere that the value of imported refined products was near to equaling the value of their exported crude."

Correct.
The drop in Mexico's net exports of crude oil and refined products was much steeper in value terms than in volume terms. It declined from US$26.2bn in 2011 to U.S.15.6 bn in 2014 and just 400 million in 2016.

Mexico: value of the foreign trade of crude oil and refined products (billion U.S. dollars)
source: PEMEX

AlexS says: 01/03/2017 at 1:37 am
"It would be interesting to compare the money they earn exporting crude to the money they spend importing refined products. Either way, Mexico is on the brink. Just as Indonesia had to fall back on other forms of revenue, like destroying their forests, once oil exports became oil imports, Mexico will have to find something else to lean on once oil doesn't pay the bills."

A sharp drop in the value of net crude and product exports had a negative impact on Mexico's foreign trade balance, which deteriorated from virtually zero in 2012 to a deficit of US$14-15 in 2015-2016.

But that's not critical, as oil and product exports now account for only 5% of Mexico's total exports, down from 16% in 2011.

Mexico's foreign trade balance (US$ billion)
source: PEMEX

AlexS says: 01/02/2017 at 7:04 pm
Mexico: net exports of crude and refined products (kb/d)
Source: Pemex
http://www.pemex.com/en/investors/publications/Paginas/petroleum-statistics.aspx

AlexS says: 01/03/2017 at 1:47 am
I think Mexico needs to build a new refinery of modernize existing refining capacity. That would solve the problem of rising product imports.

[Jan 08, 2017] Denmark might be the first country in the coming years where oil and gas production stopped

Jan 08, 2017 | peakoilbarrel.com
George Kaplan says: 01/03/2017 at 7:02 am
Has there been a country before in which oil and gas production has stopped? I can't think of one, but Denmark might be the first in coming years, what with DONG pulling out of fossil fuels, cancellation of an oil project last year (I think the last real prospect for them – I've forgotten the name though) and now this:

"Maersk pulls plug on North Sea field"

Paywall (but limited number of articles free): https://www.energyvoice.com/oilandgas/north-sea/127957/maersk-pulls-plug-northsea-field/

"Maersk Oil today confirmed it would cease production on its North Sea Trya field. The operator said it had failed to identify an economically viable solution for the full recovery of the remaining resources in the Denmark's largest gas field. Maersk Oil COO Martin Rune Pedersen said: "Tyra has since 1984 been the main hub for gas production and processing in the Danish North Sea. The Tyra facilities are approaching the end of their operational life, and together with our partners in DUC we have assessed solutions for safe decommissioning and possible rebuilding of the Tyra facilities."'

As I recall the seafloor had been subsiding as the reservoir pressure has been reduced. Jacking up existing facilities or rebuilding would be expensive for the remaining gas resource. I think the hub receives associated gas from some oil fields which will need to be rerouted as part of the decommissioning.

[Dec 26, 2016] Vehicle Sales Forecast: Sales Over 17 Million SAAR Again in December, On Track for Record Year in 2016

Dec 26, 2016 | www.calculatedriskblog.com
by Bill McBride on 12/26/2016 09:53:00 AM The automakers will report December vehicle sales on Wednesday, January 4th.

Note: There were 27 selling days in December 2016, down from 28 in December 2015.

From WardsAuto: December Light-Vehicle Sales to Push U.S. Market to New Record

December U.S. light-vehicle sales are forecast to finish strong enough for 2016 to top 2015's record 17.396 million units. However, actual volume largely will be determined by results in the final third of the month, because a major portion of December's deliveries typically occur after Christmas.

The forecast 17.7 million-unit seasonally adjusted annual rate is below November's 17.8 million, but above December 2015's 17.4 million.
...
Despite the drop in December's volume, total 2016 sales will end at 17.41 million units, barely edging out the all-time high set last year.
emphasis added

Here is a table (source: BEA) showing the 5 top years for light vehicle sales through November, and the top 5 full years. 2016 will probably finish in the top 3, and could be the best year ever - just beating last year.

Light Vehicle Sales, Top 5 Years and Through November
Through November Full Year
Year Sales (000s) Year Sales (000s)
1 2000 16,109 2015 17,396
2 2001 15,812 2000 17,350
3 2016 15,783 2001 17,122
4 2015 15,766 2005 16,948
5 1999 15,498 1999 16,894

[Dec 22, 2016] Oil Consumption Is Immune To A Transport Transformation

Notable quotes:
"... ...in 2016, 96 percent of all new vehicle sales featured a combustion engine. IHS Markit estimates the average vehicle life globally to be about 15 years, which means that the impact of new vehicle technologies is expected to take time to materially affect the vehicle fleet and overall fuel demand. ..."
oilprice.com

...in 2016, 96 percent of all new vehicle sales featured a combustion engine. IHS Markit estimates the average vehicle life globally to be about 15 years, which means that the impact of new vehicle technologies is expected to take time to materially affect the vehicle fleet and overall fuel demand.

[Dec 22, 2016] Huge Decline In U.S. Proved Oil And Gas Reserves

Proved reserved are price dependent and low price leads to the decline of proved reserves estimates.
oilprice.com

Proved reserves of crude oil in the U.S. declined by 4.7 billion barrels or 11.8 percent from their year-end 2014 level to 35.2 BBbls at year-end 2015. Natural gas proved reserves decreased 64.5 Tcf to 324.3 Tcf, a 16.6 percent decline.

... ... ...

Proved reserves are volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

[Dec 20, 2016] What's shocking about that chart AlexS is that even with the sharp price increases of oil between 2000 and 2014, the oil R/P ratio has still steadily declined. With investment having been crushed in the last few years, looks like we are facing a Seneca cliff

Notable quotes:
"... What's shocking about that chart AlexS is that even with the sharp price increases of oil between 2000 and 2014, the oil R/P ratio has still steadily declined. With investment having been crushed in the last few years, looks like we are facing a Seneca cliff. ..."
Dec 20, 2016 | peakoilbarrel.com

AlexS says: 12/19/2016 at 8:28 am

George,

The situation with global natural gas is different.

1) There is significant spare capacity in a number of countries. For example, Russia has reduced gas production in the past few years due to falling demand from Europe, but can easily increase it if demand returns.

2) There are significant developed and undeveloped proven reserves. Reserves/production ratio is much higher for natural gas (see the chart below).

3) Natural gas resources are generally explored less than oil. Potential for increase in proven reserves is much bigger for natural gas.

The countries and regions with significant resource potential and able to sharply increase production include: Iran, U.S., Russia, East Mediteranean, several countries in Asia (including China).
Several countries in Africa are not producing at full potential.

Global proven reserves / production ratio for oil and natural gas
source: BP Statistical Review of World Energy 2016

VK says: 12/19/2016 at 4:27 pm
What's shocking about that chart AlexS is that even with the sharp price increases of oil between 2000 and 2014, the oil R/P ratio has still steadily declined. With investment having been crushed in the last few years, looks like we are facing a Seneca cliff.
Synapsid says: 12/19/2016 at 5:46 pm
George Kaplan,

I got a bit of a shock when I read the caption in small print: Data excludes onshore Canada, US lower-48 onshore, and US shallow-water.

AlexS says: 12/19/2016 at 6:01 pm
The chart is named "Annual conventional oil and gas volumes discovered".

Onshore Canada production is dominated by oil sands; US lower-48 onshore – by tight oil.
Conventional output in both cases is from mature fields; and there were no major conventional discoveries for many years.

US shallow-water GoM is also a mature province. New discoveries were made in deepwater GoM.

[Dec 16, 2016] Deplete America first as national policy. The US is wasting its precious oil deposits like there is no tomorrow

Dec 16, 2016 | peakoilbarrel.com
Instead of switch to hybrids and smaller cars as well as using nat gas for local city tranport they are trying to comsume as much as possible. Without high tax of SUVs and opther "oil waisting" personal tranporation veiches it is impossible to sustain the US economy. the only question is when it falls from the cliff.

Boomer II says:

12/15/2016 at 1:00 pm
I've never understood the urgency of using up US oil so quickly. Better to buy someone else's at a cheap price and save ours for a time when it is depleted elsewhere.
robert wilson says: 12/15/2016 at 1:50 pm
Burn America First
shallow sand says: 12/15/2016 at 3:44 pm
I was going to type deplete America first, LOL.
likbez says: 12/16/2016 at 10:54 am
Its' not only the USA. KAS, Iran and Russia are doing the same. There are a lot of short termism obsessed politicians besides Obama administration

Especially KAS in 2014-2016. Who were instrumental in the current oil price crash.

But behavior of the Iran and Russia was also deplorable. Iran decided to get back its former market share at all costs. But they like KAS are governed by religious fanatics, so what we can expect?

At the same time Russia, which theoretically should be a rational player and have enough space and steel to build huge national oil reserves, using it as alternative currency reserves, did nothing. Instead Russia also increased oil production selling its national treasure left and right, while prices were hovering below $50.

Another bunch of short termism obsessed suckers. So much about Putin as a great statesman. And what he got in return for his stupidity - only additional sanctions and allegations that he fixed elections for Trump. Such a huge payoff.

IMHO of big oil producing nations only China behaved rationally.

Oil is not renewable resource and burning it in large SUVs and small trucks carrying one person to commute to work is a suicide. That's what the USA is doing on the national scale. Add to this all those wars for the expansion of the US neoliberal empire, the USA is fighting, which also consume large amount of oil and it looks even worse. See
http://www.ucsusa.org/clean_vehicles/smart-transportation-solutions/us-military-oil-use.html

The U.S. military is the largest institutional consumer of oil in the world. Every year, our armed forces consume more than 100 million barrels of oil to power ships, vehicles, aircraft, and ground operations-enough for over 4 million trips around the Earth, assuming 25 mpg.

So out of the total US oil consumption (let's say 20 MB/day) around 0.3 MB/day is consumed by military. I think that the figure in reality might be twice larger that cited as it is not clear how consumption of planes operating in Iran, Syria, Libya, Yemen (and generally outside the USA) is counted. But even 0.3 Mb/day is approximately the same amount that Greece, or Sweden, or Philippines are consuming. The latter is a country with over 100 million people.

In twenty-forty years this period would probably be viewed as really crazy.

[Dec 15, 2016] 12/14/2016 at 7:41 pm

Dec 15, 2016 | peakoilbarrel.com
According to OPEC Monthly Oil Market Report for December, the group's crude oil production rose by 150 kb/d from 33.72 mb/d in October to 33.87 mb/d in November. These estimates are based on secondary sources.
http://www.opec.org/opec_web/static_files_project/media/downloads/publications/MOMR%20December%202016.pdf

The IEA's estimate from its Oil Market Report shows an even bigger growth: by 300 kb/d to 34.20 mb/d, led by increases from Angola along with Libya and Saudi Arabia. The group's output stood 1.4 mb/d higher than a year ago.
https://www.iea.org/oilmarketreport/omrpublic/

According to a Reuters survey, in November, OPEC produced a record 34.19 million barrels per day (bpd) from 33.82 million bpd in October.
https://www.rt.com/business/369348-oil-russia-budget-opec/

OPEC countries are pumping oil at the highest rate for the past several years, ahead of the announced output cuts in January 2017.

OPEC crude oil production, 2014-16
Source: OPEC Monthly Oil Market Report, December 2016 (secondary sources)

AlexS says: 12/15/2016 at 5:40 am
China's crude oil production increased 3.6% in November from the previous month to about 3,915 kb/d, the highest since July.
Output was down 382 kb/d (8.9%) from the same month last year.
Crude production has fallen 294 kb/d (6.9%) in the first 11 months of 2016 to 3,984 kb/d.

Comment from Bloomberg:

"China's output has declined this year as state-owned firms shut wells at mature fields that are too expensive to operate at current prices. The country needs oil above $50 a barrel to stabilize production, according to analysts at Sanford C. Bernstein, as well asFu Chengyu, the former chairman of both Cnooc Ltd. and China Petroleum & Chemical Corp. Production is forecast to drop 335,000 barrels a day this year, followed by a further slide next year of 240,000 barrel a day, the International Energy Agency said Tuesday.
"November's output pickup is probably just a blip, which won't likely persist," said Gao Jian, an analyst with Shandong-based industry consultant SCI International. "For the next six months, unless oil prices stay above $50 a barrel, we we won't see solid recovery."
The rise in production last month was in anticipation of higher crude prices amid OPEC meetings, said Amy Sun, an analyst with Shanghai-based commodities researcher ICIS-China.

China's annual crude output is seen falling to 200 million tons this year (about 4 million barrels a day), down roughly 7 percent from nearly 215 million tons last year, according to estimates from SCI International and ICIS-China."

https://www.bloomberg.com/news/articles/2016-12-13/china-oil-output-rebounds-from-7-year-low-on-opec-led-price-gain

China's crude + condendate production (mb/d).
Source: China's National Bureau of Statistics

AlexS says: 12/15/2016 at 5:47 am
China's C+C production in 2002-2016 (mb/d)

Heinrich Leopold says: 12/15/2016 at 6:51 am
AlexS,

It could be also a clever strategy to buy cheap oil from the market and leave China's oil in the ground as a strategic oil reserve.

AlexS says: 12/15/2016 at 7:40 am
I agree. It was a rational decision to cut output from high-cost fields, which was loss-making at low oil prices, rather than maximizing production.

I think that, with oil prices at $50-60, China will be able to temporarily stabilize output

shallow sand says: 12/15/2016 at 11:35 am
Yes, the US clearly needs some kind of energy policy, and I think one thing that highlights how badly this is needed is the ability of anyone who can raise the money to be able to drill 96 horizontal wells in one section of land (two if the laterals are the two mile variety).

But, I guess any mention of conservation in the US industry these days is heresy.

I would not be too critical of Chinese production falling. Seems to me they are buying up all the cheap oil they can from overproducing nations, and storing it. Makes sense to me.

[Dec 13, 2016] It is amazing how many times we have caught the shale oil industry lying thru its teeth but EIA still believe everything they say

Notable quotes:
"... its amazing to me, given how many times we have caught the shale oil industry lying thru its teeth, how many people (EIA and the NDIC) still believe everything it says about itself: http://www.worldoil.com/news/2016/9/22/analyst-touts-industry-s-cost-reductions-in-us-shale-plays ..."
"... "Technically" recoverable reserves is a wild ass guess based on volumetric calculations of shale OOIP over a hypothetical homogeneous area in all the producing basins throughout the country that has absolutely nothing to do with reality. Reality is that only about 5-6% of that oil is recoverable thru primary means, not 74%. ..."
"... as we have seen in the past, poor economics did not deter sharp growth in LTO production. It seems that financial markets are ready to resume funding of the shale sector, although more cautiously than in 2011-14. And shale companies are already announcing their growth plans for next year. ..."
"... I expect growth in LTO production to resume next year and accelerate in 2018. This growth will be much slower than during the years of the shale boom, but the U.S. LTO production may reach a new peak in the beginning of the next decade. ..."
"... When the EIA states we can recover 70 plus percent of TRR shale oil in America that is a grave disservice to the public. As is "undiscovered TRR," whatever the hell that is. ..."
"... If you were to poll most Americans I believe the vast majority would say we no longer have a hydrocarbon problem in America, that we have 150 years of shale oil and more than that in natural gas and that we should, and can, isolate ourselves from the rest of the energy world and become energy independent. That is a mistake. ..."
"... The shale industry, and its "groupies," has deceived many people over the past 14 years and that pisses me off, big time. ..."
Dec 13, 2016 | peakoilbarrel.com
Mike 12/12/2016 at 5:43 pm

Alex, I might wish to disagree with you regarding the EIA's predictions; its amazing to me, given how many times we have caught the shale oil industry lying thru its teeth, how many people (EIA and the NDIC) still believe everything it says about itself: http://www.worldoil.com/news/2016/9/22/analyst-touts-industry-s-cost-reductions-in-us-shale-plays

David Hughes at PCI might disagree with you also. Predicting a 74% recovery of technically recoverable shale oil reserves in America by 2040 (EIA AEO2016) is an enormous stretch: http://www.postcarbon.org/publications/2016-tight-oil-reality-check/

Dennis Coyne says: 12/12/2016 at 7:24 pm
Hi Mike,

Alex S is mostly talking about the short term forecast. I agree that the long term forecast in the EIA's AEO for LTO is much too optimistic and that Hughes' estimates are quite good.

Note that one mistake Hughes makes is confusing the undiscovered TRR with TRR, he needs to account for 2P reserves and add those to UTRR for the Bakken/Three Forks. His estimates for Bakken/Three Forks are a bit low. Maybe a couple of Gb.

Mike says: 12/12/2016 at 8:06 pm
Dennis, what in the hell is the difference in undiscovered TRR and TRR? What shale oil resources are out there left to be discovered, do you reckon? "Technically" recoverable reserves is a wild ass guess based on volumetric calculations of shale OOIP over a hypothetical homogeneous area in all the producing basins throughout the country that has absolutely nothing to do with reality. Reality is that only about 5-6% of that oil is recoverable thru primary means, not 74%. Lordy.
AlexS says: 12/12/2016 at 9:54 pm
Mike,

As Dennis says, I was talking about the EIA's short-term forecasts, which are the initial topic of this thread. The fact is that the EIA was generally too conservative in its forecasts for U.S. C+C production, which my charts above show. I think their forecast for 2017 is still too low and will be revised upwards, especially as oil prices will likely be higher than the EIA was assuming in December STEO ($51 average).

Long-term forecasts in the Annual Energy Outlook are a different story.

Note, that I totally agree with your view on shale economics. But as we have seen in the past, poor economics did not deter sharp growth in LTO production. It seems that financial markets are ready to resume funding of the shale sector, although more cautiously than in 2011-14. And shale companies are already announcing their growth plans for next year.

I expect growth in LTO production to resume next year and accelerate in 2018. This growth will be much slower than during the years of the shale boom, but the U.S. LTO production may reach a new peak in the beginning of the next decade.

Mike says: 12/13/2016 at 8:30 am
Thank you, Alex; I am aware of the title of the post and the fact that it contains information on IEA export data for Iran, JODI data on the KSA, the Marcellus gas "miracle" a discussion of Russian politics, the usual sprinkling of ant-oil, EV stuff, Donald Trump and Obamacare. You will of course forgive me for not fully understanding this statement: " the EIA's projections tend to underestimate U.S. oil production in general, and LTO output, in particular."

My interest in LTO economics is multi-faceted and because shale oil extraction is extremely expensive, and woefully unprofitable, unlike yourself, perhaps, I do not believe it will have a significant role in our energy future until we sort out how to pay for it. Hoping for higher oil prices, and "predicting" higher oil prices is not a plan, therefore stating it will grow in the future, without stating how, is dangerous, in my opinion. I don't believe it can be funded as it has been; that WILL stop, eventually. At best, whether we believe people like David Hughes, or the EIA, we only have 6-8 years of shale oil to provide to the US's total annual crude oil needs. When the EIA states we can recover 70 plus percent of TRR shale oil in America that is a grave disservice to the public. As is "undiscovered TRR," whatever the hell that is.

If you were to poll most Americans I believe the vast majority would say we no longer have a hydrocarbon problem in America, that we have 150 years of shale oil and more than that in natural gas and that we should, and can, isolate ourselves from the rest of the energy world and become energy independent. That is a mistake.

The shale industry, and its "groupies," has deceived many people over the past 14 years and that pisses me off, big time. MY industry should tell the truth about the oil and gas future. It doesn't. We will likely have to explain to our children someday why we pissed off all of our remaining resources and did not leave them anything.

Merry Christmas, y'all.

[Dec 13, 2016] Both China and India experienced record crude oil demand in November

Dec 13, 2016 | peakoilbarrel.com
shallow sand, 12/13/2016 at 12:05 am
Read on CNBC that both China and India experienced record crude oil demand in November, 2016, with China up 3.4% yoy and India up 12.1% yoy.
Boomer II, 12/13/2016 at 12:28 am
"Read on CNBC that both China and India experienced record crude oil demand in November, 2016, with China up 3.4% yoy and India up 12.1% yoy."

I went looking for something about this and have found nothing on CNBC or anywhere else. Do you have a link?

Watcher, 12/13/2016 at 2:48 am
China's consumption growth was 5% last year. India 7%.

Of course it's growing, maybe even accelerating. Population does.

There really isn't much doubt how this ends, once ppl get past the pearl clutching.

likbez,, 12/13/2016 at 10:52 am
According to Yahoo ( http://finance.yahoo.com/news/iea-ups-oil-demand-forecast-095410829.html ):

IEA also upped its forecast for global oil demand for this year and next year due to revised estimates for Russian and Chinese demand. It saw growth of 1.4 mb/d for 2016, 120,000 barrels a day above the previous forecast. Growth in 2017 is now seen at 1.3 mb/d, an increase of 110,000 barrels a day from its previous estimate.

likbez, 12/13/2016 at 11:40 am

Realistically the only country that can substantially increase its oil production in 2017 in Libya. But that requires the end of the civil war in the country which is unlikely. Iran card was already played.

Iraq is producing without proper maintenance. At some point they might have substantial difficulties.

[Dec 13, 2016] IEA ups oil demand forecast for 2017, says next few weeks are 'crucial' for markets after OPEC deal

Notable quotes:
"... The IEA also upped its forecast for global oil demand for this year and next year due to revised estimates for Russian and Chinese demand. It saw growth of 1.4 mb/d for 2016, 120,000 barrels a day above the previous forecast. Growth in 2017 is now seen at 1.3 mb/d, an increase of 110,000 barrels a day from its previous estimate. ..."
finance.yahoo.com

...OPEC ... crude output in November was 34.2 million barrels per day (mb/d) - a record high - and 300,000 barrels a day higher than in October.

The IEA also upped its forecast for global oil demand for this year and next year due to revised estimates for Russian and Chinese demand. It saw growth of 1.4 mb/d for 2016, 120,000 barrels a day above the previous forecast. Growth in 2017 is now seen at 1.3 mb/d, an increase of 110,000 barrels a day from its previous estimate.

[Dec 13, 2016] OPEC Monthly Oil Market Report

Notable quotes:
"... Peak oil is not just about cars. Oil is the reason why our civilization exists in its current form. Oil is why we have 7 billion people on this planet. Oil is about agriculture and food supply, it is about distribution of everything we buy and not least it is about the raw materials for many if not most of our goods. It is about almost every economic and social transaction that takes place. ..."
"... It is unbelievable what misinformation has been spread by the media. I attended a public forum of the Australian Energy Council and one participant thought that OPEC had increased oil production. My presentation on the need to replace oil by natural gas as transport fuel (instead of exporting it as LNG) was met with silence and did not spark a debate. Another participant was running away when he heard the word peak oil. ..."
"... Further re climate, most agree CO2 is a greenhouse gas but estimates of the temperature change caused by a doubling of its concentration have been coming down over the last 15 years. In other words, it may not warrant the type of policy response that is being promoted at present. ..."
"... Meanwhile the IPCC projections continue with climate sensitivity estimates of 3 to 6 degrees when the more recent estimates of ECS and TRC are consistently under 2 degrees. So contrary to what is alleged above, there is lots of doubt about the IPCC models. ..."
"... I agree with author. If you look at 2 previous OPEC meetings, the players claim disorder and inability to control output only to find resolution the day after the meeting. I believe OPEC is setting up for a freeze as we are only 1% oversupplied now. If the OPEC big wigs need to fatten the bank accounts, what better way than to set up your own long call on the cheap? ..."
"... Balance this with Iran and Iraq incapable of proper well maintenance and we will soon see inadequate supply not later than 2qtr 17′. ..."
Dec 13, 2016 | www.opec.org
is out with crude only production numbers for October 2016. All charts are in thousand barrels per day.

OPEC crude only production reached 33,643,000 barrels per day in October. This includes Gabon. Since May, OPEC production has increased 1.05 million barrels per day.

World oil supply is very near its November 2015 peak.


steve from virginia says: 08/10/2014 at 12:30 pm
All this oil tens of billions of barrels all of it non-renewable, never to be seen- or made use of again for a hundred million or more years, for all practical purpose, ever!

the greatest bulk of it put into cars where it is wasted, by people driving aimlessly in circles from gas station to gas station for entertainment purposes only By way of this idiocy we destroy ourselves and our futures. We aren't doomed, we are damned.

Mike, Sydney says: 10/10/2014 at 6:05 pm
The big mistake most energy illiterates make is to talk about their cars when the peak oil subject comes up. Most hope or assume that another form of fuel or energy will power their ride post oil.

Peak oil is not just about cars. Oil is the reason why our civilization exists in its current form. Oil is why we have 7 billion people on this planet. Oil is about agriculture and food supply, it is about distribution of everything we buy and not least it is about the raw materials for many if not most of our goods. It is about almost every economic and social transaction that takes place.

When oil becomes expensive our economies and societies will implode, jobs and goods imported from far away will disappear. This will apply worldwide. The citizens of Addis Ababa are just as dependent as the ones in Amsterdam or Atlanta.

We have exhausted most of our soils and lost the skill to eke out a living from Mother Nature without fertilizers and machines. Could it be that the least "developed" countries will lead post oil because our "developed" nations are the least able to cope without oil?

Ron Patterson says: 10/10/2014 at 6:45 pm
Mike, that's exactly what I have been trying to tell folks for years. Most just don't want to believe it. They see solar, wind and other such things as keeping BAU going for awhile.

Why don't you post over on the post section. We get a lot more traffic over there.

Peak Oil Barrel

Argh says: 04/06/2015 at 1:35 pm
Big mistake thinking that this crisis will not arrive with plenty of time to avoid it. Oil prices will rise slowly over time. However we create energy, we will find a way to pay for locomotion or create food.

Oil is down 50% This is because of new sources of supply combined with continuing energy efficiency improvement. Doomed or damned, don't hold your breath. I am sure you will find something else -- perhaps global warming, now climate change, to scare people with.

Don Wharton says: 06/10/2015 at 7:54 pm
Argh. Your comment suggests that you are a militantly ignorant troll. 97% of the competent climatologists fully support the IPCC global warming summary model. There is no reasonable doubt about this science.

In my opinion there has been a revolution in drilling technology over recent years. However, the measured rate of additional improvement is now very modest as measured by the US EIA.

Most of the recent improvement is explained by the discovery and exploitation of sweet spots which are being rapidly drained. For an objective look at prospects going forward for oil and gas you should read David Hughes' Drilling Deeper report.

This is an exhaustive analysis based on a data base of all existing US oil and gas wells. It impressively documents a future of peak oil and gas based on fully exploiting fracking technology. I don't see any magical technology that will get the projected fossil fuel resources required for business as usual. It is just not there.

Nick G says: 12/15/2015 at 2:43 pm
Oil is the reason why our civilization exists in its current form.

Not really. There's nothing magical about oil. 100 years ago civilization was pretty recognizable, and it didn't require oil.

Oil is about agriculture and food supply

For the moment. Batteries and synthetic fuel can move tractors. Electricity (from many sources) can create fertilizer.

it is about distribution of everything we buy

Rail works awfully well.

is about the raw materials for many if not most of our goods.

Meh. It produces some of our raw materials. But plastic can be produced from a lot of different hydrocarbons, and it's production doesn' necessarilly create CO2, so we could produce plastic from coal for centuries. That's plenty of time for a smooth transition.

jay says: 09/24/2016 at 7:36 am
"Not really. There's nothing magical about oil. 100 years ago civilization was pretty recognizable, and it didn't require oil." You missed his point entirely. The reason there is 7 billion people now is because of oil and what it has done for industrial, agriculture ect ect ect.

There was 1.7 billion people 100 years ago. How many people do you think would be here if not for oil and all it has done?

">For the moment. Batteries and synthetic fuel can move tractors. Electricity (from many sources) can create fertilizer<".

This is lack of a better word retarded for you to even consider that a battery will be used even in the distant future to power agricultural machinery on a mass scale. Maybe the little ride on mower you cut grass with, but that is it.

" Rail works awfully well."

Ya it does, but when it gets to a terminal, it will have to be unloaded and transported then. Which basically happens now, so what is your point? And your last comment I wont even pick apart because you obviously know little to very little about the uses of oil and the advantages it has brought humanity.

Johnny Honda says: 10/13/2015 at 2:44 am
@ Steve from Vaginia: Did you ever consider that some People have to drive to *work* and *produce* so that you can sit around and swing your testicles and so that your mommy can prepare your lunch and dinner?

So when you sit around the whole day you can think what happens in 300 years, when most of the oil and gas has been used up. We don't have time for that, but we are sure that People will find a solution.

Rubber Johnny says: 10/13/2015 at 5:59 am
One or the solution will be not driving to work and wasting time in gridlock so we can have more time to swing our balls be 'productive' on our own and our real community's terms. Real community that includes momma

Rubber Johnny

Argh says: 04/06/2015 at 1:30 pm
Oil will get more expensive, some day slowly. Right now the cost is down (50%!!!) because of new sources and efficiency improvements. I think that those who predict doom will be disappointed.
SRSrocco says: 10/12/2015 at 1:23 pm
Argh,

The falling EROI destroys your lousy assumption in spades. Your time might be better spent burning books or working on one of the dozen worthless Presidential campaigns.

Steve

RSAldeen says: 04/29/2015 at 1:50 pm
Oil is very precious raw material, our demand for oil increases day after day, year after year and century after another. The search and use other sources such as atomic, wind, tide, solar, geothermal and others will continue but the prospects / trend to keep on using oil as a main source of energy still quite high and will continue with time due to the following reasons:
Matt Mushalik says: 05/12/2015 at 7:25 pm
Thanks for the graphs. Saudi Arabia may be ramping up production ahead of the air-conditioning season. Around 600 kb/d are needed in the hottest month.

It is unbelievable what misinformation has been spread by the media. I attended a public forum of the Australian Energy Council and one participant thought that OPEC had increased oil production. My presentation on the need to replace oil by natural gas as transport fuel (instead of exporting it as LNG) was met with silence and did not spark a debate. Another participant was running away when he heard the word peak oil.

Greg Surgener says: 08/20/2015 at 3:57 am
Matt,

Im lost by ur comments. 1st of all the graphs clearly show that Opec has increased production by 2+m/d in the last year.

2ndly, Saudi's oil output charts above are for just Oil not NG. Ive never been there, are you suggesting they run generators from oil for electricity and subsequent air conditioning. Why wouldn't they run thier power plants on Natural Gas? Please educate me.

No doubt that investor sentiment and market makers are playing a significant role in price decline, as opposed to actual supply/demand issues. How do you find out how much the Opec nations have sold oil short in the various markets. Not a bad deal for them, if they can lay rigs down World wide and make the money in the commodity markets while doing so. But prices can only slide so far and for so long before that game is up. It seems like if short selling or hedging slows, buyers will outweigh sellers and the price should rise soon

Your thoughts?

Greg

Ron Patterson says: 08/20/2015 at 5:41 am
Greg, Saudi Arabia is very short of natural gas and have been for several years now. They would love to run all their power plants and desal plants on natural gas if they just had enough of it. They don't. They do burn a lot of natural gas but their supply is far short of what they need.
Nick G says: 12/15/2015 at 12:48 pm
Ron,

As best I can tell, KSA is short of NG because they've fixed the price at a very low level to subsidize domestic companies that use NG.

What have you seen about that?

Ron Patterson says: 08/20/2015 at 8:43 am
...Saudi is producing flat out right now just like every other OPEC country except Iran. Sanctions are holding Iran back. Political violence is holding Libya back, but they are still producing every barrel they can. It's just that violence keeps them from producing any more.
Keith says: 08/29/2015 at 4:55 am
A few comments:

Most polls show a split of about 60 40 in terms of views on climate science, rather than 97 3 despite what POTUS may have tweeted.

Further re climate, most agree CO2 is a greenhouse gas but estimates of the temperature change caused by a doubling of its concentration have been coming down over the last 15 years. In other words, it may not warrant the type of policy response that is being promoted at present.
http://climateaudit.org/2014/09/24/the-implications-for-climate-sensitivity-of-ar5-forcing-and-heat-uptake-estimates-2/

Meanwhile the IPCC projections continue with climate sensitivity estimates of 3 to 6 degrees when the more recent estimates of ECS and TRC are consistently under 2 degrees. So contrary to what is alleged above, there is lots of doubt about the IPCC models. The latter point comes from peer reviewed science, by, among others, Nic Lewis.

Keith says: 08/29/2015 at 6:44 am
Another point of interest is the relative steadiness of Venezuelan production. Allegedly various of the empresas mixtas (Joint Ventures between PDVSA and International Oil Co.'s) are not proportionally funded by PDVSA as they should be. As a result production is down or is not reaching targets. Apparently contractor companies will not accept new contracts from PDVSA unless they set up an escrow account or other arrangement that guarantees payment in foreign currency. It is surprising therefore that Venezuelan production shows a slight rise since December.
skykingww says: 10/22/2016 at 4:35 pm
Yes one day we will be without oil that is pumped from the earth. This is not going to happen for 100's of years. Our intellect will probably find chemical or biological solution to this problem long before we run out. If not humanity will survive. Global warming, yes its real and one day the Sun will double in size and engulf the earth. I am not worried about either. I hate winter anyway.

The problem humanity will face and not discussed near enough is the lack of clean drinking water. Everyday it becomes harder to deliver enough clean water to all areas in need. States fight over the rights to what little water pass through their terrain every year. Many times it has to be pumped from other states at a premium. The worlds population grows larger every second. crops demand more and more. Ethanol was forced on us without thought as usual by the oil fear mongers. You do not grow food to solve a commodity problem.

The land resources, water resources, and corrosive properties that Ethanol introduced far out weigh any benefit accomplished but still its forced down our throats destroying everything its poured into. So please build those oil pipelines all across the country and pump that oil at rates that keep our prices low so I can drive in circles any time I feel like it. I am not going to worry about it because about the time we run out of oil we will need those pipelines to pump clean water to all that need it.

Eric Sepp says: 11/01/2016 at 2:56 pm
I agree with author. If you look at 2 previous OPEC meetings, the players claim disorder and inability to control output only to find resolution the day after the meeting. I believe OPEC is setting up for a freeze as we are only 1% oversupplied now. If the OPEC big wigs need to fatten the bank accounts, what better way than to set up your own long call on the cheap?

OPEC will shut in wells before the Fed adjusts interest rates resulting in magnified downward pressure on oil.

Balance this with Iran and Iraq incapable of proper well maintenance and we will soon see inadequate supply not later than 2qtr 17′.

cmejunkie says: 11/14/2016 at 4:05 pm
Angola: October 2016 decline – chiefly due to Dalia maintenance (though might have peaked in this cycle as no major is rushing to invest in Angola's deepwater wells). http://www.brecorder.com/markets/energy/europe/314268-angolan-oct-crude-oil-exports-to-fall-as-dalia-enters-maintenance.html

[Dec 11, 2016] I won't deny there is an uptick in drilling coming, it is just that I perceive they are trying to hold the leases not that they are jumping at $50 oil to plan to go all out for that reason.

Notable quotes:
"... Most shale oil companies are looking down the barrel of loans coming due beginning 2017 and continue to do stupid things with borrowed money because they have no choice. In spite of lower costs and higher EUR's brain washing campaign, they are all still losing money hand over fist. Even mighty EOG. ..."
Dec 11, 2016 | peakoilbarrel.com
Guy Minton says: 12/09/2016 at 3:05 am
I won't deny there is an uptick in drilling coming, it is just that I perceive a different rationale for it, than assuming they are jumping at $50 oil to plan to go all out for that reason. Some companies are completing wells that would only be profitable at $100 a barrel. No rationale for those, other than they are simply trying to hold on to the lease, and hope. I follow EOG fairly closely, and from my own lease, I know they are trying to hold on to fairly good leases, but only drill what they have to. I think that is the reason your seeing an uptick. They are planning on what will hold the leases for 2017. They are balancing those permits for "marginal" wells at $50, with permits in the sweet spots. From a planning perspective, it makes sense on getting that over with first. Then you can concentrate on what is going to keep you alive. It is interesting to note that the Austin Chalk (Sugarcane) has become their new sweet spot in Karnes County. They have 5 or 6 now producing, and 9 more planned so far for next year. All are doing very well, and two had first month production in excess of 100k barrels a month. Less decline than the Eagle Ford, so far. Other companies are now jumping on it, too.
Mike says: 12/09/2016 at 9:16 am
Mr. Minton do you have continuous drilling provisions in your lease and if so may I ask, what year did you lease to EOG?

I contend that at these oil prices the speculation about "drilling to hold leases" is vastly overblown, that most leases made in the Eagle Ford and Bakken before 2012-2013 had no continuous drilling provisions in them, and that most of the drilling still being done in those two plays, at these oil prices, are actually related to loan covenants regarding booking PDP reserves, SEC 5 year rules regarding PDNP reserves and to reduce taxable income thru IDC deductions. Most shale oil companies are looking down the barrel of loans coming due beginning 2017 and continue to do stupid things with borrowed money because they have no choice. In spite of lower costs and higher EUR's brain washing campaign, they are all still losing money hand over fist. Even mighty EOG.

HZ Austin Chalk wells cost considerably less that shale wells because they don't typically require frac'ing. Some of the initial IP's and IP90's in the Chalk have been spectacular, especially for EOG who is well know for gutting wells to create big EUR's; take it from me, an old Chalk hand, however, the decline on Chalk wells after 12-18 months will suck the hardhat over the top of your head and I am quite certain 95% of those wells will NOT payout either. They did not in 1981, 1991, 2001 nor will they this time around the block either.

Guy Minton says: 12/09/2016 at 5:06 pm
Yes it has continuous drilling clause.
Austin chalk wells by EOG are frac'ed. Who cares what happens to the decline in 12 to 18, if you recover over 300k the first year?
Mike says: 12/10/2016 at 3:01 pm
If EOG frac's those Chalk wells then they cost essentially what an EF well costs. If a Chalk well makes 300,000 BO in the first year, which they don't, then declines 80% annually after the first 12 months and every year thereafter, they'll never reach payout. If your only interest in any of that is from the standpoint of a royalty owner, then I am sure you don't care about profitability. I do.
Watcher says: 12/11/2016 at 5:45 am
Mike, pls elaborate on this theory.

We have sought the reason wells are being drilled at sure loss, and lease obligation was one suggestion. Can you flesh out this other

Mike says: 12/11/2016 at 9:25 am
I contend that most mineral leases made before 2013 did not contain "drill and earn provisions" in them (drilling commitments) and that one well could hold the entire lease. I can confirm that in S. Texas and I suspect less knowledgeable mineral owners in the Bakken that leased early in the play had no drilling commitment provisions in them either. Leases made later in both plays involved more sophisticated mineral owners who required drilling commitments. In W. Texas, for instance, all that now being drilled is subject to drilling commitments.

SEC rules are very clear regarding 'proven but not producing' reserves that were "booked" and made into assets they must be drilled within 5 years or lost. DUC wells are PDNP reserves and they too must be completed within 5 years.

I am familiar with two new loan covenants, particularly relative to recent credit swaps, etc. that if a company gets more money in the equity swap, they must develop PDNP reserves or suffer penalties.

None of this precludes the fact that 95% of the shale oil wells being drilled in America and these oil price levels will not payout unless prices rise dramatically. Those wells ARE drilled at a sure loss. The shale oil industry is penned up now like a heard of goats; they voluntarily drill unprofitable wells with borrowed money because they need cash flow and they need to book more assets to be able to borrow more money. They are also forced to drill and complete wells that are unprofitable for reasons I have explained. The ONLY way out for them, even the biggest of them, is if oil prices rise into the 80's and 90's and that is not going to happen for a long time, short of some big chicken fight somewhere in the world that would have an affect on supply.

Guy Minton says: 12/09/2016 at 8:27 am
Not really. There is not a lot of interest in drilling for $50 to $60 oil in the shale. Go back and look at what happened in 2009 when oil dropped to $60. Most places are profitable to drill at $80 to $100. Very few are profitable at $50. The press can hype all they want. It won't change reality.
Eulenspiegel says: 12/09/2016 at 9:24 am
I think the press helps – if enough people buy it, silly money will give free loans to these companies to continue drilling. You can loose as much money as you like, as long as you have creative bookkeeping and a neverending roll in of money.

We had this here in Germany in the wild 2000s – film making fonds have been the red hot burner, people lost millions but continues investing until alle these companies where history. Hollywood was laughing about Germany "silly money".

[Dec 11, 2016] The Fallacy Of Increasing U.S. Oil Production Post-OPEC Agreement

Dec 11, 2016 | peakoilbarrel.com
Ron Patterson says: 12/09/2016 at 10:03 am
The Fallacy Of Increasing U.S. Oil Production Post-OPEC Agreement

It's little surprise that Credit Suisse recently stated:

"With service prices, particularly pressure pumping expected to rise in 2017 on the back of increased activity, a Permian operator commented that it is already seeing greater than a 20% increase in completion costs. The biggest concern for Permian management teams has been a potential scramble for equipment and services that higher commodity pricing could introduce, and the OPEC move has the potential to drive faster service cost inflation than we would have otherwise seen, muting the impact of the oil spike on returns for US shale operators."

In other words, the cost of drilling is likely to go up just as fast as the price of oil goes up if there is a cut in production by OPEC.

Guy Minton says: 12/10/2016 at 8:26 am
Most of the new "drilling efficieny" is a result of depressed costs and drilling in primarily "sweet spots". Easy financing is a thing of the past. Can't see a big enough resurgence in shale drilling to overcome drops in production in the short term. A 20% increase is a killer, but that is only the beginning. The way I see it, because the new drills won't keep up wit the decline rates of the old wells; they have to recoup all their drilling costs the first year, to enable them to keep drilling. That leaves only a few areas to drill in. The only reasons it surged in the past, were easy money and oil at $100 a barrel. Both are no longer available, now.

[Dec 11, 2016] 2016 should see a new record for OPEC exports due to ramp-up in production and exports from Saudi Arabia, Iran and Iraq.

Dec 11, 2016 | peakoilbarrel.com
AlexS says: 12/08/2016 at 5:40 am
BP's numbers for oil exports (available from 1980) and production less consumption (available from 1965) are slightly different, which may reflect changes in inventories and other balancing items.

According to BP, Middle East oil exports in 2015 was 20.6 mb/d, the record for the period from 1980.
Production less consumption was 20.5 mb/d vs. all-time high of 20.8 mb/d in 1976-1977.
But 2016 should see a new record due to ramp-up in production and exports from Saudi Arabia, Iran and Iraq.

Middle East oil exports (mb/d)
Source: BP Statistical Review of World Energy

[Dec 09, 2016] It looks like shale oil is a USA phenomenon with no appreciable production anywhere else in the world but the shale oil phenomenon has given the entire world the illution the peak oil does not exist, an idea that had no valid support in the real world

Notable quotes:
"... The real danger is that the media, as well as the general public, has been sold the idea that peak oil has now been discredited because of shale oil. It has not. And that only increases the dramatic shock effect it will have when it finally becomes obvious that peak oil has arrived. ..."
"... Of course some will agree but say that "No big deal, renewables will make peak oil a non event!" And these folks are in for an even bigger shock than the peak oil deniers . Well, in my opinion anyway. ..."
"... To me, that is like a farmer saying I estimate next year and beyond that the cost of seed, chemicals, fertilizer, fuel, labor, real estate taxes, etc, will fall by 60%. I am not familiar with any commodity based business where that is reality. Yet almost ALL US LTO did the same thing, 30-60% reduction. ..."
"... The point is, had they not done that, they would have basically lost ALL of their proved reserves at 2015 prices. My point is, how can a company that is losing large amounts, pre-reserve write downs, have any economic reserves? If the costs cannot all be recovered for the well at SEC prices, there are no reserves for that well. ..."
"... 2016 SEC prices are about $10 lower. We shall see what they come up with. ..."
"... I also agree peak oil will be obvious before long, I think eventually (by 2020 at least unless a big recession intervenes) oil prices will rise, maybe to $100/b. Most will expect a big surge in output, but any surge will be small (1 Mb/d at most) and likely short lived (if it happens at all). ..."
Dec 09, 2016 | peakoilbarrel.com
Survivalist says: 12/07/2016 at 5:06 pm
Hi Ron. Thanks for your awesome website. The word blog doesn't do it justice.. It is truly the best, and attracts a great group of commenters. May I ask how you might see 'serious depletion' playing out, roughly speaking? Do you have any predictions or wild ass guesses on the slope of the production decline or perhaps where world crude plus condensate production might be by 2020 and/or 2025? Given your wisdom and insight into human nature what are your feelings about the human response to these future conditions?
Ron Patterson says: 12/07/2016 at 6:57 pm
Do you have any predictions or wild ass guesses on the slope of the production decline or perhaps where world crude plus condensate production might be by 2020 and/or 2025?

Not really. We all had a pretty good idea where things were heading until shale oil raised its ugly head. No one that I know of predicted that. But now it looks like shale oil is a USA phenomenon with no appreciable production anywhere else in the world.

My strong feeling right now is that the shale oil phenomenon has given the entire world the idea that peak oil is, or was, an illusion or an idea that had no valid support in the real world.

But peak oil is as real as it ever was. The amount of recoverable oil in the ground is finite. We may have had the numbers wrong in our personifications because of shale oil. But that does not change the big picture. The peak oil phenomenon is as real as it ever was.

The real danger is that the media, as well as the general public, has been sold the idea that peak oil has now been discredited because of shale oil. It has not. And that only increases the dramatic shock effect it will have when it finally becomes obvious that peak oil has arrived.

Of course some will agree but say that "No big deal, renewables will make peak oil a non event!" And these folks are in for an even bigger shock than the peak oil deniers . Well, in my opinion anyway.

shallow sand says: 12/07/2016 at 7:27 pm
Ron.

Like the "US phenomenon" comment.

2016 10K will be out in late February-early March for US LTO producers.

It will be interesting to compare 2014, 2015 and 2016. In particular I am waiting to see the estimates of future cash flows to see how much more the engineering firms let them slash future estimated production costs and estimated future development costs.

In my opinion, there was a lot of hocus pocus in those particular numbers, which, of course provide the basis for proved reserves and PV10.

The amounts slashed from 2014 to 2015 were incredible, for example Mr. Hamm's CLR dropped its estimate of future production costs by 60%.

To me, that is like a farmer saying I estimate next year and beyond that the cost of seed, chemicals, fertilizer, fuel, labor, real estate taxes, etc, will fall by 60%. I am not familiar with any commodity based business where that is reality. Yet almost ALL US LTO did the same thing, 30-60% reduction.

The point is, had they not done that, they would have basically lost ALL of their proved reserves at 2015 prices. My point is, how can a company that is losing large amounts, pre-reserve write downs, have any economic reserves? If the costs cannot all be recovered for the well at SEC prices, there are no reserves for that well.

2016 SEC prices are about $10 lower. We shall see what they come up with.

Oldfarmermac says: 12/08/2016 at 3:15 pm
"And these folks are in for an even bigger shock than the peak oil deniers . Well, in my opinion anyway."

I think the odds are pretty good that Ron is right. We can hope that Dennis C and the others who think production will stay on a plateau for a while and then gradually decline rather slowly are right.

If they are, and the electric car industry does as well as hoped, then the economy national and world wide can probably adapt fast enough to avoid catastrophic economic depression brought on specifically by scarce and expensive oil.

If for some reason, any reason, oil production declines sharply and suddenly, for a long period or permanently, we are going to be in a world of hurt.

People need not starve, at least in richer and economically advanced countries, but millions of people could lose their jobs and a lot of businesses dependent on cheap travel would fail. The effects of these lost jobs would expand outward thru the economy doing Sky Daddy alone knows how much damage.

In poor countries, starvation is a real possibility.

The time frame I have in mind in making this comment is out to twenty or thirty years. After that, it's anybody's guess what the population will be, and what the economy will be like.Hell, it's anybody's guess as far as next week is concerned, so far as that goes.

Dennis Coyne says: 12/07/2016 at 6:30 pm
Hi Ron

I agree.

Plateau until 2019 or 2020 then some decline slow at first and gradually accelerating. Unless a recession hits in that case acceleration is more rapid.

Ron Patterson says: 12/07/2016 at 7:00 pm
Thanks Dennis, on the rare occasion where we agree. :-)
Dennis Coyne says: 12/07/2016 at 8:00 pm
Hi Ron,

I also agree peak oil will be obvious before long, I think eventually (by 2020 at least unless a big recession intervenes) oil prices will rise, maybe to $100/b. Most will expect a big surge in output, but any surge will be small (1 Mb/d at most) and likely short lived (if it happens at all).

Whether oil prices spike and this leads to either Great Depression(GD) 2 or a lot of EV and plugin sales is unknown, it might be the latter at first with GD2 following between 2025 and 2030. It will depend on how quickly oil output falls, I think it might be 1% or less until 2030 if oil prices are high with faster decline rates once the depression hits.

As usual big WAGs by me. Of course nobody knows, but your insights on how things might play out would be interesting.

Guy Minton says: 12/07/2016 at 8:00 pm
You are a smart man, Dennis 😊
Dennis Coyne says: 12/07/2016 at 8:01 pm
Hi Guy,

When I agree with Ron of course. LOL.

BloomingDave says: 12/07/2016 at 9:07 pm
Hi Dennis,
If I am not mistaken, you have moved up your estimate of global petroleum peak, and perhaps the pace of the decline.
Just months ago, your opinion was that it would not occur until 2025. Are you moved by any specifics that you would like to share?
Thank you, and as a follower of your good work, I appreciate your insight.
Javier says: 12/09/2016 at 6:48 am
Yes, that is a change of position. It used to be 2025. Another advance and we are in.

[Dec 09, 2016] EIAs Short-Term Energy Outlook Peak Oil Barrel

Dec 09, 2016 | peakoilbarrel.com
VK says: 12/07/2016 at 1:17 pm
Steve at SRS Rocco report has a new, very informative post up showing that Middle East oil exports are lower today than 40 years ago!

"According to the 2016 BP Statistical Review, the Middle East produced 30.10 mbd of oil in 2015 compared to 22.35 mbd in 1976. This was a growth of 7.75 mbd. However, Middle East domestic oil consumption increased from 1.51 mbd in 1976 to 9.57 mbd in 2015. Thus, the Middle Eastern economies devoured an additional 8.06 mbd of oil during that 40 year time-period."

Would be great to see an update on the global export land model that Jeff Brown (westexas) used to update us on. How much C+C is available on the global markets as of today after domestic consumption?

Jeff says: 12/07/2016 at 2:04 pm
I´m not Jeff B. but if I remember last version of BP stats. correctly, the net export market has been on a bumpy plateau between 2005-2015. It has varied between 41-44 Mb/day (approx.). 2015 set a record which was just slightly higher than 2005. It´s possible that 2016 will be slightly higher.
Survivalist says: 12/07/2016 at 3:31 pm
I like this link.

http://mazamascience.com/OilExport/

World exports have been bumpy flat for 10 years or so.

Ecuador might be an importer soon'ish.

I like this site as I take an interest in observing the changes as exporters become importers. The country charts provide some rough idea of those timings.

Jeff says: 12/08/2016 at 3:39 am
2015 was indeed a net export record. The increase came mainly from Canada, Iraq and Russia. Iran may boost net exports in 2016, Kazakhstan will also add some. At least to me it seems unlikely that net-exports will grow substantially above the 2015/16-level. Increase from the mentioned countries will be needed to compensate decline in Mexico, Colombia, etc (+problems in Venezuela). Seems more likely it will continue on the plateau or decline. Nigeria and Libya are wildcards.

mazamascience also use BP-data but seems to give a much higher number, ~48Mb/day. Don't know why.

AlexS says: 12/08/2016 at 6:01 am
How do you calculate world total net export numbers if total global exports = total global imports?

Meanwhile, BP statistics for world oil exports (not net exports) show a rising trend.
I expect further increase in 2016, due to rising exports from Saudi Arabia, Iran, Iraq and Russia.

AlexS says: 12/08/2016 at 6:50 am
The IEA Oil Market Report, November 2016 on Iran's oil production and exports:

"With gains of 810 kb/d so far this year, Iran has emerged as the world's fastest source of supply growth. Crude oil output rose by 40 kb/d in October to reach a pre-sanctions rate of 3.72 mb/d and shipments of crude oil climbed well above 2.4 mb/d, a rate not seen in at least seven years.
For six straight months, the National Iranian Oil Co (NIOC) has been exporting more than 2 mb/d of crude – double the volume seen under sanctions."

AlexS says: 12/08/2016 at 6:54 am
Iraqi oil production and exports in 2016 were also above 2015 levels

source: IEA OMR, November 2016

AlexS says: 12/08/2016 at 6:59 am
According to JODI, Saudi Arabia's crude and refined product exports in January-September 2016 was about 460 kb/d higher than 2015 average.

Watcher says: 12/08/2016 at 10:16 am
So that says KSA domestic consumption is 2ish mbpd?

Are we comfortable with that?

AlexS says: 12/08/2016 at 10:36 am
3.3 mb/d in 2015

http://peakoilbarrel.com/texas-update-november-2016/#comment-587974

Watcher says: 12/08/2016 at 4:32 pm
But that's not what your chart says, in controvention to BP's data.

Your chart says KSA exports at 9. Production is known or thought to be 10.5. And since consumption is all liquids, that chart's products level is the correct number.

9 subtracted from 10.5. Leaves 1.5 consumption.

This looks bogus.

Did email BP. Waiting.

AlexS says: 12/08/2016 at 5:13 pm
10.5 is crude only.
Total liquids (including condensate and NGLs) was 12.0 mb/d in 2015 (BP number)
Jeff says: 12/08/2016 at 7:00 am
BP data. Only include countires if production > consumtion. Net export = sum(production – consumption).

Compared with your figure, US, for example, is thus not included, Canada has a lower value (import light), etc.

[Nov 28, 2016] I think oil prices are a long way away from being high enough to save the shale oil industry.

Notable quotes:
"... I do not understand the financial behavior of shale oil development, no. In the Bakken and the Eagle Ford it was indeed about reserve "growth," as Alex points out. Growth at the expense of profitability. That model failed (look at the debt, debt to asset ratios and losses for operators in those two shale oil plays) because the price of oil collapsed. ..."
"... Now, in spite of that, the Permian is using the same business model; growth at the expense of profitability. It is borrowing billions in the bottom of a price down cycle (it thinks) believing prices have no where to go but up. ..."
"... I think oil prices are a long way away from being high enough to save the shale oil industry. ..."
"... We may be overthinking all this and Alex is right again; it may be a simple matter of everyone taking advantage of a loosey goosey monetary policy in America. Money gets printed, Central Banks give it away, lenders are in desperate need of miniscule yields and CEO's and upper management borrow it, make millions personally on bonuses and incentives for growing reserves, then walk away from the whole shebang (Sheffield) before the loans come due. America looks the other way because they get cheap gasoline. ..."
Nov 28, 2016 | peakoilbarrel.com
Mike says:

11/27/2016 at 12:12 pm
I do not understand the financial behavior of shale oil development, no. In the Bakken and the Eagle Ford it was indeed about reserve "growth," as Alex points out. Growth at the expense of profitability. That model failed (look at the debt, debt to asset ratios and losses for operators in those two shale oil plays) because the price of oil collapsed.

Now, in spite of that, the Permian is using the same business model; growth at the expense of profitability. It is borrowing billions in the bottom of a price down cycle (it thinks) believing prices have no where to go but up. I would say this particular shale play might work, except that from the data I see the UR's on those wells are going to be pitiful at best, far less than the Bakken. Unless it is by the shear number of wells those operators are not going to have a lot of reserves that will appreciate with rising prices. It will therefore fail too, just like the others, perhaps for different reasons, I don't know. I think oil prices are a long way away from being high enough to save the shale oil industry.

We may be overthinking all this and Alex is right again; it may be a simple matter of everyone taking advantage of a loosey goosey monetary policy in America. Money gets printed, Central Banks give it away, lenders are in desperate need of miniscule yields and CEO's and upper management borrow it, make millions personally on bonuses and incentives for growing reserves, then walk away from the whole shebang (Sheffield) before the loans come due. America looks the other way because they get cheap gasoline.

John S says: 11/27/2016 at 1:46 pm
http://fuelfix.com/blog/2016/11/22/pioneer-denied-request-to-reclassify-oil-wells/

Happy Thanksgiving Mike! This article is for you! The RRC just refused to allow Pioneer to reclassify oil wells in the Eagle Ford to .. wait for it .GAS WELLS.

I believe Pioneer just admitted the you, Shallow, Alex, and the others have been right all along about the GOR going up, up and up.

It seems that Pioneer is trying to take advantage of the "high cost gas tax credit" designed to encourage gas production in HIGH COST low permeable tight gas reservoirs.

Interestingly, this move by Pioneer has initiated a discussion about whether there should be a new category for classifying wells. Hmmm sounds like the industry is about to hit the new Texas Legislative session up for some new tax relief to encourage horizontal drilling in its new favorite geological province the Permian Basin. But it will apply to the Barnett, Haynesville, Eagle Ford, and all those other disasters.

Mike says: 11/27/2016 at 7:22 pm
Happy Thanksgiving to you too, John -- I had actually seen this before. Scoundrels they are, one and all; Pioneer too, a Texas Company start to finish. The TRRC will roll over in another year or so, watch.
Dennis Coyne says: 11/27/2016 at 8:01 pm
Hi Mike,

Despite the CEOs not worrying about profits, I would think at some point the people buying the bonds or stock of these companies would realize that the Emperor is naked.

Eventually when enough investors get burned, the money will stop flowing. Maybe not in 2016, and perhaps not in 2017, but if oil prices remain low for the long term as experts in the field seem to suggest is a likely event (though nobody really knows future oil prices), the money will dry up. In that case these companies are done.

Dennis Coyne says: 11/27/2016 at 8:04 pm
Hi Alex,

Eventually the piper must be paid, low oil prices (for another 2 years) will be the LTO focused companies undoing in my opinion.

[Nov 28, 2016] IEA expects oil investment to fall for third year in 2017

Notable quotes:
"... "Our analysis shows we are entering a period of greater oil price volatility (partly) as a result of three years in a row of global oil investments in decline: in 2015, 2016 and most likely 2017," IEA director general Fatih Birol said, speaking at an energy conference in Tokyo. ..."
"... Oil prices have risen to their highest in nearly a month, as expectations grow among traders and investors that OPEC will agree to cut production, but market watchers reckon a deal may pack less punch than Saudi Arabia and its partners want. ..."
"... BMI's outlook is more optimistic than groups like the International Energy Agency, which said last week that the industry might cut spending in 2017 for a third year in a row as companies continue to grapple with weaker finances. Oil prices still hover around $50 a barrel, less than half the level of the summer of 2014. ..."
"... The chart below shows Exxon's E&P capex in 2007-2015 (in US$bn). There was a sharp increase in US capex (both in absolute in relative terms) following the XTO deal. In 2015, the company cut spending both in the US and abroad ..."
Nov 28, 2016 | peakoilbarrel.com
AlexS says: 11/26/2016 at 5:50 am
IEA expects oil investment to fall for third year in 2017

Thu Nov 24, 2016
http://www.reuters.com/article/us-iea-oil-investment-idUSKBN13J08H

Investment in new oil production is likely to fall for a third year in 2017 as a global supply glut persists, stoking volatility in crude markets, the head of the International Energy Agency (IEA) said on Thursday.

"Our analysis shows we are entering a period of greater oil price volatility (partly) as a result of three years in a row of global oil investments in decline: in 2015, 2016 and most likely 2017," IEA director general Fatih Birol said, speaking at an energy conference in Tokyo.

"This is the first time in the history of oil that investments are declining three years in a row," he said, adding that this would cause "difficulties" in global oil markets in a few years.

Oil prices have risen to their highest in nearly a month, as expectations grow among traders and investors that OPEC will agree to cut production, but market watchers reckon a deal may pack less punch than Saudi Arabia and its partners want.

The Organization of the Petroleum Exporting Countries meets next week to try to finalize to output curbs.

"Our analysis shows that when prices go to $60, we'll make a big chunk of U.S. shale oil economical and within the nine months to 12 months of time, we may see a response coming from the shale oil and other high-cost areas," Birol told Reuters, speaking in an interview on the sidelines of the conference.
"And this may again put downward pressure on the prices."

Birol said that level would be enough for many U.S. shale companies to restart stalled production, although it would take around nine months for the new supply to reach the market.

The IEA director general said it is still early to speculate what Donald Trump's presidency in the United States will have on energy policies.

"Having said that, both U.S. shale oil and U.S. shale gas have a very strong economic momentum behind them," Birol said.

"Shale gas has significant economic competitiveness today, and we think it will be so in the next years to come."

AlexS says: 11/26/2016 at 7:50 am
Оpposite view on 2017 global upstream capex from BMI Research:

Oil Firm Spending Seen Up in 2017 for First Time Since 2014

September 23, 2016
https://www.bloomberg.com/news/articles/2016-09-23/oil-firms-seen-spending-more-next-year-for-first-time-since-2014

• Capital spending seen growing 2.5% in 2017 and 7%-14% in 2018
• U.S. independents, Asian giants seen spurring spending growth

The oil industry may be ready to open its wallet after two years of slashing investments.

Companies will spend 2.5 percent more on capital expenditure next year than they did this year, the first yearly growth in such spending since 2014, BMI Research said in a Sept. 22 report. Spending will increase by another 7 percent to 14 percent in 2018. It will remain well below the $724 billion spent in 2014, before the worst oil crash in a generation caused firms to cut back on drilling and exploration to conserve cash, the researcher said.

North American independent producers, Asian state-run oil companies and Russian firms are prepared to boost investments next year, outweighing continued cuts from global oil majors such as Exxon Mobil Corp. and Total SA, BMI said, based on company guidance and its own estimates. Spending will increase to a total of $455 billion next year from $444 billion this year, BMI said.

"North America is where we're really expecting things to turn around," Christopher Haines, BMI's head of oil and gas research, said by telephone. "We've seen a push to really reduce costs, reduce spending and take out any waste and inefficiency. These companies have gotten to the point where they're all set up to react."

BMI's outlook is more optimistic than groups like the International Energy Agency, which said last week that the industry might cut spending in 2017 for a third year in a row as companies continue to grapple with weaker finances. Oil prices still hover around $50 a barrel, less than half the level of the summer of 2014.

shallow sand says: 11/26/2016 at 1:18 pm
From what I am reading, Permian hz wells will be drilled in greater numbers in 2017, regardless of price.

These wells are generally less prolific than those in the Bakken and EFS. However, the money has been raised and therefore it will spent.

To me, a good question is how much money is being diverted away from longer term projects that will ultimately produce more oil, to drill these Permian wells?

The Permain wells have no staying power. Under 50 bopd after 24 months is the rule, not the exception. Under 200,000 cumulative in 60 months is the rule, not the exception.

We shall see.

AlexS says: 11/26/2016 at 4:00 pm
"To me, a good question is how much money is being diverted away from longer term projects that will ultimately produce more oil, to drill these Permian wells?"

shallow sand

The companies that are postponing longer term projects are not the same companies that are planning to increase drilling in LTO plays.

Boomer II says: 11/26/2016 at 4:12 pm
"The companies that are postponing longer term projects are not the same companies that are planning to increase drilling in LTO plays."

I assumed he meant investment money. If investors want to be in gas and oil, are they picking the companies with best chance of long-term success (if there is such a thing anymore)?

AlexS says: 11/26/2016 at 4:53 pm
"I assumed he meant investment money. "

Yes, but international oil majors and U.S. shale companies generally have different investor base.

Oil majors are viewed as defensive stocks, slowly growing, but with strong balance sheets, paying high dividends and buying back shares.

On the contrary, shale companies are viewed as high risk – high reward stocks, with aggressive growth strategies, highly leveraged.

shallow sand says: 11/26/2016 at 6:46 pm
I meant both.

ExxonMobil, Chevron, ConnocoPhillips, Hess, Marathon and Oxy all have significant LTO production and all are, or were considered international upstream producers.

I agree the supermajors are defensive stocks. But there were many "growth" stock US companies which explored and produced offshore/internationally or both, prior to the LTO boom.

I may be wrong, we shall see.

AlexS says: 11/26/2016 at 7:39 pm
Most of large US E&Ps and mid-sized integrateds have divested their overseas assets during the years of shale boom.

I'm not sure that Exxon and Chevron are planning to increase their shale exposure in the near term. For Exxon, US upstream operations were hugely loss-making in 2015-16. And it has recently made two relatively large discoveries outside US.

shallow sand says: 11/26/2016 at 11:10 pm
AlexS. Are those XOM international discoveries primarily oil or gas?

Also, for the international assets you refer to which US companies divested, do you know whether the buyers are aggressively developing them? Just a guess, but I suspect maybe not.

11/30 is a big day, hoping for a cut, hard to say if it occurs whether it will be adhered to, other than by maybe the Gulf States.

AlexS says: 11/27/2016 at 6:33 am
shallow sand,

Both are oil discoveries:

1) Liza discovery offshore Guyana, with potential recoverable resource of 800 million to 1.4 billion oil-equivalent barrels

http://news.exxonmobil.com/press-release/exxonmobil-says-second-well-offshore-guyana-confirms-significant-oil-discovery

2) Owowo field offshore Nigeria with a potential recoverable resource of between 500 million and 1 billion barrels.

http://news.exxonmobil.com/press-release/exxonmobil-announces-significant-oil-discovery-offshore-nigeria

shallow sand says: 11/27/2016 at 9:27 am
AlexS. Thank you for the information.

Interesting to note Nexen is a partner in both ventures, while Hess and Chevron are in one each.

I agree XOM has sustained significant losses in North America, but they continue to spend money on new wells. Had they not spent the money they have in North America (both shale and tar sands) would the money have been spent elsewhere. A tough one to know the answer to.

I recall XOM was going to partner in Russia on projects and those were halted for political reasons? Did those projects go ahead without them?

AlexS says: 11/27/2016 at 6:39 pm
shallow sand,

I'm not saying that Exxon stopped investing in U.S. upstream. My point is that oil supermajors, like Exxon, Chevron, BP, Shell and Total are not diverting investments from deep offshore, LNG and other long-term projects to U.S. shale. They cut upstream capex both in U.S. and in overseas projects.

The chart below shows Exxon's E&P capex in 2007-2015 (in US$bn). There was a sharp increase in US capex (both in absolute in relative terms) following the XTO deal. In 2015, the company cut spending both in the US and abroad

[Nov 28, 2016] Oil companies shoulder pain of downturn with lower output

Notable quotes:
"... In the second quarter of 2016, the companies reduced production by nearly 930,000 bpd, according to Morgan Stanley. ..."
"... Large oilfields, such as deepwater developments off the coasts of the United States, Brazil, Africa and Southeast Asia, typically take three to five years and billions in investment to develop. ..."
"... "Still, unless investment rebounds relatively soon, this steep downward trend is likely to resume in 2018 and beyond." ..."
"... We haven't even begun to see a "steep downward trend" yet. As to "softening" – there is less new production coming on next year, overall and for the IOCs, than this – highlighting Canada, Brazil etc. doesn't change that. ..."
"... Also when are they going to actually understand that the companies don't ever "slash" output, like its a choice – depletion does it for them. ..."
"... I don't know when peak decent reporting happened but it's well into decline now (another big internet age negative). ..."
"... Also, the author quotes a report by Morgan Stanley (that we haven't seen). Apparently, those "109 listed companies that produce more than a third of the world's oil" are covered by MS equity research team. And changes in their output may not fully reflect trends in overall global oil production. ..."
"... But I agree that articles in Reuters, Bloomberg and other MSM sources often misinterpret third party research. A recent example are numerous article about USGS assessment of TRR in the Wolfcamp formation ..."
Nov 28, 2016 | peakoilbarrel.com
AlexS says: 11/26/2016 at 5:25 am
Oil companies shoulder pain of downturn with lower output

Nov 24, 2016
http://www.reuters.com/article/us-oil-production-idUSKBN13J0I0

The world's listed oil companies have slashed oil output by 2.4 percent so far this year.

The aggregated production of 109 listed companies that produce more than a third of the world's oil fell in the third quarter of 2016 by 838,000 barrels per day from a year earlier to 33.88 million bpd, data provided by Morgan Stanley showed.

In the second quarter of 2016, the companies reduced production by nearly 930,000 bpd, according to Morgan Stanley.

The firms include national oil champions of China, Russia and Brazil, international producers such as Exxon Mobil and Royal Dutch Shell, as well as U.S. shale oil producers like EOG Resources and Occidental Petroleum.

The drop in oil companies' output is particularly compelling given the increase in 2015, when third-quarter production rose by some 1.9 million bpd.

"Clearly, we have seen a large swing in the year-on-year trend in production, from strong growth as recent as a year ago, now to steep decline. This is the outcome of the strong cutbacks in investment," Morgan Stanley equity analyst Martijn Rats said.

Capital expenditure for the companies combined more than halved from $136 billion in the third quarter of 2014 to $58 billion in the same period this year, according to Rats.

Oil executives and the International Energy Agency have warned that a sharp drop in global investment in oil and gas would result in a supply shortage by the end of the decade.

Large oilfields, such as deepwater developments off the coasts of the United States, Brazil, Africa and Southeast Asia, typically take three to five years and billions in investment to develop.

Cost reductions and increased efficiencies have only partly offset the drop in production as a result of the lower investment. Technological advancements have also helped boost onshore U.S shale production.

"These declines should temporarily soften in 2017 as new fields are coming on-stream in Canada, Brazil, the former Soviet Union and U.S. tight oil probably stabilizes," Rats said.

"Still, unless investment rebounds relatively soon, this steep downward trend is likely to resume in 2018 and beyond."

George Kaplan says: 11/26/2016 at 6:03 am
We haven't even begun to see a "steep downward trend" yet. As to "softening" – there is less new production coming on next year, overall and for the IOCs, than this – highlighting Canada, Brazil etc. doesn't change that.

When is someone in Reuters or Bloomberg going to figure out that 2017 + 3 (or 5) + 1 (for FEED and FID approval at the beginning and ramp up at the end) = 2021 (or 2023) so there is no way to cover drops "at the end of the decade" now. Also when are they going to actually understand that the companies don't ever "slash" output, like its a choice – depletion does it for them.

And how about this paragraph

"Cost reductions and increased efficiencies have only partly offset the drop in production as a result of the lower investment. Technological advancements have also helped boost onshore U.S shale production."

He/she has suddenly started to talk about company finances rather than production, but without actually telling the reading public.

Cost reductions caused the drop for heavens sake. "Increased efficiencies" and "technological advancements" – do you think the author has the faintest idea what that actually means and how it is related to anything else he says.

I don't know when peak decent reporting happened but it's well into decline now (another big internet age negative).

AlexS says: 11/26/2016 at 8:29 am
"When is someone in Reuters or Bloomberg going to figure out that 2017 + 3 (or 5) + 1 (for FEED and FID approval at the beginning and ramp up at the end) = 2021 (or 2023) so there is no way to cover drops "at the end of the decade" now."

It should be actually 2015 + 3 (or 5), as pre-FID projects have been posponed since end-2014 – early 2015.

Also, the author quotes a report by Morgan Stanley (that we haven't seen). Apparently, those "109 listed companies that produce more than a third of the world's oil" are covered by MS equity research team. And changes in their output may not fully reflect trends in overall global oil production.

But I agree that articles in Reuters, Bloomberg and other MSM sources often misinterpret third party research. A recent example are numerous article about USGS assessment of TRR in the Wolfcamp formation

[Nov 21, 2016] Bigger fracs which cost more money result in higher IPs and higher ensuing 90 day production results. That generates more cash flow and allows for higher EURs that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that.

Notable quotes:
"... This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet. ..."
"... It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices. ..."
"... Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. ..."
peakoilbarrel.com
Hi,

Here are my updates as usual. GOR declined or stayed flat for all years except 2010 in September. Is it the beginning of a new trend?

FreddyW says: 11/16/2016 at 3:50 pm
Here is the production graph. Not that much has happened. There was a big drop for 2011. 2009 on the other hand saw an increase. Up to the left, which is very hard to see, 2015 continues to follow 2014 which follows 2013 which follows 2012. Will we see 2013 reach 2007 the next few months?

Watcher says: 11/16/2016 at 10:34 pm
Freddy, these latest years, the IP months are chopped at the top. Any chance of showing those?

The motivation would be to get a look at the alleged spectacular technology advances in the past, oh, 2 yrs.

FreddyW says: 11/17/2016 at 2:10 pm
Its on purpose both because I wanted to zoom in and because the data for first 18 months or so for the method I used above is not very usable. Bellow is the production profile which is better for seeing differences the first 18 months. Above graph is roughly 6 months ahead of the production profile graph.

Watcher says: 11/17/2016 at 2:40 pm
Excellent.

And I guess we can all see no technological breakthru. 2014's green line looks superior to first 3 mos 2015.

2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper decline at that point and is likely going to intersect 2014's line probably within the year.

There is zero evidence on that compilation of any technological breakthrough surging output per well in the past 2-3 yrs.

In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular EUR improvement.

And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also no evidence of sweetspots first.

I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with inferior technology, and then as they became less sweet the technological breakthroughs brought output up to look the same.

Too
Much
Coincidence.

It's all bogus.

Watcher says: 11/17/2016 at 8:12 pm
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.

And it would be far too much coincidence for techno breakthrus to just happen to increase flow the exact amount lost from exhausting sweet spots.

This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet.

Mike says: 11/17/2016 at 8:59 pm
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.

Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that.

Nobody is breaking new ground or making big strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank areas will be even less economical (if that is possible) and will result in significantly less UR per well. That is what is ridiculous about modeling the future based on X wells per month and trying to determine how much unconventional shale oil can be produced in the US thru 2035. The term, "past performance is not indicative of future results?" We invented that phrase 120 years ago in the oil business.

Watcher says: 11/18/2016 at 12:03 am
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra stages post 2008/9/10. How could there not be going from 15 stages to 30+?

I see NO magic post peak. They all descend exactly the same way and by 18-20 months every drill year is lined up. That's actually astounding - given 15 vs 30 stages. There should be more volume draining on day 1 and year 2, but the flow is the same at month 20+ for all drill years. This should kill the profitability on those later wells because 30 stages must cost more.

But profit is not required when you MUST have oil.

Watcher says: 11/18/2016 at 12:14 am
You know, that is absolutely insane.

Freddy, is there something going on in the data? How can 30 stage long laterals flow the same at production month 24 as the earlier dated wells at their production month 24 –whose lengths of well were MUCH shorter?

FreddyW says: 11/18/2016 at 2:55 pm
I can only speculate why the curves look like they do. It could be that the newer wells would have produced more than the older wells, but closer well spacing is causing the UR to go down.
FreddyW says: 11/16/2016 at 3:57 pm
Here is the updated yearly decline rate graph. 2010 has seen increased decline rates as I suspected. The curves are currently gathering in the 15%-20% range.

Dennis Coyne says: 11/16/2016 at 5:33 pm
Hi FreddyW,

What is the annual decline rate of the 2007 wells from month 98 to month 117 and how many wells in that sample (it may be too low to tell us much)?

FreddyW says: 11/16/2016 at 6:02 pm
2007 only has 161 wells. So it makes the production curve a bit noisy as you can see above. Current yearly decline rate for 2007 is 7,2% and the average from month 98 to 117 would translate to a 10,3% yearly decline rate. The 2007 curve look quite different from the other curves, so thats why I did not include it.
Dennis Coyne says: 11/16/2016 at 9:27 pm
Hi Freddy W,

Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one way to do it would be to look at the natural log of monthly output vs month for each year and see where the curve starts to become straight indicating exponential decline. The decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely different, I am speculating about the possible cause.

FreddyW says: 11/17/2016 at 3:37 pm
2007 had much lower initial production and the long late plateau gives it a low decline rate also. But yes, initial decline rates look similar to the other curves. If you look at the individual 2007 wells then you can see that some of them have similar increases to production as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that those increases are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau. If that is the case, then 2007 may not be different from the others at and we will see increased decline rates in the future.

Regarding natural log plots. Yes it could be good if you want to find a constant exponential decline. But we are not there yet as you can see in above graph.

One good reason why decline rates are increasing is because of the GOR increase. When they pump up the oil so fast that GOR is increasing, then it's expected that there are some production increases first but higher decline rates later. Perhaps completion techniques have something to do with it also. Well spacing is getting closer and closer also and is definitely close enough in some areas to cause reductions in UR. But I would expect lower inital production rather than higher decline rates from that. But maybe I´m wrong.

Dennis Coyne says: 11/17/2016 at 8:42 am
Hi FreddyW,

Do you have an estimate of the number of wells completed in North Dakota in September? Does the 71 wells completed estimate by Helms seem correct?

Dennis Coyne says: 11/17/2016 at 12:40 pm
Hi FreddyW,

Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed in Sept 2016.

FreddyW says: 11/17/2016 at 2:19 pm
I have 75 in my data, so about the same. They have increased the number of new wells quite alot the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it increased withouth the rig count going up. But I see that the rig count has gone up now too.
Pete Mason says: 11/16/2016 at 3:49 pm
Ron you say " Bakken production continues to decline though I expect it to level off soon."
A few words of wisdom as to the main reasons why it would level off? Price rise?
Dennis Coyne says: 11/16/2016 at 5:28 pm
Hi Pete,

Even though you asked Ron. He might think that the decline in the number of new wells per month may have stabilized at around 71 new wells per month. If that rate of new completions per month stays the same there will still be decline but the rate of decline will be slower. Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).

Guy Minton says: 11/16/2016 at 8:41 pm
I am not so convinced that either Texas or the Bakken is finished declining at the current level of completions. There was consistent completions of over 1000 wells in Texas until about October of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than they are completing.
I remember reading one projection recently for what wells will be doing over time in the Eagle Ford. They ran those projections for a well for over 22 years. Not sure which planet we are talking about, but in Texas an Eagle Ford does well to survive 6 years. They keep referring to an Eagle Ford producing half of what they will in the first two years. In most areas, I would say that it is half in the first year.
The EIA, IEA, Opec, and most pundits have the US shale drilling turning on a dime when the oil price reaches a certain level. If it was at a hundred now, it would still take about two years to significantly increase production, if it ever happens. I am not a big believer that US shale is the new spigot for supply.
Dennis Coyne says: 11/16/2016 at 10:03 pm
Hi Guy,

The wells being shut in are not nearly as important as the number of wells completed because the output volume is so different. So the average well in the Eagle Ford in its second month of production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So about 37 average wells need to be shut in to offset one average new well completion.

Point is that total well counts are not so important, it is well completions that drive output higher.

Output is falling because fewer wells are being completed. When oil prices rise and profits increase, completions per month will increase and slow the decline rate and eventually raise output if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec 2017 about 79 new wells per month is enough to cause a slight increase in output. My model slightly underestimates Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30 kb/d lower than actual output (3% too low), my well profile may be slightly too low, but I expect eventually new well EUR will start to decrease and my model will start to match actual output better by mid 2017 as sweet spots run out of room for new wells.

Guy Minton says: 11/17/2016 at 7:14 am
Guess I will remember that for the future. The number of producing wells is not important. Kinda like I got pooh poohed when I said the production would drop to over 1 million barrels back in early 2015.
Dennis Coyne says: 11/17/2016 at 10:39 am
Hi Guy,

Do you agree that the shut in wells tend to be low output wells? So if I shut down 37 of those but complete one well the net change in output is zero.

Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the net change in output would be zero, but there would be 19,000 fewer producing wells, if we assume the average output of the 1000 new wells completed was 200 b/d for the year and the stripper wells produced 10 b/d on average.

How much do you expect output to fall in the US by Dec 2017?

Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by about 1 million barrels per day from April 2015 to July 2016, can you point me to your comment where you predicted this?

Tell us what it will be in August 2017.

I expected the fall in supply would lead to higher prices, I did not expect World output to be as resilient as it has been and I also did not realize how oversupplied the market was in April 2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan to April, so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US output has decreased by 635 kb/d.

If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would also have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400 kb/d. If we consider 12 month average output of World C+C, the decline has been 340 kb/d from the 12 month average peak in August 2015 (centered 12 month average).

Guy Minton says: 11/18/2016 at 4:50 am
The dropping numbers are not as much from the wells that produce less than 10 barrels a day, but from those producing greater than 10, but less than 100. The ones producing greater than 100 are remaining at a consistent level over 9000 to 9500. The prediction on one million was as to the US shale only. It is your site, you can search it better than I can,
Guy Minton says: 11/18/2016 at 6:20 am
But then don't take my word for it. You can find the same information under the Texas RRC site under oil and gas/research and statistics/well distribution tables. Current production for Sep can be found at online research queries/statewide. It is still dropping, and will long term at the current activity level. Production drop for oil, only, is a little over 40k per day barrels, and condensate is lower for September. Proofs in the pudding.
My guess is that you would see a lot more plugging reports, if it were not so expensive to plug a well. At net income levels where they are, I expect they would put that off as long as they could.
AlexS says: 11/16/2016 at 8:51 pm
Statistics for North Dakota and the Bakken oil production are perfect, but not for well completions.

From the Director's Cut:

"The number of well completions rose from 63(final) in August to 71(preliminary) in September"
(North Dakota total)

From the EIA DPR:

The number of well completions declined from 71 in August to 52 in September and rose to 58 in October
(Bakken North Dakota and Montana).

Wells drilled, completed, and DUCs in the Bakken.
Source: EIA DPR, November 2016

Dennis Coyne says: 11/16/2016 at 9:36 pm
Hi Alex S,

I trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno Peters data has 66 completions in August 2016, he has not put up his post for the Sept data yet so I am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno tends to be spot on for the Bakken data, for Texas he relies on RRC data which is not very good.

shallow sand says: 11/17/2016 at 8:36 am
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.

It appears this was because another 13 wells in the field were recently completed.

It appears that when all 29 wells are returned to full production, this field will be very prolific initially. Therefore, on this one field alone, we could see some impact for the entire state.

Does anyone know if these wells are part of Whiting's JV? Telling if they had to do that on these strong wells. Bakken just not close to economic.

I also note that average production days per well in for EOG in Parshall was 24. I haven't looked at some of the other "older" large fields yet, but assume the numbers are similar.

shallow sand says: 11/17/2016 at 8:58 am
Also, over 3000 Hz wells in ND produced less than 1000 BO in 9/16.

This is just for wells with first production 1/1/07 or later.

Dennis Coyne says: 11/17/2016 at 10:57 am
Hi Shallow sand,

I agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk costs in wells drilled but not completed and running the numbers based on whether they can pay back the completion costs. Everyone may be hoping the other guys fail and are just trying to pay the bills as best they can, not sure if just stopping altogether is the best strategy.

There is the old adage that when your in a hole, more digging doesn't help much. 🙂

So my model just assumes continued completions at the August rate for about 12 months with gradually rising prices as the market starts to balance, then a gradual increase in completions as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90 completions per month 18 months later). At that point oil prices have risen to $97/b and LTO companies are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at that level for 40 years (not likely, but the model is simplistic).

I could easily do a model with no wells completed, but I doubt that will be correct. Suggestions?

shallow sand says: 11/18/2016 at 8:20 am
Dennis. As we have discussed before, tough to model when there is no way to be accurate regarding the oil price.

I continue to contend that there will be no quick price recovery without an OPEC cut. Further, the US dollar is very important too, as are interest rates.

Dennis Coyne says: 11/18/2016 at 10:03 am
Hi Shallow sand,

At some point OPEC may not be able to increase output much more and overall World supply will increase less than demand. My guess is that this will occur by mid 2017 and oil prices will rise. OPEC output from Libya an Nigeria has recovered, but this can only go so far, maybe another 1 Mb/d at most. I don't expect any big increases from other OPEC nations in the near term.

A big guess as to oil prices has to be made to do a model.

I believe my guess is conservative, but maybe oil prices will remain where they are now beyond mid 2017.

I expected World supply to have fallen much more quickly than has been the case at oil prices of $50/b.

George Kaplan says: 11/17/2016 at 3:31 am
Probably to do with how confidential wells are included.
AlexS says: 11/17/2016 at 4:42 am
RBN explains EIA methodology:

"EIA does this by using a relatively new dataset-FracFocus.org's national fracking chemical registry-to identify the completion phase, marked by the first fracking. If a well shows up on the registry, it's considered completed "

Sydney Mike says: 11/17/2016 at 2:19 am
There is an unlikely peak oil related editorial writer hiding in the most unlikely place: a weekly English business paper called Capital Ethiopia. The latest editorial is again putting an excellent perspective on world events. http://capitalethiopia.com/2016/11/15/system-failure/#.WC1ZCvl9600

For the record, I have no interest or connection to this publication other than that of a paying reader.

Wouldn't it be nice if mainstream publications would sound a bit more like this.

Watcher says: 11/17/2016 at 11:34 am
the word oil does not appear anywhere on that.
Pete Mason says: 11/17/2016 at 4:56 am
Thanks all. I thought that the red queen concept meant that there had to be an increase in the rate of completions. So that 71 year-on-year in north Dakota would only stabilise temporarily. Perhaps the loss of sweet spots are being counteracted by the improvements in technology? I'm assuming that even with difficulties of financing there will be a swift increase in completions should the oil price take off, but not sure how sustainable this would be
Oldfarmermac says: 11/17/2016 at 6:03 am
Hi Pete,

Sometimes I think that once the price of oil is up enough that sellers can hedge the their selling price for two or three years at a profitable level, it will hardly matter what the banks have to say about financing new wells.

At five to ten million apiece, there will probably be plenty of money coming out of various deep pockets to get the well drilling ball rolling again, if the profits look good.

Sometimes the folks who think the industry will not be able to raise money forget that it's not a scratch job anymore. The land surveys, roads, a good bit of pipeline, housing, leases, etc are already in place, meaning all it takes to get the oil started now is a drill and frack rig.

I don't know what the price will have to be, but considering that a lot of lease and other money is a sunk cost that can't be recovered, and will have to be written off, along with the mountain of debts accumulated so far, the price might be lower than a lot of people estimate.

Bankruptcy of old owners results in lowering the price at which an old business makes money for its new owners.

Dennis Coyne says: 11/17/2016 at 8:32 am
Hi Pete,

The Red Queen effect is that more and more wells need to be completed to increase output. As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output it might require 120 wells to be completed to maintain output (if new well EUR did not eventually decrease), but at 850 kb/d it might require about 78 new wells per month to maintain output.

Heinrich Leopold says: 11/17/2016 at 8:11 am
The FED oil production number for October came out yesterday. In below chart the production decline (blue line) is the same as in the previous month, yet the trend is still a massive decline year over year. In my view year over year comparison can show the dynamic of a trend. And it shows clearly that in the current cycle the oil price recovery is – in contrast to the cycle in 2008/9 – very slow and tentative.

The year over year oil price (green line in below chart) actually decreased again year over year and the risk of a double dip in the oil price is growing by the day. Drilling follows very cautiously the oil price in a parallel line (red line in below chart). If there would be really a technological advantage for shale, the red and the green line would not be paralell, but the red line for drilling would rise much stronger. This is actually the case for Middle East drilling, which barely fell during this cycle. This indicates that most Middle East producers still have high margins at the current oil price. Middle East producers – and also Russia – can quite easily cope with an oil price of 40 +/- 10 USD per barrel. This is why I think that the oil price will bounce at the bottom of the barrel within above range for a few years.

There is also something interesting going on with the world economy. The shippers rose exponentionally over the last few days (DRYS up over 1000%). Also the baltic Dry index is up 600% since the beginning of this year. House prices here in London fell – mostly at the high end. Rents for expensives homes are down by up to 36%. Donald Trump has clearly changed something already as it becomes increasingly clear that the dollar hoarders are paying for the infrastructure spending. I am not sure if he understands that he is doing a lot of harm to his own business empire as well.

Wake says: 11/17/2016 at 3:30 pm
I expect if that depressing old banker were here he would note that instability is dangerous, and that all the moves in treasuries currency and possibly trade flow create changes of which the results are difficult or impossible to predict
Oldfarmermac says: 11/18/2016 at 7:55 am
Hi Heinrich,

I can easily understand your assertion that Middle Eastern and Russian oil is profitable at forty bucks.

But if the price is to stay around forty, then it follows that you think that between them, the producers in the Middle East and Russia will be able to supply all the oil the world wants for the next few years.

Am I correct in saying this?

Do you think western producers will continue to pump enough at a loss ( most of them are apparently losing money at forty bucks ) to make up the difference?

If you are willing to venture a guess, when do you think the price will get back into the sixty dollar and up range?

If you think it won't for a lot of years, is that because you believe the economy is will be that anemic, or because electric cars will substantially reduce demand, or both ? Or maybe you have other reasons ?

Heinrich Leopold says: 11/18/2016 at 9:49 am
oldfarmermac,

The US has thrown the gauntlet to OPEC by claiming to becoming an oil net exporter. This has brought OPEC in a very difficult situation. If they cut – and oil gets to 70 USD per barrel – shale will pick up the slack and produce the amount OPEC has cut within a short period of time. So, OPEC is forced to cut again, until it has lost a lot of market share – and thus also a lot of revenue.

In my view OPEC has no other choice than to produce come hell and water – until something breaks. This could be that many shale companies give up or that for instance Iran is not allowed to export as much as they do, or there is a major conflict in the Middle East, or Saudi Arabia is running out of cash ..

He who has the market share now, will cash in when the oil price rises. And it will rise, yet not until something breaks. This is how business works. This is how Microsoft crushed Apple in the nineties in the PC market – and Apple then crushed Nokia in the smart phone market .

I do not think that Saudi Arabia has the freedom to compromise here – even if they want. If they blink they will be crushed by shale producers. So, the stand-off will go on for a while, at a loose-loose situation for both parties. However this is great luck for consumers as they can enjoy low energy prices for 2 to 3 years.

Enno Peters says: 11/17/2016 at 11:48 am
I've also a new post on ND, here .
George Kaplan says: 11/18/2016 at 8:28 am
Do you know why you show a significantly higher number of DUCs than Bloomberg do – as reported here?

http://www.oilandgas360.com/ducs-havent-flown-fast-since-april/

I think your numbers reflect numbers reported from ND DMR but Bloomberg might be closer to reality for wells that will actually ever be completed (just a guess by me though). How do Bloomberg get their numbers (e.g. removing Tight Holes, or removing old wells, not counting non-completed waivers etc.)?

Enno says: 11/18/2016 at 10:56 am
George,

Yes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old wells for example, and already include those that were spud last month (even though maybe casing has not been set). I don't do a lot of filtering, so the actual # wells that really can be completed is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know Bloombergs method exactly, so I can't comment on that.

Oldfarmermac says: 11/18/2016 at 7:57 am
Discussion of Venezuelan politics should be in the open thread, but politics are going to determine how much oil is produced there for the next few years, and the situation looks iffy indeed.

https://www.theguardian.com/commentisfree/2016/nov/17/venezuela-nicolas-maduro-dictatorship-elections-jeremy-corbyn

Watcher says: 11/18/2016 at 2:09 pm
Concerning Freddy's chart of production profile of wells drilled in various years.

They all line up by about month 18 of production. This should not be possible. The later wells have many more stages of frack. They are longer, draining more volume of rock. But the chart says what it says. At month about 18 the 2014 wells are flowing the same rate as 2008 wells. We know stage count has risen over those 6 yrs. 2014 wells should flow a higher rate. The shape of the curve can be the same, but it should be offset higher.

Explanation?

How about above ground issues . . . older wells get pipelines and can flow more oil . . . nah, that's absurd.

There needs to be a physical explanation for this.

AlexS says: 11/18/2016 at 4:36 pm
These new wells have higher IPs, but also higher decline rates.
Closer spacing (see Freddy's comment above) and depletion of the sweet spots may also impact production curves and EURs.
Watcher says: 11/18/2016 at 6:02 pm
That doesn't make sense. They are longer. By a factor of 2ish. How can a 6000 foot lateral flow exactly the same amount 2 yrs into production as a 3000 foot lateral flows 2 yrs into production?

Look at the lines. At 18 months AND BEYOND, these longer laterals flow the same oil rate as the shorter laterals did at the same month number of production. Higher IP and higher decline rate will affect the shape, but There Is Twice The Length..

Dennis Coyne says: 11/18/2016 at 8:15 pm
Hi Watcher,

I don't think we have information on the length of the wells, since 2008 the length of the lateral has not changed, just the number of frack stages and amount of proppant. This seems to primarily affect the output in the first 12 to 18 months, and well spacing and room in the sweet spots no doubt has some effect (offsetting the greater number of frack stages etc.).

Listen to Mike, he knows this stuff.

Watcher says: 11/18/2016 at 8:31 pm
From http://www.dtcenergygroup.com/bakken-5-year-drilling-completion-trends/

STATISTICS

The combination of longer lateral lengths and advancements in completion technology has allowed operators to increase the number of frac stages during completions and space them closer together. The result has been a higher completion cost per well but with increased production and more emphasis on profitability.

In the past five years, DTC Energy Group completion supervisors in the Bakken have helped oversee a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even 40-stage fracs have been achieved.

One of the main reasons for this is the longer lateral lengths – operators now have twice as much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are also being spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet in 2008, as experienced by DTC supervisors.

By placing more fracture stages closer together, over a longer lateral length, operators have successfully been able to improve initial production (IP) rates, as well as increase EURs over the life of the well.

blah blah, but they make clear the years have increased length. Freddy was talking about well spacing, this text is about stage spacing, but that is achieved because of lateral length.

Freddy can you revisit your graph code? It's just bizarre that different length wells have the same flow rate 2 yrs out, and later.

FreddyW says: 11/19/2016 at 7:22 am
Take a look at Enno´s graphs at https://shaleprofile.com/ . They look the same as my graphs and we have collected and processed the data independently from each other.
George Kaplan says: 11/19/2016 at 1:39 am
If the wells have the same wellbore riser design irrespective of lateral length (i.e. same depth, which is a given, same bore, same downhole pump) then that section might become the main bottleneck later in life and not the reservoir rock. With a long fat tail that seems more likely somehow compared to the faster falling Eagle Ford wells say (but that is just a guess really). But there may be lots of other nuances, we just don't have enough data in enough detail especially on the late life performance for all different well designs – it looks like the early ones are just reaching shut off stage in numbers now. I doubt if the E&Ps concentrated on later life when the wells were planned – they wanted early production, and still do, to pay their creditors and company officers bonuses (not necessarily in that order).
Watcher says: 11/19/2016 at 3:31 am
Hmmm. I know it is speculation, but can you flesh that out?

If some bottleneck physically exists that defines a flow rate for all wells from all years then that does indeed explain the graphs, but what such thing could exist that has a new number each year past year 2?

We certainly have discussed chokes for reservoir/EUR management, but the same setting to define flow regardless of length?

Hmmm.

George Kaplan says: 11/19/2016 at 4:01 am
The flow depends on the available pressure drop, which is made up of friction through the rock and up the well bore (plus maybe some through the choke but not much), plus the head of the well, plus a negative number if there is a pump. The frictional and pump numbers depend on the flow and all the numbers depend on gas-oil ratio. Initially there is a big pressure drop in the rock because of the high flow, then not so much. Once the flow drops the pressure at base of the well bore just falls as a result of depletion over time, the effect of the completion design is a lot less and lost in the noise, so all the wells behave similarly. That's just a guess – I have never seen a shale well and never run a well with 10 bpd production, conventional or anything else.

A question might be if the flow is the same why doesn't the longer well with the bigger volume deplete more slowly, and I don't know the answer. It may be too small to notice and lost in the noise, or to do with gas breakout dominating the pressure balance, or just the way the the physics plays out as the fluids permeate through the rock, or we don't have long enough history to see the differences yet.

clueless says: 11/18/2016 at 2:30 pm
Permian rig count now greater than same time last year.
Watcher says: 11/18/2016 at 3:27 pm
http://www.fool.ca/2016/11/16/buffett-sells-suncor-energy-inc-what-does-this-mean-for-the-canadian-oil-patch/
AlexS says: 11/18/2016 at 4:55 pm
Suncor's forecast for production [in 2017] is 680,000-720,000 boe/d. A midpoint would represent a 13% increase over 2016.

http://www.ogj.com/articles/2016/11/suncor-provides-capital-spending-production-outlook-for-2017.html

Solid growth

R Walter says: 11/18/2016 at 5:47 pm
The only oil investment that has any feck is turmoil.

Or, Term Oil Corporation.

Also known as Peak Oil.

http://www.bnsf.com/about-bnsf/financial-information/weekly-carload-reports/

The number of rail cars hauling petroleum is a constant in the range of 7,200 to 7,400 petroleum cars hauled each week for a good six months now.

Seems as though petroleum by rail is more of a necessity than a choice.

The volume is down a good thirty percent since about 2013 when over 10,000 cars were hauled per week.

Demand decreases, contracts expire, better modes of transport emerge and cost less. not as much call for Bakken oil. Plenty of the stuff somewhere else in this world.

The trend is down, not up for petroleum hauled by rail.

If there were orders for Bakken oil for one million bpd, the production would be one million bpd.

Bakken oil lost marketshare due to price drop.

Buyers can buy oil from anywhere.

GoneFishing says: 11/18/2016 at 6:34 pm
More Bakken petroleum is being moved by pipeline.

Over the whole rail system, petroleum and petroleum product rail car loadings were down to 10.5 thousand in September. That compares to a high point of 16.3 thousand railcars in Sept of 2014.

Coal car loadings are on the rise, from a low of 61,000 in April to 86,000 in Sept. Coal was running a near steady 105,00 to 110,000 railcars every month in 2013 and 2014.

AlexS says: 11/18/2016 at 6:57 pm
The chart below from RBN shows that Bakken pipeline capacity did not increase since early 2015. But production dropped, and this primarily affected volumes of Bakken oil transported by rail.

Given the higher percentage of oil transported by pipelines, the average transporation cost for Bakken crude should have decreased. Interesting, however, that the price differential between the well-head Bakken sweet crude and WTI has remained within the $10-12/bbl range.

Bakken Crude Production and Takeaway Capacity
Source: RBN

AlexS says: 11/18/2016 at 7:06 pm
This article from Platts explains better than me:

Analysis: Bakken discounts deepen as competition heats up

Houston (Platts)–16 Nov 2016
http://www.platts.com/latest-news/oil/houston/analysis-bakken-discounts-deepen-as-competition-27711340

Bakken Blend differentials at terminals close to North Dakota wellheads held their lowest assessment since December Tuesday, closing at the calendar-month average of the NYMEX light sweet crude oil contract (WTI CMA) minus $6.25/b.
While one factor dragging on Bakken differentials has clearly been a tight Brent/WTI spread - trading around 42 cents/b Tuesday, well in from the steady $2/b seen this summer - the return of Louisiana Light Sweet to the Midwest market may also be having an impact, according to traders.
One trader said there was an increase in volumes heading up the Capline pipeline, however, differentials suggest LLS is still too expensive, at least compared to Bakken. Platts assessed LLS at WTI plus $1.15/b Tuesday.
Considered by some to be the "champagne of crudes," it is unclear what appeal LLS still has for a Midwest refiner as margins for LLS actually - and unusually - lag those for Bakken.
S&P Global Platts data shows LLS cracking margins in the Midwest closed at $3.30/b Monday, compared to Bakken cracking margins of $6.37/b. In fact, the advantage of cracking Bakken has grown steadily since August.
Platts margin data reflects the difference between a crude's netback and its spot price.
Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.
What is clear however, is that the steeper discounts available for Bakken provide the biggest incentive for a Midwest refiner.
The cost of getting Bakken to this market is around $3.48/b, according to Platts netback calculations, compared to just $1.02/b for LLS.
These costs make up a significant portion of the Bakken discount.
Further, LLS moving up the Capline after many years of relative inactivity does not necessarily suggest a new trend is in the making. However, recent pipeline reversals between Texas and Louisiana mean more Permian crudes are capable of reaching Louisiana refineries, and thus, if priced accordingly, could displace incremental volumes of LLS from its home market.
With current pipeline capacity out of North Dakota typically full, the marginal Bakken barrel often gets to market via rail, and this cost has traditionally sets the floor to Bakken's discount to WTI. And part of the recent downturn in Bakken could be chalked up to an increase in railed volumes to the US Atlantic Coast, as Bakken cracking margins there are again in the black.
In fact, Association of American Railroad's latest monthly and weekly data shows crude and refined product rail movements appear to have bottomed, having grown in September from August.
Weekly data bears this out as well, showing increases in three of the last four weeks.
It remains to be seen how long this will last, however, should Energy Transfer Partners Dakota Access Pipeline go ahead as planned.
Linefill for the pipeline could boost Bakken differentials, potentially making the grade too expensive to rail east. However, the devil is in the details.
Traders and analysts have pegged Dakota Access pipeline tariffs between $4.50-$5.50/b for uncommitted shippers between North Dakota and Patoka, Illinois. A further $6.50/b would be needed to bring the crude south from Patoka to Nederland, Texas, sources have said.
If this $11-$12/b combined pipeline estimated cost were to pan out, it would be more expensive than the $10.20/b Platts assumes in its Bakken USAC rail-based netback calculation.

AlexS says: 11/18/2016 at 8:59 pm
U.S.oil rig count was up 19 units last week, the largest weekly gain in 16 months.
Gas rig count is up 1 unit.

Permian basin: + 11 oil rigs
Bakken: -1
Eagle Ford: -1
Niobrara: +2
Cana Woodford: unchanged
Other shale plays: +2
Conventional basins: +6

Oil rig count in the Permian is up 73.5% from this year's low – the biggest increase among all US basins.
It is still only 41% of October 2014 peak, but this is much better than the Bakken and especially the Eagle Ford where drilling activity remains depressed.

AlexS says: 11/18/2016 at 9:30 pm
The number of horizontal rigs drilling for oil in the Permian is now 54% of the 2014 peak.

Oil rig count in the Permian basin
source: Baker Hughes

AlexS says: 11/18/2016 at 9:42 pm
Weak drilling activity in the Bakken and the Eagle Ford helps to explain continued declines in their oil production

Oil rig count in 4 other tight oil plays

Roger Blanchard says: 11/19/2016 at 8:17 am
Alex,

As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state.

Based upon state data, the number of producing wells/square mile is 1.29 in Mountrail County, 1.22 in McKenzie County, 1.02 in Willams County, and 0.86 in Dunn County. How high can the number of producing wells/square mile go?

Is there something more than reduced drilling to explain the drop in production?

George Kaplan says: 11/19/2016 at 8:35 am
This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated.

AlexS says: 11/18/2016 at 9:53 pm
From a recent EIA report:

"U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month."

AlexS says: 11/18/2016 at 9:58 pm
The EIA DPR production volume estimates for the Permian include both LTO and conventional C+C

AlexS says: 11/18/2016 at 10:06 pm
Permian Basin also dominates M&A activity in the US E&P sector.

From the same EIA report:

"Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase.
Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value."

http://www.eia.gov/todayinenergy/detail.php?id=28772

Heinrich Leopold says: 11/19/2016 at 6:09 am
RRC Texas for September came out recently. As others will probably elaborate more on the data, I just want to show if year over year changes in production could be use as a predictive tool for future production (see below chart).

It is obvious that year over year changes (green line) beautifully predicted oil production (red line) at a time lag of about 15 month. Even when production was still growing, the steep decline of growth rate indicated already the current steep decline.

The interesting thing is that the year over year change is a summary indicator. It does not tell why production declines or rises. It can be the oil price, interest rates or just depletion – even seasonal factors are eliminated. It just shows the strength of a trend.

I am curious myself how this works out. The yoy% indicator predicts that Texas will have lost another million bbl per day by end next year. That sounds quite like a big plunge. One explanation could be the fact that we have now low oil prices and high interest rates. In all other cycles it has been the other way around: low oil prices came hand in hand with low interest rates. This could be now a major obstacle for companies to grow production.

This concept of following year over year changes works of course just for big trends, yet for investment timing it seems exactly the right tool. Another huge wave is coming in electric vehicles which are growing in China by 120% year over year. Here we have the same situation as for shale 7 years ago: Although current EV sales are barely 1 million per year worldwide, the growth rate reveals already an huge wave coming. So as an investor it is always necessary to stay ahead of the trend and I think this can be done by observing the year over year% change.

[Nov 19, 2016] 11/16/2016 at 3:49 pm

Notable quotes:
"... I am a petroleum Geologist drilling wells in the Wolfcamp, the USGS report means nothing. They periodically review basins to assess how much petroleum is there, we have been drilling Horizontal wells in the Wolfcamp for almost a decade, and vertical wells for many decades. Right now there are as many rigs running drilling this rock formation as there are in the rest of the country combined, so it is already baked in to the US production data. This is not like a Saudi Arabia field with a low drill and complete and development cost, it will take many billions of drilling capital to get a small percentage of the oil in place. The big deal is that the area is fairly resilient to low oil prices and will cushion the drop in US production due to lack of investment in other basins. ..."
"... I think when seismic, land, surface and down hole equipment is included, the number is much higher. With $20-60K per acre being paid, land definitely has to be factored in. Depending on spacing, $1-5 million per well? ..."
"... In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost. This does not include costs incurred prior to the well being drilled, which are not insignificant. Nor does it include costs of down hole and surface equipment, which also are not insignificant. ..."
"... Land costs are all over the map, and I think Bakken land costs overall are the lowest, because much of the leasing occurred prior to US shale production boom. I think a lot of acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so we have to look project by project, unfortunately. For purposes of a model, I think $8 million is probably in the ballpark. ..."
"... I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick with, being US based). The companies do not do that, those costs are included in depreciation, depletion and amortization expense. ..."
"... Once the well is in production, and failures occur, I include the cost of repairs, including replacement equipment, in LOE. I am not sure that the companies do that, however. ..."
"... I think the Permian is going to be much tougher to estimate, as there are different producing formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1 or 2. ..."
"... What most interests me are suggestions that there is so much available oil in Wolfcamp and what that will do to oil prices and national policy. Seems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling. ..."
"... The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc. ..."
"... In November 2015, the EIA estimated proven reserves of tight oil in Wolfcamp and Bone Spring formations as of end 2014 at just 722 million barrels. ..."
"... AlexS. Another key question, which is price dependent, is how many years will it take to fully develop the reserves? ..."
"... If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp up at the speed of the Eagle Ford ..."
"... It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect economic growth", "geology is about to beat human ingenuity" etc. ..."
Nov 19, 2016 | peakoilbarrel.com
JG 11/16/2016 at 3:49 pm
I am a petroleum Geologist drilling wells in the Wolfcamp, the USGS report means nothing. They periodically review basins to assess how much petroleum is there, we have been drilling Horizontal wells in the Wolfcamp for almost a decade, and vertical wells for many decades. Right now there are as many rigs running drilling this rock formation as there are in the rest of the country combined, so it is already baked in to the US production data. This is not like a Saudi Arabia field with a low drill and complete and development cost, it will take many billions of drilling capital to get a small percentage of the oil in place. The big deal is that the area is fairly resilient to low oil prices and will cushion the drop in US production due to lack of investment in other basins.
Mike says: 11/17/2016 at 8:28 am
Thank you, JG -- Straight from the horses mouth, respectfully. The USGS lost all credibility with me as to estimating TRR in the Monterrey Shale in California. It baffles me, after five years of publically discussing unconventional shale oil resources, that modelers, internet analysts and predictors completely ignore economics, debt and finances. Extracting oil is a business; it must make money to succeed. If it does not succeed, all bets are off regarding predictions.
Dennis Coyne says: 11/17/2016 at 8:49 am
Hi Mike,

The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis.

It would be better if the USGS did an economic analysis as they do with coal for the Powder River Basin. They could develop a supply curve based on current costs, but they don't.

Do you have any idea of the capital cost of the wells (ballpark guess) for a horizontal multifracked well in the Wolfcamp? Would $7 million be about right (a WAG by me)?

On ignoring economics, I show my oil price assumptions. Other financial assumptions for the Bakken are $8 million for capital cost of the well (2016$). OPEX=$9/b, other costs=$5/b, royalty and taxes=29% of gross revenue, $10/b transport cost, and a real discount rate of 7% (10% nominal discount rate assuming 3% inflation).

I do a DCF based on my assumed real oil price curve. Brent oil price rises to $77/b (2016$) by June 2017 and continue to rise at 17% per year until Oct 2020 when the oil price reaches $130/b, it is assumed that average oil prices remain at that level until Dec 2060. The last well is drilled in Dec 2035 and stops producing 25 years later in Dec 2060.

EUR of wells today is assumed to be 321 kb and EUR falls to 160 kb by 2035. The last well drilled only makes $243,000 over the 7% real rate of return, so the 9 Gb scenario is probably too optimistic, it is assumed that any gas sales are used to offset OPEX and other costs, though no natural gas price assumptions have been made to simplify the analysis.

This analysis is based on the analyses that Rune Likvern has done in the past, though his analyses are far superior to my own.

shallow sand says: 11/17/2016 at 9:00 am
I think when seismic, land, surface and down hole equipment is included, the number is much higher. With $20-60K per acre being paid, land definitely has to be factored in. Depending on spacing, $1-5 million per well?
Dennis Coyne says: 11/17/2016 at 10:07 am
Hi Shallow sand,

I am doing the analysis for the Bakken. A lot of the leases are already held and I don't know that those were the prices paid. Give me a number for total capital cost that makes sense, are you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the different assumptions you would like to change would be good so I don't redo it 5 times.

Mostly I would like to clear up "the number".

I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes, real discount rate (adjusted for inflation), well cost.

I think you a re talking about well cost as "the number". I include down hole costs as part of OPEX (think of it as OPEX plus maintenance maybe).

shallow sand says: 11/17/2016 at 11:19 am
Dennis. The very high acreage numbers are for recent sales in the Permian Basin.

In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost. This does not include costs incurred prior to the well being drilled, which are not insignificant. Nor does it include costs of down hole and surface equipment, which also are not insignificant.

Land costs are all over the map, and I think Bakken land costs overall are the lowest, because much of the leasing occurred prior to US shale production boom. I think a lot of acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so we have to look project by project, unfortunately. For purposes of a model, I think $8 million is probably in the ballpark.

I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick with, being US based). The companies do not do that, those costs are included in depreciation, depletion and amortization expense.

Once the well is in production, and failures occur, I include the cost of repairs, including replacement equipment, in LOE. I am not sure that the companies do that, however.

I think the Permian is going to be much tougher to estimate, as there are different producing formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1 or 2.

An example:

QEP paid roughly $60,000 per acre for land in Martin Co., TX. If we assume one drilling unit is 1280 acres (two sections), how many two mile laterals will be drilled in the unit?

1280 acres x $60,000 = $76,800,000.

Assume 440′ spacing, 12 wells per unit.

$76,800,000/12 = $6,400,000 per well.

However, there are claims of up to 8 producing zones in the Permian.

So, 12 x 8 = 96 wells.

$76,800,000 / 96 = $800,000 per well.

Even assuming 96 wells, the cost per well is still significant.

If we assume 96 wells x $7 million to drill, complete and equip, total cost to develop is $.75 BILLION. That is a lot of money for one 1280 acre unit, need to recover a lot of oil and gas to get that to payout.

Dennis Coyne says: 11/17/2016 at 1:22 pm
Hi Shallow sands,

I am neither an oil man nor an accountant, so regardless of what we call it I am assuming natural gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to operate the well (LOE, OPEX, financial costs, etc), we could add another million to the cost of the well for surface and downhole equipment and land costs. Does an average operating cost over the life of a well of about $17/b ($14/b plus natural gas sales of $3/b of oil produced)seem reasonable?

That would be about $5.4 million spent on LOE etc. over the life of the well (assuming 320 kbo produced). Also does the 10% nominal rate of return sound high enough, what number would you use as a cutoff? You use a different method than a DCF and want the well to pay out in 60 months. This would correspond to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3% annual inflation rate.)

AlexS says: 11/17/2016 at 9:05 am
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis."

Exactly. USGS' estimate as of October 2015 is very conservative:

"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1 million barrels of natural gas liquids, according to the first USGS assessment of continuous (unconventional), technically recoverable resources in the Monterey Formation."

"The volume estimated in the new study is small, compared to previous USGS estimates of conventionally trapped recoverable oil in the Monterey Formation in the San Joaquin Basin. Those earlier estimates were for oil that could come either from producing more Monterey oil from existing fields, or from discovering new conventional resources in the Monterey Formation."

Previous USGS estimates were for conventional oil:

"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin, estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in 2012, USGS assessed the potential volume of oil that could be added to reserves in the San Joaquin Basin from increasing recovery in existing fields. The results of that study suggested that a mean of about 3 billion barrels of oil might eventually be added to reserves from Monterey reservoirs in conventional traps, mostly from a type of rock in the Monterey called diatomite, which has recently been producing over 20 million barrels of oil per year."

https://www.usgs.gov/news/usgs-estimates-21-million-barrels-oil-and-27-billion-cubic-feet-gas-monterey-formation-san

Mike says: 11/17/2016 at 1:24 pm
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp. Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA and awaiting re-drills; that should tell you something. With acreage, infrastructure and water costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste of time, sorry.
Dennis Coyne says: 11/17/2016 at 8:54 am
Hi JG,

What is the average cost of drilling and completion (including fracking) for a horizontal Wolfcamp well?

Does the F95 estimate of 11 Gb seem reasonable if oil prices go up to over $80/b (2016 $) and remain above that level on average from 2018 to 2025?

Boomer II says: 11/17/2016 at 3:25 pm
What most interests me are suggestions that there is so much available oil in Wolfcamp and what that will do to oil prices and national policy. Seems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling.
AlexS says: 11/16/2016 at 3:53 pm
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well spacing, pick total acreage, pick a factor for dry holes – multiply a by c by d and divide by b."

The EIA and others use the same methodology

AlexS says: 11/16/2016 at 4:09 pm
USGS estimates for average well EUR in Wolfcamp shale look reasonable: 167,ooo barrels in the core areas and much lower in other parts of the formation.

I do not know if the estimated potential production area is too big, or assumed well spacing is too tight.

The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc.

Significant part of resources may never be developed, even if they are technically recoverable.

Dennis Coyne says: 11/16/2016 at 5:17 pm
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves times 1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3 Gb of 2P reserves that have been added to Permian reserves since 2011, if we assume most of these are from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that total proved plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved plus 3.5 GB probable with the assumption that probable=proved/2). I have assumed about 30% of total Permian 2P reserves is in the Wolfcamp shale. That is a WAG.

Note the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a conservative guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go to $85/b and remain at that level the F95 estimate may become ERR, at $100/b maybe the median is potentially ERR. It will depend how long prices can remain at $100/b before an economic crash, prices are Brent Crude price in 2016$ with various crude spreads assumed to be about where they are now.

AlexS says: 11/16/2016 at 7:01 pm
Dennis,
where your number for proven reserves in the Permian comes from?

In November 2015, the EIA estimated proven reserves of tight oil in Wolfcamp and Bone Spring formations as of end 2014 at just 722 million barrels.

http://www.eia.gov/naturalgas/crudeoilreserves/

AlexS says: 11/16/2016 at 7:16 pm
US proved reserves of LTO

Dennis Coyne says: 11/16/2016 at 9:11 pm
Hi Alex S,

I just looked at Permian Basin crude reserves (Districts 7C, 8 and 8A) and assumed the change in reserves from 2011 to 2014 was from the Wolfcamp. I didn't know about that page for reserves. It is surprising it is that low.

In any case the difference is small relative to the UTRR, it will be interesting to see what the reserves are for year end 2015.

Based on this I would revise my estimate to 20 Gb for URR with a conservative estimate of 12 Gb until we have the data for year end 2015 to be released later this month.

My guess is that the USGS probably already has the 2015 year end reserve data.

AlexS says: 11/16/2016 at 9:26 pm
Dennis,

The EIA proved reserves estimate for 2015 will be issued this month. I think we will see a significant increase in the number for the Permian basin LTO.

Also note that USGS TRR estimate is only for Wolfcamp.
I can only guess what could be their estimate for the whole Permian tight oil reserves.
But the share of Wolfcamp in the Permian LTO output is only 24% (according to the EIA/DrillingInfo report).

Dennis Coyne says: 11/16/2016 at 10:09 pm
Hi Alex S,

http://www.beg.utexas.edu/resprog/permianbasin/index.htm

At link above they say Permian basin has 30 Gb of oil, so if both estimates are correct the Wolfcamp has 2/3 of remaining resources.

AlexS says: 11/17/2016 at 4:32 am
Dennis,

Wolfcamp is a newer play than Bone Spring and Spraberry. That's why its share in the Permian LTO production is less than in TRR.

Dennis Coyne says: 11/17/2016 at 8:21 am
Hi AlexS,

That makes sense. I also imagine the USGS focused on the formation with the bulk of the remaining resources. It is conceivable that the 30 Gb estimate is closer to the remaining oil in place and that more like 90% of the TRR is in the Wolfcamp, considering that the F5 estimate is about 30 Gb. That older study from 2005 may be an under estimate of TRR for the Permian, likewise the USGS might have overestimated the UTRR.

shallow sand says: 11/16/2016 at 5:18 pm
AlexS. Another key question, which is price dependent, is how many years will it take to fully develop the reserves?
Dennis Coyne says: 11/16/2016 at 5:38 pm
Hi Shallow sand,

If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp up at the speed of the Eagle Ford (say 2 to 3 years). It will be oil price dependent and perhaps they won't over do it like in 2011-2014, but who knows, some people don't learn from past mistakes. If you or Mike were running things it would be done right, but the LTO guys, I don't know.

AlexS says: 11/16/2016 at 7:08 pm
shallow sand,

Yes, you are correct. And there are multiple potential production scenarios, depending on the oil prices.

Boomer II says: 11/16/2016 at 3:39 pm
From the USGS press release.

USGS Estimates 20 Billion Barrels of Oil in Texas' Wolfcamp Shale Formation

"This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically recoverable resources.

Undiscovered resources are those that are estimated to exist based on geologic knowledge and theory, while technically recoverable resources are those that can be produced using currently available technology and industry practices. Whether or not it is profitable to produce these resources has not been evaluated."

Watcher says: 11/16/2016 at 4:11 pm
This is an important way to assess.

If it requires slave labor at gunpoint to get the oil out, then that's what will happen because you MUST have oil, and a day will soon come when that sort of thing is reqd.

George Kaplan says: 11/16/2016 at 3:16 pm
This follows on from reserve post above (two a couple of comments). In terms of changes over the last three years – there really weren't anything much dramatic. We'll see what 2016 brings, especially for ExxonMobil, but it looks like they already knocked a big chunk off of their Bitumen numbers already in 2015.

Note I went through a lot of 20-F and 10-K reports watching the rain fall this morning and copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general trends are shown.

Note the figures are totals for all nine companies I looked at.

Jeff says: 11/16/2016 at 3:20 pm
IEA WEO is out: http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html presentation slides, fact sheet and summary are available online (report can be purchased). IEA seems to be _very_ concerned about underinvestment in upstream oil production. Several pages of the report is devoted to this, the title of that section is "mind the gap". More or less all of the content has been discussed on this website, including the issue with high levels of debt and that this can affect suppliers' capacity to rebound, and how much demand can be reduced as a result of a stringent carbon cap.

From the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil sands) approved for development in 2015 sank to the lowest level since the 1950s, with no sign of a rebound in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely that demand (as projected in our main scenario) and supply can be matched in the early 2020s without the start of a new boom/bust cycle for the industry"

Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"

George Kaplan says: 11/17/2016 at 3:42 am
I wonder who that paragraph is aimed at. As I indicated above the companies that would be investing in long term conventional projects don't have a very large inventory of undeveloped reserves (17 Gb as of end of 2015, some of this has gone already this year and more is in development and will come on stream in 2017 and 2018 (and a small amount in later years for approved projects). I'd guess there might only be less than 10 Gb (and this the most expensive to develop) that is currently under appraisal among the major western IOCs and larger independents; allowing for their partnerships with NOCs in a lot of the available projects that could represent 20 to 30 Gb total. That really isn't very much new supply available, and a large proportion is in complex deep water projects that wouldn't be ramped up fully until 6 to 7 years after FID (i.e. already too late for 2020). Really the main players need to find new fields with easy developments, but they obviously aren't, probably never will, and actually aren't looking very hard at the moment.
Jeff says: 11/17/2016 at 7:24 am
My interpretation is that this is IEAs way of saying that it does not look good. Those who can read between the lines get the message. Also, a few years from they will be able to say "see we told you so".

It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect economic growth", "geology is about to beat human ingenuity" etc.

WEO have become more and more bizarre over the years. On the one hand they contain quantitative projections which tell the story politicians wants to hear. On the other hand, the text describes all sorts of reason of why the assumptions are unlikely to hold. Normally, if you don't believe in your own assumptions you would change them.

[Nov 19, 2016] The bakken core is getting saturated and average production per well drops. Often dramatically as you go out of 50 km sweet spot zone.

Notable quotes:
"... As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state. ..."
"... This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated. ..."
"... "U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month." ..."
"... "Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase. Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value." ..."
Nov 19, 2016 | peakoilbarrel.com

R Walter says: 11/18/2016 at 5:47 pm

The only oil investment that has any feck is turmoil.

Or, Term Oil Corporation.

Also known as Peak Oil.

http://www.bnsf.com/about-bnsf/financial-information/weekly-carload-reports/

The number of rail cars hauling petroleum is a constant in the range of 7,200 to 7,400 petroleum cars hauled each week for a good six months now.

Seems as though petroleum by rail is more of a necessity than a choice.

The volume is down a good thirty percent since about 2013 when over 10,000 cars were hauled per week.

Demand decreases, contracts expire, better modes of transport emerge and cost less. not as much call for Bakken oil. Plenty of the stuff somewhere else in this world.

The trend is down, not up for petroleum hauled by rail.

If there were orders for Bakken oil for one million bpd, the production would be one million bpd. Bakken oil lost marketshare due to price drop. Buyers can buy oil from anywhere.

GoneFishing says: 11/18/2016 at 6:34 pm
More Bakken petroleum is being moved by pipeline. Over the whole rail system, petroleum and petroleum product rail car loadings were down to 10.5 thousand in September. That compares to a high point of 16.3 thousand railcars in Sept of 2014.

Coal car loadings are on the rise, from a low of 61,000 in April to 86,000 in Sept. Coal was running a near steady 105,00 to 110,000 railcars every month in 2013 and 2014.

AlexS says: 11/18/2016 at 6:57 pm
The chart below from RBN shows that Bakken pipeline capacity did not increase since early 2015. But production dropped, and this primarily affected volumes of Bakken oil transported by rail.

Given the higher percentage of oil transported by pipelines, the average transportation cost for Bakken crude should have decreased. Interesting, however, that the price differential between the well-head Bakken sweet crude and WTI has remained within the $10-12/bbl range.

Bakken Crude Production and Takeaway Capacity
Source: RBN

AlexS says: 11/18/2016 at 7:06 pm
This article from Platts explains better than me:

Analysis: Bakken discounts deepen as competition heats up

Houston (Platts)–16 Nov 2016
http://www.platts.com/latest-news/oil/houston/analysis-bakken-discounts-deepen-as-competition-27711340

Bakken Blend differentials at terminals close to North Dakota wellheads held their lowest assessment since December Tuesday, closing at the calendar-month average of the NYMEX light sweet crude oil contract (WTI CMA) minus $6.25/b.

While one factor dragging on Bakken differentials has clearly been a tight Brent/WTI spread - trading around 42 cents/b Tuesday, well in from the steady $2/b seen this summer - the return of Louisiana Light Sweet to the Midwest market may also be having an impact, according to traders.

One trader said there was an increase in volumes heading up the Capline pipeline, however, differentials suggest LLS is still too expensive, at least compared to Bakken. Platts assessed LLS at WTI plus $1.15/b Tuesday.

Considered by some to be the "champagne of crudes," it is unclear what appeal LLS still has for a Midwest refiner as margins for LLS actually - and unusually - lag those for Bakken.

S&P Global Platts data shows LLS cracking margins in the Midwest closed at $3.30/b Monday, compared to Bakken cracking margins of $6.37/b. In fact, the advantage of cracking Bakken has grown steadily since August.

Platts margin data reflects the difference between a crude's netback and its spot price.

Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.

What is clear however, is that the steeper discounts available for Bakken provide the biggest incentive for a Midwest refiner.

The cost of getting Bakken to this market is around $3.48/b, according to Platts netback calculations, compared to just $1.02/b for LLS.

These costs make up a significant portion of the Bakken discount.

Further, LLS moving up the Capline after many years of relative inactivity does not necessarily suggest a new trend is in the making. However, recent pipeline reversals between Texas and Louisiana mean more Permian crudes are capable of reaching Louisiana refineries, and thus, if priced accordingly, could displace incremental volumes of LLS from its home market.

With current pipeline capacity out of North Dakota typically full, the marginal Bakken barrel often gets to market via rail, and this cost has traditionally sets the floor to Bakken's discount to WTI. And part of the recent downturn in Bakken could be chalked up to an increase in railed volumes to the US Atlantic Coast, as Bakken cracking margins there are again in the black.

In fact, Association of American Railroad's latest monthly and weekly data shows crude and refined product rail movements appear to have bottomed, having grown in September from August.

Weekly data bears this out as well, showing increases in three of the last four weeks.

It remains to be seen how long this will last, however, should Energy Transfer Partners Dakota Access Pipeline go ahead as planned.
Linefill for the pipeline could boost Bakken differentials, potentially making the grade too expensive to rail east. However, the devil is in the details.

Traders and analysts have pegged Dakota Access pipeline tariffs between $4.50-$5.50/b for uncommitted shippers between North Dakota and Patoka, Illinois. A further $6.50/b would be needed to bring the crude south from Patoka to Nederland, Texas, sources have said.

If this $11-$12/b combined pipeline estimated cost were to pan out, it would be more expensive than the $10.20/b Platts assumes in its Bakken USAC rail-based netback calculation.

AlexS says: 11/18/2016 at 8:59 pm
U.S.oil rig count was up 19 units last week, the largest weekly gain in 16 months.
Gas rig count is up 1 unit.

Permian basin: + 11 oil rigs
Bakken: -1
Eagle Ford: -1
Niobrara: +2
Cana Woodford: unchanged
Other shale plays: +2
Conventional basins: +6

Oil rig count in the Permian is up 73.5% from this year's low – the biggest increase among all US basins.
It is still only 41% of October 2014 peak, but this is much better than the Bakken and especially the Eagle Ford where drilling activity remains depressed.

AlexS says: 11/18/2016 at 9:30 pm
The number of horizontal rigs drilling for oil in the Permian is now 54% of the 2014 peak.

Oil rig count in the Permian basin
source: Baker Hughes

AlexS says: 11/18/2016 at 9:42 pm
Weak drilling activity in the Bakken and the Eagle Ford helps to explain continued declines in their oil production

Oil rig count in 4 other tight oil plays

Roger Blanchard says: 11/19/2016 at 8:17 am
Alex,

As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state.

Based upon state data, the number of producing wells/square mile is 1.29 in Mountrail County, 1.22 in McKenzie County, 1.02 in Willams County, and 0.86 in Dunn County. How high can the number of producing wells/square mile go?

Is there something more than reduced drilling to explain the drop in production?

George Kaplan says: 11/19/2016 at 8:35 am
This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated.

AlexS says: 11/18/2016 at 9:53 pm
From a recent EIA report:

"U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month."

AlexS says: 11/18/2016 at 9:58 pm
The EIA DPR production volume estimates for the Permian include both LTO and conventional C+C

AlexS says: 11/18/2016 at 10:06 pm
Permian Basin also dominates M&A activity in the US E&P sector.

From the same EIA report:

"Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase.
Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value."

http://www.eia.gov/todayinenergy/detail.php?id=28772

[Nov 19, 2016] Reply

Nov 19, 2016 | peakoilbarrel.com
Dennis Coyne says: 11/17/2016 at 8:49 am
Hi Mike,

The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis.

It would be better if the USGS did an economic analysis as they do with coal for the Powder River Basin. They could develop a supply curve based on current costs, but they don't.

Do you have any idea of the capital cost of the wells (ballpark guess) for a horizontal multifracked well in the Wolfcamp? Would $7 million be about right (a WAG by me)?

On ignoring economics, I show my oil price assumptions. Other financial assumptions for the Bakken are $8 million for capital cost of the well (2016$). OPEX=$9/b, other costs=$5/b, royalty and taxes=29% of gross revenue, $10/b transport cost, and a real discount rate of 7% (10% nominal discount rate assuming 3% inflation).

I do a DCF based on my assumed real oil price curve. Brent oil price rises to $77/b (2016$) by June 2017 and continue to rise at 17% per year until Oct 2020 when the oil price reaches $130/b, it is assumed that average oil prices remain at that level until Dec 2060. The last well is drilled in Dec 2035 and stops producing 25 years later in Dec 2060.

EUR of wells today is assumed to be 321 kb and EUR falls to 160 kb by 2035. The last well drilled only makes $243,000 over the 7% real rate of return, so the 9 Gb scenario is probably too optimistic, it is assumed that any gas sales are used to offset OPEX and other costs, though no natural gas price assumptions have been made to simplify the analysis.

This analysis is based on the analyses that Rune Likvern has done in the past, though his analyses are far superior to my own.

shallow sand says: 11/17/2016 at 9:00 am
I think when seismic, land, surface and down hole equipment is included, the number is much higher.

With $20-60K per acre being paid, land definitely has to be factored in. Depending on spacing, $1-5 million per well?

Dennis Coyne says: 11/17/2016 at 10:07 am
Hi Shallow sand,

I am doing the analysis for the Bakken. A lot of the leases are already held and I don't know that those were the prices paid. Give me a number for total capital cost that makes sense, are you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the different assumptions you would like to change would be good so I don't redo it 5 times.

Mostly I would like to clear up "the number".

I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes, real discount rate (adjusted for inflation), well cost.

I think you a re talking about well cost as "the number". I include down hole costs as part of OPEX (think of it as OPEX plus maintenance maybe).

shallow sand says: 11/17/2016 at 11:19 am
Dennis. The very high acreage numbers are for recent sales in the Permian Basin.

In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost.

This does not include costs incurred prior to the well being drilled, which are not insignificant. Nor does it include costs of down hole and surface equipment, which also are not insignificant.

Land costs are all over the map, and I think Bakken land costs overall are the lowest, because much of the leasing occurred prior to US shale production boom. I think a lot of acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so we have to look project by project, unfortunately. For purposes of a model, I think $8 million is probably in the ballpark.

I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick with, being US based). The companies do not do that, those costs are included in depreciation, depletion and amortization expense.

Once the well is in production, and failures occur, I include the cost of repairs, including replacement equipment, in LOE. I am not sure that the companies do that, however.

I think the Permian is going to be much tougher to estimate, as there are different producing formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1 or 2.

An example:

QEP paid roughly $60,000 per acre for land in Martin Co., TX. If we assume one drilling unit is 1280 acres (two sections), how many two mile laterals will be drilled in the unit?

1280 acres x $60,000 = $76,800,000.

Assume 440′ spacing, 12 wells per unit.

$76,800,000/12 = $6,400,000 per well.

However, there are claims of up to 8 producing zones in the Permian.

So, 12 x 8 = 96 wells.

$76,800,000 / 96 = $800,000 per well.

Even assuming 96 wells, the cost per well is still significant.

If we assume 96 wells x $7 million to drill, complete and equip, total cost to develop is $.75 BILLION. That is a lot of money for one 1280 acre unit, need to recover a lot of oil and gas to get that to payout.

Dennis Coyne says: 11/17/2016 at 1:22 pm
Hi Shallow sands,

I am neither an oil man nor an accountant, so regardless of what we call it I am assuming natural gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to operate the well (LOE, OPEX, financial costs, etc), we could add another million to the cost of the well for surface and downhole equipment and land costs. Does an average operating cost over the life of a well of about $17/b ($14/b plus natural gas sales of $3/b of oil produced)seem reasonable? That would be about $5.4 million spent on LOE etc. over the life of the well (assuming 320 kbo produced). Also does the 10% nominal rate of return sound high enough, what number would you use as a cutoff? You use a different method than a DCF and want the well to pay out in 60 months. This would correspond to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3% annual inflation rate.)

AlexS says: 11/17/2016 at 9:05 am
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis."

Exactly.
USGS' estimate as of October 2015 is very conservative:

"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1 million barrels of natural gas liquids, according to the first USGS assessment of continuous (unconventional), technically recoverable resources in the Monterey Formation."

"The volume estimated in the new study is small, compared to previous USGS estimates of conventionally trapped recoverable oil in the Monterey Formation in the San Joaquin Basin. Those earlier estimates were for oil that could come either from producing more Monterey oil from existing fields, or from discovering new conventional resources in the Monterey Formation."

Previous USGS estimates were for conventional oil:

"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin, estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in 2012, USGS assessed the potential volume of oil that could be added to reserves in the San Joaquin Basin from increasing recovery in existing fields. The results of that study suggested that a mean of about 3 billion barrels of oil might eventually be added to reserves from Monterey reservoirs in conventional traps, mostly from a type of rock in the Monterey called diatomite, which has recently been producing over 20 million barrels of oil per year."

https://www.usgs.gov/news/usgs-estimates-21-million-barrels-oil-and-27-billion-cubic-feet-gas-monterey-formation-san

Mike says: 11/17/2016 at 1:24 pm
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp. Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA and awaiting re-drills; that should tell you something. With acreage, infrastructure and water costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste of time, sorry.
Dennis Coyne says: 11/17/2016 at 8:54 am
Hi JG,

What is the average cost of drilling and completion (including fracking) for a horizontal Wolfcamp well?

Does the F95 estimate of 11 Gb seem reasonable if oil prices go up to over $80/b (2016 $) and remain above that level on average from 2018 to 2025?

Boomer II says: 11/17/2016 at 3:25 pm
What most interests me are suggestions that there is so much available oil in Wolfcamp and what that will do to oil prices and national policy.

Seems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling.

AlexS says: 11/16/2016 at 3:53 pm
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well spacing, pick total acreage, pick a factor for dry holes – multiply a by c by d and divide by b."

The EIA and others use the same methodology

AlexS says: 11/16/2016 at 4:09 pm
USGS estimates for average well EUR in Wolfcamp shale look reasonable: 167,ooo barrels in the core areas and much lower in other parts of the formation.

I do not know if the estimated potential production area is too big, or assumed well spacing is too tight.

The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc.

Significant part of resources may never be developed, even if they are technically recoverable.

Dennis Coyne says: 11/16/2016 at 5:17 pm
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves times 1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3 Gb of 2P reserves that have been added to Permian reserves since 2011, if we assume most of these are from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that total proved plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved plus 3.5 GB probable with the assumption that probable=proved/2). I have assumed about 30% of total Permian 2P reserves is in the Wolfcamp shale. That is a WAG.

Note the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a conservative guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go to $85/b and remain at that level the F95 estimate may become ERR, at $100/b maybe the median is potentially ERR. It will depend how long prices can remain at $100/b before an economic crash, prices are Brent Crude price in 2016$ with various crude spreads assumed to be about where they are now.

AlexS says: 11/16/2016 at 7:01 pm
Dennis,
where your number for proven reserves in the Permian comes from?
In November 2015, the EIA estimated proven reserves of tight oil in Wolfcamp and Bone Spring formations as of end 2014 at just 722 million barrels.

http://www.eia.gov/naturalgas/crudeoilreserves/

AlexS says: 11/16/2016 at 7:16 pm
US proved reserves of LTO

Dennis Coyne says: 11/16/2016 at 9:11 pm
Hi Alex S,

I just looked at Permian Basin crude reserves (Districts 7C, 8 and 8A) and assumed the change in reserves from 2011 to 2014 was from the Wolfcamp. I didn't know about that page for reserves. It is surprising it is that low.

In any case the difference is small relative to the UTRR, it will be interesting to see what the reserves are for year end 2015.

Based on this I would revise my estimate to 20 Gb for URR with a conservative estimate of 12 Gb until we have the data for year end 2015 to be released later this month.

My guess is that the USGS probably already has the 2015 year end reserve data.

AlexS says: 11/16/2016 at 9:26 pm
Dennis,

The EIA proved reserves estimate for 2015 will be issued this month. I think we will see a significant increase in the number for the Permian basin LTO.

Also note that USGS TRR estimate is only for Wolfcamp.
I can only guess what could be their estimate for the whole Permian tight oil reserves.
But the share of Wolfcamp in the Permian LTO output is only 24% (according to the EIA/DrillingInfo report).

Dennis Coyne says: 11/16/2016 at 10:09 pm
Hi Alex S,

http://www.beg.utexas.edu/resprog/permianbasin/index.htm

At link above they say Permian basin has 30 Gb of oil, so if both estimates are correct the Wolfcamp has 2/3 of remaining resources.

AlexS says: 11/17/2016 at 4:32 am
Dennis,

Wolfcamp is a newer play than Bone Spring and Spraberry. That's why its share in the Permian LTO production is less than in TRR.

Dennis Coyne says: 11/17/2016 at 8:21 am
Hi AlexS,

That makes sense. I also imagine the USGS focused on the formation with the bulk of the remaining resources. It is conceivable that the 30 Gb estimate is closer to the remaining oil in place and that more like 90% of the TRR is in the Wolfcamp, considering that the F5 estimate is about 30 Gb. That older study from 2005 may be an under estimate of TRR for the Permian, likewise the USGS might have overestimated the UTRR.

shallow sand says: 11/16/2016 at 5:18 pm
AlexS. Another key question, which is price dependent, is how many years will it take to fully develop the reserves?
Dennis Coyne says: 11/16/2016 at 5:38 pm
Hi Shallow sand,

If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp up at the speed of the Eagle Ford (say 2 to 3 years). It will be oil price dependent and perhaps they won't over do it like in 2011-2014, but who knows, some people don't learn from past mistakes. If you or Mike were running things it would be done right, but the LTO guys, I don't know.

AlexS says: 11/16/2016 at 7:08 pm
shallow sand,

Yes, you are correct. And there are multiple potential production scenarios, depending on the oil prices.

Boomer II says: 11/16/2016 at 3:39 pm
From the USGS press release.

USGS Estimates 20 Billion Barrels of Oil in Texas' Wolfcamp Shale Formation

"This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically recoverable resources.

Undiscovered resources are those that are estimated to exist based on geologic knowledge and theory, while technically recoverable resources are those that can be produced using currently available technology and industry practices. Whether or not it is profitable to produce these resources has not been evaluated."

Watcher says: 11/16/2016 at 4:11 pm
This is an important way to assess.

If it requires slave labor at gunpoint to get the oil out, then that's what will happen because you MUST have oil, and a day will soon come when that sort of thing is reqd.

Fred Magyar says: 11/17/2016 at 11:18 am
Nice apocalyptic vision of the future you've got there!

Whatever happened to the ideals of democracy, capitalism, business, profits, free markets etc ? Don't worry, no need to answer, that was purely a rhetorical question. I'm quite aware of the realities of the world!

However, not to pour too much sand on your vision, But I have to wonder? Since your potential slaves in 21st century America are already armed to the teeth, they might decide not to just go with the flow. (pun intended) 🙂

Anyways slaves don't buy cars or too many consumer goods so that might, in and of itself, put a bit of a damper on the raison d'etre, excuse my french, of the oil companies and the very existence of these future slave owners.

because you MUST have oil

Really now?! You know, as time goes by, I'm less and less convinced of that!

Cheers!

George Kaplan says: 11/16/2016 at 3:16 pm
This follows on from reserve post above (two a couple of comments). In terms of changes over the last three years – there really weren't anything much dramatic. We'll see what 2016 brings, especially for ExxonMobil, but it looks like they already knocked a big chunk off of their Bitumen numbers already in 2015.

Note I went through a lot of 20-F and 10-K reports watching the rain fall this morning and copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general trends are shown.

Note the figures are totals for all nine companies I looked at.

Jeff says: 11/16/2016 at 3:20 pm
IEA WEO is out: http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html presentation slides, fact sheet and summary are available online (report can be purchased). IEA seems to be _very_ concerned about underinvestment in upstream oil production. Several pages of the report is devoted to this, the title of that section is "mind the gap". More or less all of the content has been discussed on this website, including the issue with high levels of debt and that this can affect suppliers' capacity to rebound, and how much demand can be reduced as a result of a stringent carbon cap.

From the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil sands) approved for development in 2015 sank to the lowest level since the 1950s, with no sign of a rebound in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely that demand (as projected in our main scenario) and supply can be matched in the early 2020s without the start of a new boom/bust cycle for the industry"

Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"

George Kaplan says: 11/17/2016 at 3:42 am
I wonder who that paragraph is aimed at. As I indicated above the companies that would be investing in long term conventional projects don't have a very large inventory of undeveloped reserves (17 Gb as of end of 2015, some of this has gone already this year and more is in development and will come on stream in 2017 and 2018 (and a small amount in later years for approved projects). I'd guess there might only be less than 10 Gb (and this the most expensive to develop) that is currently under appraisal among the major western IOCs and larger independents; allowing for their partnerships with NOCs in a lot of the available projects that could represent 20 to 30 Gb total. That really isn't very much new supply available, and a large proportion is in complex deep water projects that wouldn't be ramped up fully until 6 to 7 years after FID (i.e. already too late for 2020). Really the main players need to find new fields with easy developments, but they obviously aren't, probably never will, and actually aren't looking very hard at the moment.
Jeff says: 11/17/2016 at 7:24 am
My interpretation is that this is IEAs way of saying that it does not look good. Those who can read between the lines get the message. Also, a few years from they will be able to say "see we told you so".

It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect economic growth", "geology is about to beat human ingenuity" etc.

WEO have become more and more bizarre over the years. On the one hand they contain quantitative projections which tell the story politicians wants to hear. On the other hand, the text describes all sorts of reason of why the assumptions are unlikely to hold. Normally, if you don't believe in your own assumptions you would change them.

FreddyW says: 11/16/2016 at 3:43 pm
Hi,

Here are my updates as usual. GOR declined or stayed flat for all years except 2010 in September. Is it the beginning of a new trend?

FreddyW says: 11/16/2016 at 3:50 pm
Here is the production graph. Not that much has happened. There was a big drop for 2011. 2009 on the other hand saw an increase. Up to the left, which is very hard to see, 2015 continues to follow 2014 which follows 2013 which follows 2012. Will we see 2013 reach 2007 the next few months?

Watcher says: 11/16/2016 at 10:34 pm
Freddy, these latest years, the IP months are chopped at the top. Any chance of showing those?

The motivation would be to get a look at the alleged spectacular technology advances in the past, oh, 2 yrs.

FreddyW says: 11/17/2016 at 2:10 pm
Its on purpose both because I wanted to zoom in and because the data for first 18 months or so for the method I used above is not very usable. Bellow is the production profile which is better for seeing differences the first 18 months. Above graph is roughly 6 months ahead of the production profile graph.

Watcher says: 11/17/2016 at 2:40 pm
Excellent.

And I guess we can all see no technological breakthru. 2014's green line looks superior to first 3 mos 2015.

2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper decline at that point and is likely going to intersect 2014's line probably within the year.

There is zero evidence on that compilation of any technological breakthrough surging output per well in the past 2-3 yrs.

In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular EUR improvement.

And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also no evidence of sweetspots first.

I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with inferior technology, and then as they became less sweet the technological breakthroughs brought output up to look the same.

Too
Much
Coincidence.

It's all bogus.

Watcher says: 11/17/2016 at 8:12 pm
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.

And it would be far too much coincidence for techno breakthrus to just happen to increase flow the exact amount lost from exhausting sweet spots.

This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet.

Mike says: 11/17/2016 at 8:59 pm
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.

Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. Nobody is breaking new ground or making big strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank areas will be even less economical (if that is possible) and will result in significantly less UR per well. That is what is ridiculous about modeling the future based on X wells per month and trying to determine how much unconventional shale oil can be produced in the US thru 2035. The term, "past performance is not indicative of future results?" We invented that phrase 120 years ago in the oil business.

Watcher says: 11/18/2016 at 12:03 am
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra stages post 2008/9/10. How could there not be going from 15 stages to 30+?

I see NO magic post peak. They all descend exactly the same way and by 18-20 months every drill year is lined up. That's actually astounding - given 15 vs 30 stages. There should be more volume draining on day 1 and year 2, but the flow is the same at month 20+ for all drill years. This should kill the profitability on those later wells because 30 stages must cost more.

But profit is not required when you MUST have oil.

Watcher says: 11/18/2016 at 12:14 am
You know, that is absolutely insane.

Freddy, is there something going on in the data? How can 30 stage long laterals flow the same at production month 24 as the earlier dated wells at their production month 24 –whose lengths of well were MUCH shorter?

FreddyW says: 11/18/2016 at 2:55 pm
I can only speculate why the curves look like they do. It could be that the newer wells would have produced more than the older wells, but closer well spacing is causing the UR to go down.
FreddyW says: 11/16/2016 at 3:57 pm
Here is the updated yearly decline rate graph. 2010 has seen increased decline rates as I suspected. The curves are currently gathering in the 15%-20% range.

Dennis Coyne says: 11/16/2016 at 5:33 pm
Hi FreddyW,

What is the annual decline rate of the 2007 wells from month 98 to month 117 and how many wells in that sample (it may be too low to tell us much)?

FreddyW says: 11/16/2016 at 6:02 pm
2007 only has 161 wells. So it makes the production curve a bit noisy as you can see above. Current yearly decline rate for 2007 is 7,2% and the average from month 98 to 117 would translate to a 10,3% yearly decline rate. The 2007 curve look quite different from the other curves, so thats why I did not include it.
Dennis Coyne says: 11/16/2016 at 9:27 pm
Hi Freddy W,

Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one way to do it would be to look at the natural log of monthly output vs month for each year and see where the curve starts to become straight indicating exponential decline. The decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely different, I am speculating about the possible cause.

FreddyW says: 11/17/2016 at 3:37 pm
2007 had much lower initial production and the long late plateau gives it a low decline rate also. But yes, initial decline rates look similar to the other curves. If you look at the individual 2007 wells then you can see that some of them have similar increases to production as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that those increases are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau. If that is the case, then 2007 may not be different from the others at and we will see increased decline rates in the future.

Regarding natural log plots. Yes it could be good if you want to find a constant exponential decline. But we are not there yet as you can see in above graph.

One good reason why decline rates are increasing is because of the GOR increase. When they pump up the oil so fast that GOR is increasing, then it's expected that there are some production increases first but higher decline rates later. Perhaps completion techniques have something to do with it also. Well spacing is getting closer and closer also and is definitely close enough in some areas to cause reductions in UR. But I would expect lower inital production rather than higher decline rates from that. But maybe I´m wrong.

Dennis Coyne says: 11/17/2016 at 8:42 am
Hi FreddyW,

Do you have an estimate of the number of wells completed in North Dakota in September? Does the 71 wells completed estimate by Helms seem correct?

Dennis Coyne says: 11/17/2016 at 12:40 pm
Hi FreddyW,

Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed in Sept 2016.

FreddyW says: 11/17/2016 at 2:19 pm
I have 75 in my data, so about the same. They have increased the number of new wells quite alot the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it increased withouth the rig count going up. But I see that the rig count has gone up now too.
Pete Mason says: 11/16/2016 at 3:49 pm
Ron you say " Bakken production continues to decline though I expect it to level off soon."
A few words of wisdom as to the main reasons why it would level off? Price rise?
Dennis Coyne says: 11/16/2016 at 5:28 pm
Hi Pete,

Even though you asked Ron. He might think that the decline in the number of new wells per month may have stabilized at around 71 new wells per month. If that rate of new completions per month stays the same there will still be decline but the rate of decline will be slower. Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).

Guy Minton says: 11/16/2016 at 8:41 pm
I am not so convinced that either Texas or the Bakken is finished declining at the current level of completions. There was consistent completions of over 1000 wells in Texas until about October of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than they are completing.
I remember reading one projection recently for what wells will be doing over time in the Eagle Ford. They ran those projections for a well for over 22 years. Not sure which planet we are talking about, but in Texas an Eagle Ford does well to survive 6 years. They keep referring to an Eagle Ford producing half of what they will in the first two years. In most areas, I would say that it is half in the first year.
The EIA, IEA, Opec, and most pundits have the US shale drilling turning on a dime when the oil price reaches a certain level. If it was at a hundred now, it would still take about two years to significantly increase production, if it ever happens. I am not a big believer that US shale is the new spigot for supply.
Dennis Coyne says: 11/16/2016 at 10:03 pm
Hi Guy,

The wells being shut in are not nearly as important as the number of wells completed becaus