Bigger doesn't imply better. Bigger often is a sign of obesity, of lost control, of overcomplexity, of cancerous cells
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May the source be with you, but remember the KISS principle ;-) Bigger doesn't imply better. Bigger often is a sign of obesity, of lost control, of overcomplexity, of cancerous cells |
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| In recent years Americans have been hearing that the United States is poised to regain its role as the world’s premier oil and natural gas producer, thanks to the widespread use of horizontal drilling and hydraulic fracturing (“fracking”). This “shale revolution,” we’re told, will fundamentally change the U.S. energy picture for decades to come—leading to energy independence, a rebirth of U.S. manufacturing, and a surplus supply of both oil and natural gas that can be exported to allies around the world. This promise of oil and natural gas abundance is influencing climate policy, foreign policy, and investments in alternative energy sources. |
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The term "shale bubble" is about the idea that the United States is poised to regain "energy independence" becoming again net exporter instead of major importer of oil and natural gas. The primary driver of the propaganda campaign was the U.S. Department of Energy’s Energy Information Administration (EIA). The key technologies that were enabler of shell boom were:
Oil and gas outfit Fieldwood Energy is now in the market with a $2.63 billion covenant-lite first- and second-lien acquisition loan.
...As lending to lower-rated companies has increased generally, more of them are also opting for covenant-lite financings.
That trend is evident particularly in the B3 ratings category. Around 18 percent of covenant-lite loans are for B3 rated companies so far this year, versus 8 percent in 2012 and 3.7 percent in 2011...Loan portfolio managers said that new institutional clients are also seeking to invest. More than $57 billion of CLOs have been issued this year, topping 2012 volume.
This refinancing bulge in 2016 became more compressed in time and more imminent.
Most of the defaults, debt restructurings, and bankruptcies so far this year and last year were triggered when over-indebted cash-flow negative companies could not make interest payments on their debts.
During the crazy days of the peak of the credit bubble two years ago, they would have been able to borrow even more money at 8% or 9% and go on as if nothing happened. But those days are gone. Now the riskiest companies face interest costs of 20% or higher – if they’re able to get new money at all. Hence, the wave of debt restructurings and bankruptcies.
But that’s small fry. Now comes the wave of companies whose debts mature. They will have to borrow new money not only to fund their interest payments, cash-flow-negative operations, and capital expenditures, but also to pay off maturing debt.
That “refinancing cliff” is going to be the biggest, steepest ever, after the greatest credit bubble in US history when companies took on record amounts of debt, and it comes at the worst possible time, warned Moody’s in its annual report.
In its report a year ago, Moody’s had already warned that the refinancing cliff for junk-rated US companies over the next five years – at the time, from 2015 through 2019 – would hit $791 billion. Of that, $349 billion would mature in 2019, the largest amount ever to mature in a single year....Among the other macroeconomic factors, Moody’s lists the slowdown in China and volatility in oil prices. And there’s another factor that will “make it more difficult for lower-rated companies to refinance”: worried regulators have been cracking down on banks’ exposure to leveraged loans, which are so risky that even the Fed has been fingering them publicly.
Banks sell these leveraged loans to loan mutual funds or repackage them into collateralized loan obligations (CLOs) which they then sell in tranches to institutional investors. When leveraged loans mature, companies have to come up with the money, but Moody’s warns that “rising defaults and the impact of the Dodd-Frank Act’s risk retention rule will make it more difficult for existing CLOs to supply corporate financing.”
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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”
“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.note it goes on for 6 pages…
- “Only 1% of the Bakken Play area is commercial at current oil prices based on my analysis that follows.
- Only 4% of horizontal wells drilled since 2000 meet the EUR (estimated ultimate recovery) threshold needed to break even at current oil prices, drilling and completion, and operating costs.
- The leading producing companies evaluated in this study are losing $11 to $38 on each barrel of oil that they produce, the very definition of waste. …”
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.
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.
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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.
Additional information on oil shale is available through the Web. Visit the Links page to access sites with more information.
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May 16, 2019 | peakoilbarrel.com
Hightrekker
says: 05/15/2019 at 9:51 am
Global fossil fuel subsidies hit record $5.2 trillion –
https://desdemonadespair.net/2019/05/global-fossil-fuel-subsidies-hit-record-5-2-trillion.htmlThe Free Market in action.
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May 15, 2019 | www.zerohedge.com
Authored by Nick Cunningham of Oilprice.com,
Global energy investment "stabilised" at just over $1.8 trillion in 2018, ending three years of declines.
Higher spending on oil, natural gas and coal was offset by declines in fossil fuel-based electricity generation and even a dip in renewable energy spending. China was the largest market for energy investment, even as the U.S. closed the gap.
After the 2014-2016 oil market bust, spending on oil and gas plunged, and only started to tick up last year. But the oil industry is not returning to its old spending ways. New investment is increasingly concentrated in short-cycle projects, namely, U.S. shale, "partly reflecting investor preferences for better managing capital at risk amid uncertainties over the future direction of the energy system," the IEA wrote in its report.
Upstream spending rose by a modest 4 percent, which only partially repairs the savage cuts following the 2014 bust, which saw upstream spending fall by about 30 percent. However, the IEA said that 2019 could be a bit of a turning point, with a "new wave of conventional projects" in the works.
Despite the increase in spending on new oil projects, "today's investment trends are misaligned with where the world appears to be heading," the IEA said. "Notably, approvals of new conventional oil and gas projects fall short of what would be needed to meet continued robust demand growth."
... ... ...
The good news is that costs continue to fall. Solar PV has seen costs decline by 75 percent since 2010, and onshore wind and battery storage costs are down by 20 percent and 50 percent, respectively. As such, a dollar spent on renewables buys a lot more energy than it used to, so flat investment is not entirely negative. And in a growing number of places, solar and wind are the cheapest option for power generation – increasingly cheaper than existing coal plants .
Geographically, investment [in solar and wind] is concentrated in rich countries. Roughly 90 percent of total energy investment – both for fossil fuels and for renewable energy – was funneled into high- and upper-middle income regions. Rich countries alone accounted for 40 percent of total energy investment, despite only making up 15 percent of the global population.
... ... ...
peakpeat , 1 hour ago link
Evil Liberals , 1 hour ago linkNothing, no EV's, solar, wind, coal or uranium is going to help. No tight shale, Arctic or North Slope oil is going to lift this sinking ship. There are no more new oil reserves to find and all the old fields are in a state of desperate high-tech extraction. We took all the easy stuff, Bakken and Permian are the last ditch effort. That's why all the playas have negative cash flow. That's why we are fecked.
peakpeat , 59 minutes ago linkhttps://srsroccoreport.com/the-end-of-the-oil-giants-and-what-it-means/
Saudi Ghawar Field, admitted in decline
Evil Liberals , 2 hours ago linkThat was the last great elephant field. The largest resource ever discovered on the planet. Finally in decline. So goes Saudi Arabia. So goes OPEC. So goes mankind.
RDouglas , 2 hours ago linkShould have been building Nuclear Plants the last 20 years - that is Clean Energy.
Just don't build near the shore along the Ring of Fire or along Earthquake Fault Lines.
peakpeat , 57 minutes ago linkCheap crude was a 100 year party, the hangover has already begun. Fracked oil, tar sands, were a rescue remedy, funded by low interest rates, (debt). The massive population boom of the last century and a half directly coordinates with increasing oil production. If you aren't preparing yourself and your children for energy-down/population-down, you are insuring that YOUR decedents won't be among the 100 million or so people scratching out a living in North America in 100 years.
SilverSphinx , 5 hours ago linkBefore 1850 and the discovery of oil and coal, there were 1 billion people on the planet. Now there are 7 billion. 6 billion will die as the oil economy and oil infrastructure grinds to a halt. Better make you peace. Your plans are too late.
Solarstone , 3 hours ago linkNuclear power generation is still King.
The use of nuclear power has resumed since the Fukushima disaster.
All the countries that swore off of nuclear power have returned to it and restarted their nuclear power plants and resumed construction on new plants.
-- ALIEN -- , 3 hours ago linkLet's hope you are right. It's the only viable option to oil
iSage , 2 hours ago link2 words; Peak Uranium
"...Declining uranium production will make it impossible to obtain a significant increase in electrical power from nuclear plants in the coming decades."
Thorium Reactors...
"...A similar fate was encountered by another idea that involved "breeding" a nuclear fuel from a naturally existing element -- thorium. The concept involved transforming the 232 isotope of thorium into the fissile 233 isotope of uranium, which then could be used as fuel for a nuclear reactor (or for nuclear warheads). The idea was discussed at length during the heydays of the nuclear industry, andit is still discussed today; but so far, nothing has come out of it and the nuclear industry is still based on mineral uranium as fuel..."
https://www.resilience.org/stories/2017-01-18/peak-uranium-the-uncertain-future-of-nuclear-energy/
Cloud9.5 , 8 hours ago linkThere is a 1,000 years worth of uranium out west. I don't like the waste, used rods are hot for a long long time.
peakpeat , 1 hour ago linkMexican oil production is in decline. North Sea production is in decline. Alaskan production is in decline. There is a trend here.
JimmyJones , 8 hours ago linkOPEC was the necessary cartel that helped to stabilize production and prices.
Now all of it including Saudi Arabia, Iran and the rest, all 14 nations past and present, is defunct. Output has been in decline since Nov. 2016. See IEA data or peakoilbarrel for a summary
afronaut , 8 hours ago linkUS has enough coal to power us for over 200 years.
Ignorance is bliss , 8 hours ago linkNot to mention natural gas
BangDingOw , 7 hours ago linkCool..How do I fill my BMW up with coal? How about that just in time delivery. Anyone ever try to power a semi-truck with coal? Eactly what do we pave the road ways with? Coal?
Yeesh. All wrong. Most important, slick Willie gave us our china trade problems, and then demand for raw commods in china soared. In response, his geniuses gave us the cfma, which was passed to let the JPMs of the world naked short commodities till the cows came home. However, china demand growth was so far in excess of supply growth that several of the WS firms saw the writing on the wall and went long. Thus the pols amazement when finding out v=bear stearns was actually long oil. Finally prices got high enough that supply growth started overtaking demand growth. We have been going down , on average, since. china demand late 90s oil wa 3Mbpd, currently 13Mbpd
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May 13, 2019 | peakoilbarrel.com
Boomer II x Ignored says: 05/12/2019 at 9:09 pm
As many of you, I don't expect business as usual to continue. We get projections based on past trends, but with oil being finite and the globe already showing the effects of climate change, I think we are in for a tumultuous future.Samuelson points out how flawed economists are.
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May 10, 2019 | www.nakedcapitalism.com
By Nick Cunningham, a freelance writer on oil and gas, renewable energy, climate change, energy policy and geopolitics based in Pittsburgh, PA. Originally published at OilPrice
The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines.
For years, companies have deployed an array of drilling techniques to extract more oil and gas out of their wells, steadily intensifying each stage of the operation. Longer laterals, more water, more frac sand, closer spacing of wells – pushing each of these to their limits, for the most part, led to more production. Higher output allowed the industry to outpace the infamous decline rates from shale wells.
In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet and the volume of water used in drilling has surged more than 250 percent, according to a new report for the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well drilled in 2012, the report says.
That sounds impressive, but the industry may simply be frontloading production. The suite of drilling techniques "have lowered costs and allowed the resource to be extracted with fewer wells, but have not significantly increased the ultimate recoverable resource," J. David Hughes, an earth scientist, and author of the Post Carbon report, warned. Technological improvements "don't change the fundamental characteristics of shale production, they only speed up the boom-to-bust life cycle," he said.
For a while, there was enough acreage to allow for a blistering growth rate, but the boom days eventually have to come to an end. There are already some signs of strain in the shale patch, where intensification of drilling techniques has begun to see diminishing returns. Putting wells too close together can lead to less reservoir pressure, reducing overall production. The industry is only now reckoning with this so-called "parent-child" well interference problem.
Also, more water and more sand and longer laterals all have their limits . Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT quickly found out that it had problems when it exceeded 15,000 feet. "The decision to drill some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing hundreds of millions of dollars," the Wall Street Journal reported earlier this year.
Ultimately, precipitous decline rates mean that huge volumes of capital are needed just to keep output from declining. In 2018, the industry spent $70 billion on drilling 9,975 wells, according to Hughes, with $54 billion going specifically to oil. "Of the $54 billion spent on tight oil plays in 2018, 70% served to offset field declines and 30% to increase production," Hughes wrote.
As the shale play matures, the field gets crowded, the sweet spots are all drilled, and some of these operational problems begin to mushroom. "Declining well productivity in some plays, despite application of better technology, are a prelude to what will eventually happen in all plays: production will fall as costs rise," Hughes said. "Assuming shale production can grow forever based on ever-improving technology is a mistake -- geology will ultimately dictate the costs and quantity of resources that can be recovered."
There are already examples of this scenario unfolding. The Eagle Ford and Bakken, for instance, are both "mature plays," Hughes argues, in which the best acreage has been picked over. Better technology and an intensification of drilling techniques have arrested decline, and even led to a renewed increase in production. But ultimate recovery won't be any higher; drilling techniques merely allow "the play to be drained with fewer wells," Hughes said. And in the case of the Eagle Ford, "there appears to be significant deterioration in longer-term well productivity through overcrowding of wells in sweet spots, resulting in well interference and/or drilling in more marginal areas that are outside of sweet-spots within counties."
In other words, a more aggressive drilling approach just frontloads production, and leads to exhaustion sooner. "Technology improvements appear to have hit the law of diminishing returns in terms of increasing production -- they cannot reverse the realities of over-crowded wells and geology," Hughes said.
The story is not all that different in the Permian, save for the much higher levels of spending and drilling. Post Carbon estimates that it the Permian requires 2,121 new wells each year just to keep production flat, and in 2018 the industry drilled 4,133 wells, leading to a big jump in output. At such frenzied levels of drilling, the Permian could continue to see production growth in the years ahead, but the steady increase in water and frac sand "have reached their limits." As a result, "declining well productivity as sweet-spots are exhausted will require higher drilling rates and expenditures in the future to maintain growth and offset field decline," Hughes warned.
Ignacio , May 10, 2019 at 5:07 am
I think everybody knew that the shale boom would prove to be transient –I consider several years as transient– and it will end with holes in earth and wallets. The Bakken and Eagle Ford have become mature plays in a relatively short period and we will learn, sooner than later, how the decline of these plays unfolds. Somehow the shale business model depends on ever increasing production and production would have increased even faster if it wasn`t for resource constraints (takeaway capacity, crew availability ). According to the EIA the Permian is now filled with DUCKS, sorry, DUCs (drilled but uncompleted wells) waiting for production. Those are waiting for new pipelines and, "hopefully", oil price increases engineered by the US by production suppression in Venezuela and Iran.
Count me amongst those that would like oil price increases, although for different reasons.
Yves Smith Post author , May 10, 2019 at 6:00 pm
The forecasts I saw earlier were that production would peak in the early 2020s, decline gradually for the rest of the decade, and then fall off sharply.
PlutoniumKun , May 10, 2019 at 5:09 am
Arthur Berman has been predicting exactly this for year. They'll spend more and more pushing production up, but eventually you get diminishing returns – the drop off in production, when it happens, will be quite dramatic as the sweet spots run dry.
The equally big question though is the influence of oil and gas prices. A crisis in the shale fields might be precipitated not by a drop in production, but further downward pressure on prices. Or likewise, a spike in oil prices could give a boost to yet more capital investment in those fields. For now, I suspect the producers are far more worried about low prices than running out of oil/gas. A lot of them are betting on substantial rises in the future in order to make their balance sheets look better. So that's a lot of rich people who would welcome a Middle East war.
PlutoniumKun , May 10, 2019 at 5:24 am
Just to add – one possible catastrophic outcome for the planet of a shale bust is poorly capped wells. Properly capping a fracked well is very difficult (you need to plug each individual geological layer, its not just a matter of putting a concrete plug on the well head). If they are not properly plugged, they will leak gas for decades and its extremely difficult and expensive to properly plug. In theory of course they are supposed to be properly capped by the operators, but if they go out of business .
So even if gas and oil fracking stopped today, they will be a major source of CO2 emissions for decades to come, one that will cost many billions to mitigate.
Roger Boyd , May 10, 2019 at 11:57 am
Natural gas is methane, so badly capped fracked gas wells would be really bad for climate change.
States and provinces have started program to cap old O&G wells abandoned decades ago that are leaking methane. All they need to do for new fracking wells is put in tight regulations and enforce them. But that requires political will.
So even if gas and oil fracking stopped today, they will be a major source of CO2 emissions for decades to come, one that will cost many billions to mitigate.
And methane if the gas does not contain CO2.
Svante Arrhenius , May 10, 2019 at 1:50 pm
When we'd fish, mountain bike or varmint hunt in Western PA., many decades ago (ie: ancient conventional oil & gas wells only) it was clear; not only was none of the leaking gas ever flared, but folks were tapping the rusted christmas trees. By the 80's, as we were building the rail trails, it was far worse than our memories. Fracked ethane/ wet gas wells are off-limits, unless you have FLIR drones.
https://m.phys.org/news/2015-05-emissions-natural-gas-wells-downwind.html
https://m.youtube.com/watch?v=HanXGD2NJxkskippy , May 10, 2019 at 5:29 am
Fracking the modern equivalent to hydrological gold mining. But money [tm] was made some confuse this with value
Svante , May 10, 2019 at 12:02 pm
Well, gold does a: not explode (oh, yes it DOES!) b: does not cause 20%-89% more global warming than CO2 (oh yes it DO!) c: "water is precious, sometimes more precious than gold?" Walter Houston, as Howard: The Treasure of the Sierra Madre, who called Bogart, "no, not ME baby!"
jackiebass , May 10, 2019 at 5:57 am
This is old news. Drillers over estimated the production length for fracked wells to help their Ponzi Scheme. For a natural gas well the production tanks in most cases in 3 years. To keep production up more wells had to be drilled. Eventually places to drill become hard to locate.I witnessed this in northern PA. It was boom for about 5 years then came the bust. Although there is still some fracking it is only minor compared to what it was. A few made money but the cost to the environment was passed on to the taxpayers.
The Rev Kev , May 10, 2019 at 6:11 am
There may be another factor at work here. Granted that the shale boom was always going to be a short term play, maybe the move on Venezuela is all about having oil to replace US production as it taps out – slowly at first, then all at once. Trump & Co could always buy Venezuelan oil at a market price but I think that the idea is to seize it to control more of the international oil market by being able to control international prices and you can't do that if Venezuela is an independent country. I just wonder how much damage is going to be done in America in terms of the environment and more importantly water supplies by all the chemicals pumped into the ground. It is going to be a toxic legacy that will be there for generations to come.
PlutoniumKun , May 10, 2019 at 6:30 am
Venezuelan oil is very important to frackers because almost all refineries in the US were built to handle the mid-density oils from Texas and Alaska. Tight oil (fracked) is super light (it can't be fracked otherwise), and so it needs to be mixed in with heavy grade oil to make it refinable. This is where heavy Venezuelan crude and Canadian tar sand oil comes in – they are essential to create a crude that can be refined in existing plants.
So the relationship between the US tight oil industry and Venezuela/Canada is quite complex – they all need each other to some extent otherwise they are stuck with oil that can't be refined. This is of course one reason why Washington absolutely hates not having firm control of Venezuelan production. But its also why they can't afford to shut it down entirely (which would happen if there was a military invasion or civil war).
So the calculations are complex, and they are being made by idiots, so there is no telling what they are planning.
Ken , May 10, 2019 at 11:49 am
There are several facets to this. The light oil from fracking and elsewhere is needed as a dilutent for the very heavy Venezuelan crude to enable it to be pumped on and off tank ships and through pipelines. Dilutents are also needed for the bitumen from the Alberta tar sands. The reason for the Keystone pipeline system is to pump diluted bitumen (dilbit) from Alberta to the Texas refineries is that are equipped to process this very heavy material similar to the very heavy Mexican and Venezuelan crudes. (Crude oils around the world vary greatly in composition. Refineries are equipped to process only certain types of crude.)
The fracked oil and gas often have low market value. The gas wells may produce relatively low quantities of high value natural gas liquids. The oil often is so light that it produces low quantities of high value distillates like diesel fuel. The fracked crude may contain high amounts of impurities that make it difficult and expensive to refine.
The rapid decline of output of the fracked wells is not new news. Oilprice.com has a 2017 article on the same point. https://oilprice.com/Energy/Crude-Oil/Shale-Growth-Hides-Underlying-Problems.html
Olga , May 10, 2019 at 12:58 pm
Well, and then there is this:
https://www.worldoil.com/news/2019/4/11/permians-flaring-rises-by-85-as-oil-boom-continues
"The Permian Basin has produced so much natural gas that by the end of 2018 producers were burning off more than enough of the fuel to meet residential demand across Texas. The phenomenon has likely only intensified since then."The problem seems to be a lack of pipelines to get the gas to customers. Not that I disagree with "the boom is over" too much, but Permian is a large area and has a way to go. But it will fizzle out in time.
Venezuela oil can be delivered directly to the Gulf Coast refineries in tankers that require no permitting or construction. Canadian oil requires pipelines (e.g. Keystone XL) which are held up in permitting. So it is ironic that the Keystone pipeline permitting quagmire is likely to be a proximate cause for the Trump administration dabbling in Venezuela as many Gulf Coast refineries are geared for Alberta/Venezuela oil.
RWood , May 10, 2019 at 9:49 am
Using data from field experiments and computer modeling of ground faults, researchers have discovered that the practice of subsurface fluid injection used in 'fracking' and wastewater disposal for oil and gas exploration could cause significant, rapidly spreading earthquake activity beyond the fluid diffusion zone. The results account for the observation that the frequency of man-made earthquakes in some regions of the country surpass natural earthquake hotspots.
According to the U.S. Geological Survey, the largest earthquake induced by fluid injection and documented in the scientific literature was a magnitude 5.8 earthquake in September 2016 in central Oklahoma. Four other earthquakes greater than 5.0 have occurred in Oklahoma as a result of fluid injection, and earthquakes of magnitude between 4.5 and 5.0 have been induced by fluid injection in Arkansas, Colorado, Kansas and Texas.
Fracking: Earthquakes are triggered well beyond fluid injection zones
https://www.sciencedaily.com/releases/2019/05/190502143353.htmQuarterBack , May 10, 2019 at 9:51 am
I seriously doubt that the shale boom was ever about being profitable. I have long held that the shale industry has been artificially elevated as a hedge against risks induced by the long term Middle East geopolitical and military strategy. It was always expected to loose money and have negative secondary effects, but it had been decided to be necessary. Shale has survived because of a gentleman's agreement by the power players to cover the costs of the shale strategy; that along with investment media hype and stealthy subsidies to try to induce outside suckers to reduce some of the burden of those behind the hedge.
The shale industry was largely small to mid-sized firms that figured out the technology to go into low-priced leases because the oil was inaccessible. Junk bonds have fueled their growth and operations. As long as they get the cash flow from wells to pay their junk bond interest payment, it can keep going. Once they can't, expect a Wile E. Coyote splat in the junk bonds market and the fracking oil patch. The majors have moved in so they might be a bit of a flywheel for the system, but ultimately if prices are too low to support drilling, then the majors will pull the plug as fracking is not a long-term investment play over multiple price cycles in the same way an offshore oil field is. Instead, it can be turned on and off at will with new drilling always required to sustain production, so you just stop drilling when prices are too low.
Amfortas the hippie , May 10, 2019 at 10:22 am
a couple of on the ground, as it were, observations:
i live in frac sand country("Brady Brown"). there was a crisis of late to my north, as 2 of the 3 sand plants in and around Voca and Brady Texas suddenly closed(after a few years of financial shenanigans/scandal, and them being sold to multnational outfits, etc). West Texas found a way to use the more local, white sand for their purposes, and stopped buying the Brady Brown.
Immediate local Depression, folks moving if they could sell their houses( for sale signs there are routinely a decade old ), local pols/big wigs freaking out.
one of them just reopened and all of a sudden, there's gobs of sand trucks heading South(Eagle Ford). first time in prolly 8 years.Both of my brothers in law work in the patch in the Permian roughnecking. When i probe them for anecdotes being careful not to ask leading questions they expect more or less permanent employment. one, against my advice(which he asked for), just bought a house in Sanderson which has no reason for being save oil.
My cousin, in East Texas, just hired on with a pipeline company headed to either the Permian or the Bakken(he's waiting to find out).
So there's a spurt of renewed activity in South Texas, and the expectation(both in the workforce, and in the boardroom) that West Texas(and Dakota) will continue for some time.
and i just remembered my last trip through Pasadena, Texas a year ago
the great big refinery on 225(I think it's Exxon) was putting in a gigantic separater(or whatever you call those things) easily as tall as the smaller skyscrapers in downtown houston(maybe 20+ stories) using 2 of the biggest, tallest cranes i've ever seen or heard of.
Dad says it's for heavy, sour crude(a la Venezuela and Iran). so there's at least year old expectations there, as well ie: exxon thinks it's gonna need much more refining capacity for that oil.
it can't last forever, of course.California Bob , May 10, 2019 at 11:08 am
" a gigantic separater(or whatever you call those things) " Crackers. https://en.wikipedia.org/wiki/Cracking_(chemistry)
Amfortas the hippie , May 10, 2019 at 11:12 am
That's the one!
Thanks.Svante , May 10, 2019 at 12:09 pm
But, I thought, "Caucasoid American" or, "ofay, peckerwood-type individual" was more politically correct, nowadays? https://stateimpact.npr.org/pennsylvania/2017/11/16/public-health-researcher-issues-dire-warning-over-proposed-ethane-cracker-plant/
https://www.fractracker.org/2017/02/formula-disaster-ethane-cracker/
Harrold , May 10, 2019 at 12:54 pm
Midland & Odessa are definitely planning on the continuation of oil production and are forecasting no busts. This hurts my head to understand as there are still people alive there who have been thru multiple booms and busts over the past 70 years.
Harry , May 10, 2019 at 6:12 pm
I would imagine its for the same reason there is no global warming or climate change in Florida. Its bad for business. Those guys know the truth. But theres no advantage in talking about it.
Synapsid , May 10, 2019 at 3:24 pm
Amfortas,
I don't know about that particular cracker but Exxon is building up refining capability for the light tight oil and condensate coming out of the Permian. That work is in the Houston area.
The idea may be Why ship it out when we can make money out of the products? I dunno.
Svante , May 10, 2019 at 10:57 am
In summary: If you're leaving an exceedingly expensive, but eminently walkable major city, with acceptable (off peak) mass tramsit, prodigeous gas/coal/nuclear/hydroelectric sources immediately available to move to a "normal" southern Appalachian city? Don't neglect to research PV, geothermal, "passive" convection, and plug-in hybrid or EV transportation options? When we were awaiting news from LA/MS friends in 2005, I'd been wondering about what my actually retiring atop the Marcellus would be like. We'd all figured Katrina's tour of Mars, Ursa, Mensa, Bullwinkle & Ram Powell platforms would (given Halliburton ruling the country) touch off a slick water fracking pyramid scheme that would have the Acela megalopolis simply killing us for our fracked gas, as they'd simply stolen our coal, gas, oil and nuclear energy? Silly, substance abusing, deplorables!
jonst , May 10, 2019 at 12:34 pm
If Las Vegas represented the sentiment here I would be betting you guys are wrong.
Obdurate Eye , May 10, 2019 at 9:14 pm
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal. CVX knows exactly what Anadarko's actual and potential wells are worth to them under a variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of the chapeau to them.
Obdurate Eye , May 10, 2019 at 9:14 pm
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal. CVX knows exactly what Anadarko's actual and potential wells are worth to them under a variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of the chapeau to them.
RBHoughton , May 10, 2019 at 10:48 pm
The evidence for production-suppression is opposition to the new Russia to Germany pipeline and US sanctions on Iran and Venezuela. Poland is America's stalking horse in Europe but is not getting much support from its neighbors.
Its my suspicion that vast sums of speculative money have gone into fracking in USA and UK because there was nothing better to do with the great increase in the money supply. That seems to be what's keeping the industry afloat for the time being.
Plutonium Kun's advice about plugging wells points to the frightful environmental effects that are coming to those countries that have allowed fracking. It will be the people that suffer.
Ptb , May 10, 2019 at 11:27 pm
It was the fruits of Bush admin energy policy. Doubt it was primarily geopolitical, more like tail wagging the dog. Though the distinction is increasingly blurry now.
Every presidency seems to have a couple of these programs. Mixed range of soundness as policy
Market innovation (Enron), corn ethanol, developing H2 fuel cells (with the H2 coming from natgas at the time), subsidies (and loan guarantees!) for electric cars, even bigger ones for luxury electric cars, natgas import facilities, natgas export facilities, favor pipe to Canada and block the rail, favor rail to Canada and block the pipe, govt indemnifying the nuke industry from lawsuit damages arising from accidents, allowing utilities to "bail in" customers in case of losses from nuke projects, exempting any and all fracking waste products from clean water regs, actually subsidizing solar and wind, actually retiring coal, also actually sanctioning or invading no less than big 5 oil producing countries
Whew! Policy!Bob Bancroft , May 10, 2019 at 11:55 pm
Destroying limited fresh water is insane. This is a perfect example of the horrible consequences of capitalism. Profit corrupts the political system as the state merges to serve the oligarchs.
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May 11, 2019 | www.nakedcapitalism.com
https://eus.rubiconproject.com/usync.html
https://c.deployads.com/sync?f=html&s=2343&u=https%3A%2F%2Fwww.nakedcapitalism.com%2F2019%2F05%2Fthe-shale-boom-is-about-to-go-bust.html
https://acdn.adnxs.com/ib/static/usersync/v3/async_usersync.html <img src="http://b.scorecardresearch.com/p?c1=2&c2=16807273&cv=2.0&cj=1" /> The Shale Boom Is About To Go Bust Posted on May 10, 2019 by Yves Smith By Nick Cunningham, a freelance writer on oil and gas, renewable energy, climate change, energy policy and geopolitics based in Pittsburgh, PA. Originally published at OilPrice
The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines.
For years, companies have deployed an array of drilling techniques to extract more oil and gas out of their wells, steadily intensifying each stage of the operation. Longer laterals, more water, more frac sand, closer spacing of wells – pushing each of these to their limits, for the most part, led to more production. Higher output allowed the industry to outpace the infamous decline rates from shale wells.
In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet and the volume of water used in drilling has surged more than 250 percent, according to a new report for the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well drilled in 2012, the report says.
That sounds impressive, but the industry may simply be frontloading production. The suite of drilling techniques "have lowered costs and allowed the resource to be extracted with fewer wells, but have not significantly increased the ultimate recoverable resource," J. David Hughes, an earth scientist, and author of the Post Carbon report, warned. Technological improvements "don't change the fundamental characteristics of shale production, they only speed up the boom-to-bust life cycle," he said.
For a while, there was enough acreage to allow for a blistering growth rate, but the boom days eventually have to come to an end. There are already some signs of strain in the shale patch, where intensification of drilling techniques has begun to see diminishing returns. Putting wells too close together can lead to less reservoir pressure, reducing overall production. The industry is only now reckoning with this so-called "parent-child" well interference problem.
Also, more water and more sand and longer laterals all have their limits . Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT quickly found out that it had problems when it exceeded 15,000 feet. "The decision to drill some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing hundreds of millions of dollars," the Wall Street Journal reported earlier this year.
Ultimately, precipitous decline rates mean that huge volumes of capital are needed just to keep output from declining. In 2018, the industry spent $70 billion on drilling 9,975 wells, according to Hughes, with $54 billion going specifically to oil. "Of the $54 billion spent on tight oil plays in 2018, 70% served to offset field declines and 30% to increase production," Hughes wrote.
As the shale play matures, the field gets crowded, the sweet spots are all drilled, and some of these operational problems begin to mushroom. "Declining well productivity in some plays, despite application of better technology, are a prelude to what will eventually happen in all plays: production will fall as costs rise," Hughes said. "Assuming shale production can grow forever based on ever-improving technology is a mistake -- geology will ultimately dictate the costs and quantity of resources that can be recovered."
There are already examples of this scenario unfolding. The Eagle Ford and Bakken, for instance, are both "mature plays," Hughes argues, in which the best acreage has been picked over. Better technology and an intensification of drilling techniques have arrested decline, and even led to a renewed increase in production. But ultimate recovery won't be any higher; drilling techniques merely allow "the play to be drained with fewer wells," Hughes said. And in the case of the Eagle Ford, "there appears to be significant deterioration in longer-term well productivity through overcrowding of wells in sweet spots, resulting in well interference and/or drilling in more marginal areas that are outside of sweet-spots within counties."
In other words, a more aggressive drilling approach just frontloads production, and leads to exhaustion sooner. "Technology improvements appear to have hit the law of diminishing returns in terms of increasing production -- they cannot reverse the realities of over-crowded wells and geology," Hughes said.
The story is not all that different in the Permian, save for the much higher levels of spending and drilling. Post Carbon estimates that it the Permian requires 2,121 new wells each year just to keep production flat, and in 2018 the industry drilled 4,133 wells, leading to a big jump in output. At such frenzied levels of drilling, the Permian could continue to see production growth in the years ahead, but the steady increase in water and frac sand "have reached their limits." As a result, "declining well productivity as sweet-spots are exhausted will require higher drilling rates and expenditures in the future to maintain growth and offset field decline," Hughes warned.
Ignacio , May 10, 2019 at 5:07 am
I think everybody knew that the shale boom would prove to be transient –I consider several years as transient– and it will end with holes in earth and wallets. The Bakken and Eagle Ford have become mature plays in a relatively short period and we will learn, sooner than later, how the decline of these plays unfolds. Somehow the shale business model depends on ever increasing production and production would have increased even faster if it wasn`t for resource constraints (takeaway capacity, crew availability ). According to the EIA the Permian is now filled with DUCKS, sorry, DUCs (drilled but uncompleted wells) waiting for production. Those are waiting for new pipelines and, "hopefully", oil price increases engineered by the US by production suppression in Venezuela and Iran.
Count me amongst those that would like oil price increases, although for different reasons.
Yves Smith Post author , May 10, 2019 at 6:00 pm
The forecasts I saw earlier were that production would peak in the early 2020s, decline gradually for the rest of the decade, and then fall off sharply.
PlutoniumKun , May 10, 2019 at 5:09 am
Arthur Berman has been predicting exactly this for year. They'll spend more and more pushing production up, but eventually you get diminishing returns – the drop off in production, when it happens, will be quite dramatic as the sweet spots run dry.
The equally big question though is the influence of oil and gas prices. A crisis in the shale fields might be precipitated not by a drop in production, but further downward pressure on prices. Or likewise, a spike in oil prices could give a boost to yet more capital investment in those fields. For now, I suspect the producers are far more worried about low prices than running out of oil/gas. A lot of them are betting on substantial rises in the future in order to make their balance sheets look better. So that's a lot of rich people who would welcome a Middle East war.
PlutoniumKun , May 10, 2019 at 5:24 am
Just to add – one possible catastrophic outcome for the planet of a shale bust is poorly capped wells. Properly capping a fracked well is very difficult (you need to plug each individual geological layer, its not just a matter of putting a concrete plug on the well head). If they are not properly plugged, they will leak gas for decades and its extremely difficult and expensive to properly plug. In theory of course they are supposed to be properly capped by the operators, but if they go out of business .
So even if gas and oil fracking stopped today, they will be a major source of CO2 emissions for decades to come, one that will cost many billions to mitigate.
Roger Boyd , May 10, 2019 at 11:57 am
Natural gas is methane, so badly capped fracked gas wells would be really bad for climate change.
States and provinces have started program to cap old O&G wells abandoned decades ago that are leaking methane. All they need to do for new fracking wells is put in tight regulations and enforce them. But that requires political will.
So even if gas and oil fracking stopped today, they will be a major source of CO2 emissions for decades to come, one that will cost many billions to mitigate.
And methane if the gas does not contain CO2.
Svante Arrhenius , May 10, 2019 at 1:50 pm
When we'd fish, mountain bike or varmint hunt in Western PA., many decades ago (ie: ancient conventional oil & gas wells only) it was clear; not only was none of the leaking gas ever flared, but folks were tapping the rusted christmas trees. By the 80's, as we were building the rail trails, it was far worse than our memories. Fracked ethane/ wet gas wells are off-limits, unless you have FLIR drones.
https://m.phys.org/news/2015-05-emissions-natural-gas-wells-downwind.html
https://m.youtube.com/watch?v=HanXGD2NJxkskippy , May 10, 2019 at 5:29 am
Fracking the modern equivalent to hydrological gold mining
But money [tm] was made some confuse this with value
Svante , May 10, 2019 at 12:02 pm
Well, gold does a: not explode (oh, yes it DOES!) b: does not cause 20%-89% more global warming than CO2 (oh yes it DO!) c: "water is precious, sometimes more precious than gold?" Walter Houston, as Howard: The Treasure of the Sierra Madre, who called Bogart, "no, not ME baby!"
jackiebass , May 10, 2019 at 5:57 am
This is old news. Drillers over estimated the production length for fracked wells to help their Ponzi Scheme. For a natural gas well the production tanks in most cases in 3 years. To keep production up more wells had to be drilled. Eventually places to drill become hard to locate.I witnessed this in northern PA. It was boom for about 5 years then came the bust. Although there is still some fracking it is only minor compared to what it was. A few made money but the cost to the environment was passed on to the taxpayers.
The Rev Kev , May 10, 2019 at 6:11 am
There may be another factor at work here. Granted that the shale boom was always going to be a short term play, maybe the move on Venezuela is all about having oil to replace US production as it taps out – slowly at first, then all at once. Trump & Co could always buy Venezuelan oil at a market price but I think that the idea is to seize it to control more of the international oil market by being able to control international prices and you can't do that if Venezuela is an independent country. I just wonder how much damage is going to be done in America in terms of the environment and more importantly water supplies by all the chemicals pumped into the ground. It is going to be a toxic legacy that will be there for generations to come.
PlutoniumKun , May 10, 2019 at 6:30 am
Venezuelan oil is very important to frackers because almost all refineries in the US were built to handle the mid-density oils from Texas and Alaska. Tight oil (fracked) is super light (it can't be fracked otherwise), and so it needs to be mixed in with heavy grade oil to make it refinable. This is where heavy Venezuelan crude and Canadian tar sand oil comes in – they are essential to create a crude that can be refined in existing plants.
So the relationship between the US tight oil industry and Venezuela/Canada is quite complex – they all need each other to some extent otherwise they are stuck with oil that can't be refined. This is of course one reason why Washington absolutely hates not having firm control of Venezuelan production. But its also why they can't afford to shut it down entirely (which would happen if there was a military invasion or civil war).
So the calculations are complex, and they are being made by idiots, so there is no telling what they are planning.
Ken , May 10, 2019 at 11:49 am
There are several facets to this. The light oil from fracking and elsewhere is needed as a dilutent for the very heavy Venezuelan crude to enable it to be pumped on and off tank ships and through pipelines. Dilutents are also needed for the bitumen from the Alberta tar sands. The reason for the Keystone pipeline system is to pump diluted bitumen (dilbit) from Alberta to the Texas refineries is that are equipped to process this very heavy material similar to the very heavy Mexican and Venezuelan crudes. (Crude oils around the world vary greatly in composition. Refineries are equipped to process only certain types of crude.)
The fracked oil and gas often have low market value. The gas wells may produce relatively low quantities of high value natural gas liquids. The oil often is so light that it produces low quantities of high value distillates like diesel fuel. The fracked crude may contain high amounts of impurities that make it difficult and expensive to refine.
https://www.digitalrefining.com/article/1000979,Overcoming_the_challenges_of_tight_shale_oil_refining.html#.XNWZrqR7ncsThe rapid decline of output of the fracked wells is not new news. Oilprice.com has a 2017 article on the same point. https://oilprice.com/Energy/Crude-Oil/Shale-Growth-Hides-Underlying-Problems.html
Olga , May 10, 2019 at 12:58 pm
Well, and then there is this:
https://www.worldoil.com/news/2019/4/11/permians-flaring-rises-by-85-as-oil-boom-continues
"The Permian Basin has produced so much natural gas that by the end of 2018 producers were burning off more than enough of the fuel to meet residential demand across Texas. The phenomenon has likely only intensified since then."
The problem seems to be a lack of pipelines to get the gas to customers.
Not that I disagree with "the boom is over" too much, but Permian is a large area and has a way to go. But it will fizzle out in time.Venezuela oil can be delivered directly to the Gulf Coast refineries in tankers that require no permitting or construction. Canadian oil requires pipelines (e.g. Keystone XL) which are held up in permitting. So it is ironic that the Keystone pipeline permitting quagmire is likely to be a proximate cause for the Trump administration dabbling in Venezuela as many Gulf Coast refineries are geared for Alberta/Venezuela oil.
RWood , May 10, 2019 at 9:49 am
Using data from field experiments and computer modeling of ground faults, researchers have discovered that the practice of subsurface fluid injection used in 'fracking' and wastewater disposal for oil and gas exploration could cause significant, rapidly spreading earthquake activity beyond the fluid diffusion zone. The results account for the observation that the frequency of man-made earthquakes in some regions of the country surpass natural earthquake hotspots.
According to the U.S. Geological Survey, the largest earthquake induced by fluid injection and documented in the scientific literature was a magnitude 5.8 earthquake in September 2016 in central Oklahoma. Four other earthquakes greater than 5.0 have occurred in Oklahoma as a result of fluid injection, and earthquakes of magnitude between 4.5 and 5.0 have been induced by fluid injection in Arkansas, Colorado, Kansas and Texas.
Fracking: Earthquakes are triggered well beyond fluid injection zones
https://www.sciencedaily.com/releases/2019/05/190502143353.htmQuarterBack , May 10, 2019 at 9:51 am
I seriously doubt that the shale boom was ever about being profitable. I have long held that the shale industry has been artificially elevated as a hedge against risks induced by the long term Middle East geopolitical and military strategy. It was always expected to loose money and have negative secondary effects, but it had been decided to be necessary. Shale has survived because of a gentleman's agreement by the power players to cover the costs of the shale strategy; that along with investment media hype and stealthy subsidies to try to induce outside suckers to reduce some of the burden of those behind the hedge.
The shale industry was largely small to mid-sized firms that figured out the technology to go into low-priced leases because the oil was inaccessible. Junk bonds have fueled their growth and operations. As long as they get the cash flow from wells to pay their junk bond interest payment, it can keep going. Once they can't, expect a Wile E. Coyote splat in the junk bonds market and the fracking oil patch. The majors have moved in so they might be a bit of a flywheel for the system, but ultimately if prices are too low to support drilling, then the majors will pull the plug as fracking is not a long-term investment play over multiple price cycles in the same way an offshore oil field is. Instead, it can be turned on and off at will with new drilling always required to sustain production, so you just stop drilling when prices are too low.
Amfortas the hippie , May 10, 2019 at 10:22 am
a couple of on the ground, as it were, observations:
i live in frac sand country("Brady Brown"). there was a crisis of late to my north, as 2 of the 3 sand plants in and around Voca and Brady Texas suddenly closed(after a few years of financial shenanigans/scandal, and them being sold to multnational outfits, etc). West Texas found a way to use the more local, white sand for their purposes, and stopped buying the Brady Brown.
Immediate local Depression, folks moving if they could sell their houses(for sale signs there are routinely a decade old), local pols/big wigs freaking out.
one of them just reopened and all of a sudden, there's gobs of sand trucks heading South(Eagle Ford). first time in prolly 8 years.Both of my brothers in law work in the patch in the Permian roughnecking.
when i probe them for anecdotes being careful not to ask leading questions they expect more or less permanent employment. one, against my advice(which he asked for), just bought a house in Sanderson which has no reason for being save oil.
My cousin, in East Texas, just hired on with a pipeline company headed to either the Permian or the Bakken(he's waiting to find out).
so there's a spurt of renewed activity in South Texas, and the expectation(both in the workforce, and in the boardroom) that West Texas(and Dakota) will continue for some time.and i just remembered my last trip through Pasadena, Texas a year ago
the great big refinery on 225(I think it's Exxon) was putting in a gigantic separater(or whatever you call those things) easily as tall as the smaller skyscrapers in downtown houston(maybe 20+ stories) using 2 of the biggest, tallest cranes i've ever seen or heard of.
Dad says it's for heavy, sour crude(a la Venezuela and Iran). so there's at least year old expectations there, as well ie: exxon thinks it's gonna need much more refining capacity for that oil.
it can't last forever, of course.California Bob , May 10, 2019 at 11:08 am
" a gigantic separater(or whatever you call those things) "
Crackers.
Amfortas the hippie , May 10, 2019 at 11:12 am
That's the one!
Thanks.Svante , May 10, 2019 at 12:09 pm
But, I thought, "Caucasoid American" or, "ofay, peckerwood-type individual" was more politically correct, nowadays? https://stateimpact.npr.org/pennsylvania/2017/11/16/public-health-researcher-issues-dire-warning-over-proposed-ethane-cracker-plant/
https://www.fractracker.org/2017/02/formula-disaster-ethane-cracker/
Harrold , May 10, 2019 at 12:54 pm
Midland & Odessa are definitely planning on the continuation of oil production and are forecasting no busts.
This hurts my head to understand as there are still people alive there who have been thru multiple booms and busts over the past 70 years.
Harry , May 10, 2019 at 6:12 pm
I would imagine its for the same reason there is no global warming or climate change in Florida. Its bad for business. Those guys know the truth. But theres no advantage in talking about it.
Synapsid , May 10, 2019 at 3:24 pm
Amfortas,
I don't know about that particular cracker but Exxon is building up refining capability for the light tight oil and condensate coming out of the Permian. That work is in the Houston area.
The idea may be Why ship it out when we can make money out of the products? I dunno.
Svante , May 10, 2019 at 10:57 am
In summary: If you're leaving an exceedingly expensive, but eminently walkable major city, with acceptable (off peak) mass tramsit, prodigeous gas/coal/nuclear/hydroelectric sources immediately available to move to a "normal" southern Appalachian city? Don't neglect to research PV, geothermal, "passive" convection, and plug-in hybrid or EV transportation options? When we were awaiting news from LA/MS friends in 2005, I'd been wondering about what my actually retiring atop the Marcellus would be like. We'd all figured Katrina's tour of Mars, Ursa, Mensa, Bullwinkle & Ram Powell platforms would (given Halliburton ruling the country) touch off a slick water fracking pyramid scheme that would have the Acela megalopolis simply killing us for our fracked gas, as they'd simply stolen our coal, gas, oil and nuclear energy? Silly, substance abusing, deplorables!
jonst , May 10, 2019 at 12:34 pm
If Las Vegas represented the sentiment here I would be betting you guys are wrong.
Obdurate Eye , May 10, 2019 at 9:14 pm
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal. CVX knows exactly what Anadarko's actual and potential wells are worth to them under a variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of the chapeau to them.
Obdurate Eye , May 10, 2019 at 9:14 pm
I'm surprised no one has mentioned in passing Chevron's walk-away from the Anadarko deal. CVX knows exactly what Anadarko's actual and potential wells are worth to them under a variety of pricing scenarios. They'd rather pocket the $1bn break-up fee than overpay for a bunch of marginal wells. Good pricing/ROI discipline = not succumbing to deal-fever: A tip of the chapeau to them.
RBHoughton , May 10, 2019 at 10:48 pm
The evidence for production-suppression is opposition to the new Russia to Germany pipeline and US sanctions on Iran and Venezuela. Poland is America's stalking horse in Europe but is not getting much support from its neighbors.
Its my suspicion that vast sums of speculative money have gone into fracking in USA and UK because there was nothing better to do with the great increase in the money supply. That seems to be what's keeping the industry afloat for the time being.
Plutonium Kun's advice about plugging wells points to the frightful environmental effects that are coming to those countries that have allowed fracking. It will be the people that suffer.
Ptb , May 10, 2019 at 11:27 pm
It was the fruits of Bush admin energy policy. Doubt it was primarily geopolitical, more like tail wagging the dog. Though the distinction is increasingly blurry now.
Every presidency seems to have a couple of these programs. Mixed range of soundness as policy
Market innovation (Enron), corn ethanol, developing H2 fuel cells (with the H2 coming from natgas at the time), subsidies (and loan guarantees!) for electric cars, even bigger ones for luxury electric cars, natgas import facilities, natgas export facilities, favor pipe to Canada and block the rail, favor rail to Canada and block the pipe, govt indemnifying the nuke industry from lawsuit damages arising from accidents, allowing utilities to "bail in" customers in case of losses from nuke projects, exempting any and all fracking waste products from clean water regs, actually subsidizing solar and wind, actually retiring coal, also actually sanctioning or invading no less than big 5 oil producing countries
Whew! Policy!Bob Bancroft , May 10, 2019 at 11:55 pm
Destroying limited fresh water is insane. This is a perfect example of the horrible consequences of capitalism. Profit corrupts the political system as the state merges to serve the oligarchs.
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Apr 30, 2019 | peakoilbarrel.com
Watcher : 04/26/2019 at 2:32 am
Not going to scroll up for the spreadsheet above, not easy where I am sitting right now.Concerning net revenue and production. The problem is not future price of oil. The problem is the past price of oil. Two-thirds of the total lifetime production of one of these shale wells comes out of the ground in the first two years. The price was sub-60 a couple of years back and that oil flowed and generated only that much money. That well's debt is not going to get repaid by that well. The oil came out at a lower price and that deal is done.
This means that the month number where revenue becomes negative is much sooner. And if things were logical and money was not created from thin air, the fact that the well in question cannot repay its debt does not make the debt go away.
In a properly accounted world all of those wells from 2 years ago which cannot be repay their debt should have that debt apply to the new wells that are drilled now -- and erase their profit. This is forever, by the way. Anytime oil drops below whatever 60, or 55 or 50, the wells drilled then and the money borrowed to drill them is essentially guaranteed to get applied to future wells.
But this won't happen. When you have to have the oil you get the oil.
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Apr 23, 2019 | www.zerohedge.com
1969wasgood , 38 minutes ago link
deFLorable hillbilly , 1 hour ago linkWhat it really means. 42 more years, and it's gone. 1.531 trillion bbls divided by a no grow of 100 million bbls consumption a day, simple math. And we rant about finding another 50 billion bbls. That only takes the total of the recoverable oil to 1.581 trillion bbls.
Oil will leave us before we leave oil. We are heading for mass starvation. There are no electric fire engines, there are no electric ambulances, there are no electric farm machinery, there are no electric military machinery, there are no electric boats or ships or ferries, there are no electric airplanes, fighter jets, helicopters, there are 1.4 billion cars in the world of which 3 million are electric, if Tesla quadruples production it couldn't replace the gas and diesel powered vehicles in 1200 years, and the Chinese electrics are crap.
Yen Cross , 1 hour ago linkThis map is complete BS. No one, especially some spy agency, knows how much of anything is underground.
The only known fact is current production. "Known Reserves" is a hopelessly politicized exercise in conjecture, primarily for the purpose of securitizing international loans at favorable rates.
Minamoto , 1 hour ago linkThese numbers are complete horse-****.
U.S. Crude Oil, Natural Gas, and Natural Gas Proved Reserves, Year-end 2017
Proved reserves of crude oil in the United States increased 19.5% (6.4 billion barrels) to 39.2 billion barrels at Year-End 2017, setting a new U.S. record for crude oil proved reserves. The previous record was 39.0 billion barrels set in 1970.
USGS Announces Largest Oil And Gas Deposit Ever Assessed In U.S. : The Two-Way : NPR
The USGS says all 20 billion barrels of oil are "technically recoverable," meaning the oil could be brought to the surface "using currently available technology and industry practices."
Between the corrupt politicians, and oil execs. these morons can't even concoct a decent lie anymore.
bismillah , 1 hour ago linkThose numbers are somewhat laughable... Venezuela's gigantic reserves require lots of processing to get the oil sands into proper crude.
In addition, Russia's total reserves are underestimated as most of Russia's territory has not been geologically explored.
Most oil reserve claims with OPEC countries are hugely exaggerated.
And reserve claims by others are faked higher than they really are, too.
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Apr 12, 2019 | peakoilbarrel.com
xxx: 04/10/2019 at 10:56 pm
Hello Dennis. Have you ever really thought about why the Saudi's would keep their production info as a state secret? I think it has much less to do about quotas than maintaining the status quo of a country and society much different than our western norms.
I have guessed their remaining reserves around 80 gb before, and still believe its in that area. Of course ANYONE without actual production and reservoir info is also guessing whether they are economists, engineers, geologists, or whoever.
If my guess is correct, we will see KSA production declining on a accelerating rate within a few years. Kuwait will not be far behind. North American shale will likely be topped out by then. Gee, that might be post peak.
I hope they have more recoverable oil than my guess, because its going to be a difficult transition.
Mike Shellman : 04/11/2019 at 6:39 am
Mr. Patterson, thanks for the article. You have defended it quite well, this in spite of Dennis Coyne's constant interjections.Ron Patterson : 04/11/2019 at 7:26 amEstimating remaining reserves from mature fields is not difficult from an engineering standpoint and how one tinkers with known reservoirs in that field (stuffing gas back into them, HZ laterals above O/W contacts, etc.) does not magically create "new" reserves, it simply speeds up the rate of extraction (arrests natural decline rates). The Saudis lie about their sovereign wealth and it's their right to lie, I suppose; all we can do is try to outsmart them, as you have. America cannot control the Saudi's, regardless of tweets.
We can, however, demand reserve transparency in our own country and that we are NOT getting. In essence the lies being said about "economically" recoverable shale oil reserves in America are way bigger whoppers than any lies the Middle East has ever told.
Mike, thanks for the kind words. I am quite used to Dennis' interjections. They don't bother me. In fact, I enjoy the dialogue with him. It keeps me on my toes.I can feel the tide turning concerning peak oil. I think OPEC peaked in 2016, politically suppressed production notwithstanding. However, the bigger surprise may be right here in the good old USA. The shale bubble could be bursting a lot sooner than a lot of people think.
Shale Jobs In Jeopardy Despite Oil Price Rally
U.S. shale drillers have run into a series of problems that have resulted in increased scrutiny on their operations. The difficulties span their operations – production issues, poor financials and less love from Wall Street.
Even as WTI has moved solidly above $60 per barrel, the U.S. shale industry is trying to find ways to right the ship. As Reuters reports, a series of drillers, even prominent ones, are laying off workers. Pioneer Natural Resources – often held up as one of the better of the bunch – and Laredo Petroleum announced just this week that they will be cutting staff. As Jennifer Hiller of Reuters points out, Pioneer has not laid off workers since 1998.
In March, Devon Energy eliminated 200 jobs.
According to a report from Tudor, Pickering, Holt & Co., the recent layoffs may not be the end of the story. Everyone should expect more job cuts "over the coming quarters as companies address right-sizing the corporate cost structures," the firm said in its report.
Nevertheless, the EIA still expects the boom to continue for years and years. We shall see.
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Apr 12, 2019 | peakoilbarrel.com
Graywulffe x Ignored says: 04/10/2019 at 5:55 pm
Nice summary, Ron. Brought to mind the old Oil Drum days. Thanks for taking the time to provide this information. Given the admittedly not high-confidence prognostications in Saudi/world oil production, it looks to me like the global economy may be in for at least one serious oil shock in the 2020s.Yet another titanic wave on the Peak Oil ocean.
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Apr 12, 2019 | peakoilbarrel.com
Carlos Diaz : 04/10/2019 at 1:44 pm
It's "coup de grâce."Adam Ash : 04/10/2019 at 5:27 pmA great article that offers a more realistic view of the very old giant oil fields. It is very obvious that what they are doing to maintain production will result in a more rapid decline in the future. When that happens KSA will be in a lot of hurt, and the world will have an abrupt awakening.
So my simple math says: 256 URR was to last 53 years, 74 URR at the same production rate will last 15 years. Seneca with a vengeance! Rite? EOLAWKI here we come!add to that the usual woes of increasing internal oil consumption (3 mbd and rising fast) and the need to try and build their way out of their demise (requiring more oil and money), and the usual predictions of the 'export land model' look very reasonable, and disastrous for the House of Saud. There will be a tapered end, but the potential for acute instability in production and the in political and social environments of the country within the next decade is real.
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Apr 12, 2019 | peakoilbarrel.com
Karen Fremerman : 04/10/2019 at 12:17 pm
At some point the Seneca Cliff will be hit. If they are doing all this advanced recovery to to keep flow rates up then fields will probably hit a wall and crash rather than slow decline. Is my thinking correct on that? KarenHugo : 04/11/2019 at 2:20 amDennisSchinzy : 04/11/2019 at 3:42 amOil consumption has been increasing in all sectors and the growing global economy will require more oil in industry. You seem to think oil is just used in transportation. NOT true.
https://www.statista.com/statistics/307194/top-oil-consuming-sectors-worldwide/
Imagine oil production peaked today. In order for aviation to continue to grow, along with other industries that use oil. How many of the 98 million vehicles sold this year would need to be electric cars? How many electric motorcycles would have to be sold?
https://motorcyclesdata.com/2019/03/25/world-motorcycles-market/
Knowing these answers gives us a real understanding of what needs to happen.
Iron Mike : 04/11/2019 at 6:05 amThe Seneca cliff for World output requires heroic assumptions which are unlikely to be true in practice.
I strongly disagree with that assessment. I believe the probability of a Seneca cliff is increasing. I think oil extraction is an economic phenomena, not a geological phenomena. During economic expansion, a positive feedback loop is in place: oil extraction produces economic growth which encourages investment in oil extraction producing more economic growth. Once peak oil occurs, I anticipate that this feedback loop will go into reverse: decreased oil production will produce economic contraction which will discourage investment in oil extraction reducing extraction rates leading to economic collapse.
Without investment the IEA estimates that production would fall by 50% in 2025 and by 80% in 2040.
I actually think economic collapse is a great opportunity to introduce a new economic system. The one we have is not only unfair, it encourages environmental devastation.
David Graebner asks rhetorically how a theory such as neoclassic economics based on false hypotheses perdures. His answer is that you teach the biggest lies in the first year. That's why false preconceptions about the economy are so common. I think neoclassical economics chose the wrong mathematical tool to analyse the economy, they chose optimisation. I don't see anything optimal in the economy, I think differential systems would be a much more appropriate mathematical tool with which to analyse the economy, keeping track of money flows.
Our assessment of how the oil cycle will play out can be found here: https://www.tse-fr.eu/publications/oil-cycle-dynamics-and-future-oil-price-scenarios .
Hi Ron,Fred Magyar : 04/11/2019 at 8:30 amI assume a Seneca cliff scenario would imply rapid economic collapse, as a result i think there will be war over resources. Between which countries i don't know, but i assume U.S will go to war with Russia and or China, via direct war or proxy wars in regions were the countries national security depends on specific resources. So the middle east would as usual be a key area of conflict.
I believe a Seneca cliff scenario would be a catastrophic one hence the reaction to such a scenario would also be catastrophic.
German Guy : 04/10/2019 at 12:53 pmU.S will go to war with Russia and or China, via direct war or proxy wars in regions were the countries national security depends on specific resources.Perhaps! However modern warfare tends to be very energy intensive. It seems to me a rather safe bet that in a post peak oil world, mostly running on renewables, it might be more likely that societies will be trying to conserve their energy resources and not waste it on war.
But the verdict is not yet in, on whether or not humans are smarter than yeast!
World demand is currently over 100 mb/day, while production is at about 99 mb/day. Does that mean we are using up the already produced reserves?Dennis Coyne : 04/10/2019 at 3:03 pmGerman Guy,It simply means we are using oil that is being stored, the so-called oil stocks, eventually as these are reduced, oil prices start to rise and demand (consumption) decreases while supply (production) increases in response to the change in oil price.
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Apr 12, 2019 | peakoilbarrel.com
Ron Patterson : 04/10/2019 at 4:06 pm
Well, no, Ghawar is not declining at 2% per year. Ghawar did not start declining in 2004. And the southern two fields are not declining at all. The northern three fields reached their Seneca Cliff somewhere around 2010 and began declining at several times 2%. They will decline to near nothing in the next few years. Then Ghawar will have level production at somewhere around 2 million barrels per day and hold that level for a decade or two.Ron Patterson : 04/10/2019 at 7:08 pmGhawar cannot possibly be adequately described as one field. It is five different fields with five different decline and depletion rates.
When Saudi said, in 2006, that their average decline rate was down to almost 2%, that was the average for all their fields. Some fields were declining at a much faster rate and some fields were not declining at all. Khurais and Manifa were still to be ramped up. Those fields had been in mothballs and would be brought back on line. Now they are likely not declining at all but other fields are declining at a much faster rate than 2%.
But here is the important point. The depletion rate is another matter altogether. That figure is likely above 8% per year.
Do you have production data for the various fields from 2006 to 2018?Eulenspiegel : 04/10/2019 at 10:41 amDennis, you know better than ask such a silly question. Saudi production of individual fields is a closely guarded secret.
Dennis, have you ever wondered why the Saudis keep all this data such a secret? Why don't they just let the actual data known to the world? What was the production data from Safaniya in 2018? Or what was the production data from Manifa in 2018? Or what was the production data from Khurais in 2018, or from Berri, or from all their other fields? And how did that compare to the production in 2017, or 2016?
Dennis, we don't know shit about any of this. We don't know because it is a closely guarded secret. Why, Dennis, Why?
They know Dennis, they know and they don't want you to know. Why?
I know why Dennis. Because what they actually report, which is almost nothing, is a lie. You simply choose to believe it. I do not. I choose to believe the analysis who try to figure out why they are lying. You choose to simply believe the Saudis.
Dennis, the idea that Saudi Arabia has 266 billion barrels of reserves is preposterous beyond belief. Even the Saudis realize that now are trying to slowly reduce that figure. Yet some people, like you, Robert Rapier and Michael Lynch, seemed perfectly ready to believe such an absurd figure. That just floored me. Goddammit, have some people gone insane?
Okay, I have said my peace here and showed my ignorance as to what Saudi Arabia actually can produce for the next 50 years. But you know, it is what they say they can produce.
You believe them. I don't. And neither of us can prove our case. And there it must rest until the actual production data comes in next year and next year and ..
Good work Ron.When this is true, that's the reason China is pushing electric travel as hard as they can.
They have more possibilites to know the truth (secret service) than we reading reports. And with SA and Russia having only round about 80 GB left, and producing each round about 10 mbpd, there are not many years left before a major oil incident.
I wonder why oil prices are that stable at the moment. Oil production fell hard this year so far, down everywhere except USA. And there the growth is decelerated.
And demand is still climbing, it will use up all the US growth projected by the optimistic EIA.
A 500 kbpd decline from OPEC is not included here, they still calculate with an increase from opec.Last question: Where is Russia standing at the moment?
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Apr 12, 2019 | peakoilbarrel.com
Chris Martensonx : 04/10/2019 at 11:05 am
Ron,Dennis Coyne : 04/10/2019 at 11:15 amI'm wondering if you can help solve a mystery.
In the bond prospectus SA revealed their financials. Puzzling to me was the claim of revenue of $356 billion.
Why puzzling?
Because Brent averaged ~$75/bbl in 2018. Divide $356 by $75 and you come up with 4.75 Gbbl, which when we divide by 365 days in a year, we get 13 million barrels per day production.
???
I can't get their numbers to work. Even with a 10% premium on their grades of crude (generous), that leaves 11.7 mbd of production . I can't get anything to line up here.
Any ideas?
Chris,Ron Patterson : 04/10/2019 at 11:31 amThey also produce NGL and natural gas, in 2016 it was about 1.94 Mb/d or 708 MMb of NGL, I have no idea what the average selling price is for NGL on World markets, it would depend on the mix of NGL of course.
Saudi Arabia, in 2018 produced approximately 3.76 billion barrels of crude only. Their BOE produced was approximately 4.75 billion barrels. That would account for the revenue is they sold every barrel of it. But they consumed a lot themselves. So other than that I have no explanation. Do they count their own consumption as revenue?Dennis Coyne : 04/10/2019 at 11:54 amEIA has about 4.5 Gb of total liquids produced by KSA in 2018, that would imply $79/boe average selling price.I suppose in accounting terms the Saudi Government could pay Aramco for the subsidized oil and the 4.75 Gbo would give us the $75/boe selling price.
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Apr 09, 2019 | peakoilbarrel.com
Energy News says: 04/08/2019 at 9:26 am
Ron Patterson: 04/08/2019 at 10:26 am
- 2019-04-08 (ShaleProfile) US – update through December 2018 https://shaleprofile.com/blog/
- (2018) Oil production from wells started in 2018 is at: 3,541,921 bo/day, this is 54.4% of the total 6,512,307 bo/day.
- (2017) Oil production from wells started in 2017 peaked in December 2017 at 2,889,460 bo/day, they are now producing, December 2018: 1,178,108 bo/day. Giving a drop from the peak of -59.2% in the last 12 months.
- (2016) Production from wells started in 2016 peaked in December 2016 at 1,561,476 bo/day, they are now producing, December 2018: 416,032 bo/day. Giving a drop from the peak of -73.4% in the last 24 months. After one year they were at, December 2017: 662,907 bo/day. Giving a drop from the peak of -57.5% over 12 months
An annual decline rate of 57.5 percent is insane. Yet 3,541,921 bo/day from 2018 wells is even more insane. Shale oil is a phenomenon no one would have believed just a few years ago.But now it is obvious that this juggernaut called shale oil is slowing down. And its crash will likely be more shocking than its rise.
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Apr 09, 2019 | peakoilbarrel.com
Carlos Diaz: 04/08/2019 at 8:07 pm
Hickory: 04/09/2019 at 10:12 amThe decline is likely to be less steep than the increase
Have you heard about a Seneca cliff? It is called that way because Seneca in his letter number 91 to Lucillius (Epistulae Morales ad Lucilium), written towards the end of the year AD 64, a year before he died, refers to the fire that destroyed Lugdunum (Lyon) the summer of that year in the following terms:
It would be some consolation for the feebleness of our selves and our works, if all things should perish as slowly as they come into being; but as it is, increases are of sluggish growth, but the way to ruin is rapid.
It appears he knew almost two thousand years ago what you don't.
I expect that a long slow declining tail of production will have some abrupt jolts downward along the way, and end up lower quicker as a result.Carlos Diaz: 04/09/2019 at 7:12 pmThe jolts downward will come as producing countries become failed states and the chaos disrupts operations.
For examples of how this comes to be, just look at the past 5 yrs of Venez and Libya as examples. Sure they may pick back up at some point, but overall effect is diminished global production, well below a theoretically well managed industry.
Secondly, (and likely a smaller effect) some deposits will likely be kept in the ground because of choices some cultures make. For example, I could see the USA deciding to keep its large remaining coal deposits largely in the ground after 2030. Canada could decide to put a big constraint on oil sand production, keeping just enough for domestic use, if they so desired.
Why you think such scenario is so improbable? Venezuela is living a Seneca cliff in its oil production right now. Did anybody predicted it before it took place?We have no idea of what will happen after Peak Oil. Some people assume nothing, while others think it will be the end of our civilization. Somewhere in between probably. But I fail to see how the economy can take it well if for most applications we can't substitute oil. The globalization is run on oil and its derivatives.
Your assumptions can only be valid at this side of the peak. If you think otherwise you fool yourself.
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Apr 07, 2019 | peakoilbarrel.com
Freddy says: 04/06/2019 at 5:26 pm
There is no doubt the tight rock structures which are much more difficult to extract oil from than sandstone reservoir can be stimulated in different ways with good result. But that costs a lot of money.As I read fracking uses a very high hydraulic pressure open up the tight rock layers and until a few years ago the oil flow dropped at a very early stage because the overlaying weight and beacuse the oil flow carries with with itself particles that block the fraction.
Later it followed a propant research that was done before but again this gave improvement and could hold the fracs open for longer.
Than there was research on chemical injected that should reduce friction between oil flow and rock. There is also lots of other factores like gazes, metal that in certain pressures, temperatures might react and create pollutant as happened lately when oil cargo was sent back from Asia.
Better propant , longer laterals , some improvement of fluid , improved rigs and pads enable to drill several laterals simultaneously have made the improvement they call shale revolution.
Still very few are able to earn money to pay dividend, loan, interest and finance expansion with WTI 60 USD.
Now number of rigs increasing again, but why when there are so many DUCS? Probably because investors tells the business shall be cash neutral. Could it be the DUCS are so closely spaced that using along with the existing wells might be not profitable because of interference with nearby wells.
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Apr 06, 2019 | peakoilbarrel.com
Ron Patterson 04/06/2019 at 12:05 pm
Remember Peak Oil? It's back!It seems that the biggest Saudi field is losing its punch.
Years ago we used to talk a lot about peak oil, the prediction made by M. King Hubbert that the easy oil was going to run out, that it was going to get harder and harder to find the stuff, and it was going to get more and more expensive to get out of the ground.
Hubbert wrote in 1948: "How soon the decline may set in is not possible to say, Nevertheless the higher the peak to which the production curve rises, the sooner and sharper will be the decline."
According to the predictions made back in 2005, right about now the Saudis are running out and we are smack in the middle of confusion, heading for chaos. Of course we are not, we are flooded with fossil fuels, thanks to the fracking boom.
But according to Eric Reguly, writing in the Globe and Mail, there is trouble ahead, because that prediction about Saudi oil may not be that far off. He writes that the giant Ghawar field used to produce ten percent of the world's oil, five million barrels a day.
The US Permian shale basin now supplies 4.1 million barrels a day, but fracked wells run out pretty quickly, and the fracking companies are all losing money. Better sell that pickup truck; it may well cost a lot more to fill it. As Reguly concludes, the Ghawar field is indeed in trouble,"and if it does collapse, peak oil will come a bit sooner."
In fact, Ghawar is not as resilient as we were led to believe. We just found out that its output has fallen substantially since Aramco previously came clean on its reserves and production. If Ghawar is losing momentum fast, peak oil – remember that theory? – might be closer than we had thought. And Ghawar is just one of dozens of enormous conventional-oil reservoirs scattered around the planet that are in various stages of decline.
Those include the North Sea, Alaska's Prudhoe Bay, and Reguly reminds us that Mexico's Cantarell reservoir used to supply 2.1 million barrels a day and is now down to 135,000.
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Apr 06, 2019 | peakoilbarrel.com
Karen E Fremerman x Ignored says: 04/05/2019 at 6:40 am
Maybe I missed something and you guys have already talked about this but have you guys listened to Art Berman's Macrovoices podcast?https://www.macrovoices.com/podcasts/MacroVoices-2019-03-14-Art-Berman.mp3
He is basically showing that the Permian is flattening/rolling over. See slide 11:
If you listen to the interview he has lined up the 7 month lag time with Rig Count and Lagged Production. If this ends up sticking then the production flattening should show up in July. Just wanted to hear what you guys have to say about it.
Thanks! Karen
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Apr 02, 2019 | peakoilbarrel.com
Freddy
x Ignored says: 04/01/2019 at 2:58 pmSeems US oil production from shale now are declining, seems the growth based on lended money now will stop. https://oilprice.com/Energy/Crude-Oil/US-Oil-Production-Dips-For-First-Time-In-Nearly-Six-Months.htmlWatcher x Ignored says: 04/01/2019 at 6:00 pm
From the Rig Count we know this decrease will be strengthening the comming months until the oil price increase to a level profit will be possible that can pay dividend and growth. This might take time as soon Trump will tweet again as oil is to expensive and OPEC will be forced to take action.The 10 yr bond is down at 2.5% today, and with the Fed's overt announcement 6 weeks ago, clearly the Fed isn't pushing its upward bias.Low rate money is the stuff of shale oil. Not profits.
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Apr 02, 2019 | peakoilbarrel.com
OFM x Ignored says: 03/30/2019 at 7:51 am
I'm sure that so long as the world wide economy remains on its feet that there will be huge increases in demand for oil for transportation.But nobody seems to give any thought here to things that will reduce demand. Cars will be driving themselves soon. Think about trains. Before too much longer, railroaders will be able to move stuff on trains almost as nimbly as truckers do today, at least on city to city basis when the cities are at least a couple of hundred miles apart. Long distance trucking may be a thing of the past within, like camera film and typewriters, within a couple of decades. These possibilities are worthy of thought if you are in the oil biz for the long haul.
Every country that imports oil is going to have a powerful incentive to reduce demand for it to the extent it can as depletion sooner or later pushes one exporting country after another into the importer category. Countries in the Middle East with oil and gas to export are going to find it so profitable to build wind and solar farms that they will be building them like mushrooms popping up after a spring rain, because they can sell some or maybe even most of the oil and gas they are burning now to generate electricity, thereby earning a big profit on their solar and wind farm investment.
My thinking is that these changes will actually PROLONG our dependence on oil, taken all around, by helping hold the price down so we can afford to run existing legacy equipment, and have affordable petrol based chemicals, etc. I don't think anybody currently in the biz needs to worry about selling out anytime soon, lol. But considerations such as these may have a huge impact on exploration and development starting within a decade or so.
Times change. Doom doesn't necessarily have anything to do with it.
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Apr 02, 2019 | peakoilbarrel.com
Energy News x Ignored says: 04/01/2019 at 1:52 pm
Brazil's oil production at 2,489 kb/day during February, which is down -142 from January
2018 average 2,587 kb/day
No press release yet, waiting to see if they mention the new FPSOs ANP -> http://www.anp.gov.br/
Chart: https://pbs.twimg.com/media/D3FsLyMW0AANPL4.png
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Mar 30, 2019 | www.moonofalabama.org
dh-mtl , Mar 30, 2019 5:00:04 PM | link
The U.S. desperately needs Venezuelan oil.
They lost control of Saudi Arabia, after trying to take down MBS and then betraying him by unexpectedly allowing waivers on Iranian oil in November.
The U.S. cannot take down Iran without Venezuelan oil. What is worse, right now they don't have access to enough heavy oil to meet their own needs.
Controlling the world oil trade is central to Trump's strategy for the U.S. to continue its empire. Without Venezuelan oil, the U.S. is a bit player in the energy markets, and will remain so.
Having Russia block the U.S. in Venezuela adds insult to injury. After Crimea and Syria, now Venezuela, Russia exposes the U.S. as a loud mouthed-bully without the capacity to back up its threats, a 'toothless tiger', an 'emperor without clothes'.
If the U.S. cannot dislodge Russia from Venezuela, its days as 'global hegemon' are finished. For this reason the U.S. will continue escalating the situation with ever-riskier actions, until it succeeds or breaks.
In the same manor, if Russia backs off, its resistance to the U.S. is finished. And the U.S. will eventually move to destroy Russia, like it has been actively trying to do for the past 30 years. Russia cannot and will not back off.
Venezuela thus becomes the stage where the final act in the clash of empires plays out. Will the world become a multi-polar world, in which the U.S. becomes a relatively isolated and insignificant pole? Or will the world become more fully dominated by a brutal, erratic hegemon?
All options are on the table. For both sides!
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Mar 21, 2019 | peakoilbarrel.com
HuntingtonBeach x Ignored says: 03/19/2019 at 1:20 am
"Perfect Storm" Drives Oil Prices Higher"The latest Brent rally has brought prices to our peak forecast of $67.5/bbl, three months early," Goldman Sachs wrote in a note. The investment bank said that "resilient demand growth" and supply outages could push prices up to $70 per barrel in the near future. It's a perfect storm: "supply loses are exceeding our expectations, demand growth is beating low consensus expectations with technicals supportive and net long positioning still depressed," the bank said.
The outages in Venezuela could swamp the rebound in supply from Libya, Goldman noted. But the real surprise has been demand. At the end of 2018 and the start of this year, oil prices hit a bottom and concerns about global economic stability dominated the narrative. But, for now at least, demand has been solid. In January, demand grew by 1.55 million barrels per day (mb/d) year-on-year. "Gasoline in particular is surprising to the upside, helped by low prices, confirming our view that the weakness in cracks at the turn of the year was supply driven," Goldman noted. "This comforts us in our above consensus 1.45 mb/d [year-on-year] demand growth forecast."
https://oilprice.com/Energy/Energy-General/Perfect-Storm-Drives-Oil-Prices-Higher.html
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Mar 16, 2019 | peakoilbarrel.com
I am now of the opinion that 2018 will be the peak in crude oil production, not 2019 as I earlier predicted. Russia is slowing down and may have peaked. Canada is slowing down and Brazil is slowing down. OPEC likely peaked in 2016. It is all up to the USA. Can shale oil save us from peak oil?
OPEC + Russia + Canada, about 57% of world oil production.
Jeff says: 03/14/2019 at 1: 50 pm
"I am now of the opinion that 2018 will be the peak in crude oil production, not 2019 as I earlier predicted. Russia is slowing down and may have peaked. Canada is slowing down and Brazil is slowing down. OPEC likely peaked in 2016. It is all up to the USA. Can shale oil save us from peak oil?"
IEA´s Oil 2019 5y forecast has global conventional oil on a plateau, i.e. declines and growth match each other perfectly and net growth will come from LTO, NGL, biofuels and a small amount of other unconventional and "process gains".
Iran is ofc a jocker, since it can quickly add supply. Will be interesting to see how Trump will proceed.
Carlos Diaz x Ignored says: 03/14/2019 at 3:23 pm
I am quite original in my opinion about Peak Oil. I think it took place in late 2015. I will explain. If we define Peak Oil as the maximum in production over a certain period of time we will not know it has taken place for a long time, until we lose the hope of going above. That is not practical, as it might take years.Dennis Coyne x Ignored says: 03/14/2019 at 4:57 pmI prefer to define Peak Oil as the point in time when vigorous growth in oil production ended and we entered an undulating plateau when periods of slow growth and slow decline will alternate, affected by oil price and variable demand by economy until we reach terminal decline in production permanently abandoning the plateau towards lower oil production.
The 12-year rate of growth in C+C production took a big hit in late 2015 and has not recovered. The increase in 2 Mb since is just an anemic 2.5% over 3 years or 0.8% per year, and it keeps going down. This is plateau behavior since there was no economic crisis to blame. It will become negative when the economy sours.
Peak Oil has already arrived. We are not recognizing it because production still increases a little bit, but we are in Peak Oil mode. Oil production will decrease a lot more easily that it will increase over the next decade. The economy is going to be a real bitch.
Carlos Diaz,Carlos Diaz x Ignored says: 03/14/2019 at 7:18 pmInteresting thesis, keep in mind that the price of oil was relatively low from 2015 to 2018 because for much of the period there was an excess of oil stocks built up over the 2013 to 2015 period when output growth outpaced demand growth due to very high oil prices. Supply has been adequate to keep oil prices relatively low through March 2019 and US sanctions on Iran, political instability in Libya and Venezuela, and action by OPEC and several non-OPEC nations to restrict supply have resulted in slower growth in oil output.
Eventually World Petroleum stocks will fall to a level that will drive oil prices higher, there is very poor visibility for World Petroleum Stocks, so there may be a 6 to 12 month lag between petroleum stocks falling to critically low levels and market realization of that fact, by Sept to Dec 2019 this may be apparent and oil prices may spike (perhaps to $90/b by May 2020).
At that point we may start to see some higher investment levels with higher output coming 12 to 60 months later (some projects such as deep water and Arctic projects take a lot of time to become operational, there may be some OPEC projects that might be developed as well, there are also Canadian Oil sands projects that might be developed in a high oil price environment.
I define the peak as the highest 12 month centered average World C+C output, but it can be define many different ways.
So Dennis,Dennis Coyne x Ignored says: 03/14/2019 at 9:20 pmOur capability to store oil is very limited considering the volume being moved at any time from production to consumption. I understand that it is the marginal price of the last barrel of oil that sets the price for oil, but given the relatively inexpensive oil between 2015 and now, and the fact that we have not been in an economical crisis, what is according to you the cause that world oil production has grown so anemically these past three years?
Do you think that if oil had been at 20$/b as it used to be for decades the growth in consumption/production would have been significantly higher?
I'll give you a hint, with real negative interest rates and comparatively inexpensive oil most OECD economies are unable to grow robustly.
To me Peak Oil is an economical question, not a geological one. The geology just sets the cost of production (not the price) too high, making the operation uneconomical. It is the economy that becomes unable to pump more oil. That's why the beginning of Peak Oil can be placed at late 2015.
The economic system has three legs, cheap energy, demographic growth, and debt growth. All three are failing simultaneously so we are facing the perfect storm. Social unrest is the most likely consequence almost everywhere.
Carlos,Carlos Diaz x Ignored says: 03/15/2019 at 5:03 amIf prices are low that means there is plenty of oil supply relative to demand. It also means that some oil cannot be produced profitably, so oil companies invest less and oil output grows more slowly.
So you seem to have the story backwards. Low oil prices means low growth in supply.
So if oil prices were $20/b, oil supply would grow more slowly, we have had an oversupply of oil that ls what led to low oil prices. When oil prices increase, supply growth will ne higher. Evause profits will be higher and there will be more investment.
No Dennis,Schinzy x Ignored says: 03/15/2019 at 11:18 amIt is you who has it backwards, as you only see the issue from an oil price point of view, and oil price responds to supply and demand, and higher prices are an estimulus to higher production.
But there is a more important point of view, because oil is one of the main inputs of the economy. If the price of oil is sufficiently low it stimulates the economy. New businesses are created, more people go farther on vacation, and so on, increasing oil demand and oil production. If the price is sufficiently high it depresses the economy. A higher percentage of wealth is transferred from consumer countries to producing countries and consumer countries require more debt. During the 2010-2014 period high oil prices were sustained by the phenomenal push of the Chinese economy, while European and Japanese economies suffered enormously and their oil consumption depressed and hasn't fully recovered since.
In the long term it is the economy that pumps the oil, and that is what you cannot understand.
Oil limits → Oil cost → Oil Price ↔ Economy → Oil demand → Oil production
The economy decides when and how Peak Oil takes place. If you knew that you wouldn't bother with all those models.
And in my opinion the economy already decided in late 2015 when the drive to increase oil production to compensate for low oil prices couldn't be sustained.
Carlos,Dennis Coyne x Ignored says: 03/15/2019 at 3:01 pmYour reasoning is close to mine. See https://www.tse-fr.eu/publications/oil-cycle-dynamics-and-future-oil-price-scenarios .
Carlos,Mario C Vachon x Ignored says: 03/15/2019 at 6:39 pmBoth supply and demand matter. I understand economics quite well thank you. You are correct that the economy is very important, it will determine oil prices to some degree especially on the demand side of the market. If one looks at the price of oil and economic growth or GDP, there is very little correlation.
The fact is the World economy grew quite nicely from 2011 to 2014 when oil prices averaged over $100/b.
There may be some point that high oil prices are a problem, apparently $100/b in 2014 US$ is below that price. Perhaps at $150/b your argument would be correct. Why would the economy need more oil when oil prices are low? The low price is a signal that there is too much oil being produced relative to the demand for oil.
I agree the economy will be a major factor in when peak oil occurs, but as most economists understand quite well, it is both supply and demand that will determine market prices for oil.
My models are based on the predictions of the geophysicists at the USGS (estimating TRR for tight oil) and the economists at the EIA (who attempt to predict future oil prices). Both predictions are used as inputs to the model along with past completion rates and well productivity and assumptions about potential future completion rates and future well productivity, bounded by the predictions of both the USGS and the EIA along with economic assumptions about well cost, royalties and taxes, transport costs, discount rate, and lease operating expenses.
Note that my results for economically recoverable resources are in line with the USGS TRR mean estimates and are somewhat lower when the economic assumptions are applied (ERR/TRR is roughly 0.85), the EIA AEO has economically recoverable tight oil resources at about 115% of the USGS mean TRR estimate. The main EIA estimate I use is their AEO reference oil price case (which may be too low with oil prices gradually rising to $110/b (2017$) by 2050.
Assumptions for Permian Basin are royalties and taxes 33% of wellhead revenue, transport cost $5/b, LOE=$2.3/b plus $15000/month, annual discount rate is 10%/year and well cost is $10 million, annual interest rate is 7.4%/year, annual inflation rate assumed to be 2.5%/year, income tax and revenue from natural gas and NGL are ignored all dollar costs in constant 2017 US$.
You do incredible work Dennis and I believe you are correct. Demand for oil is relatively inelastic which accounts for huge price swings when inventories get uncomfortably high or low. If supply doesn't keep up with our needs, price will rise to levels that will eventually create more supply and create switching into other energy sources which will reduce demand.Carlos Diaz x Ignored says: 03/15/2019 at 6:57 pmDennis Coyne x Ignored says: 03/16/2019 at 7:33 amWhy would the economy need more oil when oil prices are low? The low price is a signal that there is too much oil being produced relative to the demand for oil.
You don't seem to be aware of historical oil prices. For inflation adjusted oil prices since 1946 oil (WTI) spent:
27 years below $30
13 years at ~ $70
18 years at ~ $40
10 years at ~ $90
5 years at ~ $50
https://www.macrotrends.net/1369/crude-oil-price-history-chart
And the fastest growth in oil production took place precisely at the periods when oil was cheapest.You simply cannot be more wrong about that.
And your models are based on a very big assumption, that the geology of the reserves is determinant for Peak Oil. It is not. There is plenty of oil in the world, but the extraction of most of it is unaffordable. The economy will decide (has decided) when Oil Peak takes place and what happens afterwards. Predictions/projections aren't worth a cent as usual. You could save yourself the trouble.
Carlos,Dennis Coyne x Ignored says: 03/16/2019 at 7:34 amI use both geophysics and economics, it is not one or the other it is both of these that will determine peak oil.
Of course oil prices have increased, the cheapest oil gets produced first and oil gradually gets more expensive as the marginal barrel produced to meet demand at the margin is more costly to produce.
Real Oil Prices do not correlate well with real economic growth and on a microeconomic level the price of oil will affect profits and willingness of oil companies to invest which in turn will affect future output. Demand will be a function of both economic output and efficiency improvements in the use of oil.
Thanks Mario.Dennis Coyne x Ignored says: 03/16/2019 at 10:49 amCarlos,HHH x Ignored says: 03/15/2019 at 9:44 pmAlso keep in mind that during the 1945-1975 period economic growth rates were very high as population growth rates were very high and the World economy was expanding rapidly as population grew and the World rebuilt in the aftermath of World War 2. Oil was indeed plentiful and cheap over this period and output grew rapidly to meet expanding World demand for oil. The cheapness of the oil led to relatively inefficient use of the resource, as constraints in output became evident and more expensive offshore, Arctic oil were extracted oil prices increased and there was high volatility due to Wars in the Middle east and other political developments. Oil output (C+C) since 1982 has grown fairly steadily at about an 800 kb/d annual average each year, oil prices move up and down in response to anticipated oil stock movements and are volatile because these estimates are often incorrect (the World petroleum stock numbers are far from transparent.)
On average since the Iran/Iraq crash in output (1982-2017) World output has grown by about 1.2% per year and 800 kb/d per year on average, prices have risen or fallen when there was inadequate or excess stocks of petroleum, this pattern (prices adjusting to stock levels) is likely to continue.
There has been little change when we compare 1982 to 1999 to 1999-2017 (divide overall period of interest in half) for either percentage increase of absolute increase in output.
I would agree that severe shortages of oil supply relative to demand (likely apparent by 2030) is likely to lead to an economic crisis as oil prices rise to levels that the World economy cannot adjust to (my guess is that this level will be $165/b in 2018$). Potentially high oil prices might lead to faster adoption of alternative modes of transport that might avert a crisis, but that is too optimistic a scenario even for me.
China will be in outright deflation soon enough. Economic stimulus is starting to fail in China. They can't fill the so called bathtub up fast enough to keep pace with the water draining out the bottom. So to speak.Lightsout x Ignored says: 03/16/2019 at 6:25 amInterest rates in China will soon be exactly where they are in Europe and Japan. Maybe lower.
In order to get oil to $90-$100 the value of the dollar is going to have to sink a little bit. In order to get oil to $140-$160 the dollar has to make a new all time low. Anybody predicting prices shooting up to $200 needs the dollar index to sink to 60 or below.
The reality is oil is going to $20. Because the rest of the world outside the US is failing. Dennis makes some nice graphs and charts and under his assumptions his charts and graphs are correct. But his assumptions aren't correct.
We got $20 oil and an economic depression coming.
Peak Oil is going to be deflationary as hell. Higher prices aren't in the cards even when a shortage actually shows up. We will get less supply at a lower price. Demand destruction is actually going to happen when economies and debt bubbles implode so we actually can't be totally sure we are ever going to see an actual shortage.
We could very well be producing 20-30% less oil than we do now and still not have a shortage.
Oh and EV's are going to have to compete with $20 oil not $150 oil.
You are assuming that the oil is priced in dollars there are moves underway that raise two fingers to that.Dennis Coyne x Ignored says: 03/16/2019 at 7:41 amHHH,Dennis Coyne x Ignored says: 03/16/2019 at 9:56 amWhen do you expect the oil price to reach $20/b? We will have to see when this occurs.
It may come true when EVs and AVs have decimated demand for oil in 2050, but not before. EIA's oil price reference scenario from AEO 2019 below. That is a far more realistic prediction (though likely too low especially when peak oil arrives in 2025), oil prices from $100 to $160/b in 2018 US$ are more likely from 2023 to 2035 (for three year centered average Brent oil price).
HHH,HHH x Ignored says: 03/16/2019 at 6:50 pmMy assumptions are based on USGS mean resource estimates and EIA oil price estimates, as well as BIS estimates for the World monetary and financial system.
Your assumption that oil prices are determined by exchange rates only is not borne out by historical evidence. Exchange rates are a minor, not a major determinant of oil prices.
Dennis,Technically speaking. The most relevant trendline on price chart currently comes off the lows of 2016/02/08. It intersects with 2017/06/19. You draw the trendline on out to where price is currently. Currently price is trying to backtest that trendline.
On a weekly price chart i'd say it touches the underside of that trendline sometime in April in the low 60's somewhere between $62-$66 kinda depends on when it arrives there time wise. The later it takes to arrive there the higher price will be. I've been trading well over 20 years can't tell you how many times i've seen price backtest a trendline after it's been broken. It's a very common occurrence. And i wouldn't short oil until after it does.
But back to your question. $20 oil what kind of timetable. My best guess is 2021-2022. Might happen 2020 or 2023. And FED can always step in and weaken the dollar. Fundamentally the only way oil doesn't sink to $20 is the FED finds a way to weaken the dollar.
But understand the FED is the only major CB that currently doesn't have the need to open up monetary policy. It's really the rest of the worlds CB ultra loose monetary policy which is going to drive oil to $20.
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Mar 18, 2019 | peakoilbarrel.com
Energy News, says: 03/17/2019 at 2:49 am
Countries that have reported their January production (shown on the chart)
OPEC14 -822
Alberta -268
Mexico -87
Russian Federation -78
Brazil -60
Norway -48
Total -1,429 kb/day
Chart https://pbs.twimg.com/media/D12BlLBW0AEDR6G.pngSo far for February: Russia, OPEC14, Norway
Total: -330 kb/dayChart for December which includes the big increases from the USA
https://pbs.twimg.com/media/D12IDSNW0AE18u1.pngChina crude oil production
February: 3,813 kb/day
Average 2018: 3,788 kb/day
https://pbs.twimg.com/media/D12PhtXWsAALxTw.png
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Mar 17, 2019 | finance.yahoo.com
The Organization of Petroleum Exporting Countries will once again become a nemesis for U.S. shale if the U.S. Congress passes a bill dubbed NOPEC, or No Oil Producing and Exporting Cartels Act, Bloomberg reported this week , citing sources present at a meeting between a senior OPEC official and U.S. bankers.
The oil minister of the UAE, Suhail al-Mazrouei, reportedly told lenders at the meeting that if the bill was made into law that made OPEC members liable to U.S. anti-cartel legislation, the group, which is to all intents and purposes indeed a cartel, would break up and every member would boost production to its maximum.
This would be a repeat of what happened in 2013 and 2014, and ultimately led to another oil price crash like the one that saw Brent crude and WTI sink below US$30 a barrel. As a result, a lot of U.S. shale-focused, debt-dependent producers would go under.
Bankers who provide the debt financing that shale producers need are the natural target for opponents of the NOPEC bill. Banks got burned during the 2014 crisis and are still recovering and regaining their trust in the industry. Purse strings are being loosened as WTI climbs closer to US$60 a barrel, but lenders are certainly aware that this is to a large extent the result of OPEC action: the cartel is cutting production again and the effect on prices is becoming increasingly visible.
Related: Pakistan Aims To Become A Natural Gas Hotspot
Indeed, if OPEC starts pumping again at maximum capacity, even without Iran and Venezuela, and with continued outages in Libya, it would pressure prices significantly, especially if Russia joins in. After all, its state oil companies have been itching to start pumping more.
The NOPEC legislation has little chance of becoming a law. It is not the first attempt by U.S. legislators to make OPEC liable for its cartel behavior, and none of the others made it to a law. However, Al-Mazrouei's not too subtle threat highlights the weakest point of U.S. shale: the industry's dependence on borrowed money.
The issue was analyzed in depth by energy expert Philip Verleger in an Oilprice story earlier this month and what the problem boils down to is too much debt. Shale, as Total's chief executive put it in a 2018 interview with Bloomberg, is very capital-intensive. The returns can be appealing if you're drilling and fracking in a sweet spot in the shale patch. They can also be improved by making everything more efficient but ultimately you'd need quite a lot of cash to continue drilling and fracking, despite all the praise about the decline in production costs across shale plays.
The fact that a lot of this cash could come only from banks has been highlighted before: the shale oil and gas industry faced a crisis of investor confidence after the 2014 crash because the only way it knew how to do business was to pump ever-increasing amounts of oil and gas. Shareholder returns were not top of the agenda. This had to change after the crash and most of the smaller players -- those that survived -- have yet to fully recover. Free cash remains a luxury.
Related: The EIA Cuts U.S. Oil Output Projections
The industry is aware of this vulnerability. The American Petroleum Institute has vocally opposed NOPEC, almost as vocally as OPEC itself, and BP's Bob Dudley said this week at CERAWeek in Houston that NOPEC "could have severe unintended consequences if it unleashed litigation around the world."
"Severe unintended consequences" is not a phrase bankers like to hear. Chances are they will join in the opposition to the legislation to keep shale's wheels turning. The industry, meanwhile, might want to consider ways to reduce its reliance on borrowed money, perhaps by capping production at some point before it becomes forced to do it.
By Irina Slav for Oilprice.com
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Mar 16, 2019 | peakoilbarrel.com
likbez says: 03/16/2019 at 9:34 pm
likbez says:Some arguments in defense of Ron estimates
1. When something is increasing 0.8% a year based on data with, say, 2% or higher margin of error this is not a growth. This is a number racket.
2. We need to use proper coefficients to correctly estimate energy output of different types of oil We do not know real EROEI of shale oil, but some sources claim that it is in the 1.5-4.5 range. Let's assume that it is 3. In comparison, Saudi oil has 80-100 range. In this sense shale oil is not a part of the solution; it is a part of the problem (stream of just bonds produced in parallel is the testament of that). In other words, all shale oil is "subprime oil," and an increase of shale oil production is correctly called the oil retirement party. The same is true for the tar sands oil.
So the proper formula for total world production in "normalized by ERORI units" might be approximated by the equation:
0.99* OPEC_oil + 0.97*other_conventional_oil + 0.95*shallow-water_oil + 0.9*deep_water_oil +0.75*(shale_oil+condensate) + 0.6*tar_sand_oil + 0.2*ethanol
where coefficients (I do not claim that they are accurate; they are provided just for demonstration) reflect EROEI of particular types of oil.
If we assume that 58% of the US oil production is shale oil and condensate then the amount of "normalized" oil extracted in the USA can be approximated by the formula
total * 0.83
In other words 17% of the volume is a fiction. Simplifying it was spent on extraction of shale oil and condensate (for concentrate lower energy content might justify lower coefficient; but for simplicity we assume that it is equal to shale oil).
Among other things that means that 1970 peak of production probably was never exceeded.
3. EROEI of most types of oil continues to decline (from 35 in 1999 to 18 in 2006 according to http://www.euanmearns.com/wp-content/uploads/2016/05/eroeihalletal.png). Which means that in reality physical volume became a very deceptive metric as you need to sink more and more money/energy into producing every single barrel and that fact is not reflected in the volume. In other words, the barrel of shale oil is already 50% empty when it was lifted to the ground (aka "subprime oil"). In this sense, shale wells with their three years of the high producing period are simply money dumping grounds for money in comparison with Saudi oil wells.
4. The higher price does not solve the problem of the decline of EROEI. It just allows the allocation of a larger portion of national wealth to the oil extraction putting the rest of the economy into permanent stagnation.
5. If we assume average EROEI equal 3 (or even 5) for shale oil then rising shale oil production along with almost constant world oil production is clearly a Pyrrhic victory. Again, putting a single curve for all types of oil is the number racket, or voodoo dances around the fire.
NOTES:
1. IMHO Ron made a correct observation about Saudi behavior: the declines of production can well be masked under pretention of meeting the quota to save face. That might be true about OPEC and Russia as a whole too. Exceptions like Iraq only confirm the rule.
2. EROEI of lithium battery is around 32
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Mar 16, 2019 | peakoilbarrel.com
TechGuy x Ignored says: 03/15/2019 at 11:52 pm
Dennis Wrote:
"I think the 4 Mb/d of increased tight oil output from Dec 2019 to Dec 2025 may be enough to keep World C+C output increasing through 2025, this assumes oil prices follow the AEO 2018 reference case "I am sure there is sufficient Oil in the ground to delay Peak production to about 2040, if the consumer demand can afford $300 bbl. Shale drilling is a lot like the housing bubble that began in 2003 and when bust in 2008. It made no sense to lend people with no job, no income and no assets, money to buy a home, but Lenders did it anyway and they did it for 5 years straight. While Shale Drillers aren't Ninja home buyers they continue to fund operations using debt.
Shale growth is a function of credit available to shale drillers. As long as they can find a sucker^H^H^H^H lender to finance their growth, it will continue.
My wild-ass guess is that credit growth for shale drillers ends in 2021, because a lot of old shale debt comes due between 2020 and 2022.
My guess is that the shale drillers will have trouble rolling over the existing debt will also finding lenders to provide them more credit. In the past I presumed that interest rates would rise to the point it cut them off from adding new debt. but the ECB & the Fed continue to keep rates low. Perhaps the Shale drillers will get direct gov't funding to continue, pseudo nationalization as Watcher has proposed over many years on POB.
I don't see much traction in significantly higher oil prices. with 78% of US consumers living paycheck to paycheck, already, I don't believe they can absorb any substantial increase in energy costs.
Its also very likely demographics will start impacting energy consumption in the west as Boomers start retiring. A lot of boomers have postponed retirement, but I suspect that this will start to change in the early 2020s as age related issues make it more difficult for them to keep on working. Usually retired workers, consume considerably less energy as they no longer commute to work, and usually downsize their lifestyles.
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Mar 16, 2019 | peakoilbarrel.com
Matt Mushalik x Ignored says: 03/14/2019 at 5:06 pm
(Global) peak oil comes in phases. The 1st phase 2005-2008 caused the 2008 oil price shock and the financial crisis. Money printing was used to keep the system afloat and finance the US shale oil boom. The resulting high debt levels are now limiting economic activities. A lot of the problems we see in the world come from this chain of events.Carlos Diaz x Ignored says: 03/14/2019 at 7:26 pmI warned the Australian Prime Minister John Howard in 2004/05 but he did not want to listen.
Howard's Energy Policy Failure 2004
http://crudeoilpeak.info/howards-energy-policy-failure-2004As a result, Australia has built a lot of additional oil dependent infrastructure. Even Sydney's new metro projects don't replace car traffic:
11/3/2019
Sydney's Immigration Metros (Part 1)
http://crudeoilpeak.info/sydneys-immigration-metros-part-1As Art Berman said, shale oil is oil's retirement party.When we are down to fracturing rocks and drilling tens of thousands of horizontal wells that produce tiny streams of oil that decline by 70% in just three years we should instinctively know that we are reaching the bottom of the proverbial barrel, literally. Amazing how most people think just the opposite .
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Mar 06, 2019 | peakoilbarrel.com
dclonghorn x Ignored says: 02/28/2019 at 11:13 am
There is an interesting article in the Journal Of Petroleum Technology which summarizes an SPE article by Schlumberger.Eulenspiegel x Ignored says: 02/28/2019 at 11:30 am"Yet another SPE paper has concluded that old wells outperform new ones, but this study offers a lot more detail about development in the Permian.
The paper, authored by Schlumberger (SPE 194310), offers comparisons of five major plays in the Midland and Delaware basins, including details down to the pounds of proppant pumped per foot, that show that completions are becoming increasingly similar.
"In general, normalized production from child wells is lower than parent wells," said Wei Zheng, production stimulation engineer for Schlumberger. Older wells outperform newer ones even when adjusting for the fact that new horizontal wells extend further through the reservoir and more proppant is pumped.
"We are getting the same result as 5 years ago when we were spending less," she said during a presentation at the recent SPE Hydraulic Fracturing Technology Conference."
Figure 2 which adjusts production for lateral length and proppant is particularly interesting.
The following article there is interesting, too.It describes especially most comapanies going to a more wide well spacing – so total recovery of the basin will fall, but drilled wells will be more profitable.
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Mar 05, 2019 | www.zerohedge.com
Shale Companies In Turmoil As Newer Wells "Drink Their Milkshake"
by Tyler Durden Tue, 03/05/2019 - 17:45 18 SHARES
US shale companies' decision to drill thousands of new wells closely together - and close to already existing wells - is turning out to be a bust ; worse, this approach is hurting the performance of wells already in existence, posing an even greater threat to the already struggling industry. In order to keep the United States as an energy supplying powerhouse, shale companies have pitched bunching wells in close proximity, hoping they would produce as much as older ones, allowing companies to extract more oil overall while maintaining good results from each well.
These types of predictions helped fuel investor interest in shale companies, who raised nearly $57 billion from equity and debt financing in 2016 – up from $34 billion five years earlier, when oil was over $110 per barrel. In 2016, oil prices dipped below $30 a barrel at one point.
And now - surprise – the actual results from these wells are finally coming in and they are quite disappointing.
Newer wells that have been set up near older wells were found to pump less oil and gas, and engineers warn that these new wells could produce as much as 50% less in some circumstances. This is not what investors - who contributed to the billions in capital used by these companies back in 2016 - want to hear.
Making matters worse, newer wells often interfere with the output of older wells because creating too many holes in dense rock formations can damage nearby wells and make it harder for oil to seep out. The "child" wells could also cause permanent damage to older "parent" wells. This is known in the industry as the "parent-child" well problem. Billionaire Harold Hamm, who founded shale driller Continental Resources, said last year: " Shale producers across the country are finding you can get a lot of interference, one well to the other. Laying out a whole lot of wells can get you in trouble."
Some of the biggest names in shale, including Devon Energy, EOG Resources and Concho Resources, have already disclosed that they are suffering from this problem. As a result, they and many others could be forced to take massive write-downs if they have to downsize their already optimistic estimates from drill sites.
Companies continue to try and find the perfect balance between using single wells that are operating at peak productivity and multiple wells that can provide better returns.
Laredo Petroleum is a great example. Two years ago, it was valued at more than $3 billion and was a strong advocate for packing wells into the Permian Basin. Its CEO Randy Foutch said a year ago that the company could drill 32 wells per drilling unit, with each producing an average of 1.3 million barrels of oil and gas. In November, the company announced that wells it had fracked in 2018 were producing 11% less than projected, in part due to "parent-child" issues.
Laredo spokesman Ron Hagood told the WSJ: "We tightened spacing during 2017 and 2018 to increase location inventory and resource recovery in our highest-return formations, and we achieved this goal."
The company's market value has fallen about 75% to $800 million since the end of 2016. Goal achieved?
Incidentally, we first reported that shale companies may be facing "catastrophic failure ahead" back in October of 2018. Days before that report, we said that shale companies had a "glaring problem". We concluded that the glaring problem with 2018's poor financial results was that 2018 was supposed to be the year that the shale industry finally turned a corner.
Earlier in 2018, the International Energy Agency had painted a rosy portrait of U.S. shale, arguing in a report that "higher prices and operational improvements are putting the US shale sector on track to achieve positive free cash flow in 2018 for the first time ever."
Now, it all appearst to have been a "pipe" - or rather "milkshake" - dream.
https://www.youtube.com/embed/a5d9BrLN5K4
Tags
just the tip , 54 minutes ago link
Big Fat Bastard , 1 hour ago linkbutt.
butt.
butt.
tsvetana at oilprice.com said:
In its January Short-Term Energy Outlook (STEO), the EIA said last week that continuously rising U.S. shale production would make the United States a net exporter of crude oil and petroleum products in the fourth quarter of 2020.
Baron von Bud , 1 hour ago linkCrude Prices Crater 28% Since Q3 2018 As China Economy Collapses
https://www.marketwatch.com/investing/future/crude%20oil%20-%20electronic
hayman , 1 hour ago linkReal oil wells could last decades. Shale - 18 months. Bottom of the barrel and a bad sign of things to come.
-- ALIEN -- , 1 hour ago linkAnd Trumpy wants Germany to stop building a pipeline from Russia. He's gonna supply em instead. He's throwing in a prayer book with every LNG cargo.
Stinkbug 1 , 1 hour ago linkWe also need to pray nobody ever shoots an RPG at one of those Liquid Natural Gas tankers or it will be like a billion Teslas exploding all at once.
Luau , 1 hour ago linkThis whole shale oil boom started back when Baby Bush was president, and Hugo Chavez announced to the world (at the UN) that W "smelled of sulfur". To add insult to injury, Hugo sent aid, in the form of fuel oil and a hospital ship, to help the victims of Hurricane Katrina, while W was busy eating cake and clearing brush with Jeff Gannon.
From that moment on, W had it in for Hugo. Venezuela was doing very well at the time. Besides sanctions, Bush figured that the best way to attack Hugo and Venezuela was to crash the price of crude. So suddenly there were financial incentives and lax regulations in the US regarding Fracking, and the Shale Oil Boom in America was born! Bush didn't care that it was costing Americans - both financially and by ruining the quality of the ground water - the lifeblood of agriculture. This oil borne of vengence went to market at way below cost of production, but it succeeded in driving the price of crude to the point of financial pain for Venezuela.
After all that, Hugo survived several assassination attempts, only to die suddenly and mysteriously from - depending on the source - either a heart attack or stroke.
Shale oil had a negative EROEI from the start, it just took this long for that to be realized.
chubbar , 1 hour ago linkAh, more doom **** for anti-shalers. Terrific stuff.
jetfuel_hahaha , 1 hour ago linkI'll bet they are understating the loan problem. I think this industry has real problems along with the banks that financed them. Someone, somewhere has some data on this issue but I've only seen it alluded too. With the cost of oil down and these wells starting to underproduce, I'll bet there is some real risk to solvency for some banks we are not hearing about.
WTFUD , 1 hour ago linkTime to circle uranus looking for oil?
Broccoli , 2 hours ago linkThe only real growth in the US -
1. Opiates/Big Pharma
2. Redundancies
3. John Bolton's harelip cover
Winston Churchill , 1 hour ago linkThese articles against shale are so biased. I work in the Delaware Basin and have intimate knowledge of the financials. The shale BS spewed on zerohedge only looks at the negative side of things. The article above is correct about the problem of well spacing, but I could write 5 positive articles about upward revisions of expected well productivity those same companies have had as they refined their frac techniques and got better at drilling laterals. Zerohedge only reports the negative revisions, not the numerous positive revisions. These companies are now going on a decade of growth and their financials are actually improving.
The shale business is fundamentally sound if you have the right acreage and don't overpay to get acreage. The naysayers are correct in that production decline in unconventionals requires ever increasing investment so as long as the company is trying to grow they will have negative cash flow and expanding debt loads to fight the decline curves of unconventionals. (The rig count you need to just to counteract natural decline keeps growing as you grow.) But it also doesn't mean jack **** for the profitability of each well. Unless you are a poorly run shale company like Encana, BHP, or BP, you would instantly be massively cash flow positive and easily pay off all your debt if you stopped drilling. In Delaware Basin, companies like EOG are hitting 40% ROCE (Return on Capital Employed) and the basin average is probably 20%. Those are good numbers.
Broccoli , 1 hour ago linkReally ?
Please explain how profitable companies keep going deeper into debt to maintain production then ?
I'm all ears to have it explained by someone like you that understands the financials.
Enron had similar problems.Its called mismatching to hide losses in any other biz, and without another
motive would never be allowed to continue.
2handband , 1 hour ago linkI explain it in my post. Don't confuse profits with cash flow and debt. The individual projects are profitable and so are the companies, but to keep growing and fight the decline they capital budget has to grow in unconventionals. The shareholders in the company push for more growth, to deliver that growth they have to first make up the natural decline plus add to the baseline. As your baseline grows the first part of the equation, fighting the natural decline, grows along with you. To show cash flow positive results and reduce debt, all the companies have to do is keep rig and frac crew counts constant, and about a year later they will all show positive cash flow and reductions in debt. However, by in large most companies are choosing to increase rig and frac crew counts year over year and thus the cash flow remains negative and debt grows because the companies themselves are growing. What the naysayers are doing is just looking at the liabilities on the balance sheet, while ignoring the asset growth.
The naysayers are not wrong about the balance sheets, they are just not talking about the full picture. Eventually these predictions will be right as viable acreage runs out and companies start throwing good money at bad projects just to show production growth, but that isn't happening yet except for at the weakest players. And that truth is the same even for conventional fields. Unconventionals just shorten the lifecycle, but it doesn't change the fact that the oil business has always been one where you produce yourselves out of business, and to remain viability you constantly have to be exploring for new opportunies. 150 years and still going and people still write articles without understanding.
Zeej , 1 hour ago linkShow me a single shale play with an EROEI above 5:1 and we'll talk.
EDIT: full disclosure: I'm invested in shale, and have made good money from it. But long-term I still think it's a loser. Net energy gain is too low to be viable.
gladitsover , 1 hour ago linkThese articles have been predicting the demise of US shale since 2010. As in any industry especially one as technologically driven as US shale you have good and bad results across the space, yet the space as a whole will continue to grow and good operators will thrive.
2handband , 2 hours ago linkShale is end game stuff. At the end of the day the average jobless consumer can't afford to run a vehicle on 100$+ per barrel shale. And producers can't really stay in business at current prices. The funding is mostly zero cost debt provided to keep the dream alive for a few more years.
gladitsover , 2 hours ago linkI've been in shale for quite awhile, and have made good money. It's a good investment if you're careful, but it's also a low EROEI product that the numbers have never really made sense on. The companies producing it are leveraged to the gills, and if interest rates were to pop and make it more expensive to roll over their debt it'd explode like a ******* bomb. On my more tinfoilly days I wonder if the whole purpose of the '08 financial crisis (which was deliberately engineered; that much I am sure of) was to give them excuse to drop the interest rates enough to make shale viable. Get a hard look at the financials of any company producing shale... you'll see some serious weirdness in their cash flow. This was the case even when crude prices were parked around $100.
Hard cold fact: net energy gain on this stuff is positive, but not by very goddamn much. Left strictly to market forces, it would not be economically viable at all. Ultimately I think what we're going to see is some kind of a nationalization of oil supplies as a security measure; there's plenty of stuff out there that is net energy positive but still not profitable to extract. But so long as it takes marginally less energy to get it out than you produce, it'll be propped up. Once net energy goes negative (and it will; we always take the low-hanging fruit first) then it's game over.
gladitsover , 2 hours ago linkMankind build industrial society on 30+ to 1 oil. Shale is scraping the bottom of the barrel.. tar sands the same. They take fresh water and natural gas to cook the oil out of the sand for christ sake.. that's late end game stuff right there.
CosineCosineCosine , 1 hour ago linkThe late Matthew Simmons called the advanced extraction thechniques like water injection etc used on legacy oil fields
"super-straws" sucking the last oil faster and in no way expanding the total recoverable oil from the field. We can expect much steeper decline curves because of it when reservoir pressures are finally depleted.
Cold cold fact: net energy gain on this stuff is positive, but not by very goddamn much. Left strictly to market forces, it would not be economically viable at all. Ultimately I think what we're going to see is some kind of a nationalization of oil supplies as a security measure; there's plenty of stuff out there that is net energy positive but still not profitable to extract. But so long as it takes marginally less energy to get it out than you produce, it'll be propped up . Once net energy goes negative (and it will; we always take the low-hanging fruit first) then it's game over.
Great balanced comment.
I see shale as essentially thermodynamic autocannibalism from the point of view that at an EROEI of 1.5-3 to 1, it can power it's extraction and refinement and (sometimes) transport, but not anything else. It cannot provide the energy needed to run a mid-19th century economy let alone a parasitic 21st century one. There is no fat to run our civilization and this is largely a desperate delay mechanism. The West has used up most it's net positive EROEI to the pump oil and gas and now it needs to plunder other economies if it isn't to go down in flames. It will implode after 2030 anyway as the global EROEI inflects, but these are in denial moves to delay the inevitable .
Again - great to see a non binary comment here on ZH on this polarising topic.
Edit
Also your comments about the probable nationalisation of the industry I believe is spot on - not only will it occur organically as these companies declare huge bankruptcies and the policy makers opt for nationalization (i.e. bail in by Joe taxpayer) rather than bail out. Note also how such a nationalization will cohere to the increasingly communist mentality of the political landscape - Big Gov redistribution & equity outcomes inclinations will all feed into the state owning and controlling te means of production. AOC is a ******, but she is simply an expression of broader psychological and financial vectors. It's coming and you can't vote your way out of it.
And yes it WILL be declared a national security issue and NO MATTER WHAT THE PRICE TO THE REST OF THE ECONOMY while there is any net EROEI (net of extraction, refinement and distribution) it wil continue.
there's plenty of stuff out there that is net energy positive but still not profitable to extract.
Only caveat I would add is that it will only be extracted when "not profitable" only while global fiat parasitism can be used to skim wealth from outside of the US . Once the US $ ceases to be able to do this then profit = net energy again, and the negative-sum game will no longer be able to be subsidised nor concealed. The remaining billions of theoretical barrels if oil at that stage will remain in the ground, of no utility to maintaining negative entropy civilization.
Before it ceases you will essentially see only the MIC and 'Strategic' government use of US oil and gas ny the early 2030s and little to no use by the domestic economy at large. Once the last slither of net calorific benefit is gone, thing go entropic.
However if they manage to steal Venezuela or Iran, this would change.
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shallow sand says: 11/17/2016 at 9:00 amNov 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.
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,shallow sand says: 11/17/2016 at 11:19 amI am doing the analysis for the Bakken. A lot of the leases are already held and I don't know that those were the prices paid. Give me a number for total capital cost that makes sense, are you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the different assumptions you would like to change would be good so I don't redo it 5 times.
Mostly I would like to clear up "the number".
I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes, real discount rate (adjusted for inflation), well cost.
I think you a re talking about well cost as "the number". I include down hole costs as part of OPEX (think of it as OPEX plus maintenance maybe).
Dennis. The very high acreage numbers are for recent sales in the Permian Basin. In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost.Dennis Coyne says: 11/17/2016 at 1:22 pmThis 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.
Hi Shallow sands,AlexS says: 11/17/2016 at 9:05 amI am neither an oil man nor an accountant, so regardless of what we call it I am assuming natural gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to operate the well (LOE, OPEX, financial costs, etc), we could add another million to the cost of the well for surface and downhole equipment and land costs.
Does an average operating cost over the life of a well of about $17/b ($14/b plus natural gas sales of $3/b of oil produced)seem reasonable? That would be about $5.4 million spent on LOE etc. over the life of the well (assuming 320 kbo produced). Also does the 10% nominal rate of return sound high enough, what number would you use as a cutoff?
You use a different method than a DCF and want the well to pay out in 60 months. This would correspond to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3% annual inflation rate.)
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis."Mike says: 11/17/2016 at 1:24 pmExactly. USGS' estimate as of October 2015 is very conservative:
"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1 million barrels of natural gas liquids, according to the first USGS assessment of continuous (unconventional), technically recoverable resources in the Monterey Formation."
"The volume estimated in the new study is small, compared to previous USGS estimates of conventionally trapped recoverable oil in the Monterey Formation in the San Joaquin Basin. Those earlier estimates were for oil that could come either from producing more Monterey oil from existing fields, or from discovering new conventional resources in the Monterey Formation."
Previous USGS estimates were for conventional oil:
"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin, estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in 2012, USGS assessed the potential volume of oil that could be added to reserves in the San Joaquin Basin from increasing recovery in existing fields. The results of that study suggested that a mean of about 3 billion barrels of oil might eventually be added to reserves from Monterey reservoirs in conventional traps, mostly from a type of rock in the Monterey called diatomite, which has recently been producing over 20 million barrels of oil per year."
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp. Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA and awaiting re-drills; that should tell you something. With acreage, infrastructure and water costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste of time, sorry.Dennis Coyne says: 11/17/2016 at 8:54 am
Hi JG,Boomer II says: 11/17/2016 at 3:25 pmWhat 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?
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.AlexS says: 11/16/2016 at 3:53 pmSeems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling.
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well spacing, pick total acreage, pick a factor for dry holes – multiply a by c by d and divide by b."AlexS says: 11/16/2016 at 4:09 pmThe EIA and others use the same methodology
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.Dennis Coyne says: 11/16/2016 at 5:17 pmI do not know if the estimated potential production area is too big, or assumed well spacing is too tight.
The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc.
Significant part of resources may never be developed, even if they are technically recoverable.
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves times 1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3 Gb of 2P reserves that have been added to Permian reserves since 2011, if we assume most of these are from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that total proved plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved plus 3.5 GB probable with the assumption that probable=proved/2). I have assumed about 30% of total Permian 2P reserves is in the Wolfcamp shale. That is a WAG.AlexS says: 11/16/2016 at 7:01 pmNote the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a conservative guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go to $85/b and remain at that level the F95 estimate may become ERR, at $100/b maybe the median is potentially ERR. It will depend how long prices can remain at $100/b before an economic crash, prices are Brent Crude price in 2016$ with various crude spreads assumed to be about where they are now.
Dennis,AlexS says: 11/16/2016 at 7:16 pm
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.
US proved reserves of LTODennis Coyne says: 11/16/2016 at 9:11 pm
Hi Alex S,AlexS says: 11/16/2016 at 9:26 pmI 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.
Dennis,Dennis Coyne says: 11/16/2016 at 10:09 pmThe 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).
Hi Alex S,AlexS says: 11/17/2016 at 4:32 amhttp://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.
Dennis,Dennis Coyne says: 11/17/2016 at 8:21 amWolfcamp is a newer play than Bone Spring and Spraberry. That's why its share in the Permian LTO production is less than in TRR.
Hi AlexS,shallow sand says: 11/16/2016 at 5:18 pmThat 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.
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,AlexS says: 11/16/2016 at 7:08 pmIf 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.
shallow sand,Boomer II says: 11/16/2016 at 3:39 pmYes, you are correct. And there are multiple potential production scenarios, depending on the oil prices.
From the USGS press release.Watcher says: 11/16/2016 at 4:11 pmUSGS 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."
This is an important way to assess.Fred Magyar says: 11/17/2016 at 11:18 amIf it requires slave labor at gunpoint to get the oil out, then that's what will happen because you MUST have oil, and a day will soon come when that sort of thing is reqd.
Nice apocalyptic vision of the future you've got there!George Kaplan says: 11/16/2016 at 3:16 pmWhatever 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!
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.Jeff says: 11/16/2016 at 3:20 pmNote I went through a lot of 20-F and 10-K reports watching the rain fall this morning and copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general trends are shown.
Note the figures are totals for all nine companies I looked at.
IEA WEO is out: http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html presentation slides, fact sheet and summary are available online (report can be purchased). IEA seems to be _very_ concerned about underinvestment in upstream oil production. Several pages of the report is devoted to this, the title of that section is "mind the gap". More or less all of the content has been discussed on this website, including the issue with high levels of debt and that this can affect suppliers' capacity to rebound, and how much demand can be reduced as a result of a stringent carbon cap.George Kaplan says: 11/17/2016 at 3:42 amFrom the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil sands) approved for development in 2015 sank to the lowest level since the 1950s, with no sign of a rebound in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely that demand (as projected in our main scenario) and supply can be matched in the early 2020s without the start of a new boom/bust cycle for the industry"Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"
I wonder who that paragraph is aimed at. As I indicated above the companies that would be investing in long term conventional projects don't have a very large inventory of undeveloped reserves (17 Gb as of end of 2015, some of this has gone already this year and more is in development and will come on stream in 2017 and 2018 (and a small amount in later years for approved projects). I'd guess there might only be less than 10 Gb (and this the most expensive to develop) that is currently under appraisal among the major western IOCs and larger independents; allowing for their partnerships with NOCs in a lot of the available projects that could represent 20 to 30 Gb total. That really isn't very much new supply available, and a large proportion is in complex deep water projects that wouldn't be ramped up fully until 6 to 7 years after FID (i.e. already too late for 2020). Really the main players need to find new fields with easy developments, but they obviously aren't, probably never will, and actually aren't looking very hard at the moment.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".FreddyW says: 11/16/2016 at 3:43 pmIt'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.
Hi,FreddyW says: 11/16/2016 at 3:50 pmHere 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?
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?FreddyW says: 11/17/2016 at 2:10 pmThe motivation would be to get a look at the alleged spectacular technology advances in the past, oh, 2 yrs.
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.Watcher says: 11/17/2016 at 8:12 pmAnd 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.
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.Mike says: 11/17/2016 at 8:59 pmAnd it would be far too much coincidence for techno breakthrus to just happen to increase flow the exact amount lost from exhausting sweet spots.
This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet.
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.Watcher says: 11/18/2016 at 12:03 amIts very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. Nobody is breaking new ground or making big strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank areas will be even less economical (if that is possible) and will result in significantly less UR per well. That is what is ridiculous about modeling the future based on X wells per month and trying to determine how much unconventional shale oil can be produced in the US thru 2035. The term, "past performance is not indicative of future results?" We invented that phrase 120 years ago in the oil business.
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra stages post 2008/9/10. How could there not be going from 15 stages to 30+?Watcher says: 11/18/2016 at 12:14 amI 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.
You know, that is absolutely insane.FreddyW says: 11/18/2016 at 2:55 pmFreddy, is there something going on in the data? How can 30 stage long laterals flow the same at production month 24 as the earlier dated wells at their production month 24 –whose lengths of well were MUCH shorter?
I can only speculate why the curves look like they do. It could be that the newer wells would have produced more than the older wells, but closer well spacing is causing the UR to go down.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,FreddyW says: 11/16/2016 at 6:02 pmWhat 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)?
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,FreddyW says: 11/17/2016 at 3:37 pmThanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one way to do it would be to look at the natural log of monthly output vs month for each year and see where the curve starts to become straight indicating exponential decline. The decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely different, I am speculating about the possible cause.
2007 had much lower initial production and the long late plateau gives it a low decline rate also. But yes, initial decline rates look similar to the other curves. If you look at the individual 2007 wells then you can see that some of them have similar increases to production as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that those increases are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau. If that is the case, then 2007 may not be different from the others at and we will see increased decline rates in the future.Dennis Coyne says: 11/17/2016 at 8:42 amRegarding 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.
Hi FreddyW,Dennis Coyne says: 11/17/2016 at 12:40 pmDo 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?
Hi FreddyW,FreddyW says: 11/17/2016 at 2:19 pmOk Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed in Sept 2016.
I have 75 in my data, so about the same. They have increased the number of new wells quite alot the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it increased withouth the rig count going up. But I see that the rig count has gone up now too.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."Dennis Coyne says: 11/16/2016 at 5:28 pm
A few words of wisdom as to the main reasons why it would level off? Price rise?
Hi Pete,Guy Minton says: 11/16/2016 at 8:41 pmEven though you asked Ron. He might think that the decline in the number of new wells per month may have stabilized at around 71 new wells per month. If that rate of new completions per month stays the same there will still be decline but the rate of decline will be slower. Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).
I am not so convinced that either Texas or the Bakken is finished declining at the current level of completions. There was consistent completions of over 1000 wells in Texas until about October of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than they are completing.Dennis Coyne says: 11/16/2016 at 10:03 pm
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.
Hi Guy,Guy Minton says: 11/17/2016 at 7:14 amThe wells being shut in are not nearly as important as the number of wells completed because the output volume is so different. So the average well in the Eagle Ford in its second month of production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So about 37 average wells need to be shut in to offset one average new well completion.
Point is that total well counts are not so important, it is well completions that drive output higher.
Output is falling because fewer wells are being completed. When oil prices rise and profits increase, completions per month will increase and slow the decline rate and eventually raise output if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec 2017 about 79 new wells per month is enough to cause a slight increase in output. My model slightly underestimates Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30 kb/d lower than actual output (3% too low), my well profile may be slightly too low, but I expect eventually new well EUR will start to decrease and my model will start to match actual output better by mid 2017 as sweet spots run out of room for new wells.
Guess I will remember that for the future. The number of producing wells is not important. Kinda like I got pooh poohed when I said the production would drop to over 1 million barrels back in early 2015.Dennis Coyne says: 11/17/2016 at 10:39 am
Hi Guy,Guy Minton says: 11/18/2016 at 4:50 amDo you agree that the shut in wells tend to be low output wells? So if I shut down 37 of those but complete one well the net change in output is zero.
Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the net change in output would be zero, but there would be 19,000 fewer producing wells, if we assume the average output of the 1000 new wells completed was 200 b/d for the year and the stripper wells produced 10 b/d on average.
How much do you expect output to fall in the US by Dec 2017?
Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by about 1 million barrels per day from April 2015 to July 2016, can you point me to your comment where you predicted this?
Tell us what it will be in August 2017.
I expected the fall in supply would lead to higher prices, I did not expect World output to be as resilient as it has been and I also did not realize how oversupplied the market was in April 2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan to April, so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US output has decreased by 635 kb/d.
If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would also have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400 kb/d. If we consider 12 month average output of World C+C, the decline has been 340 kb/d from the 12 month average peak in August 2015 (centered 12 month average).
The dropping numbers are not as much from the wells that produce less than 10 barrels a day, but from those producing greater than 10, but less than 100. The ones producing greater than 100 are remaining at a consistent level over 9000 to 9500. The prediction on one million was as to the US shale only. It is your site, you can search it better than I can,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.AlexS says: 11/16/2016 at 8:51 pm
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.
Statistics for North Dakota and the Bakken oil production are perfect, but not for well completions.Dennis Coyne says: 11/16/2016 at 9:36 pmFrom 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
Hi Alex S,shallow sand says: 11/17/2016 at 8:36 amI trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno Peters data has 66 completions in August 2016, he has not put up his post for the Sept data yet so I am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno tends to be spot on for the Bakken data, for Texas he relies on RRC data which is not very good.
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.shallow sand says: 11/17/2016 at 8:58 amIt 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.
Also, over 3000 Hz wells in ND produced less than 1000 BO in 9/16.Dennis Coyne says: 11/17/2016 at 10:57 amThis is just for wells with first production 1/1/07 or later.
Hi Shallow sand,shallow sand says: 11/18/2016 at 8:20 amI agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk costs in wells drilled but not completed and running the numbers based on whether they can pay back the completion costs. Everyone may be hoping the other guys fail and are just trying to pay the bills as best they can, not sure if just stopping altogether is the best strategy.
There is the old adage that when your in a hole, more digging doesn't help much.
So my model just assumes continued completions at the August rate for about 12 months with gradually rising prices as the market starts to balance, then a gradual increase in completions as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90 completions per month 18 months later). At that point oil prices have risen to $97/b and LTO companies are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at that level for 40 years (not likely, but the model is simplistic).
I could easily do a model with no wells completed, but I doubt that will be correct. Suggestions?
Dennis. As we have discussed before, tough to model when there is no way to be accurate regarding the oil price.Dennis Coyne says: 11/18/2016 at 10:03 amI 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.
Hi Shallow sand,George Kaplan says: 11/17/2016 at 3:31 amAt 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.
Probably to do with how confidential wells are included.AlexS says: 11/17/2016 at 4:42 am
RBN explains EIA methodology:Sydney Mike says: 11/17/2016 at 2:19 am"EIA does this by using a relatively new dataset-FracFocus.org's national fracking chemical registry-to identify the completion phase, marked by the first fracking. If a well shows up on the registry, it's considered completed "
There is an unlikely peak oil related editorial writer hiding in the most unlikely place: a weekly English business paper called Capital Ethiopia. The latest editorial is again putting an excellent perspective on world events. http://capitalethiopia.com/2016/11/15/system-failure/#.WC1ZCvl9600Watcher says: 11/17/2016 at 11:34 amFor 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.
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 beOldfarmermac says: 11/17/2016 at 6:03 am
Hi Pete,Dennis Coyne says: 11/17/2016 at 8:32 amSometimes 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.
Hi Pete,Enno Peters says: 11/17/2016 at 11:48 amThe Red Queen effect is that more and more wells need to be completed to increase output. As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output it might require 120 wells to be completed to maintain output (if new well EUR did not eventually decrease), but at 850 kb/d it might require about 78 new wells per month to maintain output.
I'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?Enno says: 11/18/2016 at 10:56 amhttp://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.)?
George,Watcher says: 11/18/2016 at 2:09 pmYes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old wells for example, and already include those that were spud last month (even though maybe casing has not been set). I don't do a lot of filtering, so the actual # wells that really can be completed is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know Bloombergs method exactly, so I can't comment on that.
Concerning Freddy's chart of production profile of wells drilled in various years.AlexS says: 11/18/2016 at 4:36 pmThey all line up by about month 18 of production. This should not be possible. The later wells have many more stages of frack. They are longer, draining more volume of rock. But the chart says what it says. At month about 18 the 2014 wells are flowing the same rate as 2008 wells. We know stage count has risen over those 6 yrs. 2014 wells should flow a higher rate. The shape of the curve can be the same, but it should be offset higher.
Explanation?
How about above ground issues . . . older wells get pipelines and can flow more oil . . . nah, that's absurd.
There needs to be a physical explanation for this.
These new wells have higher IPs, but also higher decline rates.Watcher says: 11/18/2016 at 6:02 pm
Closer spacing (see Freddy's comment above) and depletion of the sweet spots may also impact production curves and EURs.
That doesn't make sense. They are longer. By a factor of 2ish. How can a 6000 foot lateral flow exactly the same amount 2 yrs into production as a 3000 foot lateral flows 2 yrs into production?Dennis Coyne says: 11/18/2016 at 8:15 pmLook 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..
Hi Watcher,Watcher says: 11/18/2016 at 8:31 pmI 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.
From http://www.dtcenergygroup.com/bakken-5-year-drilling-completion-trends/FreddyW says: 11/19/2016 at 7:22 amSTATISTICS
The combination of longer lateral lengths and advancements in completion technology has allowed operators to increase the number of frac stages during completions and space them closer together. The result has been a higher completion cost per well but with increased production and more emphasis on profitability.
In the past five years, DTC Energy Group completion supervisors in the Bakken have helped oversee a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even 40-stage fracs have been achieved.
One of the main reasons for this is the longer lateral lengths – operators now have twice as much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are also being spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet in 2008, as experienced by DTC supervisors.
By placing more fracture stages closer together, over a longer lateral length, operators have successfully been able to improve initial production (IP) rates, as well as increase EURs over the life of the well.
blah blah, but they make clear the years have increased length. Freddy was talking about well spacing, this text is about stage spacing, but that is achieved because of lateral length.
Freddy can you revisit your graph code? It's just bizarre that different length wells have the same flow rate 2 yrs out, and later.
Take a look at Enno´s graphs at https://shaleprofile.com/ . They look the same as my graphs and we have collected and processed the data independently from each other.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?George Kaplan says: 11/19/2016 at 4:01 amIf 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.
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.clueless says: 11/18/2016 at 2:30 pmA 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.
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.Heinrich Leopold says: 11/19/2016 at 6:09 amSolid growth
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.
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Mar 02, 2019 | www.zerohedge.com
-- ALIEN -- , 15 hours ago link
KimAsa , 22 hours ago linkPeak Oil Explained
Peak oil is the simplest label for the problem of energy resource depletion, or more specifically, the peak in global oil production.
Oil is a finite, non-renewable resource, one that has powered phenomenal economic and population growth over the last century and a half.
The rate of oil 'production', meaning extraction and refining (currently about 85 million barrels/day), has grown almost every year of the last century.
Once we have used up about half of the original reserves, oil production becomes ever more likely stop growing and begin a terminal decline, hence 'peak'.
The peak in oil production does not signify 'running out of oil', but it does mean the end of cheap oil, as we switch from a buyers' to a sellers' market.
For economies leveraged on ever increasing quantities of cheap oil, the consequences may be dire.
Without significant successful cultural reform, severe economic and social consequences seem inevitable.
Keep reading at...
There's no doubt that economies suffer under high energy prices. Recently POTUS acknowledged this when he said oil is too damn high.
Oil producers (frackers) have to be profitable and they just aren't. It seems to unclear what the break even point is for fracking operations in the US, but let's say $50 per barrel goes to production costs. That doesn't leave much room. If oil is selling for less than that on the open market, the frackers are forced to finance their operations. This can't go on. Clearly the cheap oil era has peaked.
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Feb 26, 2019 | peakoilbarrel.com
shallow sand x Ignored says: 02/25/2019 at 5:45 pm
CLR. Net operating loss carryforwards for years. For years to come the company will pay zero Federal, North Dakota and Oklahoma income tax.IMO they haven't grown enough to justify this.
See the most recent conference call for details.
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Feb 26, 2019 | peakoilbarrel.com
Opritov Alexander x Ignored says: 02/26/2019 at 6:51 am
Interesting, New, Informativeyves x Ignored says: 02/26/2019 at 7:44 am
article
Alexey Evgenievich Anpilogov
(Алексей Евгеньевич Анпилогов):
http://zavtra.ru/blogs/novie_tyomnie_veka?fbclid=IwAR2s559y2EhRioWaBUv4X-YW8AzbQFdK1bzvAE1pFzxUHNdFGmpXnKzkm3A
Start:
New "Dark Ages"?
human energy futureAlexey Anpilogov
In the third decade of the XXI century, which is about to come, one of the main problems facing humanity, again, as in the 60s, will be its energy supply, as well as the search for the main "energy carrier of the future."
The three whales that the world's energy industry today holds: oil, natural gas and coal are, by their nature, non-renewable sources of energy. True, with regard to oil and gas, this thesis is actively debated at the academic level, but for practical purposes it is indisputable: modern civilization consumes so much hydrocarbons that their natural substitution, if it exists, is not able to compensate for this exemption. The energy sources mentioned above in 2017 accounted for about 81% of world primary energy production, and they still define the image of our modern industrial world, while all renewable energy sources provide only about 14% of primary energy production, and about 5% The balance comes from nuclear energy (International Energy Agency, 2017).
At the same time, the situation with renewable sources is not at all as rosy as it may seem at first glance: out of 14% of renewable sources, 10% is the energy from burning wood and biomass, and 2.5% is hydropower. At the same time, the "fashionable" in the last decade, and having received at the same time gigantic, almost trillion-dollar investments in solar and wind energy projects, are not as high as 2% in the overall balance of the production of primary energy. At the same time, it is not even about the absolute figures for the introduction of new capacities of green energy, which may seem impressive, but about the exponential dynamics of the relationship between "oil-coal-gas" and "green" in the long term. After all, a decade ago, in 2008, the world balance of power generation looked like this: 78% were oil, natural gas and coal, 5% were atomic energy, 3% were hydropower, about 13.5% were wood and biomass, and 0, 5% produced wind and solar energy. Surprisingly, over the past ten years, the transition from "wood and straw" to the energy of oil, natural gas and coal, which occurred naturally, turned out to be two and a half times more significant for the global energy balance than the development of "green" energy technologies.
The phenomenon of such meager growth of "green" energy is interesting in itself: for the first time the capitalist mode of production, in which investments in fixed assets imply quick returns in the form of profits, gives an obvious, albeit programmed failure. Its essence becomes clear if we take into account in the picture the "quiet" transition of the world from "firewood and straw" to oil, gas and coal, which lasted throughout the decade of 2008–2018. This process, which no one financed in a targeted manner or advertised in the world media or Western scientific publications, went forward thanks to economic expediency. At the same time, the planting of green energy was accompanied not only by a powerful public relations campaign and trillions of financing, but also forced almost all countries to accept special, non-economic overpriced tariffs for the purchase of green energy in order to somehow force capital to finance unprofitable production. energy with wind turbines and solar panels.
World energy: a general viewSeveral reputable organizations are engaged in the problem of the global energy balance. These include the United States Department of Energy (DOE), the International Energy Agency (IEA), located in Paris, and the well-known oil company BP (ex-British Petroleum). Each of these organizations publishes annual reports on the situation in the global energy industry and the prospects for its development. These reports are compiled on the basis of an analysis of the mass of primary information, often of an incomplete and contradictory nature. Nevertheless, due to a certain averaging of all the initial data, the annual reports of these organizations quite fully and clearly reflect the overall world dynamics. In this article, in order to bring the data to one standard, we will rely on the annual reports of BP, unless otherwise explicitly stated in the text.
In accordance with the latest available BP report, global energy consumption reached 13,511 million tons of oil equivalent in 2017 (TNE, eng. "Tonne of oil equivalent", TOE). At the same time, over the decade between 2007 and 2017, world primary energy consumption grew by an average of 1.5%. That is, the dynamics of energy consumption correlate well with the observed growth rates of the global economy over the same period – an average of 3.2% per year (World Bank and IMF, 2018).
The fluctuations of this second parameter, associated with economic crises and recessions observed in the period under review, make it possible to evaluate the contribution of the notorious "energy efficiency" to the global growth in demand
"this thesis is actively debated at the academic level".Ron Patterson x Ignored says: 02/26/2019 at 8:17 amWhat does that hint to? Abiotic oil?
No, there does not even remotely a hint of abiotic oil. Read the last two paragraphs again. That is what it hints to. An average growth of 1.5% in energy consumption and a growth of 3.2% in the global economy has been enabled by a continual growth in energy efficiency. This cannot possibly continue, especially the 3.2% growth in global economy. When the global economy does not grow it receeds. This is called a recession.
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Feb 26, 2019 | peakoilbarrel.com
So it's up to Canada, Russia and the USA to keep Non-OPEC from tanking. Canada is nearing maximum production due to pipeline constraints and even the optimistic oil experts are saying Russia is near her peak, so it is up to the USA to keep Non-OPEC peak oil at bay. And that means it's all up to the shale oil patch to keep increasing production.
However .
Olson, Bradley; Elliott, Rebecca.Wall Street Journal (Online); New York, N.Y.
The once-powerful partnership between fracking companies and Wall Street is fraying as the industry struggles to attract investors after nearly a decade of losing money.
Frequent infusions of Wall Street capital have sustained the U.S. shale boom. But that largess is running out. New bond and equity deals have dwindled to the lowest level since 2007. Companies raised about $22 billion from equity and debt financing in 2018, less than half the total in 2016 and almost one-third of what they raised in 2012, according to Dealogic.
The loss of that lifeline is forcing shale companies -- which have helped to turn the U.S. into an energy superpower -- to reduce spending and face the prospect of slower growth . More than a dozen companies have announced spending reductions so far this year, even as crude-oil prices have rallied more than 20% from December lows. More are expected to tighten budgets as they release earnings in coming weeks.
The drop in financial backing is especially being felt by smaller, more indebted drillers. But even larger, better-capitalized frackers are facing renewed investor skepticism about whether they can keep spending in check and still hit growth and cash-flow targets.
Shares of Continental Resources Inc. fell 5.4% Tuesday after the shale company, founded by billionaire Harold Hamm, disclosed that fourth-quarter spending was almost 10% higher than analyst expectations.
Wall Street support allowed shale companies to persevere through a plunge in oil prices that began in 2014, eventually helping the U.S. surpass Saudi Arabia and Russia as the world's largest producer of oil , with 11.9 million barrels a day in November, according to the U.S. Energy Information Administration.
Banks have provided financing when producers spend more cash than they take in from operations, something that has happened every year since 2010. They also help companies hedge their future oil production to lock in prices and avoid market volatility, and provide them with revolving loans backed by future oil and natural-gas prospects.
But in 2016, federal regulators concerned about banks' exposure to shale drillers tightened standards for lending to oil-and-gas companies after dozens went bankrupt amid the drop in commodity prices. The U.S. Treasury Department guidelines require lenders to regard loans as troubled if a company's total debt reaches more than 3.5 times a producer's earnings, excluding interest, taxes and other accounting items.
There is more to this article. You can find it by clicking on the link above. It appears that the shale celebration is finally slowing down. But those in the shale cheering section still far outnumber us naysayers.
We shall see.
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Feb 22, 2019 | peakoilbarrel.com
likbez x Ignored says: 02/22/2019 at 1:26 pm
Vulture funds started to descend on shale oil companiesAnd that was just overnight. On Friday morning, another activist, Kimmeridge Energy Management Co., announced it had taken a stake in PDC Energy Inc., an exploration and production company with operations in Colorado and Texas. Kimmeridge wants PDC to overhaul its financial priorities, costs, governance and maybe, given the line about "considering all strategic alternatives," its entire identity.
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Feb 22, 2019 | www.unz.com
Carlton Meyer , says: • Website February 21, 2019 at 7:15 pm GMT
@Shouting Thomas Wrong, the USA is a net importer of around 4 million barrels of oil per day.https://www.eia.gov/tools/faqs/faq.php?id=727&t=6
Here is some background on that hoax you repeated.
Fracking has helped the USA boost oil production, but that is pressuring to get oil out of older wells. Once those have been sucked dry, we'll need to import lots more. You read news about occasional big new discoveries in the USA, but read the details to see that each amounts only to a few days of oil consumption in the USA.
The world still runs on oil and the USA wants to control it all. If you doubt the importance, look at a freeway or airport or seaport to see oil at work.
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Feb 22, 2019 | peakoilbarrel.com
OFM : 02/17/2019 at 9:06 am
I just copied this from Quora, posted as part of a long comment by a person who understands the basics of the oil biz.Freddy : 02/17/2019 at 3:20 pm
"Oil is becoming difficult to extract, and this operation is becoming increasingly expensive. While it is true that the use of fracking has enabled the extraction of previously inaccessible deposits, this just buys us a little more time. As it is, a Goldman Sachs study found that the cost of extracting crude oil went up over 15% a year in the decade prior to the economic slowdown (and is still rising by possibly 10% a year)."Obviously enough, the cost of getting tight oil out is declining, but tight oil is only a small part of total oil production. I'm not sure about the costs of tar sands oil, it may be declining in real terms, or rising. I haven't seen anything recent on the costs of tight oil.
Hopefully somebody in the biz will have something to say about the cost of conventional oil production is changing, based on their personal knowledge.
If it is going up anywhere close to ten percent a year, in real terms, world wide, the price of oil will HAVE to get back into the hundred dollar plus range within five or six years, maybe sooner.. economic troubles can lead to some countries selling for less than production costs.
My opinion is since the crack in 2014 aproximately all exploration offshore stopped, there have been some discoveries near exsisting infrastructure that some have been built out as tieback. In General even with cut in drilling cost , subsea tecnology , remote controlled platforms a brent price of 65 usd bbl will make some profit for oil Companies but you will never see a huge increase in activity to find billions of new barrels that is needed. There is also a fact less discoveries are made each 100 wells drilled and size declining in average. This trend together with increase labour cost , everything else in general will demand higher oil price to solve a global supply crize..Frugal : 02/19/2019 at 2:39 amThis doesn't explain why the Saudi's spend billions building and operating peripheral water injection systems and refineries that can handle oil with vanadium. If they truly have 266 billion barrels in the ground, all they would have to do is drill some wells and millions of cheap, extra barrels/day would gush out of the ground.
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Feb 22, 2019 | peakoilbarrel.com
x Ignored says: 02/20/2019 at 2:19 pm Here is what the EIA's Drilling Productivity Report says will happen in March.They say, total new shale oil produced in March will be 628,526 barrels per day. (Net increace+Legacy decline)
Net Increase will be 84,406 barrels per day.
Legacy Decline will be 544,119 barrels per day
Therefore for every 1 barrel per day increase, 7.45 barrels of new oil had to be produced.
Frugal x Ignored says: 02/21/2019 at 2:16 am
Therefore for every 1 barrel per day increase, 7.45 barrels of new oil had to be produced.Freddy x Ignored says: 02/21/2019 at 1:07 pmThis is simply mind-blowing. And the more oil they produce, the more oil they need to produce to keep from going negative. How long can they keep this up?
https://www.rigzone.com/news/permian_oil_and_gas_production_to_hit_new_records-21-feb-2019-158209-article/
Seems EIA predict production in Permian will increase from 3.98 MMbpd to 4.02 MMbpd next month. Guess it have been mostely flat at least US production have been 11.9 MMbpd since January. Think than an increase of 40 000 /3 month = 13. 333 x12 = 160 000 barrels for 2019 increase seems reasonable. World demand seems increase by 1.5-2.0 MMbpd. Hopefully Permian production will increase significant when tje new pipeline is compleated 4th Quartile 2019 but that remaind to see.
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Feb 22, 2019 | peakoilbarrel.com
Doc Rich x Ignored says: 02/21/2019 at 7:24 pm
Reviewing this past weekly(2/15) oil inventory report reveals import of 7.5 million barrels/day and 7.0 million barrels/day for the past 4 weeks. Yet I hear how we are down to perhaps 1-2 million/day and even that we are a net exporter. Could someone Help me understand what is going on to this non oil person! Thanks in advanceOFM x Ignored says: 02/21/2019 at 9:28 pmHi Doc,dclonghorn x Ignored says: 02/21/2019 at 10:16 pmI'm not one of the experts, but I can nevertheless answer your question!
Short answer:
The fossil fuel industry is in bed with certain politicians whose mascot is the elephant, and together they put out a continuous stream of half facts, cherry picked facts, and outright lies in furtherance of their own ends.
You're at the right place to get the straight dope. HERE.
Doc,You need to look at more of the report.
http://ir.eia.gov/wpsr/overview.pdf
Crude imports on line 5 as 7,522 kbpd, crude exports on line 9 are 3,607 kbpd for net crude imports on line 4 of 3,915 kbpd.
Other supply includes products and natural gas liquids. It shows net imports on line 21 of -2,809 kbpd. Total net imports of Crude and Petroleum Products on line 33 are 1,106 kbpd.
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www.bp.com
In the ET scenario, global demand for liquid fuels – crude and condensates, natural gas liquids (NGLs), and other liquids – increases by 10 Mb/d, plateauing around 108 Mb/d in the 2030s.
All of the demand growth comes from developing economies, driven by the burgeoning middle class in developing Asian economies. Consumption of liquid fuels within the OECD resumes its declining trend. The growth in demand is initially met from non-OPEC producers, led by US tight oil. But as US tight oil production declines in the final decade of the Outlook, OPEC becomes the main source of incremental supply. OPEC output increases by 4 Mb/d over the Outlook, with all of this growth concentrated in the 2030s. Non-OPEC supply grows by 6 Mb/d, led by the US (5 Mb/d), Brazil (2 Mb/d) and Russia (1 Mb/d) offset by declines in higher-cost, mature basins.
Consumption of liquid fuels grows over the next decade, before broadly plateauing in the 2030s
Demand for liquid fuels looks set to expand for a period before gradually plateauing as efficiency improvements in the transport sector accelerate. In the ET scenario, consumption of liquid fuels increases by 10 Mb/d (from 98 Mb/d to 108 Mb/d), with the majority of that growth happening over the next 10 years or so. The demand for liquid fuels continues to be dominated by the transport sector, with its share of liquids consumption remaining around 55%. Transport demand for liquid fuels increases from 56 Mb/d to 61 Mb/d by 2040, with this expansion split between road (2 Mb/d) (divided broadly equally between cars, trucks, and 2/3 wheelers) and aviation/marine (3 Mb/d). But the impetus from transport demand fades over the Outlook as the pace of vehicle efficiency improvements quicken and alternative sources of energy penetrate the transport system . In contrast, efficiency gains when using oil for non-combusted uses, especially as a feedstock in petrochemicals, are more limited. As a result, the non-combusted use of oil takes over as the largest source of demand growth over the Outlook, increasing by 7 Mb/d to 22 Mb/d by 2040.
The outlook for oil demand is uncertain but looks set to play a major role in global energy out to 2040
Although the precise outlook is uncertain, the world looks set to consume significant amounts of oil (crude plus NGLs) for several decades, requiring substantial investment. This year's Energy Outlook considers a range of scenarios for oil demand, with the timing of the peak in demand varying from the next few years to beyond 2040. Despite these differences, the scenarios share two common features. First, all the scenarios suggest that oil will continue to play a significant role in the global energy system in 2040, with the level of oil demand in 2040 ranging from around 80 Mb/d to 130 Mb/d.
In all scenarios, trillions of dollars of investment in oil is neededSecond, significant levels of investment are required for there to be sufficient supplies of oil to meet demand in 2040. If future investment was limited to developing existing fields and there was no investment in new production areas, global production would decline at an average rate of around 4.5% p.a. (based on IEA's estimates), implying global oil supply would be only around 35 Mb/d in 2040. Closing the gap between this supply profile and any of the demand scenarios in the Outlook would require many trillions of dollars of investment over the next 20 years.Growth in liquids supply is initially dominated by US tight oil, with OPEC production increasing only as US tight oil declines
Growth in global liquids production is dominated in the first part of the Outlook by US tight oil, with OPEC production gaining in importance further out. In the ET scenario, total US liquids production accounts for the vast majority of the increase in global supplies out to 2030, driven by US tight oil and NGLs. US tight oil increases by almost 6 Mb/d in the next 10 years, peaking at close to 10.5 Mb/d in the late 2020s, before falling back to around 8.5 Mb/d by 2040. The strong growth in US tight oil reinforces the US's position as the world's largest producer of liquid fuels. As US tight oil declines, this space is filled by OPEC production, which more than accounts for the increase in liquid supplies in the final decade of the Outlook.
The increase in OPEC production is aided by OPEC members responding to the increasing abundance of global oil resources by reforming their economies and reducing their dependency on oil, allowing them gradually to adopt a more competitive strategy of increasing their market share. The speed and extent of this reform is a key uncertainty affecting the outlook for global oil markets (see pp 88-89).
The stalling in OPEC production during the first part of the Outlook causes OPEC's share of global liquids production to fall to its lowest level since the late 1980s before recovering towards the end of the Outlook.
Low-cost producers: Saudi Arabia, UAE, Kuwait, Iraq and Russia
Oil demand †
Download chart and data Download this chart pdf / 64.6 KB Download this data xlsx / 10.1 KB† Excluding GTLs and CTLs
The abundance of oil resources, and risk that large quantities of recoverable oil will never be extracted, may prompt low-cost producers to use their comparative advantage to expand their market share in order to help ensure their resources are produced.
The extent to which low-cost producers can sustainably adopt such a 'higher production, lower price' strategy depends on their progress in reforming their economies, reducing their dependence on oil revenues.
In the ET scenario, low-cost producers are assumed to make some progress in the second half of the Outlook, but the structure of their economies still acts as a material constraint on their ability to exploit fully their low-cost barrels.
The alternative 'Greater reform' scenario assumes a faster pace of economic reform, allowing low-cost producers to increase their market share. The extent to which low-cost producers can increase their market share depends on: the time needed to increase production capacity; and on the ability of higher-cost producers to compete, by either reducing production costs or varying fiscal terms.
The lower price environment associated with this more competitive market structure boosts demand, with the consumption of oil growing throughout the Outlook.
Growth in liquid fuels supplies is driven by NGLs and biofuels, with only limited growth in crude oil production
The increase in liquid fuels supplies is set to be dominated by increases in NGLs and biofuels, with only limited growth in crude.
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Feb 15, 2019 | peakoilbarrel.com
TechGuy x Ignored says: 02/15/2019 at 1:23 pm
Hugo Wrote:
"Dennis, with his calculation of a peak in 2025 + or – 3 years is about right."That really depends on how much debt the Shale Drillers can take on, and presumes there is not another global recession before 2025. Next three years for Shale Drillers may be a problem. I believe something like $150B in debt comes due between now and 2023. That's a lot of debt to roll over, as well as take on more debt to fund CapEx. Without constant US Shale production increases, world production peaks.
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Feb 15, 2019 | peakoilbarrel.com
Watcher: 02/15/2019 at 4:24 am
I have been suspicious for some time that production numbers can be corrupted by fuzzy definitions. Iran is being sanctioned, but Iran shares that enormous gas field under the Persian Gulf with Qatar. Gas production yields condensate and it yields NGLs.likbez: 02/15/2019 at 7:27 pmHigh vapor pressure NGLs get labeled liquefied petroleum gas, and that is used for transportation fuel in India. Pentane Plus is used or called something akin to natural gasoline.
You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be. Iran is using this to dodge sanctions, or they did use it when condensate was not restricted. Don't recall if that loophole was closed in the current sanctions. That would be a good thing to know.
The same thing can happen with shale. We hear all sorts of talk about how much gas is being flared and how much gas is being captured, and you know perfectly well there has to be condensate involved. There was an article a year or so ago about NGL capture in the Bakken, but I don't recall any follow-up. It shouldn't take too much of a stretch on the part of state regulators to find a way to count the high vapor pressure portion of NGL as oil.
You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be.
Exactly. And this, in turn, allows Wall Street to suppress the price of "prime oil" using fake production numbers, fake storage glut (which is essentially condensate glut) and similar tricks. Please note that the US refineries consume mainly "prime oil" while the USA mainly produces (and tries to export at a discount) "subprime oil."
Pretty polished and sophisticated racket. It might well be that shale oil companies are partially financed from those Wall Street profits as nobody in serious mind expect those loans to be ever repaid.
So OPEC cuts are the only weapon that OPEC countries have against this racket.
In any case, I think all those nice charts now need to be split into "prime oil" and subprime oil parts and analyzed separately. In the current conditions, treating "heavy oil" and condensate as a single commodity looks to me like pseudoscience.
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Feb 15, 2019 | peakoilbarrel.com
dclonghorn x Ignored says: 02/14/2019 at 3:14 pm
I do not follow Laredo Petroleum closely, however their recent year-end results and operations summary contained disclosures that may affect north American shale production more broadly, or perhaps they are company specific, I don't know.Mario C Vachon x Ignored says: 02/14/2019 at 6:17 pmLaredo is a nice sized E&P producing around 70,000 boepd in the permian, mostly in Glasscock and Regan counties. Much of their production is horizontal Wolfcamp.
Laredo has been disappointed with its oil production recently, as well as an increasing GOR.
"Laredo has taken action to address the reduced oil productivity experienced in 2018 that we believe was impacted by the tighter spacing of some wells drilled in 2017 and 2018. Responding to these results, the Company began widening spacing on wells spud in the first quarter of 2019. Laredo expects this shift in development strategy to drive higher returns and increased capital efficiency versus 2018 as widening spacing is anticipated to address one of the causes of higher oil decline rates."
They have changed their developmental strategy to widen spacing to improve recovery and mitigate the increasing GOR. They have also reduced their capex by around 35 % from $575 million in 2018 to a planned $365 million in 2019.
"Responding to the current commodity price environment of WTI strip pricing of approximately $54 per barrel, Laredo expects to invest approximately $365 million in 2019, excluding non-budgeted acquisitions. This budget includes approximately $300 million for drilling and completion activities and approximately $65 million for
production facilities, land and other capitalized costs. Laredo anticipates adjusting capital spending levels to match operating cash flow if operating cash flow does not meet budgeted expectations. Should operating cash flow exceed budget expectations, free cash flow could be used to complete additional wells, repurchase stock or pay
down debt.By the third quarter of 2019, enabled by the Company's operational flexibility, Laredo anticipates reducing activity from the current three horizontal rigs and two completion crews to operating one horizontal rig and utilizing a single completion crew, as needed. The front-loaded completion schedule and disciplined reduction in activity should drive free cash flow generation in the second half of 2019 that is expected to balance capital expenditures with cash flow from operations for full-year 2019."
Of course this is just one producers take on productivity concerns. Link below.
Interesting. They are more a gas company than an oil company with only 23000 of the 70000 BOEs being oil. Interestingly, they are forecasting oil production to decline 5% year over year while BOEs rises high single digits, showing how gas to oil keeps rising.As such a tiny oil producer (23000 barrels) its pretty meaningless in the grand scheme, but very interesting nonetheless. Thanks for sharing.
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Feb 15, 2019 | peakoilbarrel.com
Ron Patterson x Ignored says: 02/14/2019 at 4:37 pm
I had to google the link, but it was not hard to find.How Much Oil Does Saudi Arabia Really Have?
Okay, you will have to read the article to see how Robert arrived at his conclusion. But his conclusion is:
So, I have no good reason to doubt Saudi Arabia's official numbers. They probably do have 270 billion barrels of proved oil reserves.
I find his logic horribly flawed. Robert compares Saudi's growing reserve estimates with those of the USA.
First, the US Securities and Exchange Commission have the strictest oil reporting laws in the world, or did have in 1982. Also, better technology has greatly improved reserve estimates. And third, the advent of shale oil has dramatically added to US reserve estimates.
Saudi has no laws that govern their reserve reporting estimates.
From Wikipedia, US Oil Reserves: Proven oil reserves in the United States were 36.4 billion barrels (5.79×109 m3) of crude oil as of the end of 2014, excluding the Strategic Petroleum Reserve. The 2014 reserves represent the largest US proven reserves since 1972, and a 90% increase in proved reserves since 2008.
Robert says US reserves are 50 billion barrels. I don't know where he gets that number but it really doesn't matter. Oil production, along with reserve estimates, are growing in the US for one reason and one reason only, the advent of shale oil. Reserve estimates before 2008 were based on conventional oil. Onshore conventional oil production in the USA is in steep decline.
Robert Rapier is brillant oil man, but a brilliant downstream oil man. Refineries are his forte. He should know better than the shit he produced in that article.
100 percent of Saudi Arabia's reserves are based on conventional oil. Their true reserves are very likely somewhere in the neighborhood of 70 billion barrels.
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Feb 15, 2019 | peakoilbarrel.com
Ron Patterson x Ignored says: 02/14/2019 at 5 :39 pm
Food for thoughtRavi x Ignored says: 02/14/2019 at 11:05 pmI just did a little math using OPEC's estimate of OPEC and Non-OPEC World proven oil Reserves.
OPEC says they have 1214.21 billion barrels of proven reserves. And they say non-OPEC has 268.56 billion barrels of proven reserves. Average OPEC C+C production, over the last four years, has been 12.78 billion barrels per year according to the EIA. The EIA says the average non-OPEC C+C production over the last four years has been 16.8 billion barrels per year.
Okay, here is the killer. If those numbers are correct then the average non-OPEC nation has an R/P ratio of 16 while the average OPEC nation has an R/P ratio of 95. If you think those R/P ratio numbers are even remotely correct then I have a bridge I would like to sell you.
Ron,I agree that the R/P numbers seem very suspicious. But if this is true then OPEC reserves are closer to 400-500 billion barrels not 1.2 trillion barrels. That would give us another trillion barrels at best to consume in the future in addition to the 1.3 trillion already consumed. This brings the URR to 2.2-2.5 trillion barrels at best including extra heavy. What do you think of the URR of 3.1 trillion barrels that is commonly assumed? Also canadian tar sands and venezuelan heavy oil have very low EROI which brings down the extractable oil reserves further. Do you think that is taken into account?
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Feb 14, 2019 | oilprice.com
Analysis
This fallacious narrative of the U.S. tight oil industry overcoming the oil price crash of 2014 through innovation and better efficiency is the product of bundling various tight oil basins under one umbrella and the presentation of the resulting production data as a proof U.S. shale resiliency.
To properly understand the impact of the oil price crash of 2014 on U.S. tight oil production one must focus on shale basins with sufficient operating history prior to the oil price crash and examine their performance post the crash.
To that end, the Bakken and the Eagle Ford are the perfect specimen.
The Bakken and the Eagle Ford are the two oldest tight oil basins in the United States, with the former developed as early as 2007 and the latter in 2010.
Examining the production performance of these two basins in the 4 years preceding the oil crash and contrasting it to the 4 years subsequent to it, offers important insight as to the resiliency of U.S. tight oil production in a low oil price environment.
... ... ...
Both the Bakken and the Eagle Ford grew at a phenomenal rate between 2010 and 2014. The Eagle Ford grew from practically nothing in 2010 to 1.3M barrels by 2014, while the Bakken grew five fold from 190K barrels to 1.08M barrels. Following the collapse in oil prices in late 2014, the Bakken and Eagle Ford growth continued for another year, albeit at a slower pace, as the pre-crash momentum carried production to new highs. However, by 2016, both the Bakken and the Eagle Ford went into a decline and have hardly recovered since. It took the Bakken three years to match its 2015 production level, meanwhile the Eagle Ford production remains 22% below its 2015 peak. During the pre-crash years these two fields grew by a combined yearly average of 600K to 700K barrels from 2012 to 2014. Post the oil price collapse, this torrid growth turned into a sizable decline by 2016 before stabilizing in 2017.Growth in both fields only resumed in 2018 at a combined yearly rate of 210K barrels, a 70% reduction from the combined fields pre-crash growth rate.
The dismal performance of these two fields over the last few years paints a different picture as to U.S. tight oil resiliency in a low oil price environment. The sizable declines, and muted production growth in both the Bakken and the Eagle Ford since 2014 discredit the leap in technology and the efficiency gains narrative that has been espoused as the underlying reason beyond the strong growth in U.S. oil production. As we expand our look into other tight oil basins, it becomes apparent that it was neither technology or efficiency that saved the U.S. tight oil industry, although these factors may have played a supporting role. In simple terms, the key reason as to the strength of U.S. production since the 2014 oil crash is better rock, or rather, the commercial exploitation of a higher quality shale resource, namely the Permian oil field.
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The Permian oil field, unlike the Bakken and the Eagle Ford, was a relative latecomer to the U.S. tight oil story. It was only in 2013, only a year before the oil crash, that the industry commenced full scale development of that giant field's shale resources. Prior to 2013, the Permian lagged both the Bakken and the Eagle Ford in total tight oil production and growth. As can be seen from the preceding graph, the oil crash had only a minor dampening effect on the Permian oil production growth. By 2017, Permian tight oil growth resumed at a healthy clip, and by 2018, Permian tight oil production growth shattered a new record with production skyrocketing by 860K barrels in a single year to 2.76M barrels. This timely unlocking and exploitation of the Permian oil basin masked to a large degree the devastation endured by the Bakken and the Eagle Ford post 2014. In essence, the U.S. tight oil story has two phases masquerading as one: the pre-2014 period marked by the birth and rise of the Bakken and Eagle Ford, and the post-2014 period, marked by the rise of the Permian.
To speak of the U.S. tight oil industry as one is to mistake a long-distance relay race for the accomplishment of a single runner.
The performance divergence between the Bakken, Eagle Ford, and the Permian has major implications as to the likelihood of U.S. tight oil production suppressing oil price over the medium and long term. A close examination of U.S. tight oil production data leads to a single indisputable conclusion: without the advent of the Permian, the U.S. tight oil industry would have lost the OPEC lead price war. Hence, it's a misnomer to treat the U.S. tight oil industry as a monolith, in many ways, the Bakken and the Eagle Ford tight oil fields are as much a victim of the Permian success as the OPEC nations themselves.
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Considering that the majority of U.S. tight oil production growth is generated by a single field, the Permian, changes in the growth outlook of this basin have major implications as to the evolution of global oil prices over the short, medium and long term. Its important to keep in mind that the Permian oil field, despite its large scope, is bound to flatten, peak and decline at some point. While forecasters differ as to the exact year when the Permian oil production will flatten, the majority agree that a slowdown in Permian oil production growth will take place in the early 2020s.According to OPEC (2018 World Oil Outlook), the Permian basin oil production curve is likely to flatten by 2020, with growth slowing down from 860K barrels in 2018 to a mere 230K barrels by 2020:
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Feb 13, 2019 | peakoilbarrel.com
Energy News, 02/12/2019 at 2:29 pm
The EIA's STEO released today.Dennis Coyne, 02/12/2019 at 4:12 pm
https://www.eia.gov/outlooks/steo/
They forecast US C+C production to increase +0.79 million barrels per day during 2019
From Dec 2018 11.93 million barrels per day
To Dec 2019 12.72 million barrels per dayThe EIA's forecast might not be too far off, but I think they expect maybe 200 kb/d higher output in the GOM and my interpretation of George Kaplan's and SouthLaGeo's recent comments is that flat or possibly declining GOM output is a more likely scenario.
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Feb 11, 2019 | www.nakedcapitalism.com
Are Investors Finally Waking up to North America's Fracked Gas Crisis? Posted on February 11, 2019 by Jerri-Lynn Scofield Jerri-Lynn here. I try not to miss a post in Justin Mikulka's excellent series covering the fracking beat for DeSmog Blog. Here's his latest.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg, NY. Originally published at DeSmog Blog
The fracked gas industry's long borrowing binge may finally be hitting a hard reality: paying back investors.
Enabled by rising debt , shale companies have been achieving record fracked oil and gas production, while promising investors a big future payoff. But over a decade into the " fracking miracle ," investors are showing signs they're worried that payoff will never come -- and as a result, loans are drying up.
Growth is apparently no longer the answer for the U.S. natural gas industry, as Matthew Portillo, director of exploration and production research at the investment bank Tudor, Pickering, Holt & Co., recently told The Wall Street Journal .
"Growth is a disease that has plagued the space," Portillo said. "And it needs to be cured before the [natural gas] sector can garner long-term investor interest."
Hints that gas investors are no longer happy with growth-at-any-cost abound. For starters, several major natural gas producers have announced spending cuts for 2019. After announcing layoffs this January, EQT, the largest natural gas producer in the U.S., also promised to decrease spending by 20 percent in 2019.
Such pledges of newfound fiscal restraint are most likely the result of natural gas producers' inability to borrow more money at low rates.
As DeSmog has reported, the historically low interest rates following the 2008 housing crisis were a major enabler of the free-spending and money-losing attitudes in the shale industry. Wall Street has funded a decade of oil and gas production via fracking and incentivized production over profits. Those incentives have worked, with record production and large losses.
However, much like giving mortgages to people without jobs wasn't a sustainable business model, loaning money to shale companies that spend it all without making a profit is not sustainable. Wall Street investors are now worried about getting paid back, and interest rates are rising for shale companies to the point that borrowing more money is too financially risky for them. And because they aren't earning more money than they spend, these companies need to cut spending.
CNN Business recently reported that oil and gas companies stopped borrowing money in October 2018, but not out of restraint. Instead, CNN wrote, "investors, fearful of defaults, demanded a hefty premium to lend to energy companies."
With many fracking companies failing to meet their production forecasts , as The Wall Street Journal has reported , investors may have good reason to be fearful.
The days of unlimited low-interest loans for an industry on a decade-long losing streak might be coming to an end. As Bloomberg credit analyst Spencer Cutter explained to CNN : "Investors woke up and realized this was built on debt."
Canada's Natural Gas Market Facing 'A Daunting Crisis'
Prospects for natural gas don't look much better north of the U.S. border. Like the Canadian tar sands oil market , the Canadian natural gas market is also in the midst of a long losing streak. The problems facing the natural gas market in Alberta, Canada, is "far worse than it is for oil," said Samir Kayande, director at RS Energy, according to Oilprice.com .
Canadian natural gas producers are being crushed by the free-spending American companies that could produce records amounts of gas at a loss while using borrowed money.
One reason natural gas is so cheap right now is that fracking for oil in the U.S. ends up producing huge amounts of gas at the same time. This gas that comes out of the wells with the oil is known as "associated gas." And it is so plentiful that in places like the Permian Basin in Texas, the price of natural gas has actually gone negative . Paying someone to take the product that a company spent money to produce is not a sustainable business model.
https://www.youtube.com/embed/T7NBs9ixJck
Additionally, the U.S. oil and gas industry chooses to flare large amounts of natural gas in oil fields because it's cheaper than building the necessary infrastructure to capture it -- literally burning its own product instead of selling it. And the Canadian producers, who used to sell gas to the U.S. market, simply can't compete.
A natural gas advisory panel to Alberta's energy minister addressed the crisis for Canadian natural gas producers in the December 2018 report " Roadmap to Recovery: Reviving Alberta's Natural Gas Industry ." The report's opening line summarizes the problem:
" Traditional markets for Alberta natural gas are oversupplied. Prices, and therefore industry and government revenues, are crushingly low and have been increasingly volatile locally since the summer of 2017."
Noting the dire situation, one natural gas executive predicted that "this will only get worse in 2019." Too much supply, not enough demand. To remedy this problem, the report recommended expanding supply, decreasing regulation, and bailing out companies with financial backing from the government, with the ultimate goal of producing more gas and exporting it to Asia.
With Alberta's reliance on oil and gas to support its economy, it is easy to see why its politicians are loathe to recognize the economic realities of the natural gas (and tar sands oil) industries. However, some politicians feel the same way about the American coal industry, and that is dying primarily because renewables and natural gas are cheaper ways to produce electricity.
Desperate Times for Leading Gas Producer
Chesapeake Energy is often held up as a case study for the fracking boom. It was a huge early financial success story (based on its stock price, not actual profits), and in 2008, its then- CEO Aubrey McClendon, known as the "Shale King," was the highest paid Fortune 500 CEO in America. Since those high times, it has been a rough decade for Chesapeake. The stock price is near all-time lows -- where it has remained for years.
Chesapeake has stayed afloat by borrowing cash and currently owes around $10 billion in debt. Unable to make money fracking gas in America since the days of the Shale King, Chesapeake has a new strategy -- fracking for oil.
The Wall Street Journal recently reported this shift in Chesapeake's strategy, referring to it as "ill-timed" and "straining already frayed finances."
But Chesapeake is all-in on this new strategy. According to The Wall Street Journal, Chesapeake CEO Doug Lawler said the company "plans to dedicate at least 80 percent of 2019 capital expenditures to oil production because it sees crude as the key to a more profitable future."
One of the top gas producers in America and a "fracking pioneer" is abandoning fracked gas as a path to a profitable future. The fact that Chesapeake now believes fracking for oil is a path to a profitable future -- despite all the evidence to the contrary -- gives this move an air of desperation.
While U.S. politicians from both parties have given standing ovations for the U.S. oil and gas industry , investors appear to be losing their enthusiasm. The so-called shale revolution, the fracking miracle, may have resulted in record oil and gas production in North America, but the real miracle -- in which shale companies make money fracking that oil and gas -- has yet to occur.
The North American natural gas industry is facing a crisis with an oversupplied market and producers that are losing money. Those producers desperately need higher natural gas prices. However, higher gas prices mean renewables become even more attractive to investors, which may lead to gas following in the footsteps of coal -- dying at the hands of the free market. It may take some time, but eventually investors wake up -- or run out of money.
Follow the DeSmog investigative series: Finances of Fracking: Shale Industry Drills More Debt Than Profit
Ignacio , February 11, 2019 at 4:14 am
I no longer wonder why US press treats the Nord Stream 2 as "controversial" with this glut of debt fuelled natl. gas. Instead, the media should be clamoring against gas flaring, a practice that should be banned. ClimateChange101 regulation.
Carolinian , February 11, 2019 at 9:31 am
It does illustrate what any Green New Deal would be up against. Not only are simple environmental steps like no flaring opposed, but investors and drillers cling to an extraction process that doesn't even make money rather than give in to a more rational, government planned energy system. You begin to think it's not even about the money but more about who's in charge. Before we conquer AGW we may have to conquer human nature. The assumption behind the GND and indeed all AGW activism seems to be that if the world is just shown the rational path then the world will take it. The above illustrates how very irrational the world really is.
Peter , February 11, 2019 at 8:13 am
But the real miracle -- in which shale companies make money fracking that oil and gas -- has yet to occur. Which will be a miracle.
I was involved in the service part of the Peace River area gas extraction (and some oil) since the early 1980, and also when the shale gas extraction started in the early 2000's with horizontal drilling changing the face of gas production.By 2006/8 there was talk after heavy investment by Petronas of up to TEN LNG plants at the west coats in the Kitimat area not one has been build to date, no pipeline exists and no means to get any gas to market other than to the internal Canadian and the now oversupplied US market. It was a failure of politicians and regulatory agencies to speed up the permissions and likely as well the dithering by investors, that now Australia has taken on the supply of the Asian market.
tegnost , February 11, 2019 at 8:41 am
Granted they are speaking of Canada as the source of bailout, but the country will be bailing globalist investors which maybe has gone on long enough? Anyway, the same neoliberal playbook "I got your free market right here shame if somethin' was to happen to it "
To remedy this problem, the report recommended expanding supply, decreasing regulation, and bailing out companies with financial backing from the government, with the ultimate goal of producing more gas and exporting it to Asia.
Olivier , February 11, 2019 at 9:36 am
Of all the questionable practices of oil and mining companies flaring is probably the most abhorrent.
Another Scott , February 11, 2019 at 11:00 am
This has long been one of my concerns in the field. I've long held that the federal government should simply outlaw the practice, forcing drillers to find something to do with the gas (bury it, ship it or use it to create electricity). At the very least, it should be prohibited on federal lands as part of the contracts that are signed.
a different chris , February 11, 2019 at 9:39 am
>in the U.S. ends up producing huge amounts of gas at the same time.
And thus they were family-blogged. For the simple reason that this wasn't your, let alone your father's "oil bidness" anymore. Once upon a time wells were dug for water. You pumped water out, more seeped in. Should have been forever but well that's another discussion. Then you dug wells for oil. They were finite, but they lasted decades. Now you think you are "digging wells", but what you really are doing is building an underground factory. In a factory, you seed the inventory and say "go" and stuff comes out the other end. To make another batch the crank needs to be turned again.
They don't have any model in their heads that matches this. Thus they wind up with what to a manufacturer is obviously "scrap" production, aka stuff that they don't have a market for. Why it took Wall Street so long to understand this is a mystery, except I do wonder if many of them knew it but just wanted to "screw the greenies". They aren't going to miss any meals, so why not I guess.
Alex V , February 11, 2019 at 9:41 am
This is just f*&%"#g depressing. A decade of using debt that will be never be paid back to put carbon into the atmosphere that will never go back in the ground, sometimes not even extracting the energy from it first. We deserve what is coming.
Rajesh K , February 11, 2019 at 9:59 am
I read "investors are showing signs they're worried that payoff will never come" as "investors can't borrow money for cheap anymore now that the Fed has raised rates". If the Fed were to reverse course and CUT interest rates, the party will continue. Wanna bet? In another topic, how would MMT prevent people from investing in fracking?
Angie Neer , February 11, 2019 at 12:02 pm
MMT is not a policy, it is an explanatory framework. And it certainly doesn't explain human behavior.
notabanker , February 11, 2019 at 10:27 am
#Fieldwork
Talking to a 2nd or 3rd generation owner of a small family run oil and gas company that maintains local wells about 8 months ago. I expressed my concern about fracking locally. He laughed. Then said in a serious and not at all condescending tone that there is no money going into fracking at these NG prices and it's unlikely to change in the future. He went on to explain where the deposits were, the expense and environmental issues the large frackers are up against and basically said he doesn't see a scenario where it's ever expanded close to populated areas, if it recovers at all. He genuinely didn't see much future in it.
a different chris , February 11, 2019 at 1:19 pm
That would be reassuring but he was using, you know, "logic". That doesn't really match the fracker's MO, does it?
Peter , February 11, 2019 at 1:29 pm
Of course there is no future in it. Shale deposits are vertically small that horizontally extend large distances, which means horizontal drilling. Not only that, usually you need parallel wells for water injection to force the oil or gas out. The cost are much greater compared to conventional vertical drilling with the technical solutions necessarily involved. The wells deplete rapidly within a few years, requiring new wells. I have been on sites in the Peace where wells were producing mainly water after three years.
Michael Fiorillo , February 11, 2019 at 10:49 am
Those opposed to fracking for environmental reasons should perhaps also consider opposing it on national security grounds, since, given the limitations/costs of fracking, those resources should be seen as emergency rations, to be tapped only when absolutely necessary.
That fracked oil and gas is being spewed into the atmosphere when prices are low and falling, and more easily-obtained stocks are plentiful elsewhere, is just compounding the mania with insanity.
It also suggests to me that, since there isn't real money being made, there are geo-strategic, National Security State-related reasons for the US' sudden impulse to jack up oil production.
Steven , February 11, 2019 at 11:13 am
These Wall Street fracking and shale subsidies percolate through the entire economy. In addition to obvious hangers-on like the automobile industry, you have privately owned electrical utilities rushing to load up on as much stranded asset, centralized fossil fuels generation and distribution infrastructure as they can jam through their respective state public utilities commission before the gas bubble bursts.
What is important here is extending and preserving stock price rallies, elevated CEO salaries and coupon-clipping opportunities for rentiers as possible, not economic efficiency in any form that could be understood by anyone but bankers and financiers.
cnchal , February 11, 2019 at 11:24 am
> Are Investors Finally Waking up to North America's Fracked Gas Crisis?
No, because they are not investors but gamblers.
Wall Street has funded a decade of oil and gas production via fracking and incentivized production over profits.
More to the point, no Wall Street criminal was harmed because not one was stupid enough to throw his or her own money on the roll of the dice, but they certainly took the gamblers money and for a fat fee, throw the dice for them.
Susan the Other , February 11, 2019 at 11:41 am
This is getting old. Why does anyone believe in free-market economics in an emergency? It's puzzling that just when oil went into a huge glut and the heavy, full-to-the-brim tankers lined up in all the deep ports, like treasure chests, and the price of oil dropped because the global economy had been slashed by a third it was just at this time that Obama made his panicked decision to frack, to deregulate, and to subsidize it. So these so-called "investors" who are raising their prices for loans, have either seen demand come back and want their fair share of the whole ponzi operation, or the QE that facilitated it all has been tapped out politically, regardless of the economics. No one seemed to care that all the natgas blown off each well was accelerating the CO2 effect, measurably. No one cared about the polluted ground water. Nobody acknowledged that Germany didn't want our LNG. Only free money could have caused this perversion of productivity, all this destruction, this gold rush to nowhere. Our sovereign money should be distributed wisely. Never like this. And never into a deregulated market.
kernel , February 11, 2019 at 12:00 pm
Yikes, ugh, and AAARRRRRGH! Not the 1st I've heard of this (Gas Bubble), but this nails it all down.
Was this (partly/directly) caused by QE? My impression is that QE pumped a bunch of "money" into the top end of the economy (Assets/Wall Street), propping up the Stock Market, but I've never gotten exactly HOW they did it.
Did the Fed just buy lotsa Stock (or Corp Bonds)? If so, did they (partly) create the Gas Bubble by (over-) investing in Fracking companies? If so, they are now stuck bursting that bubble as they "De-QE"; either they (We!) get out of that market early – blowing it up sooner – or wait until it deflates "normally" and lose a bunch of (Our?) money.
Are the details of QE (how much of which assets the Fed bought) public?
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Feb 08, 2019 | off-guardian.org
Narrative says Feb, 1, 2019
Nations should explore better system to break US hegemonycrank says Feb, 1, 2019"The US dollar is used for the international oil and gas trade and a wide part of global trade. This gives the US an exorbitant privilege to sanction countries it opposes.
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The latest sanctions on Venezuela's state-owned oil company aim to cut off source of foreign currency of Venezuelan strongman Nicolas Maduro's government and eventually force him to step down.
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A new mechanism should be devised to thwart such a vicious circle"Francis Lee; Big B,BigB says Feb, 1, 2019OK I phrased that badly.
My question is really about those at the top of the power pyramid (those few hundred families who own the controling share of the wealth of the world) -- those who position idiots like Bolton to do their work, do they comprehend 'exergy' decline ?
If we can, then can they not? I agree with Parenti that they are not 'somnambulists'. They are strategists looking out for their own interests, and that means scrutinising trends in political movements, culture, technology and, well, just about everything. I find it hard, the idea that all these people -- people who have seen their businesses shaped by resource discovery, exploitation and then depletion, have no firm grasp on the realities of dwindling returns on energy.
The models were drawn up 47 years ago. I think that some of them at least, do understand that economic growth is coming to a halt, and have understood for decades. If true then they are planning that transition in their favour.
These hard to swallow facts about oil are still on the far fringes of any political conversation. The neoliberal cultists are deaf to them for obvious reasons; the socialist idealists believe that a 'New Deal' can lead us off the death train, but mostly ignore the intractable relationship between energy decline and financial problems; even the anarchists want their work free utopia run by robots and AI but stop short of asking whether solar panels and wind turbines can actually provide the power for all that tech. It's the news that nobody wants to think about, but which they will be forced to thinking about in the very near future.
The Twitter feed 'Limits to Growth' has less than 800 followers (excellent though it is).
CrankBigB says Feb, 2, 2019I do not want to get into the mind of the Walrus of Death Bolton! I do not want to know what he does, as he does. But at lower levels of government, and corporatism, there is an awareness of surplus energy economics. And as Nafeez has also pointed out, the military (the Pentagon) are taking an interest. And though it could rapidly change, who really appreciates the nuances of EROEI? I'm guessing at less than a single percent of all populations? And how many include its effects in a integrated political sense?
Its appreciation is sporadic: ranging from tech-utopia hopium to a defeated fatalism of the inevitability of collapse. Unless and until people want to face the harshness of the reality that capitalism has created: we are going to be involved in a marginal analysis. There are very few people who have realised that capitalism is long dead.
Dr Tim Morgan estimates that world capitalism has conservatively had $140tn in stimulus since 2008 -- without stimulating anything or reviving it at all. In fact, that amounts to the greatest robbery in history -- the theft of the future. Inasmuch as they can, those unrepayable debts -- transferred to inflate the parasitic assets of capitalists -- will be socialised. Except they cannot be. Not without surplus energy.
https://surplusenergyeconomics.wordpress.com/2019/01/20/145-fire-and-ice-part-two/
Brexit, gilets jaunes, Venezuela, unending crises in MENA, China's economic slowdown, etc -- all linked by EROEI.
It is a common socio-politico-economic energy nexus -- but linked together by whom? And the emergent surplus energy-mind-environmental ecology nexus? All the information is available. The formation of a new political manifesto started in the 1960s with the New Left but it seems to have been in stasis since. Perhaps this might stimulate the conversation.
According to Nate Hagens: there is 4.5 years of human muscle power leveraged by each barrel of oil. We are all going to be working for a very long time to pay back the debts the possessing classes have built up for us -- with absolutely no marginal utility for ourselves.
We are subsidising our own voluntary slavery unless we develop an emergent ecosocialist and ecosophical alternative to carbon capitalism. We cannot expect paleoconservative carbon relics like Bolton -- or anyone else -- to do it for us. The current political landscape is dominated by a hierarchical, vested interest, carbon aristocracy. We can't expect that to change for our benefit any time ever. Expect the opposite.
Graeber has a point, though. We could already have a post-scarcity, post-production society but for the egregious maldistribution of resources and employment. Andre Gorz said as much 50 years ago (Critique of Economic Reason). Why do we organise around production: it makes no sense but for the relations of production are, and remain, the relations of hierarchical rule. So long as we assign value to a human life on the basis of meritocratic productivity -- we will have dehumanisation, marginalisation, and subjugation (haves and have nots). So why not organisation around care, freedom and play?crank says Feb, 2, 2019Such a solution would require the transversalistion of society and not-full-employment: so that no part of the system is subordinate, and no part is privileged. All systems and sub-ordinate (care) systems would be co-equal, of corresponding value and worth. So, without invoking EROEI, that would go a long way to solve our exergy, waste, pollution, and inequality problems. It is the profligate, unproductive superstructure: supporting rentier, surplus energy accumulating, profit-seeking suprasocieties -- that squanders our excess energy and puts expansive spatio-temporal pressures on already stretched biophysical ecological systems that engenders potential collapse. It is their -- the possessing classes -- assets that are being inflated, at our environmental expense. When it comes to survivability, we cannot afford a parasitic globalised superstructure draining the host -- the ecologically productive base. Without the over-accumulation, overconsumption, and wastage (the accursed share) associated with the superstructure of the advanced economies -- and their cultural, credit, military imperialisms I expect we could live quite well. Without the pressures of globalised transportation networks, and unnecessary military budgets -- the pressure on oil is minimised. It could be used for the 1001 other uses it has, rather than fuelling Saudi Eurofighters bombing Yemeni schoolchildren, for instance. The surplus energy could be used to educate, clothe and feed them instead. That would be a better use of resources, for sure.
If we took stock of what we really have, and what we really are -- a form of spiritual neo-self-sufficiency, augmented and extended into co-mutual care and freedom valorising ecologies we wouldn't need to chase the perceived loss all over the globe, killing everything that moves. The solutions are not hard, they are normative, once we are shocked out of this awful near-life trance state of separationism. Thanks for the link.
It seems to me that there are two parallel arguments going on.BigB says Feb, 2, 2019
One is about social organisation, attitudes towards and policies determining work, money, paid employment, technological development and the distribution of weath.
The other is fundamentally based on the laws of thermodynamics and concerns resource limits, energy surpluses, the role of 'stored sunlight' in producing things and doing work for each other, pollution and projections about these into the future.I am surprised that Graeber (just as an example) seems to basically ignore the second of these even though he clearly is an incisive thinker and makes good points about the first. It is taken as a given that, theoretically at least, human civilisation could re-organise around a new ethic, transform the economy into a 'caring economy', re-structure money, government and do away with militarism. In terms of what to do now, as an individual, what choices to make, it is disconcerting to me when talk of these ideals seems to ignore those latter questions about overshoot.
I wonder if the egalitarian nature of much of indiginous North American society was inescapably bound with the realities of a low population density, low technology, intimate relationship with the natural world and a culture completely steeped in reverence for Mother Earth.
The talk I hear from Bastani or Graeber along the lines of 'we could be flying around in jet packs on the moon, if only society was organised sensibly' rings hollow to me.Crankcrank says Jan, 31, 2019Welcome to my world! Apart from as a managerial tool, systems thinking has yet to catch on in the wider population. According to reductive materialism: there are two unlinked arguments. According to Dynamic Systems Theory (DST) there is only one integrated argument -- with two inter-connected correlative aspects. We can only organise around what we can energetically afford. Consequently, we cannot organise around what we cannot afford -- that is, global industrialised production with a supervenient elitist superstructure.
Let's face it : ethical arguments carry little weight against organisation around hierarchical rule. The current talk of an ethical capitalism -- in mixed economies with 'commons' elements -- is an appeasement. and distractional to the gathering and ineluctable reality.
The current (2012) EROI for the UK is 6.2:1 -- barely above the 'energy cliff' of 5:1. The GDP 'growth' and bullshit jobs are funded by monetised debt (we borrow around £5 to make every £1 -- from Tim Morgan's SEEDS). From the Earth Overshoot Day website: the UK is in economic overshoot from May 8th onward.
These are indicators that we will not be "flying jetpacks on the moon": even if we reorganise. Everyone, and I mean everyone, will have to make do with less. A lot less. Everything would have to be localised and sustainable. Production would be minimised, and not at all full. Two major systems of production -- food (agroecology) and energy -- would have to be sustainable and self-sovereign. And financialisation and the rentier, service economy? Now you can see why no one, not even Dave the crypto-anarchist, is talking about reality. Elitism, establishment and entitlement do not figure in an equitable future. We can't afford it, energetically or ethically.
So when will the debate move on? Not any time the populace is bought into ideational deferred prosperity. All the time that EROEI is ignored as the fundamental concept governing dwindling prosperity -- no one, and I mean no one, will be talking about a minimal surplus energy future. The magic realism is that the economic affordances of cheap oil (unsustainably mimicked by debt-funding) will return sometime, somehow (the technocratic superfix). The aporia is that the longer the delay, the less surplus energy we will have available to utilise. Something like the Green New Deal -- that has been proposed for around two decades now -- may give us some quality of life to sustain. Pseudo-talk of a Customs Union, 'clean' coal, and nuclear power, will not.
An integrated reality -- along the model of Guattari's 'Three Ecologies' -- of mind, economy, and environment is well, we are not alone, but we are ahead of the curve. The other cultural aporia is that we need to implement such vision now. Actually, about thirty years ago but let's not get depressive!
We are going to need that cooperative organisation around care and freedom just to get through the coming century.
As mentioned elsewhere here, Venezualan oil deposits are not all that the hype cracks them up to be. They are mostly oil sands that produce little in the way of net energy gain after the lengthy process of extraction.The Venezuala drama is about the empire crushing democracy (i.e. socialism), not oil. [not that this detracts from Kit's essential point in the article].Francis Lee says Jan, 31, 2019
The Left (as well as the Right), by and large have not come to terms with the realities of the decline in net surplus energy that is unfolding around the world and driving the political changes that we see. So they still view geopolitics in terms of the oil economy of pre-2008.
The productive economies of Europe are falling apart (check Steve Keen's latest on Max and Stacy -- although even i he doesn't delve into the energy decline aspect).
The carbon density of the global economy has not changed in the 27 years since the founding of the UNFCCC.The Peak Oil phenomenon was oversimplified, misrepresented and misunderstood as a simple turning point in overall oil production. In truth it was a turning point in energy surplus.
I predict that by the end of this or next year, everyone will be talking about ERoEI. Everyone will realise that there is no way out of this predicament. Maybe there are ways to lessen the catastrophe, but no way to avert it. This will change the conversation, and even change what 'politics' means (i.e. you cannot campaign on a 'new start' or a 'better, brighter future' if everyone knows that that physically cannot happen).
Everyone will understand that their civilisation is collapsing.
Does Bolton understand this?"Does Bolton Understand this/? I think this might qualify as a rhetorical question.BigB says Feb, 1, 2019CrankBigB says Feb, 1, 2019If you were referring to my earlier comments about Venezuelan extra heavy crude: it's still massively about the oil. The current carbon capitalist world system does not understand surplus energy or EROEI, as it is so fixated on maximal short term returns for shareholders. It can't comprehend that their entire business model is unsustainable and self cannibalising. Which is bad for us: because carbon net-energy (exergy) economics it is foundational to all civilisation. The ignorance of it and subsequent environmental and social convergence crises threatens the systemic failure of our entire civilisation. The Venezuelan crisis affects us all: and is symptomatic of a decline in cheap oil due to rapidly falling EROEI.
I can't find the EROEI specifically for Venezuelan heavy oil: but it is only slightly more viscous than bitumen -- which has an EROEI of 3:1. Let's call it 4:1: the same as other tight oils and shale. Anything less than 5:1 is more or less an energy sink: with virtually no net energy left for society. The minimum EROEI for societal needs is 11:1. Does Bolton understand this? Francis hit the nail on the head there.
Do any of our leaders? No. If they did, a transition to decentralisation would be well under way. Globalised supply chains are systemically threatened and fragile. A globalised economy is spectacularly vulnerable. Especially a debt-ridden one. Which way are our leaders trying to take us? At what point will humanity realise we are following clueless Pied Pipers off the Seneca Cliff -- into globalised energy oblivion?
The rapid investment -- not in a post-carbon transition -- but in increased militarisation, and resource and market driven aggressive foreign intervention policies reveal the mindset of insanity. As people come to understand the energy basis of the world crisis: the fact of permanent austerity and increased pauperisation looms large. What will the outcome be when an armed nuclear madhouse becomes increasingly protectionsist of their dwindling share? Too alarmist, perhaps? Let's play pretend that we can plant a few trees and captive breed a few rhinos and it will all be fine. BAU?
The world runs on cheap oil: our socio-politico-economic expectations of progress depend on it. Which means that the modern human mind is, in effect, a thought-process predicated on cheap oil. Oleum ergo sum? Apart from the Middle East: we are already past the point where oil is a liability, not a viability. Debt funding its extraction, selling below the cost of production -- both assume the continual expansion of global GDP. Oil is a highly subsidised -- with our surplus socialisation capital -- negative asset. We foot the bill. A bill that EROEI predicts will keep on rising. At what point do we realise this? Or do we live in hopium of a return to historical prosperity? Or hang on the every word of the populist magic realism demagogue who promises a future social utopia?
If it's based on cheap oil, it ain't happenin'.
Erratum: less viscous than bitumen.wildtalents says Feb, 1, 2019Is it no longer considered a courtesy to the reader to spell out, and who knows maybe even explain, the abbreviations one uses?Jen says Feb, 1, 2019EROEI = Energy Returned on Energy Invested (also known as EROI = Energy Return on Investment)BigB says Feb, 1, 2019EROEI refers to the amount of usable energy that can be extracted from a resource compared to the amount of energy (usually considered to come from the same resource) used to extract it. It's calculated by dividing the amount of energy obtained from a source by the amount of energy needed to get it out.
An EROEI of 1:1 means that the amount of usable energy that a resource generates is the same as the amount of energy that went into getting it out. A resource with an EROEI of 1:1 or anything less isn't considered a viable resource if it delivers the same or less energy than what was invested in it. A viable resource is one with an EROEI of at least 3:1.
https://en.wikipedia.org/wiki/Energy_returned_on_energy_invested
The concept of EROEI assumes that the energy needed to get more energy out of a resource is the same as the extracted energy ie you need oil to extract oil or you need electricity to extract electricity. In real life, you often need another source of energy to extract energy eg in some countries, to extract electricity, you need to burn coal, and in other countries, to extract electricity you need to build dams on rivers. So comparing the EROEI of electricity extraction across different countries will be difficult because you have to consider how and where they're generating electricity and factor in the opportunity costs involved (that is, what the coal or the water or other energy source -- like solar or wind energy -- could have been used for instead of electricity generation).
That is probably why EROEI is used mainly in the context of oil or natural gas extraction.
wildtalents: Yes, I normally do. But the thread started from, and includes Crank's link that explains it.Thomas Peterson says Feb, 1, 2019That's true, Venezuela's 'oil' is mostly not oil.
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Feb 07, 2019 | www.unz.com
Matthias Eckert , says: February 7, 2019 at 10:48 am GMT
@Ilyana_Rozumova Despite huge increases in domestic oil production in the last years the USA is still the second largest net oil importer in the word (behind China).Winston2 , says: February 7, 2019 at 1:37 pm GMT
Also the USA is extracting its proven reserves at a much faster rate than any other large producer (a pattern it also had in the past, leading to high fluctuation in its production) so unless new reserves are discovered US production will likely start to decline again within a few years.@Ilyana_Rozumova Condensate, not oil. Only good for gas or lighter fluid. It may be called oil but that's a deliberate misnomer.Tom Welsh , says: February 7, 2019 at 3:38 pm GMTOnly financial engineering makes it appear profitable. Its a money losing psychopaths power play, not a business. Without a heavy real oil to blend it with its useless, heavy oil is where Venezuela comes in.
@Ilyana_Rozumova "Main factor here is that US due to fracking become self sufficient, what actually nobody could foresee. Just a bad luck".Vidi , says: February 7, 2019 at 9:10 pm GMTBad luck for the USA. They have fallen into an elephant trap, because fracking has already become unprofitable and is only being financed by ever-increasing debt.
Admittedly this gives them some advantage, but only in the very short term.
Of course, it doesn't really matter – in the short to medium term – whether fracking is profitable or grossly unprofitable. They can still pay for it by printing more dollars, as long as the "greater fools" (or heavily bribed officials) in other countries go on accepting dollars.
@Wally"America's energy security just got a lot more secure . Located in the Wolfcamp Shale and overlying Bone Spring Formation, the unproven, technically recoverable reserves are officially the largest on the planet."
None of these breathlessly optimistic articles say how expensive it will be to get this oil. If a dollar's worth of oil costs you more than a dollar to recover, you are obviously losing in the deal. If you print the dollars, your entire economy loses.
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Feb 04, 2019 | peakoilbarrel.com
Guym x Ignored says: 01/30/2019 at 6:04 am
https://www.bizjournals.com/houston/news/2019/01/29/exxon-reportedly-to-move-forward-on-major-beaumont.amp.htmlStephen Hren x Ignored says: 01/30/2019 at 11:29 amMotiva had previously upgraded refinery capacity to accept light oil, Exxon keeps adding more, and now Chevron will, no doubt, expand.
Maybe the big oil will buy up some more of the weaker Permian players, which could slow down the insane growth; and make the Permian more of a feeder for their refineries than an export source. I really can't imagine that they are spending billions on refineries with the expectation that it may start to expire in five years. Exxon and Chevron are already two of the top ten producers in the Permian, and they can get bigger, if they want to.
Gobbling up most of these producers would only amount to a snack for them. And doing it while the pure Permian producers a floating in the doldrums of 2019 would fit perfectly.
That could affect projections for US shale growth. The refiners would look at it over a longer term usage, and not how much they can ship out. However, it could still lower net imports. Win, win.
Thus, possibly saving West Texas from extinction, and move away from boom or bust some. Add pipelines to the East and West coast, and upgrade refineries, and you have a longer term solution.
With Canadian and Mexican heavy oil and sprinkle in some EOR, we could get by for a longer period of time. Peak oil is a meaningful event, but it does not, absolutely, have to affect the US for a while.
On a different topic, a Japanese company is interested in becoming an Eagle Ford player. Japan needs LNG. Eagle Ford has a largely untapped huge gas window. So, even if we do not use the planned upgraded ports for oil, we may still be using them for LNG.
Ok, it's only a dream, now, but the parts are beginning to come together. Big oil has its benefits, and this benefit fits into big oil's need for future existence. When the price of oil goes up, then what's the projected stock price of Exxon or Chevron? They will be back into the mode they were in decades ago, start to finish.
This rings true to me. The big boys have few other options left for expansion (Guyana, Mexico and/or Brazil if they can work their way through the corruption) other than the Permian. Oil prices are likely to remain volatile for the foreseeable future, generating occasional buying opportunities for companies with lots of cash on hand. Kind of the way the tech giants like Apple and Amazon and Facebook bought up all the small fry app/tech companies for lack of anything better to do with their money. If this happens I would expect a slower pace of development to emerge for tight oil over the next decade and a longer tail.Guym x Ignored says: 01/30/2019 at 2:04 pmYeah, that's what I'm thinking. Make peak closer to the time period of somewhere pretty close. I think we better move, we may be sitting to close to that smelly fan.Guym x Ignored says: 01/30/2019 at 6:21 pmChevron's holdings are the size of Yellowstone, and Exxon is not far behind. Will they pick up any additional acreage if the get a good buy? Does a dog bark?
https://oilprice.com/Energy/Energy-General/Chevron-Looks-To-Double-Permian-Production-By-2022.htmlSynapsid x Ignored says: 01/30/2019 at 6:51 pmPlans on growth in the Permian, " .and an increase in net acreage."
Competition with 2 800lbs gorillas?
https://www.houstonchronicle.com/business/amp/Permian-land-rush-is-over-leaving-big-players-to-12842858.phpThis says nothing about the quality of rock, but lists acreage by the top holders. Oxy, ConocoPhillips, and EOG will be more conservative in development, and are not really prime acquisition targets. But adding them and Exxon and Chevron, you get most of the acreage. Energen and Diamondback have merged.
Thanks Guym,John x Ignored says: 01/31/2019 at 12:37 pmThis is very helpful.
The state of oil and gas in Midland is healthy, according to Tim Leach CEO of Concho.GuyM x Ignored says: 01/31/2019 at 3:45 pmhttps://www.mrt.com/business/oil/article/Concho-CEO-Permian-oil-is-
economic-engine-to-13575074.php#item-85307-tbla-5Leach, chairman and chief executive officer of Concho Resources, cited statistics indicating Permian Basin crude production is expected to climb from the current 4 million barrels a day to 6 million barrels a day in just six years. That, he told the sold-out crowd at the Horseshoe, would comprise 7 percent of total world oil production and 40 percent of U.S. production. In addition, the Permian Basin could see 45,000 new high-paying technical jobs on top of the 50,000 jobs that have been created since about 2000.
"Companies operating here today will be investing $50 billion a year in drilling and completing wells," leading to over $1 trillion in spending in that same timeframe, he said. That has created numerous opportunities throughout the Permian Basin, but also significant challenges, he said.
When he and other leaders of local oil companies review their business plans and consider their greatest concerns, he said it's not sand or pipeline capacity or technology. "Collectively, they say it's schools, roads, doctors and housing."
Ok. Concho managed to eek out a loss the third quarter. Good source of info.
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Feb 04, 2019 | peakoilbarrel.com
Davo , 01/29/2019 at 4:25 pm
New here, been lurking for a while. I'm a geologist with a small oil and gas exploration and operating company. We explore conventional only. I have however read all your predictions of peak oil etc. but don't you think that given higher prices, other basins world wide that are similar to the Permian could be successfully exploited for years to come holding off peak oil for decades? I'm no expert but I would venture there are hundreds of basins that could as good or better than the Permian. Just in the U.S., we have the Permian, Bakken, Niobrara, Eagleford and about a dozen others. Surely our success could be duplicated on a global scale if the price was right.Guym , 01/29/2019 at 5:58 pmThere is the Vaca Muerte in Argentina, but probably under the scale of the Eagle Ford. There are a LOT of contraints holding the dead cow back. A lot of countries I have heard of that have gas potential, e.g. China, even UK. But, I have not heard of a lot of oil potential. The way my limited understanding goes, the play has to be new enough on the geological age, to still have oil. As in, the Eagle Ford has three windows which depend on geological age, and pressure. The oil window is younger, the condensate and gas windows are older. I think the Permian will have areas, too. But, I received my geology degree from a cracker jacks boxTimthetiny , 01/30/2019 at 1:50 pmbut your last sentence may hold some validity. For that matter, I don't think shale has given up completely after the first go round, if the price is right. Would that delay peak to another date? Quien sabe. Money talks. What price? I know I would keep an ICE around for long trips at $200 a barrel for the convenience. Food may be higher, though.
Speaking as a geologist, this is incorrect. Thermal maturity depends on far more than age. The Utica gas window is 300 million years older than the eagle fords gas window, just for example.Guym , 01/30/2019 at 2:01 pmI knew I'd be wrong on that, just repeating what I read on a non-technical site. ThanksRon Patterson , 01/29/2019 at 6:16 pmYes, of course there are more shale sources out there. But perhaps not as many as you think. All reservoir rock is not so tight as to hold most of its oil in place. There is, or rather was, lots of oil in West Texas but not much shale oil. The same is true for Southern California. I suspect most of the Middle east is similar.Phil Stevens , 01/29/2019 at 9:58 pmAlso there is the cost. If it takes more energy to extract the oil from shale than you get from the oil you pump out then it is a sink, not a source. For instance it would be extremely difficult to extract oil from offshore shale. You would have to ship the sand out by barge, build huge platforms for every well to hold all that fracking equipment and so on.
There are lots of shale oil sources in Russia. And if prices get high enough, they will probably try to extract it. Imagine hauling train loads of sand to the north slope of Alaska, then trucking it over the tundra by truck to every well. You would have similar problems in Western Siberia.
Return on investment is the primary problem with shale. If it cost more in time and energy than you receive from the extracted producte, it will stay in the ground. Anyway, that's just my unprofessional opinion. Some of the professionals on this blog may have a better educated opinion.
"If it cost more in time and energy than you receive from the extracted producte, it will stay in the ground."Ron Patterson , 01/30/2019 at 7:16 am@Ron Patterson, you seem to be saying that extraction will go forward as long as there is the potential for *any* marginal return, at least expressed in money if not in EROEI. So for example, as long as I can charge $101 for a barrel of oil that cost me $100 to get out of the ground, I'll keep doing it (or someone else will). Do you really think this is the case, or is there a threshold/floor below which it won't make economic sense due to produce oil? Due perhaps to knock-on factors in the larger economy? Obviously I'm no expert on any of this, so please take it easy on me in any replies. Thanks!
Phil, I really have no idea at what point oil companies will decide it is not worth the effort due to low profits or other causes, they will cease drilling. However it must be noted that a majority of oil companies producing shale oil today are doing it at a loss. Of course they all expect to be making money sometime soon. They expect prices to rise so they are just trying to hang on until they are profitible.OFM , 01/30/2019 at 7:52 amSo you see it is just not that simple. They may produce oil at a loss for some time before they fold. But obviously they cannot produce oil at a loss forever. There are many factors that govern their decision to fold their tents and walk away. I think it is impossible to predict exactly at what or when that point is. At least it is beyond my ability to do so.
Hi Ron,Freddy , 01/30/2019 at 8:09 amI don't have any better idea how much shale oil is out there, or whether it can be produced profitably, than you do. But I will add this much to the discussion. Even if it is out there , and can be produced profitably, this is no guarantee that shale oil can prevent peak oil happening.
New shale production, which is subject to extraordinarily fast decline in and of it self, would have to be brought online fast enough to offset both its own decline PLUS the decline of the worlds giant conventional legacy oil fields.
Even if it's profitable to do so, and in large enough quantities, at some particular price, this does not necessarily mean that it will be possible to muster enough capital, equipment, skilled labor, and political will to make it happen FAST ENOUGH to offset conventional legacy oil declining production.
It's been a while since I paid much attention to the actual numbers, but I know you are well acquainted with them.
So what's your estimate, these days, of the conventional legacy oil decline rate? Have you raised it or lowered it recently?
As I have read from news lately a more strict requirements from investors, banks, hedge funds makes it reasonable that investment in shale oil compeared to 2018.budget will be reduced by 19%.One significant player will reduce their number if riggs from 24 to 18 as they expect oil price WTI in 2019 to be in mid 50 usd range.
To me it seems the confident among investors to US shale have changed significant espesialy 4th quartile of 2018. Now they only want to support projects that give cash return , seems they are tiered of promises as there have been to much of and shale oil depth have never been higher.
Since oil demand is linked to groth in world economy that is also same for interest of liability. EIA , and some other analyst like Rystad sees US shale production in 2019 will continue with strong increase and predict we only have seen the beginning. After working within oil and gaz projects in many years I know the oil majours dont want to loose money ,when a project seems not profittable they stop until oil price incresse or they get cost down.
I doubt there will be lots of investments in US shale with oil price in range 50-60 USD, because there is significant documentation only a very limited part ( decreasing) within core area is profitable as of now. Beside this a oil price in range 50-60.WTI or 55- 65 usd each barrel Brent is not enough to pay the cost of exploration drilling offshore, build new infra structure.
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Feb 04, 2019 | peakoilbarrel.com
Karl Johnson
x Ignored says: 01/29/2019 at 10:11 amWhats the beginning of the Senneca-Cliff?GuyM x Ignored says: 01/29/2019 at 11:50 amI think it would be this year, if not last year. Ron has said 2019 at one time. Dennis thinks later, around 2025, as I recall.Hickory x Ignored says: 01/29/2019 at 2:14 pmKarl- I see that you asked 'what' rather than when.Guym x Ignored says: 01/29/2019 at 4:00 pm
Seneca Cliff refers to a very rapid decline in a feature (such as global oil production) after it has achieved a peak. This is as opposed to a very slow decline.
Obviously for oil, a fast decline would be catastrophic.https://cassandralegacy.blogspot.com/2011/08/seneca-effect-origins-of-collapse.html
According to the chart from iRA I posted below, we would be on a Seneca cliff now, without shale oil. Just flattened the drop for awhile.GuyM x Ignored says: 01/29/2019 at 11:39 amhttps://www.iea.org/newsroom/news/2018/november/crunching-the-numbers-are-we-heading-for-an-oil-supply-shock.htmlHan Neumann x Ignored says: 01/31/2019 at 10:58 pmUS production will be close to flat 2019, and if ports are not improved much until late 2020, then 2020 will not be great. After that, I don't see it catching up.
As stated many times on 'theoildrum', State of the art EOR projects deplete oilfields, who without EOR would go in terminal decline much earlier, very rapidly. So a world oilproduction cliff cannot be ruled out, especially if money reserves from oil companies dry up.Dennis Coyne x Ignored says: 02/01/2019 at 10:32 amHan Neumann,Han Neumann x Ignored says: 02/03/2019 at 1:33 pmOil prices are likely to rise if there is a shortage of oil, this will mean oil companies will have plenty of financial resources as long as demand is sufficient to consume the oil produced. Not suggesting there will not be a decline, just unlikely there will be a cliff unless oil prices drop, so far there is no evidence of a cliff and given World stock level trend, prices are unlikely to drop further and are more likely to increase in the future.
Dennis,A cliff is unlikely to happen, I agree.
But to repeat a cliché: depletion never sleeps. Already about fifteen years ago EOR projects were started that extracted oil from (quite) 'past peak' or 'on plateau production' oilfields. EOR projects in case of 'quite past peak' fields, to get 'the last recoverable' barrel out resulting in oil production/day far less than peak production.
I know, the recoverable quantity increases with rising oilprices and better extraction techniques, but still the production/day way past peak will be much less than on peak.
What will happen when oilprices don't increase a lot for the next ten years, for a combination of reasons ?
At a certain point in time all the money in the world couldn't prevent world production decline and the further that point will be in the future, the steeper will be the decline I think. So better sooner than later oilprices begin to increase significantly, to buy some time for the transition to EV's, etc.
I am not an expert in engineering nor in geology, far from that, just expressing a feeling that I got after having read the many posts on theoildrum regarding this matter.
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Jan 14, 2019 | mailchi.mp
Oil prices continued to climb last week and are now some $10 a barrel higher than they were just before Christmas when recent lows were set. Prices now have retraced about 30 percent of the $35 a barrel drop that took place between late September and late December. Part of the recent price correction likely is due to technical factors such as closing out long positions in the futures markets. The news that the Saudis will cut even more production than specified in their recent pledge in hopes of raising world prices to $80 a barrel was an important part of last week's price jump. Hopes that the US and China would settle their trade dispute during on-going talks was also an important factor in the recent price jump.
Looming over the talk about OPEC+ production cuts and how fast US shale oil production might grow are the prospects for the global economy. A major recession could drive the demand for oil so low that even current prices would be difficult to maintain. While there have always been people convinced that a major economic crash is in the offing, in recent weeks there has been a noticeable increase in the number and stridency of these predictions.
While the US economy has been bumping along nicely in recent months, the same is not true for the other major centers of economic power – China and Europe. The Washington Post headlines that "Economic growth is slowing all around the world," citing declines in the equity markets; sputtering German factories, and Chinese retail sales growing at their slowest pace in 15 years. Even Beijing is looking for its GDP to grow by 6-6.5 percent this year which is way off from the heady days of double digits ten years ago.
Eurozone economic forecasts fell last Monday again after a survey of economists found that GDP is expected to grow just below 1.6 percent this year, 0.4 percentage points lower than an already conservative estimate from March. A new report from the World Bank, citing a variety of data, including softening international trade and investment, ongoing trade tensions, and financial turmoil concludes that "the outlook for the global economy in 2019 has darkened."
Among the darker forecasts for the future are those that speculate on a global depression on the scale of the 1930s where GDPs fall by 10 to 25 percent. Others are saying that the global economy may be approaching " The Limits to Growth " as discussed in the famous 1972 book.
... ... ...
Virendra Chauhan of Energy Aspects told CNBC last week that "$50 oil is not a level at which US producers can generate cash flow and production growth, so we do expect a slowdown." In a Bloomberg radio interview John Kilduff, founding partner of Again Capital Management, said "we were getting into the zone where U.S. shale producers stop making money particularly when you sort of add in all the costs, not just the pure say drilling and extraction. It's going to start to get tough for them right now."
... ... ...
Iran : Iran's crude exports dropped to 1 million b/d in November from 2.5 million b/d in April, taking exports back to where they stood during the 2012-2016 sanctions. According to three companies that track Iranian exports, Tehran's crude shipments remained below 1 million b/d in December and are unlikely to exceed that level in January. Tracking
... ... ...
Iraq : Baghdad posted its highest monthly export total to date in December and, combined with Kurdistan, set a nationwide annual record of 4.15 million b/d -- more than 100,000 b/d above the previous record, set in December 2016. The government said on Friday it is committed to the OPEC+ output-cutting deal and would keep its oil production at 4.513 million b/d for the first half of 2019
... ... ...
Saudi Arabia : According to OPEC officials, Saudi Arabia is planning to cut crude exports to around 7.1 million b/d by the end of January in hopes of lifting oil prices above $80 a barrel.
... ... ...
Libya: Tripoli plans to pump 2.1 million b/d of crude oil by 2021 if the security situation improves, the chairman of the National Oil Corporation said last week. The plan would represent a doubling of the current rate of production, which currently stands at 953,000 b/d.
... ... ....
4. Russia
Moscow has already lowered its oil output by around 30,000 b/d compared with October volumes, which is used as the baseline under the latest OPEC/non-OPEC crude production agreement. Russian energy minister Novak said Friday: "We are gradually lowering output; our plan is that overall production in January will be 50,000 b/d less than in October."
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Jan 14, 2019 | www.zerohedge.com
Norway's Oil Production To Fall To 30-Year Low
by Tyler Durden Mon, 01/14/2019 - 14:17 9 SHARES Authored by Tsvetana Paraskova via Oilprice.com,
Despite cost controls, increased efficiency, and higher activity offshore Norway, oil production at Western Europe's largest oil producer fell in 2018 compared to 2017 and is further expected to drop this year to its lowest level since 1988.
Last year, oil production in Norway fell to 1.49 million barrels per day (bpd), down by 6.3 percent compared to the 1.59 million bpd production in 2017, the oil industry regulator, the Norwegian Petroleum Directorate (NPD), said in its annual report this week. Oil production this year is forecast to drop by another 4.7 percent from last year to reach in 2019 its lowest level in thirty years -- 1.42 million bpd, the NPD estimates show.
As bad as it sounds, this year's expected low production is not the worst news for the Norwegian Continental Shelf (NCS) going forward.
Oil production is expected to jump in 2020 through 2023, thanks to the start up in late 2019 of Johan Sverdrup -- the North Sea giant, as operator Equinor calls it. With expected resources of 2.1 billion -- 3.1 billion barrels of oil equivalent, Johan Sverdrup is one of the largest discoveries on the NCS ever made. It will be one of the most important industrial projects in Norway in the next 50 years, and at its peak, the project's production will account for 25 percent of Norway's total oil production, Equinor says.
The worst news for Norway's oil production, as things stand now, is that after Johan Sverdrup and after Johan Castberg in the Barents Sea scheduled for first oil in 2022, Norway doesn't have major oil discoveries and projects to sustain its oil production after the middle of the 2020s.
The NPD started warning last year that from the mid-2020s onward, production offshore Norway will start to decline "so making new and large discoveries quickly is necessary for maintaining production at the same level from the mid-2020s."
In the report this week, NPD Director General Bente Nyland said:
"The high level of exploration activity proves that the Norwegian Shelf is attractive. That is good news! However, resource growth at this level is not sufficient to maintain a high level of production after 2025. Therefore, more profitable resources must be proven, and the clock is ticking".
Norwegian oil production in 2018 was expected to drop compared to the previous year, but the decline "proved to be greater than expected," the NPD said, attributing part of the production fall to the fact that some of the newer fields are more complex than previously assumed, and certain other fields delivered below forecast, mainly because fewer wells were drilled than expected.
In October 2018, Germany's Wintershall warned that its Maria oil and gas field off Norway was not fully meeting expectations due to issues with water injection. Those issues haven't been solved yet, NPD's Nyland told Reuters this week.
Exploration activity in Norway considerably increased in 2018 compared to 2017, with 53 exploration wells spud, up by 17 wells compared to the previous year. Based on company plans, this year's exploration activity is expected to remain high and around the 2018 number of wells spud, the NPD says.
The key reasons for higher exploration activity have been reduced costs, higher oil prices lifting exploration profitability, and new and improved seismic data on large parts of the Shelf, the NPD noted.
However, the Norwegian oil regulator warned that "resource growth at this level is not sufficient to maintain production of oil and gas at a high level after 2025. Therefore, it is essential that more profitable resources are proven in the next few years."
Norway still holds a lot of oil under its Shelf, and those remaining resources could sustain its oil and gas production for decades to come. The industry's problem is that after Johan Sverdrup and Johan Castberg there haven't been major discoveries.
According to the NPD's resource estimate, nearly two-thirds of the undiscovered resources lie in the Barents Sea.
"Therefore, this area will be important for maintaining production over the longer term," the regulator said.
Operators on the NCS have made great efforts to try to make even smaller discoveries profitable by hooking them to existing platforms and production hubs. However, these smaller finds alone can't offset maturing production -- Norway needs major oil discoveries, and it needs them soon , considering that the lead time from discovery to production is several years.
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Jan 13, 2019 | peakoilbarrel.com
Energy News x Ignored says: 01/12/2019 at 2:24 pm
2019-01-11 (Bloomberg) Saudi and Canadian cuts are leaving world hungry for heavy crude
Refiners along the Gulf Coast and in the Midwest invested billions of dollars in cokers and other heavy-oil processing units over the past three decades anticipating supplies of light oil would become scarce while heavy crude from Canada's oil sands, Venezuela and Mexico would grow. Instead, the opposite occurred.
The shale revolution, as well as new offshore supplies form Brazil and West Africa, caused a surge of light oil, while supplies from Venezuela to Mexico declined. Canada's growth has been stymied by delays in getting new pipelines built.
https://www.bnnbloomberg.ca/saudi-and-canadian-cuts-are-leaving-world-hungry-for-heavy-crude-1.1197259
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Jan 13, 2019 | peakoilbarrel.com
Energy News
x Ignored says: 01/11/2019 at 7:57 amIndia – Consumption of Petroleum Products (Without LPG or PetCoke)(kt/day)Energy News x Ignored says: 01/11/2019 at 3:51 pm
December 2018 up +7.01% higher than December 2017
Average full year 2018 up +6.80% higher than full year 2017
Chart https://pbs.twimg.com/media/DwoYp5xWsAA_vRh.jpg
India Light Distillates Consumption (shown in chart)
Average full year 2018 up +9.74% higher than full year 2017
Chart https://pbs.twimg.com/media/DwoY_yjX4AA-S9K.jpg
India Middle Distillates Consumption
Average full year 2018 up +3.92% higher than full year 2017The increase in barrels is +220 kb/day year/year (without LPG or Petcoke)2019-01-11 (Bloomberg) The International Energy Agency, which expects the country to be the fastest-growing oil consumer through 2040, cut its 2018 demand forecast for India at least two times. The agency estimated India's oil demand growth at 245,000 bpd in 2018 and 235,000 bpd in 2019.
https://www.worldoil.com/news/2019/1/11/india-oil-demand-rises-from-four-year-low-as-cash-ban-impact-fades
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Jan 08, 2019 | www.zerohedge.com
U.S. shale industry could struggle if WTI remains below $60-$70 per barrel (differ by the area and the spots). Investing in $50th range is just "hope" investmnet which is reling og positive price dynamics, and below them is clear losses for produces, which means additional junk bond issues.
... ... ...
But even as production held up, drilling activity indicated a sharper slowdown was underway. The index for utilization of equipment by oilfield services firms dropped sharply in the fourth quarter, down from 43 points in the third quarter to just 1.6 in the fourth – falling to the point where there was almost no growth at all quarter-on-quarter.
Meanwhile, employment has also taken a hit. The employment index fell from 31.7 to 17.5, suggesting a "moderating in both employment and work hours growth in the fourth quarter," the Dallas Fed wrote. Labor conditions in oilfield services were particularly hit hard.
The data lends weight to comments made by top oilfield service firms from several months ago. Schlumberger and Halliburton warned in the third quarter of last year that shale companies were slowing drilling activity. Pipeline constraints, well productivity problems and "budget exhaustion" was leading to weaker drilling conditions. The comments were notable at the time, and received press coverage, but oil prices were still high and still rising, and so was shale output. The crash in oil prices and the worsening slowdown in the shale patch puts those comments in new light.
What does all of this mean? If oil producers are not hiring service firms and deploying equipment, that suggests they are rather price sensitive. The fall in oil prices forced cutbacks in drilling activity. Oilfield service firms in particular are bearing the brunt of the slowdown. Executives from oilfield service firms told the Dallas Fed that their operating margins declined in the quarter.
whisky eight four , 15 minutes ago link
Davidduke2000 , 2 hours ago linkBaker huges reports a current US rig count decrease of 1% in the past two weeks. Several companies I support in the Permian have stacked rigs and layed off workers. $50 bbl is the magic number, the longer below that number the worse it will get.
Catullus , 3 hours ago linktrump did what obama did when he asked the clown prince of saudi to increase pumping oil to lower the price to punish Russia.
in both cases one shot himself in the left foot the other shot himself in the right foot and now the us has a shale problem that will end very bad.
philipat , 3 hours ago linkOr it shows how much better the industry has gotten in response to production and prices. It's like a capital intensive industry that doesn't waste capital drilling for something that won't make them money. That's preservation of capital.
It doesn't take years or months to respond. It takes weeks.
philipat , 58 minutes ago linkYes sure, the easiest datasets to follow in one place are at SRSrocco. Steve StAngelo, kudos to him, has been onto this for years and has analyzed a lot of data from different sources.
There are lots of other sources if you duck it (Google is, of course, much more of the official narrative) but Steve has done a pretty good job of pulling a lot of information together over many years and for free. Even the paid access business facilities don't have much information (Surprise?).
The shale industry has been a kind of Ponzi scheme with OPM, entirely dependent on constant new loans to keep production levels up with new wells, and has never made a profit. I have often wondered, actually, to what extent the ESF (That is, USG) has supported the industry as a means of attempting to put more pressure on RRRRUUUUUSSSSSIIIAAAAA!!!!!!! and its energy income. Ultimately, unsuccessfully so, so perhaps this support might not last too much longer?
Without subsidies from "someone", it's difficult to understand how an unprofitable industry could have survived for so long. The Banks are not stupid. Wait, let me re-consider that last remark!! But not in the way I meant
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Jan 06, 2019 | peakoilbarrel.com
GuyM x Ignored says: 01/04/2019 at 9:49 am
https://www.naturalgasintel.com/articles/116950-eps-ofs-firms-cite-uncertainty-as-activity-slows-dramatically-in-4q2018-says-dallas-fedDennis Coyne x Ignored says: 01/04/2019 at 10:58 amMore info from Dallas Fed.
Thanks GuyM,From the piece you linked above which seems to indicate capex spending will be flat to slightly down there was also this:
Asked to provide a specific price for WTI used for capital planning this year, executives said they expect prices to average $54/bbl, with responses ranging from $50 to $64.99. Only 9% thought prices would be below $50.
If their oil price expectation (the average) proves correct, there will not be a lot of money made in 2019 in the tight oil plays of Texas.
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Jan 04, 2019 | finance.yahoo.com
America is now the largest producer of oil in the world. For the U.S., this is great news as the dream of energy independence grows and maybe one day we can tell OPEC to go take a hike.
However, while the shale oil revolution has helped change the energy landscape forever, we cannot take shale for granted. We can't just assume that the industry can withstand any price and that production can keep rising despite the market conditions. We can't assume that shale oil producers can match OPEC production cuts barrel for barrel.
We also can't assume OPEC, weakened by falling prices of late, won't strike back like they did in 2014. That's when OPEC declared a production war on U.S. shale producers. The then de facto head of the OPEC Cartel Ali al-Naimi spoke about market share rivalry with the United States and said that they wanted a battle with the U.S. There were no winners in that production war. Ali al-Naimi was sacked as he almost bankrupted Saudi Arabia. It took its toll on U.S. producers as well, as many were forced into bankruptcy despite making significant progress on efficiency and cost cutting.
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With 2019 underway, OPEC, along with Russia, agreed to remove 1.2 million barrels per day off the market for the first six months of the year. Early reports on OPEC compliance to the agreed upon production cuts is overwhelming at a time when there are new questions about how shale oil producers are faring after this recent oil price drop.
Private forecasters are showing that there are major cuts in Saudi exports and even signs that OPEC production is falling sharply. Bloomberg News confirmed that by reporting "observed crude exports from Saudi Arabia fell to 7.253 million barrels per day in December on lower flows to the U.S. and China." Furthermore, other private trackers believe that the drop may be the biggest in exports since Bloomberg began tracking shipments in early 2017. Oil saw another boost after Bloomberg reported that OPEC oil production had the biggest monthly drop in two years falling by 530,000 barrels a day to 32.6 million a day last month. It's the sharpest pullback since January 2017.
Rewind to 2017, there was talk that shale oil producers would make up the difference and the cut would not matter, but that was proven wrong. This time expect the same because it is likely that shale oil producers may have to cut back as the sharp price drop has put them in a bad position. The Wall Street Journal pointed out that, even now, some shale oil wells are not producing as much oil as expected. This coupled with a large declining production rate in shale swells means that they need capital to keep drilling to keep those record production numbers moving higher. "Two-thirds of projections made by the fracking companies between 2014 and 2017 in America's four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in Texas and North Dakota. Collectively, the companies that made projections are on track to pump nearly 10% less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm. That is the equivalent of almost one billion barrels of oil and gas over 30 years, worth more than $30 billion at current prices. Some companies are off track by more than 50% in certain regions" the Journal reported.
"While U.S. output rose to an all-time high of 11.5 million barrels a day, shaking up the geopolitical balance by putting U.S. production on par with Saudi Arabia and Russia. The Journal's findings suggest current production levels may be hard to sustain without greater spending, because operators will have to drill more wells to meet growth targets. Yet shale drillers, most of whom have yet to consistently make money, are under pressure to cut spending in the face of a 40% crude-oil price decline since October."
Of course, none of this matters if we see a prolonged slowdown in the global economy, Demand may indeed turn out to be the great equalizer. Yet if growth comes back, say if we get a China trade deal or if they ever reopen the U.S. government, we will most likely see a very tight market in the new year. The OPEC cuts will lead to a big drawdown in supply and shale oil producers will find it hard to match OPEC and demand growth barrel for barrel.
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Jan 03, 2019 | peakoilbarrel.com
Joseph: 01/02/2019 AT 1:12 PM
MSM seems to be catching on to the hype in shale, excerpts from an excellent article on shale on WSJ today:
Two-thirds of projections made by the fracking companies between 2014 and 2017 in America's four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in Texas and North Dakota.
Collectively, the [shale] companies that made projections are on track to pump nearly 10% less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm. That is the equivalent of almost one billion barrels of oil and gas over 30 years, worth more than $30 billion at current prices. Some companies are off track by more than 50% in certain regions.
-- --
In September 2015, Pioneer Natural Resources, based in Irving, Texas, told investors that it expected wells in the Eagle Ford shale of South Texas to produce 1.3 million barrels of oil and gas apiece. Those wells now appear to be on a pace to produce about 482,000 barrels, 63% less than forecast, according to the Journal's analysis.
An average of Pioneer's 2015 forecasts for wells it had recently fracked in the Midland portion of the Permian basin suggested they would produce about 960,000 barrels of oil and gas each. Those wells are now on track to produce about 720,000 barrels, according to the Journal's review, 25% below Pioneer's projections.
In 2014, Parsley Energy, an Austin, Texas-based producer, told investors its average well in the Midland section of the Permian basin would produce 690,000 barrels, according to a review of Parsley's quarterly earnings presentations. By 2015, its estimates averaged 1,050,000 barrels.
Parsley is on track to miss its Midland well forecasts for every year from 2014 to 2017 by an average of 25%, according to the Journal's analysis.
-- --
One reason thousands of early shale wells aren't meeting expectations is that many companies extrapolated how much they would produce from small clusters of prolific initial wells, according to reserves specialists. Some also excluded their worst-performing wells from the calculations, which is akin to eliminating strikeouts when projecting a baseball player's batting average.
Full article here (behind a paywall):
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Jan 03, 2019 | peakoilbarrel.com
Sallow sand: 01/02/2019 AT 3:17 PM
As I have posted before, the wells we apply a 60 month payout to have a much lower decline rate than the shale wells, and are being drilled out of cash flow, not borrowed money.
For example, a well we drilled in 2006 just passed 10,000 BO and produced 370 BO in 2018. It cost about 1/100 the cost of a shale well ($70K +/-).
Maybe not a valid comparison, but. 100:1 ratio would be cumulative of 1 million BO and annual of 37,000 BO, which I think a rate you will not find often for any US shale well after 12.5 years on production.
Our LOE is higher per BO, so not entirely valid, but still maybe somewhat useful for comparison.
I note in the WSJ article PXD argued that the comparisons weren't valid because they use a 50 year well life in calculating EUR v 30 year well life in the study.
I would think the PV of years 30-50 would be tiny on a 20,000' hz well producing under 20 BOEPD! That PXD uses that argument seems to make them look a little foolish? Or am I being too tough on them?
GuyM: 01/02/2019 AT 3:28 PM
Shallow, you know they can't run a stripper well like you. Damn thing will be plugged at seven years. Dennis can calculate his damn curves to twenty to thirty years if he wants to. I can't disprove it, because we are only in about year eight, and some have probably been plugged already, although I have no statistics on it. Although, I found one of EOGs that didn't make it 7 years without trying too hard.
Mike was talking about borrowing on conventional production that has a much smaller decline rate. You drill one this year, and borrow the next year to drill another, you are increasing production. Not running on a treadmill.
XXX says: 01/02/2019 AT 2:24 PM
Watcher: 01/02/2019 AT 3:32 PMDon't have the paywall, but you've given the gist. Investors were not happy with returns. Now, they are being fact checked, and that can look real messy. Borrowing is set to become restricted for many reasons. I really see some headwinds for future production increases.
Based on first year production numbers supplied by Shallow Sand, production can't increase without borrowing, except in some isolated areas.
To get even close to covering declines from last years wells, they have to, at least, recover most of that capex cost in the first year of production. That is far from reality, right now. To increase, or later to even keep up, with production, they will have to borrow money. They can possibly make a profit in three years, but that is meaningless to providing for growth. Think it going to start looking nastier.
And to add to Ron's answer, God would have to add, and make each well profitable the first year.
The miracle of US shale is about to have Toto pull back the curtain and reveal the real wizard.
Shale was, is, and will be just a supplemental source of oil supply. An investor could, if it was managed right, put x amount into the business, and in several years get a marginal return. In two to three years, a second well could be drilled to increase that income. That would be shale production growth. Not the imaginary growth numbers that are being thrown out.
The putrid 10Qs and 10ks for 2019 will add to the fire.
GuyM: 01/02/2019 AT 4:27 PMYou guys insist on continuing to think money isn't created from thin air by the Fed and actually means something in the context of a substance that feeds you food. If you have to have it, and you do have to have it, things will be done for you to get it. Borrowed money that was created from thin air . . . who cares if you can't pay it back? You have to eat.
Consumption of oil is up. OPEC and Russia have reduced output. The price falls, because there is no meaning to anything created from thin air when applied to something that depends on physics.
You won't know anything until you find yourself sitting in a line waiting for gasoline. You won't see it coming. You won't predict it. It will just happen someday.
Soon.
GuyM: 01/02/2019 AT 7:38 PMSome truth to that Watcher. Simplistic thinking in investors. If we aren't making much money, the US won't be making much money, so the price of oil must go lower. Not just simplistic, flat out stupid.
And the number of people who think oil supply is limited is fairly scarce in relation to the population as a whole. Probably less than the number of people who think chocolate milk comes from brown cows.
That would be less than 7%.
And if you think I am being unreasonably hard on the average IQ, google who is now running the country, and consider almost 50% voted for him. Ok, I'll give them somewhat of a break, as I didn't like the alternative, either. They should allow write ins, so we can all vote.
And any moron can borrow 20 billion and service the debt for awhile. Maybe all of it, if they are lucky. Who cares, it's only paper. Not a bad idea. I have an oil company, I can borrow 20 billion, stick half into BNO, and have a ball with the rest. If I lose, I can declare bankruptcy, and they can get my prepaid funeral expenses, but none of my gold bars in the Caymans. And, I am 99.9% certain that is less of a risk than any E&P I can think of.
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Dec 29, 2018 | www.nakedcapitalism.com
Jerri-Lynn here. This is the latest installment in Justin Mikulka's excellent series on the fracking beat, Finances of Fracking: Shale Industry Drills More Debt Than Profit . The industry lacks even the excuse of profit to justify the environmental costs it inflicts – yet the mainstream media continue to swallow industry waffle. I've crossposted other articles in the series, and I encourage interested readers to look at them – the entire series is well worth your time.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg, NY. Originally published at DeSmog Blog
2018 was the year the oil and gas industry promised that its darling, the shale fracking revolution, would stop focusing on endless production and instead turn a profit for its investors. But as the year winds to a close, it's clear that hasn't happened.
Instead, the fracking industry has helped set new records for U.S. oil production while continuing to lose huge amounts of money -- and that was before the recent crash in oil prices.
But plenty of people in the industry and media make it sound like a much different, and more profitable, story.
Broken Promises and Record ProductionGoing into this year, the fracking industry needed to prove it was a good investment (and not just for its CEOs, who are garnering massive paychecks ).
In January, The Wall Street Journal touted the prospect of frackers finally making "real money for the first time" this year. "Shale drillers are heeding growing calls from investors who have chastened the companies for pumping ever more oil and gas even as they incur losses doing so," oil and energy reporter Bradley Olson wrote.
Olson's story quoted an energy asset manager making the (always) ill-fated prediction about the oil and gas industry that this time will be different.
Is this time going to be different? I think yes, a little bit," said energy asset manager Will Riley. "Companies will look to increase growth a little, but at a more moderate pace."
Despite this early optimism, Bloomberg noted in February that even the Permian Basin -- "America's hottest oilfield" -- faced "hidden pitfalls" that could "hamstring" the industry.
They were right. Those pitfalls turned out to be the ugly reality of the fracking industry's finances.
And this time was not different.
On the edge of the Permian in New Mexico, The Albuquerque Journal reported the industry is "on pace this year to leap past last year's record oil production," according to Ryan Flynn, executive director of the New Mexico Oil and Gas Association. And yet that oil has at times been discounted as much as $20 a barrel compared to world oil prices because New Mexico doesn't have the infrastructure to move all of it.
Who would be foolish enough to produce more oil than the existing infrastructure could handle in a year when the industry promised restraint and a focus on profits? New Mexico, for one. And North Dakota. And Texas.
In North Dakota, record oil production resulted in discounts of $15 per barrel and above due to infrastructure constraints.
Texas is experiencing a similar story. Oilprice.com cites a Goldman Sachs prediction of discounts "around $19-$22 per [barrel]" for the fourth quarter of 2018 and through the first three quarters of next year.
Oil producers in fracking fields across the country seem to have resisted the urge to reign in production and instead produced record volumes of oil in 2018. In the process -- much like the tar sands industry in Canada -- they have created a situation where the market devalues their oil. Unsurprisingly, this is not a recipe for profits.
Shale Oil Industry 'More Profitable Than Ever' -- Or Is It?However, Reuters recently analyzed 32 fracking companies and declared that "U.S. shale firms are more profitable than ever after a strong third quarter." How is this possible?
Reading a bit further reveals what Reuters considers "profits."
"The group's cash flow deficit has narrowed to $945 million as U.S.benchmark crude hit $70 a barrel and production soared," reported Reuters.
So, "more profitable than ever" means that those 32 companies are running a deficit of nearly $1 billion. That does not meet the accepted definition of profit.
A separate analysis released earlier this month by the Institute for Energy Economics and Financial Analysis and The Sightline Institute also reviewed 32 companies in the fracking industry and reached the same conclusion: "The 32 mid-size U.S.exploration companies included in this review reported nearly $1 billion in negative cash flows through September."
NINE-YEAR LOSING STREAK CONTINUES FOR US FRACKING SECTOR
Oil and gas output is rising but cash losses keep flowing. # CSG # Fracking # Shale # Gas # FrackFreeNT # FrackFreeWA # FrackFreeNSW # FederalICAC # Auspol https://www. sightline.org/2018/12/05/nin e-year-losing-streak-continues-for-us-fracking-sector/
5 18:04 - 9 Dec 2018 Twitter Ads information and privacy Nine-year losing streak continues for US fracking sector - Sightline InstituteA look at 32 US fracking-focused companies spent nearly $1 billion more on drilling and related capital outlays than they generated by selling oil and gas.
sightline.orgThe numbers don't lie. Despite the highest oil prices in years and record amounts of oil production, the fracking industry continued to spend more than it made in 2018. And somehow, smaller industry losses can still be interpreted as being "more profitable than ever."
The Fracking Industry's Fuzzy MathOne practice the fracking industry uses to obfuscate its long money-losing streak is to change the goal posts for what it means to be profitable. The Wall Street Journal recently highlighted this practice, writing: "Claims of low 'break-even' prices for shale drilling hardly square with frackers' bottom lines."
The industry likes to talk about low "break-even" numbers and how individual wells are profitable -- but somehow the companies themselves keep losing money. This can lead to statements like this one from Chris Duncan, an energy analyst at Brandes Investment Partners:
"You always scratch your head as to how they can have these well economics that can have double-digit returns on investment, but it never flows through to the total company return."
Head-scratching, indeed.
The explanation is pretty simple: Shale companies are not counting many of their operating expenses in the "break-even" calculations. Convenient for them, but highly misleading about the economics of fracking because factoring in the costs of running one of these companies often leads those so-called profits from the black and into the red.
The Wall Street Journal explains the flaw in the fracking industry's questionable break-even claims: "break-evens generally exclude such key costs as land, overhead and even at times transportation."
Other tricks, The Wall Street Journal notes, include companies only claiming the break-even prices of their most profitable land (known in the industry as "sweet spots") or using artificially low costs for drilling contractors and oil service companies.
While the mystery of fracking industry finances appears to be solved, the mystery of why oil companies are allowed to make such misleading claims remains.
Wall Street Continues to Fund an Unsustainable Business Model Ryan Popple @rcpoppleSee Ryan Popple's other Tweets Twitter Ads information and privacyThe US shale / fracking formula... 1.) borrow billions at low interest rates 2.) lose money forcing oil & gas from marginal fields 3.) leave someone else stuck with the financial losses & environmental destruction https://www. sightline.org/2018/10/17/us- fracking-financial-red-flags/
22 15:12 - 24 Oct 2018 Twitter Ads information and privacy Financial Red Flags for Fracking - Sightline InstituteAmerica's fracking boom has been a world-class bust. Fracking companies have spent far more on drilling than they've earned by selling oil and gas.
sightline.orgWhy does the fracking industry continue to receive more investments from Wall Street despite breaking its "promises" this year?
Because that is how Wall Street makes money . Whether fracking companies are profitable or not doesn't really matter to Wall Street executives who are getting rich making the loans that the fracking industry struggles to repay.
An excellent example of this is the risk that rising interest rates pose to the fracking industry. Even shale companies that have made profits occasionally have done so while also amassing large debts . As interest rates rise, those companies will have to borrow at higher rates, which increases operating costs and decreases the likelihood that shale companies losing cash will ever pay back that debt.
Continental Resources, one of the largest fracking companies, is often touted as an excellent investment. Investor's Business Daily recently noted t hat "[w]ithin the Oil& Gas-U.S.Exploration & Production industry, Continental is the fourth-ranked stock with a strong 98 out of a highest-possible 99 [Investor's Business Daily] Composite Rating."
And yet when Simply Wall St. analyzed the company's ability to pay back its over $6 billion in debt, the stockmarket news site concluded that Continental isn't well positioned to repay that debt. However, it noted "[t]he sheer size of Continental Resources means it is unlikely to default or announce bankruptcy anytime soon." For frackers, being at the top of the industry apparently means being too big to fail.
As interest rates rise, common sense might suggest that Wall Street would rein in its lending to shale companies. But when has common sense applied to Wall Street?
Even the Houston Chronicle, a major paper near the center of the fracking boom, recently asked, "How long can the fracking spending spree last?"
For the past decade U.S. fracking firms have been spending more than they're taking in - by about $80 million per year at the 60 largest companies. With investors cracking down and interest rates rising, some are asking how much longer it can go on. https://www. houstonchronicle.com/business/energ y/article/How-long-can-the-fracking-spending-spree-last-13228180.php?utm_campaign=twitter-premium&utm_source=CMS%20Sharing%20Button&utm_medium=social
6 15:04 - 14 Sep 2018 Twitter Ads information and privacy How long can the fracking spending spree last?After a decade of U.S. oil and gas companies spending beyond their means, a debate is underway in the energy and investment sectors on whether to keep pumping money into oil fields to keep the boom...
houstonchronicle.comThe Chronicle notes the epic money-losing streak for the industry and how fracking bankruptcies have already ended up "stiffing lenders and investors on more than $70 billion in outstanding loans."
So, is the party over?
Not according to Katherine Spector, a research scholar at Columbia University's Center on Global Energy Policy. She explains how Wall Street will reconcile investing in these fracking firms during a period of higher interest rates: "Banks are going to make more money [through higher interest rates], so they're going to want to get more money out the door."
Follow the DeSmog investigative series: Finances of Fracking: Shale Industry Drills More Debt Than Profit
Harry , December 20, 2018 at 6:12 am
Some points.
1. The Sightline Institute methodology had 33 cos. Not 32. I would bet the Reuters reporter took out one company out from the analysis. Bear in mind XOP has 72 or so companies so there is a lot of scope for cherry picking there too.
2. What bank wants to run an oil company? The banks lent to a sector which conned them. I guess rates were too low for too long. Those loans/bonds are only recoverable if oil prices are high. The oil men know they are long a massive call option, and you can't take it off them. They can't get new money so they won't give back the old.
3. Diamondback and maybe 8 others make money. Infrastructure in the right place and good geologies.
4. The numbers are unfair to Andarko cos the cut off misses a bunch of cash coming back in q3
Still, a well timed piece
TimR , December 20, 2018 at 10:16 am
Wrt 2, are you saying there's a contest between the banks and oil men? How is it likely to play out?
Pym of Nantucket , December 20, 2018 at 10:27 am
Remember Enron? We're clearly not smart enough to understand the genius of how this is profitable. I guess we should just step aside and watch the smart guys spin straw into gold. I'm sure they will share the wealth with the land owners right?
John k , December 20, 2018 at 11:34 am
If they don't pay the lease they're kicked off the land. They'll share until bk.
Harry , December 20, 2018 at 4:38 pm
These oil men are not stupid. They like to get their DUCs in a row – wells drilled but uncompleted. If oil goes up enough they can open the DUCs in less than 2 months. Its the weakly capitalized ones who will pump oil out of a reservoir with low oil prices to service debt. Also by drilling they often validate a lease which would void if they didnt drill. However by not pumping they dont have to pay any royalties – just rents.
Below $50 on WTI a lot of the sector doesn't generate enough cashflow to meet investment plans.
leapfrog , December 20, 2018 at 1:47 pm
Yes, I remember the infamous "Grandma Millie" talk between Enron traders.
rd , December 20, 2018 at 4:27 pm
I think a lot of the funding is with junk bonds. So most of those bonds are sold to investors, including ETFs, mutual funds, and pension funds. Many of the banks are just middlemen and will probably not be left holding too much of the bag if they haven't kept them on their own books or written lots of stupid derivatives on them.
This should be a much smaller sector than the housing sector so a sub-prime mortgage bond-like crash shouldn't have the impact of 2008. But who knows, the main thing aI marvel about with the financial sector is their unerring ability to take something that should be relatively safe, weaponize it, and threaten global financial stability with it.
Wukchumni , December 20, 2018 at 6:56 am
I've watched in horror from a distance in regards to fracking, and then a few days ago, this planning area map for open hydraulic fracking leases has me surrounded in a sea of red
https://eplanning.blm.gov/epl-front-office/projects/nepa/100601/153195/187750/Planning_Area_Map.pdf
We're on a fractured rock aquifer in the foothills here that's separate from the one on the valley floor, and because it gets scant use in Ag, and not many people live here (we're 2.5x as big as Paradise,Ca. in size, with 1/10th of the population and at a similar altitude) nobody's hard rock wells had any issues with going dry during the lengthy drought and having to drill hundreds if not a thousand feet deeper in search of H20, as was occurring to the farmers et al on the fruited plain.
I sure don't like the idea of a fractured rock aquifer and fracking
One thing going against us, is land is cheap here, it's nature acres, nice to look at. but no development potential, as the trees are all in the way, and what sorry sap is going to cut down oaks a couple hundred old and level the hills to put in tiny boxes?
That villain doesn't exist, luckily.
But if you were to dangle large amounts of money at the owners of such low value acres, in oil leases?
And the idea it was all a circle jerk by Wall*Street & Big Oil, to get the money!
.
Makes it even harder to swallowRBHoughton , December 20, 2018 at 5:32 pm
Its not just the environmental damage. Banks lending to frackers will be precedent creditors. They'll keep loaning until whatever value in the company that can be extracted in extremis has been used up. One can easily imagine the sort of accounting Wall Street uses.
SittingStill , December 20, 2018 at 7:23 am
So when these companies finally go bust, faced with the diminishment of oil production, will US taxpayers be forced to bail out the industry because of the economic/national security implications of the prospects of eviscerated US oil production volumes? If so, Wall Street wins yet again.
Pym of Nantucket , December 20, 2018 at 10:21 am
A gigantic hidden cost is the liabilities associated with the resulting abandoned wells. This is why this fall there was a Supreme Court challenge in Canada to a ruling on who gets paid first in such cases. In Canada the reclamation costs fall to the remaining producers who share costs of the Orphan Well Association. In the US, it is completely off the books, and therefore falls to the government to clean up abandoned plays when companies go bust.
So, taxpayers could be on the hook both if there is a government bailout on bad loans, a al 2008/2009, AND will have to pay to clean this up (it's expensive, by the way, there are thousands and thousands of these sites that need to be remediated). I suspect the reason all this is happening is a strategic effort to use tax payer backstopped risk to punish Russia to daring to exist.
rd , December 20, 2018 at 10:42 am
This is similar to mines and old waste dumps. If the owners were limited partnerships or companies that went bankrupt with no remaining solvent pieces, then there is no money in the kitty to clean them up. The remaining game in town then is Superfund and state programs for inactive hazardous waste sites and orphan wells.
The RCRA Subtitle C and D regulations in the 1980s and early 90s required landfill operators to set aside funds in lock-boxes so that if they went bankrupt, the state could access those funds to close the landfills. The landfills typically charge a fee per ton just to fund these financial assurance accounts and they need to keep them on file with the states. Unfortunately, the resource extraction industry has generally been able to successfully fight against these types of requirements as "job-killers".
jackiebass , December 20, 2018 at 7:39 am
One economic problem with fracked gas wells is they only produce large quantities of gas for a short time. It's usually 2 to 3 years. After that production tanks. I suspect a similar thing happens with fracked oil wells. I I've in NY close to the PA boarder. For about 4 years, fracking was really booming. Now it has almost stopped. You see big lots filled with fracking equipment gathering rust. It didn't take most people long to realize that only a few made money while the rest pay the bill for all of the damage done. I'm glad in NY state they banned fracking. I own 50 acres and refused to buy into a leasing deal before fracking was banned. My biggest concern was my well water becoming contaminated as well as losing control over how my land is used. A big problem is that a company is allowed to drill under your land even if you don't have a lease agreement with them. They have to pay you but they can also pollute your well. If that happens your property becomes of no value and useless.
SimonGirty , December 20, 2018 at 12:45 pm
We'd become curious about folks moving to the NE tip of PA, as it looked like NJT might actually reopen rail service to all those $80-$140K houses, right before Williams/ Transco's Constitution Pipeline finally caused hundreds of new fracked wells? We'd guessed the only effect of the '16 election was who'd be prodding retirees into GasLand Poconos. Seems like a great location for a remake of Green Acres meets Deliverance? https://www.njherald.com/20180410/lackawanna-cutoff-project-may-finally-be-back-on-track
Looks like there's a mess of unwatchable YouTube videos. I wonder if refugees have any idea of what could happen up there?ape , December 20, 2018 at 7:56 am
Yes, when liquidity has a much smaller time constant then actual production, the rules of liquidity will decouple from the production and actually dominate the process.
This is well-known from physics, and why many economic theories are obviously and fundamentally wrong.
As long as the economy is financialized with almost infinite velocity, nothing in the real world (including profits) will actually drive the system. This is trivially obvious.
peter , December 20, 2018 at 8:01 am
New definition of profit: less of a loss then expected.
diptherio , December 20, 2018 at 8:40 am
Let's add that to GAAP, shall we?
Olga , December 20, 2018 at 8:21 am
And yet, Far West Texas is booming – not sure what to make of it all. And – as in 'irony' – some of that boom is powered by wind.
d , December 20, 2018 at 8:44 am
This kind of thing makes me chuckle. So the CEOs and other suits at the fracking companies are scamming their investors to enrich themselves. Hard to feel bad about it (even though a fair number of the investors are probably "institutional") if it wasn't for the needless environmental destruction that goes along with these two groups of elites ripping each other off.
Phemfrog , December 20, 2018 at 10:04 am
Very broadly speaking, wouldn't this be a good real-world example of MMT? There is a natural resource we want to extract, we have the manpower and machinery to do it, so we just do it? The money to fund it is limitless bound only by the constraints of the resource itself. Wall street is just a rent-extracting intermediary
Am I off base here?
John k , December 20, 2018 at 11:42 am
Mmt cab be used to fund war or any other negative thing. Or build schools and hospitals.
One can be rational or irrational.a different chris , December 20, 2018 at 10:06 am
It's ironic that, having lived thru the 80's when the financial "geniuses" took over and it was all about ROI – Westinghouse somehow came to the conclusion that you could make 6% on golf courses (they didn't even know, I don't think) instead of 2% on industrials (that was probably correct) so they basically sold the store. Except for the nukes, sigh.
The comments above, apes's for instance, point to the whole slosh of money. And there is some truth to that. But in this case, I'm afraid much of the answer is that people in the oil bidness make oil wells because that's what they know how to do. ROI, Scmoi O I.
Of all the industries that are gone because they weren't allowed to "do what they know" because it was "cheaper to offshore" – read a greater ROI to Wall Street – how come the worst is the only one that keeps its nose to the grindstone and does the actual work it knows how to do?
Seamus Padraig , December 21, 2018 at 6:45 am
Because you have to drill where the oil/gas is actually located. You can't do it in China, where the labor would be cheaper.
a different chris , December 21, 2018 at 10:41 am
No, what I meant was those other ones just "diversified" or whatever the word of the moment was, just did whatever made the people at the top money.
But oil/gas is different. They just "have to go get it". It's like termites and wood. I respect that, even if it's the wrong thing to do. If I must refer to The Terminator again, "it's what they do. It's ALL they do".
PS: there is oil/gas everywhere. I worked in the "bidness,"btw.
Andrew John , December 20, 2018 at 12:52 pm
So frackers can take out billions of unpayable debt and discharge it in bankruptcy, but I get to carry a millstone of student debt around my neck for the rest of my life? Great system we got here. Pretty flipping great.
Ford Prefect , December 21, 2018 at 10:14 am
You should have issued a junk bond on yourself instead of taking a student loan. You could then just default on the junk bond (after having written some derivatives to short it to profit from your financial demise).
Mike R. , December 20, 2018 at 1:40 pm
I have a different take on all this fracking.
I believe it was decided at the highest levels of our government to support it; including financially if necessary. The basis for this support and secrecy would be national security. Easy enough to see how this could have transpired.All that said, if my theory is correct, the frackers will be bailed in some form or fashion. Probably the next QE will pick up the tab or perhaps the DOD is funding it indirectly already.
Just a theory, no pressure.
steven , December 20, 2018 at 3:50 pm
Your take parallels Pym of Nantucket's. Ever since the end of WWII, the United States has been allowed to just 'print money', first to pay for its contest with the former Soviet Union for global hegemony and then to 'pay for' its energy and the products its industries could no longer profitably produce – at least as profitably as they could by off-shoring those industries. This is all really just an extension of 'petrodollar warfare' – gigantic bluff the US can continue to go it alone if necessary – having salted the central banks of 'developing countries' with all the 'reserve currencies' they realistically need, at least if the depredations of the likes of George Soros are held in check.
In summary, fracked oil is propping up not just Big Oil but the US military industrial complex and ultimately Wall Street and its banks. As long as the US can control the world's access to energy (and possibly retard its transition to renewable sources?), US politicians and bankers can continue to 'print money' (i.e. export debt) and sustain the whole rotten edifice of US and Western 'political economy'.
As usual Michael Hudson has it right:
"Finance is the new form of warfare – without the expense of a military overhead and an occupation against unwilling hosts." It is a competition in credit creation to buy foreign resources, real estate, public and privatized infrastructure, bonds and corporate stock ownership. Who needs an army when you can obtain the usual objective (monetary wealth and asset appropriation) simply by financial means?
greg , December 20, 2018 at 11:38 pm
The time will come, as a result of this, that the US will have to go it alone. They are turning your money to shit. Unless our corporate masters sell out the rest of the country to foreigners, like they already have much of our nation's productive capital.We won't be alone, but like Greece, we will no longer be independent or free.
This kind of crap increasingly pervades our economy. Military. Finance. Healthcare. Like money with Gresham's Law, bad investment drives out good. Every cost is also someone's profit opportunity, so costs are magnifying and spinning out of control. More and more the welfare of society depends on 'borrowed' money.
It's like the modern day pyramids. Nicely dressed piles of rocks in the desert. Total waste and destruction of resources. It also destroyed the social capital of Ancient Egypt, and turned them into slaves of Pharoah. It was the people of Egypt who paid for the pyramids, with their labor and their liberties.
So that's what else is going on. Your freedoms are going down those wells. And up the towers of finance. The Egyptians, at least, got something to look at. They already had the barren wastelands.
Cynthia , December 20, 2018 at 1:40 pm
At least these depressed oil prices from over fracking in the US will make Saudi Arabia poorer. Possibly poorer to the point that widespread social unrest ensues there, leading to the dethroning of the House Of Saud, which, in turn, will cause the dethroning of their chief covert friend and ally Israel.
Then in order to stave off social unrest here in the US, we'll have to cut off ties with these two roguish troublemakers in the region. Much needed balance of power will then be restored to the region with Iran and Syria restored to their former glory, sparking peace and prosperity from Pakistan and Afghanistan to Egypt, Somalia and Yemen.
I don't know if the pieces on the chessboard will ever realign this way, but it's rather amusing to speculate that this realignment could possibly be triggered by the stupidity and shortsightedness of the US to over frack!
rd , December 20, 2018 at 4:22 pm
Russia as well.
Nick Stokes , December 20, 2018 at 7:11 pm
You got it backwards. KSA and Russia need lower oil prices to force US producers off the field and get their supply chains back. Your thinking like a 1970's person. Think 2010's.
rd , December 21, 2018 at 10:19 am
This is a non-climate change reason why developing electric vehicles in North America, Europe, and China would be good. It would strip away much of the demand for oil which is a major funding source for Russia and KSA.
Gene Prodersky , December 20, 2018 at 7:13 pm
Your thinking 20th century. KSA and Russia need lower prices to support their supply chain. Everything you said, think the opposite.
whiteylockmandoubled , December 21, 2018 at 12:47 am
Jesus Herbert Walker Christ. Is anyone else getting sick of this stupid series? If you keep writing the same article every year, and Wall Street keeps engaging in the same apparently irrational behavior, you might want to rethink your smug pose and ask yourself whether there might be some additional digging to do to understand what the hell is going on.
The contrast between this series and Hubert Horan's Uber work is striking. Horan not only points out the fact that Uber is unprofitable, but also clearly shows who has an interest in extending the hype, and how and why the bandwagon keeps rolling. This series is the complete opposite.
Fracking "investors" aren't getting ripped off, and they're not stupid. You've just completely missed half the point of the Master LImited Partnership structure. For the limited partners, the losses are a feature, not a bug. Until MLP shares are cashed in, they generate tax losses for the LPs. Those losses are valuable generally, but 501c3s, especially love them because they allow non-profits to offset Unrelated Business Income.
Go to Guidestar or Nonprofit Explorer and pull down the 990T of any nonprofit with a few billion dollars worth of invested assets. Line 5 (usually blank but filled in as a long attachment at the end) is almost invariably a who's who of the fracking industry, with thousands of dollars in losses from each company. In any given year, LPs only liquidate positions in a small number of the companies their holding each year, allowing them to avoid taxes with the annual losses, then cash in (at least sometimes) when the value of the company is high.
The industry's a scam, but just as much of the taxpayers as of the investors.
Yves Smith , December 21, 2018 at 3:10 am
Do you make a habit of putting your foot in your mouth and chewing? Because you did it here, by copping a 'tude while being 100% wrong.
Passive tax exempt investors have no use for losses. Zero. Zip. Nada.
An investor in a limited partnership is a passive investor. Income from a passive investment NEVER generates Unrelated Business Income. If the idiocy you presented was correct, no endowment or public pension fund could ever show a net profit from their investments in private equity and hedge funds without it being taxed as UBI. There would literally be no private equity industry as we know it because most of its money comes from tax exempt investors, namely public pension funds, endowments, foundations, private pension funds.
UBI results from activity conducted by the not for profit. The classic example is an art museum's gift shop. See IRS Publication 598 (emphasis ours):
Unrelated business income is the income from a trade or business regularly conducted by an exempt organization and not substantially related to the performance by the organization of its exempt purpose or function, except that the organization uses the profits derived from this activity.
https://www.irs.gov/pub/irs-pdf/p598.pdf
Limited partners are required to be passive and have nada to do with the operation of the partnership. They typically make double sure that their investment income won't be characterized as business income. As one tax expert confirmed by e-mail:
Endowments/exempts/pension funds can wind up having UBTI when they don't structure their investments through corporations. They rarely fail to do this structuring. They wouldn't put themselves in the position of deliberately incur UBTI and then go hunting for losses to offset it.
So it is possible that you heard of a not-very-competent endowment that wound up seeking tax losses, but that would be highly unusual, when you incorrectly said the opposite.
There are other tells that you don't even remotely understand the how limited partnerships work, such as your comment "In any given year, LPs only liquidate positions in a small number of the companies their holding each year, allowing them to avoid taxes with the annual losses."
Limited partnerships are pass-through entities. LPs receive their pro-rata share of income and loss annually. They do not need to sell to recognize gains or losses resulting from their participation in operations.
The mainstream journalist who first wrote about the pervasiveness of losses in fracking after oil prices started trading in the new normal of $70 a barrel and below, John Dizard of the Financial Times, explained why frackers would keep drilling at losses as long as they could get their hands on funding, so this is entirely consistent with his forecast. And Dizard's column is for wealthy individuals and he is conversant with tax issues, unlike you.
Better trolls, please.
Rajesh K , December 21, 2018 at 1:05 pm
Better than Ghost Cities in China!!!
Why? Not sure, but it's in Murica, has to be better right ;)
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Dec 27, 2018 | peakoilbarrel.com
shallow sand x Ignored says: 12/26/2018 at 4:43 pm
So to keep everyone happy, here are some averages for the all wells EFS, Bakken and Permian. Decided to exclude Niobrara, oil numbers are much lower.GuyM x Ignored says: 12/26/2018 at 5:38 pm2015 Q3 36 months of production: 162,635 BO most recent monthly rate 58.6 BOPD
2016 Q3 24 months of production: 169,078 BO most recent monthly rate 103.5 BOPD
2017 Q3 12 months of production: 136,850 BO most recent monthly rate 213.1 BOPDFor 2015 162,635 x .80 x $45 = $5,854,860
7% severance $409,840
$5 per BO LOE $650,540
$2 per BO G & A $260,216
Net = $4,534,264I lowered the costs some to make the economics more favorable from the standpoint of those who love the sub $2 gasoline. Might be ok to look at 10K and 10Q if anyone would like to plug in different cost estimates.
The 2016 wells described above are at $4,713,894 per well after 24 months.
The 2017 wells described above are at $3,815,378 per well after 12 months.Of course, I was just trying to make a point that wells drilled in 2015 that had seen 3 years of weak (and one year of average) oil prices were going to be total losers that would not payout within any reasonable time horizon, if at all.
To continue, there is no mention in these numbers of how much land costs. I seem to recall many Permian players paying $15-60K per acre. So a two mile DSU would cost $19.2 million to $76.8 million. I just ignored land costs completely. Further, each of these companies has interest expense. One can go to the 10K's and 10Q's to see how much that is costing each per BOE. I just ignored interest expense too.
These wells are a lousy investment at $50 WTI. Only gets worse as the oil price sinks.
I think this all started because maybe GuyM was actually giving some credence to EOG guidance. I don't blame GuyM, or anyone else, for believing what the companies say.
I do argue until we see some well payout data (hard data, not power point variety) from these companies, we should assume the wells generally do not payout within 36 months, or even 60 months.
I do agree, wells have residual value after 36 and 60 months. I also agree that much higher oil prices make this business a money maker. Finally, I agree the wells have improved every year, although it is looking like 2016 might have been the high water mark, with later wells not moving the needle much higher.
Time for me to exit for awhile. I was just trying to remind people of the numbers. I think most of the investing public has figured it out, based on where these companies are trading since oil dumped again.
Good analysis, and thanks, again. No amount of increased productivity could make them profitable at $45, especially not $37, or $16. The clock is ticking. Yeah, EOG has gone from over $120 to $87.
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Dec 22, 2018 | peakoilbarrel.com
GuyM x Ignored says: 12/20/2018 at 6:16 pm
Looks like a lot of bubbles bursting. Not likely to bounce back, so not much financing available to float pure Permian players. Doesn't look good for any increase in production. Oil prices will probably stay low with Dow for awhile. Until inventories get closer to zero. Madness.dclonghorn x Ignored says: 12/20/2018 at 10:12 pmInteresting article from Goehring investment bank. They estimate that KSA remaining reserves are around 50 billion bbls, instead of the 260 b claimed. They also (surprise) think that was the reason the Aramco IPO was pulled. I also thought the Aramco IPO would never happen because they would not be able to buy an acceptable reserve report.Iron Mike x Ignored says: 12/20/2018 at 11:59 pmhttp://blog.gorozen.com/blog/what-is-the-real-size-of-the-saudi-oil-reserves-pt-2/2
Fifty billion does seem low, however its probably much closer than KSA's 260.
Interesting, they are probably right.dclonghorn x Ignored says: 12/21/2018 at 6:15 am
I knew Aramco would pull out of the IPO. They are one of the most secretive companies. How you going to float on the NYSE or London SE with no transparency, which is required by law.
50 billion sounds about right in my worthless opinion. Interestingly enough that would be more or less close to the Permian basin reserves.
I think peak oil will arrive without many people noticing until after it has occurred.A few more thoughts about the referenced Goering report.First, the basis or their report: "We have good data going up to 2008, however after that point data becomes difficult to find."
Does anyone else have good data on Ghawar production through 2008. Actual Saudi production data is hard to come by, and I would like to see a table of Ghawar production through 2008 if it is out there.
Based on their 2008 data they have included a Hubbert Linearization which is the basis for their claim.Second, if their production data and linearization are correct, they have not been adjusted for improved results from better technology. I believe the multi lateral super wells Saleri described in his 2005 SPE paper have allowed KSA to recover several percent of additional original oil in place, as well as to maintain high production rates longer.
Third is that it appears many of those super wells were drilled beginning in mid 2000's. It would make sense that the change in Saudi attitudes regarding production restraint between 2014 and now could be due to those multilateral wells watering out.
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Dec 22, 2018 | peakoilbarrel.com
shallow sand x Ignored says: 12/20/2018 at 7:54 pm
Coffee. I hope if you have been investing in the Appalachian gas players that you have been short.Coffeeguyzz x Ignored says: 12/20/2018 at 9:02 pmThe only investment class in oil and gas that may be worse over the past ten years would be the service sector, particularly the drillers.
Interesting that, despite all the activity, the US onshore drillers are becoming penny stocks. I have pointed out Nabors. The rest are all tanking bad it appears.
You made a big deal out of a very long lateral operated by Eclipse Resources. Eclipse equity closed at 76 cents a share.
I am not so sure that ultra cheap oil and gas is such a great thing for the US, given we are now the world's largest producer of both.
Shallowshallow sand x Ignored says: 12/21/2018 at 12:31 amI never have, nor will I ever in the future, take any financial stake in these or any other companies.
As I have stated numerous times over the years, my primary interest is in operations who is doing what, how it is being done, who is doing it better – or claims to be.
My initial interest in this site way back when was to learn why some people seemed to think this so called Shale Revolution was No Big Deal a retirement party, in the words of Berman.
It was quickly apparent to me that a great deal of unawareness vis a vis industry developments permeated this site's participants.
This, alongside several predisposing factors to NOT want the shale production to explode upwards provided fertile grounds for the soon 12 to 16 million barrels per day US oil production, along with 100+ Bcfd gas production to be a spectaculsrly unforseen reality.
What I prefer or not prefer is secondary to what I believe to be occurring, shallow.
If anyone cares to spend 3 minutes reading the April, 2017 USGS press release accompanying the Haynesville/Bossier assessment, they will read the following from Walter Guidroz, Program Coordinator of the USGS Energy Resources Program
"As the USGS revisits many of the oil and gas basins of the US, we continually find that technological revolutions of the past few years have truly been a game changer in the amount of resources that are now technically recoverable".
Addendum Eclipse is being shut down/folded into another entity.
The lead engineer behind their ultra long laterals is now working with the new outfit from which this technology will continue to spread.No offense meant coffee. I know some who post here like to tangle with you. I am not interested in that, just straightforward discussion.Shale has surprised the heck out of me, and has made me several times strongly consider liquidating my entire investment in oil and gas, absent maybe keeping just a couple of KSA like cheap (to quote PXD CEO) LOE wells to fool around with. Had I known in 2012-13 that this was coming, would have sold all but those few "piddle around with wells." It has been absolutely no fun when these price crashes occur, and is especially no fun knowing that this shale miracle is less profitable than an operation producing less than one bopd per well from very, very old and tired wells.
You have to admit that the way the shale is being developed is destroying the oil and gas industries that are developing it.
Particularly hard hit are the service companies, many which are already bankrupt.
Even XOM, which I have owned for many, many years (prior to the merger, I owned both Exxon and Mobil) has hit the skids, having fallen through the $70 per share barrier.
Range Resources is at $10.26, a level not seen since 2004. It traded as high as $90 before the 2014 crash.
EQT was over $100. Today $18.55
Whiting was nearly $400 (accounting for a reverse split) and now is $21.98
CHK closed at $1.84. All time high was $64.
Nabors Industries, the largest onshore US driller closed at $2.09. Traded at split adjusted $10 in 1978.
Halcon Resources Corp. was over $3,000 split adjusted at one time, went Ch 11 BK, now at $1.65, looking not so good re: BK again.
We shall soon see who can access what in the way of capital to keep going assuming oil prices stay below $50 WTI for a considerable time.
I guess I am always concerned about whether businesses make money. Seems to me that would be of some importance to you, but it isn't, and I suppose there is no harm in that.
I have yet to work anywhere where making money was not the primary motivation.
If the money wasn't important, the shale executives would not make so much of it, I suppose.
I have always had a hard time understanding why they kept drilling wells in Appalachia when the gas was selling for 50 cents per mcf. Not important to you, but maybe to others.
Anyway, if we didn't have different views, places like this wouldn't be very interesting.
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Dec 14, 2018 | peakoilbarrel.com
Eulenspiegel, 12/12/2018 at 12:44 pm
In other sources US growth is more 1.9 mb/year, source is Rystad:GuyM, 12/12/2018 at 2:04 pmhttps://oilprice.com/Energy/Crude-Oil/OPEC-Came-Up-Short-Heres-What-They-Should-Do.html
Looks like the USA is supplying half of the world soon at these growth rates.
As far I know Bakken is still pipeline limited the next time, so no growth from there?
So it falls most to GOM, Eagle ford and Permian, which can grow without pipelines?
EF does not have pipeline problems, but it is not going to grow at $55 or less oil price. If prices rise to $80, yes. But, the price will need to be consistent for a good long while.GOM has hit its high back in August according to SLa and George.
We won't have much, or any growth in the first half of 2019, no matter what the hype is, unless prices spike.
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Dec 14, 2018 | peakoilbarrel.com
ProPoly, 12/13/2018 at 12:35 pm
Yeah, seems highly unlikely at best that Eagle Ford will ever regain its high. Even the EIA forecast – notorious blue sky that it is – only gets it back to 1.5 million bpd. And that on a theory of producers shifting from Permian due to logistical constraints in the latter.It's a mature area, only so many decent spots to drill.
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Dec 08, 2018 | peakoilbarrel.com
Survivalist, 12/06/2018 at 6:43 pm
My apology if this was posted on the last thread; an Interesting article from Jean LaherrereGoneFishing, 12/06/2018 at 7:07 pmThoughts on the Future of World Oil Production
https://www.resilience.org/stories/2018-12-05/thoughts-on-the-future-of-world-oil-production/
I hope the oily side of the blog finds it interesting.
Great article, thanks. Author says US LTO will be done by 2040, which makes sense. The speed and acceleration of sinking oil production is critical since we have not been strongly pursuing alternatives. If the production is down 50 percent by 2030 to 2035 it's going to be a tough go. If it falls faster then we are in severe trouble.Dennis Coyne, 12/07/2018 at 10:38 amGone Fishing,Michael B, 12/06/2018 at 9:33 pmJean Laherrere knows a lot, but on LTO I think he may be wrong.
From the piece linked above:
The best approach for forecasting future production is the extrapolation of past production (called Hubbert linearization). For Eagle Ford the trend can be extrapolated toward an ultimate quantity of 3 Gb.The USGS estimates about a 12.5 Gb mean for the TRR of the Eagle Ford, when economics is considered the URR might be reduced to 10Gb under a reasonable oil price scenario (AEO 2018 reference oil price scenario).
Recent USGS estimates for the Permian Delaware Basin have lead to a revision of my US tight oil estimate to a mean of 74 Gb with peak probably in 2025 to 2030. Decline will be relatively steep from 2030 to 2040, if the USGS estimates for the US tight oil resource prove correct.
This is a terrific article. It takes all the confusions around oil and articulates them beautifully. His review really makes me want to buy the book.yvest, 12/07/2018 at 7:03 amThis is a delight to me because while I've always liked Laherrere's charts, I find his English writing atrocious (not all his fault as a native speaker of French). This could alienate lay readers, which is too bad because his message really needs to get out there.
The uncertainties he notes are shocking. That we have spent the last ten years pissing away our remaining "pennies" on a driving spree, instead of using it to build a renewable future, really makes me think that the backside of the peak is going to be awful.
Laherrere's knowledge is magisterial. Good on the editor who worked with him on this.
Indeed the amount of work that Jean is producing is truly quite amazing. By the way what about Kjell Aleklett ? According to his blog he didn't publish anything since 2017, the case ?Jeff, 12/07/2018 at 7:07 amThe "issue" with Jean is that he also is a climato skeptic (regarding CO2 effects) and this has been detrimental to his ressource studies.
But one exercice in comparing the urgencies (taking the IPCC models just as they are), and feeding them with the resource aspects of Laherrere, clearly shows that peak oil or even peak fossile is the most urgent matter (knowing that anyway the mitigation measures, dimishing fossile fuels burning, are usually the same, except stuff like CSS, that will most probably never happen anyway).
Some elements (and Laherrere charts) in below post about this, sorry in French, but should go ok in gg translate :
http://www.oleocene.org/phpBB3/viewtopic.php?p=2275983#p2275983Also below ppt in English from B Durand and Laherrere :
http://aspofrance.viabloga.com/files/BD_Fossils_Fuels_Ultimate_2015.pdfAleklett has retired.yvest, 12/07/2018 at 7:11 amOk but the case also for Laherrere, and since 20 years or something !yvest, 12/07/2018 at 7:09 amAnd on this subject the most impressive chart is probably below one :Dennis Coyne, 12/07/2018 at 10:42 am[img] https://iiscn.files.wordpress.com/2018/12/lahererre-et-scenarios-giec.png [/img]
Overall the terrible deficit of the "resource message" compared to the climate/CO2 one, could be seen as a key reason for no measures being taken for the two aspects
Guym,GuyM, 12/07/2018 at 11:20 amLaherrere also suggests a 3 Gb URR for Eagle Ford where the USGS TRR mean estimate is about 12.5 Gb and when economic assumptions are applied the ERR is probably about 10 Gb.
You are much more familiar with the Eagle Ford, at $80/b (2017$) does a 3 Gb URR estimate seem correct?
Seems low.Dennis Coyne, 12/07/2018 at 11:50 amGuym,GuyM, 12/07/2018 at 12:52 pmThanks. Does 10 Gb seem reasonable or is that too high? Average of USGS mean and Laherrere's estimate would be about 6.5 Gb, again you know the area so your estimates would probably be better than most.
It's pretty difficult to measure with strictly an $80 price. Some depends on gas price. There are three windows in the EF. Oil, gas/condensate, and mostly gas. Gas has barely been touched, and is the biggest window. Geologically older. It still will produce some oil and condensate. If any, it will be mostly condensate. But it is still production as yet mostly untouched. Gas/condensate has been drilled, and is responsible for the higher api coming out of the EF, but in the past few years, less has been drilled due to the api. Oil window is being drilled, but there is still plenty of tier two and three areas to go. Not so much tier one. How do you measure that, and at what oil and gas price. I would say 12 is possible, but it includes a lot of condensate and gas.Dennis Coyne, 12/07/2018 at 1:01 pmYou could look at the USGS assessment of the Delaware in the same light. It may be there, but is it cost productive? You may only get gas and/or condensate, depending on geological age of the formation. Or, you may have to keep chasing after anything, as it moves quickly as wells are drilled.
Thanks for the correction. Yes Gas prices would also be needed. The 10 Gb was C+C and yes there is probably lots of condensate. I guess I would make it $4/ MCF for NG, you would probably need condensate and NGL prices to do a full analysis, way too many moving parts for me.GuyM, 12/07/2018 at 1:21 pmGot that right. Here's my cracker jacks geology assessment in the Permian. midland and Delaware basins are slightly different, but the both have a wolfcamp as the lower level. It's primarily a shale from my view of core samples. From the Bone Springs to the bottom wolfcamp, there is no clear formation that acts as a container, Bone Springs looks like it is closer to a sandstone, but closely formed from my view of the core samples. Not conducive to water flooding due to lack of "walls". But, because of the lack of walls, the oil/condensate/gas travels when wells are drilled. Indications are that EF has the same problems, but not as fast? Very simplistic, and possibly wrong viewpoint.Doug Leighton, 12/06/2018 at 6:51 pmAnd there is a fairly wide variety of prices depending on what comes out. I'm still trying to figure out my pay Stubbs.
LARGEST CONTINUOUS OIL AND GAS RESOURCE POTENTIAL EVERMichael B, 12/06/2018 at 9:35 pmToday, the U.S. Department of the Interior announced the Wolfcamp Shale and overlying Bone Spring Formation in the Delaware Basin portion of Texas and New Mexico's Permian Basin province contain an estimated mean of 46.3 billion barrels of oil, 281 trillion cubic feet of natural gas, and 20 billion barrels of natural gas liquids, according to an assessment by the U.S. Geological Survey (USGS). This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically recoverable resources.
https://www.sciencedaily.com/releases/2018/12/181206135643.htm
I'll be curious to hear others' assessments of this. Zinke is really jumping up and down with the pom-poms on this one.GuyM, 12/06/2018 at 10:49 pmThe Easter Bunny, Santa Clause, Tooth Fairy, but no Trolls? Conventional? They are out of their Fxxng minds. Dept of the Interior is sharing the same hospital suite with the EIA. Both digging for that phantom oil.Dennis Coyne, 12/07/2018 at 10:44 amSomebody ought to tell the oil companies to quit using all this fracking stuff. All they need to do is drill straight down. Sheesh!
Guym,GuyM, 12/07/2018 at 11:56 amYour estimate of Permian Basin URR is ? Generally the USGS does a pretty good job in my opinion.
I'm not a geologist, but your original projections peaking in 2025 appear reasonable to me. Slow peak, not a huge peak like some. To add to that, JG Tulsa (below post), who is a working geologist in the area, agrees with a mid 2020's peak. I'm not stupid enough to argue with expertsDennis Coyne, 12/07/2018 at 1:05 pmGuym,GuyM, 12/07/2018 at 1:50 pmYou are clearly smarter than me. I do tend to listen when geologists and geophysicists try to educate me.
Here is a preliminary estimate for US LTO assuming USGS mean estimates are correct, the Permian is up to date, but the older Bakken, EF, Niobrara, and US other LTO scenarios need to be revised to reflect the AEO reference oil price scenario. Peak about 9 Mb/d in 2025, also shown is an older estimate from June 2018 (before the recent Delaware Basin Wolfcamp and Bonespring assessment from the USGS.)
I think your original is closer to reality.Coffeeguyzz, 12/06/2018 at 11:11 pmThis 46 billion barrels oil – along with 20 billion barrels NGLs and 281 Tcf gas – is for the Delaware Basin Wolfcamp and Bone Spring only.Dennis Coyne, 12/07/2018 at 8:54 am
Combined with the earlier Midland Basin assessments of the Wolfcamp and Spraberry of 24 billion barrels combined, the total so far Technically Recoverable Resource is over 70 billion barrels oil.Just as the Haynesville jumped from 39 Tcf to over 300 Tcf as the Haynesville/Bossier, the Mancos from 1.6 to 66 Tcf, the Barnett from 26 to 52 Tcf, the Bakken/TF will jump next assessment and both the Utica and Marcellus will skyrocket.
Coffeeguyzz,Watcher, 12/07/2018 at 2:55 amI know less about Marcellus, but Bakken/Three Forks was recently assessed in 2013, the new assessment may be an increase, but I won't speculate in advance what it will be.
The 46 Gb mean undiscovered TRR for the Wolfcamp (Delaware Basin) and Bonespring is a surprise to me, based on this the Permian tight oil TRR would be about 74 Gb, before this assessment I had guessed 8 Gb for Delaware Wolfcamp based on output compared to Midland Wolfcamp (it was about 30% of Midland so I took the 20 Gb Midland Wolfcamp times 0.3 and rounded to 8 Gb). My previous mean estimate for Permian tight oil TRR was 38 Gb, so I was too low by more than a factor of 2. My F5 (5% probability TRR might be higher) estimate was 54 Gb before and the F95 estimate was 20 Gb, these are revised to F95=43 Gb and F5=113 Gb.
For the entire US I had a previous TRR estimate of 70 Gb for all of the US, this is revised to 107 Gb for the mean US tight oil TRR.
An interesting development that might push the US peak in tight oil a little later and/or a little higher. My F5 model had the Permian peak at about 7.5 Mb/d in 2027, a new model might result in 2029 at 9.5 Mb/d, for the US as a whole, other tight oil plays might be declining by 2029, so the overall US peak might be 2027 or 2028, based on current information.
https://pubs.usgs.gov/fs/2018/3073/fs20183073.pdfWatcher, 12/07/2018 at 3:19 amThe formal report. The references are . . . a bit odd. There is a sense the whole thing is dependent on technology results assessment from IHS.
Meaning, I don't see anything here that suggests USGS sent teams out to look at rock for this whole area. They seem to have taken info from other IHS papers -- and the recent ones from USGS were for what looks like much more limited geographic areas. Looks like IHS encouraged extrapolation.
Btw someone at Bloomberg has declared this is a X2 on previous estimates. That would suggest 46 billion barrels of oil we're not just added to the US resource database. It would be more like 23.ProPoly, 12/07/2018 at 9:49 amThe Bloomberg guy didn't seem all that sharp, and so let's not take that as gospel.
Probably worth noting that it would not take much variance to move this resource into an API 45+ or even 50+ configuration, and given the NAT gas and NGL estimates, that would seem a pretty credible scenario. In which case it's not oil.
"Extrapolation" fits with it being undiscovered TRR.Dennis Coyne, 12/07/2018 at 10:17 amThis reminds me a lot of ANWAR (wasn't oil) and Monterey (not actual technically recoverable, our bad).
The Monterrey estimate was a study done for the EIA which was poorly done (it was not a USGS estimate), the USGS estimates tend to be pretty good and have tended to be on the conservative side, though we won't know for sure until all the oil is produced and the last well is shut in. Every resource estimate involves extrapolation and/or modelling of future well output by definition.Dennis Coyne, 12/07/2018 at 9:58 amSome estimates are better than others, for example the USGS estimates are better than the EIA estimates in most cases.
Thanks Doug,Dennis Coyne, 12/07/2018 at 10:10 amPreviously I has guessed (incorrectly) that Permian mean TRR would be 38 Gb, this new assessment would lead to a revision to about 74 Gb for mean TRR of the Permian Basin tight oil resource.
In the scenario below I have a 253,000 well scenario (about 6 times more than my ND Bakken/Three Forks mean scenario with 42,000 wells completed.) I assume new well EUR starts to decrease in Jan 2023(about 3 years after my estimate of the future ND Bakken EUR decrease start as Permian ramp up started about 3 years after Bakken). This assumption is easily modified.
Peak is about 2028 with peak output at about 7000 kb/d (currently Permian tight oil output is about 2750 kb/d based on EIA tight oil production estimates by play).
The scenario above does not consider economics. When we consider the discounted net revenue over the life of the well and assume this must equal the real well cost in order for the well to be completed using the assumptions below, then we find an economically recoverable resource (ERR) scenario.GuyM, 12/07/2018 at 10:25 amEconomic assumptions (all costs in constant 2017$) are:
real oil prices in 2017$ follow the EIA AEO 2018 Reference Brent Oil Price scenario
royalties and taxes are 32% of wellhead revenue
transport cost is $4/b
OPEX is $2.3/b plus $15000 per month per well
real annual discount rate is 7% (nominal rate is 10% at 3% annual inflation rate)
real well cost=9.5 million 2017US$Peak output is unchanged but wells completed are reduced to 173,000 and ERR=60 Gb.
The indications from drilling companies, so far, operating in the Delaware do not seem to jive with the assessment of grandiosity. So, I am more than skeptical. The government can create all the reserves they want, but if the oil companies can't get it out of the ground?? My understanding is that there is a core area in West Texas and NM. EOG is there. Extends a few Counties in West Texas and NM starting around Loving County. Even there, it is high api. Outside of that, it is highly sporadic. If you extrapolate what they are doing in tiny Loving County to the rest of the Delaware, you can come up with these numbers. But, you can't. As I read, there are over 800 Ducs outside of this area. You leave them as Ducs, because you pretty much know what the completion will look like after drilling. Basically, the report is hogwash. It's pretty easy to tell on the Texas side, as you can pull up completions by county.Dennis Coyne, 12/07/2018 at 10:53 amGuym,JG Tulsa, 12/07/2018 at 11:10 amIt may require higher oil prices and the associated gas is a problem, not enough infrastructure to move it.
Also the USGS simply does a resource assessment, these are not reserves, no economic assessment was done, the USGS leaves that to others.
I have often been skeptical of USGS Assessments (such as Bakken Assessment in 2013), looking at proved reserves and cumulative production to data in the ND Bakken/Three Forks, the 11 Gb mean TRR estimate from 2013 looks pretty good.
This may look different in 2023.
As a working petroleum geologist in the Delaware Basin and others, I will say USGS and EIA assessments are considered a joke. They do little to take into account the actual geology, or changes in the thermal maturity of the rock across a basin, it is more multiply an average well performance for a certain amount of acres drilled, times the total area of the basin, minus the number of drilled wells.GuyM, 12/07/2018 at 11:22 amEverything is more complex than that. Right now operators are drilling the best, most economic parts of the Delaware basin, at the going rate it will not be too many years before they have to shift over to other benches of the Wolfcamp or Bone Spring, which will be less productive. for deeper Wolfcamp benches you get more condensate, less oil, much more gas, you might go from a 10,000′ lateral making 1-2 MMBO in the Wolfcamp A, down to one making 300-500 MBO.
Still a decent well when you add in the gas, but if you take that across a large area that will lead to a substantial decline in new well performance. I would not doubt oil production peaks in the mid-2020s as people drill up the best rock, and have to keep shifting to less productive horizons.
Thank you. That was my take on all, but I'm no geologist. Nice to have a professional opinion.Dennis Coyne, 12/07/2018 at 1:21 pmThanks JG Tulsa,GuyM, 12/07/2018 at 4:59 pmCan you give us your estimate of the TRR or ERR of the Delaware Wolfcamp and Bonespring. There is a wide range in the USGS TRR estimate from 27 to 71 Gb with a mean of 46 Gb and a median of 45 Gb. Would you say that 27 Gb is too high? It seems clear you think that 46 Gb is far too optimistic. Note that the mean ERR would probably be around 38 Gb if the mean TRR estimate was correct and prices follow the AEO 2018 reference price scenario. For the F95 USGS TRR estimate the ERR would be around 21 Gb.
Maybe you could also comment on other USGS assessments for Eagle Ford, Wolfcamp Midland basin and Spraberry. Perhaps you could give us the "correct assessment".
I agree the EIA assessments are not good, economists do not know much about geophysics. The people at the USGS are scientists, though they have limited information and thus use statistical analysis to fill the data gaps.
Come on, Dennis. He may be a geologist, but my bet he is mortal, like you and I. I really believe your first graph with 8 million as the high is the best I have seen. The tail of that is probably not ever to be properly guessed, until it happens.Watcher, 12/07/2018 at 2:53 pmDood, one of the most frequent points we deal with on this blog is the claim that technology in horizontal fracking has multiplied output tremendously -- excluding from consideration stage count/length.GuyM, 12/07/2018 at 3:57 pmThe extra production "per well" seems to be from the well being longer in length and thus consuming more water and proppant. Is this true, or is there some magical improvement in proppant type or fracking pressure or whatever?
It's mostly the length of the lateral, although some is due to increased fracking stages within the lateral (more holes in the pipe). Better drilling is another, although extra lateral makes up most of it. The laterals, in general, are about twice as long.Michael B, 12/07/2018 at 8:41 amUS becomes a net oil exporter.Watcher, 12/07/2018 at 11:33 amHanh? And this paragraph strikes this lay reader as utterly incoherent:
The U.S. sold overseas last week a net 211,000 barrels a day of crude and refined products such as gasoline and diesel, compared to net imports of about 3 million barrels a day on average so far in 2018, and an annual peak of more than 12 million barrels a day in 2005, according to the U.S. Energy Information Administration.
From EIA: "In 2017, the United States consumed about 19.96 million barrels per day." Let's call it 20.
Also from EIA: US weekly field production ending 11/30: 11.7 million barrels.
20-11.7=8.3????
True? Fudging? Lying? What am I missing?
Then, you read further into the article:
While the net balance shows the U.S. is selling more petroleum than buying, American refiners continue to buy millions of barrels each day of overseas crude and fuel. The U.S. imports more than 7 million barrels a day of crude from all over the globe to help feed its refineries, which consume more than 17 million barrels each day.
WTF.
It's all measured in barrels.Michael B, 12/07/2018 at 1:38 pmThe US refines a lot of imported oil -- for export. There is refinery gain in this. This means a barrel comes in. It is refined to various constituent parts like gasoline, diesel, kerosene, etc. The VOLUME of these parts are liquids of less density and this means their volume is greater. So a barrel of crude will yield a sum total of more than 1 barrel of liquids of lower density. Since these products are exported, the barrel count is in favor of exports vs the barrel count imported.
This is not a huge effect, but it's significant.
There's an EIA page for US sales volume consumed. If you add up all the products you get well over 15 million bpd. US production is rather less than that. Imports must exceed exports.
Thanks for trying to explain it to me. Maybe it's just too complicated for me to understand.kolbeinh, 12/07/2018 at 1:41 pmI still can't reconcile the headline, "US becomes a net oil exporter" with the EIA's numbers: The US consumes 20 million barrels a day. The US produces 12 million barrels a day. But, yes, they're net exporters. Whatever.
After 14 years, the niceties of peak oil still escape me.
I am not sure I follow you entirely, but for heavier crude oils there is waste to get to diesel (a bit higher than 30 API). And for extra light oil there is a huge waste to get to diesel, as much has to be segregated to petroleum gas and gasoline components due to length of carbon chain.Watcher, 12/07/2018 at 2:50 pmThe case for diesel shortage in 2020 due to shipping legislation is still very much legit.
I was talking about imported crude (that would not be LTO and probably diesel rich) being refined into a larger number of barrels of product vs the barrels of input crude. They export. It's a bias towards export.Eulenspiegel, 12/07/2018 at 8:55 amI think mostly the report derives from very noisy weekly data. The US is not a net exporter.
So the oil cut is out: 1.2 mb. Together with russia and others. So LTO is saved, the frenzy can go on soon.
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Dec 08, 2018 | peakoilbarrel.com
kolbeinh , says: 12/07/2018 at 9:45 am
Yes, it is all a big show!GuyM , says: 12/07/2018 at 5:18 pmThe peak oil theme is very much forgotten in all the turmoil, but is very real still.
How much more reserves to classify as probable (2p) is a movable target, it depends on the oil price.
And how rapid the extraction rates of reserves can extend to difficult to say; technology and not at least the 3D maps of reservoirs coupled with improved seismic data, more precise drilling and lower costs due to excess oil service capacity (at least for offshore) have countered the inevitable declining quality of oil reservoirs and size of new ones coming online for some time now.
I agree that 2019 will show big declines in OECD inventory primarily because core OPEC wants it. (increasing KSA premiums to the US +3,5 dollars in Jan and lowering it to Asia).
The next question is how high oil prices will go before there is some reaction from the nations that have spare storage/capacity. I am thinking there is some relief in increased pipeline capacity in Texas in 2H 2019 and also Johan Sverdrup in Norway (since I follow things close to home) in the same time period to save the oil market in winter 2020.
Or still more likely, a spike in oil prices in 2H 2019 and a recession soon thereafter.
Who knows..the only thing certain is that oil is being pressured towards the final "spare capacity" (whatever that is) and that a recession will come anyway as a result of the low oil price environment the last 4 years.
Offshore is hit hard, so are supply in places "too risky" for cheap financing the hidden secret of the oil market (why so few news stories covering this?)
Saved from $40 oil, but I really doubt there will be much of a frenzy at $52 oil price. Hopefully, that will give them enough cash flow for stationary. They need to write Christmas letters to their shareholders telling them everything will be better next year.
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Nov 24, 2018 | peakoilbarrel.com
Fred Magyar x Ignored says: 11/22/2018 at 11:34 am
https://cleantechnica.com/2018/11/22/peak-oil-drastic-oil-shortages-imminent-says-iea/Ron Patterson x Ignored says: 11/22/2018 at 1:59 pmLOL!
Peak Oil & Drastic Oil Shortages Imminent, Says IEA
LOL!Fred Magyar x Ignored says: 11/22/2018 at 4:18 pmSorry Fred, but that joke just went right over my head. Why am I not laughing?
Twas a sarcastic laugh at the expense of the IEAGeorge Kaplan x Ignored says: 11/23/2018 at 2:21 amThat discovery chart shows the problem well, I hadn't seen it before. The big blip in deep water discoveries in the 2000s from improved technologies and higher prices contributed greatly to the subsequent glut and price collapse – and now what's left? There hasn't been much of an uptick in exploration despite the price rally, offshore drillers continue to go bust, leasing activity still fairly slow – the tranches get bigger as the last, less attractive bits are released but lease ratio falls, Permian dominates all news stories. Why would the recent decline curve turn around? And the biggest surprise might be that gas is just as bad as oil, so the recent boost in supplies from condensate and NGL might also have run its course.Survivalist x Ignored says: 11/23/2018 at 9:33 amSo we need to bring on approx 40 million barrels a day by 2025 to stay flat?George Kaplan x Ignored says: 11/23/2018 at 12:31 pm
Should be an interesting 7 years!I tracked FIDs for oil through 2017, I've been a bit less diligent this year so may have missed some, but for greenfield conventional plus oil sands I have for the remainder of 2018 through 2025: 400, 1770, 1170, 800, 985, 70, 250, 400 kbpd added – about 6 mmbpd total, nothing after 2025, plus another 1 mmbpd from ramp ups from this year. Only pretty small projects could get done now before 2022, and there aren't many of those left. Anything else would need to come from brownfield (in-fill), LTO or new discoveries (including existing known resources that become reserves once a development decision is made).Hugo x Ignored says: 11/23/2018 at 5:34 amGDP and Energy consumptionFred Magyar x Ignored says: 11/23/2018 at 5:46 amThe link between GDP and energy consumption is very clearly shown in the graph.
https://ourfiniteworld.com/2012/10/25/an-economic-theory-of-limited-oil-supply/comment-page-2/
High economic growth matched high growth in energy consumption and recessions saw fall in energy consumption.
Since 90% of the energy consumed comes from burning the stored energy in coal, oil, gas and wood. It is hardly surprising that during high economic growth CO2 emissions increase also.
Those who not not wish to see this link, obviously think Peak Oil is not a problem. GDP growth will continue even though oil becomes more scarce.If oil production falls by just 1% per year, taking into account new vehicle production. The world would have to produce 90 million electric cars each year in order to prevent oil prices from destroying other users such as the aviation industry.
This year 1.5 million fully electric cars were made and according to several people here peak oil is no more then 4 years away.
Since 90% of the energy consumed comes from burning the stored energy in coal, oil, gas and wood. It is hardly surprising that during high economic growth CO2 emissions increase alsoHugo x Ignored says: 11/23/2018 at 7:40 amI have a hunch that we are about to see some major changes to that paradigm.
FredHickory x Ignored says: 11/23/2018 at 12:21 pmI hope you are correct, but I have done some calculations on what is needed.
According to reports around $1.7 trillion was invested in energy supply in 2017. $790 billion on oil, gas and coal supply. $320 billion was spent on solar and wind.
During 2017 oil consumption increased by 1 million barrels per day. Gas consumption increased by 3% and even coal consumption went up.The world needs to spend about $2.5 trillion per year on wind, solar and batteries in order to meet increased energy demand and reduce fossil fuel burning by about 1% per year. This obviously depends on GDP growth being about average.
Since recent scientific observations have discovered that Greenland, the Arctic and Antarctica melting much faster than anyone thought. The shift needs to be a minimum of 2.5%. Thus a spending of around £4 trillion per year is needed.
I do not see any country spending a minimum of 12 times more on solar and wind in the next 3-5 years. It would take every country doing so.
Agreed Hugo. The world is only making token moves towards installation of the necessary wind and solar.GoneFishing x Ignored says: 11/23/2018 at 12:44 pm
This coming decade will see everyone scrambling to get the equipment built and installed.
Looks like centralized planning (China) is going to beat 'the market' on being the primary supplier. Our 'free' market has tariffs on PV imported. Brilliant.
Does having a 5 (or 10 yr) plan make you communist?
Or just smart."The world needs to spend about $2.5 trillion per year on wind, solar and batteries in order to meet increased energy demand and reduce fossil fuel burning by about 1% per year. This obviously depends on GDP growth being about average."HuntingtonBeach x Ignored says: 11/23/2018 at 5:14 pm
1% per year? You have got to be kidding.
The global oil consumption for transport is about 39.5 million barrels of oil per day. Using PV to drive EV transport would mean an investment of 2.2 trillion dollars in PV to provide global road transport energy.
So what do we use next year's money for?
."The global oil consumption for transport is about 39.5 million barrels of oil per day"GoneFishing x Ignored says: 11/23/2018 at 6:51 pm39.5 million is only gasoline in the world. Add diesel and jet fuel and you get to about 75 million barrels a day for transportation or about 75% of oil produced.
I was specifically talking about road transport.Hickory x Ignored says: 11/24/2018 at 12:33 am
Argue with these guys.
https://www.statista.com/statistics/307198/forecast-of-oil-consumption-in-road-transportation/Did you get the point? That Hugo overstated the cost of renewables to replace fossil fuels by a huge amount and understated their effect by another huge amount.
We have a couple of people that consistently do that on this site.You may have just been talking about transport energy, but the others of us were having some back and forth about fossil fuel replacement in general.
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Nov 16, 2018 | peakoilbarrel.com
likbez says: 11/16/2018 at 1:42 am
Shallow sand mentioned EV as a sign that oil consumption might go down.I view EVs as inefficient natural gas powered cars, or worse. And the key problem is its lithium battery. See http://www.epa.gov/dfe/pubs/projects/lbnp/final-li-ion-battery-lca-report.pdf
The cost of producing a large lithium battery is high and it is "perishable product", which will not last even 10 years. The average life expectancy of a new EV battery at about five (Tesla) to eight years. Or about 1500 cycles (assuming daily partial recharge, which prolongs the life of the battery) before reaching 80% of its capacity rating. https://www.quora.com/What-is-the-cycle-lifetime-of-lithium-ion-batteries
Battery performance and lifespan begins to suffer as soon as the temperature climbs above 86 degrees Fahrenheit. A temperature above 86 degrees F affects the battery pack performance instantly and often permanently. https://phys.org/news/2013-04-life-lithium-ion-batteries-electric.html
It is also became almost inoperative at below freezing point temperatures. For example it can't be charged.
So they need to be cooled at summer and heated at winter. Storing such a car on the street is out of question. You need a garage.
And large auto battery typically starts deteriorating after three years of daily use or 800 daily cycles.
Regular gas, and , especially, diesel cars can last 20 years, and larger trucks can last 30 years.
Recycling of lithium batteries is problematic
http://users.humboldt.edu/lpagano/project_pagano.htmlIn a way EVs can be called "subprime cars." Or "California cars", if you wish (California climate is perfect for this type of cars)
Switching to motorcycles for personal transportation can probably help more in oil economy aria then EVs.
That also suggest that "peak oil consumption" for the next five to ten years remains a myth.
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Nov 15, 2018 | peakoilbarrel.com
Mike Sutherland x Ignored says: 11/14/2018 at 10:19 pm
This fracking can't go on much longer. They've drilled out much of the sweet spots already, and from what I hear, there are already 7 'child' wells being drilled for every 'parent' well. (as I understand it, a 'child' well is drilled in close proximity to the 'parent' without – hopefully-hitting and drawing from the same formation') If fracking were to stop tomorrow, you'd lose over 600k bbls/day in production immediately and the whatever is leftover tapering off to zero over the course of two-three years.Stephen Hren x Ignored says: 11/14/2018 at 10:06 amThe question is: Just how long will the USA be able to continue to increase production in order to hold off peak oil?Eulenspiegel x Ignored says: 11/14/2018 at 10:42 amYes will it go bankrupt first or continue to run on until peak and depletion. Meanwhile it drags down the oil price artificially making most other oil development less likely, and increasing volatility.
The FED is reducing money supply by 50 billions per month at the moment. The first feeling it will be comanies needing to sell junk bonds.Stephen Hren x Ignored says: 11/14/2018 at 10:50 amThis is a big ploblem for the relentless "drill baby drill" programs of several LTO companies.
And a global economic crises, even if only a few years long, will crash oil prices AND credit supply. This will hurt LTO more than the oil price crash from 2015.
Oil bonds appear to be starting to feel the burn at $55/barrel.Mike Sutherland x Ignored says: 11/14/2018 at 10:38 pmhttps://seekingalpha.com/article/4222006-oil-plunges-energy-junk-bonds-turn-dangerous
Yes Ron, thank you for an excellent post.Watcher x Ignored says: 11/14/2018 at 11:40 pmOn the shale topic; it is marvelously stupefying to observe a heavily indebted shale industry supplying increasing volumes of oil, to an extent that the price/bbl never hits a level where any debt reduction can be realized. (to say nothing of profit)
Its' almost as if they have no intention of becoming solvent.
Some time ago presented estimate of oil used to create and move food in the US. My recall is the number wasn't huge.Recently came across new data. Will get around to laying it out.
25% of total US consumption. Tractors, insecticides, some fertilizer(transport of those to the field), transport of animal food to hogs, beef, etc, transport of human food to shelves, transport of people to the shelf and home. 15% pre transport of human food, 10% transport human food.
Pretty efficient agriculture in the US. No squeezing that 5 mbpd.
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Nov 12, 2018 | peakoilbarrel.com
islandboy says: 11/01/2018 at 10:22 am
I guess it's time to break out the champagne!dclonghorn says: 11/02/2018 at 8:29 pmU.S. monthly crude oil production exceeds 11 million barrels per day in August
U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to EIA's latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy's estimated August production of 11.2 million b/d, making the United States the leading crude oil producer in the world.
Dennis, Coffee's comment did not turn me into a shale cheerleader. I suppose I am more in the shale sceptic camp for the reasons you mention and others.Coffeeguyzz says: 11/02/2018 at 10:16 pmNevertheless, I think Coffee's comment was correct, it does appear that shale producers in the Bakken have expanded the area that produces exceptional wells. As one who underestimated shale's viability before, I don't want to repeat the same mistake.
As you note, it is difficult to predict when average well productivity in the Bakken (or anywhere) will occur. I had thought that current drilling levels would be inadequate to sustain 1.15 million bpd production levels, but somehow they are increasing production there. It does appear that for now, the shale operators are having some success.
How long that success will last depends not only on the operational decisions made, but macro factors such as debt, interest rates, and the economy will play out, and eventually Bakken production will decline. But for nowAnd in a brief follow upWatcher says: 11/01/2018 at 11:35 pmI have not read Continental's conference call transcript yet (Seeking Alpha provides them), but it seems the suit from Continental now feels they will recover – from present completions – 15 to 20 per cent of the OOIP.
That is huge as the norm was 3 to 5 per cent a few years back.Why isn't Continental's credit rating better than 1 notch above junk?Mike says: 11/02/2018 at 8:05 pmAll of this bullshit is straight, I mean straight off Continental's self servicing investor presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some common sense and think for yourself. As opposed to letting someone else do your thinking for you.Boomer II says: 11/03/2018 at 3:03 amWatcher is correct, CLR's credit rating, its credit score, so to speak, is so bad it could not in the real world buy a pickup truck without its mama co-signing the note. If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to? Never mind, you can't answer that.
If you are not in the oil business and have never balanced an oil well's checkbook in your life, which Coffee hasn't, then you don't know that higher productivity comes with a higher cost in the shale biz. The bottom line then is that the bottom line does not change if it did the shale oil industry would be paying down some debt, right? Its not. Private debt is skyrocketing.
Are things getting better for the shale biz? Right. Case in point, the largest pure Permian Basin oil and associated gas producer, Concho, the genius behind a recent $8 billion dollar acquisition from RSP, LOST $199MM 3Q2018. Inventories are going back up, prices are down 18% the past month and what does the shale oil industry do?
It adds more rigs.
Productivity is not the same as profitability. In the real oil biz you learn that on about day six.
"If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to?"Mike says: 11/03/2018 at 7:59 amI wonder about debt service, too.
When Dennis runs his scenarios he says that at a certain oil price, these companies will be quite able to pay down debt.
But will they? Or will they just pay themselves as much as they can as long as they can get away with it, and then declare bankruptcy and walk away.
I'll take door two.Reno Hightower says: 11/04/2018 at 9:37 amWe had 5-6 years of the highest, sustained oil prices in history and the shale oil industry could NOT make a profit. People seem to think now things have changed for some reason, that the shale oil industry has now become more ethical, and temporarily higher productivity of wells, and some imaginary oil price off in the future (for most shale guys its now down in the mid to low $50's) will allow them to pay down debt. Its absurd logic, but keeps people occupied, I guess, speculating about it.
I urge folks to ignore the guessing, and the lying, (Hamm's 20% of OOIP in the Bakken is a big 'ol whopper) and look at the shale industry's financial performance over the past 10 years and decide for yourselves if it is sustainable or not.
One thing to add. The shale companies did all this in the lowest interest rate environment we have had in a long time. They could not pay off their debt or even put a dent in it. What is going to happen when their interest costs increase 30-50% over the next 2-3 years?JG Tulsa says: 11/07/2018 at 3:31 pmI was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in 2007 and gas prices were the highest they had ever been, it was not cash flow positive. It actually ate all the revenue from the rest of the company. Getting to be in the black for the play was always a year off. a decade later it never got there, they just got more and more debt sold more producing assets to pay for it to keep the shell game going and just got bought by Encanna. I have seen the same at every public company I have worked for, many of them survived the downturn only because costs dropped and so did the cost of debt. Now with increasing costs and cost of debt there will likely be many bankruptcies.GuyM says: 11/02/2018 at 12:41 amYeah, I agree with Mike, Rystads announcements are mainly just self serving hogwash. Yes, oil production in the US looks to be close to 11.3 million for August. EIA's reported production for Texas is only about 50k over my high estimate, so I see nothing to argue about. GOM is the main surprise, and George and others are better suited to comment on that. The understanding I had was that it was temporary. As far as Texas goes, I'm pretty sure it is the high, for awhile. Completions dictate how much oil comes out of the ground, not drilling rigs. That is for unconventional wells, not conventional. That is why I think the EIA's DPR is a ridiculous measurement assessment. Apples and oranges. Articles that I have read indicate a significant decrease in completions in the Permian by the end of August. Texas production is not all about the Permian. A significant amount was contributed by the Eagle Ford and other areas. All completions have slowed to the point that by the end of September, they were at slightly over 60% of June's completion numbers according to RRC statistics. Significant drop, and it will show up in following months. First years decline rates will assure that it will drop slightly from this point. $64 WTI won't motivate it to expand to any extent. The next year will see US wavering along the 11.1 million barrel level, I still think. Unless, George thinks the GOM increase is somewhat permanent, which I doubt.Hickory says: 11/02/2018 at 9:59 amJune completions
http://www.rrc.state.tx.us/media/46402/ogdc0618.pdf
July completions
http://www.rrc.state.tx.us/media/46805/ogdc0718.pdf
August completions
http://www.rrc.state.tx.us/media/47577/ogdc0818.pdf
Sept completions
http://www.rrc.state.tx.us/media/47968/ogdc0918.pdf
This is a very definite trend. From 914 oil completions in June to 553 oil completions in September.Of course, no one needs to take my word for it. They can compare Texas production numbers:
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/production-data/texas-monthly-oil-gas-production/
To historical completion numbers here:
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/archive-monthly-drilling-completion-and-plugging-summaries-archive/And try to locate a time in history when production is trending up, while completions are trending down. There is usually a several month lag by the time production slows. Takes a while to get out of the ground if they are completed towards the end of the month.
Don't you just love simple logic? Like: fire burns, water is wet, stuff like that?
How do these projections (hogwash) help Rystad? By preaching the 'good' word to their paying audience? I don't know their business.GuyM says: 11/02/2018 at 1:47 pmThey are a consulting business. How much business will they generate if they tell negative stuff?kolbeinh says: 11/02/2018 at 1:55 pmI second that. Being from Norway myself, and having actually been working in consulting some years ago. It looks nice on paper, but the world is changing and it is wise to look out for deception and that is often the case in consulting (customer/revenue first and reality second).Hickory says: 11/02/2018 at 10:11 pmYeh, but they don't score a lot of points with customers by being far off the mark on projections.ECAS says: 11/02/2018 at 1:55 pmBased on the shaleprofile data it looks as if well productivity increased alot in 2016 and 2017 due to longer laterals and increased proppant intensity. 2018 well productivity looks to be trending pretty close to 2017, so the productivity gains from longer lats and increased proppant might have been exhausted by now. Therefore, comparing 2018 well completion numbers to any pre 2017 completion numbers won't tell you much, but a comparison of 2018 and 2017 numbers should. In the 4 months ending in September 2018 completions grew year over year by almost 70% from 2017, hence the large assumed increase in production in the last four months of 2018. What is interesting though is that it looks like the free lunch from increased lats and proppant looks to be almost over, and any future increases in production must be the result of an increase in completion activity, which should result in some inflation for the service providers going forward. And, according to Schlumberger, if you adjust for the longer lats and increased proppant it actually appears that productivity is starting to trend down (and the increased usage of poor quality in basin sand will likely contribute to this as well)Mike says: 11/02/2018 at 8:13 pmI take your word for it. Thank you, BTW. You are the only one left on this site that has any common sense regarding shale oil economics and the burden all that massive, massive amount of debt has on running a business where your assets decline at the rate of 28-15% annually. Everybody else seems mesmerized by productivity.shallow sand says: 11/03/2018 at 12:22 pmIf folks think I am biased (my "parade" was over 20 years ago) look see what Rune Likvern says here: https://www.oilystuffblog.com/single-post/2018/11/01/Cartoon-Of-the-Week .
Dennis.Dennis Coyne says: 11/04/2018 at 6:36 pmPaying the debt off will depend very much on future oil and natural gas prices.
Once growth slows the companies will be companies operating many low volume wells. Investors will want these companies to pay dividends because they will not be in a position to grow. The operating costs will be higher, even though CAPEX will drop.
You are very confident prices will be high in the future. I suspect they will be volatile in the future, as they have been for the past 20 years.
So, on a company by company basis, timing will be critical, IMO.
Shallow sand,shallow sand says: 11/04/2018 at 11:03 pmThe prices can be thought of as 3 year average prices, yes there will be volatility, my "low price scenario" has Brent Oil Price in 2017 $ never rising above $80/b. I cannot hope to predict the exact oil price and of course oil prices will be volatile, but the average over time allows a pretty good estimate.
Also a company by company model is a little too much work. I just do the industry average, some companies will be better and some worse than average.
It certainly is the case that oil prices have been volatile and I agree this will continue, but the three year trend in prices (centered 3 year average) has been up $7/b for the past year, my expectation is that this trend will continue and the 3 year centered average price will reach $80/b (in 2017$) by 2021 or 2022. The trend of oil prices will be higher, if the peak arrives by 2025 as I expect prices (3 year centered average oil price in 2017$) are likely to reach $100/b by 2024 or 2025.
Dennis.Dennis Coyne says: 11/05/2018 at 2:23 pmI think company by company because I have an investment in a private company. I know how important timing is in the upstream industry to individual companies.
Likewise, I understand you aren't all that interested in individual companies. No problem there.
On the price, I understand why you use different scenarios. However, the average price over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14 and 2015–17.
I was recently in a major city and saw more Tesla's than I ever had, including my first Model 3 sighting.
Our little area now has two Model S, with the early adopter trading his 2012 for a 2018.
Shallow sand,shallow sand says: 11/05/2018 at 6:33 pmPretty doubtful it will be $50/b over the next three years, in my opinion. If you believe that you should find another business
More likely is a gradual increase in oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price (today's future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61 (Dec 2026). By Contrast the EIA's AEO 2018 reference oil price scenario for Brent crude has the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too low.)
As always clicking on the chart give a larger view.
Dennis.Dennis Coyne says: 11/06/2018 at 9:59 amThe price could be $50 from 2019-2021, and then $125 from 2022-2025. (Averages, of course).
So in that scenario I'd feel pretty bad if I sold out in say 2020.
Your models are ok, I have no problem with you doing them. We try to make a budget for every year.
However, the price is far too volatile to model anything very far into the future, just like we cannot budget past one year, and usually have to make adjustments to that.
Our price has dropped over $10 in less than one month. That makes a huge difference, yet that level of volatility is common and has been for many years.
What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the market prices of 2011-14, we would be bankrupt, absent having hedged everything for four years, which is very difficult to do.
On a flowing barrel basis, I have seen leases sell as low as $2,000 per barrel and as high as $180,000 per barrel in our basin from 1997-2018. That is what an oil price range of $8-140 per barrel will do.
Few companies with zero debt ever go BK. We would with WTI at $30 for about three years. Is that likely? No, but oil did drop below that level in 2016.
Shallow Sand,shallow sand says: 11/08/2018 at 4:44 pmThe volatility is a big problem, there is no doubt of that. When imagining the "big picture". I use the estimates of the EIA's AEO as a starting point then add my personal perspective (that at some point oil output will peak.) Below is a chart with my guess from Dec 2014 for future Brent oil prices in constant 2014$, nominal Brent spot price is give for comparison.
Clearly my guess was not very good, the EIA guess from the AEO 2015 was also not great, but better than my guess. Future guesses will be equally bad.
What was your forecast in Dec 2014 for WTI?
Dennis.Dennis Coyne says: 11/08/2018 at 6:10 pmIn 2013 we assumed prices in a range of $60-120 WTI moving forward.
In June of 2014 when oil spiked up and we received $99.25 in the field, we suspected oil would fall and it began to. We again continued to assume $60 WTI would be a low.
We were dead wrong, of course.
Oil dropped again today. We will get $67 in the field for October sales paid in November. However, our price today is down to $56.50. That is about a $60,000 per month revenue hit to a small company which employs 8 full time employees, one part time employee office manager and utilized numerous contractors (rigs, electricians, etc.).
Corn here is $3.51 per bushel today. Less than a month ago it was $2.96 per bushel.
Yes, yes, a hedging program would mitigate the price volatility.
Until you actually try to hedge with money at risk, don't talk to me about that. It's about as easy as trading stocks. It is also very expensive due to the volatility. Or, if you do SWAPS or Collars, you need to put up a lot of margin money.
Shallow sand,TechGuy says: 11/07/2018 at 2:25 pmHedging seems a risky business, not sure I would come out ahead by hedging. You are in a tough business, the volatility sucks. The silver lining is that prices will be increasing.
Shallow Sand Wrote:
"Paying the debt off will depend very much on future oil and natural gas prices."I don't think so. When energy prices rise, so do prices of everything else, included interest rates. The only way the shale drillers could play off there debt is if the left large number of completed wells untapped (ie leave it in the ground) while taking advantage of cheap debt & low labor\material costs. Then selling the oil when prices & costs have soared above investment costs.
The issue is that as soon as a well is completed, they start producing, at market prices. Thus when oil prices rise most of the oil is already produced & drilling new wells (using more debt) does not pay down the old debt.
Also consider the costs shale drillers will need for decommissioning older\depleted well. I believe the cleanup cost is between $50K & $100K per drill site. To date have any shale drillers spent money on clean up for depleted wells yet, or is it all deferred (ie never going to happen)?
FWIW: I don't believe any of the shale companies are in game for the long term. They are simply a modern Ponzi scam, taking investor money & providing an illusion of profitabity by selling a product below cost. They will continue to play the game until investor capital dries up.
I suspect that most shale drillers will go bust in the next 5 years when the bulk of their bonds come due & they won't have the ability to refinance it or pay it off. If I recall correctly Shale drillers will need to payoff or refinance about $270B in high-yield bonds between 2020 & 2022.
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Oct 31, 2018 | angrybearblog.com
likbez , October 31, 2018 1:03 am
The key question not addressed by the author is how long the period of "plato oil production" (the last stage of the so called "oil age", which started around 1911) might last -- 10, 20 or 50 years. And the oil age is just a very short blip in Earth history.
Let's assume that this means less the $100 per barrel; in the past, it was $70 per barrel that considered the level that guarantees the recession in the USA, but financial system machinations now probably reached a new level, so that might not be true any longer. The trillion dollars question is "How long this period can be extended?"
It is important to understand the US shale oil is not profitable and never will be for prices under $80 or so. At prices below that level, it actually produces three products, not two – oil, gas and junk bonds.
I view it as a very sophisticated, very innovative gamble to pressure oil prices down and get compensation for the losses due to large amount of imported oil (the USA export mainly lightweight oil which is kind of "subprime oil" often used for dilution of heavy oil in countries such as Canada and Venezuela, but imports quality oil).
If the hypothesis that Saudis and Russians are close to Seneca Cliff (Saudi prince recently said that Russian are just 10-15 years from it) and that best days of the US shale and Gulf of Mexico deep oil is in the past if true, then "Houston we have a problem".
That means that in 20 years, or so the civilization might experience some kind of collapse, and the population of the Earth might start rapidly shrinking.
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Oct 27, 2018 | www.zerohedge.com
Authored by Steve St.Angelo via SRSRoccoReport.com,
While the U.S. Shale Industry produces a record amount of oil, it continues to be plagued by massive oil decline rates and debt. Moreover, even as the companies brag about lowering the break-even cost to produce shale oil, the industry still spends more than it makes. When we add up all the negative factors weighing down the shale oil industry, it should be no surprise that a catastrophic failure lies dead ahead.
Of course, most Americans have no idea that the U.S. Shale Oil Industry is nothing more than a Ponzi Scheme because of the mainstream media's inability to report FACT from FICTION. However, they don't deserve all of the blame as the shale energy industry has done an excellent job hiding the financial distress from the public and investors by the use of highly technical jargon and BS.
For example, Pioneer published this in the recent Q2 2018 Press Release:
Pioneer placed 38 Version 3.0 wells on production during the second quarter of 2018. The Company also placed 29 wells on production during the second quarter of 2018 that utilized higher intensity completions compared to Version 3.0 wells. These are referred to as Version 3.0+ completions. Results from the 65 Version 3.0+ wells completed in 2017 and the first half of 2018 are outperforming production from nearby offset wells with less intense completions. Based on the success of the higher intensity completions to date, the Company is adding approximately 60 Version 3.0+ completions in the second half of 2018.
Now, the information Pioneer published above wasn't all that technical, but it was full of BS. Anytime the industry uses terms like "Version 3.0+ completions" to describe shale wells, this normally means the use of "more technology" equals "more money." As the shale industry goes from 30 to 60 to 70 stage frack wells, this takes one hell of a lot more pipe, water, sand, fracking chemicals and of course, money .
However, the majority of investors and the public are clueless in regards to the staggering costs it takes to produce shale oil because they are enamored by the "wonders of technology." For some odd reason, they tend to overlook the simple premise that
MORE STUFF costs MORE MONEY.
Of course, the shale industry doesn't mind using MORE MONEY, especially if some other poor slob pays the bill.
Shale Oil Industry: Deep The DenialAccording to a recently released article by 40-year oil industry veteran, Mike Shellman, "Deep The Denial," he provided some sobering statistics on the shale industry:
I recently put somebody very smart on the necessary research (SEC K's, press releases regarding private equity to private producers, etc.) to determine what total upstream shale oil debt actually is. We found it to be between $285-$300B (billion), both public and private . Kallanish Energy Consultants recently wrote that there is $240B of long term E&P debt in the US maturing by 2023 and I think we should assume that at least 90 plus percent of that is associated with shale oil. That is maturing debt, not total debt.
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B annually in interest on long term debt.
Using its own self-touted "breakeven" oil price, the shale oil industry must then produce over 1.5 Million BOPD just to pay interest on that debt each year. Those are barrels of oil that cannot be used to deleverage debt, grow reserves, not even replace reserves that are declining at rates of 28% to 15% per year that is just what it will take to service debt.
Using its own "breakeven" prices the US shale oil industry will ultimately have to produce 9G BO of oil, as much as it has already produced in 10 years just to pay its total long term debt back .
Using Mike's figures, I made the following chart below:
For the U.S. Shale Oil Industry just to pay back its debt, it must produce 9 billion barrels of oil. That is one heck of a lot of oil as the industry has produced about 10 billion barrels to date. Again, as Mike states, it would take 9 billion barrels of shale oil to pay back its $285-300 billion of debt (based on the shale industry's very own breakeven prices).
Furthermore, the shale industry may have to sell a quarter of its oil production (1.5 million barrels per day) just to service its debt by the end of 2019. According to the EIA, the U.S. Energy Information Agency, total shale oil (tight oil) production is now 6.2 million barrels per day (mbd):
The majority of shale oil production comes from three fields and regions, the Eagle Ford (Blue), the Bakken (Yellow) and the Permian (light, medium & dark brown). These three fields and regions produce 5.2 mbd of the total 6.2 mbd of shale production.
Unfortunately, the shale industry continues to struggle with mounting debt and negative free cash flow. The EIA recently published this chart showing the cash from operations versus capital expenditures for 48 public domestic oil producers:
You will notice that capital expenditures ( brown line ) are still higher than cash from operations ( blue line ). So, it doesn't seem to matter if the oil price is over $100 (2013-2014) or less than $70 (2017-2018), the shale oil industry continues to spend more money than it's making. The shale energy companies have resorted to selling assets, issuing stock and increasing debt to supplement their inadequate cash flow to fund operations.
A perfect example of this in practice is Pioneer Resources the number one shale oil producer in the mighty Permian. While most companies increased their debt to fund operations, Pioneer decided to take advantage of its high stock price by raising money via share dilution. Pioneer's outstanding shares ballooned from 115 million shares in 2010 to 170 million by 2017. From 2011 to 2016, Pioneer issued a staggering $5.4 billion in new stock :
So, as Pioneer issued over $5 billion in stock to produce unprofitable shale oil and gas, Continental Resources racked up more than $5 billion in debt during the same period. These are both examples of "Ponzi Finance." Thus, the shale energy industry has been quite creative in hoodwinking both the shareholder and capital investor.
Now, there is no coincidence that I have focused my research on Pioneer and Continental Resources. While Continental is the poster child of what's horribly wrong with the shale oil industry in the Bakken, Pioneer is a role model for the same sort of insanity and delusional thinking taking place in the Permian.
Pioneer Spends A Lot More Money With Unsatisfactory Production ResultsTo be able to understand what is going on in the U.S. shale industry, you have to be clever enough to ignore the "Techno-jargon" in the press releases and read between the lines. As mentioned above, Pioneer stated that it was going to add a lot more of its "high-tech" Version 3.0+ completion wells in the second half of 2018 because they were outperforming the older versions.
Well, I hope this is true because Pioneer's first half 2018 production results in the Permian were quite disappointing compared to the previous period. If we compare the increase of Pioneer's shale oil production in the Permian versus its capital expenditures, something must be seriously wrong .
First, let's look at a breakdown of Pioneer's Permian energy production from their September 2018 Investor Presentation:
Pioneer's Permian oil and gas production is broken down between its horizontal shale and vertical convention production. I will only focus on its horizontal shale production as this is where the majority of their capital expenditures are taking place. The highlighted yellow line shows Pioneer's horizontal shale oil production in the Permian Basin.
You will notice that Pioneer's shale oil production increased significantly in Q3 & Q4 2017 versus Q1 & Q2 2018. Furthermore, Pioneer's shale gas production surged in Q2 2018 by nearly 50% (highlighted with a red box) compared to oil production only increasing 5%. That is a serious RED FLAG for natural gas production to jump that much in one quarter.
Secondly, by comparing the increase of Pioneer's quarterly shale oil production in the Permian with its capital expenditures, the results are less than satisfactory:
The RED LINE shows the amount of capital expenditures spent each quarter while the OLIVE colored BARS represent the increase in Permian shale oil production. To simplify the figures in this chart, I made the following graphic below:
Pioneer spent $1.36 billion in the second half of 2017 to increase its Permian shale oil production by 30,232 barrels per day (bopd) compared to $1.7 billion in the first half of 2018 which only resulted in an additional 10,832 bopd . Folks, it seems as if something seriously went wrong for Pioneer in the Permian as the expenditure of $340 million more CAPEX resulted in two-thirds less the production growth versus the previous period.
Third, while Pioneer (stock ticker PXD) proudly lists that they are one of the lowest cost shale producers in the industry, they still suffer from negative free cash flow:
As we can see, Pioneer lists their breakeven oil price at approximately $22, which is downright hilarious when they spent $132 million more on capital expenditures than the made in cash from operations:
The public and investors need to understand that "oil breakeven costs" do not include capital expenditures. And according to Pioneer's Q2 2018 Press Release, the company plans on spending $3.4 billion on capital expenditures in 2018. The majority of the capital expenditures are spent on drilling and completing horizontal shale wells.
For example, Pioneer brought on 130 new wells in the first half of 2018 and spent $1.7 billion on CAPEX (capital expenditures) versus 125 wells and $1.36 billion in 2H 2017. I have seen estimates that it cost approximately $9 million for Pioneer to drill a horizontal shale well in the Permian. Thus, the 130 wells cost nearly $1.2 billion.
However, the interesting thing to take note is that Pioneer brought on 125 wells in 2H 2017 to add 30,000+ barrels of new oil production compared to 130 wells in 1H 2018 that only added 10,000+ barrels. So, how can Pioneer add five more wells (130 vs. 125) in 1H 2018 to see its oil production increase a third of what it was in the previous period?
Regardless, the U.S. shale oil industry continues to spend more money than they make from operations. While energy companies may have enjoyed lower costs when the industry was gutted by super-low oil prices in 2015 and 2016, it seems as if inflation has made its way back into the shale patch. Rising energy prices translate to higher costs for the shale energy industry. Rinse and repeat.
Unfortunately, when the stock markets finally crack, so will energy and commodity prices. Falling oil prices will cause severe damage to the Shale Industry as it struggles to stay afloat by selling assets, issuing stock and increasing debt to continue producing unprofitable oil.
I believe the U.S. Shale Oil Industry will suffer catastrophic failure from the impact of deflationary oil prices along with peaking production. While U.S. Shale Oil production has increased exponentially over the past decade, it will likely come down even faster.
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Oct 24, 2018 | oilprice.com
Oil prices are down a bit, but are still close to multi-year highs. That should leave the shale industry flush with cash. However, a long list of US shale companies are still struggling to turn a profit. A new report from the Institute for Energy Economics and Financial Analysis (IEEFA) and the Sightline Institute detail the "alarming volumes of red ink" within the shale industry.
"Even after two and a half years of rising oil prices and growing expectations for improved financial results, a review of 33 publicly
