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|In recent years Americans have been hearing that the United States is poised to regain its role as the world’s premier oil and natural gas producer, thanks to the widespread use of horizontal drilling and hydraulic fracturing (“fracking”). This “shale revolution,” we’re told, will fundamentally change the U.S. energy picture for decades to come—leading to energy independence, a rebirth of U.S. manufacturing, and a surplus supply of both oil and natural gas that can be exported to allies around the world. This promise of oil and natural gas abundance is influencing climate policy, foreign policy, and investments in alternative energy sources.|
The term "shale bubble" is about the idea that the United States is poised to regain "energy independence" becoming again net exporter instead of major importer of oil and natural gas. The primary driver of the propaganda campaign was the U.S. Department of Energy’s Energy Information Administration (EIA). The key technologies that were enabler of shell boom were:
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.”
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 amThanks 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.
While current technologies are adequate for oil shale mining, the technology for surface retorting has not been successfully applied at a commercially viable level in the United States, although technical viability has been demonstrated. Further development and testing of surface retorting technology is needed before the method is likely to succeed on a commercial scale.
In Situ Retorting
Shell Oil is currently developing an in situ conversion process (ICP). The process involves heating underground oil shale, using electric heaters placed in deep vertical holes drilled through a section of oil shale. The volume of oil shale is heated over a period of two to three years, until it reaches 650–700 °F, at which point oil is released from the shale. The released product is gathered in collection wells positioned within the heated zone.
Shell's current plan involves use of ground-freezing technology to establish an underground barrier called a "freeze wall" around the perimeter of the extraction zone. The freeze wall is created by pumping refrigerated fluid through a series of wells drilled around the extraction zone. The freeze wall prevents groundwater from entering the extraction zone, and keeps hydrocarbons and other products generated by the in-situ retorting from leaving the project perimeter.
Shell's process is currently unproven at a commercial scale, but is regarded by the U.S. Department of Energy as a very promising technology. Confirmation of the technical feasibility of the concept, however, hinges on the resolution of two major technical issues: controlling groundwater during production and preventing subsurface environmental problems, including groundwater impacts.1
Both mining and processing of oil shale involve a variety of environmental impacts, such as global warming and greenhouse gas emissions, disturbance of mined land; impacts on wildlife and air and water quality. The development of a commercial oil shale industry in the U.S. would also have significant social and economic impacts on local communities. Of special concern in the relatively arid western United States is the large amount of water required for oil shale processing; currently, oil shale extraction and processing require several barrels of water for each barrel of oil produced, though some of the water can be recycled.
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.
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."
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 pmI 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 pm
I prefer to define Peak Oil as the point in time when vigorous growth in oil production ended and we entered an undulating plateau when periods of slow growth and slow decline will alternate, affected by oil price and variable demand by economy until we reach terminal decline in production permanently abandoning the plateau towards lower oil production.
The 12-year rate of growth in C+C production took a big hit in late 2015 and has not recovered. The increase in 2 Mb since is just an anemic 2.5% over 3 years or 0.8% per year, and it keeps going down. This is plateau behavior since there was no economic crisis to blame. It will become negative when the economy sours.
Peak Oil has already arrived. We are not recognizing it because production still increases a little bit, but we are in Peak Oil mode. Oil production will decrease a lot more easily that it will increase over the next decade. The economy is going to be a real bitch.Carlos Diaz,Carlos Diaz x Ignored says: 03/14/2019 at 7:18 pm
Interesting thesis, keep in mind that the price of oil was relatively low from 2015 to 2018 because for much of the period there was an excess of oil stocks built up over the 2013 to 2015 period when output growth outpaced demand growth due to very high oil prices. Supply has been adequate to keep oil prices relatively low through March 2019 and US sanctions on Iran, political instability in Libya and Venezuela, and action by OPEC and several non-OPEC nations to restrict supply have resulted in slower growth in oil output.
Eventually World Petroleum stocks will fall to a level that will drive oil prices higher, there is very poor visibility for World Petroleum Stocks, so there may be a 6 to 12 month lag between petroleum stocks falling to critically low levels and market realization of that fact, by Sept to Dec 2019 this may be apparent and oil prices may spike (perhaps to $90/b by May 2020).
At that point we may start to see some higher investment levels with higher output coming 12 to 60 months later (some projects such as deep water and Arctic projects take a lot of time to become operational, there may be some OPEC projects that might be developed as well, there are also Canadian Oil sands projects that might be developed in a high oil price environment.
I define the peak as the highest 12 month centered average World C+C output, but it can be define many different ways.So Dennis,Dennis Coyne x Ignored says: 03/14/2019 at 9:20 pm
Our capability to store oil is very limited considering the volume being moved at any time from production to consumption. I understand that it is the marginal price of the last barrel of oil that sets the price for oil, but given the relatively inexpensive oil between 2015 and now, and the fact that we have not been in an economical crisis, what is according to you the cause that world oil production has grown so anemically these past three years?
Do you think that if oil had been at 20$/b as it used to be for decades the growth in consumption/production would have been significantly higher?
I'll give you a hint, with real negative interest rates and comparatively inexpensive oil most OECD economies are unable to grow robustly.
To me Peak Oil is an economical question, not a geological one. The geology just sets the cost of production (not the price) too high, making the operation uneconomical. It is the economy that becomes unable to pump more oil. That's why the beginning of Peak Oil can be placed at late 2015.
The economic system has three legs, cheap energy, demographic growth, and debt growth. All three are failing simultaneously so we are facing the perfect storm. Social unrest is the most likely consequence almost everywhere.Carlos,Carlos Diaz x Ignored says: 03/15/2019 at 5:03 am
If prices are low that means there is plenty of oil supply relative to demand. It also means that some oil cannot be produced profitably, so oil companies invest less and oil output grows more slowly.
So you seem to have the story backwards. Low oil prices means low growth in supply.
So if oil prices were $20/b, oil supply would grow more slowly, we have had an oversupply of oil that ls what led to low oil prices. When oil prices increase, supply growth will ne higher. Evause profits will be higher and there will be more investment.No Dennis,Schinzy x Ignored says: 03/15/2019 at 11:18 am
It is you who has it backwards, as you only see the issue from an oil price point of view, and oil price responds to supply and demand, and higher prices are an estimulus to higher production.
But there is a more important point of view, because oil is one of the main inputs of the economy. If the price of oil is sufficiently low it stimulates the economy. New businesses are created, more people go farther on vacation, and so on, increasing oil demand and oil production. If the price is sufficiently high it depresses the economy. A higher percentage of wealth is transferred from consumer countries to producing countries and consumer countries require more debt. During the 2010-2014 period high oil prices were sustained by the phenomenal push of the Chinese economy, while European and Japanese economies suffered enormously and their oil consumption depressed and hasn't fully recovered since.
In the long term it is the economy that pumps the oil, and that is what you cannot understand.
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 pm
Your 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 pm
Both supply and demand matter. I understand economics quite well thank you. You are correct that the economy is very important, it will determine oil prices to some degree especially on the demand side of the market. If one looks at the price of oil and economic growth or GDP, there is very little correlation.
The fact is the World economy grew quite nicely from 2011 to 2014 when oil prices averaged over $100/b.
There may be some point that high oil prices are a problem, apparently $100/b in 2014 US$ is below that price. Perhaps at $150/b your argument would be correct. Why would the economy need more oil when oil prices are low? The low price is a signal that there is too much oil being produced relative to the demand for oil.
I agree the economy will be a major factor in when peak oil occurs, but as most economists understand quite well, it is both supply and demand that will determine market prices for oil.
My models are based on the predictions of the geophysicists at the USGS (estimating TRR for tight oil) and the economists at the EIA (who attempt to predict future oil prices). Both predictions are used as inputs to the model along with past completion rates and well productivity and assumptions about potential future completion rates and future well productivity, bounded by the predictions of both the USGS and the EIA along with economic assumptions about well cost, royalties and taxes, transport costs, discount rate, and lease operating expenses.
Note that my results for economically recoverable resources are in line with the USGS TRR mean estimates and are somewhat lower when the economic assumptions are applied (ERR/TRR is roughly 0.85), the EIA AEO has economically recoverable tight oil resources at about 115% of the USGS mean TRR estimate. The main EIA estimate I use is their AEO reference oil price case (which may be too low with oil prices gradually rising to $110/b (2017$) by 2050.
Assumptions for Permian Basin are royalties and taxes 33% of wellhead revenue, transport cost $5/b, LOE=$2.3/b plus $15000/month, annual discount rate is 10%/year and well cost is $10 million, annual interest rate is 7.4%/year, annual inflation rate assumed to be 2.5%/year, income tax and revenue from natural gas and NGL are ignored all dollar costs in constant 2017 US$.You do incredible work Dennis and I believe you are correct. Demand for oil is relatively inelastic which accounts for huge price swings when inventories get uncomfortably high or low. If supply doesn't keep up with our needs, price will rise to levels that will eventually create more supply and create switching into other energy sources which will reduce demand.Carlos Diaz x Ignored says: 03/15/2019 at 6:57 pmDennis Coyne x Ignored says: 03/16/2019 at 7:33 am
Why would the economy need more oil when oil prices are low? The low price is a signal that there is too much oil being produced relative to the demand for oil.
You don't seem to be aware of historical oil prices. For inflation adjusted oil prices since 1946 oil (WTI) spent:
27 years below $30
13 years at ~ $70
18 years at ~ $40
10 years at ~ $90
5 years at ~ $50
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 am
I use both geophysics and economics, it is not one or the other it is both of these that will determine peak oil.
Of course oil prices have increased, the cheapest oil gets produced first and oil gradually gets more expensive as the marginal barrel produced to meet demand at the margin is more costly to produce.
Real Oil Prices do not correlate well with real economic growth and on a microeconomic level the price of oil will affect profits and willingness of oil companies to invest which in turn will affect future output. Demand will be a function of both economic output and efficiency improvements in the use of oil.
Thanks Mario.Dennis Coyne x Ignored says: 03/16/2019 at 10:49 amCarlos,HHH x Ignored says: 03/15/2019 at 9:44 pm
Also keep in mind that during the 1945-1975 period economic growth rates were very high as population growth rates were very high and the World economy was expanding rapidly as population grew and the World rebuilt in the aftermath of World War 2. Oil was indeed plentiful and cheap over this period and output grew rapidly to meet expanding World demand for oil. The cheapness of the oil led to relatively inefficient use of the resource, as constraints in output became evident and more expensive offshore, Arctic oil were extracted oil prices increased and there was high volatility due to Wars in the Middle east and other political developments. Oil output (C+C) since 1982 has grown fairly steadily at about an 800 kb/d annual average each year, oil prices move up and down in response to anticipated oil stock movements and are volatile because these estimates are often incorrect (the World petroleum stock numbers are far from transparent.)
On average since the Iran/Iraq crash in output (1982-2017) World output has grown by about 1.2% per year and 800 kb/d per year on average, prices have risen or fallen when there was inadequate or excess stocks of petroleum, this pattern (prices adjusting to stock levels) is likely to continue.
There has been little change when we compare 1982 to 1999 to 1999-2017 (divide overall period of interest in half) for either percentage increase of absolute increase in output.
I would agree that severe shortages of oil supply relative to demand (likely apparent by 2030) is likely to lead to an economic crisis as oil prices rise to levels that the World economy cannot adjust to (my guess is that this level will be $165/b in 2018$). Potentially high oil prices might lead to faster adoption of alternative modes of transport that might avert a crisis, but that is too optimistic a scenario even for me.China will be in outright deflation soon enough. Economic stimulus is starting to fail in China. They can't fill the so called bathtub up fast enough to keep pace with the water draining out the bottom. So to speak.Lightsout x Ignored says: 03/16/2019 at 6:25 am
Interest rates in China will soon be exactly where they are in Europe and Japan. Maybe lower.
In order to get oil to $90-$100 the value of the dollar is going to have to sink a little bit. In order to get oil to $140-$160 the dollar has to make a new all time low. Anybody predicting prices shooting up to $200 needs the dollar index to sink to 60 or below.
The reality is oil is going to $20. Because the rest of the world outside the US is failing. Dennis makes some nice graphs and charts and under his assumptions his charts and graphs are correct. But his assumptions aren't correct.
We got $20 oil and an economic depression coming.
Peak Oil is going to be deflationary as hell. Higher prices aren't in the cards even when a shortage actually shows up. We will get less supply at a lower price. Demand destruction is actually going to happen when economies and debt bubbles implode so we actually can't be totally sure we are ever going to see an actual shortage.
We could very well be producing 20-30% less oil than we do now and still not have a shortage.
Oh and EV's are going to have to compete with $20 oil not $150 oil.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 am
https://www.scmp.com/economy/china-economy/article/2174453/china-and-russia-look-ditch-dollar-new-payments-system-moveHHH,Dennis Coyne x Ignored says: 03/16/2019 at 9:56 am
When do you expect the oil price to reach $20/b? We will have to see when this occurs.
It may come true when EVs and AVs have decimated demand for oil in 2050, but not before. EIA's oil price reference scenario from AEO 2019 below. That is a far more realistic prediction (though likely too low especially when peak oil arrives in 2025), oil prices from $100 to $160/b in 2018 US$ are more likely from 2023 to 2035 (for three year centered average Brent oil price).
HHH,HHH x Ignored says: 03/16/2019 at 6:50 pm
My assumptions are based on USGS mean resource estimates and EIA oil price estimates, as well as BIS estimates for the World monetary and financial system.
Your assumption that oil prices are determined by exchange rates only is not borne out by historical evidence. Exchange rates are a minor, not a major determinant of oil prices.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.
Mar 18, 2019 | peakoilbarrel.com
Energy News, says: 03/17/2019 at 2:49 amCountries that have reported their January production (shown on the chart)
Russian Federation -78
Total -1,429 kb/day
So far for February: Russia, OPEC14, Norway
Total: -330 kb/day
Chart for December which includes the big increases from the USA
China crude oil production
February: 3,813 kb/day
Average 2018: 3,788 kb/day
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
Mar 16, 2019 | peakoilbarrel.com
likbez says: 03/16/2019 at 9:34 pmlikbez says:
03/16/2019 at 9:34 pm
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.
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
Mar 16, 2019 | peakoilbarrel.com
TechGuy x Ignored says: 03/15/2019 at 11:52 pmDennis 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.
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 pm
I warned the Australian Prime Minister John Howard in 2004/05 but he did not want to listen.
Howard's Energy Policy Failure 2004
As a result, Australia has built a lot of additional oil dependent infrastructure. Even Sydney's new metro projects don't replace car traffic:
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 .
Mar 06, 2019 | peakoilbarrel.com
dclonghorn x Ignored says: 02/28/2019 at 11:13 amThere 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.
https://www.spe.org/en/jpt/jpt-article-detail/?art=5164The 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.
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.
just the tip , 54 minutes ago linkBig Fat Bastard , 1 hour ago link
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.
https://oilprice.com/Latest-Energy-News/World-News/EIA-US-Crude-Oil-Production-To-Keep-Setting-Records-Until-2027.htmlBaron von Bud , 1 hour ago link
Crude Prices Crater 28% Since Q3 2018 As China Economy Collapses
https://www.marketwatch.com/investing/future/crude%20oil%20-%20electronichayman , 1 hour ago link
Real oil wells could last decades. Shale - 18 months. Bottom of the barrel and a bad sign of things to come.-- ALIEN -- , 1 hour ago link
And 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 link
We 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 link
This whole shale oil boom started back when Baby Bush was president, and Hugo Chavez announced to the world (at the UN) that W "smelled of sulfur". To add insult to injury, Hugo sent aid, in the form of fuel oil and a hospital ship, to help the victims of Hurricane Katrina, while W was busy eating cake and clearing brush with Jeff Gannon.
From that moment on, W had it in for Hugo. Venezuela was doing very well at the time. Besides sanctions, Bush figured that the best way to attack Hugo and Venezuela was to crash the price of crude. So suddenly there were financial incentives and lax regulations in the US regarding Fracking, and the Shale Oil Boom in America was born! Bush didn't care that it was costing Americans - both financially and by ruining the quality of the ground water - the lifeblood of agriculture. This oil borne of vengence went to market at way below cost of production, but it succeeded in driving the price of crude to the point of financial pain for Venezuela.
After all that, Hugo survived several assassination attempts, only to die suddenly and mysteriously from - depending on the source - either a heart attack or stroke.
Shale oil had a negative EROEI from the start, it just took this long for that to be realized.
chubbar , 1 hour ago link
Ah, more doom **** for anti-shalers. Terrific stuff.jetfuel_hahaha , 1 hour ago link
I'll bet they are understating the loan problem. I think this industry has real problems along with the banks that financed them. Someone, somewhere has some data on this issue but I've only seen it alluded too. With the cost of oil down and these wells starting to underproduce, I'll bet there is some real risk to solvency for some banks we are not hearing about.WTFUD , 1 hour ago link
Time to circle uranus looking for oil?Broccoli , 2 hours ago link
The only real growth in the US -
1. Opiates/Big Pharma
3. John Bolton's harelip coverWinston Churchill , 1 hour ago link
These articles against shale are so biased. I work in the Delaware Basin and have intimate knowledge of the financials. The shale BS spewed on zerohedge only looks at the negative side of things. The article above is correct about the problem of well spacing, but I could write 5 positive articles about upward revisions of expected well productivity those same companies have had as they refined their frac techniques and got better at drilling laterals. Zerohedge only reports the negative revisions, not the numerous positive revisions. These companies are now going on a decade of growth and their financials are actually improving.
The shale business is fundamentally sound if you have the right acreage and don't overpay to get acreage. The naysayers are correct in that production decline in unconventionals requires ever increasing investment so as long as the company is trying to grow they will have negative cash flow and expanding debt loads to fight the decline curves of unconventionals. (The rig count you need to just to counteract natural decline keeps growing as you grow.) But it also doesn't mean jack **** for the profitability of each well. Unless you are a poorly run shale company like Encana, BHP, or BP, you would instantly be massively cash flow positive and easily pay off all your debt if you stopped drilling. In Delaware Basin, companies like EOG are hitting 40% ROCE (Return on Capital Employed) and the basin average is probably 20%. Those are good numbers.Broccoli , 1 hour ago link
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 link
I explain it in my post. Don't confuse profits with cash flow and debt. The individual projects are profitable and so are the companies, but to keep growing and fight the decline they capital budget has to grow in unconventionals. The shareholders in the company push for more growth, to deliver that growth they have to first make up the natural decline plus add to the baseline. As your baseline grows the first part of the equation, fighting the natural decline, grows along with you. To show cash flow positive results and reduce debt, all the companies have to do is keep rig and frac crew counts constant, and about a year later they will all show positive cash flow and reductions in debt. However, by in large most companies are choosing to increase rig and frac crew counts year over year and thus the cash flow remains negative and debt grows because the companies themselves are growing. What the naysayers are doing is just looking at the liabilities on the balance sheet, while ignoring the asset growth.
The naysayers are not wrong about the balance sheets, they are just not talking about the full picture. Eventually these predictions will be right as viable acreage runs out and companies start throwing good money at bad projects just to show production growth, but that isn't happening yet except for at the weakest players. And that truth is the same even for conventional fields. Unconventionals just shorten the lifecycle, but it doesn't change the fact that the oil business has always been one where you produce yourselves out of business, and to remain viability you constantly have to be exploring for new opportunies. 150 years and still going and people still write articles without understanding.Zeej , 1 hour ago link
Show me a single shale play with an EROEI above 5:1 and we'll talk.
EDIT: full disclosure: I'm invested in shale, and have made good money from it. But long-term I still think it's a loser. Net energy gain is too low to be viable.gladitsover , 1 hour ago link
These articles have been predicting the demise of US shale since 2010. As in any industry especially one as technologically driven as US shale you have good and bad results across the space, yet the space as a whole will continue to grow and good operators will thrive.2handband , 2 hours ago link
Shale is end game stuff. At the end of the day the average jobless consumer can't afford to run a vehicle on 100$+ per barrel shale. And producers can't really stay in business at current prices. The funding is mostly zero cost debt provided to keep the dream alive for a few more years.gladitsover , 2 hours ago link
I've been in shale for quite awhile, and have made good money. It's a good investment if you're careful, but it's also a low EROEI product that the numbers have never really made sense on. The companies producing it are leveraged to the gills, and if interest rates were to pop and make it more expensive to roll over their debt it'd explode like a ******* bomb. On my more tinfoilly days I wonder if the whole purpose of the '08 financial crisis (which was deliberately engineered; that much I am sure of) was to give them excuse to drop the interest rates enough to make shale viable. Get a hard look at the financials of any company producing shale... you'll see some serious weirdness in their cash flow. This was the case even when crude prices were parked around $100.
Hard cold fact: net energy gain on this stuff is positive, but not by very goddamn much. Left strictly to market forces, it would not be economically viable at all. Ultimately I think what we're going to see is some kind of a nationalization of oil supplies as a security measure; there's plenty of stuff out there that is net energy positive but still not profitable to extract. But so long as it takes marginally less energy to get it out than you produce, it'll be propped up. Once net energy goes negative (and it will; we always take the low-hanging fruit first) then it's game over.gladitsover , 2 hours ago link
Mankind build industrial society on 30+ to 1 oil. Shale is scraping the bottom of the barrel.. tar sands the same. They take fresh water and natural gas to cook the oil out of the sand for christ sake.. that's late end game stuff right there.CosineCosineCosine , 1 hour ago link
The late Matthew Simmons called the advanced extraction thechniques like water injection etc used on legacy oil fields
"super-straws" sucking the last oil faster and in no way expanding the total recoverable oil from the field. We can expect much steeper decline curves because of it when reservoir pressures are finally depleted.
Cold cold fact: net energy gain on this stuff is positive, but not by very goddamn much. Left strictly to market forces, it would not be economically viable at all. Ultimately I think what we're going to see is some kind of a nationalization of oil supplies as a security measure; there's plenty of stuff out there that is net energy positive but still not profitable to extract. But so long as it takes marginally less energy to get it out than you produce, it'll be propped up . Once net energy goes negative (and it will; we always take the low-hanging fruit first) then it's game over.
Great balanced comment.
I see shale as essentially thermodynamic autocannibalism from the point of view that at an EROEI of 1.5-3 to 1, it can power it's extraction and refinement and (sometimes) transport, but not anything else. It cannot provide the energy needed to run a mid-19th century economy let alone a parasitic 21st century one. There is no fat to run our civilization and this is largely a desperate delay mechanism. The West has used up most it's net positive EROEI to the pump oil and gas and now it needs to plunder other economies if it isn't to go down in flames. It will implode after 2030 anyway as the global EROEI inflects, but these are in denial moves to delay the inevitable .
Again - great to see a non binary comment here on ZH on this polarising topic.
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.
shallow sand says: 11/17/2016 at 9:00 am
Nov 19, 2016 | peakoilbarrel.com
Dennis Coyne says: 11/17/2016 at 8:49 amHi 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 am
I am doing the analysis for the Bakken. A lot of the leases are already held and I don't know that those were the prices paid. Give me a number for total capital cost that makes sense, are you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the different assumptions you would like to change would be good so I don't redo it 5 times.
Mostly I would like to clear up "the number".
I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes, real discount rate (adjusted for inflation), well cost.
I think you a re talking about well cost as "the number". I include down hole costs as part of OPEX (think of it as OPEX plus maintenance maybe).
Dennis. The very high acreage numbers are for recent sales in the Permian Basin. In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost.Dennis Coyne says: 11/17/2016 at 1:22 pm
This does not include costs incurred prior to the well being drilled, which are not insignificant. Nor does it include costs of down hole and surface equipment, which also are not insignificant.
Land costs are all over the map, and I think Bakken land costs overall are the lowest, because much of the leasing occurred prior to US shale production boom. I think a lot of acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so we have to look project by project, unfortunately. For purposes of a model, I think $8 million is probably in the ballpark.
I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick with, being US based). The companies do not do that, those costs are included in depreciation, depletion and amortization expense.
Once the well is in production, and failures occur, I include the cost of repairs, including replacement equipment, in LOE. I am not sure that the companies do that, however.
I think the Permian is going to be much tougher to estimate, as there are different producing formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1 or 2.
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 am
I am neither an oil man nor an accountant, so regardless of what we call it I am assuming natural gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to operate the well (LOE, OPEX, financial costs, etc), we could add another million to the cost of the well for surface and downhole equipment and land costs.
Does an average operating cost over the life of a well of about $17/b ($14/b plus natural gas sales of $3/b of oil produced)seem reasonable? That would be about $5.4 million spent on LOE etc. over the life of the well (assuming 320 kbo produced). Also does the 10% nominal rate of return sound high enough, what number would you use as a cutoff?
You use a different method than a DCF and want the well to pay out in 60 months. This would correspond to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3% annual inflation rate.)
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis."Mike says: 11/17/2016 at 1:24 pm
Exactly. USGS' estimate as of October 2015 is very conservative:
"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1 million barrels of natural gas liquids, according to the first USGS assessment of continuous (unconventional), technically recoverable resources in the Monterey Formation."
"The volume estimated in the new study is small, compared to previous USGS estimates of conventionally trapped recoverable oil in the Monterey Formation in the San Joaquin Basin. Those earlier estimates were for oil that could come either from producing more Monterey oil from existing fields, or from discovering new conventional resources in the Monterey Formation."
Previous USGS estimates were for conventional oil:
"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin, estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in 2012, USGS assessed the potential volume of oil that could be added to reserves in the San Joaquin Basin from increasing recovery in existing fields. The results of that study suggested that a mean of about 3 billion barrels of oil might eventually be added to reserves from Monterey reservoirs in conventional traps, mostly from a type of rock in the Monterey called diatomite, which has recently been producing over 20 million barrels of oil per year."
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp. Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA and awaiting re-drills; that should tell you something. With acreage, infrastructure and water costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste of time, sorry.Dennis Coyne says: 11/17/2016 at 8:54 am
Hi JG,Boomer II says: 11/17/2016 at 3:25 pm
What is the average cost of drilling and completion (including fracking) for a horizontal Wolfcamp well?
Does the F95 estimate of 11 Gb seem reasonable if oil prices go up to over $80/b (2016 $) and remain above that level on average from 2018 to 2025?
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 pm
Seems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling.
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well spacing, pick total acreage, pick a factor for dry holes – multiply a by c by d and divide by b."AlexS says: 11/16/2016 at 4:09 pm
The 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 pm
I do not know if the estimated potential production area is too big, or assumed well spacing is too tight.
The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc.
Significant part of resources may never be developed, even if they are technically recoverable.
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves times 1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3 Gb of 2P reserves that have been added to Permian reserves since 2011, if we assume most of these are from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that total proved plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved plus 3.5 GB probable with the assumption that probable=proved/2). I have assumed about 30% of total Permian 2P reserves is in the Wolfcamp shale. That is a WAG.AlexS says: 11/16/2016 at 7:01 pm
Note the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a conservative guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go to $85/b and remain at that level the F95 estimate may become ERR, at $100/b maybe the median is potentially ERR. It will depend how long prices can remain at $100/b before an economic crash, prices are Brent Crude price in 2016$ with various crude spreads assumed to be about where they are now.
Dennis,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 pm
I just looked at Permian Basin crude reserves (Districts 7C, 8 and 8A) and assumed the change in reserves from 2011 to 2014 was from the Wolfcamp. I didn't know about that page for reserves. It is surprising it is that low.
In any case the difference is small relative to the UTRR, it will be interesting to see what the reserves are for year end 2015.
Based on this I would revise my estimate to 20 Gb for URR with a conservative estimate of 12 Gb until we have the data for year end 2015 to be released later this month.
My guess is that the USGS probably already has the 2015 year end reserve data.
Dennis,Dennis Coyne says: 11/16/2016 at 10:09 pm
The EIA proved reserves estimate for 2015 will be issued this month. I think we will see a significant increase in the number for the Permian basin LTO.
Also note that USGS TRR estimate is only for Wolfcamp.
I can only guess what could be their estimate for the whole Permian tight oil reserves.
But the share of Wolfcamp in the Permian LTO output is only 24% (according to the EIA/DrillingInfo report).
Hi Alex S,AlexS says: 11/17/2016 at 4:32 am
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 am
Wolfcamp is a newer play than Bone Spring and Spraberry. That's why its share in the Permian LTO production is less than in TRR.
Hi AlexS,shallow sand says: 11/16/2016 at 5:18 pm
That makes sense. I also imagine the USGS focused on the formation with the bulk of the remaining resources. It is conceivable that the 30 Gb estimate is closer to the remaining oil in place and that more like 90% of the TRR is in the Wolfcamp, considering that the F5 estimate is about 30 Gb. That older study from 2005 may be an under estimate of TRR for the Permian, likewise the USGS might have overestimated the UTRR.
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 pm
If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp up at the speed of the Eagle Ford (say 2 to 3 years). It will be oil price dependent and perhaps they won't over do it like in 2011-2014, but who knows, some people don't learn from past mistakes. If you or Mike were running things it would be done right, but the LTO guys, I don't know.
shallow sand,Boomer II says: 11/16/2016 at 3:39 pm
Yes, 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 pm
USGS Estimates 20 Billion Barrels of Oil in Texas' Wolfcamp Shale Formation
"This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically recoverable resources.
Undiscovered resources are those that are estimated to exist based on geologic knowledge and theory, while technically recoverable resources are those that can be produced using currently available technology and industry practices. Whether or not it is profitable to produce these resources has not been evaluated."
This is an important way to assess.Fred Magyar says: 11/17/2016 at 11:18 am
If it requires slave labor at gunpoint to get the oil out, then that's what will happen because you MUST have oil, and a day will soon come when that sort of thing is reqd.
Nice apocalyptic vision of the future you've got there!George Kaplan says: 11/16/2016 at 3:16 pm
Whatever happened to the ideals of democracy, capitalism, business, profits, free markets etc ? Don't worry, no need to answer, that was purely a rhetorical question. I'm quite aware of the realities of the world!
However, not to pour too much sand on your vision, But I have to wonder? Since your potential slaves in 21st century America are already armed to the teeth, they might decide not to just go with the flow. (pun intended)
Anyways slaves don't buy cars or too many consumer goods so that might, in and of itself, put a bit of a damper on the raison d'etre, excuse my french, of the oil companies and the very existence of these future slave owners.
because you MUST have oil
Really now?! You know, as time goes by, I'm less and less convinced of that!
This follows on from reserve post above (two a couple of comments). In terms of changes over the last three years – there really weren't anything much dramatic. We'll see what 2016 brings, especially for ExxonMobil, but it looks like they already knocked a big chunk off of their Bitumen numbers already in 2015.Jeff says: 11/16/2016 at 3:20 pm
Note I went through a lot of 20-F and 10-K reports watching the rain fall this morning and copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general trends are shown.
Note the figures are totals for all nine companies I looked at.
IEA WEO is out: http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html presentation slides, fact sheet and summary are available online (report can be purchased). IEA seems to be _very_ concerned about underinvestment in upstream oil production. Several pages of the report is devoted to this, the title of that section is "mind the gap". More or less all of the content has been discussed on this website, including the issue with high levels of debt and that this can affect suppliers' capacity to rebound, and how much demand can be reduced as a result of a stringent carbon cap.George Kaplan says: 11/17/2016 at 3:42 am
From the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil sands) approved for development in 2015 sank to the lowest level since the 1950s, with no sign of a rebound in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely that demand (as projected in our main scenario) and supply can be matched in the early 2020s without the start of a new boom/bust cycle for the industry"
Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"
I wonder who that paragraph is aimed at. As I indicated above the companies that would be investing in long term conventional projects don't have a very large inventory of undeveloped reserves (17 Gb as of end of 2015, some of this has gone already this year and more is in development and will come on stream in 2017 and 2018 (and a small amount in later years for approved projects). I'd guess there might only be less than 10 Gb (and this the most expensive to develop) that is currently under appraisal among the major western IOCs and larger independents; allowing for their partnerships with NOCs in a lot of the available projects that could represent 20 to 30 Gb total. That really isn't very much new supply available, and a large proportion is in complex deep water projects that wouldn't be ramped up fully until 6 to 7 years after FID (i.e. already too late for 2020). Really the main players need to find new fields with easy developments, but they obviously aren't, probably never will, and actually aren't looking very hard at the moment.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 pm
It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect economic growth", "geology is about to beat human ingenuity" etc.
WEO have become more and more bizarre over the years. On the one hand they contain quantitative projections which tell the story politicians wants to hear. On the other hand, the text describes all sorts of reason of why the assumptions are unlikely to hold. Normally, if you don't believe in your own assumptions you would change them.
Hi,FreddyW says: 11/16/2016 at 3:50 pm
Here are my updates as usual. GOR declined or stayed flat for all years except 2010 in September. Is it the beginning of a new trend?
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 pm
The 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 pm
And I guess we can all see no technological breakthru. 2014's green line looks superior to first 3 mos 2015.
2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper decline at that point and is likely going to intersect 2014's line probably within the year.
There is zero evidence on that compilation of any technological breakthrough surging output per well in the past 2-3 yrs.
In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular EUR improvement.
And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also no evidence of sweetspots first.
I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with inferior technology, and then as they became less sweet the technological breakthroughs brought output up to look the same.
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 pm
And it would be far too much coincidence for techno breakthrus to just happen to increase flow the exact amount lost from exhausting sweet spots.
This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet.
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.Watcher says: 11/18/2016 at 12:03 am
Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. Nobody is breaking new ground or making big strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank areas will be even less economical (if that is possible) and will result in significantly less UR per well. That is what is ridiculous about modeling the future based on X wells per month and trying to determine how much unconventional shale oil can be produced in the US thru 2035. The term, "past performance is not indicative of future results?" We invented that phrase 120 years ago in the oil business.
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra stages post 2008/9/10. How could there not be going from 15 stages to 30+?Watcher says: 11/18/2016 at 12:14 am
I see NO magic post peak. They all descend exactly the same way and by 18-20 months every drill year is lined up. That's actually astounding - given 15 vs 30 stages. There should be more volume draining on day 1 and year 2, but the flow is the same at month 20+ for all drill years. This should kill the profitability on those later wells because 30 stages must cost more.
But profit is not required when you MUST have oil.
You know, that is absolutely insane.FreddyW says: 11/18/2016 at 2:55 pm
Freddy, is there something going on in the data? How can 30 stage long laterals flow the same at production month 24 as the earlier dated wells at their production month 24 –whose lengths of well were MUCH shorter?
I can only speculate why the curves look like they do. It could be that the newer wells would have produced more than the older wells, but closer well spacing is causing the UR to go down.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 pm
What is the annual decline rate of the 2007 wells from month 98 to month 117 and how many wells in that sample (it may be too low to tell us much)?
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 pm
Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one way to do it would be to look at the natural log of monthly output vs month for each year and see where the curve starts to become straight indicating exponential decline. The decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely different, I am speculating about the possible cause.
2007 had much lower initial production and the long late plateau gives it a low decline rate also. But yes, initial decline rates look similar to the other curves. If you look at the individual 2007 wells then you can see that some of them have similar increases to production as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that those increases are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau. If that is the case, then 2007 may not be different from the others at and we will see increased decline rates in the future.Dennis Coyne says: 11/17/2016 at 8:42 am
Regarding natural log plots. Yes it could be good if you want to find a constant exponential decline. But we are not there yet as you can see in above graph.
One good reason why decline rates are increasing is because of the GOR increase. When they pump up the oil so fast that GOR is increasing, then it's expected that there are some production increases first but higher decline rates later. Perhaps completion techniques have something to do with it also. Well spacing is getting closer and closer also and is definitely close enough in some areas to cause reductions in UR. But I would expect lower inital production rather than higher decline rates from that. But maybe I´m wrong.
Hi FreddyW,Dennis Coyne says: 11/17/2016 at 12:40 pm
Do you have an estimate of the number of wells completed in North Dakota in September? Does the 71 wells completed estimate by Helms seem correct?
Hi FreddyW,FreddyW says: 11/17/2016 at 2:19 pm
Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed in Sept 2016.
I have 75 in my data, so about the same. They have increased the number of new wells quite alot the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it increased withouth the rig count going up. But I see that the rig count has gone up now too.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 pm
Even though you asked Ron. He might think that the decline in the number of new wells per month may have stabilized at around 71 new wells per month. If that rate of new completions per month stays the same there will still be decline but the rate of decline will be slower. Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).
I am not so convinced that either Texas or the Bakken is finished declining at the current level of completions. There was consistent completions of over 1000 wells in Texas until about October of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than they are completing.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 am
The wells being shut in are not nearly as important as the number of wells completed because the output volume is so different. So the average well in the Eagle Ford in its second month of production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So about 37 average wells need to be shut in to offset one average new well completion.
Point is that total well counts are not so important, it is well completions that drive output higher.
Output is falling because fewer wells are being completed. When oil prices rise and profits increase, completions per month will increase and slow the decline rate and eventually raise output if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec 2017 about 79 new wells per month is enough to cause a slight increase in output. My model slightly underestimates Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30 kb/d lower than actual output (3% too low), my well profile may be slightly too low, but I expect eventually new well EUR will start to decrease and my model will start to match actual output better by mid 2017 as sweet spots run out of room for new wells.
Guess I will remember that for the future. The number of producing wells is not important. Kinda like I got pooh poohed when I said the production would drop to over 1 million barrels back in early 2015.Dennis Coyne says: 11/17/2016 at 10:39 am
Hi Guy,Guy Minton says: 11/18/2016 at 4:50 am
Do you agree that the shut in wells tend to be low output wells? So if I shut down 37 of those but complete one well the net change in output is zero.
Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the net change in output would be zero, but there would be 19,000 fewer producing wells, if we assume the average output of the 1000 new wells completed was 200 b/d for the year and the stripper wells produced 10 b/d on average.
How much do you expect output to fall in the US by Dec 2017?
Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by about 1 million barrels per day from April 2015 to July 2016, can you point me to your comment where you predicted this?
Tell us what it will be in August 2017.
I expected the fall in supply would lead to higher prices, I did not expect World output to be as resilient as it has been and I also did not realize how oversupplied the market was in April 2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan to April, so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US output has decreased by 635 kb/d.
If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would also have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400 kb/d. If we consider 12 month average output of World C+C, the decline has been 340 kb/d from the 12 month average peak in August 2015 (centered 12 month average).
The dropping numbers are not as much from the wells that produce less than 10 barrels a day, but from those producing greater than 10, but less than 100. The ones producing greater than 100 are remaining at a consistent level over 9000 to 9500. The prediction on one million was as to the US shale only. It is your site, you can search it better than I can,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 pm
From the Director's Cut:
"The number of well completions rose from 63(final) in August to 71(preliminary) in September"
(North Dakota total)
From the EIA DPR:
The number of well completions declined from 71 in August to 52 in September and rose to 58 in October
(Bakken North Dakota and Montana).
Wells drilled, completed, and DUCs in the Bakken.
Source: EIA DPR, November 2016
Hi Alex S,shallow sand says: 11/17/2016 at 8:36 am
I trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno Peters data has 66 completions in August 2016, he has not put up his post for the Sept data yet so I am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno tends to be spot on for the Bakken data, for Texas he relies on RRC data which is not very good.
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.shallow sand says: 11/17/2016 at 8:58 am
It appears this was because another 13 wells in the field were recently completed.
It appears that when all 29 wells are returned to full production, this field will be very prolific initially. Therefore, on this one field alone, we could see some impact for the entire state.
Does anyone know if these wells are part of Whiting's JV? Telling if they had to do that on these strong wells. Bakken just not close to economic.
I also note that average production days per well in for EOG in Parshall was 24. I haven't looked at some of the other "older" large fields yet, but assume the numbers are similar.
Also, over 3000 Hz wells in ND produced less than 1000 BO in 9/16.Dennis Coyne says: 11/17/2016 at 10:57 am
This is just for wells with first production 1/1/07 or later.
Hi Shallow sand,shallow sand says: 11/18/2016 at 8:20 am
I agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk costs in wells drilled but not completed and running the numbers based on whether they can pay back the completion costs. Everyone may be hoping the other guys fail and are just trying to pay the bills as best they can, not sure if just stopping altogether is the best strategy.
There is the old adage that when your in a hole, more digging doesn't help much.
So my model just assumes continued completions at the August rate for about 12 months with gradually rising prices as the market starts to balance, then a gradual increase in completions as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90 completions per month 18 months later). At that point oil prices have risen to $97/b and LTO companies are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at that level for 40 years (not likely, but the model is simplistic).
I could easily do a model with no wells completed, but I doubt that will be correct. Suggestions?
Dennis. As we have discussed before, tough to model when there is no way to be accurate regarding the oil price.Dennis Coyne says: 11/18/2016 at 10:03 am
I continue to contend that there will be no quick price recovery without an OPEC cut. Further, the US dollar is very important too, as are interest rates.
Hi Shallow sand,George Kaplan says: 11/17/2016 at 3:31 am
At some point OPEC may not be able to increase output much more and overall World supply will increase less than demand. My guess is that this will occur by mid 2017 and oil prices will rise. OPEC output from Libya an Nigeria has recovered, but this can only go so far, maybe another 1 Mb/d at most. I don't expect any big increases from other OPEC nations in the near term.
A big guess as to oil prices has to be made to do a model.
I believe my guess is conservative, but maybe oil prices will remain where they are now beyond mid 2017.
I expected World supply to have fallen much more quickly than has been the case at oil prices of $50/b.
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 am
For the record, I have no interest or connection to this publication other than that of a paying reader.
Wouldn't it be nice if mainstream publications would sound a bit more like this.
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 am
Sometimes I think that once the price of oil is up enough that sellers can hedge the their selling price for two or three years at a profitable level, it will hardly matter what the banks have to say about financing new wells.
At five to ten million apiece, there will probably be plenty of money coming out of various deep pockets to get the well drilling ball rolling again, if the profits look good.
Sometimes the folks who think the industry will not be able to raise money forget that it's not a scratch job anymore. The land surveys, roads, a good bit of pipeline, housing, leases, etc are already in place, meaning all it takes to get the oil started now is a drill and frack rig.
I don't know what the price will have to be, but considering that a lot of lease and other money is a sunk cost that can't be recovered, and will have to be written off, along with the mountain of debts accumulated so far, the price might be lower than a lot of people estimate.
Bankruptcy of old owners results in lowering the price at which an old business makes money for its new owners.
Hi Pete,Enno Peters says: 11/17/2016 at 11:48 am
The Red Queen effect is that more and more wells need to be completed to increase output. As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output it might require 120 wells to be completed to maintain output (if new well EUR did not eventually decrease), but at 850 kb/d it might require about 78 new wells per month to maintain output.
I'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 am
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 pm
Yes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old wells for example, and already include those that were spud last month (even though maybe casing has not been set). I don't do a lot of filtering, so the actual # wells that really can be completed is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know Bloombergs method exactly, so I can't comment on that.
Concerning Freddy's chart of production profile of wells drilled in various years.AlexS says: 11/18/2016 at 4:36 pm
They all line up by about month 18 of production. This should not be possible. The later wells have many more stages of frack. They are longer, draining more volume of rock. But the chart says what it says. At month about 18 the 2014 wells are flowing the same rate as 2008 wells. We know stage count has risen over those 6 yrs. 2014 wells should flow a higher rate. The shape of the curve can be the same, but it should be offset higher.
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 pm
Look at the lines. At 18 months AND BEYOND, these longer laterals flow the same oil rate as the shorter laterals did at the same month number of production. Higher IP and higher decline rate will affect the shape, but There Is Twice The Length..
Hi Watcher,Watcher says: 11/18/2016 at 8:31 pm
I don't think we have information on the length of the wells, since 2008 the length of the lateral has not changed, just the number of frack stages and amount of proppant. This seems to primarily affect the output in the first 12 to 18 months, and well spacing and room in the sweet spots no doubt has some effect (offsetting the greater number of frack stages etc.).
Listen to Mike, he knows this stuff.
From http://www.dtcenergygroup.com/bakken-5-year-drilling-completion-trends/FreddyW says: 11/19/2016 at 7:22 am
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 am
If some bottleneck physically exists that defines a flow rate for all wells from all years then that does indeed explain the graphs, but what such thing could exist that has a new number each year past year 2?
We certainly have discussed chokes for reservoir/EUR management, but the same setting to define flow regardless of length?
The flow depends on the available pressure drop, which is made up of friction through the rock and up the well bore (plus maybe some through the choke but not much), plus the head of the well, plus a negative number if there is a pump. The frictional and pump numbers depend on the flow and all the numbers depend on gas-oil ratio. Initially there is a big pressure drop in the rock because of the high flow, then not so much. Once the flow drops the pressure at base of the well bore just falls as a result of depletion over time, the effect of the completion design is a lot less and lost in the noise, so all the wells behave similarly. That's just a guess – I have never seen a shale well and never run a well with 10 bpd production, conventional or anything else.clueless says: 11/18/2016 at 2:30 pm
A question might be if the flow is the same why doesn't the longer well with the bigger volume deplete more slowly, and I don't know the answer. It may be too small to notice and lost in the noise, or to do with gas breakout dominating the pressure balance, or just the way the the physics plays out as the fluids permeate through the rock, or we don't have long enough history to see the differences yet.
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 am
RRC Texas for September came out recently. As others will probably elaborate more on the data, I just want to show if year over year changes in production could be use as a predictive tool for future production (see below chart).
It is obvious that year over year changes (green line) beautifully predicted oil production (red line) at a time lag of about 15 month. Even when production was still growing, the steep decline of growth rate indicated already the current steep decline.
The interesting thing is that the year over year change is a summary indicator. It does not tell why production declines or rises. It can be the oil price, interest rates or just depletion – even seasonal factors are eliminated. It just shows the strength of a trend.
I am curious myself how this works out. The yoy% indicator predicts that Texas will have lost another million bbl per day by end next year. That sounds quite like a big plunge. One explanation could be the fact that we have now low oil prices and high interest rates. In all other cycles it has been the other way around: low oil prices came hand in hand with low interest rates. This could be now a major obstacle for companies to grow production.
This concept of following year over year changes works of course just for big trends, yet for investment timing it seems exactly the right tool. Another huge wave is coming in electric vehicles which are growing in China by 120% year over year. Here we have the same situation as for shale 7 years ago: Although current EV sales are barely 1 million per year worldwide, the growth rate reveals already an huge wave coming. So as an investor it is always necessary to stay ahead of the trend and I think this can be done by observing the year over year% change.
Mar 02, 2019 | www.zerohedge.com
-- ALIEN -- , 15 hours ago linkKimAsa , 22 hours ago link
Peak 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.
Feb 26, 2019 | peakoilbarrel.com
shallow sand x Ignored says: 02/25/2019 at 5:45 pmCLR. 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.
Feb 26, 2019 | peakoilbarrel.com
Opritov Alexander x Ignored says: 02/26/2019 at 6:51 amInteresting, New, Informativeyves x Ignored says: 02/26/2019 at 7:44 am
Alexey Evgenievich Anpilogov
(Алексей Евгеньевич Анпилогов):
New "Dark Ages"?
human energy future
In the third decade of the XXI century, which is about to come, one of the main problems facing humanity, again, as in the 60s, will be its energy supply, as well as the search for the main "energy carrier of the future."
The three whales that the world's energy industry today holds: oil, natural gas and coal are, by their nature, non-renewable sources of energy. True, with regard to oil and gas, this thesis is actively debated at the academic level, but for practical purposes it is indisputable: modern civilization consumes so much hydrocarbons that their natural substitution, if it exists, is not able to compensate for this exemption. The energy sources mentioned above in 2017 accounted for about 81% of world primary energy production, and they still define the image of our modern industrial world, while all renewable energy sources provide only about 14% of primary energy production, and about 5% The balance comes from nuclear energy (International Energy Agency, 2017).
At the same time, the situation with renewable sources is not at all as rosy as it may seem at first glance: out of 14% of renewable sources, 10% is the energy from burning wood and biomass, and 2.5% is hydropower. At the same time, the "fashionable" in the last decade, and having received at the same time gigantic, almost trillion-dollar investments in solar and wind energy projects, are not as high as 2% in the overall balance of the production of primary energy. At the same time, it is not even about the absolute figures for the introduction of new capacities of green energy, which may seem impressive, but about the exponential dynamics of the relationship between "oil-coal-gas" and "green" in the long term. After all, a decade ago, in 2008, the world balance of power generation looked like this: 78% were oil, natural gas and coal, 5% were atomic energy, 3% were hydropower, about 13.5% were wood and biomass, and 0, 5% produced wind and solar energy. Surprisingly, over the past ten years, the transition from "wood and straw" to the energy of oil, natural gas and coal, which occurred naturally, turned out to be two and a half times more significant for the global energy balance than the development of "green" energy technologies.
The phenomenon of such meager growth of "green" energy is interesting in itself: for the first time the capitalist mode of production, in which investments in fixed assets imply quick returns in the form of profits, gives an obvious, albeit programmed failure. Its essence becomes clear if we take into account in the picture the "quiet" transition of the world from "firewood and straw" to oil, gas and coal, which lasted throughout the decade of 2008–2018. This process, which no one financed in a targeted manner or advertised in the world media or Western scientific publications, went forward thanks to economic expediency. At the same time, the planting of green energy was accompanied not only by a powerful public relations campaign and trillions of financing, but also forced almost all countries to accept special, non-economic overpriced tariffs for the purchase of green energy in order to somehow force capital to finance unprofitable production. energy with wind turbines and solar panels.
World energy: a general view
Several reputable organizations are engaged in the problem of the global energy balance. These include the United States Department of Energy (DOE), the International Energy Agency (IEA), located in Paris, and the well-known oil company BP (ex-British Petroleum). Each of these organizations publishes annual reports on the situation in the global energy industry and the prospects for its development. These reports are compiled on the basis of an analysis of the mass of primary information, often of an incomplete and contradictory nature. Nevertheless, due to a certain averaging of all the initial data, the annual reports of these organizations quite fully and clearly reflect the overall world dynamics. In this article, in order to bring the data to one standard, we will rely on the annual reports of BP, unless otherwise explicitly stated in the text.
In accordance with the latest available BP report, global energy consumption reached 13,511 million tons of oil equivalent in 2017 (TNE, eng. "Tonne of oil equivalent", TOE). At the same time, over the decade between 2007 and 2017, world primary energy consumption grew by an average of 1.5%. That is, the dynamics of energy consumption correlate well with the observed growth rates of the global economy over the same period – an average of 3.2% per year (World Bank and IMF, 2018).
The fluctuations of this second parameter, associated with economic crises and recessions observed in the period under review, make it possible to evaluate the contribution of the notorious "energy efficiency" to the global growth in demand"this thesis is actively debated at the academic level".Ron Patterson x Ignored says: 02/26/2019 at 8:17 am
What 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.
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.
Frackers Face Harsh Reality as Wall Street Backs Away; Key lifeline for smaller operators fades, as losses pile up and prospects dim for big investment returns
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.
Feb 22, 2019 | peakoilbarrel.com
likbez x Ignored says: 02/22/2019 at 1:26 pmVulture funds started to descend on shale oil companies
And that was just overnight. On Friday morning, another activist, Kimmeridge Energy Management Co., announced it had taken a stake in PDC Energy Inc., an exploration and production company with operations in Colorado and Texas. Kimmeridge wants PDC to overhaul its financial priorities, costs, governance and maybe, given the line about "considering all strategic alternatives," its entire identity.
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.
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.
Feb 22, 2019 | peakoilbarrel.com
OFM : 02/17/2019 at 9:06 amI 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.
Feb 22, 2019 | peakoilbarrel.com
Ron Pattersonx 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 amTherefore 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 pm
This is simply mind-blowing. And the more oil they produce, the more oil they need to produce to keep from going negative. How long can they keep this up?https://www.rigzone.com/news/permian_oil_and_gas_production_to_hit_new_records-21-feb-2019-158209-article/
Seems EIA predict production in Permian will increase from 3.98 MMbpd to 4.02 MMbpd next month. Guess it have been mostely flat at least US production have been 11.9 MMbpd since January. Think than an increase of 40 000 /3 month = 13. 333 x12 = 160 000 barrels for 2019 increase seems reasonable. World demand seems increase by 1.5-2.0 MMbpd. Hopefully Permian production will increase significant when tje new pipeline is compleated 4th Quartile 2019 but that remaind to see.
Feb 22, 2019 | peakoilbarrel.com
Doc Rich x Ignored says: 02/21/2019 at 7:24 pmReviewing 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 pm
I'm not one of the experts, but I can nevertheless answer your question!
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.
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.
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.
Feb 15, 2019 | peakoilbarrel.com
TechGuy x Ignored says: 02/15/2019 at 1:23 pmHugo 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.
Feb 15, 2019 | peakoilbarrel.com
Watcher: 02/15/2019 at 4:24 amI 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 pm
High vapor pressure NGLs get labeled liquefied petroleum gas, and that is used for transportation fuel in India. Pentane Plus is used or called something akin to natural gasoline.
You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be. Iran is using this to dodge sanctions, or they did use it when condensate was not restricted. Don't recall if that loophole was closed in the current sanctions. That would be a good thing to know.
The same thing can happen with shale. We hear all sorts of talk about how much gas is being flared and how much gas is being captured, and you know perfectly well there has to be condensate involved. There was an article a year or so ago about NGL capture in the Bakken, but I don't recall any follow-up. It shouldn't take too much of a stretch on the part of state regulators to find a way to count the high vapor pressure portion of NGL as oil.
You can see how the definitions are going to blur and they're going to allow declaring oil production numbers to be anything that they want them to be.
Exactly. And this, in turn, allows Wall Street to suppress the price of "prime oil" using fake production numbers, fake storage glut (which is essentially condensate glut) and similar tricks. Please note that the US refineries consume mainly "prime oil" while the USA mainly produces (and tries to export at a discount) "subprime oil."
Pretty polished and sophisticated racket. It might well be that shale oil companies are partially financed from those Wall Street profits as nobody in serious mind expect those loans to be ever repaid.
So OPEC cuts are the only weapon that OPEC countries have against this racket.
In any case, I think all those nice charts now need to be split into "prime oil" and subprime oil parts and analyzed separately. In the current conditions, treating "heavy oil" and condensate as a single commodity looks to me like pseudoscience.
Feb 15, 2019 | peakoilbarrel.com
dclonghorn x Ignored says: 02/14/2019 at 3:14 pmI 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 pm
Laredo is a nice sized E&P producing around 70,000 boepd in the permian, mostly in Glasscock and Regan counties. Much of their production is horizontal Wolfcamp.
Laredo has been disappointed with its oil production recently, as well as an increasing GOR.
"Laredo has taken action to address the reduced oil productivity experienced in 2018 that we believe was impacted by the tighter spacing of some wells drilled in 2017 and 2018. Responding to these results, the Company began widening spacing on wells spud in the first quarter of 2019. Laredo expects this shift in development strategy to drive higher returns and increased capital efficiency versus 2018 as widening spacing is anticipated to address one of the causes of higher oil decline rates."
They have changed their developmental strategy to widen spacing to improve recovery and mitigate the increasing GOR. They have also reduced their capex by around 35 % from $575 million in 2018 to a planned $365 million in 2019.
"Responding to the current commodity price environment of WTI strip pricing of approximately $54 per barrel, Laredo expects to invest approximately $365 million in 2019, excluding non-budgeted acquisitions. This budget includes approximately $300 million for drilling and completion activities and approximately $65 million for
production facilities, land and other capitalized costs. Laredo anticipates adjusting capital spending levels to match operating cash flow if operating cash flow does not meet budgeted expectations. Should operating cash flow exceed budget expectations, free cash flow could be used to complete additional wells, repurchase stock or pay
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.
http://www.laredopetro.com/media/223310/21319-laredo-petroleum-announces-2018-fourth-quarter-and-full-year-financial-and-operating-results.pdfInteresting. 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.
Feb 15, 2019 | peakoilbarrel.com
Ron Patterson x Ignored says: 02/14/2019 at 4:37 pmI 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.
Feb 15, 2019 | peakoilbarrel.com
Ron Patterson x Ignored says: 02/14/2019 at 5 :39 pmFood for thoughtRavi x Ignored says: 02/14/2019 at 11:05 pm
I 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?
Feb 14, 2019 | oilprice.com
This fallacious narrative of the U.S. tight oil industry overcoming the oil price crash of 2014 through innovation and better efficiency is the product of bundling various tight oil basins under one umbrella and the presentation of the resulting production data as a proof U.S. shale resiliency.
To properly understand the impact of the oil price crash of 2014 on U.S. tight oil production one must focus on shale basins with sufficient operating history prior to the oil price crash and examine their performance post the crash.
To that end, the Bakken and the Eagle Ford are the perfect specimen.
The Bakken and the Eagle Ford are the two oldest tight oil basins in the United States, with the former developed as early as 2007 and the latter in 2010.
Examining the production performance of these two basins in the 4 years preceding the oil crash and contrasting it to the 4 years subsequent to it, offers important insight as to the resiliency of U.S. tight oil production in a low oil price environment.
... ... ...Both the Bakken and the Eagle Ford grew at a phenomenal rate between 2010 and 2014. The Eagle Ford grew from practically nothing in 2010 to 1.3M barrels by 2014, while the Bakken grew five fold from 190K barrels to 1.08M barrels. Following the collapse in oil prices in late 2014, the Bakken and Eagle Ford growth continued for another year, albeit at a slower pace, as the pre-crash momentum carried production to new highs. However, by 2016, both the Bakken and the Eagle Ford went into a decline and have hardly recovered since. It took the Bakken three years to match its 2015 production level, meanwhile the Eagle Ford production remains 22% below its 2015 peak. During the pre-crash years these two fields grew by a combined yearly average of 600K to 700K barrels from 2012 to 2014. Post the oil price collapse, this torrid growth turned into a sizable decline by 2016 before stabilizing in 2017.
Growth in both fields only resumed in 2018 at a combined yearly rate of 210K barrels, a 70% reduction from the combined fields pre-crash growth rate.
The dismal performance of these two fields over the last few years paints a different picture as to U.S. tight oil resiliency in a low oil price environment. The sizable declines, and muted production growth in both the Bakken and the Eagle Ford since 2014 discredit the leap in technology and the efficiency gains narrative that has been espoused as the underlying reason beyond the strong growth in U.S. oil production. As we expand our look into other tight oil basins, it becomes apparent that it was neither technology or efficiency that saved the U.S. tight oil industry, although these factors may have played a supporting role. In simple terms, the key reason as to the strength of U.S. production since the 2014 oil crash is better rock, or rather, the commercial exploitation of a higher quality shale resource, namely the Permian oil field.
... ... ...
The Permian oil field, unlike the Bakken and the Eagle Ford, was a relative latecomer to the U.S. tight oil story. It was only in 2013, only a year before the oil crash, that the industry commenced full scale development of that giant field's shale resources. Prior to 2013, the Permian lagged both the Bakken and the Eagle Ford in total tight oil production and growth. As can be seen from the preceding graph, the oil crash had only a minor dampening effect on the Permian oil production growth. By 2017, Permian tight oil growth resumed at a healthy clip, and by 2018, Permian tight oil production growth shattered a new record with production skyrocketing by 860K barrels in a single year to 2.76M barrels. This timely unlocking and exploitation of the Permian oil basin masked to a large degree the devastation endured by the Bakken and the Eagle Ford post 2014. In essence, the U.S. tight oil story has two phases masquerading as one: the pre-2014 period marked by the birth and rise of the Bakken and Eagle Ford, and the post-2014 period, marked by the rise of the Permian.
To speak of the U.S. tight oil industry as one is to mistake a long-distance relay race for the accomplishment of a single runner.
The performance divergence between the Bakken, Eagle Ford, and the Permian has major implications as to the likelihood of U.S. tight oil production suppressing oil price over the medium and long term. A close examination of U.S. tight oil production data leads to a single indisputable conclusion: without the advent of the Permian, the U.S. tight oil industry would have lost the OPEC lead price war. Hence, it's a misnomer to treat the U.S. tight oil industry as a monolith, in many ways, the Bakken and the Eagle Ford tight oil fields are as much a victim of the Permian success as the OPEC nations themselves.
... ... ...Considering that the majority of U.S. tight oil production growth is generated by a single field, the Permian, changes in the growth outlook of this basin have major implications as to the evolution of global oil prices over the short, medium and long term. Its important to keep in mind that the Permian oil field, despite its large scope, is bound to flatten, peak and decline at some point. While forecasters differ as to the exact year when the Permian oil production will flatten, the majority agree that a slowdown in Permian oil production growth will take place in the early 2020s.
According to OPEC (2018 World Oil Outlook), the Permian basin oil production curve is likely to flatten by 2020, with growth slowing down from 860K barrels in 2018 to a mere 230K barrels by 2020:
Feb 13, 2019 | peakoilbarrel.com
Energy News, 02/12/2019 at 2:29 pmThe EIA's STEO released today.Dennis Coyne, 02/12/2019 at 4:12 pm
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.
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.
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
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?
Feb 08, 2019 | off-guardian.org
Narrative says Feb, 1, 2019Nations 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.
The latest sanctions on Venezuela's state-owned oil company aim to cut off source of foreign currency of Venezuelan strongman Nicolas Maduro's government and eventually force him to step down.
A new mechanism should be devised to thwart such a vicious circle"
http://www.globaltimes.cn/content/1137847.shtmlFrancis Lee; Big B,BigB says Feb, 1, 2019
OK 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, 2019
I do not want to get into the mind of the Walrus of Death Bolton! I do not want to know what he does, as he does. But at lower levels of government, and corporatism, there is an awareness of surplus energy economics. And as Nafeez has also pointed out, the military (the Pentagon) are taking an interest. And though it could rapidly change, who really appreciates the nuances of EROEI? I'm guessing at less than a single percent of all populations? And how many include its effects in a integrated political sense?
Its appreciation is sporadic: ranging from tech-utopia hopium to a defeated fatalism of the inevitability of collapse. Unless and until people want to face the harshness of the reality that capitalism has created: we are going to be involved in a marginal analysis. There are very few people who have realised that capitalism is long dead.
Dr Tim Morgan estimates that world capitalism has conservatively had $140tn in stimulus since 2008 -- without stimulating anything or reviving it at all. In fact, that amounts to the greatest robbery in history -- the theft of the future. Inasmuch as they can, those unrepayable debts -- transferred to inflate the parasitic assets of capitalists -- will be socialised. Except they cannot be. Not without surplus energy.
Brexit, gilets jaunes, Venezuela, unending crises in MENA, China's economic slowdown, etc -- all linked by EROEI.
It is a common socio-politico-economic energy nexus -- but linked together by whom? And the emergent surplus energy-mind-environmental ecology nexus? All the information is available. The formation of a new political manifesto started in the 1960s with the New Left but it seems to have been in stasis since. Perhaps this might stimulate the conversation.
According to Nate Hagens: there is 4.5 years of human muscle power leveraged by each barrel of oil. We are all going to be working for a very long time to pay back the debts the possessing classes have built up for us -- with absolutely no marginal utility for ourselves.
We are subsidising our own voluntary slavery unless we develop an emergent ecosocialist and ecosophical alternative to carbon capitalism. We cannot expect paleoconservative carbon relics like Bolton -- or anyone else -- to do it for us. The current political landscape is dominated by a hierarchical, vested interest, carbon aristocracy. We can't expect that to change for our benefit any time ever. Expect the opposite.Graeber has a point, though. We could already have a post-scarcity, post-production society but for the egregious maldistribution of resources and employment. Andre Gorz said as much 50 years ago (Critique of Economic Reason). Why do we organise around production: it makes no sense but for the relations of production are, and remain, the relations of hierarchical rule. So long as we assign value to a human life on the basis of meritocratic productivity -- we will have dehumanisation, marginalisation, and subjugation (haves and have nots). So why not organisation around care, freedom and play?crank says Feb, 2, 2019
Such a solution would require the transversalistion of society and not-full-employment: so that no part of the system is subordinate, and no part is privileged. All systems and sub-ordinate (care) systems would be co-equal, of corresponding value and worth. So, without invoking EROEI, that would go a long way to solve our exergy, waste, pollution, and inequality problems. It is the profligate, unproductive superstructure: supporting rentier, surplus energy accumulating, profit-seeking suprasocieties -- that squanders our excess energy and puts expansive spatio-temporal pressures on already stretched biophysical ecological systems that engenders potential collapse. It is their -- the possessing classes -- assets that are being inflated, at our environmental expense. When it comes to survivability, we cannot afford a parasitic globalised superstructure draining the host -- the ecologically productive base. Without the over-accumulation, overconsumption, and wastage (the accursed share) associated with the superstructure of the advanced economies -- and their cultural, credit, military imperialisms I expect we could live quite well. Without the pressures of globalised transportation networks, and unnecessary military budgets -- the pressure on oil is minimised. It could be used for the 1001 other uses it has, rather than fuelling Saudi Eurofighters bombing Yemeni schoolchildren, for instance. The surplus energy could be used to educate, clothe and feed them instead. That would be a better use of resources, for sure.
If we took stock of what we really have, and what we really are -- a form of spiritual neo-self-sufficiency, augmented and extended into co-mutual care and freedom valorising ecologies we wouldn't need to chase the perceived loss all over the globe, killing everything that moves. The solutions are not hard, they are normative, once we are shocked out of this awful near-life trance state of separationism. Thanks for the link.It seems to me that there are two parallel arguments going on.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, 2019
Welcome to my world! Apart from as a managerial tool, systems thinking has yet to catch on in the wider population. According to reductive materialism: there are two unlinked arguments. According to Dynamic Systems Theory (DST) there is only one integrated argument -- with two inter-connected correlative aspects. We can only organise around what we can energetically afford. Consequently, we cannot organise around what we cannot afford -- that is, global industrialised production with a supervenient elitist superstructure.
Let's face it : ethical arguments carry little weight against organisation around hierarchical rule. The current talk of an ethical capitalism -- in mixed economies with 'commons' elements -- is an appeasement. and distractional to the gathering and ineluctable reality.
The current (2012) EROI for the UK is 6.2:1 -- barely above the 'energy cliff' of 5:1. The GDP 'growth' and bullshit jobs are funded by monetised debt (we borrow around £5 to make every £1 -- from Tim Morgan's SEEDS). From the Earth Overshoot Day website: the UK is in economic overshoot from May 8th onward.
These are indicators that we will not be "flying jetpacks on the moon": even if we reorganise. Everyone, and I mean everyone, will have to make do with less. A lot less. Everything would have to be localised and sustainable. Production would be minimised, and not at all full. Two major systems of production -- food (agroecology) and energy -- would have to be sustainable and self-sovereign. And financialisation and the rentier, service economy? Now you can see why no one, not even Dave the crypto-anarchist, is talking about reality. Elitism, establishment and entitlement do not figure in an equitable future. We can't afford it, energetically or ethically.
So when will the debate move on? Not any time the populace is bought into ideational deferred prosperity. All the time that EROEI is ignored as the fundamental concept governing dwindling prosperity -- no one, and I mean no one, will be talking about a minimal surplus energy future. The magic realism is that the economic affordances of cheap oil (unsustainably mimicked by debt-funding) will return sometime, somehow (the technocratic superfix). The aporia is that the longer the delay, the less surplus energy we will have available to utilise. Something like the Green New Deal -- that has been proposed for around two decades now -- may give us some quality of life to sustain. Pseudo-talk of a Customs Union, 'clean' coal, and nuclear power, will not.
An integrated reality -- along the model of Guattari's 'Three Ecologies' -- of mind, economy, and environment is well, we are not alone, but we are ahead of the curve. The other cultural aporia is that we need to implement such vision now. Actually, about thirty years ago but let's not get depressive!
We are going to need that cooperative organisation around care and freedom just to get through the coming century.As mentioned elsewhere here, Venezualan oil deposits are not all that the hype cracks them up to be. They are mostly oil sands that produce little in the way of net energy gain after the lengthy process of extraction.The Venezuala drama is about the empire crushing democracy (i.e. socialism), not oil. [not that this detracts from Kit's essential point in the article].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?
https://medium.com/insurge-intelligence/brexit-stage-one-in-europes-slow-burn-energy-collapse-1f520d7e2d89"Does Bolton Understand this/? I think this might qualify as a rhetorical question.BigB says Feb, 1, 2019CrankBigB says Feb, 1, 2019
If you were referring to my earlier comments about Venezuelan extra heavy crude: it's still massively about the oil. The current carbon capitalist world system does not understand surplus energy or EROEI, as it is so fixated on maximal short term returns for shareholders. It can't comprehend that their entire business model is unsustainable and self cannibalising. Which is bad for us: because carbon net-energy (exergy) economics it is foundational to all civilisation. The ignorance of it and subsequent environmental and social convergence crises threatens the systemic failure of our entire civilisation. The Venezuelan crisis affects us all: and is symptomatic of a decline in cheap oil due to rapidly falling EROEI.
I can't find the EROEI specifically for Venezuelan heavy oil: but it is only slightly more viscous than bitumen -- which has an EROEI of 3:1. Let's call it 4:1: the same as other tight oils and shale. Anything less than 5:1 is more or less an energy sink: with virtually no net energy left for society. The minimum EROEI for societal needs is 11:1. Does Bolton understand this? Francis hit the nail on the head there.
Do any of our leaders? No. If they did, a transition to decentralisation would be well under way. Globalised supply chains are systemically threatened and fragile. A globalised economy is spectacularly vulnerable. Especially a debt-ridden one. Which way are our leaders trying to take us? At what point will humanity realise we are following clueless Pied Pipers off the Seneca Cliff -- into globalised energy oblivion?
The rapid investment -- not in a post-carbon transition -- but in increased militarisation, and resource and market driven aggressive foreign intervention policies reveal the mindset of insanity. As people come to understand the energy basis of the world crisis: the fact of permanent austerity and increased pauperisation looms large. What will the outcome be when an armed nuclear madhouse becomes increasingly protectionsist of their dwindling share? Too alarmist, perhaps? Let's play pretend that we can plant a few trees and captive breed a few rhinos and it will all be fine. BAU?
The world runs on cheap oil: our socio-politico-economic expectations of progress depend on it. Which means that the modern human mind is, in effect, a thought-process predicated on cheap oil. Oleum ergo sum? Apart from the Middle East: we are already past the point where oil is a liability, not a viability. Debt funding its extraction, selling below the cost of production -- both assume the continual expansion of global GDP. Oil is a highly subsidised -- with our surplus socialisation capital -- negative asset. We foot the bill. A bill that EROEI predicts will keep on rising. At what point do we realise this? Or do we live in hopium of a return to historical prosperity? Or hang on the every word of the populist magic realism demagogue who promises a future social utopia?
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, 2019
EROEI refers to the amount of usable energy that can be extracted from a resource compared to the amount of energy (usually considered to come from the same resource) used to extract it. It's calculated by dividing the amount of energy obtained from a source by the amount of energy needed to get it out.
An EROEI of 1:1 means that the amount of usable energy that a resource generates is the same as the amount of energy that went into getting it out. A resource with an EROEI of 1:1 or anything less isn't considered a viable resource if it delivers the same or less energy than what was invested in it. A viable resource is one with an EROEI of at least 3:1.
The concept of EROEI assumes that the energy needed to get more energy out of a resource is the same as the extracted energy ie you need oil to extract oil or you need electricity to extract electricity. In real life, you often need another source of energy to extract energy eg in some countries, to extract electricity, you need to burn coal, and in other countries, to extract electricity you need to build dams on rivers. So comparing the EROEI of electricity extraction across different countries will be difficult because you have to consider how and where they're generating electricity and factor in the opportunity costs involved (that is, what the coal or the water or other energy source -- like solar or wind energy -- could have been used for instead of electricity generation).
That is probably why EROEI is used mainly in the context of oil or natural gas extraction.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.
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 GMT
Only financial engineering makes it appear profitable. Its a money losing psychopaths power play, not a business. Without a heavy real oil to blend it with its useless, heavy oil is where Venezuela comes in.@Ilyana_Rozumova "Main factor here is that US due to fracking become self sufficient, what actually nobody could foresee. Just a bad luck".Vidi , says: February 7, 2019 at 9:10 pm GMT
Bad luck for the USA. They have fallen into an elephant trap, because fracking has already become unprofitable and is only being financed by ever-increasing debt.
Admittedly this gives them some advantage, but only in the very short term.
Of course, it doesn't really matter – in the short to medium term – whether fracking is profitable or grossly unprofitable. They can still pay for it by printing more dollars, as long as the "greater fools" (or heavily bribed officials) in other countries go on accepting dollars.@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.
Feb 04, 2019 | peakoilbarrel.com
Guym x Ignored says: 01/30/2019 at 6:04 amhttps://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 am
Motiva had previously upgraded refinery capacity to accept light oil, Exxon keeps adding more, and now Chevron will, no doubt, expand.
Maybe the big oil will buy up some more of the weaker Permian players, which could slow down the insane growth; and make the Permian more of a feeder for their refineries than an export source. I really can't imagine that they are spending billions on refineries with the expectation that it may start to expire in five years. Exxon and Chevron are already two of the top ten producers in the Permian, and they can get bigger, if they want to.
Gobbling up most of these producers would only amount to a snack for them. And doing it while the pure Permian producers a floating in the doldrums of 2019 would fit perfectly.
That could affect projections for US shale growth. The refiners would look at it over a longer term usage, and not how much they can ship out. However, it could still lower net imports. Win, win.
Thus, possibly saving West Texas from extinction, and move away from boom or bust some. Add pipelines to the East and West coast, and upgrade refineries, and you have a longer term solution.
With Canadian and Mexican heavy oil and sprinkle in some EOR, we could get by for a longer period of time. Peak oil is a meaningful event, but it does not, absolutely, have to affect the US for a while.
On a different topic, a Japanese company is interested in becoming an Eagle Ford player. Japan needs LNG. Eagle Ford has a largely untapped huge gas window. So, even if we do not use the planned upgraded ports for oil, we may still be using them for LNG.
Ok, it's only a dream, now, but the parts are beginning to come together. Big oil has its benefits, and this benefit fits into big oil's need for future existence. When the price of oil goes up, then what's the projected stock price of Exxon or Chevron? They will be back into the mode they were in decades ago, start to finish.This rings true to me. The big boys have few other options left for expansion (Guyana, Mexico and/or Brazil if they can work their way through the corruption) other than the Permian. Oil prices are likely to remain volatile for the foreseeable future, generating occasional buying opportunities for companies with lots of cash on hand. Kind of the way the tech giants like Apple and Amazon and Facebook bought up all the small fry app/tech companies for lack of anything better to do with their money. If this happens I would expect a slower pace of development to emerge for tight oil over the next decade and a longer tail.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 pm
Chevron's holdings are the size of Yellowstone, and Exxon is not far behind. Will they pick up any additional acreage if the get a good buy? Does a dog bark?https://oilprice.com/Energy/Energy-General/Chevron-Looks-To-Double-Permian-Production-By-2022.htmlSynapsid x Ignored says: 01/30/2019 at 6:51 pm
Plans on growth in the Permian, " .and an increase in net acreage."
Competition with 2 800lbs gorillas?
This says nothing about the quality of rock, but lists acreage by the top holders. Oxy, ConocoPhillips, and EOG will be more conservative in development, and are not really prime acquisition targets. But adding them and Exxon and Chevron, you get most of the acreage. Energen and Diamondback have merged.Thanks Guym,John x Ignored says: 01/31/2019 at 12:37 pm
This 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 pm
Leach, chairman and chief executive officer of Concho Resources, cited statistics indicating Permian Basin crude production is expected to climb from the current 4 million barrels a day to 6 million barrels a day in just six years. That, he told the sold-out crowd at the Horseshoe, would comprise 7 percent of total world oil production and 40 percent of U.S. production. In addition, the Permian Basin could see 45,000 new high-paying technical jobs on top of the 50,000 jobs that have been created since about 2000.
"Companies operating here today will be investing $50 billion a year in drilling and completing wells," leading to over $1 trillion in spending in that same timeframe, he said. That has created numerous opportunities throughout the Permian Basin, but also significant challenges, he said.
When he and other leaders of local oil companies review their business plans and consider their greatest concerns, he said it's not sand or pipeline capacity or technology. "Collectively, they say it's schools, roads, doctors and housing."Ok. Concho managed to eek out a loss the third quarter. Good source of info.
Feb 04, 2019 | peakoilbarrel.com
Davo , 01/29/2019 at 4:25 pmNew 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 box but your last sentence may hold some validity. For that matter, I don't think shale has given up completely after the first go round, if the price is right. Would that delay peak to another date? Quien sabe. Money talks. What price? I know I would keep an ICE around for long trips at $200 a barrel for the convenience. Food may be higher, though.Timthetiny , 01/30/2019 at 1:50 pmSpeaking 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 pm
Also there is the cost. If it takes more energy to extract the oil from shale than you get from the oil you pump out then it is a sink, not a source. For instance it would be extremely difficult to extract oil from offshore shale. You would have to ship the sand out by barge, build huge platforms for every well to hold all that fracking equipment and so on.
There are lots of shale oil sources in Russia. And if prices get high enough, they will probably try to extract it. Imagine hauling train loads of sand to the north slope of Alaska, then trucking it over the tundra by truck to every well. You would have similar problems in Western Siberia.
Return on investment is the primary problem with shale. If it cost more in time and energy than you receive from the extracted producte, it will stay in the ground. Anyway, that's just my unprofessional opinion. Some of the professionals on this blog may have a better educated opinion."If it cost more in time and energy than you receive from the extracted producte, it will stay in the ground."Ron Patterson , 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 am
So you see it is just not that simple. They may produce oil at a loss for some time before they fold. But obviously they cannot produce oil at a loss forever. There are many factors that govern their decision to fold their tents and walk away. I think it is impossible to predict exactly at what or when that point is. At least it is beyond my ability to do so.Hi Ron,Freddy , 01/30/2019 at 8:09 am
I don't have any better idea how much shale oil is out there, or whether it can be produced profitably, than you do. But I will add this much to the discussion. Even if it is out there , and can be produced profitably, this is no guarantee that shale oil can prevent peak oil happening.
New shale production, which is subject to extraordinarily fast decline in and of it self, would have to be brought online fast enough to offset both its own decline PLUS the decline of the worlds giant conventional legacy oil fields.
Even if it's profitable to do so, and in large enough quantities, at some particular price, this does not necessarily mean that it will be possible to muster enough capital, equipment, skilled labor, and political will to make it happen FAST ENOUGH to offset conventional legacy oil declining production.
It's been a while since I paid much attention to the actual numbers, but I know you are well acquainted with them.
So what's your estimate, these days, of the conventional legacy oil decline rate? Have you raised it or lowered it recently?As I have read from news lately a more strict requirements from investors, banks, hedge funds makes it reasonable that investment in shale oil compeared to 2018.budget will be reduced by 19%.
One significant player will reduce their number if riggs from 24 to 18 as they expect oil price WTI in 2019 to be in mid 50 usd range.
To me it seems the confident among investors to US shale have changed significant espesialy 4th quartile of 2018. Now they only want to support projects that give cash return , seems they are tiered of promises as there have been to much of and shale oil depth have never been higher.
Since oil demand is linked to groth in world economy that is also same for interest of liability. EIA , and some other analyst like Rystad sees US shale production in 2019 will continue with strong increase and predict we only have seen the beginning. After working within oil and gaz projects in many years I know the oil majours dont want to loose money ,when a project seems not profittable they stop until oil price incresse or they get cost down.
I doubt there will be lots of investments in US shale with oil price in range 50-60 USD, because there is significant documentation only a very limited part ( decreasing) within core area is profitable as of now. Beside this a oil price in range 50-60.WTI or 55- 65 usd each barrel Brent is not enough to pay the cost of exploration drilling offshore, build new infra structure.
Feb 04, 2019 | peakoilbarrel.com
Karl Johnsonx 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.htmlAccording 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 pm
US production will be close to flat 2019, and if ports are not improved much until late 2020, then 2020 will not be great. After that, I don't see it catching up.As stated many times on 'theoildrum', State of the art EOR projects deplete oilfields, who without EOR would go in terminal decline much earlier, very rapidly. So a world oilproduction cliff cannot be ruled out, especially if money reserves from oil companies dry up.Dennis Coyne x Ignored says: 02/01/2019 at 10:32 amHan Neumann,Han Neumann x Ignored says: 02/03/2019 at 1:33 pm
Oil prices are likely to rise if there is a shortage of oil, this will mean oil companies will have plenty of financial resources as long as demand is sufficient to consume the oil produced. Not suggesting there will not be a decline, just unlikely there will be a cliff unless oil prices drop, so far there is no evidence of a cliff and given World stock level trend, prices are unlikely to drop further and are more likely to increase in the future.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.
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.
... ... ....
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."
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.
Jan 13, 2019 | peakoilbarrel.com
Energy News x Ignored says: 01/12/2019 at 2:24 pm2019-01-11 (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.
Jan 13, 2019 | peakoilbarrel.com
Energy Newsx 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
India Light Distillates Consumption (shown in chart)
Average full year 2018 up +9.74% higher than full year 2017
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.
Jan 08, 2019 | www.zerohedge.com
by Nick Cunningham
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 linkDavidduke2000 , 2 hours ago link
Baker huges reports a current US rig count decrease of 1% in the past two weeks. Several companies I support in the Permian have stacked rigs and layed off workers. $50 bbl is the magic number, the longer below that number the worse it will get.Catullus , 3 hours ago link
trump 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 link
Or it shows how much better the industry has gotten in response to production and prices. It's like a capital intensive industry that doesn't waste capital drilling for something that won't make them money. That's preservation of capital.
It doesn't take years or months to respond. It takes weeks.philipat , 58 minutes ago link
Yes sure, the easiest datasets to follow in one place are at SRSrocco. Steve StAngelo, kudos to him, has been onto this for years and has analyzed a lot of data from different sources.
There are lots of other sources if you duck it (Google is, of course, much more of the official narrative) but Steve has done a pretty good job of pulling a lot of information together over many years and for free. Even the paid access business facilities don't have much information (Surprise?).
The shale industry has been a kind of Ponzi scheme with OPM, entirely dependent on constant new loans to keep production levels up with new wells, and has never made a profit. I have often wondered, actually, to what extent the ESF (That is, USG) has supported the industry as a means of attempting to put more pressure on RRRRUUUUUSSSSSIIIAAAAA!!!!!!! and its energy income. Ultimately, unsuccessfully so, so perhaps this support might not last too much longer?
Without subsidies from "someone", it's difficult to understand how an unprofitable industry could have survived for so long. The Banks are not stupid. Wait, let me re-consider that last remark!! But not in the way I meant
Jan 06, 2019 | peakoilbarrel.com
GuyM x Ignored says: 01/04/2019 at 9:49 amhttps://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 am
More 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.
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.
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):
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 PMWatcher: 01/02/2019 AT 3:32 PM
Don't have the paywall, but you've given the gist. Investors were not happy with returns. Now, they are being fact checked, and that can look real messy. Borrowing is set to become restricted for many reasons. I really see some headwinds for future production increases.
Based on first year production numbers supplied by Shallow Sand, production can't increase without borrowing, except in some isolated areas.
To get even close to covering declines from last years wells, they have to, at least, recover most of that capex cost in the first year of production. That is far from reality, right now. To increase, or later to even keep up, with production, they will have to borrow money. They can possibly make a profit in three years, but that is meaningless to providing for growth. Think it going to start looking nastier.
And to add to Ron's answer, God would have to add, and make each well profitable the first year.
The miracle of US shale is about to have Toto pull back the curtain and reveal the real wizard.
Shale was, is, and will be just a supplemental source of oil supply. An investor could, if it was managed right, put x amount into the business, and in several years get a marginal return. In two to three years, a second well could be drilled to increase that income. That would be shale production growth. Not the imaginary growth numbers that are being thrown out.
The putrid 10Qs and 10ks for 2019 will add to the fire.GuyM: 01/02/2019 AT 4:27 PM
You guys insist on continuing to think money isn't created from thin air by the Fed and actually means something in the context of a substance that feeds you food. If you have to have it, and you do have to have it, things will be done for you to get it. Borrowed money that was created from thin air . . . who cares if you can't pay it back? You have to eat.
Consumption of oil is up. OPEC and Russia have reduced output. The price falls, because there is no meaning to anything created from thin air when applied to something that depends on physics.
You won't know anything until you find yourself sitting in a line waiting for gasoline. You won't see it coming. You won't predict it. It will just happen someday.
Soon.GuyM: 01/02/2019 AT 7:38 PM
Some truth to that Watcher. Simplistic thinking in investors. If we aren't making much money, the US won't be making much money, so the price of oil must go lower. Not just simplistic, flat out stupid.
And the number of people who think oil supply is limited is fairly scarce in relation to the population as a whole. Probably less than the number of people who think chocolate milk comes from brown cows.
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.
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 Production
Going into this year, the fracking industry needed to prove it was a good investment (and not just for its CEOs, who are garnering massive paychecks ).
In January, The Wall Street Journal touted the prospect of frackers finally making "real money for the first time" this year. "Shale drillers are heeding growing calls from investors who have chastened the companies for pumping ever more oil and gas even as they incur losses doing so," oil and energy reporter Bradley Olson wrote.
Olson's story quoted an energy asset manager making the (always) ill-fated prediction about the oil and gas industry that this time will be different.
Is this time going to be different? I think yes, a little bit," said energy asset manager Will Riley. "Companies will look to increase growth a little, but at a more moderate pace."
Despite this early optimism, Bloomberg noted in February that even the Permian Basin -- "America's hottest oilfield" -- faced "hidden pitfalls" that could "hamstring" the industry.
They were right. Those pitfalls turned out to be the ugly reality of the fracking industry's finances.
And this time was not different.
On the edge of the Permian in New Mexico, The Albuquerque Journal reported the industry is "on pace this year to leap past last year's record oil production," according to Ryan Flynn, executive director of the New Mexico Oil and Gas Association. And yet that oil has at times been discounted as much as $20 a barrel compared to world oil prices because New Mexico doesn't have the infrastructure to move all of it.
Who would be foolish enough to produce more oil than the existing infrastructure could handle in a year when the industry promised restraint and a focus on profits? New Mexico, for one. And North Dakota. And Texas.
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."
Carly Woodstock @stopthefrackSee Carly Woodstock's other Tweets Twitter Ads information and privacy
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 Institute
A 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.org
The numbers don't lie. Despite the highest oil prices in years and record amounts of oil production, the fracking industry continued to spend more than it made in 2018. And somehow, smaller industry losses can still be interpreted as being "more profitable than ever."The Fracking Industry's Fuzzy Math
One practice the fracking industry uses to obfuscate its long money-losing streak is to change the goal posts for what it means to be profitable. The Wall Street Journal recently highlighted this practice, writing: "Claims of low 'break-even' prices for shale drilling hardly square with frackers' bottom lines."
The industry likes to talk about low "break-even" numbers and how individual wells are profitable -- but somehow the companies themselves keep losing money. This can lead to statements like this one from Chris Duncan, an energy analyst at Brandes Investment Partners:
"You always scratch your head as to how they can have these well economics that can have double-digit returns on investment, but it never flows through to the total company return."
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 ModelRyan Popple @rcpoppleSee Ryan Popple's other Tweets Twitter Ads information and privacy
The 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 Institute
America'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.org
Why does the fracking industry continue to receive more investments from Wall Street despite breaking its "promises" this year?
Because that is how Wall Street makes money . Whether fracking companies are profitable or not doesn't really matter to Wall Street executives who are getting rich making the loans that the fracking industry struggles to repay.
An excellent example of this is the risk that rising interest rates pose to the fracking industry. Even shale companies that have made profits occasionally have done so while also amassing large debts . As interest rates rise, those companies will have to borrow at higher rates, which increases operating costs and decreases the likelihood that shale companies losing cash will ever pay back that debt.
Continental Resources, one of the largest fracking companies, is often touted as an excellent investment. Investor's Business Daily recently noted t hat "[w]ithin the Oil& Gas-U.S.Exploration & Production industry, Continental is the fourth-ranked stock with a strong 98 out of a highest-possible 99 [Investor's Business Daily] Composite Rating."
And yet when Simply Wall St. analyzed the company's ability to pay back its over $6 billion in debt, the stockmarket news site concluded that Continental isn't well positioned to repay that debt. However, it noted "[t]he sheer size of Continental Resources means it is unlikely to default or announce bankruptcy anytime soon." For frackers, being at the top of the industry apparently means being too big to fail.
As interest rates rise, common sense might suggest that Wall Street would rein in its lending to shale companies. But when has common sense applied to Wall Street?
Even the Houston Chronicle, a major paper near the center of the fracking boom, recently asked, "How long can the fracking spending spree last?"
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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=social6 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.com
The Chronicle notes the epic money-losing streak for the industry and how fracking bankruptcies have already ended up "stiffing lenders and investors on more than $70 billion in outstanding loans."
So, is the party over?
Not according to Katherine Spector, a research scholar at Columbia University's Center on Global Energy Policy. She explains how Wall Street will reconcile investing in these fracking firms during a period of higher interest rates: "Banks are going to make more money [through higher interest rates], so they're going to want to get more money out the door."
Follow the DeSmog investigative series: Finances of Fracking: Shale Industry Drills More Debt Than Profit
Harry , December 20, 2018 at 6:12 am
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
We're on a fractured rock aquifer in the foothills here that's separate from the one on the valley floor, and because it gets scant use in Ag, and not many people live here (we're 2.5x as big as Paradise,Ca. in size, with 1/10th of the population and at a similar altitude) nobody's hard rock wells had any issues with going dry during the lengthy drought and having to drill hundreds if not a thousand feet deeper in search of H20, as was occurring to the farmers et al on the fruited plain.
I sure don't like the idea of a fractured rock aquifer and fracking
One thing going against us, is land is cheap here, it's nature acres, nice to look at. but no development potential, as the trees are all in the way, and what sorry sap is going to cut down oaks a couple hundred old and level the hills to put in tiny boxes?
That villain doesn't exist, luckily.
But if you were to dangle large amounts of money at the owners of such low value acres, in oil leases?
And the idea it was all a circle jerk by Wall*Street & Big Oil, to get the money!
Makes it even harder to swallow
RBHoughton , 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?
Why the U.S. has Launched a New Financial World War -- And How the the Rest of the World Will Fight Back
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.
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 ;)
Dec 27, 2018 | peakoilbarrel.com
shallow sand x Ignored says: 12/26/2018 at 4:43 pmSo 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 pm
2015 Q3 36 months of production: 162,635 BO most recent monthly rate 58.6 BOPD
2016 Q3 24 months of production: 169,078 BO most recent monthly rate 103.5 BOPD
2017 Q3 12 months of production: 136,850 BO most recent monthly rate 213.1 BOPD
For 2015 162,635 x .80 x $45 = $5,854,860
7% severance $409,840
$5 per BO LOE $650,540
$2 per BO G & A $260,216
Net = $4,534,264
I lowered the costs some to make the economics more favorable from the standpoint of those who love the sub $2 gasoline. Might be ok to look at 10K and 10Q if anyone would like to plug in different cost estimates.
The 2016 wells described above are at $4,713,894 per well after 24 months.
The 2017 wells described above are at $3,815,378 per well after 12 months.
Of course, I was just trying to make a point that wells drilled in 2015 that had seen 3 years of weak (and one year of average) oil prices were going to be total losers that would not payout within any reasonable time horizon, if at all.
To continue, there is no mention in these numbers of how much land costs. I seem to recall many Permian players paying $15-60K per acre. So a two mile DSU would cost $19.2 million to $76.8 million. I just ignored land costs completely. Further, each of these companies has interest expense. One can go to the 10K's and 10Q's to see how much that is costing each per BOE. I just ignored interest expense too.
These wells are a lousy investment at $50 WTI. Only gets worse as the oil price sinks.
I think this all started because maybe GuyM was actually giving some credence to EOG guidance. I don't blame GuyM, or anyone else, for believing what the companies say.
I do argue until we see some well payout data (hard data, not power point variety) from these companies, we should assume the wells generally do not payout within 36 months, or even 60 months.
I do agree, wells have residual value after 36 and 60 months. I also agree that much higher oil prices make this business a money maker. Finally, I agree the wells have improved every year, although it is looking like 2016 might have been the high water mark, with later wells not moving the needle much higher.
Time for me to exit for awhile. I was just trying to remind people of the numbers. I think most of the investing public has figured it out, based on where these companies are trading since oil dumped again.Good analysis, and thanks, again. No amount of increased productivity could make them profitable at $45, especially not $37, or $16. The clock is ticking. Yeah, EOG has gone from over $120 to $87.
Dec 22, 2018 | peakoilbarrel.com
GuyM x Ignored says: 12/20/2018 at 6:16 pmLooks 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 pm
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.
Dec 22, 2018 | peakoilbarrel.com
shallow sand x Ignored says: 12/20/2018 at 7:54 pmCoffee. 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 pm
The only investment class in oil and gas that may be worse over the past ten years would be the service sector, particularly the drillers.
Interesting that, despite all the activity, the US onshore drillers are becoming penny stocks. I have pointed out Nabors. The rest are all tanking bad it appears.
You made a big deal out of a very long lateral operated by Eclipse Resources. Eclipse equity closed at 76 cents a share.
I am not so sure that ultra cheap oil and gas is such a great thing for the US, given we are now the world's largest producer of both.Shallowshallow sand x Ignored says: 12/21/2018 at 12:31 am
I never have, nor will I ever in the future, take any financial stake in these or any other companies.
As I have stated numerous times over the years, my primary interest is in operations who is doing what, how it is being done, who is doing it better – or claims to be.
My initial interest in this site way back when was to learn why some people seemed to think this so called Shale Revolution was No Big Deal a retirement party, in the words of Berman.
It was quickly apparent to me that a great deal of unawareness vis a vis industry developments permeated this site's participants.
This, alongside several predisposing factors to NOT want the shale production to explode upwards provided fertile grounds for the soon 12 to 16 million barrels per day US oil production, along with 100+ Bcfd gas production to be a spectaculsrly unforseen reality.
What I prefer or not prefer is secondary to what I believe to be occurring, shallow.
If anyone cares to spend 3 minutes reading the April, 2017 USGS press release accompanying the Haynesville/Bossier assessment, they will read the following from Walter Guidroz, Program Coordinator of the USGS Energy Resources Program
"As the USGS revisits many of the oil and gas basins of the US, we continually find that technological revolutions of the past few years have truly been a game changer in the amount of resources that are now technically recoverable".
Addendum Eclipse is being shut down/folded into another entity.
The lead engineer behind their ultra long laterals is now working with the new outfit from which this technology will continue to spread.No offense meant coffee. I know some who post here like to tangle with you. I am not interested in that, just straightforward discussion.
Shale has surprised the heck out of me, and has made me several times strongly consider liquidating my entire investment in oil and gas, absent maybe keeping just a couple of KSA like cheap (to quote PXD CEO) LOE wells to fool around with. Had I known in 2012-13 that this was coming, would have sold all but those few "piddle around with wells." It has been absolutely no fun when these price crashes occur, and is especially no fun knowing that this shale miracle is less profitable than an operation producing less than one bopd per well from very, very old and tired wells.
You have to admit that the way the shale is being developed is destroying the oil and gas industries that are developing it.
Particularly hard hit are the service companies, many which are already bankrupt.
Even XOM, which I have owned for many, many years (prior to the merger, I owned both Exxon and Mobil) has hit the skids, having fallen through the $70 per share barrier.
Range Resources is at $10.26, a level not seen since 2004. It traded as high as $90 before the 2014 crash.
EQT was over $100. Today $18.55
Whiting was nearly $400 (accounting for a reverse split) and now is $21.98
CHK closed at $1.84. All time high was $64.
Nabors Industries, the largest onshore US driller closed at $2.09. Traded at split adjusted $10 in 1978.
Halcon Resources Corp. was over $3,000 split adjusted at one time, went Ch 11 BK, now at $1.65, looking not so good re: BK again.
We shall soon see who can access what in the way of capital to keep going assuming oil prices stay below $50 WTI for a considerable time.
I guess I am always concerned about whether businesses make money. Seems to me that would be of some importance to you, but it isn't, and I suppose there is no harm in that.
I have yet to work anywhere where making money was not the primary motivation.
If the money wasn't important, the shale executives would not make so much of it, I suppose.
I have always had a hard time understanding why they kept drilling wells in Appalachia when the gas was selling for 50 cents per mcf. Not important to you, but maybe to others.
Anyway, if we didn't have different views, places like this wouldn't be very interesting.
Dec 14, 2018 | peakoilbarrel.com
Eulenspiegel, 12/12/2018 at 12:44 pmIn other sources US growth is more 1.9 mb/year, source is Rystad:GuyM, 12/12/2018 at 2:04 pm
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.
Dec 14, 2018 | peakoilbarrel.com
ProPoly, 12/13/2018 at 12:35 pmYeah, 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.
Dec 08, 2018 | peakoilbarrel.com
Survivalist, 12/06/2018 at 6:43 pmMy apology if this was posted on the last thread; an Interesting article from Jean LaherrereGoneFishing, 12/06/2018 at 7:07 pm
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 pm
Jean Laherrere knows a lot, but on LTO I think he may be wrong.
From the piece linked above:
The best approach for forecasting future production is the extrapolation of past production (called Hubbert linearization). For Eagle Ford the trend can be extrapolated toward an ultimate quantity of 3 Gb.
The USGS estimates about a 12.5 Gb mean for the TRR of the Eagle Ford, when economics is considered the URR might be reduced to 10Gb under a reasonable oil price scenario (AEO 2018 reference oil price scenario).
Recent USGS estimates for the Permian Delaware Basin have lead to a revision of my US tight oil estimate to a mean of 74 Gb with peak probably in 2025 to 2030. Decline will be relatively steep from 2030 to 2040, if the USGS estimates for the US tight oil resource prove correct.This is a terrific article. It takes all the confusions around oil and articulates them beautifully. His review really makes me want to buy the book.yvest, 12/07/2018 at 7:03 am
This is a delight to me because while I've always liked Laherrere's charts, I find his English writing atrocious (not all his fault as a native speaker of French). This could alienate lay readers, which is too bad because his message really needs to get out there.
The uncertainties he notes are shocking. That we have spent the last ten years pissing away our remaining "pennies" on a driving spree, instead of using it to build a renewable future, really makes me think that the backside of the peak is going to be awful.
Laherrere's knowledge is magisterial. Good on the editor who worked with him on this.Indeed the amount of work that Jean is producing is truly quite amazing. By the way what about Kjell Aleklett ? According to his blog he didn't publish anything since 2017, the case ?Jeff, 12/07/2018 at 7:07 am
The "issue" with Jean is that he also is a climato skeptic (regarding CO2 effects) and this has been detrimental to his ressource studies.
But one exercice in comparing the urgencies (taking the IPCC models just as they are), and feeding them with the resource aspects of Laherrere, clearly shows that peak oil or even peak fossile is the most urgent matter (knowing that anyway the mitigation measures, dimishing fossile fuels burning, are usually the same, except stuff like CSS, that will most probably never happen anyway).
Some elements (and Laherrere charts) in below post about this, sorry in French, but should go ok in gg translate :
Also 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 aspectsGuym,GuyM, 12/07/2018 at 11:20 am
Laherrere also suggests a 3 Gb URR for Eagle Ford where the USGS TRR mean estimate is about 12.5 Gb and when economic assumptions are applied the ERR is probably about 10 Gb.
You are much more familiar with the Eagle Ford, at $80/b (2017$) does a 3 Gb URR estimate seem correct?Seems low.Dennis Coyne, 12/07/2018 at 11:50 amGuym,GuyM, 12/07/2018 at 12:52 pm
Thanks. Does 10 Gb seem reasonable or is that too high? Average of USGS mean and Laherrere's estimate would be about 6.5 Gb, again you know the area so your estimates would probably be better than most.It's pretty difficult to measure with strictly an $80 price. Some depends on gas price. There are three windows in the EF. Oil, gas/condensate, and mostly gas. Gas has barely been touched, and is the biggest window. Geologically older. It still will produce some oil and condensate. If any, it will be mostly condensate. But it is still production as yet mostly untouched. Gas/condensate has been drilled, and is responsible for the higher api coming out of the EF, but in the past few years, less has been drilled due to the api. Oil window is being drilled, but there is still plenty of tier two and three areas to go. Not so much tier one. How do you measure that, and at what oil and gas price. I would say 12 is possible, but it includes a lot of condensate and gas.Dennis Coyne, 12/07/2018 at 1:01 pm
You could look at the USGS assessment of the Delaware in the same light. It may be there, but is it cost productive? You may only get gas and/or condensate, depending on geological age of the formation. Or, you may have to keep chasing after anything, as it moves quickly as wells are drilled.Thanks for the correction. Yes Gas prices would also be needed. The 10 Gb was C+C and yes there is probably lots of condensate. I guess I would make it $4/ MCF for NG, you would probably need condensate and NGL prices to do a full analysis, way too many moving parts for me.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 pm
And there is a fairly wide variety of prices depending on what comes out. I'm still trying to figure out my pay Stubbs.LARGEST CONTINUOUS OIL AND GAS RESOURCE POTENTIAL EVERMichael B, 12/06/2018 at 9:35 pm
Today, the U.S. Department of the Interior announced the Wolfcamp Shale and overlying Bone Spring Formation in the Delaware Basin portion of Texas and New Mexico's Permian Basin province contain an estimated mean of 46.3 billion barrels of oil, 281 trillion cubic feet of natural gas, and 20 billion barrels of natural gas liquids, according to an assessment by the U.S. Geological Survey (USGS). This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically recoverable resources.
https://www.sciencedaily.com/releases/2018/12/181206135643.htmI'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 am
Somebody 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 am
Your 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 pm
You are clearly smarter than me. I do tend to listen when geologists and geophysicists try to educate me.
Here is a preliminary estimate for US LTO assuming USGS mean estimates are correct, the Permian is up to date, but the older Bakken, EF, Niobrara, and US other LTO scenarios need to be revised to reflect the AEO reference oil price scenario. Peak about 9 Mb/d in 2025, also shown is an older estimate from June 2018 (before the recent Delaware Basin Wolfcamp and Bonespring assessment from the USGS.)
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 am
I know less about Marcellus, but Bakken/Three Forks was recently assessed in 2013, the new assessment may be an increase, but I won't speculate in advance what it will be.
The 46 Gb mean undiscovered TRR for the Wolfcamp (Delaware Basin) and Bonespring is a surprise to me, based on this the Permian tight oil TRR would be about 74 Gb, before this assessment I had guessed 8 Gb for Delaware Wolfcamp based on output compared to Midland Wolfcamp (it was about 30% of Midland so I took the 20 Gb Midland Wolfcamp times 0.3 and rounded to 8 Gb). My previous mean estimate for Permian tight oil TRR was 38 Gb, so I was too low by more than a factor of 2. My F5 (5% probability TRR might be higher) estimate was 54 Gb before and the F95 estimate was 20 Gb, these are revised to F95=43 Gb and F5=113 Gb.
For the entire US I had a previous TRR estimate of 70 Gb for all of the US, this is revised to 107 Gb for the mean US tight oil TRR.
An interesting development that might push the US peak in tight oil a little later and/or a little higher. My F5 model had the Permian peak at about 7.5 Mb/d in 2027, a new model might result in 2029 at 9.5 Mb/d, for the US as a whole, other tight oil plays might be declining by 2029, so the overall US peak might be 2027 or 2028, based on current information.https://pubs.usgs.gov/fs/2018/3073/fs20183073.pdfWatcher, 12/07/2018 at 3:19 am
The formal report. The references are . . . a bit odd. There is a sense the whole thing is dependent on technology results assessment from IHS.
Meaning, I don't see anything here that suggests USGS sent teams out to look at rock for this whole area. They seem to have taken info from other IHS papers -- and the recent ones from USGS were for what looks like much more limited geographic areas. Looks like IHS encouraged extrapolation.Btw someone at Bloomberg has declared this is a X2 on previous estimates. That would suggest 46 billion barrels of oil we're not just added to the US resource database. It would be more like 23.ProPoly, 12/07/2018 at 9:49 am
The Bloomberg guy didn't seem all that sharp, and so let's not take that as gospel.
Probably worth noting that it would not take much variance to move this resource into an API 45+ or even 50+ configuration, and given the NAT gas and NGL estimates, that would seem a pretty credible scenario. In which case it's not oil."Extrapolation" fits with it being undiscovered TRR.Dennis Coyne, 12/07/2018 at 10:17 am
This 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 am
Some 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 am
Previously I has guessed (incorrectly) that Permian mean TRR would be 38 Gb, this new assessment would lead to a revision to about 74 Gb for mean TRR of the Permian Basin tight oil resource.
In the scenario below I have a 253,000 well scenario (about 6 times more than my ND Bakken/Three Forks mean scenario with 42,000 wells completed.) I assume new well EUR starts to decrease in Jan 2023(about 3 years after my estimate of the future ND Bakken EUR decrease start as Permian ramp up started about 3 years after Bakken). This assumption is easily modified.
Peak is about 2028 with peak output at about 7000 kb/d (currently Permian tight oil output is about 2750 kb/d based on EIA tight oil production estimates by play).
The scenario above does not consider economics. When we consider the discounted net revenue over the life of the well and assume this must equal the real well cost in order for the well to be completed using the assumptions below, then we find an economically recoverable resource (ERR) scenario.GuyM, 12/07/2018 at 10:25 am
Economic assumptions (all costs in constant 2017$) are:
real oil prices in 2017$ follow the EIA AEO 2018 Reference Brent Oil Price scenario
royalties and taxes are 32% of wellhead revenue
transport cost is $4/b
OPEX is $2.3/b plus $15000 per month per well
real annual discount rate is 7% (nominal rate is 10% at 3% annual inflation rate)
real well cost=9.5 million 2017US$
Peak output is unchanged but wells completed are reduced to 173,000 and ERR=60 Gb.
The indications from drilling companies, so far, operating in the Delaware do not seem to jive with the assessment of grandiosity. So, I am more than skeptical. The government can create all the reserves they want, but if the oil companies can't get it out of the ground?? My understanding is that there is a core area in West Texas and NM. EOG is there. Extends a few Counties in West Texas and NM starting around Loving County. Even there, it is high api. Outside of that, it is highly sporadic. If you extrapolate what they are doing in tiny Loving County to the rest of the Delaware, you can come up with these numbers. But, you can't. As I read, there are over 800 Ducs outside of this area. You leave them as Ducs, because you pretty much know what the completion will look like after drilling. Basically, the report is hogwash. It's pretty easy to tell on the Texas side, as you can pull up completions by county.Dennis Coyne, 12/07/2018 at 10:53 amGuym,JG Tulsa, 12/07/2018 at 11:10 am
It may require higher oil prices and the associated gas is a problem, not enough infrastructure to move it.
Also the USGS simply does a resource assessment, these are not reserves, no economic assessment was done, the USGS leaves that to others.
I have often been skeptical of USGS Assessments (such as Bakken Assessment in 2013), looking at proved reserves and cumulative production to data in the ND Bakken/Three Forks, the 11 Gb mean TRR estimate from 2013 looks pretty good.
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 am
Everything is more complex than that. Right now operators are drilling the best, most economic parts of the Delaware basin, at the going rate it will not be too many years before they have to shift over to other benches of the Wolfcamp or Bone Spring, which will be less productive. for deeper Wolfcamp benches you get more condensate, less oil, much more gas, you might go from a 10,000′ lateral making 1-2 MMBO in the Wolfcamp A, down to one making 300-500 MBO.
Still a decent well when you add in the gas, but if you take that across a large area that will lead to a substantial decline in new well performance. I would not doubt oil production peaks in the mid-2020s as people drill up the best rock, and have to keep shifting to less productive horizons.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 pm
Can you give us your estimate of the TRR or ERR of the Delaware Wolfcamp and Bonespring. There is a wide range in the USGS TRR estimate from 27 to 71 Gb with a mean of 46 Gb and a median of 45 Gb. Would you say that 27 Gb is too high? It seems clear you think that 46 Gb is far too optimistic. Note that the mean ERR would probably be around 38 Gb if the mean TRR estimate was correct and prices follow the AEO 2018 reference price scenario. For the F95 USGS TRR estimate the ERR would be around 21 Gb.
Maybe you could also comment on other USGS assessments for Eagle Ford, Wolfcamp Midland basin and Spraberry. Perhaps you could give us the "correct assessment".
I agree the EIA assessments are not good, economists do not know much about geophysics. The people at the USGS are scientists, though they have limited information and thus use statistical analysis to fill the data gaps.Come on, Dennis. He may be a geologist, but my bet he is mortal, like you and I. I really believe your first graph with 8 million as the high is the best I have seen. The tail of that is probably not ever to be properly guessed, until it happens.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 pm
The extra production "per well" seems to be from the well being longer in length and thus consuming more water and proppant. Is this true, or is there some magical improvement in proppant type or fracking pressure or whatever?It's mostly the length of the lateral, although some is due to increased fracking stages within the lateral (more holes in the pipe). Better drilling is another, although extra lateral makes up most of it. The laterals, in general, are about twice as long.Michael B, 12/07/2018 at 8:41 amUS becomes a net oil exporter.Watcher, 12/07/2018 at 11:33 am
Hanh? And this paragraph strikes this lay reader as utterly incoherent:
The U.S. sold overseas last week a net 211,000 barrels a day of crude and refined products such as gasoline and diesel, compared to net imports of about 3 million barrels a day on average so far in 2018, and an annual peak of more than 12 million barrels a day in 2005, according to the U.S. Energy Information Administration.
From EIA: "In 2017, the United States consumed about 19.96 million barrels per day." Let's call it 20.
Also from EIA: US weekly field production ending 11/30: 11.7 million barrels.
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 pm
The US refines a lot of imported oil -- for export. There is refinery gain in this. This means a barrel comes in. It is refined to various constituent parts like gasoline, diesel, kerosene, etc. The VOLUME of these parts are liquids of less density and this means their volume is greater. So a barrel of crude will yield a sum total of more than 1 barrel of liquids of lower density. Since these products are exported, the barrel count is in favor of exports vs the barrel count imported.
This is not a huge effect, but it's significant.
There's an EIA page for US sales volume consumed. If you add up all the products you get well over 15 million bpd. US production is rather less than that. Imports must exceed exports.Thanks for trying to explain it to me. Maybe it's just too complicated for me to understand.kolbeinh, 12/07/2018 at 1:41 pm
I still can't reconcile the headline, "US becomes a net oil exporter" with the EIA's numbers: The US consumes 20 million barrels a day. The US produces 12 million barrels a day. But, yes, they're net exporters. Whatever.
After 14 years, the niceties of peak oil still escape me.I am not sure I follow you entirely, but for heavier crude oils there is waste to get to diesel (a bit higher than 30 API). And for extra light oil there is a huge waste to get to diesel, as much has to be segregated to petroleum gas and gasoline components due to length of carbon chain.Watcher, 12/07/2018 at 2:50 pm
The case for diesel shortage in 2020 due to shipping legislation is still very much legit.I was talking about imported crude (that would not be LTO and probably diesel rich) being refined into a larger number of barrels of product vs the barrels of input crude. They export. It's a bias towards export.Eulenspiegel, 12/07/2018 at 8:55 am
I 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.
Dec 08, 2018 | peakoilbarrel.com
kolbeinh , says: 12/07/2018 at 9:45 amYes, it is all a big show!GuyM , says: 12/07/2018 at 5:18 pm
The peak oil theme is very much forgotten in all the turmoil, but is very real still.
How much more reserves to classify as probable (2p) is a movable target, it depends on the oil price.
And how rapid the extraction rates of reserves can extend to difficult to say; technology and not at least the 3D maps of reservoirs coupled with improved seismic data, more precise drilling and lower costs due to excess oil service capacity (at least for offshore) have countered the inevitable declining quality of oil reservoirs and size of new ones coming online for some time now.
I agree that 2019 will show big declines in OECD inventory primarily because core OPEC wants it. (increasing KSA premiums to the US +3,5 dollars in Jan and lowering it to Asia).
The next question is how high oil prices will go before there is some reaction from the nations that have spare storage/capacity. I am thinking there is some relief in increased pipeline capacity in Texas in 2H 2019 and also Johan Sverdrup in Norway (since I follow things close to home) in the same time period to save the oil market in winter 2020.
Or still more likely, a spike in oil prices in 2H 2019 and a recession soon thereafter.
Who knows..the only thing certain is that oil is being pressured towards the final "spare capacity" (whatever that is) and that a recession will come anyway as a result of the low oil price environment the last 4 years.
Offshore is hit hard, so are supply in places "too risky" for cheap financing the hidden secret of the oil market (why so few news stories covering this?)Saved from $40 oil, but I really doubt there will be much of a frenzy at $52 oil price. Hopefully, that will give them enough cash flow for stationary. They need to write Christmas letters to their shareholders telling them everything will be better next year.
Nov 24, 2018 | peakoilbarrel.com
Fred Magyar x Ignored says: 11/22/2018 at 11:34 amhttps://cleantechnica.com/2018/11/22/peak-oil-drastic-oil-shortages-imminent-says-iea/Ron Patterson x Ignored says: 11/22/2018 at 1:59 pm
Peak Oil & Drastic Oil Shortages Imminent, Says IEALOL!Fred Magyar x Ignored says: 11/22/2018 at 4:18 pm
Sorry 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 am
The link between GDP and energy consumption is very clearly shown in the graph.
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 am
I 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 pm
I hope you are correct, but I have done some calculations on what is needed.
According to reports around $1.7 trillion was invested in energy supply in 2017. $790 billion on oil, gas and coal supply. $320 billion was spent on solar and wind.
During 2017 oil consumption increased by 1 million barrels per day. Gas consumption increased by 3% and even coal consumption went up.
The world needs to spend about $2.5 trillion per year on wind, solar and batteries in order to meet increased energy demand and reduce fossil fuel burning by about 1% per year. This obviously depends on GDP growth being about average.
Since recent scientific observations have discovered that Greenland, the Arctic and Antarctica melting much faster than anyone thought. The shift needs to be a minimum of 2.5%. Thus a spending of around £4 trillion per year is needed.
I do not see any country spending a minimum of 12 times more on solar and wind in the next 3-5 years. It would take every country doing so.Agreed Hugo. The world is only making token moves towards installation of the necessary wind and solar.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 pm
39.5 million is only gasoline in the world. Add diesel and jet fuel and you get to about 75 million barrels a day for transportation or about 75% of oil produced.I was specifically talking about road transport.Hickory x Ignored says: 11/24/2018 at 12:33 am
Argue with these guys.
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.
Nov 16, 2018 | peakoilbarrel.com
likbez says: 11/16/2018 at 1:42 amShallow 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
In 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.
Nov 15, 2018 | peakoilbarrel.com
Mike Sutherland x Ignored says: 11/14/2018 at 10:19 pmThis 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 am
Yes will it go bankrupt first or continue to run on until peak and depletion. Meanwhile it drags down the oil price artificially making most other oil development less likely, and increasing volatility.The FED is reducing money supply by 50 billions per month at the moment. The first feeling it will be comanies needing to sell junk bonds.Stephen Hren x Ignored says: 11/14/2018 at 10:50 am
This is a big ploblem for the relentless "drill baby drill" programs of several LTO companies.
And a global economic crises, even if only a few years long, will crash oil prices AND credit supply. This will hurt LTO more than the oil price crash from 2015.Oil bonds appear to be starting to feel the burn at $55/barrel.Mike Sutherland x Ignored says: 11/14/2018 at 10:38 pm
https://seekingalpha.com/article/4222006-oil-plunges-energy-junk-bonds-turn-dangerousYes Ron, thank you for an excellent post.Watcher x Ignored says: 11/14/2018 at 11:40 pm
On the shale topic; it is marvelously stupefying to observe a heavily indebted shale industry supplying increasing volumes of oil, to an extent that the price/bbl never hits a level where any debt reduction can be realized. (to say nothing of profit)
Its' almost as if they have no intention of becoming solvent.Some time ago presented estimate of oil used to create and move food in the US. My recall is the number wasn't huge.
Recently came across new data. Will get around to laying it out.
25% of total US consumption. Tractors, insecticides, some fertilizer(transport of those to the field), transport of animal food to hogs, beef, etc, transport of human food to shelves, transport of people to the shelf and home. 15% pre transport of human food, 10% transport human food.
Pretty efficient agriculture in the US. No squeezing that 5 mbpd.
Nov 12, 2018 | peakoilbarrel.com
islandboy says: 11/01/2018 at 10:22 amI guess it's time to break out the champagne!dclonghorn says: 11/02/2018 at 8:29 pm
U.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 pm
Nevertheless, I think Coffee's comment was correct, it does appear that shale producers in the Bakken have expanded the area that produces exceptional wells. As one who underestimated shale's viability before, I don't want to repeat the same mistake.
As you note, it is difficult to predict when average well productivity in the Bakken (or anywhere) will occur. I had thought that current drilling levels would be inadequate to sustain 1.15 million bpd production levels, but somehow they are increasing production there. It does appear that for now, the shale operators are having some success.
How long that success will last depends not only on the operational decisions made, but macro factors such as debt, interest rates, and the economy will play out, and eventually Bakken production will decline. But for nowAnd in a brief follow upWatcher says: 11/01/2018 at 11:35 pm
I have not read Continental's conference call transcript yet (Seeking Alpha provides them), but it seems the suit from Continental now feels they will recover – from present completions – 15 to 20 per cent of the OOIP.
That is huge as the norm was 3 to 5 per cent a few years back.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 am
Watcher is correct, CLR's credit rating, its credit score, so to speak, is so bad it could not in the real world buy a pickup truck without its mama co-signing the note. If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to? Never mind, you can't answer that.
If you are not in the oil business and have never balanced an oil well's checkbook in your life, which Coffee hasn't, then you don't know that higher productivity comes with a higher cost in the shale biz. The bottom line then is that the bottom line does not change if it did the shale oil industry would be paying down some debt, right? Its not. Private debt is skyrocketing.
Are things getting better for the shale biz? Right. Case in point, the largest pure Permian Basin oil and associated gas producer, Concho, the genius behind a recent $8 billion dollar acquisition from RSP, LOST $199MM 3Q2018. Inventories are going back up, prices are down 18% the past month and what does the shale oil industry do?
It adds more rigs.
Productivity is not the same as profitability. In the real oil biz you learn that on about day six."If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to?"Mike says: 11/03/2018 at 7:59 am
I wonder about debt service, too.
When Dennis runs his scenarios he says that at a certain oil price, these companies will be quite able to pay down debt.
But will they? Or will they just pay themselves as much as they can as long as they can get away with it, and then declare bankruptcy and walk away.I'll take door two.Reno Hightower says: 11/04/2018 at 9:37 am
We had 5-6 years of the highest, sustained oil prices in history and the shale oil industry could NOT make a profit. People seem to think now things have changed for some reason, that the shale oil industry has now become more ethical, and temporarily higher productivity of wells, and some imaginary oil price off in the future (for most shale guys its now down in the mid to low $50's) will allow them to pay down debt. Its absurd logic, but keeps people occupied, I guess, speculating about it.
I urge folks to ignore the guessing, and the lying, (Hamm's 20% of OOIP in the Bakken is a big 'ol whopper) and look at the shale industry's financial performance over the past 10 years and decide for yourselves if it is sustainable or not.One thing to add. The shale companies did all this in the lowest interest rate environment we have had in a long time. They could not pay off their debt or even put a dent in it. What is going to happen when their interest costs increase 30-50% over the next 2-3 years?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 am
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:
To historical completion numbers here:
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 pm
If 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 pm
Paying the debt off will depend very much on future oil and natural gas prices.
Once growth slows the companies will be companies operating many low volume wells. Investors will want these companies to pay dividends because they will not be in a position to grow. The operating costs will be higher, even though CAPEX will drop.
You are very confident prices will be high in the future. I suspect they will be volatile in the future, as they have been for the past 20 years.
So, on a company by company basis, timing will be critical, IMO.Shallow sand,shallow sand says: 11/04/2018 at 11:03 pm
The prices can be thought of as 3 year average prices, yes there will be volatility, my "low price scenario" has Brent Oil Price in 2017 $ never rising above $80/b. I cannot hope to predict the exact oil price and of course oil prices will be volatile, but the average over time allows a pretty good estimate.
Also a company by company model is a little too much work. I just do the industry average, some companies will be better and some worse than average.
It certainly is the case that oil prices have been volatile and I agree this will continue, but the three year trend in prices (centered 3 year average) has been up $7/b for the past year, my expectation is that this trend will continue and the 3 year centered average price will reach $80/b (in 2017$) by 2021 or 2022. The trend of oil prices will be higher, if the peak arrives by 2025 as I expect prices (3 year centered average oil price in 2017$) are likely to reach $100/b by 2024 or 2025.Dennis.Dennis Coyne says: 11/05/2018 at 2:23 pm
I think company by company because I have an investment in a private company. I know how important timing is in the upstream industry to individual companies.
Likewise, I understand you aren't all that interested in individual companies. No problem there.
On the price, I understand why you use different scenarios. However, the average price over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14 and 2015–17.
I was recently in a major city and saw more Tesla's than I ever had, including my first Model 3 sighting.
Our little area now has two Model S, with the early adopter trading his 2012 for a 2018.Shallow sand,shallow sand says: 11/05/2018 at 6:33 pm
Pretty doubtful it will be $50/b over the next three years, in my opinion. If you believe that you should find another business More likely is a gradual increase in oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price (today's future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61 (Dec 2026). By Contrast the EIA's AEO 2018 reference oil price scenario for Brent crude has the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too low.)
As always clicking on the chart give a larger view.
Dennis.Dennis Coyne says: 11/06/2018 at 9:59 am
The price could be $50 from 2019-2021, and then $125 from 2022-2025. (Averages, of course).
So in that scenario I'd feel pretty bad if I sold out in say 2020.
Your models are ok, I have no problem with you doing them. We try to make a budget for every year.
However, the price is far too volatile to model anything very far into the future, just like we cannot budget past one year, and usually have to make adjustments to that.
Our price has dropped over $10 in less than one month. That makes a huge difference, yet that level of volatility is common and has been for many years.
What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the market prices of 2011-14, we would be bankrupt, absent having hedged everything for four years, which is very difficult to do.
On a flowing barrel basis, I have seen leases sell as low as $2,000 per barrel and as high as $180,000 per barrel in our basin from 1997-2018. That is what an oil price range of $8-140 per barrel will do.
Few companies with zero debt ever go BK. We would with WTI at $30 for about three years. Is that likely? No, but oil did drop below that level in 2016.Shallow Sand,shallow sand says: 11/08/2018 at 4:44 pm
The volatility is a big problem, there is no doubt of that. When imagining the "big picture". I use the estimates of the EIA's AEO as a starting point then add my personal perspective (that at some point oil output will peak.) Below is a chart with my guess from Dec 2014 for future Brent oil prices in constant 2014$, nominal Brent spot price is give for comparison.
Clearly my guess was not very good, the EIA guess from the AEO 2015 was also not great, but better than my guess. Future guesses will be equally bad.
What was your forecast in Dec 2014 for WTI?
Dennis.Dennis Coyne says: 11/08/2018 at 6:10 pm
In 2013 we assumed prices in a range of $60-120 WTI moving forward.
In June of 2014 when oil spiked up and we received $99.25 in the field, we suspected oil would fall and it began to. We again continued to assume $60 WTI would be a low.
We were dead wrong, of course.
Oil dropped again today. We will get $67 in the field for October sales paid in November. However, our price today is down to $56.50. That is about a $60,000 per month revenue hit to a small company which employs 8 full time employees, one part time employee office manager and utilized numerous contractors (rigs, electricians, etc.).
Corn here is $3.51 per bushel today. Less than a month ago it was $2.96 per bushel.
Yes, yes, a hedging program would mitigate the price volatility.
Until you actually try to hedge with money at risk, don't talk to me about that. It's about as easy as trading stocks. It is also very expensive due to the volatility. Or, if you do SWAPS or Collars, you need to put up a lot of margin money.Shallow sand,TechGuy says: 11/07/2018 at 2:25 pm
Hedging seems a risky business, not sure I would come out ahead by hedging. You are in a tough business, the volatility sucks. The silver lining is that prices will be increasing.Shallow Sand Wrote:
"Paying the debt off will depend very much on future oil and natural gas prices."
I don't think so. When energy prices rise, so do prices of everything else, included interest rates. The only way the shale drillers could play off there debt is if the left large number of completed wells untapped (ie leave it in the ground) while taking advantage of cheap debt & low labor\material costs. Then selling the oil when prices & costs have soared above investment costs.
The issue is that as soon as a well is completed, they start producing, at market prices. Thus when oil prices rise most of the oil is already produced & drilling new wells (using more debt) does not pay down the old debt.
Also consider the costs shale drillers will need for decommissioning older\depleted well. I believe the cleanup cost is between $50K & $100K per drill site. To date have any shale drillers spent money on clean up for depleted wells yet, or is it all deferred (ie never going to happen)?
FWIW: I don't believe any of the shale companies are in game for the long term. They are simply a modern Ponzi scam, taking investor money & providing an illusion of profitabity by selling a product below cost. They will continue to play the game until investor capital dries up.
I suspect that most shale drillers will go bust in the next 5 years when the bulk of their bonds come due & they won't have the ability to refinance it or pay it off. If I recall correctly Shale drillers will need to payoff or refinance about $270B in high-yield bonds between 2020 & 2022.
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.
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 Denial
According to a recently released article by 40-year oil industry veteran, Mike Shellman, "Deep The Denial," he provided some sobering statistics on the shale industry:
I recently put somebody very smart on the necessary research (SEC K's, press releases regarding private equity to private producers, etc.) to determine what total upstream shale oil debt actually is. We found it to be between $285-$300B (billion), both public and private . Kallanish Energy Consultants recently wrote that there is $240B of long term E&P debt in the US maturing by 2023 and I think we should assume that at least 90 plus percent of that is associated with shale oil. That is maturing debt, not total debt.
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B annually in interest on long term debt.
Using its own self-touted "breakeven" oil price, the shale oil industry must then produce over 1.5 Million BOPD just to pay interest on that debt each year. Those are barrels of oil that cannot be used to deleverage debt, grow reserves, not even replace reserves that are declining at rates of 28% to 15% per year that is just what it will take to service debt.
Using its own "breakeven" prices the US shale oil industry will ultimately have to produce 9G BO of oil, as much as it has already produced in 10 years just to pay its total long term debt back .
Using Mike's figures, I made the following chart below:
For the U.S. Shale Oil Industry just to pay back its debt, it must produce 9 billion barrels of oil. That is one heck of a lot of oil as the industry has produced about 10 billion barrels to date. Again, as Mike states, it would take 9 billion barrels of shale oil to pay back its $285-300 billion of debt (based on the shale industry's very own breakeven prices).
Furthermore, the shale industry may have to sell a quarter of its oil production (1.5 million barrels per day) just to service its debt by the end of 2019. According to the EIA, the U.S. Energy Information Agency, total shale oil (tight oil) production is now 6.2 million barrels per day (mbd):
The majority of shale oil production comes from three fields and regions, the Eagle Ford (Blue), the Bakken (Yellow) and the Permian (light, medium & dark brown). These three fields and regions produce 5.2 mbd of the total 6.2 mbd of shale production.
Unfortunately, the shale industry continues to struggle with mounting debt and negative free cash flow. The EIA recently published this chart showing the cash from operations versus capital expenditures for 48 public domestic oil producers:
You will notice that capital expenditures ( brown line ) are still higher than cash from operations ( blue line ). So, it doesn't seem to matter if the oil price is over $100 (2013-2014) or less than $70 (2017-2018), the shale oil industry continues to spend more money than it's making. The shale energy companies have resorted to selling assets, issuing stock and increasing debt to supplement their inadequate cash flow to fund operations.
A perfect example of this in practice is Pioneer Resources the number one shale oil producer in the mighty Permian. While most companies increased their debt to fund operations, Pioneer decided to take advantage of its high stock price by raising money via share dilution. Pioneer's outstanding shares ballooned from 115 million shares in 2010 to 170 million by 2017. From 2011 to 2016, Pioneer issued a staggering $5.4 billion in new stock :
So, as Pioneer issued over $5 billion in stock to produce unprofitable shale oil and gas, Continental Resources racked up more than $5 billion in debt during the same period. These are both examples of "Ponzi Finance." Thus, the shale energy industry has been quite creative in hoodwinking both the shareholder and capital investor.
Now, there is no coincidence that I have focused my research on Pioneer and Continental Resources. While Continental is the poster child of what's horribly wrong with the shale oil industry in the Bakken, Pioneer is a role model for the same sort of insanity and delusional thinking taking place in the Permian.Pioneer Spends A Lot More Money With Unsatisfactory Production Results
To be able to understand what is going on in the U.S. shale industry, you have to be clever enough to ignore the "Techno-jargon" in the press releases and read between the lines. As mentioned above, Pioneer stated that it was going to add a lot more of its "high-tech" Version 3.0+ completion wells in the second half of 2018 because they were outperforming the older versions.
Well, I hope this is true because Pioneer's first half 2018 production results in the Permian were quite disappointing compared to the previous period. If we compare the increase of Pioneer's shale oil production in the Permian versus its capital expenditures, something must be seriously wrong .
First, let's look at a breakdown of Pioneer's Permian energy production from their September 2018 Investor Presentation:
Pioneer's Permian oil and gas production is broken down between its horizontal shale and vertical convention production. I will only focus on its horizontal shale production as this is where the majority of their capital expenditures are taking place. The highlighted yellow line shows Pioneer's horizontal shale oil production in the Permian Basin.
You will notice that Pioneer's shale oil production increased significantly in Q3 & Q4 2017 versus Q1 & Q2 2018. Furthermore, Pioneer's shale gas production surged in Q2 2018 by nearly 50% (highlighted with a red box) compared to oil production only increasing 5%. That is a serious RED FLAG for natural gas production to jump that much in one quarter.
Secondly, by comparing the increase of Pioneer's quarterly shale oil production in the Permian with its capital expenditures, the results are less than satisfactory:
The RED LINE shows the amount of capital expenditures spent each quarter while the OLIVE colored BARS represent the increase in Permian shale oil production. To simplify the figures in this chart, I made the following graphic below:
Pioneer spent $1.36 billion in the second half of 2017 to increase its Permian shale oil production by 30,232 barrels per day (bopd) compared to $1.7 billion in the first half of 2018 which only resulted in an additional 10,832 bopd . Folks, it seems as if something seriously went wrong for Pioneer in the Permian as the expenditure of $340 million more CAPEX resulted in two-thirds less the production growth versus the previous period.
Third, while Pioneer (stock ticker PXD) proudly lists that they are one of the lowest cost shale producers in the industry, they still suffer from negative free cash flow:
As we can see, Pioneer lists their breakeven oil price at approximately $22, which is downright hilarious when they spent $132 million more on capital expenditures than the made in cash from operations:
The public and investors need to understand that "oil breakeven costs" do not include capital expenditures. And according to Pioneer's Q2 2018 Press Release, the company plans on spending $3.4 billion on capital expenditures in 2018. The majority of the capital expenditures are spent on drilling and completing horizontal shale wells.
For example, Pioneer brought on 130 new wells in the first half of 2018 and spent $1.7 billion on CAPEX (capital expenditures) versus 125 wells and $1.36 billion in 2H 2017. I have seen estimates that it cost approximately $9 million for Pioneer to drill a horizontal shale well in the Permian. Thus, the 130 wells cost nearly $1.2 billion.
However, the interesting thing to take note is that Pioneer brought on 125 wells in 2H 2017 to add 30,000+ barrels of new oil production compared to 130 wells in 1H 2018 that only added 10,000+ barrels. So, how can Pioneer add five more wells (130 vs. 125) in 1H 2018 to see its oil production increase a third of what it was in the previous period?
Regardless, the U.S. shale oil industry continues to spend more money than they make from operations. While energy companies may have enjoyed lower costs when the industry was gutted by super-low oil prices in 2015 and 2016, it seems as if inflation has made its way back into the shale patch. Rising energy prices translate to higher costs for the shale energy industry. Rinse and repeat.
Unfortunately, when the stock markets finally crack, so will energy and commodity prices. Falling oil prices will cause severe damage to the Shale Industry as it struggles to stay afloat by selling assets, issuing stock and increasing debt to continue producing unprofitable oil.
I believe the U.S. Shale Oil Industry will suffer catastrophic failure from the impact of deflationary oil prices along with peaking production. While U.S. Shale Oil production has increased exponentially over the past decade, it will likely come down even faster.
* * *
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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 traded oil and gas fracking companies shows the companies posting negative free cash flows through June," the report's authors write. The 33 small and medium-sized drillers posted a combined $3.9 billion in negative cash flow in the first half of 2018.
The glaring problem with the poor financial results is that 2018 was supposed to be the year that the shale industry finally turned a corner. Earlier this year, the International Energy Agency painted a rosy portrait of US shale, arguing in a report that "higher prices and operational improvements are putting the US shale sector on track to achieve positive free cash flow in 2018 for the first time ever."
The improved outlook came after years of mounting debt and negative cash flow. The IEA estimates that the US shale industry generated cumulative negative free cash flow of over $200 billion between 2010 and 2014. The oil market downturn that began in 2014 was supposed to have changed profligate spending, pushing out inefficient companies and leaving the sector as a whole much leaner and healthier.
"Current trends suggest that the shale industry as a whole may finally turn a profit in 2018, although downside risks remain," the IEA wrote in July. " Several companies expect positive free cash flow based on an assumed oil price well below the levels seen so far in 2018 and there are clear indications that bond markets and banks are taking a more positive attitude to the sector, following encouraging financial results for the first quarter."
But the warning signs have been clear for some time. The Wall Street Journal reported in August that the second quarter was a disappointment. The WSJ analyzed 50 companies, finding that they spent a combined $2 billion more than they generated in the second quarter.
Read more on Oilprice.com: What Killed The Oil Price Rally?
The new report from IEEFA and the Sightline Institute add more detail the industry's recent performance. Only seven out of the 33 companies analyzed in the report had positive cash flow in the first half of the year, and the whole group burned through a combined $5 billion in cash reserves over that time period.
Even more remarkable is the fact that the negative financials come amidst a production boom. The US continues to break production records week after week, and at over 11 million barrels per day, the US could soon become the world's largest oil producer. Analysts differ over the trajectory of shale, but they only argue over how fast output will grow.
Yet, even as drillers extract ever greater volumes of oil from the ground, they still are not turning a profit. "To outward appearances, the US oil and gas industry is in the midst of a decade-long boom," IEEFA and the Sightline Institute write in their report. However, "America's fracking boom has been a world-class bust."
The ongoing struggles raises questions about the long-term. If the industry is still not profitable – after a decade of drilling, after major efficiency improvements since 2014, and after a sharp rebound in oil prices – when will it ever be profitable? Is there something fundamentally problematic about the nature of shale drilling, which suffers from steep decline rates over relatively short periods of time and requires constant spending and drilling to maintain?
Read more on Oilprice.com: Oil's $133 Billion Black Market
Third quarter results will start trickling in over the next few days and weeks, which should provide more clues into the shale industry's health. There is even more pressure on drillers to post profits because the third quarter saw much higher oil prices.
"Until the industry as a whole improves, producing both sustained profits and consistently positive cash flows, careful investors would be wise to view fracking companies as speculative investments," the authors of the report concluded.
This article was originally published on Oilprice.com
Oct 24, 2018 | peakoilbarrel.com
Hickory x Ignored says: 10/22/2018 at 9:49 pmAny guess what the price of crude would be today if we had no fracking in N. America?ProPoly x Ignored says: 10/23/2018 at 6:36 am
Wild guess is all I've got, but I'm saying $142 (and much lower economic growth over the past 9 yrs- maybe even flat averaged for the whole period).
Any other speculations on this?USA LTO is ~7.5 million bpd. That exceeds global spare capacity over demand as-is today by at least four times. So if the world was still trying to consume what it is today, we would be several million short and would have been short by seven figures for several years.Dennis Coyne x Ignored says: 10/23/2018 at 10:26 am
I think we would have found out if there really are any huge but uneconomical fields out there by now as the panic from that set in a few years ago. A shortage on that scale means arbitrary prices pending demand cap/destruction.US tight oil output was about 6200 kb/d in August 2018 according to the EIA, not that the DPR includes oil from the region of tight oil plays that is conventional oil, also it is a model that is not very good so I ignore the DPR .Energy News x Ignored says: 10/22/2018 at 1:12 pm
WAG on oil price with zero LTO output is $120/b in 2017$, plus or minus $20/b.Canada (offshore), Hebron is expected to produce around 150,000 barrels a day, from about 40,000 barrels a day now.George Kaplan x Ignored says: 10/23/2018 at 1:28 am
2018-10-22 (The Globe and Mail) It's been one year since ExxonMobil's long-awaited Hebron platform off the southeast coast of Newfoundland started pumping crude from its first well. It took four years, $14 billion, 132,000 cubic metres of concrete and a few thousand workers to bring it online, and so far, it's churning out about 40,000 barrels a day, with the crude bound for markets in the U.S. Gulf states, Europe and much of eastern North America. Eventually, Hebron will drill 20 to 30 wells, and is expected to produce around 150,000 barrels a day.
With an expected reserve of 700 million barrels of recoverable crude, the Hebron project is expected to operate for 30 years. As Newfoundland's fourth offshore platform, it will play a key role in the province's plan to double overall production to more than 650,000 barrels a day by 2030.
https://www.theglobeandmail.com/business/article-why-hebron-has-a-leg-up-on-albertas-oil-sands/Hebron is already at 70 kbpd and has been for a few months. I thinks its expected annual average for oil only is 135 and it will take a year or so to get there as the coming wells will be less productive that the first ones. In the mean time the three other platforms are in decline (Terra Nova was originally due to be taken off line next year – not sure what the latest thinking is). They dropped about 35 kbpd last year but that may accelerate as Hibernia is coming off a secondary plateau.Energy News x Ignored says: 10/23/2018 at 6:18 amYes a more realistic impression of the situation than just reading the article
Oct 24, 2018 | peakoilbarrel.com
ProPoly x Ignored says: 10/19/2018 at 9:22 amOPEC is, for reasons many expected (involuntary declines in Venezuela and elsewhere), having difficulty delivering on their promised output hike.Guym x Ignored says: 10/19/2018 at 11:30 am
https://www.reuters.com/article/us-opec-oil-exclusive/exclusive-opec-allies-struggle-to-fully-deliver-pledged-oil-output-boost-internal-document-idUSKCN1MT1G0Yeah, that's going to get a lot worse. It's counting Iran production, and not what it can sell. A lot in floating storage, and being stored close to China and elsewhere. US is the only one with an increase, and that increase is on a hiatus until new pipelines come on, regardless of the EIA overstated production numbers. So, we would be short before any demand increase, or non-OPEC declines. But, never worry, as IEA says peak oil is just a figment of our imaginationSurvivalist x Ignored says: 10/21/2018 at 12:40 am"The Saudi government said it would take another month to complete a full investigation, which would be overseen by Mohammed.Watcher x Ignored says: 10/21/2018 at 2:51 am
Mohammad will find that Mohammad had nothing to do with the issue."
Perhaps an anti-KSA Boycott, Divestment, Sanctions (BDS) Movement will get started. Consumers and competitors might find the idea appealing.
Nice ideas for new KSA flag designs at this link here (I most like the chainsaw instead of the current sword design- reminds me of Scarface- Mo Bin Clownstick™ is about as legitimate and sophisticated as a coke runner):
The Sultan is playing his hand well (drip drip drip Turkish Int. leaks to the news with an intensifying puke factor- one recent read that Khashoggi was dismembered alive and dissolved in acid). Has Mo Bin Clownstick™ met his match?
https://lobelog.com/the-geopolitics-of-the-khashoggi-murder/I can't help but wonder about all those guys he threw into a hotel prison and shook down for billions of dollars. They can afford a lot of media with the money they had remaining.Survivalist x Ignored says: 10/21/2018 at 5:45 pmThe House of Saud appears to be fragmenting quite severely.Energy News x Ignored says: 10/20/2018 at 2:22 pm
Saudi Arabia's missing princes
https://www.bbc.com/news/magazine-40926963The last article he wrote before his deathLightsout x Ignored says: 10/21/2018 at 3:43 am
Jamal Khashoggi: What the Arab world needs most is free expression
By Jamal Khashoggi – October 17, 2018 – Washington Post
https://www.washingtonpost.com/amphtml/opinions/global-opinions/jamal-khashoggi-what-the-arab-world-needs-most-is-free-expression/2018/10/17/adfc8c44-d21d-11e8-8c22-fa2ef74bd6d6_story.html ?China demand for diesel only appears to be heading in one direction. Should please Watcher!Dennis Coyne x Ignored says: 10/22/2018 at 1:59 pm
https://mobile.twitter.com/PDChina/status/1053843063003525120?p=vShallow Sand,Energy News x Ignored says: 10/22/2018 at 5:27 am
No, not familiar, did you mean article linked below?
Link to full report
From the report:
The $3.9 billion in negative cash flows in the first two quarters of 2018 represented an improvement over the first halves of 2016 and 2017, when red ink totaled $11 billion and $7.2 billion, respectively.
These 33 companies have had positive net income since 2017Q4 and long term debt reached its peak for these companies in 2018Q1 at 138 billion with a gradual decrease to 126 billion in 2018Q2. As prices continue to rise debt will gradually be paid down,
When I look at that report I see an improving situation for these companies. I would prefer it if they broke the data into two groups, oil focused and natural gas focused companies. There has been a better recovery in oil prices than natural gas prices though it looks like we might see a spike in natural gas prices if we have a colder than normal winter.India's crude oil imports, the average for the first 9 months of 2018 is up +279 kb/day compared to first 9 months of 2017Energy News x Ignored says: 10/22/2018 at 5:57 am
Seasonal chart: https://pbs.twimg.com/media/DqGtWDoX4AAYDwJ.jpg
India's crude oil refinery processing, the average for the first 9 months of 2018 is up +231 kb/day compared to first 9 months of 2017
Seasonal chart: https://pbs.twimg.com/media/DqGttFOW4AAr0Uy.jpgSaudi Arabia spare capacity, there seems to be a consensus that Saudi Arabia can produce 11 million b/day. I guess that producing above that level would be subject to maintenance, outages and natural decline? (Also I'm guessing that the Khurais field expansion might not be ready until later in 2019?)Energy News x Ignored says: 10/22/2018 at 10:53 am
2018-10-22 Saudi Arabia Energy Minister Al Falih speaks to TASS
Saudi Arabia now in October is producing 10.7 million b/day.
And is likely to go up, in the near future, to 11 million b/day on a steady basis.
Our total production capacity is currently 12 million b/day.
And that could be increased to 13 million b/day with an investment of $20 to $30 billion.
Interview with TASS: http://tass.com/economy/1026924
Reuters summary of interview
https://www.reuters.com/article/us-oil-opec-saudi/saudi-arabia-has-no-intention-of-1973-oil-embargo-replay-tass-idUSKCN1MW0JUExxon in Brazil holds potential 41 billion barrels based on preliminary studiesGuyM x Ignored says: 10/22/2018 at 12:41 pm
2018-10-18 RIO DE JANEIRO and HOUSTON (Bloomberg) -- In a single year, Exxon Mobil has gone from being a tiny bit player in Brazil to the second-largest holder of oil exploration acreage, trailing only state-controlled Petroleo Brasileiro.
The last 24 concessions the U.S. giant bought with its partners may hold 41 billion bbl, based on preliminary studies, according to Eliane Petersohn, a superintendent at Brazil's National Petroleum Agency, or ANP. While the existence of the oil still needs to be confirmed, along with whether its extraction will be cost-effective, it's a huge figure -- almost double Exxon's current reserves.
The Irving, Texas-based company is betting big in particular on Brazil's offshore, where a single block is currently producing more than all of Colombia and profitability compares to the best U.S. tight oil, according to Decio Oddone, the head of ANP.
It should take six to eight years for oil to start flowing if economically viable deposits are discovered, according to ANP.
https://www.worldoil.com/news/2018/10/18/exxon-makes-major-bet-on-brazil-as-petrobras-eases-its-gripOther than the plethora of constraints in the Permian, I think this is going to develop into a bigger obstacle of shale growth for awhile. Especially, for those mostly Permian players for the next four quarters.
Almost 30% of gross production may go to service debt.
I think huge shale growth is possible, but only way north of $100 a barrel. At the current price, it is close to max.
Oct 23, 2018 | community.oilprice.com
Tom KirkmanMike Shellman writes again. No need for me to elaborate much on his persistent and very much needed gentle nudgings about debts coming due in the U.S. Shale Oil industry.mthebold , 10/20/2018 04:47 AM
Ignoring debt doesn't make it go away < cough > Venezuela < cough >
Deep The Denial
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B annually in interest on long term debt. ...
In other words, at the moment about 29% of total LTO production in America is used just to pay debt interest.
Using its own "breakeven" prices the US shale oil industry will ultimately have to produce 9G BO of oil, as much as it has already produced in 10 years...just to pay its total long term debt back. Essentially the only chance it has of doing that is if oil prices go to $125 a barrel, and stays there for a very long time.On 10/20/2018 at 12:45 AM, Dan Warnick said:Dan Warnick Dan Warnick + 640 DW
Simple, really simple: OPM (other people's money). And zero % interest rates. Payback is going to be hell.
Oct 09, 2018 | www.zerohedge.com
Authored by Nick Cunningham via Oilprice.com,
The debate about peak oil demand always tends to focus on how quickly electric vehicles will replace the internal-combustion engine , especially as EV sales are accelerating. However, the petrochemical sector will be much more difficult to dislodge , and with alternatives far behind, petrochemicals will account for an increasing share of crude oil demand growth in the years ahead.
Oct 02, 2018 | oilprice.com
"The warning signs are there – the industry isn't finding enough oil." That's the start of a new report from Wood Mackenzie. The report concludes that a supply gap could emerge in the mid-2020s as demand rises at a time when too few new sources of supply are coming online.
By 2030, there could be a supply shortfall on the order of 3 million barrels per day (mb/d), WoodMac argues. By 2035, it balloons to 7 mb/d, and by 2040, it reaches 12 mb/d. "Barring technology breakthrough beyond what we already assume, we'll need new oil discoveries," the report says.
The seeds of the problem were sown during the oil market downturn that began in 2014. Global upstream exploration spending plunged from $60 billion in 2014 to just $25 billion in 2018, according to WoodMac. Unsurprisingly, that translated into a steep decline in new discoveries. In the early part of this decade, the oil industry was discovering around 8 billion barrels of oil annually. That figure has plunged by three quarters since 2014.Read more US sanctions against Iran could give oil a boost to $100 amid dramatic shortfall in supplies
The precise figures vary, but Rystad Energy came a similar conclusion, noting that the total volume of new oil and gas reserves discovered plunged to a record low in 2017. "We haven't seen anything like this since the 1940s," Sonia Mladá Passos, Senior Analyst at Rystad Energy, said in a December 2017 statement . "The most worrisome is the fact that the reserve replacement ratio in the current year reached only 11 percent (for oil and gas combined) - compared to over 50 percent in 2012."
This year, the industry has had a bit more success. Spending is on the rebound and new discoveries are on track to rise by about 30 percent, although that is heavily influenced by the developments in Guyana, where ExxonMobil and Hess Corp. have reported nearly a dozen discoveries, and hope to ramp up production to around 750,000 bpd by 2025.
It still may not be enough. Even if the industry were to somehow return to the good ol' days prior to the 2014 market crash, and begin discovering around 8 billion barrels of oil each year, it would only delay the supply crunch into the 2030s, according to WoodMac.
But, of course, that rate of discovery remains far below those levels, so the supply crunch may take place much sooner. Moreover, because large-scale projects take several years to develop, the activity taking place today will determine the supply mix in the mid- to late-2020s.
WoodMac says that the rate of discovery is highly correlated with the level of spending, so closing the supply gap will require more capital. And because of the run up in oil prices this year, the industry will have a lot more cash to throw around.Read more Oil surges to 4-year high as investors see no sign of production rise amid Iran sanctions
The problem for the industry is that over the last few years the mindset, and the demands of shareholders, have shifted from production growth to profitability and investor returns. Shareholders are pressuring executives to return cash in the form of dividends and share buybacks. Energy stocks are not the darlings of Wall Street in the way they once were, particularly prior to the 2014 market meltdown. That puts extra pressure on oil and gas companies to dish out more of their earnings to investors rather than plowing it back into the ground.
But that means less spending on exploration. "The mind set for most E&Ps is still to be conservative, and default is to return capital to shareholders. Yet the duty to shareholders' interests cannot be myopically short term. More of the 'windfall' cash needs to find its way into exploration to sustain the business in the long term," WoodMac said in its report.
Shale output will continue to grow, especially after new pipelines come online in Texas, which will ease the current bottleneck. But the large-scale increases in production in the medium-term will come from "frontier areas," WoodMac says, as the string of discoveries in Guyana prove. WoodMac says the areas with the highest potential include "Suriname, the Brazilian Equatorial Margin; Mexico; Senegal, Gambia, Namibia and South Africa; Australia and Alaska."
For now, the level of activity is not enough to stave off the supply crunch, WoodMac warns, unless there is a dramatic increase in spending. "More explorers need to get in on the action if the spectre of 'peak supply' is to be kept at bay," the consultancy says.
This article was originally published on Oilprice.com
Sep 27, 2018 | www.zerohedge.com
The breakout in Brent crude prices above $80 this week has prompted analysts at the sell side banks to start talking about a return to $100 a barrel oil . Even President Trump has gotten involved, demanding that OPEC ramp up production to send oil prices lower before they start to weigh on US consumer spending, which has helped fuel the economic boom over which Trump has presided, and for which he has been eager to take credit.
But to hear respected petroleum geologist and oil analyst Art Berman tell it, Trump should relax. That's because supply fundamentals in the US market suggest that the recent breakout in prices will be largely ephemeral, and that crude supplies will soon move back into a surplus.
Indeed, a close anaysis of supply trends suggests that the secular deflationary trend in oil prices remains very much intact. And in an interview with MacroVoices , Berman laid out his argument using a handy chart deck to illustrate his findings (some of these charts are excerpted below).
As the bedrock for his argument, Berman uses a metric that he calls comparative petroleum inventories. Instead of just looking at EIA inventory data, Berman adjusts these figures by comparing them to the five year average for any given week. This smooths out purely seasonal changes.
And as he shows in the following chart, changes in comparative inventory levels have precipitated most of the shifts in oil prices since the early 1990s, Berman explains. As the charts below illustrate, once reported inventories for US crude oil and refined petroleum products crosses into a deficit relative to comparative inventories, the price of WTI climbs; when they cross into a surplus, WTI falls.
Looking back to March of this year, when the rally in WTI started to accelerate, we can on the left-hand chart above how inventories crossed below their historical average, which Berman claims prompted the most recent run up in prices.
Comparative inventories typically correlate negatively to the price of WTI. But occasionally, perceptions of supply security may prompt producers to either ramp up - or cut back - production. One example of this preceded the ramp of prices that started in 2010 when markets drove prices higher despite supplies being above their historical average. The ramp continued, even as supplies increased, largely due to fears about stagnant global growth in the early recovery period following the financial crisis.
The most rally that started around July 2017 correlated with a period of flat production between early 2016 and early 2018.
Meanwhile, speculators have been unwinding their long positions. Between mid-June 2017 and January 2018, net long positions increased +615 mmb for WTI crude + products, and +776 for WTI and Brent combined. Since then, combined Brent and WTI net longs have fallen -335 mmb, while WTI crude + refined product net long positions have fallen -225 mmb since January 2018 and -104 mmb since the week ending July 10. This shows that, despite high frequency price fluctuation, the overall trend in positioning is down.
And as longs have been unwinding, data show that the US export party has been slowing, as distillate exports, which have been the cash cow driving US refined product exports, have declined. Though they remain strong relative to the 5-year average, they have fallen relative to last year. This has accompanied refinery expansions in Mexico and Brazil.
Meanwhile, distillate and gasoline inventories have been building.
Meanwhile, US exports of crude have remained below the 2018 average in recent weeks, even as prices have continued to climb.
This could reflect supply fears in the global markets. The blowout in WTI-Brent spreads would seem to confirm this. However, foreign refineries recognize that there are limitations when it comes to processing US crude (hence the slumping demand for exports).
In recent weeks, markets have been sensitive to supply concerns thanks to falling production in Venezuela and worries about what will happen with Iranian crude exports after US sanctions kick in in November.
But supply forecasts for the US are telling a different story than supply forecasts for OPEC. In the US, markets will likely remain in equilibrium for the rest of the year, until a state of oversupply returns in 2019. But OPEC production will likely continue to constrict, returning to a deficit in 2019.
Bottom line: According to Berman, the trend of secular deflation in oil prices remains very much intact. While Berman expects prices to remain rangebound for the duration of 2018 - at least in the US - it's likely markets will turn to a supply surplus next year, sending prices lower once again.
Listen to the full interview below
Sep 19, 2018 | peakoilbarrel.com
Dennis Coyne x Ignored says: 09/17/2018 at 8:27 amHi Mike,Dennis Coyne x Ignored says: 09/17/2018 at 3:23 pm
Perhaps the Eagle Ford will never be profitable, it will depend on the price of oil and many other factors.
I guess I have a little more faith in the oil industry than you.
EOG has produced a fair amount of oil in the Eagle Ford and their net income in 2014 (when oil prices were high) was $2.9 billion, about 178 kb/d of C+C was produced from Eagle Ford in 2014 (about 65 million barrels) by EOG (about 62% of total 2014 EOG C+C output). The average price for C+C in the US received by EOG was about $93/b in 2014.
So it seems in 2014, for a well run oil company, $93/b worked just fine. Over the period from 2010 to 2014 EOG's net income was about $6 billion. From 2010 to 2017, the total net income was about $2.6 billion (not adjusted for inflation) as 2015 and 2016 were bad years with 5 billion losses in net income.
Debt to assets at the end of 2017 was about 21% with debt at $6.4 billion and assets at $29.8 billion. In 2017 Eagle Ford output was about 47% of EOG's C+C output, the average oil price EOG received in the US was $50.91/b in 2017, about $600 million of long term debt was paid off in 2017 with no new long term debt issued, but net cash flow was negative $766 million.
A discounted cash flow at a 10% annual discount rate results in a breakeven oil price (10% annual ROI) of $90.3/b for the average 2016 Eagle Ford well, if we assume a well cost of 9 million. Note that this is a "real" discount rate as I do costs in real inflation adjusted dollars, so it is equivalent to a nominal discount rate of 12.5% so would be equivalent to a nominal annual ROI of 12.5%.
EUR is 238 kb over 13.8 years and the well is shut in at 10 b/d. An assumption of 15 b/d shut in reduces EUR to 220 kb and well life to 9.75 years, and breakeven oil price rises to $91/b, an increase of 70 cents per barrel. Well payout is in 46 months at $91/b.
What is the full cost of the average Eagle Ford well?Note that I have assumed zero revenue from natural gas or NGL in my breakeven analysis and am considering C+C output only, not sure if there are natural gas pipeline bottlenecks in the EFS as there seems to be in the Permian basin. In any case, the economics might be slightly better when natural gas is included.Dennis Coyne x Ignored says: 09/18/2018 at 7:07 amShallow Sand,Dennis Coyne x Ignored says: 09/18/2018 at 1:29 pm
There wasn't significant drilling in the Eagle Ford Shale until 2011. How many of the 700 inactive wells started producing in 2009 and 2010? By Enno Peters data using Eagle Ford and unknown wells in Karnes County from Jan 2011 to Dec 2016, I get 2487 horizontal wells completed in total over that period. Note that the productivity rate distribution at Enno's site gives some funky numbers at the low end, so they should probably be ignored. "Zero" output after 24 months should probably be less than 15 b/d after 24 months. For Eagle Ford 2014 wells, supposedly there are 1747 wells with zero production rate after 24 months out of 3962 total wells, this is just a programming error. That is, zero does not mean zero in this case, would be my guess.
I checked with Enno Peters on this and the lowest column means output at 24 months is 0 to 50 b/d, same is true for each column it is from the previous to the next label so 0-50, 50-100, etc.Dennis Coyne x Ignored says: 09/18/2018 at 1:50 pmShallow sand,
Could over 20% of the horizontal wells in Karnes Co., TX already be shut in for over one year? These wells first produced 1/1/2019 to 12/31/2016, so they are not old wells at all? Less than 10 year economic life?
No the wells have not been shut in as you think, for 2009 to 2016 wells in Karnes county and Eagle Ford Formation I get 763 wells with "zero" production rate at Enno's site. He has pointed out that this is really 0 to 50 bopd for those 763 wells out of a total of 2425 wells producing that started production from 2009 to 2016. The average production rate was 86 bopd for all of the Karnes county Eagle Ford formation wells.
For all counties there were 15,600 wells with 7754 wells with output at 0 to 50 bopd at 24 months. Average for all counties is 63 bopd at 24 months. At 12 months the average rate was 127 bopd for all counties with about 25% of the wells at 0 to 50 bopd at 12 months.
Sep 19, 2018 | peakoilbarrel.com
Guym says: 09/14/2018 at 7:22 amhttps://mobile.reuters.com/article/amp/idUSL1N1TM1VJshallow sand x Ignored says: 09/14/2018 at 3:25 pm
Older article, but more important, now. EIA, and most of the Rystad type companies are continuing to report significant increases in the Permian. Latest monthlies are from June, all else is estimated, including drilling info. Completions are happening, and the new wells included in drilling info are, no doubt, true as to production. Who measures shut ins until final numbers are accumulated? Who spends significant time communicating with the small producer? Heck, they make up half the wells drilled in the Permian. I think there are considerable shut ins that will eventually reduce the magnificent increases that are currently being reported.GuymGuyM x Ignored says: 09/14/2018 at 4:22 pm
You seem to be pretty in tune with the EFS.
I ran a quick search on horizontal wells in Karnes Co., TX.
I found 2,778 active horizontal wells with first production from 1/1/2009 to 12/31/2016,
In the most recent month, here are the numbers:
170 wells produced 3,001+ BO
1,034 wells produced 1,001-3,000 BO
872 wells produced 501-1,000 BO
702 wells produced 1-500 BO
Could that be correct?
Furthermore, there appear to be over 700 inactive wells, which are defined as wells that have no recorded oil or gas production in the last 12 months.
Could over 20% of the horizontal wells in Karnes Co., TX already be shut in for over one year? These wells first produced 1/1/2019 to 12/31/2016, so they are not old wells at all? Less than 10 year economic life?
I know Mike has commented on how bad the EFS really is economically. It seems the hyper focus is now on the PB. However, EFS produces significant volumes of oil. Looks like this one could really collapse once the last locations are completed.
I saw many, many wells with cumulative production of 250K oil, that are now producing under 500 BO per month.
I ran the same search on De Witt Co., TX. Less wells, but similar results. Interesting to see all the wells in both counties that have maybe paid out, but are now producing less than 500 BO per month.Even Karnes County has it's less than tier one oil areas, and a lot of the wells were not up to par in the beginning. The well has to pay out capex in the first year, or its not worth drilling. Profit in year two and three, and not much after that. Period. End of story. I don't see much better out of the Permian, and may be getting worse. Yes, on the whole, less than a ten year economic life. Gets a lot worse in tier two stuff, and tier three stuff is, at these prices, a definite loss. But they are still drilling in tier three areas, go figure. My lease area is producing around 250k to 300k total, and it is barely touched, because EOG wants 300k. Yeah, when the tier one areas play out, costs to maintain will be prohibitive. Increase? Just a dream.Dennis coyne x Ignored says: 09/14/2018 at 7:40 pmEfs works at higher prices for average well. Probably needs 85 per barrel for well to payout in 60 months, maybe 90 per barrel for 36 month payout.Guym x Ignored says: 09/15/2018 at 8:47 amLook at EOG's economics of which wells are "premium" locations. There are not many left, and EOG probably owns the lion's share. It has to produce 200k barrels the first year. They priced that at $40 oil price, but it makes no difference, because it doesn't change the number of locations that can generate 200k barrels. They are justifying production to a 5200 ft lateral. Some make significantly more, some less. I have that memorized, as my wells have proven from the 125k to 175k the first year. Probably, a 250k to 300k EUR. So, I have to wait. They will be venturing into my area sometime before their "premium" locations are depleted. Beginning of the year, that count was at 2300. About 10 years at their current drilling rate, and less if they pick up activity. These are developmental wells, the Permian is still largely exploratory.shallow sand x Ignored says: 09/15/2018 at 12:12 pm
As far as holdings go, EOG is the cream of the crop. So, you can't make averages based on one company. Most look far, far worse. Their financial info was shit before, as were all the rest. Setting a bar for where to drill, will, in all likelihood, make them much better. There are a large number of smaller companies who still complete wells in tier three acreage. It's amazing, they know what they will get. I see initial production at 500 barrels a day, or less, and I know that someone is losing money.
But a big overview gives:
From completions of close to 15k oil wells in 2017 and 2018.
Now, do the math. There is not 10 years, or in most cases even five years of economically recoverable oil from shale. A 60 month payback???? At the highest bracket, it includes wells with about 3000 barrels a month. And there are only about 10k of those. Less than 3 years of completions. And if you look at the total number of producing wells it is slightly less now than in 2014. So, what happened to them??! To make it clearer, the number of wells that has become inactive is pretty close to the number of wells that has been drilled in four years. Yeah, production is up, because the wells producing over 3000 a month is up. But applying a ten year, or even five year economic life to them is pretty stupid. But, I don't have to look at total numbers to get to that conclusion, I look at individual wells, or groups of wells in a lease. It's a lot steeper treadmill than the hoopla indicates. Here's the count from Dec 2014. Shale wells will probably not drop down into the last category, so just look at the first two to compare them to current. If they do drop into the last category, the production doesn't mean much to the cost of the well, or profitability. About four thousand more, and tens of thousands of new wells since then.
So, think about this when your looking at Eno's data, averages are deceiving. Whether they are tier one, two, or three makes a huge difference.What are the operators doing with all of these inactive wells?Guym x Ignored says: 09/15/2018 at 1:19 pm
Are they able to keep them shut in or do they have to produce or plug within a certain amount of time.
The financial liability for all of these wells is huge.
700 wells x $250K per well to P&A? In just Karnes Co.The links to the report show plugging activity. Substantial. In August EF had 120 oil completions, and 50 something oil wells plugged. Completions were higher in August. Dec 2017, oil wells completed and plugged were almost equal. That is not an exact description of EF horizontals, but that is the main thing going in these districts. $250 sounds low, I think.shallow sand x Ignored says: 09/15/2018 at 7:08 pmI was assuming $250K net of salvage.Mike x Ignored says: 09/15/2018 at 6:25 am
I assume given all the activity in PB, a lot of those 640's, etc, might be traveling from EF to PB.
Maybe those guys P & A this stuff are making the real money?Shallow, FTR, last thread: my current est. economic limits of 15-18 BOPD for LTO wells will be much higher for major integrated companies, yes. The everything is peachy 'assumption' is that smaller companies will buy those wells and carry on. I do not believe that. A 6-10% decline in total UR because of premature economic limits IS a big deal. It makes or breaks thousands of wells.shallow sand x Ignored says: 09/15/2018 at 7:59 am
The liquids rich gas leg of DeWitt and Karnes Counties IMO will see <35% of its wells be 'significantly' profitable, for instance above 150 ROI. Your data you are showing is a big deal that seems to be going plum over peoples heads. Sorry. Time will show that the Eagle Ford was, is the biggest financial toilet of all three shale basins; the economics are indeed awful. I operate conventional production IN the EF trend and have interest in wells. Folks don't realize how many $10-12MM dollar wells were drilled from 2009-2013. Jeff Brown and I guessed eight years ago only 35-40% of shale oil wells in the EF will even pay back D&C&A costs. I think that is way too high now.
Whatever the definition of "works," means, Dennis, for the EF; newer well designs are leading to much higher IP180-360, but not higher UR. It does not look that way to me. Now new wells in the EF must carry the burden of the highest level of legacy debt in the LTO industry. To maintain and actually pay that debt back will take much higher oil prices than you think as the play is now pretty much exhausted. At current oil prices it takes 325-350K BO to pay new wells with longer laterals and much bigger frac's out.
The LTO industry is not in business so people can speculate about how much oil it is going to make, or the jobs it provides, or how much cheaper gasoline it can provide for consumers
https://www.oilystuffblog.com/single-post/2018/09/12/Cartoon-Of-the-Week ; its in business to MAKE money. 150 ROI's is not making sufficient money to be self sustainable and be able to kick the credit/debt addiction.
Longhorn is correct, Matador did indeed pay $95K an acre for PMNM acreage. I suggest we bow our heads and honor its shareholders with a moment of silence and a little prayer to the Goddess of Wolfcamp in order that she be merciful. Another bench Matador is touting to justify its "wisdom" is the (De) Cline shale interval. Phftttttt.The irony is that the majors and large independents divested of many assets in the US lower 48 in the 1990s because they were perceived as high cost with little economic future.Lightsout x Ignored says: 09/15/2018 at 1:29 pm
However, folks like us are still producing that stuff profitably.
OTOH the same companies are now spending large sums on shale, which is economically inferior to what they divested 20-30 years ago.Since when did big oil ever have a plan?
Sep 19, 2018 | peakoilbarrel.com
MudGod, 09/12/2018 at 11:52 amI remember Matthew Simmons saying that when Saudi peaks, the world peaks.Survivalist x Ignored says: 09/12/2018 at 2:21 pmMr.Simmons likely never considered the productive wonders of a cash flow negative oil boom aka USA LTO sarc/Dennis Coyne x Ignored says: 09/12/2018 at 3:29 pm
I wonder how many more cash flow negative oil booms the world can endure, and how long USA LTO will last. While we're at it, I wonder how the pension funds invested in USA LTO are gonna do for their members once the rats under the floorboards get flushed out.
Buckle your chin strap. Within a few to several years we'll perhaps know better how this is gonna shake out. George Kaplan and Dennis Coyne had some future production charts in the comments of last post. By my rough eyeball and memory, I think George Kaplan had future production down to about 40 million barrels a day by 2050 (see link below). Dennis, ever the optimist ;), had us down to about 50 million barrels a day by 2050 (see Mr. Coynes comments in response to George). Either way, those alive in 2050 are gonna be living in a very different world!
http://peakoilbarrel.com/eias-latest-usa-world-oil-production-data/#comment-651548Survivalist,George Kaplan x Ignored says: 09/13/2018 at 1:10 am
A lot depends on how much oil can be extracted. George Kaplan's scenario looks to be roughly a URR of 2400 Gb if the 2020 to 2063 trend continues in future years (it is roughly straight line decline over that period so I just extended the line to zero and estimated URR. It is more likely, in my view that URR will be about 3060 Gb (including 260 Gb of extra heavy and LTO oil), that's about midway between a pessimistic HL scenario(2600 GB) and optimistic USGS scenario (3000 Gb) for conventional oil.
Also higher rates of extraction could keep production a bit higher maybe 64 Mb/d in 2050, it will depend on the length of Great Depression 2 in 2030. Of course I think that might only last 4-5 years, being an optimist.I haven't worked it out but I'd guess the ultimate recovery is more than your estimate. First, as I said before, the XH production is based on long cycle projects, so it would have a fat tail extending beyond when most of the conventional oil is exhausted (there are a few reasons for that but one is that it needs upgraders and those are not built with excess capacity). Second, as I said twice before, Laherrere has about 180 Gb of "rest of the world" reserves that I didn't include as I don't know what they represent – if they are undiscovered oil then at current rates it will take about 40 years to find them, or if the recent trend for declining discoveries holds then forever.George Kaplan x Ignored says: 09/13/2018 at 1:11 am
And that is the last I am going to write – or read – on that Laherrere paper. It was just a comment on a blog, not an article in Nature or the Times or even a letter to either of those, or even a letter to the local free advertising paper. I wrote it most for my own interest, writing things out help clarify ideas, but I rarely do more than a cursory proofread. Most people who bothered to look at it would have read a couple of sentences and skimmed the rest, a very few might have got more out of it. It didn't change anything fundamental. If somebody was going to write another comment they wrote exactly what they were going to write anyway.SurvivalistLightsout x Ignored says: 09/13/2018 at 1:18 pm
It won't take to 2050 to see a different world. Just a small fall in supply has effects well out of proportion to the nominal cash value of the oil lost. Cheap flights would disappear, trade would plummet, GDPs shrink – the books have to balance one way or another (see recent paper on impact on trade, I think by Barclays, and works by Hall and Kummel). The biggest impact might be food prices, they could easily double and more short term, then the few billion who spend half their income on food suddenly have to spend it all. Turmoil would ensue and likely knock more oil supply off line. There was a paper about Sweden I think – from memory (don't quote me) a rapid fall by a quarter of the oil available leads to collapse and by a half to complete loss of civilization.
At the same time the declining cheap and efficient energy would hamper efforts to address the other big ticket, long term issues: rising population, evolutionary inevitable aspirations – "poor man wanna be rich, rich man wanna be king, and a king ain't satisfied till he rules everything" (of course); declining levels in some of the big aquifers (a few are getting to the point where the basic pump designs don't work, the replacements needed are much more expensive and much more energy intensive); declining soil loss (at current rate all the soil on sloped arable land will be gone in 50 years – that's a third – and most of the rest in another 50); and of course climate change related extreme weather. This year we've had record heat waves, wild fires, typhoons and (soon) hurricanes plus droughts etc. Soon those will be weekly events (we're not far off now) but on top of that we will be having two or three extreme extreme-weather events per year. More and more of the oil will be going simply to triage on these (but the patient will get worse anyway). At some point countries will cease to be liberal democracies, the USA seems to be leading the way there, and say what you like about liberal democracies they have never declared war on each other, dictatorships on the other hand
People will say oh we just need to do this, that or the other – but there is no "just" about any of it, and especially as oil disappears: ignoring the externalities there is absolutely no better real energy source imaginable by some way, especially the cheap stuff we used to have.
You of course know all this and are preparing much better than me, I do not much more than appease my conscience by not flying and hardly ever riding in a car, but I think I'm getting to the "acceptance" stage and pretty much missed out on depression (no physical symptoms anyway).
[end of rant].If I remember correctly someone once asked Matt Simmons how best to prepare for peak oil. His response was "be over 50".Hickory x Ignored says: 09/13/2018 at 3:38 pmAnd that was , what, about 15 yrs ago? So make it 65 now.Survivalist x Ignored says: 09/13/2018 at 5:56 pmI tend to agree with you George. Only a small decrease a short time after peak, and the realization that it's not going back up, will likely open a lot of people's eyes to the fact that almost every stock and equity is overvalued (come to understand that anticipated future growth will not be realized). I plan to hunker down and catch up on my reading while the dust settles, and I'm thinking there'll be a lot of dust. I'll send you a map. Password is 'I think I'm with the band'.
I find this to be also an interesting take on the future of oil
Fracking (Tight Oil) delays Peak Oil by some years
Sep 19, 2018 | peakoilbarrel.com
Captjohn x Ignored says: 09/12/2018 at 1:50 pmHere is someone that does have a clue – CEO of Schlumberger:George Kaplan x Ignored says: 09/14/2018 at 2:52 am
"The short-term investment focus adopted since 2014 offers a finite set of opportunities over a limited period of time, and this period is now clearly coming to an end as seen by accelerating decline rates in many countries around the world," Kibsgaard pointed out.
BAU won't get it done – no quick fixes, 'new shale revolution' or 'reserve production' to get us through – my interest is mostly how we (as a society and culture) will react as constraints on the resource 'haves' and 'have nots' set in.
Went through Irma in South Florida last Fall – and in general order was maintained – but really only out of Gas for about 3 days – and was more of a shock type shortage. A very slow decline of world supply will hit those who can't pay for it most – and maybe wake up enough through higher prices to begin planning for what will be the greatest energy transition that must take place!The big oil companies are selling a story of long term stability to their investors, partly so they can justify the long term investments needed for the mega-projects where they get most of their oil and cashflow (some of those see no net return for many years). They only need to sell themselves to their investors, not their customers who just buy the cheapest or most convenient, be it crude to refineries or petrol to motorists.Mike Sutherland x Ignored says: 09/14/2018 at 10:22 am
The service companies live more year to year – they get hired to help develop and drill a field and then their workload drops a lot except for some well servicing during operation. Schlumberger is selling itself to its customers (the 'operators' who are the E&P companies) and investors as the go to guy for the next couple of years as activity tries to pick up but faces increasing issues as the easy (and now not so easy but still OK-ish) oil goes away.Schlumberger is not a typical service provider to the producers, although that is a large portion of their business. Since their purchase of Cameron International and other oilfield manufacturing companies, they have been providing facility engineering and fabrication services to the oil producers worldwide.
In point of fact, Schlumberger does have the information that the producers have, and then some. They use those numbers as a basis for facility engineering, and as such are arguably in a better position to interpret them than the producer as of late.
I've regularly read the BP annual report, and have come to regard it as little more than a curiosity. Schlumberger, Shell and Total have a firmer grip on the world oil situation, based on my read of their CEO's comments. However that may be confirmation bias on my part. We shall see .
Sep 19, 2018 | peakoilbarrel.com
conacher says: 09/14/2018 at 10:42 amProbably the more important item is Russian reserves my estimate is we are at 90% depletion for existing technology and OIP at cost for western Russian reserves. At this point a squeeze plan in Syria would ensure foreign reserve earnings to into wars and not fuels outcome is standard wars as a result of miss spending incomekolbeinh x Ignored says: 09/14/2018 at 2:00 pmYes, I assume they have some problems since they reformed the tax system in favor of upstream risky projects and at the same time imposed more taxes on downstream refineries. But to assume Russia has problems is like assuming the whole world has a problem. Could be perfectly right, but why expose Russia as opposed to others? Russia has a lot of higher cost oil; just look at the land mass and offshore mass. How could there not be prospects? Some inside knowledge is sorely lacking, since I like most western people don't have connections in that part of the world.conacher x Ignored says: 09/14/2018 at 1:38 pmhttps://medium.com/insurge-intelligence/brace-for-the-financial-crash-of-2018-b2f81f85686bRon Patterson x Ignored says: 09/14/2018 at 2:49 pm
only way to 'pull off above' is both Russia western province and gehwar at "90%" OIP gone.Thanks for the link Conacher. Folks this article makes a prediction that needs to be read.conacher x Ignored says: 09/14/2018 at 2:56 pm
Brace for the oil, food and financial crash of 2018
80% of the world's oil has peaked, and the resulting oil crunch will flatten the economy.
New scientific research suggests that the world faces an imminent oil crunch, which will trigger another financial crisis.
A report by HSBC shows that contrary to the commonplace narrative in the industry, even amidst the glut of unconventional oil and gas, the vast bulk of the world's oil production has already peaked and is now in decline; while European government scientists show that the value of energy produced by oil has declined by half within just the first 15 years of the 21st century.
The upshot? Welcome to a new age of permanent economic recession driven by ongoing dependence on dirty, expensive, difficult oil unless we choose a fundamentally different path.
Then they say: The HSBC report you need to read, now
Global Oil Supply, Will Mature Field Declines Drive Next Supply Crunch?
This thing came out two years ago. Why did I not hear about it before? Has this been posted here and talked about already?Real issue is giants, your article in 2015 real issue is 90% ..real issue is squeeze play in motion in Syria..goal? if don't have it, don't drill it at home, no rig increases so 'end game' is cut off Isreali/Saudi friendly arab gas to Europe own Caspian area (city I recall owned by Ukraine under British treaty Yelsin) in end no WW2 buildup during economic issues (Russia 5M/day, Saudi similar) no Hilter, just preempt what's left..Carlos Diaz x Ignored says: 09/14/2018 at 5:08 pmRon Patterson x Ignored says: 09/14/2018 at 8:14 pm
"This thing came out two years ago. Why did I not hear about it before? Has this been posted here and talked about already?"
Yes, it was. Here:
I downloaded it then, and just had to look at the date the file was created. You probably also have it in your hard-drive.
It provided a nice confirmation to my thesis that Peak Oil won't happen in the future. It is taking place now, and the date we entered the Peak Oil plateau was 2015. You also forecasted that, as I did.You are correct. Hey, I am 80 years old and I just can't remember shit anymore.Carlos Diaz x Ignored says: 09/15/2018 at 4:31 am
Okay, I posted a few days ago that I thought peak oil would be in 2019. Perhaps I was wrong. Hell, I have been wrong quite a few times. But now perhaps peak oil is right now.
Perhaps? We shall see.
But my point is everyone seems to be agreeing with me now. Old giant fields are seeing an ever increase in decline rates. I predicted this a long time ago. Once the water hits those horizontal laterals at the very top of the reservoir, the game is over.
The decline rate in those old giant fields is increasing at an alarming rate. Obviously! Fucking obviously. It could not possibly be otherwise. Thank you and goodnight.Memory is less necessary these days with internet, computers, and smart phones, where searches can be run in a moment. Don't worry too much about that.Michael B x Ignored says: 09/15/2018 at 5:01 am
"But my point is everyone seems to be agreeing with me now."
I discovered your blog in 2014 when looking for confirmation on my suspicion that the oil price crash was going to result in Peak Oil. I was impressed to see that you were there years before through your analyses. I have a lot of respect for you and your intellectual capacity, and I agree with you in many things, besides Peak Oil, including the population problem, and your worries about the environment.
I don't believe the world cannot increase its oil production, I just believe it won't do it. Both Saudi Arabia and Russia have the capacity to go full throttle on what they have left. Shaybah is the most recent supergiant in KSA and expected to produce until 2060 at current output. No doubt they could increase production from Shaybah by a lot, but it is not in their interest to do so. Russia lacks the capacity to quickly increase its production, but there's still plenty of oil in Eastern Siberia, so they could also produce more. Again it is also unlikely, as it would require an investment and effort that goes against their own interest.
Peak Oil is not happening because the world is trying to produce more oil and failing, it is happening by a combination of economical, geological, and political factors that could not be easily predicted and that were set in motion in the early 2000's when the low-hanging fruit of conventional on-shore and off-shore crude oil (the cheapest kind to produce) reached its production limit. Political errors, like taking out Gaddafi, added unnecessary difficulties. The collapse of Venezuela is the latest political cause. And when things start to go wrong, it never rains, but it pours."Peak Oil is not happening because the world is trying to produce more oil and failing, it is happening by a combination of economical, geological, and political factors that could not be easily predicted and that were set in motion in the early 2000's when the low-hanging fruit of conventional on-shore and off-shore crude oil (the cheapest kind to produce) reached its production limit."Carlos Diaz x Ignored says: 09/15/2018 at 5:35 am
Isn't this just a distinction without a difference? It's peak oil.The issue is that Peak Oil has been misunderstood by most people. The argument that Peak Oil won't happen until this or that date because ultimate reserves are such or such, so often read in this forum, is incorrect. Even economically recoverable reserves are not decisive. To make the problem intractable there are many liquids so some might peak while others don't so discussions about Peak Oil are endless.Michael B x Ignored says: 09/15/2018 at 6:27 am
But it is very simple. Peak Oil is when the world no longer gets the oil it needs to keep expanding its economy. And the best way to measure it is through C+C, because crude oil is what we have been getting since the late 19th C ans is the stuff that produces everything our economy needs, from asphalt to diesel, plane fuel, and gasoline. NGL won't cut it. Biofuels won't cut it.
And Peak Oil is being determined by economical and political factors, besides the geology.
The difference matters because Peak Oil is going to get almost everybody by surprise. Most won't realize what is the cause of all the troubles we are going to get and they'll be reassured that there is plenty of oil to be extracted, which is true but irrelevant.Thanks for the reply. I also tremble at the prospect of what is to happen because of the failure of the predictions last decade. I can only describe it through an analogy (being a lay reader and a writer):Carlos Diaz x Ignored says: 09/15/2018 at 7:39 am
In the 2000s, people were saying that we had an ugly wound and that we had better do something about it. But instead of properly addressing the wound, we just wrapped it in gauze, and when the blood stopped showing through, we said, "See? All better." That's my analogy for the "shale revolution" -- it was essentially a Bandaid. The complacency has only worsened in the last ten years.
This has just made the infection all the worse. When pus starts showing through the dressing and we unwrap it this time -- we're going to find gangrene.Michael,Guym x Ignored says: 09/16/2018 at 9:20 am
I am re-reading Joseph Tainter's 1998 book "The collapse of complex societies." It is a sober reading that shows that in the end the laws of entropy and diminishing returns always produce the same result. We are not more intelligent than the people that preceded us. If anything we can only be stupider on average. We just have a very high opinion of ourselves.
Time for a wake up and a little bit more darwinism in our lives. The problem is the pain. With so many people it is just going to be unbearable. On a scale never imagined, not even by writers of bad sci-fi.That would be a more important definition of peak oil to me, and I think we are definitely there. Then we have the absolute production definition, which was the original definition, as to production. It is now anticlimactic to your definition. As to the date or year it happens, who cares? More importantly, now, is when demand will lower enough to stop draining inventories. At what oil price will that start occurring? How fast will alternate sources replace unmet demand? New directions and everyone is likely to be wrong on estimates. EIA and IEA were totally useless before, and that will probably not change in the near future. Looking in the past won't give us much, and the future is anybody's guess.Dennis Coyne x Ignored says: 09/17/2018 at 9:13 am
As to current prices, $68 oil won't get any extra interest from E&Ps outside of the Permian that is stalled. To any measurable extent. Close to $80 oil is not expanding interest very much outside of the US. We are just living on borrowed time.Guym,TechGuy x Ignored says: 09/18/2018 at 1:43 am
Oil prices are likely to continue to rise, especially if your estimates of future production (roughly similar to my estimates, but perhaps a bit more pessimistic) are correct, unless consumption of oil stops increasing. My guess is that oil (C+C) consumption will continue to increase at 400 to 800 kb/d each year , until oil prices get to about $150/b or more (around 2025 to 2027),by that time or soon after ( maybe 2030) oil consumption growth may stop either because of the expansion of electric and natural gas powered transport or because of a second Great Financial Crisis. My hope is it will be the former, but I think the latter scenario is much more likely.
Hopefully Keynes' General Theory will make a comeback before then.
It is a dollar on Kindle
https://www.amazon.com/General-Theory-Employment-Interest-Illustrated-ebook/dp/B018055I7Q/ref=tmm_kin_swatch_0?_encoding=UTF8&qid=&sr=Ron Wrote:Survivalist x Ignored says: 09/14/2018 at 11:32 pm
"I predicted this a long time ago. Once the water hits those horizontal laterals at the very top of the reservoir, the game is over. "
FWIW: That's already happened. when it occurs, they drill a new horizontal above the old one. The new lateral also have valves on there ports. so that when the water breaches one or more of the ports, they shut them off to reduce water cut. I posted Saudi Aramco tech articles here back between 2014 and 2016 when they were available on the SA website.Hi Carlos, thanks for the trip down memory lane. I tend to agree with peak oil being now (ish). From what I recall the peak month for C+C was, so far, in November 2016. I suppose there is also a peak day, a peak weak, and a peak year. Folks seem to like packaging time in various proportions. Hell, there's probably a peak decade and a peak hour. My guess is the peak year will be 2018. I like, because I'm a bit thick at maths, how Ron has added trailing 12 month average to his world production chart. I just look at the 12 month trailing average for each December to get an idea of how much was produced in each calendar year. It seems that 12 month trailing average for December 2018 will beat that of 2017. My guess is 2019 won't beat 2018. Or will any other year after that. So, if Ron say's 2019, and I say 2018, then it seems that I think he is wrong lol he's probably 100 times smarter than me so doesn't lose sleep over it lol. Up until this time I have always agreed with Ron on peak oil. But now, I throw down the gauntlet! 2018 vs 2019. Two will enter, one will leave.Carlos Diaz x Ignored says: 09/15/2018 at 5:08 amHi Survivalist,Dennis coyne x Ignored says: 09/15/2018 at 8:59 am
The exact week, month, or year when maximal production is reached has only historical interest. The point is that since the end of 2015 the 12-month averaged C+C production has barely increased (EIA data) despite the increase in demand.
Dec 2015 80,564 100.0%
Dec 2016 80,579 100.0%
Dec 2017 80,936 100.5%
Apr 2018 81,363 101.0%
We will have to see how it evolves over to the next December, but so far it is annualized to a 0.4% increase. To me we are in a bumpy plateau since late 2015 and all those meager gains and more will be lost in the next crisis. The problem will be evident to many when after the crisis we are not able to increase production above those values.
Peak Oil is a situation, not a date, and we are in that situation since late 2015. The oil that the world demands cannot be produced so prices are going up, and up. I suppose it is possible that the powers that be intervene to reduce global oil demand by favoring a crisis in developing countries, like Argentina, Brazil, Turkey, South Africa, through interest rate changes. Wait, it is already happening. It is a dangerous tactic, as crises can spread around, and the interest rise weakens the economy.Carlos,Carlos Diaz x Ignored says: 09/15/2018 at 12:42 pm
Well one has to define the plateau a bit better. If we make the bounds wide enough one could say the peak was 2005 or even 1980 and we have been on a bumpy plateau since that point.
Better in my view to define peak as peak in centered 12 month average output wth center between month 6 and 7.Dennis,Dennis Coyne x Ignored says: 09/17/2018 at 9:23 am
I use a 13-month centered average, so it is symmetrical with 6 months at each side.
But really, after a clear period of production growth 2010-2014, there was a strong growth in production 2014-2015 in response to falling prices, and then production got stuck in late 2015.
It is not a question if we are in a plateau (or very reduced growth) period, but what happens afterwards. After the previous plateau 2005-2009 there was a clear fall 2009-2010, before tight oil saved the day.
Carlos,Dennis coyne x Ignored says: 09/14/2018 at 8:11 pm
The recent plateau is due to excess inventory and the resulting low oil price level. Oil inventories have been reduced over the past 12 to 18 months and as oil prices increase, output will also increase with perhaps a 6 to 12 month lag. How much will it need to rise above the Dec 2015 level before you no longer consider that output has not risen above your "plateau". Give me a number, is it 81.5 Mb/d, 82 Mb/b, I prefer to use a year rather than 13 months, that's 182 days on either side of the middle of the 12 month period. On leap years we can use Midnight of day 183One issue that has been corrected is that reserve requirements for large banks have increased.
Also lenders are more careful with their mortgages making a housing bubble less likely.
In addition, the assumption that higher oil prices played a major role in the GFC is incorrect.
Perhaps there is a looming recession, whether this happens in 2018, 2030 or some other year we will only know when it occurs.
Someone who predicts a recession every year will be right eventually.
I maintain my guess of 2023 to 2027 for the 12 month centered average c+c peak and severe recession GFC2 starting 2029 to 2033, lasting 5 to 7 years.
Sep 19, 2018 | peakoilbarrel.com
George Kaplanx Ignored says: 09/15/2018 at 6:14 am Some interesting figures from the OPEC annual statistical review earlier this year that I missed when it came out: https://asb.opec.org/index.php/interactive-charts
First crude only peaked in 2016, with 2017 below 2016 and 2015.
George Kaplan x Ignored says: 09/15/2018 at 6:15 amSecond oil reserves have been flat since around 2010, and declining recently for the first time since the 1970s. Note, before someone points it out, they don't count Canadian Bitumen.Ron Patterson x Ignored says: 09/15/2018 at 9:23 am
This is so ridiculous it is funny. Oil discoveries have been going down, down, and down, way below replacement level. Yet so-called "proven" reserves keep going up, up and up.Timthetiny x Ignored says: 09/17/2018 at 1:03 am
That's to be expected.TechGuy x Ignored says: 09/18/2018 at 2:00 am"This is so ridiculous it is funny. Oil discoveries have been going down, down, and down, way below replacement level. Yet so-called "proven" reserves keep going up, up and up."Fernando Leanme x Ignored says: 09/15/2018 at 9:44 am
Well to some degree, technology has been able to extract more oil from a field. Thus a field discovered in 1950 with an initial proven reserve of 100mbbls, may have 125mbbls or proven reserves as technology has improved recovery rates. That said technology improvements likely don't match the paper proven reserves.The Venezuelan heavy oil reserves are overstated (I assume the large bump prior to 2010 is the booking of the Magna Reserva in the Orinoco Oil belt, which i know are fake). It's fairly easy to eyeball the better number by substracting 300 billion a flat line around 1200. If you want to add future bookings in that heavy oil belt, add up to 50 billion gradually. Dont forget that at the current decline rate Venezuela will be producing about 1.1 million BOPD in december, and IF things go as I think they will sometime in the first half of 2019 exports will drop to zero for a few months.George Kaplan x Ignored says: 09/15/2018 at 6:15 amThird gas reserves also flat. If condensate and NGLs have been meeting the increased demand that crude has been unable to, then that might be about to stop.
Sep 10, 2018 | www.moonofalabama.org
Grieved , Sep 9, 2018 11:27:48 PM | link
Money. Finance. Currency.
The Keiser Report has a very upbeat show today on RT, in which they celebrate how the NYT has finally come round to reporting the truth about US fracking, in ways that Max and Stacy were reporting 9 years ago.
Fracking has indeed produced oil and gas, but the fields deplete rapidly without massive additional investment. Only the zero-interest rates of the Fed's Quantitative Easing could have financed the fracking boom - without QE, US oil and gas would not even exist on the world's radar.
And yet Neocons are taking the US production of hydrocarbons as a major plank in their platform of war, building castles in the air from a mythical "energy supremacy" and treating current production levels as a weapon of war -- but the economics of this relatively minor industry will shut it down soon.
In the second half of the 30-minute show, Max interviews Wolf Richter and they discuss Argentina mostly. It's a rapid and valuable overview of how the US Hegemon deals with its favorite suckers south of the border, and how currencies and bonds work - and also why the IMF acts only to bail out investors and bond-holders, and never the real economy of the victim nation.
Fracking financial crisis lurking (Keiser E1277)
Sep 04, 2018 | www.zerohedge.com
Authored by James Howard Kunstler via Kunstler.com,
And so the sun seems to stand still this last day before the resumption of business-as-usual, and whatever remains of labor in this sclerotic republic takes its ease in the ominous late summer heat, and the people across this land marinate in anxious uncertainty.
What can be done?
Some kind of epic national restructuring is in the works. It will either happen consciously and deliberately or it will be forced on us by circumstance. One side wants to magically reenact the 1950s; the other wants a Gnostic transhuman utopia. Neither of these is a plausible outcome.
Most of the arguments ranging around them are what Jordan Peterson calls "pseudo issues." Let's try to take stock of what the real issues might be.Energy
The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e. Federal Reserve policy. Even The New York Times said so yesterday ( The Next Financial Crisis Lurks Underground ).
For all that, the shale oil producers still couldn't make money at it. If interest rates go up, the industry will choke on the debt it has already accumulated and lose access to new loans. If the Fed reverses its current course - say, to rescue the stock and bond markets - then the shale oil industry has perhaps three more years before it collapses on a geological basis, maybe less. After that, we're out of tricks. It will affect everything.
The perceived solution is to run all our stuff on electricity, with the electricity produced by other means than fossil fuels , so-called alt energy. This will only happen on the most limited basis and perhaps not at all. (And it is apart from the question of the decrepit electric grid itself.) What's required is a political conversation about how we inhabit the landscape, how we do business, and what kind of business we do. The prospect of dismantling suburbia -- or at least moving out of it -- is evidently unthinkable. But it's going to happen whether we make plans and policies, or we're dragged kicking and screaming away from it.Corporate tyranny
The nation is groaning under despotic corporate rule. The fragility of these operations is moving toward criticality. As with shale oil, they depend largely on dishonest financial legerdemain. They are also threatened by the crack-up of globalism, and its 12,000-mile supply lines, now well underway. Get ready for business at a much smaller scale.
Hard as this sounds, it presents great opportunities for making Americans useful again, that is, giving them something to do, a meaningful place in society, and livelihoods.
The implosion of national chain retail is already underway. Amazon is not the answer, because each Amazon sales item requires a separate truck trip to its destination, and that just doesn't square with our energy predicament. We've got to rebuild main street economies and the layers of local and regional distribution that support them. That's where many jobs and careers are.
Climate change is most immediately affecting farming. 2018 will be a year of bad harvests in many parts of the world. Agri-biz style farming, based on oil-and-gas plus bank loans is a ruinous practice, and will not continue in any case. Can we make choices and policies to promote a return to smaller scale farming with intelligent methods rather than just brute industrial force plus debt? If we don't, a lot of people will starve to death. By the way, here is the useful work for a large number of citizens currently regarded as unemployable for one reason or another.
Pervasive racketeering rules because we allow it to, especially in education and medicine. Both are self-destructing under the weight of their own money-grubbing schemes. Both are destined to be severely downscaled.
A lot of colleges will go out of business. Most college loans will never be paid back (and the derivatives based on them will blow up).
We need millions of small farmers more than we need millions of communications majors with a public relations minor. It may be too late for a single-payer medical system. A collapsing oil-based industrial economy means a lack of capital, and fiscal hocus-pocus is just another form of racketeering. Medicine will have to get smaller and less complex and that means local clinic-based health care. Lots of careers there, and that is where things are going, so get ready.Government over-reach
The leviathan state is too large, too reckless, and too corrupt. Insolvency will eventually reduce its scope and scale. Most immediately, the giant matrix of domestic spying agencies has turned on American citizens.
It will resist at all costs being dismantled or even reined in. One task at hand is to prosecute the people in the Department of Justice and the FBI who ran illegal political operations in and around the 2016 election. These are agencies which use their considerable power to destroy the lives of individual citizens. Their officers must answer to grand juries.
As with everything else on the table for debate, the reach and scope of US imperial arrangements has to be reduced. It's happening already, whether we like it or not, as geopolitical relations shift drastically and the other nations on the planet scramble for survival in a post-industrial world that will be a good deal harsher than the robotic paradise of digitally "creative" economies that the credulous expect.
This country has enough to do within its own boundaries to prepare for survival without making extra trouble for itself and other people around the world. As a practical matter, this means close as many overseas bases as possible, as soon as possible.
As we get back to business tomorrow, ask yourself where you stand in the blather-storm of false issues and foolish ideas, in contrast to the things that actually matter.
Sep 04, 2018 | www.zerohedge.com
Most of the arguments ranging around them are what Jordan Peterson calls "pseudo issues." Let's try to take stock of what the real issues might be.Energy
The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e. Federal Reserve policy. Even The New York Times said so yesterday ( The Next Financial Crisis Lurks Underground ). For all that, the shale oil producers still couldn't make money at it. If interest rates go up, the industry will choke on the debt it has already accumulated and lose access to new loans. If the Fed reverses its current course - say, to rescue the stock and bond markets - then the shale oil industry has perhaps three more years before it collapses on a geological basis, maybe less. After that, we're out of tricks. It will affect everything.
The perceived solution is to run all our stuff on electricity, with the electricity produced by other means than fossil fuels , so-called alt energy. This will only happen on the most limited basis and perhaps not at all. (And it is apart from the question of the decrepit electric grid itself.) What's required is a political conversation about how we inhabit the landscape, how we do business, and what kind of business we do. The prospect of dismantling suburbia -- or at least moving out of it -- is evidently unthinkable. But it's going to happen whether we make plans and policies, or we're dragged kicking and screaming away from it.
Aug 26, 2018 | peakoilbarrel.com
Ignored says: 08/21/2018 AT 6:37 PM
Permian- more cost, less production, more DUCs. Faces decorated with eggs. REPLY
Ignored says: 08/22/2018 AT 4:03 PMGuym
The message I get from that piece is that companies are getting ready for next year so they can hit the ground running when the pipeline bottleneck is removed. Output has not decreased, it is just rising more slowly than capital expenditures. No point in completing wells if there is not pipeline space to move the oil, so they are building pads and other facilities and drilling wells, but waiting on completion.
So far this year Permian tight oil output has increased by 478 kb/d, an annual rate of increase of about 820 kb/d. The annual rate of increase from Jan 2017 to July 2018 has been about 829 kb/d.
Ignored says: 08/22/2018 AT 7:53 PMDennis Coyne
Output has not decreased, productivity has. There's a lot in that article. Yeah, DUCs are increasing for next year. Late next year. Conoco is the only company that I read about, that said we do not intend to expand much in the Permian, until they get the infrastructure in place (pipelines). They started running out of pipeline capacity the beginning of the year. I don't know about you, but if I was a CEO, I'd feel like an absolute idiot for not figuring that into the plans. So, for another year, they get to feed the DUCs.
Many a show and tell from the operators, is how they have brought down costs. Now, I have tell everyone that costs are higher than before. That will never go into an annual report, as it makes the CEO look like an idiot.
The companies are not making the production per well that was hyped. Er, maybe we should not include that in the annual report, either. That's what I got from the article.
You don't want people to say you wound up with egg on your face, so you tell them you have decorated your face with egg. It was your intent to look better. Spin.
Ignored says: 08/23/2018 AT 12:43 PMMike
I don't follow the dog and pony shows given by the oil companies, I just look at the data from the EIA, OPEC, and shaleprofile. I guess everyone interprets information differently, what I see in the article is that output has not risen as high as previously projected because fewer wells are being completed than was projected. It is also probably true that the average completed well has lower EUR than the ridiculous well profiles that are typically presented to investors, but I always dismiss those as hype and smart investors do the same and look up the information at drilling info, frac focus or shaleprofile.com.
The average well productivity in the Permian basin has not decreased, also no decrease in the North Dakota Bakken, or the Eagle Ford, or the Niobrara all based on Enno Peter's presentations at shaleprofile.com.
I also ignore the estimates by the EIA's drilling productivity report as I think that model is poorly done.
Ignored says: 08/22/2018 AT 8:13 PMMike
Dennis, respectfully, you need to stop whatever you are doing and go seek help immediately. In an effort to be the eternal optimist, or the staff contrarian, you are losing all credibility with regards to analyzing anything oily in the world. I have no charts, or I would stick them here.
Guy is basically right, there is nothing good to draw from this article whatsoever and the author is one of the best there is. All costs in the shale biz are significantly higher than EVER before. Well productivity is declining, not from takeaway restraints but from well interference, increasing GOR and depletion. Profitability has NOT improved thus far in 2018, the Permian unconventional oil industry is still outspending revenue and interest rates are on their way up, up, and up.
If anybody is spending $3.5MM to drill DUC's and not paying back debt, they too need to seek immediate help. You have become the King of Debt on POB and are discounting completely the role that debt will play in your lofty supply demand economic theories. Rune has just written something very good on that and Art has good data now regarding declining gasoline consumption in the US due to higher prices. That is all debt related, man. You have gone freaking chart bonkers.
And why argue what the KSA says about its reserves? Its their oil, they can say whatever they want to about it and no dumb ass American is going to change it. Right here in the good 'ol US of A, reserve reporting under the ever watchful eye of the SEC, is embarrassingly awful. Shale oil EURS are exaggerated by 30% or more. We now lie in America way better than the Saudis ever did and get this: a lot of people believe it !! Ahem.
Take two aspirin and call me in the morning.
Ignored says: 08/23/2018 AT 8:51 PM
Dennis, I have to work for a living but I don't want you to think I criticized you and don't have the balls to respond to all your hours of research arguing with me. I got it. And all the charts. And the models. And the criticism directed at others for guessing, which is all you EVER do. Have you ever seen the back in of a drilling rig in your life? You gotta balance about 500 oil well check books to even be allowed to analyze the oil industry, IMO.
Look, even the EIA seems to thing productivity is declining in the Permian. Goggle it. I get the full meaning of Enno's work, all of it, including this: "all shale oil wells drilled in America before January of 2016 now only account for 27% of total LTO production." Let that sink in a minute.
You embrace debt as thought that is an acceptable thing in the world we live in today, and especially from the shale oil industry, and though you want to be un-hinged from fossil fuels as much as any of the permanent residents you have on your blog, rational ones they are, one and all, you believe strongly in the shale oil industry's ability to pay down its debt, improve its dismal financial performance, and deliver the goods it has promised to America. Its very confusing, actually. And hypocritical. I guess when the shale oil industry says past performance is not indicative of future results, you believe them.
I think, really, all you are doing is defending your damn models.
This fella Cunningham is a smart cookie. Listen up: https://oilprice.com/Energy/Crude-Oil/US-Oil-Data-Has-Markets-Confused.html
Aug 26, 2018 | peakoilbarrel.com
Ignored says: 08/23/2018 AT 9:39 AM
I have some serious doubts about how much and how fast shale oil will grow over the next few years. I have accumulated no statistics, and have prepared no computations and charts to back up my doubts. However, they should be easily understood in theory, as that's all it is, a general theory.
While I know of no industry standards to define the difference between tier one, tier two, and tier three oil, I have made my own guesses based on operators statements. Tier one has EUR of 600k barrels, or more. It will produce over 200k in the first year. Tier two has EUR closer to 300k, and will produce 100k to 200k the first year, or an off the wall estimate of 150k. Tier three is probably closer to 150k EUR, and it's long term profitability is dependent on a very high oil price. It will be drilled, but only when price is high, and tier two is gone.
If you look at tier one, it can be drilled at today's prices, and income from the first year will fund one or more wells the next year with cash flow, hypothetically.
You would need about twice the number of tier two wells to equal a tier one. At present prices you would have to borrow money to fund the equivalent number next year.
We have a limited amount of tier one wells left in the Eagle Ford and Bakken. There is beginning to be some question as to the number of tier one spots in the Permian. Plus increasing GOR is raising questions.
As more wells are drilled, of course the price of the well increases. Simple micro supply/demand.
Interest rates will increase, causing borrowing costs to increase.
Even at $100 oil price, I can't see over a two million barrel a day increase in a short period of time (three to five years).
I could put numbers to this, but I could never reach what it actually would be, anyway. Do your own figures and see what you come up with. I just can't get to over 2 million barrels, and that would be tough.
I'm not saying that the estimates for recovery are wrong. I'm saying using past data to estimate the future does not take into consideration that all rock is not the same, and that costs and borrowing ability will put their own limits on how much, and how fast growth occurs. REPLY
Ignored says: 08/23/2018 AT 11:05 AMDennis Coyne
All very much guess work. There are factors such as improved well layout, better well design and so forth that tend to drive well cost for some "optimized" well design (a given lateral length, number of frac stages and pounds of proppant and other materials) lower that may offset the microeconomic tendency for costs to go up as constraints are reached (not enough workers, equipment, or infrastructure). That's the reason I assume for simplicity that long term well cost in constant dollars remained fixed.
I also have no idea on the numbers of tier one to three wells that potentially can be drilled. All I have used is average well output for ND Bakken, Eagle Ford, and Permian from shale profile. That is simply a mix of all wells producing. I assume oil companies attempt to drill the most prospective areas first (not an exact science) so that as the play is understood average new well EUR will gradually rise to some maximum (as oil companies figure out both the best areas to drill and the best well design) and then after some period (probably 2 to 3 years) the best areas will become saturated with wells so that less prospective areas will be drilled and new well EUR will gradually decrease. That is my model in a nutshell and the result for the US is that tight oil output may be able to rise from 6000 kb/d in July 2018 to about 8000 kb/d by July 2023 (about 5 years). This scenario assumes high oil prices and is optimistic, a "medium" oil price scenario would result in maybe a 1.5 Mb/d increase in tight oil output over 5 years and a "low oil price scenario" ($80/b in 2017$ maximum by 2025) might see only a 500 kb/d increase in tight oil output from 2018 to 2023.
Note that US tight oil output has risen by about 700 kb/d over the first 7 months of 2018. I do not believe this rate of increase will continue for much longer and will gradually decrease as we approach 2021.
Ignored says: 08/23/2018 AT 2:26 PMGuym
For the Permian basin specifically the peak is about 1 Mb/d lower for my "low oil price" scenario relative to the medium price scenario ($80/b vs $113/b max price). Other basins would also be affected, but I haven't run the scenarios on all tight oil basins so I am not sure how much the entire US tight oil peak would be affected, probably 1.5 Mb/d lower than the medium price scenario. For Rune Likvern's near term oil price scenario tight oil output would be fairly flat from current output levels in my opinion and that would tend to put upward pressure on oil prices.
Ignored says: 08/23/2018 AT 6:13 PMDennis Coyne
We have not had any difference of opinion on future shale output, in the last 6 months, according to my recollection. Any minor differences that may have been discussed fit into the "who knows" classification. My comment was for those "other" projections coming out, that basically are surreal. They have caused, in my opinion, an excess of pipelines being built, and massive expenditures to be able to export another 3 to four million barrels of oil a day that will probably never show up.
700k a day out of the Permian, is actually what I am projecting for 2018. Even 800k is within probability. 200k of extra pipeline is due sometime before year end. Not much more than that until late 2019 when bigger pipelines may be available. But the amount you could crank it up to would be limited by the number of months left in 2019.
Ignored says: 08/23/2018 AT 8:44 PMGuym
Agree 100%. Note that 700 kb/d is roughly my estimate for Permian increase in 2018 as well, for the US tight oil as a whole possibly 1000 to 1200 Kb/d increase in 2018. Many of the estimates are too high on that point we are definitely on the same page.
Ignored says: 08/23/2018 AT 9:36 PMGuym
What tight oil are you adding to the 700 to get 1000 to 1200????
Ignored says: 08/24/2018 AT 7:28 AMDennis Coyne
I mean, there are only four months left. I know the Eagle Ford can't do hardly anything in that time fraim, Bakken is stuck at a high of about a 100k increase, so what fields will add that much?
Ignored says: 08/24/2018 AT 10:47 AMGuym
From Bakken, Eagle Ford, Niobrara, and STACK/SCOOP.
So far non-Permian US tight oil has increased about 215 kb/d through the first 7 months of 2018, I would expect this to accelerate if anything as capital moves to other tight oil basins due to the low oil prices at Midland. So a 400 kb/d increase from other tight oil basins (exit rate for 2018), plus 700 kb/d from Permian basin would give us 1100 kb/d.
So far in 2018 we have increases of 92 kb/d in Bakken, 61 kb/d from Eagle Ford, 38 kb/d from Niobrara, 479 kb/d from Permian, and 24 kb/d from all other US tight oil plays.
If all output stopped increasing in other tight oil plays besides the Permian after July 2018 we would have a 915 kb/d increase in US tight oil output in 2018, if my guess of a 700 kb/d increase for the Permian basin tight oil output in 2018 is correct. My best guess remains 1100+/-100 kb/d for the US tight oil increase in output from Dec 2017 to Dec 2018.
I only have data through July 2018, so 5 months left for increases, if we extrapolate the rate of increase for the first 7 months of 2018 we get 1190 kb/d for the 2018 increase in tight oil output. I scale it back a bit because I expect Permian output increase will slow down. Other plays might also speed up.
Ignored says: 08/24/2018 AT 1:21 PMDennis coyne
Ok, your looking at EIAs production estimate per play, again. I'm only going to go by monthlies. There will be other field declines, besides tight oil. GOM, Alaska, and non tight oil Texas.
Ignored says: 08/24/2018 AT 7:51 PMshallow sand
Yes I was only talking about tight oil. I am not sure hoe much decline there will be elsewhere, haven't guessed.
Ignored says: 08/24/2018 AT 1:36 PMDennis coyne
Looking at rig count, drilling capital is not going to other US shale basins from PB.
Maybe you are seeing an increase in frac spreads in the basins to speed up completion of DUC wells?
Ignored says: 08/24/2018 AT 7:57 PMshallow sand
Haven't looked at rig counts lately so it's a guess. Just figure the capial may move to higher profit areas such as Bakken or Niobrara. Yes there are DUCs that could be completed. There may be more available frac crews in other plays as everyone has flocked to Permian.
Ignored says: 08/25/2018 AT 12:23 AMktoś
Look at YOY rig counts in the the post by Energy News.
Cana Woodford, EFS, DJ Niobrara and Bakken are down a combined 5 rigs from one year ago, while Permian is over 100 rigs above last year.
Ignored says: 08/23/2018 AT 8:28 PMEnergy News
In My Mind: https://www.youtube.com/watch?v=W9P_qUnMaFg
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Ignored says: 08/23/2018 AT 1:42 PMkolbeinh
2018-08-23 (Reuters) Production at Kazakhstan's Kashagan oilfield has dropped since mid-August, hit by a 35-day maintenance outage, the Kazakh Energy Ministry said in response to a Reuters query.
chart to the 22nd https://pbs.twimg.com/media/DlTiSCLWwAAvObc.jpg
Ignored says: 08/23/2018 AT 4:35 PMjohn keller
The Kashagan oilfield is proving to be a real nightmare for operators and partners. No wonder a decision was made to expand capacity for the land based Tengiz field. No similar call was made for Kashagan even if stated reserves are a bit higher than for Tengiz.
Ignored says: 08/24/2018 AT 12:48 PMGuym
Nickname is Cash All Gone
Ignored says: 08/24/2018 AT 7:11 AMkolbeinh
North Slope fracing? Conoco's decisions continue to impress me. Right or wrong, they are not in group think.
Ignored says: 08/24/2018 AT 8:50 AMGuym
It is a bit like offshore deepwater. If the size of a new prospect warrants it, the cost can be kept down reasonably. And the North Slope is probably one of the places it is possible to find another or even several gigant oil fields (above 500 million barrels). Just shows that some majors are betting on higher oil prices.
Ignored says: 08/25/2018 AT 9:02 AMEnergy News
Yeah, in the middle of nowhere with no infrastructure. Take a while. Purely exploratory at these prices.
Ignored says: 08/24/2018 AT 12:21 PMEnergy News
Baker Hughes US rig count, down -13 to 1,044 (-9 oil: -4 gas: 0 misc)
Ignored says: 08/24/2018 AT 3:45 PM
EIA Weekly U.S. Ending Stocks to Friday 17th August
Crude oil down -5.8 million barrels
Oil products up +1.5
Overall total, down -4.3 (shown on chart)
Natural Gas: Propane & NGPLs up +1.5 (not included in the chart)
A weekly measure of inventories