320 thoughts to “Open Thread Petroleum,October 20, 2019”

    1. That is not necessarily good news, supposed this could be true.
      What will happen with all the very expensive to execute EOR projects in the OPEC when oilprices go down to 10-20 dollar/b ?
      Apart from that it is not good news for climate change mitigation efforts.
      Anyhow, everlasting growth cannot continue without killing the earth ecosystems as we know it and killing human race in the process

    2. Ivan,

      Permian new well productivity normalized for lateral length has been declining since 2016, when not normalized productivity has been relatively flat from 2016 to 2018.

      The more likely scenario is that lateral length will stabilize at around 10,000 feet and new well productivity will start to gradually decrease starting in 2019.

      Chart below is for a Permian basin scenario with URR of 59 Gb. New well EUR average is 387 kbo in Dec 2018 and starts decreasing starting in Jan 2019. New well EUR on left hand axis and horizontal oil well completion rate on right hand vertical axis.

      On reading that paper, I would be considered a pessimist by the authors of that paper, who anticipate improved productivity based on technical papers they have reviewed.

      In my view the technical improvements, if they should actually materialize (far from a given, despite the optimistic projections of the authors of that paper) might at most delay the inevitable decline in productivity that will become evident as sweet spots become fully developed and oil companies need to move to less prospective areas where the average well will be less productive despite all the technology that can be thrown at the problem.

      The projection of 20 Mb/d from the Permian basin is beyond absurd. The Permian basin might reach 8.2 Mb/d in 2028 under a high completion scenario (about 900 new wells completed per month at the peak completion rate).

      In my opinion even that high an output from the Permian basin is relatively low probability, perhaps 10% at best.

      The chances of 20 Mb/d is a similar to the chances of winning a Powerball drawing, perhaps 1 in a billion or less.

      1. And the best thinkable technical improvements don’t increase URR. A cliché though still I mention it: the more rapidly it is extracted, the more early the (easy to extract (sweet spots)) oil is gone…forever

        1. Han,

          The TRR estimates are based on technology. For the Permian the F95 estimate is 43 Gb and the F5 estimate is 113 Gb with a mean estimate of 75 Gb.

          The peak is mostly determined by the completion rate. Technology improvements might allow more oil to be extracted from a given acre and could lead to the higher TRR estimates being correct. I doubt this will be the case, but I have been wrong in the past.

          I typically use the 75 Gb TRR estimate and a medium oil price scenario ($90/b max oil price in 2017$) the URR is typically about 59 Gb and a 7 Mb/d peak for a medium completion rate scenario (727 max completion rate in 2027). Also it is assumed new well EUR starts to decrease in Jan 2019 for my typical Permian scenario. In my opinion there is about a 50/50 chance the peak might be higher or lower than 7 Mb/d, that URR might be higher or lower than 60 Gb, or that the peak will be either before or after June 30, 2028.

      2. An alternative high completion scenario with completion rate rising to 919 new wells per month (from recent rates of 495 new wells per month) in 2027. It is also assumed that technology allows the current new well EUR to be maintained until Dec 2025 and new well EUR starts to decrease in Jan 2026 (the rate of decrease is faster than my standard scenario with EUR decrease beginning in 2019). A high oil price scenario from the EIA’s AEO 2018 is used with Brent prices rising to $219/b by 2043 (2017$). URR is 74.5 Gb and peak is 9188 kb/d in 2027.

        I do not think this scenario is likely (maybe a 1 in 10 or 1 in 20 chance that a scenario this high or higher might occur), just not the ridiculous 20 Mb/d scenario suggested by the Oxford Institute paper.

        One way to think of this is that there might be a 40% chance the URR might be higher than 74.5 Gb and perhaps a 30% chance the completion rate might be higher than the peak of the scenario I created and perhaps a 10% chance that oil prices might be higher than the AEO 2018 high scenario.

        The joint probablity of all of these would be 0.4 times 0.3 times 0.1 or a 1.2% probability that all three of these would be true.

        Note that the price is less important for the peak and more important for the tail after the peak (and affects the URR).

        So the better probability would be based on 0.4*0.3 or a 12% probability so roughly a 1 in 8 chance that a higher peak than the scenario presented might occur.

        1. Price is a function of liquidity. Prices can’t be bid up to $219 unless a truly massive amount of money is shifted away from other stuff like government debt, corporate debt, stocks, bonds and all sorts of other assets. Just isn’t going to happen. You could take the Saudi’s and Russia’s production completely offline. You’d get a price spike followed by a price crash. In the end price would be pretty close to where it started before taking all that production offline.

          Price isn’t marked or set by oil producers. It’s not marked or set at all by anyone. Liquidity is shifted into or out of oil in dollars. As long as FED balance sheet is expanding. Price of oil will rise. Without too much of a negative effect on other assets. As there is plenty of dollar liquidity sloshing around. So i expect as long as they continue expanding the balance sheet oil will have a slow but steady rise in price. Regardless of whatever the day to day news is regarding supply. But if supply does tighten along with FED’s action it will be very supportive of price. Right up until price goes too high for the economy to handle. Which is a guess as to what that price is but it sure as hell isn’t $219

          My best guess is anything over $75 will put the brakes on the economy. anything over $100 = almost immediate recession even with FED QE and huge government deficit spending. $219 even 20 years from now just isn’t realistic.

          When you realize that in 20 year the official US government debt will be $50-60 trillion not counting all the off balance sheet stuff. If in fact no grand reset of the monetary system hasn’t taken place yet. I don’t believe we have 20 years before that reset happens though. We get a reset all bets are off on what the price of anything will be.

          1. HHH

            World annual GDP growth has ranged from 2.5% to 3.1% since 2011.

            The annual average oil price from 2011-2018 has been both high (over $100 Brent) and low (under $50 Brent) during that time.

            Agree that Brent significantly over $100 causes problems.

            Don’t agree that Brent over $75 causes problems.

            I think Brent below $40 causes problems for the world economy more than Brent $75-$100.

            1. I agree. Low prices are worse for the global economy than high prices. But not immediately. It takes some time before low prices actually cause production to fall as we have seen in the last 5 years. When production does fall, that will cause a severe shock to the global economy which is why I have being saying for years that peak oil is a low price phenomenon, not a high price phenomenon.

            2. Shinzy,

              If the economy crashes you will be right.

              I am sure that eventually there will be a severe financial crisis, until that occurs oil prices are likely to be high. From 2023 to 2029 we will probably see Brent over $100/bo in 2018$. My guess for Great Depression 2 is a start date of 2030+/-1.

            4. “……peak oil is a low price phenomenon, not a high price phenomenon.“

              It is both

            5. No, it cannot possibly be both at the same time. At the time of maximum world oil production, it is far more likely that the price of oil would be low rather than high.

              Just use common sense. At the time of maximum world oil production, that would be far more likely to be at a time of an oil glut rather than a time of oil scarcity.

            6. Ron,
              right, not both at the same time. At world peak oilproduction oilprices will rise if the worldeconomy is strong with oil demand increasing yoy, because price is determined by supply and demand as clarified by you many times in the past. We saw that increase of prices 1,5 decade ago. That it later turned out not to have been peak production doesn’t matter, it could have been around peak production (if shale oil wouldn’t have appeared) and the result on price movement would have been the same.
              If at peak the world economy is not growing or worse, oilprices can/will drop.
              Apart from this very low oilprices result in serious OPEC cuts.

            7. Ron,

              An interesting perspective, I I agree it cannot be both, let’s say there was a peak plateau scenario for World output, I think that is your current thesis.

              Wouldn’t you expect that oil prices would rise as output remained on that plateau?

              It seems unlikely that oil prices would remain low if World output of C+C remained at 83 Mb/d from 2018 to 2025 (or whatever year you think the plateau might end), wouldn’t you agree?

            8. Yes, if oil remains on a plateau for a few years, then, of course, the price will rise. And I think a bumpy plateau is likely, but not for as many years as you indicate. And there is no guarantee that there will be a bumpy plateau.

              And if there is a plateau, the actual peak could be anywhere along that plateau. But the plateau will be the peak. That is if the actual peak is a few thousand barrels per day higher than when we first hit that plateau, that will make little difference. When production cannot keep up with demand then, for all practical purposes, that will be the peak, or nearly so anyway.

            9. Thanks Ron,

              For the sake of discussion, let’s say 2018 is the beginning of a bumpy plateau (however that might be defined, perhaps x+/-2% or roughly 84 +/-2 Mb/d).
              You suggest a plateau is unlikely to last for 7 years, what is your guess? Three or four years perhaps, so an end to the plateau in 2020 or 2021?

            10. Dennis, I would not put it that way at all. I would expect, that if we do have a bumpy plateau, it would last perhaps 4 years. So if it began in October 2018 then it should end by late 2022 or 2023 at the latest.

              I don’t think the plateau began before 2018 because before late 2018 the 12 month trend was up. I think when we are on a bumpy plateau the 12 month average will be relatively flat though the monthly production will be quite bumpy. Of course that is just a guess.

            11. Thanks Ron,

              Seems you said roughly the same thing as me (I suggested 2018-2021 or 4 years for a plateau, you suggested 2018 to 2023 at the latest), so I guess the difference is that my guess of your estimate may have been too pessimistic, which is a surprise.

              So you believe the plateau might be 4 years or more shorter than my guess (6 years for you, 2018-2023 and 10 years for me 2018-2027.)

              That is if we remain on a plateau, my best guess is a peak of 87 Mb/d in 2025, though if we defined a plateau as centered average 12 month output between 83 and 87 Mb/d, then my best guess (based on the definition of plateau above) is a plateau from 2018 to 2031 with output ranging from 82.51 to 87.49 Mb/d over that period.

              For my best guess scenario, average output over that 14 year bumpy plateau is 85 Mb/d.

              Output in Mb/d from 2018 to 2031 listed below using comma separators:
              82.85, 83.28, 83.91, 84.61, 85.31, 85.89, 86.29, 86.85, 86.64, 86.20, 85.61, 84.92, 84.10, 83.14

            12. What is the rough error of measurement/reporting for world oil production?
              A plateau should include at least that much leeway in its range, plus some extra for good measure (like the big guys do it).

            13. Hickory,

              I would say the World annual estimates are probably good to within about 200 kb/d, my proposed plateau uses 2% as a starting point and then I round to the nearest 1 Mb/d (1000 kb/d).

              So starting with a rough guess of 85 Mb/d for the mean of the plateau 2%=1.7 Mb/d, if we add the error as you suggest (0.2 Mb/d) we would get 1.9 Mb/d, I round to 2 Mb/d for good measure so 83 to 87 Mb/d for the bounds of a theoretical bumpy plateau and note that my focus is on the centered 12 month average of World C+C output, month to month fluctuations are of little importance in my view.

            14. A +/-2 Mb/d band sounds very reasonable, if you trust the supply numbers to be that accurate. I was thinking +/- 5%, but I don’t have my finger on the pulse like you do.

            15. Hickory,

              I was specifically referring to EIA estimates of C+C.

              From here

              https://www.eia.gov/beta/international/data/browser/#/?pa=00000000000000000000000000000000002&f=M&c=00000000000000000000000000000000000000000000000001&tl_id=5-M&vs=INTL.57-1-WORL-TBPD.M&cy=199401&vo=0&v=H&start=197301&end=201906

              The numbers may get revised a bit from time to time. When I compare the most recent estimate with one from 11 months ago, for the trailing 12 month output the biggest difference is 0.2% for the most recent estimate from 11 months ago trailing 12 month average ending in Aug 2018 compared to the most up to date estimate.

              The EIA does a pretty good job with monthly data estimates, they are not perfect, but about the best you will find publicly available.

            16. Dennis, did you notice that the World 12 month average turned negative in June?

              …………….May-19 Jun-19
              Production 81,736 81,711
              12 Mth Avg 83,114 83,065

              I have no doubt that when the December 2019 data comes in, the 12 month average will be well below the December 2018 average of 82,976 thousand barrels per day.

            17. Ron,

              Yes I had noticed that, and it is possible that 2019 could be less than 2018, perhaps the plateau might be 82-86 Mb/d, doubtful we will know for sure until some time in the future. I am confident we will see centered 12 month average World C+C output as reported by the EIA at more than 85 Mb/d between now and Dec 2028. Odds of 3 to 4.

            18. Shallow sand,

              Consider that real GDP grows at about 2.5% per year so from 2012 to 2043 would be 31 years. So real GDP grows to double the 2012 level by 2043.

              Even if output remained at 2012 level until 2043 which is not likely (output will be lower) 220 dollars per barrel in 2017$ would result in same percentage of spending in 2043 on c+c as in 2012, and in reality less because output will be lower.

              A gradual rise in prices may not be a problem, but transition to an economy that uses electricity for transportation will be a challenge no doubt.

            1. On liquidity, that will affect the overall price level (rate of inflation) as will the rate of growth of real GDP.

              The price of individual products (relative prices) will be determined by supply and demand for the products (this will be influenced by price inflation and economic growth, but it will also be affected by changing preferences and changing technology).

              Economics is far from straightforward, and controlled experiments are not possible. Also changes in knowledge will lead to changes in behavior as economic actors try to game the system which then changes the system and creates a new game.

              Difficult, does not really quite cover just how difficult political economics is in practice.

          3. Very well put HHH. It’s like supply and demand is real only it’s not consumer demand and oil supply, it’s investor demand and investment supply. How many dollars are chasing how many investment vehicles.

            1. Not quite.
              The net of all positions (and therefore P&L) in futures is zero. I can only be long an oil contract if somebody else is short one.
              There is a connection the physical markets but is very tenuous (because of hedging of physical production/consumption)

            2. wow, that blew my mind /sarc. it’s very simple to imagine one person offering one thing for a bid, and there being a million buyers. The inverse is equally easy to imagine – a million people offering things, and no one wants to buy. People buy options all the time that simply expire. companies have bond or derivative offerings that don’t get fully off loaded, despite brokers working the phones. there are numerous examples of positions with no takers.

            3. When there is a mismatch between supply/demand AT A PRICE no transaction occurs–> no derivative comes into existence.
              When you own an option that expires it is because somebody else sold an option and gets to keep the premium. Still, the net is zero.
              When a broker gets stuck with a (derivatives) position that they can’t offload the net is still zero, except that the counterparty now is the broker/dealer. The net is still zero.

            4. but the whole question is what determines the price of oil. classic supply/demand would say that oil supply and oil demand create price. but if dollars = demand, and the level of dollars (demand) is so massive, and so easily changed, then the amount of supply really doesn’t matter. if you create enough demand it will move the price of everything.

              the “it all nets to zero” statement (i’ve only heard it about 1000 times since 2008) adds nothing to that dynamic. its a pointless statement and I’m not sure why you brought it up.

            5. twocats,

              keep in mind that relative prices is the important number.

              Money supply can affect the general price level, supply and demand in individual markets will determine relative prices.

              I tend to think in terms of prices of oil in constant dollars so the rate of inflation and general price level are not part of the equation.

            6. i’ll give you an example – if you fat-fingered a bunch of zeroes into my bank account tonight, on monday, when it hit my account I would quit my job and begin buying up assets. depending on how many zeroes were in there it almost wouldn’t matter what the assets were, I would simply spread them around. would I buy oil, almost certainly. (and some counter-party bookie would take the other side of the bet, sure, whatever). but either way, the price of oil would have another bidder, and would help drive up the price.

            7. If you buy a futures contract, you haven’t bought oil. You’ve placed an order for future delivery, but you haven’t bought it until you take delivery. And…you don’t need oil, so you wouldn’t take delivery. So, you’d never actually buy the oil.

              The primary determinant of oil supply and demand is based on actual buyers, who are ready, willing and able to take delivery. That includes speculators who take delivery and place the oil into storage, but that requires having actual, physical storage, which isn’t all that cheap, and is somewhat limited.

            8. but nick, the issue at hand is what moves prices. when oil shot up to $147/barrel at the very end of the 2007/2008 crash (basically money fleeing the system trying to find a safe haven), that had absolutely zero, literally NOTHING to do with the physical market of oil. all you guys can say supply and demand, and futures contracts net to zero, and not real oil until you are blue in the face, but it doesn’t change the reality that non-reality issues drive oil price just as much, if not more than all the physical issues.

        2. The scenario presented below was an attempt to see if 20 Mb/d is reasonable for the Permian Basin. Short answer, it is not.

          I used the USGS F5 TRR estimate of 113 Gb as a starting point and a high completion scenario with about 359,000 total wells completed in a high oil price scenario. I use a more conservative oil price scenario with oil prices gradually rising to $90/b by 2027 and then remaining at that level until 2052 before declining to $40/b in 2062 (all oil prices in 2017$). When that “medium oil price” scenario is used 262,000 total wells are completed and the URR is 91 Gb (vs 113 Gb for high oil price scenario).

          The completion rate rises very quickly to 1640 new wells per month by October 2029 from 495 new wells per month in Sept 2019. I also assume the technological progress allows the average EUR of Permian basin wells to remain constant at the Dec 2018 level of 387 kbo through Dec 2029. In Jan 2030 it is assumed that new well EUR starts to decrease.

          Note that I think these assumptions are unrealistic, but I was attempting to see what might allow us to get close to 20 Mb/d output in the Permian basin.

          With these assumptions we get a scenario that reaches about 16,568 kb/d in 2031. Decline rates are very large in magnitude reaching annual rates of -31% in 2037.

          The 20 Mb/d estimate for the Permian basin is likely to be at least 2 times higher than what is likely to be achieved and very possibly almost 3 times higher than the most likely (7 Mb/d) peak output level.

      3. I just re-read that paper and realize that the optimistic scenario has about 12 Mb/d of C+C output, the 20 Mb/d estimate was C+C+NGL, with about 8 Mb/d of NGL output.

        The 12 Mb/d C+C output estimate is plausible with a high TRR scenario (perhaps a TRR of 100 Gb with a high oil price scenario would allow such an outcome). I remain skeptical of the 11%per year productivity increase, further productivity increases are unlikely, the best that is likely to be hoped for is that technological advances may be able to maintain the average new well productivity attained by the end of 2018. Higher output, such as 12 Mb/d will require very high oil completion rates and new well productivity to be maintained until the end of 2025.

  2. Last night posted late.

    Syria oil assay.

    API 38

    Very good oil. Diesel and jet fuel content 37%.

  3. Shale oil industry desperately needs cash and plans to issue shale bonds paying 6% pa

    Desperate for cash, shale companies are trying to court investors with a new and potentially risky financial instrument that resembles mortgage bonds.

    The companies are floating a type of asset-backed security that involves existing oil and gas wells. Producers transfer ownership interests in the wells to special entities that then issue bonds to be paid off by the output from the wells over time.

    https://www.wsj.com/articles/frackers-float-shale-bonds-as-traditional-investors-flee-11571606865

    1. Another article shale bonds
      https://seekingalpha.com/news/3507122-frackers-float-mortgage-bond-like-security-capital-needs-intensify

      Frackers float mortgage bond-like security as capital needs intensify
      Oct. 20, 2019 10:32 PM ET|About: Schlumberger Limited (SLB)|By: Douglas W. House, SA News Editor

      Desperate for cash, shale companies are banking their capital-raising hopes on a new type of financial instrument that resembles mortgage bonds.

      Specifically, it is an asset-back security involving existing oil and gas wells. Producers transfer ownership interests in the wells to special entities that, in turn, issue bonds to be paid off with output revenues over time. Current yields on the highest quality wells are almost 6%, but are higher on riskier assets.

      The first offering, by Raisa Energy LLC, closed last month. Several others will follow by year-end.
      A range of yield-seeking institutional investors have expressed interest but modeling future production is challenging due to the complex geology of shale basins and large variability between wells according to engineers.

      The Wall Street Journal previously reported that thousands of wells drilled in the past five years are less productive that forecast.

      Producers have burned through more than $100B since 2014. Existing investors have almost completely cut off the money faucet and banks are expected to lower their credit lines in the coming months.

  4. Dennis.

    Read the story in today’s WSJ about what happens if Warren is elected President.

    I was discussing this months ago and I believe you and others dismissed the threat Warren poses to the US oil industry, shale and offshore in particular.

    Apparently many investment firms are now pressing companies to disclose Federal acreage.

    I hope Warren’s energy people leave us alone. But I doubt it. I’m sure we will be renting an $80,000 infrared camera to prove our 3/4 BOPD oil wells aren’t emitting .3 MCFPD if she is elected.

    Her policy people need to become more nuanced on this issue.

    1. Hey, she’s all for renewables. That means about seven of ten contributors to this blog should be cheering her on. Of course, I love renewables as well but I fully realize they will never replace fossil fuels.

      At any rate anyone, absolutely anyone would be better than Trump.

    2. Shallow sand,

      The WSJ is generally pretty right wing.

      If she was selling apple pie, the WSJ would be convinced it was a commie plot. 😉

      She is trying to win the left wing of the DP if she wins she will move to center.

      I tend to agree she is not the most electable. I think a candidate from the middle of the country would be best.

      1. The WSJ article doesn’t read as an opinion piece.

        It notes that the public at large isn’t taking her fracking plans seriously, but shale boardrooms and investment firms are.

        Shale is effectively banned in NY, CA, IL and MD, all states that have shale oil/gas potential.

        It will be a court fight in the red energy producing states.

        But I think Warren means what she says.

        I am not bringing this up to advocate for any political party or position, just to point out I mentioned this awhile back, and now it seems the industry is taking notice as Warren moves up in the polls.

        1. Shallow sand,

          I think states should make these decisions, has been pretty standard for about 50 years at least, maybe 250 years.

          Fracking is not allowed in Illinois? Didn’t realize that, is there a lot of shale gas and tight oil potential in Illinois? I know that there is in NY, but I think the people of New York should make those decisions, just as the people of Pennsylvannia and Texas, and North Dakota should decide what is best in their states as long as pollution etc does not cross state borders. Once that becomes the case then states should bring a case to Federal court to decide how to proceed.

          I am not a lawyer, so I may have that wrong.

          1. Illinois has a very onerous law regarding high volume fracking. One permit has been issued under it, but it was withdrawn by the operator. The costs and requirements of operators are very steep.

            Illinois likely doesn’t have the best rock for fracking either, I have heard it is similar to Kansas, which turned out to be uneconomic at high oil prices of 2010-14.

            Maryland apparently has some far Western counties with shale gas potential similar to that found in West Virginia.

            This has been a state issue on private lands and state lands, and I agree it should remain that way.

            However, the US EPA could enact regulations which cause fracking to become cost prohibitive, just like it has attempted to do with methane emissions from stripper oil wells.

            1. Shallow sand,

              Where do those methane regulations stand? Were they changed during the Trump administration or simply not enforced?

              I imagine there were court cases holding up implementation.

            2. In late August, 2019, the Trump administration proposed eliminating them. Don’t think any final action has been taken. Surely environmental groups will challenge that in court.

              It can be difficult to get from the MSM where these rules stand. What I recall is that “new source” were subject to them under Obama administration and existing source were going to be, but it had not happened by the time Trump was sworn in.

              However, existing source were supposed to supply detailed info to US EPA, in preparation for monitoring. That info was going to take many hours to comply with, even though a lot of the information is already in the public domain and EPA could compile themselves (primarily well data). But likely US EPA is too understaffed to compile the data. Trump admin halted the data gathering requirement. EPA had sent out the data requests right at end of Obama admin to a limited number of operators.

              Also, a coalition of stripper well operators joined with the DOE to have a study performed as to the extent of methane emissions among stripper wells. From what I read, DOE was going to monitor at its expense many stripper wells of many operators who volunteered to participate on condition that data would not be used against operators for enforcement purposes in the future. Not sure if that study has been completed, seems the data collection process started this year.

              We feel many stripper oil wells will fall under the .3 MCFPD threshold established by US EPA. I think DOE was going to collect the data and try to determine if there should be a stripper well exemption to these rules (i.e whether methane emissions are really a big problem among stripper wells).

              As I have discussed, there was originally going to be a stripper well exception to these rules. The Obama administration had agreed to same after some study. However, environmental groups found some abandoned natural gas wells in the state of PA that they claimed were leaking unacceptable amounts of methane. Those groups were able to convince the Obama administration to eliminate the stripper well exception.

            3. Thanks for the info.

              Seems Obama administration handled that relatively fairly. Perhaps Biden would be the same.

              Seems EPA should pay for any monitoring.

        2. I just read the article. It suggests that Warren’s goal is to make fossil fuel investments less attractive. So if companies and investors are spooked now, they are doing exactly as she wishes. Therefore, flipping out over what she says now leads them where she wants them to go,

          “A spokes­woman for the War­ren cam­paign said that mo­ti­vat­ing in­vestors to move money from the oil-and-gas busi­ness is the aim.”

          1. Boomer. Shale has borrowed on a lot of PUD reserves. Those disappear if a fracking ban is enacted.

            If you owned stock in Hershey and a leading candidate proposed banning chocolate, you might decide to sell now, rather than waiting to see the result?

            1. What I am saying is that it isn’t a given that she will be elected or the ban will be passed. Yet here she is already getting what she wants.

              Her threat is freaking some people out. Should they be reacting now, when it may never come to pass? It’s up to them to handle their own actions.

            2. Pay back is a bitch, maybe the red states should have keep their religion out of her uterus.

            3. And our Red State friends would not get that extra cash from their Blue State friends.
              California’s 20% would stay in State– and a lot of F350’s would not be bought.
              Might need to walk to get a beer.

        3. I haven’t heard that California has any significant shale resource that is amenable to fracking.
          If it did, it would be the state that decides (like NY has so far) whether or not to allow it.
          We have a water issue here in this semiarid climate, and the vast majority of Californians would rather use the water elsewhere than on fracking. And then import oil form elsewhere, or use other forms of energy.
          The feds do control the offshore oil lease zones, as far as I understand.

          1. 4 crops use about 50% of the water in CA (Alfalfa, Cotton, Rice, Almonds). Domestic use is only 8-12%. Except for what CA gets from the Colorado, all water is in State.
            Having the 5th largest GDP on Earth (larger than the UK or France), those 4 crops are of little value, but you would probably need to quit eating almonds.

            1. Water for agric, domestic use, and for wildlife (salmon for example) is preferable to fracking with it, most Californians believe.
              Especially since fracking doesn’t doesn’t get you much with the geologic nature of the deposits out here.

            3. There’s a simple solution: start charging both farmers and oil companies for water, instead of giving it to them for free.

              If you charged half a penny per gallon, fracking would only need about 20 to 40 cents of water per barrel of fracked oil, which would have little impact when oil sells for $50-60 per barrel. But almonds need 1,900 gallons of water per pound, or about $8.50 of water, and almond production would drop sharply when they sell at $3 per pound wholesale! So, reduced farm production would free up more than enough water for oil.

              That’s a much more optimal allocation of resources.

              I think that reducing oil consumption (ideally through a tax and dividend program) is much more sensible than reducing production.

  5. HHH,

    Note that I expect the high AEO scenario is low probability, maybe 1 in 20 odds.

    The World economy may be able to handle $145/bo for Brent oil in 2018$ by 2029 if real GDP growth is 2.5% per year on average from 2012 to 2029.

    I agree $219/bo in 2018$ probably won’t happen it is a boundary case for a 95% confidence interval.

    1. HHH,

      This is what a high completion (918 wells per month maximum in 2027) med TRR (74 Gb) scenario would look like with the EIA’s AEO 2018 reference oil price scenario for Brent oil prices in 2017$ (see right axis of chart below for oil price scenario). The peak is 9168 kb/d in 2027 and URR is 65 Gb for this scenario. The scenario for new wells completed is identical to the earlier scenario through 2037 and then the completion rate is lower due to a lower oil price level making fewer new wells profitable to complete after 2037.

  7. Stocks up, Oil down, again.
    Even with the new pipelines I’m not sure whats really going on, EIA expect accelerated growth for the end of the year, also the rigs in the permian slighty increased and the september completions (in Texas) increased as well.
    But the weekly US frac spread marked a new low for the year -> https://twitter.com/primaryvision

    Also Schlumbergers quarterly earnings and comments didn’t paint a rosy picture of the US E&P market, but difference between S&P and the oilprice is widening, someone has to give ?

  9. Populism is sweeping the world. The president found the right buttons to push to drag to him quite a few white male voters in the critical three states who had voted for Obama. Elizabeth Warren does not seem to have her finger on the pulse of this voter attitude. Anti-fracking and anti oil is not populism.

    The Deep State concept is the focus of populism, and fracking just does not touch that button. I suppose an attempt could be made to declare Big Oil the manifestation of energy elite against whom to rebel, but that just does not speak to white men in Pennsylvania, Wisconsin, or Michigan. She is certainly trying to move leftward of the competition, and then would presumably sprint for the center, but her people’s sense of the center is absolutely not populism. Populism just doesn’t seem to connect to opposition to oil.

    If there were a black candidate who had some sort of a oil history then he or she could try to connect at least to black populism as her VP choice. But I just don’t see how the black community has any sort of emotional connection to anti-oil or anti-fracking.

    I don’t sense there to be any black candidates who could generate maximum turnout in the black communities as Obama did, so she will be hard-pressed to find a tactical VP choice.

    1. Anti-fracking is very close to anti-coal, which didn’t help Clinton in 2016. Some claim her anti-coal comments were her biggest gaffe.

      The entire issue is high paying blue collar jobs. Anti-fracking means ending many high paying blue collar jobs.

      Most blue collar people hope to find a high paying job they like and to be able to stick with it their entire career. Blue collar people tend to be less mobile, so if the factory, or coal mine, or refinery or oil field shuts down where they live, they aren’t as likely to just up and move.

      It is a hard sell to tell blue collar people making high wages, “I am going to end your job, but don’t worry, you will find as good or better job in the new Green Economy.” That is why Bernie is promising former fossil fuel workers FIVE YEARS pay and benefits while they look for a new job.

      When I post this here, I get the response about leather companies, carriage companies, etc. I’d like to see Warren try that one. Will sure get a lot of votes.

      I really think Warren will have even more trouble with all of the auto industry workers because there are more of them. Again, it would seem they should be fine, the auto plants should be able to be retrofitted to electric. But, again, it is that fear of the unknown.

      Think about the man or woman working on the line in an auto factory in the Midwest. Maybe union. Maybe not. But making $80,000+ per year plus some good benefits. They see Tesla line workers being pushed by Elon Musk to the brink, they see that wages for line workers at Tesla are lower than what they are making at GM, Ford, Toyota, etc.

      Getting rid of FF necessarily means eliminating millions of high paying Blue Collar jobs that will not be replaced immediately with comparable paying blue collar jobs.

      What Andrew Yang is proposing, universal basic income, is scaring the crap out of blue collar workers. Yang is telling blue collar workers directly that they will not be able to support themselves in the new, high tech economy, because they won’t have a good enough paying job.

      Are there people who post here who actually work in or at least know people who work in factories? The inability of some posters to grasp why the middle has turned so red is perplexing to me. Some posters here think the middle is full of bad people. It isn’t. It is full of people who are afraid of losing their jobs, and who are already seeing their towns shrink.

      Just saying things like, “that’s too bad” and “leather companies and carriage companies went out of business” and “that’s what you get for trying to control a woman’s vagina” are some very shallow comments. Saying that kind of crap will get the Donald a second term.

      Maybe be a little more thoughtful and a little less high and mighty?

      1. Shallow sand,

        The problem is that there are not easy answers to these problems. What is Trump proposing? Has he really saved factory jobs or has he simply claimed to have done so.

        I simply claim that peak oil is a reality (which will be obvious within the next 5 to 10 years). Pretending this is not the case doesn’t help anyone.

        Wishing it were 1950 or 1960, will not change much.

        Blue collar workers are pretty smart, it is amazing to me they believe Trump’s bullshit.

        You live in an area where lots of people work in factories or on farms, are there a lot of illegal immigrants in your area which lead people to believe that building a wall to keep out Mexicans and Central Americans is the solution to their problems?

        The Republican party is very much anti-union, are most of the factories in your area non-union.

        It really amazes me that Trump’s little hard hat and shovel routine (clearly the man has never used a shovel in his life) convinces any blue collar worker he is on their side.

        I am in complete agreement that banning fracking is a bad idea.

        How has the coal industry been doing during Trump’s reign?

      2. Tactics tend to beat policy, and when policy becomes tactics it’s hard to beat.

        The president went to the relevant locations and addressed the concerns of the people there. No one had been doing that. They proved to be friendly locations, and since campaign appearances generally are always in friendly locations, it becomes difficult for an Elizabeth Warren to go to the rural areas of those three states and try to connect to white males there with a message of anti-fracking.

        There is the further tactical reality that Michigan and Pennsylvania in particular are losing population, and they are losing it from their cities. The people who are living on multi-generational farms are not leaving to go to Texas. This is a tactical reality and it’s hard to see how any policy position can reverse it. Maybe if someone promoted rather than opposed climate change that would tell city voters in those states to stay put for warmer weather coming, but of course that’s not going to happen. Add to that exodus, an influx of fracking workers and you have a double impact tactically in favor of the President.

        Pennsylvania has gas fracking and opposing fracking is going to bleed a lot of votes in Northern Pennsylvania, but her handlers have reasoned she must to get nominated.
        Tactically speaking it is a horrible policy to embrace when you know you need those 20 electoral votes, nomination or not.

        It’s frequently quoted that some small number of votes spread among three states decided the election, usually in the tactical context of there being fewer black votes in 2016 than there had been in the previous two elections. I just don’t see a black candidate on the Democrat side that can change that. A black candidate who is not at the top of the ticket is not going to generate votes from Philadelphia by talking about fracking.

        Even worse, tactically, they have not recruited a black candidate from any of those three states who could deliver those EVs. A black fracking executive who is a mayor from some city in northern Pennsylvania would be a powerful asset as a VP selection, but . . . nope. Ditto Michigan. Or Wisconsin.

        The President has changed the landscape via populism. It greatly bothers the elite, and appeals to the non-elite. The opposition seems reluctant to accept this, and that is surprising given their rejection of traditional fundraising. This rejection leaves them fighting an uphill battle. I don’t think Warren’s people have quite accepted that the media is ignored. Sending reporters from New York City to spend 48 hours interviewing someone, probably a tenured professor or some other symbol of the elite, in Green Bay Wisconsin and then pretending that they understand what goes on there generates contempt.

        The state supported Trump. Not the GOP. The GOP elite is as much disliked as any other elite. The elite are interviewed and they are ignored. For the media to connect to fracking regions they will have to relocate their headquarters to North Dakota and employee only local reporters. They are going to be ignored otherwise and I don’t think the Warren people have grasped this fundamental, tactical change to the landscape.

        1. A universal ban against fracking really isn’t the way to go, even among the anti-fracking crowd.

          In Colorado, for example, what most want is local control. Let towns and counties determine what is allowable within their borders.

          I don’t see a lot of political traction for a complete ban. However limiting or banning fracking on federal lands is a reasonable topic for a national political candidate.

          Personally I wish the discussions about fossil fuels would focus on economics. It has been obvious for some time that coal is being replaced by natural gas and renewables, so it might be better to let it die its own death.

          Similarly the lack of profit with gas and oil will limit fracking. Let’s point out the history of booms and busts and how we need to be ready for the next bust.

          States like Texas and Colorado have economically diversified out of necessity.

      3. shallow sand,

        Much of the job losses in factories is due to automation. An auto factory or refinery simply requires fewer workers today to produce the same level of output, that is the problem in a nutshell.

        Where I live there have been a lot of job losses in the paper industry, not as much paper is used today because a lot more communication is done digitally.

        Things change over time, their are different viewpoints about whether those changes are good or bad, and often the changes are both good and bad simultaneously.

        Nothing is black or white, I see only shades of gray.

        1. Dennis.

          You are missing my point.

          Of course industries change over time.

          Obama was much smarter. He said things like, “We need everyone, we need all of the above regarding energy, we need to keep training everyone who works in energy as it changes over time.”

          Clinton in 2016 said, “We are going to close the coal mines.”

          Warren is saying in 2020, “We are going to close the coal mines AND shut down the oil fields.”

          I think you and I generally agree oil will be phased out over decades, not in a decade.

          So why threaten millions of workers with almost immediate job losses when you wouldn’t be able to accomplish that even if you really wanted to.

          I think people can accept job loss due to economic changes much easier than accepting job losses due to government intervention.

          That is my point.

          2. Now I am starting to understand why Trump can lie with no repercussions to his base. The Right can’t handle the truth.

            I guess some would prefer believing in a talking snake in a garden or a virgin delivering a baby in dealing with their life.

            Now this gives a new meaning to God bless America.

            Government sets the economic landscape.

            1. Our Constitution was made only for a moral and religious people. It is wholly inadequate to the government of any other.
              John Adams

            2. Adams was a one term president. He was followed by a died in the wool Deist.

            3. “It is impossible to rightly govern a nation without God and the Bible.” – George Washington

            4. No evidence George Washington said it’s ‘impossible to rightly govern without God and the Bible’

              Why people continue to attribute fake quotes to the Founding Fathers, we may never know.

              This time, a Facebook post claims that a quote about the Bible and governing came from none other than the first U.S. president, George Washington.

              The spurious quote attributed to Washington goes as follows: “It is impossible to rightly govern a nation without God and the Bible.”

              The post was flagged as part of Facebook’s efforts to combat false news and misinformation on its News Feed. (Read more about our partnership with Facebook.)

              You guessed it. There is no evidence to suggest that Washington ever said or wrote this.

              Why do Christians continue to just make up shit in a vain effort to support their declining religion?

            6. Wow, they got me on that quote…thanks Ron; will check sources closer. Even so, America was founded by God fearing men, the vast majority of whom were Christian.

            7. Roger,

              Christians should be compassionate. I’m afraid the Christians who are supporting conservative policies have lost sight of that.

            8. Even so, America was founded by God fearing men, the vast majority of whom were Christian.

              I am not so sure that is correct. What does it mean to be God fearing? Why should one fear God? Do you really believe most of the Founding Fathers feared God was going to punish them in hellfire if they did not worship him? I simply do not believe that. They were far too smart to believe such bullshit.

              Can you imagine the vanity of a man who believes an infinite being desires his approval? The desire to be worshipped is the vaniest of all human emotions and highly unbecoming of an infinite being.

            9. “What does it mean to be God fearing?”

              My definition — a reverence for our creator…and judge.

              “Even so, America was founded by God fearing men, the vast majority of whom were Christian.
              I am not so sure that is correct.”

              Well, I’ll take them at their word:
              “We hold these truths to be self-evident, that all men are created equal, that they are endowed by their Creator with certain unalienable Rights, …”
              Quite a few of them signed that document on 7/4/1776, at risk to their lives and fortune.

              “Without the benefits of modern science, they had a hard time imagining a world without a creator, but they had no interest in Christian fairy tales.”

              That’s nonsense, Christianity is pro-science; in fact, it’s the only cogent world view in my opinion.

            10. Christianity is pro-science

              That’s great!

              So, you’re fully on board with evolution and natural selection a la Darwin, and climate change as a very serious problem caused by humans?

            11. “What does it mean to be God fearing?”

              My definition — a reverence for our creator…and judge.

              Bullshit! Reverence has nothing to do with fear. Reverence for a being is the very opposite of fearing that being. God fearing means one is afraid his sins will get him into God’s torture chamber forever.

              “God fearing” means fear of hellfire. There is no evidence that our Founding Fathers even believed in hell. I doubt seriously that any of them believed that God loves them and unless they believed that this loving God would torture them in burning flames forever and ever.

            12. Not really. America is very much the brainchild of the Enlightenment, and they didn’t really believe in gods the way modern Jesus freaks do.

              For example, Jefferson famously edited the Bible to create the so-called Jefferson Bible. This is often used to show his Christian leanings. Actually he went through and cut out all the hocus pocus (walking on water, raising people from the dead and whatnot) in an attempt to find the original message of Jesus.

              He did the same thing with the Koran, to find the original message of Mohammed. That’s the Jefferson Koran. To him, it was pretty much the same idea. He (somewhat naively) reckoned they must have had something valuable to say.

              It’s also important to remember that they founding fathers were all radical anti- monarchist, and the monarchies of Europe had been justifying their existence by claiming a connection to god since the days of the Donation of Pepin or some time. So there was a lot of natural skepticism — I recommend reading Thomas Paine on the topic.

              Keep in mind that the post Napoleanic Holy Alliance of European monarchies was the sworn enemy of The United States. People have forgotten, but it was very much on the minds of Americans at the time.

              Another point is that unlike modern America, they hadn’t forgotten the lessons of the English Civil War, and all the other Wars of Religion that had devastated Europe during and after the Reformation. Disestablishmentarianism was high on the agenda, so they weren’t babbling on about the need to be Christian, whatever today’s megachurch grifters may claim.

              Without the benefits of modern science, they had a hard time imagining a world without a creator, but they had no interest in Christian fairy tales.

          3. Shallow sand,

            I agree, but maybe not completely.

            I agree the government shouldn’t shut down industries, but I also think without some government intervention we will be in deep shit when peak oil arrives in 2025.

            Despite the impression I give to the contrary, it will not be smooth sailing when the peak arrives.

            So something needs to be done to move the economy to alternatives to fossil fuel. It could be claimed that there should be no government intervention at all. I would point a free market true believer to the period from Oct 1929 to Feb 1933, to evaluate how well free markets work in practice.

            I suggested before the link below.

            https://citizensclimatelobby.org/basics-carbon-fee-dividend/

            To account for the cost of burning fossil fuels, we propose an initial fee of $15/metric ton on the CO2 equivalent emissions of fossil fuels, escalating by $10/metric ton each year, imposed upstream — as near as feasible to the mine, well, or port of entry.

            Accounting for the true cost of fossil fuel emissions not only creates a level-playing field for all sources of energy, but also informs consumers of the true cost comparison of various fuels when making purchase decisions.

            100% of the net fees from the carbon fee are held in a Carbon Fees Trust fund and returned directly to households as a monthly dividend.

            About two-thirds of Americans will receive more in Dividends than they will pay in higher prices. This feature will inject billions into the economy, protect family budgets, free households to make independent choices about their energy usage, spur innovation, and build aggregate demand for low-carbon products at the consumer level.

            Import fees on products imported from countries without a carbon fee, along with rebates to US industries exporting to those countries, will discourage businesses from relocating where they can emit more CO2 and motivate other countries to adopt similar carbon pricing policies. Building upon existing tax and trade systems will avoid complex new institutional arrangements.

            Firms seeking to escape higher energy costs will be discouraged from relocating to non-compliant nations (“leakage”), as their products will be subject to import fees.

            …

            Carbon Fee and Dividend does not increase the size of government, require new bureaucracies or directly increase government revenues. The dividend increases real disposable income, protects personal spending decisions and will recruit widespread, sustained engagement.

            Finally, Carbon Fee and Dividend is elegant in its simplicity, transparent in its accessibility to public scrutiny and clear in its signals and benefits.

            1. I’m afraid the real problem here is truth vs honesty.

              Trump, and Republicans, have been lying shamelessly to working people. They have no intention or ability to help working people. They may slow down the transition away from FF, but they’re working much harder to lower pay, accelerate automation and raise corporate profits.

              If people looked closely at Trump’s proposals during the campaign, it was clear that the most important stuff, both the tax stuff and the environmental, were both deeply bad. Voters should have known that Trump would deliver for the wealthy, not the working poor.

              But…you can’t blame voters too much. Trump did promise to help the working poor. He promised not to hurt disability, social security, Medicare, etc. He promised jobs, better pay and healthcare, lower taxes, etc. Voters knew it was a gamble to trust him, but they thought they had nothing to lose. Sadly, they’ve lost that gamble. He kept his promises to investors, and broke his promises to working people.

              So, the question raised by Shallow Sand is: Are Democrats sugarcoating things as much as they should? I’d say, probably not. But, the real question is more difficult, because Trump is willing to say anything. No promise, no lie is too big. That’s hard to compete with. So, the question is this:

              Should Democrats lie just as shamelessly as Republicans? Should they promise the moon? Should they tell voters whatever they want to hear? Or, should they tell the truth occasionally, and lose votes?

            2. NickG.

              Obama told the truth about US Energy more than Warren is now.

              He said we will need all of the above, knowing that fossil fuels need to be replaced, but that they cannot be eliminated by a flick of the switch.

              Many here want to harp on Trump’s lies and claim those voting for him all want to be lied to. Give me a break.

              I think most of the swing voters are growing very weary of Trump.

              So what are the Democrats going to do? Nominate a moderate candidate that has attainable energy plans? Ha!!

              In my lifetime the Democrats elected President have been Carter, Bill Clinton and Obama, all moderates who appealed to a broad cross section of the US. I don’t recall any of these three threatening millions of current jobs as a part of an energy plan that can’t be attained anyway.

              What I would really like to see is a candidate that will tell the truth. That fossil fuels will be used until they are no longer economic, that if and when they become uneconomic is uncertain, that we need to develop alternatives, but that for alternatives to be truly viable, they will need to be economic also.

              That fossil fuel workers need to be wary of economic and technological forces that could make their jobs go away, but if and when that will happen is uncertain. That because of this, young people in particular need to develop skills that are not just fossil fuel focused, but are transferable across a broad number of industries and types of energy.

              We have a divider in the White House. Direct me to the candidates on the D side that are unifying like Obama.

            3. I think there are several questions here:

              1 what’s the best energy policy? That’s a very big subject, so let’s leave that alone for the moment;
              2 what energy policy will best get a candidate elected? and
              3 what should a candidate say when in their best judgment and conscience those two things are different?

              For better or worse, I think you and I would agree that they have to say what people are ready to support and vote for, rather than what they really think.

              Obama is an interesting case: he identified what he thought the country was ready for, he promised that in the campaign, and then he pretty much did the same thing during his administration.

              I suspect that most people would want a president who did that.

              Finally, there’s another question: what does a candidate do when primary voters want something very different from general election voters? I think that’s the dilemma of the democratic candidates.

              I don’t know what the answer is to that.
              Any thoughts?

            5. Shallow sand,

              I agree. There are moderate candidates, I agree they are more likely to be elected. My guess is that candidate Obama was considerably further to the left than President Obama especially in 2008. Many thought he was not as electable as Clinton who was the favorite early on.

              My guess is that a President Warren would quickly realize all her “plans” don’t have a snowball’s chance in hell of being realized.

              In any case I agree 100% a fracking ban is not a smart idea, a carbon fee and dividend is a smarter proposal (it is unlikely even that can be accomplished, but a deal with rolling back selected EPA regulations as a trade for a carbon fee or perhaps using the carbon fees to either reduce taxes or to pay down the national debt is another possibility that might appeal to conservatives.

            6. Sadly, it’s hard to imagine what would make conservative media and politicians happy: they are focused on protecting their FF clients, and don’t care so much about economic principles.

              Carbon taxes are unacceptable to conservatives for the precise reason that they are simple and very effective at reducing FF consumption.

              Tax and dividend…same thing. A carbon tax that reduced other taxes…same thing.

            7. Nick,

              So you make a deal, conservatives want a wall between US and Mexico, liberals want a carbon fee and dividend so make a deal, it is the way our system of government was set up, to try to find compromises.

            8. That’s a great idea. I’m just a little pessimistic about it being an easy deal to make.

              It seems to me that things like the wall are just tactics – PR things intended to energize the base, and get votes. But, things like carbon taxes go to the fundamental economic interests of the money behind Republicans, especially the Koch’s.

              If there is 1,000GB of oil still to be produced, at $75 per barrel that’s $75 trillion dollars at stake. That’s a big incentive to fight to the death against any serious effort to keep FF in the ground.

            9. Shallow sand,

              Basically anyone but Sanders and Warren might be fine, there are some candidates that are not as far to the left as Sanders and Warren, Biden comes to mind, but there are others like Amy Klobuchar and Kamala Harris who are moderate. I think a candidate from the midwest might have a better chance of winning so Klobuchar may be a good choice.

            10. Dennis,
              The 1929-1933 depression was made much worse BECAUSE of government intervention. If they had let the depression to the free market it would have been much shorter in duration

            11. Doc Rich,

              No that is free market myth. There was very little government intervention from 1929 to 1933, the only reason government intervention did not work is that it was too timid, very high government expenditures during World War 2 ended the Great Depression, not the free market.

      4. HI SS,
        Every body in this forum today will be dead of old age a LONG time before we are able to transition away from oil and gas.

        The industry itself is on rock solid ground for a generation at the absolute least, considering depletion on one hand and population growth on the other, plus the quantity of existing machinery and still to be built machinery that runs on oil.

        But you have absolutely NAILED it when it comes to explaining why Trump is president, and HRC is not.

        “Maybe be a little more thoughtful and a little less high and mighty?”

        Between secret emails and her arrogance and taking the working class people of this country for granted, and actually being CONTEMPTUOUS of them, she shot her own feet off.

        All the most intelligent liberals I know are utterly convinced that Epstein was murdered, considering that he was the most prominent and important single prisoner in the entire federal prison system, and the SUPPOSED number of short comings in keeping an eye on him.

        And all the people I know who are conservatives, REGARDLESS of their IQ, believe that HRC wiped that server so as to hide the evidence of her dirty little secrets. And the fact that the Democrats as a whole stood behind her, and her and Bill when it came to abusing women SET THE STAGE for conservatives to abandon their principles and say it’s time to fight fire WITH fire, enabling THEM to justify in their own mind supporting Trump in the face of his own abuse of women.

        Hopefully who ever gets the D nomination this time around won’t be spending her time making secret speeches to Wall Streeters, because the working class people of this country sure as hell know when they are being taken for idiots, at least as THEY see it.

        And of course they were ignorant enough to vote for Trump, but at least Trump wasn’t so dumb as to insult them BEFORE he got elected, lol.

        Nixon is famous for saying in so many words that you have run as hard as you can to the right to get the nomination, and then as hard as you can to the center win the election.

        Hopefully the D nominee will remember and heed this observation.

        With social media these days, and computers, it ‘s hard to impossible to change the perception of the public about your past positions, if the opposition wants to hammer you for them.

        If I were Warren, I would walk as softly as possible on the anti oil rhetoric etc.

        This is not to say you might not have problems personally with regulations that may be passed on the federal or state level.

    1. Below is a comparison of data for Permian and Bakken 2016 wells, the “tl data” is used for the trendline fit.

      Data from

      https://shaleprofile.com/blog/

      specifically well quality data for 2016 wells from month 7 to month 31 are used for the trendlines on the semilog plot. The intersection of the trendline with the 10 bo/d output level is a rough approximation of EUR (it will be a little less than this due to exponential terminal decline over the final 12 years of the well’s life). Typically, the actual EUR will be 85 to 90% of the estimate using this method.

      For the 2016 Bakken average well we get an EUR=390 kbo and for the 2016 Permian average well EUR= 440 kbo.

      https://shaleprofile.com/2019/10/14/north-dakota-update-through-august-2019/

      and

      https://shaleprofile.com/2019/09/26/permian-update-through-june-2019/

      1. To anyone in the oil industry,

        Is estimated ultimate recovery (EUR), typically used to mean the same thing as cumulative output within the oil industry? For some reason, I thought EUR was used to indicate total output over the life of a well from first flow until the well is permanently abandoned, but I may have been mistaken.

        There are some who use EUR to mean cumulative output at any point in time since first flow of the well.

        If this is standard practice, it would be good to know.

        Thanks.

        1. Mr. Coyne, whatever answer you get here will not change the fact that on MY space you used a simple observation about Bakken wells being 20% better than Permian wells thru the summer of 2019 to engage in a 17 part dissertation on decline curve analysis, hyperbolic “fitting” and more wild ass guesses about the future that don’t mean shit. All it did was confuse people and muddy the water. It was all a damn mess that served no purpose whatsoever and ended up embarrassing me. I am unclear now whether I will ever get any casual observations out of Rune Likvern, or anyone else, to share with my readers again.

          I try and keep it light, and fun, and interesting at my place so people who don’t understand the oil industry, very much like yourself, will at least begin to appreciate it for its many tribulations, and most importantly, will begin to respect the people that risk their lives to work in it every day, around the clock, around the world. The real oil business is NOTHING like you “model” it.

          In the future if you need “relevance” as an oil analyst, please go somewhere else. Thank you.

          1. Hi Mike, I read your day in the life last night. What I got out of it is an unorganized business man that is in over his head, when he should be in the kid pool.

            I guess keeping it light is your option to sanity.

            1. Huntington, I use to like the left there in front of the pier… up until just a few years ago when I found a diaper floating in the line-up full of shit. Nice place you got there. Real friendly folks, too; some drug induced Cali-guy stole my Reefs. Imagine that! It must be the taxes out there.

              If you had read more of my blog you might have learned something about the oil business; there are some neat pieces in there about the Golden Lane of Mexico, about the most perfect oilfield in the world in Kuwait, not the KSA, about hard work and sacrifice, about how the oilfield really works. There are several pieces in there about my best friends getting burned to death in Syria in a big oil well fire; I think I wrote something about that little penche blowout in Huntington, I don’t remember. God has blessed me with a long and rich life, an amazing family of my own and employees that have been with me 40 years, also my family.

              You would have also seen that I am the most environmentally compliant oil producer you have ever even read about, that I believe in conservation of America’s hydrocarbons and controlling the rate of shale oil growth to better accommodate an easier, more realistic transition to renewable fuels in the future…when the time is right for ALL of America, not just you folks on the right and left coasts.

              You skipped over all that. I understand, and it’s OK. All you need to know, the only thing you would probably understand anyway, is that this “kid” could write a check for you and everything you’ve got without even having to call the bank before hand.

              Remember, DH; when you are pecking on plastic, you are relying on the oil and natural gas industry to do so.

          2. Mike,

            Sorry, I won’t comment at your blog in the future.

            It was a simple misunderstanding on my part as I understand EUR differently from you.

            I believe there is a distinction between cumulative output and EUR, it seems you use the terms interchangeably.

            I appreciate all I have learned from you and all that I have learned from Mr Likvern as well. You both seem to take any question asked of you as an insult when none is intended.

            For that reason no questions will be asked of either of you by me in the future.

            1. Yes indeed. It’s years and years of hand-waving analysis and heuristics, and then when we try to improve the situation with real quantitative statistics on the data that’s available, a few people get offended.

              The deal is that we do quantitative stats with models that are not opaque and thus can always be improved. It’s fun to see how far we can take them.

            2. Paul

              I have not studied your model in detail yet although I have your book. My excuse is old age. But, I would like to ask you how many parameters are entered as inputs into your model.

              The strength and weakness of the logistics model is that it has no adjustable parameters as the two included in the model are extrapolated from the past data.

              Now if one were to identify, in a thought experiment, all the factors that influence the time series of daily oil production, say N of them in which N is a suitably large number and then take the curve thus generated in an N-dimensional space and then project it to the two dimensional subspace of the Hubbert plane, then clearly the objection that Hubbert’s analysis is too simple, goes away, since the the N-dimensional curve has by definition all the available data (of course the accuracy of the data is a separate issue).

              best Seppo

            3. Thanks Seppo for your interest!

              The Hubbert logistic model is simple yes, and we did come up with one derivation for it in the book based on what we can simplify from a model for resource discovery. It does have to do with subdividing a large volume into N subvolumes, where N is large, and then applying a statistical distribution to subvolume sizes AND adding an extra factor that allows for an exponential rate of increase in searching these subvolumes. Described starting on page 85 in the book.

            4. Paul,

              My only question was how many input parameters does your method require? To which I now add the second question; what are they?

              The parameters that are estimated from the past data is secondary to my interest.

            5. Seppo, A more sophisticated model would include more parameters than the logistic. You are right that the logistic has only two — one for a cumulative and one for the shape width. What happens in the math for the logistic is that the geological (controlling dispersion of volumes) and technology terms (controlling search acceleration) reduce to a ratio so 2 parameters instead of 3 or more result. That’s also why the logistic is symmetric where other peak profiles will look asymmetric as the extra terms won’t collapse into a single value.

              I hope that answers your question

            6. Seppo
              A dispersive discovery model is fit to discovery data with some assumed URR, I use 2500, 2800, and 3100 Gb. HL gives about a 2600 to 3000 Gb estimate.
              For 2800 Gb URR use roughly 12 years for mean fallow, build, and maturation period.
              Extraction rates chosen at 5 to 12% to match model with historical data. Note Producing reserves are about 450 Gb in 2010 so model should match that fairly well. Future output determined by future extraction rates and chosen URR.

              see first shock model post at pob for details and book.

            7. Paul Pukite,

              I intended never to comment anymore here on POB, but as your comment also affects me, you obviously are in need of some real feedback.
              Admittedly there are some very good commenters on POB who had deserved something better.
              Paul, before you comment, you should have started out by reading the thread of DC’s comments over at oilystuff that lead to this.
              This would be a good exercise for you in getting the facts straight! Facts do matter, don’t they?
              Perhaps you would be so kind as to give some details of your background and your experiences from the oil/gas industry.

              The comments by Dennis Coyne (at oilystuff) were disorderly presented and were highly incomplete for any professional to make any meaningful evaluation of it. In the real world with QA audits and third-party verifications DC might (if lucky) have been given the opportunity for another round.
              One important parameter for EUR (and the E stands for Estimated) in shale oil wells are developments in primarily the GOR and developments in the gas/oil portion of the control volume together with primarily (reservoir) pressure and pressure drawdown. This becomes really important in the tail phase of shale oil wells and it is here it is very helpful to have some years of real experiences from the planning and operation of oil fields/wells.

              Such insight is something that requires great experiences (which takes years/decades working with relevant tasks within an operating oil/gas company to obtain) and talent for understanding (and modeling) complex nonlinear dynamics (think multiphase). For many this becomes a lifelong process that makes the experience, and the keyword here is process.

              Such insights/experiences are also difficult to share with others in a few sentences unless the receiver has it in his/hers DNA. And you get it into the DNA by working with real and relevant tasks. So it is a classic “Catch 22”.

              Oh, and reading about it on the internet will only scrape the surface to such an extent that if you are lucky you may solve the mystery of the oily spot in your garage or parking lot where your car normally is parked.

              DC did not make any attempts to make any such links over at oilystuff.
              So, when for starters it was asked for vital and missing information, DC ends up, after some time, drawing the victim card.

              What was DC’s intentions in the first place at oilystuff of posting comments that were not strictly related to the owner’s editorial policy and intentions of the article? and at the same time requesting something that de facto is nothing short of a QA audit/third-party verification from Mike and me?
              (Neither Mike and I provide such services on the internet or otherwise.)

              A real QA audit/third-party verification is a time consuming and costly process and it appears as Mr. Coyne got the naive idea, he could engage someone on the net and get it for free in the span of a few minutes.

              Yes, I started out (at oilystuff) and gave it an honest and professional try to assist DC, but when he started backtracking on what he first presented and supplemented that with bombarding the thread with more information and expanded the scope (far beyond the intentions and scope of the article) and before the first of his items/requests was properly processed, I simply could not take it (I do not have to as I assisted Mike for free!). (I am not saying his expansions were irrelevant in the right context. I am very busy and do not have the luxury to stay 24/7 on the internet and make myself available for free for anyone and I did not have the time available to give what DC requested and what I assess as required to give DC’s items/ requests needed attention/due process). The purpose of the said article at oilystuff was far from what DC perceived it to be.
              When I was in the (Norwegian) armed forces, we referred to such behavior as the one DC put on later when requested for more complete information as “adding a smoking blanket/screen”. (He may have intended/understood it otherwise)

              Mr. Coyne has apparently no experience from any industry that makes him understand the implications for others (time, resources, etc.) from what he is requesting.

              If Mr. Coyne is serious and wants a third-party verification of his work and as he apparently is not satisfied with Mike’s and mine recent limited free responses at oilystuff, he should engage an engineering firm/consultancy that specializes in such.

              The relevant background for me who says this is from several major international oil companies (operators, also in the US) for decades and in various positions (both technical and commercial) along the oil/gas value chain and me have also for years worked extensively with other highly educated (MSc and PhD entry-level (I hold an MSc)) widely experienced and highly competent involved in using advanced mathematical and statistical methods, models and tools (later also economical modelling, tools and methods) and knows the ins and outs of such audits and verifications from being subject to such.
              Again, it is the process that is important as nothing in the oil industry (or the real world for that matter) is settled by presenting some curve fitting from some flawed assumptions into an oversimplified spreadsheet.
              My life long experiences (also from personal administration and something that amounts to about 20 years in the armed forces, not full time ) have also made me proficient in recognizing incompetent persons and to avoid any dealings with them (unless strictly necessary from professional reasons).

              From what I have learned Mr. Coyne holds an MBA, but few know anything about his professional experiences/credentials.

              Mr. Pukite do you know understand why I find your comment offensive?
              Based on previous experience with you I will provide you the answer for free; “because you have no idea about the background of the people you refer to and what you are talking about”.

              This is the same Pukite I a short while ago on POB requested documentation from to support his claims (about oil price affordability issues). So far and to my knowledge, he has not produced any.

              And a last word for Dennis Coyne, I have for years requested you (and in the public domain I will spare you the real reasons why) not to engage me (because it is a waste of my time) and I also had to take it so far as forwarding you a “cease and desist” mail.

              This time I sincerely hope DC keeps what he promises.

            8. LOL, you’re welcome! Comments are always welcome on the blogs as that’s part of the deal.

              BTW, Thanks for coining the term The Red Queen Effect to describe the fast depletion of shale plays.

            9. Mr Likvern,

              I appreciate your work and all I have learned from you.

              I am sorry for having wasted your time, the source of my confusion was the unusual use of the term EUR (which stands for estimated ultimate recovery).

              In every other context I have seen this term used, it has referred to cumulative output over the entire life of a well from first flow until the well is permanently abandoned.

              When I read the post at Mr. Shellman’s blog EUR was the term used when the meaning was cumulative output. It seems both you an Mike understand these terms as synonyms, where I have never seen that usage.

              I asked if there were any other oil industry professionals who have seen that usage for EUR, where it is used as a synonym for cumulative output. You have said you stand by that usage, Mr Shellman has not commented one way or the other, but it is his blog so I assume he agrees with that usage.

              The paper below discusses estimation of EUR, I use the hyperbolic with exponential terminal decline of 12.5% as in many cases the data I have access to is quite limited. Mr Likvern may not approve of these methods, but many authors have used this approach.

              https://link.springer.com/article/10.1007/s11053-016-9323-2

              link below to spreadsheet for average 2015 Permian basin well, terminal exponential decline at an annual rate of 12.5% per year starting in month 76 at 35 bo/d, well is assumed to reach economic limits at 5 bo/d at 251 months after first flow (21 years). EUR=298 kbo.

            10. It’s a bit like the distinction between a sample mean and a population mean. What is of interest is the actual EUR, which is truly unknown until the resource is exhausted or abandoned. But until that time, we can use the cumulative as a sample representative of the EUR, and use techniques that Dennis is using such as ARP hyperbolic to extrapolate what the EUR is.

              This is just applied math and I really don’t understand why these two are getting so upset about such innocuous discussions.

            11. There are 2 approaches to EUR (estimated ultimate recovery) of wells.

              One is relative simple: It’s determinining the mean EUR of a whole field. You take statistical data, make a timeline, some fits and some assumptions about technology changes. That’s all basic statistics, taking the right fit methods, having enough samples and executing them flawless.

              The other one is much more complicated and needs an experienced oil expert.

              It’s about forecasting how much oil this single well will give.
              First when you have only the geological prints and have to decide if you drill at all. Then after drilling to decide if the well will stay a DUC and at last after a few monthts of production if the well can give the money back.

              Here are oil experts needed that know the business and the oil field – not even an oil man from Alaska can do this in Texas, or the other way round.

            12. Dennis, can you be specfic about where in the text of subject article the confusion you refer to stem from?

              Could it be this;
              Based on data, as of summer 2019, it was found that the average Permian well, spanning several vintages, has a EUR (LTO) of about 80% of the average Bakken well.

              That text does not refer to the chart, but my estimates of the EUR for Bakken and Permian for several vintages. This work is not published…yet.

              Dennis, to me it appears that you invent problems where there is none.

              What constitutes a good well is subject to evaluation of several parameters, also economic ones.

              Paul Pukite appears to be the go to expert you should discuss your estimates with.

            13. Rune,

              Not really possible to communicate with you.

              Any question is taken as an insult and then insults are thrown back at me, so I will refrain from any further discussion with you.

              Thanks.

            14. Thanks Eulenspiegel,

              I attempt to do the first EUR estimate that you describe. Then economic analysis is applied to see if the well might be profitable to complete by looking at the net present value of future cash flows at a typical annual discount rate. It is pretty standard stuff.

            16. I always thought that EUR was an initial estimate of the final production and that the cumulative was the actual for a specific well(s). Next, by applying Bayesian updates, better estimates of EUR can be made by incorporating knowledge of the ongoing cumulative.

              So there is a difference. Having two EUR’s not agree is not the same as having the actual cumulatives not agree, since the EUR’s could be SWAGs in the first place.

              We don’t necessarily have to be experts in the oil business to do this since it’s just careful bean-counting statistics when it comes down to it.

            17. Paul,

              A strange experience trying to communicate with those folks. In some cases they seem to claim they were only talking about cumulative output as they were harping on actual data and claiming that EUR had nothing to do with the post ( though it seemed they were saying that cumulative output was synonymous with EUR), turns out they actually were talking about EUR and that the average Permian well for several vintages (without specification) has an EUR that is about 80% of the average Bakken well. My comments were simply to suggest that may be incorrect based on my analysis, the Bakken wells from 2018 may be 20% better than 2018 Permian wells, the data for Bakken 2018 wells so far is a bit unusual relative to older wells (2008 to 2015) and I do not think a good estimate can be made at this point with the limited data I have available, Mike and Rune may have access to more extensive data.

              I expect the average 2017 Permian well is likely to have an EUR of 390 kbo at $62/bo at wellhead and $1.50/MCF for natural gas at wellhead (includes any income from NGL). The Average 2018 Permian well is likely to be similar based on the data to date.

              The average 2017 Bakken well at a similar price level (the equivalent wellhead price for the Bakken would be about $57/bo as transport cost is higher in the Bakken than the Permian basin) would have an EUR of about 398 kbo.

              That is higher than the Permian but not 25% higher as a claim that the average Permian well has an EUR that is 80% of the average Bakken well would imply (1/0.8=1.25). In this case we have 398/390=1.02.

              No record of the conversation exists as the comments were deleted.

          3. Mike,

            Interesting that I thought I misunderstood how Rune (or you) uses the term EUR and that the point was that I was talking about EUR when you guys were not. In Mr. Likvern’s comment at link below

            http://peakoilbarrel.com/open-thread-petroleumoctober-20-2019/#comment-690596

            he says he was indeed talking about his estimates of EUR.

            “Based on data, as of summer 2019, it was found that the average Permian well, spanning several vintages, has a EUR (LTO) of about 80% of the average Bakken well.

            That text does not refer to the chart, but my estimates of the EUR for Bakken and Permian for several vintages. …”

            I was simply making him aware that I get a different result, no insult was intended and I thought I was pretty respectful compared to the comments by Mr. Likvern, though perhaps when someone says “thank you” that means they can proceed to throw insults.

  11. GS predicting US growth of 700 kb/d in 2020 down from 1000 kb/d.

    https://www.spglobal.com/platts/en/market-insights/latest-news/oil/102219-goldman-sachs-lowers-2020-us-oil-growth-outlook

    Goldman Sachs lowers 2020 US oil growth outlook

    Washington — Permian oil will account for an increasingly larger percentage of non-OPEC supply growth through 2022, even while US shale oil growth appears to be decelerating, Goldman Sachs said in a report this week.

    “Shale growth is slowing,” the report states.

    Overall US oil growth, after rising 1.7 million b/d in 2018, will grow by 1.1 million b/d this year and by 700,000 b/d in 2020, according to Goldman Sachs’ forecast. The 2020 growth forecast is down 300,000 b/d from the investment bank’s previous 1 million b/d growth estimate.

    The expected drop would be due to lower shale activity and a possible uptick in the decline rates in oil fields, Goldman Sachs said in the paper, released late Monday.

    “Initial 2019 productivity data suggests that shale productivity improvements appear to be decelerating across key US oil shale plays and deteriorating in the Eagle Ford Shale,” the company said. “We believe this is broadly in-line with producer commentary that there is still scope for well performance to continue to improve, though likely at a more modest pace relative to the step-changes seen in years past.”

    In its Drilling Productivity Report last week, the US Energy Information Administration said it expects US shale oil output to average more than 8.97 million b/d in November, up 1.14 million from November 2018, nearly 980,000 b/d of that growth taking place in the Permian.

    The EIA data showed shale growth clearly slowing, after growing nearly 1.6 million b/d to November 2017 from November 2016, and about 1.75 million to November 2018 from November 2017.

    S&P Global Platts Analytics forecast total US oil and condensate output to average nearly 12.22 million b/d this year, up from nearly 10.98 million b/d in 2018. Platts Analytics forecast US oil and condensate production to rise to 13.36 million b/d in 2020 and average nearly 14 million b/d in 2021.

    Goldman Sachs forecast oil output in the Permian to grow by 800,000 b/d this year, accounting for 42% of non-OPEC oil output growth.

    While the company sees Permian output declining to 600,000 b/d in 2020, and then 500,000 b/d in both 2021 and 2022, within three years the Permian while account for 116% of all non-OPEC oil output growth as oil production in non-OPEC countries outside the US is forecast to fall by 800,000 b/d.

    1. Hi Ovi,

      GS states the huge importance of future Permian oil production: “Permian to account for 116% of all non-OPEC oil growth in 2022.”

      GS US growth forecast of 0f 0.7 mbd for 2020, from 2019, equals my growth forecast for all 7 US shale regions, includes non shale oil production. I wonder if GS reads peakoilbarrel.com?

      My forecast below estimates 8.6 mbd from 7 US shales regions in 2019, increasing by 0.7 mbd to 9.3 mbd in 2020.

      Key factors for decreasing shale oil production are poor investor returns and low oil prices. If the US shale oil industry cannot raise the money to drill new wells then production must decline. Evidence of difficulties of raising money is shown by this desperate form of shale bond financing:

      “Not surprisingly, traditional financing has dried up as once-burned banks and junk bond buyers balk at second helpings. So frackers are turning to … wait for it … asset backed securities similar to the subprime mortgage bonds of the 2000s.”
      https://www.dollarcollapse.com/treasure-trash/

      “Securitizing wells may be one of the few sources of new money available to producers, said Jonathan Ayre, a partner at law firm Orrick Herrington & Sutcliffe LLP. It The firm is working with Guggenheim Securities, which also structured Raisa’s offering, on a similar securitization.”

      1. That’s a ridiculously bad idea. Mortgage backed securities were supposed to work (and do if used correctly) because the income stream of payments is backed by the lien on the asset (house). No pay = foreclosure. These failed in the financial crisis because foreclosure became undesirable due to houses losing value.

        If the income stream doesn’t pay off in fracking there isn’t anything to take. You want the declining well?

        1. And similar to housing foreclosure where cities or mortgage service providers start racking up maintenance fees – grass cuts etc, won’t these Wells have retirement costs – capping etc?

        2. Yeah, in case of a BK of the lender, you get a old well which has already produced 90%, not knowing if the stripper costs are worth the effort an YOU have to take care on the pluggin costs.

          Sounds like a good idea 😉 or some variation of the greater fool principle …

          1. I think – but may very will be incorrect – that it is a little different from mortgage finance.
            I believe that the periodic cashflow would be securitized, not the asset.
            Rgds
            WeekendPeak

      2. Tony

        I hope that you are correct in that this site is viewed by GS and others and that GS possibly used other sources to confirm your numbers. Hopefully within 2 to 3 yrs from now we will have helped make the world aware of the dual threats of CC and Peak Oil and that a path forward will evolve.

        WRT your model. Is it a bottoms up model similar to Dennis’ or do you have some other methodology. I have posted a curve fit of the STEO numbers in previous threads that show US production peaking in mid-2021.

        This morning’s EIA wkly numbers also look interesting. See Below.

        1. Ovi,

          My model is not bottom up. I use EIA DPR data to calculate historical production from new wells. Next I do a linear extrapolation for both production from new wells and legacy decline. I realise that these are not valid assumptions for the long term but I think there is some validity for the short term. That’s why I am only forecasting to Dec 2022.

          The dashed red line in the chart below is my best guess at a trend line for production from new wells. Declining DUCs tend to correlate with a slowdown of production from new wells. DUCs from the five main oil producing shale regions have dropped by 400 since early 2019.
          https://www.eia.gov/petroleum/drilling/#tabs-summary-3

          1. Ovi,

            The correlation between oil production and DUCs since Jan 2014 is a high 0.94. This correlation is for the five crude oil regions as in the chart below. The recent divergence between DUCs and oil production since May 2019 is questionable.

      3. My scenario for comparison, but note that unlike the DPR conventional output from the tight oil regions is not included in my estimate, for comparison to Mr. Eriksen’s estimate about 1000 kb/d would need to be added to my estimate in August 2019. <y scenario peaks in 2026 at about 12 Mb/d, URR for US tight oil for that scenario is 94 Gb. The AEO 2018 reference oil price scenario is used for this scenario. In reality future prices are not known. Lower oil prices would result in a lower peak, about 10 Mb/d for a $75/bo maximum oil price and perhaps a bit earlier peak (2024 or 2025).

        1. Note that my estimate is pretty close to Mr. Eriksen’s through Jan 2021, if we assume conventional output remains about 935 kb/d from the shale regions (average difference between DPR and EIA tight oil estimates by play from Oct 2018 to Sept 2019) in the future. In Jan 2021 (reading from his chart) Tony’s estimate is about 9.5 Mb/d and my scenario is about 9.7 Mb/d. This scenario has been modified from earlier and includes the conventional output from shale regions and assumes after Sept 2019 conventional output from the shale regions remains 935 kb/d. Peak is in 2025 at 10.7 Mb/d.

          Essentially all of the increase in tight oil output in the US comes from the Permian basin in this scenario after Jan 2020, other basins (as a group) begin to fall in output after 2021.

          The completion rate for the Permian basin in this scenario increases from 495 new wells per month in Aug 2019 to 595 new wells per month in Jan 2021 and then hold steady at that level until 2036 and then decrease. It is assumed that new well EUR (over the entire life of the well) remains at the Dec 2018 level of about 380 kbo until Dec 2025, after that EUR decreases. The Mean USGS TRR is assumed (75 Gb) for the Permian basin (and all other basins that have a recent estimate) and URR is 90 Gb for all US tight oil basins (62 Gb for the Permian basin). The EIA AEO Reference oil price scenario is used (maximum oil price of $113/b for Brent in 2017$ in 2050).

          The scenario is pretty conservative in most respects, the one optimistic change is the assumption that new well EUR does not decrease from 2019 to 2025, in earlier scenarios I have assumed that new well EUR starts to decrease in Jan 2019, so far there is no evidence of significant decrease in Permian basin new well EUR, though the rate of increase in EUR has been very slow from 2016 to 2018 based on the limited data we have. Some of that increase may have been related to increased lateral length or proppant use.

  15. Attached is this mornings EIA weekly production chart for the L48. They are unchanged for the past three weeks. Looking at the growth from Jan to May, it is 500 kb/d. From May to October, the growth is 200 kb/d over almost the same time period. There is a hint of slowing in these numbers. However I must add a caution. In previous years, Nov and Dec have seen big increases. There is also the question of the value of the guesstimates in the weekly data.

    Isn’t it great that we always have interesting future data to look forward to.

  18. I’ve been doing a little back of the envelope calculation using frac spreads, monthly declines from the drilling productivity report, and EIA monthly production (lower 48 onshore). Monthly decline in the third quarter is at 556,000 bpd. New production comes to average around 1336 bbl per spread, there is variability in this.

    I came up with around 415 frac spreads to maintain current production. According to primary focus spreads dropped to 405 on 8/23/19. There is a lag of around 2 months from frac to completion, so we should be roughly entering a decline for lower 48 onshore.

    There are only 363 spreads working on the last report.

    1. dclonghorn

      I am not familiar with the meaning of Spread. What is 1336 barrels per spread?

      1. Ovi,

        A frac spread is a fleet of equipment required to do fracking.
        https://www.fracspreadcount.com/learn

        Frac spread counts have been falling which explains why fracking service companies have been reducing staff numbers.

        The IEA OMR October 11 report said that: “Pure-play shale producers and independents had already flagged a 6% decline in upstream spending this year in their initial 2019 guidance. Operators shed another 29 rigs during September so that by end-month, there were 172 fewer active rigs than at end-2018. The frac spread count has declined 23% since March, to a 2.5-year low.”
        https://www.investingdaily.com/51981/faded-glory-will-the-u-s-shale-boom-go-bust/

        The decreasing rig and frac spread counts probably explain the decrease in DUCs by about 400, from May 2019 to today.

        dclonghorn says that there are 363 frac spreads working which is equivalent to new production of 485kbd (363*1336) which is less than current monthly decline of 556 kbd.

        That means that dclonghorn, you and me are probably predicting a US oil peak on or before 2021.

        1. I think the talk will change from “declining rates of production increases” to “declining production”. At least as far as lower 48 land goes. Because of the lags from frac to completion, and from production to actual recorded production, it may be awhile before the numbers start to show declines, but yes I think they are coming.

          Patterson came out with their third Q report today. They have massive write-offs for impairments. They bit the accounting bullet and “retired” 36 rigs and 300,000 frack horsepower. Rig counts and spreads continue to fall. They had 14 spreads at end of quarter and another idled so far in Q4. They expect activity levels to stabilize near current.

          1. Perhaps we are missing increased efficiency from working rigs and frac spreads. Do we know the combined horsepower of the frac fleet or the rigs?

            There are differences in the equipment that is running. The number I focus on is the tight oil output. That has continued to increase despite the fall in rig count and frac spreads.

            Seems to me the death of tight oil is greatly exaggerated. 🙂

            1. Perhaps we are missing increased efficiency from working rigs and frac spreads.

              Dennis, that is a far too simplistic explanation. Is there any evidence that efficiency from rigs and spreads have increased over the last 12 months? And by that much?

              From Tony’s link:
              “Pure-play shale producers and independents had already flagged a 6% decline in upstream spending this year in their initial 2019 guidance. Operators shed another 29 rigs during September so that by end-month, there were 172 fewer active rigs than at end-2018. The frac spread count has declined 23% since March, to a 2.5-year low.”

              I would say that what you are seeing now can more accurately be described as lag time. I think you can expect shale decline a lot more sooner than most seem to believe.

            2. Ron,

              We will have to wait to see. I think the rate of increase in tight oil output has slowed and will continue to do so, but unless there is a steep drop in the price of oil or a major Worldwide recession (or both), I doubt the level of tight oil output will decrease before 2024-2026, with my best guess remaining at 2025.

              Hey we have both been wrong in the past, and the future is likely to repeat. 🙂

              Ron the evidence is the falling rig count and frac spreads coupled with increasing output. These counts have been falling since Jan 2019, how long do you think the lag is?

            3. Dennis, the increase has been slowing down, and in some months, slowing down quite dramatically. But production is still rising, but much slower. That is the lag.

              At any rate, see my post below “The Permian Basin is facing its biggest threat yet”. I have a link to that article.

            4. Ron,

              I agree the rate of increase has been slowing, I just don’t think we will see the completion rate decrease (rate of increase in completions become negative.) Until perhaps 2025 or so.

            5. Dennis, If this is the case:

              The frac spread count has declined 23% since March, to a 2.5-year low.

              Then it would be impossible for completions to remain constant. It would violate the laws of physics. Well, that is unless the fracking crews work 23% faster. And I just don’t think that is going to happen.

            6. Ron,

              Perhaps that is correct, so far in the Permian basin completions have remained steady through Sept, if my assumption that the average productivity has remained relatively steady and the EIA tight oil estimates by play are roughly correct.

              Based on dclonghorn’s estimate there is about a two month lag between frac spread counts and actual well completions so the numbers for July in the Permian would give us an idea of the number of spreads needed to keep output growing.

              Also for the Permian basin completions would need to fall by more than 20% to lead to a decrease in Permian basin output.
              Scenario below has completion rate decrease from 495 completions per month to 395 completions per month and then completions remain at 395 per month through 2030, decrease in completion rate by 10 per month to get from 495 to 395.
              A small decrease in output (17 kb/d) occurs in 2020 in this scenario, then output continues to increase by 373 kb/d above near term peak in early 2020, peak output is 4335 kb/d in 2028 for this very conservative scenario.

            7. Completions decline by 10 per month until they are down by another 100 per month? But production continues to increase? And production from the sweet spots never seems to decline? Like the Energizer Bunny, they just keep on giving, and giving, and giving?

              A small decrease in output (17 kb/d) occurs in 2020 in this scenario, then output continues to increase by 373 kb/d above near term peak in early 2020, peak output is 4335 kb/d in 2028 for this very conservative scenario.

              THAT is a very conservative scenario?

              Rolling in the floor laughing my ass off!

            8. Ron,

              Yes most analysts predict at least 7000 kb/d peak output from the Permian basin, a scenario with completion rate constant at 495 new wells per month has a peak of over 5000 kb/d in 2028. It is pretty doubtful that the completion rate would fall to 395 completions per month and remain at that low level.

              On the sweet spots, I assume new well EUR falls as shown below, average 2018 Permian well EUR estimated at 387 kbo and falls to 336 kbo by 2030 for this scenario (rate of decrease depends on completion rate).

              If the assumptions of the scenario are correct, this is what output will look like.
              With the mean USGS TRR estimate of 75 Gb for the Permian basin and reasonable economic assumptions (oil price rising to $90/b by 2027 and remaining at that level through 2052 and then declining to $40/b in 2062) the URR would be roughly 59 Gb for the Permian basin.

              The model works quite well from 2010 to Sept 2019, with good assumptions about the future it might continue to do so. R squared from Jan 2010 to Sept 2019 is over 0.999.

            9. Not a problem Dennis. We will just have to wait and see. But I believe the sweet spots will start to play out very soon. Many, like in Eagle Ford, have already played out. That is just the nature of the shale oil patch.

            10. Ron,

              A key difference between Eagle Ford and Bakken, both with mean USGS TRR of about 10 to 11 Gb, the Permian basin has a TRR estimate of 75 Gb, so the sweet spots may have a bit more room there.

              My scenarios have flat to declining output for all tight oil basins as a group except the Permian basin. The Permian basin is likely to have URR of 59 Gb, to date cumulative production is about 5.4 Gb.

            11. Ron,

              Cumulative output for both the Eagle Ford and Bakken are roughly a third of their mean USGS TRR estimates and both are close to decreasing new well EUR (Eagle Ford may be past this, Bakken I expect will start to decrease soon). For the Permian basin cumulative tight oil output is 5 Gb and a third of the USGS mean TRR is 25 Gb, for my medium scenario with a 7 Mb/d peak in 2028, the 25 Gb cumulative output point would be reached in 2028.

              Chart below has cumulative output for my standard scenario with completion rate increasing to 727 completions by 2026 and then declining starting in 2027, peak is 7000 kb/d in 2028.

            12. Ron,

              The model uses the following hyperbolic well profile, the curve gradually shifts toward the horizontal axis after Dec 2018, well profile for jan 2040 also shown. If economic limit is reached at 4bo/d in each case the EUR is 384 kbo for 2018 well and 291 kb0 for Jan 2040 well. EUR falls to 261 kbo at end of scenario completions in 2051.

    2. dclonghorn,

      look back at legacy decline in 2015/2016 in the DPR, as completion rate falls the change in legacy production decreases in magnitude (absolute value). An assumption that the trend in the change in legacy production will remain the same is not a good one, the slope of that line become more vertical in 2017/2018 due to the increase in the completion rate over that period, as the rate of change in completion rate becomes less steep (as has been the case in 2019) or closer to horizontal (zero slope) the same will become true of change in legacy production (the slope will approach zero).

      Also keep in mind that the DPR model may miss recent changes in legacy production change.
      In the chart below two earlier DPR reports from Sept 2015 and Jan 2017 are compared with the most recent Oct 2019 report for legacy production change for all tight oil regions included in the report.

      The most recent period where rate of change in completion rate is changing (the rate of change is closer to zero than before) might be missing a change in the lope of the legacy production change as has occurred in the past.

      1. I realized a major difference between the most recent report and the older reports was that in the earlier reports the Anadarko region was not included. The chart below only includes 6 regions for the most recent DPR report (I leave out the Anadarko region for the legacy decline estimate) so that it compares more closely with the Sept 2015 and Jan 2017 DPR reports. It still misses the change in slope for the legacy production change in the first half of 2015 (Sept 2015 DPR) and the second half of 2016 (Jan 2017 DPR).

    3. dclonghorn,

      do you have a fracspread estimate for July 2019? We have a tight oil increase in Sept of about 108 kb/d based on the EIA’s tight oil production estimates by play (which excludes the conventional output from the shale regions, where few of the wells are fracced). using DPR for legacy production change, shaleprofile for average well productivity, and EIA tight oil production estimates by play we estimate an average completion rate of 917 wells per month in 2019 vs 799 wells per month in 2018, the final 6 months of 2018 had an average completion rate of 923 new wells completed per month.

      Note these these estimates are rough because the legacy production change estimate for recent months (especially 2019) may be incorrect which would cause these completion rate estimates to also be incorrect.

      1. Hi Dennis, July 2019 was when spreads began the big dip according to Primary Focus reports. 7/5 was 460 declining to 439 by 7/26, I estimate an average of 450 for the month. August ave was 416, and Sept was 379, and 363 last Friday. As per my “back of the envelope” estimate, I think around 415 is zero growth, zero decline.

        Of course there are lots of factors which could go into a more comprehensive projection or model, but I don’t think it would change my conclusion that frac spreads have dropped enough that lower 48 onshore production will be dropping soon. Of course a sharp change in future frac trends could limit or increase any change.

        As Ron said above there is a significant lag between the time a frac spread is running and production. Consider that many operators are drilling mostly multi well pads, and sometimes neighboring wells are shut in when a well is fracked. So an operation which begins on say January 1 may not be completed till sometime in Feb or March. Once the frac is done there may be battery’s to build, pipelines to construct and connect, and lots of work to be done before flow back, although I think most operators get a lot of this done before the frack. Then it takes a while for the well to flow back the massive amounts of water it was fracked with till it cleans up and begins to produce oil and gas. After it is producing, it may take 2 to 3 months before it shows up in an EIA monthly or other record. The EIA weekly’s aren’t much good at catching changing trends, and I doubt the monthly tight oil projections will do better, so we will likely have to wait for monthly data.

        So, with Sep as the first month below 415, my guess would be production declining in Nov which wouldn’t make the EIA monthly til 1/31/2020. Of course some very smart folks are saying US production will grow by over a million bpd in 2020, so stay tuned.

        1. “As Ron said above there is a significant lag between the time a frac spread is running and production. “

          These (stochastic) lags are all part of the modified shock model applied as appropriate to the analysis.

          1. Paul,

            The tight oil models don’t really use the stochastic logs in the same manner as your original shock model, simply the convolution of completion rate and average profile is the analysis in a nutshell with future completion rates subject to economic analysis where the net present value of future cash flows is positive and with an assumed future decrease in new well EUR (start date has to be guessed at) with the rate of decrease in EUR based on completion rate and assumed TRR of the basin (I usually use the mean USGS TRR estimate as a starting point).

            The other data on frac spreads and rig counts can be useful to guide estimates of future completion rates, though the number of completions per rig or frac spread can change with time as better equipment gradually replace older equipment and the newer equipment may be able to work at a higher rate.

            1. Yes, so if these lag delays are not needed in the model, they may not be a factor in reality. Therefore, the suggestion is to apply as is appropriate.

        2. dclonghorn,

          Thank you.

          See “tight oil production estimates by play” at page below, those are the best estimates we have (based on drilling info data).

          https://www.eia.gov/petroleum/data.php

          If we use the 450 estimate for July 2019 to get Sept 2019 completions, I estimate roughly 900 completions in Sept 2019 so about 2 completions per frac spread each month on average.

          Shale profile gives about 672 b/d per completion for peak average monthly output rate for the average 2019 tight oil well.

          So at 415 frac spreads we would have about 830 new wells or a new well increase of 558 kb0/d, in Nov 2019 the DPR estimates a legacy production change of -525 kbo/d, that would suggest 558-525=33 kbo/d increase in US tight oil output in Nov 2019, also keep in mind that as the completion rate decreases the legacy production change will become less negative (increase).

          The DPR tends to miss the changes in trend as I have documented elsewhere. (see link below)

          http://peakoilbarrel.com/open-thread-petroleumoctober-20-2019/#comment-690501

  19. Dan,
    thank you for Hamm’s remarks!
    I wanna add Bakken’s data from Shaleprofile

  20. Some more information about the ramp up of Johan Sverdrup as involved parties started releasing their q3s yesterday with Aker bp and today with Equinor.

    Using the breadcrumbs Aker bp revealed in their Q3 yesterday i did a conservative calculation and came up with Johan Sverdrup averaging about 230.000 boepd in Q4.

    Today Equinor released the following press statment:

    “The Johan Sverdrup field was put in production 5 October and currently five wells are producing. All eight pre-drilled wells are expected to be put in production by the end of November, giving a production capacity well above 300.000 barrels per day. The field is expected to reach plateau during summer 2020.”

    So my estimation is perhaps not that far off, seems like ramp up and capacity of first phase might be faster and higher than previously communicated.

    1. Baggen,

      Thanks. When we account for the declines in existing fields in Norway (besides JS) what would we expect for the change in Norway’s C+C output from June 2019 to June 2020?

      1. Dennis,

        I have no idea, i just follow Aker bp and Lundin Petroleum in Norway.

        Aker will have some production growth beside JS mainly in 2020.

      2. Baggen,

        If the image is larger than 50 kB it will not post, try saving in gif format (I copy to a word doc and then save from there in gif format, if still to large I edit using paint (I am on a windows box, not familiar with Macs). Hope that helps.

    3. Perhaps increasing image size?

      Anyway if you can make it out in below i found this one interesting. The expected level of production from top well in JS, also in the footnote the comment about Ghawar well.

      1. Baggen,

        For some reason I have not been able to increase image size.

        Will test other plugins

      2. Baggen,

        So that one vertical well drilled in 1948 decline at an average annual rate of 3.287% for 60 years and cumulative output of 151 million barrels of oil over those 61 years (1948-2008), if the well declined exponentially at a constant rate (hyperbolic decline is more common but we have no data for such a fit.) If that well continued to decline at 3.287% per year until 2019, then 2019 output would be 1454 bo/d and cumulative output from that well (at the assumed exponential annual decline rate of 3.287%/year) would be 158 million barrels of oil.

        We have very little individual well data from Saudi fields.

        1. Dennis,

          I found the decline rate less interesting or not interesting at all actually what was interesting to me was the level it apparently produced at in 2008 and as you say this is a vertical well.
          As this was the best well (at least in early field life before any horisontal producers were added) i assume this is positioned as a producer at the very top of the best section of that structure, much like the Johan Sverdrup well that is expected to pump 50.000 boepd will be.

          I think it supports the theory that the northern parts of Ghawar is more or less watered out and on its last leg.

          1. I had a link, ten or twelve years ago, that showed how Saudi was converting all their old vertical wells to horizontal wells. They were plugging then above the water ling then drilling horizontal wells from that point laterally.

            So your well started life as a vertical well but there is no guarantee it is still a vertical well.

          2. Baggen,

            If your assumptions are correct, your conclusion may follow. I am not familiar enough with Saudi Arabia, to make a judgement. My guess is that the north end of Ghawar is producing much less today than at it’s peak, perhaps half, maybe even one third.

      3. OMG Norway is the known outlier in all kinds of the international comparisons. And….yes… Norway did it again!

        No, Norway didn’t. We are still in 2019.
        The ‘2020 planned’ 50 000 kbd just means that Norwegians cannot let their pride go. They should read the Midas myth carefully again, so they may not think anymore than anything Norwegians touch, is going to be a fine specimen of perfection.

        It would be strange, however, if a not-so-shallow offshore oil well would produce so much oil in a consistent way (at least for the entire year).

        Anyway, the comparison is unfair to the mighty Ghawar – if anything, in 1951 Johann Sverdrup produced 0,0 bd.

        1. OneofEU

          Yes we are still in 2019, that is why the image has that * next to the 50.000 and the * Planned in the footnote.

          But we can look at production today that is “well over 200.000 boepd” and this from 5 wells, i say that puts the 50.000 for the top well in the plausible range at least.

          At the end of November 3 more wells will be in production and daily production will be at about 350.000 boepd on those 8 wells. 2-4 new wells will be drilled now to reach phase one plateau of 440.000 boepd expected summer 2020.

          This is from the companies owning interest in Johan Sverdrup and for sure the current daily production figures ar not a lie, and we will se what the future holds but from history and my experience Lundin Petroleum is very careful when it comes to promises and have a history of over delivering so i think they are quite confident when they state 80% of plateau phase 1 by end of November on 8 wells.

          1. Ok, we will see. let’s hope it will be the Cantarell of Norway. Maybe they have sophisticated multilayered horizontal wells there; in fact, the number of producing wells is pretty small…
            However, taking a look at the entire basin, it looks like Norwegian fields tend to overperform at the outset, and undeperform when in decline…
            And such a high rump-up strategy as in JS would suggest that operators think it rather smaller than larger.

  21. The Permian Basin is facing its biggest threat yet

    The cowboy-booted wildcatters who figured out how to squeeze crude from shale rock are used to booms and busts, but this time it feels different. In the Permian Basin, a giant oil field beneath the dusty plains of West Texas and New Mexico that’s the source of roughly one-third of U.S. oil output, production is up 17% in the past year, compared with an increase of almost 40% in the preceding 12 months, according to the U.S. Energy Information Administration. Unlike the last slowdown, five years ago, it’s not oil prices that are mainly to blame. It’s investors.

    Fed up with years of broken promises and make-believe forecasts, fund managers have dumped American oil and gas stocks this year, cutting off capital to investment-hungry shale producers and preventing private companies from coming to the market in initial public offerings. That this is happening in the Permian, the world’s largest and most productive shale basin, calls into question the longevity of America’s fracking revolution, which has turned it into the world’s top oil producer.

    It’s commonly believed that the boom began when wildcatters figured out how to combine two techniques—hydraulic fracturing and horizontal drilling—to unleash oceans of oil from hitherto impermeable shale rock. But the breakthrough was as much financial as technical. After the U.S. Federal Reserve slashed interest rates in response to the 2008 financial crisis, cheap money washed into America’s forgotten oil fields, supercharging production.

    A decade on, the returns on those investments haven’t matched the growth in output—not even close. The industry burned through almost $200 billion in the past 10 years. Over that time, the S&P 500 Oil & Gas Exploration Index lost 32%, compared with a 172% rise in the wider market. “The industry has destroyed so much capital for so long” that many investors have fled, says Todd Heltman, senior energy analyst at Neuberger Berman Group.

    There is more to this article plus a five minute video explaining what is happening in the Permian.

    1. “After the U.S. Federal Reserve slashed interest rates in response to the 2008 financial crisis, cheap money washed into America’s forgotten oil fields, supercharging production.”

      Thanks Obama!

    2. Ron,

      Perhaps majors will pick up slack from independents and the net will be a constant completion rate. Also the price of oil is likely to rise at some point in the future (date unknown). If oil prices remain at $60/bo in 2018$ or less long term, then we might see tight oil output remain flat or even decrease.

      Should that occur it would be short term as oil prices would be likely to increase in response.

      Of course we don’t know future oil prices, so future output is difficult to predict.

      1. Dennis, you don’t seem to understand my problem with the Permian, or shale oil in general. The shale patch declines by the acre, not necessarily by the barrel. The acreage simply peters out. You simply drill so many wells per square mile. And when you have no more square miles to drill, that’s the end of that shale oil patch.

        What started happening in Eagle Ford last year, or whenever it did, will happen in the Bakken and in the Permian just as sure as the sun will rise tomorrow. Over the past year, the rig count in Eagle Ford has declined by 20% and by 15% in the Permian. Crack spreads have declined by a similar amount.

        When you show a chart of the Permian with massive production into 2030, I have to wonder, is the Permian expanding in area? When are they going to run out of acreage? They tried drilling more wells to the square mile. That didn’t work out. So they are now back to their old method of limiting the closeness of their laterals.

        My question to you Dennis is, do you even consider the size of the drilling area when you make your prediction?

        1. Ron,

          Yes I do. The Permian is big in area and has several different layers, I am basing the estimate on the USGS mean TRR estimate of 75 Gb for Midland and Delaware Wolfcamp and Bonespring formations and the Spraberry Trend, the URR for my scenario is 59 Gb, with the assumption that the USGS mean estimate is correct tie 90% confidence interval for the Permian TRR is 43-113 Gb, with a 5% chance TRR will be lower than 43 Gb and a 5% chance it will be higher than 113 Gb, with the mean being their best guess.

          For the Bakken and Eagle Ford the mean TRR estimate by the USGS is about 10 Gb for each, cumulative output for each of these plays is roughly 3.3 Gb or about a third of the mean TRR estimate, both plays are at or near peak.

          For the Permian one third of the mean TRR would be 25 Gb, my best guess scenario reaches that point in 2028, the scenario has a URR of 59 Gb.

  22. What we really need to know is the state of the shale geology remaining.

    The entirety of the current hype about Permian growth rate flattening is focused on investor awareness that they can’t earn a return on money they commit. And consequent reduction in investment.

    This Doesn’t Matter.

    If oil stops flowing for lack of investment then you must make it flow despite this. Nationalizing the industry is the obvious path to that. (This is true globally, btw) And no, don’t delude yourself that loss of investment will be cured with a price increase. Governments that want to stay elected will not allow a price increase. They’ll subsidize, which isn’t much different from nationalizing.

    What we really need to know is . . . will a nationalized fracking industry fail to get oil out? Not for hand waved talk about the inferiority of government management vs private capitalism. For reasons of geology. How much more oil can you get out if you had infinite money to make it happen? And we should probably ask that question in the context of both barrels and bpd.

    1. If oil stops flowing for lack of investment then you must make it flow despite this. Nationalizing the industry is the obvious path to that.

      No, that is just not going to happen. Nationalization has a sorry history in countries, like Venezuela, who have tried that trick. It would be political suicide for any politician who even suggested such a thing.

      Governments that want to stay elected will not allow a price increase. They’ll subsidize, which isn’t much different from nationalizing.

      Governments cannot keep the oil price from rising. It rose to way over $100 a barrel a few years ago and the government did nothing. And no one, not one politician suggested nationalization or subsidizing the industry.

      will a nationalized fracking industry fail to get oil out?

      Not to worry about that. It just ain’t gonna happen.

      How much more oil can you get out if you had infinite money to make it happen?

      That is a question that has no answer. No answer because it simply because there is no such thing as an infinite supply of money. Geology and the open market will always control the oil supply. The idea that the government will keep the oil flowing when the supply gets so low and the price so high, that the government will just step in and take measures to keep the oil flowing is just a silly idea. Of course, the government will do everything they possibly can to keep the oil flowing. But the government does not control geology, or how much oil is left in the ground.

      When the oil runs out, it will just run out, and there is not one damn thing the government can or will do to remedy that situation. If the last few million barrels becomes so high few people can afford it, that will just be a sad situation that no one can fix.

        1. Saudi Arabia was always a partner in ARAMCO. That’s what the acronym stands for, Arabian American Oil Company. In the late 70s, Saudi Arabia began buying out all four of the American Companies and the deal was completed in 1980. It was never a hostile take-over as it was in Venezuela.

    2. “They’ll subsidize, which isn’t much different from nationalizing.”
      I think you are correct Watcher. In effect, the ‘easy money’ is a government policy subsidizing the industry [and other sectors of the economy]. Without the easy money policy of quantitative easing and low interest rates, the industry would be much smaller. Imagine the state of the global oil industry/production if fracking hadn’t been, in effect, heavily subsidized.
      Perhaps we will see it yet.

      from an article on energy/economics-
      “The implication for fossil fuels isn’t, necessarily, that worsening scarcity will cause prices to soar but, rather, that it will become increasingly difficult to set prices that are at once both high enough for producers (whose costs are rising) and low enough for consumers (whose prosperity is deteriorating). It’s becoming an increasingly plausible scenario that the supply of oil, gas and coal may cease to be activities suited to for-profit private operators, and that some form of direct subsidy may become inescapable.”

      https://surplusenergyeconomics.wordpress.com/
      #156
      worth the time to read

      2. Hickory,

        LTO is a pretty short term investment: roughly 35% of the return comes in the first 12 months. That means that interest costs are not a very large percentage of the overall cost of drilling and producing LTO. Which, in turn, means that a reduction in interest rates doesn’t reduce LTO costs very much. So, if low interest rates are a subsidy, it isn’t very large.

        It’s true that low rates have made riskier investments more attractive. But, investors still expect to make money. They’ve lost money, because everyone has expected oil prices to rise faster than they have. That, of course, is partly due to large investments in LTO, which were caused by forecasts of high prices, but which in turn made those forecasts not come true.

        Commodity markets can seem very perverse. That’s true of apples and corn, as much as for oil.

        1. I feel that a lot of folks saw peak oil, or perhaps just the Saudi America type media response to it (remember that Texas Tea commenter guy lol), as a big money making opportunity. I quite like how Schinzy has often refuted the assertion that impending peak oil is an indication of an opportunity to make money investing in oil. Not much profit in scraping the bottom of the barrel I guess. But hey, WTF do I know. I also quite like the references to permaculture that he made in the conclusion of his recent paper. He and Bradford getting together on a podcast or something would be fab.

          https://www.math.univ-toulouse.fr/~schindle/articles/2019_oil_cycle_v2.pdf

        2. Low interest rates fund LTO both in borrowing costs and in investors looking for more risky assets. Most yield investing doesn’t work in this environment, not for long term targets. Quantitative easing and near-zero rates force people to take more risk.

          Fracking debt doesn’t carry interest rates anywhere near its actual risk and until this year, raising equity in said unprofitable companies was relatively feasible. That’s the subsidy. Under normal economics, the US LTO boom wouldn’t have happened for lack of return.

          1. Fracking debt doesn’t carry interest rates anywhere near its actual risk

            Well, that requires that we all agree on how to evaluate risk, based on a prospective evaluation, rather than on hind-sight.

            Could you expand on your comparison of rates vs risk? Perhaps provide some examples?

            1. In a pre-Financial Crisis environment, 5% yield on US Treasury 10 year – which has no relevant risk – was the historic lower band.

              https://fred.stlouisfed.org/series/DGS10

              Today, high yield junk bond funds – which contain instruments that have considerable risk – have yields with 4 or 5 handles on them. The JNK symbol ETF is an example of that. 5.54% as of market close on Friday.

              Frackers have been able to borrow debt for a notoriously risky, cyclical business at rates comparable to what the AAA rated US government with taxing and printing power used to pay.

              That’s where all the money for this enterprise has come from. You think shale economics are bad now, imagine if they were paying 10.67% interest…

      3. “In short, GDP and growth have been faked by the simple spending of borrowed money. This exercise in cannibalising the future to sustain the present would look even more extreme were we to include in the equation the creation of huge holes in pension provision.”

        Some people do not realise how GDP can be manipulated. The deception is on a scale that most people cannot comprehend.

        So many people in the United States think they are winners in their capitalist society..until they get old and ill.

        https://www.bloomberg.com/news/articles/2019-06-25/u-s-nursing-home-costs-may-get-worse-thanks-to-a-labor-shortage

        Then they realise, that in order to get the care they need, they have to sell everything they have including their homes. Then what?

        How on earth will the US raise all those taxes when the number of retired people is set to double.

        https://www.prb.org/aging-unitedstates-fact-sheet/

        1. How on earth will the US raise all those taxes when the number of retired people is set to double.

          The absolute numbers of the population over 65 is supposed to come close to doubling, because of longer lifespans.

          But: the percentage of the population over 65 will rise by less, about 45%. And people will work longer before they retire. If people use roughly two thirds of that additional lifespan to work longer, the proportion of working to retired could stay the same.

          So, the price of living 10 years longer is that you work 6.5 more years, and have 3.5 more years in retirement, rather than getting the full 10 years as a retired person.

          Doesn’t seem so bad.

            1. Well, old enough to have perspective. And, to have spent quite a lot of time looking at the demographics and actuarial underpinnings of pensions, especially government pensions.

              I know that the actual process of shifting retirement ages is messy, but the underlying dynamics are clear: early retirement is obsolete.

              Much of the problem started with WWI: the US had created an army, and it’s tradition was to not have a standing army. So, it created early retirement to clear out much of the excess personnel. Unfortunately, that early retirement system stuck around, and then spread to civilian police, fire, and then other government employees.

              Social Security’s early retirement problem is somewhat smaller, but the underlying problem is the same: many more people are surviving to retirement age, and then they’re living longer.

    3. The BOJ has recently tightened, but stepping right in is the US with major POMO moves. I was forced to watch some WWF yesterday (the Young Bucks versus a couple other bigger guys) and the way they tagged in, and flowed around, into, and out of the ring, the Kayfabe is about as coordinated as the Central Banks globally. There’s a lot of jawing between nations who are supposed rivals, but they are all working together in the end.

  23. According the EIA, Rystad the majours like Exxon , Chevron is ramping up their Permian productio . They attend a oil conference where they not see any end of the growth in Permian . Geology does not much matter for output and decline rate. In the mean time Equinor presented their 3 rd quartile. The bottom line was red , because they need to write down billions of dollars on their EF assets. Stocks plunge…. I am very interested in how much the majours spend in Permian and what they get back after liabilities, interest is payed.

    1. Another chart from IEA shows well completions since Jan 2010. Given that DUCs have fallen by 400, which is not shown on the chart, well completions have probably peaked and are in decline now.

    2. With well productivity gains flat after normalizing for length, that has to force a decline. Even with quality constant, one can’t increase with fewer completions against escalating legacy decline. The math doesn’t work.

      1. Propoly,

        The legacy production change levels off as completion rate decreases, nobody seems to get this, if completions remain constant with no change in well productivity, output continues to increase in the Permian basin until 2028. Even a drop in completion rate by 20% results in only a 0.4% temporary drop in output and then if it is assumed the 20% lower rate is maintained longer term (10 years) output rises (this is due to changes in legacy production change as it becomes more positive (smaller in absolute value) at the lower completion rate.

        See http://peakoilbarrel.com/open-thread-petroleumoctober-20-2019/#comment-690577

        1. No one gets it because it isn’t true. Fewer completions in increasingly worse rock doesn’t mean more production because everything current has to be replaced. Eagle Ford has a longer exploitation record than Permian LTO and this has been seen there. Everything prior to 2015, which peaked at 1.6m, was producing 272k in June of this year, including re-frack experiments. The next four years will do the same.

          Maintaining production, let alone continued growth in these mature plays amounts to “lets do everything we did all over again.” Except neither good land nor (now) investor capital and patience are infinite. And its not like we don’t see these issues in reporting out of the Permian.

          1. Propoly,

            Do you expect the completion rate will fall to zero in the near term? If the completion rate simply remains steady, legacy production change will become less steep. Just the way the math works.

            I refer you to past data, legacy production change will level off if the completion rate starts to decrease (this may begin in 2020 or 2021).

            The rate of change in legacy production change became zero in 2015 (tangent to curve had horizontal slope), and will probably occur again in 2024 or so (perhaps 2025 it will depend on completion rate which will depend in part on the price of oil).

            1. I expect US tight oil minus Permian basin tight oil will peak in 2020 and start to decline in 2021. Permian basin output may increase through 2028 and US tight oil may peak in 2025.

              Scenario below is my best guess assuming Brent oil prices rise to $90/bo in 2017 US$ by 2027 and then remain at that level until 2050 and then decline. I expect oil prices are likely to rise higher than this level, the oil price scenario is intended to be conservative and of course it will not be correct, but for a 3 year average oil price it may be close, the monthly oil price is likely to very volatile bouncing between 70 and 110/bo over any given 12 month period.

            2. For Permian scenario in chart above the legacy production change is shown in the chart below in kbo/d.

  27. https://www.eia.gov/outlooks/steo/
    According to the latest EIA outlook from October 4th they admit the US production declined in July because of the hurricane but exspect growth will continue 4th Quartile as new pipeline capacity will be awailabil. Tgey exspect for 2019 average 12,3 mbpd that is increase off 1.3 mbpd in 12 month. For 2020 they exspect increase off 0.9 mbpd to 13.2 mbpd. This they predict will happen with brent oil price average 60 usd in 2020 or WTI about 55. It means growth off US shale is exspected to cover more than half off increase in global demand in 2020. Based on the latest update in frack spread, DUCs , productivity , decline rate and capital market for us shale this seems a bit to optimistic…

    1. Anybody compared their predictions of the past 10-15 years with what happened? Don’t care if they were wrong high or wrong low. Just were they wrong?

      Oh, and none of that crap about . . . well, we adjusted the prediction as more data arrived. If you can’t be accurate until data arrives, then they should tell everyone to 100% ignore their prediction until it does arrive and they are just trying to look busy for their paycheck.

      1. I thought oil production would be 20-30M bpd lower by now…so yeah I’m not considering a switch in careers to investment banker. Nevertheless, the arguments for peak oil become more compelling with each passing year. And I fear the longer it takes to happen the worse the downslope will be. I naively thought a peak would happen at the midpoint of the total amount of oil extracted. I didn’t realize how much could be front-loaded for more immediate consumption through aggressive extraction techniques.

        1. The word “their” above referred to EIA. Odds high their predictions have been wrong. Why do we pay them for that?

        1. Dennis, Would you agree that most of that upswing was due to a strong contribution from USA and Canada? A strong influx of money to subsidize the elevated LTO extraction after the 2008 recession. This is like a forensics case.

          1. Paul

            Around 2004 as WTI started its climb toward $50 and higher, the cash flow into the oil sands companies began to grow. Most projects back then broke even around $18 to $22/bbl. A significant number of companies announced mining projects and I think some began looking at in-situ sites where steam was pumped into the oil sands.

            There were so many projects announced that nobody thought of personell shortage. Salary costs and contract costs soared but the price of crude kept pace and cash was not a problem. I recall one company added a third coker to their operation. The initial estimate was $4.8B. Final cost was $8.4B. I remember because the numbers just flipped. Ultimately one of the partners could not make payments once the price crashed in 2008 and went bankrupt and Suncor bought them out for a song and dance. However that burst of cash from 2004 and 2008 helped fund a lot of new supply. You can see how the oil sands supply began to expand after 2009 in your chart. 2004 to 2008 were heady days in the oil patch.

            Last week we had an election. Two parties were pushing to shut the oil sands and stop building pipelines. The Prime minister who won, once said we must phase out the oil sands. He did not get anyone elected in Alberta and Saskatchewan and a WEXIT party was born in Alberta due to the indifference of the rest of Canada to the plight of workers in Alberta.

          2. Paul.

            Yes Oil Sands and LTO are the main reasons for expanding World output,
            many (including me) did not see the rapid increase in tight oil back in 2010 or so.

            updated chart (to 2018) below, showing unconventional oil on right axis, where I define unconventional oil as tight oil (LTO) plus extra heavy (XH) oil.

  28. Below is this morning’s October Monthly Energy Rpt update for US oil production. Their data estimates production up to September 2019, with September being an extra early estimate. The August estimate should be close to what we will see at the end of October in the EIA 914 report. August production increased to 12,374 kb/d, an increase of 568 kb/d from July. However, recognizing that July was affected by the hurricane, a better reference month would be June which had production of 12082 kb/d. The two month increase is then reduced to 292 kb/d or an average of 146 kb/d. Taking a longer term increase relative to Dec-18, the growth over the last 8 months has been 336 kb/d, or an average of 42 kb/d/mth.

    I have added the October STEO estimates for the L48. As can be seen, the MER estimates for August and September are very close to the STEO projections.

    The rig count is just out. Oil rigs are down by 17. Permian is down by 5 and Eagle Ford is up by 3. Interestingly Oklahoma down by 6. Any idea on how many are Oil in Oklahoma?

    1. Ovi,

      Horizontal oil rigs decreased by 6 in the most recent week in Oklahoma and fell from 134 for WE 11/9/2018 to 49 rigs for WE 10/25/2019.

      In Texas Horizontal oil rigs were 348 in the most recent week (-6) and one year ago the count was 451.
      At the end of May the horizontal oil rig count in Texas was 400, May’s count may be reflected in the Sept tight oil output (which was still increasing by about 88 kb/d in Texas), so about a 13% decrease in horizontal rig count in Texas since the end of May, note that if my 4 month lag estimate is correct the most recent count will affect completion rate in Feb 2020. The relationship is not perfect and frac spreads may give better idea as that is the final step and they complete both newly drilled wells and older DUCs. A great metric would be total horsepower of operating frac spreads as the bigger equipment may be able to complete wells more quickly and efficiently, though I would defer to anyone with more knowledge of this equipment, there are no doubt many nuances I am not aware of.

      Some interesting info in the article below

      https://www.aogr.com/magazine/frac-facts/latest-frac-fleets-are-tougher-faster

      and

      https://pubs.spe.org/en/jpt/jpt-article-detail/?art=4476

        1. Ovi,

          Yes the article date is August 2018, it just gives an idea of the expansion of frac spreads at that time and changes in horsepower, for example:

          Demand for pressure pumping horsepower is expected to jump 4 million hp this year to 17 million hp, more than double the 2016 level. Demand is expected to grow 2 million hp in 2019 and another 4 million hp in 2020 to 23 million hp, where it will remain flat in 2021.

          On the supply side, horsepower is expected to increase by 4.8 million in 2018, more than meeting demand. Growth will halve to 2.4 million hp in 2019 and then spike to 5.1 million in 2020. The increase next year will primarily serve to fulfill “skyrocketing” demand in the Midcontinent and Haynesville regions, said Ryan Carbrey, Rystad senior vice president, shale research, during a frac market webcast.

          As of mid-2018, all horsepower that was previously available for refurbishment has been refurbished, Carbrey said, meaning only new horsepower will be added to the field going forward. The overall increased supply—from both refurbished units and newbuilds—has stabilized the market, and price increases aren’t expected through late 2018 or early 2019.

          If you can find more up to date information it would be of interest, thanks.

          If the forecast from August 2018 is roughly correct (unlikely), a lot of newer frac spreads might have been added over the past 12 months, then as frac spread decreased over the past 6 months or so, older equipment may have been idles leaving the newer and possibly higher horsepower equipment running (some of this is electric which runs on field natural gas and has lower running cost due to lower fuel cost). This might explain fewer frac spreads, but continued increases in output, the remaining numbers of frac spreads may have the same total horsepower and may be able to get more done than older smaller equipment. That is why I suggest a better metric than the number of frac spreads would be the total horsepower of the active fleet. This number is probably tracked, but is no doubt proprietary, so we are left in the dark.

      2. The graps is very interesting and at least it shows the growth rate of US shale is significant lower in 2019 compared to 2018. How much of this is related to pipeline constraints and other , guess hurricanes in the gulf is seasonal and also occoured in 2018. As an Engineer I believe the equipment , frack spread is choosen based on type of wells, lenght of lateral i.e. If horsepower in pumps i.e not is suffisient it will have impact on foot wellbore each day and also diameter of wellbore that I believe is standard. My guess is you might increase the speed , but this will also have a cost and when you reach the point where the torque of the drill string because of weight i.e you will not be able to utilize all that power as you might over ride the material strenght .
        What seems clear is the URR of wells in Permian seens lower than in EF, frack spread in US is decreasing , pepole are sent home , Companies owning this Buisiness with fracking, completation like Schlumberger, Baker hughes have huge write downs of their equipment, Income in 2019 is down related to Q3 reports by 40-50%. To say it with the Pioneer Mark Papas words, the best og US shale is past but still EIA, Rystad, Exxon, Chevron i.e believe there will be no slow down when the pipeline capacity , Refinery i.e is in place. Both Shevron and Exxon will issue their 3Q reports 01 of November. Hopefully this will give some indication as I am sure ramping up their production 3 fold have a significant cost and they need to show some is comming back to the shearholders else stocks will fall down the cliff….

        1. Freddy,

          My estimates for EUR of the average 2016 Eagle Ford tight oil well is 225 kbo.
          For Permian 2016 average well the EUR is 394 kbo, and for the Bakken 2016 average well the EUR is 353 kbo.

          I agree there are limits to horsepower, the point is that some of the rigs that have been idled may have been underpowered, there are also incremental technological improvements in new equipment (even if power is identical) that can make the equipment more efficient, there are of course limits to these advances as well, but in an industry where there has been a rapid increase as in Permian basin in 2018, these changes can be significant, as equipment is idled, I would guess that the best rigs (the most efficient equipment for the job at hand) will remain active and overall efficiency (number of wells completed per frac spread or number of feet drilled per drilling rig) is likely to increase.

      3. Article from April 30 2019 on electric frack speads, so far numbers are quite small, only 8 in Permian basin from Baker Hughes as of April 2019. They estimate a total of 500 frac spreads in North America in April 2019.

        https://www.houstonchronicle.com/business/energy/article/Baker-Hughes-chooses-Permian-Basin-to-debut-13808592.php

        It looks like it will be a while for the efrack thing to catch on as there is a lot of idle equipment out there that is diesel based. (Article below is from Sept 2019)

        https://www.reuters.com/article/us-usa-oil-electric-fracturing-focus/low-cost-fracking-offers-boon-to-oil-producers-headaches-for-suppliers-idUSKCN1VX112

        Jeff Miller, chief executive of Halliburton Co, the top U.S. provider of fracking services, said his firm has tested the technology but has no desire to promote it.

        “Halliburton will be really slow around frac,” Miller said, referring to the costs of updating diesel systems to electric. Converting the industry’s 500 frac fleets would cost $30 billion, he estimated, too steep a price for oilfield firms, he said.

        He recently advised an oil producer interested in the technology that the benefits of deploying e-fracs “work for you, they don’t work for us,” he said at Barclays energy conference this month.

  29. Will the deficit effect oil?
    US deficit hits nearly $1 trillion. When will it matter?
    https://www.sfgate.com/news/us/article/US-budget-deficit-hits-984-billion-highest-in-7-14562747.php
    Trump has been bankrupt 6 times.
    His current gig may be perfect– he can’t go bankrupt.
    Fact Check: Has Trump declared bankruptcy four or six times?
    https://www.washingtonpost.com/politics/2016/live-updates/general-election/real-time-fact-checking-and-analysis-of-the-first-presidential-debate/fact-check-has-trump-declared-bankruptcy-four-or-six-times/

      1. According to shadowstats, inflation has averaged about 10% for the last 15 years, which would have raised prices by 4x. That seems way too high.

      2. The shadow stats data is nonsense.

        The US government data is fine.

        See

        https://mitsloan.mit.edu/ideas-made-to-matter/measuring-facts-using-data-to-tell-true-story-inflation?utm_campaign=Feed%3A%20mitsloannews%20%28MIT%20Sloan%20News%20Feed%29&utm_medium=feed&utm_source=feedburner

        and

        http://www.thebillionpricesproject.com/usa/

        https://web.archive.org/web/20170506213848/http://www.pricestats.com/inflation-series?chart=1837

        The billion prices project is far more realistic than shadowstats in my opinion.

    2. Wait. What?

      Individual businesses can go bankrupt. Nobody in their right mind would have all of their businesses linked together so that a bankruptcy would take down personal net worth. That’s just insane.

      Every real estate guy in your own hometown who owns maybe 20 rental properties will have each property owned within a separate LLC. A lawsuit to grab a house grabs only that house. This is standard procedure.

      So I’m pretty sure the president has never been bankrupt.

      Big oil is not going to be able to do this because if there was ever a candidate for a piercing of the corporate veil that would be it. Exxon could not make each individual oil well a separate business. A single well causing some localized disaster to generate an avalanche of lawsuits is not going to be isolated from the rest of Exxon corporate assets.

      It is maybe a bit surprising that the president doesn’t also suffer from that vulnerability since his numbers are big enough, but real estate has a history of isolation of risk from personal assets so the laws are in his favor.

      As for the deficit, that is about 4.5 – 5% of GDP. Final GDP revs are not in for 2019, of course, (call it 21.1T) and FYs don’t line up with the calendar years. 5ish% is a reasonable measure.

      Harped on this before. That is fiscal stimulus. 5% stimulus is not getting 5% GDP growth. How does this map to fracking? Not the same way in one year versus another. If you think the dollar should be weaker because of 5% deficit you have to ask weaker against what? Because that “what” may have its own reasons to be weak. It will vary from one year to the next. And it will also vary from one Central Bank’s intervention to the next.

      Not a good idea to invest a lot of time in analysis when the predominant factor in the parameter being explored is whimsy.

  30. You can go to the Department of Commerce website and examine their inflation computing methodology. It’s pretty damn good, and it is light-years better than anything shadowstats can put together, because the Williams guy doesn’t have funding.

    If people think inflation is 5%, then how can they possibly lend money to the United States government for 10 years at 1.7%?

    If people think inflation is even higher than that, then why isn’t the price of gold at its all-time high?

    There are likely definitional problems. Hedonic this and that will always change the meaning of what’s being measured, and most of the gold bugs hate that hedonic effects exist. But they are legitimate. You can debate the magnitude of their effect, but you really cannot deny that it is a factor that should be included in the calculation.

  31. Iraq protests: 40 dead as mass unrest descends into violence
    https://www.bbc.com/news/world-middle-east-50181212

    Black Swan approaching….

    “Elsewhere, as unrest spread through Iraq’s southern cities:
    About 3,000 protesters broke into a government building in Dhi Qar province
    Guards protecting a Shia militia group’s offices in Maysan province opened fire, wounding at least six
    Protesters set fire to a Shia political party’s offices in Muthanna province
    A curfew was imposed in several southern provinces”

  36. Perry says the shale fields have enabled the US to become a net energy exporter. Is this true?

    1. Requires a careful reading. Shale fields include natural gas. And he said energy, not oil.

  37. https://m.economictimes.com/markets/commodities/news/goldman-sachs-lowers-forecast-2020-us-shale-oil-output-growth/articleshow/71702091.cms
    This is the analyze where Goldman Sachs predict US shale will increase 1.1 mbpd in 2019 , 0.7 mbpd in 2020 and if that continues it should be 0.49 mbpd in 2021. Non Opec 1.4 mbpd in 2020 slowing down to 0.2 mbpd. If demand is estimated to 1.3 mbpd in 2020 there might be a oil glut with low prices depending how much Opec will cut abd decline in Opec Countries but at least in 2021 it seems there will will ve need for Opec to add more oil in the market.

    1. GS states the huge importance of future Permian oil production: “Permian to account for 116% of all non-OPEC oil growth in 2022.”

      GS US growth forecast of 0f 0.7 mbd for 2020, from 2019, equals my oil production growth forecast for all 7 US shale regions, including some non shale oil production.

      My oil price production forecast below estimates 8.6 mbd from 7 US shale regions in 2019, increasing by 0.7 mbd to 9.3 mbd in 2020.

      1. Tony , seems you have a decline from Jan to Dec 2021 of about 250 kbpd. What oil price WTI is this based on ?

  38. Freddy,

    My model does not use price and is not bottom up. I use EIA DPR data to calculate historical production from new wells. Next I do a linear extrapolation for both production from new wells and legacy decline. I realise that these are not valid assumptions for the long term but I think there is some validity for the short term. That’s why I am only forecasting to Dec 2022.

    The dashed red line in the chart below is my best guess at a trend line for production from new wells. Declining DUCs tend to correlate with a slowdown of production from new wells. DUCs from the five main oil producing shale regions have dropped by 400 since early 2019.
    https://www.eia.gov/petroleum/drilling/#tabs-summary-3

  39. In a move that totally doesn’t mean the Saudis have something to hide, the Aramco IPO isn’t going to be held on major Western exchanges or involve selling any significant interest in the company. Rather 3% ownership on the Saudi exchange, which lacks an independent SEC type body.

    https://www.nytimes.com/2019/10/28/business/dealbook/aramco-ipo-saudi-arabia.html

    Valuation discount as well but not as interesting as avoiding the scrutiny that supermajors are subject to on booking reserves.

    1. Oh heavens, don’t be taken in by supposed exceptionalism.

      US supermajors reserves booked follow rules that are carefully changed to get the results desired. Reserves are price dependent, unless the price goes in the wrong direction. Then the SEC will redefine things — most recently declaring that price used to assess reserves could now be the average price over X months, whereas prior to a price fall the rule had been a shorter value for X. Lower reserves means a company is worth less.

      There’s nothing innate superior about US procedures. They just obfuscate the cheating more deeply. If the price of Exxon stock falls, pension funds all over the US would be hurt. The obvious question is why endure that for the sake of reserves accuracy? What’s the imperative to be accurate? If accurate wipes people out, accurate is not inherently a good thing.

    1. You’d think that at least one high-level Aramco whistle blower would have come forward by now to tell the truth about Saudi reserves.

      1. Really now, why would you think that? In truth, it is highly likely that Saudi has not done a survey of their reserves since 1998 if they even did it then. They just declare what their proven reserves are, and that is that.

        At any rate, any official who dared contradict the official word of the Crown Prince would likely wind up with his body cut up with a bone saw. Hey, Saudi Arabia knows how to handle whistleblowers.

    2. But Saudi Aramco has not submitted to an independent audit of its reserves since 1980. Stated reserves have barely budged since 1998 according to the most recent BP Statistical Review of World Energy despite enormous production. One would think that 20 years of robust production would have had some downward effect on reserve numbers.

      Nuff said.

      1. OK, so they just tell the world an inflated number that they’ve pulled out of a hat. Somebody at Aramco must know what the real numbers are.

        1. Why? What is this real number that you’re talking about?

          No one has any idea how much oil is under North Dakota. Ditto the Permian. You could probably find 20 different estimates of reserves in those oil fields and all 20 would be from distinguished organizations who might not even be all that full of themselves. They might be making a serious effort to be accurate. But nevertheless they’ll all be different.

          There’s a Wiki on oil reserves that explains the whole 1P, 2P, 3P definitions and methodologies.

          Why would KSA have accurate estimate. They’re like American oil. They pretend to have an accurate estimate.

          Look at it this way. In a given oil field, if the price of oil goes up, the oil reserves estimate in that field will increase.

          In that same oil field, if the price of oil goes down, the oil reserves estimate in that field will remain flat.

          It’s a very important concept. Accuracy is not required. There is no value to accuracy.

          Now, pretended accuracy has value. Guys get paid at the EIA to offer up estimates under the EIA auspices, which pretends that they’re accurate. Their paychecks are the only value.

        2. Somebody at Aramco must know what the real numbers are.

          I will have to agree with Watcher here. There is absolutely no reason why anyone at Aramco has any idea what the real numbers are. It is extremely unlikely that they have done any survey to find the real numbers. And even if they did, every surveyor in the field would know what their job was, to deliver the largest number that would be believed.

          They just do like everyone else in the Middle East does, just put out a number large enough to be impressive but not so large that everyone would laugh their ass off at it.

          OPEC Share of World Crude Oil Reserves

          OPEC claims to have 79.4% of world oil reserves while Non-OPEC has 20.6%. Anyone who believes those numbers is !!!!… Well, I won’t say that word because I don’t want to disparage some otherwise well-informed members of this list. 😉

          1. So they have 80% of the global reserves that are also concentrated, and produce what 30-40% of the global daily supply from their superior reserves.. right..

            And those other 20% of inferior non-opec scattered reserves stands for 60-70% of daily supply..

            1. I never know how long the various guys here have been here. This has been going on for years. Decades.

              The big deception is that outside the Middle East everything is thought ethical and pure. Well, ethics and purity get redefined everyday.

              Just like oil. The liquid that comes out of these fields doesn’t have the same chemical composition today as it did 10 or 20 years ago. If you make the definition of oil broad enough you can flow anything and call it oil and declare any estimate you want of what is underground.

              So how could anyone estimate reserves when the total is dependent on technological recovery capability (which changes), price (which changes), and definition of oil itself (which changes).

              From a geology perspective, you have rock and that rock has porosity and it has permeability. The first parameter tells you how porous the rock is and within each pore there might be liquid. You have to take a core sample to measure what that liquid is. It could be ancient water or it could be oil or a mixture. The interconnectedness of those pores is called permeability and it determines how easily the liquid will flow from one area of the rock to another (where you drilled your well).

              If it’s easy, you won’t need much price. If it’s not easy, you might need more price. And if someone just gives you money, you don’t really even need price.

              The point being that a reserves estimate is dependent on all of these things and most of them are unknown.

          2. Im a bit surprised that nobody commented on the Ghawar well in the image i posted perhaps im reading to much into it?

            If original production was 15600 boepd in that top well and in 2008 same well was down to 2100 boepd isnt that a pretty strong indicator that at least that section of Ghawar is more or less depleted.

            1. This undersection is depleted.

              There are other wells now, in other regions of the 3D structure of the field that produce. The field still produces 3.7 mbd.

              Think of this field more as old conventional Texas – if one well stops producing this doesn’t mean anything.

            2. “This undersection is depleted.”

              Yes that was my point.

              “The field still produces 3.7 mbd”

              We actually dont know what it produces it was something like “up to 3.8mbd capacity” in the bond prospectus if i remember correctly, i would not bet my life on that being the actual daily production now. (or even before the attack)

              I think the northern parts are done and now it will be on a quite long plateau from the southern parts that was put into production later since the geology wasnt as good as in the north.

              Saudis resources have not declined officially, yet they are now forced to produce from worse and worse geology like everybody else in the world.. perhaps magic oil is just magic on paper.

            3. Baggen,

              Not sure two data points from a single well is representative.

              Seems we do not have enough data to make a judgment.

            4. I think we can conclude that wells start to produce less oil over time since there is less oil left and the produced liquids starts to contain more and more of other stuff water etc.

              If i were to compare to a company i am familiar with Lundin Petroleum and their Edvard Grieg field. The field has now produced on plateau years longer than first expected and it took 1-2 years longer then expected before first minor water signs in production. In other words reservoir was larger then initially expected. But over time the top wells in Edvard Grieg will start to go same as any other well and produce say 20% of what they did steadily for the first 2-3 years.. since capacity will start to fill with the water, its a sure sign that the reserves are running out the more water you pump originating from your pressure support injections.

              I would say you were correct if the well were positioned at the bottom of the reservoir close to early water injection but this Ghawar well is the top dog or was at that time, i would bet the best well is positioned in the very top of the reservoir in the best geology.

              There is no logic in the best well being positioned in an inferior position, then it would not be the best producer.

              Its not two data points from a random well, its two data points from THE BEST well, i say thats a pretty strong indication on whats going on in the northern part. As Ron posted above its probably converted to a horisontal today and i have the same opinion.

            5. Baggen,

              As before, if your assumptions are correct, your logic follows. We don’t really know if this is the “best” well, information is very limited. I certainly would agree north Ghawar produces less today than it did at peak, probably between 25% and 50% of peak.

              For the field you are familiar with, am I reading your comment correctly suggesting the field now produces 20% (or less) of peak field output. Perhaps North Ghawar is similar (or less as the field has been producing much longer).

              Of course with the data we have this is pretty speculative.

            6. Dennis,

              Well it seems logical to me that the well put in top of the reservoir in the best section of the field will be the best producer especially if the data we do have suggest that is the case.

              I posted some images here: https://aktiertips.se/northern-ghawar-water-and-production/

              instead as i could not bare trying to get trough that hassle here again :P, trying to visualize what my belief is and call it a gut feeling as ofc until saudi gives official info we wont know for sure.

              No that 20% was just ment as an example, it was poorly worded by me i realize reading it now again, i just ment to say the destiny for all fields is decline and death. Edvard Grieg is still producing on plateau several years after initial decline was expected and wells still have higher capacity than the production facility even after bottleneck reduction.

        3. Here is an excellent article, from 2016, that helps explain a lot concerning Saudi reserves>

          Saudi Arabia’s oil reserves: how big are they really? Kemp

          Saudi Arabia began reporting to OPEC that its “proved” reserves stood at around 168-170 billion barrels of crude oil.

          The Saudi figure was much higher than the 110 billion barrels of proved reserves reported by the Aramco partners a few years before.

          But it was very close to the figure for possible reserves that the Aramco partners had reported to the U.S. Senate.

          That raised the question if the Saudis had chosen to increase their reported reserve base by reporting probable reserves as proved reserves.

          In 1988/89, the proved reserve figure jumped again to 260 billion barrels despite no major new discoveries. (tmsnrt.rs/29fzTm3).

  41. A Death Sentence For Small Oil & Gas Drillers

    By Tsvetana Paraskova – Oct 28, 2019, 1:30 PM CDT

    Some of the largest banks financing U.S. oil and gas drillers have recently reduced their expectations for oil and natural gas prices, determining the value of companies’ reserves and loans that they can take against those reserves.

    Wells Fargo, JP Morgan Chase, and Royal Bank of Canada, among others, have reduced the value of reserves of oil and gas companies, according to more than a dozen banking and industry sources familiar with the borrowing base redeterminations.

    The value of reserves estimated by banks serves as the basis for many small oil and gas firms to get funding for their drilling activity and operations. And in recent months, in many cases, this is the only source of funding that many of them can get because the equity and bond markets are practically closed for small oil and gas firms right now.

    With the lowered value of reserves, drillers now face an even more restricted access to capital than in previous months.

    In the fall 2019 survey carried out in September by Haynes and Boone, for the first time since 2016, the majority of respondents expected borrowing bases to decrease in the redetermination season this month.

    According to Reuters’ sources, the banks have cut their expectations for both natural gas and oil prices compared to the previous redetermination season this past spring. Natural gas price forecasts were slashed by around 20 percent, which industry sources say would mean a 15-30 percent cut in the size of loans.

    Banks now see natural gas prices at US$2.00-2.35 per million British thermal units (MMBtu) over the next 12 months. Oil prices are now US$1 to US$2 a barrel lower than estimated in the spring redetermination, according to the Reuters sources.

  42. RESTRAINT CAME ‘TOO LATE’
    https://www.channelnewsasia.com/news/business/investors-brace-for-poor-us-shale-earnings-amid-weak-oil-and-gas-prices-12040906

    Halliburton and other hydraulic fracturing providers have taken 100 U.S. fracking fleets that complete oil and gas wells off the market, “with a portion of that to never return,” consultancy Primary Vision wrote last week.

    “We expect 2020 (spending) plans to be focused around maintenance capital,” or spending that supports existing output, said Bernadette Johnson, vice president of market intelligence at consultancy Enverus.
    Among major shale producers, EOG Resources is forecast to report per share earnings of US$1.13, down from US$1.75 a year earlier. Pioneer Natural Resources Co could post earnings of US$1.98 per share, down 9 cents, according to Refinitiv IBES.

    Continental Resources is projected to earn 47 cents per share, down from 90 cents a year earlier. Its shares have fallen to about US$29.16 from roughly US$54.15 a year ago.

    “People are ignoring shale names now and they’re sort of disgusted with them almost,” said Rohan Murphy, an analyst with Allianz Global Investors in London, adding that their push for capital discipline came “almost a bit too late.”

    1. Tony,

      I respond if someone addresses me, that is part of it. I will not, if that is what people prefer.

      Fewer comments in future.

        1. Thanks everyone,

          Estimate of Texas C+C by Dr. Fantazzini. Thank you.

          1. Denise ,your comments are appreciated . They are not hot air though sometimes not correct ( I did not say not true) . keep up the good work .Greatly valued .
            p

    2. Dennis is even tempered, always brings facts, graphs, sources. I’d rather have an active moderator than a forum that devolves into madness of name calling and venting.

    3. If I thought Dennis was making too many comments and worthless comments, I would hide them. I have chosen not to.

      He definitely adds to the discussion even if we don’t always agree with his conclusions.

      1. Thanks for all the kind words.

        Absolutely correct that I am not always correct. I throw out different future scenarios to get feedback on how they might be improved, the models match history pretty well giving some measure of confidence that if reasonable assumptions about the future are made we might have a reasonable model of what the future might look like (if all assumptions were correct).

        Obviously it is not possible to make “correct” assumptions about the future based on simple statistics. There are an infinite set of possible variables that will affect the future, each of which has an infinite set of values that might be assigned to each variable. Odds of success (a correct scenario) are very close to zero.

        My models typically have 2 to 4 key variables with perhaps three “reasonable” values chosen for each of the variables, typically a low and high value for each and some intermediate value. The best I could possibly do is constrain the infinite set of possible future scenarios with a lower and upper bound, perhaps capturing 90% of the set of reasonable possible futures.

        Where comments from the highly intelligent set of people who regularly (or occasionally) participate here can help improve these scenarios is by pointing out better or “more reasonable” assumptions about the future. We all understand that no future scenario could be “correct”, we simply do not know the future. As many astute observers have pointed out, the real World never works as “modelled”, I agree 100%.

    4. Because he has lot of models, and every model refers to alternate future. It may be interesting, but it is also the subtle perversion of mathematics, whose beauty lies in the offer of one, right answer.
      Common people tend to associate mathematics with certainty and knowledge, but it is definitely not the case here.

      Well, my impression of reading Dennis is like: ‘if you consider my models N347 and N379, I may be more wrong, but if you consider my models N248 and N422, I may be more right. However, there has been also a model N156 which I don’t consider anymore, but once did, and it says….’

      I wish the oildrum would be alive, too.

      1. OneofEU,

        Me too.

        Perhaps those who would prefer the Oil Drum can find an alternative.

      2. OneOfEU said

        “It may be interesting, but it is also the subtle perversion of mathematics, whose beauty lies in the offer of one, right answer.”

        Last I heard, probability and statistics was part of mathematics. Many answers are given in probabilistic terms, see for example statistical mechanics and quantum mechanics.

        And there is never a right answer for economics, as that is subject to the intractability of game theory. Therefore to merge geology and economics, the best one can do is provide projections given certain assumptions.

        1. Nevertheless, most of the people do not understand that the truths of probability and statistics lie only in the third realm of Frege. I mean, it is the question of their ontological status, Mr Pukite.

          1. OneofEU,

            Perhaps a blog focused more on philosophy, generally there are as many philosophical viewpoints as there are philosophers. Epistemology and ontology are subjects not well understood by anyone including philosophers. Those who think they understand have not read enough, the rabbit hole is quite deep there.

            2. Doyou really want to confirm the old cliché about Americans parading their love of ignorance…?!

              BTW, Frege WHO
              Mathematics is inherently joined to philosophy since its beginnings.

  44. A shot at Gehwar… in 1980 estimate (vertical wells only) 70Gbarrels. To date about 75G produced. Difference? Post 2000 horizontal wells… how much left. At current levels 2.5mb/day rather than 5mb/day… not much… so 80G total…

  45. Saudi Arabia is $3.4B behind on its payments for Canadian LAVs

    It looks like the Saudi military is running low on cash:

    Saudi Arabia still owes about $3.4 billion in late payments for Canadian-produced Light Armoured Vehicles (LAVs), according to the latest quarterly financial results released by General Dynamics last week.

    General Dynamics said in its quarterly earnings report that the late payment amounts — totalling $2.6 billion US, or roughly $3.4 billion Cdn —will be billed to the Canadian government “in accordance with the agreed-upon contractual terms.”

    David Perry is vice president of the Canadian Global Affairs Institute, an independent foreign policy think-tank. He said the problem with late payments has been known for a while — but experts were surprised by their sheer scope of the unpaid sum.

    1. There appears to be some political stuff surrounding this situation. The contract was about 12 billion dollars for GD’s Canadian subsidiary to build LAVs for Saudi Arabia. The previous Canadian PM approved the deal and the current Canadian PM has not reneged.

      Blah blah Yemen blah blah Khashoggi there is Canadian talk about canceling with some big number of jobs lost. KSA has some incentive to create embarrassment for the Canadian political folks who challenged their human rights blah blah. There’s not really any doubt that Saudi Arabia will get their vehicles so it doesn’t really matter if Canada wanted to posture themselves in some moral superiority.

      GD would certainly scramble to have them built somewhere else. Might even offer the workers a transfer out of Canada.Tax revs go with them.

      So if the subtext here is that the Saudis loss of production from the missile attack is creating a difficulty in making payments, that subtext is probably wrong. Other stuff is going on.

      1. Here is the real story.

        The Cdn foreign minister tweeted that SA should release some jailed Canadians immediately. That really annoyed SA and they pulled student doctors from Canadian schools, suspended flights and ceased all trade. The press and journalists suggested suspending the Cdn contract to supply SA with LAVs. That would mean a huge loss of jobs. The govt is squeezed. So they keep making LAVs, ship them to SA, and I think SA is saying, TRY TO MAKE US PAY. Not sure how it will end. Removing student doctors affected many hospitals. To many, SA reaction seemed excessive.

        Students Scramble For Info After Saudi Arabia Pulls Canadian Scholarships
        The move could affect more than 15,000 students.

        8 Aug, 2018
        Universities across Canada are scrambling to get information after Saudi Arabia suspended scholarships to Canada and planned to relocate its students already in the country.

        State-run television has reported that Riyadh will stop training, scholarship and fellowship programs in Canada — a move that will apparently affect the scholarships of more than 15,000 students attending university in Canada.

        Montreal’s McGill University says it is actively working with its partners to gather information and assess the impact of the move on institutions and individual students alike.

        It says there were 327 students from Saudi Arabia at McGill during the 2017-2018 academic year.

        McGill University in Montreal, Quebec. Some 327 students from Saudi Arabia were enrolled at the university…
        Steven Kriemadis/Getty Images
        McGill University in Montreal, Quebec. Some 327 students from Saudi Arabia were enrolled at the university during the previous academic year.
        The University of British Columbia says its president, Santa J. Ono, is working to clarify the situation and determine how many current and incoming UBC students might be affected.

        York University, meanwhile, says 115 Saudi students are currently enrolled at the Toronto university and that it is also awaiting further information.

        Also on Tuesday, the gulf between Ottawa and Saudi Arabia widened to encompass travel as the Middle Eastern country’s state airline announced it was suspending operations in Canada.

        A tweet from Saudia announced its routes operating between the two countries would cease to function in a matter of days, marking the latest escalation in the spat that erupted over the weekend.

        “All Saudia flights from/to Toronto, Canada will be suspended starting from 13 Aug 2018,” the airline wrote in a statement posted on Twitter.

        The airline currently operates at least two routes flying out of Toronto’s Pearson International Airport — one to the Saudi capital city of Riyadh, the other to the city of Jeddah.

        Transport Canada did not immediately respond to a request for comment on the development.

        The airline’s announcement comes amid newly surfaced tensions between Canada and Saudi Arabia triggered by Ottawa’s criticism of detentions in the kingdom.

        Saudi Arabia stunned officials on Sunday by announcing it was suspending future trade with Canada and severing diplomatic ties. It recalled its envoy from Ottawa and gave Canadian Ambassador Dennis Horak 24 hours to leave the country.

        Any other attempt to interfere with our internal affairs from Canada, means that we are allowed to interfere in Canada’s internal affairs Statement from the Saudi Foreign Ministry following a tweet issued by Global Affairs Canada

        The dispute ostensibly arose because of a tweet issued by Global Affairs Canada decrying the arrest and detention of two female bloggers and activists.

        “Canada is gravely concerned about additional arrests of civil society and women’s rights activists in Saudi Arabia, including Samar Badawi,” the tweet said. “We urge the Saudi authorities to immediately release them and all other peaceful human rights activists.”

        The Saudi Foreign Ministry took exception to the use of the term “immediately release,” calling it “unfortunate, reprehensible, and unacceptable in relations between states.”

        More from HuffPost Canada:

        Bill Morneau: Canada Will Continue To ‘Enunciate’ Values Despite Saudi Feud
        U.S. State Department On Saudi Arabia-Canada Spat: We’re Staying Out
        Saudi Arabia’s State Airline Saudia To Halt Flights To And From Canada
        “Any other attempt to interfere with our internal affairs from Canada, means that we are allowed to interfere in Canada’s internal affairs,” the Saudi government said.

        Amnesty International has said Badawi, the sister of jailed blogger Raif Badawi, was recently detained along with Nassima al-Sada, another prominent female activist.

        Foreign Affairs Minister Chrystia Freeland stood by Canada’s position on Monday, saying Canadians expect their government’s foreign policy to be guided by their values.

        “We are always going to speak up for human rights, we are always going to speak up for women’s rights and that is not going to change,” Freeland said in Vancouver.

  46. The Shady Truth Behind The Aramco IPO Bold mine:

    Leaving aside for a moment the enormously troublesome state of Aramco – as analyzed in depth here by OilPrice.com – making a couple of phone calls and not just taking someone’s word for it would have revealed a litany of problems in the ‘Saudi to recover quickly’ angle. For a start, both Moody’s and S&P’s statements at the time – but especially S&P’s – seem to echo the very line of Saudi Arabia’s new oil minister, Prince Abdulaziz bin Salman, just after the attacks. He stated that the Kingdom planned to restore its production capacity to 11 million bpd by the end of September and recover its full capacity of 12 million bpd two months later. As a number of analysts told OilPrice.com at the time, it was extremely telling that he spoke of ‘capacity’ and later of ‘supply to the market’, as these are terms that Saudi tends to use in order to avoid talking about actual production, as capacity and supply are not the same thing at all as actual production at the wellheads. Moreover, veteran oil sector engineers stated clearly at the time – and continue to state – that following an incident like the 14 September attacks, it would take several weeks just to assess the damage, never mind to begin doing anything about it, rather than the few days that the Saudis took.

    The oil minister’s comments – and those of Moody’s and S&P – also alluded to the completely fictional production capacity and corollary spare capacity figures that Saudi Arabia has been seeking to establish as truth for years to anyone too stupid and/or lazy to delve into the details. The country has stated for decades that it has a spare capacity of between 2.0-2.5 million bpd, implying – given actual production during virtually all of this time averaging less than 10 million bpd – total production capacity of 12.0-12.5 million bpd. This level, though, or anywhere near it, has never been even remotely tested, with the highest production ever recorded being just over 11 million bpd in November last year. This is despite the all-out oil price war that Saudi started in 2014 against U.S. shale producers to try to destroy the industry through low prices caused by flooding the markets with oil. Clearly, if the Saudis had anything near 12 million barrels per day capacity, then that would have been the time to pump it but all it managed was just under 10 million bpd with 10.5 million bpd managed for just one month over that two-year period (2014-2016) before Saudi reversed it strategy).

    There is a lot more to this article than the two paragraphs quoted above. It is my suspicion that the ARAMCO IPO is all about the dwindling production capacity of the company. They see the accelerating decline rates of their fields and want to milk a lot of cash from stupid investors who are totally unaware of what is really happening.

    2. Listing the IPO in Riyadh (and at a stake that precludes anyone getting power at the board level) is a giant red flag that something is wrong here. The NYSE actively wanted this listing, as did London. If Aramco had something good to sell, it makes no sense to not list a bigger stake in magnitudes bigger capital markets and raise much more total money. People want yield BAD (hell I want yield), it should be easy for Aramco to raise money this way. But they pulled it in favor of listing where there are no independent regulators.

  47. Denmark approved the Nord Stream 2 traverse of its territory about an hour ago. Unless the EU can manufacture some other obstacle, that was the last one holding up completion.

    That’s the end of European LNG consumption from the US, excluding some small, rabidly anti-Russia consumers.

    1. And how is the Power of Siberia doing, and the Altai pipeline?

      Russia resource basis is declining – all biggest fields, Ghawars of gas, are in decline.
      New Russian fields, with high condensate share, are so expensive that may come close to LNG price.
      Russia has already increased its gas import from Turkmenistan to fulfill its obligations.

      Nord Stream 2 is not to increase export capacity but to sidestep Ukraine. Russia pipeline transit contract with Ukraine ends with the end of this year.

      https://thediplomat.com/2019/04/russia-is-buying-turkmen-gas-again-why/

      ‘There’s no official statement on the volume or price agreed between Turkmenistan and Russia earlier this month.’
      Meaning: Turkmenistan will make up for Russian shortage, will get some kind of spot price.

      1. https://www.rferl.org/a/russia-gazprom-turkmenistan/29883131.html

        Who would have know that Turkmenistan was a well-hidden paradise of free utilities….
        UNfortunately, all things good have their end…

        ‘A year ago, Turkmen President Gurbanguly Berdymukhammedov ended a quarter-century-long practice of providing free natural gas, electricity, and water to residents in Turkmenistan in efforts to save money.’

  48. Fracking fleet equipment is not only being idled but now some equipment is being scrapped.
    https://www.rigzone.com/news/wire/frackers_scrap_idled_equipment_amid_shale_drilling_downturn-30-oct-2019-160198-article/

    About 2.2 million horsepower, or roughly 10% of industry capacity, already has been earmarked for the scrap heap, according to Scott Gruber, an analyst at Citigroup Inc.

    Estimates for total U.S. fracking capacity vary but Bank of America Merrill Lynch puts the figure at almost 25 million horsepower. Just 13 million of that is forecast to still be at work during the final months of this year, down from 17 million during the second quarter of 2018, according to Bank of America’s Chase Mulvehill.

    1. Eia monthly for August should be out tomorrow. GOM should be up around 230 kbpd bounce back after Barry reduced July a comparable amount. Lower 48 onshore should also be up some because of the new pipe from the permian in August. The average of total production per the weekly reports was 12,360 kbpd, an increase of 554 kbpd over July reported production of 11,806 kbpd. Declining rig and frac counts will start to bite soon, but not this month.

      1. Tita,

        I agree. From shaleprofile:

        Upward revisions for the summer months were relatively large in the production data that the RRC released last week. Based on the latest actual data, May production in the Permian (including New Mexico) was already at 3.5 million bo/d, which will increase further once all revisions are in. July, also shown here at 3.5 million bo/d, will probably be revised even more (as is common for more recent months), to around 3.7-3.8 million bo/d eventually.

  51. We are definitely past peak at this point. Everything is pointing down for shale:

    https://www.worldoil.com/news/2019/10/30/idled-frac-fleets-sold-for-scrap-amid-shale-drilling-slump

    It’s over. Dennis will find that his charts are about to take on a severe dent in the downward direction, as I often said would be the case. Investor money in shale, alas, is not bottomless…there is a limit to it and that limit is occurring now. Shale was always a very expensive proposition and was, as Art Berman used to say, a retirement party for the oil industry.

      1. The educational level somewhere between truck driver and bartender with a degree from Trump University

  53. https://www.eia.gov/petroleum/production/
    Seems like US December 2018 the growt of US shale signifocant startet change path to a much slower growth. Since that it seems the path have been mostely unchanged with some bumps on the way. From the graph of US oil production it seems from 2011 growth was significant and increased from 6000 kbpd to about 9000 than in 2015 it started decrease as a result of collapse in oil price and in 2017 production have falled to about 7500 kbpd , than followed a period with very strong growth unthil end off 2018 at about 12500 kbpd. From December 2018 and so far it seems the growth rate is reduced by 50% compared to the period of very strong growth 2017- 2018. It is even lower than the period 2015-2015. Based on reduction off drilling Riggs , development in Frack Spread , information regarding manpower, empty hotells , strong reduction in DUCs ( where I guess the one with highest profit potential is used first) all signs shows US oil production will reach a top next year if WTI remains at 50 usd range. There is eighter no sign based on comparing data 19.06 , 19.08 that the pipeline constraint so far have changed anything with the path of US shale perhaps it might convent a higher slowdown or decline so far.

    1. Freddy,

      So far tight oil output in the US through Sept 2019 continues to increase. I agree the rate of increase is much lower probably 700 kb/d for annual rate vs 1250 kb/d in 2018. The rate of increase will gradually slow to zero, when it arrives at that point will depend in part on the price of oil. Low price sooner, high price later, medium price (rising to $80/b by 2023) it may be roughly 2025.

      1. Dennis, I agree to your outlook but it might be 80 usd WTI will be to high. It is at least exspected a increased glut of oil in 2020 but a trade agreement with China might offset some of this. I believe from 2021 we will se US oil production will be much more depending on oil price as the majours like Exxon, Chevron will focus on cash return from investment instead of growth. It will be interesting to see the Q3 earnings from both Exxon and Chevron that shall be issued today and compare this with oil majours that not are focus on US shale. Will the stock owners be happy for the result or will the stock value fall to the ground if that is the case they might revice their investment plans in US shale and this will impact how fast we see peak in US production and future decline rate.

  55. Now the 3Q 2019 result for Exxon is released and show a profit for the quartile of 3.2 bill usd and in the same quartile they sold assets in Norway wurth 4.5 bill. Guess than actualy they loosing money. Compared to 3Q 2018 their profit is down 49%.
    If you look at Earnings US 3Q shows 37 bill usd and 2q was 355 bill . That reduction is 90% !!!.
    If you look at earning US /abroad that is 37 bill / 2131 bill. Will be very intetesting to see how much stock will plunge but I believe they focus on income from Guyana will pay the bills in future…
    https://corporate.exxonmobil.com/

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