The Future of US Light Tight Oil (LTO)


The future output from the light tight oil (LTO) sector of the US oil industry is the subject of much speculation. Above I present some possible future output scenarios based on a simple model of US LTO, the scenarios are compared with the EIA’s 2017 Annual Energy Outlook (AEO) reference scenario with cumulative output of 82 Gb from 2001 to 2050. The cumulative output of the model scenarios is for the same period (2001-2050).

The models all use the same well profiles from 2006 to 2016 and are based on data gathered from Enno Peters excellent blog, A preliminary hyperbolic profile was fit to the average LTO well data and then the parameters were fit using least squares and solver in Excel so that the model matched the data for output and number of wells added each month over the period from 2011 to 2015. The data for 2016 is incomplete and this leads to an under report of wells added for most of 2016 (from March through October). For this period the wells added were adjusted so that the model matched the output data from the EIA (which is more complete than the data reported at

The well profiles used are shown below, two were used, a lower profile for the early period and a higher well profile for the later period. The vertical axis is output in barrels per month and the horizontal axis is months from first output.


The well profile in red (219 kb) is the basis for all the scenarios. In every case it is assumed that the estimated ultimate recovery (EUR) or total output from the well over its life starts to decrease in Feb 2017, but the rate of decrease varies from model to model, based on underlying assumptions and the number of new wells added each month.

The 36 Gb, 44 Gb, and 60 Gb scenarios use the oil price scenario in the chart below along with $6 million well cost, transport, OPEX, and other costs of $13/b (combined), royalties and taxes of 27%, an annual discount rate of 10%, and down hole maintenance costs of $42,000 per year, all dollar figures are in constant 2016$. A discounted cash flow analysis suggests these wells would be profitable on a point forward basis under the above assumptions and the oil price scenario below. The 50 Gb scenario would require higher prices as the EUR decrease assumptions for that scenario are identical to the 44 Gb scenario (profitability was not considered when constructing the 50 Gb scenario.)


The maximum rate that new wells were added for the 36 Gb scenario was 870 new wells per month after June 2021 (the completion rate was below this from Jan 2017 to June 2021). For comparison I show in the chart below for all 4 scenarios the annual rate of decrease in new well EUR when 870 wells are completed (the rate of decrease of EUR will vary depending on completion rate).


To evaluate the probability that any of these scenarios might be realized I considered a maximum entropy probability distribution, which only requires that we assume that the probability distribution has a mean.  It can be shown for this case that the lowest information (or fewest assumptions) coincides with a negative exponential probability distribution whose probability density function(pdf) has the form


where x is a number greater than or equal to zero and a is a positive constant.
x in this case represents the URR and 1/a is the mean URR or the expected value. The cumulative distribution function(cdf) has the form


I assumed 1/a=60 Gb and the cumulative distribution function is shown below. The curve represents the probability that the URR will be less than the value on the x axis.


My reason for choosing a mean of 60 Gb was that the EIA clearly thinks the likely value is about 80 Gb, my estimate is about 40 Gb based on USGS estimates of 24 Gb for the Permian and 10 Gb for the Bakken/Three Forks and an assumption that Eagle Ford and other LTO plays will produce at least 6 Gb combined. The 60 Gb URR is just the average of these two estimates.

I also assumed based on about 75,000 wells completed through Dec 2016 that at least 15 Gb will be produced from the LTO plays in the US (8 Gb have been produced so far). So my probability distribution is for the 45 Gb yet to be produced and then 15 Gb is added back.

Based on this analysis there is a 33% probability that the URR will be between 33 Gb and 64 Gb (with a 33% probability that URR will be above this range and a 33% probability that it will be below this range.) This range is fairly close to the 36 Gb (37% probability that URR will be lower) and 60 Gb (37% probability that URR will be higher) scenarios. A URR of 46 Gb has a median probability with a 50/50 chance the URR will be higher or lower than this. An intermediate estimate between the mean and median is 53 Gb which has a 57% probability that the URR will be lower.

For this reason my best guess for US LTO URR is between the 44 Gb and 50 Gb scenarios, as the average of the two (47 GB) is close to the median (F50) probability estimate. Finally, there is about a 50% probability that the URR will be between 28 Gb and 77 Gb, with a 25% probability that it might be above or below this range.

A number of side cases are presented below without much comment, note that total wells in these charts includes the 75,000 wells already drilled through Dec 2016 and that in all cases the decrease in new well EUR begins in February 2017.












The 15 Gb model assumes no wells are completed after Oct 2016.


Note the estimate for 616,000 wells to reach 82 Gb by 2051.  Also the spreadsheet was only set up to go to Oct 2041 so the steep decline in 2041 is due to no wells being added after that date another 200,000 wells added from 2041 to 2050 might allow another 13 Gb to be produced, note the low productivity 65 kb per well from 2041-2050 vs 167 kb/well from 2001-2041.


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226 Responses to The Future of US Light Tight Oil (LTO)

  1. Euan Mearns says:

    Global Energy Graphed

    We have now graphed the WHOLE of the BP stat review. Knowledge is power 😉 On Monday a post on the Export Land Model.

    • Nathanael says:


      The solar and wind energy curves are with a couple of exceptions consistently exponential. The largest-deployment countries are unsurprising as basically the wealthiest countries are putting in the most.

      Iran’s huge wind deployment in the Middle East vs. pretty much no wind anywhere else, and very little solar in Iran, is an oddity, though — do they have a domestic wind turbine business or something?

  2. February 2017 update of EIA’s Monthly Energy Review with November 2016 data.

    How US shale oil sits on top of the ROW in my latest incremental crude production graphs. Except for Iraq, OPEC’s production 2016 was at the same peak level as in 2005

    • Survivalist says:

      I like your stacked graphs Matt. Thanks for doing that. It looks like Iraq and North America are the only game in town.

    • AlexS says:

      “Except for Iraq, OPEC’s production 2016 was at the same peak level as in 2005”

      What if we include Iraq, but exclude Libya?

  3. Boomer II says:

    This could probably go into the previous post about petroleum, but I will put it here.

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

    • George Kaplan says:

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

      He concludes:

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

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

      • Boomer II says:

        In reference to oil sands. This article came about a week ago.

        Have The Majors Given Up On Canada’s Oil Sands? |

      • Boomer II says:

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

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

      • Stavros H says:

        I mostly agree with what you are saying but I would add one more thing. The decline in costs is not just cyclical, it’s also a function of the initial bust that left tremendous spare capacity to the suppliers of oilfield services and drilling equipment. Moreover, projects like shale, tar sands and ultra-deep water can only be financed under the current negative interest rates environment.

    • The title should be “cost per barrel developed increase 66%”. Adjusting for inflation we see that each dollar develops about 70% of the oil it did before. This is reasonable when we consider deep water developments don’t have such good wells anymore, and that other areas are mostly limited to pounding increasingly poorer reservoirs or implementing EOR in known fields.

    • Nathanael says:

      Yeah, I’m not interested in volume at this point, I’m interested in production price. I’m reading a lot of stuff which says that everyone but the old conventional fields goes bust under $40/bbl.

      • Dennis Coyne says:

        Hi Nathanael,

        It will take time to reduce oil demand. It will not happen overnight, it will take 15 years at least before demand falls due to expanding sales of EVs and greater use of rail and expansion of electrified rail. At some point “peak demand” may become a reality, but not until after 2030 or so, remember that output will fall and quantity of oil demand will have to fall by more than output in order for oil prices to fall. Until that occurs the oil price in the long term will be determined by the marginal cost of oil (cost to produce the most expensive barrel).

        • Lloyd says:

          Hi Dennis.
          I think the concept of demand destruction in this context is unlikely. A quick thought experiment (and I apologize to anyone I may be cribbing from):
          You are an oil producer.
          You find your current transportation fuel market in the developed world destroyed by electric cars, public transit, staying home etc., or some other factor.

          Do you stop producing oil? I don’t think so.

          You sell to poor countries without electric infrastructure, and where debt financing for renewables is impractical: places where liquid fuels can gain market share right away. Places where generators, jitneys and small tractors allow people to profit even from expensive fuel.

          If they can’t afford tractors and jitneys, you sell them below cost: sell the blades, not the razors.

          All the hydrocarbons will be used, because someone, somewhere, will find a way to make a profit from it. Until we hit negative EROEI (and probably 5 or 10% beyond that point, because of hysteresis), oil will be produced. As Watcher says, if we don’t use it, some peasant in China will.


          • Boomer II says:

            If your oil is already flowing and you can afford the operating costs, you keep producing. But investing in new production might slow down because those would require extra costs.

            I don’t think anyone expects oil to disappear any time soon, but if it is unprofitable to produce it and there are no willing companies or investors to cover the loss, it likely won’t happen.

            Also, China is targeting those Third World markets. It’s financing electricity production there plus producing electric vehicles, so it may aggressively capture the market faster than marginal oil producers.

            • Lloyd says:

              Hi Boomer.
              Also, China is targeting those Third World markets. It’s financing electricity production there plus producing electric vehicles, so it may aggressively capture the market faster than marginal oil producers.
              I suspect that there will always be someone poor enough to make legacy fuels and technology profitable (at least until EROEI of less than one.) It takes weeks to months to provide an unserved population with, say, Gasoline and chainsaws, and the initial investment is much lower than the debt load to install solar. From a financial risk standpoint, it’s better to get the money up front (or net 30) for an oil shipment than to mortgage a solar array to someone in a precarious situation with very little money. My bet is on the ICE guys staying in the market (though I do feel kind of like General Turgidson in the War Room talking about the odds of that last B-52 getting through. )


  4. George Kaplan says:

    For LTO it’s interesting how EagleFord are piling on rigs (5 more this week) and the permitting seems to have increased dramatically, whereas the Bakken is steady to maybe slightly down, certainly for permitting at the moment. I don’t know where the difference for this is and I expected the opposite, but it seems EIA knows something as their predicted flattening in the EFS decline rate is looking pretty likely know, while Bakken is looking increasingly weary, with only the outstanding DUCs as a big potential source of new oil.

  5. clueless says:

    During the past 2 years, there has been a tremendous amount of great quality work concerning the economics of onshore LTO production. Much of it has been done by those who post here.

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

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

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

    • Dennis Coyne says:

      Correct that land cost is not included. I don’t know what that is. This based on Rune Likverns analysis from the oil drum.

    • Mike says:

      Successful efforts accounting methods, as opposed to full cost, are preferred by the shale oil industry because, in my opinion, it helps distort the economic picture and makes them look better than they actually are. Hardly ever is lease acquisition costs (lease bonuses), land work, curative title work, geophysical or infrastructure costs (upstream to midstream gathering systems) used when quoting well costs to the public. This might help answer your question in the Permian:

      • clueless says:

        Thanks Mike! That was good information and a good article.

        • shallow sand says:

          Clueless. If you really want to see the true economics of these Hz wells, I suggest you set up an account with There you will find, over time, working interests for sale in every unconventional basin.

          There is no charge to set up an account. I used to bid on and buy royalties through energynet. Royalties now sell way high IMO. Good for sellers.

          There you can see, for example, how a poor soul who leased an undivided 1/4 interest in a 40 acre tract in CLR’s Poteet High Density Unit was AFE’d over $1 million as a result, how it costs as much as $2.50 per BW to truck haul produced water in the Permian Basin, or how it cost over $600K to pull an ESP and convert to beam pump one of EOG’s famous Parshall wells in the Bakken.

          Lots of facts there. Actual AFE’s on company letter head. Check stubs. Joint interest billings. Lease operating statements. Production histories.

      • Dennis Coyne says:

        Hi Mike,

        I made two modifications to my assumptions:
        a. Well cost increased to $7 million to reflect full cycle costs (increase of $1 million per well)
        b. Oil price increases to $100/b by Sept 2020 and then rises linearly to $150/b by 2030 and remains fixed at that level.

        Clearly I don’t know future oil price, but without using some price level one cannot evaluate the economics. An assumption of prices fixed at current levels from now until 2050 would result in no new wells added after March 2017 and maybe 15 to 20 Gb total cumulative output for US LTO to 2050. For the scenario above (prices reach $150/b in 2030 (2016$) and rise no further it is a URR of 37 Gb as in chart below.

      • Dennis Coyne says:

        Hi Mike,

        So $9.3 million per well. Wow. Also note that in their NPV calculations they did not include royalty or tax burdens, they probably left out transport cost, interest costs, and downhole maintenance. Another problem is that they include natural gas output and convert to BOE, this should be ignored because BOE in natural gas generated very little income at current natural gas prices, though this revenue can offset a couple dollars per barrel of OPEX.

    • texas tea says:

      With respect to the parameters in your question:

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

      I would say in OKLA the EUR is much to low by a factor of 2-4 for a single horizon, in other words a ~100 acres can be expected to produce any where from 400,000 to 800,000 BO and can have 3 or more productive horizons each capable of those types of production numbers. So for example a ~100 acres can produce 1,500,000BO or more. Current density plots indicate 113 acre drainage will be achieved with a 7500′ lateral with 660′ between wells. A 10,000′ lateral would be 151 acres. I can also say, because of government interference, “forced pooling” the average leasehold cost is something under $2000 an acre. Leasehold cost are usually added to the first producing well as part of the “full cycle” cost and are a one time expense. Any given unit may ultimately have 10-15 wells. Once the Unit is HBP and the primary term of the leases have expired the full land cost will have been expensed.
      My oldest well LTO well in SCOOP has produced over 300,000 barrels of liquids from approximately 51 acres.

      • clueless says:

        Thanks TT! Since I live in OK, your information appears to be very positive information for OK – which currently is in a poor economic environment due to low oil [and gas] prices. However, based upon your information, why, in your opinion, has this OK play not attracted nearly as much “hype” as the Permian [or Baaken or Eagle Ford]? Is the long-term potential [ultimate oil to be extracted from the entire play] much less?

        • AlexS says:


          Current active oil and gas rig count:

          OK: 98
          Eagle Ford: 69
          Bakken: 38

        • Boomer II says:

          This recent analysis says: “Breakeven analysis of SCOOP and STACK shows underwhelming results compared to other major oil plays.”

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

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

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

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

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

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

          • AlexS says:

            Boomer II,

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

        • Mike says:

          Forced pooling in Oklahoma is over 80 years old. It was made law by the Oklahoma legislature in 1935 in conjunction with well spacing requirements that promoted conservation practices.

          Conservation of America’s remaining resources has been completely abandoned by most states in desperate need for tax revenue. This benefits a greedy LTO industry, of course, where in parts of the Eagle Ford resource play, for instance, some operators can now drill 6 1/2 -7 1/2 million dollar wells on 40 acre spacing, where lateral toes are only 330 feet apart. Wells communicate with each other before and after frac’ing and individual well economics are worse, not better than normal. (Marathon/Karnes County). The shale oil industry does not care if we have any oil reserves left after it’s mad charge up San Juan Hill. Its in it for short term profits, that’s it.

          Estimating TRR on the basis of EUR per current optimum acreage density in
          America’s shale basins is dumb. The EIA does this and people here on POB buy it like its gospel. Even build models using it. Optimum is qualitative. No rock is so homogenous that reserves can be estimated that way, particularly not shale or shaley carbonates. Oil, water and gas saturations change over short distances, as does net thickness values, as do thermal factors and organic content of the shale. The only way to make those kind of TRR estimates is to calculate OOIP per section, or some other metric, using the reservoir parameters under that section, and hope for some kind of reasonable guess at RF.

          • Dennis Coyne says:

            Hi Mike

            I don’t have access to that data.

            Note that i agree the EIA estimate is not good.

            Proved reserves and cumulative output for US LTO is about 20 Gb. USGS probably has access to the data and estimates a 95% probability that TRR for Bakken is 7 Gb and Permian Wolfcamp is 13 Gb, David Hughes estimates Eagle Ford at about 8 Gb.
            So this would be about 28 Gb, if we throw in a couple of Gb for other US LTO we would be at 30 Gb at minimum. The USGS median estimate is 30 Gb for Bakken and Permian only. USGS estimates are pretty good EIA not so much. 45 Gb might be too optimistic what do you think of the drilling deeper estimate for Eagle Ford?
            What’s your estimate?

            Also note that I have not assumed EUR remains constant I assume it decreases over time. If the rate of decrease is high then URR is low and vice versa.

            My guess is that as output peaks at the World level that oil prices will increase to $100/b by 2020. If that is correct I think my guess of 33 to 65 Gb may be right with about 45 Gb as a best guess.

            • HHH says:

              My guess is that they’ll pump every last bit of it a fast as they can get it out. Suppressing price along the way, until it’s all gone. Pumping the remaining shale reserves at a loss. Then once supply is gone maybe price returns to $100/b

              • alimbiquated says:

                That certainly follows the pattern of the North Sea reserves, that were pumped furiously in the 90s when prices were low.

            • Mike says:

              Dennis, I don’t have an estimate. I don’t need one. You might be surprised how few people actually care what day peak oil occurred, or will occur, or exactly how many barrels Earth gives up before She craps out completely 26 years and 299 days from now.

              I have tried to explain to you that modeling the future based on assumptions about oil prices is fruitless. You have no idea what the price of oil is going to be on Wednesday, much less in 2025. Neither does anyone else. You rely on the fundamental belief that supply will decline therefore prices will go up. There is no science in that.

              You ignore the massive debt load of the US shale oil industry, the amount of interest it must pay as a percentage of net revenue generated, and how all that will ultimately hamper its ability to manufacture wells in the future. The US LTO industry is in dismal, dire financial condition and the true value of its current assets does not come close to being able to pay off its debt. The number of wells it is drilling now, on what it says is “net cash flow” are being drilled at the expense of servicing debt. FOR THE MOST PART, THE ENTITY YOU ARE RELYING ON TO MAKE YOUR MODELS WORK IS BROKE AND INSOLVENT. Its kicking the debt can down the road and borrowing on it’s bleak future.

              You are also ignoring a changing, fluid economic situation where operating costs are increasing for legacy wells, annual decline rates are much higher than the shale oil industry lovingly says about itself, and the long tails on greatly exaggerated EURS are being whacked off in big chunks.

              Anyway, I can go on but its your blog and your personal venue for expression. When you could not properly moderate the thermodynamic debate, and let that dickhead Futilist, or whatever his name is, back in the fray, you lost me. You seem to lose a lot of oily folks over time, folks that are genuinely interested in our hydrocarbon future, but grounded with real life insight into what all the data actually means. Its a pity, that.


              • Dennis Coyne says:

                Hi Mike,

                My apologies. I generally do very little moderation, it is hard to keep determined people from posting or we would have very little discussion.

                I very much try to keep the blog open for all who wish to post, though sometimes people need to be kept out, I agree.

                I will try to do better in the future.

                I agree the LTO industry is in poor financial shape.

                You are correct that I assume if oil becomes scarce that oil prices will rise.

                Try the following thought experiment.

                Tensions mount between Sunni and Shite nations in the middle east and an all out war starts where the major nations involved start to bomb each other’s oil facilities, ports, pipelines, and other oil facilities so that 10 Mb/d of oil is taken off the World market in 3 months time.

                What happens to oil prices over the following 12 months?

                Another possible scenario, World oil output peaks and starts to decline at 1% to 2% per year, again what happens to the price of oil?

                Surely the answers are far from straightforward because the result can be an economic recession or at minimum slower World economic growth (as was the case in the early eighties). Also things are much different as we do not have Prudhoe Bay or the North Sea yet to be developed fully as was the case in 1981, though note that World output took nearly 10 years to return to the previous peak in 1979-1980.

                You are absolutely correct that nobody knows future oil prices. I simply took the EIA’s AEO2017 reference case and high oil price cases and too the average and then interpolated (as I needed monthly prices and they give annual prices). If oil prices remain $60/b or less over the long term (in 2016$), then the URR is likely to be 20 Gb or possibly only 15 Gb (about 8 Gb have been produced so far). My intent was to show that the EIA estimate is not very realistic, with high oil prices we might see about half the EIA estimate by 2050,with low oil prices it is likely to be 25% or less, just very rough guesses based on the data we have and an assumption that oil prices will be greater than zero. 🙂

                • Ves says:

                  Dennis: “Try the following thought experiment.
                  Tensions mount between Sunni and Shite nations in the middle east and an all out war starts where the major nations involved start to bomb each other’s oil facilities, ports, pipelines, and other oil facilities so that 10 Mb/d of oil is taken off the World market in 3 months time.”

                  Hi Dennis,

                  Look your how your thoughts create some false scenarios. Your thoughts create false question and then you give your satisfactory answer what would happen to the oil prices? Your thoughts create a question that if there is war in ME the oil price will go sky high.
                  But could you please tell me when there was no some kind war/tension in ME? There is non-stop war with just short breaks of peace in between. It is almost everyone is using short break of peace to prepare for more wars. Major powers, including US, have always been involved in wars in ME. That is not some new revelation.

                  But at this moment nobody is bombing each other facilities and there is very simple reason for that. Nobody would act against their self interest.

                  In terms of LTO and low price there is very very simple answer and that US LTO production is just scraping the bottom of world oil barrel in terms of extraction costs so the global oil supply/demand equilibrium is irrelevant from the US perspective.
                  Didn’t you notice that US is not involved in any talks production cuts (even if it is just pretending talks cuts)? US simply cannot cut because debt would not be able to be serviced.

                  But you don’t believe in that and you always try hanging on academic answers that “market supply/demand” and high enough oil prices will solve the problem. Well, for 2 and half years we still have low prices so how that “market supply/demand” from the economic text books is working? If you have to eat all the economic textbooks philosophies go out of the window.

                  • Dennis Coyne says:

                    Hi Ves,

                    Do you remember the Iran-Iraq war from 1980-1988. A lot of oil was taken off the market in a short period of time and it is the reason oil prices climbed.

                    Other wars as in Syria, Lebanon, and Israel have not really been in large oil producing nations, though Libya was a big part of the rise in oil prices in 2011. In that case it was about 1 Mb/d taken off the market.
                    Let’s say Kuwait, Saudi Arabia, Iran, and Iraq engage in a Sunni Shite all out war, nations sometimes do stupid things. If it should occur we are talking about 20 Mb/d of output from these 4 nations, if output was cut in half there would be a shortage of oil in my opinion.

                    When oil output peaks, it is also likely that there will be shortages.

                    Why have oil prices remained low? Output has remained higher than demand, in the long run that cannot continue.

                  • Ves says:

                    Hi Dennis,
                    There is proxy war, psychological, propaganda war, hybrid war in ME. But there is no direct hot war between major regional countries of that region. There is no hot war at this point. So why are you talking about some potentiality that has very low chances of possibility due to fact that everyone would end up on the losing end of that war?
                    Yes, in theory if you say that if you remove 20 mbd from the region price will go up. But the price is $55 Brent despite all the war rhetoric. There are lots of “shouting” from political class and media but lots of it is just noise. I don’t pay attention about that noise.

                  • Dennis Coyne says:

                    Hi Ves,

                    Yes I am aware there is no such war. Low probability events do occur such as the Global Financial crisis, Iran-Iraq war, World War 2, Great Depression, World War I, …

                    The example was indeed an extreme one and one that I agree is unlikely.

                    The second example has a probability of over 50% in my opinion between 2020 and 2030 (peak in oil output with a gradual decline in output at an average rate of decrease of 1% to 2% per year).

                    It is a possibility that demand will decrease at exactly the same rate as the supply decrease while oil prices remain low (under $60/b in 2016$), but I would put the probability that this occurs at a low oil price level at about 10% or less and the probability that oil prices will increase over the 2018-2028 period (to more than $90/b in 2016$ on average over that 11 year period) at over 80%.

                    I never get oil prices right however so perhaps oil prices will remain under $60/b long term. Note that I do expect there will be volatility, but predicting short term fluctuations in oil price is not possible in my opinion.

              • Hickory says:

                I think Dennis is absolutely correct to assume that a shortfall in oil production will lead to higher prices, with one possible scenario exception- that being the situation where a severe financial collapse removes both the capital for production and the ability of the consumers to keep up demand. That scenario would be an all out depression. It is certainly possible, and perhaps already baked in the cake.

                But there are many other scenarios that may play out instead, that all have lower oil output and higher prices.

                Side question for you Dennis- Many times you have mentioned that you foresee a depression (I believe beyond 2025 if I remember correctly). What thinking goes into your guess on the timing of this? Thanks

                • Caelan MacIntyre says:


                • Dennis Coyne says:

                  Hi Hickory,

                  My thinking is that there will be a plateau in oil output(C+C) from 2018 to 2025 at roughly 81 Mb/d plus or minus 1 Mb/d. This assumes no major recession (on the level of GFC) through 2025. Beyond that I expect relatively slow decline in output at less than 1% per year from 2025 to 2030, the economy will try to adjust, but I expect by 2030 the stresses of lower oil output and attempts to transition to other forms of energy for transportation of people and goods will lead to Great Depression 2, 2030 just seems like a good guess. It is possible the world might quickly ramp up the use of other forms of energy in the transportation sector and avoid such a depression, but I believe that is a low probability scenario (under 25%). All of this is based on my medium Oil Resource scenario, higher resources would make depression less likely (or it will occur later) and the low oil resource scenario makes a depression more likely (and likely to occur sooner) as the peak will occur sooner, plateau will be shorter and decline may be steeper.

                  • Hickory says:

                    OK thanks Dennis. I believe that is reasonable.
                    I also see the risk of depression due to a crumbling financial and/or political system (somewhere in the world) as very significant, and that could happen any old time. Unpredictable, and potentially extremely disruptive to little things like capital markets, borders, and ‘peace’.

                  • Dennis Coyne says:

                    Hi Hickory,

                    I agree it could happen at any time.

                    My thinking is that we may muddle through until the undulating plateau ends in 2025 and gradually more pressure will be put on the economic system as oil output declines and oil prices increase.

                    So I believe the likelihood of a depression increases unless we manage to quickly transition to other forms of energy for transportation. My guess is that is not very likely and a Depression at some point after 2025 is more likely, but it’s just a WAG.

                  • Nathanael says:

                    I am quite sure the ramp up of other forms of energy will happen very very quickly. The modeling isn’t rocket science.

                    The world deployment of electric cars has been growing 50% per year (much higher in China), and the production costs drop every year. Buses are similar (though the buyers are more conservative to start with). Trucks will follow buses. We can already replace oil in heating and power generation — and we largely have. That’s it for gasoline and diesel.

                    So just look at cars. Exponential extrapolation gets to 100% of the current car market being electric in 2030. Now, that’s not going to happen, but the first half of that curve will be enough to drag oil demand down massively.

                    I developed a model which matches ongoing demand reduction from electric cars with the decline rate of the existing fields. Both of those numbers are unclear. But even given growth in global car sales, sometime in the 2023-2027 range, the drop in oil demand from EVs will exceed the decline rate of the fields.

                    The world economy will no longer care about oil, just as it no longer cares about coal.

                  • Dennis Coyne says:

                    Hi Nathanael,

                    I believe that the high exponential rates of increase will not be maintained. Such rates of increase are easy to accomplish when the number are low. Your model is too optimistic in my view, their are also trains, airplanes and ships, long distance trucks and buses cannot realistically be electric, it will take time to electrify rail. Personal transport is only about 40% of oil use, so an assumption that the other 60% of oil use can be replaced quickly is not a good one imo.

                    I am not suggesting this cannot be done, just that assuming 50% rates of growth will continue for many years is not realistic.

                    Smart phones at $650 each (or computers at $1500 each) can grow at faster rates than cars at $35,000. each,

              • Nathanael says:

                Mike, I recognized (as you did) over a decade ago that the shale oil companies were fundamentally all unprofitable and were running on “extend and pretend”. I’ve been trying to figure out how long they can keep it up.

                Any ideas? It’s an interesting question, surely. When does the supply of suckers for refinancing of bankrupt companies run out? When do they actually have to declare Chapter 7 instead of Chapter 11?

                The airline industry *never* runs out of suckers to refinance them. But I suspect the oil industry doesn’t have the same sort of “magic” or cachet to draw people in forever.

          • robert wilson says:

            There is pooling in New Mexico but I am not in the oil business and have minimal information. My wife’s grandfather once owned 5 acres in Eddy County, New Mexico. My wife’s share is one sixth of the 5 acres. Probably a 160 acre pool We recently signed a lease and gained first income in 2016, more than $9,000. Have received $1,200 thus far in 1027. I am wondering, what can I expect in the future?

      • Watcher says:

        How old is that well?

      • shallow sand says:

        TT. Please stop it.

        The subscription site I pay for (IHS Energy’s US Data Online) shows 13,928 horizontal wells have been placed on production in Oklahoma, with 6 through 10/31/16 having cumulative oil in excess of 400,000 barrels.

        If you have conflicting data, please share it. We would all like to know why total OK oil production is still at around 400K BOPD, with a little more than half of that being from those almost 14K Hz wells, if, as you say, OK has the most prolific Hz oil wells in the lower 48.

        I will readily agree there are many prolific OK Hz gas producers.

        Give me the well names or operator names of the prolific wells, and I will look them up.

  6. John says:

    Good Morning Clueless,

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

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

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

    It could be an interesting exercise.

  7. Boomer II says:

    Split in oil-price, rig-count flows a cause for concern? Not yet. | TheHill: “That the land rig count is recovering at a stronger pace than its underlying commodity, which usually is the catalyst for changes in the rig count, does present a reason for concern.”

  8. Boomer II says:

    Bakken Oil Producers: IP30 And Well Decline Rate Trends Since 2014 | Seeking Alpha: “Several companies which were early adopters of enhanced completion techniques and have their acreage concentrated in sweet spots have seen significant declines of their IP30 values of new wells, indicating an exhaustion of their acreage. More recent adopters of enhanced completion methods, by limiting drilling to their best acreage, have seen a boost of IP30 of new wells since 2014 but will sooner or later face the same exhaustion problems.”

  9. Boomer II says:

    An article from February.

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

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

  10. Boomer II says:

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

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

    • alimbiquated says:

      I think rich countries are soon going to find that a lot of their infrastructure is worthless. Germany has already found that out about gas plants, which can only be saved by more expensive carbon. China is massively disinvesting in coal and wants to switch to electric cars as well.

      • Ulenspiegel says:

        “Germany has already found that out about gas plants, which can only be saved by more expensive carbon.”

        That is not correct. In 2018/20 we will see a further reduction of conventional capacity, utilities in germany and Austria assume that open turbines NG power plants will make money again.

        The stranded assets are CC powerplants which need in Germany more than 3500 FLH to become useful, a number they do not reach.

  11. Boomer II says:

    This article gives a good overview of what is happening in Colorado.

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

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

  12. Boomer II says:

    This article came out on February 28. I don’t think it’s been posted here.

    Cooking The Books? Saudi Aramco Could Be Overvalued By 500% | “WoodMac puts Aramco’s true value closer to $400 billion, eighty percent less than the Saudi estimate, and it arrived at the figure by considering future demand and the anticipated average price of oil (on which profits will depend), as well as Saudi Aramco’s status as a state-run company.

    WoodMac doesn’t dispute the figure of 261 billion barrels lying under Saudi Arabia and just offshore; that figure has been confirmed by independent sources. Where things get complicated, though, is in the management and taxation of Saudi Aramco, which does not release financial statements.”

    • clueless says:

      Seems right to me. As I posted a short while back, in my opinion, no rational investor, today, would pay anything for production that might occur more than 20 years in the future. Therefore, only about 88 million bbl of reserves is in play. And those produced 20 years out [risked] have neglible net present value.

    • Survivalist says:

      Does anybody know which independant sources confirmed the 261 billion barrels lying under Saudi Arabia? I was under the impression we were just taking their word for it. Who signed off on confirming it?

      • Watcher says:

        Bingo. And VERY OMINOUS that a firm like WoodM would fall for the “independent audit” story.

        Those auditors did not do core drilling. They did no exploration drilling. They took Aramco data, added it up (accountants add things up) and declared 261 billion barrels of reserves.

        This is such silliness.

        There is also the issue of who paid for the audit.

        • Caelan MacIntyre says:

          “There is also the issue of who paid for the audit.” ~ Watcher

          The Man With The Magic Wand?

          We are in a model, Watcher. Call it The Matrix if you wish, or Plato’s Cave.

        • Caelan MacIntyre says:

          “There is also the issue of who paid for the audit.” ~ Watcher

          The Man With The Magic Wand?

          We are of course in a model.

          The Matrix and The Cave

        • Caelan MacIntyre says:

          Which edit do you prefer? I prefer the one with the link.

          But in any case, it’s like that with models, and sometimes we have little choice…

  13. Tom says:

    Gents, a Norwegian oil analyst claimed a couple of weeks ago that for each drill rig that became active in US shale oil would give totally 5.3 mill bo/d until the end of 2019. No assumptions were stated, such as which field the rig drilled in, how many wells the rig would drill per month etc. I made a quick estimate assuming 3 wells being added per month, and a well with initial production of 300 b/d, assumed a constant percentage decline of 7 % per month (big simplification, I know) and i found an answer about 1/20 of his estimate. Anyone who can do a third estimate? I might be far away, so it would be great with a second opinion. Thanks

    • George Kaplan says:

      If you assume one rig can deliver a new well every 18 days (i.e. 20 per year) with 400 bpd initial flow and 60% decline per year then after one year there would be 5300 bpd flowing from the wells it has drilled that year. But maybe it should be averaged over the year and/or take account of production from previous wells.

    • George Kaplan says:

      If you assume an exponential decay for each well, with all wells identical, then a single rig could support steady plateau production of F0/(1-(1-r)^(1/n)). Where F0 is initial flow, n is number of wells per year added, and r is the year on year decay rate (note – not the exponent in a exponential, but related – like -LN(1-r) or something similar, and for these high decays not even close to it). So any combination of F0, r and n might do.

  14. Verwimp says:

    Hi Dennis,

    Interesting scenarios. Thanks for all the work you’ve put in it!
    – I understand you believe there will be a new period of growth during the next five years, followed by a plateau during the 2020’s or up until 2035, depending on URR.
    – I understand the entire analysis starts from USGS and EIA numbers of URR.
    – I understand you believe the price of WTI will start to increase from now on, agressively first, more moderately later on.
    – I understand you are counting in severe EUR decreases.

    As a result, I see you don’t think LTO is in decline yet. It’s on the start of an undulating plateau that will last for a decade or two, and that will have production numbers between 4 and 6 million barrels per day.

    – Barring a new leap in technology (that might be triggered by a new price shock), I doubt the new period of growth.
    – The USGS and EIA URR numbers look very optimistic in my (relatively uninformed) opinion.
    – The evolution of the oil price is unclear to all of us. Even the proposition that scarcity will lead to higher prices might be wrong: demand destruction (and low prices) may take the lead in defining oil prices, hindering new technological leaps.
    – I have the feeling, without digging into your numbers profoundly, your estimated EUR decrease is rather pessimistic. Nevertheless: EUR decrease will be in the room. But will companies still be drilling wells with an EUR of <150?

    • Dennis Coyne says:

      Hi Verwimp,

      If the oil prices rise as much as the average of the average of the EIA’s AEO 2017 reference and high oil price scenarios and the costs that I have assumed are correct, then the wells will be profitable.
      A problem with my analysis is that I have ignored land costs. I have several different scenarios for EUR decrease, not sure if you think the annual rate of decrease is too high or too low, but that rate depends on the well completion rate.

      Let’s say the completion rate is low, in that case the EUR would decrease more slowly.

      We could also assume oil prices are low because oil was plentiful or due to demand destruction caused by high debt levels, that would reduce the well completion rate.

      • GoneFishing says:

        Dennis, what is the total production for a typical well over first five years?

        • Dennis Coyne says:

          Hi Gone fishing,

          For the average US LTO well from 2013-2016 (EUR=219 kb) the 60 month cumulative output is 141 kb. So about 64% of EUR over the first 5 years.

      • Dennis Coyne says:

        Hi Verwimp,

        I left all economic assumptions unchanged except an increase in the well cost to $7 million (2016$) to reflect $1 million in land cost (to attempt to reflect full cycle costs.)
        In the scenario below I assume LTO output recovers more slowly and the maximum completion rate is 870 new wells per month (from Jan 2020 to Dec 2027)compared to 1210 new wells per month in the 44 Gb scenario. The URR through Dec 2050 falls to 40 Gb in this scenario and the secondary peak is lower. The oil price scenario is left unchanged where it is assumed that slower economic growth and demand destruction due to higher prices keeps supply and demand for oil roughly in balance at this set of oil prices. The reality is likely to be more volatile oil prices so one could imagine some sinusoidal function of output above and below the output path as oil prices fluctuate above and below the assumed oil price scenario, due to economic (financial crises),and political (war) problems. I will not attempt to predict those in advance 🙂 .

        • Dennis Coyne says:

          Hi Verwimp,

          You are correct that we do not know future oil prices, if World output decreases it is likely that oil will be scarce and that oil prices will rise. Yes there will be some demand destruction, it is unclear if the quantity of demand will fall faster than the output of oil, if so then oil prices will fall, and if not oil prices will rise to the level that inventory is stable and consumption and output are equal.

          My guess is that this won’t happen until there is a World Depression and my guess is that will occur around 2030 and last for 7 years before the World economy starts to grow again.

          I did another model with lower oil prices at link below

          The scenario below assumes prices rise until 2029 (to $150/b) and then they decline linearly until 2038 (to $108/b in 2016$). It is assumed prices decline due to a World Depression from 2030 to 2037, prices remain at $108/b after 2038. URR is 34 Gb in this scenario.

      • Nathanael says:

        Oil prices will start falling for good due to demand destruction around 2023, maybe a bit earlier. I’m not sure whether we’re already in the final drop or not; I’ve gone through several views on this.

        I now think we probably are in the final price drop because I think enough of the oil producers see the demand-destruction handwriting on the wall that they will pump all-out to sell whatever they can before demand drops.

        • Dennis Coyne says:

          Hi Nathanael,

          You assume demand will fall faster than the fall in output because you use unrealistic exponential rates of growth. Low oil prices will reduce the rate of growth of EVs and other forms of transportation that might substitute for oil (electrified rail, light rail, electric buses, etc).

          Note that world output of passenger vehicles grew by 3.43%/ year from 1999 to 2011. Data from

          One of the fastest recent motor vehicle production growth periods was from 1962 to 1972 at 8.5% per year for a 10 year period. Motor vehicle production increased from 15 million per year to 34 million per year.

          Also see
          page 20 of link below for US vehicle ownership from 1900-1997

          From 1910 to 1920 total vehicle registrations increased by 29.8% per year from 469,000 to 9,239,000. Currently plugin vehicle ownership is about 1.8 million vehicles at the end of 2016. If we assume the 29.8% growth rate in vehicle registrations from 1910 to 1920 can be matched, there would be 19 million plugin vehicle registrations in 2025. If we double it to a 60% per year growth rate (not very realistic), then we reach 124 million registered plugin vehicles by 2025. In 2014 there were about 1.2 billion light duty vehicles registered (link below)

          to get to half that number by 2025 (600 million) would require a growth rate of over 90% from 2017-2025. This would reduce oil consumption by roughly 10.5% (assuming no change in ICEV fuel economy and no increase in total passenger vehicle fleet and that plugin hybrids use no fuel) if the personal vehicle fleet continues to grow at 3.4% per year. By 2025 oil output will have fallen by at least 3.5% from 2016 output levels.

          So were good if the plugin fleet grows at 90% per year for 9 years and there is less than 0.75% annual growth in other uses of oil from 2017 to 2025. The probability that both of these assumptions will be correct is very low (less than 2% in my opinion).

          Note that cumulative worldwide plugin vehicle sales grew by 66% per year from 2014 to 2016 based on data from

          At that rate from 2017 to 2025, plugin cumulative sales reach 171 million by 2025 and the ICEV fleet reaches its maximum in 2024. If demand from other transportation sectors (water freight, air, rail, commercial trucking, etc) does not increase from 2017 to 2035 (not very likely), then in this very optimistic scenario demand would fall below supply in 2035.

          A more realistic estimate would be approximately 2065 as 30% growth rates in plugin vehicle registrations are unlikely to continue indefinitely, the longer term growth rate is likely to be 10% per year or less.

          • Nick G says:

            Tesla is growing production by about 50% per year – I’d say that’s a reasonable upper limit.

            Don’t forget: it’s not really a matter of growing from scratch – you’re really converting ICEs to hybrids, and then from hybrids to EVs. They’re built in the same factories and use mostly the same parts. Hybrid electrics share a LOT of components with ICEs. And, hybrids are essentially identical to EVs, except EVs are much simpler and easier to make.

            Honda Motor Co. wants partially or fully electric cars to account for two-thirds of global sales by 2030


            • Nick G says:

              Actually, 50% is probably too low as an upper limit.

              Tesla can only manage 50%, but they’re a small, underfinanced company. Companies like Honda, GM, Toyota, VW….they could do it much faster. Honda is talking about mostly converting in 14 years (3 full product cycles) but they could convert in 10 years (2 cycles) if they really wanted to.

    • Dennis Coyne says:

      Hi Verwimp,

      Note that the growth in output does not assume any change in new well EUR (it actually decreases starting in Feb 2017), simply that rising oil prices will lead to a higher well completion rate, from 570 new wells per month in Oct 2016 to 1200 new wells per month by 2020 with about a 20 well increase each month from July 2018 to Dec 2020.

      If oil prices remain low ($100/b or less) you will be correct and in that case US LTO cumulative output will be between 15 Gb and 24 Gb. The 15 Gb case assumes no well completions after Oct 2016,the 24 Gb case assumes another 44,000 wells are completed in the US LTO sector between Nov 2016 and July 2022, in this last case oil prices rise to no more than $100/b, the first case assumes oil prices remain under $75/b long term (2016$ in both cases).

      • Verwimp says:

        Hi Dennis,

        Thanks for your responses.

        I go back to my initial response:

        – I understand you believe there will be a new period of growth during the next five years, followed by a plateau during the 2020’s or up until 2035, depending on URR.

        If (for whatever reason) there is a new period of growth, I think that period of growth will be much more agressive, much steeper, reaching much higher, until a new peak is reached. Not a plateau. For sure not a prolonged, decade long plateau. Plateaus are unamerican. Americans live by booms and busts. If an American thinks he can earn money steadily during the next decade, nothing will stop him from trying to earn that awful amount of money today. If not, his competitor will. Thereby creating oversupply, boom, bust, end of story. I have the impression you have engineerd these plateaus in all of your scenarios. I don’t understand why.

        In case of a much higher peak, all the oil of a much higher URR will be sucked out of the ground in a much shorter time frame. In the end Hubbert will (again) be not far away.

        Best regards,


        • Dennis Coyne says:

          Hi Bruno,

          I don’t know what the limits are for adding new wells, but eventually there end up being constraints on how many wells can be added per month. At the previous peak the maximum number of wells added per month was a maximum of 1400 new wells added per month, my guess is that this may be the limit so my maximum scenarios usually approach this limit.

          I also have economic constraints which limits the number of new wells that can be produced profitably.

          • Dennis Coyne says:

            Hi Bruno,

            Also in the initial post the aim was to attempt to match the EIA’s AEO 2017 reference scenario for LTO, that was the reason for the plateau (as that reference scenario has a long plateau in oil output.)

            Perhaps output will decrease as fast as it increased. I think it depends on the timing of when various LTO plays peak and decline. One could easily imagine that these peaks will not be synchronized and the combined output of all LTO plays might exhibit an undulating plateau. Chart below shows US output from 1951-2008 (prior to LTO boom), actual history over that period does not match with your description of US oil industry behavior. It is the recent period from 2008 to 2016 that may be anomalous. Note especially the period from 1979 to 1983 when output was relatively flat, sometimes their are physical constraints that make it impossible to increase output beyond some maximum, but with enough effort the maximum can be maintained.

  15. Pingback: The Future of US Light Tight Oil (LTO) –

  16. George Kaplan says:

    I found a Pemex presentation concerning future prospects from 2012. Below are their numbers for total C&C, Cantarell and KMZ, compared to recent data. Obviously things haven’t worked out as hoped. The missing slices of production were just listed as “future offshore”, “future onshore” and “deep” (i.e. yet to be discovered). A few other company and country predictions might be looking similar over the next few years.

    Cantarell came off it’s second plateau about two years earlier than predicted, and KMZ looks like being about 6 to 12 months early. If KMX declines at a rate similar to the prediction and the other fields continue to decline as they have been then Mexico will be seeing 15 to 20% decline rates in 2018 and beyond, though ameliorating a bit over a couple a few years.

    The deep water projects they expect from the latest licensing rounds won’t be seen until 2022 (Trion) and later (assuming there are discoveries) by which time they are likely to be down around 1200 kbpd. They only have the replacement for the burnt out Abkatun platform due in 2019. They’ll still need one major project per year from then on to maintain a plateau, more if they want to grow. They are supposed to have a lot of shale resources but it looks like it’s almost all gas, and so far I think it’s not been much tested so recovery is a question mark; so too will be the cost of installing, protecting and maintaining the required infrastructure.

    • Watcher says:

      Just spent some time scoping out Mexico’s road and railway map in the vicinity of where the Eagle Ford shale extends south across the border. Laredo (Nuevo Laredo) is a semi major destination for both highways and rail.

      It’s somewhat south of the shale. North of there a considerable expanse of border exists before Piedras Negras, which is another rail/highway node. It’s that expanse in between where the shale is. The nearest proppant firm in Mexico seems to be E-Proppant in Monterrey — and they may exist only to hold the E-Proppant trademark.

      Bottom line: I don’t see the logistics route for transport of proppant to a major shale effort along that border. Even on day 1, BNSF in NoDak had the Williston node. Mexico seems to have nothing.

  17. Enno Peters says:

    I have published a new post on the Eagle Ford, which you can find here.

  18. Jeff says:

    IEA just released its 5y outlook, “Market Report Series: Oil 2017”

    “Global oil supply could struggle to keep pace with demand after 2020, risking a sharp increase in prices, unless new projects are approved soon, according to the latest five-year oil market forecast from the International Energy Agency.”

    Concerning US LTO: “The United States responds more rapidly to price signals than other producers. If prices climb to USD 80/bbl, US LTO production could grow by 3 mb/d in five years. Alternatively, if prices are at USD 50/bbl, it could decline from the early 2020s.”

    • Eulenspiegel says:

      Let’s see how it plays out.

      With electric vehicles at the horizon, who will invest in huge new deep offshore field that need 20 years to pay off, and “Pay 100 billions of dollars before you see 1 drop of oil”? Everyone will be in drilling the same shales or infilling like crazy in old fields – and when new big fields are needed, because electic cars need longer than thought, it will be a nice rollercoaster of oil prices.

      Can SA go really to 15 MBD, and Iran / Iraque to 10?
      US shale is even in optimistic sceanrios only able to replace a failing Venezuela and Mexico with about 3 MBD from today level.

      • AlexS says:


        “With electric vehicles at the horizon”

        The IEA report covers the period to 2022.
        Electric vehicles sales last year accounted for 0.86% of total global car and light track sales []. Even if their share in sales rises to 5% by 2022, they will still represent a negligeable part of global car fleet, not seriously affecting global demand.

        “Can SA go really to 15 MBD?”


        “and Iran / Iraq to 10?”

        Their combined output can reach 10 mb/d

        “US shale is even in optimistic sceanrios only able to replace a failing Venezuela and Mexico with about 3 MBD from today level.”

        I’m not sure that US LTO production can increase by 3 mb/d from current levels, although there are many forecasts anticipating comparable or even higher growth.
        But combined Venezuela’s and Mexico’s output will not drop by 3 mb/d by 2022.

        There is a lot of factors suggesting that the oil market will tighten over the next 5 years; and yes, there “will be a nice rollercoaster of oil prices”.

        • Dennis Coyne says:

          Hi AlexS,

          I agree KSA will not reach 15 Mb/d, I do not agree that combined output from Iran and Iraq will reach 10 Mb/d, maybe 9 though, but they may both be near their maximum combined output, 8Mb/d seems the best guess to me.

          Not sure how much Mexico and Venezuela will drop and potentially we might see Libya and Nigeria recover some of the reduced output due to political problems.

          I doubt the World will see C+C above 85 Mb/d and 82.5 Mb/d around 2020 seems a more likely figure. The rebound shown in my scenarios depends on high oil prices, without those high oil prices LTO goes no higher than 4.5 Mb/d, and even that requires about $100/b by 2019 with prices continuing to rise to at least $150/b by 2029 (2016$). Low oil prices (under $75/b) will eventually kill US LTO.

          Scenario below shows oil price assumption on right axis, well cost $7 million (2016$), Oil prices are assumed to reach $100/b in 2021 and remain at that level, note that the AEO reference oil price scenario reaches $100/b (2016$) in 2033 and $117/b (2016$) in 2050.

          • AlexS says:


            There are numerous factors affecting US LTO production, and I do not think a single “top-down” formula using TRR, average EURs and decline rates can reliably project future LTO output.

            I prefer detailed bottom-up analysis by shale sub-plays, which also takes into account financial aspects, such as company cashflows and debt under different price scenarios. This is obviously well beyond my modest intellectual capabilities; therefore I do not dare to make my own projections.

            BTW, this chart from BTU Analytics shows the importance of the oil price factor:

            • Dennis Coyne says:

              Hi Alex S,

              Yes bottom up is better, but much more work. I have done many scenarios for Bakken and Eagle Ford, and I could do the Permian, but each play requires the same amount of work gathering data, etc.

              Thanks for that chart, I get 363,000 wells for an oil price from 0 to over $70/b including the 75,000 already completed at the end of 2016. How old is that chart? It would seem the 600,000 plus wells needed to reach the EIA’s AEO is a bit on the optimistic side. The 363,000 wells would correspond with about 65 Gb based on my admittedly rudimentary model, but would require both high oil prices and relatively low rates of decrease for new well EUR, I think they may be overestimating well locations that will be profitable, though “over $70/b” covers a lot of ground, including $300/b . I doubt oil prices will rise that high (for a 12 month average) before 2050.

            • Dennis Coyne says:

              Hi AlexS,

              I think you may not understand how the model works.

              I take an average well profile (actually two wells profiles) and the number of new wells that start producing each month. The two data sets are combined by convolution. The only place I use decline rates is for the small amount of LTO production that started before July 2006 where I assume that output declines at an annual rate of 9.3% (this is a very small piece of the model, output was 390 kb/d in June 2006). The model is far from perfect, but is based on the data to date and assumes the average well profile is relatively stable. For projections forward in time it is assumed the rate of well completions will increase (from about 570 per month to about 1200 per month in my central scenarios) at a rate of increase of about 10 wells per month starting in late 2017, the EUR of the average well is assumed to decrease starting in February 2017 (note that this is different from the decline rate, it is a shift downward of the entire well profile.

              In any case your basic comment that the model is inadequate is correct. Chart below shows model data match from 2011 to 2016, new wells added each month are shown on right axis (dotted line) and the well profiles are as shown in the post.

              An explanation at link below


              • Dennis Coyne says:

                The well completions in the chart above is the monthly well completion rate, peak rate was about 1400 wells per month and recently about 570 wells per month were completed.

          • Dennis Coyne says:

            The point of that 24 Gb scenario is to show that the oil price will need to be considerably higher than the AEO 2017 reference case if the EIA’s reference case for tight oil has a chance of being correct, even the high price scenario might not be high enough.

      • Synapsid says:


        In view of the differences in API degree can US LTO replace production from “a failing Venezuela and Mexico…”?

    • AlexS says:

      From the executive summary:

      US light tight oil (LTO) producers saw even more striking cost reductions of 30% in 2015 and 22% in 2016. This also gives a clear indication that many are capable of positioning themselves to raise production in a lower price environment.

      We believe that by the end of 2017, LTO production will be approximately 500 kb/d higher than a year earlier. Even in a world where oil prices do not move sustainably above USD 60/bbl, LTO production will continue to grow through 2022, adding 1.4 mb/d over the period, reflecting the enormous cost savings and efficiency improvements that have been made in what remains to a certain extent an experimental sector of the oil industry. If oil prices were to rise sharply to, say, USD 80/bbl our sensitivity analysis suggests that LTO production could rise by as much as 3 mb/d by 2022.

      • Dennis Coyne says:

        Hi Alex S,

        A better analysis realizes that most of the falling costs are due to lower prices from service companies and for rigs due to the low completion rates.

        These low costs will likely disappear relatively quickly as the well completion rate increases. In addition the focus has been on the core areas, this high grading has reduced losses, but the number of well locations in the core areas is not unlimited, it is doubtful that costs are as low as Wood Mac seems to believe, they have bought the hype in investor presentations, without higher prices (say $70/b or more) it is doubtful that completion rates will increase markedly, at current oil prices LTO output will be flat in my opinion, +/-250 kb/d.

        • AlexS says:


          the above quote is from the IEA report “Oil 2017. Analysis and Forecasts to 2022”

          The EIA, WoodMac, Rystad and many investment banks have similar forecasts for US LTO production in 2017 (Dec. to Dec. growth of ~500 kb/d) and even higher growth projections for the next several years (0.5-1 mbd annually).

          I don’t think that projections for this year are totally unrealistic. Note that since mid-2016 US oil rig count has increased more than 2 times, and this has yet to affect production given the 4-5 time lag between well spud and first production. In 2017, LTO production growth will also be driven by the drawdown of the DUC inventory. Note that 500 kb/d Dec17 to Dec16 implies a more modest y-o-y growth for 2017 average vs 2016 average.

          As regards medium-term growth rates of 0.5-1 mb/d per year, I think they are not sustainable. Even leaving aside the issue of resource availability, I think such growth rates would imply significant overspending of shale companies’ operating cashflows and hence further increase in debt. But annual growth rates of 200-400 kb/d for the next 4-5 years (2018-22) are possible, in my view.

          I agree with you that falling LTO costs in 2015-16 were largely (up to 75%) due to oil service and input cost deflation. This trend is already reversing, although costs are unlikely to reach 2014 levels any time soon.

          • Dennis Coyne says:

            Hi AlexS,

            Your forecast sounds reasonable, but not at EIA AEO2017 reference case oil prices. See my scenario above (or below) with oil price assumptions considerably higher than AEO 2017 reference case, in that scenario we see about a 500 kb/d (125 kb/d increase each year) over the next 4 years. Higher oil prices (similar to the scenario in my post) would make your forecast reasonable (but many people, possibly you included) believe that oil price forecast is much too high.

            I agree with the criticism that I don’t know future prices, an economic analysis requires a guess. Based on my “low” oil price and “higher”oil price scenarios a URR of 25 Gb to 40 Gb may be realistic if oil prices fall somewhere between these two scenarios.

            • AlexS says:


              These are not my forecasts. I think that, with gradually rising oil prices and LTO production increasing by 200-400 kb/d per year, shale companies will be able to remain cashflow neutral (but not to pay down existing debt).
              This does not take into account the resource factor.

              • Dennis Coyne says:

                Hi AlexS,

                I was talking about the 200-400 kb/d increase in US LTO, which I thought was your opinion. If I am correct that you believe that is correct what is the oil price that it is based on.
                There are many forecasts, but there must be some that seem more reasonable than others.

                Below is AEO 2017 ref, high and the average of the two (dashed line) that I used in the post.

    • Watcher says:

      “Global oil supply could struggle to keep pace with demand after 2020, risking a sharp increase in prices, unless new projects are approved soon, according to the latest five-year oil market forecast from the International Energy Agency.”

      But that’s insane. Why is that the conclusion? We don’t have enough oil so I guess prices rise. WHY IS THAT THE CONCLUSION?

      If “we don’t have enough oil” then people don’t get their order for oil filled. Period. At any price. If there’s not enough oil, the SPRs drain. There are only a few months of those.

      90% of reserves are held by national oil companies, not private majors. National Oil Companies flow oil on command (not on demand) regardless of price. If they can’t flow oil, they can’t flow oil. If demand exceeds supply, then consumption matches supply, and someone is going to get their cities bombed to get their consumption down.

      • Dennis Coyne says:

        Hi Watcher,

        Why do oil prices rise? Why do they fall?

        Have you ever studied introductory economics?

        • Ves says:

          “Why do (oil prices) they fall?”

          When you drill a lot of (un)economical wells 🙂

          • Dennis Coyne says:

            Hi Ves,

            Yep too much supply in 2014 is correct. Watcher does not subscribe to main stream economic theory, though his theory seems to be linked to bombs and such, it is far from clear even to him. 🙂

            • Ves says:

              Hi Dennis,
              I agree with you, in general about supply/demand, even though I sounded in above post that it does not apply to oil at this point. I would like just to clarify myself: It only temporarily does not apply due to fact that we are already 3 years in “post-Opec”/ post oil cartel world. And it is messy and illogical oil world until things get sorted out one day. But who survives that day will tell us about it 🙂

              • Dennis Coyne says:

                Hi Ves,

                Yes part of the mess is due to an expectation by US LTO oil companies that OPEC would cut. When that didn’t happen they were caught with their pants down.

                Supply has not responded as fast as OPEC believed it would, but the eventual cuts by OPEC may get things back in balance and hopefully the US LTO industry has learned not to depend on cuts by OPEC. Time will tell.

    • George Kaplan says:

      I wonder where IEA thinks the oil is going to come from in 2019 and 2020 if the supply crunch is only seen thereafter. I know of only 1.8 mmbpd production from new projects over those years, with Brazil, Russia and Norway the biggest contributors (about half the total), though there would still be some ramp up from 2018 projects. Of course that figure does look good compared to 2021 and later, when current FIDs would give less than 0.4 mmbpd per year. I think they must be assuming a pick up in in-fill drilling to reduce decline rates, an increase from Iran and Iraq, and LTO to fill the gap, maybe with an increasing ratio of condensate and NGL in the total liquids.

      2020 is when mid to large projects with discoveries from 2015 onwards would be coming on line. In 2015 the discovery rate took a dive and doesn’t look likely to recover. SInce then around 80 to 90% of discoveries (by number not resource) have been less than 100 mmboe, so they could be developed quickly, but won’t add much production. The few larger, good quality projects are being fast tracked anyway.

      Usually, on average, projects were discovered within 7 years of coming on line. That changed a bit recently when the high oil price prompted a lot of older, and more difficult projects to be developed. That inventory has gone now, and what’s left are the even more difficult and expensive projects. They might need more than $80 to look attractive.

      If oil did suddenly jump to a higher number would all the E&Ps suddenly rush in a develop mega projects again. As a minimum they have to wait for next years budget, then pre-FEED and FEED, then an FID. But they might want to wait a couple of years to see how stable the price is, and now, unlike before, they have hungry creditors telling them how to manage their business for the creditors benefit rather than the shareholders. By my calculations $80 oil in 2020 will mean a FAO food price index of 220, the last two times that happened there was widespread unrest.

      • AlexS says:

        From the report and various articles citing the IEA projections:

        Global oil production capacity is expected to grow by 5.6 million bpd by 2022. Non-OPEC countries are likely to make up 60 percent of that total.

        Non-OPEC supply is expected to grow by 3.3 million bpd to 60.9 million bpd by 2022, led by the United States, accelerating sharply in 2018 and 2019 before slowing thereafter.

        Their base case forecast for US is slightly above 1.6 mb/d increase in 2016-2022, or>300 kb/d per year.

        US LTO scenarios:
        1/ +1.4 mb/d at $60 (base case)
        “Expectations for US LTO are higher than last year’s forecast thanks to impressive productivity gains.”
        2/ up to 3 mb/d at $80.
        3/ If prices remain closer to $50, shale output could fall from early 2020s.

        “The other countries that are expected to see their production increase significantly in our forecast period are Brazil, Canada and Kazakhstan, which will see their cumulative output rising 2.2 mb/d by 2022, reaping the rewards of investment decisions taken before oil prices declined.
        Production from Russia is forecast to remain stable over the next five years.

        Within OPEC, the IEA said most new supply will come from low-cost Middle Eastern producers, namely Iraq, Iran, and the United Arab Emirates, while production in Nigeria, Algeria and Venezuela will decline.

        OPEC is expected to increase production capacity by 1.95 mb/d, to 37.85 million bpd in 2022 from 35.9 million bpd in 2016, while demand for the group’s crude is expected to rise to 35.8 million bpd in 2022 from 32.2 million bpd last year.

        “A net demand gain of 7.3 mb/d is forecast for 2016-22—vastly exceeding the projected supply growth of under 6 mb/d.”

        The IEA report said that demand and supply trends point to a tight global oil market and in 2022, spare production capacity may fall to 14-year low.

        • AlexS says:

          projected changes in oil production capacity by country

        • AlexS says:

          Projected capacity additions by year

          • George Kaplan says:

            Thanks, but I don’t think any of that answers my question. It just reinforces that the big gains happen in 2014 to 2018, and then there is a big drop. How does the supply issue get delayed until after 2020? How come declines in India, Oman, Mexico, UK, Norway, Azerbaijan, Indonesia, Vietnam, Trinidad and Tobago, Australia, Bahrain, Thailand and Malaysia not included on the minus side for the period after 2017? What are the specific projects that will support Saudi, Kuwait and Qatar production after 2019?

            • George Kaplan says:

              Actually looking at the summary pages in order to meet any supply – demand difference it looks like it might be back to a call on OPEC with some additional allowance for stock draw down. I couldn’t find the split between the two but the last few marketing reports indicated that stocks outside US were coming down pretty fast anyway so it must be mostly OPEC; and therefore Saudi as they are the only one’s with putative spare capacity (assuming the cuts fade away for other countries this year).

              • AlexS says:

                They are projecting a significant increase in OPEC production capacity + decline in OPEC spare capacity (from 2.5 mb/d currently to below 2 mb/d) + stock draw.

                “India, Oman, Mexico, UK, Norway, Azerbaijan, Indonesia, Vietnam, Trinidad and Tobago, Australia, Bahrain, Thailand and Malaysia not included on the minus side” apparently because of projected relatively small declines.

                Saudi Arabia, Kuwait and Qatar are not mentioned in the summary report

                Generally, supply/demand balance looks quite tight already by 2020. If some projects included in supply projections fail to start production, or in case of significant supply disruptions, we may see again prices near $100.

                It seems that the IEA assumes potential supply gap could be covered by “short-cycle” US LTO.

            • Jeff says:

              The IEA report state that growth is “heavily-front loaded”, i.e. as you have noted most of new supply has or will come on line in 2016-2017. There is an appendix with tables in the back of the report, p. 137-138 lists selected upstream project start-ups by country and year. From what I can see, they have included everything significant. The smallest projects that they have included will only have a capacity of 10kb/d. Only a handful of the listed projects have startups in 2019 or later (not many in 2018 either). IOTW. the bottom-up table with new projects is more consistent with your view than the projection in the report.

              You can find a live stream presentation of the report at: on March 8

              EDIT 1: Yes, they do mention “call on OPEC”…

              EDIT 2: The table does not include new projects from Atlantis. I think most of new supply will come from there. (joke)

              • George Kaplan says:

                Jeff – thanks. Do they cover declines in mature fields in detail – it used to be flavour of the month, debating between 3% up to 7% I think, but it’s suddenly not mentioned at all.

                • Jeff says:


                  Decline rates has been discussed in some editions of World Energy Outlook (WEO) but IEA provide one global figure or figures for group of countries, type of field (on-shore vs off-shore) etc. and make reference to their own internal field-by-field analysis. Last WEO put the observed post peak decline rate at slightly higher than 6% (note the word observed as decline rate would have been higher if no investments were made).

                  The “HSBC peak oil report” that can be found online (e.g. seems to be in the right ballpark.

          • AlexS says:

            Projected OPEC capacity growth by country, 2016-2022

  19. AlexS says:

    Wood Mackenzie US LTO production projections:

    • Dennis Coyne says:

      Hi Alex S,

      Thanks. For my model to reach the Wood Mac forecast would require a very low rate of decrease in new well EUR, or for it to start later. Note that for the US LTO average well, fewer Bakken wells (which have a 320 kb EUR vs 240 kb for Eagle Ford and these are both above the US average) will cause the average new LTO well to have a lower EUR. Permian wells will likely have a lower EUR than the average Eagle Ford well (based on the 2012 to 2015 average).

      In an attempt to match the WoodMac scenario, I delay the EUR decrease until Jan 2019 (perhaps the EUR of Permian wells continues to improve offsetting the decrease due to fewer Bakken and Eagle Ford wells), the output is close to the Wood Mac scenario in 2025. Well cost increased to $7 million to approximate full cycle cost, but oil prices and EUR decrease similar to 60 Gb scenario from my post. URR is 61 Gb, output falls rapidly after 2033 due to poor well economics leading to fewer well completions.

      • AlexS says:


        Unfortunately, all those forecasters do not provide detailed assumptions.
        I guess they assume higher EURs and no negative effect from downspacing and development of shale plays’ perifery zones.

  20. Survivalist says:

    This is an interesting post on global net exports.

    “the USA seems destined to become oil self-sufficient in the next few years” seems like a bizarre thing to say (2020? I’ll have what he’s smoking), but otherwise I find it quite nice to read.

    • clueless says:

      It is a nice read, and good charts. I like they way you can trace them and see the numbers.

      But, I wonder how often, if ever, the US should be used in any kind of model. Just in the last 10 years, it is easy to document that hundreds of billions of $ have been wasted on uneconomic oil plays, that will nonetheless be produced as they have been transferred through bankruptcy, etc. such that the fixed invested costs are meaningless. The current holders only have to cover the variable production costs.

      And, only in the US, could you build a housing boom on people with no jobs, and no credit, purchasing $400,000 houses. Many never moved in – just stripped them and got signing bonuses at closing. Even I, as I easily acknowledge, was clueless. At the time, I just would not believe the anecdotal evidence that it was happening.

      So, unprofitable US oil [and housing] production skyrocketed. I do not think that can be replicated in any other country. And, hopefully not again in the US.

  21. Boomer II says:

    I don’t see how rising oil prices will get more oil out of areas that don’t have more oil to give. That thinking doesn’t seem to factor into some of the production forecasts floating around.

    If an area is playing out, it doesn’t matter what people are willing to pay for oil.

    And I think that’s what we are starting to see with some of the majors. The Permian may look good to Exxon right now, but I suspect that’s because there aren’t many areas left for Exxon to exploit.

    Oil prices may go up when scarcity hits, but that doesn’t mean production will go up, too. All those LTO companies may be pumping out what they have now, at relatively low prices, and when prices do rise, they’ll have little left.

    • Envision says:

      Or take it that way, when Exxon and Chevron and the rest of the shalers have rushed out the cheap LTO, the price will go up with no competion in the US left, and they can start again with this large scale projects and with much better pricing.
      To go shale all in only speeds up the process for the majors of exhausting this competion.

    • Dennis Coyne says:

      Hi Boomer II,

      Different areas of the LTO plays have different productivity or estimated ultimate recovery (EUR) per well. At $50/b the more productive areas are profitable, at $100/b areas with lower EUR may be profitable (and the better areas even more profitable), etc. The amount of oil that is profitable to produce depends critically on the price of oil.

      In short, I disagree.

      • Boomer II says:

        Raising the price very high still doesn’t produce oil in depleted fields.

        • Dennis Coyne says:

          Hi Boomer II,

          I agree that high oil prices does not create oil. A “depleted” field often has areas where there is oil left behind, in some cases this “expensive oil” that could not be produced profitably at $50/b or less will be produced at $100/b.

          Nobody (or not me anyway) expected in 2005 that the US would ever increase its output to 9 Mb/d, because all its fields were depleted. I was wrong.

          At some point the World will reach the point where oil output cannot be increased even at $200/b (2016 $), my guess is that we will reach that point by at least 2025 and my best guess is around 2021 or 2022. Time will tell.

          • Boomer II says:

            That isn’t that far off. We’re not being told that yet from the oil industry. They are just saying investments aren’t enough right now. But I don’t blame them. If they are trying to cash out, why tell the public and investors the industry might change before long?

          • Nathanael says:

            Saudi Arabia still has a *lot* of oil which it can produce fairly cheaply. It’s been holding back.

            At some point, before the complete end of the oil economy, it’ll basically be Saudi Arabia. Demand destruction will hit the highest-cost producers first and leave the lowest-cost producer (Saudi Arabia) standing.

            • Caelan MacIntyre says:

              What about Russia?
              Saudi Arabia is a bit of a desert and imports most everything else, yes?

  22. ashtorak says:

    But how do you justify an ever increasing oil price (apart from inflation) when the energy content of a barrel of oil equivalent (1700 kWh) is just 50-100$ with photovoltaics at around 0.05 $/kWh today? If oil is constantly above 50$ there will be mass adoption of PV and if the price is constantly above 100$ there will be large scale adoption of PV+storage. I don’t expect the oil price to stay long at over 100$ another time, certainly not more than ten years. Do you really think this is possible?

    • JN2 says:

      Correct. Especially when you get ~4.5 times as many miles per kWh from electricity as from gasoline. [Tesla Model S 75D versus average US car].

      • Dennis Coyne says:

        Hi JN2,

        We will have to see how well the Chevy Bolt and Tesla Model 3 (when it becomes available) gain market share. A lot of it is a convenience factor and people being afraid of new technology. I will be buying a Model 3 when they are available, but it will be difficult to get my hands on one before 2019. I owned a Chevy Chevette and will never buy another GM car.

        • clueless says:

          Dennis, I once bought a pair of bell-bottom pants from Macy’s. I will never buy anything from Macy’s again!

        • Nathanael says:

          We already know that Model 3 market share is strictly limited by production capacity (if you don’t have a reservation now, you won’t get yours until 2019).

    • Watcher says:

      Top 20 car models for sales in Feb. Aint none of them electric

      Bolt and Leaf sales COMBINED in Feb about 2000 cars. 1/30th F150 sales.

      This EV stuff is just profoundly silly.

      Volt and Prius sales 3100. Of course, they aren’t electric. They have gasoline engines.

      • Boomer II says:

        I don’t think the US is going to be the leader in this area. It may be more important to watch what happens elsewhere.

        Electric cars: China’s battle for the battery market: “Beijing last week called for companies to double electric vehicle battery capacity by 2020 and encouraged them to invest in factories overseas. As carmakers invest more heavily in electric vehicles the lithium-ion battery will be a key technology for at least the next decade, creating a market Goldman Sachs estimates will be worth $40bn by 2025 and dominated by China.”

        • Nathanael says:

          It will absolutely be dominated by China.

          Of the non-Chinese companies, Tesla has a chance because it’s building a factory with 500K/year capacity. So far, nobody else outside China is, though Nissan has a combination of factories which can do that much.

          A lot of people — like Watcher — just don’t get that gasoline cars are *dead* as a market within 10 years. Who wants to mess around with gasoline when you can have a car which is better in nearly every way for the same price? The auto companies are slowly waking up to it. Too slowly.

          • I don’t see many purchasers in Alcoy, because it’s in hilly terrain, has hot summers, cold winters, and locals have to drive 50 to 150 km to get to a large city. Those battery cars simply won’t outperform a small diesel which gets 55-60 mpg.

      • Dennis Coyne says:

        Hi Watcher,


        Fleet total (for those that share their data) has a median MPG of 148 miles per gallon.
        The top 99 drivers all have MPG above 1000 MPG, so if they drive 12,000 miles per year they would use less than 12 gallons of gasoline.

        The Volt does have a gasoline engine, which is used as “backup”. The Prius plugin only goes 25 miles on a charge so more gas would be used.

        When the Bolt is widely distributed more will sell because some people like GM cars.

        Right now sales of the Bolt are severely limited by supply.

      • Silicon Valley Observer says:

        For what it’s worth, I bought a Nissan Leaf in December. Why? I get to use diamond (HOV) lane at all times here in California. If you took that away, electric vehicle sales in California would drop like a rock. It’s a major incentive. Also, take away the $10,000 in federal and state rebates and electric vehicle sales would be devastated. Without those two major incentives I never would have bought it.

        My personal opinion? I like driving an electric car, I like being able to charge it at home for less than gasoline (even at these low prices). I like the quiet acceleration. But I still need my ICE vehicle for long trips. If I had to have one vehicle, it would be an ICE.

        • Nathanael says:

          Get a Model 3.

          The fact is that electric car sales are not driven by incentives, despite your personal case. They’re driven by being *nicer*, which you already acknowledge. You only need the ICE because the Leaf has short range and no high-speed charging stations (the fundamental mistakes being made by every company except Tesla, and now a few of the Chinese companies). I do road trips in my Model S, no problem.

          • Stephen Hren says:

            I’ve had a Leaf for two years now. I love it, but it is not a mainstream car, more for us treehugger types. It is superior to an ICE in terms of acceleration, pleasantness to drive, etc, but the miles fall off hard when you use a lot of heat or AC, and range anxiety kicks in. I won’t go more than 40 miles round trip if I need heat/AC.

            Now that there are second generation electrics coming on the market, there are reasons to be optimistic that EV sales will take off. Here’s why I think that:

            1) Urban areas will take up EVs fast: as the infrastructure of charging stations goes up while range in new models also goes up, range anxiety will decrease. Gas prices remain high is much of Europe because of taxes, and diesel used to be seen as green but because of the VW scandal and urban air pollution, politically there will be a big move towards EVs.

            2) Political trends like the Trump presidency and rolling back of EPA mpg requirements will encourage lefty EV fence-sitters to buy new EV cars. People love to buy new cars and if you can feel virtuous while doing so, all the better. Their Prii are getting old and EVs are looking hot.

            3) Driving in traffic is much more pleasant with an EV, as an ICE vibrates annoyingly all the time. Fuel is wasted and bicyclists have exhaust spitting in their faces from an ICE. Some estimates I’ve seen put the fuel economy of an urban trip in moderate traffic less than fifteen minutes long as around 8mpg. EVs are at least ten times better than this. Once you have an order of magnitude increase in efficiency, expect a rapid adaptation, and the cities will lead the way.

            This will likely lead to further political polarization in a few years as urban lefties rely on a completely different energy infrastructure for their mobility compared to rural righties. More fun ahead…

            • Oldfarmermac says:

              I live in a mostly rural area with fair sized to large cities at least fifty miles apart, and small cities or towns mostly at least ten to twenty miles apart.

              Incomes in this part of the country are relatively modest, but not rock bottom.

              Most households have two or more cars, as a matter of necessity or preference and convenience. Almost every household excepting the very poorest people or those who cannot drive due to age or legal trouble has a car.

              Most of the ones with one car could get along no problems except for the occasional longer trip with an electric that will go eighty to a hundred miles. Not more than maybe one person out of a dozen commutes round trip more than eighty miles.

              Almost all the households with two or more cars could make excellent use of a Leaf or comparable car as a commuter and errand car.

              IMO within a few years there will be a good solid market for short range electric cars simply because it will be possible to sell them for a few thousand bucks less, meaning they will be considerably cheaper to drive than a longer range electric, due to lower purchase price, property taxes, insurance costs, financing costs, etc.

              Most people who own two cars these days commute in the cheaper one, and buy the cheapest thing they can get for the day to day car, consistent with their status and personal preferences.

              Range really won’t matter to them, Monday to Friday, once they get used to the idea of owning an electric car.

              My wild ass guess is that the average commuter doesn’t have to make an unexpected side trip on his way home that will take him more than ten miles or so out of his way more than once every few months.

    • Dennis Coyne says:

      Hi Ashtorak,

      My expectation is that eventually PV and EVs will replace a lot of oil use.

      I explored growth in Plugin vehicles in post below

      The low scenario leads to higher oil prices because there will still be demand growth from other oil uses besides personal transport (about 40% of total oil use). Very little oil is used to produce electricity so the key metric is how quickly electricity replaces oil in transportation and the ICE vehicle fleet is replaced with plug-in hybrids, EVs, and maybe natural gas, or propane powered vehicles. The high scenario (fast ramp up in plugin vehicle ownership) might result in lower oil prices by 2040, but I believe reality may fall between the high and low scenarios and oil prices may remain high until 2045, unless there is a depression in 2030 (which becomes more likely under the low scenario (slow adoption of plugin vehicles and high oil prices leading to economic disruption).

      • ashtorak says:

        Thanks for the link. I will go with the high scenario then (fast ramp up of EV), which means from 2025 on gasoline demand stalls and starts to go down noticeably (at least in some major economies) so that oil price will not be able to stay for longer periods of time at 100+ $ levels.
        Why didn’t you put low and high price curves in your chart above?

        • Eulenspiegel says:

          The big unknown factor here is China.

          When the aggressivly promote electric cars, it will go faster – at least the chinise part of oil consumption will reverse. They have the instruments, no new number plates for ICE cars, driving stops during smog and so on. They got all electric scooter the same way, there is no gas scooter in chinese big cities anymore.

          • Caelan MacIntyre says:

            Recall that we are talking about a place that has created ghost cities, to say nothing of the rest of its messes.

        • Dennis Coyne says:

          Hi Ashtorak,

          I had to interpolate and only wanted to do it once. The EIA’s AEO gives annual data and I use monthly data in my scenarios for LTO. So I used the average of the AEO reference and high price scenarios.

          In comment linked below I use a different oil price scenario.

          Note that it will take some time to substitute for transportation of goods so that oil use for trucks, ships, air transport, and farm use will take longer to replace.
          Remember that only 40% of oil use is currently for personal transport.
          If other uses of oil (trucks, rail, air, and water transport) continue to grow at 1.3% per year until 2040, oil might still remain relatively scarce and oil prices may not decrease much before 2050. Also keep in mind that if their is adequate demand the price will be determined by the marginal cost of oil production (the cost to produce the most expensive barrel.) Those costs are likely to remain high for the oil output shown on my medium scenario (where the simplifying assumption is made that demand and oil price will adjust to available supply.) I think it unlikely that we will see “peak demand” (where this is defined as lack of demand for oil that drives oil prices lower) until 2050 or later. For that reason I believe the scenario at the link below is more realistic.

          • Kolbeinh says:

            The whole energy system is adaptable. Keep in mind that during WW2 the germans produced synthetic oil from coal, and Sweden had to convert car engines to wood based combustion, and who would have guessed…. at the end of the war briefly turned to shale oil production . You can look it up.

            I agree with you that to suggest anything else than that the future scarce oil resources would be expensive would be foolish. It is concentrated energy, difficult to replace.

            • AlexS says:

              “at the end of the war briefly turned to shale oil production”

              I guess it was oil shale (kerogen), not shale oil.

          • Nathanael says:

            There are now several companies aggressively marketing electric trucks.

            Rail is of coruse easy to make electric, and outside the US, almost all of it is already electric.

            Water and air are wild cards. But they come out of different fractions of the barrel, and this is important. The price of oil is set largely by the demand for the *highest-margin product*, which is also the highest-volume product: gasoline. A crash in gasoline demand causes a crash in oil prices, straight up, even if jet fuel demand and bunker fuel demand remain strong.

            This happens until gasoline is no longer the highest-margin product, at which point refineries spend a lot of time retooling to produce other products (removing a bunch of the units which convert other fractions into gasoline, for example). And a lot of them go bankrupt. The new smaller number of refineries may be optimized for jet fuel. I’m not sure what the stable price is after that happens, but I’m dead sure that after the gasoline and diesel demand drops, there will be massive oversupply of crude oil until all the refinery closures and retoolings are over.

    • Nathanael says:

      Well, to be *fair*, you have to store the photovoltaic energy at about $0.129 / kwh retail (production cost is suspected to be $0.078 /kwh ), which makes the all-in cost at night $304 retail or $217 production cost. (Notice the immense profit margins on the batteries.) However you don’t actually need batteries all the time (there’s daytime, and then there’s times when the wind is blowing, and then there’s hydroelectric including pumped storage… so the real cost is somewhere in between this and the pure photovoltaic cost. Also the record low PV bid is now $0.0242/kwh.

      However, this number is wrong, because the oil price is driven by gasoline demand (as of now; this will change once gasoline demand is destroyed). The most efficient gas engines are only about 23% efficient. Electric motors are upwards of 90% efficient. So in fact a barrel of oil can drive a car the same distance as about 435 kwh (slightly less) — this means the PV cost at the record bid amounts to $10.52/bbl, the PV cost at 5 cents amounts to $21.75/bbl, adding batteries at production cost amounts to $55.68/bbl and adding batteries at retail amounts to $77.87/bbl.

      The more interesting points: photovoltaic prices continue to drop, battery production costs continue to drop, and electric cars are just plain nicer to drive than gasoline cars so they can carry a premium. Also they don’t need engines or transmissions, which makes up for a lot of the battery cost.

      I see oil prices being capped by the *production capacity* for electric cars and trucks. Once production capacity isn’t a limit, the oil price will certainly drop below $40/bbl and will almost certainly undershoot (because that’s what it does). Modeling the production capacity is hard since it depends on choices by a lot of manufacturers most of whom are Chinese and don’t publish any English-language information at all.

  23. George Kaplan says:

    Baker Hughes international rig count for February is out oil up 23, gas down 7. That’s the biggest jump for oil, and now the highest number at 695 since last May. Biggest change was Europe up 13 and Latin America up 8.

    • George Kaplan says:

      Offshore is down 6 to 200, equal with October 2016 and the lowest since late 2011. A lot of rigs were added for “other Europe” – I have no idea what countries that covers, but I think it must be small onshore fields.

  24. George Kaplan says:

    There’s a new report summary from UKOG Authority covering North Sea Oil. Everything is awesome apparently, except nobody is investing. I couldn’t find a mention of Buzzard but I think it is the single biggest impact likely to happen over the next 2 or 3 years. It represents about 18% of production, it has been on plateaus for almost ten years and has produced almost 40% of the originally estimated OOIP. That is incredibly good performance, but the problem is that it will almost certainly be followed by rapid decline once it comes off plateau. A quick fall combined with steady decline of other old, small fields would eclipse any gains from the new projects this year and next. Water production was pretty steady through 2016 but there was a hint that it might be starting to rise before and after their shut down in late summer, so something might be on the horizon.

    • AlexS says:

      UKCS oil and NGLs production projections
      source: UK Oil and Gas Authority

      • AlexS says:

        According to the IEA report, the UK’s oil production is set to decrease by 50,000 bpd to 965,000 bpd this year. Production will rebound from next year amid the start up of a number of “large projects” including BP Plc’s Clair Ridge, the IEA said.
        “If we see further cutbacks in investments at already producing fields and an increase in decline rates, there is a risk that output towards the end of the forecast period could be slightly lower,” the IEA said, referring to 2022 as the end of its forecast period. The IEA expects oil production in the UK to average 980,000 bpd then.

  25. Energy News says:

    Reuters – OPEC oil exports up 1.72 mln bpd to 25.32 mln in February led by Mideast producers
    Charts on twitter
    OPEC oil exports
    Iran oil exports
    Iraq oil exports
    Saudi Arabia oil exports
    Platts OPEC cut complience

  26. Boomer II says:

    I’m a bit confused by this thinking. Is he urging oil companies to put in the money (and maybe stop paying dividends) or is he asking investors to step up (they have already been putting money into questionable LTO investments). And maybe companies and investors would rather put their money elsewhere, perhaps into companies that reduce the need for oil.

    Oil industry heading for next crisis if things don't change: Experts: “We need to spend in excess of $600 billion just to keep oil and gas recovery flat,” he said. In 2016 companies spent $380 billion, he said, adding, “That’s going to start to show itself in three to five years from now.”

    • Boomer II says:

      Also, at what point will the oil industry actually say “we have reached peak oil.” Right now they point to lack of investment. Will the industry continue to point to lack of investment as the primary reason there won’t be enough oil?

      • coffeeguyzz says:


        EIA just released their STEO.
        Natgas output for 2018 projected at 78 Bcfd.
        All time record.

        US oil output for 2018 projected at 9.7 million barrels/day.
        All time record.

        • Boomer II says:

          Are you saying there is no cause for concern that investments aren’t going to be sufficient?

          And if there is record gas production, can we assume gas prices will continue to stay low? (Good luck, coal industry.)

          I notice that Exxon is talking about increased use of natural gas for products to ship overseas. Is that a recognition that the profits will be there instead of production?

          • coffeeguyzz says:

            Essentially, all I would feel comfortable saying is that there is a great deal of increased hydrocarbon potential in the US, especially nat gas and NGLs.
            This reality, if it comes to pass over the next 20 months – as the EIA seems to say – will have a great many knock on consequences, most especially in the US’ role in the international markets.

            • Boomer II says:

              To me, the best part of increased natural gas production is that it keeps prices low and stifles the use of coal. And if gas goes into plastics and other goods, that’s better environmentally than burning it.

          • Nathanael says:

            The coal companies, for reference, are complaining about “lack of investment”. What this actually means is “lack of profitability” meaning that nobody wants to invest.

            Most industries are not as lucky as the airlines, which can get infinite investments despite a 100-year-long history of consistent losses.

        • George Kaplan says:

          They’ve slightly increased GoM production – mostly flat through 2017 and then suddenly everything grows by over 300,000 bpd to the end of 2018. I have no idea what projects they think are going to be able to give this on top of the 10% yearly decline they have to contend with (and my guess is the EIA don’t either). The IEA lack of investment issue is going to show earliest and deepest in the deep water – mostly West Africa and GoM.

  27. Boomer II says:

    Goldman Sachs Sees ‘’Long-term’’ Oil Prices Below $60 | “Oil prices will settle in the $55-$60 range in the long term, according to Jeff Currie, the lead commodities researcher at Goldman Sachs, who spoke to Bloomberg this week regarding new developments in commodities markets.

    In the interview, Currie described a survey he conducted with oil industry leaders in Texas. He asked members of the Houston energy sector where they expected prices to go over the long term and they answered with consensus: somewhere between $55 to $60.”

    • AlexS says:

      The main reason, according to Goldman Sachs, is a projected rapid growth in the U.S. LTO production.

      “The U.S. supply response seems to be gaining momentum much faster than previously thought,” Currie said. “It’s because of two factors. One is productivity gains, but also access to capital.”

      If LTO production fails to grow at rates expected by Goldman and many others, oil prices will inevitably rise much higher than $60 by the end of this decade.

      • Dennis Coyne says:

        Hi AlexS,

        My analysis suggests that LTO output will not rise very much at under $60/b, in fact I would expect the 15 Gb scenario to be more likely if oil prices remain under $60/b long term. Even the AEO reference oil price scenario would result in very low growth in US LTO through 2020.

        • AlexS says:


          I agree. As I said above, in my view, at $60 LTO production may increase by 200-400 kb/d per year over the next 4-5 years. That corresponds to the IEA forecast (1.4 mb/d in 5 years, or less than 300 kb/d per year) and the EIA AEO 2017 projections

          I think that Goldman and others who predict a much steeper growth:
          1) underestimate the effect of renewed cost inflation.
          2) assume that shale companies will be willing and able to overspend their operating cashflows (after having temporarily reached free cash flow neutrality in 2H2016); and will have unrestricted access to capital markets.

          • Dennis Coyne says:

            Hi AlexS,

            At $60/b there will be no growth in LTO output, but the decline might be less steep, flat output in my view is quite optimistic for LTO output at oil prices of $60/b or less in 2016$.

            I guess we will have to wait and see. Oil prices will need to increase to make increased well completion rates profitable. We will need to see $70/b by the end of 2017 and $85/b by the end of 2018 and $120/b by 2024 to see the rates of LTO output increase you envision.

            The analysts that think $60/b is a high enough oil price to increase LTO output are incorrect in my opinion.

          • Nathanael says:

            In the short term the question of when shale oil companies will lose access to the capital markets is very interesting. If they keep having access to Dumb Money, this means we’re into permanent oil price decline. If they lose access to capital, we get one last oil price spike before the final decline starts in the mid-to-late 2020s.

    • As you know, the renowned crystal ball firm “Wooden Fernando” outperforms “Goldman Sachs”. It predicts price will be about $63 per barrel. For a subscription to our cheap service please see my blog.

  28. Boomer II says:

    Oil little changed as growing U.S. supply offsets bullish Saudi comments | Reuters: “The market, however, fell in post-settlement trade after data from industry group the American Petroleum Institute showed U.S. crude stocks last week rose 11.6 million barrels, or more than five times analysts’ forecast.”

  29. Boomer II says:

    If oil prices are going to remain in the $55-60 range for a long time, why would companies invest billions to keep the supply going in the future?

    If there is no indication that prices will be high enough to cover costs, from a business standpoint it doesn’t make sense to do projects that lose money.

  30. Watcher says:

    Gist: Hedgies had a talk with a Saudi guy about how oil prices on NYMEX are defined . . . automated trading . . . why did funding flow so fast to shale to keep production up despite low price.

    Ominous stuff. KSA is learning supply and demand don’t define price. And there is talk of free money to the investment banks flowing funding to shale — which illuminates the ability of the Fed to essentially print oil.

    This points towards difficult decisions. OPEC knows money is a basis of sorts for day to day economics, but they can also see it’s not proper payment for something with actual value — oil.

    Durden version offered up low shale production costs in some editorializing, but like with many things, the big picture matters more than details. Hedge funds would appear to be colluding.

    • Boomer II says:

      I’ve been trying to pull apart what is being said publicly from what is going on privately. That’s why I keep asking if Exxon is mainly just doing what it can to keep investors happy rather than having any clear plan for a long-term future.

      As I have also said, if the oil industry thinks one thing privately, it won’t necessarily say so publicly. You want to cash out before potential buyers and investors realize what is happening.

      I think the best gauge we have now are decline rates in the Bakken and by extension the likely decline rates in other LTO areas. And when it becomes obvious that these area are playing out, what happens to the world oil market then?

      Some people have said the Permian is a ponzi scheme, and I have wondering what other oil plays are ponzi schemes.

      And I have also asked who is supposed to put up the money to produce oil down the road. Are investors supposed to foot the bill? Are big oil companies supposed to do it? Are governments supposed to do it?

      And why is the conversation about producing more oil rather than about getting by with less oil? Yes, I know the renewable and EV folks talk about it all the time, but will the oil industry ever acknowledge that scenario? Or is it safer to blame the problem on lack of investment?

      • Caelan MacIntyre says:

        Sociopolitical Entropy In The Context of Peak Power and The Maximum Power Principle

        “And why is the conversation about producing more oil rather than about getting by with less oil?” ~ Boomer II

        Possibly because this effectively means not only talk about the end of civilization-as-we-know-it but, from that, talk about the end of government-as-we-know it.

        In that, there’s a lot of powerful psychology and vested interests.

        I wouldn’t minimize the changes between ‘as-we-know-it’ and ‘as-we-don’t-know-it’, either, which could prove to be, or at least feel, as different as night and day.
        Bear in mind, too, that we have a growing global population with a still-growing taste for a disproportionately-large-for-the-ecosystem lifestyle-footprint in the context of shrinking energy.

        EV’s and PV’s, etc., and, with them, that fairytale smooth transition– even if they successfully happen— aren’t going to save the state/government-as-we-know it, and along with it, its musical-chairs socioeconomy and legal structures, police and military that serve up, and serve only, an ever-shrinking minority/elite…

        Good riddance…

        Let the powers that be, shrink and minimize…

        But they’re not going to go without a struggle.

        • Duncan Idaho says:

          I agree.
          And it is hard for most to grasp.

        • Nathanael says:

          Yeah, any major tech shift gores some incumbent oxes, and they will fight violently against the shift. (Witness Spain’s “tax on the sun”.)

      • Jeff says:

        Some oil companies have stated that they will increase the share of natural gas in their portfolio. This can be done by increasing the production of gas, decreasing the production of oil or both. Either way I interpret this as they don’t see the upstream oil sector as continuing to be that profitable in the future (lack of investment opportunities compared to what consumers are willing to pay for oil).

        Another way to put it is that the “risk reward” of investing in oil production has gone from “high risk high reward” to “very high risk but not so high reward”. Everyone knew that this would happen someday, since the extraction rate is much higher in OECD countries compared to OPEC countries. I think that this is one of the reasons that we continue to hear that investments need to step up but they aren’t. US LTO has a much shorter cycle and the risk is not as high.

        Major oil companies are integrated, i.e. they also refine oil and can continue to do so – although this is not that profitable at the moment. They have several potential businesses cases but none of them looks very attractive when compared to how it used to be. They are off course well aware of this but what should they tell investors?

        • George Kaplan says:

          Jeff – good comment. Things are always a bit fuzzy, and the companies might prefer to keep it that way. The recent ExxonMobil announcement of putting $20 billion into downstream investment fits in as well, and the appointment of the new CEO as someone coming with downstream experience makes more sense in that light. I think it is not just the IOCs turning to gas though – Saudi, Kuwait, Nigeria, Azerbaijan, Mexico, India, Oman – they’ve all recently highlighted gas over oil for new development opportunities – who is their intended audience for such statements?

          For the public companies it’s worth highlighting that the companies really consist of the present investors, in theory as represented by the chairman. The CEO and senior management are supposed to run the company to maximise return for the shareholders, not for personal gain (though it might not always look or work out like that). So it’s really future investors that might be subject to obfuscation for the gain of existing ones more than the board.

        • Some of it is low risk very low reward. For example, I would buy heavy oil projects in Canada, as long as I could get management to accept a 7 % rate of return.

      • Ves says:

        There is no “plan” in life; life goes from one extreme to other. Exxon buying Permian is because there is nothing else to buy. You only buy what is available to you. If it’s only crap shoes and you need shoes you buy crap shoes. Then they put lipstick on that crap shoes so their ego is not hurt.

        “And why is the conversation about producing more oil rather than about getting by with less oil? ”

        Because that conversation is very unpleasant. People could ask why they got sucked in 1 $ trillion debt on a new cars that will be unaffordable to run. Not necessarily because gasoline price will be so high but because disposable income is shrinking. If you look at recent retailer bankruptcies and their balance sheets it is consumer disposable income that is shrinking.

        • Watcher says:

          Ya you guys get it.

          Why commit money to poor prospects?

          Beyond oil of late (defined as even before 2008) CFOs have recommended buybacks with cash rather than expansion. It is analogous to scarcity of oil, scarcity of opportunity. Stock buybacks in days of yore used to be quite negative in that they said what a shareholder did not want to hear — nowhere else to put the money. And guess what — shareholders could blame management for that, for lack of advance planning, for lack of research, for lack of vision. No one believed there was nowhere else to find growth.

          That changed. Buybacks don’t threaten management anymore.

          Though maybe not so much with oil. It’s much more distinct a business. You find it, you extract it, you sell it. Covering up trends with buybacks is much less possible. So management needs to in effect look busy. Somewhat simply that. Look busy.

          The other half of the equation, why think there will be consumers, is population growth. Relentless Indian and African and South American population growth.

          Odds are pretty

  31. George Kaplan says:

    Anadarko announced 2017 budget yesterday:

    $4.5 to $4.7 billion, concentrating on upstream onshore, midstream and GoM, but looks like they are moving towards LNG.

    For offshore:

    “In the Gulf of Mexico, the company plans to continue leveraging its premier infrastructure position and drill approximately seven development tiebacks during the year. In addition, Anadarko expects to benefit from a full year of production from the recently acquired Freeport-McMoRan properties, which doubled Anadarko’s sales volumes to more than 160,000 BOE per day at the end of last year. Minimal capital investments are expected to be required in 2017 to maintain the steady, long-lived, high-margin oil production provided by the company’s strong cash-generating assets in Algeria and offshore Ghana.”

    I’d say that means no Shenandoah FID, and possibly smaller than originally planned Horn Mountain Deep and Constellation developments, maybe with Phobos and Warrior tie backs. I think most of these will maintain production in existing hub facilities rather than give a significant increase.

    • Nathanael says:

      With the lack of cheap-to-produce oil, they’re all switching to NG, which they can still produce fairly cheaply.

      But it sells for such a low price that’s not a great move either. And it’s hard to store. And the cap on the NG price is ratcheting down as solar and wind and heat pump prices drop.

  32. Dennis Coyne says:

    From oil

    In short, shale production could come back much faster than the markets originally expected. For now, estimates run the gamut. JP Morgan says shale production will add 400,000 bpd by the end of 2017 while Rystad Energy and Macquarie put the figure at a much higher 900,000 bpd.
    The higher end of that range should not be ruled out given the early signs of robust growth.

    As Bloomberg Gadfly points out, the rise in U.S. oil production since output bottomed out at the end of last summer has been swift. Since September, U.S. production has climbed roughly 125,000 bpd on average each month, pushing total production above 9 million barrels per day. That is a much faster pace of growth than the original shale boom that began years ago. The corresponding period for the 2011-2014 shale boom saw monthly growth of just 93,000 bpd.

    Note that much of this growth in output is from GOM. Since September US output increased from 8567 kb/d to 8783 kb/d, an increase of 216 kb/d. The Federal Offshore (PADD 3) aka GOM increased from 1506 kb/d to 1728 kb/d, an increase of 222 kb/d. In addition Alaskan output increased by 67 kb/d.
    So if we consider Lower 48 onshore C+C production output decreased by 70 kb/b from Sept 2016 to December 2016, so much for the robust recovery of US LTO output. So maybe it is just the LTO sector that has seen a “robust recovery” since September. The EIA data shows US LTO output has declined by 66 kb/d from Sept 2016 to Dec 2016, so 94% of the L48 onshore decline has been due to the continued decline of US LTO output. So any expectation of big increases from US LTO may be premature, there is a 5 month lag so perhaps we will see an uptick by May 2017. It will depend in part on the price of oil and nobody knows what that will be.

    • Dennis Coyne says:

      A very optimistic scenario is presented below with very low rates of decrease of new well EUR (similar to the 60 Gb scenario in the post. A couple of changes in assumptions, well cost $7 million (to reflect full cycle costs, $1 million was added to the cost of the well) in 2016$. Also the oil price scenario is different with oil prices rising to no more than $120/b (shown on right axis, dotted line).
      Also the wells completion rate is higher initially, matching the rate in 2011 (30 more well completions each month) and then matching the rate of increase from 2012 to mid-2014 (an increase of 11 completions per month. The maximum well completion rate is somewhat higher than the previous 12 month maximum (1220 wells), but less than the on month maximum of 1400 wells at 1260 well in 2021. Output increases by 100 kb/d in 2017, 440 kb/d in 2018, and 450 kb/d in 2019, 500 kb/d in 2020, and 380 kb/d in 2021. Peak is in 2022 at 6100 kb/d.

      Note that I doubt this scenario is correct and also note the high oil prices needed to make such a scenario economically feasible. I believe the high oil prices are possible, but I doubt that the annual rate of EUR decrease will be as low as assumed in this scenario. More reasonable assumptions result in about a 30 Gb URR and a peak of 5 Mb/d with the same oil price assumptions.

      At $55/b this scenario does not occur, the wells would not be profitable to drill.

    • AlexS says:


      The numbers from the EIA’s STEO for Lower 48 onshore oil production and from the EIA/Drillinginfo report for US LTO do not confirm a rapid growth in LTO output.
      The STEO shows that total onshore C+C production started to recover only in January; while the data for LTO shows continued declines to January.
      I think that 400-500 kb/d growth in LTO production between December 2016 and December 2017 (projected by JPM and IEA) is possible, but 900 kb/d is unrealistic.

      U.S. Lower 48 states ex-GoM C+C and U.S. LTO production, 2014-early 2017
      sources: EIA STEO March 2017; EIA/Drillinginfo U.S. tight oil production report, February 2017

      • Dennis Coyne says:

        Hi AlexS,

        That much of a rise in well completions would require a much faster rise in well completions than occurred when oil prices were over $100/b. At $60/b as I believe you think that oil prices will remain, there will be very little incentive to increase the well completion rate to the degree needed to raise LTO output by 400 kb/d, at oil prices less than $60/b we will be lucky to keep output at current levels. If oil prices increase to $70-$75/b by the end of 2017 we might get a 200 kb/d increase in LTO output at most.

        • coffeeguyzz says:

          … couple of data points from today’s Directors cut

          Daily output increased 38,000 bbld
          Completions decreased from 84 to 54
          ND oil price 40 bucks

          Hhmmmm …

        • AlexS says:


          Contrary to the articles in and Bloomberg Gadfly, there was no growth in LTO production in late 2016. But production apparently started to rebound in 1Q17, and growth will likely accelerate later in the year.

          Shale companies’ guidance suggests a 25-30% increase in capex for 2017 vs.

          Oil services costs have bottomed in 4Q16 and are already recovering. But annual-average costs will not be higher than last year as there is still significant spare capacity. Hence an increase in dollar capex will likely translate into a proportional increase in real drilling/completion activity.

          Shale well completion costs are about 2/3 of total well costs, so the # of well completions will likely exceed the # of wells drilled (which is supported by guidance of the companies like CLR) and the number of the DUCs will decrease.

          I have no doubt that Dec 2017 LTO output will be higher than in Dec 2016.
          Year-average production may be also marginally higher than in 2016.

  33. The North Dakota production is out with production numbers for January. ND production was up almost 38,000 bpd. I will have a post out by noon tomorrow. I would do it today but I am not feeling too great right now.

    • coffeeguyzz says:

      Mr. Patterson

      Hope you feel better.
      Yes, ND production up 4% in January from December.

      DAPL should be in service next week with more upside expected.

      • George Kaplan says:

        Availability went up. As the report says they had ten good days at the end of the month and would have preferentially bought on high producing wells, that had been knocked offline earlier. It will have gone up even more in February so there will be another production increase irrespective of DAPL. I think the low permitting is of interest – only 29 net, the lowest since 2006. Maybe they are waiting for DAPL, maybe just noise (I think numbers might be high again this month like December), or maybe they are running out of interesting spots at current prices.

  34. clueless says:

    Shallow, Mike or anybody –

    They say that there is no such thing as a dumb question. This question may challenge that assertion.

    First, I would note that iron ore prices have doubled in the past year. With that in mind, my question is: When they drill down 8,000 feet and then do a 2 mile horizontal, do they put oilfield pipe in the entire hole [both oil and gas wells]?

    If they do, that should cause a significant increase in well cost since I assume that most of the operators that inventoried pipe in anticipation of increasing prices [ of steel along with oil during 2013-2015] have pretty much liquidated their pipe inventory in the past 24 months.

    PS: Note for non-accountants. Inventory is usually valued at the lower of cost or market. So, if they acquired inventory at a high price, and the fair market value at the end of any succeeding quarter was less, a writedown to FMV would have occurred at that time.

    • AlexS says:


      I think that iron ore price accounts for a relatively small part of oil pipe price.

      • clueless says:

        Okay. But, if they need steel for oil pipe, for a 3 1/2 mile hole [see question in my previous post], the price of steel is up 55% YOY.

        “Steel prices are continuing to perform favorably in the first quarter of 2017. Higher prices for steel inputs, expectations of President Trump’s USD 1 trillion infrastructure plan in the United States and the consequences of a looming trade war between China and the United States are supporting prices. The commodity traded at USD 620 per metric ton on 10 February, which was up 2.6% from the same day in January and was 5.4% higher on a year-to-date basis. The price was up 55.4% from the same day last year.”

        • shallow sand says:

          clueless. I believe the lateral is cased. I have looked at some AFE’s for one mile lateral wells, Surface, intermediate and production casing totaled around $400K. Another $80K for tubing, which starts somewhat into the curve.

          It appears that the iron cost for wells proposed in 2017 was not much different than for wells on the same pad from 2013 and 2014.

          However, the new AFE’s estimate 2017 well costs at $5.5 million, whereas the 2013-2014 wells were nearly $8 million. Most of the savings is in the cost of the frac.

          Interesting on this four well pad, despite an overall average oil price of $58.17 and average gas price of $2.60 (due to the benefit of high oil prices in 2013-2014) the project is still around $12 million from payout.

          A non-operated working interest owner is selling out of this project as there are four more wells planned for the pad, at a cost of another $22 million for 8/8 (100% of the working interest). Gross oil is north of 600K BO and gross gas is also north of 600K mcf. Actually not bad for a four well Permian pad. However, 2016 net income for the project for the working interest owners was just $2.1 million. Payout will be tough to achieve at sub $50.

          Payout matters to private companies, be it the giants like Yates, Bass and Fasken, who are all selling. Also to small fries like us and Mike, who wish we would have sold four years ago.

          I just looked at a CLR slide presentation. Every metric imaginable, except payout.

          As US production increases despite poor economics, it will be interesting to see how much longer money will be thrown at this stuff. Here is to hoping we do not see the 2016 lows again, but I am not so sure.

          • Eulenspiegel says:

            Investorts threw money at airlines since they exist – and never got a payout. They will keep throwing.

            The narrative of oil is strong – everybody with a few grands wants to be an oil baron like in Denver Clan. And in every newspaper and oilpage is written fracking oil ears tons of money at the current prices.

            So the money will keep flowing – interrupted by small bumps when another shale company has to file chapter 11.

  35. Watcher says:

    ZH seems to have scooped this story by 24 hrs:

    The vid talks about the late night meeting of Saudis and shale lenders, hedgies and whoever, asking how prices are determined on their markets, etc, as above.

  36. Boomer II says:

    Speculators got crushed while oil industry may have learned lesson and is more cautious on prices: “BP Group Chief Executive Robert Dudley said he’s planning for ‘lower for longer prices’ in the $55 to $60 per barrel range for the next five years.”

    • I would tell Dudley to plan for $63. That price seems to tickle higher activity so it should do for a while. $55 to 60 doesn’t do the job. And we know $60 is the price needed by KSA to drill more.

  37. George Kaplan says:


    ‘Adam Sieminski, the former head of the US Energy Information Administration, cautioned Tuesday that a “decade of disorder” could be looming for the global oil market as declines in long-term supply projects and a host of other factors cause potentially severe market imbalance. … “We’re facing a lot of uncertainties, I think, in a lot of different areas,” … A wave of global populism, trade wars and geopolitical issues could all complicate market fundamentals, Sieminski said.’

    Sudden near term supply drop seems to be flavour of the month at CERA, even the Hess CEO said something similar. It’s been on the horizon for two years now, but no-one but IEA recently raised much concern – maybe it was considered too ‘alarmist’. And even then not one mention that I have seen so far of the collapse in discoveries over the past five years and how that may affect things, even if interest in higher investment does pick up, and also nothing about the debt overhang in the E&Ps and it’s likely impact.

    • Boomer II says:

      I’m thinking that the future doesn’t look good for the majors, but no one wants to come right out and say that for fear of losing investors. And the race to pump out as much from LTO just hurts the industry as a whole by keeping prices low, and depleting supplies faster.

      And the 10 year projection puts us into the time frame of peak oil predicted by some here. So we would have a combination of low prices for awhile, market disruption, and then a noticeable lack of oil.

      Maybe if there are enough of these types of warnings from the industry itself, it will finally sink in that we’ve got to make post-oil plans.

  38. Ves says:

    OPEC “talking” production cut of 6 months in making and $5-6 more per barrel is gone within 2 days. I guess that made everyone at that OPEC/Shale meeting in Houston nice to each other.

  39. Watcher says:

    Reminder there was recent indication that OPEC exports did not decline.

    Read that again.

    It was winter. Domestic consumption down. You can have lower production with no impact on export revs.

    Maybe those evil Russkies hacked NYMEX HFT. That would be cool.

  40. Dennis Coyne says:

    Hi all,

    There are new posts up. The page needs to be refreshed to see them. I can’t figure out how to fix this problem.

  41. Oldfarmermac says:

    Electric cars have gotten quite a bit of attention, but natural gas fueled cars have not even been mentioned here recently.

    If the folks working on new gas storage technologies succeed, and small tanks that will hold large quantities of methane or hydrogen get to be reasonably cheap, natural gas and or hydrogen fueled internal combustion engines will be practical and cheap to run so long as gas stays cheap.

    Is anybody here keeping an eye on this technology?

    If wind and solar power displace most of the gas needed now for electrical generation, that gas could be used to run trucks and cars, and this in turn could reduce the need for oil to a substantial extent.

  42. Pingback: U.S. Shale Could Peak Before 2025 - Global Energy News

  43. Pingback: U.S. Shale Could Peak Before 2025 - Crude Oil News

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