Future US Light Tight Oil (LTO) update

In a previous post on US LTO future output there were suggestions that a bottom up approach might be better than the top down approach and I agree. I will attempt the bottom up approach here. The chart below is a quick summary, based on three different oil price scenarios (high, medium, and low). The dashed line is just the average of the low and high oil price scenarios. Data is from Enno Peters’ website shaleprofile.com and the EIA. (Click on “Tight Oil Production Estimates” for tight oil output data.)


Clearly I do not know what future oil prices will be, but my expectation is that oil prices will be between the high and low price scenarios presented below.


Note that oil prices are assumed to remain at $80/b, $100/b, and $120/b (all in 2016$) from 2040 to 2050 in the low, medium, and high oil price scenarios respectively.  For comparison the oil price reference scenario (Brent crude spot price in 2016$) for the EIA’s Annual Energy Outlook 2017  is also presented.

In the past I have developed scenarios for the North Dakota (ND) Bakken/Three Forks(TF) and the Eagle Ford. That analysis has been combined with new analyses of the Permian Basin and “other LTO”, where other means US LTO not produced in the ND Bakken/TF, Eagle Ford, or from Permian Basin horizontal wells. Also included in “other LTO” is roughly 7% of horizontal Texas Permian basin wells that could not be easily separated from vertical well output on the same lease as explained by Enno Peters.
The low, medium, and high oil price scenarios presented above are applied to all areas of US LTO output to develop three separate scenarios for each of the four areas (Bakken, Eagle Ford, Permian, and other LTO) and these are then combined to create the US LTO scenarios presented in the first chart.
The economically recoverable resources (ERR) for the three scenarios are 29 Gb, 38 Gb, and 43 Gb for the low, medium, and high oil price scenarios respectively. The high/low average (dashed line) has an ERR of 36 Gb.
The Permian Basin scenarios are presented below.


ERR is 10 Gb, 17 Gb, and 20 Gb for the three oil price scenarios and 15 Gb for the high/low avg scenario (dashed line).
The “other LTO” scenario is presented below.


The ERR of the three scenarios ranges from 6 to 7 Gb. This analysis would be improved by separating out the Niobrara and doing that analysis separately, possibly this will be covered in a future post.

The ND Bakken/TF Scenario is presented below.


The Eagle Ford Scenarios


The economic assumptions used in the discounted cash flow analyses are shown below, it was assumed that in the long run, wells that are expected to be profitable will be completed.


Note that for other LTO $1 million would be too low a well cost for a horizontal multistage fracked well, but for a vertical well this might be roughly correct. I don’t have good information for areas besides the Bakken, Eagle Ford and Permian on costs, so this is a guess.

Average Well Profiles for late 2016 are shown in chart below, cumulative output in barrels on vertical axis and months from first output on horizontal axis.


The chart below shows the total number of US LTO wells completed for the medium oil price scenario on the right hand axis. The maximum annual rate of US LTO completion in this scenario is 14,200 wells per year in 2021 (Jan to Dec), from Jan 2014 to Dec 2014 about 13,800 LTO wells were completed. This scenario has a rate of well completion only 2.9% higher than the previous maximum annual rate of well completion in 2014. The peak rate of output for the medium oil price scenario is 6495 kb/d in Oct 2021, 1825 kb/d higher than the previous peak of 4670 kb/d in March 2015.


The high oil price scenario has a peak output of 6813 kb/d in Jan 2022 (318 kb/d higher than the peak output of the medium oil price scenario), total wells completed of 233,500 by Sept 2031 and a maximum annual rate of well completion of 15,400 wells per year in 2021 (11.6% higher than the previous peak annual rate of well completion in 2014).


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302 Responses to Future US Light Tight Oil (LTO) update

  1. Not bad. Its amazing the amount of high quality work you do.

    When we look at this information we have to consider these light oil zones have enough potential to become a factor which impacts worldwide oil prices. This means that when operators react to increasing prices they may overproduce market demand and drop prices. The end result may be an undulating price cycle which bounces around between your high and low scenarios.

    Such a bouncing behavior over a period of say 10 years may lead to a peak USA LTO around 5-6 million BOPD as the industry learns to drill at a moderate pace and watch what’s going on around them before they pick up more rigs. .??

    • daniel says:

      2 MMPD increase amount for 2% of the world production and is miles away from the numbers shown in the media.

      • Dennis Coyne says:

        Hi Daniel,

        I mostly focus on C+C output which is around 80 Mb/d for the World. So you are basically right, but I would call it 2.5% of current World C+C output.

      • Yaman Tasdivar says:

        Hi daniel,

        I wouldn’t necessarily go by the numbers quoted in the media, and always look at the source.

        Dennis here does great detailed work, but I believe his assumptions are a bit on the optimistic side. Especially for Bakken, and also for Eagle Ford.

        I believe (and take this with a grain of salt since my energy experience is only in investing in stocks and I’m not a geologist) that Bakken is in terminal decline. I would be surprised to see it going above even 1.0 mbd at any point in the future. Eagle Ford may get a dead-cat bounce a bit, but not to the level shown in this article.

        But these are my estimates, and Dennis has more experience running these models than I do. So keep that in mind.

        • Dennis Coyne says:

          Hi Yaman,


          I am also not a geologist, but the Geologists at the USGS estimate about 10 Gb for the ND Bakken/Three Forks for the technically recoverable resources (TRR) at a 50% probability (median estimate or best guess), their F95 estimate (5% probability that TRR will be lower ) is about 7 Gb.

          See https://www.dropbox.com/s/evwtxgsuisewczk/2013_Bakken_ThreeForks_Assessment.pdf?dl=0

          and keep in mind the distinction between undiscovered TRR (UTRR) and TRR. The 2P reserves plus cumulative production (about 4.2 Gb) at the end of 2012 need to be added to UTRR of 5.8 GB for the ND Bakken/TF to get the TRR.

          For the Eagle Ford see page 9 at link below


          the estimate is 7.6 Gb for the Eagle Ford.

          • Carl Martin says:

            Although many here will not agree, meaning just more flak for you, I think you need to add the perspectives of the people with their boots on the actual ground. PXD has stated, that they believe both the Midland and Delaware basins will produce 75 billion boe. CLR also claims the same 75 billion boe about the Bakken. Because of all the gains in science, technology, and basic know-how about tight oil formations, the amount of boe can probably be upped to just bo alone. Just for fun, and the perspective, why not plot some graphs using such data?

            Keep in mind, that if the Bakken produces at 2.75 million boe/d as expected, then that results in production of 1 billion boe/year, which suggests that there is still almost 75 years of production to go at that rate. On the other hand, if production is merely 1 million boe/d, then it takes 2.75 years to produce 1 billion boe, which means production will stretch out over 200 years at that rate.

            Also keep in mind that TOD went under because of the stubborness of the editors in regards to being honest and correct about LTO production, and especially the Bakken. I see this website still making the same mistakes. While I commend the fact, that your graphs are getting much more realistic, they still do not take into account the effects of all the cross basin technology coming in from the Permian.

            The idea of the Bakken being in terminal decline is absolutely absurd. You have said that about 2 billion BO has been produced. I believe it is more like 1.5 billion bo. The company information available suggests at least five more years of core production to go, meaning wells producing with about 1 million boe as an EUR. I can only wonder how large you think the producing area actually is, how many wells will be needed, what the OOIP is, and what % of that is even recoverable?

            You do a lot of work and your graphs are great, but they don’t tell us much about what is actually happening in the LTO world.

            • Boomer II says:

              What is actually happening is that oil prices are declining, and most of the money and activity has shifted to the Permian.

              Is this not true?

              • Carl Martin says:

                Boomer II,

                Yes, that is generally what is happening, and based upon company projections of their expected production increases, we should expect not just more of the same, but actually MUCH MORE of the same. The oil price only needs to be $40-$45 to supply this planet with all the oil it wants and needs. The Bakken’s production might well be flat, or even falling further over the next six months, because of that fact. It is not difficult to understand.

                • Boomer II says:

                  “The oil price only needs to be $40-$45 to supply this planet with all the oil it wants and needs.”

                  Not many people believe this. There are projections that oil supplies won’t meet needs before long.

                  The oil supply is getting less plentiful and costs to get it out of the ground are going up.

                  Perhaps you have an interest in oil activities in the Bakken and want to let people know the Bakken isn’t in decline?

                  • Boomer II says:

                    Also, I think the bigger problem, for someone like you who wants us to believe corporate statements, is that the greater investment community has grown skeptical and is no longer so interested in buying oil company stocks.

                  • Mike says:

                    No, Boomer; he does not know his ass from a hole in the ground about the oil business; never has. Whatever he “thinks” he knows, he has read about it on the internet. Like most other stock “analysts” on Seeking Alpha with a day trading agenda (his I believe is investing in potash), its in his best interest to tout the wonders of US LTO so you’ll buy some stock.

                    People that exaggerate EUR’s and book fabricated reserves with the SEC, that hide behind EBITDA and IRR, and create investor presentations don’t have “boots on the ground;” that’s stupid. They sit in glass offices and are told what to do, what to say, what to release to the public and they do what they are told. Like this guy, they don’t know which end of a workover rig to walk to.

                    75 billion more barrels of oil from the Bakken, another 500,000 wells; imagine that! Its laughable.

                    Ignore him. Or better yet, introduce him to Texas Tea, they’d get along likes peas and carrots.

                    Stay curious !

                  • Dennis Coyne says:

                    Hi Mike,

                    Shallow sands says:

                    It appears to me if WTI averages $55 from now through year end 2020, 2020 will close with US LTO production at roughly double its current rate. This appears to be what the major US companies are guiding.


                    There was no smiley face so I assume he is serious.

                    Your thoughts?

                    I doubt LTO output doubles at $55/b, in fact I believe either flat output or decline would be more likely at that oil price level.

                  • shallow sand says:

                    Dennis. I am just repeating in general terms some of the Permian companies’ investor presentations from February and March, 2017. Basically are predicting at least double their present Permian production by 2020. XOM, OXY, PXD, EOG, FANG, all are going to spend tens billions of CAPEX in the PB in the next four years per their presentations.

                    XOM is going to spend 1/2 of its entire upstream budget on US shale in 2018.

                  • Mike says:

                    If that is what Shallow said I would have to respectfully disagree with him. I actually doubt he said that. We are in a prolonged period of low, volatile oil prices. The Bakken and Eagle Ford have both peaked and short of 150 dollar oil, will not recover. The Permian will not have the money thrown it at that other shale oil plays have; debt is going to catch up to the US LTO industry sooner than most people imagine. In your need to make models you continue to ignore the precarious financial state of the US shale oil industry. Its a business, oil extraction, not a game, or a stock opportunity, and the shale oil business has failed, miserably, from a dollar in, dollar out standpoint. You and Carl can ignore that, I chose not to. This shale oil stuff cannot go on much longer without Devine intervention. Otherwise, I don’t believe in predictions other than…be ready for anything.

                    I popped in because I think Carl Martin is an idiot and could not resist the temptation to say so, one more time. Thanks.

                  • Carl Martin says:

                    Boomer II,

                    “Not many people believe this. ”

                    It is not a matter of belief. It is a matter of fact. The present price is $47.97, call it $48. The 200 day moving average is $48.92, which is what the price has averaged over the past 9 months. This is because,“The oil price only needs to be $40-$45 to supply this planet with all the oil it wants and needs.” The purpose of the Opec cut was to reduce the OVER SUPPLY. Get it???

                    “The oil supply is getting less plentiful and costs to get it out of the ground are going up.”

                    That is incorrect, but I won’t bother even proving it. Please consult the company presentations, which explain such trivial matters. Service costs have however gone up a little starting in the 4th quarter, 2016. Expect much more of that until we hit the top of the present production cycle. This is known as business as usual. Not to worry.

                    Yes, I have a small amount of money invested in Bakken Companies, mostly because of their presence in the Permian, or in CLR’s case, the S/S. What I have to say has absolutely no influence on oil or stock prices. You are kidding, right?

                  • Boomer II says:

                    When people come here and make what sounds like a sales pitch, I assume they are selling something. Maybe representing an oil company. Maybe selling leases. Etc.

                    I am skeptical that many oil companies have a profitable future no matter what they say in their presentations. The big companies are shifting focus and the little companies stay afloat as long as investors and lenders give them money.

                    I’m quite familiar with corporate PR and know how companies put the best spin on things as they can, even if they are actually pretty close to going bankrupt or selling out.

                  • Dennis Coyne says:

                    Hi Mike,

                    I appreciate both you and Shallow sand offering your perspective.

                    Shallow sand did say that, but he was just summing up the investor presentations, it is not clear if he thinks those are correct estimates.

                    I agree with you that at $55/b output is more likely to decrease than increase.

                    I also agree with you that I have no idea what future oil prices will be so I have three different oil price scenarios in the original presentation and a lower oil price scenario based on Shallow sands’ input (and others).

                    See comment at link below for a very low oil price scenario and the model US LTO output. Actually $75/b is enough to increase output a bit (about to the previous peak in US LTO output), but not for long.

                    I agree it is not a game which is why I evaluate the economics using a discounted future cash flow analysis, the game is to make money.


            • Dennis Coyne says:

              Hi Carl Martin,

              The USGS estimates the Wolfcamp at about 23 Gb for LTO output, I have not seen estimates for other formations in the Permian basin. USGS has not done a recent estimate for the Eagle Ford, but David Hughes in Drilling Deeper estimates an economically recoverable resource of 7.6 Gb (see page 9)


              and this 2016 update


              Note that a mistake that Hughes makes is not adding the cumulative output and proved reserves to the undiscovered TRR (UTRR).



              For ND proved reserves in 2012 (about 3.3 Gb in Bakken or 2012 minus 2008 reserves) plus cumulative output 0.5 Gb is about 3.8 Gb. This must be added to UTRR (7.4 Gb) to get a TRR of 11.2 Gb, some of this is in Montana, for North Dakota alone the total is about 9.6 Gb for TRR.

              For the Bakken OOIP is about 400 Gb and about 3% is expected to be recovered.

              The average new well EUR is estimated based on actual well data see shaleprofile.com.

              The number of wells is based on the analysis of the USGS and David Hughes.

              Also keep in mind I do a discounted cash flow analysis using the assumptions I have given. If the wells are profitable (the discounted cash flow over the life of the well is more than the cost to complete the well), it is assumed that the well will be drilled.

              I don’t really go for the hype in investor presentations where the typical well presented is usually at least two times more productive than the average well.

              Add the fact that these companies probably believe that twice as many wells will be drilled as is likely and that they likely assume that new well EUR will never decrease and maybe we get to a URR 4 times larger than is realistic.

              So just as I don’t buy the unrealistic projections of say 3 Gb for the ND Bakken/Three Forks, nor do I believe the projections of 25 Gb suggested by the EIA or the absurd projections of 75 Gb by CLR.

              Note the AEO 2017 projected about 85 Gb for all US LTO from 2015 to 2050, a realistic projection is about half that level if oil prices are high enough.

              Perhaps the Permian will be more prolific than the USGS has estimated, but I believe they chose the most promising formation (Wolfcamp) for their analysis (TRR=23 Gb).

              Also note that my high price scenario has about 233,500 total LTO wells completed, about 3 times current levels.

              I could try a higher oil price scenario, and possibly I will.

              • Carl Martin says:

                Dennis Coyne,

                FYI: The USGS is required by law to only operate with information that is at least five years old, so they can be reasonably assured, that they are not misleading the public with any kind of self centered industry hype. That said, they get most of their information from the same companies with their boots on the ground doing the actual work. Most of it is called ancient history. Therefore, it is not very relevant. But, it is very difficult to determine what the present day truth actually is.

                If you don’t believe company information, than you reveal that your opinions are based upon your beliefs, not actual facts. You are very consciously avoiding operating with any company information at all due to your bias. This in turn feeds the conspiracy theories, that form the basis for the PO argument. Why don’t you just look at the company past production profiles to understand how we got to here? Then plot on your graphs what the companies are saying their future production will be. Then you will know for certain if their production information is correct, or not.

                If the price should rise to $60, and stay there, then they will tell us they are increasing production even more. If the price falls back to $40 and stays there, then they will tell us they are cutting back on production. What is there to not believe?

                The source of your bias is here.

                “I don’t really go for the hype in investor presentations where the typical well presented is usually at least two times more productive than the average well. ”

                They are not showing what a typical well is producing. They are only showing what a few cherry picked wells are producing. You are not supposed to extrapolate company information to apply to all wells. By doing so, it is you who is dishonest, not the companies.

                Try this. The Permian companies are presently planning to increase production by at least 15-20% in 2017. All you need to do is figure out what that means. It is just math.

                • Dennis Coyne says:

                  Hi Carl,

                  In the investor presentations the wells are labelled as “typical”.

                  From Dictionary.com some synonyms for typical

                  normal, average, stock, usual

                  I use the state data reported at shaleprofile to determine the average well profile and the number of new wells completed.

                  The method is covered in the post linked below:


                  In each case I show how the model matches the data in the past and then I estimate (guess actually) how many wells might be completed in the future. I also assume that eventually the sweet spots will become saturated with wells so that the average well’s estimated ultimate recovery (EUR) will decrease at some point in the future.

                  For consistency I have assumed this will occur in January 2018 and the annual rate of decrease in new well EUR will be proportional to the rate that wells are completed. For example if 100 new wells per month resulted in an annual rate of decrease in EUR of 3 % per year, a 200 well per month completion rate would increase the rate of decrease of EUR to 6% per year. (numbers are for illustration only)

                  In my medium oil price scenario Permian output increases from 1230 kb/d to 1650 kb/d or by 34%.

                  The estimates are based on the data.

                  See https://shaleprofile.com/index.php/2017/03/23/us-update-through-november-2016/

                  Where Enno Peters concludes:

                  For this presentation, I used data gathered from the following sources:
                  Colorado Oil & Gas Conservation Commission
                  Montana Board of Oil and Gas
                  New Mexico Oil Conservation Commission
                  North Dakota Department of Natural Resources
                  Ohio Department of Natural Resources
                  Pennsylvania Department of Environmental Protection
                  Texas Railroad Commission. I’ve estimated individual well production from well status & lease production data, as these are otherwise not provided. Because of this, I recommend looking at larger samples (>50 wells) before drawing conclusions. About 7% of the horizontal Permian wells in Texas are excluded, as these were mixed with too many vertical wells on a lease, making reasonable well profile estimations impossible. Formation data in Texas is only available on lease level; therefore in cases where wells on the same lease are drilled into different formations, this information is not accurate.

                  • Carl Martin says:


                    I suggest you don’t get so hung up about mere semantics. When they state “typical” they mean typical for that particular area, at that particular time, with that particular well design. It is not misleading, but they are only trying to get you to marry their ugly stepdaughter by only showing her good qualities. This is called good salesmanship, not dishonesty.

                    I appreciate what you are trying to say and do, but I don’t agree with your methodology. You apparently think the future can be accurately predicted by looking at the past and then extrapolating it. What you are missing is that the results of the most recent wells (those with the least reliable info) are far better guides to future production, than the wells of 5-10 years ago. But, because you believe in PO theories, you think well production in the near or distant future will begin to resemble well production from 5-10 years ago due to the Red Queen effect. In other words what goes up, must come down, and in exactly the same manner.

                    This is not happening now. Nothing has peaked (permenantly, only temporarily). Your models do not take into account, that companies hedge their production. Right now about 75% of all production in 2017 is hedged at $50-$55. So, even if oil goes to the high $30’s again, as I believe it might, This will not greatly affect production, or profits, for the well hedged companies. So $50-60 has to be your median case for 2017 and possibly all of 2018 too. All else doesn’t matter much.

                    Also you do not take into account gains in efficiency due to science, technology and knowhow. For the Bakken, which is lagging far behind the Permian, you need to adjust for a 10-15% increase in EURs over the next three years right across the board. We know that this is in the pipeline, because is is due to cross basin technology Exchanges from the Permian. Beyond that no one knows for sure, but I would suggest you use a 5% increase in EURs for each year beyond that.

                    Furthermore, you are giving all wells equal weighting. While historically correct, it is distorting your ideas about the future production. You will have to tweak your models to give the newer wells with higher EURs more weight, than the much older wells. Keep in mind you are only working with models of the unknown future. They are actually not supposed to be based upon past production. They are only supposed to predict future production.

                    It is the Red Queen argument, that is distorting your thinking. The argument is valid enough, but your timing is way off. Like PO before it, it keeps getting delayed and pushed ever further forward in time.

                    I am open to the possibility in the EF, just not anywhere else, as yet. I also don’t know much about the EF.

                  • Dennis Coyne says:

                    Hi Carl,

                    That Permian basin increase of 34% in the comment above is for the period from Dec 2016 to Dec 2017 for the Medium Oil Price scenario, so my scenario is actually too optimistic relative to guidance from the oil companies themselves. This is opposite to what you imply at least in the short term.

                    If we assume as you do that USGS mean TRR estimates are too low based on our beliefs rather than the facts found at https://shaleprofile.com/, then we might have very high output scenarios as a counterweight to the very low scenarios from more pessimistic analysts such as Jean Laherrere.

                  • Dennis Coyne says:

                    Hi Carl,

                    No the models are not simply extrapolations of the past. I take the data we have and assume eventually new well EUR will decrease. In the Bakken/Three Forks new well EUR increased a little over the 2008 to 2016 period, but not by 5% per year, again I refer you to shaleprofile.com.

                    I have used the actual output data and the number of well completions to estimate the hyperbolic well profile of the average Permian basin well.

                    There will not be the magical increases in new well EUR that you envision in the Permian basin, the best areas are being drilled and those areas will become saturated with wells and less productive areas will have to be drilled. Even at $60/b (if all output is hedged), not much money will be made. The hedges don’t last forever, over the long term the market price is what matters.

                    Eventually technology (which often leads to more expensive wells) loses when fighting geology. Recovery factors might be increased marginally, but only with the cost of the marginal barrel produced being higher.

                    You should listen to the guys who know something about producing oil (Mike, Shallow sand, and Fernando), they seem too think you are a little optimistic. 🙂

                  • Boomer II says:

                    Read the Art Berman article I posted below. Technology won’t save oil. It just allows depletion to happen faster.

                  • Carl Martin says:


                    OFF TOPIC: But, on page 21 of RSPP’s recent investor presentation, they give some valuable information on B factors and their effect on EURs. EXAMPLE: all else being equal on a well example, a B of 1.3 = 860,ooo boe, and a B of 1,8 = 1,170,000 boe. RSPP uses an average B of 1,4 for their production in the Permian. They say 85% of the VALUE of their latest production comes at year 10. Hope that helps.

                  • Dennis Coyne says:

                    Hi Carl,

                    As I have said, the b value I use is based on the data. None of the data from the Bakken, Eagle Ford, or Permian Basin suggest that a b of 1.8 would match the data very well. I have seen papers that suggest a b of 1.4 can be used, but I have found that b from 1 to 1.2 usually matches the data best. It is really quite early to tell what the proper parameters are for the Permian basin as the well profiles have changed over time.

                    see following comment with Permian hyperbolic


            • Statements by oil companies such as “we believe” should be discarded. The best method is to take existing wells, group them by completion zone, by sector, spacing, horizontal length, number of fracs and volumes pumped. It will also be important to consider fluid properties, water production, and reservoir pressure. This data has to be correlated to rock properties, and then matched to actual production with three extrapolated decline curves (say high, medium, low). Once this has been chewed over properly you can estimate the potential resources and reserves. I think it can be done properly with about ten man years of effort, which has to be documented and published. Other than that we really can’t trust these guys at all. I suspect they can’t even be trusted in their SEC filings.

              • Carl Martin says:

                Fernando Leanme,

                “We believe” type statements are future related statements, and are thereby not to be interpreted as being absolutely true, because nobody knows the future. They are only giving INVESTORS guidance as to what to expect of them in the future. It is then up to investors whether they accept this guidance, or not. If you aren’t an investor, then the information is not meant for you.

                Everything you mention above is exactly what companies do. Therefore, their information is to trusted, unless you have specific reasons to not trust them. The fact that company information does not support PO theories is not a valid reason for your distrust. In order to honestly distrust these companies YOU, spelled Y-O-U must be able to first disprove their information. If you cannot, then it is you who is being dishonest, not the companies.

                Is it difficult for you to see, that you are caught in the same trap as Dennis? That is why the truth of shale oil is not being presented at this website.

                • Boomer II says:

                  Seems like investors believe there is a glut of oil and therefore oil will stay low and oil companies aren’t a good buy right now. So whatever the companies are telling investors isn’t reassuring investors.

                  • Carl Martin says:

                    Boomer II,

                    Yes, exactly! We investors believe there already is or soon will be a glut of oil. Therefore, oil companies are NOT a good investment at this time. They are all insanely increasing their production, which tanks the oil price, and therefore greatly limits any possible profits. This has nothing to do with PO. It is the exact opposite.

                  • Dennis Coyne says:

                    Hi Carl Martin,

                    The cause of peak oil can be either lack of demand or lack of supply, all that matters is the level of output.

                    You are incorrect that oil supply will be adequate at $40-$45 per barrel based on the analysis of the US EIA and the International Energy Agency (IEA) over the medium term (say to 2022).

                    If there is the glut of oil that you expect, and oil prices fall to $42.50/bo, then oil companies will lose money, cut back completion rates and oil supply will fall to the point that supply matches demand.

                    As an investor you should read a little economics as this is freshman level stuff.

                  • Boomer II says:

                    The oil will run out. The decline rates from the Bakken have been very helpful in indicating how long the area might be productive.

                    I’m expecting that oil companies will focus on the Permian, keep working it until it is no longer profitable, and then I don’t think the other fracked areas will come back.

                    You think there is oil for at least a century. I don’t. I think we’re seeing companies focusing on the short term and then the decline rates start to kill them.

          • Yaman Tasdivar says:

            Hi Dennis,

            I’m not sure if reserve numbers are very useful for estimating peak production level for a basin, although I understand it is a factor.

            The quick rate at which Bakken and Eagle Ford production declined after peak is a function of very high depletion rate for a shale well, as well as, a function of the dramatic difference in productivity in core counties vs. non-core counties.

            My understanding is that one of the two core counties in Bakken has been drilled to the max, and that non-core wells are one-third as productive as core counties.

            A similar situation seems to be underway in Eagle Ford.

            This is why, although I see a small dead-cat bounce in Eagle Ford from recent rig additions, Bakken still does not have the ~50 rigs needed to keep production stable. I expect further declines in Bakken production in 2017 (150-200 kbd), followed by a slower declines thereon (50-100 kbd per year). I personally don’t know of anyone, even among oil bears, predicting a massive recovery in Bakken production, as you are in this article.

            • Dennis Coyne says:

              Hi Yaman,

              The article used a fairly aggressive ramp rate for the Bakken, I revised that, but as oil prices increase, the Bakken will become profitable. So far there is no evidence that the average new well has seen any decrease in estimated ultimate recovery (EUR), though my model assumes this will begin in Jan 2018.

              Here is what the NDIC thinks will happen.

              See presentation from Sept 2016 at NDIC website

              Slide 9 of 20 Expected Case

              They believe 15,000 wells will be completed between 2017 and 2022.

              My medium oil price case has 12,000 wells completed over the same period.

              • Yaman Tasdivar says:

                Dennis – can you please provide support for your expectation that Bakken will become profitable as prices rise? As far as I understand, no company that primarily involved in shale production was profitable (operating or net income profit, both of which take into account corporate overhead etc) even at $100+ oil. At what oil price do you expect shale companies to be able to not rely on debt/equity issuance, and actually become profitable?

                • Dennis Coyne says:

                  Hi Yaman,

                  I am looking at profitability at the well level, under a very specific oil price scenario.

                  At the link below is a spreadsheet with the Bakken Model. Check the discounted cash flow (DCF) sheet, but ignore the rows from 2013 to Dec 2016 as the prices are not correct for that part of the spreadsheet. For the assumptions of my model (discount rate, well cost, OPEX, etc) the values for Jan 2017 forward should be correct for my assumed well profiles. Note that the real annual discount rate (add inflation rate for nominal discount rate) has been increased in this spreadsheet from 7% (in original model to 12%).

                  As to companies losing money, this is often the case when a company expands rapidly, over the period around 2014 the Bakken LTO companies were cash flow neutral according to Rune Likvern’s analysis, the drop in prices has been the problem, as oil prices rise, if these companies do not expand too rapidly they will make money over the life of the completed wells.


                  Note that this is a large spreadsheet (10.9 Mb).

                  • Dennis Coyne says:

                    Hi Yaman,

                    discount rate is 12%/year in the spreadsheet, but was 7%/year in the original post.

                    The file is too large to work with in dropbox and takes a couple of minutes to load, just click on download button to download, but it takes a while before the button works. If this doesn’t work I can try Google Drive (some people don’t like Google so I switched to dropbox). Link for Google Drive below.


                  • Dennis Coyne says:

                    The spreadsheet for the Bakken that I posted has an error in the DCF calculation.

                    Corrected version at link below.


                  • Yaman Tasdivar says:

                    Dennis –

                    Given your time horizon of 20+ years, it is important to consider overall profitability of companies (vs. well profitability). For shorter term projections, well profitability alone may be sufficient because these companies may continue to plug in cash flow deficit via debt/equity raises or asset sales, as they have been doing for three years, but this will not be sustainable once rates rise (over the next two years). That’s when the Permian bubble will pop.

                • Carl Martin says:


                  When you use the term profitable with shale companies, you are getting into some very deep water. You have to know everything about accounting, free markets, stock prices, bonds, hedging, etc. in other words, everything about finance. Profitable usually only refers to being cash flow positive, even though the company might be $10 billion in debt. Debt is simply leverage. It’s not a problem, unless it is. The debt does not usually come from operations, as many think. It mostly comes from buying land leases, or other companies. However, debt is sometimes incurred to cover operating expenses, especially when production is getting ramped way up like now (Permian, not Bakken, or EF). Believe it or not, shale companies actually don’t have to ever be profitable, if they play their cards right. And, debt is easily turned over, and kicked further down the road. Not to worry. All the big companies are doing well, and that’s why PO isn’t happening, yet.

                  • Carl Martin says:


                    From somewhere up above, where I can’t locate the reply button.

                    “There will not be the magical increases in new well EUR that you envision in the Permian basin,

                    Not to be too picky, but the Permian isn’t a basin. It consists of the upper shelf, which is large and shallow, and both the Midland and Delaware basins, which are also very large, but very deep.

                    All the action right now is taking place in the much newer Delaware basin, because the private companies are all gettting bought out by the stock companies for both money and stock. Much of this land is relatively unknown, because there hasn’t been much drilling activities by the private companies.

                    So, your assertion that, ” the best areas are being drilled and those areas will become saturated with wells and less productive areas will have to be drilled.” is WAY off the mark. Those areas are equivalent to the Bakken about 2010 at most. The EURs already are over 1 million boE for some companies, and there is much room for improvement. There are many different zones in most places, and up to 5,000 ft of payload. Plus, it is very gassy, very high PSI’s, which turbocharges the production. MTDR has some very good information out in their latest presentation, and XEC is a company you will need to look at, if you want to understand shale these days. They market themselves as a gas company, so everything is in MMCF. Shale oil is actually all about the gas, which is the driving mechanism, not oil.

                  • Dennis Coyne says:

                    Hi Carl,

                    Eventually the sweet spots will become saturated and at that point EUR will decrease.

                    See Texas RRC


                    The “Permian Basin” is what it is commonly referred to by the RRC, the EIA and many others. Yes there are many different formations within this area.

                    The Permian Basin has produced over 29 billion barrels of oil and 75 trillion cubic feet of gas and it is estimated by industry experts to contain recoverable oil and natural gas resources exceeding what has been produced over the last 90 years.

                    I have used the mean estimate of the USGS which has a TRR of 23 Gb for the Wolfcamp, this is in line with the 58 Gb URR estimate by the RRC as 29 Gb have already been produced.

                    My analysis is for oil not gas, the gas doesn’t really make much money these days so I am not interested in boe, just barrels of oil.

                    Not much money can be made from a couple of high performing wells, it is the performance of the average well that matters. You buy the hype, I follow the data. Also note that you seem to think I base my well profile on what happened 5 years ago. I don’t. For example the 2011 average horizontal well in the Permian basin produced 96 kb over 60 months, the well profile I use for the 2015 and later wells produces 191 kb over 60 months and 300 kb over its 25 year life, I have shown you the well profile elsewhere, note that the natural gas output is ignored as it doesn’t bring in a lot of revenue and I assume this revenue is used to offset some of the OPEX.

                    I also note you like to talk in terms of boe and for the Permian Basin 75 Gboe sound roughly correct for a URR, but about 41.5 Gboe have been produced already, and about 12.5 Gboe of natural gas is left to be produced, leaving only 29 Gb of oil rather than the 75 Gb number you suggested in another comment. This 30 Gb number is the highest that is likely, 23 Gb is a better guess.

                  • Yaman Tasdivar says:


                    I know a thing or two about finance. Don’t worry about that.

                    The only profitability that matters is net income profitability, UNLESS you can specifically point out why net income in the past is not representative of net income in the future. None of the companies that purely operate in shale have been net income profitable even at $100+ oil. So please save me the BS about how these companies are now profitable at $30 with Permian land prices up 10x.

                    I’m not interested in any other definition of profitability that excludes upfront costs, such as land purchase, as well as corporate overhead (ALL departments) that support operations, AND normalized service costs from companies such as HAL and SLB, both of which have been screaming at the top of their lungs that cost inflation is ongoing. We will all witness these so-called “productivity gains” disappear in the next twelve months.

                    I’m not interested in hearing how these companies can boost production in 2017 and 2018. Capital markets will dry up at the end of 2017 and into 2018 once rates rise another percent. Mark my words.

        • Dennis Coyne says:

          Hi Carl Martin,

          I created a “very high oil price scenario” and for the “other LTO” portion of the analysis I made the annual rate of decrease of new well EUR similar to other plays. Economically recoverable resources (ERR) are 51 Gb from 2004 to 2050, with about 374,000 total wells drilled. ND Bakken- 9 Gb, Eagle Ford- 7.3 Gb, Permian Basin (horizontal wells only)- 22.3 Gb, and other US LTO- 11.6 Gb.

          I think this scenario is very optimistic/ not very likely.

          • Carl Martin says:


            I think this scenario is extremely pessimistic and therefore not very likely.

            1.) You show the Permian at about 2,500,ooo (? ) for Jan, 2020, while it is more than 2,o00,000 right now. That’s less than a 25% gain over three years. You have got to be kidding, right? If I wanted to push the envelope a bit, I’d be willing to claim that a 25% gain in the Permian to 2,500,000 could easily happen by January 2018, less than one year away.

            2.)You’ve got the Bakken not breaking 1 million until Jan. 20th. An entire three years before production starts to climb meaningfully? Then, after that it goes up still more? Why won’t it go up much sooner? And, you’ve got the Red Queen first showing up about July 1st, 2022 – January, 2023, more than five years from today. I thought, that was my position, not yours.

            3.) The total only shows a gain of about 60% (?) in about seven years time? That is incredibly low. At this point I have to conclude that you don’t know how to model shale plays at all. I suspect that you are misinterpreting your data base. I would like to zero in on the EUR decline rates, you are using. If you are using some kind of average, then that is where the problems lie. I’d like to ask you a simple question. Why are shale decline rates so steep in the beginning, and so shallow towards the end in the long tails? I’m looking for two technical words. If you don’t know them, you better go all the way back to square one, and start over. And, why aren’t these decline rates reversed? In both individual wells and entire shale plays? If they were reversed, then that would be the exact signature of the downward slope of a typical PO bell shaped curve until production falls right off the cliff. That’s what everyone here is expecting, right? I especially want to hear about the long tails, because I don’t think you include them, because you don’t have any history of them, or perhaps you think they are irrelevant, anyway. They are not! About half the expected production occurs in the long tails, which are expected to be 25-45 years long, at least, that is what companies and geologists are saying.

            • Dennis Coyne says:

              Hi Carl

              Read this


              The model is not a logistic model, it takes the average well profile using the standard hyperbolic analysis used in the industry based on actual well data from Bakken, Eagle Ford, and Permian basin data, as well as the combined data from the rest of the US.

              For Permian Basin data, output was about 1.6 million barrels per day in Jan 2017 based on EIA data from link below


              The Permian model is for horizontal well output only, about 350 kb/d of output from vertical wells is not included. Eventually the decline from old wells makes it difficult to raise production quickly and new well EUR will eventually decrease which I estimate in my model.

              So output from Permian horizontal wells (which will be about 99% of the output increase) increases from 1.3 Mb/d in Jan 2017 to 3 Mb/d in 2025 in the very high price scenario.

              You are wrong about the long tails of these wells, which will decline exponentially after 20 years and will be shut in at an output of 8 b/d at about 23 years. Of the 300 kb EUR which the average 2015 Permian well will produce, 80% is produced in the first 10 years, so you have some very fundamental misunderstandings about geology and the oil industry.

              Here is the hyperbolic well profile used for the average Permian well q=20,000 b/month, b=1.1, D=0.35. From month 1 to month 253 this Arps hyperbolic profile is used and for month 254 to month 282 when the well is shut in due to poor economics the well declines exponentially at an annual rate of 9% per year.

              See following for hyperbolic equation I substitute D for Di and q for qi (as I can’t do subscripts here.)


              Permian basin well profile from Jan 2015 to Dec 2017 in chart below.

              • shallow sand says:


                So, 300K BO EUR for a Permian well.

                Assume 1/4 royalty.

                300,000 x .75 NRI x $45 oil = $10,125,000.

                If we assume $5 BO LOE and 8% severance tax,

                $10,125,000 – $1,125,000 – 810,000 = $8,190,000.

                • Reno Hightower says:

                  And assuming 100 acre spacing, subtract $6,000,000 right off the bat before they spud. At least for those companies that paid $60,000/acre.

                  If $60,000/acre is not a bubble, I do not know what is.

                • Dennis Coyne says:

                  Hi shallow sand,

                  isn’t 25% royalty pretty high for Texas? I have assumed 27% royalty plus taxes so if the taxes are 8%, I am assuming a royalty of 19%. Too low?

                  Also I assume $55/b not $45/b and at $55/b.

                  I also include $42,000 per year for downhole maintenance. $9/b for LOE, G&A, and other costs, as well as $4/b for transport cost (difference between refinery gate price and well head price).

                  Note that you often look at 5 year cumulative which for the average Permian well (recently) is about 191 kb.

                  So about $6.44 million after royalty at $45/b (wellhead price) and about $0.47 million in taxes and assuming $9/b variable costs another $1.29 million in variable costs (LOE, G+A, and other).
                  So over 60 months we have 6.44-0.47-1.29= $4.68 million of cash flow for a well that costs at least $7 million to complete.

                  My understanding is that a well is not likely to be profitable if cash flow over the first 60 months is less than the capital cost of the well (Mike uses 36 months I believe). This is why I suggest that there is not much money to be made in the Permian basin at $55/b.

                  Of course the solution is for all the companies to complete wells that are above average. 😉

                  • Reno Hightower says:

                    Royalties are going to be 20-25%. In the Permian, I would use 25%. The Permian is a mature basin. i.e. you have many sophisticated mineral owners. Add to that the companies were driving up bonuses and royalties, 25% is a safe number for royalties. I would not doubt that with overrides, you may exceed that in some instances.

                    AS for taxes, see this link.


                  • Mike says:

                    Dennis, in my decision on whether to pull the trigger or not 36 months is my maximum time to payout, as is a minimum 3:1 ROI over a 15 year life cycle. Those are my reserve replacement standards (infill) and I am able to achieve that without borrowing money. The shale oil industry has no such standards; it is content to plop down $8M on a well, wait 5 years to get its money back, it hopes, and earn a 1.5:1 ROI over 25 years, it hopes. That is why it is unable to stand on it’s own two feet without the use of OPM. And that is why it is in serious financial condition.

                    Reno is correct about RI burdens in W. Texas; they are 25% pretty much across the board. I use 7.0% for severance and property taxes in Texas. Over a 25 year “imaginary” life cycle of a shale well (and it is imaginary! ) I think normalized OPEX per incremental barrel is $7-9.00 with no inflation adjustments, etc. Don’t forget interest costs in your analysis; Rune has done some staggering work on that in the Bakken and for the record, even Pioneer, with very low long term debt, paid interest per incremental barrel on its debt in 2016. All shale oil companies in America have debt. I looked at nine 10K’s the other day in the Permian and Bakken, with $88B of long term debt combined, and they paid close to $4.5B in interest in 2016. If one thinks that’s not a problem, they need to have their heads examined. For instance, that tiny little example interest on long term debt (from just nine companies) would have drilled 526 more shale oil wells !

                    A typical Wolfcamp or Bone Springs well in either Permian basin is going to require, even at a hedged price of $53 dollars, over 367,000 BO just to reach payout, IMO. I think very few wells will be able to do that.

                    People that don’t know diddly about the oil business often confuse productivity with profitability. The reserve “growth” business model for shale oil has failed miserably. That can happen when you drive the price of your product down 70%. The shale oil industry has written down hundreds of millions of barrels of reserves the past 2 1/2 years and personally, I think they should be required to impair again based on real EUR’s, not fabricated ones.

                    What oil we have left in America is going to be very expensive to extract in the future. For private enterprise to extract that oil, prices are going to have to go way up, and costs way down. I do not think you are biased in your analyses at all. In fact I often fear you are far too optimistic. We no longer live in a world of abundant, cheap oil. In that sense we “peaked” many years ago.

                    In any case, it is a noble thing to care about the future. You clearly do care. It would be far better for society to error on the side of conservation than to promote, or cheerlead, for a failing industry (shale) that is producing our last remaining resources at a loss, for the sake of corporate greed, or a 2% gain in your Scottrade account.

                    Keep up the good work, Dennis.

                  • Dennis Coyne says:

                    Hi Mike,

                    Thanks. Every time you comment I learn something.

                    I don’t come across the way I mean to in many cases, but whenever I ask you a question (and I know they are stupid in many cases) I am not trying to challenge you, I am trying to learn from you.

                    In any case I am trying to keep my questions to a minimum because they often seem to offend people even when no offense is intended.

                    I will revise my royalties to 25% for Texas and taxes to 7% for a total of 32% to make my model more realistic.

                    The older Permian horizontal wells mostly do not last for 25 years, but recent wells may if the follow a hyperbolic with a b of 1.1 and an initial decline rate of 35% as I have modelled. I have assumued exponential decline of the tail at 9% per year an that the well gets shut in at 8.5 b/d.
                    EUR is about 310 kb.

                    I do not include interest cost, but I am assuming an annual ROI of 9.5%, so interest can be paid out of that revenue. This is a point forward analysis, the question being if I complete this well how much extra discounted cash flow will be generated under an assumed set of oil prices and future costs. A “profitable” well meets the 9.5% annual ROI, with “profits” being extra cash flow above this 9.5%/year ROI. Note the 9.5%/year ROI would be a 4:1 ROI over 15 years.

                  • Mike says:

                    Dennis, thanks. At 50 dollar hedged oil prices I think the current economic limit on a lot of shale oil wells in different plays may be closer to 15 BOPD. I think that is why we are seeing lots of wells go down, and stay down, as it simply does not make economic sense to spend $75K to fish, pull, hydrostatically re-test and replace tubulars, etc. etc. on a bad down hole FUBAR well. OPEX increases over time, (water, etc.) and the debt burden of that well increases over time as well. I wish Rune could explain that; he has all that figured out nicely.

                    Anyway, 310K BO UR will not pay the well out at 50 dollar oil, not in my mind. And the point in the exercise is to make enough profit from one well, to drill another well, without borrowing money. Time to payout is an important metric that always, always gets overlooked. Shallow has pointed that out many times. So, the answer to your question about how much discounted cash flow is available (after payout) is…none.

                    Stay curious. Ignore what shale oil companies say about themselves. It is not working and things are getting worse, not better, for almost all shale oil companies. In spite of all the lower costs, longer lateral, more sand, greater IP180 bullshit of 2016…they still all lost money and very few of them (some did!), paid down debt.

                  • Dennis Coyne says:

                    Hi Mike,

                    Thanks. I agree $50/b, or even $56/b at the wellhead will not be enough for these wells to pay out. I agree the interest payments are important, what I am generally trying to do is figure out what future oil price path makes the LTO well completion profitable (meaning a 9.5%/year nominal annual ROI assuming an annual inflation rate of 2.5%/year).

                    For the reasons you have given and based on the analysis that I have done, completing LTO wells (average wells based on the data) is a money losing proposition at less than $66/b in the Permian Basin.

                    So maybe Fernando’s guess for oil prices of $63/b is a good one, I like $67/b.

                  • Mike says:

                    Dennis, I think Shallow said it best, 98-99% of the shale oil wells drilled in the US since 2015 have been a waste of money, and a waste of valuable resources.

                    Art Berman says $60 dollars in the Permian, so you and him are close.

                    I have been in the oil business for over 50 years; I am very concerned about reaching a peak of affordable production capacity. A lot of people I know are, those with a square centimeter of cranial capacity. Why does Exxon for instance now embrace a carbon tax? Why for instance has Chevron, Exxon, Shell, etc. now retreated to the Permian Basin, again, for the 3rd time in 100 years? Because they know the world cannot afford 70 dollar oil anymore and they can produce that crap out there, without debt, and make money at 35-40 dollars a barrel. Major integrated companies have the financial resources to drive Pioneer, and Diamondback, and Oxy, and Concho, all those companies with enormous debt, into the dirt with $35 dollar oil prices.

                    When Uncle Harold said they other day at Cera, the “Permian better not drive oil prices down” (the wank), he was not afraid of Pioneer, or EOG…he’s afraid of Exxon, and Shell.

                    Shallow & Reno, wouldn’t THAT be the ironic ?!!? The mighty US shale oil industry getting a little taste of it’s own medicine?

              • Carl Martin says:


                I got to STRONGLY disagree with this.

                “You are wrong about the long tails of these wells, which will decline exponentially after 20 years and will be shut in at an output of 8 b/d at about 23 years.”

                My understanding based upon the comments of a well known geologist, Craig Cooper, at SA, is that the hand off from hyperbolic decline to exponential decline occurs around year 5.5 and is usually already down to a 6% decline at that time. That said, it can occur as early as year three, or as late as year seven, and there are many examples of the handoff taking place at a high of 10% and a low of 4%.

                I cannot dispute the 8 bpd # due to not knowing all costs involved, and accept the 23 year estimate as to when 8 bpd might be occuring. The long tails are more theoretical, than actual at this point in time, so I don’t place great value on them. Neither do deep pocketed investors.

                But, apparently I have revealed why your EUR estimates are so low. You think the Hyperbolic curve grinds down for 20 years, and I have never encountered anything longer than 10 years. As said before, 5.5 years is the best answer,….. according to Craig Cooper, my geology teacher.

                The explanation is that for the first 5.5 years the oil is “freely” flowing through the induced fractures, that are packed full of sand, and this is governed by the math of hyperbolic decline. The most important factor is the Beta, which you have at 1.1, which is extremely LOW. It is only 0.1 above harmonic decline, which is 1.0. You will have to get used to using Beta factors all the way to 1.8-1.9 especially in the Permian. The Permian is not a shale, and it is much more porous. Some of the zones are also sand zones.

                After 5.5 years exponential decline is used because now all the easy to get oil is gotton, and the fracked volumes between the exposed rock faces have all been drained “dry”. This is also when about half the oil is gotten. Now comes the difficult part, trying to get shale oil to flow through the original unfracked rock matrix. It flows at a very slow somewhat constant rate which slowly goes down over time. That’s the long tail. How long? The industry says typical CLR 30 frack 10,000 ft laterals will live until year 30, newer well types are believed to die at 50. You have every right in the world to not believe the long tails. I really have no opinion on the subject. All the best!

                • Dennis Coyne says:

                  Hi Carl,

                  It depends on the wells, in the Bakken the curves remain hyperbolic longer, I just go with the data and extend the exponential when the hyperbolic gets to 9%, we don’t have data out that far for the Permian so this is just a guess. Generally when one starts the exponential decline earlier, the EUR is smaller not larger as the hyperbolic has a continually decreasing decline rate.

                  You are correct that I should have started the exponential decline at 114 months and this reduces the EUR to 289 kb from my earlier incorrect estimate of 303 kb. This does not make a huge difference, but if anything the earlier exponential decline results in lower output rather than higher output.

                  • Carl Martin says:


                    Here you are only talking about when the hand off occurs. I don’t really dispute the 9%, but my mind is heavily influenced by an article I once read, where the author took the position, that exponential decline NEVER starts at 10% (that close to 9%).

                    Before you can get the handoff correct, you have to get the beta correct. I think your betas are far too low, and reflect betas from years gone by. As EURs go up (all else being equal) the beta must also go up to correctly capture the increase in production.

                    It is possible, that you are not up to date on well technologies. What is happening (mostly in the Permian) is that they are choking back the pressure much more than earlier years. They are also encountering higher pressures. This allows them to LOWER the 24 hour IP, and actually push it forward 2-3 months. That in turn greatly influences the 30 and 90 day IPs, which are also held way down. Your data will not pick this up, because at the same time lateral length is increasing and fracking techniques are greatly improving. This results in the 24 hour IPs and all subsequent monthly IPs to be as high as much older wells when there was little or no choking involved.

                    This means that the EUR curves have less downward curve than older models. To correctly model them you need higher betas. This you are not doing. In short you are basing your models on data that you do not truly understand, and that is causing unnecessary distortions, that support PO theories.

                    You might need to take a look at Deep Utica gas wells, where the pressures are
                    extremely high. They strongly choke back all the wells so production actually straightlines for as long as one year, by slowing the declines in pressure. Then production starts to decline. Now oil operators are trying to do the same, especially in the Delaware basin, which is gassy and has high pressures.

                  • Dennis Coyne says:

                    Hi Carl,

                    I use the well data from NDIC, Texas RRC and other state agencies. The b exponent as well as the initial decline rate D_nought and initial output (monthly) q_nought are determined by a least squares regression on the actual average well data.

                    Where the exponential decline will begin is difficult to say with the data we have.

                    Note that where the exponential decline begins is likely to be different from what you learned, because that was likely for conventional wells. Generally very high exponents of more than 1.4 are used as hype in investor presentations to boost the EUR. The data does not confirm b above 1.2 for most wells, though the changing well profiles in the Permian Basin (they have been improving and I include this in my model) makes this difficult to guess.

                    I will adjust my well profile as I have more data to go on.

                    Currently for 2015 to 2016 Permian data the best hyperbolic fit gives about a 262 kbo average EUR over 19 years with the well assumed to become uneconomic (and is permanently abandoned) at 7 barrels per day output. In the model I use a slightly larger well profile with EUR=289 kbo.

                    I am more interested in oil than natural gas.

              • Yaman Tasdivar says:

                Dennis – Regarding “long tails,” would you agree that shaleprofile.com data clearly shows that as initial production rates are increased with “better” completion techniques and multiple fracking stages, the life of horizontal wells have decreased over the years?

          • Carl Martin says:


            This is a reply to further up in the thread, as there is no other place for me to reply. My claim of oil prices only being in the $40-45 range is referring to the present, near future, and past year or so. It is more backward looking than forward looking.

            “If there is the glut of oil that you expect, and oil prices fall to $42.50/bo, then oil companies will lose money, cut back completion rates and oil supply will fall to the point that supply matches demand.

            As an investor you should read a little economics as this is freshman level stuff.”

            All the above is my point, not yours.

            The only cause of PO is geological restraints, which is a euphanism for, “there ain’t no more”. With your 3% of OOIP assertion of RR in the Bakken, that means that 97% is left. Exactly what prevents that oil from someday being produced? All that is needed is higher prices, or better technology. That’s why PO is inherently unpredictable.

            • Dennis Coyne says:

              Hi Carl,

              In a tight oil reservoir, it is physics and economics that prevents the recovery rate from being higher.

              Perhaps if the price of oil rises to $1000/b (in 2016$), the recovery rate might increase to 4 or 5% for the Bakken/Three Forks, but I don’t think oil prices are likely to reach that level.

              My guess is that the USGS estimate from 2013 will turn out to be pretty good and Bakken output might be 10 Gb if oil prices are high enough. Note that the slow rise in Bakken output is based on recent comments by Lynn Helms who does not expect ND output to surpass 1000 kb/d until the fourth quarter of 2018.

              The core areas of the Bakken are almost fully drilled, so it will be a struggle to raise output beyond the previous peak. I think NDIC is a little on the optimistic side with there expected case of 60,000 wells completed in North Dakota, 40,000 is a better guess in my view.

              • Carl Martin says:

                According to CLR’s White Paper from Oct, 2011, 48,000 wells with EURs of 500,000 boe will be drilled over 12,000 sq miles to yeild 24 billion boe, or about 20 billion BO. But, that is ancient history.

                Therefore, I would expect Helms to upgrade his next estimate to 20 GB. He also gets most of his info from CLR, as they did all the work. I know you won’t agree, but that is what reality suggests will happen next. You might want to prepare yourself.

                As the core (thermally mature) area of the Bakken is 10,000 sq miles according to CLR, it is nowhere near getting drilled out. But, okay, we disagree. So, you’ll just have to keep your eyes on well results, while I continue to study company information.

                • Boomer II says:

                  So basically you are here to promote CLR. This isn’t an investor forum, though. You won’t find a receptive audience here.

                  • Carl Martin says:


                    I have explained MANY times, that I am not promoting CLR!!!!!!!!!!! I am merely pointing out the fact, that it is them, that has given us the BEST information flow about the Bakken. Your problem is that CLRs information doesn’t support PO theories, or that the Bakken peaked in Dec, 2014.

                    ” You won’t find a receptive audience here.”

                    DUH!!!!! Do you actually think I don’t know that?????

                    It is true, that I don’t find a receptive audience, because I only speak the truth. Please consider.

                  • Boomer II says:

                    I’m going by what is happening to oil companies. Bankruptcies, selling off assets, shelving drilling plans, etc. Whether or not there is oil in the ground, many companies are finding that they aren’t making money.

                    I think the Permian boom will pass and I don’t expect another place to replace it.

                    I see what is happening in oil comparable to what happened in coal. It’s an industry in decline.

                  • Dennis Coyne says:

                    Hi Carl,

                    You might have noticed that my estimates are based on the data and evaluations by the experts at the USGS.

                    We also have several knowledgeable oil industry people (Fernando, George Kaplan, SoLaGeo, Mike, shallow sand, Rune Likvern, and Fernando Leanme) who see the “truth” differently than you do.

                    The USGS estimates between 8 and 13 Gb for North Dakota Bakken URR and 12 to 33 Gb for the Wolfcamp play, the Eagle Ford will be between 6 and 10 Gb and the rest of the US LTO combined about the same as the Eagle Ford for a total of 32 Gb to 66 Gb, with a best guess of 49 Gb. No doubt you believe that 66 Gb is much too low, but if you also assume oil prices are likely to remain under $100/b, then we are unlikely to even reach 49 Gb (if the low oil price assumption is correct.)

                • Boomer II says:

                  Shale Billionaire Hamm Says Industry Binge Can ‘Kill’ Oil Market – Bloomberg: “Harold Hamm, the billionaire shale oilman, said the U.S. industry could ‘kill’ the oil market if it embarks into another spending binge, a rare warning in a business focused on fast growth to compete with OPEC.”

                • Dennis Coyne says:

                  Hi Carl,

                  The data shows the wells have an average EUR of about 310 kb0, all of the 10,000 miles does not have similar quality wells, we will see the EUR decrease over time and even with 55,000 wells the URR will be no more than 11 Gb, but it will be fewer wells than the NDIC expected case, more like 40,000 maybe 45,000 at most if oil prices are over $150/b. You will see NDIC revise their forecasts in the opposite direction they will go down not up. It might be as much as 11 Gb, but I believe 7 to 9 Gb is more likely with 8 Gb as a best guess. In the grand scheme a couple of extra Gb will help very little.

                  • Dennis Coyne says:

                    should have been 10,000 sq miles

                  • Carl Martin says:


                    What happens to all your words above IF the USGS ups their estimate to 20 GB? I don’t wish to argue unknowns. I only want to discuss various possibilities. Your mind is completely closed to the possibility of 20GB, because it is only company info at this time.

                  • Dennis Coyne says:

                    Hi Carl,

                    If the USGS adjusts their evaluation, I will adjust my model, note that Bakken proved reserves are only about 5 Gb at the end of 2015 and cumulative production was 1.6 Gb at the end of 2015 for a total of 6.6 Gb.

                    If we assume (optimistically) that probable reserves are 2.5 Gb, we would have about 9 Gb. I could see the possibility that a few reserves (maybe 2 Gb) from the “possible” category might be added to 2P reserves at high oil price levels. The companies know where the oil is and if the reserves were there they would be booked, there are not another 10 Gb to be “found” in the Bakken and technology is not going to boost the recovery factor by a factor of 2.

                    Hey we can make the peak oil problem go away by just assuming there is twice as much oil as is likely to be recovered. 🙂

                    Instead of 3300 Gb of C+C as I assume in my medium scenario for total World URR, we can just make it 6600 Gb and the problem is solved.

                    Maybe you are an economist! 🙂

          • Carl Martin says:

            Dennis, From up above….

            “Eventually the sweet spots will become saturated and at that point EUR will decrease.”

            Of course, but when? I am saying the Bakken is like an animal with one head, one tail, four legs, two eyes one mouth etc. In your mind that descibes a mouse. I agree, but it also describes an elephant. You apparently do not agree, despite all the evidence. The Bakken is simply more like an elephant, than a mouse. End of story.

            To get the all important economics right, you have to include the value of both NG, and NGLs. The oil content in and of itself has much value, but no great meaning apart from the PO context. Sorry, but no one in the industry is at all concend about PO. There’s still way too much oil in the ground for that.

            One point to conside is that BOE only stands for the BTU value of the NG and NGLs. It does not stand for the economic value of the NG and NGLs. The economic values will always be much lower than the BTU values. Be careful out there on that one.

            • The Bakken is simply more like an elephant, than a mouse. End of story.

              I really don’t think so. You cannot compare an oil field against nothing else then declare that it is more like an elephant than a mouse. You must compare it with something. That something has to be other oil fields. And among other oil fields there are elephants. Gahwar is an elephant. By comparison Bakken would be a cat or a small dog.

              Sorry, but no one in the industry is at all concend about PO. There’s still way too much oil in the ground for that.

              Well one of the world’s largest banks, HSBC, (actually the world’s seventh largest bank), says it’s damn time we started worrying about peak oil.

              HSBC Peak Oil Report (dated 2017)

              One more point. The Bakken sweet spots are already saturated with wells. But now they are drilling wells between those wells. They call it “downspacing”. Obviously these wells will not have the production the original wells had.

              • Carl Martin says:


                “Obviously these wells will not have the production the original wells had.”

                Not if they are of the same design, but if the design is significantly better, then they could actually produce more than the originals. Newer wells these days are using 45 degrees phasing and diverter agents to help keep the induced fracks much closer to the well bore than before. So, what the future is promising is actually downsizing 2.0. Beyond that, companies are also experimenting with placing fracked vertical wells between the laterals.

                Any oil field that has produced over one million bopd is considered to be a giant. The reference to the elephant has more than one meaning. Here is a link to my favorite childhood story. Then maybe you will understand what I am saying here. You are all just very blind men. https://youtu.be/-Pknme2ahwA

                • Dennis Coyne says:

                  Hi Carl,

                  I go by the data. You would be wise to do so as well.

                  See https://shaleprofile.com/

                  for data on LTO.

                  Let’s do a simple calculation.

                  Average well produces 300 kb of oil.

                  NDIC expects about 53,000 Bakken/TF wells wells to be completed (about 2000 wells are in other formations in North Dakota).

                  53,000 times 0.3 MMb equals 15.9 Gb, if we make the very unrealistic assumption that all areas have equal productivity (which has never been the case in any oil field anywhere in the World).

                  If we are realistic and assume the average EUR will decrease over time so that the average EUR of the 53,000 wells is 240 kb, then we get

                  53000 x 0.24 = 12,7000 MMb = 12.7 Gb.

                  Note however that costs are unlikely to decrease to the point that the low EUR wells will ever be completed so it will be more like 40,000 wells completed (at most) with an average EUR of about 250 kb (higher because the last 13,000 of 53,000 wells would be very low EUR wells).

                  So at most the URR would be

                  40,000 x 0.25 = 10,000 MMb= 10 Gb.

                  Bottom line, if we ignore the low value NGL and natural gas and focus on the oil produced (barrels of oil not BOE) there will not be 20 Gb of oil produced in the North Dakota Bakken.

    • AlexS says:


      I also expect a period of relatively short boom-bust cycles in oil prices induced by the U.S. LTO.
      Shale companies didn’t learn nothing from the 2015-2016 price drop and will continue to produce as much as they can.

      • Dennis Coyne says:

        Hi AlexS,

        If oil prices remain low, we may see investors lose interest in the US LTO sector. As larger players (Chevron, Exxon, Shell, Total, and Statoil) start to buy up the assets of smaller oil companies that have gone bankrupt or are selling assets to raise cash, there may be more capital discipline.

        I do agree with you and Fernando that prices will not increase linearly. Do you think my upper and lower price scenarios are reasonable (think in terms of 12 month running mean oil prices)?

        Usually your insights are pretty close to the mark.

        • Your price boundaries are pretty good.

          • Dennis Coyne says:

            Hi Fernando,

            Thanks again.

            At the end of 2015 proved reserves in the ND Bakken/TF were about 4.7 Gb, would 20% of 4.7 or about 0.9 Gb be a reasonable guess for probable reserves so that 2P reserves might be about 5.6 Gb?

            This is intended to be a conservative estimate, for conventional reservoirs 2P is usually 1.5 times 1P reserves (or more).

            • I don’t know, because I haven’t seen the type curves they use. Reserves are fairly sensitive to what they assume for production decline rate and OPEX after say five years. They could assume a very low decline coupled to low OPEX and get a high number, and viceversa.

              • Dennis Coyne says:

                Hi Fernando,

                Let’s assume that the companies do their type curves exactly how you would do them, knowing what you do about tight oil resources (and I am not sure you have ever worked in that area), if proved reserves were 5 Gb, what would your guess be for proved plus probable reserves?

                For UK North Sea oil from 1970 to 2010, the ratio of 2P to 1P reserves averaged about 1.63 to 1, for US LTO I am guessing 1.2 to 1, does that seem too optimistic, too conservative, or about right if Fernando Leanme had determined the “correct” level of proved reserves?

    • Dennis Coyne says:

      Hi Fernando,


      Whether the oil prices bounce around will depend on OPEC and demand. I think we could see consistently high oil prices until 2040 if OPEC and Russia choose to moderate their output to match demand in order to keep oil prices high. Also note that by the time US LTO reaches 6.5 Mb/d there may be a serious shortage of oil due to the lack of investment from 2015 to 2018 (oil sands and deepwater). After 2021 US LTO output will fall no matter how high oil prices are, though potentially we could see some LTO output from other nations (China and Russia?) which might mitigate the decline a bit (this seems a bit too optimistic even to me), the EIA claims about 320 Gb of LTO resources outside the US, in my opinion we are unlikely to see an ERR of more than 35 Gb for non-US LTO output from 2016 to 2070.

  2. Donn Hewes says:

    I think more low price scenarios should be considered. Of course the price will bounce up and down as Fernando suggests, but around what point? The people of Greece, Italy, and the Ukraine might be able to cough up a few barrels to spare the rest of us the pain of high prices. Then a few more countries will join in our good fortune. And so on. Just my two (one?) cents worth.

    • Dennis Coyne says:

      Hi Donn,

      Any suggestions? Basically lower prices will result in lower output. I often ask people what they think the prices will be. Usually there is no response.

      Give me a set of prices and I can show you what the model result is, based on the assumptions I have given. If you would like different well costs, OPEX, etc, just let me know specifically what you believe is realistic. I don’t want to do it 10 different ways. 🙂

      • Donn Hewes says:

        Hi Dennis, That is a good deal. Disregarding price fluctuations (like up $20 and down $20 each year), I would run a sample at $55. Just above where we are now. I know this flies in the face of good old supply and demand; But I happen to believe that system has some problems at the moment. Thanks for all the effort, I know it takes a lot of time. Lately I have barely been able to get my computer to turn on! D

        • shallow sand says:

          I agree. Maybe just use WTI futures as a scenario? After all, many LTO companies are greatly increasing CAPEX in 2017 after locking in futures in the $50-55 range a couple months ago for a good portion of 2017 and 2018 production. Companies are projecting the Permian to increase to 5 million BOPD with the futures in the low to mid $50s. Maybe that should be taken into consideration?

          I would note that December, 2025 is the highest (and last) WTI price quoted, this morning it is $54.62. I suspect more rigs will have been added when the Baker Hughes report comes out tomorrow? LTO rig counts have been rising since 4/16 and during most times since, current WTI contacts have been below $50.

          • Dennis Coyne says:

            Hi Shallow sand,



            Where oil prices are $55/b until 2023 (note that I use Brent rather than WTI as that has become the World benchmark).

            I do not think the futures market get the price drop right in late 2014.

            The futures market does a pretty poor job of predicting future prices.

            I imagine you do not think the WTI oil price will remain under $55/b until 2025.

            The EIA does not agree, though I would admit they fare no better in predicting future oil prices than the futures market.

            Bottom line I cannot predict future oil prices, but under the economic assumptions of my models, the Bakken is more profitable than the Permian Basin at $55/bo. Possibly I have underestimated the EUR of the average Permian Basin well.

            • Carl Martin says:


              “Bottom line I cannot predict future oil prices, but under the economic assumptions of my models, the Bakken is more profitable than the Permian Basin at $55/bo. Possibly I have underestimated the EUR of the average Permian Basin well.”

              This is the very first time I have ever heard of the Bakken being better than the Permian. You do realize that the Bakken discount is usually about $7-8, and the completion of the DAPL is only expected to lower that to $5-7. The Permian is also not technically a shale. Therefore, the production declines are much less, than any shale play. Wells, however, are more expensive, and the Delaware basin has not been properly de-risked, meaning there is much more upside to come.

              In regards to your shale models, you also need to take into account the difference in production declines for each basin. Because most of the production gains are coming from the Permian, that means to you need to overweight all Permian production, because it is having a steadily growing, and larger and larger effect on total shale production. Notice how I’m always pointing out how , and why, your models are actually only modeling the worst case scenarios.

              • shallow sand says:

                My subscription service shows the following regarding Permian Basin horizontal wells with first production from 1/1/2009-12/31/2015, as of 1/31/2017:

                5,268 wells have cumulative production of 100,000 BO or less.
                3,497 wells have cumulative production of between 100,000-200,000 BO
                895 wells have cumulative production of 200,000 BO or greater

                In January, 2017 Permian Basin Hz wells with first production from 1/1/2009 to 12/31/2015 produced:
                5,804 wells produced 1,550 BO or less (50 BOPD or less)
                2,156 wells produced 1,551-3,099 BO (between 50-100 BOPD)
                1,602 wells produced 3,100 BO or more (more than 100 BOPD)

                I believe this corresponds closely with shaleprofile.com.

                On shaleprofile.com, it appears 2016 wells will be more productive than prior years. Need to follow up after a few months to see at what rate the 2016 wells decline.

                • Reno Hightower says:

                  There is a disconnect between actual reserves and EUR’s and P4 reserves

                  • shallow sand says:

                    Reno: One thing that is also interesting is the number of Hz Permian Basin wells with first production between 2009-2015 that have produced under 50,000 BO and in the most recent month produced under 1550 BO.

                    My subscription service shows 10,255 wells, including inactive wells in the above time frame in the PB. 2,218 of said wells have cumulative oil of less than or equal to 50,000 cumulative oil and produced less than or equal to 1,550 BO in the most recently reported month.

                    50,000 x .75 x $45 oil = $1,687,500 cumulative gross income.

                    1,550 x .75 x $45 = $52,312.50 most recent month income.

                    I am assuming 1/4 royalty and $45 oil price. I am not including any taxes, nor expenses, nor natural gas income.

                    These wells, IMO, will need to be paid for by the exceptional wells.

                • shallow sand says:

                  Looked at EOG Permian wells, first production 1/1/2009 – 12/31/2015. Subscription service shows:

                  236 Hz Permian Basin EOG wells with first production during said time period.

                  13 Hz Permian Basin EOG wells with 50,000 cumulative BO or less and 1,550 BO or less in most recent month.

                  159 Hz Permian Basin EOG wells with 200,000 cumulative BO or less and 3,100 BO or less most recent month.

              • Dennis Coyne says:

                Hi Carl,

                The well profiles are done for each area Permian, Eagle Ford, and Bakken based on the data, and no I do not break out every individual formation, too much work.

                Note no matter how finely I break things down, someone will suggest the analysis needs to be more finely grained, down to the individual well. 🙂

                Sorry I am not going to analyze 75,000 individual wells, I will continue to aggregate the data as that is how statistical analysis is done.

                Also note that your opinion may be these are worst case scenarios, but they happen to match the analysis of the USGS and David Hughes and are more optimistic than many believe.

                You somehow miss that the current analysis is done on four areas and then added together, did you read the post?

                I take facts, output data and number of wells completed to develop a model that matches the past, then I assume total output will be close to USGS mean estimates (Permian and Bakken) or David Hughes estimate (Eagle Ford) and create a future scenario for number of wells added based on the past peak completion rate (for Bakken and Eagle Ford) and a reasonable guess for the future of the Permian and “other LTO”.

                Using guesses for well costs that are reasonable I use a discounted cash flow analysis based on assumed future prices for whether the wells drilled will be profitable.

                Note that by assuming lower oil prices such as an optimist might do results and less profits an lower output.

                I assume the aim of oil companies is not so much to produce oil, it is to produce money or profit.

                In the World of economics a glut of oil cannot persist because all of the oil producers will become bankrupt, so the low price scenario of $55/b from 2017 to 2050 would result in very low LTO output.

  3. daniel says:

    This is great work.
    However there is one area for concern, the well costs (Opex and cApex) seem low and present the current low price environment. Those will not hold in any of the scenarios, but especially not the high price one.

    *We are seeing wage inflation close to 20% in the oilfield here already

    • Dennis Coyne says:

      Hi Daniel,

      Keep in mind these costs are for oil wells and I have not included any natural gas sales which can offset some of the OPEX. Do you have a suggestion for proper OPEX levels? Note that I have included $3500 per month (or $40,000) annually in 2016$ for down hole maintenance.

      The following report gives some estimated costs


      I agree higher oil prices might lead to higher well costs and OPEX.

      A possible future post will look at higher well cost and OPEX with increases of 10% and 20%.

      The current estimate is based on the current low price environment.

  4. Dennis, looking at your Bakken Chart you have the North Dakota Bakken reaching 1.2 mbd by the end of 2018. That does not quite jive with what Lynn Helms had to say:

    North Dakota oil production is doubtful to grow much in next few months

    Still, he said production should remain flat if not fall in the next few months. In fact, he doesn’t expect monthly production to top 1 million barrels per day again until 2018’s fourth quarter.

    I would say your Bakken prediction is extremely overly optimistic. I will not comment on any of your other LTO predictions however.

    • Dennis Coyne says:

      Hi Ron,

      It is always impossible to please everyone. When I have the wells added ramp up slowly, then Bruno Verwimp complains that US companies will ramp up much faster, but if I show a fast ramp up of new wells added to please Bruno, you say that is too optimistic. The chart below shows a zoom in of output to 2018 and you are correct that it does not agree with Helms and has output over 1000 kb/d by the end of 2017, chart below, with low oil price scenario.

      • Dennis Coyne says:

        Hi Ron,

        The scenario below slows down the ramp up in new wells so that output remains below 1000 kb/d for the ND Bakken/TF through June 2019 (938 kb/d in Dec 2018). Perhaps still too optimistic for the low price scenario. It is difficult to guess how quickly new wells will be completed, but the rate (through Dec 2018) for this new scenario is far lower than the 2011-2014 rate of well completion, chart below.

      • It is always impossible to please everyone.

        Really Dennis, this has nothing to do with pleasing anyone. I don’t think neither of up post with pleasing our readers. We simply post our point of view. And I, for one, could give a shit less is someone is displeased or not.

        I was just pointing out that your estimate differs quite significantly from what the director Helms has to say. And I do think Helms would have a reason to be optimistic. So his prediction likely has greater downside risk than upside risk.

        Just eyeballing your chart, it looks like you think there is about four times as much oil yet to be recovered as has already been recovered from the Bakken. In my humble opinion that is absurd beyond belief. The Bakken sweet spots have already been drilled out. But you think not. I understand your position. I just think it is totally absurd.

        I doubt seriously that my opinion pleases you but that was never my intention. And pleasing me, or anyone else for that matter, should not be your intention.

        • Dennis Coyne says:

          Hi Ron,

          About 2 Gb have been produced in the Bakken/Three Forks, there have been 11,400 wells drilled to date, with about 11,000 since 2008. The average well since 2008 is likely to have an EUR of 300 kb, which would give us 3.3 Gb, just from those wells. Proved reserves in the ND Bakken/TF is about 5.5 Gb (end of 2015) so cumulative output plus proved reserves are about 7 Gb (1.6 Gb output through Dec 2015).

          Perhaps probable reserves are zero, but I doubt it.

          Maybe your position is absurd?

          • Perhaps probable reserves are zero, but I doubt it.

            Huh? What is that all about? If they are still pulling out of the Bakken then it is quite obvious that reserves are not zero, else they would be getting nothing. Why do you feel the need to post such silly shit?

            Maybe your position is absurd?

            Hey, I ain’t pleased. 😉

            • Dennis Coyne says:

              Hi Ron,

              There are proved, probable and possible reserve categories.
              proved plus probable is called 2P reserves, proved+probable+possible reserves are called 3P reserves.

              If probable reserves were zero then 2P reserves= proved (aka 1P) reserves, so my point was that proved reserves plus cumulative output is 6.3 Gb (not 7 Gb as I said before because proved reserves decreased in 2015, which I had not double checked).
              If we assume probable reserves are zero, then URR=cumulative output to the end of 2015 plus proved reserves at the end of 2015 (we also need to assume no new discoveries and no move of possible reserves to the probable or proved category as oil prices increase in the future).

              If we make all of these absurd assumptions, then URR=6.3 Gb.

              As to 4 times more left to be produced than cumulative production so far, cumulative production to the end of 2016 was about 2 Gb and 4 times 2 is eight and 8+2=10 Gb, none of my scenarios are quite that high, but the high oil price scenario is close. The low oil price scenario is quite close to the USGS F95 TRR estimate from April 2013 for the ND Bakken/TF, which is about 8 Gb with only a 5% probability that the TRR will be lower.

              • Dennis Coyne says:

                Hi Ron,

                Also note that Helms is probably expecting oil prices to remain low through 2018. The NDIC expects a total of 55,000 to 60,000 wells to be drilled in North Dakota, my medium oil price scenario (revised to account for Helms’ comments) has only 34,000 ND Bakken/TF wells (maybe 39,000 total ND oil wells, including conventional).

                The scenario has an ERR of 8.2 Gb, fairly close to the USGS F95 estimate for ND Bakken/TF TRR.

        • Yaman Tasdivar says:

          Enough with all the pleasing of each other… Get a room.

          But I estimate that well productivity will be lower going forward than historically for Bakken. So maybe that bridges the gap between quicker ramp-up of drilling with lower overall production per day.

          • Dennis Coyne says:

            Hi Yaman,

            Note that I also expect well productivity to decrease in the Bakken starting in Jan 2018, with the maximum annual rate of decrease reached in 2023 at 8.8% per year (this is proportional to the rate of well completion so it remains at this level until 2028).

            Note that through Jan 2017 there is no evidence from the data that there has been any decrease in new well EUR, if anything it has continued to gradually increase or has remained constant since 2015.

            See https://shaleprofile.com/index.php/2017/03/09/north-dakota-update-through-january-2017/

            and click on well quality tab.

            • Yaman Tasdivar says:

              I looked through this. 2017 wells actually show significant drop in initial production, but this is just one month.

              More importantly, however, we see that recent wells (even with rampant high-grading) show higher initial production, but very similar decline rates, followed by a dip under the curves of prior period wells.

              To me, this says, higher initial production only brings forward production, and is not an indication of higher EUR.

              If anything, I would have expected high-grading to boost initial production rates and improve decline rates, as happened to an extent in Permian. But Bakken has peaked and out of sweet spots.

              • Dennis Coyne says:

                Hi Yaman,

                So far there is not clear evidence that EUR has decreased, I agree it is possible production may have been pulled forward, but from a discounted cash flow perspective this is better. The ideal well would produce all of it’s output in the first day as there would be very little discounting, obviously this is not physically possible.

                The Bakken output has declined because fewer wells are being completed, it really is that simple. I agree that in the future the sweet spots will be fully saturated and new well EUR will decrease, my gues is that this will begin with the year and it is already included in my model.

                • Boomer II says:

                  “The Bakken output has declined because fewer wells are being completed, it really is that simple.”

                  But is the cost of production really that much different between the Bakken and the Permian to shift focus from the Bakken to the Permian if wells are just as productive in the Bakken as they always were? If Bakken wells continue to look good, shouldn’t there be as much drilling there as the Permian and as there was in the past?

                  • Boomer II says:

                    In other words, why, as you say, is there less drilling in the Bakken and more drilling in the Permian?

                  • Ves says:

                    It is all the “new technologies” that make oil profitable at these prices that companies in Bakken still don’t know about it 🙂

                  • Dennis Coyne says:

                    Hi Boomer II,

                    The reason completion rates fell is because oil prices fell. When completion rates were high in the bakken oil prices were over $100/b, at $50/b completion rates have fallen as we would expect.

                    The Permian has a bit of a cost advantage due to being closer to refineries than the Bakken, so transport costs are about $6/barrel less for the Permian Basin. There is potentially more oil in the Permian Basin about 23 Gb vs 11 Gb in the Bakken, this along with better recent EUR from Permian basin wells (compared to a few years ago) and the transport cost advantage are some of the reason for the increased activity in the Permian.

                  • Dennis Coyne says:

                    Hi Boomer,

                    There is a price differential due to higher costs to transport the oil from the Bakken to refineries, about $6/b more than the Permian Basin. Completion rates fell in the Bakken due to lower oil prices.

                  • George Kaplan says:

                    There are two aspects in comparing the main shale oil plays that have not been considered here: 1) acreage needs to be retained by drilling and production, that means there will be more activity, all else being equal, in newer plays like the new parts of the Permian compared to older areas like the Bakken and Eagle Ford; 2) Bakken is a pure oil play, the Eagle Ford is much more mixed with up to 20% of C&C from condensate, there may be some impacts from gas price (e.g. seasonality), transportation limits and differences in maturity between the gas and oil plays.

                    I don’t know their current importance but they have played a role in the past.

                • Boomer II says:

                  This article link has been posted here before, but how is it that you and Berman have drawn different conclusions about whether Bakken EUR has decreased?

                  Art Berman The Beginning of the End For The Bakken Shale Play – Art Berman: “Estimated ultimate recovery (EUR) decreased over time for most operators and 2015 EUR was lower for all operators than in any previous year (Figure 2). This suggests that well performance has deteriorated despite improvements in technology and efficiency.”

      • Verwimp says:

        Hi Dennis,

        If I want to be pleased, I go to other content* on the web, far away from Peakoilbarrel. 🙂
        If you consider my interventions here as “complaints”, I apologise for any inconvenience. I look at it as: You and I have different expectations about the future and we keep on trying to convince eachother. I believe it’s a plus for this platform that different opinions can be shared. I’m honored to have the opportunity to share my opinion on ND Bakkken LTO here.

        Anyway: I am ‘pleased’ to see you seem to have abandoned the idea of a multi decade long plateau in LTO production. The set of curves you are presenting now looks far more ‘natural’ to me than the long plateaus, which looked ‘engineered’ to me.

        Nevertheless I follow Ron’s remarks about the sudden and steep increase in the near future too. So you may find a compromise to ‘please’ all of us. 😀

        I think the aspect we disagree on most, is the URR.

        Best regards,

        Bruno Verwimp
        (* Beethoven symphonies on Youtube.)

        • Dennis Coyne says:

          Hi Bruno,

          As I had pointed out earlier, they were indeed “engineered” to match the AEO 2017 US LTO output scenario in the previous post. The intent there was to show that the AEO scenario was not very realistic. As to URR, I will continue to use the USGS estimates for the Bakken and Permian Basin (10 Gb and 23 Gb respectively), and David Hughes’ estimate in Drilling Deeper for the Eagle Ford (about 8 Gb), for the rest of the US LTO I have used the data from Enno peters to estimate the average well profile through 2016 and then guess at the number of future wells (this is the weakest part of the analysis in my view), but data for other US LTO plays is rather limited. At some point I may try to tackle the Niobrara.

          Sorry about the use of “complaint”, a poor word choice on my part, observed might have been a better choice.

          Your insights are welcomed, thanks.

          The rise in rig counts leads me to think the well completion rate will rise, the rate of increase in the future is unknown, you have suggested in the past that your expectation is that the rate of increase will tend to be high rather than low, if it should occur, or that was my understanding.

          • Verwimp says:

            Hmmm, yeah. That’s what I think: If there is an increase, the increase will be rather high. It will (if it happens) gererate another boom, followed by another (more severe) bust. Just like it’s meant to be. Just like it’s ‘natural’ in America.

          • Yaman Tasdivar says:

            Dennis – I’m not sure higher rig count necessarily leads to higher completions with 1:1 correlation. Completions will increase in the coming months, but I suspect the increase will underwhelm vs. rig count increase in the last four months. I believe the difference will be explained by the rise in cost of completion services, and will show up as a rise in DUCs.

            This is in-line with the observation on EIA DPR DUC supplement that number of completed wells has remained muted through February, especially in Bakken and Eagle Ford, even though rig count had started increasing months ago. Some say there is a delay between end of drilling and completion, but I’m not sure if it is months. We’ll find out in the next couple of weeks.

  5. AlexS says:

    Article in Bloomberg: banks may deter increase in lending to the oil industry due to the current weakness in oil prices.

    Oil’s Bad Timing Pressures Drillers as Banks Review Loans


    • Slide in oil prices could deter lenders from opening up credit
    • ‘The next month is going to be absolutely critical’: analyst

    The rally in global oil prices has stalled at the worst possible time for explorers, just as banks reassess credit lines crucial to their growth.
    This year’s reviews, due to start next month, will arrive with the industry nursing a nasty case of whiplash. Spot prices surged late last year on OPEC’s pledge to cut output, hitting $54.06 a barrel in New York. Since then, they’ve fallen 12 percent, undercut by rising U.S. rig counts. Futures contracts show longer-term prices deteriorating as well.
    A drop below $45 would likely spur credit-line reductions, raising the specter of cuts that crippled drillers a year ago, said Kraig Grahmann, a partner in Houston for law firm Haynes & Boone LLP. Between the end of 2015 and October, when credit lines were last reassessed, the average borrowing base for U.S. explorers fell 16 percent, according to data compiled by Bloomberg.
    “The next month is going to be absolutely critical from an oil-price standpoint,” said Paul Grigel, a Denver-based analyst at Macquarie Capital USA. “If you see prices retrench further, clearly the banks are going to have to re-evaluate. They are going to say, ‘Should we be pulling back?’”

    • texas tea says:

      lets hope the banks do pull back. a little discipline even if imposed by bankers would be a good thing. With regard to Dennis’s work, the conclusions are one of many possibilities. I think drilling down on singular horizons, then fields, the plays might yield some information that would lead to investable conclusions. What is offered while interesting and who the hell knows might be right, are so dependent on way to many variables to be of any real value for those who require more then satisfying some curiosity.

      If Dennis is close to being right regarding maximum LTO production as to volume and timing, adding to or building position in low cost producers, drillers, and suppliers and pipelines will be a profitable proposition in the medium term. Of course that has been true for over a year.

      • Dennis Coyne says:

        Hi Texas Tea,

        For the short term such investments might pay well, but I wouldn’t plan for a long term return, because eventually the high oil prices will kill demand for oil and there may be a lot of stranded investments. Note that the breakout of ERR for the high price scenario is 20 Gb for the Permian, 9 Gb for the Bakken, 8 Gb for the Eagle Ford, and 7 Gb for the rest of the US. The Permian, Bakken, and Eagle Ford estimates line up well with USGS and David Hughes’ estimates, based on results so far from the rest of the US LTO 7 Gb seems reasonable.

        Yes lots of variables, but better than speculating in the absence of any model in my opinion. No model mirrors reality perfectly, just a simplification to clarify one’s thoughts.

      • Boomer II says:

        In response to TT, from an investment standpoint, oil stocks aren’t the only option. Investors have many industries to choose from and may not be looking for opportuities in oil.

        • Boomer II says:

          Also, I have been speculating that not only are fossil fuel companies declining, the media and investors are starting to see this, too. If you don’t have growth to offer, then you need to at least offer predictable returns to investors. If that goes, too, there is little investment appeal.

          It’s the natural course of things. Industries decline when their products become less available and/or less competitive. This forum is mostly about transitions. I don’t believe anyone expects oil and other fossil fuels to the economic drivers in the future that they were in the past.

  6. GoneFishing says:

    Dennis, those steep production declines after 2022 should really kick the transport industry into using alternative energy and fuels. Higher efficiencies and better system management will probably be the call of the day initially.

    • Dennis Coyne says:

      Hi Gone fishing,

      Yes I anticipate oil prices will rise after 2022 (which is not reflected in the oil price scenarios) as output drops, possible LTO from the rest of the World will come to the rescue, but I am very skeptical that oil sands, deep water or non-US LTO will arrive just in time to mitigate the decline, it will be demand destruction that saves the day, and a lot of economic disruption.

  7. Watcher says:

    This stuff is all worthless.

    How did the low price scenario get to be higher than today’s $47.xx in Asia. What sense does it make when a low scenario is higher than current reality.

    • Dennis Coyne says:

      Hi Watcher,

      When the scenarios were created the oil price was about $55/b, only you can predict the future oil price accurately. 🙂

      • Watcher says:

        Ya,, marvy. Worthless. If it was 55, then why wasnt that the middle case. Where is the 28 case.

        Nah don’t bother.

        • Dennis Coyne says:

          Go for it, give us your $28/b case, I don’t waste my time on unlikely scenarios.

          All three cases have oil at $55/b from Jan 2017 to Dec 2018, that is low, middle and high.

          I will go with Fernando’s assessment.

          Only cornucopians think oil will remain under $55/b for more than the next 12 months.

          Oh and can you guess the last time the trailing 12 month average of the nominal Brent spot price was $28/b or less?

          • Donn Hewes says:

            “only cornucopians think oil will remain under $55” ? I think cornucopians think it will hit over $100 for any length of time.

            • Oil price will eventually reflect the value that can be gained by using it = $10/barrel.

              The world wastes oil for fun and stupidity: maybe 3% is used for agriculture and other food, fiber and shelter provision; much- if not all of the fore-mentioned use is unnecessary ‘make work’. Yet, it is the ‘end use’ … which (theoretically) provides the means by which oil is extracted from the ground and made ready to burn. We can see if we choose to look that end use provides nothing but pleasure (‘utility’) which is not an economic return. In other words, driving a car does not pay for it, nor does it pay for the roads, fuel or its refining- and distribution system; to pay for finance or the military (to steal fuel or exportable consumption … ) to pay for the externalities such as exhausted waste carrying capacity.

              Instead of returns on use, we rely on credit to do the heavy lifting.

              The assumption is more credit will do two things:

              – It will magically appear when needed even as the ability of users to gain new credit is obviously shrinking;

              – It will offer a proportionate return in the form of extracted fuel as it (credit) did during the pre- 1998 period … even as credit productivity is also shrinking …

              End user credit failure: http://wolfstreet.com/2017/03/24/subprime-auto-loans-crushed-worse-than-2009-auto-industry-bleeds-knock-on-effects-commence/

              End user credit failure: http://theantimedia.org/retail-apocalypse-officially-america/

              The high real cost of petroleum (compared to the cost of other inputs) is why credit is eroding! Put another way, high oil prices are self-regulating. High prices cause credit hiccups => lower prices follow. How high is too high?

              A lot lower than you think.

              • Dennis Coyne says:

                Hi Steve,

                Where does your $10/b estimate come from?

                There is no objective value, how much something is worth is subjective.

                One could easily create an objective value theory using input output analysis, but everyone would have to agree on the measure of value.

                David Ricardo liked labor, but capital could just as easily be used as the measure of value. Then Marxian theory could be turned on its head and the workers would exploit the capitalists. 🙂

            • Dennis Coyne says:

              Hi Donn,

              A cornucopian with regard to oil resources believes that oil is plentiful, so much so that oil prices are likely to be very low long term, say $30/b (in 2016$) or less from 2017 to 2100.

              Those that believe oil prices will be high are peak oil believers like myself who believe that resources are limited and technology is not a magic wand which can grant all wishes. For those like me, $100/b oil is a possibility at least for a time, though as resources become more scarce prices may rise to a level ($150/b?) that crashes the economy and then oil prices will fall.

              Perhaps your point is that cornucopians think no recession is ever possible so that oil prices could rise without limit if necessary. My point is that the underlying belief in unlimited resources (if actually correct) would tend to result in very low prices.

  8. Doc Rich says:

    Your work is greatly appreciated. I continue to be amazed at the continued high level of oil shale and natural gas production as well despite the ongoing miserable prices for oil and gas. It just doesn’t compute. It is my opinion that these oil shale companies will continue their production as much as possible no matter how high or low prices are. Just my thoughts from a non oil guy.
    Thanks-Doc Rich

    • shallow sand says:

      Doc. I find it interesting that Dennis, who I think has no money at stake in oil and gas, utilizes different price scenarios to predict future US shale production.

      On the other hand, it does not appear the companies actually producing oil and gas in the US consider future oil and gas prices in their production forecasts. At least I haven’t noticed that they do.

      • Boomer II says:

        I’m concerned primarily about Washington’s seeming lack of awareness about oil supply and pricing. Little to no planning is being done to prepare for more limited and more expensive supplies. At the same time, there are politicians giving lip service to increasing current supplies, which the oil industry doesn’t need.

        • Oldfarmermac says:

          Politicians in office need cheap oil, and they are willing to do pretty much anything they think they can get away with in order to keep the price as low as possible.

          This is the real reason the Obama administration didn’t put much pressure on the domestic oil industry, compared to the pressure that COULD have been brought to bear, to clean up its act.

          But some misdirection is ALWAYS useful in politics.

          Obama, or his cronies, played the environmental camp like a violin, when it came to the Keystone, which I personally believe would have been in the best interests of the country, ALL things considered. The decision should have been made in a quarter of the time it was dragged out.

          My opinion is that playing this game probably cost the D party more votes among independents, and normally reliable but unhappy working class D voters than it won for the D party among environmentalists.

          Environmentally concerned voters can ordinarily be expected to vote D regardless of whether the D party performs to their satisfaction on a given pipeline, highway, mining operation, etc.

          I don’t know a single big D Democrat personally who would have voted for Trump if Obama had very quietly sent the word down that he wanted the pipeline approved. Environmentally motivated voters ordinarily only abandon the party and vote R when they are scared about their economic security, about their jobs, and even then only if they THINK the D’s are more at fault than the R’s in terms of their problems.

          In actual fact, the Republicans are by far and away more to be faulted for exporting jobs than the Democrats, but they were lucky in running a protectionist candidate against the D’s perceived globalist candidate last time around, when LOTS of people were very scared for their jobs. )

          The bottom line is that even if Clinton had won, federal policy in respect to drill baby drill would still be drill baby drill.

          And while I personally firmly believe in peak oil, and in getting away from using it so recklessly, I hear people making fun of peak oilers and environmentalists, and Democrats in general, equating with busy body socialists determined to ruin the economy due to not believing in the free market.

          Now if you happen to read what hard core R types have to say in some forums where they hang out………. Well, they’re saying all along that they were right, and that the free market would solve the energy problem, and that folks like Sarah Palin who believed in drill baby drill were right, and that drill baby drill would bring about the return of two dollar gasoline.

          I was one of the many people hanging out at the old TOD site, and other sites, making fun of “drill baby drill” and the R’s prediction of the return of two dollar gasoline.

          It is naïve at best to believe either party will do anything that might result in the price of oil going up sharply, if there is any possible way to avoid doing it.

          Happy campers vote for incumbents. Cheap gasoline means a hundred million happy drivers, and tens of millions more voters who do better economically when oil is cheap.

          Having said all this, I think Boomer is right, that we may find ourselves up shit creek without a paddle if for some reason the supply of cheap oil were to dry up quickly.

          If the D’s were in power, the most we could expect them to do, in respect to oil, would be to push along the growth of the electric car industry, etc.

          There are some good to excellent reasons why this might happen.

      • shallow sand says:

        I stand corrected. I looked at Pioneer Natural Resources’ March, 2017 investor presentation. In the slide that predicts 1 million BOEPD by 2025, in the fine print it is stated the prediction presumes average WTI of $55 and average Henry Hub gas of $3.

        • shallow sand says:

          OXY states they have 4,100 Permian horizontal well locations that will work at WTI prices below $60.

          • shallow sand says:

            I stand corrected again. EOG forecasts it will increase oil production to 500,000 BOPD in 2020 with oil averaging $50 WTI, but will increase oil production to 700,000 BOPD in 2020 if oil prices average $60 WTI.

            I apologize for not reading these most recent company presentations more closely.

            It appears to me if WTI averages $55 from now through year end 2020, 2020 will close with US LTO production at roughly double its current rate. This appears to be what the major US companies are guiding.

            • Dennis Coyne says:

              Hi Shallow sand,

              I don’t think much money will be made at $55/b.

              I may be wrong though.

              I tried a lower price scenario leaving other assumptions unchanged, oil price is $55/b from Jan 2017 to Dec 2023 and then rises at the medium scenario’s rate of increase of 41 cents per month until reaching $75.50 in Feb 2027 and remains at that level until 2050, all prices in 2016$. For the Bakken we get the scenario below.

      • Dennis Coyne says:

        Hi Shallow sand,

        You are correct that I have no skin in the game.

        Just curious though, as an oil producer, I would think you have your own personal guess of future oil prices when making decisions about whether to complete a well (or even perform downhole maintenance.)

        My guess is that just as you and Mike are reluctant to reveal what those forecasts are, the same would be true of any oil company.

        What do you think of my high and low oil price cases (they are in real (2016) dollars)?

        • shallow sand says:

          I believe your forecasts are too high, but I also agree that predicting oil prices is very difficult, and becomes more difficult the further in the future one is looking.

          For example, I do not recall any predictions in 2006 of prices averaging $100 in 2008, nor in 2013-2014 of 2015 prices averaging $50 and 2016 prices averaging $42.

          The most bearish predictions I recall in 2013-14 for WTI were low $70s.

        • Dennis Coyne says:

          Hi Shallow sand,

          I have created a new “very low oil price” scenario with oil prices at $55/b (2016$) until 2023, rising linearly to $75.5/b (2016$) by 2027 and then remaining at that level until 2050. In order for the Permian Basin to be profitable at these prices, the well cost had to be reduced to $7 million (2016$) from $8 million in original scenarios.

          US LTO output for this oil price scenario shown in chart below. My guess is that the declining output from 2018 to 2023 would result in upward pressure on oil prices unless there is a severe recession, perhaps you assume this will be the case?

      • Dennis Coyne says:

        Hi Shallow sand,

        How would one do an economic forecast without an assumption about future prices?

        Often the assumption is that prices will remain fixed at present levels, but that is simply an assumption as likely to be wrong as most other assumptions.

        If one assumes as I do that oil supplies will be somewhat less than the quantity of demand at current prices by say Jan 2018 (assuming oil prices remain at current levels from now until Jan 2018), then in order for supply and demand to balance the oil price must rise. I could be wrong and supplies might be plentiful (if OPEC and other nations currently restricting supply choose to end those cuts in July 2017 for example), but output is unlikely to increase very much at $50-$55/b and C+C demand will continue to increase by about 1.5% per year, eventually supply will come up short at current oil prices.

        I don’t think oil company guidance tends to be very accurate, there is a lot of hype which I do not believe. Kind of surprised you take it at face value.

        • shallow sand says:

          Dennis. I am merely repeating what the companies are stating in their most recent investor presentations. It appears they are using between $50-$60 WTI and generally plan on doubling Permian Basin Hz production by 2020.

          I assume if they are saying it, they mean it? We shall see.

          • Dennis Coyne says:

            Hi Shallow sand,

            How have their past forecasts from their presentations worked out?

            I have read a few of these in the past, they seem to be all hat and no cattle. 🙂

            So I don’t bother with them anymore.

            At $55/b until 2022, I get the following for the Permian basin. Note that prices rise to $75.5/b by Feb 2027 and then remain at that level until 2050 in this scenario, also cumulative losses in the Permian basin are $3.5 billion from Jan 2017 to Dec 2020 at these prices and an assumed well CAPEX cost of $7 million in 2016$ (all other economic assumptions as in original post.)

            • Dennis Coyne says:


              The losses of $3.5 billion are the losses over the life of the well for wells completed from Jan 2017 to Dec 2020, these wells stop producing in 2045 (for the last wells from Dec 2020), so even with the rise in prices over the 2023 to 2026 period, none of these wells become profitable because most of the well’s output is over the first 5 years (about 64% of output) of production.

  9. Hickory says:

    Strong work Dennis. I don’t have confidence in predicting the future price (at all), but have no specific quibble with your shot at it.
    I can see one scenario where the cumulative output fails way short- that being a long term financial catastrophe with lack of credit for production, and lack of demand from poverty.
    I’m not predicting this outcome, but do think it is well within in the realm of possible scenarios.
    Thanks for the work.

    • Dennis Coyne says:

      Hi Hickory,

      That is indeed a possibility, but my guess is this happens after 2030 and output might not be affected all that much for LTO. Note that even the high price scenario has output falling back to today’s level by 2030, as a whole World C+C output will also be falling by that time and might fall further due to economic crisis and low oil prices due to lack of oil demand. How much oil demand falls is hard to guess as currently oil is pretty essential, but may be less so in 2030 or 2040 as a transition to electricity for transport proceeds. Clearly a depression might slow such a transition considerably, or it might speed it up with fiscal policy implemented to solve both the depression and the underlying cause (too much dependence on fossil fuel). Hard to predict the future.

      I absolutely agree my high and low scenarios could be too high or too low and am always interested in alternatives, but few are willing to climb out on that limb with me. 🙂

  10. David Archibald says:

    A few weeks ago there was a list of the number of remaining locations in LTO plays in the US, in Peakoilbarrel comments. If anyone has it, please publish the list here again.

  11. Schinzy says:

    Excellent work as usual Dennis. Models really help clarify assumptions and
    data as your responses to previous comments have shown.

    A few comments:
    Prices affect costs indirectly. Costs go up when production is ramped
    up because new workers must be hired. Of course high prices incite
    ramping up production and hence costs. A similar argument can be stated
    for production being ramped down. Thus I would expect higher costs
    anytime production ramps up regardless of price.
    As has been mentioned above, whether or not your price range is
    correct, the curves are incorrect because they are missing volatility and a
    cyclical component. I expect prices to kick up around 2020 when the IEA
    says that lack of investment offshore will make it difficult for
    production to satisfy demand. But I do not expect prices to stay high. I
    believe the high price will pop various financial bubbles causing a
    recession to follow the high prices depressing demand.
    It would be interesting to know how LTO production will affect
    offshore investment. We have seen a sharp drop in long term projects
    since the oil price drop in 2014. Will LTO continue to depress this
    In light of the previous comment, it is possible that LTO
    production causes a sharper decline post peak oil by scaring
    investors away from long term projects offshore where there is more
    oil as consumers may react to higher prices by decreasing their
    dependence on oil (see Boomer II comments).

    • George Kaplan says:

      It’s looking like the shorter cycle times for LTO just means the the volatility acts over higher frequency but doesn’t go away. A fundamental problem remains that all the E&Ps use basically the same model, and therefore they all make essentially the same decisions at around the same time, and therefore you get boom and bust. Volatility may be the biggest contribution to delaying or preventing long term investment in bigger (principally deep water and oil sand) projects, but I think the impact of the big drop off in discoveries is significant, and not being fully appreciated. The backlog of discoveries are mostly difficult and expensive developments that were not considered as top prospects when oil was over $100. The few larger, new discoveries are also in frontier, and therefore generally more expensive, regions. E&Ps are turning to gas, or near field developments, or are giving up on offshore altogether. Much higher, and stable, prices might be needed to get these big projects going. If high prices cause a fast demand collapse, by whatever mix of mechanisms, then they might well not get done.

    • Dennis Coyne says:

      Hi Shintzy,

      The output lines are what would happen if oil prices follow the path assumed. The short term volatility in oil prices may not have a big effect on investment decisions, it is the 12 month average price that is of greater importance. I think of the upper and lower scenarios as bounds on the possibilities for the path of output.

      If you tell me what the future price will be, I will show you what the model predicts for future output assuming your prediction is correct.

      When I ask for such predictions, I get nothing.

      There will generally be a lag of 4 to 6 months between price movements and output.

      Chart below shows trailing twelve month average of nominal Brent Spot prices from 1990 to Feb 2017, the blue line is the most recent 120 month average ($83.66/b). From this chart the volatility looks to be from 2 to 6.5 years for the cycle.

      I agree that costs may rise in the future, especially as we reach diminishing returns of efficiency and technology improvements. Right now there are a lot of idle rigs and workers so it will take some time before capacity limits are reached, service companies are hungry for business and will not be quick to rise their prices.

      In fact some larger companies are reducing the use of service companies to save costs.

      Eventually though, real costs are likely to rise, so that should be in the model.

  12. What is the oil industry going to do with all that light and extra light oil?

    Is it filling up inventories?

    8/10/2016 U.S. Storage Filling Up with Unaccounted-For Oil

    • Dennis Coyne says:

      Hi Matt,

      The usual, make gasoline. There is plenty of heavy oil out there, we are talking about an extra 2 or 3 Mb/d out of 80 Mb/d produced Worldwide. Unlikely to be a problem in my opinion. In many placed the light oil trades at a premium because it is cheaper to refine. The heavy residuals are not all that valuable.

      • When mechanically mixing extra light and heavy oil, you are still not having the desired middle fractions, so there are additional refining steps needed.

        Is there now an update to this report “Working with tight oil”

        Refinery yield for gasoline did not increase

        US refinery net production is down from 2010

        Exports of gasoline have gone up by only 400 kb/d since 2010

        You really need to show statistics to explain what you are saying

        • George Kaplan says:

          I don’t follow your arguments. The fact that LTO may need to be handled slightly differently just means the transporters and refiners have to adjust. It takes a bit of time and money but it gets done. The new refinery proposed for the Permian area is a longer term response, but changing operating parameters, a bigger focus on blending and brownfield equipment modifications all play a part and can and have been done relatively quickly. Allowing crude export might also have been part of this. I think condensate was always allowed as expert and there was a increase in thiat as shale gas was developed – without causing noticeable problems.
          Gasoline exports are irrelevant, they are just what is left over after the local USA market has been met (I think it is probably mostly sent to Mexico and Canada, which almost counts as local anyway). If local supply of light oil goes up then the mix of imports is changed to give a balance – i.e. gets a bit heavier probably. The total throughput for USA refineries has declined mainly because refining capacity for producer countries and some major importers like India and China has been growing. The decline was mostly before 2010 when LTO started to increase.

        • Dennis Coyne says:

          Hi Matt,

          I agree with George Kaplan, this is not likely to be a problem.

          I was not suggesting heavy and light would be mixed, the refineries will adjust and the light oil will be shipped to those places with refineries that can process it.
          Prices of diesel (or gasoil) and gasoline (petrol) will adjust and affect demand for these fuels, as I said before we are talking about only 9% of World C+C output, the market will adjust.

  13. Oldfarmermac says:

    There’s a lot of pressure being put on the blue water shipping industry to get away from bunker oil and the only practical option seems to be natural gas.

    I don’t have any problem seeing the industry managing the switch, so long as gas stays cheap, and the necessary gas lines and storage facilities get built, which apparently do not yet exist at most ports, and will take a long time to build. And then there is the associated question, will it be feasible to retrofit older cargo ships to burn gas? That sort of work costs an arm and a leg, and it takes a long time. I don’t have shipyard experience, but I’m guessing at least a month or two with a SWARM of men on the job is the least amount of time necessary.

    New ships built to burn gas and used on routes where gas is available for refueling won’t be a problem at all.

    So — Since this change seems to be in the cards, it looks like the market for bunker oil may shrink quite a bit over the next decade or so.

    What other uses can be made of bunker oil?

    How much potential does this shift to gas have to depress the price of oil?

    It’s my impression that it’s so nasty not because of the actual hydrocarbon molecules but rather because it is contaminated with a lot of metals, maybe sulfur, etc.

    Might it be possible to build stationary boilers that can burn it to generate electricity and clean up the exhaust gases ?

    This stuff is out there, and we will be using a LOT of oil for a long time to come, and talking about wind and solar power and electric cars is fun, but electric cars aren’t relevant to the problem, and won’t be , for as long as we use oil by the millions of barrels on a daily basis.

    • Toolpush says:


      The Nat Gas, the ships are going to be burning, will be LNG. CNG has been suggested on some very short routes, but I don’t think any have actually been built. In the short term and as the IMO regulations take effect, it is thought MGO, Marine Gas oil, will be the main benefactor. MGO is diesel with a 500 ppm sulfur content. The traditional bunker fuel, can still be used, but will require large expensive scrubbers to be installed on the ships.
      The shipping industry has been the oil refineries hidden secret for many years. They have been their night soil collector so to speak, doing their best work out of sight of watchful eyes. The bunker fuel, contains up to 3.5% sulfur. Burning it at sea, means that all the SO2 is dispersed into the ocean, rather than causing acid rain over the forests of the world. The problem now, is what to do with all this “night soil”. Burning it on land without expensive scrubbers will only create more pollution. Not a good result. The most likely and best result will be that it will be consumed in complex oil refineries, where it can be broken down into lighter transport fuels, or at a second best, sold to Saudi Arabia and burnt in their oil fueled power plants, allowing them to displace burning crude oil, and exporting this crude on the world market.

      Even cruise ships are getting into the LNG market.


      There are currently ships using LNG sailing out of Jackson Florida, and Oilfield supply boats working for Shell, working in the GOM.

      • Oldfarmermac says:

        Thanks Toolpush,

        I have read a good bit about the LNG industry, and how the special tankers that haul it burn what boils off in the ship engines so none is wasted en route.

        In terms of using it as marine fuel, the question in my mind seems to be this, and really only this.

        Will it be feasible to build LNG “trains” , or just tank farms to store LNG, in major ports? It might be possible to deliver tanker loads to a tank farm to be parceled out again to individual ships as engine fuel if NG delivered by pipeline can’t be liquefied near enough to the docks.

        This sort of infrastructure costs so much nobody will be willing to pay for it, unless they are sure NG will be readily available for a long time. Just finding space to build it will run into real money.

        This could cost so much it might be cheaper overall to just further process bunker oil at the refinery, and get the sulfur and other no no contaminants out, although this approach would most likely require adding on some expensive machinery at the refineries.

    • It’s fairly easy to crack bunker crude, add hydrogen, and make lower molecular weight hydrocarbon molecules. A Coker unit does it, it cracks asphalt, puts out coke and busted molecules. But we have proven processes which take the heavy molecules and hydrogenate them without making coke. If we can take coal and make crude, we can take almost anything like trees and old furniture and make syncrude out of it. It just costs money. Bunker is easy.

      • If we can take coal and make crude, we can take almost anything like trees…

        Trees… Yeah, that’s the ticket. Who needs them damn trees anyway? They are just habitat for some wild animals. Who needs them? And their roots help to keep the topsoil from washing away. But hell, we have plenty of topsoil to spare. Who needs trees? Let’s use them to power our transportation vehicles.

      • Oldfarmermac says:

        Hi Fernando,

        Thanks, I know the basic history of synthetic petroleum and understand the chemistry and physics at the A B C level, although I know nothing about the details at the professional level.

        Have you seen any recent estimates, or maybe even made some of your own, about what it would cost to build a coal to liquid refinery, and the minimum price of oil that would make it profitable to build a coal to liquid plant?

        Do you think it might be cheaper to do additional processing of bunker fuel to get the nasty components, sulfur and metals, out and continue to burn it in ship engines, than it would be to run ships on LNG ?

  14. George Kaplan says:

    Central GoM lease sale attracted $315.3 million, with $274.8 million successful, with 189 bids on 163 tracts – i.e. most leases attracted single bds. The were over 9000 available tracts, less than 2% attracted bids, almost all in water over 400m. The numbers were up about 40% on last sale in this area when $179 million was bid and $156 million worth was successful. Shell was largest bidder with $55 million total and largest single bid of $24 million.BOEM estimates 460 to 890 mmbbls resources for oil and 300 to 600 mmboe for gas. The industry and BOEM are talking this up as a sign as growing confidence. I’m not so sure.
    I hadn’t realised until recently that the lease cost in the USA is a direct sale – i.e. the E&P pays the money and doesn’t get it back, plus has to pay some rental or minimum royalty on the tract. This is different to some other areas, e.g. UK, Norway and offshore Canada, where the E&P agrees to spend a certain amount on exploration, but then has a higher royalty fee if they find and develop anything.


    For UK 29th round, recently announced: A total of 24 application for the 113 blocks that were up for grabs this round. Only three firm well commitments were made, so mostly these will be for seismic only. The previous round had over 170 applications.

    Awards were: Statoil & BP – 5; Statoil & ExxonMobil – 1; Zennor, Alpha Petroleum, Decipher Energy and Nautical Petroleum – 1 each; Azinor Catalyst -2; TAQA Bratani, The Steam Oil Production Company, North Sea Natural Resources, Simwell Resources and Centrica – 1 each; Ardent Oil – 2; Chrysaor, Draupner Energy and Simwell – 1 each.

    I haven’t heard of about half those companies. There was a supplementary round with eleven applications for fifteen blocks, with results expected later this year.

    Next announcement for lease sales might be for Oman.

    • You do get some money back if you write the lease off and return it (you get the tax deduction). Many years ago I was involved in an exploration deal offshore Texas, with a huge bonus. The bonus was so high even though we had a viable discovery it was a better deal to write it off and hand it back to the Feds.

  15. Energy News says:

    The Economist – March 22nd, 2017 – Schumpeter
    (US Shale) Exploration and production companies are poised to go on another investment spree

    The partial recovery in the oil price, which at one point fell as low as $26, is only one factor behind renewed enthusiasm for shale. Houston’s optimists also argue that the full geological potential of Texas’s Permian basin has only just become apparent. Some experts think it could in time produce more barrels each day than Saudi Arabia does. That has offset gloom about falling production from other shale basins, such as the Bakken formation in western North Dakota. The industry has also lifted productivity. Drilling is faster, more selective and more accurate, and leakage rates are lower. Wells are being designed to penetrate multiple layers of oil that are stacked on top of each other.

    But the fact that the industry makes huge accounting losses has not changed. It has burned up cash whether the oil price was at $100, as in 2014, or at about $50, as it was during the past three months. The biggest 60 firms in aggregate have used up $9bn per quarter on average for the past five years. As a result the industry has barely improved its finances despite raising $70bn of equity since 2014. Much of the new money got swallowed up by losses, so total debt remains high, at just over $200bn.

    Oil bosses like to show off their newest wells in the Permian basin, which, they say, can now make internal rates of return of more than 50% over their working lives. But most firms have mediocre wells too, as well as corporate overheads, so their overall efficiency improvement has not been great. For the ten largest listed E&P firms, aggregate cash operating costs per barrel fell by $13 between 2014 and 2016; not enough to offset a $50 drop in the oil price. Because shale-energy fields run out far faster than traditional ones, firms must reinvest heavily to keep production flat.

    (I’m not a subcriber but it seems that you can read one for free)

  16. Enno Peters says:

    Thanks for the post Dennis.

    I also just released an update on LTO production in the 8 states that I cover, available here.

  17. Boomer II says:

    Some interesting articles.

    As Trump targets energy rules, oil companies downplay their impact | Reuters: “… the top U.S. oil and gas companies have been telling their shareholders that regulations have little impact on their business, according to a Reuters review of U.S. securities filings from the top producers.”

    This article is behind a firewall, so I haven’t read it.
    Latest Threat to U.S. Oil Drillers: The Rocketing Price of Sand – WSJ

    There’s almost zero rationale for Arctic oil exploration, says Goldman Sachs analyst: “‘Immensely complex, expensive projects like the Arctic we think can move too high on the cost curve to be economically doable,’ Della Vigna explained, pointing to a new ‘oil order’ as represented by a much shorter and cheaper production cycle driven by the U.S.”

    Big Oil Replaces Rigs With Wind Turbines – Bloomberg: “Big oil is starting to challenge the biggest utilities in the race to erect wind turbines at sea.

    Royal Dutch Shell Plc, Statoil ASA and Eni SpA are moving into multi-billion-dollar offshore wind farms in the North Sea and beyond. They’re starting to score victories against leading power suppliers including Dong Energy A/S and Vattenfall AB in competitive auctions for power purchase contracts, which have developed a specialty in anchoring massive turbines on the seabed.”

    • Yep. But those offshore wind projects do require subsidized prices, and they suffer from intermittency and extremely high OPEX. I have serious doubts they’ll be viable for society unless the turbines are built much more able to take the loads.

      • Boomer II says:

        But if your doubts about wind are accurate, then major oil companies must be in even more trouble than people assume. You are suggesting that they are expanding their focus to doomed projects, which then suggests they have little confidence in the future of oil profitability and wind looks better even given its limitations.

        • Reno Hightower says:

          It is good PR. Nothing more.

          • Boomer II says:

            But that still makes my point. If big oil is getting into wind solely for PR purposes, then they have reason to believe their traditional businesses aren’t sufficient to show that they have a future.

  18. These days, I’m super-skeptical of literally everything coming out of the financial press about oil production, oil prices, the wisdom of investment in oil companies, etc. All it takes is a rumor about more drill-rigs moving into the Permian Basin to drive down WTI prices by 5-10%, or so it seems to the uninitiated.

    So if the optimistic scenarios described above come to pass, they’re also simultaneously the pessimistic scenarios, because apparently all the OPEC nations are also capable of flooding the global market with abundant un-needed oil as well. It seems to the Guy on the Street that the fracking boom is the sound of the oil and gas industries blowing up their own business model. Over and over and over again.

    Since our mission in writing a blog is an alternative-far Leftist (or “Snowflake Stalinist” I’ve been told) analysis of what is wrong with the economic system, and how it has to change so that the younger generations can survive at least at a Second-World living standard, it’s important to get the narratives right. I live in Wisconsin, which I would place in the very bottom 5 states in terms of long-term sustainability as the petroleum era coasts slowly to a close, whenever that may be. Besides being the frac-sand capital of North America, we’re also one of the biggest crude oil corridors (Enbridge, with 5 and soon going to 6, or, 7, or 8, depending on Line 5’s fate.

    I think if we don’t build-out a 100% renewable-energy-powered mass transit system starting within the next 2 decades, even the Second-World living standard for Wisconsin is way too optimistic. And of course, we’re not going to do that, because there’s just “plenty of oil” out there (or fracked natural gas, for electric vehicles) waiting to be pumped up and burned. Also, there’s no money remaining for that option.

    The future: Looks sketchy to me.

    B.G. in Wisconsin

    • Dennis Coyne says:

      Hi B.G. in Wisconsin,

      The “optimistic” scenarios show an increase in LTO oil output of about 2.1 Mb/d from peak in March 2015. World demand tends to grow at about 1.2 Mb/d (over the past 5 years or so) each year, the peak of the “high price scenario” is in 2022, so over 7 years we would see World oil demand growth of 8.4 Mb/d from 2015 to 2022, even a reversal the OPEC and non-OPEC cuts plus the possible increase of 2.8 Mb/d from 2017 to 2022 in US LTO (high oil price) would only amount to 4.8 Mb/d, demand is likely to increase by 6 Mb/d by 2022, it is for this reason that I expect high oil prices are more likely.

      Note that we will in fact be 1.2 Mb/d short on oil output unless demand for oil rises less than I have guessed or OPEC increases output (Iraq, Iran, Libya, and Nigeria possibly) more than declines elsewhere. There might also be increased output from oil sands in Canada and Venezuela and maybe some deepwater increases from Brazil, and some onshore output increases from Russia. These might keep prices from rising too high and too much output will reduce oil prices, but I doubt there will be excess supply unless there is a recession/depression or the transition to EVs and other electric transport moves quickly under a high price scenario. Hard to predict for sure.

      • Yaman Tasdivar says:

        Keep in mind that +1.2 mbd (which seems on the low side just eyeballing) was during a tepid period for global growth, which is accelerating by many measures. I expect above-trend global growth in 2017 and 2018, so more than +1.5 mbd oil demand growth in both years.

        My estimate accounts for interest rates rising at the expected rate of 3 per year, but 2018 demand may be lower than +1.5 mbd if rate rises accelerate, which I do not expect at this time.

      • Yaman Tasdivar says:

        Also, you may pretty safely take out Iran from your list of possible contributors to oil supply in the near term, as they seem to be at max capacity and drawing down FloSto pretty quickly.

      • Yaman Tasdivar says:

        Another point we disagree is Venezuela. I expect Venezuela (where food is being protected by military…) to see declining oil production even beyond OPEC cuts.

        • Yaman Tasdivar says:

          Here is a timely article on Venezuela prodution:


          “Venezuela output is expected to drop by 200,000 barrels a day”

          which I estimate will prove to be optimistic…

          • Dennis Coyne says:

            Hi Yaman,

            I am thinking longer term like 2025 to 2030. Iran may do some EOR by bringing in outside help. Eventually Venezuela may solve its political problems and if they do oil output might increase, Libya, and Nigeria might eventually solve their political difficulties as well, these are potential areas where output might increase.

            Generally I agree though that scarcity is more likely.

          • Right now there are long gasoline lines, buses can’t do their complete routes due to diesel shortages. A union leader says the gasoline tank farm which supplies Caracas has tanks with such low fluid level, they were pumped below the safe suction point for the pipeline pumps.

            It sure looks like obama’s move to encourage the Castro dictatorship has led to Maduro driving hard towards a super disfunctional narco dictatorship. I don’t have the foggiest idea about what’s going to happen, but it looks really grim.

      • Yes, I do appreciate the points you make about the growth in demand; 1.25 MB/day is about a 1.5% per annum increase, about in line with how GDP growth has stalled in the USA.

        The problem with “sustainability thinking” is trying to get people to focus out 20 years on the timeline, because that’s how you have to think in sustainability studies. Our local University of Wisconsin campus is the lead campus in the state for natural resources and sustainability studies, so the community around it is a little more clued-in than other small midwestern communities. Especially those which have become dependent on frac-sand mining for the few jobs it provides.

        Trying to pull of a “transition” from fueling transport (and heating of buildings) with petroleum and natural gas, in anything less than a 20-year timeline, is going to be impossible. Getting people to see the urgency for this, given the glut of petroleum products, is just about as impossible as the actual transition.

        “Transition” should have gotten started around the turn of the century, at the very latest.


        • Dennis Coyne says:

          Hi BG,

          No question that it will be difficult, perhaps near impossible. When fossil fuel output peaks at a high fossil fuel price level (around 2025 for all fossil fuels, a bit earlier maybe 2022 for oil) then there will be economic disruption and peak fossil fuels will become mainstream. At that point the transition might happen quite rapidly as we may see rapid adoption of EVs and plugin hybrids. Also note that the rapid decline in fossil fuel output that some foresee is not very likely unless it is driven by lack of demand as the transition proceeds. As long as oil prices remain high the decline in output will be relatively slow (1 to 2% per year). This gives us a bit of time to make the transition, though things are likely to reach a critical mass by at least 2045 where demand may fall to the point that oil prices start to fall and oil output declines rapidly at that point.

          Also a Great Depression would also cut oil demand and lead to a drop in oil prices and perhaps government policy might speed up a transition (tax incentives for EVs and wind, and PV, as well as investment in rail, light rail HVDC transmission, and better urban planning (bike paths, walkable neighborhoods).

  19. dclonghorn says:

    Dennis I appreciate the graphs and forecasts you make. When you show the assumptions you make and the results we learn even when we don’t agree with some of the assumptions. I was thinking of another way of looking at LTO production as it relates to some of the gulf opec production.

    Of course we don’t have good data on what kind of wells are being put in production today in countries such as KSA, however we know that some years ago a well in north Ghawar often produced around 5000 bopd for years. I wonder what kind of drilling program would be needed to produce a stream of 5000 bopd from LTO.

  20. Hickory says:

    I have been surprised to not hear more about Vaca Muerta exploration and production ramping up. I suppose it will take higher prices and more time to get the ball really rolling there.


    • Argentina has a much more controlled industry than the USA. And they do tend to nationalize foreign investments. It’s mostly a YPF and major oil company play. And the infrastructure has to be put in place, including the sand and water supply. They do have a fairly low cost environment. And there’s a pretty nice paved road all along the Andes foothills. So I imagine eventually they’ll be producing as much as 200,000 BOPD from the Vaca Muerta.

  21. Boomer II says:

    Oil Producers Are Leaving Thousands of U.S. Wells Unfinished | Fortune.com: “U.S. shale producers are drilling at the highest rate in 18 months but have left a record number of wells unfinished in the largest oilfield in the country—a sign that output may not rise as swiftly as drilling activity would indicate.”

  22. shallow sand says:

    What do others think of XOM, CVX, OXY and COP allocating significantly more $$ of CAPEX in the Permian Basin, and much less to conventional projects.

    I own XOM and COP, and it is bothering me. Why will they make money and be able to continue to pay healthy dividends when the others in the shale business cannot?

    I suppose XOM has refining and other businesses. COP spun off its other businesses into PSX.

    I know this is not an investment site, but XOM is one of the most widely held stocks in the world, and is a core holding in most retiree’s mutual funds. They have a lot of inside dope on the future of oil prices, what does XOM know that we don’t? Why would they go headlong into shale given they have to date lost billions at it?

    • Reno Hightower says:

      It will be a long time before a publicly traded company drills a conventional oil and gas well onshore in North America.

      • shallow sand says:

        Reno: Per shaleprofile.com, XOM’s 2,000+ Hz wells produced an average of 44 bopd per well in November, 2016.

        They have spent North of $3 billion of CAPEX for these wells, 15-20,000′ wells that are already down to this average. These wells are almost all less than ten years old.

        • shallow sand says:

          I suppose maybe the per well BOPD is so low due to inclusion of gas wells?

          Just read that XOM is the most out of favor in terms of Buy/Sell/Hold since 1999. So Wall Street wants XOM to turn to shale or not?

    • George Kaplan says:

      Looking at their 2016 operations report they may not have that many easier options than shale. They list around 30 prospects after 2018 (below – first column is kbpd capacity – for brownfield I think this is total, not additions, second is gas capacity, third is ExxonMobil percentage ownership, red square means they are operator). About half are gas – and some of these like Scarborough and Alaska LNG are currently very unattractive. Of oil they are concentrated in oil sands (I don’t know what general SAGD means, it might be over several projects), Nigeria (deep water, expensive, previously delayed and with ongoing issues in terms of tax, corruption, security and local content requirements), Iraq and Kazakhstan (the latter two have there own issues and would be fairly far in the future for the projects involved, after current projects are started and proven). On a lot of the bigger projects they are not the majority owner and so reliant on other’s investment plans.

      They seem to be concentrating on downstream more this year and might be looking for another big purchase (BP or Anadarko shareholders have been approached). They had high hopes in Russia before the sanctions and might again.

    • clueless says:

      My somewhat educated thoughts are: There is ample evidence that virtually no oil company has information such that they have “a lot of inside dope on the future of oil prices.” They can have inside info on individual plays, but not much else. For a large company like XOM, positioned where they are in the investment world, they do have continuous pressure to grow their reserves. Otherwise, they are virtually liquidating and become unattractive as a long term investment. So, in my opinion, they can have a corporate goal of increasing reserves in the present, and worry about the ultimate profitability of those reserves later.

      • shallow sand says:

        Clueless. Bad stab at humor on my part, I don’t think XOM, or others know a lot more than the rest of us regarding future oil prices, especially out past one year. They know more, for sure, but how much more is debatable.

        I thought it might be interesting to compare OXY in 1998 to 2016. Some numbers I pulled from 10K

        Earnings. 1998. $0.99 per share. 2016 -$0.75 per share (these are not including impairments and other special charges, I think.) I didn’t get shares outstanding data, so not apples to apples, think loss in 2016 would have been higher in terms of 1998 outstanding shares.

        Production 1998. 439,000 BOEPD, 183,000 in US
        Production 2016 630,000 BOEPD, 302,000 in US

        Long term debt 1998 $5.4 billion.
        Long term debt 2016 $9.8 billion.

        1998 average oil and gas prices: $12.06 oil. $2.03 gas.
        2016 average oil and gas prices: $38.55 oil. $1.91 gas.

        1998 upstream CAPEX $751 million (grew production from 1997).
        2016 upstream CAPEX $1,978 million (production fell from 668K BOEPD in 2015).

        More upstream CAPEX information:
        1998 CAPEX was higher than 1996 and 1997
        2014 CAPEX $6.533 billion
        2015 CAPEX $4.442 billion
        2017 CAPEX projection $3.0-3.6 billion.

        Share price, adjusted for splits 1998 $7.91 on 12/31/1998
        Current stock price $62.83.

        OXY is currently paying $2.3 billion per year in dividends. Current dividend yield is 4.80%.

    • Oldfarmermac says:

      HI SS,

      I will be the first person to admit that I don’t know any more about the oil business than I have learned reading a few books, a dozen or so, and following a couple of blogs such as this one.

      But I think you have nailed it, in asking the question, what do XOM and COP know that you and I don’t?

      They have all the inside dope, and in my opinion, based on knowing how some other industries operate, I believe they know just about every damned last important fact known to ANYBODY in the oil business ANYWHERE, although of course nobody can be completely sure about the future of the economy and the future price of oil.

      Now WHY should I think XOM would know all about the supposedly secret affairs of let us say ARAMCO? It’s simple as shit, and it’s called industrial espionage aka spying. When you are one of the worlds four or five biggest buyers of the specialized machinery, engineering expertise, computer programming expertise, etc, well, the folks that sell to Aramco would have an extraordinarily powerful incentive to tell you just exactly what they sold to Aramco, and when, and even the exact date of delivery, lol.

      And when you can quietly put any old guys, or refugees, or anybody else who happens to be a former Aramco insider on the payroll, they will fill you in. They don’t have to even be put on the payroll, somebody with management clout can arrange for a honey trap, and a lonely man will tell the woman anything he knows, simply to impress her, when she makes big eyes at him and admires his expertise.

      It doesn’t even require a woman, inviting such a man over to enjoy a cookout and a few beers will do the trick sometimes, especially if he is a tradesman rather than a professional such as an engineer or accountant.

      If somebody will tell me just how much of what and when one of my competitors in the apple biz has bought in the recent past, and I can tell you to within ten percent what his production will be, no problem, lol, for the next few years. The one thing for sure the orchard biz has in common with the oil biz is that the lead times are measured in years, rather than weeks or months, although the lead time appears to be shrinking in the tight oil biz.

      Nobody ever posted much that “made sense ” in the way of comments that I remember reading about WHY the big companies cut back so far on new investments well in advance of the last oil price crash. My own personal opinion is that maybe they saw the price crash coming, rather than that they couldn’t see any way to make a profit on new investments with oil at or near a hundred bucks. I posted a few comments to this effect myself, but they were ignored, no responses.

      Is it possible they could have known for sure the price would crash? Of course not. But they obviously had better data than maybe anybody else in the world, except maybe Uncle Sam’s spy’s , or Putin’s spys, etc, who may have ALL the available data, having stolen it from EVERYBODY, at the wholesale level. ( This bit about government spying isspeculative and half humor and I don’t think Uncle Sam has devoted NEARLY enough resources to the job to do it at that level, but who really KNOWS? )

      One thing’s for sure. If the oil majors expected the price crash, then this information would have been VERY tightly held at the highest management levels, and it’s obvious that it’s the sort of info they would want to keep secret. Maybe they knew, or at least strongly suspected there would be a supply glut and a consequent crash, and maybe they DID manage to keep it secret. One thing is for sure, they DID cut back big time, well in advance of the price crash.

      My guess now is that they have data enough to be confident that whatever investments they are making now will be profitable.

      They’re betting on the price going up.

      • clueless says:

        I worked for an oil and gas company in 1981. We were not a major, but we had a lot of joint ventures with majors. The company saw the crash coming before the majors in late 1981. Why? It was pretty simple. Our accountants and the finance people went to the exploration people and told them that the amount of money that they were spending for lease acquisition and drilling was too high. We were going to lose money even if prices continued to rise. So, we cut back – significantly. Within a year, so had most others.

        Early on in late 2013, first with natural gas, the exploration companies (the poster child was Chesapeake) started to realize that with their gas finds that they could not pay for the wells with gas prices under $1. Then, the companies in the Bakken and Eagle Ford figured out that they could not make money in shale oil drilling like drunken sailors. And, the majors found out that the could not drill deep offshore projects unless oil stayed above $100. I am sure that the bankers in many instances also figured it out at about the same time.

        In 1981-1984 there was a more severe correction, in my opinion because a lot of banks went under. This time, it has been more of a dribble downward, primarily because of new sources of financing enabled the banks to largely escape the debacle.

  23. Boomer II says:

    Oil Companies Cool on Arctic Drilling. Trump Wants It Anyway. | Foreign Policy: “Big oil gave up on some $2.5 billion in drilling rights in the U.S. Arctic in 2016; expensive plays as oil prices dropped just weren’t worth the cost anymore. ‘High-cost frontiers,’ like the Arctic ‘will be shunned,’ energy intelligence firm Wood Mackenzie said in December last year.”

  24. Boomer II says:

    With rebates, you can get a new Nissan Leaf for about $11,000.

    Drive away with an affordable electric vehicle in Colorado – Xcel Energy Connect Blog

  25. I don’t know if this has been posted before or not. And I don’t know how the hell I missed it. It is dated two months ago. It deserves a fresh look even if it has been posted before.

    Brace for the Oil, Food and Financial Crash of 2018

    New scientific research suggests that the world faces an imminent oil crunch, which will trigger another financial crisis.

    A report by HSBC shows that contrary to the commonplace narrative in the industry, even amidst the glut of unconventional oil and gas, the vast bulk of the world’s oil production has already peaked and is now in decline; while European government scientists show that the value of energy produced by oil has declined by half within just the first 15 years of the 21st century.

    Among the report’s most shocking findings is that “81% of the world’s total liquids production is already in decline.”

    • Boomer II says:

      It has been posted here before, but well worth posting again. Especially when we have someone saying, “The oil price only needs to be $40-$45 to supply this planet with all the oil it wants and needs.”

    • Watcher says:

      even amidst the glut of unconventional oil and gas, the vast bulk of the world’s oil production has already peaked and is now in decline; while European government scientists show that the value of energy produced by oil has declined by half within just the first 15 years of the 21st century.

      The first part of that matters. A lot.

      The second part doesn’t. That’s just price.

      • twocats says:

        I’m not so sure. When he uses the word “value” and “cost” I think he’s tying them directly to energy content, not just some spot price on a futures market.

        “This means that overall, despite total liquids production increasing, as the energy value it generates is declining, the overall costs of extraction are simultaneously increasing.”

        here he specifically links energy to value, and then that directly to costs. Nafeez does mention that HSBC thinks oil prices will fluctuate around $75/barrel to push off decline. So there is the “number” that Dennis keeps asking for. Nafeez then quickly mentions that this is probably too high to avoid recession, and talks about the dynamic between peak oil, debt levels, and current growth.

        nafeez ahmed is consistently very good, and this is a fantastic article simply for the fact that he’s tying together both the geophysical and economic systems – not an easy thing to do without getting sidetracked.

        • Watcher says:

          “HSBC thinks oil prices will fluctuate around $75/barrel to push off decline. So there is the “number” that Dennis keeps asking for. Nafeez then quickly mentions that this is probably too high to avoid recession, and talks about the dynamic between peak oil, debt levels, and current growth.”


          Recession is measured with printed pieces of paper. Oil priced north of $100 from about 2011 to mid 2014. That’s 3 yrs. Real US GDP growth over that time, flat 1-2ish%. No recession. Price going on 3 yrs since 1/2 that, GDP growth 1-2ish%. No recession. No change.

          Oh, but blah blah blah blah. In a world of printed pieces of paper, blah blah blah takes on its own imperative.

          Three years high. No effect. Three years low. No effect.

          • Boomer II says:

            This post pretty much summarizes the various discussions about debt, growth, declining resources, and environmental damage. A lot more to it than I am quoting.

            Dying of (wilful) ignorance – Consciousness of Sheep: “Money printing – whether by governments or banks – has a cyclical effect. At the start of a cycle, as the economy recovers from the last recession, spare capital is locked up in ‘safe haven’ assets like property, gold and fine art. This acts as a break on investment, and is part of the reason for recession. When a government prints or a bank loans currency to businesses, this new currency effectively brings forward future production. New resources are mined, new fuels recovered, new technologies deployed and new products and services created and sold. But the economic system has a blind spot to the resource implications. There comes a point in the cycle when the real economy can no longer bring forward the quantities of resources, energy, capital and labour required to maintain growth. Toward the end of the cycle, the ratio of currency/debt to GDP gets too high. Costs increase. Growth stalls. Investors flee. People stop buying. Businesses close. Suddenly we find ourselves back in another recession.

            Note that the only way in which we can get the economy out of a recession is to print/loan-into-existence sufficient new currency to bring forward (in an environmentally damaging way) additional resources, fuels, capital and labour. But, as we now understand from our climate scientists, we have already done this beyond the point where it is going to destroy the habitat that allows humans to exist.”

          • twocats says:

            it is true that if you keep interest rates at zero or negative for a decade and print trillions of dollars globally, build ghost cities, buy vacant shacks in vancouver ca for millions, you are bound to see a little bubbling of the economy.

            plus, there are people who still want to live their lives even if it means taking a three year loan to buy a computer, or 7 years for a car, or buy a condo for $1,000 sqft because its in seattle and sf and that’s where their high tech job is.

            I think in some way your “crapola” dismissal of that historical fact of high oil prices correlating with recessions is accurate because we have entered this new economic reality, which is what I’m assuming you are pointing to with the “printed pieces of paper”.

            Of course, if oil prices go to $75 and we enter a recession everyone will be on this blog saying “I told you that would happen”. soooo….

            I’m agnostic on the issue.

            • Dennis Coyne says:

              Hi two cats,

              The main point is that for the World real GDP growth rates from 2011 to 2014 (at market exchange rates) was about 2.5% to 3% per year, oil prices were over $100/b (in 2016$) over most of this period.

              So I agree with Watcher that oil prices over $75/b do not necessarily cause a recession. The World uses oil much more efficiently than it did even 15 years ago, at $130/b (2016%) we might run the risk of recession due to high oil prices, but at $75/b not so much in my opinion.

              Note however this does not tell us what oil prices will be, that is determined by supply and demand which is impossible to predict.

              • twocats says:

                I would claim that some of that demand destruction (you call efficiency) was a bit of a one-off. now that the US and Europe have shaved off/transferred demand to Asia for a decade (I don’t have the numbers in front of me but I think it was somewhere in the ballpark of 10 quadrillion btu), let’s see if we can have a repeat of that process for another decade. taking bets.

                in addition you guys are completely discounting QEs 1, 2 & 3. which have now ended, though world Central Banks are still printing at a clip (I haven’t looked at the numbers in a while).

                They have attempted to short-circuit the business cycle altogether, and this has resulted in a semi-comatose global economy. we have entered a new economic reality, but you guys aren’t even seeing why price didn’t matter to demand or GDP since 2010. just saying efficiency is a bit of a cop-out.

                • Dennis Coyne says:

                  Hi two cats,

                  My “efficiency” is essentially World Real GDP (at market exchange rates) divided by crude plus condensate consumption. When we get more goods and services from each barrel of oil consumed (adjusted for inflation) we are using the oil more efficiently, this has been going on since 1972 though the rate of increase in constant dollars of GDP per barrel has not been constant.

                  Higher oil prices lead to greater efficiency and oil prices will continue to rise until the fall in demand is faster than the fall in supply, I expect this to occur in 2030 to 2040, best guess 2035 due to a major World recession.

                  • twocats says:

                    Yeah that’s also flawed. if i print paper, put it into the economy and people buy and sell non-physical assets into oblivion, or buy and sell the same house 1,000 times, that all goes into GDP. sure, no oil was used. very efficient indeed.

                  • Dennis Coyne says:

                    Hi two cats,

                    Only the realized capital gain (or loss) on the sale is reflected in GDP.

                    I agree GDP is not perfect because a lot of economic activity is not a part of the market.

                    When I clean my house or do yardwork it is not included in GDP. If I hire someone to clean my house or take care of my lawn, then it is included in GDP.

                    I agree the measure is flawed. How do you measure economic activity?

                    GDP is the measure we have, most statistics are imperfect.

        • Dennis Coyne says:

          Hi two cats,

          The value of a good is not determined by any objective quantity whether it be hours of labor in the labor theory of value, or even hours of capital used in the capital theory of value (I made that up), one could claim that energy is the source of all value, or apples, bananas. One just needs to do a sophisticated input output analysis to value all goods in the unit of some other good, the choice of good is entirely arbitrary. In modern economics there is no objective theory of value, each individual subjectively assigns a value to a good and they express their preferences by purchasing goods in such a way that maximizes their utility.

          Price has nothing to do with objective value, it is a market clearing mechanism to balance supply and demand.

          • twocats says:

            you are using an economic definition of value, and completely disregarding other potential definitions. if you don’t agree that the word value can have more than one meaning that’s fine, but I don’t need an econ 101 lesson, its condescending. thanks.

            why would he qualify the word “value” with the word “energy” if value cannot be modified in anyway. as if value is some unique signifier. seems a little dense to me.

            • Dennis Coyne says:

              Hi two cats,

              My point was mostly that value is not objective it is subjective in my opinion.

              So using value in a technical discussion is not very useful.

              Do you believe value can be measured?

              Can you explain how it is done?

              Note that value is rarely discussed in most introductory economics classes that I have taught, mostly that comes at the intermediate microeconomics level.

              • twocats says:

                think more like EROEI. i can’t believe I’m having to explain this to you. he’s talking more about energy left to the economy. he’s just using economic/subjective terms to keep the article from becoming pages longer or having to have a page long footnote explaining EROEI.

                i think we are talking in circles a bit here. i can’t read the author’s thoughts, but I think watcher’s original claim of “the author is talking about price and therefore that portion of the article is uselss” is selling the author’s understanding of the issue short. i think he understands price/value is relative and was putting the phrase “energy value” to mean net energy to society.

                if you don’t agree with the definitions laid out by the author or if you and watcher don’t really believe that concepts like EROEI have any significance to peak oil dynamic that’s fine. we will just agree to disagree. i find it pertinent.

                • Dennis Coyne says:

                  Hi two cats,

                  The author argues that due to falling EROEI, the oil price will fall. I do not think the oil price and EROEI are tied very closely.

                  EROEI is best used to consider society wide energy use. Looking at a single energy source’s EROEI (oil, coal, natural gas, solar, wind, hydro, or nuclear) reveals very little as there are many forms of energy used as inputs in the energy production system and we need to look at energy inputs and outputs for the entire economic system.

                  If energy becomes scarce, its price will increase and people will use energy with greater care and waste far less. You may not believe this is the case, but I would disagree.

                  • twocats says:

                    I appreciate your time on this issue. thanks Dennis and all contributers at peak oil barrel.

      • Lloyd says:

        Hi Watcher.
        From the article:“In order to avoid the [oil] price affordable by the global economy falling below the extraction cost, debt piling (borrowing from the future) becomes a necessity, yet it is a mere trick to gain some time while hoping for something positive to happen,” said Meneguzzo. “The reality is that debt, basically as a substitute for oil, does not work to produce real wealth, as apparent for example from the decline of the industry value added as a percentage of GDP.” Emphasis mine.

        You sure you read the whole article? Meneguzzo sounds like a kindred spirit.


    • Why hell yes, it has been posted before, I posted it myself. But for some stupid reason I paid little attention to it before and therefore did not remember it. But now after thoroughly reading it I find it shocking.

      10 things you need to know

      1. The oil market may be oversupplied at present, but we see it returning to balance in 2017e

      2. By that stage, effective spare capacity could shrink to just 1% of global supply/demand of
      96mbd, leaving the market far more susceptible to disruptions than has been the case in
      recent years

      3. Oil demand is still growing by ~1mbd every year, and no central scenarios that we recently
      assessed see oil demand peaking before 2040

      4. 81% of world liquids production is already in decline (excluding future redevelopments)

      5. In our view a sensible range for average decline rate on post-peak production is 5-7%,
      equivalent to around 3-4.5mbd of lost production every year

      6. By 2040, this means the world could need to replace over 4 times the current crude oil
      output of Saudi Arabia (>40mbd), just to keep output flat

      7. Small oilfields typically decline twice as fast as large fields, and the global supply mix relies
      increasingly on small fields: the typical new oilfield size has fallen from 500-1,000mb 40
      years ago to only 75mb this decade

      8. New discoveries are limited: last year the exploration success rate hit a record low of 5%,
      and the average discovery size was 24mbbls

      9. US tight oil has been a growth area and we expect to see a strong recovery, but at 4.6mbd
      currently it represents only 5% of global supply

      10. Step-change improvements in production and drilling efficiency in response to the downturn
      have masked underlying decline rates at many companies, but the degree to which they
      can continue to do so is becoming much more limited

      • Hickory says:

        Agreed Ron. Profound conclusions, and I see no reason to differ with their analysis.

        • Dennis Coyne says:

          Hi Hickory,

          The analysis is pretty good and it is the reason I think forecasts of $55/b until 2020 are not sensible, even the AEO 2017 reference price scenario is likely to be too low. In the chart below I show real Brent Prices (in 2016$) from AEO 2017 for the reference scenario, the high oil price scenario, and the average of the high and reference cases (dashed line). To me the dashed line looks like the best case, but a better guess would be for prices to remain at $150/b from 2030 to 2045 (for 3 year average price) and then to decline to $100/b by 2050 as transition to electric transport takes hold.

  26. Bob Frisky says:

    Remarks by President Trump in TransCanada Keystone XL Pipeline Announcement

    Oval Office

    THE PRESIDENT: Thank you very much for being here this morning. Today, I’m pleased to announce the official approval of the presidential permit for the Keystone XL Pipeline. TransCanada will finally be allowed to complete this long overdue project with efficiency and with speed. We’re working out the final details as we speak. It’s going to be an incredible pipeline, greatest technology known to man or woman. And frankly, we’re very proud of it.

    Russ Girling, President of TransCanada, is right behind me, and I’m going to have him say a few words. I know, Russ, you’ve been waiting for a long, long time. And I hope you don’t pay your consultants anything because they had nothing to do with the approval. (Laughter.) You should ask for the hundreds of millions of dollars back that you paid them because they didn’t do a damn thing except get a no vote, right?

    It’s a great day for American jobs and a historic moment for North American and energy independence. This announcement is part of a new era of American energy policy that will lower costs for American families — and very significantly — reduce our dependence on foreign oil, and create thousands of jobs right here in America.

    And I also would like to add I think it’s a lot safer to have pipelines than to use other forms of transportation for your product.

    When completed, the Keystone XL pipeline will span 900 miles — wow — and have the capacity to deliver more than 800,000 barrels of oil per day to the Gulf Coast refineries. That’s some big pipeline.

    The fact is that this $8 billion investment in American energy was delayed for so long — it demonstrates how our government has too often failed its citizens and companies over the past long period of time. Today, we begin to make things right and to do things right. Today we take one more step in putting the jobs, wages, and economic security of American citizens first. Put America first.

    As the Keystone XL pipeline now moves forward, this is just the first of many energy and infrastructure projects that my administration will approve — and we’ve already approved a couple of other big ones, very, very big ones, which we’ll be announcing soon — in order to help put Americans back to work, grow our economy, and rebuild our nation.

    And with that, I’d like to invite Russ to say a few words. Russ is a very highly respected man in the energy world. He’s President of TransCanada. And I know you’ll do a fantastic job, Russ, and get it up and hire plenty of American people.

    Thank you.

    MR. GIRLING: Thank you, Mr. President. And this is a very, very important day for us — for our company. So on behalf of thousands of people that have worked very hard to get here — as you’ve pointed out, very long time to get here — but we’re very relieved, and very much just want to get to work.

    Some of those folks I have with me today — the building trades with Sean McGarvey; some of our — construction contractor, Quanta; our pipe suppliers from Welspun. There’s thousands of people that are just ready and itching to get to work. We got a lot of work to do in the field, but as you pointed out, this is the safest and most reliable way to move our products to market. We’re going to use the best technology and be able to create thousands of jobs and important tax revenues in local communities.

    That’s something often that’s overlooked in new projects like this, is local communities benefit greatly from these projects. It gives them tax revenues in which they can invest in schools, hospitals, roads, teachers, nurses — all of those things — build the fabric of communities and make those places better for those folks to live.

    So, again, thank you very much for this opportunity, and we’re not going to let you down, sir.

    THE PRESIDENT: Well, thank you, Russ. And I know the voters appreciate this. Some of them expressed it very, very strongly. The workers definitely appreciate it. The building trades’ heads didn’t, but now maybe they’re going to start to. Where are my building trades guys? I think they’re going to start to, because other people were not going to be signing this bill. That I can tell you. And if it ever did get done, it would be years. But I don’t think it would have ever gotten done.

    So we put a lot of people to work, a lot of great workers to work, and they did appreciate it. And they appreciated it, Russ, very much at the polls, as you probably noticed. And so we’re very happy about it.

    So the bottom line — Keystone finished. They’re going to start construction when?

    MR. GIRLING: Well, we’ve got some work to do in Nebraska to get our permits there —

    THE PRESIDENT: Nebraska.

    MR. GIRLING: — so we’re looking forward to working through that local —

    THE PRESIDENT: I’ll call Nebraska. (Laughter.) You know why? Nebraska has a great governor. They have a great governor.

    MR. GIRLING: We’ve been working there for some time, and I do believe that we’ll get through that process. But obviously have to engage with local landowners, communities. So we’ll be reaching out to those over the coming months to get the other necessary permits that we need, and then we’d look forward to start construction.

    THE PRESIDENT: Okay. I’m sure Nebraska will be good. Peter is a fantastic governor who’s done a great job, and I’ll call him today.

    So thank you all very much. Appreciate it. Thank you.

    10:32 A.M. EDT

    • Boomer II says:

      Why did you post the entire transcript here? Did you assume no one here can look this up for himself?

      • Boomer II says:

        Oh, and what about the part about taxing imported oil? That should please Canada, yes?

      • Bob Frisky says:

        Well, I didn’t see any other discussion here about the President’s actions on the Keystone XL. I just wanted to show the awesome upside now in place for the US energy industry and economy.

        • Boomer II says:

          This is a fairly knowledgeable group of people. They know about the Keystone and what it will or won’t mean.

          “I just wanted to show the awesome upside now in place for the US energy industry and economy.”

          If you want to discuss this in depth, and in relation to the economics of oil, this might be a good place to post. But the boosterism will pretty much go nowhere here.

        • Watcher says:

          This is not a hardcore liberal blog, politically.

          Peak Oil is often sneered at by both sides as a tool of the other side. I’ve seen many hard core liberals scream that talk of oil scarcity is just evil right wingers arranging to get more Gaia raping drilling approved. And right wingers think it’s just an evil anti growth concept intended to generate taxpayer funded swilling at the trough for green this and that.

          Andddd it’s not an investment blog. Lots of money analysis about costs and budgets, but the name of the blog is peakoilbarrel and the money stuff just is a measurement of scarcity impact.

          More than anything else, it’s about geology, though darcies are rarely mentioned.

          • Oldfarmermac says:

            “This is not a hardcore liberal blog, politically.”

            The open threads are pretty much aligned with the overall liberal agenda, because the liberals/ Democrats happen to be right on the environmental issues, and the members of this forum are generally environmentally literate.

            It’s maybe pushing it a little to say it’s all about geology, since politics, technology, and the way the economic cards fall have arguably as important as the geological facts, at least in the short to medium term.

            In the long term, who knows?

            New technology may actually result in our getting away from oil before oil gets away from us.

            Remember the famous guy what’s his name, a Saudi prince as best I can remember.

            He said the stone age did not end for a lack of stone, and that the iron age did not end for lack of iron, and that the oil age will not end due to a lack of oil.

            I am willing to believe he may be right, in the end, but the end of the oil age is still at least fifty years or more down the road in my opinion. There will probably still be a lot of oil burning machinery around even seventy five years from now.

            There’s plenty of oil burning machinery still in use today that is over fifty years old, and a new bulldozer built in 2050 might easily still be in good running order in 2100, if it is well cared for , and only used intermittently, as are most such machines once they get some age on them.

    • Boomer II says:

      The Keystone XL may not make economic sense because Canada has two other pipelines to use. And of course if the Trump administration does start taxing imports, shipping oil from Canada to the US would likely be less attractive than shipping it to the Canadian coast.

      Keystone XL Does Not Make Sense Anymore | OilPrice.com

    • Boomer II says:

      Investment community still skeptical over prospects for Keystone XL | CTV News: “Beyond the political and corporate bravado that greeted the White House’s blessing, analysts took a more cautious view over whether TransCanada’s pipeline would ever get built.”

      • Oldfarmermac says:

        Whether building the Keystone would have made BUSINESS sense, when Obama was in office, or would make sense NOW is a question I can’t answer, because I am not an expert in the oil marketing biz.

        But the D’s fucked up big time, imo, in denying the permit, from the political pov. If anybody wants to know WHY, a one liner here will get my response in the current non petroleum thread.

        • Boomer II says:

          Actually, the real opponents have been Republican farmers in Nebraska who don’t want the pipeline on their property. It’s a property rights thing. And they plan to continue to fight.

          The same thing will happen with the proposed wall. The government will have to force landowners to sell in order to get the necessary land. It won’t go well.

          • Boomer II says:

            'We hate to have to fight again': Nebraska farm couple defiant as Trump acts to advance Keystone XL, Dakota Access pipelines | Nebraska | omaha.com: “If the company tries to use eminent domain to forcibly obtain right of way from Nebraska landowners, a lawsuit would be filed, Kleeb promised.

            ‘It isn’t right for a foreign corporation to use eminent domain for private gain,’ she said. At least 100 Nebraska landowners, Kleeb said, will resist selling right of way.”

          • Oldfarmermac says:

            Nobody in Washington gives a hoot about a few dozen or even a thousand rural landowners. Eminent domain IS a potent political issue though, and both sides have both lost and won in supporting the taking of private property for public or semi public purposes such as roads and power line and pipeline rights of ways.

            But there was little widespread debate centered around eminent domain, or the ownership of the company or companies involved. In recent times, we have gotten used to foreign based companies owning all sorts of assets in this country.

            The debate was all about a line in the sand involving the pollution associated with tar sands oil, and the environmentalists versus the business as usual camp.

            In this case, the business as usual camp had the politically important facts on its side, in respect to winning elections.

            First off, hardly anybody other than true believers actually believed stopping the pipeline would make any real difference, in terms of the Canadian oil tar sands oil industry, other than maybe to slow it down for a while.

            The safety argument was equally silly. The oil could either be moved thru a brand new, state of the art line, or it would continue to be moved in lines near the end of their service life, or on trains.

            D partisans were more than ready to believe in these arguments, or at least pay them lip service, but middle of the road and R leaning voters saw them as bullshit. .

            IF the denial of the pipeline permit HAD stopped this heavy oil from getting to market, the Canadians would most likely have put in some new pipelines, eastward or westward , to get the oil to market, because that’s just TOO MUCH LOOT to be passed up , with everybody clamoring for MORE when it comes to government services.

            When an oil company can make money enough, it will agree to high enough taxes to get the permits it needs.

            Getting the new pipelines built might have taken a long time of course. There was some potent opposition among the Canadians, including some of the First Nations people.

            The Obama administration was quite happy to allow the domestic fracking industry to run wild, because cheap oil is GOOD electoral politics, when you are the incumbent, regardless of party.

            The dog and pony show was all about rallying the environmental camp for the D party, rather than actual environmental considerations.

            I may be wrong, but my conviction as an observer on the ground is that the stalling tactics used, and the eventual denial of the permit, costs the D party a LOT more votes than it gained for the D’s.

            The environmentalist camp is solidly in the D column no matter what.

            The D’s could have forced a bargain whereby the oil industry paid for a few nice large tracts of sensitive land to be added to the nations park system, or something along that line, which would have been a political win for them, AND for the country.

            That would have actually accomplished something useful , rather than contributing to the political backlash that has had so much to do with putting the R’s in , and the D’s out, in DC.

            • Boomer II says:

              This is your interpretation. I know people in Nebraska and this IS about their land. It became an environmental cause, but the farmers raised the issue first.

              • Boomer II says:

                A chronological look at the controversial Keystone XL pipeline project | rdnewsNOW: “July 2008: TransCanada and ConocoPhillips, joint owners of the Keystone Pipeline, propose a major expansion to the network dubbed Keystone XL to carry oilsands bitumen from Alberta to Texas.

                2009: As the U.S. State Department wades through comments based on an environmental assessment of the project, TransCanada starts visiting landowners potentially affected by the pipeline. Opposition emerges in Nebraska.”

              • Oldfarmermac says:

                Hi Boomer,
                Sure it’s my interpretation, within the context of the national political landscape.

                What’s yours?

                Do you think opposition to the Keystone won the D party more votes than it cost them?

                Or did it irritate some normally reliable blue collar D voters to stay home, or even to vote R ?

                How many R inclined voters did the endless dawdling about the permit energize, given that a decision could easily have been reached far more quickly, allowing them a longer cooling off period before they maybe actually voted rather than just staying home?

                I sympathize with the local guys in Nebraska, or anywhere else when the GUV ‘ MINT comes thru and takes some or all of their property.

                The Keystone at the local level is or was no doubt a big loser for the R party in places where the local people were strongly opposed.

                It’s happened to people I know too, and even to some of my family members.

                I have no way of knowing that it would have passed down to me, but if the property lines of the Blue Ridge Parkway had been placed a quarter of a mile from where they actually ARE in one particular spot, somebody in my family would likely be the owner of a few million dollars worth of skyline acres that are now public property. It coulda been me, with a little luck.

                It’s pretty much the way it is that power companies, phone companies, rail roads, and other companies that provide what are considered essential services are legally enabled to take property at least to the extent of establishing right of ways.

                The exceptions mostly just prove the rule.

                • Boomer II says:

                  The Dems stalled as long as possible on Keystone, letting it go back to the courts to be settled. Obama finally weighed in when he wasn’t up for re-election. Approving it would not have won any Republican voters but it would have been an issue with Democratic voters.

                  Voting for Keystone in hopes that Republicans would approve would have been a wrong move for Obama.

                  • Boomer II says:

                    Obama tried to be the compromise politician most of his administration. It didn’t get him much support from the Republicans, so in the end he started passing the more liberal actions he might as well have done all along.

                • Boomer II says:

                  Here’s a bit more background.

                  Despite Trump approval, Keystone pipeline still has hurdles to cross | TheHill: “While Montana and South Dakota have issued approvals for construction of their respective segments of the pipeline, consideration of the Nebraska permit by the Nebraska Public Service Commission has just begun.

                  Along with these state permits, there may be additional local regulatory hurdles for TransCanada, including compliance with local zoning regulations, building permits and permits for use of local roads by construction equipment. In addition, TransCanada may still need to reach deals with a significant number of potentially affected landowners.”

            • Dennis Coyne says:

              Hi OFM,

              You said:

              Nobody in Washington gives a hoot about a few dozen or even a thousand rural landowners.

              Strange that. I had heard that Nebraska has two senators and three representatives in Congress. So perhaps you meant most people in Washington … 🙂

              • Oldfarmermac says:

                Hi Dennis,

                That’s what they call hyperbole on my part, but the fact is that there are ninety eight other senators, and hundreds of representatives, plus the administration itself, regardless of which party is in control.

                Except for the rather small minority of them that owe the oil industry big time, they pretty much all would rather have oil cheap rather than expensive, even the ones with the greenest of green credentials.

                A very small number of them occasionally find it necessary to vote for or against some given project of course, because their own constituents are really hot for or against it.

                How many of them there congress critters have ever seriously proposed raising gasoline taxes significantly??

                Out here in the boonies, we say about things that are more or less accurate to within the ballpark, “that’s close enough for government work”.

                Incumbency rules, except when the voters are unhappy with the economy. Cheap oil equals happier voter.

                • Dennis Coyne says:

                  Hi Old Farmer Mac,

                  There are quite a lot of Senators from rural states that might be persuaded by arguments of eminent domain not being used to help foreign companies.

                  I agree however that not many legislators will be concerned about a few farmers in Nebraska and to be honest I am agnostic on the issue. It is unlikely to keep oil prices low, but some of that oil will be produced an they may as well ship it to the US to be refined, pipelines are a lot safer than trains. Whether it is actually needed is unclear.

                  Many more jobs could be created building wind turbines, solar, EVs, rail, light rail, and HVDC transmission than by building this pipeline imo.

                  • Oldfarmermac says:

                    “Many more jobs could be created building wind turbines, solar, EVs, rail, light rail, and HVDC transmission than by building this pipeline imo.”

                    Totally agree about the renewables industries being worthy of support as employers who hire LOTS of people.

                    I don’t think the pipeline in and of itself matters anymore than one more or one less grain of sand on the beach, there are obviously plenty of pipelines, etc.

                    It’s the political implications of building or not building it that really matter.

                    Personally speaking as an observer of the political scenery, I remain convinced that dragging out the permit process , and then finally denying it, gained the D’s a lot fewer votes than expected by whoever made the decision to play it that way. Virtually all environmentally inclined voters would have voted D anyway.

                    A number of blue collar D’s apparently either just stayed home, or actually voted R because of this issue, given that they took it as being representative of the D party’s overall attitude about their economic problems.

                    I may be the ONLY regular here who pays close attention to the right wing political scene, other than to just make fun of it, and I am dead sure that the Keystone played out as a very big vote winner for the R party.

                    R inclined voters tended to see it as a display of overreaching arrogance on the part of the D party, and evidence that the D’s cared less about hands on working people.

                    It pissed them off, and energized them.

          • Bergen Johnson says:

            “The same thing will happen with the proposed wall.”

            All they need is razor wire on top of the existing fence. If that doesn’t work then have land mines on the US side. Put up a sign that reads; Trespass at your own risk – razor wire and land mines.

            • Boomer II says:

              Yeah, but that doesn’t give us “The Trump Wall.” He likely wants something big and visible, like the Great Wall of China.

  27. Boomer II says:

    This article says what I have been saying. Oil companies are headed the way of coal companies. Some companies may already realize this, but don’t want to say so publicly.

    The Coal Industry Collapsed–Is Oil Next? | Fast Company: “Investors should be asking oil companies for analyses of risk, says Fugere, and then asking how the companies plan to adapt and change over the next five, 10, and 20 years. ‘I think they should be demanding that companies show them that they will be one of the companies that remains standing,’ she says.”

  28. Boomer II says:

    Another U.S. oil company wants Trump to stay in the Paris climate agreement. | New Republic: “Though it may seem surprising that fossil fuel companies would agree to further limits on carbon emissions or leaving oil in the ground—which the agreement would make them do, eventually—they clearly believe it’s in their economic interest to support the agreement. As The Hill notes, ‘The agreement could be extremely beneficial to oil companies, particularly if the countries involved forego coal-fired power and switch to natural gas, which numerous utilities worldwide are doing.’”

  29. Boomer II says:

    The latest from Art Berman.

    Tech Miracle In U.S. Shale Is A Media Myth | OilPrice.com: “Most of the celebration of efficiency and productivity is really about a depression in the oil industry that has resulted in massive price deflation. I estimate that only about 10-12% of the cost reduction is because of technology and most of that was a one-time benefit in the first year or so it was used. Going forward, efficiency gains are a few percent at most.”

    “Technology does not create energy. The effect of better technology is a bigger spigot that produces the energy faster. The downside of the technology is that it increases the rate of resource depletion.”

    • Yes, and Art Berman did an earlier debunk of the Permian Basin story when it first came out (huge energy bonanza, etc.). Wish I had that link now. What popped out of his story was that it would take 1 million horizontal wells, each costing about $6 million minimum, to extract the full resource identified by USGS. In other words, a $6 trillion investment in wells alone.

      I think it was the same story where he used the line: “Sweet: Jed Clampett shootin’ at some food,” which made my day when I read it.

      B.G. in Wisco

      • Boomer II says:

        Here you go. And the Jed Clampett quote is in this article.

        Art Berman Permian Giant Oil Field Would Lose $500 Billion At Today’s Prices – Art Berman: “According to the USGS’ input data, it would take 196,253 wells to produce the 20 billion barrels if it exists. At $7 million per well, that would cost almost $1.4 trillion in drilling and completion costs alone.

        It would cost more than $1.4 trillion to generate $900 billion in revenue resulting in a net loss of $500 billion at $45 oil prices excluding all operating expenses, taxes and royalties–and no discounting.”

        • twocats says:

          don’t worry, I got that on me.

        • Oops, my bad memory. I was off by a factor of 5. But still, that $1.4 trillion is a stack of 1,400,000 million-dollar bills.

          also want to wish,

          Best wishes and hopes for the best to Ron Patterson’s wife, and Ron.



  30. Pete Mason says:

    Glut?? What glut??
    Oil Speculators Can’t Dump Rally Bets Fast Enough Amid Glut
    “… Part of the glut in U.S. stockpiles stems from a surge in imports last month. Arrivals into the country reached the highest level in more than four years in the week ended Feb. 3 as barrels that were pumped before OPEC and its partners made cuts arrived at U.S. ports. These shipments will probably slip in the weeks ahead, according to Thummel.”


  31. Energy News says:

    Goldman Sachs: OPEC Should Not Extend Production Cuts

    We believe that the rebalancing of the oil market is making progress despite the record high US crude inventories with non-crude US inventories and non-US inventories down yoy. Further we forecast that OECD inventories on a days of demand cover will reach their 5-year average level by year-end even with OPEC bringing production back online in 2H17. While the shale production rebound has surprised to the upside, it will be offset in our view by the high compliance to the production cuts through 1H17 and most importantly, strong demand levels. The OECD stock draws we project would be further accelerated – as was the case through 4Q16 – if the recent strength in survey activity indicators, pointing to 4% yoy global GDP growth, translates into stronger oil demand growth than our above consensus 1.5 mb/d forecast. This demand pull is important in our view as the supply response to only slightly higher oil prices has been faster and larger than expected.

    However, oil prices above $60/bbl would prove self defeating in our view given the flattening of the oil cost curve and the unprecedented velocity of the shale supply response.

    The central bank-inspired hunt for yield drives investors down the quality ladder, creating artificial demand for HY debt and equity follow-ons. This relentless appetite for anything that offers investors some semblance of yield allowed otherwise insolvent US production to remain online as operators tapped capital markets to plug funding gaps.
    Full text with charts, here:

  32. Dennis Coyne says:

    Hi all,

    Ron Patterson’s wife’s health has taken a turn for the worse. She was in the hospital for 6 days with congestive heart failure and came home on Wednesday and is on hospice care. Ron expects she has from days to weeks left and does not think he will be posting much.

  33. Boomer II says:

    Global Oil Demand Growth Will Slow Significantly In 2017 | Seeking Alpha: “The strong dollar will significantly impact oil demand and the current consensus for oil demand growth is still too high. We expect oil demand to grow by 1mmbd instead of the expected 1.4mmbd by the IEA. Countries like India and China won’t match the 2016 expectations due to higher retail prices, currency demonetization and pollution concerns.”

  34. Boomer II says:

    Oil's Paradigm Shift Has Tapered A Bit | Seeking Alpha: “In addition to negative results from US output, we can also see that motor gasoline demand remains weak. Based on the data provided, demand came out to 9.20 million barrels per day, a decrease compared to the 9.503 million barrels per day seen the same time last year. The four-week average figure for demand is down 2.9% year-over-year, falling from 9.373 million barrels per day to 9.102 million barrels per day.”

  35. George Kaplan says:

    Mexico slightly raised total liquids last month because of combined condensate and NGL increase, but C&C continued to decline, albeit less steeply. It looks increasingly likely that KMZ is off plateau and it’s decline will now start to accelerate. Decline rates shown are y-o-y.

  36. Dennis Coyne says:

    Hi all,

    I was checking breakeven prices for Bakken($67/b) vs Permian($66/b) and found an error in the discounted cash flow sheet for the Bakken. This error caused too high an output for the ND Bakke/Three Forks scenarios as I only spotted the mistake today. For the “medium oil price” scenario for the ND Bakken/Three Forks we get the scenario shown below.

    My apologies, about 2 Gb lower URR and the peak is about 300 kb/d less than in the original post for the medium oil price scenario.

    • Dennis Coyne says:

      The chart below shows the corrected medium oil price case for US LTO (dashed line) compared with the original scenarios in the post, I have not yet run the corrected cases for the low and high oil price scenarios, but I have rechecked the analyses for all 4 areas (Bakken, Eagle Ford, Permian, and other) and the DCF sheet was only incorrect for the Bakken which has now been corrected.

      • Dennis Coyne says:

        As a sanity check I used the spreadsheets to find breakeven oil prices for all four areas.

        For the Eagle Ford it is $70/b (2016 $) with an assumed $6 million well completion cost (drilling plus fracking from spud to producing well). For US other LTO there was also a mistake in the DCF sheet which has now been corrected, at an assumed $2.7 million completion cost (2016$) the breakeven is $73/b (2016$). For the Permian the break even oil price is $65.50/b (2016$), and for the Bakken the breakeven oil price is $67/b.

        So the scenario for US “other” LTO needs to be redone.

      • Dennis Coyne says:

        Correction 2,

        ERR=39 Gb, medium oil price scenario corrected for errors in Discounted cash flow analysis for Bakken and Other LTO. Well cost increased for “other LTO” to $2.7 million (used also for breakeven calculation) also royalties plus taxes raised to 30% for other LTO and 32% for Permian and Eagle Ford for breakeven calculation and medium oil price scenario.

        These changes in royalties and taxes were suggested by shallow sand and Mike and based on that input I also raised royalties and taxes for other LTO. I also incorporated Ron Patterson’s suggestion that Lynn Helms does not expect North Dakota oil output to rise above 1000 kb/d until the 4th quarter of 2018 so the ramp up of the Bakken/Three Forks is slower. All of these changes taken together result in a lower peak and a longer plateau in output, though it is impossible to predict with precision how quickly new wells will be added. In general, the area under the curve (URR) will not change by much given the assumptions of the model (both well profiles and economic assumptions), a higher peak would result in a shorter plateau and steeper decline.

        The corrected medium scenario is the dashed line in the chart below.

        • Yaman Tasdivar says:

          Dennis – I just saw these updates. It may make sense to put a warning at the top of the article for updated graphs in the comments – or a new article.

          Bakken now makes relatively more sense, although I still think it is optimistic. I don’t see it going above 1.0 mbd again, due to the low number of wells yet to be drilled in sweet spots, and the subsequent fall-off in initial production when rigs move from core to non-core areas.

          Thank you for the follow-up.

          • Dennis Coyne says:

            Hi Yaman,

            Thank you for your contributions as it helped me to catch some mistakes I had made in the DCF analysis. As I have suggested the Bakken scenario is quite conservative relative to what the NDIC thinks will happen, especially the updated scenario in the recent comment (3/28/2017 at 1:12 PM). There may be more oil in the ND Bakken/TF than you believe. The proved reserves on Dec 2015 were about 4.7 Gb in the ND Bakken/TF (I subtract 2015 from 2008 reserves to arrive at this estimate and assume 99% of the proved reserve increase since 2008 has been from Bakken/TF reserves.) See link below


            We need to add cumulative production through Dec 2015 from the ND Bakken/TF (1.6 Gb) to get a resource estimate of 1.6+4.7=6.3 Gb. This assumes there are no “probable” reserves (those with a probability of being extracted of less than 95%, but more than a 50% probability) or where probable reserves=2P reserves minus proved reserves. Typically these are not equal to zero so this is a very conservative assumption. My medium oil price scenario has Economically Recoverable Resources (ERR) at 6.8 Gb. For reference UK North sea probable reserves are about 0.63 Gb for every 1 Gb of proved reserves, possibly it will be much less for the Bakken, in my scenario it is 0.1 Gb of probable reserves for each Gb of proved so over 6 times less than the UK North sea, perhaps it is zero, but I doubt it.

            I tried to get Fernando to weigh in because sometimes he is willing to climb out on a limb, but not in this case. We just do not know what the level of probable reserves will be. George Kaplan has suggested it will be much less than conventional reserves, I agree (and he knows much more than me). He has not really suggested how much less they will be, but zero seems to be an extreme estimate, maybe he would agree with a factor of 6 less than the average conventional reservoir for the 2P to 1P ratio of an LTO play?

            • Yaman Tasdivar says:

              Dennis – I think we come at this from different perspectives, but it’s good to know we are mostly aligned. In short, I come at it from a pure finance/economics/accounting/game theory perspective and I like to keep things very simple:

              Given that no shale company has shown a cent of net income even when prices were $100+ oil, and that vast majority of lower well breakevens are due to service company discounts which have started to reverse in a major way, oil prices cannot stay low for much longer.

              I would love to have the time to learn from you regarding EURs, but for now, I will have to rely on the quality work that you put up here. It is clear to me that you know what you’re talking about when it comes to modeling these basins out and have incorporated all available information. I will continue to follow your blog and chime in where I can.

        • Dennis Coyne says:

          In the corrected model above, about 20 Gb is from the Permian Basin, 7 Gb from ND Bakken/TF, 6 Gb from Eagle Ford, and 6 Gb from other US LTO (includes vertical wells from the Permian, Montana Bakken/TF, Niobrara/DJ, and other smaller LTO plays in the US).

          Peak US LTO output is 5200 kb/d from July 2022 to March 2024 (5195 to 5205 kb/d over this period) with a longer plateau (with output above 5100 kb/d) from July 2021 to June 2025.

          Chart below shows output from the various plays on the same chart, all of the increased output is from the Permian basin where output from horizontal wells (about 350 kb/d is from vertical wells in Dec 2016) increases from 1250 kb/d to 2900 kb/d by 2027 (2750 kb/d is reached in Nov 2024). This increase of 1650 kb/d is offset by declines in the ND Bakken/TF, Eagle ford and other LTO after Nov 2022, at the peak, Permian output has increased by 1216 kb/d since Dec 2016 while the rest of US LTO has declined by 138 kb/d in this scenario.

          Bottom line, increases in US LTO are all about the Permian basin.

  37. Boomer II says:

    The title of this article is misleading. It’s actually about how demand has fallen short of predictions. There are some good graphs comparing predicted demand to actual demand.

    There Is No Such Thing As Peak Oil Demand | OilPrice.com: “Sequential global demand forecasts over the last decade have projected slower growth, mostly now forecast at less than 1 percent, and sensitivity cases now allow for the possibility of substantial demand decline by 2040. Unfortunately, experience demonstrates that the crest will likely occur unexpectedly and sooner than predicted. And then our industry enters a whole new world as the moving balance of supply and demand turns into a race to the bottom.”

    • Eulenspiegel says:

      I think it can be a period with high oil prices.

      Sure, shale oil can expand, but who sinks all these 10s of billions of dollars into deep sea drilling then, which brings now lots of oil, but pays out only after many years.
      With a falling demand, this lead to more infill drilling old fields and fracking, everything that is fast and not too much investment.

      And when the big old conventional fields mature too fast, while deep sea declines fast, this can be a bumpy road even with falling demand. I know many oil analyst think Permian will replace OPEC and other oil countries with 20$ oil soon, but I’m not that optimistic 😉 .

      • Dennis Coyne says:

        Hi Eulenspiegel,

        I agree, the Permian needs $66/b to break even and there is at most 36 Gb (F95 resources) which is a drop in the bucket at the World level. Optimists like to throw out numbers like 75 Gb of oil equivalent, but about 25 Gb of that oil equivalent is natural gas, for crude plus condensate about 30 Gb have already been produced, leaving about 20 to 25 Gb of oil left to be produced which matches with the USGS best estimates.

        They have been producing oil in this region since at least 1930 so there are not a lot of new discoveries that are likely, we know what is there, it is expensive to produce what is left.

        • Yaman Tasdivar says:

          Thank you for the explanation Dennis.

          Do you have any info on what percent of core areas have been drilled in the Permian? The quick increase in rigs, longer laterals, more sand/water, more fracking stages, must have quickened the depletion of oil in core areas. But we need to find a way to turn this hypothesis into data to be used in modeling.

          Essentially, the question I’m trying to answer is: when does Permian turn into Bakken?

          • Dennis Coyne says:

            Hi Yaman,

            The Permian is more complicated as there are several plays within the play. My understanding is that the Wolfcamp is where most of the potential is, the USGS has undiscovered technically recoverable resources (UTRR) at a median of 19 Gb (F50) and F95 is 10 Gb and F5 is 30 Gb for the Wolfcamp. The EIA estimates about 0.8 Gb of proved reserves and about 0.6 G of cumulative production from the Wolfcamp so the median estimate would be 21.4 Gb.

            David Hughes has some estimates for the other plays in the Permian such as the Spraberry and Bone Spring


            Unfortunately my Permian basin scenarios are highly speculative. They are based on production and number of wells completed to date, with an estimate that the average well profile from Jan 2015 to May 2018 will be about 290 kb. It is possible that the well profile will increase marginally over this period as was the case from 2012 to 2015 in the ND Bakken/TF, I have guessed that the well profile will begin to decrease in Jun 2018, but note that From 2008 to 2016 there was no decrease in ND Bakken/TF well profiles. The drilling of horizontal fracked wells didn’t start to ramp up until 2012 in the Permian so it might not be until 2019 or 2020 before core areas become saturated with wells. Note that despite speculation by many that the core areas of the Bakken are saturated, so far the average well profile has not reflected this, so it is even possible that the Permian might not have core areas fully drilled until 2022, this will depend in part on how quickly the wells are completed. In any case the rate of decrease in new well EUR is assumed to result in about 23 Gb from the entire Permian basin in my model, it is possible that other plays within the Permian basin (so far not assessed by the USGS) might contribute another 5 to 7 Gb, though we do not really know. Despite many believing that my scenarios are too optimistic, they may in fact be on the pessimistic side. Note that the EIA’s AEO 2017 reference case for US LTO has cumulative output of 82 Gb from 2005 to 2050, roughly double my medium oil price scenario.

            Looking closely at USGS assessment, much of the Wolfcamp will have lower productivity wells which may never be worth drilling, the better areas with average EUR of around 167 kb only total about 13 Gb Wolfcamp A and B (upper and lower), the Wolfcamp D has a mean EUR of 126 kb (I think this is too low to be economic), if this is included, the mean UTRR increases to 18 Gb, the median UTRR is 17 Gb (F50) for Wolfcamp A, B and D. The other zones have EURs per well of 64 kb and 83 kb which are unlikely to be economically recoverable, a reasonable ERR might be 15-16 Gb. The maximum EUR estimated by the USGS is 250 kb for the Wolfcamp D and 300 kb for the Wolfcamp A and B, my model uses an EUR of about 290 kb so it may be too optimistic. Using these higher EURs the USGS gets 27.6 Gb for the Wolfcamp A, B and D, but that assumes no decline in average new well EUR. The median estimate of 17 Gb seems a reasonable guess for UTRR and roughly 18 Gb for TRR with ERR somewhat less.

            USGS paper at link below


  38. George Kaplan says:

    Both OceanRig and Westinghouse declaring bankruptcy (over $13 billion debts combined). OceanRig have a big proportion of the latest generation ultra deep drill ships.

    • Eulenspiegel says:

      OceanRig will recapitalice – and the beat goes on:

      So, loosing money is no reason in oil business not to continue as usual. It’s no problem to get new money, just a formality.
      That seems to be the cause of drilling frency while losing money, too. Enough dump investors.

      • George Kaplan says:

        They might keep going, but they still aren’t going to find enough customers to pay the day rates they need to break even in the current climate. All the IOCs have pulled back from ultra deep wells, there might be few attractive areas left even if the oil price does increase – I think over $100 might be needed even for a few wildcats.

  39. Jeff says:

    IEA Oil market report for March is now available to public, see https://www.iea.org/oilmarketreport/reports/2017/0317/.

    Inventory build in January (+48 mb crude and +6.3 products). Crude inventories are expected to be almost flat in February (-5 mb), products are expected to be down a lot (-23.3 mb) and refinery runs are expected to surge in 2Q2017.
    Remember that inventory build in January (and most of Feb too) comes from oil produced in late 2016 when OPEC was pumping flat out.

    Crude inventories in short: OECD inventories “rose for the first time in six months by a sizeable 48 mb (or 1.5 mb/d) to reach 3 030 mb at end-January” and “Preliminary data show a modest draw of 5 mb in February despite further builds in US crude”.

    Considering product inventories: “Oil product stocks grew more moderately by 6.3 mb to 1 504 mb. A seasonal pickup in demand for LPG and steady US propane exports to Asia helped offset builds in diesel and gasoline. Overall OECD stocks remained 302 mb above the five-year average at the end of January.”
    “Meanwhile, oil products likely drew by a significant 23.3 mb in February with ongoing exports of propane from the US to Asia as well as lower refinery runs in some regions. Gasoline, middle distillates and fuel oil inventories were all likely to have drawn in February.”

    …and refinery:
    “Global refinery crude throughput rose 860 kb/d year-on-year (y-o-y) in 4Q16 to 79.5 mb/d, only 280 kb/d lower than in 3Q16. Following gains of 1.6 mb/d in 2015, runs increased 440 kb/d last year. This is well below the observed demand growth in 2016 of 1.6 mb/d.”
    “Refinery throughput growth recovered to 0.9 mb/d y-o-y in 4Q16, but will slow down to a 0.6 mb/d increase in 1Q17, before surging by 1.9 mb/d in 2Q17. This reflects a recovery from 2Q16’s unusually low levels, with implied refined product stock drawdowns supporting higher throughput.”

  40. Energy News says:

    EIA – This Week in Petroleum – March 29, 2017
    U.S. oil producers issued record equity in 2016 and increased investment in the final quarter

    A group of 44 U.S. onshore-focused oil producers issued a record amount of equity in 2016, $15.8 billion.

    In the fourth quarter of 2016, capital expenditure for these companies was $4.9 billion (72%) higher than in the fourth quarter of 2015.

    Despite the increase in crude oil prices, cash from operations declined $475 million year-over-year in the fourth quarter of 2016 (Figure 2).

  41. Boomer II says:

    I think this has enough to do with petroleum that I am putting it here rather in the non-petroleum thread.

    By the numbers, Trump’s big environmental regulation rollback is all kinds of unpopular – The Washington Post

    • clueless says:


  42. Boomer II says:

    Oil executive warns of overproduction | News OK: “Producers repeatedly have said operating costs have tumbled over the past two years as companies have improved technology and processes around both drilling and completing wells.

    Ruscev dismissed those claims.

    ‘Technology has not changed in the last two years,’ he said. ‘We just went faster for drilling and bigger for fracking. We have not introduced any new technology.’

    Well costs have dropped because service companies like Weatherford have absorbed steep price cuts that have required them to lay off 30 percent to 50 percent of their employees, Ruscev said.”

  43. Dennis Coyne says:

    New post up at link below


    also a new Open Thread Non-Petroleum at link below


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