North Dakota Bakken/Three Forks Update

The North Dakota Industrial Commission (NDIC) reported June crude plus condensate (C+C) output on August 12, 2016. North Dakota(ND) Bakken/Three Forks (BTF) output fell by 20.46 kb/d in June to 973.86 kb/d. Overall ND C+C output fell to 1026.58 kb/d in June, a decrease of 185.2 kb/d in the past 12 months. Based on data from Enno Peters, 43 new wells started producing oil in June 2016.

I pulled the charts below from (Enno Peter’s website).


The chart above shows the number of new wells that started producing each month in North Dakota.  The chart that follows shows the number of wells in North Dakota that started the drilling process each month.



The number of drilled uncompleted (DUC) wells (chart above) has not changed very much since 2014 and the latest estimate is about 924 DUCs in the ND Bakken/TF. At some point these wells might be completed if oil prices rise above $70/b, whether that ever occurs is unknown, my guess is that oil prices are likely to be above $70/b within about 12 months (by August 2017).

My simple Bakken model using estimated future well profiles consistent with the average 2014-2015 well and with cumulative output of about 300 kb over 20 years (similar to the 2008-2013 average well) underestimates actual ND Bakken/TF output from Oct 2015 to June 2016 by an average of 56 kb/d over that 9 month span. In June the model predicts 920 kb/d, about 55 kb/d too low, but at some point sweet spots will become fully drilled, new well estimated ultimate recovery (EUR) will decrease, and the model may match actual output more closely when that occurs.

I present three scenarios that assume the well profile will not change, the low scenario assumes 43 new wells per month are added from July 2016 until Dec 2018, the high scenario assumes 125 new wells per month are added each month from July 2016 to Dec 2018, and a medium scenario with 85 new wells per month added from July 2016 to Dec 2018. Depending upon oil prices my expectation is that ND Bakken/TF C+C output will fall somewhere between the high and low scenarios, the “medium scenario” is not a best guess, but simply an intermediate scenario.


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220 Responses to North Dakota Bakken/Three Forks Update

  1. SRSrocco says:

    Dennis… while I appreciate your three scenarios, I still believe Jean Laherrere and Tad Patzeks forecast of a collapse of the Bakken back to 2007 levels by 2025…. if not sooner.


    • Dennis Coyne says:

      Hi Steve,

      The scenarios presented only show output to 2018, in 7 years output could fall,

      I think David Hughes estimate is better, about 6.8 Gb by 2040 and maybe 700 kb/d in 2025, with about 32,000 total wells drilled. Time will tell.

    • Dennis Coyne says:

      Some excerpts from Drilling Deeper (page 62):

      3. Peak production is highly likely to occur in the 2015 to 2017 timeframe and will occur at between
      1.15 and 1.77 MMbbl/d. The most likely peak is between 1.15 and 1.22 MMbbl/d in the 2015 to
      2016 timeframe. …

      5. The projected recovery of 6.8 billion barrels by 2040 in the “Most Likely Rate” scenario (2,000
      wells/year declining to 1,000 wells/year) of the “Realistic” case (80% of play drillable, at 3 wells per
      square mile), agrees fairly well with the mean estimate of latest USGS assessment of the Bakken
      (including the Three Forks) of 7.4 billion barrels.

      Note that Hughes makes an error here (one that I made myself initially). The 2013 USGS Bakken mean estimate is undiscovered technically recoverable resources of 7.4 billion barrels of oil.

      In December 2012, the proved reserves for ND Bakken/Three Forks were 3.28 Gb, and cumulative output was 0.57 Gb. See link below for proved reserves where I assume reserves added from 2007 to 2012 are from the Bakken/TF in ND.

      When all of these are added (7.4+3.28+0.57) we have 11 billion barrels for the USGS mean estimate in April 2013 for the US Bakken/TF. For the North Dakota Bakken/Three Forks (78.5% of undiscovered resources) the mean estimate was 9.7 billion barrels of oil.

      Hughes summarizes his “realistic” scenario as follows on page 60 of Drilling Deeper:

      The drilling rate scenarios in this case have the following results:
      1. MOST LIKELY RATE scenario: Peak production occurs in 2015 at 1.19 MMbbl/d. Drilling continues until 2030, and total oil recovery by 2040 is 6.8 billion barrels.
      2. EXPANDED RATE scenario: Peak production occurs in 2016 at 1.41 MMbbl/d. Drilling continues until 2026, and total oil recovery by 2040 is 7.1 billion barrels.
      3. FASTEST RATE scenario: Peak production occurs in 2016 at 1.72 MMbbl/d. Drilling continues until 2021, and total oil recovery by 2040 is 7.6 billion barrels. In this scenario, production would be
      considerably lower after 2024 than in the “Most Likely Rate” scenario.

      Caption for chart below (also from page 60 of the report):

      Figure 2-26. Three drilling rate scenarios of Bakken tight oil production, in the “Realistic
      Case” (80% of the remaining play area is drillable at three wells per square mile).
      “Most Likely Rate” scenario: drilling continues at 2,000 wells/year, declining to 1,000 wells/year;
      “Expanded Rate” scenario: drilling increases to 2,500 wells/year, declining to 1,500 wells/year;
      “Fastest Rate” scenario: drilling increases to 3,000 wells/year, holding constant.

      • Tom says:


        Thanks for sharing your analyses and this interestring analysis from David Hughes. Does this mean you have changed your mind about Bakken production? It seems like you earlier thought that Bakken could reach higher production levels while it now looks like you think that the production is at (or close to) peak level.

        Is David Hughes’ “Most likely rate Scenario” in line with your analysis?


        • Dennis Coyne says:

          Hi Tom,

          It is difficult to know what will happen in the future. A lot will depend on future oil prices which are unknown. I specifically chose a “maximum” number of new wells per month of 125 per month in my “high” scenario.

          This assumes oil prices remain under $85/b until 2019. Higher oil prices could result in higher rates of new well completion, in the past the rate has been 150 new wells per month or higher for several years (2012 to 2015). Note that I suggest that Hughes mistakenly stated that the mean USGS resource estimate was 7.4 Gb, the correct interpretation is about 11 Gb for Montana and North Dakota Bakken/Three Forks and about 9.5 Gb for North Dakota only.

          I would consider David Hughes “most likely” scenario as a minimum estimate for URR, potentially a higher peak might be reached in the future, but no more than 1.3 Mb/d is likely and overall URR will be less than 10 Gb. If there is a secondary peak around 1100 kb/d, it is likely to be in 2022+/-2 years.

        • Verwimp says:

          Hi Tom,

          That scenario is ‘in line’ with my analysis insofar the elevation and the timing of the peak are concerned. Our views differ strongly on the post-peak side of the curve. Hughes has a downslope much less steep than the upslope, while my analysis is a symmetrical curve (It’s a slightly modified Hubbert curve).
          Today the dataset still behaves like a Hubbert curve, taking the seasonal variations in account nicely. (That means we are now on a post peak summer plateau. Please buckle up for the huge slide starting approximately november 2016.)
          If everything goes well, you can see the difference between the dataset and my analysis here. Left hand scale is – obviously – not zero based. This is ‘zoomed in’ on the top op the modified (seasonally adjusted) Hubbert curve, and on the peak of the data. The period taken into account here is the period from when I made my analysis up till now (latest available datapoint).

          Best regards, Bruno.

          • Tom says:


            It’s very impressive how well your model corresponds to reality (so far). What is the secret behind the seasonal variations?

            • Verwimp says:

              Well, just the fact North Dakota has severe winters. That slows down, apparently, some aspects of the oil industry. Others here will be better in telling you what exactly happens in ND’s winters. I just found the seasonal variations in the dataset prior to december 2013. So I modelled it (a sinus, frequency 1 year obviously, amplitude variable (proportional to the oil output), phase shifted untill as correct as possible), and added it to the Hubbert curve. Notice a rather large discrepancy between the data and the model from december 2013 untill march 2014. North Dakota was suffering ‘Polar vortex Conditions’. It was easy for me to predict a winter, but it was impossible to predict a polar vortex! That was a very severe winter, resulting in lower than expected oil output.

            • Verwimp says:

              I kindly invite you to read this comment.

              Here you read a lot of background and discussion about my model.

  2. Chart Monkey says:

    Bloombergs interpretation of the IEAs figures…

    OPEC Could Still Tip Next Year’s Oil Deficit Into Surplus – Grant Smith – August 15, 2016
    The re-balancing of oversupplied oil markets is on track as demand climbs and U.S. shale production falters, according to the International Energy Agency.

    The world will face a 560,000 barrel-a-day supply deficit in 2017 if OPEC members pump at the same rate as this year, IEA data show.

    If Iran and Iraq add just some of the new capacity they’re planning, Libya recoups a fraction of the supplies lost to political conflict and Nigeria restarts oil fields halted by militant attacks, there’ll be an 810,000 barrel-a-day excess — a fourth year of oversupply.

    • George Kaplan says:

      It might depend on Kashagan restart as well. There have been some reports that they are ahead of schedule and will be able to get towards 350,000 bpd rather than 180,000 bpd originally planned. The first phase is to replace the corroded pipelines but the second phase is, I think, to add some compression and additional facilities that would increase capacity overall, and was originally planned for 2019.

      If everything comes on line, Venezuela doesn’t fall too far and other unplanned outages aren’t too high we might beat the 2015 peak next year (but only just and maybe for not long).

    • Daniel says:

      Wow. This seems slightly simplisitc…natural decline, lack of investment, collapse of venezuela, signifocant inventory draws in nigeria and ksa dont seem to matter.

      • Chart Monkey says:

        Yes these news articles often don’t go into detail about their assumptions.
        I don’t know which factor will win out. Low oil prices and low revenues so lower capex vs low interest rates and loans from China plus long term projects still being completed.

        The Permian is still attracting investors money…

        August 15, 2016 04:11 PM Eastern Daylight Time
        MIDLAND, Texas–(BUSINESS WIRE)–Concho Resources Inc. (NYSE: CXO) (the “Company”) today announced the launch of an underwritten public offering of 9,000,000 shares of common stock. The underwriters will have an option to purchase up to an additional 1,350,000 shares of common stock from the Company.

        Aug 15- Concho Resources Inc said on Monday it would acquire about 40000 net acres in the core of Midland Basin in Texas for about $1.63 billion.

        The EIA is still forecasting increasing production per rig. In their Drilling Productivity Report – 2016/08/15th.
        The Permain is the miracle that keeps on giving.

        I guess that I should include an explanation for the adjusted rig count
        The adjusted rig count on the chart is the rig count weighted for the increase in production per rig. It’s as if production per rig stayed constant from November 2014. In other words, how many rigs would it take to produce the same amount of new oil production without the increase in production per rig.

        And horizontal rigs…

  3. SRSrocco says:

    How a GOOD PEAK OIL website dies….

    Ron Paterson is no longer is a part of it


    • JN2 says:

      Steve, I can imagine Dennis wanting to quit with comments like yours! Is that what you want?

      • Dennis Coyne says:

        Hi Steve,

        Ron has told me he is finished. I would love for him to post and/or comment, but I believe he needs to attend to his wife’s failing health and does not have the time.

        • shallow sand says:

          Dennis. Sorry to hear that. Thoughts are with Ron and his wife.

        • Javier says:

          I am sorry too, and send my best wishes to Ron and his wife. He has given a lot to the oil interested community and we should be thankful. I hope we can continue hearing from him from time to time.

        • Lee Gardner says:

          Dennis, thank you very much for your contributions and much gratitude to Ron for this site. Best wishes to Ron, his wife and the support they have.

        • Jonathan Madden says:

          My best wishes to Ron.

          Thanks, Dennis, for your sterling efforts here.

        • Nick G says:

          Yes, my best wishes to Ron – Alzheimer’s is very, very tough.

          Dennis, you’re doing a great job.

        • Dave P says:

          Hey Dennis will you keep Ron’s spreadsheets and production graphs up to date? They’re one of the most interesting pieces of data.

          By the way, I appreciate your work! Thanks.

    • SatansBestFriend says:


      Dennis does a great job and IMO offers a fresh perspective on the peak oil narrative.

      We are overloaded with doomers and cornucopians. Having a balanced view is needed.

      I have learned a lot from Dennis and I appreciate it.

      • Watcher says:


        Dennis has a balanced view? What blog are you reading?

        • Watcher says:

          Sashay on over to search and find the balanced price predictions.

        • SatansBestFriend says:

          Perhaps I should have said in the middle, unlike watchers ideas which not many on this site agree with.

          Hey watcher, if money is meaningless and imaginary can u deposit you’re money in my account.

          After all it is just an abstract concept.

    • Verwimp says:

      Hi Steve,

      While I agree with your point of view Bakken might decline more sharply than Dennis’ three projections, I would like to add two things:
      – I really appreciate Dennis’ projections. Basically they say: “Current rate of new wells/mth (43) will lead to this decline… To get back to where we were within a reasonable timeframe 125 wells/mth are needed. To stay where we are now we need 85 new wells/mth. That is interesting, especially because Dennis takes the effort to calculate these scenario’s once in a while and the numbers are changing.
      – I expressed my concern about POB too, a couple of days ago. Apart from all my respect for Rons efforts, for Rons current situation and for Dennis’ attempts to keep things running, I would like to express why POB kept attracting my attention since its conception post Oil Drum. POB used to be a kind of Portal site where every available dataset was kept up to date, and was presented the day new data came up. Very often Ron didn’t add a lot of text to it. Just graphs and a short sentence about where things were going. So just facts basically. From EIA, from IEA, from OPEC, from Bakken, from TRRC, … given these data, the public (you and I and many others) had an incentive to go ‘wild’ on everything, often resulting in very interesting conversations. When the data don’t come in as quickly as before, the quality of the discussions is lower too (that’s what I feel.) I would like POB to stay afloat! We might suggest to help Dennis collecting data, to help Dennis write articles, … I offer hereby my services to present Bakken data every month. I hope others follow, if Dennis appreciates this of course.

      Best regards,


      • Dennis Coyne says:

        Hi Bruno,

        I would welcome your help and any other help others would like to give.

        Just email the post to me next time Bakken data comes out.

    • Survivalist says:

      I like the scenarios and data that Dennis posts. While no scenario is likely to be an accurate representation of the future it does give a rough indication. I like the optimistic vs pessimistic scenarios as the future reality will likely be somewhere between. I find it interesting and helpful.

      • Richard Dawkins says:

        I think it’s important to realize that when two opposite points of view are expressed with equal intensity, the truth does not necessarily lie exactly halfway between them. It is possible for one side to be simply wrong.

        • Dennis Coyne says:

          Hi Richard

          I agree. We do not know the answer in many cases. The truth is likely to be between high and low estimates. The medium scenarios are just in the middle, probability is unknown.

          • Richard Dawkins says:

            If something is true, no amount of wishful thinking will change it.

            We frequently look into the future of mankind and see dangers. We see if we carry on doing what we are doing in 20 years’ time there will be no rainforests left, just to use one example. Looking into the future may be one of the reasons that brains evolved in the first place.

            By all means let’s be open-minded, but not so open-minded that our brains drop out.

            • Dennis Coyne says:

              Hi Richard,

              I agree if something is true, there is not much room for discussion.

              The interesting discussions are about those things that we are not sure about, things such as how much fossil fuel will be produced and how fast we can transition to alternatives.

              You might think the answer to these questions are known with some precision, I do not think that to be true.

              • Richard Dawkins says:

                I am not an enthusiast for diversity of opinion where factual matters are concerned.

                Survival machines that can simulate the future are one jump ahead of survival machines who can only learn on the basis of overt trial and error. The trouble with overt trial is that it takes time and energy. The trouble with overt error is that it is often fatal. Simulation is both safer and faster. The evolution of the capacity to simulate seems to have culminated in subjective consciousness.

                Evolution has no long-term goal. There is no long-distance target, no final perfection to serve as a criterion for selection, although human vanity cherishes the absurd notion that our species is the final goal of evolution.

                Nature is not cruel, only pitilessly indifferent. This is one of the hardest lessons for humans to learn.

                I am one of those scientists who feels that it is no longer enough just to get on and do science. We have to devote a significant proportion of our time and resources to defending it from deliberate attack from organized ignorance.

                • Paul Isaacs says:

                  “Evolution has no long term goal”.

                  Agreed. But everything in the universe, including evolution, must be a consequence of the laws of physics.

                  Adding energy to a system that is capable of storing some of the energy by moving to a state of higher embedded energy will, at random, cause the system to move to a state of higher embedded energy.

                  Evolution is the semi-organized process of life forms responding to the energy from the sun. The energy is stored in an increasingly complex biomass on the earth that moves towards maximizing the embedded energy of the planet. Evolution is the process of decreasing the planet’s entropy in response to the sun’s energy.

                  Similarly oil is an increase of embedded energy in subducted organic matter in response to the geothermal energy of the earth. The oil molecules store increasing amounts of embedded energy. They reduce entropy by increasing their complexity and becoming more highly organized.

                  Oil contains more geothermal energy than solar. The burning of fossil fuels has probably been one of the largest injections of entropy into the environment that the planet has ever experienced. The resulting decrease in organization is placing stress on the high level of organization sought by evolution and the planet’s biosphere by rapidly moving the environmental set-point.

                  Relative to the natural infrastructure, human infrastructure is vastly less complex. Energy is required to maintain the reduction in complexity ( increase in entropy ). That energy has been mostly provided by fossil fuels. Those days are coming to an end and evolution will inevitably begin to decrease entropy and increase embedded energy following the ineluctable laws of physics. Evolution will commence the day-by-day processing wearing down and degrading the oil age infrastructure in order to replace it with a more complex and lower entropy biological infrastructure.

                  • Richard Dawkins says:

                    I’m not clever enough to be a physicist.

                  • Nick G says:

                    Oil contains more geothermal energy than solar.

                    That’s highly unrealistic.

                    The total cumulative stored energy in oil is probably about 3 weeks of solar insolation. The total annual release of energy by human burning of fossil fuels is maybe…an hour of sunshine.

                    The sun dumps 100,000 terawatts of continuous very high quality energy onto the earth. Humans only release about 10-20 terawatts. There’s no comparison.

  4. Watcher says:

    Repasting from late in last thread, because this matter decides global widespread death timing:

    Doug Leighton says:
    08/14/2016 AT 1:48 PM
    Hi George,

    I’m certainly no expert but did spend about seven years in the China/Russia oil patch (mostly assessing reserves for Western companies) and consider the following piece a pretty fair assessment. The Dejing oil field is hooped (in terminal decline).

    Watcher says:
    08/15/2016 AT 2:15 AM
    Doug, buried in there is the only sentence that matters — the one about ductile shale layers that are too pliable to fracture — and we discussed this about the Bazhenov in the same context.

    This guy says you get bendable shale vs fracturable shale if the rock derives from ancient lakes instead of ancient ocean. Heard of this?

    The geology truly is the final arbiter.
    Doug Leighton says:
    08/15/2016 AT 8:42 AM
    “Heard of this?” Yes and I agree. Just got tired of repeating it because nobody, apart from you, seemed to listen (or care).
    Watcher says:
    08/15/2016 AT 9:53 AM
    I mean . . . is that the cause of bendable rock? The water was not salty so the rock is non frackable? That’s the mechanism for shale there being non frackable (and thus any oil or gas being inaccessible)?
    Doug Leighton says:
    08/15/2016 AT 10:25 AM
    No, it’s mainly due to the fact many Chinese (and Russian) shale deposits are mixed with clay and clays are plastic owing to their water content (and the chemistry of that water). If you want to get serious check phyllosilicate minerals (closely related to clays) which are hydrated with water and/or attached hydroxyl groups.
    Watcher says:
    08/15/2016 AT 10:03 AM
    Vaca Muerta is probably the poster child for any non Bakken and non Eagle Ford around the world as potential shale places.

    It’s marine deposited rock. Has a pretty darn good wiki.

    But it appears to be mostly gas. Optimistic plans for multi decades talk only about 40,000 bpd. Lots more gas, but only 40K bopd so it’s not going to save Argentina’s bacon.

    • Watcher says:

      So Doug, the writer of that article claiming salt water vs fresh water in ancient times decides rock bendability — and you do not confirm that, but the underlying point is bendability is what determines if oil can come out of shale rock. If you bend rather than shatter, there is no permeability added and oil (or gas) doesn’t flow.

      The wiki says Vaca Muerta is marine sourced sediment and I concluded from that guy’s claim that this means it will shatter when frack pressure applied, but you do not confirm that.

      • Doug Leighton says:

        Watcher, let’s not take the fresh/salt water thing too far. And remember, unlike the Chinese reservoirs that were referred to, the Bazhenov stratum (in the West Siberian basin) formed from sediment deposited in deep-water. The key thing to remember about the Bazhenov is there are major facies changes (along strike and up/down dip) meaning the geology changes over relatively short distances. You can’t properly generalize about potential productivity (or lack of) yet because there is limited information.

        • Watcher says:

          Passage from the wiki:

          The Vaca Muerta Shale is a continuous tight oil and shale gas reservoir of late Jurassic (Tithonian) and early Cretaceous (Berriasian) age formation. The formation covers a total area of 30,000 square kilometres (12,000 sq mi).[8] The shale is at a depth of about 9,500 feet (2,900 m) where it has been found productive of oil and gas. Although called a shale, and with a total organic carbon content varying from 1 percent to 5 percent, the Vaca Muerta is predominately marl and consists of mature black shales, marls and lime mudstones.[9][10] Formed in a marine environment with little clay and brittle rock the deposit is 30 to 1,200 metres (98 to 3,937 ft) (usually over 400 metres (1,300 ft)) thick extending throughout the basin.[10][11]

          It’s like someone crafted that verbage to reassure money there is no clay and the brittle rock won’t be pliable. Suspicious.

          • Doug Leighton says:

            I know almost nothing about the Vaca Muerta BUT as far as I know its basically a semi-continuous tight shale gas reservoir. Who’s talking about oil there? BTW Vaca Muerta is Spanish for Dead Cow. 🙂

            • Watcher says:

              The large oil discovery in the Vaca Muerta Formation was made in 2010 by the former Repsol-YPF, which announced the discovery in May 2011.[1] The total proven reserves are around 927 million barrels (147.4×106 m3), and YPF’s production alone is nearly 45,000 barrels per day (7,200 m3/d).[2][3][4] In February 2012, Repsol YPF SA raised its estimate of oil reserves to 22.5 billion barrels (3.58×109 m3).[5][6] The US EIA estimates total recoverable hydrocarbons from this Vaca Muerta Formation to be 16.2 billion barrels (2.58×109 m3) of oil and 308 trillion cubic feet (8.7×1012 m3) of natural gas, more than even the Neuquén Basin’s hydrocarbon-rich Middle Jurassic Los Molles Formation holds.[7]

              This time frame there was a fight YPF Repsol and Argentina govt. This really smells of hype, and EIA probably never sent anyone down there. They relied on maybe a govt report.

              • Doug Leighton says:

                All I know Watcher is that ExxonMobil, in their technical reports, has claimed Vaca Muerta the world’s second-largest shale gas deposit with little or no reference to oil. Whether it’s being hyped by some players as an oil rich province, or not, I have no idea.

            • AlexS says:

              The EIA expects LTO production in Argentina to reach 0.69 million b/d by 2040
              “The Argentine national oil company, Yacimientos Petrolíferos Fiscales, reported that shale production reached 0.05 million barrels of oil equivalent per day (of which 0.03 million b/d was estimated to be tight oil) in the fourth quarter of 2015 from its joint venture with Chevron in Neuquén Basin, Argentina”


              • Watcher says:

                Remember, the price is about $70/barrel there.

                • AlexS says:

                  Argentina cuts wellhead oil prices, freezes retail

                  15 Aug 2016

                  Buenos Aires, 15 August (Argus) — Argentina’s government and leading oil companies hammered out a plan to gradually trim artificially high wellhead crude prices over the next three months in exchange for a temporary freeze on retail fuel prices.
                  The agreement is aimed at stemming inflation, which clocked in at 46pc in the 12 months ending in July, according to unofficial estimates released by opposition lawmakers.
                  Oil producers in Argentina have long enjoyed above-market crude prices mandated by the government. The policy, which was retained by the new government that took office in December 2015, is intended to stimulate domestic production and prevent job losses in the oil industry.
                  The new agreement will not eliminate the steep premium on international prices. Producers of 34°API Medanito crude currently receive $67.5/bl from local refiners, while heavier Escalante crude is pegged at $54.9/bl, following a 10-12pc price cut implemented in January shortly after the new government came to power.

                  • Watcher says:

                    They have been specifying price for what, about two yrs now? And are cutting it to attack generic (not fuel) inflation.

                    No reason they can’t.

            • Vaca Muerta has sands in parts of the basin. I believe it’s oil sand at Malargüe Field, near the Mandoza-Neuquen border. I was there scouting the area in 1979. Since it has been so many years, I can’t remember the logs very well.

              One thing that’s wrong with that description is the generalization. That basin is fairly large, and the formation can range in depth as well as dip, petrophysics, etc. I remember the shale section had a really nice radioactive dirty lime. I bet that’s where they are drilling the horizontal wells. And if I know YPF they are drilling to the south, near Loma de la Lata, because they already have all the facilities to handle the gas. The eventual peak rate has to be established, it depends on the per well recovery they can establish, and the drilling pace that recovery per well can support. The government won’t be too keen on generating a lot of exports, they focus on internal supply and the jobs market.

    • Greenbub says:

      Thanks for the repaste, I learned something(about clay/shale).

  5. Ken Barrows says:

    Bakken: 740 or so additional wells and production down 15% year over year. Great, just great.

    The question to keep production level or rising is this: how much debt will it take?

    • Dennis Coyne says:

      Hi Ken,

      If the Bakken/TF was developed using old school rules where new wells are developed using cash flow, then not a lot of debt would be needed at over $85/b. The only reason debt ballooned in 2011-2014 in the ND Bakken was the play was developed too quickly leading to an oversupply of oil on the World oil market. Perhaps US oil companies will learn from past mistakes, perhaps not. We will find out by August 2018 when oil prices start to approach $85/b. In the mean time, there will be more bankruptcies and consolidation in the US LTO sector.

      • Eulenspiegel says:

        I don’t believe they learned.
        If oil rises over 85 or even reaches 100, all wallstreet money will be free lunch again, since wallstreet can sell these bonds to dumb customers to bear the risk and gain risk free profit.

        And the dumb investors sees something like 7% profit on bonds instead of 0, so the brain will shut down again.

        It will repeat.

        • Dennis Coyne says:

          Hi Eulenspiegel,

          I am not sure what will happen. Consider that during the boom, US oil companies assumed that OPEC would cut back production if they overproduced and they were proven wrong, investors who have lost money on their oil investments may not be as willing to part with their money in the future.

          Sometimes people learn from past mistakes, unfortunately not as often many (myself included) presume.

          • Eulenspiegel says:

            Hi Dennis,

            But that would mean no instant production increase when oil prices rise – since you’ll need 100 billions ++$ in new junk bonds to fuel the drilling bonanza drilling 1000s of new wells.

            Since utility companies have downsized, too, nobody will earn money even at 100$, since every price will shoot to the moon when everybody wants to frac in the same week bidding each other up, while equipment is in cold store or outdated. So no superfracs, but old fracs with old technique bought back in the last minute from the scrap yard.

            • GoneFishing says:

              I see LTO as probably the easiest investment to predict, most of the product is produced in the first two years of a well so long term timelines are not an issue, only price. Downstream at the pipelines, refineries and distribution systems, as well as the vehicles using the product, the timelines are much longer. Investments there will be on the order of a decade to several decades timeline.
              With the looming carbon pollution reductions and the upcoming hybrid/EV production, product demand in the long term could reduce dramatically. Same with coal and natural gas for electric power, they have long investment timelines at the power end while renewables and efficiency are poised to eat away the demand.
              At what point the investors and banks will switch investment strategy is another big unknown. Will they continue to fund oil and gas or will they suddenly shift toward renewables sometime in the near future?
              It is a Wild West chaotic world from the point of view of investment and timelines for legacy energy. So any guess as to future production has to take into account reduced sweet spots, limits to areas of production, political changes, competing technologies, and investors who may just opt out. Anything past a few years is just plain entering unknown territory.

              Usually, smaller or even large businesses that show good profitability are bought up by larger businesses. Is this happening in the oil sector?

            • Dennis Coyne says:

              Hi Eulenspiegel,

              There are smart people in the oil industry that know how to do things properly, those people are probably getting things in place right now in anticipation of rising oil prices in the future. When the boom arrives they will be well placed to be profitable, those late to the game will not be very profitable. The smart investors will know which companies are which and will rely on 10K reports rather than investor presentations when doing their research.

              I do not expect an instantaneous ramp up as prices rise, the best approach will be a slow and steady rise in wells completed over a 3 to 5 year period and then slowing to a plateau for several years with a gradual ramp down as sweet spots get saturated with wells and new well EUR decreases along with the number of completions as profitability gradually falls.

              Such a scenario would depend on oil prices rising to between $95 and $130/b (2016$) and remaining in that band from 2020 to 2030. A spike in prices to over $150/b would probably lead to a recession and another oil bust.

              Prices are impossible to predict, but I think it highly unlikely that the annual average Brent oil price will be less than $60/b in 2018(US nominal dollars).

  6. R Walter says:

    Looking at future production another way, the recent peak in production has been 75,000 barrels of oil per day (discussed in more detail below). Even if operators are able to triple this amount, the resulting production of 225,000 barrels a day (which would be a considerable challenge), will amount to only about 1.1% of US oil consumption, assuming the US uses about 20.7 barrels of oil a day, based on EIA data.

    If we can reach 225,000 barrels of oil per day, the history of Bakken suggest this level would be short-lived – the peak production will probably last for a year or less – because as we shall see below, total Bakken production can be expected to decline to 50% or less of its peak rate within a few years, because of the steep decline rate of individual wells.

    Guess the projection was wrong.

  7. Toolpush says:

    Bakken crude by rail is about to be very limited. The 450 mbopd Dakota Access pipeline will come online in the next 6 months. Some oil will still go ny rail to see out current contracts, but there will be enough pipeline capacity for all Bakken crude. The oil producers should gain a little price rise. I don’t thin it will be enough for them to make money, just allow them to lose it more slowly.

    • Dennis Coyne says:

      Hi Toolpush,

      Excellent point. The oil producers would be wise to keep total output close to pipeline capacity and their oil will be more profitable, the smart companies will lock up pipeline capacity.

      • We aren’t all wise. There will always be somebody who miscalculates and uses rail, trucks. The North Dakota regulatory agency could try to manage it, but they seem to be quite unable to actually run things.

    • Dennis Coyne says:

      The RBN piece that Toolpush linked above has an interesting forecast from RBN.

      Excerpt from RBN:

      The Bakken production/takeaway scenario that we reviewed in With or Without You featured the contrast between plunging crude oil output and a big increase in planned pipeline capacity. According to Baker Hughes, the Williston Basin rig count dropped from an average of 190 in mid-2014 to just 22 in May 2016. As noted above, the reduced investment in drilling eroded production in the play to under 1.0 MMb/d. The run-up in oil prices to the $50/bbl range a few weeks ago helped boost the latest rig count to 28 (as of August 12). RBN Energy’s Growth Scenario forecast for the Bakken (based on a gradual rise to $60/bbl oil over five year) sees an increase to about 1.5 MMb/d in 2021—that’s the red-plus-blue layers of production in Figure 2. RBN’s Contraction Scenario, in turn, puts 2021 output at only about 900 Mb/d (red layer only).

      Figure 2 from the RBN article is shown below.

    • GoneFishing says:

      Toolpush, I know oil trains were coming down from the north through Scranton and headed toward Philly or points east and south. Are there pipeline connections to the northeastern seaboard from Pakota Hub?

      Some local articles and interactive map concerning Bakken oil trains in Pennsylvania

      • Toolpush says:

        Gone Fishing,

        There are no pipelines running east or west from ND. That is one of the reason why rail became so useful. But if their is enough pipeline capacity to carry total Bakken production south into the matrix and refineries that exist around the gulf coast for a few per barrel transport cost there will not be too much call for rail shipment to the east or the west coast at $12+ per barrel.
        There is a rider of course. There are existing take or pay contracts, that will still have time to run. So the trains will not stop immediately, but are sure to drop as the contracts expire. At the coasts, all the Bakken oil can be replaced by imports, as these refineries were using imported oil up to only a few years ago, when the Bakken oil came on the scene.

        As side note. Last year when I was in Wisconsin. A relative lived very close to a rail that had regular oil trains travelling along it. There was a low level wooden rail bridge over 2 lane road. Even though the low height was well advertise and sign posted, it was a favourite target for trucks. One hit while we were there. I am sure there are many more high risk potential spots across the rail network. The good thing, is, pipelines are traditionally a much safer method of oil transport, even though people still complain when they are being proposed.

        • GoneFishing says:

          Apparently crude by rail accounts for about half of east coast refinery (at least up to January 2015).

          Moving crude by barge and ship on the Great Lakes is quite controversial, although diesel and gasoline have been transported.

          • Toolpush says:

            Gone Fishing,

            You will find before about 2011, the coastal refineries, got all of their crude from overseas, and only got to use of Bakken crude as the producers struggled to find exit routes out of North Dakota and forgien oil went up in price. As pipelines come on stream,with cheaper transport cost, Bakken oil will not be available to the coast, except with a transport cost premium. The coastal refineries will just go back to importing foreign oil, from those renown counties of stability such as Libya, Nigeria and Iraq.

            • Synapsid says:


              Oh, but here in Washington State we’re sitting pretty, because we get that Alaskan crude…oh, wait…well anyway, we steal crude from the pipeline that carries Alberta oil to the Vancouver area…um– don’t forget the Bakken crude that’s railed in!

              Lots of, um, crude in our future, you see.

              Moving on to LNG: I’ve been keeping a sort of eye on the LNG project up in Alaska, the one that requires a pipeline from the North Slope east of Prudhoe Bay down to the Kenai Peninsula; about 800 miles, I believe. It’s a strange bunch behind it: ExxonMobil, BP, and ConocoPhillips (75%)…and the state of Alaska in for 25%. Does a state normally get involved in such a project?

              Anyway, an article at OilPro yesterday tells us that the oil companies are thinking that running the project ought to be in Alaska’s hands and that they may not be continuing to take part at all (this after about half a billion dollars have been spent).

              The fellow put sort of in charge now says that maybe financing from investors of various kinds should be sought, instead of the parties themselves supplying the money. Sounds like a hot investment with a great future, doesn’t it?

              • Doug Leighton says:

                Another minor issue (actually not so minor) is that most Alaskan natural gas is near and used to pressurize Prudhoe Bay reservoir. Without that, Prudhoe (and satellites) start to die, well, start to die even faster.

                • GoneFishing says:

                  More magnets under the roulette wheel of life Doug?

                  The more I learn about the fossil fuel industry, the more it seems to be feeding on itself. It probably has already started tapping wind and solar energy to run itself.

                  Free the Gas, it’s Natural!!!!

                • George Kaplan says:

                  Doug – I think they’d still be able to fill the LNG plant and provide pressure support, and if the LNG plant were built they’d then be able to blow the oil gas caps down at the end of oil field life and get their money back to some extent (with no LNG the gas has gone for good). The financing issue is that the oil companies would need to invest $50 billion, which would almost certainly escalate given the nature of the project with a long pipeline in difficult conditions, over ten years before they got any return. The IOCs are borrowing to pay dividends anyway. There is currently a large LNG glut that is getting worse as Russia, Africa and Australia projects come on line this year and next. Typically LNG projects have customers involved (i.e. utility companies in Asia or Europe) and the LNG is effectively pre-sold on a guaranteed contract, sometimes the LNG plant just acts as a service provider and the resource is owned by the customer who pays a processing fee to the plant. None of that seems to be the case here. It looks like Alaska got involved to push through the project and with current prices and economic conditions it just isn’t looking attractive to the IOCs anymore.

                  • Doug Leighton says:

                    I’m sure you’re right on all points George but I do remember some push-back from oil companies on giving up rights to gas based on adverse EOR efforts: likely it was politics: companies vs state? I’ll see if I can find the reference(s).

                • Doug, i may be wrong, but the Sadlerochit has taken so much gas over the years that it may be a good idea to blow it down slowly. So it’s not a given that production will drop faster if some of the gas is redirected.

                  One of the issues I saw being modeled was having the ability to remove co2 from the LNG gas stream and using it for EOR. This of course requires a huge investment.

              • Toolpush says:


                In a logical world, Alberta oil would find its way via pipeline to Washington state. But we don’t live in a logical world, so it is doubtful this will happen, or should I doubtful new pipelines will be built.
                I suspect the new Panama canal would make Atlantic basin oil available to Washington state. US LTO should be able to be shipped from the gulf coast to Washington, but I think the Jones act will either minimize or totally eliminate it.
                So my guess is Bakken oil will be replaced with West Coast of Africa oil. We should get an idea in 12 months or so.

                • Synapsid says:


                  I should have added /sarc.

                  All the sources I mentioned are real. We’ve been tapping the TransMountain pipeline carrying Alberta crude to Burnaby (near Vancouver) for years. Alaska crude arrives by ship from Valdez, and has been dropping in volume, and the Bakken stuff comes in by rail. I’m not an optimist about the Bakken.

                  My point was that each of the sources I mentioned is going to provide us less and less oil.

            • GoneFishing says:

              Sure Toolpush, they go for the cheapest and easiest to refine. Also the Bakken production was fairly low before 2011.
              Just one more reason to switch to electric vehicles.

  8. George Kaplan says:

    BHP went from $8 billion profit to $6 billion loss based on latest results:

    Capital cuts to be expanded next year.

    “Capital and exploration expenditure declined by 42% to US$6.4 billion and is expected to decrease further to US$5.0 billion in the 2017 financial year (BHP Billiton share)(5).”

    I don’t know if there is enough detail to say how much came from oil and gas operations. The Samarco dam accident seems to be budgeted at $1.2 billion so far.

    Petrobras made a small profit but less than expected:

    “In 2Q16, Petrobras’s earnings attributable to its shareholders stood at $106 million compared to $171 million in 2Q15. This was on account of a fall in crude oil and natural gas prices, which impacted upstream earnings. Plus, crude oil and natural gas production volumes fell by 6.3% over 2Q15 to 2.1 billion barrels of oil equivalent per day in 2Q16.”

    Production has picked up recently though and there is more to come with several FPSOs in the pipeline, as long as they can avoid major unplanned outages.

    • likbez says:


      This is a typical Wall Street racket. In this case oil producers are victims. As Kunstler said

      === quote ===
      Societies have a really hard time understanding what they’re doing, articulating the problems that they face and coming up with a coherent consensus about what’s happening, and coming up with a coherent consensus about what to do about it. Combine that with another quandary, the relationships between energy and the dead racket for concealing real capital formation. I like to reduce it to one particular formula that is pretty easy for people to understand.

      It’s a classic quandary: that oil priced at over $75 a barrel in today’s dollars tends to crush economies, and oil priced under $75 a barrel in today’s dollars tends to crush oil companies. There is no real sweet spot between those two places. We’re ratcheting between them and each one of them entails a lot of destruction.

      That’s a terrible quandary that we’re in and it’s being expressed in banking and finance…and the people in charge of those things don’t really know what else to do except continue the deformation of institutions and instruments.

  9. George Kaplan says:

    From Reuters and EIA

    “U.S. shale oil production is expected to fall for a tenth consecutive month in September, according to a U.S. government forecast released on Monday, as low oil prices continue to weigh on production.

    “Total output is expected to drop 85,000 bpd to 4.47 million bpd, according to the U.S. Energy Information Administration’s drilling productivity report. That is the lowest output number since April 2014.

    “The EIA’s previous forecast calling for an output decline in August of 99,000 bpd was revised up to nearly 112,000 bpd, data shows.

    “Bakken production from North Dakota is expected to fall 26,000 bpd, while production from the Eagle Ford formation is expected to drop 53,000 bpd. Production from the Permian Basin in West Texas is expected to rise 3,000 bpd, according to the data.”

    Ron’s graphs summarised this better but I don’t have the previous history to show it. Has anybody here explained why Eagle Ford drops are so much more than Bakken?

    • Dennis Coyne says:

      Hi George,

      The DPR tends to overestimate the decline in the Eagle Ford.

      Enno Peters uses Texas RRC data to estimate Eagle Ford output and that also underestimates output for the same reason that Texas data in general is too low because it is incomplete.

      I have estimated Eagle Ford output by finding the percentage of total Texas C+C output from the Eagle Ford for each of the most recent 24 reported months and than multiplied this percentage by Dean Fantazzini’s estimate of Texas C+C output (which is better than any other estimate in my opinion).

      The Chart below compares this method using Dean’s estimate (DC estimate) and the EIA estimate for Texas C+C output, to find Eagle Ford output through June 2016.

      The reason Eagle Ford output has decreased more rapidly is because the wells decline more rapidly and because the ramp up in the Eagle Ford was more rapid than in the Bakken/Three Forks so that a lot more wells are declining at once.

      • Dennis Coyne says:

        The Chart below is from Enno Peter’s excellent website

        It shows the number of new wells completed in the Eagle Ford (he calls these wells “first flow” as in the month that the well started producing oil). Compare this chart to the Bakken chart in the post.

        • George Kaplan says:

          Dennis, Thanks – would that mean it could ramp up faster if conditions became more favourable?

          • Dennis Coyne says:

            Hi George,

            I don’t know if they might have reached saturation in the sweet spots in the Eagle Ford, they seem to have an advantage in Texas with infrastructure and pipeline capacity, but a lot of that has now been established in North Dakota so going forward the main advantage for Texas is lower transportation costs to refineries.

            Take a look at there is a ton of information there.

    • Enno Peters says:


      > Has anybody here explained why Eagle Ford drops are so much more than Bakken?

      Although the number of new wells producing dropped very similarly (relatively) in these two basins, Eagle Ford wells decline faster after initial production. You can see this most clearly by:

      1. Going to my latest US presentation here.
      2. Go to the “Well quality” tab.
      3. Group wells by “Basin”.

      => You can see the profiles of the average well in each of the basins, and that Bakken wells in general have a longer production life. Note that there is some distortion as especially the early 2007-2008 Bakken wells (Sanish & Parshall) were exceptionally good.

      You can play with the “first flow” filter to see this for wells starting in different years.

      • Dennis Coyne says:

        Hi Enno,

        Thanks. Using your link above I created the following chart from your website.

        I compare only wells with first flow from 2012 to 2016 because the Eagle Ford play did not really start being developed as an oil basin until late 2010 and they probably hadn’t really figured out optimal well spacing and frack setup until 2012.

        This demonstrates the steeper decline for the Eagle Ford that you refer to.

        • Dennis Coyne says:

          Cumulative well profile that goes with chart above, color scheme is the same, Bakken red, Eagle Ford green, etc.

          • Enno Peters says:

            Exactly, thanks Dennis.

          • George Kaplan says:

            So ‘other’ would represent the 130 Gb of undiscovered resource that Rystad reckons exists in the USA? That’s going to need a lot of wells.

            • Enno Peters says:


              No, the “other” represents other horizontal wells that were drilled in Texas in the last couple of years, outside the Eagle Ford & Permian area, e.g. in the Barnett, Granite Wash, etc.

      • AlexS says:

        Thanks Enno,

        These charts from the EIA confirm your conclusions.
        They show that, while IP rates in the Bakken and the Eagle Ford are similar, EFS production rates are declining much faster.
        Would be interesting to know if this is due to more rapidly falling reservoir pressures, different completion techniques, or something else.

        • AlexS says:

          Eagle Ford

          • clueless says:

            Somebody needs to buy an “Ultimate” box of crayolas that has 152 different colors to choose from.

            • Fred Magyar says:

              No, they need to do exactly the opposite. They need the 16 color basic kindergarten box so they won’t have the option to choose 7 shades of lavender… Keep it simple Susy!

              • clueless says:

                Good point!

              • Verwimp says:

                I disagree. I like the seven shades of lavender. It’s a very intelligent way to introduce a third dimension into the graph. In one blink of an eye it’s clear there is an evolution. The production profile is changing.

        • AlexS says:

          New-well oil production per rig is higher in the Eagle Ford.
          Apparently, this is because EFS is shallower and it takes less time to drill a well than in the Bakken.
          As a result, more wells can be drilled by 1 rig in the same period of time.

          Source: EIA DPR August 2016

    • Verwimp says:

      To put Enno’s “relatively” into perspective: Peak output of Eagle Ford used to be bigger than peak output of Bakken. The more you have, the more you can lose.

    • AlexS says:

      The trend in rig count and the absolute number of active oil rigs are quite similar in the Bakken and EFS.

      • AlexS says:

        The number of drilled but uncompleted wells is bigger in the Eagle Ford.
        According to Rystad Energy, it was 1000 as of May 2016 in EFS vs. 850 in the Bakken.


        • AlexS says:

          The intentionally postponed (abnormal) part of the DUC inventory has been growing much faster in the Eagle Ford than in the Bakken since mid-2015.
          That could also explain steeper declines in EFS oil production vs. the Bakken.

        • AlexS says:

          Bloomberg shows a different trend in DUCs inventory: a decline in the Eagle Ford vs. continued growth in the Bakken. That would suggest more resilient production volumes in EFS.
          But I think that Rystad’s estimate is more reliable.

  10. Oldfarmermac says:

    Any discussion of this link should go over to the open thread but the hard core oil guys need to keep an eye on this sort of thing .
    It promises to cut into the sale of oil in a substantial way within a decade or so.

  11. AlexS says:

    “The Norwegian Petroleum Directorate reported that Norway’s oil production in July reached its highest level in 5 years because many fields were “producing above prognosis.”
    Oil output of 1.728 million b/d was 10% above July 2015 and about 18% above this past June, which had 1.449 million b/d. [June production was low due to maintenance – AlexS].
    The July liquids total averaged 2.136 million b/d after combining the oil number with 375,000 b/d of natural gas liquids and 33,000 b/d of condensate.”

    Norway liquid hydrocarbons production (mb/d)

    source: Norwegian Petroleum Directorate

    • likbez says:

      The more they produce the more money they lose.

    • George Kaplan says:

      Goliat ramp-up following a delayed start-up and probably increased Ekofisk flow after maintenance are mostly responsible. There is one more start-up this year for Ivar Aarsen, at about 120,000 bpd, then two next year, Gina Krog and Aasta Hansteen (gas), and four in 2018 (mostly smaller tie backs and gas). Then Johan Sverdrup in 2020 (300,000 or more boepd after a few years) and Johan Castberg, but then not so much unless exploration success picks up a lot. On a year by year basis they are expected to decline slightly to 2020 then a small tick up and plateau with Johan Sverdrup ramp up and then temrinal decline.

  12. Chart Monkey says:

    China is still building it’s crude stocks and SPR, but theres no official inventory information…

    China data: Crude stocks rise by 525,000 b/d in July – Platts
    China does not release official data on stocks. Platts calculates China’s net crude stock draw or build for the month by subtracting refinery throughput from the country’s crude supply. The latter takes into account domestic crude production and net crude oil imports.

    …the country is continuing to fill its strategic petroleum reserves, including new sites in northeastern China’s Jinzhou (18.9 million barrels) and southern China’s Yangpu (9.69 million barrels).

    Analysts also expect the new Huizhou storage in southern China and Zhoushan Phase II in eastern China, each 31.45 million barrels in capacity, to start taking in crude oil next year.

    Long term China inventory growth chart on twitter (Bloomberg, ISI Energy Research):

    Platts Jan+Feb missing on their chart…

    • Chart Monkey says:

      China’s July refinery throughput retreats from record highs
      Singapore (Platts)–12 Aug 2016
      After surging to a historical high of 11.02 million b/d in June, China’s refinery throughput in July took a breather, easing 2.7% month on month to 10.72 million b/d, although it was 2.5% higher from July 2015, S&P Global Platts calculations based on preliminary data released Friday by the National Bureau of Statistics showed.

      China, July gasoline output 10.54mm tonnes. +1.6% y/y. Bureau of Statistics on Wednesday.

  13. Longtimber says:

    Scraping the bottom on conventionals ? May have to Search “WSJ giants too big to frack”

    • Since a lot of that fracked production turned out to be money losing, maybe the question should be whether oil majors realized or felt that fracking boom was bogus? Oil majors can buy other companies if they think it’s worthwhile. I believe only Exxon bit that hook and it didn’t turn out that well?

      • AlexS says:

        Oil majors’ corporate strategies are more conservative and, unlike shale players, more focused on financial results than volume growth

      • John Keller says:

        The majors have realized that shale was a scheme. Shell lost a billion in the Eagle Ford when prices were high. Sumitomo lost nearly $2 billion in their jv with Devon in the Permian when prices were high.

    • Longtimber says:

      Someone should publish same operator bar chart of NET Cash Flow from “Shale Operations” to date.

    • clueless says:

      The WSJ does not classify ConocoPhillips as a major? I guess because of no refineries?

  14. Daniel says:

    EIA weekly numbers out and US production up 152 mbpd. Hopefully this is only the result of an overdue correction. I cannot imagine that this is “real”.

    • Chart Monkey says:

      EIA – Weekly Petroleum Status Report – U.S. Petroleum Balance Sheet, Week Ending 8/12/2016

      As you know, the weekly production figures are based on a model. And so yes, did production really bounce that much in just one week, or was it that production never actually fell that low in prior weeks? This line 13 is enough to give anyone a headache. As it’s a balancing factor, it could be due to unaccounted for imports or production. Someone even suggested that exports are lower than reported. I’m guessing that the EIA must have accurate figures for imports, exports and refinery input and so I’m guessing line 13 is due to production. I’ve started plotting line 13 to see if there is a pattern?

      • Chart Monkey says:

        Bloomberg – The 100,000-Barrel Oil Output Increase That Didn’t Really Happen
        August 17, 2016 – Mark Shenk
        The output estimate jumped by 152,000 barrels a day for last week, the biggest increase since May 2015, according to the Energy Information Administration. Production didn’t actually increase by that amount but was modified to incorporate a “re-benchmarking” versus the agency’s Petroleum Supply Monthly, according to Jonathan Cogan, an EIA spokesman.
        “The weekly data is based on models, with the exception of Alaska,” Cogan said. “When the monthly data or Short Term Energy Outlook differ from the weekly data, we re-benchmark”

  15. Daniel says:

    Saudis produce 10.67 mmbpd and still have to draw down their inventories by 200mbp to fulfill home and customer demand…..

    • Chart Monkey says:

      JODI updates all of it’s data tomorrow, the IEA said that product stockpiles were high around the world, I might have a look for data on that.

    • aws. says:

      ELM and Climate Change converging to increase KSA domestic demand.

      Oil demand likely rising in sweltering Middle East: Kemp

      John Kemp, Reuters, Thu Aug 11, 2016 2:22pm EDT

      Saudi Arabia raised its oil production to a record last month while much of the kingdom sweltered in record temperatures that have also hit neighboring countries across the Middle East.

      There is not enough statistical data to draw a direct connection between the two but it is likely most if not all the extra oil production was burned in the kingdom’s power plants to meet electricity demand.

      Saudi Arabia’s power generators rely heavily on burning unrefined crude as well as residual fuel oil and diesel to meet electricity demand.

      • Watcher says:

        Consumption, more than demand. From an export perspective, analagous to buying for storage. That is demand exceeding consumption.

    • aws. says:

      From the classics…

      Burning Oil to Keep Cool: The Hidden Energy Crisis in Saudi Arabia

      Glada Lahn and Paul Stevens, Chatham House, 01 December 2011

      • Strange. Why don’t they buy solar panels? The solar panel prices are very low due to overcapacity, and the Saudis have the money to invest.

        I checked KSA average temperatures for May using the university of Maine’s Climate reanalyzer, it shows it has increased 1 degree C in 30 years. The same data base shows Australia’s May temperature has increased about 0.3 degrees C in 30 years. South America’s tropical region’s May temperatures dropped 0.2 degrees C over the last 30 years.

        I used May because that’s the latest month they loaded. It will be interesting to see August temperature trends using this Maine data base.

        • Nathanael says:

          Atttitude. The UAE is buying solar panels. But KSA simply can’t *think* that way. The KSA leadership is very rigid and doesn’t know how to change…

  16. GoneFishing says:

    Set of info slides on Norfolk Southern oil trains.

    Sand headed up to NE Pennsylvania, looks like gas fracking is going again, 20 cars yesterday. First time in a long time.

  17. aws. says:


    There is truly no hope for Christy Clarke’s B.C. LNG plans.

    Gas Glut Upends Global Trade Flows as Buyers Find Leverage

    Tsuyoshi Inajima, Bloomberg, August 15, 2016 — 7:01 PM EDT

    Japanese may force renegotiation of $600 billion in contracts
    India already encouraging importers to rework long-term deals

    Historically, LNG has been sold on long-term contracts that guaranteed buyers supply and helped producers finance liquefaction plants at a time when less of the product was shipped. Now, a gas glut is causing LNG importing countries to support renegotiating existing deals that can run 20 years or more while suppliers offer more flexible terms to lock up customers spoiled for choice.

    “There will be 40 million to 50 million tons of homeless LNG by 2020, which can go anywhere or doesn’t have any fixed customers,” said Hiroki Sato, a senior executive vice president with Jera Co., a fuel buyer that plans to increase spot and short-term LNG deals. “Homeless LNG will provide a great opportunity to improve liquidity in Asian and global markets.”

    The world’s fourth largest LNG buyer was among the first countries in Asia to renegotiate a long-term deal after Petronet LNG Ltd. in December reworked a 25-year contract with Qatar’s RasGas Co., resulting in prices dropping by almost half.

  18. aws. says:

    Externalized costs.

    Louisiana’s Sinking Coast Is a $100 Billion Nightmare for Big Oil

    The state can’t pay, so someone has to. And the water keeps rising.

    Catherine Traywick, Bloomberg, August 17, 2016

    The canals tell a story about the industry’s ubiquity in Louisiana history, but they also signal a grave future: $100 billion of energy infrastructure threatened by rising sea levels and erosion. As the coastline recedes, tangles of pipeline are exposed to corrosive seawater; refineries, tank farms and ports are at risk.

    “All of the pipelines, all of the things put in place in the ’50s and ’60s and ’70s were designed to be protected by marsh,” said Ted Falgout, an energy consultant and former director of Port Fourchon.

    • GoneFishing says:

      Nothing new here, land deposition stopped 70 years ago. Destructive engineering practices for the oil and gas industry as well as extraction of fossil fuels from the area has been the major culprit. 50.000 wells drilled and more than 10,000 miles of dredged canals. Where the canals were dredged, the soil was dumped along the edges, forming walls and isolating the marshes from any source of new soil brought down by the river system.

      “but a U.S. Department of Interior report says oil and gas canals are ultimately responsible for 30 to 59 percent of coastal land loss. In some areas of Barataria Bay, said Turner at LSU, it’s close to 90 percent.

      Even more damage was to come as the oil and gas industry shifted offshore in the late 1930s, eventually planting about 7,000 wells in the Gulf. To carry that harvest to onshore refineries, companies needed more underwater pipelines. So they dug wider, deeper waterways to accommodate the large ships that served offshore platforms.

      Congress authorized the Corps of Engineers to dredge about 550 miles of navigation channels through the wetlands. The Department of Interior has estimated that those canals, averaging 12 to 15 feet deep and 150 to 500 feet wide, resulted in the loss of an additional 369,000 acres of coastal land.

      Researchers eventually would show that the damage wasn’t due to surface activities alone. When all that oil and gas was removed from below some areas, the layers of earth far below compacted and sank. Studies have shown that coastal subsidence has been highest in some areas with the highest rates of extraction.”

    • Nathanael says:

      Sadly, the state is run by know-nothings who have no interest in reversing this disaster.

  19. George Kaplan says:

    I plotted the ND DMR well data or the Bakken below. Unfortunately I have had to do it in grey scale to meet the file size limits and split the charts. Black diamonds are dry holes since 2000 (well permit #15000), the smaller grey circles are dry wells between #10000 (1983) and #15000, and this excludes a whole lot of wells from before 1971, a large proportion of which were dry. There are different reservoir layers and vertical versus horizontal types, but I think the limits are pretty clear.

    The black circle symbols in the second chart below are any oil and gas active or confidential wells (some of which may not produce, but most seem to now).

    Black filled squares are drill sites or permitted but not yet drilled. It looks to me like these are moving outside the original core areas.

    Open triangles are DUCs. There are only 691 in the database and the DMR estimates over 800, the others might still be confidential (or do they include Montana numbers, or I’ve missed something). It is interesting that the DUCs appear to concentrate on the banks by the Missouri and Lower Missouri rivers. Do the rivers reflect subsurface geology in some way, or could be environmental or access issues as well. I am afraid I am not skilled enough to mix images to overlay a map, and it would exceed size limits anyway, but the gap in wells about three quarters up in the chart for active wells shows the Missouri River and the northern arm of Lake Sakakawea clearly.

    • AlexS says:

      From the latest Director’s Cut:

      “Estimated wells waiting on completion2 is 887, down 44 from the end of May to the end of June.
      Estimated inactive well count is 1,486, down 98 from the end of May to the end of June. ”

      Inactive wells include all well types on IA and AB statuses.
      IA= Inactive shut in >3 months and 12 months)
      AB= Abandoned (Shut in >12 months)

      This includes only North Dakota.

    • Fred Magyar says:

      Hey George, if you can post a link to your color charts I might be able to tweak them to work here.
      No guarantees but it might be worth a try.

      • George Kaplan says:

        Fred – thanks – I tried a couple of online converters and a couple of tweaks to the colour palette but I was a long way off even with the best attempt. The heat map doesn’t make much difference anyway.

        • Fred Magyar says:

          BTW, This is what I use for technical graphics.

          Canvas X is a fully integrated data visualization solution that addresses the needs of the Oil & Gas sector. Share the results of your research and analysis. With Canvas X you can easily and accurately measure, analyze, and illustrate all forms of spatial relationships, trends, and patterns. In fact, Canvas X’s GIS+ module handles most spatially-oriented geodata.

          Disclaimer: I am not currently affiliated with them in any way. I just love their product.

  20. George Kaplan says:

    Active wells:

  21. George Kaplan says:

    This third chart is a coarse heat map showing producing and confidential wells. The grid is 0.1 degrees longitude and latitude, so each square is 7395 acres in the south dropping to 7362 in the north. 53% of the grids aren’t drilled. 17% have less than one well per 600 acres. The highest concentration is 40 acres. I don’t think this proves anything for shore but my feeling is that Bakken is going to be at the lower end of ultimate recovery estimates, even with significant price rises.

    • shallow sand says:

      George: Look at just announced CLR acreage sale for anecdotal evidence.

      Per 2015 CLR 10K:

      ND Bakken developed acreage: 595,396
      MT Bakken developed acreage: 148,764

      ND Bakken undeveloped acreage: 205,227
      MT Bakken undeveloped acreage: 96,049

      CLR announced they are selling 68,000 ND Bakken acres and 12,000 MT Bakken acres, which includes about 2,000 BOEPD of production, for $222 million.

      Given activity in MT, doubtful even undeveloped acreage they kept will add significant oil volumes.

      As for ND, now less than 19% of CLR acreage would be classified as undeveloped, after this sale.

      Given amount received for sold acreage, clear it is not “core”.

      Also, note comments on Seeking Alpha by a poster named “deadshot7” Claims companies are cramming way too many wells into drilling units, sole purpose to satisfy Wall Street.

      Looks like Bakken is running out of “core” locations.

      • Reno Hightower says:

        Interesting Sand

        So with that said, has the Bakken peaked? If not, what do you think its peak will be?

        • shallow sand says:

          Reno, I think Bakken would need a pretty big burst of completions to pass it’s peak. I don’t know, I am not good at predicting those things.

          I would also highlight, that despite getting all the hype, hz Spraberry is not all it is cracked up to be IMO.

          Proponents have been pointing to increasing well productivity. I do acknowledge that, but also would note:

          It appears to me 2,017 hz wells with first production of 1/1/2014 or later are Spraberry.

          Production information through 5/16, so wells have 17 months or less of production.

          Despite that, 806 of the wells produced LESS than 3,000 BO in 5/16.

          39 of the wells have cumulative of 200K+ BO
          588 of the wells have cumulative of 100-200K BO
          1,390 of the wells have cumulative of 1-100K cumulative BO

          As Art Berman says, the Permian story is all about vastly more locations, not about well productivity.

        • Dennis Coyne says:

          Hi Shallow sand,

          I am also not good at predicting the future.

          The scenario below assumes the 2015 average well represents future Bakken average wells until June 2017 and then EUR gradually decreases at an increasing rate until June 2018 and then EUR decreases at 3.5% per year while 132 new wells per month are completed, as completion rate decreases EUR decrease slows in proportion (if 61 wells/month are completed the annual rate of EUR decreases falls to 1.75% per year). It is also assumed that Brent oil prices rise from $50/b to $105/b(in 2016$) from 2016 to 2020, output reaches to near the previous peak (1160 kb/d) and total ERR to Dec 2040 is about 8.5 Gb with a total of 30,700 wells completed in the ND Bakken/Three Forks from 1951- 2041. Note that the 2015 average well EUR estimate is about 330 kb over 23 years and the 11,050 wells completed through June 2016 will produce about 3.7 Gb (about 1.8 Gb produced through June 2016). Based on this scenario the 19,650 future ND Bakken/TF wells will produce about 4.8 Gb or about 244 kb per well on average. Clearly such a scenario is highly speculative.

      • GoneFishing says:

        That total area is bigger than the state of Rhode Island.

        • shallow sand says:

          The square mileage of Rhode Island’s land area is just 1,045. McKenzie County, ND square mileage is 2,861. Mountrail County, ND square mileage is 1,942. Dunn County, ND is 2,082. Williams Co., ND is 2,148. (All per Wikipedia).

          • GoneFishing says:

            I was talking about the industrial oil development area, not county size. It’s still just one company developing a 32 by 33 mile area.

            In total more than 11.500 square miles have been taken by oil and gas drilling in the US. That is about the size of New Jersey and Delaware combined.

            Add another 13,500 square miles disturbed by surface mining in the US.
            Of course this is small compared to the 1.5 million square miles of farms in the US. That is about half of the land area in the contiguous US. So the farmers and ranchers own half the contiguous US. ( I don’t count water area).

      • John Keller says:

        Thanks for pointing that out. I went and read all of Deadshot7’s posts on Seeking Alpha. I would suggest for everyone on this board to do it. He should post over here. As has been discussed by many industry veterans here, the claims by the shalies don’t match reality.

        • shallow sand says:

          John Keller.

          Are you familiar with Citation?

          Do you agree with me it is interesting that they are selling out of an XTO high density drilling unit in the Bakken, and that the listing is on the internet auction?

          Speaking of Citation, I know they own a lot of interests in long producing, low decline fields. What is really telling is to look over their website, and then look up some of the leases/units they operate.

          The cumulative production from some of these old leases/units is staggering.

          Also interesting to me that, unlike Continental Resources, although they were in the ND Bakken, they did not get into the Bakken boom.

          Citation’s website indicates they produce 31K Bopd and 32K mcfpd, with 90+% of production PDP. I wonder what their debt is? It would be interesting to compare this to CLR. I would say Citation and CLR were peers pre shale boom.

          Clearly, CLR has a much bigger market cap than Citation, but will be interesting to see how this plays out in the long run.

          • john keller says:

            I’m not familiar with Citation. I have not followed internet or other smaller sales in the Bakken other than what I’ve read from your posts. I read through all of Deadshot7’s posts and found them very interesting especially as they related to EOG, CLR and wells in the Bakken. They further confirmed suspicions that a good chunk of the shale/LTO industry are nothing more than stock promotion schemes. High density drilling to increase production at the expense of profits. Combining his posts with yours and some of George Kaplan’s mapping, it seems the Bakken’s best days are behind it.

    • George Kaplan says:

      It appears I don’t know my R’s from my elbow (or at least D’s). The areas above should be 4 times higher – i.e. about 120 km^2 or about 30000 acres per grid square, and minimum spacing at around 150 acres per well, only 12% is more concentrated than 600 acres per well. Those numbers still don’t mean anything to me but I think they are more in line with what companies are saying. And nobody got my DUC pun, which I worked on with more than one beer? And I spell shore instead of sure – wow.

  22. AlexS says:

    Iran’s Crude Oil Exports Above 2.1 Million Bpd In July

    DUBAI, Aug 17 (Reuters) – Iran’s crude oil exports in July were more than 2.1 million barrels per day, the oil ministry’s news agency SHANA cited a senior Iranian oil official as saying on Wednesday.
    Director of the International Affairs Department at National Iranian Oil Company (NIOC) Mohsen Ghamsari told SHANA the total amount of crude and gas condensate exports by Iran reached 2.740 million bpd in July. He said 600,000 bpd out of that figure were condensate exports.
    “Exports of crude are now at a good level but … have not yet touched that of the pre-sanction level,” he said, adding that Iran used to export 2.350 million barrels of crude per day before international sanctions were imposed.

  23. GJ says:

    Nat gas storage added 22 Bcf last week vs. 27 estimated, vs. 57 Bcf 5-year average. Sixteenth week of below average build. Slowly chipping away at the oversupply. Keep in mind the “oversupply” is the 5-year average, the US burns a lot more natural gas now than 3-5 years ago for power. I would imagine the drillers in the Utica and Marcellus will put rigs back to work shortly.

  24. Doug Leighton says:


    16 December — As the price of Brent crude fell below $60 for the first time since 2009, the most powerful nations in Opec have made clear that they are willing to push prices as low as $40 a barrel in their bid to take on Russia and US shale, a high-profile Gulf oil minister said this week…Suhail al-Mazrouei, energy minister of the UAE, said that the organisation will let prices fall by more than $20 per barrel before they consider an emergency meeting to cut production…”We are not going to change our minds because the prices went to $60, or to $40,” he said.”

    • Watcher says:

      Suppose they cut production and there’s no surplus when they do it?

      Someone doesn’t get an order filled. And somewhat instantly.

    • Nathanael says:

      Well, the UAE can survive at $40/bbl, maybe even at $20/bbl.

      Below $40/bbl gasoline cars actually become competive on fuelling cost with electric cars (using average electricity prices). So maybe they know this…

  25. Chart Monkey says:

    Canada – JODI-Oil World Database – Closing Stocks for both Crude and Products
    Not much sign of drawdowns due to the wild fires. I don’t know, maybe they don’t store bitumen in these tanks? Products dropped around 7 million barrels in May.

    Another oil market balance chart on Twitter, ANZ Research

    • Chart Monkey says:

      Canada version 2, sum of Crude Oil plus Total Oil Products Closing Stocks to see the trend.

      Also, new Canada oil projects 2016 to 2020 – Merrill Lynch
      Chart on Twitter:

      • George Kaplan says:

        What are the four blocks in 2020 supposed to represent? So far unapproved optimisation on previous projects, or are there missing parts of the legend?

        I think Rystad figures are better and represent ramp up times rather than just start up:

        Note neither of these show Hebron that starts late 2017 and ramps up to 135 to 150,000 bpd through 2018 and 2019. For Rystad this is OK as they are only considering tar sands but Merrill Lynch figures are for Canada. For completeness they should also include Lloyds heavy oil in Saskatchewan – 25000 bpd this year.

        Although approved, I don’t think either Pike or Leismer expansion have reached FID so meeting start up before 2020 would be difficult.

        • Chart Monkey says:

          Very good article, thanks

          • George Kaplan says:

            OK but do you understand that Merrill Lynch chart, there are 13 blocks but only ten legend entries. It looks like the 2020 entries are: yellow – Horizon, but after phase 3 next year there are no more phases there so maybe optimisation; blue – Fort Hills, there is a debottlenecking project approved by the regulators , but not funded; light green – unknown but maybe Christina Lake phase G or H neither funded yet, bluey grey – Pike approved but no FID. My assumptions may be wrong, it’s a crap chart either way, but more than that those projects are unlikely to get funding until oil is above about $80. Debottlenecking may be reasonably quick (say 2 years) depending on what is involved, if there is big capital outlay for processing plant it could be 4 to 5 years.

            • Chart Monkey says:

              I don’t understand the Merrill Lynch chart. I was surprised to see so many oil sands projects still ongoing. Good to see Rystad Energy has an article about them.

    • “Bitumen” isn’t stored. At best they have to make a heavy diluted crude blend, say 16 degrees API. That should be pumpable in summer time.

  26. Watcher says:

    The issue of the majors fleeing shale. It’s curious that they didn’t trash the numbers publically. Lots of good things happen when companies’ stock crashes and they get desperate for cash.

    OTOH they all sharply reduced investment in Feb 2014, 6 mos before the price crash, so maybe they not only didn’t invest in shale, they didn’t invest in anything.

  27. Amatoori says:

    Rig Count is out +10 oil. Referring to the discussions above looks like only place that adding rigs are Texas/Permian, 7/10 there.

    Gas price is still struggling IMO, very low injections and rigs are not being added (-5 Canada). Surprise me a bit.

  28. SatansBestFriend says:

    Obviously, Satan will win the ultimate battle between good and evil..DUH!

    Me think no one understands USA medical industry is about to blow sky high due to Algebra. 1.3 trillion @ 9 percent compounding.

    Carl is a climate change denier, peak oil denier….but he is very talented financially.

    Want to bet?

    • DDD says:

      What are Karls view on the oil dilemma in general?

      • SatansBestFriend says:

        Karl thinks USA should convert to CTL/GTL/KTL. He thinks you can create Thorium/Nuclear reactors that all do the Fischer Tropsch process and use hydrocarbons (any type) as feedstock.

        Karl thinks anyone who disagrees with him should go to jail (over exaggeration…but close). He is a catholic who likes the laws of thermodynamics (doesn’t make sense to me….how could the holy trinity work? ).

        But his financial stuff is really good. His understanding of the climate not so good.

        Sorry…I should have posted this in the other thread.

  29. Chart Monkey says:

    Saudi Arabia – JODI – Closing Stocks for Crude Oil and Total Oil Products – June 2016
    I’ve tried plotting Crude Oil and the sum of Crude Oil+Total Oil Products just to see if it’s any easier to see the trend?

    JODI – Closing Stocks for Crude Oil for the countries listed, with and without the USA
    this link:

  30. GoneFishing says:

    Four Corners aerial sensing of methane hotspot discovers multiple sources (250) mostly related to natural gas extraction. The hot spot was previously discovered by satellite imaging.

  31. Chart Monkey says:

    43 Countries – JODI – Closing Stocks for both Crude Oil and Total Oil Products
    From March 2011 to May 2016 (India started participating in March 2011)
    I’m only looking to see if there is a trend
    Countries list…
    Australia Austria Azerbaijan Bahrain Belgium Brazil Brunei Darussalam Canada Chile Chinese Taipei Czech Republic Denmark Ecuador Finland France Germany Greece Hungary India Iraq Ireland Italy Japan Korea Mexico Netherlands New Zealand Nigeria Norway Peru Philippines Poland Portugal Qatar Saudi Arabia Slovakia Spain Sweden Switzerland Thailand Turkey United Kingdom

    Producers – JODI – Closing Stocks for both Crude Oil and Total Oil Products
    Algeria and Angola have a few gaps in their data which I filled with the averages from the adjacent months. Azerbaijan and Qatar don’t have data for June and so I copied their May figures.

    • John Keller says:

      Charts like this support my belief that the crude glut was never as big as analysts claimed. Stocks in these countries is about 100million barrels greater and the 2011-2014 averages. I realize that other countries have increased inventories as well, but demand is higher so more stocks are also needed. I expect Brent to keep rallying and to pull WTI up with it. Brent is moving into backwardation. Setting the ramp up do to summer season aside, the Saudis have been selling 300kbd more than they have been producing. A good chunk of Iran’s production increase has come from stocks. Nigeria has lost about 700kbd from attacks and has depleted its inventories. So, the world will be getting about a 1 MMBD+ cut in supply during the second half of 2016 as demand heads higher.

  32. Chart Monkey says:

    Bloomberg – Pemex Woes Snowball as Cash Crunch Deepens Production Plunge – August 18, 2016
    Pemex has had cash flow shortfalls for the past three years, and this year the gap will almost double to a record $22 billion, from $13 billion in 2015, according to data and estimates compiled by Bloomberg.

    The company’s total debt has ballooned to almost $100 billion, and it may lose its investment-grade rating from Moody’s Investors Service.

    Pemex forecasts production to fall to about 2.1 million barrels a day this year, which the company aims to stabilize and slowly increase in the following years.

  33. Fred Magyar says:

    LOL! Dennis, you can shut this site down now, ‘Peak Oi’l like climate change is just a hoax!

    Abiogenic Petroleum: Peak Oil and “Fossil Fuels” – Debunked

  34. Chart Monkey says:

    Bloomberg – Iraq Will Boost Oil Exports This Week After Agreement on Kirkuk – August 21st, 2016
    Iraq, OPEC’s second-biggest producer, will increase crude exports by about 5 percent in the next few days after an agreement to resume shipments from three oil fields in Kirkuk.

    “Pumping operations started with test pumping at 70,000 barrels a day last Thursday and the Northern Oil Co. aims to boost it to its normal rate at 150,000 barrels a day this week,” Hussein said. “This is a good step and significant initiative to strengthen relations between KRG and the federal government.”

  35. Chart Monkey says:

    I’m not sure if this is of any interest to anyone…

    EIA – Weekly Supply Estimates – Closing Stocks – June 2010 to August 12th, 2016
    Weekly U.S. Ending Stocks of Total Gasoline + Distillate Fuel Oil + Kerosene-Type Jet Fuel + Residual Fuel Oil
    Weekly U.S. Ending Stocks excluding SPR of Crude Oil (Commercial)
    Weekly U.S. Ending Stocks of Propane and Propylene + NGPLs LRGs
    (NGPLs LRGs = Natural Gas Plant Liquids and Liquefied Refinery Gases – data starts from June 2010)
    Weekly Mont Belvieu, TX Propane Spot Price FOB (Dollars per Barrel)
    Cushing, OK WTI Spot Price FOB (Dollars per Barrel) – Weekly

  36. Chart Monkey says:

    U.S., European, Singapore and global floating oil storage levels all fell last week – SEB (A bank in Sweden)

    • GoneFishing says:

      Looks like stocks are 30 percent higher than in 2014. Cheap fuel getting bought up and stored or flattening demand despite increase in Asian driving?

    • AlexS says:

      ” global floating oil storage levels all fell last week ”

      Isn’t a decline in stocks in August a normal seasonal pattern?

  37. shallow sand says:


    Texas has June production out.

    Would be interested in Dean’s analysis, if he is still doing that.


    • Dennis Coyne says:

      Hi Shallow Sand,

      Probably not until next Monday, but I will post Dean’s chart in the new thread later this week, if he sends them.

  38. GoneFishing says:

    Any validity to these claims of future refinery bankruptcies?

    “The RIN market will cause a number of refinery bankruptcies…The domino effect of this will be that ‘big’ oil will sop up the bankrupt refineries, causing an oligopoly resulting in skyrocketing gasoline prices.” Icahn wrote in an Aug. 9 letter to Environmental Protection Agency administrators …”

  39. George Kaplan says:

    For what it is worth I finally got the chart for Bakken to work in colour at less than the size limit (note Excel for Mac adds shadows to data points whether you ask it or not but doesn’t indicate so – to remove you have to artificially add then remove shadows on each data set. No legend as that exceeded the size.

    The yellow are all active or confidential wells since 2000, the red diamonds are dry wells since 2000, the small orange dots are dry wells 1972 to 2000, the brown triangles are DUCs, the blue squares drilling and the small green squares are open permits.

    I think the drilling and permits are moving west and south. Most of the core areas to the east have densities of 150 to 200 acres per well if you include active wells, confidential, DUCs and drilling – i.e. there isn’t room for any more. The drilling locations and permits are almost all in areas with well density already higher than 600 acres per well – i.e. the peripheral areas within about 5 or 10 km of the dry wells band are not being exploited.

    The symbols may show more than one well on top of each other, usually because of a well pad – e.g. the drilling locations represent 76 wells but typically are in blocks of 4 to 10 on each well pad (DUCs are similar – all wells on a well pad are left uncompleted together).

  40. George Kaplan says:

    I also looked at the history for how the DUCs have grown. I thought there might be a pattern as to what is being completed and what not, but it’s not so obvious. The problem with some of this is that all the Confidential wells can hide any trend over recent months – i.e. in the chart below there are 653 “NC” wells from the data base, but there should be about another 190 or so confidential. There doesn’t seem to be much to pick out except that all the operators started to leave wells uncompleted at about the same time and all the major players have a large inventory (27 for QEP up to 150 plus for Continental). As they are mostly still completing some wells it would be reasonable to assume those left are not the best (e.g. either costly to complete and/or not expected to be the most productive).

    • Enno Peters says:


      Even for confidential wells, the spud date is filled in. You can use that to find the other ones, as all DUCs have at least been spudded.

      • George Kaplan says:

        Enno – thanks. On my download not all confidential wells have spud dates, and I think confidential wells could be completed and producing as well (for up to six months is it?) and they could also be plugged and abandoned or even PNC at some point. I’m not sure of the timing or requirements of when they have to be released from tight hole status, but I can’t see a way of identifying DUCs until they are released.

        • Enno Peters says:


          In my understanding, all confidential wells that do not have a spud date, are not yet spudded, and therefore not DUCs. They are just in the permit stage.

          Confidential wells, with a spud date, and with production reported (using runs or gas sold), are flowing. The ones with a spud date, but without production, are DUCs (or SP[udded]UCs..) .

  41. Watcher says:

    In the context of . . . if you have to have it, you will get it . . . do we have solid estimates of ultimate possible recovery regardless of economics?

    Given KSA is the #5 oil consumer on earth, and growing sharply (they will almost certainly surpass Japan this year to be #4), when the time comes that they no longer export (i.e. consume all they produce) just how much can they get out of the ground to feed themselves?

    There are other places of this sort. Any producer that consumes all their production would care about this. That would be the US and China, and India, Egypt, Thailand, Argentina, and Brazil — and others. Anywhere that consumes all they produce will eventually not care about economics, because they HAVE to have it.

    So estimates of non economical total are pretty important.

    • Nick G says:

      if you have to have it, you will get it

      They don’t have to have it. There are better substitutes, especially when prices rise above, say, $80 per barrel.

      KSA, for instance, is already using more per capita than almost anyone. Solar power would be far, far cheaper than burning oil for electricity. They’re being stupid now, to not build a lot of solar. But…to ignore solar when net exports were approaching zero? That would be utter, utter insanity.

      • R Walter says:

        You are an ‘oil have to have it’ denier, you are in denial.

        Much like a climate change deniers.

        Oil is essential, can’t do without it.

        160 years ago it was a different story, but not today.

        In the post- modern era, oil is the lifeblood of global survival.

        • George Kaplan says:

          How much oil did Cuba survive on after the USSR collapsed and before Venezuela starting helping out? (That is a genuine question, not trying to make a point.)

        • Nick G says:

          In the post- modern era, oil is the lifeblood of global survival.

          No, it’s really not. This is a myth – that oil somehow has supernatural powers.

          Roughly half of all oil is used for personal transportation, which obviously can be replaced by EVs, and it would be cheaper than oil.

          Commercial transport includes trucks, which can move to rail, electrify with swappable batteries, or use synthetic fuel. Water transport can do the same. Air can go to synthetic fuel, which uses existing chemistry – it’s more expensive than oil (if you don’t include the external costs of oil, such as security of supply and pollution) but it would be affordable.

          Petrochemical feedstocks can use fossil fuels with no necessary pollution for many years, and then move to carbon from other sources.

        • Nathanael says:

          It’s magical thinking to imagine that oil is a magical substance which you must have. It isn’t.

          Neither is anthracite. Remember that Hubbert based peak oil theory on peak anthracite theory. I do just fine without anthracite, though it’s pretty.

      • clueless says:

        Nick says: “KSA, for instance, is already using more per capita than almost anyone.”

        Is that really true? Does that include all the amounts that run through its refineries and chemical plants for export? I casually observe that Iran, with many more people, uses much less. Iran has no substantial refineries, etc. But, they appear to have much more military/industrial capability.

        Maybe someone here knows of a reference that discusses the uses of oil by KSA viz-a-viz the uses by Iran. My personal prejudice is that with the removal of sanctions that much of Iran’s production increase eventually will be gobbled up by domestic use – their population seems to be too large for it to be otherwise.

        • Nick G says:

          Does that include all the amounts that run through its refineries and chemical plants for export?

          It just includes domestic consumption. Iran prices gasoline somewhere near it’s market price, while KSA greatly underprices it for domestic consumers. Iran uses a lot of CNG for personal transportation, I believe.

          KSA uses oil for electrical generation, which is ridiculous – it’s far more expensive. But, that’s the political power of legacy industries…

          • Nathanael says:

            OK, so KSA is basically just being a bunch of complete dumbasses. This doesn’t surprise me.

  42. Rune Likvern says:

    I have a new post up on Bakken. It looks at Bakken as one entity and a closer look at EUR (for wells) and the R/P ratio (which is an important metric).

    • clueless says:

      I appreciate your “vicious dynamic” illustration. However, I would like to point out another hypothetical. If oil were to rise again, to the $110 you used, and if a new average well well could be completed for $6 million, then that new well would pay for itself, and have a significant amount of profit left to pay off debt from older wells.

      If I were a bank and an oil company, that would be my prayer.

      • Daniel says:

        Only issue with this is that it will no longer cost 6 million to drill this well. The cost inflation the industry will experieince will be monumental. The cuts by operators and service companies have juzt been too deep this time to be able to react to any meaningful uptick in activity

        • Rune Likvern says:

          Then add that the sweet spots are about saturated and near future wells on average likely will be poorer.

          • Nathanael says:

            Add to that that oil *cannot* go to $110 for long, because well before it reached that price, there would be massive demand destruction by people switching to electric cars, trucks, heat pumps, etc… all of which would be massively cheaper than continuing to use oil.

            We’re already going to see the beginnings of demand destruction in earnest by 2018. I’m not sure how fast demand destruction will go after that, but a high oil price at that time would accelerate the process massively. It can’t be sustained.

      • Rune Likvern says:

        My article says that at $100/bo (as from Jul-17) the population of wells per Jun-16 will give a return of 7%.
        In other words, they would then not need any support from new wells.

        • Chart Monkey says:

          Thanks for the articles, written to a high standard – like reading a textbook.

Comments are closed.