Brazil: Reserves and Production

Guest Post by George Kaplan

Brazil is a major oil producing country, but in 2016 was still a net importer, though imports dropped significantly and they have been a slight exporter overall so far this year. It is one of the few countries that have consistently grown production over recent years, and possibly the only non-OPEC country that will show overall growth of conventional crude in the ten years to (say) 2022.


Brazil ANP or anp (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis) publishes Excel files for monthly production on all wells. In theory it should be easy to extract field data from these, in practice not so much. The files are downloaded from a database but not always consistently, sometimes in field units sometimes SI, sometimes one month per file sometimes more, around 2010 onshore and offshore was split but naming conventions weren’t always followed, handling of wildcat wells seems a bit arbitrary, and spelling conventions can change. However after more effort than I expected I did download the data and split it by basin and field.

The total production fits Jodi data well except for three periods: 2005 when the reports stated, and doesn’t make much difference; 2010 when ANP split offshore and onshore reporting and the well files are a complete mess; and 2017, which may indicate that some of the data is revised (this should become evident as more releases are made over the next months).


Land based production is a small component at about 130 kbpd. It averages over 90% water cut (and increasing) and is in long-term decline at over 9% per year (which also appears to be increasing recently). Petrobras is trying to sell off some of their holdings.

The gas and oil rigs combined for onshore and offshore are also shown. The majority is oil rigs for both off and onshore. It is interesting that their numbers started to decline in mid-2012 when oil prices were high and rising. I don’t know the reason – could be to do with the financial and political problems in Petrobras, or associated with geology (i.e. a lack of exploration targets and development projects, which is probably the case for onshore drilling), or a move from many smaller shallow fields to fewer deep and ultra -deep rigs offshore.

The locations of the basins are shown here:


Most of the production to date has come from the Campos basin (Campos actually just means fields in Portuguese). It and Espirito Santo are older basins now in decline at about 9% per year, combined. The big recent additions have been in the Santos basin, particularly Lula (which was Tupi at one time) and Sapinhoá. Note that gas production is not considered here though there are significant gas or gas/condensate fields in these basins, such as the Jupiter field. The charts below show C&C production from individual fields within Campos, Santos and others offshore. There isn’t enough detail to show much of interest, but they are quite colourful.




Most of the offshore production comes from large FPSOs, but there are shallow water platforms in smaller fields. Each of the larger fields in the charts above would have one to three FPSOs. Historically the FPSOs seem to start declining after about a six to twelve-month ramp up period. There are few showing any long plateau periods, though this may be different for Santos. Decline rates can vary from 5% up to 20% per year – i.e. to maintain production in a basin new FPSOs need to be continually bought on line.

Water cut seems to be the biggest impact on decline rates. Campos and Espirito Santo started to decline once water cut hit 50%, and it is still rising in both. Santos fields seem to be low in water at the moment.



ANP provide reserve data following SPE guidelines, however they seem to give only 1P, 3P and 1C numbers in their bulletins – i.e. providing upper and lower limits but not an expected 2P number. They give all numbers to six significant figures, so I guess they must be right. The stacked chart below shows the history for 1P and 3P crude and condensate reserves by state. Almost all the reserves are offshore in Rio de Janeiro and Espirito Santo States – i.e. the Campos and Santos basins. Note I could only find 2016 data by basin, some basins (e.g. Campos) split across two states so I pro-rated numbers bases on 2015 figures – the totals remain as given by ANP.

There was a big hit to reserves in 2015. This may have been partly price related but Forbes reported Petrobras as saying “…decline in reserves was due to other factors, primarily revisions of well estimates at its pre-salt sites offshore.” In the context of the article the word “other” used there makes no sense, so there’s still some ambiguity.


Future Projections

From the 2016 reserves bulletin I estimated remaining recoverable reserves assuming 97% of 1P (which equals P1) and 50% of P2 plus P3 (which equals 3P minus 1P), as below. I didn’t use 1C numbers but include them to show there isn’t a huge upside there (these should be less than 10% probability of production). Numbers shown are mmbbls, converted from Mm³ used in the ANP report.

1P 3P 1C 2P (Calculated)
Santos 6,116 12,621 1,945 9,185
Campos 5,741 8,733 2,479 7,065
Total 12,666 22,742 4,579 17,324
Others 809 1,388 155 1,074

I fitted Verhulst equations for each of the three categories (Campos, Santos and others) based on the production data from 2005 till now, and ensuring the remaining production (out to infinity) equaled the numbers calculated above. I also added a guess at Libra production assuming 6,000 mmbbls (a bit less than the 8,000 sometimes reported, but then there hasn’t been any production yet and it looks like their other pre-salt fields might not be as good as originally thought, and some of the reserves are already included in the ANP Santos numbers). To match the profile shown they would need to be approving major FPSO and drilling budgets next year, so the profile shown may be unrealistically aggressive as the Libra extended well test project hasn’t even started yet.


(Sorry about the random changes in units.)

An alternative view of the future is to look at bottom up projection based on the projects identified by the E&P companies. Below shows such a scenario. Only the projects up to Bezios 4 have been approved and are under construction (plus possibly Peregrino, although I don’t think there has been a formal FID). After that the capacities (shown as kbpd nameplate after the project name) and start up date are guesses. Most of the projects are in Santos but some (e.g. the Marlim revamp) are in Campos. Some have been cancelled, so I’m assuming these would be revived given high enough prices.

Meeting this schedule for new projects in 2020 to 2023 is now unlikely. For Campos Petrobras use cloned FPSO designs that can be built in around three years, but these may not be suitable for the need for gas reinjection and ultra deep wells in Libra. They currently have higher priorities than development, in particular reducing debt (their interest is $6 billion per year), so other E&Ps would need to get involved. The developments also need latest generation drilling rigs and for Libra would be waiting for initial extended test results from the pilot projects. Petrobras vessels also have a history of major lost time incidents; only one or two such would knock production down considerably. While cloned designs reduce costs they can incur common mode failures; for example as all the gas injection risers on recent FPSOs seem to be seeing (pretty much the highest risk component on any offshore development) and such failures may also produce large downtime across several facilities.


Near term these projections are in-line with IEA (from OMR, June 2017): “In all, Brazilian production is forecast to increase by 190 kb/d in 2017, with gains ramping up to 260 kb/d in 2018.” The EIA STEO also has projections for Brail, but includes ethanol, which is highly seasonal and makes the numbers difficult to follow.

For longer term the new Santos pre-salt fields are the big hope. Lula is in production and Libra is being developed. Libra was discovered in in 2010 and may have up to 8 to 12 Gb recoverable, but it is expensive oil: ultra-deep, difficult wells, 40% carbon dioxide content in sour gas. The high CO2 means the gas has to be reinjected and provides pressure support, but even with this, extensive gas treatment facilities are required on board the production facilities. A consortium of companies won the rights to development, comprising Petrobras (the operator), Shell, Total, CNPC and CNOOC, They are starting with smaller developments to find the problems. To save money, I’ve seen that they are looking at combined water and gas injection, which may not be ideal for the reservoir and introduces hydrate risk.

There have been reports that there may be over 100 Gb other oil in the pre-salt play (unrisked), but there is little current exploration – in addition to the price collapse, possibly because of Petrobras finance and corruption issues, or waiting for results from the initial Libra production tests or for help from outside interests (e.g. Statoil, ExxonMobil, Shell, Total, CNOOC, Repsol etc. are invested or looking to invest there). There have been other fields discovered in Santos, e.g. Iara and Iracema in 2008/2009, but there were also a number of high profile dry wells (i.e. expensive and operated by IOCs) in the basin in the years between the Tupi and Libra discoveries, and not much positive news since Libra, with some leases being given up even in the high price years. In addition the Santos basin geology is somewhat mirrored offshore Angola in the Kwanza province, which has proved pretty barren (and expensive) for the E&Ps. BP recently took a $750 million write-off against dry wells and lease costs there and have given up all leases. Other majors, including Statoil and Total, haven’t done much better. Cobalt (Cameia) and Maersk (Azul) seem to have the only announced discoveries there, but there’s been little news on developing them; Cobalt is in litigation and Maersk has gone very quiet on Angola in general. There are differences with Brazil though, e.g. Santos is deeper and would have a better chance to seals the oil traps.

So overall does this indicate a coming Brazil peak? Probably yes near term, say around 2019/2020, but only more exploration and development will tell whether that could be exceeded again longer term. Statoil plan to be drilling wildcats later this year, the 14th bidding round has four significant offshore blocks up for lease starting in late July, but such things seem to go very slowly in Brazil: another Libra or another Kwanza – who knows, until they drill?

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421 Responses to Brazil: Reserves and Production

  1. Watcher says:

    I wonder what happened to that dood who posted here some detail on the software for seismic imaging past salt domes, which in the past had prevented such things. The focus was Brazil in what he was talking about.

    Brazil’s oil consumption was down last year amid their political disaster and an ongoing GDP recession dating to 2014 (appears derived from a Volker-like 10+% interest rate CB-imposed to crush inflation, now down to 4%). That is pent-up demand coming. GDP growth was 1% Q12017, with the CB cutting rates, most recently May 2017 (albeit “down” to 10.25%).

    Oil is 8% of GDP. GDP dominated by their powerhouse agro industry in the Matto Grasso. When oil scarcity starts generating wars and starvation, Brazil is where people should go.

    • GoneFishing says:

      It was not long ago that the Matto Grosso was one of the last truly wild places on earth. Explorers often did not come back out of there.

    • Fred Magyar says:

      Oil is 8% of GDP. GDP dominated by their powerhouse agro industry in the Matto Grasso. When oil scarcity starts generating wars and starvation, Brazil is where people should go.

      It’s Mato Grosso… and what makes you think Brazil will welcome all those starving refugees with open arms? Especially refugees of the ‘Gringo’ variety. Hey maybe they will limit immigration from certain countries and impose a travel ban! MBGA!

      On the other hand Brazil has recently impeached one corrupt president, tried and convicted a previous one, is in the process of trying a third and has been vigorously pursuing corrupt businessmen and politicians and putting them in jail.

      However they do consider Health Care a universal right and it is written into the Brazilian constitution. Maybe the US could learn a thing or two from the Brazilians!

      • OFM says:

        Hi Fred,
        If I were a Brazilian, I would advocate sharply limiting immigration into my country, so as to better preserve it from the ravages of ill considered development.

        I would also prefer to see the economy developed in such a way that the country is as REASONABLY self sufficient as possible in terms of manufactured goods, investment money, etc, so as to better preserve the environment.

        There’s WAY MORE to be considered than just simple minded arguments about greater prosperity being associated with greater trade.

        If Brazil winds up gut hooked on exporting agricultural goods, like a fish that has swallowed a baited hook, the result will be the destruction of what’s left of the Amazon rain forest, etc.

        Forgoing so much international trade in agricultural products means less overall prosperity NOW of course but it can also mean a FAR HEALTHIER and FAR MORE PROSPEROUS Brazil a few years down the road.

        How about translating MGBA into gringoese for those of us who don’t know the prevailing lingo ?

        I am impressed with just about every thing I hear about Brazil, with a couple of exceptions. One is public corruption, but progress is being made in that respect.

        The other is that a lot of people appear to be getting treated VERY poorly indeed, especially the original peoples who live in the wilder areas, and laborers on giant farms, but I am not very well informed about these issues.

        Any reply placed over in the not petroleum thread will be appreciated.

        • Brazil is accepting the refugee flow from Venezuela, many of them native indians fleeing Amazonas state. They have 7000 at a camp near the border. I don’t have a head count for flows heading south, but two days ago Colombia reported 26 thousand Venezuelans crossed into Cucuta, the Maduro dictatorship lets them go bacause they are mostly poor people from Tachira, who have been fighting regime forces with a bit more muscle than Venezuelans elsewhere.

          The Campos Basin was named after the town officially named São Salvador de Campos de Goytacazes about 350 years ago, these Indians are better known as the Goitacá nowadays. So the origin of the basin’s name comes from a town named “Sainted Saviour of the Fields of the Goitacá”.

          • Dennis Coyne says:

            Hi Fernando,

            Can you point me to a source for data on Venezuelan output (annual data is all I need) for the Orinoco Belt?

            At PDVSA they claim 1442 kb/d output in 2015 from Orinoco.

            The strategic plan calls for 4000 kb/d by 2019 from Orinoco, this seems highly unlikely.

            Do you know if they have been able to maintain Orinoco output at 2015 levels in 2016? Do you think the PVDSA estimate of 1400 kb/d in 2015 is overstated? And finally does 2000 kb/d from Orinoco by 2020 under an assumption that the political crisis resolved by 2018, seem reasonable.

            I realize that the assumption that the political crisis is resolved by 2018 is not likely to be reasonable.


            • Dennis, there is no reliable data. A couple of years ago I saw two PowerPoint presentations by high level faja managers, and they didn’t show the same production curves. In other words, things are so shoddy even PDVSA managers can’t get their lies straight.

              PDVSA “strategic plans” are never met. As regards conditions on the ground, a few hours ago the boys were laying out how to blockade PDVSA support bases, including those operated by foreign companies.

              By the time this is over it’s possible Venezuela may look a bit more burnt down, because eventually the emerging resistance will start burning the wells.

              • Dennis Coyne says:


                Do you have any guesses for Faja output 1000 to 1200 kb/d maybe in 2016?

                No doubt your guess would be better than mine.

                Would a rough guess maybe be OPEC reported output from secondary sources subtracted from the output reported by Venezuela and then multiply by 0.8?

          • Fred Magyar says:

            Brazil is accepting the refugee flow from Venezuela, many of them native indians fleeing Amazonas state. They have 7000 at a camp near the border.

            True, the Average Brazilian is a lot more compassionate than most politicians and they do have a lot of empathy for the plight of the Venezuelan people. But for ‘Gringos’ not so much…

            I worked in the Campos Basin and know the history quite well.

          • OFM says:

            I fully approve of Brazil accepting such refugees, and of the USA, my own country, accepting REAL refugees.
            What I don’t approve of is accepting enough to significantly accept population now, and in the future.
            We are just about there, in terms of birth rates being low enough in the USA to allow our population to peak, except we take in so many people.

        • David Frankenstein says:

          Make Brazil Great Again!

        • Fred Magyar says:

          I could give a very long response to all your points. The short answer is Brazilians are not stupid and they have some pretty good scientists and engineers and also some of the most corrupt politicians on the planet… but I’m sure you already knew that 😉

          Current President Temer has an approval rating of 5% right now.

  2. shallow sand says:

    Thank you for another informative post!

    • SouthLaGeo says:

      Thanks for another great post, George.
      This puts the Brazil pre-salt in better perspective for me. So do you think Shell’s acquisition of BG was a good deal? The Brazil pre-salt was supposed to be one the big prizes.
      Interesting how the Santos basin production has been increasing over the last few years (perhaps peaking in late 2016?) in spite of low oil prices – similar to the deepwater GOM – Petrobras and other companies made FID commitments in times of high oil prices, and when prices crash, come hell or high water, the projects get executed.

      • George Kaplan says:

        SLG – thanks. I think there was more to Shell buying BG than just the Brazil assets, in particular further diversification from oil to natural gas. I don’t know if they have sold off enough assets fast enough to please the shareholders and they’ve also had some terrible exploration results so it’s difficult to exactly see cause and effect, but I think the BG part in Brazil will work out OK for them.

        Santos growth was really fast, they took on huge debt and are paying for it now, it’s also difficult to know how much corruption influenced the decisions – it looks like a considerable amount (you can’t get kick backs if there are no contracts). The development momentum is a big factor. PetroBras seemed to place rolling contracts for cloned FPSOs and rigs, and maybe it was more difficult and expensive to stop these than on one off projects, though they did cancel a lot of the rigs. Of course the other side of that is what happens when the project pipeline dries up and it takes five years to bring new production on, which I think we will start to see late next year. In the mid eighties crash I seem to remember there were a lot of cancellations of well advanced projects, not so much in the late nineties. Maybe interest rates play a part, or the higher sunk cost for the deep water mega projects.

        I don’t think Santos basin peaked in 2016 – more likely 2018 or 2019, but it depends also on how the extended well tests and pilot plant goes on the Libra field. There are some more data from anp for April and May which show more increase from the dip, though I’ll probably wait to update with June numbers when available.

  3. Glenn E Stehle says:

    George Kaplan said:

    For longer term the new Santos pre-salt fields are the big hope. Lula is in production and Libra is being developed. Libra was discovered in in 2010 and may have up to 8 to 12 Gb recoverable, but it is expensive oil: ultra-deep, difficult wells, 40% carbon dioxide content in sour gas.

    Brazil pre-salt includes many projects that Goldman Sachs says are “so uneconomic, so stranded, that we almost don’t see any scenario under which they would be developed….”

    “Not all projects that are currently in the pipeline will be needed. Shale has substituted the need for a lot of the more complex deep water, heavy oil projects and so we estimate that between $700 billion and $1.3 trillion of projects will not be needed any longer.”

    Lower for Longer? The Impact of the New Oil Order: Goldman Sachs

    • Goldman Sachs isn’t known for their industry expertise. They and Morgan Stanley seem to believe shale oil will last forever. Or maybe they are trying to profit from bonds issued by OPEC nations and oil companies. They have a missing ethics department.

  4. Glenn E Stehle says:

    Brazil has shale potential, but not a great deal according to a study conducted for the EIA:

    Technically Recoverable Shale Oil and Shale Gas Resources: Brazil

  5. name says:

    When will you guys learn that only thing that matters is price per barrel? If you’re interested in Peak Oil, then every article on this site should be about what is the current maximum price of barrel of oil, that won’t trigger demand destruction.
    Please understand that reserves, and resources estimates are laughable, and the only thing that matters is what the economy can pay.

    • Energy News says:

      People just don’t seem to enjoy numbers. Maths was never a popular subject.

    • Survivalist says:

      Thanks for the update doc. You just blew my mind.

    • Watcher says:

      dood, you do realize where dollars come from? and why price therefore has no physical relevance?

      If you quantitative ease dollars into existence in an entirely whimsical way, why would you think they matter to something measured in joules?

    • Hickory says:

      Good points ‘name’less, but the information that you reference [the current maximum price of barrel of oil, that won’t trigger demand destruction] is something no one produce any good data for.
      So we are left with wondering and speculating about it.

    • George Kaplan says:

      “When will you guys learn that only thing that matters is price per barrel.” – maybe when there’s some evidence to support it. If you have some I’m sure Dennis would welcome a post. I’d try to make some constructive comment for you rather than some trite, fact free grandstanding.

      Demand is highly inelastic, supply has a 3 to 5 year delay between project start and delivery, price responds immediately to stock level changes not the other way round: all those say today’s price doesn’t really matter that much.

      Exploration is continuous and continuously more expensive, public companies share price is highly influenced by their reserves, debate about OPEC reserves never stops, France has never produced more than a trickle of oil whatever the oil price (it doesn’t have any): all those say reserves and resources are quite important and far from laughable (whatever you may mean by that, assuming you know).

      • Dennis Coyne says:

        Hi George,

        I believe that he means the estimates of reserves and resources are not very precise.

        Certainly for OPEC resources I would agree, and for much of the World we don’t have a good handle on either conventional or unconventional resource estimates for crude plus condensate, in my opinion.

        Though research that you have done sure helps make things clearer in the Gulf of Mexico and Brazil. We also have good data for the US, UK, and Norway, and perhaps Canada and Mexico. OPEC is a huge problem as far as transparency, a black box really.

        • George Kaplan says:

          But by his assertion reserves and resources don’t matter, only the price, so why should it matter whether they are known accurately, or even whether they exist at all?

          • GoneFishing says:

            Price does not appear to have much of an effect on demand, see my comment below.

            • OFM says:

              Price never has much effect on demand when demand is HIGHLY INELASTIC, by definition of the term.

              Apparently this is a term that is not well understood by the vast majority of people, excepting the handful that have taken a basic economics course.

              The consumer will buy almost the same quantity of a good that displays high price inelasticity, no matter how high the price goes, because he MUST HAVE that good. Milk for the little kids is such a good, and parents will pay any amount for it, up to the limits of their ability to pay.

              But it doesn’t matter if the price goes down to a fifty cents a gallon retail, they won’t buy more milk for their kids, beyond the amount the kids will drink, because it will be tossed out with the trash.

              The demand for my apples is not highly inelastic, because there are many suitable and affordable and readily available substitutes for apples.

              For now, and for some time to come, probably at least a few more decades, NO affordable, suitable and readily available substitute exists for oil in terms of the big picture. Yes, you can buy an electric car, but you can’t buy an electric over the road truck, or bulldozer, or farm tractor.

              Hence the demand for oil is highly inelastic in the short to medium term. The customer has GREAT NEED of his usual amount, but hardly any need at all for MORE, and beyond the amount he NEEDS, he WILL NOT buy MORE , short term.

              What would the average driver do with an extra couple of gallons of gasoline THIS WEEK? Take a forty mile pleasure drive? A few might, but only a VERY few.

              Now if gasoline stays cheap three or four years, the customer may be tempted to buy a BELCH FIRE V8, rather than a more sensible car…….. TIME matters.

              The demand for oil is nearly fixed short term, but it obviously varies over the long term.

              In general terms, the price of oil, short to medium term, is basically determined by the quantity that is coming to market. When producers bring MORE THAN USUAL to market, the price crashes, it’s as simple as that. When they bring LESS, the price spikes.

              When producers over produce, the price will go low enough that enough that some producers EVENTUALLY drop out thereby lowering production, and THEN the price will go up again.

              This statement is entirely justified by what lawyers and judges refer to as the “preponderance of the evidence”, lol.

              Given that most of the oil in the world is controlled by GOVERNMENTS rather than ordinary for profit oil companies, and that governments have other priorities than profit and loss, and that governments are notoriously slow to react to changing circumstances, it can and does take years for them to get around to curtailing money losing production.

              Then there’s the higher priority of WAGING ECONOMIC WARFARE………..

              • Dennis Coyne says:

                Hi OFM,

                In the short term oil demand is inelastic, over the longer term people buy more efficient vehicles and demand becomes more elastic, so over the short term (1 to two years) oil demand is relatively inelastic (though people may vacation closer to home so there is still a small effect), over the longer term (5 to 10 years) demand will respond to higher prices as it did during the 80s in the US.

                • Hickory says:

                  Another way to look at price, demand and elasticity with oil is as a two-tiered system.
                  There is a highly inelastic demand for essential uses such as basic industry, food production, commuting to work, delivery of basic goods.
                  On the other hand there is a type of demand which is very flexible, such as vacation and entertainment travel, production and transport of discretionary (luxury) products, and even commuting in single occupancy vehicles., for example.

                  • Dennis coyne says:

                    Hi hickory

                    I agree with your analysis in the short term of 2 years or less, longer term even the first tier of demand will be reduced as oil is used more efficiently by changing equipment, smaller cars more efficient trucks and tractors a d substitution of alternative fuels such as natural gas and renewable power.

                  • Nick G says:

                    Some industrial/commercial demand is relatively elastic: both container ships and long distance trucking can slow down and dramatically reduce fuel consumption; trucks can add aerodynamic modifications; petrochemicals can switch to different feeds (ethane vs natural gas); plastics users can modify containers, switch to other materials; electrical generation can switch between coal and nat gas; etc.

                    I’d say that an important thing here is that demand elasticity is somewhat non-linear: if fuel prices rise by 10% that doesn’t really get anybody’s attention. If fuel prices double, that will get some users serious attention. For instance, trucking fleets might launch a wholesale aerodynamics modification program.

                    Another important concept is “hysteresis”: efficiency modifications and substitution will stick around even if prices go back down.

                • alimbiquated says:

                  Which is why the US should institute a tax at the pump that increases by two cents a month for a few years and then levels off.

                  • Nick G says:

                    Yes, that has the beauty of getting people plan for the day when taxes are very high, without actually shocking them right now.

                    Of course, everyone has to believe that it will really happen – that’s a tough order.

                    I’d say 5 cents per month for 5 years…

          • Dennis Coyne says:

            Hi George,

            Yes on re-reading the comment you are correct, I initially interpreted the comment as saying that the oil price is important, which I agree with.

            What he seems to miss is that the price is determined by supply and demand, not demand alone. So resources will matter because it will determine supply when costs of production and oil prices affect the economic decisions of oil companies in determining proved and probable reserves.

            Mr Name seems not to understand that production cost and oil price is implicit in the estimates of reserves.

    • Dennis Coyne says:

      Hi name,

      We can only speculate what the demand response will be to higher oil prices, at present there is an excess supply at current prices (high inventories). The data on oil stocks is not very good at the World level so the changes in stock levels are largely unknown (except perhaps in the OECD).

      Can you tell us what the maximum oil price is that will result in demand falling below supply? My guess it is around $90/b, but there are at least as many guesses as there are observers.

      Please enlighten us. 🙂

      • GoneFishing says:

        According to data from the EIA, even with the low prices the last few years, we have finally reached the peak usage of gasoline we saw back in 2007. The high prices and recession caused less than a 10 percent drop in gasoline use. So doubling the price has a small effect and halving the price has a small effect on consumption. Not much linkage there, more likely the steady increase in use over the years had more to do with more population, business activity and more cars than price had to do with it.

        So to stifle demand of gasoline would probably take a large increase in price. maybe up to the $6 to $8 a gallon range. I would say we have no data here. Since it is a necessary commodity, people and business will give up other things and delay other purchases before really reducing their consumption of fuel.

        No one really knows the breakpoint for the price of oil. If they do, they are keeping quiet. All we think we know is that oil production will eventually fall at these prices and maybe even at higher prices. We also do not have a case to examine where oil production was not subsidized.

        • twocats says:

          Agreed. the system in most cities doesn’t really encourage reducing fuel consumption with even significant fuel price rises. If you have a car you are already paying insurance (and possibly car payment) whether you use the car or not. If you want to take public transportation the most affordable option is typically the monthly pass, and even then it is usually a significant cost ($90+). So you are committing to not commuting by car for the entire month. You are probably saving money (if fuel costs are high and assuming some wear and tear) but if the time difference to commute is significant its not a high savings per hour.

        • Nick G says:

          Long term demand elasticity is higher than short term. And…substitutes are improving…

    • What counts is return on capital employed. That in turn is influenced by costs, taxes, production profile, financing costs, and risk. Focusing on price only can bankrupt you in a hurry.

    • OFM says:

      Yep. I can sell nice red oak logs for five hundred dollars EACH- except I don’t have any big ones, lol.
      The red oaks will grow back , EVENTUALLY. I didn’t harvest the ones on my property, but my grand parents did. I won’t live to see the ones I have reach maturity, that will be another fifty years plus.

      Oil is a depleting one time gift of nature, and it will never sell , over the medium to long term, for less than it costs to get it out of the ground and get it to the nearest refinery. Oil does sort of “grow back” but it takes millions of years, lol.

      And on average, the cost of every new barrel coming to market is going up, rather than down.
      Oil won’t stay cheap unless the electric vehicle market goes NUTS, and sooner than most people think it can.

  6. MASTERMIND says:

    The name Elon Musk has been well chosen; it defies categorization as to race, class, religion, etc.Ever met or even heard or read of an Elon, or a Musk? So rare a combination as to have no established profile.

    People of a certain kind, created in large numbers by our education system, can project themselves onto the Elon image, and feel very pleased with themselves:‘He’s young, cool, hopeful, clever and rich, cosmopolitan just like me,and will take us to another world now this sad old mud ball is nearly finished!’
    We are witnessing one of the most brilliant propaganda creations, appropriate for late-stage industrial, mass, civilization!

    It’s really quite staggering that the propaganda and mind-conditioning system is projecting Elon Musk as the man to solve ALL our problems, and that this is being pushed energetically on children in school

    The Soviet Union could not have done better: it’s Uncle Joe Stalin – he’d even pop up and fix your car if it broke down, with a cheery smile and a ‘No problem, Comrade!’ as he lit his pipe and waved you on your way.

    The majority of people are so historically ignorant -and have been kept so – that they can’t see this for what it is.

    • GoneFishing says:

      Oh come on, that is a bit over the top. Everyone knows that the inventor of the laser bar code reader produced our modern civilization. Next RFID and just walk your shopping cart right on out the door, you will be charged on the fly, just like at toll booths. No more waiting in line. Now that is modern civilization.
      Elon is just improving cars, improving rockets, and trying to improve on an old idea of underground mass transit. So far success at improving on what is already there. Not so sure about that Mars thing though. But as we all know failure is the best teacher. Still, everybody likes flames, explosion and glitz.
      He is South African born Canadian-American. A man of the world with out of this world ideas. Remember much of the actual work and invention goes on in the background.

    • Survivalist says:

      Elon R. Brown (1857–1922), American politician
      Elon Howard Eaton (1866–1934), American ornithologist
      Elon J. Farnsworth (1837–1863), American general
      Elon Galusha (1790–1856), American preacher
      Elon Ganor (born 1950), Israeli businessman
      Elon Gasper (born 1951), American computer scientist
      Elon Gold (born 1970), American comedian and actor
      Elon Huntington Hooker (1869–1938), American businessman
      Elon Lages Lima (born 1929), Brazilian mathematician
      Elon Lindenstrauss (born 1970), Israeli mathematician
      Elon James White (born 1978), American journalist

  7. Energy News says:

    NEW DELHI: About $23 billion is planned to be invested in the oil and gas fields of the KG Basin, Oil Minister Dharmendra Pradhan told Parliament on Monday.

    “The operators of blocks /fields in KG basin under Production Sharing Contract (PSC) regime and nomination fields have submitted DoC (Declaration of Commerciality)/FDP (Field Development Plans) for the commercial oil and gas discoveries along with projected investment estimates,” Pradhan said, adding that the estimated investment from these plans were $22.9 billion.

    The new oil and gas production from these fields in the KG Basin is expected to reach up to 22.27 billion cubic meters of gas and 4.68 million metric tonnes of oil by 2021-22, Pradhan said.

  8. Energy News says:

    LONDON (Reuters) – Britain will ban the sale of new petrol and diesel-powered cars from 2040 as part of a plan to get them off the roads altogether 10 years later, environment minister Michael Gove said on Wednesday.
    It follows a similar announcement earlier this month by the French government, while German cities including Stuttgart and Munich have also said they are considering banning some diesel vehicles.
    Ahead of a June election, the governing Conservatives pledged to make “almost every car and van” zero-emission by 2050.

    • George Kaplan says:

      By estimates based on low global resources and rising internal producers use there won’t be much export crude around by 2040, maybe just enough for some heavy transport, the military and the emergency services, so going petrol free on personal transport by then probably isn’t much of a stretch. How much power is available and where it ultimately comes from is another matter. The biggest potential energy source by far in the UK is subsea coal (stand by for lots of replies about wind and tides), whether it is technically or commercially recoverable is another matter, but a lot of people think it is, including the government which has already issued development licences in some areas.

      Our government has a split personality in many areas when it comes to climate and energy – e.g. we have a law that states we must meet certain emission targets, but another (I think the same law actually) saying we must use as much of the North Sea resource as possible and a department with a part mandate to help export our North Sea expertise and equipment supply

      • Doug Leighton says:

        “Our government has a split personality in many areas when it comes to climate and energy”

        I think this pretty much mirrors Norway as well who have infuriated environmental groups by opening up a record number of blocks in the Arctic for oil exploration. The oil ministry is offering 93 blocks in the Barents Sea, entirely in the Arctic Circle, with applications by companies expected by the end of November. FWIW my Norwegian niece (and keen environmentalist), who is an EV driving Petroleum Engineer, insists every last barrel of oil in Norway will be pumped and exported as quickly as humanly possible; so much for “stranded oil”.

      • Energy News says:

        I’m still holding on the hope that someone finally makes a breakthrough with thorium fission or fusion. Or more efficient solar, maybe this:

        • alimbiquated says:

          The Chinese have totally overinvested in solar PV production, pretty much killing the hope of innovation for a few years. They have about 75 GW of annual solar panel production, which they will max out for cash flow reasons, even though the investments will never pay themselves off.

          They are at 50 cents a watt, and may fall even farther. At that price there isn’t much incentive to build new PV production capacity or develop new technology — you’d have to target 10 cents a watt or something.

          There is about 350 GW of solar PV installed now. So in five years there will probably be 75*5+350= 725 GW installed. If it runs at a quarter capacity, then average output will be about 160 GW.

          There is about 400 GW of nuclear running at 80% so it is about 320 GW on average. So in 5 years solar output should be about half the size of nuclear. Feel free to challenge my numbers, they are very rough.

          What is more interesting is the 725 GW max, which will wreak havoc on existing electricity grids unless storage ramps enormously. Not surprisingly, hundreds of gigawatt hours of annual battery production capacity is in planning for the next few years.

          The great thing about oil is not that it is a good source of energy. Coal, for example, is much cheaper. The great thing is that oil is a good store of energy. So solar’s real contribution in the short term will be to force the pace of battery production, and that will spill over from the electricity market into the oil market via electric vehicles. And the oilmen will find that their product is too expensive.

          • Nick G says:

            Absolutely, EVs are the best way to smooth out renewable power.

            EVs with 200-300 mile range have a lot of flexibility for when they charge. Even short range EVs can charge pretty much when they want to during the night.

    • If these guys are right and we are close to peak oil, the stuff may be selling for $300 per barrel in 2040 and the U.K. would suffer from extreme energy insecurity depending on the Kalifah of the United Arab Islamic Federation for its oil supply.

      • Nick G says:

        Oil prices will never stay above $200 for long: it’s not worth it. There are very good substitutes for most of it’s use above $100, and at $300 even the things that really require liquid hydrocarbons would be replaced by synthetics.

        • OFM says:

          As usual , Nick

          You are overselling your case.

          When the opposition quotes remarks like yours, and Joe Sixpack reads your quoted words, it’s FINE grist for the Koch brothers propaganda mill.

          There AREN’T any good substitutes for oil at a hundred dollars a barrel, or even two hundred dollars a barrel, that are READILY AVAILABLE and that can be quickly scaled up to the volumes needed to replace oil, and there WON’T be any such substitutes for quite some time to come, most likely ten to twenty years at an absolute minimum.

          The best we can realistically hope for, being believers in GEOLOGY, is that renewable energy and electrified cars, etc, will displace oil fast enough that the price of it DOESN’T go two hundred bucks a barrel, bringing on GREAT DEPRESSION II, which would of course drive the price down again.

          I have high hopes that we will indeed eventually manage a successful transition to renewable energy, but it’s going to be a GODDAMNED long time before any substitute is available for oil in the quantities needed, excepting one possibility- synthetic oil made from coal.

          And even additional quantities of coal based synthetic oil can’t be brought to market in less than maybe five years or so , even on an emergency basis, because it would take that long to design and build a coal to liquids plant.

          Maybe in the event of a national security emergency, we could build a coal to liquids plant here in the USA in less time, but still not less than a couple of years bare minimum, and that would only be possible in the event of a lasting national emergency with EVERY usual environmental and permitting regulation out the window.

          It bothers me that people so well informed as the regular members of this forum seldom seem to realize what is actually written, or broadcast , and BELIEVED, for good reasons ( from the point of view of readers, watchers, and listeners ) in the anti environmental and anti renewable energy press.

          • Dennis Coyne says:

            Hi OFM,

            Any reasoned argument can be quoted out of context and be made to look foolish.

            Nick’s point is that oil at 200 or 300 per barrel will make EVs and other substitutes more attractive so that over time demand for EVs will increase and demand for ICEV will gradually decrease.

            He is not speaking to the right wing who for the most part will only be convinced that this will happen after it has occurred and then will wish for the good old days. Like we all wish for points and carburetors because they worked so well 🙂

            • Nick G says:

              Thanks, Dennis. That’s exactly right – I wasn’t talking about liquid substitutes, I was talking about a wide range of things that people will choose instead of very expensive oil. Synthetic liquid fuel is still expensive – it’s far from the first thing that we’ll use to replace oil.

              It’s worth mentioning that $200 oil would bring forth a very wide range of responses, some of which are very short term: three obvious ones are aerodynamic retrofit modifications for trucks, slower speeds for trucks and container ships, and expanded carpooling (which is already larger than mass transit for commuting).

    • Hickory says:

      A much more meaningful policy/headline would have been a ban by year 2030.
      Good chance that by 2040 the process of a switch away from ICE will largely complete anyway.

    • Dennis Coyne says:

      Hi Texas Tea,

      The US produces a lot of coal and natural gas. We have gone from being a natural gas importer (mostly from Canada) to self sufficiency in natural gas, and that is good, I agree. At some point natural gas in the US will peak(but probably after 2035). Coal has not been imported to the US (on a net basis) for over 100 years, so not really a big deal for US “independence”.

      Do you expect that US oil output will increase to 16 or 17 Mb/d? Unless US demand for crude oil decreases, that is what is needed for US oil independence. I am highly skeptical that US C+C output will ever break 12 Mb/d. Note that NGL helps very little in producing gasoline, diesel, or jet fuel, the major products needed from US oil refineries which currently have inputs of about 16.5 Mb/d of crude oil.

      The discussion here is mostly about liquid fuel rather than coal or natural gas.

      The fact is that the US is very far from oil independence at present.

      I doubt this will change very much unless demand for crude falls in the US.

      That is a possibility by 2030 when oil prices may be much higher than today, probably over $100/b in 2017 $.

      • Glenn E Stehle says:


        The title of the post that texas tea linked reads “U.S. becomes global fossil energy giant feeding hungry world energy markets,” not “U.S. becomes global oil giant feeding hungry world oil markets.”

        • texas tea says:

          another glimpse into the real world

          Andy McConn, principal analyst at Wood Mackenzie,said: “We are confident in tight-oil producers’ ability to grow and generate free cash flow in a $50/bbl oil-price environment.”

          He added: “We’re only in the early stages of tight-oil development. Like any high-growth, capital-intensive investment, the first years are a poor indicator of future profitability. To date, high early-life costs have weighed on cash-flow metrics, but tight-oil producers have made great strides in honing technology and reducing costs. Collectively, that progress – as measured by well productivity and companies’ cost structures – have improved immensely during the downturn, providing the necessary structural stability for sustained profitability.”

          • clueless says:

            I guess that service companies like Halliburton will have to provide their services at a loss forever.

            • shallow sand says:

              Actually Halliburton posted positive earnings of 3 cents per share and Schlumberger posted a loss of 5 cents per share.

              Both pretty darn close to break even, which is the definition of success in the commodity bear market.

              • Dennis Coyne says:

                Hi shallow sand,

                Would you agree that a large portion of the cost savings in the LTO focused companies has been due to lower prices from service companies?

                At some point these companies will no longer be viable if they continue to work at a large discount.

                I also question whether these LTO companies will remain cash flow positive at oil prices under $50/b.

                Have we seen many 2Q earnings? Are these companies now showing positive earnings? 2016 was a disaster, it is not clear that 2017 will be much better.

                • shallow sand says:

                  Dennis. I agree, but I base that on the Haynes and Boone bankruptcy monitor for service companies, along with service company earnings. Finally, our costs are down significantly in almost all areas.

                  Of course, many would argue that by reducing our workforce, we have achieved efficiency gains. Labor is a very large expense in the industry, so reduced headcounts, wages and benefits could be where much of the efficiency gains are occurring?

                  If the men on the frack crew were earning $50 an hour in 2014 and are now earning $25 I assume that would be deemed an efficiency gain?

                  • Dennis Coyne says:

                    Hi Shallow sand,

                    It is not clear that there will be much of a ramp up in output if they don’t find some people to frack those drilled wells, no doubt there will be shortage of workers before long and wages and service costs will increase.

                    Have you looked at any 2Q reports for large LTO players, you follow the financial stuff closer than I do?

                    Maybe a post on this would be good, just shoot me an email if you have the time or interest. Just a summary of top 10 US LTO focused companies (leave out majors) is one suggestion, but it is entirely up to you of course.

                  • shallow sand says:


                    I think a post comparing earnings in the US E & P space to other major US industries would be noteworthy.

                    Just today, COP reported adjusted EPS of 14 cents, which was a beat. However, actual was a quarterly loss of $1.1 billion, due to recognition of losses from sales in the Barnett Shale and San Juan Basin, both of which are in the lower 48. Further, COP is guiding year end 2017 production of under 1.2 million BOEPD. That is down almost 400K BOEPD from 2014.

                    So, while 14 cents is a beat, they are shrinking the company and still borrowing to pay the dividend. Plus, the stock price is half of three years ago, with a lower dividend. Compare that with other major US industries, such as banks, industrials, technology, consumer staples, etc.

                    I assume investors have been bottom fishing since the crash, hoping to cash in when oil and gas rises. But, as traders are pricing oil and gas prices primarily off US production and inventories, prices cannot recover as long as US E & P’s keep growing production. Catch 22 deal. Further, many of the companies are very overvalued if prices stay where they have been the last three years. Break even, whatever that means, doesn’t sound like a good goal.

                    I still think $55-65 WTI and $4 gas would be good, but whenever I mention that, my comments get smacked by some here and elsewhere.

                  • Boomer II says:

                    I posted this before. It compares net margins across many industries.


                  • Dennis Coyne says:

                    Hi shallow sand,

                    I used to think $55-65 would not be high enough to increase LTO output, but clearly I was wrong. Whether World output will continue to meet demand at $55-65 per barrel remains the question. Currently stocks are falling and if OPEC continues its cuts along with the 10 non-OPEC countries, eventually the lack of new projects in the pipeline will begin to hit World output, probably by 2019 or 2020.
                    At that point even if OPEC and LTO producers produce as much as possible profitably, output is unlikely to satisfy demand.

                    It is for this reason that I expect by 2020, $65/b will be too low an oil price to keep the oil market in balance.

                    I never get these price predictions right, so maybe oil prices will remain less than $65/b until 2030. 🙂

                    Note that I don’t think shallow sand has ever suggested this, I think he might mean $55-$65/b for 2018 to 2019.

                  • Glenn E Stehle says:


                    When it comes to predicting future oil prices, there are as many different predictions as there are different people making them.

                    Yesterday Shell CEO Ben van Beurden said the company has adopted a “lower-forever mindset,” as peak demand should hit within a decade.

                    Shell braces for ‘lower forever’ oil amid electric vehicle boom

                  • Dennis Coyne says:

                    Hi Glenn,

                    I agree future oil prices are not known.

                    If prices are low, supply is more likely to grow more slowly. In the short term (3 to 5 years) demand is likely to outstrip supply which implies oil prices will rise.

                    How much they will rise and the precise demand and supply response are unknown.

                    So as you have said, a precise prediction of future oil output given these uncertainties is “a fool’s errand” (I believe that is the term you used).

                • shallow sand says:

                  XOM US upstream reported a loss of $183 million for Q2, 2017.

              • coffeeguyzz says:

                Bloomberg just released a report by Denning on Hess, specifically its Bakken-centric operations.

                Sheds some light on sub $50 WTI effects on shale E&PS.

                • Boomer II says:

                  Here’s the article link. Sounds like Hess isn’t a rousing success, but doing as badly as it could be. The title is more favorable than the article.


                  • Boomer II says:

                    I meant to say it isn’t doing as badly as it could be. The tone of the article seemed to be cautiously optimistic.

                • Glenn E Stehle says:

                  From the article, it looks like shale is the only place where Hess and Anadarko are making money.

                  Yet, also like Anadarko, Hess is holding its own where it counts: U.S. shale.

                  Production in Hess’s core Bakken basin beat guidance handily, at 108,000 barrels of oil equivalent per day. That should rise to somewhere between 110,000 and 115,000 in the fourth quarter.

                  More important than that is how Hess is getting to those higher levels….

                  With four rigs operating in the Bakken, the company had indicated it might add another two if oil prices warranted it — the implication being that those two might be needed in order to maintain momentum.

                  Hess now says that a move to more intensive fracking methods meant it could meet its targets with just four rigs. The company says its Bakken operations generate free cash flow even at today’s prices and that it would require only 2.5 rigs, on average, to hold production flat, down from 3.2 rigs a year ago.

                  That a U.S. E&P company is holding steady at sub-$50 oil in the Bakken — and not the red-hot Permian shale — should cause some nervous twitching over at OPEC’s offices. At $60 oil, which still wouldn’t salve the economic wounds of many petrostates, it’s a fair bet those other two rigs would be put to work quickly….

                  In short, Hess is increasingly a story of grinding out further productivity gains in the Bakken but using the cash this generates for now to fund the Guyana venture.

                  • Boomer II says:

                    The importance of that, then, is how long the LTO lasts. That’s why I am so interested in decline rates. If there isn’t global potential, the the future of oil is up to LTO. So goes LTO, so goes the oil industry.

                  • John Keller says:

                    Haven’t we gone over this before? You can’t believe a word the shalie huxters say about costs or economic returns. Just look at their financial statements. None of them make money. The numbers don’t lie.

                  • coffeeguyzz says:


                    Although I’m far more positive regarding the longer term production capacity of LTO than you might be, the natgas supply will tend to overwhelm its liquid cousin in future decades.

                    One aspect of LTO beyond its individual decline profiles (still leaving about 90% hydrocarbon unrecovered), is the expanding areas that are becoming more economically feasible as the industry matures.
                    Known formations such as the Powder River Basin, Uinta, Rogersville, Tuscaloosa Marine and several others might attract increased development if the economics warrant.

                    However, on another site, an interesting update on the Utica was presented by the “Father of the Marcellus”, William Zagorski.
                    28 page graphic rich pdf is titled “Discovery of the Utica Shale: Update on an Evolving Giant”.

                    Although it is a bit wonky and not inclusive of the most recent data, the sheer size of this resource should indicate what is possible to produce in decades to come.

                  • Boomer II says:

                    John, we must also factor in where investors and lenders put their money. Why be satisfied with an industry barely hanging on when they can finance industries with more potential?

                  • shallow sand says:

                    Hess lost $340 million in US upstream in Q2, 2017 and lost $14 million in International upstream in Q2, 2017.

                    I didn’t see that Anadarko broke out US v International in Q2, 2017, but I just scanned the press release and didn’t look at the 10Q.

                    As I recall, in Q1, 2017 and in past quarters as well, companies that broke out US or North American operations v International all showed much heavier losses in US/North American. Examples would be XON, CVX, OXY and COP.

                    My previous paragraph is from memory, so if anyone wants to actually look at the numbers instead, please correct me if I am wrong.

                    Really interesting how long these companies have went with substantial negative EPS.

                  • Dennis Coyne says:

                    Hi Coffeguyzz,

                    I agree the natural gas shale resource is large, the LTO resource not so much especially at current oil prices. When oil prices increase to $100/b or more, then more of the LTO resource will be economically recoverable.

                    It will be interesting to see what happens to the well profiles of the more productive Bakken wells that have started producing in 2017.

                    Most petroleum engineers believe the overall EUR will be no different, production is simply pulled forward to earlier months, this helps the finances as long as the increased cost of more proppant and a higher number of frack stages does not offset the increased net present value of the output (due to faster recovery in the early months).

                    The above comment refers to the Bakken where lateral length has remained at about 10,000 feet for many years. In the Permian basin much of the apparent increase in new well productivity is due to increased lateral length, if we double the lateral length from 5000 feet to 10,000 feet then the well produces 2 times the oil per well, but unless the prospective are also increases by a factor of two, the number of prospective wells decreases by a factor of 2 ceteris paribus.

                  • Dennis coyne says:

                    Hi shallow sand


                    Many of the LTO players are also cutting back on capex so we may see flatter LTO growth in Q3 and Q4.

        • Dennis Coyne says:

          Hi Glenn,

          I suppose the US could export some coal, not really very interesting for a peak oil discussion in my opinion.

          • Nick G says:

            Not to mention that coal is pretty cheap per BTU/joule. Even if the US were to export enough coal to balance it’s crude imports, the US would still have a large dollar deficit.

            OTOH, crude oil is cheaper than refined products. I’d be curious to see an analysis of dollar-weighted energy imports/exports.

            • Dennis Coyne says:

              Hi Nick G,

              Then do it and I will post it.

            • texas tea says:

              Dennis says upthread” Most petroleum engineers believe the overall EUR will be no different, production is simply pulled forward to earlier months, this helps the finances as long as the increased cost of more proppant and a higher number of frack stages does not offset the increased net present value of the output (due to faster recovery in the early months).”

              please provide where you got that bit of information. I do not think you truly understand what is happing in the real world where frac technology is advancing and will advance too. I am not saying you are wrong, i am saying you do not know yet what will be the impact on EUR. By the way neither do I, but i can say what I am seeing is VERY encouraging, I will more than surprised if EUR is not increased (significantly) by these new technologies based on watching production on my wells for over 30 years.

              • Glenn E Stehle says:

                texas tea,

                The peakists, whose beliefs are about as doctrinaire and dogmatic as they come, operate in what Nassim Nicholas Taleb calls the “platonic fold”:

                The platonic fold is the explosive boundary where the Platonic mindset enters in contact with messy reality, where the gap between what you know and what you think you know becomes dangerously wide.

                — NASSIM NICHOLAS TALEB, The Black Swan

                • Nick G says:

                  That sounds a little like epistemological nihilism.

                  I share your frustration with many Peak Oil analyses. I have often argued that PO enthusiasts should acknowledge the large uncertainties involved. They should think in terms of risks, not certainties.

                  But, I think Dennis is sincerely trying to get it right, and I think his projections are pretty good. I would do them a little differently if it were up to me, and I sometimes give him somewhat unsolicited advice. But….Dennis is willing to do pretty complex and very time consuming analyses for free and that’s astonishing! I think he deserves enormous credit.

                  Forecasting and scenario analysis is often very hard to do, but it’s still necessary. Every large organization does it (including oil companies!) – they know that they are very, very imprecise, but you have to make your best guesstimate of what’s coming in order to plan.

                  Forecasts are a necessary evil. Don’t complain – make substantive and constructive suggestions, or, even better, do your own.

                  • Glenn E Stehle says:


                  • Nick G says:

                    And what evidence does Pascal provide for this idea?

                    It seems to be simple, old fashioned religion – the assumption that reason cannot fully understand our world, or find meaning in it.

                    Reason includes biology and psychology, and it is completely arbitrary to assume that these things cannot help us understand why we do what we do, and what can make us happy and give our lives meaning.

                    Pascal died at the age of 39, after a life of illness. “Pascal’s ascetic lifestyle derived from a belief that it was natural and necessary for a person to suffer. In 1659, Pascal fell seriously ill. During his last years, he frequently tried to reject the ministrations of his doctors, saying, “Sickness is the natural state of Christians.”[31]”. Wikipedia.

                    Medicine, biology, psychology – these disciplines didn’t really exist during Pascal’s life – he was just born too early.

                  • Glenn E Stehle says:

                    Nick G,

                    Five hundred years after the rebirth of the Platonic doctrine “that reason can fully understand our world, or find meaning in it,” can you marshall empirical evidence demonstrating the truthfullness of that claim?

                  • Nick G says:

                    Of course – there has been enormous progress in understanding the world in the last 500 years. There’s really no sign of that progress stopping (please don’t respond with statistics about patents – I think any reasonable person can see that progress still continues – just look at energy engineering and medicine.

                    Two hundred and fifty years ago Franklin invented the lightning rod. Churches were the last to accept them, arguing that lightning strikes were the wrath of god, and it was defying gods will to stop them. They only accepted lightning rods after churches kept burning down. Theologians are not a reliable source about the limits of science.

                    I don’t know whether Plato really applies here – I don’t think he was really thinking of the Scientific Method. When I refer to reason, I’m referring to the idea that we think for ourselves, rather than going by ideas laid down by prophets, preachers, and other authorities who ask that we take their ideas on faith. That made sense in a world where change was very, very slow and we knew little about how the world works – accumulated human wisdom could be fossilized into rigid doctrines, which then fought each other in clashes of empires and civilizations. It doesn’t really make sense now. There are better ways to develop and continually improve our “map” of how the world (including humans) works.

                    Does human understanding have limits? Who knows? Who cares? Why try to prove a negative? In the end, pretty close to 100% is almost certainly good enough.

                    But certainly theologians are not a reliable source on the subject.

                  • alimbiquated says:

                    Pascal did a lot of groundbreaking work on statistics. His work was based on gambling games like cards, dice and roulette wheels. All games with well defined rules.

                    As Pascal’s Wager shows, he really didn’t understand statistics in a situation with incomplete information.

                    Bayes figured it out the statistics of uncertainty in his abortive attempt to prove the existence of his god.

                • Dennis Coyne says:

                  Hi Nick,

                  I always clearly state my assumptions and present various scenarios because I recognize the future is not known, we can only make reasonable guesses as to how it might look by using several different assumptions. For conventional oil my URR estimate is between 2400 and 3600 Gb of conventional C+C. For unconventional (mostly extra heavy oil sands and LTO) my estimate is 300 to 1000 Gb (250-600 Gb for extra heavy oil and 50 to 400 Gb for LTO). So for all C+C the range is 2700 Gb to 4600 Gb.

                  The best way to approach a high uncertainty analysis is to use the maximum entropy probability distribution, I would set 2700 Gb to zero and use a mean and standard deviation of 1000 Gb for such an analysis. This results in a mean of 3700 Gb and a median (50% probability of URR being higher or lower) of 3400 Gb. There is about a 66% probability that the URR would be less than the mean (3700 Gb).

                  • Nick G says:

                    hmmm. So what would the 95% confidence interval limits (IOW, a double tailed distribution with 90% of the curve between the two limits) be for the date of Peak Oil?

                  • Dennis Coyne says:

                    Hi Nick,

                    The analysis points to URR and the 90% interval is 2750 Gb to 5700 Gb with a median (50% probability) of 3400 Gb.

                    The date of the peak depends on demand, this has further uncertainties which are more difficult to model (how fast do substitutes develop, how fast do technology improvements in oil extraction occur?).

                    It is possible that lack of demand and low oil prices are more responsible for the peak than lack of oil in the ground and the ability to extract it.

                    Extraction at a profit over the long term is a key point. When the maximum output point will occur is a very difficult problem, which I have always acknowledged.

                • Dennis Coyne says:

                  Hi Glenn,

                  The beliefs of the cornucopians are equally dogmatic in my opinion.

                  Of course name calling by you or I proves very little.

                  • Glenn E Stehle says:


                    Ah, but my name calling is backed up by hard evidence.

                    See, for instance, this thread below:


                    You cherry pick the evidence that conforms to your peak oil dogma, and ignore any evidence that contradicts it. The bottom line is that what you end up with are distortions and partial truths, and of course a failure to accurately predict.

                  • Dennis Coyne says:

                    Hi Glenn,

                    I use empirical evidence to model the past, then assume the future will be similar,
                    you assume that it will not be similar.

                    We have no empirical evidence of the future, we can only speculate based on past experience.

                    The arrow of time goes from past to future in my experience, I believe this will continue to be the case.

                    I am not the one who initially claimed those who disagree with my view are “dogmatic”, that was you, backed by nothing but opinion.

                    Oh and your accurate predictions can be found where?

                    That’s right they cannot be found.

                    I have never claimed to make accurate predictions, it cannot be done.

                    I can usually create low and high scenarios which bound reality fairly well and I adjust my thinking based on evidence. For example the scenarios I created in 2012 are more consistent with conventional oil output which will probably be in the range of 2400 Gb to 3200 for URR, where I picked a single case of about 2800 Gb. Later I used (in 2015) 2500 Gb to 3100 Gb (where LTO was included in this estimate) since that time there have been new estimates by the USGS on LTO resources and I also have more information on LTO output from the EIA and Shaleprofile.

                    I use all the evidence I have, but an assumption that new well EUR will continue to increase is unproven and might lead to inaccurate estimates of future output, if one were to make such an estimate using that assumption.

                    We are in agreement that the future is not known, I have never claimed otherwise.

                    For an example of a past scenario which has done pretty well so far bounding World C+C output between a low and high scenario see the following from July 2012:


                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “I use empirical evidence to model the past, then assume the future will be similar, you assume that it will not be similar.”


                    You assumed those pre-2015 type curves and resultant EURs were engraved in stone.

                    Fast-forwarding to 2017, that doesn’t look like a very sure bet any more.

                    Your only hope now is for the newer completion techniques to prove to be a failure.

                  • Dennis Coyne says:

                    Hi Glenn,

                    You are incorrect, I did not assume the 2015 type curves were engraved in stone, I simply don’t know how they will change in the future, productivity may increase or decrease, I cannot predict the future so I assume it will be similar to the past, I also cannot accurately predict the number of new wells completed, so I guess what the future number might be based on completion rates in the past.

                    When I have enough information to estimate a new type curve, I do so, but this requires about 11 months of data minimum.

                    In the Bakken the EUR was stable from 2008 to 2013 and has increased since then, the higher EUR well profiles are included in my models, as I said before, future improvements in the well profile cannot be anticipated in advance, at least by me.

                    We don’t really know what a well will produce with any certainty until it has been produced.

                    The model makes the simplifying assumption that the well profile will not change because of my lack of clairvoyance.

                    No doubt you could do much better. 🙂

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “I did not assume the 2015 type curves were engraved in stone, I simply don’t know how they will change in the future, productivity may increase or decrease….”

                    You can say that with a straight face, after having just claimed that “the overall EUR will be no different, production is simply pulled forward to earlier months”?

                  • Dennis Coyne says:

                    Hi Glenn,

                    The shape of the type curve can change so that more of the oil is produced in early months and less in later months, potentially this can lead to a higher EUR depending upon the economics at the tail. It may be the case that EUR increases or decreases depending upon where the economic cutoff is. In almost every case faster extraction in the early months will lead to a higher overall EUR even if the tail of the high output wells (in the first 24 months) falls below the lower output wells after 24 months, it is unlikely the difference in the tails would offset the higher early output unless the wells were produced to very low output levels (say to 2 b/d).

                    My models adjust the well profiles as I have enough data to estimate them.

                    In the simplified LTO model I linked to, the well profile was held fixed for simplicity of presentation.

                • @whut says:

                  “The peakists, whose beliefs are about as doctrinaire and dogmatic as they come”

                  No glenne, the premise is that fossil fuels are a finite and non-renewable resource. This is not really a belief but empirically true based on all known evidence.

                  The ones with the strange dogmatic beliefs are those that believe that fossil fuels are infinite or regenerate in some fantastical fashion, perhaps abiotically.

                  • Glenn E Stehle says:

                    @whut said:

                    “….the premise is that fossil fuels are a finite and non-renewable resource. This is not really a belief but empirically true based on all known evidence.”

                    No, the “premise that fossil fuels are a finite and non-renewable resource” is not an empirical truth. It is an analytic truth.

                    We’ve already been through this once before, but you don’t seem to be able to move beyond your same old hackneyed talking points and strawman arguments.


                  • Dennis Coyne says:

                    Hi Glenn,

                    Interesting that you would claim it is not an empirical truth.

                    You made fun of me in a previous comment for my claim that all oil fields peak and decline (almost every field that has started producing oil has exhibited this behavior), suggesting that this was self evident.

                    Are you now questioning this “self evident” assertion?

                    Perhaps not. Maybe you believe the rate of abiotic oil production is greater than the rate that oil is used worldwide or that the number of oil fields that are yet to be found are unlimited?

                    How exactly would you prove that oil is not a finite resource? I have a hard time understanding your position.

                    I think most in the oil industry would not agree with the proposition that the oil resource is infinite.

                    If that is correct, then it is finite.

                    Whether that is empirical or analytical (in fact it is a combination of reason and observation which is true of all scientific understanding) is really beside the point.

                    It is a widely accepted truth.

                  • Glenn E Stehle says:


                    Is it possible for you and @whut to make an argument without alleging an absurd absolute or standing up some strawman?

                    Can you show me exactly where I “made fun of you in a previous comment for your claim that all oil fields peak and decline.”

                    Sure, go ahead and show me where I did that.

                    Of course all oilfields will eventually “peak and decline,” but they may not do so on your schedule.

                    The debate is not over if peak oil will happen, but when it will happen.

                    Peak oil may have already happened, or it may not happen for another 100 years or more. There’s a big difference between those two, believe it or not.

                  • @whut says:

                    Notice that every time this guy glenne ends up talking circularly? See :

                    “The debate is not over if peak oil will happen, but when it will happen.”

                    I think this is the reason for having this blog in the first place! All the charts that are posted here and all the interactive apps that are created are for the benefit of people that are interested in following the trajectory of the oil depletion timeline.

                    The term “peak oil” is to oil depletion as “global warming” is to climate change. It’s but one property of the overall process.

                  • Dennis Coyne says:

                    Hi Glenn,

                    You don’t remember what you post?

                    You seemed to question the fact that oil is a finite resource.

                    Are you walking back from that stance?

                    This absurd absolute was suggested by your argument and I agree that indeed it is absurd.

                    Yes peak oil is a question of when, experts put the conventional resource at about 2000 Gb to 4000 Gb and unconventional oil resources at 250 Gb to 1000 Gb.

                    Even the very optimistic estimates of 5000 Gb for C+C would peak before 2050, most experts expect a peak between 2020 and 2030 (the most likely scenario), those with a more pessimistic view believe it will be before 2020, only those with an extremely optimistic outlook believe oil will peak after 2050.

                    I agree with the expert consensus of 2020 to 2030, the higher end of the range of URR estimates might result in a later peak than 2030, but the probability is less than 10%, about 2.5% for 2040 and maybe 1% for 2050 or later.

              • Dennis coyne says:

                Hi Texas tea,

                Fernando has suggested this and another engineer named Frank Liu who comments at For the Bakken so far the well profile falls to the level of earlier wells after 12 to 18 months.

                I mention as a possibility that the increased technology might increase the speed with which the oil is extracted but might not increase the total oil recovered.

                At this point the wells are mostly less than 10 years old so we can only speculate.

                • Dennis Coyne says:

                  Hi Texas Tea,

                  The relevant comment thread is at link below:


                  An excerpt:

                  As a reservoir engineer, I think the some presentations mislead investors for using such a big EUR to get a very small break even oil price. They may find an excuse since no one knows the exact EUR until the well was abandoned. The type curve analysis they used to get such a high EUR is mainly based on the high initial rate and apply the same decline rate as they used before for lower completion efficiency wells. The decline will not follow the type curve that they used, and the EUR will not reach more than 1 million BOE on an average basis that Pioneer Natural Resources used for Wolfcamp B completion 3. Increasing stage and cluster density only increases well completion efficiency, it can’t increase EUR if the well spacing is the same and also assume there is no economic production rate cut off.

                  To make a summary for high completion efficiency resulted by high stage and cluster density, it makes early time rate high that otherwise should be low. The EUR can’s be significantly boosted by increasing completion efficiency. Without increasing the distance between two wells, I would expect the oil rate of late drilled wells will all cross over with that of early drilled wells for similar reservoir. The higher the density of stage and cluster, the quicker the rate cross over. The reservoir is a close certain amount for both. If more is recovered earlier, less will be recovered later. The expected more than one million BOE EUR will not be reached due to use the same decline curve analysis. The late fast decline is the wrath of science. The low breakeven price based on such a high EUR is not true. Investors should be alerted.

                  Follow the entire thread looking for Frank Liu’s comments (mine can be ignored), the man really knows his stuff.

                  Maybe Fernando could comment as well as he is well versed in this area (reservoir engineering).

                  • Boomer II says:

                    And if many LTO companies are operating as Ponzi schemes, it is in the management’s best interest to get the oil out fast, collect as much money from willing lenders and investors as they can, transfer it to their personal accounts, then walk away when it all collapses.

                  • texas tea says:

                    thanks Dennis to be accurate perhaps you overstated your case, where “some” engineers or perhaps a “few” or maybe to be most accurate you should of said “a couple of engineers” instead of MOST😜

                  • Dennis Coyne says:

                    Hi Texas Tea,

                    I only have a sample of two, perhaps they are not representative, but their views also confirm what Mike Shellman and Shallow Sands have been saying. In addition the data Enno Peters provides at also confirms this.

                    I tend to go with the empirical evidence.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “I tend to go with the empirical evidence.”

                    Oh really?

                    Can you show me where the empirical evidence exists on this graph from that leads you to “believe the overall EUR will be no different, production is simply pulled forward to earlier months”?

                  • Dennis coyne says:

                    Hi Glenn

                    For the Bakken where lateral length has been consistent the barrels per month falls to the level of older after 12 to 18 months. The cumulative well profile does not show this as clearly.

                    Also you need to give us more information.
                    Where are those wells?

                    In some LTO plays the length of the laterals has increased, this increases the area accessed by the well and increases output per well but decreases the number of wells that can be drilled per unit area. The net increase in URR would be zero.

                  • Dennis Coyne says:

                    Hi Glenn,

                    Using data from the following Bakken post at


                    The chart below is from the Well Quality tab using years from 2008 to 2017 for all North Dakota Bakken/Three Forks wells which started producing between Jan 2008 and March 2017.

                    By 25 months the higher productivity wells have fallen to the same or less output than the earlier less productive wells. This is despite a higher number of frack stages and more proppant being used in the newer wells.

                    Any increase in cumulative output is during the first 24 months, after that output is the same or less.

                    In the Permian Basin much of the productivity increase is simply a matter of longer laterals, if we looked at output per feet of lateral length, the progress would likely be similar to the Bakken chart below.

                    A larger chart can be seen by clicking on the chart.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “For the Bakken where lateral length has been consistent the barrels per month falls to the level of older after 12 to 18 months.”

                    It that is so, then how do you explain this?

                    Many of these developments are very recent, and in your haste to condemn shale you may have jumped the gun.

                  • Glenn E Stehle says:


                  • Dennis Coyne says:

                    Hi Glenn,

                    Too few wells there to say very much, there is statistical variation which cannot be explained. The 12 to 18 months was incorrect (I was going by memory and was incorrect), after about 24 months past wells have fallen in output to the level of earlier wells.

                    I cannot predict the future, I can only say what has happened so far, looking at results by quarter gives results that are too noisy to make a judgement in my view.

                    Some of the apparent productivity increase may be due to high grading. At some point they will run out of room in the sweet spots in the ND Bakken/Three Forks, the faster the rate of completion the more quickly this is likely to occur.

                    When it does, the EUR will start to decrease, but it is impossible to predict when this will occur.

                    Also note that eventually the technology will reach a limit where further spending on improved productivity will not be justified by the increased revenue. This point may be reached fairly soon in the Bakken/Three Forks (within 2 to 3 years), but as with all guesses about the future that is speculative, just as an assumption that productivity will continue to improve is also pure speculation.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “Too few wells there to say very much….”


                    But not “too few wells there” for you and your “expert consensus” to confidently proclaim that “the overall EUR will be no different, production is simply pulled forward to earlier months.”

                  • Dennis Coyne says:

                    Hi Glenn,

                    I took a look at and that chart has 130 wells or less for that little flat spot for that one quarter.

                    Too small a sample to be meaningful and it is from month 10 to 12, we will see what happens to these wells going forward.

                    The bulk of the data in that chart agrees with my hypothesis, there is undoubtedly well to well variation, and I have never claimed otherwise. I am more interested in the average well using 1000s of wells as the basis, 130 wells or less tells us very little.

                    So far there has been very little change in the Bakken average well profile from 2008 to 2016, maybe a 17% increase over a 9 year period, if we assume the 2016 wells do not fall below the output of the older wells in the future, this is not known.

                    I have repeated what an expert in the field has claimed, and it would be interesting if Fernando chimed in because he is an expert and I am not.

                    Mike Shellman and Shallow sand are also professionals in the oil industry and know far more than me.

                    I am unlikely to convince you that investor presentations might be optimistic, just as I was unable to convince coffeguyzz that the Bakken well profile he found on the NDIC website does not reflect reality.

                  • @whut says:

                    glenne said:
                    “It that is so, then how do you explain this?”

                    Is this guy serious? He sees an slight plateau in a diffusional decline curve and implies that this indicates some magical behavior? Like maybe the flow will level off forever … perhaps thanks to magic beans proppant that kick in at halfway down the decline curve?

                    BTW, these are plotted on a semi-log scale.

                  • coffeeguyzz says:


                    …ND website not indicative of reality concerning Bakken well profiles???

                    ND DMR has large, full time staff that focusses exclusively on North Dakota hydrocarbon output as, amongst other ramifications, it has huge impact on state revenue, budget, taxation issues affecting many, many other areas – infrastructure (bridges, roads, schools, etc.) to name just a few.

                    Been doing this stuff about 60 years now.

                    Their most recent “Typical Bakken” well profile shows 110 bpd at 5 year mark and hitting 50 bpd 16 years online.

                    Now, if you use as reference other sources, Enno’s site in particular, there are some things you, and others should be mindful as significant discrepancies immediately appear between DMR and shaleprofile presentations.

                    Two big components are Enno’s incorporation of ALL production data from Bakken/TF wells and presenting them on a calendar production basis.
                    The DMR folks use far more discretion in qualifying a “typical” well, but it most certainly does not include the hundreds (thousands?) of extremely poor producers scattered throughout the Basin as can readily be seen on the single graphic of 60 day IPs displayed in ongoing fashion in the DMR’s presentations.

                    This can justifiably be described as ‘cherry picking’ because that is exactly what it is, namely, the minimising or discarding of wells way out on the fringes of this vast area as it is grossly unrealistic to include them in real world planning.

                    Second item, calendar based presentations, also impact analysis as geologic considerations that are tempered by 10%/25% shut in rates offer different conclusions than when a 30 day per month online production is, incorrectly, deduced.

                    Enno has, as far as I know, consistently stated that all his data is taken from publicly available data and I am certain this is true.
                    However, the calendar and location factors play a large role in the divergence of profiles from these two sources.

                    Call it reality, bias, blindness or whatever you choose, Dennis, but, as a statistician extraordinaire, you – of all people – surely recognize the impact of source data on future projections.

                  • Glenn E Stehle says:

                    ••••Dennis Coyne said:

                    “The bulk of the data in that chart agrees with my hypothesis.”

                    Right, and “the bulk of the data in that chart” is for wells with first production 2016-01-01 or before.

                    You are correct when you say “we will see what happens to these wells (with first production after 2016-01-01) going forward.”

                    But that ephemeral moment of lucdity didn’t stop you and your “expert consensus” from confidently proclaiming that “the overall EUR will be no different, production is simply pulled forward to earlier months.”

                    ••••Dennis Coyne said:

                    “I am unlikely to convince you that investor presentations might be optimistic….”

                    The data I’m citing here is not from “investor presentations,” but, in case you haven’t noticed.

                  • Dennis Coyne says:

                    Hi Coffeeguyz,

                    The few wells on the fringes affects the analysis very little. I include all wells drilled in the middle bakken and three forks formations. Do you really think that from 2014 to 2016 they were drilling a lot of wells in low productivity areas?

                    I give the oil companies a little more credit than you do I guess.

                    I have shown you before what output would look like if the NDIC “Typical well” was used in place of my “average well” from Jan 2015 to May 2017.

                    Reality does just not match up with this mythical typical well with an EUR of 647 kb.

                    Enno’s data is sound, the NDIC analysis is not.

                    Click on chart for larger image.

              • shallow sand says:

                TT. I agree with you, we do not know UR till the well is plugged.

                Clearly, Permian well productivity has improved from 2014 to present.

                What I wonder about is optimal spacing. Way over my knowledge. Interesting that our very shallow wells in a very old field cannot, by state spacing rules, be drilled as tightly as they are pad drilling in not only the Permian Basin, but other plays as well.

                Seems to me racing to produce as fast as possible isn’t the best idea. We know it wasn’t a good idea at Spindletop, the East Texas field, etc.

                I just hope the engineers and geologists are in charge, and not Wall Street. More important to me is not seeing how high US production can go, but how long can we maintain a high steady rate.

                I am not anti shale, far from it. I am very concerned about the land rush way it has been developed.

                We need to be thinking about not just the next quarter, but the next few decades. If US can achieve and sustain 9-10 million BOPD plus for a few decades, that would be much better than shooting up to 11-12 and then quickly crashing back down.

                Finally, I realize everyone likes $2 gasoline. However, the US has to be considered a major world producer. So, why would prices that cause massive layoffs and substandard company earnings be desirable?

                For the first time in decades US production influences prices. Maybe Wall Street is finally figuring out that supply that outstrips demand is self-defeating.

                • Dennis Coyne says:

                  Hi Shallow sand,

                  The USGS mean estimates so far are about 34 Gb for Permian and Bakken, David Hughes has estimated about another 6 Gb for the Eagle Ford so the big three plays about 40 Gb, perhaps another 10 Gb at most from other formations (besides Wolfcamp and Spraberry) of the Permian basin would bring us to 50 Gb.

                  The EIA’s reference scenario for US tight oil is about 80 Gb through 2050 and is very optimistic in my view ( the tail of decline would add another 20 Gb or so making 2 times higher than USGS TRR estimates). Do we really think that other plays in the US (Niobrara and others in the Rockies) will yield 50 Gb of tight oil?

                  The US tight oil output at a 50 Gb URR will peak by 2025 and decline relatively rapidly.

                  George Kaplan’s GOM research and that of SoLaGeo suggests the GOM will also peak fairly soon (2018 or 2019) and then decline and conventional onshore and Alaskan oil output will continue to decline.

                  Flat US output at 9 to 10 Mb/d after 2025 is highly unlikely in my opinion.

                  I would like 10 Mb/d for several decades to be true, but that will not make it so. Lack of oil supply after 2025 will lead to higher oil prices, but this will only slow the decline rate, it is unlikely to lead to higher oil output.

                  Only a rapid increase in the substitution of EVs for ICEV will keep oil prices from rising to very high levels (over $150/b in 2017$) by 2030, in my view.

                • Dennis Coyne says:

                  Hey shallow sand,

                  Does your IHS data give the lateral lengths of the wells? Is it easy to determine if the average lateral length has increased (and by how much) in the Permian basin from 2014 to 2017?

                  • Dennis Coyne says:

                    Hi Glenn,

                    We are pretty far from the first inning in the Bakken where wells have been drilled since 1951 and horizontal fracked wells started in 2005.

                    You can speculate that EOR will be profitable in the tight oil plays and that refracks will provide an adequate ROI, I am skeptical that your speculation will prove correct.

                  • Glenn E Stehle says:


                    But you’re the one making all the predictions about what the future holds, and using rhetoric, tortuous logic, and cherry-picked evidence in an atttempt to give them validity.

                    I’m merely challenging your predictions, pointing out the defects of logic and evidence, and reminding folks that there are a lot of ‘what ifs’ out there that you are ignoring.

                  • @whut says:

                    “But you’re the one making all the predictions about what the future holds, and using rhetoric, tortuous logic, and cherry-picked evidence in an atttempt to give them validity.”

                    That’s called psychological projection. You are actually the one applying various high-school debating techniques to try to counter what is a geophysics-based quantitative analysis.

                  • Dennis Coyne says:

                    Hi Glenn,

                    The LTO models are quite simple.

                    maybe you should read about them.


                    The Oil shock model is a little more complex and is introduced at link below


                    I don’t cherry pick, I use all the data.

                    Choosing 130 wells out of 12,000 wells might be more in line with cherry picking though as someone has done for the Bakken.

                    The rhetoric and tortuous logic also seem to be a strong suit of yours bringing up philosophers and historians to somehow prove your comments have some substance.

                  • Glenn E Stehle says:

                    Dennis Coyne says:

                    “The LTO models are quite simple.”

                    That’s the understatement of the century.

                • Glenn E Stehle says:

                  shallow sand

                  “TT. I agree with you, we do not know UR till the well is plugged.

                  Lots of things can happen to enhance EURs of wells that are already drilled and completed. As one anyalyst said, when it comes to shale we’re still in the first inning.

                  For instance, QEP is having success with re-fracs in the Hyanesville, which helps explain its 2Q2017 earning beat.

                  Core Labs and others are beginning to explore the prospects for various types of enhanced oil recovery (EOR) for shale reservoirs:

                  Discussion of the feasibility of air injection for enhanced oil recovery in shale oil reservoirs

                  Experimental Evaluation of Shale Oil Recovery from Eagle Ford Core Samples by Nitrogen Gas Flooding

                  Characterization and Evaluation of the
                  Bakken Petroleum System for CO2 Storage
                  and Enhanced Oil Recovery (EOR)


                  • @whut says:

                    “As one anyalyst said, when it comes to shale we’re still in the first inning.”

                    The geophysics of collecting oil from porous shale is based largely on diffusion.
                    The problem with diffusion is that it is uncontrolled — a frac can send the oil deeper just as it can send it toward the surface.

                    So, unless technology advances and starts producing self-assembling robots that can crawl through the pore-space and collect globules of oil and then make make their way back, the efficiency of the collection will always be less than optimal.

                    Not impressed with the results of a refrac that clearly shows the expected diminishing return. The first frac dispersed the oil even further, and the second frac is trying to recover the oil that is even more spread out. So what do they see, like a 10% additional return?

                    Diffusion engineers such as myself are not impressed.

                  • Glenn E Stehle says:


                    Since when does theory trump reality?

                    Early wells in the Bakken recovered something like 2% of original oil in place (OOIP), and more recent wells, using the most advanced completion technologies, something like 8 or 9% of OOIP.

                    EOR has the potential to give that recovery figure another big boost.

                    Going from 2% to 8% of OOIP is a four-fold increase in recoveries. Going from 2% to 20% would be a ten-fold increase in recoveries.

                    This is not rocket science, despite your rhetorical (certainly not scientific) attempts to make it so.

                  • @whut says:

                    So, if the technology has improved so much in 6-years, then why is that refrac flow shown in the last chart so tiny? Why isn’t it 10x as big as the original frac?

                  • Dennis Coyne says:

                    Hi Glenn,

                    The recovery factor did increase when the horizontal wells and fracking first started from 2005 to 2008, since then there has been very little change .

                    We don’t really know the recovery factors or the OOIP, you are speculating.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “• The recovery factor did increase when the horizontal wells and fracking first started from 2005 to 2008…

                    • since then there has been very little change (in the recovery factor)…

                    • We don’t really know the recovery factors…”

                    Lordy, Lordy! Talk about an orgy of cognitive dissonance, that one takes the prize.

                  • Dennis Coyne says:

                    Hi Glenn,

                    Yes that was poorly stated.

                    The EUR of the average well increased from 2005 to 2008, it roughly doubled.

                    The OOIP has been estimated between 300 and 500 Gb, USGS expects the TRR to be about 10 Gb (mean estimate).

                    Recovery factor (RF) would depend upon OOIP.

                    If OOIP is 300 Gb RF is about 3% and if OOIP is 500 Gb RF is 2%.

                    We really don’t know how much of the OOIP has been accessed by the wells drilled to data so any claims about recovery factors are specious.

                    We don’t know how much oil will be recovered (USGS estimates 8 to 12 Gb in the ND Bakken/Three Forks) or the OOIP, so your claim that we know the recovery factor is highly speculative.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “We really don’t know how much of the OOIP has been accessed by the wells drilled to data so any claims about recovery factors are specious.

                    We don’t know how much oil will be recovered or the OOIP, so your claim that we know the recovery factor is highly speculative.”

                    I think most people drilling shale wells have a pretty good idea what the OOIP under their leasehold was.

                    And after their wells have been producing for a while, they have a pretty good idea how much of that OOIP they’re going to recover.

                    Any additional development of course entails risk. The risk, however, can be lessened by emulating the successful techniques used by other operators in the field, or similar fields. Every operator doesn’t have to reinvent the wheel, believe it or not.

                    It is of course near impossible to get a precise handle on reservoirs and recoveries using the type of field-wide analysis you prefer. This type of analysis entails a lot of broad, sweeping generalizations.

                    But if we move back down to the micro level, to the individual operator level, most shale operators know a lot more about their particular leases, the reservoirs beneath them, and how much of the OOIP they stand to recover with current technology than what you imagine.

                  • Dennis Coyne says:

                    Hi Glenn,

                    Yes the analysis has broad sweeping generalizations, but works fairly well.

                    I do not have the time or the data to do a well by well analysis of the 12,000 wells in the Bakken. If we add them all up we would get reported output (if the data is accurate in both cases).

                    Chart below shows most recent North Dakota Bakken/Three Forks model through May 2017 with data, the model was 4% too low in May 2017 relative to the data.

                    If chart is too small, click on chart for larger image (true for every chart at POB).

                • OFM says:

                  About that two dollar gasoline……

                  It bears MENTIONING that most people don’t know, or give a damn, about anything not of immediate concern to them in their daily life.

                  There are at least fifty million AMERICAN voters, in total, who have heard the “Drill Baby Drill” mantra and now, for one reason or another, the drilling happened, and they have two dollar gasoline, for one reason or another.

                  And since they pay about as much attention to the environmental issue in general, and peak oil issue in particular, as I pay to the scores of professional athletic teams, meaning NONE, except in passing in casual conversation, they have assumed we peak oilers, and environmentalists, are either idiots or out for grant money or both, etc.

                  And so they were inclined to vote for Trump, and this had quite a bit to do with Trump winning, and Republicans across the board winning.

                  We need to be careful how we present our case, inserting some qualifiers here and there, for instance inserting the words ” ten years from now” in a comment about electric cars sharply reducing the demand for oil. Otherwise, our cherry picked words are easily and readily used as clubs to destroy our credibility by the Koch brothers oriented press.

                  I may be the ONLY person in this forum who reads the right wing press AS WELL as the left wing press, on a regular basis.

                  I apologize in advance for being off topic in this comment, but some of the regulars here don’t show up often in the non petroleum thread.

                  • Nick G says:

                    they have assumed we peak oilers, and environmentalists, are either idiots or out for grant money or both, etC

                    POers and environmentalists are two distinctly different groups. POers just got it wrong – that’s all there is to it. On the other hand, environmentalists in general didn’t say “drill baby drill” wouldn’t work to produce $2 oil – they just argued that it was a bad idea – that oil produced a lot of pollution, and that we would be better off concentrating on greater efficiencies and substitutes like EVs. And, they were right.

              • Dennis Coyne says:

                Hi Texas Tea,

                You are correct that I do not know what most reservoir engineers think, I have heard the opinions of only two.

                I also agree we don’t know what will happen to new well EUR, but based on the experience in the Bakken/Three Forks of North Dakota where we have data from 11,000 wells the increase in new well EUR has been pretty marginal ( maybe 17% total or so over the past 9 years).

                The increased output is mostly over the first 24 months, after that cumulative output is the same or less than 2008 wells (months 25 to 120 cumulative output.)

                The big increases in the Permian basin are mostly due to longer laterals, increase the lateral by a factor of 2 and output doubles but the number of potential wells falls by half for any given area if the longer laterals become the norm.

                • Glenn E Stehle says:

                  Dennis Coyne said:

                  The big increases in the Permian basin are mostly due to longer laterals, increase the lateral by a factor of 2 and output doubles….

                  Using data for the Permian Basin, and comparing the initial output of wells whose first production was 2017-01-01 vs. those whose first production was 2014-01-01, what we see is that output has approximately doubled.


                  But if we look at the average lateral length in the Permian Basin during the same period, it’s only increased by about 15% or 20%.

                  So to sum up, average well productivity has doubled, but average lateral length has increased by only about 15 to 20%.

                  Empirical data has proved your assertion to be false.

                  • Dennis Coyne says:

                    Hi Glenn,

                    Based on the data from Enno Peters and fitting a hyperbolic to earlier and later data, the EUR has roughly doubled (100% increase) while lateral length has increased by about 66%.

                    So about two thirds of the increase in productivity is from increased lateral length.

                    Many people consider more than half as “most”, you may be different.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    “….lateral length has increased by about 66%.”

                    And where did you come up with that gem?

                    As the chart from BTU analytics I have provided indicates, average lateral length in the Permian Basin has increased by about 15% to 20% between 2014 and 2017, not 66%.

                    Can you provide a citation to where you came up with that 66% figure?

                  • Dennis Coyne says:

                    Hi Glenn,

                    Initial output does not determine the EUR of a well, higher initial output changes the overall shape of the well profile, you seem to miss this basic point.

                    Several factors have caused the well profile to increase, including increased lateral length (and more proppant and more frack stages per foot of lateral).

                    Just like happened in the ND Bakken these increases from frack stages and proppant will reach an optimum level and further increases will be minimal, this point is likely to be reached between 2018 and 2020. After that EUR per foot of lateral length will remain relatively stable in the Permian basin until sweet spots are fully drilled, then EUR per new well will decrease. It is unclear when that will occur, but a rough guess is 2023 to 2025.

        • Dennis coyne says:

          No shortage of energy is likely. Oil is a different matter by 2025.

    • That website is run by rabid cornucopians who don’t know much about the oil industry. They actually think the USA will be a giant gas and oil exporter for decades, blah blah blah

  9. Boomer II says:

    Investors don’t want big oil companies to spend too much on new projects.

  10. Glenn E Stehle says:


    Recent headlines from journalists and industry veterans alike have pointed to the latest EIA Drilling Productivity Report (DPR) as a sign that US oil production growth rates are slowing and that the growth in Permian productivity has stalled out. (See chart below). BTU Analytics would contend that those hoping that Permian productivity has hit a peak and thus US oil production forecasts are overblown are deceiving themselves….

    As of July 2017, BTU Analytics estimates the fleet drilled 375 horizontal wells but only turned to sales approximately 250 wells, reducing the effectiveness of the rig count by 33%. Adjusting the rig productivity for July by the effective rig count (607 / 67%) indicates that rigs are contributing more than 900 barrels per rig, nearly 30% above the EIA peak in productivity in August 2016.

    • daniel says:

      did they take into account the reduction in DUCS in 2016? This distorted the data as well

      • Glenn E Stehle says:

        In the Permian Basin the reduction in DUCs in 2016 was very small.

  11. Boomer II says:

    To me, projections of how long the oil will last are less important to me than actual LTO decline rates. If these are relatively short-lived wells and the only way to maintain production is to constantly drill new wells, and if the process continues to lose money, or break even at best, this is not an especially sustainable industry.

    And I look at what the major oil producers are going to see how their current decisions might foretell their expectations of the future.

    From what I can tell, the LTO business model has been based on lenders and investors who may very well never get their money back. So the cash keeps flowing to LTO as long as people are willing to take those financial risks, but could come to a halt if financial sentiment changes.

  12. MASTERMIND says:

    U.S. energy secretary duped into fake interview with Russian comedians

  13. MASTERMIND says:

    Saudi Arabia hires Goldman for Riyadh airport stake sale, (Going out of business sale)

    I bet they won’t haggle too much over the price…. given it will soon be worthless

  14. Watcher says:

    Concerning “looking things up”. EPS are ttm. Trailing twelve months. This avoids issues of YTD or having annual earnings conform to the company’s financial calendar. It also smooths out seasons or events.

    So go have a look at CLR or WLL or EOG and see what lenders are gonna be stiffed. For extra credit, go find the S&P or Moodys rating of their 10 yr paper.

    Btw shell just reported in Europe. Downstream and chemical earned them money net. Having no shale burden helped a lot.

  15. George Kaplan says:


    In addition to being the latest confirmation of Horseman’s bearish shale thesis, Whiting also posted its eighth consecutive quarterly loss, as production slipped, sending its shares lower by 4% to $5 in after-hours trading. The company’s stock has fallen 60% YTD.

    As we said on Monday, the launch of a new round of CapEx cuts “will likely end up being positive for oil prices as much of the “swing” crude production courtesy of the US shale basin is about to be reduced substantially, in a clear victory for OPEC which has been waiting long for just this day.”

    It seems to me the LTO players work on a six month to one year boom to bust cycle, so the oscillations don’t get as big as those in the five to ten year cycles for megaprojects.

    • George Kaplan says:

      Hess also knocking 4% off capital expenditure after a loss and lower production.

      • Daniel says:

        Traditional e&p companies posting steong results in contrast to very poor q2 reports from shale companies. Will the investing comunity “wake up”? Probably not…

  16. George Kaplan says:

    US stocks look like they’ve fallen off a cliff, another 10.1 mmbbls last week (7.2 crude, 1.0 gasoline, 1.9 distillate) – about 1.2% like the previous week.

  17. George Kaplan says:

    IEA July OMR is open to the public today for anybody interested.

    • From the report:

      “Global refinery throughput is forecast to reach a record high of 81 mb/d in 3Q17, up 0.8 mb/d from 2Q17 levels. The US contributes half of the 3Q17 build. Refinery runs will decline seasonally by 1.5 mb/d from the peak August level to October.”

      As far as I can see, given the amount of NGL, biofuels and refinery growth we see reported in the total, the refinery throughput and storage change may be a better number to track?

      • Dennis Coyne says:

        Hi Fernando,

        Yes it looks like refinery throughput tracks C+C output fairly well and gives a better indication of C+C output than considering all liquids by volume.

        It would be nice if the IEA used mass instead of volume for all liquids as this would track actual energy output more closely. The barrels of NGL and biofuels only have about 65% of the energy content of the average barrel of C+C.

        So if we take the 98 Mb/d of liquids output we get roughly 80*1+18*.65=91.7 Mboe/d (million barrels of oil equivalent per day).

        It is probably a little less than this because “refinery gains” are just the higher volume of lower energy products such as gasoline (which has less energy per barrel than the average barrel of crude plus condensate) and are phantom barrels that would be ignored if figuring barrels of oil equivalent.

      • Watcher says:

        Reports China’s refinery throughput up to 11.2 mbpd. (Their all liquids total is 12ish for consumption). This rise is on par with last year’s growth rate. Zero evidence China consumption growth is slowing.

        Domestic oil output actually rose month to money in June. Their decline rate will be much less than last year.

    • Energy News says:

      OECD industry stocks, crude & major products
      Chart on Twitter:

  18. Boomer II says:

    We have a few people here who tell us all is great in the oil business. But we’re not the decision makers.

    The financial community is not so impressed.

    “By prioritizing production growth over profitability and margins, investors and producers are at risk of killing their goose before it lays a golden egg,” according to Wood Mackenzie analyst Benjamin Shattuck.

    • texas tea says:

      Boomer says, “We have a few people here who tell us all is great in the oil business. But we’re not the decision makers.”
      I am not sure where “here” is in your world. No one in the industry likes sub $60. No one in the industry benefits by sub $60, but contrary to some here, this forum, we don’t speak out our asses about things we no nothing about. Some here KNOW that there are some people and companies and some LTO plays that can MAKE FREAKING MONEY at $50. that is just a fact. I am one such person in one such play, another fact. I have said for as along as I have posted here companies should seek profits over growth and the market would applaud that, its has always been the traditional business model.

      • Boomer II says:

        The financial markets are increasingly skeptical that there is money to be made. You can say that there is, but if the investment money and loans dry up, there will be companies that will be hurt.

        What I am suggesting is that posting here about money being made means nothing to those with money deciding where to invest it.

      • Dennis Coyne says:

        Hi Texas Tea,

        Perhaps there are a few small private companies making money in the LTO plays.

        On average the largest non-major LTO focused companies are not doing well as a group, at least through 2016. Also the oil price is under $50/b.

        Can you point us to the large LTO focused publicly traded companies that have positive GAAP earnings, excluding major oil companies such as XTO (owned by XOM), Statoil, or Conoco Philips?

        I agree there are maybe 10% of LTO wells that may be profitable at $50/b. The problem is the average well loses money at current prices, and that is a fact.

        • Glenn E Stehle says:

          Dennis Coyne said:

          Can you point us to the large LTO focused publicly traded companies that have positive GAAP earnings, excluding major oil companies such as XTO (owned by XOM), Statoil, or Conoco Philips?

          I already did on the last oil thread.

          It’s called Encana.

          The way your mind works, however, is that any evidence that doesn’t conform to your peak oil ideology is either ignored or summarily ruled inadmissable by use of one tortuous logic or the other.

          • shallow sand says:

            I haven’t looked. Did Encana break down earnings by region?

            • Glenn E Stehle says:

              Encana concentrated its investment activities in four shale plays: Montney, Duvernay, Permian and Eagle Ford. Late last year it announced it was shedding most of its conventional assets.

          • Dennis Coyne says:

            Hi Glenn,

            How much tight oil did they produce in 2016? Seems they are not all that big a player. Based on data from the averaged about 75 kb/d in 2016 of about 3750 kb/d by all tight oil produced in the areas covered by shaleprofile, that’s about 2% of US tight oil output in those states covered by Enno Peters.

            The problem is that most of the other 98% of US tight oil output is burning cash and results in negative GAAP earnings.

            You had to dig deep to find any positive news, are there other large oil producers that have positive earnings (top 10 LTO producers that are non-majors)?

            • coffeeguyzz says:


              …speaking of Encana …
              Today’s RBN Energy blog has an outstanding description of how hydrocarbon reserves are calculated and presented to government authorities (US and Canadian, in this case).

              For you folks who put a great deal of emphasis on future capacity potentials based, in part, on officially sanctioned criteria, this RBN piece can be particularly informative.

            • Glenn E Stehle says:

              Dennis Coyne said:

              The problem is that most of the other 98% of US tight oil output is burning cash and results in negative GAAP earnings.

              That’s quite a bold claim.

              Can you marshall empirical evidence to back it up?

              That would require breaking out every company’s shale operations from its other operations. And even if that level of detailed information were available to the public, it would be a herculean undertaking.

              • Dennis Coyne says:

                Hi Glenn,

                I guess you would also need to back up the claim that these companies are doing well.

                I looked at the top 10 LTO producers that were not major oil companies, as a group they produced over 30% of US LTO output, as a group the 10 companies lost money from 2014 to 2016.

                No I did not have the information needed to break out the LTO portion of each companies operations.

                To claim either positive or negative earnings for LTO only would require more information than is publicly available.

                The fact is all these companies have been losing money, perhaps the fact that they are all large LTO producers is just a coincidence, but I am skeptical of such a claim.

                How about you prove that they are making money on LTO, because full well costs, output, and oil prices suggests that is not the case.

                Note that the full cost of a well includes land cost.

                Even in cases where companies have land access due to legacy wells, there is still the opportunity cost of the land.

                If the rights to produce on that land was sold to someone else, the price of such a potential sale reflects the land cost and should be included in the cost of the well.

                A proper accounting of the full well cost would reflect all costs including land at full value.

                • Glenn E Stehle says:

                  Dennis Coyne said:

                  I guess you would also need to back up the claim that these companies are doing well.

                  Well no, I don’t “need to back up the claim that these companies are doing well” becuase I never made the claim that “these companies are doing well.”

                  Since 2014, most oil and gas companies’ earnings have not been good.

                  But if you’re going to blame shale for what ails oil and gas companies, then you must be prepared to demonstrate with empirical evidence that the oil and gas companies’ shale assets are performing worse than their other, non-shale assets.

                  Can you do that?

                  And if you’re going to allege that “most of the other 98% of US tight oil output is burning cash and results in negative GAAP earnings,” you must be prepared to demonstrate with empirical evidence that to be true.

                  Can you do that?

                  Or are you blaming shale, when other factors are to blame for oil and gas companies poor financial performance since 2014?

      • MASTERMIND says:

        Isn’t Texas the state where they executed a mentally handicapped man a few years ago?

        • OFM says:

          It’s also the state that leads in wind energy, because the government of Texas can be quite forward looking in certain respects, and of course because Texas has an EXCELLENT wind resource making it possible to invest profitably in wind.

  19. shallow sand says:

    So, QEP sells assets and then announces a Permian acreage purchase with the proceeds. The market reaction is that the stock drops over 14%.

    So, are companies now being punished for piling into the Permian?

    I would note QEP beat on EPS, loss of 8 cents versus Street expected loss of 20 cents per share.

    Is this a one off, or is the worm turning? Maybe Wall Street wants to see if deals will make money, not just increase production in the favored Permian?

    • Glenn E Stehle says:

      “Piling into the Permian”?

      Let’s see.

      • In 2Q2017 only 13.94% of QEP’s total production came from the Permian.

      • After the Permian acquisition, only 20.22% of QEP’s acreage holdings were in the Permian.

      • Before the acquisition, 17.08% of QEP’s acreage holdings were in the Permian.

      Is that what we call “piling in” these days?

    • Glenn E Stehle says:

      “QEP sells assets and then announces a Permian acreage purchase with the proceeds. The market reaction is that the stock drops over 14%.”


      The announcement that QEP was selling its southwest Wyoming properties in order to buy Permian acreage was made on July 24. The stock price did not respond in any way to this announcement.

      QEP announced 2Q2017 earnings at 9:00 a.m. on July 27. It was after this announcement that the stock tanked.

      So you cannot demonstrate correlation between the announcement of the sale of the Wyoming properties and the stock tanking, much less causation.

      • shallow sand says:

        Ok. I wonder why the stock tanked given the earnings beat?

        Looks like they paid around $65K per acre. Must be some good acreage.

        • shallow sand says:

          I wonder if QEP will sell out of the Bakken like HK did? Might boost the stock price as they could use part of the proceeds to pay down debt and part to add Permian rigs?

        • Glenn E Stehle says:

          Could it have something to do with this? Very high D&C costs for 7,500′ lateral wells, which most of QEP’s are.

          • Dennis Coyne says:

            Hi Glenn,

            What about land cost?

          • shallow sand says:

            Glenn. It does not look like these costs are on the high side.

            • Glenn E Stehle says:

              shallow sand said:

              “It does not look like these costs are on the high side.”

              QEP CEO Chuck Stanley said during the July 27 a.m. conference call: “The acquisition cost is roughly $2.50/boe for this asset. The development cost is another $10-12/boe. So all-in youre talking about $14/boe cost to develop this asset.”

              Why would you believe these costs are “not on the high side”?

              1Q2017 Pioneer reported $9.11/boe F&D costs. Plus almost all of Pioneer’s acreage, as well as many other operators in the Permian Basin, is legacy acreage, so their acreage cost is essentially zero.

              That’s a difference of almost $5/boe, which in today’s tough oil price environment could make it difficult for QEP to compete with other more efficient and better positioned operators.

              • shallow sand says:

                I thought you were referring to the graphic you posted which refers to D & C and equipment costs for QEP.

                I do agree that companies such as PXD, Concho, XEC, OXY, EGN and CVX, which all have legacy acreage, have a cost advantage.

                Do companies also have a “well cost” advantage in the Permian over QEP. If so, it would be interesting to know the reasons why.

                • Glenn E Stehle says:

                  shallow sand,

                  QEP CEO Stanley threw out the figure of $10-12/boe for development cost.

                  This compares to Pioneer’s $9.11/boe in F&D cost it reported for 1Q2017.

                  Encana says its D&C cost during 2Q2017 for its average 7,500′ lateral well, completed in a range of zones from the sprayberry to the wolfcamp, was slightly less than $5 million. Now look at that QEP chart, and you will see costs for a 7,500′ lateral well ranging from $5.7 to $7.3 million.

                  To understand the “reasons why,” I suggest you take a look at Encana’s July investor presentation, where they explain in great detail how the lower costs are achieved.

                  • Glenn E Stehle says:

                    shallow sand,

                    Here you go. Encana says its development cost in the Permian Basin is $8.00/boe.

                  • Glenn E Stehle says:

                    2Q2017 ExxonMobil has 16 rigs running in the Permian Basin with development cost in the Midland Basin of $7 per oeb, and when it gets its development program in the Delaware Basin kicked off development cost are estimated to be between $5 to $7 per oeb.

                  • Glenn E Stehle says:

                    2Q2017 Chevron has 13 company operated and 7 non-operated rigs running in the Permian Basin, for a total of 20 rigs.

                    Chevron didn’t break down development costs separately, but reports combined development and operating costs of about $15/boe.

                    Chevron’s LTO production from the Permian Basin is greatly exceeded expectations. Chevron guidance for Permian Basin production for 2Q2017 was less than 150,000 boepd, but actual produciton was about 185,000 boepd.

                  • Glenn E Stehle says:

                    Chevron places a value of over $50,000/acre for its best acreage in the Permian Basin, so the $51,000/acre that QEP paid doesn’t appear excessive.

                    What are excessive are QEP’s D&C ($10 – $12 per boe) and lease operating and transportation expense (2017 guidance $9.50 – $10.50 per boe). These are not competitive with what more efficient operators in the Permian Basin are achieving.

                • shallow sand says:

                  It could also be that QEP is not getting as good of results productivity wise as other companies, despite supposedly having some of the best locations.

                  I scanned through QEP 2016 and 2017 wells and did not see any of the “monster” wells that some other companies have had, such as EOG, PXD, etc. I went through them quickly, so I could have missed something.

                  When you discuss finding costs per BOE, there are more variables than just well cost, which I know is stating the obvious. Maybe QEP’s EUR per well is also lower?

                  In any event, it looks like the Street finally wants companies to show a little restraint. I have been whining for a $55-65 WTI range for quite awhile, and maybe if these guys calm down some, we will get there.

                  Yes, I am whining for that range primarily for personal reasons, but I do think in that range we would see much better EPS for the US industry, which I argue is GOOD for the US economy, without taking a big bite from consumer spending, as the gas prices would be $2.40-2.60 in most parts of the US, assuming “normal” crack spreads.

                  EPS for shale has been improving for several companies, despite low prices, no doubt about it. But, sub $50 WTI IMO is a stretch to do much more than have minimal earnings, especially as the service companies aren’t making any money either.

                  I think $55-65 WTI is the sweet spot. I am sure there are those that disagree, and I welcome their arguments for why higher or lower than that range is better, and for who.

                  • coffeeguyzz says:


                    I think that is exactly right for US LTO, from what I’ve seen.
                    The surge in hedging several months back in the low $50 WTI range provided strong evidence that operators felt they could function at that price.
                    Below $50, the slowing down became clear. When the $60/$65 price point appears, I think people will be surprised – not only at the uptick in familiar areas – but at the slowly emerging, shallower drilling in conventional formations across the country.

                    This has already begun in Ohio, Colorado (eastern plains), and the Madison formation in North Dakota.

                    These operations are attempting to employ several of the ‘Big Boy’ unconventional tools such as 3D seismic, ultra precise directional drilling, latest iterations of artificial lift.

                    It is fascinating since these are ‘little guys’ who are pursuing far more modest returns, and they are operating in familiar territory (their backyard).
                    Equipment prices are low and small services companies are ‘hungry’. Should be a somewhat small, yet interesting, consequence of all this ‘shale revolution’ stuff.

                    Same thing is happening with the smaller gas boys, but different economics and operational stuff kicks in … aka pipelines. The world’s first mobile, micro LNG plant, LNGo, got deployed to north central PA several months back for just this reason.

                    One big caveat to all this, however, is that sub $60 WTI is a true death knell to several overseas regimes.
                    This should be obvious by the machinations that are taking place over there.

      • shallow sand says:

        Wait a minute. The link disclosed the sale, but not the Permian purchase.

        I’ll see if I can find any mention of the Permian purchase prior. I had read earlier they were marketing the production they sold, but the Permian acreage I just read about today, but I surely could have missed it.

        As for the piling in comment, QEP had almost nothing in the Permian but has since made some high dollar acreage purchases. It is also what they tend to lead with in investor presentations. So maybe piling in is too strong, but they are trying very hard to become a Permian name, IMO, to boost share price.

        • shallow sand says:

          Glenn. The news release for QEP $732 million Permian purchase was made by QEP after the close of trading on 7/26/17. Further, QEP announced increase in CAPEX budget of $100 million to develop Permian acreage.

          Next day, 7/27/27, stock down 14+%. Motley Fool says that QEP is down because they are going against the grain, while everyone else is cutting CAPEX, QEP is increasing it

          If you have contrary info, please let me know and I’ll read it.

          • Boomer II says:

            Looking at various news stories, the Permian purchase info was written about today, so it was new news.

            • Boomer II says:

              This article said the announcement came out yesterday after market close and it was a very expensive purchase.

              According to analysts, QEP paid the Cox family a rich price for their properties. Tudor, Pickering, Holt & Co. called the deal “expensive” at around $51,000 per acre, versus more than $40,000 for other deals in the area recently. The firm values the company’s existing properties in the region at $47,000 if they’re fully developed and oil trades at around $50 per barrel long term, leaving “almost no room for upside for the company,” it said.


              • Glenn E Stehle says:

                I knew John L. Cox. Many moons ago I got a farmout from Atlantic Richfield and sold the deal to him.

                He looked at the deal himself and, after I laid out the deal out to him, it took him only about five minutes to decide to buy it. It was close to a million dollar commitment, which was a lot of money back in those days.

                I wish I still had the acreage, because it would be worth much more now.

                • Dennis Coyne says:

                  Hi Glenn,

                  Perhaps you know inside stuff that most others don’t.

                  Can you provide a link to news of the Permian purchase, before the date that Boomer and Shallow sand have suggested?

                  Your silence is quite loud on this matter.

                  • Glenn E Stehle says:


                    If you will look at this thread, I have hardly been silent.

                    I have cited the principle reason I believe the stock tanked 15% after the earnings release and conference call: QEP’s D&C costs in the Permian are too high in comparison to other operators.

                    The extra $1.25/boe that QEP paid for the Cox leases may be a factor, but it is not nearly as big a factor as QEP’s high D&C costs.

            • Boomer II says:

              “Following the announcement, investors did not embrace the Permian acquisition. Analysts at Tudor, Pickering, Holt & Co. (TPH) pointed to the ‘expensive price tag.’ By lunchtime, QEP’s stock had lost about 15% of its value on the day, trading down around $1.50/share.

              ‘The market’s No. 1 concern has been around QEP potentially paying up for another Permian deal, and the company did just that,’ TPH analysts wrote. They calculated based on QEP’s disclosed numbers that the sticker price for the acquisition is around $51,000/acre, which they argued ‘leaves almost no room for upside.'”


              • shallow sand says:

                One thing I will say in favor of QEP, if Pinedale DD&A was used up,they may get a big tax benefit for doing a 1031 exchange for the PB acreage. This could help offset the high purchase price.

                I have seen a lot of “1031 money” drive farmland higher than the market.

              • Glenn E Stehle says:

                QEP CEO Chuck Stanley said: ” “The acquisition cost is roughly $2.50/boe for this asset. The development cost is another $10-12/boe. So all-in youre talking about $14/boe cost to develop this asset.”

                This is probably the problem.

                1Q2017 Pioneer reported $9.11/boe F&D costs. Plus almost all of Pioneer’s acreage, as well as many other operators in the Permian Basin, is legacy acreage, so their acreage cost is essentially zero.

                That’s a difference of almost $5/boe, which in today’s tough oil price environment could make it difficult for QEP to compete with other more efficient and better positioned operators.

                • Boomer II says:

                  But Shallow’s original comment is that we may have reached the point where Permian acquisitions are no longer enough to please investors. Realism has set in.

      • Dennis Coyne says:

        Hi Glenn,

        That piece only says they have been looking to purchase Permian properties, it says nothing about a specific purchase, only about the sale of Wyoming property.

        It was the announcement of the purchase in the Permian that drove the stock price down.

  20. Boomer II says:

    How Oil Prices Are Held Hostage By Derivatives | “Unfortunately, that’s what really determines the price of oil – financial transactions involving oil derivatives, not the trade in oil itself.”

    • twocats says:

      good article boomer ii. watcher recently had a scathing critique of “supply/demand” arguments in which he listed like 10 things comprising many economic transactions that have left the supply/demand dynamic.

      for those hoping… that peak oil will ever send the proper “market signals” to the global economy (other than accidentally) and, on top of that, will actually result in the proper reaction of a sincere power-down / “renewablitz” (you’re welcome) combination… well, I participate in a lottery pool at work so I can’t really fault a person for false hopes.

  21. Boomer II says:

    Shale oil drillers are cutting spending as oil prices languish: “‘Spending within your cash flow is becoming a more important element for all oil and gas producers at this time,’ he said. ‘Outspending your cash flow is something that I think investors are becoming less comfortable with.'”

  22. Boomer II says:

    U.S. shale producers cutting budgets as oil prices lag: “This week alone, Anadarko Petroleum Corp, ConocoPhillips, Whiting Petroleum Corp and Hess Corp cut a combined $750 million from their capex plans, each citing weaker-than-expected oil prices.

    The quartet are just the first in a wave of oil industry earnings results expected over the next two weeks, with many analyst expecting peers including Noble Energy Inc and Marathon Oil Corp to cut their own spending in order to appease Wall Street’s demands for fiscal restraint.”

    • shallow sand says:

      I’d say the tail is sure wagging the dog in the oil patch.

      One would think firms would develop long term plans on developing their assets.

      Instead, it looks like the Street is dictating to them what they should do. First it was grow, now it is cut back. All in the same year.

      What if QEP has acreage that is the best of the best? What if they need to drill due to contractual commitments?

      The unison with which these firms are acting is concerning. Almost enough to claim collusion. But, I assume it is not collusion, it is just taking orders from the Street, which could probably sink most of them given the less than stellar financial shape they are in.

      That the Street has so much control is a concern. I’d rather have trained and experienced engineers and other professionals in the industry having the stroke with management, as opposed to bankers who likely do not know as well as the engineers, geologists, etc how to maximize the recovery of oil, gas and products from these shales.

      Yes, these reserves are generally privately owned. However, they are extremely important national resources. That is why spacing rules, etc have been developed.

      I sure hope these companies have not stranded a lot of oil because they felt like that had to pad drill to please Wall Street.

      I am sure this post will get a negative response from Glenn and TT. Keep in mind guys, what Al Walker just said to the Street a month ago.

      Maybe I am wrong, maybe the E & P”s don’t allow the Street that much clout. However, for a bunch of companies that would seemingly be led by independent thinkers, they sure are looking like they are taking orders. Six months ago pedal to the metal. Now, tapping the breaks, and all in about the same proportion.

      Last but not least, have to wonder about all these asset sales to PE. Are the money center banks putting so much pressure on firms to sell “non-hot play” assets for nefarious reasons when we are in a depressed market?

      • Boomer II says:

        But they have to take orders from the Street if that’s where the money comes from to keep going. The alternative is to self-fund, which is the most sensible thing to do.

        Now for the majors, they may be paying attention to the Street as their best hope to get money out of their companies before they run out of options. The goal would be to keep stock prices up rather than planning for a long-term future.

        Investors don’t really have any obligation to do what is best for the industry. So most of them aren’t likely thinking if these companies will still be around 10 or 20 years from now.

      • George Kaplan says:

        SS – I don’t think it is collusion. I worked for various IOCs, not on LTO but larger projects, they all tend to work in the same way, they all have an economic model on which to base decisions, and although these are kept secret, they all tend to be nearly the same. The career path is also similar in all – people move jobs every couple of years and do not have to live by their decisions, but more by impressing their immediate boss and not being associated with any financial disasters (whether their responsibility or not). Hence all the companies made pretty much the same decisions at the same time.

        It may be a bit different for smaller LTO companies, and when I worked there was almost no debt for the larger companies, but shareholders (rather than bond holders) still had a big influence and the focus was always on next quarters figures, however the evidence suggests it’s still as I experienced.

        • Hickory says:

          A country with an energy policy (adults at the table making long term decisions aimed at the common good for the overall economy) would not be allowing export of petroleum products and would not be allowing drilling at a fast pace.
          They would be aiming for a more sustained production output over time.
          Big mistake .
          Like cutting down all the forests in 10 yrs and exporting the logs, and then having huge unemployment in the lumber industry for the next 3 decades.

          • @whut says:

            “Like cutting down all the forests in 10 yrs and exporting the logs, and then having huge unemployment in the lumber industry for the next 3 decades.”

            Here is an interesting parallel from geophysicist Pirrehumbert

            The story of Wisconsin white pine timber depletion, recounted in William Cronan’s book Nature’s Metropolis, should give us pause:

            The manufacturer’s acute seasonal need for short-term credit drove them to the one market where they knew they could get quick cash, even if it meant that they were forever selling lumber at lower prices than they liked. Under such circumstances, the only way they could keep up with costs was to cut more trees, contributing still further to the overproduction and saturated markets that had created low prices in the first place. Chicago thus became the focal point of a vicious circle: Undercapitalization caused overproduction, which in turn kept prices low and accelerated the destruction of the northern forest. The Lumberman summed up the problem by attributing it to “so many men … striving to carry on a larger business than their capital will warrant” and, as a result, having to turn natural capital into liquid capital merely to survive. “The only reasonable explanation of this paradoxical state of affairs,” the Lumberman’s editors wrote, “is that the mill men … are using up their capital, as it exists in the form of stumpage, for no other end than simply keep themselves in business.”

    • Boomer II says:

      But EVs aren’t currently a threat to oil prices, yet oil prices are low. EVs or not, we can still get low oil prices.

    • Dennis Coyne says:

      Hi Texas Tea,

      That is an interesting opinion piece, other empirical evidence is that plugin vehicles sold Worldwide increased by 65% per year from 2014 to 2016.

      Also note that change can happen quickly as it did when the World changed from horses to automobiles from 1910 to 1930. We may be on the verge of such a transition from ICEV to EVs, so far even the most optimistic forecasts have proven to be too pessimistic. We may see 25% growth in EV sales for 20 years, at which point 50 % of new personal vehicle sales would be plugin vehicles.

      The costs of EVs keeps decreasing and within 5 years will be on a par with ICEVs. Oil prices are also likely to increase within 5 years making ICEVs less attractive, this may result in the 25% per year sales growth assumption being too pessimistic.

      The guys at will only see this when oil prices start to fall due to lack of demand, though trucks and air travel may keep demand high, eventually these will be replaced as well especially if supply cannot keep up with demand and oil prices remain high.

      • MASTERMIND says:

        EV’s will never catch on in the US ever. There are only around 86 million garages for over 250 million vehicles. And just do a youtube search for “Tesla Problems”. They are some of the least reliable cars that are made. Sorry Delusional Dennis!

        • Hickory says:

          I think you are dead wrong on this M.Mind
          New ICE will be rare for passenger vehicles in 10 yrs.

          • MASTERMIND says:

            Triple AAA just raised Tesla’s rates by 30% because they break down so much and make so many claims. Do you trust triple AAA? No I doubt it. That would pop your techie delusional dream of a brighter world.

            • Hickory says:

              I am not saying that Tesla will even exist in 2030. Maybe.
              They might be outdone by the Amazon EV, or one from China like BYD (backed by Buffet), or maybe one from Softbank- they have hundreds of billions to throw around.
              And no I don’t believe in some brighter world. I see us as far far into overshoot territory that will lead to a very painful downsizing.
              Still, ICE days for passenger cars are numbered.
              Vacuum tubes were replaced by transistors in about 10 yrs time, by mid-50’s. Digital cameras sunk Kodak in about 5 yrs. That kind of thing is about to happen.

              Where will people charge them?- at places with electricity probably. There are more places with electricity than with gasoline. I would prefer to be able to swap out battery. Maybe that mechanism will be part of the choice, if not I’ll charge at home mostly.

              • OFM says:

                You won’t be swapping out batteries, because they are too big and too heavy, and even with a standardized design, the business model ain’t going to work.

                Too slow to swap. Too many different cars using different batteries, not enough customers to cover the investment in a station alongside a major highway for many years to come, maybe forever.

                Plus there is no standardized design, and most likely there won’t be one.

                Fast charging will rule.

                It could be that you will be able to buy or rent an extra battery mounted in a small trailer to hook on behind your car, which you can exchange for another , a few hundred miles down the road. You might even rent one that fits into the trunk or hatchback, or even to haul on a roof rack, if your electric car is wired to accept it.

                People that need to go ten or twenty hours straight stopping only five or ten minutes will be able to own or rent a conventional car for at least another thirty or forty years. After that……… who knows ?

            • Nick G says:

              It kind’ve makes sense – the high end Teslas are pretty expensive, they’re new so not that many shops can do the work, and the bodies are made of aluminum, which is expensive to repair.

              It’s not surprising that they’d have birthing pains. The amazing thing is that Tesla has been able to break in to the car industry at all. The physics and economics of EVs have given Tesla an opening, but if the big car companies were able to disrupt themselves and push forward with EVs aggressively Tesla would never, ever have a chance. Amazingly, the big car companies STILL aren’t responding properly, and Tesla is still in a good position to grow and succeed. It’s astonishing!

              • Fred Magyar says:

                The amazing thing is that Tesla has been able to break in to the car industry at all.

                To be fair, Tesla is actually a combination computer on wheels, AI, big data, energy storage and energy production company.

                They are light years ahead of ICE and fossil fuel companies. EVs don’t have to burn dirty carbon based fuels to produce heat energy to move thousands of complex parts in highly inefficient engines…

                They are not even remotely comparable. A Tesla has roughly 20 moving parts total and is powered by stored electrons flowing into a 95% efficient electric motor.

                To be clear it doesn’t matter one whit if Tesla as a company survives or not, the technology they are using is orders of magnitude better than the fossil fuel/ICE combo of the last 100 years.

                • Boomer II says:

                  The advantage Tesla has over other companies is planning for the day when its primary product is replaced by competitors.

                  Opening up a market, and then moving on, is often the right approach in a fast changing technological marketplace.

                  If you can’t see the future and then fight like hell to preserve the past, you will likely get left behind at some point.

                  • Fred Magyar says:

                    If you can’t see the future and then fight like hell to preserve the past, you will likely get left behind at some point.

                    The future has arrived…

                    Elon Musk announces Tesla Model 3 Edition 2017 on July 29 Event. The new car has amazing performance characteristics. Now it can charge faster! This is the full presentation of Tesla Model 3 2017 Edition within July 29 event!


                    100% Electric, 300 mile range with fully autonomous capability already built in, just waiting for regulation to catch up.

                • Nick G says:

                  They are light years ahead of ICE…companies.

                  Not really. GM was a pioneer, and could have done everything Tesla did, and done it better years before. But, they didn’t have the vision. They didn’t believe in EVs, they didn’t like EVs, when they produced EVs they sabotaged them in every way they could.

                  And look at Nissan. Just like GM, some of the leadership believed in EVs, but the rank and file sabotaged them – just look at how ugly the Leaf is.

                  Then look at the Tesla Model S – it’s beautiful. It clearly was produced by a company that really wanted to have their product succeed.

                • Boomer II says:

                  “Tesla’s Model 3 Is Here and It’s Much More than an Electric Car”


        • Fred Magyar says:

          EV’s will never catch on in the US ever.

          Do you live on this planet with the rest of us or are you just passing through from some far away galaxy?

          The high level of confidence that automotive industry leaders have in the future of electric vehicles (EV’s) has been on full display recently.

          In just the past few weeks:

          Tesla’s Model 3 started to roll off the assembly line
          Daimler announced a $740 million investment to produce EV batteries in China
          Cummins noted it would have a fully electric truck platformavailable by the end of 2019
          Lyft pledged to provide a billion rides a year powered by electricity by 2025
          Porsche set a 2023 target for having 50 percent of its production be electric vehicles
          Volvo Cars announced that “all the models it introduces starting in 2019 will be either hybrids or powered solely by batteries”
          This spurt of corporate announcements has been paired with a bevy of statements of international leadership:
          France declared it would be all electric by 2040
          India challenged itself to be gas free by 2030
          China took the global lead in terms of number of EVs on the road
          These developments are more than just excitement about an emerging solution. They are indicators that the market for EVs is developing faster than anticipated even just last year.

          Consider the findings of a new report from Bloomberg New Energy Finance

        • Songster says:

          Read a little more carefully Mastermind and you would find that many of the Tesla problems stem from pushing the envelope feature-wise with the doors on the Model X. Hardly a scathing indictment of EV adoption in the US or in the world. What about the Volt, Prius, Leaf? Forget about those? Or did you just wish to make a “hair on fire” argument to denigrate EV’s. Try again.

          EV’s will dominate land transportation…because they are cheaper to own, more reliable, and one hell of a lot of fun to drive. If you haven’t noticed, practically every automotive company out there is either selling some kind of an EV or imminently planning to. They must see something. Maybe it the Teslas that outrun their much more expensive ICE cars?

      • texas tea says:

        the empirical evidence outlined in the article shows that only rich people buy EV’s and then only when the government pays a huge chunk of the cost and gives them perks and access to HOV lanes, as most rich folk aren’t stupid when the government stop paying for the EV”S the rich stop buying them.

        of course since debt does not matter the government can always buy everyone a new car, a new tv and of course heath care, think of the cash that will free up for things government as not yet stepped up to provide😜

        • Dennis Coyne says:

          Hi Texas Tea,

          As costs fall the subsidies will no longer be needed, in fact the rebate to Tesla buyers will be used up pretty quickly as production ramps up.

          Many luxury cars have reliability problems, Tesla may be no different.

          Reliability will need to improve for the Model 3 to be successful.

          • MASTERMIND says:

            Where are people going to charge them Genius?

            • Nick G says:

              Unlike underground fuel tanks, electrical infrastructure can be placed anywhere: parking meters, parking garages, wireless pads under parking spaces, etc., etc. My local drugstore has 4 charging spots.

              Go to Canada: above a certain latitude cars need to be plugged in to heat the engine block overnight: those plugs can be anywhere.

              One charging point at the market doesn’t cut the mustard. Hundreds of charging points distributed all over the neighborhood certainly will.

            • Fred Magyar says:

              Come on! look at the current map of chargers which are being expanded all the time
              909 Supercharger Stations with 6,118 Superchargers

              • twocats says:

                I don’t think very many people would buy an EV unless they personally owned the means to charge it. even just having charging stations at work – I’ve heard personal accounts of arguments starting over charging spots. plus, people move jobs more and more. what if your new job doesn’t have a station or one nearby. you’d literally have no way to conveniently charge your car – again, assuming you don’t personally own one or have GUARANTEED access at home.

                people want to compare this process to TAAS or cellphones but zipcar (one of the early ones) could put as few cars out there as they wanted and if they lived in a dense population people would suck up available demand (because of low monthly charge and “pay per use” and convenient scheduling). the model just isn’t the same with EVs

                • Fred Magyar says:

                  I don’t think very many people would buy an EV unless they personally owned the means to charge it.

                  Right, every single man woman and child in the USA has electricity at home which they can use to charge an EV. It may not be a super charger or very fast but it will charge the batteries. It can be done overnight if necessary.

                  I have a friend who owns a 2013 Chevy Volt which has a limited electric only range. He charges it at home overnight, drives it to work where he plugs it in to a charger plugged into the 120 Volt AC electrical system, charges it as needed and drives it home every night. his round trip commute is about 38 miles and he almost never stops at a gas station…

                  Anyone can slow charge even a Tesla Model S at home, get over this charging not possible bs!

                  And it is even easier with the two wheeled variety of EV, namely the electric bicycle…

                  • twocats says:

                    he pulls the battery every night? how much does it weigh? That would be definitely doable if it were say less than 40lbs.

                  • Fred Magyar says:

                    he pulls the battery every night?

                    Surely you jest?! You just plug the charger, which comes with the car, into any standard 120 V Ac household outlet.

                  • twocats says:

                    then you’re an idiot. how many people out of the millions of big city residents get to park their car in a garage attached to their home?

                    the vandalism alone will be through the roof. well technically through the port.

                  • Boomer II says:

                    In urban areas where parking is hard to come by, people tend not to own cars. So they are just as likely not to own an ICE vehicle, too.

                • Fred Magyar says:

                  then you’re an idiot. how many people out of the millions of big city residents get to park their car in a garage attached to their home?

                  And you are stuck in the past!

                  Aside from the fact that when I lived in NYC I found I didn’t even need a car because the subways and my bicycle worked just fine. Self driving shared EVs will reduce the auto fleet on the streets but I digress. Then there are other ideas like this:


                  Published on Jun 7, 2015
                  Smart Solar Charging starts in Lombok with the first sunpower-controlled charging station en V2G-system. A project of GE, Vidyn, Nissan, Stedin, LomboXnet, LastMileSolutions, Upp Energy, NewSolar, Economic Board Utrecht en de Gemeente Utrecht.
                  More info on:

                  But whatever dude, just keep digging for oil and driving your ICE until you just can’t anymore…

                  • GoneFishing says:

                    The ICE is an amazing machine. Tremendous amount of thought and design has gone into it. It has become a critical and widespread machine of our civilization.

                    But the same could be said of the steam engine. Now they are in museums and the working ones are displayed or run out of museums and county fairs.

                    When better comes along, it’s not long before previous technology goes away. Bye, bye typewriter, dial phone, push lawnmower, hand powered drill, CRT TV, vacuum tube radios, discrete circuitry.

                  • Hightrekker says:

                    Any car, EV or ICE, is a liability in NYC or SF.

                  • Hickory says:

                    Two Cats is correct in that many people in urban areas will have trouble with charging at home, for example I currently live in a hilly area. There is plenty of money but space is tight, and many homes don’t have any off-street parking for charging.
                    But even so most will have the capacity and many millions of EV vehicles will in use in 2030.

                  • Boomer II says:

                    The issue in urban areas is already lack of parking. That’s why public transportation is preferable to owning a car.

            • Dennis Coyne says:

              Hi Mastermind,

              Installing charging points is not really a big challenge. Tesla has already begun this process. Businesses will find charge points attract customers.

              • OFM says:

                And pretty soon, landlords who own apartment buildings will be upgrading by installing charging stations at the parking slots assigned to individual tenants, who will be able to lock their station to prevent others from using it.

                Even in the boonies where I live, the more upscale employers are starting to install charging stations for SELECT employees- the kind that are HARD to find, the ones that are REALLY good on new technology.

                And cities and towns will start installing charging stations alongside parking spaces on the street, to be fed with coins or with a plastic card, because there will be MONEY to be made by doing so.

                Some people are are UNWILLING to think a little.
                Others may be UNABLE to think at all.

      • Javier says:

        Hi Dennis,

        so far even the most optimistic forecasts have proven to be too pessimistic.

        That is not correct. In Spain official forecasts by the government’s secretary of industry for 2011 were of 20,000 units to be sold. The actual number came as 800. Only 10 to private owners. That was only 10 more than flying cars and nuclear cars.

        The EU forecast (2012) for Spain in 2020 was 2.5 million electric vehicles.
        That’s 3.5 years away and Spain has less than 50,000 electric vehicles (4746 new in 2016). A few more if you count golf carts. With those numbers obviously increases of 50% or 80% are easy in a good year, but the predictions are wildly off.

        Most electric cars are sold to businesses and government. Private owners in Spain don’t buy electric vehicles. Cabs are transitioning quite fast to hybrids. If you drive a lot they make sense.

        So I find most people here wildly optimistic about the future of EVs over the next couple of decades. For sure there is going to be more, but how many more depends on oil, not on climate or EVs.

        • Glenn E Stehle says:

          Javier said:

          For sure there is going to be more [EVs], but how many more depends on oil, not on climate or EVs.

          That’s why peak cheap oil supply just has to happen, and soon. 😊

          • Dennis Coyne says:

            Hi Glenn,

            I think oil supply will be limited because the resource is finite (which I believe you agree with). When this will occur will depend upon exactly how limited the resource is, if conventional and unconventional oil are between 3000 Gb and 4500 Gb (25% to 75%) probability that URR will be less than these numbers, I think it likely the peak will be between 2020 and 2030.

            When the peak arrives, oil price is likely to increase.

        • Dennis Coyne says:

          Hi Javier,

          I am looking at Worldwide sales, many forecasts have been too pessimistic.

          I agree that it will depend on oil prices, perhaps you expect oil is plentiful and oil prices will remain low, I believe the opposite is true, if that view is incorrect then EVs may take much longer to gain market share.

          • Javier says:

            perhaps you expect oil is plentiful and oil prices will remain low

            Not precisely. I believe peak oil C+C took place in 2015 last time yearly growth stopped. A significantly higher production is possible, but unlikely in my opinion.

            Prices will be decided by what the world economy can afford to pay for the world production. If oil prices go up too much the economy crashes and prices go down. With an economy that is not performing properly due to oil constrains few EVs will be sold.

            • Javier says:

              Yes, I know. You think that we have to wait for 30 years of data before saying that the trend has changed. Well, sorry, but I follow a lot more information than just that number. As the cost of producing oil is increasing as more and more oil is coming from more and more expensive sources, and as oil companies have been cutting greatly in upstream exploration and production, a lower oil producing capacity is already baked in the mix. Together with increasing depletion from old fields is going to create serious problems a few years from now, unless demand decreases. In any case I don’t see how significantly higher production could be achieved for quite a few years.

              In any case looking at the trend is not going to tell you much about the future. And if most vehicles on the road are EVs in a few years, it will be because there are a lot less vehicles on the roads.

            • Dennis Coyne says:

              Hi Javier,

              That is with climate data.

              Overall C+C output (conventional and unconventional) grew from 1982 to 2016 at about 1.2% per year. R squared over 97%.

              I agree this trend may change and if oil prices rise quickly enough then it may be disruptive to the World economy.

              The World economy did fine at oil prices over $100/b from 2011 to 2014, perhaps this will change in the future.

              I would not claim to know what the future will bring.

              I believe the World economy will remain more resilient than you predict and that other energy sources such as natural gas and electricity might gradually substitute for oil as oil prices rise.

              If I am incorrect then there may be a recession (possibly a depression), but eventually the World will recover from such a recession/depression.

        • OFM says:

          Hybrids ARE electrics- at least for the first forty miles or so in the case of hybrids such as the Chevy Volt.

          They will catch on pretty fast as the price of them comes down.

  23. Watcher says:


    1). The shale guys face the fast response reality of output. Most of the cost of the wells is completion. Not drilling. So when they cut Capex they don’t hide behind the DUCs. One could try, but the rig count would not just trickle lower; it would crash. That faces long term rig contracts. So, they are going to complete fewer wells.

    2). Revenue comes from IP. Fewer completions, less IP.

    3) Debt service will be strained. So will production bonuses.

    4) Recent credit rating reviews — compare the legit to the shale

    • clueless says:

      “Recent??” – February 2016??

      • Watcher says:

        About the only place you can get a compilation of up/downgrades in one place without a login at Moodys or Fitch.

        The overall point was ratings for Exxon or Shell contrasted with Continental or Whiting.

        Or even Eni and Total vs Continental or Whiting.

        “The bond guys usually get it right.”

  24. Boomer II says:

    Here is that link mentioned in a comment above.

    Gimme Some Truth – What Reported Oil And Gas Reserves Reveal, And What They Don’t

  25. shallow sand says:

    Baker Hughes lost 42 cents per share GAAP, lost 11 cents per share ex items in Q2, 2017.

    So, we have Halliburton making 3 cents ex items, Schlumberger losing 5 cents ex items and Baker Hughes losing 11 cents, ex items, all per share.

    Repeating, go look at these numbers and compare them to 2Q earnings for companies such as Proctor Gamble, 3M, United Technologies, General Dynamics, DuPont, Coca Cola, Bank of America, Goldman Sachs, Prudential, Pfizer, Microsoft, Nike, etc.

    At sub $50 oil and sub $3 gas, it is a pipe dream that upstream can compete earningswise with other industries, ECA’s 18 cents per share notwithstanding.

    Again, XOM and CVX lost money on US upstream in Q2, 2017. See my post above. $183 million and $102 million respectively.

    • Boomer II says:

      Yes, that’s the primary issue with stock prices. There are better places for investors to put their money. Now, if oil companies pay dividends, then buying those stocks might make financial sense. But we have seen that companies may have to pull back on exploration and drilling in order to have the cash for dividends. So dividends are good to keep investors interested, but may gut the company. Which doesn’t matter if the oil is disappearing anyway.

      As for lending to oil companies, that only becomes attractive if the rates are high enough to account for the possibilty that the companies won’t be able to service the loans.

      Based on the coverage coming out in recent months, the financial community is no longer so positive about gas and oil, either in the present or the future. Trump’s support of fossil fuels isn’t propping up the market.

    • clueless says:

      SS – And Weatherford lost $.28/share ex-items. And Helmerich & Payne [the premier onshore drilling rig company] lost a bunch. I hope that you can now forgive my facetious comment the other day about service companies operating at a loss forever in order to enhance the productivity of the operators – unfortunately, I threw out the name Halliburton, which is about the only large one to make a profit ($.03/share).

      I know that it is a ridiculous exercise, but multiply 3 cents times 4 quarters and divide into $42/share and Halliburton has a PE multiple that only Amazon, Facebook, Google, etc. could dream about.

      This cannot continue. Who [top employee talent] would go to work for these companies? The top people get 25% to 50% or more of their compensation from performance bonuses [including stock]. So even if you get $250,000 of restricted stock for keeping losses “manageable” [vests over 5 years], the stock keeps going down in value.

  26. MASTERMIND says:

    Peak Oil has passed! Do the Malthus!

  27. dclonghorn says:

    I was looking for more information about the problems KSA is having with Manifa and came across the article linked below.

    In addition to its info on Manifa this article publishes a listing of “Saudi Arabia Capacity, July 2017”

    The table lists Ghawar current capacity at 4 million b/d, Abqaiq at 0.2., Manifa at 0.6 for others see the link.

    Manifa was “redeveloped” in 2015 with a 900,000 b/d nameplate capacity, and the 300.000 b/d capacity decline is due to the water injection problems which will apparently persist until the injection pipeline is replaced, to be completed around the end of 2018. It seems surprising to me that the corrosion problems which are bad enough to reduce capacity by a third after only two years operation, won’t have any other impacts over the next year and a half while a new line is being constructed.

    Gharwar has had a KSA rated capacity of 5 million b/d or more in anything I’ve seen. This is 1 million b/d less, and it purports to show capacity, not production.

    Abqaiq is KSA’s oldest giant and has been severely depleted for some time, they redeveloped parts of it around 10 years ago with maximum reservoir contact wells. It’s amazing that it would still have 0.2 mb/d capacity.

    • shallow sand says:

      Thank you for the link re KSA. Interesting. Not much spare capacity.

      • Watcher says:

        Pipeline corrosion is what generated the recent delay at Kashagan.

        Oh and heads up. They are aiming at 350K bpd, end of 2017.

      • dclonghorn says:

        Thanks for checking it out shallow. Maybe I’ve been reading the tea leaves too much, but it seems to me that there are an awful lot of signs that world excess capacity is very thin, Gulf producers are limited, and facing declines soon.

        In the 80’s when there was a worldwide oil glut, KSA had rig counts under 10 for the best part of the decade. Now, with our post 2014 glut they are running around 150 and have been increasing for years. They are even working to develop their gas fields which were mostly ignored in the past. Other Gulf countries have increased their rig counts. International rig count drops are mostly in places that are way past peak.

        Many of the wells drilled by KSA since the mid 90’s have been horizontal, with maximum reservoir contact (MRC) wells starting about 15 years ago. KSA’s use of advanced technology including intelligent completions, geosteering, advanced reservoir modeling, and who knows what else, have allowed them to squeeze more oil out of their fields, but as most of us on this forum know there is a finite amount of oil there.

        KSA’s plan to sell part of Aramco could just be a desire for diversification, but it likely has roots in field depletion. I think UAE is also looking to sell now.

        The way KSA and Gulf countries have managed their production since 2014 has been interesting. There was an early bump in production after it was clear there wasn’t enough will to keep prices up, then production spiked when they were close to establishing quotas. Compliance has been remarkably good, is that because they have more willpower now, or because they are near capacity. I think sustained productive capacity has a lot to do with it.

        The Manifa capacity decline may have alot to do with KSA’s recent announcement of export cuts in August. Of course it could be that they are cutting exports simply to help the other oil producers maintain price and production.

        The period of unrestrained production and low prices has knocked out many future deepwater and oil sand developments, and the pipeline of such projects is running low.
        And shale? LTO’s economics have been debated constantly, but let’s look at another facet. Can LTO be a substitute for declining conventional oil?

        What would it take to replace Gharwar with LTO? Gharwar has been producing 60 years with a plateau of over 5,000,000 b/d. Details are often hard to come by, but it appears the entire field only has had about 2,000 wells. One of the top three LTO fields, the Bakken in North Dakota has around 13,000 wells with current production of 1,050,000 b/d.

    • George Kaplan says:

      DCL – that’s good info. It might be they can maintain seawater injection but not produced water recycling (or the other way around). I’d guess they got the produced water chemistry wrong, but it could be anything really (somebody’s career path has come to a dead end though). I think Abqaiq is sucking on fumes, and they may have to rest it regularly to get the stated capacity – so it’s not really an average annual number. If they have 240 Gb why not just open up another field … oh wait, they don’t have that much you say? What sort of problems would you expect from a country or company unable easily to increase capacity and trying to save money? – I think things like this.

    • coffeeguyzz says:

      Those Rystad guys seem to continuously offer excellent info and analysis in these matters.

      Thanks for posting.

    • clueless says:

      Based upon Rystad’s figure 4, 1/3 of the future depends upon (divine??) Providence.

      Personnaly, I have never heard of this operator.

  28. MASTERMIND says:

    One of the biggest risks to the world’s financial system is the $2.5 trillion of debt owed by oil and gas firms. (Economist)

    This Could Be the Death of the Fossil Fuel Industry — Will the Rest of the Economy Go With It?

  29. MASTERMIND says:

    According to a Goldman Sachs study quietly published in December last year, as much as $1 trillion of investments in future oil projects around the world are unprofitable, effectively stranded.
    Examining 400 of the world’s largest new oil and gas fields (except U.S. shale), the Goldman study found that $930 billion worth of projects (more than two-thirds) are unprofitable at Brent crude prices below $70. (Prices are now well below that.)

    The collapse of these projects due to unprofitability would result in the loss of oil and gas production equivalent to a colossal 8 percent of current global demand. If that happens, suddenly or otherwise, it would wreck the global economy.

  30. MASTERMIND says:

    Confidential Wall Street sources claim that the Federal Reserve in Dallas has secretly advised major U.S. banks in closed-door meetings to cover up potential energy-related losses. The Federal Reserve denies the allegations, but refuses to respond to Freedom of Information requests on internal meetings, on the obviously false pretext that it keeps no records of any of its meetings.

    • Watcher says:

      Dood, that is 18 mos old. We know this to be true because 18 months ago we discussed it here.

      It is another manifestation of oil being so dominant and vital that something as whimsical in its creation as money cannot be allowed relevance.

    • coffeeguyzz says:


      Cabot’s story, and that article in particular, gives a small glimpse of what is to come from the Appalachian Basin in future years.

      35 billion cubic feet of gas from a $7.5 million well. Amazing. And they are already showing it can be done.

      King D 4 … online 10 months, 6.5 Bcf cum.
      T Kropa 10, online 82 days, 2.8 Bcf.
      T Kropa 8, 68 days online, 2.73 Bcf … that’s over 40 MMcfd flow rate.

      The conference call from EQT the other day is one of the more significant I have ever read for all the uber important data that was revealed.
      The EQT suits are now suspending Deep Utica development because – get this – future wells will need to exceed a 4 Bcf/1,000′ threshold to surpass expected Marcellus economics.
      That is to say, with their anticipated 12,000 foot laterals (following Rice acquisition), they figure on 40 Bcf plus cum ongoing as routine protocol for years (decades?) to come.

      • coffeeguyzz says:

        … and for the folks more familiar with oil particulars, that 35 Billion cubic feet of natgas from Cabot at an initial cost of 7 1/2 million bucks, contains the energy equivalent of over 6 million barrels of oil (5.8/1 ratio).

        This is one of the many reasons that people are increasingly looking at natgas for future energy sourcing.

        • clueless says:

          Coffeeg says: “… and for the folks more familiar with oil particulars, that 35 Billion cubic feet of natgas from Cabot at an initial cost of 7 1/2 million bucks, contains the energy equivalent of over 6 million barrels of oil (5.8/1 ratio).”

          That is impressive, BUT: They said that they were getting $2.38 per Mcf, and you used a conversion of 5.8 – so they are getting the equivalent of $13.80 per equivalet barrel of oil. So, if the oil guys get $45/barrel, then they need to get only 1.851 million barrels to have the same amount of money – not 6 million.

          Nonetheless, if you can get 35 bcf from a $7.5 million gas well, why is anyone drilling oil wells??? I know of nobody saying that they are getting an EUR of 1.851 million barrels of oil from any onshore location.

          • coffeeguyzz says:


            Your numbers are correct but, if I am interpreting correctly, you are presenting the $13.80/$45 figures from the producers’ perspective of revenue received for comparable energy contained in different forms (gas vs. oil).

            My main point is from the consumer’s take on this, essentially paying way less than half to receive this same amount of energy.

            Now, the efficiency of the energy – especially transportation uses – strongly favors oil, but that is in the early stages of change and may negatively impact oil producers down the road.

            Regarding the “6 million barrel oil equivalent” from Cabot in Susquehannah county, that is certainly a leading edge example of productivity in the industry.

            However, and I cannot stress this more emphatically, if the soon-to-be largest natgas producer in the US (EQT) is claiming individual wells going forward will routinely be expected to produce 40 Bcf … That is a remarkable state of affairs in the world of O&G.

            BTW, EQT operates 250 miles southwest of Cabot/Susquehannah county.
            The productive area is not unbroken between them, but it is exceptionally large nonetheless.

            • Glenn E Stehle says:


              Here where I live public transport is skipping the natural gas => electricity step, and going directly to buses that run on natural gas.

              After all, natural gas is so unbelievably cheap in the north American market that it seems only a matter of time before we see more of this.

              Autobuses a gas natural, opción previa a eléctricos: El uso de autobuses a gas natural podría crecer porque ese combustible es más barato que la gasolina y diésel y porque son una opción más económica que los automotores eléctricos.

              Incredibly, the cost of operating a natural gas vehicle is cheaper than diesel, ethanol, hybrids and, of course, electric ones. After the electric buses that do not release polluting emissions, natural gas is the greenest….

              And, if they are almost as clean as the electric ones and they are the cheapest option and they are safe, why is the public transport service to natural gas not happening more rapidly? The answers have to do with the subsidy that has been maintained every year for fossil fuels (gasoline and diesel), the inadequate system of pipelines for the transport and distribution of natural gas and, of course, the meager growth of service stations to supply the fuel….

              In addition to having a positive impact on the environment and health, governments and carriers must take into account that natural gas is 40% cheaper than diesel. Instead of electric public transportation, the most profitable option is natural gas, whose total reserves in Mexico would be sufficient to supply the market for 100 years.

              • Glenn E Stehle says:


              • Glenn E Stehle says:


                • coffeeguyzz says:


                  While I have not been keeping too close an eye on developments in this area, there has been a furious race amongst a wide array of companies – both large and small – to effectively commercialize natgas for transportation via adsorption.

                  The MOF guys, the activated carbon guys, are collaborating with Ford, GM, and others to perfect the ‘Holy Grail’ of 20 Gallon of Gas Equivalent (GGE) tanks at under 500 psi.
                  At that low a pressure, any household supplied with natgas could fuel their CNG vehicle in their own driveway.

                  Some fuzzyhead up in Oregon modified an 8 cylinder engine to use it as its own power plant to boost house gas into an onboard tank.

                  I don’t know what or when all these transportation changes will arrive, but I expect them to be highly innovative and sooner than later to make their appearance.

              • Fred Magyar says:

                After all, natural gas is so unbelievably cheap in the north American market that it seems only a matter of time before we see more of this.

                Then again, maybe there is something better.

                Revolutionizing transit with America’s most popular electric bus

                Proterra is rapidly advancing the emerging category of battery-electric transit. We built the Catalyst® from the ground up exclusively as an EV, with a durable, life-extending composite body. We developed advanced, modular battery storage and tied it to a proven electric drivetrain and state-of-the-art energy delivery systems. Then we proved its performance with rigorous federal testing.

                LOWEST MAINTENANCE COSTS Imagine no more oil changes or emissions after-treatments. Imagine not having to maintain an engine, fuel system, cooling system or exhaust system. With Proterra, all that effort and expense is a thing of the past. And without all those costs, maintenance savings can add up to $237,000 over the lifetime of a Catalyst compared to a diesel-hybrid bus, and up to $151,000 compared to diesel. With a substantial reduction in inventoried parts, the savings are dramatic.

                • Glenn E Stehle says:

                  In Mexico the conversion of buses and taxis to natural gas is already well under way.

                  As of this time last year in Mexico City there were already 2,500 taxis operating on natural gas, a number that is expected to grow to 12,500 by 2021.

                  The following article explains why natural gas vehicles are a viable option, and EVs and hybrids not so much. It all boils down to economics:

                  Circulan dos mil 500 taxis a gas natural en la CDMX

                  In the state of Queretaro 50% of taxis and buses already operate on natural gas, but beginning in August 2017 the state government is rolling out a program to make that 100%.

                  The cost to convert a taxi from gasoline to natural gas is $34,500 pesos, but the taxi operator’s fuel bill will be reduced by $6,000 pesos per month. The payout is less than six months.

                  Desde agosto, transporte público usará gas natural

                  In 2015 there were a total of 1,842 EVs and hybrids sold in all of Mexico. Mexico is a poor country, and one only has to look at the price of EVs and hybrids to see why these cars are not selling like pan caliente in Mexico. The economics just don’t work.

                  Ahorra gasolina con estos coches híbridos o eléctricos

                  • Fred Magyar says:

                    Right but so what?! In Brazil, the original topic source of this thread every street corner mechanic has long known how to convert any ICE engine to LNG. It ain’t brain surgery and kits are readily available.

                    Yet not a lot of people actually do it, I’ll let you figure out for yourself, why. In case you are wondering, most fueling stations in Brazil have readily available gasoline, ethanol and LNG… not to mention that most home cooking is done with LNG delivered to just about every home in tanks that are swapped out.

                    Back in the day of the oil embargo and fuel crisis I remember people using their cooking tanks to run their cars, it was illegal “but if you don’t have a dog, you hunt with your cat.” Brazilian saying!

                • OFM says:

                  “the savings are dramatic”

                  THEY HOPE.

                  And if their bus proves to be reliable, long term, and the batteries last, long term, the savings will be real.

          • shallow sand says:

            Cabot is making money, they earned 14 cents per share, which was better than Q2, 2016, when they lost 7 cents a share.

            Those numbers are “adjusted” of course.

            A 25 PE ratio on those earnings translates to $14 per share.

    • Glenn E Stehle says:

      texas tea,

      The Marcellus and other shale plays never cease to amaze.

      Since the US wants to become a major exporter of LNG, this should make for some interesting times ahead, geopolitically speaking, as the US vies for market share:

      The energy factor in the GCC crisis: Gas production from the world’s largest gas field takes centre stage in Qatar-Iran relations and the GCC crisis.

      The LNG market is becoming a more integrated global market in which prices are set by market factors, rather than geopolitical interests. The change was ushered in by the emergence of new players – as well as the increase in global supply, which ensures that LNG’s price and quantity are not controlled by a monopoly. In addition to increased production by Iran, Australia is expected to become a top gas exporter, the US entered the export market, and Russia is ambitious to take the first place held by Qatar.

      Under these new conditions, Qatar is likely to seek more than ever to maintain leadership of the market and will, therefore, continue to foster relations that support energy development, even if it comes at the expense of regional relations.

      The centrality of the energy question for both Iran and Qatar means that both countries will continue to put forward policies that favour the development of said resources, even if it places them at odds with regional and global players. Therefore, any such attempts to isolate either country would not only be in vain, but also threaten the stability of a fragile region and endanger international energy security.

      • Glenn E Stehle says:

        Yves Smith also had an interesting post this past week at Naked Capitalism on the geopolitics and economics of natural gas.

        Are the Latest Russia Sanctions Really About Forcing US LNG on Europe?

        I have no idea what to make of all this. It’s all too cloak and dagger for me, all too ambiguous.

        I do know, however, that Smith, who has a long history of anti-fracking advocacy, omitted two key pieces of information that add to the ambiguity. Things are not nearly as clear cut as she believes.

        1) The oil industry, or at least some sectors of it, came out in opposition to the sanctions:

        House GOP Leader Says Energy Tweak Near in Sanctions Bill

        A growing number of businesses — including General Electric Co. and Honeywell International Inc. — are expressing concern about the impact of the Russia sanctions language in the Senate legislation, McCarthy said. Oil companies, including Royal Dutch Shell Plc, also have raised concern.

        A section of the legislation would prevent U.S. companies from doing business anywhere in the world with Russian interests, causing consternation in the capital-intensive energy industry and among other companies that rely on foreign partnerships.

        GE is buying BakerHughes, who wants to sell its service anywhere and everywhere and to anyone in the world it can, so this helps explain why it is protesting the sanctions:

        General Electric Is Making a Big Investment in Oil and Gas

        2) Trump was opposed to parts of the senate sanctions bill originally, but it looks like he may have capitulated after it became obvious there was nothing he could do to stop it:

        Trump faces Russia dilemma as Senate overwhelmingly passes new sanctions

        The Senate overwhelmingly passed a bill to slap new sanctions on Russia and prevent the White House from making any changes without Congressional review today despite the reservations expressed by the Trump administration.

        The enormous support from the Senate sets up a showdown between Congress and President Trump. The president expressed a desire to work with Russia throughout his campaign and tasked his secretary of state with improving relations between the two countries, but his policies have faced backlash as several people in Trump’s inner circle remain under investigation by Congress and the Department of Justice in probes of Russian meddling in the 2016 election.

  31. Adam Ash says:

    While we wait for the next post, can someone please remind me what product do they get out of Marcelius shale and other LTO wells. Is it something that can be refined to produce petrol aand deisel, or does it just substitute for other non-fuel petrochemical streams?

    Is it a product which, like ‘oil’ is said to be, from breakdown of organic matter, or is it abiotic stuff locked in rock created by ‘other’ non-organic proocesses?

    • Watcher says:

      The measurement of how heavy or light oil is compared to water is with a number . . . the API number in degrees.

      The higher that number above 40, the less “middle distillates” are present in the liquid. Middle distillates are diesel (sometimes called fuel oil) and kerosene (jet fuel). If the number is below 40, the liquid will likely be rich in those distillate fractions, though note one oil field’s liquid with an API of 38 may not have the same distillate yield as another field across the world with the same API 38.

      The liquid that is produced with natural gas is cleverly called NGL, Natural Gas Liquids. It won’t have any diesel or jet fuel in it. And yes, often such stuff is used as chemical feedstock and not fuel.

      Eagle Ford shale flows liquid that is often well above API 45. The Bakken liquid API number is now 42. For years it was claimed to be 39.

      • Adam Ash says:

        Thanks for your explanations Watcher and George!

        So even tho EF and Bakken are producing something, they are not contributing much liquid fuel to the alleged ‘energy independence’ of the USofA. Rite?

        So if an energy crunch happens, they cannot be of much help no matter how hard they pump??

        • George Kaplan says:

          They are contributing quite a lot of oil, but the Permian is a bigger source and growing. But the US is still a big importer (and imports are growing again now). In terms of energy independence there’s confusion between the USA and “North America” (including Canada and Mexico) and between oil and energy (including gas, coal and renewables), so it’s difficult to give a single answer. Also the data can be a but fuzzy, open to interpretation and changes every day – just projecting trends into the future doesn’t work when dealing with finite resources. A big unknown is the actual amount of oil and gas that can be recovered in these tight oil and gas formation, and a lot of the (generally inconclusive) arguments here really come down to opinions about that – as the tight oil plays are fairly new there is no real history for end of life operation to go by, unlike on conventional fields, and most people here (maybe all) don’t have access to the data needed to come up with really detailed predictive models of the wells.

        • Glenn E Stehle says:

          Adam Ash,

          It is quite common to hear the myth that the fluids produced from shale are somehow inferior to those produced from conventional reservoirs, allegedly because of their high API gravity.

          This myth is propagated by peak oil theorists. After all, if LTO and condensate are not considered to be “oil,” then peak “oil” occurred some years ago, just as the peakists had predicted.

          However, the product yield of Eagle Ford and Bakken crude is almost identical to that of West Texas Intermediate (WTI).

          • Glenn E Stehle says:

            Another way to look at this is through the lens of the market place — the price that various grades of crude oil and condensate command.

            This price list is what Sunoco was paying for various types of crude oil ten days ago. At that time a barrel of Eagle Ford LTO sold at no disount to WTI, and a barrel of Eagle Ford condensate, which is much higher API gravity than either WTI or Eagle Ford LTO, sold at only a $1.00 discount to WTI.

            • @whut says:

              “This myth is propagated by peak oil theorists. After all, if LTO and condensate are not considered to be “oil,” then peak “oil” occurred some years ago, just as the peakists had predicted.”

              Modern “peak oil theory” is not Hubbert curves. It relies on knowledge of discoveries and then estimating production from that, ala the Oil Shock Model.

              So the correct interpretation is of accounting for various types of oil and then presenting the analysis based on that. In that case, we were correct 10 years ago and are still correct today.

          • Glenn E Stehle says:

            There is no rule written in stone that high API gravity liquids must sell at a discount to lower gravity liquids.

            In the Canadian market, for instance, a barrel of Edmonton condensate sells for the same price as WTI, and at a $1.00 premium to the lower API gravity Canadian Light.

            • Watcher says:

              You’ve been instructed in the change of WTI from 39 to 42 twice now so I won’t revisit it. Comparing anything to WTI has no meaning if the standard itself changes.

              And why would you measure something like joules with an imaginary substance created by whim with value only determined by counter party agreement. Joules are physics. Money is arbitrary. It tells you nothing.

              How many times have you been told this is not an investment blog?

              • Glenn E Stehle says:


                I kind of prefer to live in the reality based community, and not the world of abstract monetary theory that you live in.

                If you believe that money is so “arbitrary,” then why don’t you go out on the street and conjure yourself up a few billion?

                Hey man,

    • George Kaplan says:

      Marcelus is gas, Bakken is light oil, Eagle Ford is light oil and rich gas etc. The shale is source rock – i.e. the rock in which the organic matter that goes on to form the oil or gas was laid down. It got converted to oil or gas by getting pushed down deep into high pressure and temperature conditions (the oil window and, deeper and hotter, the gas window) and left to bake. In conventional reservoir the oil or gas migrates from the source rock and collects above in a trap which is a sealed, porous volume. With the LTO it hasn’t migrated out.

      There has been no evidence found for abiotic oil, the stuff in Russia was probably drilling mud, the field in Texas that looked like it refilled was some complicated mechanism where periodically steam built up pressure which forced a fault to open and allow oil to migrate, and the pressure to drop so the cycle could restart. All oil shows biomarkers – chemicals that must have been originally made by animals and plants, they are important for geologists to understand where and when the oil has come from. Even if there was abiotic oil it can only be being made very slowly (so slow as to make no difference) otherwise we would be literally knee deep in it.

  32. Glenn E Stehle says:

    Refracking in the Bakken:

    New technology could recover more oil from early Bakken wells

    Oil companies are applying new hydraulic fracturing techniques to early Bakken wells….

    Operators are targeting wells drilled between 2008 and 2010, the early years of Bakken development before fracking technology advanced to where it is today.

    Companies are refracturing the older wells using today’s technology and getting promising results, said Justin Kringstad, director of the North Dakota Pipeline Authority, who recently analyzed the wells.

    “On average, they’re getting better performance from the wells,” Kringstad said.

    More than 140 wells in the Bakken have been refractured, and most saw an increase in oil production from 200,000 to 250,000 barrels, according to Kringstad’s analysis.

    Fracking — or pumping a high-pressure mixture of water, sand and chemicals deep underground — and horizontal drilling techniques allowed operators to recover oil from the Bakken.

    But the industry believes it’s only recovering about 5 to 15 percent of the oil available, Kringstad said.

    The newly fracked wells are injected with larger volumes of fluid and sand and the fracture treatments are applied to smaller segments of the well, he said.

    North Dakota legislators also are interested in the potential for refracturing existing oil wells and are planning a study during the interim focused on the fiscal impact to the state.

    Sen. Kelly Armstrong, R-Dickinson, said recovering more oil would mean more tax revenue and more jobs.

    “We are only getting a small, small amount of the total potential reserve down there,” Armstrong said. “Everybody would benefit if we could figure out a way to recover more.”

    • daniel says:

      interesting that they “admit” that cummulate average recovery for 2008-2010 wells was 200,000 bbl. Also how much does a refrac cost? Are the economics favourable for “only” 50,000 bbl?

      • Glenn E Stehle says:


        The refracs increased the average EUR by 200,000 to 250,000 boe over and above what the wells would have produced if they were not refraced.

        With frac jobs for 7,500′ lateral wells costing in the $2 to $2.5 million range and WTI at $50/barrel, a mere 50,000 BO would come nowhere near to paying out the cost of a refrac.

    • clueless says:

      Glenn – from your post [quoting information from someone else]: “More than 140 wells in the Bakken have been refractured, and most saw an increase in oil production from 200,000 to 250,000 barrels, according to Kringstad’s analysis.”

      I am clueless! But, this statement indicates that the results are “in” from more than 140 refrackings. With production profiles, this would take more than 5 years to determine. So, have there been over 140 refracturings that are over 5 years old? Or is this more “potential” bullshit?

      • Glenn E Stehle says:


        A workover is considered to be successful or not depending on the sort of production boost it achieves.

        Whether that production boost is sustained into the future or not does leave room for “‘potential’ bullshit.”

        But the “bullshit” can be overly pessimistic just as easily as it can be overly optimistic, as has been frequently demonstrated on this forum in the past.

  33. MASTERMIND says:

    Saudi Aramco CEO believes oil shortage coming despite U.S. shale boom – Fox News

    The Oil Age may come to an end for a shortage of oil.

    -Saudi Oil Minister Sheikh Yamani

    • MASTERMIND says:

      Better sell that I-Toy and buy some preps! Once the shortages come gas stations only have a few days supplies. And that will be gone in a few hours with Preppers fueling up bug out trucks and bankers fueling up their private jets!

      • GoneFishing says:

        How much of the global oil production is actually profitable at $50 oil?

  34. MASTERMIND says:

    Aubrey McClendon, billionaire sports NBA team owner, oil executive and “visionary” pioneer of the US fracking revolution kills himself

    • Glenn E Stehle says:


      Aubrey McClendon was just one of Obama’s many victims. Other victims of Obama’s weaponized Department of Justice and IRS that gained notoriety included, to name only a couple, Gibson Guitar and the Tea Party.

      Aubrey McClendon Indictment: Political Witch Hunt

      The circumstances of the death of Aubrey McClendon notwithstanding, I believe that the indictment handed down last Tuesday was nothing more than a witch hunt by Obama’s Department of Justice. The indictment, which has since been dismissed, was handed down along with promises of more investigation into oil and gas company practices. Obama’s stated goals center around taking down coal and fossil fuel industries. Who better to go after than a man who put American energy on the map?

      Aubrey McClendon was a capitalisit in the original sense of the word. He and his companies and employees took the risks necessary to drive American energy production to the forefront of the world. Aubrey McClendon was not only a visionary, he was a DOER. Our country, indeed, our world, needs MORE doers and far less government lawyer types whose mission in life is to throw obstacles before the wheels of business and capitalism. It is rich irony that Aubrey McClendon’s companies set the extremely high bar in per acre lease costs and he was indicted for trying to conspire to hold prices down. The Justice Department isn’t finished with the oil and gas industry, so look for the ongoing hunt to try to find another high profile witch.

      In this world where everyone gets participation trophies, where college students need “safe spaces” to protect them from thoughts that might challenge them, where people are actively being DISCOURAGED from excelling and producing something, Aubrey McClendon made things happen. He moved, he shook, he brought capital and jobs and a higher standard of living to Oklahoma, and other states where massive geologic formations still hold reservoirs of untapped oil and gas.

      Aubrey McClendon exemplified what used to be known as American ingenuity. How ironic that with his energy, drive and smarts, he launched a huge warning shot over the bow of OPEC’s own price fixing cartel practices. How sad that our own government is more interested in promoting mediocrity and punishing success.

      • MASTERMIND says:

        I bet Soro’s was behind it as well. LOL You are as dumb as they come Glenn.

        • clueless says:

          As someone who knows a little about the oil business, Aubrey was unfairly targeted. There are precious few oil and gas wells that are 100% owned by one company. Sharing the risk is part of the business. When the US auction’s offshore leases, most times there are syndicates of multiple companies in the bid – or, agreements that if you win the bid they will take a part of the action.

          Aubrey [his company] bought leases, and had other companies participate in the leases that he bought [and vice versa]. The Obama administration filled charges that he was cheating landowners [I guess so did every other oil company in the history of the US]. My God – landowners share information on every lease that is signed in their area in order to get a good deal.

          Just look at Walt Disney. They set up 100’s of shell corporations in order to purchase 10’s of thousands of acres in Florida for a 2nd Disneyland without the sellers finding out that Disney was behind the purchases. Was Disney ever indicted for cheating landowners? Hell no! Just smart business.

          If Amazon hired you to buy 1000 acres for a 2nd headquarters and a distribution center, would you go to a rural area anywhere and announce that you were looking to buy land for that purpose? Being a Mastermind, you probably would.

          • MASTERMIND says:

            The reason he got busted is because he broke the law and his emails leaked to Reuters. He was never under a microscope or anything. One of his emails was very funny though because he told another CEO “Me and you need to smoke a peace pipe together”. It doesn’t matter shale companies are scams nothing more. They are all hat and no cattle!

            • Glenn E Stehle says:

              MASTERMIND said:

              The reason he got busted is because he broke the law….

              Gosh, and here I was laboring under the mistaken belief that we live in a country where one is innocent until proven guilty.

              McClendon was never convicted of anything.

        • Glenn E Stehle says:


          Has it ever occurred to that “MASTERMIND” of yours to ask why it was that only McClendon was indicted, and his co-conspiritor was not? And not only was McClendon’s co-conspirator not indicted, he wasn’t even named in McClendon’s indictment. Imagine that, a conspiracy where the co-conspirator is a fantom! Only in Obama’s “justice” department.

          Ex-Chesapeake CEO Aubrey McClendon indicted over lease bid rigging

          Aubrey McClendon, the co-founder and former chief executive officer of Chesapeake Energy Corp., was indicted on charges that he conspired to rig bids for the purchase of oil and natural gas leases in northwest Oklahoma, the U.S. said….

          From December 2007 to March 2012, the conspirators decided ahead of time who would win the leases and the winning bidder would then allocate an interest in the leases to the other company, the government said….

          Prosecutors said McClendon contacted an unnamed co- conspirator at Company B in 2007 and proposed they stop competing on bids to purchase leases.

      • MASTERMIND says:

        I bet it was Putin and the Russian hackers took over controls of his Suburban and crashed him into a bridge on computers used in George Soros’s basement!

        • Glenn E Stehle says:


          It was Obama’s “justice” department that alleged a conspiracy. That “MASTERMIND” of yours seems to have quite a problem wrapping itself around the facts.

    • Glenn E Stehle says:

      MASTERMIND said:

      Aubrey McClendon…kills himself

      The death of McClendon was ruled an accident:

      Crash That Killed Aubrey McClendon Was Accident

  35. MASTERMIND says:

    Documents: Leaked Industry E-Mails and Reports NY Times skeptical on Shale oil boom

    Leaked Emails include

    Where is the SEC?
    Drill fast, Con wall street
    We are headed for Enron moment
    There is a sucker born every minute
    Shale is a Ponzi

    • clueless says:

      Well, I clicked on the “click bait.”

      This stuff dates from 2009, 2010, 2011 etc. So, although I am clearly a skeptic of the profitability of shale oil, none of this appears to be relevant to 2017. This even shows emails trashing the Marcellus. Say what you will, but some companies are now getting 35-40+ bcf from a single well in the Marcellus. I am jealous of the landowners and their royalties.

      • MASTERMIND says:

        It is relevant because it proves that the industry insiders were well aware that shale was unprofitable from the start. And now here we are several years later. And how is the NY TIMES click bait?

        • Glenn E Stehle says:

          MASTERMIND says:

          …industry insiders were well aware that shale was unprofitable from the start.

          But shale is not “unprofitable,” at least not all shale.

          These sweeping overgeneralizations of yours do nothing to help your credibility, and are quite the demonstration of a logical fallacy.

      • shallow sand says:

        The Shale Boom has been a great deal for royalty owners, provided they do not handle their increased income in the same manner as lottery winners and pro athletes.

        Assume a 1% RI in a Permian well.

        Year 1: 200,000 BO x $40 x 1% = $80,000.

        Year 2: 60,000 BO x $40 x 1% = $24,000.

        Year 3: 30,000 BO x $40 x 1% = $12,000.

        Year 4: 20,000 BO x $40 x 1% = $8,000.

        Year 5: 15,000 BO x $40 x 1% = $6,000.

        Take it from someone who sold oil for over $100 per barrel in 2008 and $85-95 per barrel in 2011-2014. It is easy to lose your head and think, “this is forever.”

        Think I am wrong? Look how much CAPEX shale professionals spent with borrowed funds in 2014. A certain highly publicized shale CEO liquidated all of his company’s oil hedges in late 2014 to provide capital to drill more wells in early 2015.

        • Glenn E Stehle says:

          shallow sand,

          The Shale Boom has been a great deal for royalty owners….

          The shale boom has been “a great deal” for everybody with ownership interests in the Permian Basin, regardless of whether their ownership is working interest or royalty interest.

          • shallow sand says:

            The great deal for anyone who owns WI in the Permian is inaccurate, just as are the constant comments that all shale is a Ponzi scheme,which I readily admit is not true either.

            I have seen plenty of unconventional Permian wells that won’t payout, and I’m sure the non-ops that got big AFE’s for those were not too thrilled how those wells worked out.

            Also, the Permian has been sliced and diced so much that very few small fry types own all depths. So, it really depends on what you specially own if you are going to get a big payday like the two families that have sold to QEP,for example.

            Finally, shale clearly played a major part in crashing the price, so those folks in the Permian minding their own business operating Seven Rivers, Yates, San Andres, Grayburg, Glorietta, vertical Spaberry, etc, etc have gotten slammed, just like Mike, my family and everyone else.

            You seem to forget that almost every company that drills these horizontal wells also owns conventional stuff. So, as they go wild drilling and sinking the price, they only hurt not only the economics of those LTO wells, but also the economics of all of their conventional projects.

            I think maybe, hopefully, these guys (and more importantly Wall Street) have had an epiphany, being that pushing the US to 10+ million BOPD will not do them any good as it will keep oil sub $50 WTI, where the profits, if any,will be puny.

            While Schlumberger and Halliburton break even, the rest of the industries have shares making in the dollars per share per quarter. XOM stock is fighting to stay above $80. They and Chevron both lost $$ in the US, and I’ll bet some of what they own that is underwater is in the PB, seeing how they both operate a lot of waterfkoods and CO2 floods, in addition to the fact that both have unconventionals that stunk, along with both having some unconventional wells that have been strong performers.

            Maybe I’m wrong, maybe PXD will be able to earn $8 per share at $45 WTI. But, if I had to bet, I would bet that won’t happen.

            Here is to a $55-65 price band on WTI, from 2nd half of 2017 to 2021.

            • Glenn E Stehle says:

              shallow sand,

              You’re going to have an uphill battle trying to convince folks in the Permian Basin of your negative point of view.

              Most working interest owners are people who have been active in the oil business for years, so they have acquired interests in multiple leases throughout the years, including sprayberry and wolfberry.

              I personally don’t know a single working interest owner who decided to participate in the drilling of a horizontal shale well. Everyone I know took a payday, and a large one at that, selling out their leasehold at prices many times what they were worth before the Permian shale play began.

              The people I know realized that one needs extremely deep pockets to play the shale game, and needs to participate in multiple wells to have a chance for the law of averages to work out. Also, a lease that was worth $300,000 before the shale boom began all of a sudden was worth $3 million. So they took the money and ran.

              For the younger set who are still active in the oil business in the Permian Basin, they’re too busy putting new deals together to be crying over any spilled milk. The shale boom created a land of opportunity. The young folks are happy to have all the new opportunities, and are working their tails off trying to get a piece of the action.

              Remember the old saying about how a rising tide lifts all boats? And the tide in the Permian Basin is definitely rising.

              What I’d give to be young again and still have the drive and the energy to be in there slugging it out, still playing the game.

              • shallow sand says:

                Look at every MLP that bought conventional leases in the Permian. Either BK or close.

                Most of those have et als.

                As I stated, many WI owners do not own deep rights in PB. So they have nothing that Wall Street wants.

                The ones that have sold out obviously have done so because they see a bubble. See Yates and Bass families, who clearly have the $$ to develop shale. In fact, they did, found it was better to sell out, so they did.

                I agree the economic activity has been a boon to the PB.

  36. Energy News says:

    LONDON (Reuters) – OPEC oil output has risen this month by 90,000 barrels per day (bpd) to a 2017 high, a Reuters survey found, led by a further recovery in supply from Libya, one of the countries exempt from a production-cutting deal.

    The Libyan and Nigerian increases mean OPEC output in July averaged 32.85 million bpd, about 1.1 million bpd above its supply target, adjusted to remove Indonesia and not including Equatorial Guinea.

  37. George Kaplan says:

    Mexico C&C for June was down 21 kbpd to 2028 kbpd; down 8% y-o-y. They are down over 106 kbpd since October, I think 100 was their agreed NOPEC target. Condensate took a big hit (down 41% on the year now) but that might be just to do with reporting methods and schedules. They will likely be below 2000 for July as they are starting some maintenance turn arounds on KMZ facilities. They are also getting close to the expected drop off for KMZ from previous Pemex predictions.

  38. Energy News says:

    EIA US crude oil production, the gap between the monthly and the weekly numbers has narrowed slightly from 178 kb/day in April down to 151 kb/day in May. (The gap is the same using the revised April number of 9,110 kb/day. The gap for both April & May = 151 kb/day)

    • George Kaplan says:

      GoM up 3000 bpd after April was adjusted down 1000, but still down almost 100,000 from March. Some fields came back on line (Great White, Cardamom) but Constitution Spar is off line for May and part of June, Stones dropped production again as well. One well on Horn Mountain Deep started in late May, and there were some additions from Marmalard. With Hurricane Cindy impacting June figures there’s likely to be another fall coming. South Santa Cruz and Barataria started in mid June (they are pretty small fields and will immediately decline) and there are a couple of other development wells due plus possibly Atlantis North, but I think these will just be able to maintain plateaux on their facilities, so it might be a bit of a jump in July and then permanent decline.

      Final May BOEM lease data should be out tomorrow.

    • George Kaplan says:

      This is FuelFix take on the shale numbers (might be a paywall and I just got lucky):


      New data shows the surge in shale drilling hasn’t lifted U.S. oil production as much as expected.
      In a monthly report on Monday, the Energy Department said the nation’s daily output rose 0.6 percent to 9.17 million barrels in May, well below its original forecast of 9.32 million for that month.
      Texas outpaced the rest of the country, boosting output by 2.3 percent, or 78,000 barrels a day, as the oil fields in the Permian Basin surged. In New Mexico, parts of which share the Permian, production rose by 14,000 barrels a day. Colorado put out an extra 10,000 barrels a day.
      But other oil-rich states stalled out. In Alaska, Louisiana, Oklahoma, North Dakota and Wyoming, oil production collectively dropped nearly 45,000 barrels a day in May. It’s another sign the oil industry’s uneven recovery has left several U.S. oil fields behind as drillers focus on the prolific Permian.

      Has there ever been a comment here about how much the Permian surge might be just due meeting hold-by-drilling obligations on new leases or purchases?

      • Glenn E Stehle says:


        Good grief, who writes those headlines?

        The headline has nothing to do with the content of the article, which says:

        Texas outpaced the rest of the country, boosting output by 2.3 percent, or 78,000 barrels a day, as the oil fields in the Permian Basin surged. In New Mexico, parts of which share the Permian, production rose by 14,000 barrels a day….

        It’s another sign the oil industry’s uneven recovery has left several U.S. oil fields behind as drillers focus on the prolific Permian.

        The article omits mentioning the 1,000+ extra DUCs that have built up in the Permian Basin over the past nine months, another 300,000 or 400,000 boepd that is stalled from coming on line.

  39. George Kaplan says:

    “It is with great sadness that we announce the closure of”

    Not really surprising, there isn’t much interesting news and very few of the sort of jobs that those sites used to advertise. I think at least one of the magazines/blogs based in Aberdeen is going to have to go as well.

    • Lightsout says:

      Hi George

      Don’t know if you are watching the weald basin but this just out after market closed.

      All Approvals for a Rig-less Flow Test in Place,

      Broadford Bridge-1 Exploration Well, Weald Basin, UK


      All flow test regulatory permissions now in place following review by the Health and Safety Executive (“HSE”). Work continues to “complete” the well as a potential oil producer to be followed by a rig-less flow-test, encompassing multiple Kimmeridge zones over a total aggregate perforated section of 926 ft.
      Preliminary log interpretations indicate that the extensively naturally-fractured Kimmeridge section is oil bearing from around 3,800 ft to below 5,640 ft measured depth (“MD”) a vertical section of around 1,330 ft. This observation is in accord with the mobile light oil recovered to surface in cores and recovered from drilling fluid, together with wet gas shows.
      An application to extend the exploration/testing phase for a further year to 15 September 2018 has been submitted to West Sussex County Council (“WSCC”) with a decision expected in September 2017.

    • MASTERMIND says:

      Where is Glenn going to go to get his right winger lunatic conspiracy theories?

      • Glenn E Stehle says:


        It was Obama’s “justice” department that alleged a conspiracy.

        That “MASTERMIND” of yours seems to have quite a problem wrapping itself around the facts.

        • MASTERMIND says:

          Yes and Obama is still running a shadow government right now as well. And all the news that questions trump is fake. And Soros wants to flood America with migrants and start a NWO to redistribute the wealth and destroy capitalism. And the gays want to destroy the American family. And the climate scientist are manipulating data in hopes to get the world off of oil and join together as one and drink organic kool aid.

  40. MASTERMIND says:

    Collapse Starter Pack

    • Glenn E Stehle says:

      Blog: Our Finite World

      Your apocalypticism is indeed much more in tune with the end times theology proselytized by Our Finite World.

      You and Fast Eddy are two peas in a pod with all your doomsday mongering, and make quite the pair with all your belligerence and fact-free pulpiteering.

      • Watcher says:

        Gail is absurdly optimistic.

        Scarcity will not be uniformly distributed.

        Have a look at the map. Shanghai nuclear strikes are at the same latitude as the Permian. The fallout will take only a few weeks to arrive and shut it down.

        • Glenn E Stehle says:

          Apocalypticism certainly is a popular theology in the United States.

          • Watcher says:

            You’re not up to speed. The end of the world quote unquote is defined as 100% population loss of the planet.

            Apocalypse only requires a loss of about 75% of the population of the planet. My recall is “collapse” is about 50% ( no big deal).

            A Chinese strike would not come close to 75%. Good luck with shale production in anti radiation suits wearing dosimeters clipped to . . . a lapel.

      • MASTERMIND says:

        Fact free? I listed numerous academic scientific papers you right wing nitwit.

      • MASTERMIND says:

        Glenn you can’t talk your way out of this one. Remember me when collapse hits.

  41. Adam Ash says:

    Two Half-Finished Nuclear Reactors Scrapped as Costs Balloon


    Missing documentation throws Santee Cooper, SCE&G nuclear project timeline, costs in doubt

    which concluded with

    Santee Cooper, SCE&G pull plug on roughly $25 billion nuclear plants in South Carolina

    So much for ‘zero emission’ energy, and ‘energy too cheap to meter’. No new reactors built in USA since Three Mile Island. So its burn baby burn from here on down.

    • Boomer II says:

      I wonder how Trump and Perry are going to spin that.

    • coffeeguyzz says:

      The massive build out of huge Combined Cycle Gas Turbine plants in Ohio and Pennsylvania is rapidly spreading south to Virginia and Florida.
      The big plants have 1,200/1,600 Mw capacity and are extremely flexible (dispatchable responding to varied demand throughout the day).

      At about a billion bucks per 1,000 Mw construction cost, these are exceptionally competitive plants to build.

      Texas is also building some and other states NC, WV are building smaller sized units.
      There is simply no other existing process – that is, inexpensive natgas fueled plants with 60%+ efficiencies – that can economically compete with this source of electricity.

      Up in Connecticut, the owners of the huge – 2,000 Mw – nuclear Millstone units are clamoring for state subsidies or they are stating that their ongoing viability is imperiled.

      This is just one more follow on consequence to this so called Shale Revolution.

      • Hickory says:

        Coffee- who builds those Combined Cycle Gas Turbine plants?

        • coffeeguyzz says:


          I never even wondered about that until you asked, although Fluor had been mentioned in a few articles as the General Contractor (overall company responsible for construction).

          Just did some checking and it looks like Bechtel and Skansa also build these plants, but I’m guessing a few other large contractors must do so as well.
          These GPs have to be huge for bonding purposes as well as reputations for getting projects of this size built.

          From my understanding, there is high collaboration between the contractors and main component manufacturers – GE, Siemens, I think a few from Japan – and the usual drawing from local resources (labor, etc).

    • Nick G says:

      This seems to raise a key question:

      Would nuclear be competitive if natural gas generation had to pay the cost of it’s pollution*?

      *stipulating that green house gases like methane and CO2 are pollutants with serious risks.

      • Hightrekker says:

        Nuclear Reactors have potential.
        With one drawback:
        Humans design, build, and maintain them.
        Not to mention, finance them.

  42. MASTERMIND says:

    A Post Oil Man (Caution NOT for sensitive viewers)

  43. MASTERMIND says:

    The Return of the Great Depression 2.0 ?

    Saudi ARAMCO IPO – Great Opportunity or Riddled with Risk ?

  44. Energy News says:

    Eni fast-tracks promising Mexican well, the first new field drilled by an international company. First oil from Amoca in the Gulf of Mexico should be delivered in the first half of 2019, with potential for 50,000 barrels per day.
    Eni’s discovery in March was followed by an even bigger find of up to 2bn barrels by a consortium of US-based Talos Energy, Mexico’s Sierra Oil & Gas and Premier Oil of the UK.
    FT (one free)

  45. Energy News says:

    Mature UK acreage is up for grabs on improved terms, but attracting the explorers could still prove difficult
    Petroleum Economist – 25 July 2017

    The OGA reckons that 10bn to 20bn barrels of oil equivalent remain under the UKCS—compared to the more than 42bn barrels that have already been produced. But persuading firms to return to mature areas in the hope that gems will turn up that were missed first time round will be a tough sell in an era of more prudent spending. Last year’s 29th licensing round, which focused on frontier areas, produced the lowest interest in 14 years: only 29 applications came in for 113 blocks, when a total of 1,261 blocks had been on offer.

    The authority’s Innovate Licence is intended to lure companies by giving them more flexibility in setting the timetable for data processing, surveying and drilling. The fiscal regime is more attractive to drillers and the hope is that improved technology and greater drilling efficiency will keep costs down..
    (free article)

  46. Glenn E Stehle says:

    texas tea,

    Why don’t we take up a collection and send it to the environmentalist groups in Australia? Maybe they can get fracking banned in all of Australia, not just Victoria. 😊

    The Real “Land Of Plenty” – Why U.S. LNG Won’t Face Australia’s Natural Gas Supply Problem

    [W]e would anticipate that the uncertainty created by the Australian government’s reaction to the supply-demand balance could only help the U.S. projects’ competitive position.

    • coffeeguyzz says:

      Over a 6 hour stretch the other day, the SA wholesale electricity price veered almost A$800 from -A$544/Mwh (that’s a minus sign. Still don’t understand how that works to pay others to take your electricity), to around A$200 as the morning ramp up kicked in.
      Data is easily viewable on site under data dashboard tab.

      It seems at least twice a day, around 8:00 AM and 6:00 PM the wind/solar input drops off and conventional needs to be employed.
      Possibly this is what Elon’s battery is supposed to address.

      If the South Australia situation is being touted as a pacesetting example of renewables in action, I’d be a little concerned if I were a proponent.

      If the July electric bills are now being sent out to customers, there will be a hew and cry raised over these extremely high rates.

  47. MASTERMIND says:

    Collapse Starter Pack!

    (Extraordinary claims require Extraordinary evidence -Carl Sagan)

  48. MASTERMIND says:

    I found this article from oiprice back in 2010 claiming EV’S and peak demand was right ahead. And here we are almost 8 years later. And EV sales are not even one percent of total car sales yet. LOL

    • Nick G says:

      I don’t see a prediction in that article that “peak demand was right ahead”.

      • MASTERMIND says:

        Peter Hughes, a director of Arthur D. Little’s global energy and utilities practice, said:

        “As the number of new policy measures implemented to reduce reliance on hydrocarbons for transportation reaches critical mass over the next 10 years, the world could see downward pressure on demand for oil and oil-products materialize much sooner than the [oil] industry would currently concede.

        • Nick G says:

          Sure. “in the next 10 years” is by 2020. And the change could come much later than that, and it would still ” materialize much sooner than the [oil] industry would currently concede”.

          • MASTERMIND says:

            Tesla sold one percent of the total volume of GM last year. Tesla does not exists. This is like comparing Granny’s knitting booth at the local fair with Wal-Mart in the same sentence. And without tax credits they will go out of business permanently. Who killed the electric car? The consumers because nobody wanted one besides rich yuppies in silicon valley. And most in Silicon Valley suffer from a disease called “Irrational Exuberance” or “Braggadocio”

            • GoneFishing says:

              Yeah, I guess a global rise in sales of 69% is not enough.
              If you are looking to see collapse, it will be a while yet. Most we will get soon is a recession.

              • MASTERMIND says:

                And what will the CB’S do to dig us out of a recession nitwit?

                Can’t lower interest rates like normal, they have been at near zero for almost eight years. (Longest period in history).

                Can’t purchase assets they have been printing money like there is no tomorrow for eight years and its been futile?

                Can’t bail out the TBTF it would be political suicide.

                They are all out of bullets?

            • Nick G says:

              Tesla sold one percent of the total volume of GM last year

              Tesla revenues are about $10.5B, which is about 6% of GM’s $166B. More importantly, Tesla is growing at about 50% per year consistently, which is about 10x GM’s growth rate of 4.5% over the last four years. Which is why Tesla’s market cap is about the same as GM’s.

              without tax credits they will go out of business

              Tesla’s average sales price is about 100k. The credit is 7.5k. It could disappear, and Tesla current buyers would barely notice.

              Soon Tesla will be relying on their Model 3, which will sell for about $45k. And, the credits will expire soon. Will buyers notice? Probably not – there are about 500k deposits already placed for the model 3, and these buyers know that few of them will get the credit.

              “The first reviews of Tesla’s Model 3 are in — and they are resoundingly positive beyond expectations, even for those anticipating the world from the new model. Yes, the reviews are filled with hyperbole — and they’re absolutely heartfelt, with the detail to back them up.”


              • MASTERMIND says:

                Honk Kong removed the credit and sold ZERO cars the next year. Denmark the most progressive country on earth removed the credit and sold 6 cars the next month.

                You nitwit. And I notice you cherry picked your data to talk about revenue. How about focusing on PROFITS. Which were NEGATIVE for the 10 year in a row. LOL

                Tesla is just a pump and dump. and its the most shorted stock on wall street this year. And Triple AAA raised Tesla drivers rates by 30% recently because they break down and have to have so many repairs.

                Just do a youtube search for “Tesla Problems”. One of the most unreliable cars on the market. Consumer reliability reports ranked them 27/29 almost dead last. They are just a cult purchase for yuppies

                • Nick G says:

                  Honk Kong removed the credit and sold ZERO cars the next year. Denmark the most progressive country on earth removed the credit and sold 6 cars the next month.

                  “Honk” Kong never gave a credit. Instead, they waived an 80% registration tax. Denmark’s tax policy was similar, IIRC.

                  When people have the opportunity to buy something at a good price and they know the price is going up, they stock up now. It’s not surprising that sales spiked just before the exemption was eliminated, and then cratered the first several months afterward – buyers would be idiots to wait until after the deadline to buy.

              • MASTERMIND says:

       (BWWAAAHAAA the site that says we going to be living on Mars (Which has no magnetic field and the solar radiation will fry your brain according to NASA). And we will be mining asteroids for minerals. LOL Techno junkies are like donkeys, no questioning, no common sense, just feed it to them and they will eat it.

              • MASTERMIND says:

                You have to argue percentages because you can’t argue total sales. LOL And you have to argue revenue because you can’t argue profits. Just like the shale producers have to argue break evens because they can’t argue free cash flow.

  49. clueless says:

    Waiting for SS to give us his opinion, but PXD is down $9+ per share after announcing an earnings beat of $.21/sh, ex- derivative mark-to-market gains and gain from sale of properties.

    I think that they know how to sling the BS. They say that production increases benefited from increased gas and NGL from a higher GOR. What they do not say is “that” increase in production suffers from receiving only 1/3 [or less ?] the price that they receive from oil. Their future production is now expected to be 58% oil.

    They also noted that this year they had expected to drill 260 wells with an ” associated capital spending” of $2.4 billion. Now, they expect to drill 230 wells with “an associated capital spending” of $2.3 billion. So, anticipated spending per well has gone from $9.231 million per well to $10 million per well, an 8+% increase in cost. So much for the huge productivity improvements. I guess that we should all note these costs for estimating the profitability of future Permian wells [at least from PXD] – 58% oil and $10 million [probably excluding leasehold cost].

    After two glasses of wine, I appologize in advance for errors in my analysis.

    • shallow sand says:


      No errors in your analysis.

      I am not understanding why CAPEX appears to be $10 million per well, but in another area we are given a lower number for different horizontal formations in the Permian, where 95%+ of the CAPEX is spent.

      Of course, I would argue all the CAPEX that pertains to producing oil and gas should be included. So, it really is over $10 million per well.

      One thing very surprising to me is mention of some of the first wells, including reference to increasing GOR and a statement that GOR has rapidly increased because the wells were TOO TIGHTLY SPACED. I think us supposed anti shale cranks have discussed this quite often.

      In an event, the company earned 21 cents per share, which was a beat, yet even after the after hours tanking, carries a forward PE based on Q2 earnings of 180. I continue to have the opinion that most E & P’s and service companies will have difficulty generating strong EPS in a sub $50 WTI and sub $3 Henry Hub gas environment.

      Finally, assuming these guys are taking depletion based on 1.3-1.7 million BOE EUR, PXD’s depletion expense is vastly understated, which is exaggerating earnings to the upside. Based on Enno Peters data, PXD could be understating depletion by a factor of 2 or more. Say, after 5 years a well has hit 300,000 BO and 600,000 MCF. So just 1/4 of the intangible cost of the well would have been taken in the first five years if the well’s EUR is assumed at 1.6 million BOE. But this well produces 18,000 BO and 30,000 MCF in year six, and is still headed south. If PXD ever sells the well, huge impairment.

      Funny I never can get anyone to touch on this depletion understatement,, or why PXD vastly understates SEC PUD. Oh well.

      • Watcher says:

        Morningstar has a transparent methodology for credit rating, which you can search out on their site if you want.

        PXD’s corporate credit is rated BBB-.

        Moody’s Fitch and S&P have all different nomenclature for specifying the credit worthiness of debt issuance. Meaning one company may have BBB- and another Abb or whatever. The letters don’t mean the same thing for each. Morningstar has its own too.

        All you need to know is 1) Is the rating “investment grade” or “less than investment grade”. Less than investment grade is HY (high yield) or junk, which nowadays just means it pays more yield (because it’s junk). 2) how does it compare to peers, or if it clearly is not a peer, at least businesses doing the same thing

        PXD is BBB-

        XOM’s Morningstar credit rating is AA+
        CVX is AA- chevron
        TOT is A- total
        RDS.A is A royal dutch shell

        • Glenn E Stehle says:

          XOM and CVX are the second and third most active companies in drilling shale wells in the Permian Basin.

          Why do you believe that is?

      • Glenn E Stehle says:

        shallow sand,

        Pioneer deducted $341 million, or $14.46 per boe, for DD&A during 2Q2017.

        Pioneer realized $32.56 in revenues for each boe it sold during 2Q2017.

        Do you believe 44.4% of revenues for DD&A to be “vastly understated”?

        Another way to look at it is that Pioneer expects to invest $2.4 billion on its oil and gas properties in FY2017. If it takes $1.364 billion ($341 million x 4) in DD&A during the year, it will have taken a total of 56.8% of its total oil and gas capitalized cost in FY2017 in DD&A.

        Do you believe taking 56.8% of total new oil and gas capitalized cost in DD&A during the first year to be “vastly understaated”?

      • Glenn E Stehle says:

        shallow sand said:

        Finally, assuming these guys are taking depletion based on 1.3-1.7 million BOE EUR, PXD’s depletion expense is vastly understated, which is exaggerating earnings to the upside. Based on Enno Peters data, PXD could be understating depletion by a factor of 2 or more. Say, after 5 years a well has hit 300,000 BO and 600,000 MCF. So just 1/4 of the intangible cost of the well would have been taken in the first five years if the well’s EUR is assumed at 1.6 million BOE. But this well produces 18,000 BO and 30,000 MCF in year six, and is still headed south. If PXD ever sells the well, huge impairment.

        Have things changed that much with GAAP accounting rules? Back when I was still active in the oil business, impairments applied to depreciation and book value, not depletion.

        Here’s how Investopia explains it, which is consistent with my understanding of impairments. There is a difference between GAAP book value and tax basis:

        Impairment occurs when a business asset suffers a depreciation in fair market value in excess of the book value of the asset on the business’ financial statements. Under the U.S. generally accepted accounting principles, or GAAP, assets that are considered “impaired” must be recognized as a loss on a business’ income statement.

        The technical definition of impairment loss is a decrease in net carrying value, the acquisition cost minus depreciation, of an asset that is greater than the future undisclosed cash flow of the same asset. An impairment occurs when assets are sold or abandoned because the company no longer expects them to benefit long-run operations. This is different from a write-down, though impairment losses often result in a tax deferral for the asset.

  50. Boomer II says:

    “Although fuel economists think that Weld County’s oil patch will continue to offer drilling opportunities for a few dozen years more, a rush of alternative energy generation signals change in the county that now produces the largest amount of oil in Colorado.”

  51. MASTERMIND says:

    United States National Academy of Sciences (Scheffera 2016)
    Anticipating societal collapse; Hints from the Stone Age

    • George Kaplan says:

      What’s that got to do specifically with oil, which this post is nominally about?

  52. MASTERMIND says:

    From 1999 through 2014, the age-adjusted suicide rate in the United States increased 24%, from 10.5 to 13.0 per 100,000 population, with the pace of increase greater after 2006(Same year Conventional Oil Peaked).

    • George Kaplan says:

      What’s that got to do specifically with oil, which this post is nominally about?

  53. OFM says:

    Is anybody in a position to comment from first hand knowledge on what’s going on in Venezuela now?

    I’m thinking that there is a very real possibility that oil production there might crash, if the opposition cannot figure out a way to get rid of the Maduro regime otherwise than by sabotaging the oil industry.

    One man with one match in the right place……….

    The situation there reminds me of a poster I have , someplace, of four old native Americans, with their rifles, looking pretty desperate.

    The caption reads:
    Turn in your weapons, the government will look after you.

  54. MASTERMIND says:

    The US middle class will be extinct by 2035 (Federal Reserve NYC)

    • George Kaplan says:

      What’s that got to do specifically with oil, which this post is nominally about?

  55. john keller says:

    Anybody following Pioneer today and yesterday. The Permian players are getting slammed. There is concern about their rising GOR. I’ve read some posts that are beginning to question the Permian as maybe the basin is showing effects of depletion and losing energy.

    Any thoughts?

Comments are closed.