US Gulf of Mexico, May Production

Guest Post by George Kaplan

GoM Production

Production for May by BOEM was 1673 kbpd and by EIA 1661, compared with 1661 and 1658 kbpd, respectively in April.

March looks like the peak, at least near term, for the basin, especially with Hurricane Cindy impacting the coming June figures.


The combined new fields added from late 2014 look to be peaking as well. Great White came back on line but xxx and yyy declined. In previous data I had omitted one big producing lease in Mars, which included the new Deimos field. With this added the production growth through 2017 is higher (and as shown later the decline in mature fields faster) than previously shown. There may be more increase to come: the Mars leases had three rigs operating through June, one dedicated for Deimos, which has now gone. The two platforms on the field each have a dedicated platform rig, so they can continue with in-fill drilling and workovers as they wish. The Kaikias development will be tied into the Olympus TLP on the Mars field in 2019, but it’s a subsea tie-back so would need a separate drilling rig. The facility has nominal capacity of 100 kbpd, but that might be limited by the platform wells and manifolds rather than production trains – if not then Shell must be expecting some decline before Kaikias comes on line.


Stones start-up is still not looking good with an 8 kbpd fall – Shell are taking over the operation from SBM by buying the FPSO instead of leasing. Maybe this indicates poor operating performance (if so it’s something for ExxonMobil to be concerned with as they are following the same approach with SBM for Liza), or maybe just a convenient scapegoat. Julia, Cardamom, Stones, Jack and Lucius still have active drilling programs so may have opportunity for growth. Julia had plans for subsea multiphase pumping, I don’t know if that is operating or will be brought on as pressures fall.

Production from the South Santa Cruz and Barataria fields started in mid June (actually part of Fourier and East Anstey fields by BOEM naming). The first Horn Mountain Deep well, for Anadarko, started production in April, a second well is due to be spudded this quarter. These are the only new fields announced for this year. Anadarko was the only company that had hinted they may develop something else (e.g. with Warrior and Phobos tie backs), but with them slashing budgets for 2017 after poor second quarter results that is now be unlikely: in their investor presentation they indicated they expected flat production out 3 to 5 years, and didn’t sound particularly confident of that to me, and with no mention of Shenandoah so that might be on the way to full cancellation. One new lease in the Marmalard field (the last there) for LLOG was started in late May.

I’ve added natural gas production for the new fields here. Hadrian South and Otis are the only dedicated gas fields. Hadrian South production is a big proportion of the gas total from GoM now. It produces to the Lucius Spar, operated by Anadarko, and according to their investor presentation Hadrian South is supposed to finish by about 2021. I’m not sure if that can be correct, but if so it’s production should be declining significantly soon. Also on Lucius, it’s biggest producing lease, really part of Hadrian North field, started showing a sudden water cut increase in May, and dropped about 8% production (for some reason this does not show up in BOEMs list of qualified fields, but it is definitely tied in to Lucius). The first lease on the Lucius field has been killed in about two years with water break through; it’s not clear what their plans are for it (this is Anadarko as well).



A couple of leases in Na Kika look like they have gone off line so production is down. Thunder Horse numbers were revised and now clearly show the impact from South Thunder Horse with about 35 kbpd increase. There have one rig still operating, but I think they will just maintain plateau now. Atlantis looks to be running about at nameplate capacity, so the coming North Atlantis development is likely only to be able to extend the plateau; there is one rig operating there now.



For the Caesar/Tonga/Tahiti fields the Anadarko facility (Constitution Spar) went off line taking off 40 kbpd production (Ticonderoga and Constitution fields go there too). The turn around was for 42 days so will reduce June figures too. The Constellation field is to be tied into the spar next year, the spar has nominal nameplate of 70 kbpd so another 25 or so (average) might be added to overall output.

For the Chevron fields in these leases it looks like production is limited by the gas handling capacity on Tahiti platform, at 70 mmscfd, which is pretty low given it’s oil capacity of 125 kbpd.


After a bit of a plateau from some brownfield work and new tie backs the decline in the larger mature fields looks like starting up again; the drop in gas is particularly noticeable, but is mostly due to Baldpate turn around. Overall water cut looks like it might be rising as well. Thunder Hawk has two new rigs operating, but I haven’t seen any announcement for new developments there. The smaller mature fields (not included in the charts) seem to be holding up quite well, I will try to get some individual lease data for these next month.




For the GoM activity report from the last week in July, there were 28 rigs drilling, twelve running tools and two in plug and abandon operation. I think the report can mean there is dual activity on a single well (e.g. wire line and drilling). Two rigs are predrilling on Stampede, one on Appomattox and one on Mad Dog II. For the newer fields there is development drilling on Lucius, Cardamom, Mars (two rigs), Stones, Julia, Jack / St. Malo, plus new wells for recently added or due production on Horn Mountain Deep and South Santa Cruz/Barataria. Atlantis also has a new rig, which may be for development of the Atlantis North discovery – it’s noticeable how any reasonable discovery is immediately fast tracked, the North Sea is similar. The Dorado field (operator Anadarko, discovery in 2014) is also being drilled; I think it is one of the last of wells for small fields (King, Dorado, Holstien Deep) being tied back to Marlin, there’s probably one more for King and a couple of others possible. Only Phobos has appraisal drilling.

Five rigs are drilling on unnamed fields, so presumably exploration – four of these are in Green Canyon, which means they are near field, and probably smaller, prospects; the other one is for Shell, in Walker Ridge, and probably a frontier wildcat. With all the predrilling on new fields, most new fields reaching plateau or decline periods, and few exploration wells (and fewer still in frontier regions) it seems likely that the drilling numbers will tend to decline over the next few years as unused well slots and tie back locations on the facilities are exhausted, even with an increase in oil price.

In the past few months as production rose the EIA STEO showed a new production forecast which had the same shape but was just raised to start on the new production number. They didn’t do the reverse as the production fell but instead kept the June STEO forecast with a single dip down for April. The August STEO, showing May data, is due next week.

GoM Lease Sales

As further support that the current decline in exploration is not just a function of price, the chart below shows the acreage of GoM leases that have been successfully auctioned, plus the percentage of offerings that were taken up (charts are stacked according to BOEM designated production areas to the give total). The numbers before about 1976 are listed against states (FL, LA, TX) and I think are inshore shallow leases, although it might be they just changed naming convention. After about 1990 areas were split from just GOM to east, central and west. The percentage bought calculation only considers the area auctioned after 1990. It is marked how the amount bought and the percentage bought both peaked and rapidly dropped off, even in the high price years through to 2014. However there were obvious impacts from earlier price collapses in the late nineties and 2008.


It’s possible to read too much into these charts but generally it looks like, on average, discoveries follow three or four years behind the lease sales and production about the same length after that. But the recent production rise isn’t in that pattern – maybe disrupted by the 2008 recession and 2010 drilling hiatus, or maybe the high oil prices after 2011 allowed some difficult and expensive long term discoveries to become commercial.


The number of open, undeveloped leases is relatively few, and declining. The chart below shows the number of leases discovered (and not terminated without development), producing or in development, and those still undeveloped. The open bars show my guesses for some larger fields that seem likely to be approved soon (e.g. Vito, Anchor). Most of the undeveloped leases (in yellow) are associated with existing, fairly recent, fields on production (e.g. St. Malo, Tubular Bells( and are likely to be poorer wells, waiting on surface facility capacity to become available before being tied in. There are two new field discoveries this year: Mormont and Khaleesi, by LLOG in Green Canyon (they have switched from Animal House to Game of Thrones naming convention) and are likely to be smaller reserves similar to their Delta House developments.


There is one area that might be expanding: deep shelf pre-salt. These are deep or ultra-deep wells but in shallow water (this is a rare combination and hence one problem is that there aren’t many rigs – jack-ups – that are suitable). W&T brought on Mahogany field this year, in an already producing lease (one well at 5000 boed with up to three others due, although the production data suggests it wasn’t as great as expected) and there may be more to come. The production is high pressure and high temperature, and in places can be too high for the available technology or commercial development, and mostly gas prone.

This entry was posted in Uncategorized and tagged , , , . Bookmark the permalink.

296 Responses to US Gulf of Mexico, May Production

  1. shallow sand says:

    Again, thank you for the GOM update!

    In the continued debate on US lower 48 shale, interesting developments with PXD. Stock at one point was off over $25 per share, but has recovered some. Will be interesting to see what happens to it in the next few weeks. Apparently GOR guidance was off, wells are producing too much gas?

    Also, EOG earned 8 cents a share. Based on those earnings, EOG stock trading at a PE multiple of around 280. It’s stock is not down that much today.

  2. clueless says:

    Glenn – Regarding your comment to SS in the previous thread: “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.”

    I have not analyzed SS assertion that PXD is understating depletion, thereby leaving a greater asset on its books after 5 years of production than it is worth.

    With regard to your comment – no, GAAP has not changed. I think there is a communication gap. PXD, like all oil companies, capitalizes the entire cost of drilling a well for “book” purposes. The entire cost includes probably 95% “intangible” costs, such as paying for the rig and just digging a hole in the ground. About 5% of the cost is “tangible” equipment, including the steel casing, cement, pump jack (if needed) etc. [For tax purposes, only the tangible cost is capitalized, along with the leasehold cost.] For book purposes this entire drilling amount is capitalized [along with the original leasehold cost] and adds to PXD’s book value. This book value is reduced pro-rata when production starts, and the pro-rata reduction is called depletion.

    SS point is, for example, let’s “assume that WE know” that the well is only going to produce 500,000 boe total. But, assume that PXD beleives that the well will produce 1,000,000 boe. After the $10 million of cost [assumption] is capitalized and 400,000 boe are produced, PXD will have deducted $400,000 of depletion, leaving $600,000 of book value. But, we know that the well is only going to produce 500,000 boe, so the book value should be only $200,000 [$10,000,000 minus 80%]. So, SS asserted that if this happens and PXD tries to sell the well [or even if it keeps it], at some point they will have to record an impairment and reduce the book value accordingly. So, SS is asserting that the impairment IS applying to book value.

    • texas tea says:

      as i understand tax issues relating to oil and gas production the “depletion allowance” is calculated at a rate of 15% of gross proceeds on an annual basis and has nothing to do with some EUR calculation. Depreciation on the other hand…

      • shallow sand says:

        TT. You are referring to percentage depletion for income taxation purposes, which only applies to the first 1,000 BOEPD produced by any company. For income tax purposes, there is income depletion and cost depletion, and the producer is permitted to take the greater of the two, but as to percentage depletion, only as to the first 1,000 BOEPD.

        I am referring to depletion for GAAP purposes, utilizing the units of production method. From what I understand, depreciation applies to the tangible equipment, such as casing, tubing, rods, pumpjack, downhole pump, gathering facilities, etc. Depletion refers to the intangible costs of the well, such as land, seismic, drilling the hole, completing the hole, etc.

        Take a look at the website, under depletion method. There is an overview which I think is fairly easy to understand.

        I would very much like those with more knowledge than me to comment further on this issue, but I do realize this is a specialized accounting area.

        My suspicion, which I have discussed with others, is that inflated EUR helps earnings in the near term, by causing less of an “expense” to be charged against earnings during the early years of the well. This, of course, will lead to reserve restatements/impairments, or impairments upon liquidation of the wells. However, as that is a problem 5+ years down the road, it is better to just kick that can a few years out rather than to keep recognizing losses now.

        However, I think maybe recording small earnings is worse than losses. Losses can be excused for growth, new tech, Amazon and Tesla comparisons, etc. Small EPS results in 100+ P/E multiples, and suddenly some start to think, “are these companies overvalued trading at a forward P/E of 175?”

        • Glenn E Stehle says:

          •••••shallow sand said:

          I am referring to depletion for GAAP purposes, utilizing the units of production method. From what I understand, depreciation applies to the tangible equipment, such as casing, tubing, rods, pumpjack, downhole pump, gathering facilities, etc. Depletion refers to the intangible costs of the well, such as land, seismic, drilling the hole, completing the hole, etc.

          I don’t think so. Tanglible drilling costs are capitalized in both tax basis and book value. I think clueless is correct in this.

          There is book depletion used for SEC forms, and there is tax depletion used for federal income tax returns. They are two separate things. Here’s a brief explanation from an accounting firm:

          What are the differences between book and tax depletion?

          There are a few important facts to remember if you are a producer calculating book and tax depletion.

          1) Intangible Drilling Costs (IDCs) are capitalized for GAAP and expensed for tax.
          2) G&G costs are sometimes expensed for book but are always capitalized and amortized over 24 months for tax.
          3) Accretion expense is deducted for book but is non-deductible for tax. Only actual cash paid for asset retirement obligations for the year is deductible.
          4) Impairment of oil and gas properties are expensed for book but are never deductible for tax.

          Book and tax basis will never be the same because of reasons 1 and 2 above.

          •••••shallow sand said:

          My suspicion, which I have discussed with others, is that inflated EUR helps earnings in the near term, by causing less of an “expense” to be charged against earnings during the early years of the well.

          And so I will ask again what I asked on the other thread:

          According to its SEC filings, 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 expense 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 expense during the first year to be “vastly understated”?

    • Glenn E Stehle says:

      clueless said:

      I have not analyzed SS assertion that PXD is understating depletion, thereby leaving a greater asset on its books after 5 years of production than it is worth.

      But the book value of an asset is the acquisition cost minus depreciation, not minus depletion.

      If an asset is sold for less than its book value (acqusition cost minus accumulated depreciation), then sure, shallow sand’s assertion that “If PXD ever sells the well, huge impairment” is true.

      But what does impairment or book value have to do with depletion? Absolutely nothing. Can you show me where depletion enters into the formula that is used to calculate book value?

      You and shallow sand are using depletion and depreciation as if they were interchangeable, and I’m pretty sure they’re not, or at least they weren’t back when I was still active in the oil business. They weren’t the same for income tax purposes, and they weren’t the same according to GAAP accounting rules either.

      Take this passage from Pioneer’s FY2016 annual report, for example:

      Depletion, depreciation and amortization expense. The Company’s total DD&A expense from continuing operations was $1.5 billion ($17.29 per BOE), $1.4 billion ($18.59 per BOE), and $1.0 billion ($15.75 per BOE) for 2016, 2015 and 2014, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $16.77, $18.01 and $15.19 per BOE during 2016, 2015 and 2014, respectively.

      Depletion and depreciation are not the same thing.

      • Glenn E Stehle says:

        And so I will ask shallow sand again what I asked on the other thread:

        According to its SEC filings, 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”?

        • Watcher says:


          Do you think they just imagine that credit rating?

        • shallow sand says:


          I am looking at PXD earnings release for Q2, 2017. The expense for depletion, depreciation and amortization taken for Q2, 2017 is $341 million. So, annualized, this is the $1.364 billion that you are referring to. The DD&A for Q1, 2017 was $337 million. So it looks like the annualized number you use will be very close.

          PXD plans on spending $2.4 billion on drilling and completion capital in 2017, plus $275 million in other capital for 2017, for a total of $2.675 billion in CAPEX in 2017. That is roughly double the amount of DD&A expense that will be taken in 2017.

          On page 70 of the 2016 10K, and page 71 of the 2013 10K the actual DD&A numbers appear in the consolidated statement of operations for 2016, 2015, 2014, 2013, 2012 and 2011. Those number are:

          2016:$1.480 billion
          2015: $1.385 billion
          2014: $1.047 billion
          2013: $.907 billion
          2012: $.708 billion
          2011: $.490 billion

          On page 73 of the 2016 10K, and on page 75 of the 2013 10K in the consolidated statements of cash flows for 2016, 2015, 2014, 2013, 2012 and 2011 are shown additions to oil and gas properties and additions to other assets and other property, plant and equipment. These numbers, (added together), are:

          2016: $2.060 billion
          2015: $2.393 billion
          2014:$3.576 billion
          2013: $2.876 billion
          2012: $3.055 billion
          2011:$2.290 billion

          PXD DD&A expense 2011-2016: $6.017 billion
          PXD additions to oil and gas properties and other PP&E 2011-2016: $16.250 billion.

          This seems out of whack to me, considering how quickly PXD’s wells decline.

          Glenn, are you arguing the estimated DD&A of $1.364 billion in 2017 would pertain to only 2017 CAPEX? I believe it would apply to all PXD wells, and other PP&E additions that have not been fully depleted, depreciated and amortized, and that have not been disposed of or abandoned by PXD for all years since the company came into existence. There could very well be 1990s assets still on DD&A, in the case of buildings and oil wells back to the late 1970s.

          I do agree I did not figure in impairments in comparing 2011-2016 DD&A v. 2011-2016 CAPEX, but I do not see that PXD has taken impairments large enough to close a discrepancy of over $10 billion dollars over the course of six years.

          It appears that much of the DD&A is being kicked far out in the future, but I would need to see the schedules carried out for the next 30+ years to confirm that, and I do not have access to that, of course.

          Clueless, do you care to give your views on this? Am I looking at this incorrectly?

          • Glenn E Stehle says:

            shallow sand,

            I think Pioneer dug itself a heck of a hole back in 2012, 2013, 2014 and 2015.

            The wells it drilled in those years, whether wolfberry or horizontal shale, will struggle to pay out with $50 oil. They were high cost, low performance wells in comparison to today’s wells. But a great deal of that sunk investment is still on the books. That’s why Pioneer’s DD&A per boe is so high. And that’s also why Pioneer’s DD&A to capital spend in 2017 is high. It’s like trying to swim (show positive earnings) with a lead anchor tied around your foot.

            Should this DD&A expense be even greater than what Pionner is reporting? Has Pioneer engaged in some accounting tricks to make this DD&A less than what it should be? I don’t know.

            As to a forward-looking analysis, it looks like Pioneer’s D&C cost per boe is too high in comparison to other peers like Diamondback and Encana.

            With its “cube” strategy, Encana is nearing well manufacture mode where it stamps out 60 wells per section in five different stacked pay zones all at one time. It’s boilerplate at under $5 million per well. In its latest investor presentation, Encana argues that’s the only way drilling shale wells in the current oil price environment makes sense.

            Pioneer has been, I can earnetly say, a pioneer in drilling shale wells in the Permian Basin, and is still playing that role, experimenting with longer and longer lateral lengths and more and more advanced completion techniques. Others can learn from its failures and successes.

            In the long run, however, you may very well be correct when you said:

            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.


            Time will tell, but there don’t seem to be any shortage of batters at the plate trying to eek out a profit from Permian shale, even at these depressed prices.

            • shallow sand says:


              I have looked at Encana’s recent wells. I think we need a few more months to see how productive they will be.

              I understand how drilling 60 wells as they are intending would cut down on costs per well. We will need to see how productive the wells are.

              My initial reaction is that productivity per well is suffering, but it is too early to tell. By year end we should have a better idea.

              FANG is a company that seems to have an edge, I haven’t had a chance to look at Q2 for them yet.

          • Heinrich Leopold says:

            shallow sand,

            In my view the underlying reason for the fast declining cash flow/DD&A ratio for PXD is the strongly rising depletion rate (see blow chart). As most analyst assumed the shale oil depletion rate (for Bakken, Eagle Ford and Permian combined) will be stable over the years, it actually rose to 91% for July. Although this is already an extreme depletion rate, it will very likely even rise further over the next months.

            Bakken, Eagle Ford and the Permian spend cash on 5 mill bbl/d of annualized new production, yet get cash on just 0,5 mill bbl/d of net production growth. As this reduces cash flow considerably, it means also that drilling cost per net produced barrel are nearly ten times higher than for conventional production, despite much lower drilling costs per well.

            As most investors probably cannot see the technical difference, it is now most obvious in financial numbers, which led to the crash of PXD (down 10.77% and spread triple breakdown on the point and figure chart). As PXD is the stallion of shale gas and oil production, it is a strong indicator of the future development and should give investors much concern about their shale oil and gas investments.

            However, the strong decline of future US oil and gas production is an excellent indication for high oil and gas prices over the next few years.

        • Glenn E Stehle says:


          I was looking at Diamondback Energy’s 8-K that was filed this morning for 2Q2017.

          What a difference between them and Pioneer.

          • DD&A for FY2017 is almost 100% of capital spend for FY2017.

          • DD&A is only $9.00 to $11.00 per boe, as opposed to $14.46 per boe for Pioneer (2Q2017).

          • Budget to drill horizontal wells is estimated between $650 and $775 million

          • For that you get between 115 and 135 wells

          • That works out to an average of $5.7 million per well

          Diamondback’s average lateral is only 7,500′, and Pioneer’s is closer to 10,000.

          Pioneer is pushing the limit on lateral length, and that may prove to be a mistake. That extra 2,500′ seems to come at a very high initial cost, and with a lot more “operational problems,” as Pioneer called them, that slow down execution.

          Diamondback is experimenting with a few of the long lateral wells. But they haven’t tried to make that their bread and butter the way Pioneer has. So maybe the Diamondback and the Encana strategy is the way to go. The stock market seems to be saying so.

      • clueless says:

        Glenn – Believe me, people write entire books on various accounting words. So, when we talk here, we are not going to write a book.

        I believe that I remember that Black’s Law Dictionary essentially defines an asset as anything of value. Anything of value that ends up on the asset side of a company’s balance sheet is called an asset AND EVERYTHING THAT ENDS UP THERE INCREASES THE COMANY’S “BOOK VALUE.” Everything that is a liability decreases book value, and the net of the two, whether positive or negative ends up being the “net book value” of the company. Purchased Goodwill is an asset. If you purchase CocaCola, the value of the formula would be an asset [billions of $’s] that would end up on the balance sheet and add to book value. If you bought General Motors, the value of their dealer network would be an asset [billions of $’s] and add to book value. If you purchased both with 100% borrowed money, well the debt would be an offsetting liability and the net book value of your company for these two items would be zero.

        Assume that a comany uses its own employees to construct their own office building. All expenditures for employee labor, materials, even allocated interest costs, if the company has debt, are capitalized into an asset called office building. Generally, the building asset is depreciated, but at different rates for book and tax. They do not have to acquire the building from someone else. Same thing with an oil well. Only the asset ends up being put into two sub-categories – generally intangible costs, which are depleted and tangible assets which are depreciated.

        You say: “But the book value of an asset is the acquisition cost minus depreciation, not minus depletion.” Like I say, you could write a book. But, for your information, the book value of an asset is the capitalized cost less ANY DEDUCTION. If you purchase a patent that is generating royalties, the deduction is called “amortization.” For tangible equipment or buildings, the deduction is called “depreciation.” For intangible drilling costs the deduction is called “depletion.” For accounts receivable assets, there is generally an offsetting reserve for “allowance for doubtful accounts.” For example accounts that are more than 6 months past due might be valued at 50%, and accounts in bankruptcy a zero. For other assets that are demostrably worth less than the book value computed normally, the deduction is called an “impairment.” [Once an impairment is recorded, it can never be reversed in GAAP, no matter how much the asset subsequently goes up in value. [But, you could write a book. For example, if a company has a net operating loss and it is doubtful that it will ever make enough money in the future to receive a tax benefit, the potential tax benefit (which would be an asset, which would increase book value) cannot be recorded on the books. However, if the comany’s profitablility does imporove such that it is reasonable that they will be able to use the benefit of the net operaing loss carryforward, then it can be added as an asset at that time – which increases book value.]

        Glenn says: “Tanglible drilling costs are included in both tax basis and book value.” In oil and gas accounting, generaly there is no such thing as “tangible drilling cost.” Tangible items are classified as what they are – generally, depreciable equipment. And depreciation is not tied to production. I believe (but I am 30 years removed) that oil and gas equipent is depreciable over 5 years for tax, but most likely 5-10 years straight line for book purposes.

        Glenn says: “You and shallow sand are using depletion and depreciation as if they were interchangeable.” No we are not. Depletion [generally recorded pro-rata over the expected total production] reduces the book value of an asset [generally intangible drilling costs and leasehold costs] and the net is the net book value of that asset. Depletion reduces the book value of an asset, eq1uipment, [for book purposes generally 5-10 years using a straight line method (same amount each year)] and the net is the net book value of those assets.

        For general purposes, depletion, depreciation, amortization, valuation reserves and impairments are not recorded as liabilities, but rather as a direct reduction of the value of an asset. They are a reduction of the related asset’s book value. Assets have a book value, and the company as a whole has a book value. Liabilities affect the company as a whole.

        • Glenn E Stehle says:


          Well all I can do is speak from experience.

          Back when I was participating as a working interest partner in the drilling of a well, in the first year:

          1) I got to expense 100% of the Intanglible Drilling Cost.

          2) I got to expense the first year’s depreciation, which was figured on a straight line basis (for instance, if it was 10 year property I could expense 10% of Tangible Drilling Cost).

          3) I received a 10% investment tax credit, which was calculated by multiplying .10 times the Tanglible Drilling Cost.

          4) I got to expense the depletion allowance, which for a little investor like myself amounted to 15% of the gross revenue generated by oil and gas sales.

          At the end of the year, my tax basis would be the Tangible Drilling Cost less 10% deprecitation.

          In the second year:

          1) I got to expense the second year’s depreciation, or 10% of the Tanglible Drilling Cost.

          2) I got to expense the depletion allowance, or 15% of the gross revenue generated by oil and gas sales.

          At the end of the second year, my tax basis would be the Tangible Drilling Cost less the cumulative depreciation of 20% I had taken in two years.

          Now let’s say I decided to sell my workng interest in year three. My capital gain (or loss) would be calculated as the sale price less sales expenses, minus the tax basis, which at that moment would be Tangible Drilling Cost less 20%.

          Depletion in no way, shape or form entered into the calculation of tax basis. Depletion was a tax break that producers of oil, gas, other minerals and timber get to take.

          Public corporations also got to expense Intangible Drilling Cost, got to take the investment tax credit, got to depreciate Tanglible Drilling Cost, and got to take the depletion allowance, even though depletion might have been figured on a cost basis rather than a percentage basis.

          However, now you’re telling me that, for a public corporation, “the book value of an asset is the capitalized cost less ANY DEDUCTION,” and that “for intangible drilling costs the deduction is called ‘depletion.’ ”

          You furthermore state that:

          Depletion…reduces the book value of an asset [generally intangible drilling costs and leasehold costs] and the net is the net book value of that asset. Depletion reduces the book value of an asset, eq1uipment, [for book purposes generally 5-10 years using a straight line method (same amount each year)] and the net is the net book value of those assets.

          Well maybe that’s what depletion is according to current GAAP accounting rules and definitions. But if that is true, then what is depreciation according to GAAP rules and definitions?

          Something tells me that the SEC is not nearly as imprecise as you are when it comes to stipulating its rules and definitions.

          • clueless says:

            Glenn – You personnaly did all “tax accounting,” which has virtually nothing to do with GAAP accounting. But, with respect to depletion. There is depletion and “percentage depletion.” Well over 30 years ago, oil and gas companies lost virtually all percentage depletion for tax purposes [it never was used for book purposes], which was the 15% that you referred to. That used to be a tax break and used for tax purposes only. Now no taxpayer can use percentage depletion for tax purposes on more than 1,000 barrels per day. So, it it almost meaningless for public companies producing tens of thousands of barrels per day.

            Obviously, what you refer to as “tangible drilling costs” is equipment costs. I cannot say that some operator did not produce a joint venture working interest statement you that said tangible drilling costs. However, I would beleive that most of them would have just said “tangible costs.”

            With respect to depreciation, I should have proof read my comment. Your quote of my comment taken from the second to last paragraph – the first word of the last sentence should have been “depreciation” not a repeat of the word depletion used in the previous sentence. For some reason, I suspect that you recognized it as a typographical mistake.

            Back in the investment tax credit days [1970’s?], I do know that there was accelerated tax depreciation allowed on most equipment. I would be surprised if you could not have used something that was essentially double declining balance over 5 years for oil and gas equipment depreciation. And section 1245 depreciation recapture was in effect, which may have required you to recapture depreciation at an ordinary income rate – if you sold equipment at a price that exceeded its tax basis.

            • Glenn E Stehle says:


              So then what you are saying is that, when it comes to GAAP accounting and the SEC’s rules and definitions, that tanglible costs are depreciated and intangible costs are depleted?

              And furthermore, the only place where the IRS’s concept of a depletion allowance shows up on SEC forms is in the income tax line (in the form of lower taxes)?

              • clueless says:

                Glenn – I would say in general, your first paragraph is correct. But, remember that the terms are more convention than radically different ideas. It’s like a musician produces music, and I produce noise. But, in both cases, the scientific result is noise. [Probably a crappy analogy, but I do not want to argue about it.]

                With respect to IRS’s concept of depletion – I do not know how to answer. The IRS Code has % depletion, which is not in GAAP. So, you only see % depletion on tax returns. On the other hand, the IRS also does have normal depletion, just like GAAP. However, with respect to oil and gas, tax return depletion is generally much less than GAAP. That is because intangible drilling costs are expensed immediately for tax purposes, but are capitalized and depleted for GAAP purposes.

                • Glenn E Stehle says:


                  That makes sense and seems to be consistent with the numbers that the O&G companies that operate in the Permian Basin are reporting on their SEC forms.

                  This discussion has helped me clarify some things. The fact that the IRS and SEC have completely different rules and definitions for “depletion” makes it quite confusing.

                  • It sure is. And when we operate in other countries we have to keep three separate sets of books, all of them linked to ensure compliance, but which use different rules.

                    For example, in some nations there’s no difference between tangible and intangible costs. We also have different rules regarding what can be expensed versus capitalized. In some cases there’s a cap on capital recovery. In others, for example Angola, the net share of sales is adjusted according to the rate of return.

                    I’ve got so exasperated over stupid meetings with accountants to decide which portion of a well sidetrack is expensed and which is capitalized, I decided that if I ever get to design a system I won’t even have a difference between OPEX and CAPEX. I’ll simply say everything gets lumped and 33% of the total will be deducted from the gross income line each tax year.

        • clueless says:

          clueless CORRECTION 4:25 pm comment- The first word of the last sentence in the 2nd to last paragraph should be “Depreciation” – not Depletion.

    • Hightrekker says:

      Thanks George—
      My literacy on this is minimal.

  3. SouthLaGeo says:

    Thanks again, George.
    A few comments regarding your last paragraph on the shelf subsalt – there was a fair bit of interest in that play a few years ago after Freeport McMoran announced gas discoveries at Davey Jones and Blackbeard – nothing has come of them since except for an onshore gas development called Highlander. (Freeport spent a lot of money trying to produce one of the Davey Jones wells, but were, in the end, unsuccessful).
    The W&T’s oil wells at Mahogany are actually a re-development of a subsalt discovery Phillips made in the mid 90s. Not sure if W&T is developing a different sand, or different fault blocks than Phillips.

    In general, the shelf subsalt is thought to be a gas play, but, most of the prospective reservoirs are interpreted to be in a deep-water slope setting, rather than a basinal setting like the GOM deepwater subsalt. Being in a slope setting implies that reservoirs are going to be isolated to channels/channel systems. This suggests that unless your seismic data is good enough to identify these channels, and remember this is subsalt data, you are taking a big chance that reservoir is going to be present at any given prospect.

  4. clueless says:

    George – We have got to be from different generations. I am 76, and in the 1960’s did COBAL F programming for Bell Helicopter for a couple of years. So, I have been somewhat comfortable with computers.

    But, I am just blown away by your charts and graphs and the huge volume of information that you put into a post. I have no clue where you get all of your information, nor how you are able to mass produce your graphs, etc. And, you have to be very good at it or else it would be consuming all of your spare time.

    I have Windows 10, and I will be typing along and accidently hit some key [or combination, I have no idea what] and my entire comment will disappear. And I have no idea how to “find” it, and must start over. That could never happen to you because you would shoot yourself.

    But, thank you for all that you do for us.

    • George Kaplan says:

      I guess I’m very good at it – LOL – not really. I’m a bit younger, but not much, my first programs were on tape and punch cards and on a main frame with men in white coats tending and sticky mats you had to walk over to keep the dirt out. I did Cobalt and Fortran and another beginning with B that I’ve completely forgotten (that was the tape one) then moved up to C, C++ and VBA and even Postscript, not sure if that’s used any more. It took a bit of time to set some of this up, but now the only time is with downloading the data from BOEM, and then only because it limits the number of leases that can be downloaded at once. Other than that I just run a couple of macros and use the SUMIFS function a lot (and with a lot of arguments) – I tried pivot tables, but not a fan really. I can handle interpretive languages these days, I’m not so sure how I’d do with the write-compile-correct-run cycles we had to go through, and my spelling and grammar get worse each day. Really I started looking in detail at GoM because the EIA forecasts didn’t make sense, overall it fills an hour or two most days.

      I use a Mac, I hate Windows, I liked Unix the best – for some reason I think Mac operating systems might be based on it, long ago, but can’t remember why I think that.

      • JN2 says:

        Yes, Mac operating system is a Unix derivative, so is Android and Linux. And Chrome OS which runs my chromebook, my best laptop ever!

        • Hightrekker says:

          All but one release of Mac OS X (now macOS) has been certified as Unix by The Open Group, starting with 10.5:

          10.12 (Sierra)
          10.11 (El Capitan)
          10.10 (Yosemite)
          10.9 (Mavericks)
          10.8 (Mountain Lion)
          10.6 (Snow Leopard)
          10.5 (Leopard)
          Apple’s page on The Open Group site only lists the current version of macOS as I write this, but all of the links above were at one point found via that page.

          OS X’s status as a certified Unix is called out in Apple’s Unix technology brief, which also has other good technical bits in it that will help you compare it to other UNIX® and Unix-like systems.

      • Fred Magyar says:

        I did Cobalt and Fortran

        Cobalt was the original precursor of today’s BLUE Screen of Death, in MS Windows’ Common Business Oriented applications… 😉

        BTW, I did a lot of graphics and vaguely recall editing postscript code in text files for creating vector based images but then later Adobe evolved and I became a black belt bezier curve master with Illustrator and a mouse not having to worry about the underlying code.

        • George Kaplan says:

          I think I might have meant COBOL – did I? Whichever one was more for business and accountancy types in the 70s, with an attempt at natural language commands I think.

          • Doug Leighton says:

            Yeah, I think the commerce types used COBOL while we (engineers) worked with FORTRAN. Not sure who used BASIC, I never did. The most time consuming job for me, and every other geophysicist, was doing the programming though by the time I came on the scene sub-routines were becoming available which helped a lot. Alas, punch cards.

          • Dennis coyne says:

            Hi George

            cobol is correct.

  5. SouthLaGeo says:

    I can’t find the link now, but, I recently saw an EIA document about their projection for US production out through December, 2018. They projected that GOM production alone would have an increase of over 300 kbopd between June-2017 and December-2018. That would put GOM production at about 2 mmbopd or so by December-2018.
    Between now and December-2018, the most notable new projects to come on line should be Big Foot and Stampede, which could add about 100 kbopd by December-2018. I can’t see where the rest is coming from.
    We’ve established that EIA’s GOM projections are consistently too favorable, and here we see it again.

    • George Kaplan says:

      Probably STEO, which comes out around the middle of the month I think.

      • SouthLaGeo says:

        Found the link.

        The EIA identifies more than 2 projects to come on line between now and December-2018, but, I suspect most of them are tie-backs.

        • George Kaplan says:

          I think a lot of what they have is wrong: for this year and next they have Son of Bluto 2 – which came on last year; Otis, which is a gas field and came on last year; Atlantis North, which will come on but I think they don’t have capacity to increase production overall but only maintain plateau; Amethyst, which is gas field that came on last year and gave up after 4 months and I think has been abandoned; Horn Mountain Deep, which is on line but a small tie back; and then Stampede (I think 70 kbpd).

          Last year they had a few that might increase in production especially Julia and Stones, but Heidelberg Phase II isn’t for a couple of years; Wide Berth is a small field that has been operating since 2012 (I think they actually meant Penn State); Thunder Horse South happened this year; I don’t know what Caesar/Tonga II is, I think they probably mean Constellation (maybe 30 kbpd next year). I think your 100 kbpd to come through 2018 is about right, Big Foot is not due until the end of the year, and then nothing planned for 2019 at the moment.

          • Dennis Coyne says:

            Hi George,

            Did your analysis this month change your future projection from previous posts?

            Seems you and SoLaGeo agree the EIA’s STEO for GOM in Dec 2018 is about 200 kb/d too high (or perhaps at least 200 kb/d too high).

            • George Kaplan says:

              If anything, with Anadarko cutting spending, I think maybe a slightly higher decline rate than I thought previously. I think EIA are predicting 300+ kbpd growth. I think it will be a decline from where we are now, unless there are a couple or more decent tie back discoveries in the next couple of months.

              The BH GoM rig count dropped seven for last week, I expect some is just random variation and will come back, but as I said above it’s also likely that they are running out of planned development well targets, and possibly also near field exploration prospects; and opportunity in fill drilling for acceleration has been dead for three years now.

  6. Boomer II says:

    Both the auto industry and US voters support increased fuel efficiency standards.

  7. Watcher says:

    ThunderHorse assay. 30% middle distillates. Right and proper oil.

  8. shallow sand says:


    Which companies are still big players in GOM?

    Did ConocoPhillips state they were soon out?

    • George Kaplan says:

      SS – This gives you an updated rank by oil production (CoP second bottom on first page, but they may have subsidiaries listed separately):
      and this by gas

      • shallow sand says:

        George. Thank you!

        Is there any possibility that GOM wells that produced majority gas or solely gas have been economic in the past three years with gas prices under $3 per MCF?

        Also, I had mentioned before looking at Energy XXI wells on an individual basis, and noted how many produce under 100 BOPD. Do you have any information as to how many oil wells in GOM produce under 100 BOPD at present?

        I do not know much about GOM production, but suspect many wells have been operated at a loss since late 2014. I have heard there are concerns of many wells in GOM being abandoned and not plugged. Any truth to those concerns?

        • George Kaplan says:

          You are getting outside my comfort zone there, I mostly just look at the oil. First off I think you’d need to separate the associated gas from produced gas, and then shallow water from deep, and then new developments from legacy fields. Hadrian South and Otis (in charts above) are the only gas fields added recently. Baldpate is the only other largish deep water gas field operating. All the data you want is available but the download time is high if I haven’t kept the Excel files (or more likely can’t remember what the names mean). I’ll see what BOEM have and what I can easily extract.

        • George Kaplan says:

          SS – this shows the number of oil wells in the range shown (up to the maximum under the bar) in bpd for January this year. I calculated the flow as stream day (i.e. production divided by days on line) rather than monthly average. Don’t know if it helps. There are over 6000 wells that didn’t produce at all, and probably didn’t through the year, I haven’t managed to figure out if they are plugged yet, but might be able to.

        • George Kaplan says:

          This shows the number of gas wells (i.e. not associated gas) in the given flow range (again streamday, not average over the month). Does this mean anything – it might make more sense if I split it up by water depth?

          • shallow sand says:

            Looks to me like there are likely a large percentage of both oil and gas wells in the GOM that are not economic on an operating basis, plus if those 6,000 wells are not plugged, wow!!

            I have a hard time understanding how an offshore well making under 100 BOPD works in the world of sub $50 oil.

            Energy XXI operates many of those and they long ago went BK, but I’d sure like to hear from someone in the know how to make stripper oil wells in GOM work. Not because I am interested in investing, but because I cannot see how it can work financially.

            • SouthLaGeo says:

              Many, or most, of those GOM wells currently producing at low rates (<100 bopd) now are shallow water wells that were drilled at a time when oil prices were much higher – so the wells may have actually been a good investment at the time, produced at higher rates during a year or years of high oil prices, and may have even paid out. Now, the operators are just milking them along for as long as they can.

              Current shelf drilling activity is very low – maybe 3-4 drilling wells.

              Current shelf oil production is probably around 150-200 kbopd.

              I don’t know enough about shelf operating costs to know if an operator can afford to keep a platform with a bunch of 20-50 bopd wells.

              • shallow sand says:


                I don’t know hardly anything about offshore operating costs either.

                I would think offshore wells would need someone to periodically check them, which would mean taking a floating vessel with men and tools to them. I assume these wells quit flowing naturally, so need some type of artificial lift and I am trying to picture how those are powered if produced gas is not sufficient. Next, of course, would be disposal of salt water. How does that happen efficiently as the water cut rises? How about down hole chemical treatments? How about gathering for such small volumes. Finally, the abandonment costs have to be huge?

                I’d sure like some information on this, if anyone out there is reading and knows the answers.

            • George Kaplan says:

              SLG beat me to it but below shows the split for deep and shallow. Almost all shallow wells are below 100 bpd. I’d imagine they are mostly on unmanned wellhead platforms, the water is mostly extremely shallow, I doubt there’s that much of a difference in operating costs with onshore wells, maybe a bigger one for new developments. Note I had something wrong above and included gas wells in the oil wells so had shown a lot of low producing condensate.

            • George Kaplan says:

              This shows the numbers for inactive wells, very few P&A fully, thousands inactive or temporarily abandoned (which probably means permanently abandoned but not yet fully P&A’d). With a caveat that this is new info. to me so I may have got something wrong somewhere along the line.

              • shallow sand says:

                George. Thanks again for the GOM information.

                I can’t help but think wells in very shallow water would still be much more expensive to operate than onshore wells.

                For example, what all is involved to repair a tubing leak in a shallow offshore well?

                Same with abandonment.

                I do note many of these shallow offshore wells have produced over 1 million BO. But they have to really be hurting economically now, I suspect worse than most onshore stripper oil and gas wells.

                • George Kaplan says:

                  Probably a bit more expensive, but I should think most of the wells are pretty simple and fairly short compared to horizontal wells on shore. I’ve seen a couple of shallow drilling rigs in yards and there’s not much to them compared to, say, a deep water DP drilling ship. Moving them around can’t be much of a problem, maybe easier than a fleet of trucks. But that’s all supposition.

                  As far as P&A goes it looks like they might have decided the best bet is not to bother. Although there have been activities listed as non-rig P&A on several deep water rigs each time I’ve looked at the BSEE activity list over the last six months or so.

                  • shallow sand says:

                    George. If you have time, take a look at Energy XXI financials, on their website.

                    They also provide a good overview of their operations. They own some of the most prolific fields in shallow GOM. Some are Humble Oil discoveries from the late 1940s.

                    Unfortunately, production has fallen from 49K BOEPD to 41K BOEPD from Q1 2016 to Q1 2017. At $51 oil and $3.10 gas in Q1 2017, they only cleared $6 per BOE, before DD&A.

                    There is nothing left for new wells, very expensive to operate, more than our 1 BOPD shallow onshore stuff.

                  • George Kaplan says:

                    If they are wholly or mostly in GoM then they are going out of business within a few years I’d have thought.
                    They have 335 producing oil wells (but getting fewer each month by 2 or 3) averaging 85 bpd and falling slowly, and 88% water cut and rising, plus 250 inactive wells to be plugged.
                    For gas: 53 wells averaging 130 mscfd, but falling fairly quickly by the look of it (maybe 20 to 25% y-o-y decline), and 210 wells to be P&A’d.

        • clueless says:

          SS asks an interesting question: “Do you have any information as to how many oil wells in GOM produce under 100 BOPD at present?”

          I really have never even thought of such a thing. My guess is that would be like McDonalds operating a restaurant that sold less that 100 hamburgers a day. If any company has such wells, I think that I would be a seller.

  9. Watcher says:

    Oh btw sportsfans re credit ratings. Fitch (one of the big three, if you don’t want to study Morningstar’s methodology) rates PXD as BBB.

    They rate BP at A.

    That’s BP. The company whose litigation expense from the spill has come in at the top end of estimates. The company dealing with $49 oil like everyone else. ANDDDDD the company with huge asset profiles inside Russia, which were seized in retaliation for England signing onto sanctions.

    They are rated A. Compare and contrast.

  10. George Kaplan says:

    TWIP has all stocks falling again, but by a total less than half each of the last couple of weeks: -1.5, -2.5 and -0.2 mmbbls for crude, gasoline and distillate respectively.

    • Lightsout says:

      Hi George

      Announced this morning.

      The Stena Icemax encountered the Druid prospect in the porcupine basin and it is porous sandstone but water bearing they will now drill down to the lower Drombeg prospect.

    • coffeeguyzz says:

      Few data points concerning wind power, electricity generation, and natgas …

      World’s first floating offshore wind turbines being installed right now off Aberdeen by Norwegians. Project – called Hywind – incorporates amazing degree of engineering coupled with very high price.

      South Australia wholesale electricity hit A$416/ Mwh a few hours ago, which is nearly 15 times New England’s (expensive for US) US$25/Mwh.
      New England’s juice is 91% gas or nuclear sourced.
      NE renewables right now provide 6% of total, 2% of that from wind. (Wood and refuse provide 92% of the overall 6% renewable category).

      Range, along with EQT and Cabot, are now describing 4 Bcf of gas per 1,000 lateral foot from their wells to be the ‘new normal’.
      They project thousands of these wells will be developed over the coming decades at lengths ranging from from 10,000′ to 15,000′ in length.

      Do the math.

      The folks who are expecting wind and solar to provide high amounts of electricity in the future are facing increasing challenges in seeing that implemented.

      • Dennis Coyne says:

        Hi Coffeeguyzz,

        Like every other natural gas field, these fields will also peak and decline.

        The shale gas also need to fill in supply from declining conventional natural gas, if it displaces coal fired power, great.

        Eventually solar and wind will take over from natural gas as it depletes and becomes more expensive and as further technological improvements in solar power and batteries reduce the cost of solar power so that natural gas can only compete as backup power. This might take until 2040, hard to guess accurately. Wind power in good locations (Great Plains in US) is also very cheap, cheaper than new natural gas plants at current prices.

        • MASTERMIND says:

          It takes 150 wind turbines to power one shopping mall. And there are over 47k shopping centers in America. It would over 25 million wind turbines to power just our shopping centers! And only when the wind was blowing heavily. BWWWAAAAAAA

          • Nick G says:

            I think you should check your math: 25 million wind turbines, at 1.5MW each, would produce 37.5 terawatts when the wind was blowing heavily, while the US uses less than .5 terawatts.

            Off by only a factor of 75.

            • MASTERMIND says:

              Thus, if we now adopt this 10% effective capacity, each turbine provides 0.15 MW, and we need over 150 turbines just to provide the basic needs of ONE SHOPPING MALL!!

              • Nick G says:

                It’s not 10% effective capacity, that’s around 33%.

                The 10% figure is for something entirely different: statistical contribution to peak capacity. It’s a technical measurement used by utilities and grid operators – it doesn’t tell you how many kWhs are produced.

            • MASTERMIND says:

              Did ruin your dreams of a brighter world? LOL You are a like a donkey Nick G. You will believe anything that Obomba and Musk and the MSM tell you. No questioning ever, No common sense. Just feed it to Nick and he will eat it!

          • alimbiquated says:

            There are about 1500 shopping malls in America, and 500 of them are dead. I notice you switched terms mid post.

      • texas tea says:

        61.8 MMcf/d from a single well
        A – Robert Douglas Lawler: Okay, Charles, hold on to your sideboards of your desk there. So this well is a little bit more expensive than the wells we’ve drilled. This is a 10,500 foot lateral with a relatively aggressive frac on it, about $8.5 million. That’s the field estimate today. These are early numbers, of course, because we’ve been only been on for about six days or seven days, but we believe that we can get that cost down as we go forward.

        Q – Charles A. Meade: Well, I tell you what, I’m out of my chair and on the floor, now.

        A – Robert Douglas Lawler: Okay. Jason’s team has done a great job. I’d love Jason to put a little color on that as well.

        A – Jason M. Pigott: Well, it’s funny. The team, again, they were trying to figure out how to get 60 million a day out of one of these wells, and they actually call it the Rambo frac because they needed to attack that formation like Rambo would a POW camp. So they increased the cluster efficiency and packed it with 32 million pounds of Hell on Earth. So we succeeded in setting the captive gas molecules free.

        • coffeeguyzz says:

          Lottsa significant info in that article. I believe that is the highest 24 hour IP from any Marcellus well of which I’m aware.

          To give some perspective on the vast, vast potential of the Utica …

          Consol actually has 2 Utica wells, the Gaut and the GH 9 with 24 hour IPs at 61MMcf. (Casing pressure on the Gaut was a touch under 10,000 psi.

          EQT’s Scotts Run – arguably the most successful unconventional well in the world – had a 24 hour IP of 72 MMcf, casing pressure st 10,000 psi, and a lateral only 3,200′ long. (Flowed 29 MMcfd for 8 months).

          Appalachia Rising.

          • shallow sand says:

            EQT’s upstream segment posted a net loss (non-GAAP) of $4.2 million in Q2, 2017.

            EQT’s earnings of 24 cents per share in Q2 were the result of positive earnings in its gathering and transmission segments.

          • John Keller says:

            Once again, the Scott’s Run well cost $30mm. That well will lose $10mm+. The Scott’s Run was very unsuccessful.

            • coffeeguyzz says:

              The Scotts Run was in every sense of the word a ‘science project’ as it was EQT’s first Deep Utica well.

              The $30 million dollar cost to drill and complete this well was partially due to the extraordinarily high pressure encountered. So high, in fact, that the original rig was replaced – after a several month delay – with a much larger rig with pumps able to handle the 10,000+ psi pressure.

              Now, with 22 months’ production (665 days), the SR has surpassed 13 Bcf cum (13.038), and still flows over 8 MMcfd.

              Using $3/mmbtu for rough evaluation, this well has generated almost $40 million in under 2 years.
              EQT originally projected 12 to 19 Bcf cum over 30 years time for this well.

              The only company seemingly still interested in Deep Utica wells in SWPA is Consol.
              The expected D&C price of $14/15 million per well along with production results should increase available knowledge of this enormous resource’s potential.

        • shallow sand says:

          This appears to be from Chesapeake’s CC.

          Take a look at share price, $4.50. News reports out today say they are cutting back in NE Appalachia in a bid to increase the oil percentage of their production.

          I assume the Marcellus and Utica companies will continue to over produce for years and sell their gas for $2.50 per MCF or less?

  11. shallow sand says:

    OXY released Q2 2017 earnings.

    OXY earned 66 cents per share, however only 15 cents per share was from continuing operations. The remaining 51 cents per share was a gain on the sale of assets.

    OXY lost $300 million in Q2 on US upstream v a loss of $191 million in Q1 on domestic upstream.

    OXY had positive earnings of $422 million in international upstream v earnings of $418 million in international upstream in Q1.

    OXY had positive earnings of $230 million in chemical v positive earnings of $170 million in chemical in Q1.

    OXY declared a dividend of 77 cents per share, which is a payout ratio of 513.3% of earnings per share from continuing operations.

    OXY is the largest volume producer in the Permian Basin. OXY’s US upstream operations have been a large drag on earnings since 2015:

    2015 – negative EPS of $704 million.
    2016 – negative EPS of $1.658 billion
    First 1/2 2017 – negative EPS of $491 billion.

    So, from the above, OXY has had negative EPS of over $2.8 billion from its US upstream oil and gas operations since 1/1/2015.

    It is noteworthy to look at OXY 2013 and 2014 US upstream EPS:

    2013 – positive EPS of $2.545 billion.
    2014 – positive EPS of $1.854 billion.

    I think OXY is a very solid example of what low oil and natural gas prices from 2015-1/2 2017 have done to the economics of onshore lower 48 US upstream oil and gas.

    • Boomer II says:

      The irony is that instead of saving the gas and oil industry, LTO may be hastening its decline.

    • clueless says:

      First 1/2 2017 – negative EPS of $491 billion.

      SS- Since I am the poster boy for typos and have been appropriately humbled, it is with no malice that I would note that in this case, the billions should be millions.

      • shallow sand says:


        Thank you, my bad. I meant million. $491 million is still a lot of losses in just 181 days.

        • shallow sand says:

          Clueless. I have a good example for how overvalued some shale stocks are.

          PXD just cratered the last two days to about $135. It earned 21 cents a share for Q2.

          Clorox just posted earnings today. It is also trading at about $135 per share. It earned $1.53 per share for the quarter, declared a per share dividend of 84 cents, and guided fiscal 2018 earnings of $5.25+.

    • Watcher says:

      “OXY declared a dividend of 77 cents per share, which is a payout ratio of 513.3% of earnings per share from continuing operations.”

      RDS and BP both have this going on, but Shell has some downstream earnings so they are undercovered I think less than 100%.

      But they can borrow. Credit ratings as . . . above? well last post. They don’t have to pay 8% for money.

      OXY credit rating: A . . . on some 10 and 30 yr debenture issuance about 7 mos ago.

      Compare and contrast with the shale credit zombies.

  12. Boomer II says:

    I put this in the older oil post. I meant to put it here.

    The fight over water for drilling in Texas.

  13. Boomer II says:

    I put this in the previous oil post in response to a comment about the Permian. But it is an article from yesterday so I want to post it here.

    Here’s an article, plus a graphic showing sharp decline rates in the Permian, Bakke, Eagle Ford, and Niobrara.

    • Roger Blanchard says:

      This calls into question why drillers don’t drill outside of the core area where there wouldn’t be well interference. I monitored initial production figures for Bakken wells for 3-4 years and found that wells within the core area had a high probability of having initial production of >1000 b/d and often >2000 b/d. Outside of the core area, it was common for initial well production to be less than 100 b/d. The core area of Bakken is pretty well saturated. I personally don’t see production again reaching the level reached in Dec. 2014 even if the price of oil raises to over $100/barrel.

  14. MASTERMIND says:

    The “Self-Driving Car” is Only an Oxymoron

    How are the potentially driverless cars doing in their testing? Awful. For example, in the first week of March, Uber’s 43 test cars in three states logged some 20,000 miles on public roads. Their drivers had to intervene and take control away from the software, an average of once every mile. Critical interventions, required to save lives and property, were counted separately; they occurred every 200 miles. Which makes your life expectancy, as a passenger in a truly autonomous car, approximately four hours.

    Bottom line: “driverless cars” are not here, and not coming. Like artificial intelligence, virtual reality, genetic engineering and other “next-big-thing” oxymorons, what we’re really talking about here is a high-tech con, designed to separate real morons from their money.

    • I think they can build special highway lanes for cars equipped with autopilots. These can stay on course and react properly as long as the geometry is kept simple. I can also see use for small electric self driven vehicles limited to 35 mph (50 kmph). In this town where I live, that’s the top speed limit in 95% of streets and avenues. The slow speed and the enforced crosswalks make a serious accident almost impossible to have (I haven’t heard of a single deadly accident on city streets in years).

      Such driverless vehicles would come in handy for older folk who mostly go to the market, to shopping centers, visit friends, the doctor, etc. They seldom log more than 30 km in one trip. So the battery range can be say 100 km. We really can’t use electric vehicles to go to a nearby city, the summers are hot and we have mountains to climb which really reduce battery life.

  15. MASTERMIND says:

    Limits to growth are not “predictions” they are scientific models based on computer simulations. They are used in physics, astrophysics, climatology, chemistry, biology, economics, psychology, social science, and engineering. (MIT Smithsonian Meadows 1972)

    • Nick G says:

      That’s exactly right – the Club of Rome LTG models were not predictions, they weren’t forecasts: they were *scenarios* that assumed limits to growth, and simply modeled the dynamics we’d see in the model outputs when the economy hits those limits. Basically, they modeled “overshoot” – what happens when there are lags, delays and positive feedback between between the points of hitting limits and seeing the results in the economy.

      Most of all, they *assumed* limits to growth – they didn’t prove that those limits existed.

      Sadly, Dennis Meadows has forgotten this basic fact, or chooses to not remember it, and is still going around talking as if those scenarios were in fact forecasts, and discussing how close they came to reality. In fact, the overshoot modeled in those scenarios has not been seen in any way – so far the world economy is pretty much simply growing in the same exponential way as before.

      “Can anything be learned from such a highly aggregated model? Can its output be considered meaningful? In terms of exact redictions, the output is not meaningful.…The data we have to work with are certainly not sufficient for such forecasts, even if it were our purpose to make them” (Meadows et al. 1972, p. 94).”

      The Club of Rome models did do us a service, by showing us what overshoot might look like, and showing us the impact of lags and delays. This appears to be relevant to Climate Change, though probably not relevant to Peak Fossil Fuels – the lags, delays and positive feedbacks that might impair mitigating the impact of PFF are much smaller and shorter.

  16. shallow sand says:

    Looked at Diamondback’s Q2 earnings release.

    Diamondback’s gross revenue through the first six months of 2017 is $504 million. This is before any expenses.

    Diamondback plans on spending between $900-$1,000 million in CAPEX in FY 2017. However, 2017 DD&A guidance is just $300 million.

    IMO deferred depletion expense due to exaggerated EUR is the only reason why Diamondback has strong earnings. PXD DD&A/annual CAPEX ratio is around 50%, whereas FANG’s is around 30%.

    • Glenn E Stehle says:

      shallow sand,

      I agree that FANG’s DD&A/annual CAPEX ratio is around 30%. Where I said above that “DD&A for FY2017 is almost 100% of capital spend for FY2017,” that is mistaken. Your “around 30%” figure is the correct figure.

  17. shallow sand says:

    Diamondback has $12.5 billion of PP&E, with $2 billion of DD&A taken against said assets thus far.

    49% of Diamondbacks’s horizontal wells produced under 3,000 BO in 4/17 and 95% of Diamondback’s vertical wells produced under 750 BO in 4/17.

    IMO depletion expense for GAAP purposes is understated.

    • Glenn E Stehle says:

      shallow sand,

      Where do you get the $12.5 billion figure? According to Diamondback’s 2016 annual report, it had $3,390,857,000 net property and equipment on Dec. 31, 2016.

      • Glenn E Stehle says:

        Diamondback took some very large impairments in 2015 and 2016.

      • shallow sand says:

        Look at PP&E for Q2, 2017. Note FANG has elected not to schedule a little over $4 billion, which I assume must be land.

        • Glenn E Stehle says:

          shallow sand,

          I still don’t see where you’re coming up with the $12.5 billion.

          If you add the $4,008,388 excluded to the $6,508,747 included, the total is $10,517,135.

          But even that figure is erroneous, as is explained in detail lower in the Form 10-Q. The correct figure for net property and equipment on June 30, 2017, including the cost of recent acqusitions, is $6,508,747.

          • shallow sand says:

            You are referring to net of DD & A. I am referring to gross, before DD & A, ($12 billion). However, you are correct, I did make an error and double counted the $4 billion not subject to depletion.

            So, PP&E all categories is about $8.5 billion, and accumulated DD&A is about $2 billion, leaving about $6.5 billion of PP&E net of accumulated DD & A. Big error on my part. Sorry about that.

            However, you do see where I indicate the percentage of horizontals below 100 BOPD and verticals below 25 BOPD? Shouldn’t depletion on those low volume wells have been mostly exhausted under the unit of production method, which FANG utilizes (see the note in the screenshot you posted)?

            I agree, I am doing some educated guessing here. I would sure love to see the well by well schedules, and compare them to actual production histories. Given the sudden emergence of the “bubble point death” debate, I wonder if companies will possibly disclose this detail.

            Interesting that PXD, who did acknowledge rapid pressure decreases and increasing GOR, is still being punished by Wall Street (low today of $131.08). Why wouldn’t this issue be relevant across the PB, and likely across all US shale basins? Aren’t companies drilling on very tight spacing, with longer laterals and larger fracs in all basins?

            I also wonder over how many years tangible equipment is being depreciated. I assume 7 years, but that is also an educated guess on my part.

            • Glenn E Stehle says:

              shallow sand,

              On new years eve December 31, 2014, both Pioneer and Diamondback entered 2015 with a considerable number of wolfberry wells and horizontal shale wells. The shale wells were drilled during the experimental phase of the Permian shale play when oil was $100/barrel. And just like the wolfberry wells, these older shale wells were high cost wells with poor well productivity. More recent shale wells are much less expensive and have much higher well productivity.

              The difference between Pioneer and Diamondback, however, is that the latter was very aggressive in 2015 and 2016 in realizing the necessary impairments to clean up its balance sheet. So, using impairments, Diamondback had reduced the book value of its oil and gas properties by 41% going into 2017.

              Pioneer, on the other hand, had reduced the book value of its oil and gas properties using impairments by only 10%.

              One end result of this is that in 2017 Pioneer is looking at about $14/boe in DD&A, whereas Diamondback is looking at about $10/boe in DD&A. That $4/boe difference counts directly against 2017 earnings.

              Pioneer also experienced significant execution problems during 2Q2017, slowing it down and adding significantly to D&C costs.

              Pioneer is also pushing the envelope on lateral length, far more so than Diamondback.

              I suspect these factors have a lot more to do with why Pioneer’s stock price declined than the “bubble point death” debate.

              Furthermore, Pioneer did not “acknowledge rapid pressure decreases.” Pioneer explained both in its slides and its conference call that the increase in GOR will enhance EUR, not diminish it. To date, it has had no effect on oil production whatsoever.

              • Glenn E Stehle says:


                • texas tea says:

                  “increase in GOR will enhance EUR”

                  that explains in a nutshell why the scoop and stack play have some of the best economics of any LTO play. In simple terms the gas trapped in an over pressured tight formation is highly compressed and transports the liquids out of the pore spaces into the well bore and “lightens” the load of the liquids has it is brought to the surface. Higher pressure and more gas = more liquids where the formation contains oil, condensate or NGL’s.

                  • Glenn E Stehle says:

                    texas tea,

                    It’s articles like the one linked below, written by someone who knows nothing about drilling and producing oil wells (his ignorance is obvious to anyone knowlegeable about drilling and production operations), that gives the shale bashers hope that the shale revolution will be a flash in the pan:

                    Rising Gas Output Drags Down Shares Of US Shale Leader Pioneer

                    What we’ve got is the blind leading the blind.

                    I listened to Pioneer’s 2Q2017 conference call, and the situation isn’t anything like the Reuter’s reporter says.

                    In the Midland Basin, it’s customary to set intermediate casing at about 5,000′. In one of the areas that Pioneer is operating in, it experienced an overcharged gas zone somewhere between 5,000′ and the top of the Sprayberry, so it had to mud up to keep this abnormally high-pressured zone under control. Then when Pioneer drilled into the depleted Wolfberry (conventional) zones, the mud was too heavy and they lost circulation.

                    These overcharged gas zones in the Midland Basin are exceedingly rare. For that reason it was totally unexpected and unplanned for. Nevertheless, the gas zone covered an area that affected about 30 wells that Pioneer was drilling.

                    Pioneer solved the problem by running a third string of casing to seal off the abnormally high-pressured zone. This extra string of casing cost them an extra $300,000 per well and many extra days of rig time per well. And, as I’m sure you’re aware, this could also completely screw up their well design, restricting bit and hole size below the extra string of casing and maybe causing a reduction in the size of production casing.

                    As Pioneer CEO Tim Dove called them, these were “train wreck wells.” And I’m sure they were.

                    So to conclude, here’s what the Reuter’s reporter wrote:

                    “The higher pressure, meanwhile, means Pioneer is producing more gas from the Permian than it anticipated.”

                    So here I am, saying to myself, “Lordy, lordy, save us from this ignorance.” The high-pressure zone is above the producing sprayberry and wolfcamp shales, completely sealed off behind an extra string of casing, and has nothing to do with the fact that Pioneer is producing more gas.

                    But something tells me that many oil and gas investors are no more knowledgeable about drilling and production operations than what the Reuters reporter is.

                  • coffeeguyzz says:


                    And that is also the fundamental reason why EOG, being the very first significant player in the Eagle Ford, leased the hundreds of thousands of acres they did in the southwest to northeast narrow band they still operate.
                    It was at the point where high liquids were suspected go be along with high gas pressure with which to drive the oil out of formation, into wellbore, and assist in lift.

                    Their acreage is viewable on any of their presentations.

                  • Mike says:

                    There is a very distinct difference in high initial GOR (as was found by GeoSouthern and Petrohawk in DeWitt County in the Eagle Ford play) and increasing GOR over the life cycle of a well in solution gas driven reservoirs like organic shales (Bakken/Eagle Ford) or shaley carbonates (Permian). Increasing GOR in solution gas (and/or gas expansion) driven mechanisms is natural; as hard as it is for shale oil cheerleaders to accept, its just life. Its the way reservoirs deplete. The party never lasts forever.

                    There are a host of SPE papers etc., that explain this phenomena Better yet, there is a petroleum engineer among you that, in the interest of proper Society of Petroleum Engineers (SPE) ethics, should offer all of you an ‘unbiased, impartial’ explanation for what happens to oil recovery when GOR increases to below bubble point. Finding graphs and spin from investor presentations like those recently spewed by PDX does not count as unbiased. A shale oil company is never going to tell the truth about itself. As to the ethical requirements of an engineer, please see:

                    Truthfully the same thing happening in the Bakken and Eagle Ford may already be happening in some benches of the Permian and our friend Art Berman has already addressed this, here: The problem of increasing GOR in the Eagle Ford is so pronounced that EOG is now taking many of its wells off rod lift and placing them back on gas lift to recover more TF with much higher WOR.

                    “Increase (with a capital ‘I’) in GOR will enhance EUR,” is a wormy statement and not true. High initial GOR, yes, increasing GOR, no. Increasing GOR will ultimately have a negative effect on oil recovery. It did in the vertical Spraberry wells I drilled and every other reservoir I have ever drilled except those driven by water.

                    Increasing GOR does, however, ‘enhance’ BOE EUR because the increasing gas component in the production stream, multiplied times 600%, makes for huge EUR’s. I contend that increasing GOR is predicted in the type curves used for reporting EUR’s. It is part of the ploy.

                    I spent 3 1/2 days in both sub-basins of the Permian last week and spoke with many landmen, frac and drilling engineers, consultants, water haulers, water sellers, SWD owners and saw a thousand wells. It is indeed something to see, particularly in the Delaware Basin. I would liken that boom out there to be as great or greater than anything in oil history. There is so much lying going on, however, about everything, one gets four different answers from four different people on the same location, about the same question. For instance, points for MASSIVE volumes of produced water injected back down hole ran from above the Dean formation to below the Ellenburger, from one SWD facility to another… 1/4 mile apart. In my opinion it is impossible to know the full truth about any of this shale oil stuff, from the gauger all the way up to the CFO.

                  • Glenn E Stehle says:

                    ••••Mike said:

                    “Increasing GOR in solution gas (and/or gas expansion) driven mechanisms is natural; …its just life. Its the way reservoirs deplete.”

                    Well low and behold, that’s the same thing that the Pioneer folks said in their conference call. Did you somehow manage to miss the slides from the conference call I posted below?

                    ••••Mike said:

                    …”as hard as it is for shale oil cheerleaders to accept…The party never lasts forever.”

                    Is it possible for the shale bashers to make an argument without using straw men and alledging absurd absolutes?

                  • Glenn E Stehle says:

                    Here is a graph of the latest figures for oil production from Midland County from the Texas Railroad Commission. And as most people here are probably aware, these are incomplete, and understate production for the more recent months.

                    It’s hard to find the negative in that graph, but that doesn’t keep the shale bashers from trying.

                  • Mike says:

                    I know what I wrote, it is not necessary that you quote me, Mr. Stehle. You should just address my points, if you wish, from an engineers perspective. I am not an engineer. I am just a dumb ‘ol oil and gas producer of 50 years. If you wish to refute my observations and opinions as an operator about the shale oil industry, and as someone who has interest in shale oil wells, you as an engineer may do so, in an unbiased, impartial manner. Some SPE papers, for instance, about how increasing GOR has little to no effect on oil recovery. With some case examples. That would be nice

                    Otherwise, I pay little attention to what you link up to in the way of spin and excuses and absolutely avoid investor presentation BS as much as possible. I like people who have been there, done that, and think for themselves. The strawman you refer to are real people in the field, not sitting in the office making stuff up for the benefit of shareholders, Wall Street and politicians. I mean anybody can sit on their ass all day and look for links on the internet, right?

                    I am not a shale basher as much as I am a truth seeker. Its important to know the truth. Have a good, productive Saturday, sir.

                  • Glenn E Stehle says:

                    And here’s southeastern New Mexico oil production from the New Mexico Oil Conservation Division.

                  • Glenn E Stehle says:


                    I am quite aware that the shale industry rained on your parade.

                    But do you really believe that sitting around, bashing shale and hoping that it goes belly up is the best way out of your dilemma?

                    What you are doing amounts to little more than wishful thinking, and with every passing day your wishful thinking becomes more and more detached from factual reality. Where is the evidence that the shale industry is going belly up? It is like Erewhon. It is nowhere.

                  • Dennis coyne says:

                    Hi Glenn,

                    When somebody pokes holes in your stories you come back with the old aburd absolutes and straw man meme.

                    Can you point out the adsurd absolute and straw man in Mike’s argument.

                    His was a description of what he found talking to people producing oil in the Permian.

                    Along with the fact that increasing GOR over the life of an LTO well can lead to lower output when gas pressure becomes too low to drive the oil.

                    Not a lot of money to be made on these expensive wells when they need artificial lift.
                    They become uneconomic as soon as a pump or two needs replacement on many wells.

                  • Glenn E Stehle says:

                    Dennis coyne said:

                    “When somebody pokes holes in your stories….”

                    When did “somebody” poke holes in my stories? Can you be a little more specific and show me exactly when “somebody” did that?

                    Dennis coyne said:

                    “Not a lot of money to be made on these expensive wells when they need artificial lift.”

                    Not a lot of money to be made on expensive wells when they need artificial lift?

                    Phew! Who can argue with logic like that?

                  • Mike says:

                    Mr. Stehle:

                    I am quite aware that after 30 or more years of being in the oil business, in whatever capacity that is, you apparently have no conventional production revenue to rely on that is very oil and gas price sensitive and that apparently ALL of your eggs are now in the shale oil basket and whether someone else can make money FOR you. I understand why my real life observations from the field are so offensive to your internet world. Please ignore my occasional once a month post here on POB like I do your 50 posts (links) per day.

                    As to raining on my parade, I have probably made more money from shale wells than you have, I just don’t feel the need to brag about it like you do. As I have said to you before I am truly interested in, and concerned for, the role that unconventional shale resources will have in our energy future. That is why I seek the truth about it. I know that is hard for you to understand, and why.

                    There are countless shale oil wells on AF throughout America that are at, or near economic limits and do not make sufficient net revenue to pay for more than one significant well intervention per year. I suspect you know that, as an engineer and all, but instead of asking Dennis, or engaging with him on the matter, its easier to simply ridicule him.

                    I am out again for awhile, you can have your blog back now.

                  • Glenn E Stehle says:


                    Why do believe that anecdotal evidence is superior to engineering and geological studies?

                    Do you honestly believe that your “real life observations from the field” — information you gleaned by talking to “landmen, frac and drilling engineers, consultants, water haulers, water sellers, SWD owners” — is superior to the systematic search and testing done by reservoir engineers, at least when it comes to describing reservoir qualities and predicting future well performance?

                    I also note the ease and deftness with which you switch from an article published by the AAPG describing the various reservoir drive mechanisms (knowledge that is universally accepted by everyone) to the highly polemical and controversial article published by Art Berman on his website. What I find so egregious is that you don’t seem to know the difference between the two. The Berman article is presented as unquestioningly and with the same authority as the AAPG article.

                    So let’s take a closer look at the Berman article. And it hardly requires a reservoir engineer with specialized training to spot its faults. It just takes someone with average intelligence and some common sense.

                    Berman begins with this ominous title,

                    The Beginning of the End For The Bakken Shale Play

                    He then goes on to write:

                    “It’s the beginning of the end for the Bakken Shale play.

                    The decline in Bakken oil production that started in January 2015 is probably not reversible. New well performance has deteriorated, gas-oil ratios have increased and water cuts are rising. Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate. More drilling may increase daily output for awhile but won’t resolve the underlying problem of poorer well performance and declining per-well reserves.”

                    First, let’s take a look at Berman’s claim that “The decline in Bakken oil production that started in January 2015 is probably not reversible.” How does this claim square with reality?

                    Berman’s last month of production data was December, 2015. Below is a graph of what happened to Bakken oil production since then, according to EIA statistics. And as one can see, the decline in Bakken production was reversed.

                  • Glenn E Stehle says:


                    Second, let’s take a look at Berman’s claim that “New well performance has deteriorated.”

                    Below is a graph from And as one can clearly see, new well performance in the Bakken has not deteriorated. If anything, it has improved. IPs are significantly higher, and decline rates are equal or lower during the first few months of production.

                    So Berman’s second claim that “new well performance has deteriorated” is also proved false by empirical data.

                  • Glenn E Stehle says:


                    Lastly, let’s take a look at Berman’s final claim that “Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate.”

                    This is an iteration of what shallow sand calls the “bubble point death” theory, or what you refer to when you speculate on “what happens to oil recovery when GOR increases to below bubble point.”

                    But as the empirical data I have cited above indicates, the “bubble point death” in the Bakken did not occur as the theory predicted. As it turns out, oil and gas, and as a follow-on solution gas drive mechanisms, behave the same way in shale reservoirs as they do in conventional solution gas drive reservoirs.

                    So the peak oilers’ “bubble point death” theory was not validated by the empirical evidence.

                    And since this theory failed the test of validation by observation, it looks like the peak oilers need to go back to the drawing board and come up with a new theory to rationalize their end times theology.

                  • @whut says:

                    “So the peak oilers’ “bubble point death” theory was not validated by the empirical evidence.”

                    Glenn has no idea what he is rambling about. He clearly has zero expertise in physics, otherwise he would realize that the behavior is based on diffusion, and that there are no break points in the flow curves for a diffusional process.

                    He will eventually tire and go away.

                  • Glenn E Stehle says:


                    So what are you arguing, that the peak oilers’ “bubble point death” theory was validated by the empirical evidence?

                  • @whut says:

                    There’s never been any indication that this guy knows anything about physical processes.

                  • Dennis Coyne says:

                    Hi Glenn,

                    So you are going to hang tour hat on the results of fewer than 130 wells, when the evidence from the other 11,270 wells that have been completed in the Bakken since 2008 show that the EUR has increased very little.

                    I have already pointed to a reservoir engineer’s opinion at shaleprofile, can you point us to the peer reviewed papers and geological studies that support the investor presentations?

                    You always point to investor presentations as if they are “the truth”.

                    In fact when we read the small print of any investor presentation, it says, in a nutshell,
                    don’t believe a word. 🙂

                    I have shown how the NDIC’s “typical well”
                    does not match output at all.

                    Likewise the average Permian well is not even close to the well profiles presented in most investor presentations, at least through the first half of 2016.

                    NDIC model using the “typical well profile” from 2015 to 2017 and the actual average well profile through Dec 2014 is shown below,using the actual number of well completions and actual output according to the NDIC.

            • Glenn E Stehle says:

            • Glenn E Stehle says:


    • shallow sand says:

      I made an error and double counted $4 billion in PP&E that FANG has elected to not be subject to depletion. I apologize for that.

      FANG (Diamondback’s) PP&E is $8.5 billion, and net of DD&A is $6.5 billion.

      • shallow sand says:

        I guess, is taking just $134 million of DD&A in the first six months of 2017 on $2.5 billion of “actively scheduled” net PP&E reasonable given the decline rates of FANG’s wells (see in this regard)? We cannot really know this without the DD&A schedules and the EUR’s being utilized by FANG in the unit of production depletion method.

        • shallow sand says:

          I looked and FANG’s most recent presentation and read their CC transcript.

          Seems they are not having the pressure issues that PXD alluded to.

          Looks like they are projecting oil EUR’s of 650-900K BO per well, depending on well location and lateral length.

          • Watcher says:

            what’s freddy say

          • Dennis coyne says:

            Hi shallow sand

            Often the projected EUR of the average well is quite optimistic.

            For example in the Bakken they claim 650 kb oil for typical well when 350 kb is probably about right for 2016 average wells.

            So the low end of that range should be used and 500 kb may be more reasonable.

  18. Watcher says:

    Diamondback Moodys rates it B1 as PDR (Probability of Default Rating)

    As mentioned before the big 3 have different letter nomenclature

    Moodys rates Chevron Aa2 (3rd highest rating)

    In case anyone cares, for Moody’s nomenclature, it goes as Aaa the highest. AaX where X is 1, 2, or 3, as a division within the preceding letter. So Aa2 means it needs to get to Aa1 as one step and then one more step would be up to Aaa, the absolute highest.

    From Moody’s text explaining what the letters mean
    B Obligations rated B are considered speculative and are subject to high credit risk.

    Below Baa is junk bonds. That’s the threshold for investment grade vs speculative aka junk

    This is just Moodys.

    So Diamondback at B1 means it’s on the threshold of Ba, then would need 3 more upgrades to get to Baa, and then one more level would lift it out of junk status.

    Reviews are not weekly, they gotta do the whole universe, but pretty much everyone goes in their spreadsheets about quarterly, so here are some ratings from moodys

    CVX as I said is Aa2 (and that was a recent downgrade)

    BP A1 (bumped up June 2017, first upgrade for BP in 19 yrs, mostly cuz there is now litigation clarity)

    XOM Aaa max

    Apache Baa1 negative outlook (year old)
    Conoco Baa2 negative outlook
    Devon Ba2 negative outlook
    EOG Baa1 stable outlook
    Marathon Ba1 negative outlook

    outlooks mean credit worthiness trend suggests the next review will hold, upgrade or downgrade depending on outlook

    • Watcher says:

      My bad.

      Diamondback at B1 is on the threshold of Bb, not Ba. Long way to go to get above Baa.

  19. Glenn E Stehle says:

    Oil Tumbles as Rising Shale Output Risks Mounting Supplies

    Full Steam Ahead

    American shale drillers EOG Resources, Devon Energy Corp., Newfield Exploration Co. and Diamondback Energy Inc. outlined goals that would help raise U.S. production to a record 10 million barrels a day next year. In a blow to investors concerned about the oil glut, the drillers also said they’ve gotten more efficient.

    • Glenn E Stehle says:

      Here’s a bullish case for the price of oil:

      Is The EIA Exaggerating U.S. Oil Production?

      Moreover, the U.S. could also disappoint. As discussed in previous articles, the shale drilling boom is starting to slow. A bottleneck of services is held back the completion of some wells, while many shale companies have actually started to throttle back on their spending and drilling activity….

      The cuts, coming in response to the recent dip of oil prices into the mid-$40s, will likely translate into much lower production next year. As a result, the projection from the EIA that shale will hit 10 million barrels per day (mb/d) in 2018, or even the more recent downward revision to just 9.9 mb/d, could be hard to reach.

      However, there is one other important uncertainty that could point to higher oil prices in the near-term. Not only will future production come in lower than expected, but what if current production is actually lower than we think? What if we are overestimating the shale boom?

      • Guym says:

        Not usually my favorite writer, but this time he nailed it. Also, it does not consider GOM decline vs increase.

        • SouthLaGeo says:

          The latest EIA 2017 estimate for the GOM averages about 1.7 mmbopd – which is, I think, a pretty fair estimate (of course we are half way through the year!)

          But regarding 2018 production, the EIA is anticipating an average of around 1.9 mmbopd, with production at the end of 2018 approaching 2 mmbopd, I see GOM production staying pretty flat, or even declining a bit, between 2017 and 2018, with new production being offset by decline from existing fields. That alone is a 200 kbopd difference.

  20. Watcher says:

    I’d call this conspiratorial curious re Dallas Fed stuff but clueless heads up:

    Devon debt

    This is a Ba2 company paying only 4.83% for 30 year paper. That’s a junk bond company paying 2 lousy % above the 30 year US Treasury instrument? WTF

    XOM 30 yr paper 3.7%

    Somebody is subsiding this rate. This is bizarre.

  21. MASTERMIND says:

    Saudi Aramco CEO believes oil shortage coming despite U.S. shale boom

    International Energy Agency Chief warns of oil shortages by 2020 as discoveries fall to record lows

    HSBC Global Bank warns of Oil shortages by 2020

    UBS Global Bank warns of Oil Shortage ahead

    The Oil Age may come to an end for a shortage of oil. -Saudi Oil Minister Sheikh Yamani

  22. Glenn E Stehle says:

    The doomsdayers will like this one, since it talks about the risks for the oil industry if the developed nations slip into a recession.

    Kemp: Macroeconomic Risks For The Oil Industry

  23. Glenn E Stehle says:

    And who knows what in the heck this guy is talking about when he asserts, “The Permian has seen the steepest declines among the four largest U.S. shale plays.”

    The Shale Boom Slows Down While Investor Enthusiasm for Permian Fades

    Shares of major shale producers including Pioneer Natural Resources Co. and EOG Resources Inc. tumbled this week as investors began to lose confidence in the prolific Permian basin. As the productivity of older wells in shale fields is rapidly declining, explorers added rigs at a record pace this year to keep increasing output. The Permian has seen the steepest declines among the four largest U.S. shale plays.

    • coffeeguyzz says:

      Core Labs conference call was last week. Just read it.
      The opening statement from the COO, Monty Davis, went a long way in explaining the noticeable upsurge in well productivity across all basins this past year. Essentially far more effective fracturing.

      Of particular note – and, mebbe Dennis and the boys will need to redo all their predictive production charts – is the relatively advanced state of EOR work employing huff n puff.
      These Core guys feel, at this moment, successive cycles could bump recovery up 50% for a 1 to 2 million dollar cost.

      Interesting information.

      • Glenn E Stehle says:


        I listened to the conference call, and it is indeed “interesting information.” The Core Labs folks provided a road map of where technological development in the shale industry might be going.

        The “huff n puff” EOR techniques, which they estimated can enhance well recoveries by about 50% over and above primary recoveries, certainly received the most attention in the question and answer segment.

        Nevertheless, just as interesting a topic was the enormous amount of work still left to be done to maximize primary recoveries.

        “Unstimulated reservoir volumes” are still very large, they said, and only the “most technologically sophisticated companies like Pioneer” are currently achieving the stage lengths of 240′ or less that are necessary to ameliorate this problem. Tighter stage density, however, will eventually catch on with other operators, they believe, so they see a trend in this direction in the future.

        The Core Labs folks also foresee the use of far more complex frac designs in the future. These will entail the use micropropants to open up “secondary and tertiary fracture patterns.” This advancement, like tighter stage density, will further reduce the large amount of unstimulated reservoir volume characteristic of present day completions.

        In its latest investor presentation, Pioneer gave us a glimpse of the sort of well performance that can be achieved using more technologically advanced completion techniques, what Pioneer calls “Version 3.0+ completions.” So far, Pioneer has only completed nine wells using Version 3.0+ completions, but the results are impressive. In the first four months of production, these wells have produced an average of about 125,000 of boe each, with no decline in production experienced during this time.

        • Watcher says:

          125K over 4 months is an avg of 1000 bpd, but boe, not oil. Not impressive.
          Ghawar wells flow 10,000 bpd, of oil, for 60 yrs.

          Always suspicious when well profiles are not provided in 1) oil, gas doesn’t plant any food or carry it to shelves


          2) not cumulative, avg well profile of oil in bpd. Avg well, not the best.

    • Heinrich Leopold says:


      The above Bloomberg article reveals the structural weakness (soaring depletion rates up to 91% – and still rising) of the shale concept. This weakness shows now up in financial numbers, which will get much worse over the next few months. RRC had capex of USD 285 mill and cash flow of just USD 185 mill during the last quarter, leading to a negative free cash flow of USD – 100 mill per quarter. As this would fit a start up company in the early stage of a development, it is a catastrophic number for a mature company like RRC. Moreover, negative free cash flow is very likely to worsen over the next quarters as depletion rates could go even higher. It is very important for investors to monitor the development, which could turn even giants like PXD and RRC into penny companies.

      • John Keller says:

        Coffee should read up on RRC. The Marcellus is probably coming close to a peak. RRC is showing that the sweet spots are being drilled out. New wells are coming up short. Sure there will be a few cherry picked ones that look good but on the whole things will be heading downhill for the Marcellus. Ted Patzek and some guys at UT looked at the Marcellus on a county by county basis on a very granular level. They see the Marcellus peaking by 2020.

        • coffeeguyzz says:

          Mr. Keller.

          I actually do read up on Range, Cabot, Antero, Rice and many of the other operators in the Appalachian Basin.

          Although no longer as extensively as I once did dating back to 2008, I also keep an eye on the happenings in the Bakken, and – to a lesser degree – the other unconventional areas including the Niobrara, EF, Permian, Powder River, TMS, and more, including the Canadian plays.

          I have zero motivation in trying to persuade people in these matters, but, in constantly reading questionable, even significantly erroneous statements, I occasionally try to point out facts/data that may clarify things, as it were.

          Your statements regarding the Marcellus would indicate an unawareness of the Leach Xpress, Rover, and Mariner East 2 pipelines which are currently under construction, their capacities, contractual commitments, and other particulars.
          Likewise, the Atlantic Sunrise, Penn East, Mountain Valley, Nexus, Northern Access, Constitution, and many other takeaway pipelines from the AB that might validate a 35 Bcfd projection in the future.

          Sweet spots drilled up?
          Easy to validate that Range has slightly over 200 pads in Washington county. 124 have fewer than 6 wells, another 59 have fewer than 10.
          These pads are currently designed to have 20 wells each, but EQT is already placing 30 wells on their pads.
          Of course, when the Upper Devonian formations including the Rhinestreet, Middlesex, Genesee, and Burket are included, the ultimate well count is presently unknowable.
          This, naturally, does not include the deeper Utica.

          Speaking of which – the Utica – I briefly engaged Mr. Patzek via his blog on why he dismissed the Utica’s potential.
          His brief response, if I recall correctly, was that it is ‘lousy rock’.

          Mr. Keller, it may stem from my skeptical, fiercely anti authority nature, but I take nothing at face value … whether it originates from a blowhard CEO of a ‘shale’ company, a supposedly informed academic, reporters and analysts right across the board.
          I take their views as starting points and do my own research.

          Final note on the AB … should you check out Enno’s well profiles from 2016 on, especially Bradford, Susquehannah, Greene and Washington counties, you may get a glimpse of what is to come.
          Then check out Tioga and Potter counties.
          Although many listed are Utica, rather than Marcellus wells, you may get a hint of the huge scale of this area as well as what is to come.

    • Watcher says:

      Rig count?

      • clueless says:

        Every Friday, just after noon, you can google Baker Hughes Rig Count (go to the B-H web site), and then click on North American Rig count for the date of that Friday.

        • Watcher says:

          No, the question was what was the guy talking about with the Permian having the fastest decline. I offered up rig count. Maybe that had the fastest decline in the perm.

  24. Watcher says:

    HAL Baa1 stable outlook

  25. Heinrich Leopold says:

    Another Bloomberg article, which should give some food for thoughts:

    Investors who do not recognize the urgency of this situation will pay a high price. Andy Hall did already.

    • Boomer II says:

      It’s coming down to where you put your money. There are better investments right now than gas and oil companies. And even some gas and oil companies are deciding that paying dividends makes more sense than looking for more oil.

      Gas and oil are mature industries and perhaps even declining industries so money is starting to go elsewhere. Depletion is a problem and even under the best of circumstances competition is likely to keep margins low.

    • John Keller says:


      Things like this usually signal a bottom.

      • Boomer II says:

        But if supply keeps the price down, then how do these companies make money? Why should investors and lenders support these industries?

      • Heinrich Leopold says:


        I agree that Andy Hall bailing out of oil is a sign of a bottom for the oil and gas price. I am very optimistic about oil and especially gas. However, for the shale industry this is another pair of shoes. What concerns me the most is the ratio of shale companies stock price versus underlying oil price. These ratios are imploding and show that the industry cannot make a positive contribution at current prices. Unless these ratios are positive again, I would stay out of any shale investment.

    • Glenn E Stehle says:

      Andy Hall bet against U.S. shale and lost.

      After all, if OPEC had won its price war on U.S. shale, Hall’s bullish bets on the price of oil could have paid off.

      But OPEC didn’t win its price war on U.S. shale. It lost. U.S. shale proved to be much more resilient that OPEC predicted, and when oil prices began to recover, production came roaring back.

      • Boomer II says:

        But the point is that oil doesn’t look like a good investment.

      • Heinrich Leopold says:


        It is too early to say who has lost or won. In my view there are many losers here including shale investors who have lost fortunes. A clear winner is the US dollar who has stabilized over the last three years through a lower US trade deficit. However, this may not last as it is increasingly unattractive to make shale investments and many investors got burned badly. It will take a lot of time and much higher oil and gas prices until this industry will regain confidence again.

        The important point is that the shale industry has to reduce capacity in order to bring oil prices up again. Are they willing to do this or are investors ready to suffer more?

  26. Watcher says:

    This is Pioneer’s debt. Morningstar rates them BBB-. Moodys Baa2 as of March this year.’s balance sheet for them lists 2.7 Billion LT debt. Another half billion short term. (these numbers are 7 months old)

    But back to the morningstar link above. First debt item 600 million bux due 2022. It was issued 2015 so it is long term. Rate . . . for a friggin Baa2 company . . . 2.75% traded. The US Treasury 5 yr note is at 1.8%.

    That’s less than 1% over Treasury, for a Baa2 company.

    But when you QE money into existence whimsically, it clearly can’t mean anything physically so why not lend to near junk companies at less than 1% over the, by definition, riskless rate of return. Just don’t pretend it is capitalism or technology.

  27. shallow sand says:

    I have looked at several Q2 2017 10Q.

    It is interesting that expenses such as LOE, taxes, and G & A are not greatly different among the US “oil” shale players, no matter where they operate. Yes, there are differences, but not substantial.

    Where I find the widest differences are in DD&A. Sorry to keep harping on this, but DD&A appears to be the determining factor as to US shale corporate earnings. This makes sense, as the industry is very capital intensive. However, it is also something that makes comparing earnings tough, because unlike LOE, taxes, G & A, gathering and transportation expenses, the depletion portion of DD&A is the result of estimates of well productivity over the life of the well. This must be determined on a well by well basis, I believe, using the units of production method.

    From my reading of the website,, the first step in determining unit depletion rate under the units of production method is to calculate the depletion base.

    The depletion base would include land acquisition costs, exploration costs, development costs and restoration costs.

    To determine the unit depletion rate, the following formula is used:

    (Depletion base-salvage value)/Total units to be recovered.

    A thought that has popped into my head is that gas production percentage to total BOE appears to be increasing in shale oil wells over time. Assuming gas BOE’s using a 6:1 ratio continue to be worth much less, as time passes, depletion expense per unit will take a bigger chunk out of revenue.

    Also, the thought that has already popped into my head is whether the estimates for total units to be recovered are too high. It is not uncommon for estimated total units to be recovered to be advertised as in excess of one million BOE per well.

    One other problem with these estimates is that the estimates disclosed in company presentations are gross, not net, of royalty. That is not necessarily a problem for the units of production calculation, but I mention it here because, just as BOE is commonly interchanged with BO, it is almost never noted that the WI owners of a well may receive anywhere from 50-100% of the gross oil sold, with a more common range being 75%-87.5%.

    So, lets assume we have a shale well with a depletion base of $7.05 million and salvage is estimated at $.05 million. Further, EUR to the WI owner is estimated at 700,000 BOE.

    ($7,050,000-$50,000)/700,000 = $10 per unit depletion rate.

    In year one, the well produces 200,000 BOE. The depletion expense for the well would be $2,000,000 for year one.

    However, if the EUR is too high by a factor of 2, our calculation is:

    ($7,050,000-$50,000)/350,000 = $20 per unit depletion rate.

    In year one, the depletion expense would be $4,000,000.

    Furthermore, as the units are in BOE, more gas over time, assuming much lower $ BOE gas on a 6:1 ratio becomes a problem. Under current prices, if the well turns to 100% gas, at $20 per unit, depletion expense per unit would be equal or greater than sales proceeds alone.

    There is no doubt that Permian focused companies have lower per unit depletion rates than Bakken focused, for example. The $64,000 question is, how much of that is due to better economics, and how much, if any, is due to more aggressive EUR’s?

    I focus greatly on earnings, because, over the long haul, earnings do matter. However, earnings are a tough gauge in upstream shale E & P when so much of earnings depends on well productivity estimates.

    I encourage those interested to compare DD&A per BOE of the many shale focused companies.

    Just as I would like to see shale oil payout statements well by well, so would I like to see how these companies are computing per unit depletion rates. Both are critical to me, because I think both would give the clearest guides to the economic sustainability of the dominant segment of the US upstream oil industry.

    • shallow sand says:

      Comparing two similarly sized companies in different shale plays shows how much different costs, and especially DD&A per BOE can be:

      Diamondback 1st half, 2017:

      Realized price per BOE: $39.84

      Per BOE expenses:
      LOE $4.47
      Taxes: $2.52
      G & A $2.04
      DD&A $10.69

      Oasis 1st half, 2017:

      Realized price: $40.12 per BOE

      Expenses per BOE:
      LOE $7.82
      Taxes $3.47
      Gathering $1.97
      G &A $4.18
      DD&A $22.25

      While FANG clearly has cost advantages in every category over OAS, DD&A per BOE is the biggie.

      Edit: I take back the idea that other cost differences besides DD & A are not substantial. I was primarily thinking of LOE, but when all non-DD&A are totaled in this example, there is a big difference.

      • coffeeguyzz says:


        All your above computations are partly why I shy away from the financial aspects in this stuff. As extensive a parsing as you have done, there are probably a million other components that come into play when the number crunchers do their thing.

        There has always lurked in the background a heretofore non-existent – yet influential – piece to these affairs, namely, how to handle profits?
        As a businessman, you recognize the tax benefits to shielding “excess’ revenue from government acquisition.
        Up till now, almost all these guys have been losing their ass and profit protection has been a moot topic.

        Cabot, who looks to be operating in the black for the foreseeable future, may indicate how ‘vulnerable’ a company chooses to appear by way of financial machinations.

        • shallow sand says:

          Coffee: Keep in mind I am discussing GAAP and not tax.

          The tax accounting for upstream is a whole different thing altogether.

          I’m just trying to figure out how Diamondback earns $3.18 per share in six months, while ExxonMobil, Chevron, OXY, Marathon, etc. all lost $$ or made very little on US upstream in Q1 & Q2.

          I have had it drilled into my head by the cornucopians that we need to COMPETE, but figuring out if our investment can seems to be unachievable. Of course, that also assumes the oil price has anything to do with these shale guys anyway. It probably has more to do with the strength of the US dollar, ETF’s, QE or lack thereof, and a host of other financial deals that have zero to do with producing oil.

          • coffeeguyzz says:

            So many factors, so much change at a dizzying pace.

            You made reference awhile back that shale development was starting to resemble offshore with its large capital requirements.
            To buttress that view, Rice – in their highly truncated recent conference call (no Q&A) – just described their recent 4 rig, 19 well simultaneous operation a la Encana in the Permian.
            The numbers were staggering in that all 19 wells are flowing 14 MMcfd at restricted rates and will be until late 2017.
            The amount of capital deployed for delayed return is not for the faint of heart.
            Rice indicated that this approach would be how future Marcellus development would play out.

    • clueless says:

      SS – I really have not analyzed DD&A in any detail because I think that it is virtually impossible in some cases.

      Remember, if a company takes a write-down because of valuation due to low market prices, then future DD&A is forever distorted [lower than normal]. Further, I do not know how to determine which properties were written down. Some companies have taken writedowns in 2008, 2015 and 2016. And, as you have pointed out, there are other unknowns.

      More interesting to me is your analysis below. Why is every category of expense significantly lower for Diamondback? Are they virtually all gas with production coming from a few high volume wells?

      • shallow sand says:

        Clueless. Ironically, Diamonback presently operates around 725 vertical Spraberry wells and around 320 horizontal wells, mostly in the Midland Basin, but some in the Delaware Basin, where they bought a lot of acreage in the last year. 95% of the vertical wells produce under 25 BOPD.

        Diamondback produces more oil BOE’s than gas BOE’s, but OAS does produce a higher percentage of oil than FANG.

        However, OAS has seen the percentage of oil fall, and I suspect that will continue, given Bakken oil production is flat to slightly down field wide, while gas production sets new highs each month.

    • Glenn E Stehle says:

      shallow sand,

      A lot of analysts take GAAP earnings with a grain of salt, and your comment gives some insight as to why.

      Some analysts invent their own pro-forma earnings. Others look to cash flow from operations, free cash flow, EBITDA, and efficiency of newly invested capital as being better indicators of a company’s past performance.

      One thing’s for sure, and that is that the evaluation of company performance is far from objective. In fact, it might be correct to say it’s more subjective than objective.

      That’s bad news for those seeking to find sure truth in SEC forms.

      • shallow sand says:


        I agree and believe the best way to gauge the economics is by well payout. Unfortunately, that metric will not be readily disclosed.

        • Glenn E Stehle says:

          shallow sand,

          By looking at the information that is made public, we can’t even get a good handle on how much it costs to drill and complete a well.

          We’ve got what the companies say they spend to D&C wells in their investor presentations, and then we’ve got their actual total capital outlays divided by the number of new wells they put on production. The two are not the same.

          Pioneer, for instance, says it can drill a 10,000′ lateral Jo Mill well for $7 million and a 10,000′ lateral Wolfcamp B well for $8.8 million.

          But if we look at Pioneer’s total capital outlay for 2017 of $2.7 billion and divide that by the 230 new wells they plan to put on production, that works out to an average of $11.74 million each.

          Likewise, Diamondback says it can drill a 7,500′ lateral well in the Midland Basin for $5.0 to 5.5 million, and in the Delware Basin for $6.0 to 8.0 million.

          But if we look at Diamondback’s total capital outlay for 2017 of $875 million (midde range of estimate) and divide that by the 125 new wells they plan to put on production (middle range of estimate), that works out to an average of $7 million each.

          So the cost to D&C a well in the Midland Basin and construct all the ancillary infrastructure necessary to produce it is somewhere between $5 million and $11.74 million. Some of that difference can be explained by the difference in lateral length and the completion design. But $11.74 million compared to $5 million? That’s a big difference.

          • Mike says:

            So why then, Mr. Stehle, do my “anecdotal” observations from the field, where I have actually set numerous shale wells, seen cumulative well costs, water source costs, frac costs, talk to buddies who every day are washing tons of frac sand out of PB wells with CT, fishing and replacing ESP’s at $250K a pop, squeezing failed casing, etc., so deeply offend you? You seem to believe I make that stuff up because I can’t back it up with a stupid “link.”

            I feed my family and the families of my employees by understanding well economics. When I have time I look at K’s and Q’s and SEC filings and none of it adds up to me. It never did, not since the beginning, least of which being over exaggerated EUR’s that reservoir engineers are TOLD to create. By getting steel toe boots on the ground and hearing the real deal from real people it helps clarify a cloudy picture for me… one you now seem to be admitting is convoluted and fraught with lies, even to the Security Exchange Commission.

            The investor presentation links are meaningless; the shortest distance to the truth is being open minded enough to gather ALL the data, then think for oneself.

            • shallow sand says:

              Mike. I think 10 years from now, the industry and Wall Street will admit a big mistake was made when the shale companies (with Wall Street pressure) put out that they could be profitable at $60 WTI, then $50, then $40 and then $30. Capitulation didn’t occur until below $30, and these below $50 prices have destroyed a lot.

              It will not be admitted for several years, but when the smoke clears, I suspect a lot of 20/20 hindsight will agree. That doesn’t do you or me any good, of course.

              The thing that burns me the most is the early 2017 Permian ramp up, which was greatly hyped. Just when it looked like we might stay above $50, BAM. We could see this coming, but what can you do when puts now cost $4-5 per barrel for a small producer?

              This has been a tough 3 years, maybe going to last longer yet?

              • Boomer II says:

                There is legitimate skepticism here, by both long-time oil and gas people and those just trying to decipher the available info, that cost of production goes down at the same rate as the price of oil.

                A number of long-time oil people say that there haven’t been any significantly new technologies to transform the industry. LTO got its boost as cheaper sources were harder to come by and oil was priced high enough justify the LTO expenses.

                Wall Street no longer seems to be buying the LTO miracle and doesn’t want to fund it. If production costs really are coming down, then maybe these companies can self fund from now on.

                • Glenn E Stehle says:

                  Boomer II said:

                  If production costs really are coming down, then maybe these companies can self fund from now on.

                  If one listens to the Core Labs conference call, they also believe the oil companies will have to self fund in the future. Wall Steet has reached its limits, and the shale industry will have to begin funding itself out of cash flow from now on.

                  That’s the reason the Core Labs folks predict that if oil prices remain as they are, US rig count will drop by 150 or 200 rigs next year.

              • Mike says:

                Its frustrating, Shallow, but all anyone has on their little pea brains these days is shale this and shale that; it is as though 4.3 M BOPD of conventional Alaskan, GOM and stripper production does not even exist in America. Some, amazingly, like the stuff that declines at the rate of 78% the first two and half years of production life (and earns, maybe, a whopping 135% ROI over 20 years) over the stuff that declines 4.5% annually, but secretly I think that’s got a lot to do with RI and ORRI and nothing to do with having to write checks.

                I don’t know about oil prices; I am predicting a range of $40-50 for numerous years. And I am plenty good with that if I have to be. I don’t think any shale oil play in America is close to self-funding itself at <$50 (and paying down debt!), except maybe some very isolated parts of the Bone Springs play in the Delaware, where they can shave off an entire sand dune near Wink, wash it, truck it to Orla, and shove it back down some stinking well somewhere. There is an awful lot of debt out there that takes an awful lot of production revenue to keep happy. What happens the next 3 1/2 years will all depend on who replaces Yellen and whether interest rates stay low, as per the Trump OPM doctrine. If interest rates stay low Wall Street and the shale biz stay overdosed on stupid pills and prices will be closer to 40, than 50.

                You are doing all the good here on POB, pardnor; people believe your chili. They should. Realized production data and a little K/Q work is the path to the truth.

            • Glenn E Stehle says:


              An owner-operator would certainly know what it cost to drill and complete a well he or she drilled.

              However, a drilling or completion consultant working on a day rate would not. The only thing he would see are snippets of information. It’s the guys back in the office — the accountants, the engineers and the managers — that see the final tallys.

              As an indpendent owner-operator, how many horizontal shale wells have your drilled and completed in the past couple of years?

              On top of that is another factor that complicates things: every well is different. There are seven different zones in the Midland Basin that are considered core in one area or another, and several more that are considered prospective. Lateral lengths are constantly changing, as are stage densities, quantity of frac fluid and sand. And more recently the complexity of the frac job (whether each stage begins with micro proppants and is finished off with 50-70 mesh sand) can also vary. Larger and more complex frac jobs greatly add to the D&C costs.

              In order to do a proper economic analysis, the cost of wells completed in zone A of lateral length B using completion procedure C must be compared to production profiles of wells completed in zone A of lateral length B using completion procedure C. No other combination is valid.

              Of course I don’t have access to this detail of information, any more than you do.

              What I do have access to is the Texas Railroad Commission online Research Queries data base. What one can see from this are numerous examples of, for instance, three offset wells, one drilled in 2012, one drilled in 2015, and one drilled in 2017, and how well productivity has increased so dramatically through the years.

              The peak oilers, however, are slow to acknowledge these dramatic increases in well productivity, regardless of the fact they are staring them right in the face.

              • Reno Hightower says:

                I bet Mike has seen the AFE’s and JIB’s for a few Eagleford wells.

                • Glenn E Stehle says:

                  Well if he has, then maybe he can provide the IRS schedules that, along with production histories, will be sufficient information to perform a full economic analysis of the wells.

                • Mike says:

                  Mr. Stehle, you should try to get over the fact that you are an engineer, I am not, and not assume I am stupid about any part of the oil business, even the shale business. Engineers have always looked down their arrogant noses and little guys like me; I think its because they don’t know how to use chain tongs or don’t know which way to knock a hammer union standing on their head in a cellar and are embarrassed. I can muddle thru most of that they know, however, with a red Halliburton book and a choke manifold. And my yellow lab can make better EUR predictions than what I’ve seen the past 8 years in the shale biz.

                  On the other hand, I like engineers. Some of the best production acquisitions I have ever made were in stuff engineers screwed up, or overlooked, or could not fix, and the biggest, funnest, bestest blowouts I was ever on were ALL big engineer screws ups. People spending other peoples money do really dumb things.

                  Me too sometimes, with my own money, but never so much as to drill and complete a shale oil well myself.

                  Here’s a good link for you to spend all day refuting tomorrow: Indeed these 12-15M # fracs are taking every bit of 650K of fresh, potable water now days… in arid, West Texas, no less. How much longer can THAT go on in the desert, do you think, Mr. Stehle?

                  • @whut says:

                    “Mr. Stehle, you should try to get over the fact that you are an engineer,”

                    He’s definitely not an engineer or a scientist.

                  • Glenn E Stehle says:

                    Mike said:

                    “Mr. Stehle, you should try to get over the fact that you are an engineer, I am not….”

                    As I stated earlier, one need not be an engineer to discern the faults in the peakists’ most recent pet theory du jour, the “bubble point death” theory. Here’s what I said back up the thread:

                    “So let’s take a closer look at the Berman article. And it hardly requires a reservoir engineer with specialized training to spot its faults. It just takes someone with average intelligence and some common sense.”

                    All one needs to know is that the theory predicted that Bakken field-wide production would fall off a cliff. The theory furthermore predicted that this would happen even if a great many new wells were drilled, since the productivity of new wells would fall off a cliff too. This of course did not happen. Bakken field-wide production did not fall off a cliff, and new well productivity is greater than ever.

                    Certainly one can drill down into the nuts and bolts of the theory to see why it failed to predict, and this might require more specialized engineering knowledge. But that is not necessary. Looking at the production curves for field-wide and for newly-drilled wells, anyone can see that the theory was invalidadted by the empirical evidence. No engineering degree required.

                  • @whut says:

                    Again this dude is definitely not an engineer or a scientist. There are no “cliffs” in statistical physics models. Diffusional flow has no sharp corners with respect to time.

                    I wouldn’t listen to anything that this guy is saying.

                  • Glenn E Stehle says:

                    @whut said:

                    “There are no “cliffs” in statistical physics models. Diffusional flow has no sharp corners with respect to time.”

                    Why don’t you try telling that to Art Berman?

                    It was Berman, after all, who made that claim, not me.

                    ART BERMAN: The Beginning of the End For The Bakken Shale Play

                    As I’ve asked many times before, is it possible for you guys to make an argument without standing up straw men or alleging your opponents favor absurd absolutes?

                  • @whut says:

                    The issue is about you and your inability to understand physical processes, and not about Art Berman.

                  • Glenn E Stehle says:


                    Of course you want to make the issue about me, and not the physical processes. That’s all part of your rhetorical strategy: attack the messenger and not the message. And I must hand it to you, you are quite good at playing that game.

                    The arguement that matters, however is still and always will be about the physical processes, and not about me.

                  • @whut says:

                    More psychological projection on your part.

                    You are the one that cites David Hume and Leo Tolstoy in a technical/scientific discussion.

                  • @whut says:

                    To this guy, all scientific answers can be found in Tolstoy’s War and Peace.


                  • Glenn E Stehle says:


                    And the physics?

                    Instead of your orgy of ad hominem, standing up straw men and alleging I favor absurd absolutes, why don’t you use that great command of phsics of yours to explain to us why Berman’s bubble point death theory is correct, and that we are witnessing “the beginning of the end for the Bakken Shale play”?

                  • @whut says:

                    Why don’t you start by citing exactly where Berman coined the phrase “bubble point death theory”? Poseur.

                • Mike says:

                  Howdy, Reno. Its hot in Texas, ain’t it? I wish you would pipe in more often here, give people the benefit of your decades of oily experience.

                  I have seen some AFE’s and JIB’s, sure. Its not hard to figure out what things cost when you’ve been an operator forever and a day. But of course I don’t need to explain how, or why, nor would I share IRS data, confidential or not, on a public blog. That’s kind of a stupid idea.

                  • Glenn E Stehle says:

                    Mike said:

                    “I have seen some AFE’s and JIB’s, sure.”

                    But the question is whether you’ve seen AFEs and JIBs for shale wells.

                    The answer appears to be that you have not, at least if what you said above is true. Here’s what you said:

                    “People spending other peoples money do really dumb things.

                    Me too sometimes, with my own money, but never so much as to drill and complete a shale oil well myself.”

                  • Mike says:

                    Yes, of course I have…for shale oil wells. That was the implication made by Mr. Hightower and I answered it. I have interest in shale oil wells. It does not take a petroleum engineer to know what shale wells cost and why those costs are so grossly understated. You are insulting, again.

                    Its funny, though not really, that your arguments regarding ‘strawmen’ and ‘absurd absolutes’ are exactly the basis for your arguments and defense of poor shale economics. Your absolutes simply come from the shale oil companies themselves, which most people would automatically be suspect of, now, it seems, even yourself.

                    I submit another link herewith regarding flaring, which there was still way to much of going on in the Permian given the fact that these shale companies tout their drillable locations for the next two decades: Imagine wasting this valuable natural resource, at $3.50 per MMBTU, to get to oil that is worth $38 bucks a barrel or less…all using OPM? Its damn poor planning and actually quite embarrassing.

                    When I waste time looking for links it seems there are two bad ones for every good one (for the shale biz).

            • John Keller says:


              Lots of talk now about increasing decline rates out of shale. A year ago you were talking about the long laterals leading to increased IP but lower production on the back end. Do you think these 10,000-15,000 horizontal wells are dropping off faster than claimed?


              • Mike says:

                Hi, John; I hope you are well. Its hard to sort thru individual well performance on multi well leases in Texas but I am helping Enno Peters sort that out with individual, annual W-15 well tests and he is designing a really cool tool for that on his website. They are cramming more sand into PB wells (that of course cost more money) and the IP180’s are pretty impressive, in some places. I just don’t know that there has been a long enough time frame to really determine yet how, and to what extent, the UR will be on those wells and whether all that hubbub will actually be economic.

                But hey, I must be the only sumbitch in the world who questions the shale biz, so say some… but no, wait a minute, there are others amongst us,, gasp !!

          • shallow sand says:

            Glenn. I agree.

            I think when the oil price crashed, the companies felt a lot of pressure to make it seem that they could still be profitable at 1/2 or less the oil price (plus natural gas prices that also were less than half). Therefore, no more clarity, instead a lot of fuzzy numbers.

            To me, the GOR issue could turn out to be a big deal. I fully assumed the US would push through 10 million BOPD, maybe even hit 11 million BOPD.

            It now appears that may be tougher to achieve, even with a large number of new wells.

            The Bakken has added a considerable number of wells since 12/14, yet is still a good bit below that month’s production. EFS is in s similar boat, lots of wells added since its high production month.

            The Permian is the remaining big oil producer. Many wells being added. If oil production growth stalls, US will likely stall as well.

            GOM and Alaska aren’t going to be adding much, and WY, CO and OK don’t look to be large enough.

            Another interesting thing, don’t remember which CC, maybe FANG’s, but don’t hold me to it. I recall a statement that company would not be adding more rigs. One reason was that all of the quality rigs are now in the field.

            I know at one time the oil rig count was double, but a lot of those were smaller rigs drilling conventional wells. So have to wonder how many more high HP oil rigs are even left. That could be wrong, I haven’t studied it.

            Still hoping to get into the $50s WTI. Makes a big difference for us, as does $49 WTI v $43 WTI.

            • Glenn E Stehle says:

              shallow sand said:

              To me, the GOR issue could turn out to be a big deal.

              What distance from the wellbore do you believe a well can drain in these very low permiability shales?

              Why would you believe that a solution gas drive mechanism would work any differently in a shale reservoir than it does in a conventional reservoir?

              • shallow sand says:

                Glenn. I don’t.think it is any different.

                I am definitely a lay person here, so correct me if I am wrong. However, it appears as more and more wells are drilled in a tight reservoir, be it by conventional or horizontal wells, the gas to oil ratio in both the existing and new wells tends to increase.

                For example, a year or so ago when the SCOOP and STACK plays in OK were being touted, I noticed that oil production in most of those wells would fall dramatically, but gas production would stay relatively strong. My beef was that operators of those wells would tout a 30 day IP of say, 2,000 BOEPD, 55% oil. However, one year later, 90+% of the BOE would be gas. You will note that, despite very strong activity in STACK, OK state production has stayed fairly flat.

                Now, what if we have the same in all the other shale plays, maybe not to that extent, but enough to where the bean counters at EIA, Wall Street, etc have overshot estimated future production?

                I assume those bean counters have figured that in. They should hopefully know more about that than me.

                In addition, it makes sense to me that if the cheapest way to drill wells is to drill 60 off one pad, maybe those wells are being drilled so tightly spaced that the per well production will be much less than if just one or two wells were drilled. However, if that is not taken into account by the bean counters, maybe there will be an overshoot in estimated future production?

                I don’t know, maybe the problem is a good problem as PXD’s CEO states. Maybe they will produce the same oil and just even more gas?

                I did notice in looking at Oasis information, that their BOEPD is increasing, but BOPD is slightly decreasing. BOE has went from 83% oil to 76% oil in one year.

                It is interesting that recently the EIA weeklies have been overshooting the monthlies. Could this be why?

                Yes, just speciation by me.

                • Glenn E Stehle says:

                  shallow sand,

                  You really do need to read the article that Mike linked above by Art Berman. It sets out the nuts and bolts of the “bubble point death” theory. Here is the link to the article again:


                  Berman keys off a graphic produced by Schlumberger and Labrynth that illustrates production and GOR behavior from existing wells that produce from a reservoir with a solution gas drive mechanism. No one disputes that this is how reservoirs with solution gas drive mechanisms perform.

                  Initially, the GOR rises. But later, when the reservoir reaches the more advanced stages of depletion, the GOR begins to decline.

                  So first and foremost, it is important to realize that Berman did not predict that the “bubble point death” would occur when GOR is rising, but when it begins to decrease.

                  It is also important to note from the graph that production does not suddenly drop off a cliff when GOR starts to decrease, but continues along the same straight-line curve. Berman seems to have missed this.

                  Here’s the graph:

                • Glenn E Stehle says:

                  shallow sand,

                  Berman posts a graph of Continental’s wells put on production in 2012 in the Bakken. It shows a sudden decrease of GOR in the latest month of production:

                • Glenn E Stehle says:

                  shadow sand,

                  This sudden drop in GOR was accompanied by a precipitous drop in oil production, or what became known as the “bubble point death.”

                  Berman believed this was happening field-wide:

                  Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate….

                  December 2016 production fell 92,000 barrels per day (b/d)–a whopping 9% single-month drop (Figure 1).

                • Glenn E Stehle says:

                  shallow sand,

                  As it turned out, however, the sudden fall in Bakken production from November to December 2016 was an anomaly, and production in the following months quickly recovered to what it was in November. So the “bubble point death” of the Bakken failed to happen as predicted.

                  • @whut says:

                    This guy is making stuff up. Anybody can google the words “bubble point death” and find out that Berman is not associated with that term.

                    It is embarrassing watching somebody with no scientific knowledge stringing together all these arbitrary pieces of info, thinking that it means anything.

                  • Glenn E Stehle says:


                    And the physics?

                    Instead of your orgy of ad hominem, standing up straw men and alleging I favor absurd absolutes, why don’t you use that great command of phsics of yours to explain to us why Berman’s bubble point death theory is correct, why “the decline in Bakken oil production that started in January 2015 is probably not reversible” (it was reversed), and why we are witnessing “the beginning of the end for the Bakken Shale play”?

                    Those, after all, were Berman’s predictions. Defending them should be a snap for someone as brilliant in physics, engineering and science as you are.

                  • shallow sand says:

                    Glenn. I am not arguing there will be an sudden drop in oil production.

                    Just, possibly, as more wells are drilled, and on tighter spacing, less oil will be produced per well.

                    Also, as production climbs higher in each field, more and more wells are needed to offset the decline from producing wells.

                    I am just speculating. I haven’t made any calculations. I just noticed that OAS referred to meeting production guidance per BOE, but that is occurring through growth in gas production, not much growth in oil production.

                    Bakken and TFS production in 5/17 was 985,051 BOPD from 11,300 wells. In 5/14, Bakken and TFS production was 976,114 BOPD from 7,687 wells. (This is North Dakota only, right from the State’s PDF.

                    Sure, had activity not slowed, oil production would have been higher. But, gas production keeps going higher, despite decreased activity. Is that affecting oil volumes? I do not know.

                    I am just thinking about whether drilling up these fields on tight spacing will yield as much oil as predicted. How much higher can each of the three big shale oil basins go? Probably PB should be divided into Midland and Delaware anyway.

                    Looks like both EFS and Bakken need a lot of new wells to go past original monthly high point in oil production. $64,000 question will be when Midland and Delaware Basins get there, and at what production levels?

                  • @whut says:

                    “Instead of your orgy of ad hominem”

                    ha ha

                    Anyone can Google who came up with the term “bubble point death” and it certainly wasn’t Art Berman.

                    That’s the way these Trump-like people operate. They just make up stuff and keep repeating it until other people start assuming it is true.

                  • Glenn E Stehle says:

                    shallow sand,

                    Core Labs, in its 2Q2017 conference call, estimates that with the latest and most advanced completion technology only about 9% of original oil in place (OOIP) can be recovered from shale reservoirs.

                    The greatest breakthroughs in completion technology didn’t begin happening until the second half of 2015, however, so most of the wells producing in the Bakken were completed using obsolete completion technology.

                    The percentage of OOIP that these older Bakken wells will recover is probably no greater than 4 or 5%. And as the Core Labs folks explain, these wells are also not candidates for application of the huff ‘n puff EOR techniques, which they believe can bring total recovery of OOIP up to 15%.

                    In-fill drilling in older field like the Bakken is also problematic due to inter-wellbore communication and the parent-child phenomenon (drilling poor performing child wells into depleted reservoirs).

                    In virgin reservoirs like the Permian Basin things are less complicated. But even then there’s no agreement on well density.

                    Below is a graphic from Diamondback Resurces’ latest investor presentation. Take a look at the difference in spacing assumptions for the Wolfcamp C and Wolfcamp D: four wells per section versus sixteen, 1320′ between wellbores versus 330′, 320 acre spacing versus 80 acre spacing (assuming 10,000′ laterals).

                    The problem is that there’s still much more we don’t know about these reservoirs than we do know. We’re not very far along on the learning curve, so that leaves a lot of room to substitute opinion and speculation for knowledge.

                  • Glenn E Stehle says:

                    shallow sand,

                    And just imagine the enormity of the job that geologists and engineers are tasked with.

                    In its latest investor presentation, Encana identified 14 different pay zones on its properties in the Midland Basin, 8 “premium return” and 6 others. And every one is distinct, with different rock properties and reservoir qualities.

                • Glenn E Stehle says:

                  shallow sand,

                  Berman, however, was just getting started. He next turned his attention away from the depletion around existing wellbores in the Bakken to newly drilled infill wells. These too, he claimed, were being completed in a reservoir that was already depleted.

                  “New well performance has deteriorated,” Berman asserted. “Well-level analysis indicates a fairly systematic steepening of decline rates over time.”

                  Berman makes his own EUR calculations for new wells which he uses as evidence for his claim that new “well performance is declining” and “Bakken EUR has generally decreased over time.”

                  “Oil reserves for 2012 wells averaged 343,000 barrels but only 229,000 barrels for 2015 wells–a 33% decrease in well performance,” he says. “Steeper decline rates result in lower EURs.”

                  “[W]ell performance has deteriorated despite improvements in technology and efficiency,” Berman adds. “Most 2015-2016 drilling was focused around the commercial core area. The fact that EURs from these core-centered locations were lower than earlier, less favorably located wells indicates that the commercial core is showing signs of depletion and well interference.”

                  “Current well density in the Bakken core of 215 acres per well suggests substantial infill locations remain yet declining EURs, increasing water cut and falling GOR do not support further infill drilling.”

                  “Available evidence suggests that current well density is sufficient to fully drain reservoir volumes. That implies that further drilling will not result in producing new oil volumes but will interfere with and cannibalize production from existing wells.”

                  Berman concludes that “The downside of efficiency and technology is that depletion has accelerated.”

                  The well performance data assembled by, however, does not bear out Berman’s claims. Wells drilled in the later half of 2016 and first of 2017 are the best performing wells ever to have been drilled in the history of the Bakken. First, they have higher IPs. And second, they have experienced decline curves that are certainly no steeper than earlier wells, and in some cases are less steep.

                  This is not rocket science. No engineering degree is needed to be able to observe what has happened.

                  • Glenn E Stehle says:


                  • Dennis Coyne says:

                    As before, Glenn the circles area of that chart is for 130 wells or fewer.

                    The other 11,500 North Dakota Bakken/Three Forks wells show no such behavior.

                    You seem to be hanging your hat on a statistical anomaly.

                    Also after 24 to 30 months the output of the wells all approach the same well profile line (and perhaps lower).

                    So any increase in the cumulative well profile over the first 24 to 30 months is all we get, after that from month 25 until the well s abandoned the cumulative output is the same or less than the older 2008-2013 wells.

                    We know this for the Bakken, for other shale plays the results in output per lateral foot of the horizontal well section is likely to be similar.

  28. Watcher says:

    Guys, there was talk in the thread about how non-objective the various financial analyses one encounters are.

    This is why God gave us credit rating agencies. They get paid essentially to be objective and they have been preparing spreadsheets for the various Industries for decades. They certainly messed up in 2007 and everyone knows it but that’s not in play with their evaluation of shale. They have quite a lot of incentive to achieve objectivity in their analysis.

    So all of the babble above about how they rate these companies to a certain extent transcends anything that any of us can do, absent those decades of experience.

    Now as for Wall Street preparing to cut off borrowing from these companies, it sure does not appear in the interest rates assigned the paper outstanding, and it should if a cutoff were about to happen.

    We can make a case for rates in general being so abnormal macroscopically that rates tell us nothing. That is a valid case to be made. The world runs today on interest rates below the rate of inflation, and no one points out this can’t make sense, mostly because they prefer to conclude everything is okay and what they see themselves must be wrong.

    And so, do not think shale finances have to work. They are borrowing money for tiny interest rates.

  29. Longtimber says:

    Latest from Art. Significant confusion on how much Oil is where? Back to the Future?
    “Lower net imports and higher consumption account for all of the comparative inventory reductions since late June but only for a little more than one-half of reductions for the previous 4 months. It is disturbing that this important development cannot be more fully understood.”

    • Boomer II says:

      The global oversupply point is what interests me most.

    • George Kaplan says:

      He has this misunderstanding about unaccounted for oil which isn’t going away. He says:

      “An EIA representative initiated dialogue about the points raised in our post just after its publication. The EIA contends that its methods for estimating stock changes are more reliable than its published flows we used to calculate implied stock changes. Although this may be valid for relatively recent data, it seems that revisions should largely cancel those differences after some reasonable number of months have passed.”

      The EIA understands the issue, any revisions, because the flow measurements are off, would be done by effectively assuming the stock levels were correct, i.e. as soon as the revision is done then the unaccounted for oil has to go to zero, almost by definition, there’s no other way of doing it. So he is talking nonsense, if you ask me.

  30. BlueTwilight says:

    Chart showing EIA U.S. Field Production of Crude Oil from 1920 to 2017-02 with annotations.

  31. Watcher says:

    Why, geologically, does an ageing oil well start to produce more gas than oil?

    • George Kaplan says:

      Are you talking about specific LTO wells? If so I don’t know all the details, but for conventional fields with voidage replacement, especially gas injection, they are often blown down at the end of life – i.e. injection is stopped and they allowed to depressure, then all the injected gas comes out with not much oil. For wells without pressure support they would normally increase GOR as the pressure declines, sometimes they get to a stage when oil is dead (typically artificial lift of some kind is then required) and the GOR starts to fall again, but in some cases the well is abandoned as non-economic before then.

      • @whut says:

        George said:

        “… and the GOR starts to fall again, but in some cases the well is abandoned as non-economic before then.”

        That’s really the point. Follow the tail of the decline curve until it gets to diminishing returns.

      • Watcher says:

        Okie doke.

        Unsatisfying answer, which is not your fault. So it’s not geology that does it. It’s external gas that overwhelms very little oil coming out in the ratio.

        I was groping for some sort of level of microdarcies of geological permeability that has oil flow blocking gas flow that would otherwise be present in the output (were the oil not present blocking . . . permeability paths or something).

        But . . . it’s just gas from injection that comes out in higher ratio because the oil is gone.

        Oh well.

        • George Kaplan says:

          Things like that might be happening in tight oil wells, I don’t know. It’s fairly new stuff so any research is probably in progress and might not have been published (or is company proprietary). In gas condensate wells pressure drop around the well bore can lead to liquid drop out from retrograde condensation that can mess up the gas production (but the would be falling GOR not rising).

  32. Energy News says:

    Texas RRC oil well completions are down again. At 437 for July (Including 43 re-completions)(June 510)(May 593)
    I had a quick look at OK, oil and natural gas, not sure if it means anything?

  33. MASTERMIND says:

    Saudi Arabia Builds Cities in the Sand to Move Beyond Oil

    i can’t wait to visit a saudi entertainment hub

  34. SRSrocco says:


    Hello. This is Steve from the SRSrocco Report site. I wanted to reply to you down here as the comment section in the area above was shrinking.

    I have to tell you Mike, you provided me with some seriously overdue laughter in your response to our PERMA-BULL, Glenn Stehle. I especially roared while reading your explanation how Engineers provided you with plenty of profitable opportunities in fixing up their screw ups.

    I believe there are only a handful of folks on this blog that really understand the DIRE SITUATION as it pertains to U.S. Shale Oil and Gas. Of course Mr. Stehle does not fit into our group because he reminds me of someone who is standing next to giant onion. While Glenn assumes that the healthy outer onion skin layers suggest that the onion is doing just fine, he doesn’t realize the inner part is ROTTEN to the core.

    Actually, I find this a lot with what I call Intellectually ignorant people… very smart when it comes to writing and thinking, but very ignorant when it comes to wisdom about things.

    For example, I recently wrote an article titled, “U.S. SMASHES RECORD: Highest Production Of Lowest Quality Fuel In The World.” This article linked below was about the 1+ million barrels per day of corn based ethanol production in the United States.

    Somehow, my article published on another website caught the eye of the VP of the Auto Channel. He then left a stream of nasty comments suggesting the author (me) was inept or stupid. Now, not only did this VP of the Auto Channel leave comments on one website that ran my article… he did it on several.

    Actually, I imagine he wasted hours replying to commenters that were seemingly defending my stance on the wasteful corn based ethanol. A little later in the day, this fine upstanding VP professional decided to contact me directly as he wanted to make it known that he put a rebuttal article on the Auto Channel site and was eagerly awaiting my reply. Of course, I did not reply because I am just a lowly analyst, not an important VP.

    This VP started off his email to me by letting me know that he just finished doing a speaking engagement at some South Dakota Corn Growers Ethanol convention. That I gather, according to his thinking, should have made me rethink my stance on ethanol… as he was an IMPORTANT PERSON.

    So… what does all this mean. I believe Mr. Stehle bellows to the same sort of character as this VP. You know… wasting lots of time posting useless comments trying to persuade people who in all actuality, think they are completely FOS. I gather you can figure out what FOS stands for.

    Mike… I relish coming in here and reading your comments. Actually, they make my Day….LOL. So, keep up the good work and maybe when the U.S. Shale Oil and Gas industry finally succumbs to the forces of nature and fiscal responsibility, we may find Mr. Stehle resorting to only posting comments about colorful butterflies or how nice the weather is.

    best regards,


    • Glenn E Stehle says:

      SRSrocco Report said:

      I believe there are only a handful of folks on this blog that really understand the DIRE SITUATION as it pertains to U.S. Shale Oil and Gas.

      Mike certainly understands the “DIRE SITUATION as it pertains to U.S. Shale Oil and Gas.”

      He understands that those evil shale people flooded the world oil market with oil and crashed the price, which has created a DIRE SITUATION for his pocketbook.

      But Mike isn’t falling for the shale ponzi scheme. No siree, not Mike. As he adamantly states up thread:

      People spending other peoples money do really dumb things.

      Me too sometimes, with my own money, but never so much as to drill and complete a shale oil well myself.

      But wait! No sooner having said that, Mike gushes:

      Yes, of course I have [seen AFEs and JIBs] for shale oil wells…. I have interest in shale oil wells.

      I have probably made more money from shale wells than you have….

      Sometimes it’s difficult to avoid whiplash trying to follow all the conflicting and contradictory claims that issue from the keyboards of you oil and gas experts.

      • SRSrocco says:

        Ahhh…. Glenn. Couldn’t you just resist for a wee bit and allow Mike to reply first? Of course not. You better take a good look at yourself in the mirror as you seem to be suffering from a serious case of OCD in that you just can’t keep yourself from leaving at least 50 comments a blog post.

        Maybe, you should consider a break by taking a vacation from the site for a while. Probably good for your head and all… just saying.

        Don’t worry, the site will still be here in a few days or week. That is, if you can overcome that OCD for a little while.

        All the best…


        • Glenn E Stehle says:


          So let’s see. Besides being an oil and gas expert, you’re an expert in psychology too?

          And what an expert psychologist you are! You can diagnose an emotional disorder in someone 1) you have never spoken to and, 2) you don’t even know. And the best thing of all is that you can perform this diagnosis over a medium as impersonal as the internet, and from thousands of miles away. Now that’s what I call an expert psychologist!

          So let me ask you, is there anything you’re not an expert in?

          • Srsrocco says:

            Glenn…. a million thanks. With that 51st comment, you just proved that my diagnosis was correct.

            Don’t worry… no cash necessary. I’ll send you a bill.

            Doc Steve

            • Mike says:

              Holy Moly, what a comment that is directed at me. Yeow ! Anyway, thanks for your comments, Steve.

              Almost everyone with enough oil sense to pour piss out of a boot has already left Peak Oil Barrel the past six to eight months. Its clear to me now why, and that was/is the plan, to drive away anyone not willing to pimp for the shale industry.

              My sincere apologies to the community for any role I’ve played in causing disruption. Adios, y’all.

              • Glenn E Stehle says:

                Srsrocco & Mike,

                It’s amazing how great minds think alike.

                Now you two can close ranks and unite in your jihad on engineers.

                Just imagine, however, if you can get @whut to join the cause. It’ll be like the Holy Trinity — the Father, the Son and the Holy Ghost — waging holy war on engineers.

                You guys can take Ludditism to an entirely new level.

              • Trumpster says:

                Hey MIKE,

                Please hang in here, and fuck GS and the horse he rode in on.

                I stay over in the non petroleum thread when commenting almost all the time, because that’s where we talk about the things I know enough about to make useful comments.

                But I know enough about oil to assure you that the vast majority of the readers of this blog have a very high opinion of you , personally and professionally.

                I have hung in myself when dealing with assholes who refuse to look at facts until they have departed, and will continue to do so.

                But in the case of GS, I am not personally knowledgeable enough to argue the dollars and cents of the oil industry, at the day to day operational level.

                However, I can argue it in general terms, and will, now.

                Here are a few thoughts that I personally perceive to be indisputably factual.

                One , cheap oil is VERY good for the economy, short to middle term.

                Two, all politicians as a CLASS want the economy to run smoothly, because incumbents get reelected. The out party pisses and moans about economic hard times, but seldom ever pursues a policy intended to make hard times worse, lol.

                Three, politicians don’t give a flying fuck about any particular constituency such as the oil industry, unless they happen to be congress critters from an oil state who get big money from oil industry donors.

                Politicians are perfectly ready to throw any particular industry under the bus, except the ones that own THEM, such as the banking industry, big pharma, big insurance, etc. The oil industry simply doesn’t own government, not any more, and hasn’t, for some time now.

                Bottom line at this point, the government doesn’t give a fuck about the financial health of the oil industry, because the cheaper oil is, the better the REST of the economy does. There are DAMNED FEW voters employed in oil ( or coal! ) on a national basis, lol.

                Now let’s move on a bit.

                We have lots of regulatory agencies, and investigative agencies, right up to the FBI, lol, that are supposed to be watching out for financial shenanigans and outright fraud, in the oil industry as well as other industries.

                But if there is to be any serious investigation, the word has to come down from the TOP of these agencies.

                The people actually tasked to do the work understand that to start digging into the finances of the tight oil industry, and the people financing it, means they will NOT be promoted, they will NOT get raises, they will be transferred to inventorying the toilet paper, and if they still persist, they will be fired on one pretext or another.

                Individual loan officers are generally as dumb as fence posts, in terms of understanding the big picture. They do whatever is consistent with the guidelines provided to them by higher management, and what their fellow employees are doing, in the same and in other banks and lending institutions.

                We’ve all heard the saying that nobody has ever been fired for going with Microsoft, lol. I can’t borrow a dime to expand my farm, due to my limited cash income, etc, even though I am rock solid on assets and quite capable of making payments. But I can walk out with a loan for the same amount on a fast depreciating CAR, in an hour, or a day or two at the most. The loan officer knows the score, she just shrugs and says she only works there, she doesn’t MAKE THE RULES.

                If I default on a car loan, she will not suffer, because she will have MADE IT BY THE RULES. If somehow she were to sneak me a new car sized loan for more land,or machinery, and I defaulted, she would be fired. She might be fired just for making it. She sure as hell would get her ass chewed, and a permanent flag on promotion, etc.

                The banks are capable of looking after themselves, and when they fuck up, they are pretty comfortable with the idea that the REST of us will bail their fucking asses out these days, because the BAU Democrats are more or less just Republican Lite, and the R’s are the R’s , no more need be said.

                The real ELITE, the politicians, bankers, rich people in general, etc, are well satisfied with the tight oil industry as it exists, and they don’t give a flying fuck at a rolling donut whether the loans are ever repaid, or NOT repaid.

                There are VERY good reasons why this is so, beyond the fact that cheap oil greases the wheels of the economy overall, so that any RELATIVELY small losses experienced on bad loans to tight oil operators are TRIVIAL, compared to the benefits of oil staying dirt cheap.

                Cheap oil is entirely consistent as well with the so called GREAT GAME of international power politics, and international finance, from the point of view of the USA and our REAL ALLIES, virtually all of them oil importers or soon to be oil importers. Cheap oil is a fist in the nose and solar plexus of our enemies and or potential enemies that export oil. We don’t have ANY REAL FRIENDS that are oil exporters, excepting Canada, Mexico, and maybe a few trivial other suppliers.

                Now it may take a FARMER to understand that just a minor excess of product coming to market is enough to result in a PRICE CRASH. It may take a FARMER to understand that producers don’t just fucking close up, like a guy with a hot dog cart, when they are losing money. They hang in there until they are either broke or until the price goes up again, and this applies TRIPLE to GOVERNMENT, and government owns or tightly controls most of the oil in the world.

                Call it institutionized corruption, or deliberate oversight, or benign neglect, whatever you please.

                The so called POWERS THAT BE like it like it is, and so it will STAY like it is, in terms of money going to tight oil operators- money that will never be repaid.

                I noticed one of my neighbors was letting about a thousand dollars worth of nice peaches rot on the tree a couple of weeks back, and the explanation was that it was either a thousand dollars worth of peaches , or ten thousand dollars worth of hay, to be dealt with, IMMEDIATELY. So the peaches hit the ground, except for the ones picked by grateful friends of his.

                I have often run a machine in need of repair, knowing that by doing so I would triple the cost of making the repair LATER. I did it knowing that my bottom line would look best getting the work out ON TIME.

                These examples parallel the situation that prevails in terms of banks, other lenders, government, and the tight oil industry.

                This general situation prevails in many parts of the economy. Our schools, taken all around , are managed in a similarly slipshod fashion. Everybody knows it’s SNAFU, but nobody is in a position to do anything about it. Ditto health care, insurance, real estate, agriculture, the overall environment, etc, to a greater or lesser extent, in terms of EFFECTIVE oversight .

                Now Dennis and Ron believe in free expression, even to the point of tolerating ME, lol.

                They won’t run off GS.

                DON’T let GS get under your skin. Dennis knows he’s an idiot, but he’s polite, and won’t ever say so , in so many words, lol.

                And there’s ANOTHER issue to be considered as well. Most of the regulars disagree with me, and want to chase of guys such as Javier, but as I see it, anybody really interested in learning the real score, who is not yet expert, has a GREAT deal to gain by reading Javier’s comments, and the responses ripping them apart, made by other members.

                I have learned a good bit about the intricacies of climate science myself, as the result of Javier posting his stuff, right or wrong.

                Anybody who really wants to understand the oil industry NEEDS to hear what you have to say. The forum is desperately short of guys with hands on expertise.

                You are a VALUED member of this forum.

                I doubt more than three regulars have a higher opinion of GS than they do of you. They all appear to have skin in the game, just as you do.

                I have a pretty good nose, when it comes to smelling bullshit. You aren’t a bullshitter.

                I can’t say that about those three, lol.

                Mike, this comment is signed Trumpster, another handle I use here because old HB over in non petroleum calls me that. I do it deliberately, because he’s the an idiot just like GS, to mock him, when it comes to politics.

                I post more dirt on Trump than everybody else put together. I’m OFM, but you might not know that, since you don’t seem to read the non petroleum thread, at least not often.

                • Glenn E Stehle says:


                  You admit that you are “not personally knowledgeable enough to argue the dollars and cents of the oil industry,” but then everything that follows in your screed (e.g., the law enforcement agencies that are supposed to be looking into the “financial shenanigans and outright fraud” of the tight oil industry but are not, the loan officers who are “dumb as fence posts” who make bad loans to the tight oil industry, etc.) assumes that, as you put it, the “money going to tight oil operators” is “money that will never be repaid.”

                  How do you know the money lent to the tight oil operators will “never be repaid” if you are “not personally knowledgeable enough to argue the dollars and cents of the oil industry”?

              • Boomer II says:

                Mike, I hope you keep posting, too.

                I don’t take Glenn’s postings seriously because most of his sources are investor presentations.

                Much of what he posts doesn’t make sense to me from an oil industry point of view unless he is hoping to sell leases or shares in a company.

                Low prices and excess supply are not good for the industry, and technology has not reduced production costs enough to generate a profit for most companies. If the funding sources dry up, there won’t be the money for them to keep going.

              • Dennis Coyne says:

                Hi Mike,

                Just click on the x next to Glenn’s name.

                I agree with others that your views are much more worth reading than Glenn Stehle’s.

                It is interesting that his inability to counter your arguments results in an attack on you, when he gets so upset when others do the same to him.

                In any case the perspective of people who actually know how to produce oil, like Mike Shellman, will be missed.

                Thanks for all you have taught us here.

    • MASTERMIND says:

      Good work Steve! Ill make a small donation on your behalf!

  35. Longtimber says:

    Gotta have all sides – Let’s focus on Realities! much here to learn from everyone and the graphs are just dynamite. I’m here to grasp Rockman’s POD – PEAK Oil Dynamics. Oil and Silver are both Golden. Oil’s worth is certainly taken for Granted but for how long? I for one am concerned with liquid hydrocarbon’s role in sparking serious global events or entanglements. Like or not Oil is the blood of modern systems as designed. Symptoms prior to a major event obvious, or not?
    Possible MSM coverage flip from Russia noise to Life giving matters of energy?
    From ZH:
    “According to Bloomberg, Repsol field workers left the country in the past few weeks, with a skeleton expatriate staff remaining at the company’s offices in Caracas. Separately, Statoil withdrew its last three foreign workers before the July 30 election to ensure their safety, Erik Haaland, a company spokesman, told Bloomberg by phone.”
    “The immediate result of the departures will be an even bigger decline in Venezuela’s oil output – the only remaining asset which Maduro can readily exchange for dollars – further exacerbating the country’s financial crisis as the inflow of hard currency slows further.”

    • Watcher says:

      Wait a minute:

      “Separately, Statoil withdrew its last three foreign workers before the July 30 election to ensure their safety, Erik Haaland, a company spokesman, told Bloomberg by phone.”
      “The immediate result of the departures will be an even bigger decline in Venezuela’s oil output”

      Okay, don’t know how many Statoil people were in Venezuela on . . . say . . . Dec 31, 2016. But the way that reads suggests this guy thinks his 3 guys were in some way hugely defining of an entire country’s oil flow.


      • George Kaplan says:

        It means no decisions will be made and no funding will be available for anything, so any oil coming from Statoil and Repsol operated wells (I don’t know how much that is) will gradually run down to zero (or maybe not so gradually).

  36. Watcher says:

    There is a graph way up thread with a red ellipse on it. It shows a flattening of decline curves of recently drilled wells in NoDak.

    No, that isn’t deserving of an ellipse. That flattening is in month 10. Everything looked like all the other years in terms of decline shape months 1 through 10. Geology isn’t going to change suddenly in month 10. Porosity and permeability are what they were in month 1.

    Unless there was a refrack redefining permeability, in which case that curve has to re-position to month 1. The label “months of production” is not really valid. The measure is not months of production. It’s months past completion. That graph is not showing months past completion for a refrack.

    • @whut says:

      Watcher says:

      “Geology isn’t going to change suddenly in month 10. Porosity and permeability are what they were in month 1.”

      Agree. Yet there’s only one guy that comments here that doesn’t seem to get that, and its the guy that keeps adding these charts. 🙁

    • Glenn E Stehle says:


      The lower decline rates achieved with the rapidly changing completion technology are even more pronounced in the Permian Basin.

      The graphs I have posted present nothing but the raw, unadulterated, empirical data from

      It’s amazing the loops you and @whut will go through to deny factual reality when it doesn’t square with your stealth religion.

      • @whut says:

        So what?
        I see self-similarity on a semi-log scale. You don’t know anything about physical processes so that goes over your head.

        • Glenn E Stehle says:

          @whut, taking Ludditism, stealth religion and the denial of factual reality to an entirely new level.

          • @whut says:

            When will you ever admit that Art Berman didn’t come up with the “Bubble-Point Death” theory?

      • Glenn E Stehle says:

        Or maybe you guys prefer the graphs Art Berman uses?

        Here’s the thing: Garbage in, garbage out.

        The question is, of course, who’s data do you trust?

        • Watcher says:

          I don’t know what any of that means.

          The graph with the ellipse on it had decline rates for recent wells showing the same slope out to month 10. Then there was a flattening.

          Again, think strictly about geology. What would change in month 10? Even if there were magical proppant properties that were doing something great, they would be just as magical in months 1-10 as 10-15.

          That’s not what it says. The decline slope looks like all the other years up to month 10. Then it changes.

          Some other action was taken in month 10. That is the equivalent of doing a new completion.

          Now, there can be definitions in play. In a conventional well, perhaps you send a pump out and start pushing CO2 in or even water as a water drive, and you do that in month 10 and get improvement.

          But this does not define improved technology in what was done on day 1. Improved technology on day 1 will not wait 10 months to show itself.

          Mostly the question is what was happening month 1 through 10. Forget month 10 onwards. What did the technology do months 1 through 10?

          • @whut says:

            Don’t try to reason with this dude using scientific concepts. Doesn’t work on a contrarian.

            OTOH, what you are saying I agree with.

      • I would love to see the “Daily Oil Production” graph normalized for lateral length and proppant used.

        If desperate operators are drilling 9,000 feet and reporting an average of 600 BPD how does that compare to times past when they might have been drilling 6,000 feet and reporting 450 bpd?

        My sense is the geology is what it is and there’s no new “well efficiency” or higher productivity to speak of really. Just more drilling and more sand.

      • Dennis Coyne says:

        Hi Glenn,

        That chart leaves out a lot of data. Why?

  37. George Kaplan says:

    Pacific Drilling considers bankruptcy after CEO departure:

    Their fleet is seven deep water drill ships, all delivered since 2010, and all becoming very expensive junk unless some new deep water targets come up pretty soon. I think only two ships are active and their contracts will probably end this year (one for Chevron in GoM, one for one well with two options offshore Nigeria).

  38. Energy News says:

    Possible gasoline engine technological breakthrough – compression ignition – no spark plugs, just like a diesel engine.

    Mazda Motor Corp unveiled plans for the world’s first commercial gasoline engine using compression ignition. Mazda said the new engine would be 20 to 30 percent more efficient than its current engine. Launches in 2019
    The news follows Mazda’s Friday announcement of a capital tie-up with Toyota, an alliance that will see the pair build a $1.6 billion U.S. assembly plant and work together on electric vehicles.

    • JN2 says:

      OK, so 20% goes to 24%-26% efficiency. Life in the old dog yet. But compare to EVs at 95%…

    • Trumpster says:

      I’ve been hearing about compression ignition gasoline engines for quite some time. It’s hard to understand why nobody has built one yet, commercially, until you stop and think a minute about why.

      Such an engine will have to basically be nothing more and nothing less than a conventional diesel engine, except that the fuel injection system must be capable of injecting gasoline rather than diesel fuel, at the extremely high pressures required for direct injection. This is not easily accomplished, given that gasoline is a VERY poor lubricant, and the existing reliable but intricate and very expensive diesel injection system is lubricated by the diesel fuel flowing thru it.

      So it’s been a long time arriving, and may be a long time yet achieving commercial success.
      I’m willing to bet we don’t see it in a car or pickup truck within the next five years.

      • Energy News says:

        I was wondering what the breakthrough might be as it doesn’t mention anything in the article.

  39. George Kaplan says:

    BP have said Atlantis North is going to be scheduled for 2019 / 2020, so whatever they are drilling, as mentioned in the original post above, it isn’t that. It would be a tie back as there are no dry trees on the platform. I got the capacity wrong – it’s 200 kbpd, so they probably do have spare (although there may be other limits like water, gas, manifolds or risers).

  40. MASTERMIND says:

    ‘Nothing To See Here’ – Frackers Ignore Rising Well Decline Rates

    • Watcher says:

      I don’t think Freddy’s graphs that appear here monthly show any increase in decline rate.

      You do get increased cumulative decline because there are simply more wells declining, but there is nothing showing the decline rates getting steeper for individual wells.

      • Dennis Coyne says:

        Freddy’s graphs are for Bakken only. The decline rates in that article are for the legacy decline rate which is different.

        See EIA’s Drilling Productivity report.

  41. MASTERMIND says:

    Current U.S. gasoline prices are a going-out-of-business clearance sale at prices that don’t reflect the cost of extraction and refining.

  42. Energy News says:

    It looks like the EIA is expecting a big production increase in October and November. I guess we are going to have to wait and see if there is a completions bottleneck?

    • Nick G says:

      They seem to be projecting that US crude production in the last quarter of 2017 will surpass the 1970 peak.

      • SRSrocco says:

        Nick G,

        Yeah…. that’s great. Crying shame no one really made any money doing it… LOL.


        • texas tea says:

          remind us all again Steve how much money have “investors” made listening to you over the last 5 years?

    • George Kaplan says:

      I think it’s really just steady growth onshore with a big dip from hurricane season in GoM taken out for August and September, that then comes back. They have revised GoM figures down about 20 kbpd going back through 2016, and also dropped 50 kbpd from their projection for exit rate in GoM for 2018. However the growth in the second half of 2018 is still all from GoM I think, so it looks like they are predicting a new plateau (or at least much slower growth) for LTO around May next year. As I (with OPEC and IEA) think they have GoM wrong then, if their onshore numbers are about right, the US is unlikely to exceed the previous peak, and production would start falling again from around March.

  43. MASTERMIND says:

    Conventional Oil Peaked in 2006 –IEA

    New Oil discoveries by scientists have been declining since 1965 and last year was the lowest in history -IEA

    International Energy Agency Chief warns of world oil shortages by 2020 as discoveries fall to record lows

    Saudi Aramco CEO believes world oil shortage coming despite U.S. shale boom

    UAE warns of world oil shortages ahead by 2020 due to oil industry spending cuts

    HSBC Global Bank warns 80% of the worlds conventional fields are declining and world oil shortages by 2020

    UBS Global Bank warns of world Oil Shortage ahead by 2020

    German Army (leaked) Peak Oil study warns world oil shortages would collapse the global economy and democracies

    The Oil Age may come to an end for a shortage of oil. -Saudi Oil Minister Sheikh Yamani

    • George Kaplan says:

      Please stop misquoting Yamani. I’ve pointed out twice that he actually said the opposite of what you say he did. If you don’t I’m going to ask Dennis to start deleting you and/or banning you from commenting on any of my future posts.

      • Boomer II says:

        I think he has been banned before, posting under a different name.

      • MASTERMIND says:

        He did say that I got it from a peer reviewed scientific article.

        • George Kaplan says:

          I said you completely misread that article, looks like you also completely misread my comment. Something of a pattern forming.

  44. Energy News says:

    I hadn’t noticed this chart before, I thought that the EIA had stopped providing drilling data?
    The number of GoM development wells drilled fell in 2015 & 2016 but they don’t give any clues as to how much potential production was deferred?

  45. Energy News says:

    LONDON, Aug 9 (Reuters) – U.S. shale producers need a WTI oil price around $50 per barrel to break even, according to an analysis of financial statements for the second quarter.

    Fifteen of the largest shale oil and gas producers reported total net losses of $470 million for the three months between April and June when benchmark WTI prices averaged $48.

    Total losses were down from $3.7 billion in the first three months of the year and $7.4 billion in the same period in 2016, according to earnings statements published in the last week
    It remains unclear if these figures apply to full lifecycle costs (including overheads) and all the parts of all the shale plays (or just the most productive sweet spots).

    • Glenn E Stehle says:

      I don’t disagree with Kemp.

      His view is what one sees by looking in the rearview mirror. SEC forms, after all, give us an indication of past, proven performance.

      Just a few years ago (2014-2015) U.S. shale producers needed an oil price of something like $100 to break even. So the shale industry has made great strides in bringing down the cost to produce a barrel of shale oil.

      But U.S. shale producers certainly aren’t resting on their laurels.

      Technology is evolving rapidly, as are business and operating practices. It will be interesting to see whether these will succeed in dropping that $50 break even price even further in the future.

      Time will tell.

      • Watcher says:

        I was unable to find the graph with the red ellipse at, which seems to end at May 2017. Can you do a complete link to it?

      • SRSrocco says:


        Unfortunately, you are unable to discern between advances in technology and the falling EROI. I gather you have no clue that more technology that is thrown at something, the more the EROI declines.

        Unfortunately, they don’t include that TID-BIT in glossy oil-gas investor presentations.

        Furthermore, a lot of PRODUCTION COSTS dropped in many different sectors of the economy due to the falling oil price. For example, the primary silver mining industries cost of production declined from $24-$25 an ounce in 2012, down to $16-$17 today. While the primary silver mining industry made a lot of additional cuts, ENERGY was the key has it had a profound impact on all costs relating to producing silver.

        We must remember, material supply costs for the primary silver mining industry are based upon the cost of energy. So, when the cost of oil declined by more than 50%, so did many of the material costs to produce silver.

        Glenn… you are an interesting chap. I find it disturbing how many comments you feel you need to make in each blog post. It almost feels like desperation.

        However, I would imagine you will reply with at least 2-3 comments. Don’t want to let your average 20-25% of total Blog comments drop too low. So, keep up the good work.


        • Glenn E Stehle says:

          SRSrocco said:

          [The] more technology that is thrown at something, the more the EROI declines.

          There’s that great mind at work again, taking Ludditism to an entirely new level.

  46. Watcher says:

    About those lower costs for shale producers. Here’s Halliburton’s text from Q2 2017. (GAAP 3 pennies/share profit).

    Completion and Production revenue in the second quarter of 2017 was $3.1 billion, an
    increase of $528 million, or 20%, from the first quarter of 2017, while operating income was
    $397 million, an increase of $250 million. These improvements were primarily due to
    improved pressure pumping utilization
    and pricing in the United States land market. Also
    benefiting these results were increased well completion activity in the Gulf of Mexico, North
    Sea, and Russia, partially offset by pricing pressure in the Middle East.

  47. Watcher says:

    This looks like quality work out of HAL.

    It’s a description of horizontal steering in the vertical plane to remain positioned within a desired strata. This is the sort of tech one would expect. No quantitative claims in the paper, but the way it reads suggests 1-3% improvement in . . . whatever. Not the bizarre magic claimed elsewhere.

    There is also this on the HAL site:

    Halliburton awarded a multi-million dollar software grant to King Fahd University for
    Petroleum and Minerals. The software grant is delivered through Landmark’s
    University Grants Program, which contributes renewable software licenses to
    qualified academic institutions worldwide.

    HAL is sending money to Dhahran, KSA?

  48. Watcher says:

    Experiment to replace diesel trucks with LNG fueled:

    Bison Transport is a major Canadian carrier. They have 1400 tractors and xxx trailers.

    “Bison Transport purchased 15 liquefied natural gas (LNG) trucks and ran them back and forth from Calgary to Edmonton. The trucking company partnered with Shell to provide fuel stations to fill up.

    The motivation was obvious as the company expected to save 30 per cent on fuel costs with LNG trucks compared to diesel, and produce 30 per cent fewer emissions.

    But after two years, and more than 1.5 million kilometres travelled, Bison Transport hit the brakes.

    The trucks were sold and the pilot project was shelved.”

    • Boomer II says:

      Other than to create a market for LNG, is there any benefit to using it rather than gasoline or diesel? I did a quick search and it looks like LNG doesn’t offer significantly more environmental benefits than the fuels it replaces.

      Yes, get rid of coal. But why substitute natural gas for gasoline and diesel? More of it?

      • Watcher says:

        Forget environmental aspects. Zero importance.

        No one will elect starvation over the environment.

        • Boomer II says:

          I see no starvation issues in using LNG where it works, such as urban areas, as you suggest.

          I’m just asking what advantages are there in using it?

          • They should use high pressure gas cylinders instead of LNG, refuel from preset stations every 150 miles. But there isn’t enough natural gas supply to replace gasoline and diesel.

            • Eulenspiegel says:

              They use (not should) pressured gas with 200 bar, range is 400-600 km.

              That is what you can buy as a refit kit for almost every normal car here in Germany.
              I see refill stations for natgas everywhere, many stations have one – and you can keep your old gas tank to switch back if you run out of natgas.

  49. texas tea says:

    from the same article

    “Not all experiments with LNG have failed. Currently, at least eight different companies across the country use natural gas powered trucks and buses, according to the Canadian Natural Gas Vehicle Alliance. Groupe Robert trucking in Quebec runs 125 trucks on LNG.”

    “When Bison Transport put up its LNG trucks for sale, they were bought by Vedder Transport in B.C., which was already running 50 of its trucks on natural gas. Vedder Transport’s experience with LNG seems remarkably different, as it says maintenance costs and performance have not been an issue.

    The LNG industry is much larger south of the border, where more than 150,000 vehicles use the fuel, according the U.S. government’s department of energy.

    “In Western Canada right now, the over the road transportation business is challenged because we don’t have a lot of infrastructure built and there isn’t a lot of viable engine technologies for the Western Canadian market,” said Travis Balaski, an executive with Calgary-based natural gas company Ferus.”

    • Watcher says:

      Those are short runs elsewhere. In a city you need only 25 miles of range.

      No food grows in cities. Distance is how you feed cities. 1905 NYC was fed by farms in the suburbs using 350,000 horses to haul the food in, as well as hay for themselves. That was for a human population of just over 1 million. Quite the animal ratio, and horses with muscles for that were bred out of them. They are very rare now.

      The farms are 100s of miles away now. Only trucks with range can deal with that, and as was seen going 175 miles Calgary to Edmonton, that needs diesel.

  50. Boomer II says:

    Thinking about oil, though this article makes no mention of it.

    “Yet markets’ dependence on central-bank largesse appears largely unabated. The decline of volatility readings and the rise of valuations in all asset classes seem to presume any market shock or economic downturn can be handily contained. Perhaps some lessons are easier learned than others.”

  51. MASTERMIND says:

    The Saudi’s are going to remove their peg after their IPO sale. Then the dollar will collapse!

    • Carmen says:

      The article has a graphic that shows that US Dollar will strengthen if the Riyal Dollar Peg collapses. Strong US dollar will crash commodities and stock markets, bankrupt energy sectors and send a deflationary wave of tsunami across the world. Saudi Arabia will not remain immune to the effects of a unpeg.

  52. WannabeMacro says:

    It makes more sense for the Saudis to remove the peg (force abandon) or when they have diversified. Both the scenarios highlighted here are plausible. The Dollar will not crash, instead it will strengthen. Look at the Peg effect graphics.

Comments are closed.