Texas Update- June 2017


Dean Fantazzini has provided me with updates to Texas Oil and Natural Gas estimates, the data shifted about a year ago so I use the most recent 13 months of Texas RRC data along with the “all vintage” data estimate which uses all data from Jan 2014 to April 2017 for oil and April 2014 to April 2017 for condensate. The most recent EIA estimate is shown for comparison. In April 2017 the EIA estimate is 3345 kb/d, the 13 month corrected estimate is 3443 kb/d, and the all vintage estimate is 3572 kb/d.


The data in the table below is for Texas Natural Gas output (million cubic feet per day) .


Eagle Ford output estimates through April 2017 are from the EIA in the chart below.


Permian LTO output in Texas was estimated by using New Mexico Permian output from shaleprofile.com and deducting this from the EIA’s Permian basin estimate, this gives us data through Feb 2017. In order to estimate March and April 2017 Texas Permian output I used Dean Fantazinni’s 13 month estimate multiplied by the percentage of Texas output from the Permian basin (Districts 7C, 8, and 8A) based on the latest Texas RRC data. From this we can determine that from Jan 2015 to Sept 2016, TX Permian conventional output was about 486 kb/d on average and then fell to a lower level of 437 kb/d from Dec 2016 to Feb 2017.

If we assume conventional output continues to average about 437 kb/d from the TX Permian basin in March and April, we can estimate TX Permian LTO output in March and April. I have also assumed that the New Mexico Permian basin output estimates at shale profile are relatively accurate, which may not be the case. Those with access to IHS data could check to confirm whether this is true. A chart with the Texas Permian Basin output estimate is below.


Using the Permian and Eagle Ford estimates and the 13 month Texas C+C estimate from Dean Fantazzini’s data, we can estimate Texas conventional output (Texas C+C minus TX Permian and Eagle Ford), which is shown in the chart below.


Conventional output seems to have stabilized at an average of about 874 kb/d from May 2016 to April 2017 after falling about 120 kb/d from Dec 2014 to May 2016. Conventional output is about 25% of Texas C+C output in April 2017, 42% of output is Permian Basin LTO, and 33% of output is from the Eagle Ford.

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149 Responses to Texas Update- June 2017

  1. Boomer II says:

    Good article by Art Berman on natural gas pricing and why the industry often misreads future pricing and supply.


    • Guy M says:

      I was a fan of Art, until I read a recent article last month. According to his analysis, prices will be lower for longer. With an added glut in 2018, which be a result of 4 million barrels a day added to world supply by then. 62% was to be from US production. That is 2.48 million barrels. Unicorns.
      Unicorns make the oil production, and turn the oil into Teslas. Then we don’t need oil. Well, except for the truckers, and it will be easier driving my Tesla without truckers on the road. It’s all figured out! We don’t need that slimy oil!

  2. Glenn E Stehle says:

    Qatar Plans To Boost Gas Output Capacity Amid Gulf Rift

    Qatar Petroleum plans to boost gas production from its giant North Field, which it shares with Iran, by 20 percent after new gas development, QP’s chief executive said on Tuesday, despite sanctions imposed on the Gulf Arab state by its neighbours.

    Qatar in April lifted a self-imposed ban on development of the North Field, the world’s biggest natural gas field, and announced a new project to develop its southern section, increasing output in five to seven years.

    That new project will raise Qatar’s total liquefied natural gas (LNG) production capacity by 30 percent to 100 million tonnes from 77 million tonnes per year, Qatar Petroleum’s CEO Saad al-Kaabi told a news conference in Doha.

    Global LNG demand was 265 million tonnes in 2016, according to Royal Dutch Shell’s annual LNG outlook.

    “After further assessment, we have decided that the best way to develop this huge project is by dedicating it to the production and export of liquefied natural gas,” Kaabi said.

    “We have decided that the best option would be to double the size of the project to 4 billion cubic feet of gas per day… This project will strengthen our position as the world’s largest LNG producer and exporter.”


    The announcement comes a day after France’s Total signed an agreement with Iran to develop its part of the shared off-shore gas field that Tehran calls South Pars….

    The deal on Monday with Total is to develop its South Pars Phase 11 project, the first major Western energy investment in the country since the lifting of sanctions.

    Gulf OPEC member Qatar, a future World Cup host with a population of 2.7 million, faces sanctions by Saudi Arabia, the United Arab Emirates, Egypt and Bahrain who have severed diplomatic and transport ties with Doha, accusing it of supporting terrorism. Qatar denies the accusation….

    Kaabi said the company’s operations would not be affected by the crisis.

    “Qatar Petroleum will continue working…If some companies decide they don’t want to work with QP that’s their choice. We will find other foreign companies to work with,” he said.

    • Glenn E Stehle says:

      Qatar flattens Straya’s LNG dream

      Big news from Qatar overnight: Qatar Petroleum on Wednesday announced plans to significantly raise natural gas production in the coming years, creating an obstacle to President Donald Trump’s goal of “energy dominance.” The move threatens to add to a projected glut of liquefied natural gas, or LNG, as a wave of new projects come online……..

      • Eulenspiegel says:

        Yes, this looks like LNG will be in deep trouble soon. Everybody wants to earn a lot and doubles output – the road to disaster. Especialle when lots of credit is involved.

        It will be double difficult for fracking gas to compete with these giant fields, where cost structures scale more easy, have shorter ways to LNG liquifier plants and so on.

        In Europe we can lean back and see what it brings, with all own sources in decline. Fracking didn’t worked on polish and english rocks so far. They produced lots of duds and the best ones where only at 10-30% of commercial breakeven.

        • Ves says:


          “LNG will be in deep trouble soon”

          LNG is not in trouble. It is Qatar that is in trouble and that’s why is the desire to increase production. Qatar’s situation is not pretty. It was punching above its weight and lost and now It must find accommodation with one of the power players in the region. With their increased LNG gas production, it has better cards to do that. So again, it is desperate political and not economic motive.

          • Eulenspiegel says:

            It’s not the Qatar LNG – it’s other producers (with higher costs) LNG that will be in deep trouble because of price collaps. Even Qatar can get trouble, if they collaps price too much even a double production can mean less money – as seen in oil, 100$->30$ and nobody wins anything.

            • Ves says:


              Okey, let me put this way. The timeline of Qatar LNG expansion is 5-7 years, (realistically a decade). Qatar is under siege; land, air, sea blockade. Considering how bankers and military types fond of drawing new borders on the napkin I really doubt that Qatar will even exist in that time-frame. It is not a Liechtenstein with rocks to pretend to be a country but it is a huge gas field with LNG gas terminal pretending to be a country. It is too valuable and too small to be left alone. But it is their fault, they were playing politics in the big league.

              • Glenn E Stehle says:


                But Qatar has friends in high places too.

                An additional blockade of Qatar is impossible without the agreement of the U.S. Russia and other big states….

                It has hundreds of billions in monetary reserves [and] international support from its liquefied gas customers and allies….


                • Ves says:

                  That article is childish. What additional blockade you want when Qatar is forced to get their supply of milk, fruits, vegetables, daily all the way from Istanbul and Teheran instead of next door. Do you even have any idea in practical terms how sustainable is that? Do you have a concept how far away these places are from each other.

                  • texas tea says:

                    i see it as Saudi’s manifest destiny they will control the entirety of the peninsula one way or another, they are not going to let Iran have another foothold or a 2nd-3rd front on their border.

              • Hightrekker says:

                We shall see—Iran is not a adversary to take lightly, and this is a opportunity to stick the caged fat pig, that is SA.

              • Boomer II says:

                I would think having a major US military base in Qatar might offer some protection.

                • Hightrekker says:

                  I would think having a major US military base in Qatar

                  With almost 800 globally, they may not notice.

        • Glenn E Stehle says:

          Exclusive: Energy giants court Qatar for gas expansion role despite crisis

          The West’s three biggest energy corporations are lobbying Qatar to take part in a huge expansion of its gas production, handing Doha an unintended but timely boost in its bitter dispute with Gulf Arab neighbors.

          The chief executives of ExxonMobil(XOM.N), Royal Dutch Shell (RDSa.L) and France’s Total (TOTF.PA) all met the emir, Sheikh Tamim bin Hamad al-Thani, in Qatar before it announced a plan on Tuesday to raise output of liquefied natural gas (LNG) by 30 percent….

          Qatar, the world’s largest LNG supplier and second biggest gas exporter after Russia, has some of the lowest production costs. The plan was seen as an opening shot in a price war as Doha tries to defend its market share, especially against supplies from U.S. shale deposits where costs are higher.

        • Glenn E Stehle says:

          The Saudi-Qatar Spat – Qatar And Iran Are Winning – MbZ, MbS Lose Face

          The Saudi/UAE campaign against Qatar quickly turned into a mess. Qatar did not fold as had been expected. There was no plan B. The instigators of the plan have now to fear for their head….

          On June 5 the four countries launched a boycott and blockade of Qatar. Three weeks later they issued a list of demands to Qatar which could be summed up as “surrender your sovereignty or else …”

          Qatar did not fold. It has hundreds of billions in monetary reserves, international support from its liquefied gas customers and allies, and it secured supplies and support from Turkey and Iran. It simply did not response to the “offer” in time for the ultimatum’s end….

          [Qatar] also announced that it would increase its liquefied gas exports by a third which threatens to take market share and income away from the Saudis. It reminded the UAE that 80% of its electricity supplies depend on natural gas delivered from Qatar….

          Today the Saudis, the UAE, Egypt and Bahrain met to discuss further consequences and new measures against Qatar. The Gulf media predicted more sanctions.

          But the gang of four decided to do … nothing….

          This is a huge embarrassment for the clown princes of the UAE and Saudi Arabia. They, Mohammad bin Zayed and Mohammad bin Salman, are the instigators of the campaign against Qatar. The meeting today had to deliver some penalty against Qatar for not giving in to any demand: some additional significant sanctions , a more intense blockade, some threat of military strikes. But the meeting came up with … nothing…..

          Such a huge loss of face will have consequences. When the Saudi clown prince launched the war against Yemen he expected, and announced, that Sanaa would fall within days. Two years later Sanaa has not fallen and the Saudis are losing the war. Qatar was expected to fold within days. But it has enough capital and income to sustain the current situation for many years to come. The war against Yemen and the sanctions against Qatar were indirectly aimed against Iran- the Saudis’ cpsen arch-enemy. But without investing even a dime Iran is now the winner from both conflicts. MbS, the Saudi clown prince, has twice proven to be a terrible strategist who endangers his country.

          • Glenn E Stehle says:


            These LNG price wars bode very well for energy poor countries who have to import most of their natural gas, like those in Europe and Asia.

            But for folks like me who would like to see higher U.S. natural gas prices, these events run counter to my economic interests.

            Nevertheless, these events are the facts, and going into denial mode about what’s happening would serve no purpose whatsoever.

          • Hightrekker says:

            “This is a huge embarrassment for the clown princes of the UAE and Saudi Arabia. ”
            I like it.
            But always have been a Billmon fan.

      • Glenn E Stehle says:

        From the article:

        In all resource markets, highest-cost producers have to curtail production first.

        Goldman Sachs observes the same phenomenon occurring with highest-cost producers in the global oil market.

        With the advent of the shale revolution, the cost to produce that marginal barrel has come down, leaving many high-cost projects uneconomical.

        ExxonMobil, for instance, wrote down 13% of its reserves, mostly Alberta sands, in February that are no longer economical to produce.

        Some of these projects have become so uneconomic, so stranded, that we almost don’t see any scenario under which they would be developed.

        Crude Awakening – Adapting to the New Oil Order: Goldman Sachs’ Michele Della Vigna


        • Glenn E Stehle says:


          • Dennis Coyne says:

            Hi Glenn,

            The largest 11 non-major (XOM, Statoil, and Conoco-Philips taken out of the mix) USLTO producers lost $62 billion from 2014 to 2016.

            Using data from


            The average monthly spot price for WTI from Jan 2014 to Dec 2016 was

            So I am a little skeptical that the marginal (most expensive) barrel from the LTO producers is $39/b.

            It might be $55/b or even $60/b, but $39/b would only allow the top 5% to 10% of wells to breakeven.

            • Glenn E Stehle says:


              Do you believe this might have something to do with those losses?

              • Dennis Coyne says:

                Yes Glenn,

                The low prices are a problem, that was my point.

                At and average oil price of over $60/b from 2014 to 2016 these 11 companies (which produced about 30% of US LTO over this period) lost money.

                Now we are supposed to believe the marginal barrel in the LTO plays is viable at $39/b (these would be the most expensive barrels to produce by the definition of marginal barrel.)

                Only a true optimist would believe those claims.

                I used to be one of the more optimistic people here (with the possible exception of Nick G and a few others).

                $39/b is the breakeven price for maybe 2% of LTO wells drilled in the US, and 2% is probably too optimistic.

                • Glenn E Stehle says:

                  Dennis Coyne said:

                  At and average oil price of over $60/b from 2014 to 2016 these 11 companies (which produced about 30% of US LTO over this period) lost money.

                  So is a company’s being a “top LTO producer” the cause of these losses?

                  For this to be true, then other private domestic oil companies that were not “top LTO procers” (that is, the “control group”) would need to have made money.

                  But they didn’t. Non-LTO producers also lost money during this time.

                  Whether a company was a “top LTO producer” or not seems to have little effect, since most all oil companies — LTO producer and non-LTO producer alike — experienced losses during this period.

                  Your argument is not logical.

                  • texas tea says:

                    if I may make a observation….those who hold “liberal” or if you prefer “progressive” views do not rely on facts or logic by definition😜

                    it is clear to almost all active and experienced observers that several large US LTO plays are now some of the worlds lowest cost of new oil.

                  • Dennis Coyne says:

                    Hi Texas Tea,

                    Well the fact is the largest 11 LTO producers (excluding XOM, Conoco-Philips, and Statoil) from 2014 to 2016 lost $62 billion.

                    I agree the cost of LTO is lower than some deep water and oil sands projects.

                    The claims that the marginal barrel (by definition those that are most costly to produce) in the LTO plays is $39/b is absurd.

                    The top 2% of LTO wells might have marginal costs that are that low. The average well is more like $70/b breakeven.

                    That is a fact.

            • Glenn E Stehle says:

              From the chart in the Rystad study, it’s pretty amazing to note that Chevron hasn’t even entered the fray yet, even though Chevron considers the Permian Basin to be the jewel in its crown:


              With approximately 2 million net acres of resources, Chevron is the Permian Basin’s largest net acreage holder.

              But that’s just the beginning of the story. TXL Oil Corporaton acquired the two million acres of mineral rights of the Texas Pacific Land Trust in 1954, Texaco acquired TXL in 1991, and Chevron acquired Texaco in 2002.

              Not all of that two million acres of minerals is located in the Permian Basin, but about half of it is. The Texas Pacific Land Trust retained a 1/16 non-participating royalty interest under some of the acreage, a 1/128 non-participating royalty interest under some, and no royalty interest under some.

              The bottom line is that of the two million net acres of resources that Chevron owns in the Permian Basin, approximately half is burdened with an extremely low royalty (0 to 1/16).

              Most of Chevron’s remaining acreage resources are leaseholds that date back to the 50s and 60s, and most of these are burdened with only a 1/8 royalty.

              The low royalties that Chevron has to pay give it an immense competitive advantage when it finally does decide to enter the fray in the Permian Basin, which it says will be very soon.

              Chevron’s 2017 budget includes about $2.5 billion for shale and tight investments, the majority of which is slated for Permian Basin developments in Texas and New Mexico.


              • Eulenspiegel says:

                Perhaps they wait a little bit, before slowly ramping up.
                At the moment worldwide oil investment is still on the way down, and demand still going up.

                A perfect time to ramp these up is when oil settles again > 60$ to make a good bit of money, not loosing money like most of the companies now. Perhaps while phasing out other fields to compensate it.

                • Glenn E Stehle says:

                  The performance of the Texas Pacific Land Trust stock certificates gives a glimpse of what investors believe is to come once Chevron begins drilling shale wells on its acreage.

                  The trust owns a 1/16 non-participating royalty interest under 377,777 acres of the Chevron acreage, and a 1/128 non-participating royalty interest under 85,414 acres. Most of the acreage is in the Delaware Basin, but a small part is in the Midland Basin. Another part is outside the Permian Basin.

                  When the Wolfbone play began in 2005 the stock certificates went from about $10 a share to about $40. But the big jump occurred in 2013 when the shale play began in the Permian Basin. Since then the stock went from $40 to $300.

                  So overall there has been about a 3,000% appreciation in the price of the stock over the last ten years. And Chevron hasn’t even began drilling shale wells on the acreage in any significant way yet.

              • Dennis Coyne says:

                Hi Glenn,

                Rystad’s breakevens are based on an unreasonably large EUR, they use about 533 kb, the average PXD well in the first quarter of 2016 might have an EUR for oil of about 425 kb, when natural gas is included and a reasonable well cost of 9 million, breakeven is about $50/b including natural gas and NGL sales. PXD has better than average wells, so these are to the marginal barrels.

                The average Permian basin well which started production in the first quarter breaks even at $60/b.

                • Glenn E Stehle says:


                  You do realize that the “E” in EUR stands for estimated?

                  If everybody agreed about future events, then there would be no horse races nor people willing to bet on them.

                  • Dennis Coyne says:

                    Hi Glenn,

                    We just call it a billion barrels per well then. 🙂

                    Yes I know the E is for estimate. There are good estimates (those that are reasonably accurate) and then there are those found in investor presentations which are about 32 to 3 times higher than a reasonable estimate.

                    If one makes an unreasonably high estimate it makes breakeven prices lower, but as a company loses money year after year, people start to question the veracity of the EURs that are claimed by the hucksters.

                  • Glenn E Stehle says:


                    The Rystad study is not an “investor presentation.”

                    And not everyone who disagrees with your ultimate recovery estimates is a “huckster.”

                  • Dennis Coyne says:

                    Hi Glenn,

                    Only the guys creating those investor presentations. It says in the fine print, don’t believe a word. 🙂

                    That’s why you don’t see these kinds of estimates in 10K, or 10Q SEC reports, those need to be truthful.

                    Rystad’s EUR estimates are not very good, especially because they give estimates for wells with very short output histories. One needs at least 11 months of output data to get a decent EUR estimate.

                    You accuse me of being speculative, I won’t guess what the EUR of the most recent wells will be. For wells which started producing the first quarter of 2016 the average Permian well has an EUR of about 350 kb. Those wells have 13 months of data so a reasonably good estimate can be made. Perhaps Rystad is using output from a couple of months to estimate 2017 EUR. Perhaps longer laterals (10,000 feet vs 7500 feet) might lead to higher average EUR, but we will need to see proof that this is the case, otherwise we would be speculating that EUR will rise by 33% to 467 kb due to longer laterals.

                    I do not have data on the average lateral length for 2016Q1 wells, only the average output data.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    That’s why you don’t see these kinds of estimates in 10K, or 10Q SEC reports, those need to be truthful.

                    Sure you see “these kinds of estimates” in 10-K reports.

                    How do you believe companies come up with their estimates of proved reserves, other than through a summation of EURs from the wells in their portfolios?

                    And of course you would assert that “Rystad’s EUR estimates are not very good.” If you were to claim otherwise, you wouldn’t be the faithful peak oil believer that you are.

                    Here’s a screenshot from Pioneer Natural Resources 2016 10-K, where one can see that they certainly do make reserve estimates.

                  • shallow sand says:

                    I have discussed this before and have read up on it some too. Notice PXD’s PUD reserves are very low.

                    Would appreciate some informed commentary on that.

                  • Glenn E Stehle says:

                    shallow sand,

                    If one goes to Pioneer’s 2016 annual report, page 31, one will find a section titled “Reserve Estimation Procedures and Audits.”

                    The first important thing to note is that Pioneer, as the annual report states, “does not provide optional disclosure of probable or possible reserves.”

                    The annual report goes on to state that:

                    Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility.”

                    Trimming “proved undeveloped reserves” down to only “undrilled acreage directly offsetting development areas” leaves a very small area. The result is very small numbers for proved undeveloped reserves.

                    The entire section on Reserve Estimation Procedures and Audits, which is three pages long, is a worthwhile read for those seeking insight into how companies and their auditors, under the aegis of the SEC, arrive at a company’s reserve estimates.

                  • shallow sand says:

                    Glenn. I have read that before. You will notice they use the word, “may”.

                    I do not think they even include most directly offsetting acreage. I think they, FANG and others are doing this because they do not want to start amortizing costs of acreage, etc, on the non-producing acreage they own anymore than they have to. For example, from memory, FANG has over $3 billion on the books that is not being amortized, which keeps down DD&A, which boosts earnings.

                    The above is what I suspect, but am glad to be corrected by someone who knows more on the subject.

                    Go to their estimate of future cash flows in the 2016 10K and see how much lower their estimate of future development costs (CAPEX) is than what they elsewhere state they are actually going to spend in the next five years.

                    This is the reason why I quit taking much stock in SEC PUD PV10.

                  • D coyne says:

                    Hi Glenn

                    Find me an EUR estimate for the average well in a 10k or 10q
                    And report back.

                  • shallow sand says:

                    PXD estimate of future development costs as of 12/31/2016, undiscounted, was $1.189 billion, with $603 million of that being undiscounted future retirement expenditures. That is for the next five years. So this seems to say they will spend around $100 million per year.

                    However, I think to ramp up to 1 million BOEPD by 2026 they need to spend over $2 billion per year on new wells alone.

                    Again, I assume the reason for leaving almost all PUD off the books is an election to defer recognition of amortization. But, again, I stand to be corrected.

                  • Glenn E Stehle says:

                    shallow sand,

                    Pioneer entered the Permian Basin shale play in 2012 with a 900,000-acre legacy leasehold position. Much of that acreage Pioneer acquired when it merged with Parker and Parsley in 1997, so I think that leasehold was depreciated out many moons ago. The rest of Pioneer’s legacy leasehold has producing wells on it, so the depreciation clock on that acreage also began a long time ago.

                    During 2012, Pioneer sold or farmed out 200,000 acres of its acreage in the southern part of the Permian Basin to a Chinese company. That left Pioneer with a leasehold of 827,000 gross acres (707,000 net) on December 31, 2012.

                    Pioneer ended 2016 with 800,000 gross acres of leasehold (690,000 net) in the Permian Basin. Pioneer has spent almost nothing on property acquisition since 2012.

                    I don’t think Pioneer’s Permian Basin legacy leasehold has much book value left to depreciate, and there’s very little new acreage to depreciate.

                    FANG I don’t know about, nor do I know what the current SEC rules are that regulate the depreciation of undeveloped acreage. Back when I was active in the oil business, we wanted to expense everything and depreciate everything as quickly as the IRS would allow, because we wanted the tax deductions.

                  • Glenn E Stehle says:


                    Can you tell me what the difference betweeen the EUR for a well and the reserve estimate for that same well is?

                • Glenn E Stehle says:


                  According to the Rystad data, the average lateral in the Permian Basin in 1Q2107 was 7551′.

                  “Recent drilling has increased lateral lengths to 13,000 feet, with Pioneer Natural Resources leading this effort.”

                  The result of “Pioneer leading this effort” is the average lateral of a Pioneer well in 1Q2017 was closer to 10,000′ than to 7,500′. So yes, the average 10,000′ Pioneer well in 1Q2017 did cost $8.5 million to drill, according to company reports.

                  But a 7,500′ lateral well only costs about $5.5 or $6 million to drill.

                  This habit of yours of taking the cost to drill a 10,000′ lateral well and using the average EUR for a 7,500′ well mixes apples and oranges, and results in misleading conclusions.

                  The devil is in the details.

                  • Dennis Coyne says:

                    Hi Glenn,

                    I use the 10Q to estimate the capital cost,

                    for Pioneer in 2016 if one takes the capital spent and divides by the completed wells we find about $9 million per well.

                    Also note that the cost is not necessarily proportional to the length of the lateral, it depends upon many factors. Also those who know the industry such as Mike, suggest $9 million is a good cost estimate as does the IHS study done for the EIA.

                    In 2017 PXD expects capital spending to be about $9.5 million per well completed.

                  • Glenn E Stehle says:

                    Dennis Coyne said:

                    Also those who know the industry such as Mike, suggest $9 million is a good cost estimate as does the IHS study done for the EIA.

                    “As does the IHS study done for the EIA”?

                    Try again, Dennis.

                    Here’s a link to the IHS study.


                    The study found that the average D&C cost for a well in the Midland Basin in 2016 was $6.5 million, and in the Delaware Basin $5 million. Averaging $6.5 and $5 we get $5.75 million.

                    For the Bakken D&C cost was $5.7 million, and for the Eagle Ford $5.4 million.

                    So now you’re down to your view from 30,000 feet above earth, or “those who know the industry such as Mike,” to justify the inflated well costs that you plug into your mathematical models.

                  • Glenn E Stehle says:


                  • Glenn E Stehle says:

                  • Mike says:

                    Mr. Stehle you have your head stuck so far up the shale oil industry’s ass you can’t probably see your toes. I thought you were an engineer, man? Don’t you have an ethical responsibility to be as unbiased as possible to the public? Your problem is you pick and chose what you want to link up to, and can’t think for yourself. Sometimes the EIA is overly pessimistic, sometimes optimistic, wrong or spot on, whichever you need for them to be. One month you puff up about all the free cash flow PDX made 1Q17, the next month they’ve impaired reserves and lost money. Which is it?

                    I’ve seen HPP tickets on 15M pound fracs, and cumulative well costs on daily reports, and all the things you weenie RI owners don’t have a clue about; frac’s alone cost $5.5M in W. Texas with water. Wells cost every bit of $9M out there. Well productivity is going down in the PB also, check it out; costs are going up and get this…so are interest rates ! That’s going to kill the shale business !! NOBODY IS MAKING ANY MONEY! Except you, of course. Free and clear of all costs.

                    I liked your E in EUR comment. Cute. That’s pretty much why most EUR’s are exaggerated x 2 as well, because people like you believe everything your told to believe and the shale biz knows it. Its why the meaningless metric of breakeven is as low as it is, as Dennis points out, that and that the shale oil industry leaves out all kinds of things in D&C costs. They put flowback water disposal costs back into CAPEX, a half million dollars of OPEX the first 6 months of well life (washing out all that 100 mesh crap) also back into CAPEX, after the fact; hide this and cover that.

                    Gawd I hope nobody believes your shit. I am pretty sure they don’t. You are clearly here only to cause disruption; please do not drag me into these debates. There is NO reason for ‘Mike’ to even come up.

                    Dennis, what happened to my X-Box, it failed. Hep !

                  • Glenn E Stehle says:


                    Free cash flow and earnings/losses are not the same thing.

                    And sure, the EIA has just as poor of a track record at predicting future shale production as Dennis does. But the fact that the EIA has such a poor track record does nothing to make Dennis’ dismal track record look any better.

                    As to well costs, I think I’ll go with comprehensive studies like those conducted by IHS and Rystad, and pass on your anecdotal evidence.

                    Granted, well productivity has gone down a tad over the past few months. As Rystad explains, this is because of “revived activity in the non-core parts of the basin.” Operators are stepping out into untested areas, drilling wells in non-core areas in hopes of finding new sweet spots. How, after all, do you believe the existing core areas were found in the first place, if not by drilling wells? And there still exist vast areas of the Permian Basin that have yet to be tested.

                    As to EURs, I think I’ll stick with the industry consensus, with the teams of engineers and scientists who have analyzed mountains of detailed well data to form their conclusions.
                    Count me out on the conclusions that a handful of dissidents with very limited information and knowledge, like the “expert consensus” here on POB, have come up with.

                    So sure, as to the charge that I “pick and chose” what I “want to link up to,” I plead guilty as all get out.

                  • Dennis Coyne says:

                    Hi Glenn,

                    You are leaving out average land cost and also G&A costs, and facilities for storing oil and handling water, all of this capital investment is part of the cost of a well.

                    So I am talking about full cycle cost, you are doing a point forward type of estimate which doesn’t tell the real story.

                    On page 100 of the report you linked to above, the Delaware wells have land cost of about $2 million per well and this increases with longer laterals, in Midland it was about $1.5 million per well for land cost. Figure 8-3 of the report shows wolfcamp wells cost about $7 to $7.5 million for drilling and completion, add the 1.5 to 2 million in land cost and we get about $9 million for the average Wolfcamp well.

                  • Glenn E Stehle says:


                    You don’t have the foggiest notion of what the average land cost in the Permian Basin is, because so much of the acreage is legacy leasehold.

                    And G&A costs are “capital investment”?

                    And money spent to build “facilities for storing oil and handling water… is part of the cost of a well”?

                    On page 100 of the IHS report that I linked above I find no mention whatsoever of leasehold cost or drilling and completion costs.

                    Dennis, where do you come up with all this stuff you write?

                • Mike says:

                  “Furthermore, there has been no shortage of capital to fuel the growth in shale oil production and this has allowed operators to significantly outspend their cash flows. The marginal economics of the typical shale oil producer have proven to be no impediment to the industry’s resilience. The breakevens referred to earlier are based on half-cycle economics. Full-cycle costs that cover land acquisition, infrastructure and overhead are probably almost $10 higher. But companies base their drilling decisions on half-cycle costs even if this leads them on the path to eventual bankruptcy (to which the shale oil industry is no stranger) so long as they have access to capital. It’s quite possible that shale oil production growth can only be reined in by the capital markets rationing the supply of funds as industry management seems to be more focused on growth than generating free cash flow or even paper profits.” Andy Hall, AUM

                  Updated July 7, 2017 4:57 p.m. ET
                  “Easy Wall Street cash is leading U.S. shale companies to expand drilling, even as most lose money on every barrel of oil they bring to the surface.” https://www.wsj.com/articles/wall-street-cash-pumps-up-oil-production-even-as-prices-sag-1499419801

            • Eulenspiegel says:

              The numbers are somewhat fishy – they tell these low breakeven numbers are in the core parts of their acreage, not in their acreage.

              So it’s something like drilling the best parts of the sweet spot – you can do that, but not all 40 billion barrel of permian is in a center of a sweet spot.

              Ok, if you throw away 80% of all acreage – then you have really low shale oil prices. But only for a few years, then the best parts are drilled, and the “bread and butter” wells have to keep on producing.

              • Glenn E Stehle says:


                The article alluded to that issue. To wit:

                Driven by a combination of high-grading, efficiency gains and service pricing, WTI breakevens decreased by almost 50% from early 2014 to mid-2016. Some reversion was observed in 4Q 16 and 1Q 17 due to the first evidence of growth in service costs and revived activity in the non-core parts of the basin. An average horizontal well in the Permian Basin exhibits a WTI breakeven price of 50 USD/bbl as of early 2017.

                Development in the Permian Basin is still in its infancy. The basin is so vast with so many stacked payzones that most of the Basin is still untested. New sweet spots are being discovered every day. But of course every time one drills a well in an untested area or zone, one runs the risk of drilling a less than stellar well.

                This is the great advantage Chevron has. Given its enviable acreage position, it can give farmouts on small parcels in areas where it has large acreage holdings and let somebody else take the risk of testing a new area. In this way it has complete access to all the well data. If the test is successful, then Chevron can go in and develop the offsetting acreage, emulating the successful techniques that were used to complete the successful test.

                • Glenn E Stehle says:

                  Here is a map of the Chevron acreage that the Texas Pacific Land Trust owns a non-participating royalty interest under. As you can see, most of it lies in the heart of the Delaware Basin, and testing on this acreage hasn’t even begun in any serious way yet.

                • Dennis Coyne says:

                  Hi Glenn,

                  How long have wells been drilled in the Permian basin?

                  • Glenn E Stehle says:

                    OK Dennis.

                    I should have said testing and development “of the shale plays in the Permian Basin is still in its infancy.”

                    Happy now?

                  • Dennis Coyne says:

                    Hi Glenn,

                    They are very familiar with the geology.

                    What has been learned in the Bakken and Eagle Ford, and Permian so far can be applied to “other areas” of the Permian.

                    I would assert that the petroleum engineers are smart enough to explore the most prospective areas first.

                    That there will be large resources in relatively undeveloped areas is unlikely based on past history in other LTO plays.

                    A cornucopian would argue otherwise of course, but I am not a pie in the sky guy.

                  • Glenn E Stehle says:

                    ••••Dennis Coyne said:

                    What has been learned in the Bakken and Eagle Ford, and Permian so far can be applied to “other areas” of the Permian.

                    Yes, that is true. But what you omit from your narrative is this, from Bloomberg via Rigzone:

                    Given the far-reaching impact of hydraulic fracturing, it’s easy to forget how young the technology is. The fractures, tucked thousands of feet below ground, remain a mystery, their dimensions only inferred through seismic measures and mathematical modeling. Explorers still don’t know how many fracture stages are optimal, or why some stages are more productive than others. The process has gotten better, but is far from efficient.


                    New and improved fracking technologies are being deployed everyday with results that are nothing short of amazing, but there is still much unknown, much to be learned and much room for improvement in the future.

                    ••••Dennis Coyne said:

                    I would assert that the petroleum engineers are smart enough to explore the most prospective areas first.

                    The technology for identifying sweet spots has improved, but is still far from efficient. In the real world the acid test still remains drilling and testing a well. Lady fortune, or the laws of probablilty, still rule.

                    If what you say was true, then why do you believe the oil companies drill so many stinkers when they are stepping out into new, untested territory?

                    Once agian, your arguments are an orgy of cognitive dissonance.

                  • Glenn E Stehle says:


                    And speaking of cornucopianism, when it comes to your abiding faith in the hallowed “energy transformation,” which may or may not ever happen, you certainly are “a pie in the sky guy.”

                    But when it comes to the shale revolution, you are a nattering nabob of negativism.

                  • D coyne says:

                    Hi Glenn

                    I disagree my expectations for an energy transition are pretty realistic.
                    They start with the premise that fossil fuel resources are limited and will become more expensive in the future.

                  • Glenn E Stehle says:



                    Fossil fuel resources have to “become more expensive” in the near future, right?

                    That’s why peak oil has to happen soon, so the high fossil fuel prices can ease the way for your hallowed “energy transformation.”

                    But oil prices are going down, not up. And they may stay down for a long time. This doesn’t bode well for your hallowed “energy transformation.”

        • Goldman Sachs knows nothing about the oil industry. They rely on consultants, and from the questions they ask we can tell not only are they ignorant, they don’t even want to learn. I’ve had telephone conferences with those guys in the past, and I had to boil things down to kindergarten grade for them. The same applies to all investment bankers I’ve ever met. To thus day I can’t understand why anybody would bother to read their garbage.

          Goldman Sachs does have a special place in the pantheon of evil, they have been financing the Maduro dictatorship at usurious rates using a runaround via a shady group called Dinosaur, I already wrote the FBI financial crimes unit to explain to them GS may be breaking the law with these financial moves.

          • Glenn E Stehle says:


            So do the engineers, scientists and management at ExxonMobil “know nothing” about the oil industry too?

            They wrote off 13% of their highest-cost reserves in February.

            And then in March ExxonMobil’s CEO, Darren Woods, had this to say about the Permian Basin, where “the diversified energy giant can make a profit even when crude prices are just $40 per barrel”:

            More than one third of the capex [capital and exploration spending] will be invested in advancing our large inventory of … short-cycle opportunities. They are primarily Permian and Bakken unconventional plays and short-cycle conventional work programs. This component of our investment plan is expected to generate positive cash flow less than three years after initial investment….

            A large chunk of those wells will make higher than 10 percent. … It’s a very prolific play. We’re very excited about the opportunity in the Permian….

            Our view on the oil price is there’s still a lot of uncertainty in the marketplace, so while we have seen prices go up in the short term, we’re not building our investment campaign based on the assumption those prices are going to be there forever. One of the advantages we have with this recent acquisition that we did in the Permian is we have a much bigger portfolio of short-cycle investments. That gives us the flexibility to move as the market moves, and raise our investment levels up to match what we see as opportunities in the marketplace.


            • Ves says:

              “So do the engineers, scientists and management at ExxonMobil “know nothing” about the oil industry too?”

              So “know something” management types at Exxon, Statoil, Shell bought all that beautiful oil sands at inflated $120 and sold ALL of that last year at $26 and you call that “knowing” !!!!!??
              They are in dark like everyone else.

              • Glenn E Stehle says:


                Do you believe this might have had something to do with ExxonMobil’s decision to write off its investments in the Alberta oil sands?

                • Ves says:


                  I have already answered to you that and you keep repeating the same argument. You don’t understand that market is zero sum game. Exxon, Shell, Statoil sold that beautiful oil sand. But to sell someone must buy that same beautiful oil sands. Do you understand that by looking just at the sale transaction you can not get absolutely any insight why someone is selling and why someone is buying? If you are CNRL, Cenovus, and Athabasca Oil sand that bought oil sands you could argue that they bought at the very steep discount. You like to interpret only your version of events based just on snippet of news of sale transactions.

                  • Glenn E Stehle says:


                    So then you believe ExxonMobil, Statoil and Shell sold these properties at below market value?

                    And the price of oil at the time, you don’t believe that had anything to do with determing the market value of the properties?

                  • Ves says:

                    You yourself said that you have received many offers in $100’s of thousands $ for what $38, $39 barrel at wellhead price in Permian at the moment? So what one has to do with other?

                    I don’t know if Exxon, Shell sold below market value. I say only that we, and you included, don’t know why they sold and why someone else bought.

                  • Glenn E Stehle says:


                    Let me try to explain.

                    Take the classic economic example of an entrepreneur who wants to make an investment. Let us say that he wants to build a factory that produces cotton goods. Let us further say that he is fully aware of all the costs – from the cost of the cotton-producing machines, to the raw materials, to the wages that the workers will need to be paid and so on.

                    Now he needs to weigh these costs against the amount of unit sales that he can make times the prices at which he can make these sales.

                    By subtracting the costs from the revenue he will be able to calculate his profit.

                    Finally, he can compare the profits that he will make to the investment that he has to undertake and decide whether he should do it or not.

                    For a royalty owner, however, there is no investment. All revenue is profit.

                    What you seem to be missing is the part about revenue being equal to “the amount of unit sales that he can make times the prices at which he can make these sales.”

                    For instance, a lease with unit sales (Barrels of oil) of 12,000 BO per year times a price of $100/barrel produces only a fifth as much revenue as a lease with unit sales of 120,000 BO per year times a price of $50/barrel.

                    I can’t see why this is so difficult to understand.

                  • Ves says:


                    My observation is this: “That total prices increase (Cost) are ALWAYS faster than total incomes when regarded as a flow .” If you look at top shale producers it is only exponentially increasing debt. And this is not just consequence in oil industry but the whole economy. So it is accounting problem. Society is forced to produce goods that consumers either do not want or cannot afford to purchase. We don’t need that marginally the most expensive oil, we don’t need millions of empty condos, we don’t need millions of unsold cars on a dealers lots and etc. etc.

              • Glenn E Stehle says:


                And did you miss this part of Woods’ comments?

                Our view on the oil price is there’s still a lot of uncertainty in the marketplace, so while we have seen prices go up in the short term, we’re not building our investment campaign based on the assumption those prices are going to be there forever. One of the advantages we have with this recent acquisition that we did in the Permian is we have a much bigger portfolio of short-cycle investments. That gives us the flexibility to move as the market moves….

                There’s a new oil order out there brought about by the shale revolution, which ExxonMobil and a lot of other folks are attempting to adapt to.

                Adapting to the new oil order is a painful process for those heavily invested in the old order, but do you believe going into denial mode helps in the adjustment process and behooves one’s economic interests?

                • Watcher says:

                  My comments are more sophisticated than Woods.

                  Exxon sold to fund its dividend.

      • Glenn E Stehle says:

        From the article:

        After five decades of least-cost domestic gas supply, industry is showing an inability to now supply gas at even export price parity, putting the government under ever-increasing pressure to intervene and secure remotely affordable energy supplies for both residential and industrial consumers.

        The various solutions proposed by the industry—producing more gas at Narrabri, fracking in the Northern Territory, opening an LNG import facility in NSW or even supplying the East Coast with a prohibitively long and expensive pipeline from Western Australia—are all uneconomic. The gas supplied under such proposals would be at a price above the world’s most expensive market, Japan. Producing expensive wellhead gas and then adding expensive pipeline charges is no way to bring down the domestic price of gas.

        Accounts of the market published by the oil and gas industry in Australia lack integrity.

        MacroBusiness is one of the most virulently anti-fossil fuel publications around, so this sort of commentary is to be expected.

        Omited from the MacroBusiness narrative, however, is the fact that the natural gas industry in Australia has been hogtied by government intervention and regulation:

        Vic bans fracking as legislation passes

        Australia steps up gas fracking bans despite supply crunch | Reuters

        Coal seam gas: Further fracking bans could lead energy price hike, shortages, industry says

        And sure ‘nuf, regulating natural gas producers out of business led to higher natural gas prices.

        Who wudda ever thunk it?

        But of course, according to MacroBusiness, the high natural gas prices are all the fault of those evil oil and gas producing folks.

        • Glenn E Stehle says:

          Power shock escalates

          Market trader and analyst Global-ROAM has described the price surges as “gut-wrenching” for energy users in states such as Victoria, where the average price broke the $100 a megawatt-hour barrier.

          That’s up a painful 64 per cent from the second quarter last year, which the analyst notes was already historically high….

          The change in the market is extreme, even in comparison with the already-startling prices seen in the June quarter last year and in the 2007 drought conditions, says McArdle, who describes the pattern as “mind-blowing”.

          As of today it has, if anything, gotten worse with July wholesale prices averaging in QLD 72.94/MWh, NSW 87.13/MWh, VIC $128.34/MWh, and SA $129.88/MWh.

          • coffeeguyzz says:

            Those prices are wildly unsustainable for any country hoping to function on routine 21st century protocols.

            Either our Aussie friends get their power industry on track or say goodbye to things like refrigeration, air conditioning, reading after sundown, workable hospitals, etc.

            • Dennis Coyne says:

              Hi Coffeeguyz,

              Those are Australian dollars worth about o.76 US dollars. So in US$ we are talking about 9 cents per kWhr for $120/MWhr in Australian $, some places in the US have prices higher than that (New England and New York peak electricity prices.) The peak price in Texas over the past 12 months for wholesale prices (May 2016 to April 2017, latest EIA data) was about $75/ MWhr. Just a bit less than the Australian price of $90/MWh (US $).

              • Glenn E Stehle says:


                Comparing momentary peaks in wholesale prices to monthly or annual average wholesale prices is not a true comparison.

                If you’re interested in comparing apples to apples, here’s a chart of Texas montly average wholesale prices. As one can see they range between $15 and $40 per MWh, with an average of about $27 per MWh.

                • Glenn E Stehle says:

                  And what the consumers see are not wholesale prices, but retail prices.

                  Here’s what those look like for the different jurisidictions in Austalia in 2016-17.

                • Glenn E Stehle says:

                  And it looks like those 2016-17 prices are set to go much higher in some jurisdictions this year.

                  South Australia power prices to rise to highest in the world on Saturday, energy expert warns

                  “South Australia will overtake Denmark as having the world’s most expensive electricity when the country’s major energy retailers jack up their prices this Saturday [July 1, 2017]….

                  Bruce Mountain, the head of a private energy consultancy firm, said the increases would see South Australia take the lead on world power prices….”

                  Dennis, you can try to put lipstick on that pig all you want, but there it is.

              • coffeeguyzz says:


                Glenn addresses the distinction between brief spikes versus systemic pricing.
                The wholesale price in Boston one day in May exceeded $800/Mwh, but this was an anomaly and ‘filtered in’ over a monthly or longer time frame for customer billing.

                This is why the underlying framework is so crucial.
                Having reliable, copious amounts of electricity from numerous sources enables unexpected or temporary glitches to be handled effectively.

                If, in fact, Australia has entered a situation of extended, high cost power generation, their economy will suffer greatly.
                New England is not there yet, but they are heading in that direction.

                • coffeeguyzz says:

                  Now you guys got me curious so I just pulled up the real time, spot wholesale electricity price/demand for Australia. aemo.com.au.
                  The ‘dashboard’ tab has the realtime data for the different regions.
                  Big differences throughout the country.
                  Looks like Victoria and South Australia are paying about A$115/120 per Mwh midday Saturday with spikes expected in the 250/300 A$ range early next week.

                  Dennis, I don’t care what currency you choose to use, that’s mucho dinero to keep the lights on.

                  • Dennis Coyne says:

                    Hi Coffeguyzz,

                    The average for the month is much more relevant in my opinion.

                    High prices are how scarce resources are allocated.

                  • coffeeguyzz says:

                    Current spot price for South Australia wholesale electric is $141 (Aussie bucks, Dennis) and going only higher, by the looks of it, over the next 24 hours, at least.

            • Glenn E Stehle says:


              Not to worry.

              Saint Musk is coming to our Aussie friends’ rescue. He will slay those evil fossil fuel devils.

              South Australia has announced Elon Musk’s Tesla as the principal builder of the world’s largest lithium ion battery to expand the state’s renewable energy supply.

              The company’s battery boss says SA’s power woes can be solved in 100 days….

              The mega-project will be built in conjunction with French renewable energy firm Neoen and paired with Neoen’s existing wind farm at Hornsdale north of Adelaide.

              From the COMMENTS section:

              • “Good,” said Arrow2. “A nice little unintended consequence for those who are gaming our electricity market by exploiting our reliance on coal and gas.”

              • “The economics means nobody on the planet will build a new coal power plant ever again,” says Ronin8317.

              • “THAT will stop the gaming,” says Tassie Tom.

              • And The Traveling Wilbur proclaims: “Victory is nigh!


              • Caelan MacIntyre says:

                I recently saw the new Wonder Woman movie. Perhaps we can tell a lot about cultures by their myths/stories in general and the myths/stories of their elites. I wonder who invented the Greek gods, or statistical anomalies about the oil patch.

                In Wonder Woman’s case, she transcended simple superhero into more of a demigod than others, (in her case, fighting, all the way from Hollywood, along with so many others before her, constructs of WW2 Germans and their ‘demonic-demigod[s]’).

                In any imagination, Wonder Woman could probably power, long-post-peak oil, a small town if we threw her on a hamster-wheel pump or heater to melt salt, and Spiderman could take care, at the very least, of all the town’s clothes if we threw him a loom, a sewing machine and some free tailoring lessons.

                But there’d be the problem of energy, etc., slavery, so it would have to be willing.

                Jame Bond’s problem for humanity would be less about any near-demigod-like powers, save for the tech kind, and more about a simple ideological transformation from the ethically-dubious brainwash of serving for ‘His Majesty’s Secret Service’ and ‘her’ relative monopoly on violence, to actually serving humanity and the rest of the planet.

  3. Guy M says:

    Not sure if it means anything, but the totals for Texas were put out about 6 days later than normal. I have been able to find total Texas production on the Statewide query by the 17th of the month. Give or take a couple of days. April’s production was not available until the 24th in June.

  4. Dennis, if you run a six month average for conventional production you should see it is declining slightly, at about 2-3 percent per year. This makes sense because that production is very old, and the level of activity at $50 per barrel should not be able to keep production from declining.

    I guess the future of the LTO in Texas will depend on whether oil prices go above $55 or so. The bulk of the wells to be drilled aren’t viable at $50.

    • Dennis Coyne says:

      Hi Fernando,

      If I look at a short period (past 8 months Sept 2016 to April 2017) I get about 3%/year exponential decline, but the R squared is quite low at 0.16. If a longer period is considered (Nov 2014 to April 2017) we see a 6.65%/year exponential decline rate with a higher R squared of 0.92. A six month plot gives a 2% annual decline rate with R squared of 0.03, so I would call it flat for the past year or so.

      Chart with longer period of natural log of TX conventional C+C output vs year below.

      • Dennis Coyne says:

        Hi Fernando,

        Over the past 11 months the annual decline rate has been 1%/year, but again a low R squared of 0.046.

        I agree that at an oil price of $50/b Texas conventional output may continue its decline, possibly at the longer term rate of 6.6%, but your 3% annual decline rate estimate is likely better imo.

        • Guy M says:

          What are you considering conventional production? Is it all vertical wells? The tens of thousand of low producing, low EUR wells they drilled prior to 2016?

          • Dennis Coyne says:

            Hi GuyM,

            Total Texas C+C output minus Permian basin LTO output minus Eagle Ford output is how I got the estimate for Texas conventional output.

            Through Feb 2017 I use EIA tight oil estimates for the Permian and Eagle Ford, then I subtract the estimate of New Mexico Permian output at shaleprofile.com.

            • Guy M says:

              Yeah, I understand it is not easy with RRC data. It is interesting to look at district 8A data from about June 2014 to compare to current production data. There is about a one million one hundred thousand per month drop. More drilling has been done with verticals, and a lot less horizontals. With a reduced number of verticals, there is about a 12% drop in total production. They did not, by any means, stop drilling. They only drilled less vertical wells than they were drilling before. Isolated, only one district, but the decline rate looks pretty substantial.

              • shallow sand says:

                From my review of production data it is difficult to determine what is conventional and what is unconventional in the Permian Basin. Operators are still drilling vertical Wolfberry wells on leases where there are also horizontals. Operators are also drilling horizontals in shallower sandstone formations such as the San Andres. Add to that reporting on the lease level in TX, it is not easy to quantify production.

                • Guy M says:

                  I agree totally. The question in my mind is the current activity enough to prop up the conventional oil drop when it does start going away. My understanding is that it wasn’t a comparable conventional field to what they had in the Permian years ago. It had dropped off to the point that a lot of verticals had to be drilled to prop up production. That was when it was less than a million barrels a day prior to 2010-2014. There was a lot of drilling verticals from 2010 to 2014, which made the majority of Texas wells during that period. I am guessing maybe 30k or more. Now, it is way down. Comparing apples to oranges is pretty difficult when you can’t see, smell, or touch them.

                • Glenn E Stehle says:

                  shallow sand,

                  I don’t know of anyone still drilling vertical Wolfberry wells. They needed $100/barrel oil to make the economics work, so that play came to a screeching halt post-2015. The sunk investment that Permian Basin operators have in these high-cost wells, however, will continue to be a drag on their financial statements for a long time to come.

                  Pioneer, for instance, took a $285 million impairment against its oil and gas properties in 1Q2017, which caused it to show a $42 millon net loss during the quarter.

                  I think Pioneer operates about 5,000 of these wells. With the benefit of hindsight, they were not good drilling investments, but the leasehold proved to be extremely valuable with the advent of the shale revolution.

        • We know that “conventional” production has to decline. The decline is softened by drilling additional wells and injecting whatever they can dream up. And I don’t think drilling more wells makes sense at $60. We need some sort of new technology, like generating pressure pulses, to shake oil loose from those rocks.

  5. Lightsout says:

    This is the latest update from the fractured test well drilled in the HRZ shale on the north slope of Alaska. It has flowed back 15% of the frac fluids in 2 weeks.

    Flowback operations continue, with fluid composition comprising 100% water. A recent increase in salinity of the recovered fluid possibly indicates that some in-situ reservoir fluid is starting to flowback.

    The forward plan remains unchanged and may include shut in for pressure build-up and soak and/or artificial lift to increase the rate of stimulation fluid recovery.

    Question to the shale guys on here does this read as good or bad news for successful flow rates?

    • Guy M says:

      No idea, they don’t do two wells at a time. Usually frac is finished and they test soon after. They did two horizontals, right? At over 11k feet? The real answer is that it will take a while to know anything. Pearsall shale did magnificent, at first, mostly died out in the first month.

    • Mike says:

      Lightsout, thanks for the 2nd update. I am following this well the best I can also. It was clear the need to drill out the frac plug below the top perforations immediately after frac’ing was not good, nor were the corresponding pressure differentials. Increasing Cl’s is not good and this update; not good either. Continued statements made regarding the need to put the well on AL; not good. Induced frac energy is pooping out without hydrocarbon shows; not good. The remarks about having to recover 30% of frac fluid before shows of hydrocarbons occurred; not good. They would have been looking for much better results from a vertical “pilot” well to justify the drilling of a HZ well. It could still turn around, but I doubt it.

      Its just the oil business. This will be one of countless unconventional shale play ideas lots of people have hung their hardhats on that did not work out; does not look like it. This list is long. They’ll throw more money at it and it still might be productive, which is NOT the same as profitable. Some seem really confused about that around here.

      • Lightsout says:

        Thanks for the reply I am no expert but I have drawn the same conclusions as you. I was actually invested in the company prior to the drilling of the first well. I got a good return but the share price at one point rose 100 fold and a lot of unwary investors got dragged in.

        As I am sure you know the guy behind it has a good pedigree but they are making some extraordinary claims about vapour phase oil and super highways. The figures touted for this vertical well is that they expect 100-150 barrels per day.

        All the updates and announcements are available here.


        • Mike says:

          Please keep us informed; its an interesting idea for a number of reasons. I did a bucket frac (small) on a 60 foot section of Eagle Ford shale once, vertical well, back in 1981. Waste of money. But we all know what happened 30 years later.

          Thank you.

          • Lightsout says:

            Mike / Fernando

            Is it standard practice to use a choke when flowing back frac fluids and if so could this account for the low recovery rate? Or is it more likely the shale is simply lacking pressure.

      • I’ve worked in remote areas, one trick I used with success after a bum acid frac was to surge the well with an enormous pressure differential, and cross my fingers. I ran nearly empty 4 1/2 inch with a valve and opened that sucker. In one case the well had been barely breathing, and it came in at 8000 BOPD. Another option is to inject a high volume of nitrogen. But I assume these guys have to fly that N2 in by helicopter?

        In any case, that well was screwed up. They probably need to drill again next year.

        • Lightsout says:

          Hi Fernando

          They drilled it from the Franklin bluffs gravel pad a staging point on the side of the Dalton highway. This is the main reason why it got drilled. It is a vertical well and had a 2 stage frac job in the upper and lower section of the HRZ shale. They have stuffed one million lbs of proponent down there so it has been given every chance.

  6. Boomer II says:

    OPEC can’t save oil market alone—the U.S. has to step in, says Morgan Stanley – MarketWatch: “’If OPEC doesn’t balance the market, the oil price will have to force it somewhere else, most likely in U.S. shale. For a chance of a balanced market in 2018, the U.S. rig count can no longer grow and possibly needs to contract ~150 rigs. Given current break-evens, this requires WTI between $46-50,’ the Morgan Stanley analysts said in the report.”

  7. Oil’s Game Of Chicken: Can OPEC Finally Bankrupt U.S. Production?

    If you missed it, you should read FGE Chairman Fereidun Fesharaki’s note on this dynamic because it’s pretty amusing. Here are a couple of choice excerpts:

    “The rise in U.S. tight oil production is close to madness. It’s effectively a path to self-destruction [and] it is apparent that the downward pressure tight oil producers are generating will not stop until they are seriously crippled by their own actions in a world of lower prices around $30-$35/bbl.

    Junk bond spreads are already beginning to widen, which is a sign money may soon start drying up; within a year, massive restructuring, many bankruptcies will follow.”

    • Watcher says:

      Or they’ll find other lenders, amorphous or otherwise.

      If you have to have it, and you DO have to have it, you’ll get it.

      • Crock of shit Watcher. Lenders are not lemmings and they are not stupid. If there is no chance of even getting your investment back, lenders will not just magically appear, handing over their money, knowing they are very likely to lose it.

        Every day, throughout this nation, businesses go bankrupt. They go bankrupt because they just HAD TO HAVE IT. But alas, they just could not get it.

        • shallow sand says:

          Ron. There have not been many liquidation bankruptcies in the US E & P space up to now, at least with regard to the large publicly traded companies.

          Companies such as HK and SD kept right on drilling, despite both shareholders and bond holders taking some serious haircuts.

          We are in an era where certain businesses can hemorrhage cash for years, if they are large enough and in the right industry. Mom and pop cannot do that, therefore it makes it difficult for mom and pop to compete. Mom and pop go BK, almost always going to be a liquidation.

          • Boomer II says:

            But if the gas and oil industry falls out of favor, which it appears to be doing, you will have trouble finding lenders and investors.

            If lenders and investors are going to throw money at unprofitable companies, they either want something that they can turn around and sell to the greater fool, or they anticipate that these companies are going to grow so big in the future that they want to be in on the ground floor.

            Market psychology just doesn’t favor fossil fuels right now and perhaps it may never again view fossil fuel companies as good investments.

        • Watcher says:

          I think you missed amorphous.

  8. Glenn E Stehle says:

    Are Northeasterners Really So Anti-Pipeline?

    According to New England’s independent system operator, the region’s gas-fired electricity capacity has surged from 18 percent in 2000 to 45 percent this year. By 2025, that figure is expected to hit 56 percent with the retirement of older nuclear and oil- and coal-fired power stations.

    Despite its close proximity to the Marcellus and Utica shale formations, New England currently sources much of its natural gas from the Caribbean via something that’s become rather quaint since the onset of the shale revolution: a liquefied natural gas (LNG) import terminal in the United States. Shipping domestically produced natural gas via pipelines is cheaper than importing LNG, but stiff government regulatory hurdles and strident opposition from “green” activists have limited pipeline companies’ progress in expanding gas infrastructure in the region. Two such growth projects that have been targets of pipeline opponents include the Access Northeast and Constitution projects.

    A recent survey by the Consumer Energy Alliance (CEA) casts doubt on the notion that opposition to pipeline growth in the Northeast is far, wide and deep. Some conclusions from CEA’s poll of more than 500 voters in Connecticut, Massachusetts, New Hampshire and New York include:

    • 97 percent of respondents believe having affordable, reliable energy is important for the region’s families and businesses

    • 92 percent agree that maintaining and delivering adequate supplies of affordable fuels is a necessity
    88 percent agree that having sufficient natural gas supplies is important in keeping electricity and home heating affordable and reliable

    • 76 percent support “generating electricity using natural gas and fuels”

    • 58 percent approve of “expanding pipelines to deliver transportation fuels for consumers and markets”

    “The truth is, as this polling shows, people recognize the need for pipelines and support the maintenance and expansion of our energy infrastructure,” Brydon Ross, CEA’s vice president for state affairs, told Rigzone. “The region needs additional supply to help alleviate issues on high demand days and address the area’s exorbitant residential and industrial electricity costs – which are the highest in the continental U.S.” ….

    “In reality, it’s a small but very influential set of opposition voices that are setting and determining the economic future and trajectory for an entire state and region,” he said. “At the end of the day, the polls are confirming what we all intuitively know – we need this critical infrastructure and the public not only wants it maintained but expanded.” ….

    “The rise of the professional protester has really changed things across society.”

    • coffeeguyzz says:

      Data points

      Ten year average wholesale price for New England power was $59 per Megawatt hour.
      2016 price was $35/Mwh.

      While the environmentally sensitive folks are being told this is due to effective conservation, the reality is the price drop stems from the massive rise in cheap, highly dispatchable natgas fueled electricity.

      Consequences …
      Gigantic nuclear powered plant in Connecticut – Millstsne, capacity 2,000 Mw – can no longer continue to operate while receiving such low prices for their product.
      Just as in other states such as New York and Illinois, the nuke plant owners are seeking subsidies to stay in business.
      Although highly improbable, should Millstone stop producing in the near future, those poor bastards in NE will be lighting bonfires to keep warm.

      • Glenn E Stehle says:


        What households, industry and businesses see, however, is the retail price. And there has been no relief on this front in New England and New York as there has been, for instance, in Texas.

      • Watcher says:

        Don’t worship at the altar of supply and demand.

        Maybe public service commissions denied rate increases and dictated decreases. How can you imagine an industry controlled by PSCs to have any aspect of free market associated with them.

        • coffeeguyzz says:


          Two things …
          The utility commissions DID okay electric rate increases so as to provide funding to build natgas pipes. This gas supply could then be purchased by independent power producers who would provide electric utilities cheap, gas-fueled electric power for decades to come.
          The courts slapped this down on legal grounds.

          Second item … supply.
          Without sufficient pipeline to deliver natgas, there is simply not enough natgas delivered to New England (about 4.5 Bcfd right now) to both heat and power NE during cold winter spells.

          This supply issue seems to have similarities with the Australin situation and may be a harbinger of what’s to come up there.

          • Watcher says:

            Missed the point. The PSC determines price. Period.

            • coffeeguyzz says:

              PSC determines RETAIL price.
              Market determines WHOLESALE price.

              Exclamation point.

              • Watcher says:

                Dood what is that.
                A utility buys from another? That’s not a free market either. One supplier and one customer, besides which all your quoted rates are PSC defined.
                You have no leg to stand on here. You’re using PSC pricing to support claims. Obviously bogus.

                • coffeeguyzz says:

                  Wholesale prices in New England are set a day ahead of time with the electricity generated by private companies using various fuels to make the juice.
                  Spot prices are in live, 5 minute increments, to provide additional juice above the previously sold (day ahead) amounts.
                  The non profit outfit that manages this in NE is the ISO.
                  In northeast , it is PJM.
                  Throughout US, other Regional Transmission Operators manage the market at these wholesale levels to ensure the smooth flow and availability of juice at the lowest cost.

                  Downstream of all this are the local utilities, highly regulated by PSCs.
                  The local utilities have no control over upstream pricing.

                  • Watcher says:

                    On tablet, not sure of indentation. I didnt see anything about supply and demand in that text, only references to group(s) *managing* the process, which doesnt sound very laissez faire.

                    You also face the challenge of explaining why utilities collecting flat 14 cents/kwhr but paying a slashed wholesale price didn’t accumulate more money than the NY Fed over that period. Why didn’t their stock price explode?

          • Dennis Coyne says:

            Hi Coffeguyzz,

            So if there are problems, flexible pricing will be introduced. Where I live in New England this already applies to residential natural gas for heat, the price rises during colder months (Jan and February). So I burn some wood during those periods and those that cannot may turn their thermostat down and where warm clothes indoors.

            If it becomes a problem the laws will be changed (Massachusetts is currently the main problem) so that the cost of new pipelines are passed through to electricity consumers. Also the electricity can be moved from areas with better access to natural gas to New England, until New England sorts this out.

            When a crisis occurs, the laws will change.

            To my knowledge this has not been a problem so far, some states are willing to pay higher electricity rates (New York and the New England States). If they were not they would elect representatives who would change the laws.

            • coffeeguyzz says:

              What you have described is essentially correct.
              The increasing reliance upon natgas to provide NE electricity is not being matched by increasing natgas supplies.

              That is the crux of the situation.

  9. Boomer II says:

    Since we are talking LNG.

    Gulf Coast LNG boom may become bust for some – Houston Chronicle: “Energy companies are building or have proposed so many export terminals, they can’t all be successful, said energy research firm Wood Mackenzie. At full build-out, LNG capacity could quadruple current production.

    ‘The numbers proposed far exceed what the world realistically needs’ said Alex Munton, WoodMac’s principal analyst of LNG in the Americas. ‘They can’t all go ahead.’”

  10. Glenn E Stehle says:

    EY Study Decodes Oil, Gas Perception Challenges in Young People

    A 2017 study by EY, which polled 1,200 U.S. consumers ages 16 and older, revealed a few harsh realities. Namely, young people aren’t interested in working in oil and gas….

    For starters, young people perceive “oil” less favorably than other fuel sources, such as renewables and natural gas. According to the study, just 25 percent of Gen Z have a positive perception of oil and only 40 percent have a positive perception of natural gas. However, 77 percent have a positive perception of renewable energy (wind, solar, etc.)….

    Seventy-one percent of teens believe renewables are the fuels of their generation, while 56 percent believe oil and gas are the fuels of their parents’ generation. So while oil and gas works for now, young people believe cleaner energy resources will replace it in the future….

    “Young people think future energy will be solar, wind and other renewables; therefore, they’re not looking for positions in oil and gas as a career,” said Rachel Everaard, EY’s US oil and gas people advisory services principal….

    The study also reveals a disconnect between how younger people view the oil and gas industry and how oil and gas execs think young people view the industry.

    Just 59 percent of Gen Z believe the industry uses advanced technology, 55 percent believe the industry offers opportunities to travel and 47 percent believe the industry offers opportunities for growth (stark comparisons to how executives responded: 91 percent, 95 percent and 90 percent, respectively)….

    Only 44 percent of teens aged 16-18 believe oil and gas is a leader in technology. But 83 percent of energy executives believe the oil and gas industry does a good job on leveraging innovative technology.

  11. Watcher says:

    We should be only hours or days away from data revisions indicating supply was not declining or consumption was not increasing. Why should they revise? Because price didn’t do what they wanted.

    • Watcher says:

      Right on cue. BofA generic mouthpiece says the US summer driving season is a bust.

  12. Energy News says:

    Houston Chronicle – Collin Eaton – July 6, 2017
    Oil companies are shelling out more cash and signing long contracts for a limited supply of monster rigs that drill wells much faster than the older models that led the U.S. first shale boom.
    “Every single one of the super-spec rigs that can work is working today,” James West, an analyst at investment bank Evercore ISI in New York, said in an interview. “Now we’re seeing that exploration and production companies can’t get these rigs if they don’t sign contracts.”

  13. Survivalist says:

    Renewed slide in oil price will test U.S. shale profits: Kemp


    …. Harold Hamm, chief executive of Continental Resources, a major producer in North Dakota and Oklahoma, has said oil prices need to be above $50 to be sustainable.

    Prices below $40 would force producers to idle rigs again, he said in a recent interview (“Harold Hamm warns oil prices below $40 will idle U.S. drilling”, CNBC, June 28).

    The renewed drop in oil prices, unless quickly reversed, looks set to put these conflicting claims to the test.

    • Glenn E Stehle says:


      All that sunk investment that the oil companies carry forward from an era of $100/barrel oil is like a lead weight tied around their foot. It will weigh down on earnings for many moons to come.

      From the article you linked:

      Fifteen independent producers with operations focused on the United States reported a combined net loss of $3.7 billion in the first three months of 2017 (tmsnrt.rs/2uxKwbb).

      But most of the losses were attributable to Marathon Oil, which reported a net loss of $4.9 billion, mostly as a result of an impairment charge linked to its Canadian oil sands businesses.

      The other fourteen companies in the sample reported total net income of almost $1.3 billion, up from a loss of $9.9 billion in the first quarter of 2016.

      Ten companies in the sample reported positive net income during the first quarter, up from just two in the previous quarter and none in the first quarter of 2016.

      Financial performance for the companies in the sample has been steadily improving since losses peaked at $23 billion in the third quarter of 2015.

      Shale producers have benefited from a combination of cost reductions, improvements in drilling efficiency and well productivity, and a significant increase in oil and gas prices.

      • Watcher says:

        I just went and looked at the Q1 earnings of the companies listed.

        (all these 15 of graph are from finance.google.com)

        CLR -$0.56 /share yahoo has -$.54
        APA -$2.08/share
        APC -$4.44/share confirmed on yahoo
        CHK -$5.03/share -$33 on yahoo
        CXO +1.13/share
        DVN +1.00/share
        EOG -$1.08/share yahoo confirm
        HES -$19.12/share
        MRO -$2.10/share
        NBL -$1.57/share yahoo confirm
        OAS -$0.85/share yahoo -$0.77
        PXD -$2.01/share
        RRC -$1.56/share
        SWN -$2.91/share yahoo -$2.83
        WLL -$4.63/share

        “Ten companies in the sample reported positive net income during the first quarter, up from just two in the previous quarter and none in the first quarter of 2016.”

        Okay, I went and double checked google with yahoo for 6 of the listed companies. Not all 15 because my time is valuable. Only 2 had positive earnings for Q1 (Q2 just ended and usually don’t report for a month). Someone may have manufactured a definition of some bullshit “positive net income” to be something other than EARNINGS, but otherwise reality is right there in front of you. The industry is in freefall, losing money hand over fist.

        Believe no articles. Period. They have agenda. I noticed the source of the graph lists JKempEnergy. Imagine that.

        Look the stuff up.

        • Glenn E Stehle says:


          It looks like the Reuters reporter was relying on GAAP earnings.

          Many analysts, such as those at Google and Yahoo, don’t use GAAP earnings for their analyses, because they don’t believe they give a true forward-looking indication of a company’s performance. They therefore create their own pro-forma earnings figures, based on their own opinions.

          So if we go have a look at, for example, CLR’s 1Q2017 10-Q, what we see is that it had positive net income of $469,000 for the first quarter of 2017. (See attached screenshot from CLR’s 1Q2017 10-Q).

          The bottom line is that CLR showed a positive net income for 1Q2017, regardless of Google’s claim that it lost $0.56 a share and Yahoo’s claim that it lost $0.54 a share.

          So by all means, “Look the stuff up.”

          • Watcher says:

            Why are you posting unaudited data?

            dood look at the earnings. Only 2 have earnings and I should go scope them out, or you should, because they probably have some special situation (maybe a gain on ancient acreage sold) that got them positive earnings. It’s probably they who are special circumstance, not the losses.

            • Glenn E Stehle says:

              Watcher said:

              Why are you posting unaudited data?

              So the data that companies report in their SEC filings is not credible and reliable data?

            • Glenn E Stehle says:

              Watcher said:

              ….because they probably have some special situation (maybe a gain on ancient acreage sold) that got them positive earnings.

              But far more likely, given the current oil price environment, is that they had “some special situation” that made their earnings less, or even negative.

              For example, CLR wrote off $51,372,000 in impairments against its properties during 1Q2017. PXD wrote off $285,000,000. And as Reuters reports, Marathon had a whopping $4,907,000,000 income loss from discontinued operations.

    • Glenn E Stehle says:

      Since there is so much back and forth on this forum about positive net income and losses, it’s worthwhile to reproduce the Reuter’s graph here.

      • shallow sand says:

        Q2 will be interesting. Will this group’s losses continue to shrink, or will lower Q2 oil price reverse the trend?

  14. Hickory says:

    Texas brings us brilliant national energy policy-
    Rick Perry (US Energy Secretary courtesy of a-hole Trump), on coal-
    “Here’s a little economics lesson: supply and demand. You put the supply out there and the demand will follow,”

    • Watcher says:

      Doesn’t seem worthy of smirk. No real difference from “buiid it, they will come.”

      Maybe there will be magical storage like with oil.

    • Schinzy says:

      Actually I agree with Perry, though there are nuances I don’t think he understands. I think the feedback loops leading to increased production have been stalling and might have started to go into reverse. We will see.

  15. BlueTwilight says:

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

  16. Dennis Coyne says:

    Hi George Kaplan,

    Check e-mail please.

  17. Dennis Coyne says:

Comments are closed.