Texas Oil and Natural Gas Update- Sept 2016

D Coyne Uncategorized

TXchart/

Dean has provided his monthly update for Texas Oil and Natural Gas.  The most recent month’s estimate is often volatile and may be ignored, the June and May estimates are likely pretty good (within 1% and 2%), the April 2016 estimate is likely to be robust(within 1% of the final value). The June EIA estimate is 240 kb/d lower than Dean’s estimate (about 7% too low).  The numbers above the lines are for Dean’s estimate and the numbers below the lines are the EIA estimates for each month.

TXchart/

The change in the correction factors over time is shown in the chart above in kb/d, this amount is added to the RRC estimate to get the “corrected” output given by Dean’s estimate. The average is the April 2014 to July 2016 average shown by the dotted lines (T and T-1 only). T is the most recent month reported, T-1 is the month before month T, etc.

TXchart/

The chart above shows how Dean’s estimates have changed over time, wth estimates from Jan 2015 to July 2016.   I have dropped the final 3 data points from each of the estimates, except for July 2016 where only the final month (July 2016) was dropped. Most months there was a tendency to underestimate output (except for the final 3 months of the estimate which is not shown in most cases). March 2016 was a notable exception, but even in that month’s estimate output was only too high by 0.6% relative to the July estimate after the most recent 3 months are dropped. By contrast the Nov 2015 estimate was 1.6% too low. The final 2 points of the July 2016 estimate in the chart above might be high or low by a few percent, but the April 2016 data point of 3434 kb/d for TX C+C output is likely to be within 1% of the final value.

TXchart/

Lots of people like to see this chart, it doesn’t really tell me much except that there is a tendency for the RRC to under report output due to incomplete data collection. It takes about 18 months for the RRC reported data to be within 1% of the final value (when all the data is in and finalized). It is not clear why the NDIC is able to compile their data so much more quickly, it may be the fact that they only produce one third or less of the oil and natural gas produced in Texas. In any case, due to Dean’s fantastic work, we have pretty good estimates through at least April 2016.

TXchart/

The chart above is an estimate of Texas Natural Gas output in millions of cubic feet per day.  The last 3 data points might be relatively volatile for the corrected estimate but the April 2016 “corrected” estimate is likely to be robust. In April 2016 the TX natural gas output was 23,916 million cubic feet per day, the EIA estimate for that month is 22,697 MMCF/D (gross output).

There was a problem with the February 2016 Gas Well gas reported by the RRC this month compared with last month.  To correct this, I took the average of the difference between last month’s RRC data and this month’s data for Jan 2016 and March 2016 and used that for the Feb 2016 estimate (the average difference was added to last month’s Feb 2016 estimate.) Then Dean’s usual method was applied to get the estimate in the chart above.

88 thoughts to “Texas Oil and Natural Gas Update- Sept 2016”

  1. From recent John Kemp e-mail, Best in Energy
    “U.S. natural gas stocks rose by just +52 bcf to 3,551 bcf in the week to Sep 16 compared with a five-year seasonal average rise of +83 bcf. Stocks have shown below-average increases for 20 consecutive weeks. Stocks are building more slowly than in 2015 for any given level of airconditioning demand as low prices rebalance the market. But warmer than normal temperatures have accelerated the rebalancing process. Temperatures have been consistently higher than average since the end of May. Population-weighted cooling degree days so far this year have been +15% higher than the long-term average and +7% higher than in 2015. The stock overhang from the unusually warm winter of 2015/16 is rapidly clearing. Gas stocks are now just +110 bcf (+3.2%) higher than at the same point last year, down from a surplus of +1,014 bcf (+69%) back in Mar.”

  2. I posted this late this morning on the 9-20 thread, but will re-post here. OT, but petroleum-based. With the release of the new Deepwater Horizon movie, Rockman posted a great series of messages at peakoil.com re-iterating his perspective on the 2010 Macondo blowout. It brought back memories of his compelling real-time daily technical analysis on TOD in the midst of the disaster. It deserves a read by anyone interested in the oil/gas industry and not already intimately familiar with the technical details of that blowout or of underground drilling in general.

    http://peakoil.com/forums/deepwater-horizon-oil-spill-capped-three-years-ago-t68495.html

    2. Maybe its my background, but I find it difficult to visualize what happened in events like the Macondo blowout without wellbore sketches and pressure graphs. I’m not sure somebody outside the industry can grasp what went on without those visual aids.

  3. Trump mentioned in the debate something like ” Oil Companies are Going Broke under the current administration” Refreshing to see root causes other than Low Price and regulations.
    “The real reason energy companies are going bankrupt is more technical.
    Reserve base lending for unconventional reservoir projects became a Ponzi scheme. This is how it works.”

    http://oilprice.com/Energy/Energy-General/Low-Oil-Prices-Are-Not-The-Reason-Oil-Companies-Are-Going-Bankrupt.html

    1. I believe the big difference between Trump and Hillary when it comes to the oil industry is his proposal to drop the corporate tax rate to 15%. That would really help increase activity across the board. And I suspect we would see a lot of cash get repatriated, pay the tax, and get put to work inside the USA. Another big difference would be the approval for pipelines from Canada. That would allow the USA to import Canadian oil to replace Venezuelan oil. And as we know, the Venezuelan regime is evolving into a tyranny and a self declared enemy f the USA.

      Regarding the post, it seems that Permian Basin prospects do keep production level at 3.4 mmbopd with a price deck at $50-55 per barrel.

      I don’t keep track of the details, what’s the latest estimate of per well recovery for wells completed in the (for example) Wolfberry?

      1. Subthread yesterday’s post for Bakken pretty solid evidence EUR avg well 300K barrels. Because of surprising out-year decline rates.

        1. The decline rates for 2009 wells are 9.85% from year 4 to 6.7, for 2009 and 2010 wells from year 4 to 5.6 the decline rate is 12.2%. Fernando has suggested this rate might fall to between 7.5% and 9% over time.

          Refracks muddy the picture however, and as wells are abandoned the decline rate increases, so it is possible the decline rate of the average well could increase over time as wells are abandoned.

  5. Hi FreddyW,

    Continuing our conversation from here

    http://peakoilbarrel.com/mexico-china-and-beyond/#comment-582056

    In the chart below I show the Jan 2009 to Dec 2009 wells, there are 470 Bakken/Three Forks wells, I eliminated the 2008 wells because of the anomalous increase in output possibly due to refracking or the “halo” effect. The plot is the natural log of monthly output in b/month on the vertical axis and time from first production in years on the horizontal axis. The data is plotted from 4 to 6.67 years from first output. The decline rate is 9.85%/year and assuming that level of exponential decline from 6.7 years until abandonment at 15 b/d, the EUR of the average 2008 to 2015 ND Bakken/TF well is 334 kb of oil.

    1. Hi,

      This data looks better than the last graph you showed. However I see a problem in that you try to fit a linear line in the data as if the decline rate was constant during that period when it was not. The decline rate was low between 4 and 5 years. So if you instead draw a line from 5 to 6,7 years you will get a higher decline rate. Also the slope of the line depends on where you start and end it. I could draw a line in that graph with a steeper slope.

      1. The o.0985 makes physical sense. Individual wells should gradually move to a slightly lower decline rate. I do worry about production efficiency as water cut and gas/oil ratio increase. Based on what I read here the decline rates are pinned down well enough. The issuue I’m not sure about is the per well OPEX when a well is producing 20 BOPD plus 50 Bwpd.

      2. Hi FreddyW,

        I guess you could make the line wherever you would like. The data is noisy due to only a few wells and wells go off line for maintenance and that is somewhat random. I simply did a least squares on a little more than 2.5 years, I think using more data gives a more robust result in nailing down the trend.

        In addition some of the 2009 wells may have been refracked, after the refrack the decline rate will increase for 24 months or more. Trying to account for those complicates the analysis. The 20% decline rates you are seeing may be due in part to this effect.

  6. IEA OMR is out for public viewing today:

    https://www.iea.org/media/omrreports/fullissues/2016-09-13.pdf

    Energy Matters blog usually has a summary sometime soon afterwards. The biggest changes are on the demand side predictions which I always take with a pinch of salt. For supply they have all non-OPEC countries in decline from this year compared to 2017 except Canada, which they still have peaking in August 2017 and then in decline, Brazil which has a steady increase (but not as steep as a couple of years ago), Kazakhstan which has a big jump in the second half of next year and Russia with a slight increase.

  7. As I consider a sudden, significantly large year-on-year drop in oil supply to be the biggest exogenous risk (that is probability multiplied by consequence) to my happy retirement over the next few years I have been keeping a list (I wouldn’t go so far as to call it a database) of new projects that are mentioned in company presentations or in industry blogs like RigZone and OilPro.

    I keep expected start up date and nameplate capacity and approved at FID versus appraisal. I was quite surprised to see my numbers for probable new supply to agree quite closely with those from Rystad (see below), Wood Mackenzie and TransOcean in recent reports. Therefore I’ve presented here the numbers as I see them out until 2022.

    The ‘New Supply’ are projects in construction. ‘Probable’ are those I think likely to be approved soon – mostly Brazilian clone FPSOs and some in GoM, Nigeria and the North Sea. There will be others, but maybe not that many that can come on line by 2022. ‘Brownfield’ is a nominal number for possible in-fill drilling etc. – I think this is probably an overestimate as the places in Russia and ME likely to have on shore fields that could accept new wells quickly have actually slightly increased drilling in the recent down turn so further increase might be difficult. I have taken decline rates as Rystad gave them but slightly increase it with time to reflect increased ratio of ageing fields (this might be open to debate). Note the numbers aren’t impacted by what the world URR might be (other than how that impacts the companies investment decisions) or the recent lack of discoveries (that may however limit the options from 2021 onwards though).

    Note I assume 95% availability for projects, even in the first year, and assume all the capacity comes on at start date (obviously not correct but evens out over time somewhat).

    As shown there is a big shortfall. Even all the possible projects that I have listed from the majors and larger independents (and some NOCs) presentations from earlier this year is not enough to fill the gap. I have not included Libya or Nigeria offline capacity or any increase it USA LTO, which might help a bit but similarly there are other possible major supply disruptions that could balance these.

    1. Thanks George, really interesting to see. Do you think there could any new supply, especially after 2018 where we don´t have Rystad to compare with, that you may have missed?

      One thing though. If there will be that much missing production the coming years, then that will for sure cause major increases to oil price which should cause a major recession which will reduce the demand. So I think demand growth will start to be negative in that case.

      1. FW – Yes there are all sorts of things likely to happen once a big supply shortfall is seen – I don’t pretend to know what is likely to happen except it won’t include BAU growth as we presently have it.

        I don’t think I have missed any major projects that have been through FID so far. There will be projects that are approved and come on line before 2022, but I don’t know for sure how many – I just approximated those in the ‘Probable’ column based on recent news. Also Iran and Iraq might change quickly, though I’d interpret Iraq’s statement that they will only add a few hundred thousand by 2020 to mean that they will actually decline in reality.

        One problem with this is that all the oil industry will be assuming that costs stay low, and therefore they will all make the same assumption on when to proceed, and then suddenly costs won’t be low anymore.

        One thing I know I’ve missed is projects started last year that are still ramping up this year (including improved availability) – that could add 1 to 1.5 mmbpd to supply numbers (and hence give a possible new peak in late 2017 in line with IEA numbers) – it will also keep prices down and therefore mean fewer projects get through FID.

      2. To try to be a bit clearer – if the ramp up is properly distributed over successive years (which I think Rystad do) then some 2016 new supply would move to 2017, and some of that to 2018 etc. So 2019 would see a bit more than I estimate and 2020 could increase a bit as well (but less in proportion to the total new projects coming on line for each year).

    2. As some further support for the numbers at least until 2020:

      https://www.oilandgaspeople.com/news/9994/why-oil-prices-cant-stay-low-for-much-longer/

      “However, a study by RBC Capital Markets expects new non-OPEC production of 2.16 million barrels a day to come online this year. In 2017, they expect an addition of 1.24 million barrels a day and for 2018, the figure is 1.58 million barrels a day. In 2019 and 2020, the additions are expected to subside to 680,000 barrels a day and 480,000 barrels a day respectively, reports The Financial Post.”

      I can’t find the RBC report on line, but their numbers look a bit low to me, especially for next year and 2020.

    1. Thanks for the Rystad graph, they do good analysis. So we should get an oil price spike over the next few years. I’ve been calculating the oil displacement by electric car production, and every million electric cars should knock out roughly 0.09 million barrels/day of oil demand (depending on how efficient the cars replaced are). This is eventually going to catch up with the oilfield declines, but it’ll take a while. We’ll be at a million a year in 2018 easily, but even if electric car sales every year (which it very realistically might), it takes until 2022 to match the 1.6 million barrels/day shortfall which Rystad is showing for 2018. So we get a price spike for a few years. It’s interesting to try to figure out what happens next, after 2022, but it looks bad financially for the oil companies in so many different ways.

  9. SS, something to think about.

    Your profile of costs in laying out shale finances — time is passing. There’s a lot of debt on the books. More important, there’s more and more debt on the books, and apparently they didn’t borrow in Japan at 0%.

    So you should be seeing across the various companies interest from loans not repaid that accumulates. Meaning some of these wells flow near nothing, probably not many dry holes, but probably not zero dry holes. The interest on that loan still flows. If they shut down wells before they have fully retired their loan from cash flow (ha), that interest still flows. It should be divided among new wells.

    It all should be getting worse.

  10. OPEC agree to cut 1mb/d from today level, cap is 32.5mb/d. We will see how much will Russia cut from 11.1 mb/d. From november market will be in short supply.
    Like i said month ago

    1. Frackable NO Clay Shale under them Dunes ? With energy density > Captain Kingdom Crunch. How much will be left over after 9-11 Judgments ?

    1. not really the point. the only thing to pay attention to is trader psychology, NO ONE and I will repeat for emphasis NO ONE benefits from oil prices below $60-65. The Saudis f**k up big time. Their market and currency are in shambles. With that back drop who in the hell is going to short oil going forward. There will of course be the usual headlines to spook the naive, as there always are and it is rarely an easy pat deal. Never the less, as I pointed out weeks ago, this was built in and was just a matter of time. Again, if they are going to do an IPO of Aramco who is going to invest with them while they are engaged in a price war…NO ONE. investors want pricing power, if they are serious about selling some assets expect them to raise the price of those asset prior to sale. common freaking sense.

      1. So where do refineries and their purchase negotiations with oil suppliers figure in with determining what they pay for it?

        And why should the KSA central bank not buy the 5% of Saudi Aramco to be offered to the public? Or maybe restrict it to the Saudi royal family.

      2. The usual procedure is for the oil marketing department to see what’s being made available matching volume and quality the refinery requires, and bid a price differential versus a set marker at a given date. Oil sellers usually send notices laying out the quality, volume, and location where the load will be available. Because the amount in the transaction is used to pay taxes the tax authorities expect the price will be set in open bidding. The refinery engineers and economists are the ones who run the computer models which give marketing the pricing guidelines, but marketers don’t necessarily follow these 100%. They also have to see about tanker availability and pricing, as well as the seller’s reliability. For example, some sellers don’t make the load available on time, have several days’ delay. This costs money and is factored into the bid price.

          1. Someone will have the answer, but my guess is that far more than 99% of NYMEX trading has nothing to do with the physical deliver or the physical accepting delivery of crude oil at the contracts’ delivery point, Cushing, OK. It is primarily just an exchange of money. Which is what hedging is all about.

            It is like you and I have a bet on football game. Neither of has a team. And if we make a bet, it has no effect on who wins or loses the game. But, after the game, one of us wins and the other loses – but it is just an exchange of money.

            Hedging. A trucking company thinks that the price of fuel will go up. If it does, it will lose money. So it purchases contracts on the NYMEX. If the price does go up, it pays more at the pump. But, they then sell the fuel contracts for a profit that offsets the higher prices. If fuel prices unexpectedly go down, then it saves money at the pump, but it sells the fuel contracts at a loss. Thus, it does not have increased profits from paying less at the pump. But, it has protected its margins, which if prices had increased may have caused it to default on other obligations.

      3. “NO ONE and I will repeat for emphasis NO ONE benefits from oil prices below $60-65.”

        So here’s the fascinating problem facing the oil industry, and I know this is getting a little off topic, but it’s very relevant to what you just said.

        A friend of mine ran a regression on cheapest-grade US gas to WTI crude, and got
        gas price = 0.922 + 0.0261 * WTI.
        Now, you can convert from a gas price to dollars per mile if you know your MPG.
        gas price / mpg == dollars / mile
        Now, suppose you’re considering replacing your gas car with an electric car (or buying a new gas car vs. a new electric car). You know the efficiency in kwh / mile of an electric car. You can think of what you would spend on electricity, and convert dollars / mile to dollars / kwh. You can then compare this to your electricity rate.

        (.922 + .0261 * WTI) / gas car mpg / electric car efficiency == equivalent electricity rate

        If this is higher than your electricity rate, getting a gas car is losing you money. The moment an electric car is at roughly the same price as the gas car you are considering, you buy the electric car.

        The most efficient gas car is the Prius Eco at 56 mpg. The second most efficient is the Prius at 50.
        The *least* efficient electric cars are the Tesla Model S 90D and Tesla Model X P90D at 0.380 kwh / mile. A Model X 75D is 0.360, a Model S 75D is 0.330

        I’m tilting this calculation *heavily* in favor of gasoline, because this isn’t a fair comparison: most people in the US would prefer a big Tesla to a Prius. And the $35,000 Tesla Model 3 coming out in 2017 will have higher efficiency than the existing Teslas. But anyway, at $60 oil, plug in the numbers and get:

        Prius Eco Versus Model X P90D
        (.922 + .0261 * 60) / 56 / 0.380 == 0.1169. Electricity is less expensive than this in half the US.
        Prius Versus Model X P90D
        (.922 + .0261 * 60) / 50 / 0.380 == 0.1309.
        Prius Versus Model S 75D
        (.922 + .0261 * 60) / 50 / 0.330== 0.1508.
        Average New Car from 2014 (36.4 mpg) vs. Model S 75D
        (.922 + .0261 * 60) / 36.4 / 0.330 == 0.2071
        Average New Car from 2014 (36.4 mpg) vs. Model S 75D at $65 oil
        (.922 + .0261 * 65) / 36.4 / 0.330 == 0.2180

        If you’ve ever looked up electricity rates, nearly the entire country has rates lower than this. Most of the spots which don’t are extremely sunny and you can generate electricity cheaper than this with solar panels immediately.

        So, I’d say there are a lot of people who benefit from oil prices below $60. Such as the entire gasoline car industry. Because above $60, the gasoline car manufacturers become completely uncompetitive…. if they aren’t already uncompetitive at $40.

        Average New Car from 2014 (36.4 mpg) vs. Model S 75D at $40 oil
        (.922 + .0261 * 40) / 36.4 / 0.330 == 0.1636

        The destruction of oil demand will happen as fast as the electric cars can be pumped off the production lines. I’m not sure how fast that actually is, since it involves building a lot of factories, but the opportunity to make money will be obvious, so investors will be throwing money into factories as fast as they can.

        Even at this website, it looks to me like most of the oil industry insiders are going to be completely blindsided by this.

        The correct move for the upstream oil companies is to end exploration entirely. Production cost from existing wells is quite low and they can often be profitable sat $10/bbl, so keep taking the cash. Then put the business into “runoff mode”, pumping what’s left, shutting things down in an orderly fashion, cleaning up your environmental liabilities, selling off wells when you find a sucker who hasn’t figured out the fate of the business yet, and mailing the cash out in dividends The correct move for the midstream business is to plan for shrinkage and target jet-fuel refineries. The correct move for the refineries is to target jet fuel. The correct move for the gasoline stations is to shut down now. The correct move for most of the oil company employees is to go back to school in electrical engineering or as electricians (depending), because that’s a booming growth business. The geologists should switch to geothermal. I think basically none of the people in the industry are doing any of this.

        1. In your equation, you should take the price of the car into account. If you compare a Prius to a Tesla (I don’t know the prices), and get 5000$ cheaper for the Prius, how many miles/km do you have to drive to cover the price difference?

    1. the comments in the comments section are somewhat depressing but give an insight to the problem some of the public has in understanding the issue

      Forbin

  16. Colombia was one of the first to cut drilling as the oil price fell, and their production has followed. They are now at 14% year on year decline (similar to China and a bit higher than Mexico). They are trying to add rigs from now until the end of the year to at least try and hold steady.

    1. If they vote for peace in the referendum then they have a chance to increase output. Unlike some other producing countries they still got a lot of places to drill. The OBA pipeline is all ready to go and should be operational in a few days.

      1. Watcher, you of all should know EPS is completely irrelevant to certain industries, such as those that drill for unconventional oil and gas, produce solar panels, windmills, electric cars, and propose to colonize Mars.

        Never in my many years have I seen a group of oil producers publicly talk down the price of the product they sell. That is because it is pretty much irrelevant to them.

        As long as they have a “story” the oil price matters little. Again, like solar, wind, EV’s and colonizing Mars.

        1. Well, they’re right. If the Dallas Fed did indeed tell lenders not to foreclose on these properly bankrupt companies, then money does not matter.

          And if it’s truly a national security issue, money probably should not matter.

        2. Solar panels are a cutthroat industry from hell. Eventually, some company is going to end up making a hell of a lot of money making solar panels, but there is an insane amount of competition and some upstart comes up with a better product every week.

          So you spend a lot of capital upfront to build a factory, produce panels profitably for a couple of years, and then some upstart takes all your business and forces the price down, before you’ve covered the cost of the factory. Very hard situation to invest in. But *someone* is going to make a mint. It’s just not clear who.

          Wind turbines are a stable and profitable business right now and are mostly produced by the big conglomerates.

          Electric cars… well, if you can read a balance sheet, you can identify a capital-intensive business which has high gross margins and needs more volume to cover overhead. BYD and Tesla are both in this category and they are both capable of getting the volume.

          You should understand this because the old oil wells worked quite similarly: you spend a lot of capital now, but then you pump oil profitably from that one well for decades and eventually you cover capital costs.

          Shale gas is a particularly ridiculous situation, however, because the wells run out in 5 years — an electric car lasts longer! — making is nearly impossible to cover the capital costs.

      2. to reuse a phrase how does that “advance the conversation”, everybody and their dog knows that companies like CHK are in debt up to their eyeballs and are corporate zombies. The point of the article was how cost have come down and the methods some companies are using to try keep cost down. Taking out the middle men, seems to me is unique approach in the oil patch, at least in my experience.

      3. a general observation Watcherdood. Let’s say company x borrows a shit load of money and drills 100 wells of which each and everyone appears that they will lose money to some degree. The wells are still producing mind you and the debt is still on the books, then one day because of a variety of factors company x drills their 101 well, and it appear that this well just might make money. Does that mean the last 100 wells are now better, does that mean that the debt goes aways, of course not. What it does mean is that IN THE FUTURE what they are doing may make money. That is how money is made in investing. The facts can still be debated but if true it is a game changer.(ask the saudis)
        Now in the business world the above scenario is not really that unusual. It is also reasonable to be skeptical that company x is telling the truth that after drilling 100 non commercial wells that they finally figured it out but if true what does that mean for the future. That is the point that so many self-proclaimed experts seem to ignore.
        As I have pointed out now for months, despite being ridiculed, Oklahoma is going to produce a great deal of LTO. just the facts. And while I chuckle when the so called experts do have the ability to understand this, it also speaks to their ability to understand things, their critical thinking ability and understand the history of our industry, things are not static. There are those that spend their time on the field and others spend their time in the bleachers and the view is always quite different.

        For for just a moment think about this. I receive a production report saying a well I have an interest in is producing 400BOPD, 30 days later a get a check in the mail paying me for my share of that oil. Then I have people on the blog tell me that oil does not exist, and if it does I am going to lose money. They do this in spite of the fact they do not have the facts. It speaks volumes at least to me about who they are and what their motives are.

        I would get a job as a door greater at walmart before I would spend my time sitting around bitching, but that is just me.??

        1. TT.

          I do not want to get into arguments with you.

          I personally am going off production histories for the OK wells. There are several that have high oil IP, strong first year oil production.

          Historically, those have dropped off quickly, but I agree there are areas/zones that will produce more oil than others. I will readily agree that many of these wells will produce a lot of gas. However, I am not seeing indications of wells that will produce 500K BO in the first 60 months, for example, like some of the monster wells in the Bakken and EFS.

          I am going off history, I have zero inside knowledge. So we will see how things play out. Maybe you have some inside knowledge that I do not?

          My beef is given the histories, how are the companies so confident that wells on average will produce double the oil than the best 30 of so Hz wells, out of over 13K, have produced in the State of Oklahoma? A very tiny fraction have topped 400K BO.

          Again, I may very well be proven wrong. Just have to give it time I suppose.

          It looks like OK oil production, per EIA, peaked at 473K BOPD March, 2015. It has ebbed and flowed, last month, July, 2016, it stood at 410K BOPD. Again, not super confident about EIA numbers, but that is what they have.

          Looks like prior to Hz boom, OK was at 170-180K BOPD range. There were a lot of wells in formations like Cleveland, Hunton, Des Moines, Mississippian system, etc., drilled in addition to your focus areas of SCOOP, STACK, Meremac , Woodford. So has not been an explosion of oil production, per EIA data, especially compared to EFS, Bakken and Permian.

          I also note that, despite a lot of OK resource play activity, CLR’s oil production numbers are dropping, while gas is rising.

          Also, I looked at the wells in the Félix – Marathon transaction. Large percentage of BOE is gas. Oil production disappeared fast on those.

          I will say this area appears to be very economic at $4+ gas, which could be around the corner. Sub $2 hurt them, but then not much is economic at sub $2 gas.

          Here is hoping for higher oil and natural gas prices in the future. I think $55-$65 oil would be a good thing for producers, without hurting consumers. Don’t have a good feel for a fair natural gas price. $4-5?

        2. TT, I read your comments propping up the STACK/SCOOP on every post. You claim that you see the checks coming in and that you have no doubt that your investments will pay out easily. I have no reason to doubt your word on that, but in the Mexico/China blog post you implied that you own minerals in that area (correct me if I’m wrong) and that you participate with what I assume to be WI, carried WI, ORRI, or most likely some combination. Is this true? If so, it is very easy to see why you believe your investment will pay out, since some type of carried WI or part WI/part ORRI will deliver a revenue disproportionate to the amount of capital you actually put in to the well. This is also not an accurate representation of the profitability for operator who drilled the well, since they are getting a lower % of revenue to make up for your higher %. Do you own a WI in any STACK/SCOOP well that you entered heads up? That means you paid for your share (equal to your WI% without a carry) of the lease cost, D&C, and OPEX from day 1? If so, what are the prospects of those wells paying out for you?

          These numbers are most important when we talk about the profitability of an operator drilling these wells. There have been many smart businessmen who have made a profit by being carried or having an ORRI on wells that never made a dime for the operator who drilled the well.

        3. Somehow no one has told you this is not an investment blog.

          It’s a Peak Oil blog.

      4. I get a kick out of all this “lower cost” BS the shale oil industry spews forth, as though that is now going to make it more profitable, and more sustainable. Truthfully, when you don’t pay back the money you borrow to drill and complete a well, you have NO costs.

        Lets take, for instance, two out of over 75 bankruptcies that have occurred in the past 12 months in the shale oil industry, both of these “pre-packaged” bankruptcies (about as skanky as you can get) where Halcon wormed out of 1.8 billion and Penn Virginia out 1.2 billion of long term debt. That’s 3 billion dollars, the equivalent of 375 FREE shale oil wells at 8 million dollars each. Just about any 8th grader I know could build a sustainable business with 3 billion dollars, not either one these companies, however; they will both ultimately fail. All that production revenue from all those free wells is gone, vanished, disappeared. Along with shareholder equity. Floyd, however, bought himself a new G-5 600 A before he crawled off into the woodwork.

        If you are a shale oil cheerleader, THAT’s something to really be proud of.

        1. Mike, pre pack BK is yet another reason why OPEC and Russia should pull back some.

          Unfathomable how much capital has, is and will be destroyed by LTO.

          Cut big and ignite another US boom, can US get past 11 million bopd?

          When the good spots have been maxed out, what is the next option?

        2. “Truthfully, when you don’t pay back the money you borrow to drill and complete a well, you have NO costs.”

          Exactly. It’s stealth nationalization, and if it’s a national security issue, maybe it should be overt nationalization.

          1. Further, it can be argued that share issuance is similar for companies with no earnings and pay no dividends.

            Couldn’t the Fed just start buying shares of US LTO companies to keep the oil flowing. Are they doing that already indirectly through zero interest rate policy?

            While we are at it, in addition to the BK’s, there has been a lot of debt bought back by the companies themselves for pennies on the dollar. There has also been a lot of debt written off by companies giving equity in exchange for debt.

            Free money.

            1. Noted in the past — the Swiss National Bank and the Bank of Japan are both explicitly authorized to buy stocks.

              Janet Yellen recently said such authorization would be a good thing for the Fed to have.

              On tablet, can’t paste url. Go to zerohedge Sept 29. They have her quote from a speech the previous night.

              The underlying truth is without oil everything dies. There MUST be oil. If it takes destruction of capitalism in that industry to get it, then destroy it. If it takes bullets in the brains of the uncooperative, then they will die.

              There is no choice.

  20. http://www.zerohedge.com/news/2016-09-30/satellite-imagery-reveals-chinas-strategic-petroleum-reserve-vastly-greater-disclose

    This didn’t make much sense. The overall theory seems to be measuring shadows on the top interior of above ground tanks as a measure of tank content.

    A startup satellite imagery company did this. I suspect they measured one tank shadow, maybe even at the same time each day because the guy assigned wanted to be thorough, within the budget of a startup, and hyped it across all tanks to get contracts. There is a one sentence disclaimer about the estimate excluding below ground storage.

  21. I just noticed that the non-petroleum thread at PeakOilBarrel has 291 posts while the petroleum thread has 43.

    Time for more port.

    1. That is further evidence indicating that they should be kept separate. The non-petroleum trash and petty bickering can and has at times totally ruined intelligent discussion of oil and gas. Posters have the option of reading either or both.

      1. Ok, although I said a couple days ago I was done posting, maybe I can get some good opinions on some things oil production related.

        First. On low volume wells, what is the best way to figure out how to pump them?

        Trial and error? We were debating today whether you should let the well pump and then check it intermittently, and when it has pumped off, then you know how long it should be pumped each day. I am not sure about this. Seems to me that, over time, those time intervals could decrease?

        Along those lines, lets say we determine the well can pump 12 hours in 24, how do you determine whether to pump it 12 on and 12 off, or for shorter intervals adding up to 12?

        Another question, if you have a small, high, casing hole, and need to use continuous treat chemicals, will all the chemical just go out the hole? We have been debating this too. Wouldn’t batch treat do the same?

        Another question. Have a low volume well that makes straight oil, almost no water. When first took over lease, batch treated, one gallon per month with corrosion/scale inhibitor. Well would almost immediately stick up. So quit using chemical, sand pumped well out, no acid. Well has had zero problems in 5 years, two down hole pump changes only. Well has just a 4 Ft stroke, 5 strokes per minute. Funny thing, production from well continues to slowly increase, have gradually went from selling one 115 bbl tank per alternate month (85-95 bbl sold) to almost one per month. Pound hasn’t changed, no water injection wells very close, only one within half mile disposes of just 35-50 BWPD at 300 psi. What is the explanation for production increasing?

        Last question. Have lease that has wells in two zones. Unfortunately, original operator ran all into common tank battery, co-mingled water causes barium issues. Have treated produced water, still have some problems, have to bore out lines from time to time. Any opinions as to whether it would pay to set a separate tank battery, run deeper wells (there are just 2, with two deeper injection wells offsetting) into it, with separate lines back to deeper injectors? Or, given the water has been co-mingled for years, think that it is too late, just need to keep treating?

        I readily admit my field knowledge is limited. Again, we are talking shallow sandstone wells here. If more info is needed, let me know.

        Any advice that is willing to be given would be greatly appreciated.

        Just to show some of us care about actual oil and gas operations that doesn’t have to be done by large institutions through Wall Street. Like the straightforward aspects of stripper production, there are no shortcuts or schemes.

        1. How about . . . Have a look at those down hole pumps. Manufacturer may have changed something for the better.

          Lots of electric motors went neodynium over the past 10 yrs and suddenly electric shavers were far more powerful.

          Not suggesting that specifically, but that sounds like a maybe for increased output.

        2. You would have to post wellbore sketches, a gamma ray and porosity log, an oil sample, water sample, production history, any description of the reservoir rock you have available, a map, etc. I guess you could put this in a blog site and give us the link.

          I could look it over and give you some tips (which could be wrong), free of charge. If you get something useful I could help you from here, but I’m not interested in working on individual wells as a hobby. I’m used to looking over whole fields or large reservoirs, but since I’m retired this could be an interesting challenge. But I’m not making any promises.

          By the way, the information I asked for was standard anywhere I worked or managed teams running field operations. I don’t like having this in a series of computer data bases, or in little folders. It has to be paper in a three hole punch binder, with tabs for each well. And I expect field ops engineers to know their wells. Not too long ago I consulted for a large multinational and I found their engineers married to computer data bases, which they simply didn’t look over, and they just didn’t know their wells. Seems that nowadays we have highly paid petroleum engineering supervisors who are very impressed by lots of PowerPoint bs and don’t even know how to design or troubleshoot their wells. I think it’s all going to hell.

          1. It is just as bad on the exploration side. We are training a generation of geologists who have no idea how to explore for oil and gas using seismic and subsurface mapping.

          2. Fernando said:

            “It has to be paper in a three hole punch binder, with tabs for each well. “

            I need to be sitting in a comfy chair with a plush pillow that I can read my head against, along with a latte. Only then can I get down to the business of explaining to the world what it all means.

            sarcasm off.

            Robert Wilson was complaining about petty bickering. All I can certainly say is guys like Fernando and Javier know how to push people’s buttons. It’s almost as if these guys enjoy annoying people.

        3. By the way, I have seen viscous oil wells increase production over time if they are allowed to produce small amounts of sand. This oil has the ability to lift the sand to the surface. The sand being produced seems to clean up the well over a period of years. This type of well needs to be kept pumping slowly to avoid having sand fall back to the pump.

          I guess you don’t have wells on ESP. Those should never be put on a clock. But a well with an ESP should produce at least 500 bfpd (more or less).

          1. We do not use ESP’s in this field except for water supply wells. Everything rod pumped.

            I agree, not really enough information for anyone to give definite answers.

            We actually have very few wells that do not pump full time. We have just used trial and error for the few that pump off.

            We are very small, no engineer on staff. Just operations personnel.

            Just trying to get some discussion going.

    1. At 12500 miles average per year, the average car uses 520 gallons. That is more than one gallon per day per car right there.

  23. I have mentioned this before, and will again.

    OPEC cuts 5 million, or something pretty dramatic, something to get oil into 2010-2014 price range.

    US starts drilling frenzy.

    Service costs rise.

    Ramp back up to 1,000+ rigs.

    How high can US production go, when does shale peak? Can US ramp up so fast that all of such a cut is offset.

    Do companies, seeing the possibility of debt being paid off, begin to pay off some debt instead of kicking the can down the road?

    I don’t know the answers, but to me, it seems better for KSA to be at 9 million at $90 oil than 10.5 million at $45 oil.

    It seems possible that EFS and Bakken have little ability to get much higher than previous peaks. I still contend OK resource plays, while high on BOE, produce a low percentage of that in oil over the well life.

    That leaves the Permian. Wouldn’t it be better for OPEC to cede a little market share to the Permian, at 60-90% higher prices. How high can the Permian get? How long will it stay there?

    PXD’s CEO says Permian can hit 5 million BOPD. I think he says that because he likes to compare Permian to KSA’s largest field. How many rigs would that take, how many wells?

    Seems that to get Permian to slow down will take WTI sub $40. Pretty clear OPEC cannot handle that for much longer.

    Seems to me best approach for someone wanting to maximize profits would be to cut, try to get another boom going in US, try to get those locations developed, as opposed to a slow grind?

    I have no clue if I am right. Wildcard is what non-US/Canada production would do, particularly Russia. Other wildcard is demand, although I think demand may not drop that much, as oil price increase would likely result in across the board commodity price rise, helping developing world, where consumption growth potential is largest.

    Have been trying to think this through for sometime. Would be interesting to see just how high US production could get before it hits a wall. Would seem, a absent worldwide LTO type growth, once US LTO hits the wall, catalyst for OPEC to resume complete control?

    1. For example, looked at PXD’s wells with first production in 2016. Seeing most are on the same leases, such as XBC Giddings, Donald Hutt Fee, ET O’Daniel, Sale Ranch, Preston.

      I don’t know how many locations are left on those, but if it were me, I think I’d encourage the core to be hit hard fairly quickly, then see where things go. I see the same for the others in the Spraberry trend, many wells, few lease names.

      Maybe different on the west side?

      1. Read where Diamondback is paying $2.5 billion for 42,000 acres in the Delaware Basin. 35 producing Hz wells, about 8K BOEPD coming from those, mostly under one year on production.

        Anyone in the Permian who could give some info as to how many Wolfcamp A and B locations there would be? Are there other zones that are worthwhile?

        I am coming up with about 400 locations, but that has to be wrong, because that would be over $5 million per undrilled location.

        1. Silver Run Acq. bought about the same amount of acres in the Delaware Basin with Centennial. They claim 1,357 drilling locations.

          1. Thanks.

            Still, $1.5-$2 million per location.

            Looks like about $7.5 billion to drill, complete and equip that many wells.

            Assume 300K BO per well

            Assume 600K BO mcf gas per well

            Assume 400K BOE per well

            540 million BOE.

            Assume $10 per BOE in LOE and G & A.
            $5.4 billion in LOE and G & A.

            $15.4 billion/540 million BOE = $28.52 per BOE.

            Would be interesting to me, and maybe a handful of others here, to see the composite engineering on some of these Permian deals.

            1. I can’t help but feel like I’m watching the same bad movie over and over again. Your numbers are probably accurate, but in the world of shalie huxterism it is 2mm BOE per well.

    2. Oil consumption and price.

      Front screen of mazmascience.com/oilexport

      Shows a black line for global consumption. 2010 to the latest year 2015. That is $100+ oil and $45 oil — for the five years.

      Essentially no change in slope. At all.

    3. if past is prelude and it may not be, my personal most likely scenario considering, the overhang of debt, bad memories, infrastructure etc will keep “most” operators very conservative for a while, maybe even a couple of years. Even if we double the rig count from here (@$60wti), there would be a 1000+rigs sitting idol as well as their crews, drivers etc. Hard to see much pricing power for rig rates for sometime to come. Since 2014 drilling time in many instances have come down 30-50% depending on the play, a further cap on cost. If companies are rewarded for profits and dividends over production growth (historical model) I expect the most economic plays will be development and in time as prices rise, the higher cost plays. I don’t think, unless we jump to $100+ we get the drill anywhere and everywhere and hope for the best attitude to sneak back in anytime soon. Boom cycles developed over many years like stock market bubbles, until the memories of the last bust are behind those making the decisions, I expect some “normalcy” in board rooms for sometime to come.
      I stated earlier that I thought we would be lucky to ever get back to the production levels of 2 years ago that continues to be my thought but I have also been surprised at some of the advancements industry has made, so it may well be we can, but that event is at least 4-5 years out I think if ever.

  24. “Would be interesting to see just how high US production could get before it hits a wall? ”
    In a constrained supply situation just how much precious crude available for LTO Industrial ops?
    Pumps, Sand, Water, Rail, Trucking? Maybe why US Politicos are keen on wrecking consumer Diesels?

    1. Longtimber,

      Thanks for posting Art’s piece. Hopefully George (Kaplan) will give us his take on this.

      1. Doug – I am highly flattered you should request my opinion, but doubt that it counts for much more than anyone else’s here. I know a bit about the supply side, but even there I am no more than a dilettante reliant on what I get from the internet. Most of the article is about the demand side, and there I am in the ‘huh?’ category, like most others. As a dilettante I can of course say ‘I don’t know’, as an expert you can’t and I think that is part of Art’s problem – he has to come up with something interesting to say every month or two.

        His argument, like a few others, is based around the world economy, deep in debt, being unable to afford oil at a higher price. This might be true but it always reads like a ‘Just So’ story to me – it fits the facts nicely but there isn’t real evidence. I don’t see how the present price as a function of the supply-demand balance can be discussed without bringing in the huge industry overinvestment that happened in 2011 to 2014 – not only lots of large conventional and tar sands projects, but also the fast ramp up in LTO and the growth in in-fill, horizontal wells on existing fields. There was a confluence of reasons for this – high prices, low interest rates, a lot of deep water fields discovered in the previous few years, a fairly (lets say relatively) peaceful period in the Middle East, a big push by Russia to be a superpower again.

        As I said previously while the supply-demand balance affects price, going the other way is very slow and, for demand, not always a big feed back. That means price can settle at a number that is influenced by short term, minor parameters – e.g. how can adding 7 land rigs have any effect on a 96 mmbpd supply, how can a growth in crude storage which is less than the decline in gasoline and diesel mean anything, how can OPEC saying they will cut 250,000 bpd have a $5 impact, when that is what happens every autumn anyway? But those thing act day to day, supply acts over years, demand – I don’t know how that works, it seems to get swamped by outside effects before the oil price impact can be spotted. Hence if there isn’t a real trend in price up or down it is becomes pretty noisy. There may be 6 month cycles in the recent price but does that signify anything much fundamental – I certainly don’t see the same cycles in supply or demand. Demand has a definite yearly cycle though, independent of price. Also there is a lot of storage at the moment which should dampen out fundamental supply-demand cycle, but maybe acts to fuel speculation induced volatility. There is a tendency to get fixated on current price, when in fact it is always going to move, but when it does move we have to come up with reason (look at any crap Bloomberg headline trying to explain the latest move – chances are tomorrow it will be the exact opposite).

        On the debt side I think there is a difference between personal, government and financial institution debt – I wouldn’t pretend to know what it is but I don’t think they can be lumped together like here. Lot’s of personal debt is a much bigger issue overall I think (but please nobody tell me how wrong I am – I have no argument to present).

        There are some statements in the presentation that I just can’t follow –
        “A major oil price and production bubble fueled by debt burst in 2014.” – one problem is the production bubble hasn’t burst, it’s got about 18 months still to go, and I don’t think it was all debt fuelled
        “The real cost of oil is almost 3 times higher than 20 years ago.” – yet the economy can’t bear higher prices, what is special about the price we have now?
        “The upper boundary ($52) is largely controlled by record-breaking volumes of U.S. and world crude oil inventories and the fact that producers add rigs and production with each upward
        swing in oil prices.” – inventories probably have an impact, but sentiment more so, but 7 rigs might produce 3500 bpd for a few months, and completions are the important number. Once stocks decline this seems to imply prices can and will increase, just a question of for how long I suppose.
        “Meanwhile, a global uprising is unfolding. It seems to be about immigration and borders but it’s really about hard times in a failing global economy.” I find that a bit of a stretch and far too simplistic.
        “The public knows there is something terribly wrong and a global upheaval to restore the impossible is underway.” – I know of nobody who thinks that any more than people usually do. I think it is at odds with the previous comments about the public believing LTO company hype as well.

        The light oil oversupply argument I don’t get either. If all of it is going into storage and nobody wants it how can inventories act as a cap on price?

        “The best path forward is to stop looking for improbable solutions that allow us to live like energy is still cheap, and find ways to live better with less.” – I agree with that, but if we can live with a lot less wouldn’t that allow prices to rise sustainably?

        I do agree that there will be a big drop in supply within the next two years. After that prices will rise and the economy may be clobbered. Or the economy may be clobbered first and demand drops at the same time, or something else. All those dynamics and how they exactly impact price are entirely beyond my reasoning capabilities though. I think the fact we have stopped finding much all is also as important as anything else discussed for it’s impact on the future and should have been mentioned (although maybe not enough time).

        So that was a bit long, probably nobody made it this far as there were no charts, but you did ask (YMMV).

        1. This is worth touching:

          His argument, like a few others, is based around the world economy, deep in debt, being unable to afford oil at a higher price. This might be true but it always reads like a ‘Just So’ story to me – it fits the facts nicely but there isn’t real evidence.

          There’s never evidence for lots of economics stuff. There is only quoting of examples. In 5000 years there have never been sustained interest rates this low. This won’t be taught in grad school macro. Not because of conspiracy. Because it’s not in the curriculum. Better one hopes it goes away than deal with changing the curriculum ( changing the curriculum requires tenured profs to spend time creating new lesson plans instead of planning symposium trips errr vacations).

          a big push by Russia to be a superpower again.

          If you’re a country that is food self sufficient, oil self sufficient, natgas self sufficient and apparently software self sufficient (just threw Microsoft out), and you’ve been abused by the US in recent years with sanctions and a coup created on your doorstep to the south, you don’t have any reason to worry a great deal about dollar based pricing. If a refiner offers $60/barrel but Russia wants to inflict harm on the US, refuse the offer and make your Urals oil available at $45. If this concept didn’t exist, you would not have heard of Predatory Pricing.

          The light oil oversupply argument I don’t get either. If all of it is going into storage and nobody wants it how can inventories act as a cap on price?

          A fairly aggressive campaign began when Bakken oil started to flow to make damn sure the average API number was quoted as 39 and all challenges to metals content were smacked down. Per Jeffrey’s timeless chart, the middle distillate content of oil crashes quite suddenly above API 40. And let’s not forget the Bloomberg article (never subsequently dwelt on) noting that the definition of WTI was adjusted because of the quantity of LTO filling Cushing. It was diluting Texas and Oklahoma conventional oil. And, of course, by changing the definition one could more easily note that LTO was essentially identical to WTI and its 39 degree number. Point being, refiners don’t like changing their refining process for imported oil one day and LTO the next. So into storage some goes.

          Price and consumption and consequences. Is there any indication of a more vibrant global economy today at $45 vs 2010-2014 at $120?

          As for consumption, the mazama link above . . . says no visible impact.

Comments are closed.