Eagle Ford Output Estimate and Future Scenario

D Coyne Texas

Eagle Ford output is difficult to estimate as there are 20-25 separate fields that need to be followed to get a full picture. To save time, I have used Enno Peters’ data for horizontal wells from Districts 1 to 5 in Texas from his website shaleprofile.com, he has data through June.  Enno’s data is combined with the RRC data for statewide C+C output to find the percentage of Texas C+C from the Eagle Ford. This percentage is multiplied by Dean’s estimate for Texas C+C output to get the following estimate, which is compared with Enno Peters’ data.  EF-EP is Enno Peter’s collection of data from the RRC, EF-DC is my estimate using the method described.  Based on a May 2016 Eagle Ford estimate, I subtract 70 kb/d from the EF-DC estimate to account for non-Eagle Ford horizontal well output in Districts 1 to 5

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The data labels in the chart above are for the EF-DC estimate.

I used these updated output estimates for the Eagle Ford and David Hughes estimate (from Drilling Deeper ) of 7.8 Gb of liquids output from 36,000 total wells drilled to develop a future output scenario for the Eagle Ford.  Hughes’ estimate includes both oil and gas wells and through September 2016 about two thirds of wells completed have been oil wells, so I will assume 24,000 total oil wells drilled. As of Sept 1, 2016, 11,600 oil wells had been completed in the Eagle Ford according to the RRC. Hughes estimates about 290 kb for the EUR of the average Eagle Ford well, my estimate (including condensate from the average gas well) is 270 Kb of C+C for the average Eagle Ford well with 216 kb of crude only (excluding condensate from gas wells). I assume new oil wells added will be 131/month from July 2016 to Dec 2016 and then the number will increase by one well each month from Jan 2017 to June 2019 when 160 new wells per month are added. The new wells added remain at 160 per month until Sept 2021 and then begin to decrease. There is a secondary peak in 2021 at about 1300 kb/d with total output from Jan 2010 to Dec 2040 of 6.4 Gb, output declines sharply from 2022 to 2026, falling to 200 kb/d by Jan 2030.

TXchart/

101 thoughts to “Eagle Ford Output Estimate and Future Scenario”

  1. Dennis,
    Great work on your part!
    I am amazed at how many oil wells have been drilled in the EFS area and that 131 new wells are added each month. Have read that some 100 oil companies are now bankrupt with more to come. Yes, I know they are using other peoples money to drill and yet the drilling goes on. It just seems confusing to me and it just doesn’t add up IMO. Your thoughts, Thanks in advance

    1. Hi Doc Rich,

      Thank you.

      Enno Peters has only 90 more wells producing in June 2016 relative to May 2016 and 660 oil wells that started producing in 2016 (an average of 110 new wells per month). This may be an underestimate due to incomplete data. The average number of new oil wells “on schedule” for the first 8 months of the year was 184 new wells per month. For the past 4 months (May 1 through August 31) the average number of new wells per month has been only 113 per month. For the first 4 months of the year the average was 255 new wells per month.

      The 131 new wells was a guess to make the model match the data through June, I do not have exact numbers and the RRC data is not great.

      The June completion report is at link below. Eagle Ford is districts 1 to 5, if we assume all activity in these districts is Eagle Ford activity (probably about 95% of it is), then there were over 200 completions in the Eagle Ford in June.

      http://www.rrc.texas.gov/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/

      My model has an average of 141 new wells added per month from Jan 1, 2016 to June 30, 2016 and 138.5 new wells on average from Jan through August 2016.

      I share the view of Mike and shallow sand that continued completions at these prices seems unwise, but the 131 new wells per month I have assumed is less than the completions reported by the RRC in July (165) and August (166). It leaves me mystified.

      1. it might help to look at the economics like this.
        Presumably everyone is familiar with a random real estate housing development. A company buys the land, puts in roads, bridges, sewer, electrical and of course builds the big fancy entry way. They hire an engineer to survey the land, lay out the tracts and file the obligatory paper work with the county and apply for zoning. During this process the companies shows a loss. The company then builds a model home, still shows a loss. Finally they start building houses. The company still shows a loss after 5 houses built and sold. Does that mean that the whole venture will be an economic loss. Maybe it will be maybe it won’t. Each development stands on its own. The one’s that go bust will be picked up by a new developer and the process with continue on. That is the way it works. The old business model of the domestic oil and gas exploration has forever been changed. It is truly not all that mystifying.
        Great post on the natural gas market below. You have several contributors who were pointing out the facts presented therein months ago. Hope some of you took note and made a profit?

        1. Hi Texas tea,

          If the cost to build the house is $100,000 and the selling price for that house is $75,000, would you continue to build houses?

          If so, I would be mystified.

          Same case for Eagle Ford and Bakken at present oil prices. I have not delved into the Permian Basin.

        2. As always, Tea, this is ridiculous mumbo jumbo.

          It’s an oil well, not a house. Your analogy is unenlightening.

          Either you’ve got some kind of proof- a balance sheet showing payout or projected payout at a given price- or you don’t. And if you can’t show it, it’s the same as not having it.

          Put up or shut up, I say.

          1. Lloyd, are you any good at something like flowcharts, such as to explain a system very simply, quickly, easily and clearly? (I seem to recall you posting one awhile back.)
            If so, would you be interested in collaborating or at least consulting on one?

            1. Hi Caelan.
              I can consult and offer advice. Email me at Lloyd underscore gray at rogers dot com.
              -Lloyd

          2. So EOG is run by economic illiterate charlatans? Ridiculous. The house analogy is actually not that far off the mark, except that what you have after drilling the well is a 20 year stream of hydrocarbons, which follow a moderately predictable path, broken up by periodic required investment, and subject to unpredictable market pricing. Looking backwards, you have lots of sunk costs. As such, a well that is completed and brought on line in a low price environment cannot be declared either economic or uneconomic without the caveat of “at today’s prices”…And we all know that the spot price today has zero predictive power.

            1. Go to shaleprofile.com. I think the information on that site shows why near term oil prices are very important with regard to horizontal, high volume fractured wells in the Eagle Ford Shale, Bakken, Permian and Niobrara.

              Also, EOG and their shale brethren are not dumb, management gets paid, even if there is a company bankruptcy.

              Hard to be considered dumb when you are making millions is salary and other compensation with no personal risk.

              Other People’s Money is a great thing for those that are masters at raising it and do not let their conscience get in the way.
              That is not limited to LTO, it is pretty much standard with regard to public companies as well as many large private companies in the United States. Won’t find to many of those guys falling on their swords

              I haven’t noticed anyone, outside of the management at Abraxas, taking pay cuts during this bust. That is despite pretty much all taking losses.

              Again, the old saying attributed to HL Hunt, “owe the bank $100K it is your problem. Owe the bank $100 million, it is the bank’s problem.”

              Us little guys just constantly whine because we want the price up a few bucks. I don’t see why that is a big deal, have to vent somewhere about going from making big bucks (for us anyway) to losing or making very little, due largely to unprofitable LTO overproduction.

              Get us to $55-$65 WTI, and keep it there, and we will shut up about EOG, et al.

            2. So EOG is run by economic illiterate charlatans?
              No. EOG is run by highly economically literate charlatans.

              As Shallow says, they’re still getting paid.

            3. EOG aren’t dumb and they are completing only 25 wells in the Bakken this year and seem to have no plans for any new capital spending there in 2017. I think another nail in the coffin for that play.

  2. Something that doesn’t get much discussion and seems to be building to a head, is the US Nat Gas market.
    Why only 2 weeks ago, Henry hub Nat gas was hitting yearly highs of over $3 mcf, Marcellus gas price was falling to the low $1 mark. Over the weekend it got down to 10c mcf. Marcellus had plenty of gas and nowhere to put it, but it cannot get to Henry Hub in quantities to effect the HH price.

    http://www.bentekenergy.com/
    Record-low spot prices drive production to year-to-date lows
    Monday, October 03, 2016 – 6:10 AM
    Despite the service start of production growth-oriented projects Ohio Valley Connector and TETCO Gulf Markets Expansion on gas day 1, production in the region is down by roughly 1.1 Bcf/d this month to date compared with the last week of September. Cash trading on Friday sent spot prices for gas days 1-3 to the lowest levels on record at some locations, with Dominion South posting a 31 cent/MMBtu index, and at times trading as low as 10 cents/MMBtu during the morning. The production declines have been concentrated around Southwest Pennsylvania, with SW PA Wet and South PA Dry production areas making up roughly 540 MMcf/d of the declines, while Northeast PA has seen production fall around 240 MMcf/d, and West Virginia by around 190 MMcf/d. The service start of the Ohio Valley Connector and Gulf Markets projects was virtually indistinguishable, buried beneath the production declines. Ohio Valley Connector flows were off to a shaky start, as operational issues at the new Equitrans-REX Isaly interconnect forced Equitrans to reduce volumes to zero for gas day 3.

    In the north, all storage units are full to near to full, and are placing limits on any further injections this season. Meanwhile, in the South, there have been withdrawals for the last 11 weeks, even into the shoulder season, where the largest injections normally take place. Along with this, the Sabine Pass LNG plant has been shut down for maintenance for a month, and therefore taking 1.3 bcf off the market.
    http://ir.eia.gov/ngs/ngs.html

    What happens in winter will be interesting. Just for a normal winter, storage stocks will get pulled down quite severely. It will be the refill season that will show up how well the Nat gas producers can recuperate, and what price is required to generate the required investment.

    The fact that nearly every pipeline expansion has been delayed, only complicates the matter. The 3.25 bcfpd Rover Pipeline, is a case in point. Approval was expected to have been given in August, after being delayed from Feb this year. The fact it has yet been approved, looks to me that it will not be until after the election.

    PS, Just saw this article from John Kemp on the same subject.
    http://www.downstreamtoday.com/news/article.aspx?a_id=53740

    2. It seems the message is that natural gas prices will rise, which seems reasonable. This will tend to reduce consumption and increase output, probably with a delay of 6 to 12 months.

      A number of pipeline projects are supposed to be completed in 2016, link to projects near end of article linked below.

      http://www.eia.gov/todayinenergy/detail.php?id=24732

      Another piece on pipelines.

      http://marcellusdrilling.com/2016/05/list-of-17-northeast-pipeline-projects-status-update/

      1. Dennis,

        Your EIA link for pipeline expansions is history. It states the 2 bcfpd of expansion that came on line in the first 2 months of this year. Currently the 400 mmcfpd, TETCO’s Gulf Market Expansion Phase I, came online as of the 1st of Oct. Though according to Bentek, may have a few teething issues. REX expansion is due for a 800 mmcfpd expansion, due the 1st Nov, along with AIMs 300mmcfpd, though they had an issue with a drill bit and a river crossing and could be delayed a little. After that, I don’t thing anything has been approved or in construction. Not of any distance or volume at least.

        On the other hand, there are heaps of projects that are held up in the approval process, at one stage or another.

        A little update on the Northern States storage situation,from Bentek

        http://www.bentekenergy.com/
        Dawn storage 99% full
        Tuesday, October 04, 2016 – 5:55 AM
        Union Gas began restricting storage injection overrun on Saturday which is a possible factor in Dawn injections slowing to average about 0.5 Bcf/d since the start of this month down from 1.1 Bcf/d over the second half of September. While Union Gas did not reply to a question from Bentek asking if this was due to high inventories at Dawn, this would seem a likely reason. Bentek models indicate Dawn inventories currently sit at 265 Bcf out of a listed 268 Bcf of capacity. Union owns approximately 156 Bcf of total Dawn storage capacity, with Enbridge owning the remaining 112 Bcf. Bentek uses an implied storage number to calculate daily Inj/WD in Eastern Canada and then uses monthly data released by Union Gas and Enbridge at the beginning of each month to adjust for any error in the implied figure over the month prior. The October 1 posting of this data is not yet available from either company, but it should be released in the coming week and there is the possibility that this could show Dawn inventories are a bit different from what Bentek’s models indicate. But even if Bentek’s model is overstating inventory levels somewhat, storage is likely to still be close to capacity right now, and further restrictions through October may continue.

        Dennis as you like to ask other peoples opinions, may i ask yours. If the price rises. where do you see demand falling the most?
        1/Rescom
        2/Industrial
        3/Electrical
        4/LNG export

        1. Hi Toolpush,

          If you look at the spreadsheet, it gives more info on projects through 2017.

          I don’t know how much demand might fall in those different sectors, probably LNG export would fall the most as their are other exporters with very low costs, so a rise in prices might make that fall to zero. Higher prices would probably affect residential demand growth most as new construction and heating replacements may go towards heat pumps (both air source and ground source depending upon climate), this might also affect the commercial service sector.

          There might be some affect in the industrial sector where natural gas is used for heat processes. In the electric power sector in areas with good wind or solar resources, natural gas may be reduced to a backup role and more coal may be used at those plants that continue to operate.

          The short answer is all of the above should decrease, but the relative proportions are not known by me.

          1. Hello Dennis,

            I am not sure which spreadsheet you are referring, but Marcellus drilling .com is a pay site, if you want the second page. The EIA does a spreadsheet of potential projects, and the time lines are based on the pipeline companies expectation. These expectations have been thrown into dis array by the FERC, who have not been approving projects on the same timetable as the pipeline companies expected, due to extra environmental studies having to be conducted. The Constitutional pipeline was actually approved by FERC, but stopped by the State of New York. As I said before, once REX and AIMs are online next month, nothing else in under construction.

            As for the drop in demand, in the short term. I expect the electrical sector will lead the way, with the coal plants that are left being ramped up to capacity. Wind and solar may have an effect, but it will be a longer slower ramp up. LNG will be interesting, as they have take of pay contracts on the LNG plants. Sunk costs could lead to what would seemingly appear to be irrational consumption. Rescom is fixed, but dependent on the weather, in the short term at least. There are several large industrial plants coming online this year. Ammonium Nitrate (N2 fertilizer) for one and probably some methanol plants, all in response the advertised cheap and unlimited nat gas from a few years ago. These plants will run.

            It is going to be a real interesting next 12 months in the US Nat gas market.

            1. Push
              The coming months may prove very instructive as the New England power supply situation continues to evolve (devolve?).
              In addition to the Constitution delay, the NED no longer planned, and, seemingly, even Spectra’s Access Northeast no longer viable, the New England folks are looking at a very precarious winter (2017/2018 will be worse).

              When prominent local politicians such as Rosenberg and Kulik, are clamoring – as they are – for immediate build out of LNG infrastructure so their constituents can keep the lights on, you know those people are in trouble.
              After years of demonizing fossil fuels and the pipelines to deliver same, a realization seems to be taking hold that cold temperatures will deprive the area of sufficient fuel for electricity.
              Coal and oil (!) backup may tide them over as it did all last February, but it will be cutting it close.

              I think the folks who embrace renewables, as, indeed, everyone, may learn a lot this winter by following the New England saga.

              Mr. Leopold may need to wait a long time for $20 HH, but the Algonquin Citygate, presently $8/mmbtu, may far exceed that.

            2. I think the folks who embrace renewables, as, indeed, everyone, may learn a lot this winter by following the New England saga.

              Renewables (and efficiency and substitution) aren’t magic. They don’t work if you don’t build them.

              You’d think people would already know that.

            3. Nick G
              Renewables most certainly are not magic, and, as far as working, Push’s fellow countrymen in South Australia just learned of the potential downside with the recent 100% shutdown of their grid due to problems with their wind generation infrastructure.
              Tell you what, Nick, let’s keep an eye on what takes place in New England the next few years, starting this December, perhaps.
              The tiny offshore wind project near Block Island should be running. Costs per MW are extremely high, scheduled to increase over coming decades, but … need to give it time for fair appraisal as it is the first of its kind.
              The hoped for hydro coming from Canada needs, surprise, transmission lines. Folks in New Hampshire, currently receiving 100% power from their nuclear plant, do not want their forests, lands, streams sullied by huge, unsightly towers to benefit Massachusetts consumers.
              The Danish wind turbine manufacturer is gearing up to provide a bunch of hardware over the coming decades when mega offshore wind projects are to be built.

              Meanwhile, just a short car ride to the west, some of the largest gas deposits on the planet are available.
              As more and more natgas is shipped south to Mexico to fuel that country’s shift from oil to gas fueled electricity, the hapless New England widget makers will be paying high utility bills while unsuccessfully competing with their Mexican competitors who will be using low cost US natgas.
              Bye bye NE widget makers … bye bye jobs, tax base to fund civic obligations.
              Oh, well.

            4. Well, sure, that’s what I mean.

              Oil and gas require pipelines. Wind requires transmission lines. For instance, wind power from Iowa is cheaper than natural gas generated electricity from Pennsylvania.

              No magic or mystery here. You’ve gotta make choices, and build something.

              Although…solar can be put on roofs. It’s a little more expensive than utility scale solar transmitted from places with better solar resources, but it’s a lot cheaper than doing nothing at all.

              For some reason, people in the US NE seem to prefer to wish and hope.

            5. Hi Nick,

              The solar resource is not very good in the winter, wind could work, but there may not be a big enough onshore wind resource. Transmission lines would make sense. They may already be in place so that cheap natural gas in Pennsylvania and Ohio could generate electricity and transmit it to New England, though a pipeline would probably be more efficient than using HVAC (high voltage Alternating current) transmission.

            6. Dennis,

              That’s all true. NE has many choices – they just need to implement some of them. A couple of thoughts:

              All of the cheapest choices involve importing energy. If NE cares about reducing local imports, they have a better chance with renewables. The US East Coast does have some solar insolation (perhaps 50% of the best areas in the SW) and decent offshore wind – it’s more expensive than imports, but that’s the cost of wanting “domestic” energy.

              And…if NE cares about the cost of pollution and other external costs (including security of supply & price and especially GHG pollution) then renewables are the cheapest choice, especially wind power from the central “wind belt” via HVDC.

            7. For what it is worth, there are two sides to the story of the major outage in Australia.

              A hell of a lot of the grid went down due to storm damage, there can be no question at all about that.

              The renewables folks down that way say the grid would have been down wind or no wind on the grid.

              I haven’t kept links about this particular blackout but might go back and hunt them up and post them in the non petroleum thread.

            8. Nick,

              I am the first to admit I do not always agree with your point of view, but I do agree with your following statement.

              No magic or mystery here. You’ve gotta make choices, and build something.

              If nothing is built, then either
              1/ continue burning oil
              2/Don’t de-commission the old coal plants 3/Don’t de-commission the old rusting nuclear plants
              4/Make do with less energy.

              Obviously the last is the ideal, but convince the locals that this is in their interest as the prices start to rise.
              Of course, there is always
              5/Import more LNG.

              I feel this will be the what will help out the NE keeping warm in the depth of winter in the future.

            9. Coffee,

              I wonder how many onshore wind turbines are going to be welcomed in the NE. As I understand it, wind turbines put out quite an annoying noise. This has become a problem in the sparsely populated places where wind turbines have been placed until now. In the more populated areas of the NE US, should bring out the NIMBYs in full force.
              As Nick says, They have to build something.

            10. Push

              Cornell University is pretty much Ground Zero for anti fossil use in the northeast USA.
              In their quest to become carbon neutral, the university is embracing wind generated electricity … so long as the turbines are not located on their beautiful grounds.
              If you wan some entertainment, read up on the defenses offered, the justifications for the placement of the “Wind Farm” in the nearby town of Enfield.
              Apparently, the Enfield locals are unaware that ‘small inconveniences’ are but a trivial happenstance when their ‘betters’ are saving the planet, dontchano.

              If the fuzzy heads in Cornell’s labs are ever to enable the stench of hypocrisy to become combustible, those folks could provide power for the entire universe for, like, forever.

  3. Speaking of Natural Gas, in about 2013 I bought UNG which allegedly follow the price of natural gas at $2/mcf. As you know NG is about $2.90/mcf. I should have had a profit of about 40%. Not! It turn out that UNG is a very opaque stock ETF that buys a lot of long term hedges and as a result I have a loss of 27%. Have cashed out at a loss. As usual Caveat Emptor. Just thought I would pass along my experience so others will not fall in the same trap. BTW this a great web site with a lot of smart people commenting and I really appreciate the work of Ron Patterson, Dennis, and others for their outstanding work. I don’t post that often as well I am a Doc and have no experience in the oil field bidness but I sure enjoy reading about it. Best Rich

    1. USO and UNG are for day trading not buy-and-hold. The monthly roll will kill you.

      If you want exposure to NG, try SBR (a RoyTrust) but do your research first

      1. If you want to play oil, for it’s coming rise, try UWTI. 3 times levered to WTI. Played it twice recently and did Ok. In and out in 5 to 7 days. The daily roll works against you. I missed the latest move as I was away.

  4. I wonder how much the Eagle ford production projections will be affected by the “low hanging fruit” phenomena. If the best drill sites were exploited first and depleted first shouldn’t there be a fudge factor in future output showing a decline? How on Earth could you estimate that effect?

  5. I love this hope springs eternal for the shale oil industry stuff; it’s plum entertaining. First it was technology, sliding sleeves and coiled tubing fracs, then it was just plain ‘ol mega – cram as much sand into them as you can- fracs for 1.2M BOE EUR’s, then it was EOR hope, then it was lower costs (my favorite when you borrow money and don’t pay it back anyway) and now its after 17,122 Eagle Ford shale oil wells in S. Texas they are still in the learning curve and going to be more profitable, they just need more time; the A team did not get it right but the B team will.

    What’s next?

    I know, I know: complete debt forgiveness and a do-over. Better yet, a do-over, with the FEDS paying for the well thru casing point. THAT should do it, that will for sure save the shale oil industry. Energy independence here we come !

    1. If you have 5-6 rigs running and you really are drilling good wells, at some point you should be able to fund your drilling through cash flow.

      1. I agree, Mr. Hightower; providing you don’t owe 8 billion dollars and are spending 6 dollars an incremental barrel on interest costs.

        BTW, I liked your comment the other day on sub surfacing mapping; of all the many hats I must wear to be a small producer, much like yourself, I understand, that is my favorite thing in the world to do… slip logs, pick faults, and contour all around the sub-terrain’ian world below us. I met a young EOG geologist the other day and I told him I was mapping something on a 1/200 scale with 10 ft. contours and he literally looked at me and asked, why? He was keen on TOC content in shale but likely never slipped an open hole induction log in his young professional life.

        1. It’s crazy Mike. I think when the spot we are in flips, we will be in a good spot to capitalize. These shale companies are killing themselves slowly over time.

  6. https://www.oilandgaseurasia.com/en/news/dallas-based-caelus-energy-alaska-llc-%D1%81laims-large-scale-oil-discovery

    Early estimates are six to ten billion barrels.

    This is enough, assuming it’s there, to supply the world for six months or longer. I am never sure when I see such a press release if the amount is estimated oil in place or the estimated amount that can be gotten out of the ground. Most press releases are apparently about the amount of oil in place, in which case the relevant number is two or three billion barrels.

    Getting it out is going to take at least ten to twenty years, and most likely thirty to forty years.

    I can’t remember the last time I read about a large discovery, but it’s been a while.

    It’s hard for me to imagine demand destruction outrunning depletion, since there are so many oil burners out there ranging from weed eaters to giant ships that it will take ten years at the absolute minimum, and probably twenty, for electric cars and light trucks, etc, to displace even a third of them.

    1. Is this shale oil or good old conventional oil where you can put in a few dozend holes, perhaps some infills and start pumping?

      With shale and alaska, in this freezing enviroment all this drilling and fracking should get really expensive, or slow due to interruptions.

    2. That is oil in place and in fact both numbers are a straight guess. They are estimating 30 to 40% recovery. Note they didn’t flow the test well they are relying on core samples, and those are company figures, not a “competent party report”, so a long way from “proven”. Probably a decent find even so, though there have been recent similar size claims that came to not much (e.g. Oman – 7 Gb to nothing and Circle Oil pulled out and wrote off all investment, Southern England shale – 100 Gb to … a lot, lot less, and some years back another putative 1 Gb find in Alaska that never got developed).

      http://www.adn.com/business-economy/energy/2016/10/04/caelus-claims-world-class-offshore-arctic-oil-discovery-that-could-among-alaskas-biggest/

    3. These are very preliminary estimates.

      From Caelus press-release:

      “Based on two wells drilled in early 2016 as well as 126 square miles of existing 3D seismic, Caelus estimates the oil in place under the current leasehold to be 6 billion barrels. Furthermore, the Smith Bay fan complex may contain upwards of 10 billion barrels of oil in place when the adjoining acreage is included. Due to the favorable fluids contained in the reservoir, Caelus expects to achieve recovery factors in the range of 30-40%.

      The Smith Bay development has the potential to provide 200,000 barrels per day of light, highly mobile oil which would both increase Trans-Alaska Pipeline System (TAPS) throughput volumes and reduce the average viscosity of oil in the pipeline, extending its long term viability.”

      https://t.e2ma.net/webview/61h5rb/b8a5ef6c056caf78b83d8ade238a1fb1

      1. Wiki for Smith Bay says there is a known oil seep in the region, presumably for decades. REALLY hard to see how BP and Shell and whoever else is up there didn’t look into the oil seep decades ago.

        1. Its a stratigraphic trap, some sort of Brrokian deep water sandstone fan. This type of play required tax breaks the state wouldn’t give until recently. They say they took sidewall cores.

          Small companies have a tendency to be optimistic, but if their description is right they could have a really decent find. This also opens up future heavy oil production under the Conoco-Phillips and BP units. The heavy oil needs a diluent, and this crude (they claim) is very light.

          I would guess they will eventually sell out because the development is difficult, requires pretty sophisticated work to get permits.

          Also, if the sands are as good as they claim then this isn’t something they have to fracture.

  7. OPEC announces a cut in November, and oil prices rise.

    If they follow through, I suspect the two years of low prices will be over.

    Just like after 1986, 1998-1999 and 2008-2009.

    Statements that OPEC is irrelevant may be premature?

    1. It’s hard to see why oil prices should be able to stay significantly above production costs.

      1. Hi me,

        It is pretty simple why oil prices would remain equal to production costs for the marginal barrel (highest cost to produce) because it is not profitable to produce higher costs barrels. In the long run a rational business person will stop drilling and completing wells that are not profitable.

        Why would the average barrel cost less to produce than the oil price?

        Again simple, all wells are not the same so there are many wells that are lower cost wells that will earn the companies a profit.

        Remember oil companies are not interested in producing oil, the aim is profits.

        1. Dennis,

          Yes, in theory, oil price should move around the cost of the marginal barrel (not the average barrel).
          And the cost is not production cost, but replacement cost, which includes production + capital costs + rate of return of at least 10-15%.

          1. + exploring costs + cost of CEOs etc. + costs of the oil producing state to not break out into civil war when oil is the main source of income.

            Otherwise, there is no future production without new oilfields and unrest (Nigeria …).

            1. exploration costs are part of the capex.
              Dry hole costs are normally included in operating expenses

          2. Hi AlexS,

            An economist would include all those costs (except rate of return) as the cost of production. The rate of return is the profit. Economic theory says investment will continue until the marginal dollar earns no profit. Salaries, etc. are included in costs.

        2. Hi Dennis,
          Any privately or corporately owned oil company can be expected to act rationally when it comes to producing only oil that is profitable, according to economic theory, and I am on board with that.

          But if we consider that the oil industry moves as slowly as molasses in January , we have to consider that management decisions made before the price collapsed are probably still determining actual day to day production in some cases. It may take a while yet for companies in this situation to finish up projects that are too far along to let them die on the vine, and some or most of them may be in too bad a bind for cash to simply shut in some or all of their money losing wells and wait for higher prices.

          Now I don’t know what the higher level text books say about NATIONALIZED oil companies decision making process, but I am sure they consider some factors above and beyond the basics of supply and demand, profit and loss.

          It is fairly obvious that their primary consideration must be to make a profit, so as to have a surplus to be used as the government sees fit.

          But oil company managers at nationalized oil companies are also obviously subject to a hell of a lot of pressure from other folks higher up the pecking order and thus aren’t able to do the rational thing all the time or maybe even most of the time.

          Providing steady employment for the workers, maintaining existing long term relationships with customers, and preserving the illusion if not the reality of internal economic stability, etc, are some factors that could result in producing oil that must be sold at a loss.

          I have no way of knowing how important these factors are, but maybe you or some others can throw some light on how much they matter.

          But it seems that a good case can be made for some countries some of the time using oil as an economic weapon of war, with very little consideration given to the cost of production versus the selling price in this situation.

          1. Hi Old Farmer Mac,

            To be honest I forget what the textbooks say about a monopoly situation, except it is not the same as a perfectly competitive market (think apple producers). For the US the oil industry is pretty close to the perfectly competitive market so in the long run it should approximate that.

            Even apple producers move pretty slowly as it takes time for trees to grow.

  8. It seems inevitable that production in Venezuela must decline soon, and stay down, until that unfortunate country’s political problems are solved, and that is going to take a long time, even after they bottom out.

    Getting rid of Maduro is taking longer than I expected, probably because he has the loyalty of all the people who ARE getting food and medicine, etc, by way of preferential handout and employment of supporters.

    Oil workers are selling their uniforms.

    http://www.reuters.com/article/venezuela-oil-workers-idUSL2N1CA0ZA

  9. The situation in Venezuela is constructed by low oil prices, certain government failures and the intention of the upper class to capitalize the actual crisis (with support of the US). While we can argue if Maduro does or does not implement the right politics, one must know that in Latin America doesn’t exist common ground between the political oppositions. This is not the US nor is it Europe. Rather than dividing Venezuela’s politicians in good and bad ones, you have to see the whole picture. And it’s very dire. A takeover of the right would probably lead to civil war – a situation which the land already had to face in the nineties (and brought Hugo Chavez into power). May nobody believe that the conservative class in Venezuela has any scruple to use violence or to be in any sense more humanitarian than the Chavist government. In economical terms they are probably more efficient – but at what price? Again: There are no good or bad ones, nor does any will exist to put the country on a functional base everybody could live with. And the US will do nothing but helping to push the country towards the failed state status – just like they did with Libya, although in a more covert style.

    1. The discussion of Venezuelan political and cultural affairs should be in the non petroleum thread, so I am copying your reply to that thread, and will comment on it there.

      1. Agreed Oldfarmermac – but as I still can’t find it there I copied it there myself.

  10. Bonanza Creek Energy, an oil company I have followed for a couple of years now, just watching what happens to the price of a share for curiosity’s sake. In October of 2014 the share price was above 60 usd. Today, it is trading at 1.03 usd.

    That is close to a 97 percent drop. A fall from grace swan dive style.

  11. BHP Billiton did an investor presentation on future prospects yesterday:

    http://www.bhpbilliton.com/~/media/bhp/documents/investors/reports/2016/161005_richsetofopportunitiestodrivevaluablegrowth2.pdf?la=en

    They announced finds in GoM at Caicos / Shenzi North but didn’t give numbers. They also predicted FID for Mad Dog II in the next six months with first oil 2022 and plateau in 2024 (that’s a long schedule for a 120,000 boed project I think, ddep water though).

    Most interesting was their world view for new oil supplies for 2025 (as below). They indicate about 32 mmbpd required (I think 10 are increased demand, the rest for decline). Only 7 mmbpd come from the Middle East – which I think would mean that area is in decline overrule by BHP forecasts. Heavy oil is relatively small at around 4 mmbpd. Shale core and non-core (all in USA) is about 11 mmbpd – I don’t see how that is even remotely possible, but they indicate the core increase can happen at $45 per barrel average. The rest is deepwater (at $60 average) and other conventional (non ME) at $55 (the largest single block – I have absolutely no idea where they think that oil is, maybe Russia?).

    Their mid range price forecast hits $65 in 2019 so about half of their predicted new oil would have to come from projects going through FEED / FID and ramp-up in the 5 or 6 years after that (and a large chunk would also have to be discovered first I’d guess) – I don’t think that is possible even if the oil exists.

    1. I don’t get it anyway – if much of US shale is profitable at 35$, why isn’t there a huge oil boom raging on again???

      At 50$ now (which can be used to hedge) it would be easy to make billions of dollars by just getting cheap money from wallstreet and start a drilling frenzy – not only this slowly adding of a few ridges, which is only a shadow of the 2011-13 oil boom.

      1. The chart shows that US shale core is profitable at oil prices between $35 and $62.5.
        Non-core at $65-100

        $35 is the lower boundary of the price range

        1. By this chart, not in reality. At 35 dollar gross oil prices there is no take home pay after expenses for shale oil folks, NONE. At 60 dollars less than 30% of the shale oil wells historically drilled in America’s major shale oil plays will reach payout, looks to me, based on Enno’s work. Besides, how much more “core” acreage can there possibly be after 65,000 shale wells? They are not saving the best for last. And of course, don’t forget the big boogie man, debt. Anyone with the knowledge and ability to develop remaining shale oil resources is so deeply in debt it will take triple digit oil prices for them to deleverage legacy debt and manage new debt. As to shale oil, the chart is meaningless.

          1. Mike,

            In my view:

            1/ most of shale breakeven price estimates, including this one, are indeed too low as they do not include some important cost items (such as interest, etc.);

            2/ this estimate is still better than many others as it shows that large part of core shale areas remain unprofitale at $50. And non-core can be profitable only at very high oil prices.

            3/ the most recent breakeven prise estimates reflect a 30-35% deflation in drilling and fracking costs. This is much more important than the effects of improvements in technology. If and when drilling and fracking activity rebounds, drilling and service companies will inevitably increase their rates, and we will see cost inflation (though I do not expect a return to 2014 levels any time soon).

            4/ I agree with you that, even if shale companies’ economics improve with higher oil prices, and they become cash-neutral, there remains the issue of debt accumulated in previous years. Besides, being cash-neutral or slightly cash-positive, implies very modest growth in capex from the current low levels. And relatively modest capex cannot support a return to ~1mb/d annual growth in LTO volumes (seen in 2012-14). Shale companies simply cannot afford sharp increases in spending as it would result in rapidly inflating debt.

            5/ the above chart shows potential additional supply from core shale areas of ~6 mb/d by 2025. I do not think this is realistic. First, because of inevitable cash constraints. Second, I’m not sure that such large number of new wells can be drilled in the core shale areas.

            Summing-up, I think that U.S. LTO production will rebound from early 2017 and can even reach a new peak by the end of this decade. But I doubt that this peak will be well above the previous peak of April 2015.

            1. Thanks AlexS,

              That sounds reasonable. If oil runs short (and this seems likely by 2018 or 2019) then oil prices might rise to $100/b or more, if that happens by 2019, I believe the previous LTO peak might be surpassed, if so it will not be by much, maybe 500 kb/d at most, but more likely around 200 kb/d above or below the previous peak, is my guess.

            2. Thank you, Alex; you have, as I suspected, a good handle on it. Personally I think shale oil development is only marginally profitable at 5o dollar oil prices, even in core areas, and that marginal profitability is woefully insufficient to deleverage legacy debt and manage new debt. We agree on that, and specifically agree that “technology” to improve production will not save the shale oil business model, only lower costs will. My actual experience from operating conventional oil and gas production in the middle of the Eagle Ford shale play is that prices have NOT declined 30-40%, only 20% at most, and costs are actually increasing again from demand on now very limited service capability. Very little of what the shale oil industry states about itself is true, this from actually owning interest in shale wells and operating myself in the largest shale play in the country. I am often left dumbfounded at economic presentations and promotional campaigns by the shale oil industry, and how gullible people are…particularly those funding shale oil well manufacturing.

              We differ only from the standpoint of recovery. Debt now controls the shale oil industry, little else. Costs will go up, as you point out, and contrary to some, I do not believe the price of oil will recover to 85-90 dollars, the level that myself and, for instance, Rune Likvern, feel is necessary to cope with debt. Not soon enough, anyway. Regardless, the financial condition of 95% of the active shale oil companies in the US is dire and they will not survive, in my opinion. Again, what happens going forward to the US LTO industry is all about debt, and finances, not costs, technology, learning curves or “hope” for higher oil prices.

            3. I agree Mike that at least $85/b, maybe $90/b will be needed. We just differ on whether that will happen. I think the World will be very short on oil by 2019 and we may see $100/b by Sept 2019. I am usually wrong on oil prices and as you believe the oil price will be under $60/b, if you are correct (and that is more likely) the LTO industry is toast.

            4. Dennis, 85-90 dollar oil prices will happen again, though not in sufficient time to save the LTO industry that exists today. It is already toast by every definition.

              Pity, that. We need the stuff, or we will need it some day a great deal. But by then light tight oil will be so important the government will intervene, for the benefit of all society. Had the shale oil industry been properly regulated, its fiscal irresponsibility put in check, it might have survived and been in the cat birds seat. As it is, the shale oil industry got too greedy, and was too stupid, to see that far in the future. We have become a society of instant profit, to excess, and immediate gratification. This shale oil phenomena is a perfect example of that.

            5. Mike, isn’t the government (Wall St) already involved?

              Plus If shale has pricing power maybe its not ‘already toast’.

              Do you really expect fiscal responsibility from the government in running shale oil operations?

              It seems like you have done a 180 degree turn after seeing the BHP graphic above. Some time ago you said this was a bad source rock to base future energy dependency on.

      2. Eulenspiegel –
        You do understand [or not] that if you wanted to make $1 billion by borrowing the money to drill and produce oil at a cost of $35 and sell it for $50, that you would have to hedge 66,666,666 barrels on the NYMEX [or privately with Goldman Sachs, etc.].

        Sounds pretty easy to me. However, by hedging, that means you go short oil at $50. And there is a MINOR detail with hedging. You have to put up margin if your contract is “underwater.” So, let’s say that by the time you start drilling, the price of oil rises to $70. No problem?? – not so fast. Sure, you are eventually going to deliver real oil against your short contract [at $50] , but the MINOR detail is that you have to put up a CASH margin call of $20 per barrel, or merely $1,333,333,333 [70-50 = 20 x 66,666,666], just as you start drilling with already “borrowed money.”

        Now, does that still look EASY???? Unless you have DEEP pockets [think Warren Buffet], no one will let you do the hedge.

    1. from NYTimes article:
      “The new discoveries have also reinforced the confidence within the industry that the United States will remain a major oil power — capable of producing substantial amounts for itself and exporting major quantities around the world.”

      …exporting major quantities…???

      Current crude exports are basically zilch, 400-500 kbpd recently.
      Compare to net crude IMPORTS of 7,270 million bpd.
      https://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z00_mbblpd_w.htm

    1. I encourage all to review Enno’s recent update.

      Try looking at production for each year as of December of that year, then look at those wells in June, 2016.

      For example, 2014 wells have declined over 1.8 million bopd from 12/14 to 6/16. 2015 wells have declined over 800,000 bopd from 12/15 to 6/16.

      Enno, is this correct? Over 2.6 million BOPD from the peaks in just these two years?

      2. Hi Shallow sand,

        Keep in mind that the data for Texas is incomplete.

        You can see this at Enno’s site by paying attention to well counts at the two dates.

        In many cases the well count falls not because the well has been shut in but because of the incomplete nature of the Texas data. So in June for example the Eagle Ford has declined 128 kb/d less than Enno’s data shows, a similar percentage could be used to estimate the TX Permian basin, Bakken is probably accurate, I don’t know about Niobrara and NM Permian. They might be like Texas or the data might be as good as North Dakota, Enno probably knows as he looks closely at the data.

        1. Dennis: Still a pretty steep decline.

          Seems odd there would be slow/inaccurate reporting for wells that were completed in 2014 and 2015, especially 2014.

          1. Hi Shallow Sand,

            It’s just the way it is done in Texas.

            For Texas wells that started flowing in 2013, there were 6853 wells producing in month 20, 6829 wells in month 30, 4547 wells in month 35, 1480 wells flowing in month 40, and 463 wells in month 42 (final month reported for 2013 wells). The reason the data for the most recent 18 months is not very good is because not all wells are reported in a timely manner.

  14. Everybody is after ExxonMobil:

    “Exxon Mobil fined $74 billion by Chad court over royalties”

    http://www.bloomberg.com/news/articles/2016-10-06/exxon-mobil-disagrees-with-chadian-court-royalties-ruling-itydgz6c

    The Chad-Cameroon project was one of the bigger recent busts for a major in terms of expected reserves at the time of project sanction versus actual recovery (I don’t know the exact figures but maybe 40% lower than expected), and it looks like things are getting worse.

    1. Rig count is still at a very low point compared to the average for the last 5 years or so. I believe this will have a serious effect on 2017 production and likely 2018 production.

      1. Interesting to note where rigs aren’t being added, despite price rises over the last couple of months – Eagle Ford, Bakken, and Niobrara, even the Permian seems to have stalled.

        1. And we lost 2 gas rigs. Despite the move up in price the last 6 months. These gas plays are not economical at these prices either

    2. The ‘North Sea’ rig count is the lowest since records began in 1982 apparently. But it has held up quite well over the years. Not all rigs are in the North Sea – most are in Norway (16 out of 24 for oil) and some are in the Barents and Norwegian Seas. It’s noticeable how gas rigs have dropped much faster than oil in the last two years as well, I don’t know what that exactly foretells though (geology or LNG glut or something else).

  16. OPEC SEPT CRUDE OIL OUTPUT JUMPS AGAIN TO RECORD HIGH OF 33.24 MIL B/D

    October 7, 2016
    http://www.platts.com/news-feature/2016/oil/opec-guide/index

    OPEC crude output rose again in September to a record high of 33.24 million b/d, an S&P Global Platts survey showed October 6. The figure is 110,000 b/d higher than August and marks the fourth consecutive month of growth, as output rises in Libya, Iraq, Nigeria and Iran more than offset declines from Saudi Arabia, Angola, Qatar and Venezuela.

    Iran, Libya and Nigeria are reportedly exempt from the tentative production freeze announced by OPEC in the week ended September 30, which will see the group keep output between 32.5 million and 33 million b/d.

    Iraq, meanwhile, has already voiced its displeasure at various secondary sources, including Platts, which it says are underestimating the country’s output, potentially putting it at a disadvantage when the individual country quotas are set.

    Final details of the freeze — including which sources are used to verify compliance — are to be decided by OPEC’s next formal meeting, November 30 in Vienna.

    The Platts estimates are obtained by surveying OPEC and oil industry officials, traders and analysts, as well as reviewing proprietary shipping data. Iraq production rose to 4.4 million b/d, according to the Platts survey, with exports of Kirkuk crude resuming after an agreement between the Iraqi central government and the Kurdistan Regional Government to transport it to the port of Ceyhan.

    Libya saw its production rise to an average of 340,000 b/d in September, as the state-owned National Oil Company lifted force majeure on the Es Sider, Ras Lanuf and Zueitina terminals in mid-September, paving the way for a rise in exports and output. NOC chairman Mustafa Sanalla told Platts on the sidelines of the OPEC talks in Algiers Libyan oil production had reached 485,000 b/d by late-September, as exports from Ras Lanuf continue to rise and the Harouge and Agoco fields ramp up production.

    In Nigeria, production rebounded somewhat to 1.49 million b/d in September, after the force majeure on Bonny Light was lifted, and production of its two main export grades Qua Iboe and Forcados was said to have gradually picked up, with exports resuming in early-October. The government has reached a tenuous ceasefire with rebel militants that have attacked oil facilities in the Niger Delta, although the Bonny export pipeline was bombed mid-month, affecting loadings of Bonny Light.

    Iran, which had seen its output plateau at 3.63 million b/d for the previous three months, was able to raise production slightly in September to 3.65 million b/d, as exports ticked higher.

    Saudi Arabia, OPEC’s largest producer, saw a decline in September to 10.55 million b/d, according to the survey, after setting its all-time survey high of 10.66 million b/d in August.
    Reduced crude consumption for air conditioning, as peak summer temperatures moderated during the month, along with lower refinery runs offset higher exports, the survey found.

    Angola production declined to 1.73 million b/d as the Plutonio field went offline for maintenance for about 10 days. The country is expected to see further declines in October, with loadings of Dalia, which normally range between 200,000-230,000 b/d, set to fall to zero next month due to field maintenance.

    Qatar saw a decline to 640,000 b/d, with traders saying partial shutdowns at the Al Shaheen facilities that began September 7 reduced oil cargoes by 5%, with some loading dates deferred. The partial shutdowns are expected to continue through the end of October.

    Venezuela continued its decline in production to 2.1 million b/d in September, as the country struggles with its economic crisis.

  17. I don’t think anybody has posted this yet.

    The guys who wrote it are well known and well respected in this forum.

    I haven’t given it enough thought to come to any conclusions, but my first cynical and sarcastic thought is that the data are being manipulated in order to advance the agendas of those with the power to bring about the manipulation. Banksters are always a tempting target when I am in the mood to sling some mud, lol.

    http://www.forbes.com/sites/arthurberman/2016/10/07/u-s-storage-filling-up-with-unaccounted-for-oil/#6271d5be7f74

    Something needs fixing. Let’s hear some opinions as to what it is, lol.

    1. The balancing formula for crude oil, on a per day basis is:
      ProductionEstimated + Adjustment + NetImports = InputToRefineries + StockBuild
      See:
      http://ir.eia.gov/wpsr/overview.pdf
      Lines : (1) + (13) + (4) = (14) + (10)
      So , Adjustment is a proxy for production under – estimation, as other quantities seem to be more accurately measured.
      Strange enough, the cumulative daily average adjustment for 2016 is 83 kbpd (KiloBarrels/Day)
      versus 223 kbpd in 2015 ( see line 13 toward end ) . As EIA production estimation includes Texas , this would suggest that in the last months , EIA bias is not for Texas production under-estimation, but on the contrary!!

    2. Art and Matt seem to have buried the lead on this one. Made me wade through all those charts and statistics (and having me do it is only a little better than having your dog do it.) You have to get to page 6 to see what they’re talking about, and even then, they don’t actually say it.

      The authors feel that unaccounted-for oil inventories, which make up 80% of reported stocks at the moment, are too high, and are a factor driving down the oil price. They suggest that the most likely explanation for the unaccounted-for oil is the over-reporting of crude oil storage. Over-reporting storage has no tax or other financial penalty, whereas the other possible sources of unaccounted-for oil ( production, imports and refinery inputs) are all taxable transactions. There would be costs associated with over-reporting, making it unlikely.

      (edit)The authors don’t offer any reasons why anyone would manipulate this value.(end edit.)

      My thoughts:
      It does raise the question of whether refiners (who I assume hold a lot of storage) would benefit from over-reporting. Lower Oil price could mean lower gas prices at the pump, which might mean more gas sales and therefore more refinery business, particularly since it has been going on for years (gas usage is not flexible in the short term, but rather based on people being comfortable buying larger vehicles.) The problem is that many of the refiners are also producers. I’m curious as to where the most money can be made: on the refining or the production side, and if there is, indeed, a benefit to them from keeping the price down.

      Oh, and the underlying implication is a conspiracy of some kind, because no single entity could cause this deviation.

      -Lloyd

      1. To be fair to Art and Matt, it’s possible that Forbes editors and there web format made it difficult to get to the meat of the article. That Forbes forces readers to page through an article is annoying and kind of a web anachronism.

        That said there has been a lot of storage infrastructure built lately which implies a need to store oil.

    3. This was written by somebody who has never worked on a tank farm. The actual storage in the tanks is a small percentage of the annual flow through the plant. However the thing that can be measured accurately is the tank levels – there are electronic instruments (e.g. based on pressure) but there are also outside gauges which can just be looked at and recorded by shift operators. What is more difficult to measure is flow, which has to be inferred from other indirect measurements, often non-linearly, and also can require knowing the fluid density not just its velocity. Therefore the flow has some error in it (noise and a bias). For fiscal meters (i.e. where money is involved, compared to those just used for plant operation) the error is required to be very small, and the meter has to be regularly calibrated and certified. But the errors are never zero. Therefore you are taking the difference of two very large numbers with non balancing errors (input minus output) to give a very small number. The errors that were a small percentage of the big flows are now a very large percentage of the small residual storage change. Therefore they have to be corrected against actual level measurements, which have very small errors of a very small (relatively) quantity.

      In the past I have had dealings with refineries (no names), which employed specific operators to make full use of the allowed error range – i.e. to under read as much as legally possible for the intake from suppliers (tankers) and to over read as much as possible for deliveries to customers. This made millions of dollars over time. Just part of the business and overall it is balanced by price changes, if you don’t do it you lose out compared to the competitors.

      It is interesting that the adjustment has had to grow as shale oil has come on line – could be something to do with density adjustment or how volumes change during blending (i.e. it’s not strictly linear), but I don’t know for sure. However I suspect there are people who do, and might be making money out of it (legally).

      1. In the past I have had dealings with refineries (no names), which employed specific operators to make full use of the allowed error range -snip-It is interesting that the adjustment has had to grow as shale oil has come on line

        Is it possible that the growth in unaccounted oil could have something to do with the size of loads? Might the cumulative error from many small loads (tank cars or trucks) be greater than from the same volume delivered by pipelines or ships?

        -Lloyd

        1. Lloyd good point – metering on road and rail tank cars might be different from pipelines and ship tankers. It might have different regulations or just be more liable to errors as there are so many. I don’t know for sure though. In fact I don’t know what measurements and reporting methods EIA uses to collect it’s data.

        1. Should be interesting to see (we already are beginning to) what happens, since, apparently, the lower the EROEI, the less people/societies(/’governing’ bodies) can afford; while at the same time, I seem to recall Watcher suggesting that price (if not actual cost/affordability) can be decreed.
          (Although how good is the energy for those bodies to enforce those decrees?)

          I guess money/price is a kind of denial (whose strengths and effects can be modulated).

    1. I don’t think it’s that bad. Otherwise the truth would be out since a long time.

      Looking for input output isn’t the only way to estimate the oil storage – you can simply measure how many oil is in the tank, and the tank company should know these values exactly.

      If they would be almost empty, no one would build new ones as they do the last 2 years(they are expensive after all), and workers would talk in bars (only dust left in our storage…) or online forums like this one, so in a forum like this the truth would come out if they are empty instead of almost full.

      The incorret numbers in the storage report can be another thing – a mixture from simply accounting fraud, tax evasion, “black” oil from ISIS, stolen tankers, mafia etc. disturbing the numbers.

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