Texas and Eagle Ford Update April 2017

Dean Fantazzini recently updated his estimates for Texas Oil and Natural gas. Data from the Texas Railroad Commission has improved so correction factors are smaller, the estimates from Dean now match the estimates by the US EIA fairly closely for Crude plus condensate (C+C) produced in Texas.
There was a noticeable change in the Texas data about 6 months ago so I show an estimate based on the correction factors from the previous 6 months. Dean prefers to show an estimate based on all the data (which he has done for many months) and an estimate based on the most recent 3 months of data (which has been presented more recently). The EIA estimate is more consistent with the 3 month or 6 month estimate with the “all vintage data” estimate being somewhat higher.



For Jan 2017 the estimates for the 3 month, 6 month, and EIA estimates are 3196, 3191, and 3195 kb/d respectively for Texas C+C output. The “all vintage data” estimate is about 200 kb/d higher than the others.
In the future I will drop the all vintage data estimate.
The natural gas estimate is shown below.


Enno Peters recently updated his Eagle Ford region estimate which includes all horizontal well output from Districts 1 to 5 in Texas. I modified this by finding the percentage of total Texas output from this region relative to the Texas RRC Statewide output estimate. Then the EIA’s Texas C+C production estimate was multiplied by the previous percentage to obtain a new Eagle Ford region estimate. Enno’s estimate is labelled “shale profile”, my estimate is labelled “modified SP” where SP is Shale Profile.


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103 Responses to Texas and Eagle Ford Update April 2017

  1. Marcus says:

    Thank you for your efforts Dean Fantazzin & Dennis

  2. Re gas peaks.
    In his energy white paper 13 years ago Australian Prime Minister John Howard ignored warnings on peaking conventional gas production on the east coast which lead to a flawed LNG export policy without domgas reservation. Result: power shortages in the summer 2016/17

    Howard’s energy super power stuck in domestic gas shortages

    • Ian H says:

      Off topic… but: Oz has a massive shale potential in the McArthur Basin; specifically the Beetalloo sub basin has several basin wide shale horizons, one of which has had a short horizontal frac production tested. Origin energy (the operator & owner of 30% interest) estimate 500TCF in place in the tested horizon on the basis of the test. A fraccing ban was then imposed, over concerns of carbon impacts and groundwater and soil pollution etc. On the other hand the area has less than 10% of the population density of Siberia, so people are not so at risk of the induced earthquakes.

      The shales are old (pre Cambrian), but it is theorised that they were matured recently when the region traversed a hot spot.

      The unplanned load shedding events and greenouts in Oz make the lifting of this moratorium a distinct possibility. It would also bring much employment, but would upset the big foreign cattle ranch tenants, who worry about fraccing fluids/ earthquakes killing their cattle etc.

      I am not a petroleum geologist, I dont know how well the Beetaloo compares with the Appalachian shales, it certainly covers a large area, a link to some week end reading material is here:

      This isnt an investment blog, but Falcon O&G should be an interesting story to follow over the next couple of years IMO, as they own 30% of the Beetalloo shale. They had a disaster in a over hyped basin centered gas accumulation in Mako, Hungary that didnt deliver, (wrongly)compared to the Jonah/Pinedale field at the time IIRC. They also have an interest in the Karroo basin in South Africa, pie in the sky at the moment, though a similar ban on shale may be lifted eventually.

      In principle shale could come to the rescue in Oz and keep the air con on.

      • scrub puller says:

        Yair . . .

        Dunno Ian H. This may not be shale as you know it . . . as I understand it think more Green River.

        But I could be wrong.


    • Caelan MacIntyre says:

      “The American investment banker Matthew Simmons (book: Twilight in the Desert, the coming Saudi Oil Shock and the World Economy) used some of my graphs in his slide show to the Pentagon, on Feb 19th, 2008” ~ Matt Mushalik

      Well, they are probably the hottest, juiciest, most colorful graphs I’ve ever seen. And very tastefully displayed on a dark-gray background, they are further emphasized and help bring that data out and get it seen. They’re almost art. Before I selected your linked name, I thought to myself, “This must be the guy with the colorful graphs on the dark gray…”, and sure enough!

      But, Matt, now that I think about it… Someone hereon has some graphs that you can actually fiddle with directly on their site, like tweak them and stretch them and maybe select for certain variables or whatnot. It might be Enno. Do you have something like that or would want to?

      BTW, I love the name, Beetaloo. It’s the first time reading it. It is so cute, like a loo for beetles or something. ^u^

  3. HuntingtonBeach says:

    Price of oil spikes at same time U.S. fires cruise missiles. Heavy off hours trading.

    • My Russian friends say that Putin will only respond via diplomacy and some stepped up bombing of rebel forces. The Syrians will shrug their shoulders and bitch and complain. The “chemical attack” has all the signs of being a false flag operation, which was leveraged by the USA “imperial state” to justify a stupid attack. So the USA used up $75 million worth of missiles and it lost this particular propaganda battle (which of course the USA public won’t even realize given the USA media’s distortion of what goes on in real life).

      I think the oil market will realize this is an inconsequential move and prices should come down in a while. However, I’m still thinking the $63 average is viable for the year, although it’s looking a bit iffy right now.

      I also want to point out the attack is a clear violation of the us constitution, which requires the USA president to obtain congressional approval before engaging in an act of war


      • gnutim says:

        it’s an important specification!

      • Wake says:

        I don’t think the US would gas children in a false flag. I don’t think there is any evidence of it or any reason to suggest it other than dislike for the us. I am aware of terrible acts by all governments over time. But for one there are still people making the decisions and for two the risk would be too high were it ever discovered

        • Boomer II says:

          Also, would the Trump administration actually sour relations with Russia just to create a distraction?

          I’m thinking, though, that it seems unlikely that the US will drop the oil sanctions against Russia anytime soon now.

          • Boomer II says:

            Well, maybe Fernando isn’t so far off after all. Evidently the Russians knew the bombing was coming, alerted the Syrians, and then the US dropped bombs that resulted in mostly show because there was no one left on the bases.

            • Lloyd says:

              Indeed…a conspiracy theorist might note that it is in both Putin’s and Trump’s interest to get the electorate’s attention off of the investigations into Russian interference in the US Electoral process- particularly if there was collusion.


          • This is an extremely complex set up. USA democrats and neocons are in a alliance to attack Trump over Russia. The democrats simply want to overthrow Trump. The neocons want the USA on a war footing, they are like rabid dogs. So trumps approach towards Russia was something they couldn’t stand. This explains the intelligence leaks and the continuous barrage of innuendo without any solid proof.

            Trump, who is quite impulsive, narcisistic, populist, and doesn’t seem to give a hoot about risking wars, decided to take the bait, go full bore anti Russian, because this defuses the neocons, and puts the democrats in a bind. This is why now we see the conspiracy theories about Putin and Trump being in cahoots about a “fake attack”. We have to understand the democrat propaganda machine won’t stop until the Russians nuke Washington.

            The risk of war involving tactical nuclear weapons is very real.

            The Russians simply won’t knuckle under a USA imperial power they see trying to destroy the Russian federation. (whether Americans believe that is irrelevant, the Russians do believe it, and I think they are right, the USA neocons are quite open about trying to impose American imperial rule).

            The tactical weapons would be used if the USA starts taking out Russian assets. I would expect a tactical nuke set to explode in the air on top of a USA base or aircraft carrier fleet. The Russians, of course would give a 2 minute warning.

            • Boomer II says:

              “The tactical weapons would be used if the USA starts taking out Russian assets. I would expect a tactical nuke set to explode in the air on top of a USA base or aircraft carrier fleet. The Russians, of course would give a 2 minute warning.”

              Why would Russia risk a major US response to that?

              What US action would lead Russia to use nuclear weapons against the US knowing that the US would respond with force? What action would lead them to the brink of WWIII and a likely unwinnable war?

            • alimbiquated says:

              I think the Russians are just enjoying watching Trump flailing, and feel pretty confident that he will keep the Western establishment too busy to do anything useful for the next 4-8 years.

              Putin can’t up his own game, because he has no vision of Russia’s future, but he figures disrupting the West will keep him from falling too far behind. He apparently doesn’t realize that by playing the disruptor in the West, he is just falling into the hands of the Chinese. Like Trump, he is stuck in the 20th century.

        • Pete Mason says:

          Didn’t take fernando to be suggesting that kind of false flag, just the kind where you say an atrocity has taken place as an excuse to ramp up a war or force a president to show his hand

        • The gas escaped from an Al Nusra weapons depot. The Syrian regime knew they were manufacturing and storing something, so they struck it at sunrise with two guided bombs.

          The full explanation has been made available by various sources. Thus the false flag refers to American propaganda attributing the gas release to the Syrians when it was a bit more complicated. I’m aware USA media knows this is probably what went on, but thus far they are keeping it quiet. This is turning out to be similar to the Iraq WMD falsehoods used to start the war in 2003.

          • Lloyd says:

            Hi Fernando.
            It always worries me when I think Fernando is right about anything besides oil well engineering.

            However, I do think this explanation- that bombing a rebel chemical weapons stockpile or factory- is more likely to be the correct one.
            The issue for me is why would a country use a weapon they are not supposed to have, and that will have extreme negative repercussions if you are found out, for such a small advantage? It makes no sense for it to be a simple “state terror strike”. It makes more sense to be an attack on a rebel munitions factory or storage area.

            It doesn’t really matter if they knew of the potential for a toxin discharge: the US wouldn’t be concerned about collateral damage when protecting its citizens in such a situation. And indeed, unleashing 50-odd Tomahawk missiles on a military base that they claimed was the point of origin for the chemical weapons would be exactly the same thing- unless, of course, they knew there were no chemical munitions at that location.(Though it’s also possible that an airfield would not have the same potential for collateral damage because its not cheek by jowl with civilian structures, and thtat this might have been factored in.)

            The missile strike also potentially destroys, or muddies, contrary evidence: flight logs, chemical weapons handling facilities (or the lack thereof), etc.

            This is more likely a pretext to start a war. Yellowcake uranium all over again.


      • Nathanael says:

        The President has ignored the War Powers clause for a very, very long time. Continuously starting with the Korean War, but also repeatedly in the second half of the 19th century. Since the end of the Vietnam War, the President has also ignored the War Powers Act, passed with an override over Nixon’s veto, which implements the War Powers clause. Most Presidents have openly refused to obey the law on this.

  4. SRSrocco says:

    Yes… it seems as if the U.S. Govt and Pentagon have another leader in the crosshairs that they went to remove. How many is that now?? Would be interesting to see the reaction if another country said, we need to get rid of Obama or Trump. Funny how the world looks from the other side.

    That being said, Saudi Arabia continues to BURN THROUGH ITS CASH RESERVES as the low oil price is not allowing it to pay all of its bills. Saudi Arabia liquidated another $9.8 billion of its Foreign Exchange Reserves in FEB, on top of $11.8 billion in JAN. Saudi Arabia has liquidated 32% of its Foreign Exchange Reserves in just the past two and a half years.

    While it still has a little more than $500 billion remaining…. any continued weakness in the oil price will make a BAD situation WORSE for the Kingdom.


  5. George Kaplan says:

    Baker Hughes international rig count out today: up 2 overall, offshore down 3, biggest drop in Europe – down 13/Latin America up 6, oil up 14, gas down 4 (difference is misc.)
    Offshore continues to drop and is near the lowest numbers seen in the late nineties. Including North America offshore (below) and the drop is much starker. Offshore was not broken out before 2000, but there were a lot of rigs in GoM then (mostly shallow gas) and probably a a significant number immediately before). Offshore is being affected by more than just price I think – there is component of just running out of attractive places to drill as well.
    Ecuador still has 7 rigs. I don’t quite follow these numbers – Schlumberger and Haliburton (or might be Baker Hughes) are supposed to have spent, respectively, about $3 and $1 billion dollars there over the last few years (and not been fully paid), which would suggest much more activity than those few rigs. Also that is not enough to maintain 500 kbpd of heavy oil production on their own. Maybe a lot of the work is work overs and/or retrofitting downhole pumps, or maybe not all drilling digs are counted by Baker Hughes.


    • Yaman Tasdivar says:

      Could you please provide support for “there is component of just running out of attractive places to drill as well”

      Thank you in advance.

      • Dennis Coyne says:

        Hi Yaman,

        George follows the deepwater drilling very closely, the projects that are out there that have not been sanctioned are not attractive at $55/b. In addition there have been very few new oil discoveries since 2014 and most oil discoveries have been pretty small in size.



        Also note that the “breakevens” of $40/b assume zero ROI and ignore royalty and tax payments and is a wellhead price (typically $4/b less than Brent).

        When we do a “real” breakeven oil price that accounts for a reasonable ROI (at least 5% per year), as well as royalty and Tax payments of about 32% combined in Texas, the result for the Permian is about $65 per barrel, and it is likely for deep water projects the breakeven jumps to $85/b.

        Another thing often included in these projections is that barrels of natural gas and NGL are converted to boe and treated as liquids. In most cases natural gas and NGL are poor substitutes for C+C. I doubt we will see World C+C output reach beyond 85 Mb/d as declines will start to offset increases by 2023 and we will either remain on plateau for a few years at 85 Mb/d (to 2027 at most) or start to decline slowly in World C+C output. This may be hidden for a few years by the “all liquids” figures from the IEA which does not convert NGL and biofuels to boe and thus inflates those barrels (which only have about 70% of the energy content per barrel of the average C+C barrel). Using BP data in metric tonnes comes a little closer to the energy content of the C+C+NGL reported as produced output or the all liquids reported in the consumed “oil” (biofuels included in consumption but not production in the BP Statistical review of World Energy).

        If you look at the chart form the piece (link below)

        It predicts about 9 Mb/d increased liquids output from the projects identified at $60/b, but keep in mind that even if infill drilling keeps total field decline at 2% per year (optimistic in my view), this would amount to 11.2 Mb/d decline in output from the wells producing 80 Mb/d in 2016, so 9 Mb/d from the projects in the chart would leave us at about 78 b/d in 2025 if oil prices remained at $60/b.

        I expect oil prices will not remain this low and we may see output increase to 82 or even 85 Mb/d by 2023, it will depend on the level of oil prices.

        At $120/b in 2016$ we might see close to 85 Mb/d, at $100/b it will be closer to 82 Mb/d in my opinion for World C+C output. Note also that a lower peak enables a longer plateau or a slower rate of decline.

        • Yaman Tasdivar says:

          I agree that deep water projects need higher prices, but DO management has said (and this is in-line with others) that at $60 Brent, more than half of deep water projects become profitable. Atwood management has said above $60 Brent is needed for substantial demand to come back to deep water.

          I do expect prices to increase above $60 this summer.

          But this is the first time I’ve read/heard that we ran out of deep water locations to drill. A more reasonable way to put that, I suspect, is that given prices above $60, we will see higher demand for offshore drilling.

          Seeing that offshore makes up more than 20mbd of global supply, it’s hard to see offshore production being replaced by Permian (or other shale).

          NPV of offshore projects are still more than those of shale production, as one can see from nonexistent profits in shale.

          The main challenge offshore has is that the projects do not produce positive cash flows for the first couple of years. This is why e&p’ are currently focused on “short-cycle” projects such as shale. Therefore E&P companies need assurance that oil prices will rise and remain above $60-65 before they can hedge future production before they can make the offshore capex investment now.

          My understanding is that oil prices will rise to $60+ this summer, $70+ by the end of 2017, and $80+ in 2018.

          I suspect BP/Total/Statoil can find offshore locations to drill at those prices…

          • SouthLaGeo says:

            I don’t know about other deepwater basins, but the deepwater GOM, is, in my opinion, rather mature. While deepwater GOM exploration drilling is down partly due to low oil prices, it is also down due to lack of high impact exploration projects. I believe the Wilcox trend, that which has been responsible for many of the recent notable discoveries, is largely drilled up. There is a play to extend the Wilcox to the north and west. I haven’t seen any locations proposed to test that play concept yet. I suspect industry believes those plays to be more gas prone.

            Wilcox discoveries that are probably going to get developed include Anchor, North Platte, Shenandoah, the Tigress complex, Buckskin (via LLOG’s recent entry), and Constellation (Anadarko’s rename of the BP Hopkins discovery). Haven’t heard anything about BP’s Kaskida, or Repsol’s Leon for a few years – not sure if they are going to get developed – although higher oil prices may put those back into play.
            The type of exploration wells that are being drilled now, for the most part, are likely to be tie-backs to existing facilities.

            I could be wrong on all this, but this is my opinion.

            • Yaman Tasdivar says:

              Would you mind sharing your experience/background?

              Here’s what Wood Mac said about declining offshore costs above and beyond the drop in rig dayrates:


              My understanding is that oil prices are driving demand levels, and that higher than $60-65 oil, which some analysts expect by 3Q17, will bring some demand back to offshore.

              Also note that, as the wood mac article points out, onshore costs have started to increase due to land and service price inflation.

              • SouthLaGeo says:

                I am a active geologist with a major oil industry company with over 30 years of Gulf Coast experience, more than half of that in deepwater. While I don’t claim to know much about other basins, I am pretty familiar with the Gulf of Mexico.
                Even though I am currently not in exploration, I have been in deepwater exploration in my career, and I do continue to keep pretty close tabs on what industry is doing -that is, I not only keep up with the press releases, but also follow the scout reports. That means I often know when a discovery is drilled soon after it is drilled – same with a dry hole – and maybe weeks before a press release ( if a press release is even issued). When an exploration well is proposed, I spot it on my GOM map and try to figure out what they are looking for.
                I appreciate your comments that costs are coming down in the deepwater, and lower costs will may make some marginal discoveries economic. My comments, though, were not related to lower costs, but were around the maturity of the northern deepwater GOM. (I didn’t specify the northern deepwater GOM in my comments. I am hopeful that some elephants are uncovered in the offshore Mexico waters.)

                Again, I could be wrong, but given what I know about both the geology and the geologic trends of the northern deepwater GOM, I think the basin is fairly mature from an exploration standpoint. Discoveries will continue to be made, but they are likely to be smaller, and also, likely to be tiebacks to existing facilities.

                • Pm says:


                  SoLaGeo between you and George I think we have GOM and North Sea well covered. My guess is you probably know more about this than any of us except maybe George and Rune.

                • Yaman Tasdivar says:


                  Thank you for the reply. I appreciate your experience in the field.

                  What are your thoughts on Trump opening up Artic and Atlantic?

                  Also, do you know roughly what percent of global offshore exploration drilling has happened in the GoM in the last decade?

                  • SouthLaGeo says:

                    Regarding opening up the Arctic and the Atlantic : While I am encouraged by Trump’s decisions, I have 2 major concerns. The first is – will the next administration reverse these decisions (this happened under Obama) , and the 2nd is – will the impacted states and the environmental lobby allow oil industry activity, or will they push back so hard that industry will feel it is just not worth it?

                    As far my first concern – in order for successful development in either of these areas, the oil industry needs to be assured of stability. They can’t invest millions in seismic or lease acquisition and then have the leases revoked.

                    Don’t know the answer to your 2nd question regarding percent of global offshore exploration drilling in the GOM.

        • George Kaplan says:

          Note: 1) the graph above is for all offshore, not just deep water oil, 2) as I indicated some of the drop is to do with price, my comment was that not all of it has been.

          Success rates in frontier areas have dropped from 1 in 5 to 1 in 12 or 1 in 20, depending on who’s numbers you read; proportion of gas discoveries has been rising (at least until last year – this year very little gas so far); lease sales have been, and really continue to be. poor; the recent fall in discoveries means there is an equally big relative fall in follow up appraisal wells; Marathon and CoP have publicly stated that they have pulled out of deep water completely (i.e. never to return); others like Shell, Chevron Statoil, BP have pulled back, e.g. Statoil out of GoM, EM out of North Sea, Shell out of lots of places, and are looking at existing plays (e.g. near-field offshore, buying into PetroBras discoveries, favouring gas, Permian etc.); a large proportion of the drilling fleet has been cold stacked or decommissioned over the last three years (compared to warm stacking if they were expected to be reused); shallow water basins, except those under moratoria and in the Artic, are highly mature with few attractive prospects left; a lot of the known near field in-fill and tie back opportunities were exploited in the high price years and those relatively few left are the least attractive; several major drillers have gone bankrupt and/or merged; Angola and Nigeria have growing issues with tax / royalty changes, local content requirements and corruption; booster pieces in the press or from the majors and consulting groups are getting more and more general with less actual details, and seem to be concentrating on how optimization of organization improve costs rather than about just going out and finding oil.

          The $60 breakeven refers to existing (and best) discoveries and might influence whether companies think it worth looking in deep water, but doesn’t mean what they find (if anything) would be that good – in fact as the best prospects are drilled first it’s likely the break even price, whatever that means, would rise for new discoveries (i.e. they are smaller, or deeper, or more difficult reservoirs, or have less market for the gas etc.) I estimate there are 35 deep production systems under construction, with another 60 known, for shallower systems it’s similar (but smaller units) and for tie backs it’s about 25 and 20. There are a few condensate fields in there, but mostly oil only. There will be a number of gas projects, some very big, on top of these (timing will depend on demand and how USA, and Canada probably, tight gas production evolves). For those listed though, there will be (rough guess) 3000 to 4000 production wells and, say, 2500 to 3000 injection. Some will have been predrilled, the rest, plus others for recent start-ups, completed over the next 10 to 20 years and tailing off. Other than those there are only new discoveries, which are dwindling away, and increased activity isn’t going to improve the success rate (it is likely to continue to decline as the best prospects are drilled first), it just means we hit zero fewer years. No matter what the oil price does there is likely to be a dip in development drilling as the bulge in project start-ups stops in 2018, the drilling impact will be delayed and smoothed though.

          With a reduction in available rigs it’ll be interesting how prices respond over the next few years. Even at around $100 million per deep water well there is a lot of room for a big high side risk for even small demand changes, and not much room for more savings.

          • Yaman Tasdivar says:


            SouthLeGeo and you clearly have a degree or two of magnitude of experience in this than I do. Here are my thoughts/questions on each point:

            – Note the sharp rise in number of offshore rigs in 1999, when oil prices rose substantially, following the last OPEC/NOPEC deal. This is not surprising as offshore projects are large-scale projects that require a lot of capex for a number of years first before any pay-off so they get cut first at times of depressed oil prices, but they also come back strong when prices are higher. That’s the type of return I expect as oil rises to $70+ this year and $80+ next.

            – Drop in success rates is alarming for the world, but doesn’t that also mean increased need for exploration drilling to replace the same amount of decline? My understanding is that currently ~25 mbd of offshore production must be sustained (decline rate of double conventional wells, so 10-20% depending on the project, which I believe increases with in-fill drilling and tiebacks, so ~3-4 mbd of decline per year just from offshore production) as shale cannot meet demand growth alone and oil sand production is even more expensive than offshore with $100+ breakevens.

            – The proportion of gas rising is a problem at $50 oil and $3 gas, but likely less of a problem at $70+ oil and $4 gas?

            – Lease sales are likely to rise as Trump opens up Arctic and Atlantic, additional areas in GoM, and my understanding is that international lease sales will also rise as oil prices rise.

            – Companies make and reverse strategic decisions based on price and investor climate. I am not surprised to see such announcements as energy companies would rather cut capex than the sacrosanct dividend, but I would be surprised if they did not increase offshore capex as oil rises above $70-80+. What other option do they have, as Permian and other production you listed are unlikely to make up for large declines expected in ex-US non-OPEC production in the foreseeable future?

            – I don’t expect the coldstacked rigs to ever come back, which is a problem for the world, and will limit how fast offshore drilling can ramp back up beyond 2018/19. There still is, however, a very high number of working rigs and warmstacked rigs as well as newbuilds coming in 2017/18, in anticipation of demand coming back offshore as onshore cost inflation rises and oil prices rise this year and next.

            – It makes sense that shallow water basins are more mature as they’ve been drilled for longer, but I suspect this is more true in the US. Aramco for example recently signed a multi-year agreement with Rowan, which is primarily a jack-up company. But I generally agree that offshore drilling is moving more towards deepwater, which is why major drillers were adding 6th and 7th gen UDW rigs to their fleets before oil prices crashed.

            – In-fill drilling is currently prevalent both onshore and offshore, and is merely a function of lower oil prices leading to lower exploration capex. I would expect this to reverse as oil prices rise to $70+ later this year.

            – I agree that several offshore companies recently went bankrupt, but I’m not sure how this affect our discussion here. New ones have emerged recently and even the bankrupt ones still operate under bankruptcy protection. Rig oversupply remains, but I do expect coldstacked rigs to be scrapped, which will limit how quickly the industry can come back beyond 2018/19.

            – I can’t comment on specific details of press releases, but my general sense from earnings calls and consultancy commentary is that as prices have risen, client inquiries for offshore projects has also increased. Note, however, that under $60-65 oil, there will not be much demand for offshore exploration. As I expect oil to rise above $70 later this year, I expect demand for offshore exploration to start increasing around the same time.

            – My understanding is that $60 oil breakeven refers to more than half of offshore projects per Diamond Offshore management. The best ones are profitable at as lows as $40-45 oil. I do not know if future wells will be more or less profitable at a given price, but it seems to me that demand of exploration drilling will rise as oil prices rise, as they always have throughout the last 40 years.

            It seems to me that we agree on the precarious situation the global oil supply is in, but disagree on how demand for offshore drilling will change as oil prices rise. Would that be a fair summary?

            • SouthLaGeo says:

              You make a lot of good comments. While I won’t respond point-by-point, I will comment on a few:

              – Yaman – Drop in success rates is alarming for the world, but doesn’t that also mean increased need for exploration drilling to replace the same amount of decline?

              – SLG – I agree, but one key peak oil concept is that, in the end, geology wins. It isn’t a given in the future that supply will meet demand. Poor exploration results in recent years are not just a result of less drilling, but also a result of fewer high impact opportunities. You would think that recent low oil prices would cause oil companies to prioritize their exploration portfolios, and only drill the best, and yet, the results have still been poor. I think the results have been poor because geology is winning – the high impact opportunities are just not there.

              – Y – I generally agree that offshore drilling is moving more towards deepwater, which is why major drillers were adding 6th and 7th gen UDW rigs to their fleets before oil prices crashed.

              – SLG – And now some of these drillers wished they had never built those rigs, and the oil companies that convinced the drillers to build these rigs now have rig contracts that they can’t get out of. During the “heady” days of 2012-2014, no barrel was a bad barrel. Now, big oil has to learn how to make money in a $50 world, and some barrels just don’t stack up.

              – Y – It seems to me that we agree on the precarious situation the global oil supply is in, but disagree on how demand for offshore drilling will change as oil prices rise.

              – SLG – Yaman, you are more of an optimist than I am. You believe both that oil prices will rise, and that deepwater activity will pick up as a result. I think, if oil prices do rise, the oil industry will take a more measured approach to increased deepwater activity.

              • George Kaplan says:

                I was commenting on how things are at the moment, and the recent past, not so much on the future, which seems to be your primary focus. I’d guess you have some sort of investment standpoint, with which, to be honest, I am not all the interested. You are arguing points that I didn’t make. You also seem to mix up development drilling with exploration – a mature basin might have a lot of development drilling going on, especially if, like Saudi, they are trying to maintain a production plateau, that doesn’t mean they have any new fields to develop. The Arctic and Atlantic are going to be mostly gas prone. The Arctic has been extensively drilled for oil (I think over 1000 wells in the Chukchi Sea) with little success, certainly no major anchor finds. After Shell spent $8 billion on a dry well in 205 most companies gave up their leases, why would they buy another lot? IOCs don’t like controversy, and they are going to get a lot if they drill in the Arctic and in Atlantic fishing grounds.

                • Yaman Tasdivar says:

                  Got it. Thanks for the info.

                  You are correct that I have investments, which somewhat behave has call
                  Options on oil prices with strike price of $60 without an expiration date (basically).

                  That is why I’m very interested in oil demand/supply dynamics in the next 12-24 months, as oil markets look out shorter-term than one might think. Prices only reflect developments expected in the next few months.

                  In short, I expect higher prices in the short-term, but lower in the longer term, driven by drop in oil demand due to electric cars, solar electric generation and utility-scale batteries, progress of which is wildly underestimated by at least one order of magnitude and maybe two.

                  • Dennis Coyne says:

                    Hi Yaman,

                    The drop in demand below supply will not occur until 2035 at the earliest in my view.

                    Optimists claim it is easy to ramp up EVs as we are already making cars, probably batteries will be the bottleneck as well as people resisting change from ICEV to EVs.

                    I doubt the ramp up will be any faster than smart phones or personal computers, which I used in the piece below.


                  • Boomer II says:

                    Drop in demand could easily come with a recession. There’s too much emphasis on EVs in this forum as the reason demand might drop. Anything that discourages people from driving ICE vehicles will reduce demand. If they don’t have much money or no jobs to commute to, they will likely drive less. And if more people don’t bother to own a vehicle, demand will also drop.

                  • Dennis Coyne says:

                    Hi Boomer,

                    From the perspective of the World, demand may continue to increase or may only decrease a little with a recession. Also a recession is unlikely to be permanent, so once a peak in oil output is reached either people and goods no longer travel very much (a rather unlikely scenario) or some alternative to fossil fuel powered transportation will be found.

                    It will likely be a combination of less travel, increased use of public transport (rail, light rail and bus), and improved efficiency of private transportation that will need to occur as oil supply decreases.

                    Whether oil supply falls faster than oil demand will depend on many factors one of which is World economic output and another major factor being how easily the transportation system can become less dependent on oil as a source of energy (natural gas may be a possible bridge fuel, but that will also peak and decline, so ramp up of non-fossil fuel use for electricity production will also be a factor.)

                    A final point. The owning of vehicles is not what uses the fuel, it is the driving of vehicles.

                    If all miles travelled were in Uber vehicles owned by a large corporation and most rides were single passenger rides, fuel used would depend on miles driven. In fact the driving to pick up fares might increase miles driven.

                    More use of public transport might save fuel, but non rush hour public transport is not very efficient.

                  • Boomer II says:

                    Energy use per capita has dropped noticeably in the US since 2000.

                    Two Centuries Of Energy In America, In Four Graphs : Planet Money : NPR

                    It has also dropped in other countries as well.



                    So it isn’t unreasonable to assume that people will continue to use less energy, whether that be fossil fuels or renewables.

                    Of course, population increases could mean that the total energy use continues to rise, but if it is more about renewables than about fossil fuels, then it might not be as problematic.

                  • Boomer II says:

                    This image is busy, but you can see that energy use per capita has dropped at points in a variety of countries.


                  • Nick G says:

                    Optimists claim it is easy to ramp up EVs as we are already making cars, .

                    US oil consumption is 6–9 MBPD lower now than it would have been without CAFE regs.

                    There was a dramatic change in MPG from 1975 to 1982, from about 13 to about 21. This is a 38% reduction in 7 years, and represents an annual change of about -7% per year. This was achieved by a combination of sharply higher CAFE standards and high gas prices.

                    people resisting change from ICEV to EVs

                    This is the key problem: resistance to change, driven by fossil fuel oligarchs. Both coal and oil consumption could be reduced dramatically and quickly, if there existed massive social consensus for it.

                    Strategies could include aggressive carpooling – carpooling is currently larger than mass transit in the US, it could be ramped up literally in weeks, and has essentially zero capital costs; an aggressive transition from income taxes to fossil fuel consumption taxes; and aggressive tightening of CAFE regulations.

                    I doubt the ramp up will be any faster than smart phones or personal computers

                    That makes sense. Neither of those transitions was pushed by any kind of urgency. Feature phones (the predecessor to smart phones) worked just fine, but smart phones were better. More expensive, and better.

                • George Kaplan says:

                  That should be 100 no 1000.

    • I’ve consulted in Ecuador. It’s not all heavy oil. It’s medium to heavy, but it’s the type of oil we can water flood. They do have a lot of water production, and a huge number of electric submersible pumps. The project economics for government owned properties are ok, but for the private outfits they are lousy. Thus we saw production hold steady in the first place, and decline slowly for the second group.

  6. Dennis Coyne says:

    Hi All,

    Ron’s wife passed away recently. He let me know yesterday afternoon.

    Alice Myrna Patterson
    September 26, 1941 – April 6, 2017

    Alice M. Patterson age 75, passed away Thursday, April 6, 2017.

    Mrs. Patterson is survived by her husband Ronny O. Patterson; children Stanley R. Patterson, Stephen B. Patterson, Scott D. Patterson; brother Clark D. Cleveland; six grandchildren; five great-grandchildren.

    She was preceded in death by her son Stuart Jeffery Patterson.

  7. aws. says:

    BTW, @JigarShahDC of the Energy Gang just referenced the last post in this tweet.


  8. Brian says:

    My condolences to you and your family in your great loss.

  9. Doc Rich says:

    I am very sorry for your loss. Please let me and the other people who visit your website if you need anything to help with your loss. You are a good man. Best Rich

  10. Stephan says:

    My condolences to you Ron.
    Keep going each day.

  11. George Kaplan says:

    I had a go at a simple curve fit for the Bakken, where this month’s production is a fixed ratio of last month (i.e. exponential decay) plus a linear function (multiplier) of this and last months’ completions. It works quite well, but only using the EIA completion numbers – those from ND DMR are much more volatile. Also the proportionality for this month versus last month comes out greater than one, not sure why and there probably is a math’s reason why it shouldn’t. Partly it is because successive months completions are usually close in number so the correlation is a weak function of their differences – if all completion numbers were the same the proportionality ratio (A) would be undefined. But more than that, allowing the ratio to rise higher than one seems to allow the fit better to handle the recent oscillations from offline wells because of weather and neighbouring completion activity. The projections shown are for 50, 70 and 90 completions per month going forward. The chart to the left shows the number of completions per month needed to maintain a given plateau (which would take some time of decay or rise to be reached).

  12. Enno Peters says:

    I have a new post on LTO production from all 8 US states that I cover, available here.

    • Dennis Coyne says:

      Hi Enno thanks, great work.

      Chart below shows cumulative well profiles.

      At 60 months from first output for wells that started producing from 2011 to 2016 the average cumulative well profile for the Bakken was 194 kb, Eagle Ford 139 kb, Permian 133 kb, and Niobrara 100 kb.

      • Yaman Tasdivar says:

        Why do Bakken wells have the most output even though Permian supposedly has multiple layers from which one well can extract oil?

        • AlexS says:

          Interesting question.
          How many Permian wells produce from multiple layers?
          Do they have a horizontal section for each layer?
          What could be the cost of a well with multiple horizontal sections?
          Or there are different wells for different layers located on the same well pad?

        • It’s hard to extract oil from multiple layers when they are placed far enough apart that fractures can’t cover the vertical reservoir extent.

          I’ve seen operators try to get around this problem drilling multi laterals, and also single horizontals with fish bone sidetracks. In general we’ve found its better to keep it simple. Simple may mean drilling the well with a large casing string set at the top of the bottom layer, drilling out, setting a liner, fracturing say 25 fracs…producing 10 years, plug back, sidetrack out of casing, and repeat. It takes patience. Theoretically it’s possible to get 0.7 million barrels from one well plus two sidetracks and 75 frac jobs over 30 years.

        • coffeeguyzz says:

          Multi lateral wells have been done frequently in the early years of the Bakken with two or three laterals originating from a single vertical and targeting the same layer/horizon/formation.
          Apparently the operators didn’t find it an efficient process.
          BHP announced last year that they would experiment with multilaterals in their Permian holdings and draw upon their offshore experience in the efforts.
          In general, multilaterals can target different vertical areas (never done in shale, as far as I know, or multiple wellbores on the same horizon.

          The Bakken has had almost exclusively 10,000′ +/- long lateral since 2010 due to the size of the leasing areas.
          This is 50%/100% longer than other areas up till recently.
          In addition, the Bakken is definitely an ‘oil play’ wherein 85% +/- of what comes out of the ground is oil.
          Other areas vary widely – and are definitely well specific – but much lower oil content than the Bak.
          (One of the alluring aspects of the Tuscaloosa Marine Shale was its 92% plus oil composition).

      • Enno Peters says:

        Thank you Dennis,

        Although you can group the wells by a non-time dimension like “basin”, be aware that there are dangers of using it: If wells did change behavior over the past 5 years, these average curves will not give a good picture of what the latest wells in each basin is going to do. This is because the wells that make up the end of the curves only consist of the wells that started in the early years, while all wells are represented in the early part of the curves. I’ve tried to visualize that with the thickness of the curves, which as you becomes thinner with time – it is determined by the number of wells in each data point.

        I have seen several faulty analyses that missed this issue.

        Therefore, I prefer to group wells by a time dimension (month/quarter/year), as then the trend of changing well productivities can be seen, while still allowing an observer to make an estimation of what these wells may do in the future. The disadvantage is that you then need to do this for each basin separately (if you want to compare the performance in different basins), but I belief the result is more accurate.

    • Yaman Tasdivar says:

      Enno – thank you for your work; very helpful. Do you have any plans to include production forecasts in your post? Even a likely range would be very helpful at a time when Permian CEOs are projecting 25 mbd production in ten years…

      • AlexS says:

        25 mb/d = current production of Saudia Arabia + Russia+ Iraq.
        So what are recoverable resources in the Permian? Some 500 billion barrels?
        How many investors believe in these fantasies?

        • coffeeguyzz says:

          When the USGS recently pegged the Wolfcamp formation (trend, as Rockman would describe it) at 16 billion barrels TRR, it seems to be widely NOT recognized that the Delaware basin was NOT included, only the Midland.
          Nor, for that matter were the several other productive, non Wolfcamp trends/formations … and there are many of them.
          These operators have only recently been optimizing recovery operations, and still leave over 90% of the oil behind.

          There is a bit of a corollary, if you will, to this whole so called Shale Revolution that may hold more significance than presently seems acknowledged, that is, natgas versus oil.
          The amount of natgas recoverable versus oil completely dwarfs the liquid.

          Just dwarfs it.

          Furthermore, due to the physical properties of gas and liquids, horizontals – especially 3 and 4 mile long ones – strongly favor gas production and recovery.
          In the Appalachian Basin, there are over a dozen 3 mile, and a couple of 4 mile long lateral to be drilled this year.

          • AlexS says:


            Do you think the Permian can produce 25 mb/d in ten years?
            Up from the current 2 mb/d, including conventional.
            What should be the resource base?
            How many wells should be drilled annually?

            • coffeeguyzz says:

              25 million?
              Short answer … no.
              But, if we keep an eye on what operator after operator are currently projecting – and evaluate their accuracy in, say, 24 months’ time – 10 million or more may be reasonable.
              Many variables, selling price of oil being primary, would lend credence to this seemingly outlandish stance.

              Alex, looking back to 2012/2014, and reading those projections, especially for west Texas, one can see how volatile (and erroneous) the best-informed analysts can be.
              I do not know what will happen tomorrow, let alone 2025.
              However, there is a bunch of oil and gas sitting in the Permian, in SCOOP/STACK, the Bakken, Niobrara, Appalachian Basin, PRB, and other places around the world.
              These guys know how to get it and, year after year, are improving greatly their operational expertise.

              • Boomer II says:

                “However, there is a bunch of oil and gas sitting in the Permian, in SCOOP/STACK, the Bakken, Niobrara, Appalachian Basin, PRB, and other places around the world.”

                I’m not an oil industry person, so forgive me if I ask a dumb question. How do we know there’s a bunch of oil and gas sitting in all of these places?

                • coffeeguyzz says:

                  No question, sincerely posed, should be considered dumb, in my opinion.
                  Two tacks, at least, can be approached to discern the data …
                  1. Government and academic studies
                  2. Up to the moment info provided by the operators in the areas mentioned
                  Actually, a third path, such as work put forth by David Hughes could be read, but contrary evaluations may arise based upon Mr. Hughes’ demonstrably erroneous track record.
                  I make no sarcastic aspersions towards Mr. Hughes.
                  Rather, I would encourage anyone to simply spend 10 minutes reading the Executive Summary to his Drilling Deeper and draw one’s own conclusions.

                  The government’s analysis is virtually always dated and prone to underestimation.
                  While the predominate view from readers of this site towards operators’ data is highly suspect, nonetheless, presentations can offer extensively detailed analysis of just what the heck is in the ground.
                  In fact, virtually all the raw data goverment and academics use stems originally from these companies.

                  If you have some time and interest, Google around a bit in your neck of the woods … the Niobrara and the Piceance over the mountains, especially the Mancos.

                  • Boomer II says:

                    I’ve been on this forum to get info about what current production looks like and decline rates. I figure those are reasonably accurate.

                    For projections, lately I have been paying close attention to where major oil companies are putting their money. Based on what I see them doing, I’m guessing they are less positive about the future than you are.

                    I know that the LTO companies have been promising rosy futures, but I am a bit skeptical. I guess we’ll wait to see how it pans out for them. I have no money invested in any of this, so how they do or don’t do doesn’t affect me personally.

                    I was very interested in decline rates in the Bakken and now will pay attention to the Permian. I do watch what is happening in the Niobrara. Yes, there is activity, but no talk of the boom like there was before oil prices dropped. All I ever wanted for this basin is some caution and realistic assessments. As long as people are aware that with booms can come busts, hopefully people will make good decisions about how much emphasis to put on oil and gas for local economies.

                    I remember the days when Denver’s Petroleum Club was roaring. In 1978 it had a landmark building and 2400 members. Eventually the club ended. In 2007 the club was restarted, is now sharing another club’s space, and has 800 members. There is gas and oil activity, but busts have taken their toll.

              • AlexS says:


                10 million b/d or more for the Permian alone?

                • coffeeguyzz says:

                  This is one reason I shy from predictions/projections … just way too much room for error or misinterpretation.

                  Specifically, if an outfit like Pioneer currently produces around 10% of Permian output (250,000 boe out of 2 million bo?), then their claims of one million in ten years would roughly jive with 10 million boe as well.
                  Note, I include boe, whereas current Permian is 2 mill bo, I think.
                  Not gonna check, but should be close.
                  The bigger, potentially validating issue – if indeed the ridiculous sounding 10 million boe comes to pass, is that so many other operators are projecting huge future output in the coming decade.
                  The gas component can inflate the boe category for the unwary, but, nonetheless, there is a Ghawar sized resource sitting under the ground in west Texas.
                  There is a Ghawar PLUS sized resource – in gaseous form – sitting under the Appalachian Basin.
                  No bout adout it what. so. evuh.

              • Mike says:

                Coffee, you never give up, do you? I cannot even begin to comprehend how someone like yourself, clearly a smart feller, can be SO focused, so totally mesmerized by unconventional shale operations, yet so completely oblivious to costs, lack of profitability, debt, the horrible, horrible financial state of almost every shale company in America, of shareholder losses, geological/areal constraints, realized production data that does not even come CLOSE to matching reported EUR’s, to 85% effective decline rates within 2 1/2 years of well life…sorry, its just amazing to me.

                10M BOPD, just out of the Permian; “Saudi America,” I believe is what Sheffield calls it. If a shale oil company says its true, it has to be true; there is no fake news, no lying in the shale business !! Its all just a matter of better technology and greater “operational expertise,” how much more damn sand they can cram into those stinking shale wells, isn’t it?


                • coffeeguyzz says:

                  Mr. Roughneck

                  That was an excellent piece on the Greta and Kinley.
                  It can be both humbling and inspiring to learn of the achievements of great men, all the more so when conveyed so effectively as you have done.
                  My compliments.

                  No, in fact, it is not my nature to ever give up, but I am not striving to do more than learn in this rapidly evolving swirl of the most momentous industrial evolution in my lifetime … this so called Shale Revolution.

                  If the Permian currently produces 2 million barrels oil and 7 billion cubic feet gas, that’s already 1/3 towards 10 million boe a decade out.
                  Not gonna get into the bo/boe here, it is what it is.
                  (BTW, your buddy Harold has recent presentations with wells labelled 99% methane and depicted in boe terms. We all should be wary).

                  But, I mentioned months back how significant the tighter staging, increased perf clusters, real time microseismic were to productivity.
                  The diversion technology is playing a huge role in this.
                  Where’s all that sand going?
                  Great question as that holds the key to the upsurge in recent increased output.
                  No longer are 1,000′ long, large fissures sought, only to rapidly close off prompting the dreaded decline.
                  Now, a gazillion micro spider cracks are both created, thoroughly scoured, and propped just a few hundred feet from the wellbore.

                  You might want to use caution quoting Enno”s numbers.
                  Not that they are in any way inaccurate, quite the opposite.
                  When one uses all the numbers, as does Enno (curiously omitting refracs, though?), the wells drilled out in Bumfuck Egypt somewhere count – statistically on a one to one basis – the same weight as an El Primo 2016 well in Twin Valley field.
                  The ND DMR claims a typical Bakken well flows 110 barrels oil per day at the 5 year mark …hitting 50 bpd 15 years out.
                  Far, far higher than Enno’s charts as the Bumfuck wells are not included.

                  As for the economics, I’ll leave that to the people and companies more knowledgeable and impacted than I.

                  This is the future of your industry, Mr. Roughneck, and the future don’t wait.

                  • Enno says:


                    Just to be sure, I am not leaving out refracs in my posts. That explains the bump in the performance of 2009-2010 ND wells late in life.

                  • Mike says:

                    Thank you for the compliment; it is a good story, Myron Kinley, and one I am proud of and deeply associated with.

                    I am not going to dissuade you from your opinions, no matter how irrational I might think they are. I have tried, for what, three years now? You chose to focus on the top 3% of all shale wells in America, as though that is our energy future. That is not our future; the other 97% IS our future and that future is declining at the rate of 12-15% per year. We cannot now replace that fast enough; shale oil is too expensive to extract. Private enterprise in America has not succeeded at it, nor can it with prices less than 90 dollars a barrel.

                    Unconventional shale resources in America represents the bottom of the barrel; that is about all we have left. It is a mistake to be hell bent to produce those resources, at these prices, for the benefit of short term greed. LTO in not reducing our reliance on foreign imports, its out of control, fiscally irresponsible development at the moment is a tragedy to our energy future. We should be promoting hydrocarbon conservation in America, not filling foggy, unknowledgeable heads with the notion of abundance, as you so desperately feel the need to do.

                    I could not in good conscious do that. Nor can I ignore the lies the shale oil industry engages in, nor can I ignore borrowing money and not paying it back. The same year Scott Sheffield made 13 million dollars from running Pioneer, Pioneer shareholders lost over 400 million dollars. That to me is bug splatter on a windshield.

                    Forgive me for interceding; you have minds to brainwash. It appears to me, however, that Alex is going to take more work.

                  • Cracker says:


                    Alex isn’t the only one needing more convincing. Lots of us know BS when we see it. Some people are just in love with their investments.


          • Nathanael says:

            So, I noticed long ago that most of the recoveries from shale are gas, not oil.

            The thing is, I don’t see any evidence that any of these wells are profitable on gas alone. They seem to only be profitable because of the liquids.

            Would any of these actually be drilled as pure gas plays? Gas is too cheap, isn’t it?

      • Enno Peters says:


        Thank you.

        > Do you have any plans to include production forecasts in your post?

        I like to refrain from forecasts, and focus on the hard actual production data. Much less to argue about 🙂

        Future production will greatly depend on factors that are highly unpredictable, such as the number of wells drilled, and the future changes in well performance. I don’t claim any particular insights on these matters.

        The only exception I have made so far is that I can project what existing, already flowing wells, are likely to produce in the future, based on the actual performance of earlier wells. You can see this in my “Projection” posts, e.g. here.

  13. Longtimber says:

    Chevron holds onRisk & Mega_Projects. Reduces .. GeoPolitical Risks? Nowhere to go? More Downward pressure for LTO prices?

    “Chevron’s production in the Permian was 90,000 net barrels of crude oil per day in 2016.
    Watson expects the company’s output in the shale play to increase eight times over the next decade and reach 700,000 bpd. Chevron will also be adding 9 drilling rigs by the end of 2018 to the 11 rigs that it currently operates in the Permian. Chevron’s acreage in the shale play amounts to 2 million net acres, of which, 85 percent is free of royalties to landowners or have low royalties.”

    • The Art Berman interpretation appears to be wrong. The standard measure uses prior year prices, it set reserves, sets value at pv10. Thus this value is forced to be under the previous year’s average. In a sense it’s dictated by sec rules.

  14. Petro says:

    please accept my deepest condolences!
    My thoughts and prayers are with you and your family.
    May you and yours have the strength to go through this and may you all find peace in cherishing the memories.



  15. Energy News says:

    I don’t know if this is right, I just like that they have included an estimate for China’s SPR which you don’t see very often

    World Oil Inventories – Scotiabank – April 12, 2017 – page 2
    The supply glut that began in mid-2014 has dumped almost one billion barrels of
    petroleum into global inventories, of which only 35–45% ended up in transparent OECD
    tanks. However, the majority of the remainder was absorbed by China’s growing strategic
    petroleum reserve (SPR), meaning that the lion’s share of functional—and thus needing
    to draw from an OPEC perspective—industry inventories remain in the OECD, and
    specifically in the US (chart 3). We expect state-side stocks to begin drawing in Q2 as
    refineries come out of maintenance and the lagged shipping of OPEC crude begins to
    reflect observed cuts.
    pdf file: http://www.gbm.scotiabank.com/scpt/gbm/scotiaeconomics63/SCPI_2017-04-12.pdf

    • Watcher says:

      But this is all wrong.

      It’s not consistent with the China SPR wiki.

      Oh and look! It was (allegedly) growing, indicating additional purchases, during the period of price fall. All that extra demand (not consumption) driving the price down. Imagine that.

      US SPR is 730ish million barrels and largest on Earth. Japan’s is 580ish. How is one to read that graph? In Jan 2017 it shows a big dark region of 250 to 800 million bbls for the Chinese SPR. What’s that mean? Is that the error possible in their estimate? haha factor of gazillion

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