161 thoughts to “Open Thread Petroleum, November 28, 2018”

        1. Peak oil is what we have been talking about since early in this century. We have predicted the peak in 2005 and in several years thereafter. Now, some are so gunshy that they are afraid to make any kind of prediction whatsoever. Others predict peak oil several years out. I am predicting 2019 as the peak year, and I grow more confident with that prediction every day.

          Simply because many were wrong, including myself, in the past does not mean oil production will never peak, as many seem to think.

          I think the IEA now sees the handwriting on the wall. The EIA will not likely see it until we are well past peak oil.

          1. Well we did hit a peak ~ 2005. Everything global aggregate gain since has been new resources. Mostly fracking, some Canadian tar.

          2. Now we are at firing almost everything. Iraq is back, Libya, Nigeria is almost back.
            LTO is at high level. There is no much space to grow besides bringing Iran an Venezuela back, and building LTO a further bit – how much is possible here depends very much on oil price, much more than other countries.

            Other big sources of growth are not in sight – beside the old statements from gulf countries doubling their output. They have done some the last 20 years I think.

            So this looks like near a peak – the absolute peak will be more determined by knocking out a producing state and bringing it back only after the peak.

            I’d say in the next 5- 10 years – after this countries will be much more aware of climate change and start phasing out oil using vehicles by law, or even forbid pumping the oil in their political influence area.

            1. Right now, phasing out oil by law is not working well in France…

          3. Looking at the charts on this site my impression is there are only about eight major producers that have not reached peak production. They are the Republic of Congo, Iraq, Kuwait, Saudia Arabia, the United Arab Emirates, Russia, the USA and Canada. These eight countries are producing about 50 percent of the worlds oil. With many countries producing less and less oil and a few countries producing more and more oil the peak of world production should come soon.

            2. They are opening up their property to outside bidders starting mid 2019, so yeah. In the not too distant future.

            1. For instance how do you know when Russian oil production will peak??

              Know? Hell, I don’t know. I have never claimed absolute knowledge. All we can do is give it an educated guess. And our guesses get a little more educated each year.

              I don’t know but my educated guess is that Russia will peak in 2019. Most of the rest of the world has already peaked.

            2. Ron

              In order to claim as you did…

              “But I am putting my reputation on the line in making the claim that the period, September 2014 through August 2015 will be the year of Peak Oil.”

              This kind of statement needs to be based on knowledge of decline rates of old fields. How effective infill drilling is and new discoveries.
              If you do not know this data, you are simply guessing.
              If you actually had the imformation you need you would not have been wrong for so many years.

            3. The US Military predicted peak oil in 2015

              https://www.theguardian.com/business/2010/apr/11/peak-oil-production-supply

              They didn’t see the shale boom either.

              No one who does forecasts for a living thinks they will be 100% correct. If you were that dumb you wouldn’t have a job.

              Now look at how Putin is behaving, The Chinese are building islands with military equipment on them, NATO is trying to get into Syria, with the Russians blocking them.

              I think they have similar projections.

              Just haven’t made them public.

            5. Russia should have peaked a while ago (and everyone including their own estimates thought they would). They haven’t opened any new fields of size.

            6. Two or three new ones in the Caspian, depends what you mean by ‘size’ I guess.

            7. It’s easy to stack small fields on top of slowly declining large fields. This is true for Russia, where there is enough small fields to give them production gains. For the world, stacking of enough Shale oil plays has given the world the appearence of “growth”, too bad its all done on other peoples money that won’t get paid back.

            8. David

              I agree. The decline rates are such that only a few more years of growth are possible. I believe the United States is drilling as many wells for 5 million barrels of shale oil as the rest of the world is drilling to produce 90 Million barrels of oil.

        2. The chart with peak oil now or soon assumes no investment in new production, that is a very unlikely scenario at best. Even without new discoveries, there is a lot of oil that has already been discovered, but has not been developed, these reserves are in the proved undeveloped reserves as well as probable reserves, and possible reserves and contingent resources, resources at least as large as the SDS scenario will be developed and probably something between the SDS and the NPS scenarios (dashed lines on the first chart) is a reasonable guess.

          My guess for the peak remains 2023 to 2027 with a best guess of 2025, much will depend on oil price level and political and economic developments over the next 5 to 10 years. These are impossible to predict which explains the wide window for my guess, but if forced to pick a single year I would bet on 2025 (centered 12 month average for World C+C output would fall between Jan 2025 and Dec 2025, that’s what I mean when I say 2025, single month peaks are of little interest to me.)

    2. Yes inventories are still low so far, the oil market seems to be looking at what might happen in 2019?

      1. What i see, is a slight bump up for the slow time last year, and even less, so far, this year. Yes, they are listening to the EIA with their wild a!!ed projections and estimates of current production, which is way over actual. So, the market will welcome OPEC cuts, which will further magnify the shortage in 2019. If OPEC cuts, 2018 has to be the peak. Shale may pick up significantly in 2020, which will be overwhelmed by declines. So, the longer EIA keeps up this facade, the bigger the shock. Shale cant survive with $50 oil. It was on life support the last time it happened.

    1. Thanks energy news,

      Stocks did not increase by much (0.4 million barrels of 1900 million or 0.02%), this is a rounding error and would be considered flat by most. It is net imports that matter, those were up by 135 kb/d or 0.945 million barrels for the week, if we look at line 10 from table 1, it shows a stock draw of 359 kb/d or 2.5 million barrels for the week, this disagrees with the data elsewhere in the report, these weekly reports are really bad, not sure why anyone pays attention to them.

      Edit: The last sentence above is incorrect, see comments below where Gone Fishing got me on the correct track. Report is fine, I read it incorrectly.

    2. Imports are 10,096,000 and exports are 8,714,000 MMbpd. EIA week Nov 23rd.

      1. Gone fishing thanks,

        I stand corrected.
        I mistakenly used only crude oil supply and missed the “other supply” category, my bad.

        Your figures are correct. Net imports 1382 kb/d, 833 kb/d lower than the previous week.

        Likewise I missed the “other supply” stock change for the total it is a build of 62 kb/d which adds to 434,000 barrels or 0.4 million barrels just as it says in the EIA report for Total Stocks including SPR.

        The report is fine if you read it correctly (as Gone fishing obviously did).

  3. Latest US LTO and Permian basin estimates from EIA, Oct 2017 to Oct 2018. About 66% of the increase in US LTO output over that period has been from Permian basin LTO output.

    1. I see some are still paying a few pennies for someone to take their natural gas in the Permian.

      Waha spot price 62 cents.

      What are these producers thinking? Learned absolutely nothing from 2014-17 crash.

      They are again privately begging OPEC to cut while Trump continues to argue for lower oil prices.

      Look at shale earnings 2015-17. Can they survive $50 and lower WTI again, especially with pipeline constraints blasting basis by up to $25?

      I suspect most hedges are tied to WTI. That would be a shame if you have a WTI lower collar at $50, but local basis is $20 less. So, at $51 WTI, you get $1, and net is just $31 in that example. Hedges did not help.

      1. Shallow sand,

        Can the pump jacks be run on natural gas rather than liquid fuel?

        Pipelines seem to be a big problem for these Permian producers, not enough oil or natural gas pipelines, a sensible strategy would be to stop drilling more wells until there is adequate takeaway capacity, even someone who doesn’t know which way the bit turns can figure that out . 🙂

        1. Our pumpjacks all run on electric.

          Some run on natural gas that is produced at the well.

          I haven’t heard of them being powered by liquid FF, but that is possible I suppose.

          When I looked at JIB statements it seemed that the pumping units were primarily powered by electricity.

          1. Shallow sand,

            I just assumed they ran on gas or diesel like a backup generator, didn’t realize they were electric. Thanks.

            I was thinking the excess natural gas that is being flared or sold for pennies could be used to power pumps, it might be a logistical nightmare, I imagine there are good reasons for just using electricity (simple, dependable, etc).

            1. Same reasons you would want to run everything on electric. No reason to use fossil fuels at all. Pity some people are making so much effort to keep fossil fuels going.

    2. I have no idea why you continue to quote EIA numbers, projections, or anything on their website. Bad data. I see validity up to May. After that, they are in la la land. Most of the info on the website was always in never never land. More recently, is all down the rabbit hole.

      We are seeing an increase in gas, not because there is more oil being produced, but because the area they are drilling in primarily produces more gas and an oil that is close to condensate. Even worse than the EF gas/condensate window.

      1. Guym,

        The data has been pretty good in the past, for monthly output data.

        Data from “tight oil production estimates by play” from page below:

        https://www.eia.gov/petroleum/data.php

        It is just another data point, all we have to go on for tight oil as Enno Peters does not have access to data from all tight oil producing areas in the US.

        Eventually the EIA will revise the monthly data if they believe it is incorrect. Looks like EIA is not far off from RRC data through June (about 150 kb/d above RRC reported output, if I am reading your spreadsheet correctly). EIA often revises data for monthly report so we will soon see what they think output is for August and Sept (I am thinking they might revise August lower).

        In any case they are in some cases far off from the RRC report (January 2018 there was a big difference). In time we will see which is correct.

      2. Guym,

        Yes I know the gas is due to increases in the gas oil ratio as the drill near the New Mexico border.

        I think the data from the EIA is not as bad as you believe, in fact for a while you thought it was ok. It has never been perfect, only the RRC can lay claim to that. 🙂

        1. The EIA monthlies were 200k overstated for Texas for August. GOM was at a high, which I dont believe that 200k increase can be maintained. But George can chime in on that. EIA reported 11.3 mbppd for August, that was at least 200 kbpd overstated, and GOM might be declining, yet they maintain current production is 11.7 mbpd. That is a massive descrepancy. 600kbpd, or more.

          1. Hi Guym,

            I did not put the weekly data up, that was Energy news as the stock levels move the price of oil. You will notice that I said nothing about the output number from that weekly report as those numbers are often wrong and never revised (unlike the monthly data which is corrected over time).

            The STEO has guessed Oct output is 11.45 Mb/d and Nov output is 11.6 Mb/d, they have Sept at 11.46 Mb/d and Aug at 11.35 Mb/d, the August estimate does look high, but I would wait for the drilling info data which tends to be pretty close after about 5 months so in Feb 2019 we will have a better idea about August output.

            I prefer to take several estimates and average them as no estimate is perfect.

      3. Guym,

        STEO for L48 US (exl GOM) in chart below from Dec 2017 to Dec 2019 has about a 1.8 Mb/d increase over 2 years or about a 900 kb/d annual increase, this does not seem unreasonable, though their GOM forecast is probably too high based on George Kaplan’s analysis.

        1. Up to April, they matched RRC, so historicals up to then, i will buy. From that point on, they seem intent on getting historical data to match their wild estimates on current production. Perry should have kept his campaign promise, and eliminated the EIA. But, I guess just like in his speech, he forgot.

          1. The last two months of published GOM oil production, July and August, were the highest ever – the first time ever over 1.8 mmbopd, with August over 1.9. I suspect September will at least be over 1.8, but we’ll see in a few days.
            October should be less because of Hurricane Michael related shut-ins, but, otherwise, is this becoming a new normal for the GOM? I’ll step out on a limb and say that for the next 6 months we could see monthly totals averaging 1.8 or so, with things starting to decline from there – maybe going to March-May, 2019.
            I think the recent increases are due to new developments coming on line (like Kaikias and Stampede), new production from both new wells and new projects coming online in existing fields (at Jack/St. Malo, Tahiti’s TVEX, and Thunderhorse northwest expansion), and, I think some fields that had been shut-in have come back on line (like Stones, and some of LLOGS Delta House tie-ins).

            1. Thanks SouthLaGeo,

              Your perspective is much appreciated, only George Kaplan comes close to you in understanding the potential (or lack) of the GOM (as far as people who comment here.)

            2. Thanks, southLa, you and George have the best bottom up pictures of the GOM.

            3. Availability in July and August for the whole region was pretty close to 100%, I’d be surprised if that was sustained – given the weather, the ageing infrastructure and BSEE testing requirements I think overall it’s less than 95% over the year. Mid summer always seems to have low maintenance, is it because gas demand is highest then? Most LLOG tie ins haven’t been completed yet, but should be over the next few months but I’d expect them to be pretty small flows – maybe 5 kboe per well for La Femme, Claiborne, Red Zinger (6 total I think). Some of the other gains came from completion of 4 or 5 Anadarko wells. The biggest contribution came from Shell in Mars Ursa and could have been Kaikias but I’m not sure as they are over several leases (and the specifically named Kaikias lease is only at 6 kbpd so far). Overall the number of wells classed as “drilling inactive” dropped from over 30 in May to 11 in September, so I’d guess these were all new tie-ins for pre-drilled wells (however it’s not always easy to tell as often they seem to have to drop other wells to make room, so overall production well numbers don’t change much). From the mid August month data I think September will drop about 130 kbpd or maybe a bit more, but you never know. There are sill a few drilled inactive wells left, some of them ill be for LLOG, but after they go it will be interesting to see if new production can keep up with overall decline when it comes only from ongoing drilling programmes.

  4. Could be a game changing year and a half, where the emphasis is not so much on how much oil is produced, but the quality of oil that can be used by the refineries, here.

  5. 2018-11-28 (CTV News) Alberta Premier Rachel Notley says her government has been considering cutting oil production for some time now, adding that an announcement will likely come down in days – not weeks.
    .
    The leader of the opposition in Alberta, Jason Kenny, Kenney floated his own plan for addressing the oil price differential in a press conference Wednesday. He suggested the Alberta government cut oil production by 10 per cent – about 400,000 barrels per day.
    https://www.ctvnews.ca/politics/alberta-considers-cutting-oil-production-announcement-coming-in-days-notley-1.4196127

    1. Read where the judge is going to allow preliminary work on the Keystone. Still a while before that is settled. IMO, this is an important pipeline for the future. Heavy oil is going to be hard to find, soon.

      1. Hardisty light oil $6.29, WCS $10.29.

        30% or more fluctuations in price day to day are commonplace.

        I dont get it, I remember reading a report on relative production costs, including deepwater and shale, back in 2012 that put the cost of Alberta bitumen production at over 150USD a barrel – the most expensive on the planet.

        How could anyone anticipate this farce – do these prices even mean anything? – are significant volumes of oil actually sold at these prices?.

        And yet more production is being brought online. Waiting for some Bay Street type to explain that its all profit above 5 usd because efficiency improvements.

        1. https://pl.boell.org/sites/default/files/marginal_oil_layout_13.pdf
          Generally, Canadian tar sands production is regarded
          as the most expensive oil production in the world and
          has been described by the IEA as “the marginal barrel.”
          Minimum oil prices required for new projects to be
          profitable are variously quoted as between $60 and $90
          per barrel.The IEA claimed in December 2010 that at
          mid-2010 prices, “most new oil-sands projects are thought
          to be profitable at oil prices above $65 to $75 per barrel.”

          So not 150USD, my mistake. (even after adding on todays WTI discount)

          1. https://www.reuters.com/article/us-canada-oilsands-economics-analysis/canadas-oil-sands-survive-but-cant-thrive-in-a-50-oil-world-idUSKBN1CN0FD

            An interesting read from last year in Oct. Its a completely different animal than drilling. They have to be losing money hand over foot, but what to do? The capital required dwarfs completing a well, and unlike a well that largely does not require much manpower, the pictures I have in my mind is that it requires significant manpower. A well, you might be able to shut in, or not complete another.

            2. Profit is no longer a goal, or a reality.
              Seems to work, sort of—–

            3. Perhaps some of the big producers have long running contracts about pipeline slots?

              So they have only to transport the surplus to these cutthrout prices?

      2. Below, after my comment, is a quick Q3-18 summary for Canadian Natural Resources (CNQ: NYSE)

        The high cost numbers of $70 to $100 to produce a barrel of SCO typically includes building an upgrader plant. The marginal cost of producing a barrel, as reported by CNQ below, is closer to US$17.50. Note this does not include maintenance cost, interest charges, admin, etc.

        About a year ago, CNQ purchased Shell’s oil sands operations and at the time they said, as best as I can recall, that the purchase price was about 60% of what it would cost to build from scratch.

        For more info:
        https://www.cnrl.com/investor-information/quarterly-reports.html#2018

        Canadian Natural’s President, Tim McKay, added, “Operations were strong in the third quarter of 2018 across our large, balanced and diverse asset base. The planned turnaround at our Horizon operations was successfully completed under budget and production ramped up on schedule. Our focus on effective and efficient operations resulted in strong quarterly unadjusted operating costs of $22.90/bbl (US$17.52/bbl) of Synthetic Crude Oil (“SCO”) and adjusted operating costs of $19.95/bbl (US$15.26/bbl) of SCO at our Oil Sands Mining and Upgrading operations.
        Net earnings of $1,802 million were realized in Q3/18, an increase of $820 million and $1,118 million over Q2/18 and Q3/17 levels, respectively. Adjusted net earnings in Q3/18 of $1,354 million were achieved, a $75 million increase over Q2/18 and an increase of $1,125 million over Q3/17 levels.

        Cash flows from operating activities were $3,642 million in Q3/18, increases of $1,029 million and $1,120 million over Q2/18 and Q3/17 levels, respectively.

        Canadian Natural generated record quarterly adjusted funds flow of $2,830 million in Q3/18, increases of $124 million and $1,155 million from Q2/18 and Q3/17 levels, respectively. The increase over Q2/18 was primarily due to higher natural gas netbacks and the Company’s continued focus on lowering operating costs in the Exploration and Production (“E&P”) and Oil Sands Mining and Upgrading segments. The increase over Q3/17 primarily reflects higher realized prices from the Company’s liquids production and higher liquids production volumes from the completion of the Horizon Phase 3 expansion.

        Q3 Production (C+C) 801,742

  6. 2018-11-29 (Platts) Houston — The US rig count dropped by 25 on the week to 1,183 for the period ended November 28, posting small reductions in most of the eight large domestic oil and natural gas basins, but with the Permian Basin by far the biggest loser, S&P Global Platts Analytics said Thursday.
    The Permian, located in West Texas and southeast New Mexico, fell by 12 rigs to 482, reversing most of the gains during the last month, according to Platts weekly rig count released each Thursday.
    https://www.spglobal.com/platts/en/market-insights/latest-news/oil/112918-us-rig-count-drops-by-25-to-1183-in-week-ended-november-28

    1. Be interesting if they could break out Singapore from the mix. That’s where part of the Iranian storage is located. Which may be slowly working into the regular sales.

  8. It would be nice to know the average API degrees of liquids flowing since 1970 or so.

    You can get any production you want if you change the definition of oil. The price of WTI is certainly meaningless since WTI’s API has changed in just the last few yrs and that should prevent any comparisons to the past.

  9. Oilprice.com is running a story announcing a new record high in crude and natural gas reserves of the US.

    They do note carefully that this is price derived. It is a bit curious that 2014 at $100+ had less to quote as reserves. That year was sufficiently recent that shale estimates had already risen.

  10. Peak oil summary. in 2000 was 1800G barrels total…then moved to 2400 now 3600….idea cheap 1P then expensive 2P then very hard (Shale, tar sands EOIR) 2+P. In 2008 price for recovery became the driver and printing funds the means to obtain 2+P. Otherwise the 20% used for food and distribution would have meant starvation…As that option was not good, we ‘broke’ the ‘gold’ standard banks…it all works with just in time spending which doesn’t permit ‘running the system’. When does 2+P peak? at 51% of total depletion. Are we there in the banking system? Yes…Brussels broke, Fed broke, Us deficiets broke…Stocks 10% recession decline, most firms junk…

  11. Anybody know of any regulatory requirement for “storage” to provide accurate numbers to anyone? What do they have to gain by doing so?

    1. I don’t guess they have anything to gain. Storage, or inventory has no real measurement. The ones that do try to measure it miss stuff like floating storage, and other significant areas. When it backs up in OECD countries, like in 2014, it’s apparent. So far, those countries are not reporting a build according to IEA. Otherwise, just a huge guessing game.

      Then, there is the cheap Iranian oil for sale. Who knows, some of this may wind up in California.
      https://www.spglobal.com/platts/en/market-insights/latest-news/oil/112818-china-linked-vlccs-storing-iran-crude-loading-from-kharg-island-sources

  12. US crude oil production (EIA-914 survey)
    September up +129 at 11,475 kb/day
    August not revised at 11,346 kb/day)

    Alaska +43 at 471
    Federal Offshore Gulf of Mexico -147 at 1,780
    North Dakota +64 at 1,338
    Texas +106 at 4,692

    Prior estimates for September
    EIA STEO 11.46 million b/day
    IEA OMR 11.52 million b/day
    September average of the weeklies 11,037 kb/day
    https://www.eia.gov/petroleum/production/#oil-tab

  13. 2018-11-30 (Bloomberg) OPEC’s Economic Commission Board recommended the group should cut production by 1.3 million barrels a day from output levels in Oct. 2018, a delegate said, asking not to be named because the meeting is private. ECB deliberations are advisory only and don’t decide policy. The figure reflects the over-production forecast by OPEC in its most recent monthly report, published earlier this month. Ministers will decide their own policy at meeting in Vienna on December 6th

  16. I appreciate this web site so much. Tnx to everyone who makes it work.

  17. At what price does US Shale go through a temporary drop in production like in 2015-16? What price would mean not enough new wells to keep production moving higher? WTI below 50?

    1. I don’t see the Permian dropping. There is a massive amount of ducs drilled. That’s over 40% of the cost. As to the others, they will probably mostly maintain at $50. If WTI stays around $50 or lower by next June, odds are you would see a similar drop. Not likely to stay at $50, though.

  18. Somethings for the shale bugs:

    MORE THAN 75% OF DEDICATED US SHALE OIL COMPANIES KEEP REPORTING CAPEX IN EXCESS OF CFO
    https://www.rystadenergy.com/newsevents/news/press-releases/Shale-companies-ready-to-show-they-can-grow-within-cash-flow/
    See below, numbers are through Q3 so they are presumably worse now.

    SHALE PATCH SEEN CUTTING BUDGETS FOR FIRST TIME SINCE CRASH
    https://www.worldoil.com/news/2018/11/29/shale-patch-seen-cutting-budgets-for-first-time-since-crash
    I haven’t seen much evidence of LTO becoming a swing producer so far, as predicted by some – it has standard company boom and bust dynamics on speed as far as I can tell, which has made things worse rather than smoothing out.

    1. Interesting read, both articles. I don’t see that changing my prediction of flat production for 2019. However, I am wondering now, how that will affect the scheduling of all these new pipelines. The pipelines, by themselves, would not help growth much until port improvements are complete. Still, if the operators can not see pipelines coming online as soon as projected, it will not be an impetus for additional production until they do. Increased oil prices would help, but these companies have to have become real gun shy of stable prices. Right now, many have to feel one step in front of the grim reaper.

  19. ZH reporting the Administration will allow seismic testing in the Atlantic.

  20. Iraq could push Peak Oil out another 10 years.

    U.S. shale oil has helped delay peak oil by 10 years, and may not peak until 2023.

    Iraq by then would have had the time to develop fields affected by the civil war and explore areas barely touched by the oil industry.

    https://oilprice.com/Latest-Energy-News/World-News/Iraqs-Oil-Reserves-May-Be-Much-Higher-Than-Thought.html

    https://www.telegraph.co.uk/business/2018/01/18/bp-returns-northern-iraqs-recaptured-oil-fields/

    http://www.iraq-businessnews.com/list-of-oil-and-gas-fields-in-iraq/

    http://www.iraq-businessnews.com/list-of-oil-and-gas-fields-in-iraq/

    https://www.spglobal.com/platts/en/market-insights/latest-news/oil/101018-lukoil-to-start-production-at-iraqs-newest-massive-discovery-in-2021

    1. Hugo-“Iraq could push Peak Oil out another 10 years.”

      A peak could be prolonged with one force contributing the most to it- that being a big unexpected drop in demand from a severe global recession. Otherwise, good luck.

      1. Iraq and Iran could produce 10 mbd economically at $50. It’s US politics and the need of additional infrastructure to get it out to the market that are the only constraints.

        1. True, enough.
          And Venezuela could produce much more.
          And people could use less petrol, gradually use it rather than ‘all at once’.
          And all the countries could operate the crude market in a coordinated way to prolong the plateau.
          But humans are part of the equation.

        2. HuntingtonBeach,

          Iran and Iraq have been at about 9 Mb/d on average for the past 12 months (C+C output), so 10 Mb/d adds only 1 Mb/d to World output. Venezuela may get producing again at some point, but my guess will be some time after 2025 (perhaps well after). US LTO output is likely to peak by 2024 at about 8.5 to 9 Mb/d, then it will decline by about 4.3 Mb/d over the next 6 years after the peak. The rest of the World will have difficulty making up for this drop in US output, which will have its peak rate of decrease over a two year period, from 2 years after peak to 4 years after peak where output will fall at an annual rate of 1200 kb/d over that two year period.

          This is the reason that a 2023 to 2027 peak is likely, OPEC, Russia, Canada, Brazil, or offshore deep water projects (of which there are few that are economic) will not be able to fill the gap left by declining US LTO output.

          Chart below is Iran and Iraq C+C output TTM=trailing twelve month, over the 1982-2018 period the trend has been a 122 kb/d annual increase in C+C output, currently they are about 1500 kb/d above the long term trend in C+C output.

    2. So Iraq’s going to double their already inflated reserves. Somehow they recently found another 150 billion barrels that were previously hidden under the desert sand??

    3. I read the first article. Towards the end of it there is a puzzling bit of text describing the phases of development of this brand new discovery. One of the things mentioned is that in the very near-term there would be additional wells drilled for the injection of water.

      Does this make sense for a new oilfield? Aren’t they supposed to have their own natural pressure that persists for years, at which time only then you need water drive. Why on day one, or actually before day one, would they be drilling holes for water injection?

      1. On another forum you would have got some pretty offensive remarks. I am not like that.
        It is all about pressure maintenance in order to maintain a single phase(hopefully) in the reservoir. Assuming that the petroleum reservoir is conventional and without a gas cap then the oil and gas will exist as a single phase. If fluids are withdrawn then unless something else replaces the fluids then the pressure will drop as the volume increases and the dissolved gas will come out of solution. This will raise the viscosity of the oil in the rock pores making recovery more difficult, reducing the EUR of the oil in place. If there is an aquifer beneath the oil then water may replace the produce and maintain pressure. If not then water can be injected , usually to the flanks, to maintain reservoir pressure.; the idea is that the injected water sweeps the oil towards the producer wells. Aramco has done this in the Ghawar field very successfully and the Haradh III development did this from the start using injector wells at the flanks and multi lateral horizontal producer wells around the centre portion of the reservoir structure. See image.

    4. Iraq has been spewing nonsense about overtaking Saudi Arabia for at least a prior ten years. Simply hasn’t happened.

      1. While RT defiantly has a direction it is propagandizing, I find the analysis interesting.
        The US has no major news sites that are not idiot based drivel. You really need to get offshore.

  23. U.S. Ending Stocks – month/month change – September
    (million barrels)
    Crude oil +9.3
    Oil products +19.5
    Total (crude oil+products) +28.8 (on chart)
    LPG +11.3 (not included in chart)
    https://pbs.twimg.com/media/Dtbdx2BXQAUR9rd.jpg

    Total (crude oil + products) up +5.8 million barrels from December 2017 (without LPG)
    https://pbs.twimg.com/media/DtbeL_gWoAE4Tid.jpg

    Like the monthly production number, these monthly inventory numbers are higher than the weeklies during September, the monthly increase is almost double the weeklies
    The total (crude oil+products) inventory change calculated from the weeklies in Sept is up +14,643 kb
    Crude +3,809 kb
    Products +10,834 kb
    (without LPG or as they are known in the weeklies NGPLs)

  24. https://oilprice.com/Energy/Crude-Oil/Shale-Drillers-May-Cut-Capex-As-Oil-Falls-To-50.html

    I said the Permian would probably remain flat, now I an not so sure. I wasnt thinking about the small producer, which makes up almost half the drilling activity. RRC points out that activity is already nosediving in the article. By early part of 2019, we should see a decrease in rig count. Not in the neighborhood of the 2015/16 drop, but at this level of production, who knows?

    1. Breakeven isn’t good enough for most shale beyond that, well, you invest to make money not tread water. Because of the decline rates, fracking wells lose most of their production before their debt is paid off, so new wells owned by the same operator have to service that prior debt as well.

      We saw what happened last time when this stops moving for any length of time. A lot of people default and file bankruptcy.

  25. CTVNews.ca Staff, with a report from CTV Edmonton’s Nicole Weisberg
    Published Sunday, December 2, 2018 12:26PM EST

    Alberta’s premier will announce Sunday evening whether the province will temporarily cut its oil production to try and reverse the price drop that has seen Alberta crude sell for significantly less than the world price.

    Premier Rachel Notley may have hinted at her intentions in an op-ed piece published over the weekend in various Alberta newspapers. She laid out the problem, saying 35 million barrels of Alberta oil are sitting in storage because of transportation backlogs.

    “With so much oil just sitting there, unable to be moved, it is being sold at fire-sale prices, around $10 a barrel,” she wrote.

  27. Alberta to temporary cut oil production by -325,000 barrels of oil per day, or -8.7 per cent

    2018-12-02 (CTV News) Alberta’s premier announced on Sunday that the province will temporarily cut its oil production in an attempt to shore up prices and reverse a historic price gap that has seen Alberta crude sell for significantly less than the world price.

    Premier Rachel Notley said the province will mandate a temporary oil production cut of 325,000 barrels of oil per day, or 8.7 per cent, starting in January 2019. She added that the reduction will be subject to a monthly evaluation and that the curtailment amount will decrease over the year.
    https://www.ctvnews.ca/business/alberta-to-cut-oil-production-by-8-7-per-cent-to-deal-with-low-prices-1.4201372

    1. – government sees current surplus of provincial production vs takeaway capacity at ~190 kbpd.
      – cuts will be on an operator rather than a project-level basis.
      – first 10 kbpd of output will be exempt, shielding smaller producers.
      – baseline for cut will be highest 6-months of production over past year.
      – after excess storage is drawn down, curtailment level will fall to 95 kbpd.
      – curtailment regime set to expire on December 31, 2019.
      https://www.alberta.ca/release.cfm?xID=621526E3935AA-08A2-6F45-72145AEBDF115BDF

    2. Reducing inventories will narrow the discount for Canadian oil prices. But I don’t see this making a difference to world supply/demand, not unless Canadian exports were to decrease. And part of the plan is to buy more rail tankers so there doesn’t seem to be any real change.
      I don’t know anything about the demand for Canadian exports, how much pent-up demand is there? In theory the increase in rail tankers will keep a lid on the price rise? And obviously rail costs more.
      Alberta Gov. is said to be worried about the drop in tax revenue which is based on local oil prices?

      1. No, probably won’t dent current world production. But, it will affect any increase. Non-OPEC growth for 2019 was expected to come from primarily three sources: US, Canada and Brazil. Brazil will open up their fields to outside producers mid 2019. That will, no doubt, raise production after 2019, but insignificant for 2019. So, all three will have insignificant to no growth for 2019. And OPEC counters with a cut? Then, we have declines, so how is 2019 going to be higher than 2018?

        2019 will be the Year of the Inventory Draw. OPEC will change direction later, but it wii be too little, too late. And, they will only have alligator tears over it. And why would they be the one to blame? They wouldn’t be responsible for the the irrational projections coming out of EIA.

        Inventories have stabilized at current production. Which, to me, means the earlier projections of demand were worse than wags. Still, we will, no doubt, see some demand growth in 2019. Production will be down. I see, at least, an inventory draw equivalent to 2017/18, which puts inventory levels where? And we won’t see much of that until the second quarter of 2019.

        On another note, EIA has September monthlies going up another 100k for Texas. They have completely lost reason. I can be off 100k, but they are reporting production at over 400k of my estimate. And August is still more than 200k over Texas production. And they still do not realize that, yet? BS.

        Dennis, you asked for my second month totals, earlier. These are the ones for 2018. Earlier four months are on another sheet, which I can get later:

        Jan. 3933 RRC actual
        Feb 4030 RRC
        Mar 4177 RRC
        Apr 4150 RRC
        May 4210 RRC
        June 4344 RRC
        July 4353 RRC
        Aug 4350 RRC
        My guess for Sept is 4240.

        1. So, all three will have insignificant to no growth for 2019. And OPEC counters with a cut? Then, we have declines, so how is 2019 going to be higher than 2018?

          It is possible because most of the 2018 increase in production was in the second half of the year. World production in the second half of 2018 will be about a million barrels a day higher than the first half. And the very highest three months will be October, November and December. So they can cut quite a bit from their last quarter and total production could still be higher than the average of 2018.

          True, it will be close but I think 2019 will be higher but only by a very slight amount.

          1. The most of it will be political:
            – How does the USA/Iran standoff continue
            – How does the USA/SA standoff continue – cutting or blood red state etat
            – Will the Libya / Nigeria calm continue
            – Venezuela

            And the oilprice itself – a further decline can lead to a shale crash, an increase doesn’t do so much here due to other restrictions.

      2. There’s very little pent-up demand for Canadian oil because it is landlocked and heavy. WCS is trading today after the news at $17. This is way, way below full cycle production cost and a fraction of where it trades historically. Less than a third of what it was trading at in July of this year.

        They might as well cut production, there’s no demand for it and they have to be below cash cost for the most part. This was in 2016 but it had Canadian cash cost at $26 including taxes.

        http://graphics.wsj.com/oil-barrel-breakdown/

        1. East coast oil (which is quite an attractive API, though Hebron is heavier) is also down a bit with Hibernia (130 kbpd) off for turnaround for all of September and then shutdown for a fierce storm and delayed start up because of damage to subsea system at White Rose (I think subsea systems for White Rose and Terra Nova are still offline – about 60 kbpd total).

        2. Yes I guess that there’s only so much bitumen upgrading capacity in the USA and so not much pent-up demand for more WCS.

    4. 2018-12-3 (EIA) Pipeline constraints, refinery maintenance push Western Canadian crude oil prices lower
      Relatively low Midwest refinery inputs of crude oil have temporarily reduced the main market for WCS crude oil. Four-week average refinery utilization for the week ending October 26 was 73%, the lowest utilization in the region at any point since 1985.
      https://www.eia.gov/todayinenergy/detail.php?id=37672

  28. Mexico had a big production drop last month and based on the field data that have now been released it mostly came from Ku-Maloob-Zaap. It looks like there has been a big increase in gas breakthrough there (hydrocarbon and nitrogen) over the last year or so and they might be hitting limits on compression. If so they will need to continue choking producing as the GORs increase. The decline is a few months later than Pemex predicted in their 2012 study but might be a bit steeper.

    1. KMZ only data – red dots are gas production and show the step climb this year (I think it is all recycled for voidage replacement with new nitrogen added to make up the difference for produced oil).

  30. 2018-12-03 Alberta crude oil production for October was 3,663 kb/day
    Up +224 from September
    Up +479 from the average for 2017 (full year) which was: 3,184 kb/day
    Split https://pbs.twimg.com/media/DthGaucX4Acrx3y.jpg

    Alberta crude oil inventories at the end of October were 75,616 kb
    Up +355 from September
    https://pbs.twimg.com/media/DthF9BRWkAAdhox.jpg

    Just showing the maths for the baseline, it doesn’t include October’s production so the baseline will be higher & obviously they will export from inventories
    – baseline for cut will be highest 6-months of production over past year.
    https://pbs.twimg.com/media/Dtgf5mtWoAAyMmd.jpg

  31. Yes I think that it’s a fair comment to say that the Alberta production cut will stop production growth in 2019.
    Rystad Energy tweeted this chart today that includes +269 kb/day of growth from Canada during 2019, they must read the news?
    A chart showing what looks like the highest theoretically possible World production growth.
    https://pbs.twimg.com/media/DtfzAY_WsAEN0xP.jpg
    with a 1 million b/day OPEC+ cut https://pbs.twimg.com/media/DtfzFfHWsAEDhsL.jpg

  32. I have Texas production estimated at 4,240 kbpd for September, but am guessing it will rise another 250k by year end, and stay there for awhile. Possibly decreasing some if oil prices hover for awhile at $50. GOM is probably up to 1.8 kbpd according to SouthLa and George until around March. So, my revised estimate for an average US production for the first half would be 11.2.

  35. Schlumberger a drop in US Shale activity

    Schorn Speaks at the Cowen 8th Annual Energy & Natural Resources Conference
    Date: 12/4/2018
    In North America, revenue from our offshore business and our land drilling operations is trending to be flat sequentially. For hydraulic fracturing, we are seeing a significantly larger drop in activity than we expected, which is leading to a larger drop in pricing than we anticipated.
    https://www.slb.com/news/presentations/2018/2018_1204_schorn_cowen.aspx
    Bloomberg graphic, frack crews: https://pbs.twimg.com/media/Dtma6J1XQAAG2cl.jpg

    1. That pretty much supports my estimate that there was a drop in production in September that will trend up a little in Oct and Nov. Fits into the pipeline expansion. I think it will continue to trend down while the current oil prices hover below $55. Smaller producers can’t survive well, and they make up close to 50% of Permian activity.

      I have Texas down by about 100k bod for September. If that holds up, it’s intersting to note how quickly a change in completions affect production.

      Good read, thanks EN.

      1. Guym,

        Smaller producers only produce 10% of Texas C+C, lot of activity, but not a lot of oil.

        https://www.eia.gov/petroleum/production/

        see crude oil comparison with other estimates on right of page

        Using 914 survey data and assuming flat small producer output at 400 kb/d from March to July and then 10% monthly decline in small producer output after July and small producer output at 10% of total Texas output in Jan and Feb, I get the following estimate of Texas C+C output from Jan to Sept 2018 in kb/d (Jan first, then Feb, etc).
        3,863
        3,989
        4,156
        4,210
        4,216
        4,368
        4,419
        4,495
        4,556
        For comparison EIA estimates below
        3,894
        4,015
        4,185
        4,222
        4,260
        4,406
        4,456
        4,586
        4,692

        The Sept estimate is likely too high, by at least 100 kb/d and probably 150 kb/d, August about 90 kb/d too high.

        GuyM’s numbers below:

        Jan. 3933 RRC actual
        Feb 4030 RRC
        Mar 4177 RRC
        Apr 4150 RRC
        May 4210 RRC
        June 4344 RRC
        July 4353 RRC
        Aug 4350 RRC
        My guess for Sept is 4240.

        Difference between my estimate and the RRC data is about 145 kb/d in August and 66 kb/d in July. I agree Sept EIA estimate is not very good, but the average of your estimate and that of the EIA is about 100 kb/d below my estimate. The average of all three estimates is 4496 kb/d for Sept 2018 (about the same as my estimate for August 2018.)

        Also note that the 914 survey has the large producers (typically 90% of Texas output) at 4232 kb/d in Sept 2018, so Guym’s estimate suggests that small producers output fell from 400 kb/d in June 2018 (when my estimate and his data nearly matches) to 8 kb/d in Sept 2018 (if the 914 survey data is accurate).

        Note the 914 survey is the output reported by large C+C producers in Texas to the EIA.

        Small producers do not fill out this survey, they report production only to the RRC and not to the EIA.

        If we take the RRC data from Jan total output was 3933 kb/d and 914 survey data was 3477 kb/d. If the 914 survey is accurate, this implies that large producers produced 88.4% of Texas output in Jan and the 456 kb/d produced by small producers represented about 11.6% of total Texas C+C output.

        Based on GuyM’s data and the 914 survey data the small producer output would be as follows from Jan 2018 to Aug 2018 for C+C in kb/d:
        456
        440
        432
        356
        394
        376
        334
        215

        1. straight from EIA’s records. Has to be true. I can’t find the article now, but I posted it months ago, in that almost 50% of the activity in the Permian was attributed to the small producer. Henceforth, when you quote EIA information, I won’t bother to argue. Your the EIA guy. To me, they are absolute garbage. Per RRC, 32 of the producers make up 71% of Texas production. Some of those are far from household names. The larger producers have more tier one locations. The Texas Alliance representing small producers has 2600 members by itself. The smaller have tier two and mostly three. The smaller is going to produce less than the larger, but that does not mean the production is Fxxcing 10%.

          1. Guym,

            Not exactly 10%, around 10%.

            See

            https://www.eia.gov/petroleum/production/pdf/eia914methodology.pdf

            I did not say the EIA was correct, I said if they are correct in their “large producer” estimate and we deduct the 914 survey estimate from your “actual RRC” production data we get some other number (whuch I have called “small producer” simply indicating that they produce less than the companies that fill out the 914 survey.

            From the doc linked above:

            “The total sample consists of approximately 375 operators out of roughly 15,000 oil and gas operators in the United States. ” So about 2.5% of oil and gas companies are sampled.

            ” The cutoff rates are designed to yield sample coverage of at least 85 percent of the total oil and gas production of each state. ”

            So the target is 85%, but historically for Texas (2015 to 2017) it has been about 90% (0.8995 using drilling info data) for 914 survey coverage. There is of course variation and from April 2015 to Sept 2017 the coverage ranged from 89.2% to 91.8% with a mean of 90.6% over those months (earlier months Jan 2015 to March 2015 were lower at 87.5% and the last 3 months of 2017 were higher at 93.4%, not clear why.) As I have pointed out before this is simply an alternative method to your approach. The maximum for the 914 survey has been 94.4% and the minimum was 86.2% over the first 36 months (2015 to 2017) in Texas. Using your RRC actual for 2018 the range was 88.4% in Jan (min) to 95% in August 2018, your preliminary Sept estimate suggests the 914 survey for Sept covers 99.8% of Texas output, my guess is that there will be a data adjustment, we will see next month where it comes from.

            Have you read somewhere that only 32 producers report to the EIA’s 914 survey?

    1. I think this is nonsense.

      One thing only: Mining industry rampup time. Electric cars are not like smartphones, which is a small device with not much raw material to produce.

      New Lithium deposits have to be found and developed, new mining technic has to be developed and ramped up. In countries with less money supply than the USA shale – and even this industry is now 10 years old.

      The current generation of batteries is insufficient for such a global change – the next battery generation will be more suitable for really mass production – more compact, more safe, less material – but new production technic.

      For example, only the next generation works without kobalt – and this is a bottleneck for the current battery generation

      As a side effect – when the new battery technic is out, we’ll see more flying cars/drones. Small distance air travel will get electric, too. Only middle/long distance flying will stay kerosen, where most of your starting weight is kerosen.

    2. Long timer

      Aviation and shipping will consume any oil that cars do not use. Look at the increase in these two sectors.

  38. 2018-12-05 (Reuters) – Chinese oil trader Unipec plans to resume U.S. crude shipments to China by March after the Xi-Trump deal at the G20 meeting reduced the risk of tariffs being imposed on these imports, three sources with knowledge of the matter said.
    https://www.reuters.com/article/us-usa-trade-china-oil-exclusive/exclusive-chinas-unipec-to-buy-u-s-oil-after-xi-trump-tariff-truce-idUSKBN1O40CX
    Chart https://pbs.twimg.com/media/Dto2JdpWkAAVS1r.jpg
    (And the price of WTI has fallen since Oct)

  39. 2018-12-04 (ShaleProfile) Permian – update through August 2018
    Oil production in the Permian from horizontal wells has continued to rise at an astonishing pace, adding about 1 million bo/d in production capacity in the 12 months through August, to about 2.7 million bo/d (with upward revisions coming).
    The main driver behind this growth is the high level of completion activity; so far more than 2,800 horizontal wells have been completed this year, double the level of just 2 years ago, and 40% higher than last year.
    https://shaleprofile.com/2018/12/04/permian-update-through-august-2018/
    The high on this chart is in June just like the Bloomberg chart for frack crews.

    1. Good to see here:
      Well quality 2017 and 18 increased compared to 2016 – but much less than the improvements the years before. Without a breakthrough here, the optimum is reached.

    2. EN, looks like you would have gotten to my conclusion without me, just using alternate data. But, then again, Enno’s data source is really RRC, as is everyone’s, except EIA. They live in their own world. I look at Enno’s data and the completion activity, and there is a very quick and direct correlation to productivity. Overlap my data, and it just takes a while for total production to drop. 4240 kbpd was the low in Sept. I have estimated it back up another 200 kbpd, but the more I think about it, it will probably only get back up around 4360 kbpd, at best. 11,2 would be a very high estimate of average US production for the first half of 2019, but I will stick with that, for now.

      1. Schlumberger has suggested that unit well productivity in the Midland Wolfcamp has started to decline.

        Unit well productivity is based an a standard lateral length and frac stages per foot of lateral and pounds of proppant per lateral foot. The increase in new well proctivity is largely due to longer laterals, more frac stages per foot of lateral and more proppant use per foot of lateral. Permian producers may be close to determining the optimum well configuration and when that has occurred (if it has not already), well productivity increases will cease and as sweet spots get fully drilled up, poorer geology will lead to decline in new well productivity. My guess id this will occur between 2020 and 2026 with a best guess of Jan 2023 or the start of a decrease in average new well productivity. Much will depend on the rate of horizontal well completions which in turn will depend on future oil prices which are impossible to predict with any accuracy. A knowledgeable oil man often points this out to me, he is correct in my opinion.

        In the past there have been pretty significant revisions in completion data for the most recent 6 months reported, so data from Feb 2018 to Aug 2018 is subject to future revisions as RRC and New Mexico data gets revised over time.

        1. Enno’s data has Permian output increasing by 100 kb/d from June to August.
          From 2578 kb/d in June 2018 to 2677 kb/d in August 2018. For the Eagle Ford there as a decrease over the same period from 1264 kb/d to 1180 kb/d (84 kb/d) so the net gain was only 16 kb/d from these two plays. If we look at Texas Permian only the gain is from 2077 kb/d to 2116 kb/d from June to August, only a 39 kb/d increase and a net loss for Texas LTO output of 45 kb/d, perhaps the data will be revised as Enno always says the data is subject to revision.

          When we compare the EIA’s estimated increase in Eagle Ford Austin Chalk and Permian Basin from Jan 2018 to Aug 2018 with Enno’s “Eagle Ford Region” and Permian Basin over the same period, Enno has the increase at 911 kb/d and EIA’s estimate is lower at 783 kb/d.

          I used Tight Oil production estimates by play at EIA page below

          https://www.eia.gov/petroleum/data.php#crude

          Compared with Enno peter’s data at the two pages below

          https://shaleprofile.com/2018/12/04/permian-update-through-august-2018/

          https://shaleprofile.com/2018/11/29/eagle-ford-update-through-august-2018/

          1. Well, someone has to adjust their data. Time will tell whether data from EIA or current drilling info is better than the source data. But, I said August was the peak:

            1. Guym,

              The drilling info estimates are mostly lower than the RRC reported output, the EIA 914 is a separate survey, the EIA simply shows drilling info data for comparison purposes. Perhaps the oil companies don’t report accurate data to the EIA on the 914 survey. Bottom line is we don’t really know for two years or so what Texas output is, your earliest second month estimate is from about Oct 2017, by Jan 2020 we can compare that estimate to the estimate that the RRC reports in the Production Data Query for Statewide output. Drilling info estimates (which are also based on RRC data) look pretty good through Feb 2018, after that they are a bit low.

    1. Yes this is a good one.

      Flood the world in oil, everyone buys SUVs, especially in China, until LTO and deep sea investments all run dry.

      Then enjoy 150$ oil, until you get back 30$ oil. Pig cycle investing on drugs.

      1. This looks like a setup for a hard spike up – not much longs and increased shorts. It only needs a trigger.

        The decrease of oil price in the last month is explainable with this chart, too. Lots of traders forced to sell their longs into a falling market, increasing momentum.

        I must confess I’ve bought a few paper barrels last Friday. They last 2 years, so no need to see a fast reaction.

        1. 2 years? Yeah, we don’t need that long. My leaps are for Jan 2020, and I feel pretty comfortable with that. Still, I see it taking six months or slightly longer, before they realize how short we will be. EIA will keep putting up these ridiculous projections of current and future production. Which makes it impossible to get a clear demand estimate. That’s been off for awhile, so it’s fairly baked in. Inventories are fairly stable now, as it’s a slow time of year. But, we will get some increase in demand, and very little to no growth out of the US, Canada and Brazil. Throw in an OPEC cut, and a moron can predict inventory drops, eventually. Unless, we get some increases from yet unknown sources, which will make me the moron. Shale producers have been burned bad by these price drops. They will need a significant period of higher prices to return to the hay bales.

          1. Guym,

            The weekly estimates are ridiculous. Everything else is not that bad, the 5 to 15% of Texas Output that is not based on 914 Survey data will mean that the EIA estimates are never perfect (they could be 5% too low or too high depending upon the changes in output from the oil producers that are not part of the 914 survey. The STEO estimates are pretty reasonable and the AEO for the first 10 years to about 2025 is relatively conservative. The AEO longer term (after 2025) is not realistic as the EIA thinks the tight oil resource is about 2 times larger than the mean estimates of the USGS. Chart below has AEO 2018 reference scenario through 2025. The Short term energy outlook has US C+C increasing by 570 kb/d over the next 12 months or about 29% of the increase of the past 12 months (1960 kb/d), this also seems pretty conservative. If the producers not surveyed by the EIA (914 survey) have reduced their output over the past 4 or 5 months, then the July to Sept EIA monthly estimates might be 100 kb/d too high. Not really a big deal.

  41. OPEC+ meeting in Vienna, early statements…

    Bloomberg: Oman Oil Minister: Cuts to be measured against baseline of whichever month is higher between September and October; reductions are for 6 month period from January
    Reuters: Russia agrees to reduce oil production in cooperation with OPEC and its allies in 2019 Discussions are continuing on the figures and the base level of reductions

    OPEC meeting Thursday too

  43. To those the may have missed it, I refer you to three posts above: mine on 12/3 at 9:47, Energy News on 12/4 at 4:36, and his again on 12/5 at 7:39. US production has temporarily peaked in August. Lower than the EIA monthlies. At present, EIA weeklies are reporting production at around 600k-700k bpd over actual. It won’t increase much or any past that point during the first three quarters of 2019, according to most laws of physics. The current oil price won’t move it any higher, either. OPEC sounds like they will come up with an production cut of around one million bpd. That’s why I called 2018 as peak, but Ron is more likely to be right with 2019. At this level of production, there will be huge draws eventually by mid year. OPEC will reverse course, and the pipelines will be complete by the third quarter of 2019. By that time prices will be higher, and stimulate production that still won’t be able to be exported. 2020 will be the big struggle to get enough exported, slowing growth. The next peak projection is Dennis’ projection in 2025, which is running into some headwind with Schlumberger reports of Permian expansion and decline rates of non-opec production. However, he is very likely to be correct on shale production peak.

    1. I see people talk about Iraq being able to increase production into the foreseeable future. Currently at 4.6 million a day, is 5 million a day a reasonable target? or higher?

      1. Dunno, guess that is a Ron question. Most have their area of knowledge, except Energy News, who always comes up with something substantial and new. I’m just an aged CPA who mainly looks at Texas.

        1. The question is how many untapped field do they have to add, or how much they can invest in enhanced production like injections and creaming.

          The oil data from near east is not very transparent.

      3. Holy crap.

        Somewhere in the archives is a projection by the then Iraqi oil minister of some utterly enormous predicted Iraq oil flow, and it was to occur by 2016. Rather more than 4.6 mbpd.

        Shoulda kept that link.

    2. The next peak projection is Dennis’ projection in 2025, which is running into some headwind with Schlumberger reports of Permian expansion and decline rates of non-opec production. However, he is very likely to be correct on shale production peak.

      Peak world production will very likely be in 2019. Peak 12 months will likely be somewhere close to July 2018 thru June 2019, give or take a couple of months.

      I don’t remember where Dennis is pridiction US shale peak but it will be closer to 2020, give or take one year. I will elplain my reasoning there in my OPEC post. That will be Wednesday, Dec. 12, or soon thereafter when Dennis would like it scheduled.

      1. Thanks, Ron. Well, my best guess is that 2019 is when peak demand will start gobbling peak supply’s inventory.

      2. Ron,

        We will have a better idea in 2020. Permian Basin output will be able to grow when pipeline constraints are relieved, though it is possible that ports will become the problem. I think the rate of growth in World output may slow, but I think 2019 will be a temporary plateau (like many times before) and that US tight oil will continue to increase until 2024, the rest of the World (excluding US tight oil) will be roughly flat with Canada and Brazil offsetting decline elsewhere and OPEC will be flat or possibly up slightly. The World will peak very close to the peak in US Tight oil output and I expect that peak to occur between 2021 and 2027 (2021 if the USGS(F95 TRR estimate reflects actual TRR, 2024 for mean USGS estimate, and 2027 for the F5 USGS TRR estimate). This is based on the data we have to date on tight oil average well productivity an assumption that the AEO 2018 reference oil price scenario will be roughly correct.

        1. US tight oil will continue to increase until 2024,

          No, it will not. I will try to explain my reasons for this opinion in my OPEC post nest week. Meanwhile the rest of the world will continue to decline, as it is currently doing.

          1. Ron,

            The rest of the World (including OPEC) cut back on output, but may well slowly decline. There is plenty of potential for US tight oil to grow another 2 to 3 Mb/d over the 2019 to 2023 time frame. If oil supply grows too slowly then oil prices will rise and projects not previously economically viable will become so and this will reduce decline rates for World minus tight oil output. I maintain my estimate of 2023 to 2027 for the peak in World C+C output, mostly based on a peak in US tight oil output in 2022 to 2026, the World peak I expect about a year after the US tight oil peak as high prices may bring on a bit more development, but it will not be enough to stave off a decline in World C+C output. I expect a US tight oil peak of about 8 to 9 Mb/d, I do not expect the World excluding tight oil C+C to decrease by more than 2 to 3 Mb/d over the next 6 years. My guess is that higher oil prices will lead to flat output for World C+C minus US tight oil over the 2019 to 2025 period.

            1. I expect a US tight oil peak of about 8 to 9 Mb/d,

              Really now? And just what is US tight oil production today? Do you think the EIA’s Drilling Productivity Report is anywhere close to being correct. After all their historic numbers match all other EIA numbers exactly. And their 2 to 3-month projection cannot be that far off. They estimate December 2018 shale production to be 7,943,460 barrels per day.

              I have to go with those numbers Dennis. Because those are the only numbers I have.

              I do not expect the World excluding tight oil C+C to decrease by more than 2 to 3 Mb/d over the next 6 years.

              That will be enough.

    1. 9.4 million draw on total stocks including SPR. It begins. That’s about how much it is down for the month, and it is not a high demand period of the year. And prices are down, because they are worried about an extra .3 mbpd of the cut. If this cut lasts six months, it will be a surprise to me.

      1. Net import is down hard this month, too. So it’s just noise for me.
        Inventories are roundabout the same level than last year, so no + or -. Not quite the glut, but no scarity so far, too.

        Global inventory is what matters now to decide how many surplus/decline we have – but these numbers are more clouded and hard to come by.

  45. 2018-12-06 (FT) OPEC has cancelled the press conference for today. Increasingly looks like the decision on size of cut has been left to tomorrow when Russia joins the meeting.
    .
    Saudi energy minister Khalid Al-Falih said that a 1 millon b/d cut between OPEC and non OPEC countries was the main scenario being discussed but still “debating participation and distribution”. Said he was “not confident” of a deal and talks could take “all day” tomorrow

  46. 2018-12-06 (Kepler) Tehran’s exports fell to about 1 million barrels per day in November, compared with an average of 2.7 million barrels per day from April to June.
    https://twitter.com/Kpler

    1. Other reports have indicated in the past, that there is another .3 mbpd that escapes undetected. And I still don’t have a clear picture of where the difference between production and exports wind up. But, nobody expects Iran to be transparent.

  47. Peak oil exports happen back in 2006 at 37.87mbpd. On a global market there is less oil available today than there was back in 2006. It’s currently not much less still above 37.00mbpd i believe. Asia imports is about 26.7mbpd 2017. Asia production is about 7.9mbpd. Europe imports about 11 mbpd. Europe production about 4 mbpd. Now if your China you’ve been able to increase your imports due to the US decreasing their imports. Because obviously without shale oil US is still importing the lion’s share of that 37.00+ available for exporting. China will be targeted for oil consumption decrease. I have to believe that is exactly what is happening today. Trade war and interest rate hikes at the end of a credit cycle.

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