129 thoughts to “Open Thread Petroleum, May 4, 2018”

  1. Hi

    How are you?

    Im from Uruguay, sorry my english is so bad.

    Can you resume the peak oil and natural gas years of the principal production countries?
    Saudi Arabia oil
    Russia oil and gas
    USA oil and gas
    Iran oil and gas
    Iraq oil
    Qatar gas
    UAE oil
    Canada oil anda gas
    China oil
    Kuwait oil
    Brazil oil
    Venezuela oil
    Algeria gas

    Thank you

    Cecilia

    2. Cecilia,

      The information can be found at the link below:

      https://www.bp.com/content/dam/bp/en/corporate/excel/energy-economics/statistical-review-2017/bp-statistical-review-of-world-energy-2017-underpinning-data.xlsx

      or

      https://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html

      Saudi Arabia oil, 585.7 Mt/year 2016 (gas 98.4 Mtoe/year 2016)
      Russia oil and gas, 554.3 Mt/year 2016 and 546.3 Mtoe/year 2011
      USA oil and gas, 565.1 Mt/year 2015 and 707.1 Mtoe/year 2015
      Iran oil and gas, 303.2 Mt/year 1974 and 182.2 Mtoe/year 2016
      Iraq oil, 218.9 Mt/year 2016
      Qatar gas, 163.1 Mtoe/year 2016
      UAE oil, 182.4 Mt/year 2016
      Canada oil and gas, 218.2 Mt/year 2016 and 155 Mtoe/year 2002
      China oil, 214.6 Mt/year 2015
      Kuwait oil, 167.3 Mt/year 1972
      Brazil oil, 136.7 Mt/year 2016
      Venezuela oil, 191.8 Mt/year 1968
      Algeria gas (oil 86.5 Mt/year, 2005), 82.2 Mtoe/year 2016
      Mt= million metric tonnes, for oil 7.33 barrels per metric tonne, for natural gas 1110 cubic meters per metric tonne of oil equivalent (Mtoe)

  3. Just read CC transcript for LGCY, a company which operates primarily conventional stripper well production in the Permian. They also have two rigs running, drilling “shale” wells in PB.

    A lot of mention of well bashing caused by offset operators fracks.

  4. http://caplinepipeline.com/Reports1.aspx

    Capline. The primary assays.

    Note not a drop of Eagleford is anything other than condensate now. Remember 5 yrs ago?

    WTI not even pretending to be 39.6 anymore.

    Which was the number Lynn Helms swore by for Bakken 5 yrs ago. Capline doesn’t agree.

    1. The Eagle Ford their pulling out of my leases are about 32, and many of the completions I have been following in District one and two, are less than 45 and lower. Can’t explain this.

    2. They are approved assays that producers can choose to ship against if they want to use that pipeline, they are not what is actually being shipped. EFHI, EFLO are just names that have been picked for those assays, a lot of EF oil leases might be covered by existing assays with completely unrelated names.

    3. Where does that high API Eagle Ford crude go, then? Is it being exported, or blended in U.S. refineries with heavier crudes in order to be usable?

      Also, from reading Art Berman my understanding is that very little of the fracked-shale oil is useful for making diesel fuel. Is this true or am I reading something into his words?

      Cheers, B.G.

  5. https://www.telesurtv.net/english/news/Russia-Criticizes-Calls-to-Boycott-Venezuelas-Elections-US-Plans-for-Regime-Change-20180504-0003.html

    “14 of 18 political parties in Venezuela signed the democratic guarantees agreement before the May 20 elections and former governor, and opposition member Henri Falcon and several others have entered the presidential race with incumbent Nicolas Maduro. ”

    If Maduro wins, how can the US justify sanctions? Whatever happened to the policy of avoiding interference in a sovereign nation’s affairs.

    1. The Monroe Doctrine has never left.
      Venezuela is flying in the face of that.
      We shall see——

  6. https://www.westwoodenergy.com/news/westwood-insight/westwood-insight-northwest-europe-high-impact-exploration-in-2018/

    Interesting article about recent and near term exploration in UK and Norway offshore regions.

    In the last five years, 121 discoveries have been made in the UK and Norway, of which 41 are currently considered potentially commercial. Only four (3%) of the 121 discoveries were >100 mmboe and all four targeted play opening frontier prospects. Two of the discoveries, Lincoln and Halifax, are within the West of Shetland fractured basement play and are classified as non-commercial pending successful production tests. The other two discoveries, Wisting Central and Alta targeted frontier plays in the Barents Sea, and are considered potentially commercial following appraisal, but are as yet unsanctioned.

    Achmelvich got a lot of attention with BPs 2017 annual report, but it’s only around 25 mmbbls. Wisting is in the north Barents Sea, it will be an interesting, but expensive, project should it proceed: apart from it’s location the reservoir is low pressure and highly compartmentalised.

    1. Thanks.

      Seems the NPD and UKOGA are a little too optimistic about future discovery and reserve growth, between the two they probably guess about 15 to 20 Gb too high for C+C resources.

    1. This looks like something happens the next time – heavy Venezuela oil will break away even more, demand will grow and only the light LTO will increase by some number.

      What’s about the candian increase? Do they build new pipelines the same time, or do they plan to put a few 100kb/day more on rail and road?

      1. I’m still waiting to see if Canada can get its production increase to market (road+rail+tanker), they have 390 kb/day of new pipeline capacity starting next year.

        2018-04-24 (Platts) Enbridge’s plans to proceed with its Line 3 replacement project delivering an additional 380,000 b/d of Canadian crude to refineries in the US Midwest, was boosted Monday when an administrative law judge in Minnesota gave a conditional approval for the planned expansion.
        Line 3 currently ships 390,000 b/d of Western Canadian crude from Hardisty, Alberta to Superior, Wisconsin, with the pipeline passing through Minnesota.
        Enbridge is planning to replace the existing pipeline that was built in the 1960s with 1,031 miles of new pipeline and related facilities on either side of the Canada-US international border, besides nearly doubling its total capacity to 760,000 b/d.
        Enbridge has already received Canadian government approval for the project in 2016 and is now targeting to complete the facility in 2019, the company said in its last earnings call in February, noting work is already underway on the Canadian side to replace the pipeline.
        https://www.platts.com/latest-news/oil/houston/us-judge-gives-conditional-approval-for-enbridge-21863154

      2. I’ve not heard of a reason for the drop in rail movements in January and February but there was talk of cold weather at the time. And so it might not be due to a drop in the availability of locomotives and crews?

      3. TransCanada said a week ago that they will start clearing land in Montana in the coming months for the Keysystone XL.
        The only remaining legal hurdle is complying with Nebraska regulators to do a small re-routing.
        Construction is expected to start in 2019 with a capacity over 800,000 bbld.

  9. The report I referenced above is from Burggraben Holdings. The author is listed as Alexander Stahel. They predict oil prices over 100/bbl. While most of the analysis will not be new to folks who have been paying attention to oil and gas, this is a very complete analysis, including a lot of demand and market info.

    2. Yeah, that article has a lot of meat. Thanks. A lot better analysis than my meager attempt, but also not that far off from mine. I would think an 11 million barrel a day shortage by 2020, would cause prices to rise a tad. My $14 options of USO at January 2020, are beginning to look safer after that read. Heck, they are already in the money.

    3. Pretty good, if a little slanted towards the economist’s view rather than petroleum engineer’s – I guess they are some kind of investment firm are they? I always like the price predictions that show things historically swinging all over the place and then a nice smooth linear or exponential trend off into the future, but that’s been avoided here (just showing actual futures).

      I think he didn’t make the case for the drop off in recent discoveries being as important as it is going to prove; I think he probably thinks everything gets solved there at the right price level.

      There is the assumption of 19 mmbpd new production to 2022 from in-fill drilling. I don’t know how that is arrived at. In-fill wells accelerate production but don’t do so much to grow reserves. They can also be used to get round surface constraints like water injection/processing limits, but there’s a limit, especially on mature fields. A lot of the low hanging fruit was picked in the high price years. In-fill wells on deep water fields can be very expensive, and on recent projects that have been more optimally designed with latest seismic data and often have production heavily front loaded, may not not yield so much. If that amount of in-fill is achieved then I’d suggest production will drop like a stone after 2022, when there are no more opportunities in mature fields and relatively fewer new fields that might be receptive to it (he almost touches on this in the slide on accelerating decline rates). The drop off in discoveries also means there are fewer short cycle tie-back opportunities – the very last ones with around 10 mmbbls are just being used up in the North Sea, smaller ones don’t produce much and might be marginal at any oil price. For the capacity additions I think he has them all against the start up year (e.g. noticeably Johan Sverdrup and Brazil this year) rather than with ramp up times, which will actually add slightly to the deficit before 2022, and I think a significant chunk are actually brownfield projects design to maintain production rather than increase it (e.g. Tengiz).

      I think he may be underestimating how many countries are going to start showing significant decline soon, and by how much – UK will be dropping 100 kbpd per year after 2019, a lot of the Asian countries, too, are likely to see acceleration and are switching to gas projects. The importance of condensate and NGL in the mix could also be important – it has had an impact not far short of shale oil, but it too may be falling off now with maybe drier gas developed for some LNG and overall decline in some fields brought on since 2000.

      The chart below caught my eye particularly, though I’m not sure if this might be oil and gas combined.

      1. Yeah, there are some overestimations and underestimation, but much more realistic than most. Gave a lot more to look at, because of the level of detail. I think the decline will be faster and bigger than he estimated, but he makes my methods look bad by level of detail. He gets an A+.
        I guess I especially like it, because he makes my argument clear. You can project a ridiculous amount of US production, and we will still be short. So my argument that US production will be no where near it’s projection in this, or any other, will not matter. It will be far short even if it attains their lofty projections.

        1. On that piece that dclonghorn posted.

          First thanks, a good overview.

          I think the demand for C+C (which is what we pay for when we purchase a barrel of Brent or WTI) will be maybe 800 to 1000 kb/d, whether there is another 800 to 1000 kb/d demand for biofuels and NGL is doubtful in my view and these are not what there will be a shortage of, it’s C+C that’s needed.

          I think in 2018 there may be enough output of LTO to keep the market balanced if my demand estimate is accurate (note that long term fro 1982 to 2017 the trend of supply has been an average rate of increase of 800 kb/d, it’s possible 2018 could be a little higher or lower than this overall trend, difficult to predict demand in advance. Bottom line, prices should stay about where they are until the end of 2018, in 2019 prices will need to rise to get enough of an increase in LTO to meet demand and there will be downside risk due to falling North Sea and GOM output hitting by 2020 at the latest (I think 2019 is more likely).

          Also the page 58 claim that all LTO plays are profitable at $60/b is likely incorrect, for a 10% discount rate the average Permian well needs $70/b and all other plays need more than that (Permian is currently the lowest cost basin as far as cost per barrel). That analysis is based on average 2016 Permian wells oil and gas output and includes average NGL per barrel of natural gas in the analysis, $3/MCF for gas and 75% of the barrel of oil cost for NGL.

          Often these analyses take the sweetest of sweet spots (I have seen analyses based on 30 wells from a particularly productive core area) and deem these to be “typical” Permian wells.

          That’s a little like analyzing Michael Jordan, Lebron James, Larry Bird, Magic Johnson, and Steph Curry and claiming these at “typical” basketball players.

          In short, all US LTO plays are not profitable at $60/b.

          1. should have said I expect the increase in demand for C+C in 2018 will be 800+/-200 kb/d as that has been the trend from 1982-2017 in the average annual increase in C+C output (based on EIA data).

            Also I updated my Permian well profile based on the latest oil well profile data from Enno Peters at

            https://shaleprofile.com/index.php/2018/04/03/permian-update-through-december-2017/

            Turns out that for Permian LTO wells that started producing in 2016 the EUR has increased to 380 kb over their life (a 24% increase from the average 2015 Permian well).

            If a 9 million dollar well cost (2018$) and 10% nominal discount rate are assumed, the discounted net revenue from the well is about 9 million at a wellhead oil price of $62.4/b over the life of the well. At that price, payout is reached in 65 months. A 60 month payout is reached at a wellhead price of $64/b, and a 36 month payout is reached at a wellhead price of about $75/b.

  11. WTI crosses $70 in overnight.

    Last time we saw that was pre-thanksgiving 2014.

    Was a tough old slog.

    Things sure heating up.

    Got a free sample of American Oil Investor in the mail. Issue focuses on water handling in the Permian.

    The photos of all the huge open top water tanks lined up side by side are unreal. So are the photos of all of the man made “lakes”.

    Lots of money guys (Wall Street, etc) getting into the water handling business in the PB.

    Gold Rush stuff.

    1. Maduro chided the original decision of 2 billion plus, as being a win for PVDSA, and ConocoPhillips went for the throat.

    2. They also dropped eight rigs, down to 36 – about half what they averaged in 2014/2015.

    3. Bogota, 7 May (Argus) — Venezuela could be forced to shut in some of its already declining crude production, reprogram exports and sell distressed cargoes to cope with the indirect impact of liens on Venezuelan state-owned PdV´s Dutch Caribbean assets imposed by ConocoPhillips, a leading arbitration claimant.
      PdV has begun recalling its oil tankers from Dutch Caribbean waters to forestall further asset seizures, effectively restricting its ability to import critically needed fuel and diluent, and export crude and fuel oil, industry officials say.
      For ConocoPhillips, the objective of the action is less about the value of the assets or the oil stored in them, and more about putting an operational “stranglehold” on PdV to force it to pay the ICC award, one of the attorneys says. The strategy appears to be to “grab something so vital to PdV, the company will have no choice but to pay the award,” the attorney said.
      http://www.argusmedia.com/news/article/?id=1675802

      1. And to pay the award, Ven will need to lay out a substantial amount of their remaining piggy bank, resulting in more risk for future defaults. Catch 22. Not knowing all the details, it would seem that a prudent business decision would be, at least, an agreement to pay out the award. Then, again, I am not Maduro.

        1. Maduro will be re-elected May 20. Russia and China will congratulate him.

          The US will declare it a fraud.

          The UN will seat the Maduro delegation. All embassies of the world ditto. Including the US Ven embassy, plus whatever, 6 or 7 Ven consulates from Houston to Boston.

          The US will then be imposing mostly oil sanctions on a democratically elected govt that it and the UN recognizes.

  15. Brazil oil production declined about 54 kbpd in March. Campos basin decline is fairly steady at 20 to 30 kbpd per month; ANP generally finds a reason in operation disruption on one or two FPSOs, but given the number in operation there is always going to be something like that going on and it cancels out over time, so the trend is from overall depletion. Santos basin also dropped over 20 kbpd and it is noticeable that some of their older FPSOs may be starting to decline and I think the deep wells there can die even faster than those in Campos.

    1. The Berbigao FPSO has been delayed to 2019. Atlanta (20 kbpd) started in May and Buzios 1 (150 kbpd) in late April. There are 5 other 150 kbpd clones due, but I wouldn’t be surprised at a couple of other delays. To maintain plateau I think they need 3 a year starting up and 3 completing ramp-up (they only have one small one – the Mero pilot – ramping up, hence the current decline).

  17. 2018-05-08 EIA STEO
    EIA estimates that U.S. crude oil production averaged 10.5 million barrels per day (b/d) in April, up 120,000 b/d from the March level. EIA projects that U.S. crude oil production will average 10.7 million b/d in 2018
    https://www.eia.gov/outlooks/steo/

  18. Trump confirms US will withdraw from Iran nuclear deal:
    * Says will reimpose sanctions
    * Says will be introducing the highest form of economic sanctions
    * “Any nation that helps Iran in its quest for nuclear weapons will also be sanctioned by United States”
    & Trump says that he is “ready, willing and able” to negotiate new deal with Iran

    US Treasury says petroleum-related transactions will see sanctions reimposed again after 180 day wind-down period

    2. Asia still bought Iranian crude during the sanctions, mostly China and India

      2018-05-09 (ClipperData) Iranian crude offtake by region since 2013.
      https://pbs.twimg.com/media/Dcu5-1mXUAANyO2.jpg
      https://twitter.com/ClipperData
      another version https://pbs.twimg.com/media/Dcu9B_9WsAE_5EK.jpg

      The consensus of opinion is that Iranian oil exports may fall anywhere from 200 to 500 kb/day over the next 6 months

      2018-05-09 (Bloomberg) Japanese government plans to seek exemption from U.S. sanctions on imports of Iranian crude, Takashi Yamada, director of petroleum policy at Ministry of Economy, Trade and Industry

      2018-05-09 (Reuters) South Korea’s energy ministry is seeking an exemption on oil/condensates imports from Iran.

      1. In theory OPEC (Saudi) could just make up the difference within the overall production limit – be interesting to see if they do/can.

        1. Make up for Iran, Venezuela, and Angola? They wouldn’t be in too much of a rush to do it.

  19. Today the EIA published its May-18 STEO. Attached is a chart which shows how the EIA’s projection for the onshore lower 48 production has changed significantly over the last few months, Mar, Apr and May. Two trends are clear from this chart. Production from onshore production is expected to increase at a rate of close to 110 kb/d/mth up to May 2019 after which it may start to plateau. While the May STEO shows production plateauing at 9.6 Mb/d, that level has increase by 60 kb/d from March to May, of which 40 kb/d occurred from April to May.

    From Dec 17 to Dec 19, GOM production is projected to increase by 36 kb/d to 1.94 Mb/d. Alaska production continues at 500 kb/d, except for summer maintenance season.

  20. API report a total draw of -10.5 million barrels (crude+gasoline+distillates)

    (MarketWatch) The American Petroleum Institute reported Tuesday that U.S. crude supplies fell by nearly 1.9 million barrels for the week ended May 4, according to sources. The API data also showed a fall of about 2.1 million barrels in gasoline stockpiles, while inventories of distillates dropped 6.7 million barrels, sources said.
    https://www.marketwatch.com/story/api-data-reportedly-show-a-weekly-decline-in-us-crude-supply-2018-05-08
    Chart on Twitter: https://pbs.twimg.com/media/Dcs_vjTWsAABcU_.jpg

    1. World economy is thirsty. The thing is that whatever oil supply will be, world econony will always want MORE. When supply grows, like in recnet years, world economy will grow, and become addicted to this bigger supply. Untill supply will shrink, and the economy starts to collapse.

    2. I’d bet a lot of that is just catch up from the putative and unpredicted gains in the previous two weeks (i.e. just sampling and reporting artefacts). Either way Brent heading for $77 at the moment, I think it’s going up just about as fast as during the 2008 and 2011 spikes, at some point trader sentiment takes over to drive it to the peak, but I don’t think it’s there yet.

      The drop in distillate is pretty noticeable now – is that just loss of Venezuela heavy oil? Might also have to do with higher demand as the low sulphur IMO rules start to impact and ships switch over to marine diesel.

    3. I’m guessing it’s due to world economic growth. The usual story, growing middle class, increasing air travel, a shortage of electricity, lorries, construction. And I keep remembering that some statisticians are saying that even if population growth slows there could still be 9 billion people in a few decades time.

      I keep looking for news on a shortage of heavy barrels but not found much.
      Bloomberg, US refiners diet: https://pbs.twimg.com/media/DcLkL1TXUAEHvF0.jpg

      I seem to remember that the ship fuel rule only starts in 2020.

      1. It is mandatory then but owners are switching over now to be ready. There’s not much demand for heavy oil as such (marine bunker oil is one of the biggest market and is shrinking with the IMO rule changes); most gets cracked so it would show up as distillate or gasoline depending on how the spread is set. Saudi cuts were supposed to be mostly heavier oil so maybe they can adjust if they have spare capacity, but it’s possible they just took Manifa off line because of the water injection problems and can’t bring it back straight away.

      2. EN: do you know if and how the higher API has affected the relative composition of products? For example, the share of diesel produced in US relative to gasoline?

        This is just from the top of my head (and it’s pretty empty): distillate stocks (including diesel) seems to decline faster than gasoline stocks and I guess there are a number of factors explaining this including the use of higher API stuff (LTO) and perhaps exports to Europe.

        BTW. WCS is trading at a discount in Canada (due to take a way capacity-bottleneck) but the heavy to WTI discount is low in Houston and I think it has narrowed lately. Calling it a shortage would be to stretch it too far though.

  21. I don’t completely understand this situation.

    1. Vanadium and hydrogen sulfide are considered significant contaminants in oil. If a reservoir has a high concentration of vanadium, it is considered sub-quality. But how much? http://www.theoildrum.com/node/9056
    “The Oil Drum | Manifa Oil: Malodorous, But Really Not That Bad”

    2. The Canadian oil sands have apparently a high vanadium content. Now the news is that this is good for extraction on its own
    http://www.cbc.ca/news/business/vanadium-shell-oilsands-renewables-1.4608208
    “Oilsands research could be ‘game changer’ for renewable energy
    Researchers are extracting vanadium from the oilsands and using it to build batteries”

    cf. Vanadium flow batteries or vanadium redox batteries

    1. Sounds like most of the vanadium might be in the tailings, so needs different processing methods than if it goes with the oil. Venezuela oil has a high vanadium content, I seem to remember around 2%, I hate to think of what the storage areas for that waste look like at the moment. Shell is selling up in the oil sands for $3 billion so this might not go any further.

    1. Distillates inventories down partly because exports are high at the moment

    2. The distillate stocks has never been bellow 111 mb in 2010s. So at 115 mb we appear to be in the lower part of the comfort zone. It was as low as 93 mb back in 2000, but distillate production was lower back then. See
      https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WDISTUS1&f=W
      and
      https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WDIRPUS2&f=W
      The distillate stocks has been dropping fast since February. So if this continues, then I think we could see shortages quite soon. There is still a lot of commercial oil stocks left. But those are maybe mostly light oil? Here is a good article related to this:
      https://oilprice.com/Energy/Energy-General/US-Shales-Refining-Crisis.html

      1. How do exports go up as shown in the chart if there isn’t enough of the right kind of feed stock to produce the distillate? It looks more like they can just get more money selling the distillate abroad.

        1. But why would they get more money selling it abroad if there were plenty of there and low levels at home? Transporting it also costs which should normally make the home market a better option.

          1. I don’t know, I was really just criticising that article as much as anything. About twenty years ago there was always a trade of diesel from the USA to Europe and gasoline the other way (and diesel was relatively cheap in UK compared to petrol), because of the supply and demand balance – in particular more gasoline vehicles than diesel in USA. Things are much more changeable now, but transport by tankers is pretty cheap (about one dollar per barrel) and normally not a big factor. The global diesel demand may be increasing, especially in Asia as the economies there are growing faster than in OECD, and the IMO changes (which have already been implemented – actually more stringently – in Europe and USA) might be a factor.

            I just don’t see refinery limits as an issue at the moment. It’s more that there may be a growing overall shortage of distillate, but the MSM is not allowed to even hint at such a thing, and the shortage is really from a relatively sudden decline in heavy oil that can be cracked, not too much light oil.

            1. I’ve found an article about a “sudden decline in heavy oil” if anyone is still interested in the subject…..

              Sep 23, 2017 (Oil & Gas 360) OPEC cuts mostly bring heavy oil offline

              One of the most important oil supply developments at present is the OPEC production cut. While compliance is not total, it has been successful in bringing some production off the global oil market. Most of this production is heavy and medium crude, as Saudi Arabia and Iraq are among the largest medium oil producers and Venezuela is one of the foremost heavy oil producers.

              Light crude producers, on the other hand, have been growing quickly. U.S. unconventional shale operations produce exclusively light oil, and have already added significant production from the lows seen in 2016. The two OPEC countries excluded from the cut agreement, Libya and Nigeria, also produce light oil.
              https://oilprice.com/Energy/Crude-Oil/Heavy-Crude-Production-Hit-Hard-By-OPEC-Cuts.html

            2. And Venezuela has dropped much more since then, Iran also heavy, Mexico decline is now more in the heavy stuff as the lighter oil is mostly exhausted, maybe not quite as much Canadian as expected as well, Ecuador and Colombia are heavyish and declining. On the other hand the newer stuff in the North Sea is heavier.

            3. George K.

              I made a comment on the Norwegian production and forecast thread, if you are interested. Not very timely… a bit late.

              One of the things I am not following closely is that the natural gas reserves in Norway is not as high as most would like it to be. You mentioned that in an earlier post if I remember right.

            4. Thanks. They seem to be covering for gas decline elsewhere by raising the production allowance for Troll, I don’t know how high they can go though. Orman Lange is in decline, which has been a bit ameliorated by compression, but I think it will be finishe in the mid 20s. One problem is that the Barents Sea associated gas can’t be produced commercially and is reinjected, another is the big mature, field gas cap blow downs are getting exhausted.

            5. Thanks Energy News. I had a look at OECD Europe industry stocks (from IEA monthly):

              Jan 2018:
              Motor Gasoline: 101.2 mb
              Middle Distillate: 289.4 mb

              Jan 2017:
              Motor Gasoline: 104.0 mb
              Middle Distillate: 319.2 mb

              Jan 2014:
              Motor Gasoline: 94.3 mb
              Middle Distillate: 259.3 mb

              Middle Distillate decreased much faster than Motor Gasoline between January 2017 and 2018. So it´s not only US which is affected. They were still above the 2014 levels. But that was in January. It will be interesting to see next weeks reports.

            6. The demand for products can change as well as engines can be quite flexible when it comes to fuel. The diesel engines have become just better and more energy efficient than gasoline engines in my opinion. They also pollute less than before. The policy in Europe to move away from diesel in personal transportation makes sense. The fuel is vital to shipping and heavy road transportation which runs the economy. I guess in the future we will have a mix of gasoline and electric cars for personal transportation in many countries.

              And kerosene use in aviation is also just too useful; only high prices will stop the growth. Distillate products should be priced high due to their usefulness, maybe it is natural with a supply squeeze in this segment now. And the scarcity is sure coming, no amount of light oil/condensate from Delaware basin can stop that.

            7. In about 19 months from now, January, 2020, stringent emission standards for international shipping kicks in.
              This is expected to cause a huge spike in the price of low sulfur diesel.

              Simultaneous with the anticipated price increase is the incremental market introduction of Nikola Motors electric Class 8 truck fueled with a hydrogen cell.
              Anheiser Busch just announced an 800 truck pre order with Nikola for their over the road fleet.

              Big, big changes may be right around the corner.

            8. There will be big changes and the 3 year low oil price enviroment (2015-2017) will force it coming forward. Talking about hydrogen and electric cars it should be mentioned that these are high cost alternatives. Which could be forced upon us. Still, there are many options higher priced than cheap oil that can keep the energy revolution going for quite a while. The peak of convenience is likley to be about now (2019-20), with livable alternatives going forward. (I am a free thinker; a rational one hopefully).

            9. Kol

              I’ve been inclined to think natgas will provide transportation fuel going forward with the rapidly evolving MOF technology playing a big role.

              However, this Nikola outfit seems to have some heavy hitters in their corner (along with a ton of detractors), and – most intriguingly to me – they have hooked up with some Norwegians who seem to be economically producing hydrogen via solar-sourced electrolysis.

              Beats me how it will all turn out, but the info coming out of Nikola such as the truck’s specifications, free one million miles worth of fuel, all-encompassing leasing program …
              Guess within a couple of years we will get to see.

            10. I wrote that backwards – USA used to get the diesel, I guess more long distance trucking apart from anything else.

  23. https://www.platts.com/latest-news/oil/washington/permian-crude-producers-work-to-reduce-exposure-10395154

    Pipeline shortage article. I found Ecana’s CEO’s comments as horses mouth, stuff. Seeing it now by rail and truck. Discount to $15 expected within a few months, and discount problem until most of 2019. At these prices, I don’t see much let up, until there are no more rowboats to take it down the Rio Grande river. The trucking cost is going to be horrendous. Trucking companies can make a fortune just in the next year, if driver shortages were not so bad. If I were younger, I’d be tempted to get my CDL and invest in a rig.

    1. Guym,

      Thanks.

      They are talking about big spreads at Midland of as much as $15/b by the end of 2018, even if WTI goes to $80/b that’s probably only $60/b at the well head (if we assume transport cost of $5/b to Midland). The average 2016 Permian well needs over $60/b to earn a 10% annual ROI, so the pipeline issue might slow down the pace of Permian well completions as the spread get’s bigger.

      1. There would really not be all that much extra profit rolling around in 2018, anyway. Most of these companies, including those that have a substantial amount of their production flowing through pipelines, have to do something with all of those derivatives they loaded up on when oil was in the $50s. Now, they have discounts on top of that.
        Fortunately, my main operator, EOG, had only bought 9% of their production with derivatives.

  24. Kinder Morgan pipeline won’t get built, Vancouver mayor says
    https://www.sfgate.com/news/article/Kinder-Morgan-pipeline-won-t-get-built-Vancouver-12901409.php

    “I don’t think the resistance on the west coast is going to fade — I think it will only intensify,” he said. “Escalation looks likely.”

    Lets see who wins– the corps or the people.
    BC is a foe with teeth.

    “Alberta’s oil and gas sector “represents such a tiny fraction of the overall economy and a job count,” whereas cities like Vancouver and Toronto are driven by newer technology and innovation-related sectors, he said.”

        1. Well, guess that makes me a psychopath, cause I own a few corps. So do most of the small business people that make up the majority of places that pay most employees in the US. The alternative would be to let the government run everything. Which would make it one big psychopath, instead of a bunch of small psychopaths. Pick your poison.

          1. “Well, guess that makes me a psychopath, cause I own a few corps.”

            So do I– the sicker the better!

      2. Guym,

        I think the ban is on tanker traffic along the west coast from the northern tip of Vancouver Island to the Alaska border. The Kinder Morgan pipeline would end near Vancouver, way to the south.

  26. Hi there peakoilers, I live in Europe and need to buy a new car. I do believe an oil shock is just around the corner, and am considering a Gpl vehicle, assuming Gpl prices will be less affected than gasoline and diesel. Is that a correct assumption?

    1. For those who aren’t sure what Gpl vehicle is –
      “Autogas is the common name for liquefied petroleum gas (LPG) when it is used as a fuel in internal combustion engines in vehicles as well as in stationary applications such as generators. It is a mixture of propane and butane.”
      “Autogas is the third most popular automotive fuel in the world, with approximately 16 million of 600 million passenger cars powered using the fuel, representing less than 3% of the total market share. Approximately half of all autogas-fueled passenger vehicles are in the five largest markets (in descending order): Turkey, South Korea, Poland, Italy, and Australia.[2]”

      I suppose if you are in a country that has plentiful supplies, that would make plenty of sense. An electric or hybrid electric is a good alternative if your country has a good infrastructure for electrical generation, or your locale is plenty sunny (solar on the roof).

      1. There is an extraordinary amount of propane (and ethane) coming to market shortly from the Appalachian Basin, Oklahoma, and the Permian.

        The Mariner East 2 pipeline should bump output to Marcus Hook from the current 70,000 bpd (ethane and propane) shipped via Mariner East 1, to an additional 275,000 bpd on Mariner East 2 when it comes online this year.
        A companion pipe, the 16 incher Mariner East 2X could be in service by 2019 carrying an additional 250,000 bpd.
        Both new pipes could expand capacity by several hundred thousand bpd with additional compressors.

        No idea of the downstream pricing, but supply looks strong for decades.

    3. The problem is that gas is much more expensive to transport that oil so gas is much less of a global market than oil. Will Russia continue to supply gas at current rates? Will N. Sea gas production continue at present rates? Things could go wrong with European gas even though world wide gas extraction continues to increase.

    4. Hi Nicholas,

      Natural gas will also peak and decline (LPG is a byproduct of natural gas production).

      My recommendation is a plugin hybrid or EV, or at minimum a hybrid.

    5. I also live in Europe. My personal tactic is to look for very fuel efficient vehicles. The rules of thumb for efficiency are low weight and aerodynamic body. My personal favorite is not yet available, it is the hybrid human-electric powered Pod Ride: http://mypodride.com/ (I am old guy for whom the world goes too fast). In the States, I like the Elf: https://organictransit.com/. The drawback with the Elf is that it is a slow moving vehicle that doesn’t fit in a bike lane so there are many places where you might be a bit annoying to other drivers.

      2. I don’t like these hybrids – too dangerous on road and don’t fit in bike lanes.

        Either an (electric) bike,+ good rain equipment and or an app for the public transport time scedule, or a small fuel efficient car – and economic driving it. When you go sub 4 litres / 100km the gas price won’t matter that much even in expensive Europe.

        The Elf will have a very limited range – as I can guess due to my experience with my electric bike don’t expect to go farther then 20-25 mile on one charge when you don’t do most of the work – and it is definitly more heavy than a conventional bike.

  28. https://oilprice.com/Energy/Crude-Oil/Permian-Bottleneck-Provides-Huge-Opportunity-For-Oil-Traders.html

    Down to the rail, but according to this, I don’t see the rail taking most of the expected increase. The article says the discount is already at $16. Not $15 in a few months, but $16, already. It takes a full day to load a 75k train. Most of the rail is used by sand and other equipment, so something will have to be displaced. Just don’t see the increase in the Permian that others are projecting. Drivers are still in a shortage, but just think what an independent could get driving one tanker of 200 bbls a day. If he/she could directly contract with a producer to get it to Corpus or Houston at $20 a barrel, then that’s a $4000 gross per trip.

      1. https://www.reuters.com/article/usa-oil-permian-eastcoast/rpt-us-east-coast-refiners-look-to-texas-crude-for-discounted-oil-idUSL1N1SG1ZI

        Found what I was looking for, it came from Genscape, although reported second hand. The cost is just not clear yet, nor is it clear how much that would interfere with getting necessary supplies in.
        There are 15 terminals in the Permian capable of loading 500k to 600k a day. However, you would have to convince the railroads that it is cost beneficial to do so. The railroads know this will be a short term income, and a lot of cost. The drivers are not there, but they could pay for a very expensive train ride for their oil. You may be looking at the same discount Canada is having to pay, close to $31 a barrel. Better than rowboat.
        Or, once they get it on train, it could go to the east coast.
        https://www.reuters.com/article/usa-oil-permian-eastcoast/rpt-us-east-coast-refiners-look-to-texas-crude-for-discounted-oil-idUSL1N1SG1ZI
        Which would be optimum, as it would lower imports. Require less exports, too. Although, I still expect production to flatten out, a bit, until new pipelines are established. Yet, train shipments to the east coast are still an option if they get backed up on exports.

      1. So there was a declining trend up until 2014 which was then reversed until 2017. Iraq production increased by 1,5 mb/d from 2014 to 2017. At the same time US production declined by close to 1 mb/d from beginning of 2015 to end of 2016. That can probably explain it.

        1. Good point – new Iraq production was heavier. It looks like that curve is still dropping past the normal inversion point for the year, though last year was later too, so interesting to see how things play out now.

        2. I looked into it a bit more. Bellow is a graph showing US distillate and gasoline production. You can see that distillate production has been about flat since 2014 with maybe a slight increase since 2017. The distillate / gasoline production ratio is actually a little higher than it was pre-2008.

          Here we can see US distillate consumption:
          https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mdiupus1&f=a
          It´s down a little since 2014. So increased US consumption is not the reason for the stock draws.

          Here is US distillate exports:
          https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=wdiexus2&f=4
          A bit hard to see, but it increased end of 2017.

          Here we can see from which countries US imports oil from:
          https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbblpd_a.htm
          Actually very little of the extra Iraq production I talked about has been exported to US. So that can explain why there was slighly less demand of US distillates – it was produced outside the US. We can also see that oil imports from Canada increased more than what was lost from Mexico and Venezuela from 2014 to 2017. On a global scale however, production lost from Mexico and Venezuela from 2016 to 1Q18 was 1 mb/d while Canada increased production by 0,5 mb/d. Instead, as you know, most of the increase in oil production has been from US LTO. So that explains why there is a higher demand for importing US distillates.

      2. A quick look at product prices, the prices of both, diesel and heating oil are above the price of gasoline at the moment (spot prices – dollars per gallon)

        1. Pretty inelastic over the short term at those sort of ranges I’d have thought hence stock changes are taking up the slack at the moment.

    2. USA – distillate days of supply
      https://pbs.twimg.com/media/DdAZ46YWAAAfkiV.jpg

      2 more US diesel/gasoline ratios
      https://pbs.twimg.com/media/DdASk6gX0AAT-8l.jpg

      Demand ratio
      EIA – Weekly U.S. Product Supplied of Distillate Fuel Oil
      Divided by
      EIA – Weekly U.S. Product Supplied of Finished Motor Gasoline

      Production Ratio
      EIA – Weekly U.S. Refiner and Blender Net Production of Distillate Fuel Oil
      Divided by
      EIA – Weekly U.S. Refiner and Blender Net Production of Finished Motor Gasoline

  31. Sorry to anyone who couldn’t access the blog, it was temporarily down, but should be ok now.

    1. The “truth” is in PDP and PUD reserves reported to the SEC by 13 of the largest shale oil operators in the Permian and in that regard, Art is correct; about seven years from the Permian at 3.3MM BOPD: https://www.oilystuffblog.com/single-post/2018/05/09/Saudi-America-My-Ass. The Bakken and the Eagle For are through growing up; that’s just the oil business and shale is no different.

      Additional reserves that might prolong the inevitable in the Permian, particularly in Tier II areas, will cost more money and be even less profitable, therefore requiring more borrowed capital. Then there is the matter of legacy debt, debt maturities, new debt to refinance old debt and rising interest rates, which EVERYONE simply ignores. Like it is all going to go away, magically.

      Art is a friend and this is a stupid article. He has been right as often, or more, than he has been wrong and both things occur when you have the courage to stand up for what you believe in. He is not the shale industry’s public enemy No. 1; that is really stupid. After driving the price of oil down 65% with overleveraged oversupply, and now with hundreds of billions of dollars of debt it can barely manage, the shale oil industry is its own worse enemy.

      1. Yeah, I respect his opinion, too. Doesn’t mean I have to agree completely.

      2. Mike.

        Keep in mind, the 2017 SEC numbers utilize the average 2017 WTI oil price, less discounts. So, one could argue that PUD should be higher now, given the current WTI price.

        However, because those guys are again in such a frenzy, they are shooting themselves in the foot. They are selling oil for $10-15 less per BO due to no pipes and well costs are skyrocketing due to demand for all services, labor shortage, and suddenly $3-3.50 per gallon for diesel, which power the thousands of trucks needed to drill and compelete just ONE PB shale well.

        As sellers of low to mid 30’s API light sweet, I am hopeful that our price will remain strong, even if the market is flooded with 45+ gravity.

        I really cannot understand these guys. OPM causes a lot of messed up stuff.

  33. As Rest of World Moves Towards Renewables, US Keeps Offering Exclusive Tax
    Breaks for Fossil Fuels

    http://www.truth-out.org/news/item/44391-as-rest-of-world-moves-towards-renewables-us-keeps-offering-exclusive-tax-breaks-for-fossil-fuels

    About a half decade ago, as the shale drilling rush was sweeping across
    the US, drillers needed upfront cash — and quick — to let them snap up
    acreage, drill and frack exploratory wells, and hone their skills at the
    horizontal drilling and hydraulic fracturing (fracking) that fueled an oil
    and gas boom.

    Bankers and financiers began attending shale industry conferences, marketing
    a clever idea. By dusting off an obscure part of the tax code, drillers and
    pipeline builders could attract a different class of investor than would
    usually look at a boom-and-bust prone industry, an investor hunting for
    stability and predictability. Form a Master Limited Partnership, or MLP,
    shale drillers and pipeline builders were advised, and you’ll be able to
    access that capital.

    The pitch for investors on MLPs was hard to resist: They “offer high yields
    and low taxes,” as the Financial Times described them in 2013. The tax
    benefits were a huge part of the draw, especially for wealthy investors (not
    just individuals, but also pension funds, which poured in billions).

    The biggest benefit: a tax loophole that lets MLPs dodge so-called “double
    taxation,” paid by regular corporations and much-hated by investors, in
    which tax is paid both by the corporation on earning money and by investors
    as personal income. No corporate income tax, more money to go around for
    everyone but the government.

    In 2000, MLPs had a total market value of less than $14 billion; by 2014,
    they had drawn over $500 billion in investments and some people were
    breathlessly predicting MLPs could wind up a trillion-dollar asset class.

    The problem now is, many MLPs may not even prove to be sound investments.

    Heavily tilted towards pipeline companies, MLPs were often marketed to
    investors as running the “toll booths” on the shale highway. Investors
    were advised: Don’t be the one who funds the risky fracking company; be
    the one who charges a tiny percent for every barrel of oil or million
    cubic feet (mcf) of natural gas those frackers pump. MLPs had the
    potential to become the “primary capital provider” for the infrastructure
    required for the shale rush, analysts predicted

    And when MLPs go bad, they carry a double-punch, as many investors found
    out in 2016 when oil prices crashed. Their tax benefits reverse, and
    investors face both losses and a climbing tax bill at the same time. That
    happened the first time shale MLPs suffered a major crash in 2015-2016, as
    falling oil prices caused many investors to flee.

    Now, John Dizard, columnist for the Financial Times who presciently warned
    about the shale bubble back in 2010, is pointing to evidence of an “oil
    and gas infrastructure bubble” that he says is bursting for a whole new
    reason — even as oil prices have begun to creep higher.

    “Dry wells? Your problem,” he warned in an April 13 column. “That fate has
    just arrived for the pipes and plants connected to some of the first great
    shale-gas plays in Barnett, Woodford, and Haynesville. In September, Wells
    Fargo analysts estimated that four pipelines serving the original boom
    areas would be re-contracted for much lower volumes.”

    3. The headline is a bit misleading. I think the important point there is that expensive infrastructure was built but turned out to have only a short shelf life and the investors didn’t do as well as they expected. EF, Niobrara and Bakken might look similar in a year or so; Marcellus, Utica and Permian maybe as well – bigger plays but also more infrastructure.

  34. Economic growth seems to be strong at the moment

    The J.P.Morgan Global Manufacturing PMI – posted 53.5 in April, up from March’s six-month low of 53.3. The headline PMI has signalled expansion in each of the past 26 months.
    (J.P.Morgan & IHS Markit with ISM and IFPSM)

    2018-05-13 (Argus Media) Opec president and UAE energy minister al-Mazrouei says global oil demand in 2018 is to be “much healthier” than Opec was expecting.

  36. OPEC, citing secondary sources, says its April oil output rose 12,000 b/day m/m to 31.93 million b/day
    Production tables: https://pbs.twimg.com/media/DdJy-HDWkAAJhLm.jpg
    OPEC forecasts global oil demand to rise 1.65 million b/day this year (previously 1.63 million b/day)
    OPEC sees 2018 non-OPEC supply growing by 1.72 million b/day (prev. forecast 1.71 million b/day); but says U.S. shale output growth increasingly facing logistical constraints
    Production forecast countries chart https://pbs.twimg.com/media/DdJ4cWCWsAEDZ-t.jpg
    OPEC says OECD oil inventories declined in March to stand 9 mln barrels above latest 5-year average
    OECD commercial oil stocks https://pbs.twimg.com/media/DdJzEDmVQAARGi0.jpg
    Non-OPEC Capex chart: https://pbs.twimg.com/media/DdJrwjQXUAAyST2.jpg

    2. I don’t know, but I guess that if it’s the same as the forecast from the EIA STEO then it’s without NGLs

      Short-Term Energy Outlook, May 2018.
      2018 Annual Growth (million barrels per day)
      Crude oil +1.367
      Natural gas plant liquids +0.554

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