Non-OPEC Mid-size Oil Producers

A Guest Post by George Kaplan

This post covers recent C&C production and future prospects, with a bit on gas, for several mid-size non-OPEC producers. A few have been omitted (e.g. Canada, Kazakhstan, Egypt, UK) for no particular reasons other than lack of time or anything much to say, but may be covered in the future. Many of the countries here have held a bumpy plateau over the last twelve to eighteen months. For most this has come after a period of decline, and some are showing signs that decline might be starting again. Brazil has been on a plateau after a period of increase, and may be about to renew that growth. There is a general theme that oil discoveries and developments are drying up and most of the countries are looking more to gas, but with the current gas glut looking like it might end up worse than the 2014/15 oil glut that strategy may prove difficult in the near term.


Brazil production peaked in March and has been on a plateau since (data below is through July, there should have been an August update but ANP aren’t very consistent in release dates). They have had several large FPSOs offline for maintenance (generally their FPSOs don’t have the best availability and they have had recent common mode failure issues with the high pressure gas risers, though I don’t know if this is a direct cause of the recent turnarounds). The Campos fields’ average water cut seems to be accelerating, which might also be contributing to a plateau rather than allowing a new peak.

All the new production growth is coming from the Santos basin. PetroBras production contributes about 82% to the total, but gradually falling as the new Santos production is partly foreign owned, e.g. by Shell – one reason they bought BG, and may fall faster now as PetroBras are trying to divest older fields. Their figures come out quicker than ANP and they report a new record in August, but falling slightly in September and October. They have bought the Libra extended test production on-line this month which will add production, and give some indication of future expectations.


There are ten new, large FPSOs due through 2021, and a couple of others possible, which would altogether add about 1.5 mmbpd extra nameplate. However the overall decline rate now indicates they need about three major new projects per year just to maintain plateau, and if the Campos FPSOs’ performance is repeated then the earliest Santos facilities should start to decline this year or next, and can go quite quickly.


Data from: ANP and PetroBras.


Mexico had a big drop in September production because of hurricanes and planned turnarounds, which has mostly been recovered, but they still continue on a general decline, losing an average of about 15 kbpd C&C per month from August to October (10% y-o-y drop from October 2016). With KMZ showing more signs that it might be coming off plateau this may accelerate (i.e. Ku field looks to have recent gas breakthrough and overall y-o-y decline is up to 1.9%). Abkatun-A2 is due on stream in 2019 (a replacement for a previous platform lost to an explosion and with 60 kbpd nameplate) and there were some recent significant discoveries that should add production in 2021 or so provided the appraisal drilling is successful. There have also been some onshore discoveries that could be brought on-line quickly, but Pemex just seems to keep on losing money so CAPEX funding could be a problem.



Data from: Pemex.


Norway data is through September. They are in slight decline this year, which has accelerated recently because the Goliat platform is being held offline for safety reasons. Gina Krog (60 kbpd nameplate) is ramping up and Maria (40 kbpd) started this month. The other recent start-ups are showing fairly early and relatively steep decline. There’s no new oil due in 2018 but about 140 kbpd in 2019 (in particular Martin Linge and Oda) and then more than 300 kbpd to start ramping up in 2020 when Johan Sverdrup comes on-line. Martin Linge has had problems and this month Total sold its stake to Statoil, who take over operatorship.



Data from: NPD Fact Pages.


Colombia is holding a plateau that will allow them to meet this year’s target of 840 kbpd. There isn’t much else immediately in prospect but plans for more offshore drilling, which has so far been disappointing, and shale deveelopment.


Data from: Colombia Ministry of Mines.


China has had some success in arresting their decline rate, but have a lot of ageing fields which use various EOR methods and only a few, smaller, offshore fields in development. There’s quite a bit of exploration activity in the South China Sea.


Data from: National Bureau of Statistics of China.


Most Azerbaijan oil production comes from the BP operated offshore Azeri-Chirag-Gunashi facilities, and it is declining pretty much in line with the original production application for that development. There isn’t much additional oil in the pipeline but Shah Deniz II (also BP), a large gas field has just started and will add about 50 kbpd condensate, and a similar Total project, Absheron, is in early engineering and due to start-up in 2021.


Data from: SOCAR.

Selected Other Mid-size Producers


All the producers shown are oil importers except Oman, with Indonesia, Vietnam, Thailand and Malaysia switching from exporters in the last fifteen years and India and Australia showing rising import rates in the same period.

Data from: Jodi, EIA, IEA and OPEC.


Oman has a nice new data and statistics government website but seems to have forgotten to employ anybody to keep it updated, so there’s no production data there after May. They also stopped reporting to Jodi last year but, as with all countries I’ve looked at, EIA estimates look pretty good. They have been meeting their commitments to NOPEC cuts and holding at 970 kbpd. It’s possible, however, that this cut is hiding a peak in C&C production, as they redeveloped some pretty mature and declining, heavy oil fields starting about ten years ago using various EOR methods, including miscible gas, chemical and steam injection projects, and those gains were obviously fading before the cuts. They have some new gas developments, e.g. the Khazzan tight gas project for BP at 200 kboed started in September, but no major oil developments, and nothing big on the cards (Yibal Khuff is a small field at 10 kbpd due in 2020).


India is holding a plateau, but never seem to meet monthly targets. They don’t have much new oil production in development (one platform at 75 kbpd due in 2020, and some smaller shallow and heavy oil facilities) and seem to be switching over to concentrate on gas, like a few other countries.


Australian oil production is in terminal decline. A large proportion of their production is condensate, which has been holding steady, so all the drop is in the crude, which is falling at about 15% per year. A small offshore development, Greater Enfield at 12 kbpd, is due in 2019, but they have potential for natural gas both offshore and onshore (with tight gas and coal bed methane).


Data from: Australian Petroleum Statistics, Commonwealth of Australia 2017.


Vietnam oil production is in terminal decline at aroud 8 to 10% per year, and gas production may have peaked this year. The Ca Rong Do project (a tension leg wellhead platform and chartered FPSO at 30 kbpd) is due in 2020. I haven’t heard much about new exploration but there has been a dispute with China in the South China Sea, which is supposed to have been rectified and may open up some offshore prospects.


Thailand is the smallest of the producers shown and has held a plateau for eight or nine years at just above 200 kbpd. It doesn’t have much in prospect for new developments and exploration has been a disappointment recently.


Malaysia has high quality, light, sweet oil (its Tapis grade is among the priciest) and is a large LNG exporter, though gas production looks like it may be plateauing. C&C production has increased from a low in 2015 but is now again in decline with nothing major due for oil after Malikai completes ramp-up this year (60 kpbd, Shell operator), but some smaller gas developments. Almost all discoveries since 2012 have been gas or gas-condensate. There are prospects for deep-water exploration and EOR on some of the mature fields, but these probably need much higher oil prices.


Indonesia had Banya Urip extension, large ExxonMobil oil project, ramp-up last year but is now back in decline. There are some small oil tie-backs due in 2019 at Natuna. The government has promised to attract $200 billion investment to try to stop its production declines, for both oil and gas (in which it has been a major producer but peaking in 2001). However so far there hasn’t been much to show for this. East Natuna is a huge gas field development ($40 billion estimate) that ExxonMobil recently pulled out of saying it wasn’t commercial in current conditions. Masela (Abadi) is another multi-billion project for LNG, much delayed but possibly now in pre-FEED with Shell and Inpex. Ande Ande Lumut is a heavy oil development that looked likely to go ahead but the operator has now down graded the resources from 2P to contingent. Other prospects are mostly gas. The small gas-condensate field, Madura BD at 110 mmscfd and 6 kbpd condensate, started up in August.

Off Topic Finish – USGS Undiscovered Conventional Resources

I posted these charts as comments on a previous thread and made a bit of a mess of them. They show USGS estimates for global, undiscovered, conventional oil (or actually all liquids) and gas by area and region, from a 2012 analysis: Supporting Data for the U.S. Geological Survey 2012 World Assessment of Undiscovered Oil and Gas Resources, by U.S. Geological Survey World Conventional Resources Assessment Team. It’s worth keeping in mind that these are technically recoverable numbers, i.e. at any cost (for example it’s been suggested – not by the USGS – that a lot more oil in the North Sea could be recovered if coffer dams were built north and south and the sea completely drained so that wells could be drilled all over and produced without needing expensive offshore facilities). These are probabilities and with a wide range from P5 to P95 in all the numbers (nominally there is a non-zero chance that nothing will be found) and I don’t know if the USGS goes back and re-does the analyses as actual data becomes available. On some of their assessments there is a constraint the the resources are expected to be discovered within thirty years, but I don’t think that can be the case here and couldn’t find a statement either way in the briefing reports.

The largest expected resources from the USGS analysis are in offshore regions, and mostly in deep water or other inhospitable areas. The P50 cases (i.e. most likely) given are about 400 Gb oil offshore, 200 Gb onshore and 550 Gboe gas offshore, 200 Gboe onshore.


Recent discovery rates have been around 2 to 4 Gb per year for oil, and a bit more for gas, with each seemingly on a falling trend. Giant fields are rarely found now and average discovery sizes are below 50 mmboe, and also falling. Discovery success rates are also falling, down from about one in five wells to one in twelve to one in twenty in frontier areas (where many of the USGS resources are expected to be found). Therefore it might be expected to take well over a hundred years, thousands of wells and trillions of dollars to find the P50 resources, assuming a BAU trend could be continued. In fact fitting a geometric decline to recent years’ data and extrapolating would give only about 25 Gb total of future oil discoveries

Deep-water wells are expensive, probably over $100 million each, though slightly lower at the moment, but likely to increase quickly if activity picks up again (the deep water drillers have been burning the furniture or chucking stuff overboard to keep their ships running – and that includes scrapping many deep water rigs and laying off a lot of experienced staff). As an example of (currently) an extreme case: say twenty wells, including appraisals, per discovery, average of 25 mmbbls per oil discovery, and $100 million per offshore frontier well gives $800 billion expense to find 10 Gb. That is $80 per barrel that might not be paid out for fifteen or more years and does not include operations and development costs (which would be huge for small, isolated offshore fields). Such a scenario would not happen without oil at maybe $200 or $300 per barrel, and maybe EROI considerations make it impossible at any price. Of course extrapolating trends like this from fairly short ranges of stochastic data can make you look pretty stupid, even from just one or two outliers in the near future.

For more details on discovery successes see: 1) HSBC, Global oil supply: Will mature field declines drive the next supply crunch? 2) Rystad, Eyeing Beyond The Short-Term: Discoveries and Their Impact On The Oil Price 10 Years Down The Road. 3) IHS, Oil and gas discoveries dry up to lowest total for 60 years (FT report from February 2017). The image below is from the Rystad report: Rystad.

Usually there are more discoveries in the second half of the year, maybe because of the northern hemisphere summer or because E&Ps like good news for their end of year statements, but 2016 was different and I think this year will be the same and show continued decline. Operators tend to prioritise the best prospects, irrespective of what they think the oil prices will do, therefore every time a well is drilled, whether successful or not, the average chance of success in the pool of prospects declines, and that only changes if some attractive new leases become available, although a discovery will improve other near field prospects. It’s also worth noting that any large, good quality discoveries made recently, like Liza in Guyana or Zohr in Egypt, are almost immediately being fast tracked for development despite depressed oil and gas prices.

The number of wildcat (i.e. frontier exploration) wells has been trending down, and without much correlation to oil price but definitely accelerating since the recent price collapse, for the last twenty five years: for example 2009, following the recession, saw low shallow water activity but no fall in deep-water and a record number of wells for ultra-deep, probably because of new generation DP rigs becoming available, whereas all exploration continued to fall through the high price years from 2011 to 2014. At current trend there will be none drilled within ten to fifteen years (see the FT article referenced above), which suggests to me the E&Ps are running out of places they think there might be things worth discovering. Seismic can’t tell if oil is present but it can find the maximum likely unrisked resource (i.e. the size of the trap), and if that is below a commercial limit then there won’t be any drilling. Gas might be doing a bit better because, although it is significantly discounted against oil price, recently there have been some giant discoveries that can be developed economically, and that trend might continue, plus FLNG might open up some otherwise stranded, smaller prospects.


The chart below highlights some of the high profile basins. I decided on offshore or onshore designation depending on whether the USGS had more than 90% allowance for the basin in the respective location. These are not all the regions considered but include the ten top oil and gas estimates and a few other interesting ones. They are ordered by total, combined P5 estimates, but I’ve only shown the P50 numbers, so riskier areas, like Greenland, stand out.


Santos (Brazil), Mesopotamia (Iraq) and Zagros (Iran) are the three major possibilities for big oil finds (maybe also Arctic Alaska based on recent discoveries). Santos has had mixed lease interest and before that mixed exploration results. E&Ps are probably also waiting for the PetroBras Libra pilot project results. The West Central Coastal basin includes Kwanza province, which had high, and ultimately disappointing, prospects. Nile Delta Basin and Mozambique Coastal have had successful gas discoveries since the report. Guarija is offshore Colombia and has been a disappointment with a couple of dry wells and only gas in the others, though I think Anadarko are planning another well next year. East Barents Basins and Barents Sea indicate mostly gas and therefore it is maybe not surprising that Statoil and Lundin haven’t been successful in their oil exploration (not much gas either, and probably very difficult to develop should they find any). The Red Sea basin has been explored by Saudi and Kuwait, it has pre-salt possibilities, but no announced successes and a distinct waning of interest recently. Guyana-Suriname has had big discoveries by ExxonMobil/Hess. Senegal, I think, includes Mauritania, which Tullow just gave up on, but was the site of the biggest find by far this year: 15 tcf gas (2.5 Gboe) for BP/Kosmos. Campos and Foz do Amazonas, like Santos, are offshore Brazil and have had a fair bit of lease interest but there are ecological issues with the second one. South China Sea has had a border dispute, which might be settled now, and includes interest from Vietnam, Philippines, China and Malaysia.

USGS also show onshore resources by country: they have 12 Gb oil for China but I find it hard to believe that there is a part of that country that hasn’t been thoroughly drilled. For oil China is fourth after Iraq (42 Gb), Iran (13) and Russia (17); Saudi has 10 Gb, but like China that seems to have been thoroughly explored in all the likely spots, and USA 11 Gb. For natural gas onshore the top countries are Russia, Iran, Iraq, Brazil (a surprise to me) and USA.

Data from: USGS and Rystad.

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228 Responses to Non-OPEC Mid-size Oil Producers

  1. Pingback: Non-OPEC Mid-size Oil Producers –

  2. Dennis Coyne says:

    Hi George,

    Nice post.

    Did the USGS data come from the link below?

    Also a description of the summary at link below

    The undiscovered conventional resources in this study exclude the United States.

    The F50 estimate for conventional C+C for the World is 478 Gb, and the NGL F50 estimate is 139 Gb for a total C+C+NGL of 617 Gb, though given the uncertainty it should probably be 500, 100, and 600,or rounded to 2 significant digits at most (620, 480,140 Gb).

    I believe these USGS F50 estimates are likely to be too high by roughly a factor of 2 to 3.

    The F95 estimates of 200 Gb for C+C and 50 Gb for NGL seem more reasonable.

    I wonder if the USGS has a tendency to confound reserve growth with new discoveries.

    It seems to me there is a possibility that with high oil prices that reserve growth and discoveries (sometimes called cumulative discovery) might approach the F50 estimate if oil prices were sustained at over $200/b, but it is doubtful that those oil prices (in 2016 US$) could be sustained for more than 5 years.

    For that reason I would expect discoveries plus reserve growth would be roughly 200-300 Gb for conventional C+C.

    • George Kaplan says:

      I wonder if the USGS has a tendency to confound reserve growth with new discoveries

      I don’t think so – they have a parameter in the Monte Carlo simulation which represents the proportion of an area that has been explored, so they are only considering new discoveries.

      Those links look correct, you can get to both from my link at the bottom as well.

      They exclude offshore mainland USA (and actually part of East Coast Canada I think) but not Alaska and they have onshore estimates listed for USA in the Country summary.

  3. George Kaplan says:

    There’s a new report on North Sea Decommissioning, which now includes Norway, Netherlands and Danish sectors:

    It is from the UK oil and gas trade body so everything is, and alsways will be, awesome.

  4. Energy News says:

    EIA Petroleum Status Report
    I guess that there must be a big error somewhere = Line 13 adjustment +576 kb/day

    Crude oil stocks down -3.4 million barrels plus SPR sale -2.4 million barrels

    The overall fuel stock level stayed about the same,
    Increased +6.3 million barrels = gasoline & distillate
    Decreased -6.7 million barrels = unfinished oils & residual fuel oil

    Saxo Banks collection of charts:
    YTD numbers by TFA
    J.Kemp (Reuters) always has a range of charts

    • Energy News says:

      The EIA-914 survey tomorrow,

      November 29, 2017 – Rystad Energy’s comprehensive well data for the United States shows that domestic oil production could pass 9.9 million barrels per day in December 2017. For comparison, the EIA estimates oil production will reach just 9.72 million barrels per day in its September Short-Term Energy Outlook (STEO). Tomorrow, November 30, the EIA will publish a new EIA-914 survey and petroleum supply monthly report (PSM) with the actual oil production for September 2017. The preliminary estimate by the EIA is 9.34 million barrels per day. Any significant adjustment to this estimate will be the first indication of who is right on where U.S. oil production is heading towards year-end.

  5. coffeeguyzz says:

    Mr. Kaplan
    I appreciate the time and effort you contribute to this site and feel we all can benefit from your input.

    One question regarding offshore …
    With the continuing advances of seismic, is there any accepted appraisal of what may exist and be recoverable in the sub salt/pre salt rock?
    The enormous expense in actually drilling to “find out” would make the most swashbuckling of wildcatters blanche.
    However, if successful efforts are made, it may encourage additional activity.

    On a completely separate topic, and one of highest relevancy to the renewable energy stance, 8 hours from this posting, wholesale electricity prices in Victoria and South Australia are expected to hit the $14,000/Mwh ALL afternoon.
    While I cannot identify the cause, the weather appears to be cloudy with temperatures in the low 90s (F).
    In addition, the quarterly futures contracts for electricity for 1st Qtr 2108 are $173/ Mwh and $147/Mwh for SA and Victoria respectively.

    Folks, if you all are not familiar with what the above numbers represent, it broadcasts an unmitigated disaster for those regions as no modern society can remotely expect to function with energy costs so high.

    • George Kaplan says:

      I think recent seismic advances mean that pre and sub salt geology can be reasonably mapped, which wasn’t the case a few years ago, but I’d imagine it’s still not as good as seismic where there isn’t inteference from the salt. As far as knowing if there is anything there, you still have to drill, and even if something is found it still doesn’t look like recovery factors are very well understood. I think the few pre-salt fields in GoM aren’t doing as well as expected and have pretty low recoveries, the Libra extended test FPSO ,which just started producing, has been specifically developed as a low cost option as the operators didn’t want to commit a lot of money without knowing what to expect, and the pre-salt in Kwanza (a mirror in Angola for Santos) has turned out to be a dead duck after some high initial expectations.

    • Dennis Coyne says:

      Hi Coffeeguyz,

      Spot prices at that level suggest, nobody will be buying electricity. Those that need the electricity will have secured supply at a lower price, for others I imagine if electricity is in short supply there will be demand pricing and people will turn down their thermostats during the high price period, not do their laundry, etc and cut back on electricity use.

      In any case Australian electricity prices have historically been high, not sure why. I imagine they have some cheap coal, though perhaps transport is expensive.

      • coffeeguyzz says:

        I’ve been trying to understand this whole electricity business, yet – after a year of study – I am still very much a neophyte.
        This is especially true regarding Australia as their structure is a little bit different from US.
        However, that 14k/Mwh will most definitely be factored into the end users’ bills, but since it may only be a (now) 2 hour block of useage, the lower aggregate pricing over a 3 month billing period is what will be charged.
        (Up your way, couple weeks back, ISO wholesale spiked over $1,000/Mwh for 20 minutes. I think Millstone 3 being down and Pilgrim having hiccups is what forced the oil burners to kick in. That 1,000 bucks will be blended in to your aggregate 30 day billing cycle).

        What I think is happening right this moment in OZ is the AEMO encouraging a bunch of smaller generators to fire up and that pricing – momentarily at $200 – is succeeding at extra generation.
        The ridiculous $14k window has shrunk from 6 hours down to 2 1/2 this late afternoon.
        As it is spot pricing in 5 minute intervals, it could drop further.
        No matter how you look at it, it’s a heck of a way to do business … and summer has yet to kick in.

        • Eulenspiegel says:

          That happens all the time if you have not enough pumped storage / other medium time storage facility.

          It was before the solar boom here in Germany, too. Always at noon, where peak demand was.

          It’s now history, at noon are the prices lowest now.

          • coffeeguyzz says:


            Your observation addresses one of the key components of renewables … intermittency, which is often conflated with unreliability.
            I am not too familiar with either the European electrical market nor the German in particular, but my understanding is the build out of several coal burners might be stabilizing the market some?
            Hydro backup offers a great deal of reliability, but – like everything else – many issues there.

        • Dennis Coyne says:

          Hi coffeeguyzz,

          Where I live the rate is about $160/MWhr for residential service and has been at that level for many years. As my usage at home is only 0.3 MWhr per month, this amounts to about $48 per month which is pretty affordable in my view.

          I believe the average residential rate in the US is about $120/MWhr and considerably less for industrial users (maybe $50/MWhr).

          Note that industrial users do not buy on the spot market, they have a fixed contract and in my state the Electric Utilities are separate from the power producers (they just transmit and distribute (T+D) the power) the suppliers are separate. The T+D is about $80/MWhr and the supply is about $80/MWhr.

          The spikes in price are matched by many hours of low prices and it is the average price that matters to the consumer.

          I checked wholesale prices for New England from 2014 to 2017 (weighted average for the year) using data from EIA (prices in $/MWhr)

          2014, 85.28
          2015, 55.03
          2016, 36.50
          2017, 34.74

          New England data is from the Massachusetts hub

          which is labelled “Nepool MH DA LMP Peak”
          in the spreadsheets with historical data.

          Since 2014 average annual wholesale electricity prices have been decreasing in New England, based on the historical data for weighted average annual prices.

          Note that I took the weighted average daily price and multiplied by daily volume for each day for total dollars for the year, then divided by total volume of MWhr for the year to get a weighted annual average price in $/MWhr for each year from 2014 to 2017 for the Massachusetts Electricity Hub.

          If you are looking for evidence that the expansion of renewables increases electricity prices, you will not find it in New England from 2014 to 2017.

          Although not much of an increase in non-hydro renewable power in New England with an increase from 8% in 2000 to 10% in 2016, most of the change has been a shut down of coal (18% to 2%) and oil fired (22% to 1%) power plants and an increase in natural gas power plants (15% to 49%) over the 2000 to 2016 period. See page 12 of report linked below

          • coffeeguyzz says:

            Your numbers are accurate, but your take on it might be a little off.
            This past August, New England’s wholesale cost was about the lowest ever, primarily due to temperate weather and the huge shift to natgas fueled electric generation.

            My above post referencing $173/$147 for SA and Vic futures electric contract price for 1st quarter ’18 is the WHOLESALE price.
            Retail runs 4 to 5 times higher depending upon local conditions.
            I’ll follow up a bit more in a couple hours.

            • Dennis Coyne says:

              Hi Coffeguyzz,

              The numbers I reported for New England are also wholesale prices for 2014 to 2017.

              I doubt retail prices are 4 to 5 times higher, typically transmission and distribution would be no more than $10US per MWhr and remember that the Australian dollar is about 80% of the US dollar so $147AU is $117US, based on the report linked below


              Retail residential prices are about $240US per MWhr so roughly double the wholesale rate.

              In California rates are about $230US per MWhr, so similar to Australia.

            • Ian H says:

              Coffee, are you aware of the Beetaloo Basin shale in the Northern Territories that Origin Energy and Impex have high hopes for?.
              Exploitation/exploration has been stopped because of environmental concerns over fracking – currently the eco types have managed to impose a moratorium, and apparently convince most people of the massive negative impacts that such a major new industry might have on the existing cattle stations etc. The NT has a population density a fraction that of Siberia.


              • coffeeguyzz says:

                Thanks for the heads up on that.
                While I know little of the Australian hydrocarbon market – upstream in particular – I just did a bunch of speedreading and found both Origin’s and Falcon’s sites to have some informative technical and operational information.

                Bearing in mind I am using incomplete ‘internet’ data …
                Citigroup sez 100 Tcf recoverable.
                Origen sez 61 Tcf OGIP in their 2,000 km area, with 6.6 Tcf recoverable (little more than 1 year Pennsylvania output).
                Falcon sez 464 Tcf OGIP (a lot).
                Stacked play.
                Depth of Amungee well under 5,000′ – relatively shallow. Marcellus runs 6/8,500′.
                Amungee well had 11 stages, flowed 63 MMcf over 57 days with 2,000 feet of lateral frac’d..
                That is impressive for a very early stage test well.
                Comparisons to North West Shelf gas resources could be positive if certain factors are applied …
                Logistics, especially water.
                With China’s Fuling, Argentina’s Dead Cow, and the Permian all dealing with water issues, intense efforts on many fronts are continuously being made to overcome this matter.
                Takeaway pipe might be somewhat accessible.
                Contamination of aquifers should not be an issue at that depth, but I am too ignorant of the geology to say.
                Bottom line, if a widespread cooperative effort were made (good luck with that), this area could economically provide total domestic Australia for many decades in an optimistic, but doable, scenario.

                In a slightly more possible view, AGL’s proposed FSRU off Melbourne will be importing LNG from West Virginia, much to the chagrin of the domestic producers.
                (The vulnerability of the Gladstone enterprise is far more vulnerable than may be obvious as it relies upon CSG for supply).

                Lottsa moving parts.
                Will do more checking later.

                • Ian H says:

                  Thanks for your input on the Beetaloo , there was a fracking ban – an enquiry was held, a precis of the scientific conclusions , published today, is to the effect that with proper safeguards fracking is safe. A social impact report is to follow in March. The area has a low population density – a tenth that of Siberia(IIRC) – with little apart from a few cattle stations to provide employment. The whole exploration effort is stalled awaiting a political decision on fracking.

                  I understand it is the oldest potential gas field on the planet, 1,600 million year old rock.

                  The numbers you cite are for one shale, as you say there’s a stacked play. Need a lot more wells to define the plays, find sweet spots etc.

                  A gas pipeline runs across the basin, there are plans for a capacity increase (if needed).

                  But where would the water come from?. There are cute ideas such as gas powered atmospheric water recovery systems:

                  Gas would seem a cheap fix for Ozzy problems of expensive non dispatchable renewables damaging the economy.

          • coffeeguyzz says:

            Renewable generation in NE has certainly not boosted prices directly as they play such a minimal role.
            (The folks in Rhode Island who just got hit with large increases may beg to differ).

            What HAS been a major impact is the staunch resistance to 2 new gas pipelines to assure both reliability and affordability for decades to come.

            If you are checking out that much detail in your neck of the woods (which I think is great), track down the new gas plants opening in Salem Harbor and Bridgeport, along with the one in RI.
            Check out how much juice Pilgrim puts out and mind that next winter will be its last.

            You have 4.5 billion cubic feet of gas heading your way every day, (thanks, in part, to the much-contested AIM expansion).
            Keep an eye out how the UK responds in the coming weeks to the predicted brutal cold snap and imagine your neighbors facing a similar situation with scant fuel to both heat and light.

            Dennis, I applaud your diligence in delving into these issues as they are important to us all.

            • Dennis Coyne says:

              Hi Coffeeguyzz,

              The pipelines were rejected based on Massachusetts law by the Massachusetts Supreme Court. It the Massachusetts legislature believes there is a problem the Law can be changed.

              Note that I am not a Massachusetts resident so have little say in this matter.

              I wonder if the Commerce Clause could be used to invalidate the Mass decision, I am not a lawyer.

              Other states may be depending on the Gas, I imagine it could take a different route and avoid Massachusetts so that New England states North and South of New England could get enough Gas.

              I imagine Connecticut and Rhode Island may be able to get plenty of Gas from New York. A line could probably go across Vermont and New Hampshire to Maine from New York.

              I don’t know what has been planned.

            • George Kaplan says:

              New England got most of the gas from the Nova Scotia gas fields, Sable and Deep Panuke, which are about to shut down, and the pipeline flows reversed so NS can get what it needs. Before the shale boom they were much more reliant on this gas, and not so long ago. Don’t know if that means much though.

            • George Kaplan says:

              We always have “coldest winter ever” warnings about this time of year, usually from the Daily Mail or Express and the nutjob denier who is Jeremy Corbyn’s brother. It’s pretty cold now but not too bad, and expected to be well above normal by next week. Spain and France are staying cold, and Norway is really cold so maybe the jet stream has split.

              (Wrong thread delete if needed)

    • Longtimber says:

      VIC Does show an order of magnitude+ spike on the 5 MIN timeslice round 17:00.
      It’s Summer so it looks like they need a bit more west facing PV and/or some demand management.
      With overcentralized fossilized Grids, Fractional % shortfall and it’s Armageddon time domain.
      Is the Australia grid truly deregulated? If so it would bring diversified supplies online as needed. Not much Power traded here. – 10% of Texas Peak Demand. Can you imagine what future prices would be without PV? Australia exports what % of their coal? Guess China needs it more?

      • coffeeguyzz says:

        Just before 17:00 yesterday, Vic hit over $2,000 and SA over $10,000 Mwh before prices plummeted.
        Somewhat coincident with that, the AEMO folks did a market intervention with a RERT announcement, which – best as I understand – prompted the backup gas peaker in Tasmania to fire up and pull ol’ Vic’s butt out of a crack.

        The situation in Australia is still a bit of a mystery to me as it seems to be mostly free market with a bit of remaining vertical integration with some producers still in the retail segment.
        In addition, somewhat similar to the US, is the different fuel sources for generation … coal, gas, (no nukes), or the wind and sun.
        Somewhat clouding the issue is the widespread emplacement of rooftop solar.

        The intense political polarization seems to play a large role in the current state of affairs.

  6. Rockman's Ghost says:

    George/Coffee – It’s been almost 10 years since I was in the DW GOM game. At that time I was on contract at Devon as a well site pore pressure analyst. My last well was going to be truly historic. It was goin to be the shallowest salt penetration of any subsalt well…600′. It was going to penetrate more salt section then any other well…22,000’+ of salt before it came out into the rock. It might also be the deepest well in the western hemisphere…35,000’+. Apparent as we entered the potential productive section the structure was as mapped. Unfortunately not only no hydrocarbons but no show indicating that any had migrated thru that section. The well was P&A before reaching PTD.

    I wasn’t working as a geophysicist at the time but have done so for about 30 years in the GOM Basin. And had watched the development of seismic HCI’s…Hydrocarbon Indicators…since my early days at Mobil Oil in the 70’s. Not entirely sure but while subsalt structural mapping had developed to a fairly accurate degree the data content was not sufficient to do the HCI magic. And it can be truly magical. In the mid 80’s in a shallow gas trend in Texas I hit 23 out of 25 wildcats. And of the two I missed I could prove one due to a misspoted line and suspected the other was also. The magical part: this was in a trend of small stratigraphic traps with a subsurface mapping success rate of 5% to 10% at most. Having worked HCI’s offshore it was the proverbial shooting fish in a barrel. And no competition…at first. The small independents that played that trend couldn’t spell geophysicist let alone bought seismic data.

    • SouthLaGeo says:

      RG – what was the deepwater prospect you mentioned above?
      Subsalt data quality has not gotten to the level where HCIs work, but not all of that is due to the overlaying salt – some is due to the rock properties because of the reservoir depths and the low GOR of a lot of the oils. Fortunately, at least in the more successful GOM subsalt trends, the stratigraphy is fairly forgiving. We aren’t pursing highly channelized reservoirs, like the shallow Texas gas trend you mention above. Rather, the depositional systems are either sheet sands, or highly amalgamated channels systems (which can behave a lot like sheet sands).

      • Rockman's Ghost says:

        SLGeo – Sorry to be such a tease but I would rather not say. It’s been 10 years but I try to still honor my Confidentiality Agreement. Not that I haven’t pushed the limits already. But if you have access to the public data base just search for a very deep dry hole drilled by Devon around that time. Drilling about 22,000′ of salt should make it stand out. If it helps Chevron took over ops not too long afterwards. I just don’t want to mention the lease and well name publicly.

        When my new company started chasing deep NG in onshore S La. after I left Devon we were pushing data content well beyond reasonable limits. Extreme data reprocessing to try to bring out NG amplitude data to generate viable HCI events. Worked sometimes but often failed badly. For one thing migration became very tricky. We drilled a dry hole on one deep HCI: all shale. But we remigrated the data and proposed a sidetrack. Our partner dropped out. And we found 200′ of pay in a sand 600′ away from the dry hole. Worked well enough when gas was $5+/mcf. But when prices fell we dropped the program entirely. One of the reasons my owner took a chance on my crazy hz redevelopment idea: we had $200 million to spend and almost no where to put it.

        • SouthLaGeo says:

          Can’t blame me for trying!
          If, and when, NG prices get over, say $5-6 /mcf, I wonder how aggressively the onshore/shallow GOM deep gas play will be pursued. I think there are a lot of undrilled prospects around, and, at least offshore, high quality 3D volumes that image features as deep as 3500′ or so below many of the collapsed salt canopies.

  7. Watcher says:

    Didn’t see projected ratios of C&C + NGL. How much of each.

    BOE doesn’t keep the society functioning. Only BO.

  8. George Kaplan says:

    Has gone kaput?

  9. I supervised reservoir management teams expected to deliver a “technical resource” estimate. Unfortunately we had very vague guidelines, and I found colleagues in other companies were apparently just as lost as we were.

    So I gave them an informal guidance and suggested they prepare rough estimates assuming oil prices were triple our “official” price deck. This was used to extend well and field life, lay out very rough and conceptual EOR and infill projects, and develop marginal areas where per well recovery wasn’t justified.

    As Denis points out, if one goes wide open its possible to assume really high figures based on nonsensical approaches.

    What we found when we were assuming the triple price deck was that we could increase “reserves” but the rates were low because we had logistics and reservoir performance limits. This means stacking technical reserves on top of proved plus probable reserves doesn’t really increase rates that much, it mostly keeps production steady for a decade or so, followed by a gentler decline for over 50 years.

  10. Energy News says:

    Potential production increases in 2018, I’m not sure about this as I’ve not heard that increases could be this high from any of the other forecasters. And there is never any mention of production declines in any of these forecasts…

    JBC – Even without more shale, the oil market faces an increase of more than 2 million bpd crude supply from producers outside OPEC – more than projected demand growth, says JBC
    (The easiest bit to understand is the 2018 Y-o-Y section on the RHS)

    • George Kaplan says:

      It does just say “additions from new crude stream” rather than “net”, but that’s not definitive either way I guess, especially as it has one negative point. But there’s no way the North Sea is going to add 400,000 bpd net next year.
      (Why are 2016 and 2017 included – was this a prediction made in 2015?)

      • Energy News says:

        Yes it would make sense if it was an old one from 2015. Reuters tweets these research notes and so I don’t know anything about them, other than saying that Reuters have always been very reliable.

  11. Energy News says:

    ClipperData, Nov 30th, OPEC crude exports are closing out November at their lowest monthly level since mid-2016
    Chart on Twitter
    ClipperData Blog:

    Chart on Twitter:

  12. Energy News says:

    Not sure if this will interest anyone, just looking at JODI crude oil imports and seasonality. No real surprise, it matches seasonal refinery intake and products demand. Demand usually decreases in January more than imports causing the yearly inventory builds.

  13. Energy News says:

    OPEC – This is a fairly good summary of the news that I’ve been reading about the OPEC meeting today…

    Headlines this morning gives the impression that all are now on-board for extending the cuts to the end of 2018. Reading in more detail however shows that it is not at all yet a done deal. And in addition it does not say whether the cuts will be maintained at current level all to the end of 2018. Specifically it seems like there is going to be an option to review and revise strategy at the next meeting in June. I.e. “maintain cuts if needed, but only if needed”. Russian producers are deeply concerned about the end-game. How to wind down the cuts without risking to crash the oil price. As such a sensible outcome in our eyes would be to wind down the cuts gradually through seasonal demand strength in H2-18. The cutters probably do not want to surprise the market positively risking firing up the oil price yet more at the same time as Rystad Energy is calling US crude oil production to hit 9.9 mb/d end of 2017 while also the US oil rig count has started to rise.

    • Energy News says:

      The OPEC meeting has ended
      – no specific plan to review output at the June meeting.
      – quotas for Libya and Nigeria – the two countries’ production to be at 2017 level.

  14. George Kaplan says:

    The UK oil and gas authority published the 2016 reserve assessment at the end of October. They don’t seem to be following the same methods as the old ministry department did (which I found difficult enough to follow) in how they differentiate between C&C, associated gas, dry gas and NGL. I think they are presenting data based on total reserves in oil fields (which would include associated gas) and total reserves in gas fields (including condensate and NGL), but might be wrong. Either way their conclusions:

    To date, a total of 43.5 billion boe has been produced from the UK and UK Continental Shelf (UKCS).
    The OGA estimates that UK reserves are approximately 5.7 billion boe (probable) and these alone, based on current production forecasts and not taking into account potential future exploration successes, have the capacity to sustain production for at least the next two decades.
    However, there is a significant opportunity to add to these reserves by maturing the UK’s considerable contingent resources. The OGA estimates there are 7.4 billion boe of discovered undeveloped resources. Much of this resource is in mature developed areas and under consideration for development. This will require substantial investment in new field developments and incremental projects.
    Replacement of proven and probable reserves remains a concern. In 2016 approximately 600 million boe were produced however only 80 million boe of contingent resources were matured to reserves.
    Exploration success in 2016 helped add 210 million boe to the contingent resources.
    The OGA’s current estimate of prospective (undiscovered) resources is 6 billion boe, with a range from 1.9 billion boe (lower estimate) to 9.2 billion boe (upper estimate).
    Taking account of this range of possibilities for prospective resources, together with the range of discovered reserves and contingent resources shown in the report, the current best estimate of remaining recoverable hydrocarbon resources from the UKCS is in the range 10 to 20 billion boe.

    The key curves, below, show remaining 2P reserves are falling, and in fact there was a slight downward revision for total discovered 2P for both, though this may only reflect timing of some developments including some impact of prices so the downward revisions might come back in the future.

    I think the statement “have the capacity to sustain production for at least the next two decades” is a bit dodgy – I think they mean production would decline to zero over that time, but the implication of the word sustain is that a plateau would be held (production is about 0.6 Gboe per year, and 2P reserves 5.7).

    • Watcher says:

      “The OGA estimates there are 7.4 billion boe of discovered undeveloped resources. ”

      Got a problem with this. Just 3 years ago at $120/barrel, this stuff wasn’t getting investment. Why not?

      • George Kaplan says:

        Maybe it needs $300 per barrel, or maybe there were better opportunities and the industry only had/has a fixed capacity for development spending per year, or other.

      • Eulenspiegel says:

        When you produce 600 million barrel / year this isn’t much – not everyone is a shale producer trying to produce everything in 1 year. Most conventional oil companies plan for longer horizonts.

        Other thing: Expensive Infrastructure is only for x barrel / day – you only drill to replace declines – until you discover something really big new.

  15. Longtimber says:

    The Internet like Fossil Fuels is a good example of Inertia locking out evolution. So many things are Broke like IPv4, DNS. Solutions have been ready in waiting for over a Decade. but what me worry. Like Buying a Truck without securing a fuel supply. Implementing DNS_SEC would end much attack nonsense.

    What a Gas – PeakOil as sooo fake news
    “By 2025, the growth in American oil production will equal that achieved by Saudi Arabia at the height of its expansion, and increases in natural gas will surpass those of the former Soviet Union, the agency said in its annual World Energy Outlook. The boom will turn the U.S., still among the biggest oil importers, into a net exporter of fossil fuels.”

  16. Energy News says:

    EIA 914 Survey – U.S. crude oil production for September, 9,481 (thousand barrels per day)

    • daniel says:

      quite something. Rystadt might be up to something here (see post further up). Weekly averages for september were 9,330. I wonder if the hurricanes were playing havoc with the data, since Auguet was 9,495 on the weeklies and 9,191 on the monthly.

      • shallow sand says:

        I suspect if US increase from August to September continues on pace, we have seen the high for WTI for 2017, absent a shock (ie Venezuela for example).

        Too bad, $55-65 WTI, we barely knew ye!

        • Energy News says:

          I guess US exports are keeping US inventories down and $WTI above $50 at the moment

          Bloomberg – U.S. net oil imports, including crude and refined products, last week dropped to just 1.77 million barrels a day, the lowest level in data going back to 1990, the EIA reported Wed.

        • Dennis Coyne says:

          Hi shallow sand,

          If US output continues its 623 kb/d annual increase and OPEC remains flat then demand will outrun supply unless other non-OPEC nations (Brazil and Canada) can more than offset declines elsewhere. Demand is expected to go up by about 1.2 Mb/d, so if the US increase remains steady and the rest of the World doesn’t increase production by more than 600 kb/d and the demand forecast is ok, then prices might stay where they are today.

          A supply disruption somewhere (Venezuela, Libya, Nigeria, or Iraq are all possibilities) might lead to shortages and a price spike.

          Always impossible to know, a fall in prices would tend to reduce output eventually.

    • Guym says:

      Texas production per the 914 is 3,574. No comment.

      • Dennis Coyne says:

        Hi Guym,

        The ratio of 914 survey to drilling info data from April 2015 to May 2017 was an average of 0.902. If we assume this remains near that level for July to September, we get 3435 kb/d, 3337 kb/d and 3524 kb/d respectively. The EIA estimates are about 40 to 50 kb/d too high relative to drilling info from April 2017 to June 2017 and also about 50 kb/d higher than the 914 survey divided by 0.902 for July to Sept 2017.

        My best guess is drilling info estimate up to June 2017 and then 914 survey divided by 0.902 from July 2017 to Sept 2017.

        EIA 914 report at link below

        • Dennis Coyne says:

          For US C+C from July 2016 to Sept 2017 the average increase has been 623 kb/d per year (52 kb/d each month). This is in line with the estimate of the former CEO of EOG (Papa?) for annual increases in US output through 2020.

        • Guym says:

          How do you think this compares to your most recent post?

          • Guym says:

            Which is more correct, in your opinion? The 3119 average you stated in your last post, or the 3524 amount you just posted above? There is a 400k difference. If we used Dean’s numbers, the EIA is over by more than 500k barrels a day.

            • Dennis Coyne says:

              Hi Guym,

              The last post was based on RRC data and the Sept data was probably less complete than usual. The 914 survey uses the same companies as previous months and for most of the previous months from April 2015 to May 2017 the 914 survey averaged 90.2% of the reported drilling info data, note that the difference between drilling info and the 914 survey was about 325 kb/d.

              In order for my previous estimate to be correct, the other 10% of output would have fallen to negative 75 kb/d.

              The Sept estimate in my previous post was not very good, because I had no 914 estimate to go on. Even the drilling info data is not complete for the most recent few months, so recent months are difficult to estimate for Texas.

              Perhaps Hurricane Harvey made conditions difficult for timely reporting in September, or perhaps the 914 survey is inaccurate.

              Note that I also have updated drilling info data through August,
              as can be seen on the chart the 914 survey data when corrected by adding the 9.8% of missing output (from smaller companies not surveyed by the EIA) matches drilling info data fairly well through June 2017 (this corrected estimate is actually somewhat lower than the drilling info data from July 2016 to May 2017).

              The July drilling info data is likely incomplete, August is quite incomplete and there is no Sept drilling info data reported by the EIA.

              • Guym says:

                Drilled wells are reported by the RRC. Although, the RRC data may lag, they usually tell the trend.
                May 593 oil completions
                June 510
                July 437
                aug. 401
                Sep. 318
                Oct. 257
                I threw oct in, just so you could see there probably wasn’tmuch of a carryover into oct from sep. Texas RRC production is trending down, although Harvey complicated things. So, I find it difficult to grasp how so few completions can generate such an upswing in production. This time, I would guess that the 914 is amiss. Maybe, in between, but surely closer to going down, than up.
                And I was asking which one you thought was closer, not being critical of you. I said Harvey was going to make a mess out of telling what’s actually happened, and it did. I still am guessing that Oct RRC data will tell a clearer picture, but after this mess, who knows. Usually, hurricanes just mess up offshore production.

                • Dennis Coyne says:

                  Hi Guym,

                  Sorry didn’t mean to sound defensive.

                  I would say the more recent estimate is likely to be better.

                  I do not know why completions are not in sync with output.

                  Here is one possible explanation. In August production was lower due to Harvey and in September output recovered because there may have been fewer days with production shut in.

                  In addition maybe pressure built up while wells were shut in and when they were brought online in early Sept there was a boost in output.

                  Total speculation on my part.

                  Maybe Mike, SoLaGeo, shallow sand, George, or Fernando can comment because they all know more than me (you may as well as a royalty owner).

                  • Guym says:

                    I think I will stick with the RRC trend, and question EIA data. If they popped the plug, and it sprayed all over, then it would be in RRC data and some royalty holder would have been paid on it. Trend started down before August, as corresponding declines in completions would indicate. In line with drilling info to as far as posted. Few more months and we can reach a mutual conclusion. That’s September, if any companies received that big of boost in September, it would have been on some company’s third quarter report. I haven’t seen anything that big.

                  • Dennis Coyne says:

                    Hi Guym,

                    If output is reported quarterly and output went down in August and then up in Sept, wouldn’t it be a wash in reported quarterly results?

                    It seems from the reporting that Harvey had a bigger effect in August, so reduced output in August and then recovery in September makes sense. Note also that from April through July output was increasing based on the drilling info data once we correct for incomplete data.

                    You can throw out the 914 data if you choose, but an assumption that the 914 survey represents 90% of output usually gets you pretty close (sometimes a bit too low and sometimes a bit too high, but usually about within 40 kb/d of the final RRC data). The range is about 88% to 92% since Jan 2015 (ratio of 914 survey to drilling info estimate excluding the most recent 3 months reported by drilling info as covered in the Nov 30 EIA comparison oil statistics.

              • Dennis Coyne says:

                Hi Guym,

                Were your leases output higher in Sept than in August?

                In the estimate below I show the drilling info data reported by the EIA on Oct 31, 2017 and Nov 30, 2017, the numbers on the chart are the difference between the two data sets in July 2017 (302 kb/d) and June 2017 (85 kb/d). The difference in May 2017 was 20 kb/d and for the 5 months previous the difference was less than 10 kb/d (which I ignore).

                A corrected estimate for November DI data adds these differences to the most recent 3 months reported (20, 85, and 302 added to June, July, and August Nov DI data).
                We do not Drilling info data for Sept so I use the reported 914 survey result, plus the difference between the Nov DI corrected August 2017 estimate and the August 914 survey (337 kb/d).

                Note that for the “Nov DI corrected” estimate only the September estimate depends on the 914 survey result in this case. The Jan 2016 to August 2017 estimate uses only drilling info data for the estimate (and the drilling info data comes from the RRC).

                Essentially it is an RRC estimate that includes the pending lease data.

                Also the way I did the Sept estimate assumes no increase or decrease in the output of the 10% of output from smaller producers. If output from that 10% went down in Sept the actual output would be lower and if it went up output would be higher, that’s why I asked what happened on your leases in Sept (very small sample, but perhaps indicative), maybe Mike could chime in on whether his company’s output was up or down in Sept vs August (which would give us a larger sample).

                As I don’t live in Texas, I don’t know, was the impact from Harvey on oil output bigger in August or September? (I thought it was August, but as you know I am often wrong).

                As is always the case, clicking on the chart will give a larger view.

                • Guym says:

                  I’m not sure of anything, now. Too vast of a disparity between EIA data and RRC data for Sept. I am pretty sure, it is going down, and not up. Completed wells for November will be out soon, and Oct preliminary will be out in a little over two weeks. I will post both, and we can revisit this conversation then. For EIA to be correct, a shitpot of people would not have received royalties from the stuff that was not posted to RRC. That’s not out of the realm of probability theory, but pretty far fetched. As RRC data is online, and basically machine driven, I am more apt to consider the paper shuffling by various estimates by producers to be more apt to mistakes. I received some strangely deficient gas production numbers for Sept., but the oil production looked in line. No, I just found October’s, and gas is dropping on three wells. Probably put them on pumps, soon. Happened on the first two after 9 months, and pumps picked up both oil and gas. Anything is possible.

                  • Dennis Coyne says:

                    Hi Guym,

                    Not sure why you doubt the 914 survey, they have been doing the same thing since Jan 2015, the Drilling info data comes from the RRC (online query plus pending lease data), even that data is incomplete for 3 to 4 months. The 914 survey was 3179 kb/d in Sept. From April 2015 to May 2017 the percentage of output (DI estimate) covered by the 914 survey was in the range from 88.65% to 91.75%.

                    So the September output might range from 3465 to 3606 kb/d. The average 914/DI over the April 2015 to May 2017 period was 90.18% which suggests 3525 kb/d for Sept 2017. In 3 months we can revisit and see if my guess is correct, I would say for Sept 2017 TX C+C it should be 3525+/-60 kb/d.

                  • Heinrich Leopold says:

                    I wonder if the magic production increase is correlated with the release of oil from the SPR. That would be a reasonable explanation as RRC does not have to report the oil released from the SPR. Releasing oil from the SPR is certainly a supply increase, yet is in my view not’oil production’.

  17. Boomer II says:

    I’ve been following the Alaska drilling news coverage. Seems like the GOP wants to open up the ANWR to claim it will bring in money to help balance the budget. But how many companies would actually bid and then drill?

    • Watcher says:

      The ANWR has not been subjected to exploratory drilling.

      Do that. If there is nothing there there won’t be any political fight. If there’s something there, then fight about it.

      It’s never made sense to fight without knowing what’s there.

      • Boomer II says:

        Isn’t the plan to sell the leases first and then discover if there is sufficient oil to drill?

        The US has a habit of leaving money on the table when it sells leases. But then again, if your goal is to practically give away access to public lands rather than raise money, then letting companies have it on the cheap is the plan.

    • George Kaplan says:

      Every time a new article comes out about this the decline rate goes up one percentage point. While shale is important it’s worth keeping in mind the other influences: 1) More in fill drilling to maintain plateaus and as other prospects became more expensive (it gives a bit more capture, but a much steeper decline. 2) More horizotal wells and MRC completions – they give the oil earlier than vertical wells but it drops off a cliff once the water comes. 3) More deepwater – high initial flows fast decline. 4) Smaller fields and more tie backs – same as 3. 5) Cut backs in brownfield development and planned maintenance after the price crash will be showing up 2 or 3 years later in lower availability and overall declines. 6) I think there must be some impact from so many facilities reaching end of life and needing redevelopment or getting scrapped and therefore not being available of near field discoveries – without building new plant the old plant hits one limit after another (oil, water, gas, power, total liquids, wells, manifolds etc.)

      I think I’ve said all this before, so sorry about that.

      • Watcher says:

        One wonders how global decline rate is computed.

        If it is per well then the sheer number of shale wells is going to amplify global decline rate. Hmmm. Seems unlikely there is well data available for the entire world so I suppose that’s not how it’s done.

        Per field? One would think the data for that is similarly not available.

        This would suggest global decline rate is an outright guess on the part of whoever offers up a number.

        • Dennis Coyne says:

          Hi Watcher,

          I believe they weight the wells (or fields) by their output in determining decline rate.

      • shallow sand says:

        George and Daniel. The article Daniel posted is a primary reason we are hangining on.

        Peak demand now seems assumed as a fact that is right around the corner, due to electrification of transportation.

        I’m not so sure peak demand is right around the corner. I don’t think the entire worldwide fleet of transportation autos can be subsidized by pension funds and crowd funding, like Tesla currently is. Tesla’s should have much higher pricing, which would also mean lower demand and slower transition.

        Plus, the average vehicle on US highways is 11 years old? Our kids are driving 2008 and 2011, wife insists on continuing to drive her 2007. I just traded a year ago, but I have to put many miles on per year for work. However, I will put on a lot of miles. I traded a 2011 for a 2017.

        In the field we have 6 trucks, 4 ATV’s one tank truck, one single drum rig, one double drum rig, one testing truck, one back hoe, one medium sized tractor for mowing and grading lease roads and one small bucket truck. All of those will be driven until the wheels fall off.

        I have read a lot about the Tesla semi unveiling. Seems like a lot of questions. One commenter on SA indicated over three and a half acres of brand new, highly efficient and prime location solar panels would be needed per truck. Another claimed that the electricity needed to “Mega charge” two semis side by side would equal the usage of almost 4,000 US households.

        I drive interstates in the US. So Tesla is going to deliver all those WalMart and Amazon orders cross country soon? In addition to the electricity demand issues, Tesla doesn’t even have a factory built to build Semis.

        Not trying to cause a “non-oil” post, but I think “peak demand” due to electrification of the fleet could cause what I think WILL cause peak demand, peak supply plus extremely high prices, when fleet electrification takes a lot longer than assumed.

        • daniel says:

          Hi ShallowSand. article re electricity demand for EV…

          • Longtimber says:

            So there appears to be on the Order of 100 gWh Annual Global Battery manufacturing capacity. A BOE is 1.7 mWh. So Global Annual Battery Capacity = 170,000 BOE “capacity wise”. That equals 465 BOE DAILY. Hell, that’s a single well. Is my Math close? As a Solar Installer, we have Installed TWO Powerwalls. They are not useful since they are incompatible by design with most everything, but it “macht nichts” since they won’t exist for years if Tesla wants to profit from car sales. So, eChem production ramp up is everything. Granted a Battery can be charged thousands of cycles, but the capacity has to exist.


            Much Lower cost kWh’s from PV = Energy game changer.
            One Energy company gets the reality of kWh time Shifting.
            * PV by Day – Storage by Night *
            was the motto of an investor presentation. Li Battery tech makes this possible. Li eChem thrives independently of the charge environment. ie. State of Charge / x.x volts per cell @Dusk does not dictate cell life economics. So a kWh of Battery can leverage a lot of Daily PV kWh’s even in autonomous applications

        • George Kaplan says:

          I know very little about EVs, but the transition that everybody hopes is going to go peacefully, rapidly and globally seems a couple of orders of magnitude more complicated than has ever before been achieved.

          • Dennis Coyne says:

            Hi George,

            Consider that the manufacturing capacity for personal vehicles exists already, if we switch to EVs we switch to something easier to manufacture (electric motors instead if IC engines) with the possible exception of the batteries. Can the manufacture of lithium ion batteries be ramped up? It is not clear to me that this a problem that cannot be overcome. Installing charging stations? Relatively easy, no more difficult than petrol stations.

            Obviously it will not happen overnight and does not need to as it will take 10 to 20 years to replace the existing IC fleet of personal vehicles.

            Perhaps it will not go smoothly, I have never assumed a smooth path with no bumps in the road, only that it is technically possible.

            • George Kaplan says:

              It was more switching to a grid that could support all those EVs I was talking about, and more the world that is not the USA.

        • Eulenspiegel says:

          One question: Without oil, how many acres would it need to support a semi by agriculture fuel?

          I know in the 19th century about a quarter to a third of all farmland was used for feeding horses – transportation use.

          Here in Europe Biodiesel is from rape, about 450 litres / acre in a year.

          So it depends how long you drive – you’ll need one or 2 acres per fill up. Over the whole year it’s a lot.

          Diesel used to grow up the rape isn’t calculated in.

          • shallow sand says:

            2.8 gallons of ethanol from a bushel of corn. In a good year USA average yield per acre is 170. So 476 gallons of ethanol per acre.

            Corn is barely profitable at current prices and US. Ethanol production using corn is likely preventing a 1980s style farm failure, maybe one even worse.

            But US farmland is selling as if corn was selling for $5 per bushel or more.

            $10,000 acre or more for Class A soils in Illinois and Iowa. Payout is over 50 years when income and real estate taxes are included.

            Consider: 80 acres x $10,000.

            Cash rent $250 per acre x $80 = $20,000.

            Real estate taxes = $3,000

            $20,000 – $3,000 = $17,000 net income annually.

            $17,000 x .25 Federal and state income tax (estimated, could be higher or lower) = $4,250.

            $800,000/$12,750 = 63 year payout.

            The wildcard, of course, is inflation. Every buyer of farmland presently must believe in his or her lifetime there will be major league inflation.

            • OFM says:

              Hi SS,

              Nobody ever seems to really understand what controls the price of farmland. My own opinion is no better or worse than that of anybody else I guess. It’s that nothing controls it, and yet EVERYTHING controls it.

              The expectation of inflation sure as hell plays a big role. The expectation of future REAL price increases, by which I mean increases in CONSTANT money plays a big role.

              These two can be very different, as for example consider that if you can borrow money at four percent, and break even on operations, and inflation is running at six percent annually across the board, with land inflating at six percent or MORE as well……..

              After a few years, you can sell out, pay off any loan balance, and realize a substantial cash profit. That profit can still be a hefty one even though it’s in the form of depreciated money.

              Sometimes farmers can get purchase money at ridiculously low rates. And REAL farmers, by which I mean anybody who actually FARMS, who lives on or near his property, and does some farming work personally, on a regular basis, are seldom EVER interested in selling. They’re ALMOST ALWAYS interested in buying though. It’s more a lifestyle as a business or profession. For a farmer to move off his home place is about the same order of change for him as it is for a city guy to move to a totally different city, leaving behind everything in the way of community, friends and maybe even family as well.

              Then there’s the fear factor. Personally I believe the price of gold short to medium term is determined more by fear than any other factor, with the price shooting up when enough people get afraid that having most or all of their assets in the form of paper or real estate is dangerous, and so they rush out and buy some gold, creating a sellers market.

              When things calm down, when the fear subsides, they realize that gold is a lousy investment in a stable environment, lol, and sell it, and the price falls again.

              One thing is for sure of course, which is that they ain’t making any more land, except by filling in a hole in the water at extraordinary expense occasionally……. ESPECIALLY first class farm land.

              Barring the crash of BAU, good farmland is sure to go up on average over time.

              Politics plays a big role. If there’s an oil crisis, and the price of ethanol shoots way up, and government mandates the use of more ethanol, or biodiesel, the price of farmland will go up.

              Farmers have extraordinary political power, in relation to our actual numbers, because farm state senators and representatives can and do cut deals with congress critters from other states. I could go on all day.

              There’s absolutely no way in hell that we will ever support anything even remotely resembling today’s business as usual by producing biofuels of any sort using any existing farming technology.

              But given time enough, and enough change in society,in the way we live, and enough progress in vehicle technology, we could possibly produce enough biofuel to squeak along, for instance if every body drives a super mini two seat fore and aft plug in hybrid car, with a lawn mower sized engine in it so the driver can take it an occasional longer trip. This assumes that trains make huge comeback and or that trucks can be electrified as well as cars.

              It’s a hell of a lot easier in principle to justify an electric truck that will be used all day, almost every day, and maybe even two or three shifts a day, than it is to justify buying an electric car that will be used an hour a day on average.

            • Dennis Coyne says:

              Note that when I say renewables, I am not talking about biofuels.

              That’s a dumb approach in my view which causes more problems than it solves.

              I am talking about primarily wind and solar, with maybe some pumped hydro backup, widely dispersed and interconnected with an HVDC grid. Some nuclear may be good to have as backup, but it should be next generation that shuts itself down safely when the power goes out. If that is impossible to accomplish, nuclear should just be shut down altogether once solar and wind ramp up to the point that 95% reliability can be maintained. Critical uses such as hospitals will have battery backup and possibly biofuel generator backup.

        • Dennis Coyne says:

          Hi Shallow sand,

          I imagine there is plenty of money to be made producing EVs.

          Once the big boys like Toyota, VW, Ford, etc join the fray things will turn very quickly, batteries may be the bottleneck, but I imagine Panasonic, LG, Duracell and other battery manufacturers will be up to the task.

          Any battery company not heavily invested in getting into supplying the EV industry is not interested in making money.

          Lots of naysayers posting articles on Tesla to support their short positions.

          They will be naked soon. 🙂

          • Hightrekker says:

            Tesla – lost $619 million in Q3 – delivered only 3,590 vehicles in November in the US, down 18% from a year ago.
            3,590 vehicles amounts to a market share of only 0.26%, of the 1,393,010 new cars and trucks sold in the US in November. Porsche outsold Tesla by 55% (5,555 new vehicles).

            They really need to get the Model 3 act together.

            Tesla has put electric vehicles on the map. That was a huge feat.

            • Dennis Coyne says:

              Agree model 3 is important. They will get it sorted and it will sell big imo. I think 2019 sales will be over 500,000. In 2018 maybe 250,000.

        • Boomer II says:

          China and India have reasons to promote a transition away from fossil fuels. Three main reasons:

          1. Reduce dependence on fossil fuel countries.
          2. Clean up their atmospheres.
          3. An economic development opportunity. Beat out the US in the next generation of energy production and transportation.

          While the transition from oil hasn’t fully happened yet, developing countries and the rising global powers would be foolish not to pursue it.

        • Wake says:

          interesting post shallow, thanks. electric will make a lot more sense for lighter duty delivery and local fleet vehicles. it is not clear when, lots of OEMs are launching in 2019 so maybe a few years after that it will be competitive

          The tesla truck doesn’t seem to make sense, infrastructure is an issue, route flexibility is an issue. but I think Elon Musk cares about carbon output and is targeting high fuel use vehicles, whether t makes sense to the rest of us or not

          • Dennis Coyne says:

            Tesla semi makes sense for short haul routes. Long haul can move to trains which can be electrified.

  18. George Kaplan says:

    Despite poor results this year (one minor oil find at Kayak) and pretty expensive wells Statoil is going to concentrate even more on the Barents Sea next year. I think that says as much about options and prospects worldwide as it does about Statoil’s current reserve problems.

    • Watcher says:

      Wow. Behold the power of the Norwegian Sovereign Wealth Fund. Profit is not a requirement.

      • George Kaplan says:

        Statoil isn’t controlled by the wealth fund, I’m not even sure if the fund would be allowed to hold shares in it.

      • daniel says:

        Statoil “wasting” money and the wealth fund are not 100% linked. 78% of the exploration wells are paid by the taxpayer, so that stings slightly, but makes it much easier to take a risk for them 🙂

  19. Mike says:

    I’ve long held the position that OPEC and Russia have become, out of necessity, good students of the US shale oil phenomena; they are aware production has peaked in both the Bakken and Eagle Ford plays, that D&C costs have gone up associated with much larger frac’s just to maintain well productivity in the Permian, of well communication issues, of sweet spot saturation and of increasing GOR and obvious signs of depletion. They know these plays are getting gassier and that there in no place to put that gas anymore other than up a flare stack. They have their reservoir engineers analyze realized production trends and understand, fully, exaggerated EUR’s. They have access to SEC filings and totally comprehend how unprofitable the US shale oil industry is, how totally dependent it is on credit, the massive amount of debt the shale oil industry is burdened with, of the revenue required to service that debt and that the entire scheme is totally dependent on federal stimulus that will add to our national debt and ultimately make America economically weaker. They get it. They are not stupid.

    Various OPEC princes and oil czars in Russia have recently stated, publically, they expect US shale oil to grow for a while longer but they are no longer concerned about the threat that US LTO presents to their market share and long term oil markets. So, extending production cuts for another 9 months makes perfect sense. WTI prices will likely trade in a higher range, accordingly, and the shale oil industry will borrow more money and/or defer more legacy debt, bring more rigs out of the barn and incrementally increase the rate of unconventional shale extraction in the US. The rest of the oil producing world understand this; hell any 6th grader can understand it. OPEC is giving America just enough rope to hang itself from a hydrocarbon standpoint. America has no long term energy policy whatsoever; it has drank the shale abundance kool-aid and the powers that be are set on draining the barrel in America as fast as it can, and selling it to China. Then OPEC and the rest of the non-OPEC producing world, including Russia, will have America by the ying-yang once again.

    Its a perfect plan, and it IS working.

    • Dennis Coyne says:

      Hi Mike,

      I agree US LTO output might rise to 6.5 to 7.5 Mb/d at most even if WTI goes to $120/b, in my view if oil prices rise to over $100/b then we might get to about 7 Mb/d in 2020 with a peak of 7.5 Mb/d by 2023 followed by rapid decline (peak decline rate about 2030). Lower prices (say less than $75/b) are likely to result in a peak of 6 Mb/d or less. Of course I always assume oil prices will be higher in the future than proves to be the case. If prices remain about $55-$65/b we may see a plateau of US LTO at about 5 Mb/d for 10 years with gradual decline (relative to the 7.5 Mb/d scenario) after 2027.

      No doubt your view would be that such scenarios are absurdly optimistic, thoughts?

      Oh and was your company’s C+C output higher in September than in August (if you can reveal that)?

      • Mike says:

        Dennis, Art sent me this EIA to real oil chart this morning…

        • Guym says:

          Glad I’m not the only one scratching my head over EIA recent reports. Wonder which cartoon figure is Perry?

        • Dennis Coyne says:

          Hi Mike,

          The EIA’s estimate may be 50-75 kb/d too high. If one looks at how drilling info data changes month to month, the most recent two datasets show that the most recent month is 300 kb/d too low, the next most recent 85 kb/d too low and the month before that 20 kb/d too low. Prior to that it’s close enough (within 10 kb/d). I am talking about drilling info data. If the November dataset is corrected by adding 20, 85, and 300 to June, July and August drilling info data, you get a decent estimate through August 2017. For Sept 2017 take the 914 survey result and add the difference between the corrected August 2017 drilling info data (add 85 kb/d) and the August 914 survey data, this is roughly 3510 kb/d.

          Data at

          Looking back at 7 older data sets of DI data (stored on my computer), the most recent month tends to be about 292 kb/d too low and the next most recent month about 50 kb/d too low. Based on this, my revised estimate for Sept 2017 is about 3500 kb/d, Aug and July are also slightly lower (by 10 kb/d for August, by 35 kb/d for July, and by 20 kb/d for June).

        • Dennis Coyne says:

          Chart below shows the various drilling info datasets, the date (month and year) is the date the EIA published the data, and the most recent month for each data set is three months earlier. For example the Nov17 DI data set’s most recent DI data point is August 2017. The average correction factor is 290 kb/d for the most recent month (August for the Nov dataset) and 32 kb/d for the next most recent month (July 2017 for the Nov dataset), earlier months are within 15 kb/d of the correct value on average (for the data I have saved).

          Corrected Nov17 DI data for July and August are 3417 and 3335 kb/d respectively and my Sept estimate based on the 914 survey estimate is 3502 kb/d. Typically the final Texas estimate has been about 323 kb/d higher than the 914 survey on average from May 2015 to June 2017 (range 275 to 371 kb/d).

        • Dennis Coyne says:

          Texas C+C in kb/d, my best guess, with the data up to June 2017 being the drilling info data.

          July and August 2017 are “corrected” and September 2017 is based on 914 survey. July 2017 +/- 25 kb/d, August 2017 +/- 50 kb/d, and Sept 2017+/- 100 kb/d for error estimate.

          • Guym says:

            Here is another hypothesis, someone higher up in EIA is trying to hold on to their job. After making ridiculous assumptions on the future and current growth, they are trying to wait until some anticipated growth covers the error enough so that revisions won’t be so apparent. If you look at Texas production per district in September, it indicates a definite drop in the Permian. Permian was far, far away from Harvey. All of the trends in Texas, indicates production is, or should be dropping. The 914 for September is a flight of fancy.

            • Dennis coyne says:

              Hi Guym,

              Data can always be incorrect. As Mike often points out, we need patience. After July 2017 it’s guesswork. It will be interesting to see next month’s data especially if you can figure out the pending data file. It looks complicated.
              We may have to wait until the end of December.

            • Dennis Coyne says:

              Hi Guym,

              I thought there were some refinery shut downs during Harvey. I would think that the flow of oil out of the Permian could have been affected and perhaps some wells needed to be choked back to reduce output. Maybe guys in the business could comment, I am just speculating. We know that output was affected in the Eagle Ford in August. I don’t have drilling info data for the Permian basin, but the RRC data for August and Sept are not complete enough to draw conclusions. Where are the RRC headquarters? If they are in Houston, then perhaps the flooding affected the reporting of data throughout Texas and after a few months things will get sorted out.

              Nope the main office is in Austin and there are district offices all over the state (one for each district). You Texas guys know all this of course.

              I will just be patient and stop speculating.

              • Mike says:

                On the east side of Harvey’s path across Texas a lot of Eagle Ford wells were shut in. Additionally, end users (refineries) in severely impacted flood plains along the Gulf Coast were shut down completely for several weeks and this caused upstream shut-ins and significant curtailments as far away as the Permian. Dennis, you will please recall we had a conversation about this and I speculated that a lot of unconventional shale wells, once shut in, do not recover to original rates because of fracture closure, proppant embedment and a host of other down-hole reasons.

                Austin manages production reporting and when that reporting becomes public. Enno and I have been discussing recently that there are indeed some hiccups going on regarding production reporting that I cannot explain. I simply don’t know and have too many of my own problems to speculate about other people’s problems. Time will sort it out but I am not sure there will be too much to be learned from the why part of it.

                Its important to make guesses about the future, sure. As to a comment down-hole, it is actually less important to operators because we understand the volatility of product prices, can sometimes protect our near term future with hedging, and tend to work within 3 year payout frames, etc. With regard to the US shale oil industry, it doesn’t rely on price predictions to make budgets anyway. Prices don’t matter. The availability of other peoples money, credit limits, debt deferrals, maturities, loan covenants and upper managements reserve base compensations packages…do matter. Its pretty much ALL that matters based on the past.

                Read MIT’s actual report about over exaggerating the future of shale production in America. Speculating about oil prices is fruitless and that is not really the fix anyway. The shale industry is trapped like goats in a pen with debt. Depletion is real and we’re seeing the beginning of it, now, big time. I believe it was Deep Throat in All the Presidents Men that said…”follow the money.”

                • Dennis Coyne says:

                  Thanks Mike.

                  I will stick with my current guess of 3400-3600 kb/d for TX C+C output in Sept 2017. We will find out in a few months.

                  If prices are flat LTO will probably remain where it is (maybe a small 200 kb/d annual increase in US LTO output), higher prices ($75/b or more) would lead to higher output (maybe a 600kb/d annual increase). Eventually these companies will need to make money.

                  As Shallow sand says, they’re not Tesla, they are commodity producers.

  20. World C+C has been relatively flat for 2.5 years.

  21. Non-OPEC C+C appears to be declining.

    • Ovi says:

      Ron I have taken the same EIA data and removed Russia, US and Canada to see what the decline rate for the remaining Non -OPEC countries has been since 2004. It is 260 kb/d/yr.

      • Thanks, Ovi. Those three are now on a bumpy plateau. So it’s just a matter of time.

        • Dennis Coyne says:

          Hi Ron,

          Higher prices might lead to small increases in output from Canada, Brazil, US and Russia, OPEC might be able to increase a bit as well. I still like 2025 for the peak.

      • Stephen Hren says:

        Who has any serious upside potential? I would guess Iraq, Russia, USA, Brazil, Saudi maybe +1M/day each, about 5M/day max increase, or three years at 1.6M/day increase in demand.

        Who has the biggest downside? Wild ass guess of course but in general order I would say Venezuela first, then Libya, Iraq, Nigeria, Saudi Arabia (still expecting a massive collapse of Ghawar Canterell-style that takes 5M/day off market in a couple of years), or else political coup. Downside potential 1-20M/day off market.

        Then of course there is old fashioned depletion 5-10%/year until forever.

        • Dennis Coyne says:

          Hi Stephen,

          I would say US, Saudi, and Iraq might be able to increase by 2 Mb/d, also depletion is off set by new wells being drilled, that’s why non-OPEC less US, Russia and Canada is only declining by (based on Ovi’s chart) about 260/22000=1.2%/year. Be careful with depletion/decline.

          It is decline rates that have been estimated at 5-10%. Depletion is more difficult to measure, because the size of “the tank” changes as reserve estimates change over time, we don’t really have good estimates of depletion rates because resource estimates are very rough. World conventional C+C URR estimates are in the range of 2000 to 4000 Gb, with about 1250 Gb produced by the end of 2016, so 750 to 2750 Gb left to produce, call it 1750+/-1000Gb.

          Unconventional (USGS calls them “continuous”) resources add another 1000+/-500 Gb, but the bulk of these (750 +/-350 Gb) are oil sands in Canada and Venezuela, with the rest being LTO (250+/150 Gb).

          Those are my estimates based on the work of Miller et al (2014)

          and Mohr et al.(2015)

          • Stephen Hren says:

            Thanks, Dennis, I get the difference but I also appreciate your clarification. Main point is the oil and gas industry has the Sisyphean task of pushing a boulder uphill (worldwide C+C production) that is always wanting to accelerate downhill due to increasing overall field depletion rates. Especially as fewer resources have been dedicated to this struggle of late, the less likely it is to succeed.

            • Dennis Coyne says:

              Hi Stephen,

              I agree it will not be easy, and I also agree that my scenarios may be too optimistic. I try to look at both the pessimistic views of Laherrere and Campbell and the more optimistic view of the IEA, EIA, and USGS and figure reality will fall somewhere in the middle, but of course nobody really knows.

  22. Longtimber says:

    May international politics Trump market forces? MAGA US LNG to the rescue!
    As a Solar Installer, this is a wet – I mean dry – dream. Freeze m Yanks.

  23. Energy News says:

    New North American energy information website. (NACEI)
    Data, maps, and information from: U.S., Canada, and Mexico!/overview

  24. Watcher says:

    Anybody else notice that EIA has revised US oil production in 1970’s to be over 10 million barrels per day?

    • Guym says:

      That’s to include all that oil coming out of Washington DC, that was apparently omitted previously🤥

      • Dennis coyne says:

        Or EIA has updated to the latest data reported by the states which is now more complete.

    • Dennis Coyne says:

      US C+C trailing 12 month average output using EIA data from today. Peak 12 month period was from August 1970 to July 1971 at a 12 month average output of 9752.8 kb/d. The most recent trailing 12 month output was 9048 kb/d and the near term peak (12 months ending Nov 2015) was 9428 kb/d.

      • Hightrekker says:

        Kinda looks like Enron Accounting?

      • Dennis Coyne says:

        Hi Watcher,

        I have an old dataset on my computer saved on May 11, 2015, the data for Oct and Nov 1970 on those dates were (in kb/d)

        Oct-1970, 10013
        Nov-1970, 10044

        So for about the past 2 years and 7 months the reported monthly output for data from Jan 1920 to Dec 2004 has not changed.

        And for those that believe that the EIA estimates are always too high, here is the comparison of the Nov 2017 estimate with the May 2015 estimate for the period from Jan 2014 to Feb 2015 (last data point for the May 2015 dataset).

        In May 2015 the EIA estimate for Feb 2015 was 299 kb/d (3%) too low.

  25. Heinrich Leopold says:

    The RRC just published its October Drilling, Completion and Plugging summaries. Although permits are up considerably (green line in below chart) , completions are at record lows (blue line). These data do not suggest any material production outburst in September as recently reported by the EIA. My guess is the recent release of oil from the SPR has got something to do with the sudden supply increase.

    However, as releasing oil from the SPR counts for sure as more supply, it has nothing to do with oil production.

    • Guym says:

      The completion report for Oct was posted by Energy News an I almost a month ago. In several days November will be posted.

      • Heinrich Leopold says:

        The most important message of my post is that a September outburst of production is unlikely based on the current completion data.

    • Dennis Coyne says:

      Not every completion results in the same amount of oil production, the number of vertical wells drilled and completed has decreased while the number of horizontal wells drilled and completed has increased.

      The vertical wells on average are far less productive (for wells completed in the past 5 years in Texas) than horizontal wells. So looking at completion rates tells us very little, if we don’t know the ratio of vertical to horizontal wells.

      In any case, through June 2017 the drilling info data (which comes from the RRC) shows increasing output in Texas, beyond that we will have to wait a few months for more data (we should have a better handle on Sept 2017 output by the end of February (in about 3 months). Just the way it is.

      • Heinrich Leopold says:

        Dennis, and the ratio of horizontal vs vertical drilling is very unlikely to have changed much over the recent months. Most important is the total amount of wells completed and this is down by 50%from last year, which was anyway a very weak year. The most important message in my post is that an outburst of much higher production becomes very unlikely and the reason for this supply increase must come from somewhere else. And this is in my view the release of oil from the SPR. This link is just too compelling to be dismissed.

        • Dennis Coyne says:

          Hi Heinrich,

          Ignore August (due to the effects of Harvey) and output was only up 85 kb/d from the July level (based on my estimate). Output has been increasing most of the year (Jan through July) even though the completion rate has decreased.

          So over a 2 month period production was up about 42.5 kb/d each month.

          Why did output decrease in August? Let’s assume the Eagle Ford and Austin Chalk combined produce about 1000 kb/d and that they were shut down for 3 days due to the Hurricane, this would reduce output by about 99 kb/d in this simple example. When the Hurricane was over production recovered.

          Your speculation on the SPR is also wrong as that is simply a stock change.

          Supply= output produced + reductions in stock levels.

          The supply from the reduced stock level in the SPR does not affect production reported.

          You can assume the ratio of vertical to horizontal wells completed has not changed, I can assume the reverse, we don’t have the data on horizontal vs vertical completions so we don’t know who is correct.

          The main point is that the productivity of the average well completed can increase over time for many reasons (vertical vs horizontal, focus on sweet spots, amount of sand used in the frack, number of frack stages, and lateral length to name just a few). If productivity increases enough it can offset a decreased well completion rate.

          This would be the logical explanation that would coincide with the data we have.

    • Energy News says:

      I’m not sure what to think, these completion numbers are completely different. I’m just going to wait and see what happens. I remember AlexS saying that the numbers from TexasRRC are not revised. And so I guess that makes it more difficult to measure their accuracy.

      • Guym says:

        Not really sure what the story is on this chart. I have looked at a lot of completion data posted by RRC. Most of the producing wells that are decent, are posted in the current month of completion, or the following month. Though, when things were booming, some were over a month late. It appears that slow times in completions brings out the stuff that hasn’t been reported in six months to two years. I don’t think RRC counts these as completions. I haven’t seen any of these late postings contain anything but a dabble of oil. The stuff posted on RRC may be late, but meaningful. While, the consensus is that there are few dry holes in the shale, some may as well be considered dry holes. Does the EIA completions consider vertical wells?

        • Dennis Coyne says:

          Hi Guym,

          The way that chart is labelled, I think the completion data may be from the RRC.

          • Guym says:

            And the DPR is wells they have assumed to have been drilled, or what?

            • Dennis Coyne says:

              Hi Guym,

              I didn’t know the DPR had wells completed, I thought they had rigs.

              In any case the DPR is a bit of a mystery to me, I usually ignore it.

              Not sure about DPR, I was ignoring that line on the chart.

              Remember the Permian for the DPR includes New Mexico, so the comparison is not quite apples to apples.

              Ok also the DPR is Permian and Eagle Ford regions (both gas and oil) and RRC is all of Texas.

              • Dennis Coyne says:



                 Monthly completion activity is assessed by accessing the database for all wells that were completed after December 2013. To eliminate recompletions from our count, wells fracked multiple times are only counted once. Because the hydraulic fracturing data is reported to with a lag, estimates of well completions for recent months are based on weekly filings and may be updated over the course of several months.

                • Guym says:

                  Part of posting a completion on the RRC site goes through the frac focus system. They are promoting it. The frac focus information is used in part to identify problems in well water, which is why the RRC is interested in it. Frac focus charts would be adjusted per date, where RRC just counts it when it’s posted. It’s still trending down. EIA says they are estimating some current because of lags. You may ignore DPR data, which is to your credit. However, I think the DPR data is from whence all these wild ass estimations from the EIA come from.

                  • Dennis Coyne says:

                    Hi Guym,

                    The EIA projections are not great, though the DPR through Dec 2017 is probably only 50-150 kb/d too high. The EIA’s longer term estimates are based on the projections of economists rather than engineers and generally assume upward trends never end ( a very poor assumption) and that increased demand is always met with increased supply (another bad assumption).

                    I ignore those estimates.

                    Data from the past by the EIA (the monthly output estimates) are not as bad as many assume.

                    I compared the EIA estimate from Oct 2016 with the Nov 2017 estimate (data for comparison only through August 2016). All of the two data sets were within 0.5% of each other. Although during some periods the older EIA estimate was too high by as much as 0.44% (about 40 kb/d), that is not too bad in my opinion.

                    Note that this is similar to the difference between my estimate and the EIA estimate.

                    Also fracfocus revises their estimates, so if the DPR completion summary uses the data from frac focus it may be more accurate than the RRC “data” for completions (the monthly completion summaries), which are not revised (as far as I know).

                    Data on individual leases is eventually accurate and is revised, but rolling it up into a statewide estimate requires mad programming skills and perhaps Enno Peters has such data, I do not.

                    I looked at “first flow” (aka completion) data from Enno Peter’s for the most recent September data and compared with older data from 4 months ago.

                    It looks like the most recent 3 months of data are “incomplete” much like the drillinginfo data. Chart below shows horizontal oil well completion data from the Texas Permian and Eagle Ford using the two pages linked below (click on well status).



                    Remember the July to Sept data in the chart below is likely to be revised up in future months.

                    Click on chart for larger view if it’s too small.

            • Dennis Coyne says:

              For DPR completed oil and gas wells in Permian and Eagle Ford combined we have chart below.

              • Guym says:

                That’s an interesting chart on first flow. No doubt, it will be revised upwards, at least the past two months, maybe more. However, does it look like it is trending up?

                • Dennis Coyne says:

                  From July 2016 to June 2017, yes. The annual rate of increase has been 68 more completions per month. We will have to wait for a few months to figure out completion rates for July to Sept 2017.

                  Data in chart from (see post above) and is Texas horizontal oil completions in the Permian and Eagle Ford.

  26. Energy News says:

    Art Berman replied to this chart on Twitter…
    Potential production increases in 2018

    Art Berman
    This argument has been stated by Citi Research & others but depends on sanctioned projects delivering projected rates on schedule, things that rarely happen. Cut the volumes in half & I might believe it.
    Why do SLB, OPEC and Total disagree & believe supply will be tight?

    his replies page:
    Art Berman:

  27. Energy News says:

    Alberta Canada, total production (crude + condensates + bitumen) down a little more than -100 kb/day month/month. Production is almost flat compared to October 2016.
    Chart on Twitter:

    From the IEA Oil Market Report, world supply updated to October, OECD industry stocks updated to September
    Chart on Twitter:

    The backlog of barrels waiting offshore USA, updated to Friday December 1st
    The total is down only 1 million barrels from last Friday
    TankerTrackers –>
    Chart on Twitter:

    Malaysia – Sungai Linggi Port – barrels at anchor. A whole years worth of data – happy birthday data 🙂
    TankerTrackers –>
    Chart on Twitter:

  28. clueless says:

    Let’s just watch the price of oil and nothing else. I think that will tell everyone what is going on with respect to oil supply and demand. KISS – Keep It Simple S.

    • Em Butrus Partake says:

      Exactly clueless. So much energy and time is spent speculating, when in reality in this case it’s just much easier to stop the banter and wait to see what happens.

      • Boomer II says:

        From an energy policy point of view, it is necessary to make projections five, ten, or fifteen years down the road.

        Also, oil companies need to decide whether investing more money will pay for itself in the future.

        So it is necessary to speculate about the future,

        Even for infrastructure, like pipelines, you need to give some thought to future prices, supplies, and demand.

        • shallow sand says:

          Yes, I have found that all my thinking about the price of oil has caused it to move $0.00.

          I still reserve the right to whine about US shale, equally futile as it is.

          Those dopes crashed the price in 2014, kept it low throughout 2015 and 2016, then killed the early 2017 rally. I assume they will keep killing rallies, and making little to no profit, until the monster wells they love to power point about are pretty much drilled.

          How about just holding production flat for a couple years? It is surely better for shale r us to produce 250K BOEPD at $60+ WTI and $3.50 HH than to produce 325K BOEPD at sub $50 WTI and $2.50 HH?

          Maybe not. It seems no P/E ratio is better for the share prices of shale than 100+ P/E ratio. With negative P/E they can issue shares and decrease negative EPS, plus more easily spin the narrative, “We are tech!! We have to lose money to be cool!!”

          Wonder how the frac hits are going in the STACK? Blowing up 4,000’ vertical wells left and right. Is this happening elsewhere as they cram these 15-20,000+’ wells on 330’ spacing?

          • Dennis Coyne says:

            Hi shallow sand,

            Brent futures for March 2018 are still at about $62/b, WTI futures for Jan 2018 are at $58/b. So for now we are in your preferred $55-65/b band. The futures price deck stays above $55/b out to Jan 2019 for WTI and Brent stays above $59/b out to April 2019.

            I expect the increased exports from the US may reduce the Brent/WTI spread to the cost of transporting the LTO barrels from the Gulf coast to Europe (or wherever those exported barrels are going to be refined, Italy maybe?)

            As of Oct 2017 (using EIA estimates) US LTO output is 4840 kb/d and has increased at an annual rate of about 670 kb/d since Sept 2016 (4119 kb/d)

            • Dennis Coyne says:

              Chart below shows US LTO from Jan 2016 to Oct 2017, about 68% of the increased LTO output from Sept 2016 to Oct 2017 was from the Permian basin (486 of 719 kb/d increase).

            • shallow sand says:

              Dennis. We have thought some about hedging 2018. Looks like we could lock in $53 WTI floors for around $2 per barrel.

              I like floors better than SWAPS and Collars. Don’t have to give up any upside if the price spikes, but they are pricey sometimes.

              • Dennis Coyne says:

                Hi Shallow sand,

                I am pretty sure you know more than me about hedges, as I know nearly nothing.

                Floors sound better if I understand correctly, as my guess is that prices will go up, so you can get the high price, but have downside protection. Check with Mike, shoot me an email if you don’t have his address.

          • Heinrich Leopold says:

            shallow sand,

            In 2000 oil prices and especially natgas prices pricked the high tech bubble. This is what Wall Street wants to avoid to happen again. High energy costs drag out capital from consumers and the stock market. And the sums are huge. The world needs around 100 bn barrels of oil equivalent of primary energy each year. When the barrel costs USD 40 per barrel, the World spends USD 4 trillion per year. If this goes up to USD 60 per barrel the World spends USD 2 trillion more as the total spent for primary energy goes to USD 6 trn. These are large sums, which are missed somewhere else. So, energy has certainly the power to move the world. As oil has reached 60 per barrel, the Nasdaq gets already wobbly again. This is why the order for shale has been: cheap and abundant energy – whatever it takes. All the losses which have been occured so far are minor to the massive gains the Nasdaq made over the last years. It is just a question of time how long this can be sustained. However, for many this game has paid off so far.

            • Dennis Coyne says:

              Hi Heinrich,

              Global GDP was $75.5 trillion in 2016, about 29.5 Gb of C+C were produced. At $20/b difference in price between your example of $40/ and $60/b, this amounts to $0.589 trillion (20×29.5=589 billion). So in your example, this amounts to 0.78% (.59/75.5) of World GDP, not really Earth shattering in my view.

              Coal and natural gas trade at different prices than oil, so talk of Global Energy has to include the prices of that energy and the share of those different types of energy in the mix.

              So your 100 billion barrels of oil equivalent might be correct (I have not checked), but less than a third of that is crude plus condensate which is what is sold when a barrel of oil is bought and sold.

              If you want to include NGL in the story, each barrel of NGL has about 70% of the energy content of a barrel of crude, so the appropriate metric is barrels of oil equivalent (where every barrel has the same average energy content). By this measure World C+C+NGL output is about 31 Gb and the $20/b price increase causes an increase of 0.62 trillion dollars in spending or 0.82% of World GDP, again not really a big deal.

              • Heinrich Leopold says:

                Dennis, I referred to total primary energy including coal, which increased actually by 100% from last year. It is a rough calculation, yet in total it is correct. Primary energy is something we have to tribute to nature. Any other products or services are exchanged as if there is seller there is also a buyer. High energy costs are extremely dangerous for the economy as this set an inflationary spiral in motion as tributes to the nature are sunk costs. As Shale could succeed in producing more energy, it is increasingly clear that Shale cannot flood the world with cheap energy. Too many investors have been burned and too many companies went bankrupt. Cheap energy from Shale is simply unrealistic. It certainly helped the USD to strengthen, yet as Shale oil becomes increasingly gassy and decline rates are soaring, also the produced quantities are in doubt for the future.

                • Dennis Coyne says:

                  Hi Heinrich,

                  My point was simple, less than 30% of primary energy is crude plus condensate. For the other 70% the price of oil is of little relevance. Now if the average price of energy in $/barrel of oil equivalent(boe) increases by $20/boe, then your calculation would be correct. Perhaps that is what you meant, but it was not how I interpreted what you said.

                  My apologies, on re-reading your comment perhaps when you said “barrel” you thought boe was implied, I missed that.

                  In any case 2 trillion is 2.6% of World GDP, if that is the price, that’s what will be paid as energy is essential. Eventually other energy resources will be used as fossil fuel becomes more expensive. The economy will adjust. LTO in the US will probably peak around 2023 and may be in rapid decline by 2028 or so (US LTO decline will be about 4%/year or more). I doubt that fossil fuel energy will remain cheap and as the price increases it will be used more efficiently.

                  • Heinrich Leopold says:

                    Dennis, I have made many calculations about the costs of alternative energy sources. I have made even my thesis on this subject. However, Oil is the cheapest source of energy as it is made ready to use. Refineries just have to separate the chemicals and transform them in a relative simple processes. It is manifold more expensive to generate the molecules we have now available from biomass or coal. Oil is cheap as we just have to pump it up. If oil is not available anymore in large quantities, this will increase the energy consumption to up to 20% of GDP (from now 6%). This will not anymore allow for any debt fuelled tech bubbles.

                  • Dennis Coyne says:

                    Hi Heinrich,

                    Maybe you are an economist rather than a physicist. The entire oil system (production, transport, refining, and distribution) uses a huge amount of energy. Then when the fuel is burned in and internal combustion engine about 35% or less of the energy is converted to useful work.

                    EVs convert electrical energy into Work at about 90% efficiency.

                    Solar and wind also do not have the losses that exist in fossil fuel power plants where average electrical energy produced is about 40% of the energy in the fuel (35% for coal and maybe 45% on average for natural gas).

                    In short, oil is far from the most efficient form of energy, especially from the low quality resources that are being tapped today (LTO, oil sands, and deep water off shore).

                    When did you publish your thesis? Much has changed over the last 30 to 40 years, maybe you need to update your research.

    • Guym says:

      Yeah, Clueless, I think it has been given enough discussion. Probably too much on my part, I have learned a great deal from this board, from everyone. Should be an interesting year.

  29. Phil S says:

    Hi coffeeguyzz and Dennis,
    If you are really interested in the Australian Electricity market you should read
    (the abc is the australian broadcasting corporation and is the australian equivalent of the BBC)
    It seems private companies operating in a government regulated market have worked out the most lucrative ways to operate their businesses to maximise their returns – and consumers’ electricity prices have “skyrocketed” as a result.
    Cheers, Phil

    • OFM says:

      Hi Phil,

      THANK YOU for this link. I’m going to copy it over to the non petroleum thread and hope to get some discussion of it going over there.

    • coffeeguyzz says:


      Good article.
      The electricity business seems to be somewhat similar to the hydrocarbon in having upstream (production), midstream (transmission/pipelines), and downstream (utilities-customers/refineries) components.

      A big aspect with the electricity boys is the vast, and variable, involvement by differing governmental agencies.

      This can cause significant distortions that businesses will be quick to take self serving advantage.

      • Dennis coyne says:

        Hi coffeeguyz

        Everyone tries to gain an advantage through lobbyists.
        Government interference in markets should be minimized.
        Any advantage given to one energy producer should be given to all or none whether fossil or nonfossil.

        A level playing field is best.

  30. Senate tax measure helps President Trump pivot away from clean energy and back to fossil fuels

    The Trump administration’s campaign for “American energy dominance,” which focuses on elevating the nation’s fossil fuel production, received a potential big boost from Republican senators early Saturday.

    The tax measure they approved proposes to open the Arctic to oil and gas development, weaken investment incentives for solar and wind production, and end a big tax credit for new electric vehicles.

    To quote John Stuart Mill:
    Although it is not true that all conservatives are stupid people, it is true that most stupid people are conservative.
    And the same can be said about Republicans. Every stupid person I know is a Trumpite.

    • Guym says:

      The more I learn about people, the more I like my dog. Mark Twain

    • Boomer II says:

      I think we have to focus on the global situation rather the US from now on. We’ll pump out as much oil as we can, keep prices lower than they otherwise might be, hasten depletion, and give other countries the opportunity to advance beyond fossil fuels.

      Politics aside, even environment aside, we’re pursuing a path than will put us at an economic disadvantage.

    • Watcher says:

      “Although it is not true that all conservatives are stupid people, it is true that most stupid people are conservative.”

      Average IQ of the general population is 100, by definition.

      Average IQ of prison inmates is 84. In vast majority, they self declare as democrats, registered or otherwise, and tend to support left of center ideology.

      • Average IQ of prison inmates is 84. In vast majority, they self declare as democrats,

        Really now? Where did you find that stat? Somehow I just cannot picture most prisoners as belonging to any organized political party.

        I am not a member of any organized political party. I’m a Democrat.
        Will Rogers

        • Guym says:

          After 68 years, I have seen no need to affiliate with either the Republican, nor Democratic Party. They are both in a constant state of flux, and neither is clearly defined. What worries me most about the insane wall between Mexico, is that it can keep us in, as well as keep others out. And none of this has anything to do about oil, most of the inmates can’t vote, and many will never vote, again.

          • Ovi says:

            Guym there is no wall being proposed for the northern border. The word is “Come on up”.

      • Boomer II says:

        BS. You didn’t do your research, Watcher. You’re just tossing stuff out.

        “Part of what their study is picking up is the race effect, he said. According to the Sentencing Project, 38 percent of people in state or federal prisons in 2011 were black, though black people make up just 13 percent of the overall U.S. population. According to the Pew Research Center, about 80 percent of the black population in the U.S. aligns with the Democratic Party.”

        • shallow sand says:

          The vast majority of people in prison have substance abuse issues that are directly related to their incarceration. Many also have dual diagnosis, addiction plus mental health.

          How much does heavy long term use of crystal meth, heroin, crack cocaine or synthetics such as bath salts and K2 lower IQ?
          Same for heavy consumption of alcohol?

          Have read that up to 25 million US adults are addicted to illicit drugs (including illegal use of prescription) and/or alcohol. Tremendous drag on the USA economy. Plus, this issue is very generational, so the cycle is very tough to break.

          But this all should go on the non-oil board.

        • Watcher says:

          all true, how is that rebuttal

          • shallow sand says:

            If that was meant for my comment, no it was not intended to rebut anything.

            Grouping people into subcategories politically is kind of narrow in my view.

            There are a lot of good people on both sides of the aisle and a lot of bad people on both sides. Same with intelligence and many other traits.

            What does stink is the lack of civility, which continues to hit new lows.

            • Mike says:

              It does stink, Shallow. But here, on Peak Oil Barrel, you must remember it is NOT about free speech, or about rational debate regarding our country’s energy future, it is about picking a peak date, or having a model, or a prediction actually work, and otherwise promoting the end of fossil fuels as fast as possible. Those kinds of nasty comments, and the lack of moderation, are meant to control the context of the blog. Notice what got deleted and what didn’t.

              One has to be blind to not see that. I actually cannot believe anybody with an ounce of oil sense comments here, myself included. I am quite certain that nobody running this show has ever actually even seen a drilling rig in their entire internet consumed lives.

              • Dennis Coyne says:

                Hi Mike,

                I guess I missed what got deleted. Ron said there was a nasty comment that he thought should be deleted and I simply trust his judgment.

                I agree with shallow sand that the political groupings are not useful, nor is the lack of civility.

                Are you referring to the nasty quote by John Stuart Mill?

                I generally try to delete as little as possible.

                On the end of fossil fuels as fast as possible, I guess that is my opinion due to environmental concerns.

                Even without those concerns, eventually fossil fuel will peak and we need a plan B.

                Trying to get decent data so we know what has happened in the past helps us to guess what the future might look like.

                I imagine it would be difficult to run your business with no data, but you are correct I have only driven by a few oil rigs, the only physical work I have done (that I was paid for) is millwright, carpentry, pool building, and roofing.

                I have never produced a drop of oil and know much less than you shallow sand and many others.

                • Guym says:

                  If you make an inflammatory comment regarding someone’s intelligence, you can expect an over the top response. I read the comment, and it was. I hope you keep George posting, as he Obviously knows his stuff on oil production. Other than that, the majority of oil producers are probably closer to Republican, than Democrat. Not all, of course, but why take the risk of chasing knowledgeable people away (not including me, of course) with non oil related political insults?
                  There is some value in listening to both sides, without the insults. Part of my family is liberal, and part conservative. Most of the time we get along, without resorting to insults.
                  The comment by Ron, appears to give himself an outlet by indicating that not all conservatives are stupid, but tries to include all people who voted for Trump within a subset of its own. Which includes most Republicans, as they believed their options were limited, which was a perceived reality. So, he is insulting almost half, or more of his readers. Which doesn’t say anything about his intelligence, only that he doesn’t care what they think.

                  • Dennis Coyne says:

                    Hi Guym,

                    I guess if one did not like Ron’s comment, they could say that they thought everyone who did not vote for Trump was stupid and leave it at that.

                    My opinion is that there are people of varying intelligence in all political parties and that any correlation between party affiliation and intelligence is probably spurious correlation if it exists.

                    I have no data to back this up.

                    If people think Trump is a good president, fine. The majority of voters did not agree and most political polls also indicate the majority are not pleased with his performance so far.


                    In Oct 27/8,2009 Obama was 50% approve, 41% disapprove accorcing to Fox News. For Trump Oct 22-24, 2017 it is 38% approve and 57% disapprove according to Fox News, see link above.

                    Do you believe Trump is a good president?

                  • Dennis Coyne says:

                    Hi Guym,

                    I also think Ron does not realize that people seem to care what he thinks. Otherwise why would someone go off for having their intelligence insulted.

                    Lots of Republicans also don’t like Trump, but voted for him anyway because they liked Clinton even less.

                    I think when Ron says “Trumpite”, he means the Trump true believers rather than all Republicans, I don’t agree they are stupid, they just see things differently than me.

                    They are the middle class people that favor tax breaks for the wealthiest among us. 🙂

                    I agree name calling is a bad idea, and usually refrain (or try my best).

                  • Trumpite: One of the 33% of the voting public who thinks the sun rises and sets in Donald Trump’s ass.

                    Let me explain my earlier comment on that subject.

                    I did not mean that all Trumpites are stupid; I meant, that stupid persons are generally Trumpites. I believe that so obvious and undeniable a fact that I hardly think any honorable Gentleman will question it.

                    Well, let me amend that a bit. I should have said: “All stupid WHITE people are generally Trumpites.” Trump is a white supremacist you know. And the David Duke crowd just love him.

              • GoneFishing says:

                Mike said”But here, on Peak Oil Barrel, you must remember it is NOT about free speech, or about rational debate regarding our country’s energy future, it is about picking a peak date, or having a model, or a prediction actually work, and otherwise promoting the end of fossil fuels as fast as possible. Those kinds of nasty comments, and the lack of moderation, are meant to control the context of the blog.”

                Mike, unless I am misinterpreting your meaning, you have things a bit backward in this case. Peak Oil is a warning about the depletion of oil and it’s probable disastrous effects on civilization. You know, lots of screaming and blood in the streets, starvation, disease. The realization of Peak Oil is about avoiding the worst of the catastrophe of oil and fossil fuel depletion by finding energy and material alternatives. Of course renewables and efficiency must be promoted heavily. They have very powerful people and ideologies actively against them.

                The reality of the situation is that most likely we will not leave oil or other fossil fuels, they will leave us. We will fill in the expansion in energy with renewables and keep using FF as long as possible, since the population is growing and becoming more wealthy.

                Bloomberg just published a prediction that half the new cars sold in 2039 will be EV’s. I think that is a reasonable prediction. On the surface that looks like a takeover of the vehicle type and suppression of oil use. In reality that scenario will mean that oil must be produced at near the rate of today or more since there will be about twice the number of cars in the world by then and there will be many millions of new ICE’s being produced for a long time after 2040.
                So when we have 1 billion ICE’s and 1 billion EV’s running around in the 2050’s or later, how does that equate to less oil production? We have 1 billion ICE’s now.
                Do you think that we can keep producing 90 MMbpd or more for the next 50 years? Do you think there is enough oil left to do that economically? Or will we get caught very short? That is what peak oil is about, getting away from oil because it is a dead end, literally if not handled properly. With the world as it is now, it will take two or more generations.

                • Guym says:

                  Again, Dennis, there was no room for a response. Whether I approve, or disapprove, would be determined when he is finished. Remember, the period of time for Obama approval you quote, is before the results of Obamacare were assessed. Now, I will have to wade through the results of a “tax reform” which is always worse than either party says. That’s all non petroleum. I will say, I was ready for a change when Obama took office, and I was also ready for a change before he left. Seems like we are safer when there is not a party controlling all three (House, Senate, and Administration). My desire would be for them to spend less, but I guess that is out of the question.

                  • Dennis Coyne says:

                    Hi Guym,

                    I think people often don’t realize how little of the budget is non-discretionary.

                    If we take military and veterans benefit spending out of the discretionary portion (assuming that is “mandatory spending”, (like social security and medicare), then about 18% of the federal budget is discretionary. There is much less fat to cut than many believe.

                    The question I guess is how do you think Trump is doing so far, those polls were at similar times of their first term. Obama had been handed a nation facing an economic crisis.

              • Boomer II says:

                I was a partner in an oil company years ago, but it isn’t relevant to what I read today. I also have a family member who serves as a consultant to oil companies.

                I’ve been concerned with depletion since the Carter days and have wished we would have had a transition plan in place for when oil becomes scarce enough that it is too expensive to burn the way we do now.

                I came to this forum initially to get some sense of decline rates in the Bakker. The topic wasn’t being addressed many places.

                Now I am following Permian discussions.

                Even more of a concern now is whether the current administration’s energy policies make much sense from an economic or strategic point of view. I don’t think they do. I am curious as to whether opening up more land for drilling will actually result in much industry interest, and if it does, whether it will just to continue to suppress prices, thereby penalizing producers in other areas.

                I suspect the current administration is more concerned with spite than sound economic, energy, and strategic policy.

              • shallow sand says:

                Hi Mike.

                I hear you. Really enjoying Oily Stuff! Just keep on doing what you are doing. You have brought a wealth of experience both here and elsewhere. If the anti oil crowd visited you and your operations, they’d be singing a different tune I am sure.

                I do appreciate POB, very glad there are split boards (even though I violate the policy here and there).

                There is a vast middle in this country that is looking for common sense in Washington and Statehouses.

                On oil, one side wants to ban all oil production. The other wants to drill everywhere, with no plan or limits of any kind.

                I will go out on a limb and say both are bad policy. Why do the two parties have to be extreme on everything?

                • Dennis Coyne says:

                  Hi shallow sand,

                  Sometimes people may come across here as wanting to ban oil production.

                  That is not my position, I just want us to move to other sources of energy as quickly as possible because the response of the Earth system to increased CO2 is highly uncertain. If I am lucky enough to have Grandchildren some day, I am hoping that humans have not destroyed the planet so that life is very difficult.

                  This is unlikely to happen until you and Mike have long since retired (maybe in 2050 World oil production may have fallen to 50 Mb/d).

                  Eventually EVs are likely to become ubiquitous, I expect by 2050 about 95% of new car sales will be EVs and by 2060 probably 95% of passenger vehicle miles travelled will be powered by electricity rather than gasoline or diesel fuel.

                  Long haul transport will mostly be electrified rail, short haul will be EVs or possibly overhead wire on main roads with batteries for the final few miles to store or factory.

                  Most transport will eventually switch to EVs and plugin hybrids as scarce oil will lead to very expensive gasoline and diesel fuel.

                  So in my opinion, we need to get to work accomplishing this transition as it will be far from easy to accomplish. I expect peak oil (C+C) output for the World will be 2025+/-5 years at about 85+/-5 Mb/d.

            • Watcher says:

              wasn’t meant for your comment

    • texas tea says:

      if one, for the purposes of this discussion can define “stupid” as the need to demand service(s) from the government (riding in the wagon) as opposed to those who pay the taxes for the services (pulling the wagon)…please consider me one of the few, the proud and the stupid(rich enough and prosperous enough and stupid enough to pay the taxes). This can also apply to those smart people who need government to underwrite their business models first by subsidies and then my shutting down any competition, which under our last smart president those, who think like you relied on. Now like Warren buffet says..when the tide water goes out we will see who is swimming naked. (who’s smart and who is not)

      • Hey, it was just a takeoff on the John Stuart Mill quote. If you have a problem with that then you should take it up with John. Of course, John has been dead for almost a century and a half now. And you should know that unless of course, you are a Trumpite. I doubt if the average Trumpites has a clue as to who John Stuart Mill was.

        Although it is not true that all conservatives are stupid people, it is true that most stupid people are conservatives.
        John Stuart Mill

        He later explained this quote when so many conservatives objected.

        I did not mean that conservatives are stupid; I meant, that stupid persons are generally conservatives. I believe that so obvious and undeniable a fact that I hardly think any honorable Gentleman will question it.

      • Dennis Coyne says:

        Hi Texas tea,

        The state with the most wind power is Texas, where I imagine the state does not provide a lot of subsidies. All smart businesses will take advantage of every benefit the government grants them and they will hire lobbyists and pay substantial money to candidates who will support their cause.

        For now coal has won, though it is mostly cheap natural gas that has suppressed coal use.

        You do realize that the coal lobby has managed to get regulations enacted that will be a disadvantage for natural gas. I would think you would not be cheering for that (unless you invest in the coal business, I assume you are involved in the oil and gas business).

        The EV support is minor and repeal will have little effect. The wind and solar subsidies should be repealed as in the best areas (Midwest for wind and southwest for solar) these types of energy are competitive. As price falls for wind and solar, it will be the natural gas industry that will need government support as heat pumps, wind and solar drive down demand for fuel, though perhaps export markets can be found.

        The next 10 years will be interesting as natural gas producers join coal producers asking for subsidies.

        • coffeeguyzz says:

          Your statement regarding Texas not providing wind energy subsidies is both inaccurate and relevant to the entire concept of wind sourced electricity.

          The Texas government assured the funding – to the tune of $7 billion – so that the main transmission lines could be constructed carrying west Texas wind juice throughout the state.
          With these massive takeaway lines in place, smaller wind operators could construct their farms and hook up to the existing grid.

          These new operators, BTW, all currently receive both Investment Tax Credits (ITCs) and Production Tax Credits (PTCs).
          These federal level credits are incrementally expiring, which is a big reason behind the recent rush to build wind farms in the US.

          • Dennis Coyne says:

            Hi Coffeeguyzz,

            Yes they received the Federal subsidies, like every other state.

            If Texans, think building transmission infrastructure is a good idea, that’s their choice. I will let Texans comment as to whether that was a good idea, it’s not my state.

            Prices for electricity have decreased in Texas since 2008, natural gas net generation has increased from 48% to 50% and wind net generation has increased from 4% to 12.7%. Prices fell from 11 cents/kwhr to 8.4 cents per kwhr. Data from EIA.


  31. Energy News says:

    Petroleum Economist & Energy Aspects. November 20th
    If demand does not slow, the world will need far more oil than tight oil can offer at $50/b
    (free article)

  32. OFM says:

    Discussion of this news might be better conducted over in the non petroleum thread, but Venezuela is a major oil producer.

    So I’m going to post it there as well and say something stupid about it in hopes of learning more about crypto currencies, lol, because somebody will point out my errors.

    • Watcher says:

      The Catalonia independence people have said if they succeed in breaking away from Spain, they will not have a central bank and will base their money on bitcoin or another cryptocurrency. Venezuela’s Petro blockchain based currency has that as precedent.

      I am astonished that central banks and governments have not moved to stop Bitcoin. It is a tremendous threat to the power of central banks to run everything and can further expose the whimsical creation and destruction of money by a handful of unelected people.

      The renminbi or yuan is pegged. It’s not traded against the USD. China can create yuan as they wish. It has a government decreed ratio to the USD, and oil is purchased by China in amounts that are near the largest in the world. Bitcoin is being quoted as having a price in dollars, but the ominous direction is for that to stop and have it be quoted in barrels. This would not be an oil based currency. Oil would be based in the blockchain.

      • Guym says:

        I do some limited investing. Bitcoin scares the hell out me. I may be somewhat of a gambler, but someone is going to lose big time on this mess. It’s not me.

  33. Energy News says:

    2017-12-04 – LONDON (Reuters) – OPEC oil output fell in November by 300,000 barrels per day (bpd) to its lowest since May, a Reuters survey found, pressured by a drop in Angolan and Iraqi exports, strong compliance with a supply cut deal and involunary declines.

    ANP – Oil production in Brazil in October totaled 2.627 million barrels per day, a decrease of 0.9% compared to the previous month and an increase of 0.1% over the same month in 2016.

    Russian Federation crude oil and condensates production in November 10.94 million b/day (October 10.93 million b/day)

    • Energy News says:

      OPEC survey: Bloomberg sees OPEC crude output down 80 kb/day m/m to 32.47 mb/day in November

  34. Boomer II says:

    A good article on the decline of coal in Friday’s Wall Street Journal. It says economics are killing coal, and plants are being retired we already knew that). It also says older natural gas plants are being retired and there might not be new ones built because solar and wind are getting cheaper and electricity demand is no longer rising due to increased efficiencies.

    The states particularly open to renewables are those that allow utilities to buy generation from whoever offers it cheapest on a given day.

    • Longtimber says:

      The Energy Gang Podcast Mentioned 24 Coal plants closing in 2016.
      Of Interest: Article on Future LTO Growth: Perhaps / Perhaps NOT
      “As a group, tight oil producers have not made money. The 51 US E&P companies we track together spent $18.2bn on capex in the second quarter of 2017, while cashflow from operations was $12.2b – negative free cashflow of $5.9bn. Nor was Q217 an anomaly. Simply put, these firms have never been able to fund themselves with cash generated from oil and gas production. This is not a dirty little secret; it is a common feature of businesses in growth mode in a multitude of sectors unrelated to oil and gas.”

      • Boomer II says:

        Of course, firms rewarded for growth are assumed to become profitable at some point. It definitely doesn’t work, however, if what you are selling depletes rather than grows.

  35. Energy News says:

    Western companies’ oil projects in Venezuela – FT research – looks like it adds up to approx 120 kb/day
    Chart on Twitter

    Goldman Sachs chart for year/year crude oil demand growth
    demand growth with 2018 forecast
    potential production growth

    Reuters Tanker Tracking – OPEC seaborne crude oil volumes drop to 23.53 mbpd in Nov, from 24.4 mbpd in Oct, an 870 kbpd decline m-o-m. Sharp drop for Saudi crude shipments.

    • Energy News says:

      I’m starting to think that there must be a large margin for error in Tanker Tracking too. The figure they’re giving for Venezuela in this report is completely different to the one they gave just a week ago.

      • Energy News says:

        Bloomberg – US October Crude Exports Rise To Record 1.7M BPD – U.S. Census Bureau

    • Watcher says:

      That consumption growth thingy at 76% of total suggests nearly 3 mbpd, though forecasts should usually all be ignored.

    • Guym says:

      Yeah, I read Goldman Sucks prediction for oil in 2018. It’s what it is now. How imaginative, indicates a lot of thought.

      • Guym says:

        Although if they predicted a rise in prices, it would have spelt doom. Better we keep the predictions 100% wrong.

  36. Energy News says:

    Book – This sounds good (certainly educational) but I’ve not read it yet, I guess some of you must have read it?

    Energy and Civilization: A History – Hardcover – 13 Jun 2017 – by Vaclav Smil
    Bill Gates review – In his latest book, Energy and Civilization: A History, he goes deep and broad to explain how innovations in humans’ ability to turn energy into heat, light, and motion have been a driving force behind our cultural and economic progress over the past 10,000 years. Yes, our history has a lot to do with kings and queens and games of thrones. Smil shows that it has even more to do with energy innovation.

    I’m guessing that this might be a simpler version (certainly shorter, cheaper)
    Energy: A Beginner’s Guide – Paperback – 5 Jan 2017 – by Vaclav Smil

    • Tim says:

      Vaclav Smil’s books are excellent. I particularly recommend Creating the Twentieth Century which discusses the innovations that came out of the use of electricity and the development of of the oil economy and how they created the late twentieth century economy.

  37. Watcher says:

    Anybody noticed the asymptote in Alaska at 500K bpd? It was 30K of the Sept US rise.

  38. Guym says:

    By the third quarter 2018, it should be apparent to most, that EIA and IEAs projections of US output for 2018 are vastly overstated. That in itself, should create upward oil price movement. It couldn’t get as high as they project if oil was at $125 a barrel by the end of 2018. Later, yes, within a year, no.

    • Dennis Coyne says:

      Hi Guym,

      The EIA’s STEO looks a bit high from Nov 2017 to May 2018, but October 2018 (9.95 Mb/d) may be pretty close if the trend from June 2016 to Sept 2017 continues through Oct 2018. The longer range EIA forecasts (from AEO) of 10.3 Mb/d in 2023 seems reasonable, but the plateau forecast out to 2048 (10 Mb/d) is indeed a fantasy. Decline is likely to be rapid when LTO hits the wall in 2023 and decline will be rapid by 2028 (4%/year or more at peak decline rate). STEO in chart below (forecast Oct 2017 to Dec 2018).

      • Guym says:

        I think you are doing the same thing you blamed on the economists. That is always projecting upward. I think it will level out, or go down this year, and then pick back up in Jan. Putting it at the approximate 9.5 to 9.6 marker by Dec 2018. Just my guess.

        • Dennis Coyne says:

          Hi Guym,

          I am assuming oil prices increase to $80/b for the average annual Brent price (2017$) for 2018. Note that I don’t really assume that oil output will increase, I am simply saying that if it continues to increase at the rate that has been followed for the past 15 months for the next 13 months, we will be close to the STEO estimate for Oct 2018.

          The rate of increase will depend on oil prices, if you tell me what they will be, I will tell you what my guess for output is.

    • texas tea says:

      I liike Rapier, he seems to have a level head and good reasoning. His forecast mirrors mine made here several months back, so I hope he is right. At $70 we (the industry) will be a very good shape indeed.

  39. Guym says:

    To Dennis’ question on Trump. Don’t know, yet. A comparison to Andrew Jackson comes to mind, so far. RRC is setting up the FTP account. Supposed to be in csv format, but have no idea what it will look like, yet.

    • Guym says:

      And before I am berated for the loose comparison to a Democrat, remember it was all different back then. One of the reasons that I can’t identify with a specific party. Back then the Democrats were the conservative Southern land owners, hence a large part slave owners. Jackson was, too. It was a Republican, Lincoln, who belatedly supported emancipation. Republican support of civil rights continued through to the bi-party civil rights acts mid century last year. Afterwards, the Democratic Party made a magnificent public relations drive to gain support of minorities which worked. I remember that. Hence, the minorities now support the political party that fought to keep them as slaves. Now, that’s ironic.
      “I am quite sure now that often, very often, in matters concerning religion and politics a man’s reasoning power is not above the monkey’s.” Mark Twain

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