149 thoughts to “Open Thread Petroleum, January 10, 2020”

    1. Agree, the price of a resource is important, US shale gas and tight oil are both being oversupplied, so production growth will need to slow down, if it is to remain profitable.

      1. “if it is to remain profitable.”

        Interesting wording. One of the central questions asked here is about whether or not it’s even profitable now. How should your sentence above truly end?

        a) …. if it is to remain profitable.
        b) …. in order for it to become profitable.
        c) ….. to give it even the slightest hope to become profitable.

  2. Low price and medium price US tight oil scenarios compared, output in kb/d (left axis) and oil price scenarios for Brent Oil price in 2018$/b used for each scenario on right axis. The low oil price scenario has a URR of 58 Gb, and the higher price scenario has a URR of 96 Gb, currently tight oil proved reserves plus cumulative tight oil output is 36 Gb. Proved plus probable reserves might be higher at perhaps 36 Gb and cumulative tight oil output to Dec 2018 was 13 Gb, so perhaps cumulative output plus 2P reserves might be 49 Gb, it is likely that higher future oil prices will lead to higher reserves. My best guess is the URR=96 Gb scenario with a 50/50 chance the URR will be higher or lower than this and perhaps a 75% probability the URR will fall between 70 and 110 Gb.

    The models used to develop these scenarios are based on well profiles developed by fitting Arps hyperbolic well profiles to data gathered from https://shaleprofile.com

    Insights from oil industry professionals were used to develop the economic models and initial inspiration for the models came from reading posts Rune Likvern and Paul Pukite.

    Pukite posts:

    http://theoilconundrum.blogspot.com/2012/07/bakken-dispersive-diffusion-oil.html

    http://theoilconundrum.blogspot.com/2012/05/bakken-growth.html

    Likvern posts are numerous, but the first I saw was

    http://theoildrum.com/node/9506

    others at Oil Drum

    http://theoildrum.com/node/10102

    There was also a post at peakoilbarrel

    http://peakoilbarrel.com/debt-oil-price-bakken-red-queen/

    his blog is

    https://runelikvern.online/om-fractional-flow/

    Bakken posts at

    https://runelikvern.online/?s=Bakken

    My Likvern has never reviewed any of my work, I have simply tried to utilize what I have learned from what he has written.

    The posts by Pukite I found later.

    My first post on tight oil at link below

    http://oilpeakclimate.blogspot.com/2012/10/using-dispersive-diffusion-model-for.html

    Any errors in the analysis are mine alone.

    1. Great effort to link projections of output with profitability.
      Do you think that $90 is enough to get most of the oil to the surface,
      or would even higher prices result in squeezing more out?
      I assume at some point there is diminishing return.

      It was pointed out by another (the other thread) that in the USA coal contribution to electricity supply has declined by about 1/3rd, and “the cause of death is lack of profitability, not lack of supply or demand.”

      1. Thanks Hickory,

        If my assumptions are correct $90/bo will allow much of the tight oil to be profitable. At a very high price level, say 150 per barrel the URR might be as high as 120 Gb if the mean USGS estimate for TRR is correct. Possible that might occur, but I doubt URR will be over 110 Gb. Could be as low as 60 Gb ifow end of USGS estimates proves correct.

        Lots of uncertainty.

    1. $56.72 WTI for 2019 doesn’t seem to be exciting anyone.

      That was the average price for 2019.

      I think the major agencies see US C + C topping 20 million BOPD by 2030.

      Along with the slow but steady increase in renewables, just not much of a reason to get excited about oil. Reminds me a lot of the 1990s.

      1. Shallow sand,

        I think the 20 Mb/d estimates include NGL. Currently US C+C+NGL for US is close to 18 Mb/d. The 20Mbpd estimate seems reasonable for 2027 but will fall from there. C+C about 15 Mbpd.

    2. So rigs and frac spreads continue to fall yet almost all experts predict continued LTO growth …. it would appear the day of reckoning is coming and the majors in the Permian will not save the day ….. wasn’t everyone hoping for a pick up in rigs and spreads as budgets were meant to be renewed in the new year …

      1. Jack

        Oil prices are the key.

        If they remain low output will eventually fall, then oil prices will increase and output will follow.

        1. I think independents are finally getting it that they can’t simply look to increase production as soon as the POO goes up.

          I think the change has solely been bought about by investors requiring a return on investment, I’m not sure we can surmise that LTO producers will act as they have in the past, I suspect it will take a sustained period of high POO before LTO producers open the spigots it will create even more of a boom/bust scenario going forward …..

          1. I agree with you Jack, a large increase in oil prices seems unlikely to have much boost in LTO production for several years because banks will want significant loan payback before increasing drilling budgets. Dennis’ model is an excellent BAU projection, but we live in more dynamic times than that imho. Banks will need a consistent high oil price to lend like they did in the past. That seems unlikely given possibility for recession, war, EV adoption, increased regulation from Democratic prez, etc.

            Wall Street is obsessed with the shiny new thing and that is not FF production. Tesla’s share price now more than GM and Ford combined.

            1. Lot of possibilities between the low and medium price scenarios and the medium price scenario is a very conservative.

            2. I, too, have been skeptical that there will necessarily be a close correlation between rising oil prices and more production. With all the potential places for investors and companies to put their money, why should we assume they will want to put money back into the oil industry?

            3. seriously?
              you don’t think that rising prices (when demand exceeds production), that money won’t then flow towards attempts at production?
              we must live in different universes.

              think of it in terms of carrots. Despite the huge glut of carrots in 1952 with resultant plummeting of prices and profits earned , just 2 years later acreage planted picked up sharply due to a relative shortage in the markets (and higher prices).

            4. I am not confident that oil will look like a good investment even if prices rise. Where investment money goes depends on many factors.

              If Dennis is right that companies will finance more drilling via cash flow as prices rise, that could happen. Or they might try to take advantage of higher prices to pay down debt and get their money out rather than reinvest it into oil.

              I’m just looking at the global economic picture. It’s possible that money doesn’t want to stay tied up in oil if it can be invested elsewhere.

            5. Boomer,

              At some point demand for crude may start to fall after a period of high oil prices. It is likely to be around 2035 before consumption of crude falls below output so that oil price start to fall. In the mean time oil prices will rise to a level that output will match desired consumption at that price level. The level of output from tight oil plays will depend on the price of oil and the cost to produce the oil (which is determined by both technology and geology).

              As always, it is difficult to predict the future interaction between economics, technology, and geology.

              I am less confident that demand for oil will decrease significantly in the short term (next 5 years). Longer term (15 years) it may happen.

            6. Dennis, I hedge because money decisions aren’t always “rational.”

              “As always, it is difficult to predict the future interaction between economics, technology, and geology.”

              I think there will be people who decide there are better places to invest in than oil. Psychology, legalities, etc. can play a big role in where the money goes. Who knows? Maybe governments will seize oil assets and the owners will get little or nothing for it.

              I am always a bit skeptical of economic models because I know that models are only as good as the variables plugged in. I don’t view it as a given that a rise in oil prices will result in a rise in production in a predictable way.

              I don’t have any alternative to offer. I am just speaking as someone who majored in economics years ago.

            7. Boomer,

              I agree it is not a given that a rise in oil prices will lead to more output. In fact, my models suggest that after 2025/2026 output is unlikely to rise regardless of the price of oil.

              For an individual oil producer, they are likely to produce as much oil as is profitable to produce at any given price level. Under current geological, technological, and economic conditions, it is likely that at the price scenarios I have modelled, and assuming the USGS mean estimates for TRR are correct, and that cost of producing oil do not change significantly (technological breakthroughs are minimal), that my models will be roughly correct. Any of these assumptions could b incorrect, a lower TRR would reduce output and a higher TRR would increase it, lower prices would reduce output, higher oil prices might increase output (mostly in the tail). Also completion rates might be higher or lower than I have assumed (higher completion rates would lead to a higher peak and steeper decline and lower completion rates would have the reverse effect.

              In my “medium scenario” I assume completion rates increase by about 25% over the Jan 2020 to Jan 2028 period (about 2.8% per year on average). The low scenario assumes basically no increase in the completion rate for 2020 to 2028 and then decrease thereafter.

              You are correct that any (and more likely all) of these assumptions will be incorrect.

              They are a small set of choices of an infinite set of possibilities. The range between low and medium scenarios, might have a 60% probability of bracketing likely outcomes (see chart near top of thread).

              Agree that not all decisions are “rational” in the economic sense or in the general sense of being rational (as in sensible when all factors are considered).

              Of course not everyone agrees on what is or is not “rational”.

              Makes life interesting.

            8. Boomer

              With higher oil prices oil companies can finance out of cash flow. I do expect there may be less lending to oil producers.

          2. Jack,

            Perhaps, as prices go up profits will increase and oil companies will self finance.

            2. Stephen,

              I suspect if output goes down prices will rise to a level that will raise output.

              If prices rise enough producers can use cash flow to increase capital spending.

            4. Stephen,

              Depends on price, if oil prices remain at 53 to 63 per barrel in 2018$ for WTI, yes we get bumpy plateau.

              On the other hand, a higher oil price scenario where oil prices rise to $83/b in 2018$ for WTI by 2025 or so might lead to higher tight oil output of perhaps 10.7 Mb/d by 2026/2027 with declining output thereafter. In my view, the $83/b(2018$) oil price scenario is fairly conservative, as World oil output peaks, I expect oil prices could rise even more than my “medium” oil price scenario. As is often pointed out, nobody know the future price of oil tomorrow, much less 5 or 20 years from now. I agree, these scenarios just cover a couple of possible cases from an infinite number of possible scenarios.

        1. Looking like no sign of a frac spread turnaround as predicted it would be good to get more granular data out of primary vision as to where the retired spreads are coming from but this costs….

          Can’t keep on losing rigs without this impacting production, completion rates appear to be falling again data out of Texas for dec 19 was very similar to dec 18 when oil cratered to $45.

          Can’t see completions picking up as rigs continue to decrease, frac spreads decrease and DUC ain’t being drawn in a big way (suggesting quality of DUC ain’t all they are expected to be …)

          Early 2020 should be interesting as reduction in rigs, frac spreads and completions come home to roost ….

          1. Even a decrease in completion rate of 8% would leave tight oil output flat.

            Will be interesting to watch output could dip a bit but will rise after oil prices rise in response.

            1. I presume the 8% reduction also takes into account legacy decline ? Data out of the RRC for December 19 oil completions is weak at 491 (-13%) vs 564 December 18. I note that completions rose substantially in Jan 19 to 742 (+30% over Dec 18 levels) if the weak Dec data continues into the new year i think its fair to say completions will be well below the 8% dip you mention will leave output flat in which case LTO oil should decline fairly rapidly if completions fail to increase ….

              https://www.rrc.texas.gov/media/55723/dec2019drillingpermitscompletions.pdf

              thoughts ? What average level of completions are you modelling ?

            2. Jack,

              The RRC completion data is not very good, if you dig into the numbers you find that the completions reported for December are simply when the paperwork was filed, but actual completion dates range from 2 months ago to 18 months ago. Essentially the data is not useful. For a better data look check https:/shaleprofile.com. Note however that the most recent 6 to 12 months of data is incomplete as the state agency data gets reported very slowly.

            3. Jack,

              The low scenario is essentially a constant completion rate.

            4. Jack,

              Double checked the completion rates and it is not a constant completion rate. The completion rate falls by about 20% for the low price scenario and then recovers a bit to only 11% below the Sept 2019 completion rate by the end of 2028.

            5. Jack,

              Yes legacy decline is included in the model. The Permian completions fall by 8% to 460 from 500, for low oil price scenario, for total US tight oil completions the drop is 20%(from 1116 to 904) for my “low oil price” scenario. Output falls from 8100 kb/d in mid 2020 to 7760 kb/d in late 2022, then output recovers as oil prices rise from $53/b to 63/b (2018$) for WTI crude, reaching 8250 kb/d by late 2029, if oil prices never rise above $63/bo for WTI in 2018$.

              Note that this oil price scenario seems highly unrealistic from my point of view, which makes the scenario also highly unrealistic. Output is likely to be higher because oil prices are likely be higher than $63/bo (in constant 2018$) by 2029.

              Chart below shows this unrealistic scenario with the US tight oil completion rate on right axis.

            6. Jack,

              Here are the completion rates for all tight oil basins in Texas from https://shaleprofile.com

              Most recent 6 to 8 months may be underestimates due to incomplete data. For my Permian and Eagle Ford models I have an average completion rate from Oct 2018 to Sept 2019 of 566 completions per month for Eagle Ford and Permian basin combined, in Sept 2019 the completion rate was 500 for the Permian Basin (including New Mexico) and 154 for the Eagle Ford.

    3. Long term Horizontal oil rig count on land in the US.

      From the 2014 peak to the 2016 low HOR count fell by a factor of 4.4, recently (since early 2019) the HOR count has fallen by a factor of 1.3, it is not clear if this will be enough to stop output growth, but I expect the growth rate will fall from the rate of the past 12 months.

  4. Too much obsession with rig count. Maybe rigs are not the same as they used to be. Maybe they’re better. Maybe they do different things with them.

    Too much obsession with rig count.

    1. Agree but a LTO well cannot be bought into production without a frac spread and you can only frac a completed well hence the need for rigs …..

      It’s the trend re rig count which is important rather than fixating on the number …..

      1. It’s all about the Permian and has been for quite some time.

        None of the other shale basins have enough rigs running to grow production significantly.

        The Bakken is probably the most economic besides the Permian, and it seems the operators there are in maintenance mode with regard to production.

        There are still 397 rigs running in the PB. That is still a large number. I suspect there are more locations left there than in the remaining shale basins combined (not counting the ones which produce mostly natural gas).

    2. It takes rigs to drill wells and frak spreads to complete them. No, rigs and frak spreads have not improved their efficiency that much in such a short time. And drillers and frakers are not working that much faster.

      What you are seeing, or are about to see, is a slowdown in completions. The frak spreads that are being retired have obviously just finished completing a well. But they will not be completing another one. That’s why you see a lag between falling rig and frak spread count and completions.

      1. Ron

        I don’t have enough information to judge frac spreads. We only have numbers for all frac spreads in USA both oil and gas.
        Permian number is most important. Efficiency of fleet improves as count decreases as least efficient are idled first.

        1. Hell, that’s all we need Dennis. If the total number of national frac spreads fall then the total completions, nationwide, will fall. If production falls everywhere except the Permian, then that decline will offset any increase in the Permian.

          Okay, we know that the lions share of frac spreads are for oil therefore???

          I think you are way overplaying your hand with this efficiency stuff. Last time when rigs and frac spreads declined, then production declined. Why should it be any different this time?

          The simple fact of the matter is: “The total number of frac spreads are falling”. Therefore completions will fall because retired frac spreads frac no new wells. Yes, it is as simple as that. Saying the remaining frac spreads will be more efficient therefore completions will not fall, is just wishful thinking at best, and total nonsense at worst.

          The Primary Vision Frac Spread Count is 275 for the week ending January 10th, 2020.

          1. Well said Ron losing frac spreads means that the maximum number of completions able to be completed has decreased – the concept of increased efficiency is a red herring when spreads have fallen 40%!in the past 6 months – spreads efficiency sure hasn’t risen 65% in the same time …..

            I think we all agree once the worm turns in the Permian LTO production will decrease, I am not sure producers will increase production as the POO rises they do have to pay back a lot of debt and have shareholders to answer to who want a return …..

          2. From what I have read there is always improvement of efficiency in operation regarding new Buisinesses such as shale. This improvement is normaly linked to exsperiance, increased volumes i.e. but typical it will slow down during time as much of the easy potential will be taken out. I see this as drilling padds, skidding systems as same rig could drill more wells without be dismantled and mounting again. Dere have also been improvements in latheral lenghts, propant, and fluid . But as Slumberger wrote in 2019, they believed max latheral lenght already is reach as if increased cost off equipment will be much higher and also risk increase when operating atbthe limit, more tear i.e. There might still be improvements but more slow than it have been. According to reports the break even price increase 4-5 times each Tiere class, and I believe rock quality will be a main challange in years to come as shale will need higher oil price to earn money, pay back ballons and dividends.

            1. Let’s see the next quarterlies from LTO producers noting the continued comments about being profitable under $50. If Permian centric producers cannot profit on maintaining production output we know Houston we have a problem going forward ….. will the companies be able to stick to using cash flows from continued operations only or will we see more excuses carted out again ….

            2. Jack,

              If oil prices remain low long term, output will decrease.

              If output decreases, what is your expectation for the price of oil?

            3. Very interesting question you raise i presume if oil production falls OPEC will thumb its nose at DJT request to open the spigots after his last calls. i think $85 bucks will be reached fairly quickly once the LTO abundance narrative is questioned especially when producers will look to maximise cashflow to repay debt and pay divi’s to SH’s. I don’t think we can assume what has happened in the past one oil price rise will occur in the future as a result of fiscal discipline being forced onto producers by shareholders …..

            4. Jack,

              So you expect oil prices to rise to $85/b, but tight oil output will not increase, and OPEC will also not increase output (or that seems to be what you are proposing). Under that scenario, does the oil price remain at $85/bo?

              Is your expectation that $85/bo causes growth in oil consumption to stop?

              If nobody increases oil output, that would be the requirement, does that make sense to you?

            5. Freddy

              I agree low prices may bankrupt many oil producers.

              Without higher oil prices much of the resource will not be produced.

              Generally low output is likely to lead to higher oil prices.

              The system tends to self correct.

          4. Ron,

            In September primary vision said they were completing more wells per operating frac spread than earlier in the year. In December they said much the same.

            Not sure there is a reason not to believe them.

            We do not know how the number of tight oil frac spreads has changed. Also some plays have higher output per well than others so where the frac spread counts have changed matters.

            So far output has increased for tight oil. Perhaps that will change, we will know in a few months.

            1. Dennis they have not quantified their comments we cannot infer that operational efficiencies have overcome the substantial decrease in spreads.

              The drop in spreads has decreased of late you would imagine with the lag to production this should show up in the data very shortly.

              In the current POO environment you can’t imagine may LTO producers are wanting to grow production at these prices of they are losing money on each barrel.

              Would be good for primary vision to provide a bit more granular data to the market for free even if delayed going forward ….

            2. Jack,

              I expect the lag between changes in frac spreads and completion rate would only be 8 weeks or so. About 12 weeks ago the frac spreads had fallen to about 375, which would coincide with November output, which was still rising, then frack spreads fell to about 350 by the end of October, we will have to see what Dec tight oil output is, at some point I expect the completion rate might fall and if it falls enough output will no longer increase. I expect the December frac spread drop will affect output in February.

              Consider the fact that frac spreads dropped from 450 to 150 in the major downturn in 2014-2016 (a factor of 3) and tight oil output dropped by about 12%. So far frac spreads have dropped by a factor of 1.7, so perhaps we might see a drop in tight oil output of 7%, if the frac spreads drop no further. The frac spread count in the Permian would allow a better estimate.

              I suggest better frac spread efficiency to reconcile the drop in frac spreads from 450 to 375 with little change in the completion rate and increasing tight oil output.

              Also see this article

              https://www.rigzone.com/news/frac_spread_drop_could_end_soon-25-sep-2019-159898-article/

              especially the quote below:

              Johnson attributes the downward movement in frac spread counts in recent months to operators’ ability to do more with less.

              “It seems that more wells were completed with less spreads,” he said. “When the dust settles, it will be interesting to understand how utilization changed year over year.”

              Johnson refers to Matt Johnson the principal of Primary Vision.

              I agree we don’t know how much frac spread efficiency might have increased, only that Primary vision has implied that there has been some increase.

              My main point is that we do not have a very clear picture, sometimes output continues to grow when we expect it to fall, this has occurred many times in the past. We will have to wait to see what future output is.

          5. Ron,

            There are many unknowns.

            Lag between change in frac spread count and change in completions.

            How many gas focused frac spreads?

            Where have frac spreads changed?

            Maybe you could answer these questions.

            It seems surprising that tight oil has continued to increase so rapidly. I don’t have a great explanation.

            Perhaps you can explain.

  5. Horrific look at the aftermath of the sautéeing of Oz:

    ‘Deathly silent.’

    one unburnt patch I visited … was literally crawling with birds, all chasing one another, trying to work out who owned the last little bit of turf. It was clearly insufficient to sustain them all.

    Just imagine what it’s going to be like when those roasted chickens come to roost amongst the humans.

    1. Australians are committing climate suicide exporting coal to China and SE Asia… but better to talk about this on the other thread.

      1. I feel terrible for the Australians, however, I am very skeptical that if Australia was to stop exporting tomorrow it would make any difference in China or SE Asia’s coal consumption. I bet they would replace it as needed.

      2. Stephen,

        I agree it would be better to discuss this on the EPM thread.

    2. It is horrific. Much of the burning is in the very small zone of forested zone on that continent.
      Dry and dyer.
      It will be interesting to watch how this affects the political landscape there.

      1. My brother had a dive business there.
        Having a asian wife, he had trouble with the racism, and did not enjoy being there.
        I was just there briefly.

    3. Australia’s bush fire’s have nothing to do with climate change and everything to do with mismanagement. We have removed high country grazing reduced controlled burning, don’t allow us firefighters to back burn, Restrict private landholders rights to put in fire breaks, and allow more and more people to live in these area’s.
      I have been fighting these fires for months the whole narrative has been hijacked by this climate change crap which has NOTHING to do with these fire’s.

        1. Number of extreme Heat events/year, according to the Government of Australia

          1. Here is some raw data not the spin data.
            http://www.bom.gov.au/jsp/ncc/cdio/weatherData/av?p_nccObsCode=36&p_display_type=dataFile&p_startYear=&p_c=&p_stn_num=015540
            http://www.bom.gov.au/jsp/ncc/cdio/weatherData/av?p_nccObsCode=36&p_display_type=dataFile&p_startYear=&p_c=&p_stn_num=015590

            Most of Australia’s temp records are to corrupted by cement and building’s Alice Springs is one of the few locations you can trust.
            The hottest temp recorded in Australia was Oodnadatta, South Australia, 50.7 degrees Celsius, occurring on 2 January 1960.
            However it was removed from the records because it was recorded on a Sunday. https://jennifermarohasy.com/2017/02/australias-hottest-day-record-ever-deleted/
            But of course climate change……

            1. In your raw data the 30s for year average are much more common after 2000 than before.

              But I agree, it’s much more mismanagement and the common fire vegatation (some plants need to burn to breed themselves), the climate change is only the icing on the cake.

              It’s the same with flood water in parts of Europe – it get some more severe with the climate change, but 90% of the damages come from building expensive things in flood areas and other mistakes.

              The whole discussion is much too mindless – we have an old wisdom for it: “If you have louses, it doesn’t protect you from fleas”.

              I see the climate change here in every summer vacation in the mountains – bushes where only gras was 30 years ago, a valley with a lake where a glacier was 30 years ago. Ötzi thawing up after buried under ice for 5000 years.

              But common errors and false planning multiply the damages at every location by a magnitude. In the mountains for example: building ski infrastructure and hotels at spots where nobody has build in old times. And then crying when there was a avalanche or thawing up landslide. And then the newpapers write something about climate change – when the damage was 90% foolishness. Perhaps the climate change triggered the landslide – but there should not have stand a hotel at this space or a freeway.

            2. ” not the spin data.”
              Sorry, I’ll go with Australian Government Dept of Meteorology analysis over yours, every time. Take it up with them.
              You seem to have a bit of an agenda. [Zappuppy]

      2. This comment is somewhere between ridiculous and insane as Australia went on fine for millions of years without cattle and humans setting fires.

          1. Yellowstone: They let it burn
            And it was a good thing.

            N. hemisphere: +1C over average
            Arctic +2.9C Antarctic +1.5C

            1. This buring has no, really no impact on CO2. Please think before falling in CO2 panic.

              These are fire woods – they just regrow and bind it again. Then they burn again. And grow again.

              That’s why you can call it a circle. As in normal vegetation – it grows, it rots, it grows.

              And that’s why bio fuel/heating is called regenerative energy and not fossil energy.

            2. No reference to the burning and Co2.
              This was about letting Yellowstone burn for its own health.

          2. Fire is only one way to reduce the amount of wood around. Termites and fungus do the same thing.

            Once you start setting fires, you kill the fungus and termites, so you start thinking fire is the only option. The ecosystem reaches a tipping point where natural feedback loops are so broken artificial loops are needed.

            It’s also worth noting that many modern forests are unnaturally young — average tree age is low due to repeated disturbances, like logging etc. But fungus thrive on older, less healthy trees. Loggers usually harvest trees before they age enough for growth to slow down, so logged forests add wood faster than natural forests.

            There are other factors as well, especially the balance between herbivores (that clean out underbrush but also suppress new tree growth by eating saplings) and their predators.

            Another important factor is the amount of water the ecosystems retain. This depends on erosion.

            Just as logging increases the rate of wood formation, predation can increase the rate of grass production. Ungulates and grass are symbiotic, because ungulates trample down the competitors of grass. Grass reacts to cropping by increasing its growth rate. Predation speeds up meat production by forcing prey to produce more fast growing offspring. This in turn increases demand for grass, and allows grass to spread in preference to herbs and saplings. This can change the speed at which fires spread.

            1. Yes this is right.

              How many regulation from fire, fungus and termites (or other bugs) comes, depends on the climate.

              Long hot summers with a thunderstorm here and there – that’s fire country, and to a grade termites.

              Rain around the year – we are in fungus land, fire almost unknown and very local.

              You can see this in California, too. The native people have avoided many parts of the land for settlement due to the fire danger every year.

              And in Australia especially Eucalyptus likes fire to remove competitors:
              https://wildfiretoday.com/2014/03/03/eucalyptus-and-fire/

              This year everything came together, the perfect storm: An abnormally dry and hot summer, and long time of not burning / other removal of fire loving vegetation.

            2. “You can see this in California, too. The native people have avoided many parts of the land for settlement due to the fire danger every year.”

              Well not really. They were living all over the habitable areas in high numbers. Many of habitable zones are in extremely high fire risk zones. It comes with the territory. It is not unusual for these wind driven fires to run 25 miles in a day.
              People have been learning the hard (horrific) way in these ‘Mediterranean’ climates for as long as they have been living in them.

              Just like people living along the riverbanks. Hard lessons learned over and over and over.

            3. Hi everyone,

              These discussions should take place on the non-Petroleum side, this week that means the Electric Power Monthly post should be where these discussions occur. Thanks.

    1. Nordstream II scheduled for first flow late this year or early next, per Merkel and Putin.

      I’m actually surprised it’s that long. The pipes will be in place within weeks, but a lot more has to happen than only that.

  8. Production from these selected top 8 US shale oil companies might be about to fall as shown by decreasing quarterly crude oil production changes as in chart below.

    EOG
    Pioneer
    Concho
    ConocoPhillips
    Marathon
    Occidental incl Anadarko acquisition
    Diamondback
    Devon

    1. very interesting graph it shows what is evident that independents are being forced into financial discipline at last. I cannot see the majors picking up the slack regardless of what the MSM say, why would they continue with the growth at all costs strategy which has caused noting but carnage for the above 8 producers.

        1. Looks like XOM grew quite strongly. Their pockets are deep, they can buy up assets on cheap as smaller companies fail, fairly standard in capitalism.

          1. Can XOM do all the heavy lifting itself once the independent growth plateaus then falls is the million $ question. My bet XOM will grow but in a sustainable way, the impact of the Permian increase will be interesting to note in their quarterly how much has that growth cost them is the question …..

            1. Jack,

              If we look at Exxon/Mobil, Chevron, Conoco-Philips, Shell, and Total combined, they have increased combined tight oil output from 400 kb/d to 840 kb/d in the past 2 years (Sept 2017 to Sept 2019). Most of this increase occurred from Sept 2017 to Sept 2018 when oil prices were a bit higher, in the past 12 months output grew by only 155 kb/d. Oil prices matter, low oil prices may kill tight oil output growth, if so, oil prices are likely to rise.

            2. Dennis.

              I read some of your models some of the time, so forgive me if this question you have already answered.

              When you model the Permian, how many wells are you assuming?

              It seems the EFS and Bakken likely do not have years of locations left, at least on a large scale. Likely why there aren’t a lot of rigs.

              If there are a decade of locations for 400 rigs in the PB, I suspect oil prices will remain range bound.

            3. Shallow sand,

              For my “medium oil price scenario” (maximum WTI price of $83/b in 2018$ reached in 2027), we get about 195,000 total wells drilled, about 110,000 total horizontal tight oil wells get completed from 2010 to 2030 (about 26,000 have been completed through November 2019) so roughly 80k wells completed from Sept 2019 to Sept 2029 in scenario below.

              Also link below has spreadsheet you can play with.

              Changing row 4 changes completion rate to any rate that seems reasonable. Scenario ends in 2030 for this particular spreadsheet, you can use excel, google sheets, or some other spreadsheet program, it is saved in microsoft excel format.

              https://drive.google.com/file/d/1fyAD5-CngWdgq_kaZ7ow1k7O_dNr8xaW/view?usp=sharing

              On prices remaining range bound, that depends in part of how quickly oil consumption grows. From 1982 to 2018 the average rate of growth in annual oil consumption has been about 800 kb/d. My $83/bo model has US tight oil growing by about 385 kb/d over the next 7 years, it is not clear that the rest of the World will be able to fill the 415 kb/d gap each year (assuming the 800 kb/d C+C consumption growth continues for the next 7 years). That is why I expect oil prices to rise.

              There has been relatively low offshore oil investment over the past 5 years and this is likely to start affecting World oil output soon, the bumps in output from Brazil and Norway are likely to be offset by declines in other producing nations (Mexico, China, and UK) and it is far from clear that we will see higher output from Iran, Venezuela, Libya, or Nigeria.

              As always the future is difficult to predict and I am often wrong, so perhaps oil prices will remain “range bound” in your preferred $55 to $65/bo range. If that is correct Permian output will grow far more slowly, perhaps growing from 4 Mb/d to about 6 Mb/d. The low oil price scenario has about 72,000 wells completed from Sept 2019 to May 2030 in the Permian, about 52,000 wells in all other US tight oil basins for a total of about 124,000 wells for the low oil price scenario over that period. The completion rate falls from 850 in 2030 to zero in 2035 for the low oil price scenario and output falls from 8200 kb/d at the start of 2030 to 2600 kb/d at the end of 2035.

              I think it unlikely oil prices will remain range bound when World oil output peaks in 2026, that is only 6 years away, growth in oil output will slow significantly starting in 2024 and oil prices are likely to rise (at the latest) by June 2023.

            4. Thanks.

              That is a lot of locations. Of course, not all locations are the same productivity wise.

              Incredible how much oil the Permian Basin has produced and will produce in the next decade.

              Interesting how many companies sold out most of their acreage in the PB in the late 1980s and 1990s, thinking it was past its prime.

              I know of a small operator that bought leases in the PB and drilled some good vertical wells. Martin Co. I don’t know what they paid, but I am sure it was a tiny fraction of the $600 million they sold out for a three years ago.

              QEP bought about 9,500 acres from them for $600 million. There was 1,400 BOPD of production from vertical wells at the time of the sale.

              I have been looking at the wells QEP has drilled on this acreage. I don’t think $600 million for 450 hz locations was a good deal for QEP. There are some good wells, but not enough of them.

            5. Shallow sand,

              Yes I agree, all locations will not have the same productivity, I use the average for all wells drilled for any given month as I am interested in the entire industry, some operators will have better wells than others, some of this is skill and some of it is luck, I simply assume generic company X will have a well productivity distribution that will be similar to the industry average, in practice this is not likely to be true, but if we think of the entire Permian basin as being run by a single large oil producer (Big Permian Oil Company) it would be approximately correct, if my economic assumptions are correct.

              I also find it amazing how much tight oil has been produced (5.6 Gb so for for Permian since Jan 2000) and will be produced ( a total of 29 Gb for my model from Jan 2000 to May 2030, and for longer scenarios out to Dec 2079, about 60 Gb URR for Permian basin alone.) Mike Shellman thinks that is completely wrong, but if the USGS mean estimate is roughly correct and my medium oil price scenario and other economic assumptions are correct, that is what the model suggests might happen. Mike is not a fan of the USGS TRR estimates, their F95 estimate is 43 Gb for Permian Basin URR, my low oil price scenario is in line with that F95 TRR estimate, with a URR of about 37 Gb.

              If the TRR is low, oil prices are likely to be higher and a higher percentage of the TRR is likely to be profitable to produce. (For a low TRR scenario the EUR would decrease more rapidly than my “medium” TRR assumption (the basis for my best guess estimates).

              I assume new well EUR starts to decrease starting in Jan 2019. In Dec 2018, my model has the average Permian well with an EUR of 378 kbo. Chart below shows how the model assumes the EUR will change from Sept 2019 to May 2030 (end of model scenario) for the Permian scenario I presented above.

              Again this is a guess for how future EUR will change based on a TRR scenario (no economics) with 255,000 wells and a TRR matching the USGS mean estimate of 75 Gb for the Permian basin. The rate that the EUR decreases depends on the number of wells completed each month. Chart is small, click on chart for larger chart.

              So they paid 1.33 million per well, I agree the wells do not look very good, for a 2017 average well, QEP has cumulative output of 145 kbo, my basin wide average well has about 190 kbo at 24 months, so the QEP wells about 24% lower than average, yikes.

    1. What is the currency fluctuation correction in this for large food consumers. In this specific case probably gotta look at India’s issues. Not oil driven.

      1. have you looked at the webpage? FAO provide a short explanation for the most important price drivers (usually “good/bad harvest in country x” is the main factor). Energy is often more indirect and affects the trend rather than the short term volatility. This issue the oil price was mention explicitly as it increased demand for Brazilian ethanol (and thus sugar price) and biodiesel (and thus vegetable oils).

        1. I looked. I saw no mention of currency. How can there be price without currency? Even a basket approach would fail if faced with India losing value against the basket.

          1. There are two links at the top of the page. They contain background information of the 73 price series that are used and how these are weighted in the index. The difference between international market prices and local prices is also discussed as well as how this impact food security for the poor and how vulnerable countries have been forced to change their composition of foods as a respond to higher prices.

            The approach can off course be criticized but I find the FAO to be transparent on what they do.

  11. Production from these selected top 9 US shale oil companies might be about to fall as shown by decreasing quarterly crude oil production changes in chart. ExxonMobil (XOM) shale oil is growing fast about 11% per quarter but probably not enough to offset declines from other operators.

    EOG
    Pioneer
    Concho
    ConocoPhillips
    Marathon
    Occidental incl Anadarko acquisition
    Diamondback
    Devon
    ExxonMobil

    XOM data is taken from shaleprofile.com, averaging three months into a quarter, then multiplying by 75% to get crude oil. 75% is used because Pioneer Natural Resources crude to total shale oil is 75% and Pioneer operates in the Permian which is also XOM main basin.

    1. Pretty sure shale profile reports crude plus condensate, for “oil” production. As the data matches pretty closely with the EIA’s tight oil estimates by play when Oklahoma output is excluded (shaleprofile only reports Oklahoma output on the subscription service.)

      In short, one should not assume 75% of what is reported at shale profile is the “crude” portion of output. In fact all US output is reported as crude plus condensate, all the way back to 1860.

      There is also Chevron, BP, and Shell operating in US tight oil, all have deep pockets and will be unaffected by the tightening up of the credit markets. In the past 2 years these 5 have doubled their tight oil output, though most of the increase occurred in 2018 when oil prices were higher.

      Output may drop, that in turn will lead to higher oil prices and higher tight oil output, also the majors will be able to pick up cheap assets as smaller oil companies that have not been financially prudent go bankrupt, that may accelerate the growth of tight oil output from the majors as oil prices rise.

    3. If we consider the top 7 producers without the major oil companies included (Exxon Mobil and ConocoPhilips) we get the chart below. In the Sept 2017 to Sept 2019 period the output from these 7 large producers increased from 1456 kb/d to 2268 kb/d, so it is likely correct that the increase for majors would not offset the decline from these 7 companies (if their output does indeed decline), from 2015 to 2016 output fell by about 300 kb/d for these 7 oil producers, it is not clear if they will decline as much in 2020.

      Also from

      https://shaleprofile.com/blog/us-monthly-update/us-update-through-september-2019/

    1. Tony,

      Did you ask Enno Peters? I believe NGL is not included. As I suggested the shale profile data matches very closely with US tight oil estimates by play, which does not include NGL.

      See link below for EIA’s definition of crude oil

      https://www.eia.gov/dnav/pet/TblDefs/pet_crd_crpdn_tbldef2.asp

      where it says:

      Liquids produced at natural gas processing plants are excluded.

      1. I just emailed Enno Peters.

        From: Tony Eriksen
        Sent: Wednesday, 15 January 2020 9:42 AM
        To: Enno Peters
        Subject: RE: Your ShaleProfile Analytics trial will expire soon

        Enno,

        Could you please tell me if your shaleprofile.com definition of oil includes crude, condensate and natural gas liquids (NGLs)?

        Thanks,

        Tony

        1. Enno Peter’s reply to Tony and I:

          Dennis, Tony,

          You both asked me about the definition of oil that we use.

          We simply report the oil & gas numbers that each state agency publishes on well (or lease) level. This means that we follow the definitions of oil and gas that each of the state agencies uses (which can be slightly different!).

          If condensate is reported separately, then we add it to the oil stream.

          Regarding NGLs, it is my understanding that:
          – several state agencies do not even collect data on NGLs from operators, notably the Texas RRC (I have verified this with a Texan operator).
          – almost no state lists NGLs separately.
          – North Dakota includes it in the gas stream

          Hope this helps.

          Best regards,
          Enno

          http://shaleprofile.com

      2. Dennis,

        EIA DPR says:
        https://www.eia.gov/petroleum/drilling/faqs.php

        Are natural gas liquids (NGL) included under oil or under natural gas? What about lease condensate and vented or flared natural gas?

        The DPR uses well-level data from state reports. These reports measure hydrocarbon liquids produced at the well as oil measured in barrels and hydrocarbon gases produced at the well as natural gas measured in thousands of cubic feet. Because the DPR uses the well-level data, any separating/processing/refining occurring downstream of the well meter is not accounted for in the DPR. Lease condensate is liquid, counted in the oil stream. Natural gas production includes volumes that after being produced may be vented, flared, reinjected, separated, or otherwise processed; this is also known as produced natural gas or gross withdrawals.

        Enno also uses well-level or wellhead data so his oil definition would have to include lease condensate and NGLs.

        2. Tony,

          There is a lot of confusion about what an NGL is and whether pentanes plus should be included as NGL or defined separately as “condensate”, which might be defined as NGL that is a liquid at standard temperature and pressure, which is not the case for ethane, propane, or butane (in their various forms, that is C2, C3, and C4 hydrocarbon molecules in their various configurations.)

          You seem to be using the non-US meaning of NGL where pentanes plus (aka lease condensate) is considered NGL. Shaleprofile uses the US definition where lease condensate is considered as separate from NGL, which typically are called NGPL in the US to highlight the fact that they are produced at natural gas processing plants where the ethane, propane, and butane are removed from the natural gas to produce “dry” natural gas (relatively pure methane or CH4).

          See

          https://rbnenergy.com/through-the-looking-glass-ngl-condensates-and-pentanes-us-vs-world

      3. DC,

        Liquids produced at natural-gas processing plants are excluded. Those are the NGPLs if memory serves and are not NGLs which I think of as coming from NG at the well head.

        In other words liquid from NG is listed two ways: The stuff obtained at the well head (NGL) and the stuff obtained farther down the line at NG processing plants (NGPL), and the latter is not included as oil. This is from my failing memory but so is my ability to find my way home most of the time.

        Hmm…it’s been a while since Port.

        1. What some do not realize is that the natural gasoline (which condenses from the natural gas stream at standard temperature and pressure of 1 ATM, 25 C) has always been included in the crude plus condensate data in the US since 1860. The lower carbon chain products (C2, C3, C4) are not liquids at STP, they are gases and remain in the natural gas stream until they are separated at the natural gas processing plant. The definition given by the EIA is quite clear on this point.

  13. In the Permian basin, the ratio of crude to total oil (incl NGL) produced by Pioneer has fallen from 81% at beginning of 2016 to 75% at the end of 2019. If this fall is similar for other Permian producers then it may be harder to continue increasing Permian crude production.

    1. The comparison between oil production from shaleprofile.com and from Pioneer is very close, as shown by the two green lines. For 2019Q3, shaleprofile production was 286 kbd compared to 290 kbd from Pioneer quarterly report. Note that both these numbers include crude, lease condensate and NGLs.
      http://www.pxd.com/

      1. I read an very interested report here on this forum where US geological Institute had estimated break even prices for Thiere 6 to 1. Thiere 6 was categorizized as sweet spots with more than 800 kbpd. As I remember this had break even cost 18 usd each barrel and to next class you could aproximately multiplay it with 3. I believe this is much of the core knowledge the Pioneer Mark Papa is estimated US future shale production at wich again is related to change in rock quality. What we know is in 2014 -2015 I believe US could earn money at least with some borrowings at 30 usd WTI , 5 years after tjey cant earn money at 60 usd WTI even with huge improvement in drilling efficiency that it is a reason to believe will go much slower in future. Labour cost and all other will continue to increase. It might be break even price in 2025 will be above 120 usd WTI iff Thiere 5 runs out as same as Tiere 6 the sweet spots. This mean we will be back to the situation before 2014 when the main source off oil was offshore, and investment was there. It simply means US need to cut more cost in shale oil, develop more oil from wells drilled in less quality rock but this challange might be very hard to solve even for Exxon that is ramping up, the question will be if their barrels are profittable at 42 usd WTI as they predict. Perhaps Mr. President could give tax release, or simply start buy up the 1500 billion in depth that need to be payed next 4 years.

      2. Tony,

        Some people may consider natural gasoline (which condenses from Natural gas in the lease separators) as “NGL”, I consider this this to be lease condensate and generally is is mixed with the crude and sold with the crude. Perhaps Pioneer keeps a separate account of “crude” and “condensate”, in the US these are usually lumped together as C+C, most of the NGPL produced in the US is Ethane (C2), Propane (C3), and Butane (C4), about 12% of the NGPL is natural gasoline (C5), roughly 600 kb/d of a 5000 kb/d total output of NGPL. Note that the US does not count the pentanes plus from NGPL plants as part of C+C output even though it is chemically very similar to lease condensate. In Canada, for example the pentanes plus from NGPL is added to C+C from the field, not sure why the US does things this way, Canada’s approach seems more sensible.

        See https://www.eia.gov/dnav/pet/pet_pnp_gp_dc_nus_mbblpd_m.htm

      3. Tony,

        It is possible that Pioneer is reporting condensate as NGL as Texas reports these separately, not really very clear.

        In Dec 2018 for the US shaleprofile reports 6811 kb/d of tight oil output (note that they do not include Oklahoma output in their data and I have excluded “other” basins from the shaleprofile data). EIA reports 6849 kb/d of tight oil output for Dec 2018 (excluding Oklahoma basins), pretty close to the estimate reported by shaleprofile.com.

  14. Something new to chew on. The attached chart is from the January STEO, which projects production out to December 2021. It shows increasing production over the December 2019 report starting in January 2020, 100 kb/d in January 2020. It also shows the failure of the quadratic model. The projected increase from Dec-19 to Dec-21 is 1.12 Mb/d.

      1. Jack,

        There is a lag between changes in rig counts and output. The EIA estimates that tight oil output increased by about 95 kb/d from October to November 2019, from 8070 kb/d to 8165 kb/d. The STEO has probably over estimated Dec 2019 output by about 100 kb/d, December output will probably be about 12.85 Mb/d (about 120 kb/d lower than the STEO estimate.) They have estimated about a 500 kb/d increase in output in 2020 (from Dec 2019 to Dec 2020) which seems pretty reasonable, it might be a bit lower than this, but I doubt it will be less than 400 kb/d, so I would expect Dec 2020 output to be about 13.25 Mb/d at minimum for US L48 excluding GOM. From Dec 2018 to Dec 2019 the increase in L48 excluding GOM may be about 810 kb/d. So a 400 kb/d increase in 2020 would be a significant slowdown from 2019. In 2018, the increase in output was 2 Mb/d (Dec 2017 to Dec 2018).

    3. Ovi,

      Projected increase from Dec 2019 to Dec 2021 is 1.12 Mb/d, I believe (typo above).

  15. Such is the extent of the shakeout in the U.S. shale industry that Permian Basin oil production is closer to peaking than many forecasts suggest, according to one energy investor.

    Adam Waterous, who runs Waterous Energy Fund, regards the sector’s financial position as unsustainable after years of disappointing returns for investors and negative free cash flow. With capital markets now largely shunning shale producers, the impact will begin to show in oil and natural gas output from the largest U.S. oil patch, he said.

    “We think we are at or near peak Permian” production, Waterous said last week in an interview. “The North American oil market has been grossly overcapitalized, which is not sustainable.”

    Predicting peak Permian output for 2020 isn’t a mainstream view. There’s plenty of debate about how much production growth in the West Texas and New Mexico patch may slow this year as shale drillers slash capital spending, but the consensus is that supplies will rise, albeit at a slower pace. Tai Liu, an analyst at BloombergNEF, said in a report Tuesday that the pessimism may be overdone.

    https://www.bloomberg.com/news/articles/2020-01-14/peak-permian-oil-output-is-closer-than-you-think-investor-says

  16. Just because there are newcomers I will re offer up a consideration.

    If you have to have it, and you do have to have it, you are not going to let a substance created from nothingness on a whim by the local Central Bank get in the way.

    This is a peak oil blog, and that means scarcity. When something that you have to have is scarce, then you are going to go get it. The concept of price is a parameter of value — value that exists only in the imagination of counterparties. Oil moves food and your stomach doesn’t care about the imagination of counterparties. So don’t be so sure that price determines production. Or consumption.

    Anybody notice that the price is rather a lot less than it was five or six years ago? How does production compare to then?

      1. Maybe you should read the data. The price is lower than 6 yrs ago and production is higher.

        How much fuller a stop must there be?

        Now go ahead and wriggle around and vacillate about how it will all turn out right if you just give it time. Or you could just accept that theories are theories and if there is even a single experiment that contradicts them, they are declared failed.

        Math sort of works that way. And it’s hated when it doesn’t fit the scientific method.

        You lose. And worst of all. You know it.

        1. “‘There are known knowns. There are things we know that we know. There are known unknowns. That is to say, there are things that we now know we don’t know. But there are also unknown unknowns. There are things we do not know we don’t know.”

          Economics is the study of how people allocate scarce resources for production, distribution, and consumption, both individually and collectively.

          Supply and demand is the amount of a commodity, product, or service available and the desire of buyers for it, considered as factors regulating its price.

          Watcher, we don’t live in a perfect world of instant information and production.

          ” Over the past five years, the industry and its investors “mistook a massive structural change for a simple cyclical event,” he said. “It’s impossible to continue to have uneconomic production and capex.””

          https://www.bloomberg.com/news/articles/2020-01-14/peak-permian-oil-output-is-closer-than-you-think-investor-says

          Watcher, maybe some day you will figure out you need to apologize to Dennis for your ignorance and demeanor. Until than your the loser.

        2. Watcher,

          I believe I said production and consumption, if consumption is less than production we call that oversupply, when that occurs price falls.

          This is very basic stuff.

          1. It is basic stuff. I can show you many time periods of increasing price that aligned with increasing consumption.

            And again, worst of all, you know I can show those time periods.

            The theory fails. If you find even one instance where it is wrong, it fails. That’s the scientific method. The hypothesis is proposed. Experiments are observed. If even one fails to support it, that’s failure. That’s how it’s always worked.

            There is no oh, but. Price is lower than 6 years ago and production is higher. 2010 to 2014 price rose from $95/b to $112/b. Consumption 2010 89 bpd to 2014 93 mbpd. I found that without breaking a sweat.

            The theory fails. Embrace a new one. And why be surprised? It’s a substance whose value derives from whimsy and counterparty imagination

            1. Watcher,

              You seem to not understand the concept of varying rates of production growth or consumption growth.

              I will explain slowly for you.

              We start with a market in balance where the rate of increase in production matches the rate of increase in consumption so that over the course of the year the total produced is equal to the total consumed, then things change so that production of C+C increases by 2 million barrels per day while consumption increases by 1 million barrels per day. Do you see the problem?
              The market ha an extra 365 million barrels at the end of the year (that they had not been planning for) and storage facilities are nearly overflowing. This is commonly referred to as a market that is oversupplied. Typically we see oil prices fall in this situation as long as prices are not artificially supported by government decree, in other words free market forces are allowed to operate.

              Would you like to propose an alternative explanation for oil price movements?

              Also keep in mind that social science has no controlled experiments, there is no laboratory. That is why there is little agreement within the economics field on many questions.

              Also price discovery is problematic because often there is incomplete information. In other words the balance of supply and demand is not known with precision on World markets until long after the fact when the data gets collected, at any given moment in time the market is guessing at the proper price that will balance the market.

            2. Excellent simple explanation Dennis

              The American shale production has been a game changer to the market place. Increasing the available supply and moving the supply curve to right. The marketplace has yet to balance to the marginal cost of an additional barrel. Leaving the market over supplied for the last 5 years with a blood bath of red ink and bankruptcies.

            3. Chart below shows OECD stock levels in days of forward consumption (left axis) and the Real WTI Oil price in 2018$.

              Unfortunately we do not have a good estimate for World oil stock levels, that is part of the problem, the OECD stock levels are the best data we have on oil stocks.

      1. Search the article name in google and open it from there, this gets around the paywall for me.

    1. You need to learn how to read a chart Wayne. Nothing in the MOMR even remotely suggests such. Even by OPEC’s World Oil Supply chart shows the last quarter of 2019 below the last quarter of 2018, total liquids.

      I will have a complete report on the OPEC MOMR in a new post tomorrow and it will include the chart in question.

      1. My error meant to say Non OPEC oil production has increased by 3 million barrels over the last 2 years.

        The middle East, which has half the world’s oil can obviously increase production.
        They are only using 68 rigs, while the US is using 944. They cannot even sell the oil they can produce, due to Non OPEC growth.

        1. Wayne,

          US C+C output increased by 3000 kb/d from Oct 2017 to Oct 2019, almost 2/3 of the increase occurred from Oct 2017 to Oct 2018, in the past 12 months US C+C output growth has slowed considerably (it is nearly a factor of 2 lower).

        2. The middle East, which has half the world’s oil can obviously increase production.
          They are only using 68 rigs, while the US is using 944.

          According to Baker Hughes, your figures are a tad off. They say the MiddleEast had 430 rigs in December to the US’s 804.

          1. I read some place Saudi is now increading their investment in drilling and well improvement.

  19. In several shale basins across the US, the ratio of crude to total oil (incl NGL) produced by EOG has fallen from 80% at beginning of 2017 to 77% at the end of 2019. EOG is the biggest US shale oil producer and their production seems to be slowing as shown by chart below.
    https://www.eogresources.com/

    1. The comparison between oil production from shaleprofile.com and from EOG is very close, as shown by the two blue lines. For 2019Q3, shaleprofile production was 612 kbd compared to 604 kbd from EOG quarterly report. EOG numbers include crude, lease condensate and NGLs.

      Dennis believes that shaleprofile numbers are mainly crude oil and condensate. However, EOG crude oil and condensate production for 2019Q3 was 463 kbd which is much less that 612 kbd from shaleprofile.

      One possible explanation for this difference is that the 612 kbd is from shaleprofile selecting EOG as actual operator. However shaleprofile says:

      “The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.”

      Maybe if EOG is selected as operator (current) then a different oil production rate would be shown.

  21. In several shale basins across the US, the ratio of crude to total oil (incl NGL) produced by Occidental (Oxy) has fallen from 73% at beginning of 2018 to 71% at the end of 2019. Oxy will be the biggest US shale oil producer when their 2019Q4 results are released. Their production seems to be slowing as shown by chart below.
    http://www.oxy.com

    1. Shaleprofile shows oil production from Oxy to be about 450 kbd for 2019Q3 which is about 50 kbd less than Oxy stated crude oil production. A part of the explanation for this difference is that Shaleprofile has only horizontal well data while Oxy has production from about 3,400 vertical wells.

      The chart below is derived by choosing both Oxy and Anadarko as operator (actual).

      Oil production of Occidental including Anadarko

  23. Updated production from these ranked top 9 US shale oil companies might be about to fall as shown by decreasing quarterly crude oil production changes in chart. ExxonMobil (XOM) shale oil is growing fast about 11% per quarter but probably not enough to offset declines from other operators.

    Ranked by 2019Q4 crude production

    1 Occidental incl Anadarko acquisition 504 kbd
    2 EOG 465 kbd
    3 ExxonMobil (XOM) 337 kbd
    4 ConocoPhillips 284 kbd
    5 Pioneer 215 kbd
    6 Concho 210 kbd
    7 Marathon 195 kbd
    8 Diamondback 195 kbd
    9 Devon 157 kbd

    XOM crude oil data is taken from shaleprofile.com, averaging three months into a quarter. XOM shale crude oil production rate increased by over 60% from 2018 avg to 2019 avg. If XOM continues this growth rate into 2020 then US shale crude oil production could grow very slowly in 2020.

    XOM Permian growth rate on page 10 https://corporate.exxonmobil.com/-/media/Global/Files/investor-relations/quarterly-earnings/presentation-materials/2019-presentation-materials/earnings-presentation-3q.pdf

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