August Non-OPEC & World Oil Production Rose

105 thoughts to “August Non-OPEC & World Oil Production Rose”

1. Great post, Ovi; thanks. Just eyeballing your charts, I see about a 2 million barrel per day jump between May and December 2025. Any idea where all this new oil is coming from?

   1. Hi Ron,

      Non-OPEC output increases from Jan 20025 to November 2025 by 1860 kb/d in the STEO forecast (this is all liquids), 1600 kb/d of this increase comes from 6 nations (Argentina, Brazil, Canada, Guyana, Norway, and the US). For Total World liquids from Jan 2025 to Nov 2025 the increase is 2380 kb/d for the STEO. This implies that OPEC liquids output increases by 520 kb/d from Jan 2025 to November 2025 in the December STEO. About 67% of the liquids increase comes from those 6 nations with the largest increases from Brazil and the US (21% from each) and about 63% of the share of the increase from these 6 nations.

   2. Ron

      Thanks

      I assume you mean May 2024 to December 2025. This is where it is coming from. The first three are the usual suspects.

      – Canada    1.1
      – U.S.           0.52
      – Guyana      0.20
      – Norway       0.26
      – Kazakhstan 0.17
      Total            2.25

      – As for Canada 0.4 has occurred up to August due to fires. Between August and December 2025, add in another 0.2 max. So the 1.1 gets cut back to 0.6 max.
      – U.S.: Cut it back to 0.3
      – Norway 0.2: Most of it has happened between May and August.
      – Kazakhstan. Could be real. See article referenced after the chart. Will they go along with the OPEC targets? That is the question?

      Canada and the US are over estimated. Typically Canada could do 0.1 Mb/d/yr.

2. Here’s a bottoms up for two distinct groups:
   Top is Middle East + Russia&friends + US/CAN (2023 peak)
   Bottom is the others (peak was 2003)
   1P reserves run out early 2030s (URR=1800 Gb)
   2P reserves run out by 2045 (URR=2000 Gb)
   2PC reserves run out ~2080-2090 (URR=2750 Gb)

   

   1. Reserves are subject to constant revision they don’t equal the amount of oil actually present just a certain percentage of it. I don’t see the justification for end date calculations like this.

      1. End date estimates provide useful conceptual models to highlight oil’s finite nature. These are broad estimates and not meant to be taken as having a high level of precision. You may also be confusing resources and reserves, while total resources might be 5-10 Tb, getting more than 2 Tb (reserves) may be challenging (technical/economic factors). Recently, 1 barrel is discovered meanwhile 6 barrels are extracted, or every 6 years we find enough oil to extend these dates by 1 year…so I agree with you more accurately, 2042 may actually mean 2045. If conservation is also factored we might shift out another 5-10 years. US currently has an 8 year supply of 1P reserves, so if we use that then we could say it runs out in 2033, with maybe a couple more years due to revisions. Were you thinking that significant revisions would change these values drastically?
         Another way to approach the problem:
         In 2014, U.S. reserves were estimated to last thru 2027
         In 2018, thru 2029
         In 2021, thru 2032
         In 2024, thru 2032
         Notice anything?

         1. In 2014 US proved reserves were about 40 Gb and crude input to refineries were about 5.8 Gb per year, so with no imports this would have been enough to last until 2021, not 2027. In 2021 the reserves would take us to 2029 with no imports. The Rystad estimates for US proved reserves are quite low at 32 Gb and probably should not be compared with EIA estimates, but if we ignored this significant difference, it would suggest we “run out” of proved reserves in 2028 if there were no imports of crude. Reserves are continually added over time, in 2009 there were 22.3 Gb of proved reserves and input of crude to refineries was 5.23 Gb that year suggesting we would run out of crude (if there were no imports) by 2013.

            As far as I know it was not a problem.

            1. Do you know where I can find actual oil in place estimates? That info seems to be incredibly scarce nline. I’d imagine such figures would be closely kept secrets and maybe that has something to do with it.

               1. It’s a good question actually. I don’t know. I think to swag it, I would just take the largest technical reserve estimates* and double (or even triple) them.

                  This ought to account for the 30-70% of oil left in place (even after tertiary recovery). And also some major deposits not yet really identified even in optomistic TRRs (e.g. underexplored Alaska, Zagros mountains, and the Atlantic offshore basin on both the SA and Africa sides). It would include low API petroleum “tar sands” in Canada, Vz, and even the US. But it would NOT include immature kerogen (Green River “oil shale”, as opposed to “shale oil” or “tight oil” (the latter would be included).

                  *By that, I mean start with some Rystad or BP TRR. NOT the Laherre estimates which are WAY too conservative. Or the Dennis Coyne ones that are better than Laherre but also much too conservative, for long term considerations.

               2. Jacob,

                  OOIP (Original Oil in Place) for the World is probably about 3 times URR estimates for conventional oil. Typically about 35% of OOIP is expected to be produced on average for conventional oil reservoirs, for tight oil and oil sands the number is lower perhaps 5 to 10% of OOIP. So for conventional oil perhaps 9000 Gb of OOIP and for unconventional oil with URR of perhaps 400 Gb, maybe 4000 to 8000 Gb OOIP say 6000 Gb as a midpoint estimate so a total OOIP of perhaps 15 Tb. This would be 5 times the URR which is around 3 Tb by my estimate.

                  A good resource is USGS.

                  https://www.usgs.gov/programs/energy-resources-program/science/science-topics/world-petroleum-assessment

      2. A wrote: “Reserves are subject to constant revision”

         Almost like abiotic oil exists. Of course with high oilprices much more can be recovered.
         However:
         Not all the ‘original oil in place’ (OOIP) can be recovered, no matter how high oilprices are and notwithstanding the most advanced EOR techniques. Not even close to 100%. And the last Gb’s that can be recovered form the flat tail of the production curve.

         From earlier posts one example:

         “…..the combination of horizontal drilling and water flooding has allowed Aramco to keep Ghawar production flat at the expense of future production.”
         Bold mine
         This counts for a lot of (super)giant oilfields.

         Aggressive EOR was mentioned many times, also by ROCKMAN on the former website “The Oildrum”.
         This could make the downward slope of the worldproduction curve make more steep than many are expecting. Maybe geopolitics (or (something like a) worldwar) will trump geological factors or will a quite rapid transition to EV’s (like many times pointed out by Dennis Coyne) prevent a disaster (mainly by strongly falling oil exports). In the latter case demand could drop more rapidly than supply or at least could stay more or less in balance with supply.

         1. Hi Dennis I wanted to ask you about something

            I was looking at the EIA overview on the subject. According to this 20.01 mbd barrels of petroleum were produced and 9.52 mbd were exported leaving us 10.49 mbd barrels of oil adding the imports it gets us back to 18.82 which isn’t equal to stated consumption values of 20.8 mbd.

            What’s going on here?

            https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php#:~:text=In%202022%2C%20total%20petroleum%20exports,million%20b%2Fd%20in%202022.

            1. Jacob,

               The use of barrels as a measure is part of the problem, if they used mass instead the numbers might match up better, using crude only makes things a bit better, but even in that case there are very different crude densities so the problem remains when we report in volume rather than by mass. A large amount of the “oil” in that 20.8 million barrels of consumption is “bottled gas” such as propane, ethane, and butane. The important components of refinery output that are consumed are gasoline, distillate (diesel fuel), and jet fuel which in 2023 were 8.95 Mb/d, 3.92 Mb/d, and 1.65 Mb/d respectively , a total of 14.52 Mb/d out of 16.5 Mb/d of finished petroleum products consumed.

               See

               https://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_mbblpd_a.htm

               1. Could oil and other products kept in stock account for this? That’s what chatgpt said when I asked it this.

               2. Jacob,

                  That probably doesn’t help with the unit problem. Needs to be measured in energy units or mass, volume is just a problem when we have products with many different densities.

                  Also note that chatgtp often gives incorrect answers, it is not a great tool.

            2. messy definitions in that link.

               Petroleum in import/exports includes crude, products, NGLs, and pretty much everything…
               ‘Petroleum production” on the other hand only includes feedstocks for products: crude, condensate, biofuels ets…
               “petroleum consumption” only concerns products…

               So you cannot really add import/export barrels to production/consumption barrels. Apples and oranges.

         2. Depletion moves reserves down. Price increases and technology move them up. Price decreases move them down also, of course…but if you are the typical peak oiler, not the electric car kind, and believe in Matt Savinar, Matt Simmons $200+ oil, that is going to unlock extra reserves.

            Technology is also clearly something that can increase reserves. Even in 1956 Hubbert gave the excellent example of how seismic technology had led to new production peaks (after old ones) in the IL basin. Almost a microcosm of what happened with the US from shale/fracking.

            In addition to seismic, Hubbert was aware of secondary recovery and that it might improve over time. He thought he was accounting for that, but still probably didn’t as seismic, secondary/tertiary recovery have improved more. And also, offshore oil, which he was well aware of and included in his estimates has improved considerably. Not just depth of wells, but also the seismic to find oil offshore.

            Hubbert actually did NOT excluded shale (tight oil) from his estimates. The Permian and Bakken were producing conventional fields when he wrote. What he excluded was oil shale (the immature kerogen in the Green River that Jimmy Carter wanted to turn into Synfuel. But he did not exclude source rock. Again some drilling and production was done even in the 40s, 50s. It’s just that systemic production needed to wait for a moderate price increase as well as industry practice in making decent (reasonable cost) multistage hz fracks.

            Note also, that Hubbert DID exclude tar sands (like in Canada). He was well aware of them and excluded them (since the amount was huge and would shift his peak). However, this was probably NOT a good assumption. Since we did develop the ability/facility to produce tar sands and they are now significant on the world stage.

            I mean sure, people can say “neener, neener, he excluded tar sands”. But then what was the point of his prediction? Since they are meaningful now. Instead he should have actually included them, figuring they’d get developed eventually. Of course this makes one wonder about even the Green River and the Synfuels. Who’s to say that decades from now, that process can’t be made cheaper. Look at what has happened with tight oil and with tar sands.

            1. why stop there? coal and gas can also be converted to liquids, why not count them too.

               There’s just a lot of buried hydrocarbons in tHe Earth’s crust. Biomass has been getting buried for billions of years, away from oxygen, turning into hydrocarbon. How do you think the Earth got 21% oxygen in the atmosphere and only 400 ppm CO2? By sequestering biomass away, so that it cannot get “burned”.

               Then, in just the last couple of hundred of years, this species Homo Sapiens started unearthing all this sequestered and “fermented” biomass and burning it. As good and aggressive we are at getting this stuff out, the time of deposition and time of extraction are hugely disproportionate: billions of years vs hundreds of years… So there should be enough to keep extracting during our lifetime, at least…

               Hubert and other peak oil people never meant to expand their EUR model so much, however. What they considered foremost was pretty specific: liquid hydrocarbon in high porosity reservoirs.

         3. Dude you don’t need to go full retard to explain this. More oil isn’t magically appearing rather we simply find more while increasing the percentage we can get out of the ground

3. Great Job Peakoilbarrel team!

   I am going to post my brilliant comment again….for any dumb dumb that wants to disagree….

   Jokes….

   “Canada cutting off oil exports to the USA would be one of the worst geopolitical decisions in human history

   Canada gets the USA 900 billion a year military for FREE.

   Turning that against yourself would be very stupid!”

   1. ANDRE THE GIANT,

      Ontario Premier, Doug Ford, was referring to “Energy Cuts” to the United States as in Electricity, not oil.

      The Premier wants to cut Electricity entering into Wisconsin, Michigan, and New York State. Canada exports a lot of electricity to the United States.

      Doug Ford can’t make that decision for Alberta because that is up to Alberta’s Premier, Danielle Smith. I doubt Alberta will cut any Oil Sands production exports to the United States.

      steve

      1. Canada’s cold war era submarine “fleet” is becoming obsolete and needs to be replaced.

         Canada doesn’t manufacture subs (I don’t think)

         I would not energy embargo Uncle Sam if I was on the border to the North.

         Canada will ride out Peak Oil better than anyone else if they maintain good relations with USA. And that seems a very likely scenario.

         “There are only 2 types of ships, Submarines and Targets” – A great submariner said.

         1. Andre

            Canada does not produce submarines. The US, UK and Australia made a deal whereby US nuclear subs are to be transferred to Australia. Canada tried to join but they were not allowed. Not sure why. My guess is that there might be some fear that super secret sub info might leak to an unfriendly country.

            1. I don’t know exactly either, but I suspect the issue was nobody trusted the Canadians to actually go through with it and pay for such submarines. They have never had nuclear submarines, so have no history of such operations. They have considered it several times, one I remember was in the 80s, and never gone through with it.

               UK has a history of nuclear subs and a lot of similarities, shared history with the US S5W reactors. But they are not really sister programs. Limeys do their own thing and have enough critical mass and history to have credibility as operators or builders of nuke subs. Maybe “cousin program” instead of sister.

               There are also issues like the border disputes in the Arctic. (Canada claims a lot of waters there…and US disagrees.) US has sent surface ships through the NW Passage and has also sent subs all over the Arctic. But I think this is sort of a formality. Nobody takes the Canadians seriously. It’s not like they enforce their claims. So, I think it’s a lot more about nobody trusting them to actually spend the money for a nuclear sub program.

               P.s. I’m still not 100% sure the Australians will go through with the expense of building and operating nuke subs. I mean, I think they should. But not sure if they will, in the end.

         2. Andre,

            Do I understand that you predict Ontario Premier Doug Ford won’t retaliate against Trump’s trade war because Canadian feds in Ottawa need new subs?

            The world must be such a mystery to you.

            1. Not suggesting or predicting that in the short term.

               Canada and USA need to create (and continue) a win-win relationship over the long term.

               If you think Canada should energy embargo the USA, I believe that would be a very DUMB decision.

               And I think Trumps trade war is stupid.

               The Monroe Doctrine.

4. It’s possible there may be some “hidden” production going on that is not in the listed figures. In particular, it’s pretty well known/documented that Iran and Russia are evading sanctions by selling to China and India. E.g. China supposedly imports more oil from Malaysia than the entire production of that country! If countries are playing games with the destinations, then perhaps they are also doing the same thing with production totals. In the past, some stealth, extra production has also occurred in the context of OPEC quota cheating.

   Note, I’m not saying not to use the listed figures. Official figures are probably the best we have. And I’m fine with peakers celebrating the 2018 (most recent) peak. Just noting this possible nuance. FWIW.

   Prices don’t seem to indicate a supply shortage constraining consumption. But could be lower market demand driving the difference of pre/post Covid also. Certainly US motor gasoline consumption has still not recovered to pre Covid levels.

   1. There also could have been unreported oil during any and all other times in the history of oil production. I don’t really know how we can take that into account? Is there a good way to do that?

      There has been plenty of oil world wide since 2014, based upon oil prices since that time. The only spike was more political in nature than a supply issue. Shale has been the key.

      Shale absolutely saved the US economy. Where would the S&P 500 be if the US was producing 4-5 million BOPD, let alone the natural gas glut, which has returned so much manufacturing to the US?

      1. Closely related, the EU states (or most of them at least) are now, for some strange reason, utterly dependant on US, mostly fracked, LNG to keep the lights on… Things that make you go hmm….
         (some ME countries are of course happy to sell NG too)

         1. I’d say closely related for sure.

            Since 2010, compare the US economy to the EU economy.

            Shale might be the most important contributor to this disparity.

            1. Shallow,
               Hope things are going well for you.
               Your comment about the US gas glut and reinvigorated American manufacturing activity prompted me to re-visit Lazards most recent (2024) LCOE report.
               The LCOE report CLEARLY displays the overwhelming economic – and operational – advantages of Combined Cycle Gas Plants for inexpensive, abundant, reliable power availability far off into the future in the US.
               For those not inclined to ‘get into the weeds’ (aka minutia) of this report, the Lazards folks have always skewed the presentations to depict renewables in a very favorable comparative light to conventional sources.
               The appendix clearly shows this with parameters such as 20 year facility life – versus Real World being 40+ years – for CCGPs’ capital cost amortization (a huge component in the overall cost comparisons) while using 30 years facility life for onshore wind (LOL).
               Plant size – 550 Mw – at about $1 billion cost is also way off, and using $3.45/mmbtu fuel cost (another big cost factor comparison) is on the high side.
               Hands down, the US is in a position to realize enormous economic benefits should the political will be found to seize and use this vast bounty.

         2. Looking into the not so distance future: the US could stop exporting LNG to the EU anytime they want (or have a regime change). Then the shit will hit the European fan quite fast and hard.

            1. True. To be reliant on imported energy is a fragile position to be in, whether the source is a neighbor or the US, the Mideast, or Russia. China seems to be acutely aware of that vulnerability.

      2. We don’t need all that. AI and Bitcoin can fix this.

         Making things in material reality is for suckers. That’s why backwards and poor nations (the ones not America) do it.

      3. Shallow Sand: “Shale absolutely saved the US economy. Where would the S&P 500 be if the US was producing 4-5 million BOPD, let alone the natural gas glut, which has returned so much manufacturing to the US?”

         That’s a very refreshing observation! And totally accurate. Despite all the sharp elbows used in the discussion of energy, it is important to stop and reflect on the tremendous contribution of shale hydrocarbons to the global community.

         1. It’s paradoxical. Without question, the shale has been an economic boon.

            But it has also been a huge and devastating head-fake: people now think peak oil is a myth, that growth in production will continue without worry, that no preparations are needed.

            To misquote you: “. . . it is important to stop and reflect on the tremendous contribution of shale hydrocarbons to global complacency.”

            It’s the perfect example of the oft-quoted Eric Severeids’ law: “The chief source of problems is solutions.”

            The problem is that civilization must power forward. We accomplish this through an utter dependence on a dwindling resource that must be destroyed to be of use and that consequently poisons the atmosphere. Shale oil is a hair-of-the-dog solution.

         2. As noted above, compare the US Economy to the EU Economy since 2010.

   2. Nony,

      The oil production numbers are not hidden, they just try to hide where the oil is shipped, many of the nations that have sanctions are part of the DOC and they carefully follow the production of members. The numbers may be imperfect, but this has always been so.

5. The Rig Report for the Week Ending December 13

   
– US Hz oil rigs decreased by 1 to 438. They are down 21 rigs from April 19 and are up 11 relative to their recent lowest count of 427 on July 24th.
   
– In New Mexico, Permian rigs were unchanged at 94 while the Texas Permian lost 2 to 190.

   – In New Mexico, Lea and Eddy were unchanged at 46 and 48 respectively.
   

– In Texas, Midland dropped 1 to 26 and Martin added 1 to 27
   – Eagle Ford dropped 1 to 39.
   

– NG Hz rigs dropped 1 to 86.

   

6. Frac Spread Report for the Week Ending December 13

   The frac spread count decreased by 3 to 217. It is also down 48 from one year ago and down by 55 spreads since March 8.

   

   1. So no drill, baby drill and then frac it bonanza currently? Bad news to the BASF people in Germany, and the VW workers too. Quite some stir in Europe about volatile energy prices lately and hoping for cheap, possibly/likely promised, LNG seems distant.
      Norway has apparently also been thinking about reducing electricity export to EU for related reasons, interesting times indeed.

      1. We should absolutely keep the Ukraine war going as well, because that in no way is a self-own by the EU powers.

         People love inflation now. It’s all they know.

         1. Just to cut Boris J a little slack, his marching orders were likely from elsewhere, I hope at least, he doesn´t seem that dumb from what little I´ve seen but I may be wrong. (but otoh the parties were certainly dumb so you never know)
            And previously there were “but the EU don´t want that”, with known results and comments…
            So a lot of moving parts to follow, are you not entertained?

7. “The December 2025 oil production projection is 345 kb/d lower than estimated in the previous post and note that it is also lower than the November 2018 peak.”
   What is the reason to put the projections in the graphs?
   Often we see that the projections are over optimistic and overestimate the eventual realized production.

   Second question: why stop the projection in december 2025? Why not extend it to december 2027 of 2028?
   The further we look into the future, the less certain the projection becomes.
   One thing is certain though, future oilproduction will decline eventually. By limiting the projection to 18 months you can pretend that the decline is still far off.
   Have a great Christmas guys

   1. Hans,

      The basis for the projection is the December 2024 STEO from the EIA, the last data point is December 2025 in that report. In January the new report will probably extend to December 2026. Also note that I do not think Ovi believes the STEO projection is corrrect, it gets revised each month. At link below is Ovi’s forecast based on data in Jan 2024 from EIA International data and the Jan 2024 STEO. At that time the estimate for Dec 2025 was 83426 kb/d vs 84468 kb/d in the most recent report. The estimate was revised higher and then lower. No estimate of the future is ever correct and even estimates of recent historical production are often revised over time.

      I think you are correct that output will eventually decline, but for now we seem to be on a rough plateau around 81-83 Mb/d for 12 month average output. I expect decline will begin around 2028, but I am always wrong.

      1. Dennis am always still surprised when people in the peak oil space continue to make predictions. The theory is on the money I guess. But in my eyes the predictive methods have been discredited.

         1. Jacob,

            There are an infinite number of possible future scenarios and only one of those will be correct. This has always been true and will always be true in the future. Odds of a correct forecast are zero so I would be very surprised by a correct prediction.

            1. Dennis,

               Please keep your predictions and other commentary coming.

               It seems like a number of people in this space have a direct, day-to-day financial investment in the topic. If they are wrong an hour, day or month in their entrance/exit to the market it matters. If their price forecast for a producing well is off next year it matters.

               Others, like me, have different interests, different experiences with modeling complex systems and different experiences with uncertainty. Let’s say we look back 50 years from now and your predictions ends up +/-10% of the peak production volume at +/-5 years with a decline on the same order. That would be an incredibly accurate prediction, and we’d still see the same types of consequences for energy use, energy transition, national security, climate, other environmental impacts, etc. And, we’d have the benefit of making decisions and taking actions guided by those predictions.

               Keep up the good work.

               1. T Hill,

                  You are too kind. My predictions might end up being as close as you suggest by luck. There are a host of assumptions about the future in these models and many of them will undoubtedly be incorrect.

         2. Jacob, do you mean that the prediction that the peak of Crude + Condensate would peak in November 2018? Exactly when was that predictive method discredited?

            1. Maybe in 2014, when you said,

               “Crude Oil, or rather C C will peak no later than 2017. I strongly believe the peak will be in 2016 but it could be a year or two earlier but no later than 2017.”

               https://peakoilbarrel.com/peak-oil-blibbit-principle/

               Right after that first quote, you showed a graph of World C&C, showing oil bouncing between 75-76 MM bopd from about 2011-2013 and made this comment:

               “In spite of all the hoopla about the US shale boom world C C has been relatively flat for two years.”

               And now we are firmly in the 80 range!

               1. Okay, I was off by 11 months. Call the Washinton Post and the New Your Times and report my error. It has now been 6 years and 1 moth since that peak. Report that fact as well.

               2. Nony,

                  If you re read the piece by Ron he had 3.5 to 4 Mb/d being added to 2014 output by 2016 so that brings us to about 80 b/d, at the time Ron was relying in part on the EIA’s AEO 2014 which had US output peaking at around 9.5 Mb/d in 2019, the EIA was wrong in 2014 as well. All scenarios of the future are wrong, it is statistically impossible to make a correct prediction, anyone who is surprised at failed predictions has little understanding of basic statistics.

               3. Projections should include a range of outcome…perhaps 3%.
                  Here is a Peak Plateau projection previously offered by Dennis, with the box indicating a range of less than 3%.
                  81Mbpd +/- 2 Mbpd
                  2014-2031

                  

               4. Ron, you’ve been wrong in many other areas in the past. Saudi Arabia, the world, the Bakken, etc. And always in the doomer direction of being wrong.

                  About a decade ago, at peakoil.com, you challenged me to find evidence of you doomering on Russian production. I responded with about ten quotes from your Internet history, showing you being too negative about Russian production since the early 2000s (and it hung in there fine, even growing slightly.)

                  You’d think you’d learn, just from being so often wrong.

                  And what “methodology”? Plotting monthly production charts? Reading peak oil blogs?

               5. Wrong about Russi? Dear God, how could I have been so wrong? Ditto for Saudi Arabia and the Bakken. All are well past their peaks.

                  Oh hell, I may have gotten the timing a tad off. I only wish I could have been perfect, like you with all your projections. By the way, what projections did you have the courage to make? Were you spot on? Please post your predictions and their accuracy. I don’t have them because I do not save everyone’s projections therefore, I cannot say, years later, nana, nana, nana, you missed!

                  Click on graph to enlarge.

                  

               6. But, but, but Covid, it delayed peak oil by 10-15 years….right???

                  It’s so nice we don’t have to hear those BS excuses about how Covid delayed the peak…that was painful to watch…

                  The fuel tank is at 1/3 and falling 1.5% each year, so 20 years till the shit really hits the fan…2045

            2. We didn’t hit a resource limited peak rather a a temporary peak caused by economic and political disruptions. Oil production and supply has been growing very quickly which shouldn’t happen if we hit true geologic scarcity.
               And if somebody actually predicated 2018. I would say they just got lucky.

               1. Global oil production levels are not just about geology. Its also dependent on some very big factors like geopolitical tensions, technological innovation, strength/weakness of economies and how that plays into affordability of and demand for the product, etc. Did I mention wars and pandemics, tariffs and sanctions, fracking and electrification, and of course the availability of credit or production subsidies.

               2. Jacob, when oil peaks, if it has not already, it will not be at a time when everyone is at their resource limit. Many countries have already peaked and are now in decline. Many will keep increasing for some time. And that will always be the case whether or not we have already passed peak. And there will always be political problems, and it doesn’t matter whether or not those political problems contribute to the peaking of world oil production. The world peak will be or was the peak regardless of political problems and even if a lot of countries are nowhere near peaking.

                  Hell, I thought everyone already knew that. Why do I have to point that so very obvious?

               3. Jacob,

                  Here is one such lucky guess from 2012, the medium 2800 Gb scenario was my best guess with a peak in 2019 (which was admittedly too low by 3 Mb/d). As far as production growing rapidly from 2020 to 2022, that was recovery from production falling by 8 million barrels per day in 2020/2021. Since 2022 output has been pretty flat at 81 to 82 Mb/d, more from a lack of demand than scarcity in my opinion. It may be that demand becomes the more important factor determining the peak, time will tell.

                  Post at link below

                  https://oilpeakclimate.blogspot.com/2012/07/further-modeling-for-world-crude-plus.html

                  

   2. Hans

      Before these posts contained forecasts, they just reported production history that was four months old. Since this site is concerned with peak oil that old data couldn’t tell us much. On top of that this site focuses on C C rather than all liquids which the STEO used to report. At some point a methodolgy was developed to convert the all liquids production data into C C production.

      Having done that the next issue became should we publish the projections. As Dennis says predicting the future is not easy and usually wrong. Add in the assumptions that had to be made to get to C plus C which only added to the probability that the forecasts would be wrong. Regardless the decision was made to put them out there in the hope that it would add to the discussions and bring forth alternate views.

      So there are two question that arise in making forecasts:
      1) What is the magnitude of the possible error
      2) What is the trend

      I have checked the projections for the past year and found that the July forecast for December 2025 was the highest at 85,074 kb/d vs the current 84,468 kb/d. The difference of 608 kb/d amounts to a deviation of 0.71%. So is that size of a miss significant?

      Perhaps and I think more importantly, is the forecast trend. Since the July post the December 2025 production forecasts have been slowly dropping. That dropping trend in a way may be saying that the world may be near max production next December 2025.

      Thanks for the comment because I now realize that in addition to reporting the monthly change in the December 2025 forecast, I should add the change from the month with the highest forecast production so our readers get a better sense of the trend.

      1. That’s a great idea Ovi! Thank you so much!

      2. Thank you for clarifying, Ovi.
         And thank you, Dennis.

8. Ovi, the above was a very well thought-out note. The elephant in the room is shale, which is not endless but has been politicized as being so by one group and maligned by another group as being wasted by a bunch of harebrained Big Oil idiots. The Williston, Niobrara, Eagle Ford and Permian are in early decline. A well-kept secret is that there are many fringe shale zones amenable to horizontal drilling. The large Eaglebine crescent is one such. The Powder River Basin is another. In the Granite Wash are hundreds if not thousands of drill sites, extending all the way from the old Stiles Ranch in Wheeler up to Hemphill county, and over into western Oklahoma as far east as Washita county. In the Cherokee Outlet is the Mississippi Lime, which is being quietly but expertly drilled by Tom Ward, formerly of Chesapeake fame. In essence, the thick and multi-bench Permian Basin has been developed so quickly, with the build-out of tremendous infrastructure, that it has sucked all the oxygen out of the room and obscured some very good drilling sites. It is ironic that most of the oil will have been drained from the Bakken and Permian at a $50-100 price tag, while the less developed fringe areas will likely sell into a $100-150 per barrel market. It probably goes without saying that along with the oil from all these fringe zones will come a huge amount of gas, because shale oil is a solution gas driven system–always. It is likely that the last bit of shale will come with more respect given to reservoir pressure, too.

   When does the absolute last shale oil get drained from the United States? In my view, which is no worse than most, that will be some time in the late 2030’s, maybe as late as 2050. There is little doubt that “coked” proppants will increase the recovery quotient by dropping the friction coefficient to keep the pores open, and when it becomes scaled, it will be well worth the money. It’s also likely that, since necessity is the mother of invention, there will be a cost-effective way of recycling produced water, disposing only the multiple recycled water into earthquake prone disposal wells. And then there’s refracking. Right now, since there’s no sensible place to put the produced water in some parts and also because the price of oil is–by inflation comparison standards–very cheap, there’s very little refracking going on. But once the barren land is all drilled out, watch out, it’s a whole new world out there. Pressure-impacted tube systems to seal off the toe and previous fracture zones can be installed, then new intercalated fracture zones blasted in, and in many instances you have a new oil well, fully capable of producing with the best of the parent wells. This is particularly interesting in the Bakken, where much of the shale is laminated–layers of sedimentary rock fitted flake-like, one atop the other. It’s not going to take much of a learning curve before it’s obvious which wells are amenable to refracturing.

   Shallow Sand was correct: the shale boom singlehandedly rescued the U.S. economy and put our country on a glide path to prosperity that otherwise would not have occurred, because the price of energy would have been too high using OPEC oil. In my view, shale will continue for at least another decade. It’s not going to be pretty, and it’s going to have to spread out, but the U.S. is a big country and the shale is out there. Hopefully there will be enough to last until machine learning, driven by artificial intelligence, will run all the equations, process all the algorithms, until the nut called nuclear fusion is cracked. And then we can use the few remaining hydrocarbons for feedstock to produce petrochemicals.

   So, you might ask, how do you know there’s “fringe” shale? Well, I own some of it, mostly bought on the cheap. I’m thinking specifically about a horizontal well on remote property that has produced like a gorilla for a whole decade. It’s off the beaten path, but believe me, it’s not a one-off–it was just drilled prior to the Permian Craze. I’m been waiting for a long time for the other dozen offset wells to go in. They haven’t. I’ll pass that on to my offspring. At some point, when the takings are slim in the Permian, someone will drill the offset wells, and that oil will likely sell for over $100 per barrel. It’s solution gas driven, of course, so there will be ample NG and NGL’s to sell as well. There’s a pipeline nearby, but there are no stream of trucks carrying produced water, no man camps, no waiting in line at the Burger King. It’s just a well that was drilled out in the boondocks about ten years ago, and it has been one grand champion producing son of a gun. The acreage is still fairly inexpensive, so my fervent wish is that they adhere to common sense reservoir standards and use 1,600 feet spacings–for optimal recovery. There’s a lot of land just like it right up the road, for, oh, say 200 miles. In my view, the shale has done more than just rescue us, and we should stop being derogatory or using the past tense in talking about it. The shale revolution is well underway, but it has left quite a bit at the roadside too.

   I’m an American. While I care about the peoples of the world, I care about the peoples of this country first and foremost. Peak oil doesn’t mean anything to me, but peak oil for domestic use means a great deal. By that, I mean we are now exporting one-half of all we produce. The term “peak” means (to me) the point where we can no longer produce enough for our own needs. That is the point where we have to scramble for oil. The lowest hanging fruit for the U.S. was oil that formed millions of years ago in source rock and subsequently migrated into oil traps that could be tapped by drilling into it. The best of all were “water-lift” systems with an underlying aquifer that lifted the oil until it was all gone, allowing you to drain the entire oil trap. We’re well past that. Now we’re down to blasting open the source rock to use the entrapped oil and gas within. The next phase is to go after the dregs. And I think there’s a lot of them. Shale may not be the ideal API gravity of 30 but it’s what we’re left with. Put your hands together for the shale!

   1. There’s definitely some “fringe shale”. Could add the TMS to your list:

      https://www.dnr.louisiana.gov/page/tuscaloosa-marine-shale

      Or the shallow Utica (not the tiny oil fairway that is actually good in OH, but the big parts that never worked out).

      I wouldn’t go buying minerals there. Or “count on it”. But there’s possibility that as technology (to include geological understanding of the resource) improves that fringe plays become economically feasible. I doubt anything soon. But, certainly we have already seen how capabilities improve over time and make shales feasible. Heck, I still remember Art Berman being disparaging about the Marcellus in 2010! How did that work out!

      I would maybe think just expansion of literal fringes (e.g. Divide County in the ND Bakken) happens first, before failed plays like the Miss Lime or TMS turn on again. But who knows. Bottom line is there is oil in place there. And the peakers have a many decades habit of getting surprised how technology improves and enables new resources to produce in the future.

      1. Mr. Maddox and Nony,
         Those are both excellent posts that shed light on future oil production probabilities.
         The amount of hdrocarbon-bearing rock in the US is simply enormous.
         Economics are currently sidelining vast swaths of oil-rich shale as you both have pointed out.
         One possible difference of view between you and me, Mr. Maddoux, is that I believe alternative sources (primarily natgas and/or electricity) will continue to supplant oil’s present functions.
         Thus, the “Stone Age not ending due to running out of stones” concept is apt to arise as demand for oil will continue to – relatively – decline.
         I spent some time yesterday reviewing the near-decade long production history of dozens of Upper Devonian wells in Pennsylvania (Geneseo, Rhinestreet, Burket, Middlesex, Genesee).
         Impressive – for the most part – to say the least.
         Whereas Gregory Wrighstone estimated EURs of ~ 3 Bcf in the southwest PA ‘core of the core’ (~1 million square acres), several of these wells have already produced between 5 and 10 Bcf and still throw off $75,000/$100,000 per MONTH using ATW pricing of $2.24/mmbtu.
         These are wells that have been drilled/frac’d using ~10 year old technology, are located on pads that are already developed (with Marcellus wells), and more can be brought into production quickly with minimal capital investment.
         And, in the basement, lies the Big Brother … the Deep Utica whose (relatively) few wells have regularly dwarfed the output from the shallower Marcellus on the very same pads.
         No, hydrocarbon carbon scarcity is simply not ‘in the cards’ for the North American market for the foreseeable future.

         1. The Deep Utica is separated (much deeper) than the Marcellus, so is not impacted by fracs. However the Upper Denovian may have some communication. Some people speculate this is why the Marcellus produces so well! So, I would not extrapolate “showcase” wells, to a general potential.

            There’s something additive there, in the UD, sure. But it was pretty clearly oversold several years ago. One of the reasons why development stalled after all the hype.

            If you want a really cautionary tale, look how Cabot sold the upper and lower Marcellus, where it really didn’t work out to get added resource. Too much communication of the fracs.

            I do think there’s a metric butt-ton (SI unit for landmen) of gas in the Deep Utica though!

         2. One other thing I wouldn’t count out, on a longer time frame, is the Monterey Shale. Yes, I know EIA pulled a boner there. And most of the industry wa not hyping it, even during peak hype. Harold Hamm said the faulting and other geology was too bad for shale development. But all that said, there’s a metric butt-ton of oil in place there. If they figure out how to access it technologically, it has huge potential.

            1. The thing keeping a lid on development of shale in “fringe areas” is the relatively low price of oil and natural gas.

               I was very anti-shale 2014-2019 almost solely because of the “breakeven lying” and the capital destruction during the time the companies had Wall Street convinced that shale was akin to a tech growth industry.

               Once Wall Street figured things out about shale, sanity showed up. I think the pandemic “did that.”

               Now shale execs think $69 WTI is too low for much growth. See Dan Doyle’s open letter to incoming energy cabinet member Chris Wright.

               I’m just glad our family has no natural gas, outside of some insignificant ORRI in the Hugoton.

               I suspect most of the fringe area growth will be around the big shale basins. It costs a ton to build out a lot of infrastructure in places like the TMS, and definitely a huge lift anywhere within California.

               Of course, if there is an oil price spike, that is always the worst time to drill, from the standpoint of expenses. Now is probably a great time to workover wells. We did two this year and have two identified for 2025, assuming nothing crazy happens.

               Our field saw a few new wells in 2024, drilled mostly by the guys who own the rig and literally do it themselves.

               1. Shallow,
                  Re ‘fringe area growth’ … CEO of Encino said it may take a decade to even delineate the Utica oil boundaries.
                  Cost of operations continues to plummet as described in January’s AOGR article.
                  Average lateral length ~15,000 feet, short drill times, 99% accuracy in target zone, minimal produced water, 80% recycled flow back cuts down on sourcing/disposal expenses.
                  Yeah, this is definitely a growth play.

               2. Coffee:

                  It’s a cute little play, but the oil window is quite small.

                  https://x.com/NextWaveEFT/status/1861469254006063106

               3. Nony,
                  There is actually quite a bit of oil beneath the ground in the Buckeye State.
                  About 8 years back, outfit called Enervest drilled/frac’d a few wells targeting the Clinton Sandstone.
                  Fairly shallow (4,000 feet?), short (~3,500′) laterals. Didn’t work out, but – again – should higher prices combine with advanced technology, the earl is still there.
                  Lottsa places/situations throughout the US like this.

               4. Agreed, there is oil in place. But we need to figure out how to frack areas that have a lot of clay or recover from areas that have low pressure. So, sure a lot in the future bucket. But it’s not a major play taking off right now as the Encino comment would seem to imply. OH is up 30,000 bopd in a year. That’s nice, but it’s like a month of NM growth.

         3. Gerry

            “My only purpose was to show that while yes, the Permian is the big kahuna, if you take all the “other stuff” it’s probably just as big.”

            There is a difference between the Permian’s high concentration of LTO and the distributed nature of “all of the other stuff”. The economics of the Permian basin along with access to pipelines and talent is just not as good in those other places. While other stuff is there, it will dribble out compared to the firehouse of oil coming out of the Permian.

            I see little chance of that other stuff impacting peakoil in the US.

9. Gerry

   Thanks for your thoughts on shale and the potential for a longer life than I think is there. My knowledge is limited and am just going by what I can extract from the New Mexico and Texas RRC data. Shale will be around for a long time. The issue is at what level?

   With regards to your last paragraph, I see the US exporting light crude in exchange for a heavier crude that the Texas refiners like. Unfortunately at this point there seems to be an imbalance in that more crude is imported than exported. Not sure of the economics of swapping LTO for Saudi crude.

   Closer to home I have a better idea. I wish that your new Guy would have a little more respect for the US’ friendly northern neighbour rather than imposing 25% tariff on all imports. As you are aware, Canada has either the second or third largest oil reserves after Saudi Arabia and exports little over 3 Mb/d to the US. Our oil, Western Canada Select is sold to US refiners at a discount of $12/b to $15/b. That sounds like a good deal to me for the US refiners and the supply is secure and guaranteed. Also XOM owns a lot of it.

   I hope that saner minds prevail down there and your Energy Czar finds a way of strengthening both of our economies and securing our future demand for oil.

   https://boereport.com/2024/12/12/discount-on-western-canada-select-heavy-crude-widens-slightly-2/

   1. Ovi. In my view, there will not be tariffs on Canadian oil imports. There might be on most everything else, but no way on oil.

      1. SS

         I hope you are right.

   2. “I hope that saner minds prevail down there”
      Me too. Threatening your friends, neighbors and premier trading partners (Mexico and Canadians) as if they are foes is an approach that most Americans did not vote for. Keep in mind that only about 23% of Americans voted for that approach.

10. GERRY MADDOUX & GROUP,

    Yes, it is certainly true that U.S. Shale Oil & Gas not only put the United States back on the top again, it also allowed the Chinese Economy to become the world’s largest manufacturer of goods. The U.S. Shale Oil Industry accounted for 85 % of Global Liquids production growth since the 2008 GFC – Global Financial Crisis.

    However, the contributing factors that allowed the U.S. Shale Oil & Gas Bonanza, seem to be overlooked, are zero interest rates and massive U.S. Govt Debt.

    Since the 2008 GFC, U.S. Public debt increased from $9 trillion to the current $36 trillion. During this same period, U.S. Shale Oil & NGLs production increased 13.5 Mb/d. A tremendous feat, indeed.

    Why did U.S. Govt Deficits and Debt increase significantly since the 2008 GFC? We didn’t see the same thing after WW2 until the early 1970s. The deficits began to increase significantly after U.S. peaked in conventional oil production in 1970, and especially after Global Conventional peaked in 2006.

    Going forward, while U.S. Shale Oil & NGLs production will likely increase a bit going forward, most of the new production will be used to offset the massive annual natural decline rate. Thus, there will no longer be another 13.5 Mb/d of growth coming from the United States Shale Industry.

    So, the BIG QUESTION that seems to be ignored by the market, is how much debt will be needed to just maintain the U.S. Standard of Living with very little Shale Oil Growth?? And, if Trump & Musk do start Deficit Spending Cuts, as they claim they will do, then that means… it GUTS the U.S. Economy and GDP that has been propped up by the massive Govt Deficits and Debt.

    Thus, if Govt Deficits are cut, U.S. Economic activity declines and with it, Stock and Asset values. Why? Debts are propping up the Asset values on the other side… something seemingly ignored by the market.

    The next four years are going to be quite interesting.

    steve

    1. How did this peak shale gas prediction work out for you?

       https://peakoilbarrel.com/collapse-of-shale-gas-production-has-begun/

       1. Anonymous,

          Shale has certainly humbled many people, me being one of them. However, the question still remains about the Debt, Deficits and zero interest rates.

          steve

          1. From VA, currently in Eastern Europe.
             Life is good, they are talking about tight 3% budget deficit, practically no oil production.
             Maybe one day our great USA will get there. 😆 🤣 😂

          2. SC. Aren’t you a gold guy too? That hasn’t been a bad call over the last 25 years.

             1. Shallow,

                While I analyze and recommend precious metals as a store of value, I wouldn’t label myself as a Gold Guy. But, I know that is a label mainstream investors use.

                The reason the Gold price has done well over the past 25 years, comes down to the Cost of Production based on central bank money printing. Interestingly, in 2019, the Top Gold Miners, Barrick & Newmont’s Total Combined Cost was only $1,241 based on $1,333 Average gold price for the year.

                However, after the Pandemic Shutdown and the massive amount of Money Printing & Stimulus, inflation in goods surged higher, especially for the Gold Miners.

                As of Q3 2024, Barrick & Newmont’s Combined Cost is now $2,041 based on an average quarterly gold price of $2,506. So, the Gold Market price is keeping up with the Cost of Production for the Major Gold Miners.

                Unfortunately, Trump will have to continue with the U.S. Treasury printing, even though Musk says that DOGE is going to cut $2 trillion from Govt Spending. If Trump-Musk cut $2 trillion in Govt Spending, that will destroy U.S. GDP and employment.

                So, I believe no one stops the Printing Train or else, we head into a Depression we never recover from.

                steve

                1. Sorry, didn’t mean to refer to you in a negative way.

                   I don’t have much gold or silver, but what I did acquire decades ago is still in the lock box and I assume it will stay there until the kids get it out after my wife and I are gone.

    2. Wonder how much of that $10 trillion COVID money is in the stock market right now?

    3. “The deficits began to increase significantly after U.S. peaked in conventional oil production in 1970, and especially after Global Conventional peaked in 2006.”

       Most likely because we left the gold standard as gold was a restraint on the money supply growth. Do you agree?

11. If worldwide there are 8-10 Tb of crude oil equivalents in place, primary recovery would yield 1,200 – 1,500 Gb. Secondary recovery might see a similar amount, for a smaller volume (500-750 Gb), recovery factor might approach/exceed 50%. This means 7-9 Tb only 2 Tb is recoverable, for ~1 Tb half is recoverable (0.5 Tb). This yields a URR of 2,500 Gb. If we add cumulative production to 2P (~700 Gb) we get a URR of only 2,200 Gb. This is the “most likely estimate in existing fields”. We can also look at the conservative URR of ~2,000 Gb. Looking to a much more optimistic estimate (2PC) we might have a URR of ~2,700 Gb. And of course we could average all 3 and get a URR of 2,300 Gb.
    In all cases the peak (50%) production was between 5 and 25 years ago…

    Some here are tempted to revise these values upwards…I understand the temptation…so let’s pretend that we have net additions (discoveries/growth) of 8 Gb/year for the next 20 years. Even so, this lands on the 2P scenario and oil is effectively exhausted by ~2043. Since we are running at peak production, we can easily burn thru 10-15% of URR each decade…

    Some others have said that much of the oil will stay in the ground, if decline is too steep then I see that as a logical conclusion, if we can gradually reduce production by 3-5% annually then I think we will find a way to get it all…time will tell.

    1. Kengeo,

       The OOIP for all oil resources is probably more like 15 Tb, 10 Tb would be conventional oil resources only, unconventional oil adds at least another 5 Tb of OOIP resources.

12. We can surmise that URR (that matters) is nowhere near 3 Tb since global conventional production growth ended about 20 years ago. I’m not sure it will matter how much unconventional oil is in place since it’s likely not very recoverable (3% or maybe 5%?). It could make up a very long tail at extremely low production volume, but wont do much in the grand scheme of things…

    Changing the subject. What impact has inflation had since the 2018/2019 peak? In theory a $65 barrel of oil in 2018 terms should be approaching $85 by now??? But it’s trading 20% below that level, is this sustainable for the shale drillers?

    1. Conventional oil peaked in 2016, which is 8 years ago, not 20 years. Cumulative output was about 1273 Gb at the end of 2016. If we assume peak occurs at 50% of URR and that the output curve is symmetric, this suggests a URR of 2550 Gb for conventional oil. Unconventional oil URR could easily be 250 Gb and that is likely conservative. Much will depend on future demand for oil which is unknown.

       Big oil companies like XOM claim they can drill tight oil wells profitably at $60/bo, maybe they are lying, but I watched a presentation in early December and they seem to believe what they say. Presentation at link below.

       https://event.webcasts.com/viewer/event.jsp?ei=1686800&tp_key=1320d23f2e

       1. Kengeo,

          Also keep in mind it is the expansion of unconventional oil output that has kept conventional oil output low since 2016, when unconventional output starts to decrease conventional oil output will grow, currently OPEC plus (aka DoC nations) are keeping about 3000 kb/d of conventional output off the market to support the price of oil. If this oil was added back along with conventional oil output growth from Guyana, Brazil, and Norway we could exceed the 2016 peak, if there was enough oil demand and/or unconventional oil output decreased.

13. North Dakota production for October, 1,178,062 barrels per day.

    Click on chart to enlarge.

    

    1. “Operators have drilled ~80% of Tier 1 locations and 60% of Tier 2; less than 2,000 Tier 4 locations have been drilled to date. Beyond that, we estimate >50% of remaining Tier 1 locations are encumbered by surface issues, such as rugged badlands topography, lake cover, or sitting in National Forest lands. Much of the remaining Tier 1 beyond that is infill.”

       https://x.com/tedcross/status/1867589662283337844

       https://pbs.twimg.com/media/GesCuhwXMAA0Pz-?format=jpg&name=900×900

       1. Thanks Tomas, great stuff.

14. Latest ND Director’s Cut:

    https://www.dmr.nd.gov/dmr/oilgas/directorscut

    If you click the link for the DC, you will get a pdf of the report. This month’s ideo was not posted yet, but should be soon. I listened to the MS Teams call.

    Oil was down about 2% (22,000 bopd). Reason was wildfires. Most of that returned in NOV, but some remains offline (where pads were actually damaged as opposed to shut in as a precaution).

    Gas (~3.5 BCF/d) was down about 5% versus last month. Location of the fires was near the high GOR wells so gas affected more than oil. Gas capture percentage was similar 94% versus 95% as most of the wells were shut in, not vented.

    Differential for oil in basin (actually MN clearinghouse) versus East Coast remains a few bucks, slightly widening.

    Some minor infrastructure projects are progressing. One intra-ND gas pipe (~.75 BCF/D) is in very early stage of investigation, but is a project that has not gotten off the ground for 10 years now.

15. ““We expect that China’s oil demand will continue to rise in 2025, but almost all of the growth will be accounted for by petrochemical feedstocks. Demand for transport fuels is likely to decline,” Wood Mackenzie wrote in a recent set of predictions for next year. The consultancy also said it expected global diesel demand to rise next year but only marginally, thanks to China’s new obsession with LNG trucks, which would undermine growth in this huge consumer. Wood Mac also predicted a decline in China’s gasoline demand because of EVs and growth in jet fuel demand that would not be able to offset the declines in the other fuels.”

    https://oilprice.com/Energy/Crude-Oil/China-and-US-Shape-2025-Oil-Predictions.html

    1. Hickory,
       “… China’s new obsession with LNG trucks”.
       Eggzacklee.
       This aligns with my above response to Mr. Maddoux’s comment regarding the displacement of the use of oil in the transportation realm with non oil alternatives … natgas and/or electricity being the most prominent.
       Folks who have not followed the eye watering advances in LNG/CNG infrastructure and hardware development are apt to be taken unawares of what is shortly coming down the pike.
       As of today, retail CNG prices in the Los Angeles area are $2.25/$2.50 per GGE (Gallon of Gasoline Equivalent).
       Retail diesel is running about $4.70 per.
       Commercial operators will be on that like white on rice when it becomes more widely accessible (the Cummins 15L, that is. Fuel supply is already available).
       The 15L is what is driving the current paradigm shift in China.

16. Goehring & Rozencwajg

    “U.S. shale production may have peaked in late 2023, with declines in both oil and gas output. Despite optimism, the downturn is driven by geological limits, not just market or policy factors. Advanced AI models suggest the shale boom is over.”

    https://blog.gorozen.com/blog/the-depletion-paradox?utm_campaign=3762791-2024 3Q Commentary&utm_content=319857691&utm_medium=social&utm_source=twitter&hss_channel=tw-940698796903878657

    1. Tom,

       A nice piece, but I disagree with the claim the tight oil peaked in 2023, chart below has regional C plus C output from 5 major shale plays. I agree tight oil will peak, but doubt it will be before 2027. I expect future tight oil growth will be at about 200 to 300 kb/d per year. On the chart title I mistyped Bakken.

       Data from

       https://www.eia.gov/outlooks/steo/data/browser/#/?v=9&f=M&s=0&start=201901&end=202512&ctype=linechart&maptype=0&linechart=COPRPUS

       

       1. OK, Dennis !

          “Time will tell”

          “Only the future will tell”

    2. These guys have a consistent record of underestimating shale. Yet, they keep putting out similar reports.

       I will grant they are well written and occasionally have some interesting content. But in general it’s just same old, same old, preaching to the peak-oil/price-bull choir.

       1. G&R did a ‘hit’ piece on CNX a few years back.
          Claimed that they were running out of drillable acreage and were misleading investors by claiming several decades’ were available to develop.
          Well, when one looked closely at the numbers depicted in the G&R report, turns out that there WERE tons of locations left, just somewhat shorter (7,500′ laterals would be possible due to the vast – yet discontiguous – nature of their holdings.
          Ongoing consolidation/land swaps may help CNX somewhat, but there is no doubt that they control a lot of land … much of which is outright mineral ownership – not leasing – due to their legacy coal history.
          I would be wary of putting much faith in self proclaimed proprietary AI analysis with these guys.

17. New posts are up

    https://peakoilbarrel.com/opec-update-december-2024/

    and

    https://peakoilbarrel.com/open-thread-non-petroleum-december-19-2024/

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