Peak Oil Barrel

109 responses to “US May Oil Production Hits New High, Again”

1. Jean-François Fleury

   08/04/2025

   Thank you for the post, Ovi. Are Texas oil production statistics becoming as reliable as those published by some OPEC countries? Are there any secondary sources for Texas oil production?

2. Ovi

   08/04/2025

   Jean

   I would not say they are unreliable. Texas production data is accurate because the drillers have to pay royalties to the Tx government based on their production.

   The issue appears to be the time taken to process all of the information from all of the drillers and the errors associated with their input.

   In April a driller in Reeves county entered the wrong data. When he figured out his royalties he realized he had made a mistake. Unfortunately the data affected all of Texas along with District 8.

   I notified the RRC and they were able to fix it for May but for some reason could not change the published April data.

   If there is a reasonable monotonic change in the production data, MoM, then it gives me a feeling the data may be up to date. Regardless after a few months the data gets corrected.

   1. Jean-Francois Fleury

      08/05/2025

      Thanks for the précision.

3. Anonymous

   08/04/2025

   Thanks Ovi.

   Maybe it’s time to move OH to its own chart. Put MT and LA together if you want. OH is actually close to UT than it is to LA.

   1. Ovi

      08/05/2025

      Nony

      Thanks for the suggestion.

      Actually I was thinking of shortening the report a bit by getting back to the original definition of more than 100 kb/d. In that case I would drop MT and LA all together and just keep OH. I would continue to track them in case things changed.

      Other opinions invited.

   2. Anonymous

      08/05/2025

      Makes sense.

   3. Ervin

      08/05/2025

      Remove the red channel from Alaska.

4. Ovi

   08/05/2025

   In the Martin County report above, I raised the following question: “With the Martin County rig count falling, one must question how can production continue to increase?”

   It seems that Yahoo/Reuters saw my question and has provided an answer.

   “Sliding US rig count outpaces efficiency gains, threatening onshore oil output

   HOUSTON (Reuters) -The falling number of oil and gas rigs deployed across the United States is reaching a level that would indicate onshore crude output from the world’s top producer could fall in early 2026.

   U.S. energy companies are producing record amounts of oil, much of it from onshore shale fields. New techniques and technology, like longer lateral wells, automation and more powerful equipment, have driven productivity gains across the industry that have allowed oil companies to pump more with fewer rigs and less capital.

   But the number of rigs working in U.S. shale fields has almost fallen so low – and is projected to keep falling – that those improvements will not be enough to keep onshore U.S. production rising, or even steady in some basins, analysts say.

   “Right now virtually all operating rigs are the most efficient and highly upgraded rigs available. Drillers saw big efficiency gains because they upgraded to a bigger rig but there are no bigger rigs left to upgrade to,” said Paul Mosvold, president and COO of Scandrill, whose company has seven rigs in the Haynesville and four in the Permian.

   “We have seen a 25% improvement over the last few years in rig efficiency, but the rig count has fallen over 30% over that same period. Put simply, the rig count declines have begun to outpace drilling efficiency gains,” said Brandon Myers, head of research at Novi Labs.

   Despite improvements to drilling technologies, oil wells in the Permian basin are becoming less productive as operators have drilled through a lot of the best rock. Those less productive wells cost more to drill and are producing more unwanted byproducts such as gas and water, and less oil.

   The Permian’s Delaware and Midland sub-basins have seen oil per foot drilled fall 8% so far in 2025 compared with last year’s average, Morgan Stanley (MS) analysts said in a July note.

   “In 2020, when the rig count fell, operators drilled the best rock they were ever going to have. That high-quality inventory doesn’t exist in that quantity anymore, and operators won’t be able to do that again to the same degree,” said Novi Labs’ Myers.

   There is lot more in the article

   Bottom line: A consensus is developing that within a short while the US will be close to peak oil production.

   https://finance.yahoo.com/news/analysis-sliding-us-rig-count-090618587.html

   1. Iver

      08/05/2025

      This is exactly what OPEC have been waiting for and in part engineering. OPEC knew that while the United States was increasing production they had to cut production to maintain prices. Now however OPEC, with the cheapest oil on the planet can increase production. The price of $70 and below, is not great for them but a disaster for many American producers.

      OPEC is now back in control of the market, at least while they have spare capacity.

5. Anonymous

   08/05/2025

   Ovi:

   Some of that “efficiency” gain is really just high grading. Like a running team getting faster on average because I cut the slowest runners. Not because each runner actually got faster individually.

   As rigs roll off, the work done tends to be on the better projects geologically (well, really financially…but on average these are in the sweeter spots). If you are only going to do 90 of 100 projects, you tend to cut the least profitable ones. Same things happens with crews and with the mechanical equipment…you idle the weaker ones first. But just project selection is maybe the most important.

   I’m not saying there are no improvements in efficiency itself. It is a manufacturing process and they can learn by doing. Probably the area where you can look at efficiency the most is just “speed” (lateral drilled by same rig). And sure it improved during the shale revolution. But…I suspect a lot of any recent improvements in the DPR (if that still existed), would be from high grading, not from people getting smarter.

   I think pretty much the consensus view is that US production is looking at a long plateau. Maybe slight growth to end of the year and then an ultra slow decline. It won’t fall off a cliff though. There’s a lot of inertia in the system and replacement drilling can probably keep production averaging above 13 for the next several years. [Assuming no price crash. Or price boom. Or temporary, short ones only.]

   There’s still some growth, slower, but still, in the Permian. And that compensates for a relatively slow decline in the Bakken/Eagle Ford/conventional. Probably GOM is flattish in the 1.8 range for a long time. Tiny growth in UT and OH, but those are really just interesting local stories, not counteracting decline in other regions.

   It’s basically Total of 0 = Permian change (up) plus rest of US (down). Arguably it’s been non-zero total for the last year, but very small positive. Will shift to very small negative. Won’t be some sort of wet dream peaker accelerating decline though. There’s just too much inertia in the system (sunk cost of infrastructure, high grading, etc.)

   Also as shale ages, it actually becomes lower decline. A well has a tremendous decline rate in its first year. But a 10 year old well will have a very low rate of decline (10% or less). Stripper wells are an extreme example with almost zero decline.

   As the overall population of shale gets older on average, you have more and more “stripper-like” wells that are low production, but also very low decline. And less drilling is needed to keep production flat, then.

   1. shallow sand

      08/05/2025

      As has always been the case (except for 2017-19, when the shale companies were really spinning some bullshit about their profitability) the oil price will have a major influence on future US oil production.

      Go back and look at what happened after the first peak in 1970-71. Production strongly correlated to oil price, with a lag.

      With regard to the 2017-19 time frame, I sometimes wonder if it just didn’t take the shale companies a long time to realize that $90 oil was the anomaly and not the the new norm. So, as prices stayed well below that, they had to make up “break evens.” The COVID collapse broke that.

      I think if WTI stays in the $60-70 range, a long plateau might be right. If demand lags and there is a drop below that, a bigger drop, and vice versa if demand worldwide continues to grow.

   2. Ovi

      08/05/2025

      Nony/SS

      Thanks for your thoughts.

      I think we will know within three or four months whether the US production has peaked. We need to see July and August production data. July/August is roughly six months from when the rig count started to plunge.

      Hopefully the next set of data that the RRC produces will clear up what is happening in Martin and Midland counties. Having better knowledge of what is happening in those two counties plus Lea and Eddy over the next few months will set the tone for US production going forward.

   3. Anonymous

      08/05/2025

      I would anticipate a US oil peak in OCTish2025.*

      Think there’s still some seasonality (e.g. ND summer recovery). Then in NOV/DEC we start getting winter effects. Some recovery next spring but not same level. But…a very slow decline (that for all effective purposes is more of a plateau). It won’t “accelerate”, won’t be some Seneca Cliff fantasy drop.

      This assumes of course that we don’t have a large price drop (or rise).

      It’s impossible to predict world events, but I sort of see more danger of peace breaking out than of war breaking out (in both Ukraine and the ME, or at least one of them). And peace…lower prices. War…higher prices.

      I suspect Trump will TACO on the secondary sanctions. He seems like he is full of bluster. Speak loudly and carry a wet noodle. Like the inverse Teddy Roosevelt.

      *Not to be Deffeyes-like! 😉 https://www.youtube.com/watch?v=_2aE2gdvM0U

   4. Ovi

      08/05/2025

      Nony

      I could buy your OCTish 2025 bet.

   5. DC

      08/06/2025

      My tight oil scenario (DC scenario) compared with EIA AEO 2025 tight oil reference scenario.

   6. Sheng Wu

      08/06/2025

      if EVs really destroy the oil market, it will be a market peaking first fast and earlier in 5 years.

      Another country joined the EV boom, Nepal, which might replace 50% ICE by 2026, and almost all using hydro-power, and 95% by 2030

   7. Nick G

      08/07/2025

      Peak China ICE

      https://peakoilbarrel.com/open-thread-non-petroleum-august-4-2025/#comment-791548

   8. Dan

      08/07/2025

      Dennis,

      I wish I could meet you in person, but in the meantime, cheers and thank you for your hard work visualizing our energy predicament.

   9. DC

      08/07/2025

      Thanks Dan,

      I invite the discussion and criticism that Nony, Coffeeguyzz, and many others over the years contribute here as it improves my work.

      If we assume the AEO and DC tight oil scenarios define a 2 sigma (95%) confidence interval assuming a normal probability distribution and assuming the one sigma (68%) confidence interval is intermediate we have the following (which is certain to be incorrect, it is a WAG).

6. DC

   08/06/2025

   Ovi,

   Your report is fine as is, tweek it how it makes the most sense to you. There will always be criticism, ignore it.

   Thanks for your work here, it is appreciated by all.

7. Anonymous

   08/07/2025

   I would be wary of taking DC and EIA as two estimates to split the baby between. I think the true uncertainty is higher and you have to include more upside from EIA and downside from DC, especially when looking so far out.

   My gut feel is that EIA is already a median, for US C&C. EIA is more the “economist view” that extraction technology will continue to improve (as it has for the last 150 years), especially when considering decades out timelines. Dennis Coyne is the classic peaker “resource/reserve” estimate methodology. Over the last two decades (or even last two centuries), the economists have proven more prescient than the geologists. But that is just my personal, gut, feel, from following the drama for years…and from being an analytical guy in real life (but not an industry person, I’m a “civilian”).

   And that we will continue to find new resources. This can happen in existing areas (look at the “old” Permian, e.g.). Or it can happen in areas like AK or the VACAPES that are tremendously underexplored, but are “sedimentary basins (in the terminology of M. King H.). Yes…I know the librulz don’t want to drill near the polar bears or the sea turtles…and these preclusions may in fact continue or become stronger. But…a refusal to allow exploration/drilling/production is a lot less firm constraint than just not having the resource in the ground. On the time frame of decades, policies can be changed…especially if prices increase…look how poplar drill, baby, drill was. And how even the Democrats wanted to be disassociated from high gasoline prices, at least at election times.

   I actually think the (US) oil is closer to getting figured out than the natty. It is a much more viscous fluid…and has been more aggressively developed (because of economics). The uncertainty to the upside for US natural gas is massive. Not saying it happens (especially given how it is market limited, lot easier to put oil on a ship than natty). But it sure might. The vastly different Utica TRRs (from serious researchers, Boswell had a 59 h-index…the WV BEG and PGC are full of Ph.D.s) should give the peakers pause. You don’t even have to believe the corny view…just open your uncertainty window.

   1. kolbeinih

      08/07/2025

      Mr. Anonymous (or Nony as called by some others)

      It is definitely a very strong case that technology has been the main driver for better exploitation of about anything the last decade. Raw computational power combined with artificial intelligence has been able to shift the curve of what is possible (not only in the US ofcourse).

   2. Nick G

      08/09/2025

      “technology has been the main driver for better exploitation of about anything the last decade”

      Tech aka IP aka innovation, has been the main driver for thousands of years. It’s just that lately it’s been accelerating.

      The Romans had coal. They had oil, they just didn’t know it or know how to make use of it.

      The Victorians had solar energy, they just didn’t know how to make use of it the way we do now.

   3. Alimbiquated

      08/09/2025

      Anonymous —
      The economic idea is that oil consumption is roughly proportional to the site of the economy. so it grows with the economy. The geology argument is focused on the rocks. Both give nods to technical innovation, but don’t attempt to model significant or previously unexpected technological advances.

      The claim that EVs will cut demand enough to reduce production puts technological change in the center of the model instead of on the periphery.

   4. D C

      08/10/2025

      Nony,

      Could be that uncertainty is much higher, EIA estimate might be too low or too high. This is my estimate, yours would be different. My underlying assumption is oil, NGL, and natural gas prices at current level or lower in 2025$. Future prices are unknown, especially for next 25 years.

      Two competing things, resource depletion causing increased cost and technology reducing cost. Not clear which wins short term, long term my guess is that depletion wins. The US offers few new opportunities for oil at reasonable cost relative to more resource rich areas.

8. Anonymous

   08/07/2025

   I would also look at current oil and gas prices, and adjust for inflation.

   https://www.bls.gov/data/inflation_calculator.htm

   Whodathunk, even as late into the “revolution” as 2015, that we’d be sitting at over 13MM C&C and over 130 BCF/d (total withdrawals, includes AK). And doing so at ~$48 WTI and ~$2.25 Henry Hub (in 2015 constant dollars). That’s been a growth of over 30% volume…and in a relatively low price environment.

   ————–

   Again, in 2015, you couldn’t any longer say that shale oil (or gas) was a black swan event, that would happen after 2015. Had been in the news massively (even annoyingly, if you were a peak oil afficionado…look at the death of ASPO and TOD). But even when known…shale outperformed median industry estimates (e.g. EIA). And DEH-fun-itely outperformed the peaker shale skepticism (“reality doses” from Berman, Hughes, Coyne, et. al).

   And what gets me about the Hughes and RuneRedQueen bunch: It’s not just that they were wrong. Happens. But wrong to a consistent side.

   And…instead of reacting the the “black swan” (which had emerged by 2012 at the latest), with uncertainty, with curiousity, with humility. Instead of that…they jumped into the discussion battle to aggressively counter any cornie hopes. It is child’s play to come up with the gazillion “shale is overrated” articles from the peakers. Almost more like advocacy than analysis. Like instead of saying there was something new on the battlefield…let’s be cautious and just figure it out…they just jumped on the hand grenades, with pompous articles.

   1. Iver

      08/08/2025

      Anon

      Peak oil alarmists did not just refuse to see the potential of shale. The worst ones, who unfortunately got the most publicity underestimated resources everywhere. Colin Campbell was quoted as saying British North Sea oil would be gone by 2020. Thankfully it is still producing over half of U.K. demand.

      Matt Simmonds claimed Saudi Arabia was on the verge of irreversible decline, that was in 2005.
      The Peak Oil movement was taken over by the worst doomsayers like Ron who has been claiming since 2012 that global oil production is almost certainly in steep decline. You can find his quotes on The Oil Drum.

      Sensible analysts could see both the effects of technology but also the inevitable decline.

      Once all technology has been used, decline will follow as there is a certain amount of oil in each reservoir.
      The list of countries where technology has reached a limit and production is in decline is growing almost each year.
      Mexico, Colombia, Norway, U.K. Nigeria, Angola, Oman, India, Australia, Egypt. The list goes on.
      Shortages are effecting various countries, oil reserves running out, coal, water is the immediate threat to Iran and Pakistan. Oil was too cheap and over used, water practically free and abused beyond limits and all good things come to an end.

   2. gerryf

      08/08/2025

      Iver,
      Peak oil alarmists did not just refuse to see the potential of shale. The worst ones, who unfortunately got the most publicity underestimated resources everywhere. Colin Campbell was quoted as saying British North Sea oil would be gone by 2020. Thankfully it is still producing over half of U.K. demand.

      I can find an old Colin Campbell piece (2001 maybe?)
      Now let us look at the North Sea in Fig 1A6. It shows a very similar pattern. Discovery very clearly peaked in 1973 and it’s a long time since a giant field was found there. The corresponding production peak was predictably passed in the United Kingdom in 1999, and output is falling fast.

      More recent data shows the production did peak in 1999, and by 2020 had dropped by 70% from it’s peak value.

      So did he get the prediction correct, and it’s just the time scale that’s wrong?

   3. Iver

      08/09/2025

      Gerryf

      As I said Peak Oil is an obvious fact, over half the oil producing countries are in decline.

      Where the alarmists were wrong was to totally dismiss how prices could bring on better rigs, more expensive technology etc. The U.K. was producing 800,000 barrels per day in 2019, that is a world away from zero. Predictions about other countries were far worse.

      On The Oil Drum charts were being presented of global production being down to 40 million barrels by now. Ridiculous!

      They underestimated new discoveries, they underestimated ability to extract more oil from existing fields. Not surprising as most of them were not geologists.

   4. Paul Pukite (@whut)

      08/09/2025

      “Not surprising as most of them were not geologists.”

      Professional oil geologists don’t get paid for predicting their own demise.

   5. Iver

      08/09/2025

      Paul

      I do remember your predictions were way off the mark also.

      You had global production down to 60 million barrels by now.

   6. Sheng Wu

      08/09/2025

      Pessimists

   7. Paul Pukite (@whut)

      08/09/2025

      iver,
      Right on the money as far as published conventional crude oil production.

      Also right on the money with models of El Nino (ENSO), QBO, Chandler Wobble, and various other geophysics behaviors.

      Earth scientists don’t know much about using advanced applied mathematical techniques, which is why the book Mathematical Geoenergy exists.

   8. gerryf

      08/09/2025

      Iver
      The U.K. was producing 800,000 barrels per day in 2019, that is a world away from zero.

      But that 800,000 bpd is still 70% lower than the peak in 1999.

      Sounds like the peakers were right about the peak, but got the tail of the distribution wrong??

   9. Paul Pukite (@whut)

      08/10/2025

      “Sounds like the peakers were right about the peak, but got the tail of the distribution wrong??”

      The classical Hubbert peak is mathematically known as the derivative of the logistic sigmoid curve. This has an exponentially declining tail, which will always be wrong for modeling a so-called “fat-tail”, or one that has a slow decline. The history behind that curve is more borne out of convenience than modeling the details of reality, where fat-tails are common — just consider reservoir size distributions.

   10. DC

       08/08/2025

       Nony,

       Here is the AEO Reference case for US tight oil in 2015 vs Actual US tight oil output through 2014. It was not only the peak oil crowd that underestimated tight oil potential.

       See https://www.eia.gov/outlooks/archive/aeo15/excel/aeotab_14.xlsx

   11. Anonymous

       08/08/2025

       Perfect example of why using EIA and DC as two bounds of uncertainty was a bad idea. I told you over 10 years ago that uncertainty was higher. And that you needed to consider upside from EIA, not just downside, as a reasonable risk.

   12. DC

       08/08/2025

       Nony,

       Your guess was correct then, the EIA estimate was not very good, my expectation was that the EIA estimates would be on the optimistic side, but looking back at World liquids forecasts for the reference case they have been quite good, even though they got it wrong early on with tight oil.

       As I get new information I adjust. Here is a US tight oil scenario from Sept 2019, URR=92 Gb, peak in 2026 at 10.54 Mb/d.

   13. Anonymous

       08/09/2025

       It was always reasonable that EIA uncertainty about US would be higher than about world. World was larger for one thing, just to be simplistic. Some self-averaging.

       Also, the world volumes are certainly strongly affected by trends in demand, not just supply. A radical growth in world volume is unlikely because the demand is not there (relatively inelastic). In contrast, the US could grow at the expense of other producers.

       Also, world involved more conventional. US definitely more of a new technology and in flux and at prey to world price. Thus their different scenarios for the US, within the AEO, with a pretty wide spread.

   14. DC

       08/08/2025

       In the comment linked below is a model I did in April 2015 for ND Bakken/Three Forks and Eagle Ford

       https://peakoilbarrel.com/eagle-ford-permian-basin-and-bakken-and-eagle-for-scenarios/#comment-514469

       Data for these two plays from Jan 2008 to April 2024 in chart below.

   15. Paul Pukite (@whut)

       08/08/2025

       Spot. On.

   16. Paul Pukite (@whut)

       08/08/2025

       Prediction made by Dennis in 2015

   17. Paul Pukite (@whut)

       08/08/2025

       2015.

   18. Anonymous

       08/08/2025

       1. How’d ya do on the Permian?

       2. It’s hilarious to me how many different scenarios you’ve made (including buried in comment threads). Sometimes when someone here (more peaker than you) criticizes your prediction, you’ll even make another line chart with alternate, lower, numbers. Just to mollify the crowd. Can’t even tell what you really stand behind.

   19. DC

       08/08/2025

       Nony,

       In 2015 I didn’t have enough information on the Permian Basin to make a prediction. The USGS made estimates of the Permian Basin on 2016, 2017, and 2018. Once I had all three estimates which covers the bulk of Permian tight oil output, I created the following scenarios based on the mean TRR estimate as well as the F5 and F95 TRR estimates and a set of economic assumptions based on known CAPEX and OPEX costs in 2018 and using the AEO reference oil price scenario as a guide to future oil prices.

   20. Anonymous

       08/08/2025

       Did you have an overall US (or all US LTO) prediction? I.e. which would have necessarily contained the Permian?

       Not even a rhetorical question. Just straight asking.

   21. DC

       08/10/2025

       Nony,

       In Feb 2019 I created the following scenario, it uses the medium Permian scenario from previous chart and my Bakken and Eagle Ford medium scenarios from that date, the rest of the US LTO was a very rough model based on production data and a guess at the well profile for tight oil not produced in the largest 3 plays (Permian, Eagle Ford and ND Bakken/Three Forks. The data presented is current (july 2025 tight oil data). The URR of this scenario is about 80 Gb.

   22. Nick G

       08/08/2025

       Dennis, I looked back at the 2015 discussion and found the following:

       “Dennis Coyne
       04/29/2015 at 9:34 am
       Hi Nick G,

       I agree that long term price elasticity of demand for oil is higher than in the short term and that oil prices matter.

       It is not clear to me that a real oil price of $100/b in 2015$ will be enough by itself to reduce demand for oil. I also see no reason why $100/b (2015$) would be the limit on oil prices, I think by 2025 (or sooner) we will see $150/b (2015$) or maybe higher. This may crash the economy or it may lead to widespread substitution of EVs, light rail, rail, and other forms of transport for internal combustion engine driven transport in trucks and cars. It is not clear to me which of these will occur perhaps a bit of both.

       Nick G
       04/29/2015 at 12:27 pm
       Dennis,

       This is a complicated discussion, and it’s hard to be clear on the definitions of terms. In this case, it may be helpful to define demand not as consumption, but the way economists use it which is a certain relationship between price and consumption – a demand curve. If prices rise consumption will be lower than it would otherwise have been. That doesn’t necessarily mean the absolute level of consumption has declined. See what I mean?

       About half of US fuel consumption is for personal transportation, and it’s the single largest component of consumption for the world.

       As far as I can tell, the cost of electric vehicles and liquid fuel vehicles is about the same when oil is at about $75. I think that’s also roughly the point where all consumers (household, industrial, commercial) start to look at alternatives, starting with greater efficiency. Conveniently, it also is roughly the price at which LTO can grow. So, that looks like roughly the equilibrium price of oil: the number around which the price will fluctuate/ oscillate. Prices can go below that and above that but not for that long. The longer they go above or below that in one direction, the longer and higher or lower the next swing will be.”

       I actually came reasonably close to getting a forecast right! Woohoo!

   23. Anonymous

       08/08/2025

       Yeah, I remember when Dennis used to always predict some massive oil prices.

   24. DC

       08/08/2025

       Nony,

       Yes unlike you I am human and fallible.

   25. Nick G

       08/08/2025

       Heck, back when prices were around $125 (12 or13 years ago), I thought that they would persist for a much longer time.

       “Predictions are hard, especially about the future”

       Yogi Berra or possibly Neils Bohr

   26. Anonymous

       08/08/2025

       Duuuude. Sigh. Don’t take it personally. Didn’t mean to hurt.

       It’s really not about being infallible or even about “competing oracles”. That’s something that always bugged me about the TOD and the writers there. Wanting to puff themselves up as forecasters as oracles. Sort of Internet swagger.

       The clash of ideas (and learning new ones) is more interesting than the I’m Ace, I’m Rune, I’m DC. Like I loved it when you showed me the state by state marketed gas numbers (hiding in that fricking maze of a website!) I gave you props for that. Or even digging up the articial lift for gas wells (although I’m still sort of curious if it is anything like oil…would figure not, but I am not an earl man).

       —–

       I think what is interesting is to consider uncertainty. How much is there? And what are the major/minor factors. E.g. Boswell is up front that his estimate is driven a lot by EUR assumptions. (Not all, there’s still interesting features even if you use more timid EURs…but he is upfront and says that per well EUR is a major uncertainty).

       Looking at your work in the past (not a new realization, I pointed it out ~decade ago), one of the major “levers” affecting uncertainty was the TRR assumptions you imported from USGS (or made up for the Delaware, I didn’t quite follow it, but same concept).

       IOW, consider Boswell. It is likely that EUR/well uncertainty is a major driver of different results. It is likely that (I donno) exact production history and well maps of the states are NOT a major driver of uncertainty. This is not to say the latter two are Euclidean theorems of infallible correct numbers. But that they are pretty good…and any small revisions would not drive his overall analysis to radically different numbers.

       Again…it’s just way of thinking to embrace more uncertainty. Like the 90% confidence interval that the EIA STEO has for future oil/natty prices (and we are talking about relatively small distance out, year or two). Those error bounds are GINORMOUS. And guess what? Those are the literal “betting odds” uncertainty bounds. Oil and gas futures are priced in terms of fixed levels contracts as well as most likely strip. So you can tell how likely (by the odds) a $100/oil contract is a year from now. And…the 90% CI is wide. It just is.

       The same thing probably applies with production forecasting. More so in the past, when the industry was evolving more rapidly, but still…

   27. DC

       08/10/2025

       Nony,

       You are correct that I expected high oil prices to return after the pandemic, so far it looks like I was wrong, demand has not recovered as quickly as I expected and the transition to electric land transport for the World has proceeded more quickly than I expected.

       So absolutely my predictions about the future were not correct and as I state often, the only thing that is certain is that I cannot predict the future accurately.

9. Ovi

   08/08/2025

   Below are some interesting comments from the Q2 Baytex Energy report on what they are doing in the Eagle Ford basin and the Canadian Duvernay shale basin.

   Eagle Ford
   “We brought onstream 14.9 net wells while realizing an approximate 11% improvement in operated drilling and completion costs per completed lateral foot compared to 2024. We also completed two successful refracs that are delivering initial rates comparable to our broader development program with improved capital efficiencies and returns.

   The two refracs (Moulton A5H and Renee Unit 2H) were brought onstream in April and May with average completed lateral lengths of 1,648 meters (5,406 feet) and generated average 30-day peak production rates of 963 boe/d per well (734 bbl/d of crude oil, 124 bbl/d of NGLs, 631 Mcf/d of natural gas).

   The refrac program extends inventory duration – we have identified approximately 300 refrac opportunities across our acreage and anticipate an expanded program in 2026.

   Since I am totally unfamiliar with what is happening operationally in the US basins and since production appears to be on a plateau in a number of counties, my question is “Are refracs playing significant role in helping to maintain US shale oil production?” Are 300 refracs significant considering Baytex brought almost 15 wells online in the quarter?

   Duvernay
   “The first Pembina Duvernay pad (07-01, 3 wells) from our 2025 program was brought onstream in May with average lateral lengths of 3,800 meters (12,500 feet) and generated average 30-day peak production rates of 1,865 boe/d per well (1,239 bbl/d of crude oil, 422 bbl/d of NGLs, 1,224 Mcf/d of natural gas). The second pad (08-08, 3 wells) came onstream through early July with similar lateral lengths, and over the last 26 days has averaged 1,264 boe/d per well (709 bbl/d of crude oil, 352 bbl/d of NGLs, 1,220 Mcf/d of natural gas.”

   https://www.baytexenergy.com/content/uploads/news/1753995720-260831.pdf

10. Coffeeguyzz

    08/08/2025

    Some perspectives in the 4 well Indian Foot pad from Expand in Bradford county now that it is approaching 11 months of published production …
    1. Total cum just over 54 Billion cubic feet.
    2. This is the oil-equivalent in heat energy of almost 10 million barrels of oil.
    3. Still flowing at over 120 MMcfd, this pad is producing the energy equivalent of more than 20,000 barrels of earl Each. Day.
    4, The cost to D&C these 4 wells would be in the range of $60 million.
    5. This pad – in less than 11 months’ production – has already provided for the annual residential natgas needs for almost 2 million people. (Did I mention that the cost was only 60 mil?)

    The impact of natgas on this country’s – and, frankly, the entire world’s – future energy needs will continue to call for the spotlight to increasingly be focused on this wondrous hydrocarbon … its availability, costs, projected future supplies, and ever-expanding applications.

    The Age of Oil may be – like the Sone Age – drawing to a close; not by ‘running out’ but by being supplanted by other energy sources, its lighter hydrocarbon cousin being one of the major usurpers.

    1. Ovi

       08/08/2025

       Coffeeguyzz

       I guess CH4 + ?? > C8H20 is too costly in terms of EROEI.

    2. Coffeeguyzz

       08/08/2025

       Ovi,
       I am not quite clear in understanding your statement.
       In an illustrative, strictly financial/heat energy comparison … at $3/mmbtu for natgas, $17.40 worth of natty contains the same mmbtus as 1 barrel of oil.
       Conversely, $70 WTI would equate to natgas selling at over $12 Henry Hub.

       Either perspective, Ovi, should demonstrate just how widespread is the monetary difference obtained by using natgas versus oil in applications where it is viable.

       Adding to this is the ‘relative’ ease and long life span of natgas recovery versus older oil wells.
       Despite much debate in the last thread in these matters, it is an incontrovertible truth that natgas wells are long lived using relatively minor/inexpensive techniques by which they are maintained.

       So, the supply is abundant.
       Cost of development/extraction/maintenence is low.
       Myriad processes/hardware are being introduced to make transportation/storage more ‘oil/diesel/gasoline-like’ . (Even a brief perusal of LNG mini/micro storage innovations should raise a few eyebrows.)

       These factors – and others – should prompt a continuing diminishment in the demand for oil … relative to the overall, voraciously growing global appetite for energy in toto.
       Nuclear and – egads – coal are on track to bolster their contributions to the global energy supply.
       Nuclear, with its focus on smaller (mini/micro size), and coal, with its characteristics (efficiency/environmental) greatly enhanced via the supercritical pathway, are already entering the paradigm in an electricity constrained world

    3. Ovi

       08/08/2025

       Coffeeguyzz

       I was just wondering if CH4 can be converted into gasoline economically and with a net energy gain. I was using C8H20, octane, as a proxy for gasoline.

    4. Nick G

       08/08/2025

       “Synthetic diesel is made by reconfiguring another hydrocarbon fuel, such as natural gas, into liquid diesel fuel. Synthesizing diesel fuel from natural gas is possible through gas-to-liquid (GTL) technology and such synthetic fuels are often called GTL diesel or FTD (Fischer-Tropsch diesel) from the Fischer-Tropsch chemical conversion process.”

       https://www.man-es.com/marine/strategic-expertise/future-fuels/synthetic-diesel

       https://www.shell.com/what-we-do/oil-and-natural-gas/gas-to-liquids.html

       Qatar has a very large ($billions) GTL plant.

       https://www.shell.com/investors/results-and-reporting/portfolio-and-major-projects.html

    5. Carnot

       08/11/2025

       Nick, it must take some effort to continually being the village idiot. It would be a good idea if the engaged your brain before you mouth.

       I will give some data on the SMDS process ( Shell Middle Distillate Process) which is the process that was built in Qatar 15 years ago at a cost in excess of $23 billion.
       From the Handbook of Petroleum Refining Processes- Third Edition 15.27

       Based on a flow rate of 600 SCF/day (5TCF over project life( you could make):
       1. 30 million tonnes per annum of methanol
       2. 100 million tonnes of LNG
       3. 3 million tonnes per annum of SMDS products.
       The unit in Qatar has an approximate capacity 7.5 million tonnes roughly equivalent to a refinery of 150 mb/d.
       Qatar provided FREE feedstock until the CAPEX had been paid down. In reality this was a vanity project. Much of the output is used in speciality products such as waxes and solvents rather than fuels.
       The basic process relies on the partial oxidation of methane to produce syngas, which is then converted to paraffins ranging from about C4 upwards.The products are high quality but have some limitations, insomuch that the jet and diesel products need additional blending to meet fuel standards. The jet fuel has low lubricity and requires aromatics to be blended into the the finished stream or blended into Jet A1. The diesel steam requires similar treatment. The naphtha / gasoline stream has poor octane (70’s RON) and is better as steam cracker feed or feed for a reformer.

       The number of SMDS plants is 2. Other similar plants number <8 (Syntroleum. Sasol) and that is globally.

       15 years ago there were many proposed projects for the US. All Failed to make in the early design stages as not economic. I worked on a methanol to propylene concept and it was clear form the start that synthesising propylene from NG was economically unviable.

       That there are so few plants is only testament to the fact that though it works it is not economic and is never likely to be so. One issue is the exotic metals that are required to safeguard the plant form corrosive co-products.

       The Chinese are generally mugs when it comes to new technology; they are very good at stealing that technology once it is built. But so far the Chinese have shied away from Fischer Tropsch plants.
       On a separate note Exxon developed a process called G to G, gas to gasoline, which required the production of methanol as an intermediate. A small plant was built and was shit down never to be heard of again.

    6. Nick G

       08/11/2025

       Carnot,

       I hope you know what you’re talking about with O&G, because you’ve been willing to repeat nonsense about climate change.

       Makes it hard to believe anything you say.

    7. Anonymous

       08/08/2025

       Ovi,

       The answer is “no” for the economics. This is well known. Prices for transport fluids (just use C&C oil price as a proxy if you want) have to be dramatically higher versus natural gas to make this sort of conversion economical.

       It’s almost certainly not a net energy gain (most conversion processes are lossy, not gainy). But of course it’s the economics that drives the decision, not the energy gain. I mean running natty through a turbine and making electricity is also not an “energy gain”. You don’t do it to “gain energy”. It’s just that you’d rather have the electricity than the natty.

       There was some hoohaa about GTL (gas to liquids) and about using natty directly in vehicles (the Pickens plan), back when crude was at $100+ and natty was below $3. But it never took off, especially because oil prices moderated.

       Traditionally natty and crude were thought of as substitute products and competitors (many decades ago). But this is really archaic now. Just showing up in things like “BOE” terminology or in pricing LNG. Very few electrical power plants burn crude oil any more. It is too valuable for transport uses. Natty competes with coal for electricity generation. There has been some movement of natty into transport (e.g. bunkering fuel), but overall it’s been small…much less than the Pickens Plan hype. Which was more than 10 years ago.

    8. Nick G

       08/11/2025

       of course it’s the economics that drives the decision

       Yes, of course. Conversions like this are typically not all that efficient, and it’s very, very hard to justify unless (as you noted) the cost differential between alternatives is very large.

       And really, the important question isn’t converting NG, it’s converting H2 and C into liquid fuel. We haven’t really needed to do this before, so we haven’t really tried, but of course it can be done. But…if all else is equal it will be more expensive than petroleum if you don’t count the external costs. If you’re not willing to acknowledge the pollution (esp GHGs) of oil, then it’s easy to dismiss a more expensive replacement.

       Of course, all else is not likely to equal: it is very likely that there will be significant periods when there is very cheap surplus electricity, due to the economics of “overbuilding” – consider that US generation capacity is about 2.5x average load. Most generation now uses fuel, so it doesn’t run when not needed (that would be crazy), but wind and solar have essentially zero marginal costs, so they could run at 100% 24×7 if there was a use for the surplus power (at or near zero prices).

    9. DC

       08/08/2025

       Coffeeguyzz,

       The important factor is average well productivity, the sweet spots are very limited. The productivity of all wells drilled is the number that matters, in 2020 for PA Marcellus wells it was about 15 BCF for average well EUR, that’s what the data tells us. As to whether shale gas wells require downhole pumping equipment, I think any liquids (whether it be water or condensate) in the horizontal lateral will require a downhole pump and these are expensive to repair or replace.

       Maybe Shallow sand could comment on this or someone else with real world oil or natural gas field experience?

    10. Coffeeguyzz

        08/08/2025

        Dennis,
        The formation pressure initially drives the gas out of the rock, into the lateral casing, up the production tubing to the surface where the guage pressure is zero psi.
        As the well matures and formation pressure drops, a point is ultimately reached where liquids – primarily water – accumulate in the lowest vertical part of the well.
        When sufficient water builds up, it exerts enough back pressure (one might non-scientifically think of this as the ‘weight’of the water) to stifle any gas from travelling up the wellbore.

        A plunger lift efficiently, economically addresses this situation as it is about a foot long, ~25 pound ‘plug’ that cycles up and down throughout the vertical.
        It automatically drops to the seating near the bottom of the vertical and the well is shut in.
        When measured casing pressure builds up and is deemed sufficient to push the plug to the surface, the well is automatically opened, higher pressure gas rushes in, the plug, liquids and natgas all shoot topside with the water being separated, the plug suspended uphole, and the gas diverted to the gathering lines.
        Rinse/repeat for decades.
        As pressure drops further, compressors can be/are brought on-site to push the gas into the gathering lines as well as create a negative pressure differential at the surface which assists lifting the gas (and liquids) from the wellbore.

        There are no submersible pumps, pumpjacks or other expensive hardware.
        The physical properties of gas pressure do most of the ‘work’.

11. Anonymous

    08/08/2025

    Reuters article discussing the battle between rigs and efficiency:

    https://www.reuters.com/business/energy/sliding-us-rig-count-outpaces-efficiency-gains-threatening-onshore-oil-output-2025-08-05/

    I don’t really see any new, strong, analysis, but you do get slightly different perspectives, including Novi Labs. But at the 10,000 foot level they are the same. Whether you expect US to peak in MAY or OCT or 2026…or at 13.5 or 13.8. None of them see some wet dream collapse though. Just a very slow, losing the battle, plateau-ish downtrend.

    Novi (I think, it was them) does point out that the operators drilled their best projects last year…and that staved off decline and gave small increases, even as rigs rolled off. However, those days are over and per lateral foot results are down 8%. (I would caution you peakers not to dream of some magic collapse though…there’s always more rock that is 10% worse than there is that is the best…it’s a resource pyramid.)

    The one thing not addressed (and this is just an analysis nit, not meant to argue for cornie-ness) is “speed”. IOW, it’s not just the quality of the rock times the number of rigs. But if the rigs get faster, you get more POPs. So the impact of a rig can be higher, just because it actually is more “efficient”. Again, I’m not arguing this swings the equation…just prefer it to have been analyzed, discussed. Maybe (completed*) feet drilled/rig/month. Time averaged, to deal with random variation). I’m just honestly curious if this is still improving, or not. It did for a while.

    Now, peakers can make the point that drilling faster (more POPs) is just eating up the resource faster. And…um…I actually agree with that logic! However, all that means is same area under the curve, with a different shape. However, if you are trying to talk about “what next year looks like”, it’s not so relevant the earlier TRR consumption of the field. And the “speed” of the rigs IS relevant.

    New oil/time period= (quality of rock/foot)*(#feet drilled/time period). And # feet drilled/time period =# rigs*(feet drilled/rig/time period). And feet drilled/rig/time period is what I call average rig “speed”.

    At an extreme of course, you could even get the “Seneca cliff”, in the further off future, I guess, from speed drilling. Although, I think for economic and technical reasons (sunk cost of infrastructure) that you don’t have this dreamy “worse than bell curve” shape. Rockman used to point this out a lot…don’t misunderestimate how the decline will be less than bell curve, not greater. But, I digress.

    *And yes, I know the rig doesn’t do the completion. It’s just that this is the relevant eventual parameter. (If you drilled an uncompleted foot, it’s useless for production.) And this way you avoid the confusion of tracking frack crews. Just concentrate on the start (drilling) and end (production) of the process–both of which are much easier to track than frack crews (very lousy and lagged data, plus not needed analytically on longer time frames).

    1. Coffeeguyzz

       08/08/2025

       Nony,
       The ‘speed’ factor is absolutely not some analysis nit.
       It plays a very large role in how this entire hydrocarbon recovery narrative will continue to unfold.

       Biggest factor – of several – is the ongoing expansion of the economically viable footprint in all the basins.
       Seeing that play out right now in the Bakken.

       While Antero’s record setting 12,340 lateral feet drilled in 24 hours is impressive, there are many, many wells in the AB that qualify for the Mile A Day club.

       Faster drilling/frac’ing>lower costs>more profitability>growing prospective footprint for development.

12. Anonymous

    08/08/2025

    It’s fascinating to me how FEW rig are needed to maintain a massive natural gas production output from the App.

    https://marcellusdrilling.com/2025/07/baker-hughes-u-s-rig-count-down-again-542-pennsylvania-adds-1/

    You have less than 18 rigs in PA. And over 20 BCF/day. That’s over a BCF/rig, to hold production! Even if you look at it App-wide (PA/WV/OH), you’re looking at 36 rigs and about 36 BCF/d. (OH which is less gassy, oilier pulls the average down versus PA/WV)

    I mean that is MASSIVE production. And from an extremely small amount of rigs. Almost diametrically opposite to what the Hughes/Berman crowd was telling us when fracking started up…that it would take a gazillion rigs to keep up with the plunging individual well shale declines.

    Those must be some hyooge (TM, your president) wells, to compensate from the evil decline. Like offshore gas well sized wells. Or maybe the rigs just drill fast. Likely both. Anyhow…it sure seems like very small number of rigs to keep the Red Queen at bay!

    1. Coffeeguyzz

       08/08/2025

       Nony,
       The consolidation in the AB these past few years has greatly enhanced the contiguous acreage for the major operators.
       More/larger contiguous acreage>longer laterals>higher output per well.
       Not uncommon to see a 4 well pad throw off over 30 Bcf first year. (That Indian Foot pad mentioned above will come close to 60 Bcf first 12 months online.)
       In addition, operators are now routinely drlling/frac’ing 6 to 8 wells simultaneously on a pad in their ongoing quest for efficiency.

    2. DC

       08/08/2025

       Coffeeguyzz,

       If we double the size of the lateral we halve the number of potential wells. Nobody is creating any more rock volume.

    3. Anonymous

       08/08/2025

       DC: Yeah…everybody knows that. Nobody ever said that it was some 2x improvement. You are correcting a straw man.

       The point is that there is some fringe of the field, where the marginal well exists, where costs and revenues balance (or to be more rigorous where NPV=0). Inside that fringe, it makes sense to drill. Outside, it does not. Any cost reduction (and longer laterals are done to reduce costs) enables drilling “less sweet” spots.

       Calculating the exact amount of resource added is non-trivial. If there’s a sweet spot and very little intermediate (near drillable) inventory, then it’s nothing. If there’s a lot, then it’s a lot.

       You can really think of it as analogous to how much resource exists at different price points. Except instead of varying price, you are varying cost.

       This has been explained to you many times before…

    4. DC

       08/08/2025

       Nony,

       Yes thanks for the lesson in economics, the amount of TRR is unchanged when costs are reduced, but ERR obviously increases. Have you heard of diminishing returns? Eventually costs will be reduced no further and as the better areas become fully drilled EUR per foot of lateral tends to fall. Eventually an optimum lateral length is reached where any further increase leads to an increase in cost rather than a decrease.

    5. Anonymous

       08/08/2025

       Much more thoughtful comment. And FWIW, I agree that efficiency improvements are likely much smaller recently than a decade ago. But why not make that comment instead of the red herring straw man, “coffee, it’s not twice as much”.

       And even here…there’s sort of a straw man game of acting as if I’d said these benefits were huge. Even when I talked about “margin”al improvements.

       FWIW, if you want to think about this analytically, what matters is the amount of rock that is enabled by a cost reduction. So, in a play where the dropoff from sweet to goat pasture is very sharp (almost digital), the ERR benefit is small. In another play, the benefit could be quite large. After all, it is a resource pyramid and the overall extent of the plays is large (and no…please don’t strawman me to say that that means the entire thing gets drilled).

       Even within the same exact play, the benefit of a cost reduction (in increasing ERR) may vary based on the price environment itself. It depends on the gradient of inventory versus cost (which will be different itself, at different price points…likely more critical in the low price environment, but in any case, dependent on the particular slope of the curve).

       Totally swagging it, I might guess that going from 1 mile to 2 mile laterals would reduce costs by ~10%. Figure 1/3 drilling cost…and then doubling the lateral is maybe a third of the cost (basically halfing the vertical shaft and setup time (because lateral twice as long). So that’s a ninth reduction. So call it 10%. Maybe my numbers are off and it’s 15%. Who knows. It’s definitely less than a third though. So, let’s just use 10% unless someone has a better analysis.

       How much extra rock comes free with 10% cost reduction? It’s not zero. Consider how a 10% raise (or drop) in price affects the amount of drillable inventory.

       Again…don’t be such an advocate that you need to strawman me. I feel like I need to caveat everything or you will twist it.

       Just be analytical and think about what’s going on.

       —

       Oh.,..and again, I actually agree that length increases (in the current day) are very moderate “levers” for affecting production. For one thing, we’re probably not talking about going from 5,000 to 10,000 feet (unless you compare to a baseline of a decade plus ago). You’re probably talking less than 500 ft/year, if that. So…it’s a very small change on a yearly basis.

       I would just be a tiny bit “wary” of dismissing efficiency gains. It’s child’s play to go back several years ago and seeing people dismissive of technology improvement. And then we still had very substantial improvements in both costs and production. Again…these are mostly over. But still…the past overconfidence of the peakers should make you a little more humble, curious, thoughtful.

       An interesting example of relatively “late” technology improvement were the “propageddon” fracks in the Haynesville. That was a past peak province…one of the older ones. Yet, there was still more to be learned…leading to a turnaround in production and actually exceeding the old peak.

       Note (strawman preventer), I’m NOT saying this always happens…or happens on average. Just saying it is an interesting example of how there really ARE Rumsfeldian “don’t know what you don’t know” examples of unexpected results. And then…when you look over the course of decades? To expect no more? Seems unlikely. But…again, I’m not claiming fossil fuels are unlimited, etc. etc.

       I just want you to be a more thoughtful and less of an advocate. You could even have dramatically different projections, but if there are factors and analytics that are new and interesting and insightful, that’s a win. (And yes…you need to be able to look in a paper like Boswell and see interesting features…yes, even if you retain the doubt about the 50 year EURs…don’t be such a bull to miss other interesting analysis like the percent of land unuseable from minor boundary issues, like the (inherent) economic assumption within a “TRR” (because of infill drilling density limitation).

    6. DC

       08/09/2025

       Nony,

       I consider all of those in my analysis, there are two competing trends, the marginal technical improvements which decrease costs and the depletion of tier one and tier 2 acres which tend to increase costs, I don’t have access to the granular data to know how many tier one, 2, 3, etc acres are left in each play. For Permian only I assume average well productivity will decrease starting in Jan 2025 by 2% per year at current completion rates (this rate is proportional to number of wells drilled per year (if rate increases by factor of 2 the rate of decrease in EUR increases by a factor of 2 and vice versa), for other plays I assume the EUR remains fixed at current level. Note that I also have looked at the Permian reports in detail and even did an analysis where I took the parameters from the USGS reports and created separate well profiles for Midland and Delaware Wolfcamp (2 separate well profiles for each sub-basin) and Bonespring and Spraberry well profiles with an estimate for potential future wells of each type (the bulk of Permian tight oil wells are from these formations), the analysis was not significantly different from what I had been doing and was far more work so I stuck with the simpler analysis using average well profile for each year for the entire basin and completions for the entire basin. At this point I no longer have updated well profile data after 2022 so from Jan 2023 to Dec 2024 I assume average well profile remains at 2022 level (this is simply a guess in the absence of information).

    7. DC

       08/09/2025

       From 2016 to 2022 EUR per 10kft decreases at an average rate of 1.7% per year for Permian basin.

    8. Paul Pukite (@whut)

       08/10/2025

       anonymous said:

       “where the dropoff from sweet to goat pasture is very sharp (almost digital),”

       digital???

       “It depends on the gradient of inventory versus cost “

       This is all just running-at-the-mouth drivel. Gradient is dI/d$ so this is just the reciprocal of cost per amount. And then he says “(basically halfing the vertical shaft and setup time (because lateral twice as long).”, which is exactly what he was complaining about in the first place.

       Where do they find these people?

    9. Sheng Wu

       08/11/2025

       There is a similar trend in Bakken, where the initial unbounded flow turned into bounded flow, see,
       https://novilabs.com/wp-content/uploads/2024/03/2.-Well-productivity-2.png
       https://novilabs.com/blog/north-dakota-update-through-jan-2024/
       while the industrial EUR estimate still use old DCA for latest wells.

       But, in Marcellus, it is different.

    10. Paul Pukite (@whut)

        08/12/2025

        Unbounded versus bounded flow is the difference between classical Fickian diffusion and Ornstein-Uhlenbeck diffusion.

    11. DC

        08/08/2025

        Nony,

        Hughes was focused on tight oil, 40 BCF/d equates to about 6.7 Mbo/d, the gas rigs do seem to be very efficient in the shale gas plays relative to say the Permian, also we may have somewhat lower rates of decline for shale gas wells. Perhaps the resource is unlimited and will last forever, I doubt this is the case.

    12. Anonymous

        08/08/2025

        I’ve always seen Hughes as covering both and nearly evenly.

        David Hughes portfolio on Post Carbon: https://www.postcarbon.org/our-people/david-hughes/

        (Look at the bulleted list, as well as the four further lists, below.)

        Maybe you meant Berman? He has covered both, some, but arguably noticeably more oil, especially post 2012.

    13. DC

        08/08/2025

        Nony,

        You are correct, I must have been focused on the tight oil part of the analysis.

    14. Anonymous

        08/08/2025

        Thanks, Dennis!

    15. Sheng Wu

        08/11/2025

        berman started to PS the numbers for shale gas, e.g. Haynesville, it is quite amazing.

    16. Sheng Wu

        08/11/2025

        D C,
        Your prediction in 2015 for Bakken and EF are quite amazingly close to real production.
        I have been studying the huge super giant gas reservoir clusters in the West Siberia Yamal region lately.
        The largest field Urengoy already produced almost 250TCF, or 70~80% of the reserve in the shallow formation (Cenomanian ~1.1km TVD), along with nearby super giant fields produced another 70~100TCF, and yet still have another 100~200TCF left there. Yet, there is another formation below 2km TVD which might actually sourced the gases above, tighter formation with another 70~100 TCF. Further north into the Kara sea, where the Yamal LNG is developing, they have another 100~200 TCF in similar shallow formations. So, the amount of conventional gas is enough so Russia basically doesn’t have to think about shale.

    17. Coffeeguyzz

        08/09/2025

        Nony,
        In regards to ‘hyooge’ AB wells (I believe the common spelling is ‘huuuge’) … the second most productive pad in Pennsylvania is the 8 well Carpenter pad from EQT in Greene county.
        Online less than 5 1/2 year well average, this pad has already produced over 206 Billion cubic feet.
        Current production is over 50 MMcfd.

        For those interested in getting a handle on just how staggeringly productive these wells are, just divide those numbers by 6 (or, more precisely, 5.8) and see the energy equivalent in ‘oil’ terms.

        Appalachia Rising!

13. shallow sand

    08/08/2025

    DC and Ovi. Thanks for the posts and the data!

    There really isn’t a lot to discuss at this time though. If I had something to add, I would. But I don’t, and the little I comment on is probably the same stuff I’ve typed for several years.

    1. Ovi

       08/08/2025

       SS

       Thanks.

       Above I asked a question on refracs. Have you heard anything on refracs from your associates?

    2. shallow sand

       08/08/2025

       Ovi. I don’t have contacts in shale. Mike or LTO Survivor might be able to help on that.

    3. DC

       08/09/2025

       Thanks shallow sand,

       Thought you might have some idea on natural gas wells (or more knowledge than me), but I know your focus is on oil and you have said in the past your wells produce little or no methane.

14. Ovi

    08/08/2025

    Rig Report for the Week Ending August 8

    The rig count drop that started in early April when 450 rigs were operating added 1 this week. However the Permian was down 3 rigs.

    – US Hz oil rigs increased by 1 to 363, down 87 since April 2024 when it reached 450 or down 20%.
    
– New Mexico rigs dropped by 1 to 82 while Texas dropped 3 rigs to 182.
    – Texas Permian dropped 2 to 149. The largest rig drop in Texas occurred in La Salle County, 2 rigs. Lasalle County had 7 operational rigs in February.
    
– In Texas Midland dropped 1 to 23 while Martin was unchanged at 19.
    – In New Mexico Eddy dropped 2 to 34 while Lea added 1 to 47. Lea has added 11 rigs over the last 8 weeks.
    – Eagle Ford dropped 1 to 28.
    – NG Hz rigs were flat at 108.

15. Ovi

    08/08/2025

    Frac Spread Report for the Week Ending August 8
    The frac spread count dropped by 4 to 163. It is also down 77 from one year ago and down by 52 spreads since March 28.

    1. Coffeeguyzz

       08/11/2025

       Ovi,
       Don’t know if you read that May 7, 2025 article from the EIA’s Today In Energy post, but it describes some of the current practices/efficiencies that operators are employing during frac’ing operations.
       Apparently, so-called trimulfracs (frac’ing 3 wells simultaneously), are now pretty much routine when conditions enable it.
       Although somewhat unrelated, so-called ‘horseshoe’ or ‘u turn’ wells are increasingly being drilled to maximize production with lowered expense on smaller (1 square mile) leases. Although 10,000 feet seems to be the limit at the moment, it is not inconceivable that improved oil recovery processes could extend those drilled lengths in the future.
       Interesting stuff.

       Technological advances – like depletion – never sleeps.

16. Anonymous

    08/09/2025

    I keep wondering, when you shift topics, Dennis, if it is sophistry, or lack of analytical ability. E.g. in a thread about cost reduction, you start talking about EUR/foot.

    There are many, many factors going on in the development of these shale plays. When you consider one factor, you need to consider it. Not muddle in the others. Of course eventual production will depend on all of them. ut to analyze one, to start with, you have to analyze it. Not dodge.

    So, for example, you could have EUR/foot getting worse (or better, or staying the same), while cost efficiency was reduced. And it’s not at all clear that the two are anticorrelated. They might be, for sure. But they don’t have to be. For example, it could be geology driving the (very slightly) worse EURs over time. In which case, cost efficiency (by lateral length increase, for example). might be what is needed to keep drilling the progressively getting worse geology!

    You can also easily consider areas where some lower EUR, for lower costs is justified. For example, the wells would produce more if gel-fracks and ceramic proppant were used. That is better at breaking/holding the rock apart. But the point is that this benefit to EUR is not worth the cost. The operators are trying to maximize NPV, not recovery.

    It’s not a dick size contest to look bad or good on Dennis’s EUR/foot chart. They are trying to make money. And they make tradeoffs all the time.

    1. DC

       08/11/2025

       Nony,

       The reason for bring up normalized productivity is that we then look at how much oil we are getting from a given rock volume. I agree the costs per foot of lateral will usually be lower with longer lateral length, but the question is if oil produced decreases by as much as the costs decrease so that it is a wash, or perhaps costs per barrel decrease by less than assumed due to lower output per lateral foot. Also keep in mind that much of the increase in well productivity is due to increasing lateral length. I recently got some of this lateral length information on the Permian from the EIA, see https://www.eia.gov/todayinenergy/detail.php?id=54079

       Prior to seeing this article I didn’t have solid numbers for average lateral length in Permian Basin and how it had changed over time. Chart below shows my estimate of how average Permian EUR changed from 2012 to 2022.

    2. D C

       08/11/2025

       Note that I don’t have lateral length numbers for Bakken, but it is possible that if we normalize for lateral length that there might have been deterioration in EUR for Bakken/Three Forks over time that I was not aware of.

17. Anonymous

    08/09/2025

    Also, for what it’s worth, I wonder how many peakers foresaw the Permian improvement from 2012 to present day? I suspect it was much more the opposite. They were pushing the idea that the sweet spots were known, getting used up…and ignoring the cornie BS about improvements in completion design.

    Like, I don’t recall you doing the Permian in 2013, but I sure remember how (back then) your other shale models always had some “wells start getting worse in a year” type of feature. Which you had to keep moving the goalposts to a year later, every year. Oh well, eventually you’d have been right in 2020 or so. But wells are still doing WAY better than they did in 2012, overall. And the rate of decline has probably been less than the kind of ramp rates you used to include.

    For that matter it is possible for things to change. Like, look at the Haynesville Renaissance, where we had a late in play life massive increase in EURs. And (strawman preventer), I’m NOT saying this will happen everywhere…it’s an outlier, probably. And I’m quite comfortable with the idea that the sweet spots in the Permian are getting drilled out. But at least let the Haynesville example give pause, to “widen” the uncertainty window about future evolution. Especially on the time scale of 2050.

    1. DC

       08/11/2025

       Note that when we normalize for lateral length there has been no improvement in average well productivity since 2016 in the Permian Basin. From 2012 to 2016 there was a large increase in Permian productivity, but the Permian Basin wasn’t really on the radar before 2016 in any case when the USGS released its first assessment (of 3 assessments from 2016 to 2018).

       Here is the EIA forecast for the Southwest (mostly Permian Basin output ) from AEO2015

       https://www.eia.gov/outlooks/aeo/data/browser/#/?id=71-AEO2015&region=0-0&cases=ref2015&start=2012&end=2040&f=A&linechart=ref2015-d021915a.10-71-AEO2015&ctype=linechart&sourcekey=0

    2. DC

       08/11/2025

       EIA AEO 2015 Southwest US (Permian Basin mostly) several cases Reference, High and low oil price and high oil and gas resource cases.

    3. DC

       08/12/2025

       AEO 2025 Southwest estimate has changed quite a bit from AEO 2015.

18. Ovi

    08/09/2025

    By accident I came across this old headline that was issued on June 12.

    U.S. Energy Secretary Pushes Back on the EIA’s Oil Decline Narrative

    Energy Secretary Chris Wright does not expect U.S. crude oil production to decline in 2026, although the Energy Information Administration forecast such a development.

    “That is a projection — we don’t know what’s going to happen next year,” Wright told Bloomberg in an interview. “We have seen weak prices for a few months, and if prices are too low for an economic incentive, you’ll see some drilling reduce on the margin. I think it’s unlikely you’ll see enough reduction to actually see a decline in production next year.”

    Bloomberg noted in its report that shale drillers have been laying off workers and cutting the number of drilling rigs in the patch but Wright said that “This administration is making it lower cost for them to drill wells and therefore a lower threshold at which they would start to pull back activity.”

    “As you know that most of the shale basins now have either plateaued or are starting to decline, except for the Permian,” Occidental’s Vicki Hollub said on the company’s Q1 call.

    So what happens if US production stops hitting new highs?

    https://www.theglobeandmail.com/investing/markets/stocks/XOM/pressreleases/32843932/us-energy-secretary-pushes-back-on-the-eias-oil-decline-narrative/

    1. Anonymous

       08/09/2025

       It’s either going to be a slow decline (almost a plateu). Or it will be the tiniest of increases. Assuming strip prices.

       I think decline YOY, seasonally adjusted, is more likely than growth. Just my gut feel from watching from the cheap seats. It won’t be some peaker dream of a collapse though. It is really very close to a balance.

    2. Ovi

       08/10/2025

       Nony

       I was thinking of the commissioner who put out the low job numbers.

    3. Jean-François Fleury

       08/10/2025

       Not difficult to predict : fired! That’s the new trend. What I am afraid of is the possibility for EIA’s data to be manipulated as they will no longer match the desires of the Energy Secretary.

19. Ovi

    08/11/2025

    A Tale of Two Big Oil Companies

    ExxonMobil speeds up in Permian as Chevron taps brakes

    “New York, 11 August (Argus) — ExxonMobil is chasing further production growth from the Permian just as Chevron is slowing down to focus on running its operations in the leading US shale basin for cash flow.

    ExxonMobil, which reported record output of 1.6mn b/d of oil equivalent (boe/d) from the basin in the second quarter, plans to further boost its Permian production by 44pc to 2.3mn boe/d bwy 2030. Crucially, while other operators have sounded the alarm over peak output, ExxonMobil sees growth continuing well into the next decade. “Nowhere is our emphasis on technology and innovation paying off more clearly and immediately than in the Permian,” chief executive officer Darren Woods says.

    Chevron, in contrast, is hunkering down in the Permian after reaching a targeted production plateau of 1mn boe/d during the second quarter. One of the criticisms levelled at the industry in the heyday of the shale boom in the last decade was that the majority of cash flow was directed back into growth, and investors were left with little to show. Chevron is flipping that script on its head by moderating growth and reducing spending. The billions of dollars in additional free cash flow the company expects to generate as a result will go towards shoring up its balance sheet, as well as investment elsewhere.”

    What is not clear with the XOM 44% increase is whether the primary increase is from Oil or NG or how it is split.

    https://www.argusmedia.com/pages/NewsBody.aspx?frame=yes&id=2719844&menu=yes

    1. shallow sand

       08/12/2025

       Doesn’t XOM have more New Mexico acreage than CVX, or am I wrong about that?

       Since the end of 2019, the major US production growth has been from New Mexico. Over 1 million BOPD, while the remainder of the US minus NM is down from the end of 2019.

    2. DC

       08/12/2025

       Shallow Sand,

       Great point!

       US minus New Mexico C plus C output down by about 220 kb/d from 2019 to 2014.

    3. Ovi

       08/12/2025

       SS

       I’ve taken a look at the Texas and New Mexico production contributions to US oil production from January 2021 to May 2025

                Jan 21      May 2025     Inc
       Tx       4,637       5752         1,115
       NM    1,092       2,199        1,107

       Almost identical increases. Percentage wise NM has done an outstanding job.

20. Ron Patterson

    08/12/2025

    EIA expects low crude oil prices and declining rig count to affect U.S. crude oil production trends through 2026

    The U.S. Energy Information Administration (EIA) expects the Brent crude oil price to fall to near $60 per barrel by the end of the year and to average about $59 per barrel in 2026. EIA expects the low price of crude oil to affect both U.S. crude oil production and retail gasoline prices in the short term.

    In its June Short-Term Energy Outlook (STEO), EIA forecasts U.S. crude oil production to average about 13.4 million barrels per day this year, just below the record highs earlier this year. For 2026, the forecast is slightly lower than 2025 levels. EIA expects U.S. retail gasoline prices to average below $3.10 per gallon through the end of 2026, which is about 6% lower than the 2024 average price.

    U.S. energy market indicators ………………………… 2024 2025 2026
    Brent crude oil spot price (dollars per barrel) $81…….. $66 ……. $59

    There is a chart on this article that gives all of what the EIA is expecting next year. but when one copies and pastes such a chart, it does not format well. So just click on the blue link above and you can read it.

21. Ovi

    08/13/2025

    An update to April World and Non-OPEC Oil production has been posted.

    https://peakoilbarrel.com/april-world-and-non-opec-oil-production-drops/

    A new Open Thread Non-Petroleum has been posted.

    https://peakoilbarrel.com/open-thread-non-petroleum-august-13-2025/