The OPEC Monthly Oil Market Report (MOMR) for October 2025 was published recently. The last month reported in most of the OPEC charts that follow is September 2025 and output reported for OPEC nations is crude oil output in thousands of barrels per day (kb/d). In the OPEC charts below the blue line with markers is monthly output and the thin red line is the centered twelve month average (CTMA) output.
OPEC 12 output for July 2025 was revised higher by 25 kb/d and August 2025 output was revised lower by 32 kb/d compared to last month’s report. OPEC 12 output increased by 524 kb/d with the largest increases from Saudi Arabia (248 kb/d), UAE (98 kb/d), Iraq (65 kb/d) and Iran (44 kb/d). Nigeria (-21 kb/d) saw decreased crude output. All other OPEC members had small increases of 27 kb/d or less (net increase for the 7 other OPEC members was 90 kb/d).
The chart above shows output from the Big 4 OPEC producers that are subject to output quotas (Saudi Arabia, UAE, Iraq, and Kuwait.) After the pandemic, Big 4 average output peaked in 2022 at a centered 12 month average (CTMA) of 20849 kb/d, crude output has been cut by 954 kb/d relative to the 2022 CTMA peak to 19895 kb/d in September 2025. The Big 4 may have about 954 kb/d of spare capacity when World demand calls for an increase in output. Since April 2025 the OPEC Big 4 have increased output from 18346 kb/d to 19895 kb/d, an increase of 1549 kb/d in just 5 months (an average monthly increase of 310 kb/d.) If the average rate of increase of the past 5 months continues for another 3 months, OPEC spare capacity will be reduced to 24 kb/d by the end of 2025.
The chart above shows the most recent 36 month average annual increase of 134 kb/d for the Other 6 OPEC group which excludes the Big 4 and Iran and Venezuela. Iran and Venezuela have seen their output rise over the past 3 years at an annual rate of 386 kb/d which I believe will fall to zero in the near future. The chart below shows the long term trend for the OPEC Other 6 which is roughly flat (a small average annual rate of decrease of 4 kb/d over the past 11 years.) I expect the Other 6 will see their output return to this flat trend in the next few years.
Refinery crude throughput is a measure of World demand for C+C (though imperfect because some crude is burned directly in power plants in the middle east.) OPEC data shows the peak was 81.68 Mb/d in 2018. For the most recent 4 quarters the average World refinery throughput was 81.34 Mb/d, the previous 4 quarters had average refinery throughput at 81.00 Mb/d and 2024 had refinery throughput at 81.04 Mb/d. If the recent rate of increase continues (about a 450 kb/d annual rate of increase) we may see a new peak in annual average World refinery throughput in 2026.
Preliminary August 2025 data show that OECD commercial inventories fell slightly by 0.5 Mb, m-o-m, to stand at 2,793 Mb. At this level, OECD commercial stocks were 45.7 Mb less than the same time last year, 92.2 Mb lower than the latest five-year average, and 192.0 Mb below the 2015–2019 average.
OPEC has again reduced its estimate of US tight oil output in 2025 and 2026 compared to last month’s report by 20 kb/d for both years.
OPEC’s estimate for US C+C output is a bit more pessimistic than the EIA’s recent STEO where 13.53 Mb/d is forecast for annual US C+C in 2025 and 13.51 Mb/d in 2026, 210 kb/d less in 2025 for the OPEC estimate compared to the STEO and 300 kb/d less in 2026 for the OPEC estimate compared to the EIA forecast. Both agencies predict a near term peak in 2025 for US C+C. Also note that most of the increase in US liquids output in 2025 comes from increases in NGL output and all of the 2026 liquids increase in 2026 is due to higher NGL output according to OPEC estimates.
Longer term the AEO 2025 reference case has US C+C output reaching a peak of 14 Mb/d in 2027, but that case also forecasts higher oil prices with average wellhead oil prices at about $84-86/b in 2024$ from 2024 to 2026, rising to $92/b in 2027. The low oil price scenario with wellhead prices around $75-76/b in 2024$ in 2026-2027 and at $82/b in 2025 has the US C+C peak in 2024. So for the EIA at today’s wellhead oil prices the long term outlook is for lower US C+C output.
The chart above compares the short term outlook for Global Liquids demand growth from OPEC, EIA, and IEA. OPEC has the highest estimates, IEA the lowest and the EIA is in between fairly close to the average of the three. There is a fair amount of uncertainty considering the short term nature of the forecast with OPEC’s estimate being roughly 2 times that of the IEA.
The EIA’s International Energy Outlook(IEO) from 2023 has long term global liquids consumption increasing by about 18 Mb/d from 2026 to 2050.
For Global C+C output the IEO 2023 has 2050 at 92.7 Mb/d, actual 2024 World C+C output was 82 Mb/d, so only about 60% of the increase in global liquids is expected to be from C+C with the balance being mostly NGL and biofuel. The IEO 2023 reference case reaches 85 Mb/d for World C+C output in 2040, but note that this scenario from 2023 assumed that oil prices would be high in 2024$ with Brent prices ranging from a minimum of $94.73/b in 2025 and rising gradually to $103/b in 2024$ by 2040 and rising to $109/b in 2024$ by 2050.
122 responses to “OPEC Monthly Oil Market Report, October 2025”
Post by Mr. Shellman on Garzon Delaware post at linkedin
https://www.oilystuff.com/group/engineering-and-geological-discussions/discussion/3e59333d-c6fd-4bbd-ad41-03c1fd26de6c
(Mike asked me not to comment his blog, honoring that. Here…open discssion.)
1. Reads like he’s a little grumpy about the topic, versus just analytical. (Understandable, but what matters in the end is arguments, not exasperation…and it is possible to be exasperated from the other side, also.)
2. I don’t understand what Tier 1/2/3/4 means, either. Not even being prickly about terminology, Novi should specify what they mean (and so should other operators, analysts.)
3. I don’t think Novi predicted much of anything in 2011. They are sorta hindcasting and looking at total basin now, versus the history of development.
4. (Not a Mike thing, just looking at Novi chart more closely myself). Just noticed the segmented column chart has a nonzero axis. So well over half the locations were Tier 1 to start (not quartiles then, I guess). And still well over half are Tier 1. It’s a massive amount of T1 inventory in that case.
5. I agree that people tend to drill their best first. But that leaves the puzzle of why T4 is developed so fast in this example. Hope that is a Novi teaser and they give us an eplanation later.
6. Mike notes the gasiness especially if you move to the west of the core. This backs up what I was trying to explain to Dennis. That right now, nobody is drilling for gas. This means if they need it 20 years from now, there are areas that are gas rich, oil poor, that could become economical as Waha prices improve. I.e. that gas egress pipes are not that risky. Permian unlikely to run dry of gas supply. I’d be worried about the oil first. And I’m not that worried about the oil pipes. But definitely not the gas ones.
7. “$11MM hz”. I wonder if this is STILL the drilling decision model that includes sunk cost of lease aquisition. For a going forward model, if the land is leased, that cost is sunk. Sure we can rate people on M&A decisions. But if we are looking at (what is mostly) infill drilling, the cost of the land is irrelevent to the going forward question of how much the basin will get developed.
8. Discussing high prices for leases from the Feds. (And yes this is new land aquisition, agreed.) I mean…the Feds are auctioning those rights. If people want to pay $120M/acre than that’s what the market sees as the value. And that’s with 10 years of development experience and 10 years of listening to peak oilers and Wall Stree fuss at them. And two price crashes. And current/strip prices being relatively low. Yet still the paying market values that land high. Maybe the market is not as negative as the shale doomers.
Nony,
$120k per acre and note a 10k lateral on typical 1320 foot spacing would require about 300 acres for a drilling unit. 120k times 300 is $36 million, wow. Let’s say 4 wells can be drilled in Wolfcamp A and B and 2nd and 3rd Bonespring on such a plot of land, that’s 9 million per well on top of 7.5 million per well to drill, complete and equip the well so $16.5 million, seems expensive. We would need about 825 kbo per well just to pay for the well and lease cost at current oil prices. Seems a very risky bet.
Nony,
The model is not a drilling decision model, it is a model asking a different question. Not do I drill or not drill, but is this a viable business or not? It is the difference between long term and short term thinking.
On those high prices, there is a sucker born every minute.
On the natural gas, it is never a matter of running out of gas, in the Permian the gas is not worth drilling without the oil, tight oil drives the economics as tight oil output falls due not non-core areas not being profitable to drill, the gas output will also fall. Nobody drills for shale gas in the Permian purposefully, they are just failed tight oil wells.
On Delaware Basin locations in 2011 the chart is zero scaled on right vertical axis.
In 2011
tier 1-27k
tier 2-28k
tier 3-28k
tier 4-27k
approximately.
63% of tier 1 and 80% of tier 2 locations have not been developed so 17k of tier 1 and 22k of tier 2, about 39k tier 1/2 locations remaining.
New post from Garzon
https://www.linkedin.com/posts/jorge-garzon-ph-d-00633672_everyone-knows-delaware-holds-more-top-tier-activity-7388935990821904385–Iw0?utm_source=share&utm_medium=member_desktop&rcm=ACoAABDV_wMB3QBPTlgD0zpWSJp3xTFeAV0uqvA
About 30% of top tier (probably tier 1/2) have parent child degradation.
Also not that the best formations (highest average EUR) which are Wolfcamp A and 2nd and 3rd Bonespring have highest rates of parent child degradation (about 40%) maybe about 5000 locations in these 3 formations with less than 15% degradation. At current prices these are the only locations that are likely to be profitable to develop. Recent annual rates of development have been about 1400 wells per year for tier 1 and 2 so less than 4 years of top quality locations not affected by parent/child degradation.
At $60-70/b and $2.50/MCF Permian is probably past peak and will decline more steeply after 4 years or so.
How is it not a drilling decision model, when you use the (sunk cost included) full cycle economics to inform yoursel on the future Permian production, with comments like:
“At $60-70/b and $2.50/MCF Permian is probably past peak and will decline more steeply after 4 years or so.”
Nony,
I look at the simple NPV model using point forward model and the fact that average new well EUR per foot of lateral is decreasing and the information on parent/child pressure depletion from Novi in both the Midland and Delaware Basins, the 4 years is based on poor economics of the remaining tier one locations due to pressure depletion reducing future new well EUR.
We can assume 2025 wells are similar to the average 2020 well (likely an over estimate) and assume all producers have capital costs similar to FANG at about $8 million per well. In that case we get an average annual ROI over the life of the well at 2.2% per year at $60/bo and $2.5/MCF and NGL at $17.4/b. These companies need to pay back debt and many have a dividend yield of 4%, this low ROI is not going to get it done and I haven’t included plugging liability at the end of well life which brings annual ROI down to 1.8% per year. Eventually the low prices lead to a slow down in completion rate and decreasing output as a result. A high oil/natural gas price scenario would give different results. At oil price of$65/bo, NGL at $18.85/b, and NG at $2.50/MCF, annual ROI is 2.8%, still not enough to cover 4% dividend and corporate income tax.
Thanks for the update, interesting that Libya have almost recovered from the government change (coup if you´d like, NATO sponsored in my view) caused by, in part, selling oil in Euros, not USDs….
Also PDVSA will be most interesing to follow.
Dennis,
This post of yours is not showing up on the main page.
Only by tapping your link in last post brings it to the screen.
Coffeeguyzz,
What browser are you using? Try refreshing page or different browser.
Just tested on Chrome, Edge, Firefox, and Duckduckgo browser, seems to work for me.
Dennis,
Brave browser.
A couple of hours after I commented, this posting was viewable on the home screen as usual.
Some George Kaplan type information.
GLOBAL OIL DISCOVERIES COLLAPSE TO DECADE LOWS DESPITE FRONTIER BREAKTHROUGHS By Rystad Energy – Oct 23, 2025, 4:00 PM CDT
• Annual discovered volumes have fallen from over 20 billion boe in the early 2010s to just 5.5 billion boe in 2024, despite new frontiers emerging.
• Exploration focus has shifted toward a few prolific basins—particularly the Orange Basin in Namibia, the pre-salt in Brazil, and the deepwater zones of Guyana and Suriname.
• Supermajors and NOCs now dominate global exploration, prioritizing strategic precision and technological innovation amid reduced budgets and rising energy security risks.
“Annual conventional discovered volumes once averaged more than 20 billion barrels of oil equivalent (boe) per year in the early 2010s, but these have fallen to nearly one-third of that, with analysis by Rystad Energy showing global discoveries have averaged slightly over 8 billion boe annually since 2020 despite several standout frontier finds in Namibia, Suriname, and Guyana. Despairingly, the yearly average declines further to about 5.5 billion boe between 2023 and September this year. The contraction reflects a strategic change where the global exploration map of exploration and production (E&P) companies is defined less by sheer acreage and more by strategic precision. Supermajors and national oil companies (NOC) alike are narrowing focus on a handful of high-impact basins – Namibia’s Orange Basin, Suriname’s deepwater basin, and Brazil’s pre-salt basin – and infrastructurally rich near-field explorations, while divesting from marginal, mature, and low-return regions. These advantaged exploration campaigns blend advanced subsurface datasets, low-cost near-field tiebacks, implementation of digital technologies, and utilization of low-carbon infrastructures to balance risk with return.”
https://oilprice.com/Energy/Energy-General/Global-Oil-Discoveries-Collapse-to-Decade-Lows-Despite-Frontier-Breakthroughs.html
And yet the EIA chart near the bottom shows “The EIA’s International Energy Outlook(IEO) from 2023 has long term global liquids consumption increasing by about 18 Mb/d from 2026 to 2050.”
That implies a few things, including a huge increase in productive acreage devoted to biofuels worldwide. Most countries will do much better simply deploying EV’s rather than engaging in a big expansion of such a low margin/low EROI and high cost (in acreage) project as biofuels.
The discovery numbers as used by peak oilers ignore the increases in resource in existing fields. So, for instance the “new” potential of the Spraberry (post 2010) is allocated BACKWARDS to the discovery of the trend (1950ish). This has two effects. It makes the past look bigger and the present look smaller. Both helping to give that sooper scaree looking discovery graph that peak oilers love to cite. (Which somehow ignores the massive practical increase in production/reserves/resource of oil and natural gas, within the USA.)
Nony,
Yeah those peak oilers at Rystad don’t know what they are doing.
see also following which summarizes recent Rystad research
https://dieselnet.com/news/2025/08rystad.php
Dennis:
That article actually supports my point. Instead of comparing new discoveries to production, you SHOULD include the increase in resource within existing fields. In this case, you see the resource GREW. I.e. we “found” more than we used up. We outpaced consumption.
“While the global amount of discovered, recoverable oil resources (Rystad’s 2PC category) has increased by 5 billion barrels over the past year, this net increase was driven primarily by the delineation of upside potential in Argentina’s Vaca Muerta play and the Permian Delaware basin in Texas and New Mexico—rather than by new discoveries.”
BTW, if you look at this Rystad press release rather than dieselnet.com’s reprint, they actually headline the same info more positively:
“Discovered, recoverable oil resources increased by 5 billion barrels despite production growth in 2024”
https://www.rystadenergy.com/news/discovered-recoverable-oil-resources-increased-by-5-billion-barrels-despite-produhttps://www.rystadenergy.com/news/discovered-recoverable-oil-resources-increased-by-5-billion-barrels-despite-produ
Like anoymous said 5B barrels not enough to supply US for 1 year. LOL
Klim: Good point. Still…held serve versus depletion.
5 is global and is “equivalent” oil (BOE) . IIRC, crude would be 1/2 or less of this.
Nony,
The recent Rystad 2PCX estimate has Global C plus C URR at about 3100 Gb, pretty close to my guess. Could be larger or smaller than this, from 2600 to 3700 Gb for an 80% confidence interval. Depends on prices.
On cost per well look at capex compared to wells completed to get an idea of D&C cost. At the enterprise level sunk costs cannot be ignored because they affect the bottom line.
Dennis:
The vast majority of the Permian has already been leased. If you look at going forward well costs,, that cost is sunk. You don’t get it back by failing to drill a well on leases you have already paid the bonus for (or bought from someone else). That money is gone.
Evaluating drilling decisions going forward has to be done based on avoidable costs, not sunk costs. MBA 101. The same applies to a pipeline or an LNG plant. Those costs are sunk. Even if a project ends up being NPV negative in the end (based on total costs), once you’ve already put the steel in the ground, you don’t turn off the machine, unless the cash costs are negative. The same thing applies too wells themselves. Even if the project was a bad project in hindsight, you don’t stop pumping the well. You get what you can out of it.
If you want to give the executives a resport card on their past decisions. If you want to evaluate the old leasing decision or M&A, fine, include the lease costs. But that’s fundamentally a different question than “will the new wells get drilled or not”. Even if they are full cycle negative NPV, you can’t get the sunk costs back AFTER the decision was made. OXY can’t have the money back for buying APC. That money is gone.
Note that this does not mean that every lease aquisition is a bad decision in hindsight. E.g. when EOG ran around the core of the Bakken buying leases for a few hundred an acre, that ended up being a very positive decision in hindsight You pays your money and takes your chance.
But after the money is gone, it’s gone. You don’t get it back by not drilling. The decision to drill wells (inspecially infill wells) is just based on going forward economics. After all the lease acquisition costs are sunk. And the lease is held by production.
Also…if the acreage is so crappy, why are Federal auctions getting such great prices? That’s the market talking. Might be wrong, but so be it. Could be wrong low as well as high!
I mean do I think gold should intrinsically be worth 4000/oz? No. Could it crash? Yes. But still…that’s what people are paying for it.
Nony,
So people are paying big bonuses, but we should ignore that right? Yes sunk costs are not considered when deciding to drill or not, but if I were an investor I would be interested in full cycle cost as that is what flows to the bottom line. You can’t say everything is great because large amounts of money are being paid for leases and at the same time claim that we shouldn’t consider land or lease costs. The fact is that if a company pays a billion per acre for lease costs it is a very big sunk cost, so big it will sink the ship.
Consider also that high prices indicate scarcity, so one would think a free market fundamentalist would realize that such high leasing costs suggests there are not a lot of good prospects, that is there is scarcity of tier one and tier two drilling locations.
You are almost always talking about expected future production and total resource development. In these cases, the sunk costs should not be included. If you look at the Permian and want to know how many wells will go into it, sunk costs are sunk. Take them out of your model. It was a mistake when you didn’t vet Mike’s number more carefully (and he even warned you).
Almost all of the basin is leased. And a lot of it already has parent wells even! In these cases, the cost of the land is sunk. Sunk, sunk, sunkitty sunk.
If you are bidding on a Federal lease auction, of course you look at full cyle. Since your decision is full cycle. But for the vast majority of the basin, this is not the case.
“Consider also that high prices indicate scarcity, so one would think a free market fundamentalist would realize that such high leasing costs suggests there are not a lot of good prospects, that is there is scarcity of tier one and tier two drilling locations.”
————
This is another economic fallacy. (Sorry.) There is no requirement to make a bid at these auctions. Capital is fungible. Companies can just decline. And if prices go low enough they will!
Anyone paying that amount of money has a model to justify their bid. And yes, in that case FULL CYCLE. Since we are looking at the acquisition decision itself. They might be wrong. But they are not going to just buy if the NPV is negative. Lots of GOM leases go unbid on, even! They have convinced themselves the acreage is worth it. And put their money behind their opinion!
I mean was it crazy when Josh Harris paid $6B to Dan Snyder for the Washington Football Team? Maybe. Maybe not. But he convinced himself and his partners that he could make the asset pay enough to justify the price. And Dan Snyder would have sold for less if he had to…but that was what the bidding topped out at. And he would have gladly taken more also. But no investor could convince themselves that the team was worth it.
If anything, those high lease prices (on CURRENT auctions) should make you consider how the Permian may have more legs than you think it does. Gotta stick a lot of straws in the ground to make those projects pay off. 😉
P.s. If you are still having a problem understanding this, consider what LOW prices paid for leases indicate. Do you think that means the industry sees more oil in them? No. So…high prices for leases means the industry is betting plenty of oil and gas in the ground. And the converse. So high prices paid for lease auctions are a vote of confidence
Dennis, ignore this Annoying fella, he is simply being antagonistic to draw attention to himself.
If lease bonuses in a recent purchase of a Federal/ BLM bolt-on lease in the Delaware Basin should be consider in “full cycle” well costs, so should $4.5 MM per drillable location in the Midland Basin be considered in an M&A in the Midland Basin.
Exxon and Diamondback just paid $92 stinking billion dollars to acquire acreage in the Midland Basin…try “sinking” THAT into oblivion, as if it never was spent. That is the stupidest thing I have EVER heard from an internet expert. How else are Exxon and Diamondback going to pay back their collective debt of $43 B other than from oil and gas revenue from wells drilled ON that acquired acreage?
Revenue from production carries the burden of ALL corporate debt, copy paper to jet charters to CEO salaries to interest on long term debt to dividend payments. Particularly to paying long term debt…back. Yeah, that actually has to be done before the Permian sector can consider itself “profitable.” And there are 57,000 HZ wells to plug and clean up. Those are all liabilities and no oil company, or pizza maker, is profitable until all its debt, ALL of its liabilities are paid off, in full. Then we’ll look at the bottom line.
Land costs are real, read what oil men say about it at my place. Read the AFE’s I provide. It is the height of ignorance, and deception to ignore those costs.
I do not know what portion of new Delaware Basin wells to be drilled carry the burden of new leasehold costs; there is an enormous amount of debt to carry in that Basin.
In the Midland, Exxon and Diamondback control 80% or more of remaining locations left to be drilled and the $4.5 MM per drillable location identified by Reuters, Bloomberg, Enverus, etc. is the real deal. That puts well costs ABOVE $12MM.
Find me, please, how many Midland Basin wells have made, will make in a severely pressure depleted environment, over 700 K BO each in their life time X $15 net back at $60 WTI NYMEX. I can. Its way less than 3% of total.
Ignore this guy. He doesn’t know shit.
If you can’t do your OWN work, for instance with regard to economics and when a marginal stripper well meets economic limits, then you are total reliant on what people tell you to think.
And very selective on what you wish to hear.
Mike,
I agree, I try to do my own analysis, but getting all the numbers together can be tricky in trying to determine an industry average for say OPEX, CAPEX, royalty burdens, severence taxes in each tight oil and shale gas basin. I do the best I can with limited information and a very limited budget. When I look at capital expenditure at FANG and wells drilled I get about 8 Million in 2025Q3 (average lateral length about 11.5 kft). When we add the cost paid of $4.5 million per location, at least for those locations it would be over 12 million.
FANG has about 15 B in debt, some of that comes from mergers and costs paid for drillable locations. We want to be careful not to count this debt 2 times, if we are going to include the land cost as part of well cost, it needs to be deducted from the debt accumulated. I think some people look at this as the profits from the well are used to pay the sunk costs (debt) rather than including those sunk costs up front in the cost of the well. Debt for FANG has increased by 10 Billion in past 12 months (June 2024 to June 2025). Exxon is too complicated for me to get my head around Fang is a much simpler story. Agree 100% all debt and plugging liabilities need to be included, along with dividends, interest, etc for a company to be considered profitable. Also for FANG for 2025Q2 they had net revenue of about $20/BOE, the average EUR for Permian 2020 wells is about 1030 kboe, so that would be about $20 million in net revenue over the life of the well (20 year well life assumed). So at $8 million for D&C cost, we get $12 million back over life of well at 2025Q2 realized prices, some of this can pay back debt, while also paying dividends and corporate taxes (interest is already included in expenses, along with royalties and severance taxes.)
One obvious problem is that with $15 B in debt and at 2025Q2 realized prices (and they are worse now) we would need 1250 wells to pay back the debt, they claim to have 7700 future locations as of end of 2025Q2, but only about 2000 of these locations are in Wolfcamp A and Lower Spraberry where the best results occur and a significant portion of their acres are in low productivity counties like Reeves, Pecos, Ward, Reagan, Glasscock, Howard, Ector, Crane, and Andrews county. In addition there is a significant proportion of cash flow being paid as dividends, so not a great chance the debt will be repaid.
Nony,
You can’t have your cake and eat it as well. High prices suggest scarcity, low prices suggest abundance. You can’t at the same time suggest oil prices are low so there is plenty of supply and price of drilling locations is high so there must be plenty of drilling locations. I agree that the high price paid for a federal lease suggests these are probably prime drilling locations, the point is that the high price also indicates there may not be many locations available that are in the core (tier 1) areas, that is the reason prices are high. I consider company wide bottom line and for that all full cycle costs should be considered, debt must be paid back eventually.
Nony,
Yes drilling decisions are made on a point forward basis. That’s how I do my NPV analysis. One also should consider big picture, is this enterprise a viable business? One can look at the entire basin as one very large enterprise called Permian Inc. Can the enterprise succeed by paying back all of its debt, and plug all wells when they reach end of life and restore the land after the wells have been plugged? It is the more interesting question in my view. This is long term thinking rather than short term MBA thinking, two very different perspectives, I take the long view.
Rystad piece at link below
https://www.rystadenergy.com/news/discovered-recoverable-oil-resources-increased-by-5-billion-barrels-despite-produ
at $60/b about 1261 Gb of 1519 Gb of 2PCX resources are commercial.
Note that a 5 Gb increase on 1519 Gb of resources is about 0.33%.
the low oil and gas discovery in 2024 is a result of decade long almost fanatic drive by the climate change extremists, and forced almost all major IOC and NOCs into green wash waste of money.
The increase in Vaca Muerta delineation is huge in terms of oil, probably tripled the original projection, i.e. from 16GBO to >40~50 GBO according to my calculation.
“ forced almost all major IOC and NOCs into green wash waste of money.”
Can you point us to any examples of IOCs or NOCs wasting money on green wash?
Nick G,
seems that EU oil and gas companies did most of the green wash, from Statoil changing name to Equinor, to BP’s green diversion and backtrack to oil and gas, and now this UK service company, Petrofrac collapsed with wind,
https://www.logisticsmiddleeast.com/news/petrofac-collapse-gcc
US companies just green wash with website and banners, claiming heading to zero emissions, but actually drilling harder.
Persian Gulf NOCs actually are starting to invest in solar and wind, but more symbolic than real yet.
“ The business has been in financial trouble for years, starting with a Serious Fraud Office investigation in 2017 that resulted in a conviction in 2021 for failing to prevent bribery and the payment of more than $100m in penalties. That investigation made it harder for the company to win work. It bounced back initially, before the coronavirus pandemic added to its woes.
Petrofac has been trying to restructure its finances for more than a year, and a formal plan was approved by the high court in May. It has debts of that may be approaching $4bn (£3bn), according to a judgment from July in a case brought by some creditors.
But the company told investors on Thursday that the cancellation of a contract by TenneT, a European electricity grid operator and its biggest customer, meant that a solvent restructuring was no longer possible. The TenneT contract was to build offshore wind projects off the Dutch coast.”
https://www.theguardian.com/business/2025/oct/27/oil-gas-petrofac-files-for-administration-jobs-north-sea
It looks like Petrofrac’s only problem with wind was that it didn’t get a wind contract that it needed to maintain cashflow.
“ Persian Gulf NOCs actually are starting to invest in solar and wind, but more symbolic than real yet.”
Yeah, they’ve been over promising and under delivering on solar and wind for years. Solar especially would be an incredibly good investment in the ME, freeing up oil and gas for export, but O&G operators have a hard time transitioning to…well…anything else.
Picking on a subject that has garnered attention of late-
Nuclear energy is going to take a long time to make a significant impact on new E generation, and it will be very expensive to build.
For the AP1000’s that are the go to reactors currently in much of the world we are looking at 7-15+ $B per unit, and something like 7-15 years timeline. Vogtle unit 3 & 4 in SC are AP1000’s and they took 14/15 years to construct and 30$B cost overrun.
SMR’s are projected to be more expensive/kWh.
Time will tell if we can do better (despite inflation in labor, materials and fuel).
The 2025 status report of the Global Nuclear Industry is excellent if you have any interest in all the details, including projects in the construction or planning phase.
https://www.worldnuclearreport.org/IMG/pdf/wnisr2025-v1.pdf
A few highlights from the summaries
-Over the past two decades (2005–2024), there were 104 startups and 101 closures in the world. Of these, 51 startups were in China, which did not close any reactors. As a result, outside China, the net number of reactors has significantly declined by 48 units and net capacity has declined by close to 27 GW over the period
-In 2024, total investment in (non-hydro) renewable electricity capacity reached a record US$728 billion, 21 times the reported global investment in nuclear energy. Solar and wind power capacities grew by 32 percent and 11 percent, respectively, resulting in 565 GW of combined new capacity, over 100 times the 5.4 GW of net nuclear capacity addition. Global wind and solar facilities generated 70 percent more electricity than nuclear plants (in 2024).
-Fukushima Status Report- Onsite and offsite challenges remain overwhelming, with an initial removal of fuel debris amounting to around a billionth of the total.
——————
An additional report worth considering, at least the abstract and executive summary, is-
Advanced Nuclear Power Program- 2024 Total Cost Projection of the Next AP1000
https://web.mit.edu/kshirvan/www/research/ANP201%20TR%20CANES.pdf
This is written with industry enthusiasm out of the MIT Department of Nuclear Science and Engineering.
Nuclear is like hydrogen passenger vehicles: feasible but very far from competitive. Kind’ve technologically sexy, but falling further and further behind in cost and timeliness.
And no one in the nuclear industry is willing to address the 800 pound gorilla in the corner: weapons proliferation. Nuclear weapons came first, nuclear power generation was a distant after thought and an obvious attempt to improve the image of countries that wanted nuclear weapons, like the US and France.
Nuclear power is inextricably linked to weapons, which is why European Greens hate nuclear power. Why does everyone have so much trouble understanding why so many Germans hate nuclear power? They were the likely battleground between the the US and the USSR, where tactical nukes would have been deployed – remember the neutron bomb?
———————
Modular nuclear seems to make sense, at first blush. The problem is that nuclear power plants were built at 1GW scale for a reason: the physics of shielding, containment and heat-engine efficiency point to very large scale. Reduce the size and you are trying to swim upstream: many of your costs rise inextricably.
They work well in cost-plus environments like nuclear subs, but I can’t imagine they’ll compete with wind and solar except in very niche situations (the Arctic?).
In theory modular reactors could reduce costs with large unit volumes and expanded manufacturing experience, but they appear to be far too behind to catch up in that way – the “runway” is just too short for it to take off.
Nick
France has the highest amount of electricity generated by nuclear power.
https://www.rte-france.com/en/eco2mix/power-generation-energy-source
Germany now has practically none.
Germany has the highest amount of electricity generated from wind and solar.
Do you know how much?
Do you know which country has the cheapest electricity?
https://ec.europa.eu/eurostat/statistics-explained/index.php?title=Electricity_price_statistics
A grid engineer tried to explain on here where the extra cost come regarding wind and solar. Why don’t you learn anything?
The facts speak for themselves. The last twenty years of increasing wind and solar has seen relentless price increases of grid and balancing costs.
Nick
France has the highest amount of electricity generated by nuclear power.
https://www.rte-france.com/en/eco2mix/power-generation-energy-source
Germany now has practically none.
Germany has the highest amount of electricity generated from wind and solar.
Do you know how much?
Do you know which country has the cheapest electricity?
https://ec.europa.eu/eurostat/statistics-explained/index.php?title=Electricity_price_statistics
A grid engineer tried to explain on here where the extra cost come regarding wind and solar. Why don’t you learn anything?
The facts speak for themselves. The last twenty years of increasing wind and solar has seen relentless price increases of grid and balancing costs.
Iver:
The USA has more than double the MW of nuclear power that France has. France has highest in-country percentage. Not the biggest fleet.
https://www.nei.org/resources/statistics/top-15-nuclear-generating-countrieshttps://www.nei.org/resources/statistics/top-15-nuclear-generating-countries
Unless, you just meant Europe, in which case: https://www.youtube.com/watch?v=OjYoNL4g5Vg
RBN Daily Blog on two/three well simultaneous fracking:
https://rbnenergy.com/daily-posts/blog/producers-ramp-simultaneous-fracking-triple-fracking-increase-efficiency
Read ASAP, before it gets paywalled.
See in particular the diagram showing the simplified piping arrangement. Also, includes a comparison to zipper fracking.
Benefit is cheaper costs (up to 10% improvement). Detriments are less customized completion design (per well). Also, higher upfront cost (but money is a commodity) along with the logistics of double (or triple) the sand/water at once. Also an increase in pumping capacity, but the diagram makes that look nonlinear (i.e. less than doubling).
Per Novi, essentially all Permian wells would get completed this way if the logistics (pad space, deliverability of sand/water) allowed it. I.e. companies think the cost benefit worth the less fussy completion optimization. (Bad news for selling AI/ML?) But a fair amount of the play doesn’t hae the infrastructure (space, roads, water pipes) to allow this sort of manufacturing style completion. Maybe 50% are completed that way?
there is also innovations to reduce the logistic load, e.g. on-site slick water preparation, near-site wet sand, etc.
Dennis:
On shale well end of life. Continuing discussion from last thread.
1. I would be VERY wary of the “I got it from a guy with 50 years experience”. First of all that is a sample of one. You need to cast your net more widely. There are a huge amount of people in the tight oil industry. It is great to get information from SMEs, but you have to do some sampling. If guy A says answer A and guy B says answer B, they can’t both be right. So…”I got it from an expert” has some limitations.
1.5. Also, be aware that not everyone is an expert on everything. Doing some projects kind of gives a starter for info, but don’t take it as an end point. In particular, there are people with degrees in petroleum engineering, specialized in reserves estimation. There are firms that do this for a living. Doesn’t mean they are right…how can we know, if the wells haven’t aged out yet, what the average end of life will be? But…I would at least talk to someone from Ryder Scott or the like. Even if you don’t like what they say, TALK to them and listen and at least have heard them. Sure there may be some evil grassy knoll conspiracy. But I would at least see if they don’t have such conservative lifetimes, WHY they don’t. Maybe they laugh at the “won’t be able to maintain a hz well” concerns. Or maybe they even validate you. I donno…but check.
2. It’s interesting to hear you say 20 years now. Could swear I’d seen 15 from you back in the day. I could be wrong and it was commenters. What were you saying 10+ years ago?
2.5. Heck, I remember some peak oiler saying 10 back in the day! Was that you? Not at an accusation at all, just asking. Can’t remember who all was pushing that. Patzek? Random doomer commenters? I know I heard this from some shale naysayers. But here we are in 2025 and the goalposts have shifted.
3. I agree (!) that the difference of 25 to 30 doesn’t matter much. Most of the production comes early. So 2% EUR in last 15% of life would not surprise me. [And it’s even less important economically, given discounting!] That said, I bet going from 10 to 40 makes some difference.
3.5. Or for that matter, if it’s no big deal to do X versus Y, why do you default to the conservative skewed estimate? Why not be generous and say that you have resource concerns despite being generous. Rather than putting a thumb on the scale in your benefit.
Nony,
I try to do something that is accurate. 10 years ago I used 30 year EURs for tight oil, those who knew more about real world oil operations suggested that down hole failures would kill most wells under 10 bopd, I use 7 Bopd to be conservative, most tight oil wells in the Permian reach this point at about 20 years (2020 average well). Downhole failures probably occur about every 10 years on average. The ROI on this capital expense after reaching 10 bopd does not pencil out. On inactive wells vs plugged wells, many of these are operators waiting as long as possible to plug the well, state agencies often let these slide.
The downhole issue is not as much of a problem for dry gas wells that produce little water, so these wells might last for 30 years.
Also 10 years ago, I only considered tight oil and was not looking as shale gas output. For average Utica wells output at 25 years is similar to Marcellus wells at 30 years, roughly 4 boepd which seemed a reasonable cutoff.
Also in response to those complaining that my estimates are too optimistic I will sometimes do scenarios with shorter well life to show how it changes the analysis, it does not change things very much, I have tended to use a cutoff of 7 bopd for tight oil wells to be shut in, well profiles have changed over the years, so a well in 2013 might have reached this point earlier than a 2020 well and the well profiles vary from basin to basin.
Eagle Ford 2015 average well reaches 7 bopd at 15 years. The average 2016 Niobrara well reaches output of 7 bopd at 6 years. The average 2015 Bakken/Three Forks well reaches 7 bopd at 18 years, and the average 2015 Permian well reaches 7 bopd output at about 16 years. In 2020 the average Permian well had a longer lateral than in 2015 and those wells reach 7 bopd at 20 years. If we extend well life out to 30 years for the average 2020 Permian well (where output reaches 1.8 bopd at 360 months) the EUR increases by about 3% vs the assumption of the well being shut in at 20 years (I use the 20 year number to be realistic).
Nony,
There have been others such as LTO Survivor who was the CEO of a mid-size Oil Company, there is shallow sand who operates a small oil business, there was Fernando Leanme who was a petroleum engineer for a large multinational oil company, so no not a sample of one. I also posted the comments from a recent Dallas Fed Survey where many of the comments are very pessimistic. You mentioned they are whining about prices, it is with good reason as low oil prices may be nice for you, but not so great for an oil company.
Maybe prices rise, I have been predicting that since 2020 and am still waiting, perhaps it happens, we will see.
https://www.dallasfed.org/research/surveys/des/2025/2503#tab-comments
https://www.dallasfed.org/research/surveys/des/2025/2503#tab-questions
Next report is mid-December.
Dennis:
You sound like a self-parody. Oh…it’s not one (self selected via commenting on a blog!) old warhorse, but three! Wow!
Heck, for one thing, Mike has even said that some disagreed with him (for instance on including sunk costs in drilling decisions). That’s a perfect opportunity to go talk to the “anti-Mikes” and hear what they have to say. This isn’t religion. You won’t get converted to a heresy. You don’t lose anything by surveying more of the market!
Have you ever done VOC? You claiming some kind of great industrial insights because three people (self selected via commenting here) on your blogs say things you like? Leaving aside peak oil entirely, I would never want you doing any kind of business development or marketing, with that lack of curiosity about the customer and that willingness to stick to your day one hypothesis.
Nony,
I do not have the opportunity to speak with others directly. Perhaps, EUR should be done to 100 years, it doesn’t change the analysis much in fact when done properly. We can speculate that horizontal fracked wells will last forever, but if we look at the oldest wells out there in the Barnett Shale (near Dallas). If we look at the oldest Barnett wells from 2001 as of 2021, only 1 of 5 was still active after 20 years. So we can speculate as to well life, but after 20 years there is not much to go on. There are a number of points of view, I am skeptical of both ends of the spectrum. Note however on the high end there is no limit the bottom end is bounded by either zero ( in the case of future output) or cumulative production to date in the case of URR.
So I reserve the right to be skeptical of for example Bakken/Three Fork estimates of 55 Gb. Those types of guesses are very likely to be too high in my view, perhaps a 1% probability at most that URR will be that high or higher.
Annoying: I have NEVER written publicly that “land costs” are always included in “decisions” to drill HZ tight oil/gas wells or not. Not EVER. That is an outright lie designed to make myself and Mr. Coyne appear less than honorable. I HAVE, constantly used land costs in well economic evaluations, EUR predictions and economic limit estimates. You are distorting the truth to cover your otherwise really bad take on tight oil.
As an example of your economic ignorance, lets take Diamondback, for instance, the second largest Midland Basin tight oil producer. It grew its gross long term debt from $12.9B to $15B in just one quarter, 2Q to 3Q 25. Does that sound like things are good? It paid effectively $4.8 MM dollars per drillable location, or for acreage that would comprise a drilling unit, when it bought Endeavor. If you ignorantly, Non-GAPP those costs. where do they go. They go over into long term debt. So, FANG better be considering land costs in ALL the wells it drills in the Midland Basin or its not going to pay debt back. Or pay plugging and decommissioning costs. Does that register?
So, what’s up with the “anti-Mike” stuff? I’ve been called a communist, an anti-oil, tree hugger, dickhead, disloyal patriot, but did not know there were anti-Mikes out there. They are, I am sure, heavily dependent on tight oil to make a living, regardless of depletion, CEOs making $20MM a year plus and, of course, royalty and overriding royalty interest owners that have made, IMO, three quarter trillion dollars from the shale revolution. And, of course, internet experts like you who cannot think for themselves and are TOTALLY dependent on links, websites, paid for journalists, self serving people IN the business and public opinion for insights.
“Anti-Mike’s”?!!
I am pro-American !!!
Mr Shellman,
Thanks!
Mike,
FANG’s CEO is making big AI pitch now to justify all the foreseeable cost-down and EUR improvement.
https://www.linkedin.com/posts/pathinds_technology-ai-diamondback-automating-the-activity-7375880679399731200-U_xK/
Dennis, another continued from last, PGC:
I’m actually sympathetic to your discounting of the PGC numbers for cost, etc. They are ginormous.
The interesting thing is that they grew. Despite production, and growth of production, the resource numers have climbed for last 20 years.
Whether PGC is biased high or low, there numbers grew over last 20 years. Unless their BIAS grew, it seems to show that as we learn more, the estimate grows.
———–
If it takes 50 years instead of 100, it’s sort of irrelevent economically. Won’t affect current pricing if we run out two generations from now or four from now. Hotelling theory will show that.
And that’s not even including the reasonable assumption that we have other sources of energy that far down the line, to take the pinch off. Mr. Fusion in a Delorean. Lot of time for the grasshoppers to party! The ants will make something when we need it.
Nony,
Yes they grew, but they are not very useful in my view. Also I am not going to pay for the report, so no idea where there numbers come from, the USGS information is not great, but there is some information, and the Patzek analyses are quite good in my view.
I’m not paying for it either!
But they are professionals. Lot of spiffy degrees. “Trust the science.” 🙂
You don’t have to buy it…but you should let it affect your uncertainty windows.
Actually based on the history of oil and gas, it will probably still end up low. Really bad record for bottom up estimates of resource. Look at past estimates from Hubbert, Laherre, etc. I remember Pratt saying something to Hubbert to the effect of “nice paper…but we’ve tried the total resource approach in the past [and he was talking in the 1950s]….and each time, we ended up exceding it.”
Fereidun Fesharaki says the same about Saudi oil reserves. Says he has seen the numbers get made up in the past even been involved in it. And look how they grew. but his gut is that the numbers are off low, not high!
Nony,
Lots of examples of estimates being too high rather than too low, Barnett was expected to be 45 TCF by BEG, looks like it will be maybe 60% of that, Bakken was expected to be 25 Gb by some, looks like it will be less than 50% of that. So gut estimates may prove to be high or low.
I agree there is uncertainty, my gut tells me the PGC estimates are 2 times too high, especially if we put a time window on the estimate of say how much natural gas gets produced by 2070, or look at economically recoverable resources rather than technically recoverable resources.
Lots of spiffy degrees at the USGS as well, but you do not trust that analysis and Patzek’s analysis is out there to look at in detail, it is a bottom up analysis, well by well.
ND monthly data is out.
https://www.dmr.nd.gov/dmr/oilgas/directorscut
Dropped 10,000 bopd. Not good. (Especially when winter is coming! Them boys ain’t making hay when the sun is shining.) I watched the YT video but kinda zoned out on the specific explanation for this month’s drop. He did say that in general the amount of activity (at current prices, with current rock quality) is basically keeping the basin close to flat, but with a slight decline.
If you look at the presentation, slide 10 is interesting, showing some J and U well experimentation (at least in permits).
Slide 14 (also discussed in video) is interesting in that it shows a clear trend to longer laterals. Not just fancy words. basin used to be stereotypically 2 mile lats, almost every one. but now about a quarter are 3 mile lats. He says it is being done to make drililng feasible in worse acreage. (Most of the core is drilled up and the few rigs are more on the fringe more, now.)
P.s. Apologies if this was in last thread, missed it.
North Dakota Bakken/Three Forks Scenario below assumes completion rate at about 80 wells per month until 2030 then gradual decrease in completion rate as fewer profitable locations may be available. URR about 9.4 Gb. My best guess certain to be incorrect.
bakken2510
Last 12 months of global production has exceeded any other previous 12 months.
Glad oil prices are this low.
Last 12 months average using EIA monthly data for World C plus C is 82614 kb/d, peak was 82962 kb/d in Feb 2019 for trailing 12 month average. In fact the trailing 12 month average exceeded the June 2025 average every month from November 2018 to August 2019.
https://www.eia.gov/international/data/world/petroleum-and-other-liquids/monthly-petroleum-and-other-liquids-production?pd=5&p=00000000000000000000000000000000002&u=0&f=M&v=mapbubble&a=-&i=none&vo=value&t=C&g=none&l=249–249&s=94694400000&e=1748736000000
DC
According to the IEA global production and global refinery throughput are the highest ever.
https://www.iea.org/reports/oil-market-report-october-2025
EIA are 4 months behind on data but their predictions agree with The IEA.
2025 is a new global high
Iver,
I don’t consider NGL and biofuel to be “oil”, I define it as crude plus condensate, the refinery throughput is defined differently by IEA than OPEC, perhaps by including non-crude inputs.
I do think we will see a new peak by end of 2025, but I think the EIA or Energy Institute’s Statistical Review of World Energy data is best and production data is probably more accurate than refinery throughput data.
D C
The amount of bio fuels has increased
https://www.worldbioenergy.org/uploads/241023%20GBS%20Report%20Short%20Version.pdf
Up a quarter of a million barrels per day from 2018 to 2023.
Let’s be generous and say it is now half a million barrels per day higher.
Global total liquids is expected to hit 106mb/d this year. Six million more than 2018. September reached 108mb/d !
How much of that is NGLs and how much is Oil?
I think about 1.5 million barrels of that is C&C.
Ovi’s chart prediction of 86.8mb/d for September. If so the record will be smashed.
That will be all 3 main institutes saying the same thing.
Iver,
Most of the increase will come from NGL, I agree there will be a new peak in C plus C, your guess seems reasonable. The EIA, IEA, and OPEC tend to focus on World liquids and have slightly different estimates for liquids demand growth (from 700 to 1400 kb/d for annual increases in 2025 and 2026). We don’t have specific forecasts for C plus C.
Anyone still follows Ghawar after Matthew Simmons?
Svaya,
I couldn’t find anything new on Ghawar since Oil Drum Days, but came across this comparison of Bakken to Ghawar
https://www.zawya.com/en/business/column-is-bakken-set-to-rival-ghawar-john-kemp-bp03ej2u
In that piece it says that Continental resources estimated 24 Gb of recoverable resources from Bakken and another 32 Gb of recoverable resources from the Three Forks Formation for a total of 56 Gb for the Bakken/Three Forks. These are probably TRR estimates, let’s assume 67% is economic, that would suggest 37 Gb of ERR for Bakken/Three Forks, an estimate that is probably 4 times too high (my best guess is roughly 10 Gb for Bakken/Three Forks with about 6 Gb produced up to Sept 2025.)
Likewise the Eagle Ford has cumulative output of about 5.5 Gb and peaked earlier in 2015 vs 2019 for Bakken/Three Forks so my guess for Eagle Ford ERR is a bit lower at 8.5 Gb. Up to now the Permian, Bakken/Three Forks and Eagle Ford have produced about 83% of US tight oil with the three formations probably having an ERR of around 68 Gb, if we assume this will be about 83% of US tight oil ERR we would have a US tight oil ERR of about 82 Gb (=68/0.83) with about 32.5 Gb cumulative production through Sept 2025.
If it is assumed that peak occurs at about 50% of URR (41 Gb) for US tight oil, this suggests peak occurs in about 3 years as about 3.3 Gb of tight oil are produced per year (recent 12 months) and we are about 8.5 Gb from the peak (8.5/3.3=2.6 years).
The specific shape of the tight oil output curve will depend on future oil prices and future technology developments both of which are difficult to predict. It is nearly certain the peak will be earlier or later than this very simple forecast.
Islandboy, here’s hoping you get past hurricane Melissa okay as the storm comes to visit you in Jamaica.
second that!
Some say that to have a lead in AI is a national security issue…internal and external.
Certainly it will have a major role in economic growth (and dislocation/destruction of certain workforce’s and industries.).
Electricity supply growth is clearly a major foundation for AI, along with other critical economic functions such as robotic industry, smelting, electrification of transport, etc.
Nuclear is a 2030’s and more so a 2040’s story when it comes to adding any significant generation.
That is too late to make an impact on AI for the coming 10 years. Too late for the major 1st phase of AI and quantum computing race, as some have pointed out.
I don’t see much sign of nuclear adding anything at all in the US, UK or France. They’re likely to lose more retirements than they gain in new plants.
France, in particular, has only built one plant in the last 25 years – Flamanville 3. It cost 4x the original budget (final cost 19B euros in 2015 prices, for 1.65GW), and it started construction in 2007 and finished…last year. That’s right – it took 17 years to build! The builder was EDF, the French state entity that runs their nuclear program. They are talking about building another 6 plants in the next 25 years, which are both a bit unlikely to happen (none have even finished the planning process, none are in construction) and very unlikely to do more than replace some of the 40+ year old plants that will be decommissioned during that period.
France hates fossil fuels, and nuclear has been flat and is very likely to decline. Instead they’ve been building wind and solar steadily, every year – now at 12% of supply and growing. The nice thing about solar: it’s synergistic with nuclear, as nuclear doesn’t help with the daytime peak, while solar fills in that peak. That means fewer imports at premium prices from Switzerland’s hydro to cover peak domestic consumption, and more net power exports.
Just checked in with Ron Patterson, he is doing well.
For Nick, re small modular reactors for use in the Arctic.
What could ever go wrong? 😉
https://www.youtube.com/watch?v=Q0zT9ARfsT4
Yikes!
Check out France’s nuclear power . French use translator .
https://lachute.over-blog.com/2025/10/parlons-du-nucleaire-et-d-autres-choses-aussi.html
Hubbert is famous for suggesting nuclear power as a solution for peak oil. And, of course, he was right: nuclear could work. It’s feasible, despite its problems.
What is less well known is that he also suggested solar power.
“In October 1973, the Arab oil-producing states cut back their exports to America in reaction to the nation’s support of Israel in the Yom Kippur War. The ensuing shortage, National Geographic reported in 1974, brought about the greatest disruption in peacetime in the United States and much of the rest of the developed world since the Great Depression of the 1930s: “Factories shut down, workers were laid off, lights dimmed, buildings chilled, gasoline stations closed, Sunday driving was banned, fuel prices soared, stock markets fell.” Petroleum geologist Marion King Hubbert, whose work had suggested such a crisis would one day occur because we were approaching the point of “peak oil,” told the magazine, “We’ve had an oil shortage in this country for more than twenty years and didn’t know it.” As far back as 1947, “our domestic production slipped below our consumption, and we became a net importer of oil.”22 “When political events cut back oil imports from the Middle East in 1973,” the National Geographic reporter commented, “King Hubbert’s 26-year-old oil shortage came alive.”
When asked about possible solutions, Hubbert suggested solar energy. “We have it already,” he asserted, and to prove his point he took from his pocket a propeller driven by a small motor powered by solar cells. When Hubbert faced the array toward the sun pouring in from the window, it “began to whirl,” fueled solely by the “clean, pure energy from a source at least as long lasting as man’s occupation of the planet.”
Noel Grove, “Oil, the Dwindling Treasure,” National Geographic (June 1974): 792–93. 23.Ibid., 794, 823
I have been leaning strongly towards a scenario unfolding that could put a big dent in oil demand.
It looks more and more like AI will result in big job losses over the next 5 years, and is already just beginning. At risk are white collar sectors of wide scope, and labor jobs subject to robotics replacement.
We very well may see a big and growing wave of unemployment, with loss of purchasing power and subsequent big real estate valuation decline…shortage of buyers with purchasing power.
This may become a large magnitude disruptive event. I think it will.
Employment in sectors of finance, administration of all sorts, HR, insurance, medical admin and billing, and government are examples of large scale jobs at risk. Most cities, small medium and large, have large employment proportions represented by these sectors.
All of these people will no longer be able to purchase fuel for discretionary purposes, and perhaps even more essential purposes.
Curious if you guys think this is a significant probability event.
“ labor jobs subject to robotics replacement.”
Have you seen any examples of this that were clearly due to AI (e.g., Large Language Models, etc)?
Any indication of an acceleration of automation of manual labor jobs due to AI? Remember, automation of manual labor has been happening for 300 years. For example agriculture in the US has gone from 95% of the workforce to 1% of the workforce, and that didn’t require “AI”. The same trend is clearly visible for manufacturing: jobs have largely disappeared while output has risen.
The automation is indeed a long story. Robotics is big in certain industries already (warehouse operations, manufacturing), and is a growing trend. I expect much more of this towards the end of this decade. AI will be a big enabler of this trend.
The white collar effects sooner.
https://www.wsj.com/economy/jobs/white-collar-jobs-ai-324b749c?st=Z7po7c&reflink=desktopwebshare_permalink&mod=tldr&utm_source=tldrnewsletter
Hickory,
Fundamentally, improvements in labor productivity are what make us all more prosperous. The fact that farms no longer employ 95% of the workforce has made all of our lives infinitely better. Improving labor productivity in manufacturing has made stuff cheaper, and freed people up for expanded services, most of which we are pretty happy to have.
AI has the possibility of freeing people up for other things. There are an enormous number of things which need to be expanded and improved: medical research, energy research, energy investments, elder-care, child-care, education, environmental cleanup, building housing and transportation infrastructure, mental health, helping other countries, etc., etc., etc.
We have to manage these transitions well. Crashes and bubbles are caused by bad management: examples are many and include tulips, gold, railroads, electrification, horses to tractors, housing bubble. On the other hand, there have been a number of crashes and bubbles which never became a recession or depression due to good management.
And, of course, we have a childish vandal in the White House right now, so I’m a bit nervous.
I hear you Nick, however I’m thinking that any attempt at ‘good management’ of the situation will get buried by the landslide of the actual scenario.
Certainly there will be big winners.
Yet there will be a trail of destruction that could get severe. Over the next 5-10 years watch payroll stats and residential real estate price trend.
This is a post on OPEC, yet the first comment was by DC on you guessed it. The Permian or also known as The Centre of the Oil Universe.
Does anyone here know anything about the oil industry in any other country?
Saudi Arabia? Russia? Iran perhaps?
Stopping non oil post was a bad mistake at least there was a break from the Permian.
Dennis how is your 8 year old prediction on self driving cars going?
I have phoned my local taxi firm for one they said, be a little while. Maybe another 8 years. Think I will get the bus 😂
Iver,
Thanks for that informative post. Chart linked below shows how tight oil does not matter. Increases in OPEC output will increase World C plus C over the next 12 months or so with the big increase since April pointed out in the post. Low prices are likely to reduce any future growth in US tight oil to zero or less. US tight oil is only 10% of World C plus C output, chart below is not zero scaled, so a very small part of the picture.
My comments on OPEC are in the post, Ovi will comment on Russia in his non-OPEC post, but you are always welcome to enlighten us. In the OPEC MOMR not much information is revealed about Saudi Arabia, Iran, or Russian oil output (besides the information I present in the post), mostly it covers the non-DOC nations.
world cc and tight
On self driving taxis what did I say 8 years ago?
In the US they are available in some places, but not where I live. Tony Seba was guessing in 2017 the transition would happen by 2020 (meaning 99% of new cars sold would be EVs self driving would be subject to regulatory approval), I think my guess was more like 2030, I most likely will be wrong.
https://www.youtube.com/watch?v=M27KECEL5Zo
Chart below which has a zero scale for vertical axis and uses the centered twelve month average (CTMA) gives a better impression of the insignificance of the Permian Basin vs World C plus C output.
permian2510
DC
You said self driving cars would be widely available by now and self driving taxis would be so cheap that many people would not bother buying a car.
Maybe you had just watched blade runner 😂
A quick, perspective jarring outlook (perhaps) that follows Iver’s view on other-than-Permian hydrocarbon news …
Yesterday, Robert Rapier posted on the emerging global potential (probability?) of shale development across the globe.
Even a 5 second glance at the provided EIA graphic depicting worldwide shale hydrocarbon resources should allay scarcity concerns of of all but the most committed (myopic?) doomsters.
No need for ‘running out’ fears due to geologic factors what so evah.
Iver,
I do not think I have ever believed that, can you point us to a quote with a link?
Even Tony Seba had only said (8 years ago) that EVs would be widespread by 2020, my modeling suggests at least 2035 before ICE passenger vehicles might be fully replaced, 8 years ago there weren’t any self driving cars in the US, Musk was making ridiculous promises which I may have reported, but have never believed. At some point self driving cars may become more widespread, likely not for 10 years (roughly 2035 at the earliest). When TaaS becomes common after self driving vehicles become widespread only the very wealthy will bother to own a car because TaaS will be far cheaper. Maybe this happens by 2040 (50/50 odds it will be earlier or later than this is my WAG.)
Thanks Coffeeguyzz,
Seems a bit of a puff piece. KSA with 230 TCF of Gas and 75 Gb of NGL and Argentina with 16 Gb of oil and 308 TCF of natural gas, for other nations no estimates are given. My mid-case scenario for World natural gas in 2015 was 19000 TCF with a range of 13000 to 26000 TCF. So for oil we have 16 Gb of about 1570 Gb of remaining resource and about 3100 Gb for URR (about a 0.5% increase in Oil resource from tight oil, probably already included in Rystad’s estimate). For natural gas the 538 TCF of potential shale gas would be a 2.8% increase, but note that my estimate for World shale gas and coal bed methane was about 4000 TCF, which leaves about 3000 TCF from outside the US (where my guess is about 1000 TCF for URR) so this 538 TCF would be a subset of the 3000 TCF of shale gas and coal bed methane from outside of the US. Also note that for my high case the shale gas/coalbed methane would be about 5500 TCF and my US high case is around 1400 TCF so this case would have about 4100 TCF of unconventional natural gas from outside of the US. A ton of uncertainty especially outside of the US so maybe 2000 to 8000 TCF might be a more reasonable guess (90% CI) for unconventional gas for the World excluding the US.
Note also I have never believed geology alone determined economically recoverable resources, it is how much can be extracted profitably that matters.
China’s Sichuan Basin is estimated to have 626 TCF of resources. Total shale gas resource for China estimated at 1115 TCF. These are technically recoverable resources ERR would be about 420 TCF for Sichuan Basin and 747 TCF for all of China assuming 67% of TRR is profitable as is the case in the US.
It is a common error when people try to imagine the impact of new technology to imagine that everything will stay the same except for the replacement of one tech with another. Another error is to imagine new tech simply replacing older tech across the board, instead of creeping into the market by taking over an ever increasing number of niches.
Self-driving cars will get here eventually, but not as a one-to-one replacement for cars in their current state. They have already been around for decades, but safety is an issue. Of course cars are already deadly, killing 40,000 Americans (about 20 9/11s) a year, but with a self-driving vehicle it is harder for corporations to dodge liability. Corporations and governments currently avoid liability by calling traffic deaths “accidents”, shifting the blame to the driver. Private cars are a dumb idea for mass transit anyway, and one of the main drivers of poverty in America. Asia’s huge cities will not develop on the same path.
Expect self driving to come with cars taking increased control over driving, and true autonomy being adopted in private areas like ports, airports, large factories, military bases, farms etc. Farmers on large Midwestern farms already rely heavily on self-driving. Check out John Deere’s website for details.
Infrastructure will probably have to adapt. Traffic lights are useful to human drivers, but digital communication between vehicles and intersections makes more sense for autonomous vehicles. Shenzhen already has a large network for this.
Electrification is the same. Practically all new demand for energy is for electricity. Buses and delivery vans are rapidly switching to the new tech. It is said that shipping will never be electric, but diesel powered cranes at ports are disappearing, and ferries and other short haul ships are already changing. Last-mile delivery is rapidly changing to electric, and port vehicles are as well. China is now trying to electrify riverboats.
China now builds more EVs than America builds cars of any description. Exports are booming. Big countries like Brazil and Ethiopia are now focusing on following China’s lead here. Just because you don’t see it in your immediate neighborhood doesn’t mean it isn’t happening.
Alimb,
Those are good thoughts, and I generally agree. Just one thing: it’s extraordinarily unrealistic to apply a “no-death” standard to autonomous driving. In my mind it’s primarily an attempt by legacy industries to protect themselves from competition. Secondarily, of course, people are very risk-averse when they’re not at the wheel of their vehicle – they have much higher expectations of safety from flying than from driving – but someone needs to be the adult in the room.
While we wait for autonomous vehicles to become perfect, hundreds of thousands are dying and millions are being injured…
Nick
You hear a lot about autonomous vehicles being dangerous, but the real problem is the streets and vehicles, not the drivers. Americans don’t even have this on their radar. Google “most dangerous streets in America” and you get a lot of links about crime. But an American is twice as likely to be killed in traffic as being murdered.
American traffic planners KNOW that certain streets are killers, but they don’t care. Denver even refuses to build pedestrian infrastructure in dangerous places because it would increase the city’s liability in case of a death. Victim blaming (“he shouldn’t have been walking there”) is cheaper than actually providing safety.
Most traffic deaths could easily be prevented. Roundabouts are much safer than traffic lights. Lots of cities use flex posts to “protect” bike lanes and breakaway posts that do nothing to protect pedestrians. Cities pretend to care about drunk driving but insist on parking minimums at bars.
Given widespread disinterest in safety, it is odd that there is so much hesitation about autonomy. Liability is probably the main issue, because blame can’t be shifted to the driver. Either the street designer or the manufacturer faces liability claims for every death or injury.
Farms are private and the biggest risk is killing a few farm animals. So liability isn’t a big issue. Also a GPS-aware robot is much better than a human at covering a big field evenly.
Well, liability does seem to be central.
Liability is a social choice. We can redefine it to suit our needs. A good example is No-Fault car insurance.
Again, it’s a tragedy to have a whole system from GM shut down because of a single death. It’s crazy. Again, every single day 3,000 people are killed around the world and about 100,000 are seriously injured. Every day we delay the implementation of autonomous driving is another day we needlessly suffer these losses.
Until the self-driving car is entirely liable for an accident, these things will never pick up steam.
Who wants to go to prison because their car decided to run someone over while they were sleeping or drunk in the back.
Andre,
Self-driving cars ARE entirely liable. (You may be thinking of Tesla’s Self Driving feature, but don’t: it’s not at all self-driving, as Tesla makes very clear if you actually drive one).
In a sense, that’s the problem – we need reduce our unrealistic expectations. 3,000 people are dying every day, and a solution for that gross tragedy can’t be held to a standard of zero deaths.
The perfect is the enemy of the good.
DC
Is there a search facility on this website.
Should be easy to find, autonomous taxi or self driving taxi.
You used the term many times.
Here’s a Dennis comment from 11/11/2023 EIA posting:
“ The potential for autonomous robo taxis in the future would lead to a rapid increase in vehicle miles travelled with electric transport on land.
Somewhere between 2030 and 2040 we may see oil prices plummet due to lack of demand for oil.”
Seems consistent with a 2035 estimate of autonomous vehicle dominance.
———————-
It’s quite clear that autonomous driving will save many lives, and that the sooner it arrives the sooner we’ll save many lives. The sad fact that GM was driven out of the business by one death (while 100 die in car crashes daily and thousands are badly injured, just in the US) is a very bad commentary on the resistance to change of legacy industries, and the vulnerability of people who respond to fear-based reporting and politics.
Nick G
You were not part of the conversations back 8 years ago. So you know nothing of this issue.
Dennis makes predictions and when the time of the prediction elapses he just makes a new one. On and on learning nothing.
“ You were not part of the conversations back 8 years ago.”
I’ve been part of this conversation since the Oildrum started over 20 years ago, and from the beginning on this blog. Heck, I’ve discussing this since the original Limits to Growth was published. I’ve debated with both Ron and Dennis many, many times, on forecasts and many other things.
Look closely at the blog post you provided below: you’ll see 37 comments from me, including a debate with Dennis on his forecast. Please read them, especially those in reply to Dennis’ prediction – IIRC they will stand the test of time quite well.
Arrogance?
If you feel there is a splinter in the other person’s eye, you should remove the beam from yours first.
Mathew 7:3
Looking for past Dennis predictions.
https://peakoilbarrel.com/has-china-reached-peak-oil/
Dennis Coyne
08/29/2016
Hi Steve,
It seems you have been predicting a severe recession next year for the past 5 years, eventually you will be correct 🙂 , between 2027 and 2033. Oil (C+C) will start to decline from the present plateau (around 80 Mb/d for C+C output) in the 2020-2025 time frame.
By 2025 the fact that peak oil has arrived will be clear to all who do not have their head in the sand, output is likely to have fallen to 78.4 Mb/d by then and a gradual decline of 1 to 2% per year will continue until recession hits in 2027-2033 (this will be closer to the Great Depression in 1930-1936”
It is not just how wrong the predictions are, it’s the arrogant way Dennis says things to people who hold a different view. Hardly any wonder most of the people who used to comment here don’t bother any more.
We are now at the end of 2025 and output has not fallen to 78.4321mb/d.
It is over 85mb/d.
Iver,
Yes my prediction was incorrect. I have said endlessly that all predictions of the future will be wrong. Note that in 2016 I did not predict a pandemic, the fact that we ha several years with output below what I predicted leaved oil to be produced in the future pushing out the peak.
I was responding to a prediction that the oil price would fall to $12/bo and that peak would be by 2018 see link below for full context.
https://peakoilbarrel.com/has-china-reached-peak-oil/#comment-579668
In any case my predictions of the future have been wrong in the past and any prediction of the future (whether mine or anyone else’s, except Iver’s) is pretty much certain to be wrong.
Iver,
I couldn’t find a shock model from 2016, but found this on my computer from november 2017 (oldest file I could find near 2016). URR about 3300 Gb for this scenario, which is also certain to be incorrect.
Here is a post from 2019
https://peakoilbarrel.com/eia-international-energy-outlook-2019-and-oil-shock-model-scenarios/
Another post with many different scenarios
https://peakoilbarrel.com/oil-shock-model-scenarios-2/
link below to many different shock models over time
https://duckduckgo.com/?q=shock+model+charts+from+peakoilbarrel&t=ffab&ia=images&iax=images
shock 2017Nov
Oh but it has! Conventional oil has fallen dramatically! A look at 5 key exporters shows decline approaching 10% since 2018 peak…
Dennis – if actual production data match 2P reserves, why focus on 2PCX (or even 2PC)?
A reminder for all:
1P reserves are the money in the bank (developed fields)
2P developed + undeveloped fields
2PC = 2P + known but not yet viable resources
2PCX is a wishful horizon: real rocks may or may not deliver it, and policies, prices, or carbon limits could prevent much of it from ever being produced.
Probability wise they are 90%/50%/25%/10%
We can read between the lines and use average of 1P/2P for low scenario, and average of 2P/2PC for high scenario (37.5-70% range):
Low est: 572 Gb
High est: 970 Gb
Cumulative is ~1550 Gb
URR low is ~2,100 Gb
URR high is ~2,500 Gb
Peak midpoints:
2005 – 1,000 Gb (URR=2,000 Gb)
2015 – 1,250 Gb (URR=2,500 Gb)
2025 – 1,500 Gb (URR=3,000 Gb)
The observable world peak was closest to 2015, so we can confirm that a best case scenario is around 2P (710 Gb) plus annual increase (replacement) of around 5-10 Gb for next 25 years, therefor 1P will shrink by around 20-25 Gb annually due to low replacement:
2025-410 Gb
2030-330 Gb
2035-250 Gb
2040-170 Gb
2045-90 Gb
~2050-0
We could also be ultra conservative and use only 1P, if somehow we stop looking for/developing the undeveloped/know/unknown potential resources…
How might that happen?
💰 Global recession or credit freeze – no funding for exploration or new development.
⚖️ Strict climate or carbon policies – bans, taxes, or ESG rules stop new projects.
💣 War or geopolitical isolation – major producers cut off or infrastructure destroyed.
🧱 Supply-chain breakdown – rigs, parts, and technology unavailable for new drilling.
🌋 Environmental or natural disaster – large-scale damage limits extraction capacity.
🦠 Pandemic or global disruption – workforce and logistics collapse, halting expansion.
🌍 Managed energy transition – governments deliberately cap future production.
📉 Sustained low oil prices – exploration uneconomic; only producing fields continue.
🔒 Nationalization or expropriation waves – private capital withdraws, freezing investment
You might note that current crude + condensate production level is at the 2004 level (excluding North America). Peak was 2015 plus/minus a year and decline rate is ~1% but will likely accelerate soon (2% and 3% by 2030, then accelerating rapidly after 2033/2034
Kengeo,
Perhaps conventional C+C has peaked, not clear that peak always occurs at midpoint of URR.
I tend to focus on total C+C, this is likely to see a new peak in 2025 or 2026. There are many different definitions of “conventional” oil, mine is C+C that is not LTO and has an API Gravity of over 10 degrees (that excludes oil sands and Orinoco Belt). Using my definition the conventional peak was in 2016 at a cumulative output of 1270 Gb. I think this peak was artificial due to rapid expansion of tight oil reducing demand for conventional oil over the 2016 to 2020 period and also OPEC’s attempt to take back market share from US tight oil over the 2015 to 2017 period. Difficult to know what happens in the future, my predictions are certain to be wrong, though maybe you or Iver will prove clairvoyant. Remind us why North America should be excluded?
What is Iver predicting!??!
Dan
About 12 years ago I went through every oil producing country. Reading up on what was going on in each. I then created a spread sheet on possible minimum and maximum production of the 50 or so countries.
The maximum global crude, condensate and ngpl figure I reached was 118mb/d, the minimum was 102mb/d.
Any reasonable person would exclude the maximum. To get to that amount every country would have to do everything right and the global oil demand would have to be within the historical average. Think about the turmoil in Iraq, the corruption in Venezuela the civil war in Libya.
The minimum global Crude etc figure I arrived at was 102mb/d. So Dennis was even more pessimistic than my minimum figure. This really shows how little he actually knows about the oil production in the countries of the world.
The most reasonable global production peak is half way between the two figures. Which is around 110mb/d. It looks like it will not be far off that amount.
Now let’s get the inevitable petty remarks that Mr wrong is so good at. You know why Mr Wrong has been wrong for so many years? Because he thinks he can’t learn anything from anyone. Excuse me while I dig my head out of the sand.😂
Iver,
We will see, my model, including NGPL has a peak in 2029 at about 101 Mb/d, though the NGL model I have not revised for many years, peak for C plus C which is my focus is around 85 Mb/d in 2027-2028. I have learned much from many, but will always be wrong about the future. As to minimum numbers for C+C+NGPL peak annual output that would be 96.32 Mb/d (2024 output). This estimate is my current best guess, range would be 97 Mb/d to 110 Mb/d from 2028 to 2035 for C plus C plus NGPL.
Iver said: “I then created a spread sheet on possible minimum and maximum production of the 50 or so countries.”
The obvious next step is to publish that spreadsheet so people can learn from it, or critique it.
Nah…like 2PCX, the spreadsheet is also make believe…
Iver.
I read work that others have done such as Jean Laherrere and Steve Mohr.
Laherrere paper from 2018, forecasts output from 35 nations see table 1 on p 134, suggests URR of 2700 (bottom up) to 3000 Gb (based on HL).
https://aspofrance.org/wp-content/uploads/2018/10/35cooilforecast-oct.pdf
Steve Mohr’s Thesis from 2010 at
https://openresearch.newcastle.edu.au/articles/thesis/Projection_of_world_fossil_fuel_production_with_supply_and_demand_interactions/28976855
or
http://theoildrum.com/node/6782
Also work by others published at The Royal Society. The Future of Oil Supply
https://royalsocietypublishing.org/doi/10.1098/rsta.2013.0179
US August Production at Another New High
Production rose by 86 kb/d. Alaska 30 kb/d and GOM 67 kb/d. Very small gains and losses for NM and Texas respectively, rounding errors.
A US
Dennis,
Quick snapshot relating to why so many of us are bullish on long term, future US natgas production …
Range just announced 16 wells drilled and completed this past quarter.
Average lateral length almost 16,400 feet, average cost under $10.5 million.
Gross revenue – @ $3 per – would pay for these wells when 4 Bcf is produced … a benchmark now regularly surpassed within the first few months online.
At 50/60 wells per year, Range has over 30 years inventory remaining in its core areas.
When one includes the vast Tier 2/3 acreage in the AB – a topic that I have dug into via ~300 wells’ production histories in demonstrably poor (relatively) acreage – the century long production projections become obvious to embrace.
Age of Gas has arrived.
Appalachia Rising!
PS …
That 30 year core inventory of Range’s is for the Mighty Marcellus formation only.
Upper Devonians not included.
Neither is the Utica which underlies 100% of Range’s 500,000 square acres.
Lottsa gas.
Coffeeguyzz,
Took a quick look at Range’s 10Q, looks like net revenue is about $1.50 MCFE so for a $10.5 million well, the well is paid off at about 7 BCF which the average 2020 Range Resources well reaches at month 48. Annual ROI over assumed 30 year well life is about 2.7% per year at recent net prices received by Range (after hedges and operating and transport costs.) Not really a great investment at prices for 2025Q2. Maybe prices rise.
Most of the shale gas plays have been flat since 2016 or so, the growth in output since that time has been primarily from Marcellus, Utica, Haynesville, and the Permian Basin. Since 2019 most of the growth in US shale gas output (58%) has been from the Permian Basin, without the Permian the other big Shale Gas Basins (Appalachia and Haynesville) have seen average annual growth rates of about 1.35 BCF/d. Permian shale gas output is likely to be fairly flat over the next 10 years (average annual growth of only 0.04 BCF/d) before dropping as the Permian Basin drilling rate slows due to pressure depletion and lack of profitability. Perhaps the other 3 big shale gas basins can make up for falling output in the rest of the shale plays, we will see.
Permian shale gas scenario, medium case at link below
permian gas 2510
Did a quick Hubbert Linearization (HL) on US tight oil and shale gas. Tight oil URR around 90 Gb and shale gas URR around 900 TCF, usually the HL tends to underestimate so these URR estimates may might be too low. The tight oil seems about right, shale gas I am less confident in my estimate, this may well be 1100 TCF rather than the 900 TCF estimate which was a recent best guess by me.
Time will tell.
Range has most acreage in the SWPA and WV, and therefore more wet gas and higher price?
https://www.rangeresources.com/operations/our-regional-operations/
It is amazing that they claim 2BCFe/1Kft, with 16K ft lateral, that is 32BCFe EUR!!! SWPA is hard to imagine — with thickness only single formation only 50~80ft roughly!!!
from Range’s recent quarter report,
their realized price for natural gas is $2.56 versus $1.69 from 2024 Q, NGL at $22/bbl versus $26/bbl from 2024Q, or roughly $5.5/MCFe or $6.5/MCFe using mixed NGL 1 bbl = 4 MCFe conversion rate.
But, it is true that after transportation cost it is only $1.82/MCFe this past Q versus $1.67/MCFe in 2024Q. On average they are doing ~$2/MCFe if counting the best 2022.
Sheng Wu,
Re that 32 Bcfe EUR … there are about 130 wells in Pennsylvania that have already produced over 20 Bcf with the Top Dog – the Mcenaney 102HC – at over 33 Bcf and STILL putting out 14.5 MMcfd at the 5 year online mark!
Of greater interest, perhaps, for forward looking observers are the 4 Taft wells that Seneca brought online less than 9 months ago in Tioga county.
Targeting the Utica, they are all on restricted choke at 28/29 MMcfd and each has surpassed the 7 Bcf cum mark.
This clearly shows that Seneca has cracked the code for Utica development in this part of the state, coincident with numerous nearby highly productive Marcellus wells.
Coffeeguyzz,
The best 4 wells tell us little, anecdotes are not convincing. When you have a 1000 well average, let us know, that would be meaningful.
Tioga county had about 45 wells in Utica with 48 months of cumulative output as of March 2023, average cumulative was 6.85 BCF. For all PA counties there were 160 wells in Utica with average cumulative at 48 months of 4.1 BCF, so Utica is very good in Tioga, better than Marcellus with 2.78 BCF cumulative at 48 months for same county.
To assume this will be true for all PA counties is a mistake, Tioga county is a sweet spot for Utica.
Rig Report for the Week Ending October 31
The rig count drop that started in early April when 450 rigs were operating and rebounded over the past few weeks dropped this week.
– US Hz oil rigs dropped 8 to 369, down 81 since April 2025 when it was 450. The rig count is down 18% since April.
– New Mexico Permian was unchanged at 92 while Texas dropped 4 rigs to 177.
– Texas Permian dropped 5 to 137. Midland was unchanged at 23 while Martin dropped 1 to 18. Reeves was down 2 to 14 and loving was flat at 17.
– In New Mexico Eddy and Lea were unchanged at 37 and 55 respectively.
– Eagle Ford was unchanged at 30.
– NG Hz rigs rose by 1 to 109.
A Rig
Frac Spread Report for the Week Ending October 31
The frac spread count dropped by 3 to 175. From one year ago, it is down by 57 and down by 40 spreads since March 28.
A Frac
Dennis
Your Oil Shock model needs to clearly show dates ie 2025, 2030, 2035, 2040. No point going back to 1965.
Funny when I suggested high decline rates as in your oil shock model you rubbished it.
Have you changed your view again?
Iver,
The shock model can change depending on several assumptions such as the unconventional C+C URR (in 2017 my assumption was about 600 Gb, today this has been reduced to about 280 Gb), conventional C+C URR (over time this has ranged from 2200 Gb to 3100 Gb) and future extraction rates, along with future rates of oil development (time from discovery to reaching full maturity with maximum output from the discovery). None of these assumptions is fixed, they change with historical output and research by others.
Annual decline rates for my recent models are around 2.7% at the peak in roughly 2070. Not sure what you mean by high decline rates. This scenario assumes constant extraction rates for conventional oil from 2031 to 2051 with slowly decreasing extraction rate after 2051, falls from 5.61% in 2051 to 5.147% in 2070 and reaches 4.25% by 2100.
shock2511
Dennis and Ron
2 non oil people constantly say that total liquids are irrelevant, that only C&C is the only metric they will look at. The fact is that all fossil fuels can be used interchangeably.
The Germans made oil from coal 80 years ago and the process is greatly improved since then.
https://thecoalhub.com/china-consumes-almost-400-mt-of-coal-to-produce-liquid-fuels.html
Gas can be used on a vast scale to produce liquid transport fuels.
https://www.shell.com/what-we-do/oil-and-natural-gas/gas-to-liquids.html
With coal to liquid and gas to liquids and electric vehicles, peak oil is not really an issue any more.
Droughts and food costs are rapidly becoming the issue facing humans now.
Iver,
Most transport fuels are made from C plus C, NGLs tend to be used for heating and cooking (in the case of LPG) and as inputs to the petrochemical industry (ethane and naptha), so I think C plus C is the more useful measure.
Shock model including NGL (C+C+NGL), annual decline rate is about 1.14% on average from 2030 to 2070 and from 2040 to 2070 the average annual decline rate is about 2.1%. URR is 3600 Gb, peak is 101 Mb/d in 2028/2029, see link below.
Peak oil may not be a problem, if energy substitutes are found, natural gas and coal are also likely to peak, so peak fossil fuel may not be far off.
ccngl2511
Iver,
As somebody who has worked in oil, gas, and petrochemicals for 47 years I probably know a little more than most people. NGL’s (EPB)should in my opinion be treated separately to crude oil and condensate. I do no consider naphtha as an NGL even though in NGL fractionation plants some C5+ is produced. On their own propane and butane have limited use as transport fuels, and are mainly used as heating fuels (space and cooking), petrochemicals ( steam cracking, PDH), and (butanes) in alkylation units.
The disposition of naphtha is mainly, but not exclusively, in isomerisation units and reforming units for gasoline production, and in steam cracking.
Thee is not a great deal of interchangeability between fuel end uses. For instance gasoline cannot be substituted for diesel and vice versa. Jet kerosine has some very specific requirements that must be met.
Gas turbines have the greatest range on interchangeability, but it is not a simple case of switching fuels because the density and viscosity affect the air to fuel ratios which in turn affect the efficient combustion.
Coal to liquids and gas to liquids technologies exist but they are not widespread. There are no operating units in the west. The biggest unit is in Qatar- Pearl project. By current standards its 7.5 million tonnes p.a. of output is big for such a unit, but against a typical new build refinery (15-20 million tonnes p.a. small). Less than 10 of these units exist globally producing liquid fuels and all operate on gas. China has coal to chemical processes that produce ethylene and propylene via methanol. These units are based next to the coal mines. The process is quite dirty as 5 tonnes of coal are required to produce 1 tonne of olefines. The biggest products are carbon dioxide and water. The overall production of coal to olefines plants is small <3% of global prodution. China also has some methanol to olefines plants on the east coast producing olefines from imported methanol. These are not economic.
Carnot,
Thanks for the correction on Naptha, I had read somewhere it was used in petrochemicicals, there might be some minor uses as “white gas” for cooking, but I guess it’s main use is as a blending component in gasoline production. Is this article fairly accurate?
https://en.wikipedia.org/wiki/Petroleum_naphtha
An update for US August production has been posted.
https://peakoilbarrel.com/us-august-oil-production-new-high/
Dennis –
Use 2016 as the world conventional peak, make sure you don’t mix conventional with unconventional as that will skew the peak.
For the 11 countries producing above 2.0 mb/d, we can see they had a cumulative output of 864 Gb by ~2018.
Let’s imagine those 11 countries had 864 Gb remaining 2018, they have produced 154 Gb so they have 710 Gb remaining.
Under the most optimistic circumstances there might be 800 Gb left to produce.
Under the most conservative scenario there is only half that amount….
Half the remaining oil is in the Middle East and 20% in North America and 20% in Russia…