The EIA Short Term Energy Outlook (STEO) was published recently. A summary in chart form.
Note the large increase in petroleum stocks for OECD in 2025 and 2026, well above 5 year range. This rise in stocks is expected to drive Brent oil prices lower (previous chart.)
WTI is expected to average $48/b in 2026.
Lower crude prices lead to lower gasoline prices in 2025 and 2026 which reduces expenditures on gasoline as a percentage of disposable income to the lowest level since 2005 (excluding the pandemic year of 2020 when much lower driving levels occurred due to fear of Covid exposure prior to vaccine availability.)
The premium of oil to natural gas falls to the lowest level in 2025 since 2020 and in 2026 to the lowest level since 2005.
Most of the increase in demand for natural gas in 2025 and 2026 comes from increasing LNG exports.
Electricity output is expected to increase more than originally forecast in Jan 2025.
Coal consumption for electric power rises in 2025 as coal is substituted for more expensive natural gas fired power. then falls slightly in 2026, but does not return to the 2024 level.
Demand is less than supply in 2025 and 2026.
Note the strong increase in OPEC output expected in 2025 and smaller increase in 2026.
Most of the increase in consumption comes from non-OECD nations.
Marketed natural gas production increases strongly (3.4%) in 2025, but less so in 2026 as lower associated gas production due to lower oil prices offsets higher shale gas production driven by higher natural gas prices.
Natural gas exports are forecast to increase by 4.3 BCF/d in 2025 and 2026 combined.
The two charts above cover tight oil production. The first is tight oil only and has no forecast, it is EIA data through July 2025. The second chart includes both tight oil and conventional output in the various shale regions of the US, with other covering the Lower 48 onshore output outside of the major shale regions. Note that the dotted forecast line should be moved to the right by 12 months, this applies also to the marketed natural gas chart below. Also note the peak in Lower 48 onshore crude oil output which occurs in July or August 2025.
142 responses to “STEO September, 2025”
1. That price deck is hella low. Brent at $51? Maybe WTI down in the upper 40s? If I look at the WTI strip, mid 2026 is about 62+. Brent is probably about 65. I’m not even sure what they are predicting to drive such low prices (a recession, peak breaking out and Russian volumes coming back, OPEC collapsing)? Of course anything can happen. But I trust the futures strip more than EIA guessium.
2. Given the price deck, the US crude supply seems too high. Does anyone think we stay flat in production with prices dropping more then $10 from present? That seems like cornie crazy talk.
3. Net, net: I think the US oil supply flat is fine. But price needs to stay flat to allow it. Not crash!
Nony,
I agree the prices seem too low for the output projection, maybe something between futures and EIA reference case will be about right, given the OPEC announcements, the futures market seems not to believe OPEC will follow through. As to what really happens, no idea, I tend to get oil prices wrong when guessing about the future.
How long can the Marcellus natural gas trend keep increasing production for? Eventually it will peak and US natural gas exports to Europe might have to cease and Europe will have to look elsewhere for LNG imports.
Petroslurp,
Again not known, higher natural gas prices may lead to more drilling, but the Marcellus is pipeline constrained, some of the higher output going to LNG exports may come from Permian and Haynesville/Bossier.
Given that the Marcellus is pipeline constrained, if anything that means it will be around longer before it declines. (Since we aren’t burning through it as fast as we would if it were unconstrained.)
There’s also the Deep Utica, which is very little developed. But with a large resource base. This would use the same infrastructure and could make up for eventual Marcellus declines. It is not being developed now because it also has pipeline constraints. Since it is deeper, it needs higher prices to produce the DU. But I think it would be very similar to the Haynesville, if it could get Haynesville pricing.
Big picture, I think the “App” (the layered play) has a long run room. The constraints are vexatious for companies and leaseholders that would like to develop the resource faster. But they have the result of making it a longer life asset.
Nony,
I agree on Marcellus, but the economically recoverable resource will depend on prices. Utica will require high prices to see significant development. Less will be profitable at $2.50/MCF than at $5/MCF.
Consider the following Pennsylvania Shale gas chart for 2021 shale gas wells by county, the lower output areas are less likely to be fully developed.
https://public.tableau.com/shared/5XRGT66S4?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y
Most of the PA shale gas(85%) comes from 6 counties.
Petroslup,
I did a quick look at Marcellus. If we assume the most productive 3 regions covered by the 2019 USGS assessment and half the next highest productivity region are close to the mean of the assessment we get about 82 TCF of undiscovered TRR at the end of 2018, we add to this proved reserves(135 TCF) and cumulative production(38 TCF) at the end of 2018 to get a URR of 255 TCF for mean TRR estimate for Marcellus. If we assume peak occurs at 50% of URR that would be cumulative output of 128 TCF. Cumulative output as of August 2025 for Marcellus is 99 TCF and most recent 12 months had Marcellus output of about 10 TCF, so in 3 years cumulative output reaches 50% of TRR. Typically ERR is less than TRR, let’s suggest ERR=0.8TRR=204 TCF for Marcellus ERR, that would suggest we may be fairly close to the Marcellus peak right now. Note that peak does not always occur at 50% of URR, but the more we extend the peak beyond 50% of URR the steeper will be the decline.
There is also Utica, but fewer wells have been drilled there and TRR is fuzzier. Utica gas is likely to be more expensive to produce.
No duh there are sweet spots. And no duh, price helps. Next in the litany of trite peak oiler comments you’ll tell me that shale wells have steep decline rates! Heard that one too!
Dennis, there’s a differential between HH prices and local App prices. This is caused by the transport bottleneck. It’s similar, but not as extreme, as the situation with gas prices in the Permian. If the Marcellus starts running dry, then the differential will go away (since the pipes are no longer jammed full). Typical value of the differential is $0.75. That’s a big difference when you’re looking at production on the margin.
Of course price helps and 5 is better than 2.5. But that’s the point. When the Marcellus dries up, the differential will disappear and prices will rise moderately. And that can matter. (You agree if they drop 0.75 it matters right? So, if they go up, it matters also.)
And note that the prices needed several years ago are not theprices needed now (or potentially in the future). Heck, just look at the USA, right now doing 13+ MM bopd at prices that are below $50 (in constant 2014 dollars). I bet you would have said that was laughable and you were “skeptical”, if asked about the possibility in late 2014. But…it happened.
Another important example is the Haynesville, which had a massive post-peak resurgence, despite relatively lower prices than during its previous peak. And the Deep Utica is very similar to the Haynesville (deep, high pressure, large/dangerous wells).
I don’t get much out of that 2021 chart. Of course the Marcellus has sweet spots. And note that that chart is almost entirely Marcellus production, not DU (which has a somewhat different sweet spot pattern and arguably less of a stark sweet/not pattern). In particular, mid-PA DU is pretty decent, while mid-PA Marcellus is not. But…no duh there are sweet spots. I’m not an idiot that thinks a play has the same productivity over its extent.
Nony,
I am aware of the differential pricing. I point out the sweet spots because the TRR estimates include all of it, but much of the goat pasture is not likely to be developed.
The Marcellus is not as large a resource once we take the economics into account and make realistic future price assumptions. The futures strip has NG prices at HH at about $3.50/MCF all the way to 2037 (taking average of June and Dec option). So the futures market does not see high natural gas prices over the next 12 years. Obviously there is very large uncertainty about future prices.
Not a lot of Utica or Point Pleasant wells have been drilled in PA, 85% of all shale gas produced in PA comes from 6 counties in Northeast and Southwest parts of the state of PA.
For all of the Appalachian Basin as of Sept 2021 (last datapoint from Novi for PA, OH, WV) about 3000 of 17000 wells were Utica/Point Pleasant wells (18%), the USGS assessment is not great because of lack of drilling results over a huge area. The TRR estimate has a 90% CI of 52 to 312 TCF with a mean of 148 TCF. If we assume 65% of mean TRR is profitable we get 96 TCF for Utica/Point Pleasant ERR (this is in line with the ratio I use for Permian ERR/TRR=0.65.)
As of the end of 2023 Utica cumulative (20 TCF) plus proved reserves is 48.5 TCF, so over time maybe another 47.5 TCF of reserves will be added, if the mean USGS TRR estimate is correct and my assumption of 65% of TRR being profitable to produce is also correct. Cumulative shale gas output through Aug 2025 for Utica is 24 TCF. Most recent 12 months output is 2.43 TCF. If my URR guess of 96 TCF were correct (it won’t be) in roughly 10 years at current Utica (most recent 12 months) output levels we would reach 50% of URR.
In any case, the uncertainty is very large for Utica TRR from one third of mean at F95 to 2 times mean at F5.
For contrast the 90% CI for Marcellus TRR is 204 TCF to 322 TCF with a mean of 255 TCF.
Also on that chart of 2021 wells there were 557 shale gas wells completed in PA in 2021, of those only 32 were completed in either the Utica or Point Pleasant formations (6% of the total).
There are not a lot of Utica/Point Pleasant wells completed in PA, more of an OH and WV thing.
Chart linked below has Utica Output.
utica 2509
Petro,
Well, the EIA just projected an increase from the current 35 Bcfd to well over 50 Bcfd a few decades out.
Many of us observers think this is not only plausible but highly likely with the recent shifts favoring pipeline buildout coupled with the insane demand for electricity generation/consumption.
Geologic constraints/limitations?
Not to worry.
As has been mentioned, the Deep Utica has not only barely been drilled in PA, the resulting production numbers in recent years have dwarfed the shallower MIghty Marcellus’ outputs on the very same pads. (See Seneca, CNX, and Olympus’ [recently sold] well profiles and company statements).
Innovations such as the just-announced Ultra drill rig from Nabors should enable operators to more confidently/efficiently target these deeper, HPHT formations.
Even a cursory glance at the latest USGS Marcellus Assessment map readily shows the vastly larger footprint of the Tier 2/3 acreage compared to the core. The former CEO of Olympus just stated that his new company will target these lower productive regions as leasing costs are now dirt cheap (a powerful market indicator of how much hydrocarbon rich land exists in this region).
The seldom mentioned shallower Upper Devonian formations hold several trillions of recoverable resources and should prove especially economic to develop as virtually all the infrastructure is already in place.
There are nascent calls prompting the New York state government to reconsider its ban on frac’ing. Literally within walking distance of the PA/NY state line are several dozens of 10 Billion cubic foot plus cumulative wells (one closing in on 20 Bcf) in Tioga county.
Unlike some onlookers (cough, Dennis, cough) who view dated production numbers and incorporate somewhat nebulous (questionable?) assumptions to create future scenarios that have a long, consistent track record of underestimating actual production, some of us try to keep up with the rapidly evolving current events, processes, production numbers and the always daunting socio/political/financial components.
Age Of Gas has arrived, Petro.
App Basin leading the charge now and in the years to come.
Coffeeguyzz,
Do you mean underestimates like in the chart linked below (from December 2018)?
Note the middle case corresponds with the USGS Mean TRR for Permian Basin (75 Gb) and my estimate of profitable resources using the AEO 2018 reference scenario for oil prices.
Also the estimate I have made for the Marcellus (205 TCF) assumes 80% of TRR is recovered (quite optimistic based on history) and only excludes the fringe areas of the Marcellus (with very low EUR per well). So far the Utica has been gradually declining since 2019, perhaps that changes, but the hype about the Utica seems reminiscent of the 30 Gb predictions for the Bakken/Three Forks.
Time will tell.
permian1812c
Appalachia shale gas output in BCF/d in chart linked below (second link) based on EIA data from
https://www.eia.gov/outlooks/steo/xls/Fig43.xlsx
appalachia2509
Model for Appalachian output, URR=310 TCF (Marcellus 216 TCF, Utica 94 TCF), 50% of URR for cumulative output reached in Feb 2028 for model. Model is my best guess based on historical data, USGS assessments and Patzek papers. Click on link for chart
appalachian2509model
For Appalachian output cumulative plus proved reserves at the end of 2023 was about 250 TCF, my best guess for URR is about 310 TCF, so about 60 TCF of undiscovered resources at the end of 2023 based on my best guess. Using a negative exponential probability distribution where the mean is equal to the standard deviation, the 80% CI for URR is 256 to 388 TCF with mean of 310 TCF.
Coffeeguyzz,
Here is the reference case for US natural gas from the AEO 2025
https://www.eia.gov/outlooks/aeo/data/browser/#/?id=14-AEO2025®ion=0-0&cases=ref2025&start=2023&end=2050&f=A&linechart=ref2025-d032025a.37-14-AEO2025&ctype=linechart&sourcekey=0
Peak is in 2032 at 119 BCF/d up from 105 BCF/d in 2024, shale gas also peaks in 2032 at 100 BCF/d up from 80.5 BCF/d in 2024.
The EIA does have a big increase in East region natural gas output to 53.7 BCF/d in 2050 up from 34.3 BCF/d in 2024. The cumulative output for the East up to 2050 for the AEO 2025 reference case is 550 TCF, if we assume a sharp drop to zero over the 2050 to 2060 period, the URR would be 648 TCF, the probability that the URR will be less than this is about 99.7% and the probability it will be more than 310 TCF is about 37%, about a 10% probability that Appalachian URR will be more than 388 TCF,
chart(109)
Paper on Marcellus
https://archives.datapages.com/data/bulletns/2024/01jan/BLTN21078/images/bltn21078.pdf
Pager above predicts about 180 TCF for URR for Marcellus for core and noncore areas, for Outer Marcellus (with very low productivity) possibly another 20 TCF. 90% CI is 107 to 266 TCF for core plus non-core.
Paper on Utica
https://www.sciencedirect.com/science/article/pii/S2949891024008613
This second paper does not seem as good as the Marcellus Paper, a major shortcoming is a lack of realistic confidence interval for URR for scenarios and also not dividing EUR estimates by core and non-core areas. It may be that there was not enough data to make these estimates. Also an unrealistic NGL price of $80/b was used in the economic analysis. Typically NGL price is about 30% of crude price so $80/b for NGL implies a crude price of $267/b, NGL price should be about $25/b for annual 2023 average (when paper was first submitted).
Appalachian scenario below assumes flat output for a few years and then decline which when we use HL suggests a URR of about 320 TCF.
appalachian2509
Was looking at OPEC adjustments for September and October (announced in August and September). If these are fully implemented the OPEC Big 4 spare capacity will be down to about 600 kb/d by the end of September with close to 100% of remaining OPEC spare capacity in Saudi Arabia. I imagine that stocks may rise and OPEC may pull back on output due to low prices. If the demand is there to keep oil prices at current level, it will be interesting to see how long OPEC can sustain output. Sanctions on Russia, Iran, and Venezuela might reduce OPEC plus output enough to maintain the oil price level. Interesting times.
D C
If you are correct, we have a tragic situation of OPEC effectively spiking its own guns.
Whatever their spare capacity is, increasing production at the moment makes no financial sense. OPEC are losing millions each day selling oil at $70 per barrel if they dropped production by 3 million per day they could have $90. They would earn more and keep oil for another year.
They are using up their spare capacity and severely damaging the U.S. oil industry.
Are they doing Trump a favour in his quest for low oil prices?
Are the Saudis trying to destroy the Iranian economy?
If any serious incident happens, Russian export terminals for example, oil price will spike and OPEC will not be able to take advantage of it.
Just seen this after posting above
https://oilprice.com/Geopolitics/Europe/Zelensky-Says-Trump-Signed-Off-on-Strikes-Against-Russian-Energy-Infrastructure.html
Iver,
I think the Middle East OPEC producers are trying to please Mr. Trump, I agree that it seems a dumb move, but OPEC seems to believe the extra output is needed even though oil prices show that is not the case.
It’s your fault…they read your posts about only giving them credit for capacity for what they produce, not what they say they can. And so they said, we will show that guy! Thanks for crashing the price, Dennis. 😉
Thank you for the comprehensive presentation.
Am I correct in my understanding that the US imports roughly 1/3rd of its oil consumption (net)?
Hickory,
If we define oil as crude plus condensate and consider net imports of crude oil vs crude input to refineries we get for the most recent annual data (2024) net imports of 2495 kb/d of C plus C and net crude oil inputs to refineries and blenders in 2024 of 16255 kb/d, so 2495/16244=15.4%.
If we look at total net exports of crude oil plus petroleum products the US was a net exporter in 2024. most of these exports were hydrocarbon gas liquids (and over 100% of those were NGLs). In some sense we import a portion of crude (around 15%) and then export that as products, if we think of the export of tight oil being exchanged for the same amount of heavier crude that works better in Texas and Louisiana’s refineries.
[This answer is similar to Dennis’s, not a correction, just how I think about it.]
If you look at oil produced (13.5ish) versus domestic refinery product consumption (~14.5ish), it is pretty close to breakeven. Maybe slightly negative, but less than 10% imports.
However, what confuses things is that the US is partially a “merchant refiner”. I.e. our refining capacity/usage (~17 MM bopd inputs to refineries) is higher than our internal consumption of refined products. So…that’s like 17-13.5 = 4.5 MMbpd “extra” needed. Or…about 25%.
An extreme example of a “merchant refiner” is Singapore, needing about 2 MM bopd for internal usage, but with refineries running 5 MM bopd…thus exporting 3 MM bpd (of liquid products). Other countries that are too some degree “merchant refiners” are China and Korea. Of course there are corresponding countries that don’t have enough refining capacity for internal needs (thus importing products, not just crude). Many Latin American countries fall in this category.
If you define “consumption” as eventual use by consumers within the US, it’s very close to breakeven (slightly needing imports, maybe less than 10%). However if you define needs to include operation of the “merchant refiner” capacity (after all there are machines there and jobs there and the like), than your 1/3 number is pretty reasonable.
Another confusion is that many charts and news stories talk about “crude plus products”, but include NGPLs, which are mostly coming from natural gas plants, not refineries. Things like ethane, propane, butane, and liquid “drip gas”. I agree that those really don’t have much to do with refineries and/or some sort of crude in/out balance. However they are legally “products” in that they don’t have export controls like crude or natty do. And they really do come from large integrated natural gas processing plants (so they are a product of those big plants). But they have nothing to do with C&C and refining.
Well…almost nothing. There are some NGLs that come out of the refinery (crude is a mixture of hydrocarbons…incredible cosolubility…so the distillation tower and some later process in the refinery do produce C2, C3, etc. But most of it (I think like 85%+) is from gas processing, not refining.
Personally, if you want to look at net products, I would just do the quick and dirty and exclude ethane/propane/butane (not worrying about the exact source) from your product import/export balance. I would leave the pentanes plus (drip gas) in the product import/export balance. It is a liquid hydrocarbon after all (yes even if it came out of the NGL plant), not a gas. And it is pretty comparable to light naphtha (one of the refining liquid streams). Also…it sort of gets recycled back in the form of dilbit (Canadian crude, mixed with drip gas). So if you count total imports of Canadian crude as imports, I think it’s reasonable to include the drip gas exports. Also…it sort of makes up for the small fraction of propane/ethane/butane, etc. that is coming out of refineries, not NGPLs.
Butane itself is a bit of a judgment call since about 50% of it gets mixed into gasoline (in the winter). But to not put a thumb no the scale, I would just cut it from some export/import products consideration.
One final confusion is “refinery gain”. I.e. the products coming out of the refinery have a slightly higher volume than the crude did. (There is some hydrogenation going on, desulfurization, and then different fractions just having nonideal densities versus the mixture.) I pretty much wouldn’t worry about that. It does sort of juice things towards the cornie view, but it’s slight…and we are being conservative, by excluding butane (a major gasoline component) from discussion.
Net/net: less than 10% net imports needed, if you look at domestic final consumption. Over 25% needed if looking at supplying domestic consumption AND “merchant refining”.
[EDIT] P.s. There is also some amount of “drip gas” that is either directly put into refineries (mixed into the crude, at the front of the tower) or is mixed into fractions coming out of the refinery or even just sold as is (for petrochemical crackers). Maybe [sorry, thinking as I type!] you can just add the drip gas to the C&C. It’s a little more than 0.5 MM bpd. So…it juices the domestic production of refinery input-able liquid to 14+ MM bpd. In that case, you’re looking at something like 3% net imports to keep domestic consumption satisfied. Or 18% net imports to satisfy domestic needs AND keep the merchant refining capacity humming.
—-
Of course, the whole discussion is slightly flawed even if we (on some budget) are at breakeven, we still have some import needs for CA and the East Coast (both crude and products) that persist even if the Gulf Coast is net exports. Also, we benefit from importing heavier grades (matching our complex refineries) and exporting light sweet (which gets a premium for simpler overseas refineries).
I don’t do math right, in my head. 17-13.5 is 3.5. Sigh. 🙁
Thank you two for the reply.
What I stumble on is the data presented in the chart on US Petroleum products (near the top),
showing 20.5 liquids consumption and 13.4 crude oil production oil in 2025.
The explanation that ‘liquids consumed’ don’t equate to ‘crude produced’ makes sense, thanks for the reminder and details on that.
Hickory
Not too sure how to answer the “liquid consumed” question.
But I would like to comment around the rather comprehensive comment made by Anon (the short version used by replying too many times – I get that) above. What to do with the excess wet gas? The Pearl GTL project in Qatar was an attempt to turn wet gas into more liquid fuels. It was not very successful overall. The rich gas is very useful and can not be discarded in the total picture, even though the energy content could be something like 1/2 of high density crude oil. Power plants like pure methane, which means purifying rich gas before being relevant. I would have to confront my 1-2 experts in the field to have more to say regarding all the details.
I think the economics are better to just sell the stuff, whether it’s the methane or the “liquids” (NGLs). GTL projects depend on a high oil price and low gas price. They are not economic right now.
If you had $100 oil and $3 natty, then maybe. But right now, it just makes more sense to LNG the methane. And send the ethane, propane, etc. into the petrochemical feedstock markets.
Also, even if there are small amounts of time where GTL is cost competitive, that’s not enough. You can’t build those plants on a dime. Takes years to do so…and then they operate for years. Nobody is going to make that sort of long term bet unless there is a clear long term high oil price. And a cheap gas source.
Lot of buzz in the GTLs before the 2014 price crash. But shale killed oil prices. And they have been down for 10+ years now. With a futures strip showing market expectation being low for decades.
Of course the strip might be wrong temporarily or even regarding the long term picture. But nobody will invest billions based on the hopium of oil price bulls.
Hickory,
In 2024 the US produced about 7 Mb/d of NGL, average annual crude oil output was 13.2 Mbpd in 2024, so if we add those we get 20.2 Mb/d of petroleum liquids, but note that there is also biofuel production, 1 Mb/d of ethanol and maybe 0.2 Mb/d of biodiesel bringing total liquids to 21.4 Mb/d in 2024, total products supplied in 2024 was 20.5 Mb/d.
Here is a decent EIA page on net imports of crude and products:
https://www.eia.gov/dnav/pet/PET_MOVE_NETI_DC_NUS-Z00_MBBLPD_A.htmhttps://www.eia.gov/dnav/pet/PET_MOVE_NETI_DC_NUS-Z00_MBBLPD_A.htm
It’s about -2.3 overall, for 2024. However, -2.7 of that is NGLs (includes natural gasoline, a liquid phase hydrocarbon, but that’s only net -.150.)
Net, net: It’s pretty close to breakeven if you deduct the NGLs and make an allowance for natural gasoline (AKA pentanes plus AKA drip gas AKA plant condensate) and maybe for refinery produced C2-C4.
Not saying for sure it’s breakeven. But even if you cancel out all the NGLs (from natty or refining, and the c5+), it’s still like +0.4 MM bpd. And that’s for 2024, and with the curve rising. It’s “close” to breakeven.
A good overview on the supply/demand aspects of refining. (Not the engineering aspects.) Pretty dated, but discusses energy security (of refining), “merchant refiners”, etc.
https://www.youtube.com/watch?v=hqM44iY0Suo
https://www.miragenews.com/full-steam-ahead-beetaloo-pipeline-construction-1539178/
Beetaloo Basin pipeline construction begins.
Andre,
The Northern Territory folks are doing it smart … getting a small (12 inch) pipe in the ground right away to run ~ 40 MMcfd up to Darwin by mid 2026.
Proof of concept playing out in real time.
The early pilot production looks like the Beetaloo could be throwing off huge, huge wells within 2 years’ time.
Great opportunity for younger, hard working guys/gals (shelias?) to head thataway to make their fortunes in the upcoming boom.
Now that Australia is following in the footsteps of Argentina, Canada, China and the USA (not clear on the status of the Kingdom’s shale efforts) in proving the viability of hydrocarbon recovery from ‘shale’, one wonders about the possible global ripple effects.
The UK is sitting atop massive natgas resources in the Bowland and Weal Basins.
Time to git ‘er done, Brits, and warm up those hearths with cheap fuel.
You gotta love the name “Beetaloo”
I would love some expert to explain the oil potential of the Beetaloo.
No clue from me
You know what the blokes said about that possibility:
Rig Report for the Week Ending September 26
The rig count drop that started in early April when 450 rigs were operating added more rigs this week. So much for they can’t make a profit at these $65/b WTI prices. Since the low of 362 rigs on August 1, 13 rigs have been added
– US Hz oil rig count rose by 6 to 375, down 75 since April 2025 when it was 450. The rig count is down 16.7% since April.
– New Mexico Permian added 4 rigs to 83 while Texas added 2 rigs to 191.
– Texas Permian dropped by 2 to 148. Midland dropped by 1 to 19 while Martin was unchanged at 17.
– In New Mexico Eddy added 4 to 37 while Lea was unchanged at 46.
– Eagle Ford added 1 to 34.
– NG Hz rigs dropped by 1 to 103.
A Rig
Ovi
Do you know where the rigs were removed from?
I would think that rigs in areas that are less productive and need say $80 plus are being removed and sent to more attractive places.
Iver,
The rigs that are added went from idle to operating. Most of the rigs (4 of 6) were added in Eddy County New Mexico, the heart of the Delaware sub-basin in the Permian. Eddy County and Lea County New Mexico are the highest average productivity tight oil areas in the US.
Also note that 73% of all US horizontal Oil Rigs are operating in Texas(51%) and New Mexico(22%).
As far as profits, sometimes the actions of the operators seem unrelated to profits, it is possible that they are high grading and drilling the last of the profitable locations in tier one or higher natural gas prices expected this winter may improve profitability and they hope to be taking advantage of that. Perhaps they believe oil prices will rise or DUC inventory may have fallen to too low a level and they are building this.
Frac Spread Report for the Week Ending September 26
“Things are getting curiouser and curiouser”: Lewis Carroll
“The Frac count and Rig count are getting curiouser and curiouser”: Unknown
The frac spread count rose by 5 to 179 this week. It is also down 59 spreads from one year ago and down by 36 spreads since March 28. The frac spread count has added 15 spreads over the last three weeks.
A Frac
Ovi,
Unfortunately we don’t know which frac spreads are for gas and which for oil.
And many wells produce both.
Even for rigs, it’s a little unclear what is an “oil rig” versus a “gas rig”. Baker Hughes says (read their FAQ) that the decision of what to call a rig is up to an operator. A rig doing 50% gas, 20% NGLS, and 30% oil (on a BTU basis) could be called “gas” (largest component) or “oil” (drives the economics, highest revenue stream). It is totally up to the operator.
I think it’s fair to say that gas price is the only thing driving rigs in dry gas plays like Haynesville and Marcellus. And the Bakken and Permian are oil driven. But there are definitely rigs in OH, OK, and the Eagle Ford where the drilling decisions depend on both oil and gas prices, substantially.
Nony,
Of course most wells produce both oil and gas, at the margin for any given oil price, the price of NGL and natural gas will also influence economic decisions, with the ratios of oil, NGL, and natural gas for any given well determining how much of an influence the 3 prices will have on the decision.
For Texas:
“Oil Well
Any well which produces one barrel or more crude petroleum oil to each 100,000 cubic feet of natural gas.”
“Gas Well
Any well:
(a) which produces natural gas not associated or blended with crude petroleum oil at the time of production;
(b) which produces more than 100,000 cubic feet of natural gas to each barrel of crude petroleum oil from the same producing horizon; or
(c) which produces natural gas from a formation or producing horizon productive of gas only encountered in a wellbore through which crude petroleum oil also is produced through the inside of another string of casing or tubing. A well which produces hydrocarbon liquids, a part of which is formed by a condensation from a gas phase and a part of which is crude petroleum oil, shall be classified as a gas well unless there is produced one barrel or more of crude petroleum oil per 100,000 cubic feet of natural gas; and that the term “crude petroleum oil” shall not be construed to mean any liquid hydrocarbon mixture or portion thereof which is not in the liquid phase in the reservoir, removed from the reservoir in such liquid phase, and obtained at the surface as such.”
From
https://webapps2.rrc.texas.gov/EWA/help/P-5_gloss.htm
Basically in Texas a gas well has a GOR>100 MCF/bo.
For Texas, well designation is important because it changes the tax rates. Many other states, you have some rate on gas and some rate on oil (C&C) and it doesn’t matter how much of each you get (it just gets the respective rate). But in Texas, it does. And a well can even change designation (and hence tax rates) over time.
But in ND, OH, PA…there’s not this sort of system of call it one or the other. There’s a rate of X% for oil and Y% for gas. Of course the total tax changes, but just using those percentages. But it doesn’t change if the well is mostly a gas well or oil well. It’s just those are the rates on the fluids.
—
From BH Rig Count FAQ:
How is the determination between drilling for oil and gas made?
The determination is made by the operating company when the rig permit is issued by the state’s permitting authority. The operating company will drill appraisal well(s) to determine the hydrocarbon target. Based on the results, the operator makes a judgment call on how to classify the well. For example, if a well is producing – on a Btu basis – 50% gas; 20% NGLs and 30% oil, it could either be listed as a gas well (gas is the largest component), or an oil well (which is driving the economics). This judgment is solely up to the operator.
Dennis
That is a problem with Frac spreads. However what is clear is that oil rigs are starting to increase/reboubd while NG rigs have been bouncing around 105 since mid July.
OPEC falls short on promised increases in oil supply.
The eight core OPEC+ members who introduced voluntary cuts in April 2023 plan to fully unwind their most recent 2.2 million bpd layer of cuts by the end of September.
They are then scheduled to begin removing a second layer of 1.65 million bpd starting in October.
However, analysts are deeply skeptical. With key members like Algeria, Kazakhstan, Oman, and Russia already producing near capacity, experts predict that the actual production increases for the coming months will likely represent only half of the official targets.
The total real production boost from fully unwinding the second layer may not exceed 700,000 to 800,000 bpd.
https://globalfinancialdigest.com/opec-shortfall-nears-500000-bpd-tightening-global-oil-supply/
There’s no reason to think the USGS has some God-like insight into truth. Their methodology is actually pretty simple, for “resource plays”. They buy a DI dataset.
1. Make a type curve, based on previous wells and a model for extension to end of life. No huge issue with the modeling, have to do something…but it’s a model. You can use different algorithms and endpoints and get different answers on the type curve. We don’t really have end of life data yet, so these are guesses. Future wells could have worse type curves (depressurized reservoir) or better (completions capability continuing to improve).
2. They look at the areal extent, find out how much has been drilled up, making a spacing assumption, and then get a number of locations remaining, to multiply by the type curves.
3. They do very little differentiation of sweet and non sweet spots. Their areas are huge. They are underestimating production in remaining sweet locations and overestimating in the Tier 3/4. Note, this isn’t even a “don’t like their low numbers” criticism. It’s methodology. Heck…you could worry about it creating OVERestimates. But it’s just insane to me that they don’t divide up the plays more, use kreiging, etc. Heck peakers were oh so happy to jump at the EIA for doing county level estimates, when the MIT paper came out and showed how much the productivity varied across Bakken counties. But now DC defends USGS when they have these massive areas (many counties glommed together).
4. USGS uses a format (algorithm) with some fudge factors (“percent success”) that don’t make much sense in the context of shale drilling.
5. Really…for the number of people listed as authors and the infrequency of their estimates, I’d expect better return on my tax dollars. I have no doubt that Rystad, EIA, academics (peaker OR cornie) do better work in terms of granularity…like the whole “counties are different” point that Dennis was making!
6. The have tended to be pretty infrequent in output. You end up having to look at stuff that’s pretty old. And then there’s some delay from when they bought the DI dataset and the writeup. And then some time (a year or two) from when they got the data and having enough production to type-curve a well. So…you can definitely be behind the learning curve.
7. They have had to shift (usually upwards) pretty massively over the years. Maybe less recently…but massively in the past. And it can be dangerous to assume that is over. (Like do we really understand the Deep Utica?) Look at Dennis in 2018 standing in front of a poster that had just been invalidated by a new release increasing TRR by 2X.
P.s. I’m not saying they are biased. But I don’t think EIA is biased. Or Rystad. Or UT. Or the people with much larger estimates. (Like with the Deep Utica kerfuffle.) But I don’t see any reason to just say we have to close our eyes and only look at USGS. I mean…there’s a history of that not always working out. Look at Dennis in 2018. (Yeah, great he changed after…but why did he put trust into it before? How can he have trust that there won’t be more changes. Why didn’t he, and doesn’t he, discuss the uncertainty coming from the USGS itself…not their plus/minus…but the uncertainty of the whole thing…when you look at past history or competing providers.)
Nony,
There are not a lot of places where the USGS has repeated their analyses in shale gas and tight oil basins. One exception is the Bakken/Three Forks which has an assessment from 2013 and from 2021, in 2013 mean TRR was estimated as 11.53 Gb and in 2021 the mean TRR estimate was 11.95 Gb.
A Patzek paper also looks at Bakken
https://www.researchgate.net/publication/336038796_Generalized_Extreme_Value_Statistics_Physical_Scaling_and_Forecasts_of_Oil_Production_in_the_Bakken_Shale/link/680b1e58d1054b0207e05675/download
It predicts about 7 Gb of Bakken oil if only core areas are developed beyond 2019, if non core areas were fully developed (unlikely due to lower productivity and profitability) URR would increase to 13 Gb, This is fairly close to the USGS 2021 estimate of about 12 Gb and if we assume 70% of TRR is profitable to produce, we get an ERR of roughly 8.5 Gb, I would guess perhaps 9.25 plus or minus 0.75 Gb for Bakken/Three Forks URR, or we could guess 8 to 12 Gb to cover wider potential uncertainty, but I think 9 Gb is more likely than 11 Gb.
On the Permian thing that you make such a big deal about, there was a large area of the Permian with no USGS assessment (the Delaware sub-basin)
I made a poor estimate of Delaware resources in advance of the USGS assessment being released.
This was an error on my part, if I had looked at shaleprofile.com, I might have realized that 52% of Permian output was from the Delaware Basin as of July 2018, so if I took the mean TRR estimate from the USGS(31.5 Gb) and divided by 48%, I would have arrived at a mean TRR estimate for Permian of about 66 Gb, I was ignorant of the geography of the Permian Basin at the time and missed this obvious solution.
Had I done this my estimate for Permian TRR would have been 9 Gb too low rather than the 39 Gb error in my analysis.
Hey mistakes are made and then corrected, I am imperfect.
Enno’s update from Nov 2018
https://novilabs.com/blog/us-update-through-july-2018/
Blacks are 400% more likely to murder someone than a white person.
https://en.wikipedia.org/wiki/Race_and_crime_in_the_United_States
Blacks are also 500% more likely when arrested to react with violence with intent.
When arrested if people go quietly without making the officer feel their lives are at risk, then they don’t get shot. There are very rare exceptions but police are under great stress, why don’t you try that job. See how you get on.
Ukraine is obviously able to hit Russian refineries deep inside Russia.
https://www.rferl.org/a/ukraine-russia-war-drone-strikes-oil-refinery/33539528.html
The map shows hits all over Russia and not just near Ukraine.
This is obviously why oil prices are not that low despite OPEC increasing production.
Production does not mean much if it gets blown up in pipelines and refineries.
September 28, Alexander Fleming discovers penicillin
Let’s try to keep comments energy related, these types of off-topic comments along with any replies to off topic comments will be deleted in the future. Replies automatically are deleted so if you want your comment preserved, don’t reply to comments that are off topic.
But the off topic thread is broken DC, can you post another to replace it?
Or is that it, no more?
Thompson,
I have decided to eliminate the Open Thread. If you want to discuss random stuff, you will need to find another forum. Topics related to energy are fine, if it is very unrelated it may be deleted, I will decide.
Understood
There always will be plenty of oil, coal and gas reserves in the ground – untill world fiancial markets collapse. It will collapse, because average EROEI of all energy sources will drop to low to support ever increasing complexity of world economy. Symptoms of this is unsusainable debt level across the world, and a 100% increase in gold price in 2 years.
Yergin note:
I got his “third” oil book in the mail a couple days ago. He put out The Prize in 1991. Then The Quest in 2011. Finally The New Map (one I just got) in 2020.* (It was only $7 for a used hardcover library edition, in good condition.)
The Prize, 1991, was an incredible history of the oil industry. Whether you are a peaker or not, a consumer or a producer. It is incredibly worth reading. So much about Rockefeller and his shenanigans for instance. The famous story of how he got all his hated production competitors in a room…and said…”the real enemy is the consumer!” Good coverage of OPEC also.
The Prize even covered Desert Shield (Storm had not happened yet). I literally read the book in 1991 as I headed off to war. (And I did nothing special, my unit never even got all the way on scene…but it was a bizarre time knowing we might be involved. And it felt eerie reading that book about how countries might fight over oil!)
I read The Quest a while ago. It was a decent book. Not as memorable. The Prize was the “banger”. Sort of figuring this one will be similar. But still…lots of detail and organized well…looking forward to it.
I have also read several popular books on the fracking revolution. (Two were done by different WSJ reporters competing with each other…some witnesses even joked about how they got interviewed by both of them.)
I also read the Mason Inman hagiography of M. King Hubbert. I’m much more cornie than Inman…but he’s a good science writer…and lots of interesting detail, especially on pre 1956 Hubbert.
I’m sure you all can’t wait for my review of the latest Yergin book. (Kidding.) But you will have to wait until after I read it. I’m sure you all can write reviews of it without reading it! 🙂
*He also wrote a book about the Cold War in 1977. I haven’t read it.
Take your time
The 914 is out.
https://www.eia.gov/petroleum/production/
Crude:
US overall was up over a hundred thousand, hitting a new peak at 13.642 MM bopd. I think the previous month was slightly reduced down. Large gains in TX and NM. Large drop in AK. Rest of US was small potatoes up/down.
Notable states or changes:
AK: large drop, over 50 thou. Probably temporary.
CA: continued slow decline, down 3.
CO: up 11.
FGOA: almost flat, down 1.
NM: up 66.
ND: up 16. Still below 1.2 MM bopd.
OH: up 15. Just broke past 150,000.
OK: down 6.
TX: up 87.
UT: down 5.
WY: down 1.
EIA 914 natural gas (total withdrawals):
US overall was down slightly from 129.8 to 129.5 BCF/d. However, taking AK out of the equation (as it gyrates and is mostly reinjected, not used), lower 48 was up about 1 BCF/d.
Significant changes (other than AK):
LA, NM, and TX all had decent gains in the 0.4-05 BCF/d range.
PA had a decent drop (~0.5 BCF/d). Note that PA is bottlenecked by lack of pipelines. So it is normal to have some seasonality. PA produces less in the summer, when local demand is lower. (This is not a “running out”, peak oiler thing. You can look at local prices and see Transco below $2! That is a lack of pipelines to go to Henry Hub, along with lower local demand in the summer.)
Economic analysis:
The jump in LA is related to (relatively) strong Henry Hub prices. (Still…WAY below what the peakers would have predicted, pre-shale, but at least up versus recent.) Along with the “Haynesville Renaissance” (turns out it wasn’t post-peak after all!)
NM is mostly oil-driven. So the extra gas is from associated gas (along with a normal shift to higher GOR as wells age).
TX is a mix of reasons. The western part (Permian) is oil-driven like NM, with ass gas. In the south (Eagle Ford) and East (Haynesville), it’s more of a response to Henry Hub prices.
[As previously discussed, the PA decline is a result of the pipeline bottleneck, with very low local prices in the summer.]
In 2014, Mason Inman published an article in Nature magazine, warning of shale gas peaking danger, with the provocative and sensational title “The Fracking Fallacy”. Nature magazine had an accompanying editorial with more hand-wringing.
https://energyskeptic.com/2014/natural-gas-the-fracking-fallacy-nature-2014/https://energyskeptic.com/2014/natural-gas-the-fracking-fallacy-nature-2014/
So…what actually went down?
Marketed dry gas:
2014: 25.9 TCF
2024: 37.8 TCF
That’s a 46% increase, during the past decade. Sure seems like natty is going strong. And the early/mid 2010s shale gas critics were wrong.
Note that you can’t really explain the difference by price either. 2014 averaged $4.37/mmbtu. 2024 was about half that, at $2.19. (Actually $1.66 in 2014 dollars.) Now…natty does tend to gyrate from weather (even annual averages). But at a minimum, you can’t say price drove the increase. The directionality is reversed.
We are making more natty. At lower prices. That is not shale gas running out of steam. That is a full on glut, crushing the peak oiler shale gas h8ers.
Of note, Inman has moved on from peak oil/gas writing to more straight environmental advocacy and public relations. Hmm…wonder why he moved on? Not really…the pattern is common. You can see how Post Carbon pivoted also. And for that matter…look how ASPO and TOD shut down.
Nony,
At the time (2014) natural gas prices were pretty high, higher than any ensuing year except 2022 for annual average price.
Shale gas output has grown a lot since August 2014. The average annual rate of increase from Sept 2014 to August 2022 for US shale gas was 9.6% per year. From Sept 2022 to August 2025 the average annual rate of increase has been about 1.8% per year. From Jan 2017 to Dec 2019 the exponential rate of increase in US shale gas output was 16.7% per year.
A chart linked below shows shale gas output on a logarithmic vertical axis where the slope of the line corresponds with exponential rate of increase. The rate of increase has been slow of late, perhaps higher natural gas prices will change things, though note that low oil prices may reduce associated gas from tight oil plays which may offset increases from Haynesville and Appalachia.
At the page you linked, Patzek said we might see significant growth for about 10 years in shale gas output and then it would level off followed by steep decline. Right now we would be approaching the plateau. This was his best guess but he noted there was significant uncertainty. The quote is:
“Patzek argues that actual production could come out lower than the team’s forecasts. He talks about it hitting a peak in the next decade or so — and after that, “there’s going to be a pretty fast decline on the other side”, he says.”
shale gas log
Even if there is some voodoo slowdown right now*, 2014 to 2024 had a 46% increase (annual data). That sure doesn’t seem consistent with the Mason Inman/Nature “Fracking Fallacy”.
You love to cherry-pick endoints to drive a narrative. Very specific months and years there.
Also, slowdowns can revert. 2015-2017 was also pretty flat…then back on the rocket! Often the slowdowns are associated with weather-driven price variations, not some meta-geology reason. But the peakers jump on it and get tripped up repeatedly. Happened 2012-2013 also. And…it’s very easy for me to go pick peakers that jumped on those temp slowdowns. Ugo Bardi did in 2013 at his Cassandra blog. And there was a shale gas peaked post on this blog in 2016 (from the goldbug guy).
FWIW, (next post coming), 2023 and 2024 had miserable prices. That’s a sign of too much supply for the market, Dennis, not too much. Who wants to increase supply when prices are in the $2s? So…duh…why do you think growth slowed!
This should make it crushingly obvious why gas production growth slowed. Look at the price!
Date TCF, drymkt Price, nom price, 2000
2000 19.2 4.31 4.31
2001 19.6 3.96 3.84
2002 18.9 3.38 3.25
2003 19.1 5.47 5.11
2004 18.6 5.89 5.35
2005 18.1 8.69 7.69
2006 18.5 6.73 5.75
2007 19.3 6.97 5.81
2008 20.2 8.86 7.09
2009 20.6 3.94 3.15
2010 21.3 4.37 3.44
2011 22.9 4.00 3.05
2012 24.0 2.75 2.07
2013 24.2 3.73 2.76
2014 25.9 4.37 3.19
2015 27.1 2.62 1.90
2016 26.6 2.52 1.81
2017 27.3 2.99 2.11
2018 30.8 3.15 2.16
2019 33.9 2.56 1.73
2020 33.8 2.03 1.35
2021 34.5 3.89 2.48
2022 36.3 6.45 3.79
2023 37.8 2.53 1.43
2024 37.8 2.19 1.20
As you can see, prices in 2023 and 2024 were in the mid to low $2 (nominal). And even lower, sub $2 if you correct back to 2000 dollars.
That’s not “running out of shale gas”. That’s shale gas crushing prices until it self limits itself.
Maybe we need some more LNG. And some pipes out of PA. Damned treehuggers!
Nony,
The endpoints were chosen to mitigate the seasonal cycle that you had correctly pointed out earlier. In every interval chosen I use a multiple of 12 months for the length of the interval. August is chosen as the end date because the last data point for dry shale gas is August 2025.
I agree the slowdown is likely due to low gas prices, also note that if gas prices rise too much, there may be less demand for US LNG as it may no longer be competitive on international markets. Also note that there are cheerleaders who claim that the gas is profitable to produce at very low prices, so one can’t make the argument that it is profitable to produce the gas at $2/MCF and then claim that output is not growing because gas is at $2/MCF. You have not made the low price claim, that would be something that Coffeeguyzz might say.
Did you click on the link for the chart? One can visually see the change in slope over time and yes there have been previous slowdowns followed by growth. Sometimes the slow downs in shale gas growth are tied to changes in oil price and slower tight oil output with lower associated shale gas output tied to low oil prices.
The prices for natural gas were low from 2015 to 2019. The average annual rate of growth was about 12% per year vs under 1.8% per year in most recent 36 months. The average HH spot price in 2000$ over the Sept 2022 to Aug 2025 period was $1.69/MMBTU vs $1.94/MMBTU over the Jan 2015 to Dec 2019 period. Much of the growth from 2015 to 2019 may have been associated gas from tight oil plays which grew rapidly over that period. Not related only to natural gas price, oil and NGL prices also play a role in overall shale gas growth.
OK, you didn’t cherry-pick the months–you did the years. 😉
Glad to hear you admit that prices (EXTREMELY LOW) were behind the slowdown. Too bad you didn’t say so before I reminded you though. 😉 It’s the same thing we saw before with 2012-2013 and in 2015-2017.
As far as price and supply. It’s a balance for sure. If price goes too far down, growth will slow and even reverse. We saw this in 2012-2013 and 2015-2017 and 2023-2025. It’s happened several times…but for each of them (well the first two, jury out on the last), we got back on the growth horse. And it did not require very high prices, just up from the crash.
Note: weather (an abnormally warm, or cold, winter can drive prices low for most of a year. This isn’t even about the industry momentarily over/under producing. It’s about how cold the winter is. Cold, average, warm.
Also, note that the overall trend in price has been one of getting cheaper. I’ll graph it and give a trend line. But you can see it just with the numbers. We’ve almost doubled supply…while also going down from 5ish to 5+ in 2000-2010, to prices about half that, during the shale revolution. (Constant dollars.) That’s not just getting more supply from more price. That’s getting more supply and crushing the price.
P.s. I’ll let Coffee speak for himself. I have enough chinks in my armor, on my own. 😉
Nony,
I assume my readers are intelligent, so not really a need to say that low prices may affect output in my view, especially when oil, NGL, and natural gas prices are all quite low. The point was that both periods I covered were low price periods, but output growth was very different.
It is possible we may be close to the limits of technological progress counteracting depleting resource availability. Always impossible to predict in advance and I have very limited data on current well productivity as there is only old data available for free from Novi Labs. At some point every oil and natural gas field reaches maturity and soon after the begin to decline(though not every one at the same time of course).
The resources that have been discovered over the past 10 years are mostly expensive to develop and very limited in size. I also expect that lack of demand may lead to many fossil fuel energy resources being stranded within the next 15 to 20 years. I agree prices are quite low, this will continue to be a problem for producers, we are getting closer and closer to peak oil demand, this may be the reason for low fossil fuel prices.
1. If shale gas is so expensive, how come prices halved, while production doubled?
2. How sanguine are you that we are about to have a sudden, harsh Patzek decline? Especially given where prices were during the slowdown…and that only caused a slowing, not a drop even?
3. Patzek was out to lunch on the Marcellus and Haynesville. Here he is in 2016 (more than a year after the 2014 kerfuffle, but he talks about it).
https://patzek-lifeitself.blogspot.com/2016/03/is-us-shale-oil-gas-production-peaking.html
Using his graphs, the Haynesville should be doing about zero now. And it’s doing more than it’s old peak!
And he’d have the Marcellus close to zero also. Yeah, he had some caveats…but he still graphed that as his best guess. Even his upside caveats ended up way shy also.
There’s also a huge amount of natty coming from the Permian that Patzek never mentioned. You can try to bail him out by saying he can’t do everything…but then the point of his analysis is misguided as things happen outside his scope that are extremely important. I mean who gives a fig about the Fayetteville at this point in time?
Net/net: 2016 Coffee is looking a lot better than 2016 Patzek.
Nony,
The charts in the Patzek blog piece are “base cases”, for Patzek this is a case that assumes no wells are drilled in the future, it is not what he expects to happen. Try reading in the future, it helps.
Nony,
This paper gives some of the history of Patzek’s work on shale. Read and learn.
https://pubs.acs.org/doi/full/10.1021/acs.energyfuels.9b01385
This post gathers together a lot of Patzek papers.
https://patzek-lifeitself.blogspot.com/2021/05/papers-on-us-shale-plays-by-patzek-et-al.html
1. Dennis, yes I missed the caveat about Patzek only covering existing wells, with the Hubbert curves.
2. I’m well aware of Patzek’s c. 2021 papers. They are good work. Kudos to the students especially, but also to him. They are night and day versus the 2016 blog posts. The answers are much bigger. And the methodology much richer (buying a data set, parsing into areas and generations, doing type curves, discussing economics.)
2.1. I have ZERO problem including the Patzek 2021ish stuff in a portfolio of expert analyses. In fact, when we discussed the Utica, I advocated for including him. In the basket of flowers. I just include others also, that show signs of sound work. EIA, the NIST guy, UT, etc. This is sort of in contrast to you…where you dismissed any high estimates (even though done with a strong methodology by real scholars) and only look for some validation between USGS and Patzek.
3. Going back to the Patzek 2016 blog posts. That is really sort of unusual to use a Hubbert curve to estimate remaining production from drilled wells.
a. It’s not best practice. Should use type curves instead.
b. That’s like the first time I’ve seen that. I’m much more used to people like Laherre or Verwimp having Hubbert models that are explicitly for the field production. I.e. including future development.
4. The disclaimer is interesting in that he only posits a very small factor for continued field development. Here is the whole thing:
“Disclaimer: The plots below are only for the active producing wells up to date. To the extent that robust drilling will continue unabated in each play, the three shale gas plays described below might produce another 50 percent more energy. If the rate of drilling rapidly diminishes, as is the case today, the ultimate production from these three shales may be only 10-20% above the projections in this blog.”
Now…do you really think production to date is in agreement with adding 10-50% area under the curve to his dramatic Hubbert TRRs? I can pull the production data from EIA and do the Excel, but just looking at the graph of Haynesville and integrating by eye, we get something way larger than he predicted, in terms of production.
https://www.eia.gov/outlooks/steo/images/Fig43.png (look in particular at the Haynesville and compare the pre and post mid-16 production.)
The production rate recently is much higher than the mid 2016 production. And the cum from post mid-16 production looks like it is 3x or more versus the prior production. Compare to his blogpost graph showing ~2 boxes of prior production and 1 box of future production.
Even with the 10-50% addition, to his very small TRR, I don’t think you can square what happened versus what he predicted. You’d get something like 3.3-4.5 boxes total. Or future production being 1.3-2.5 boxes (versus prior of 2 boxes). That’s a ratio of 0.65-1.25:1 for future versus previous. But actually (again visual integration), future production to prior…which ain’t even over yet…has been ~3:1 or better.
Again, I can download it and slog through the math…how much you want to bet he wasn’t low? 🙂
In addition to massively underpredicting continued development, I don’t think the Hubbert curves even work for predicting production tails.
After all, why should they? One involves a speed of development (with some decline happening as wells are added). And the other is the tail of all the wells declining (which will be slower for older generations). I mean there’s no good reason to think a Gaussian is the right curve for well decline, especially with forcing the symmetry of growth and decline, which has no reason to exist in the real world.
Anyhow, consider the most recent Novi blog I could find:
https://novilabs.com/blog/haynesville-update-through-april-2023-4/ (select for 2015 and earlier wells only).
The production peak (end of 2015) was ~4.1 BCF/d. The tail of production (from those wells) was ~1.4 at end 2019, start 2020. And was pretty flat the next few years also. Still doing ~1.2 in early 2023. So that’s like dropping to 34%, five years later. And only dropping to 29%, 8 years later.
In contrast, if you look at his blog: We go from about ~1.7 (end of production history) to ~0.1 five years later. That’s a drop to ~6% in five years. In eight years, the curve is so close to zero, I can’t distinguish it.
So…even just for existing wells, his Hubbert method is dramatically underpredicting future production.
Another US Record?
Primarily driven by TX and NM and held back by Alaska.
US1
Thanks Ovi,
At some point, maybe Sept or October, the lower horizontal oil rig counts will start to have an affect, remember we have a 6 to 8 month lag from spud to first flow. So if it is 7 months the drop in rigs that started in April would start to show up in October 2025.
Dennis
I think the EIA still has NM totally wrong. I have production dropping for the last two months.
As for the rig count, the rigs have been time shifted forward by 6 to 8 months and production is flat in Lea County. Maybe the lag is more than six to eight months, inexplicable?
This is what the Dallas Fed is saying about oil production in the third quarter.
“Oil and gas production declined slightly in the third quarter, according to executives at exploration and production firms. The oil production index remained negative and was relatively unchanged at -8.6 in the third quarter. Similarly, the natural gas production index was relatively unchanged at -3.2.
Firms reported rising costs, with all series above their averages. Among oilfield services firms, input costs rose but at a slightly slower pace than the previous quarter as the input cost index declined slightly from 40.0 to 34.8. Among E&P firms, the finding and development costs index increased from 11.4 to 22.0. Also, the lease operating expenses index increased from 28.1 to 36.9.”
Also the STEO prediction for July was 13,406 kb/d vs reported 13,642 kb/d, a 223 kb/d miss.
https://www.dallasfed.org/research/surveys/des/2025/2503
Ovi,
I am just looking at total US HOR which started to drop in April, I am using Mr. Shellman’s rule of thumb for lag from spud to first flow, perhaps it is longer today than in the past, I am not an oil hand so I am guessing.
Took a look at OCD data today and compared with OCD data from a year ago.
The differences are listed below starting with Oct 2022 and last number is for July 2024 (last datapoint from dataset in Oct 2024).
4
11
19
15
14
14
14
16
13
13
14
11
17
16
8
9
27
37
41
32
43
54
When we go two years back the errors are a bit bigger, my guess is that after adjusting for this (using two year % differences) the EIA 914 estimate for NM seems to be 1 to 3% too high (recent numbers with larger errors) over the Jan to July 2025 period.
Ovi (on NM):
That’s OK. It’s not a huge deal, your NM worries. And won’t be first time an EIA doubter proved wrong.
I still remember all the squawks in late 2017 as production started rising. Lots of peakers and price bulls said it was EIA lying or counting NGLs or whatever conspiracy theory they could think of. And it kept blasting…broke the record in NOV2017. And in 2018 continued on up another 2 MM bopd. And the 2017 never got revised down!
Dennis
I am also using Mr Shellman’s rule of thumb. It was his suggestion that led me to do that. Seems to work for some cases. However for Midland I need to use 1 year and I keep noting that this is really different than the other counties being reported on.
Nony,
Historically the EIA data has been very good for NM. From Jan 2015 to Dec 2022, the 914 estimate has on average been lower than the Final Estimate (based on State data) by about 0.4%, occasionally the 914 estimate is too high for an individual month by 4% and low also by 4 % on occasion (one example for high and low over this 84 month sample.) Mostly the 914 estimates are within plus or minus 1.5% of the final estimate, but the estimates have been good since Jan 2015.
Dennis, yeah…you said that before. You and I should be playing doubles tennis versus Ovi and Dean Fantazinni. We are actually pretty much aligned (on this tiny issue).
The interesting (minor) thing to me is the continued growth of NM for another month. This can get uncomfortable for the EIA h8ers. Saw it in 2017…they kept expecting a reversion to (what they thought was) reality. And instead the gap grew. In 2017-2018, they eventually gave up the ghost as the numbers kept getting worse and worse for them. Show me one now who says the US didn’t really grow in late 2017. The ship sailed!
The new month is the new datum. I could be wrong, but I think I remember Ovi even saying something to the effect of “let’s see how next month goes”. And yes, of course there can be noise (both in growth and in EIA accuracy). But in this tiny case, the new datum didn’t help his Dean-like modeling and calling out EIA.
Dennis
I agree that the EIA estimate is too high. Here is different look.
Below is a table which shows the production I was projecting for NM in the April update. In April production info was available up to January 2025. Back then I was using Lea plus Eddy production to estimate overall production for NM.
The numbers in this table are from the latest comp-stat-oil which updated the EIA 2024 production to NM production.
Compare the difference between the April report and the EIA final. The biggest error of 30 kb/d was for January 2025. It is much larger than that now which I will report on Friday or Saturday.
A Table
Frac spreads are really no longer a leading indicator of future production because of simu-frac’ing multiple wells on the same pad, all of which are taking much longer to drill and complete in the Midland Basin because of longer laterals, mostly by Exxon (PXD) and Oxy, for instance.
Many of these wells are now requiring 3 casing strings, even a liner setting. Three or four 15,000 plus foot laterals have to be completed before source water can be arranged, which for four wells can exceed 2.5MM bbls. and is giant undertaking. That alone can take months. Fewer rigs have not led to less production, yet, within the normal lag time in this county, also because of DUCs, which are now all gone. I wrote about this at my place.
If sitting in your basement in New York you are not going to know this. All you know is what you read on the internet. So why even listen? Its not a reliable source even to argue with.
A word about associated gas “molecules,” more LNG export facilities and associated gas from tight oil wells in the Permian Basin, please: phftttttt.
https://www.oilystuff.com/group/natural-gas/discussion/521038ab-423b-4cab-958f-00ae53926ad9
Remember, please, for the sake of America, there is nothing magical about the tight oil and tight gas phenomena….it all happened on the back of debt, much of which will never be paid back. Cheerleaders always, I repeat ALWAYS leave the debt part out.
Give me enough money and I can turn all of Kuwait in to Augusta National, complete with the Azaleas.
With regards to oil and LNG exports…America first. Always!
Mike
I sit in Toronto and have made it clear I have not seen a drilling rig. The only thing I do is take EIA, Lea and Midland etc., production numbers and try to convert them into nice charts so experts like you can comment on them.
I thank you for the idea you gave me to time shift the rigs numbers ahead by 6 to 8 months. From your comments I think I am hearing that a longer time shift may be required today. Maybe the one year I am using for Midland is reasonable.
Thanks for the update, much appreciated.
Ovi. my comment was NOT directed at you, sir. You do good work. I am trying to help.
Midland County I believe had a higher number of DUC’s thru 2024 and that along with higher, long-lateral IP’s has distorted the falling rig count picture. That appears to be over. I updated Novi’s DUC map in the Permian and its clear there were still lots of DUC’s being completed in 2024. When you see where those remaining DUC’s are… they may not be dead but they are very sick. Enverus data is the same; DUCs are finally almost all exhausted.
I think lag times are still 6-8 months in general; less HPP services increases wait time.
My comment about LNG exports reflects very long term concern for all of North America, including Canada, actually, not just America. Associated gas from tight oil wells (particularly in an over-drilled Permian) is a poor reason to spend $54B on new LNG facilities, the permitting of which is actually quite expensive including environmental studies, etc. etc. Some of the other stuff said here, about gas well classifications and what constitutes WTI quality in Texas is actually quite dumb and should just be ignored.
Thanks Mr Shellman,
I agree exporting US energy resources, except perhaps to Canada and Mexico, is not a smart move on the part of the US.
What is HPP? Maybe High Pressure Pump and there is a current shortage of these services? Chat GPT seems to think there may be some signs that an HPP shortage may be developing, but of course you would have far greater knowledge on this.
data for EIA 914 with comparisons to other estimates at link below
https://www.eia.gov/petroleum/production/xls/comp-stat-oil.xlsx
Using data from NM tab in spreadsheet link above the chart linked below compares NM data for 914 estimate with EIA final estimate (which uses state data as of August 2025, updated annually every August) from Jan 2015 to December 2024. The EIA estimates are imperfect, but not terrible in my view.
914 NM
Ovi,
Not unusual for the STEO to miss and perhaps the July data (and perhaps even June) might be revised lower in the future. Sometimes the 914 data reported by large operators gets revised and this will affect the 914 estimate for the most recent couple of months. The recent months often get revised and they will get revised again in August 2026 to bring them in line with state data.
I graphed the constant (2000) dollar HH annual average price versus year.
The linear trend is from about $5.5 to $1.5 (the ends of the line, not the endpoints on the chart). That’s about a $4 drop, over 25 years.
Note, this isn’t even as extreme as I could make it. If I did last 20 years (say from 2005, peak oil hype year), the rate of price decline would be even more harsh. But…this is good enough for me. 🙂
And note…while all this was happening with price, supply doubled!
Now…you know why we want LNG plants! Let my molecules go!
https://www.youtube.com/watch?v=fHbC8Nhd46s
Nony,
Using monthly HH spot prices from Sept 2010 to Aug 2025 in 2000 US$, I get an annual decreasing trend of $0.065/MMBTU or a drop of $0.98 over 15 years, average price was $2.21/ MMBTU in 2000$ over the 15 year period.
A longer term chart from Sept 1997 to Aug 2025 has an annual decrease of $0.11/MMBTU, the average price over the 28 year period is $3.31/MMBTU (both in 2000 $). Prices decrease by $3.14/MMBTU in 2000$ over the 28 year period from $4.88 to $1.57/MMBTU in 2000$. This result seems to be more similar to your analysis.
On the LNG plants, I would not be an investor as the demand may not be there or the supply may not be there, if prices continue their trend lower. Low prices will kill supply or high prices will kill demand, the LNG capacity is being over built in my view (assuming all proposed projects in the US get built.)
Dennis:
As with any investment, there is down and upside risk. I certainly don’t recommend that you invest in an LNG plant. But I don’t recommend to invest in any single asset or stock. You should be investing in the index. But companies and financiers should feel free to invest in LNG. They are in the business of making bets. Some will work out. Some won’t.
For every Facebook, there’s a pets.com. But LNG per se, is not that different than investing in a pipeline or a FGOM oil platform or a big chemical plant. All heavy metal assets with long lifetimes. Might be printing cash. Might not. That’s capitalism.
“Low prices will kill supply or high prices will kill demand…”
Dennis, if prices are low that means the LNG plant is in a good position to make money. Don’t even think about “killing supply”. If prices are stuck at $2.50, they’re stuck at $2.50. (Or whatever you think is “low”.) But low prices are good for loading cargoes. (Assuming destination markets don’t suddenly get pipeline gas or oil doesn’t crash, of course.)
Note that most of the risk is really on the consumers that lock in 20 year contracts or the like. Very few LNG facilities are built on spec. They have presold most of the capacity. There might be a small fraction on spec. And might be some delinquency risk. But in general, the LNG plant is a sort of middleman.
In general, high HH prices are the danger (for spec volumes and for delinquency risk). Low is just fine for the LNG plant. They are like refineries…they don’t care if oil producers go bust. They are mostly converters, but to the extent there’s a correlation, it’s ANTI correlation with the producers. (Who love high prices and hate low.)
“the LNG capacity is being over built in my view (assuming all proposed projects in the US get built.)”
They won’t all get built. FERC permits are cheap. Like leasing rights or permits in the oil patch. When you actually spend the money to buy all the pots and kettles…that’s the big investment. A lot of weak sisters in the US will get shaken out. For one thing, there’s a reasonable amount of competition from international (especially Qatar). Or from pipe gas. What happens if peace breaks out and the Russians start supplying Europe again (much cheaper than US LNG).
But don’t let it worry you. Sometimes companies overbuild. Sometimes they underbuild. Each can happen. But…it’s not your money. Let them take their bets. That’s capitalism.
https://en.wikipedia.org/wiki/Free_to_Choose
Don’t try to pick winners and losers. Let my molecules go!
Nony,
Yes low prices are good for the LNG producers, but not good for the natural gas producers, so there won’t be supply to feed the LNG trains, no natural gas means no LNG. High prices will generate supply, but will kill the profits for the LNG producer, especially if competition in the LNG market does not allow higher prices. I have read there is a likely glut coming for the World LNG market, if so profits may evaporate.
Just how I see it and yes S&P 500 is about all the risk I am willing to take. Capitalists are Free to Lose.
I think a lot of LNG these days is not locked up in 20 year commitments.
IEA analysis of LNG
https://www.iea.org/data-and-statistics/data-tools/global-lng-capacity-tracker
I think you need to refresh your knowledge of econ 101, tracing an input on a P-Q chart.
If prices are low, prices are low. You don’t need to worry about what is happening to supply, when you run an LNG plant and buy at Henry Hub. You just buy.
If the HH is at $2.50, you just put an order in at $2.51 and get your gas. If there’s no supply, prices will go up…but then this is not consistent with your precondition that prices were low.
This is literally supply and demand.
IEA expects about 300 BCM per year of new LNG capacity will come online from 2025 to 2030,
For simplicity I will assume 45 BCM per year in each year from 2025 to 2030 (6 years) which assumes LNG facilities operate at an average capacity of 90%.
Chart linked below has World LNG exports from 2000 to 2024 with simple forecast in red. Looks like a potential glut of LNG which would tend to result in lower prices for LNG.
world lng exports
Continental selling partial stake in OK, to Total.
https://www.businesswire.com/news/home/20250926216379/en/United-States-TotalEnergies-Pursues-its-Gas-Value-Chain-Integration-by-Acquiring-Producing-Assets-in-the-Anadarko-Basin
Not sure what it really means. Seems sort of financing in nature. Not sure why CLR did it and/or why TTE wanted to, either.
In the above note regarding Continental selling Andadarko Basin wells to Total, here is a response to your several statements about LNG and the Henry Hub. Due to a terrific network of pipelines built during the big Granite Wash deep gas boom of the eighties/nineties, just about all the wells in the Anadarko Basin feed into the Henry Hub. They generally produce some oil but at 14,000 feet they produce mostly NG under high pressure with a very slow decline rate that can be extrapolated with some degree of assurance. That makes them calculable cash cows in a time of uncertainty. And with them comes infill/offset allowances.
In fact, with the high water cut and high GOR in the Delaware Basin, new wells in that area are generally much more profitable than the Delaware wells. Because of that, there is a small boom in Roger Mills County, which is next to the Texas Panhandle and about 2/3rds of the way up the “pan.” The most elaborate example is undoubtedly the Telli Camdyn 30-19-1H well, which was brought in last fall and in Feb or march of this year produced over 60,000 BOE during the month. These deep wells are relatively inexpensive to drill, at least by current comparisons to the Permian, and there’s quite a bit of room to spread out. A couple of the Mewbourne rigs have moved in up there.
Total is trying to become the king of LNG and since these wells send NG into the Henry Hub they’re a perfect fit. Roger Mills County and a couple of others were sort of passed over when the big NG boom hit a few decades past, but now with the help of AI they seem to be able to handle these complicated wells with a good likelihood of prompt payout–a rare thing these days.
As an aside for those of you who like geology, that area was once an ancient ocean and then, at some point, there was an immense deep earth disturbance. North of the Red River, massive granite slabs were turned over but none came up to the surface. Some of those lop-sided slabs formed partitions that became wonderful oil traps. South of the Red River the disturbance brought the granite to the surface, so they cut tombstones down there (Granite, Oklahoma) but have no oil or gas to speak of.
For those of you interested in history, the site I’m speaking about is north of the fabled camp of the Southern Cheyenne, where Black Kettle the Peacekeeper was chief. He wore a top hat and dressed like Abe Lincoln when he made trips to Washington, DC (like some other famous chiefs)–but it didn’t help his cause. General Custer wiped out the Southern Cheyenne, but in a twist of irony, it was the Northern Cheyenne that killed him at Little Big Horn. I apologize, Dennis, for adding this colorful commentary but it is an exceptional part of a geologically fascinating area.
Ger:
Thanks, kindly! (Including the color.)
If you look at OK natty production, it is up 0.5 BCF/d, over the last half year. Still short of record levels, but will be interesting to watch it and see if the 1H2025 growth continues.
https://www.eia.gov/dnav/ng/hist/ngm_epg0_fgw_sok_mmcfdm.htm
I hadn’t been watching TTE for a few years. I still remember 10ish years ago when they said they did NOT want to get into shale (like the other majors, buying in). They felt their expertise was more in Africa…whole French thing. But…I guess with time things can change. And here they are Hamming it up in OK. Pun intended. 😉
Good article about early days of the shale boom. How high prices pre 2010, drove investment and development. But then the genie turned on its master and high production started to push prices lower than “normal”.
https://rbnenergy.com/evolution-how-shale-boom-remade-the-gas-market-and-turned-the-us-into-a-major-lng-exporter
[Note, you have to read it in next 4 days…goes behind paywall after.]
Thanks Nony, interesting piece.
Does anyone know of a good overview on the Hertz EV experiment? I admit to some schadenfreude, but mostly just want a dense retrospective on what the plan was, how it was worked , and what the results were. I must live under a rock, but was not aware until today that it had been a huge financial failure. I just remember all the annoying Tom Brady commercials. (I guess those are done now.)
I tried Googling, but mostly finding short articles on quarterly earning charges or sell offs. I want a thorough analytical start to finish (at least as of now, I get that some writeoffs will continue to end of fiscal year 2025). I seem to be able to get a more analytical discussion of the Cracker Barrel failed transformation than of Hertz! (Could be my poor Google-fu.)
This article is over a year old, but has a lot of detail from interviews with internal sources, not just rehashing the 10-Qs and press releases:
https://archive.ph/BcBTx
Basically a combination of corporate hubris, an EV “bubble” and the inherent issues with renting EVs to time-constrained travelers (not the ideal market).
No, but I can tell you that the US has lost the global automobile industry competition. China has paced us on the track and is coming around fast to go two laps up, and gaining speed.
We are trying hard to avoid looking at the obvious (future).
https://www.newsweek.com/chinas-ev-supremacy-raises-national-security-concerns-for-the-us-10799968
https://theconversation.com/chinas-electric-vehicle-influence-expands-nearly-everywhere-except-the-us-and-canada-262459
And their electrical generation capacity buildout is leaving this country in their dust trail.
Dennis, moving the LNG topic down.
1. Thanks for the info. I really don’t have an internal “model” (even a casual one) on LNG growth. Just haven’t followed it much recently. Lot of my knowledge is 5-10 years old. And not saying that was perfect either!
2. It seems like there was a fair amount of US capacity that came on line…then a long pause…then a bunch more coming. And probably another long pause after that! (I “buy” the overcapacity concern.)
It’s kind of natural in commodity industries for there to be periods of over/under capacity. It takes a long time to build these plants. And in the mean time wars (or peace!) can break out. Or other factors on the demand side change.
There’s definitely competition with oil or pipeline gas. Of course oil can change price rapidly. Pipes are slower and more predictable. Still…on the timeline of a liquefaction plant….pipes can come and go.
All of which is to say that even though I buy the overcapacity concern, I still remember the oercapacity from 8 years ago! Then under. Now OK…but “over” looming for the 2030 timeframe.
3. I admit to having to look up BCM, mmtpa, and the like definitions and how to compare them to BCF/d. It confuses me. I like to think in BCF/d.
4. There’s also the issue of capacity versus expected utilization (90%?) as well as export volumes versus inputs (substantial fraction used for the process itself). Or even export volumes versus landed volumes versus regas volumes. Not always sure which people are talking about!
5. I quite like the old FF presentation from 10 years ago. The world has change since then in terms of new projects and the like. But a lot of the “how the industry works” have persisted. This is a video that I would routinely tell the “LNG cornies” and Tellurian pushers to watch!
https://www.youtube.com/watch?v=_SYcFAvc7HQ
6. I was sort of surprised to see Driftwood LNG project get FID. Under new owners, Tellurian shareholders still lost their shirts…but the project is going now…very rare to see a halt after FID made…too much spent on capital, with ordering the compressors.
https://rbnenergy.com/im-back-back-in-the-lng-groove-how-woodsides-fid-on-louisiana-lng-shakes-things-up
7. It is interesting that Woodside (Driftwood owners) are basically building the project on spec. The RBN article mentions that and says the norm is for 2/3+ of volumes to be presold. That percent has been creeping down from 90%. But is still substantial. I have long wondered why we don’t see these LNG plants built on spec (producer/owner taking full risk). After all, we see multibillion dollar oil megaprojects built on spec. And we see PE crackers and the like built on spec. Nobody tries to get 20 year contracts for a big PE plant…they just build it and take the risk/reward. Maybe…we are finally starting to see this happen with LNG, at least in the US. TBD.
Just getting myself back up to speed on LNG:
1. This article is about a year old, but you can see a very nice graphic of how LNG capacity has/will grow. (First chart in link.)
https://www.eia.gov/todayinenergy/detail.php?id=62984
You can see that capacity was added close to linearly from 2016 to 201. About 9 BCF/d, over 3 years. Then a much slower growth from 2019 to 2024, only about 1.5 BCF/d added, over 5 years (with the last two years completely flat). Now, we are looking at adding 13 BCF/d from 2024 to 2028. And that is all under construction…i.e. it will happen. And even some more BCF/d from Driftwood coming in 29-31.
It’s easy to see how the additions can be pretty lumpy. Overcapacity. Then nothing. Then overcapacity. And…all of this is the result of decisions from 5 years before the plants come on line! So, 2022-2024 was a GREAT time for selling LNG (Ukraine war and all). But it takes 5 years to go from FID to volumes. So…no ability to just “turn on the volumes” in response. And of course…stuff coming on in the 2025-2030 time frame may see a totally different European demand picture…especially if peace breaks out!
2. This is the most recent DOE list of facilities under construction.
https://www.ferc.gov/media/us-lng-export-terminals-existing-approved-not-yet-built-and-proposed
In particular, see the second page, item number “3”. Yes…Driftwood is really under construction!
Nony,
Perhaps it is difficult to get the capital for a full risk project, or was difficult in the past and today perhaps the wealthy are willing to take higher risk for greater return potential. These kinds of risks are way beyond what I could tolerate (can’t afford those kinds of potential losses).
The other thing to think about is capacity coming online worldwide, see the IEA piece I linked earlier and 300 BCM per year is about 10.5 TCF per year over the 2025 to 2050 period (capacity, multiply by 0.9 if you think 90% capacity utilization makes sense that is often what is used for refineries.) For BCFpd it would be about 29 BCF/d increase in LNG capacity over a 6 year period (the IEA analysis includes US projects).
World consumption of natural gas in 2024 was about 400 BCF/d. About 12% of natural gas is consumed in the production and transport of LNG, so the 29 BCF/d LNG becomes 32.5 BCF/d of natural gas consumed. This would be an 8.1% increase in gas consumption over 6 years so 1.3% annual increase in natural gas consumption. Over past 10 years World consumption of natural gas has grown at about 1.8% per year, but over the past 5 years the rate of growth in gas consumption has slowed to 1.3% per year, so perhaps no glut if rate of growth continues at rate of past 5 years and IEA forecast for LNG is correct.
Dennis:
I still think it’s the norm for most of the volumes to be pre-sold. It has been and still is a very slow transition to a true commodity business. The first thing to change was requirements to take to own market (allowing customers to resell). Gradually some changes from 20 year to shorter duration contracts. And gradually producers taking a larger portion of the facility as spec volume.
But still…in general the smaller players can’t get financing unless they pre-sell the volumes. And even many of the bigger players (supermajors or governments like Qatar) still tended (and tend to) presell a lot of the volumes. Perhaps because they can (they are the premier suppliers in terms of “name”.)
I donno…I think it has been a very slow moving train of liberalization. And one that the business journalists tend to overhype. All that said, clearly there is more fluidity in the LNG market now than there was 20 years ago. But it shouldn’t be overdramatized. It is WAY less fluid than oil sales. And way less fluid than the domestic US pipe gas market.
Of course on top of all this is that I think LNG is kinda crazy versus pipeline gas! The Europeans “should” be buying from the Russians. And so should the Chinese. And the ME should buy from Qatar and Iran. Maybe some volumes need to go to Japan and HI and LATAM. But in a “perfect world”, there would be WAY less LNG on the ocean. It is a very wasteful product. And I’m not even talking about the gas used for running the compressors. Just the $$$$$ in the compressors is a waste of money!
But…the world is not “perfect” and there can be issues with pipelines. SA refuses to buy from Qatar. And somebody blew up Nord Stream.
I kind of think LNG will continue to be a means of dealing with an imperfect world. If we got rid of wars and terrorists and proud Saudis, we could just pipeline all the gas. (Except islands.) I mean LNG versus a pipe is almost like running crude on a Buffet train instead of a pipe. But…still happens, no?
And it’s not your money going into the facilities. So let them be free to lose/choose. 😉
Nony,
I agree pipelines make more sense from an efficiency standpoint. Generally free markets are a nice idea, but many of the ideas underlying the market and its efficiency rely on an unrealistic set of assumptions about how the World works. There are very few perfectly competitive markets for example, and there is no auctioneer that was invented by Walras to solve the problem of how an equilibrium set of market clearing prices is determined (needed for the market efficiency hypothesis).
Fossil fuel energy is a depleting resource, perhaps letting the free market decide on its allocation on international markets is not wise from a national security perspective.
Free market absolutism is not always the wisest policy in my view.
Short video from a few months ago.
https://www.youtube.com/watch?v=M5qNnkLNSJw
The CNBC newstalkers are morons. But the guest is intelligent. Makes the point that LNG prices are likely to crash, not just from oversupply (which is baked in, is coming), but also the very real danger of “peace breaking out”. He sees the drops in LNG destination prices being steep enough to actually drive shutin of some US LNG. 🙁
P.s. Of course…if you had a crystal ball AND had built countercyclically (coming online in 2022) AND had kept spec volumes….you could have made a metric butt ton of money when EU gas prices were over $30/mmbtu! Of course you’d need a crystal ball and…two brass balls. I’m not suggesting anyone should have made that bet. But if you had? Cha ching!
Nony,
Not clear that the Ukraine problem will be resolved any time soon, it would be nice, but as they say if wishes were horses, beggars would ride.
Yeah…I’m not seeing peace “soon” either. But I also doubt the war and sanctions are humming along 20 years from now, also.
As a customer or a producer planning on EU LNG demand being high for 20 years in the future is very risky. “Pop” said the bubble. 😉
Nony,
I agree in 20 years things are likely to be resolved in Ukraine, and yes I agree the LNG export facilities seems like a very risky bet. It makes much more sense to just produce what US, Canada, and Mexico can consume and use pipelines to move it.
One of the better video overviews of the negative view of LNG.
https://www.youtube.com/watch?v=OivNxX8ffdc
Minutes 9 to 15, go in detail on the coming overbuild (supply side). Then a much longer discussion on issues in the demand side also.
Somehow the market DID absorb the last overbuild from 8 years ago. But he has concerns that this time it will be even worse, even longer until the market balances.
Mostly very sound economics although there were one or two boners. E.g. saying that oil oversupply hurts refiners (it doesn’t, to the opposite moderately). But mostly showed a brain.
Cautionary tale on an assumption that USGS estimates are always too low.
USGS assessment of Barnett Shale in 2015 has a mean TRR of 91 TCF with a 90% CI of 78 to 107 TCF, lets assume 75% of TRR is economic and that brings ERR to 68 TCF with a 90% CI of 58 to 80 TCF.
Link to assessment below
https://pubs.usgs.gov/fs/2015/3078/fs20153078.pdf
Research from BEG at UT Austin (Patzek and others) is reviewed at O&G Journal in September 2013 at link below
https://www.beg.utexas.edu/files/content/beg/research/shale/OGJ_SFSGAS_pt2.pdf
Mean URR based on the analysis is 45 TCF with low and high cases ranging from 27 to 64 TCF.
See chart linked below from paper and see table 6 on final page.
ogj barnett
Barnett Shale Gas output in TCF per year, 2000 to 2024, see chart linked below. Using Hubbert Linearization on the data suggests a URR of roughly 30 TCF for Barnett shale gas, this aligns well with the BEG low case (27 TCF) in previous comment.
barnett gas
I think you should be concerned about the USGS being too high AND too low. They don’t have a pipeline to God. And they do a VERY crude, simplistic methodology. And are often years and years in the past.
There is a LOT of structural uncertainty about resource estimates. Look at your 2018 Permian experience (whether that was your fault or USGS…the issue is with the ability to decide a future URR for decades). I think some humility about uncertainty is helpful. Who knows…maybe the “crazy high” Utica estimates work out. After all, if we go back to 2013, it was the craziest of crazy high estimates that were the closest.
And I’m not even saying to only think of upside exposure. Consider downside AND upside possibilities. There really is a lot of uncertainty. I warned you about that a decade ago.
Now, sure hopefully there is LESS uncertainty now than there was a decade ago. It would make sense. But still…why were we so unhumble a decade ago? Why didn’t we have wider error bars? Have we just moved the goalposts? Or did we learn something about humility when making peaker predictions?
Nony,
I have never claimed either clairvoyance or omnicience. I tend to present a range of guesses and state which I think will occur based on what I know at the time. Sometimes USGS estimates are in fact too low such as the older Marcellus estimates and perhaps the older Haynesville estimates. Often this is because formations where there was little production at the time were not assessed due to lack of data (no production from those formations at the time). There is always room to the up side as zero is a hard lower limit and infinity is the upper limit. I imagine we can agree that resources will fall in that range. Humble enough?
Took a quick look back at April 2015 (a bit more than a decade ago) https://oilpeakclimate.blogspot.com/2015/04/oil-shock-model-for-world-4100-gb.html
At that time for the World I had 3400 Gb for my best guess with a range of 3000 to 3800 Gb. I think it unlikely (less than a 5% probability) that World URR of C plus C will be outside of the interval from 2000 Gb to 4500 Gb, but could be wrong.
I also look at work by Patzek and others, not just the USGS.
We are always looking at past data, in most cases we can’t really make a good type curve estimate without 24 months of data and if we are looking at annual type curves we are 3 years behind.
I am working with data about 4 to 5 years old, it’s what I have to work with.
Something can be gleaned, analysis is always imperfect.
Another post from Oct 2013 exploring different scenarios in the ND Bakken/TF
https://oilpeakclimate.blogspot.com/2013/10/exploring-future-bakken-decrease-in.html
The scenarios range from 3.7 to 29 Gb for North Dakota Bakken/Three Forks, with a best guess of around 8.5 Gb, that’s a pretty wide range of uncertainty.
Nony,
I have lots of crazy high scenarios from the past that have not been close at all, here is an example from 2013 for ND Bakken/Three Forks with TRR of 29 Gb, similar to claims made by some at the time that the Bakken would produce at least 30 Gb. This scenario was not close at all to reality.
Looking back it seems the Continental estimate was 24 Gboe back in 2010, wells were about 80% crude and 20% NG back in those days so this would be about 20 Gb of C plus C. Continental in those days was claiming a well type with 518 kboe which translates to about 414 kbo for EUR for crude alone, tis is likely too high by about 38% back in 2010 though it may have been attained by 2018 or so. For the 48 thousand wells they expected to be drilled, at actual 2010 EUR this would be about 14.4 Gb, still a bit high for a mean guess, but perhaps close to the upper end of a 90% CI. For C plus C ERR.
old bak 29G
52% of Americans don’t have a passport.
Is that why this site hardly has any real discussion about oil production outside the USA USA USA.
Any idea how important want is going on in Russia is at the moment
A hundred times more than Taxas
I can assure you
Iver,
Feel free to fill us in, we have less data on the rest of the World and we cover OPEC and non-OPEC (besides the US) every month. I have travelled to Europe many times and once backpacked in North and West Africa with a trip through the Sahara when I was 21 (about 3 months). One of my children went to University for 4 years in the UK.
I agree what is happening in Russia is important, but have very limited information on their oil and gas industry.
Another thought on Russia vs US, based on 2024 output levels Russia produced 61 BCF/d of natural gas and the US produced 100 BCF/d, for C plus C Russia produced 10.2 Mbpd and the US produced 13.2 Mbpd. So bottom line both are important, but we have a lot of data from
https://www.eia.gov/
on US oil and natural gas, Russian data is far more limited, mostly from EIA, IEA, and OPEC.
Would love to learn more.
Iver
The big news coming out of Russia these days is that their refineries and crude export terminals are being bombed. Unfortunately that does not provide any info on Russian production and whether it is hurting their exports. Even if Russian exports are down, OPEC is offsetting that with their production increases. At the same time WTI price keeps falling.
https://www.youtube.com/watch?v=f4yhiAW9z9M
https://kyivindependent.com/much-oil-but-no-fuel-after-ukrainian-strikes-long-lines-at-russian-gas-stations/
https://nypost.com/2025/09/12/world-news/ukraine-strikes-key-russian-oil-terminal-in-overnight-attack/
Ovi
It’s true that there is no solid data about Russian output and exports.
It’s still remarkable that one of the world’s biggest oil industries is under massive and very public attack, but nobody seems to be panicking.
4 Oil Giants Stand Tall as Permian Basin Fuels U.S. Growth
The Permian Basin remains the powerhouse of U.S. oil production, fueling both growth and efficiency. With rising volumes, stronger technology, and proximity to Gulf Coast refineries, it anchors energy security. Companies with deep roots in the region — EOG Resources (EOG), ExxonMobil (XOM), Diamondback Energy (FANG) and Chevron (CVX) — are strategically placed to harness its potential, reinforcing their status as prime names for investors to track.
EOG Resources, ExxonMobil, Diamondback Energy and Chevron are among the key players to watch. These companies have extensive operations in the Permian and are well-equipped to capitalize on its potential.
https://ca.finance.yahoo.com/news/4-oil-giants-stand-tall-130000925.html
EOG burned about 2 billion in cash last quarter, XOM burned through $7.5 B, Fang had positive cash flow ($57 million), Chevron burned through 2.9 B in cash. All 4 had lower net income for the most recent quarter compared to the same quarter in 2024.
They may stand tall, but are not making much money, that article is hype. If oil prices continue to fall, income will fall and more cash will be burned.
I expect the Permian might grow by a bit less than 100 kb/d in 2025 (annual average compared to 2024 annual average) and will likely decline a bit in 2026.
I agree that article is fluffy. Can find a lot like it. About all it is saying is these are the big 4 in the Permian (without even giving percentage shares, without showing a correlation of size to success).
If you just want to see how concentrated the basins are and which operators have more share, I would look at the Novi webinar. It did a very nice job of showing how the Delaware remains much more fragmented than the Midland. (So, I guess the overall basin is sort of in between.)
I looked at the EOG statement of cash flows:
https://filecache.investorroom.com/mr5ir_eogresources2/424/2025%2006.30%2010-Q%20Publish.pdf (see page 7)
For last six months, not last quarter, EOG did have negative $1.9B of cash flow. Note that this was from a higher base, though, so the cash on hand is very similar to a year ago. (Far from any crisis.)
If you look what drove the negative cash flow, a lot of it was from lower net earnings (which I expect and agree with you is likely oil price related). They also did a half billion long term debt repayment this period (and not last year’s first 6 months). Dividends were similar. But there was also a much high accrual for taxes (almost 0.8 billion different than than last year’s first six months.)
Of course oil prices are way more important to these companies than how the Permian is doing (which is sort of “known”…it’s good…ish, but it’s expected performance).
For XOM and Chevron, they may be big in the Permian, but the Permian isn’t big in them. It’s a small fraction of each of their oil production. And they are integrated companies also. For EOG, it’s a bigger fraction (halfish?) of their production. FANG is a pure play (I think).
Nony,
There tends to be a focus on the Permian because all of US growth in oil output since 2015 has come from the Permian Basin (4.65 Mb/d increase for Permian from Jan 2015 to August 2025 and 4.26 Mb/d for US C plus C growth over same period.) I agree that Permian Basin is a small part of XOM and Chevron’s portfolio. Probably significant for other 2.
Even at the World level C plus C output increased by 4077 kb/d from Jan 2015 to June 2025 (last data point) while Permian Basin output increased by 4638 kb/d over the same period.
When the Permian begins to decline it might be a big deal and may start as early as 2026 for 12 month average output.
Agree prices of oil, NGL, and natural gas are very important for all oil and natural gas producers, along with input costs for labor, materials, and other services. The microeconomics is very straightforward.
On Russia:
The Trump administration announced that the precise coordinates of Russian oil and gas infrastructure–pipelines, gathering stations, compressors, refineries, loading docks–will be transmitted from the Pentagon to the Ukrainian intelligence service. Once the Ukrainians have enough long-range missiles to do the job, I think we can expect a dramatic reduction in Russian oil and gas exports, as wells as refined products (which are already running low in places).
Additionally, I always had the feeling that Exxon was the majordomo in Russia Far East, especially Sakhalin Island. Exxon took a 4.5 million-dollar hickey when the war began, by walking away. If I had to guess I’d suppose that the infrastructure is lagging already. Japan has an interest in Sakhalin II, and they’re capable, but I would imagine infill drilling has faltered.
It sounded like maybe Iver had some inside information on Russia. I’d like to hear it. He’s quite right: Russian production and exportation is of paramount importance–much more than the Permian, at least to the international scene. If I understood this plan correctly, it will eventually shut down much of Putin’s revenue stream. Of course, that will make him even more dangerous. Perhaps enough that he will break out the old tactical nuclear.
Come on, Iver, jump in here and give us the skinny on this thing. We’re all waiting.
Gerry
My point was that every post on this website regardless of title ends up talking about the bleeding Permian. Ovi always posts frack down one or up two on every single post. Why? Cos he knows nothing else?
My point also is no matter what happens with oil prices U.S. production will only go up or down by a couple of hundred thousand barrels per day next year.
What is happening in Russia is several levels of magnitude above that and those running this site should wake up and try and find and talk more about the most important thing going on globally regarding Oil and Gas.
The Ukrainian President has said his country will go all out to destroy Russian oil and gas infrastructure.
If Europe or the U.S. give Ukraine long range missiles, the Russian economy will implode. Putin knows this is is already threatening European countries.
All this is just slightly more important than the never ending comments on frac spreads. Some balance is needed.
Iver,
I agree Russia is important. Europeans are free to offer more important information in the comments that is energy related. Also you are welcome to find a better blog that has what you are looking for, if you don’t want to share the relevant information here.
I cannot create information that I do not have.
As I pointed out earlier, for the past decade the Permian Basin has increased C plus C output by more than 100% of the increase in World C plus C output. This is likely to end in 2025 while OPEC increases output to the limits of their spare capacity.
All of this points to the attack on the Russian oil industry being very important, but for Ukraine they see this as the only way to end the war. I tend to agree that shutting down the Russian oil industry may make it difficult financially for Russia to import more drones to attack Ukraine.
Maybe Putin decides to start negotiating in good faith.
In 2024 Total World net exports of crude and petroleum products was 41650 kb/d (Stat Rev World Energy data), Russia’s net exports pf crude and products was 7018 kb/d about 17% of the total, only Saudi Arabia had higher net exports (7235 kb/d). The top 5 net exporters were 59% of the total. Those nations were Saudi Arabia, Russia, UAE, Canada, and Iraq from highest to lowest. The US is actually the 7th largest net exporter of crude plus products at 3.5% (excluding the nation groupings that the Statistical Review of World Energy uses.)
Article on Ukrainian attacks on Russian refineries.
https://www.bbc.com/news/articles/czx020k4056o
The article points out that much of Russian exports are in the form of crude oil, though these exports bring less revenue per barrel than product exports. I would think targeting major port facilities where crude is loaded to cargo ships might slow Russian crude oil exports. Probably focusing on the Baltic oil terminals and those near the Black Sea and perhaps attacking the crude oil pipeline to connecting to the far east terminal would be the most effective approach to reducing Russian crude oil exports.
It is impossible for us Americans (or Canadians) to get a more complete insight into Russian oil and gas than what we read in the Wall Street Journal or the oil and gas journals, which is where I receive my information. You are exactly correct in that what is happening in Russia is potentially much more important than what is happening in the Permian. But these days, with Exxon out of RFE, it is even difficult to get reliable data on oil transport from Russia. You can get pricing from Platts or Argus but you need Vortexa to get any idea of shipping manifests, and since so much is transported by the Dark Fleet, none of that’s particularly relevant. The U.S. government (and probably all the NATO countries) are watching this and have good data, but it’s not to be had for us ordinary citizens. The same is true for Iran. Both Russia and Iran are under sanctions, but at least we have a handle on Iran because 90+% comes straight from Kharg Island, halfway up Aqaba. There’s obviously a lot of transshipment of both Russian and Iranian oil, so it’s hard to track it all.
But you’re right in that when (not if, not now that the Ukrainians have precise Russian infrastructure coordinates) Ukraine cuts loose with enough fire power, the world will literally wake up to a sizable hole in both Russian clean and dirty (crude and refined) exports. If an old pudknocker here in the U.S. can figure this out, I’m pretty sure President Zelenskyy has figured it out.
The broader picture is even more important. This is apt to collide with a drop in shale oil production. I know, I know, this is getting back to the Permian, primarily, but it will likely decline more precipitously than one might imagine. When you look at populations of wells, it’s an aging demographic out there in West Texas. For example, whole clusters of oil wells have matured into low pressure gas wells, with nowhere to go with the gas right now. And another cluster is heading into that sad category. We’re not talking about a few dozen, but tens of thousands. Looking back at history, when U.S. production began to decline on the 1970 Hubbert curve (drawn in 1956, mind you!), the decline was gradual, then faster, almost as though logarithmic. A philosopher said history always repeats itself twice, once as a tragedy, then as a farce. (We’re on the farce repeat.)
This all could be compounded by the fact that Saudi Arabia is using four times the number of rigs they used ten years ago. Call the increase workover rigs, which makes it especially pertinent, since that means trouble keeping the Saudi Red Queen on the treadmill. I’m not trying to be pessimistic, but a blind man could see that this—a multicentric decline on the global market—is coming much quicker than advertised.
I’m afraid this is as international as I can make it. I used to travel more, and had more connections, but now I have to get my “News of the World” by mail. But the mail keeps saying the same thing.: there’s a good likelihood that several sources of oil on the global market will decline at one time. As Mike Shellman keeps saying, this is a damn good time to refill the old SPR and preserve some of our precious resource. Because I also get the news on President Xi. Over the last few years he expanded his bunkers and is fully loaded on coal, oil and gas. Confucius say . . .
Dallas Fed Survey at link below
https://www.dallasfed.org/research/surveys/des/2025/2503
From Comments section of survey:
“Comments from Survey Respondents
Survey participants are given the opportunity to submit comments on current issues that may be affecting their businesses. Some comments have been edited for grammar and clarity. Comments from the Special Questions survey can be found below the special questions.
Exploration and production (E&P) firms
– There are a variety of issues affecting our business. First, excess in the global oil market is restraining oil prices near term. Second, there is continued uncertainty from OPEC+ unwinding production cuts. Third, trade and tariff changes and the resulting geopolitical tensions.
– Day to day changes to energy policy is no way for us to win as a country. Investors (rightly) avoid investing in energy (of all types, now) because of the volatility of underlying business results as well as the “stroke of pen” risk that the federal government wields as it relates to long duration energy developments. Life is long, and the sword being wielded against the renewables industry right now will likely boomerang back in 3.5 years against traditional energy which will find itself facing harsher methane penalties, permitting restrictions, crazy environmental reviews and other lawfare tactics.
-The administration is pushing for $40 per barrel crude oil, and with tariffs on foreign tubular goods, [input] prices are up, and drilling is going to disappear. The oil industry is once again going to lose valuable employees.
-The noise and chaos is deafening! Who wants to make a business decision in this unstable environment?
-The uncertainty from the administration’s policies has put a damper on all investment in the oilpatch. Those who can are running for the exits. Tobin’s q < 1.
-The U.S. shale business is broken. What was once the world’s most dynamic energy engine has been gutted by political hostility and economic ignorance. The previous administration vilified the industry, buried it in regulation and cheered the flight of capital under the environmental, social and governance banner. Wall Street and pension funds walked away, and even private equity shifted from fueling growth to engineering exits. Now the current administration is finishing the job. Guided by a U.S. Department of Energy that tells them what they want to hear instead of hard facts, they operate with little understanding of shale economics. Instead of supporting domestic production, they’ve effectively aligned with OPEC using supply tactics to push prices below economic thresholds, kneecapping U.S. producers in the process. The collapse of capital availability has fueled consolidation by the majors, pushing out independents and entrepreneurs who once defined the shale revolution. In their place, a handful of giants now dominate but at the cost of enormous job loss and the destruction of the innovative, risk-taking culture that made the U.S. shale industry great.
– The downward pressure on oil prices coupled with continued tightness in finding qualified labor in remote locations continues to pressure profitability and dividends.
– Commodity pricing seems impossible to predict with daily market swings over 5 percent up or down being normal for both natural gas and crude oil. We sell to spot pricing, so our near-term financial performance is unpredictable. There are too many lever movers at play at the same time in everyone's models zooming out at the macro level (inflation, tariffs, commodity oversupply both domestically and globally, domestic electricity demand growth from data center buildouts, liquefied natural gas (LNG) export demand), and it is no wonder the market is so volatile.
– Workover rigs hourly rate continue to increase, which affects all our repair and development costs.
– Because of global circumstances we think crude oil prices will stay low at the $60 per barrel level. Alternatively, because of an increase in the LNG market we feel that natural gas development and production will increase.
– Uncertainty, both domestically and offshore, have made it difficult to plan. Just in time inventory practices exacerbate planning and/or budgeting forecast processes, making it difficult to project future capital needs. Commodity pricing is extremely difficult, primarily due to geopolitical risk, and uncertainty as to whether this economy will flourish or be stagnant. Stagflation is back on horizon.
– The West Texas natural gas situation is awful! Oklahoma crude purchasers are increasingly adding additional "distribution" charges on each truckload of oil taken. Gas purchasers are increasing their current expense categories and adding new ones, creating total deducts in excess of 5x total severance taxes.
– A series of rate decreases will stimulate business activity and also consumer confidence. The cost of money hinders progress.
– California permitting issues added hundreds of thousands of dollars to new well permitting costs and dragged the ordeal out with delays amounting to years, thwarting developments. The internal state policies need drastic political and/or regulations reform. We own and operate a Federal Unit that has been in place since 1933. Our U.S. Bureau of Land Management agents have been responsive and supportive putting our project in a priority position with new permits for drilling program needs. Financing is still not readily available except for companies in the active horizontal shale developments in specific states and basins. We need more financing options to support independent operators. Costs are going up across the board.
– While crude prices have stabilized in the low-$60s per barrel, the expectation of higher prices is still present. Because of that, a stable price in the low-60s has increased uncertainty due to the expectation of low-60s well into 2026 if not beyond. Costs have been relatively flat and we're not seeing the efficiency gains that are being reported elsewhere in the Permian. With all of that, our expectation is to manage our lease expirations but not drill unnecessary wells in this price environment.
– OPEC overproduction is affecting our business. So is weak sanctions on Russia. U.S. production staying flat while non-U.S. and non-OPEC production is growing exacerbating the glut. The administration’s tariffs, particularly on steel and aluminum at fifty percent, are increasing our cost of business.
– Access to private capital remains challenging. Capital groups appear to be unsure of future pricing and profitability. Higher prices are needed to push perceived profits higher in order to engage capital groups to elect to invest at a higher level. Small operators are struggling to compete financially, and the larger corporations that have larger balance sheets to weather the current lull are better equipped to consolidate and grow their assets at a relative bargain.
– Lowering interest rates will have a positive affect on the oil and gas industry and the overall economy.
– We are confused as to effect of Saudi increases due to increases in storage. Crude oil prices are firm. Why?
– It is very tough to know where prices will go. It seems like we are opening new and larger markets with Japan, Korea, India and Europe but why aren't prices going up as a result?
– Lower commodity prices depress cash flow and make it more difficult to invest capital."
1. Overall, a lot of price whining. It’s not as bad as the farmers. But pretty similar. 🙂
2. Current price is down to $61. That’s down a bit from last few days (when survey was done), which was in the 62-64 range. I think. Sort of surprising, given some increased war jitters. Although one shouldn’t read too much into the little up and downs. The 5 or 10 or 20+ moves are the real story, not the small gyrations.
3. The price is actually deceptively bad. This is because of inflation. Especially in the early 2020s, but also just adding up over time. So if we correct back in 5 year increments. Starting with $62. (It’s $61 as I type this, but that’s a little low versus last few days, so I don’t want to overegg.)
Equivalent of $62 in AUG2025 dollars, backdated to AUG20XX dollars:
a. 2020: $49.74. Yep…that’s right. We ARE doing 13+ MM bopd, at LESS than $50 in 2020 terms. How’s that working out peak oilers!?
b. 2015: $45.61. Yep. Remember all the disbelief about the Permian from the liberal, Yankee (but I repeat myself) peak oilers?
c. 2010: $41.8. Yeah…what would the TODers think of 13+ MM bopd at this kind of price? TOD is dead. HA!
c. 2005: $37.59 (see above, TODers.)
d. 2000: $33.07. Yep…look at that production. And at that constant dollar level. Poor little peak oilers. Getting their butts kicked by reality. Hmm…wonder why ASPO and TOD died?!
Thank you, Dennis
We are exploring the lower boundaries of the oil price. With low capital costs, it is always the temptation to “go big” and bet on the future. The discipline to curtail output can not be on Saudi Arabia alone. More of the same; overinvestments, major players trying to control the market seems to be the mantra at the moment. Needless to say, technology is the big driver here making these low prices possible.
The Russia thing:
1. I would love to get a “for dummies” guide to oil and gas production in Russia. If done, I’m more interested in the actual production itself, rather than refining and midstream. Like the geography, reserves, unexplored areas, etc. And with more of a long term perspective than the U/R war. I just think it would give a good baseline. I admit that I want, is just my bias…but sharing it, FWIW. (Please if someone does this, do NOT make it a blizzard of field names and assumptions that we already all have the background.)
2. I believe there was a trope of Russia about to exhaust resource and start declining. Very similar to the sort of Saudi stuff you would see on TOD, while it operated. It would be very easy to just do a Google search and show all the wrong predictions (in the peaker direction, from the peaker side). [Note that there may have been high predictions also. I’m sure Dennis can sleuth them out…but it just amazed me how the peakers (supposedly objective and rational and science-y) were almost always wrong in a particular direction.
3. I remember several years ago, Ron Patterson challenging me to “put up or shut up” when I said he had a history of saying Russia was about to decline (which it didn’t). This was over at Peakoil.com. I went and scoured the net and found 20 different comments from Ron/Darwinian over several years prior, with him doomcasting Russian production. He had no reply to the long list. And even the other peaker commenters over there (remember I’m in a minority when I comment on blogs like this/that), said “da-yum!” I’m too tired to recreate it. And I can’t find the place where I did the work (was in response to a front page article on that site, not in the proper forums). But it happened. Trust me. 😉
And it’s mostly pouring down into China now I believe, then sent offshore. It’s not ‘Russian’ oil if it comes off a Chinese ship is it 🙂 India switching to buying oil in Yuan will certainly shake the tree. I believe the last one to pull that stunt was Saddam Hussein in 2000 (euros) and he got invaded for his trouble.
https://www.theguardian.com/business/2003/feb/16/iraq.theeuro
An update for US July Oil production has been posted.
https://peakoilbarrel.com/us-july-oil-production-another-new-high/