The EIA STEO was published recently, the estimate for World C+C output from September 2024 to December 2025 in the chart below is based on crude oil estimates in the STEO for World minus US C+C output and the trend in the ratio of the STEO crude estimates and C+C estimates from the EIA’s International Energy Statistics for World minus US C+C output for the most recent 48 months (September 2020 to August 2024).
In my view the estimate for World C+C annual output in 2025 (83.47 Mb/d) looks optimistic, I expect World C+C will average about 82.5 Mb/d in 2025 about 600 kb/d higher than the 2024 estimate, which appears reasonable.
The chart above shows how the STEO estimates for annual output have changed from Jan 2024 to December 2024. If we throw out the Jan 2024 estimate, which is significantly different from the other 10 estimates, the average is 83.79 Mb/d with a standard deviation of 197 kb/d. If we assume that the probability distribution is Gaussian then we expect 95% of the data would fall between 83.4 and 84.2 Mb/d. Note also that decisions by OPEC on future quotas have changed over the past 11 months and this affects the STEO estimate. The decision by OPEC to delay the future ramp up in output from Jan 2024 to April 2024 likely dropped the STEO estimate for December.
The Brent price has been revised lower by $2/b compared to last month’s STEO and the price of natural gas has been revised higher by 10 cents per MCF, the estimates for US crude oil output and US LNG exports are both unchanged from last month.
The chart above reflects the delay in OPEC output increases to later in 2025 and shows what the EIA expects for OPEC output in 2025, which is slightly below the OPEC targets for the second half of 2025.
Most of the 1.6 Mb/d increase in World liquids fuel output in 2025 is expected to come from countries that are not part of OPEC+.
US crude oil net imports are expected to fall below 2 Mb/d for the first time since 1971.
US Jet fuel stocks have been falling since mid 2024 after rising over most of the period starting in Jan 2022, Jet fuel stocks continue to decrease through 2025.
Falling natural gas stocks in 2025 result in generally increasing natural gas prices in 2025.
World crude stocks are expected to decrease in 2024 Q4 and 2025Q1 with a small stock build expected for 2025Q4.
The chart in the right panel above gives some indication of where the increases in liquid fuels in 2025 are coming from. The other non-OPEC increase is about 500 kb/d with about 130 kb/d coming from Europe, 50 kb/d from non-OPEC Middle East nations, 180 kb/d from non-OPEC Africa, and 70 kb/d from Asia and Oceania.
Most of the increase in liquids consumption in 2025 comes from non-OECD nations.
US Natural gas production remains relatively flat in 2025, especially when compared to 2022 and 2023.
Most of the increase in US tight oil output since 2021 has come from the Permian basin. Notice how flat Permian tight oil looks in 2024 for the EIA estimate above. Below I will suggest this is not a good estimate.
The chart above looks at all US L48 output excluding Gulf of Mexico (GOM), like tight oil most of the increase since Jan 2021 has come from the Permian Basin region (including conventional oil output from this region). Notice how the regional Permian estimate is less flat in 2024 than the tight oil estimate.
The chart above compares several estimates for the Permian Basin with two regional estimates (the higher two data sets) and two Permian tight oil estimates. The regional estimates compare the EIA STEO estimate for the Permian region with an estimate based on EIA State data for Texas and New Mexico and Permian basin and state level data from the RRC of Texas and the OCD in New Mexico, these estimates are nearly identical. The Permian tight oil estimates compare EIA data with Novilabs data from Jan 2022 to September 2023, from October 2023 to September 2024 I subtract the average difference between the RRC/OCD/EIA Regional estimate and the Novilabs data over the Jan 2022 to Sept 2023 period (493 kb/d) from the RRC/OCD/EIA regional estimate. The EIA leaves out several Permian formations from its tight oil estimate which should be included leading to an underestimate of Permian tight oil output.
Dennis,
Thank you very much for this article.
Am I reading it correctly for 2024 production: flat C+C, but 0.6 kbpd of liquids?
So all liquid growth is from NGL and biofuels?
Do they have a breakdown for total liquids: how much is C+C vs NGL vs biofuels?
Kdimitrov,
They give crude oil output and total liquids, my C plus C estimate is based on the trend of the ratio of crude to C plus C for World minus US, US C plus C is forecast by the EIA, but not for the World, no breakout of NGL and biofuels in the STEO at the World level.
If crude oil and condensate production would be between 70 and 75 million barrels per day by 2050, what would be the estimated production levels of natural gas liquids (NGLs) and biofuels under the best-case scenario?
Omar,
Not known, check the international Energy Outlook from EIA for one view or OPEC or IEA forecasts.
I want approximate numbers of NGLs + biofuels + refinery gain if the crude and condensate are between 70 – 75 mbd in 2050?
Omar,
Doubt there will be much change in biofuels from today, NGL is difficult to guess, it depends on natural gas output. An older model I did 9 years ago for natural gas has NGL about 100 kboe/d higher than 2024 in 2050, about 1.3% higher than 2024 (estimate of about 7738 kboe/d for World NGL in 2024). I haven’t revisited this estimate for some time so it is highly speculative.
Nelow is my current guess based on my C plus C scenario and the older natural gas and NGL estimate with NGL adjusted for lower energy content using barrels of oil equivalent.
Thank you so much
Omar,
Keep in mind that the probability that my scenario is accurate is 0%. For your 72.5 Mb/d estimate in 2050, NGL would add about 7.8 Mb/d so roughly 80 Mboe/d for C C NGL. According to Energy Intitute liquid biofuels production was roughly 1 Mboe/d in 2023. My guess is that it will be a similar level in 2050, if this is correct then total liquids output in 2050 would be about 81 Mboe/d in 2050 for your guess of 72.5 Mbo/d for C plus C in 2050.
Did the predictions of a oil glut pan out?
Jacob,
Oil prices are pretty low relative to 2010 to 2015 so in a sense yes the predictions of an oil glut have proven relatively accurate since 2016, with the exception of 2022 when the War in Ukraine caused prices to rise.
The Rig Report for the Week Ending December 27
– US Hz oil rigs were unchanged at 441. They are down 18 rigs from April 19 and are up 14 relative to their recent lowest count of 427 on July 24th. The rig count has remained in a very tight range between 427 and 442 since July.
– In New Mexico and Texas, the Permian rigs were unchanged at 94 and 193 respectively
– In New Mexico, Lea and Eddy were unchanged at 45 and 49 respectively
– In Texas, Midland and Martin were both were unchanged at 27 rigs
– Eagle Ford dropped 1 to 38
– NG Hz rigs were unchanged at 85
Frac Spread Report for the Week Ending December 27
The frac spread count decreased by 9 to 201. It is also down 39 from one year ago and down by 71 spreads since March 8.
The last time the frac spread count was close to 201 was March 6, 2021 when it was 200 and the frac spreads were rising coming out of Covid.
It is amazing how the frac spreads keep dropping and US production grows.
Dennis and Ovi:
Do either of you have any recent DUC data for the US shale basins?
SS
The only data we have comes from the DPR. That data was reported in the last US update and will be updated in the next one probably around Jan 3 or 4.
There is a lot of controversy around those numbers. In the Permian there are close to 875 DUCs. Mike used to claim there were no more than 100 DUCs.
I think it is a question of how one classifies DUCs. If one considers all the wells that have been drilled and the average time gap of 6 months between drilled and completed, I can see 800 to 900 as being in the ball park in the Permian. Some participants on this site might have been considering Dead DUCs, those that would never be completed. I can see those being in the 100 to 150 range.
Shallow sand,
See
https://www.eia.gov/outlooks/steo/data/browser/#/?v=32&f=M&s=0&start=201901&end=202512&map=&ctype=linechart&maptype=0&linechart=DUCSPM~DUCSEF~DUCSBK
This DUC estimate includes WIP wells which Mr Shellman excludes from his DUC estimate, though in reality the Permian has a monthly completion rate of about 480 wells per month and if we assume WIP is 6 months (480 times 6) it should be at least 2900 wells so the EIA estimate seems too low. Novi labs has much different estimates than the EIA (they are considerably higher), but we can no longer access that data.
Found an old chart from Novilabs and they had Permian Ducs around 3500 in May 2023. This would be about 7 months of WIP wells if it is 7 months from spud to first flow, which seems more reasonable than the EIA estimate recently of 1000 DUCs for the Permian Basin.. Most DUC counts include WIP.
Bottom line is that the EIA estimates are all we have these days since Novilabs stopped making any data available without paying 10k per year and the EIA DUC estimates, especially for the Permian basin are not very good.
Ovi: “It is amazing how the frac spreads keep dropping and US production grows.”
Tack on an extra lateral mile of rock facies to hydraulically fracture and this is what you get: stronger initial well production. But it would also appear that a cost in ultimate recovery could be suffered due to earlier and more severe decline in performance. Time will tell whether these three (and even four)-mile laterals is an overall plus, minus, or a draw.
In the early three-mile laterals there was far from an equivalent increase in production. It has been generally believed that this was due to earlier fissure and pore closure in the distal segment. Exxon engineers obviously think they can solve this by using a carrier fluid containing coked petroleum as a far-field diverter to settle into the dendritic distal fractures and prevent long-chain hydrocarbon molecules from plugging up fissures as the pressure drops. In fact, they think this can add 15-25% to well production.
This is going to be an interesting experiment. An increasing problem is that over a million gallons of water are needed to hydraulically fracture each long lateral, and it, along with produced water, has to be disposed somewhere. Many of the Permian disposal wells are over-pressured and costs of disposal are rising. Unless water re-use is revolutionized or oil and gas prices rise (or both), the extra gain from enhanced proppants and more stages could be overwhelmed by rising water-handling costs.
This can go on for quite a while. Long enough to make people start to doubt stark warnings about the shale basins peaking, with a rollover coming soon. It could even quite possibly go on long enough to give Mr. Trump his extra 3 mboepd. But eventually the basins (and even Exxon) will run out of room for 3-mile allocation wells, and possibly also water. In other words, this can’t go on forever.
Gerry,
Thank you, spot on in my view.
Gerry
I just became aware of 4 mile laterals in reporting North Dakota’s production in the upcoming US September oil production update.
Googling 4 mile laterals brought up this interesting tidbit: “For three-mile wells, Chord assumes the third mile is only 80% as productive as the first two miles, Brown said, with a 40% EUR uplift for a 50% longer lateral and 20% more drilling and completion costs.”
I wonder what the productivity of that last mile of the 4 mile lateral will be. If 50% increase yields 80% productivity, how much productivity will a 33% increase yield.
These laterals must initially act like a pressure equalizing channel. All of these random local isolated oil bearing spots must have slightly different internal pressures that would equalize once the frac occurs and oil starts to flow. If the pressure midway down the lateral happens to be higher than the last mile, it would take a while for the oil in the last mile to start to flow. It will be intersting to see how this extra mile works out.
XOM is also experimenting with 4 mile laterals: “Exxon Mobil plans to drill longer, more capital efficient wells in the Midland Basin after a major boost from the $60 billion Pioneer Natural Resources acquisition. Data shows that Exxon is a leading operator drilling 4-mile laterals in the Permian’s Delaware Basin.”
https://finance.yahoo.com/news/chord-energy-goes-long-bakken-160000502.html
https://www.hartenergy.com/exclusives/exxon-shale-exec-details-plans-pioneers-acreage-4-mile-laterals-209060
Ovi,
The longer laterals may be more cost and capital efficient, but overall URR per acre of formation are likely to be lower than with shorter laterals (say in the 7k to 10k region, rather than 20k). Bigger is not always better.
Evidently Stuart Staniford passed away recently.
https://www.linkedin.com/posts/alexlanstein_sad-news-to-share-with-the-fireeye-family-activity-7254663936036200448-ZnM3/
I was not able to find an obituary. But a little bit of online search shows that he had “met” an African woman online and eventually progressed to meeting physically and marrying. He traveled to Nigeria to do so (I think completed, not sure). Shortly after he returned, he died of malaria.
Almost sounds like a LARP, given the story, but I think there’s enough comments on the LI post, to show it is most likely true.
Thanks Nony,
The posts by Stuart Staniford at the Oil Drum are a big part of what got me interested in Peak Oil, sorry to hear of his passing. My thoughts and prayers go out to his loved ones.
The last peak oil post by Stuart at his blog Early Warning at the end of 2013.
https://earlywarn.blogspot.com/2013/12/oil-supply-update.html
Like many of us, I think he was an oil outsider that provided a fresh perspective.
“U.S. Shale Is Growing Old. That’s a Problem for Donald Trump’s Oil Plans.”
https://www.wsj.com/business/energy-oil/us-shale-trump-oil-policy-1a001e6c?st=dZxXsn&reflink=desktopwebshare_permalink
What a shocker – I thought the center of the earth was this gooey oil filled ball that was infinite in size…..
rgds
Vince
Dennis
I keep reading that WTI is in the $70/b range because a number of experts believe that there will be an oversupply of oil next year in the range of 300 kb/d to 500 kb/d. Looked at the OPEC supply demand scenario and they are not showing such an over supply.
Attached is a supply/demand chart from the current STEO. They are showing an average deficit of close to 94 kb/d. It will be interesting to see if WTI strengthens into the first 3 months of 2024 and OPEC can add barrels in April 2025.
Oil bulls and peak oilers (and there is substantial overlap of their circles in a Venn diagram) are recurrently surprised that OPEC is not “struggling to produce”, but instead is actively withholding barrels they could supply. Of course this is how a cartel works and OPEC is a well known cartel. But peak oilers are not the best at microeconomic analysis.
Net, net: the threat (even just the threat) of OPEC sending more barrels into the market tends to hurt future prices. And this is what the price and the term structure (getting cheaper for futures contracts further out) shows this sort of thinking from the market.
And of course, the term structure is not an infallible prediction. Just as the point spread for an NFL game is not infallible. But in both cases, we can see the market odds. What people putting money down, think. What the more likely outcome is. Then again, amateur oil analysts are not savvy at Bayesian thinking.
FYI, Staniford was one of the people pushing the Simmons-lite projections for Saudi Arabia. Here he is in 2007, talking about SA being in decline.
https://econbrowser.com/archives/2007/04/more_speculatio-2
Now, 17 years later and they are easily pumping more than they did then…when they were “in decline”. So much for another too early peak oiler TOD-type prediction. Amazing how often the peak oilers are wrong…and how consistently in one direction. Lather, rinse, repeat!