By Ovi
All of the Crude plus Condensate (C + C) production data for the US state charts comes from the EIAʼs Petroleum Supply monthly PSM which provides updated production information up to July 2025.
U.S. July oil production increased by 109 kb/d to 13,642 kb/d, another new high. Note that June was revised down by 47 kb/d from 13,580 kb/d to 13,533 kb/d. The largest increases came from Texas and New Mexico. The September STEO prediction for July production was 13,522 kb/d vs reported 13,642 kb/d, a 120 kb/d miss.
According to this Report, “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.”
So the Dallas Fed Energy Survey states oil production declined in the third quarter while the EIA reports it rose. Hmmmm.
The dark blue graph, taken from the September 2025 STEO, is the U.S. oil production forecast from August 2025 to December 2026. Output for December 2026 is expected to drop to 13,190 kb/d. From July 2025 to December 2026 U.S. oil production is expected to drop by 452 kb/d.
The light blue graph is the STEO’s projection for Onshore L48 output to December 2026. July’s Onshore L48 production rose by 94 kb/d to 11,292 kb/d. From July 2025 to December 2026 production is expected to decrease by 445 kb/d to 10,847 kb/d.
U.S. Oil Production Ranked by State
Listed above are the 10 US states with the largest oil production along with the Gulf of Mexico.
These 10 states accounted for 83.3% of all U.S. oil production out of a total production of 13,642 kb/d in July 2025. On a MoM basis, July oil production in these 10 states rose by 115 kb/d. On a YoY basis, US production increased by 430 kb/d with the biggest contributors being Texas and New Mexico.
State Oil Production Charts
July’s production increased by 87 kb/d to 5,802 kb/d according to the EIA.
Texas production has rebounded since the weather related January 2025 drop. July’s production is still 30 kb/d lower than October 2024. The point to note here is both the production projection and the EIA production are going in the same direction from January 2024 to June 2025. However for July the projection is down by 24 kb/d to 5,895 kb/d while the EIA is reporting an 87 kb/d increase 5,802 kb/d.
I am not the only one questioning the EIA’s Texas production according to this Article. “He says to get accurate numbers, look at the Texas Railroad Commission data. While he points out that July hasn’t adjusted, October 2024 was the peak, and from that peak to June 2025 there has been a 12% decline. Texas is the leading producer—as Texas goes, so goes the nation. Hence, he says that U.S. oil production is declining at a 12% rate from October 2024 through June 2025.” I don’t believe the 12% decline rate.
The red graph is a production projection using the June and July Texas RRC data. The projection trend follows the EIA’s production up to June but not for July. The projection is higher starting in February 2025 because of the cumulative effects of the MoM production increases starting betweenJune 2024 and July 2025.
The blue graph shows the average number of weekly rigs reported for each month shifted forward by 10 months. So the 276 rigs operating in July 2023 have been shifted forward to May 2024. From February 2024 to July 2024, the rig count dropped from 312 in time shifted February 2024 to 256 in July 2024. That drop of 56 rigs had no impact on production up to October 2024 but November was the first month when the impact of the rig drop on oil production started to show up along with fewer completions. The rising production after January 2025 is difficult to explain. The small decline in the projected production after April 2025 may be the first indication the drop in the rig count may be having an impact on oil production.
According to the EIA, New Mexico’s July production rose by 66 kb/d to 2,283 kb/d.
The blue graph is the preliminary July oil production provided by the New Mexico Oil Conservation Division (ODD). Next month when I will have two consecutive months of production a projected NM production will be reported.
In the last post the following was noted “It is difficult to explain the 107 kb/d June difference between the EIA data and the NM OCD”. It is even more difficult to explain the larger 173 kb/d July gap. See next chart.
This May NM production chart was posted in the US August update. Compare this May NM chart with latest NM July chart above between January 2024 to December 2024. Note how all of the green dots above the blue graph have collapsed to the blue line in the latest July chart. Those green dots reflect EIA’s over estimation of NM’s 2024 oil production.
May’s projected production of 2,133 kb/d used Lea’s and Eddy’s production as a proxy vs the EIA’s 914 survey to estimate the 2,199 kb/d. So the EIA agrees the NM results for 2024 are correct and then keeps on using their same procedure for 2025 and the production gap gets bigger.
This table taken from the latest comp-stat-oil sheet shows the May NM production data for the above chart from July 2024 to May 2025 in the added August Report Column. The difference column is the difference between the NM May projected production (August Report column) and the EIA Final column. Note how close the EIA final estimate is to the projected production from July 2024 to December 2024. The projection under estimates the final EIA/NM data by between 6 kb/d to 12 kb/d, i.e. close to 0.5%. The EIA’s 2025 914 Estimate’s have a much higher error. As noted above, the EIA’s July over production estimate now exceeds 150 kb/d.
Bottom line. The most recent NM OCD production data is close to final after two or three months.
More oil production information for a few Texas and New Mexico counties is reviewed in the special Permian section further down.
July’s output rose by 16 kb/d to 1,170 kb/d. Production is down 117 kb/d from the post pandemic peak of 1,287 kb/d.
The North Dakota Department of Mineral resources reported July production rose by 2 kb/d to 1,161 kb/d, which is close to the EIA’s estimate.
According to this Article, ND reached all-time high in producing wells in July.
“North Dakota’s producing wells were at an all-time high of 19,547 in July, according to the North Dakota Department of Mineral Resources.
“According to the report, the number of producing wells is up 38, month over month.
North Dakota produced more than 1.160 million barrels of oil a day or 35,987,222 barrels in July. There’s been a 0.19% increase in production from June to July. The majority of the oil production (97.5%) is from the Bakken/Three Forks formations and the other 2.5% is from non-Bakken/Three Forks.
According to the report, 32% of North Dakota’s production comes from McKenzie County. The top five counties (McKenzie, Williams, Dunn, Mountrail and Dunn) make up 96.4% of N.D. oil production.
In North Dakota, 27 rigs are actively working, up two since August and July.”
Alaskaʼs July output dropped by 65 kb/d to 357 kb/d while YoY production decreased by 51 kb/d. The EIA’s weekly July reports indicated that July production would drop close to the 350 kb/d level.
Alaska has recently brought new fields online to consistently have flat YoY and monthly production gains which have broken away from the earlier dropping production red trend lines.
In early 2026 the Alaska Picca field is expected to come online. At its peak, Pikka could produce up to 80 Mb/d from 45 wells. The production expected from these projects may be enough to flip Alaska oil production into a steady growth period.
Coloradoʼs July oil production rose by 11 kb/d to 454 kb/d.
The biggest oil producing county in Colorado is Weld County and its production has been added to the chart. The two graphs have been almost parallel since January 2024. Weld’s production rose by 12 kb/d in July to 371 kb/d.
Colorado began 2025 with 6 rigs in January and February and then dropped to 5 in March/April/May. In September the average weekly rig count rose to 9.
It should be noted that Colorado drillers are facing increasingly stricter environmental rules according to this Article which could be reducing drilling locations.
Oklahoma’s output in July dropped by 6 kb/d to 397 kb/d. Production remains below the post pandemic July 2020 high of 491 kb/d and is down by 56 kb/d since May 2023. Output entered a slow declining phase in June 2023 and now appears to be range bound around 400 kb/d ± 20 kb/d.
In May Oklahoma had 51 operational rigs. However by July the number had dropped to 41. In September 41 rigs were operating.
California’s overall declining production trend continues. July’s production dropped by 3 kb/d to 255 kb/d, a new low. YoY production dropped by 49 kb/d. The mid 2023 Spike is new as of July.
Wyoming’s oil production reached a post pandemic high in February 2024 and appears to have entered a plateau phase around 295 kb/d. July’s production dropped by 1 kb/d to 299 kb/d.
At the beginning of 2025 Wyoming had 14 operational rigs and they rose to 15 in May and June. The rig count In September dropped to 8..
July’s production decreased by 5 kb/d to 189 kb/d. Utah had 8 rigs operating from October 2024 through May 2025 but dropped to 6 in early June but returned to 8 in September..
Ohio’s July oil production increased by 15 kb/d to 151 kb/d. The most recent Baker Hughes rig report shows no oil rigs operating in Ohio. They have all been re-classified to NG rigs. During July, August and September Ohio had on average 10 NG rigs operating.
GOM production declined by 1 kb/d in July to 1,912 kb/d. August’s production is projected to decrease by further 32 kb/d to 1,880 kb/d.
The September 2025 STEO GOM projection has been added to this chart. It projects production in December 2026 will be 34 kb/d lower than July 2025 at 1,878 kb/d.
A Different Perspective on US Oil Production
Combined oil output for the Big Two states Texas and New Mexico.
July’s production in the Big Two states increased by a combined 153 kb/d to 8,085 kb/d, a new high. Clearly these two states were the drivers of US oil production growth up to October 2024. The rising trend has slowed since October 2024.
Oil Production by The Rest
July’s oil production by The Rest dropped by 59 kb/d to 3,207 kb/d and is 228 kb/d lower than November 2023.
Permian Basin Report for Main Counties and a District
This special monthly Permian section was added to the US report because of a range of views on whether Permian production will continue to grow or will peak over the next year or two. The issue was brought into focus many months back by two Goehring and Rozencwajg Reports and Report2 which indicated that a few of the biggest Permian oil producing counties were close to peaking or past peak.
A more recent report was issued and can be reviewed Here. In this report they state:
“For years now, we have outlined with what we hoped was clarity, and what we now submit was prescience, the view that U.S. shale oil, that great source of modern supply, could not grow forever. It would mature, crest, and begin its long descent. That moment, by our models and measures, has arrived: shale has plateaued, and 2024 appears to be its high-water mark. And yet, investor sentiment has scarcely been more downbeat.”
This section will focus on the four largest oil producing counties in the Permian, Lea, Eddy, Midland and Martin. It will track the oil and natural gas production and the associated Gas Oil Ratio (GOR) on a monthly basis. The data is taken from the state’s government agencies for Texas and New Mexico. Typically the data for the latest two or three months is not complete and is revised upward as companies submit their updated information. Note the natural gas production shown in the charts that is used to calculate the GOR is the gas coming from both the gas and oil wells.
Of particular interest will be the charts which plot oil production vs GOR for a county to see if a particular characteristic develops that indicates the field is close to entering or in the bubble point phase. While the GOR metric is best suited for characterizing individual wells, counties with closely spaced horizontal wells may display a behaviour similar to individual wells due to pressure cross talking . For further information on the bubble point and GOR, there are a few good thoughts on the intricacies of the GOR in an earlier POB comment and here. Also check this EIA topic on GOR.
New Mexico Permian
The rig counts in Lea and Eddy county have started to move in opposite directions but appear to be stabilizing at new levels.. However the overall total rig count in Lea and Eddy counties has remained in the same range between 80 and 84 rigs. In the week ending October 3, the rig count was unchanged at 83 and down 11 from the January 2025 count of 94.
Eddy county rigs stabilized close to 45 in May but then began a slow drop and hit the current and recent low of 32 at the end of August. Eddy added 4 in the last week of September to 37. Lea county, starting in late June, added 12 rigs to 48 by late August. At the beginning of October the rig count has dropped by 2 to 46. What is driving the increased drilling activity in Lea County?
New Mexico Permian
Lea County’s oil production entered a plateau phase in May 2024 at 1,203 kb/d and the plateau continues to June 2025. July’s projected output dropped by 45 kb/d to 1,146 kb/d. Could July be the first sign that Lea County may be entering its declining phase. Preliminary July data from New Mexico’s Oil Conservation Division (OCD) indicates Lea County’s oil production dropped by 46 kb/d to 1,146 kb/d. There is virtually no gap between July’s preliminary data and the projected data, which indicates Lea’s OCD data is essentially fully reported.
Production has been essentially flat since May 2024 as the rig count fell and rose. July’s projected production drop may be the first indication/clue the overall dropping rig count has started to impact oil production.
The dropping rig count starting in time shifted June 2025 may be a contributing factor in the July production drop. Will Lea county production drop in August or continue on a lower plateau?
The blue graph shows the average number of weekly rigs operating during a given month as taken from the weekly rig data. The rig graph has been shifted forward by 8 months. So the 64 Rigs/wk operating in August 2023 have been time shifted forward to April 2024 to show the possible correlation and time delay between rig count, completion and oil production.
Note that rig counts are being used to project production as opposed to completions because very few extra DUCs are being completed at this time.
After much zigging and zagging, oil production in Lea county stabilized just below 1,100 kb/d in early 2023. Once production reached a new high in January 2023, production appeared to be on a plateau while the GOR started to increase rapidly to the right and first entered the bubble point phase in July 2023.
Since July 2023 Lea County’s production continued to increase as the GOR remained within a second semi-bounded region. This may indicate that additional production was coming from a new field/zone since the GOR’s behaviour since August 2023 to March 2024 time frame appears once again to be in a second semi bounded GOR phase accompanied with rising production.
The GOR moved out of the second semi-bounded GOR region in April 2024 and production hit a new high of 1,203 kb/d in May 2024. From July 2024 to May 2025 the GOR was range bound between 3.35 and 3.45 but June’s and July’s GOR hit new highs of 3.62 and 3.87 respectively while preliminary production dropped.
This zigging and zagging GOR pattern within a semi-bounded GOR while oil production increases to some stable level and then moves out to a higher GOR to the right has shown up in a number of counties. See a few additional cases below. The rising GOR to new highs in Lea county is another indicator that production is close to entering its declining phase.
July’s projected oil production increased by 30 kb/d to 915 kb/d. Also preliminary production from the NM OCD increased by 30 kb/d to 928 kb/d. Eddy county’s month over month production updates are very few and small and primarily occur in the last three or four months which indicates their preliminary production is very close to final. This is indicated by the red graph covering most of the green graph, i.e. there is little separation between the two graphs except for the last few months.
Eddy County’s recent oil production rise and fall is related to the rise and fall in the rig count. From May 2024 to November 2024, production rose from 757 kb/d to 905 kb/d, an increase of 148 kb/d, while essentially paralleling the increasing rig count. Over that same time shifted rig period, 14 to 15 rigs were added to Eddy County as production rose. Was a new Tier 1 region/zone discovered to attract such a large increase in the rig count?
The blue graph shows the average number of weekly rigs operating during a given month as taken from the above weekly drilling chart. The rig graph has been shifted forward by 8 months to roughly coincide with the increase in the production graph starting in November 2023.
Clearly the production rise up to November 2024 is closely associated with the rise in the rig count and associated well completions delayed by roughly eight months. The rising July production might be linked to the rising time shifted rig count in July and August
The Eddy county GOR pattern is similar to Lea county except that Eddy broke out from the first semi bounded range earlier and then added a second wider semi-bounded GOR phase. For July New Mexico’s Oil Conservation Division (OCD) reported oil production increased to 928 kb/d while the GOR stayed within the second Semi-bounded GOR range.
Texas Permian
The rig count in both Midland and Martin counties started to drop in early August.
The Midland county rig count dropped to 17 rigs at the end of July and then added 6 to 24 in the first week of August before dropping back to 19 at the end of September and first week in August.
Martin county’s rig count has been slowly dropping since March 7 high of 29 rigs. July and August saw continuing drops. The September and October rig counts dropped to a new recent low of 17.
Oil Production in Texas Counties
July’s projected production rose by 4 kb/d to 658 kb/d. However I think July’s projected production data looks optimistic because June’s production rose by 41 kb/d to 654 kb/d relative to last month’s report. July’s increment of 4 kb/d appears to be correct. Note how May’s and June’s preliminary production, green graph, are essentially flat. I think a more realistic projection for June and July production is in the 625 kb/d to 635 kb/d range.
The orange and green graphs show oil production for Midland County as reported by the Texas RRC for June and July. The red graph uses the June and July data to project production as it would look after being updated over many months.
The blue graph shows the average number of weekly rigs operating during a given month as taken from the weekly drilling chart. The rig graph has been shifted forward by 12 months to better align with production. So the average 34.5 Rigs/wk operating in July 2023 have been moved forward to July 2024 to show the possible correlation and time delay between rig count, completions and oil production.
The 12 month rig time shift is much larger than the typical six to eight months used in other counties. It is not clear why there should be such a difference. If the twelve month shift in the rig count is approximately correct in that oil production can be tied to the rig count, oil production in Midland county should continue falling up to July 2025. The preliminary production fell by 35 kb/d but the projection didn’t.
For July the Midland GOR ratio rose to 4.39 from 4.25 in June while reported preliminary oil production dropped by 37 kb/d to 581 kb/d.
With Midland county into the bubble point phase, oil production and the GOR stayed within a narrow range outside of the initial Semi-Bounded GOR region from March 2024 to March 2025. However the April, May, June and July 2025 GORs have broken out to new highs.
The oil production and GOR data shown in this chart are based on the RRC’s July production report. Note that while the last few months are subject to revisions, the January 2024 to April 2024 production data has been steady for a number of months.
Martin county’s projected July oil production dropped by 21 kb/d to 683 kb/d. The July preliminary production data along with the MoM updates look normal but Martin’s projected production estimate is optimistic because the month over month updates start in February 2024, a little further back than in recent updates. The projected production increase starting January 2025 is real but then peaks in April before starting a new declining trend. The more significant part of the projection is the last four months which shows production fell from 739 kb/d by 56 kb/d to 683 kb/d. A more realistic production projection for July would be in the 650 kb/d to 660 kb/d range. Hopefully this will be clarified next month.
The red graph is a projection for oil production as it would look after being updated over many months. This projection is based on a methodology that uses preliminary June and July production data. The green graph shows the updated oil production reported by the Texas RRC for July and note that July itself is 20 kb/d lower than June’s preliminary production. Production since May might have begun to track the time shifted rig chart.
The orange and green graphs show production for Martin County as reported by the Texas RRC for June and July. The blue rig graph time shifts the rig count ahead by 6 months.
Martin county’s oil production after November 2022 increased and at the same time drifted to slightly higher GORs within the semi bounded range. However the June 2024 GOR saw its first move out of the semi bounded region. The RRC’s preliminary July 2025 production for Martin County shows a 35 kb/d decrease in production accompanied by an increase in the GOR to 3.14, a new high.
Martin county has the lowest semi-bounded GOR boundary of the four counties at a GOR of close to 2.60. The GOR is now clearly out of the semi-bounded region. Martin County has now entered the bubble point phase that should result in oil production possibly entering a slowly declining phase.
This chart shows the total oil production from the four largest Permian counties. Assuming current Permian production is close to 6,400 kb/d, these four counties account for 53% of the total. July’s projected production decreased by 31 kb/d to 3,403 kb/d and is the fourth consecutive month showing declining production. Another indicator for dropping production and possibly a stronger one is the 88 kb/d drop in the preliminary July production, which appears to be slightly above recent levels.
The June and July initial production data are shown in the orange and green graphs respectively. The red graph uses the June and July production data to project a more realistic estimate for the final updated July production.
Findings
– The preliminary July production data for New Mexico was good. Texas county data was generally good.
– The production charts for the four largest Permian County’s appear to be in different phases of their production life. Of the four, one NM Permian county continues in its plateau phase while the other one may be entering its declining phase. The two Texas counties may have also entered their declining phase. Taking into consideration the price for a barrel WTI is stuck in the low $60s, the rig and frac spread counts continue to bounce around their recent lows, when taken all together these considerations all point to peak production occurring in the onshore lower 48 within the next three to four months.
– Lea county entered its plateau phase in May 2024. While oil production is not following the rig count graph directly, the dropping rig count is resulting in Lea production currently being in a steady flat plateau phase. However July had a 49 kb/d production drop along with an increase in the GOR to a record 3.87 which is another indicator of an upcoming declining phase..
– Eddy county’s production hit a new high in March 2025 but had a big drop in April while July saw an increase, possibly signalling the beginning of a plateau phase at a lower production level.
– Midland county’s production has been decreasing since November 2024. July’s projected production increase may be associated with under reporting of last month’s June production. The addition of six new rigs to Midland county in real August 2025 is an unexpected surprise and makes one wonder what it implies going forward.
– Martin county’s projected production has been affected by revisions to previous months. However I think the increasing production up to April is real along with the decline since then.
Texas District 8
The District 8 production chart is signalling it’s in its plateau phase which appears to have started in November 2023 at 3,604 kb/d.
The projected July production indicates that production may have peaked in April 2025 at close to 3,662 kb/d. Since then projected production has wandered around 3,600 kb/d. July saw an increase of 34 kb/d to3,622 kb/d.
While revisions in the production chart affect the projection, it does not affect the GOR.
Plotting an oil production vs GOR graph for a district may be a bit of a stretch. Regardless here it is and it seems to indicate many District 8 counties may well be into the bubble point as the July GOR increased to a record 4.59 from 4.48 in June..
Oil Production and GOR Charts for Three of the Next Larger Texas Oil Counties
Texas July data appears to be better than the June data but the projections may be a slightly optimistic.
July’s projected oil production for Reeves county rose by 13 kb/d to 506 kb/d. The production projection is reasonably close up to February 2025 but slightly optimistic after that. It does appear that Reeves is in its plateau phase. Reeves county is ranked as #3 for oil production in Texas, after Midland and Martin counties.
Reeves county peaked in May 2024 at 526 kb/d and production dropped up to January 2025. The GOR chart indicates Reeves County initially entered the bubble point phase in January 2025 and then reversed back into the Semi-Bounded region. July’s GOR is 7.33 and at a record high.
Reeves county GOR is high because it is the number one Texas county ranked by gas production. The current C + C production is equally split between crude and condensate.
In Real June, 29 rigs were operational in Reeves. By late September the rig count had dropped by 8 to 21.
Loving’s projected production rose by 13 kb/d to 505 kb/d in July. Loving production first peaked at 506 kb/d in November 2024, when it entered its plateau phase. For June, the GOR increased to 4.32, a new high.
While Loving had 19 operational rigs in real June, they jumped by 3 to 22 in real September. Loving has had roughly 20 rigs operating all year.
Upton entered its plateau phase in September 2024. July’s projected production rose by 6 kb/d to 304 kb/d. Upton’s oil production does not appear to have entered the bubble phase as of July. Upton’s rig chart has been time shifted forward by six months.
Upton began the year with 13 rigs. In real September, 17 rigs were operating.
Drilling Productivity Report
The Drilling Productivity Report (DPR) uses recent data on the total number of drilling rigs in operation along with estimates of drilling productivity and estimated changes in production from existing oil wells to provide estimated changes in oil production for the principal tight oil regions. The new DPR report in the STEO provides production up to August 2025. The report also projects output to December 2026 for a number of basins. The DUC charts and Drilled Wells charts are also updated to August???? 2025.
The EIA’s September STEO/DPR report shows Permian August output dropped by 8 kb/d to 6,613 kb/d. SEptemerb is expected to drop by 6 kb/d to 6.607 kb/d. From September 2025 to December 2026 output is expected to drop by 236 kb/d to 6,371 kb/d. Note that December 2026 production has been revised down by 43 kb/d from 6,414 kb/d to 6,371 kb/d.
Production from new wells and legacy decline, right scale, have been added to this chart to show the difference between new production and legacy decline.
August’s output in the Eagle Ford basin increased by 2 kb/d to 1,097 kb/d. September’s 2025 production is forecast to drop by 1 kb/d to 1,097 kb/d.
Output in December 2026 expected to be 1,082 kb/d, a decrease of 17 kb/d from the previous report of 1,099 kb/d.
The DPR/STEO reported that Bakken August output dropped by 6 kb/d to 1,190 kb/d. September production is expected to increase by 7 kb/d to 1,197 kb/d. The STEO/DPR projection, red markers, shows output rising up to January 2025 before dropping to 1,185 kb/d in December 2026.
This chart plots the combined production from the three main LTO regions. For August output decreased by 12 kb/d to 8,900 kb/d. Production for December 2026 is forecast to be 8,638 kb/d, a downward revision of 43 kb/d from the previous report.
DUCs and Drilled Well
The number of DUCs available for completion in the Permian and the three major DPR regions has returned to a dropping trend. August’s DUC count for the three basins dropped by 33 to 1,556. In the Permian the DUC count dropped by 21 to 977.
In the three primary regions, a total of 619 wells were completed in August, unchanged from July. There were 586 wells drilled in August, down 9 from July. For comparison, In January 2023, 722 wells were drilled.
In the Permian, the monthly drilling rates have begun to drop.
In August 2025, 445 wells were completed and 424 new wells were drilled. This is the seventh month in a row in which the number wells drilled has dropped
107 responses to “US July Oil Production Another New High”
Ah…Ovi, Ovi, Ovi. Still holding out hope for your Dean Fantazani-like views on EIA versus RRC and NM version of RRC. I remember well the peak oilers and price bulls being in denial in late 2017. Look how that worked out!
Anoymous,
You can’t trust EIA….
Nony, Nony, Nony
I got NM 2024 right within 0.5%. Let’s return to this discussion a few months from now.
Texas and New Mexico 914 estimates vs state data from Jan 2015 to March 2024 (final date when EIA final estimate uses state data for both TX and NM). The average for the 914 for all months is 99% of the state data, so a bit lower on average than the final state data.
Click on link below to see chart.
914 v state 2510
Hello
So the Texas EIA 2024 numbers are still higher than Texas RRC data. Are the EIA numbers now complete for 2024 or can there still be revisions? I guess there should not be any more that kind of updates to RRC data that would bring them close to EIA numbers. Would it then be the case that EIA and Texas RRC have different numbers for Texas 2024 production?
RRC updates for 24+ months, but is pretty close after 18 months. DEC2024 is less than a year ago, so it’s not surprising that the annual 2024 figures will differ. Still some upward RRC revisions in the pipeline.
This is an old chart, but shows the RRC pattern of revisions:
https://www.eia.gov/todayinenergy/images/2015.07.10/chart2.png
Juha,
The EIA will update its final estimate to match the RRC data again in August 2026, probably through Feb 2025, the data I showed compared the EIA 914 estimate (which is not adjusted except the most recent 2 or 3 months) with the most recent state data from Texas and New Mexico, the match is quite good and when averaged over the period is within 1% (on average the EIA 914 estimate has been 1% lower than the final state data not higher as you suggest).
Dennis
I meant the Texas RRC data in Ovi’s Texas graph (Actual July RRC), for many months in 2024 it is still below the EIA data. Is it possible there becomes such big updates to RRC data for 2024 that it would match the EIA data. For now the updates seems to be small ones for months that are more than 6 months back.
For New Mexico, Ovi showed that EIA corrected (in August, I guess) the 2024 data to match the state data. and the graphs (lines) are aligned now.
Juha,
In August 2025 the EIA updated its final estimate to the RRC state data from March 2024 (this is done once each year in August so it will happen again in August 2026). It takes 18 to 24 months for the RRC data to be complete.
Chart linked below compares RRC data from October 2024 with October 2025.
rrc data 2510
Difference between Oct 2025 and Oct 2024 TX RRC data for C plus C. Chart is Oct 2025 C plus C minus Oct 2024 C plus C. Also found the comp-stat file for oil from Oct 2024 on my computer, in chart below the EIA Final estimate is used to find the difference between RRC Oct 2025 data and Oct 2024 estimates by RRC and EIA. To my eye, the EIA looks quite a bit better over the last 12 months of the October 2024 estimates.
Note that Ovi’s estimate for Texas output in October 2024 was much closer than the EIA estimate (only 10 kb/d too low vs 61 kb/d too high for the EIA estimate), so Ovi’s method looks like it is more accurate.
rrc+eia diff 2510
Waha is at -$9. That’s right. NEGATIVE nine!
https://naturalgasintel.com/data-snapshot/daily/WTXWAHA/
Let my people flare!
From EIA
https://www.eia.gov/naturalgas/weekly/
Excerpt:
“The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell 98 cents this report week, from -$1.52/MMBtu last Wednesday to -$2.50/MMBtu yesterday. The Waha Hub set a record-low average price for the month of September, with -$0.64/MMBtu, surpassing last year’s record low of $0.03/MMBtu. Out of 188 trading days this year, the Waha Hub recorded 30 days of negative natural gas prices, or 16%. September accounted for 14 of these days, nearly half of the total, as recent force majeure and maintenance events have limited pipeline capacity and producer takeaway options. “
Thank you Ovi for your refined work. So, if there is not any December surprise, the US have peaked. Interesting times lay ahead. The US will no longer outweigh the decline of the rest of the world, while the west relentlessly attempts to cut Russian oil exports. Are they betting on Guayana? Oh, I forgot, it’s another trouble spot …
Things could become very tight, when Europe intents to get out of its stagnation. Fortunately, they do not want to grow, but to wage war (sarcasm).
Westexasfanclub
Thanks, much appreciated.
“Let my people flare.”
My industry is not your people; my nation is not “your” people. Flaring valuable associated gas is the height of conservational and environmental stupidity in America; in your specific case, Annoying, simply another means to draw attention to yourself when you make stupid comments like that. The stupider your comments, the more obviously aggravating they are to many and the more people pay attention to you. I feel sorry for you; you’ve got nothing to offer than…trying to piss people off.
You have aggravated people on social media for 13 years or more, I recall. You do no work of your own, are a cut and paste, quote-with-no-quotes, pseudo ANALyst that knows nothing other than what you read on the internet. You like to insult people. I don’t know why people bother with you.
The Energy Inaccuracy Administration does not do oil and natural gas accounting in Texas; the TRRC and Texas Comptroller’s office does. In the end Texas knows what Texas does and the books balance. If you can’t wait for the facts, read a book. Clean the rain gutters. Get out of the basement.
On another matter, Americans think they are entitled to know everything about everything. We are not. In America we do not even know about American oil because of all the NON-GAPP lying on SEC filings and exaggerated reserve reporting’s.
Russian oil does not belong to America, it belongs to Russia…and China. East against the West. There is nothing more important to Americans, and to all of North America and the West, than understanding what is left in America and how much it is going to cost. The comment about Russian oil being more important than Taxes oil is stupid. Permian Basin HZ tight oil has been the ONLY source of oil production growth in the entire world the past decade.
Annoying, not very respectfully, your fear of “peak oil” rhetoric is actually counter productive to the hydrocarbon future of my country. You are distracting from the truth. Nobody knows the future of oil and gas; its hard to see down there in the dark. If you think you do, or have some special insight, you don’t. Diddy.
Mike Shellman
I think Anonymous might have been being sarcastic when he wrote “Let my people flare”.
the hydrocarbon future of my country
While we’re at it, it’s not your country and hydrocarbons might not be the future.
I agree Mr Shellman that flaring is not smart policy. I also agree the EIA forecasts seem very optimistic, though the data is not that bad in my view.
Shale gas scenario (my best guess using USGS and Patzek analysis) compared to AEO reference case for shale gas at link below, I assume a linear decline over 20 years from the 2050 level for the AEO reference case to get the URR, also convert dry to marketed gas using ratio of 1.1 wet gas to 1.o for dry gas. My model uses wet gas as that is how natural gas reserves are reported, also USGS and Patzek analyses also use wet gas (aka marketed gas).
shale gas2510
The EIA;s AEO 2025 Reference Case is compared with my medium tight oil Scenario, which assumes WTI in the $70-$80/b range and NG about $3/MCF (future prices are impossible to predict accurately, if prices are higher output might be somewhat higher and if prices are lower output may be lower. There are innumerable variables, some known, and some unknown which makes uncertainty very large. Potentially output could be half as large or 2 times as large (in terms of URR) as my best guess. Scenarios at link below.
tight2510
AEO 2025 tight oil scenarios for reference case, low oil price and high oil price cases have URRs of 140 Gb, 104 Gb, and 169 Gb respectively, these are all unrealistically optimistic in my view. The low and high resource cases have URRs of 90 Gb and 180 Gb for tight oil, My best guess is more in line with the low resource case in terms of URR (around 88 Gb for my medium case with low and high cases having URR of 59 Gb and 132 Gb).
chart(110)
The US tight oil reserves plus cumulative production at the end of 2023 was about 53 Gb (26 Gb of reserves). My mid-case scenario for US tight oil is about 88 Gb which suggests about 35 Gb of undiscovered ERR. If we use a negative exponential probability distribution with mean and standard deviation equal to 35 Gb, the mean ERR is 88 Gb with a 90% CI of 55 to 158 Gb and a 75% CI of 58 to 126 Gb.
Cumulative probability for negative exponential probability distribution for US tight oil, assumes mean undiscovered resources have a mean of 37 Gb with standard deviation of 37 Gb. Mean URR is 88 Gb and median URR is 77 Gb (F50). A 63% probability the URR will be less than mean and 37% probability URR will be larger than mean.
90% CI is 53 Gb to 162 Gb
80% CI is 55 Gb to 136 Gb
70% CI is 57 Gb to 121 Gb
60% CI is 59 Gb to 110 Gb
50% CI is 62 Gb to 102 Gb
40% CI is 64 Gb to 95 Gb
The 40% CI also suggests a 70% probability that US tight oil URR will be more than 64 Gb and a 70% probability that US tight oil URR will be less than 95 Gb.
The AEO 2025 reference scenario has a US tight oil URR of 139 Gb. For the probability distribution shown there would be a 91% probability that the URR will be less than the AEO reference case and about a 9% probability that the URR would be larger.
Link below has cumulative probability chart.
max ent tight
Rig Report for the Week Ending October 3
The rig count drop that started in early April when 450 rigs were operating and rebounded over the past few weeks dropped by 1 this week.
– US Hz oil rigs dropped 1 to 374, down 76 since April 2025 when it was 450. The rig count is down 17% since April.
– New Mexico Permian was unchanged at 83 while Texas dropped 2 rigs to 189.
– Texas Permian dropped by 1 to 147. Midland and Martin were unchanged at 19 and 17. Upton county was down by 1 rig to 17.
– In New Mexico Eddy and Lea were unchanged at 37 and 46. respectively.
– Eagle Ford dropped 1 to 33.
– NG Hz rigs dropped by 1 to 103.
A Rig
Frac Spread Report for the Week Ending October 26
The frac spread count was unchanged at 179. From one year ago, it is down by 57 spreads and down by 36 since March 28.
A Frac
Why haven’t US authorities open up licensing for exploring federal waters other than GoM? Huge parts if the East Coast have potential for oil and gas production.
Petroslurp,
Many east coast states are not in favor of offshore drilling, not clear there is a lot of interest from E&P companies.
I agree with Dennis. There were lease sales and around 50 wells drilled along the offshore east coast back in the 70s and 80s and there was not a significant discovery made. The folks in these states never were really in favor of drilling as well.
I would love to see some new lease sales with new seismic, and ultimately some wells get drilled, but I think the likelihood is very, very small. The GOM will continue to have more and more lease sales to the accompaniment of much happy talk and bluster from the Trump administration about “unleashing US energy”. If they really wanted to unleash US energy, find ways to open up the east coast.
Bob,
Do you think there is much to be found on the East Coast of North America? I would think if oil companies really pushed for this that Trump would oblige. You of course would know much more than me, but may be uncomfortable revealing all that you know due to NDAs.
I actually worked on several of those rigs off the New Jersey coast in the late 70s.
As usual, the companies were pretty close mouthed regarding the results, but there were reports of numerous gas shows from the returns.
There is scarcely any current need for more offshore US natgas production.
Oil?
That could be a whole different ballgame.
Well…it’s incredibly likely there’s a lot of oil to be discovered in Alaska. And that is restricted by the keep it in the ground liberals.
If there’s nothing to be found on the East Coast, fine. You all can be happy with no production. But let the industry try.
Bob,
Maybe Trump could make a deal with Democrats to open up Federal waters for Off shore Wind in exchange for more lease sales for oil and gas exploration in East Coast Federal Waters. Given the lack of discovery in 70s and 80s maybe there is not much interest from E&P companies, but seismic technology has improved in the past 40 years so maybe there is something out there.
With the current administration objecting to “windmills” because they look ugly from a golf course, it could be that they think oil rigs are ugly too.
Looking at Permian Horizontal oil rigs shifted forward by 8 months to account for lag from spud and first flow (left vertical axis) compared with Permian basin tight oil output (right vertical scale). It looks like if completions follow the rig count that we would expect Permian output might start to fall in December 2025.
permian rigs and output
A longer term chart of Permian horizontal oil rigs and output shows less of a relationship, though perhaps in 2023 and 2024 there was a draw down of DUC inventory which might have kept output up. Output right axis (Mb/d) and HOR count on left axis
permian rigs v output
On the global price of oil:
The story of year 2025 may well be collapse of the Russian oil and gas industry, from wellhead to refinery, including export loading docks. In his astonishing confidence that domestic oil will keep growing at lower-than-breakeven prices the American president has overlooked a most important principle: the base price for a barrel of oil may equilibrate around the globe.
In today’s WSJ, an article emphasized that Saudi Arabia had bent to Trump’s demands that they lower the price of a barrel of crude oil. They did so by pumping more crude, trying to reclaim lost market share. The article goes on to point out that Trump’s family and businesses had long cultivated ties to MbS. But later in the article comes the shocker: while the lifting expense per barrel of oil in the KSA is only about ten bucks, the breakeven price to maintain their quasi-welfare state is a whopping $92/bo. That is just about exactly on par with the breakeven cost of lifting a barrel of LTO out of the shale basins, if you (appropriately) factor in debt repayment and ultimate P&A costs.
Russia has a totally different problem, though a similar economic reality may be in the offing. Russia brings up a lot of sour oil, which must be blended to produce the much ballyhooed Urals Blend. Over the decades Europe became comfortable running that particular blend—with its unique potion of mineral contaminants—through her refineries, or as commonly, buying refined products from Russia. And then Putin went off the rails. The inept Russian military has thrown hundreds of thousands of men into the meat grinder called the Ukraine Invasion, ostensibly to free the Russian-speaking people of the Donbas from Nazi-like rule. With the coordinates of Russian infrastructure that Ukraine is acquiring, soon it’s going to be a full time job repairing pipelines, refineries and loading docks that have been blasted to smithereens. Within that scenario of devastation all around, I wouldn’t be surprised if the cost of putting a barrel of Urals Blend on the market didn’t come to roughly the same $92 that the Permian shares with the KSA. (Unless Trump intervenes and puts a stop to the missile barrage, which would be a very, very bad look.)
So what happens when this global breakeven becomes apparent? Well, the markets will have to adjust, and it’s going to be fun to watch. The historic ratio of gold to oil has been 10:1. In other words, traditionally an ounce of gold would buy you ten barrels of oil. Today that ratio is 60:1, standing alone as the only discernible metric that either the price of gold is too high or the price of oil is too low. From what we are all experiencing, gold is simply following the scent of global fear; oil prices have been artificially suppressed by the president (taking advantage of a very real glut).
But something else is changing, too. Right after WWII, at Bretton Woods, the United States was awarded reserve currency: greenback backstopped by gold. When Nixon dissolved the Gold Standard, Henry Kissinger advised the president that there was nothing on which to base the value of a USD. From thin air Dr. Kissinger came up with the notion of a Petrodollar. It has held sway since.
Is this changing? I am told that whenever the KSA or Russia transact an oil sale to China, they do so not in exchange for the USD but for the digital yuan backed by gold, or, better yet, Bitcoin. This is very dangerous ground for America. Mr. Trump obviously has no experience with all the moving parts of the oil market. He will almost certainly learn the hard way that it’s at least as complicated as the luxury real estate market.
Gerry,
I always love your posts. Keep them coming.
There is no such thing as “Reserve Currency Status”.
It is all a function of MATH.
Many countries have lots of USA dollars in their reserves based on trade.
No one AWARDS it (Jesus?? he was from Israel and his language was ARAMAIC ).
The US dollar is stable, so people price things in it. Rather than Mexican Pesos which are all over the place.
It is just math!!!!!!!!
Without doubt the most important thing going on in the world today is the war in Ukraine.
Trump probably realises now that Putin has been playing him along and only tough measures will work. There is great danger here, Putin can’t be seen to lose this war. So who knows what he may do.
I think Ukraine has held off hitting Russian gas and oil facilities because several European countries relied on Russian oil and gas. These countries have mainly moved to other sources so Ukraine can up the attacks.
We could easily see 2 or 3 million barrels per day removed from the market by early next year. This would bring the oil prices up to where U.S. producers need.
What will Putin do?
https://en.wikipedia.org/wiki/Blowing_Up_Russia
Seriously he could do anything.
ger
The lifting cost is what matters. If they forego production, they only save the lifting costs. The welfare costs remain. They are not reduced by stopping pumping.
FWIW, I have heard this “Saudis need 90+” argument for years now. Somehow they did fine prior to 2010, with prices lower. Maybe they had to silver plate a few toilets, instead of using gold.
Also, if you look at the last 10 years, Brent has averaged $66, with only a single year above $90 (2022): https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=RBRTE&f=A Yet somehow the Saudis are still calmly pumping. We haven’t even had a revolution in SA.
Gerry Maddoux,
Everyone is misjudging just how bad the global economy is. Jobs numbers in the US are just made up and revised later on.
US has been in recession since before Trump took office.
My two cents is Russia oil production doesn’t matter that much. The global economy is really way worse than we are being told by politicians, central bankers and the media.
The Saudi’s will just have to continue adding debt. Never going to get the price needed to make it work without taking on debt to pay for stuff.
The Saudi’s business model currently isn’t much different than the shale companies.
https://www.dailymail.co.uk/news/article-15160039/us-military-venezuela-operations-boat-strike.html
Coincidence? The world’s largest oil reserves and Guyana on the obvious rise?
Peter Hegseth (fox and friends) running the USA military with swastika tatoos on his body.
And Maduro is a wonderful chap who only sells drugs to prop up the economy and only kills who he has too.
https://www.amnesty.org/en/location/americas/south-america/venezuela/report-venezuela/
Maduro is threatening to invade Guyana for its oil he needs to be executed.
https://www.youtube.com/watch?v=LK0K4sIQw9U
12 minutes
Trump prepping for regime change in Venezuela
See middle chart for Permian gas production versus pipe capacity. Currently constrained by lack of transport pipes and will not get relief until middle of 2026.
https://insight.factset.com/permian-pipeline-production-update
See middle chart for Permian gas production versus pipe capacity.
https://insight.factset.com/permian-pipeline-production-update
Currently constrained by lack of transport pipes and will not get relief until middle of 2026.
Quite some capacity (likely needed) coming on after 2026.
Nony, that forecast is not very likely for Permian output. Even a high price scenario ($90/b to $100/b) is likely to only see a peak around 6 Mb/d, that forecast goes to 8 Mb, probably won’t happen so more pipeline capacity not needed as even with the high price scenario Permian dry natural gas output peaks at 23.9 BCF/d in 2034, fairly close to existing capacity.
Note that the high scenario is very optimistic, probably less than 25% probability the output curve will be this high or higher, with TRR mean estimate from USGS at 75 Gb and Patzek ERR estimate at 55 Gb.
permian scenarios 2509
Excerpt from the piece that Nony linked:
“The Permian Basin looks to be set for growth on the dry-gas and NGLs side but may require more crude pipeline capacity by the end of 2030. Also, as crude economics should continue to drive operator activity, more crude takeaway capacity will likely be built as utilizations increase.”
I don’t think more crude pipeline capacity will be needed for the Permian Basin, but agree there is adequate NGL and dry gas pipeline capacity.
Chart of Permian dry shale gas for high price scenario 2022-2035 at link below.
permian gas high price
I was trying to talk about gas. And getting into their graphics, not their arguments about future production. No intention to red flag your bull. Put down the horns please. 😉
In particular, you can see the “pinch point” with current gas production and current gas capacity. Which totally makes sense, given the $-9!
My POINT was that the relief won’t come until mid 2026. Which I didn’t realize until seeing the article So…settle in for close to a year of negative Waha. (And then relief after.) I didn’t know if this was a month or a year or a 5 year issue. But the graphic implies it’s a 9-12 month issue.
Obviously the future is hard to predict. Consider that we neglected to put in the needed capacity for gas in the past! We are negative 9! So…it is possible to be conservative like you and then not have enough pipes.
Of course the opposite can happen also! That’s why companies and investors make bets. And they can be (and have been) wrong in either direction.
Nony,
The gas is associated gas, so if the forecast for tight oil is optimistic (and 9 Mb/d for Permian tight oil is very optimistic) then the shale gas forecast will also be much too high. There is adequate capacity when the pipes are not down for maintenance or other reasons, when the gas price is negative they can choose to shut in output or flare the gas and pay fines, it is a business decision. The larger operators have pipeline capacity contracted, the smaller players take the hit.
That forecast was from July 30, 2025, perhaps some of the capacity did not come online as planned.
This piece from Sept 2025
https://www.naturalgasintel.com/news/permian-pipeline-boom-is-too-much-natural-gas-takeaway-capacity-possible/
has about 10 BCF/d of new Permian basin natural gas pipeline capacity coming online by 2029, I expect this will be about 5 times what is needed.
I told you to put down the horns. 😉
My main point was not the 2030 capacity needed, but the current issue and when relief from it occurs. You can see that by just zooming in on the graph and looking at 2024-2026. The relief is expected in mid 2026.
There is zero doubt that outlet capacity is insufficient right now. Prices are negative now and EIA predicts the average for the year will be negative also. And they averaged about zero during 2024. That is a long duration of inadequate transport capacity. That’s not a compressor down for a couple weeks!
If you are so all knowing to warn about overbuilds, why didn’t you warn about the 2 year pinch point (mid 2024-mid 2026)? Hmm?
Nony,
You are the one who seems to think he is omniscient. I am just looking at the chart, from that it looks like pipeline capacity is adequate. The fact that Waha prices are negative suggests there should be more capacity, I have been saying that more natural gas pipeline capacity is needed in the Permian Basin for years. I am not the one building the pipes. If all of the proposed capacity gets built, there will indeed be overcapacity. Many of the proposed lines probably won’t get built, unless midstream companies like losing money.
Dennis:
It’s absolutely clear that there is not enough outlet pipe capacity.
1. Waha prices averaged about zero in 2024. That was over a $2 differential to Henry Hub. They are currently negative and have been near zero for most of the year, negative for last month.
2. You can see this on the graph also. Look at the middle graph and production from 2024-current. Production is already bumping up against a limit. You can never go over 100%. And there will be occasional corrective/preventative maintenance, throughout the network. So…if you have ~95% production versus theoretical capacity, you’re “full”. Hence the prices. (Same thing happened in 2019-2021…look at the chart.).
Nony,
I agree not enough natural gas pipeline capacity currently for Permian. Must be all those liberals in West Texas not allowing the pipelines to be built. 😉 I don’t decide how much pipeline capacity to build, above my pay-grade. Dry shale gas production in Permian Basin was 21 BCF/d in August 2025 (most recent data point). The charts in the July 2025 article you linked has regional demand at about 3 BCF/d so about 18 BCF/d of capacity is needed, if we assume pipelines run at an average capacity of 85% then nominal capacity of 21 BCF/d would be needed to meet the August 2025 level of output. Supposedly two projects will be coming online in 2026 adding 4.5 BCF/d of capacity (according to articles from Sept 2024) a more recent article from Sept 2025 suggests 4.5 BCF/d of capacity will be built year end 2026, about 0.5 BCF/d added in 2027 and another 5 BCF/d in 2028. The Permian peak in dry shale gas may only be about 23 BCF/d so perhaps 24 BCF/d of capacity is needed (again assuming average utilization of 85%) assuming regional demand of 3 BCF/d. The capacity coming online in 2026 is much needed, the capacity scheduled for 2028 may take Permian natural gas pipeline utilization down to 67%, if my mid-case forecast is roughly correct.
Not my problem, but if I were an investor in these mid-stream companies (operators of the Permian Basin natural gas pipelines), I would be nervous about the coming glut of pipeline capacity.
Dennis! 🙂 You made me smile with the liberals comment.
But…we all know nobody lives in West Texas. 🙂
https://en.wikipedia.org/wiki/West_Texas#/media/File:West_Texas_Hwy_302_west_of_NoTrees.jpg
I remember driving from Los Alamos to Orlando in the 1980s. NM was great. Like a Western movie, really. But it was dark by the time we were in West Texas, so I couldn’t tell what that looked like, just turned in at some crap motel.
Woke the next morning and saw the landscape. Flat. No trees. Just desolate. Almost not even any cars. On I-10!
And then TX takes forever to cross itself. Was happy to get to FL finally. It was flat also. But at least it had water and vegetation and people. And manatees.
Well, at least we are not exhausting our Solar Energy Reserve while we still have Natural Gas to burn.
OPEC + Announces November Oil Production Targets
Today Opec + announced its November oil production targets along with its expected monthly production increases going forward.
The attached table shows production targets for the next few months and a projection out to July 2026, provided the monthly November increases are the same.
The big 3, Kuwait, UAE and Saudi Arabia will meet their target. They typically are very close. Iraq will also be close because of the addition of approximately 185 kb/d from the newly reopened Kurdish pipeline. The big outlier will be Russia which probably will be closer to 9,000 kb/d or less by July. Kazakhstan will more than likely be 200 kb/d day over target.
Assuming that Russia will be close to 9,000 kb/d in July, a bit optimistic, a more likely total increase from OPEC plus will be closer to 1,300 kb/d rather than the 2,088 kb/d.
As a sidebar to this OPEC + increase, a new peak oil might emerge in November/December, accompanied by a US peak, because of a likely increase of 1,000 kb/d from OPEC +. The big unknown here is the effect of Ukrainian bombing on Russian export capacity. Russian production could be down to 8,500 kb/d by July if the war is still on. Hopefully not.
https://opec.org/pr-detail/243578-05-october-2025.html
A Opec
I followed the link and was still confused if it is a cut or an increase they were talking about. Googled it and got the answer. It’s an increase. But only 137,000 bopd. Pretty small, really.
https://www.reuters.com/business/energy/opec-poised-raise-oil-output-further-sources-say-2025-10-05/
“OPEC+ opts for modest oil output hike as glut fears mount”
Be interesting to see how markets react. I would think the small change (almost flat) is less than growth that the markets feared. Should give some price support (if markets feared worse). Maybe jump price a couple bucks. But…we will see.
Nony
That will be a monthly increase out to July as shown in the table.
Without appearing crass, who cares if the natural gas takeaway pipeline build-out is excessive? As an avid outdoorsman, to me almost anything under the sun beats what’s happening now (and has been occurring for years)—the unfettered flaring of NG. I’m sure you all know that the greenhouse gas number ascribed to methane gas is about 27 (times that of CO2). With NG prices upside down due to the glut, the current choice is either flare for free or pay someone a ton of money to carry it away. The pipeline companies do well. Let them put in all the pipes they want, as long as they do it right, and if they’re not used, the hickey will be absorbed by a robust balance sheet.
There’s likely going to be enough NG put out during the next half-decade to fill the pipes. The Tier 1 has been developed. Future drilling is going to be in Tier 2 and 3. Some of it will be into the lower Wolfcamp formation. All of this will yield a higher GOR than ever seen before from new wells. The legacy wells are hitting the bubble point at an astounding rate, in populations numbers that would stagger a mule. In short, there’s going to be an awful lot of associated gas. I don’t think there’s any way to predict with any accuracy just how much. As the GOR increases to the point where it’s 50% of the hydrocarbon production stream–and it’s just about there–then it’s going to be more and more important to sell the gas rather than burn it up in the atmosphere and poison the oceans.
Gerry,
As a wise oilman often points out the goat pasture is not likely to be developed and at first GOR increases and then it decreases as the well approaches end of life. I agree pipeline capacity should be built and that natural gas should not be flared, but if there is overcapacity midstream companies won’t be making much money on a pipeline that is running at 50% of capacity. My mid-case scenario for the Permian at a URR of 55 Gb is already on the optimistic side (45 Gb is likely more realistic) and I take account of rising GOR in my scenario. It isn’t all that likely that wells will be drilled in the Permian in the very gassy goat pasture as they won’t be profitable ventures. Peak gas output (marketed gas) in the Permian will be about 25 BCF/d with peak dry gas at about 22 BCF/d, if the 10 BCF/d of capacity is built as suggested in the Sept 2025 piece I linked earlier, that brings capacity to 29 BCF/d, regoinal demand is about 3 BCF/d, so only 19 BCF/d is needed at peak. I am not in the midstream business, but it seems running a pipe network at 65% capacity is not likely to lead to profits for midstream companies. According to Chat GPT natural gas pipelines need to run at 70 to 85% capacity to break even (no profit).
Permian Wet Gas scenario at chart linked below (corresponds with tight oil scenario with URR=55 Gb).
permian gas 2510
Midstream companies are pretty savvy in terms of looking at future supply. If anything they are more conservative than the producers, since they are left holding the sack when there’s a bust.
Midstreamers do a lot of modeling. And better than the peak oilers, they have a profit motive not an ideological greenie bias. So, when you see pipes going in, that’s a big boy bet. Not just someone standing next to a 2018 AGU poster.
In addition, they usually won’t build on spec. They’ll get take or pay contracts for a substantial portion of the capacity. So…that is producers also putting their money where their mouth is.
Of course there are still under and over builds. Because it is impossible to predict the future. E.g. they underbuilt for 2024-current. The good thing is there’s a lot of capacity coming on in the 2026-2030 time frame.
The bad thing is we will have to wait until mid 2026 before the first increment of new outlet piping comes on line. Expect bad Waha gas prices for the entire 2025. Now if the pipeline h8er leftists would just allow flaring? But no. 🙁 So…expect more gas pipes coming out of Waha!
Intuitively, I think there’s a lot of capacity for gas out of the Permian.
1. Even as oil growth slows and plateaus, gas will rise. This is because from a given well, gas usually declines slower than oil. So if the basin stays constant for oil, gas will still rise.
2. Drilling/growth has shifted to the Delaware which is gassier just to start with.
3. There are several areas of the Permian that could be developed for gas, but have minimal oil. These parts are not being developed at all right now. It would be insane given the gas prices at Waha! But 10+ years from now? If there’s a need at Henry Hub? And capacity on the transport pipes (as ass gas eventually declines) is available? Well…that dedicated gas can come in and backfill for the ass gas.
Dennis,
I would be a little bit wary of predicting ultimate gas production out of the Permian based solely on oil prospectivity, especially if you’re using USGS as your basis.
The USGS estimates are limited to certain formations and areas. And really are based on where hz drilling is currently happening. So…they are biased to looking at oil, which is what is being developed now. They won’t perfectly predict oil, either, but at least that’s what they’re looking at. But USGS is not looking at the Barnett formation or Alpine High area or the like.
Note: this isn’t even to slag USGS. Just that you need to think about what their reports do and what their constraints are. That way you’re not just mechanically shoving them into the front of your process…but thinking about one USGS estimate versus another and how good they might be. And implicitly they will do a better job at predicting more mature plays.
Think of the analogy of how the Utica has higher uncertainty than the Marcellus. In similar fashion (I’m not saying amount, I’m saying directionally, “fashion”), so do the gas-prone horizons of the Permian have higher uncertainty than the oil-prone ones. We have done a LOT of hz drilling in the Permian for oil. Not much for gas.
Consider also the analogy of the Permian oil production from 2013ish. Remember? When people were only looking at the Bakken and the Eagle Ford and lumping the Permian in with some snips and snails and puppy dog tails of “rest of US shale production”! Well…how did that view turn out?
Note: I’m not even saying FOR SURE that Permian gas prospects are huge. Just that there is much higher uncertainty. Because people really aren’t even drilling for gas there. (And it is a very complex area, with many different strata, some deeper and gassier…so yeah, there’s gas prospects also, amount TBD, if the price ever justifies going after them.)
Nony,
The view in 2013 was very much in line with the forecast from the EIA for US tight oil. As I get better information over time I adjust my thinking taking into account what I know. I will continue to do this in the future.
USGS and others look at oil and natural gas. Some of the wells drilled in West Texas are already natural gas wells (the bad wells that don’t produce much oil). Not clear that these wells would be drilled just for gas, not likely to be profitable. The average Permian well in 2020 produced about 2 BCF of gas over first 15 years (projected) vs 8 BCF for an average Marcellus well. Not enough gas to justify a $10 million well project. I use the average well data from Novi for both oil and gas to make my estimates and I assume the gas will be associated gas, when the drilling for oil stops, the gas will stop as well. Perhaps at very high natural gas prices drilling continues for gas only in the Permian Basin, I doubt this is likely.
For my tight oil and shale gas scenarios (mid-case) the basin average GOR v date.
permian GOR 2510
Dennis:
The USGS did not look at the Barnett formation (which is gassy, not oily) within their most recent Delaware TRR estimate.
“Using a geology-based assessment methodology, the U.S. Geological Survey assessed undiscovered, technically recoverable continuous mean resources of 46.3 billion barrels of oil and 281 trillion cubic feet of gas in the Wolfcamp shale and
Bone Spring Formation of the Delaware Basin in the Permian Basin Province, southeast New Mexico and west Texas.”
https://pubs.usgs.gov/fs/2018/3073/fs20183073.pdf
Nony,
The Barnett is separate from the Delaware Basin, the assessments are by Basin. The tight oil plays are assessed for both oil and gas.
The USGS assessed Barnett separately in 2015. Nothing new in past 10 years from USGS, but looking like USGS assessment was probably high with a mean undiscovered TRR of 53 TCF, at end of 2014 cumulative output plus reserves were 36 TCF so mean TRR is 89 TCF, even the F95 TRR was 76 TCF, URR will be about 35 TCF at most (F5, cumulative output plus reserves is about 27.5 TCF and the basin is fading.) In this case the USGS was likely much too high. A BEG analysis gave a 45 TCF ERR estimate at $4/MCF. A 2019 paper by Patzek forecast about 30 TCF for Barnett.
Dennis:
That 2015 study is on the Barnett in the Dallas area. It does not cover the Barnett stratum OF the Delaware basin. Look at the map.
https://pubs.usgs.gov/fs/2007/3115/pdf/FS07-3115_508.pdf
You’re talking apples and oranges. (I suspect same confusion with the Patzek paper. I would be interested in their Permian estimates though, especially if they looked at the Barnett layer of the Delaware basin.)
I’m not talking about the Barnett in Dallas. That wouldn’t use Permian pipes anyways! I’m talking about the Barnett in the Permian.
Dennis,
I found the Patzek 2021 Permian (not 2019 Barnett) study
https://www.mdpi.com/1996-1073/15/1/43
It looks like they did not estimate gas production from the Barnett stratum (different from the “Barnett play” several hundred miles away). They don’t have a Barnett gas TRR for either the Midland nor the Delaware.
Nony,
Typically when one speaks of the Barnett Shale, they are talking about the production in East Texas. That’s the Barnett output reported in the EIA’s shale gas report.
Using Novilabs data the Barnett in the Permian has 5 wells flowing as of Dec 2023 with output of 5.4 MMcf/d out of 22 BCF/d of Permian shale gas output at that time. That’s about 0.0245% of total output. The Barnett won’t be producing a lot of shale gas in the Permian Basin.
See
https://public.tableau.com/shared/MKQZKQ579?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y
Most of the Permian shale gas produced comes from the Wolfcamp, Bonespring, and Spraberry formations.
Dennis:
I said several times the Barnett WITHIN the Delaware. That’s your fault, not mine, that you didn’t pay attention. And the Ft. Worth play has ZERO relevance to a discussion of Permian pipes. But, hey, maybe you learned something.
Oh…and you also paid zero attention to where I said it was NOT being targeted now and was an unknown.
Sheesh. Read.
Nony,
The analysis by Padsek uses production data, nobody is producing from the Barnett Formation in the Permian Basin (5 wells out of 45000 wells in Barnett Formation and these were completed in 2022 after the Patzek study, though 5 wells is not enough data to do anything with).
When the 2007 study was done nobody was drilling horizontal wells in the Permian Basin so there wasn’t really any data to make a good assessment.
No duh, Dennis. I told you this a while ago. You are just too laser focused on a particular methodology, you can’t comprehend anything else. Even when told so.
We also don’t have oil production from the AK petroleum reserve, from the East Coast of the US, from the Neutral Zone of Arabia, etc.
You can’t use your “everything looks like a nail to me, when I’m so used to swinging a hammer” on screws and bolts. 😉
Nony,
It is possible that the supply is infinite, I don’t think it is very likely. Though there will likely be technological progress, I don’t expect we will invent new physical laws, also possible there might be new discoveries (akin to general relativity or quantum physics in the 20th century) but not likely this will affect oil and gas production (except possibly to eliminate them as an energy source because they can no longer compete).
Nony I didn’t get it because it is irrelevant, I didn’t pay attention to a formation that is ignored by oil and gas producers. They likely ignore it because it is not productive, the best plays are developed first. Some things are so obvious I leave them unstated.
You’re a waste of time.
Slightly off topic but of strategic importance to Californians. On Oily Stuff there is a description of the Chevron El Segundo refinery and fire in the Isomax plant.
https://www.oilystuff.com/group/oil-natural-gas-refining/discussion
Nice article. Ima check out what else he has written. After all, I wasn’t born with a wrench in my hand…so I learn from the Intertubes.
I donno, but sounds like the refinery can maybe still operate, albeit at lower throughput, with this unit out?
And that the unit itself, only had a subunit damaged. So a good candidate for repair, and getting whole site back to full capacity.
Pipelines:
We’re all making the same point: they’re likely to overbuild takeaway pipelines to relieve the NG glut now present at the core of the Permian. To me that doesn’t matter, as the damage to waterways and land to lay a pipe is so much less of an environmental insult than flaring billions of tons of methane gas into the world troposphere that they’re not comparable. I have four large NG pipelines running across my property. Even back in the fifties, when the first one was put in, the standards were high and they didn’t permanently damage our cropland. Three of those pipes are now empty, but they’re not really harming anything. At some point, face it, all the pipelines in the world will be empty. It’ll be one hell of a mess down there, but it’s the cost of having heating, electricity, jet fuel, and all the building blocks that go to make up our houses, power commerce, and give us utensils and appliances in our homes. I don’t mean to beat this to death but to underscore that what has happened in the Permian for the last decade (and other shale basins too) has been nothing short of criminal. At some point somebody will probably try to calculate how many trillions of tons of methane gas were put into the air by shale basins. It will be a staggering number. Furthermore, I strongly suspect the ICC @ The Hague will try to press a case. The land belongs to hardworking ranchers and farmers and I hate like the devil to see it fouled by laying a pipe, but it’s so much better than having all that gas flared and vented that it’s a no-brainer. And I don’t really care if a couple of pipelines go belly-up. As a landowner I can tell you that the pipeline reps cajole you to tears trying to lowball you on a price per rod in damages. They’re taking a risk. Let them, for Pete’s sake.
I’m not so sanguine about a near term pipeline glut for gas out of the Permian.
Not so sure we all think the same. Dennis and I have similar views on a near term glut of LNG…as does everyone. But we disagree on Permian gas pipes.
Right now, it’s inadequate. And we won’t start to get relief until mid 2026. Yes, there’s some build coming then through 2030. But it’s not like the massive LNG build that pretty much everyone sees as a few year glut coming.
Just eyeballing it and considering the history, I’d think it’s more likely that we have something like this:
2024-2026: not enough gas pipe capacity.
2026-2030: about right gas pipe capacity.
2030+: more gas pipes needed.
Gerry,
I clearly have no control over which pipelines get built, generally I think it is silly to build much more than needed, we need more natural gas pipelines in the Permian at present, when the 4.5 BCF/d comes online in 2026, that will probably be adequate and the pipelines planned for 2028 will probably be too much, if my forecast for Permian oil and gas is correct (I believe it is on the optimistic side.) Makes no difference to me and I agree extra pipelines is better than more natural gas flaring.
Nony,
I agree roughly on pipeline capacity through 2029, after that if planned projects are built we will be way over capacity, if it is all built capacity utilization will be about 50%
Flaring gas seems especially perverse when you are simultaneously importing electricity, but I guess water for cooling is a problem.
Electricity is easier to transport than gas.
Looking at USGS, the most recent Delaware/Barnett shale estimate I could find was from 2007. Dennis, you are better at looking up USGS than I am, so please correct me if there is a more recent update.
https://pubs.usgs.gov/fs/2007/3115/pdf/FS07-3115_508.pdf
AT that point in time, the USGS had a mean 17 TCF of gas in the Delaware’s Barnett stratum.
Given the substantial developments in drilling and completion since 2007, I would have to think that is low.
———
Consider that in this same 2007 report, the USGS had 0.5 B of oil for the Delaware Spraberry (Bone Spring/Avalon). In their 2018 update, they grew that to ~18 B bo from the same formation. (And that’s not even including production and PDP reserves developed between 07 and 18!)
Now, I’m not saying gas from the Barnett grew the same amount as oil from the Spraberry. But I think you’d have to be naive to think a 2007 estimate is still valid. In all likelihood, it’s a very substantial underestimate. (Look how projections of gas and oil have grown for the USGS since this time frame.)
And I’m not even 100% clear what their boundaries were for their 2007 estimate. There’s a map, but it doesn’t clearly indicate each AUs boundaries, just the whole study. For instance is the Alpine High (Diablo Extension) included? I tried getting more info, but there’s not a lot for a 2007 study and I’m not that great at navigating the site.
————
I’m not sure there aren’t other possible gassy areas of the Permian. (I just Google stuff on the web, although I do also try to think, not just recite…but I’m not a geologist.)
After all…nobody has been optimizing for gas in a long, long time in the Permian. It’s a very complex system with a very large areal extent and a deep column of hydrocarbons. So…I would not be sanguine that there is no gas potential outside of “ass gas”.
All of which makes me think there’s some “we will find it when we need it”, if the onslaught of ass gas lessens. (And even that is probably many years out!)
Nony,
It depends on prices and competing basins, for now nobody is targeting the Barnett formation in the Delaware Basin, 5 wells in that formation in the Permian in Dec 2023 out of 47540 wells (0.01% of all wells flowing were in the Barnett Formation of the Permian Basin).
Doubt the 2007 assessment is very reliable, the USGS developed a new methodology for continuous oil and gas formations in 2012, anything before 2012 should be ignored. Probably the 2007 assessment is an over estimate of Barnett and Woodford formations in the Permian Basin.
We can reassess if more wells are drilled, 5 wells is a pretty small sample.
Link to Novi Chart with all Permian Barnett formation production, approximately 7.5 MMcf total through Jan 2024
https://public.tableau.com/shared/HWKQXB2D4?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y
1. Agreed that it’s not being drilled now. I told you that, before. Duh. The point is…they might go after it when they need it. And it’s NOT in your TRRs.
2. I’m curious why you say that the estimate of 17 TCF is likely an overestimate. That feels like peaker bias, dude. Consider
a. The industry has learned something in the last 20 years.
b. The Spraberry oil estimate (within that 2007 report) has already gone up more than 30X.
c. Many other estimates from that time frame have gone up.
did someone read NOVI’s latest assertion that tier 1 inventory in Midland will last into 2040?
https://www.linkedin.com/posts/jorge-garzon-ph-d-00633672_most-people-think-midlands-best-rock-is-activity-7379158557998387200-HRU1?utm_source=social_share_send&utm_medium=member_desktop_web&rcm=ACoAACrnZFQBd4VTlgCdrybYHfZSuQO1tkRmD8o
there is also an inversion of maturity underneath the Carboniferous in Delaware, NM.
The isotope log there shows that the similar inversion happened in Northern part of Lea and Eddy, as it happened in the Permian formations, i.e. from Bones to Wolfcamp, and Wolfcamp actually more oily than Bones as a result.
Sheng Wu,
Saw that, but believe the analysis is likely flawed, see discussion of this at oily stuff forums.
From the Novi post:
“But there’s an important caveat: a portion of this 60% of top-tier rock will be impacted by parent well depletion, leading to 40–50% performance degradation in new wells depending on proximity and depletion levels. In other words, not every top Tier location will be economically viable. I’ll cover this issue of parent-child impacts in a future post.”
The question is what proportion of these 42k drilling locations (this number seems high) are not affected significantly by parent child productivity losses. Let’s guess it is 50%, which brings us to 21k locations. Further let us assume most wells (90%) completed are tier one and tier 2 wells. Recent completion rates are maybe 200 per month in Midland Basin, using 90% estimate we get 180 wells per month or 2160 wells per year, so this would take us to 2035 at current rates of drilling. Note that the 50% guess is probably optimistic so 2030 to 2035 might be possible. The parent-child interference might be much higher than 50% affected significantly. Much will depend on future oil, NGL and natural gas prices.
Nony,
Earlier (2007) methodology was not very good. For Gas there have been some very large estimates (Barnett shale, E Texas), Haynesville/Bossier, and Utica which seem likely to be revised lower. Barnett in particular at around 75 TCF for mean TRR is probably 2.5 times too high. Also the fact that nobody is targeting the gas formations in the Permian Basin suggests it may not be profitable to do so. If it was, pipelines would be built and the wells would be drilled. There is always upside potential as we have a hard floor of zero and an upper limit of the mass of all hydro carbons within the planet. Seems unlikely that 100% (or even 10%) of that mass will be extracted.
You are correct it is not in my URR (which is an ERR not a TRR). My Permian mid-case scenario has a URR of 244 TCF. It is based on the formations that are currently being produced.
Care to venture a guess as to how much will be extracted from the Barnett formation in the Permian, and throw in Woodford too?
There is obviously always uncertainty in these estimates. I would say perhaps 160 TCF to 360 TCF for Permian Basin Gas would be my 80% CI.
comment on Novi post
https://www.oilystuff.com/group/forum-stuff/discussion/7c684002-bb78-45d2-a516-130851b3f6f2
I realized on looking at the chart more carefully that there are about 22k Tier 1 and tier 2 wells remaining according to Novi and recent drilling rates were about 1600 wells per year for tier one and two. That is enough tier 1 and 2 to get us to 2039 at recent drilling rates. If we assume only 50% of remaining tier 1 and 2 inventory (11k locations) is viable due to parent child interactions, we are out of drilling locations for tier 1 and 2 by 2032. If we assume only 30% of tier 3 and tier 4 wells are profitable we are left with 8400 tier 3 and tier 4 wells, lets say these are completed at a slower rate of 750 per year, that is 11 years of potential completions taking us to 2036 when viable inventory is depleted and no more wells are completed.
Mr. Coyne, as to Novi’s recent estimate of remaining economic drilling locations in the Midland Basin, please recognize its standards for what’s “economic” and what’s not. Rystad says $65 breakeven, Enverus says $70, going to $95…Novi says $50. See where I am going? Austin fucks up everybody, eventually; Novi is no exception, apparently.
Respectfully, there are still over 4,300 wells per year being completed in the Permian Basin and at current product prices, ALL of them are being stuffed into the BEST acreage available. Nobody, I repeat nobody is willingly drilling in goat pasture. So with that in mind, 4 years, maximum, and there will be an OMG moment, even for “annoying.” Unless of course, America keeps wanting to get deeper and deeper in debt.
For both of our sakes I dug sorta deep into Novi today on the Barnett. Its not that good, man.
Stay the course. You are 100% on the right track now. Ignore the socialists from Europe, and Australia. Its not their debt.
Its our country and OUR children’s future. West vs. East. Globalization is still a big deal for those that had no long term plan, and are in need. That shit is all over now.
Thanks Mr Shellman,
I think that Novi chart was for Midland Basin only, for Tier 1 to Tier 4 in 2024 they have about 2500 wells per year completed in the Midland sub-basin of the Permian, about 1400 of the 2500 were tier 1/ tier 2 and 1100 were tier 3/4. I agree at current oil, NGL, and natural gas prices we would expect the tier 3/4 completion rate to fall, if we see high grading with mostly tier 1/2 completions at 4000 wells per year (lower completion rate due to low oil price) and the 22k tier 1/2 inventory estimate is correct, then 5.5 years gets us to the end of tier 1/2 inventory. If we assume only 70% of the 22k tier 1/2 inventory is viable (due to parent-child issues) we have 15.4k wells which are used up in roughly 4 years as you suggest.
I realize now the last data point in the chart is 2024 (I had been thinking 2025) so this suggests decline starting in 2028. I agree that unless oil prices rise a lot ( I have been wrong about oil prices since 2016) we may not see a lot of tier 3/4 wells completed.
Thank you so much for all the analysis you do at oilystuff, I learn a ton, but try to keep my mouth shut and just learn.
Edit:
Made a mistake above assuming 4000 wells per year completed in Midland, that should have been 2500 wells per year, of tier 1/2, if we assume operators switch to drilling only tier 1/2 wells and leave tier 3/4 for later. At that rate and assuming only 70% of the 22k tier 1/2 inventory is viable we get 6.2 years of drilling which would take us to 2030. If we then assume operators switch to the 8400 tier 3/4 inventory that is viable, we would have another 3.4 years of inventory taking us out to 2034. Output would start to fall in 2030 due to the switch to lower quality tier 3/4 wells as viable tier 1/2 inventory depletes. After 2034 we would see steeper decline as no more wells would be viable in the Midland Basin.
A similar scenario could be set up for the Delaware Basin, but the timing would likely be different. I don’t have the information I would need for a similar Delaware Basin Scenario.
For those interested in Mr. Shellman’s analysis of the Barnett formation results in the Permian Basin see link below.
https://www.oilystuff.com/group/engineering-and-geological-discussions/discussion/a28685cc-e0ca-48b6-869a-6c70074cb776
Thanks Mike for the analysis.
You are correct, DC, about Midland Basin wells only; my bad.
DC,
Agree that the “NOVI 2040 Tier1&2” are overly optimistic due to parent/child well interferences.
The deeper Barnett is quite different from the Alpine high or the Fort Worth which are both much shallower and actually much higher GOR, so the pressure is lower and liquid is much less in Alpine high and Fort Worth, where the GOR is over well over 50MCF/bbl, and pressure much lower.
I actually was on the Barnett rig in TX Delaware which caught fire in the almost a year ago, and the GOR is about 1~1.5:1 BOE, or 6~10MCF/bbl?
Like I said above, in the NM part, Lea and Eddy actually has another inversion at about 12K feet deep, and the Barnett/Woodford could have more liquid.
The US GOM/GOA actually are much deeper now, the latest discovery well is at over 33Kft, or 10km total vertical depth with water depth over 1.5km or 5k ft. With pressure ~> 20K psi and temperature close to 150C.
As I already said, nobody is targeting the Barnett stratum of the Permian (especially not in the most gas prone areas like the Deep Delaware.) So…it should be crushingly obvious that USGS/Patzek methods are not going to assess the potential properly. Since they require current drilling. I already said this.
You have to use geological methods of estimating potential, not type curves and area and drilling density (the USGS mindless method).
Who knows what we c dould get out of it. I’m not guaranteeing anything. But it’s upside. And with a decent rationale. If ass gas falls off a cliff and the pipes have space on them, Waha price will converge to Henry Hub. And gas drilling may become economical.
Nony,
One can use analogs to areas that have production occurring, but we don’t know what is viable until wells are drilled. Even at current Henry Hub price, if the well produces 3 BCF over its life, it will not be worth drilling. Now we could claim that these wells will look like Marcellus wells or that HH price will be $10/MCF and of course beggars will ride. Obviously there is no limit to supply 🙂
We are all Palestinians now.
Here’s an interesting 2007 geology emphasis report on the Barnett layer in New Mexico.
https://geoinfo.nmt.edu/publications/openfile/downloads/500-599/502/ofr-502.pdf
The discussion is necessarily geology heavy as there was no production.
TOC percentage, thermal maturity, and layer depth were all highly positive for significant shale gas development.
The obvious reason it’s not being developed now, and hasn’t in the past, is that gas prices suck in the Permian. And especially in NM!
But…if we start to run low on ass gas and have empty pipes like Dennis worries about? This layer might become economical.
An EIA Review of Permian geology
https://www.eia.gov/maps/pdf/Permian-pI_Wolfcamp-Bonespring-Delaware.pdf
This also does not discuss Barnett Formation in Permian. It does mention about 235 TCF for USGS Permian estimates of Natural Gas in Wolfcamp, Spraberry and Bonespring/Avalon Formations. When we add cumulative production and reserves to this estimate we get 275 TCF, this does not include Barnett or Woodford.
see also last graphic at link below
https://afeleaks.substack.com/p/deeper-returns-evaluating-the-delaware
The Barnett and Woodford formations are deeper than the Wolfcamp so would be more expensive to develop.
This piece on Barnett development in Permian is interesting.
I had not been aware of this.
https://www.tgs.com/hubfs/Well%20Intel/2024_Well%20Intel%20Article%2025-Barnett%20Shale_final_hr.pdf
Nice refining discussion: https://www.oilystuff.com/group/oil-natural-gas-refining/discussion/2c87a2c4-518a-4044-a650-cb1a6024afec
1. The fellow has deep knowledge in this area, decades of it (saw his bio). I have very little, but still more than the typical blog commenter…sadly often more than the typical upstream veteran…they just sell the crap…couldn’t troubleshoot a heat exchanger if their life depended on it…and organic structural chemistry? Ai yi yi! 😉
2. His blog discussion and the “wordy” slides are more helpful than the data dense PPT slides, other than just giving a feel of the sorts of tables that refinery people use.
3. One basic chart missing in the presentation is the distillation curve, showing how much mass percent product comes off as temperature goes up. People live by this…and it’s supplied with all crude data sheets. For one thing a given refinery may have slightly different cut points (temps) than another one, dictated by the equipment and the market. But the crude curve tells you how it will shake out.
4. I really like the Leffler Refining in Nontechnical Language book (see Amazon). If you get a refinery job, or just want to understand things, that is a great read. And even humorous. Do the homeworks though. I actually corresponded with the author (having worked every problem prior to a gig) and gave him a list of the few problems that had math mistakes. He’s a good dude.
5. It’s true that shale can be harder to run through a medium complexity refinery. But sometimes people overemphasize that. Prior to the export ban going away, I worked at a site that went from a regular diet of Basrah Light (which wasn’t, was sub30 and full of sulfur) to a steady diet of WTI at about 39 (or blends of EF 47 and medium grades from the ME). The reason was about a $5-$6 benefit from the restrictions on exporting (versus Brent, even more versus Basrah Light). Yeah, we had some pipes shaking in some heat exchangers and different issues different places. But refining is a conversion business. You get free money like that export ban? You figure out how to run the thing a little different. Of course, when the export ban was lifted, our free money went away. 🙁
6. I also recommend the 2016 Fesharaki CSIS refining video, for a good discussion of some of the larger economic issues, especially in different parts of the world. (Not the pots and kettle view, but the industry structure.)
Wouldn’t it be better to save some for later?
Having lots of oil tends to lead to bad politics, the Dutch curse. But without political complications, the oil would get pumped out even faster.
The fact that net oil-consuming countries are happy to sanction oil producers for political no-noes says to me that there is no supply shortage.
In the book “Angela’s Ashes” there’s a description of a teacher who would peel and eat an apple in front of the class and let his favorites eat the peels. Humiliating and degrading, but those kids were hungry. These days children turn up their noses at anything but their favorite candy or cake. Sugar is dirt cheap these days.
Oil not being pumped now for political reasons will still be available when oil goes short for geological reasons.
I don’t know if this has been commented fefore. IEA report about implications of oil and gas field decline rates. Or, it’s never been a peak demand, after all.
https://www.iea.org/reports/the-implications-of-oil-and-gas-field-decline-rates
I did bring it up when it appeared, but can’t find the post now. If you go back to the link provided in the report for WEO2008, there is table of the 20 largest oil fields in the world, from which one can see how the production from Ghawar with peak at 5588 kb/d in 1980 and production in 2007 at 5100 kb/d (today likely about 3300 kb/d) and Safaniya with a peak in 2003 at 2054 kb/d and production in 2007 at 1640 kb/d. Greater Burghan peaked on 1972 at 2415 kb./d and production in 2007 was 1170 kb/d. Note the slow decline in Saudi Arabia, likely caused by a large number of supergiants, whereas Kuwait is losing production faster as she has fewer giants. Cantarell is an example of this kind of decline as it was the main source for Mexico. The most significant aspect in the September 16 reports was that 90 percent of all the investments is to slow down the decline rate, but even then it is 5.6% a year for all post peak fields. The development time of nearly 20 years is also a noteworthy fact brought out by the report.
I wonder if the recent high will get revised downward in 3 months such that December 2024 is still the most recent U.S. peak? I would bet money on it…
IEA monthly report has global refinery throughput at a record high.
https://www.iea.org/reports/oil-market-report-september-2025
If the Ukrainian forces keep hitting Russian refineries, this could be the last peak.
Here is the follow up to the Novi post by Jorge Garzon about Midland Basin well inventory
https://www.linkedin.com/posts/jorge-garzon-ph-d-00633672_the-midland-basins-best-rock-isnt-gone-activity-7381675538874245120-Xrxg?utm_source=share&utm_medium=member_desktop&rcm=ACoAABDV_wMB3QBPTlgD0zpWSJp3xTFeAV0uqvA
The original post at link below
https://www.linkedin.com/posts/jorge-garzon-ph-d-00633672_most-people-think-midlands-best-rock-is-activity-7379158557998387200-HRU1?utm_source=share&utm_medium=member_desktop&rcm=ACoAABDV_wMB3QBPTlgD0zpWSJp3xTFeAV0uqvA
Turns out that my WAG that tier 1/2 inventory would be reduced by 50% due to parent/child interference, turns out it is 46% based on Novilab’s analysis.
A lucky guess by me.
Nony (et al interested in Utica/Marcellus gas production),
A 4 well Utica pad from Seneca in Tioga county has been flowing on restricted choke for almost 7 months at 29 MMcfd (3 wells) and the remaining one at 23 MMcfd.
That 29 MMcfd is an identical profile to the legendary Deep Utica Scott’s Run well from a decade back (still flowing ~2 MMcfd, btw).
About 30 miles to the west, in Potter county, upstart outfit – Greylock – is drilling 4 more Uticas on the same pad as its two currently producing Utica wells which have been flowing 16/14 MMcfd on restricted choke for 6 months.
Flipping the ‘script’ entirely … when one looks at wells in absolutely the poorest of acreage, one can see the 6 wells in Blair county (the ONLY producing wells in this county) that came online almost 15 years ago.
All are still producing with total daily production of 900 Mcfd.
Ridiculously low numbers, certainly, but still throwing off almost a thousand bucks per day at $3/mmbtu for the scrappy operator LPR.
As these wells are within a stone’s throw from one another, the operator can – hopefully – eke out a living.
Still, from a macro view, if a half dozen, archaically designed 15 year old wells in the poorest of regions can still function, one wonders about the five and a half million square acres that the USGS has designated as non core (Eastern Interior and Southwestern Interior) which have seen virtually no activity in a long, long time.
Lots and lots of gas in the Appalachian Basin.
Coffeeguyzz,
For the Marcellus formation only the Eastern Interior is considered non-core with USGS estimating the EUR at about one third of the Northern Interior and about half of the Southern Interior and Southwest interior Assessment Units. The Eastern Interior was assessed at about 4 million acres in 2019 for undiscovered resources and about 21 TCF for mean undiscovered resource, about 22% of the total mean undiscovered Marcellus Resource.
For the Utica/Point Pleasant assessment, the area was divided into only a shale gas and oil area, the Marcellus Assessment Units do not apply for that formation. Not enough well data in 2019 to make a more detailed assessment. Note that the Utica assessment has very large unsertainty with undiscovered resource mean at 117 TCF and F95=21 TCF and F5=281 TCF.
Kind of a crap shoot. Keep in mind that operators generally try to develop the best areas first. There are far fewer Utica/Point Pleasant wells that have been drilled and a couple of very good wells make things look very good. When we have thousands of producing wells we can make a better assessment. In 2023 there were about 386 Utica/Point pleasant wells that has been completed and over 10 thousand Marcellus wells in PA. Eight wells does not tell us much.
Map from
https://pubs.usgs.gov/fs/2019/3044/fs20193044.pdf
at link below.
utica map
If we use recent(end of 2023) reserve (29 TCF) and cumulative production (22 TCF) for a total of 51 TCF of discovered resources and the level from the assessment in 2019 (32 TCF combined), this suggests 19 TCF of the undiscovered TRR estimated in 2019 has been discovered as of the end of 2023.
So as of Dec 31, 2023 about 98 TCF of Utica Shale Gas remains undiscovered (if the USGS assessment is accurate). We use a negative exponential cumulative probability distribution to maximize the uncertainty, where mean and standard deviation are equal at 98 TCF. We get the cumulative probability distribution in chart shown below, with mean TRR at 149 TCF and median TRR at 119 TCF. The 50% CI is 79 TCF to 187 TCF and the 90% CI is 61 TCF to 345 TCF. So very wide uncertainty.
Note that I am assuming here that URR=TRR, but realistically URR is 75% of TRR due to economic factors (at the median estimate) at the low end URR might be 85% of TRR and at the high end URR would be 60% of TRR. In short, these are very optimistic URR estimates.
Chart with cumulative probability at link below
utica max ent
https://oilprice.com/Latest-Energy-News/World-News/Maduro-Offered-Venezuelas-Oil-to-Trump-to-Avoid-Conflict-with-US.html
Maduro (Venezuela) offers natural resources (oil and gold) to Trump to avoid military attack.
I’ve always wondered what could become of Venezuela as an oil producer if the US Oil patch was unleashed on the country
An updated June World and Non-OPEC oil production report has been posted.
https://peakoilbarrel.com/june-world-and-non-opec-oil-production-rise/