US oil production at a record high, SPR is lowest since October 1982; gasoline supplies are lowest since November 2014

US oil prices fell for a second week after rising six out of the prior seven, as shipments of oil thru the Strait of Hormuz increased and Saudi Arabia resumed Red Sea oil exports after repairing its damaged East-West pipeline….after falling 3.8% to $92.41 a barrel last week on hopes that negotiations to end the war in Iran would proceed with Iran’s president in New York for a United Nations General Assembly meeting, the contract price for the benchmark US light sweet crude for October delivery jumped more than 2% during Asian trading on Monday after US President Trump rejected an Iranian peace proposal aimed at resolving the conflict and reopening the Strait of Hormuz, and was up $2.51 to trade near $106.83 a barrel as markets opened in the U.S., after Trump’s rejection of the Iranian peace proposal came amid reports he was considering new military strikes on the country, but pulled back from session highs later in the session after Saudi Arabia reportedly ramped up its critical East-West pipeline after repairs, and settled just 19 cents higher at $92.60 a barrel amid the stalemate in U.S.-Iran peace talks, while Trump said that U.S. negotiators were expected to engage in more talks later in the week…oil prices continued to rise in Asian trading Tuesday amid fading hopes for the reopening of the Strait of Hormuz and expectations that the US Federal Reserve would raise interest rates again next month, but softened Tuesday morning in New York as signs of higher Middle Eastern oil supply outweighed concerns over stalling U.S.-Iranian negotiations, and then tumbled to settle $3.22 lower at $89.38 a barrel after trade sources said that Saudi Arabia resumed oil loadings from its Red Sea port of Yanbu after restarting operations on the East-West Pipeline…oil prices rose during trading in Asia on Wednesday after US President Trump rejected reports that he was prepared to ease sanctions on Iran, and were still up during trading on the ICE Futures Europe exchange in London, then rose to a session high during morning trading in New York after the EIA reported that both gasoline and distillate inventories fell, leaving Midwest gasoline supplies at their lowest on record, and settled $1.04 higher at $90.42 a barrel amid the continuing stalemate in U.S.-Iran peace talks…oil prices rose around 2% during Asian trading on Thursday after China suspended exports of oil products to most destinations, raising concerns about tighter fuel supplies worldwide, but were mixed in a volatile morning session Thursday in New York as a tightening global fuels market outweighed resurging crude exports from the Middle East, and settled $2.45 higher at $92.87 a barrel on the Chinese export ban and on the news that the U.S. was sending a third aircraft carrier strike group and up to 10,000 additional troops to the Middle East… oil prices edged higher during Asian trading on Friday as China halted fuel exports, while the US weighed additional military deployments to the Middle East, raising concerns over a potential escalation in tensions with Iran and further disruption to regional energy supplies, but fell $2 during European trading after European leaders agreed on Friday to a request by US President Trump to release diesel from their reserves to lower prices and reduce the need to import fuel from America, and were down more than $3 Friday morning in New York after the Elysée Palace proposed a joint EU-wide release of crude oil and diesel from strategic reserves, and settled $1.76 or 1.9% lower at $91.11 per barrel after the Group of Seven nations announced the release of diesel and crude stocks to ease surging fuel prices, while Saudi Arabia planned an offensive against Iran-backed Houthi militants in Yemen, which left oil prices 1.4% lower for the week…

meanwhile, natural gas prices finished lower for the first time in three weeks on milder weather and a quick return to normal Appalachian pipeline flows after last week’s outage…after rising 9.8% to $3.196 per mmBTU last week on falling production from domestic wells, another smaller than normal injection of gas into storage, and a leak-related shutdown of the Mountaineer XPress pipeline in West Virginia, the price of the benchmark natural gas contract for October delivery opened 10.8 cents lower on its last day of trading on Monday, and trended lower into the afternoon after an early rally failed, as traders assessed lower demand and the October contract’s settlement, and expired 19.6 cents lower at $3.000 per mmBTU as restored Mountaineer XPress supplies and fading shoulder season demand weighed on the front of the curve. while the price of the benchmark natural gas contract for November delivery settled 11.9 cents lower at $3.106  per mmBTU….now the quoted front month, that benchmark natural gas contract for November opened 4.6 cents lower on Tuesday and trended lower thereafter, as mild forecasts kept the pressure on, and settled 9.5 cents lower at $3.011 per mmBTU after a volatile session, pulled down by mild early October weather forecasts and restored Appalachian pipeline flows…that November natural gas price started Wednesday 0.8 cents lower and dipped to an intraday low of $2.966 by 9:55AM, as traders monitored production levels amid largely comfortable fall temperatures, then rose into the afternoon to settle 1.5 cents higher at $3.026 per mmBTU, as traders weighed thinning production against weak shoulder season demand ahead of Thursday’s government inventory report…November natural gas opened 1.1  lower on Thursday and hovered near $3.005 ahead of the weekly report, then drifted lower into the afternoon amid bearish short-term weather forecasts after failing to react to the as-expected injection, and settled 5.9 cents lower at $2.967 per mmBTU, as an in-line storage report failed to counter pressure from mild autumn weather and soft seasonal demand….natural gas futures started Friday’s session trading gingerly, amid largely stagnant – and bearish – demand-side fundamentals, then probed higher during late morning trading on diverse regional weather patterns and possible supply constraints, and settled 6.8 cents higher at $3.035 per mmBTU as an unplanned outage on the 30-inch diameter Tetco pipeline in Kentucky and approaching cooler weather provided support against a still-loose fundamental backdrop….natural gas prices thus ended 5.0% lower for the week, while the benchmark natural gas contract for November delivery, which had ended the prior week at $3.225 per mmBTU, finished 5.9% lower….

The EIA’s natural gas storage report for the week ending September 25th indicated that the amount of working natural gas held in underground storage rose by 64 billion cubic feet to 3,415 billion cubic feet by the end of the week, which left our natural gas supplies 138 billion cubic feet, or 3.9% below the 3,553 billion cubic feet of gas that were in storage on September 25th of last year, but 79 billion cubic feet, or 2.4% above the five-year average of 3,336 billion cubic feet of natural gas that had typically been in working storage as of the 25th of September over the most recent five years….the 64 billion cubic foot injection into natural gas storage for the cited week was close to the 63 billion cubic foot injection into storage that the market had been expecting ahead of the report, while it was more than the 56 billion cubic foot of gas that were injected into natural gas storage during the corresponding week of 2025, but less than the average 80 billion cubic foot injection into natural gas storage that had been typical for the last week in September over the past five years…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending September 25th showed that after a big seasonal drop in our oil refining more than offset an increase in our oil exports, we had surplus oil left to add to our stored crude supplies for the the third time in twenty-three weeks, and for the 28th time in seventy weeks, despite an increase in demand for oil that the EIA could not account for…. Our imports of crude oil fell by an average of 179,000 barrels per day to 5,698,000 barrels per day, after falling by an average of 1,181,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 289,000 barrels per day to average 3,570,000 barrels per day, which, when used to offset our imports, meant that the net of our trade of oil worked out to an import average of 2,128,000 barrels of oil per day during the week ending September 25th, an average of 468,000 fewer barrels per day than the net of our imports minus our exports during the prior week... At the same time, transfers to our oil supplies from Alaskan gas liquids, from natural gasoline, from condensate, and from unfinished oils were 4,000 barrels per day higher than the prior week at 431,000 barrels per day, while during the same week, production of crude from US wells was 16,000 barrels per day higher at a record high of 13,965,000 barrels per day.  Hence, our daily supply of oil from the net of our international trade in oil, from transfers, and from domestic well production appears to have averaged a total of 16,514,000 barrels per day during the September 25th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,257,000 barrels of crude per day during the week ending September 25th, an average of 554,000 fewer barrels per day than the amount of oil that our refineries reported they were processing during the prior week, while over the same period, the EIA’s surveys indicated that a net of 20,000 barrels of oil per day were being added to the supplies of oil stored in the US… So, based on that reported & estimated data, the crude oil figures provided by the EIA appear to indicate that our total working supply of oil from net imports, from transfers, and from oilfield production during the week ending September 25th averaged a rounded 238,000 more barrels per day than what was added to storage plus our oil refineries reported they used during the week.  To account for the difference between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a [ -238,000 ] barrel per day figure onto line 16 of the weekly U.S. Petroleum Balance Sheet, in order to make the reported data for the supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus indicating there must have been a error or omission of that amount in the week’s oil supply & demand figures that we have just transcribed.... Since 215,000 barrels per day of oil supplies could not be accounted for in the prior week’s EIA data, that means there was a 453,000 barrel per day difference between this week’s oil balance sheet error and the EIA’s crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week’s report are somehow off by that much, and are therefore pretty useless….However, since most oil traders react to the figures in these weekly EIA reports as if they were gospel, and since these weekly figures therefore often drive oil pricing and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it’s published, and just as it’s watched & believed to be reasonably reliable by most everyone in the industry…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil supply, see this EIA explainer….also see this March 2023 twitter thread from an EIA administrator addressing these ongoing weekly errors, and what they had once hoped to do about it).

This week’s rounded 20,000 barrel per day average increase in our overall crude oil inventories came as an average of 132,000 barrels per day were being added to our commercial stocks of crude oil, while 112,000 barrels per day were being pulled out of our Strategic Petroleum Reserve, the twenty-seventh consecutive Iran war related withdrawal from the SPR, which left the SPR level at 283,767,000 barrels, the lowest since it was initially being filled in October 1982....Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports fell to 6,364,000 barrels per day last week, which was still 4.8% more than the 6,073,000 barrel per day average that we were importing over the same four-week period last year, while the four week average of our exports fell to 3,775,000 barrels per day last week, which was 7.1% less than the 4,064,000 barrel per day average that we were exporting last year year at this time... This week’s crude oil production was reported to be 16,000 barrels per day higher at a record high of 13,965,000 barrels per day as the EIA’s estimate of the output from wells in the lower 48 states was 3,000 barrels per day higher at 13,484,000 barrels per day, while Alaska’s oil production was 13,000 barrels per day higher at 468,000 barrels per day...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 6.5% higher than that of our pre-pandemic production peak, and was also 43.9% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021.

US oil refineries were operating at 92.5% of their capacity while processing those 16,257,000 barrels of crude per day during the week ending September 25th, down from 94.0% the prior week, but still high for mid-September….the 16,257,000 barrels of oil per day that were refined that week were 0.6% more than the 16,168,000 barrels of crude that were being processed daily during the week ending September 26th of 2025, and 1.5% more than the 16,017,000 barrels that were being refined during the pre-pandemic week ending September 27th, 2019, when our refinery utilization rate was at 86.4%, which was a bit below the pre-pandemic normal utilization rate for this time of year…

With the decrease in the amount of oil that was being refined this week, gasoline output from our refineries was also lower, decreasing by 124,000 barrels per day to 9,466,000 barrels per day during the week ending September 25th, after our refineries’ gasoline output had decreased by 54,000 barrels per day during the prior week... This week’s gasoline production was 1.3% more than the 9,344,000 barrels of gasoline that were being produced daily over the week ending September 26th of last year, but 7.3% less than the gasoline production of 10,081,000 barrels per day seen during the prepandemic week ending September 27th, 2019….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 156,000 barrels per day to 5,003,000 barrels per day, after our distillates output had decreased by 69,000 barrels per day during the prior week.  Even after those production decreases, our distillates output was 0.9% more than the 4,959,000 barrels of distillates that were being produced daily during the week ending September 26th of 2025, and 3.9% more than the 4,813,000 barrels of distillates that were being produced daily during the pre-pandemic week ending September 27th, 2019....

With this week’s decrease in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the twenty-sixth time in thirty-three weeks, decreasing by 1,684,000 barrels to 204,362,000 barrels during the week ending September 25th, the lowest since November 7th 2014, after our gasoline inventories had decreased by 1,686,000 barrels during the prior week.  Our gasoline supplies fell again this week even though the amount of gasoline supplied to US users fell by 158,000 barrels per day to 8,689,000  barrels per day, because our exports of gasoline rose by 94,000 barrels per day to 838,000 barrels per day, while our imports of gasoline rose by 99,000 barrels per day to 500,000 barrels per day.. After fifty-six gasoline inventory withdrawals over the past eighty-four weeks, our gasoline supplies were 7.4% lower than last September 26th’s gasoline inventories of 220,694,000 barrels, and about 7% below the five year average of our gasoline supplies for this time of year…

After this week’s decrease in distillates production, our supplies of distillates fell for the fifteenth time in thirty-three weeks, decreasing by 2,251,000 barrels to 105,180,000 barrels during the week ending September 25th, after our distillates supplies had decreased by 428,000 barrels during the prior week... Our distillates supplies fell by more this week even as the amount of distillates supplied to US markets, an indicator of domestic demand, fell by 27,000 barrels per day to 3,948,000 barrels per day, because our exports of distillates rose by 198,000 barrels per day to 1,529,000 barrels per day, while our imports of distillates rose by 68,000 barrels per day to 153,000 barrels per day... After 30 withdrawals from distillates inventories over the past 63 weeks, our distillates supplies at the end of the week were 14.9% below the 123,577,000 barrels of distillates that we had in storage on September 26th of 2025, and were about 14% below the five year average of our distillates inventories for this time of the year…

Finally, after the seasonal slowdown in our oil refining, our commercial supplies of crude oil in storage rose for the 11th time in twenty-six weeks, and for the 27th time over the past year, increasing by 922,000 barrels over the week, from 426,398,000 barrels on September 18th to 427,320,000 barrels on September 25th, after our commercial crude supplies had increased by 2,969,000 barrels over the prior week….After this week’s increase, our commercial crude oil inventories were about 2% above recent five-year average of commercial oil supplies for this time of year, and they were about 20.1% above the average of our available crude oil stocks as of the fourth weekend of September over the 5 years at the beginning of the past decade, with the difference between those comparisons arising because it wasn’t until early 2015 that our oil inventories had first topped 400 million barrels. After our commercial crude oil inventories had jumped to record highs during the Covid lockdowns in the Spring of 2020, then jumped again after February 2021’s winter storm Uri froze off US Gulf Coast refining, but then fell sharply due to increased exports to Europe following the onset of the Ukraine war, only to jump again following the Christmas 2022 refinery freeze-offs, changes in our commercial crude inventories had been less extreme up until the onset of the Iran war, when they were initially built up to a three year high by mid-April, before falling to the lowest in nearly eight years by late July…This week’s increase was the second following three decreases, and as of September 25th our commercial crude inventories were 2.6% above the 416,546,000 barrels of oil we had in commercial storage on September 26th of 2025, and were 2.5% more than the 416,931,000 barrels of oil that we had in storage on September 27th of 2024, and 3.2% more than the 414,063,000 barrels of oil we had left in commercial storage on September 29th of 2023…

This Week's Rig Count

The US rig count fell by one over the week ending October 2nd, as the number of rigs targeting oil was up by one, but the count of rigs targeting natural gas was down by two, while miscellaneous rigs were unchanged…for a quick snapshot of this week's rig count, we are again including below a screenshot of the rig count summary table from Baker Hughes...in the table below, the first column shows the active rig count as of October 2nd, the second column shows the change in the number of working rigs between last week’s count (September 25th) and this week’s (October 2nd) count, the third column shows last week’s September 25th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday of the same week of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting period a year ago, which in this week’s case was Friday, the 3rd of October, 2025…

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Ohio's fuel tax holiday includes gas and diesel, but no breaks for EV or hybrid owners | The Statehouse News Bureau -- The 90-day suspension of the state’s 38.5 cent tax on gasoline goes into effect Sunday. It’ll save drivers $5.77 on a 15-gallon fill up. While that may not be much to some Ohioans, it’s more than owners of hybrids and electric vehicles (EV) see from that gas tax holiday. The gas tax suspension doesn’t include any discounts for EV drivers, who pay $200 more to register them to pay for their use of roads because they use no gas. It also doesn't include breaks for owners of plug-in hybrids, who pay $150 more for using less gas, or for hybrid owners, who pay $100 extra. Sen. Casey Weinstein (D-Hudson) said a quarter of vehicles sold in Ohio are EVs or hybrids, and those motorists deserve a break too. "This is a significant number of Ohioans on the road who are paying their fair share through a registration fee, who are not getting any relief from the economic consequences of Trump's Iran war, and we owe them economic relief too," Weinstein said in an interview. Weinstein said he wanted the gas tax holiday legislation to include an amendment to provide discounts for those vehicle owners. "I had an amendment ready to go. Unfortunately, the Republican majority used a procedural motion to shut down all debate and all amendments on the bill," Weinstein said. "It really shut out a huge percentage of drivers on our roads who are paying their fair share, who are feeling economic consequences, who need relief, but who we weren't able to help because of that. So it's very frustrating." Other Democrats said they wanted to propose amendments as well, including a resolution urging an end to President Trump's war in Iran. Senate President Rob McColley (R-Napoleon) said of the motion to end debate on the bill: "We came in here saying that we made $725 million cost relief for Ohioans at a time when they need it the most. The Democrats, through some of the theatrics they were trying to pull, were trying to make it about anything other than that, which would be it very well jeopardized what we were trying to do here today. And our caucus thought it was important to get in and get the job done on behalf of Ohioans across the state who desperately need this relief." McColley is the running mate of Republican candidate for governor Vivek Ramaswamy. Last week Ramaswamy announced the plan to bring lawmakers back to the Statehouse from their campaigning break and pass the gas tax holiday. Ramaswamy's plan was unveiled following a call for a gas tax holiday from Democratic candidate for governor Amy Acton. The $726 million to cover the lost gas tax revenue, which goes to road construction and repair, will come from the state's general revenue fund. The initial gas tax holiday proposal from Republican legislative leaders had identified Ohio Department of Transportation funds as the source of replacement revenue, but the Office of Budget and Management said the $1.8 billion balance in ODOT's main operating fund had already been allocated to other projects.

Burned Worker Sues 2 Companies Over Ohio Wayne NF Well Blast - Marcellus Drilling News -   A year and a day after the Farnsworth #4 orphan well blew out and burned six people inside Ohio’s Wayne National Forest, one of the survivors went to court. Chazz Bates — a 20-year-old rig hand at the time — filed suit Aug. 21 in Washington County Common Pleas Court against his own employer, Monroe Drilling Operations LLC, and the cementing subcontractor on the job, Zanesville-based Formation Cementing Inc. The complaint, which also names 10 unidentified “John Doe” defendants, alleges the two companies skipped basic well control before pumping cement into a well nobody had pressure-tested — and that an ODNR inspector had flagged Monroe Drilling’s homemade wellhead as leaking and inadequate two months before the explosion.

Cause of deadly Rainbow Terrace Apartments explosion remains undetermined - City of Cleveland officials say that they could not determine the cause of an explosion that ripped through Cleveland's Rainbow Terrace Apartments in June 2025. Based on witness statements and surveillance footage, the Cleveland Division of Fire's Fire Investigation Unit believes that there was a rapid accumulation of natural gas in the lower levels of two of the complex’s buildings when an unknown heat source came in contact with the gas. That resulted in an explosion that caused widespread fire, heat and smoke damage June 23, 2025. Cleveland Fire Capt. Bob Zimmerer said during a news conference Monday that a security officer was approached by a juvenile who reported the smell of gas coming from one of the buildings. “He reported to him the odor of gas in the building,” Zimmerer said. “And then the officer himself, when he approached the building, stated he smelled strong, strong odor of the gas as well.” The investigators were unable to determine the cause of the gas leak or how it was ignited. "A light switch could do it, an appliance turning on or off, a refrigerator cycling on," all could have ignited the gas, said Zimmerer. The explosion and fire in Cleveland's Garden Valley neighborhood killed one person and displaced dozens of residents. The city has been under heavy pressure, including from former residents and Councilmember Richard Starr, to release the results of the investigation. Chief Director of Public Safety Dornat Drummond said that the sole responsibility for the investigation and determination if a gas pipeline failed, why it failed and if the operator, Enbridge Gas, complied with pipeline safety laws and regulations, falls on the Public Utilities Commission of Ohio. “In accordance with the established process, Enbridge conducted the inspection with oversight by PUCO,” Drummond said. “PUCO is the final decision-maker regarding gas pipeline failures. Enbridge, of course, the supplier, the pipeline operator, is required by the Federal Code of Regulations to investigate an incident involving its pipeline that resulted in a death, which this did, or a personal injury necessitating inpatient hospitalization.” Enbridge employed S-E-A, Ltd. to perform site inspections, laboratory examinations and testing based on the principles of NFPA 921, which is the National Fire Protection Association’s guide for fire and explosion investigations. S-E-A, Ltd. also did not reach a conclusion regarding the origin and cause of the explosion, though Enbridge concluded that the “apparent cause” of the explosion was ignition of leaking gas from the building-owned two-inch house line gas piping. PUCO’s investigation also did not find any compliance failures that could have caused or contributed to the explosion. PUCO’s report also stated that Enbridge performed an inspection and leak survey of the inside piping and meter manifold just 21 days before the explosion, though they outlined five deficiencies in Enbridge’s post-incident response. Zimmerer said that while the investigation has been titled “undetermined,” it does not mean the investigation is closed. “If new data or new technology comes to surface or arises, then that's always potential for more information,” Zimmerer said. Rainbow Terrace resident Cordale Sheffield, 32, died weeks later as a result of injuries he suffered in the blast. “Although the reports involved may not provide the answers many had hoped for, I hope that their release will provide some finality to this stage of the investigation and allow the community to continue the difficult process of healing,” Drummond said.

RINO Alert: Marietta Council Prez Endorses Democrat Amy Acton -- Marcellus Drilling News -  Susan Vessels, the Republican (we use that term loosely) president of Marietta, OH City Council, has endorsed Democrat Amy Acton for governor of Ohio. Why? Because Acton promised to honor Marietta’s call for a three-year moratorium on new wastewater injection wells. Vessels is so fixated on blocking injection wells that she’s willing to hand the governor’s office — and control of the agency that regulates Ohio’s oil and gas industry — to the woman who, as Ohio’s health director in 2020, signed the order that shut down the state. That’s not a Republican. That’s a RINO (Republican In Name Only).

Utica Shale Academy receives $900K to expand student transportation – WTRF - – More students are receiving rides to and from the Utica Shale Academy thanks to $900,000 in state rural transportation funds allocated in Ohio’s biennial budget through the efforts of several local state lawmakers. Bill Watson, superintendent of the regional trade school, said the funding has made it possible to increase its fleet of eight-passenger vans from seven to 17, all used to transport about 138 students to and from school. He expressed thanks to the local representatives for securing the funds. While based in Columbiana County, the school also serves students from Jefferson, Carroll, Mahoning and Stark counties. Watson said the additional vans have been a boost for multiple reasons. He said while some students got rides through public transportation or buses operated by local school districts, their schedules didn’t always mesh with those who work after school. Watson noted the vehicles also will serve as teaching tools, with students changing the vans’ oil and tires and performing other routine maintenance on them under the supervision of a trained instructor. He also said the additional vehicles are part of an ongoing effort that began a few years ago to ease access for students in the largely rural area served by the school. Watson said it resulted in better attendance and test scores. Additionally, Watson said chronic absenteeism at the school has been reduced by 6.2% while the number of students who haven’t undergone end-of-course proficiency testing has dropped from 14.7% to zero, with 9.3% more students demonstrating proficiency through the testing.

CenterPoint Energy completes $2.62B Ohio gas unit sale -  CenterPoint Energy completed the sale of its Ohio natural gas distribution business to National Fuel Gas Company for $2.62 billion on Tuesday, according to a press release statement. The transaction involved Vectren Energy Delivery of Ohio, which includes approximately 5,900 miles of gas transmission and distribution pipeline serving approximately 335,000 metered customers in West Central Ohio. The sale received all required federal and state approvals, including clearance from the Public Utilities Commission of Ohio. National Fuel Gas, headquartered in Western New York, assumed immediate responsibility for serving the former CenterPoint Ohio natural gas customers. CenterPoint stated the proceeds will support its $66.7 billion, 10-year capital plan focused on investments in electric and natural gas systems across its remaining utility footprint in Indiana, Minnesota and Texas. "We remain focused on executing our long-term strategy and investing in the electric and natural gas systems that serve the customers and communities across our core utility footprint," said Jason Wells, CenterPoint Chair and Chief Executive Officer. As of June 30, 2026, CenterPoint owned approximately $48.3 billion in assets and serves nearly 7 million metered customers across its remaining service territories. The company employs approximately 8,800 people. The divestiture represents CenterPoint’s exit from the Ohio natural gas market as it concentrates operations in its Texas, Indiana and Minnesota service areas.

Ohioans should be leery of data centers and secrecy they come with -George Banziger, Ph.D., of Marietta - Data centers upset the local economy and drive local people away who have lived here for generations and may wish to pursue much-needed agricultural pursuits.  State representatives Kevin Ritter, R-Marietta, and Justin Pizzulli, R-Scioto Valley, say people living in areas impacted by data centers should be measurably better off economically once they are built. If data centers − which exploit local natural resources with minimal benefit to communities − are like other natural resources extracted from Appalachian areas, there will be minimal benefit accruing to local communities.The representatives’ Aug. 28 Dispatch guest column, “A data center in Appalachia should help Appalachia,” is full of other claims about data centers that ignore actual facts.It’s well documented that the natural gas boom, which started in Ohio in 2008, did little to improve the local economy, raise employment levels or increase income levels of the average person living in southeast Ohio, according to “Frackalachia,” a comprehensive study by the Ohio River Valley Institute, a nonpartisan think tank analyzing those three factors in 30 fracked counties in Ohio, Pennsylvania and West Virginia. Stephen Stoll, in his book “Ramp Hollow,” chronicles in detail the long history of exploitation of the Appalachian region, starting with George Washington surveying the area for the Virginia elite, followed by its exploitation for timber, then coal, then natural gas – all for the benefit of outsiders.And now we have data centers.   Ritter and Pizzulli also claim decisions determining data centers “closest to home should be made closest to home.” Non-disclosure agreements, such as those developed in Ritter’s 94th District involving the Waterford community of Washington County, do nothing to bring data center decisions “closest” to home. In fact, the secrecy involved with NDAs is a major reason many locals are suspicious of them. Additionally, in the rural Waterford community, before a data center was proposed there, farmland sold at $3,000 to $5,000 per acre.Now data center developers are offering up to $35,000 an acre to use agricultural land to build hyperscale data centers.This upsets the local economy and drives local people away who have lived here for generations and may wish to pursue much-needed agricultural pursuits. Republican gubernatorial candidate Vivek Ramaswamy himself has said that data centers should be built on industrial sites, not farmland. There are ways data centers could be built to ensure positive outcomes for local communities. One way is the development of community benefit agreements, which ensure that local workers are hired for long-term employment at livable wages; greenspace is provided to local communities; funded apprenticeships leading to permanent jobs are arranged; annual reports of water and energy use are provided; and long-term studies of public health in the impacted areas are conducted.Data center developers may tell communities they will create hundreds of local permanent jobs, but the reality is that they lead to no more than a few dozen on average per data center, which is almost equivalent to the number of employees at one high school in our area.The track record for data center developers on telling the truth is not good and should not give any comfort to the people of Appalachia Ohio. Often, data centers are developed with no public notice, no public information sessions and no public hearings.  Of great concern is the rise in electric utility costs for residents, extreme water use and greenhouse gas emissions that cause respiratory disease, asthma, COPD and other health issues, in addition to heating our already-burning planet.Perhaps data centers would be more welcome in Appalachia and in Ohio if electric energy to power these centers relied more on renewable energy rather than just natural gas, a policy that the Ohio General Assembly follows that I would characterize as a war on renewables. According to the website Heatmap, 25 data center projects were canceled in 2025, and 60 local governments declared a moratorium on the development of data centers.Recent national polls have shown that fully 75% of Americans are opposed to data centers in their communities. This lack of popularity is shared by those in Appalachia and will continue as long as the historical exploitation of this region continues. Clearly, Ramaswamy is getting the people’s message on data centers when he says that there should be a moratorium on data center development until there is comprehensive data center regulation. As Ohio legislators, do Ritter and Pizzulli support Ramaswamy on this issue of a comprehensive regulation plan?

Appalachian Ohio and its people don't exist to be exploited by politicians and industry. Stop. ​Randi Pokladnik​, Ohio Capital Journal - More and more people are expressing their discontent with hyperscale data centers. A recent Gallup poll showed 70% are against hosting a large data center in their community. Concerns include: utility costs, water usage, environmental and health effects, and the use of these centers for AI surveillance.  The data centers of the early 2000s functioned like an interactive library/storage facility and were about 0.2 MW in size. Today’s hyperscale data centers cover 500+ acres of land, use more than 100MW of energy, and require billions of gallons of water each year. A proposed data center in Pike County (the PORTS Technology Campus) will cover 3,700 acres and will be the largest in the world at 8 GW: equivalent to the power used by all homes in Ohio.  Some politicians like Govs. Greg Abbott (Texas) and Josh Shapiro (Pennsylvania) have pulled back on their support for data centers, while Ohio Republican U.S. Sen. Bernie Moreno warns there is backlash against data centers. However, Trump and many of Ohio’s politicians, including the current Republican governor candidate Vivek Ramaswamy and state Reps. Kevin Ritter and Justin Pizzulli, have favored building data centers across our communities. In order to avoid pushback from farmers in Ohio who object to using prime farmland for massive data centers, some politicians like Reps. Ritter and Pizzulli are suggesting that brownfields (areas with significant contamination issues) be used for data centers. Brownfields can be abandoned mines and shuttered industrial sites, and many are located in the Appalachian regions of the state. Rural communities near brownfields have been exploited in the past; why allow data centers to once again extract their water and energy and use their land?  Additionally, brownfield sites like the retired R.E. Burger coal-fired power plant in Belmont County must secure funding for clean-up efforts. JobsOhio spent 70 million to clean up the R.E. Burger site and demolish the plant to pave the way for a plastics-making ethane cracker. The cracker was never built. For decades the Ohio Valley has experienced pollution and health effects from industries, power plants, and steel mills that occupy both sides of the Ohio River.  Until the fracking boom, coal was the energy source for those industries. Coal combustion emissions include: carbon dioxide, sulfur dioxide, nitrogen oxides, particulate matter, and toxic heavy metals like mercury. In 1976, I worked as a college intern on the prominent Harvard School of Public Health Six Cities Study. The study focused on pollutant particles less than 2.5 microns in diameter because these travel deep into the lungs. Steubenville, Ohio was chosen as a city for the study because of the high levels of air pollution. One of the main conclusions of the study was that “Exposure to air pollution contributes to excess mortality.”  The results were so substantial that they led to a revision of air quality standards by the EPA. The combustion of methane (fracked gas) also releases many air pollutants, and is the energy choice of most data centers in Ohio.The emissions from a gas turbine include: 2.5 micron particulate matter, carbon monoxide, carbon dioxide, nitrogen oxides, and formaldehyde.A recent study, “Air Quality, Health, and Economic Impacts of the Proposed MZX Tech Facility,” discovered that emissions from the proposed methane gas turbines (1.2-GW MZX Tech) for xAI’s Colossus 2 data center would result in increased risks of heart disease, stroke, respiratory illness, asthma exacerbation, and premature death for local citizens. Several environmental groups, including Earthjustice, filed a lawsuit against the U.S. Environmental Protection Agency for fast-tracking the approval of two data center chemicals classified as PFAS compounds.PFAS chemicals are toxic “forever compounds” that do not break down in nature.The EPA acknowledged that “both chemicals pose potentially severe risks to public health”, but the EPA “does not know the level at which the chemicals are acutely lethal or cause other serious health damage.”The EPA granted approval for immediate use anyway.Additionally, PFAS compounds are used in immersion cooling systems for data centers, and while this cooling technique does reduce water usage, it significantly increases exposures to; toxic hydrofluoric gas, endocrine disrupting compounds, and reproductive toxins. These chemicals not only affect workers who are involved in manufacturing the components, but also the data center workers and local communities living near data centers. Reps. Ritter and Pizzulli failed to mention anything about the health and safety issues associated with data centers. The huge PORTS data center will be located at the site of the radioactively contaminated Portsmouth Gaseous Diffusion Plant. This facility enriched uranium in Pike County from 1954 to 2001. Will the PORTS data center bring more illness to a region already suffering from legacy pollutants?  Data centers will not make our communities a “benefit zone,” but rather a sacrificial zone, and communities will not be “measurably better off.”Data centers also pose potential risks in the form of fires and exposures to toxic compounds.  Local firefighters and emergency personnel, many of whom are volunteers, are often excluded in the preparation of Emergency Response Plans for these mega facilities. “Contributing causes of such fires include electrical faults, battery failures, cooling system malfunctions, and human error.”Recently, Moreno touted the Trump Administration’s $45 million dollar grant directed at breathing life into the coal-fired Cardinal plant which sits along the Ohio River; close to where I grew up.Once again, propping up a dirty fossil fuel project to increase power availability is disingenuous given Ohio’s politicians killed 5.3 GW of wind and solar projects in the past dozen years.Additionally, Moreno’s claim that data centers do not drive-up utility costs for consumers has been proven false by peer-reviewed studies. Trump’s Executive Order 14318 was a gift to data center CEOs; allowing “qualifying projects” to by-pass the National Environmental Policy Act, modify the US Environmental Protection Agency (EPA) regulations and environmental protection statutes, and find ways to work around the Endangered Species Act. Finally, the elephant in the room is the ridiculous amounts of carbon dioxide generated from using fracked gas for data centers’ electrical production.Whether centers tie into the PJM grid, which is heavily invested in fossil fuels, or use behind-the-meter methane fuel cells or gas-turbines, they will be using an energy source that has multiple health and environmental issues associated with it.The PORTS center could emit 53.4 million tons of greenhouse gases annually at full capacity.Appalachian communities are tired of false promises of jobs and money from outsiders and corporate PR representatives.President Trump might think we are “backwards and poor” but we realize data centers are just another extractive industry that will pollute our land, water and air, take our resources, and leave us with the health effects.

Shale Insight: Meta Says Behind-the-Meter Gas Is the Model That Works -- Marcellus Drilling News - Meta’s energy chief closed Shale Insight 2026 by explaining how gas-fired power built “behind the meter” helped the company bring its first gigawatt-scale AI cluster online in Ohio. She had a message for the gas patch: if you have a site with plenty of power and a community that wants a data center, call her. But not everyone on stage was so sure about how fast data center demand will grow. An energy analyst and Expand Energy’s CFO both warned that forecasts may be running ahead of reality.

HydroEdge Solutions Acquires Majority Interest in RES Water  - HydroEdge Solutions has acquired a majority interest in RES Water, creating a combined water management platform serving natural gas producers across the Marcellus and Utica shale regions in Pennsylvania, Ohio and West Virginia. The transaction was completed through WET Tech, HydroEdge’s newly formed parent company, which acquired Reserved Environmental Services and its affiliated operating companies. Financial terms were not disclosed. The combined business will provide water management services across the drilling and production lifecycle, including pipeline and on-pad management, hauling, treatment, recycling and storage. It will employ approximately 350 people and operate five treatment, recycling and storage facilities across Pennsylvania. The platform will have approximately 700,000 barrels of storage capacity and processing capacity of up to 116,000 barrels per day. It will also operate an automated water transfer and trucking network serving the broader Appalachian Basin. “This transaction creates the platform to do the same in energy services, and we will continue to pursue both organic and acquisitive growth across Appalachia,” said Matt Brewer, CEO of the combined company and co-founder of HydroEdge. Management expects the combination to reduce trucking miles, expand water reuse and improve service coverage while creating opportunities for additional infrastructure investments and acquisitions. The transaction was financed through a senior secured credit facility arranged by Atlantic Union Bank Capital Markets. Atlantic Union Bank serves as administrative agent and sole lead arranger, with EagleBank and Dollar Bank participating as lenders. Canonsburg, Pennsylvania-based HydroEdge was founded in 2013 and provides water logistics, automation and trucking services for hydraulic fracturing operations. RES Water, founded in 2008 and based in Bridgeville, Pennsylvania, operates four water treatment, recycling and storage facilities in the state.

16 New Shale Well Permits Reported for PA-OH-WV Sep 21 – 27 -- Marcellus Drilling News - The Marcellus/Utica region received 16 new drilling permits last week, September 21 – 27, down 1 from the 17 permits issued two weeks ago. Pennsylvania issued 6 of the new permits. Ohio also issued 1 new permit. And West Virginia issued 9 new permits. The drillers who received new permits last week were: Antero Resources, Ascent Resources, Beech Resources, Expand Energy, and Range Resources. Antero Resources | Ascent Resources | Beech Resources | Bradford County | Doddridge County | Expand Energy | Harrison County | Lycoming County | Noble County | Range Resources Corp | Washington County | Wetzel County

DEP - Day 700: Seneca Resources Continues To Manage Contaminated Water From Taft Shale Gas Well Pad In Tioga County - On September 23, 2026, the Department of Environmental Protection did a follow-up inspection of the Seneca Resources Taft 851 shale gas well pad in Middlebury Township, Tioga County to determine the status of contaminated water cleanup from a 2024 and continuing incidents.DEP found operations were under way to pump fluids down a Taft shale gas well while a well at the nearby Chappell shale gas well pad was being fracked to reduce communication between the wells. Forty-eight frac tanks were staged in secondary containment for use during the operation.Field tests confirmed contaminated fluid in the sediment basin and at the central stormwater sump continued to be present as a result of operations at the well pad."The DEP recommends that Seneca continues to monitor the conditions on the pad surface and the sediment basin and remove elevated conductance fluids and soils as discovered. Prevent elevated conductance fluids from leaving the facility and causing pollution to the waters of the Commonwealth." Violations at the well pad were continued now for 700 days. DEP did not request a write follow-up from Seneca.  Click Here for DEP inspection report + photos.  Violations for the wastewater releases at the Taft site were originally issued on October 23, 2024.DEP found similar conditions-- spills, crews trying to clean up the pad while drilling and fracking new shale gas wells continues-- starting October 23, 2024, then on  July 11, 2025,  August 21, 2025, October 2, 2025, October 31, 2025, December 23, 2025, January 21, 2026, April 21, 2026, June 23, 2026 and July 17, 2026.   A July 27, 2026 inspection of the 75HU Utica shale gas well at this same Taft shale gas well pad found evidence of continuing casing/cementing failure originally discovered on Nov. 13, 2024. The violation was continued and so will the monitoring. DEP inspection report.  On October 31, 2025, Attorney General Dave Sunday announced criminal charges against Seneca Resources, LLC, following multiple violations of Pennsylvania’s environmental protection laws in several counties, as recommended by the 48th and 51st Statewide Investigating Grand Juries.Three separate criminal complaints were filed regarding the natural gas company’s violations related to improper waste management practices and policies.Prominent in the Attorney General’s announcement of the charges was the fact that DEP repeatedly warned Seneca that their practices were not in line with Pennsylvania law, but those warnings were ignored or disputed. Read more here.In all, Seneca is charged with 64 counts of violations of the Solid Waste Management Act and 36 counts of violations of the Clean Streams Law in Cameron, Clearfield, Elk, Jefferson, Lycoming, McKean, Potter, Tioga Counties. Read more here. To report oil and gas violations or any environmental emergency or complaint, visit DEP’s Environmental Complaint webpage. Text photos and the location of abandoned wells to 717-788-8990.

DEP: Pipeline Excavation Hits Conventional Oil & Gas Well Drill Cuttings Disposal Area At Eastern Gas Transmission Oakford Gas Storage Area In Westmoreland County - On September 24, 2026, the Department of Environmental Protection inspected an Eastern Gas Transmission & Storage Inc. pipeline excavation area near the Oakford Gas Storage Reservoir after notification that a drill cutting disposal pit was uncovered in Salem Township, Westmoreland County. Eastern Gas Transmission was constructing a 20-inch natural gas pipeline between two gas storage facilities when excavation uncovered a conventional oil and gas drilling disposal pit for drill cuttings near a conventional well owned by Eastern Gas Transmission on September 23. Dark gray matter and pieces of liner were found in the excavation area. [Conventional oil and gas well owners are allowed by DEP to dispose of drill cuttings in lined pits at the site of well drilling rather than take them to a waste disposal facility.] Near the top of the excavation area, the DEP also observed water seeping out of the upslope hill side, into the excavation area and a pump at the bottom of the excavation area pumping water into a frac tank for disposal. Contaminated soil and drilling cuttings from the excavation area were being stockpiled on a plastic liner and contaminated material was also being loaded into two roll-off boxes. DEP did field testing and took soil samples from the site as well as water samples from Beaver Run downslope from the excavation. Multiple violations were issued for exposing a drill cuttings disposal area and DEP requested a response by October 13. Click Here for the DEP inspection report + photos.

DEP: Equipment Failure At Catalyst Energy Injection Well Results In Contaminated Water Discharges In Keating Twp., McKean County - On September 28, 2026, the Department of Environmental Protection inspected the Catalyst Energy Inc. LOT 580 580-1 oil and gas wastewater injection well in response to a notification of a spill of contaminated water in Keating Township, McKean County. DEP found the failure of filter equipment caused the release of contaminated water from the filter building where the water was being processed at the site. [There was no secondary containment around the filter building based on photos of the site.] The company said an employee noticed a leak coming through the side of the filter building and when he opened the door “fluid immediately discharged onto the well pad and over the southern edge of the well pad.” Field testing by DEP found “numerous fingers/pockets of elevated specific conductance within an approximate 30' x 100' area beyond the southern edge of the well pad where the discharged fluid that originated from the filter building ran over the edge of the well pad, given the vegetation was pushed down from the flow. “Significant iron staining was also evident in several areas where the specific conductance was elevated.” A second discharge point and area of impact was also discovered at the southeast corner of the well pad about 75 feet from the first discharge. “This point of interest appears to originate from within or underneath the fill used to construct the location, as elevated specific conductance readings were not observed on the surface of the fill above where elevated readings and staining were observed at the natural elevation.” “The impacted area beyond the well pad consists of previously delineated Exceptional Value wetlands and is partially within the floodway of an UNT of Kinzua Creek. At this time, it does not appear that the nearby UNT of Kinzua Creek has been impacted.” Initial estimates by the company reported about 840 gallons of contaminated water were released. Multiple violations issued. DEP requested a response by October 15. Click Here for a copy of the DEP inspection report + photos.

DEP - Day 873: Contaminated Water Still Leaking From Stonehaven Energy Conventional Oil & Gas Well Storage Tank In Clearfield County - On September 29, 2026, the Department of Environmental Protection did a follow-up inspection of the Stonehaven Energy MGT Co., LLC Walls 3 conventional oil and gas well in Bloom Township, Clearfield County and found contaminated water was still leaking from a storage tank. DEP last inspected the site on July 17, 2024 and found the same conditions. The original violations related to the release of contaminated water were issued on May 9, 2024. DEP reported in July 2024 “NOVs mailed to the owner were returned by the USPS “return to sender.”” During the September 29 inspection, DEP found “exposed soil and dead vegetation was observed extending [about] 48 ft. from the brine tank with the widest part being [about] 12 ft. “ DEP field tested the path of the release to confirm it was contaminated and took soil samples. DEP said “no cleanup appears to have been conducted.” “The Department strongly suggests pursuing Act 2 [Land Recycling Program] for site remediation.” DEP continued the 2024 violations for the well, but did not set a deadline for a response.Click Here for the DEP inspection report + photos.  To report oil and gas violations or any environmental emergency or complaint, visit DEP’s Environmental Complaint webpage. Text photos and the location of abandoned wells to 717-788-8990.

DEP Issues 21 More Violations For Abandoning, Not Plugging Conventional Oil & Gas Wells To 17 Companies In 11 Counties; Total Of 46 Abandoned Well Violations In September -  In September, the Department of Environmental Protection issued or continued 21more violations to 17 conventional oil and gas well owners for abandoning and not plugging their wells in 11 counties.These are in addition to--

• -- 16 violations issued to Mifflin Energy Resources LLC for abandoning and not plugging wells in Washington and Greene Townships, Greene County.  Read more here.
• -- 6 violations issued to American Natural Resources LLC for failure to comply with an order to plug abandoned wells in Allegheny County.  Read more here.
• -- 3 violations issued to HR McClure for failure to plug abandoned wells in Greene County. Read more here.
• DEP also did inspections of nearly 300 abandoned conventional oil and gas wells as part of the federally-funded Well Plugging Program during September.
• The additional violations were issued to--
• Allegheny County
• -- Plum Boro: McGuffie Oil Co. Inc. - CG Mallasse 3 - 9.25.26
• -- Oakmont Boro: S&F MGMT LLC - Edgewater Steel 5, Edgewater Steel 6 - 9.28.26
• -- Trafford Boro: D&B Gas Production Inc. - Trafford Center 1 - 9.4.26
• Armstrong County
• -- Madison Twp: MGPR LLC - M. Douthett 1 - 9.2.26
• Butler County
• -- Parker Twp: B&K Partnership - Bruce & Kevin Smith 1 - 9.1.26
• -- Oakland Twp: Brighter Properties LLC - Waltman 1 - 9.28.26
• Cambria County
• -- Munster Twp.: Vessels Coal Gas Inc. - Gergely 1 - 9.3.26
• Erie County
• -- Erie City: Kingsley United Methodist Church - Kingsley UM Church 1 - 9.21.26
• -- Erie City: St. Lukes Catholic Church - St. Luke Ch 1 - 9.30.26
• -- Harborcreek Twp: Erma L. Berry - Berry 1 - 9.18.26
• -- Harborcreek Twp.: Gannon University - Gannon Farm 1 - 9.18.26
• Fayette County
• -- Perry Twp.: James E. Brumage - John E. Matway 1, John E & Anna Matway 4 - 9.24.26
• Greene County
• -- Wayne Twp.: HR McClure - JB Coen 14 - 9.2.26
• Somerset County
• -- Stonycreek Twp.: Alloy Energy LLC - Thomas Benson 1 - 9.29.26
• Venango County
• -- Cranberry Twp.: Stonehaven Energy MGMT Co. LLC - BW Bredin 659 - 9.21.26
• -- Irwin Twp.: S.C. Hoffman - Rober E & Merle Gilmore 2 - 9.22.26
• Washington County
• -- Hanover Twp: Prosperity Oil Co. Inc. - G. Tennan 2, G. Tennan 7 - 9.17.26
• Westmoreland County
• -- Unity Twp: Michael Harju - James N. Johns 1 - 9.25.26

Details on each of the wells are available through DEP’s Inspection Reports Viewer webpage using the company name and date of inspection.

Alpha Compute Update on Operating Oil and Gas Assets Due Diligence in Pennsylvania, Securing 300+ Acres Across the Marcellus and Utica Shales - -- Alpha Compute Corp., a vertically integrated technology pioneer in Sovereign Intelligence, Confidential Compute and GPU-as-a-service, today announced an update on the Alpha Energy 02 transaction, first announced on September 22, 2026 with a total purchase price is USD $5.5 million. Last week, Alpha Compute’s oil, gas, and minerals leadership visited the property to review additional due diligence documents, met with the sellers/managers, and toured the pad sites. Information on the operations, financials, on-site verification of well resources, and equipment inventory were obtained and completed. Evaluation of log files from one natural gas test well into the Marcellus shale indicates substantial recoverable gas resources across multiple formations linked to the acquired land and mineral rights. Supplemented by potential unconstrained production-type curves from adjacent analog wells of two producing shallow gas wells, these reserves correspond to an estimated 200 MW of power generation capacity dedicated to Alpha Compute data center planned for Q1 2028. Beyond providing on-site, behind-the-meter power for planned data center developments, the transaction encompasses over 75 active oil wells with an estimated 2.9 million barrels of remaining oil-in-place. The acquisition delivers a stacked-resource position on more than 300 acres of surface, mineral and gas rights spanning both the Marcellus and Utica shale formations. The assets include:

• One natural gas test-well with proven natural gas reserves;
• More than 75 existing, producing oil and shallow gas wells with complete pump jack inventories;
• Operational maintenance facilities, heavy equipment and associated gathering infrastructure; and
• Full surface control, enabling co-location of power generation and compute on the same parcel.

Historical documentation and test-well logs obtained in due diligence from an assessment estimates approximately 10,000 barrels per acre of light Pennsylvania-grade sweet crude oil across the subsurface parcels, implying roughly 3.0 million barrels of original oil in place across the acquired acreage. Preliminary evaluations indicate that only an estimated 4% of that volume has been extracted to date, leaving approximately 2.9 million barrels of oil in place. For context, at prevailing West Texas Intermediate prices of roughly $90 per barrel in late September 2026, the remaining in-place volume carries an illustrative gross, undiscounted value on the order of $260 million. Based on standard primary-recovery rates of 5% to 15% for shallow Appalachian crude, estimated recoverable reserves range from 145,000 to 435,000 barrels. At current market rates, this projects to roughly $13 million to $39.1 million in gross top-line revenue, prior to royalties, taxes, and operational expenses. Backed by more than One decades of documented financial history, the current wells remain active and cash-flow positive today. A planned workover capital expenditure of approximately $3.5 million is projected to restore field output to these higher historical rates. One test-well is the near-term catalyst. Horizontal wells completed in the Pennsylvania Marcellus and Utica typically recover on the order of 10 to 20 billion cubic feet (Bcf) of natural gas each over their producing lives, implying combined estimated ultimate recovery of approximately 20 to 40 Bcf for the One wells, depending on lateral length, completion design and reservoir quality. Bringing both wells online is expected to cost approximately $10 million to $12 million per well. At an illustrative realized price of $2.00 to $2.50 per MMBtu, reflecting Henry Hub pricing of roughly $3.00 less Appalachian basis differentials, the One wells alone represent approximately $40 million to $100 million of gross lifetime gas revenue if sold to market. Across the full 300-acre block, the stacked Marcellus and Utica formations are estimated to hold roughly 50 to 70 Bcf of recoverable gas, supporting additional drilling locations beyond the One existing wells. Alpha Compute does not intend to simply sell this gas. Consumed on site through simple-cycle generation at approximately 7.5 MMBtu per megawatt-hour, initial combined production of 20 to 40 million cubic feet per day from the One wells could support roughly 100 to 200 MW of generation capacity at first production, with the combined 20 to 40 Bcf of recoverable gas sufficient to sustain approximately 30 to 60 MW of continuous load for a decade. This converts a commodity exposed to Appalachian basis discounts into low-cost, dispatchable power for AI compute. "We paid $5.5 million for an operating business that produces oil and cash flow today, and that sits on roughly 2.9 million barrels of oil in place and one gas well ready to complete," said Enzo Villani, Executive Chairman and President of Alpha Compute Corp. "Our updated geological work, modern appraisals and third-party reserve engineering are underway, and we expect them to support a substantial revaluation of these assets on our balance sheet. In the meantime, the site pays for itself." "This acquisition gives Alpha Compute something few AI infrastructure companies have: the fuel, the land and the compute on a single asset," said Brittany Kaiser, CEO of Alpha Compute Corp. "With one well already drilled. Completing them is the fastest path in Pennsylvania to behind-the-meter power for our next data center, and we will do it under Pennsylvania DEP oversight, in partnership with the county and with the local community at the forefront of our plans."

Precision Drilling Settles 15-Year PPE Overtime Suit for $1.9M - Marcellus Drilling News - How long does it take a rig hand to pull on coveralls, lace up steel-toed boots, and grab a hard hat? According to Precision Drilling’s own expert, about 2.6 to 4.1 minutes per shift. According to the workers’ lawyers, a lot longer. After 15 years, two trips to the Third Circuit and one to the U.S. Supreme Court, the two sides have split the difference, and it will cost Precision $1.9 million. On Monday (Sept. 22), both sides filed a joint brief in Williamsport federal court asking Judge Matthew Brann to approve the deal. It covers 1,006 hourly rig workers, some of whom worked Precision rigs right here in the Marcellus. The dollars are small. The legal rule the case left behind for Pennsylvania is not.

EQT Loses Bid to Toss WV Kids Health Lawsuit; 4 of 5 Claims Survive -- Marcellus Drilling News - -A federal judge in Pittsburgh has ruled that two EQT subsidiaries must face most of a lawsuit filed on behalf of four West Virginia kids who claim that emissions from EQT’s shale wells and a nearby compressor station made them sick. On Sept. 23, U.S. District Judge Robert Colville threw out just one of the five claims, a request for a medical monitoring trust fund, and he gave the kids’ lawyers 21 days to fix and refile it. The rest of the case moves forward. That includes a “strict liability” claim that EQT had argued West Virginia law flat-out does not allow against oil and gas operations. It’s a pleading-stage ruling, not a verdict. Even so, it’s a loss for EQT, and it’s one the whole industry should watch. Read More

Chatham County, NC Commissioners Vote to Fight Enbridge Pipe - Marcellus Drilling News - - Chatham County, North Carolina’s Board of Commissioners last week unanimously passed a resolution opposing Enbridge Gas North Carolina’s proposed 28-mile natural gas pipeline from Siler City to Moncure. This isn’t a garden-variety “we don’t like it” resolution. It authorizes the county to actively fight the project by challenging environmental permits, teaming up with like-minded groups, working the media, organizing residents, and coaching landowners on how to resist condemnation. In other words, a county government just signed itself up as a Big Green activist group, with taxpayers picking up the tab.

NJ Hits Vineland Data Center with $1.07M Fine Over 62 Gas Generators -- Marcellus Drilling News –-New Jersey regulators have fined the company building a giant AI data center in Vineland (Cumberland County, South Jersey) $1.07 million for installing and running 62 large natural gas-fired generators without air permits. The NJ Department of Environmental Protection (DEP) calls it “by far the largest” enforcement action ever taken against a data center in the Garden State, and “possibly one of the largest such actions in the nation.” Our math: those 62 engines add up to nearly 123 megawatts (MW) of gas-fired power, running behind the meter at a site that is supposed to become a 300 MW data center serving Nebius and, through Nebius, Microsoft. The developer, DataOne, says the engines are temporary until Bloom Energy fuel cells (which also run on natural gas) take over, and it will now apply for permits.

Shale Insight: Lack of Pipes Leaves Appalachia Out of LNG Boom -- Marcellus Drilling News - Expand Energy, the country’s largest natural gas producer, opened Shale Insight 2026 with a price forecast and a warning. Marcel Teunissen, Expand’s Chief Financial Officer, predicted gas prices of $3.50 to $4.00 through 2030 and $4.00 to $4.50 from 2030 to 2035, with plenty of volatility along the way. The warning was that most of the new gas needed to meet Gulf Coast LNG demand won’t come from Appalachia, because there aren’t enough pipelines to get it there. The Haynesville will fill the gap instead.

Marcellus Gas Fetches $1.59 While Florida Pays $3.96: Blame Pipes -- Marcellus Drilling News - Here’s a number that should make every Marcellus/Utica landowner and driller wince: $1.590. That’s what gas at the Tennessee Zone 4 Marcellus hub is fetching for October delivery, according to NGI’s Forward Look. Meanwhile, down in Florida, the very same molecule (quite possibly gas that started life in a Pennsylvania or West Virginia well) is priced at $3.960 for October. That’s a $2.37 gap, which means Florida buyers are paying 2.49 times what our local hubs get. The culprit? Not enough pipe heading south. And this week, one of the few big southbound pipes we do have, Mountaineer XPress, sprang a leak.

U.S. LNG Feedgas Holds Steady Despite Cove Point Offline  -U.S. LNG feedgas demand was essentially flat last week as stronger intake across most terminals offset the maintenance outage at Cove Point. Total U.S. LNG feedgas demand averaged 18.3 Bcf/d for the week ending September 28 (blue-dotted line below), virtually unchanged week-on-week. Intake rebounded at Cameron, coupled with smaller increases at other terminals, offsetting the loss from Cove Point, according to our LNG Voyager Weekly Report. Cove Point shut down for annual maintenance on September 19. The terminal is currently not taking feedgas and the outage is expected to last around three weeks. Intake at Cameron LNG rebounded to full contracted utilization after being reduced the week prior because of pipeline maintenance on Columbia Gulf Transmission.  Intake strengthened at most of the U.S. terminals, and all (except Cove Point) are operating at or above full utilization, with Calcasieu Pass and Plaquemines especially strong and operating at peak levels. Intake at the commissioning Golden Pass also strengthened last week, with feedgas above 0.5 Bcf/d for part of the week and averaging 0.4 Bcf/d last week.

Propane/Propylene Stocks Decline as Exports Continue to Grow | RBN Energy  EIA reported a total U.S. propane/propylene inventory draw of 1.2 MMbbl for the week ended September 18, with essentially all of that total coming out of PADD 3 and driven by rising reported exports. Total stocks fell to 107.9 MMbbl but remained 8 MMbbl, or 8%, above the same week in 2025 and 6.4 MMbbl, or 6%, above the five-year maximum. Inventories were also 17.5 MMbbl, or 19%, above the five-year average. PADD 3 (Gulf Coast) propane inventories fell by 1,192 Mbbl to 68,434 Mbbl. Inventories were 8.5 MMbbl, or 14%, above both the same week in 2025 and the previous five-year maximum. Stocks were 17.7 MMbbl, or 35%, above the five-year average. Weekly propane exports reported by the EIA averaged 2,469 Mb/d, up 256 Mb/d from the prior reporting week and 270 Mb/d above the four-week average of 2.2 MMb/d

ConocoPhillips Adds Venture Global Deal to Expanding LNG Portfolio - ConocoPhillips is deepening its bet on US Gulf Coast LNG, signing a long-term supply deal with Venture Global that extends a recent run of 20-year-plus contracts for US export capacity. At a Glance:

• Buyers lock in long-duration US supply
• Venture Global adds 1 Mt/y buyer
• ConocoPhillips expands long-term LNG portfolio

Petrobras Signs Long-Term Deal to Lift Cargoes from Cheniere Terminals - Cheniere Energy said Tuesday it signed its first long-term agreement with Brazil’s state-owned Petrobras LNG to sell the company the super-chilled fuel for more than 20 years. At a Glance

• Petrobras will purchase 0.8 Mt/y
• Term covers 22 years
• SPA underpins Cheniere expansions

U.S. Propane Inventories Climb as Exports Sink | RBN Energy -  The EIA reported a 1.8-MMbbl build in total U.S. propane/propylene inventories for the week ended September 25, lifting stocks to 109.6 MMbbl (red line in the chart below). The build exceeded both the industry-expected increase of 470 Mbbl and the average build of 1.6 MMbbl for the week. Stocks are 6.3 MMbbl, or 6%, above both the same week in 2025 (blue line) and the five-year maximum, and 17.7 MMbbl, or 19%, above the five-year average (green line). The build was concentrated on the Gulf Coast, where PADD 3 inventories increased by 2 MMbbl to a record 70.4 MMbbl. The increase more than accounted for the nationwide build, as Midwest inventories declined and gains in the other regions were relatively small.U.S. propane exports fell sharply this week, decreasing by 800 Mb/d to 1.67 MMb/d (red line in the chart below). Exports were 409 Mb/d, or 20%, below the four-week average of 2.08 MMb/d (green dashed line) and 337 Mb/d, or 17%, below the 2.01 MMb/d reported for the same week in 2025 (blue line). The decline coincided with a larger-than-expected build in U.S. propane inventories, leaving the combination of elevated stocks and lower exports to watch as the market moves into the seasonal draw period.   

Bolstered by One-Two Demand Punch, South Louisiana Spot Prices Lead Lower 48 --Daily natural gas prices in South Louisiana, home to national benchmark Henry Hub, are on average the highest in the country as the market nears the end of September. US natural gas prices for the National Avg., Henry Hub and South Louisiana regional average from May through September 2026.   At a Glance:
South Louisiana prices lead nation
Regional hubs far above average
LNG, heat and storage key factors

NYMEX Gas Jumps 9.75% for Week on WV Pipeline Leak, Storage - Marcellus Drilling News - - The front-month October NYMEX natural gas futures contract settled Friday (Sept. 25) at $3.196 per MMBtu, up 28.4 cents, or 9.75%, for the week. That’s a nice week to be long gas. Most of the fireworks came on Thursday, when a leak on TC Energy’s Mountaineer XPress (MXP) pipeline in West Virginia knocked roughly 1.8 Bcf/d of Appalachian takeaway offline and sent futures up 9.06% in a single day, the biggest one-day gain since January (see WV Pipeline Leak Knocks 1.8 Bcf/d Offline, Gas Futures Jump 9.1%). Traders gave back 10.1 cents on Friday after Columbia Gas Transmission said it had found the leak and expected to fix it over the weekend. Even so, the contract ended the week at its highest Friday close since early July.

Natural Gas Drops As Mountaineer XPress Return Is Expected To Lift Daily Output - Natural gas settled down 2.1% at ₹293.7 as expectations of rising US production weighed on prices following the return to service of the Mountaineer XPress pipeline in West Virginia. The Columbia Gas Transmission unit of TC Energy lifted the force majeure on the pipeline, which had affected around 1.4–1.8 billion cubic feet per day of flows from the Marcellus and Utica shale regions, raising expectations of stronger supplies in the coming days. LSEG reported average US Lower 48 gas production at 112.3 billion cubic feet per day so far in September, matching the record monthly level seen in August, although daily output was expected to fall temporarily to 107.5 bcfd due partly to pipeline maintenance. US gas inventories also remained an important market factor, with the Energy Information Administration reporting a 53 billion cubic feet storage injection for the week ended September 18, matching analyst expectations but below the 77-bcf build recorded during the same week last year and the five-year average increase of 76 bcf. Despite strong summer demand for power generation, inventories have remained supported by record production. The EIA expects US dry gas production to rise from 107.6 bcfd in 2025 to 111.2 bcfd in 2026 and 116.0 bcfd in 2027, while domestic consumption is projected at 92.0 bcfd in 2026 and 94.8 bcfd in 2027. LNG exports are forecast to increase to 17.4 bcfd in 2026 and 18.6 bcfd in 2027. Meanwhile, speculative net shorts declined by 27,105 contracts to 27,158, indicating a substantial reduction in bearish positioning.

US Natgas Prices Fall for 3rd Session -  US natural gas prices slipped more than 1.5% to around $3.05 per MMBtu on Tuesday, marking a third consecutive decline as forecasts pointed to limited heating and cooling demand. The NOAA’s latest outlook calls for mostly near-normal temperatures across the eastern US over the next two weeks, reducing expectations for a significant increase in gas-fired power consumption. In addition, Columbia Gas Transmission lifted force majeure on Sunday after resolving a mechanical problem, allowing production to increase in the coming days. Analysts estimate inventories were 2.4% above normal in the week through September 25, compared with 2.9% previously. Meanwhile, feedgas deliveries to nine major US export facilities averaged 17.9 bcfd in September, up from 17.2 bcfd in August.

Long Time – Economics, LNG Exporters’ Needs to Determine Which Gulf Coast Gas Storage Gets Built -- Just a few years ago, natural gas storage capacity along the Gulf Coast was widely available at low cost, but that has all changed. The operators of existing and planned LNG export terminals have locked up most of the old storage surplus and much of the incremental storage capacity on the drawing boards. But more storage is needed, and the competition among developers to provide that space is heating up. There will be winners and losers. In today’s RBN blog, we begin an in-depth series on Gulf Coast gas storage — why the market flipped from bust to boom, what’s being planned, and how to predict which projects will make it over the finish line.The scale is enormous. More than 350 Bcf of new gas storage capacity — most of it salt cavern storage with high injection and withdrawal rates — is known to be under active development in Texas, Louisiana and Mississippi, and it’s safe to say that at least a couple more projects are still flying under the radar. There are several drivers behind this ongoing, multibillion-dollar buildout, chief among them (1) the proliferation of new and expanded LNG export terminals along the Gulf Coast and (2) terminal operators’ need for a place to quickly store large volumes of gas in the event of a liquefaction plant outage.  This is key: Without nearby storage capacity to serve as an at-the-ready buffer for gas supply, terminals could expose themselves to major financial losses, either by not having the gas they need to operate or, most ominously, by being forced to dump billions of cubic feet of gas into the market during an outage event. In essence, gas storage serves as relatively low-cost insurance. (Note that, as a rule of thumb, an LNG export terminal requiring 800 MMcf/d of feedgas should have 15 to 20 days of storage capacity — that is, 12 to 16 Bcf — under contract.)To a lesser degree, new gas storage capacity is also needed to manage gas flows along the Gulf Coast, which have increased sharply in recent years due to Permian gas production growth and new LNG export, industrial and power demand. Power generators — many of them tied to planned AI data centers — need backup sources of gas supply if regional gas and power demand soars or traditional supplies are interrupted.As you may recall, Gulf Coast gas storage capacity saw a massive overbuild in the late 2000s. There were two major catalysts. First, the Energy Policy Act of 2005 provided that if a storage owner could show a lack of market power, its rates could be “market-based,” attracting more marketers and traders into the storage game. Second, back then almost everyone thought that the U.S. was running out of natural gas and would soon have to rely on huge volumes of LNG imports to keep pace with demand — and that gas storage would be needed to receive and manage those imported volumes.Instead, the Shale Revolution happened, and gas production in the Permian, Haynesville and other U.S. shale plays grew by leaps and bounds. By the 2010s, the Gulf Coast had way more gas storage capacity than it needed and storage rates plummeted. As we all know, several of those LNG import terminals in Texas and Louisiana were repurposed as LNG export facilities, new liquefaction plants were built, and the Gulf Coast quickly ramped up the volumes of LNG it was sending out.The new LNG export capacity was welcome news to gas storage owners, whose previously underutilized facilities were suddenly a hot commodity. LNG terminal operators quickly locked up the storage space they needed and, as you would expect, storage rates started to rise. (More on storage rates to come.)More recently, a second wave of LNG export projects in Texas and Louisiana has been advancing to final investment decision (FID), financing, construction and, in a few cases, operation. LNG terminal operators with liquefaction/export capacity coming online in 2026-28 have already secured almost all of the storage space left from the last boom-and-bust cycle and, once that was spoken for, entered into long-term commitments with developers to underwrite much of the buildout of new gas storage capacity in the region, most of it expansions at existing (i.e., brownfield) storage facilities. Many of those storage projects are now being built.Still more storage capacity will be needed beyond what has already been sanctioned, however, and the developers of LNG export projects coming online in 2029 and beyond are scrambling to line up capacity at storage projects that have not yet reached FID. But storage developers have proposed more storage space than is likely to be needed, so there’s a fierce competition among them to line up commitments from LNG terminal operators, power generators and other potential customers.As shown in Figure 1 above, most of the incremental storage capacity under development is either greenfield salt cavern facilities (blue dome icons) or expansions to existing salt cavern operations (green dome icons) along a roughly 250-mile stretch of the Gulf Coast from the Tres Palacios storage operation in Matagorda County, TX, to the Jefferson Island Storage & Hub (JISH) in Vermilion Parish, LA — an area also dotted with several existing and proposed LNG export terminals (solid and striped pink diamonds, respectively). A handful of depleted gas reservoir facilities (orange triangles) have also been proposed, mostly away from the coast (and coastal salt deposits) in northeast Texas.Salt cavern storage offers several benefits over depleted gas reservoir facilities. Most important by far, salt caverns offer considerably higher gas injection and withdrawal rates — a must-have for LNG export terminals and other customers that may need to “park” large volumes of gas within a short period of time. (That benefit comes in part from the fact that a salt cavern functions as a large underground tank, with gas flowing freely into or out of the cavern via the wellbore. In a depleted reservoir, gas is stored in microscopic pore spaces within sandstone or carbonate rock and doesn’t flow in or out as freely.) Also, salt caverns require considerably less “base” or “cushion” gas — that is, the amount of gas that needs to remain within a storage facility to maintain pressure and physical integrity. Typically, a salt cavern needs only 20% to 30% of cushion gas, compared to 50% or more for a depleted reservoir.As we said earlier, LNG terminal operators, power generators, and utilities have already locked up most of the excess storage capacity that was left over from the decade-long period of overbuilding. The competition to secure the incremental storage capacity that will be needed for the current wave of LNG export development has been heating up, as evidenced by strong responses to storage-project open seasons and higher capacity prices — prices north of 20, 25 and even 30 cents per dekatherm (dth) per month are now common, compared to prices south of 10 c/dth per month a few years ago.The scramble for incremental gas storage space in Texas and Louisiana doesn’t mean that every pre-FID project — or even most — will succeed in lining up the long-term commitments needed to make their economics work. Salt cavern storage development in particular has always been an expensive and time-consuming undertaking, and in recent years the massive demand for compressors, piping and all kinds of other equipment has sent project costs soaring.  That gives an economic edge to existing storage owners/operators and brownfield storage projects, whose costs can be minimized by the extensive use of existing infrastructure such as header systems/gas-pipeline interconnections, compressors, water pipelines and brine ponds. In contrast, greenfield projects, many of them backed by private equity, must start from scratch — and their extra costs may make at least some uncompetitive.Other factors that impact a project’s odds for success in the current environment include its location, size, connectivity to existing and planned gas pipelines — LNG export terminal operators typically want storage that is nearby and directly linked — and injection and withdrawal rates, which are important determinants in how much of a buffer the storage will actually provide.As we’ll discuss in more detail later in this series, gas storage projects that offer all or most of these attributes — among them, an experienced developer with an existing brownfield site, extensive pipeline connectivity, a location near LNG export terminals, and a direct link to those terminals — should have an edge over new players, greenfield sites, and proposals with less-advantaged locations. There’s a wildcard in all this, though: Some long-term storage players with strong pipeline networks, etc., can make even a questionable project work due to their marketing skill. Similarly, a seemingly promising project can fail if the developer lacks the marketing expertise to make a go of it. In the upcoming blogs in this series, we will discuss in more detail the boom-bust-and-boom cycles in the Gulf Coast gas storage market over the past quarter century and their impact on storage rates. (Spoiler alert: Rates for new projects are at all-time highs.) We’ll also look at the types of storage deals different customers (LNG export terminals, power generators/utilities, and gas marketers) enter into. We’ll conclude with blogs on the many storage projects being planned — brownfield salt cavern jobs, greenfield salt cavern projects and depleted reservoirs — and their prospect.

Google Data Center Anchors 550,000 Dth/d NGPL Natural Gas Expansion in Texas - Natural Gas Pipeline Company of America LLC (NGPL) is asking the Federal Energy Regulatory Commission (FERC) to approve a 550,000 Dth/d pipeline expansion in the Texas Panhandle that would ship natural gas to power a planned Google data center.NGI NGPL Midcontinent natural gas price chart showing daily spot prices in 2026 and forward prices through 2036, with seasonal winter peaks near $4.50/MMBtu. At a Glance:
New compression adds 321,200 Dth/d
Existing capacity covers 228,800 Dth/d
Texas permit freeze clouds timeline

Comeback Story? – New Pipelines Boost Permian Natural Gas Economics, But Oil Still Drives Activity | RBN Energy -- The Permian has up to 11 Bcf/d of new natural gas takeaway capacity scheduled to enter service through the end of 2029, with still more coming in the early 2030s. The central question is whether Permian crude oil production will generate enough associated gas to fill that capacity and, if so, how quickly. The short answer is there appears to be enough incremental capacity to provide a near-term runway, but higher gas prices and new egress are not materially changing most producers’ oil-led development strategies. In today’s RBN blog, we’ll discuss how producers may respond to the new gas pipelines planned for the Permian.This is the third blog in our series on the outlook for major U.S. producing basins, starting with the largest: the Permian. In our first blog, we covered the major gas pipeline projects expected to enter service this year and next. Together, the Gulf Coast Express (GCX) expansion, Hugh Brinson Pipeline and Blackcomb Pipeline will add about 5.3 Bcf/d of egress capacity from the Waha area. Our forecast calls for Permian production to grow by 11.2 Bcf/d from 2026-36, with the strongest growth concentrated in 2027-29. That growth could absorb a meaningful portion of the new takeaway over time, particularly as LNG and other Gulf Coast demand expands. Given the scale and timing of the projects, however, some pipelines could initially operate below capacity rather than being fully utilized from the start.Kinder Morgan’s GCX expansion (0.57 Bcf/d; aqua-blue line in Figure 1 below) is already flowing more gas to the Agua Dulce Hub in South Texas. The expansion lifted the pipeline’s total capacity to 2.6 Bcf/d and has helped the Waha Hub recover from negative prices, though it has not fully resolved Permian takeaway constraints. Energy Transfer’s Hugh Brinson Pipeline (medium-blue line) is ramping up flows to Northeast Texas and will eventually have a capacity of 2.2 Bcf/d. The Blackcomb Pipeline (dashed red line) is still in the commissioning process but is expected to enter full commercial service by the end of this year, providing an additional 2.5 Bcf/d of takeaway to Agua Dulce, while the planned 2.4-Bcf/d Traverse Pipeline (dashed light-pink line) will provide onward access from Agua Dulce to the Katy/Houston area in 2027. Part 2 of our series looked at projects farther down the road. The 48-inch-diameter, 3.7-Bcf/d Eiger Express pipeline (dashed dark-green line) is expected to begin service from the Permian to Katy in mid-2028 with 2.5 Bcf/d at first, followed by the remaining 1.2 Bcf/d in mid-2029. Energy Transfer’s Desert Southwest Project (dashed light-green line) is an expansion of its Transwestern Pipeline system expected to enter service in Q4 2029 and raise the Permian’s westbound takeaway capacity to as much as 5.5 Bcf/d, from 3.2 Bcf/d today.A consortium led by WhiteWater Midstream reached a final investment decision (FID) in August on the Solitude Pipeline System, which will have the capacity to take an astonishing 4.5 Bcf/d of gas from the Permian to Katy by the early 2030s. Solitude (dashed dark-pink line) will consist of two 48-inch pipelines, each capable of transporting 2.25 Bcf/d. WhiteWater has been operating the Matterhorn Express pipeline (dark-blue line) since late 2024. Other projects currently under construction include Blackfin (dashed orange line), which would provide a route for Permian gas to reach Jasper County, TX, where it will connect with CP Express (dashed yellow line) to the coast. The Trident Pipeline (dashed light-purple line), in turn, will add another downstream outlet from Katy, moving gas toward the Port Arthur LNG corridor.With takeaway capacity expanding and Waha prices back in positive territory, Permian gas economics are improving. But the first half of the year showed how quickly they can weaken when takeaway is constrained. The question is whether stronger gas realizations will change how Permian producers allocate capital — or simply improve the economics of oil-focused development. Producers in the basin don’t often say much about gas production, but this year has been an exception, given the sharp swings in gas economics and the major changes underway in Permian pipeline capacity.Next, let’s look at how the basin’s top producers are expecting things to play out in the coming years.  ExxonMobil is the Permian’s largest producer with 4.4 Bcf/d of gross operated wellhead gas output, according to Novi Insights, and offers a clear example of the industry’s oil-first mindset. (Note: Novi Insights figures are gross wellhead volumes on an operated, two-stream basis and therefore differ from company-reported net production figures). During ExxonMobil’s Q2 2026 earnings call, management highlighted continued growth in Permian production. Asked whether new gas pipelines coming online could prompt a material increase in gas production from the basin, Chairman and CEO Darren Woods said ExxonMobil does not expect to change its strategy anytime soon. “As we're developing wells, we're looking at the economics. There's a clear incentive to have higher oil production,” Woods said. “As you look at economically maximizing the value of every well, you want more oil and less gas, given the constraints in the gas market. I think that's not going to change.” Additional takeaway capacity, in Woods’s view, would not turn gas into the primary target. Instead, it would remove a constraint on oil development. “If you’ve got the takeaway capacity, it just opens up your ability to produce more oil and the gas then comes with it,” he said. Devon Energy, next in line with around 3.2 Bcf/d of gross operated wellhead gas production, was direct about the commercial risks tied to Permian gas. In its Q2 2026 earnings, management said weak Waha pricing was challenging, but argued the company is relatively well protected by its marketing arrangements. More than 70% of Devon’s production is either covered by financial hedges or backed by firm transport to the Gulf Coast, CFO Shane Young said. The company expects its exposure to improve further as additional egress becomes available later this year and as Blackcomb enters service in H1 2027. Still, Devon does not appear to view new takeaway as a reason to alter its underlying Permian development strategy. Young said the gas-market challenge is “not going away,” while acknowledging that growing LNG exports and power demand could create more pricing volatility farther downstream along the Gulf Coast. Occidental Petroleum Corp. (Oxy) produces about 2.6 Bcf/d of gross operated wellhead gas production in the Permian and was impacted by the basin’s gas economics in Q2 2026. The wide Waha-to-Gulf Coast spread pushed Occidental’s domestic upstream realized gas price to about negative $1.50/Mcf, roughly $2.50/Mcf lower than in Q1 2026, CFO Sunil Mathew said during the company’s earnings call. As new Permian takeaway capacity narrows that spread, Oxy expects its upstream gas realizations to improve. The benefit to domestic upstream earnings should largely offset lower income in its midstream segment, which had benefited from wider regional spreads. In short, better gas egress should make Oxy’s Permian barrels more valuable by improving the price received for associated gas. ConocoPhillips is also a major gas producer in the Permian, with 2.5 Bcf/d gross operated wellhead gas production, but offered little discussion on natural gas in its Q2 2026 earnings call. Management highlighted record Permian production of 920 Mboe/d and focused its operating commentary on oil recovery, well productivity, longer laterals and capital efficiency, without discussing Permian gas volumes or Waha exposure or identifying gas takeaway as a driver.EOG Resources, which has about 2.4 Bcf/d of gross operated wellhead gas production in the Permian,remains more oil-focused, particularly on high-return oil opportunities. “When it comes to our exploration program, we’re probably slightly more biased on the oil side, but honestly, it really comes down to returns for us,” Chairman and CEO Ezra Yacob said. “Ultimately, I think we cheat just a little bit towards being a little more optimistic or a little more exploration-focused on the liquid side of things, just because the margins tend to be quite a bit greater than on the gas side.”Other producers have shown that they can respond quickly to local gas economics, although the larger question is how much they affect basin-wide production. Diamondback Energy describes gas as additive to its value proposition, rather than a core focus. Permian Resources, meanwhile, has shown it will curtail wells with a high gas-to-oil (GOR) ratio; when Waha prices turned sharply negative in Q2 2026, the company cut gas production by about 20%. It returned the curtailed wells to service as prices recovered. Matador Resources also reported shut-in volumes during the quarter, citing both weak Waha prices and third-party plant maintenance.Taken together, we see a Permian gas market improving without yet changing the basin’s oil-first development model. Better gas realizations can improve well-level economics, particularly in higher-GOR areas, and new takeaway should reduce one of the basin’s biggest constraints. But for gas to become a more meaningful driver of capital allocation, producers would need greater confidence that netbacks will remain attractive after gathering, processing and transportation costs. That would require more than pipeline capacity alone. Stronger and more durable gas prices, reliable downstream demand, and sufficient connectivity to Gulf Coast and LNG markets would all help support a more sustained increase in gas-directed development.

Diesel Cracks the Ceiling, Closing above $100/bbl for Two Straight Weeks | RBN Energy  - Sept 23 - Diesel cracks shifted into overdrive the last two weeks, leaving double-digit territory in the rearview mirror. As we discussed in our Crude Billboard for the week ended September 18, the diesel crack skyrocketed to a record high of $113.48/bbl on Wednesday, September 16 before easing to $108.10/bbl on Friday (far right of green line in chart below). Diesel cracks have now settled above $100/bbl every day since September 9, turning what was recently a brief spike into a sustained stretch of extraordinary refining economics. The benchmark 3-2-1 crack (blue line) rose 10% to $74.46/bbl, helped by a rebound in gasoline cracks (orange line). Diesel remained the defining feature of the barrel: its crack finished the week more than $50/bbl above gasoline’s and at more than three times its year-ago level. Fall maintenance would normally pull refinery runs lower in the coming weeks. However, with diesel margins this strong, refiners have a compelling reason to keep units running where they can, limiting the seasonal decline. The question is how long those runs can rise to meet diesel demand before they begin to cool the crack.

Leap of Faith – Potential Plans to Limit U.S. Diesel Exports Come With Plenty of Downside Risk | RBN Energy - It’s been a banner year for U.S. refiners, especially those able to consistently run at high rates and maximize their production of diesel. The U.S. Gulf Coast diesel crack spread surpassed $100/bbl for the first time in August and has remained elevated ever since, driven by a series of disruptions to global refining capacity and refined-product flows significant enough to raise the prospect of a ban on U.S. diesel exports as a way to keep prices in check. In today’s RBN blog, we look at where things stand and how a U.S. export ban could result in a number of unintended short- and long-term consequences.Geopolitical tensions and upset trade flows have been the central theme of this year’s energy markets. Middle Eastern refineries have been affected by damage inflicted during the Iran conflict and disruptions around the Strait of Hormuz, while Russian refining and exports have been repeatedly set back by Ukrainian drone attacks. Those developments come at a time when global refining capacity is already tight due to a number of permanent shutdowns (many during the COVID years) and limited new capacity coming online (a subject addressed in detail in our recently released Future of Fuels report), leading to sharply higher prices for crude oil and refined products.The diesel market is particularly exposed to those types of disruptions because global supply remains constrained and demand is comparatively (vs. gasoline) resilient, leaving little cushion when disruptions occur. The U.S. has historically been the biggest supplier of diesel to the global market, so it should be no surprise that exports have increased this year, with foreign buyers pulling harder on a system that is already near its limit. U.S. distillate exports (blue line in Figure 1 below)  averaged about 1.4 MMb/d in H1 2026, up from 1.25 MMb/d in 2025 and about 7X the volumes from 20 years ago. Imports have also declined this year, leading to a record level of net exports (orange line).As we said in Basket Case, the record-high crack spread is also being influenced by extremely high Renewable Identification Number (RIN) prices. (A RIN is the regulatory mechanism for tracking the production and blending of renewable fuels and also allows refiners and importers to prove they’ve met their Renewable Volume Obligation, or RVO, mandates.) We also said in that blog that refiners have little capability to simply run harder, as the refining system is essentially full, with the Gulf Coast (PADD 3) reaching all-time record runs of over 9.7 MMb/d earlier this month and utilization rates above 98%. This year’s higher prices — plus the U.S. midterm elections, which are a little more than a month away — have left some government officials looking for ways to decrease the pressure on U.S. consumers and businesses.  So far, Jones Act waivers and the early end to summer gasoline requirements have helped, but only on the margin. The Trump administration is assumed to be considering a number of measures to provide additional relief, such as using the Defense Production Act to increase refinery capacity/efficiency and extending logistics waivers, although they are likely to produce only additional marginal improvements at best. The most dramatic step would be an outright ban (or severe limitation) on diesel exports, but taking that step — even for a very short time — has the potential to produce a wide range of unintended (and negative) consequences. Below are a few examples of how things could play out for refiners and consumers in the short and long term, although for brevity there are numerous potential impacts not detailed here. The U.S. produces more diesel than it consumes (which is why it’s a net exporter), so any ban or restriction on exports is likely to create a short-term domestic surplus and lead to initially lower prices. The first place we would expect to see an impact is along the Gulf Coast, home to most U.S. refinery capacity and the source of the large majority of diesel exports. If roughly 1.7 MMb/d of diesel (the U.S. weekly average since July, per EIA data) were prevented from being exported while refinery operations initially remained unchanged, the surplus would build quickly — by about 11 MMbbl per week. That’s equivalent to more than 10% of current U.S. distillate inventories. The market could not absorb those barrels for very long. Prices would have to fall far enough to discourage refinery output (more on that in a bit), stimulate domestic demand where possible and, importantly, make alternative outlets economically viable. While prices for Gulf Coast ultra-low-sulfur diesel (ULSD) could initially fall by a fairly large amount, the impacts are unpredictable and would likely vary significantly by region. Also of note, such a policy would likely cause RIN prices to skyrocket farther since these policies would push the soybean oil-ULSD differential much wider. Renewable diesel and biodiesel production margins, however, would likely still fall since the RIN price rise would be expected to only partially offset the wider soybean oil-ULSD differential.There would also be a significantly negative global impact. Removing 1.7 MMb/d of U.S. exports from an already tight market would push diesel prices substantially higher elsewhere as buyers compete for replacement barrels. A McKinsey analysis of a proposed refined products export ban in 2022 estimated that removing about 1.4 MMb/d of U.S. products could require a roughly $25/bbl increase in international product prices to bring marginal supply into the market. With global diesel inventories already unusually low and refinery capacity already stretched, the adjustment would likely be even more pronounced today. It’s also worth noting that previous well-intentioned (if sometimes ill-conceived) attempts by the government to control prices, such as after the 1973 oil embargo, have not been successful. Marketers always find clever ways to skirt the system. The implications of an export ban get more challenging after the initial shock to prices and barrels in storage. U.S. refiners produce more than 5 MMb/d of petroleum diesel, versus domestic consumption of less than 4 MMb/d. Refiners can tweak yields, but they cannot eliminate a surplus of that size through optimization. The initial response would likely come in stages. Refiners could move away from maximum-distillate operating modes, shift yields toward gasoline and naphtha where units allow, and push more diesel into domestic storage. But once tanks begin to fill and diesel economics deteriorate, the only lever remaining would be reducing crude throughput.At first, refinery runs, at least outside California, would change relatively little as the system absorbs the initial surplus, but that wouldn’t last long. As early as the second week, U.S. crude runs would start to decline noticeably, with the most immediate and major impacts likely felt in California, which along with the Gulf Coast is a net exporter of diesel and very limited on storage capacity. Within a month, a sustained ban could push the U.S. reduction in crude runs beyond 1 MMb/d, with ever-deeper cuts likely the longer the restrictions persisted and no alternative outlets emerged. If the policy persisted for more than 2-3 weeks, the Gulf Coast would bear the bulk of the adjustment, in absolute terms. With the region’s refinery utilization already in the high 90s%, a prolonged ban could push utilization down into the 80s%, with the exact level varying depending on how quickly inventories accumulate, with significant variation between individual refineries.With an export ban in place, U.S. diesel prices could have a two-stage trajectory. Retail diesel prices would initially move lower as inventories rose. But once refiners started to cut diesel production, the inventory build would start to slow and diesel prices would likely recover from their initial lows, although not necessarily back to today’s levels. It’s also important to remember that refiners cannot stop making diesel without also affecting gasoline, jet fuel and other products, so any move to shift yields away from diesel would impact other fuels too, potentially pushing up prices for those products even as diesel prices moved lower. As such, gasoline prices would likely increase considerably, especially once U.S. refiners start to cut throughput rates. California (which, as mentioned earlier, has also become a net exporter of diesel due to renewable mandates) and the surrounding states would likely be the first to feel this impact and would probably see the largest increase in gasoline prices, due to the high cost of long-haul imports necessary to replace the supply lost from refinery cutbacksAn export ban would also have a major impact on Latin America, especially Mexico. Mexico (green slice in Figure 2 below) was the #1 destination for U.S. distillate in H1 2026 with a 15.7% share. Regional neighbors Chile (dark-green slice), Ecuador (purple slice), Peru (light-blue slice), Brazil (dark-blue slice), Panama (brown slice), Guatemala (pink slice) and Argentina (black slice) made up most of the Top 10.  A ban would force Mexico to replace substantial volumes with barrels from places such as Europe, India, China or other Latin American suppliers (assuming that they could even find replacement barrels). That would likely mean higher landed diesel prices in Mexico, longer voyages, greater freight expense, more pressure to maximize Pemex refinery production (which likely isn’t even doable), heavier inventory draws and potentially tighter supply in northern Mexico. To add some perspective to Mexico, specifically, about 40% of Mexican diesel demand is supplied via U.S. imports. As such, Mexico (and much of the rest of Latin America) would likely face not only increasing diesel prices, but also physical shortages of the fuel. The global market is poorly positioned to replace any lost U.S. barrels. China raised its refined product exports to about 1 MMb/d in August, but even if it raised exports further, those volumes would not come close to making up for lost U.S. barrels. A ban or restriction on U.S. diesel exports might provide some very near-term relief to diesel consumers, but it could carry a much bigger long-term cost: undermining the economics of future refinery investment. As we noted in our most recent Future of Fuels report, U.S. refiners remain globally advantaged by scale, complexity, low-cost natural gas, flexible crude access (except for PADDs 1 and 5) and (especially in the case of the Gulf Coast) access to growing export markets. With domestic petroleum demand offering limited growth, incremental refinery expansions increasingly need access to global markets to justify the capital. Restricting diesel exports would effectively cap that upside. U.S. transportation-fuel exports averaged 2.4 MMb/d in 2025, with distillate — mostly diesel — accounting for more than half the total. That export outlet matters because U.S. refining capacity already exceeds domestic requirements in key regions, particularly PADD 3, which produced more fuel than it consumed even after capacity declined in 2025. Lower export realizations and greater regulatory uncertainty could also discourage debottlenecking, expansions and other investments, accelerating the shift from growth to rationalization. So, a policy aimed at increasing domestic fuel availability today could leave the U.S. with less refining capacity — and less supply flexibility — down the road. An export ban could be even more damaging for the West Coast (PADD 5), which has seen refining capacity move sharply lower over the past several years but remains a significant exporter of diesel today, shipping out about 120 Mb/d in H1 2026. (That’s a distant second to PADD 3 but well above the other PADD regions and significant relative to total regional diesel production.) PADD 5 refiners are challenged by high regulatory costs, declining regional gasoline demand and new inbound pipelines, such as the proposed Phillips 66/Kinder Morgan Western Gateway Pipeline. We already expect the region’s refining capacity to drop by about 1.2 MMb/d by 2050 to keep regional supply/demand in balance, so any mandated reduction in diesel exports, even for a short period, has the potential to encourage those capacity reductions to happen sooner rather than later. It’s important to note that even if a ban were only implemented for a short time, the mere precedent set by such a policy would remain a key negative factor in investment/closure decisions refiners make in the future.There’s also the potential upset to longtime trading patterns. This year’s market disruptions have served to highlight the U.S.’s role as a reliable supplier of all types of energy commodities, but an export ban could undermine those efforts and encourage other countries to diversify their supply mix away from the U.S., a concern noted during a fireside chat at our recent School of Energy: Fundamentals. (Click here for details on School of Energy Encore, a full replay of our conference that includes complete slide decks, Excel models and online-only material.)A diesel export ban might sound like a straightforward way to lower prices, but refined-product markets rarely cooperate with simple solutions. The initial benefit to U.S. consumers of diesel would give way to lower refinery runs, higher prices for other fuels, tighter supplies in international markets (especially to key allies) and, eventually, less U.S. refining capacity. With the U.S. now an essential supplier to a tight global market, restricting exports could reshuffle trade flows and investment decisions in ways that linger long after the ban ends.

Motor Gasoline Inventories Plummet to 12-Year Low as 3-2-1 Crack Spread Soars to All-Time High - Refiners have a strong incentive to keep running, but gasoline inventories are still struggling to keep pace. According to the EIA’s Weekly Petroleum Status Report (WPSR) for the week ended September 25, U.S. motor gasoline stocks declined 1.7 MMbbl to just above 204 MMbbl, their lowest level since November 7, 2014.  As discussed in this week's Crude Billboard, the Midwest remains particularly tight, with PADD II inventories falling to approximately 41.8 MMbbl, nearly 6 MMbbl below the same week in 2025 and the lowest level on record for the region. One particular refinery outage to note was Exxon’s Joliet, Illinois refinery. Its 275 Mb/d CDU was shut at 3:16 pm on September 13 due to a power outage.That thin inventory cushion leaves little room for production losses as fall maintenance and unplanned outages reduce refinery throughput. The supply squeeze has helped keep all eyes on this year’s extraordinary refining economics. Gasoline cracks surged to $68.74/bbl midweek (far right of orange line in chart below) before easing to just above $60/bbl at Friday’s close, three times their year-ago level, helping push the benchmark 3-2-1 crack to a record $80.63/bbl (blue line in chart below). Together, those margins provide a compelling reason for refiners to sustain elevated runs where operating schedules allow, even as maintenance limits their ability to replenish depleted product inventories.

A Matter of Trust – Variations in Crude Oil Quality Make On-Spec Delivery Critical for Global Refiners | RBN Energy - As anyone who has ever bought a used car knows, appearances can be deceiving. Two vehicles may look nearly identical from the outside, but what’s under the hood can make all the difference in performance, reliability and value. The same principle applies to crude oil, as barrels that meet the same basic specifications can still behave very differently once they reach a refinery. In today’s RBN blog, we conclude our look at crude quality by examining why maintaining consistent specifications has become more challenging as Permian production has grown, blending practices have evolved, and WTI Midland has become a cornerstone of global crude pricing.As anyone who has ever bought a used car knows, appearances can be deceiving. Two vehicles may look nearly identical from the outside, but what’s under the hood can make all the difference in performance, reliability and value. The same principle applies to crude oil, as barrels that meet the same basic specifications can still behave very differently once they reach a refinery. In today’s RBN blog, we conclude our look at crude quality by examining why maintaining consistent specifications has become more challenging as Permian production has grown, blending practices have evolved, and WTI Midland has become a cornerstone of global crude pricing. As discussed in Part 1, crude oil is not a uniform commodity; each stream has a unique chemical composition that affects its value and how it performs throughout the supply chain. The two primary measures of crude quality are API gravity (density) and sulfur content. In general, crude oils above about 35 degrees (°) API are considered light (blue-shaded rows in Figure 1 below); those between roughly 25° and 35° API fall into the medium category (pink-shaded rows); and anything lower than 25° is heavy (green-shaded rows). Sweet crude has relatively little sulfur, typically less than about 0.5%, while sour crude contains more than that. Light, sweet crudes generally produce higher yields of valuable products like gasoline, diesel and jet fuel with less refining, while heavier or more sulfur-rich crudes require additional processing and involve higher costs. Other quality factors — including distillation characteristics, molecular composition, carbon residue, acidity, metals and mercaptans — also influence refinery efficiency, equipment reliability, catalyst performance and overall market value.Crude quality has become increasingly important as West Texas Intermediate (WTI) at Midland has taken on a larger role in global oil markets, including its inclusion in the Brent benchmark. Because WTI is marketed as a light, sweet, low-contaminant crude, maintaining consistent quality is essential for buyers and refiners. But quality can differ between barrels of crude from different locations, even if it is considered the same grade. When exporting crude from the U.S., there are four load regions we typically look at: Corpus Christi, Houston, Beaumont and Louisiana. Recent attention has focused on elevated levels of metals such as iron, nickel and vanadium, which can damage refinery equipment and reduce crude value. As a result, stricter testing, blending controls, pipeline standards and quality specifications help ensure that WTI remains a reliable and fungible global benchmark. Those standards are essential because European refineries are typically not as complex as their U.S. counterparts, meaning they are not able to filter, manage and tolerate contaminants as well as the more complex refineries are able to do.The observed sulfur limit on Platts WTI Midland stands at 0.2% and cargoes loaded from the Gulf Coast prior to Midland’s inclusion in the Brent benchmark trended between 0.09%-0.15%, while other contaminants didn’t garner as much attention. But in the past couple of years, reports have begun to pop up highlighting concerns about elevated iron and other metals in a small number of shipments, prompting tighter quality checks and closer enforcement. A recent example occurred at the Texas International Terminal in the Houston area. Details remain limited, but Platts stripped the terminal of its Brent eligibility earlier this year. Its removal was likely not linked to one singular issue, but rather a combination of off-spec quality concerns, draft limitations and schedule impacts, where it is believed the vessel arrived outside of the allocated window. WTI Midland can still be loaded from the terminal, but the barrels shipped are not currently being factored into Dated Brent price formation, and uncertainty remains about how long the terminal’s “probationary period” will last.. There are several reasons why crude quality has become more difficult to ensure in recent years:

• Upstream gathering systems are becoming increasingly complex. As production spreads over a wider area and more streams feed into shared lines and hubs, crude characteristics can vary more from batch to batch.
• Evolving blending practices are another factor. Operators often combine different streams to meet pipeline specifications or optimize logistics, but crude oil produced in different formations can have varying characteristics (see Iron Man). For example, crude oil from the Wolfcamp formation (yellow-shaded area in Figure 2 below) in the Permian Basin contains higher iron content than formations in the surrounding areas.
• Conditions inside an area’s pipeline infrastructure could also play a role. Over time, pipeline corrosion or internal scale buildup might introduce small amounts of iron into crude moving through the system.

Global supply dynamics may also be influencing the market (and impacting crude quality and blending) in less-direct ways. One example is West Texas Sour (WTS), a Permian-produced grade that typically receives strong demand from regional refineries for asphalt production and as a blendstock to bring lighter crudes down to WTI gravity specifications. WTS has seen increased pricing volatility recently, with premiums to Domestic Sweet (DSW) as high as $4.45/bbl and discounts as low as $4.90/bbl (orange line in Figure 3 below) in the last few months. Several factors are likely at play. Global light-heavy crude differentials widened in late 2025 and early 2026 as shifts in the global supply/demand balance altered the relative value of heavier barrels like WTS. At the same time, Delek, historically one of the largest consumers of WTS, completed a major refinery turnaround during Q1 2026, temporarily reducing demand. In addition, asphalt margins were weak in early 2026 compared to transportation fuel margins, giving refiners less incentive to maximize asphalt production or pay a premium for WTS. Instead, many refiners have been better off running lighter crudes that yield a greater share of higher-value fuels, particularly in West Texas and southeast New Mexico.In such environments, some traders/marketing shops have a commercial incentive to blend portions of WTS into West Texas Light (WTL) in order to upgrade the crude to WTI. However, these cheaper barrels typically have higher levels of sulfur, iron, vanadium and nickel. Thus, such blending could elevate the crude’s metals content, even if the final blended crude remains technically within pipeline specifications. Pipeline operators also play an important role in managing crude quality. These enforcement actions can effectively segment crude flows, separating higher-quality streams from lower-quality barrels moving through the broader transportation network. These dynamics could eventually lead to a kind of bifurcation within WTI streams. In this scenario, one stream would resemble traditional WTI, with sulfur levels around roughly 0.15% and relatively consistent characteristics. Another stream might push closer to sulfur levels of 0.4% and potentially carry higher hydrogen sulfide content. Although they are technically still within the specs, they are potentially skirting the line.If such a divergence were to develop, operators would likely need to maintain separate storage (if they do not already have separate facilities) for different streams before blending them later to meet final delivery specifications. Different crude qualities could then move toward different end users. Higher-quality barrels might flow toward export terminals and refineries optimized for lighter feedstocks, while slightly heavier or sourer streams could be directed toward refining complexes better equipped to handle them.  Blending, of course, is nothing new in crude markets, as we discussed in Turner Mason and the Goblet of Light & Heavy. Marketing/trading companies have long combined different streams, mainly to drive higher profit margins but also to bring barrels back within specification limits. Lower-quality crude can often be diluted with higher-quality barrels to produce a final blend that meets pipeline or benchmark requirements. Even so, some market participants argue that these blending practices could gradually change the overall character of crude reaching the Gulf Coast.  In that sense, what ultimately arrives at export terminals may increasingly resemble a blended DSW crude rather than the classic WTI profile many international buyers have historically expected. However, the strict specs on WTI included in the Brent basket prevent this level of deterioration in the quality of Houston WTI. For example, Cushing blenders can blend considerable amounts of Canadian heavy crude while still meeting DSW specs. The same operation is basically impossible in Houston due to the strict metals specs on WTI that is destined for inclusion in the Dated Brent basket.So … has crude oil quality gotten more or less consistent since the inclusion of WTI in the Brent basket? The short answer is: more consistent overall, but not because the crude itself became more uniform. Rather, the benchmark now has a much larger and more standardized pool of eligible barrels, even while quality differences inside the basket have actually increased in some respects. While quality issues appear to crop up more often, that’s partly a function of scale. With significantly higher volumes and tighter specifications, there are simply more barrels to monitor and more opportunities for off-spec cargoes to draw attention. From a market perspective, many traders would say the benchmark has become more stable and representative, even though the eligible crude slate is less homogeneous. An interesting consequence is that WTI Midland frequently sets the Dated Brent price because it is often the cheapest qualifying barrel. In 2024, it was setting the benchmark more than half the time. According to Reuters, there were zero cargoes of North Sea Brent crude initially scheduled to load in August for the first time since LSEG data began tracking in 2007.In the end, the credibility of any benchmark crude depends on trust. Buyers need confidence that the barrels they purchase will behave predictably in their refineries. If market participants cannot rely on consistent specifications across pipelines, terminals and export hubs, it could eventually undermine the attractiveness of U.S. Gulf Coast WTI in global markets. Strengthening quality controls upstream in the basin and maintaining transparency around crude specifications could help ensure that WTI continues to hold its place as one of the world’s most trusted benchmark crude grades.

Permian Natural Gas Production Still Near Record Highs | RBN Energy -  Permian natural gas production during the week ended September 28 averaged 23.5 Bcf/d, which was just 0.1 Bcf/d lower than the record high average of the prior two weeks. In general production remains extremely high and has been climbing this month since Hugh Brinson Phase 1 began service. With just a few days left in the month, production has averaged around 23.6 Bcf/d, up 0.5 Bcf/d month-on-month and up over 1.6 Bcf/d since the Gulf Coast Express expansion came online in June. The high production levels are visible in the orange line in the graph below. The two new takeaway capacity projects have debottlenecked the basin and more capacity is still coming this year. Blackcomb Pipeline is commissioning and will begin full commercial service before the end of the year. RBN expects production to climb to just under 24 Bcf/d by the end of the year, which is nearly 2 Bcf/d above the level of six months earlier before new capacity came online. While incredibly strong, that growth in supply is much less than the new takeaway capacity, which leaves room for continued production growth next year and beyond. To the point, eastbound capacity from the Permian was not fully in use last week. Outflows to the East averaged 14.3 Bcf/d during the week ended September 28, which was 0.3 Bcf/d lower than the prior week. Flows to the East remain strong, but reported outflows on Whistler Pipeline, which had been incredibly high for most of this month, eased slightly last week.

Michigan tribes file request to overturn state permits for Line 5 tunnel - Great Lakes Now - The move by tribes follows the Whitmer administration’s request for a state agency to review the same permits using new guidance from a Michigan Supreme Court ruling.Four Michigan tribes asked state regulators on Thursday to overturn permits for the plan to update an aging segment of the Line 5 pipeline in the Straits of Mackinac.Tribes said that construction on the fossil fuel pipeline would threaten their ways of life by damaging cultural and environmental resources, in their request to the Department of Environment, Great Lakes, and Energy (EGLE) for an administrative hearing to contest the permit.If granted, the hearing will allow parties to submit evidence and testimony in front of an administrative judge who makes a decision on the permit.The move by tribes comes after the Whitmer administration this week asked the agency to review the same permits using new guidance from a Michigan Supreme Court ruling.Whitney Gravelle, president of the Bay Mills Indian Community, said in a statement that the tunnel is a trap designed to keep Line 5 operating in the straits for generations to come.“It is time for Michigan to right this wrong by honoring its commitments to Tribal Nations and choosing a future that protects our waters rather than locking us into future generations of risk,” she said.Enbridge Energy wants to encase a new segment of its pipeline carrying oil and natural gas liquids in a tunnel buried beneath the Straits.In a statement, the company said it already has an agreement from 2017 with the state to build the tunnel. Without years of litigation and political intervention, this project would be moving toward completion,” said spokesperson Ryan Duffy.The company received a water resources permit for the tunnel project from EGLE on July 15. Despite acknowledging “adverse” impacts on ecological and tribal resources, state regulators said it’s better than an oil spill in the Great Lakes.Two weeks later, the Michigan Supreme Court vacated a tunnel permit issued by a different state agency — the Michigan Public Service Commission — saying that the scope of harm under consideration was too narrow and sent it back for more review. Justices told the agency to review the permit again. The project has received federal approval, and EGLE is expected to decide on a separate wastewater discharge permit before the end of the month.

Oil spill reported on Mississippi River near Winona (KTTC) – According to Winona County Emergency Manager Ben Klinger, Winona County Dispatch was contacted about an oil spill on the Mississippi River near Lock and Dam 5A, roughly 10 miles north of Winona along U.S. Highway 61. The incident was reported to the Minnesota Duty Officer at approximately 2:46 p.m. on Monday. The Winona Fire Department and Winona County Emergency Management were subsequently notified. Klinger stated the release involved less than 50 gallons of diesel fuel from a tugboat. Winona Fire deployed a containment boom to help prevent the fuel from spreading. Further investigation into the cause of the incident will be handled by the U.S. Coast Guard. Cleanup is being completed by a contracted environmental cleanup company hired by the responsible party.

October Heat Wave Poised to Extend California Natural Gas Price Rally -California natural gas demand is poised to jump over the coming week as an October heat wave settles over the state, extending support for a SoCal Citygate premium that has swelled to its widest in three weeks. Graphic: Pacific natural gas power burn demand forecast to jump near 5 Bcf/d in early October 2026, more than double year-ago levels. At a Glance:
Pacific power burn forecast near 4.8 Bcf/d
California gas-fired output jumps 48%
Cooling demand runs four times normal

US Natural Gas Exports to Mexico Hit September Record as Power Demand Grows - September was another strong month for US natural gas exports to Mexico, helping to drive demand for supplies of the fuel from the South Central region. Agua Dulce and Waha bidweek natural gas prices compared with US pipeline exports to Mexico from October 2023 to October 2026.  At a Glance:
South Texas flows average 5.15 Bcf/d
West Texas supplies another 2.06 Bcf/d
South Central storage trails year-ago levels

Ksi Lisims LNG Signs 1 MMtpa Agreement with Centrica | RBN Energy  - Ksi Lisims LNG has signed a Heads Of Agreement (HOA) with British energy company Centric Energy for 1 MMtpa of LNG (approximately 135 MMcf/d) for a term of 20 years, on an FOB basis, subject to the completion of a Sale and Purchase Agreement (SPA), according to a September 30 press release.  This agreement brings the total capacity with SPAs or HOAs to 9 MMtpa. In May, the CEO of co-owner and project operator Western LNG LLC was quoted as wanting 8-9 MMtpa of capacity under SPAs before making a positive Final Investment Decision. Shell, TotalEnergies, and Uniper have each signed long-term SPAs for 2 MMtpa, and earlier this year Ksi Lisims announced HOAs for 1 MMtpa with both SEFE and Santos.The September 30 press release also noted that the project has secured “Project of National Interest” status from the Government of Canada, which was expected, and should help expedite the project through federal regulatory processes.The Ksi Lisims LNG project is a proposed 12 MMtpa floating LNG project to be located on Pearse Island in northwest British Columbia, that would take in 1.7-2.0 Bcf/d of natural gas and be amongst the lowest emissions LNG export facilities in the world (see chart below). The consortium is owned by Houston-based Western LNG, Rockies LNG Partners, and the Nisga’a Nation. For more information on the project see our Analyst Insight from May.

Another ‘Vote of Confidence’ in Ksi Lisims, Canadian LNG With Latest Supply Deal - The Ksi Lisims LNG project being developed in British Columbia (BC) announced Wednesday it has signed a tentative deal to sell UK utility Centrica 1 Mt/y of the super-chilled fuel in another sign of growing momentum for Canadian natural gas exports. North American LNG netback prices compared with AECO, SoCal Border, Transco Zone 5 and Waha forward prices through October 2027.   At a Glance:
Centrica signs HOA for 1 Mt/y
Ksi Lisims commits 9 of 12 Mt/y
Middle East conflict spurs contracting wave

Tourmaline Eyes Data Centers, Oilsands to Drive Next Phase of Canadian Natural Gas Growth - Industrial demand from Alberta’s oilsands and a surging data center sector could add to LNG export growth in driving Canadian natural gas demand, according to Jamie Heard, vice president of capital markets at Canada’s top natural gas producer, Tourmaline. Meta’s Sturgeon Data Centre campus in Alberta, Canada, featuring multiple large data center buildings.  At a Glance:

• Alberta eyes 1 Bcf/d data center demand
• Oilsands require additional gas supply
• Pipeline constraints threaten industrial growth

AECO Gains as LNG Canada Expansion Adds 2 Bcf/d of Natural Gas Demand --Western Canadian natural gas producers got a boost Tuesday from news that Shell had sanctioned the second phase of LNG Canada.NGI NOVA/AECO C MidDay natural gas price chart showing Alberta benchmark prices from September 2025 through September 2026, with prices rebounding toward $2.00/MMBtu in late September..  At a Glance:
Shell targets early 2030s startup
Westcoast Station 2 jumps C22.0 cents
Expansion doubles LNG capacity to 28 Mt/y

Shell Greenlights LNG Canada Expansion Amid Global Supply Crunch - Shell on Tuesday sanctioned the second phase of LNG Canada, which would double the facility’s capacity to 28 Mt/y and boost output at a time when roughly 20% of global supplies have been curbed indefinitely by the Iran war. At a Glance:

• Expansion doubles capacity to 28 Mt/y
• Startup targeted for early 2030s
• Global LNG supply disruptions bolster expansion

Let the Fun Begin! LNG Canada Partners Sanction Phase 2 Expansion | RBN Energy - On September 29, 2026, the five joint venture (JV) partners in LNG Canada announced that they had reached a decision to proceed with the expansion of the LNG Canada site that will result in a doubling of its LNG liquefaction capacity from 14 million tonnes per annum (MMtpa, ~1.8 Bcf/d) to 28 MMtpa (~3.6 Bcf/d). No timeline to completion of the expansion or costs were announced, but industry speculation is that the expansion will be completed in the second half of 2031 or the first half of 2032. Press reports have suggested the expansion's total cost as approaching C$33 billion (US$23 billion). Based on equity ownership, the JV partners in LNG Canada are: Shell (40%), Petronas (25%, with 5% of the 25% implicitly held by Saudi-backed MidOcean), PetroChina (15%), Mitsubishi (15%) and KOGAS (5%). LNG Canada is located near the town of Kitimat, BC on Canada’s West Coast (purple diamond in map above) and is currently the only operating LNG liquefaction export site in Canada, although several others are under construction or are well advanced in the planning process. LNG Canada’s expansion work will include: the construction of two additional LNG trains on the site’s existing footprint which was already sized for potential future expansion; the construction of an additional LNG storage tank, condensate tank, loading berth and additional systems. The JV partners also confirmed that the positive sanctioning will trigger the implementation of an equity agreement originally announced on July 14 with five neighboring First Nations that will result in the investment of up to C$1 billion (US$705 million) in a special purpose equity firm, MNT Investments LP, that will purchase the second LNG storage tank and lease it back to the JV partners for the life of the project. This transaction was described as one of the largest Indigenous ownership positions in major Canadian infrastructureRelated to the expansion work, the Coastal GasLink (CGL) Pipeline, which feeds gas to the Kitimat site from producing areas in northeast BC (orange line in map above), will double its throughput capacity from the current 2.5 Bcf/d to 5.0 Bcf/d with the addition of five new compressor stations. CGL will, in the future, also be sending additional gas supplies to the under-construction Cedar LNG project (green striped diamond) which is currently scheduled for completion in 2028 and located a short distance from LNG Canada.In terms of more recent activity at LNG Canada, the site’s gas intake for August was reported as 1.54 Bcf/d (green bar in chart above). Given that export activity from the site in September has been close to matching the rate of August after allowing for what appeared to be a brief shutdown earlier this month, gas intake in September is currently estimated to be 1.45 Bcf/d (red bar). LNG Canada began commercial operations in June 2025 and to date has shipped nearly 140 cargoes of LNG to Asian destinations.

Westward Ho! — North American Gas Finding the Short Way to Asia -- For a decade, the story of North American LNG has been written almost entirely along the Gulf Coast, where a flood of liquefaction capacity stretches from Corpus Christi to Plaquemines Parish. But for the important and growing Asian gas market, the Gulf Coast is a long way away. A cargo from Louisiana bound for Tokyo has to squeeze through the Panama Canal or take the long way around the Cape of Good Hope. That means a voyage of three weeks or more, versus roughly 10-12 days from British Columbia or Baja California. The tide of West Coast gas projects is rising and there has been a flurry of announcements in the last couple of weeks. The biggest came on September 29, when LNG Canada announced a positive final investment decision to proceed with Phase 2 (orange diamond in map below, for more, see our blog, Beautiful Day). The expansion doubles the Kitimat facility's production capacity from 14 MMtpa (~1.8 Bcf/d) to 28 MMtpa (~3.6 Bcf/d), with commercial operations expected to begin in the early 2030s. The JV's ownership tells you where the molecules are headed. Shell's partners include Malaysia's PETRONAS (25%), China's PetroChina (15%), Japan's Mitsubishi Corporation (15%), and South Korea's KOGAS (5%). And a second wave is filling in behind LNG Canada. Woodfibre LNG near Squamish is a 2.1-MMtpa (~285 MMcf/d) facility targeting in-service in late 2027, and it was reported in April that the project is looking to double or triple in size (teal striped diamond). Cedar LNG, the Haisla/Pembina floating LNG project, remains on track for a late-2028 startup (pink striped diamond). Once fully operational, it would add roughly 3.3 MMtpa (~450 MMcf/d) of feed gas demand pulling on WCSB supply via Coastal GasLink (yellow line). Next up for FID is Ksi Lisims (purple checkered diamond). The floating LNG project north of Prince Rupert recently signed another tentative supply deal ahead of a final investment decision expected by the end of 2026, and it now has tentative sales deals for 9 MMtpa of its projected 12 MMtpa. We wrote a detailed update on the Canadian projects recently in Shut Up and Drive.  And the West Coast pull isn't limited to Canadian Montney supply. Permian gas is increasingly being plumbed toward Mexico's Pacific coast as well. As we will detail in an upcoming blog, on September 21, ESENTIA Energy Development agreed to acquire the Guadalajara-Manzanillo pipeline for $400 million from TC Energy. Esentia Energy’s pending acquisition of the Guadalajara-Manzanillo Pipeline, would give the company the last link in a chain of connecting pipelines that together — for the first time — would enable gas to flow along an integrated system from the Waha Hub to Mexico’s west coast. That matters because all or part of that expanded capacity could be employed by the proposed Gato Negro LNG project being planned by a group of investors led by Mexican entrepreneurs Carlos Camacho and Emilio Fuentes. The current plan calls for the project to be developed in three 3-MMtpa (400 MMcf/d) phases, with the first phase beginning commercial operation as soon as 2030-31 and the second and third phases following over the next two or three years. Farther north in Baja, Sempra's ECA LNG has shown both the promise and the growing pains of being first. The inaugural cargo was lifted by TotalEnergies and shipped to Asia. However, a planned post-cargo inspection uncovered damage in the refrigerant compressors, which pushed substantial completion to 4Q26. Mexico Pacific's 15-MMtpa (2 Bcf/d) Saguaro project in Sonora remains the biggest Mexican wildcard. After missing its December 2025 export commencement deadline, the developer asked DOE to push commercial operations out to 2032. Then there's Alaska, the longest-running "almost there" project in North American energy (see Road to Alaska). On September 30, President Trump announced that Alaska LNG would receive $54 billion from South Korea as part of an overall $200 billion investment agreement in U.S. energy infrastructure. That headline number covers nearly the whole project, since Glenfarne estimates the cost at up to $55 billion. But Seoul's framing was notably cooler. Korea's trade minister said the government is reviewing the project and will invest only if commercial viability is established. The commercial book is also not yet complete. Glenfarne holds preliminary, nonbinding agreements for 13 MMtpa across Asia, three million tons short of what it says it needs to finance the project. Still, the pitch is the same one driving every project on this list: proximity. Alaska avoids the Panama Canal entirely, and it gives Korean and Japanese buyers an energy-security hedge alongside a trade-policy relief valve.  Add it all up and the West Coast is a surging second front for North American LNG. On one side are Canadian and Alaskan supply basins getting increased access to a tidewater outlet. On the other is Permian gas taking the cross-border escape hatch through Mexico to reach the Pacific. The Gulf Coast will remain the volume king for years. But for Asian buyers counting days at sea, canal fees, and chokepoint risk, the marginal North American cargo is increasingly going to start its journey on the Pacific side of the continent.

IER Wants Canadian Oil and Gas Counted as American-Made -- Marcellus Drilling News --Here’s an argument you don’t hear every day: the oil and natural gas the United States buys from Canada shouldn’t count as “imports” at all. That’s the case laid out in a new report from the Institute for Energy Research (IER), published September 18. Change how Washington keeps the books, IER argues, and the alarming-sounding trade deficit with Canada very nearly disappears — no tariffs, no trade war, just honest accounting.

Trump set to unveil $54B South Korean investment in Alaska LNG - - President Donald Trump unveiled a $200 billion package of investments from South Korea Wednesday, including proposed funds for a long-stalled liquefied natural gas project in Alaska. The announcement is part of a White House effort to highlight economic wins ahead of the midterms and featured heavy praise for Sen. Dan Sullivan (R-Alaska), who is fighting to win reelection this fall and attended the event at the White House announcing the funding. But the South Korean government has only said that it is considering the Alaska project and has not confirmed that it approved funding — which would go well beyond the $20 billion cap that Korea’s National Assembly put in place in March for annual outbound investment to the U.S. The South Korean embassy did not immediately respond to a request for comment. According to the White House, the South Korean government will put money into U.S. energy projects including a natural gas power plant in Texas and eight nuclear power plants. They are the first investment announcements to come out of an August 2025 trade deal in which Seoul agreed to invest $350 billion in projects in exchange for reductions in threatened U.S. tariffs — which includes $150 billion for shipbuilding projects. “The colossal package of investments that we are announcing today is a major step toward securing our critical energy supply chain, ensuring American energy dominance and making our partnership with South Korea and the entire Pacific region more powerful than ever before,” Trump said. Bloomberg first reported the investment news. The White House was quick to celebrate the potential $54 billion investment in the proposed Alaska LNG project, which would include an 800-mile pipeline to carry gas from the North Slope to an export terminal on the state’s south coast. The pipeline funding would be a massive boost to a project that has been stalled for decades amid questions around its massive price tag and ability to find customers. The Trump administration has explored a range of options to speed its development. Brendan Duval, the CEO of Glenfarne, a New York and Texas-based developer in charge of the project, said at the White House event the pipeline would be built within three years and that construction could start immediately after receiving funding.

United States Teases $50B-Plus Alaska LNG Plan as Seoul Reviews Terms - The Trump administration unveiled plans for South Korean investments that could direct more than $50 billion toward Alaska LNG, potentially opening a major new source of financing for the long-planned export project. Seoul, however, has only agreed to review the project and has not stated whether it would invest, nor how much. At a Glance:

• US outlines $50B-plus Alaska investment
• South Korea says commitment not final
• Public financing could reshape project economics

Korea to Trump: We aren’t funding your Alaska pipeline, yet - The Korean government denied Thursday morning that it has finalized an investment for a long-stalled Alaskan natural gas project, less than 24 hours after President Donald Trump tried to help boost the state’s Republican senator with a flashy Oval Office funding announcement. “This is a great senator, who is totally responsible for this pipeline,” Trump said of Sen. Dan Sullivan, who stood beside him Wednesday at the White House. “This is a man that works with me, shoulder to shoulder.” There is just one problem: Korea says the pipeline investment is still under review. Korean President Lee Jae Myung and several other members of his government said Thursday that their investment in the Alaska pipeline remains conditional. “The Alaska LNG project will proceed to working level under the preconditions that 1) its commercial viability is confirmed and 2) it complies with the legal procedures of the Republic of Korea,” Lee posted on X Thursday morning, according to a translation. The government also issued a release saying “the two countries have agreed to begin reviewing the project,” and will proceed based on “commercial reasonableness requirements.” The project involves a large-scale natural gas pipeline to transport energy from northern Alaska to the southern part of the state and would create a terminal that would help facilitate exports to Asian countries like South Korea and Japan. Presidents have been promising to tap into those isolated natural gas reserves in northern Alaska since the Carter administration, but several efforts have failed to attract investment due to concerns about cost and future returns. Trump on Wednesday claimed South Korea had committed $54 billion in funding for the project as part of a $350 billion U.S. investment pledge Seoul made last year in a deal to lower threatened U.S. tariffs. He also said that Korea would spend around $120 billion on eight nuclear plants across four states and around $20 billion on a natural gas power plant in Texas. It was the latest in a series of events the White House has held in recent days to tout massive foreign investment for projects in midterm battleground states — even if the details remain fuzzy. Earlier this week, the administration highlighted a new steel plant in Iowa, but some industry experts are skeptical that the plant will be built given the troubled financial past of Mesabi Metallics, the company linked to it, and the fact that its projections are based on the current high U.S. steel prices. Trump made it clear Wednesday that the LNG investment announcement had to do with Sullivan’s election chances. He denounced the fact that another candidate named Dan Sullivan — who is running as an independent — was allowed on Alaska’s ballot in November and told the reporters gathered that the incumbent Sullivan had his ear. “I have to tell you this because he has an election,” Trump said at one point. Trump and Sullivan emphasized Wednesday that the pipeline project would be transformative for Alaskans, and a developer claimed the project would be done in three years. No members of the Korean government spoke during the White House announcement. If they had, they might have pointed out that the government in Seoul had already allocated its annual $20 billion U.S. investment commitment for the natural gas power plant in Texas — another state where Republicans are in a closely contested Senate race.

TotalEnergies Pitches Natural Gas Growth in Global Market Constrained by Iran War - TotalEnergies said this week it would spend $14–17 billion annually between 2027 and 2032 to boost energy production and LNG sales as the world confronts potential shortfalls with a conflict in the Middle East that shows no signs of ending. At a Glance:

• Highlights plans to spend $14–17 billion
• Oil and gas output to grow by over 3%
• Growth key amid Iran war

Global Natural Gas Prices Surge as Diplomacy Fails, LNG Supplies Stay Tight - Asian and European natural gas prices were climbing again on Monday as hopes for a quick reopening of the Strait of Hormuz faded.European Union natural gas storage chart showing inventories at 64.7% full as of Aug. 29, 2026, below the five-year average, with historical storage levels from 2021 through 2026. At a Glance:
TTF, JKM climbing again
Trump rejects Iranian proposal
Shipping targeted in Hormuz

Qatar's UCC Eyes Expansion into Venezuelan Oil and Gas - Qatari producer UCC Oil and Gas Holding is in talks for its possible entrance into new fields in Venezuela, the company's head of Upstream, Erik Keskula, said on Tuesday at a conference in Caracas. UCC, British BP and XRG, a unit of United Arab Emirates' state company ADNOC, last month were granted a long-term license to develop the Loran gas project, one of the largest in Venezuela's waters and which extends into Trinidad and Tobago. The pact gave the group rights to produce up to 4 ⁠trillion cubic feet of gas in Loran, whose total reserves are estimated at 7.3 TCF. Energy producer Shell SHEL.L was granted a parallel license for the same gas field. "We have interest in everything, really," Keskula said. "We are looking for the right opportunities in all sectors." Venezuela's interim President Delcy Rodriguez discussed cooperation opportunities in a recent meeting in Caracas with Qatar's Minister of State Mohammed bin Abdulaziz Al-Khulaifi, Qatar's foreign affairs ministry said on Tuesday on X, without providing more details.

Oil, Natural Gas Firms Bet ‘Interest Is So Strong’ in Venezuela, It Outweighs Political Risk --The recent diplomatic thaw between Venezuela and neighboring Trinidad and Tobago marks a critical turning point for regional energy integration, and could mean more LNG from the Americas reaches an energy-hungry global market. At a Glance:

• Offshore gas offers new export potential
• Existing pipelines ease regional integration
• United States remains key to projects

Russia's pipeline gas exports to Europe down 13.3% in September year-on-year -- Russian energy giant Gazprom's average daily natural gas supplies to Europe via the TurkStream undersea pipeline declined 13.3% from a year earlier to 44.8 million cubic meters in September. Russian energy giant Gazprom's average daily natural gas supplies to Europe via the TurkStream undersea pipeline declined 13.3% from a year earlier to 44.8 million cubic meters in September, Reuters calculations showed. Turkey is the only transit route left for Russian gas to Europe after Ukraine declined to extend a five-year deal with Moscow that expired in January 2025. Calculations based on data from European gas transmission group Entsog showed that total Russian gas supplies to Europe via TurkStream stood at 1.34 billion cubic meters last month, down from 1.55 bcm in September 2025. Russian gas exports fell due to maintenance work on the pipeline section at the Strandzha-2 border entry point through which gas is delivered to Bulgaria. Bulgarian gas transmission operator Bulgartransgaz said the section underwent reconstruction from September 21 to September 26. For the first nine months of the year, supplies increased by 1.2% to around 13.2 bcm year-on-year. Gazprom, which has not published its own monthly statistics since the start of 2023, did not respond to a request for comment. The company's gas exports to Europe sank by 44% last year to just 18 bcm, the lowest since the mid-1970s, following the closure of the Ukrainian route, according to Reuters calculations. Russian pipeline gas exports to Europe peaked at around 180 bcm per year in 2018-2019.

Asia Retakes LNG Premium Over Europe as Mild Weather Curbs Heating Demand - Mild forecasts across Europe and a warmer outlook for North Asia are holding back early-season heating demand, as Asian buyers pull ahead of Europe in the competition for flexible US cargoes.Europe and Asia daily temperatures compared with normal in Northwest Europe, Beijing, Seoul and Tokyo through Oct. 2, 2026.  At a Glance:
Asia reclaims premium over Europe
Europe warmth holds through midweek
Tropical Storm Choi-Wan strengthening near Guam

Indian Coast Guard saves flooding chemical tanker and 23 crew from capsizing off Odisha -A little over a month after the bulk carrier MV Ocean Winner sank off Odisha with 22 of its crew, the Indian Coast Guard (ICG) on Sunday pulled another stricken merchant vessel back from the brink in the state's maritime approaches. This time, all 23 crew members are safe. The Belize-flagged chemical tanker MT Seagull 9, laden with 9,000 tonnes of palm oil, sent out a distress call around 7.30 am on Sunday after its main engine failed and a ballast tank began flooding rapidly. The vessel was about 37 nautical miles east-southeast of Paradip and was listing "dangerously", the ICG said on Monday. The Coast Guard rushed its offshore patrol vessel ICGS Vishwast to the spot. A specialist damage-control team boarded the unstable tanker "under challenging conditions" and deployed submersible de-flooding pumps. Subsequently, the team blanked two damaged seawater pipelines and contained a third fractured line. Working alongside the ship's crew, it carried out cargo-transfer and de-flooding operations simultaneously, "effectively stabilizing the tanker and eliminating the threat of capsizing", the maritime force said. With 9,000 tonnes of palm oil on board, the Coast Guard also moved to contain the risk of a spill. It diverted a pollution-control vessel and another offshore patrol vessel to the area, while a Dornier maritime surveillance aircraft operating from Bhubaneswar flew sorties over the tanker. A minor palm-oil sheen spotted near the vessel on Sunday was found to have fully dissipated during follow-up sorties on Monday, an official said. The stabilised tanker was subsequently taken under tow by Paradip Port Authority tug Dolphin towards the anchorage off the port. Its main engine is being repaired with assistance from the technical team of ICGS Vishwast. "ICGS Vishwast, alongside the deployed specialised assets, remains on scene maintaining an active sentinel watch and providing continuous operational support," the official added. The ICG has not disclosed what caused the ballast tank to flood, the extent of damage to the vessel or its last port of call and destination. The rescue stands in contrast to the fate of MV Ocean Winner. The Panama-flagged bulk carrier left Paradip on August 20 with about 72,000 tonnes of iron ore fines and sank two days later, roughly 230-240 nautical miles off the Odisha coast. An Indian Navy P-8I aircraft spotted liferafts and guided the nearby merchant tanker Aisopos to the area. The tanker rescued two Chinese crew members. A week-long search followed, involving Coast Guard ships, Navy aircraft and vessels, merchant ships and two Chinese vessels. The search yielded an empty lifeboat and an emergency beacon before being called off, with the remaining 22 seafarers presumed dead. The Coast Guard is India's central coordinating authority for combating oil spills in Indian waters. Paradip has a Tier-I oil-spill response facility and regularly conducts pollution-response exercises involving the Coast Guard, port authorities and state agencies. The most recent regional exercise at the port was held in December last year. The same port also witnessed a fuel-spill incident earlier in May, when a pipeline carrying petrol from a vessel to an Indian Oil Corporation terminal ruptured and spilled thousands of litres of fuel into nearby water bodies and the sea.

Oman returns 135 tonnes of oil-polluted sand to beach after cleaning it - Nearly a year after oil pollution affected parts of Dhofar's coastline, Oman has returned treated sand to Awqad Beach after removing oil contaminants through a specialised cleaning process. What happens to beach sand after it becomes contaminated with oil? In Oman, the answer was not simply to throw it away. Around 135 tonnes of contaminated sand have been cleaned and returned to Awqad Beach in Salalah, as authorities continue efforts to restore part of Dhofar's coastline affected by oil pollution in 2025. The sand was part of around 190 tonnes of contaminated material removed from the area during the clean-up operation. Instead of permanently disposing of it, authorities sent the sand for treatment before returning it to the same beach once tests showed it was free from oil derivatives. The treatment process took around three months and was capable of processing about five tonnes of sand every hour. The technology uses oxidisers and catalysts that react with oil and other organic pollutants in the sand. During treatment, the pollutants are broken down into simpler substances, including water, oxygen and sodium carbonate. Officials said the process does not require toxic solvents and avoids burning the contaminated material. After laboratory testing confirmed the treated sand was free from oil derivatives, around 135 tonnes were transported back to Awqad Beach. Rather than replacing the contaminated sand with new material, the project aimed to restore the original sand and return it to the coastline. Oman's Environment Authority said the treated sand was used to rehabilitate an affected stretch of beach covering around two kilometres. Returning the original material also helps preserve the natural characteristics of the beach and supports efforts to reduce coastal erosion and restore the surrounding environment. Oil pollution affected parts of Dhofar's coast in 2025, including areas between Khor Salalah and Awqad Beach, as well as parts of Raysut Beach. Authorities surveyed the affected coastline and carried out clean-up operations before contaminated sand and other material were removed for treatment. The response involved several government and environmental bodies, including the Environment Authority and Dhofar Municipality. Officials described the operation as the first experience of its kind in Oman and Dhofar involving the removal, treatment and return of oil-contaminated beach sand. The project was carried out using specialised technology designed to treat contaminated soil and sand. Instead of ending with tonnes of polluted sand being discarded, the operation brought much of it back to where it came from. After months of treatment, 135 tonnes of sand are now back on Awqad Beach.

Help! – With Refining Capacity to Spare, China Could Help Ease Global Gasoline, Diesel Crunch It’s no secret that rising prices this year for refined products (especially gasoline and diesel) have drawn scorn from consumers, businesses and politicians alike. But while no obvious remedy appears likely in the very near term, that doesn’t mean the market is stuck indefinitely, as some major refiners, especially China, still have the capacity to boost output and exports. In today’s RBN blog, we look at how China could help stabilize the refined products market. China could play a major role in restoring market balance, but let’s look at how we got here before we dive into those details. As we noted in Basket Case, the U.S.-Iran conflict has created one of the most significant supply disruptions to global petroleum markets in decades, with much of the market attention focused on crude oil and the loss of flows through the Strait of Hormuz. As we discussed in Stuck in a (Gulf) You Can’t Get Out Of, the volume of products flowing out of the strait has plummeted since the start of the war. After averaging an aggregate 3.3 MMb/d in January and February (sum of stacked areas in Figure 1 below), they cratered in the following months, dropping to as little as 100 Mb/d in April (dashed blue circle) as the three-month moving average (dashed red line) plunged. We estimate that regional refinery runs are down by about 2.5 MMb/d vs. pre-war levels, with two-thirds of that due to physical damage from war-related attacks. Total global refinery runs fell by roughly 5.1 MMb/d year over year in Q2 2026, with declines in Asia caused by the loss of Hormuz-constrained crude flows. It’s important to note that Middle Eastern refineries don’t simply produce crude-derived products for their domestic markets; they are also important suppliers of refined products to the global market. The strait’s effective closure has moved the market from a relatively balanced (though fairly tight) system to a very short market, resulting in an aggressive bidding process for the marginal barrel. Even as some (however inconsistent) progress is being made to reopen the strait, recent Houthi rebel advances in Yemen and attacks on the Saudi East-West pipeline threaten to disrupt movements through the Red Sea, a key alternate route. (Note: The East-West pipeline was shut for 11 days as a result of the attacks. It has since reopened but will likely remain constrained for several weeks due to ongoing repair work.)The continuing Russia-Ukraine war has compounded the issue. Russia, typically the second-largest exporter of diesel after the U.S., has seen accelerating levels and effectiveness of Ukrainian attacks against its refineries over the past few months. This has resulted in estimated Russian refinery throughput falling below 4 MMb/d over the past two months (and operating at less than 60% of capacity), its lowest level in more than 20 years. With diesel production down by close to 30%, diesel exports have been totally shut and gasoline imports are needed to meet domestic demand.It’s also important to note that U.S. refiners have little to no spare capacity to boost production. As discussed in our weekly Crude Oil Billboard report, Energy Information Administration (EIA) data show Q2 2026 runs at their highest level since 2019. Distillate exports averaged 1.56 MMb/d, 30% above the five-year average, in the quarter, an indication that foreign buyers are pushing harder on a system that is already near its limit. U.S. refiners ran at 96.8% of capacity during the week ended September 11 and have been above 95% every week since exiting the spring turnaround season in May.So, if U.S. refining capacity is near its limit and the disruptions in the Middle East and Russia continue, where could relief come from? China is one potential alternative, largely because its refineries operate in a way that is unique in the global market. While refiners in the U.S. (and most everywhere else) make decisions on production rates, imports and exports based on what’s best for them individually, that’s not the case in China, where refiners operate within a very specific set of government controls. For starters, China’s massive refining sector operates at the intersection of market economics and government policy, giving Beijing considerable influence over how much crude refiners process and how much gasoline, diesel and jet fuel leave the country. The government does not dictate every refinery’s operating rate, but it controls several key levers that affect refinery economics.  Crude-import quotas are one measure China uses to maintain market control. Independent “teapot” refiners generally need government authorization to import crude, allowing Beijing to influence both the volume of crude entering the country and which refiners can access it. State-owned companies such as Sinopec, PetroChina and CNOOC are subject to fewer of these constraints but remain closely aligned with broader government priorities, particularly energy security and domestic supply.Refined product exports are another powerful tool. Beijing allocates export quotas for gasoline, diesel and jet fuel, effectively determining how much surplus production can be placed into international markets. When quotas are tight, refiners have less incentive to run at high rates because their ability to export excess product is constrained. Larger export allowances can have the opposite effect, allowing refiners to capture overseas margins and supporting higher utilization.Figure 2 below shows how those policies have affected refined product exports since 2015. Net exports (blue line) have varied significantly over the past decade, peaking at about 1.6 MMb/d before the pandemic, then crashing with the rest of the global market. But instead of a major rebound in the post-pandemic boom, China has limited refinery utilization to about 80% since then. More recently, it reduced net exports after the Hormuz closure to less than 400 Mb/d, although those cuts were relaxed in July and volumes exceeded 1 MMb/d in August, indicating it could export more if it chose to do so.Domestic fuel prices also remain subject to government influence, meaning refiners do not always respond solely to international crude and product prices. During supply disruptions, Beijing can put energy security and domestic availability ahead of refinery margins. But private refiners still respond to crude costs, product margins and local market conditions, and they can cut runs when economics deteriorate. Refiners also retain considerable discretion over which crude grades they buy and from which suppliers.All of that means that China has the potential to significantly expand its refined product exports if it chooses to do so, and a doubling of its August rate would only require total system utilization to increase to very achievable levels in the mid-80s% (from the sub-80% level currently). This would take net export volumes past their pre-pandemic highs to 2 MMb/d or more. It should be noted that China has been significantly expanding its refining capacity over the past three decades and while this expansion program has greatly slowed down there are still some more additions in the pipeline. As a result, with domestic demand flattening out, China will continue to maintain high levels of surplus refining capacity.First up of these expansions, as detailed in our recently published Future of Fuels report, is a 300-Mb/d grassroots refinery and petrochemical complex in northeast China being constructed by the Huajin Aramco Petrochemical Co. (HAPCO) joint venture (JV) that includes Norinco (51%), Saudi Aramco (30%) and Panjin Xincheng Industrial Group (19%). The refinery is in the final stages of construction (which began in 2023) and the official startup has recently been pushed back to Q4 2026. We expect it will be pushed back a bit beyond that, with a phased startup beginning in H1 2027, with full operation not expected until early 2028. Although it won’t help alleviate the current market tightness, we should note that a new grassroots refinery was also added to the Probable List of projects in our latest report. A JV that includes Fujian Petrochemical (50%), Sinopec (25%) and Saudi Aramco (25%) plans to build a 320-Mb/d integrated refining and petrochemical complex in Fujian province in southeastern China. (Fujian Petrochemical is a JV between Sinopec and the Fujian government.) While we’ve accepted the official startup timeline of 2030, it could slip into the early 2030s. As with most recent Chinese projects, both refineries are integrated with petrochemical plants, with production focused on petrochemicals and a secondary focus on middle distillates.Several Chinese projects are also on our Watch List and could progress to our Probable List in the future. The most likely is the 200-Mb/d brownfield expansion of Sinopec’s Qilu refinery in Shandong province (although with some reconfiguration taking place at that plant, the net increase will likely only amount to 70 Mb/d if that project is completed). However, we believe any increases would be at least partially balanced by additional shutdowns of less-competitive plants, as China has a stated policy to limit total refining capacity to meet carbon-peaking goals and also due to stagnating domestic demand.China’s refining sector won’t single-handedly solve the global refined-products squeeze, but it represents one of the few meaningful potential sources of additional supply available to the market in the short term. Beijing’s control over crude imports, refinery operations and, most importantly, export quotas gives it the ability to influence how much product reaches international buyers. With Middle Eastern and Russian supply still constrained and U.S. refiners running near full tilt, even a modest increase in Chinese exports could take some pressure off global balances. The question is not whether China has the barrels, but whether Beijing decides it wants to supply them to meet global market needs. With President Trump scheduled for a state meeting with Chinese President Xi Jinping on Thursday in Washington, the topic certainly could come up. While refined product exports are unlikely to be a headline Trump-Xi negotiating item, they could be part of a broader discussion about global fuel availability and energy-market stabilization, topics of mutual interest to the U.S. and China.

China Halts October Fuel Exports as Global Diesel Crunch Deepens  -China’s major refiners have suspended most refined fuel exports for October as Beijing prioritizes domestic supply security, removing another source of diesel, gasoline and jet fuel from an already severely constrained global market.PetroChina has cancelled several gasoline and jet fuel cargoes scheduled for October, while Zhejiang Petrochemical did not schedule exports during China’s week-long National Day holiday, Reuters reported, citing four people familiar with the matter. Beijing has yet to authorize October exports outside Hong Kong and Macau, although shipments could resume after the holiday ends on October 7 depending on domestic inventories and refinery output.The move follows a sharp deterioration in China’s own fuel-stock position. Kpler estimates commercial diesel and gasoil inventories are around 20 million barrels below pre-war levels, while gasoline stocks are roughly 9 million barrels short of the threshold Beijing wants restored before allowing exports to normalize.China had significantly increased exports during the summer. Official customs data showed total oil-product exports reached 6.01 million tonnes in August, up 12.7% year-on-year and the highest since March 2024, according to S&P Global. At the time, Chinese refiners said Beijing had not yet restricted clean-product exports despite tightening domestic supply.The reversal comes as global diesel supplies are already being squeezed by Middle Eastern disruptions and Ukrainian attacks on Russian refineries. S&P Global warned this week that Asian fuel markets have limited surplus supply, meaning any further restriction on U.S. diesel exports would increase ompetition for Asian and Middle Eastern barrels.China’s own government has meanwhile intervened to limit the domestic impact of high international oil prices, partially suppressing scheduled gasoline and diesel price increases in September while instructing refiners to ensure stable supplies.

One of Europe's largest onshore oil fields has restarted production - Many people will know the Groningen gas field, the discovery of which triggered offshore exploration in the wider North Sea in the 1960’s. It is also well-known that the Groningen gas field was permanently shut in a few years ago, following decades of induced seismic events. But a little further south from Groningen is the Schoonebeek oil field, which ranks amongst the largest oil fields onshore Europe. As is the case with Groningen, Schoonebeek did not produce hydrocarbons for the last few years too, but last month, oil production was restarted from the Lower Cretaceous Bentheim sandstone reservoir. Operator NAM had to suspend operations in 2021 due to production water issues. As the heavy oil from Schoonebeek comes with a high water-cut of around 90% or higher, the separated water was re-injected in three abandoned gas fields in the Twente area south of Schoonebeek, using an existing 70 km long pipeline to transport the fluids. However, this led to microbially-induced corrosion and the risk of leakage. This was subsequently remediated through the fitting of flexible pipes into the existing pipelines, ensuring minimal disruption and allowing quick resumption of operations. Map – Location of the Schoonebeek oil field, and the Schoonebeek gas field situated below it. Produced water from the oil field is now injected into the Schoonebeek gas field, where it used to be piped to a cluster of abandoned gas fields to the south before problems arose in 2022. The pipeline used for that operation is also shown on the map. Cross-section – demostrating the shallow nature of the Schoonebeek oil field in comparison to the gas field. Source: Aanvraag Instemming Gewijzigd Winningsplan Schoonebeek Gas (NAM, 2023). Production profile – showing the Schoonebeek oil production from the start of the steam-assisted project in 2011. Before that, around 250 million barrels were produced from the field already (1947-1996). However, a downhole rupture in the outer casing wall of one of the Twente injection wells was subsequently found. Even though it did not lead to fluid leakage, NAM was accused of not picking this up in a timely manner. This triggered an outcry of public anger in the Twente area, which ultimately led NAM to stop water injection in August 2021. This also meant that the production of oil from the Dutch part of this major oil field came to a stop. In the German part of the field (Emlichheim), where a more conventional way of production using nodding donkeys take place, production has continued all the while. But a solution has now been found, and this solution does not require a long route of water transport anymore. The produced water is injected into the Permian Zechstein gas reservoir beneath the Cretaceous reservoir from which the oil is being produced. It makes you wonder why that solution wasn’t selected straight away. And while water injection into the gas field is taking place, a limited amount of gas production will continue (0.9 Bcf/year), possibly aided by the increased water injection from the oil field above.

Why is oil price rising? Brent jumps 2.5% after Trump rejects Iran peace proposal Hindustan Times - Brent crude oil prices jumped more than 2% on Monday after US President Donald Trump rejected an Iranian peace proposal aimed at resolving the conflict and reopening the Strait of Hormuz. Brent futures rose $2.60, or 2.49%, to $106.92 a barrel at 0803 GMT. US West Texas Intermediate (WTI) crude also climbed. WTI rose $2.08, or 2.25%, to $94.49 a barrel. The move came as markets reacted to uncertainty over the conflict and the future of oil shipments through the Strait of Hormuz. Trump's rejection of the peace proposal was a major reason for the rise in oil prices. Hamad Hussain, senior climate and commodities economist at Capital Economics, said oil prices appeared to have jumped after Trump rejected Iran's proposal, as reported by Reuters. Iran had presented the peace proposal last week at the UN General Assembly in New York. Iran said the proposal had been sent to the US through Qatari mediators as part of efforts to find a diplomatic solution to the conflict. Trump said on Saturday that he had rejected Iran's plan. However, he also said on Sunday that he expected US negotiators to hold more talks with Iran during the week. Trump made the comments in a phone interview with Axios. The Strait of Hormuz remains central to the oil market. The waterway is a major route for global oil shipments, so any disruption or uncertainty around its reopening can put upward pressure on crude prices. Oil prices are rising despite some recovery in shipments through the Strait. Hussain said higher flows through Hormuz have reduced some of the pressure on oil prices, but the broader oil market is still facing a supply deficit. That means the market is still worried about a shortage of oil. Even though more barrels are moving through Hormuz, total supply has not fully caught up with demand, keeping the oil market in deficit. Capital Economics' Hussain said, according to Reuters. There is also a wider security risk in the Middle East. Yemen's Saudi-led coalition said early Saturday that it had intercepted two ballistic missiles and two drones launched by Iran-backed Houthis toward Saudi Arabia. At the same time, Middle East oil exports have started recovering. Crude exports from major Middle Eastern producers reached 12.8 million barrels per day in September, the highest level since the war began in February. Preliminary Kpler data cited by Reuters showed this. Saudi Arabia and the United Arab Emirates helped drive the increase in exports. Their higher shipments pushed regional oil exports higher in September even as the conflict continued. Oil shipments through the Strait of Hormuz also recovered. Shipments through the waterway were expected to reach about 7.4 million barrels per day in September, according to the preliminary Kpler data. Saudi Arabia also changed its export route after attacks damaged its East-West pipeline. The country diverted some oil exports from the Red Sea port of Yanbu to its eastern Ras Tanura port. The oil market has also been dealing with uncertainty over US diesel exports. Brent gained only 0.4% last week, while WTI fell more than 7%, partly because investors were worried that the US could ban diesel exports to bring down record-high domestic diesel prices. A US diesel export ban could also affect US oil production. Markets are concerned that limiting diesel exports could reduce refinery operations in the US, which could then affect demand for crude oil. Diesel prices in Europe have also surged. The premium of European low-sulphur gasoil over Brent crude futures reached a record of about $95 a barrel last week, showing how tight the global diesel market has become. The diesel shortage has been linked to a wider global supply problem. Prices have reached record levels, and Trump's support for a possible US diesel export ban has added another layer of uncertainty to the market. Goldman Sachs warned that a US diesel export restriction could affect markets far beyond America. Europe and Latin America, especially Brazil and Mexico, are major destinations for US diesel exports, according to Reuters. A US diesel shortage could push other countries to compete for available fuel. Goldman Sachs said Europe and Latin America could start buying more diesel from other suppliers, including countries such as India, which could spread the supply shock to Asia. Goldman Sachs estimated that the impact could increase European diesel prices quickly. The bank estimated that each week of a US diesel export ban could raise European wholesale diesel prices by about $3 a barrel, or just under 2%. So, the latest Brent price rise is being driven by several risks at the same time: Trump's rejection of Iran's peace proposal, uncertainty over the Strait of Hormuz, the continuing Middle East conflict, a global oil-market deficit and tight diesel supplies. For now, the key question for oil markets is whether US-Iran talks can reduce the conflict and keep oil flowing normally through Hormuz. Trump has rejected Iran's current proposal but has also indicated that US negotiators could hold more talks this week.

Oil Prices Jump as Trump Rejects Iran's Hormuz Offer, With Brent Near $107 and WTI Near $95 a Barrel --Oil prices rose sharply on Monday after President Donald Trump rejected Iran's conditional offer to reopen the Strait of Hormuz, reviving fears that supply through the world's most important oil chokepoint will stay disrupted. International benchmark Brent crude traded near $107 a barrel and U.S. West Texas Intermediate near $95, both in U.S. dollars, though prices moved through the morning. Brent futures for November delivery were 2.7% higher at $107.11 a barrel at 8:32 a.m. Eastern time, paring gains after climbing as high as $108.83 earlier in the session, CNBC reported. WTI futures for November were 3% higher at $95.20. Later in the morning, CNBC's market blog showed Brent up more than 2% at $106.79 and WTI up about 2% at $94.40. In early Asian trading, Brent had gained as much as 2.89% to $107.34 and WTI had risen 1.87% to $94.14, according to CNBC. The move reversed part of Friday's decline. Oil fell more than 2% on Friday after reports that the two sides were exploring a phased arrangement, and it rebounded at the start of the week, Euronews reported. Trading Economics data showed Brent up about 18% over the past month and about 59% higher than a year ago, while WTI was up about 9.7% over the month and about 48% higher year on year. Brent remains well below its April peak, when it reached a four-year high of $126, according to a chronology of the year's oil market on Wikipedia. The trigger was Trump's rejection of a seven-day proposal from Tehran. Iranian Foreign Minister Abbas Araghchi presented the offer on the sidelines of the U.N. General Assembly in New York. "If certain conditions are met, the Strait of Hormuz will be open at the end of seven days, and talks will be restarted," Araghchi told reporters. According to Iranian foreign ministry spokesman Esmaeil Baghaei, the conditions include an end to what Tehran describes as U.S. "acts of aggression," the lifting of the naval blockade and economic warfare, and the release of Iranian assets. Trump confirmed that he had turned the offer down. "They made a proposal but I rejected it," he told reporters, CNBC reported. The Wall Street Journal reported Saturday, citing unnamed U.S. officials, that Trump told aides he expects U.S. strikes on Iran to resume after November's midterm elections. Trump also told Axios on Sunday that Iran has overplayed its hand and that Tehran's conditions are something Washington might have agreed to about a year ago, Bloomberg reported. He said he expects negotiations to resume this week. Iran said it is waiting for a definitive U.S. response and will not ease its conditions, according to Trading Economics.   Analysts said markets were pricing in a longer standoff. Energy market participants are seeing a "clear and present danger" of a return to U.S.-Iran hostilities after the midterm elections, Cornelia Meyer, chief executive of Meyer Resources, told CNBC. Trump said earlier this month that he expected the conflict, which began with U.S. and Israeli airstrikes on Iran on February 28, to conclude soon after the midterms, with oil prices subsequently declining, CNBC noted. On Friday, before the rejection, David Morrison, senior market analyst at Trade Nation, said traders saw room for a sharp oil pullback if a phased deal landed but that there were "still plenty of obstacles to overcome first." . Before the strikes on Iran, roughly one-fifth of global oil supplies flowed through the waterway, which links the Gulf to the Gulf of Oman and the Arabian Sea, according to Al Jazeera. Commercial shipping has declined drastically since the war began amid attacks on vessels in the Gulf, most of which have been blamed on Iran or allied groups. Vessels made 132 transits of the strait from September 21 to 27, up from 116 the previous week, according to the maritime intelligence platform MarineTraffic.  Euronews said shipping risks have also grown in the Red Sea after the Houthis seized Yemen's coastline, including territory near the Bab al-Mandab Strait. Other factors are adding to volatility. Trading Economics said oil markets have been unsettled by mixed signals over peace prospects, signs of recovering Middle East energy flows, and speculation that the United States could restrict diesel exports. Previous negotiations have repeatedly appeared close to a breakthrough before collapsing, the outlet noted, which has kept traders cautious. Higher crude pushed up inflation worries and rippled through other markets. In the United States, the Dow Jones Industrial Average was down about 0.6% in early trading and the 10-year Treasury yield traded above 5.2%, according to CNBC. In Europe, the Euro Stoxx 50 was about 0.5% lower in early trading, Euronews reported. In Asia, Japan's Nikkei 225 and South Korea's Kospi fell 0.73% and 2.70%, respectively, according to Al Jazeera. For consumers and businesses, the stakes are largely about fuel costs. Higher crude prices tend to feed into gasoline, diesel and jet fuel costs, and traders are watching whether the rise in oil adds to price pressures at a time when interest-rate expectations are already sensitive. The article notes that these are futures prices, which move constantly and may differ from what motorists pay at the pump. The next moves depend on diplomacy. Trump has said talks could resume this week, Iran has said its conditions stand, and the market has shown it will react to each shift in tone, with prices dropping when a deal seems possible and jumping when it recedes. Investors are also watching shipping data for signs of whether flows through Hormuz keep recovering.

Oil Market Swings as U.S.-Iran Peace Talks Remain Stalled - The oil market on Monday erased its early gains but remained within last Thursday’s trading range amid the stalemate in U.S.-Iran peace talks. On Saturday, U.S. President Donald Trump rejected an Iranian peace proposal announced last week at the UN General Assembly. However, he said that U.S. negotiators were expected to engage in more talks this week. The crude market held support at its previous lows and extended its gains to $4.13 as it traded to a high of $96.54 early in the morning. The market later erased its gains and extended its losses to $1.16 as it posted a low of $91.25. It retraced some of its losses and settled in a sideways trading range during the remainder of the session. The November WTI contract settled up 19 cents at $92.60 and the November Brent contract settled up 96 cents at $105.78. The product markets ended the session in mixed territory, with the heating oil market settling up 7.06 cents at $4.7553 and the RB market settling down 5.57 cents at $3.3377. According to data from the Department of Energy, stocks of crude oil in the U.S. Strategic Petroleum Reserve fell to 283.8 million barrels last week, the lowest level since October 1982. According to sources, the White House is considering regulatory relief that would allow broader sales of red-dyed diesel as part of an effort to bring down prices, a move that could allow some buyers to avoid the federal fuel tax. The red-dye proposal has emerged from days of administration deliberations as one of the leading alternatives to a diesel export ban, which has been discussed as global supply disruptions drive prices to record levels. President Donald Trump has supported a ban, but that has faced widespread opposition from the oil industry and other parts of the business community. The administration has also been seeking voluntary commitments from major refiners to limit diesel exports. Energy Secretary Chris Wright has contacted executives at several major refiners to gauge their willingness to engage in such an action. A White House official said no final decisions have been made, but the president is weighing all options to lower prices. Kpler data showed that crude oil exports from key Middle East producers rebounded in September to 12.8 million bpd, the highest level since the U.S.-Israeli war with Iran started in February, as Saudi Arabia and the United Arab Emirates increased their exports. The rebound came following a recovery in exports via the Strait of Hormuz, which were set to hit about 7.4 million bpd this month, as Saudi Arabia diverted oil exports from the Red Sea port of Yanbu following attacks that damaged its East-West Pipeline. According to Kpler, while exports from the region have rebounded, they were still about 6 million bpd down from 18.8 million bpd in February. The region’s top exporter Saudi Arabia was on track to ship about 5.4 million bpd this month, rebounding from 2.446 million bpd in August. September shipments from the Ras Tanura port in the Gulf increased to about 3.6 million bpd from 929,000 bpd in August, but still lower than the 6.411 million bpd recorded in February. A total of 19 very large crude carriers, carrying 2 million barrels of Saudi oil each, exited the Strait of Hormuz last week. IIR Energy said U.S. oil refiners are expected to shut in about 542,000 bpd of capacity in the week ending October 2nd, increasing available refining capacity by 289,000 bpd. Offline capacity is expected to increase to 622,000 bpd in the week ending October 9th.

Oil prices climb again as Middle East supply risks persist - Global oil prices rose for a second consecutive session on Tuesday (September 29) as the prolonged US-Iran conflict raised fresh concerns over disruptions to crude supplies from the Middle East. Brent crude futures climbed $1.49, or 1.4 per cent, to $106.77 a barrel, while US West Texas Intermediate (WTI) crude gained $1.34, or 1.5 per cent, to $93.94. Both benchmarks had risen by about $1 in the previous session. Despite a recovery in regional exports, traders remain concerned about the cost and reliability of alternative shipping routes. KCM Trade chief market analyst Tim Waterer said increased exports from the Gulf were being facilitated partly through costly and slower ship-to-ship transfers, keeping upward pressure on prices. Data from commodities intelligence firm Kpler showed crude exports from major Middle Eastern producers rose to 12.8 million barrels per day in September, their highest level since February, driven mainly by higher shipments from Saudi Arabia and the United Arab Emirates. However, the figure remains about 6 million bpd below February levels of 18.8 million bpd. Meanwhile, Washington and Tehran have renewed diplomatic efforts to end the seven-month conflict, with officials from both sides holding indirect discussions through mediators. Talks could focus on a revised version of a seven-day ceasefire proposal put forward by Iran last week on the sidelines of the UN General Assembly. Analysts at UOB, however, said uncertainty remained high, warning that the prolonged US-Iran confrontation and the situation around the Strait of Hormuz could continue to fuel inflation and threaten global oil supplies.

Oil Softens after Red Sea Export Restart Eases Supply Woes -- Oil prices softened Tuesday morning as signs of higher Middle Eastern oil supply outweighed concerns over stalling U.S.-Iranian negotiations. By 08:50am EDT, ICE Brent for November delivery was down $2.17 to trade near $103.11 bbl, and NYMEX WTI for November delivery fell $2.21 to $90.39 bbl. Downstream, NYMEX ULSD for October delivery slid $0.0853 to $4.67 gallon, and front-month RBOB futures retreated $0.0517 to $3.286 gallon. The U.S. dollar index strengthened by 0.16 points to 101.085 against a basket of foreign currencies. Saudi Aramco last week partially restored flows on its East-West pipeline, allowing exports from the Red Sea port of Yanbu to resume after a two-week hiatus. In combination with oil shuttling operations in the Gulf of Oman running near maximum capacity, and an increasingly porous Iranian blockade of the Strait of Hormuz, Middle Eastern oil exports have rebounded to their highest since the start of the war in late February. Ship-tracking experts estimate flows to now average around two thirds of pre-war levels. U.S. and Iranian diplomats, meanwhile, continued the indirect exchange of messages via mediators after the White House on the weekend rejected Tehran's offer of a temporary ceasefire and a mutual lifting of naval blockades akin to June's so-called memorandum of understanding. While market participants welcomed the resumption of diplomatic efforts, reports suggested that negotiations have so far yielded little progress. Oil futures remained well on track for a third consecutive monthly increase. Supply, particularly of refined products, continued to fall short of meeting demand, as evidenced by globally rescinding inventories. In the U.S., distillate fuel oil inventories continued to hover near seasonal decade-lows, trailing the five-year average by 12%, according to the most recent Energy Information Administration (EIA) data. Weekly inventory estimates from the American Petroleum Institute are scheduled for release later today, followed by official EIA data on Wednesday.

Oil Prices Fall as Saudi Arabia Resumes Red Sea Exports - The oil market traded lower on Tuesday on signs of recovering crude exports from the Middle East, with the restart of the East-West pipeline in Saudi Arabia and the resumption of Red Sea oil exports. Trade sources stated that Saudi Arabia resumed oil loadings from its Red Sea port of Yanbu after restarting operations on the East-West Pipeline. In overnight trading, the oil market retraced some of Monday’s losses as it traded to a high of $94.74 after U.S. President Donald Trump said he has offered Iran nothing to end the war, rejecting media reports stating that he was willing to ease sanctions and release frozen funds for concrete steps regarding Iran’s nuclear program. However, the market erased any of its gains and sold off on the resumption of Saudi Arabia’s Red Sea oil exports. The crude market extended its losses to almost $3.54 as it sold off to a low of $89.06 ahead of the close. The November WTI contract settled down $3.22 at $89.38 and the November Brent contract settled down $2.69 at $102.89. The product markets ended the session in mixed territory once again, with the heating oil market settling up 14.26 cents at $4.8979 and the RB market settling down 5.95 cents at $3.2782. The Trump administration said it is offering to loan energy companies 40 million barrels of oil from the Strategic Petroleum Reserve, in an effort to control increasing fuel prices that have rallied on the widening war with Iran and Russia’s war on Ukraine. The White House has urged the European Union to draw down emergency diesel inventories in an effort to lower global prices, as President Donald Trump and his administration pursue a range of options to ease fuel costs ahead of November’s midterm elections. According to sources, the White House is frustrated that some European countries have not lived up to commitments made earlier this year to tap their emergency oil and petroleum reserves to help address supply disruptions and price spikes stemming from the Iran conflict and disruptions to shipping through the Strait of Hormuz. Iran’s parliamentary speaker, Mohammad Baqer Qalibaf, said no country in the region would be able to export oil if the Islamic Republic was prevented from selling its own oil. He said no regional infrastructure would be safe if Iran had no security. IEA head, Fatih Birol, said the IEA’s member states may discuss whether more strategic oil reserves could be released on the market in the future. He said “We are following the markets very closely, especially the product markets, diesel and others. If there is a need, of course, we will discuss with our member governments to take the necessary steps.” Valero Energy Corp reported flaring at its 85,000 bpd Wilmington, California refinery due to unplanned maintenance. BP Plc said it is proposing a six year contract term that would provide stability for the Whiting refinery and employees. It is proposing an extended notice period before the union can strike or before the company can initiate a lockout. BP said it will continue to meet with USW-71 representatives to find common ground as negotiations progress.

Oil Prices Climb as Trump Rules Out Easing Iran Sanctions | OilPrice.com -- Crude oil prices ticked higher today, after dipping on Tuesday, following reports that President Trump has no intention of easing sanction pressure on Iran, which has decimated exports from one of OPEC’s biggest producers. At 12;37 AM CDT, Brent crude was trading at $103.13 per barrel, and West Texas Intermediate was trading at $89.53, both set to end the month with a gain. For Brent, the gain is more pronounced, at around $10 per barrel, while for WTI, the gain would be about $3 per barrel. Earlier in the week, prices dipped slightly on the news that oil flows from the Persian Gulf have recovered to a level close to pre-war daily averages but there appear to be doubts about whether the recovery is sustainable. “Continued uncertainty over sanctions relief and negotiations is keeping a geopolitical risk premium embedded in prices,” analyst Sugandha Sachdeva, founder of India-based SS WealthStreet said, as quoted by Reuters. “Improving supplies could cap further gains, but renewed disruption or an escalation in tensions could ‌trigger another rally,” Sachdeva added. Data from Kpler has suggested oil exports from the Persian Gulf have rebounded strongly this month, with Hormuz flows alone at 13.2 million barrels daily, or 77% of pre-war levels, CNBC reported this week. An earlier report by Reuters citing Kpler data as well, pegged Hormuz flows specifically at 7.4 million barrels daily, with total Middle East oil export rates at 12.8 million barrels daily. “Despite more vessel traffic through the Strait of ‌Hormuz, flows remain below pre-conflict levels, keeping the market undersupplied,” UBS’ commodity analyst Giovanni Staunovo said, as quoted by the publication. It could be this shortfall that is keeping oil prices elevated, in addition to the still present risk for tankers in the Strait of Hormuz, in spite of the export recovery

Oil Hits Session High After DOE Shows Lowest Midwest Gasoline Stocks On Record -Oil prices rose to session highs after today's DOE inventory data refuted the latest cheerful API prints from Tuesday afternoon. Instead of the API-reported builds in distillates and gasoline, the DOE said that in the last week both products drew, with a modest increase in Cushing inventories, while crude inventories rose by 922K. API:

•     Crude +1.0mm
•     Gasoline +3.0mm
•     Distillates +0.3mm
•     Cushing +0.2mm

DOE:

•     Crude +0.922mm
•     Gasoline -1.684mm
•     Distillates -2.251k
•     Cushing +553mm

As Bloomberg notes, that’s a large draw of distillate fuels at 2.25 million barrels, well below the 300,000 barrels increase API saw. The October diesel contract is expiring today, so price action is a little murky, but the most-active contract is holding pretty strong gains near $4.75 a gallon. Cushing stocks saw another bounce off 'tank bottoms' even as crude inventories saw a modest increase, while product stocks both saw modest draws... Here' a look at some more of the data:

• PADD 1B gasoline -1,422k
• PADD 1 Distillates -254k
• PADD 3 crude +3,417k
• Refinery utilization -1.5ppt vs est. -0.3ppt
• Refinery crude inputs -554k b/d
• Crude imports -179k b/d
• Crude production +16k b/d

The 922,000 barrel build in commercial crude stockpiles was close to the 1 million barrel increase seen by the API on Tuesday. It compares with a Bloomberg survey of analysts that saw the stockpile shrinking by 710,000 barrels and Bloomberg users’ expectations just before the data were released of a 1 million barrel build. Stockpiles at Cushing, Oklahoma, rose to the highest since May. At 24 million barrels, inventories are inching further away from the 20-million mark generally seen as the minimum operating level for the storage hub. It’s the second straight week of builds at Cushing. Meanwhile, the US Strategic Petroleum Reserve declined by another 785K barrels; SPR stockpiles will continue to draw further throughout the end of the year after the energy department re-offered 40 million barrels of sour oil in a tender. The oil was offered as part of the exchange program, and must be returned in kind between 2027 and 2029. It’s to be seen if the government will be able to attract interest from traders and refiners. The minimum premium has fallen to 7% to 9.5%, compared with as much as 22% earlier this year. A total of 132 million barrels of crude has been taken out of the SPR since late March under a program to release 172 million barrels as part of a relief plan coordinated by the International Energy Agency aimed at lowering energy costs. That means that the build in commercial crude stockpiles was mostly offset by another 785,000 barrels withdrawn from the SPR. That reduced the overall nationwide crude build to just 137,000 barrels in the week to Sep 25. Taking a closer look, we find that gasoline stocks in the US Midwest are at the lowest level on record. Overall, the US has the least gasoline on hand since November 2014, with stockpiles falling by 1.68 million barrels. On a seasonal basis, PADD2 (Midwest) gasoline has also never been lower. Distillate fuel stockpiles in the US also remain at their lowest seasonal levels on record. Stockpiles fell in every single region. Exports, meanwhile, rebounded to 1.5 million barrels a day. While discussion of a US diesel export ban has died down a bit, it hasn’t faded entirely, and a number like this might revitalize some of those conversations. Linked to that, there was another big drop is US crude processing by refineries. Over the past three weeks, crude consumptions fell by 1.3 million barrels a day. That’s the lowest since May. Rates fell in all regions, with the exception of the Rockies Imports of Brazilian oil rose to the highest level since November 2024 and the highest level ever for this time of year, with the US importing nearly 500,000 barrels each day last week. While it’s unclear what’s driving the move, one explanation could be that strong American refinery runs are supporting demand for nearby foreign crudes while, at the same time, less Brazilian oil heads to Asia. At the same time, imports from Canada rose for the second time in three weeks. Shipments from the country remain fairly low at 3.4 million barrels a day, but there was an uptick nonetheless. PADD 2 takes the most Canadian crude out of any region, so the build in Cushing was likely at least partially due to shipments from the North. Bloomberg offers another take on falling refining crude processing: Canadian crude delivered via pipeline to both the US Gulf Coast and the Patoka hub are at a contango, a sign of weak demand. On the flip side, WTI at Houston is still in a backwardated structure. That can be partly explained by the light-heavy differential, that currently favors the use of light crude over heavy crudes from places like Canada and Venezuela. WTI futures jumped a few cents higher to session high in a knee-jerk reaction to the report. EIA data showed a relatively unexciting US crude stockpile build of roughly 900,000 barrels, but the markets focus is elsewhere this week - namely, diesel.

Oil Prices Rebound Amid Stalemate in U.S.-Iran Peace Talks - - The oil market on Wednesday retraced its previous losses and ended the session higher amid the continuing stalemate in U.S.-Iran peace talks. On Tuesday, U.S. President denied reports by Axios and CNN that cited U.S. officials as saying he was willing to give Iran sanctions relief and release frozen Iranian funds in return for steps by Iran on its nuclear program. Meanwhile, Qatar said it hoped that shuttle diplomacy between Iran and the U.S. could lead to a breakthrough. The oil market posted a low of $88.58 on the opening on Tuesday evening before it began to retrace its previous losses. The market extended its gains to over $2.50 as it posted a high of $91.96 by mid-day. The crude market later gave up some of its gains and settled in a sideways trading range during the remainder of the session. The November WTI contract ended the session up $1.04 at $90.42 and the November Brent contract settled up 94 cents at $103.53. The product markets ended the session higher, with the October heating oil contracts going off the board up 5.90 cents at $4.9569 and the October RB contract settling up 15.96 cents at $3.4378. Analysts have raised their 2026 oil price forecasts with benchmark Brent crude expected to average nearly $90/barrel as disruption to Gulf exports offsets concerns over demand growth. A September survey of 30 economists and analysts forecast that Brent crude would average $89.05/barrel in 2026, up from a previous forecast of $85.08/barrel and U.S. crude would average $83.90/barrel, up from a previous estimate of $80.20/barrel. The EIA reported that U.S. crude oil production in July increased 104,000 bpd to 13.948 million bpd. U.S. crude oil exports fell to 3.556 million bpd in July, down from 4.735 million bpd in June. U.S. total oil demand in July fell by 2.7% or 580,000 bpd to 20.612 million bpd. The EIA reported that gasoline demand in July fell by 2.5% or 231,000 bpd on the year to 8.946 million bpd, while distillate demand fell by 3.8% or 146,000 bpd to 3.685 million bpd. The Dallas Fed said oil and gas production in Texas, Louisiana and New Mexico increased in the third quarter of 2026. Oil and gas activity also expanded in those states over that same time period. On average, respondents expect a WTI oil price of $88/barrel in a wide range of $70 to $126, and a Henry Hub natural gas price of $3.29 per million British thermal units at year-end 2026. Sources stated that OPEC+ oil-producing countries are likely to keep their oil production targets steady for November when they meet on Sunday. The sources said no final decision had been made. A separate OPEC+ ministerial group called the Joint Ministerial Monitoring Committee, which does not decide policy, also meets on Sunday to review the market. IIR Energy said U.S. oil refiners are expected to shut in about 545,000 bpd of capacity in the week ending October 2nd, increasing available refining capacity by 298,000 bpd. Offline capacity is expected to increase to 668,000 bpd in the week ending October 9th.

Oil prices jump 2% as China halts fuel exports amid US-Iran war: Brent crude tops $100 - Oil prices moved sharply during Thursday's trading session. Prices initially fell by more than 1% before recovering and rising. The reversal came as traders assessed China's export restrictions, global fuel shortages and developments in the US-Iran conflict. Chinese refiners have been told to stop exporting oil products to regions outside Hong Kong and Macau until further notice. Four people familiar with the matter confirmed the development to Reuters on Thursday. The export restrictions could put further pressure on global fuel supplies. Markets are already facing supply constraints linked to the war and disruptions to refining operations. China's decision could reduce the amount of fuel available to buyers in international markets. UBS analyst Giovanni Staunovo said the export restrictions suggest that China is worried about the domestic availability of oil products. He added that it remains unclear whether the measures will lead China to increase crude oil imports after recent declines in its crude oil and fuel inventories, Reuters reported. Global diesel supplies have also tightened. Refining capacity has fallen following attacks linked to the wars in the Middle East and Ukraine. These disruptions have increased pressure on governments to take action to protect consumers from rising fuel costs. The Trump administration has urged Germany and France to use emergency diesel stocks. The United States has asked both countries to draw down their emergency diesel inventories to help ease global fuel prices. Three people familiar with the discussions told Reuters that the countries could face a potential US diesel export ban if they do not comply. European diesel refinery profit margins stood at around $80.05 per barrel at 8:29 GMT on Thursday, down approximately 4% from the previous session. The margins had reached an all-time high of $95 per barrel on September 23. Investors are closely tracking diplomatic efforts to end the US-Iran war. Alongside China's export restrictions and global fuel shortages, traders are monitoring developments in the Middle East to assess whether oil supplies could recover or face further disruption. Saudi Arabia has resumed loading oil tankers at Yanbu. The development followed the earlier restart of operations on the country's East-West Pipeline, which provides an alternative route for transporting crude oil towards the Red Sea. Reuters reported the resumption of tanker loadings on Tuesday.

Oil Steadies as Traders Assess Higher Flows, Export Bans -- Oil and product futures were mixed in a volatile morning session Thursday, with crude benchmarks advancing 1.5-2%, while ULSD's new front-month contract slipped following Wednesday's rally. By 9:00 a.m. EDT, ICE Brent for December delivery was up $1.77 to trade near $99.80 bbl, and NYMEX WTI for November delivery rose $0.67 to $91.09 bbl. Downstream, NYMEX ULSD for November delivery retreated $0.1234 to $4.5647 gallon, while front-month RBOB futures edged higher $0.0088 to $3.2693 gallon. The U.S. Dollar Index strengthened by 0.365 points to 101.555 against a basket of foreign currencies, having reached a 10-month high 101.755 earlier in the session. A tightening global fuels market has been supporting the oil complex, outweighing resurging crude exports from the Middle East. To secure domestic supply and combat surging prices, more and more countries have been implementing, extending or at least considering refined product export bans, which added to fuel supply woes. Russia has recently extended its existing diesel export ban until the end of October, and reports on Thursday suggested that China had suspended all fuel exports for at least the first week of this month. The U.S. administration has also been floating the possibility of a temporary ban on diesel exports, downplaying industry warnings about the cascading effects on supply and prices of other refined fuels. On Thursday, Reuters reported that the Trump administration urged European Union countries to release their emergency diesel stocks or face a U.S. export ban. In May 2025, the last month for which Eurostat has provided a detailed breakdown of emergency oil and product reserves, the EU sat on around 280 million bbl of strategic diesel reserves, with more than a third of volumes situated in Germany and France. Data from September 2026 showed that total strategic reserves were still high, as European countries have generally been slow to fulfill their IEA commitment. Diesel inventories in the U.S., meanwhile, have fallen to their lowest seasonal level on record. The U.S. Energy Information Administration on Wednesday reported that nationwide stockpiles of distillate fuel oil dropped to 105.2 million bbl last week, down nearly 15% year-on-year. On the East Coast, diesel and heating oil reserves are lagging year-ago levels by close to 29%.

Oil jumps 4% on reports China halts fuel exports, US troops head to Middle East (Reuters) - Oil prices ‌jumped on Thursday and settled up more than $4 a barrel, after a report, opens new tab said the US was sending more troops and carriers to the Middle East and China suspended oil products exports, stoking fears that global fuel shortages could worsen. The new front-month December Brent crude futures contract settled at $102.31 a barrel, up 4.37% or $4.28. US West Texas Intermediate crude futures finished at $92.87 a barrel, up 2.71%, or $2.45. A Wall Street Journal report said the US was sending a third aircraft carrier and up to 10,000 more troops to the Middle East as President Donald Trump weighed resuming strikes on Iran after the US midterm elections. Trump told reporters at the White House before departing on a campaign ⁠trip that he was weighing his options on Iran. "Now I have to make a decision. They'll either sign a very fair deal, or they won't exist any longer," he said. The comments, coupled with China's suspension of fuel exports, contributed to a volatile trading session. Oil prices fell 1% early but reversed course after Reuters reported that Chinese refiners had suspended exports of oil products beyond Hong Kong and Macau until further notice, citing four people familiar with the matter. "The Chinese export ban suggests concerns about domestic product availability," UBS analyst Giovanni Staunovo said, adding that it remains to be seen whether the measures will support higher crude imports after recent drawdowns in Chinese crude and fuel stocks. While crude supplies continue to reach the market, diesel and other refined products remain in short supply following damage to refinery infrastructure in the Gulf and Russia. Global diesel inventories are already tight after Russia, a top exporter of the fuel, banned exports through October. Industry participants said shortages were unlikely to end before next year. President Vladimir Putin said Russia will not supply diesel to global energy markets until sanctions against Moscow are lifted. "The ‌impact of ⁠China’s fuel export restrictions will not be as large as the loss of Russian and Middle Eastern refined oil product exports. However, it is another source of stress on global fuel markets when supply is severely constrained," said Hamad Hussain, senior climate and commodities economist at Capital Economics. US stocks rallied on Friday, with the Dow gaining half a percent, the S&P 500 adding about three-quarters of a percent and the Nasdaq climbing more than one percent. To mitigate pressure, the European Union's energy taskforce will meet on Friday to discuss a potential release of diesel stockpiles, two EU diplomats told Reuters on Thursday. Sources told Reuters the Trump administration told Germany and France to draw down emergency diesel inventories or face a potential US diesel export ban. In the meantime, diplomatic efforts ⁠to end the Iran war have been relatively subdued of late as attacks continue. On Tuesday, three Liberian-flagged oil tankers were struck by unknown projectiles when transiting the Strait of Hormuz, shipping intelligence service Marisks said in a Wednesday report. Iran is preparing a broader and more forceful response if the US resumes large-scale military attacks, sources said, while continuing a diplomatic push that Iranian officials privately see as unlikely ⁠to succeed. Lingering disruptions to global oil and fuel markets spurred analysts to raise their average Brent crude oil price forecasts for 2026 to $89.05 a barrel, although they noted signs of a gradual improvement in exports from the Middle East. Saudi Arabia resumed oil tanker loadings from Yanbu on Tuesday, after restarting operations on its East-West Pipeline. Meanwhile, Goldman Sachs estimated Gulf oil exports, including "dark ⁠exports" involving ships operating with their location transponders turned off, have recovered to 23.3 million barrels per day over the last week, in line with their 2025 average, as exports doubled in September, it said in a note on Tuesday.

Oil prices steady above $102 amid supply concerns — Arabian Post - Oil prices were broadly steady above $102 a barrel on Friday as traders weighed China’s suspension of fuel exports and an expanding US military presence in the Middle East against signs that regional crude supplies were recovering. Brent crude slipped 3 cents, or 0.03%, to $102.28 a barrel by 0350 GMT after edging higher earlier in Asian trading. US West Texas Intermediate fell 19 cents, or 0.2%, to $92.68, reversing small early gains. The subdued moves followed a sharp rally on Thursday, when Brent settled at $102.31, up $4.28, or 4.37%, and WTI climbed $2.45, or 2.71%, to $92.87. Prices had initially fallen before concerns over refined-fuel availability and Middle East security drove a rapid reversal. China’s refiners have suspended exports of oil products for October as Beijing seeks to protect domestic inventories. Major refiners entered the week-long national holiday without approval to ship diesel, petrol and jet fuel beyond Hong Kong and Macau, leaving uncertainty over whether exports will restart after the holiday ends on October 7. PetroChina cancelled several petrol and jet-fuel cargoes scheduled for October, while Zhejiang Petrochemical did not schedule product exports during the holiday week. China’s National Development and Reform Commission had not publicly clarified whether broader shipments would be authorised later in the month. The restriction has added pressure to a refined-products market already struggling with disrupted supplies from the Middle East and Russia. Commercial gasoil and diesel inventories in China were estimated at about 20 million barrels below levels Beijing considers adequate for restoring exports, while petrol stocks were roughly 9 million barrels short, according to Kpler. Asian diesel spreads strengthened after the export suspension. China loaded an estimated 1.4 million tonnes of diesel, 500,000 tonnes of petrol and at least 2 million tonnes of jet fuel in September, including bonded volumes destined for Hong Kong and Macau, with total shipments lower than in August. Geopolitical concerns also remained prominent. The US military is dispatching roughly 9,000 sailors and Marines aboard a group of ships to the Middle East, including the USS Theodore Roosevelt carrier strike group and the USS Makin Island amphibious readiness group. Their arrival could put three US aircraft carriers in the region by late October. The deployment comes as President Donald Trump considers further military action against Iran. Trump said in an interview published on Thursday that renewed strikes after the November 3 US midterm elections were possible, while declining to disclose operational details. Two US carriers, the USS George H. W. Bush and USS George Washington, are already in the region, alongside the USS Boxer amphibious readiness group. The additional deployment could raise the US naval presence to more than 20,000 sailors and Marines, together with hundreds of aircraft. At the same time, Washington has pressed Germany and France to release emergency diesel stocks as governments seek ways to ease elevated fuel prices. The US has asked the European Union to release 120 million barrels of diesel over six months, according to people familiar with the discussions. EU countries hold nearly 109 million tonnes of emergency crude and fuel inventories. Those prospective releases, together with improving Middle Eastern crude flows, helped restrain Friday’s oil rally. KCM Trade chief analyst Tim Waterer described the market as absorbing mixed signals after Thursday’s volatility, with stronger Saudi exports offset by the additional US carrier deployment and China’s export curbs. Brent was heading for a weekly decline of about 2% despite its Thursday surge, after gaining about 14% during September. WTI, which advanced about 4% last month, was on course for a weekly rise of roughly 0.3%. Oil’s reaction also reflected the importance of the $100-a-barrel level for Brent, which analysts regard as a key psychological and positioning threshold. Priyanka Sachdeva of Phillip Nova said immediate attention remained on the availability and movement of Middle Eastern crude and refined products to consuming markets globally.

Oil prices drop as Europe agrees to release diesel reserves -  Oil prices fell $2 after European leaders agreed on Friday to a request by US President Donald Trump to release diesel from their reserves to lower prices and reduce the need to import fuel from America. Brent was down $1.80, or 1.76%, at $100.50 a barrel at 10:49 a.m. CDT (1649 GMT). West Texas Intermediate dropped $2.02, or 2.18%, to $90.85 a barrel. For the week, Brent was down about 2.84% so far with WTI around 1.54% lower. European Union countries agreed to a French proposal to release additional diesel stockpiles, a source familiar with details of the discussion told Reuters. “Europe has just agreed to release a massive amount of their heavily stocked Diesel Oil,” Trump wrote in a post on Truth Social. Previously, Trump had said he was mulling a ban on US diesel exports. “Europe is feeling pretty vulnerable,” said Phil Flynn, senior analyst with the Price Futures Group. “Europe would be one of the areas to suffer the most if we put an export ban on diesel.” Iran says it receives US response to latest proposal as Washington pulls out of Iraq EU governments acted after discussing the proposal by France for European countries to release 50 million barrels of diesel, and for International Energy Agency members to release 50 million barrels of crude oil, three sources familiar with the discussions told Reuters. Under the proposal, Europe would release part of the diesel volumes in a 20-day period, two of the sources said. French President Emmanuel Macron chaired a videoconference with G7 leaders on Friday, the Elysee Palace said. It was not immediately clear if G7 countries had agreed to France’s proposal on the volumes of fuel to be released. “This highlights that the main stress in the energy market is no longer crude availability, with Middle East flows recovering, but rather refined product supply, constrained by reduced refinery capacity and output across the Middle East and Russia,” said Ole Hansen, head of commodity strategy at Saxo Bank. On Thursday, prices settled higher after Reuters reported that Chinese refiners had suspended oil product exports for October, looking to preserve domestic stocks. Also supporting prices, the Wall Street Journal reported that the US was sending a third aircraft carrier and up to 10,000 more troops to the Middle East as Trump weighed resuming strikes on Iran after the midterm elections. Hamad Hussain, senior climate and commodities economist at Capital Economics, said another release of oil stocks “could be enough to help tip the overall market back into a slight surplus if the recent pick-up in flows from the Middle East is sustained”. Barclays said in a note that despite better crude flows out of the Middle East, physical market fundamentals remained strong, with inventories still being drawn, and prompt cargoes commanding steep premiums over forward prices. It raised its fourth-quarter Brent forecast by $20 a barrel to $115 and lifted its 2026 forecast to $100 a barrel. Elsewhere, Ukraine has struck oil facilities in Russia’s Samara and Volgograd regions over the past 24 hours, President Volodymyr Zelenskiy said on social media on Friday.

Oil prices lower as G7 nations to release diesel stocks, Saudis reportedly plan attack on Houthis -- Crude oil prices edged lower Friday, after the Group of Seven nations announced the release of diesel and crude stocks to ease surging fuel prices. Brent crude futures, the international benchmark, lost 6 cents to close at $102.25 per barrel, while U.S. West Texas Intermediate crude shed $1.76 to settle at $91.11 per barrel. The G7 will deploy 100 million barrels of reserves over the next four months “with a frontloaded substantial diesel release within the first 20 days,” the group’s leaders said in a joint statement. The G7 are France, Canada, Germany, Italy, Japan, the United Kingdom and the United States. As Western nations prepare to release more stocks, tensions are simmering in the Middle East. Saudi Arabia is planning an offensive against Iran-backed Houthi militants in Yemen, regional and Western officials told Reuters. Oil prices settled higher in the previous session following a report that the U.S. is sending a third aircraft carrier strike group to the Middle East. The Trump administration has called on Europe to release diesel stocks as the world faces a fuel supply shortfall due to the wars in Eastern Europe and the Middle East. Treasury Secretary Scott Bessent said Thursday that “American farmers, truckers, and businesses should not be left carrying the burden of a global diesel shortage.” U.S. President Donald Trump has indicated the U.S. could impose a diesel export ban, but he appeared to cool on the idea earlier this week due to its potential impact on gasoline prices. The U.S. supplied around half of the EU’s diesel imports in August, according to the International Energy Agency, underscoring the 27-nation bloc’s exposure to a potential export ban.

Iran’s Disappearing Oil Is Becoming Everyone’s Problem - Iranian oil is disappearing from the market just as its biggest buyer returns for more. China’s recovering crude demand is colliding with the loss of a supplier that sustained its independent refiners through the crisis, forcing them to compete for increasingly expensive alternatives. The consequences reach beyond China: every replacement barrel tightens supplies for other buyers, while Tehran faces a growing incentive to disrupt the Strait of Hormuz, which is now carrying an unexpectedly strong 13 million barrels a day (just 5 million below pre-crisis level), while its own oil remains trapped. Iranian crude has long been an underestimated part of the global oil balance. After Bashar al-Assad’s government fell in December 2024, breaking the political relationship that sustained Iranian shipments to Syria, China became Iran’s only crude buyer - in 2025, it received an average of 1.4 million b/d. The war initiated by the US and Israel in late February initially made Iran even more important to Chinese buyers: while Tehran blocked other tankers from crossing Hormuz, its own cargoes passed freely, lifting Chinese intake of Iranian oil to around 1.76 million b/d in April. That competitive edge ended with the US blockade announced on April 13. Loaded tankers could no longer leave the Gulf, while empty vessels could not enter. Loadings at Kharg Island, Iran’s main export terminal, collapsed from 1.8 million b/d in March to 260,000 b/d in May. A June 17 memorandum allowing Iranian cargoes to pass for 60 days offered temporary relief: loadings recovered to 740,000 b/d in June and 890,000 b/d in July. But the reprieve expired in August, shipments slumped again to 250,000 b/d, and no Iranian loadings were observed in the Gulf in September. The more important part of the story, however, was unfolding outside the Strait. Iran had accumulated a vast floating stockpile that allowed deliveries to China to continue even when fresh cargoes could not leave the Gulf. In mid-April, that cushion stood at about 160 million barrels, spread across waters around South, Southeast and East Asia. Drawing on those stocks, China still imported 1.37 million b/d of Iranian oil in May, just 10% below February’s level. But the buffer was shrinking; floating storage fell to 106 million barrels by mid-June before the temporary reopening replenished it to 128 million by mid-July. That replenishment of available floaters has since stopped. China still received 980,000 b/d of Iranian crude in August, but only 475,000 b/d in September, with arrivals ceasing from September 26 (all of the last arriving cargoes had been loaded in June). Iran still has around 86 million barrels on the water, the lowest volume since January 2025. Yet 23 million barrels (more than a quarter) are trapped inside the Gulf. The total has barely changed since Chinese arrivals have wound down to an almost complete halt over the past two weeks, with evident loadings in the Kharg island stopping completely. With onshore storage gradually filling up (Kpler data suggests Iranian storage tanks are now 60% full, storing around 70 million barrels), Iran will face the inevitable choice of cutting production. Whilst roughly 2.2 million b/d of production is relatively safe due to demand from its refineries, Tehran’s pre-war crude output of 3.2 million b/d seems to be no longer achievable. For China’s ‘teapots’ (the smaller independent refineries concentrated in Shandong province), this removes a cornerstone of their crude supply. Accounting for roughly a fifth of Chinese crude imports, these refiners have built their purchasing strategies around discounted sanctioned barrels, particularly from Iran and Russia. Now they must search for barrels farther away, from the Middle East, West Africa and South America. In mid-September, ten Chinese independent refiners reportedly sent traders to Singapore to secure available supplies from the mentioned regions. The shift is visible at Shandong’s ports. Qingdao, connected by pipeline to 12 independent refineries, relied on Iran for 40% of its 690,000 b/d incoming flows in 2025. In recent months, it has increased purchases of Brazil’s Tupi and Buzios grades and even started receiving Guyana’s Golden Arrow in July, while still relying on Saudi and Russian supplies. Nevertheless, intake has fallen to a record low of around 150,000 b/d over the past three months. At Dongying, on Shandong’s northern Bohai coast, situated near 32 independent refineries, Russia and Iran supplied virtually all of last year’s 330,000 b/d intake, accounting for two-thirds and one-third respectively. Iranian deliveries started to decrease in summer months, with just two cargoes arriving in August and just one in September. Total intake fell to a mere 220,000 b/d in September as crude-deprived refiners were compelled to cut refinery throughputs. These refiners are being left with less oil and more expensive alternatives. Guyanese crude is particularly costly when long voyages coincide with an unprecedented shortage of very large crude carriers and record freight rates. To encourage independent refiners to increase runs, the Chinese government issued an additional 28.05 million tonnes of crude import quotas in late September, taking the annual allocation for non-state imports to a record high of 257 million tonnes. These quotas determine how much crude refiners are authorised to import, so the increase gives them room to buy more, but does little to make barrels available or more affordable. Competition for Russian oil is intensifying, too. Chinese buying has reportedly pushed ESPO differentials to an all-time high premium of $28/bbl vs ICE Brent, while Urals is also trading $7-8/bbl above the same benchmark. Independents must also compete with state-owned buyers, which currently account for roughly half of China’s seaborne crude imports, compared with 45% in February. China’s recovery is still at an early stage. Seaborne crude imports rose from 7.24 million b/d in August to 7.5 million b/d in September, but remain far below February’s 11.5 million b/d. During April–July, imports had fallen to roughly half that pre-crisis level, depressed by the Beijing-mandated refinery product export ban, lower refinery runs and a gradual shift towards SPRs usage. China’s strategic reserves (both state- and private-owned) remain at 1.12 billion barrels, down from 1.25 billion in April, but rebuilding imports while Iranian supplies disappear will put greater pressure on barrels available elsewhere. For Tehran, the imbalance is becoming harder to tolerate. Peace negotiations continue without a breakthrough, its crude remains blocked, and its export revenues are squeezed. Meanwhile, oil from neighbouring producers is moving through Hormuz at a surprisingly strong 13 million b/d. That recovery is both a relief for buyers and a vulnerability. As long as Iran cannot export, it has little economic incentive to preserve the arrangement allowing its neighbours’ barrels through. Mounting financial pressure could eventually push Tehran to disrupt those flows, even more than it did ever before. The market therefore faces two connected risks: China must replace Iranian oil as its demand recovers, and Iran may lose patience with a Strait that is reopening for everyone else. The disappearance of Iranian barrels is already tightening supply. A renewed disruption to Hormuz would make the cost of replacing them much higher.

Iran just handed the world a big clue that the war is nowhere close to ending anytime soon - The U.S. and Iran continue to negotiate over the status of the Strait of Hormuz. Meanwhile, reports describe an incident in the Strait this week. According to Reuters, citing the shipping intelligence service Marisks, three Liberian-flagged oil tankers were “struck by unknown projectiles” while transiting the Strait of Hormuz on Tuesday.The report says the ships were moving with their Automatic Identification System transponders turned off, a common practice in recent months as ships avoid detection while transiting the Strait of Hormuz. The ships were named as the oil products tanker Al Ruwais, the “Very large crude carrier” Mersin Prosperity, and the Aframax-sized tanker Sinbad. ADNOC Logistics & Services manages the first two, while Anglo-Eastern Tanker Management manages Sinbad. Seatrade Maritime News, meanwhile, reported that a fourth vessel, the VLCC Al Funtas, was also struck in recent days. The report added that, of those ships, only Sinbad is on Iran's list of “non-compliant vessels” subject to “fines, detention, or confiscation” for transiting the Strait.The latter report cited Vanguard Tech, which said: “the extent of damage to the three vessels remains unclear at current.”According to a report by Maritime Executive about the recent wave of strikes, they show that Iran is “lashing out to demonstrate that it is still threatening vessels,” amid reports that Iran’s grip on the Strait of Hormuz has been loosening.That report also cited Iran’s Fars News Agency, which claimed that warning shots had been fired at vessels trying to get through the Strait on Tuesday.These reports follow last weekend’s reporting from NBC News, which stated Iranian forces on September 14 had struck a ship that U.S. forces were on in the Strait of Hormuz, which led to injuries – including smoke inhalation and possibly traumatic brain injuries — for those service members, who were not on a Navy ship at the time. Seven of the injured were enlisted, while one was an officer, and all have since returned to duty, NBC said.  It took two weeks for the first news reports to break. The War Zone reported that while it’s unclear which ship the service members were on, there’s a “strong possibility” it was the former British Royal Mail vessel RMS St Helena, converted into a “floating armory.”TWZ had not confirmed that this was the ship, and CENTCOM did not comment.However, Trade Winds News reported more definitively, shortly after the attack, that Iran had “attacked a historic former British Royal Mail passenger ship in the Strait of Hormuz,” although that report did not state that U.S. service members were on board.How, exactly, did Iran’s grip on the Strait loosen? A series of media reports in recent days has examined how that happened. According to the Wall Street Journal, Iran’s ability to “choke off oil” flowing through the crucial waterway has weakened, along with its leverage in talks with the U.S. That’s because both the U.S. Navy and Gulf oil producers have improved their ability when it comes to “fending off or evading Iranian attacks, allowing more tankers to cross the strait.”As a result, Middle Eastern crude oil exports have rebounded to nearly 80 percent of their prewar levels, the Journal said, citing Kpler data.Factors include Saudi Arabia getting its East-West Pipeline back online and other workarounds.Separately, Bloomberg News reported this week that Sheik Khaled bin Mohamed Al Nahyan, Abu Dhabi’s crown prince, is spending billions of dollars on a project called “Zero Hormuz.”  The Sheik, who earlier this year took control of L’imad Holding, a $300 billion sovereign wealth fund, is working to build new port infrastructure needed to achieve the goal of “overriding Iran’s stranglehold over the Strait of Hormuz.” The fund announced it is taking Abu Dhabi Ports Co. private at a valuation of over $9 billion, aiming to reduce dependence on the Strait of Hormuz.Meanwhile, The Economist reported that President Donald Trump’s public rejection, earlier this week, of Iran’s latest ceasefire proposal came because Trump feels it’s a better idea to wait.

Three Ships Struck in the Strait of Hormuz as IRCG Says US Isn't Responding to Attacks - -The UK Maritime Trade Operations (UKMTO) said on Wednesday that three ships had been struck by projectiles in the Strait of Hormuz a day earlier, as Iran’s Islamic Revolutionary Guard Corps (IRGC) suggested it has been continuing daily attacks on vessels in the strategic waterway. Hossein Mohebbi, a spokesman for the IRGC, said the US has “not been responding” to the attacks. Several weeks ago, the US began what was called a “tanker for tanker” policy where it would bomb Iranian tankers in response to attacks on US ships, but it appears to have backed down on the strategy.  “We have been hitting small ships and preventing them from passing for a long time, but America does not respond,” Mohebbi said, according to The Cradle. “There is a military confrontation in the Strait of Hormuz every 24 hours. For some time now, the US has not been responding.”  Also on Wednesday, energy data firm Kpler said crude exports from the Gulf nations, except Iran, have reached pre-war levels, with 40% of shipments bypassing the Strait of Hormuz through pipelines, up from 17% before the war.  Oil has been exiting the strait mainly by smaller tankers conducting ship-to-ship transfers from larger tankers inside the Gulf to others in the Arabian Sea, as well as by supertankers escorted by the US Navy. At least one of the ships that was struck on Tuesday was one of the smaller tankers, which shut off their AIS while transiting the Strait of Hormuz to avoid detection. Iranian officials said Wednesday that they received an official response from the US in the Qatar-mediated negotiations. But the chances of a breakthrough still appear unlikely as the two sides remain far apart, and US officials reportedly expect President Trump to resume bombing Iran after the midterm elections.

Tanker struck by unknown projectile in Strait of Hormuz: UK maritime agency - A tanker was struck by an unknown projectile while transiting the Strait of Hormuz on Friday, said the UK Maritime Trade Operations (UKMTO). The ship’s master reported that the tanker was hit during an outbound transit through the strait at 1122GMT, according to UKMTO. The strike caused a small fire and a blackout aboard the vessel, it said. The fire was later extinguished and the vessel is underway, it added. No casualties or environmental impact were reported from the incident, according to the agency. Authorities are investigating the incident, while the agency advised vessels transiting the area to exercise caution and report any suspicious activity.

India says 5 citizens rescued after Kuwait-flagged tanker hit by projectile in Hormuz Strait - India on Saturday said five of its citizens had been rescued after a Kuwait-flagged tanker was hit by a projectile in the Strait of Hormuz. The Indian Embassy in Oman said on US social media company X that it had coordinated the rescue of five Indian citizens on board the Kuwait-flagged tanker MT Kazimah III, that were “struck by a projectile in the Strait of Hormuz.” “All 5 Indian nationals have been shifted ashore safely,” the embassy said. “We thank the Omani authorities for their continued support and assistance.” “We remain committed to the safety, security and welfare of our seafarers abroad,” India's Ministry of External Affairs spokesman Randhir Jaiswal said on X. Regional tensions have remained high since the US and Israel launched attacks on Iran on Feb. 28, prompting Tehran to retaliate against Israeli targets and US military facilities across the region. The war has also severely disrupted navigation through the Strait of Hormuz, a key route for global energy supplies. Iran has since linked the full reopening of the Strait of Hormuz to measures including an end to hostilities, sanctions relief, the release of frozen assets and the implementation of commitments by Washington.

Report: Ansar Allah Tells EU It Won't Target European Ships - - Yemen’s Ansar Allah, also known as the Houthis, has told the EU that it doesn’t intend to target European shipping, The Financial Times has reported, as the group has maintained that its Red Sea blockade applies only to Saudi shipping. Ansar Allah began its blockade on Saudi shipping after Saudi Arabia launched airstrikes against the Sanaa International Airport back in July, which reignited the war after a ceasefire had held relatively well since 2022.The FT report said Ansar Allah sent the EU a letter saying its ground offensive, which has involved the group taking over the Red Sea port city of Mocha and islands in the Bab el-Mandeb Strait, wouldn’t affect international shipping.Ansar Allah has also conveyed a similar message to the US, as a US-Ansar Allah ceasefire reached in May 2025 remains in effect, something President Trump has made clear. The US president said last week that his administration is in “constant communication with the Houthis and that they have agreed not to fight the United States.”Ansar Allah has also made clear to the US that there would be consequences if the US directly joins the Saudi war, with one official warning US “interests” would be targeted in the region in response and that the Bab el-Mandeb would be shut to US shipping.Back in 2024, the US and the UK began a bombing campaign against Ansar Allah over its blockade on Israeli-linked shipping in the Red Sea, which was imposed in response to Israel’s genocidal war in Gaza. In response to the US-UK bombing campaign, Ansar Allah began targeting US and British-linked shipping in the region, and the US-UK strikes failed to stop the attacks. While it hasn’t entered the current war directly, the US is still providing significant support for Saudi Arabia’s bombing campaign in Yemen. According to recent reports, up to 200 US military advisors are in Saudi Arabia providing targeting and intelligence support. The UK also announced recently that it would begin refueling Saudi warplanes, and France said it will send troops and military equipment to help “protect” the Saudi port city of Yanbu, where Ansar Allah has repeatedly targeted oil infrastructure.

Saudi Airstrikes on Yemen Market Kill at Least Seven: Yemeni Health Ministry - (video)Saudi airstrikes hit a market in Yemen’s Taiz province on Sunday, killing at least seven people and wounding 40, including five children, according to Ansar Allah officials and Yemeni media reports. Footage from Yemen’s Al Masirah TV shows the aftermath of the strike, which hit several shops, and Yemeni civilians being treated for their wounds. The Health Ministry within the Ansar Allah-led Yemeni government said that it condemned “this horrific crime committed by Saudi enemy aircraft through their direct and deliberate targeting of civilian objects.” Footage via Al-Masirah TV.  Sources from the Saudi-backed Yemeni government, whose leadership is based in Riyadh, claimed in comments to Reuters that Ansar Allah, also known as the Houthis, set up a military camp in the area. The Saudi-backed Yemeni government claimed that it carried out a strike targeting Ansar Allah in the same location, but it hasn’t had a real air force since Ansar Allah took control of Sanaa in 2014, and it relies on Saudi Arabia for air power. Saudi Arabia was notorious for frequently hitting civilian targets during its war against Ansar Allah from 2015 to 2022, and there have been an increasing number of civilian casualties since the war was reignited by the July 13 Saudi airstrikes that targeted the Sanaa International Airport. The US strongly backs Saudi Arabia’s air campaign in Yemen by providing intelligence and targeting support, plus the fact that Saudi Arabia uses US-made F-15 fighter jets and US-provided bombs to carry out many of the strikes. So far, the US has refrained from entering the war directly, and a ceasefire reached between the US and Ansar Allah in May 2025 remains in effect.  Ansar Allah has continued launching missile and drone attacks on Saudi Arabia, and more are expected following the market bombing. “This bloodshed, unjustly and aggressively spilled in the Mawiyah market in Taiz Governorate, will have dire consequences for the Saudi aggressors, God willing,” Ansar Allah military spokesman Yahya Saree said in a statement on the attack, which also said the strikes were carried out by an F-15.In a separate statement, Saree said that over the past 24 hours, Saudi forces “launched 26 airstrikes using F-15 fighter jets that took off from Khamis Mushait Air Base, targeting the provinces of Taiz, Al-Jawf, Marib, Dhamar, and Saada.”“These attacks resulted in dozens of civilian casualties, bringing the total number of Saudi-led airstrikes and missile attacks since the escalation began to 1,085,” Saree added.

Ansar Allah Says Saudi Arabia Launched 35 Airstrikes in Yemen Over 24 Hours - -Ansar Allah military spokesman Yahya Saree said on Tuesday that Yemeni forces recorded 35 Saudi airstrikes over the previous 24-hour period, which comes as ground fighting between Ansar Allah and Saudi-backed forces continues mainly in the southwestern Taiz province.“Over the past 24 hours, Saudi warplanes launched 35 airstrikes using F-15 and Typhoon aircraft, taking off from Khamis Mushait and Taif airbases,” Saree wrote on Telegram.Saree alleged that the “strikes targeted civilian infrastructure, including communications networks and schools, in the governorates of Taiz, Al-Jawf, Amran, Saada, and Hodeidah.” He added that the latest attacks bring the “total number of Saudi-led airstrikes and missile attacks since the escalation began to 1,158.”Separately, Yemen’s National Human Rights Authority, a rights monitoring group that operates in the part of Yemen governed by Ansar Allah, which is where most Yemenis live, accused “Saudi enemy forces” of killing a girl in a mortar attack in the Maqbanah District of Taiz. A day earlier, Yemeni media reported that a Saudi strike on a civilian home in Taiz killed four people, including an elderly man and three women. Saudi Arabia was notorious for bombing civilian areas during its war against Ansar Allah from 2015 to 2022, and the current conflict, which was reignited by Saudi airstrikes on the Sanaa International Airport in July, has followed a similar pattern. The US is supporting the Saudi airstrikes by providing targeting and intelligence support. Also on Tuesday, Arab News reported that an Ansar Allah missile attack hit a base belonging to the Saudi-backed government in the southern Lahj province, killing at least eight fighters.The US and other countries that back Saudi Arabia have so far refrained from directly entering the war by launching airstrikes in Yemen. Ansar Allah has made clear that it would respond to such escalations by ramping up its Red Sea blockade, which currently applies only to Saudi shipping.

Signs Of Fresh Houthi Attack On Saudi Aramco Facilities - At a moment there are widespread reports that Persian Gulf exports are fast recovering, there are simultaneous emerging albeit delayed reports of new tanker attack incidents that happened Tuesday. On apparent crude transit recovery amid continued deep uncertainty, "For now, that reduces fears of an immediate crude shortage and explains why prices can fall even though talks between the US and Iran have made no clear progress," Simon-Peter Massabni from XS.com says. "The market's main question is whether this faster pace of shipments can be sustained through October."But the UK's Maritime Trade Operations agency has announced more vessel incidents which looked to have happened on Tuesday. Three distinct incident advisories detailing strikes on vessels within the region. The affected ships included a liquefied natural gas carrier and a crude oil tanker, both of which were reportedly impacted by unidentified projectiles - with little other details known.We reported earlier on one of the three assaults, which involved a Very Large Crude Carrier in the Strait of Hormuz getting hit by a drone, after which a fire briefly erupted but was extinguished, and the tanker traversed on, and with no casualties.In the meantime Islamic Revolutionary Guard Corps (IRGC) spokesman Hossein Mohebbi has proclaimed that there is a "military conflict" in the Strait of Hormuz on a daily basis but that the US is not responding."We have been hitting small ships and preventing them from passing for a long time, but America does not respond," Mohebbi told semi-official Fars news agency.Axios late in the day Tuesday had cited "little progress" in US-Iran indirect talks, with on Wednesday an Al Jazeera correspondent saying that Washington has submitted a counter-proposal to Tehran. Here's more from Axios which basically contradicts much of their own earlier in the week reporting:  Efforts this week by Qatari mediators to broker a diplomatic breakthrough between the U.S. and Iran have made little progress, with neither side willing to budge, according to three sources familiar with the talks. The stalemate bolsters the belief on both sides that a renewed military conflict is becoming more likely. U.S. officials think President Trump could order a return to major combat operations after the midterms. Update(1159ET): While very unconfirmed at this early stage, the Houthis have reportedly attacked the Abqaiq oil city in eastern Saudi Arabia this afternoon (local), reports IRNA citing anonymous news sources. Abqaiq is at the heart of of Saudi crude processing, and it has been struck previously in the context of the Saudi-Yemen conflict. However, there have been conflicting reports, with some open-source accounts offering satellite imaging saying there are signs of a large fire at the site: No official sources have confirmed a Wednesday attack as of yet. Early purported images circulating:

Saudis plan assault on Houthis to break Red Sea chokehold (Reuters) - Saudi Arabia is planning an offensive against Iran-backed Houthi militants in Yemen, with options being considered including a coastal push to secure the Red Sea shipping route or an assault on multiple fronts, regional and Western officials told Reuters. The operation, expected to be launched in the coming weeks, will by led by Yemeni forces on the ground, which are overseen by Riyadh, and supported by Saudi air strikes, according to six people with knowledge of the preparations. While the US is already providing intelligence to support Riyadh's operations in Yemen, and some regional and European nations are providing mainly defensive military aid to the kingdom, the Saudi allies aren't expected to play a direct role in combat operations, said the people who requested anonymity to discuss security matters. Saudi Arabia entered neighboring Yemen's civil war in 2015 at the head of an Arab coalition in support of the internationally recognized government, which the Houthis had driven out of the capital Sanaa. A truce agreed between the warring parties in 2022 largely held until this year when the Houthis launched missile and drone attacks on Saudi shipping and oil infrastructure in a spillover from the Iran war. A key objective of the planned Saudi offensive, which hasn't been previously reported, is aimed at reversing the rapid gains made by the Houthis last month when they advanced down the coast and seized control of the Bab el-Mandeb strait, according to the people with knowledge of the plans who include Gulf and Yemeni officials and Western diplomats. The Saudis are considering two possible options for the assault, the Gulf and Yemeni officials said: Either a narrowly focused attack on the area around Bab el-Mandeb or a broader offensive that also includes other synchronized attacks on multiple fronts around Yemen, in the governorates of Al-Bayda, Marib, Taiz and Al-Jawf. More than 100,000 Yemeni troops could be mobilized in the offensive, depending on the scale, the officials all said. Spokespeople for the Saudi and Yemeni governments, the Houthi group and the US military didn't immediately respond to requests for comment about the Saudi plans.

Israeli Strikes Surge Across Southern Lebanon in Latest Escalation -  On Saturday, Israeli officials reported that Hezbollah carried out an explosive drone attack against their troops. Notably, the drone was described by the IDF as having been “launched toward” their troops, but it caused no damage or casualties.  Israel responded with yet another substantial escalation of Israeli strikes against southern Lebanon. Intense shelling was reported against Mansouri, and an Israeli Apace helicopter attacked a main commercial center of Mayfadoun.  Israeli tanks fired shells at Hadatha, and machine gun fire was reportedly directly at Beit Yahoun. Many of these villages are under standing evacuation orders, and there were no reports of casualties, though considerable destruction was reported.   White phosphorus munitions were fired against Nabatieh al-Fawqa and Zawtar al-Sharqiyah, setting fires. Lebanese Army personnel disarmed unexploded ordinance dropped by Israeli forces in and around Majdal Selm. Having spent hours attacking residential and commercial districts around southern Lebanon, the IDF did what the IDF does, and issued a statement saying that they’d been hitting “Hezbollah infrastructure,” providing no evidence that any such infrastructure was actually hit. 

IDF Declares Mostly-Destroyed Lebanese Town of Mansouri ‘Finished’ After Huge Explosion - - Israel launches attacks on several locations in southern Lebanon on any given day. That’s barely news in and of itself anymore, but one of the sites most persistently targeted in recent weeks was the town of Mansouri, in Tyre District.In early August, Israel’s military imposed a full evacuation order on Mansouri, and the attacks started scaling up. At this point, the town appears to have been largely destroyed, and the IDF declared today that their Combat Engineering Unit has “finished” destroying Hezbollah infrastructure in that town.They reported 600 “Hezbollah infrastructure” sites destroyed, which are more commonly referred to as civilian homes and commercial sites. The IDF said the destruction was meant to ensure Hezbollah could never reestablish itself in the area. Today’s completion of operations came after a massive explosion in the town, which could be heard across the district, and after which smoke could be seen rising over the town, to the extent it can be called a town anymore.Earlier this summer Israeli DM Israel Katz said that a number of Lebanese villages had to “disappear,” but previously those were immediately along the border with Israel. Mansouri, by contrast, is about 10 km north of the boundary, but seems to have similarly been wiped out.

Mass Funeral Held in Central Gaza for Dozens of Palestinians Killed by Previous Israeli Attacks - News From Antiwar.com   A mass funeral was held in the Nuseirat refugee camp in central Gaza on Tuesday for dozens of Palestinians killed by previous Israeli attacks, whose remains have been recovered from the rubble.  Reports vary on the number of people who were buried during the funeral, with Reuters reporting 41 and the Yaffa News Network reporting that 51 Palestinians were mourned.Mohammad Abu Nabhan, a 42-year-old Gaza resident, told Yaffa that he was mourning 13 members of his family, including his mother, two brothers, their wives and children, who were killed by an Israeli strike on the family home in July, 2025.Areej Farajallah, 36, said that she was saying goodbye to her husband, Samir, who was killed by an Israeli strike in November 2024. She said she had only two of his bones to bury, calling it “better than nothing.”“There are mixed feelings between relief, sadness, and pain. But thank God, the fire in my heart has eased a little, because my husband now has a grave that my orphaned children and I can visit,” Farajallah told Reuters.Gaza’s rescue workers have struggled to dig bodies out of the rubble as the US and Israel are still blocking construction equipment from entering the Strip and preventing reconstruction, a joint decision made by the two countries. There have been multiple mass funerals held in Gaza this year, including one in Gaza City earlier in September, where about 100 Palestinians, including 62 children, were buried.Gaza’s Civil Defense said on Tuesday that there will be another mass funeral for 105 Palestinians in Gaza City on October 1. “May God have mercy on the martyrs and grant their families patience and strength,” the agency said on Telegram.     Gaza’s Health Ministry said that since the ceasefire deal, which Israel has constantly violated, was signed in October 2025, 834 bodies have been recovered from the rubble. It’s estimated that more than 8,000 remain buried, including many on the Israeli-occupied side of the strip, where the IDF has continued demolitions and has been removing rubble, raising questions about whether human remains are also being removed.

Smotrich Calls for Israel To Do in the West Bank 'What We Did in Gaza' as IDF Imposes Week-Long Closure -   Israeli Finance Minister Bezalel Smotrich has called for Israel to “go to war” in the Israeli-occupied West Bank in the same way it did in Gaza, as the Israeli military imposed a complete closure of the West Bank for one week, further restricting the movement of Palestinians. “I think we need to go to war in Judea and Samaria (the West Bank). Do there what we did in Gaza. Dismantle the Palestinian Authority, which is a terrorist authority,” Smotrich said in an interview with Ynet that was published on Sunday.When asked what he meant, Smotrich referenced an Israeli military campaign in the northern West Bank refugee camps of Jenin, Tulkarem, and Nur Shams that began in January 2025 and involved the forced displacement of more than 30,000 Palestinians from their homes. The refugee camps remain empty today as the residents haven’t been allowed to return, and many of the roads and buildings in the camps have been destroyed.“We’ve already done it. There are three refugee camps there that are empty,” Smotrich said. He framed the forced evacuation as a way to “protect” the population, but Smotrich has been explicit about his desire for more Palestinian land and said in the interview that he wants to annex swathes of territory in Gaza and Lebanon.“I would like us to annex at least as far as the yellow line in Gaza and as far as the Litani River in Lebanon, because a war that ends along the same lines where it began will not prevent the enemy from going to war again next time,” he said. Smotrich’s interview came as settler and Israeli military violence against Palestinians in the West Bank continues to skyrocket. Amid the escalations, the Palestinian news agency WAFA first reported on Sunday that the Israeli military has “imposed a comprehensive closure on the occupied West Bank and closed border crossings, citing the Jewish holidays,” which includes “tightened military restrictions at checkpoints.”

Smotrich Says the Key To Forcing Palestinians Out of Gaza Is To 'Take Away Their Hope' - - Israeli Finance Minister Bezalel Smotrich has repeated his calls for the ethnic cleansing of Gaza and the re-establishment of Jewish settlements in the Palestinian territory in a new interview with Israel’s Channel 14 that was published on Monday.  Smotrich, who also holds a position in the Israeli Defense Ministry, said that the key to forcing Palestinians out of Gaza is to “take away their hope” and keep them in a tiny, crowded part of the Strip that will never be rebuilt.“The biggest key to migration is: take away their hope. As long as they think that one day there will be reconstruction there, and then it will flourish again — if you annex up to the Yellow Line, and that’s ours, and then what remains is tiny, crowded, and destroyed, everyone will understand that there’s nothing to look for there. They’ll start looking for solutions for where to go,” Smotrich said.Smotrich made similar comments in May 2025 when he was discussing an Israeli plan at the time to push all of Gaza’s civilians into a concentration camp in a tiny area in southern Gaza.“The Gazan citizens will be concentrated in the south. They will be totally despairing, understanding that there is no hope and nothing to look for in Gaza, and will be looking for relocation to begin a new life in other places,” he said.In the Channel 14 interview, Smotrich complained about Egypt not opening its borders to Palestinians from Gaza and said that European countries should take them in.“Listen, if every country in Europe were willing to take 20,000–30,000 refugees from Gaza, this whole thing would be over. But they really, really love the Gazans when they’re stuck here, like a thorn in our side,” Smotrich said.