oil price at a seven month high; largest US crude inventory increase in three years; distillates imports at a three year high

US oil prices finished higher for the eighth time in ten weeks as talks between US and Iran concluded without an agreement and oil analysts raised their forecasts for 2026 oil prices….after trading in the March oil contract expired 5.9% higher last week as a breakdown of talks between Russia and Ukraine, a US troop buildup around the Persian Gulf, and Trump’s saber rattling against Iran increased the geopolitical risk premium on crude, the contract price for the benchmark US light sweet crude for April delivery, which had settled at $66.48 a barrel​ on Friday​, declined in early Asian trading on Monday following President Trump's announcement of an increase in U.S. tariffs on ​all global imports, triggering uncertainty about global economic growth, and were down about 1% as markets opened in Europe, as the U.S. and Iran readied for a third round of nuclear talks, alleviating concerns of a worsening conflict, but rose Monday morning in New York as the market awaited developments in the Middle East ahead of another round of U.S.-Iranian nuclear talks slated for this week, before retreating to settle 17 cents lower at $66.31 a barrel amid increased economic uncertainty after the latest U.S. tariff upheaval….oil prices climbed in Asian trading on Tuesday, as traders priced in a significant geopolitical risk premium ahead of Thursday’s high-stakes negotiations in Geneva, and hovered near seven-month highs early in the US session on reports ​t​hat the State Department ​was evacuating non-essential personnel from the U.S. embassy in Beirut, but reversed and settled down 68 cents or 1% at $65.63 a barrel after Iran said it was prepared to take any necessary steps to reach a nuclear deal with the U.S., after weeks of increased military deployment by the U.S. in the Middle East….oil prices rose close to seven-month highs in Asian trading Wednesday amid growing concerns about a possible escalation of the military conflict between the United States and Iran, and were mostly higher early Wednesday morning in New York, as both Iran and the U.S. indicated they would make few concessions in talks over the White House's attempt to shut down Tehran's nuclear program, but turned south to extend the week’s losses after the EIA reported the largest US crude inventory increase in three years, and settled 21 cents lower at $65.42 a barrel as ongoing developments surrounding US-Iran talks in Geneva during the session drove whipsaw moves in crude futures…oil prices were largely steady in Asian trading on Thursday as markets braced for the third round of U.S.-Iran nuclear talks later in the day, a pivotal event for the near-term price trajectory, then posted modest gains on global oil markets as traders repositioned ahead of a fresh round of diplomatic engagement between the United States and Iran, with geopolitical risk premiums creeping back into crude benchmarks, but tumbled 2% as the markets opened in New York as the crucial U.S.-Iran talks began in Geneva in what analysts saw as one last attempt to reach a nuclear deal through diplomacy, then partly recovered to settle 21 cents lower at $65.21 a barrel after a choppy session as traders tracked developments in talks between the United States and Iran, weighing potential supply concerns if hostilities should escalate….oil prices edged higher as global markets opened on Friday, after diplomatic efforts between the United States and Iran aimed at easing tensions over Tehran's nuclear program concluded on Thursday without an agreement, but dipped as the US and Iran extended their nuclear talks, easing supply fears, while OPEC+ was to consider resuming output increases at Sunday’s meeting, then regained their upward momentum in New York trading as limited progress in U.S.-Iran nuclear talks and evacuations by Washington of diplomatic staff and their families in the Middle East raised expectations of an imminent military strike on Tehran, and surged as much as 3.7% as economists and oil market analysts hiked their oil price forecasts for 2026 amid rising geopolitical tensions and heightened war premiums due to the U.S.-Iran standoff, before settling $1.81 higher at a seven month high of $67.02 a barrel on the increasing prospect of U.S. military action against Iran, after U.S. President Trump said force might be necessary to get OPEC's fourth-largest producer to abandon its nuclear program, leaving oil prices 0.9% higher for the week, while the benchmark US light sweet crude contract for April delivery finished 0.8% higher…

Meanwhile, natural gas prices finished lower for a fourth consecutive week on a seasonally small inventory draw and forecasts for mild March weather….after falling 6.0% to $3.047 per mmBTU last week on a warmer forecast and the third straight lower than expected inventory withdrawal, the price of the benchmark natural gas contract for March delivery opened 3.3 cents higher and climbed early Monday, building on Friday’s short-covering rally sparked by forecasts for widespread weekend winter storms, and held above $3 though midday on prospects of an early March northern cold snap, even as ample supply limited bullish excitement, but settled 6.2 cents lower at $2.985 per mmBTU, as the fierce northeast blizzard failed to support prices…natural gas prices opened 3.9 cents lower on Tuesday amid steady production and above-average temperature covering much of the country, but failed at a midday attempt to reclaim $3 to settle 7.0 cents lower at $2.915 per mmBTU, as traders braced for spring weather and rapidly receding storage withdrawals…March natural gas opened 5.5 cents higher on the last day of trading for that contract Wednesday, and rose cautiously through the morning, even with little change to market fundamentals, continued strong LNG demand, and forecast mild March temperatures, then ​p​ulled back throughout the afternoon to settle 5.4 cents higher at $2.969 per mmBTU on short covering ahead of the contract’s expiration, while the more actively traded natural gas contract for April delivery settled 3.7 cents higher at $2.868 per mmBTU…with the markets now citing the price of the benchmark natural gas contract for April delivery, that contract opened 6.8 cents lower on Thursday, pressured by expectations for a quite modest storage withdrawal, robust production levels, and forecasts calling for warmer weather into March, but ascended throughout the afternoon to hit the intraday high of $2.866 per mmBTU just ahead of the 2:30PM close, before settling 4.1 cents lower at 2.827 per mmBTU​,​ after the lean EIA inventory report all but erased this winter's storage deficit…natural gas futures edged up overnight and opened higher Friday, supported by forecasts calling for another round of wintry weather, and held modest gains through midday, as mostly mild forecasts teased a potential mid-March cool shot amid strong LNG demand, and settled 3.2 cents higher at $2.859 per mmBTU as natural gas traders tried to balance hardy export activity and bargain buying against weakening weather demand and stout supply, but still finished 6.2% lower on the week, while the natural gas contract for April delivery, which had been priced at $2.984 per mmBTU at the end of the prior week, finished 4.2% lower….

The EIA’s natural gas storage report for the week ending February 20th indicated that the amount of working natural gas held in underground storage fell by 52 billion cubic feet to 2,018 billion cubic feet by the end of the week, which left our natural gas supplies 141 billion cubic feet, or 7.5% above the 1,877 billion cubic feet of gas that were in storage on February 20th of last year, but 7 billion cubic feet, or 0.3% below the five-year average of 2,025 billion cubic feet of natural gas that had typically been in working storage as of the 20th of February over the most recent five years….the 52 billion cubic foot withdrawal from natural gas storage for the cited week was more than the 41 billion cubic foot withdrawal from storage that the market was expecting ahead of the report, but was far less than the 252 billion cubic foot of gas that were pulled out of natural gas storage during the corresponding week of 2025, and also quite a bit less than the average 168 billion cubic foot withdrawal from natural gas storage that has been typical for the same mid February week 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 February 20th indicated that after a decrease in our exports, a decrease in our oil refining, and a big jump in our supply of oil that the EIA could not account for, we had surplus oil to add to our stored crude supplies for the 19th time in thirty-nine weeks, and for the 47th time in eighty-four weeks….Our imports of crude oil rose by an average of 136,000 barrels per day to 6,659,000 barrels per day, after falling by an average of 281,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 277,000 barrels per day to average 4,313,000 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 2,346,000 barrels of oil per day during the week ending February 20th, an average of 413,000 more 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 5,000 barrels per day higher at 554,000 barrels per day, while during the same week, production of crude from US wells was 33,000 barrels per day lower than the prior week at 13,702,000 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 16,602,000 barrels per day during the February 20th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 15,661,000 barrels of crude per day during the week ending February 20th, an average of 416,000 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 average of 2,284,000 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 February 20th averaged a rounded 1,342,000 fewer barrels per day than what was added to storage plus what 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 [ -1,396,000 ] 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 magnitude in the week’s oil supply & demand figures that we have just transcribed…moreover, since 1,396,000 barrels per day of demand for oil could not be accounted for in the prior week’s EIA data, that means there was 2,739,000 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 off by that much, and therefore nonsense.... However, since most oil traders react to 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 old 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 2,284,000 barrel per day average increase in our overall crude oil inventories all came as an average of 2,284,000 barrels per day were being added to our commercially available stocks of crude oil, as the amount of oil in our Strategic Petroleum Reserve was unchanged… Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports rose to 6,547,000 barrels per day last week, which was 4.9% more than the 6,241,000 barrel per day average that we were importing over the same four-week period last year. This week’s crude oil production was reported to be a rounded 33,000 barrels per day lower at 13,735,000 barrels per day as the EIA’s estimate of the output from wells in the lower 48 states was 2,000 barrels per day lower at 13,280,000 barrels per day, while Alaska’s oil production was 31,000 barrels per day lower at 422,000 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 4.6% higher than that of our pre-pandemic production peak, and was also 41.3% 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 88.6% of their capacity while processing those 15,661,000 barrels of crude per day during the week ending February 20th, down from 91.0% the prior week, with the decreased utilization rate likely due to seasonal maintenance and temporary shutdowns​, as refineries switch to produc​e​ summer blends of fuel….the 15,661,000 barrels of oil per day that were refined that week was 0.5% less than the 15,733,000 barrels of crude that were being processed daily during the week ending February 21st of 2025, and 2.2% less than the 16,008,000 barrels that were being refined during the prepandemic week ending February 21st, 2020, when our refinery utilization rate was at 87.9%, which was below the pre-pandemic normal utilization rate for this time of year…

With the decrease in the amount of oil that was refined this week, gasoline output from our refineries was also lower, decreasing by 223,000 barrels per day to 9,215,000 barrels per day during the week ending February 20th, after our refineries’ gasoline output had increased by 290,000 barrels per day during the prior week... This week’s gasoline production was ​still 0.5% more than the 9,170,000 barrels of gasoline that were being produced daily over the week ending February 21st of last year, but 5.9% less than the gasoline production of 9,797,000 barrels per day seen during the prepandemic week ending February 21st, 2020….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 136,000 barrels per day to 4,751,000 barrels per day, after our distillates output had increased by 28,000 barrels per day during the prior week. After that production decrease, our distillates output was 8.0% less than the 5,162,000 barrels of distillates that were being produced daily during the week ending February 21st of 2025, and 2.0% less than the 4,816,000 barrels of distillates that were being produced daily during the pre-pandemic week ending February 21st, 2020....

After this week’s decrease in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the second time in fifteen weeks, decreasing by 1,011,000 barrels to 254,834,000 barrels during the week ending February 20th, after our gasoline inventories had decreased by 3,213,000 barrels during the prior week. Our gasoline supplies decreased by less this week because the amount of gasoline supplied to US users fell by 16,000 barrels per day to 8,733,000 barrels per day, and because our imports of gasoline rose by 210,000 barrels per day to 563,000 barrels per day, and because our exports of gasoline fell by 85,000 barrels per day to 769,000 barrels per day … In spite of thirty-three gasoline inventory withdrawals over the past fifty-five weeks, the recent string of inventory additions meant our gasoline supplies were 2.6% higher than last February 21st’s gasoline inventories of 248,271,000 barrels, and about 3% above the five year average of our gasoline supplies for this time of year…

Even after this week’s decrease in distillates production, our supplies of distillate rose for the eleventh time in fifteen weeks, increasing by 252,000 barrels to 120,351,000 barrels during the week ending February 20th, after our distillates supplies had decreased by 4,566,000 barrels to during the prior week… Our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of domestic demand, fell by 858,000 barrels to 3,895,000 barrels per day, and because our imports of distillates rose by 212,000 barrels per day to a three year high of 411,000 barrels per day, while our exports of distillates rose by 246,000 barrels per day to 1,231,000 barrels per day... Even after 20 additions to distillates inventories over the past 33 weeks, our distillates supplies at the end of the week were 0.1% lower than the 120,351,000 barrels of distillates that we had in storage on February 21st of 2025, and about 5% below the five year average of our distillates inventories for this time of the year…

Finally, after the decrease in our oil exports and the decrease in our refining, our commercial supplies of crude oil in storage rose for the 14th time in twenty-six weeks, and for the 30th time over the past year, and by the most since February 2023, increasing by 15,989,000 barrels over the week, from 419,815,000 barrels on February 13th to 435,804,000 barrels on February 20th, after our commercial crude supplies had decreased by 9,014,000 barrels over the prior week….Even after this week’s increase, our commercial crude oil inventories were still about 3% below the recent five-year average of commercial oil supplies for this time of year, while they were 33.2% above the average of our available crude oil stocks as of the third weekend of February over the 5 years at the beginning of the past decade, with the big 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 supplies have generally leveled off since, and as of this February 20th were 1.3% more than the 430,161,000 barrels of oil left in commercial storage on February 21st of 2025, but were 2.5% less than the 447,163,000 barrels of oil that we had in storage on February 23rd of 2024, and 9.0% less than the 479,041,000 barrels of oil we had left in commercial storage on February 17th of 2023…

This Week's Rig Count

The US rig count was down by one over the week ending February 27th, as the number of rigs targeting oil was down by two, the count of rigs targeting natural gas was up by one, and 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 pdf from Baker Hughes...in the table below, the first column shows the active rig count as of February 27th, the second column shows the change in the number of working rigs between last week’s count (February 20th) and this week’s (February 27th) count, the third column shows last week’s February 20th 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 the 28th of February, 2025…

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Ohio Oil Production (from Utica) Hit Record-High in 2025 -Marcellus Drilling News - Ohio’s Utica/Point Pleasant shale production reached a record 48 million barrels of oil in 2025, a 39% increase from the previous year. While natural gas output remained stable at 2 trillion cubic feet, oil volumes have tripled since 2021. This surge was fueled by high-performing wells in the Northern Tier, specifically Columbiana and Mahoning counties, largely driven by EOG Resources and Encino Energy (which EOG bought in mid-2025 for $5.6 billion). Although southern hubs like Harrison and Carroll counties remain major producers, the expansion into northern regions highlights a significant shift in Ohio’s energy landscape and drilling success. Go North, young molecule!

Oil Production Soars Across Ohio's Utica Shale - The Youngstown Business Journal – Oil production skyrocketed throughout eastern Ohio’s Utica/Point Pleasant shale formation during 2025, helped along by consistent yields in areas such as Columbiana County, according to the most recent data from the Ohio Department of Natural Resources. Total oil production from horizontal wells in the Utica/Point Pleasant hit a state record of more than 48 million barrels last year, compared with 34.5 million barrels in 2024 – an increase of 39%, ODNR data show. Moreover, oil volumes during 2025 stand nearly three times higher than in 2021, when the state yielded approximately just 16.4 million barrels. Natural gas production, meanwhile, remained relatively stable at just more than 2 trillion cubic feet in 2025, according to ODNR. Helping oil production in recent years are wells drilled in the northern tier of the Utica/Point Pleasant – Columbiana County, for example – which have elicited strong returns in a region that was once regarded strictly as a dry and wet gas play. Oil produced from wells in Columbiana County stood at 1.431 million barrels in 2025 – or 3% of total state production – a drop of 4.2% compared with results a year earlier. In 2024, the county’s approximately 200 horizontal wells yielded 1.494 million barrels – or 4.3% of the state’s total production – the first time the county surpassed 1 million barrels for a year. All of the oil-producing wells in the county are owned by Houston-based EOG Resources’ affiliate EOG Ohio LLC. Last year, EOG acquired Encino Acquisition Partners’ Utica/Point Pleasant assets for $5.6 billion. The most promising well in Columbiana County is EOG’s Kitzmiller KNX 10H well in Knox Township. That well yielded a total of 376,345 barrels of oil in 2025 and 61,221 barrels in the fourth quarter. During the second quarter, that well ranked as the third most productive oil well in the state, pumping out 162,621 barrels over 91 days. Equally strong is a sister well at the Kitzmiller pad that produced 51,377 barrels during the fourth quarter and 318,401 barrels through all of last year. According to ODNR, Columbiana County reports 197 horizontal wells as of the fourth quarter of 2025. Of these wells, EOG owns 92, Hilcorp Energy Co. operates 89, and Pin Oak Energy Co. and Geopetro LLC operate eight apiece. Meanwhile, natural gas production from Columbiana County wells dropped year-over-year, according to ODNR records. In 2025, the county’s wells produced nearly 84.7 billion cubic feet of natural gas, compared with 92.3 billion cubic feet in 2024. Still, wells such as the Kitzmiller 10H recorded impressive results with natural gas production in 2025. During the third quarter, for example, the well yielded 1.075 billion cubic feet of gas and produced another 591.5 million cubic feet during the fourth quarter. Collectively, Columbiana County’s wells produced 18.979 billion cubic feet during the fourth quarter, according to ODNR. Among the most surprising finds last year in the Utica/Point Pleasant came in Mahoning County, where oil and natural gas production has historically been weak. EOG’s Wehr Valley Spring Farm well at the corner of Leffingwell Road and state Route 45 in Ellsworth Township produced 69,660 barrels of oil since it was first commissioned in the second half of 2025. The well yielded 40,489 barrels in the third quarter over 84 days and produced another 26,246 barrels during the fourth quarter, ODNR data show. Wells in Trumbull County have thus far yielded negligible oil and gas since production began more than a decade ago. Strong Wells Further SouthMuch of the attention in eastern Ohio’s Utica was initially focused on geology in the southern tier of the play, as exploration companies tapped vast reservoirs of both natural gas and oil in regions such as Carroll, Guernsey and Harrison counties. EOG’s Folsam CR well in Carroll County, for example, produced 195,194 barrels of oil during the second quarter, along with 953.5 million cubic feet of natural gas. In all, wells across Carroll County produced 12.342 million barrels of oil in 2025. Harrison County produced even more. Last year, wells drilled in that county pumped out more than 13 million barrels of oil. Wells in Belmont County, on the other hand, produced little oil but yielded nearly 500 billion cubic feet of natural gas in 2025, approximately one-quarter of the state’s entire production.

A gargantuan natural gas plant is planned for Ohio. These stocks could benefit. - A deal announced this week between the U.S. and Japan could help fund the largest power plant ever built in America, and benefit companies that drill and transport natural gas in the region. Japanese companies could also be winners. President Donald Trump announced on Tuesday plans for a 9.2 gigawatt natural gas plant in Ohio, which is expected to receive funding from the Japanese government. The plant would be more than twice as large as the biggest existing natural gas plant in America and could produce enough electricity to serve more than five million people. The total cost could come to $33 billion, according to the Commerce Department and the Japanese government. The Commerce Department didn’t respond to a request for details on the funding or the timeline for construction. Most conventional natural gas plants have less than 1 gigawatt of capacity and take at least five years to build. There is a good chance the power plant will be used for other purposes beyond residential electricity, given there are few major population centers nearby. The plant is being developed by SB Energy, which is backed by Japanese technology company Softbank. A fact sheet from the Japanese government says the plant will be used “to supply electricity to AI data centers, etc.” Softbank has several data center projects under way in the U.S., including one in Lordstown, Ohio, that is expected to be completed this year and is part of its Stargate project with OpenAI. The natural gas plant will be located in the southern Ohio town of Portsmouth. The area is rich in natural gas from deposits known as the Marcellus and Utica shale. Some of the producers and pipeline companies that operate there could be in good shape to profit off the project. Two of the largest producers in the area are EQT and Expand Energy, says Rob Thummel, senior portfolio manager at Tortoise Capital. Thummel also expects the plant to benefit companies that own nearby pipelines, including TC Energy and Enbridge. Japanese companies should benefit, too. Japan is likely to offer debt financing to the project, according to Jennifer Schuch-Page, an energy expert at The Asia Group. And Japanese companies—including names such as Toshiba, Hitachi, and Mitsubishi Electric—may end up working on the project. “The Japanese government is trying to show back to its public that it’s not just giving money to the US—that it’s investing in projects that are profitable and will be beneficial to Japan’s interest,” Schuch-Page said.

OH Local, State Leaders Blindsided by Trump’s Big Gas-Fired Plant - Marcellus Drilling News - This seems kind of….odd. We’ve been tracking and reporting on what will be the country’s (and possibly the world’s) largest gas-fired power plant, coming to Portsmouth (Scioto County), Ohio. Last week, President Trump unveiled the first projects under a $550 billion trade deal with Japan, including a $36 billion investment in U.S. energy and minerals (see Trump Announces Largest-Ever U.S. Gas-Fired Plant Coming to Ohio). In exchange for reduced tariffs on imports, Tokyo committed to fund initiatives in Texas, Ohio, and Georgia. The centerpiece is a record-breaking 9.4-gigawatt, $33 billion natural gas power plant in Portsmouth, operated by SoftBank’s SB Energy (Japanese company). However, nobody told local officials in Portsmouth, nor county officials, nor even the Ohio governor. Prior to the announcement, none of them knew a thing about this “biggest ever” project.

Is World’s Biggest Gas Plant Coming to Ohio? It’s Complicated | Energy Intelligence -To hear the White House describe it, a new gas-fired power plant in southern Ohio would be the largest of its kind in the world, financed by a Japanese conglomerate to the tune of $33 billion. It would produce enough electricity to power 7.4 million homes and help meet the exploding demand from data centers.

Pipeline lawsuit brought liens to western Erie County. They are over - GoErie.com ...Property owners in western Erie County were baffled by $18.9 million in pipeline-related mechanic's liens placed on some of their land in late 2020. Now, the liens have been discontinued in court.In December 2020, scores of property owners in Albion and other areas of western Erie County were unwittingly caught up in a federal lawsuit over the construction of an $86 million pipeline for natural gas. The plaintiff in the lawsuit, an energy-services company based in Houston, Texas, had the property owners served with mechanic's liens — documents that contractors attach to property to secure payment of a debt.. The amount the debt listed on each lien was an astronomical $18,946,185.... Natural gas transmission lines were common near Route 20 in North Kingsville, Ohio...A lawyer for the Wood Group, Neal Devlin, of Erie, did not respond to a request for comment. But the discontinuation of the liens appears to be the result of a settlement in the lawsuit that the Wood Group filed in U.S. District Court in Houston...

Mechanic’s Liens on OH/PA Landowners for Risberg Pipe Finally Lifted - Marcellus Drilling News - click map for larger version - Here’s a story we haven’t revisited in oh, about five years, because there was nothing new to report. In March 2019, MDN brought you the news that Wood Group had been awarded a $34 million contract to build 28 miles of the 60-mile Risberg Pipeline from Crawford County, PA, to Ashtabula County, OH (see Wood Wins $34M Contract to Build PA to OH Risberg Pipeline). The portion Wood built was a new “greenfield” pipeline. The rest of the pipeline (32 miles) already existed and was repurposed. There is an ongoing controversy between Wood and RH energytrans (the owner) concerning payment for services rendered that grew to involve the landowners whose property the pipeline crossed.

Enough is enough: Salt Fork up for fracking after last year's blast –Save Ohio Parks- After a massive explosion about five miles away from Salt Fork State Park last year, an unknown oil and gas company has nominated 513 acres of pristine park land for fracking. This nomination sits in front of the Ohio and Gas Land Management Commission (OGLMC). Tell the commission that there will no more drilling on public land.First responders to the well pad explosion stated they saw “100-foot flames” leap into the air. There was an areawide evacuation, forcing families to leave their homes.Now a company wants to come in and put the area at further risk by proposing fracking seven parcels totaling 513 acres of land throughout the park. Salt Fork hosts campers, birders, fishers, hunters as well as host of other outdoor recreational activities. It is the home of the beautiful Salt Fork Lake, the historic Kennedy Stone House, as well as an overnight lodge and over 50 cabins.This is just some of what makes Salt Fork great and why we’re calling on you to tell the commission not to allow drilling there.Go to the OGLMC nomination comment form, and choose Nomination 26-DNR-0003. Fill out the form and put your comment in the comment box. You are welcome to use our sample comment below, but please personalize it to make your comment your own. Explain what Ohio’s state parks and public lands mean to you. Tell a story about visiting Salt Fork or another park. Explain why you do not want to see our state parks fracked.

EQT Expands Clarington Connector, Targets Tightening Ohio Natural Gas Supply - EQT Corp. is upsizing its planned Clarington Connector pipeline by 33% to 400 MMcf/d, positioning the Appalachian producer eyes to move natural gas into Ohio as dry gas Utica Shale inventory in the state thins toward the end of the decade. Map of EQT’s Clarington Connector Project in Ohio showing the proposed pink pipeline route linking the EQT system in Belmont and Monroe counties to Marshall County, WV, expanding Appalachian natural gas takeaway capacity." At A Glance:

• Clarington capacity raised to 400 MMcf/d
• Ohio Utica seen declining after 2030
• Appalachia basis narrows vs. Henry Hub

Ohio’s ‘Bad Faith’ Bar for Mineral Trespass a Win for Drillers - Ohio’s Revised Code Section 5303.34 (part of House Bill 96, recently passed and signed into law) significantly shifts mineral trespass law, favoring oil and gas operators over landowners. Replacing common-law precedent, the new statute limits default damages to net revenue minus production costs, ensuring industry expense credits. Crucially, it creates a high bar for “bad faith,” requiring plaintiffs (landowners and rights owners) to prove an operator’s specific intent to steal minerals or actual knowledge of illegality. Since a “reasonable belief” in a lease or permit now negates bad faith, landowners face a difficult path to full revenue recovery

Gulfport Eyes 5% Growth in Production & New Drilling in 2026 -Marcellus Drilling News - Gulfport Energy is the third-largest driller in the Ohio Utica Shale (by the number of wells drilled). Gulfport released its fourth quarter and full-year 2025 update yesterday. The company reports delivering a strong performance during the period, with total net production reaching 1.10 Bcfe per day and net liquids production rising 12% over the fourth quarter of 2024 to 18.2 MBbl per day. Financial highlights included $132.4 million in net income and $234.8 million in adjusted EBITDA, supported by $185.4 million in net cash from operating activities and $120.2 million in adjusted free cash flow. Gulfport spent $25 million on drilling and completions (D&C) and $11.4 million on maintenance, land, and leasehold spending. The company spent an additional $55.7 million on discretionary appraisal and development. Furthermore, the company expanded its footprint through the acquisition of $47.2 million in opportunistic acreage.

Infinity Natural Resources Completes Transformational $1.2 Billion Acquisition of Ohio Utica Assets -Infinity Natural Resources, Inc. today announced the successful completion of its transformational $1.2 billion acquisition of upstream and midstream assets in the Ohio Utica Shale from Antero Resources Corporation and Antero Midstream Corporation (the "Transaction"). Announced on December 8, 2025, the Transaction represents INR's acquisition of an undivided 60% interest, increased from the originally announced 51% interest following the Company's previously announced $350 million strategic equity investment from Quantum Capital Group ("Quantum") and Carnelian Energy Capital Management ("Carnelian") that closed simultaneously with the Transaction. In addition to using proceeds from the strategic equity investment, the Transaction was funded through Infinity's existing credit facility and cash on hand, requiring no additional equity issuance.The addition of these assets to Infinity’s portfolio significantly enhances the Company’s position in the core Ohio Utica Shale, adding approximately 71,000 net horizontal acres in the core of the Utica Shale concentrated in Ohio’s Guernsey, Belmont and Harrison counties, and 110+ undeveloped long lateral drilling locations totaling 1.6 million lateral feet across volatile oil, rich gas and dry gas windows, on an 8/8ths basis. The midstream and marketing assets include 141 miles of high- and low-pressure gathering lines with 600 mmcf/d throughput capacity, providing immediate vertical integration benefits and substantial operational synergies."This transformational acquisition represents a hand-in-glove fit with our existing Ohio operations and further solidifies our compelling long-term growth platform," said Zack Arnold, President and Chief Executive Officer of Infinity Natural Resources. "We are acquiring a position we know very well that provides us with the opportunity to demonstrate our capabilities to deliver shareholder value through our best-in-class operations and focused development of the area. The combination of high-quality acreage, extensive drilling inventory, and integrated midstream infrastructure augments our capital efficiency and returns while positioning us to capitalize on the significant development opportunities in the Ohio Utica core.

Infinity ups Utica stake in $1.2 billion Antero Ohio deal with $350 million equity backing (WO) — Infinity Natural Resources has increased its ownership in the $1.2-billion Antero Ohio Utica Shale acquisition to 60%, funded in part by a $350-million strategic equity investment from Quantum Capital Group and Carnelian Energy Capital. The Morgantown-based independent agreed to raise its stake from 51% under an arrangement with Northern Oil and Gas, positioning Infinity to expand its footprint in eastern Ohio’s Utica Shale. The $350-million investment will be made through Series A convertible preferred stock and is expected to close alongside the Antero Ohio acquisition, which Infinity anticipates completing by the end of the first quarter of 2026. Infinity said the capital infusion will reduce pro forma leverage, increase liquidity and support continued development across its Appalachian Basin drilling inventory. A portion of the proceeds will also be used to repay borrowings under the company’s senior secured revolving credit facility. "Quantum and Carnelian bring deep energy sector expertise and a proven track record of partnering with management teams to drive operational excellence and strategic growth," Zack Arnold, president and CEO of Infinity, said. "Their investment further validates our strategic direction while allowing us to increase our participation in the Antero Ohio acquisition and maintain a conservative capital structure. The transaction furthers our financial flexibility to pursue additional accretive growth opportunities. We are excited to have Matt Kelly from Carnelian join the Board at closing." "Infinity's strong operational execution and successful organic drilling program demonstrate management’s ability to create significant stakeholder value in the Appalachian Basin," said Rob Anderson, Managing Director at Quantum. "We are excited to partner with Infinity as a strategic investor and to support its transformational Antero Ohio acquisition and continued growth trajectory." "The combination of Infinity's operational excellence and the strategic scale provided by the Antero Ohio acquisition positions the company as a leading consolidator in one of North America's premier unconventional basins," said Matt Kelly, Managing Director at Carnelian. "This investment aligns with our focus on partnering with best-in-class management teams executing accretive growth strategies." On an as-converted basis, the preferred equity would represent approximately 20.5% of Infinity’s voting power. The preferred shares carry an 8% annual dividend for the first five years, increasing to 12% thereafter, and are convertible at $21.39 per share — a 30% premium to the five-day volume-weighted average price prior to signing. BofA Securities is acting as sole placement agent on the transaction. Infinity focuses on development of the Utica Shale in eastern Ohio and stacked dry gas assets in the Marcellus and Utica formations in southwestern Pennsylvania.

Infinity, NOG adjust Ohio Utica acquisition split, close deal – MSN - -Infinity Natural Resources and Northern Oil and Gas (NOG) announced last week that they had agreed to adjust the ownership split of their pending acquisition of Utica shale assets in Ohio from Antero Resources and Antero Midstream. This week, this was followed by an announcement from the companies saying they had closed the acquisition. Infinity said on February 19 that it had agreed to increase its stake in the $1.2bn Utica acquisition to 60%, compared with 51% previously. This came after the company secured $350mn in equity investment from energy-focused private capital investors Quantum Capital Group and Carnelian Energy Capital Management. The investment involved Series A convertible preferred stock, which Infinity said would “significantly” reduce its leverage while boosting its liquidity. According to the Quantum bought $275mn of the preferred stock, while Carnelian purchased $75mn worth of it. The preferred shares carry an 8% per year dividend for the first five years, rising to 12% thereafter, and can later be converted to Class A common stock. Only a portion of the proceeds from this investment will be used to increase Infinity’s stake in the Utica acquisition. The remainder is set to be used for general corporate purposes, including the repayment of borrowings under Infinity’s senior secured revolving credit facility. NOG, for its part, said it would now acquire a 40% interest in the assets being bought from Antero, compared with 49% previously. In a separate February 19 announcement, NOG said its share of the purchase price would be reduced to $480mn from $588mn as a result of the ownership adjustment. The purchase price remained on the same pro rata economic terms as originally announced, NOG noted. “By adjusting the sizing of our interest, NOG also optimises and increases its financial flexibility to allow for further participation in inorganic and organic growth opportunities as they emerge in the coming year,” stated NOG’s CEO, Nick O’Grady. On February 23, the companies followed up with separate announcements saying they had closed the Utica acquisition. “This transformational acquisition represents a hand-in-glove fit with our existing Ohio operations and further solidifies our compelling long-term growth platform,” stated Infinity’s president and CEO, Zack Arnold. “We are acquiring a position we know very well that provides us with the opportunity to demonstrate our capabilities to deliver shareholder value through our best-in-class operations and focused development of the area. The combination of high-quality acreage, extensive drilling inventory, and integrated midstream infrastructure augments our capital efficiency and returns while positioning us to capitalise on the significant development opportunities in the Ohio Utica core.”
NOG finalises $464.5m acquisition of Utica Shale assets - Northern Oil and Gas (NOG) has announced the completion of its purchase of non-operated interests in the Utica Shale in Ohio, US, from Antero Resources and Antero Midstream. The transaction was finalised through a payment of $464.5m, which includes a $58.8m deposit made at signing. Announced in December 2025, the transaction involved joint acquisition with Infinity Natural Resources (INR) for a combined price of $1.2bn in cash. Under the terms of the deal, NOG acquired a 40% interest, while INR bought a 60% stake. NOG utilised cash on hand, operational free cash flow and its revolving credit facility to fund the acquisition. The acquired properties span approximately 35,000 net acres in eastern Ohio's Utica Shale. They comprise more than 100 gross identified undeveloped locations. For 2026, these assets are projected to produce approximately 65 million cubic feet (mcf) equivalent per day, primarily comprising gas, with expectations for a compound annual growth rate exceeding 30% through the end of the decade. This growth is anticipated under a continuous one-rig development approach. Additionally, these assets are expected to generate unhedged cash flow from operations amounting to around $100m in 2026 at current strip prices.

Northern Oil And Gas Expands Utica Footprint And Increases Lending Flexibility

• Northern Oil and Gas (NYSE:NOG) has closed an acquisition of non-operated properties in the core of the Ohio Utica Shale.
• The company has also secured an upsized reserves-based lending facility through an amended credit agreement.
• The transaction expands NOG's upstream and midstream asset base, and the larger lending facility adds financial flexibility.

The Ohio Utica Shale acquisition gives Northern Oil and Gas fresh exposure to a core US gas and liquids basin while staying true to its non-operated model. By taking a 40% stake alongside Antero Resources and Antero Midstream, NOG is effectively tying its fortunes to operators that focus on Appalachia, which can add basin diversification to its existing Williston, Permian, Uinta and other positions. On the funding side, increasing the elected commitment on the reserves-based lending facility to US$1.8b and the borrowing base to US$1.975b, with terms otherwise unchanged, widens NOG’s liquidity without introducing new structural complexity. For you, the key questions are how much incremental production, cash flow stability and midstream access these Utica assets can provide, and whether the larger facility will be used for further acquisitions, debt management or shareholder returns. Comparing this model with other upstream companies such as Devon Energy, EOG Resources or Marathon Oil can help you gauge where a non-operated, acquisition-driven approach like NOG’s sits on your own risk and reward spectrum. How This Fits Into The Northern Oil and Gas Narrative

• The focus on acquiring long-dated, stable production assets lines up with the narrative that NOG is using M&A and basin diversification to support more resilient cash flows over time.
• The reliance on acquisitions for growth is also one of the key risks in the narrative, and a larger credit facility can increase that exposure if future deals do not meet return hurdles.
• The addition of Utica midstream interests and the extra lending headroom may not be fully reflected in the existing narrative’s view of operational risk sharing and optionality for future deals.

Antero Resources completes $800 million Utica Shale asset sale - Antero Resources Corporation announced Monday the completion of the previously disclosed sale of substantially all of its Utica Shale oil and gas assets. The assets were sold to an affiliate of Natural Resources, Inc. and Northern Oil and Gas, Inc. (NOG) for total cash consideration of $800 million, subject to customary post-closing adjustments and other items. The transaction was carried out by Antero Resources and certain wholly-owned subsidiaries, as outlined in the purchase and sale agreement dated December 5, 2025.The $10.5 billion company has demonstrated strong financial health, with a perfect Piotroski Score of 9 indicating robust financial strength. Revenue grew nearly 20% over the last twelve months to $5.14 billion.The company also confirmed that it had previously issued a conditional notice of full redemption for its 7.625% senior notes due 2029. With the closing of the Utica Shale asset sale, the conditions for redeeming the 2029 notes have been met. The notes are scheduled to be redeemed on Tuesday. The company currently carries $3.53 billion in total debt. This information is based on a press release statement included in a filing with the U.S. Securities and Exchange Commission.

Antero Resources Sells Utica Assets to Reduce Debt - On February 23, 2026, Antero Resources completed the previously announced sale of substantially all of its Utica Shale oil and gas assets in Ohio to an affiliate of Infinity Natural Resources and Northern Oil and Gas for $800 million in cash, subject to customary closing and effective-date adjustments. The transaction marks a major portfolio shift for Antero and enables the company to proceed with the full redemption of its 7.625% senior notes due 2029, which will be redeemed on February 24, 2026, signaling balance sheet deleveraging and a potential improvement in its financial flexibility for stakeholders.With the closing of the Utica Shale asset sale, Antero has effectively exited a large portion of its Ohio asset base, reshaping its operational footprint within the U.S. shale sector. The imminent redemption of the 2029 notes following the sale underscores the company’s focus on using asset monetization proceeds to reduce debt, which could strengthen its capital structure and impact its standing among creditors and investors.Antero Resources Corporation is an independent oil and natural gas exploration and production company focused on shale development in the United States. The company’s portfolio has included significant positions in the Utica Shale and related midstream assets, supplying hydrocarbons to domestic markets through its operated subsidiaries and partnerships.

EOG Resources beats profit estimates on strong output, higher gas prices (Reuters) - EOG Resources beat estimates for fourth-quarter profit on Tuesday, as higher output and elevated natgas prices offset the impact of a drop in crude prices. U.S. natural gas futures rose over 11% sequentially in the fourth quarter, driven by stronger demand and increased pipeline volumes, breaking a falling streak that started in the second quarter due to record‑high U.S. production.EOG said it produced about 1.40 million barrels of oil equivalent per day in the fourth quarter, compared with 1.09 million boepd a year earlier.The company's $5.6 billion purchase of Encino Acquisition Partners in May helped lift production and broadened EOG's foothold in the Utica Shale, one of the country's most productive natural gas regions.The average realized prices for natural gas stood at $3 per thousand cubic feet (Mcf), compared with $2.57 per Mcf a year earlier.The average realized price of oil, however, fell to $59.54 per barrel from $71.66 per barrel a year earlier.Global crude oil prices have been pressured by growing worries of a glut and the increasing prospect of Venezuela adding more barrels to global supply.The company said it expects current-year production to be in the range of 1.37 million boepd to 1.42 million boepd and between 1.35 million boepd and 1.40 million boepd for the first quarter.

EQT Upsizes Clarington Connector, Announces Strong Fern Flows on MVP - Appalachia’s largest natural gas producer, EQT, announced during its Q4 2025 earnings call last week that it now has plans to make the Clarington Connector pipeline a 400 MMcf/d project, up from 300 MMcf/d earlier. The pipeline is planned to carry gas from Pennsylvania into Ohio, where it will take advantage of the pricing spread between M2 and Rex Zone 3. Exposure to planned data center demand in Ohio is also a catalyst for the pipe, which is expected to be in service by the end of this year. EQT’s CFO Jeremy Knop also predicted that Ohio Utica gas production will “go into structural decline” in the 2030s, increasing the importance of pipes in Ohio that can draw gas from “a much deeper inventory base on the Pennsylvania side.” EQT also announced important information regarding Mountain Valley Pipeline (MVP). The company purchased a portion of ConEdison’s interest in the pipeline, increasing its ownership stake from 49% to 53% and making it the majority owner. In the earnings call, EQT noted that during Winter Storm Fern, MVP flowed 6% above its nameplate capacity of 2 Bcf/d, helping gas reach the Southeast during a time of soaring spot prices. As seen in the purple line in the chart below, deliveries to Transco on MVP have averaged 100% of utilization capacity over the first month and a half of this year.

Antis File Lawsuit to Challenge Va. Permit for MVP Southgate Pipeline – Marcellus Drilling News - Several Big Green groups, including the Sierra Club, Wild Virginia, Appalachian Voices, and the Center for Biological Diversity, have filed a legal challenge against a permit issued by Virginia for the Mountain Valley Pipeline (MVP) Southgate extension. The Virginia Department of Environmental Quality (DEQ) approved a water permit for the project in January 2026. Big Green radicals argue that the pipeline “threatens” 138 streams, wetlands, and regional drinking water supplies. It’s the typical lawfare tactic used by the left to stall work on projects, hoping to delay them long enough that the builder (EQT in this case) gives up. Or if the builder won’t give up, they have to pay double or triple the price to construct it. That’s the game the radicals are playing.

Radical Groups File Lawsuit to Block Dominion Va. Peaker Plants - Marcellus Drilling News - The far-left Southern Environmental Law Center, representing three radical nonprofits, has appealed the Virginia State Corporation Commission’s (SCC) approval of Dominion Energy’s $1.47 billion natural gas plant in Chesterfield County. The challenge is the first under both the Virginia Environmental Justice Act and the Virginia Clean Economy Act. Antis argue the 1,000-megawatt facility would disproportionately “harm” marginalized communities through increased pollution and significant health risks, including premature deaths. Critics maintain that Dominion failed to prioritize renewable alternatives or demonstrate a genuine threat to grid reliability, potentially placing unnecessary financial and health burdens on the public.

Largest US Gas Producer Vexed by Its Own Marketing Shortfalls | Energy Intelligence --Expand Energy’s interim CEO wasted little time challenging his management team to do better, insisting the largest US gas producer ramp up its marketing efforts and midstream partnerships to extract more value from its gas.Expand Energy's interim CEO warned the company "has not done enough" to maximize gas production revenues through its downstream and midstream strategies.

U.S. Propane Stocks Show Modest Draw as Regional Imbalances Deepen - The EIA reported a 1.7 MMbbl draw in total U.S. propane/propylene inventories for the week ended February 20. While the draw exceeded industry expectations of a 1.4 MMbbl decline, it was smaller than the five-year average draw of 2.2 MMbbl for the same week. Total inventories now stand at 72.5 MMbbl, which is 20.9 MMbbl (41%) above year-ago levels, 11.9 MMbbl (20%) above the five-year maximum, and 23.7 MMbbl (49%) above the five-year average. A significant portion of the surplus continues to be held in PADD 3. PADD 1 (East Coast) propane inventories declined by 402 Mbbl to 3.3 MMbbl. Stocks are 919 Mbbl (22%) below year-ago levels, 335 Mbbl (9%) below the five-year minimum, and 930 Mbbl (22%) under the five-year average, with inventories now at their lowest level for this week since 2018, underscoring the region’s tight supply position. In contrast, PADD 3 (Gulf Coast) inventories increased by 35 Mbbl to 51.8 MMbbl and remain historically elevated, standing 18.9 MMbbl (57%) above year-ago levels, 14.9 MMbbl (41%) above the five-year maximum, and 22.6 MMbbl (78%) above the five-year average.

Can the Haynesville Meet a Growing Global Thirst for LNG? | Energy Intelligence -International gas buyers are starting to look beyond the Haynesville Shale for long-term gas supply as the Texas-Louisiana basin's long-term prospects wane, executives at US gas producer EQT said this week. But some analysts say the Haynesville's growth trajectory will depend on who is drilling there — and how aggressively.

$5 Billion Pipeline Deal Could Be Coming to the Gulf Coast --Texas-based EnCap Flatrock Midstream is considering a sale of gas pipeline operator Momentum Midstream in a deal that could fetch $5 billion. According to a Bloomberg report citing unnamed sources, the venture capital firm is currently talking with financial advisers to find a buyer. The sources noted that talks are in their early stages and EnCap Flatrock Midstream may eventually decide against a sale.If it does sell Momentum Midstream, however, it would make one of the largest deals in the oil and gas pipeline space, after the Brookfield Infrastructure Partners acquisition of Colonial Enterprises for $9 billion.Momentum Midstream operates a network of 4,000 miles of pipelines with a system capacity of 6 billion cu ft of natural gas daily. The company reports some 4 billion cu ft in minimum volume commitments and 20 billion cu ft in daily connectivity via 91 interconnections. Momentum services 10 LNG-producing facilities and 26 power plants.Natural gas pipelines have become coveted assets in the energy space amid soaring demand for gas from the tech industry. The demand trends have prompted a massive pipeline investment rush, with a total of 12 projects for new or expanded gas pipelines set to be completed this year across Texas, Louisiana, and Oklahoma.These projects are set to boost the U.S. Gulf Coast region’s capacity to transport natural gas by 13%, per data compiled by Bloomberg on the basis of EIA estimates. That would be the biggest expansion of pipeline capacity in one year since the dawn of the shale gas boom in 2008.Companies have committed $50 billion worth of investments in new gas pipelines that would add 8,800 miles of new pipeline in the United States, energy consultancy Wood Mackenzie said last year, noting that this time the investment wave was led by producers of liquefied natural gas, power utilities, and Big Tech, which is on a data center construction spree amid the heating AI race.

METLEN/Shell LNG Deal Boosts Demand for U.S. NatGas Exports - Marcellus Drilling News - METLEN (Greek energy company) and Shell have signed a memorandum of understanding to cooperate on liquefied natural gas (LNG) supply and trading between 2027 and 2031. This partnership allows the Greek company to secure up to one billion cubic meters of LNG annually, leveraging domestic terminals and the Vertical Gas Corridor to supply Central Europe and Ukraine. The agreement highlights Greece’s growing importance as a strategic energy hub designed to replace Russian gas with U.S.-produced alternatives. This shift is further reinforced by increased Mediterranean exploration by major U.S. firms such as Chevron and ExxonMobil, solidifying the region’s role in European energy security. Believe it or not, there are implications for the Marcellus/Utica region.

Aramco Starts Natural Gas Production at Middle East’s Largest Shale Play - Here are three things to know about the global LNG market this week. Venture Global Inc. has signed its first long-term deal with a South Korean offtaker, agreeing to supply LNG to Hanwha Aerospace Co. Ltd. Under the sales and purchase agreement, Venture Global said it would sell Hanwha 1.5 million tons/year (Mt/y) of the super-chilled fuel for 20 years beginning in 2030.

Late-Stage Commissioning Begins at Corpus Christi Expansion, Golden Pass After Key FERC Approvals -Federal regulators granted major approvals to Gulf Coast LNG facilities this week, starting the timer for another large incremental boost in feed gas nominations. At A Glance:

• Pipeline flows in Texas accelerating
• Commissioning boosts nominations
• U.S. LNG feed gas demand nearing 20 Bcf/d

Cheniere Brings Another Train Online at Corpus Christi LNG -Cheniere Energy Inc. produced first LNG this week from the fifth train at its Corpus Christi LNG (CCL) Stage 3 expansion in South Texas and remains on track to bring the project’s remaining two trains online by this fall, management said Thursday during a year-end earnings call. At A Glance:

• 9 Mt/y of liquefaction under construction
• 40 Mt/y of additional capacity planned
• Sabine Pass expansion FID set for 2027

Cheniere Announces Progress on Corpus Stage 3 --The nation’s largest exporter of LNG gave an update on construction at Corpus Christi LNG during its earnings call on Thursday. The company estimates that more than 87% of construction work related to the original Corpus Christi Stage 3 project has now been completed, along with nearly all engineering and procurement work. Cheniere’s CEO Jack Fusco stated that Trains 3 and 4 of the project were substantially completed in Q4 2025, and substantial completion of Trains 5, 6 and 7 are expected to occur later this year. For Train 5 specifically, first LNG was achieved earlier this month. Cheniere also reported progress on the Midscale Trains 8 and 9 project, which only reached Final Investment Decision (FID) in June of last year. Substantial completion of that project is now expected in 2028. As seen in the table above, Corpus Christi feedgas, which includes the operational portion of the Stage 3 expansion, has been strong lately. We estimate that feedgas exceeded 3 Bcf/d for every day of the past week, contributing to overall U.S. feedgas that exceeded 19 Bcf/d on every day except one.

Cheniere Bets Big on Asian LNG Demand Through 2050 --Cheniere Energy led North America’s expansion into LNG in 2016. Ten years later, the company is placing its growth bets on a rising Asian market. Cheniere Energy's long-term Asian contracts and brownfield expansion strategy reveal where executives see global LNG demand heading through 2050.

U.S. LNG Feedgas Demand Robust as Golden Pass Takes Significant Feedgas -- U.S. LNG feedgas demand remained strong last week, with all operational terminals at or above full contracted utilization and Golden Pass has begun taking meaningful feedgas volumes for the first time. Feedgas demand averaged nearly 19 Bcf/d last week, up 0.05 Bcf/d week-on-week. The average has been nearly 18.5 Bcf/d since the beginning of November, compared to 14 Bcf/d at the same time last year. The largest growth driver has been Plaquemines LNG, which is technically still commissioning but has been producing LNG at full utilization since then. More growth is expected this year as Corpus Christi Stage III continues to ramp up online and Golden Pass is expected to begin producing LNG soon. On February 17, intake at Golden Pass jumped from around 30 MMcf/d to 171 MMcf/d and hit nearly 300 MMcf/d over the weekend. ExxonMobil said it expects to begin LNG production at Golden Pass by early March.

Federal Approval of Rio Grande Tanks Signals Progress Toward 2027 First LNG - A look at the global natural gas and LNG markets by the numbers

• 720,000 cubic meters: NextDecade Corp. has received authorization from federal regulators to build Storage Tanks 3 and 4 at its Rio Grande LNG facility in South Texas. At full capacity, the first phase of Rio Grande LNG is designed to have four tanks with a combined storage of 720,000 cubic meters, an equivalent of 15–16 Bcf of natural gas. Commencement of construction of the final two tanks sheds clues as to when trains could be commissioned at the facility. Tanks can typically take 24-36 months to be completed and are essential before a terminal can begin late-stage commissioning and LNG production. First LNG is anticipated sometime in 2027, according to NextDecade.
• 19.4 Bcf/d: U.S. LNG feed gas nominations have moderated after flirting with an all-time high last week, but are still expected to sustain more than 5 Bcf/d over last year’s level during the same period. Feed gas flows were estimated at 19.5 Bcf/d over the last seven days and are expected to float around 19.4 Bcf/d in the coming seven, according to Wood Mackenzie data. Nominations reached 19.8 Bcf on Feb. 22, tying with the last record set in January.
• 2.7 Mt: U.S. LNG exports are expected to see a week/week gain the week of Feb. 23 as LNG demand in Latin America and Egypt heats up. Volumes from the United States are set to increase 0.15 million tons (Mt), or about 2 cargoes, to 2.7 Mt, according to Kpler predictive data. The increase was driven by more than 0.2 Mt destined for the Caribbean and South America and several cargoes shifting toward Egypt. Meanwhile, LNG cargoes to Europe are set to fall by 0.63 Mt week/week as the continent eyes milder weather forecasts in the coming weeks.
• 2008: Winter heating demand and pressure to fill storage across the U.S. Northeast is driving imports to a Canadian import terminal to an almost five-year high. Saint John LNG is on track to receive its eighth LNG cargo by the end of the month, marking 0.48 Mt in imports, according to Kpler data. That volume is almost as much as the facility received in 2025, the previous highest import year since 2021. The pull for LNG cargoes to North America’s northeastern market has also attracted the first cargo from Australia since 2008. A vessel from Curtis LNG in Queensland is expected to arrive at the facility Thursday, according to Kpler data.

EOG Leverages South Texas Play to Secure LNG Contracts with Global Price Exposure - Executives at Houston’s EOG Resources Inc. called the firm’s Dorado natural gas play in South Texas a “foundational asset” for its high returns, with significant “running room” and the ability to support dedicated crews while generating free cash flow. Line chart titled “NGI’s Agua Dulce Daily Natural Gas Prices” shows Agua Dulce cash prices from Feb 2025 to Feb 2026, mostly between $2-$4/MMBtu before spiking above $14/MMBtu in late January 2026, then retreating near $2/MMBtu. At A Glance:

• Dorado $1.40/Mcf breakeven
• Ties volumes to JKM, Brent
• EOG grows output year/year in 4Q

GasCon 2026: Gas Market is 'All Gas, No Brakes,' But Midstream, Storage Are Critical for Growth - The fundamentals of the natural gas market have never been better, but the continued buildout of midstream infrastructure remains critical to meeting supply-and-demand needs in the coming years, a trio of industry experts said during a panel discussion Wednesday at RBN’s GasCon 2026 conference in Houston. Sital Moody, President of Natural Gas Pipelines at Kinder Morgan, said pipeline developments will need to focus on three things in the coming years – unlocking supply, building new infrastructure and debottlenecking problem areas, and increasing ways to reach the end-user market. If those challenges can be met, he said, big things are ahead. “When I take a step back and reflect on the natural gas industry, the one thing that comes to mind for me is all gas, no brakes,” he said. Danielle Bertoldi, a technical adviser at the Federal Energy Regulatory Commission (FERC) emphasized that better gas-electric coordination has become a much-bigger priority, a lesson learned that hard way during 2021’s Winter Storm Uri. “What used to be very siloed sectors, the electric sector and the gas sector, designed very differently … we’re at the point now where you can’t really differentiate between the two industries, you have to consider them together if you want to maintain reliability for the U.S. grid,” she said. Gas storage (see map below) is becoming an increasingly important part of the supply-demand mix, especially as U.S. LNG exports are poised to increase sharply in the next few years. Dave Marchese, CEO of Caliche Storage, said a single LNG train that trips offline could divert up to 1 Bcf/d of natural gas to storage. Natural gas storage facilities in the Lower 48. (map) The U.S. saw a significant overbuild of natural gas storage in the early 2000s, but all of that capacity is now gone, Marchese said. “(Storage) prices were stinky for a really long time, but as my mom says, ‘Keep something in the closet for about 10 years and it’ll come back in style,” he said. “All that storage got bought cheap … gas production and consumption has more than doubled and storage has done nothing, so we’re in style again.” He said there are two main holdups to getting more storage built – storage is more expensive than it was a few years ago and storage developers are looking for the long-term contracts (10 or 15 years) necessary to secure financing. In the past, storage contracts were much shorter. The time to line up storage is now, he said. “There is a pain point that’s coming. We’re not there yet,” he said. “When you look at these 2-, 3-Bcf/d chunks of LNG terminals that are coming online, I see in 2027 and 2028 a real squeeze.”

GasCon 2026: Producers Can Deliver Gas, But Infrastructure is Critical | RBN Energy - Two giant natural gas producers and an analytics expert are hopeful natural gas will remain available to meet growing demand, but logistical and infrastructure challenges will shape how smoothly they can get it to market. In a panel narrated by RBN President and CEO David Braziel at the company’s GasCon 2026 conference on Wednesday in Houston, the gas producers said they plan to use AI and ramp up technology to effectively grab natural gas. “The question this panel is going to get at is: Will there be enough natural gas? And that depends on the price signals, the infrastructure buildout, and how quickly operators can respond,” said Anders Hyde, Director of Fundamental and Quantitative Analytics at Expand Energy, one of the nation’s largest natural gas producers. Also on the panel was James Pearson, Senior Consultant of Market Analysis of ConocoPhillips, and Brandon Myers, Head of Research at Novi Labs. Pearson said ConocoPhillips envisions drilling in the Permian for more than a decade. “We don’t see oil being depleted to 2035, and gas maybe five years after that,” he said. Hyde and Pearson said they’re using better strategies and technology to slash costs when producing wells, but there's no silver bullet. “I can’t point to one specific thing. … It’s a series of continuous improvements," Hyde said. Demand isn’t the issue, the panelists agreed, because AI and data centers are pushing a huge demand for gas, but they argued that interstate pipelines, storage and the pace of these buildouts are critical for the industry. Myers also cautioned against putting too much stake in the “dark horse gas plays,” because many of them can be quite expensive and challenging to capture gas efficiently and effectively.

GasCon 2026: Brouillette Says Energy Demand Will Rise, But Permits and Infrastructure Must Be In Place | RBN Energy Today’s energy challenge is not a shortage of natural gas resources or lack of demand, but whether infrastructure, permitting systems and policies can keep up with rapidly expanding global energy needs, Dan Brouillette, the 15th Secretary of the U.S. Department of Energy, said during the keynote presentation at RBN's GasCon 2026 conference Wednesday in Houston. Speaking to a crowd of about 300 oil and gas leaders, he noted that in Washington, announcements are often treated as accomplishments, but “gas doesn’t move on press releases, it moves on pipelines.” Brouillette stressed that pulling or delaying permits creates uncertainty that discourages investment, and he highlighted a structural regulatory mismatch because pipelines and gas suppliers operate under different rules than electric utilities, which are legally obligated to keep the lights and heat on. But the big issue is permits and infrastructure, he said. If the U.S. executes well, the current LNG buildout could cement American energy leadership for generations, but if the country stumbles, those projects could move elsewhere. The Energy Information Administration estimates that LNG exports will reach about 18 Bcf/d by 2027. “So, production in the United States is resilient and around the world is resilient as well," he said. Brouillette wrapped up his keynote with a word of thanks to the industry. “On behalf of all of America … thank you for what you're doing. It makes me emotional. I got to tell you because I really appreciate what you guys do.”

GasCon 2026: Policy Choices, Regulatory Certainty Play a Major Role in LNG Development | RBN Energy -Policy choices can have a major impact on project development and regulatory certainty is a key factor in the recent growth in the LNG industry, Tala Goudarzi, a Torridon Group partner and former Department of Energy (DOE) official, said during a fireside chat with RBN President and CEO David Braziel at RBN’s GasCon 2026 conference in Houston. Goudarzi, who served as Acting Assistant Secretary and Principal Deputy Assistant Secretary of the Office of Fossil Energy at the DOE, led initiatives that expanded U.S. LNG exports, including lifting the Biden administration’s pause on LNG exports, which she said slowed the industry’s development and was based on “politicized data.” “The overpoliticization of the industry is just something that we can’t do,” she said. “Energy is not political.” Goudarzi emphasized that regulatory certainty was a key factor in the industry’s future success. “Regulators and our policymakers shouldn’t stand in the way of American progress,” she said. With LNG export capacity expected to increase sharply over the next few years, topping 30 Bcf/d by 2030 (see chart below), there has been some concern that the global LNG market will become oversaturated, but Goudarzi said that was not likely to happen. “There’s been no evidence to suggest that there’s an oversupply in the market,” she said. “All data points to the fact that demand is certainly going up and there is no data to suggest that natural gas will have no place to go globally.” LNG Export Capacity by Terminal

U.S. LNG Exports Continue to Surge 10 Years After Lower 48’s First Cargo Set Sail -- Wednesday marked 10 years since the first LNG was exported from the Lower 48, a stretch of time that has realigned global energy flows and transformed the United States into the world’s leading producer of the super-chilled fuel. Graph: North American operational and sanctioned LNG facility peak capacity, highlighting the steady expansion of export infrastructure over time. At A Glance:
U.S. now world’s largest LNG exporter
Cheniere has shipped 5,000 cargoes
Another five plants under construction

U.S. Natural Gas Exports Keep Rising on Record LNG, Mexico Demand -Total U.S. natural gas exports are charging toward historic highs as feed gas to LNG terminals nears a record 20 Bcf/d, bolstered by resilient demand from pipeline flows into Mexico.Chart titled “NGI’s Agua Dulce & Waha Bidweek Prices vs Average US Natural Gas Pipeline Exports to Mexico” shows bidweek prices from Feb 2023 to Feb 2026 alongside exports rising toward 8 Bcf/d, Waha turning negative at times. At A Glance:
LNG feed gas approaches 20 Bcf/d
Mexico cross-border flows target record year
Storage deficit narrows to 0.3%

Lake Charles LNG Contracts Terminated After Energy Transfer Walked Away -- Several offtake agreements for the long-proposed Lake Charles LNG export facility have been canceled after developer Energy Transfer LP (ET) suspended development of the project late last year, according to a disclosure filed with the U.S. Securities and Exchange Commission. At A Glance:

• Sanctioning failure triggers cancellations
• Third-party takeover still possible
• Site may pivot beyond LNG

ET Ponders Resurrecting Lake Charles LNG Project for NGL Exports - Marcellus Drilling News -In December, we brought you the sad and unexpected news that Energy Transfer (ET) had suspended development of its Lake Charles LNG project to “focus on allocating capital to its significant backlog of natural gas pipeline infrastructure projects that Energy Transfer believes provide superior risk/return profiles” (see Energy Transfer Unexpectedly Kills Lake Charles LNG Export Project). Even though ET is not moving forward with LNG exports at the site, the company is considering another option: NGL (primarily ethane) exports.

NGL-to-Crude Ratio Drops To 18 Month Low - The ratio of NGL prices to crude oil weakened to 0.36 on Friday (green oval, right-hand graph), a level last seen in the fall of 2024. Over the past six months, the ratio’s decline can be attributed to lower prices for ethane and butanes (down by 13% and 8% respectively) and a higher crude oil price (up by 8%), supported by a ‘war premium’ stemming from escalating tensions with Iran and the associated risks to Middle East supply and shipping flows through the Strait of Hormuz. The ratio so far during 2026 has averaged 0.39, meaning Mont Belvieu NGLs have averaged 39% of WTI crude oil at Cushing. As shown in the left graph below, the annual NGL-to-crude ratio since 2013, has averaged 0.42, ranging between 0.36 and 0.52 (red line). With the ratio now pressing the low end of its post-2013 range, today’s NGL to crude relationship reflects a market where crude is carrying a geopolitical premium while the NGL barrel remains fundamentally oversupplied — widening the relative discount and underscoring the divergence between oil and NGL fundamentals.

Amigo LNG MOU Targets Permian Natural Gas Glut, Negative Waha Prices -Mexico’s national pipeline operator, Cenagas, has signed a memorandum of understanding (MOU) with an affiliate of Amigo LNG to develop a 48-inch natural gas pipeline.NGI chart of Waha daily natural gas prices from Feb 2025 to Feb 2026, showing frequent negative pricing below $0/MMBtu and spike near $15/MMBtu in January 2026. At A Glance:
Waha summer prices negative
48-inch pipe would link Arizona, Guaymas
7.8 Mt/y LNG vessel nears permits

U.S. Natural Gas Exports Keep Rising on Record LNG, Mexico Demand -Total U.S. natural gas exports are charging toward historic highs as feed gas to LNG terminals nears a record 20 Bcf/d, bolstered by resilient demand from pipeline flows into Mexico.Chart titled “NGI’s Agua Dulce & Waha Bidweek Prices vs Average US Natural Gas Pipeline Exports to Mexico” shows bidweek prices from Feb 2023 to Feb 2026 alongside exports rising toward 8 Bcf/d, Waha turning negative at times. At A Glance:
LNG feed gas approaches 20 Bcf/d
Mexico cross-border flows target record year
Storage deficit narrows to 0.3%

Supreme Court grapples with venue question in Michigan pipeline fight - The Supreme Court on Tuesday considered a hypertechnical question that could help determine the fate of the Line 5 oil pipeline in Michigan. During oral argument in Enbridge v. Nessel, the justices did not clearly indicate whether they thought a federal judge had the ability to waive a 30-day deadline for Enbridge to file a request to transfer a lawsuit related to its pipeline from state to federal court. The lawsuit stems from Michigan’s effort to shut down Line 5 due to oil spill risks in the Great Lakes. However, at least one conservative justice questioned how moving the case might affect the sovereign interests of the state of Michigan. Advertisement “Here it’s a state that would be suffering, to the extent [Enbridge’s] complaint is allowed to go forward,” said Chief Justice John Roberts, adding that Michigan’s sovereignty might be a point in favor of keeping the Line 5 lawsuit in state court. John Bursch, a private attorney and former Michigan solicitor general representing Enbridge, argued that it would be wrong to assume that Congress wanted to “handcuff federal courts so that they couldn’t exercise equity.” “You need a clear command or some other really compelling statement to strip federal courts of that,” Bursch said. The dispute arrived in the courts after Michigan Gov. Gretchen Whitmer, a Democrat, ordered the shutdown of Line 5 beneath the Straits of Mackinac, due to concerns that the aging oil pipeline would spill into the Great Lakes. Attorney General Dana Nessel, also a Democrat, initially filed the suit defending the order in state court. Enbridge did not attempt to remove the case to federal court until nearly two years later. A federal judge in Michigan waived a 30-day deadline for Enbridge’s transfer request, but that ruling was later struck down by a federal appellate court. Whitmer has filed a separate Supreme Court petition challenging another Enbridge lawsuit filed in federal court that remains pending. During Tuesday’s arguments, more than one justice expressed qualms about one Line 5 case proceeding in federal court, while the other works its way through state court. The justices also questioned the ability of the state court to properly address some of the issues raised in Nessel’s case. “It seems to me if they were going to be removed in that way, they would have been removed in pairs,” said Justice Clarence Thomas. Bursch said it wasn’t clear initially that Nessel’s challenge was a federal case. However, circumstances changed after the Canadian government warned that Whitmer’s order violated a 1977 pipeline transit treaty between the United States and Canada. The terms of the treaty bar state and local officials on either side of the border from blocking operation of the pipeline. Justice Sonia Sotomayor asked Michigan Solicitor General Ann Sherman whether she would be willing to commit, if the state prevails in state court, to staying the lawsuit until the case brought by the governor is resolved in federal court. Sherman demurred, stating she would have to discuss that strategy with her client. Justice Brett Kavanaugh asked Bursch at one point in the hearing whether Enbridge thought it would not get a “fair shake” in state court. When Bursch, the attorney for the company, responded that state courts haven’t dealt with foreign affairs, Kavanaugh replied that federal district courts don’t often deal with those claims either. But Justice Samuel Alito appeared swayed by the argument, noting the consequences of a pipeline shutdown for U.S.-Canada relations and the economic risks of halting the oil supply. He also referred to Bursch’s argument that if a state court issued a preliminary injunction, it would take a long time before the issue of treaty rights could be addressed by the Supreme Court. “The state’s position is these are state law claims,” Sherman replied. “If something goes really awry in state court, this court can review that and can fix that, but we trust state courts to do their job and to have concurrent jurisdiction.” She added that Congress designed strict removal deadlines “out of respect” for state courts. Meanwhile, some of the Supreme Court’s liberal justices appeared skeptical of Enbridge’s claims that the justices could extend the removal deadline under what is known as equitable tolling, which allows a court to stretch a statute of limitations deadline in certain circumstances to allow a party to pursue a case they would otherwise have been unable to file. “I have trouble understanding what right you are losing,” Sotomayor said to Bursch. “There is still a forum for your claim.” Her concerns were later echoed by Sherman, who said in cases with a statute of limitations “the courthouse door closes for that litigation.” “In this case, one door might close, but there is another door open,” Sherman said.

Diversified to Buy Sheridan’s East Texas Gas Assets for $245MM - Diversified Energy Co. has agreed to purchase high-working interest natural gas assets and related facilities in East Texas for $245 million cash.

Ground Game Added Locations for E&Ps, Built Barnett Stealth Play for Diamondback - The massive consolidation wave that swallowed one upstream company after another from 2022 through 2024 has cooled, but the ground game rolls on—including the stealthy building of an impressive position in the highly scrutinized Permian Basin. E&Ps rolled up acreage, swapped leasehold and bought interests in 2025, but Diamondback Energy quietly assembled 200,000 acres in the Midland Basin’s Dean Formation.

Permian Resources Holds $3B for Delaware Basin M&A as Divestitures Loom - Midland, Texas-based Permian Resources is well positioned to compete for large divestiture packages rumored to be coming to market, executives said in a Feb. 26 earnings call. Permian Resources says it can comfortably spend up to $3 billion on Delaware Basin acquisitions in the coming quarters, hoping to capitalize on potential divestitures.

Stream advisory issued for Kansas river after oil spill (KSNW) — The Kansas Department of Health and Environment issued a stream advisory Monday after an oil spill in a Kansas river. The advisory is for the Chikaskia River and an unnamed tributary. The area of concern starts in the tributary near Southwest 150th Street to where it joins the Chikaskia south of Spivey. The advisory covers the river from that point to the Kansas Highway 2 bridge in Harper County. A spill of crude oil and water from an oil production lease in the area was discovered on Sunday. Kansas plans water cuts to protect Ogallala aquifer’s future The Kingman County Sheriff’s Office, KDHE, the Environmental Protection Agency and representatives from the Kansas Corporation Commission are on scene helping with cleanup efforts. People are asked to avoid contact with the bodies of water and to not allow livestock to enter or drink from the water. KDHE said that the full extent of the spill is still being determined but that water quality has been impacted. The advisory will be rescinded once testing shows the waters are safe.

EPA: Spill in Kansas river involved 33,600 gallons of oil-water mixture (KSNW) — The Environmental Protection Agency is ordering an oil company to clean up a spill in a Kansas river.On Monday, the EPA issued an order to Atlas Operating LLC. and provided the public with the clearest picture yet of the extent of an oil spill in the Chikaskia River.The spill happened Feb. 15 at a system of oil tanks south of Spivey, in Kingman County.The EPA said 33,600 gallons of a mixture of brine production water and crude oil leaked into an unnamed tributary of the Chikaskia and into the river itself. Officials said impacts could be seen 12 miles downstream from the tanks.Regulators have issued a unilateral administrative order instructing Houston-based Atlas Operating to do the following:

• Stop the flow of oil into the stream and river.
• Remove oil, contaminated soil and debris in the area around the spill.
• Recover oil and “oil-impacted debris” along the shorelines.
• Dispose of the waste in compliance with state and federal regulations.

The EPA wants the work to be done by March 13.

Regulators rely on fossil fuel industry data. How often is it wrong? - Federal and state regulators have long relied on oil and gas operators to self-report data covering almost everything they do, but some high-profile missteps and fraud have shaken that framework.Operators are supposed to provide details around emissions data, the amount of crude spilled in an accident, well pressure test results and how much gas is coming out of a well, among other things. Regulators then review the data and conduct field inspections to verify a company’s report.The major problem, analysts and environmental groups say, is that governments often lack the staff and resources to properly vet data — making it difficult for agencies to track how accurate the data and reports they receive are.“Generally, every state is overwhelmed by the work, and because of that, there’s little opportunity to systematically audit the industry’s self-reported data,” said Adam Peltz, a director and senior attorney in the Environmental Defense Fund’s Energy Program. “There’s an unknown but huge number of mistakes and errors and problems that slip through the cracks.”Colorado oil and gas regulators dropped a bombshell in 2024 when operators reported to the state that their third-party contractors had purposefully falsified thousands of data points for hundreds of wells, fudging pollution numbers and other data related to well remediations.The Railroad Commission of Texas, which regulates that state’s massive oil and gas industry, flagged 81 instances of operators submitting false data that were referred for legal enforcement since 2020.Other state regulators — including those in Utah and Virginia — said they’ve never encountered falsified data, while regulators in Oklahoma and Louisiana have not tracked the number but could give anecdotal examples. On the federal side, the Interior Department has fined and investigated companies for falsifying tests for offshore blowout preventers, faking the data because employees were worried their equipment wouldn’t pass the safety tests. Much more common than deliberately submitting false information, regulators and experts say, are instances in which operators submit typos or incorrectly logged data. But the limited ability regulators have to check all the documents and data they receive can make it easier for bad actors to hide misfeasance, said Dwayne Purvis, founder and principal adviser of Purvis Energy Advisors. “I do think most operators in most forms are accurate and reliable,” Purvis said. “The problem is when a person does something they shouldn’t do, they have the ability to conceal it, at least in part, by not reporting it explicitly or correctly.”POLITICO’s E&E News polled 21 state agencies and five federal agencies about their inspection programs, instances of falsified data and how they police industry self-reporting. Of those, 12 state agencies and three federal agencies responded. All of the written responses from state and federal regulators can be viewed here. The number of people reviewing data and tests self-reported by the fossil fuel industry varies dramatically from state to state, their responses show.Regulators in Texas, the country’s largest oil and gas producer, wrote that they employ 131 field inspectors across the state. The New Mexico Energy, Minerals and Natural Resources Department has just 18 field inspectors on staff, although that state is the second largest producer of oil in the country.Michigan — which produced 238 times less crude in September 2025 and 56 times less natural gas in 2024 than New Mexico — has 30 field inspectors on staff.

You Go Your Way, I’ll Go Mine – Why Accounting Methods Matter. (No, Seriously, You Gotta Read This) | RBN Energy -As E&Ps release a flood of year-end results, investors, analysts and industry observers scrutinize annual reports to compare the performance of upstream oil and gas companies. Yet, despite operating in the same shale basins, drilling similar wells and facing the same commodity price environment, some producers report markedly different financial results that are often not driven by geology, operational execution or management strategy. Instead, they stem from accounting methodology, specifically from whether a company uses the Full Cost (FC) or Successful Efforts (SE) method to account for its oil and gas properties. Although the FC and SE approaches are permitted under U.S. Generally Accepted Accounting Principles (GAAP), they reflect fundamentally different philosophies about how exploration successes and failures should be recognized in financial statements. These differences influence reported earnings, asset values, depreciation and depletion rates, impairment behavior and, ultimately, how companies are perceived by the market. For decades, FC and SE accounting methodologies were viewed largely through the lens of conventional exploration. In that Pre-Shale Era, dry holes were common, exploration risk was high, and accounting methodology played a major role in determining financial results. FC tended to smooth results by spreading failures across large cost pools, while SE forced companies to recognize losses immediately. The rise of large-scale shale development changed that dynamic. Modern shale drilling is more repeatable, more data-driven, and far less exposed to traditional exploration risk. As a result, many market participants assume that the differences between FC and SE have become less relevant. That assumption is only partly correct. While shale has reduced the importance of classic dry-hole risk, it has not eliminated the economic and analytical consequences of accounting choice. Instead, the battleground has shifted. Today, the most important differences between FC and SE appear in impairment timing, depreciation profiles, reserve revisions, and the way capital costs are embedded in balance sheets over time. (Wake up! We’re just getting to the good stuff.) However, it is important to recognize that despite whichever accounting methodology a company subscribes to, cash flow and cash flow-related metrics will still tell the economic truth about a company’s financial fortunes. To understand why FC and SE accounting still matter today, it is necessary to briefly revisit the environment in which these methods were developed. Both emerged in an era when upstream oil and gas exploration was fundamentally different from the manufacturing-style drilling programs that dominate today’s shale basins.From the 1950s through most of the 1990s, much of the industry’s capital was devoted to high-risk, high-cost exploration. Companies routinely drilled wildcat wells in frontier basins, offshore environments and geologically complex regions with limited subsurface data. In addition, seismic quality was rudimentary by modern standards. As a result, failure rates were high. In many basins, a significant portion of exploratory wells encountered no commercial hydrocarbons. A single unsuccessful well could cost tens of millions of dollars and generate no reserves. Exploration outcomes were often binary: either a discovery was made, or the entire investment was lost. In this environment, how companies accounted for exploration costs had a substantial impact on reported financial performance. Against that backdrop, two distinct accounting philosophies emerged. Under the SE method, companies are required to expense the costs of unsuccessful exploratory activities as they occur. Only expenditures associated with proved reserves and productive assets are capitalized. This approach emphasizes project-level accountability and rapid recognition of failure. Poor exploration results translate quickly into lower earnings. Supporters of SE argue that it provides a more transparent and conservative view of financial performance. By recognizing losses promptly, it prevents companies from carrying uneconomic investments on their balance sheets and forces management teams to confront unsuccessful strategies.FC accounting adopts a different perspective. Rather than evaluating projects individually, it treats exploration as a portfolio activity. Under this method, most exploration and development costs are capitalized and accumulated in large cost pools, typically organized by country. Dry holes, abandoned prospects and unsuccessful acreage positions are viewed as unavoidable components of the exploration process — sort of like Gold Rush prospectors spending a lot of days panning for gold without success before hitting the jackpot. Proponents of FC argue that this approach better reflects the long-term economics of resource development. Individual failures are expected to be offset by future discoveries, and capitalizing costs smooths earnings over time. In their view, expensing dry holes immediately creates excessive volatility that does not reflect underlying business value.[….] Because accounting policy primarily affects the timing of expense recognition rather than underlying economics, cash flow remains the most reliable indicator of performance. Investors and analysts evaluating upstream companies should emphasize operating and free cash flow, reinvestment rates, finding-and-development (F&D) costs, reserve replacement efficiency, payout ratios and capital returns. These measures are less distorted by accounting treatment and more closely reflect economic reality.In Figure 2 below, we compare the FC and SE accounting treatments. In this example, the FC company posts a profit of $86 million compared to a $60 million profit for the SE company (see green-shaded row). This difference is due to the $30 million expensing of three unsuccessful wells for the SE company (yellow-shaded row) and the $4 million in higher depreciation, depletion and amortization (DD&A) expenses (pink-shaded row) for the FC company. Also note that cash flows (blue-shaded row) for both companies are the same.While FC and SE accounting can materially affect reported earnings and asset values, neither method changes the business's underlying economics. Shale development narrowed the most visible historical differences between FC and SE by reducing traditional dry-hole risk, but it did not eliminate the importance of accounting methodology. Instead, it shifted the battleground toward impairment timing, DD&A profiles, reserve revisions, and the accumulation of embedded capital on balance sheets. Now that we’ve introduced the accounting methods, we will augment our reporting of year-end reserve reconciliations in upcoming blogs to highlight their impact on individual company results.For investors and analysts, however, we want to reinforce a simple but critical principle: Accounting determines when results are recognized, but cash flow determines whether value is created. In the end, cash flow — not accounting methodology — is the only true measure of success or failure in the upstream oil and gas business.

PHMSA wants to issue permit to Sable Offshore to restart Calif. pipeline - Federal regulators want to issue a special permit to allow a Texas company to restart a coastal pipeline network in California that failed in 2015 and resulted in one of the worst oil spills in state history. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration on Monday posted a notice proposing granting Sable Offshore a special permit to restart two segments of the Santa Ynez pipeline system, which transports oil drilled offshore through Santa Barbara, San Luis Obispo and Kern counties.The proposed waiver is a win for Sable, which has turned to the federal government for support in restarting its pipeline since hitting significant opposition among state and local California officials.Sable needs a special permit to operate its pipeline due to a consent decree imposed after the 2015 oil spill, before Sable purchased it.

U.S. Crude Daily Average Production Falls in December as Bakken Leads Pullback -- Average daily crude oil production in the United States eased in December to the lowest daily production rate in months, according to the latest EIA data. Total December production, however, was higher than in November. According to the EIA, U.S. crude oil output averaged 13.655 million barrels per day in December, down from 13.788 million in November and the lowest daily average since June 2025. The dip from November to December was modest at the national level — roughly 1% — but some regions saw sharper percentage declines. The steepest drop came from North Dakota, where production fell from 1.168 million barrels per day to 1.092 million (-6.5%). Ohio followed with a roughly 6% slide, while Louisiana posted a 3% drop. Texas slipped less than half a percent. By contrast, Alaska’s average production continued climbing, rising from 428,000 to 433,000 barrels per day. Federal Gulf of Mexico output rebounded from 1.953 million bpd to 1.996 million bpd. The broader picture isn’t nearly as dramatic as some framing implies. Production remains elevated by any historical standard, still hovering around record territory above 13.6 million bpd. December’s average daily production is still nearly 200,000 bpd above December 2024’s average, and above every month except the previous five. What December shows is moderation, particularly in the Bakken and parts of PADD 2. The December slowdown aligns with softer pricing in late autumn. WTI spent much of November and December in the mid-to-high $60s before firming again early this year. For shale producers—especially shale producers in higher-cost basins like the Bakken—that price band is enough to sustain production, but it might not be enough to increase it. The data suggests that as 2025 came to an end, operators leaned toward maintenance rather than expansion. A one-month dip in daily averages does not signal structural decline. It reflects a mature shale sector responding to price signals in real time. If crude holds above $70 through the first quarter, the December softness may prove temporary.

Bring Me to Life – Bridger Pipeline Aims to Create 550-Mb/d Outlet for Canadian Crude | RBN Energy - Bridger Pipeline Expansion LLC — a wholly owned subsidiary of Bridger Pipeline LLC — has filed plans with the Montana Department of Environmental Quality (DEQ) for a 36-inch-diameter crude oil pipeline designed to move 550 Mb/d of Canadian production 645 miles from the U.S.-Canada border to the major Rockies crude hub at Guernsey, WY. The concept is straightforward but ambitious: move barrels south into U.S. markets by leveraging existing infrastructure, including what could amount to a revival of the long-dormant Keystone XL facilities in Alberta. Bridger submitted a formal plan for the project to the Montana DEQ on January 28. The project includes plans for a new crude oil line (dashed yellow-and-black line in Figure 1 below) whose proposed route largely follows existing rights-of-way and aims to streamline permitting while preserving the optionality for Bakken interconnects in Montana. Guernsey is not the final stop but more of a switchyard, meaning that additional downstream links would be needed to shuttle crude onward to hubs such as Cushing, OK; Patoka, IL; and ultimately the Gulf Coast (more on that below). Given the proposed border origin point, the only infrastructure that appears capable of supplying that scale of incremental volume is the partially constructed Keystone XL system (red line in Figure 1) in Alberta, which has remained idle since 2021 (see The Payback and One Is The Loneliest Customer). We all know the Keystone XL story, but here’s a quick recap. The pipe was initially proposed in 2008 by TransCanada (now TC Energy) and designed to transport crude from Canada’s western oil sands south to U.S. refiners. The 1,179-mile pipeline system would have moved up to 830 Mb/d of crude oil from Hardisty, AB, to Steele City, NE. The key twist? It required a U.S. Presidential Permit because it crossed the international border, which allowed the project to be turned into a political lightning rod. From 2008-15, Keystone XL faced intense scrutiny and organized opposition from environmental groups, Native American tribes, landowners and climate advocates. In 2015, President Obama rejected the pipeline’s border crossing, arguing the project would undermine U.S. climate leadership. President Trump reversed that decision in 2017 and approved the permit, allowing development efforts to resume amid ongoing legal challenges. But President Biden revoked the permit on his first day in office in 2021 and TC Energy formally terminated the project later that year, bringing the long-running proposal to a dead end. TC Energy completed the spinoff of its crude oil pipeline business into a standalone company, South Bow Corp., in 2024. Through all the turmoil on the U.S. side of the border, some construction on the Canadian side went forward anyway. Segments of 36-inch pipe, along with a Hardisty-area terminal and two pump stations, are still in place, including at the border crossing. Assuming the Bridger project is tying into that dormant footprint, the combined pipes could create a functional cross-border outlet without the need for Keystone XL’s southern leg (dashed gray-and-black line in Figure 1), which was never built out, and allow stranded steel to be converted into working infrastructure. Of the 645 miles of new Bridger pipeline from the Canadian border to Guernsey, 435 miles would span Montana’s Philips, Valley, Daniels, Sheridan, Roosevelt, Richland, Wibaux, Fallon and Carter counties, with the remaining 210 miles covering Wyoming’s Crook, Weston, Niobrara, Goshen and Platte counties. More than half of the Montana segment and all of the Wyoming part would parallel existing rights-of-way (ROW). That approach is intended to lower construction costs and reduce environmental and regulatory risk in a landscape where permitting timelines can make or break project economics. Operationally, the line could interconnect with Bridger’s existing system (green line in Figure 1) at Four Mile and Baker in Montana, allowing some Bakken light crude to enter the system. Although Canadian barrels appear to be the primary target, incremental Bakken receipts could add commercial optionality. Bridger’s current proposal only extends to Guernsey. As noted above and covered in Guernsey, I'll Keep Coming Back to You, the hub isn’t an end market but rather a gateway, which means downstream connections are essential. And outbound egress from Guernsey is nearly maxed out. A couple of possibilities for enough capacity to handle an incremental 550 Mb/d have been theorized by our good friends at Plainview Energy Analytics. One would be to construct a new pipeline (black arrow in Figure 1) linking Guernsey to South Bow’s existing Keystone system (blue lines in Figure 1) at Steele City. While much of Keystone’s U.S. mainline operates near capacity, once it reaches Steele City the system divides into two segments, with one leg heading to Cushing and the other to Patoka. Both legs are understood to have underutilized capacity, making them potential options for absorbing additional flows and allowing barrels to access Gulf Coast markets. Most of these volumes would likely be heavy crude from Alberta’s oil sands. PADD 2 (Midwest) refineries have a limited ability to run additional heavy, low-API barrels. That means a substantial portion of incremental imports would need to travel through Midwest crude hubs, then continue on to refineries and export terminals along the Gulf Coast. Another possibility for egress from Guernsey to Cushing is the use of existing infrastructure. For example, the 760-mile Pony Express pipeline (teal line in Figure 1) currently has full-path capacity (including Seahorse Pipeline’s leased capacity; see What Happened in Wyoming) of roughly 400–500 Mb/d, depending on the use of DRAs — drag-reducing agents (chemicals that effectively increase a pipe’s capacity; see Kind of a Drag). Today, Pony’s mainline runs nearly full, transporting about 450 Mb/d of crude from Guernsey and northern Colorado to Cushing. While Pony in its current configuration could not accommodate anywhere close to an additional 550 Mb/d of flow, a scalable pathway to market could be developed by leveraging parts of the existing system alongside construction of a new pipeline broadly paralleling the Pony Express route. Although this approach would still require substantial new build, it would anchor an expansion to a proven corridor and an established delivery point rather than starting from scratch.

Turn Me Loose – How Canada Became the World’s #4 Oil Producer | RBN Energy -Canadian crude oil production has once again reached new highs and is expected to continue growing. But, in an area where steep price discounts have been a frequent problem in the past, and in a world that is seemingly awash in crude at the moment, what does that mean for Canadian crude producers, and how will all this growing supply get to market? In today’s RBN blog, the first of a series, we discuss the ongoing growth of Canadian crude supply. Canadian crude oil and condensate production has nearly doubled since 2010, making Canada the world’s fourth-largest producer, trailing only the U.S., Russia and Saudi Arabia. In fact, the province of Alberta on its own is the world’s #4 producer. Canadian production saw another year of growth in 2025, with November and December setting new highs at 5.6 MMb/d (total across stacked layers at right end of Figure 1 below). All but 4% of this production (gold layer) came from the Western Canadian Sedimentary Basin (WCSB), where pipeline capacity constraints and steep price discounts have been a frequent problem for producers over the past couple of decades. Most production from the WCSB comes from the oil sands: upgraded oil sands production (red layer) was 1.3 MMb/d last year, while non-upgraded oil sands bitumen from thermal or mining (black layer) was 1.9 MMb/d. Other WCSB heavy oil production (light-gray layer) was 0.7 MMb/d, conventional light/medium oil production (blue layer) was 0.6 MMb/d, while WCSB condensate and pentanes production (green layer) was nearly 0.6 MMb/d. Production from Eastern Canada, almost entirely from offshore Newfoundland, was 0.2 MMb/d (gold layer). While the 2024 startup of the Trans Mountain Expansion Project (TMX) — which increased the pipeline’s capacity from 300 Mb/d to 890 Mb/d — improved Canadian crude price differentials, they have started to widen out again in recent months. Before we look at what might come next for the WCSB crude oil market, let’s start with a review of the key drivers of Canadian growth to this point.Canadian crude and condensate production growth has been dominated by Alberta’s oil sands region (red and black layers), where production has grown from 0.6 MMb/d in 2000 to 3.5 MMb/d in 2025. The remainder of Canadian production (other layers) has seen only modest growth over this period, from 1.6 MMb/d to 1.8 MMb/d.While commercial production from Alberta’s oil sands began in the 1960s, it was the decade of the 2000s that saw most of the groundwork laid for this growth. The mid-2000s saw a big jump in oil prices (green bars and right axis in Figure 2 below), as global demand grew while the oil market worried that global production would struggle to keep up with demand growth. Despite strong oil prices, U.S. crude oil production continued to decline (solid blue line and left axis) before U.S. shale oil production took off (dashed blue line with dots and left axis). Alberta’s oil sands — with its vast bitumen reserves, relatively investment-friendly jurisdiction, proximity and pipeline connections to the world’s largest crude market south of its border, and recent advances in steam-assisted bitumen recovery from horizontal wells — attracted the investment interest of global supermajors and domestic producers alike, resulting in significant production growth over the past 25 years (red line and left axis). While ExxonMobil had long had a presence in Canada’s oil sands, the 2000s also saw the likes of Shell, Chevron, Marathon Oil, ConocoPhillips, BP, Devon Energy, Equinor (Statoil) and Total Energies step into the space and deploy significant capital to fund greenfield oil-sands projects.The flurry of investment in Canada’s oil sands resulted in mining and thermal bitumen production capacity additions averaging about 175 Mb/d annually from 2007 through 2018, as shown in Figure 3 below (blue bar segments show thermal capacity adds, green bar segments show mining capacity adds, red triangles show upgrading capacity adds, while the black line shows total Alberta oil sands production growth year-over-year). Despite several years of lower oil prices following 2014, oil sands production capacity continued growing at a rapid clip until 2019. Since then, the rate of capacity expansion has slowed considerably. (Projects typically take around three years from the start of construction to first production.)Despite a much slower pace of capacity additions since 2018, production from Alberta’s oil sands has grown by around 20%, or 600 Mb/d, since then. By and large, this growth has been more capital-efficient than prior growth, as operators have improved capacity utilization rates and found smaller (often under-the-radar) projects to enhance plant and well efficiencies. Another factor has been the synergies that operators have extracted between their legacy oil sands assets and those acquired from competitors that exited the area. Most foreign-headquartered oil companies have either exited the area entirely (BP, Chevron, Devon, Equinor, Marathon, Total) or significantly reduced their stakes (Shell, Conoco), selling their interests to incumbent domestic Canadian producers (primarily CNRL, Suncor and Cenovus) as they shifted their focus to opportunities in U.S. shale, LNG and/or offshore plays like Guyana. Persistently low natural gas prices have also helped the cost competitiveness of oil sands, as most projects use around 1 Mcf of natural gas for every barrel produced.

While thermal and mining oil-sands projects have been the biggest drivers of WCSB production growth, the second-biggest driver has been from condensate and pentanes plus (green line in Figure 4 below), whose output has grown from about 125 Mb/d in 2010 to about 590 Mb/d in 2025. Volumes from the prolific Montney formation in northwestern Alberta and northeastern British Columbia have been out front, increasing by nearly 300 Mb/d from 2014 to 2025 (while Montney raw gas production grew by 8 Bcf/d). The Montney accounts for roughly two-thirds of WCSB condensate and pentanes production, while the Duvernay provides nearly 20%. With the WCSB being short of diluent to blend with the tar-like bitumen and extra-heavy oil into a blend “thin” enough to flow on pipelines, condensate and pentanes plus are priced at a premium in the WCSB to attract diluent imports via pipeline from south of the border. WCSB natural gas drillers have often skewed their drilling programs to liquids-rich zones to benefit from strong condensate prices, especially when WCSB natural gas prices are weak (which feels like most of the time). Conventional heavy oil production has recovered strongly in recent years (gray line in Figure 4 above). After peaking at ~785 Mb/d in 2014, weak prices beginning in late 2014 triggered a decline that lasted for several years. However, since output bottomed at 571 Mb/d in 2020, it has seen a resurgence, averaging ~720 Mb/d in 2025. The Lower Cretaceous Mannville/Spirit River group accounts for essentially all of WCSB heavy oil production. The deployment of highly economic open-hole, multi-lateral well designs targeting the Clearwater formation starting late last decade — and in more recent years also targeting other zones within the “Mannville Stack” (the Sparky, Waseca and other zones) — has driven this growth. (We should note that while all crude oil and bitumen production from Alberta’s designated oil sands is reported as bitumen, we prefer to classify the production from that region that is not produced from mining or thermal stimulation as heavy oil — about 260 Mb/d of the WCSB’s 720 Mb/d of heavy oil production in 2025 — as these barrels are being recovered either by primary or water/polymer-flood means.)Conventional light and medium oil production has grown modestly since 2010, from ~525 Mb/d to ~590 Mb/d (blue line in Figure 4 above), albeit well off the 2014 peak of ~740 Mb/d. The major areas of growth in recent years include oil production from the Montney (from 10 to 90 Mb/d), the Duvernay (from zero to 42 Mb/d) and Charlie Lake (from 2 to 42 Mb/d). Meanwhile, the Bakken/Torquay shale in Saskatchewan near the North Dakota border has seen its oil output drop from 77 Mb/d to 44 Mb/d over this period. Other plays such as the Cardium (50 Mb/d) and Viking (50 Mb/d) have grown since 2010 but have been on the decline in recent years. Production from Eastern Canada (orange line) has been between 0.2 MMb/d and 0.3 MMb/d. While WCSB crude oil demand from refineries has seen impressive percentage growth since 2010 (approximately 40%), it is still “only” around 600 Mb/d, so the vast majority of crude production growth in the basin has had to find a home outside of Western Canada. Unfortunately for Canadian oil producers, export pipeline capacity growth has historically struggled to keep up with production growth. In the next blog in this series, we’ll look back at the growth of WCSB crude oil export capacity and how supply and egress capacity have impacted crude oil prices up to this point. Later in this series, we will discuss our outlook for growth in WCSB supply and pipeline egress, including how a Bridger Pipeline proposal that would tie into the Canadian portion of the canceled Keystone XL project might fit in (see Bring Me to Life).

Glenfarne Brings on Another Potential Offtaker for Alaska LNG Project -- Glenfarne Group LLC has reached a tentative deal with TotalEnergies SE, the largest offtaker of U.S. LNG, to sell the company super-chilled natural gas from its massive export project proposed for Alaska. At A Glance:

• TotalEnergies could buy 2 Mt/y
• 13 Mt/y now under negotiation
• Early pipeline construction could start soon

Federal safety regulator warns his office can’t keep up with Trump’s Alaska oil push - The top federal safety regulator for offshore oil and gas drilling in Alaska publicly warned agency counterparts last fall that his office lacked the staffing to oversee existing operations in the state — let alone the massive expansion being pushed by the Trump administration, according to a document obtained by POLITICO. Justin Miller, a longtime Interior Department employee who oversees inspection and enforcement of regulations on the oil rigs operating in federal waters off the Alaska coast, said the Trump administration’s voluntary separation programs spearheaded by Elon Musk’s so-called Department of Government Efficiency, along with declining industry interest in drilling in Alaska, have resulted in the “loss of many decades worth of experience” that are not easily replaced.The missive from Miller, which the Interior Department told POLITICO was not authorized, raises new questions about the Trump administration’s plans to hold potentially dozens of new oil sales in the federal waters off Alaska, the first of which is scheduled for next Wednesday. President Donald Trump has painted Alaska as a key piece of his “energy dominance” agenda, but the state’s often-treacherous weather conditions and sensitive natural ecosystems require particularly stringent oversight for oil companies operating there. Miller’s warning message shows how the administration’s DOGE-driven cuts to the federal workforce last year could cause unforeseen problems for Trump’s policy objectives.

Global Natural Gas Prices Swing Lower as U.S. Stands Down on Iran Ahead of Talks -- Global natural gas prices seesawed Monday amid milder forecasts and easing geopolitical tensions. European Union gas storage chart as of Feb. 21, 2026 showing inventories at 352.85 TWh, 30.9% full, down 136 TWh year/year and 185 TWh below the five-year average, based on GIE and NGI calculations. At A Glance:
Upside risk remains
Mild weather for Europe through March
U.S. feed gas deliveries ramp up

US Says It Will Allow Sale of Some Venezuelan Oil to Private Companies in Cuba - The US Treasury Department’s Office of Foreign Assets Control said on Wednesday that it would allow some sales of Venezuelan oil to private businesses in Cuba, marking an easing of the US oil embargo, though it’s unclear if the limited sales will bring real relief to the island.The OFAC statement said that its new “favorable licensing policy” will authorize licenses for companies seeking to resell Venezuelan oil for “commercial and humanitarian use in Cuba” but that it would not allow “transactions involving, or for the benefit, of any persons or entities associated with the Cuban military, intelligence services, or other government institutions.” Since the US attack on Venezuela to abduct President Nicolas Maduro, the US has cut off Venezuelan oil shipments to Cuba and pressured Mexico to stop exporting oil to the country by threatening an increase in tariffs. The two countries accounted for nearly 80% of Cuba’s oil imports, and the ramped-up US embargo has caused a major fuel crisis in Havana, with some analysts expecting a total blackout by the end of this month.President Trump previously boasted about the effects of his embargo, noting that “they don’t even have jet fuel for airplanes to take off.” He said the embargo would remain in place until Washington and Havana reach some sort of “deal,” though it’s unclear what sort of agreement could be reached since the administration is signaling that it wants regime change.The Treasury Department’s policy change regarding the embargo came after US Secretary of State Marco Rubio met with Caribbean officials who expressed concern about the embargo and the worsening humanitarian crisis it’s creating.“Humanitarian suffering serves no one,” Jamaican Prime Minister Andrew Holness said at a gathering of Caribbean leaders. “A prolonged crisis in Cuba will not remain confined to Cuba.”

Supreme Court weighs Exxon bid to recoup Cuban Revolution losses - The Supreme Court on Monday considered whether it should allow Exxon Mobil to sue for damages against a Cuban-owned company for its oil and gas assets seized during the Cuban Revolution more than 60 years ago.Several members of the court’s conservative majority did not clearly indicate how they were likely to rule in the case, but the court’s liberal minority appeared highly skeptical of the oil major’s claims that a 1996 law bypassed established legal requirements for challenging a foreign nation or foreign-owned company.“It seems you are asking us to do something very unusual here,” said Justice Elena Kagan in an exchange with Deputy Solicitor General Curtis Gannon, who argued in support of Exxon. The oil major is seeking compensation for $70 million (in 1960 dollars) in oil and gas assets that were seized following the 1959 Cuban Revolution by Fidel Castro’s government. The assets are now controlled by the Cuban-owned company Corporación Cimex.

Vaca Muerta Drives Argentina Natural Gas Surge as FLNG Plans Accelerate --Argentina is on pace to reach production highs this year and is set to “reshape natural gas markets in the region,” according to analysts at Fitch Ratings.Argentina natural gas production by basin, illustrating annual output trends and the growing contribution from key producing regions. At A Glance:
Unconventional gas tops 70% share
Output reaches 144 MMcm/d
Pipeline expansion eases bottlenecks

Fracking in Argentina 'linked to hundreds of tremors' The extraction of gas and oil by fracking—large-scale fracturing of underground rocks by injecting water, sand and additives—is generating growing concern in Argentine Patagonia. Neuquén province—home to the country's largest hydrocarbon reserves—has experienced an increase in earthquakes since fracking operations began there in 2015. In January, a report by the independent consulting firm NCS Multistage revealed that 2026 began with an exceptionally high number of fracturing operations in the area. Continuing at the same rate, this year is expected to set a record for the activity. Luciano Fucello, author of the report and professor of petroleum engineering at the Buenos Aires Institute of Technology, told SciDev.Net that there was a correlation between hydrocarbon production and the tremors reported by residents of Sauzal Bonito and Añelo, in Neuquén province. "During the [COVID-19] pandemic, when activity stopped, the earthquakes stopped. And when it resumed, they returned," he said. Together with Plaza Huincul and Cutral Co, these towns form an oil producing region that, at the end of 2025, generated more than 570,000 barrels of shale oil and 64 million cubic meters of shale gas a day. Both are unconventional hydrocarbons, meaning they require large-scale hydraulic fracturing to produce because they are attached to a source rock. In 2013, a legislative reform enabled fracking in Vaca Muerta, a 30,000 square kilometer formation that today represents—along with grains and oils—the country's main source of foreign currency. Following the subsequent expansion of fracking, the number of earthquakes recorded in territories near the operations has increased—in places where they were not usually felt before. The tremors were strong enough to cause cracks in buildings, leaving many homes uninhabitable. The Induced Seismicity Observatory, created by local experts, has recorded 442 tremors on its website since the end of 2018, when seismic activity intensified. Javier Grosso, a geographer and one of the observatory's founders, told SciDev.Net that the updated figure exceeded 600. In 2025 alone, the observatory recorded 102 tremors in Añelo, near Sauzal Bonito and Rincón de los Sauces, where seismic activity is expanding. This is a record number which Grosso attributes to the increase in fracking operations. "The entire subsoil is being investigated, and it is beginning to show a sensitivity it did not have before," he said. In a 2022 analysis published in the journal Scientific Reports, Grosso and colleagues observed "vertical displacements" since 2017, following periods of intense industrial activity. This included a 4.9 magnitude earthquake in March 2019. The fracturing of rocks "produces a seismic wave that travels through the subsoil," Grosso explained. "The tremor is the response to the injection and extraction of fluid, the readjustment of tectonic plates that respond to these enormous pressures." When the wave reaches populated areas, residents feel noises and tremors, sometimes strong enough to knock over furniture and appliances and even cause structural damage. The Argentine Institute of Petroleum and Gas maintained that the only way to determine the origin of the tremors was to establish a "baseline" that identifies the mobility of the entire basin—something it said was still pending due to infrastructure issues. But according to Grosso, "Vaca Muerta has the most seismic monitoring equipment in all of Latin America. The National Institute for Seismic Prevention has nine seismographs and private companies have between 21 and 25." "We have residents who have been in the area for 60 years and they tell us this never happened before." Fucello acknowledges the high productivity of fracking, with the wells producing up to three times as much as conventional ones. But he warns that the activity requires constant reinvestment. Environmentalists also raise concerns about the industry's water usage. While a conventional well may require 6,500 cubic meters of water, a shale well needs up to 60,000 cubic meters. Much of that volume is unrecoverable, and what is returned is usually reinjected into abandoned wells. Sand consumption is also high. "Last year, five million tonnes were used for fracking in Vaca Muerta," said Fucello. "This year it will be six million," he predicted. "Conventional deposits [extracted using traditional methods] consume 100 times less," he added. Fracking also generates large quantities of contaminated solid waste, warns Santiago Cané, a lawyer specializing in the impacts of this industry at the Inter-American Association for Environmental Defense. In 2024, a geospatial analysis by the National Geographic Institute of Argentina warned about the "potential for critical contamination" in the Negro River basin, due to the high density of wells, many located near bodies of water, agricultural and urban areas. Although no country in Latin America has banned fracking, the Brazilian states of Paraná and Santa Catarina do not allow it, while in Colombia six bills to eliminate it were rejected by Congress. In Mexico, President Claudia Sheinbaum appears willing to promote it to reduce dependence on natural gas from the United States, a stance that has revived the debate about fracking in the region.

Warmth Spreads Across Europe, Asia as U.S. LNG Exports Poised to Rebound -Geopolitical influence on U.S. LNG demand is muscling out weather signals as patterns trend considerably mild in Europe and Asia into early March, according to forecasters.NGI Europe & Asia weather data charts showing trailing 365-day mean temperatures for Northwest Europe, Beijing, Seoul and Tokyo versus normal as of Feb. 26, 2026. At A Glance:
Asia drives incremental LNG demand
Europe LNG imports seen slipping
Middle East tensions lift risk premium

Ukraine Steps Up Imports of U.S. LNG Amid Continued Russian Shelling of Energy Infrastructure -- Ukraine’s Naftogaz Group said Monday it took its first delivery of U.S. LNG at a German import terminal to help supplement domestic supplies that have been impacted by Russian attacks. European Union LNG regasification terminal storage table as of Feb. 21, 2026 showing total inventory of 4,085.4 (10^3 m3), down 248.4 (10^3 m3) on the week, with overall utilization at 43.1% across major EU terminals.At A Glance:
TotalEnergies delivering cargoes
Germany importing volumes
35 Bcf expected in 2026

Appeals court weighs future of Trump’s $4.7B loan for Mozambique LNG project - A federal appeals court on Thursday struggled to navigate an environmental group’s quest to block the Trump administration’s $4.7 billion loan for a liquefied natural gas project in Mozambique. It was not clear from arguments how the panel from the U.S. Court of Appeals for the District of Columbia Circuit will land on the issue. The judges spent over an hour pressing Friends of the Earth on whether it even has standing to bring most of its claims while also questioning the Export-Import Bank’s process in extending the loan to TotalEnergies.The fight over the loan comes as the Trump administration seeks to boost fossil fuel production, albeit primarily domestically. The Export-Import Bank first approved the LNG loan to Total in 2019. Before the company began drawing down the funds, the project was put on hold in 2021 as insurgent attacks from militant group al-Shabab targeted a nearby town. The ensuing conflict with Mozambican forces led to human rights abuses and allegations of war crimes, as POLITICO reported in November.

Shell Weighs $24 Billion Stake Sale in Australian LNG Project - Shell is in talks with ADNOC and Midocean Energy on the potential sale of its minority stake in the Australian North West Shelf LNG project, Bloomberg has reported, citing unnamed sources. The supermajor holds a 16.67% in the project, which is worth some $24 billion. An earlier Bloomberg report said Shell had started considering a sale following changes to how the North West Shelf project would operate, namely as a so-called third-party tolling facility, meaning buyers of the gas pay a fee to have it liquefied. Woodside’s North West Shelf gas processing plant in Karratha, Western Australia, is the country’s first and largest LNG plant. Its life was recently extended until 2070, from an initial term until 2030. Woodside first applied for the extension back in 2018. State and federal governments spent the time since then reviewing the plans to extend the project’s life beyond 2030 amid hundreds of appeals by activists campaigning to preserve the environment and the cultural heritage of the local people. In response to those appeals, the project will be required to reduce its emissions every year and reach net zero greenhouse gas emissions by 2050 under the Albanese government’s strengthened Safeguard Mechanism. Australia is one of the world’s top three producers of liquefied natural gas, featuring some of the largest projects globally. Shell is a major player in that space, but it appears the third-party toll scheme is sub-optimal for the company. Earlier this month, Shell’s chief executive predicted that the global LNG market was set for an annual expansion rate of 3%, which is much faster than the broader natural gas market. New LNG export projects coming online and ramp-ups of recently commissioned facilities are expected to drive a 10% jump in global LNG supply this year, as the market shifts from tightness to abundance.

U.S. Strikes Iran: What is Means for Global Natural Gas Deliveries, Prices- The United States and Israel launched coordinated military strikes against Iran early Saturday in a major escalation of conflict in the Middle East that could impact deliveries of oil and natural gas globally. (see map) At A Glance:
U.S., Israel attack Iran
Oil, gas shipments at risk
Global trade, prices vulnerable

QatarEnergy’s North Field West LNG Project Startup Slips to 2031 -QatarEnergy has lined up construction partners for one of its massive LNG export expansion projects as it pushes toward 142 million tons/year (Mt/y) in export capacity by next decade. At A Glance:

• Technip-led JV secures EPC deal
• Qatar targets 142 Mt/y capacity
• Global capacity wave pressures prices

Egypt to Drill Largest Number of Offshore Wells -The minister described PMS as one of the petroleum sector’s key national entities specialising in offshore construction and marine services, citing its accumulated technical expertise, advanced capabilities and highly qualified workforce. Minister of Petroleum and Mineral Resources Karim Badawi said 2026 will witness the drilling of the largest number of offshore wells in recent years, underscoring the need for early preparation by Petroleum Marine Services (PMS) to maximise the benefits of these opportunities. The minister described PMS as one of the petroleum sector’s key national entities specialising in offshore construction and marine services, citing its accumulated technical expertise, advanced capabilities and highly qualified workforce. Speaking during the company’s general assembly meeting to approve its 2025 results, Badawi commended the strong performance achieved over the past year, which reflects the company’s efficiency in executing complex offshore projects in line with the highest technical standards and within scheduled timeframes. He noted that the current phase presents promising prospects for PMS, particularly amid intensified gas exploration activity in the Mediterranean. Badawi stressed the importance of leveraging the company’s advanced marine fleet and technical capabilities to forge strategic partnerships with exploration and research companies, ensuring readiness to participate in development and production phases immediately upon the completion of ongoing exploration activities.

Croatia Ready to Supply Crude to Hungary and Slovakia -- Croatia can ensure crude oil supplies to Hungary and Slovakia, which haven’t received Russian oil for a month following damage on the Druzhba oil pipeline, the Croatian Prime Minister, Andrej Plenkovic, has said. “Croatia is here as a neighbor, partner and friend to ensure the energy security and smooth functioning of the economies of both Hungary and Slovakia,” Croatian state media quoted Plenkovic as saying. Hungary and Slovakia are releasing oil from their strategic petroleum reserves after Russian crude flows via the Druzhba pipeline stopped at the end of last month.At the end of January, Druzhba, the pipeline that carries Russian crude to refineries in Hungary and Slovakia, was damaged in what Ukraine said was a Russian drone attack. Supplies of Russian oil to the last two remaining EU member states dependent on Russian crude flows via Druzhba have been halted since January 27.Croatia is now in talks with Hungary, Slovakia, and the European Commission on a plan to ensure crude supply to the two EU member states that have kept ties with Russia and Putin since the Russian invasion of Ukraine. Croatia’s pipeline operator JANAF has assured the market and public in recent days it has the capacity to provide non-Russian oil to meet Hungary and Slovakia’s needs. Last week, JANAF said in response to media reports that it “considers partnership and reliability to be the Company's most important business values and its activities contribute to the fact that crude oil supply to Central European countries – Hungary and Slovakia – remains completely unthreatened.”“At this moment, a significant quantity of non-Russian crude oil is being transported via JANAF’s pipeline for MOL Group, while three additional tankers carrying non-Russian oil, also for MOL Group, are on their way to the Omišalj Terminal,” the company said on February 20, referring to Hungary’s energy firm MOL. This week, JANAF said that one shipment for MOL is currently being unloaded at JANAF’s Omišalj Terminal. By early April, seven additional tankers loaded with non-Russian origin oil are expected to arrive for the same user of JANAF’s oil pipeline system, the Croatian company said.

Russia running out of money for new oil wells as drilling hits three-year low – Bloomberg - Russia's oil producers have cut drilling to the lowest level in three years, denting prospects for output growth this year as tougher western sanctions and a strong rouble squeeze revenues. Drilling rigs in Russia drilled about 29,140 km of production wells in 2025, down 3.4% from 2024, Bloomberg News reports, citing industry data. After a record pace in the early months of 2025, activity began to slow in June. In December, drilling fell by about 16% compared with the same month a year earlier, data shows. The slowdown comes as Russian producers face pressure from lower global oil prices, deeper discounts on their crude because of tighter western sanctions and a stronger rouble, which has made exports less profitable. Meanwhile, the Organisation of the Petroleum Exporting Countries (OPEC) and its allies are reviewing how much their members can produce in the years ahead, seeking to better align output quotas with actual capacity. Oil output in Russia, the de facto leader of OPEC+ alongside Saudi Arabia, has already been falling for two consecutive months amid export restrictions. Weaker drilling could add to the pressure as the alliance considers its next steps on supply policy. Stronger US sanctions, which have pushed the price of Russian oil to US$40 a barrel or lower, have already led to a string of bankruptcies among smaller oil companies in key oil-producing regions of Russia.

OPEC May Resume Oil Output Increases from April – The Organisation of Petroleum Exporting Countries (OPEC) is leaning towards a resumption in oil output increases from April, three OPEC+ sources told Reuters yesterday, as the group prepares for peak summer demand and price strength is bolstered by tensions over US-Iran relations. The resumption would allow OPEC leader Saudi Arabia and fellow members, such as the UAE, to regain market share at a time other OPEC+ members, such as Russia and Iran, contend with Western sanctions and Kazakh output is restrained by a series of setbacks. Eight OPEC+ producers – Saudi Arabia, Russia, the United Arab Emirates, Kazakhstan, Kuwait, Iraq, Algeria and Oman will meet on March 1. The eight members raised production quotas by about 2.9 million barrels per day from April to the end of December 2025, equating to about 3 per cent of global demand, and froze further planned increases for January through March 2026 because of seasonally weaker consumption. The Brent crude benchmark is trading near $68 a barrel despite speculation that a supply glut would suppress prices this year. That’s not far from a six-month high of $71.89 hit in January on tensions between the United States and Iran. All three OPEC+ sources, who declined to be identified by name, said the eight members at the March 1 meeting were leaning towards a resumption in production quota increases from April. Three other sources familiar with OPEC+ thinking said they expected increases to resume in April. No decision has yet been made and talks will continue in the weeks ahead of the March 1 meeting, two of the OPEC+ sources said. OPEC and authorities in Russia and Saudi Arabia did not reply immediately to requests for comment. OPEC’s latest oil market forecasts show demand for OPEC+ crude in the second quarter falling by 400,000 bpd from the first three months of the year, but demand for the whole year is projected to be 600,000 bpd higher than in 2025.

Goldman Sachs Hikes Year-End Oil Price Forecast by $6 Per Barrel - Even if it maintains the view of global oversupply this year, Goldman Sachs has raised its oil price forecast for the fourth quarter by $6 per barrel as inventories in advanced economies remain low. The Wall Street bank lifted its Q4 2026 price estimate by $6 to $60 per barrel Brent Crude and made the same upward revision of its WTI Crude price outlook, to $56 per barrel at year-end, on the back of lower-than-expected stocks in the OECD countries, according to a Sunday note cited by Reuters. Early on Monday in Asian trade, the U.S. benchmark WTI Crude was trading 1% lower at $65 per barrel, and Brent Crude was down 1% at $71 a barrel amid uncertainties over the U.S. trade policies after the Supreme Court struck down President Trump’s so-called retaliatory tariffs.Oil prices have jumped in recent weeks on the prospect of a U.S. military campaign in Iran. The investment bank’s base-case scenario continues to assume there would be no supply disruptions related to Iran.Goldman’s supply-demand balance for 2026 remains at a surplus of 2.3 million barrels per day (bpd), assuming no major supply disruptions and no peace reached in the Russia-Ukraine talks.Goldman lifted its Q4 2026 Brent forecast to $60 and WTI to $56 per barrel, citing lower-than-expected OECD stock levels.The bank still projects a 2.3 million bpd surplus in 2026, assuming no major supply disruptions.OPEC+ may resume production increases in 2026 amid limited inventory builds and shifting market dynamics.Lower OECD inventories, however, have prompted the bank to hike its year-end oil price forecast.Last month, Goldman Sachs said that WTI could drop all the way to $50 per barrel towards the end of this year, amid expected excess supply that would put pressure on benchmarks.OPEC+ could reinstate production increases in the second quarter of 2026, considering the lack of meaningful builds in OECD stocks so far this year, the bank said on Sunday. Reports emerged earlier this month that the OPEC+ alliance is leaning toward resuming production increases from April following a pause in output hikes in the first quarter.

Oil prices fall 1% on US-Iran nuclear talks, Trump's tariff hikes; JM Financial says crude to stay subdued till November -- Oil prices declined by around 1% on Monday, after hitting a six-month high last week, amid signs that the US-Iran tensions are unlikely to worsen. Concerns around global growth and lower fuel demand following the tariff hike announcements by US President Donald Trump also weighed on crude. Brent crude futures fell by 76 cents, or 1.06%, to $71 per barrel as of 0354 GMT, while US West Texas Intermediate (WTI) crude futures dropped 75 cents, or 1.10%, to $65.75 per barrel.Back home, crude oil prices on Multi Commodity Exchange (MCX) were also marginally down by 0.30% at₹6,039.Iran and the US are set to hold a third round of nuclear negotiations in Geneva on Thursday, Badr Albusaidi, Oman’s foreign minister, said on Sunday, easing concerns about a potential escalation in tensions.According to a Reuters report, Tehran is willing to consider concessions on its nuclear programme in exchange for sanctions relief and formal recognition of its right to enrich uranium.Meanwhile, on Saturday, Trump said he would increase a temporary tariff on US imports from all countries to 15% from 10% — the highest level permitted under the law — after the US Supreme Court invalidated his earlier tariff programme.Earlier today, China stated that it is conducting a “comprehensive assessment” of the US court’s tariff ruling and urged Washington to withdraw the “relevant unilateral tariff measures” imposed on its trading partners, according to Reuters.The latest round of tariff-related announcements has again created uncertainty over global economic growth and fuel demand.Amid the current backdrop, domestic brokerage firm JM Financial expects oil prices to remain subdued till the November 2026 mid-term elections in the US, as Saudi Arabia-led OPEC+ output hikes seem to be primarily aimed at meeting the US President’s near-term request for lower oil prices.“We believe Brent may remain subdued ~USD 65/bbl till the Nov'26 mid-term elections in the US as Saudi Arabia is obliging the US President’s near-term request for low oil prices, but it is likely to stabilise ~USD 70/bbl in the medium term as otherwise it could hurt US shale capex and lead to a jump in Saudi Arabia’s fiscal deficit,” the firm said.

Oil Prices Rise as Market Awaits US-Iran Moves (DTN) -- Oil and product futures rose Monday morning as the market awaited developments in the Middle East ahead of another round of U.S.-Iranian nuclear talks slated for this week. A drop in U.S. crude, gasoline and distillate inventories in the week ended Feb. 13, as reported by the Energy Information Administration (EIA), also provided support. The U.S. has positioned its largest military force in the Middle East in more than two decades, with U.S. President Donald Trump cautioning Thursday, Feb. 19, that Iran had 10 to 15 days to reach a deal on its nuclear program or face consequences. Traders are bracing for further tensions in the Persian Gulf and have accordingly boosted their bullish bets on crude with long-dated futures showing a bias toward call options that benefit buyers. Crude prices are up 17% so far this year, though intermittent market swings have also resulted in the highest volatility in eight months. The CBOE Crude Oil Volatility Index shows a mid-February reading of 58, a peak since 74.41 in June. On the inventory front, U.S. commercial crude stocks declined by 9 million bbl to 419.8 million during the week ended Feb. 13, the EIA reported. Gasoline inventories fell by 3.3 million bbl the same week for their first drop in 14 weeks, while distillate balances retreated by 4.6 million, the agency added. In Monday's morning session, NYMEX WTI crude futures for March delivery were up $0.31 at $66.79 bbl. ICE Brent crude for April delivery also rose $0.31 to $72.07 bbl. Downstream, RBOB futures for March were flat at $1.9974 gallon while front-month ULSD futures rose $0.0567 to $2.6425 gallon. The U.S. Dollar Index eased 0.139 points to 97.59 against a basket of foreign currencies, boosting the upside in dollar-denominated energy prices.

Tariff Uncertainty and Iran Talks Drive Volatility in the Oil Market - The oil market posted an outside trading day on Monday. It weighed a scheduled third round of nuclear talks between the U.S. and Iran on Thursday and increased economic uncertainty after the U.S. Supreme Court last week struck down parts of President Donald Trump’s tariff plans. Over the weekend, Iran indicated it is prepared to make concessions on its nuclear program in return for sanctions lifting ad recognition of its right to enrich uranium. However, the risk of an attack on Iran remains high amid the U.S. military buildup in the Middle East. The oil market was pressured following the U.S. Supreme Court decision, with the U.S. Customs and Border Protection Agency saying it would halt collections of tariffs on Tuesday, while President Donald Trump said over the weekend that he would raise a temporary tariff from 10% to 15% on U.S. imports from all countries. The market sold off sharply on the opening and posted a low of $65.38. It settled in a sideways trading range before it bounced higher and rallied to a high of $67.28 by mid-morning. The market later retraced more than 62% of its earlier move and settled in a sideways trading range during the remainder of the session. The April WTI contract settled down 17 cents at $66.31, while the April Brent contract settled down 27 cents at $71.49. Meanwhile, the product markets ended the session in mixed territory, with the heating oil market settling up 9.24 cents at $2.6782 following the winter storm that swept through the Northeast, while the RB market settled down 81 points at $1.9892. Goldman Sachs said the global oil market was expected to remain with a surplus of 2.3 million bpd in 2026, assuming no Iran-related disruption to supply, while raising its Brent and WTI forecasts for the fourth quarter of 2026 by $6 to $60 and $56 a barrel, respectively, citing lower OECD inventories. It sees potential sanctions relief in Iran/Russia accelerating stock builds and unlocking higher supply in the longer term, posing $5/$8 of downside risk to fourth quarter prices. It expects Brent/WTI to average $65/$61 in 2027 and to recover to $70/$66 by December 2027 on solid demand and slowing supply growth.Morgan Stanley raised its near-term Brent forecasts, saying that the geopolitical risk premium is likely to persist for a period, but added that it still expects prices to soften to $60/barrel later this year. The bank now sees Brent at $62.50/barrel in the second quarter of this year, compared with $57.50/barrel previously. It also raised its third-quarter forecast to $60/barrel from $57.50/barrel earlier.IIR Energy reported that U.S. oil refiners are expected to shut in about 1.03 million bpd of capacity in the week ending February 27th, increasing available refining capacity by 118,000 bpd. Offline capacity is expected to fall to 751,000 bpd in the week ending March 6th. Rob Carolan, owner of Hometown Forecast Services, which provides outlooks for Bloomberg Radio said the storm that hit the U.S. East Coast originated from a strong Pacific system that struck California with heavy snow and flooding rain last week, built off the clash of cold air above milder Atlantic water to morph into a so-called weather bomb. He said the eastern U.S. will probably remain locked in a colder regime for months because of all the snow and ice across the Great Lakes. He added that the only thing that will unlock the pattern is the sun rising higher in the sky as spring in the Northern Hemisphere advances.

International Oil Prices Jump to 7-Month High Amid Fears of US Attack on Iran -- Global oil prices rose to a seven-month high on Tuesday as markets weighed the risk of a potential military escalation between the United States and Iran.Both major crude benchmarks advanced during Asian trading before slowing down. WTI Crude rose 0.9 percent to $67 per barrel by 7:40 PM Pakistan Standard time (PKT), while Brent Crude edged up 0.76 percent to $72.03 per barrel, staying close to their highest levels in seven months. Regional tensions have reignited concerns over global trade and economic growth, and forced investors to rotate out of risk-sensitive assets such as oil and into traditional safe havens, including gold.Energy analysts have begun factoring in more extreme price scenarios. Speaking to Bloomberg Television, Fereidun Fesharaki, Chairman Emeritus of FGE NexantECA, said oil prices in the $90–$100 per barrel range are “within reach” if tensions escalate further.The analyst said that accepting US demands could undermine Iran’s political standing. So a breakdown in talks is more likely, which may increase the risk of a sharp spike in crude prices in the coming days.

Oil Prices Near 7-Month Highs on Elevated Iran Tensions (DTN) -- Oil and product futures were mostly higher Tuesday morning, hovering near July peaks, as tensions between the U.S. and Iran stayed elevated ahead of negotiations scheduled for this week. NYMEX traded WTI futures for April delivery rose $0.42 to $66.73 bbl, and ICE Brent for April delivery advanced $0.39 to $71.88 bbl. Downstream, ULSD futures added $0.0552 to trade near $2.7340 gallon. RBOB futures, however, bucked the uptrend, with the front-month edging lower by $0.0118 to $1.9774 gallon. The U.S. Dollar Index strengthened by 0.234 points to 97.8750 against a basket of foreign currencies. Brent and WTI futures reached a seven-month high during Monday's session on reports of the State Department evacuating non-essential personnel from the U.S. embassy in Beirut, a stronghold of Iran-affiliated Hezbollah. U.S. President Donald Trump, meanwhile, on Monday reiterated on social media that not reaching a deal "will be a very bad day for that Country, and very sadly, its people." U.S. negotiators are set to meet Iran's foreign minister for a third round of nuclear talks in Geneva on Thursday, Feb. 26. Prices were also boosted by lower-than-expected tariff rates. The U.S. on Tuesday imposed an across-the-board 10% tariff on goods imports after the Supreme Court last week struck down the president's use of emergency laws to enact high import tariffs. Following the ruling, the president said he will institute a 15% rate using other legal mechanisms. Mideast escalation risks were also reflected in rates for chartering dirty tankers, which have soared to the highest in three years. This year alone, the Baltic Dirty Tanker Index shot up by 55%. Rates for crude tankers from the Middle East to Asia have more than doubled since the beginning of the year. Geopolitics aside, traders were closely monitoring U.S. diesel and gasoline inventories, the latter of which began last week with a decline from a prolonged build-up that peaked at 5% above the five-year average. The American Petroleum Institute's weekly inventory report is scheduled for release after market hours today, followed by official inventory data from the U.S. Energy Information Administration on Wednesday. The Conference Board, meanwhile, issues at 10 a.m. EST today its monthly update on U.S. Consumer Confidence. The data, which indicates views and expectations on personal finances and inflation, is expected to see a modest rebound after hitting a 12-year low last month.

Oil prices ease as Iran says prepared to take steps to reach deal with US (Reuters) - Oil prices closed down 1% on Tuesday after Iran said it was prepared to take any necessary steps to reach a nuclear deal with the U.S., after weeks of increased military deployment by the U.S. in the Middle East.Brent futures settled at $70.77 per barrel, down 72 cents, or 1%. WTI futures also fell 1%, settling at $65.63, down 68 cents.Iran, the third-biggest crude producer in the Organization of the Petroleum Exporting Countries, and the U.S. will hold a third round of nuclear talks on Thursday in Geneva, Oman's Foreign Minister Badr Albusaidi said on Sunday. bThe U.S. wants Iran to give up its nuclear program, and has sent aircraft carriers, warships and jets to the region.Iran has denied it is trying to develop an atomic weapon, and its deputy foreign minister said on Tuesday that Tehran was ready to reach a deal to lower tensions between the two countries.Swiss bank UBS said it expected a modest decline in oil prices in coming weeks provided there was no escalation of tensions in the Middle East that could disrupt supply.U.S. crude prices include a $3-$4 a barrel geopolitical risk premium because of tensions between the U.S. and Iran, the director of North Dakota's Mineral Resources Department said on Monday. North Dakota is the No. 3 U.S. oil-producing state. The oil industry needs crude prices to rise and sustain at $70 per barrel in order to grow output, energy executives said.The U.S. State Department is pulling non-essential government personnel and their families from the U.S. embassy in Beirut, a senior official said on Monday, as concerns mount about the risk of conflict with Iran, which, sources said, was close to a deal with China to purchase anti-ship cruise missiles.Meanwhile, the U.S. began collecting a temporary new 10% global import tariff on Tuesday, but President Donald Trump's administration was working to increase it to 15%, a White House official said, sowing confusion over tariff policies after last week's Supreme Court defeat.Trading houses and buyers of Venezuelan oil have chartered the first very large crude carriers to export from the South American country since a Caracas-Washington supply deal began. This is set to speed up shipments from March while boosting deliveries to India, according to sources and data.The European Commission will submit a legal proposal to permanently ban Russian oil imports on April 15, three days after Hungary's parliamentary election, according to EU officials and a document seen by Reuters.Russia's oil pipeline monopoly Transneft has cut crude intake into its system by some 250,000 barrels per day, two sources familiar with the situation said on Tuesday, a day after Ukrainian drones attacked a pumping station serving major oil hubs and ports.U.S. crude stocks rose while gasoline and distillate inventories fell last week, according to market sources, citing American Petroleum Institute figures on Tuesday. Crude stocks rose by 11.43 million barrels in the week ended February 20, much higher than the 1.5 million barrels analysts projected energy firms added to storage.

Oil near seven-month high as Mideast war clouds loom - Oil prices were hovering near seven-month highs on Wednesday as the threat of military conflict between the US and Iran that could disrupt supply continued to worry investors as talks between the parties are set for Thursday, reported Reuters. Brent prices reached their ⁠highest since July 31 while WTI hit its highest since ⁠August 4 on Monday, and both contracts have held near there as the US has positioned military forces in the Middle East to compel Iran to negotiate an end to its nuclear and ballistic missile programme. An extended conflict could disrupt supplies ‌from Iran, the third-biggest crude producer in the Organization of the Petroleum Exporting Countries, and other countries in the key Middle East producing region, said the report. "This uncertainty means the market will continue to price in a large risk premium and remain sensitive to any fresh developments," ING commodities strategists said on Wednesday. US envoys Steve Witkoff and Jared Kushner are slated to meet with an Iranian delegation for a third round of talks on Thursday in Geneva. Iran’s Foreign Minister ⁠Abbas Araqchi said on Tuesday that a deal with the US was 'within reach, but only if diplomacy is given priority.' ″Trump has warned that without a deal, there will be ‘very ‌bad consequences’. Whether (Iran’s) concessions will meet the US's ‘zero enrichment’ red line remains to be seen,” Tony Sycamore, IG market analyst, said in a note.

WTI Extends Losses After Biggest Crude Build In 3 Years --Oil prices are sliding this morning following as an over-supplied market (API reported a huge 11.4mm barrel build last week) beats the geopolitical risk premia (with the US poised to attack Iran). "Iran, rather than backing down and agreeing to all and any term [U.S. President Trump] is placing on the table (as he had expected), is instead daring him to attack. "Just you try it and you will see what you will get!" is kind of what Iran implicitly said to Trump when it held military drills in the Straight of Hormuz last week," Bjarne Schieldrop, chief commodities analyst at SEB Research, wrote. But, prices dipped into negative territory after a Hezbollah official said the group will not intervene in the event of limited US strikes on Iran, AFP reported. “My preference is to solve this problem through diplomacy, but one thing is certain: I will never allow the world’s number one sponsor of terror, which they are by far, to have a nuclear weapon,” Trump said on Tuesday. Nevertheless, The US has ordered the biggest military build-up in the Middle East since the second Gulf war in 2003, including two aircraft carriers. America is adding even more assets to the region, deploying 12 stealth F-22 fighter jets to Israel, according to CNN, which cited a defense official. “So long as we remain in this realm of uncertainty, oil prices are more prone to upside risk on any headlines out of the US-Iran talks,” said Samantha Hartke, head of market analysis for the Americas at Vortexa Ltd. “Our view is that a prolonged disruption is unlikely given the onerous effect that will have on Iranian trade flows and revenues,” she added, referring to Hormuz. So will the official data confirm API's ugly over-supplied build signal? API

• Crude +11.4mm
• Cushing +1.8mm
• Gasoline -1.5mm
• Distillates -2.8mm

DOE

• Crude +15.99mm - biggest build since Feb 2023
• Cushing +881k
• Gasoline -1.01mm
• Distillates +252k

The official data confirmed a huge inventory build for crude stocks in the US (15.99mm barrels is the biggest build since early Feb 2023), reverses some of the bumper draws we’ve seen in the last few weeks. The rest of the energy complex was 'meh'... Source: Bloomberg Don't get too excited though as a huge jump in the adjustment factor is a sign that this data is likely still being impacted by the bad weather of recent weeks... Crude production dipped last week... WTI slid before the DOE data but is holding in the red for now after the huge crude build...

Oil settles little changed, supply worries persist despite large US crude stock build (Reuters) - Oil prices settled largely unchanged on Wednesday as a much larger-than-expected U.S. crude stock build did not do much to calm jitters about the threat to oil supply ‌from potential military conflict between the U.S. and Iran. Brent futures closed up 8 cents at $70.85 a barrel, while WTI futures settled 21 cents lower at $65.42. U.S. crude inventories rose by 16 million ⁠barrels last week as refinery utilization fell and imports increased, the Energy Information Administration said on ⁠Wednesday. That far exceeded the 1.5-million-barrel rise that analysts had forecast in a Reuters poll. However, the EIA's adjustment number, which totals unaccounted-for changes in crude stocks, hit a record last week at 2.7 million barrels per day. "A bearish (EIA) report with a large crude build... the prices impact was however limited, as the oil market remains more influenced by other factors at present, such as geopolitical tensions in the Middle East," said Giovanni Staunovo, ‌commodity analyst at UBS. Brent prices had reached their highest since July 31 on Friday while WTI hit its highest since August 4 on Monday, as the U.S. positioned military forces in the Middle East to try to compel Iran to negotiate an end to its nuclear and ballistic missile programme. An extended conflict could disrupt supplies from Iran, the third-biggest crude producer in the Organization of the Petroleum Exporting Countries, and other countries in the Middle East. Supporting oil prices, U.S. President Donald Trump briefly laid out his case for a possible attack on Iran in his State of the Union speech on Tuesday, saying he would not allow a country he described ‌as the world's biggest sponsor of terrorism to have a nuclear weapon. U.S. envoy Steve Witkoff and Jared Kushner are due to meet an Iranian delegation for a third round of talks on Thursday in Geneva. Iranian Foreign Minister Abbas Araqchi ‌said on Tuesday that a deal with the U.S. was "within reach, but only if diplomacy is given priority". "The real question, of course, is to what extent oil production or oil exports could be halted out of Iran if the US were to strike," said Dennis Kissler, senior vice president of trading at BOK Financial. "Many traders believe that if oil production is hampered, Saudi could raise production quickly, filling in the void, and the U.S. military presence could keep passage in the Strait of Hormuz open. Still, crude will remain ‌in a nervous trade awaiting the meeting’s outcome," Kissler said. Top OPEC+ producer Saudi Arabia has activated a plan for a short-term oil output and export surge in case a U.S. strike on Iran disrupts oil flows, two sources familiar with the Saudi plan told Reuters. Separately, OPEC+ will likely consider raising its oil output by 137,000 barrels per ⁠day for April ⁠to end a three-month pause in production increases, three sources with knowledge of OPEC+ thinking said, as the ‌group prepares for peak summer demand and tensions between the U.S. and Iran boost prices. Eight OPEC+ producers - Saudi Arabia, Russia, the United Arab Emirates, Kazakhstan, Kuwait, Iraq, Algeria and Oman - meet on March 1. Tariff uncertainty also further worried investors. Trump's temporary global tariff of 10% took effect on Tuesday after the Supreme Court's sweeping ruling last week. He later said the levy ‌would be 15%, but it was unclear when and if it would apply. The U.S. tariff rate for some countries will rise to 15% or higher from the newly imposed 10%, U.S. Trade Representative Jamieson Greer said on Wednesday, without naming any specific trading partners or giving further details.

Oil Prices Edge Higher As U.S.–Iran Nuclear Negotiations Resume In Geneva -- Global oil markets posted modest gains as traders repositioned ahead of a fresh round of diplomatic engagement between the United States and Iran, with geopolitical risk premiums creeping back into crude benchmarks. Brent crude futures advanced to $70.83 per barrel, marking a 0.12 percent uptick from the prior session’s close of $70.74. Meanwhile, U.S. benchmark West Texas Intermediate (WTI) settled at $65.51 per barrel, also up 0.12 percent compared to $65.43 recorded previously. The price movement comes as attention shifts to the third round of indirect nuclear discussions between Washington and Tehran, scheduled to hold in Geneva under the mediation of Oman. Diplomatic sources indicate that the talks are part of renewed efforts to de-escalate tensions surrounding Iran’s nuclear activities and regional security posture. Energy markets have remained highly sensitive to geopolitical developments in the Middle East, particularly amid reports of expanded U.S. military deployments across the Persian Gulf and elevated defense readiness in Israel. Speaking earlier in the week, U.S. Secretary of State Marco Rubio described Iran’s unwillingness to negotiate limitations on its ballistic missile program as “a significant obstacle” to progress. He emphasized that any durable agreement would need to address broader regional security concerns. U.S. Vice President JD Vance reiterated Washington’s longstanding position that Tehran must not be allowed to acquire nuclear weapons capability. While affirming that diplomacy remains the preferred route, he signaled that alternative measures remain on the table should negotiations falter. On the Iranian side, Foreign Minister Abbas Araghchi defended the country’s missile arsenal, characterizing it as purely defensive and structured around deterrence doctrine. He dismissed assertions that Tehran is developing intercontinental systems capable of striking the U.S. mainland. Since the resumption of diplomatic engagement last month, the two sides have completed two rounds of indirect negotiations facilitated by Oman. Regional actors, including Türkiye, have also supported de-escalation initiatives aimed at restoring stability to energy corridors and maritime trade routes. Both delegations described the previous discussions as constructive, noting agreement on preliminary “guiding principles” that could frame a broader accord. Analysts say this cautious optimism has prevented oil prices from experiencing sharper volatility, despite ongoing military maneuvers. Nonetheless, the strategic backdrop remains tense. Iran’s Islamic Revolutionary Guard Corps recently conducted military exercises, while the U.S. Treasury Department unveiled additional sanctions targeting what it described as Iran’s “shadow fleet” and illicit weapons procurement networks. While geopolitical risks provided modest upward support, crude prices faced headwinds from fresh U.S. inventory data. Figures released by the Energy Information Administration showed that commercial crude stockpiles surged by approximately 16 million barrels in the week ending February 20 — significantly exceeding market expectations. The sharp inventory build raised concerns about short-term demand softness in the world’s largest oil-consuming economy. However, a simultaneous drawdown in gasoline inventories suggested that refined fuel consumption remains resilient in certain sectors. Market strategists note that the interplay between diplomatic developments and macro demand indicators will likely determine the near-term trajectory of oil prices. Should negotiations yield tangible de-escalation signals, risk premiums could moderate. Conversely, any breakdown in talks may inject renewed volatility into global energy markets. For now, crude benchmarks appear range-bound, reflecting a delicate balance between geopolitical uncertainty and underlying supply-demand fundamentals.

Oil Prices Tumble as Crucial U.S.-Iran Talks Begin | OilPrice.com - Oil prices fell by about 2% early on Thursday as the crucial U.S.-Iran talks began in Geneva in what analysts see as one last attempt to reach a nuclear deal through diplomacy. As of 7:50 a.m. ET on Thursday, the U.S. benchmark,WTI Crude, traded down by 1.61% to below the $65 per barrel threshold, at $64.38. The international benchmark, Brent Crude, was falling by 1.27% and was just below $70 per barrel, at $69.96. Prices were under pressure after the latest weekly data by the U.S. Energy Information Administration (EIA) showed on Wednesday that crude oil inventories in the United States surged by 16 million barrels during the week ending February 20. Yet, recent weeks have been distorted by weather-related production freeze-offs and the subsequent snap-back in output, which can swing inventories sharply from one report to the next. The market’s attention today is squarely fixed on Switzerland, which hosts the U.S.-Iran talks mediated by Oman. Oman’s Foreign Minister Badr Albusaidi said negotiators had “demonstrated unprecedented openness to new and creative ideas and solutions.”Still, it is uncertain whether any breakthrough could be made on Thursday. The U.S. continues to amass forces in the Middle Eastern region, with the U.S. military saying it is prepared to execute orders given by U.S. President Donald Trump. Commenting on the oil market implications, ING commodities strategists Warren Patterson and Ewa Manthey said early on Thursday that “A constructive resolution would likely prompt the market to gradually unwind as much as a $10/bbl risk premium, which we believe is currently priced in.” The upside risk to oil remains should talks break down, “but the market may hold off on a full reaction until the scale of potential US action against Iran becomes clearer,” the strategists noted. “If we are to see de-escalation between the US and Iran, it should allow weaker fundamentals to feed through to a lower flat price -- particularly if OPEC+ resumes supply increases from April, which we believe they will agree to this weekend.”

Oil Falls on Record Inventory Build as Volatility Continues -- The crude market on Thursday posted an outside trading day as the market weighed the EIA report released on Wednesday showing U.S. crude oil inventories increasing by 16 million barrels on the week, the most in three years, while the market also assess whether the U.S.-Iran talks could avert a military conflict. The crude market traded mostly sideways in overnight trading before it breached its previous low and extended its losses to over $1.80. It posted a low of $63.60 in light of the surge in oil inventories as well as the news that Saudi Arabia is increasing its crude production and exports under a contingency plan should any U.S. strike on Iran disrupt supplies from the Middle East. However, the market reversed course and rallied over $1.20 as it posted a high of $66.71 by mid-day on reports that the U.S.-Iran talks had stalled over Washington’s insistence of zero uranium enrichment by Iran. The market later erased some of its gains ahead of the close after Oman’s Foreign Minister stated that there was significant progress made during the U.S.-Iran talks. This was despite Axios reporting that the White House envoys were disappointed following their talks on Thursday morning. The April WTI contract settled down 21 cents at $65.21 and the April Brent settled down 10 cents at $70.75. The product markets ended the session in mixed territory once again, with the heating oil market settling down 6.15 cents at $2.6125 and the RB market settling up 4.09 cents at $2.0323. LSEG data showed that the cost of hiring a very large crude carrier to ship 2 million barrels from the Middle East to China exceeded $200,000 a day on Thursday for the first time since April 2020. It has nearly quadrupled from the start of the year. The surge in oil shipping costs follows increased crude exports from the Middle East as traders have accelerated charters ahead of a possible military conflict between the U.S. and Iran. According to sources, the Trump administration has settled on a plan that would require big oil refineries to make up for at least half of the biofuel blending volumes obligations waived in recent years under the Small Refinery Exemption program. The decision could be unwelcome news for larger oil refiners that have argued that additional blending obligations would raise their costs. However, it could help the biofuel industry by increasing demand for blending credits. Under the Renewable Fuel Standard, oil refineries have to blend billions of gallons of ethanol and other biofuels into their fuel or buy credits, called RINs, from those that do. However, small refineries can have those obligations waived if they demonstrate economic hardship. The question of whether to reallocate those exempted blending obligations to larger refiners is a point of contention between the agriculture and fuel industries. Citgo reported a planned startup of a fluid catalytic cracking unit following maintenance activity at its 165,000 bpd Corpus Christi, Texas refinery East plant. A Texas Commission on Environmental Quality filing showed that Valero’s 205,000 bpd Houston refinery reported a third‑party power interruption on Wednesday morning caused a loss of power to the plant. The outage led to emissions from the main refinery flare 30FL1. Refinery personnel followed established procedures to safely stabilize affected units and limit emissions.

Oil Prices Climb As US-Iran Talks End Without Deal - Oil prices edged higher on Friday after diplomatic efforts between the United States and Iran aimed at easing tensions over Tehran's nuclear program concluded on Thursday without an agreement. Benchmark Brent crude futures jumped 0.9 percent to $71.44 a barrel while WTI crude futures were up nearly 1 percent at $65.86. Following meetings in Switzerland, an Omani mediator involved in the negotiations said the talks led to understanding on some issues and that the next round of talks will take place next week in Vienna. The stakes have never been higher, but traders waited to see if a diplomatic breakthrough can avert a potential military conflict in the Middle East. According to the Wall Street Journal, Iran rejected major U.S. proposals, including transferring enriched uranium abroad, halting enrichment, and dismantling certain nuclear sites. Elsewhere, Pakistan has declared an open war against Afghanistan, launching Operation Ghazab Lil Haq with extensive airstrikes against Taliban targets in Kabul, Kandahar and Paktia amid fierce border clashes. Meanwhile, Venezuela's oil ministry has suspended 19 oil production-sharing contracts with private companies signed under the administration of ?President Nicolas Maduro, Reuters reported citing sources with knowledge of the move. It was said the suspension has had no impact on the country's oil and gas output so far.

Oil Prices Surge 3.7% as U.S.-Iran Standoff Triggers Higher 2026 Forecasts -- Economists and oil market analysts have hiked their oil price forecasts for 2026 amid rising geopolitical tensions and heightened war premium due to the U.S.-Iran standoff. Both crude oil benchmarks are now expected to average above $60 per barrel this year, with price forecasts higher by about $1.50 per barrel compared to a month ago, the monthly Reuters poll showed on Friday. Despite ongoing concerns about an oversupplied market, the 34 analysts and economists surveyed by Reuters in February raised their projections in view of uncertainties in how the Iran crisis would unfold in the coming weeks and months. In the February poll, Brent Crude prices are expected to average $63.85 per barrel in 2026. This month’s estimate is higher compared to the January forecast of $62.02.The analysts in the poll expect the U.S. benchmark, WTI Crude, to average above $60 per barrel this year, too—at $60.38 a barrel, up from $58.72 expected in January. Year to date, Brent price have averaged $70.48 per barrel and WTI – $65.01 a barrel. Early on Friday, both benchmarks were trading 3% higher, with Brent near $73 and WTI at $67, after the United States and Iran adjourned the Thursday talks with plans for another round of negotiations next week. Oman’s Foreign Minister, Badr Albusaidi, who was mediating the indirect talks in Geneva, said the parties had made “significant progress” in the nuclear talks. Next week, negotiations are set to be held in Vienna, Austria. It is the ongoing U.S.-Iran standoff that has been the main driver of oil analysts in the Reuters poll to raise their oil price forecasts for this year. Currently, the geopolitical risk premium already baked in the price of oil is about $4-$10 per barrel, analysts say. The war premium, the OPEC+ supply policy, and the fundamentals in supply-demand balances will steer the direction of oil prices this year, they note.

WTI Hits $67 on Potential U.S. Strike Against Iran -- Crude prices hit seven-month highs Friday on the increasing prospect of U.S. military action against Iran, after U.S. President Donald Trump said force may be necessary to get OPEC's fourth-largest producer to abandon its nuclear program. "I'd love not to use it but sometimes you have to," Trump told reporters when asked whether he was considering the use of force, after three rounds of talks between U.S. and Iranian negotiators had failed to produce a nuclear deal. Multiple outlets had reported earlier that Trump was set to convene with senior advisors later in the day to discuss the potential of limited strikes on Iranian military and nuclear facilities. "We want no nuclear weapons by Iran and they're not saying those golden words," the president said when asked about this, adding that he was not happy with the situation, even if talks were to continue. Fears of an imminent strike on Iran have obscured the bearish fundamentals for crude arising from this week's inventory data from the U.S. Energy Information Administration. U.S. commercial crude oil inventories rose by 16 million bbl last week, registering their biggest weekly stockpile growth in three years. At Friday's close, NYMEX WTI crude for April delivery settled up $1.81, or 2.8%, at $67.02 bbl. WTI's session peak of $67.83 was the highest since August 1, when it hit $69.58. The U.S. crude benchmark rose 0.8% on the week, adding to the prior week's rise of 6%. The ICE Brent crude contract for April settled up $1.73, or 2.5%, at $72.48 bbl after an intraday peak of $73, the highest since July 31, when it reached $73.53. The global crude benchmark rose about 2% on the week, extending last week's 6% advance. Downstream, front-month RBOB futures climbed $0.0456 to $2.0779 gallon, while ULSD futures perked up by $0.058 to $2.6709 gallon. The U.S. Dollar Index slipped by 0.205 points to 97.535 against a basket of foreign currencies.

Oil prices rise more than 2% as US and Iran extend talks (Reuters) - Oil prices rose about 2% on Friday with traders bracing for supply disruptions as nuclear talks between the United States and Iran had yet to reach an agreement. Brent crude futures settled at $72.48 a barrel, up $1.73, or 2.45%. U.S. West Texas Intermediate crude finished at $67.02 a barrel, up $1.81, or 2.78%. The two sides agreed to extend indirect negotiations into next week but traders grew skeptical that an agreement between U.S. President Donald Trump's administration and Iran was possible. "The likelihood Iran is going to agree to what the Trump administration wants doesn't seem possible," "There's got to be an endgame to this and the market seems to think that's where we are headed." The Brent and WTI benchmarks were trading at their highest since July and August, respectively, and were poised to register weekly gains well above 1%. "Uncertainty prevails, fear is pushing prices higher today," said Tamas Varga, an oil analyst at brokerage PVM. "It is completely driven by the outcome of the Iranian nuclear talks and possible military action the U.S. might take against Iran." The United States and Iran held indirect talks in Geneva on Thursday after Trump ordered a military buildup in the region. Oil prices gained more than a dollar a barrel during the talks, on media reports indicating that discussions had stalled over U.S. insistence on zero enrichment of uranium by Iran. However, prices eased after the Omani mediator said the two sides had made progress. They plan to resume negotiations with technical-level discussions scheduled next week in Vienna, Omani Foreign Minister Sayyid Badr Albusaidi said on X. "We think the latest round of talks offers some hope on chances of a peaceful resolution, but military strikes are in no way out of the equation," . Trump said on February 19 that Iran must make a deal over its nuclear programme within 10 to 15 days or "really bad things" will happen. Geopolitical risk premiums of $8 to $10 a barrel have been built into oil prices on fears that a conflict will disrupt Middle East supply through the Strait of Hormuz, where about 20% of global oil supply passes, Sarkar said. To cushion the impact from a possible strike, UAE oil producer Abu Dhabi is set to export more of its flagship Murban crude in April, two trade sources said on Friday. Earlier this week, other sources said Saudi Arabia would also increase oil production. Additionally, Saudi Arabia may raise its April crude price to Asia for the first time in five months due to higher demand from India to replace Russian supplies, potentially raising it by about $1 a barrel. Producer group OPEC+, meanwhile, is likely to consider raising oil output by 137,000 barrels per day for April at its March 1 meeting, sources said, after suspending production increases in the first quarter.

Iran Rushes to Ship Oil Ahead of Possible U.S. Strike -Iran has tripled the rate of loading tankers in recent days as Tehran rushes to get its oil out of the Gulf ahead of potential further escalation of the tensions with the United States, according to vessel-tracking data. Crude oil exports from Iran’s key export hub on the Kharg Island soared to 20.1 million barrels during the period February 15 to 20, according to Kpler data cited byBloomberg. The rate of loadings at Kharg Island, which handles nearly all of Iran’s oil export volumes, was three times higher between February 15 and February 20, compared to the period January 15-20, for example. The loadings last week were equivalent to over 3 million barrels per day of crude oil, which is more than double Iran’s estimated typical export levels in recent years. The elevated rate of oil loadings in recent days suggests that Iran is bracing itself for a possible escalation of the U.S.-Iran tensions and could be preparing for some kind of U.S. military intervention, analysts say. In recent years, Iran has on several occasions rushed to ship oil out of Kharg Island at times of heightened tensions. For example, in October 2024, Iranian oil tankers moved away from Kharg Island amid fears of an imminent Israeli attack on the most important crude export infrastructure in Iran.During the June 2025 conflict with Israel, analysts did not rule out that Kharg Island—the crude terminal handling 90% of Iranian crude oil exports—could become a target of Israeli strikes. While Iran hastens to ship crude out of its waters, the U.S. continues to amass military forces in the region. The United States and Iran are holding a round of indirect talks in Geneva on Thursday—negotiations that analysts see as possibly the last chance of reaching a nuclear deal through diplomacy.

Saudi Arabia Boosting Oil Output In Anticipation of U.S. Attacks On Iran -Saudi Arabia has started to increase its oil output as part of a contingency plan in the event the United States attacks Iran and oil flows are disrupted, Reuters reported on Wednesday, as OPEC’s biggest oil producer positions itself as a "reliable supplier" looking to take up its traditional role as a key swing producer ready to stabilize the markets if a conflict occurs.U.S. President Donald Trump recently revealed that he is considering a "limited military strike" on Iran in a bid to pressure its leaders into a new nuclear agreement. Saudi crude shipments jumped to 7.3 million barrels per day (bpd) in the first 24 days of February 2026, the highest level since April 2023.The Kingdom is prepared to implement a short-term output hike specifically to offset potential supply losses from Iran or disruptions in the Strait of Hormuz, a critical chokepoint.Saudi Arabia can utilize its East-West Pipeline to the Red Sea to bypass potential Gulf blockades, though its spare capacity is currently limited to ~2.4 million bpd. Iran, which produces around 3.2 million barrels per day (approximately 3% of global oil), has warned that any U.S. or allied military strikes against its territory will trigger immediate and decisive retaliation. The ongoing tensions have raised significant concerns that Iran could attempt to disrupt shipping through the Strait of Hormuz, a critical bottleneck which handles 20-30% of global seaborne oil.The threat of disruption has increased the geopolitical risk premium on oil, with analysts warning that a conflict could lead to sharp price spikes similar to those that occurred four years ago when Russia invaded Ukraine.Saudi Arabia’s output hike comes at a time when OPEC+ is considering a resumption of its unwinding program. OPEC+ is likely to consider increasing oil output by 137,000 barrels per day for April 2026 when it meets on March 1, ending a three-month pause in hikes. The group paused its program for the first quarter of 2026 after steady increases of 137,000 bpd in Oct/Nov/Dec 2025 due to fears of oversupply.

Saudi Arabia Records Largest Budget Deficit Since 2020 --Saudi Arabia recorded its widest quarterly budget deficit in five years in the final three months of 2025, as lower crude oil prices weigh down the kingdom's finances, Bloomberg is reporting.Data released by the Saudi Ministry of Finance shows the government posted a deficit of 94.9 billion riyals ($25.3 billion) in the fourth quarter, which brought the total shortfall for 2025 to nearly 276.6 billion riyals ($73.73 billion), more than double the previous year's 115.6 billion riyals ($30.82 billion) deficit in 2024. The full-year deficit amounted to roughly 5.5 percent of gross domestic product.Non-oil revenue reached about 122.6 billion riyals ($32.68 billion) in the fourth quarter of 2025, while oil revenue fell to around 154.2 billion riyals ($41.10 billion), down from 170.8 billion riyals ($45.53 billion) in the same period a year earlier, according to Finance Ministry data.Saudi Arabia has been running budget deficits since late 2022, with Bloomberg Economics noting that the kingdom would need oil prices to average about $97 per barrel in 2025 to balance its budget.That figure rises to roughly $114 per barrel when domestic spending by the sovereign wealth fund is included. Meanwhile, Brent crude, the global benchmark for oil prices, is currently trading at around $71.This gap has prompted heavier borrowing on international bond markets, as well as major delays and downscaling of the Kingdom's large-scale megaprojects tied to the Saudi Vision 2030 program, championed by Crown Prince Mohammed bin Salman (MbS).Bloomberg reported in late January that Saudi authorities had begun pressing some of the kingdom's wealthiest families to inject additional capital into domestic ventures, as Vision 2030 megaprojects face scaling back or suspension.

US, Israel Launch War on Iran - The US and Israel have started an aggressive war against Iran, and Tehran has retaliated with strikes against Israel and American military bases in the Middle East. In a video posted to Truth Social early Saturday morning, President Donald Trump announced the beginning of military operations against Iran. Trump called on the Iranian people to rise up and seize power from their government. The President also stated that the war may result in American soldiers being killed. An Israeli official said the goal of the war is regime change in Tehran. “The goal is to create all the conditions for the overthrow of the Iranian regime. We are targeting all of Iran’s political and military leadership – past, present, and future.” They continued, “The developments also depend on the question of how much the Iranian people will rise up.”The Department of War has dubbed the attack on Iran Operation Epic Fury. US officials told Fox News that the strikes against Iran are expected to continue for days. Kann News reports that Israeli strikes targeted the top political leadership of Iran, including Supreme Leader Ayatollah Ali Khamenei and President Masoud Pezeshkian. Iranian state media has reported that Khamenei and Pezeshkian are unharmed. Trump said the US would completely destroy Iran’s missile program and navy. Iran has responded by attacking US military bases around the Middle East and Israel. Blasts have been reported in Kuwait, Bahrain, the UAE, Qatar, Jordan, and Israel. Explosions were reported at Popular Mobilization Forces (PMF) bases in Iraq. The Iraqi militias have ties with Iran. Kataib Hezbollah, an Iraqi Shia militia allied with Iran, said it would begin striking US bases in the region. Congress did not authorize Trump to go to war with Iran. The House was planning to vote next week on a War Powers Act resolution to prevent the President from starting an aggressive war. Trump ordered the bombing as US and Iranian negotiators were in the process of making a deal to avert war. On Friday, the Omani Foreign Minister, who is mediating the talks, said Tehran had agreed to significant concessions and a deal was possible.

Iran live updates: Trump says Khamenei dead; Iran has not confirmed - The United States and Israel launched a massive attack on Iranovernight Saturday, killing what Iranian media said was more than 200 people. "Our objective is to defend the American people by eliminating imminent threats from the Iranian regime, a vicious group of very hard, terrible people," President Donald Trump said in a video message. Trump later confirmed media reports, citing Israeli claims, that Iran's Supreme Leader Ali Khamenei was killed in airstrikes. He said in a Truth Social post: "Khamenei, one of the most evil people in History, is dead." Iran has not confirmed reports of the Supreme Leader's death. CNBC has not independently verified Khamenei's condition. Iran launched counterattacks against multiple cities in the Middle East, including Jerusalem. Explosions were heard around those cities. Both the U.S. House and Senate are poised to vote next week on a war powers resolution requiring Trump to get approval from Congress before the U.S. carries out further strikes in Iran — but it's unlikely the measure will pass. In the House, a few Republicans, including Kentucky Rep. Thomas Massie and Ohio Rep. Warren Davidson, have said they will vote to limit Trump's ability to further strike Iran, asserting Congress' power to declare war under the Constitution. "War requires Congressional authorization," Davidson said on X. Even if Massie and Warren vote to curb Trump's power, at least two House Democrats say they will back Trump's ability to fight Iran — Josh Gottheimer of New Jersey and Jared Moskowitz of Florida. In the Senate, Sen. Tim Kaine, D-Va., plans to force a vote on war powers against Iran this week. The Senate voted on a similar resolution in June to require Trump to seek approval from Congress before any strike. While Republican Sen. Rand Paul, R-Ky., joined nearly all Democrats in voting yes, the measure lacked the 51 votes needed to pass. Sen. John Fetterman, D-Pa., voted with Republicans to oppose the war powers resolution. Fetterman expressed his support for the latest strikes. The U.S.-Israel attack came after Iran refused American demands that it reduce its nuclear program.

Tehran strikes back at Gulf states after U.S.-Israel attack Iran - The U.S. military has begun "major combat operations" in Iran, U.S. President Donald Trump confirmed on Saturday, as Iranian missiles targeted several Middle Eastern cities."Our objective is to defend the American people by eliminating imminent threats from the Iranian regime, a vicious group of very hard, terrible people," Trump said in a video message on his Truth Social account.A U.S. official confirmed earlier that American forces attacked Iran by air and sea, Reuters reported. It also cited an unidentified Iranian official as saying that several ministries in the southern part of the Iranian capital, Tehran, were targeted. Israel also launched a Saturday attack on Iran's capital, with a cloud of smoke rising from the city's downtown. Explosions were heard in key cities around the Middle East, including Jerusalem, as Iran launched counterattacks. CNBC producer Joan Muwahed in Dubai reported hearing two explosions over the city in the United Arab Emirates.Qatar and the UAE condemned Iranian missile counterattacks."The State of Qatar expresses its strong condemnation of the targeting of Qatari territory with Iranian ballistic missiles, considering it a flagrant violation of its national sovereignty," Qatar's Ministry of Defense said in a statement.A UAE statement said: "the Ministry of Defense announced that the country was subjected today to a blatant attack by Iranian ballistic missiles, which was dealt with by the UAE air defenses with high efficiency and a number of missiles were successfully intercepted."The Israel Defense Forces said it had identified missiles launched from Iran toward Israel."Defensive systems are operating to intercept the threat. In the past few minutes, the Home Front Command has sent a precautionary directive directly to mobile phones in the relevant areas," the IDF said in a tweet.Elsewhere, Bahrain said the service center of the U.S. Fifth Fleet was subjected to a missile attack. The U.S. embassy in Bahrain's capital, Manama, issued a security alert warning of "imminent drone/missile attack in Bahrain". In a tweet, the embassy urged "U.S. citizens in Bahrain to shelter in place, review security plans in the event of an attack, and to stay alert in case of additional future attacks. U.S. Embassy personnel are sheltering in place."The U.S. embassy in Abu Dhabi, the capital of the United Arab Emirates, also issued a shelter-in-place alert.

Iran's revolutionary guards tell ships passage through Strait of Hormuz 'not allowed', EU naval mission official says (Reuters) - An official from the European Union's naval mission Aspides said on Saturday that vessels have been receiving VHF transmission from Iran's Revolutionary Guards saying "no ship is allowed to pass the Strait of Hormuz". The strait is the world's most vital oil export route, which connects the biggest Gulf oil producers, such as Saudi Arabia, Iran, Iraq and the United Arab Emirates, with the Gulf of Oman and the Arabian Sea. The official, who spoke to Reuters on condition of anonymity, said Iran had not formally confirmed any such order. Tehran has for years threatened to block the narrow waterway in retaliation for any attack on the Islamic Republic.

US calls on vessels to keep clear of Strait of Hormuz, surrounding waters amid military escalation - The US Department of Transportation's Maritime Administration on Saturday called on US-flagged commercial vessels to keep clear of the Strait of Hormuz and nearby waters amid the start of significant military escalation in the region. In a maritime alert issued, the department said military operations began on Feb. 28 in the Strait of Hormuz, the Persian Gulf, the Gulf of Oman and the Arabian Sea, warning of potential retaliatory strikes by Iranian forces. "It is recommended that vessels keep clear of this area if possible," the advisory said. It noted that "any U.S.-flagged, owned, or crewed commercial vessels that are operating in these areas should maintain a standoff of 30 nautical miles from U.S. military vessels to reduce the risk of being mistaken as a threat." The advisory, which is set to expire on March 7, also strongly encouraged ships to maintain close contact with Naval Forces Central Command's Naval Coordination and Guidance for Shipping and to review the latest advisories from the UK Maritime Trade Operations and the Joint Maritime Information Center. It further advised mariners to implement risk mitigation measures outlined in US Maritime Advisory 2026-001 concerning potential Iranian boarding, detention or seizure incidents in the Strait of Hormuz and Gulf of Oman. The advice comes after Israel and the US launched an attack against Iran early Saturday, citing alleged threats posed by the "Iranian regime." The attacks came as talks between Washington and Tehran over Iran's nuclear program had been ongoing under Oman’s mediation. A new round of talks in Geneva ended on Thursday.

Smotrich: 'In the End,' Israel Will Occupy Gaza and Establish Jewish Settlements - Israeli Finance Minister Bezalel Smotrich has once again vowed that there will eventually be Jewish settlements in Gaza, saying that “in the end,” Israel will fully occupy and settle the Palestinian territory, according to The Times of Israel.Smotrich, who also holds a minister position in the Israeli Defense Ministry, said that he expects the US to give Hamas an ultimatum in the “coming days” to disarm, and if the group doesn’t, Israel will restart its full-scale bombing campaign with the goal of conquering”Gaza with US support.“If [Hamas] does not comply, the IDF will receive international legitimacy and American backing to do it itself,” he said, adding that the demands for disarmament include “all AK-47 rifles, all small arms, and of course, all the tunnels and explosives.” Previous reporting said the US was considering a plan that would allow Hamas to keep some small arms.“One thing is certain: The IDF will enter and occupy Gaza if Hamas does not disarm,” Smotrich said. “In the end, Israel will occupy the Gaza Strip, implement a military government, and establish Jewish settlements there. It is impossible to run away from that because it is the truth.”The Israeli minister vowed again that Israel will fully occupy Gaza, saying it “doesn’t matter if it happens in a year, two years, or three years.” He was asked about President Trump’s “peace plan” for Gaza and the fact that Indonesia has said it’s committed troops to deploy to the Strip as part of the “International Stabilization Force,” which is supposed to replace IDF troops who are currently occupying more than 50% of Gaza.“If this happens, they will fold very quickly and allow the IDF to enter. This is coordinated with the Americans,” he said. “By the way, I don’t yet see them going in that fast.”

Russia to Tighten Budget Fiscal Rule as Oil and Gas Revenues Plunge -The Russian government is considering lowering the oil price level above which it sends the proceeds to its wealth fund as the Kremlin’s oil and gas revenues are plummeting with widening discounts and key buyers like India pulling out of the spot market. Under the so-called budget rule, Russia had a baseline price of $60 per barrel of oil for 2025. At prices above $60 per barrel for its oil, Moscow funnels excess revenue to its National Wealth Fund, a rainy-day reserves fund. However, when the price is below $60 per barrel – as Russia’s crude grades have been for months now – Russia taps into the fund to offset shortfalls in revenue from oil and gas exports. Despite the recent rise in international benchmark prices, Russia’s crude is selling at significantly lower levels, as discounts have widened in recent weeks. Russian crude is offered at discounts of more than $11 per barrel below Brent quotes for shipments to China, which has remained the main market for Russia’s oil following the massive withdrawal of Indian refiners. Russia now is rushing to save its revenues and budget amid plunging income from oil sales. “Oil and gas revenue really is falling [as a share of overall budget revenue]. We see this and the Russian government is thinking of tightening the fiscal rule by lowering the cut-off price to keep the National Wealth Fund intact and to ease pressure on the currency market,” Russian Finance Minister Anton Siluanov said. The government could make the decision to lower the price of oil in the budget rule within two weeks, the local Interfax news agency quoted the minister as saying. Last year, the government decided gradually reduce the cut-off price for oil in the fiscal rule by $1 each year, from $60 per barrel in 2025 to $55 by 2030. Officials are now considering slashing that price to as low as $45-$50 per barrel, sources with knowledge of the plans told Bloomberg, adding that the government could also cut the economic growth estimate for 2026 amid the major hit to oil revenues.

After Four Years of War, Zelensky Insists Victory Requires Ukraine Reclaiming All Territory Captured by Russia – Tuesday marks four years since Russia first launched its invasion of Ukraine, and, despite President Trump promising to end the war quickly, there’s no end in sight to the conflict as Russian and Ukrainian leadership haven’t budged on their core demands for a peace deal. Ukrainian President Volodymyr Zelensky reaffirmed in an interview with the BBCover the weekend that he wouldn’t cede the territory Ukraine still controls in the eastern Donbas region and defined “victory” as Ukraine regaining all of the land it has lost to Russia since February 2022. Ukraine ceding the Donbas is a key Russian demand to end the war, and President Trump has repeatedly called for Zelensky to do so, arguing that Ukraine will likely lose the territory in bloody battles in the coming months and years. When asked by the BBC interviewer if he thought it was a “reasonable request” for a ceasefire, Zelensky said he didn’t agree. “I see this differently. I don’t look at it simply as land. I see it as abandonment – weakening our positions, abandoning hundreds of thousands of our people who live there. That is how I see it. And I am sure that this ‘withdrawal’ would divide our society,” Zelensky said. When asked whether he still sought to regain all the land Ukraine has lost, Zelensky answered in the affirmative but suggested he needed more help from his Western backers to do so. “We’ll do it. That is absolutely clear. It is only a matter of time. To do it today would mean losing a huge number of people – millions of people – because the [Russian] army is large, and we understand the cost of such steps. You would not have enough people, you would be losing them. And what is land without people? Honestly, nothing,” Zelensky said. “And we also don’t have enough weapons. That depends not just on us, but on our partners. So as of now that’s not possible but returning to the just borders of 1991 without a doubt, is not only a victory, it’s justice. Ukraine’s victory is the preservation of our independence, and a victory of justice for the whole world is the return of all our lands,” he added. Another major sticking point in the negotiations is the issue of security guarantees. Zelensky and many European leaders want troops from NATO nations to deploy to Ukrainian territory with the backing of US airpower after a peace deal is signed, but Russian officials have repeatedly rejected the idea and made clear that the condition is a non-starter. Zelensky said in the BBC interview that he wants whatever security guarantee he gets from the US to last 30 years. He made the comments when asked about the Trump administration’s call for him to hold elections, saying that US security guarantees would need to be in place before that happened. Russian and Ukrainian officials held talks in Geneva last week, but there’s been no sign of progress. Russia maintains it won’t agree to a deal unless its key demands are met, which include Ukraine ceding the territory and guarantees on Ukraine not joining NATO, and has made clear it’s willing to continue the grinding war to achieve those goals.

Pakistani Military Says 274 Fighters Killed, Over 400 Wounded in Attacks on Afghanistan --Pakistan’s Defense Minister Khawaja Mohammad Asif declared Friday that a state of “open war” exists between Pakistan and the neighboring nation of Afghanistan, following ever-growing tensions and cross-border raids. Pakistan has reportedly pounded major cities in Afghanistan in the escalation of the conflict.The attacks reportedly centered on major military centers of the Taliban government in Afghanistan, and included significant attacks on the capital city of Kabul, causing explosions that fueled panic in the city and reportedly a soaring death toll.Pakistani military statements claimed at least 274 Afghan fighters had been killed in the strikes, and over 400 others were wounded. If confirmed, this is one of the single largest incidents of attacks on war-torn Afghanistan in decades. Pakistani officials also suggested that some 228 Taliban fighters had been killed in Kabul alone, while also confirming attacks on Paktia Province and the city of Kandahar.Fighting and exchanges of fire have been reported in the area around the Torkham Border Crossing, which lies along a highway that connects the Pakistani capital of Islamabad and the city of Peshawar to the Afghan city of Jalalabad and the capital of Kabul.Taliban statements reported the mobilization of a “battalion” of suicide bombers to fight Pakistan, and claimed to have launched attacks in Nangarhar leading to the death of some 55 Pakistani soldiers and the capture of 19 Pakistani military posts. Pakistan confirmed the Nangarhar fighting but denied the outcome, insisting they had sustained no casualties at all.Pakistan and the Taliban have been facing growing tensions in recent months, with long-standing disputes about the actual border between the two nations escalating amid allegations by Pakistan that the Taliban have been hosting Pakistani Islamist factions like the Tehreek-e Taliban Pakistan (TTP).In addition to tensions over the status of the TTP, Pakistani officials have accused the Taliban of serving as a proxy for regional rival India. India, for its part, issued a statement condemning the Pakistani attacks on Afghanistan The international community is calling for the two sides to settle their differences peacefully, with both Russia and China offering to mediate. Iran has similarly suggested they would be willing to provide whatever assistance possible to facilitate the talks.