US oil prices finished lower for the second time in three weeks on fears of a global supply glut after an expected OPEC output hike and on the restoration of Kurdish exports….after rising 4.9% to $65.72 a barrel last week on Trump’s threats of further restrictions on Russian oil exports, after a deal to restart a Kurdish oil export pipeline floundered, the contract price for the benchmark US light sweet crude for November delivery edged lower in early Asian trade on Monday, following the resumption of crude exports from Iraq’s Kurdistan region and growing expectations that OPEC+ would approve another production increase for November, then tumbled about 2% on Monday morning in New York, as traders looked ahead to the monthly OPEC meeting later in the week, where further production hike commitments were expected to add to oversupply concerns, and settled $2.27, or more than 3% lower at $63.45 a barrel, the sharpest one-day drop since June 24th, as OPEC+’s plans for another increase in oil output in November and the resumption of oil exports by Iraq's Kurdistan raised the global supply outlook…oil prices fell further on Tuesday morning as global markets assessed the impact of a Gaza peace plan announced by the US, and remained pressured during the US trading session by potential plans for a larger OPEC+ output increase next month, and by the resumption of oil exports from Iraq’s Kurdistan region via Turkey, and settled down $1.08, or 1.7%, at $62.37 a barrel, ahead of the anticipated production increase by OPEC+, as the resumption of oil exports from Iraq's Kurdistan region reinforced expectations of a supply surplus…oil prices recovered slightly in early Asian trading on Wednesday, as traders weighed the prospect of a larger OPEC+ output increase against signs of tighter U.S. crude inventories, but dipped modestly in early US trading, after the latest EIA data showed another weekly inventory increase across most oil products against expectations for continued declines, and settled down 59 cents at $61.78 a barrel amid the U.S. federal government shutdown that added to worries about the economy, and on expectations of an OPEC+ output increase in November…oil prices ticked upward on global commodities markets on Thursday after the Group of Seven (G7) industrialized nations unveiled fresh measures aimed at tightening restrictions on countries purchasing crude oil from Russia, but extended their decline into a fourth trading day in US trading as East Asian manufacturing indices showed the region's industrial sectors stagnating, while the U.S. federal government shutdown added to concerns over slowing demand growth, exacerbating the bearish sentiment, and settled $1.30 or 2.1% lower at a four month low of $60.48 a barrel largely due to concerns about oversupply in the market ahead of the OPEC+ group meeting over the weekend….oil prices stabilized on global markets on Friday, as traders were in a wait-and-see mode for what the OPEC+ Group of Eight would decide over the weekend, then rose by 1% during US trading following a fire at one of the biggest refineries on the U.S. West Coast, and settled 40 cents higher at $60.88 a barrel, after Baker Hughes reported producers cut oil rigs by 2 to 422, but still ended 7.4% lower for the week, the largest one week drop in over three months, as the expected increase in OPEC+ production and the Iraq/Kurdish pipeline beginning to flow after being shut in for two years kept sellers in crude..
meanwhile, natural gas prices finished higher for the fifth time in six weeks on short covering and on a smaller than expected injection into natural gas storage….after rising 0.5% to $3.206 per mmBTU last week as traders unwound short sale positions ahead of the October contract’s expiration at week’s end, the price of the benchmark natural gas contract for November delivery opened 3.8 cents lower on Monday, but reversed those overnight losses by 10:00 AM, as traders turned their attention to the seasonal shift from cooling demand to heating demand, then rallied to as high as $3.299 by 12:45 PM, before backing off to settle 6.1 cents higher at $3.267 per mmBTU as traders looked past bearish weather forecasts to record Gulf Coast LNG exports, still untouched by this year’s Atlantic storm season…November natural gas opened 6.8 cents higher on Tuesday, then trended cautiously lower as traders seemingly awaited the next market catalyst, but clung to its early gains and settled 3.6 cents higher at $3.303 per mmBTU, as traders weighed near-term mild weather against expectations for an eventual cooldown and stronger demand….natural gas prices started Wednesday 6.3 cents higher, as uncertainty surrounding the government shutdown sent prices higher, then rallied to an 11-week intraday high of $3.492 by 2:15 PM, before settling 17.3 cents, or 5.2% higher on the day at $3.476 per mmBTU, as gas output fell and traders covered short positions…natural gas prices opened higher Thursday and traded near $3.485 in the hour leading up to the weekly storage report, then surged upward to a fresh 11-week intraday high of $3.585 at 11:15AM on the news of a bearish injection, before arcing lower on profit taking to settle down 3.4 cents at $3.442 per mmBTU on forecasts for significantly less demand next week…natural gas prices drifted lower as trading got underway Friday, searching for a new floor as traders weighed a bullish storage print against stout overall supply and modest shoulder season demand, then trended lower through early afternoon trading amid plump supply readings and forecasts for benign weather, and settled 11.8 cents lower at $3.324 per mmBTU as traders ignored a pipeline-driven blip in supply and instead eyed lackluster demand outlooks for early October, but still finished 3.7% higher for the week…
The EIA’s natural gas storage report for the week ending September 26th indicated that the amount of working natural gas held in underground storage rose by 53 cubic feet to 3,561 billion cubic feet by the end of the week, which left our natural gas supplies 22 billion cubic feet, or 0.6% more than the 3,540 billion cubic feet of gas that were in storage on September 26th of last year, and 171 billion cubic feet, or 5.0% more than the five-year average of 3,390 billion cubic feet of natural gas that had typically been in working storage as of the 26th of September over the most recent five years….the 53 billion cubic foot injection into US natural gas storage for the cited week was notably less than the 68 billion cubic foot addition to storage that analysts had forecast in a Reuters poll ahead of the report, but was close to the 54 billion cubic foot of gas that were added to natural gas storage during the corresponding week of 2024, while it was far less than the average 85 billion cubic foot addition to natural gas storage that has been typical for the same late September 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 September 26th indicated that after relatively large decreases in our oil exports and our oil refining, we had surplus oil to add to our stored crude supplies for the eighteenth time in thirty-four weeks, and for the 35th time in sixty-four weeks, as oil supplies that the EIA could not account for were little changed….Our imports of crude oil fell by an average of 662,000 barrels per day to average 5,833,000 barrels per day, after rising by an average of 803,000 barrels per day over the prior week, while our exports of crude oil fell by an average of 735,000 barrels per day to 3,751,000 barrels per day, which, when used to offset our imports, meant that the net of our trade of oil worked out to 2,082,000 barrels of oil per day during the week ending September 26th, an average of 71,000 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 averaged 276,000 barrels per day, while during the same week, production of crude from US wells was 4,000 barrels per day higher than the prior week at 13,505,000 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 15,863,000 barrels per day during the September 26th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 16,168,000 barrels of crude per day during the week ending September 26th, an average of 306,000 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 362,000 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 storage, from net imports, from transfers, and from oilfield production during the week ending September 19th averaged a rounded 666,000 fewer barrels per day than what oil refineries reported they used during the week. To account for that difference between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a [+666,000 ] 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 an error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed.…since 637,000 barrels per day of oil supply could not be accounted for in the prior week’s EIA data, that means there was a 30,000 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....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 362,000 barrel per day average increase in our overall crude oil inventories came as an average of 256,000 barrels per day were being added to our commercially available stocks of crude oil, while 106,000 barrels per day were being added to our Strategic Petroleum Reserve, extending the string of nearly continuous additions to the SPR since September 2023, which followed nearly continuous SPR withdrawals over the 39 months prior to August 2023… Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports fell to 6,073,000 barrels per day last week, which was 7.5% less than the 6,568,000 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 4,000 barrels per day higher at 13,505,000 barrels per day as the EIA’s estimate of the output from wells in the lower 48 states was unchanged at 13,078,000 barrels per day, while Alaska’s oil production was 4,000 barrels per day higher at 427,000 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 3.1% higher than that of our pre-pandemic production peak, and was also 39.2% 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 91.4% of their capacity while processing those 16,168,000 barrels of crude per day during the week ending September 26th, down from the 93.0% utilization rate of a week earlier, and closer to the normal post-pandemic utilization rate for this time of year…. the 16,168,000 barrels of oil per day that were refined that week were 3.0% more than the 15,691,000 barrels of crude that were being processed daily during the week ending September 27th of 2024, and were 0.9% more than the 16,017,000 barrels that were being refined during the prepandemic week ending September 27th, 2019, when our refinery utilization rate was at 86.4%, which was on the low side of the pre-pandemic normal range for this time of year, likely due to catastrophic flooding in Southeast Texas in the wake of tropical storm Imelda of that year…
With the decrease in the amount of oil being refined this week, gasoline output from our refineries was also lower, decreasing by 363,000 barrels per day to 9,344,000 barrels per day during the week ending September 26th, after our refineries’ gasoline output had increased by 300,000 barrels per day during the prior week.. This week’s gasoline production was 2.7% less than the 9,602,000 barrels of gasoline that were being produced daily over the week ending September 27th of last year, and 7.3% less than the gasoline production of 10,081,000 barrels per day seen during the prepandemic week ending September 27th, 2019….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 25,000 barrels per day to 4,959,000 barrels per day, after our distillates output had increased by 29,000 barrels per day during the prior week. With this week’s modest production decrease, our distillates output was 3.4% more than the 4,794,000 barrels of distillates that were being produced daily during the week ending September 27th of 2024, and 3.0% more than the 4,813,000 barrels of distillates that were being produced daily during the pre-pandemic week ending September 27th, 2019....
Even with this week’s decrease in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 2nd time in eleven weeks and for the 9th time in thirty-one weeks, increasing by 4,125,000 barrels to 220,694,000 barrels during the week ending September 26th, after our gasoline inventories had fallen 1,081,000 barrels to a 42 week low during the prior week. Our gasoline supplies increased this week because the amount of gasoline supplied to US users fell by 441,000 barrels per day to 8,518,000 barrels per day, and because our imports of gasoline rose by 162,000 barrels per day to 668,000 barrels per day while our exports of gasoline rose by 18,000 barrels per day to 919,000 barrels per day… Even after twenty-four gasoline inventory withdrawals over the past thirty-four weeks, our gasoline supplies were only 0.2% below last September 27th’s gasoline inventories of 221,202,000 barrels, and were back to the five year average of our gasoline supplies for this time of the year…
Even with the decrease in this week’s distillates production, our supplies of distillate fuels rose for the 19th time in 39 weeks, increasing by 578,000 barrels to 123,577,000 barrels during the week ending September 26th, after our distillates supplies had decreased by 1,685,000 barrels during the prior week.. Our distillates supplies increased this week because the amount of distillates supplied to US markets, an indicator of domestic demand, fell by 121,000 barrels to 3,617,000 barrels per day, and because our exports of distillates fell by 178,000 barrels per day to 1,378,000 barrels per day, and because our imports of distillates rose by 49,000 barrels per day to 118,000 barrels per day... With 49 withdrawals from inventories over the past 87 weeks, our distillates supplies at the end of the week were 1.6% more than the 121,637,000 barrels of distillates that we had in storage on September 27th of 2024, while still about 6% 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 oil refining, our commercial supplies of crude oil in storage rose for the 13th time in twenty-six weeks, and for the 28th time over the past year, increasing by 1,792,000 barrels over the week, from 414,754,000 barrels on September 19th to 416,546,000 barrels on September 26th, after our commercial crude supplies had decreased by 607,000 barrels over the prior week… After this week’s increase, our commercial crude oil inventories were still 4% below the recent five-year average of commercial oil supplies for this time of year, while they were still about 26% above the average of our available crude oil stocks as of the last weekend of September 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, our commercial crude supplies have somewhat leveled off since, and as of this September 26th were just 0.1% less than the 416,546,000 barrels of oil left in commercial storage on September 27th of 2024, but were 0.6% above the 414,063,000 barrels of oil that we had in storage on September 29th of 2023, while they were 2.9% less than the 429,203,000 barrels of oil we had left in commercial storage on September 30th of 2022…
This Week’s Rig Count
The US rig count was unchanged over the week ending October 3rd, after rising each of the four prior weeks, as rigs targeting oil decreased by two, while the number of rigs targeting natural gas was up by one and miscellaneous rigs also increased by one…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 October 3rd, the second column shows the change in the number of working rigs between last week’s count (September 26th) and this week’s (October 3rd) count, the third column shows last week’s September 26th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend 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 4th of October, 2024…
+++++++++++++++++++++++++++++++++++++++++++++++++++++
Industry interested in horizontal well results - The Vindicator— One of the first new horizontal gas and oil wells to be drilled in Mahoning County in recent years has started to produce gas and oil at is well pad along state Route 45 (Salem-Warren Road) and Leffingwell Road west of Canfield. Karina Cheung, public information officer for the Ohio Department of Natural Resources, said the well was drilled in early May, and “hydraulic stimulation operations,” also known as hydraulic fracturing, took place between June 9 and June 15. The Wehr Spring Valley Farm well is now producing gas and oil, Cheung said. It is new enough that the latest ODNR oil and gas production report does not list the well’s production numbers. The report is for the first and second quarters of 2025, ending June 30. In February 2024, Guy Coviello, president and CEO of the Youngstown / Warren Regional Chamber, said he was excited to see gas and oil production moving north from the Steubenville area into Columbiana County and eventually the rest of the Mahoning Valley. “We see an increasing amount of opportunity, especially for Columbiana, Mahoning and eventually Trumbull County in the Utica play,” Coviello said. The Utica play is an area in eastern Ohio containing hydrocarbon-bearing rock formations under ground. “We have already experienced a lot of long-term success in the supply chain. Then there will be ancillary benefits in attracting companies here because of our abundance of energy, primarily natural gas,” Coviello said. The Mahoning Valley caught “shale fever” around 2012 when energy company BP leased 100,000 acres in Trumbull County and surrounding areas and drilled several wells. But the results were not what the company hoped for and pulled out of the Utica Shale play in 2014. But Utica wells in Columbiana County had a good year in 2023, producing its highest number ever, Coviello said. Coviello could not be reached for this story, but the Youngstown Business Journal reported earlier this year that horizontal wells in Columbiana County produced nearly 1.5 million barrels of oil in 2024, a production record in the northern tier of the Utica / Point Pleasant shale play. It cited data released by the Ohio Department of Natural Resources for those numbers. One high-producing Columbiana County township in 2024 was Butler, which is one township south of Mahoning County’s Goshen Township and two townships south of Ellsworth Township. Oil production in Mahoning and Trumbull counties in 2024 was negligible, the Business Journal reported. The new Ellsworth Township well is owned by EAP Ohio of Houston, formerly known as Encino Energy. It is called the Wehr Spring Valley Farm well, and it takes in 150.6 acres of land that heads southeast from the well pad, ending just north of West Western Reserve Road and just north of Green Township. Twenty landowners are listed as royalty interest holders. They have Canfield and Berlin Center addresses on Leffingwell Road, Salem-Warren Road and Western Reserve Road, according to ODNR documents. Their acreage makes up the area where the resources are being mined or will be mined about 15,000 feet below the surface. The new well is called a horizontal well because even though it is drilled vertically to begin with like traditional wells of the past, it also curves at some point deep underground and then runs horizontally to collect gas and oil along that zone. There are 12 producing horizontal gas and oil wells in Mahoning County, six in Poland Township, four in Jackson Township and now two in Ellsworth Township, according to ODNR. The Hilcorp Energy Co. wells in Poland all went into production in 2014, according to ODNR production data. The four in Jackson Township went into production in 2014 and 2015, as did the other Ellsworth well. The other Ellsworth Township horizontal well is just to the east of the Wehr Spring well and is owned by Northwood Energy Corp of Columbus. It began production in July 2014 and produced 506 barrels of oil and 632 thousand cubic feet of natural gas during the first two quarters of 2025. In Columbiana County, EAP has 87 producing horizontal wells, Hilcorp has 82 producing wells and Geopetro has eight. EAP Ohio received permission from ODNR to drill its Wehr Spring Valley Farm well May 1, 2025. The well was going to be 15,275 feet deep, according to ODNR documents. EAP Ohio applied for permission to drill the well April 4, 2025. At the time, the letterhead on the company’s application was for Encino Energy, and the well was being called Encino Energy Wehr Spring Valley Farm. Among the property owners who are royalty interest holders, the biggest appears to be Glenn L. Wehr Mineral Trust, which has 25 acres. The well pad appears to be on that property. One property is only 0.058 of an acre along Western Reserve Road. At the May 14, Ellsworth Township trustees meeting, township zoning inspector Wayne Sarna reported that an onsite visit had been made to the Wehr Spring Valley well site. The zoning report stated that Encino Energy would be providing the township with the company’s “registration application” as required under township regulations. The company was not going to have to apply for any permits through the township, the minutes state. Mike Chadsey, director of external affairs for the Ohio Oil and Gas Association, responded to a request for comment on the new Ellsworth well by explaining that the well is now owned by EOG Resources, which acquired EAP / Encino. When asked what significance anyone might place on the drilling of the new Ellsworth well, he said: “The significance for the Valley and Mahoning County is more about the results of the well than the fact that it was permitted and drilled.” He added that “there continues to be renewed interest in the northern part of the Utica Shale play which could be encouraging to the greater Mahoning County area.” He provided a spreadsheet that showed that 30 permits have been issued since 2011 for horizontal wells in Mahoning County. Many of them were never drilled or otherwise are not producing gas and oil, according to the ODNR database. Hilcorp received permits for 12 wells in Poland Township. Five permits were issued in 2011 in Goshen and Ellsworth Townships and the most recent one was in Milton Township in 2019. The detail in the ODNR database indicates that the Milton Township well was drilled in 2011 but had almost no production after 2012. There also were permits issued in Green and Beaver townships in 2012.
Request to Drill Under (Not On) OH's Jockey Hollow Wildlife Area - Marcellus Drilling News --In January 2023, Ohio House Bill (HB) 507 became law with the signature of Gov. Mike DeWine (see OH Gov. Signs Bill Expanding Drilling in State Parks, NatGas “Green”). The law allows shale drilling under (but not on top of) Ohio state-owned land, including state parks and wildlife areas. HB 507 encourages (pushes for) more drilling under state-owned land. The special commission created to award contracts — called the Ohio Oil & Gas Land Management Commission (OGLMC) — met in September 2023 to consider 12+ “nominations” (requests to drill) received (see Ohio Comm. Says 12.5% Royalties for State Land Drilling Too Cheap). Since that time, environmentalists have been apoplectic at the prospect of drilling under state-owned land with every new request. It's happening again with a request to drill under (not on) 1,460 acres of Jockey Hollow Wildlife Area in Belmont County.
Website Launches to Counter Objections to Marietta Injection Well -- Marcellus Drilling News ---The fight in Marietta, OH, over DeepRock Disposal Solutions’ plan to build a fifth shale wastewater injection well is getting heated. Opposition to the well has made for some very strange bedfellows. The Republican City Council is utilizing the legal services of the radicalized Earthjustice green group to challenge a permit issued by the Ohio Department of Natural Resources, which would allow the well in Marietta, OH (see Marietta, OH City Council Discusses Suing to Block Injection Well). The nonprofit Accountability Project Institute has just launched a website, InjectionWellFacts.com, to counteract what they say is a lack of information and outright misinformation being spread about the injection well.
Ohio State U. Gas-Fired Power Plant Completion Delayed Until 2026 - Marcellus Drilling News ---Ohio State University (OSU) is constructing two natural gas combustion turbine generators and one steam turbine generator with a maximum power generating capacity of 105.5 megawatts of electricity and 285 kilopounds per hour of steam. It’s being built on 1.35 acres at OSU’s main campus in Franklin County (see OH Approves Gas-Fired Power Plant for OSU – Antis Pledge to Fight). In 2021, as project construction began, a group of spoiled rotten children who are being “educated” at OSU instructed the university to stop construction or else (see Spoiled Kids Threaten OSU re NatGas Power Plant – Stop or Else). Construction continued, and the “or else” never materialized. The little snots are all talk and no action. However, here it is four years later, and the project is still not done.
Natural gas line struck in Beavercreek; Road reopened - WHIO-TV — The repairs for a gas line that was hit in Beavercreek this morning are expected to take hours. The natural gas line was hit on N. Fairfield Road around 11:20 a.m. CenterPoint Energy told News Center 7 that a third party hit the line.N. Fairfield Road was closed between Shakertown Road and Cedarwood Lane and reopened around 7:30 p.m.Beavercreek Police shared an update on social media early Thursday afternoon, saying that CenterPoint Energy is currently estimating the repairs to take up to 12 hours..“We were sitting and having breakfast, and I said to my husband, ‘God, what is that noise?’” Anita Retter said.Retter said her neighbor then called and told her a gas line had been hit. As reported on News Center 7 at 5:00, it wasn’t long after that that she could smell it.“The gas smell was horrendous,” she said.While her home was not one of the two to be evacuated by police, Retter and her husband decided to leave anyway.“We just felt better leaving,” she said.CenterPoint Energy sent the following statement to News Center 7 about the break:“This morning, a third-party unrelated to CenterPoint Energy caused damage to a natural gas pipeline near North Fairfield Road in Beavercreek. Out of an abundance of caution, two nearby homes were evacuated, electricity has been temporarily shut off in the area and North Fairfield Road has been closed as CenterPoint crews work closely with local authorities to make the area safe and stop the flow of natural gas. Motorists are advised to adhere to posted detour routes and exercise caution in the area. Safety is our top priority, and we urge customers in the area to be on alert for natural gas leaks. If you smell natural gas, leave the area immediately on foot and tell others to leave, too. Do not turn the lights on or off, smoke, strike a match, use a phone or operate anything that might cause a spark, including a flashlight or a generator. Once safely away from the area, call 911 and CenterPoint at 800-227-1376, and the company will send a trained service technician immediately."
Public Employees Retirement System of Ohio Decreases Holdings in TC Energy Corporation - Public Employees Retirement System of Ohio cut its holdings in shares of TC Energy Corporation (NYSE:TRP - Free Report) TSE: TRP by 40.2% during the 2nd quarter, according to its most recent Form 13F filing with the SEC. The institutional investor owned 154,552 shares of the pipeline company's stock after selling 104,092 shares during the quarter. Public Employees Retirement System of Ohio's holdings in TC Energy were worth $7,531,000 at the end of the most recent quarter. TC Energy Corporation (formerly TransCanada Corporation) operates as an energy infrastructure company in North America. It operates through five segments: Canadian Natural Gas Pipelines; U.S. Natural Gas Pipelines; Mexico Natural Gas Pipelines; Liquids Pipelines; and Power and Energy Solutions. The company builds and operates a network of 93,600 kilometers of natural gas pipelines, which transports natural gas from supply basins to local distribution companies, power generation plants, industrial facilities, interconnecting pipelines, LNG export terminals, and other businesses.
Public Employees Retirement System of Ohio Reduces Stock Holdings in Pembina Pipeline Corp - Public Employees Retirement System of Ohio reduced its stake in shares of Pembina Pipeline Corp. (NYSE:PBA - Free Report) TSE: PPL by 36.0% during the 2nd quarter, according to the company in its most recent 13F filing with the SEC. The firm owned 76,634 shares of the pipeline company's stock after selling 43,066 shares during the quarter. Public Employees Retirement System of Ohio's holdings in Pembina Pipeline were worth $2,872,000 as of its most recent filing with the SEC. Pembina Pipeline Corporation provides energy transportation and midstream services. It operates through three segments: Pipelines, Facilities, and Marketing & New Ventures. The Pipelines segment operates conventional, oil sands and heavy oil, and transmission assets with a transportation capacity of 2.9 millions of barrels of oil equivalent per day, the ground storage capacity of 10 millions of barrels, and rail terminalling capacity of approximately 105 thousands of barrels of oil equivalent per day serving markets and basins across North America.
Fortune 500 energy company to establish new division in Central Ohio with purchase of former Bob Evans HQ - Columbus Business First --The campus will house EOG Resources' new Columbus division, adding support for the company's Utica Shale asset development close to its operations in the region...The company will employ 150 people at the new division, which is being established following the $28.7 million acquisition of a large corporate campus in New Albany.
Cushman & Wakefield Brokers Sale of 170000 SF Office Campus in New Albany, Ohio — Cushman & Wakefield has brokered the sale of a 170,000-square-foot office campus located at 8111 Smith’s Mill Road in New Albany near Columbus. EOG Resources Inc., one of the largest crude oil and natural gas exploration and production companies in the United States, was the buyer. The campus will house EOG Resources’ new Columbus division, adding support for the company’s Utica Shale asset development close to its operations in the region. The LEED Gold-certified building offers office, training and lab facilities along with modern amenities. The company plans to open the new office later this year.
EOG Resources Establishing Utica HQ Near Columbus, OH; 150 Jobs - Marcellus Drilling News - In August, EOG Resources, one of the largest oil and gas drillers in the U.S. (with international operations in several other countries) and a Fortune 500 company, closed on the $5.6 billion purchase of Encino Energy, adding 675,000 net acres in the Utica and over 1,000 operating shale wells (see EOG Closes on $5.6B Purchase of Encino Assets in Ohio Utica). Before buying Encino, EOG owned approximately 460,000 acres in the Utica. Now, with over 1 million acres under management and active drilling operations, including five rigs and three completion crews working in Ohio, EOG needs a regional headquarters.
Ares Management to acquire Meade Pipeline for $1.1 billion - (Reuters) - Ares Management said on Monday its infrastructure funds have bought Meade Pipeline for about $1.1 billion, adding a key natural gas asset to its U.S. energy business as demand for power and gas surges. The investment management company is buying it from affiliates of XPLR Infrastructure, a leading independent power producer formed by NextEra Energy. The deal deepens Ares' bet on energy infrastructure as utilities and investors look to secure reliable supplies of lower-cost fuel to backstop intermittent renewables. "Driven by electrification, industrial activity and increasing LNG exports, we are witnessing tremendous growth in power and natural gas demand," said Steve Porto, partner at Ares Infrastructure Opportunities. Meade owns a 40% stake in the Central Penn Line, a 180-mile pipeline that carries gas from the Marcellus and Utica shale basins in Pennsylvania to demand centers in the U.S. Northeast, Mid-Atlantic and Southeast. Williams' Transcontinental Gas Pipe Line, or Transco, co-owns and operates the system under long-term leases. The Central Penn Line, which began operations in 2018, can move about 2.3 billion cubic feet per day, including capacity from its Leidy South expansion completed in 2022.
27 New Shale Well Permits Issued for PA-OH-WV Sep 22 – 28 -- Marcellus Drilling News -- For the week of September 22 – 29, the number of permits issued to drill new wells in the Marcellus/Utica increased from the previous week. There were 27 new permits issued across the three M-U states last week, up three from 24 issued two weeks ago. Pennsylvania issued 18 permits in four counties. Ohio issued nine permits, also in four counties. West Virginia got skunked last week, issuing zero new permits. ASCENT RESOURCES | BEAVER COUNTY | BELMONT COUNTY | CARROLL COUNTY | COTERRA ENERGY (CABOT O&G) | ENCINO ENERGY | EOG RESOURCES | EQT CORP | GREENE COUNTY (PA) | GUERNSEY COUNTY | JKLM ENERGY | NOBLE COUNTY | RANGE RESOURCES CORP |SUSQUEHANNA COUNTY | TIOGA COUNTY (PA) | WASHINGTON COUNTY
Infinity Natural Resources Increases Borrowing Base under its Credit Facility --Infinity Natural Resources, Inc. (“Infinity” or the “Company”) (NYSE: INR) announced today that its lenders increased the borrowing base under the Company’s credit agreement from $350 million to $375 million, effective October 1, 2025. This increase resulted from the regularly scheduled borrowing base redetermination and was supported by each of the lenders of the Company’s credit facility. As of June 30, 2025, the Company had $34.4 million of borrowings outstanding under its credit facility, providing $340.6 million of unused capacity on a pro forma basis for the increased borrowing base of $375 million. Infinity is a growth oriented, free cash flow generating, independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. Our operations are focused on the volatile oil window of the Utica Shale in eastern Ohio as well as our stacked dry gas assets in both the Marcellus and Utica Shales in southwestern Pennsylvania.
Energy Transfer starts maintenance work after jet fuel leak in Bucks County, Pennsylvania - -After months of frustration, a Bucks County, Pennsylvania, community is still searching for answers following a jet fuel leak that contaminated their well water. However, on Monday, Energy Transfer, the company behind the Sunoco pipeline, started maintenance work in the Glenwood Drive area as part of its ongoing pipeline inspection program. "Some people have been dealing with this since 2023," Joe Babiasz, a resident of Bucks County, said. For Babiasz and his family, life in this quiet Bucks County neighborhood used to feel peaceful — until a pipeline leak changed that. "People moved here because it's a nice, safe, quiet neighborhood, and you know some aspect of that has been taken away by the pipeline leak and the ongoing threat of pipeline leaks," Babiasz said. The September 2023 jet fuel leak from an underground pipeline has left many neighbors worried about long-term impacts to their water, soil and air. Since then, there have been ongoing meetings between Energy Transfer and residents. "In terms of day-to-day life, there's a lot more traffic," Babiasz said. "It's seems a little bit more industrial." Now, Energy Transfer plans to dig up a section of pipeline near Glenwood Drive as part of routine maintenance. The company says there's no safety risk and the work is precautionary after an inspection flagged an anomaly — a technical term for something unusual but not necessarily dangerous. "You know, whether or not this leak was fixed, I think people do have a general fear that this pipeline poses a threat to us in the present and future," Babiasz said. While crews prepare to dig and inspect the pipeline, Babiasz said not everyone in the neighborhood feels reassured. "There's mixed opinions across the neighborhood. Personally, I think this pipeline should be shut down until it can be proven to us that it's safe to operate," Babiasz said.
Second Leak of Drilling Mud During Pipeline Work in Bradford County - Marcellus Drilling News - On September 8, Blackhill Energy informed the Pennsylvania Department of Environmental Protection (DEP) of an “inadvertent return” that occurred during horizontal drilling for the Brad-Tenn Loop Pipeline in Granville Township, Bradford County (see Pipeline Work in Bradford County Leaks ~430 Barrels of Drilling Mud). Blackhill reported that while drilling beneath Route 6 and Sugar Creek, they experienced a pressure issue. The company discovered that 18,000 gallons of nontoxic bentonite drilling mud had been lost. On September 29, 2025, Blackhill notified the DEP of a second inadvertent return of bentonite drilling mud from horizontal drilling, this time in West Burlington Township in Bradford County.
PA DEP Seeks Paperwork on “Dump Lines” at EQT Well Sites -- Marcellus Drilling News - - On July 3, 2024, the Pennsylvania Department of Environmental Protection (DEP) issued an order to EQT asking the company to produce records as part of the agency’s ongoing investigation into the release of up to an estimated 940,000 gallons of wastewater at the Brova shale gas well pad in North Bethlehem Township, Washington County, and similar failures at six other EQT well pads. The issue revolves around the use of “dump lines” at well pads. EQT states that the DEP’s request for reviewing physical paperwork is onerous, and the agency lacks the authority to regulate dump lines anyway. The DEP wants to ensure that another dump line issue (spilling of wastewater) doesn’t happen.
Environmental Advocates Call On DEP To Reject Permit For A 4.5 GW Natural Gas Power Plant At The Homer City A.I. Data Center Complex In Indiana County -- On September 29, Citizens for Pennsylvania’s Future, Clean Air Council, Sierra Club, and Earthjustice submitted public comments to the Department of Environmental Protection calling on the agency to reconsider its draft approval of a proposed 4.5-gigawatt natural gas power plant in Indiana County – what would be the largest gas plant in the country. The Homer City Generation project would produce enough electricity for nearly 3 million homes, but instead would be used largely to power a 3,200 acre data center campus. The organizations warned that the project would significantly harm nearby communities while offering little economic benefit. If approved as is, the plant would release huge amounts of air pollutants – including ammonia, carbon monoxide, and particulate matter – that cause respiratory and other illnesses. Advocates said the project would emit three times more carbon dioxide than any other single facility in Pennsylvania, moving the state further away from meeting its climate targets under the state’s Climate Action Plan. At the same time, the project would provide little economic benefit to the community because both data centers and the gas plants that power them have been shown to create few jobs. Signatories also raised concerns about DEP’s handling of the application and any other agency regulatory actions regarding the project. DEP said it would act as a ‘concierge’ for companies behind the project, suggesting a troubling willingness to prioritize private industry over its responsibility to protect Pennsylvanians. They called on DEP to uphold its constitutional and statutory obligations and ensure that any future decisions comply fully with the state’s constitution and laws. “If it is built, this facility would be the largest source of carbon dioxide pollution in the Commonwealth – creating carbon pollution without creating commensurate benefits for Pennsylvanians. The Department must consider its obligations as a trustee of Pennsylvania’s public natural resources and deny this plan approval,” said Jessica O’Neill, managing attorney for litigation at PennFuture. “Approving an illegal project as deadly as this one would be a massive moral failure on the part of our state government. To heap insult upon injury, the thousands of deaths which would result from the tens of millions of tons of air pollution from this plant would not be in service of keeping the lights on at your home, but instead be for making profits for New York hedge funds and Silicon Valley billionaires. DEP can and must do better for Pennsylvanians,” said Alex Bomstein, executive director of the Clean Air Council. “Building this plant would lock in an egregious amount of climate pollution – it would be capable of emitting more greenhouse gases than all the cars in Pennsylvania," said Tom Schuster, director of the Sierra Club’s Pennsylvania Chapter. “It would be one thing if the power went to Pennsylvania homes and businesses, but instead it would mostly just fuel the tech billionaires’ AI bubble. Moving this project forward as planned would be reckless, unlawful, and an environmental disaster in the making.” “The Department of Environmental Protection says it wants to ‘concierge’ the permit for the largest gas plant in the nation,” said Charles McPhedran, an attorney with Earthjustice. “But DEP does not exist to serve gas plants. Its mission is to protect the public health of the citizens of the Commonwealth.”
Hochul draws heat for advancing Trump-backed gas pipelines - Environmental groups say New York Gov. Kathy Hochul is quietly smoothing the path for two gas pipeline projects President Donald Trump is pushing for in the state.The Hochul administration has said state officials will do an impartial review of the Constitution natural gas pipeline and the Northeast Supply Enhancement, or NESE, gas project. But activists coming together to fight them say the Democrat’s appointees are allowing shortcuts that violate environmental laws and procedures.“Why isn’t she following the law?” said Anne Marie Garti, a lawyer who has fought Constitution for years from her home in the Catskills, near the route of the proposed line. “That makes me suspicious.”State regulators said they are following the laws in their reviews of the pipelines. Williams Cos., the corporation behind both lines, said its projects undergo rigorous reviews.White House officials have bragged that Hochul “caved” under pressure from Trump earlier this year. They say she agreed to support the two pipelines in exchange for lifting the hold the administration put on construction of Empire Wind 1, a fully permitted wind energy project off the coast of New York.After that, Williams announced it was reviving its NESE and Constitution projects, which it had abandoned in the face of regulatory and political resistance. The growing criticism of Hochul shows that, while some of the hurdles are lower now, they haven’t disappeared. It also highlights the tricky choices Hochul faces as she seeks reelection next year — as well as resistance to energy projects in the Northeast even as Democratic governors take a friendlier stance. Hochul has denied making a pipeline-for-wind-farm deal with the president and has said she was already willing to support pipeline proposals if they are needed and comply with the law. But now that Trump is targeting wind projects off the coast of other states, it’s the activists in the Democratic base who are targeting Hochul.Hochul’s office referred a request for comment to her previous statements, such as an interview with Bloomberg this month where she said she focused on saving 1,500 jobs Empire Wind would bring. “But I also said, ‘I’m looking at an all-of-the-above approach to energy, so work with me,'” Hochul told Bloomberg, explaining her negotiations with Trump about Empire Wind.The White House did not respond to a question about whether officials there think Hochul’s administration is reviewing Williams’ pipeline projects swiftly enough. But White House spokesperson Taylor Rogers said in an email that only “self-interested activists would oppose streamlining reliable US natural gas flowing to help fellow Americans reduce their energy bills.”Constitution and NESE were two of at least five Northeastern gas pipeline proposals shredded by local opposition and environmental litigation during the Biden and first Trump administrations.The revival of Constitution and NESE has renewed the tug-of-war over how to power the Northeast, from wind turbines and other renewable sources to fossil fuels delivered by pipeline.Whether or not the governor made a deal with Trump, her moves suggest she’s not putting up any obstacles to the projects, which were previously stymied by state regulators during both her tenure and that of her predecessor, former Gov. Andrew Cuomo (D).
Hope Gas Moves to Put 1,000-Mile Pipeline Abandonment Plan on Hold (P&GJ) — Hope Gas asked the West Virginia Public Service Commission (PSC) in April to pause proceedings tied to its plan to abandon more than 1,000 miles of “Red Line” pipelines across 22 counties, according to The Dominion Post. In March, the company proposed abandoning more than 1,000 miles of pipeline across over 20 West Virginia counties, drawing sharp criticism from local producers who warned the move could cut off access to critical infrastructure and threaten small well operations.The company previously announced an agreement for Diversified Midstream to acquire the system but told regulators the deal was not yet finalized. Oil and gas producers voiced concerns that abandoning the network would cut off a critical outlet for moving gas from the region.Hope also noted it planned to file a new base-rate case later that month and said the PSC should wait for that filing before making decisions. Earlier in February, regulators had ruled that about 479 farm-tap customers could be converted to propane or electricity, but only if the PSC approved the pipeline abandonment.As reported by The Dominion Post, Hope argued that holding the proceedings in abeyance was in the best interest of all parties. The company also canceled planned town halls with affected customers until the PSC rules on its request.
DC Circuit backs FERC review of gas pipeline - An appeals court has dismissed claims that federal regulators failed to adequately weigh the risks of building a 32-mile gas pipeline to supply a Tennessee Valley Authority power plant. In a ruling Tuesday, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal Energy Regulatory Commission was in line with federal law when it found the project’s environmental effects would not be significant. The court’s majority relied heavily on the Supreme Court’s decision this summer in Seven County Infrastructure Coalition v. Eagle County, which found that agencies get considerable deference for their interpretation of the National Environmental Policy Act. The ruling also limited how far NEPA reviews could stray from effects within an agency’s jurisdiction or from effects close to the project itself. Judge Justin Walker, who wrote the majority opinion, said the 2025 Supreme Court ruling has changed the legal landscape, ending the period where courts had ordered expansive environmental reviews spanning hundreds or even thousands of pages.
Williams to Invest $3.1 Billion in Power Projects, Boosts 2025 Capital Spending (Reuters) — U.S. pipeline operator Williams Companies said on Oct. 1 it plans to invest about $3.1 billion in two projects to supply power to data centers. The move takes the total capital committed to such 'power innovation' projects to about $5 billion, the company said in a filing. Power consumption is expected to hit record highs in 2025 and 2026, driven by a surge in demand from data centers used for artificial intelligence technologies, according to the U.S. Energy Information Administration (EIA). This rising demand is prompting utilities to add billions to capital plans to upgrade the grid and related infrastructure. Williams on Oct. 1 said it would raise its 2025 capital spending plan by $875 million to between $3.45 billion and $3.75 billion. The Tulsa, Oklohoma-based company did not disclose the locations of the two projects in the filing. It expects the transaction to close in the first half of 2027.
Colonial Pipeline Restarts 5,500-Mile Fuel Network After Brief Outage - (Reuters) — Colonial Pipeline has restarted operations after taking the largest U.S. fuel conduit offline earlier on Oct. 2 for unplanned system maintenance, a company spokesperson confirmed. Reuters earlier reported Colonial's main fuel delivery lines had been offline since around 5 a.m. ET on Oct. 2, according to market sources. Colonial confirmed the outage and said it was informing customers that it expects to restart before noon ET. Colonial Pipeline moves over 2.5 million barrels per day of fuel across its 5,500-mile network stretching from the U.S. Gulf Coast to major consumption centers across the U.S. East Coast, according to its website. The company says its pipelines are responsible for transporting about 45% of all fuel consumed on the East Coast. In the past, prolonged outages, including one on the pipeline's main gasoline line earlier this year, have led to fuel shortages in some locations and caused prices to increase. However, Oct. 2's outage was not expected to have a price impact because it was brief, said Tom Kloza, analyst for consultancy Turner, Mason & Co. The timing of the outage, coinciding with most markets easing vapor pressure restrictions on gasoline for the winter, also dulls the impact of the interruption, Kloza said. The U.S. allows refiners to make and sell a more volatile blend of gasoline in the winter, compared to what is allowed in the summer, making the fuel cheaper.
Louisiana Gas Storage Project Wins FERC Approval, Advances Toward FID (P&GJ) — Black Bayou Gas Storage, LLC, a subsidiary of Black Bayou Energy Hub, has received a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission (FERC), clearing the way for construction of a major underground natural gas storage project in Cameron and Calcasieu Parishes, Louisiana. The project includes the development of four salt dome caverns with 34.7 Bcf of working capacity, capable of delivering up to 2.0 Bcf per day and injecting up to 1.6 Bcf per day. A 27-mile looped header pipeline will connect the site to 10 major interstate pipelines, positioning the facility as one of the Gulf Coast’s most interconnected storage hubs. The site sits within 25 miles of more than 30 Bcf/d of demand from current and planned LNG facilities. Initial operations for Caverns 1 and 2 are targeted for 2028, with Caverns 3 and 4 expected online by 2030. FERC’s approval followed an environmental review that found no significant impacts with mitigation measures. To advance the project, Mercuria has committed $50 million in structured capital, strengthening its role as a cornerstone investor. “Receiving FERC certification is a key inflection point for the Black Bayou Energy Hub,” said Boris Bystrov, managing director of investments at Mercuria. “Strategic infrastructure projects like this are essential to our broader mission of enhancing market efficiency and supporting the energy transition.” Black Bayou CEO Tad Lalande said the project is now advancing toward a final investment decision. “With strong partners and committed capital, this milestone strengthens our ability to execute at scale,” Lalande said. “We are positioning the project to meet the growing demands of LNG, power, and industrial customers across the Gulf Coast and beyond.”
Woodside’s 16.5 Mt/y Louisiana LNG Project Gains Turkish Support in HOA -Woodside Energy Group Ltd. is looking to place a significant portion of the capacity of the first phase of its Louisiana LNG export project under contract as a part of a tentative supply deal with Türkiye’s state-owned pipeline company. At A Glance:
- Botaş targets nine-year LNG contract
- Woodside would provide 5.8 Bcm
- Türkiye builds on Mercuria, Cheniere deals
U.S. LNG exports at new record in September on strong Louisiana shipments – U.S. LNG exports hit a record high in September at 9.4 million metric tons, up from a previous record 9.3 million metric tons in August, according to preliminary data from financial firm LSEG. The United States was the world's largest liquefied natural gas exporter in 2024, with Louisiana accounting for about 61% of total LNG shipments. Texas, the second biggest exporter, was the source of about 31% of the U.S. LNG shipped overseas in 2024. Weekly data compiled by Bloomberg shows 81 LNG tankers departed Louisiana export terminals between Sept. 3 and October 1, representing 67% of total U.S. shipments during the four-week period. The data shows 35 LNG tankers departed Texas export facilities during the same four weeks, while three shipments left terminals in Virginia and Georgia, according to Bloomberg. Cheniere Energy’s Sabine Pass facility in Cameron Parish, the world’s largest export terminal with capacity of 29.5 million tons per year, shipped 32 cargos in September. “Louisiana is leading the nation in LNG exports and it is crucial that our leaders continue to support the policies that have unleashed this dominance,” said Tommy Faucheux, president of the Louisiana Mid-Continent Oil & Gas Association. “Louisiana’s energy industry is revitalizing our state’s economy and creating the opportunities that will keep our kids here in Louisiana,” Faucheux said. Since taking office in January, President Donald Trump has advanced U.S. "energy dominance" through executive orders and policies that streamline the permitting process on LNG projects and reduce regulatory burdens on existing export facilities. Commonwealth's LNG facility in Cameron Parish, Louisiana, was authorized in February to export up to 1.21 billion cubic feet of natural gas per day to non-FTA countries and in August Venture Global's Calcasieu Pass LNG project was approved for an increase in liquefaction capacity from 12.0 to 12.4 million tons per year. In May, the DOE issued a final authorization to Sempra Energy’s Port Arthur LNG Phase 2 project that allows exports to countries that do not have free trade agreements with the United States. Trump has also taken actions to advance U.S. energy dominance through trade deals, such as such as a recent agreement with the European Union for the purchase of $750 billion of American energy products. Record overseas purchases of U.S. LNG in September was driven by strong sales to Europe and Asia, according to LSEG. Europe, the most popular destination for U.S. exports in September, received about 6.22 million metric tons, or about 66% of all LNG shipments from American ports. Asian nations received about 1.63 million metric tons in September, about 17% of total U.S. exports. Africa and Latin American nations received a combined 1.63 million metric tons in September, representing about 15% of U.S. LNG exports.
Vistra to Add 860 MW of New Gas-Fired Capacity at Permian Basin Plant (P&GJ) — Vistra Corp. said it will build two new natural gas-fired power units at its Permian Basin Power Plant, a move that more than triples the site’s generation capacity to 1,185 megawatts. The $1 billion investment decision marks a key step in Vistra’s multi-year plan to add more than 2,000 MW of new capacity in ERCOT by 2028. The new units, totaling 860 MW, will support rising electricity demand in West Texas, particularly from the oil and gas sector. “As the leading competitive generator in Texas, customers from residential to commercial and industrial are turning to Vistra to help them meet their energy needs,” said Jim Burke, president and CEO of Vistra. “We are uniquely positioned to deliver solutions that provide reliable, affordable power to our residential customers as well as industries across Texas and the United States to ensure our economic competitiveness and national security.” Texas Gov. Greg Abbott praised the project, calling it an investment that will “reinforce our state’s electric grid, spur jobs, and drive regional economic growth for years to come.” The Permian Basin expansion is part of a larger slate of projects. Since 2020, Vistra has added about 1,000 MW in Texas through gas fleet upgrades and new solar projects. Additional efforts include a 200-MW Oak Hill solar facility set to begin operations later this year and the planned conversion of the retiring Coleto Creek coal plant into a 630-MW gas plant. When completed, Vistra will have invested nearly $2 billion to add 3,100 MW of new generation capacity in Texas since 2020.
Targa to Build 500-Mile NGL Pipeline from Permian to Mont Belvieu (P&GJ) — Targa Resources said on Sept. 30 it will construct the 500-mile Speedway NGL Pipeline to move natural gas liquids from the Permian Basin to its fractionation and storage hub in Mont Belvieu, Texas. The 30-inch-diameter pipeline will launch with a capacity of 500,000 barrels per day, expandable to 1 million bpd. It is scheduled to enter service in the third quarter of 2027 at an estimated cost of $1.6 billion. Targa is also advancing its midstream buildout with the planned Yeti gas processing plant, a 275 MMcf/d facility in the Permian Delaware system, expected online in Q3 2027. Combined with other projects under construction, the company will add five Permian plants over the next two years, increasing inlet capacity by 1.4 Bcf/d. In addition, the company announced Buffalo Run, a project that includes a new 35-mile natural gas pipeline and a 55-mile conversion of an existing line to gas service. Buffalo Run will link Targa’s Midland and Delaware systems and, together with the previously announced Bull Run Extension, expand connectivity to multiple markets including Waha. The staged project is slated for completion in early 2028. CEO Matt Meloy said the Speedway pipeline is central to Targa’s long-term strategy. “Speedway is critical to the continued execution of our core integrated wellhead to water strategy, will generate attractive and growing fee-based cash flows, and will provide Targa with significant operating leverage once in service,” he said. With the addition of Speedway, Buffalo Run, and the Yeti plant, Targa raised its 2025 growth capital spending forecast to $3.3 billion.
US natgas prices hit 2-month high on contract expiry, more flows to LNG export plants — U.S. natural gas futures climbed about 2% to a two-month high on Monday with the start of a new, more expensive front-month, and as the amount of gas flowing to liquefied natural gas export plants increases. That increase came despite a rise in daily output, ample amounts of fuel in storage and forecasts for milder weather and less demand over the next two weeks than previously expected. On its first day as the front-month, gas futures for November delivery on the New York Mercantile Exchange rose 6.1 cents, or 1.9%, from where the November contract closed on Friday to settle at $3.267 per million British thermal units (mmBtu). In the cash market, prices at the Waha Hub in West Texas and the AECO Hub in Alberta remained in negative territory because pipelines in both regions were constrained by expected and unexpected maintenance work. For the Waha, that was the fourth day in a row and the 13th time this year that prices were in negative territory. For AECO, that was the fifth day in a row that prices were below zero, with each day setting a fresh record low, according to LSEG pricing data. In the tropics, the U.S. National Hurricane Center projected both Hurricane Humberto (between Bermuda and the Bahamas) and Tropical Storm Imelda (over the Bahamas) would move away from the U.S. East Coast as they head toward Bermuda and then into the open Atlantic Ocean over the next week. Meteorologists at AccuWeather said they expect Humberto to pull Imelda out to sea, reducing tropical rain and wind impacts in the southeast U.S. Financial firm LSEG said average gas output in the Lower 48 states fell to 107.5 billion cubic feet per day so far in September, down from a record monthly high of 108.3 bcfd in August. On a daily basis, however, output was on track to rise to a preliminary three-week high of 108.4 bcfd on Sunday. That compares with an all-time daily high of 109.7 bcfd on July 28. Preliminary data is often revised later in the day. Record output earlier this year allowed energy companies to inject more gas into storage than usual so far this summer. There was about 6% more gas in storage than normal for this time of year. Meteorologists forecast the weather will remain mostly warmer than normal through at least October 14. That late-season heat will likely reduce gas demand by cutting the amount of fuel used to heat homes and businesses by more than the amount of gas power generators burn to keep air conditioners humming. LSEG projected average gas demand in the Lower 48 states, including exports, would slide from 102.4 bcfd this week to 99.7 bcfd next week. Those forecasts were lower than LSEG's outlook on Friday. The average amount of gas flowing to the eight big U.S. LNG export plants held around 15.8 bcfd so far in September, the same as in August. That compares with a monthly record high of 16.0 bcfd in April. On a daily basis, feedgas to LNG export plants rose to a one-month high of 16.4 bcfd on Saturday as record amounts of gas flow to Venture Global LNG's VG 3.2-bcfd Plaquemines plant in Louisiana.
U.S. Natural Gas Futures Climb 5% as Output Drops, Waha Hub Still Negative -U.S. natural gas futures climbed 5% on Oct. 1 as output fell and traders covered short positions. Waha Hub prices stayed negative amid pipeline constraints, while LNG feedgas dropped to a six-week low. (Reuters) — U.S. natural gas futures jumped about 5% to a 10-week high on Oct. 1 on a drop in daily output and some likely technical short-covering. Prices rose despite a decline in daily gas flows to liquefied natural gas (LNG) export plants, ample amounts of fuel in storage and forecasts for mild weather and less demand over the next two weeks than previously expected. Front-month gas futures for November delivery on the New York Mercantile Exchange (NYMEX) rose 17.3 cents, or 5.2%, to settle at $3.476 per million British thermal units (MMBtu), their highest close since July 18. That kept the front-month in technically overbought territory for a third day in a row for the first time since February. Prices were also supported because some short sellers needed to cover their positions in recent days, analysts said, noting speculative short positions on the NYMEX reached a 10-month high last week. In the cash market, average prices at the Waha Hub in West Texas remained in negative territory for a sixth day in a row and a 15th time so far this year due to ongoing pipeline constraints in the region from expected and unexpected maintenance work. In the tropics, the U.S. National Hurricane Center projected that neither the remnants of Hurricane Humberto nor Hurricane Imelda would hit the U.S. East Coast as they moved east across the Atlantic Ocean. Imelda, however, was on track to hit Bermuda overnight on Oct. 1. Financial firm LSEG said average gas output in the Lower 48 states fell to 107.0 billion cubic feet per day so far in October, down from 107.4 Bcf/d in September and a record monthly high of 108.3 Bcf/d in August. Record output earlier this year allowed energy companies to inject more gas into storage than usual so far this summer. About 6% more gas was in storage than normal for this time of year. Meteorologists forecast the weather will remain mostly warmer than normal through at least Oct. 16. LSEG projected average gas demand in the Lower 48 states, including exports, would slide from 101.4 Bcf/d this week to 98.8 Bcf/d next week. Those forecasts were lower than LSEG's outlook on Sept. 30. The average amount of gas flowing to the eight big U.S. LNG export plants fell to a six-week low of 14.7 Bcf/d so far in October, down from 15.8 Bcf/d in September and a monthly record high of 16.0 Bcf/d in April. The primary reason for the LNG export feedgas decline was a drop in gas flows to Venture Global LNG's 1.6-Bcf/d Calcasieu plant in Louisiana from 1.7 Bcf/d on Sept. 30 to around 0.7 Bcf/d on Oct. 1. LNG plants can pull in more gas than they can turn into LNG because they use some of the fuel to power operations. Gas was trading around $11 per MMBtu at both the Dutch Title Transfer Facility benchmark in Europe and the Japan Korea Marker benchmark in Asia.
US LNG prices ease on profit-taking after hitting over two-month high --US natural gas futures fell on Thursday as traders booked profits, after prices hit a more than two-month high following a government report showing a smaller-than-expected storage build. Front-month gas futures for November delivery on the New York Mercantile Exchange fell by 3.4 cents, or about one per cent, to settle at $3.442 per million British thermal units (mmBtu). The contract hit its highest level since July 18 earlier in the session. The US Energy Information Administration said energy firms added 53 billion cubic feet (bcf) of gas into storage during the week ended September 26. That was smaller than the 68 bcf build analysts forecast in a Reuters poll and compared with a boost of 54 bcf during the same week a year ago and a five-year (2020-2024) average build of 85 bcf for this time of year. "The market definitely got a boost as the injection into inventory was much smaller than expected. It was a big miss...and I think what we're seeing here is that the demand for fuels was higher than expected last week," Meteorologists forecast the weather will remain mostly warmer than normal through at least October 16. The November contract is expected to find support around $3.40 and will likely trade within a range of $3.36 to $3.47, said Gary Cunningham, director of market research at Tradition Energy. Financial firm LSEG said average gas output in the Lower 48 states fell to 106.0 billion cubic feet per day (bcfd) so far in October, down from 107.4 bcfd in September and a record monthly high of 108.3 bcfd in August. LSEG projected average gas demand in the Lower 48 states, including exports, would drop from 101.5 bcfd this week to 99.2 bcfd next week. Meanwhile, US LNG exports hit a record in September at 9.4 million tonnes, beating their previous record of 9.3 million tonnes in August, according to preliminary data from LSEG. Demand for LNG as a marine fuel will at least double by 2030 as abundant supply and rising emissions regulations spur orders for ships that can run on it, industry executives said.
Execs Predict Where NatGas Price Will Land in Future | Rigzone -Executives from oil and gas firms have revealed where they expect the Henry Hub natural gas price to be at various points in the future in the third quarter Dallas Fed Energy Survey, which was released recently. The survey asked participants what they expect Henry Hub natural gas prices to be in six months, one year, two years, and five years. Executives from 121 oil and gas firms answered this question and gave a mean response of $3.35 per million British thermal units (MMBtu) for the six month mark, $3.53 per MMBtu for the one year mark, $3.94 per MMBtu for the two year mark, and $4.50 per MMBtu for the five year mark, the survey showed. Executives from 116 oil and gas firms answered this question in the second quarter Dallas Fed Energy Survey and gave a mean response of $3.66 per million British thermal units (MMBtu) for the six month mark, $3.81 per MMBtu for the one year mark, $4.12 per MMBtu for the two year mark, and $4.50 per MMBtu for the five year mark, that survey showed. In the first quarter Dallas Fed Energy Survey, executives from 117 oil and gas firms answered this question and gave a mean response of $3.71 per MMBtu for the six month mark, $3.98 per MMBtu for the year mark, $4.30 per MMBtu for the two year mark, and $4.83 per MMBtu for the five year mark, that survey showed. The third quarter Dallas Fed Energy Survey also asked participants what they expect the Henry Hub price to be at the end of this year. Executives from 133 oil and gas firms answered this question and gave an average response of $3.30 per MMBtu, the survey highlighted. The low forecast was $2.20 per MMBtu, the high forecast was $4.75 per MMBtu, and the average Henry Hub natural gas daily spot price during the survey was $2.99 per MMBtu, the survey pointed out. Executives from 133 oil and gas firms answered this question in the second quarter Dallas Fed Energy Survey and gave an average response of $3.66 per MMBtu, that survey highlighted. The low forecast was $1.75 per MMBtu, the high forecast was $5 per MMBtu, and the average Henry Hub natural gas daily spot price during the survey was $3.30 per MMBtu, that survey revealed. Executives from 127 oil and gas firms answered this question in the first quarter Dallas Fed Energy Survey and gave an average response of $3.78 per MMBtu, that survey showed. The low forecast came in at $2 per MMBtu, the high forecast was $5.25 per MMBtu, and the average Henry Hub natural gas daily spot price during the survey was $4.10 per MMBtu, that survey highlighted. An EBW Analytics Group report sent to Rigzone by the EBW team on Thursday highlighted that the November natural gas contract closed at $3.476 per MMBtu on Wednesday. This figure was up 17.3 cents, or 5.2 percent, from Tuesday’s close, the report outlined. In a report sent to Rigzone by the Standard Chartered team on October 1, Standard Chartered projected that the nearby future NYMEX basis Henry Hub U.S. natural gas price will average $3.35 per MMBtu in 2025, $3.30 per MMBtu in 2026, and $2.90 per MMBtu in 2027. In that report, Standard Chartered forecast that the commodity will average $3.20 per MMBtu in the fourth quarter of this year, $3.20 per MMBtu in the first quarter of 2026, $3.70 per MMBtu in the second quarter, $3.50 per MMBtu in the third quarter, and $2.80 per MMBtu in the fourth quarter. In a BMI report sent to Rigzone by the Fitch Group on October 3, BMI projected that the front month natural gas Henry Hub price will average $3.50 per MMBtu in 2025 and $3.80 per MMBtu in 2026.
Dallas Fed Survey Shows Oil and Gas Activity Decline | Rigzone - Activity in the oil and gas sector declined slightly in the third quarter of 2025, according to oil and gas executives responding to the Dallas Fed Energy Survey. That’s what the Federal Reserve Bank of Dallas stated recently on a Dallas Fed Energy Survey page on its website, adding that the business activity index - which it described as the survey’s broadest measure of the conditions energy firms face in the Eleventh District - remained negative, “but edged up from -8.1 in the second quarter to -6.5 in the third quarter”. “The company outlook index fell from -6.4 in the second quarter to -17.6, suggesting pessimism among firms. Meanwhile, the outlook uncertainty index remained elevated but edged down from 47.1 to 44.6,” the Dallas Fed noted on its site. “Oil and gas production declined slightly in the third quarter, according to executives at exploration and production firms. The oil production index remained negative and was relatively unchanged at -8.6 in the third quarter. Similarly, the natural gas production index was relatively unchanged at -3.2,” it continued. The Dallas Fed went on to state on its site that firms reported rising costs, with all series above their averages. “Among oilfield services firms, input costs rose but at a slightly slower pace than the previous quarter as the input cost index declined slightly from 40.0 to 34.8,” it highlighted. “Among E&P [exploration and production] firms, the finding and development costs index increased from 11.4 to 22.0. Also, the lease operating expenses index increased from 28.1 to 36.9,” it added. Oilfield services firms reported modest deterioration in nearly all indicators, the Dallas Fed noted on its site. “The equipment utilization index for oilfield services firms fell slightly from -4.6 to -13.0. The operating margin index was relatively unchanged at -31.8, indicating margins compressed at a similar rate,” it added. “Meanwhile, the prices received for services index declined slightly from -17.7 to -26.1,” it continued. The Dallas Fed also pointed out on its site that, “overall, demand for employees was relatively unchanged and hours worked was also little changed”. “The aggregate employment index advanced from -6.6 in the second quarter to -1.5 in the third. Additionally, the aggregate employee hours index was relatively unchanged at -3.7,” it added. “Meanwhile, the aggregate wages and benefits index was relatively unchanged at 11.5,” the Dallas Fed went on to note. ‘Variety of Issues’ In a ‘comments’ section of the Dallas Fed Energy Survey page, which the Dallas Fed has previously outlined shows comments from respondents’ completed surveys that have been edited for publication, one exploration and production firm said, “there are a variety of issues affecting our business”. “First, excess in the global oil market is restraining oil prices near term. Second, there is continued uncertainty from OPEC+ unwinding production cuts. Third, trade and tariff changes and the resulting geopolitical tensions,” that firm added. Another exploration and production firm said in the comments section, “day to day changes to energy policy is no way for us to win as a country”. “Investors (rightly) avoid investing in energy (of all types, now) because of the volatility of underlying business results as well as the ‘stroke of pen’ risk that the federal government wields as it relates to long duration energy developments,” it added. Another exploration and production company warned that “the oil industry is once again going to lose valuable employees”, while another said, “who wants to make a business decision in this unstable environment”. “The uncertainty from the administration’s policies has put a damper on all investment in the oilpatch,” one more exploration and production company warned, adding that “those who can are running for the exits”. One more exploration and production company said “the U.S. shale business is broken” and another pointed out that “commodity pricing seems impossible to predict with daily market swings over five percent up or down being normal for both natural gas and crude oil”. Also in the comments section, one oil and gas support services firm said, “tariffs continue to increase the cost of production”. Another oil and gas support services firm said, “a vibrant oilfield services sector is critical if and when the U.S. needs to ramp up production - right now we are bleeding”.
West Texas Gas Bottleneck Threatens AI Data Center Expansion (P&GJ) — West Texas holds vast natural gas reserves that could help power the wave of energy-hungry artificial intelligence data centers, but the region lacks the pipelines and generation facilities needed to deliver that electricity, according to AP News. Although the Permian Basin accounts for 40% of U.S. crude output, much of the gas produced alongside that oil has limited value without sufficient infrastructure to process and transmit it. “Meeting this unprecedented demand takes more than production alone,” Ed Longanecker, president of the Texas Independent Producers and Royalty Owners Association, said according to AP News. “It requires a strong network of pipelines and infrastructure to move natural gas efficiently and ensure reliable power for end users. In Texas, expanding this network has never been more important to keep pace with growth.” Analysts say this leaves the Permian at a disadvantage compared with the Eagle Ford and Haynesville shales, which are better positioned with stronger transmission systems, access to LNG hubs, and more robust fiber optic networks. Jason Jennaro, CEO of FrontierGen, said companies with high energy demands — from cryptocurrency miners to industrial developers — may favor those regions over West Texas. Jennaro, who authored a recent study on basin competitiveness, estimated the U.S. must add roughly 400 terawatts of generation capacity within five years to support AI growth. That figure, he noted, equals France’s annual power consumption. The Electric Reliability Council of Texas projects its grid could nearly double in size by 2030, with data centers and the oil and gas industry driving most of the demand. In the Permian, gas that surfaces with oil often becomes a financial liability rather than a resource. Earlier this year, some producers were paying other firms to take excess gas. Redirecting that supply to data centers could transform a cost burden into a revenue stream, as reported by AP News. To make that possible, the region would need not only new gas-fired power plants but also expanded pipeline capacity beyond the 6.5 billion cubic feet per day already moving through the system. Longanecker added that federal reforms to streamline pipeline permitting, which can stretch to seven years, are essential to unlock investment. Jennaro pointed to the state-backed Permian Basin Reliability Plan, scheduled for completion by 2030, as a promising step. “In our opinion, we are entering America’s Fourth Industrial Revolution,” he told AP News. “This revolution will be defined by the creation of large industrial nexus points where substantial amounts of electricity, transmission, natural gas, water, and fiber optics converge. Texas and its energy basins are a great place for this.”
TotalEnergies to Acquire Stake in Anadarko Gas Producing Assets | Rigzone - TotalEnergies SE has signed an agreement to buy a 49 percent stake in natural gas-producing assets operated by Continental Resources Inc on Oklahoma's side of the Anadarko basin. "These assets have the potential to reach a gross production of around 350 MMscfd by 2030 and to sustain this production level over the long term", TotalEnergies said in a statement on its website. "They will enable TotalEnergies to secure a net gas production of around 150 MMscfd". "This acquisition of low-cost and long-plateau assets, well connected to Henry Hub through existing midstream infrastructure, further strengthens TotalEnergies' integration across the liquefied natural gas value chain in the U.S.", TotalEnergies said. "This acquisition of non-operated shale gas assets complements the Dorado and Constellation acquisitions completed in 2024 in the Eagle Ford Basin", it said, adding it also operates a production of around 500 million standard cubic feet a day in the Barnett shale play in Texas. Last year TotalEnergies executed two Eagle Ford transactions with Lewis Energy Group LP. It intends to use its share of production from both acquisitions, which consisted of non-operating interests, in the producing Cameron liquefied natural gas (LNG) plant in Louisiana, in which it owns a 16.6 percent stake. The assets in the second of the two transactions with Lewis Energy can reach 400 million cubic feet a day (MMcfd) in gross production by 2028, TotalEnergies said in a statement September 27, 2024. The assets are in southwest Texas. In the earlier transaction, TotalEnergies took over Lewis Energy's 20 percent stake in the Dorado field. “Located in Texas, the Dorado field will allow TotalEnergies to increase its net U.S. natural gas production by 50 million cubic feet a day (MMcfd) in 2024, with the potential for an additional 50 MMcfd by 2028", TotalEnergies said April 8, 2024. The new Eagle Ford assets will supply Cameron LNG, a three-train facility with a capacity of 14.95 million metric tons per annum (MMtpa), an equivalent of 772 billion cubic feet a year of natural gas according to the Cameron LNG joint venture. TotalEnergies and its partners plan to add 6.75 MMtpa of capacity. Earlier this month TotalEnergies said it had signed agreements with NextDecade Corp raising its stake in Rio Grande LNG in Brownsville, Texas. TotalEnergies will take a 10 percent stake in the joint venture developing Train IV of Rio Grande LNG. "In addition to the 10 percent held directly, TotalEnergies will hold indirectly next to seven percent in this Train IV as a 17.1 percent shareholder of NextDecade", TotalEnergies said in a statement September 10. TotalEnergies already holds a 16.7 percent stake in the under-construction phase I, or trains I to III. According to a Department of Energy (DOE) order August 13, 2020, amending Rio Grande LNG's export permit, the facility's five trains each have a nominal capacity of 5.4 MMtpa. However, Houston, Texas-based developer NextDecade has said phase I would be capable of up to about 18 MMtpa. Announcing the FID for train IV on September 9, NextDecade said the newly approved train will grow Rio Grande LNG's capacity to around 24 MMtpa when the train starts production 2030. In total, Rio Grande LNG can export up to 1.32 trillion cubic feet a year of natural gas equivalent - 27 MMtpa of LNG from trains I to V - to FTA and non-FTA countries until 2050. DOE granted authorization through orders first issued - later amended - August 2016 for the portion for countries with a free trade agreement (FTA) with the U.S. and February 2020 for the non-FTA portion. TotalEnergies says it is the biggest exporter of U.S. LNG, with over 10 million metric tons exported from the country last year.
Gov. Landry urges swift cleanup after Roseland oil spill — Gov. Jeff Landry and other state and local leaders are providing an update on the cleanup efforts in Roseland. New drone video shows a large amount of oil in several lakes near the Smitty's explosion site. Gov. Landry posted to his social media Sunday, urging the recovery process to be fast-tracked. The explosion at Smitty's Supply happened roughly six weeks ago and sent millions of gallons of oil into the community. The Environmental Protection Agency (EPA) says nearly 79 million gallons of oily liquid have been picked up between the Tangipahoa River, the Smitty's site, and nearby ponds. The EPA is hosting office hours today at the Independence Public Library from 10 a.m. to 1 p.m. Tomorrow, they will be at the Amite City Hall and the Ponchatoula Library for those with questions for the agency or in need of guidance or assistance.
U.S. Gulf Coast Fuel Oil Imports Hit 25-Year High As Sanctions Change Flows -- Fuel oil imports into the U.S. Gulf Coast surged in September to the highest level in a quarter century, reflecting the impact of sanctions constrainingVenezuelan and Russian crude exports and forcing refiners to improvise with alternative feedstocks.Ship-tracking data from Kpler cited by Reuters show the Gulf Coast imported about 541,000 barrels per day of fuel oil last month, the strongest inflow since 2000. Refiners configured for heavy sour crudes are increasingly relying on residual fuel oil to keep coking units supplied.At the same time, crude imports into the Gulf fell to roughly 880,000 barrels per day, the lowest since late 2022. Domestic fuel oil inventories have tightened as well, dropping to just over 20.6 million barrels, levels well below pre-Ukraine war norms.The shortfall is being met by Middle Eastern producers, with Saudi Arabia, Kuwait, and Iraq redirecting cargoes to the U.S. freed up by a seasonal decline in their own power-burn demand. Reuters cited traders pointing to a notable increase in spot availability from the region, with some volumes also moving from Asia and North Africa.On Thursday, Hoa Nguyen of Sparta Commodities told Reuters that “there is way more availability of high-sulfur residuals right now, which the U.S. refining system is hungry for and which will help boost the diesel yield.” Another Gulf Coast refining source told Reuters that the trend is “driven by declining supplies of heavy crude, particularly from U.S.-sanctioned Venezuela”. The increase in imports comes as global fuel oil demand itself is rising, supported by longer tanker voyages around the Red Sea and a growing “shadow fleet” moving sanctioned barrels. These factors are feeding into the Gulf Coast shift, creating tighter links between global shipping markets and U.S. refinery operations.
U.S. drilling slows as high operating costs, low oil prices and capital restraint motivate operators --In the first half of 2025, U.S. oil and gas drilling slowed down, as companies cut back on the number of rigs, especially in major areas like the Permian and Eagle Ford. Oil prices were unpredictable, so operators focused on spending cautiously. Production levels stayed steady, thanks to technology improvements—such as drilling longer wells and using more advanced completion techniques—but companies chose to buy smaller rivals or assets (“bolt-on” deals), rather than spend heavily on brand-new drilling projects. Natural gas drilling was weaker, even though demand for U.S. LNG exports and related infrastructure continued to grow. At the same time, high equipment costs, supply chain delays, permitting hurdles, and some job cuts limited how much producers could increase activity, even with high-quality drilling prospects. . While many operators hoped for fast-tracked projects and more profitable margins under President Trump, decisions by the new presidential administration in first-half 2025 have presented both pros and cons for drillers. Early in the term, executive orders, such as Unleashing American Energy and Unleashing Alaska’s Extraordinary Resource Potential reversed several Biden-era restrictions, reopening federal leasing and expediting permitting. On the other hand, tariffs have presented hurdles, particularly for operators in the Permian basin, where high duties on steel and aluminum have increased costs for critical equipment and materials. Meanwhile, energy trade tensions — including tariffs on energy imports from Canada and Mexico — introduced uncertainty into supply chains and raised input costs for producers. On the regulatory front, proposals under Trump, such as ending mandatory greenhouse gas reporting and aggressively reducing environmental review timelines signal further shifts aimed at lowering compliance burdens for operators. Trump also established the National Energy Dominance Council, chaired by Secretary of the Interior Doug Burgum, Fig. 1. Collectively, these actions have sought to lower barriers and costs for drilling, production, and infrastructure development in 2025, but operational challenges, material price inflation and other external factors have created roadblocks. Internationally, several geopolitical factors have added uncertainty to the U.S. oil and gas market. Increased sanctions on Russian oil, ongoing Middle East tensions, global trade policies and a wave of production increases from OPEC+ have caused oil prices to swing. While this has influenced capex planning and hedging, U.S. operators have largely stayed disciplined, keeping drilling activity steady-to-lower.
US Oil, Gas Drillers Pause Amid Oil Price Drop -The total number of active drilling rigs for oil and gas in the United States stayed the same this week, according to new data that Baker Hughes published on Friday. The total rig count in the US stayed the same at 549 according to Baker Hughes, down 36 from this same time last year.The number of active oil rigs fell in the week, according to the data, to 422. Year over year, this represents a 57-rig decline. The number of gas rigs rose by 1 to 118 active rigs, which is 16 over this time last year. The miscellaneous rig count rose by 1 to 9.The latest EIA data showed that weekly U.S. crude oil production rose in the week ending September 26, from 13.501 million bpd to 13.505 million bpd. Average weekly oil production in the United States is now 57,000 barrel per day under where it was at the beginning of the year.Primary Vision’s Frac Spread Count, an estimate of the number of crews completing wells rose for week ending September 26 to 179—the fourth weekly rise. This is 17 crews above the four-year low. The Permian Basin fell by 2 to 251 this week, which is 53 rigs under year-ago levels. The count in the Eagle Ford stayed the same at 45, which is just 3 less than this same time last year. At 12:59 p.m. ET, the WTI benchmark was trading up $0.70 per barrel (+1.16%) on the day at $61.18, a figure that is $4.60 under the level from this time last week as the market waits for news of OPEC+’s production decision at their virtual meeting scheduled for this Sunday. The Brent benchmark was trading up $0.68 (+1.06%) on Friday at $64.79.
AXP Energy finds oil and gas across multiple zones in Oklahoma well - AXP Energy has confirmed hydrocarbons across several pay zones in its Charlie #1 well, located on the Edward Lease in Noble County, Oklahoma. The well reached total vertical depth of 4,725 ft on Sept. 22, and a full suite of wireline logs was successfully run before 5½-in. casing was set and cemented. The logs identified oil and gas shows in four key intervals: the Oswego Lime (3,776–3,806 ft), Mississippi Chat (4,293–4,317 ft), Mississippi Lime (4,403–4,623 ft) and Woodford Shale (4,623–4,662 ft). The Mississippi Lime showed the most extensive presence, with hydrocarbon indicators across 260 ft. Completion operations are now being designed, with staged hydraulic fracturing of the Mississippi Lime set to begin the week of Oct. 20, 2025. First production is expected by the end of the month. AXP Energy Managing Director and CEO Dan Lanskey said the company is focused on moving quickly to bring Charlie #1 into production. “We are working with our contractors to design a multi-stage frac job across key intervals of the Mississippi Lime. This well confirms the highly prospective nature of this formation across our lease holdings,” Lanskey said. The Edward Lease covers about 1,000 acres, with AXP holding 100% working interest and 81.25% net revenue interest. Additional wells are planned over the next 12 months to further appraise and develop the 300-ft-thick Mississippi Lime formation, which is laterally extensive across the region. The Charlie #1 well represents an important step in AXP’s ongoing strategy to expand its position in Oklahoma’s mature producing basins, leveraging modern completion techniques to maximize recoveries from historically productive formations.
U.S. Pipeline Company Fined for Massive Gasoline Spill in Walnut Creek, California -- A subsidiary of a major energy company will pay a six-figure penalty for spilling more than 40,000 gallons of gasoline from a pipeline in Walnut Creek, California, according to a settlement with the U.S. Environmental Protection Agency.SFPP, L.P., a subsidiary of Kinder Morgan, Inc., agreed to pay a $213,560 penalty to resolve claims of Clean Water Act violations following the 2021 spill. The gasoline discharge contaminated local soil and water, posing a significant threat to the environment.“Pipeline operators must be held accountable when they discharge gasoline into our environment,” said Amy Miller, EPA Pacific Southwest Region Enforcement and Compliance Assurance Director. “This enforcement action sends a clear message: companies must properly operate and maintain their pipelines to prevent spills.”EPA claimed SFPP discharged gasoline in quantities that could be harmful to the environment, breaching the federal law requiring companies that transport petroleum to properly operate and maintain their pipelines to prevent spills. If a spill does occur, the law mandates that companies contain it immediately to prevent environmental harm. Meanwhile, SFPP is conducting ongoing cleanup work to address the environmental impacts of the oil spill, a process coordinated with the Regional Water Quality Control Board. SFPP operates pipelines and terminals that transport refined petroleum products, natural gas, and other energy products across North America. The EPA emphasised that it takes its responsibility to protect communities and waterways from petroleum discharges seriously. The last settlement follows a similar incident in March 2023, when a group of international shipping companies, as well as their subsidiaries, agreed to pay Amplify Energy Corp. $96.5 million to settle the last lawsuit over a massive oil spill off the Southern California coast in October 2021.
Massive fire, explosion rock Chevron refinery in El Segundo - Los Angeles Times -An explosion and fire rocked a refinery in El Segundo on Thursday night, sending up massive flames that could be seen for miles. The city of El Segundo said there was no public threat or evacuation orders, even as several local fire departments continued to work to suppress flames at the major Chevron refinery, located just off the Pacific Coast Highway. By Friday morning, the fire had slowed considerably, but investigators were still trying to determine what caused it. No one was hurt, although the power of the blast rattled people in surrounding areas. As the sun rose Friday, a portion of the refinery still showed flames but there appeared to be little visible damage. Officials they were also monitoring air quality levels for pollution and dangerous contaminants. El Segundo officials called the fire contained as of 7 a.m. Friday, but said it was not fully extinguished. The blaze originated in a processing unit of the refinery. Videos taken when the explosion occurred around 9:30 p.m. showed a massive fireball erupt amid a loud, extended roar. But over the next hour, the blaze died down considerably and the skies largely cleared even while bright, strong flames continued to burn near the southern portion of Chevron’s plant. Chevron released a statement calling it an “isolated fire” and that “all refinery personnel and contractors have been accounted for and there are no injuries.” “No evacuation orders for area residents have been put in place by emergency response agencies monitoring the incident, and no exceedances have been detected by the facilities fence line monitoring system,” the statement said. Chevron did not offer updates on the amount of damage caused and whether the blaze would affect refinery operations. Thursday night, massive plumes of smoke and a neon orange hue spread across the sky, visible in El Segundo and other South Bay communities. The refinery has its own fire department, and other regional agencies assisted in the response. In north Redondo Beach, smoke billowed across a glowing sky. Traffic was diverted away from the scene while road closures were put in place along Rosecrans Avenue from Vista Del Mar to Pacific Coast Highway and along Pacific Coast Highway from Rosecrans Avenue to El Segundo Boulevard. Los Angeles Mayor Karen Bass and Gov. Gavin Newsom were each briefed on the incident Thursday night. Bass said there was no known impact to Los Angeles International Airport in a statement on X. The governor’s office said on X that it was coordinating with local and state agencies to protect the surrounding community and ensure public safety.Refinery fires are part of life in the South Bay, which is home to several major oil production facilities.In 2022, it took firefighters two hours to put out a fire at the El Segundo facility. In 2020, a fire at the Marathon Petroleum refinery in Carson sent flames at least 100 feet into the air and sparked hours of concern. But the fire was eventually gotten under control and did little major damage to refinery operations. The Chevron refinery is considered the largest on the West Coast. It remains unclear how the fire might impact the global oil market. Reuters reported that the overall market might not be hit but California gas prices could rise.
Fire at Chevron refinery sends massive flames shooting into Southern California night sky -A massive fire erupted at an oil refinery in Southern California Thursday night. Firefighters were dispatched around 9:35 p.m. to the Chevron refinery in El Segundo after receiving calls of smoke in the area, according to authorities. Billowing smoke and orange flames could be seen in the sky for miles across theSouth Bay Area. Fire Division Chief Casey Snow with the El Segundo Fire Department told Fox News Digital that some of the products – gasoline and diesel – were burning. Witnesses described the fiery scene as visible for miles. "So I saw the sky turn orange, and I was just wondering, like, what the h--- happened. What is that? And then I saw the whole explosion happen. It was just like a whole mushroom cloud of fire. It just started popping up," Miguel Morales, told Fox News Digital.Snow said crews contained the flames to the refinery and were focusing on preventing the fire from spreading."It’s contained to the Chevron refinery, so there’s no hazard to the adjacent cities or residents in El Segundo or Manhattan Beach," Snow said. "Units on scene are working to depressurize and isolate the incident and suppress the fire." He also noted that while it is a "waiting game" because of what's burning, there is no threat to residents in surrounding cities at this time."It’s just a waiting game right now because there’s residual gasoline and diesel that’s going to burn, and there’s not much we can do about it. We’re just keeping everything around it cool and trying to depressurize it, and eventually that gasoline will burn out and we’ll be in good shape," Snow said.He added that there are no injuries to report, which was also confirmed by a Chevron spokesperson."All refinery personnel and contractors have been accounted for and there are no injuries," Allison Cook said in a statement to Fox News Digital.She added, "No evacuation orders for area residents have been put in place by emergency response agencies monitoring the incident, and no exceedances have been detected by the facilities fence line monitoring system." The refinery is one of the largest on the West Coast and serves as a critical hub for the region’s fuel supply. It spans about 2 square miles and processes crude oil into jet fuel, gasoline and other petroleum products.
Cause of massive Chevron refinery fire in California still unknown | KTLA -A massive blaze that erupted and burned throughout the night at the Chevron refinery in El Segundo appears to be under control Friday morning, but the investigation into what caused the fire has yet to begin. Residents reported hearing an explosion, with some even saying that their houses shook when the fire broke out around 9:30 p.m. “It felt like an earthquake,” said resident Jax Nellor. Multiple fires could still be seen burning at the refinery as Sky5 was overhead at 4:30 a.m. on Friday. “It’s looking a bit better this morning, but they are still putting water on it,” KTLA’s Erin Myers reported. “Some smoke and some fire are still very active.” The City of El Segundo issued a statement Friday morning indicating that the fire was under control, but any investigation into the cause would have to wait. “The fire originated at a process unit at the southeast corner of the refinery. The fire is contained, but fire crews continue to work to fully extinguish the incident. Once the fire is safely extinguished, Chevron will launch an investigation to determine the cause,” a portion of the statement read. Thursday night, the massive fire at the refinery on 324 West El Segundo Boulevard sent flames so high that they were seen from Pepperdine University in Malibu, more than 20 miles away. The refinery’s fire department was able to prevent the flames from spreading to other parts of the facility by using water lines to douse the fire. Roads around the refinery were closed and shelter-in-place orders were given Thursday night, but they have all been lifted. No evacuation orders were issued. Officials recommend that residents keep doors and windows closed due to potential air quality issues, but as of early Friday morning, air quality in the area was still good. Los Angeles Mayor Karen Bass said she was monitoring the situation. Governor Gavin Newsom also released a statement on X, saying state officials were aware of the blaze. “Our office is coordinating in real time with local and state agencies to protect the surrounding community and ensure public safety,” the statement read. A refinery spokesperson has confirmed that all personnel have been accounted for and no injuries were reported.
US refinery fire incidents so far in 2025 (Reuters) - A fire broke out in a jet fuel unit at Chevron's 285,000 barrel-per-day El Segundo refinery near Los Angeles on Thursday, sending flames and smoke into the air. No injuries were reported and all workers at the refinery were accounted for, Chevron said in an email. The fire broke out in the refinery's Isomax 7 unit, which converts mid-distillate fuel oil into jet fuel, two sources said. Isomax 7 produces jet fuel along with the refinery’s two crude distillation units for Los Angeles International Airport (LAX). Chevron's second-biggest refinery in the United States, the El Segundo facility supplies a fifth of all motor vehicle fuels and 40% of the jet fuel consumed in southern California. In the U.S. so far in 2025, there have been several refinery fire incidents. Below are key details:
Phillips 66 to Take $100 Million Charge as It Idles Los Angeles Refinery, Retires Midstream Assets Phillips 66 will book $100 million in charges as it winds down its 139,000-bpd Los Angeles refinery by year-end, including $30 million tied to its midstream segment for retiring transportation assets. The refinery received its final crude shipment Sept. 30, with processing to end in mid-October. (Reuters) — U.S. oil refiner Phillips 66 expects to book about $100 million of charges to idle its 139,000-barrel-per-day Los Angeles-area refinery, which will cease operations by year-end, the company said on Oct. 1. These include around $70 million to mitigate groundwater contamination, and about $30 million for its midstream segment to retire transportation assets. "Several process units have been placed in an idle state. The remaining units will be idled in a phased manner through the end of 2025," the Houston-based company said. The refinery received its last waterborne crude on Sept. 30. The final crude processing date is expected to be in mid-October. Phillips 66 began winding down its Los Angeles refinery in September.
EIA Forecast Oil Price Falls Gas Price Rises Renewables Surge -The U.S. Energy Information Administration (EIA) has released its latest Short-Term Energy Outlook, projecting notable shifts in global energy markets through 2026. The independent report highlights declining oil and gasoline prices amid oversupply, rising natural gas costs, and robust growth in electricity demand—driven largely by renewables. The EIA forecasts a significant drop in global oil prices over the coming months, citing rising stockpiles as a primary driver. Brent crude, a key benchmark, averaged $68 per barrel in August 2025. Prices are projected to fall to around $59 per barrel in the final quarter of 2025 and hover near $50 per barrel in early 2026. The agency predicts an annual average of $68 for 2025, dropping to $51 in 2026. The decline is attributed to production outpacing demand. OPEC+ nations, including Saudi Arabia and Russia, plan output increases, adding to supply from non-OPEC producers such as the U.S., Brazil, Canada, and Guyana. Global oil inventories are expected to rise by 1.7 million barrels per day in 2025 and 1.6 million in 2026, with some oil potentially stored offshore—further weighing on prices. Global oil demand is projected to grow slowly, by 0.9 million barrels per day in 2025 and 1.3 million in 2026, mainly driven by Asia. However, geopolitical tensions, including the situation in Ukraine and trade disputes, could alter this outlook. U.S. crude production is forecast to peak at 13.4 million barrels per day in 2025, declining slightly to 13.3 million in 2026 as lower prices limit drilling activity. Lower oil prices are expected to ease costs at the pump. The average U.S. retail price for regular gasoline is projected to decline from $3.30 per gallon in 2024 to $3.10 in 2025 and $2.90 in 2026—the lowest annual average since before the pandemic, excluding the West Coast. As a share of disposable income, gasoline spending is forecast to drop below 2%, down from roughly 2.4% over the past decade, leaving more room for household expenses like groceries and leisure. Gasoline consumption is expected to rise slightly by 0.3% in 2026, reflecting updated Census data showing a larger working-age population and the incentive of lower fuel costs. Unlike oil, natural gas prices are set to rise. The Henry Hub benchmark averaged $2.91 per million British thermal units (MMBtu) in August 2025, lower than expected due to high production and reduced power-generation use. Prices are forecast to reach $3.70/MMBtu in late 2025, averaging $3.50 for the year, and climb to $4.30 in 2026. Rising costs are linked to steady U.S. production and growing demand, particularly from liquefied natural gas (LNG) exports. U.S. LNG shipments are projected to increase from 12 billion cubic feet per day (Bcf/d) in 2024 to 16 Bcf/d in 2026, supported by new facilities including Plaquemines Phase 2 and Corpus Christi Stage 3. Total U.S. natural gas consumption is expected to reach 91.4 Bcf/d in 2026, with the power sector remaining the largest consumer at 40%. Electricity consumption is accelerating, driven by data centers, industrial activity, and general usage. The EIA projects a 2.3% increase in 2025 and 3.0% in 2026, higher than previous estimates. Solar power will account for most of this growth, increasing renewables’ share of U.S. electricity from 23% in 2024 to 26% in 2026, while wind and hydropower contribute modestly. Natural gas remains the top source at 40%, though generation may fall 3% in 2025 due to higher prices. Coal sees a temporary 9% increase in 2025 before declining, while nuclear stays steady at 18–19%, supported by the restart of Michigan’s Palisades plant. The U.S. economy is forecast to expand 1.7% in 2025 and 2.4% in 2026, slightly higher than previous predictions. CO2 emissions from energy use are expected to rise 1.5% in 2025 due to increased coal burning, then fall 0.5% in 2026. Overall emissions are projected to remain flat compared to 2024. The EIA cautions that uncertainties—including OPEC+ policy decisions, weather events, and geopolitical tensions—could influence market dynamics. The outlook was finalized before OPEC+’s September 7 announcement of a minor production increase in October 2025, which may further affect prices. The report underscores a shifting energy landscape: consumers can anticipate cheaper fuels, while producers face challenges amid rising supply, evolving demand, and the growing influence of renewable energy.
Things Have Changed - Rebound in U.S. Crude Exports Driven By Shifts in Production, Imports, Refinery Runs - After setting an annual record of 4.1 MMb/d in 2024, U.S. crude exports started off this year relatively strong, but cracks soon began to show, with volumes falling all the way to 3.2 MMb/d in July, one of the weakest months since 2023. But just when it seemed the momentum was gone, Gulf Coast exports rebounded to near 3.9 MMb/d in August and are topping 4.1 MMb/d so far in September. In today’s RBN blog, we look at how shifts in production, imports and refinery runs have impacted U.S. crude exports. On paper, the math behind the U.S. supply/demand crude oil balance is straightforward: Production + Imports = Refinery Demand + Exports. Figure 1 below shows the U.S. balance in 2024 (left side) versus what we’ve seen so far, on average, in 2025 (right side). Every piece of this equation has been shifting under our feet in 2025, with a notable change in the export market — a critical factor in balancing trade. So what’s really going on and what contributes to these changes? Let’s take a tour through the pieces of the above supply/demand balance to see what’s changed since 2024. For the better part of a decade, U.S. shale was the growth story in global oil. But 2025 is showing us what happens when that engine starts to sputter. In 2024, U.S. production edged about 2% higher, averaging 13.2 MMb/d, with the Permian Basin continuing to shoulder most of the growth and offshore production from the Gulf of Mexico (GOM; see Take a Chance on Me) displacing some medium sour crude imports. By early 2025, production pushed up to around 13.5 MMb/d. But since then, things have leveled off. Efficiency gains that once delivered double-digit growth rates are harder to come by. Resource quality is slipping in some plays, capital discipline remains a priority for operators (see Here Comes the Rain Again), and service costs have stayed sticky. Despite continued increases in U.S. production the last few years, the rate of growth has been slowing as we near our 2025 year-to-date (YTD) average of 13.5 MMb/d. Imports are the other side of the supply picture, and here the story has shifted in a big way with the startup of Canada’s Trans Mountain Expansion (TMX). TMX, which came online in May 2024, nearly tripled the pipeline system’s capacity from 300 Mb/d to 890 Mb/d. That change gave Canadian producers something they’ve been chasing for years: direct marine access to the Pacific Coast. Suddenly, barrels that once had to flow south into the U.S. for re-export could head west straight to Asia (see Did You Ever Know That You’re My Hero?). That shift has real implications for U.S. markets. Canadian crude, especially Western Canadian Select (WCS), no longer needs to be priced at steep discounts just to move south to Gulf Coast refiners. And, because they now have a closer outlet, these barrels are less likely to flow down to the Gulf Coast to be placed on ships for re-export. With more direct access to tidewater, Canadian producers can compete directly in Asian markets (see Both Sides Now), sometimes undercutting U.S. barrels thanks to shorter shipping routes. For U.S. exporters, that means more competition abroad and, at times, fewer Canadian heavy barrels available on the Gulf Coast. The result? Narrower discounts for WCS and tighter margins for U.S. sellers. Crude isn’t just crude … the quality matters. Refiners pay close attention to API gravity and sulfur content (see The Weight), which broadly divide oils into light sweet and heavy sour grades. Light sweet crudes (like WTI, Eagle Ford and Brent) are simpler to refine, produce lots of gasoline, diesel and jet fuel, and generally trade at a premium. Heavy sour crudes (like WCS, Mexico’s Maya, Iraq’s Basrah Heavy and Venezuela’s Merey) are tougher to process, yield more residual products, and usually trade at a discount. The spread between light and heavy is representative of whether it’s more profitable to run light barrels (simpler, but usually more expensive) or heavy barrels (more complex, but often discounted). When heavy supply gets tighter, as it has been recently with less supply from Canada (TMX startup), Venezuela (sanctions; more on that below) and Mexico (production issues), refiners that have these grades as part of their diet bid up the price, narrowing the discount. The numbers tell the story. In June, WCS in the Gulf Coast averaged a discount of just $2.88/bbl to the NYMEX calendar-month average (CMA), a far cry from the $7.81/bbl discount a year earlier or the $14-$17/bbl range seen in early 2023. Within the last month, however, these spreads have started to widen out again (far right of blue line in Figure 2 below) but are still far from the previous levels seen in 2023-24. This narrower spread compared to 2024 has increased the attractiveness of light barrels to refiners in the Gulf Coast, leading to them running more light crude in the summer months than normal and reducing the number of barrels heading onto ships for export.
Analysts See Remote Chance of Winter LNG Market Tightness as Oversupply Extends Into 2026 - The continued easing of global price volatility and a consistent glut of U.S. cargoes available to fill European storage has pushed LNG freight rates to seasonal lows at the beginning of the heating season.Chart showing spot LNG vessel rates in USD per day as of September 30, 2025, from Fearnleys. Rates for 174k XDF/MEGI carriers are $23,000 West and $27,000 East. Rates for 155k–165k TFDE carriers are $12,000 West and $14,000 East. Rates for 138k–145k steam turbine carriers are $4,000 in both West and East. Pacific, Middle East, and Atlantic voyage parameters all include 100% fuel and 100% hire on ballast bonus to load port. At A Glance:
Spot LNG vessel rates hit seasonal low
U.S. LNG to Europe reaches 2.5 Mt
JKM, TTF spread narrows
Supply Disruptions, Weather and Geopolitical Tensions Loom Despite Stable Global Gas Prices — LNG Recap --European and Asian natural gas prices were trading in the same range they have been for the past month as the week got underway, and fundamentals remained largely unchanged on Monday. At A Glance:
TTF, JKM Stuck Near $11
Arctic LNG 2 cargoes adding to supply mix
French strikes disrupting LNG imports
Canada’s Cedar LNG Plans for Higher Capacity — The Offtake --A look at the global natural gas and LNG markets by the numbers
- 1.2 Bcf/d: FERC has approved a request from Caturus Energy LLC to begin site prep for the proposed 9.5 million tons/year (Mt/y) Commonwealth LNG terminal in Louisiana. Commonwealth is currently unsanctioned, but Caturus is one of a growing list of U.S. developers vying to be the fifth company to reach a final investment decision on a U.S. project this year. At peak operation, the facility could add roughly 1.2 Bcf/d in feed gas demand to the Gulf Coast market by early 2029.
- 36 trains: Venture Global Inc. has begun introducing nitrogen to Block 17 at its Plaquemines LNG facility after an order granted by the Federal Energy Regulatory Commission. The introduction of nitrogen is usually shortly followed by a request to introduce feed gas, launching early production activities. The block of two modular liquefaction trains is the final pair of Plaquemines’ 36 trains to begin commissioning. At peak capacity, the facility could create between 2.6-3.2 Bcf/d in feed gas demand for the Gulf Coast market.
- 10 Mt/y: A fourth midscale train at Cheniere Energy Inc.’s Corpus Christi Stage 3 expansion project has been undergoing startup activities, according to a filing with Texas environmental regulators. The Houston-based company told state officials flaring and other commissioning activities could last up to a year as crews bring the 0.626 Mt/y capacity train online. Once complete, all seven trains of Stage 3 would increase export capacity at Corpus Christi LNG by 10 Mt/y.
- 500 MMcf/d: Cedar LNG Partners LP disclosed it is planning to seek federal approval from Canadian energy regulators to upsize the capacity of its proposed LNG export project in British Columbia to 500 MMcf/d. The project partners, led by the Haisla Nation and Pembina Pipeline Corp., were originally approved to export 400 MMcf/d. The floating LNG unit currently under construction in South Korea could add around 3.8 Mt/y in export capacity to Canada’s growing BC LNG hub by 2028.
MidOcean to Acquire 20% Stake in PETRONAS’ Canadian LNG Assets (P&GJ) — MidOcean Energy, an LNG company managed by EIG, has agreed to acquire a 20% interest in PETRONAS’ Canadian upstream and LNG assets. The deal includes stakes in the North Montney Upstream Joint Venture (NMJV) and the North Montney LNG Limited Partnership (NMLLP), which holds PETRONAS’ 25% share in the LNG Canada project. LNG Canada, the country’s first LNG export terminal, shipped its first cargo earlier this year and is considered a cornerstone project for supplying Asian markets at competitive costs. The NMJV spans more than 800,000 gross acres and holds an estimated 53 trillion cubic feet of reserves and contingent resources. Upon closing, MidOcean will gain exposure across the LNG value chain, from upstream development in the North Montney to liquefaction and export through LNG Canada. The deal also secures MidOcean about 0.7 MTPA of LNG offtake, with growth potential if LNG Canada moves ahead with a second phase. “This transaction marks an important milestone in MidOcean’s growth journey,” said R. Blair Thomas, MidOcean Chairman and EIG CEO. “We are proud to join PETRONAS in its efforts to deliver reliable, low-cost LNG to global markets.” De la Rey Venter, CEO of MidOcean, added: “This investment is a clear reflection of our conviction in the future of LNG and its long-term role to help deliver global energy security and to underpin a practical and affordable energy transition.” The transaction is expected to close in the fourth quarter of 2025, pending regulatory approvals.
MidOcean Secures LNG Canada, Montney Positions in Petronas Deal - MidOcean Energy LLC said Tuesday it would acquire an indirect stake in the LNG Canada export terminal for an undisclosed amount as part of a broader agreement with Malaysia’s Petroliam Nasional Berhad, or Petronas.
Map of Western Canada highlighting natural gas pipelines and LNG facilities, including operational, under construction, and proposed export terminals. Key shale plays such as Montney and Duvernay in Alberta and British Columbia are shown, along with major hubs like Westcoast Station 2, NOVA/AECO C, Kingsgate, and Northwest Sumas. The map uses colored lines to distinguish operational and proposed pipelines, and symbols to mark LNG facilities and price index locations.At A Glance:
Agreement includes 700,000 tons of offtake
Potential for more if phase 2 sanctioned
MidOcean to gain Canadian upstream exposure
KKR Weighs $7 Billion Sale of 40% Stake in Pembina Gas Infrastructure --The Canadian midstream operator controls key natural gas and NGL processing, storage and transportation assets in the Montney and Duvernay regions. (Reuters) — KKR is exploring a potential sale of its 40% stake in Pembina Gas Infrastructure, with its holding in the Canadian midstream operator expected to be valued at around $7 billion, four people familiar with the matter said on Oct. 1. Pembina Gas Infrastructure was formed in 2022 as a joint venture between the investment firm and Pembina Pipeline Corp., and owns natural gas and natural gas liquids transportation, processing and storage infrastructure in western Canada. KKR has been working with investment bankers at Scotiabank in recent weeks to solicit potential buyer interest in the stake, said the sources, who cautioned that no sale was guaranteed and spoke on condition of anonymity to discuss confidential information. KKR and Scotiabank declined comment. Pembina Pipeline did not respond to comment requests. The KKR stake in Pembina Gas Infrastructure is expected to attract interest from other alternative asset managers and infrastructure funds, the sources said. Such buyers are drawn to minority stakes in such assets because they can pocket steady returns from the revenues earned without needing operational knowledge. Opportunities to own substantial stakes in large-scale Canadian pipeline assets are rare, which gives the Pembina Gas stake additional scarcity value, the sources added. Deal activity has remained strong for the Canadian energy sector this year, gaining attention from investors as companies seek to consolidate and build scale on growing demand for infrastructure and energy projects to meet rising energy needs. When Pembina Gas was formed, the parties said the venture was worth around C$11.4 billion ($8.17 billion) in total, meaning an exit for KKR at the mooted price would be significantly profitable for the investment firm. Since formation, Pembina Gas has grown through bringing built projects online and acquiring further assets. Pembina Gas has capacity to process around 5 billion cubic feet per day of natural gas, with assets within both the Montney and Duvernay shale formations, according to its website.
Shell Prepares to Double Output Capacity at LNG Canada Project -Shell is preparing to start production of liquefied natural gas from the second train at its installation in British Columbia, set to boost the total output from the facility by 6.5 million tons. The news comes as unnamed sources told Reuters this week that Shell and its partners at LNG Canada were still having trouble ramping up output from the first train of the facility. Train 1 has been having technical difficulties since June, the Reuters sources told the publication, which has meant it was operating at less than half of its capacity, which is also 6.5 million tons annually. The publication cited an LNG Canada spokesman as saying that the 14th cargo to set off from the facility had been loaded in September and in a few days another one would depart from Kitimat. Reuters reported that the September export total from LNG Canada was estimated at 300,000 tons, per LSEG data, down from 400,000 tons in August. LNG Canada’s peak capacity is planned at 14 million tons of liquefied gas per year. Backed by Shell, Petronas, PetroChina, Mitsubishi, and Kogas, LNG Canada is expected to redirect a portion of Canadian gas exports—currently flowing almost entirely to the U.S.—toward global markets. The price tag of the project is $40 billion. Construction of the first train took seven years. The first cargo set off from Kitimat in June this year. The project is a joint venture between Shell, with 40%, Malaysia’s Petronas with 25%, Mitsubishi Corp. with 15%, Korea Gas Corp. with 5%, and PetroChina with 15%. The facility will process 1.9 billion cubic feet of natural gas per day—a significant chunk of Canada’s output. Meanwhile, another LNG project is moving slowly to construction. The Ksi Lisims project received an environmental assessment certificate earlier this year from the government of British Columbia, and it has also received approval from the federal government of Canada.
Shell-Led LNG Canada Begins Train 2 Startup Amid Ongoing Issues at Train 1 - -The $40 billion project, North America’s first West Coast LNG export facility, is struggling to ease Western Canada’s gas glut as pipeline congestion and storage levels weigh on prices. (Reuters) — Shell-led LNG Canada has begun the process of starting up its second 6.5 million tonnes per annum (mtpa) liquefied natural gas processing unit known as Train 2 in Kitimat, British Columbia, a company spokesperson told Reuters on Thursday. The startup of Train 2, however, is happening as the company continues to experience technical problems at Train 1, according to two people with knowledge of its operations. The train was reported by sources to have technical issues in July, a month after it had started first production. LNG Canada is the first major LNG export facility in Canada, and the first on the west coast of North America that provides direct access to Asia, the world's largest LNG market. The facility took almost seven years to be built and has been operating at less than half its stated capacity, the people said. "We have had to swap out the supercore, and while string 2 is running, string 1 is down," one of the two people told Reuters. When asked about the technical issues, the company spokesperson pointed to ongoing export activity at the terminal and said flaring that started on September 11 had ended. "A 14th cargo departed the LNG Canada facility on September 30. A 15th cargo is expected to depart in the coming days," the spokesperson said. In September, LNG Canada exported less of the superchilled gas than the month before, with only four cargoes leaving the port for a total export of just under 0.3 million metric tons compared with the 0.4 million tons it sold in August, according to preliminary ship tracking data from financial firm LSEG. When fully operational, the facility is expected to convert about 2 billion cubic feet of gas per day (Bcf/d) to LNG, which market participants have hoped will boost Canadian natural gas prices.The slow ramp-up of LNG Canada, however, has contributed to daily spot prices slumping to record lows last week, as it has failed so far to drain a gas glut that built in anticipation of increasing demand from the plant, causing pipeline congestion. Gas storage in Western Canada remains at last year's record highs, according to investment bank Jefferies, and Reuters reported last week that some gas producers are aggressively cutting output in an effort to ease an ongoing glut. LNG Canada is a joint venture between Shell, Malaysia's Petronas, PetroChina, Japan's Mitsubishi Corp., and South Korea's KOGAS. On Sept. 30, MidOcean - an LNG company backed by EIG and Saudi Aramco - announced a plan to buy a fifth of the Petronas venture that holds a 25% share of LNG Canada.
Alberta to Seek Federal Fast-Track for New Oil Pipeline to British Columbia Coast (Reuters) — Alberta announced on Oct. 1 it will submit by spring of 2026 an application for a new crude oil pipeline for fast-track approval by the federal government, even without a private company to build the project. Canada's main oil-producing province said it will act as the formal proponent for the proposal, taking the lead on early planning and engineering work aimed at determining the route, size and cost of a pipeline. Alberta's government said the proposed pipeline could carry up to 1 million barrels per day of crude to British Columbia's northwest coast for export. It will invest C$14 million ($10.04 million) to develop a credible proposal for federal consideration, and will work with Canadian pipeline companies Enbridge, South Bow and government-owned Trans Mountain, which have agreed to provide advice and technical support, Alberta said. None of the companies have committed to building the pipeline or investing in such a project, and Alberta Deputy Energy Minister Larry Kaumeyer told reporters Wednesday the government has no intention of building or owning a pipeline. The companies did not immediately respond to requests for comment. "The objective of the Alberta government is to get it to the starting gate," Kaumeyer said, adding that in spite of growing Canadian oil production, no private sector company is willing to take the risk of proposing a pipeline project. In recent years, major Canadian oil pipelines have faced years of regulatory delay and legal challenges, leading to cancellations for some projects and spiraling costs for others, like the Trans Mountain expansion that opened last year. But Canada - which currently sends 90% of its oil exports to the U.S. - is now trying to diversify oil exports in part to protect its economy against tariffs. The Canadian government under Prime Minister Mark Carney aims to accelerate the construction of natural resource projects, and in August created a new federal office designed to fast-track the review and approval of projects such as mines and pipelines. If a pipeline proposal were to be approved for fast-tracking, Kaumeyer said, then a private sector partner is likely to feel confident enough to step forward and take over the project from the Alberta government. "We are confident that there will be private capital that comes to build this pipeline," he said. Pipeline companies have repeatedly said significant federal legislative change — including the removal of a federal cap on emissions from the oil and gas sector, as well as the removal of a ban on oil tankers off B.C.'s northern coast — is required before a private sector entity would consider proposing a new pipeline. Kaumeyer said the federal government has been made aware that Alberta will be putting forward a pipeline proposal and that Alberta and Canada are in "ongoing discussions" about the matter.
Major road still shut for repairs after oil spill -- A main road will remain closed into the weekend to fix "extensive" damage caused by a spill from an oil tanker, a council has confirmed. The A37 is shut near Chelwood in Somerset, between the junction with the B3130 and the turn off for Birchwood Lane, for emergency repairs according to Bath and North East Somerset Council. Avon and Somerset Police said the spillage, which happened at about 08:00 BST on Thursday, also led to a three-vehicle collision. Drivers have been told to follow the official diversion and avoid using narrow country lanes in the area..
LNG Demand for Marine Fuel Set to Skyrocket by 2030 - Global LNG demand growth will be supported not only by higher power and gas consumption but also by surging demand from the shipping industry, where liquefied natural gas is poised to become key to replacing the dirtier fuel oil and other oil-based marine fuels. Demand for LNG bunkering is expected to at least double by the end of the decade, industry executives and experts have told Reuters. “LNG is great because the infrastructure is there. It's readily available ... maybe later on it's going to be, hopefully, quite cheap as well,” Tuomas Maljanen, associate director for LNG and new energy at shipbroker Fearnleys, told Reuters. According to Jo Friedmann, senior vice president of supply chain research at Rystad Energy, demand for LNG as a marine fuel could top 4 million tons by the end of this year, and double by 2030. LNG is pulling ahead of renewable ammonia and methanol as the preferred choice for ships now that regulations say that the industry must either install the so-called scrubbers if vessels use high-sulfur fuel oil (HSFO), or run the ships on cleaner alternatives such as methanol, LNG, or ammonia. In addition, the EU has a new regulation, FuelEU Maritime, which came into effect on January 1, 2025 and sets maximum limits for the yearly average greenhouse gas intensity of the energy used by ships above 5,000 gross tonnage calling at European ports, regardless of their flag. This new regulation is expected to drive demand for LNG as a marine fuel as renewable ammonia and methanol are in early-stage development and lack extensive infrastructure, analysts say. Maersk, the Denmark-based shipping giant, late last year ordered 20 container vessels equipped with dual-fuel engines, with all ships equipped with liquefied gas dual-fuel propulsion systems. Until 2024, Maersk was betting only on green methanol as a fuel to replace fuel oil and reduce its carbon footprint.
Greenpeace Blockade Forces LNG Tanker Diversions From Belgian Terminal --Greenpeace activists from 17 countries blockaded Belgium’s Zeebrugge LNG terminal on Thursday, forcing at least three tankers to divert. Protesters in kayaks, inflatables, and small craft occupied the channel, demanding an end to both Russian and U.S. LNG flows. Fluxys, which operates the terminal, told Reuters that operations inside remain unaffected, though tanker access was restricted and the blockade was expected to continue through Sunday.The Megara and Rias Baixas Knutsen, both carrying U.S. LNG, along with the LNG Phecda carrying a Russian cargo, were among the ships that changed course, according to LSEG vessel tracking cited by Reuters. Zeebrugge, which serves not only as a Belgian import terminal but also as a re-export hub, sees Russian volumes frequently redirected from there to markets in Spain, Italy, and Asia.Belgium imported roughly 2.3 million tonnes of Russian LNG in the first eight months of 2025, second only to France, customs data show. Despite efforts to cut ties, Europe remains a significant buyer: Russian gas supplied over 40% of EU imports in 2021, a share that dropped to below 19% by 2024. Brussels has proposed phasing out Russian gas entirely by 2027, with the first-ever EU sanctions on Russian LNG due to take effect in January 2027. Still, NGO estimates suggest the bloc has sent €8.1 billion to Moscow this year through LNG purchases.Europe’s reliance on LNG is growing. The IEA projectsEU imports will rise 25% in 2025, with U.S. cargoes capturing more than half of incremental supply. New German terminals at Wilhelmshaven and Brunsbüttel, alongside expanded facilities in the Netherlands, France, and Spain, are anchoring this trend. Storage levels remain tight, with inventories only 39% full at mid-year, well below seasonal averages. On Thursday, the Dutch TTF gas benchmark fell by more than 3%, slipping to 10.82, even as traders monitored disruptions from French LNG strikes and the Zeebrugge blockade. The decline reflects broader softness in European gas markets, though physical risks remain elevated.
Poland to Invest $5.5 Billion in NATO Fuel Pipeline Link -- Polish pipeline operator PERN will sign a preliminary agreement with the defense ministry to extend its fuel network and connect with NATO’s Central Europe Pipeline System. The project also includes new fuel storage facilities to support NATO forces in the region. (Reuters) — Poland said on Oct. 3 that its plan to link to a NATO pipeline network, which is designed to supply troops with fuel in the event of war, will cost 20 billion zlotys ($5.5 billion). Earlier in the day, the ministry and Polish pipeline operator PERN signed a preliminary deal to extend the country's pipelines to connect them to the NATO system. "We are talking about...construction of pipelines over a distance of 300 km...we are talking about one of the largest investments in the security of the Polish state in the last 30 years," Deputy Defence Minister Cezary Tomczyk said. Poland has long sought to connect with NATO's Central Europe Pipeline System (CEPS), which dates from the Cold War era and transports jet fuel, gasoline, diesel fuel and naphtha across Belgium, France, Germany, Luxembourg and the Netherlands. The matter has taken on increased urgency for the eastern flank NATO member since Russia's 2022 invasion of Ukraine and more recently, drone incursions. NATO has allocated 60 million zlotys to Poland to undertake the project which is expected to take several years to complete. "At the NATO level, the decision regarding the planning and design of this investment has been made," said Tomczyk.
TotalEnergies Ready to Resume $20 Billion LNG Project After Force Majeure, Mozambique Says (Reuters) — Mozambique President Daniel Chapo said on Oct. 2 that the conditions have been met for French energy company TotalEnergies to lift force majeure on its $20 billion liquefied natural gas (LNG) project in the Southern African country. TotalEnergies halted work on its Mozambique LNG project in 2021 after an Islamist militant attack. It forecasts the 13 million metric ton-per-year project will come online in 2029, around five years later than initially expected. "Conditions are met for the lifting of force majeure, and we await the pronouncement of the concession holder shortly," Chapo said at a ceremony where Italian firm Eni and its partners took a final investment decision on another gas project in Mozambique. TotalEnergies declined to comment on Chapo's comments. For TotalEnergies, the world's second-largest listed LNG player, the megaproject offers a chance to narrow the lead of rival Shell as global demand for gas surges and Western buyers seek to avoid Russian gas.
India’s Diesel Flows to Europe Jump to All-Time High - India likely exported the highest-ever monthly volume of diesel to Europe in September, as higher premiums and curbed capacity due to maintenance in Europe incentivized Indian refiners to ship more fuel to the west, Reuters reported on Thursday, citing vessel-tracking data and trade sources. India is estimated to have exported 9.7 million to 10.4 million barrels of diesel to Europe last month—the highest ever in records dating back to 2017, according to trade sources and ship-tracking data from Kpler and LSEG. The widening east-west diesel spread incentivized shipments from India to Europe, while shipping costs have dropped since the end of August to further provide more profit incentive for Indian refiners to direct their shipments to Europe. On the other hand, seasonal maintenance at some European refining capacity has curtailed Europe’s domestically produced diesel and other fuels. In this context, India has stepped up to supply more diesel to Europe. Following the likely surge to record-highs in September, Indian diesel exports, to Europe and elsewhere, could decline in October as demand in India is set to jump seasonally with the Diwali festival later this month. Diesel is the most widely used fuel in India, ahead of gasoline. Even with the expected strong demand during the festive season, Indian refiners could be tempted to keep exports elevated, due to the high refining margins supporting overseas sales, Ivan Mathews, head of APAC analysis at Vortexa, told Reuters. Further down the road, it’s uncertain how much diesel and other fuels India will be able to export to Europe, considering the EU’s 18th sanctions package against Russia. In this package, adopted in the middle of July, the EU said it is introducing an import ban on refined petroleum products made from Russian crude oil and coming from any third country – with the exception of Canada, Norway, Switzerland, the United Kingdom and the United States. The goal of this measure is to prevent Russia’s crude oil “from reaching the EU market through the back door,” the EU says. Russia accounts for about a third of all of India’s crude oil imports, so the world’s third-largest crude importer will be hit by the EU move, with the effect on fuel flows uncertain.
Eni Sanctions Coral North FLNG, Doubling Mozambique’s Export Capacity by 2028 --Eni SpA and its project partners in Mozambique have added another project to the list of final investment decisions (FID) in an already record-rivaling year for large-scale LNG development. At A Glance:
Coral North designed with 3.6 Mt/y capacity
First production targeted for 2028
Project marks seventh global FID in 2025
Russia Plans More Sanctioned Cargoes to China — Three Things to Know About the LNG Market -NO. 1: Iraq has awarded Woodlands, TX-based Excelerate Energy Inc. an opportunity to develop a floating LNG import terminal. The facility would allow the country to import LNG for domestic power generation and grid stabilization, Excelerate said. Iraq issued an award letter to the company, which is a preliminary step. Excelerate said it must now negotiate binding commercial agreements.
U.S. Backs Historic Deal to Keep Kurdish Oil Moving --The U.S. Administration wants to ensure that the just-restarted oil exports from Iraq’s semi-autonomous region of Kurdistan continue to flow via pipeline to Turkey in the long run, an anonymous official at the U.S. Department of State told Bloomberg on Friday.The Trump Administration is working toward the goal of keeping Kurdistan’s crude flowing in the long term to boost the Iraqi economy, counter Iran’s influence in the region, and benefit U.S. companies operating in Iraq, according to the official. The U.S. has played a role in the deal that allowed the resumption of the exports from Kurdistan, the official told Bloomberg.U.S. Secretary of State Marco Rubio commented last week on the agreement to restart exports, saying on X “We welcome the announcement that the Government of Iraq has reached an agreement with the Kurdistan Regional Government and international companies to reopen the Iraq-Türkiye pipeline. This deal, facilitated by the United States, will bring tangible benefits for both Americans and Iraqis while reaffirming Iraq’s sovereignty.”Kurdistan’s oil exports resumed on Saturday, September 27, following a two and a half year suspension of the flows via the pipeline from northern Iraq to the Turkish Mediterranean coast.Eight foreign companies operating in Kurdistan have signed agreements with the Kurdistan Regional Government (KRG) and the Federal Government of Iraq to enable the restart of international crude exports from Kurdistan.This agreement paved to way to the restart of exports, which were halted for two and a half years, after they were shut in in March 2023 due to a dispute over who should authorize the Kurdish exports.The federal government in Baghdad and the regional Kurdish government in Erbil squabbled for more than two years over who should be responsible for the oil exports and the subsequent revenue distribution. Under the agreement, hailed as historic by Iraq’s federal government, KRG is delivering about 190,000 barrels per day (bpd) of crude to Iraqi state marketing company SOMO. Kurdistan is also entitled to keep 50,000 bpd to use for local consumption.
Oil falls as Kurdistan exports resume, OPEC+ eyes hike -- Oil prices slipped during Asian trade on Monday after Iraq’s Kurdistan region restarted crude exports via Turkey and OPEC+ prepared for another supply boost in November, adding to global output. By 3:30 pm AEST (5:30 am GMT) Brent crude futures dropped 34 cents, or 0.5%, to $69.79 per barrel, while U.S. West Texas Intermediate (WTI) crude fell 43 cents, or 0.7%, to $65.29. Meanwhile, crude shipments resumed on Saturday through a pipeline linking the semi-autonomous Kurdistan region in northern Iraq to Turkey’s Ceyhan port, marking the first flows in two and a half years. Iraq’s oil ministry said the breakthrough followed an interim deal between Baghdad, the Kurdistan regional government (KRG), and foreign producers operating in the area. The agreement will allow 180,000 to 190,000 barrels per day to reach Turkey, with flows expected to rise to as much as 230,000 bpd, according to Iraq’s oil minister, who spoke to Kurdish broadcaster Rudaw. Washington had pushed for the restart, which comes as OPEC+ seeks to expand market share. The producers’ group is likely to approve a crude output hike of at least 137,000 bpd at its meeting on Sunday, three sources told Reuters, with higher prices encouraging additional supply. Brent and WTI rallied more than 4% last week, their sharpest weekly rise since June, after Ukraine’s drone strikes on Russia’s energy infrastructure disrupted fuel exports. Russia responded with heavy missile attacks on Kyiv and other cities on Sunday, in one of the most sustained barrages on the Ukrainian capital since the full-scale war began. Geopolitical risks were also amplified after the United Nations reinstated an arms embargo and other sanctions on Iran over its nuclear programme. ANZ analysts observed: “UN economic and military sanctions on Iran were reinstated over the weekend, with the UK, France, and Germany triggering the ‘snapback’ mechanism, citing Iran’s ongoing nuclear escalation and lack of cooperation.”
Oil Prices Tumble 2% On Glut Expectations Pre-OPEC -- Oil prices tumbled about 2% in Monday morning trade ahead of a monthly OPEC meeting later this week where further production hike commitments were expected to add to oversupply concerns. The return of northern Iraq exports to the market after a two-and-a-half year hiatus added to the weight on prices. In crude oil, NYMEX-traded WTI for November delivery fell $1.30, or 2%, to $64.42 barrel (bbl). ICE Brent for November delivery retreated $1.22, or 1.7%, to $68.91 bbl. Among oil products, October RBOB gasoline futures slid $0.0154 to $1.9734 gallon, and the front-month ULSD contract fell $0.0494 to $2.3795 gallon. The U.S. Dollar Index remained little changed at 97.582, down 0.242 points against a basket of foreign currencies. Over the weekend, flows along the Kirkuk-Ceyhan pipeline resumed after a two-and-a-half year long halt, delivering oil from northern Iraq to Turkish export terminals. At least 200,000 barrels per day (bpd) of crude oil are likely to return to the market immediately. Before the shutdown, flows on the pipeline averaged more than 400,000 bpd, but lacking takeaway capacity has dented Kurdish production capacity since the interruption. On Wednesday (10/1), OPEC delegates will be convening virtually to set production policy for November. Last month's meeting resulted in a quota hike of 137,000 bpd for October. While that was only a quarter of prior monthly increases, it still took market observers by surprise given that the hikes were part of the unwinding of some 2.2 million bpd in voluntary additional production curtailments shouldered by eight member states, something which had been achieved in September. Wednesday's meeting is expected to result in yet another quota increase as OPEC+ tries to regain lost market share, which risks further tilting the global oil balance into oversupply. Actual production hikes are likely to come in below target, as evidenced by the group's history and waning spare production capacity.
Oil Suffers Steepest Fall Since June - Oil declined on signals that OPEC+ will hike production again in November, tempering last week's rally. West Texas Intermediate fell 3.4% to settle near $63 a barrel, the biggest drop since June, while Brent closed below $70. The OPEC+ alliance led by Saudi Arabia is considering raising output by at least as much as the 137,000 barrel-a-day hike scheduled for next month, according to people familiar with the plans. While such an increase could add supply to a market in which there's already expected to be an excess, it would also bring further scrutiny to which of the group's members are running into capacity limits. "We view a repeat of the incremental 137,000-barrel-a-day addition for November as the most likely outcome," Helima Croft wrote in a note, referring to the decision likely to be taken at the group's Oct. 5 meeting. "Given that many producers, excluding Saudi Arabia, have essentially hit their production ceilings, future OPEC+ supply increases will be materially lower than the announced headline numbers," the analysts added. Crude remains on track for monthly and quarterly gains, even as the Organization of the Petroleum Exporting Countries and its allies have been pursuing a strategy to reclaim market share rather than managing prices. Oil has been underpinned by robust buying for stockpiling in China, as well as on geopolitical tensions. Today's slide also reflects a pullback from last week's highs, when traders covered long positions ahead of the weekend to hedge against mounting threats to Russian energy infrastructure. The International Energy Agency has projected a record oversupply in 2026 as OPEC+ continues to revive production, and as supply climbs from the group's rivals. Goldman Sachs Group Inc., meanwhile, has said it sees Brent falling to the mid-$50s next year, despite crude stockpiling by China. "The major forecasters are still looking for price weakness in the coming months and as long as the Russia focus does not turn into an actual disruption of supply, traders will at least in the short term struggle to build a bullish narrative, not least considering the risk of another OPEC+ production increase," said Ole Hansen, head of commodities strategy at Saxo Bank. In Iraq, meanwhile, flows via a pipeline that ships crude from the country's northern region to a terminal in Turkey restarted in recent days after a halt of more than two years. Amer Al-Mehairi, director general of Iraq's North Oil Co., said the resumption of exports along the conduit was continuing. Elsewhere, President Donald Trump said Israeli Prime Minister Benjamin Netanyahu had agreed to a 20-point plan designed to stop fighting between Israel and Hamas. An end to the nearly two-years long was in the Middle East, the source of about a third of the world's supplies, may siphon some war premium out of prices. WTI for November delivery fell 3.5% to settle at $63.45 a barrel in New York. Brent for November settlement slid 3.1% to settle at $67.97 a barrel.
Expectations OPEC+ Will Increase its Output Again in November - The oil market on Monday sold off sharply on expectations that OPEC+ will increase its output again in November and the resumption of oil exports by Iraq’s Kurdistan region via Turkey. Sources stated that OPEC+ will likely approve another increase to crude oil production of 137,000 bpd at its meeting on Sunday. Meanwhile, crude oil flowed through a pipeline from the semi-autonomous Kurdistan region in northern Iraq to Turkey for the first time in 2-½ years on Saturday. The crude market opened lower and retraced some of its previous losses as it posted a high of $65.40. However, the market sold off sharply and retraced more than 62% of its move from a low of $61.06 to a high of $66.42 as it posted a low of $62.98 ahead of the close. The November WTI contract settled down $2.27 at $63.45 and the November Brent contract settled down $2.16 at $67.97. The product markets ended the session lower, with the heating oil market settling down 7.23 cents at $2.3566 and the RB market settling down 4.25 cents at $1.995. U.S. President Donald Trump said that it is time for Palestinian militant group Hamas to accept a 20-point peace proposal that he agreed to with Israeli Prime Minister Benjamin Netanyahu regarding the future of Gaza. Meanwhile, Israeli Prime Minister Benjamin Netanyahu said he supported U.S. President Donald Trump’s peace proposal to end the war in Gaza. Standing next to President Trump, Israel’s Prime Minister said “I support your plan to end the war in Gaza, which achieves our war aims. It will bring back to Israel all our hostages, dismantle Hamas’ military capabilities, end its political rule, and ensure that Gaza never again poses a threat to Israel.” Separately, Hamas official Mahmoud Mardawi reiterated that the group has not yet received U.S. President Donald Trump’s written Gaza peace plan.In a joint statement, Germany, France and Britain said they will “continue to pursue diplomatic channels and negotiations” despite the reimposition of U.N. sanctions on Iran. The statement said “The reinstatement of U.N. sanctions does not mean the end of diplomacy.”Former Russian President Dmitry Medvedev said that Europe could not afford a war against Russia but that if its leaders made the mistake of triggering one then it could escalate into a conflict with weapons of mass destruction. Ukrainian President, Volodymyr Zelenskiy, said Ukraine would like to build a joint aerial defense shield to protect against threats from Russia together with its European partners. NATO leaders have said that Russia has been testing the alliance’s readiness and resolve with airspace incursions in Poland and the Baltic states, and Kyiv says its experience in dealing with aerial threats would be valuable.Three sources familiar with the talks said OPEC+ will likely approve another oil production increase of at least 137,000 bpd at its meeting next Sunday, as increasing oil prices encourage the group to try to further regain market share. OPEC+ has reversed its strategy of output cuts from April and has already raised quotas by more than 2.5 million bpd. Eight OPEC+ countries will hold an online meeting on October 5th to decide on November output. Crude oil flows from Iraq’s Kurdistan region to Turkey’s Ceyhan port are running at 150,000-160,000 bpd after their resumption on September 27th.
Crude oil declines as markets assess impact of US-sponsored Gaza peace plan - The Hindu BusinessLine -Crude oil futures fell on Tuesday morning as markets assessed the impact of the Gaza peace plan announced by the US. At 9.55 am on Tuesday, December Brent oil futures were at $66.68, down by 0.61 per cent, and November crude oil futures on WTI (West Texas Intermediate) were at $63.08, down by 0.58 per cent. October crude oil futures were trading at ₹5,611 on Multi Commodity Exchange (MCX) during the initial hour of trading on Tuesday against the previous close of ₹5,610, up by 0.02 per cent, and November futures were trading at ₹5,591 against the previous close of ₹5,593, down by 0.04 per cent. On Monday, US President Donald Trump announced the support of Israel for a US-sponsored peace deal to end the war in Gaza.Addressing a joint press conference with the Israeli Prime Minister Benjamin Netanyahu at White House on Monday, Trump said they were ‘beyond very close’ to an elusive peace deal for the Palestinian enclave. However, he warned Hamas that Israel would have full US support to take whatever action it deemed necessary, if the militants reject what US has offered.The 20-point document released by White House sought an immediate ceasefire, an exchange of hostages held by Hamas for Palestinian prisoners held by Israel, a staged Israeli withdrawal from Gaza, Hamas disarmament and a transitional government led by an international body.A peace deal between Israel and Hamas would help provide stability in the oil-rich West Asia region.Meanwhile, crude oil prices came under pressure following the reports of a likely increase in production by the Organization of the Petroleum Exporting Countries and its allies (OPEC+) in November. In their Commodities Feed for Tuesday, Warren Patterson and Ewa Manthey said oil prices came under significant pressure on Monday, with ICE Brent falling more than 3 per cent over the day. This came amid reports that OPEC+ is considering increasing supply by a further 137,000 barrels a day in November.“We should get confirmation on October 5, when the group is set to meet. Our balance sheet clearly suggests additional supply isn’t needed. We expect the market to move into a large surplus in the fourth quarter and remain in surplus through 2026. As a result, we expected oil prices to come under significant pressure over the course of next year,” they said. October menthaoil futures were trading at ₹960 on MCX during the initial hour of trading on Tuesday against the previous close of ₹965.20, down by 0.54 per cent. On the National Commodities and Derivatives Exchange (NCDEX), October turmeric (farmer polished) contracts were trading at ₹12,246 in the initial hour of trading on Tuesday against the previous close of ₹12,418, down by 1.39 per cent. October guargum futures were trading at ₹8,840 on NCDEX in the initial hour of trading on Tuesday against the previous close of ₹8,931, down by 1.02 per cent.
Potential Plans for a Larger OPEC+ Output Increase - The crude oil market remained pressured by potential plans for a larger OPEC+ output increase next month and the resumption of oil exports from Iraq’s Kurdistan region via Turkey. The market remained pressured in overnight trading and continued on its downward trend following the news of crude oil starting to flow on Saturday through a pipeline from the Kurdistan region in northern Iraq to Turkey for the first time in two and half years. The market was further pressured by news that OPEC+ may be considering a larger oil production of 411,000 bpd for November, which would be three times as much the 137,000 bpd increase that OPEC+ agreed to for October. The oil market, which posted a high of $63.26, sold off to a low of $62.03 early in the session. The market, however, retraced some of its losses and settled in a sideways trading range as OPEC dismissed the reports of a possible increase in output of 500,000 bpd. The November WTI contract settled down $1.08 at $62.37 while the November Brent contract settled down 95 cents at $67.02. The product markets ended the session lower, with the heating oil market settling down 2.41 cents at $2.3325 and the RB market settling down 2.22 cents at $1.9729. OPEC rejected media reports suggesting that the group of eight oil-producing countries was planning to raise output by 500,000 bpd at its meeting on Sunday. OPEC said these claims are wholly inaccurate and misleading. Two sources said OPEC+ is likely to consider a larger oil production increase of 411,000 bpd for November at its meeting on Sunday as increasing oil prices encourage the group to try to regain more market share. A 411,000 bpd increase would be three times the 137,000 bpd increase that OPEC+ agreed for October. A separate OPEC+ ministerial panel, the Joint Ministerial Monitoring Committee, meets online on Wednesday and sources said it will discuss the producer group’s compliance with oil output quotas. Bloomberg News reported that OPEC+ is considering accelerating output hikes by 500,000 bpd over the next three months. U.S. President Donald Trump said he and his team were waiting on Hamas militants to accept the Gaza peace plan that he outlined on Monday. Israel’s U.N. Ambassador, Danny Danon, said that if Palestinian militants Hamas reject U.S. President Donald’s Trump Gaza peace plan, Israel will “finish the job” and bring home all the remaining hostages. Russia imposed a partial ban on diesel exports and extended an existing gasoline export ban until the end of the year. The measures were expected, as Deputy Prime Minister Alexander Novak had given advance warning of them last week. The government said in a statement that it “continues to work to maintain stability in the domestic fuel market.” The gasoline export ban applies to all exporters. The ban on diesel exports also includes marine fuel and other gas oils. It applies to resellers but not to direct producers of those fuels.
Oil settles lower as investors brace for possible OPEC+ output hike (Reuters) - Oil prices settled lower on Tuesday as investors braced for a supply surplus due to potential OPEC+ plans for a larger output hike next month and the resumption of oil exports from Iraq's Kurdistan region via Turkey. Brent crude futures for November delivery , expiring on Tuesday, settled down 95 cents, or 1.4%, at $67.02 a barrel. The more active December contract settled at $66.03. U.S. West Texas Intermediate crude settled at $62.37 a barrel, down $1.08, or 1.7%. On Monday, Brent and WTI both settled more than 3% lower, their sharpest daily declines since August 1. At its meeting next Sunday, OPEC+ may speed up production increases in November from the 137,000 barrels per day hike it made for October, as its leader Saudi Arabia pushes to regain market share, three sources familiar with the talks said. Eight members of OPEC+ could agree to raise production in November by 274,000-411,000 bpd, or two or three times higher than the October increase, two of the three sources said. OPEC+ pumps about half of the world's oil. The increase could be as big as 500,000 bpd, one of the three sources said. Earlier on Tuesday, Bloomberg News reported that OPEC+ was considering accelerating its increases by 500,000 bpd. OPEC in a post on X said it rejected media reports for plans to raise output by 500,000 bpd, calling them inaccurate and misleading. "This (OPEC+) strategy could significantly squeeze margins for high-cost U.S. shale producers, potentially forcing them to scale back the record-level output they've maintained," said StoneX analyst Alex Hodes. Meanwhile, crude oil flowed on Saturday through a pipeline from the semi-autonomous Kurdistan region in northern Iraq to Turkey for the first time in two-and-a-half years, after an interim deal broke a deadlock, Iraq's oil ministry said. "Oil prices are under pressure in anticipation of OPEC+ deciding to restore additional quantities of oil back to market, along with the resumption of Kurdish exports, so additional supplies are weighing on market prices," The market has remained cautious in recent weeks, balancing supply risks, which mainly arise from Ukraine's drone attacks on Russian refineries, with expectations of oversupply and weak demand. Elsewhere, U.S. President Donald Trump won Israeli Prime Minister Netanyahu's support for a U.S.-backed Gaza peace proposal, but the stance of Hamas was uncertain. In an ideal scenario, shipping traffic through the Suez Canal would return to normal following a Gaza peace deal, which would remove a significant portion of the geopolitical risk premium, PVM analyst Tamas Varga said. Adding to the bearish sentiment, the potential risk of a U.S. government shutdown has raised demand concerns, said ANZ analysts in a note. U.S. crude production rose to a fresh monthly high of 13.64 million bpd in July, up 109,000 bpd from the previous record in June, data from the Energy Information Administration showed on Tuesday. U.S. crude stocks fell while gasoline and distillate inventories rose last week, market sources said, citing American Petroleum Institute figures on Tuesday. Crude stocks fell by 3.67 million barrels in the week ended September 26, the sources said on condition of anonymity. Gasoline inventories rose by 1.3 million barrels, while distillate inventories rose by 3 million barrels from last week, the sources said..
Oil steadies; investors weigh OPEC+ hike, stockpile draw - Oil prices traded slightly higher during Asian deals on Wednesday after two straight sessions of declines, as investors assessed potential production increases against signs of falling crude inventories in the United States. By 2:30 pm AEST (4:30 am GMT), Brent crude futures for December delivery rose 19 cents, or 0.3%, to $66.22 per barrel, while U.S. West Texas Intermediate gained 18 cents, or 0.3%, to $62.55 per barrel. The modest rise followed sharp losses earlier in the week, with both Brent and WTI down more than 3% on Monday, and falling a further 1.5% on Tuesday.Fresh data from the American Petroleum Institute showed U.S. crude inventories fell last week, even as gasoline and distillate stocks climbed.The Organization of the Petroleum Exporting Countries (OPEC+) is also reportedly weighing a significant production hike for November, with Saudi Arabia pushing for an increase of up to 500,000 barrels per day (bpd) to regain market share, three people familiar with the talks told Reuters. That would be triple the October rise.OPEC, in a post on X, pushed back against speculation, saying reports of a 500,000 bpd hike were “misleading”.ANZ analysts said: "Supply risks are still looming due to deepening geopolitical situation and supply outages. "President Trump stated that he had dispatched ‘a submarine or two’ to Russia’s coast. While it remains unclear whether this move signifies an escalation or not, the remark underscores a shift in diplomatic tone toward Russia. "This change heightens the likelihood of additional restrictions on Russian oil exports, increasing risks for Russian exports." Political uncertainty also loomed large. In Washington, President Donald Trump secured the backing of Israeli Prime Minister Netanyahu for a U.S.-brokered Gaza peace plan, though Hamas’s response remained unclear.
Oil Trims Losses After DOE Shows Modest Weekly Inventory Builds - Oil dipped modestly, extending its two-day slide, after the latest DOE data showed another weekly increase across most oil products, even as expectations were for continued declines.
- Crude +1,782k vs est -50k
- Gasoline +4,125k vs est. -80k
- Distillates +578k vs est. -1,650k
- Cushing crude -271k
The 1.79-million-barrel build in commercial crude stockpiles contrasts with the 3.7-million-barrel draw seen by the API on Tuesday. Following draws in the past two weeks, crude, gasoline and distillate inventories were expected to post another modest drop, but the official data showed an increase across all three products. Increases in crude, gasoline and propane are enough to push total crude and product inventories higher versus last week. It’s the fourth overall build in the last five weeks and the largest weekly increase since early September. Meanwhile, crude inventories at Cushing, Oklahoma fell to around 23.5 million barrels. It’s the third draw at the hub in four weeks, bringing levels to the lowest since late August. Some other notable weekly changes:
- PADD 3 crude +4,031k
- Refinery utilization -1.6ppt vs est. -0.3ppt
- Refinery crude inputs -308k b/d
- Crude imports -662k b/d
The build in commercial stockpiles was boosted by another 742,000 barrels injected into the SPR. That increased the overall nationwide crude build to 2.53 million barrels in the week to Sep. 26. Crude exports fell below 4 million barrels a day, which brings them to the lowest in about one month. More barrels staying put might have helped relieve a bit of downward pressure on US inventories, which rose to the highest since early September. According to BBG, a decline in Gulf Coast crude refinery runs pulled down the overall US number to 16.2 million barrels a day, the lowest level since May. That was most likely due to the turnaround at Marathon’s Garyville plant in Louisiana, one of the largest refineries in the nation. Overall US crude runs are still at the highest seasonal level since 2018. Meanwhile, US production continued its relentless weekly increase, rising by another 4k barrels/day on the week, back near record highs, even as rig counts remain near 4 year lows. Indeed, total crude production edged higher to 13.5 million barrels a day last week, the highest since March. The small increase came as the number of rigs drilling for oil rose for a fifth straight week, with six units put into operation last week, according to Baker Hughes. At some point there will be questions about all the toxic water flowing out of Permian wells which is allowing productivity to approach 100%, but not yet... Oil prices recovered some of their losses, having plunged from their Friday highs (oil had just closed its best week since the Iran-Israel conflict) and sinking to the lowest level since June as CTAs are now back aggressively shorting the price as long as momentum remains lower. Finally, Bloomberg reports that US gasoline demand continues to pull back, recording a fourth consecutive decline last week based on the four-week average of product supplied. The figure is down 351,000 barrels a day over the stretch and brings the figure to a six-month low. That said, demand is still closely tracking year-ago levels and is still firmly above where it sat this week in 2023. If that trend continues, we could see a solid bounce back in the next few weeks.
Crude Oil Plummets to Lowest Since June -Crude oil benchmarks were trading even lower midday Wednesday, at prices lower than they’ve dipped for several months, even as OPEC+ emphasizes that it is committed to a calibrated increase in crude output, rejecting media speculation of a sweeping jump in inventory. Still, it involves additional supply, and as of the time of writing, that continued to put downward pressure in markets already showing signs of strain. The expanded cartel’s decision to add barrels amid soft demand has empowered the bears, dragging both Brent and WTI back to their weakest levels since June, with even measured dips feeling outsized in a fragilly balanced market. At 12:33 p.m. ET on Wednesday, Brent crude was trading at $67.51, down 0.97% on the day, while West Texas Intermediate (WTI) was trading at $62.21, down 0.26% on the day. Meanwhile, Kurdistan’s resumption of exports to Turkey’s Ceyhan terminal at volumes estimated between 180,000 and 230,000 barrels per day is reintroducing more crude to the global markets. Weakening demand in Asia is compounding the supply overhang. Manufacturing surveys from Japan showed a sharper contraction in September, hitting a six-month low. China’s factory sector contracted for the sixth consecutive month, adding to the sense of stalling momentum. Export-reliant economies across the region are seeing soft external orders, while domestic demand remains lackluster. Slower fuel consumption in Asia is a key flashpoint for traders. In the U.S., the government shutdown is injecting additional uncertainty into energy markets. Critical agencies with furloughed employees could find themselves unable to deliver the data that traders depend upon, heightening volatility. “Oil prices are under pressure in anticipation of OPEC+ restoring additional quantities of oil back to market, along with the resumption of Kurdish exports,” said Andrew Lipow, president of Lipow Oil Associates. StoneX analyst Alex Hodes warned that the renewed supply burden could “squeeze margins for high-cost U.S. shale producers.” Meanwhile, Diamondback Energy CEO Kaes Van‘t Hof cautioned that U.S. production growth is likely to stall if crude stays around $60, noting that fewer Tier-1 drilling zones remain viable at lower prices.
The Crude Oil Market Settled Lower Amid the Government Shutdown -The crude oil market continued to sell off on Wednesday, settling lower for the third consecutive session amid the U.S. federal government shutdown that added to worries about the economy and expectations of an OPEC+ output increase in November. The market has also been pressured by the resumption of oil exports from Iraq’s Kurdistan region. The market traded mostly sideways in overnight trading, posting a high of $62.89 before it continued to sell off. The market remained pressured by expectations that OPEC+ will increase its production in November by about 500,000 bpd, despite OPEC stating that media reports of plans to increase its output by that amount were misleading. The market was also pressured by larger than expected build in crude oil stocks of over 1.7 million barrels reported on the week. The market later bounced off its low and settled in a sideways trading range. The November WTI contract settled down 59 cents at $61.78 and the December Brent settled down 68 cents at $65.35. The product markets ended the session lower, with the heating oil market settling down 2.22 cents at $2.3019 and the RB market settling down 3.64 cents at $1.8859. The U.S. Energy Information Administration will be able to operate for a period of time during the lapse in appropriations. Until further notice, the EIA.gov website will continue to be updated, and publications will continue to be released according to established schedules.Russian Deputy Prime Minister Alexander Novak said that the situation with supply of fuel on the domestic market is under control on the whole, while some regions are experiencing shortages of the fuel. Several regions in Russia reported shortages of certain popular types of gasoline, including Crimea, which Russia annexed from Ukraine in 2014, as well as Nizhny Novgorod, east of Moscow. Ukraine has shut in some of Russia’s refining capacity via drone attacks.Russia’s U.N. Ambassador, Vassily Nebenzia, said Russia does not recognize the reimposition of United Nations sanctions on Iran.OPEC said the Joint Ministerial Monitoring Committee stressed the need for achieving full compliance with oil output agreements at its online meeting on Wednesday. The CEO of Diamondback Energy, Kaes Van’t Hof, said U.S. oil production growth will stall if prices stay near $60/barrel, as fewer drilling sites are profitable at that level. According to three trading sources, Russia increased its oil exports via its western ports by 25% in September versus August, as refinery outages caused by Ukrainian drone attacks freed up more crude. Exports via the western ports of Primorsk, Ust-Luga and Novorossiisk in September increased to 2.5 million bpd. Daily loadings of Urals, KEBCO and Siberian Light grades at Primorsk, Ust-Luga and Novorossiisk in September increased by 500,000 bpd, up 25% from August.
Global Oil Prices Edge Higher As G7 Moves To Clamp Down On Russian Crude Buyers -Oil prices ticked upward on Thursday in the global commodities market after the Group of Seven (G7) industrialized nations unveiled fresh measures aimed at tightening restrictions on countries purchasing crude oil from Russia. Geopolitical instability in the Middle East and weakening demand from China continue to weigh on global supply, even as India maintains strong energy ties with Moscow. This ongoing trade relationship has drawn further scrutiny from the United States, which has imposed sanctions to limit Russia’s energy revenues. The rebound in prices came as traders assessed a larger-than-expected build-up in US crude inventories alongside renewed signals that the G7 intends to intensify financial pressure on Moscow’s oil exports. Brent crude climbed to $65.46 per barrel, slightly above its previous close of $65.32, while West Texas Intermediate (WTI), the US benchmark, advanced 0.25% to $61.77 from $61.61 in the earlier session. In a statement following a virtual meeting on Wednesday, G7 finance ministers confirmed plans to target buyers of Russian crude and entities accused of helping Russia bypass existing sanctions. “Now is the time to maximize pressure on Russia’s oil exports, which remain a critical source of revenue,” the ministers declared, adding that countries expanding their Russian oil purchases since the Ukraine invasion could face consequences. The group said it would gradually phase out remaining Russian hydrocarbon imports, consider restrictions on refined oil products, and evaluate penalties for nations providing Moscow with indirect support. The matter is expected to be discussed further during the IMF and World Bank annual meetings in Washington on October 15. Market analysts noted that the threat of stricter sanctions heightened concerns about potential supply disruptions, offering some price support. Meanwhile, data from the US Energy Information Administration showed commercial crude inventories rose by 1.8 million barrels last week to 416.5 million, exceeding forecasts of a 1.5 million-barrel increase. Gasoline stockpiles also expanded, rising by 4.1 million barrels to 220.7 million. Strategic petroleum reserves climbed by 700,000 barrels to 406.7 million. Investors are now turning their attention to the upcoming October 5 OPEC+ meeting, where major producers including Saudi Arabia, Russia, Iraq, and the UAE will decide on November production quotas. Last month, the alliance agreed to increase output by 137,000 barrels per day for October. Analysts suggest expectations of continued production hikes may fuel concerns of oversupply in the months ahead..
Oil Drops to 4-Month Low as Fundamentals Trounce Supply Risks -- Oil prices extended their decline into a fourth trading day as the prospects of new OPEC production hikes weighed on sentiment in a market that already looked to be oversupplied by the year-end. In Thursday morning, Oct. 2, trade, NYMEX-traded WTI crude for November delivery fell $0.31 to $61.47 bbl, after a fourth-month low at $61.22. Oil prices steadied after a four-day selloff pressured mainly by oversupply concerns that took them to their lowest since early June. ICE Brent crude for December delivery retreated $0.36 to $64.99 bbl, after hitting $64.81, its lowest since June. Among oil products, November RBOB gasoline futures slid $0.0095 to $1.8764 gallon, and the front-month ULSD contract softened $0.0283 to $2.2736 gallon. The U.S. Dollar Index remained relatively unchanged, down 0.04 points to 97.70 against a basket of foreign currencies. Sluggish macroeconomic indicators released this week suggested a grow rate at which the market will struggle to absorb extra barrels from OPEC+. East Asian manufacturing PMIs released this week showed the region's industrial sectors stagnating, with the indices for September hovering close to the 50-point mark. In the U.S., consumer confidence slipped to a three-month low in September, as a key index monitored by the Conference Board slid 3.6 points to 94.2 from a revised 97.8 in August. The U.S. federal government shutdown added to concerns over slowing demand growth, exacerbating the bearish sentiment. Oil futures have been trading in a narrow range for months, caught in a tug-of-war between weak market fundamentals and geopolitical risks. The restart of northern Iraq's 200,000-bpd Kirkuk-Ceyhan pipeline comes ahead of Sunday's, Oct. 5, OPEC meeting, that is likely to result in more output from the 23-nation producer group which will be discussing production quotas for November. A slew of fresh economic data also points to weak demand growth for energy, skewing the market's attention towards the risk of rapidly growing global oil inventories. The Energy Information Administration on Wednesday, Oct. 1, reported higher commercial crude oil inventories, as well as a surprisingly large 4.1 million bbl build in gasoline stocks for the week ending Sept. 26.
Oil Sinks Near 5-Month Low on OPEC Signals, Government Shutdown - Oil fell to the lowest in nearly five months as OPEC+ is expected to agree on restoring more idled supply in a meeting over the weekend, while the ongoing US government shutdown fueled risk-off sentiment. West Texas Intermediate slid more than 2% to settle at $60.48 a barrel, its lowest close since early May. Brent traded lower to settle near $64, the lowest since late May. Early signs of global oversupply may be emerging in the Middle East, while US crude and gasoline stockpiles swelled last week. In Washington, political uncertainty added another layer of concern as White House press secretary Karoline Leavitt warned that layoffs tied to the federal government shutdown are likely to number in the thousands. The news added to worries about the health of the US economy and in turn, oil consumption. This week's price slump was also partly stoked by the possibility that Organization of the Petroleum Exporting Countries and its partners could consider fast-tracking their latest round of production hikes when they meet on Sunday. A Bloomberg survey predicted OPEC's crude production rose last month. Some investment banks are already predicting Brent will drop to the $50s-a-barrel range next year. Prices have found some support from the fact that China has been purchasing large amounts of oil for its strategic reserve, easing the buildup of inventories in the West. Those purchases may slow next year, according to Rystad Energy. "The focus for oil this week is squarely on the OPEC+ meeting over the weekend. We expect they will agree to continue adding barrels back to the market even amid forecasts for high inventory builds in 2026," said Edward Bell, acting group head of research and chief economist at Emirates NBD. Turkey's Ceyhan oil export terminal is scheduled to load its first cargo from Iraq's Kurdish region since 2023 after a deal was reached last month to allow flows to resume, adding even more supply to the market. Meanwhile, French President Emmanuel Macron said that detaining oil tankers can help put a stop to the shadow fleet that helps Russia skirt sanctions and export barrels around the world. But Russian President Vladimir Putin warned oil prices "will skyrocket" and immediately exceed $100/bbl without Russian crude supplies to the global market. WTI for November delivery fell 2.1% to settle at $60.48 a barrel. Brent for December settlement edged 1.9% lower to settle at $64.11.
Oil set to experience steepest weekly drop in 3 1/2 months - The oil prices were slightly higher on Friday, after four consecutive sessions of declines. However, they are on course for the steepest weekly drop since late June because market expectations expect that OPEC+ could increase output despite concerns about oversupply. Brent crude futures rose 18 cents or 0.3% to $64.29 per barrel at 0000 GMT. U.S. West Texas Intermediate Crude climbed by 19 Cents, or 0.3% to $60.67 per barrel. Brent could end the session at its lowest level since last week's May 30. WTI might finish at levels not seen since May 2 if prices don't recover further in this session. Brent is down 8.3% on a weekly basis while WTI has fallen 7.6%. Sources told The Week that OPEC+ may agree to increase oil production in November by as much as 500,000 barrels a day, which is triple the October increase, because Saudi Arabia wants to regain market share. Tony Sycamore is an analyst with IG. He said, "If OPEC+ announces a 500,000 bpd hike this weekend, that's likely to be a large enough increase to send crude back down, first to the support level of $58.00 before testing this year's lowest $55.00 area." Analysts say that a potential increase in OPEC+ oil supply, a slowdown in global crude refinery operations due to maintenance, and upcoming seasonal drops in demand will accelerate the buildup of oil stocks in the U.S. Energy Information Administration reported on Wednesday that U.S. crude, gasoline and distillate inventory rose last week due to a decline in refining and demand. Sycamore stated that "concerns about a US shutdown curtailing economic activity, and the return of Iraqi Kurdish oil to the market are also impacting the crude price." The Group of Seven finance ministers announced on Wednesday that they would increase pressure on Russia, targeting those countries who continue to buy Russian oil.
Oil prices rise 1% following fire at US refinery. Set to end four-session loss streak - After four consecutive sessions of declines, oil prices rose by 1% on Friday following a fire at one of the biggest refineries in the U.S. West Coast. However, they were still on course for their steepest week-long fall since late June. Brent crude futures rose 61 cents or 1% to $64.73 per barrel at 0658 GMT. U.S. West Texas Intermediate Crude climbed by 62 Cents, or 1% to $61.10 per barrel. According to a county official, the fire was contained to just one area at Chevron’s El Segundo Refinery. The U.S. Energy Major also reported a flare-up emergency at its 290,000 BPD refinery that produces primarily gasoline, jet fuel, and diesel. Brent traded 7.6% lower and WTI fell 7% weekly due to expectations that OPEC+ could increase output despite concerns about oversupply. Sources told The Week that OPEC+ may agree to increase oil production in November by as much as 500,000 barrels a day, which is triple the October increase, because Saudi Arabia wants to regain market share. Tony Sycamore is an analyst with IG. He said, "If OPEC+ announces a 500,000 bpd hike this weekend, that's likely to be a large enough increase to send crude back down, first to the support level of $58.00 before testing this year's lowest levels (of about $55.00)." Analysts say that a potential increase in OPEC+ oil supply, a slowdown in global crude refinery operations due to maintenance, and upcoming seasonal drops in demand will accelerate the buildup of oil stocks in the U.S. Energy Information Administration reported on Wednesday that U.S. crude, gasoline, and distillate inventory rose last week due to a decline in refining and demand. JPMorgan analysts wrote in a report that they believe September was a turning-point, and the oil market is now headed towards a large surplus in Q4 of 2025 as well as next year. The Group of Seven finance ministers announced on Wednesday that they would increase pressure on Russia, targeting those countries who continue to buy Russian oil.
Oil prices post biggest weekly decline in three months ahead of Opec meeting -- Oil prices settled higher on Friday but posted a weekly loss of 8.1 per cent over expectations that Opec+ will raise output, adding to a glut in crude supplies.Brent, the benchmark for two thirds of the world's oil, closed up 0.7 per cent at $64.53 a barrel. West Texas Intermediate, the gauge that tracks US crude, was up 0.7 per cent at $60.88.For the week, Brent fell 8.1 per cent, the largest weekly loss in over three months. WTI tumbled 7.4 per cent in the week.The rebound in crude came after prices steadily dropped this week through to Thursday, which put Brent and WTI on pace to slide 6.5 per cent and 7.1 per cent, respectively, their biggest weekly losses since June.That also widened losses for 2025 overall, with Brent now down 13.3 per cent and WTI giving up 15 per cent for the year to date.The sentiment in the oil market took a sharply bearish turn this week amid reports that Opec+, the group of oil producers led by Saudi Arabia and Russia, is preparing to boost output for next month at its meeting on Sunday, after increasing production for seven consecutive months since April this year.Opec+'s move to increase output "will bring more idled supply back to the market, fuelling oversupply concerns", said Soojin Kim, a Dubai-based research analyst at MUFG."Early signs of excess supply are already visible in the Middle East ... market focus will be on Opec+’s decision, the pace of returning barrels, and global demand resilience as surplus risks build," she added.This week, Goldman Sachs predicted that Opec+ will raise oil production by 140,000 barrels per day for November amid lower crude stocks in the US, higher demand in Asia and downside risks to Russia’s crude production after Ukrainian attacks on Russian refineries.Last month, Opec+, citing steady global economic outlook and current healthy market fundamentals, approved adding about 137,000 bpd to the market for October as it began to unwind 1.65 million bpd of voluntary cuts announced in April 2023.This came after the group eliminated about 2.2 million barrels of voluntary cuts announced in November 2023 the month before, with monthly cuts starting in April."Crude futures were marginally higher [early on] Friday morning in the Middle East amid tepid bargain-hunting buying, after sliding for the fourth session in a row to three-month lows," analysts at Vanda Insights said.However, "prices may go into a holding pattern through the rest of the day, awaiting the result of the Opec+ meeting on Sunday".Fears of an oversupply of oil in the market are “exaggerated”, Vandana Hari, chief executive of Singapore-based Vanda Insights, told The National this week. The market is not “seeing the glut and it’s not evident yet in the physical market … it’s exaggerated”, she said.Also, higher supply from Opec+, combined with a seasonal decline in US oil demand, could raise stockpiles in the US, the world's biggest consumer of crude.The US Energy Information Administration on Wednesday said inventories climbed last week on tepid demand and refining activity.US President Donald Trump’s pressure on countries to stop buying Russian crude in an effort to curtail Moscow’s revenue and spending on the Ukraine war is also affecting oil prices. Oil's drop this week also came after prices last week posted their biggest weekly gains since June on Mr Trump's pressure and Ukraine's latest attacks on Moscow's energy infrastructure.
Why OPEC+ will likely hike next month's oil-output quota - even as prices just posted their biggest weekly drop since June -- OPEC+ has been 'swinging an axe [at] oil prices' each time it announces output increases, says Velandera's Manish Raj OPEC+ is scheduled to decide Sunday on oil-production quota levels for November. The major crude-oil producers known as OPEC+ are expected to agree to another monthly hike in oil-output quotas at a meeting this week - despite expectations for a global supply surplus this year and next. Oil prices on Friday tallied their biggest weekly loss since late June. The price drop shows that "surplus fears are back in charge," said Stephen Innes, managing partner at SPI Asset Management. On Friday, U.S. benchmark West Texas Intermediate crude for November delivery (CLX25) (CL.1) settled at $60.88 a barrel on the New York Mercantile Exchange, down 7.4% for the week, according to Dow Jones Market Data. Global benchmark December Brent (BRNZ25) (BRN00) ended at $64.53 on ICE Futures Europe, for a weekly loss of 6.8%. Oil prices are lower because "traders can see the seasonal-demand air pocket," said Innes - referring to the time of year when demand for oil tends to slow and inventories start to tick higher. "No one's chasing scarcity [in supply] here. The market's leaning into the surplus story," he added. 'No one's chasing scarcity [in supply] here. The market's leaning into the surplus story.'Stephen Innes, SPI Asset Management Forecasts from the International Energy Agency show that global oil supplies are poised to outpace global demand in 2025 and 2026. But at a meeting Sunday, OPEC+ - comprised of members of the Organization of the Petroleum Exporting Countries and their allies - is expected to boost crude-production quotas for November, according to the CME's OPEC+ Watch Tool. At a meeting in early September, the group lifted its output quotas for October by 137,000 barrels per day. It had been announcing monthly increases since April, to lift its quotas by a total of about 2.5 million barrels per day through September. October's hike was a "token move," because the bigger issue is that quotas "haven't been barrels for a while," said Innes, explaining that OPEC+ has been producing oil below its quota levels all year. Members have managed to produce "only about three-quarters of what's promised," he noted, leaving "a half-million-barrel hole between paper targets and wet [actual oil] cargoes." "Unless Riyadh or Abu Dhabi open the taps wider, any November increase is just another headline that doesn't move actual flows," Innes said. The International Energy Agency said in a monthly report that as of September, OPEC+ will have ramped up actual crude output by 1.5 million barrels per day since the first quarter of 2025, which would be well below the announced target of 2.5 million barrels per day. OPEC+ has been 'swinging an axe [at] oil prices each time it announces production increases.'Manish Raj, Velandera Energy Partners Still, OPEC+ has been "swinging an axe [at] oil prices each time it announces production increases," said Manish Raj, chief financial officer at Velandera Energy Partners. So far this year, U.S. oil futures have lost 15.1%, while Brent crude is down by 13.6%. Not all OPEC producers have spare capacity, but Saudi Arabia, the United Arab Emirates, Kuwait and Iraq "definitely have barrels to unload," Raj said. There are also likely to be "substantial barrels" coming from newly reopened wells in Kurdistan, where Iraq resumed crude exports in late September after a more than two-year halt, according to a report from Barron's. At the same time, U.S. shale drillers are "pushing the envelope on production," said Raj. Rising rig counts are U.S. drillers' "way of saying that when the going gets tough, the tough get going, he noted, adding that oil at around $60 a barrel is "lucrative enough" for U.S. shale to stay busy. Michael Lynch, president of Strategic Energy & Economic Research, believes that the meeting of major oil producers this weekend is a "test of OPEC+ intentions." They can "forego an increase very easily, since most can't raise production anyway," he said. Given the U.S. government shutdown, economic uncertainty and the recent drop in prices, "that might be the way to go," said Lynch, and would suggest that they "at least want to put a floor on prices." However, if they increase production quotas anyway, that would imply that they "aren't concerned about current and potential price weakness," he added, and that the Saudis potentially see the new Kurdish production as worrisome, as it implies Iraq is going to continue violating its quotas. A minor increase wouldn't really deal with that potential issue, but "could signal Saudi intention to let prices run their course as long as some members don't cooperate," Lynch said.
Saudi Arabia’s Spending Spree Meets Oil Price Reality -Saudi Arabia’s grand Vision 2030 ambitions may be colliding with a colder fiscal reality. Fitch Ratings warned Friday that Riyadh faces rising financial risks as oil prices soften and government spending balloons, threatening the kingdom’s plans for fiscal consolidation.The numbers tell the story: Saudi Arabia now expects a budget deficit equal to 5.3% of GDP in 2025—nearly double its original 2.3% forecast—before narrowing to 3.3% in 2026. The deterioration comes largely from weaker oil income, Fitch said, with non-oil revenues holding up but not enough to offset the gap. The rating agency pointed to revenue shortfalls and overspending as the main culprits, noting the massive capital outlays required by megaprojects like NEOM.This week’s pre-budget statement from Riyadh signaled a shift toward tighter fiscal discipline, but Fitch noted the tension between Saudi’s promises of restraint and its reliance on the Public Investment Fund’s trillion-dollar Vision 2030 agenda. That tension is only magnified by sliding crude prices, with Brentdown more than 7% this week on speculation of further OPEC+ supply hikes.Those hikes are themselves controversial. Reuters sources have floated that Saudi Arabia wants much larger quota increases than Russia, moves that could win back market share but put additional pressure on oil prices. OPEC has already lashed out at the newswire, dismissing reports of a half-million-barrel increase as “wholly inaccurate.” Yet the clash illustrates the stakes: Saudi Arabia’s fiscal health depends on a stable oil market, but its production strategy is geared toward defending long-term relevance, even if that risks lower near-term prices. Fitch said fiscal tightening would ultimately come through modest spending cuts, stable oil revenues, and continued growth in non-oil income. But the kingdom’s vulnerability to oil price swings remains obvious. Vision 2030 may be designed to break the dependence on crude—but for now, Saudi Arabia’s books are still hostage to it.
Russia does not recognise return of UN sanctions on Iran - Russia does not recognise the return of United Nations sanctions on Iran, Russia's UN Ambassador Vassily Nebenzia told reporters on Wednesday when asked if Moscow would enforce the measures. The United Nations reinstated an arms embargo and other sanctions on Iran over its nuclear programme on Saturday evening, following a process - known as snapback - triggered by European powers. Tehran has warned the move would be met with a harsh response. Britain, France and Germany initiated the snapback process at the UN Security Council over accusations Iran had violated a 2015 deal that aimed to stop it from developing a nuclear bomb. Iran denies seeking nuclear weapons. "We do not recognise the snapback as coming into force," he said at a press conference to mark the start of Russia’s presidency of the UN Security Council for October. "We'll be living in two parallel realities, because for some snapback happened, for us it didn't. That creates a problem. How we will get out of it - let's see," Nebenzia said. The end of the decade-long nuclear deal originally agreed by Iran, Britain, Germany, France, the United States, Russia and China could exacerbate tensions in the Middle East, just months after Israel and the US bombed Iranian nuclear sites. "This development is really fraught with a major escalation around Iran, because it opens the door for those countries who want to finish Iran's nuclear program," said Nebenzia, referring to the military action by Israel and the US in June. With the return of UN sanctions, Iran will again be subjected to an arms embargo and a ban on all uranium enrichment and reprocessing activities, as well as any activity related to ballistic missiles capable of delivering nuclear weapons. Other sanctions to be reimposed include a travel ban on dozens of Iranian citizens, asset freezes on dozens of people and entities and a ban on the supply of anything that could be used in the nation's nuclear programme.
Israel Captures Hundreds of Activists Attempting To Bring Food Into Gaza, Including American Citizens - The Israeli military has stopped the Global Sumud Flotilla from breaking its starvation blockade on the Gaza Strip and has arrested hundreds of activists who were on board the vessels, including American citizens, attempting to bring food to starving Palestinians.According to a congressional letter to President Trump calling for the US to guarantee safe passage for the flotilla, which was led by Rep. Rashida Tlaib (D-MI), 24 US citizens were among the activists onboard, including at least six US veterans.Greg Stoker, a contributor to Mint Press News and one of the US veterans participating in the flotilla, was posting regular updates on his X account before he was presumably captured by the IDF.“Israeli Navy trying to spray us with skunk water. Still in international waters Save Gaza,” Stoker wrote on X in his last post, which he said was written at 2:50 am Gaza time on Thursday morning.So far, the US government has been silent about the arrest of its citizens, while some governments and international organizations are speaking out. Irish Prime Minister Micheal Martin said the interception was a “breach of international law” if it happened in international waters.“It’s a humanitarian mission, no threat to anybody other than to highlight and also to bring humanitarian aid into the people of Gaza, and it underlines the absolute imperative of getting humanitarian aid into Gaza as quickly as possible,” Martin said. The Irish government has said that at least 14 Irish citizens, including a senator, have been detained by Israeli forces.Belgium’s Foreign Minister Maxime Prevot said the interception was “unacceptable” and said he summoned the Israeli foreign minister to Belgium. “The manner in which they were boarded and the location in international waters are unacceptable, which is why I summoned the ambassador,” he said.
No comments:
Post a Comment