largest gasoline inventory increase in 24 months leaves gasoline supplies at a 49 week high

US oil prices finished higher for a fourth consecutive week as threats to Russian and Iranian oil exports outweighed prospects of increased crude supplies from Venezuela….after rising 3.1% to $59.12 a barrel last week as traders struggled to sort out the implications of the sudden US takeover of Venezuelan oil output, the contract price for the benchmark US light sweet crude for February delivery rose on global markets​ on Monday following the escalation of protests in Iran, threatening the stability of supplies from OPEC's fourth-largest producer, and on Trump’s declaration of a national emergency to protect revenues from the sale of Venezuelan oil, and continued to trade higher during the US session as traders assessed the geopolitical risks from Iran, Venezuela and Russia that had been driving the recent oil price volatility, and settled 38 cents higher at a seven week high of $59.50 a barrel on worries that Iran's exports would decline as the OPEC member cracked ‌down on anti-government demonstrations…. oil prices continued to climb ​dduring Asian trading early on Tuesday, as markets focused on unrest in Iran and the risk that a U.S. intervention would disrupt suppl​ies from the world's most important oil region, then surged across global markets as traders reacted to escalating drone strikes at the Novorossiysk terminal​ on the Black Sea, which handles roughly 2% of the world's daily supply, raising fears of a prolonged supply squeeze, then extended​ their gains for a fourth consecutive day in New York amid the anti-government demonstrations in Iran and concerns over the potential impact of that on the country’s exports, and settled $1.65 higher at $61.15 a barrel after Trump urged Iranians to continue protesting the regime in Tehran and promised Iranian protesters that help was on the way… oil prices declined on global markets Wednesday, reversing earlier gains, as American Petroleum Institute data showing that US crude oil inventories increased by ​an unexpected 5.3 million barrels outweighed lingering geopolitical concerns in the Middle East, but traded higher in New York after the U.S. urged its citizens to leave Iran immediately, while Iran warned U.S. allies in the Middle East it would strike U.S. bases on their soil if the U.S. attacked Iran, and settled 87 cents higher at a twelve week high of $62.02 a barrel on fears of Iranian supply disruptions due to a potential U.S. attack on Iran and possible retaliation against U.S. regional interests, only to sell off to a low of $59.77 in the post settlement period following Trump’s statement that killings in Iran were halting, quelling market concerns of a possible military operation in Iran…oil prices fell sharply in early Asian trading on Thursday, after U.S. President Trump said that killings in Iran’s nationwide protests were subsiding, easing fears of a U.S. military strike and potential supply disruption in the Middle East, then further extended Wednesday’s late sell off in New York trading after the U.S. was seen adopting a wait and see posture after previously threatening intervention in Iran for the government’s crackdown on protests, and settled $2.83, or 4.56% lower at $59.19 a barrel on concerns that inventories of U.S. crude and gasoline could pile up amid seasonally weak winter demand for fuels amid a wind down in U.S.-Iran tensions…oil prices fell in Asian trading on Friday, extending losses from the previous session, as concerns about supply risks eased after the likelihood of a U.S. strike on Iran receded, but then moved higher on global markets, as supply risks remained in focus despite the receding likelihood of a U.S. military strike against Iran, and settled the New York session 25 cents higher at $59.44 a barrel as some traders covered short positions ahead of the three-day Martin Luther King holiday weekend in the U.S., amid lingering worries about a possible U.S. military strike against Iran, and hence managed to eke out a 0.5% increase for the week…

on the other hand, natural gas prices finished lower for the fifth time in six weeks, as a smaller than expected withdrawal of gas from storage left ample supplies available ahead of an expected cold spell…after falling 12.4% to a ​3 month low of $3.169 per mmBTU last week as traders focused on mild short term weather forecasts amid lower spot prices, the price of the benchmark natural gas contract for February delivery opened 4.2 cents higher on Monday and plodded​ upward into the morning, as traders took advantage of the recently discounted prices, spurred on by the latest short-term forecast, which provided a healthy boost to forecasted HDDs, and settled 24.0 cents higher at $3.409 per mmBTU as weather forecasts swung back in a colder direction to close January, and speculators rotated out of the heaviest short positioning in 13 months…natural gas price opened 1.9 cents higher on Tuesday, and traded within a wide range throughout the session, as traders weighed short-term heating demand against record production, but settled just a penny higher at $3.409 per mmBTU, as abundant supply anchored the market, in spite of forecasts for northern chills…the front-month natural gas contract opened 20.0 cents lower Wednesday after tumbling lower overnight, as traders chose to focus on near-time mild temperatures and healthy storage levels, despite the impending seasonally cold temperatures next week, and ended 29.9 cents lower at $3.120 on chances that a dissipating Alaska ridge would open a milder February risk, and a Webber Research report that Golden Pass LNG Trains 2-3 might be delayed until 2027…natural gas prices opened 2.0 cents lower on Thursday, then fell to a three-month intraday low of $3.006 as a bearish weekly storage report hit the wire, but battled higher into the afternoon to settle 0.8 cents higher at $3.128 per mmBTU, following a bearish EIA inventory report that left supply at healthy levels ahead of coming waves of cold….natural gas futures inched higher overnight into Friday as colder weather signals emerged ahead of the long holiday weekend, but still appeared to be heading for modest week/week losses by midday, as ample supply outweighed supportive forecast trends, and settled 2.5 cents lower at $3.103 per mmBTU, as abundant supplies weighed on prices after Thursday's weekly EIA report showed natural gas storage levels 3.4% above their 5-year seasonal average, and thus ended 2.1% lower for the week..

The EIA’s natural gas storage report for the week ending January 9th indicated that the amount of working natural gas held in underground storage fell by 71 billion cubic feet to 3,185 billion cubic feet by the end of the week, which left our natural gas supplies 33 billion cubic feet, or 1.0% higher than the 3,152 billion cubic feet of gas that were in storage on January 9th of last year, and 106 billion cubic feet, or 3.4% more than the five-year average of 3,079 billion cubic feet of natural gas that had typically been in working storage as of the 9th of January over the most recent five years….the 71 billion cubic foot withdrawal from natural gas storage for the cited week was less than the 89 billion cubic foot withdrawal from storage that the market was expecting ahead of the report, and was much less than the 227 billion cubic foot of gas that were pulled out of natural gas storage during the corresponding week of 2024, and was also less than half of the average 146 billion cubic foot withdrawal from natural gas storage that has been typical for the same early January 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 January 9th indicated that after a sizable increase in our oil imports, we had surplus oil to add to our stored crude supplies for the 15th time in thirty-four weeks, and for the 43rd time in seventy-nine weeks, with a reversal from demand to supply that the EIA could not account for contributing….Our imports of crude oil rose by an average of 752,000 barrels per day to 6,339,000 barrels per day, after rising by an average of 1,387,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 43,000 barrels per day to average 4,306,000 barrels per day, which, when used to offset our imports, meant that the net of our trade of oil worked out to an import average of 2,786,000 barrels of oil per day during the week ending January 9th, an average of 709,000 more barrels per day than the net of our imports minus our exports during the prior week... At the same time, transfers to our oil supplies from Alaskan gas liquids, from natural gasoline, from condensate, and from unfinished oils were 63,000 barrels per day higher at 743,000 barrels per day, while during the same week, production of crude from US wells was 58,000 barrels per day lower than the prior week at 13,753,000 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 17,282,000 barrels per day during the January 9th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,958,000 barrels of crude per day during the week ending January 9th, an average of 48,000 more 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 515,000 barrels of oil per day were being added to the supplies of oil stored in the US… So, based on that reported & estimated data, the crude oil figures provided by the EIA appear to indicate that our total working supply of oil from net imports, from transfers, and from oilfield production during the week ending January 9th averaged a rounded 1​91,000 ​f​ewer barrels per day than what was added to storage plus our oil refineries reported they used during the week. To account for the difference between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a [ + 191,000 ] 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 the week’s oil supply & demand figures that we have just transcribed.…moreover, since 171,000 barrels per day of demand for oil not be accounted for in the prior week’s EIA data, that means there was rounded 361,000 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 also off by that much, and also useless.... But 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 515,000 barrel per day average increase in our overall crude oil inventories came as an average of 484,000 barrels per day were being added to our commercially available stocks of crude oil, while an average of 31,000 barrels per day were being added to our Strategic Petroleum Reserve, extending the string of nearly continuous weekly 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 rose to 6,117,000 barrels per day last week, which was 5.7% less than the 6,487,000 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 58,000 barrels per day lower at 13,753,000 barrels per day because the EIA’s estimate of the output from wells in the lower 48 states was 60,000 barrels per day lower at 13,320,000 barrels per day, while Alaska’s oil production was 2,000 barrels per day ​h​igher at 433,000 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 5.0% higher than that of our pre-pandemic production peak, and was also 41.8% 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 95.3% of their capacity while processing those 16,958,000 barrels of crude per day during the week ending January 9th, up from the 94.7% utilization rate of the week ending December 19th, with higher utilization levels typical near new years, following the end of routine Fall refinery maintenance….the 16,958,000 barrels of oil per day that were refined that week was 1.9% more than the 16,647,000 barrels of crude that were being processed daily during the week ending January 10th of 2025, but less than 0.1% less than the 16,973,000 barrels that were being refined during the prepandemic week ending January 10th, 2020, when our refinery utilization rate was at 92.2%, on the low side of the pre-pandemic normal range for this time of year…

With the modest increase in the​ amount of oil that was refined this week, gasoline output from our refineries was also a bit higher, increasing by 29,000 barrels per day to 9,029,000 barrels per day during the week ending January 9th, after our refineries’ gasoline output had decreased by 472,000 barrels per day during the prior week... This week’s gasoline production was still 2.7% less than the 9,280,000 barrels of gasoline that were being produced daily over the week ending January 10th of last year, and also 2.7% less than the gasoline production of 9,281,000 barrels per day seen during the prepandemic week ending January 10th, 2020….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 19,000 barrels per day to 5,296,000 barrels per day, after our distillates output had increased by 81,000 barrels per day during the prior week. After that relatively small production decrease, our distillates output was still 2.2% more than the 5,183,000 barrels of distillates that were being produced daily during the week ending January 10th of 2024, and 1.7% more than the 5,205,000 barrels of distillates that were being produced daily during the pre-pandemic week ending January 10th, 2020....

With this week’s modest increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the ninth consecutive week, and by the most in 24 months, increasing by 8,977,000 barrels to a 49 week high of 251,013,000 barrels during the week ending January 9th, coming after our gasoline inventories had increased by 7,702,000 barrels during the prior week. Our gasoline supplies increased by more this week even though the amount of gasoline supplied to US users rose by 134,000 barrels per day to 8,304,000 barrels per day, after falling by 379,000 barrels during the week ending December 26h, because our exports of gasoline fell by 108,000 barrels per day to 859,000 barrels per day, while our imports of gasoline fell by 101,000 barrels per day to 448,000 barrels per day… Despite thirty gasoline inventory withdrawals over the past forty-nine weeks, our gasoline supplies were 3.1% higher than last January 10th’s gasoline inventories of 243,566,000 barrels, and about 4% above the five year average of our gasoline supplies for this time of year…

After this week’s modest decrease in distillates production, our supplies of distillate fuels fell for the first time in nine weeks, edging down by by 29,000 barrels to 129,244,000 barrels during the week ending January 9th, after our distillates supplies had increased by 5,594,000 barrels to a 51 week high during the prior week..… Our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of domestic demand, rose by 901,000 barrels to 4,096,000 barrels per day, and even as our imports of distillates rose by 13,000 barrels per day to 220,000 barrels per day, while our exports of distillates fell by 102,000 barrels per day to 1,425,000 barrels per day... With 56 withdrawals from distillates inventories over the past 102 weeks, our distillates supplies at the end of the week were 2.1% less than the 132,015,000 barrels of distillates that we had in storage on January 10th of 2025, but about 4% below the five year average of our distillates inventories for this time of the year…

Finally, after the big increase in our oil imports, our commercial supplies of crude oil in storage rose for the 13th time in twenty-six weeks, and for the 31st time over the past year, increasing by 3,391,000 barrels over the week, from 419,056,000 barrels on January 2nd to 422,447,000 barrels on January 9th, after our commercial crude supplies had decreased by 3,832,000 barrels over the week ending January 2nd… After this week’s increase, our commercial crude oil inventories were still 3% below the recent five-year average of commercial oil supplies for this time of year, while they were about 31% above the average of our available crude oil stocks as of the second weekend of January over the 5 years at the beginning of the past decade, with the big difference between those comparisons arising because it wasn’t until early 2015 that our oil inventories had first topped 400 million barrels. After our commercial crude oil inventories had jumped to record highs during the Covid lockdowns in the Spring of 2020, then jumped again after February 2021’s winter storm Uri froze off US Gulf Coast refining, but then fell sharply due to increased exports to Europe following the onset of the Ukraine war, only to jump again following the Christmas 2022 refinery freeze-offs, changes in our commercial crude supplies have generally leveled off since, and as of this January 9th were 2.4% more than the 412,680,000 barrels of oil left in commercial storage on January 10th of 2025, but were 1.7% less than the 429,911,000 barrels of oil that we had in storage on January 12th of 2024, and 5.7% less than the 448,015,000 barrels of oil we had left in commercial storage on January 13th of 2023…

This Week's Rig Count

The US rig count was down by one over the week ending January 16th, the 7th decrease in twenty weeks, as the number of rigs targeting natural gas was down by two, while the count of rigs targeting oil was up by one, and miscellaneous rigs were unchanged…for a quick snapshot of this week's rig count, we are again including below a screenshot of the rig count summary pdf from Baker Hughes...in the table below, the first column shows the active rig count as of January 16th, the second column shows the change in the number of working rigs between last week’s count (January 9th) and this week’s (January 16th) count, the third column shows last week’s January 9th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday of the same week of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting period a year ago, which in this week’s case was the 17th of January, 2025…

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Ohio's Shale Energy Industry Attracts $3.5B in Direct Investment in Second Half 2025 -- A study published today by Cleveland State University’s Levin College of Public Affairs and Education shows Ohio’s shale-energy sector drew approximately $3.5 billion in fresh capital between July and December 2024, pushing cumulative investment since 2011 to $114.6 billion. Commissioned by JobsOhio, the bi-annual Shale Investment Dashboard captures direct spending across the upstream, midstream and downstream segments of the industry. “Ohio’s rich shale resources continue to attract billions in investment, reflecting global confidence in our exceptional workforce, infrastructure and business climate,” said JobsOhio President & CEO J.P. Nauseef. “Adding more than $3 billion in just six months demonstrates how abundant, low-cost natural gas is helping power our economy and strengthen our nation’s energy security.” Overall upstream investments were up by about $615 million in the second half of 2024 compared to the first half of 2024, reflecting continued growth in drilling activity, especially for oil-producing wells, with new wells accounting for 29% of the 19.3 million barrels of oil produced overall during the study period. Despite softening oil prices, continued production efficiencies—driven in part by artificial intelligence and by the Utica’s structural cost advantages relative to other shale regions—are likely to sustain oil-related development, which accounted for more than 10% of total gas-equivalent production in the first half of 2025. Of the 191 new wells developed during the second half of 2024—the highest six-month total since 2017—more than 70 percent were located in the oil-producing portion of the Utica shale play. Belmont County led all counties in production for the third consecutive study period. Guernsey County had the highest number of new wells developed, largely within the Ohio Utica’s volatile oil window, which has seen consistently increasing activity since the first half of 2023. Midstream investment reached $280.1 million in the second half of 2024, up from $235.8 million in the first half of the year. This continues a pattern of elevated spending: six-month totals have consistently averaged well over $200 million since the first half of 2023. Midstream investment during the study period went toward infrastructure and transportation, with $124.4 million spent on gathering lines and $155.7 million on compression. Construction began in 2025 on more than 30 miles of high-pressure intrastate pipeline, consisting of multiple projects undertaken to deliver gas to power generation facilities serving data centers in central Ohio. There was little downstream investment in the second half of 2024, with $1.8 million in liquified petroleum gas fueling stations opening throughout the state; however, growth in demand for electricity—particularly by data centers—is accelerating the development of gas-fired generation in Ohio and may continue to do so in the coming years. As long as wholesale power prices remain sufficiently above the delivered cost of gas, market conditions will continue to support investment in gas-fired generation. "Oil development continues to play an expanding role in upstream investment. While downstream activity remained subdued, reforms enacted under Ohio HB 15 are expected to support future gas-fired generation and downstream investment,” said Mark Henning, research supervisor at Cleveland State. “Ohio’s regional cost structure and evolving regulatory framework position the state to navigate ongoing uncertainty in the energy sector." These benchmarks reaffirm JobsOhio’s commitment to converting the state’s natural gas advantage into high-value jobs, resilient supply chains and competitive energy costs. The Shale Investment Dashboard will continue to be updated every six months, offering policymakers, investors and communities an authoritative lens on capital flow and the long-term economic impact of Ohio’s energy leadership.

Save Ohio Parks warns against expanding frack leases under public lands - Environmental advocates and Ohioans converged in Columbus on Monday to call out the environmental havoc that extending lease terms to frack Ohio’s state parks and public lands will cause Ohio’s air, water, soils, biodiversity—and future generations. Save Ohio Parks, Freshwater Accountability Project, Buckeye Environmental Network, and Third Act Ohio were among environmental groups speaking to Oil and Gas Land Management Commissioners directly for the first time allowed them in three years about the myriad of dangers that await the state as it expands natural gas fracking under Ohio’s state parks and public lands. They had a lot to say. Topics included:

• The undemocratic legislative process used to pass the state law that mandates fracking Ohio public lands;
• Potential drinking water contamination in Washington County, Ohio, where injection wells storing toxic, radioactive gas and oil wastes are communicating with conventional oil wells, threatening rural drinking water wells and groundwater;
• Fracking and injection well-caused earthquakes;
• Destruction of biodiversity and habitat from fracking that could cause the extinctions of endangered Indiana bats, eastern hellbenders and eastern black bears;
• Methane gas emissions from natural gas production and utility use that cause rare cancers in young children, increase respiratory disease and accelerate climate warming and climate change.

Speakers peppered their testimony with personal stories, research, statistics and emotions ranging from anger to appeals to love the planet and future generations of young people. But expressionless members of the Ohio Oil and Gas Land Management Commissioners asked no questions and unanimously voted 4-0 to award Grenadier Energy III LLC of The Woodlands, Texas rights to frack 171 acres of Leesville Wildlife Area in Carroll County. Commissioners accepted $6,000 per acre, or $1 M, plus a 12.5 percent royalty and 5.5 percent of production as an additional financial incentive. Commissioners also rubberstamped nominations 4-0 in repeated votes to advance bidding next quarter on more than 4,726 acres to frack Egypt Valley Wildlife Area in Belmont County and 1,842 acres in Jockey Hollow Wildlife Area in Belmont and Harrison counties. They also advanced to bid in the next quarter eight acres across the street from the Noble County Correctional Institution in Noble County and 11 rights-of-way along state highways. The wildlife areas targeted are popular hunting, fishing, hiking and birding areas re-claimed by conservation groups from coal mining over the past 30 or more years. In a move many environmentalists and the public consider a sell-out to the gas and oil industry, the Ohio state legislature and Gov. Mike DeWine made the Ohio Department of Natural Resources (ODNR) dependent on fracking for half of its state parks budget beginning in 2027. Save Ohio Parks organized a 30-member coalition in early 2025 calling for Gov. Mike DeWine to declare a statewide moratorium on fracking Ohio’s state parks and public lands. DeWine has refused to meet with them or discuss the issue despite more than 7,000 public comments uploaded to the OGLMC website against fracking public lands. Typically, 98 percent of comments uploaded onto the OGLMC website oppose fracking Ohio public lands. Save Ohio Parks was formed in 2023, after 135 pages of last-minute amendments were tacked onto H.B. 507, a bill originally created to limit the number of poultry chicks allowed in a shipment. The bill passed into law during a lame duck session. It falsely defined polluting fracked gas (ie: natural gas) a “green energy” and mandated fracking under state parks and public lands. It was one of the first bills DeWine signed into law after his re-election as governor. DeWine’s campaign was aided by a $500,000 FirstEnergy donation to State Solutions, a dark-money group connected to the Republican Governors Association. Leatra Harper, director of Freshwater Accountability Project and an advocate for fresh water since 2012, said the magnitude of environmental and public health damage from fracking is already evident and will likely only get worse as the negative impacts of fracking increase. “The state of Ohio’s lack of adequate regulation and oversight has never addressed the cumulative contamination impacts of this industry, which are compounded by the negative impacts of methane emissions warming the atmosphere and accelerating climate change; toxic, radioactive brine-spreading on roads; and gas and oil well pad explosions,” she said. “We who follow the science know that pollution from fracking is definitely affecting the health of our children and grandchildren here in Ohio,” said Judy Smucker of Third Act Ohio. “Especially here in Ohio, where we are now known as the dumping ground of America– the dumping ground for other states to come and add their fracking forever- chemicals into Ohio injection wells.” Melinda Zemper of Save Ohio Parks said she received what she considers inadvertent advice from ODNR director Mary Mertz last summer following a roundtable discussion Mertz participated in at an environmental education conference for children. “Ms. Mertz told me that if we wanted change regarding fracking our state parks and public lands, we needed to change the state legislature,” said Zemper. “I think she’s right. We need legislators in power in all offices, from local township officials to city council members, to county commissioners, state reps and senators on up to the governor’s office who commit to protecting clean air, water, soils, and biodiversity throughout the state, as well as in and under our public lands. “We are at the very beginning of an existential global climate crisis and must use all technology and renewable energy solutions available to reduce carbon emissions and enjoy cleaner water, decent air and healthy soils. Ohioans need pristine nature in our state parks and wildlife areas, and to be convinced to want to remain living in Ohio. “The science is clear, no matter what supermajority politicians may say: fossil fuels and fracking need to be phased out quickly and cheap, reliable, renewable energy ramped up quickly in order to mitigate the worst effects of climate change.” No other state in the country allows fracking of its state parks, said Cathy Cowan Becker, board president at Save Ohio Parks. “Our parks and wildlife areas were set aside for the use and enjoyment of all Ohioans. These lands are meant to be protected. Fracking them is a betrayal of the public trust and future generations.”

Ohio OGLMC Awards Contract to Drill Under Leesville Wildlife Area - Marcellus Drilling News - Yesterday, the Ohio Oil & Gas Land Management Commission (OGLMC) met in a public forum in Columbus and voted to open another 6,570 acres of state-owned wildlife land (in Belmont and Harrison counties) to allow bids to frack under (not on top of) those areas. The Commission also awarded a contract to Grenadier Energy to drill under another wildlife area in Carroll County, 172 acres of the Leesville Wildlife Area. The state is getting an amazing $6,000 signing bonus, equaling $1.03 million, plus big royalties!

Why are we fracking Ohio's only national forest? - Randi Pokladnik - The acreages that make up the Wayne National Forest in Southeastern Ohio are a patchwork of land parcels which lie in 12 Ohio counties. In the 1800s, the region was heavily logged to supply wood for 46 charcoal furnaces used for iron smelting. Farming also damaged the landscape as the remaining areas were cleared for agriculture, causing destructive soil erosion.Nature, time, and help from the Civilian Conservation Corps in the 1930s helped restore the second-growth forests we see today.Sadly, the oil and gas industry is seeking to frack parcels within the wooded areas, possibly destroying the vibrant mesophytic ecosystem that has evolved over the last nearly 100 years. The Bureau of Land Management (BLM) will be accepting oil and gas leasing applications in September 2026 for 41 oil and gas parcels, totaling 2,795 acres. These parcels of the Wayne are located in Monroe and Washington Counties. More than 85% of Ohio forests are privately owned, making the Wayne National Forest very important for Ohio residents and non-residents.This forest remains a sanctuary for people who need an escape from their hectic lives. Visitors find peaceful settings, as well as spaces for recreating, bird watching, and fishing in the natural environment provided by the Wayne.There are hundreds of miles of hiking trails, horse riding trails, mountain biking trails, and off-road vehicle trails. Over a quarter million visitors find their way to the Wayne every year. The Little Muskingum River flows through the middle of the Marietta Unit of the forest. It “has an exceptional warmwater quality designation” and species like the rare river otter and the state endangered Ohio lamprey make their homes in the river. Additionally, the Wayne is critical habitat for the eastern hellbender salamander, a species which has been proposed for listing as an endangered species. When speaking of fracking in Ohio’s State Parks in 2024, then-state Rep. Don Jones said, “You will never know where fracking has occurred”. I strongly disagree.I live in Harrison County, one of the most fracked areas of Southeastern Ohio.Well pads and fracking infrastructure have taken over the rural landscape.Examining areas around the towns of Scio, Cadiz, and Jewett via a satellite image with Google Maps reveals over 179 well pads in the county. These appear like small white squares on the Google landscape map, but if you zoom in on these pads, you will see some of the infrastructure associated with fracking; large storage containers, wells, compressors, roads, and often the outline of pipelines crossing through the areas. These well pads are not reclaimed because many times wells are often re-fracked.What was once a region of rural beauty has become an industrial zone, as fracking eats away at the wooded hills like metastatic cancer. Fracking significantly impacts forests, as land is altered for well pads, roads, pipelines, and other infrastructure. Research shows that up to 19 acres per well pad is needed for gathering lines. In addition to gathering pipelines, there are transition pipelines, and distribution pipelines, as well as roads to the well pads. The construction of this infrastructure results in clearcutting of the forested area, which leaves gaps in the forest canopy. Think of it as death by a thousand cuts. The Halliburton loophole legislation of 2005 exempted natural gas drilling from most federal regulations created to protect human health and the environment.Companies are exempt from disclosing the chemicals used during hydraulic fracturing but an EPA assessment reported there were at least 1,606 chemicals used in fracking that could impact drinking water. Leaks, spills, and runoff from operations threaten groundwater and surface water quality, impacting aquatic ecosystems. Billions of gallons of radioactive waste brine are generated by the industry.This brine, although toxic in nature, is exempt from the Resource Conservation and Recovery Act.Every day “brine” tankers travel through fracked communities to deliver the toxic brew to Class II injection wells.Fracking the Wayne, especially in the Washington County region, could mean more Class II wells for an area already dealing with well contamination issues from brine infiltration into production wells. The process of high-pressure hydraulic fracking requires 1.5-16 million gallons of water per well.In Ohio, a facility is allowed to withdraw surface water in the amount of “up to two million gallons per day in any thirty-day period without first obtaining a permit from the chief of the division of water resources under section 1521.29 of the Revised Code.” Ohio saw record droughts in the summers of 2024 and 2025. Counties where fracking is ongoing experienced extreme and exceptional droughts in 2024. Withdrawing water from streams decreases volume, increases pollution concentrations, increases water temperatures, decreases dissolved oxygen, and affects the pH, making streams less habitable for aquatic organisms.Surface water will no doubt be withdrawn from the local streams in the Wayne National Forest. Fracking creates air pollution that can seriously impact wildlife.A Colorado study revealed that exposure to air pollution from fracking could cause neurological problems, respiratory diseases, and cancer in wild animals.Some of the compounds released during fracking include benzene, a known carcinogen, as well as xylenes and nitrogen oxides.Studies show these compounds can cause cancers, particularly if exposure occurs within a 0.5-mile radius of a well pad. There are additional issues that will impact the rural area that makes up the Wayne National Forests.The hydraulic fracturing process requires 2,300 to 4,000 truck trips per well. Many of the roads in rural areas are not built to withstand the amount and weight of these trucks and additional traffic has resulted in an increase in vehicular accidents.Anthropogenic noise from fracking reduces habitat quality and interferes with communication for species that rely on acoustic communication.The bright lights on the drilling rigs and pads can significantly impact birds, especially during migration.A 2020 study shows “shale oil and gas production reduces subsequent bird population counts by 15%, even after adjusting for location and year fixed effects, weather, counting effort, and anthropic land-use changes.” Ohio’s Republican legislature and Gov. Mike DeWine sacrificed our state parks to fracking during a lame duck session in 2022.Without any public comment period, our parks were opened up for fracking. Now our only national forest and the rural communities surrounding it will become a new sacrificial zone.The BLM says on its page, “The preliminary parcel list is not subject to protests or appeals.”At the very least, we need to let our concerns be known to the Bureau of Land Management. Allowing our natural resources in Southeast Ohio to be exploited to supply power for data centers or to be exported out of the country is not ecologically or economically sustainable for our region.

Ohio Judge Adds $28M in Fines Against Austin Master Services - Marcellus Drilling News - One of the significant stories of 2024 in the Ohio Utica was about Austin Master Services (AMS), a radiological waste management solutions company in Martins Ferry, Ohio, that processes and transports fracking waste for disposal. AMS ran into trouble when it ran out of money. The Martins Ferry facility in Belmont County, where waste is temporarily stored, had vastly exceeded its permitted limit of 600 tons (storing over 10,000 tons), resulting in a permit violation. The Ohio Attorney General’s office filed a lawsuit against the company in March 2024 to compel compliance and require the company to clean up the facility. After the company didn’t perform, the Ohio Department of Natural Resources (ODNR) stepped in to handle the cleanup (seeAustin Master Services Ohio Frack Waste Cleanup Complete Today). The AG’s office sued for $6 million to cover the cost of cleanup, and last November, a Belmont County court ruled in favor of the state (see Ohio Judge Rules Against Austin Master Services for $6.2 Million). The judge has just issued a second ruling imposing a $ 10,000-per-day fine for the time the facility was out of compliance. It adds up to another $28+ million.

EOG's "Profound Shift" in Identity from Oil to Premier Gas Producer - Marcellus Drilling News -Last year, Houston-based EOG Resources acquired Encino Acquisition Partners for $5.6 billion, establishing the Utica Shale as a “third foundational play” alongside its Permian and Eagle Ford assets (see EOG Closes on $5.6B Purchase of Encino Assets in Ohio Utica). As the energy sector navigates a complex landscape of fluctuating oil prices and surging electricity demand, EOG Resources has officially entered 2026 with a strategy that signals a profound shift in its corporate identity. Using the Utica (and Eagle Ford), EOG is now positioning itself as a premier natural gas powerhouse.

The Gas Inflection: EOG Resources Pivots Toward AI and LNG as 2026 Strategy Takes Shape - As the energy sector navigates a complex landscape of fluctuating oil prices and surging electricity demand, EOG Resources (NYSE: EOG) has officially entered 2026 with a strategy that signals a profound shift in its corporate identity. Long considered the "Apple of Oil" for its technical prowess and focus on high-return crude plays, the company is now positioning itself as a premier natural gas powerhouse. By prioritizing capital discipline and high-margin gas assets like the Dorado and Utica plays, EOG aims to capture the dual tailwinds of the global LNG export boom and the domestic power hunger driven by artificial intelligence and data centers.The transition comes at a critical juncture for the company. While EOG’s stock has faced headwinds in late 2025—trading near 52-week lows in the $102–$107 range—management remains steadfast in its refusal to chase production volume. Instead, the 2026 outlook is defined by a rigorous $6.5 billion capital expenditure plan and a commitment to return at least 70% of free cash flow to shareholders. This "returns-first" approach is designed to weather short-term market volatility while setting the stage for a massive demand uptick as major export and power projects come online later this year.EOG’s 2026 roadmap is the culmination of a multi-year effort to build a "gas company within a company." The timeline of this transformation reached a fever pitch in 2025, which CEO Ezra Yacob described as the "inflection year" for the company’s gas business. This strategy was anchored by two major moves: the aggressive development of the Dorado dry-gas play in South Texas and the $5.6 billion acquisition of Encino Energy’s Utica Shale assets in Ohio. These regional "islands" were chosen specifically for their proximity to high-demand hubs—the Gulf Coast for LNG and the Eastern U.S. for power generation. As of January 9, 2026, the market is closely watching the commencement of EOG’s supply agreement with Cheniere Energy (NYSE: LNG) for the Corpus Christi Stage 3 project. Expected to begin in late 2026, this deal will see EOG supply up to 720,000 MMBtu/d of natural gas, with pricing linked to the Japan-Korea Marker (JKM). This move effectively decouples a significant portion of EOG’s revenue from the volatile domestic Henry Hub price, allowing the company to capture international margins. Initial industry reactions have been mixed; while analysts praise the move toward global pricing, some investors remain cautious about the "low-to-flat" oil production guidance for the year, which prioritizes financial health over raw growth.The primary winner in this strategic shift is undoubtedly EOG itself, provided it can execute its "direct-to-customer" vision. By controlling its own infrastructure, such as the 1 Bcf/d Verde Pipeline, EOG can bypass midstream bottlenecks that plague smaller operators. Furthermore, Cheniere Energy (NYSE: LNG) stands to benefit from a reliable, low-cost supply of gas from EOG’s Dorado play, ensuring the operational success of its Stage 3 expansion. Tech giants and hyperscale data center operators may also emerge as winners, as EOG’s "standalone" gas assets offer a level of reliability and dedicated supply that "associated gas" (gas produced as a byproduct of oil) simply cannot match.On the other side of the ledger, traditional oil-focused peers like Devon Energy (NYSE: DVN) and Diamondback Energy (NASDAQ: FANG) may face pressure to justify their capital allocation strategies if EOG’s gas pivot begins to yield higher-margin returns. Companies heavily reliant on domestic Henry Hub pricing may also find themselves at a disadvantage compared to EOG’s diversified international exposure. However, the broader industry faces a collective challenge: the slow pace of regulatory approvals for new pipelines and power plants. If infrastructure development fails to keep pace with EOG’s production capabilities, the company could find itself with an abundance of "stranded" gas, potentially depressing local prices and hurting short-term earnings.EOG’s strategy is a direct response to two of the most significant trends in the modern economy: the electrification of everything and the globalization of natural gas. The rise of AI and hyperscale data centers has created a "reliability premium" for energy. Unlike renewable sources, which are intermittent, natural gas provides the 24/7 baseload power required by the massive server farms currently being built in "Data Center Alley" and the Midwest. By positioning its Utica assets near these hubs, EOG is betting that tech companies will pay a premium for a dedicated, "behind-the-meter" fuel source.This shift mirrors broader industry trends seen by giants like Exxon Mobil (NYSE: XOM), which has also increased its focus on LNG and global gas markets. Historically, natural gas was treated as a secondary commodity in the U.S., often flared or sold at a loss to get to the more valuable oil. EOG’s 2026 outlook represents a definitive break from this past, treating gas as a high-value, strategic asset. This "multi-basin" approach—balancing oil for cash flow and gas for growth—is likely to become the blueprint for the modern E&P company in an era of decarbonization and digital expansion.In the short term, investors should expect EOG to focus on "cost efficiencies" and the full integration of its Utica acreage. The company has already signaled a move toward a "full-time" rig program at Dorado, which is expected to drive down well costs by 15% or more through economies of scale. The real test will come in the second half of 2026, as the Cheniere Stage 3 project nears completion. Any delays in this infrastructure would be a significant setback for EOG’s international pricing strategy.Longer term, the potential for direct contracts with "hyperscalers"—the Googles and Microsofts of the world—could re-rate EOG’s stock. If the company can secure long-term, high-value contracts to supply gas directly to private power plants serving data centers, it would transform EOG from a commodity price-taker into a critical infrastructure partner for the tech industry. However, the company must navigate a complex regulatory environment and potential political shifts that could impact LNG export permits or domestic pipeline construction.

21 New Shale Well Permits Issued for PA-OH-WV Jan 5 – 11 - Marcellus Drilling News - A return to normalcy last week for permits issued to drill new shale wells in the Marcellus/Utica. Two weeks ago, we reported that just one new permit was issued (see M-U Issues Just One New Permit Last Week, Dec 29 – Jan 4). As promised, we double-checked to be sure there wasn’t a lag in posting permits by the various environmental agencies. There were no new permits (except the one) for two weeks ago. As for last week, Jan. 5 – 11, Pennsylvania issued 12 new permits, Ohio issued 2, and West Virginia issued 7. Among the drillers receiving new permits last week: Antero, Ascent, CNX, EQT, HG Energy, Repsol, and Seneca Resources. ANTERO RESOURCES | ASCENT RESOURCES | CNX RESOURCES | QT CORP | GREENE COUNTY (PA) | HARRISON COUNTY | HG ENERGY | JEFFERSON COUNTY (OH) | LEWIS COUNTY | LYCOMING COUNTY | REPSOL | SENECA RESOURCES | TIOGA COUNTY (PA) | WASHINGTON COUNTY

Expand Energy CEO: Drillers Won’t Add New Production at $3.50 Gas- Marcellus Drilling News - Expand Energy CEO Nick Dell’Osso was recently interviewed at the Goldman Sachs Energy, Clean Tech & Utilities Conference held in Miami, Florida, on Jan. 6. During the talk, Dell’Osso outlined Expand’s strategy following the merger of Chesapeake Energy and Southwestern Energy, emphasizing that even if natural gas prices reached the $3.50/MMBtu range, the company would remain disciplined and likely prioritize shareholder returns (such as dividends and buybacks) over aggressive production growth. With respect to the price of gas, he said this of producers in general: “But if we continue to have pricing that hangs around $3.50, I just don’t think you have a producer that is motivated for growth. I think the marginal breakeven for growth in this country is above $3.50.”

Current Pipeline Restrictions & Flow Orders Affecting the M-U Region- Marcellus Drilling News - As we’ve often noted, the NYMEX futures price and spot (physically traded) prices often move in tandem. It’s not a direct, one-to-one relationship, but when futures prices fall, spot prices tend to fall too. Most often, the reason is the weather. However, other factors can influence regional spot prices. In the Marcellus/Utica region, pipeline constraints sometimes contribute to lower prices. If we can’t get our molecules to other markets, they pile up, and the price goes down. There seems to be some of that at play right now

When It Comes To C3, Think in Thirds - When it comes to understanding propane markets, you can think about it in thirds. It just so happens that about one-third of total hydrocarbon liquids (crude + natural gas liquids) produced in the U.S. are NGLs. About one-third of those NGLs (ethane, propane, butanes and pentanes+) are propane. Around one-third of that propane is consumed domestically while the rest is exported (green area in pie chart below). Of the one-third of propane that's consumed domestically, one-third of that is used as a petrochemical feedstock to make olefins (light blue and light purple slices in the pie chart below) and a little less than one-third of that petchem demand is from propane dehydrogenation facilities (PDH; pink slice), which convert propane to propylene. This wasn’t even one-third of what was covered in today’s Propane Master Class hosted by Rusty and David Braziel. Did you miss it? Not to worry, we will make an encore version available later this week. Click here for more information.

Talen Energy to Acquire PJM Gas-Fired Power Plants for $3.45 Billion Talen Energy has agreed to acquire 2.6 GW of gas-fired generation in the PJM market for $3.45 billion, expanding its Ohio and Indiana footprint and positioning the company for growing data center power demand. (P&GJ) — Talen Energy Corporation has signed definitive agreements to acquire approximately 2.6 GW of natural gas–fired generation capacity in the PJM market for $3.45 billion, expanding its footprint in Ohio and Indiana. The deal includes the Waterford Energy Center and Darby Generating Station in Ohio, along with the Lawrenceburg Power Plant in Indiana, acquired from Energy Capital Partners. Talen said the acquisition significantly strengthens its presence in western PJM and adds efficient baseload capacity to its fleet. The purchase price consists of about $2.55 billion in cash and roughly $900 million in Talen stock, valuing the transaction at an estimated 6.6x 2027E adjusted EBITDA. The company expects the acquisition to be immediately accretive to adjusted free cash flow per share by more than 15% annually through 2030. “This acquisition further diversifies Talen’s generation portfolio by adding both baseload capacity and strong cash flow contribution and enhances our presence in the western PJM market, which has significant data center tailwinds,” said Mac McFarland, Talen chief executive officer. “The transaction is immediately cash flow accretive and maintains our balance sheet discipline. Following on the heels of our acquisition of Freedom and Guernsey in 2025, it is another great example of our ‘Talen flywheel’ strategy.” The Lawrenceburg (1,218 MW) and Waterford (869 MW) plants are combined-cycle gas turbines with average heat rates of about 7,000 Btu/kWh and capacity factors exceeding 80%. Darby, a 480-MW facility, operates as a peaking unit, providing additional operational flexibility. All three plants have access to Marcellus and Utica shale gas supplies. “When this transaction is complete, Talen will have approximately doubled its expected annual generation output inside of two years, meaningfully diversified our fleet, and materially increased our free cash flow per share,” said Terry Nutt, Talen president. “We are also excited to welcome ECP as a significant Talen shareholder.” ECP will receive approximately $900 million of the purchase price in Talen equity, becoming a significant shareholder after closing. “ECP invested in this portfolio to serve rapid load growth in the Ohio region with efficient, baseload natural gas assets; we continue to believe this is PJM's most exciting narrative,” said Andrew Gilbert, ECP partner. “Talen has demonstrated that its platform of scale is uniquely positioned to serve PJM’s large customers and, with this transaction, will only be better positioned to do so.” Talen expects to fund the cash portion of the acquisition with new debt and said strong pro forma cash flows should support rapid deleveraging, targeting net leverage of 3.5x or lower by the end of 2026. The transaction is expected to close in early second-half 2026, subject to regulatory approvals, including clearance from the Federal Energy Regulatory Commission, the Indiana Utility Regulatory Commission and review under the Hart-Scott-Rodino Act.

Gulfport Energy Insider Sells $881K as Stock Trails S&P 500 This Past Year -- This natural gas and oil producer, active in Ohio and Oklahoma, reported a significant insider sale in its latest SEC filing. Lester Zitkus, a senior vice president at Gulfport Energy Corporation, directly sold 4,745 shares in multiple open-market transactions on Jan. 7 for a total consideration of approximately $881,087.70, as disclosed in a recent SEC Form 4 filing. The transaction disposed of 37.76% of Zitkus's directly held shares, a material reduction in ownership compared to his previous post-transaction balances.No indirect holdings or derivative securities were involved; all shares were sold from Zitkus's direct account, with no activity via trusts or options. This sale of 4,745 shares exceeds the recent-period median sell size of 3,329 shares, indicating a slightly larger than typical disposition. Post-transaction, Zitkus holds 7,821 shares directly, valued at approximately $1.45 million as of the Jan. 7 market close. Gulfport Energy Corporation produces and markets natural gas, crude oil, and natural gas liquids, with principal operations in the Utica Shale (Ohio) and SCOOP (Oklahoma) regions.The firm generates revenue through the exploration, development, and sale of hydrocarbons from owned and operated reserves.Gulfport Energy Corporation is a U.S.-based independent exploration and production company focused on natural gas and liquids-rich resource plays. With a significant acreage position in the Utica Shale and SCOOP, the company leverages technical expertise to maximize recovery and operational efficiency. While the percentage involved here might sound large, the absolute dollar value remains modest relative to executive compensation more generally, and though the sale is slightly above his recent median transaction size, it's not out of character based on Zitkus' selling history over time. It's also important to note that, operationally, Gulfport’s latest quarterly report shows a business still generating meaningful cash. Third-quarter net income totaled $111.4 million, with $213.1 million in adjusted EBITDA and more than $100 million in adjusted free cash flow. Management also reiterated plans to repurchase roughly $325 million of equity throughout last year while maintaining leverage at or below one times.

Rumor Mill Lights Up: Coterra Considers Merger with Devon Energy - Marcellus Drilling News - The rumor mill is in overdrive today with news that Coterra Energy is in serious talks with Devon Energy exploring a potential merger “that would be among the biggest oil and gas deals in years.” While the primary driver of this deal is gaining massive scale in the Permian Basin, Coterra’s substantial Marcellus Shale assets in northeastern Pennsylvania (NEPA) are a major point of speculation for analysts and investors. It appears possible (likely?) that a combined company would sell off the PA Marcellus assets.

Leetonia neighborhood evacuated after crew strikes natural gas line - A contractor crew near the intersection of Lisbon and Somer streets in Leetonia has struck a gas line, and homes were being evacuated. The crew hit a running fiber optic line with a mole machine. "There was definitely concern of it blowing up," Jason Hephner, Leetonia assistant fire chief said. "It was extremely dangerous, we had a large volume of gas filling the area, filling homes, so it was you know, very volatile," he said. For several hours firemen were on scene working with Columbia gas, finally sealing the leak just before 8p.m. "It was backing up into the sewer system and we did have a few houses that we detected gas in the basement so we did evacuate this street just as precaution," Hephner said. Hephner adds, they were working on getting all 32 homes checked on Somer street before restoring the power. At about 9:40 Wednesday night, firefighters were letting residents back into their homes. Leetonia Fire and EMS also sent an "urgent message" in a Facebook post asking residents of street addresses 349, 345, 343, 337, 342, 346, 350, 351, 358, 362, 366, 370 and 374 to return home so the departments are able to check that their natural gas levels are at zero. Leetonia Police Dispatch told 21 News that homes within a 500-foot radius of the gas leak were being evacuated. Firefighters posted on their Facebook page asking Leetonia residents to stay indoors and not to smoke in homes near Lisbon and Somer streets.

Law Firm for Ascent Resources Bd. Accused of Conflict of Interest - Marcellus Drilling News - The bidding war for Ascent Resources continues and gets more complex. Law firm Kirkland & Ellis has been drawn into a dispute between Ascent Resources investors and the private equity firm Energy & Minerals Group (EMG). Mason Capital Management is questioning Kirkland & Ellis’s role representing the Ascent board while also advising EMG in its legal fight with the Abu Dhabi Investment Council. The dispute concerns EMG’s plan to put Ascent into a “continuation vehicle,” which Mason Capital and other investors have opposed. Other companies have since jumped in to make bids to take over Ascent.

Kirkland & Ellis Accused of Conflict in Private Equity Spat - Law firm Kirkland & Ellis has been drawn into a dispute between investors of Ascent Resources and the private equity firm that’s seeking to raise a continuation fund to prolong its hold on the natural gas producer.Mason Capital Management questioned the law firm’s role representing the Ascent board while also advising the private equity firm, Energy & Minerals Group, in its legal fight with another Ascent investor, the Abu Dhabi Investment Council, according to a letter seen by Bloomberg.Last month, the Mideast sovereign wealth fund sued to stop EMG from shunting Ascent into a continuation vehicle amid disagreements over the valuation of the portfolio company and the process surrounding the proposed fund. The two sides agreed to pursue arbitration, and the continuation fund can’t close until that’s resolved. Ascent, based in Oklahoma City, operates in Ohio’s Utica shale basin and is that state’s largest natural gas producer, according to the company’s website. “Managers may not reasonably rely on conflicted advisers whose interests are aligned with a controller pursuing a challenged transaction,” Mason wrote in the letter dated Monday and addressed to Ascent’s board, which is led by Chairman and Chief Executive Officer Jeff Fisher. Five of the 12 board members are EMG executives. Ascent and Kirkland & Ellis didn’t reply to messages seeking comment. Mason declined to comment. Kirkland & Ellis topped the deals and private equity league tables last year, according to its website. The firm serves more than 800 private equity firms, advising on a variety of matters, including fund formation, fundraising, buyouts, take-privates, recapitalizations and deal exits. The dispute over the sale concerns an increasingly popular, sometimes controversial asset-shuffling technique that allows managers to extend their bets on long-held companies. The strategy gained traction amid a tough environment for asset sales, though some critics have said it poses conflicts when private equity firms are on both sides of the transaction.In the case of Ascent, the board “stifled a fair and open process” to evaluate options such as an initial public offering or strategic sale of the company, New York-based Mason said last month in a Delaware Chancery Court filing. At the time, Mason asked the board to form a special committee and retain an independent financial adviser to evaluate alternatives and disclose valuation materials. But the board — through Kirkland & Ellis — refused, asserting it had no obligation to take action. “The board taking advice as to its own conflicts, collectively and individually, from legal counsel which it knows, or reasonably should know, has a direct conflict is wrongful on its face,” Mason wrote in Monday’s letter. Even as EMG and ADIC pursue arbitration, other Ascent investors have come forward with offers to buy the company. Mason put forth its own proposal to deliver a fully financed, all-cash approval to acquire Ascent at a “price superior to that contemplated by the EMG transactions” and to make the payment upfront rather than over multiple years, according to a separate letter viewed by Bloomberg. Kimmeridge Energy Management had also submitted a $6 billion proposal for Ascent, according to Monday’s letter.“Neither bidder has received any response from the board,” Mason wrote, adding that it also asked for “immediate corrective action, including withdrawal of conflicted counsel.

Cleanup Stalled: Frack Wastewater Lingers at 3 Eureka Plants in PA - Marcellus Drilling News - On August 17, Eureka Resources’ Williamsport Second Street facility (one of the three wastewater treatment plants previously operated by Eureka) leaked some of its stored untreated frack wastewater, which ended up in the nearby Susquehanna River via a storm drain (see ‘Black Goop’ Spills into Susquehanna River from Closed Eureka Plant). That event led the Pennsylvania Department of Environmental Protection (DEP) to launch an investigation into all three of Eureka’s shuttered plants: two in Williamsport (Lycoming County) and one in Bradford County. The DEP found untreated wastewater stored at each facility—over 4.6 million gallons in total—and demanded Eureka dispose of it within 90 days. In September, Eureka outlined a plan to do just that (see Eureka Proposes Plan to Clean Up, Close All 3 PA Wastewater Plants). The 90-day period has expired. The DEP reinspected and found that some progress has made, but wastewater is still stored at each site.

Denver natural gas producer raising money for $3.9 billion deal - --One of the United States’ largest natural gas suppliers makes moves to fund a deal meant to focus the company on West Virginia production. Antero Resources of Denver said it's buying 55,000 net acres in the Marcellus Shale gas field production area in West Virginia for $450 million.

Antero Midstream announces launch of $500M offering of senior notes - Antero Midstream (AM) on Tuesday said it intends to offer $500 million in aggregate principal amount of senior unsecured notes due 2034 in a private placement to eligible purchasers. Antero Midstream intends to use the net proceeds from the offering, together with borrowings under Antero Midstream Partners revolving credit facility and the net proceeds from the disposition of all of Antero Midstream's Utica Shale midstream assets to fund the acquisition of HG Energy II Midstream Holdings from HG Energy II, and related fees and expenses.

Vickery Energy acquires Marcellus gas assets from Tribune Resources - Vickery Energy Partners has closed the acquisition of natural gas assets in the Appalachian basin from Tribune Resources, adding approximately 38,000 net acres and more than 200 MMcfe/d of net production across Wetzel, Tyler, Harrison and Doddridge counties in West Virginia. The assets include development inventory in both the wet and dry windows of the Marcellus Shale, providing Vickery with an established production base and multi-year drilling runway. Financial terms of the transaction were not disclosed. Vickery is led by former Tug Hill executives, including President and CEO Sean Willis and CFO Daniel Rowe, and is backed by Quantum Capital Group. Quantum previously sold Tug Hill Operating and XcL Midstream’s Appalachian assets to EQT in a $5-billion transaction in 2023. The transaction further consolidates private-equity-backed positions in the Appalachian gas sector as operators position for long-term demand growth and improved basin economics.

Vickery closes acquisition of Appalachia player Tribune --Vickery Energy Partners, which is a portfolio company of Quantum Capital Group, announced last week that it had closed its acquisition of Tribune Resources. According to the January 8 announcement, the transaction includes assets located primarily in West Virginia’s Wetzel, Tyler, Harrison and Doddridge counties. The assets span roughly 38,000 net acres (154 square km) and have net production of more than 200mn cubic feet (5.7mn cubic metres) per day of gas equivalent. Hart Energy cited a source familiar with the matter as saying that the purchase price Vickery paid for Tribune was around $400mn. The outlet added that analysts had estimated the transaction value had fallen to $350-500mn. Vickery’s president and CEO, Sean Willis, described the acquired assets as “high quality”, with development inventory in both the wet and dry windows of the Marcellus shale. “This transaction provides Vickery with a significant production base and multiple years of development runway, allowing us to apply our expertise and demonstrated execution capabilities to grow production, build a business of scale, and create value for our investors,” Willis added. Willis is a former executive of Tug Hill. Quantum sold Tug Hill Operating and XcL Midstream’s portfolio of upstream and midstream assets in the Appalachian Basin to EQT for around $5.0bn in 2023. The transaction comes amid rising demand for natural gas, including in Appalachia. A month earlier, Antero Resources announced that it was buying the upstream assets of HG Energy II in the Marcellus shale for $2.8bn while simultaneously agreeing to sell its Utica shale assets in Ohio for around $800mn. Energy data and services provider TGS commented at the time that this capped off a busy year for mergers and acquisitions (M&A) in the Marcellus, citing operators building inventory to meet rising demand from AI data centres. The company noted that according to its TGS Well Data Analytics service, the Marcellus was in a “prime position” to meet growing gas demand. Permits in the play had risen by 26% over the past year, TGS said, which it added was coupled with an increase of 3% in productivity per foot of lateral length.

Enbridge Begins Construction on 122-Mile Ridgeline Expansion - Enbridge has started construction on its 122-mile Ridgeline Expansion Project in Tennessee, expanding its East Tennessee Natural Gas system to supply TVA’s Kingston Fossil Plant replacement. (P&GJ) — Enbridge Inc. has begun construction on its Ridgeline Expansion Project, a 122-mile natural gas pipeline expansion of the company’s East Tennessee Natural Gas (ETNG) system designed to serve the Tennessee Valley Authority’s (TVA) planned natural gas replacement of the Kingston Fossil Plant, according to an Oct. 20 update on the project.According to Enbridge, Ridgeline has received all necessary regulatory certificates and permits, including a FERC Notice to Proceed earlier this month. Construction is scheduled to continue through 2026, with in-service targeted for November 2026 and full restoration expected by spring 2027.The project involves installing 122 miles of 30-inch looping pipeline and one electric-powered compressor station. Enbridge said 91% of the new route will parallel existing rights-of-way to minimize land and environmental impacts. In addition, about 80 acres of solar panels will be installed to offset the project’s operational energy use.Enbridge emphasized that the project will “provide affordable and cleaner energy” to TVA customers and represents a multi-year collaboration that included multiple rounds of public input and environmental review.Once complete, Ridgeline will enhance the ETNG system’s capacity and reliability across the Tennessee Valley, supporting TVA’s transition away from coal and toward a lower-emission energy portfolio.

Natural gas storage dips less than expected, signaling robust demand By Investing.com --In the latest report from the Energy Information Administration (EIA), natural gas storage has seen a decline of 71 billion cubic feet (Bcf) in the past week. This drop is less than the forecasted decrease of 89B, indicating a stronger demand for the energy resource than initially anticipated. The actual decrease in natural gas storage is also less than the previous week’s decline of 119B. This suggests a possible stabilization in the energy sector, with demand outpacing supply at a slower rate than in previous periods. Natural gas storage is a critical indicator of the energy sector’s health, particularly in Canada, due to its substantial energy sector. The storage report measures the change in the number of cubic feet of natural gas held in underground storage during the past week. When the increase in natural gas inventories is more than expected, it implies weaker demand, which is bearish for natural gas prices. Conversely, if the increase in natural gas storage is less than expected, it signifies greater demand, which is bullish for natural gas prices. The same can be said if a decline in inventories is more or less than expected. In this case, the lower-than-expected decrease in natural gas storage suggests a bullish outlook for natural gas prices. This could have a positive impact on the Canadian dollar, given the country’s sizable energy sector. The EIA’s report provides valuable insight into the dynamics of the energy market, and the current data suggests a robust demand for natural gas. This could have significant implications for energy companies and investors, as well as for the broader economic outlook, particularly in energy-dependent economies like Canada. (NB: a smaller draw than expected means demand was weaker than expected, not the other way around...this article was written by AI, but reviewed by a human)

Expand Chief Says $3.50 Natural Gas Unlikely to Spur Aggressive Growth -Expand Energy Corp. CEO Nick Dell’Osso sees a U.S. natural gas market that remains volatile in the near term but structurally constructive as producers navigate supply growth, shifting basin dynamics and an increasingly global demand outlook tied to LNG. Line chart showing NGI forward fixed natural gas prices for Henry Hub and Texas Eastern M-2, 30 Receipt from February 2026 through January 2036, with Henry Hub consistently priced above Texas Eastern M-2 and both hubs displaying recurring seasonal peaks near $4.00/MMBtu and winter troughs closer to $2.00/MMBtu, based on NGI Forward Look data as of Jan. 12, 2026. At A Glance:
Haynesville growth outpaces expectations
Lower 48 annual output up 5 Bcf/d
Higher-cost supply to push prices up

Into the Great Wide Open — Technology, LNG Pull Gas Producers into High-Stakes Western Haynesville | RBN Energy - Producers venturing into the substantial natural gas reserves in the far-west part of the Haynesville Shale — south of Dallas and about 200 miles west of DeSoto Parish, LA, in the core Haynesville — were historically thwarted by extreme geological conditions and poor drilling economics, which quickly relegated the area to the back burner in the early years of the Shale Era. Now, technological advancements and bullish market conditions are once again beckoning producers to look beyond the core areas of the Haynesville. Rig activity in the Western Haynesville is the highest it’s been in 10 years and production volumes have been ticking up over the past two. In today’s RBN blog, we begin a series looking at recent activity and production scenarios for the region as it fits into the larger Gulf Coast supply-demand balance. We have written extensively about the Haynesville Shale in the RBN blogosphere (see Say You’ll Be There, Don’t Call It A Comeback and, most recently, Sitting, Waiting, Wishing). In short, the wells here are deep (10,500-13,500 feet compared to 4,000-8,000 feet in the Marcellus) and expensive to drill, but the basin offers large, overpressurized, dry gas reserves — a profile that was highly attractive in 2008 when gas supply disruption fears gripped the market and gas prices at the national benchmark Henry Hub were well over $4/MMBtu. As we detailed in Dig a Little Deeper, the extreme conditions remain a risk for drilling economics in the area. The reservoirs are up to 19,000 feet deep with an average well depth in mid-2024 of 16,872 feet, according to Enverus data, compared to 11,700 feet in the traditional Haynesville. Bottomhole temperatures can exceed 450°F in the Western Haynesville, whereas temperatures are relatively cooler at 320°F or so in the traditional Haynesville, although it varies. The extreme depths and harsh conditions mean that it takes a lot more time to drill than in the core Haynesville and drilling-and-completion costs are among the highest in the industry, ranging from more than $20 million to nearly $40 million per well. And while the wells boast impressive initial production (IP) rates (upward of 30 MMcf/d vs. an average 21 MMcf/d in the traditional Haynesville, 20 MMcf/d from the Marcellus and 2 MMcf/d from the oil-focused Permian on average in 2025), they could also require additional upfront investment in midstream facilities and logistics to accommodate large swings in volume resulting from the high IP rates, high-pressure output and subsequent declines. On top of all that, this is a pure gas play without the potential uplift of oil or NGLs like the Permian.No doubt the Western Haynesville is still fraught with challenges and uncertainties. And as we warned in Should’ve Been a Cowboy, it’s still early days and the area’s long-term prospects remain a question mark. But in some respects, much has changed since the early Shale Era days, and the outlook may be as good as it’s ever been.Technological advancements, such as insulated drill pipes, mud-chilling systems and advanced hydraulic fracturing techniques, are now available to handle the extreme conditions present there. As a result, Comstock Resources, the firm that has had the most success in the area, has seen dramatically lower drilling times and costs than just a few years ago. Moreover, Comstock, for one, has said it has been experimenting with a choke-management program across many of the wells, limiting initial production in hopes of improving estimated ultimate recovery (EUR). Additionally, in terms of market conditions, the Gulf Coast natural gas market is experiencing an extended demand boom. LNG facilities have added nearly 20 Bcf/d of export demand on the Gulf Coast since 2016 and sanctioned projects will just about double that volume over the next 10 years. And, as we discussed in God Blessed Texas, there’s a slew of data center projects proposed in eastern Texas that could significantly boost demand for both power and gas in the region. The demand boom is ushering in an era of tighter supply-demand balances and higher natural gas prices in the Gulf Coast region (see All Shook Up). This, along with the technological advancements, has made the tough conditions of the mega-well play less daunting, if still challenging.A handful of producers, at least, have dusted off their boots to test the frontier. Figure 2 below plots the horizontal wells (colored dots) with a minimum vertical depth of 13,000 feet drilled in the four counties since 2022. The well count is broken out in the table into producing wells vs. “other wells,” which is defined as permitted, drilled, drilling and completed wells, excluding permitted wells that were canceled or expired. The map also shows active rigs (colored X’s) as of December.

EPA Aims to Limit States’ Regulatory Role as Natural Gas-Hungry LNG Plants, Data Centers Boom -- The U.S. Environmental Protection Agency has proposed a rule to curb the ability of states to hinder natural gas pipeline projects and other infrastructure as energy demand is on the rise and development is accelerating. U.S. data center development clusters closely along major natural gas pipeline corridors, highlighting growing power demand tied to existing energy infrastructure. At A Glance:
Proposal would limit water quality reviews
States have long used law to slow pipelines
Final rule targeted for spring 2026

Delfin Targets Imminent FID, Eyes First LNG in 2029 as Export Wave Crests --Delfin Midstream Inc. disclosed it is honing in on a final investment decision (FID) for its offshore U.S. LNG project within the month as it finalizes equipment agreements with contractors.Image of a map showing the project location of the proposed Delfin LNG export facility with associated offshore infrastructure signified.At A Glance:
FID expected within weeks
Henry Hub 2029 forwards seen near $3.60
Post-surge LNG outlook shifts later

Venture Global Pulled Plant Maintenance Ahead as Weaker LNG Market Squeezed Year-End Ops -- Venture Global Inc. said higher U.S. natural gas prices and a tight shipping market that capped the end of last year impacted both its export volumes and the pricing of its cargoes in the fourth quarter. At A Glance:

• Fourth quarter liquefaction fees averaged $5.15
• Maintenance work brought forward
• Pre-tax earnings guidance cut

Magnolia LNG Pushes Back Louisiana Project Timeline, Citing Biden-Era DOE Policy - A unit of Glenfarne Group LLC, the company behind the Alaska LNG and Texas LNG projects, is seeking an extension for a long-proposed southwest Louisiana export terminal. Stacked area chart showing North America operational and sanctioned LNG facility peak export capacity rising from near zero in 2016 to roughly 36 Bcf/d by 2033, highlighting major U.S., Canadian and Mexico projects including Sabine Pass Trains 1–6, Freeport LNG, Corpus Christi Trains 1–5, Cameron LNG, Calcasieu Pass Phases 1–2, Plaquemines LNG, Golden Pass, Port Arthur LNG Phases 1–2, Rio Grande LNG Trains 1–5, Louisiana LNG and LNG Canada. At A Glance:
Magnolia seeks 2031 FERC deadline
Project proposed with 8.8 Mt/y capacity
Glenfarne cites Biden LNG permit pause

Court Upholds Texas LNG Deadline Extension, Clearing Path for FID - A federal court has rejected an environmentalist group’s legal challenge against Texas LNG’s construction extension, averting another possible disruption in the project’s long timeline. At A Glance:

• Construction deadline pushed to 2026
• Court ruling reinforces permit durability
• Texas LNG fully subscribed

Texas LNG Signs RWE for Final Offtake Deal, Eyes FID - US LNG developer Glenfarne says it is nearly ready to take a final investment decision (FID) on the Texas LNG project this year after fully contracting the offtake for the 4 million ton per year facility.

Cheniere Commissioning Fifth Train at Corpus Christi LNG, Keeping Startup on Track for Spring -- Cheniere Energy Inc. told state and federal regulators that it would begin starting up the fifth train at its Corpus Christi LNG Stage 3 expansion project in South Texas this week. In an emissions report filed with the Texas Commission on Environmental Quality, Cheniere said its engineering contractor Bechtel Corp. would begin startup and commissioning operations on Wednesday (Jan. 14). Cheniere said the thermal oxidizer, furnace and ground flares would be operated during the initial startup work.

Weekly U.S. LNG Loadings Fall by 8 Cargoes on Gulf Coast Cuts - A look at the global natural gas and LNG markets by the numbers. February 2026 pricing shows U.S. LNG landed in Europe remains competitive, with a wide premium between U.S. Henry Hub–linked supply and major European gas hubs.

• 2.24 Bcf/d: U.S. feed gas nominations tumbled roughly 2.24 Bcf/d since the beginning of the week, driven by maintenance and outages at two terminals. Testing at the Sinton Compressor Station that helps feed Corpus Christi LNG is expected to reduce supply by up around 1.3 Bcf/d on Jan. 14 and 0.7 Bcf/d on Jan. 15, according to Wood Mackenzie. However, those totals could increase if maintenance is extended.Nominations to Freeport LNG have also been reduced after an outage of all three trains Tuesday evening to Wednesday morning.
• 2.17 Mt: U.S. LNG exports are set to decline 0.58 million tons (Mt) week/week, or by roughly eight cargoes, driven by reductions at the Plaquemines and Cameron facilities. U.S. terminals are expected to send out 2.17 Mt in LNG volumes the week of Jan. 12, with 59% of cargoes landing in Europe, according to Kpler predictive data. The week also represented a continued shift of some spot cargoes to Asia as export volumes to the Pacific are projected to grow by 0.16 Mt.
• $10–12/MMBtu: Increasing electricity demand backed by reliable LNG supplies will stabilize Title Transfer Facility (TTF) prices between $10–12/MMBtu in 2026, according to Enverus. The analytics firm estimates that European gas buyers will pull U.S. supply during the year as regulators hone in on grid reliability. Since the beginning of the year, TTF has mostly hovered in the mid-$9 range before freezing temperaturesacross central and western Europe triggered a rally earlier in the week.
• 8 Mt/y: Woodside Energy Group Ltd. is a major step closer to increasing LNG exports from Australia later this year with the arrival of a floating production unit at the Scarborough field. The firm disclosed its Scarborough extension project is around 91% complete as the unit prepares for connection to the offshore gas production system. Once operational, the unit would process gas from the Western Australia field that is targeted to feed up to 8 Mt/y in LNG exports and 0.2 Bcf/d in domestic market supply.

U.S. LNG Feed Gas Deliveries Bounce Back as Unplanned Outages End, TTF Rallies --Feed gas deliveries to U.S. LNG export facilities appeared to bounce back on Friday after a midweek lull caused by unexpected maintenance at two facilities on the Gulf Coast. NGI table showing U.S. Gulf Coast LNG netback prices on a 12-month strip as of Jan. 15, 2026, comparing JPN/KOR, NBP, and TTF benchmarks. February 2026 spot-month netbacks range from $8.518/MMBtu to $11.061/MMBtu after shipping costs, with the highest netbacks tied to NBP and TTF. Across the forward curve through January 2027, Gulf Coast netbacks generally trend between about $8.15/MMBtu and $9.50/MMBtu, while margins versus Henry Hub range from roughly $4.80/MMBtu to nearly $8.00/MMBtu. At A Glance:
CCL, Freeport curbed intake this week
Feed gas back near record highs
TTF gained 29% this week

EIA Slashes Natural Gas Price Outlook as Mild Weather Saps Winter Heating Demand -- Benchmark U.S. natural gas spot prices could average sharply lower than previously forecast this winter as mild temperatures curb heating demand, though price strength is expected to return in 2027 on the back of rising LNG exports and power demand, according to updated federal forecasts. Line chart comparing U.S. natural gas prices from 2021 through 2026, showing Henry Hub bidweek prices and residential natural gas prices with annual averages and forward-looking forecasts, highlighting seasonal residential price spikes above $20/MMBtu and lower Henry Hub prices generally ranging between $2.00–$5.00/MMBtu. At A Glance:
EIA reduces winter Henry Hub to $3.56
Agency expects $4.59 average for 2027
Winter strip flirts with sub-$3 amid warm-up

Analyst Reveals What Spurred Monday's Gas Price Recovery - A “recovering” late January forecast “spur[red]…” the NYMEX gas “recovery” yesterday, Eli Rubin, an energy analyst at EBW Analytics Group, outlined in an EBW report sent to Rigzone by the EBW team on Tuesday. “The February contract netted a 24.0 cent gain yesterday - reversing Friday’s 23.8 cent decline - as weather forecasts swung back in a colder direction to close January,” Rubin said in the report. “Speculators rotating out of the heaviest short positioning in 13 months may amplify upside, while yesterday’s bounce reset short-term technicals in a bullish direction,” he added. “Today may be the mildest day nationally until late February. Week 2 could see weekly heating demand soar 53 gHDDs and more than 100 billion cubic feet as blowtorch weather flips colder,” he continued. “The Week 3 forecast added 15 gHDDs in the past 24 hours. Other meteorologists also point to chances for reloading cold risks in early February,” Rubin stated. Rubin went on to note in the report that daily LNG feedgas nominations “suggest a record high at 20.4 billion cubic feet per day”. He added, however, that “soaring storage surpluses to year-ago and five-year average levels, and likelihood that the market will manage the coldest days of winter next week without massive disruption, suggest the near-term relief rally may wobble and retreat in the most-likely scenario”. The EBW report highlighted that the February natural gas contract closed at $3.409 per million British thermal units (MMBtu) on Monday. It outlined that this marked a 7.6 percent increase from Friday’s close. In Tuesday’s report, EBW predicted a “test higher and relent” trend for the NYMEX front-month natural gas contract price over the next 7-10 days and a “rebound and retreat” trend over the next 30-45 days. In an EBW report sent to Rigzone on Monday by the EBW team, Rubin stated that the NYMEX front-month gas contract “plunged to $3.131 intraday on Friday as support disintegrated, taking out key technical support at $3.25 per MMBtu to open further downside risks”. “With Henry Hub physical prices retreating to just $2.84 per MMBtu over the balmy weekend, January-to-date Henry Hub has averaged a mere $3.28 per MMBtu,” he added. “While some meteorologists indicate chances for a near-term gHDD gain, DTN’s Week 3 loss of 16 gHDDs since Friday suggests further loss of fundamental support. The storage surplus vs. five-year normal is poised to rise towards 185 Bcf into the end of January,” Rubin continued. Rubin went on to predict in that report that “daily LNG feedgas may hit a new record high today” and added that “a building speculator short position may raise chances for a near-term price pop higher”. “The longer-term outlook into spring may see more substantial fundamental support with weak March weather comps and low prices driving coal-to-gas fuel switching,” Rubin said in this report. “Nonetheless, deteriorating weather and building storage surpluses suggests further weakness cannot be ruled out,” he noted. In this EBW report, EBW highlighted that the February natural gas contract closed at $3.169 per MMBtu on Friday. This marked a 7.0 percent drop from Thursday’s close, the report outlined. In Monday’s report, EBW predicted an “attempt to rebound” trend for the NYMEX front-month natural gas contract price over the next 7-10 days and a “rebound and retreat” trend over the next 30-45 days.

Analyst Explains Why Feb NatGas Contract Collapsed Wednesday | Rigzone -- In an EBW Analytics Group report sent to Rigzone by the EBW team on Thursday, Eli Rubin, an energy analyst at the company, highlighted that the February natural gas contract “collapsed” yesterday. Rubin outlined in the report that the February natural gas contract fell to $3.068 per million British thermal units (MMBtu) on Wednesday “on (i) chances for a dissipating Alaska ridge opening milder February risks and (ii) a Webber Research report that Golden Pass LNG Trains 2-3 may be delayed until 2027”. “Weakness was compounded by volatility: yesterday’s $3.120 close is within 1.1 cents of Friday’s low,” Rubin added. In the report, Rubin pointed out that daily LNG demand “dropped to a two month low” yesterday, “mitigating weather driven Henry Hub spot price upside to clear at $3.12 per MMBtu”. He also noted that “LNG could jump 3.5 billion cubic feet per day - adding to a 12.4 billion cubic foot per day increase in weather-driven demand into Tuesday”. Rubin went on to outline in the report that “consensus projections” for the U.S. Energy Information Administration’s (EIA) next weekly natural gas storage report - which is scheduled to be released later today and will include data for the week ending January 9 - “are for an 87-91 billion cubic foot draw”. “The bigger story is likely to be rising physical market strength into a cold Martin Luther King holiday weekend,” Rubin added. “Healthy storage surpluses suggest NYMEX futures may try to continue to look past near term cold, however,” he continued. The EBW report highlighted that the February natural gas contract closed at $3.120 per MMBtu on Wednesday. It outlined that this marked a 29.9 cent, or 8.7 percent, decrease from Tuesday’s close. In Thursday’s report, EBW predicted a “mixed signals” trend for the NYMEX front-month natural gas contract price over the next 7-10 days and a “rebound and retreat” trend over the next 30-45 days. In an EBW report sent to Rigzone by the EBW team on Wednesday, EBW highlighted that the February natural gas contract closed at $3.419 per MMBtu on Tuesday. EBW outlined in the report that this marked an increase of 1.0 cents, or 0.3 percent, from Monday’s close. “The February contract rose 1.0 cents yesterday to close within 0.6 cents of $3.413 for the third time in four trading days as natural gas searches for equilibrium following price volatility since Thanksgiving,” Rubin noted in that report. “The short term market remains caught between increasing cold into late January and simultaneously rising storage surpluses,” he added. In this report, Rubin said “forecasts trended colder for Weeks 2 and 3 to bolster near-term support”. He added, however, that “Henry Hub spot prices at $3.04 per MMBtu remain at a steep discount to the February contract”. “Henry Hub should be less affected than regional basis during next week’s cold shot, giving bears an opening to drive prices lower,” Rubin warned. Rubin went on to highlight in that report that daily LNG feedgas was down. He added that the market “may ‘look past’ upcoming cold” and stated that “rising storage surpluses, despite a cold back half of January, may give the impression of a fundamentally oversupplied supply/demand balance to offer bearish risks later this month”. In Wednesday’s report, EBW also predicted a “mixed signals” trend for the NYMEX front-month natural gas contract price over the next 7-10 days and a “rebound and retreat” trend over the next 30-45 days.

Abundant Nat-Gas Supplies Pressure Prices - February Nymex natural gas (NGG26) prices settled lower on Friday but remained above Thursday's 3-month nearest-futures low. Abundant US supplies are weighing on nat-gas prices after Thursday's weekly EIA report showed nat-gas storage levels +3.4% above their 5-year seasonal average. Losses in nat-gas prices were contained on Friday amid forecasts of colder-than-normal US temperatures, potentially boosting nat-gas heating demand. The Commodity Weather Group said Friday that below-normal temperatures are seen across much of the northern US and East for the January 21-30 period. Nat-gas prices are also under pressure, as feedgas to Cheniere's Corpus Christi LNG export facility and the Freeport LNG export terminals along the Texas Gulf Coast have been below normal levels this week due to electrical and piping issues. The reduced capacity at the export terminals allows US nat-gas storage levels to build, a bearish factor for prices. As a negative factor for gas prices, the Edison Electric Institute reported Wednesday that US (lower-48) electricity output in the week ended January 10 fell -13.15% y/y to 79,189 GWh (gigawatt hours), although US electricity output in the 52-week period ending January 10 rose +2.5% y/y to 4,294,613 GWh. Projections for lower US nat-gas production are supportive for prices. The EIA on Tuesday cut its forecast for 2026 US dry nat-gas production to 107.4 bcf/day from last month's estimate of 109.11 bcf/day. US nat-gas production is currently near a record high, with active US nat-gas rigs recently posting a 2-year high. US (lower-48) dry gas production on Friday was 113.0 bcf/day (+8.7% y/y), according to BNEF. Lower-48 state gas demand on Friday was 104.9 bcf/day (-2.4% y/y), according to BNEF. Estimated LNG net flows to US LNG export terminals on Friday were 19.8 bcf/day (+2.5% w/w), according to BNEF. Thursday's weekly EIA report was bearish for nat-gas prices, as nat-gas inventories for the week ended January 9 fell by -71 bcf, a smaller draw than the market consensus of -91 bcf and well below the 5-year weekly average draw of -146 bcf. As of January 9, nat-gas inventories were up +2.2% y/y and were +3.4% above their 5-year seasonal average, signaling ample nat-gas supplies. As of January 13, gas storage in Europe was 52% full, compared to the 5-year seasonal average of 68% full for this time of year. Baker Hughes reported Friday that the number of active US nat-gas drilling rigs in the week ending January 16 fell by -2 to 122 rigs, falling further below the 2.25-year high of 130 set on November 28. In the past year, the number of gas rigs has risen from the 4.5-year low of 94 rigs reported in September 2024.

EIA Jan. STEO Predicts HH Spot Price Avg $3.46 2026, $4.59 2027 - Marcellus Drilling News - The U.S. Energy Information Administration (EIA) issued its latest monthly Short-Term Energy Outlook (STEO) on Tuesday. The STEO is the agency’s monthly best estimate of where energy prices and production will head over the next 12 months. The EIA published its first energy-sector forecasts through 2027. For natural gas, the EIA predicts the U.S. benchmark Henry Hub spot price to decrease about 2% to just under $3.50 per million British thermal units (MMBtu) in 2026, then rise sharply in 2027 to just under $4.60/MMBtu. The reason for the sharp increase next year? Growth in demand—led by expanding LNG exports and more natural gas consumption in the electric power sector—will outpace production growth.

North American Natural Gas Facing Test as LNG, Power Demand Set to Collide, Say NGI Thought Leaders - Natural gas in North America achieved celebrity status in 2025 as LNG exports grew, industrial demand rose and hyperscalers looked for utility deals. Production also showed little sign of slowing, even with fewer rigs. Can 2026 top it? At A Glance:

• Storage refills pressuring natural gas prices
• LNG exports approaching 20 Bcf/d
• Western Canada output rising

What Excites and Worries LNG Exporters in 2026: Maguire - (Reuters) – The year 2025 in the LNG sector will be one for the history books after production and exports of the super-chilled fuel smashed records and raked in billions of dollars in revenues across the global liquefied natural gas supply chain. A 25% surge in LNG purchases by European countries was a key highlight and raised hopes among gas sellers that further growth in gas use in economies such as Germany, Italy and the United Kingdom is in store for 2026 and beyond. On the other hand, lower imports by three of the five largest LNG buyers – all in Asia – have raised profit concerns, especially among exporters banking on selling the even greater volumes of LNG expected to hit the market this year. The steep climbs in LNG purchases by several European countries in 2025 beg the question whether the region can sustain such a voracious appetite. On the plus side, Europe’s generation of electricity from gas-fired power plants posted its first annual rise last year since before Russia’s invasion of Ukraine snarled regional gas flows in 2022. Total European gas-fired electricity output during January to November was 1,009 terawatt hours (TWh), according to think tank Ember, up 3.4% from the same months in 2024 and the first year-over-year increase for that period since 2021. Further increases in gas-fired power generation will obviously trigger further LNG import demand, especially in markets with shortages of alternative power sources. Europe’s broader industrial economy, however, remains hobbled by weak manufacturing and consumer demand, and output among gas-intensive sectors such as chemicals and fertilizers remains near historic lows in top regional producer Germany. Until a synchronised upturn in consumer and business activity takes root, it’s likely that Europe’s overall demand for natural gas may remain patchy, which may cap any further increases in LNG import interest over the near term. Another question for LNG exporters is whether Europe’s LNG purchases in 2025 were artificially inflated as several countries attempted to narrow their trade gaps with the United States during trade talks with the Trump administration. European imports of LNG from the U.S. last year jumped by close to 60% from 2024 levels, data from commodities intelligence firm Kpler shows. That outsized jump in U.S. purchases – well above the increase in Europe’s total LNG imports – suggests the region may have been trying to curry favour with President Donald Trump as European and U.S. policymakers discussed trade deals. With international focus now turning more to geopolitical concerns – such as the U.S. interest in acquiring Greenland – it is possible that European countries may prove less keen to please President Trump in 2026. MicroWatt Controls: Instrumentation & Safety System Experts If that’s the case, volumes of U.S. LNG imports aimed at reducing trade deficits in 2025 may get curbed in 2026. LNG exporters also have questions about the state of demand in Asia, which accounted for around 64% of all LNG imports last year, data from Kpler shows. Total shipments to Asian buyers last year were just over 613 million cubic meters, marking a nearly 5% fall from 2024. While a 5% volume slip was not much of a concern through 2025 given the steep growth in sales to Europe, LNG exporters will be anxious if Asia’s overall appetite remains weak this year and Europe’s buying pace also slows. The top two overall LNG importers – China and Japan – registered LNG import cuts of 15% and 2% respectively in 2025. The synchronized dip in imports by such critical markets will remain a cause for concern in 2026, especially if China’s economy remains sluggish and trade relations with the United States and other markets remain chilled. Rapidly expanding renewables power generation in China and steadily recovering nuclear power generation in Japan are further causes for concern as those power sources squeeze gas out of generation mixes. LNG purchases by number four importer – India – also dropped by 7% last year, yet another source of worry among LNG exporters who had hoped India would be a steady growth market. Higher global gas prices have resulted in a steady decline in gas-fired electricity generation in India so far this decade, bringing as well a sharp slowdown in spending on gas distribution and storage infrastructure. Bullish forecasters argue the steady swell in planned LNG exports will drive global prices lower and reignite demand for the fuel in fast-growing but cost-sensitive economies like India, Pakistan and Bangladesh. They may be right, but with benchmark natural gas prices near three-year highs and rising in the United States – the top global gas producer – it may be hard for LNG exporters to drive sale prices lower over the near term. That may leave LNG exporters in 2026 focusing on already established markets, struggling in Europe to grow sales much from last year’s levels and hampered in Asia by patchy demand as China’s economy struggles for growth.

Targa to Build 500-Mile NGL Pipeline from Permian to Mont Belvieu -Targa Resources will build the 500-mile Speedway NGL Pipeline from the Permian Basin to Mont Belvieu, expand processing capacity with the Yeti plant, and add Buffalo Run gas infrastructure in a $3.3 billion growth plan. (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.

236-Mile Texas-to-Gulf Pipeline Reaches FID in $2.3 Billion LNG Expansion Push - A 236-mile, $2.3 billion Texas-to-Gulf natural gas pipeline has reached FID, marking a major step forward in connecting key Texas gas hubs to the Gulf Coast’s growing LNG export corridor. (P&GJ) — ARM Energy Holdings and PIMCO have reached a final investment decision on the $2.3 billion Mustang Express Pipeline, a 236-mile, 42-inch natural gas line designed to move up to 2.5 Bcf/d of gas from key Texas hubs to Gulf Coast LNG demand centers. The project, developed and operated by Houston-based ARM Energy with financial backing from Pacific Investment Management Company (PIMCO) and co-investors, has secured an anchor shipper commitment from Sempra Infrastructure to supply its Port Arthur LNG Phase 2 project, which recently achieved FID. The pipeline system will include:

• Cougar Lateral – 55 miles from Tres Palacios Storage to the Katy Hub
• Mustang Mainline – 178 miles from Katy to Port Arthur
• Golden Triangle/Spindletop Lateral – 3 miles near Port Arthur

Completion is expected in late 2028 or early 2029. The project has already secured required steel and compression, with Jindal Tubular USA providing pipe and Solar Turbines Inc. supplying 300,000 hp of gas-driven compressors across three stations. “Developing the Mustang Express Pipeline represents a major milestone in our growth and reinforces our commitment to quality, large-scale customers like Sempra Infrastructure,” said Zach Lee, CEO of ARM Energy. “By linking two of the most prolific natural gas-producing regions in the U.S. directly to LNG export facilities in Texas, we are helping ensure a reliable supply of natural gas for liquefaction and export.” ARM Energy plans to launch an open season later this month for remaining capacity on the Mustang Express system.

Pipeline safety enforcement cut in half in Trump’s first year - The Trump administration slashed pipeline safety enforcement in 2025, bringing about half the average number of cases as in previous years. The change reduces pressure on an industry that includes some of President Donald Trump’s biggest financial supporters and sits at the center of his “energy dominance” agenda. It’s also part of a broader retreat across the federal government from policing companies’ environmental, safety and financial activities. “In an administration with a president who has emphasized, as this one has, that he thinks there is too much regulation, reducing enforcement activity is an easy and unreviewable way to lessen immediate regulatory burdens,” said Cary Coglianese, a law professor at the University of Pennsylvania who heads the Penn Program on Regulation. But less enforcement by the Pipeline and Hazardous Materials Safety Administration risks eroding support for the many pipelines and natural gas export facilities Trump wants to see built — if people who live near them don’t think regulations will keep them safe from explosions and other dangers. PHMSA initiated 111 enforcement cases in 2025, according to data on its website. That’s 44 percent below 2024 numbers and about half the average from prior years — 217. It levied 11 fines last year, far fewer than the average of 45. But a nearly $10 million fine levied New Year’s Eve against Panther Operating Co. for a 2023 oil spill off the Louisiana coast pushed the total dollar number for fines sought in 2025 to a record $14 million. That’s more than double the prior year average of $5.7 million. PHMSA spokesperson Emily Wong said safety remains a top priority for Trump and his administration. “Everything PHMSA does — from encouraging innovation to going after bad actors — is to ensure the American people can safely and affordably access the energy they need, to fuel their cars and power their homes,” Wong said in an emailed statement. “To suggest otherwise is disingenuous and ignores PHMSA’s thorough and transparent process.”

WSJ Op-Ed: Data Center Moratoriums are the New Fracking Bans - Marcellus Drilling News - MDN was among the first to tell readers that so-called environmental groups were quickly morphing from anti-fracking to anti-data center. Over the past three months, we’ve observed in various posts how opposition to data centers (from the same people who oppose fracking and shale energy) has gone from local and regional anti groups (seeMore Evidence that PA’s Anti-Frackers are Now Anti-Data Center andAntis in Ohio Join the Chorus Bashing AI Data Centers) to national groups (see 200 Enviro Groups Want Freeze on Building ALL New Data Centers). The usual bought-and-paid-for suspects in Congress have joined the cause, blaming data centers for high electricity costs and calling for the construction of all-new data centers to be blocked (seeCongressional Dems Blame AI Data Centers for High Electric Prices). An op-ed published in the Wall Street Journal echoes our observations. The title of the op-ed: “They’re Coming for Our Data Centers.”

Rigs-to-Reefs hearing sparks fight over Trump energy plans -A House hearing on a bipartisan bill promoting the use of decommissioned offshore oil rigs as artificial reefs instead devolved into a contentious partisan squabble Tuesday as lawmakers debated the merits of offshore drilling and the Trump administration’s oversight of it.The Natural Resources Subcommittee on Energy and Mineral Resources hearing was intended to discuss H.R. 5745, the “Marine Fisheries Habitat Protection Act,” sponsored by Rep. Mike Ezell (R-Miss.). The bill would expand the use of old offshore oil platforms as artificial reefs by streamlining a decades-old permitting process for doing so in federal waters along the five Gulf Coast states — Alabama, Florida, Louisiana, Mississippi and Texas.But the hearing detoured into a debate over offshore drilling, and assertions by some Democrats that the proposal amounts to a financial and regulatory giveaway for the oil and gas industry, and is an “extreme waiver of responsibilities” for their infrastructure.The bill, among other things, would allow the Bureau of Safety and Environmental Enforcement, in concert with the individual states, to designate Reef Planning Areas. And it would direct BSEE to submit maps of idle offshore structures with reefs to Congress, the Interior secretary and the NOAA administrator.

Mixed Signals – While Many U.S. Refiners Face a Gloomy Outlook, Things Look Brighter in PADD 3 | RBN Energy - The U.S. refining industry has been on a real rollercoaster ride in recent years, as the disastrous COVID shutdown period of 2020 — which led to the closure of many refineries — was closely followed by the “Platinum Age” margins experienced when demand recovered in 2021 and 2022. Since then, the trend has been mostly downhill, as demand growth has slowed and new refining capacity has come online from projects that were delayed during the pandemic. But while many of these trends were felt across the U.S. (and even globally), there have been major regional differences in refiner market performance, a dynamic we expect to continue as we head toward an uncertain future, made even more so by the recent events in Venezuela. In today’s RBN blog, we take a region-by-region look at the future of the U.S. refining industry and explain why reductions in refining capacity are expected in some areas while others may be in a position to thrive. Since 2010, global refinery net capacity has increased by about 700 Mb/d per year, with significant year-to-year volatility (see Figure 1 below). A decades-high level of net refining capacity additions of 2.1 MMb/d took place in 2023, the largest annual increase since 1977, followed by a still-significant 1.15 MMb/d of net additions in 2024. While our preliminary estimates show an addition of more than 1 MMb/d in 2025, they were negated by an even-larger level of refinery closures, resulting in a net capacity decrease of about 200 Mb/d (which excludes all the temporary loss of operating capacity in Russia). In the U.S., refiners continue to face a number of challenges, with less-competitive plants feeling the most pressure. We saw more than 1.7 MMb/d of capacity closures from 2019 through 2025, most driven by the severe drop in demand during the pandemic, with closures across every PADD. A new wave of shutdowns began in 2025 — notably LyondellBasell’s Houston facility (closed in Q1 2025) and Phillips 66’s (P66) Wilmington plant in Southern California (Q4 2025) — with at least one more expected this year, Valero’s Benicia refinery in Northern California, planned for closure by April. (More on these below.) But given the challenges faced by Russian, European, Latin American and even Chinese refiners, the turmoil has the potential to benefit U.S. refiners, who could capitalize and gain new business (see The Dog Days Are Over), assuming global demand growth maintains a positive trajectory — a subject we also address in Future of Fuels.So, what’s next on the U.S. side of things? Our Refined Fuels Analytics (RFA) practice has done a detailed supply-and-demand balance by PADD region and developed a schedule identifying the areas (see Figure 2 below) where capacity reductions are most likely to be required over the next two decades, along with those with the potential to add capacity.

• Refining capacity in PADD 1 (East Coast) has been on the decline since 2010 and the remaining refiners could continue to struggle in the short term, but there are no imminent closures expected. The potential reversal of Buckeye’s Laurel Pipeline to Philadelphia will add some competition from PADD 2 refiners, but the continued closures of less-competitive refineries in Europe (along with previous PADD 1 closures) provide some breathing room for the remaining plants. In the long term, in-region demand declines, potential energy transition policies and high regional costs make the further rationalization of refining capacity highly likely.
• Much like PADD 1, PADD 2 (Midwest) is challenged by declining in-region demand. The potential Laurel Pipeline reversal all the way to Philadelphia would be a positive development, as would be the 1,300-mile Western Gateway Pipeline, a project proposed by P66 and Kinder Morgan that would enable refined products flows from the St. Louis area to Southern California (see Going to California), part of the race to move refined products west from PADDs 2, 3 and 4 to PADD 5. While these projects will improve prospects for PADD 2 refiners by opening up new markets, some refining capacity rationalization still appears likely long term, with smaller, less-competitive, gasoline-focused refineries that rely on light crudes considered most at risk.
• It's a far different story in PADD 3 (Gulf Coast), which remains a globally dominant refining region. Its access to export markets allows regional refiners to weather today’s turbulence and even thrive despite domestic demand declines. As noted above, LyondellBasell shut its Houston refinery in 2025 but it’s likely to be the last significant closure in the region for some time. While some small shutdowns are possible and large expansions (like ExxonMobil’s 250-Mb/d Beaumont project completed in 2023) are very unlikely, smaller “capacity creep” and upgrading projects — like recent ones at Citgo Lake Charles, Chevron Pasadena and ExxonMobil Baton Rouge — could lead to net increases in overall regional capacity. The favorable conditions in PADD 3 have even incentivized some smaller refineries to add capacity, as Ergon Refining is planning to do with an impending project to increase crude capacity by 5 Mb/d and add the ability to produce 6 Mb/d of gasoline at its refinery in Vicksburg, MS. The recent developments in Venezuela could also be very positive for complex Gulf Coast refineries if they lead to substantive increases in advantageous heavy crude supply. As noted above, the rate of demand growth in potential export markets will be particularly important for Gulf Coast refiners and will ultimately determine the level of capacity creep which will make economic sense.
• Regional demand and crude supply trends are also relatively positive in PADD 4 (Rockies). These should allow refining capacity there to hold steady in the coming years, with new pipeline access to PADD 5 markets helping to replace any declines in regional demand.
• Refiners in PADD 5 (West Coast) remain under the most pressure, as has been the case for many years. More than 400 Mb/d of refining capacity (among three plants) has been idled in the region since 2020, including one very recently. P66 idled its 139-Mb/d Los Angeles-area refinery complex in Q4 2025, citing an uncertain future environment for refining in California (see It’s Time To Go). The facility spans two sites, in Carson and Wilmington, connected by pipeline. And more is to come soon, as Valero is scheduled to shutter its 150-Mb/d Benicia refinery by April, with plans to convert parts of the site into housing and commercial property while using harder-to-remediate sections for industrial or warehousing functions. Replacing this lost production and potentially accelerating additional closures in the coming years are the proposed new pipelines into the region. These include the Western Gateway project noted above, ONEOK’s proposed Sun Belt Connector (see Go West), which would run from El Paso, TX, to the Phoenix area and be connected to the company’s existing refined products system across Texas and Oklahoma, and HF Sinclair’s multi-phase expansion plans, which primarily target product movements from their Utah and Wyoming refineries to Nevada and California.

While the underlying supply/demand dynamics will drive the overall level of regional closures and/or capacity additions (along with potential new logistics infrastructure investment), it’s important to remember that the actual timing — and which refineries might be affected — will be determined by factors specific to individual plants and their corporate ownership. These include individual refinery profitability, corporate strategies, required capital expenditures (see Turn Around), the ability to compensate for the loss of capacity with another in-system refinery, major casualty events (both weather-related and accidents), and other factors.In short, the U.S. refining system is being reshaped by changes in demand, geography, logistics, government regulation and relative competitiveness. Regions with high costs, a difficult regulatory environment and shrinking markets — like PADDs 1, 2 and 5 — will continue to rationalize capacity, while those with advantaged crude access, strong logistics and export optionality are positioned to endure — and in some cases grow — despite structural headwinds. As we detail in our Future of Fuels report, the question isn’t whether change is coming, but where — and how fast.

How America Plans to Refill Its Emergency Oil Stockpile Using Venezuelan Crude - The Trump administration is exploring a workaround to America’s Strategic Petroleum Reserve problem: swapping heavy Venezuelan crude for U.S. medium sour barrels that can actually go straight into SPR caverns. According to Reuters, the Department of Energy is considering moving Venezuelan heavy crude into commercial storage at the Louisiana Offshore Oil Port, while U.S. producers deliver medium sour crude into the SPR in exchange. It’s a crude-for-crude swap designed to solve a very practical issue that Washington rarely likes to admit exists. Not all oil belongs in the SPR. The reserve was built to hold mostly medium and heavy sour barrels. This is inconvenient because the US has an abundance of light, sweet shale crude. That mismatch has quietly complicated every refill effort since the reserve was drained during the 2022 price spike. As of the latest EIA data, SPR inventories sit just under 400 million barrels, barely more than half of capacity. Venezuelan heavy crude fits into the SPR better than much of what the U.S. pumps today—on paper. But in practice, it’s not that simple. Heavy Venezuelan oil often needs blending, specialized handling, and infrastructure that the SPR itself doesn’t provide. Solution? Park the Venezuelan barrels elsewhere and backfill the reserve with U.S. medium sour crude. This isn’t quite an SPR refill either. It’s a logistical sleight of hand that highlights how boxed-in the refill strategy has become. Buying hundreds of millions of barrels outright would cost tens of billions of dollars. Slow-walking purchases risks turning the SPR into a permanent half-empty museum exhibit. The irony is that the U.S. doesn’t lack oil. It lacks the right oil in the right place at the right time. Net imports are negative, production is near record highs, and yet Washington is still improvising to make the reserve work as designed in the 1970s.

U.S. Oil & Gas Rig Count Falls to 543 In Uneventful Week - In another relatively slow week, total U.S. rig count fell to 543, a decline of one vs. a week ago according to Baker Hughes data for the week ending January 16. One rig was lost in the All Other (-1) group, while all major basins were unchanged for the week. Total US rig count is down four in the last 90 days, and down 41 vs. this week a year ago. Oil-directed rigs grew to 410 (+1) on the week, with gas-directed rigs falling to 122 (-2) and miscellaneous rigs unchanged at 11.

The 40% of US Oil Jobs Lost Over the Last Decade Aren't Coming Back - The US oil and gas industry slashed 40% of its workforce over the past decade of record-breaking production — and those jobs are unlikely to return. In an industry known for its booms and busts, higher oil prices have historically spurred greater drilling activity, and therefore more hiring. But this link broke after years of poor returns to investors following the bursting of the shale bubble in the mid-2010s. New technologies to drill faster for cheaper, corporate mergers and robots replacing humans on rigs resulted in the disappearance of some 250,000 jobs since the sector’s employment peaked in 2014. Production surged 50% during that time. Note: Upstream oil and gas employment is calculated as the combined employment of three BLS industries: Oil & Gas Extraction, Drilling Oil & Gas Wells, and Support Activities for Oil & Gas Operations. In 2025, even as output reached new highs and a pro-drilling president returned to the White House, payrolls are hovering at the lowest level in three years. “This industry has always been cyclical. You ride the wave when it’s good, and you brace for the downturn,” said Karr Ingham, president of the Texas Alliance of Energy Producers. “But what’s different now is, even when prices recover, we don’t see the same hiring bounce we used to.” That means fewer career opportunities for people like Shaun Carter, a geologist who was laid off when the Oklahoma-based exploration and production company he was working for in 2019 unexpectedly shuttered. Carter took up truck driving out of Houston — crisscrossing the Southeast and Midwest — assuming it would be temporary. More than six years later, he’s still driving, and his dreams of returning to the industry are fading. In the years after the 2014 oil price crash, investors pushed companies to focus on profits instead of growth, triggering a wave of consolidation and job losses. Mergers and acquisitions activity in the sector has exceeded $500 billion since the start of 2023, according to Bloomberg calculations, more than a 20% increase compared with the prior three years. Major players continued to reduce headcount in the past year as crude prices fell, with Chevron Corp., ConocoPhillips and Exxon Mobil Corp. all announcing job cuts in 2025. US oil producers are pumping a record 13.8 million barrels of crude a day, and they’re doing so with less than a third of the active drilling rigs than in 2014. That means each rig is now producing roughly four times as much oil as it did a decade ago — “brutally efficient,” as Ingham says — thanks to powerful equipment, refined techniques, automation as well as incentives to encourage workers to drill faster. While the Trump administration apprehended former Venezuela President Nicolás Maduro in part to access the nation’s vast oil reserves, major US oil executives have expressed caution about investing in the country. Analysts similarly doubt that the move will open up more jobs in the sector for Americans, as the domestic workforce is available and probably much cheaper, Since taking office last year, President Donald Trump has made it a priority to increase US oil and gas production by relaxing environmental regulations and pushing to open more federal land and waters to drilling. But some experts doubt that proposals to expand offshore drilling will result in new jobs. Those rigs will be unmanned in the future, “They’ll be entirely run by robots and automation, with much of it handled onshore,” Krishnamoorti said. “We’re likely to see a very different oil and gas industry — far fewer jobs, and the remaining ones out of harm’s way.” With oil currently priced around $60 a barrel, producers in some regions are right around that breakeven level that’s just high enough to keep wells running but too low to fatten profits. It’s a fine line for Trump too, who wants to advocate for the industry’s profitability but lower gas prices for everyday Americans. Energy executives polled by the Federal Reserve Bank of Dallas said oil prices need to be around $65 a barrel to justify drilling a new well. Prices have remained below that level for the past three months, and even a spike would need to be sustained to persuade producers to ramp up spending. “There’s this squeeze of trying to wring out as much cost as possible,” said Trey Cowan, an analyst with the Institute for Energy Economics and Financial Analysis. “Labor is the first place that really takes the punch.” Thanks in part to the efficiencies, some of the producers who have slashed jobs are performing better than expected. In the latest quarter, ConocoPhillips’ production exceeded its own highest estimate despite a decline in capital spending. Similarly, Chevron saw increased output in the Permian Basin even with fewer rigs. Carter has come close to getting back into the industry multiple times. Most recently, Marathon Oil called him in May 2024: After he was a runner-up for an earlier position, the company wanted him to consider a different opening. He said he was interested, and was told to expect a call in the coming days. Days later, driving his rig to a Costco in Tulsa, Oklahoma, he heard on the radio that ConocoPhillips had submitted a bid to buy Marathon. “I was like, ‘Oh no, I know what that means,’” Carter said. He never heard about the position again.

Feds sue to block state oil-field setbacks law -The federal Department of Justice filed a lawsuit Wednesday intended to nullify a contentious state law banning oil-field activity within 3,200 feet of homes and other sensitive sites. The suit in U.S. District Court for the Eastern District of California seeks a declaration that 2022’s landmark Senate Bill 1137 is unconstitutional. A DOJ news release said the department will file for a preliminary injunction within days to halt its enforcement. SB 1137, championed by Gov. Gavin Newsom after state regulators failed to impose similar measures by administrative means, is seen by industry and anti-oil activists alike as the most impactful of many petroleum-related laws that have emerged from the state Legislature in recent years. Environmental justice advocates pushed for years for oil-field setbacks as a way of protecting nearby residents they said have suffered from a variety of oil-related respiratory ailments and birth defects. But industry proponents have argued there is no scientific evidence supporting the 3,200-foot buffer zone. The state’s oil industry stalled the law’s implementation by preparing a voter referendum, but it abandoned the effort in mid-2024 in favor of a court fight. Two lawsuits challenging SB 1137 are pending in Los Angeles Superior Court. The DOJ’s news release said SB 1137 is preempted by two federal laws, 1920’s Mineral Leasing Act, which authorizes the government to lease federal property for developing deposits of hydrocarbons and other materials, and the Federal Land and Policy Management Act of 1976 requiring the federal Bureau of Land Management to balance various uses of public lands. Enforcement of SB 1137 would forestall about one-third of all federal oil and gas leases in California, according to the release. It adds that the lawsuit advances President Donald Trump’s executive order protecting American energy from “state overreach.” “This is yet another unconstitutional and radical policy from Gavin Newsom that threatens our country’s energy independence and makes energy more expensive for the American people,” U.S. Attorney General Pam Bondi said in the release. She added that the governor “is clearly intent on subverting federal law at every opportunity.” A spokesman for the Governor’s Office responded to the lawsuit by noting the Trump administration sued California for keeping oil wells away from elementary schools, homes, day-care centers, hospitals and parks. “Think about that,” spokesman Anthony Martinez said by email. “SB 1137 creates a science-based buffer zone so kids can go to school, families can live in their homes and communities can exist without breathing toxic fumes that cause asthma, birth defects and cancer.” Director Kassie Siegel of the Center for Biological Diversity’s Climate Law Institute denounced Wednesday’s lawsuit. “Attempting to block the law that protects the air we breathe and the water we drink from oil industry pollution is the Trump administration’s latest attack on our state,” Siegel stated. “Big Oil backed down from their deceitful referendum campaign because Californians wouldn’t stand for it. This is a last ditch attempt to overturn the law’s critical health protections. I’m confident this historic law will stand.”

Harvest Targets Nikiski LNG Upscale as Alaska Faces Major Supply Gap -Harvest Midstream Co. is seeking federal approval on plans to significantly upscale its proposed LNG import facility in Alaska ahead of a projected 40 Bcf/y supply deficit by the beginning of the decade.Cook Inlet gas annualized volume forecast chart showing Alaska natural gas production declining from 2022 to 2041 across high, mid, mean and low cases, falling below steady demand near 70 Bcf, according to Alaska Department of Natural Resources data. At A Glance:
Terminal targets 0.4 Mt/y imports
Cook Inlet production continues declining
Utilities face higher gas costs

Alaska LNG Wins Early Federal Approval, Clearing Final Permit for 800-Mile Pipeline Federal regulators have completed all environmental and permitting reviews for the $40 billion Alaska LNG project, clearing the way for its 800-mile (1,287 km) gas pipeline and export terminal. The long-delayed project aims to deliver North Slope gas to global markets and strengthen U.S. energy security. (P&GJ) — The Federal Permitting Improvement Steering Council announced on Dec. 11 that it has completed all federal approvals for the Alaska LNG project, finalizing a permitting process that began in 2017 and clearing one of the largest infrastructure projects in modern U.S. history. The NOAA Fisheries permit renewal, issued Dec. 10, marked the final authorization required under the federal FAST-41 process. The project includes an 800-mile (1,287 km) natural gas pipeline from Alaska’s North Slope to a liquefaction and export terminal in South Central Alaska, capable of delivering up to 3.5 billion cubic feet per day of gas for domestic use and global export. “I am thrilled to see the Alaska LNG project finish federal permitting actions ahead of schedule,” said Permitting Council Executive Director Emily Domenech. “After delays during the previous Administration, Alaska LNG returned to FAST-41 coverage to help navigate the complexities of the federal permitting process.” The $40 billion project, sponsored by 8 Star Alaska LLC, a Glenfarne-led consortium, is designed to unlock the state’s North Slope gas reserves, create long-term jobs, and expand energy access for both Alaskans and international partners. “This project strengthens U.S. energy security, creates jobs for Alaskans, and reinforces our commitment to a permitting system that works at the speed of American innovation,” said Interior Secretary Doug Burgum. Alaska’s congressional delegation hailed the news as a turning point for the state’s energy economy. Sen. Lisa Murkowski called it “crucial for our future—it can help secure Alaska’s economy for the next generation,” while Sen. Dan Sullivan said the approval “will transform our state with billions of dollars in economic activity and reliable, low-cost energy for our communities.” The Federal Energy Regulatory Commission (FERC) served as the lead agency for the review, coordinating efforts under the FAST-41 permitting framework. With federal permitting now complete, Alaska LNG moves closer to a potential final investment decision and construction start.

Alberta Gas Storage Records Rare January Net Injection | RBN Energy -Gas storage in the Western Canadian province of Alberta, the region in Canada with the greatest amount of storage capacity, recorded a rare net injection on January 12 of 0.3 Bcf (red circle in chart below) thanks to much warmer than average weather and robust wellhead production based on data from RBN’s Canadian NatGas Billboard. This would be only the second time that an injection has taken place for this date (the other in 1995). In the first half of January, on average some of the coldest temperatures that are experienced over the course of the winter heating season, injections into Alberta storage are very rare with only three single day injections occurring since 1994 (including the latest), and a string of days from January 1-8 in 2006 when the province experienced its fourth warmest stretch of temperatures for that eight day span since 1900. After seeing a very strong drawdown for gas storage during December due to colder-than-average temperatures, the moderation in weather has quickly shrunk Alberta's year-on-year storage deficit to just 7 Bcf with storage standing at 433 Bcf as of January 13 (blue line and text in chart below), the second highest for this time of year (last year being the highest). As mentioned in our insight of December 24, even with the December cold, Alberta gas storage remains plentiful and a bearish factor for AECO prices, Western Canada’s most closely watched gas price index. Although temperatures in Alberta may be moderate at present, they are also moderate across much of North America, denting storage withdrawals, and coming at a time when Western Canada is registering very robust wellhead supplies. Another factor at work in the Canadian gas market is that gas intake to LNG Canada remains very uneven and well below capacity, leaving more gas available for the Alberta and North American markets.

Canadian LPG Stocks – Propane and Butane Remain Seasonally Low | RBN Energy - Western Canada’s propane inventories at the end of December 2025 (red line and text in left hand chart below) were posted at 5.3 MMbbl, with a less than average decline of 0.8 MMbbl versus November and stood 0.8 MMbbl (-13%) below the five-year average (blue line) according to data from the Canada Energy Regulator (CER). The smaller than average decline in the month likely reflected very strong propane production on the back of natural gas output in Western Canada that was near a record and contrasted against weather that was colder than average, with regional heating degree days (a measure of how cold were temperatures) that were 21% greater than last year and 9% more than the 30-year average. Preliminary estimates suggest that Western Canada's output of propane in December was near or above the record high of November. In Eastern Canada (right hand chart above), December propane stocks landed at 2.9 MMbbl, falling a slightly greater than average 0.6 MMbbl versus November, were 1.4 MMbbl (-32%) below the five-year average (blue line), and the lowest December reading since 2019. The region’s heating degree day count in December was 15% greater than a year ago and 12% more than the 30-year average. With Western Canada’s propane production likely near or at a record, combined with strong shipments to Eastern Canada by rail and by pipeline as a mix with butane down Enbridge’s Lines 1/5, an even larger reduction for the month was likely avoided. Butane stocks in Western Canada (red line and text in left hand chart above) fell a seasonally average 0.5 MMbbl in December to 2.7 MMbbl and were 0.7 MMbbl (-21%) below the five-year average (blue line). Butane stocks in Eastern Canada fell a greater than seasonal average 0.8 MMbbl to 1.5 MMbbl and stood 0.4 MMbbl (-21%) below the five-year average (right hand chart) and were at their lowest for December since 2021. The average decline in Western Canada’s butane stocks may have been a combination of strong or record production offsetting higher demand as a diluent in the oil sands with the strong possibility that that output of bitumen reached a record in December.

Canada Leverages Low AECO Prices, Global Diplomacy to Advance LNG Exports - Canadian officials are ramping up trade talks and cooperation agreements with key global natural gas buyers as it looks to accelerate development of more than 64 million tons/year (Mt/y) in LNG export capacity. Map of Western Canada natural gas pipelines highlighting operational, under-construction, and proposed LNG facilities, with major systems across British Columbia and Alberta, key supply basins such as Montney and Duvernay, and export routes to the Pacific Coast. At A Glance:
Canada-China LNG cooperation signed
India emerges as key LNG target
More than 64 Mt/y capacity proposed

While Neighbors Race for Natural Gas, U.S. Oil Giants Hesitate on Venezuela -Despite a potential historic opening in Venezuela’s energy sector, major U.S. oil and gas companies are remaining cautious. At A Glance:

• U.S. oil firms cite legal risk
• Natural gas prices stay weather driven
• Venezuelan gas boosts LNG supply outlook

Oil Majors Tell Washington They Want PDVSA Out of the Way --International oil companies are wasting no time testing how serious Washington and Caracas really are about reviving Venezuela’s oil industry. And their opening demand is refreshingly blunt: if we’re going to invest, we need to control our barrels. According to Reuters sources, international oil executives and lawyers are pushing for fast, targeted changes to Venezuela’s hydrocarbons law that would allow foreign partners to export the oil they produce directly, rather than handing it over to state oil company PDVSA to sell on their behalf. The ask is narrow by design. Leave PDVSA as majority owner, they say, but let international partners control their share of production, access export terminals, and—most importantly—get paid quickly. Oil companies are likely to be sticklers on the last point. Under the current framework, PDVSA controls sales and deposits proceeds into joint venture accounts. That system collapsed under U.S. sanctions, leaving billions of dollars owed to partners including Chevron, ENI, and Repsol. For oil companies with long memories, Venezuela isn’t short on geology—it’s short on trust. The industry is also pushing to roll back extra taxes layered onto the law in 2021, which pushed Venezuela’s government take to some of the highest levels in Latin America. Companies are signaling they can live with royalties and income tax. Extra taxes, opaque fees, PDVSA-controlled sales, delayed payments, or contracts open to interpretation, not so much. This legal pressure campaign dovetails neatly with the Trump administration’s broader strategy. According to a Friday interview with Axios, Energy Secretary Chris Wright said the U.S. is pursuing oil and critical minerals deals with Venezuela as part of a plan to stabilize the country economically and redirect exports away from China. The goal, Wright said, is higher production, cleaner flows, and a more predictable business environment—without U.S. government subsidies. What’s emerging is a pragmatic alignment. Washington wants oil flowing under U.S. supervision. Oil companies want export control and legal clarity. Caracas wants cash flow and investment yesterday.

Trump's control over Venezuela's oil threatens OPEC's influence, Washington to own 30% of market – WSJ --Donald Trump plans to resume oil production in Venezuela to lower global prices to $50 per barrel. This would allow the US to control about 30% of the world's raw materials market. Donald Trump's ambition to establish control over Venezuela's oil industry poses critical risks for the OPEC cartel. The US president's initiative to restore Venezuelan oil fields aims to lower global prices to $50 per barrel, which directly threatens the revenues of traditional oil exporters. This is stated in an article by The Wall Street Journal, writes UNN. According to JPMorgan's estimates, the consolidation of US, Guyanese, and Venezuelan capacities will allow Washington to control about 30% of the global raw materials market. Trump's inner circle is considering increasing Venezuela's oil production from the current 1 million to 3 million barrels per day within the next three years. This will require massive investments, but even the short-term expectation of increased supply is putting pressure on a market already suffering from an oil surplus. Against this backdrop, OPEC and Russia have already changed tactics. At a meeting on Sunday, January 11, the alliance members decided to suspend any increase in production during the first quarter of 2026 to prevent prices from falling further. Saudi Arabia maintains a wait-and-see approach, citing the critical state of Venezuelan infrastructure, the restoration of which will take years. At the same time, some OPEC members see potential benefits in Trump's actions: if the US cuts off Venezuelan oil supplies to China, Beijing will be forced to increase purchases from Persian Gulf countries.This shift could give the US greater influence over oil markets, potentially keeping prices historically lower and altering the balance of power on the international stage.

U.S. Exports to Europe Surge as Continent’s Pipeline Imports Fall, Asian Prices Still Weak -Europe’s pipeline imports continued to fall last year as increasing amounts of U.S. LNG entered the continent to displace Russian supplies in a trend that’s expected to continue. At A Glance:

• More LNG is being imported than pipeline gas
• Pipeline imports declined last year
• European LNG imports hit record in 2025

Record EU LNG Import Growth in 2025 Eclipses Piped Gas -Record LNG imports into the EU outpaced piped gas imports in 2025 as the superchilled fuel contributed to meeting stronger gas consumption in the region and filling the void left by the stoppage of piped Russian gas transited via Ukraine.

Greece Boosts LNG Imports, But Still Relies on Russian Gas - Greece boosted LNG imports in 2025, but Russian pipeline gas was still the largest source of supply, Greek gas transmission system operator (TSO) Desfa said in a report on Thursday.

U.S. Cold Snap, European Stock Draws Rekindle Upward Pressure on Natural Gas Prices - Dropping temperatures across the eastern United States and cautious LNG stockpiling in Europe is opening a door for upward price movements in the week ahead. Trailing 365-day mean temperatures versus seasonal normals for Northwest Europe, Beijing, Seoul, and Tokyo as of Jan. 13, 2026, highlighting recent deviations from typical weather patterns. At A Glance:
Eastern U.S. cold boosts heating demand
U.S. feed gas demand remains elevated
TTF rally supported by withdrawal risks

European Gas Prices Hit 10-Week High -Europe's benchmark front-month gas futures contract settled at a 10-week high on Wednesday due largely to weather and storage concerns, with the bull run showing no sign of stalling on Thursday.

Cold Weather In Europe Pushes Gas Prices 20 Pct Higher In A Week- Natural gas prices continue to rise amid unusually cold weather in parts of Europe, reaching their highest level in nearly six months, reported German Press Agency (dpa). Over the course of the trading week, the price of natural gas rose by about 20 per cent. On the Amsterdam exchange, the benchmark TTF futures contract for European natural gas delivery in one month was trading at €34.30 (US$39.80) per megawatt hour on Friday morning, its highest level since August. The price jump is the sharpest increase since October 2023. European gas reserves are currently at 52 per cent, well below the seasonal average of 67 per cent. The icy temperatures expected at the end of the month may lead to a further withdrawals of gas from storage sites. The tense situation in Iran, which is an important gas supplier for Turkey, has also had an impact on prices. Recent threats by the United States (US) government against countries that do business with Iran have increased supply concerns. The US has threatened new punitive tariffs of 25 per cent for Iran's trading partners. trading partners. The market is also factoring in stronger demand in China, the world's largest buyer of liquefied natural gas.

Problems with exports from Kazakhstan have driven up oil prices in Europe -The escalation of the situation regarding the export of Kazakh raw materials has led to an increase in oil prices in international markets. This has also affected the prices of oil from Azerbaijan and the USA. According to Bloomberg, the reduction in Kazakh oil supplies has significantly impacted the rise in prices in the European market, despite the existence of a global surplus. — The decrease in CPC Blend volumes from Kazakhstan, along with supply disruptions from Libya and several fields in the North Sea, have been the main factors contributing to the price increase in the northern and Mediterranean markets, — emphasizes the publication. On trading platforms on Tuesday, American WTI Midland oil reached a premium of $2.9 over Brent, the highest value in more than a year. Additionally, prices for Azerbaijani oil Azeri Light set a record for the past year. Although at the beginning of 2026, risks for the global oil market were associated with instability in Iran and Venezuela, in fact, the main impact came from Kazakhstan. The reduction in supplies through the CPC pipeline had the most significant effect on the market.

EU’s Russian Gas Exit Leaves Massive LNG Supply Gap as U.S. Volumes Surge - As the European Union (EU) moves to phase out all Russian natural gas supplies next year, questions are rising about the substantial LNG volumes the bloc would have to source elsewhere.Horizontal bar chart showing Europe’s LNG imports by region of origin from 2020 through 2025, highlighting the United States as the dominant supplier with rapidly growing volumes, alongside contributions from Russia, Qatar, North Africa, Sub-Saharan Africa, the Middle East, and other regions measured in million tons. At A Glance:
Russia remains EU’s second-largest LNG supplier
EU’s Russian gas ban begins 2027
Higher EU LNG imports support prices

Gazprom Exports More to China Than to Europe, Turkey Combined - Gazprom’s pipeline gas exports to China in 2025 for the first time exceeded the company's combined exports to Europe and Turkey, underscoring Russia’s eastward energy pivot, the state-run gas giant said on Jan. 12.

Pipeline leak causes gasoline spill at oil depot in Russia’s Murmansk | Caliber.Az - An oil depot in Olenegorsk, Murmansk Region, Russia, has recorded a spill of about 80 tons of AI-95 gasoline, according to the Telegram channel Tassovka. The incident was confirmed by the regional office of Russia’s Emergency Situations Ministry, per Caliber.Az. The ministry said the accident was caused by a loss of tightness in a pipeline connected to a gasoline storage tank.

U.S. to Asia LNG Arb Near One-Year Low as Global Natural Gas Flows Continue Shift -Russia's Gazprom PJSC said it again broke a record for daily natural gas supplies delivered to China on the Power of Siberia (POS) pipeline this week as its flows continue to shift eastward in an ongoing shakeup of the global natural gas market. Table showing U.S. Gulf Coast LNG netback prices for a 12-month strip as of January 12, 2026, comparing JKM (Japan/Korea), NBP, and TTF futures settlements, estimated shipping costs, and resulting Gulf Coast netbacks in $/MMBtu, with netbacks peaking near $9.90/MMBtu and margins versus Henry Hub exceeding $5.50/MMBtu across most months. At A Glance:
Russia sets new Power of Siberia record
Plans for second pipeline to China advancing
U.S. arb to Asia closed through year’s end

EIA: Global oil inventories will continue to increase through 2026, 2027 | Oil & Gas Journal -- Global oil inventories will continue to increase through 2026 and 2027, albeit at a more gradual rate in 2027, the US Energy Information Administration (EIA) predicted in its January 2026 Short-Term Energy Outlook (STEO). Brent crude oil prices are forecast to average $56/bbl in 2026 and $54/bbl in 2027, compared with an average of $69/bbl in 2025. Global crude oil prices declined through the second-half 2025, with the Brent crude oil spot price averaging $63/bbl in December, about $11 lower than in December 2024. Prices were flat or fell in every month during second-half 2025 as growing crude oil production and increasing volumes of oil in floating storage outweighed the effects of potential export disruptions linked to tensions in Russia and Venezuela. In the outlook, EIA expects global production of liquid fuels will increase by 1.4 million b/d in 2026 and 0.5 million b/d in 2027. Global liquid fuels production growth in 2026 is driven by crude oil production growth in OPEC+, while production growth in 2027 is driven by countries outside of OPEC+, primarily in South America. EIA’s forecast assumes existing sanctions on Venezuela remain in place through 2027. Global liquid fuels consumption increased by an estimated 1.2 million b/d in 2025 and is forecast to increase by 1.1 million b/d in 2026 and 1.3 million b/d in 2027. EIA noted that consumption growth rises in 2027 as global economic activity picks up pace. According to forecasts from Oxford Economics, global GDP will grow by 3.1% this year and 3.3% in 2027. Following an annual peak of 13.6 million b/d in 2025, EIA predicts that US crude oil production will again average about 13.6 million b/d this year. However, in 2027, EIA anticipates a decline in production to 13.3 million b/d, reflecting a 2% decrease from the 2026 forecast. According to EIA, with sustained lower crude oil prices, US crude oil production will decrease as the slowdown in drilling activity will outpace increases in drilling productivity. The West Texas Intermediate (WTI) price averages $52/bbl in 2026 and $50/bbl in 2027 in EIA’s forecast, down from $65/bbl in 2025. On an annual basis, US natural gas prices are relatively flat in 2026 before rising in 2027 as market conditions tighten. EIA expects the Henry Hub natural gas spot price will average just under $3.50/MMbtu this year, a 2% decrease from 2025, and then rise by 33% in 2027 to an annual average of almost $4.60/MMbtu. According to EIA, the substantial increase in Henry Hub spot price in 2027 is due to demand growth outpacing supply growth. Factors such as the expansion of US LNG export capacity and increased natural gas consumption in the electric power sector are expected to drive stronger demand, pushing storage inventories below the 5-year average and posting upward pressure on prices.

OPEC expects global oil demand to rise 1.34M bpd in 2027 -Crude oil production by the Organization of the Petroleum Exporting Countries (OPEC) rose by 105,000 barrels per day (bpd) in December 2025 compared to the previous month, reaching around 28.56 million bpd, according to the group's latest Monthly Oil Market Report. The largest output increase came from Iraq, while Venezuela recorded the biggest decline last month. Iraq’s daily oil production increased by 55,000 barrels to 4.1 million barrels, while Venezuela’s output declined by 60,000 barrels per day to 896,000 barrels in December. Total crude production by the OPEC+ alliance, comprising OPEC members and some major non-OPEC producers, fell by 238,000 bpd to 42.83 million bpd during the same period. OPEC kept its global oil demand growth forecast for 2026 unchanged, projecting an increase of 1.38 million bpd year-on-year, bringing total demand to 106.5 million bpd. Most of the growth is expected to come from non-OECD countries, where demand is seen rising by around 1.23 million bpd to 60.4 million bpd, led by China, Asian countries and Middle East. Demand in OECD countries is projected to rise by just 150,000 bpd to 46.09 million bpd, driven mainly by OECD Americas and supported by OECD Europe, and OECD Asia-Pacific. For 2027, OPEC expects demand to grow by around 1.34 million bpd, reaching 107.86 million bpd. This is expected to reach 61.67 million bpd in non-OECD countries, with an increase of 1.24 million bpd, and 46.19 million bpd in OECD countries, with a rise of 100,000 bpd.

OPEC crude oil production up 105,000 barrels per day in December -OPEC expects global oil demand to grow by 1.34 million barrels per day (bpd) in 2027, pointing to a delicate balance between supply and demand in the oil market. For the current year, the organization forecasts global oil demand growth of 1.38 million bpd, unchanged from last month’s estimate. In a report released today, OPEC projected oil demand in OECD countries to increase by 100,000 bpd next year, while demand in non-OECD countries is expected to rise by around 1.2 million bpd. The organization also kept its forecast for global economic growth unchanged at 3.1% in 2026, with growth expected to edge up to 3.2% in 2027, supported by a positive outlook for global trade. OPEC expects the US economy to expand by 2.1% in 2026 and 2.0% in 2027, while China’s economy is forecast to grow 4.5% in both the current and the following year.

Goldman projects lower oil prices in 2026 as supply swells - (Reuters) – Oil prices are likely to drift lower this year as a wave of supply creates a market surplus, although geopolitical risks tied to Russia, Venezuela and Iran will continue to drive volatility, Goldman Sachs said in a note on Sunday. The investment bank maintained its 2026 average price forecasts of $56/$52 per barrel for Brent/WTI, and expects Brent/WTI prices to bottom at $54/50 in the last quarter as OECD inventories build up. “Rising global oil stocks and our forecast of a 2.3mb/d surplus in 2026 suggest that rebalancing the market likely requires lower oil prices in 2026 to slow down non-OPEC supply growth and support solid demand growth, barring large supply disruptions or OPEC production cuts,” Goldman Sachs said. Brent crude futures were trading around $63 a barrel, as of 0412 GMT, while U.S. West Texas Intermediate crude holds ground at $59. Last year, both the benchmarks posted their worst annual performance since 2020, with an almost 20% decline. [O/R] U.S. policymakers’ focus on strong energy supply and relatively low oil prices will keep sustained oil price upside in check ahead of the midterms, analysts at the bank noted. Prices are expected to gradually start recovering in 2027, with the market returning to a deficit as non-OPEC supply slows down and solid demand growth continues, Goldman analysts said in a note. The investment bank expects Brent/WTI to average at $58/54 in 2027, although $5 lower than its prior estimate, citing upgrades to 2027 supply in the U.S., Venezuela and Russia by 0.3, 0.4 and 0.5mb/d, respectively. Goldman said it expects a substantial price recovery later this decade as demand grows through 2040 after years of low long-cycle investment, with 2030–2035 Brent/WTI prices averaging $75/$71, $5 below its previous estimate. Risks to the price forecasts are skewed modestly to the downside given a further increase in non-OPEC supply, Goldman said, adding that it expects no OPEC production cuts, despite geopolitical risks and low speculative positioning. “We still recommend investors short the 2026Q3-Dec2028 Brent time-spread to express the 2026 surplus view, and oil producers hedge 2026 price downside.”

Why 2026 could see a global oil surplus despite Middle East chaos - Oil prices steadied on Monday following strong gains last week, as markets weighed escalating unrest in Iran against signals that Venezuelan oil exports could resume. Brent and WTI futures remained near recent highs, reflecting caution among traders amid competing supply factors. Both benchmarks had risen more than 3% last week, marking their strongest weekly performance since October. In early trading, Brent crude futures for March delivery edged slightly lower to $63.16 per barrel, while West Texas Intermediate crude slipped to $58.87 per barrel. The modest movement followed last week’s rally, as investors refrained from taking aggressive new positions. Market participants continued to assess whether geopolitical developments would translate into actual supply disruptions. Focus remains firmly on Iran, where intensifying anti-government protests have raised concerns over potential supply disruptions from one of OPEC’s key producers. More than 500 people have reportedly been killed in the unrest, heightening fears of broader instability. Iranian officials warned that U.S. military bases in the region could be targeted if Washington intervenes, raising the risk of a wider confrontation. Any disruption to oil shipments through the Strait of Hormuz, a critical global supply route, would have significant implications for crude markets. Analysts note that Iran produces around 3.2 million barrels per day, leaving a meaningful amount of supply at risk if tensions escalate further. Oil price gains were limited by expectations that Venezuelan crude could return to the market. U.S. officials have signalled that restrictions on Venezuela’s oil sector may be eased, potentially allowing sanctioned barrels to be sold. Plans under discussion could result in tens of millions of barrels entering global supply chains, easing some of the tightness caused by geopolitical risks elsewhere. However, major oil companies remain cautious about re-entering the country without clearer legal and political protections. Investors are also monitoring developments in Russia, where ongoing attacks on energy infrastructure linked to the Ukraine conflict have raised concerns about potential supply interruptions. At the same time, the possibility of tougher U.S. sanctions on Russian energy exports continues to add uncertainty to the outlook. These risks have helped support crude prices, even as longer-term supply forecasts point toward surplus conditions. Looking ahead, analysts expect oil prices to face downward pressure as global supply growth outpaces demand. Forecasts indicate that rising inventories could lead to lower average prices in 2026 unless major disruptions occur or production cuts are introduced. While geopolitical risks tied to Iran, Venezuela and Russia are likely to keep volatility elevated, expectations of a supply surplus continue to cap sustained price upside.

Traders Assessed the Geopolitical Risks From Iran, Venezuela and Russia --The oil market on Monday traded higher as traders assessed the geopolitical risks from Iran, Venezuela and Russia driving the recent oil price volatility. The market weighed the concerns over Iran’s oil exports during the Iranian government’s crackdown of the largest anti-government demonstrations in years against expectations that supplies could increase from Venezuela. The crude market rallied to $59.80 on the opening after U.S. President Donald Trump reiterated his threats to strike Iran if the Iranian government crackdown on protests turned violent. However, the market erased its gains and traded to a low of $58.45 early in the morning as Iran’s Foreign Minister said the country’s security forces had full control of the country and was keeping communication open with the United States. The market was also assessing the possibility of Venezuela resuming its oil exports, with oil trading houses, Vitol and Trafigura starting talks with refiners in India and China for Venezuelan oil cargoes to be delivered in March. The market later retraced its earlier losses and rallied to a high of $59.81 ahead of the close. The February WTI contract settled up 38 cents at $59.50 and the March Brent contract settled up 53 cents at $63.87. The product markets ended the session higher, with the heating oil market settling up 1.94 cents at $2.1544 and the RB market settling up 1.32 cents at $1.7938. Shipping data intelligence firm Kpler said Iran has a record amount of oil on the water, equivalent to around 50 days of output, as China has bought less because of sanctions and Tehran seeks to protect its supplies from the risk of U.S. strikes. The amount of Iranian crude and condensate, either on tankers in transit or in floating storage vessels, reached a record high of 166 million barrels in the week ended January 11th. The upcoming annual rebalancing of commodity indexes will lead to the purchase of oil contracts, a bullish factor for crude. Citigroup projects that the BCOM and S&P GSCI indexes, the two largest commodity indexes, will see inflows of $2.2 billion in futures contracts this week to rebalance the indexes. Vortexa reported today that crude oil stored on tankers that have been stationary for at least 7 days fell -0.3% w/w to 120.9 million bbl in the week ended January 9. IIR Energy said U.S. oil refiners are expected to shut in about 724,000 bpd of capacity in the week ending January 16th, cutting available refining capacity by 450,000 bpd. Offline capacity is expected to increase to 1.1 million in the week ending January 23rd.

Oil prices settle at 7-week high on worries about Iran exports - (Reuters) - Oil prices climbed and settled at seven-week highs on Monday on worries that Iran's exports could decline as the sanctioned OPEC member cracks ‌down on anti-government demonstrations. Limiting price gains were expectations that supplies could rise from Venezuela, another sanctioned member of the Organization of the Petroleum Exporting Countries. Brent futures rose 53 cents, or 0.8% to settle at $63.87 a barrel. U.S. West Texas Intermediate crude rose 38 cents, or 0.6%, to settle at $59.50. It was Brent's highest settlement since November 18 and WTI's since December 5. Iran said it was keeping communications open with Washington as President Donald Trump weighed responses to a deadly crackdown on nationwide protests, among ‌the stiffest challenges to clerical rule since the 1979 Islamic Revolution. On Sunday, Trump said the U.S. may meet Iranian officials and he was in contact with Iran's opposition. He threatened possible military action over lethal violence against protesters. Iran has a record amount of oil on the water, equivalent to about 50 days of output, with China having bought less because of sanctions and Tehran seeking to protect its supplies from the risk of U.S. ‍strikes, data from Kpler and Vortexa shows. Venezuela is expected to resume oil exports soon following the ouster of President Nicolas Maduro. Trump said last week the government in Caracas was set to hand over as much as 50 million barrels of sanctioned oil to the U.S. Oil companies have been racing to find tankers and prepare operations to ship ⁠the crude safely, four sources familiar with the operations said. In a White House meeting on Friday, multinational commodities firm Trafigura said its first vessel should ‍load in the next week. Two China-flagged supertankers that were sailing to Venezuela to pick up debt-paying crude cargoes during the U.S. oil embargo on the OPEC country have made ‌a u-turn ‌and are now heading back to Asia, LSEG shipping data showed on Monday. Investors are also watching the risk of disruptions in supply from Russia, as Ukraine's attacks have targeted its energy facilities, and the prospects of tougher U.S. sanctions on Moscow's energy. In Azerbaijan oil exports dropped to 23.1 million tonnes in 2025 from 24.4 million tonnes in 2024, the energy ministry said on Monday. Russia and Azerbaijan are both members of OPEC+, which includes ⁠OPEC and allied producers. In Norway, the government said ⁠on Monday it will present a policy document to parliament next year on the future of the oil and gas industry, including companies' access to exploration acreage. "The oil and gas industry is crucially important for Norway, and should be developed, not phased out," Norway's Prime Minister Jonas Gahr Stoere said in a speech. U.S. bank Goldman Sachs said in a note ‍that oil prices are likely to drift lower this year as new supply becomes available and creates a market surplus, although geopolitical risks tied to Russia, Venezuela and Iran will continue to drive volatility. The Trump administration's move to open a criminal investigation into Federal Reserve Chair Jerome Powell escalates Trump's pressure campaign against the central bank. The Fed chief called the move a "pretext" to influence interest rates. Former Fed chiefs and key members ‍of Trump's Republican Party also criticized the investigation. Lower interest rates could boost economic growth and oil demand by reducing borrowing costs, but could hinder the central bank's efforts to control inflation.

Oil Prices Jump 2% Following Drone Strike at Major Black Sea Terminal -- Global oil prices surged on Tuesday as markets reacted to the escalating drone strikes at the Novorossiysk terminal, which handles roughly 2% of the world's daily supply. The disruption to the Caspian Pipeline Consortium (CPC) infrastructure, a vital artery for Kazakh exports managed by Western majors like Chevron and Shell, raised immediate fears of a prolonged supply squeeze. WTI was at $60.75, up 2.1%... While Brent was trading at $65.13, up 1.9%. Two oil tankers waiting to load crude from some of Kazakhstan’s biggest oilfields were hit by drones at the marine terminal of the Caspian Pipeline Consortium (CPC) near Novorossiysk on Russia’s Black Sea coast, sources told Reuters. The Caspian Pipeline Consortium Marine Terminal, a major oil export facility close to Novorossiysk, handles most of Kazakhstan’s crude oil exports, as well as some Russian crude supply. The Delta Harmony and the Matilda tankers were waiting to load crude from Tengizchevroil and Karachaganak, respectively, according to Reuters’ sources. Tengizchevroil, operating the supergiant Tengiz oilfield in Kazakhstan, is managed by a consortium led by U.S. oil and gas supermajor Chevron. Karachaganak, another giant field in Kazakhstan, is operated by a consortium comprising Shell, Chevron, and Italy’s Eni, among others. Drone attacks at or near the CPC terminal have intensified in recent weeks and have affected the loading and departure schedules of Kazakhstan’s crude cargoes. Kazakhstan’s oil output fell sharply at the end of November and early December after damage at the CPC export terminal disrupted flows. Output dropped in the first two days of December after storms and structural damage limited loading capacity at the Black Sea terminal, prompting producers to scale back throughput as storage filled.Kazakhstan relies on the CPC for roughly 80% of its crude exports. The disruption came at a sensitive moment for Kazakhstan, which was attempting to stabilize production following repeated CPC interruptions earlier in 2025. Oil has continued to flow, but at lower rates, while Kazakhstan sought to re-route some exports away from the Black Sea to keep supply relatively steady.CPC operates the pipeline from the Caspian coast in northwest Kazakhstan to the Novorossiysk port, which handles 80% of Kazakhstan’s crude exports from giant oilfields operated by international oil firms.Affiliates of Chevron and ExxonMobil are also minority shareholders in CPC, with the Russian Federation as its largest shareholder with a 24% stake.

Crude Rallies for Fourth Day Amid Geopolitical Risks - The oil market extended its gains for the fourth consecutive day on Tuesday amid the geopolitical tension in Iran and concerns over the potential impact on the country’s exports. Iran is currently facing its largest anti-government demonstrations in years and the Iranian government’s crackdown against protesters has drawn a warning from U.S. President Donald Trump of possible military action. He told Iranians that help was on the way and on Monday announced that any country that does business with Iran will be subjected to a tariff rate of 25% on any business conducted with the United States. The crude market posted a low of $59.47 in overnight trading before it continued on its upward trend. The market retraced more than 62% of its move from a high of $64.97 to a low of $54.89 as it rallied to a high of $61.50 by mid-day. The market later erased some of its gains and traded sideways during the remainder of the session. The February WTI contract settled up $1.65 at $61.15 and the March Brent contract settled up $1.60 at $65.47. The product markets ended the session higher, with the heating oil market settling up 8.4 cents at $2.2384 and the RB market settling up 3.27 cents at $1.8265. In its Short Term Energy Outlook, the EIA forecast world oil demand in 2026 at 104.8 million bpd, down 400,000 bpd from a previous forecast of 105.2 million bpd and demand in 2027 is estimated to increase to 106.1 million bpd. It forecast 2026 U.S. oil demand at 20.6 million bpd, unchanged from a previous forecast and expects demand to increase by 100,000 bpd to 20.7 million bpd in 2027. The EIA sees 2026 world oil output of 107.7 million bpd, up 300,000 bpd from a previous estimate, and sees 2027 output in 2027 at 108.2 million bpd. The EIA reported that U.S. crude oil production will fall in 2026 and 2027 after reaching a record high in 2025. It projected crude production would fall to 13.59 million bpd in 2026 and 13.25 million bpd in 2027, down from a record 13.61 million bpd in 2025. It said lower oil prices are expected to cut U.S. drilling activity and reduce output 1% this year, while potentially higher output from Venezuela could add pressure. The EIA forecast the average price of WTI in 2026 at $52.21/barrel, down 21 cents from a previous estimate, while the price of 2027 is expected to fall to $50.36/barrel. The price of Brent crude is forecast to average $55.87/barrel in 2026 and $54.02/barrel in 2027. According to monitoring service Tankertrackers.com and shipping records from PDVSA, at least two supertankers, not under sanctions, were departing Venezuelan waters on Monday carrying crude. The Panama-flagged very large crude carriers Kelly and Marbella, controlled by PDVSA as part of its ships under lease, set sail from PDVSA’s Amuay anchorage area on Venezuela’s western coast. They are carrying about 1.8 million barrels each of Venezuelan Merey heavy crude. Their intended destinations and whether the cargoes were part of the flagship supply deal announced by Trump were not immediately clear. Venezuela’s PDVSA has started reopening some of the wells it and its joint venture partners had shut amid a strict U.S. embargo, as crude exports resume with two shipments departed on Monday. The country’s overall crude output fell to some 880,000 bpd last week from 1.16 million bpd in late November, with its main oil region, the Orinoco Belt, seeing a drastic reduction to some 410,000 bpd compared with 675,000 bpd in late November.

WTI Crosses $61 as Trump Urges More Protests in Iran -- Crude futures reached 10-week highs Tuesday as U.S. President Donald Trump urged Iranians to continue protesting the regime in Tehran, adding to market concerns about supply from OPEC's fourth-largest producer. Oil prices had already been on a tear from the start of the session after Trump, in a social media post late on Monday, threated to impose tariffs on any country that did business with Iran. He followed that up with a call on Tuesday for Iranians to heighten their protests and "take over" institutions in the Islamic republic. "I have cancelled all meetings with Iranian Officials until the senseless killing of protesters STOPS. HELP IS ON ITS WAY," Trump wrote on his Truth Social media site. Trump indicated that his prior offer to negotiate a diplomatic outcome for Iran had passed, with deaths of thousands of people reported by human rights groups there, and that the U.S. might see through with its threat to launch air strikes. Iran, on its part, said it was ready for war with the U.S. Oil futures closed up for a fourth consecutive week on Friday as geopolitical risks curbed traders from adding substantially to short positions despite U.S... As OPEC's fourth largest producer with an output of 3.2 million barrels per day (bpd), Iran has limited customers for its oil due to U.S. sanctions imposed since Trump's first presidency in 2018. China is its largest buyer, reportedly acquiring than 80% of Iranian crude exports last year. Crude prices fell almost 20% last year but rebounded strongly since the start of 2026, despite a global glut of 3.8 million bpd warned by the International Energy Agency. The rally came on the back of the developments in Iran and Venezuela -- another OPEC member whose production of between 800,000 bpd and one million bpd has come under U.S. control. "We might be at an equilibrium now on supply concerns, with the Iranian production at stake making up more than 80% of the projected glut for this year," observed John Kilduff, partner at New York energy hedge fund Again Capital. According to reports on Monday, oil industry workers were among those who had joined nationwide strikes in Tehran. U.S. inflation data released on Tuesday had little impact on the market, with the Bureau of Labor Statistics reporting a 2.7% year-on-year growth in December Consumer Price Index -- unchanged from November. NYMEX WTI for February delivery settled up by $1.65, or 2.8%, at $61.15 barrek (bbl) after a 10-week high at $ 61.50. The March ICE Brent futures contract closed up $1.60, or 2.5%, at $65.47 after rallying to $65.92. Among refined products, the front-month ULSD futures climbed by $0.0812 to $2.2356 gallon. Front-month RBOB advanced by $0.0329 to reach $1.8549 gallon. The U.S. Dollar Index rose by 0.299 points to 98.93 against a currency basket.

Oil Prices Slide As Inventory Data Overshadows Geopolitical Risks - Global oil prices declined on Wednesday, reversing earlier gains as fresh data pointing to rising US crude inventories outweighed lingering geopolitical concerns in the Middle East. Brent crude, the international benchmark, fell to $64.59 per barrel, representing a decline of about 0.6% from Tuesday’s close of $64.98. Meanwhile, US benchmark West Texas Intermediate (WTI) crude slipped to $60.48 per barrel, down approximately 0.57% from its previous settlement of $60.83. The downward move followed a report from the American Petroleum Institute, which showed that US crude oil inventories increased by roughly 5.3 million barrels last week. The build significantly exceeded market expectations, which had forecast an increase of around 2 million barrels. The larger-than-anticipated rise in inventories renewed concerns about demand in the United States, the world’s largest oil consumer. As a result, traders shifted their focus away from supply-side risks, exerting fresh downward pressure on prices. Market participants are now awaiting official inventory figures from the US Energy Information Administration, scheduled for release later on Wednesday, for confirmation of crude supply trends. Earlier in the week, oil prices had gained support from heightened geopolitical tensions linked to developments in Iran. Investors closely monitored statements from Washington amid fears that escalating tensions could disrupt oil supplies from the region. US President Donald Trump warned on Tuesday that the United States was prepared to take “very strong action” if reports of planned executions of protesters in Iran were confirmed. He also urged anti-government demonstrators in Iran to continue their protests, signalling increased pressure on Tehran. In addition, Trump threatened to impose tariffs on countries maintaining trade ties with Iran, a move aimed at further isolating the regime and reinforcing geopolitical risk premiums in energy markets. Despite these tensions, expectations that global oil supply will continue to outpace demand have capped price gains. Analysts note that projections pointing to persistent oversupply are strengthening bearish sentiment, limiting the market’s ability to sustain rallies even amid geopolitical uncertainty.

Oil Market Swings on Middle East Developments and Rising U.S. Inventories -- The oil market on Wednesday extended its gains and settled higher for a fifth consecutive session, only to erase all of its earlier gains in the post settlement period. The sharp sell off followed U.S. President Donald Trump’s statement that killings in Iran were stopping, quelling market concerns of a possible military operation in Iran. In overnight trading, the crude market traded mostly sideways as its gains were limited by the large builds in crude stocks and products stocks reported by the API late Tuesday. However, the market traded higher after the U.S. late Tuesday urged its citizens to leave Iran immediately, while Iran warned U.S. allies in the Middle East it would strike U.S. bases on their soil if the U.S. attacked Iran. Also, the Pentagon advised some personnel to leave a U.S. military base in Qatar, further supporting the market. The crude market traded to $62.10 and traded sideways as it awaited for the release of the EIA’s weekly petroleum stocks report and any further developments in the Middle East. The market remained in a sideways trading range following the release of the inventory report, which showed a build of 3.4 million barrels on the week. The February WTI contract settled up 87 cents at $62.02. However, the crude market later traded to a high of $62.36 before it retraced more than 38% of its move from a low of $55.76 to a high of $62.36 as it sold off to a low of $59.77 in the post settlement period as concerns of a military operation in Iraq dissipated. Meanwhile, the March Brent contract settled up $1.05 at $66.52. The product markets ended the session higher, with the heating oil market settling up 4.35 cents at $2.2819 and the RB market settling up 39 points at $1.8304. In its monthly report, OPEC forecast world oil demand in 2027 would increase at a similar rate to this year and data in the study indicated a close balance between supply and demand in 2026. OPEC said that demand would increase by 1.34 million bpd in 2027, a similar rate to the growth of 1.38 million bpd expected this year. It reported that OPEC+ crude output averaged 42.83 million bpd in December, down 238,000 bpd on the month. It forecast world demand for OPEC+ crude would average 43 million bpd in 2026, unchanged from a previous forecast, and is expected to average 43.6 million bpd in 2027. Goldman Sachs is maintaining its forecast of stable Iranian crude production of 3.5 million bpd in 2026 following the Trump administration’s announcement that any country that does business with Iran will be subjected to a tariff rate of 25% on any business conducted with the United States. IIR Energy said U.S. oil refiners are expected to shut in about 724,000 bpd of capacity in the week ending January 16th, decreasing available refining capacity by 450,000 bpd. Offline capacity is expected to increase to 1.1 million in the week ending January 23rd. Exxon Mobil is preparing to run Venezuelan crude oil at its 522,500 bpd Baton Rouge, Louisiana refinery. The refinery previously ran Venezuelan heavy sour crude, but has not since sanctions were imposed on Venezuela. Chevron plans to run Venezuelan crude oil at its 356,440 bpd Pascagoula, Mississippi refinery. No date has been set for Venezuelan crude to arrive at the refinery.

Oil prices settle higher, then reverse gains after Trump eases worries about Iran (Reuters) - Oil prices settled higher on Wednesday, then gave back most of the day's gains after U.S. President Donald Trump eased fears of disruptions to Iranian supplies when he said late in the afternoon that killings in Iran’s crackdown on civil unrest were subsiding. Brent futures were down 92 cents or 1.41% at $64.55 after settlement at 3:18 p.m. ET (2018 GMT). U.S. West Texas Intermediate crude futures slipped 96 or 1.57% to $60.19. Earlier, Brent futures settled $1.05, or 1.6%, higher at $66.52 a barrel. U.S. West Texas Intermediate crude gained 87 cents, or 1.42%, at $62.02 a barrel. Prices rose on fears of Iranian supply disruptions due to a potential U.S. attack on Iran and possible retaliation against U.S. regional interests. Trump said on Wednesday afternoon he had been told that killings in Iran’s crackdown on nationwide protests were subsiding and he believed there was currently no plan for large-scale executions. "The market now thinks that maybe there is not going to be an attack on Iran so the stock market rallied and oil prices plummeted really quickly," Still, tensions between Tehran and Washington remained high. Iran had warned U.S. allies in the Middle East it would strike U.S. bases on their soil if the U.S. attacked it. The U.S. was from key bases in the region as a precaution given heightened regional tensions, a U.S. official said on Wednesday. "Protests in Iran risk tightening global oil balances through near-term supply losses, but mainly through rising geopolitical risk premium," Citi analysts said in a note. The analysts noted, however, that the protests had not spread to the main Iranian oil-producing areas, which had limited the effect on actual supply. Also supporting oil prices, Federal Reserve Bank of Minneapolis President Neel Kashkari said on Wednesday he was optimistic about the economic outlook and expected inflation to wane. U.S. crude and gasoline inventories both rose more than expected last week, the Energy Information Administration said on Wednesday, as refining activity and imports jumped. Crude stocks rose by 3.4 million barrels to 422.4 million barrels last week, the EIA said, compared with analysts' expectations in a Reuters poll for a 1.7 million-barrel draw. Gasoline stocks increased by 9 million barrels in the week to 251 million barrels, compared with analysts' expectations for a 3.6 million-barrel build. Also limiting price gains, Organization of the Petroleum Exporting Countries member Venezuela has begun reversing oil production cuts made under a U.S. embargo as crude exports were also resuming, three sources said. Two supertankers departed Venezuelan waters on Monday with about 1.8 million barrels each of crude in what may be the first shipments of a 50 million-barrel supply deal between Venezuela and the United States to get exports moving again following the U.S. capture of Venezuelan President Nicolas Maduro.

Oil Prices Plunge 3% as Trump Plays Down Prospect of War With Iran -Oil prices fell sharply in early Asian trade on Thursday, with both major crude benchmarks retreating by around 3 percent as markets reacted to comments from U.S. President Donald Trump that appeared to lessen the likelihood of an imminent U.S. military strike on Iran. At the time of writing, WTI crude was down $1.86, or 3.00 percent, at $60.16 per barrel, while Brent crude stood at $64.57, down $1.95, or 2.93 percent on the day. This drop in prices represents a significant reversal from earlier in the week when geopolitical risk sent prices climbing aggressively. Trump’s claim that he had been told that killings of protesters in Iran were subsiding and that there were no plans for large-scale executions signalled a lower probability of direct U.S. military action against Tehran. This reduced the geopolitical risk premium that had been supporting oil prices. Later, in an exclusive interview with Reuters, the president expressed doubts over whether Reza Pahlavi, the son of the former shah of Iran, would be able to garner support in the country. With the geopolitical risk premium subsiding somewhat, traders could focus on bearish fundamentals, with U.S. crude inventories climbing by more than analysts expected last week. It is also looking increasingly likely that Venezuela's oil supply is set to return to markets, with the U.S. completing its first sale of Venezuelan oil on Wednesday. While markets may have cooled somewhat on the back of President Trump's comments, protests in Iran have persisted, and there remains plenty of uncertainty over what might come next.

Oil Prices Drop as Trump Signals US Action in Iran – Oil prices fell sharply on Thursday after US President Donald Trump suggested that violence in Iran had decreased and that a US military response was not likely in the near term. Brent crude for March delivery dropped 4.15% to $63.76 a barrel, while West Texas Intermediate (WTI) for February delivery fell 4.56% to $59.19. Trump, who had previously threatened intervention in response to Iran’s crackdown on protests, offered a softer message at a White House event on Wednesday. When asked whether military action was off the table, he said Washington would “watch it and see” how events unfold. He added that “the killing has stopped,” citing reports from sources in Iran. The White House confirmed Thursday that Tehran had suspended plans to execute 800 protesters that had been scheduled for Wednesday. Analysts said markets interpreted the comments as a signal that tensions in Iran might ease, reducing the risk premium that had lifted prices in recent days. Oil also faced pressure from supply-side developments. The US has moved to take control of Venezuelan oil resources after the capture of President Nicolás Maduro, completing a $500 million sale, the first since Washington assumed oversight of the sector. Further sales may follow in the coming weeks. Traders had priced in the possibility of a military escalation in the Middle East, a region crucial to global energy supply. With that threat appearing less likely and additional supply entering the market, the structure of oil prices became fragile once again. Investors now watch for any signals that could reverse the calm, knowing that even small changes in the region can affect global prices.

Oil Futures Fall 4% as Trump Winds Down US-Iran Tensions - -- Crude futures tumbled by more than 4% Thursday after a wind down in U.S.-Iran tensions snapped a five-day rally in oil. Concerns that inventories of U.S. crude and gasoline could pile up amid seasonally weak winter demand for fuels also weighed on markets. "It's back to the drawing board on supplies, only this time the focus is on the likelihood that we have more supply than we need, and that prices need to correct after going up too much, too fast," Oil futures closed up for a fourth consecutive week on Friday as geopolitical risks curbed traders from adding substantially to short positions despite U.S... In the span of a week between last Wednesday (1/7) and yesterday (1/14), crude prices jumped almost 9%, hitting three-month highs, as anti-government demonstrations in Iran sparked concerns about the future of crude supplies from a country ranked OPEC's fourth largest producer, with an output of 3.2 million barrels per day (bpd). Heightening the tensions were U.S. President Donald Trump's urging that the protests in Iran continue, while he hinted at the same of airstrikes against the regime in Tehran if civilian deaths mounted. But Trump suddenly switched course Wednesday afternoon, saying he had been informed that the situation in Iran was improving. That led to a dramatic pullback in crude prices. Supply risks also abated amid reports that Venezuela had begun to restart some of its crude production forcibly shut by U.S. sanctions. The development came after secondary sources polled by OPEC reported Venezuelan output in December at below the 900,000-bpd mark for the first time since May. Surging U.S. inventories had put the market on a backfoot too. U.S. Energy Information Administration data Wednesday showed gasoline up 9 million barrels (bbl) in the week ended Jan. 9, and commercial crude oil inventories growing 3.4 million bbl -- propelling stocks 3.1% and 2.4% above year-ago levels, respectively. NYMEX WTI futures contract for February delivery settled down $2.83, or 4.6%, at $59.19 bbl. ICE Brent for March delivery closed down $2.76, or 4.2%, at $63.76 bbl. Front-month NYMEX ULSD futures contract slid $0.0792 to $2.2027 gallon, and RBOB futures contract for February delivery retreated $0.0529 to $1.8076 gallon. The U.S. Dollar Index rose 0.213 points to 99.12 against a basket of foreign currencies.

Oil Prices Tread Water as Supply Surplus Neutralizes Geopolitical Risk - Oil markets remain locked in a narrow trading range as structural supply dynamics continue to dominate price formation, limiting the impact of recurring geopolitical headlines. Front-month WTI crude trades near $59.10 per barrel while Brent holds around $63.64, both easing after brief rallies driven by unrest in Iran and renewed supply risk rhetoric linked to Venezuela. The swift reversals underscore a market that reacts quickly to geopolitical developments but struggles to sustain momentum in the absence of tangible disruptions to physical flows. The underlying constraint on prices is a growing global supply surplus that has become increasingly difficult for sentiment to overpower. Industry data and major forecasters point to robust output from non OPEC producers and steady flows from the Middle East and Russia, despite sanctions and political noise. As a result, inventory levels continue to build, reinforcing the view that recent price spikes are driven by positioning and headlines rather than genuine shortages. In this environment, geopolitical risks are translating into short-lived volatility rather than a durable repricing of crude. Market behavior reflects this imbalance. Each surge linked to conflict escalation or sanctions rhetoric has been met with selling pressure once traders reassess the absence of meaningful bottlenecks in exports or transportation routes. This dynamic keeps crude prices rangebound and limits upside follow-through, even as geopolitical risks remain elevated across several producing regions. For investors, the implication is that oil prices will remain sensitive to news flow but anchored by surplus conditions. In the base case, crude continues to trade within recent ranges as supply growth offsets incremental demand gains, keeping WTI near the upper $50s and Brent in the low $60s. The key variable to watch is Chinese demand, where a sustained revival could absorb excess barrels and tighten balances. The risk scenario lies in continued demand softness combined with rising inventories, which would increase downside pressure and potentially push prices toward the lower end of the current range. Until either demand strengthens materially or physical supply is disrupted at scale, oil markets are likely to remain driven by headlines without escaping their underlying fundamental constraints.

Oil prices extend losses as chance of US strike on Iran recedes - Oil prices extend losses as chance of US strike on Iran recedes (Reuters) - Oil prices fell in Asian trade on Friday, extending losses from the previous session, as concerns about supply risks eased after the likelihood of a U.S. strike on Iran receded. Brent was down 21 cents, or ‌0.3%, to $63.55 per barrel, while U.S. West Texas Intermediate fell 15 cents, or 0.3%, to $59.04 per barrel at ‌0418 GMT. Both Brent and WTI rose to multi-month highs this week after protests flared up in Iran and U.S. President Donald Trump signalled the potential for strikes on the nation. Brent prices were still set for a fourth week of gains. Late on Thursday, however, Trump said ⁠Tehran's crackdown on the protesters was ‌easing, allaying worries about possible military action that could disrupt oil supplies. Brent prices have given back earlier gains but remain higher than a ‍week ago, with the decline in prices spurred by Trump's statement that he would hold off on military strikes on Iran, BMI analysts said in a note. "Given the potential political upheaval in Iran, oil prices are likely to experience greater volatility as markets digest the potential for ‌supply disruptions," they said. Analysts remained bearish on expectations of longer supply in the market this year despite earlier OPEC expectations for a balanced market. "Sentiment is driving markets, but the impact of headlines is always short-lived, especially when fundamentals look comfortable in the backseat," said Phillip Nova senior market analyst Priyanka Sachdeva. "Despite the steady drumbeat of geopolitical risks and macro ⁠speculation, the underlying balance still points to ample supply ... unless we see a genuine revival in Chinese demand or a meaningful bottleneck in physical barrel flows, oil looks range-bound, with Brent broadly hovering between $57 and $67." On Wednesday, OPEC said oil supply and demand ‍would remain balanced in ⁠2026, with demand rising in 2027 at a similar pace to growth for this year. Oil giant Shell released its 2026 Energy Security Scenarios on Thursday, making ⁠a bullish case for energy demand and oil growth. The company estimated that primary energy demand by 2050 ‌could be 25% higher than last year.

Oil prices on track for weekly gain despite selloff as Trump eases Iran fears - Oil prices rose Friday, bouncing after a sharp selloff in the previous session as U.S. President Donald Trump played down the risk of military action against Iran, easing supply disruptions fears. At 04:35 ET (09:35 GMT), Brent Oil Futures expiring in March edged up 0.9% to $64.35 per barrel and West Texas Intermediate (WTI) crude futures gained 1.1% $59.84/barrel. Both contracts plunged more than 4% in the previous session, but are still on course for weekly gains. Thursday’s steep decline came after Trump told reporters that Washington was not planning imminent military action against Iran, helping deflate a geopolitical risk premium that had built up rapidly at the start of the week. Earlier this week, oil prices had surged to multi-month highs as widespread anti-government protests in Iran raised concerns that crude exports from one of OPEC’s largest producers could be disrupted. Those worries were amplified after Trump issued warnings over the use of lethal force against protesters, interpreted as increasing the likelihood of U.S. military intervention. "Any escalation with Iran will also raise concerns about potential disruption to oil flows through the Strait of Hormuz, a choke point where around 20m b/d passes," ING analysts said, in a note. "While risks have eased somewhat, they remain significant, keeping the market nervous in the short term," ING added. "However, the longer this goes on without any U.S. intervention, the risk premium will continue to fade, allowing more bearish fundamentals to dominate," they added. Venezuela’s oil exports resume Trump has also moved to ease tensions with Venezuela, signaling support for the country’s continued role in OPEC and opening the door for Venezuelan oil exports to return more fully to global markets. Venezuela’s state-run oil firm PDVSA has started rolling back production cuts introduced under a tough U.S. oil embargo, as crude exports resume with U.S. oversight, Reuters reported on Thursday, citing sources. Shipments had dropped to near zero after the December blockade, leaving only Chevron exporting under a U.S. license, the report said. Any increase in Venezuelan supply would add barrels to an already well-supplied market. U.S. inventory data this week showing higher crude and fuel stockpiles also weighed on prices, reinforcing concerns about oversupply.

Oil prices settle up as US begins holiday weekend (Reuters) - Oil prices settled higher on Friday as some investors covered short positions ahead of the three-day Martin Luther King holiday weekend in the U.S. and lingering worries about a possible U.S. military strike against Iran. Brent crude settled at $64.13 a barrel up 37 cents or 0.58%. U.S. West Texas Intermediate finished at $59.44 a barrel up 25 cents, or 0.42%. Most of Friday's gains seemed to be due to buying supply ahead of the long weekend. "With that carrier strike group making the move to the (Persian) Gulf, it doesn't seem likely anything will happen soon," The U.S. Navy's aircraft carrier U.S.S. Abraham Lincoln was expected to arrive in the Persian Gulf next week after operating in the South China Sea. Weighing against those fears are potential supply increases from Venezuela, said Phil Flynn, senior analyst with Price Futures Group. "The supply from Venezuela has not become the tidal wave that was expected," Flynn said. "Buying today seems to be people not wanting to be caught short over the long weekend." Both benchmarks hit multi-month highs this week after protests flared up in Iran and U.S. President Donald Trump signalled the potential for military strikes, but lost over 4% on Thursday as Trump said Tehran's crackdown on the protesters was easing, allaying concerns of possible military action that could disrupt oil supplies. "Above all, there are worries about a possible blockade of the Strait of Hormuz by Iran in the event of an escalation, through which around a quarter of seaborne oil supplies flow," Commerzbank analysts said in a note. "Should there be signs of a sustained easing on this front, developments in Venezuela are likely to return to the spotlight, with oil that was recently sanctioned or blocked gradually flowing onto the world market." Analysts expect higher supply this year, potentially creating a ceiling for the geopolitical risk premium on prices. "Despite the steady drumbeat of geopolitical risks and macro speculation, the underlying balance still points to ample supply," said Phillip Nova analyst Priyanka Sachdeva. "Unless we see a genuine revival in Chinese demand or a meaningful bottleneck in physical barrel flows, oil looks range-bound, with Brent broadly hovering between $57 and $67."

Yemen’s Separatists Rule Out Call to Integrate Into Saudi-Led Government - While the Saudis and their allies in the self-proclaimed Yemeni “government” are treating the disputed dissolution of the separatist STC as a fait accompli, the reality of the situation continues to elude their diktats, and STC officials are rejecting calls for their forces to come under the direct control of Saudi Arabia. STC Vice President Faraj al-Bahsani said Sunday that the notion of unifying everyone under a single coalition would be “difficult” in general, and that the STC would absolutely not accept this plan, as announced by that putative government.Maj. Gen. Ibrahim Haidan, from the Saudi-backed forces, announced his intention to unite the forces loyal to the STC and all other militias outside their control under a single coalition, which Saudi officials made clear Sunday would be directly under their command. Rashad al-Alimi, nominally the head of the “government” faction’s Presidential Council, reiterated those intentions and said any support for any militia remaining outside the government’s control would only “fuel terrorism.”This plan rests on the idea that the STC, which seeks to establish Southern Yemen as a separate country, no longer effectively exists, because the Saudi state media announced their dissolution by way of negotiators the STC dispatched to Riyadh last week, who promptly went incommunicado.The STC, for their part, insists they’ve still not been able to talk to any of their negotiating team in Riyadh, nor have any of their family members been able to contact them. The Saudis appear to be holding that team, and are using that to advance the narrative that the group has disbanded, despite it still very much existing within Yemen itself.Though the Saudis attacked the STC while the negotiating team was en route, and their allies claim to control the historic South Yemen capital of Aden, major pro-STC protests continue to erupt in Aden.In practice, the pro-Saudi government of Yemen is a government in exile. Yemen’s capital of Sanaa is under the control of the Houthis, officially known as Ansar Allah, and Aden, which the Saudis declared the “temporary capital of Yemen,” isn’t really under their control either. Maj. Gen. Haidan confirmed as much, saying “additional time” was needed before the government could actually establish a permanent presence within Aden.

As Iran’s Government Tries to Quell Protests, Accounts of Brutal Crackdown Emerge - The New York Times -As the Iranian authorities impose a near-total communication blackout on a country convulsed by mass protests, videos and witness accounts slowly emerging suggest that the government is waging one of its deadliest crackdowns on unrest in more than a decade. Eyewitnesses say government forces have begun opening fire, apparently with automatic weapons and at times seemingly indiscriminately, on unarmed protesters. Hospital workers say protesters had been coming in with pellet injuries but now arrive with gunshot wounds and skull fractures. One doctor called it a “mass-casualty situation.” Despite the communications blockade, a recurring image has made its way out of Iran: rows and rows of body bags. In videos uploaded by opposition activists on social media, families can be seen sobbing as they huddle together over bloodied corpses in unzipped bags. And in footage aired on Iranian state television, a morgue official, sheathed in blue scrubs, stands amid bags neatly arranged along the floor of a white room, under glaring fluorescent lights. The state broadcaster said the images show the danger that protests pose to Iran’s society: “There are individuals in these gatherings who want to drag ordinary people — people who have nothing to do with these events — and their families into this situation. So that they too are drawn into the chaos,” the reporter in the voice over said. “I have never seen images like these in my life before.” Those who still support Iran’s theocratic government and those in the streets calling for its downfall agree: These are days of brutality unlike anything they have ever seen. The toll of dead and injured across the country is unclear. Human rights groups are struggling to reach their contacts inside Iran and follow the methodology they normally use to verify information but say they have counted more than 500 dead. Multiple American officials say that U.S. intelligence agencies have conservatively estimated that more than 600 protesters have been killed so far. The agencies have noted that both the current protests and the crackdown are far more violent than those in 2022 or other recent uprisings against the government. A senior Iranian health ministry official, speaking on the condition of anonymity, said about 3,000 people had been killed across the country but sought to shift the blame to “terrorists” fomenting unrest. The figure included hundreds of security officers, he said. Another government official, also speaking on the condition of anonymity, said he had seen an internal report that referred to at least 3,000 dead, and added that the toll could climb. If confirmed, the death toll would be among the worst in recent Iranian history. Witnesses spoke of seeing snipers positioned on rooftops in downtown Tehran and firing into crowds; of peaceful protests turning abruptly into scenes of carnage and panic as bullets pierced through people’s heads and torsos, sending bodies toppling to the ground; and of an emergency room treating 19 gunshot patients in a single hour. “The regime is on a killing spree,” said one protester, Yasi. She, like other Iranians interviewed by The New York Times, asked that her full name be withheld for safety. Yasi, who is in her 30s and works for a publishing company, said she was marching along Andarzgoo Boulevard in Tehran on Friday night with friends when security forces stormed in and shot a teenage boy in the leg as his mother looked on. “My son! My son! They shot my son!” the woman cried, Yasi said. Videos posted to social media on Monday night and verified by The New York Times showed a large crowd of protesters in Tehran. The sound of gunfire could be heard, and the cry: “Death to the dictator!” For the past five days, the Iranian authorities have shut down the internet, international phone lines and sometimes even domestic mobile phone connections. That has left rights groups, journalists and families alike struggling to understand the scope of what has happened. But videos trickling out of the country and the messages of some Iranians who occasionally get satellite internet connections offer a devastating picture of bloodshed. “I managed to get connected for a few minutes just to say it’s a blood bath here,” Saeed, a businessman in Tehran, told The Times. He said he was using a Starlink internet connection late on Sunday. When protests over the dire Iranian economy broke out in Tehran’s marketplace, on Dec. 28, Saeed took to the streets to join them. He had done the same during the protest movement in 2022 and those before it, he said. But as Iran descends into deeper isolation, it has become increasingly clear, he said, that this crackdown is “unlike any of the protests that came before.” “I personally saw a young man get shot in the head,” he told The Times in recorded audio messages. “I witnessed someone get shot with a bullet to the knee. The person fell to the ground unconscious, and then security forces gathered over him.”

The death toll from a crackdown on protests in Iran jumps to at least 2,571, activists say --(AP) — The death toll from nationwide protests in Iran has surpassed 2,500, activists said, as Iranians made phone calls abroad for the first time in days Tuesday after authorities severed communications during a crackdown on demonstrators. The number of dead climbed to at least 2,571 early Wednesday, as reported by the U.S.-based Human Rights Activists News Agency. That figure dwarfs the death toll from any other round of protest or unrest in Iran in decades and recalls the chaos surrounding the country’s 1979 Islamic Revolution.Iranian state television offered the first official acknowledgment of the deaths, quoting an official saying the country had “a lot of martyrs.”The demonstrations began in late December in anger over Iran’s ailing economy and soon targeted the theocracy, particularly 86-year-old Supreme Leader Ayatollah Ali Khamenei. Images obtained Tuesday by The Associated Press from demonstrations in Tehran showed graffiti and chants calling for Khamenei’s death — something that could carry a death sentence. As the reported toll grew Tuesday, U.S. President Donald Trump wrote on his Truth Social platform: “Iranian Patriots, KEEP PROTESTING - TAKE OVER YOUR INSTITUTIONS!!!” He added: “I have canceled all meetings with Iranian Officials until the senseless killing of protesters STOPS. HELP IS ON ITS WAY.” However, hours later, Trump told reporters that his administration was awaiting an accurate report on the number of protesters that had been killed before acting “accordingly.”Trump said about the Iranian security forces: “It would seem to me that they have been badly misbehaving, but that is not confirmed.”Iranian officials once again warned Trump against taking action, with Ali Larijani, secretary of Iran’s Supreme National Security Council, responding to U.S. posturing by writing: “We declare the names of the main killers of the people of Iran: 1- Trump 2-” Israeli Prime Minister Benjamin Netanyahu.The activist group said 2,403 of the dead were protesters and 147 were government-affiliated. Twelve children were killed, along with nine civilians it said were not taking part in protests. More than 18,100 people have been detained, the group said.Gauging the demonstrations from abroad has grown more difficult, and the AP has been unable to independently assess the toll. Skylar Thompson with the Human Rights Activists News Agency told AP the new toll was shocking, particularly since it reached four times the death toll of themonthslong 2022 Mahsa Amini protests in just two weeks.She warned that the toll would still rise: “We’re horrified, but we still think the number is conservative.”Speaking by phone for the first time since their calls were cut off from the outside world, Iranian witnesses described a heavy security presence in central Tehran, burned-out government buildings, smashed ATMs and few passersby. Meanwhile, people were concerned about what comes next, including the possibility of a U.S. attack.“My customers talk about Trump’s reaction while wondering if he plans a military strike against the Islamic Republic,” said shopkeeper Mahmoud, who gave only his first name out of concern for his safety. “I don’t expect Trump or any other foreign country cares about the interests of Iranians.”Reza, a taxi driver who also gave just his first name, said protests are on many people’s minds. “People — particularly young ones — are hopeless, but they talk about continuing the protests,” he said.

Report: Kurdish Fighters Have Been Entering Iran From Iraq and Clashing With the IRGC - Turkish intelligence has warned Iran’s Islamic Revolutionary Guard Corps (IRGC) that Kurdish fighters have been entering Iran from Iraq amid protests inside Iran, Reuters reported on Wednesday.An unnamed senior Iranian official speaking to the outlet said that the IRGC has been clashing with armed Kurdish fighters dispatched from both Iraq and Turkey. The Kurdistan Freedom Party, or PAK, a Kurdish Iranian separatist group mainly based in Iraq, has been claiming that its armed wing has been conducting operations against Iranian forces.On Tuesday, the PAK claimed its forces launched an attack on an IRGC base in western Iran. TheReuters report and claims of Kurdish attacks come as Tehran is accusing the US and Israel of arming “terorrists” inside Iran who have attacked Iranian security forces.The US has a significant presence in Iraqi Kurdistan, including a military base and an $800 million consulate compound that it opened in December. The Israeli Mossad is also known for having a presence in the area, and Iran claimed that it attacked a Mossad base in Iraqi Kurdistan in 2024.The Mossad has a long history of covert operations inside Iran, and a Farsi-language X accountaffiliated with the Israeli spy agency suggested it had operatives on the ground in Iran when the protests first broke out. “Let’s come out to the streets together. The time has come. We are with you. Not just from afar and verbally. We are with you in the field as well,” the account said on December 29. Israel’s Channel 14 has reported that “foreign actors” have armed protesters in Iran and said that’s the reason why hundreds of Iranian security personnel have been killed.“We reported tonight on Channel 14: foreign actors are arming the protesters in Iran with live firearms, which is the reason for the hundreds of regime personnel killed,” Channel 14 reporter Tamir Morag wrote on X on Tuesday. “Everyone is free to guess who is behind it.”

Iran & Israel Secretly Agreed Not To Attack Each Other Through Russian Backchannel --There may have been some back-channel dealmaking and a 'mutual understanding' reached between Iran and Israel far behind the scenes as protests unfolded on Iran's streets, and as President Trump began to make threats about striking Tehran.At a moment Trump seems to have climbed down (at least for now) from the threatened drive to intervene militarily, The Washington Post has issued a Wednesday report saying Israel and Iran have been in indirect diplomatic contact via Russia as a mediator."Days before protests erupted in Iran in late December, Israeli officials notified the Iranian leadership via Russia that they would not launch strikes against Iran if Israel were not attacked first," WaPo writes. "Iran responded through the Russian channel that it would also refrain from a preemptive attack, diplomats and regional officials with knowledge of the exchange said."Could this be because of the Iranian missiles that rained down on Tel Aviv back in June? If so, it seems the Islamic Republic has finally established deterrence. The timeline of what was communicated when remains unclear. But this backchannel had already been revealed in Middle East media reports, for example in the following prior reporting:Israel and Iran have recently exchanged secret, indirect messages through Russia in the midst of heightened regional tensions, according to a new report by Amwaj.media today. The exchanges were described as an effort to prevent further military escalation rather than to establish any form of ceasefire or diplomatic framework.According to the report, the messages were conveyed through Russian President Vladimir Putin after Israel sought to pass along a signal that it was not interested in escalating military conflict at this stage. Iranian officials acknowledged the message but emphasized that their reply carried no commitment, no coordination, and no obligation on Iran’s part. An Iranian political source quoted in the report said bluntly that “there is no commitment, no coordination, and no ceasefire agreement.” The source emphasized that the contact should not be interpreted as a step toward broader understandings between the two countries, which remain bitter adversaries with no direct diplomatic ties.The exchanges were reportedly limited in scope and intent. No guarantees were offered, no timelines were discussed, and no monitoring or enforcement mechanisms were established. One source described the communication as “a mutual announcement to a mutual friend on no new strikes,” meaning that the goal was simply to manage tensions at a specific moment rather than to lock in any lasting arrangement.A senior Iranian political source confirmed that indirect communication with Israel had indeed taken place, identifying Russia, and specifically Putin, as the intermediary. The source reiterated that there was “no ceasefire agreement” and that the messages amounted only to parallel notifications of intent, rather than a shared understanding or deal.The report says the Iranian side of the exchanges was handled not by the foreign ministry but by Ali Larijani, secretary of Iran’s Supreme National Security Council. It's possible that this served as important background to Trump's apparent decision to not strike Iran at this point. Israel is usually the country yelling loudest to hit Iran, but this time the Netanyahu government was somewhat muted.

Israel Has Demolished 2,500 Buildings in Gaza Since Signing Ceasefire Deal - Israeli forces have destroyed more than 2,500 buildings in Gaza since the signing of the ceasefire deal in early October, The New York Times reported on Monday, citing satellite imagery from Planet Labs. The majority of the demolitions have occurred on the Israeli-occupied side of the so-called “yellow line,” the vague boundary separating the two sides of Gaza, but the IDF has also destroyed dozens of buildings beyond the yellow line. The Times report cited Husam Badran, a Hamas official who said the demolitions were a violation of the ceasefire deal, which calls for the halt of “all military operations” in Gaza. “The agreement isn’t vague, it’s clear,” he said. “Destroying people’s homes and property isn’t allowed. They’re hostile actions.” The IDF has justified the demolitions by claiming it is only destroying Hamas infrastructure and tunnels, but others have noted the indiscriminant nature of the campaign, which has involved the destruction of entire residential blocks, farmland, and greenhouses. “This is absolute destruction,” Shaul Arieli, a former IDF officer, told the Times. “It’s not selective destruction, it’s everything.” Mohammed al-Astal, a political analyst based in Gaza, told the paper that the IDF is “destroying everything in front of it — homes, schools, factories, and streets. There’s no security justification for what it’s doing.”

Seven Children Dead from Cold in Gaza amid Storms and Collapsing Shelters - The Ministry of Health in the Gaza Strip announced on Monday that three children have died from extreme cold, bringing the total number of child deaths since the start of winter to seven, as officials warned of catastrophic consequences from an incoming polar weather system threatening around 1.5 million Palestinians. Civil Defense authorities and Al-Shifa Hospital also reported four additional deaths caused by partial collapses of war-damaged buildings west of Gaza City, triggered by strong winds and heavy rain battering the enclave. In the central Gaza Strip, thousands of displaced residents in the Nuseirat refugee camp were forced to seek shelter inside mosques and partially destroyed structures after violent winds tore down their tents. Civil Defense spokesperson Mahmoud Basal told Anadolu Agency that a new polar air depression began affecting Gaza on Tuesday, warning that its impact could be devastating for families already living in dire conditions. He said more than 1.5 million people are currently sheltering in tents, many of which are unable to withstand severe weather. Basal warned that the deteriorating conditions could lead to further casualties, as well as the collapse of unstable buildings and the flooding of displacement camps. He renewed his appeal to the international community and humanitarian organizations to urgently intervene, stressing the need to provide assistance that preserves civilians’ dignity and prevents further loss of life. Palestinian weather forecaster Laith Al-Alami said the Palestinian territories are being affected by a deep and stormy low-pressure system from Monday night through Tuesday evening, accompanied by a very cold polar air mass. He warned of sharply dropping temperatures, strong winds—particularly along the coast—and heavy rainfall across all governorates, including Gaza, with the possibility of thunderstorms and hail. He cautioned that high wind speeds pose a serious threat to tents housing displaced families.

Ukraine Reports 200,000 Soldiers AWOL, 2 Million Ukrainians Avoid Conscription - The Ukrainian military revealed some of its struggles to get men in uniform and remain on the frontlines. “I don’t want to be a populist — I want to be a realist,” Defense Minister Mykhailo Fedorov said. “The Ministry of Defense is coming into my hands with a [$6.7 million] shortfall, two million Ukrainians who are wanted and 200,000 who are AWOL.” Ukrainska Pravda reports the number of desertions is significantly higher, nearly 300,000. The Russian invasion of Ukraine has turned into a four-year-long war of attrition. As a much larger country, Russia has been slowly winning the conflict. Ukraine’s manpower issues have been previously documented, but a public admission from a top official is rare. Ukraine has attempted to fill its ranks by barring men from leaving the country and conscripting all males 25 and older. Ukraine is also facing a massive budget shortfall. The EU has attempted to exploit frozen Russian assets held in Europe to fund Kiev, but has failed to agree on how to execute the scheme.