natural gas price hits a 38 month high; gasoline supplies at a 71 month high, distillates supplies at a 24 month high

oil price hits a 4 month high; natural gas price hits 38 month high; gasoline inventories at a 71 month high, distillates inventories at a 24 month high, imports of gasoline at an eleven month low

US oil prices finished higher for a sixth consecutive week after 15% of our domestic ​oil production and ​Gulf Coast refining capacity was knocked out by a winter storm, and after Trump escalated his saber rattling against Iran…after rising 2.9% to $61.07 a barrel last week after France seized a Russian​ oil tanker ​i​n the Mediterranean and Trump warned that an armada of US warships was steaming towards Iran, the contract price for the benchmark US light sweet crude for March delivery was​ fairly steady in Asian trading on Monday after ​the strong gains on Friday, as traders weighed concerns about a potential supply glut against heightened geopolitical risks, and awaited signals from a key Federal Reserve policy meeting later in the week, then edged higher as traders reacted to fresh signs of weather-related supply losses in the US, and added a risk premium to crude on Trump’s declaration of a US armada sailing toward Iran, but gave up its early gains during US trading and ended the session 44 cents lower at $60.63 a barrel as traders assessed the impact of winter storms on output from U.S. producing regions and the impact of tensions between the U.S. and Iran following Trump’s renewed warning to Iran….oil prices traded lower in Asia on Tuesday after the disruption to Kazakhstan's oil exports eased after a Black Sea terminal was brought back into service, and continued lower on other global markets in spite of ​the severe winter storm that curtailed crude production and disrupted refinery operations along the U.S. Gulf Coast, but rallied during the US session to settle $1.76 or 3% higher at $62.39 a barrel, as US producers reeled from a winter ‌storm that hobbled crude production and ​had dr​ive​n U.S. Gulf Coast crude exports to zero over the weekend, and as the US dollar hit a 4 year low, making oil cheaper for buyers with other currencies…oil prices extended those gains in Asian trading on Wednesday, supported by supply disruptions caused by the extreme winter weather across the United States and continued weakness in the US dollar, which boosted demand for dollar-denominated commodities, then hit their highest since late September on global markets after the winter storm disrupted U.S. crude output​, while a weak U.S. dollar and continued Kazakh outages lent further support, and further rallied during New York trading after the EIA reported the biggest oil + products draw since October, and settled 82 cents higher at $63.21 a barrel after Trump wrote "A massive Armada is heading to Iran. It is moving quickly, with great power, enthusiasm, and purpose,"​ on his policy social website….oil prices continued to rise during Asian trading on Thursday, as tensions between the United States and Iran escalated once again and concerns grew over potential disruptions to Middle East oil supplies, and climbed about 4 percent to a five-month high on global markets on rising concerns that global supplies could be disrupted if the US decided to attack Iran, one of OPEC's biggest crude producers, and rallied to a high of $66.48 by mid-morning in New York​, the highest level since early August, on increasing concerns over a possible U.S. military attack on Iran, before settling into a sideways trading range for the rest of the session and ending $2.21 higher at $65.42 a barrel, as US President Trump weighed military strikes on OPEC member Iran…oil prices retreated more than 1% in Asia early on Friday on signs that the U.S. might engage in dialogue with Iran over its nuclear program, reducing ​the immediate concern over potential supply disruptions from a U.S. attack, and continued to trade lower after the U.S. eased some sanctions on the oil industry in Venezuela​, and ​after a stronger dollar prompted traders to book some profits after prices had hit their highest levels since September, and settled the New York trading session 21 cents lower at $65.21 a barrel, thus consolidating recent gains and holding near six-month highs, supported by nagging tensions between the U.S. and Iran, and ​h​ence ended 6.8% higher for the week…

meanwhile, natural gas prices finished higher for a second week, after falling the prior three, after a winter storm shut down US LNG exports and froze off more than 15% of US natural gas production….after rising 70% to $5.275 per mmBTU last week on fears of disruptions to supplies from a major winter storm traversing the US, and on the increased demand in the arctic air outbreak expected in its wake, the price of the benchmark natural gas contract for February delivery opened 48.8 cents higher on Monday and surged to a three-year intraday high of $7.439 by 12:35 PM, as frigid temperatures and short covering sent prices higher, but pulled back heading into the close and settled $1.525 higher at $6.800 per mmBTU, as icy temperatures throttled production and traders assessed the ongoing impacts of Winter Storm Fern and the February contract’s pending expiration…that expiring February ​gas contract opened 27.1 cents lower on Tuesday and fell back to an intraday low of $5.772 at 9:55 AM, as analysts judged the worst of the cold had passed, which would allow some of the froze-off wells in the basins to get their production back up, but buyers reentered the ​thin market once again and the F​ebruary price rallied into the afternoon to settle 15.4 cents higher at $6.954 per mmBTU, as cold continued to grip the eastern US, while the more actively traded March benchmark contract closed 7.8 cents lower at $3.820 per mmBTU, as traders took profits amid the wreckage of Winter Storm Fern…the February natural gas contract opened 80.6 cents lower on its last day of trading Wednesday, but ascended choppily through the session to settle 50.6 cents higher at $7.460 per mmBTU, following weather-induced blowouts at several hubs, as a polar vortex disruption shut in production and sent demand surging, while the more heavily traded March contract opened 16.1 cents lower and stabilized near $3.860 by 11:00AM, but pulled back after midday as fundamentals grew less supportive, and closed 8.8 lower at $3.732 per mmBTU, as traders reassessed a seasonal supply picture reshaped by the surprise onslaught of Arctic air…with markets now citing the benchmark natural gas contract for March delivery, its price opened 10.8 cents higher on Thursday, but largely shrugged off a bullish storage withdrawal​, as markets were still ​r​eacting to the past week’s volatility, and settled 18.6 cents higher at $3.918 per mmBTU, as traders assessed conflicting weather outlooks for early February….natural gas futures were little changed early Friday, as traders digested a bullish storage report, mixed demand forecasts and recovering production, but vaulted above the $4 level by midday, as sustained cold risks into mid-February eclipsed a rapid rebound in Lower 48 production, and settled 43.6 cents higher at $4.354 per mmBTU, as shrinking inventories, lingering production freeze-offs and hints of a possible mid-February cold shot fueled substantial gains…while Friday’s ​final price quote was​ 17.5% lower than the natural gas price quoted at the beginning of the week, that was due to the midweek switch to quoting the lower priced March contract....comparing apples to apples, February natural gas prices expired 41.4% higher and were up 140.4% over their last 8 days of trading, while the March contract price, which had settled the prior week at $3.609 per mmBTU, ended this week 20.6% higher…

The EIA’s natural gas storage report for the week ending January 23rd indicated that the amount of working natural gas held in underground storage fell by 242 billion cubic feet to 2,823 billion cubic feet by the end of the week, which left our natural gas supplies 206 billion cubic feet, or 7.9% higher than the 2,617 billion cubic feet of gas that were in storage on January 23rd of last year, and 143 billion cubic feet, or 5.3% more than the five-year average of 2,680 billion cubic feet of natural gas that had typically been in working storage as of the 23rd of January over the most recent five years….the 242 billion cubic foot withdrawal from natural gas storage for the cited week was more than the 230 billion cubic foot withdrawal from storage that the market was expecting ahead of the report, but was less than the 307 billion cubic foot of gas that were pulled out of natural gas storage during the corresponding week of 2025, while more than the average 208 billion cubic foot withdrawal from natural gas storage that has been typical for the same 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 23rd indicated that after a sizable decrease in our imports and a sizable increase in our exports, we had to pull ​oil out of our stored crude supplies for the 16th time in thirty-five weeks, and for the 44th time in eighty weeks, in spite of another​ notable refining pullback….Our imports of crude oil fell by an average of 804,000 barrels per day to 5,642,000 barrels per day, after falling by an average of 645,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 901,000 barrels per day to average 4,589,000 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 1,053,000 barrels of oil per day during the week ending January 23rd, an average of 1,705,000 fewer barrels per day than the net of our imports minus our exports during the prior week... At the same time, transfers to our oil supplies from Alaskan gas liquids, from natural gasoline, from condensate, and from unfinished oils were 5,000 barrels per day higher at 751,000 barrels per day, while during the same week, production of crude from US wells was 36,000 barrels per day lower than the prior week at 13,696,000 barrels per day. Hence, our daily supply of oil from the net of our international trade in oil, from transfers, and from domestic well production appears to have averaged a total of 15,500,000 barrels per day during the January 23rd reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,209,000 barrels of crude per day during the week ending January 23rd, an average of 395,000 fewer barrels per day than the amount of oil that our refineries reported they were processing during the prior week, while over the same period, the EIA’s surveys indicated that a net average of 254,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US… So, based on that reported & estimated data, the crude oil figures provided by the EIA appear to indicate that our total working supply of oil from storage, from net imports, from transfers, and from oilfield production during the week ending January 23rd averaged a rounded 455,000 less barrels per day than what our oil refineries reported they used during the week. To account for the difference between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a [ 455,000 ] barrel per day figure onto line 16 of the weekly U.S. Petroleum Balance Sheet, in order to make the reported data for the supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus indicating there must have been a error or omission of that magnitude in the week’s oil supply & demand figures that we have just transcribed…moreover, since 3,000 barrels per day of demand for oil could not be accounted for in the prior week’s EIA data, that means there was rounded 458,000 barrel per day difference between this week’s oil balance sheet error and the EIA’s crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week’s report are off by that much, and therefore 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 254,000 barrel per day average decrease in our overall crude oil inventories came as an average of 328,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while an average of 74,000 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 6,380,000 barrels per day last week, which was still 0.9% less than the 6,437,000 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 36,000 barrels per day lower at 13,696,000 barrels per day because the EIA’s estimate of the output from wells in the lower 48 states was 42,000 barrels per day lower at 13,266,000 barrels per day, while Alaska’s oil production was 6,000 barrels per day higher at 430,000 barrels per day...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 4.5% higher than that of our pre-pandemic production peak, and was also 41.2% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021.

US oil refineries were operating at 90.9% of their capacity while processing those 16,209,000 barrels of crude per day during the week ending January 23rd, down from the 93.3% utilization rate of the week ending January 16th, with lower utilization levels typical heading into a new year, as refineries start to change over to producing Spring blends of fuel….the 16,209,000 barrels of oil per day that were refined that week was 6.7% more than the 15,189,000 barrels of crude that were being processed daily during the week ending January 24th of 2025, and 1.7% more than the 15,924,000 barrels that were being refined during the prepandemic week ending January 24th, 2020, when our refinery utilization rate was at 87.2%, which was on the low side of the pre-pandemic normal range for this time of year…

Even with the decrease in the amount of oil that was refined this week, gasoline output from our refineries was much higher, increasing by 791,000 barrels per day to 9,574,000 barrels per day during the week ending January 23rd, after our refineries’ gasoline output had decreased by 246,000 barrels per day to a two year during the prior week... This week’s gasoline production was 4.1% more than the 9,193,000 barrels of gasoline that were being produced daily over the week ending January 24th of last year, and also 4.5% more than the gasoline production of 9,158,000 barrels per day seen during the prepandemic week ending January 24th, 2020….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 268,000 barrels per day to 4,819,000 barrels per day, after our distillates output had decreased by 209,000 barrels per day during the prior week. Even after those production decreases, our distillates output was still 1.7% more than the 4,738,000 barrels of distillates that were being produced daily during the week ending January 24th of 2024, but 3.2% less than the 4,979,000 barrels of distillates that were being produced daily during the pre-pandemic week ending January 24th, 2020....

After this week’s big increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the eleventh consecutive week, increasing by 223,000 barrels to a 71 month high of 257,213,000 barrels during the week ending January 23rd, coming after our gasoline inventories had increased by 5,977,000 barrels during the prior week. Our gasoline supplies increased by less this week because the amount of gasoline supplied to US users rose by 923,000 barrels per day to 8,757,000 barrels per day, and because our imports of gasoline fell by 48,000 barrels per day to an eleven month low of 364,000 barrels per day, while our exports of gasoline fell by 110,000 barrels per day to 683,000 barrels per day … Despite thirty gasoline inventory withdrawals over the past fifty-one weeks, the recent surge of additions meant our gasoline supplies were 3.4% higher than last January 24th’s gasoline inventories of 248,855,000 barrels, and about 5% above the five year average of our gasoline supplies for this time of year…

Even after this week’s decrease in distillates production, our supplies of distillate fuels rose for the tenth time in eleven weeks, increasing by 329,000 barrels to a two year high of 132,921,000 barrels during the week ending January 23rd, after our distillates supplies had increased by 3,348,000 barrels during the prior week… Our distillates supplies rose by less this week because the amount of distillates supplied to US markets, an indicator of domestic demand, rose by 545,000 barrels to 4,069,000 barrels per day, while our exports of distillates fell by 345,000 barrels per day to 956,000 barrels per day, and while our imports of distillates rose by 38,000 barrels per day to 253,000 barrels per day, ... With 56 withdrawals from distillates inventories over the past 104 weeks, our distillates supplies at the end of the week were 7.2% higher than the 123,951,000 barrels of distillates that we had in storage on January 24th of 2025, and about 1% above the five year average of our distillates inventories for this time of the year…

Finally, after the big decrease in our oil imports and the the big increase in our oil exports, our commercial supplies of crude oil in storage fell for the 11th time in twenty-six weeks, and for the 21st time over the past year, decreasing by 2,295,000 barrels over the week, from 426,049,000 barrels on January 16th to 423,754,000 barrels on January 23rd, after our commercial crude supplies had increased by 3,602,000 barrels over the prior week… After this week’s decrease, our commercial crude oil inventories were about 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 fourth 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 23rd were 2.1% more than the 415,126,000 barrels of oil left in commercial storage on January 24th of 2025, and were 0.4% more than the 421,912,000 barrels of oil that we had in storage on January 26th of 2024, but 6.4% less than the 452,688,000 barrels of oil we had left in commercial storage on January 27th of 2023…

This Week's Rig Count

The US rig count was up by two over the week ending January 30th, the 14th increase in twenty-two weeks, as the number of rigs targeting natural gas was up by three, while the count of rigs targeting oil was unchanged and miscellaneous rigs were down by one …for a quick snapshot of this week's rig count, we are again including below a screenshot of the rig count summary pdf from Baker Hughes...in the table below, the first column shows the active rig count as of January 30th, the second column shows the change in the number of working rigs between last week’s count (January 23rd) and this week’s (January 30th) count, the third column shows last week’s January 23rd 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 31st of January, 2025…

++++++++++++++++++++++++++++++++++++++++++++++++++++++

Local residents deserve to know about gas-fired power plant planned for Meta data center - Leatra Harper - In reviewing the publicly available information in an attempt to understand how a huge data center could be planned and approved, given substantial tax breaks, with a huge swath of land sold with development begun without the knowledge of most area residents. It does not take long before it becomes obvious the lengths it took to ensure our local elected and economic development officials kept it a secret, leaving the public in the dark until it was too late. No townhalls, no permit hearings, no opportunity to ask questions or have them answered. Even the name and purpose of the project was withheld with the shell LLC, Liames, secret project name, Accordion, and numerous non-disclosure agreements signed. Now the pattern of secrecy is obvious and continues with yet another project, “Apollo” being fast-tracked by the “Will-Power LLC” a subsidiary of Williams Company, the builder of the Nexus fracked gas pipeline. The informative, well-researched article published by BG Independent News 9/14/25 did not mention the huge 350 MW gas fired power plant that was being planned at the time because – well – who knew? In fact, when Will-Power proposed the 350 MW Title V air polluter to the Ohio Power Siting Board with a Letter of Notification just three months ago, even that letter kept Meta a secret. That letter initiated the fast-track process with the Ohio Power Siting Board which apparently plans to approve the facility the first part of February. Local residents who are concerned about the region’s air quality need to speak out now before the massive polluter is permitted if we do not want more asthma and ozone action days – not to mention the climate impacts of greenhouse gas emissions (it is reported that Apollo is seeking approval to emit 2,475,581 tons of CO2 yearly – this does not count the emissions from the additional upstream industries like fracking that would feed the power plant or the diesel powered generators also planned).We are waiting for a copy of the air permit to review. We called the Ohio EPA because even that appears not to be publicly available. Could the OPSB fast-track the approval of Apollo before local residents receive a copy of the air pollution permit and have a chance to comment? How could the OPSB approve the siting of this Title V project without looking at cumulative impacts that would include not only the data center itself, but the diesel generators and the two 16″ pipelines that are also planned – and who knows what else that is still not disclosed? To add insult to injury – no public input for the 75% tax abatement for Meta for 15 years! And Apollo likely will get Ohio sales tax breaks as a new power plant for a data center as well! In Hamilton, Ohio, there is much more transparency, and a proposed data center project has even been paused for additional public information. Wood County residents did not receive that courtesy. It stands to reason that if the deals being made would be acceptable to the local community, such secrecy would not be needed. Now as more people are becoming aware, it is obvious that important information was kept from us. Even though the Apollo project is being fast-tracked, there is still time to register comments to the Ohio Power Siting Board by calling 866-270-6772 or by emailing ContactOPSB@puco.ohio.gov. Our elected “representatives” need to hear from us – they seem to forget that they are paid with our taxes, and they are supposed to represent us and not be seduced by the “ribbon cutting syndrome” at the expense of their constituents.

Fracking produces a lot of wastewater. Millions of gallons of it are stored under eastern Ohio - The Allegheny Front -- This is the first of a three-part series about concerns over injection wells in Washington County. Read the second and third parts here. - Hydraulic fracturing, particularly on public lands, has spurred protests across Ohio. But a lesser known part of the process — where companies discard the wastewater from drilling — is causing an uproar in a small town in southeast Ohio. Some residents in Marietta are concerned that the wastewater could contaminate the city’s drinking water supply. To understand how that could happen, we’re breaking down the science. Americans have been drilling for oil and gas for over a century, but about 15 years ago, a different kind of energy mining took off: hydraulic fracturing, often nicknamed fracking. Jeffery says drilling horizontally allows companies to reach oil and natural gas reserves that were previously difficult to access with conventional vertical drilling.In order to get those fuels out, operators inject the holes with millions of gallons of fluid at pressures so high it pulverizes surrounding rock and allows oil and gas to escape. That fluid is usually composed of water, sand and chemicals like disinfectants. Ohio law requires companies to disclose information about the volume and types of products used in drilling, but there are exemptions for chemicals considered trade secrets. After the fluid has done its job, it comes back up to the surface. But after sloshing around underground, it picks up a lot of salt and, potentially, some radioactive material.Between the unknowns about the chemicals in the fluid and the substances it picks up underground, Jeffery says the wastewater isn’t safe for humans above ground.“So they have to dispose of them somehow,” Jeffery said.That’s where injection wells come in. Injection wells are drilled deep underground in porous geologic formations to store fluids like the wastewater from hydraulic fracturing. “That would normally be a very good solution if you find a place in which you can find space underground for this yucky stuff to be in perpetuity,” Jeffery said. There are several types of injection wells. Some are used to store industrial waste, while others are used to mine minerals like uranium and copper. Class II injection wells are the ones used to inject waste from oil and natural gas production. How many injection wells are in Ohio? According to a database from the EPA, Ohio had over 250 Class II disposal wells for oil and gas waste in 2023. A map from the Ohio Department of Natural Resources shows 234 of those wells were active that year. Seventeen were in southeast Ohio’s Washington County. In comparison, the entire state of Pennsylvania had 16 active Class II disposal wells in 2023. The state says it sends most of its “produced fluids” to neighboring states like Ohio. In Washington County, Ohio, four injection wells are within two miles of the City of Marietta’s aquifers. Last year, the Ohio Department of Natural Resources approved two more to be drilled within that radius. Jeffery, and many others who live in Marietta, like Dee Wells Arnold, worry that’s too many wells in close proximity to the city’s drinking water supply. A leak, they say, could be devastating.“If you don’t have fresh water, if you don’t have clean water, if you don’t have safe water, you can’t have a community,” Wells Arnold said. “I don’t think it’s worth the risk.” In a Q&A style document addressing concerns over a proposed injection well near Marietta, the ODNR said geologists evaluate each injection site and make sure the wells are constructed in a way that protects the environment. DeepRock Disposal Solutions, which owns the injection wells near Marietta, did not respond to a request for comment. Matt Dole, a consultant for the Accountability Project Institute, says the risk of injection wells leaking is negligible. “If you consider that that injection well is two miles from the water’s supply, behind reinforced concrete, behind reinforced steel, encased in concrete and 4,000 feet in the ground below solid rock, it might as well be a million miles,” he said. But leaks have happened in Washington County (Ohio) before. Just a few years ago, fracking fluid infiltrated dozens of vertical oil and gas wells there. Regardless, Dole says any attempt to shut down injection wells could cripple an industry that’s become essential to southeast Ohio economies. “Some opponents of injection wells will say ‘I’m for oil and gas. I don’t want to lose the jobs and the economic benefit and the energy developed by the oil and gasoline industry. I’m just against injection wells,’ ” he said. “Well, that is an irreconcilable position because the water used in the fracking process needs to be disposed of properly and injection wells are the proper way to dispose of that material.”

Why some Washington County residents are worried about the future of their drinking water | The Statehouse News Bureau --This is the second of a three-part series about concerns over injection wells in Washington County. Read the first and third parts here. When the Ohio Department of Natural Resources issued permits to construct two injection wells, to store waste from oil and gas drilling, within two miles of the city of Marietta’s aquifers, residents in the area grew concerned.Washington County — home to the southeast Ohio city of Marietta — already had more of the wells than the entire state of Pennsylvania, as of 2023.Some locals worried the oil and gas drilling waste could contaminate the community's drinking water supply.Bob Wilson was among them. Wilson has been working in oil and gas since the mid-’70s — decades before the hydraulic fracturing boom revolutionized the industry. His family owns 170 conventional, vertically drilled oil and gas wells, mostly located between Marietta and Belpre.Since 2019, after an injection well was drilled nearby, he says 50 of them have stopped producing oil and gas and started pulling up sludgy wastewater instead.To him, the cause seemed obvious. He reported the problem to the ODNR. “And I told them, I said, ‘You guys are getting disposal water in my wells.’ And they just completely ignored me,” he said. “They said, ‘It's not possible, can't happen, click.’”Several of Wilson’s neighbors started losing wells to wastewater, too. Four years ago, one of them joined Wilson in suing a number of injection well companies. After a lower court dismissed his suit, Wilson appealed and another court ruled in his favor. Those companies have since appealed and the cases are now awaiting decisions from the Ohio Supreme Court.But Wilson says, no matter what happens, the damage can’t be undone.“They've ruined my business,” he said. “They've ruined my life.”A 2020 report from the ODNR concluded the wastewater found in Wilson’s well did, in fact, come from the injection site. According to the ODNR, Redbird Development LLC, which owned the site, voluntarily modified the injection well and temporarily stopped using it because of an unrelated pump issue.The department said it has spoken with Wilson about his complaints.Now, as Wilson mourns his once-successful business, he has another mounting concern. The contamination of his wells is proof that fracking wastewater has migrated underground, and he worries it could get into the drinking water supply.He’s not alone.“It seems pretty clear that this material is not – the fluids are not staying where they're supposed to stay,” said David Jeffery, who teaches courses on petroleum geology at Marietta College. “It looks like they are migrating through fractures, whether they are natural fractures or induced fractures or faults.”In its 2020 report, the ODNR said it’s unlikely brine could directly migrate into local aquifers given the composition of rock layers in the area.Jeffery agrees. He says what’s more likely is that the brine migrates into an unplugged orphaned well and then travels into drinking water reserves from there.“There are thousands of orphaned wells around here, which are just wells that might have been drilled more than 100 years ago and only the landowner might know that they're there or not,” he said. Professor Natalie Kruse Daniels, director of the environmental studies program at Ohio University, said she’s concerned it could take a long time for anyone to notice fluid coming out of an orphaned well.“What concerns me the most is: Are we going to detect it, do people know what to look for and will folks be believed, if and when they notice a change in their water?” she said.“In Appalachia we've seen multiple cases of drinking water contamination, where it took a really long time for people's experience to be believed and for there to be an action to ameliorate an issue.” DeepRock Disposal Solutions, which owns the injection wells near Marietta, passed my number on to Matt Dole, a consultant for the Accountability Project Institute, a 501(c)(4) nonprofit with undisclosed donors that’s advocated against state and local Democratic candidates.Dole says the number of reported leakages is tiny compared to the number of injection wells in the country. “It is a lower percentage than the number of people who die on their bike going down the street every year,” he said. “It is so minuscule that we think it's wrong to ask the government to regulate.” The ODNR suspended six injection wells in southeast Ohio’s Noble andAthens counties in 2023, after fracking wastewater migrated out of intended injection well zones.For Bob Wilson, that’s enough to be concerned about, especially as the ODNR approves additional injection well sites in close proximity to Marietta’s aquifers.“We care about what's happening with the water situation and everything here because we live here,” he said. “It's not just our businesses. We want to stop it because this is where we live. It’s where our families live.”

In southeast Ohio, state and local officials fight over the future of injection wells | The Statehouse News Bureau -This is the last of a three-part series about concerns over injection wells in Washington County. Read the firstand second parts here Last July, a short notice appeared in the back of the Marietta Times.“DeepRock Disposal Solutions, LLC… is applying to permit a well for the injection of brine water produced in association with oil and natural gas,” the clip read.At the time, injection wells weren’t on Susan Vessels’ radar.“But it sounded like something that I ought to learn about,” the Marietta City Council president said..So she hosted a big public meeting and invited everyone from public officials to DeepRock representatives to petroleum engineers and PhD geologists.What she learned alarmed her. “They're literally putting these wells almost on top of one another,” she said. “And to have seven wells just outside of our city injecting up to 35,000 barrels a day, it doesn't take a PhD to know that ultimately that's not going to turn out well for our community.” Vessels isn’t alone. Across southeast Ohio’s Washington County,community members are concerned that wastewater stored in injection wells could contaminate the local water supply.“It might not be tomorrow. It might not be next year. It might not be three years [from now]. It might be 10 years, but do we want this for our children?” said Dee Wells Arnold, a member of the community organization Washington County for Safe Drinking Water. In August, Vessels and a bipartisan group of nine other elected officials filed an objection letter to DeepRock’s application, expressing serious concerns for the safety of the city’s drinking water. They asked the Division of Oil and Gas to deny the permit and hold a public meeting on the matter.The Ohio Department of Natural Resources’ division did neither.. In an email, a spokesperson cited pending litigation and said they wouldn’t comment on the approval the well or the refusal to hold a public meeting. But the department did send the city two Q&A-style responses to their concerns last year. In those documents, the department said injection wells are designed to protect underground sources of drinking water and that there’s no law limiting the number of injection wells within a geographic area. Marietta’s city council wasn’t reassured. They passed a series of resolutions, including one asking the state for a three-year moratorium on injection well activity within Washington County, to give experts time to study the area’s geology.“The council agrees that we have too many wells injecting too much too close to our aquifers,” Vessels said. “So it's a plea for help, essentially, that we need to change how things are being done.” She says the city has received little response from the state since.“To me, personally, it's shocking,” she said. “I always felt that the Ohio Department of Natural Resources, the EPA – I felt that they were almost, perhaps even doing too much to protect us. And having delved into this over the last four months, I'm learning that that isn't the case.”In November, the Buckeye Environmental Network – a grassroots environmental justice group – sued the ODNR and its oil and gas division. They say the state broke the law last year when it used old rules to approve two injection wells near Marietta proposed by DeepRock, even though new rules went into effect in 2022.“The ODNR is obligated to follow the Federal Clean Drinking Water Act and to uphold the current state rules that they themselves wrote and the legislature passed into law for a reason,” said Bev Reed, an Appalachian organizer for the network, in a press release. “They didn't do that when permitting these wells, so we're holding them to account.”She wants the department to be more proactive when it comes to protecting the safety of local drinking water. “They're not protecting us as Ohio citizens,” she said. “They're just not.” In its Q&A response to the city, the ODNR said it used the old rules because it received DeepRock’s application in 2021, before the new rules went into effect. DeepRock Disposal Solutions didn’t respond to a request for comment. But they passed my number on to Matt Dole, a consultant for the Accountability Project Institute, a 501(c)(4) nonprofit with undisclosed donors that has previously run ads against Ohio Democrats. He says Marietta City Council’s attempt to regulate injection wells based on the possibility they could contaminate drinking water is unnecessary and an example of government overreach. “A lot of things could happen,” Dole said. “I could get hit by lightning tomorrow, but the government has chosen to not regulate my ability to go out in a rainstorm because it is so unlikely that regulation would be overkill in that circumstance. And the same is true with injection wells.” He sees the city council’s efforts as part of a bigger environmental movement. “Truly, we believe that this is an attempt by the environmental lobby to oppose oil and gas,” he said. “No, they can't win that battle, but if they win a battle against injection wells, they shut down the oil and gas industry.”

WATCHDOG: Who is responsible if someone strikes a utility line in Ohio? - WFMJ.com - Digging is a situation that can mean anything from a minor inconvenience to a mass evacuation like the valley saw in Leetonia weeks ago. In some cases, like the Realty building, gas leaks can even have deadly consequences. And while they're often caused by human error, there is surprisingly little in place to prevent them and rarely any serious consequences for causing them, even when someone ends up dead. So, do the rules in place actually have any teeth? Ohio law, in theory, has two layers to protect you from potential disaster from gas leaks. The first layer is a requirement that anyone who puts a shovel in the ground calls in advance so utilities can be marked. “Within 48 hours, they're going to arrive on the site. They're going to identify their utilities, if there are any there, and they're going to go ahead and mark them so that you can begin digging at the end of 48 hours in a safe manner,” said Roger Lipscomb, executive director of Ohio 811. The second are fines when disaster does strike and there's a leak or, in cases like the Realty building, an explosion. But what happens if someone doesn't call, and disaster strikes? In Ohio, the only way a company can even potentially face fines is if someone voluntarily reports the problem to the State Public Utilities Commission (PUCO). “In other states, enforcement is driven by an incident or an issue. There was damage, there was some kind of a near miss, there was some kind of a situation like that. In Ohio, our revised code and our excavation laws are governed much by compliance,” said Lipscomb. The Common Ground Alliance, a national nonprofit committed to reducing damages to the critical underground structure, has tracked an increase in damage done by third party workers, some with devastating results. “There is a lot of competing interests out there to try to get their infrastructure underground. And so part of the challenge is that legislation and law, both state and federal, haven't really kept up with that,” said Sarah Magruder Lyle, president and CEO of the Common Ground Alliance. PUCO numbers show 160 Utility strikes in Ohio led to $204,750 in fines, but more than $63,000 are unpaid to date. And only three of those damaged utilities fines were from the Valley in all of 2024 and 2025. In some states, enforcement happens when there is an incident. But in Ohio, this is all based on voluntarily reporting the issue. That means if a company hits a gas line or causes an explosion, they would either need to actively report themselves or anyone who was affected would need to know to report them to the state. And even then, many fines simply go unpaid. “I would like the states to actually not only pass, you know, language and legislation that protects the communities and put safety first, but they also have to ensure that they have an enforcement mechanism that will actually drive behavior change, because you can have the best law, like I said, on the books, but if nobody is enforcing it, it doesn't matter,” said Lyle.

Ohio senator failed to disclose ties to well companies, complaint alleges - The Allegheny Front Ohio environmental advocates have filed an ethics complaint against Sen. Brian Chavez (R-Marietta), alleging he failed to disclose financial ties to at least five oil and gas companies in 2023 and 2024. Submitted to the Joint Legislative Ethics Committee (JLEC) last Wednesday, the complaint by Washington County for Safe Drinking Water also claims that Chavez’s legislative committee assignments create direct conflicts of interest financially. He is currently the chair of the Ohio Senate Energy Committee. He also owns a business that bids on government contracts to seal abandoned, or orphan, oil and gas wells. Dawn Hewitt, Washington County for Safe Drinking Water treasurer, said in an interview Chavez stands to profit from Senate Bill 219 if it passes the Ohio House.. “If it were solely a matter of experience, that would be one thing,” Hewitt said Tuesday. “But what Chavez has is material gain from the policies he’s making and that’s wrong.” SB 219 cleared the Senate floor in November. It would be an extensive overhaul of oil and gas laws, including those regulating orphan wells. Among its numerous measures, SB 219 would redirect injection well fees from the state Oil and Gas Well Fund to cities and counties where they come from. John Fortney, the spokesperson for the Senate Majority caucus, wrote over text the claims in the complaint were “nothing more than a fabricated publicity stunt backed by out of state special interests that want to kill the oil and gas industry in Ohio.” “Their work of fiction used the words ignorant and dishonest,” Fortney said Tuesday. “They should look in the mirror.” Hewitt said only local and state groups have been involved. Buckeye Environmental Network, Save Ohio Parks and Sierra Club Ohio were among the dozen groups that cosigned the complaint.

Antis Attack Ohio State Senator with Ethics Complaint - Marcellus Drilling News --Ohio Senator Brian Chavez faces a sham ethics complaint that alleges he failed to disclose ownership in five natural gas LLCs while leading the Senate Energy Committee. Reports from Signal Ohio (a leftist Democrat publication) and the Athens County Independent (ditto) purport to detail how Chavez’s company won state contracts for “orphan” well capping as he advanced legislation that supposedly benefited his business interests. A coalition of environmental groups alleges these supposedly undisclosed ties create conflicts of interest that undermine public trust and environmental safety. A GOP spokesperson dismissed the allegations as a “baseless” political attack. State ethics officials are currently reviewing the complaint.

Strs Ohio Has $21.76 Million Holdings in Kinder Morgan, Inc.-- (Strs Ohio State Teachers Retirement System of Ohio) trimmed its stake in shares of Kinder Morgan, Inc. (NYSE:KMI - Free Report) by 16.1% during the third quarter, according to its most recent disclosure with the Securities and Exchange Commission. The institutional investor owned 768,501 shares of the pipeline company's stock after selling 147,132 shares during the period. Strs Ohio's holdings in Kinder Morgan were worth $21,756,000 at the end of the most recent reporting period. Kinder Morgan (NYSE:KMI - Get Free Report) last released its quarterly earnings data on Wednesday, January 21st. The pipeline company reported $0.39 EPS for the quarter, beating analysts' consensus estimates of $0.37 by $0.02. The business had revenue of $4.51 billion during the quarter, compared to analysts' expectations of $4.33 billion. Kinder Morgan had a net margin of 18.04% and a return on equity of 9.02%. The firm's quarterly revenue was up 13.1% on a year-over-year basis. During the same quarter in the prior year, the company earned $0.30 EPS. Equities research analysts anticipate that Kinder Morgan, Inc. will post 1.25 EPS for the current year.Kinder Morgan NYSE: KMI is a large energy infrastructure company that owns and operates an extensive network of pipelines and terminals across North America. Its core activities center on the transportation, storage and handling of energy products, including natural gas, natural gas liquids (NGLs), crude oil, refined petroleum products and carbon dioxide. The company's assets include long-haul and gathering pipelines, storage facilities, and multi-modal terminals that serve producers, refiners, utilities and industrial customers.Kinder Morgan's operations deliver midstream services such as pipeline transportation, terminaling, storage and related logistics and maintenance.

DEP: Owner Of At Least 43 Abandoned Conventional Oil & Gas Wells Issued Violations For 6 More On State Game Lands In Venango County; Efforts To Locate The Owner Have Been Unsuccessful - On January 22, 2026, the Department of Environmental Protection issued Carol A. Morrison Baker 6 more notices of violation for abandoning and not plugging 6 conventional oil and gas wells on State Game Lands #45 in Cranberry Township, Venango County.These inspections are part of a DEP initiative to inspect never-inspected conventional oil and gas wells and determine their status.The well owner also failed to submit annual production, waste generation/disposal, and well integrity reportsThe wells included State Game Lands #45 J3, J25, J35, J39, J45 and J68. Click Here for links to inspection reports.DEP said it has been trying to track down the owner of the wells “for some time with no success.”Carol A. Morrison Baker, address listed is in Franklin, PA, holds 217 oil and gas well permits, including 43 abandoned wells.On September 25, 2025, Morrison Baker was issued violations for abandoning and not plugging 10 conventional oil and gas wells in Cranberry Township, Venango County. Read more here.Click Here for an example of a DEP inspection report. If you have information or or the whereabouts of Carol A. Morrison Baker, please contact the nearest DEP Oil and Gas District Office.

DEP: Day 455 And Counting: Seneca Resources Continues To Release Wastewater, Frack New Shale Gas Wells At Taft Well Pad In Middlebury Twp., Tioga County --On January 21, 2026, the Department of Environmental Protection inspected the Seneca Resources Co LLC Taft 851 shale gas well pad in Middlebury Township, Tioga and found evidence of wastewater spills continuing at the site.Eight new gas wells were recently completed on the pad and prepping was underway to frack the wells.Five other wells drilled and fracked since October 2024 were being staged for production.DEP found “visible evidence of a release of material that overtopped the secondary containment structure” and contaminated liquid in secondary containment that had not been removed.DEP also found erosion and sedimentation control measures at the pad and not been converted to post-construction best management practices to control runoff from the pad.“DEP recommends that Seneca continues to monitor the conditions on the pad surface and the sediment basin and remove elevated conductance fluids and soils as discovered. Prevent elevated conductance fluids from leaving the facility and causing pollution to the waters of the Commonwealth.DEP did not request a written follow-up to the violations.Click Here for the January 21, 2026 inspection report and photost.These conditions have continued for 455 days at this well pad without abatement.During a December 23, 2025 inspection found similar conditions-- spills, crews trying to clean up the pad while drilling new shale gas wells.DEP issued the original spill violations at the site on October 23, 2024 and documented spills again during a July 11, 2025 inspection that were confirmed with water samples collected on August 21, 2025.DEP found spills and releases during an October 2, 2025 inspection and one on October 31 making the same recommendations to monitor and remove contaminated water and soil..Also on October 31, Attorney General Dave Sunday announced criminal charges against Seneca Resources, LLC, following multiple violations of Pennsylvania’s environmental protection laws in several counties, as recommended by the 48th and 51st Statewide Investigating Grand Juries. Three separate criminal complaints were filed regarding the natural gas company’s violations related to improper waste management practices and policies. Prominent in the Attorney General’s announcement of the charges was the fact that DEP repeatedly warned Seneca that their practices were not in line with Pennsylvania law, but those warnings were ignored or disputed. Read more here. In all, Seneca is charged with 64 counts of violations of the Solid Waste Management Act and 36 counts of violations of the Clean Streams Law in Cameron, Clearfield, Elk, Jefferson, Lycoming, McKean, Potter, Tioga Counties. Read more here.(Photos: Evidence of overtopped secondary containment; Erosion control sediment basin; below- 8 new shale gas wells ready for fracking - DEP inspection photos.)

10 New Shale Well Permits Issued for PA-OH-WV Jan 19 – 25 --Marcellus Drilling News - The Marcellus/Utica region received a combined 10 new drilling permits last week, Jan. 19 – 25, down significantly from the 27 issued two weeks ago. Pennsylvania issued 6 new permits, Ohio issued 4, and West Virginia issued none. The drillers receiving new permits last week included: Ascent Resources, EOG Resources, Expand Energy, and Pennsylvania General Energy. ASCENT RESOURCES | EOG RESOURCES | EXPAND ENERGY | HARRISON COUNTY | JEFFERSON COUNTY (OH) | LYCOMING COUNTY | PENNSYLVANIA GENERAL ENERGY | SUSQUEHANNA COUNTY

PA PUC Publishes Marcellus Impact Tax Hike – Older Wells Up 116% - Marcellus Drilling News - Marcellus drillers who have drilled new wells over the past three years in Pennsylvania are going to get hit by an increase in the state’s impact fee. However, older shale wells (drilled 11 to 15 years ago) will get hit the hardest by the 2025 impact fee/tax. Drillers must pay the impact fee (PA’s equivalent of a severance tax) once per year, based on the wells they drilled or operated during the previous year. The fee is a complex calculation based on (a) how long a well has been drilled, (b) the average NYMEX Henry Hub price for natural gas from the previous year, and (c) a cost adjustment for inflation. The fees PA drillers will pay this year, depending on how long a well has been drilled, range from 3.8% higher to 116.1% higher.

Winter weather to disrupt U.S. gas production, increase prices - Wide­spread extreme cold is expec­ted to restrict the pro­duc­tion of nat­ural gas in the U.S. in the com­ing days, with sup­ply dis­rup­tions likely in key shale basins that could cut aver­age daily out­put by about 10%, industry ana­lysts say. The price of bench­mark nat­ural gas futures at Henry Hub in Louisi­ana for deliv­er­ies in mid-Feb­ru­ary soared this week, rising 59% on Fri­day after­noon, the biggest weekly increase since 1990. The spike is expec­ted to cause bill increases for res­id­en­tial con­sumers in some states, but the tim­ing and degree of the impact will vary depend­ing on the util­ity. Entergy cus­tom­ers in Louisi­ana, for example, will likely see fuel adjust­ment charges on their bills in two months, reflect­ing higher whole­sale prices for gas dur­ing an upcom­ing winter storm. Ana­lysts expect large with­draw­als of nat­ural gas from stor­age in the weeks ahead. The U.S. Depart­ment of Energy estim­ated U.S. invent­or­ies of nat­ural gas in under­ground stor­age at 3,065 bil­lion cubic feet on Jan. 16, 141 bil­lion cubic feet higher than last year and 6.1% above the five-year aver­age of 2,888 bil­lion cubic feet for this time of year. “This deep freeze is hurt­ing pro­duc­tion, espe­cially for nat­ural gas,” Price Futures Group ana­lyst Phil Flynn wrote in his daily mar­ket com­ment­ary. ”Daily out­put is tak­ing a hit, with losses soar­ing to as much as 10 bil­lion cubic feet a day at peak times! Even under more mod­er­ate scen­arios, we’re see­ing pro­duc­tion drops between 0.2 and 2.5 bil­lion cubic feet per day across the hardest hit regions, start­ing around Janu­ary 20–22 and stick­ing around through Janu­ary 31,” Flynn wrote. The cul­prit is "freezeoffs" that occur when water or hydrates, pro­duced along with nat­ural gas, freeze and then solid­ify dur­ing peri­ods of extreme cold. They cre­ate block­ages that dis­rupt flows from well­heads at the pro­cessing facil­it­ies where impur­it­ies are removed, as well as inside pipelines that sup­ply gas-fired power gen­er­a­tion plants and indus­trial users. Freeze-offs played a role in a 2021 winter storm in Texas that made head­lines for leav­ing mil­lions of people without power for days. Accord­ing to a study from the Fed­eral Reserve Bank of Dal­las and the Fed­eral Energy Reg­u­lat­ory Com­mis­sion, freeze-offs caused a 45% drop in Texas nat­ural gas pro­duc­tion over a five-day period. The study found 87% of unplanned out­ages at elec­tri­city gen­er­a­tion plants in Texas were due to insuf­fi­cient sup­plies of nat­ural gas, caused mostly by freeze-offs at the well­head where it is pro­duced and at nearby pro­cessing plants. The storm res­ul­ted in between $80 bil­lion and $130 bil­lion in fin­an­cial losses to the Texas eco­nomy and killed at least 210 people, accord­ing to Glenn Hegar, the state’s comp­troller of pub­lic accounts, in a report pre­pared in 2021. In response, the Texas Legis­lature man­dated new weather­iz­a­tion stand­ards for the nat­ural gas industry. The Texas Rail­road Com­mis­sion cre­ated a Crit­ical Infra­struc­ture Divi­sion to identify and inspect key ele­ments of nat­ural gas infra­struc­ture and ensure read­i­ness for winter storms, inspect­ing 7,400 facil­it­ies last year to ensure com­pli­ance with weather­iz­a­tion stand­ards, accord­ing to con­sultancy firm RBN Energy. Freeze-offs are most likely around the Haynes­ville shale gas basin in north­w­est Louisi­ana, where wells, pipelines and other infra­struc­ture are less cap­able of func­tion­ing in extreme cold, RBN Energy said in a Fri­day blog post. Reduced gas pro­duc­tion is also expec­ted in Oklahoma, New Mex­ico, Col­or­ado, North Dakota and within the pro­lific Mar­cel­lus and Utica shale basins of Pennsylvania, Ohio, and West Vir­ginia, where equip­ment is designed to oper­ate in tem­per­at­ures as low as zero degrees. Overnight lows are fore­cast to drop to near zero degrees dur­ing the next few days in the Mar­cel­lus and Utica shale regions, where about 32% of U.S. nat­ural gas is pro­duced. Reduced gas pro­duc­tion is expec­ted over the next nine days in Pennsylvania, Ohio and West Vir­ginia, where equip­ment is designed to func­tion at tem­per­at­ures as low as about zero degrees. The Cli­mate Pre­dic­tion Cen­ter's long-range guid­ance fea­tures below-nor­mal tem­per­at­ures for the Mid-Atlantic and North­east from Wed­nes­day to Feb. 3. In Cent­ral Pennsylvania, AccuWeather’s daily fore­casts for the first week of Feb­ru­ary show overnight lows ran­ging from 7 to 12 degrees.

Aboveground Water Pipelines Feeding Shale Gas Drilling Operations Beginning To Freeze Due To Cold Temperatures; Range Resources Incident Reported In Washington County; Notify DEP Of Pipeline Problems --On January 22, Mount Pleasant Township Police reported the freezing of an aboveground water pipeline serving Range Resources shale gas drilling operations in Washington County near the Yonker Tank Pad. The police notice said "extreme weather and temperature conditions have caused frozen piping" requiring Range Resources to switch to hauling water by dozens of trucks on Township roads for the next two weeks.The notice explained the Mount Pleasant Township Zoning Officer granted a temporary modification of a Range Resources permit to allow hauling water by truck rather than pipelines.Anyone seeing pipeline problems caused by cold temperatures or anytime, should report it immediately to DEP’s 24-hour Emergency Response Hotline - 800-541-2050.Contact DEP’s Oil and Gas Office nearest you for more information.There are hundreds of miles of aboveground water and wastewater pipelines feeding shale gas drilling operations across the state.These pipelines are vulnerable to failure due to sustained freezing temperatures like those Pennsylvania is now experiencing. These HDPE plastic pipelines are laid on top of the ground and are frequently not secured.DEP does not have the authority to regulate the routes taken by these pipelines, but does require erosion and sedimentation and stream crossing permits. Natural gas infrastructure is very vulnerable to sustained cold temperatures. Cold temperatures in December 2022 were blamed for a series of accidents involving natural gas facilities in Pennsylvania--

• -- Christmas morning December 25 the Energy Transfer Revolution Cryogenic Natural Gas Processing Plant in Smith Township, Washington County suffered a catastrophic explosion. Read more here.
• -- December 26 MarkWest Liberty Midstream & Resources LLC had a 10,000 gallon spill at the Imperial Pipeline Compressor Station in Robinson Township, Washington County. Read more here.
• -- December 27 the CNX Oak Springs Natural Gas Pipeline Pigging State in South Franklin Township, Washington County vented 1.1 million cubic feet of natural gas. Read more here.
• -- December 30 KDKA in Pittsburgh reported a Hyperion Midstream natural gas gathering pipeline under construction slid down a hill and crashed through the basement of a home in Allegheny Township, Westmoreland County. Read more here.

Freezing temperatures have also been responsible for taking natural gas-fired power plants offline at the most critical times during periods of high winter demand.During Winter Storms Elliot and Gerri, the largest number of power plant “unplanned outages” were natural gas power plants. Read more here. Read more here.These power plants for penalized over $1.5 billion in 2023 for not being available when they were needed most. While improvements have been made, the North American Electric Reliability Corp again expressed its concern about the availability of natural gas-fired power plants in its report leading up to this winter. Read more here. On January 22, Bloomberg reported the current sustained cold weather may cut US natural gas output by the most since the deadly winter storm of 2021. Read more here. Also on January 22, the PJM Interconnection issued another Cold Weather Alert saying it may break the record for winter power demands on January 27 and 30. Read more here.

Freeze-Offs Near Record, Setting Stage for Natural Gas ‘Deliverability’ Issues and Upside Volatility - U.S. natural gas production freeze-offs hit a single-day high of 17 Bcf on Sunday (Jan. 25), according to Wood Mackenzie, with the worst to come in the Appalachian Basin as temperatures are forecast to fall well below zero in the Northeast this week. NOAA map showing the Friday night low temperature outlook across the Lower 48 United States, with widespread subfreezing temperatures across the Midwest, Plains, and Northeast, single-digit and below-zero readings in parts of the central and northern U.S., and milder lows along the West Coast and Florida, based on data as of Jan. 27, 2026. At A Glance:
-- 49 Bcf of freeze-offs over past week
-- Worst to come in Appalachia
-- Eastern price indexes well above $100

Wood Mackenzie reports historic natural gas freeze-offs as arctic weather drives production losses to near-record levels -- Wood Mackenzie today reported that natural gas freeze-offs reached a single-day high of 17 billion cubic feet (BCF) on January 25th, approaching the record 18 BCF seen during Winter Storm Uri as an intense Arctic weather system sweeps across the United States. Current freeze-off and cold weather impacts are estimated at approximately 13.5 billion cubic feet per day (bcfd), with Lower 48 production at approximately 95.8 bcfd. The cumulative freeze-off for the 2025-2026 winter season has now reached 58.3 bcf. "Freeze-off estimates for January 25th were revised upward, with North Louisiana estimates increasing by approximately 3 bcfd as temperatures at Shreveport reached a high of only 28°F and a low of 21°F following hailing conditions on January 24th," said Randall Collum Jr., P.E., Senior Vice President at Wood Mackenzie. "In response, pipe nominations were adjusted downward across nearly all pipelines, most notably with NG3 seeing a reduction of approximately 585 million cubic feet per day (mmcfd) and Tiger pipeline declining by approximately 365 mmcfd. Additionally, Gulf Run, Tiger and TETCO issued underperformance notices at several points for gas day January 25th, further reflecting the operational challenges stemming from the severe weather conditions." The freeze-offs have contributed to a historic jump in natural gas prices, driven by a dramatic shift in weather forecasts and the unique characteristics of this cold weather event. "This cold weather event differs significantly from last year," explained Eric McGuire, Director of Research – Commodities, Trading, & Data Analytics at Wood Mackenzie. "This cold event is much more intense and shorter-lived. The cold is also reaching much further south than we normally see in the U.S. This has resulted in large freeze-offs and intense spikes in demand, particularly in the south where Henry Hub—the futures price for natural gas—is located. We are seeing freeze-offs reach just over our forecast of 16 BCF and just shy of the Winter Storm Uri high." McGuire noted that the price surge also reflects broader market dynamics: "Coming into January, temperatures were looking significantly warmer than normal and production levels were strong. As a result, prices had dropped approximately $2 from their December highs. In the period of a single week, the entire outlook flipped due to changes in the weather forecast. On top of freeze-offs, the U.S. currently faces large 'deliverability' issues in Q1. While we theoretically have enough gas in underground storage to meet these supply shortfalls, these shortfalls can exceed what the market can withdraw from storage in a single day in some regions. This helps explain why prices have risen so much in the February contract, since February still has moderate risks of cold fronts coming through."

DEP: Range Resources Force Heating, Cutting Apart Frozen Polyethylene Shale Gas Water Pipeline To Release Water, Ice In Mount Pleasant Twp., Washington County --On January 21, 2026, the Department of Environmental Protection inspected the Yonker - Carns shale gas freshwater pipeline in response to a notification by Range Resources Appalachia, LLC the pipeline had frozen in Mount Pleasant Township, Washington County. On January 22, the Mount Pleasant Township Police reported the freezing of the pipeline serving the Yonker Tank Pad would require the company to switch to hauling water by truck. The police said repairs to the pipeline could take two weeks. Read more here.[Note: Mount Pleasant Township is also where horizontal drilling for new shale gas-related pipelines by MarkWest Liberty Midstream caused the release of 1.2 million gallons of drilling fluids into abandoned mine voids along the pipeline route from October to early January. Read more here.]During DEP’s inspection, Range Resources said they were in the process of dewatering the aboveground polyethylene pipeline at multiple locations along its route by "forcing heat into the line" and cutting the pipeline open to release water and ice. However, Range said the frozen water in the pipeline meant the company could not follow the dewatering plan it had in place for incidents like this and limited the locations where water and ice could be released.The company said at one location the operation "sprayed freshwater from the line into a nearby stream and into the trees along the stream."During its inspection, DEP took initial field measurements to verify freshwater was being released during the dewatering operations.DEP requested a response to the inspection report, "including information in regard to thedewatering of the TWL, including but not limited to, all areas of the TWL that were dewatered with photos and specific conductivity results of the areas, a total volume of water released duringdewatering, the Operator's plan for bringing the line back into use, and the Operator's dewatering plan."DEP's inspection report said "although no violations are observed, violations may be forthcoming pending further review." Click Here for DEP's inspection report + photos and the initial notification.

Flow Restrictions, Freeze-Offs Lead to 10-12% Drop in M-U --We’ve recently begun to highlight flow restrictions along pipelines that carry Marcellus/Utica molecules. When flows slow or stop (can’t reach other markets), the price typically falls because supply exceeds demand. But sometimes, the opposite happens. If pipelines are restricted due to outages and freeze-offs (as is happening right now with Winter Storm Fern), the supply of natural gas is diminished, leaving insufficient supply to meet increased demand due to the cold weather. When that happens, spot prices for natural gas soar. Wood Mackenzie reported that natural gas freeze-offs across the country reached a single-day high of 17 billion cubic feet (Bcf) on January 25th, approaching the record 18 Bcf set during Winter Storm Uri, as an intense Arctic weather system sweeps across the United States. What about the situation in the M-U?

Baker Hughes: $3B Data Center Bet Boosts Marcellus/Utica Gas - Marcellus Drilling News - Oilfield services giant Baker Hughes (BKR), a company with its fingers in many different energy pies (not just OFS) and operations in over 120 countries worldwide, issued its fourth-quarter 2025 update last week. We scoured the update, the conference call, and the latest slide deck. The company did not explicitly mention the Marcellus or Utica shale regions. However, several items from the update directly impact the outlook for the M-U region.

AI Comes to Expand Energy's Marcellus Wells in Pennsylvania - -Marcellus Drilling News - Baker Hughes has signed a multi-year agreement with Expand Energy, North America’s largest natural gas producer, to deploy its Leucipa™ AI-powered production solution across thousands of U.S. wells. This collaboration focuses on optimizing operations in the Marcellus, Utica, and Haynesville shales using data-driven insights and "Lucy," a generative AI production assistant. Leucipa will make Expand's operations more efficient and reliable by streamlining field decision-making and forecasting. AI comes to the shale fields of the Marcellus/Utica!

Infinity Natural Resources Buys Chase Oil Stake in South Bend Field in $36 Million All-Stock Deal-- Infinity Natural Resources, Inc announced that it has acquired Chase Oil Corporation’s working interest in Infinity’s South Bend field in Pennsylvania through an all-stock transaction valued at approximately $36 million. The transaction is effective January 1, 2026. Infinity said the acquisition marks the company’s first use of equity as consideration to advance its post-IPO expansion plan. The deal follows Infinity’s previously announced $1.2 billion pending acquisition of Antero Ohio, disclosed in December, and supports the company’s broader strategy of building scale in the Appalachian Basin through targeted consolidation. The acquired interest includes 18 producing wells, which delivered approximately 14 MMcf/d of net natural gas production in December 2025. Infinity also noted near-term development activity in the field, with three additional wells currently in progress and expected to begin sales in the first half of 2026. Beyond current production, the transaction adds long-dated drilling potential. Infinity stated that the acquired acreage position supports an estimated 40 additional gross Marcellus locations and 38 gross Utica locations, strengthening its future inventory in key stacked-play development zones. The acquisition also consolidates acreage in one of Infinity’s core dry gas areas in Pennsylvania. The deal adds 1,613 net Marcellus acres and 1,613 net Utica acres, bringing Chase’s working interest into Infinity’s operated footprint and improving operating continuity across the South Bend field. Commenting on the announcement, Zack Arnold, President and CEO of Infinity, said the deal supports the company’s consolidation strategy in the Appalachian Basin. “This bolt-on acquisition allows us to use our equity currency for the first time to consolidate our core dry gas position in Pennsylvania and execute our post-IPO strategy,” Mr Arnold said. “The transaction adds high NRI leases that contribute immediate production and EBITDA in 2026, while being accretive in both 2026 and 2027. We remain focused on disciplined growth through acquisitions that strengthen and complement our existing portfolio.” Infinity Natural Resources is a growth-focused independent energy company with operations concentrated in the Appalachian Basin. The company is active in the Utica Shale in eastern Ohio, along with stacked dry gas positions in the Marcellus and Utica Shales in southwestern Pennsylvania, and focuses on building free cash flow through a combination of development and strategic acquisitions.

Antero Resources: Projected FCF Boosted By Recent Transactions - Antero Resources (AR) is increasing its production by approximately 20% through its recent transactions and may end up with around 4.2+ Bcfe per day in pro forma 2026 production.The transactions add around $2 billion to Antero's debt, but it is also expecting close to $500 million in net additional 2026 free cash flow from the transactions. I now project Antero to generate around $1.54 billion in pro forma 2026 free cash flow at the current strip if it goes with a maintenance capex budget.Antero Resources announced a couple of significant transactions in December 2025. It acquired HG Energy II's upstream assets (West Virginia Marcellus) for $2.8 billion in cash plus the assumption of HG Energy's hedge book. That hedge book is reasonably close to neutral value, although slightly negative at the current strip.Antero Resources is also divesting its Ohio Utica Shale upstream assets for $800 million in cash.These transactions are expected to net out to approximately 700 MMCFE per day in additional 2026 production for Antero Resources for a total net cost of $2 billion.Antero also estimated that its 2026 EBITDAX would increase by approximately $700 million and its 2026 free cash flow would increase by approximately $495 million due to these transactions. This was based on early December 2025 strip prices, which were above $4 for NYMEX natural gas (a bit above the current $3.95 level).These transactions are a positive for Antero's free cash flow and its future development plans. It is divesting Utica Shale assets that it had paused development on for the last couple of years and adding an estimated five years of Marcellus inventory at maintenance capex levels.Antero announced that it was issuing $750 million in 5.4% unsecured notes due 2036 at a price of 99.869% of par. It expects to receive $743 million in net proceeds after expenses and discounts, which it will use to help fund part of its HG acquisition. Antero is also expecting to use the free cash flow from the acquired assets to help pay down its debt. The 10-year Treasury yield was around 4.1% to 4.2% at the time, so Antero is paying around 1.3% above that. This is also consistent with Antero's BBB- credit rating.Antero hasn't provided exact details around its expected post-transaction 2026 production mix yet, so I've attempted to model it based on available information. This includes the production mix from its divested Utica assets as well as East Daley's information around HG Energy's production.Antero may thus average approximately 4.212 Bcfe per day in total 2026 production, pro forma for its recent transactions. This includes 2.7 Bcf per day in natural gas production, for a 36% liquids weighting.At the current 2026 strip of $3.95 NYMEX natural gas, Antero is projected to generate $6.347 billion in revenues after hedges. This is also net of distributions to Martica and dividends from Antero Midstream.

Antero Resources completes notes offering for acquisition funding - On January 28, 2026, Antero Resources Corporation completed a $750 million underwritten public offering of 5.400% senior unsecured notes due 2036, which pay interest semiannually and rank equally with the company’s other senior unsecured debt but are structurally subordinated to obligations at its subsidiaries. The notes, issued under a new indenture with typical covenants and redemption provisions, are intended to help fund Antero’s planned acquisition of HG Energy II Production Holdings, LLC alongside a new term loan facility, with remaining acquisition costs to be covered by proceeds from the sale of substantially all of Antero’s and certain subsidiaries’ Utica Shale oil and gas assets, or, if timing requires, its revolving credit facility and cash on hand, after which Utica sale proceeds would be used for general corporate purposes including debt repayment; if the HG acquisition does not close by the agreed outside date or is terminated, Antero must redeem all of the notes at 101% of principal plus accrued interest, underscoring deal-contingent financing risk for noteholders and tying the company’s capital structure moves closely to its strategic portfolio shift.Antero Resources Corporation is an independent oil and natural gas company focused on the exploration, development and production of unconventional resources, including shale oil and gas assets in the United States, with a portfolio that has included significant holdings in the Utica Shale region.

Form 8-K ANTERO RESOURCES Corp For: Jan 28 – report to the SEC

WV Court Vacates Shale Forced Pooling Order for Arsenal Resources - Marcellus Drilling News --The Intermediate Court of Appeals of West Virginia vacated an order combining 58 oil and gas tracts into a Harrison County drilling unit, ruling that the state’s Oil and Gas Conservation Commission failed to provide sufficient findings of fact. The case involves the “JOsborn 213 Unit” operated by Arsenal Resources, which mineral rights owners claim failed to negotiate in good faith as required by law. The court found the Commission ignored conflicting testimony and provided only summary conclusions rather than a detailed analysis. Consequently, the case was remanded for further proceedings, requiring the Commission to properly evaluate all evidence and issue a new order.

History Repeats: NY DEC Asks FERC to Reject Constitution Pipeline - Marcellus Drilling News -- Reverting back to true form by obsequiously bowing to environmental extremists, New York Governor Kathy Hochul ordered her lapdogs at the state Department of Environmental Conservation (DEC) to log an objection with the Federal Energy Regulatory Commission (FERC) to a request by Williams to resurrect the Constitution Pipeline project. Even though Hochul bartered a deal with President Trump to allow this pipeline (see Trump Deal Trades NY Offshore Wind for Constitution, NESE Pipes). The Constitution is a 124-mile pipeline from the Marcellus gas fields of Susquehanna County, PA, to Schoharie County, NY, to move Marcellus gas into New York State and New England.

40% of New England’s Electric Generated by Oil During Winter Storm - Marcellus Drilling News -- New England’s Democrat-led energy policies have failed spectacularly, leaving the region as an “energy island” during peak winter demand. Despite ambitious “net-zero” goals, a recent snowstorm forced the power grid to rely on oil for 40% of its electricity because renewables like wind and solar contributed less than 2%. New England policymakers like Govs. Maura Healey of Massachusetts and Janet Mills of Maine have created artificial scarcity and price spikes by blocking natural gas pipeline expansions. They insist on unreliable renewables. When a storm like Winter Storm Fern hits, it forces New England to rely on carbon-intensive oil and increases the risk of blackouts. You can’t fix stupid.

High Gas Price Crushes the Ethane Ratio-to-Natural Gas to 6 Year Low - With the February price of natural gas soaring above $5/MMbtu last week in response to Winter Storm Fern, the ethane-to-gas ratio has been crushed below 0.75 for the first time since mid-2019 (left graph below). The ratio, which compares Mont Belvieu ethane prices to Henry Hub natural gas on a BTU basis is an indicator of ethane rejection economics. When ethane prices are lower than natural gas on a BTU basis, more ethane is “rejected” at the natural gas processing plant and sold as natural gas, assuming there are no physical or contractual constraints on doing so. The ethane-to-gas ratio averaged 1.06 in 2025, and 0.92 so far in 2026, both very weak numbers. The dip below 0.75 (purple dashed circle, right graph) is primarily due to the 70% increase in the prompt natural gas price, while the price of ethane increased “only” 37%, from 19 c/gal to 26 c/gal. Note that the M1 (March) natural gas price on Friday was $3.61/MMbtu, well below the prompt month. If March continues at level, the ethane-to-gas ratio will likely move back above 1.0 when the CME/NYMEX contract month rolls on Wednesday (January 28).

Propane Continues to Lag Crude in January - - The Mont Belvieu propane price continues to lag crude despite recent weather-driven demand. The propane-to-WTI ratio is averaging 43% so far in January, based on monthly average prices, with WTI crude at $59.22/bbl and propane at 60.67¢/gal. The ratio is down from 47% in December and remains below the spring peak near 56%. While parts of the country experienced a winter storm this week that likely supported near-term heating demand, its influence on the monthly propane-to-crude ratio has been muted so far, with broader fundamentals still dominating price relationships. At current levels, the ratio is approximately 7 percentage points below the same period last year.

Chesapeake Utilities to Build NatGas Pipeline to Va. Eastern Shore - Marcellus Drilling News --Last November, Accomack County, Virginia, secured a $6.5 million state grant to expand piped natural gas to the Eastern Shore, a move aimed at stabilizing the local economy (seeNatural Gas via Pipeline for Va. Eastern Shore Gets a $6.5M Boost). The project targets major employers like Perdue Farms, Tyson, and NASA’s Wallops Flight Facility. It aims to reverse employment declines and lower energy costs for everyone. Analysts say that natural gas could cost homeowners 57% less than using propane, and industrial users 75% less than using electricity. The new news is that Accomack County has signed a deal with Chesapeake Utilities to build the project.

Winter Storm Stops Nearly All Feedgas to Cove Point, Elba Island - Marcellus Drilling News --Winter Storm Fern triggered a sharp decline in U.S. LNG feedgas demand, which plummeted to 11.5 Bcf/d on Sunday from a previous weekly average of 17.2 Bcf/d. The storm caused production freeze-offs and price spikes, forcing Elba Island to shut down, and Cove Point inflows fell below 0.2 Bcf/d. Sabine Pass and Freeport (along the Gulf Coast) were down 50% and 30%, respectively.

Man Bites Dog: Elba Island & Cove Point *Import* LNG from Trinidad - Marcellus Drilling News --Here’s an unusual turn of events. During the recent cold snap and winter storm, the Cove Point LNG export facility (in Maryland) and Elba Island (in Georgia) stopped exporting LNG and instead *imported* LNG—from Trinidad and Tobago. They aren’t the only ones. The Everett LNG import facility off the coast of Boston and Canaport in New Brunswick, Canada, also imported Trinidad LNG cargoes. What the heck is going on here? We’ll explain.

Top 50 Public E&P Operators of 2025 Ranked by O&G Production - Marcellus Drilling News Enverus, a leading energy SaaS and analytics platform, has released its annual list of the top 50 public onshore exploration and production (E&P) companies in the U.S., based on gross-operated production last year. ExxonMobil leads the ranking again at 1.95 MMboe/d, followed by Expand Energy (formerly Chesapeake Energy) at 1.75 MMboe/d and ConocoPhillips, which climbed three positions to claim the No. 3 spot at 1.42 MMboe/d. Six of the top 10 companies list the Permian Basin as their primary operating region. Two of the top 10 are companies primarily operating in the Marcellus/Utica, including Expand Energy and EQT---the #1 and #2 gas-producing companies in the U.S., respectively. EOG Resources is also in the top 10. Although it's categorized as a Gulf Coast-focused driller, EOG has major assets and drilling activity in the Ohio Utica Shale.

Chesapeake, Berkshire Canaveral (FL) LNG Plan Continues to Advance -- Marcellus Drilling News - In December, representatives from Chesapeake Utilities and BHE GT&S, a subsidiary of Berkshire Hathaway Energy, presented a proposal to the Port Canaveral Authority to construct a new liquid natural gas (LNG) liquefaction facility in Brevard County, FL (seeChesapeake, Berkshire Hathaway Propose LNG for Port Canaveral). The project, targeting a 2029 completion date, aims to supply essential fuel for both cruise ships and the burgeoning space industry’s rockets. While LNG is currently trucked in to support rocket launches, this facility would provide dedicated local infrastructure to meet the growing demands of the world’s busiest cruise port and the active space sector.

Woodside Reports Strong Construction Progress at 16.5 Mt/y Louisiana LNG Terminal -- Foundational work on Louisiana LNG’s first phase is advancing on schedule as commercialization continues, keeping the project on track for first LNG before the end of the decade, according to Woodside Energy Group Ltd. At A Glance:

• First LNG targeted for 2029
• Project reaches 22% completion
• North American gas exposure expanding

ExxonMobil Sees First Golden Pass Cargo in Early March, Potential Mozambique FID by Year-End -- ExxonMobil is doubling down on natural gas, with LNG now grouped with the Permian Basin and Guyana as drivers of the company’s upstream future. At A Glance:

• Golden Pass LNG in commissioning phase
• First LNG cargo expected early March
• Mozambique project redesign lowers costs

Galveston LNG Bunker Port Targets Mid-2026 for First Jones Act Vessel Charter --Project partners behind Galveston LNG Bunker Port LLC (GLBP) are working with shipbuilder Tote Services LLC to secure a fleet of bunkering vessels for the small-scale marine fueling project. At A Glance:

• Tote Services to develop bunkering fleet
• Project advances toward 2026 FID
• Texas City site gains commercial momentum

XRG Deepens U.S. LNG Push With Equity Buy in Rio Grande Trains - Abu Dhabi’s energy investment arm XRG PJSC is increasing the United Arab Emirates’ (UAE) exposure to Texas natural gas exports with a stake in the Train 4 and 5 expansion of NextDecade Corp.’s Rio Grande LNG. At Glance:

• NextDecade expansion attracts Gulf capital
• XRG buys 7.6% Rio Grande stake
• Six-train buildout eyed by 2032

Winter Storm Temporarily Slashes U.S. LNG Feedgas Demand - U.S. LNG feedgas plummeted over the weekend as Winter Storm Fern hit parts of the country. The storm caused massive production freeze-offs, high domestic demand, and spiking U.S. prices, which in turn disrupted LNG feedgas demand. Feedgas demand averaged 17.2 Bcf/d last week (blue-dotted line in chart below), down about 1.2 Bcf/d from the previous week. Feedgas demand averaged 18.9 Bcf/d from Monday to Friday last week, then dropped to around 14.4 Bcf/d on Saturday and 11.5 Bcf/d on Sunday. Inflows were reduced at every terminal. Elba Island shut in completely over the weekend, while inflows at Cove Point were below 0.2 Bcf/d. The impact was more mixed for the terminals on the Gulf Coast, with intake at most terminals dropping by 20-30% at the peak of the storm, but Freeport and Sabine Pass saw larger disruptions. Sabine Pass was operating at 50% capacity on Sunday, while Freeport intake dropped to 30% of its typical utilization. LNG feedgas demand is already rebounding as the country begins to thaw out from the storm. Feedgas demand on Monday was down slightly from Sunday, but is up by 2 Bcf/d today (January 27). Temperatures will likely continue to warm up this week and LNG feedgas intake should normalize. Stay tuned to the LNG Voyager Weekly Report for more updates on the U.S. LNG market.

U.S. LNG Feed Gas Deliveries Fall off Cliff as Operators Grapple With Severe Cold -Every U.S. LNG export facility in the country curbed operations ahead of Winter Storm Fern, sending feed gas deliveries plummeting by more than 30% between late last week before the worst of the weather arrived and Monday. NGI North America LNG export flow tracker chart showing daily U.S. LNG feed gas deliveries from Jan. 17–26, 2026, ranging from about 12.0 to 19.1 million Dth, with facility-level volumes for Corpus Christi, Freeport, Sabine Pass, Calcasieu Pass, Plaquemines, and other major export terminals.At A Glance:
All export terminals impacted
Feed gas demand plummets by 34%
Henry Hub rally continues

LNG Flows Surge into Everett as New England Gas Prices Soar -- New England has received an LNG cargo to shore up supplies just as freezing weather settles over the region, sending natural gas prices into the stratosphere. At A Glance:

• Algonquin prices surge amid storm
• Everett sendout jumps near capacity
• Canadian gas prices move higher

Freezing Weather Forces the World’s Top LNG Exporter to Import Gas | OilPrice.com -Several energy companies imported liquefied natural gas into the United States, with the unusual move prompted by surging demand for energy and heating pushing gas prices to all-time highs. According to LSEG data cited by Reuters, BP and Shell sent LNG cargoes from their jointly owned Atlantic LNG plant in Trinidad and Tobago to the U.S. last week. In fact, per the data, most of the LNG coming into the United States amid the freeze is coming from Trinidad and Tobago. The gas arrives at import terminals for regasification and distribution, although some cargoes arrived at two export terminals - Elba Island and Cove Point - highlighting the tight supply situation. The severe winter weather sweeping across the United States has not only led to a surge in the demand for electricity and heating but has also disrupted the production of oil and gas. According to Rystad Energy, as much as 25 billion cu ft in daily production may have been knocked out by the storms and the freezing temperatures.Oil production has suffered as well, with outages in the Permian alone estimated at 1.5 million barrels daily, according to Energy Aspects. Total oil production outages may have reached 2 million barrels daily, resulting in a rally for oil prices, with Brent crude earlier today inching closer to $70 per barrel and West Texas Intermediate at $64.11 per barrel. LNG prices on the spot market, meanwhile, hit $100 per million British thermal units at one point, according to Reuters.The unusual situation of the U.S. having to import the commodity it is the biggest exporter of on a global level has its explanation in the Jones Act, which the industry has been grumbling against for years. The Jones Act effectively bans the trade in LNG between U.S. ports because it mandates that all trade between local ports must be executed using U.S.-flagged vessels. There are no U.S.-flagged LNG carriers.

US Natural Gas Jumps Almost 20% as Arctic Blast Takes Hold - U.S. natural gas jumped by almost 20% as freezing weather swept across much of the country, boosting heating demand and disrupting supplies. Front-month futures soared above $6 per million British thermal units for the first time since 2022. That followed a 70% rally last week, the biggest weekly advance in records going back to 1990. The winter storm is estimated to have knocked offline almost 10% of U.S. natural gas production, just as demand for the heating and power plant fuel jumped. The big freeze has strained electricity grids and crippled transport links, grounding thousands of flights. Traders are closely watching how long the disruption to U.S. gas output will last as the storm sweeps in, and some were caught off guard by the scale of the disruptions in key export hubs such as Louisiana and Texas. Global gas markets have seen a volatile start of the year and a bigger impact than what’s already priced in could continue to send prices higher. The largest U.S. grid operator is pushing power plants to secure natural gas supplies through the week on expectations that frigid temperatures will drive electricity usage to a winter record. Gas flows to U.S. liquefied natural gas export plants have dipped to the lowest in a year as the winter storm disrupts output. Natural gas prices hit the highest since December 2022, when European demand for U.S. liquefied supplies was booming after it lost supplies from Russia following the country’s invasion of Ukraine earlier in the year. “U.S. gas price volatility is set to become a much bigger driver of LNG market value and risk across the next five years,” Timera Energy analysts wrote in a note. The impact on front-month prices is also being exacerbated because the February contract expires on Jan. 28, leaving liquidity relatively thin. Open-interest was less than 25,000 contracts on Jan. 26, compared with 340,000 contracts for March futures. The March contract climbed as much as 11% to $3.997 per million Btu, while the one for February gained as much as 19%.

US spot gas prices soar near LNG terminals -Natural gas spot prices at key regional hubs near US LNG terminals soared today as a winter storm sweeps the country, topping fob LNG values and incentivizing some offtakers to reinject their supplies to domestic markets. Customers with LNG tolling arrangements have more flexibility than those with sales and purchase agreements because they control their gas supply and are not obligated to liquefy it. This can spur traders to redirect gas to much more profitable domestic markets in extreme weather rather than export the volumes. Texas' 17.3mn t/yr Freeport, Louisiana's 15mn t/yr Cameron, Georgia's 4mn t/yr Elba Island and Maryland's 5.75mn t/yr Cove Point primarily operate on tolling agreements. Weighted average day-ahead feedgas costs from hubs near those LNG terminals surged to between $20-52/mn Btu on 23 January, likely discouraging exports (see chart). Those prices are much higher than Argus' spot LNG price for January-loading LNG on the Gulf coast, which averaged $8.27/mn Btu in December. Prices for LNG delivered to northwest Europe in the second half of February also were below the US spot prices, settling on 23 January at $12.99/mn Btu, according to Argus data. Preliminary feedgas nominations as of 6pm ET for the gas day beginning at 10am ET on 24 January showed less volume going to Freeport, Elba Island and Cove Point than the day prior, with Elba Island set to reinject about 555mn ft³ into the grid. Nominations to Cove Point halved to about 160mn ft³, and flows to Freeport were set to drop by 41pc to 1.2bn ft³. Nominations to Cameron were marginally lower at 1.9bn ft³, which would be the lowest since 30 October if realized. The arctic blast cold also shut in capacity at other US LNG facilities due to operational issues, such as frozen equipment on pipelines and compressor stations.

Spot Prices Wrap: Regional Natural Gas Hubs Surpass $100 Amid Winter Storm Carnage -With much of the country still firmly in Winter Storm Fern’s icy grip, natural gas cash prices reached astronomical heights on Monday as plummeting production and surging heating created headaches for traders. Line chart showing NGI’s Transco Zone 6 non-NY daily natural gas prices from early 2025 through January 2026, with prices mostly ranging below $10/MMBtu before a sharp spike above $130/MMBtu in late January 2026. At A Glance:
Production plunges
Northeast hubs hit triple digits
More supply impacts to come

Industrial End Users Plea for Suspension of Spot LNG Exports as U.S. Energy Prices Soar - The head of the Industrial Energy Consumers of America (IECA) sent a letter to the U.S. Department of Energy on Wednesday warning that extreme cold and soaring electricity and natural gas prices are forcing manufacturers to shut down.Line chart showing NGI’s National Avg. Daily Natural Gas Prices from late January 2025 through late January 2026, with prices mostly below $5/MMBtu before spiking sharply above $45/MMBtu in late January 2026.At A Glance:
Manufacturers see profits squeezed
IECA warns of supply chain disruptions
Trade group has long bemoaned rise in exports

Geopolitical environment supports oil as weather sends gas soaring -Oil prices have held up well so far this year, with several geopolitical events providing support to the market. The US arrest of Venezuela’s president and escalating tensions between the US and Iran pose risks to supply, particularly with the latter. An escalation between the US and Iran puts around 1.5m b/d of Iranian oil exports at risk – but clearly, any escalation would also raise concerns over broader Persian Gulf oil flows through the Strait of Hormuz, where roughly 20m b/d moves through.There have also been disruptions to oil supply elsewhere. This has proved supportive for the prompt Brent timespread, which has strengthened this month. Kazakh oil exports from the CPC terminal in Russia have been under pressure following drone attacks on the terminal, while oil production from the country has also faced unplanned outages due to power issues. Still, these flows are set to recover in the weeks ahead. Meanwhile, freezing weather conditions in the US not only provide support to demand for heating fuels but also pose a risk to some US oil production and refinery operations.However, the scale of the expected oil surplus in the market suggests that if and when geopolitical risks ease, we should see oil prices coming under pressure. We continue to hold onto the view that ICE Brent will average $57/bbl over 2026. A weakening in timespreads would make us even more confident in the view of lower oil prices.Natural gas prices have seen significant strength through January. Initially, strength was seen in the European market, with colder weather, tighter storage, and speculative short-covering providing a boost to TTF.However, more recently, the US gas market has dominated market moves, with a severe winter storm across the US raising heating demand and leading to production shut-ins. This saw Henry Hub front-month futures more than double in as little as 10 days, trading to their highest levels since 2022. Speculators were also caught off guard, holding a net short in Henry Hub ahead of the storm. Short covering from speculators would have only added fuel to the fire. The impact of the storm is likely to lead to a significant drawdown in US natural gas storage, but given that storage was very comfortable ahead of the storm, it should be manageable; we expect that prices will correct lower, assuming no longer-term impact on supply from the storm.The US winter storm has raised further supply concerns for Europe, with US LNG plants having reduced operating rates, suggesting that US LNG flows to Europe could slow. This has led to European gas prices trading at a large premium to Asia to ensure LNG cargoes are directed to Europe.It is looking increasingly likely that EU gas storage will finish the 2025/26 heating season below 2022 levels. However, the difference between 2022 and 2026 is that now we have a sizeable amount of LNG export capacity ramping up, which should ease supply concerns in the medium to long term. In addition, there is much less uncertainty over Russian gas flows to Europe in 2026 than in 2022.

LNG Imports Surge as Third Trinidad Cargo Nears U.S. Shores - Prompt month natural gas statistics, summarizing pricing, spreads and storage data as of trading close to provide a snapshot of current market conditions. A look at the global natural gas and LNG markets by the numbers:

• 3 cargoes: The United States could receive its third cargo of LNG from Trinidad and Tobago this week, marking a high point for U.S. imports. A Shell-controlled vessel, the Paris Knutsen, entered the Savannah River and headed to the Elba Island LNG terminal Wednesday, according to Kpler data. It would be the first cargo imported at Elba Island since 2020. Two other vessels with volumes from Atlantic LNG loaded at the Everett terminal near Boston and Cove Point in Maryland earlier in the week.
• 2.61 Mt: U.S. LNG exports are set to recover this week, driven by a slight uptick inAsian demand. Shipments from U.S. terminals are seen rising 1.2% the week of Jan. 26 to 2.61 million tons (Mt), according to Kpler predictive data. The uptick comes in the face of widespread outages and pipeline constraints across the Gulf Coast that have pushed down feed gas nominations. Demand from South Korea helped offset a 0.17 Mt week/week reduction in volumes to Europe.
• 16.2 Bcf/d: Nominations to U.S. LNG terminals have recovered after a more than 45% reduction during Winter Storm Fern, according to Wood Mackenzie. That drop outpaced the 2025 freeze across the Gulf Coast and 2021’s Winter Storm Uri. Feed gas nominations dropped Monday to one of the lowest points in more than a year. By the Wednesday morning gas cycle, nominations had recovered to near 17 Bcf/d. Wood Mackenzie estimated nominations to average 16.2 Bcf/d over the next seven days.
• 25–30%: Santos Ltd. has shipped the first cargo from Darwin LNG produced from theBarossa field, marking a milestone for its expansion and extension project for the legacy export terminal. The Australian firm disclosed a vessel left Darwin over the weekend and was headed to Japan. Exports from the 3.7 Mt capacity facility declined exponentially after 2021 and ceased completely in 2024. With new supplies from the field northwest of the Australian coast in the Timor Sea, Santos is targeting a 25-30% increase in its production portfolio by 2027.

Another Blast of Winter Poses Risk of Further Disruptions to LNG Exports Just as Feed Gas Rebounds -- U.S. LNG feed gas nominations have climbed by about 50% over the past two days as the market recovers from Winter Storm Fern, but more disruptions could occur in the days ahead as another round of cold is forecast to spread southward.North American LNG export tracker, detailing export volumes by terminal alongside a map of active and proposed LNG facilities across the United States. At A Glance:
Feed gas noms climb above 16 Bcf
High prices, upstream issues still pose risks
Elba Island poised to import cargo

Manufacturers Ask DOE Sec. Wright to Suspend Spot LNG Exports - Marcellus Drilling News -- Industrial Energy Consumers of America (IECA), a trade group representing some of the largest energy consumers in the U.S. (i.e., manufacturers), on Wednesday sent a letter to Energy Secretary Chris Wright urging the immediate suspension of spot LNG exports to reduce natural gas and electricity prices and ensure reliability. This raises many questions, such as how much of our LNG exports are spot/cash and how much are under long-term contracts. Would suspending spot LNG exports be beneficial for consumers? Is this anti-free market?

Henry Hub Prices Smash All-Time Records as Winter Storm Fern, LNG Tag-Team to Tighten Balances -- Henry Hub natural gas spot prices surged to an all-time high average $30.565/MMBtu on Monday (Jan. 26) as Winter Storm Fern exposed how LNG growth has upped the ante for supply shocks. NGI’s Henry Hub Daily Natural Gas Prices: A snapshot of the highest daily price spikes on record, highlighting periods of extreme volatility in the U.S. natural gas market. At A Glance:
Henry Hub spot tops Uri 2021 records
LNG demand double that during Uri
Power demand, Mexico exports also factors

New NYMEX NatGas Front-Month Contract (March) Closes “Up” at $3.92 --Marcellus Drilling News - Yesterday, the NYMEX natural gas March futures contract became the “front month” contract after the previous February contract expired. As we reported, the February contract went into the stratosphere, closing at $7.46/MMBtu based on something called a short squeeze (seeShort Squeeze: NYMEX NatGas Up Another 50.6 Cents to $7.46/MMBtu). The March contract closed at $3.918/MMBtu yesterday, which is $3.54 lower than the previous day. So, how can we say the March contract closed up from the previous day?

Kinder Morgan Updates Major Projects in Q4 Earnings Call -On their year-end earnings call January 21, 2026, Kinder Morgan (KMI) management attributed record results to growth in their natural gas businesses, particularly in the Eagle Ford, Haynesville and Northeast segments. In their opening comments, they highlighted strong Haynesville gathering growth and noted the system hit a new throughput record of 1.97 Bcf/d on Christmas Eve. They also gave a quick progress update on several big projects. Trident kicked off construction the prior week, and both Mississippi Crossing (MSX) and South System Expansion 4 (SSE4) have received FERC scheduling orders, with final certificates expected by July 31. MSX is now expected to come online earlier than originally planned, moving up from Q4 ’28 to Q2 ’28. The prepared statements also highlighted the recently announced second open season for Western Gateway (their products pipeline JV with Phillips 66), which adds additional origin points and expands delivery into the Los Angeles market by reversing KMI’s existing SFPP lines between Watson and Colton, CA (the proposed project mapped below). In the Bakken, management said Phase 1 of the Double H conversion to NGL service is still on track to startup in Q2 of this year, with a portion of the NGL volumes expected to come from KMI plants. They didn’t offer a firm update on Phase 2, but pointed to rising gas-oil ratios in the basin as a reason to expect additional volumes over time. Looking ahead, KMI’s project backlog climbed to $10 billion, with a big chunk tied to rising power demand and LNG feedgas needs. When asked whether KMI might take an equity stake in an LNG terminal like some of their peers, CEO Kimberly Dang shut down the idea, stating "we're staying in our lane" and noted LNG returns aren't attractive to them at the moment and wouldn’t be interested in building a terminal themselves either. Executive Chairman Richard Kinder jumped in briefly during Q&A to add that LNG feedgas and power-related contracts they have are often long-term (typically 20-25 years) take-or-pay deals, which helps mitigate risk as opposed to contracting directly with project developers of both LNG terminals and data centers.

P&GJ 500 Report Shows Established Operators Still Dominate U.S. Pipelines -— The companies leading Pipeline & Gas Journal’s (P&GJ’s) latest 500 Report will look familiar, though the newest rankings reveal notable reshuffling across several key metrics as operators continue to adjust to evolving market conditions. Among U.S. gas distribution utilities, rankings vary depending on the measure examined, highlighting differences in system scale, sales volumes and financial performance. By miles of U.S. distribution piping, CenterPoint Energy Operations leads the industry with 176,000 miles of distribution piping, followed by Columbia Gas of Ohio and Southern California Gas. Other large systems include Dominion Energy Ohio, Consolidated Edison of New York, UGI Utilities, Atmos Energy and AGL Resources, underscoring the concentration of physical infrastructure among a relatively small group of utilities. When ranked by gas sold, DTE Energy tops the list, followed by Dominion Energy Ohio and CCMS Energy, including Consumers Energy. National Grid, INE Gass, UGI Utilities and Xcel Energy also rank among the Top 10, reflecting strong regional demand across the Midwest, Northeast and West. In terms of operating revenue, Pacific Gas & Electric and Southern California Gas again lead the industry, each reporting gas sales of more than $6 billion. Gas transmission pipeline rankings show consistency at the top, with some variation by category. DCP Midstream leads the industry in total miles of gas pipelines, followed by Pacific Gas & Electric, Nicor Gas and Energy Transfer. Northern Natural Gas, Columbia Gas Transmission and Tennessee Gas Pipeline also remain among the largest systems by mileage. The liquids pipeline sector shows greater differentiation depending on whether rankings are based on deliveries, revenues or miles of pipe. In crude oil deliveries, ConocoPhillips Alaska leads the industry, followed by Hiland Crude and Marathon Pipe Line. Buckeye Pipe Line, ETP Crude and Seaway Crude Pipeline also rank prominently, with ExxonMobil Pipeline, Medallion Pipeline, Enbridge Energy and LOCAP completing the Top 10. By miles of liquids pipelines, Energy Transfer operates the largest system, followed by Magellan Pipeline Company and Marathon Pipe Line. Mid-America Pipeline, Enbridge Energy and Buckeye Pipe Line Transmission also rank among the Top 10..Southbound – New Pipelines Push More Haynesville Natural Gas South to Meet LNG Demand | RBN Energy -Haynesville natural gas production is heading back to record levels thanks to growing LNG demand and new pipelines designed to move gas from north to south in Louisiana. Since last summer, two new pipelines, Momentum’s NG3 and Williams’s Louisiana Energy Gateway (LEG), have been pushing production east and pulling more gas south to serve LNG demand in the area near Lake Charles. In today’s RBN blog, we’ll preview some of the topics we’ll be covering regularly in our new weekly NATGAS Haynesville report by taking a closer look at how LEG and NG3 are reshaping the market. The Haynesville Shale is one of the most consequential gas basins in the U.S., especially as LNG exports along the Gulf Coast continue to grow (see Sitting, Waiting, Wishing). One of the first shale basins to be extensively exploited with unconventional drilling techniques, the Haynesville burst onto the scene in 2008 during the early days of the Shale Revolution. While the Appalachian Basin is the largest gas producer, and the Permian the fastest-growing, the Haynesville stands out for three significant reasons. First, its location in Northwest Louisiana and Northeast Texas puts it in a sweet spot, nestled close to Gulf Coast LNG export facilities and well positioned to serve rising power demand across the Southeast. Second, unlike the Permian and Appalachian basins, the Haynesville isn’t boxed in by infrastructure and pipeline constraints. It has spare pipeline capacity (though that does not mean that all the gas can get to the most ideal markets), which means producers can ramp up output in the near term without waiting for new infrastructure. Finally, the basin is extremely responsive to Henry Hub prices, perhaps more so than any other basin in the U.S. When prices are high, production climbs; when prices are low, it pulls back. That makes the Haynesville one of the country’s most effective swing producers. As LNG demand grows and puts upward pressure on Henry Hub prices, the Haynesville is poised to respond. Production in the basin peaked in May 2023, just shy of 16.5 Bcf/d, following the extremely high Henry Hub pricing in 2022 (teal line and left axis in left graph in Figure 1 below). The rig count (orange line and right axis) peaked in late 2022, reaching 75, before producers scaled back in response to lower prices in 2023 and 2024. The rig count began climbing again last year and stands at 46 as of mid-January. Production fell from the May 2023 peak to just above 13 Bcf/d at the end of 2024 (sum of gold and green layers in graph to right) before beginning to climb again last year. Current production is around 16 Bcf/d, and we expect output to keep rising this year, topping the previous record by spring. Once new takeaway capacity comes online, it will push even higher from there as the new pipelines begin to fill. While overall U.S. production growth has been based on supportive production economics intrinsically linked to the prices of crude oil and natural gas, increases in export demand have done more to shape the Haynesville. Although the basin had sufficient spare pipeline capacity, most of it was heading east across the top of Louisiana. And while much of that gas subsequently turned south, it’s not the ideal route for serving the growing demand along the coast. Strong LNG demand incentivized pipeline buildout along a more direct path, heading straight from the producing area in Northwest Louisiana (yellow section in Figure 2 below) to LNG demand in the Sabine River area (pink section). Projects like Energy Transfer’s Gulf Run (green line) and DT Midstream’s LEAP (red line) began expanding flows along this route in 2022 and 2023, then last year service began on Williams’s LEG and Momentum Midstream’s NG3 (orange and yellow lines, respectively). We should note that LEAP, LEG and NG3 are all regulated by state entities rather than the Federal Energy Regulatory Commission (FERC) because they are technically long gathering lines rather than traditional pipelines (see Shall We Gather at the River for more). This has helped speed up infrastructure and buildout in the basin and for more projects to move forward. While Louisiana has always had higher production levels than the Texas side of the play, the buildout in Louisiana has emphasized this trend. Haynesville production on the Texas side is down year-on-year, while Louisiana is up more than 2.3 Bcf/d from January 2025. Production on the Texas side was particularly weak when the pipelines began service over the summer but has strengthened this winter. Comparatively, production in Louisiana surged in the back half of last year, but growth has leveled off somewhat. More growth is still expected on both sides of the state line both this year and in the years ahead as LNG export capacity and related feedgas demand continues to grow. Winter Storm Fern led to dramatically lower production from the Permian Basin over the weekend, although the dip was not as catastrophic as what was seen in 2021. Even with the growth in Haynesville production, there is still available capacity on three of the four routes that bring basin volumes down to the Sabine River area. Flows on LEAP (red layer in Figure 3 below) are consistent with or just below the pipeline’s 1.9 Bcf/d capacity, but there is still southbound capacity available on Gulf Run, LEG and NG3. In the case of Gulf Run (green layer), this is because of the delayed startup of Golden Pass LNG on the Texas side of the Sabine River. Golden Pass is the anchor shipper on that pipeline, holding 1.1 Bcf/d of its 1.65 Bcf/d of capacity. While the terminal’s startup will cause more gas to flow south, this won’t necessarily cause an increase in Haynesville production because that gas can also head east on Energy Transfer’s pipelines in northern Louisiana. Data indicates that flows on LEG (orange layer) are around 1.2 Bcf/d and flows on NG3 (yellow layer) are 1.3-1.4 Bcf/d, leaving more than 2 Bcf/d of combined capacity (space between dotted line and stacked layers at right end of chart) on the four pipelines still available. (Because gathering-to-market lines are not FERC regulated, they are not required to report operational data and it is possible that the lines are still ramping up to full capacity.) As Haynesville Shale production has shifted east and outflows have shifted toward the Sabine River, this has, of course, changed the way gas moves into, out of, and around Louisiana. With output down on the Texas side of the basin, less gas is flowing across the state line into Northwest Louisiana. Likewise, as more gas is pulled south, less of it flows to the east. However, strong winter demand in the Southeast and lower inflows from Appalachia began pulling more gas east, across the state, in December. This caused a drop in outflows from Northwest Louisiana to South Louisiana, which had risen as Plaquemines LNG was ramping online. Having spare capacity on multiple routes allows the Haynesville to react to seasonal domestic demand trends, pricing incentives and the specific “where” of LNG export demand. In the short term, that helps the market optimize, but in the long run, LNG demand is expected to grow by more than 14 Bcf/d by the early 2030s. In the face of that astronomical growth, more production and pipeline capacity are needed not only from the Haynesville but from anywhere you can get them.

Deep Freeze Wreaks Havoc on Texas Oil Producers, Refiners - Freeze Has Taken 22% of Natural Gas Production Offline in Southern Central Corridor. A massive winter storm that swept the U.S. over the weekend crippled oil and gas producers and the industrial plants that refine the raw commodities into everything from gasoline to plastics. Refinery flares lit up the Houston Ship Channel late Jan. 25 and into the next morning as a cold front hit the Texas coast and plunged temperatures below freezing. Plants operated by INEOS, Pemex, Shell and LyondellBasell all reported flaring gases, a common safety measure when severe weather causes operational disruptions. Several plants, including Exxon Mobil’s Baytown mega refinery and Goodyear’s Bayport chemicals facility, curtailed operations Jan. 24 ahead of the freeze. The waterway connecting Houston’s refineries to crude imports and global export markets for their products closed Jan. 24 as the cold front approached and partially reopened Jan. 26. Weather-related refinery issues weren’t just contained to East Houston’s industrial corridor. One of INEOS’s plants on the Texas coast was struck by lightning as the winter storm approached the facility, tripping the site off line, according to a regulatory filing. Farther north in Illinois, where refineries are designed to operate in colder temperatures, Phillips 66’s Wood River plant reported a leak in a piping system due to the winter storm, the company said in a community alert. Freezing temperatures also caused issues for the companies pulling oil and gas out of the ground in West Texas. Chevron reported hatches freezing open while Anadarko said severe weather made repairs to a leaking water tank challenging. Filing after filing with the state’s environmental regulator tied operational issues to the severe winter weather disaster declaration issued by Texas Gov. Greg Abbott headed into the storm. The freeze has taken about 22% of natural gas production offline in the southern central U.S. corridor, suggesting crude production is likely down 1 million barrels a day, according to TP ICAP Group Plc energy specialist Scott Shelton. Before the freeze, the U.S. was producing just shy of 14 million barrels of oil daily. In North Dakota, between 80,000 and 110,000 barrels a day of production was offline Jan. 26 due to the cold, unchanged from Jan. 23, according to ND Pipeline Authority. Oil futures traded lower by as much as 0.9% Jan. 26 with gasoline futures leading the petroleum complex down as much as 1.8% on lower industrial and travel demand. Meanwhile, fuels used in heating and electricity generation such as diesel and natural gas surged with heating oil futures up as much as 4.9%.

Fern Freeze-offs Fell Permian Gas Production -Permian natural gas production during the week ended January 26 started out in line with where it has been so far this year, around 21.7 Bcf/d but then dropped dramatically over the weekend because of extremely cold weather and Winter Storm Fern. Temperatures in Midland, Texas plummeted on Friday night, dropping into the low 20s and then falling further from there over the weekend. Sunday night, the low temperature was just below ten degrees, which is extremely low for the area. Temperatures are rising but are expected to remain below the 30-year average for the rest of the week. Production dropped along with the temperatures, with daily production dropping by an estimated 3.1 Bcf/d from Friday to Saturday and then falling further on Sunday. The production decline is starkly visible in the orange line in the chart below. In keeping with the lower production, overall outflows from the Permian were down last week. Outflows to the West dropped by well over 1 Bcf/d over the weekend, from over 2.5 Bcf/d at the beginning of the week to around 1.1 Bcf/d as of Sunday. Outflows to the North were around 2 Bcf/d at the beginning of the week and fell as low as 1.1 Bcf/d on Sunday. Outflows to Mexico averaged 1.7 Bcf/d, up 0.1 Bcf/d week-on-week. Outflows to the East averaged 11.6 Bcf/d, down 1.3 Bcf/d week on-week and dropping as low as 10 Bcf/d on Sunday because of the cold weather.

Texas deep freeze shuts refineries, cuts oil and gas production - A massive winter storm that swept across Texas over the weekend disrupted oil and gas production and forced several Gulf Coast refineries to curtail operations as freezing temperatures settled across the state. Flaring lit up parts of the Houston Ship Channel late Sunday and into Monday morning as Arctic air pushed into Southeast Texas, sending temperatures below freezing and disrupting refinery operations. Facilities operated by INEOS, Pemex, Shell, and LyondellBasell reported the flaring, a standard safety measure used when severe weather interrupts normal production, according to Bloomberg News.Several major facilities took precautionary steps ahead of the freeze. ExxonMobil's Baytown refinery, one of the largest in the country, and Goodyear's Bayport chemical plant curtailed operations Saturday as temperatures fell. The Houston Ship Channel—a critical artery for crude oil imports and exports of refined products—was closed Saturday as the cold front approached and partially reopened Monday morning.The storm's impacts extended beyond Houston's industrial corridor. An INEOS plant along the Texas coast was struck by lightning as the winter storm moved into the area, forcing the facility offline, according to a regulatory filing via Bloomberg.Freezing temperatures also created challenges for oil and gas producers in West Texas. Chevron reported equipment issues caused by frozen hatches, while Anadarko said severe weather complicated repairs to a leaking water tank. Multiple filings with the Texas Commission on Environmental Quality tied the disruptions to the winter storm and a disaster declaration issued by Gov. Greg Abbott ahead of the freeze. The storm forced a significant share of energy production offline across Texas and the surrounding region. About 22 percent of natural gas production in the south-central U.S. corridor was shut in during the freeze, according to estimates from TP ICAP Group Plc. That level of disruption suggests crude oil production may have dropped by roughly 1 million barrels per day. Before the storm, U.S. oil output was nearing 14 million barrels per day.

Big Freeze Disrupts U.S. Oil and Gas Production Winter storm Fern has slashed U.S. oil and gas production as operators curtailed output amid the big freeze. Over the weekend, the storm led to producers losing up to 2 million barrels per day (bpd) of oil production, or about 15% of total U.S. oil output, according to estimates by analysts and traders cited by Reuters.According to estimates by Energy Aspects, the Permian alone saw production outages of around 1.5 million bpd. However, production is already recovering, and the lost output in the Permian is down to some 700,000 bpd. Output is expected to be fully restored by the end of the month.The average monthly impact of the big freeze for the whole month of January could be about 390,000 bpd, mostly due to disruptions in the Permian, independent consultants Rystad Energysaid on Tuesday.The impact should be more limited in other oil regions such as the Bakken in North Dakota, or the Rockies and the Mid-Continent. The maximum downside scenario could feature an additional impact of 273,000 bpd, according to Rystad Energy.In natural gas output, the winter storm led to losses of up to 11% of U.S. production.The total impact on January output, based on Rystad Energy’s initial intelligence of the freeze, suggests that America’s natural gas production would be down by 3.3 billion cubic feet per day (Bcfd) compared to an average of 104 Bcfd for the Lower 48 region expected earlier in January.The Permian would be the main contributor to curtailments in gas output, too, Rystad Energy reckons. There is a potential for an additional 2.3 Bcfd loss for January, primarily driven by a significant curtailment scenario in the Permian similar to Winter Storm Uri in 2021.The cold snap sent U.S. benchmark natural gas prices more than doubling in just one week in the strongest rally since the 1990s. Prices eased on Tuesday morning, following a 117% rally in recent days, as traders turned to profit-taking.

Texas oil, gas and petrochem facilities emitted 1.6 million pounds of regulated pollutants during last week’s icy weather -- As freezing temperatures swept over West Texas last week, leaky pipeline systems in the Permian Basin of West Texas began to suck in air, spoiling their products, risking an explosion and leading operators to release or burn off vast volumes of gas. Chevron, for example, reported 11 large gas releases as it sought to purge oxygen from its tanks, according to filings with the Texas Commission on Environmental Quality. Chevron estimated that it released more than 125,000 pounds of regulated pollutants in incidents during the storm. In some cases, Chevron’s tank hatches “remained frozen open,” allowing gas to vent freely for days at a time. All of the incidents were “directly related to the severe winter weather disaster proclaimed by Texas Gov. Greg Abbott,” the company wrote in its reports. In a statement to Inside Climate News, a Chevron spokesperson said the company followed its “winter weather action plans to enable safe, reliable and sustainable operations,” and that safety is its top priority. At the TCEQ, Texas’ environmental regulator, Abbott’s declaration on Thursday, Jan. 22, activated a policy called “enforcement discretion,” under which authorities could choose to excuse infractions of environmental law, given the circumstance, as long as operators report them diligently. Inside Climate News tallied reports of air emission events reported by industrial facilities—mostly oil, gas and petrochemical operations—posted on the TCEQ’s website. In the month of January prior to the storm, there were an average of 3.4 incidents per day. But in the four days from Jan. 23 to Jan. 26, that rose to a daily average of 14.2. In total, companies estimated that about 1.6 million pounds of regulated pollutants were released during the four days of icy weather, as valves failed, units tripped and pipe connectors began to leak, according to the Inside Climate News analysis. (This figure does not include releases of methane and ethane, which are not regulated and so are not reported.) The TCEQ did not respond to a request for comment. While Texas enacted requirements for power plants to winterize in 2021, following a catastrophic winter storm, the rules don’t apply to gas-processing plants—enormous complexes that refine raw gas before it is piped to power stations, chemical plants and export terminals. “The fix isn’t mysterious,” Metzger said. “Require full weatherization across the entire energy and industrial supply chain, enforce pollution limits during upset events and plan for extreme weather as the new normal.” As the winter storm began to creep over Texas last week, companies in the Permian Basin first detected high oxygen levels in gas early Friday, Jan. 25. Targa Resources, a supplier of petrochemical feedstocks, reported “oxygen levels exceeding the maximum allowable limits” at its Legacy Gas Plant at 5 p.m.“You don’t want high amounts of oxygen anywhere near hydrocarbons,” said an oil and gas consultant who requested anonymity to maintain trust with his clients. “They’re prioritizing safety,” he said, explaining why operators would vent or flare gas when oxygen starts to build up. Oxygen can enter a system during a freeze, he said. Freezing temperatures and moisture affect equipment operation in ways that can lead to the entry of air into systems connected to natural gas feed, or “oxygen ingress.” It’s particularly problematic in regions where infrastructure is not designed to withstand freezing weather conditions. “Most pieces of oil and gas infrastructure in Texas are not designed to handle freezes like this. A lot of things can happen,” In response to high oxygen levels, Targa, an integrated gas conglomerate based in Houston, routed the gas from its Legacy Gas Plant in the Permian Basin to flares to be burnt off for disposal. At 10:30 p.m. Targa measured elevated oxygen at its Greenwood Gas Plant and routed gas to its flares. One hour later, Targa did the same at its nearby Pembrook Compressor Station, then 13 minutes later at its Buffalo Gas Plant, then at its High Plains Gas Plant, then itsGateway Gas Plant.Throughout the weekend, a dozen Targa facilities in west Texas burned off gas for up to 24 hours each. In its reports to TCEQ, Targa estimated its flares collectively emitted more than 240,000 pounds of carbon monoxide and 35,000 pounds of nitrogen oxides. Targa did not respond to a request for comment. Gas giant Energy Transfer, based in Dallas, also reported flaring for up to 24 hours at six of its Permian Basin processing plants due to high oxygen levels with 25,000 pounds of nitrogen oxide emissions. When an Anadarko E&P Onshore tank broke and started leaking in west Texas on Jan. 25, the Woodlands-based company wrote, “We are working to find a crew to repair it today, but weather conditions make it challenging.” The leak remained for 24 hours and released 39,000 pounds of regulated natural gas pollutants, the company reported. The unregulated methane that accompanied those pollutants likely totaled up to 117,000 pounds, according to Permian Basin gas composition data provided by the Environmental Defense Fund. “The oil and gas industry is too fragile to handle the extreme weather,” said Sharon Wilson, founder of the nonprofit Oilfield Witness, who has monitored oilfield emissions for 15 years. “These releases happen during the extreme summer weather, too.” Many emissions are never reported, she said. A certified thermographer with a $100,000 gas imaging camera, she records air pollution events in the Permian Basin. Of all the times she has videoed operators purging gas from pipelines, she said, none ever appeared as reports online. Around midnight Monday, compressors tripped at Deer Park Oil Refinery east of Houston. “Some of the refinery systems suffered freeze-related issues,” it reported. The facility flared gas for 14 hours, releasing an estimated 52,000 pounds of sulfur dioxide.At 1 a.m., a compressor tripped at Equistar Chemicals Channelview Complex, and at 7 a.m. Dow Freeportreported: “Process upset caused by extreme freezing conditions which resulted in off-specification material.” Dow directed the material to its large flare and burned it off for 25 hours.Bayport Polymers’ warning system, on the Houston ship channel, tripped at 11:30 a.m. and routed gas to its ground flare for 48 hours, emitting 190,000 pounds of carbon monoxide, 48,000 pounds of nitrogen oxides, 380 pounds of 1,3-butadiene and 200 pounds of toluene.
In east Texas, at 1:30 p.m., a stuck valve at a VMH gas plant released almost 130,000 pounds of the neurotoxin hexane. Later that night in Port Arthur, on the Louisiana border, acompressor tripped at a Motiva refinery, so the unit’s gas was flared for 18 hours, emitting 230,000 pounds of sulfur dioxide, 12,000 pounds of hexane and 3,200 pounds of isopentane.

US energy sector reels after winter storm knocks out 2 million bpd of crude output (Reuters) - U.S. oil producers lost up to 2 million barrels per day, or up to 15%, of the country's production over the weekend, analysts and traders estimated, as a winter storm swept across the country, straining energy infrastructure and power grids. Oil production outages peaked on Saturday at 2 million bpd, consultancy Energy Aspects estimated, with the Permian Basin likely to have experienced the largest share of that decline at around 1.5 million bpd. Production losses eased on Monday, with Permian shut-ins estimated at about 700,000 bpd and production set to be fully restored by January 30. U.S. oil and gas producer ConocoPhillips' Permian crude production was down by 175,000 bpd as of Sunday owing to frigid weather, according to a source familiar with the matter, who was not authorized to speak on the record. Chevron reported hatches were frozen open during the storm on Sunday in Midland, Texas, according to a regulatory filing. Meanwhile, ExxonMobil was experiencing multiple shut downs in gas compressors across different fields owing to low ambient temperatures, affecting oil production because the gas compression is used to lift the oil, said a source familiar with the matter, who was not authorized to speak on the record. "We closely monitor severe weather conditions and proactively implement necessary safety and operational measures to safeguard our people, maintain infrastructure integrity, and ensure continuity of essential operations," an ExxonMobil spokesperson said. Companies also face third-party takeaway challenges due to hazardous road conditions, specifically regarding water hauling and technician dispatch for repairs, the Texas Oil and Gas Association said in a note. Occidental and Targa Resources were among the two dozen reports of upsets at natural gas processing plants and compressor stations in Texas, according to regulatory filings over the weekend, but that paled in comparison to the more than 200 reported upsets during the first five days of a severe winter storm in 2021, TACenergy analysts said in a note on Monday. Occidental and Targa Resources did not immediately respond to requests for comment. Output in North Dakota, the third-largest oil-producing state, was estimated to be down by around 80,000 to 110,000 bpd as of Monday morning, said Justin Kringstad, director of North Dakota Pipeline Authority. Associated wellhead natural gas production was estimated to be down by 0.24 to 0.33 billion cubic feet per day. U.S. crude futures settled at $60.63 a barrel, down 44 cents. Average gas output in the Lower 48 U.S. states dropped to 106.9 bcfd so far in January, down from a monthly record high of 109.7 bcfd in December, according to LSEG, as producers shut in production. On the refining side, several refineries along the U.S. Gulf Coast reported issues related to the freezing weather over the weekend, including ExxonMobil which shut units at its Baytown, Texas, petrochemical complex on the east side of Houston. Cenovus Energy's 172,000 bpd Lima, Ohio, refinery experienced mechanical issues brought about by the storm on Sunday. A full restart may be delayed until later this week due to extreme cold, industry monitor IIR said. Meanwhile, peak natural gas production losses are estimated to hit around 20 bcfd owing to the storm, according to Rystad Energy. Front-month gas futures closed at their highest since December 2022 on Monday, rising nearly 30% on the day to settle at $6.80 per million British thermal units. Some 810,000 customers across the U.S. remained without power on Monday following the Arctic blast over the weekend that brought heavy snow, sleet and freezing rain from the Ohio Valley and mid-South to New England. Cold temperatures are expected to persist for parts of the country in coming days. The weekend snow and ice storm knocked out power to more than a million homes and businesses along the U.S. Gulf Coast and Southeast, including in Texas. The largest U.S. power grid, PJM, anticipated generation outages for Monday would rise to 22.4 GW, or about 16% of total committed capacity. Most of those outages are expected in Dominion Energy's Mid-Atlantic territory, according to PJM data. Demand on PJM was 124 GW on Monday morning, above the forecast of 123.3 GW, but it continues to meet demand, PJM operations data show. Spot wholesale electricity prices were around $200 per MWh, recovering from temporary spikes over the weekend that topped $3,000 per MWh. Next-day prices in New England soared about 82% to $313 per megawatt hour, while PJM West prices in Pennsylvania and Maryland soared about 360% to around $413, their highest since January 2014. The Southwest Power Pool, meanwhile, which operates the power grid across 14 U.S. states in the Midwest and West, said it extended a cold weather advisory for the region by two days and it will now run until midday Wednesday. It is meant to alert the public about possible disruptions caused by the frigid temperatures, but it does not require homes and businesses to conserve energy.

Ksi Lisims LNG Power Agreement Advances BC’s Natural Gas Export Buildout --The Ksi Lisims LNG project partnership has inked a tentative power agreement key to its plans for delivering natural gas volumes with net-zero emission to Asia by the end of the decade. A Map of British Columbia showing major natural gas pipelines, Montney and Duvernay shale plays, NGI price index locations, and operational, under-construction, and proposed LNG export facilities including LNG Canada, Cedar LNG, Woodfibre LNG, and Coastal GasLink. At A Glance:
BC Hydro to supply 600 MW
Supports 12 Mt/y net-zero LNG project
FID targeted later this summer

U.S. Reopens Venezuela’s Oil Spigot, but Refuses to Guarantee Security - U.S. officials told oil executives on Wednesday that Washington will not provide security guarantees for companies operating in Venezuela, even as the Trump administration encourages the industry to re-engage with the country’s oil sector. According to people familiar with the discussions, senior administration officials said companies would be expected to manage their own physical and political risk if they choose to invest, signaling limits to U.S. involvement as Venezuelan crude re-enters global markets. “We are not going to get involved in providing on the ground security for people in Venezuela,” U.S. Energy Secretary Chris Wright said during an interview with Bloomberg Television. “Oil and gas companies operate all around the world in all different settings, they’re well versed in those challenges.” Years of expropriations, contract rewrites, payment arrears, and operational breakdowns have made boards reluctant to deploy long-cycle capital without firm legal and security assurances. U.S. oil companies have privately warned that without enforceable contracts, clearer fiscal terms, and some form of risk backstop, investment will remain limited, capping how quickly Venezuelan output can recover even under a more permissive U.S. policy framework.Earlier this month, American Petroleum Institute (API) President and CEO Mike Sommers publicly said that policy changes, security, and investment protections were among the prerequisites the industry wants in place before investing significantly in Venezuela’s oil sector. In the near term, Venezuelan barrels are returning to the market not through upstream investment but through discounted trade flows. U.S. refinersincluding Valero and Phillips 66 have snapped up Venezuelan crude via trader Vitol, with cargoes priced roughly $8.50 to $9.50 per barrel below Brent. For Gulf Coast refiners configured to run heavy sour grades, the economics are attractive. Before sanctions in 2019, the region processed hundreds of thousands of barrels per day of Venezuelan crude, and refiners have been eager to partially replace heavier imports lost elsewhere.

Tanker Carrying Venezuelan Heavy Oil Heads To Louisiana -A crude tanker chartered by Trafigura departed on Sunday from Venezuela's Jose port to Louisiana Offshore Oil Port (LOOP), LSEG data and documents showed, the first cargo going directly to the U.S. as part of a 50-million-barrel supply deal agreed this month between Caracas and Washington. This month, trading houses Vitol and Trafigura received the first U.S. licenses to load and export Venezuelan oil as part of the deal. They have since shipped cargoes to storage terminals in the Caribbean, and from there they have been marketing and selling the crude to refiners worldwide. The Liberia-flagged tanker Gloria Maris, carrying some 1 million barrels of Venezuela's Merey heavy crude, is the first sent by the traders directly from Venezuela to a U.S. port since the deal began, according to the documents and data. A smaller tanker, the Barbados-flagged Volans, also departed from Jose on Sunday carrying some 450,000 barrels of Venezuelan crude to the Bullen Bay terminal in Curacao, the LSEG data showed. The traders have shipped between 10 million and 11 million barrels of Venezuelan oil as part of the supply deal so far, according to shipping data. They are getting ready to begin exporting fuel oil as well, according to the sources and documents. Before Venezuela can reverse output cuts it has made during a U.S. blockade of all sanctioned tankers, the country needs to drain most of the over 40 million barrels it accumulated in storage since last month.

Crude Oil Exports Rebound as South Texas Gateway Extends Its Run - Crude oil exports out of the U.S. Gulf Coast (USGC) increased 440 Mb/d to average 4 MMb/d for the week ended January 23, 2026. As mentioned in our Crude Voyager, exports were once again led by the Corpus Christi region, which averaged 2.2 MMb/d and loaded 18 vessels, averaging just above the 4-week moving average. Gibson’s South Texas Gateway (STG) terminal led the region by volume for the second straight week (yellow dashed oval in chart below), again surpassing Enbridge Ingleside Energy Center (EIEC), marking the first time since 2022 that STG has been the dominant terminal in back-to-back weeks. Exports out of STG increased 13% week-on-week to average just under 1 MMb/d. The terminal loaded seven vessels: five Suezmaxes, one Aframax, and one VLCC. Week-to-week volatility in export volumes is not unusual and additional data will be needed to determine whether a sustained trend is taking shape. However, as mentioned previously, STG’s emerging strength coincides with Gibson’s recent completion of a new connection between the STG terminal and Plain's Cactus II Pipeline, which transports crude from the Permian Basin to Corpus Christi. According to Gibson, the connection is designed to improve terminal connectivity and provide up to 700 Mb/d of incremental supply, a development that could support higher and more consistent crude export volumes.

GOP probes climate lawyers for ties to education group for judges - Congressional Republicans are demanding documents from lawyers who work on climate lawsuits against the oil and gas industry as part of an investigation into a legal education organization that provides climate science courses to judges. Two attorneys who have been active in lawsuits against the fossil fuel industry have until Wednesday to deliver materials about their interactions with the Environmental Law Institute to the House Judiciary Committee, according to letters signed by Chair Jim Jordan (R-Ohio) and Rep. Darrell Issa (R-Calif.), who chairs the Subcommittee on Courts.The inquiry comes amid an uptick in cases against the fossil fuel industry brought by more than two dozen local governments seeking to hold oil and gas producers financially accountable for climate change. Michigan last week became the 11th state to file such a suit. The probe also marks a continuing effort by Republicans to target the Environmental Law Institute which came under scrutiny in 2023 after industry and conservative groups raised questions about the organization and the objectivity of judges handling climate lawsuits following a handful of losses at the Supreme Court.

California sues Trump administration over approval of oil pipelines near coast - California sued the Trump administration over its approvals for oil pipelines near the state’s coast amid the White House’s broader push for more drilling there.California is arguing that the Trump administration’s moves to restart the pipelines contravene the state’s authority over the vessels.“In its latest unlawful power grab, the Trump Administration is illegally claiming exclusive federal authority over two of California’s onshore pipelines,” said California Attorney General Rob Bonta in a written statement. “California has seen first-hand the devastating environmental and public health impacts of coastal oil spills — yet the Trump Administration will stop at nothing to evade state regulation which protects against these very disasters,” Bonta said.The pipelines in question are owned by Sable Offshore, which drills off California’s coast.Operating under a different company at the time, the pipelines in question were shut down in 2015 after a spill that flowed into the Pacific Ocean and impacted beaches. The Trump administration has sought to expand offshore drilling, including off California’s coast. It has proposed offering up new leases to allow companies to drill, which would mark the first time in more than three decades that new drilling rights were offered off the state’s coast. The administration told The Associated Press that the approvals “will bring much needed American energy to a state with the highest gas prices in the country.”

Shiver and Suffer – Canada and Ontario Set Single Day Gas Demand Records with Latest Arctic Blast -Winter Storm Fern that swept across the eastern half of North America this past weekend (including most of central and eastern Canada), combined with a brief but intense cold outbreak in Western Canada to establish a new single day Canadian gas demand record on January 24, 2026. Based on data from RBN’s Canadian NatGas Billboard, natural gas demand rose to 19.3 Bcf (blue text and arrow in chart below), surpassing the previous record set less than a year ago on February 18, 2025 of 19.1 Bcf (burgundy text and arrow). The nation’s population-weighted heating degree days (HDDs, a measure of how cold was the weather) for January 24 was the fifth highest since 1900 and the coldest for this date since 1936. When considering Canada’s most populous province of Ontario, it also set a single day gas demand record one day later on January 25, 2026 at 7.54 Bcf (blue text and arrow in chart below), just slightly ahead of the prior record of 7.45 Bcf established on January 21, 2025 (burgundy text and arrow). For the latest record, Ontario’s population-weighted HDDs on January 25 were ranked 16th since 1900. The province has also been trending toward a higher degree of dependence on gas-fired power generation at times of very high demand and which established a single day demand record on January 24, 2026 at 1.74 Bcf, followed by the second highest the next day at 1.59 Bcf.

Dow Will Proceed With Fort Saskatchewan Ethane Cracker Expansion | RBN Energy - Dow, one of the world’s largest petrochemical companies, announced in its fourth quarter earnings conference call on January 29, 2026, that it will proceed with an expansion of its ethane cracker located in Fort Saskatchewan, AB. The expansion, dubbed the Path2Zero project (artist rendition below), originally sanctioned in November 2023 and then placed on hold in April 2025, will more than double the existing cracker’s output of polyethylene and will require a commensurate significant expansion in its consumption of ethane as feedstock (see Shock to the System for further details). The expansion will include additional emission abatement technologies to generate net zero Scope 1 and Scope 2 emissions with a revised estimated total cost of C$10.3 billion (US$7.5 billion, originally US$8.1 billion). In April 2025, Dow announced an indefinite delay to the expansion citing uncertainties in global economic activity and whether it could time the expansion with growth in polyethylene demand. At the time of its prior third quarter earnings release the company stated that it would provide clarity on the expansion in early 2026. The Path2Zero project is planned as a two-stage expansion of the existing Dow ethane cracker that would result in a net increase in its ethane consumption from ~95 Mb/d in 2025 to ~205 Mb/d by 2031 (+110 Mb/d). The first phase is now planned to be in service by year end 2029 (+70 Mb/d), instead of 2027 as originally envisioned, increasing total Alberta ethane consumption to ~342 Mb/d (red column in chart below) in 2030. The second phase is planned to be in service by year end 2030 (+40 Mb/d), a year later than originally planned, and take provincial ethane consumption to a range of ~382 Mb/d (green column) in 2031. Multiple third party projects are in the works across Alberta to increase the province’s output of ethane to accommodate most or all of the increase in ethane demand from the Dow expansion (additional details can be found in Wish You Were Here).

When the US freezes, the global LNG market catches a cold (Reuters) - An Arctic blast sweeping across the U.S. Northeast and Midwest has triggered a sharp rally in natural gas prices on fears of production disruptions. The spike has reverberated across overseas markets, underlining the growing globalization of the U.S.-dominated liquefied natural gas trade. U.S. natural gas futures have surged by almost 70% over the last week to $5.35 per million British thermal units (mmBtu), their highest since December 2022. The cold spell is set to lift domestic gas demand this week to 156 billion cubic feet per day (bcfd), compared with a five-year January average of 137 bcfd, according to LSEG forecasts. At the same time, icy conditions are forcing drillers in regions such as the Permian shale basin in Texas and New Mexico to curb output due to “freeze‑offs,” when water and other liquids in the gas stream freeze. The trend will likely intensify as temperatures drop further. Average gas output in the U.S. has already slipped to 108.4 bcfd so far in January, down from a record 109.7 bcfd in December, LSEG data showed, partly due to the cold weather. Tighter U.S. supply could reduce LNG exports, as liquefaction plants receive less feedgas. Severe cold has curtailed oil and gas production several times in recent years. A 10-day cold spell in January 2024 led to a 3% drop in average monthly dry gas output, according to U.S. Energy Information Administration data. And three years earlier in February 2021, Winter Storm Uri led to a drop of over 20% in gas output at the lowest point compared with pre-storm levels. LNG feedgas fell by as much as 75% during the storm, leading to a 30% drop in February LNG exports that year, according to Kpler. In each of these past Arctic blasts, output generally rebounded within a month or two. But since Uri, the U.S. has nearly doubled its liquefaction capacity, becoming the world's top LNG exporter, meaning a disruption today could create a much larger shortfall.What has changed in recent years is that cold weather conditions in the U.S. can now lead to higher gas prices in Asia and especially Europe, which is heavily dependent on U.S. LNG after Russia slashed pipeline flows following its invasion of Ukraine in 2022. The U.S. has since 2023 dominated the LNG market, becoming the first country to export over 100 million metric tons per year in 2025. Around two-thirds of that was delivered to Europe, according to data analytics firm Kpler. Benchmark European TTF gas prices gained over 6% last week to almost 40 euros per megawatt hour, or $13.75 per mmBtu, the highest since June 2025. Prices have risen by 38% so far this month, driven by a rapid depletion of regional gas stocks, which are currently 48% of capacity, far below last year's level of roughly 58%. Europe is expected to import a record amount of LNG this year, the International Energy Agency said on Friday, with the bulk of the increase expected to come from the U.S. To be sure, the current rally pales in comparison to the post-invasion spike in 2022, when TTF prices quadrupled to more than 300 euros per MWh. Global LNG prices eventually returned to near pre‑invasion levels, helped by surging new supply that is expected to keep prices relatively low in coming years. Between 2025 and 2030, new LNG export capacity is expected to grow some 50%, or by 300 billion cubic meters (bcm) per year globally, driven mainly by the U.S. and Qatar, according to the IEA. Yet, the increasingly interconnected LNG market means that when sudden shifts in supply or demand do occur in major producing areas, whether due to outages or extreme weather, the global impact will be more pronounced than in the past.And, importantly, climate change is likely to make such extreme weather events more frequent."The global gas market has become far more interconnected," "Regardless of their absolute price levels, markets such as TTF and (U.S.) Henry Hub are now structurally more volatile and increasingly exposed to supply, demand, and geopolitical dynamics originating outside their own regions."

Europe’s Gas Storage Is Draining at the Fastest Pace in Five Years | OilPrice.com - Below-average winter temperatures are driving the fastest pace of withdrawals from natural gas storage in Europe in five years, as heating demand is rising.EU gas storage sites were only 47% full as of January 21, according to the latest data from Gas Infrastructure Europe. That’s well below the average for the past few years, signaling that Europe will have to import more gas in the summer to replenish storage supplies. Gas withdrawals have accelerated this month amid colder-than-normal temperatures in most of Europe, and the pace of withdrawals has been the fasters in five years, according to Bloomberg’s estimates.LNG cargo arrivals have been at less than half of the daily volumes withdrawn from storage.The cold weather has driven immediate gas demand higher, while the unfavorable price spread between winter and summer prices is not encouraging for stockpiling.In addition, global gas benchmark prices have jumped in recent weeks as Arctic weather has gripped most of the northern hemisphere, including the United States and Asia.As a result, prices have spiked, making LNG imports costlier for any customer in Europe and Asia. The front-month Dutch TTF Natural Gas Futures, the benchmark for Europe’s gas trading, have jumped by 30% since the start of January, from $34 (29 euros) per megawatt-hour (MWh) on January 2 to as much as $45.40 (38.65 euros) per MWh on January 23.“With heating demand firm and storage withdrawals accelerating, European buyers have been forced to pay up to secure supply,” Ole Hansen, Head of Commodity Strategy at Saxo Bank, saidthis week, noting that the extreme cold has driven a sharp rise in heating demand just as supply flexibility has diminished. Traders have sharply turned bullish on European gas, with funds aggressively buying the market, shifting from a net short of 55.1 TWh to a net long of 57.7 TWh over the last reporting week, Warren Patterson, head of commodities strategy at ING, wrote in a Thursdaynote. “This move was driven fairly equally by short covering and fresh longs entering the market,” Patterson said.

Trump’s trade policy blamed for US gas auction flop in Eastern Europe - — Washington’s ambition to replace Russia as Eastern Europe’s dominant gas supplier has hit a surprise hurdle: European buyers, it seems, don’t want it.On Monday, an auction for contracts to carry American gas along pipelines from Greece to Ukraine, organized by Greece’s national gas network operator, attracted almost zero interest for the second consecutive month.Out of nearly 72 gigawatt-hours of capacity offered across three different entry routes, a minuscule 48 megawatt-hours were eventually booked — less than 0.1 percent of the total. In December’s auction, no one bid at all.The indifference dealt a major blow to Greece’s ambition to become a new European gateway for U.S. liquefied natural gas imports and prompted warnings that President Donald Trump’s unpredictable trade policy is undermining his own energy export ambitions. Greece’s energy minister said U.S.-EU tensions had scared off potential buyers of American LNG.

European gas prices edge higher as US cold limits LNG supply - Dutch and British wholesale gas price rose slightly on Tuesday morning as freezing weather in the United States continued to curb liquefied natural gas exports. The benchmark Dutch front-month contract at the TTF hub was 0.60 higher at €40.30 per megawatt hour, or $14.02, by 09:31 GMT, LSEG data showed. The price reached its highest since April last year on Monday. British day-ahead gas was up 3.70p at 105p per therm while the front-month contract inched up by 0.22p to 103.60p per therm. US gas market developments could continue to be a concern as supply disruptions affect LNG exports. US natural gas futures soared by a record 119 per cent over five days to a three-year high on Monday after an Arctic blast over the weekend boosted heating demand and cut production to a two-year low by freezing oil and gas wells and pipes. LNG feedgas dropped to a one-year low of 12.1 bcfd on Sunday due to reductions at all plants, including Freeport LNG in Texas and Elba Island in Georgia. "In recent days, US LNG plants have significantly reduced their gas intake, estimated to be down around 48 per cent, which will translate into reduced LNG exports from these plants," said analysts at ING. TTF prices continue to trade at a healthy premium to Asian LNG to ensure LNG cargoes move into Europe, where storage has now fallen below 45 per cent full. Last week, at least two LNG tankers that were initially eastbound were diverted towards Europe and Turkey, shiptracking data showed. "It's looking increasingly likely that storage will end the 25/26 heating season at below 25 per cent full. This would also be below the levels seen in 2022," ING said. The market will be watching for how quickly US production recovers in the United States and whether more extreme cold could come next month, analysts at EBW Analytics added. Further out this year, a lot of new LNG supply is expected, mainly from Qatar and the United States. Meanwhile, supply in north-west Europe is stable. Forecasts have been revised colder until February 6 and milder from February 8-18, LSEG data showed. Wind generation in north-west Europe is forecast above normal until at least February 4 before falling below normal and remaining there until at least February 10.

U.S. LNG Export Fluctuations, Severe Winter Weather Propping up Global Natural Gas Prices --European natural gas traders are still eyeing further cold weather and U.S. LNG supply, adding a bullish upside to an otherwise stable global natural gas market.Four-panel NGI chart showing trailing 365-day mean temperatures for Northwest Europe, Beijing, Seoul and Tokyo as of Jan. 26, 2026, with daily mean temperatures in degrees Fahrenheit compared against normal levels, illustrating seasonal warming through mid-2025 followed by cooling into winter across Europe and Asia. Source: NGI calculations, Bloomberg. At A Glance:
TTF prices remain sticky
European storage drops below 45%
U.S. LNG exports to Asia rise

China’s LNG Imports Rise for a Third Straight Month - The recovery in China’s imports of liquefied natural gas is expected to extend for another month in January, Kpler has reported, for a total of three consecutive months of higher LNG imports year-on-year. The analytics provider estimates that China will import 6.94 million tons of LNG this month, as quoted by Bloomberg, which added the amount would represent a respectable 15% increase on January 2025. According to the report, the import increase may suggest more cargoes getting delivered to China under long-term contracts. Over most of last year, China recorded annual declines in its LNG imports, resulting from the U.S. president’s tariff offensive against the world’s biggest energy importer, to which China responded with its own tariffs on LNG, and from rising domestic production. Earlier in the year, domestic gas production hit an all-time high, bringing LNG imports to the lowest in six years, down by 19% on the year over the first seven months of 2025. The decline was partially driven by a record year for gas imports in 2024 as China sought to fill its inventories to be ready for winter. Between November 2024 and October 2025, China recorded 12 straight months of LNG import declines. This trend reversed in November 2025, when the seasonal increase in demand for electricity and heating prompted a tick-up in LNG imports. The November total stood at 6.94 million tons—the same as what Kpler projects for January. That volume represented a 13.6% climb on the year. In December, imports moved higher still, to an estimated 7.17 million tons, per Kpler. LNG imports from Russia specifically hit an all-time high at the end of last year, with the November total at 1.6 million tons, up twofold on October and likely to have continued strong into December and possibly this month as well.

TotalEnergies Restarts Mozambique LNG Work, Adding to Global Supply Wave - TotalEnergies SE and its partners have finally restarted work on the Mozambique LNG project, opening the potential for an even larger jump in global natural gas supply by the end of the decade.Map of the Mozambique LNG Project showing offshore gasfields in Area 1 near Palma and Mocímboa da Praia, including the Golfinho and Atum fields in the Mozambique Channel along the northern coast of Mozambique. At A Glance:
First LNG output targeted 2029
13.1 Mt/y capacity back in play
Improved security underpins project financing

Chevron Says Venezuelan Crude Oil Production Could Jump 50% in 18-24 months --Chevron could increase its crude oil production in Venezuela by up to 50% over the next 18 to 24 months, Chairman and CEO Mike Wirth said during the company’s quarterly earnings call on Friday, January 30. Wirth said Chevron has worked with its Venezuelan partners to increase production by more than 200 Mb/d since 2022, with output now at about 250 Mb/d.Wirth said Chevron remains committed to leveraging its deep expertise and long-standing partnerships in Venezuela. As we noted in Watching the (Oil) Flow, Chevron is the only U.S. company currently producing oil in Venezuela.“There is significant potential in our assets and in the country,” he said. “We’re optimistic the future holds a more competitive and robust pathway to deliver value to Venezuela, the United States and Chevron.”Wirth said Chevron has been bringing about 50 Mb/d of Venezuelan crude to its refinery in Pascagoula, MS, and that it can take another 100 Mb/d into its system, either at Pascagoula or along the West Coast, where it has coking capacity at its refinery in El Segundo, CA. (For more on how U.S. refiners might benefit from additional volumes of Venezuelan crude, see When Love Comes to Town.)"So I think you should expect to see us, assuming it competes against alternatives, to be running more Venezuelan crude in our system over time. In California, it's an interesting situation. We have a very strong downstream position there," he said.

Russia Claims Ownership of Oil Assets It’s Developing in Venezuela - Russia on Tuesday asserted ownership of all oil assets a state Russian company is developing in Venezuela, following the claims of U.S. President Donald Trump that major American and Western oil firms would help revive Venezuela’s oil industry. Russia’s Roszarubezhneft, a state-owned firm that took over Rosneft assets in 2020 following U.S. sanctions on Rosneft’s Venezuelan oil trade, said on Tuesday that “all assets of Roszarubezhneft in Venezuela are owned by the Russian state,” as they have been bought at market prices and conditions.Roszarubezhneft, owned by a unit of the Russian Ministry of Economic Development, was incorporated in 2020. After the U.S. sanctioned two units of Rosneft for trading Venezuelan oil, Roszarubezhneft bought the Venezuelan assets of the Russian state-controlled oil giant Rosneft. "All assets of Roszarubezhneft JSC in Venezuela are the property of the Russian state, having been acquired by the Russian side under market conditions, in full compliance with the legislation of the Bolivarian Republic of Venezuela, international law, and interstate agreements between Russia and Venezuela,” the Russian company said in a statement carried by Russia’s news agency TASS. Roszarubezhneft has five oil-producing joint ventures with Venezuelan state oil firm PDVSA in Venezuela. Roszarubezhneft plans to further develop its assets in Venezuela, the company said. “The company will continue to strictly honor its obligations in close coordination with its international partners, focusing on the sustainable development of joint oil production projects, infrastructure, and an effective response to emerging challenges,” the Russian state-owned firm added. Since the beginning of the year, the U.S. has captured Nicolas Maduro and flown him to New York to stand trial on drug-trafficking charges. The U.S. has also seized a Russia-flagged tanker in the North Atlantic after a dramatic pursuit that began near Venezuelan waters in late December. Russian President Vladimir Putin has not commented in public on the shock arrest of Maduro, but the Russian Foreign Ministry “strongly urged the American leadership” to release Maduro and his wife immediately after their extraction from Venezuela.

Russian Crude Piles Up at Sea as India Steps Back - Russian crude is piling up at sea as India’s refiners step back from purchases, leaving Moscow with millions of barrels on tankers and fewer clear outlets for its oil exports.Russia shipped an average of 3.18 million barrels per day of crude in the four weeks to January 25, according to vessel-tracking data compiled by Bloomberg. That volume was little changed from the prior week but down by about 680,000 bpd from the pre-Christmas peak and the lowest level since August. The bigger issue is not how much Russia is shipping, but where those barrels are ending up. Deliveries of Russian crude into Indian ports fell to about 1.2 million bpd in December, the lowest level in more than three years. Early January data show imports averaging closer to 1.12 million bpd. The pullback coincided with the European Union’s January 21 ban on imports of refined products made from Russian crude, which has complicated trade flows and refinery economics for Indian buyers.As a result, Russian oil is piling up at sea. About 140 million barrels of Russian crude oil are currently being held on seaborne vessels, Bloomberg estimates show, which is a roughly 60-million-barrel increase since late August. Some tankers have been idling off India’s west coast and near Oman. Others have made their way closer to China or diverted to interim destinations such as Port Said or the Suez Canal—many without declaring final discharge points.Some barrels are being offloaded into storage tanks in Indonesia, including sites at Karimun, Balikpapan, and Tanjung Intan, according to tracking data. Even so, only a handful of cargoes have actually discharged, underscoring how limited the available outlets have become.Despite the logistical bottlenecks, Russia’s export revenues have not collapsed. Bloomberg calculations show the gross value of Moscow’s seaborne crude exports edging up to about $920 million per week in the four weeks to January 25, rising 2% from the prior period. Urals crude prices from the Baltic rose to an average of $38.44 a barrel, while Black Sea cargoes rose $0.70 per barrel to average $35.98. Delivered prices into India rose to roughly $56.27 a barrel, the highest in four weeks.The risk for Russia is that tougher enforcement against the shadow fleet and buyer caution could turn floating storage from a buffer into a bottleneck. With India stepping back and China absorbing barrels more selectively, Moscow is exporting oil faster than it can reliably sell it.

India Is Offered Tiny Volume of Venezuelan Oil as Most Goes to U.S. --Offers of Venezuelan crude to India are limited, and in small volumes, as most of the oil under U.S. control is heading to the United States, Indian refining executives told Reuters.Since the U.S. took control of Venezuela’s oil sales and authorized two of the world’s biggest independent traders, Vitol and Trafigura, to market the crude, Indian refiners have vied for crude from Venezuela as they seek to diversify the large exposure to Russian crude they had amassed over the past three and a half years.Indian Oil Corporation, Hindustan Petroleum Cor p (HPCL), Mangalore Refinery and Petrochemicals Ltd (MRPL), and Reliance Industries have been willing to buy crude from Venezuela since the U.S. said it would sell Venezuela’s oil. But the Indian refiners haven’t been top of the list of potential buyers for Vitol and Trafigura.“Offers are not there. Traders are looking to meet their commitment to the U.S. market,” an anonymous executive told Reuters.All Indian refiners have said they would comply with the U.S. sanctions on Rosneft and Lukoil, and Russian supply to India has now plunged to a three-year low.As a result, Indian refiners have scoured the globe for supply and have sourced more crude from the Middle East, West Africa, and the Americas to replace part of the lost Russian barrels.Meanwhile, Vitol and Trafigura have sold Venezuelan crude to U.S. refiners Valero and Phillips 66, as well as to Spain’s Repsol, and to the Saras refinery in Italy owned by Vitol.At the request of the US government, Trafigura and Vitol are providing logistical and marketing services to facilitate the sale of Venezuelan oil, Trafigura said early this month, following a meeting of oil industry executives with U.S. President Donald Trump at the White House. Since then, Vitol and Trafigura havestarted offering Venezuelan crude to refiners in China and India for March delivery, but U.S. customers are a priority for the sales of the oil under U.S. control.

Canada Looks to Boost Energy Exports to India in Strategy Reset -Canada’s efforts to diversify its energy exports away from the United States go through boosting sales oil, gas, and uranium to the major energy market India, Canadian Energy Minister Tim Hodgson said at a conference in India on Tuesday.Canada has the opportunity to work with India now that it sees its high dependence on the U.S. market as a “strategic blunder,” the minister told the Indian Energy Week conference in Goa today, as carried by Reuters.“If Canada wants to be an energy superpower, we need to be trading our energy and natural resources with one of the world’s largest energy markets: India,” Hodgson posted on X, referring to the Canadian government’s goal to make the country an energy superpower.“That’s why, this week, I’m in India for trip of firsts: Canada’s first federal ministerial presence at India Energy Week and the first Canada–India energy dialogue in eight years,” the Canadian minister added.“As major projects are being built at home, we’re building relationships abroad that will allow us to sell our products worldwide and carve out a new path for a stronger, more sovereign Canada,” Hodgson concluded.Canada does not export LNG to India currently, after launching last year its first-ever export project, LNG Canada.But apparently Canada wants to boost exports to Asia from its West Coast, and India, which will drive global oil and gas demand in the foreseeable future, is a key export target. “We're now building pipelines to the West Coast. We have three pipelines built here, looking at building more,” Hodgson said at the Indian forum on Tuesday.Canada has just signed a major energy and trade partnership with China, as it moves away from hostilities from the Trump Administration.Now Canada and India are expected to pledge more Canadian exports of crude, LNG, and LPG to India, and more Indian fuel exports to Canada, according to a draft joint statement on energy seen by Bloomberg News.

Yeosu Coast Guard Detects Pollutant Spill at Sapo Pier 1 – 아시아경제 -- The Yeosu Coast Guard in South Jeolla Province announced on January 19 that it had apprehended Vessel A (4,688 tons) on charges including violations of the Marine Environment Management Act while it was engaged in cargo loading and unloading operations at Yeosu Sapo Pier 1. According to the Yeosu Coast Guard, at around 3:01 p.m. on January 18, they received a report that hydraulic oil had leaked into the sea from Vessel A, which was moored at Sapo Pier 1. Upon arriving at the scene, they confirmed the presence of a yellow oil slick near the vessel. An investigation revealed that approximately 48 liters of hydraulic oil had been discharged into the sea after an unidentified rupture occurred in the hydraulic pipe of Vessel A. The Yeosu Coast Guard immediately deployed two response vessels and three private response ships to carry out containment and cleanup operations around Vessel A. Samples from the sea and the vessel are currently being collected and analyzed to determine the exact cause of the incident. Under relevant laws, discharging oil or other pollutants into the sea may result in imprisonment for up to five years or a fine of up to 50 million won. A Yeosu Coast Guard official stated, "Oil spill incidents from vessels can cause severe damage to the marine environment. We will continue to do our utmost to prevent marine pollution accidents in advance and maintain a clean sea through prompt and accurate response as well as ongoing monitoring and enforcement."

OPEC+ Set to Maintain Oil Output Despite Oversupply Fears -OPEC+ is expected to hold oil production flat in March and reiterate the first-quarter pause in supply hikes when the group meets on February 1 to discuss output levels, four delegates from the alliance told Bloomberg on Monday. The group has not yet held discussions ahead of next Sunday’s online meeting, but it does not see any need of changing the policy despite the expected oversupply and the geopolitical developments that could influence supply from OPEC members Iran and Venezuela.Early this month, the eight OPEC+ members that have been implementing cuts since 2023 – Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman – reaffirmed the decision to pause monthly increments during the first quarter of the year. The decision was first taken in November 2025 and was confirmed at two consecutive meetings in December and January.There is no indication that the February meeting would change that course, according to the OPEC+ delegates who spoke to Bloomberg.The group will likely wait out the first quarter of the year, typically the weakest quarter for demand of any year, and see how supply could be affected – if at all – from the geopolitical flare-ups in recent weeks. These include, so far, the new oil order in Venezuela, the situation in Iran, and the pace of Russian supply amid the U.S. sanctions on top producers Rosneft and Lukoil and the EU ban on imports of oil products processed from Russian crude.Last week, Amin Nasser, chief executive of Saudi oil giant Aramco, dismissed the glut narrative saying that forecasts of a massive oil glut are seriously exaggerated as demand keeps rising and global stocks are below the five-year average.Global oil stocks are low, while the amassed barrels in floating storage on tankers are mostly sanctioned supplies, the CEO of the world’s biggest oil firm and top crude exporter said on the sidelines of the World Economic Forum in Davos, Switzerland.

US-Iran flare-up, cold stint push oil prices to multi-month peak --Oil prices edged higher on Monday, 26, as traders reacted to fresh signs of weather-related supply losses in the US. “President Trump’s declaration of a US armada sailing toward Iran has reignited supply disruption fears, adding a risk premium to crude prices and supported risk-aversion flows more broadly this morning,” Tensions between Washington and Tehran underpinned the premium. US President Donald Trump said on Thursday that “The United States has a fleet heading toward Iran," but hopes he "will not have to use it." A senior Iranian official warned Friday that Tehran would regard any attack as “an all-out war.” JPMorgan analysts estimated that winter storm Fern cut US oil production by roughly 250,000 barrels per day, disrupting flows from the Bakken and from fields in Oklahoma and Texas. “Oil prices are influenced this week by signs of production disruptions in the US,” said Priyanka Sachdeva, senior market analyst at Phillip Nova PTE Ltd, according to Investor.bg. Taders still assessed a broader surplus despite the weather-driven rally, adding that the market appeared unlikely to tighten without deeper cuts from OPEC+ or other major producers. Prices had already been near multi-month highs at the end of last week. Brent settled Friday at 64.41 dollars and WTI at 60.31 dollars, modestly higher week on week. Analysts projected that WTI would likely hover in the high-50 dollar range and Brent in the low-60s, with any weather-driven spikes expected to fade quickly. FX Empire observed that rising geopolitical risks—from Iran, Venezuela, and strains between Saudi Arabia and the UAE—kept a risk premium in energy markets. A memo from DNB Carnegie said Brent prices firmed after Trump’s comments on Iran, as traders reduced short positions. Political uncertainty in Venezuela also a factor Political uncertainty in Venezuela also weighed on sentiment. The White House allowed Venezuelan barrels to flow to China, “but not at unfair, undercut prices." The International Energy Agency raised its 2026 oil-demand growth outlook by 70,000 barrels per day to 930,000 barrels, citing a weaker oversupply outlook and an improving global economy. Russian-related flows remained under scrutiny. India’s Reliance Industries would resume buying “sanctions-compliant” Russian crude after a month-long pause, leaving its 2025 average intake near 540,000 barrels per day. In the Mediterranean, the French navy intercepted a tanker carrying Russian oil in what Paris called a lawful operation, the same outlet reported. With winter storms curbing North American output, naval deployments unsettling the Gulf, and policy moves reshaping Venezuelan production, traders balanced immediate supply threats against weak structural fundamentals for 2026.

Oil Prices Edge Higher As Brent Climbs Above $65 Amid Geopolitical Tensions -Crude oil prices recorded modest gains at the start of the trading week, reflecting heightened geopolitical concerns in the Middle East and lingering uncertainty surrounding United States trade policy. In international markets on Monday, Brent crude, the global benchmark, traded above the $65 mark, while US West Texas Intermediate (WTI) also posted gains, supported by rising risk sentiment linked to escalating US-Iran tensions. Brent crude was priced at $65.49 per barrel, representing a slight increase from the previous session’s close of $65.40. Meanwhile, WTI crude advanced to $61.40 per barrel, up from $61.20 in the prior trading session. Market analysts attributed the price movement largely to growing security concerns in the Middle East, following high-level military engagements between the United States and Israel. US Central Command (CENTCOM) chief, General Brad Cooper, recently held extended discussions with Israeli military Chief of Staff, Lieutenant General Eyal Zamir, during an official visit to Israel. According to the Israeli military, the meeting included both private consultations and broader discussions with senior defence officials, focusing on strengthening operational coordination and strategic cooperation between the two allies. Cooper is also expected to hold talks with Israeli Air Force Commander, Major General Tomer Bar, as part of the visit. The diplomatic and military engagements come amid heightened anxiety in Israel over the possibility of a preemptive strike by Iran, while the United States continues to reinforce its military presence across the region in response to rising tensions with Tehran. Beyond geopolitics, oil markets are also navigating uncertainty linked to US trade policy. Investors remain cautious as President Donald Trump’s position on Greenland continues to attract global attention. Although the US administration has stepped back from immediate tariff actions, unresolved negotiations and policy ambiguity have weighed on broader market sentiment. Despite the current price uptick, traders are exercising restraint due to concerns over the medium- to long-term supply outlook. Robust output growth from non-OPEC oil-producing nations has reinforced expectations that global crude markets could slide into surplus later in the year if supply growth continues to exceed demand expansion. Energy analysts note that increased production from the United States and other non-OPEC producers could limit further upside in prices, even as geopolitical risks remain elevated. Attention is also turning to monetary policy developments in the United States. Investors are closely watching the Federal Reserve’s policy meeting scheduled for this week, with markets broadly anticipating that interest rates will remain unchanged. However, futures pricing suggests growing expectations that the Fed could begin cutting rates as early as June, a move that could influence commodity prices by weakening the US dollar and stimulating demand for risk assets, including oil. For now, oil prices remain caught between geopolitical risk premiums and concerns about oversupply, leaving markets sensitive to both political developments and macroeconomic signals in the days ahead.

Oil Market Slips as Winter Storm Supply Risks Begin to Ease - The crude oil market gave up its early gains and ended the session lower as traders assessed the impact on output in U.S. crude producing regions from winter storms and the impact of any tensions between the U.S. and Iran following U.S. President Donald Trump’s renewed warning to Iran last week. The oil market was underpinned by the freeze-offs due to the winter storm that swept across the country over the weekend. According to Energy Aspects, oil production outages peaked on Saturday and production losses eased on Monday, with Permian shut-ins estimated at about 700,000 bpd and production set to be fully restored by January 30th. The market traded to a high of $61.71 in overnight trading. However, it gave up some of its gains amid the expectations that the shut in output would be restored by the end of the week. The market later erased its gains and sold off to a low of $60.32 ahead of the close. The March WTI contract settled down 44 cents at $60.63 and the March Brent contract settled down 29 cents at $65.59. The product markets ended the session in mixed territory, with the heating oil market settling up 13.95 cents at $2.5680 amid the winter storm and colder temperatures expected over the next week, and the RB market settling down 3.09 cents at $1.8201. Analysts and traders estimated that U.S. oil producers lost up to 2 million bpd or about 15% of national production over the weekend, as a winter storm moved across the country, straining energy infrastructure and power grids. Consultancy Energy Aspects estimated that oil production outages peaked on Saturday, with the Permian Basin likely to have experienced the largest share of that decline at around 1.5 million bpd. Production losses eased on Monday, with Permian shut-ins estimated at about 700,000 bpd and production set to be fully restored by January 30th. IIR Energy reported that U.S. oil refiners are expected to shut in about 1.14 million bpd of capacity in the week ending January 30th, cutting available refining capacity by 27,000 bpd. A malfunction triggered flaring in the East Plant of Citgo Petroleum’s 165,000 bpd Corpus Christi, Texas refinery. A community warning notice did not say which units were affected by the malfunction and if it was related to the unusually cold weather that descended to the Gulf Coast of Texas overnight. On Saturday, Exxon Mobil Corp said it was idling units at its 564,440 bpd Baytown, Texas crude oil refining and petrochemical complex due to freezing weather expected over the next three days. Pemex reported work activities that may cause flaring at its 312,500 bpd Deer Park, Texas refinery. Delek’s 73,000 bpd Big Spring, Texas refinery reported emissions caused by process equipment faults due to extreme low ambient temperatures. Cenovus Energy’s 172,000 bpd Lima, Ohio refinery experienced mechanical issues brought about by the winter storm. Calumet Specialty Products’ 60,000 bpd Shreveport, Louisiana refinery suffered from winter storm-related issues.

Oil Edges Lower As Kazakhstan Reports Progress In Restoring Oil Production (RTTNews) Oil prices traded lower on Tuesday amid easing disruptions to Kazakhstan's oil exports after a Black Sea terminal was brought back into service. Investors also watched ongoing U.S.-Iran tensions and supply disruptions stemming from extreme weather in the United States. Benchmark Brent crude futures dipped 0.3 percent to $64.58 per barrel while WTI crude futures were down 0.2 percent at $60.52. Kazakhstan signaled that it would resume production from the Tengiz oil field, its largest oil producing facility, helping traders pare back expectations of tighter supplies. Kazakhstan's Ministry of Energy has reported significant progress in restoring production operations at oilfields in the Atyrau region, following disruptions earlier this month. Elsewhere, a winter storm and ensuing Arctic blast have claimed at least 34 lives across multiple U.S. states. Extreme cold has left nearly 540000 people without power and knocked an estimated 12 percent of U.S. natural gas production off-line. In Iran, foreign ministry spokesman Esmail Baqaei has warned that the Islamic Republic is fully prepared to deliver a "sweeping, regret-inducing response" to any act of aggression. "The notion of carrying out a so-called limited, rapid and clean operation against Iran stems from incorrect assessments and an incomplete understanding of the defensive and offensive capabilities of the Islamic Republic," the unnamed official said, as reported by Iran International citing Mehr News Agency.

Crude Rallies on Weather Disruptions and Fresh Geopolitical Nerves --Oil prices jumped on Tuesday as the market priced in fundamentals once again, showing that when U.S. infrastructure gets punched in the face by weather, it’s more than geopolitics and vague supply forecasts that move the needle. Brent was trading around $66.90 a barrel on Tuesday late morning, up about $1.30 on the day. At the time, WTI neared $61.90. By afternoon, the gains continued, with Brent passing $67 and WTI nearing $62. The continued rise means it could be more than just a recovery from an earlier dip. It may be recalculating near-term supply risk. The immediate spark was the winter storm that clipped U.S. production and snarled Gulf Coast logistics. Analysts and traders estimated that as much as 2 million barrels per day (bpd) of production went offline over the weekend amid severe weather. Crude export flows from Gulf Coast ports even hit zero on Sunday before bouncing back as channels reopened, analysts estimated. Exports have become the pressure-release valve for the U.S. system, and when the valve shuts, even briefly, U.S. supply stops being seen as infinitely flexible. But the rally wasn’t just a weather headline. A second, cleaner catalyst is that the global supply backdrop is already tight enough that any disruption looks bigger. Kazakhstan’s Tengiz field is recovering more slowly than expected after a fire and power outage, with less than half of normal production restored heading into early February, per Reuters reporting. Layer on a softer U.S. dollar, and crude gets an extra shove higher on the screen. Then there’s the ever-present geopolitical bid. U.S. naval assets moving into the Middle East doesn’t guarantee anything happens, but it does raise the “things could get messy” premium, especially with Iran in the frame and no clean progress on the Russia-Ukraine front.

Oil Market Rallies on U.S. Storm-Related Output Losses and Geopolitical Risk -The crude market posted an outside trading session on Tuesday as the market weighed a loss of U.S. oil production after a severe winter storm swept across the country and geopolitical risks against a resumption of supply from Kazakhstan. The market breached its previous low and sold off to a low of $60.14 in overnight trading amid the expectations that Kazakhstan will resume production from its largest oilfield, Tengiz, and the CPC, which operates Kazakhstan’s main exporting pipeline, also said it returned to full loading capacity at its terminal on the Russian Black Sea coast following the completion of maintenance of one of its three mooring points. However, the market’s losses were limited by the loss of oil output in the U.S. due to the winter storm over the weekend. Also, on the geopolitical front, two U.S. officials said a U.S. aircraft carrier and supporting warships arrived in the Middle East, expanding the U.S. capabilities to defend U.S. forces or potentially take military action against Iran. The crude market rallied to a high of $62.37 ahead of the close. The March WTI contract settled up $1.76 at $62.39 and posted a new high of $62.58 in the post settlement period. Meanwhile, the March Brent contract settled up $1.98 at $67.57. The product markets also ended the session sharply higher, with the heating oil market settling up 7.82 cents at $2.6462 and the RB market settling up 4.51 cents at $1.8652. Vortexa said exports of crude oil and liquefied natural gas from U.S. Gulf Coast ports fell to zero on Sunday, after a winter storm swept across the country. According to some analyst forecasts, up to 2 million bpd of oil production went offline over the weekend due to the frigid weather. Exports of liquefied petroleum gas, such as propane and butane, were down to about a third of seasonal norms due to the storm. Exports rebounded on Monday with flows coming in above seasonal norms, as ports reopened.Abu Dhabi National Oil Company’s Managing Director and CEO, Sultan Ahmed Al Jaber, said global oil demand will remain above 100 million bpd through 2040, while demand for both liquefied natural gas and electricity will increase by 50% or more. He said that electricity demand will be driven by the need to power cooling systems as well as AI infrastructure and data centers.Reuters reported that China’s storage flows surge in December, resulting in a surplus of more than 1 million bpd for 2025. China’s surplus of crude oil increased to 2.67 million bpd in December, up from 1.88 million bpd in November and the most since the 2.27 million bpd seen in June 2020. According to calculations based on official data, for 2025 the volume of surplus crude was 1.13 million bpd, largely steady from the 1.15 million bpd seen in 2024. December’s crude imports increased to a record 13.18 million bpd, up 17% from the same month in 2024, with the strong arrivals taking imports for the full year to 11.55 million bpd, another all-time record and up 4.4% from the prior year.Sources stated that U.S. officials are working to issue a general license soon that would lift some sanctions on Venezuela’s energy sector, a shift from a previous plan to grant individual exemptions to sanctions for companies seeking to do business in the country.

WTI at $62, USD Hits 4-Year Low; NatGas Dips as Storm Eases-- Crude futures jumped 3% Tuesday as a four-year low in the dollar drove energy markets, other than natural gas, higher. Geopolitical tensions also boosted oil as U.S. President Donald Trump pressed Iran for a nuclear disarmament deal while a fleet of U.S. warships sat in Middle East waters. The U.S. Dollar Index sank to 95.97 against a basket of currencies, its lowest since February 2022, ahead of the Federal Reserve's decision on U.S. interest rates due after a two-day policy meeting that ends Wednesday. While some on Wall Street anticipate that the Fed might deliver a 25-basis point cut for a fourth consecutive time since September, the broad expectation is for the central bank to leave rates unchanged in a 3.5%–3.75% range. President Trump said he understood Iran was prepared to make a nuclear deal with the White House as a U.S. Navy armada resided in the Middle East. Tehran said it welcomed talks but was also prepared for war in the event of a U.S. strike. WTI crude futures for March delivery settled up $1.76, or 2.9%, at $62.39 bbl, while ICE Brent crude for March delivery closed up $1.98, or 3%, at $67.57 bbl. Among refined products, NYMEX RBOB futures for February rose $0.0425 to $1.8626 gallon. Front month ULSD futures were up $0.0727 to $2.6407 gallon, after hitting a seven-month high of $2.6482 earlier in the session. Natural gas retreated from Monday's peaks after the worst of the weekend's Winter Storm, although frigid temperatures remained in the Northeast to Mid-Atlantic, keeping intact demand for heating oil, a proxy for ULSD. Natural gas for March delivery fell $0.093 to $3.805 MMBtu after the prior session's one-week high of $3.997. U.S. crude output and inventories of oil to fuel could see untoward moves in the coming weeks from production shut-ins and the impact to refineries from Storm Fern. Analysts at Energy Aspects estimate that 1.5 million bpd of Permian output was sidelined by the storm. The American Petroleum Institute will release after 4:30 p.m. EST today inventory data for the week ended Jan. 23. The Energy Information Administration will report numbers for the same period at 10:30 a.m. EST on Wednesday. Swings in API and EIA data in the aftermath of Storm Fern could cause a recalibration of oil supply demand in the near term. However, the larger focus will be on global oversupply, particularly as Kazakhstan has returned to full production after earlier outages.

Oil prices rise as US cold snap disrupts supply, dollar weakness supports crude --Oil prices extended gains in Asian trade on Wednesday, supported by supply disruptions caused by extreme winter weather across the United States and continued weakness in the US dollar, which boosted demand for dollar-denominated commodities. Brent crude futures for March rose 0.1% to $67.66 a barrel, hovering near a four-month high, while West Texas Intermediate (WTI) crude gained 0.2% to $62.53 a barrel by 20:49 ET (01:49 GMT). Crude prices have rallied this week after a severe winter storm swept through large parts of the United States, disrupting oil production and halting exports from the US Gulf Coast. Heavy snowfall and sub-zero temperatures forced multiple production sites offline, tightening near-term supply. According to estimates cited by Reuters, around 2 million barrels per day of oil production was affected over the weekend. The disruption has prompted traders to position for sharp drawdowns in US crude inventories in the coming weeks, signalling a tighter supply outlook in the world’s largest fuel-consuming nation. Further supporting prices, data released by the American Petroleum Institute (API) showed US crude inventories fell by 0.25 million barrels last week, against market expectations of a 1.45 million-barrel build. API data often serves as an early indicator for official US inventory figures, which are scheduled to be released later on Wednesday. Oil prices also benefited from a sharp decline in the US dollar, which slid to a near four-year low earlier this week. A weaker dollar typically supports crude prices by making commodities cheaper for holders of other currencies. Investors remained cautious ahead of the US Federal Reserve’s policy decision later in the day. While the Federal Reserve is widely expected to keep interest rates unchanged, markets are closely watching Chair Jerome Powell’s guidance on the outlook for monetary policy amid ongoing economic and geopolitical uncertainty.

WTI Holds Gains After Winter Storm Sparks Biggest Total Inventory Draw Since October -Oil prices hit a fresh four-month high this morning after President Trump threatened another attack on Iran, urging Tehran to negotiate a nuclear deal. “Hopefully Iran will quickly ‘Come to the Table’ and negotiate a fair and equitable deal,” Trump said in a post on his Truth Social network, adding that “the next attack will be far worse!” than the one that took place last year. Prices pared gains somewhat after Iran’s mission to the UN repeated in a post on X that it stands ready for dialogue based on mutual respect and interests, but said it will “defend itself and respond like never before,” to US aggression.API

• Crude -247k
• Cushing -92k
• Gasoline -415k
• Distillates +2.01mm

DOE

• Crude -2.295mm (+1.95mm exp)
• Cushing -278k
• Gasoline +223k
• Distillates +329k

Total crude and fuel stockpiles fell last week for the first time since early December led by a surprise crude draw (bigger than the small one reported by API)... (Graphics Source: Bloomberg) Bloomberg reports that the 6 million barrel draw (which was the biggest since October) was led by a decline in crude inventories and also the biggest drop in propane inventories since early last year ahead of the big freeze. Crude production fell to 13.7 million barrels a day last week, down by 36,000 barrels a day from the previous week. The drop may reflect the initial impact of the winter storm that hit the US in recent days and came as the number of rigs drilling for oil edged higher for a second week, with 1 unit put into operation last week, according to Baker Hughes.WTI is holding on to early gains after the surprise draw...Finally, circling back to the start, the potential risk to Iranian supplies has injected a premium into oil prices and led futures to start the year on a strong footing, up more than 10% this month, despite forecasts for a glut. That has also kept the cost of bullish options high relative to bearish ones.“Market sentiment appears to be gradually turning more positive, as the bearish oversupply narrative so prevalent in the second half of 2025 weakens,” Standard Chartered analysts including Emily Ashford wrote in a note.“We envisage an uptick in volatility and increasing focus on both supply and demand risks.”The prompt spread for both oil benchmarks — the difference between their two nearest contracts — has widened in a bullish backwardation structure over the course of this month, indicating tighter supply.

Oil Futures Hit 4-Month High on Weak USD and Weekly Crude Draw (DTN) -- Crude futures settled near four-month highs Wednesday, Jan. 28, propelled by a U.S. weak dollar and geopolitical tensions amplified by concerns over a potential U.S. military strike on Iran. The first U.S. crude inventory decline in three weeks, reported by the Energy Information Administration, also boosted oil. Futures of gasoline edged higher while those for distillates dipped after the EIA cited inventory builds in both. The U.S. Dollar Index was up by 0.44 points to 96.475 against a basket of currencies after the Federal Reserve left benchmark U.S. interest rates unchanged in a 3.5%-3.75% range following a two-day policy meeting. Earlier in the day, the dollar hit a four-year low of 95.705, pressured by declines over four prior sessions. The U.S. currency has lost 5% of its value from its December peak in the aftermath of U.S. trade disputes and coordinated yen interventions by global central banks diversifying their dollar reserves into gold. Geopolitical risks remained elevated as U.S. President Donald Trump continued to press Iran to make a nuclear disarmament deal with the United States or face the risk of war, as an armada of U.S. warships took positions in the Middle East. Despite Trump's warnings, Saudi Arabia and the United Arab Emirates said they will not allow their airspace or land to be used in any attack on Iran, effectively mitigating some of the risks facing the OPEC member and oil markets. According to OPEC, Iran consistently produces about 3.2 million. The Strait of Hormuz that straddles the Islamic republic also provides passage to roughly 20 million bpd of crude oil and petroleum products transit equivalent to 20% of the world's total liquid fuel consumption, the EIA says. On the U.S. inventory front, the EIA said commercial crude stocks dropped by 2.3 million bbl to 423.8 million during the week ended Jan. 23, after back-to-back weekly builds of 3.6 million and 3.3 million bbl. Gasoline inventories rose for a 12th straight week, rising by 200,000 bbl to 257.2 million. Distillate balances climbed by 300,000 bbl to 132.9 million. NYMEX WTI for March delivery settled up $0.82, or 1.3%, at $63.21 bbl, after a four-month high at $63.52. The ICE Brent contract for March finished up $0.83, or 1.3%, at $68.31 bbl after peaking at $68.53 earlier -- its highest since September. Downstream, the NYMEX RBOB futures crude contract for February delivery rose by $0.0267 to $1.8919 gallon, while front-month ULSD futures edged down by $0.0278 to $2.6184 gallon.

Tensions between US and Iran fuel oil price surge, Brent rises by 1.5% -Rising tensions between the US and Iran have pushed oil prices up, with Brent crude gaining 1.5% and WTI rising 1.7%, amid concerns over Middle East supply disruptions. Tensions between the United States and Iran have escalated once again, with US President Donald Trump warning Iran that if it continues to reject nuclear talks, the next US military response would be "stronger than before." The situation has sent ripples through global markets, including a significant spike in oil prices as concerns grow over potential disruptions to Middle East supplies. On January 29, 2026, Trump made it clear in a social media post that Iran must return to the negotiating table for a "fair and just" nuclear deal under conditions of no nuclear weapons. His comments are part of a broader diplomatic and military strategy aimed at exerting more pressure on Iran, whose military tensions and regional influence have been rising. In response to the growing conflict, Trump revealed that USS Abraham Lincoln, a US aircraft carrier, is heading closer to Iran. This follows the relocation of the ship from the Asia-Pacific region to the Middle East amid rising geopolitical tensions. Meanwhile, analysts also anticipate that the tensions could spill into greater economic instability, particularly as oil prices responded immediately. On January 29, oil prices surged for the third consecutive day, with Brent crude climbing by 1.5% and WTI rising by 1.7%. This increase is largely driven by concerns that any potential conflict could disrupt oil supply routes in the region, especially as Iran is a major producer within OPEC, producing roughly 3.2 million barrels per day. Geopolitical risk, combined with supply-side issues like the unexpected drop in US crude stockpiles by 2.3 million barrels, has also pushed prices higher. Some analysts have warned that continued escalation could drive Brent oil to as high as $72 per barrel if the tensions continue to escalate. At the heart of the escalating geopolitical risks is not just the military threats but also the economic power of oil-producing nations. The Middle East continues to be a critical hub for the global energy market, and any instability can have long-lasting ripple effects on the global economy. As the US-Iran standoff intensifies, all eyes will be on whether oil prices continue to climb and how this situation affects the broader stability of the global energy markets, especially as nations like Saudi Arabia, Qatar, and Egypt express concern that escalating conflict could lead to missile or drone strikes, potentially threatening critical energy transport routes like the Strait of Hormuz. In conclusion, the ongoing diplomatic and military tensions between the US and Iran could push oil prices even higher, with analysts projecting that the geopolitical uncertainty may lead to further price increases in the near future.

Oil prices surge 4 percent to five-month high on worries US could take action against Iran - Oil prices climbed about 4 percent to a five-month high on Thursday on rising concerns that global supplies could be disrupted if the US decides to attack Iran, one of OPEC's biggest crude producers. Brent futures rose (US)$2.50, or 3.7 percent, to (US)$70.90 a barrel, while Us West Texas Intermediate (WTI) gained (US)$2.35, or 3.7 percent, to (US)$65.56. That pushed both crude benchmarks into technically overbought territory and put Brent on track for its highest close since July 31 and WTI on track for its highest close since September 26. US President Donald Trump is weighing options against Iran that include targeted strikes on security forces and leaders to inspire protesters, multiple sources said, even as Israeli and Arab officials said air power alone would not topple Tehran's clerical rulers. In Iran, meanwhile, plainclothes security forces have rounded up thousands of people in a campaign of mass arrests and intimidation to deter further protests. Two US sources familiar with the discussions said Trump wanted to create conditions for "regime change" after a crackdown crushed a nationwide protest movement earlier this month, killing thousands of people. "The immediate (market) concern... is the collateral damage done if Iran takes a swing at its neighbours or possibly even more tellingly, it closes the Strait of Hormuz to the 20 million barrels per day of oil that navigates it," said PVM analyst John Evans. Iran was the third-biggest crude producer in the Organization of the Petroleum Exporting Countries (OPEC) behind Saudi Arabia and Iraq, according to US Energy Information Administration (EIA) data. European Union foreign ministers, meanwhile, adopted new sanctions on Iran on Thursday targeting individuals and entities involved in a violent crackdown on protesters. Separately, the EU designated Iran's Revolutionary Guards as a terrorist organization. "The potential for Iran getting hit has escalated the geopolitical premium of oil prices," Citi analysts said in a note. The Kremlin said on Thursday that Russia had reiterated its invitation or Ukrainian President Volodymyr Zelenskiy to come to Moscow for peace talks, as US-led efforts to reach a deal to end the nearly four-year war in Ukraine intensify. Any peace deal that would allow Russia to export more oil should increase global supplies and decrease energy prices. Russia is the third-biggest crude producer in the world after the US and Saudi Arabia, according to EIA data. US private equity firm Carlyle Group has agreed to an initial deal to buy most of Lukoil's foreign assets, which Russia's second-largest oil company is being forced to sell because of US sanctions. In other news that could boost global supplies and reduce prices, Kazakhstan said US oil major Chevron would take measures to ensure the reliable and safe operation of facilities at Kazakhstan's giant Tengiz oilfield, with the aim of reaching full production in a week. "Disruptions in Kazakhstan (CPC terminal, Tengiz field force majeure) have removed a significant number of barrels from the market," UBS analyst Giovanni Staunovo said. In Venezuela, lawmakers are expected to discuss on Thursday a sweetened oil reform after a proposal submitted by interim President Delcy Rodriguez was modified to introduce a new hydrocarbon tax, the possibility of asset privatisations and oilfield operation outsourcing, a draft seen by Reuters showed. On Venezuela, Exxon Mobil and Chevron executives may face more questions about their investment opportunities in Venezuela than their actual quarterly earnings when they hold calls with analysts on Friday. In the US, the dollar held near its lowest against a basket of other currencies since February 2022 on uncertainty over US economic policies. A weaker US dollar can boost oil prices by making dollar-priced oil less expensive for many global buyers. The US Federal Reserve struck a more sanguine tone on the US labour market and inflation risks overnight, which investors took to imply that interest rates could be on hold for longer. Lower interest rates would reduce consumer borrowing costs and could boost economic growth and oil demand. US President Trump, who wants the Fed to lower interest rates, said he intends to announce his pick to replace Chair Jerome Powell next week. The number of Americans filing new applications for unemployment benefits fell last week from an upwardly revised level in the prior week, suggesting layoffs remained low, but tepid hiring is stoking households' anxiety about the labour market. Separately, analysts noted the premium of futures for Brent over WTI rose to (US)$5.27 per barrel, its highest since April 2024. Analysts have said that when Brent's premium over WTI rises over (US)$4 a barrel, it generally makes economic sense for energy firms to send ships across the ocean to pick up US crude, which should result in higher US exports.

Rising Iran Tensions Propel the Oil Market to Its Highest Level Since August -- The crude market soared on Thursday, reaching its highest level since early August, on increasing concerns over a possible U.S. military attack on Iran. U.S. President Donald Trump has increased pressure on Tehran to end its nuclear program, with threats of military strikes and the arrival of a U.S. naval group in the region. Sources stated that President Trump is considering options that include targeted strikes on security forces and leaders to inspire protesters to create conditions for a regime change. The oil market posted a low of $63.28 on the opening and continued on its upward trend amid the geopolitical escalation. The market extended its gains to over $3.20 as it rallied to a high of $66.48 by mid-morning. It later settled in a sideways trading range during the remainder of the session. The March WTI contract settled up $2.21 at $65.42 and the March Brent contract settled up $2.31 at $70.71. The product markets ended the session in mixed territory, with the heating oil market settling down 8.07 cents $2.5854 and the RB market settling up 2.77 cents at $1.92. Sources said U.S. President Donald Trump is weighing options against Iran that include targeted strikes on security forces and leaders to inspire protesters , even as Israeli and Arab officials said air power alone would not topple the clerical rulers. Two U.S. sources familiar with the discussions said President Trump wanted to create conditions for “regime change” after a crackdown crushed a nationwide protest movement earlier this month. They said to do so, he was looking at options to hit commanders and institutions Washington holds responsible for the violence, to give protesters the confidence that they could overrun government and security buildings. One of the sources said President Trump has not yet made a final decision on a course of action including whether to take the military path. A second U.S. source said the options being discussed by President Trump’s aides also included a much larger strike intended to have lasting impact, possibly against the ballistic missiles that can reach U.S. allies in the Middle East or its nuclear enrichment programs. Axios reported that the Trump administration is hosting senior defense and intelligence officials from Israel and Saudi Arabia for talks on Iran this week as U.S. President Donald Trump considers military strikes. The Axios report said the Israelis traveled to Washington to share intelligence on potential targets inside Iran, while Saudi officials sought to help avert a wider regional war by pushing for a diplomatic solution. Earlier this week, Saudi Crown Prince Mohammed bin Salman told Iranian President Masoud Pezeshkian that Riyadh would not allow its airspace or territory to be used for military actions against Tehran. A U.S. official said the U.S. Navy has sent an additional warship to the Middle East, amid a large military buildup in the region and increasing tensions. The official said the USS Delbert D. Black had entered the region in the past 48 hours. This brings the number of destroyers in the Middle East to six, along with an aircraft carrier and three other littoral combat ships. Citi analysts said that the potential of a military strike against Iran has escalated the geopolitical premium of oil prices by potentially $3 to $4/barrel. It added that further geopolitical escalation could push prices to as high as $72/barrel for Brent over the next three months.

Oil falls as Trump signals dialogue with Iran over nuclear programme (Reuters) - Oil prices slipped on Friday on signs the U.S. may engage in dialogue with Iran over its nuclear programme, reducing concerns of supply disruptions from a U.S. attack, though prices were on track for large monthly gains as tensions have increased. Brent crude futures fell $1.10 to $69.61 a barrel by 0707 GMT after rising 3.4% ‌to close at its highest point since July 31 on Thursday. The March contract expires later on Friday. The more active April contract slid $1.29 to $68.30. U.S. West Texas Intermediate crude dropped $1.25 ‌to $64.17 a barrel after gaining 3.4% to settle at its highest level since September 26 in the previous session. Middle East tensions and oil prices have increased this week due to a U.S. military buildup in the region. U.S. President Donald Trump urged Iran on Wednesday to make a deal on nuclear weapons or face an attack but on Thursday said he was planning to speak to the country's leaders. Tehran responded to his earlier comments by ⁠saying it would strike back hard. "Prices eased after last ‌night's rally as the market reassessed geopolitical risks in the Middle East," said LSEG senior analyst Anh Pham, adding neither a U.S. attack nor the closure of the crucial Strait of Hormuz waterway has actually materialized. The Strait of ‍Hormuz connects the Gulf to the Indian Ocean and is a key conduit for oil supplies from Saudi Arabia, Iraq, Kuwait, Qatar, the UAE and Iran. Prices also slipped as the dollar rose on Friday, paring a weekly slide, after Trump said he would soon announce his nominee to head the Federal Reserve and on optimism that lawmakers in Washington would avoid a government shutdown. A stronger greenback can limit demand from oil buyers paying in other currencies. Still, both ‌oil benchmarks are set to record their first monthly gains in six months amid the tensions between Iran and the U.S., with Brent up 14.5% to notch its biggest jump since January 2022. WTI is on track to rise 12% in January, its biggest monthly gain since July 2023. The Trump administration is hosting senior defence and intelligence officials from Israel and Saudi Arabia for separate talks on Iran this week in Washington, according to two people familiar with the matter. U.S. officials say Trump is reviewing his options but has not decided whether to strike Iran. "Given elevated inflation ⁠and this year's midterm elections, we do not anticipate protracted oil supply disruptions," JPMorgan analysts led by Natasha Kaneva said in a note.

Oil Prices Edge Lower On Profit Taking - Oil prices traded lower on Friday after the U.S. eased some sanctions on the oil industry in Venezuela. A stronger dollar also prompted traders to book some profits after prices hit their highest levels since September the previous day amid tensions in the Middle East and production outages in Kazakhstan. Benchmark Brent crude futures were down 0.9 percent at $68.99 a barrel while WTI crude futures fell 0.9 percent to $64.84. Nevertheless, oil prices remain on course for their best monthly gain since July 2023, helped by ongoing geopolitical risks and supply issues. The dollar traded higher, clawing back some of its slide on the week, as U.S. lawmakers reached an agreement to avoid a partial government shutdown and President Trump said he has chosen a very good person to be the new Federal Reserve chairman, with a formal announcement expected later in the day. The U.S. Treasury Department issued a general license that expands the ability of American energy companies to purchase, refine, and transport crude oil originating in Venezuela. The move came after Venezuela's acting President Delcy Rodriguez signed a law that will open the nation's oil sector to privatization. Traders also braced for an upcoming OPEC+ meeting that could influence supply decisions.

Oil Closes Lower but Posts Strong Monthly Gain | Rigzone Oil edged lower, though still notched its biggest monthly gain since 2022, as US President Donald Trump reiterated openness to negotiations with Iran, though investors remain on edge about the potential for further tensions. West Texas Intermediate fell 0.3% to settle near $65 a barrel, snapping a breathless three-day rally, while Brent ended the day above $70. Prices tumbled after Trump told reporters that Iran wants to make a deal. The US president's messaging has shifted from punishing Tehran for its deadly crackdown on protesters to this week trying to extract a new nuclear agreement. That siphoned some risk premium out of a market on edge after Trump ordered naval assets to the region, with an aircraft-carrier strike group recently arriving in the Middle East. The Islamic Republic is the fifth-biggest producer in the OPEC+ alliance, when including Russia. The de-escalatory remarks from Trump aren't necessarily new, but heading into the weekend, the market is trying to gauge where Trump's head is at, said Rebecca Babin, a senior energy trader at CIBC Private Wealth Group. "Any signal that he may lean toward diplomacy rather than military action creates immediate selling pressure," she added. Crude had earlier fallen alongside other markets as Trump's nomination of Kevin Warsh as the next Federal Reserve chair led to a debate about how far he would cut interest rates. The US president later said that Warsh "certainly wants to cut rates." Several bullish factors are still at play, limiting the slide. In the US, coastal cities are bracing for a record-setting cold spell to intensify in coming days, in a potential disruption to production and boost to heating demand. The storm would come just a week after Winter Storm Fern shut in nearly 2 million barrels a day of US oil production at its peak, according to Energy Aspects. Market concerns are primarily focused on how any fallout from an escalation in tensions could impact Iranian oil flows as well as shipping through the Strait of Hormuz, a narrow passage separating Iran and the Arabian Peninsula. Tankers carrying crude and liquefied natural gas transit through the strait daily to deliver cargoes worldwide. The turmoil helped drive WTI to a 16.2% monthly gain, its largest in nearly four years. Traders are flocking to the options market, and Citigroup Inc. predicts the risk premium for Brent is around $7 to $10 a barrel. The Associated Press reported that Iran issued a warning to ships at sea on Thursday that it planned to run a drill on Sunday and Monday that would include live firing in the strait, citing two Pakistani security officials. Members of OPEC+ will gather online on Sunday to review supply policy for March, with expectations for the group to stick with a pause, and investors will be watching for any commentary regarding Iran. WTI for March delivery fell 21 cents to settle at $65.21 a barrel in New York. Brent for March settlement, which expires Friday, edged down 2 cents to settle at $70.69 a barrel. The more-active April Brent contract settled at $69.32.

Oil Hits Biggest Monthly Hike in 2 1/2 Years in January -- Crude futures dipped Friday, Jan. 30, but posted their highest monthly hike in 2-1/2 years, supported by concerns over near-term oil supply, after the United States took over the Venezuelan oil industry and threatened military action against Iran. On Jan. 3, U.S. military forces captured Venezuelan President Nicolas Maduro and assumed control of the country's oil industry, which produced 896,000 bpd in December. In the weeks thereafter, as mass civilian protests rocked Iran, Washington threatened Iran with military strikes. As on Friday, an armada of U.S. warships were deployed in Middle East waters as U.S. President Donald Trump pressed Iran -- OPEC's fourth largest producer with a 3.2 million bpd output -- to enter nuclear disarmament talks. The two events, along with a major snowstorm last week that disrupted output in the Permian Basin in Texas and the Williston Basin in North Dakota, covering an area with combined production of 2 million bpd, sent crude futures spiraling. The U.S. dollar's tumble to a four-year low against a basket of currencies also boosted prices of crude and other energy products denominated in the greenback. On Friday, the U.S. Dollar Index rose 0.768 points to 96.905 against a basket of currencies, after a four-year low of 95.52 earlier in the week. NYMEX WTI futures for March delivery settled the final session of the month down $0.21, or 0.3%, at $65.21 bbl on light profit-taking, after hitting a five-month high of $66.48 in the prior session. The contract rose 7% for the week and jumped 14% in January, its biggest monthly rise since July 2023, when it advanced 16%. The ICE Brent contract for March settled down $0.02, or 0.03%, at $70.69. For the week, it rose 6% while for the month, it climbed 15%. Among refined products, ULSD for March delivery was up $0.0618, or 2.5%, at $2.5456 gallon. For the week, it rose 5% and for the month advanced by 20%. The gasoline contract for March rose $0.0158, or 0.7%, to $1.9511 gallon. It rose 5.5% on the week and 14% in the month.

Ukraine and Russia Agree to Short-Term Energy Truce - Trump confirmed Moscow had agreed to stop strikes on Ukraine’s energy targets. On Thursday, unconfirmed reports claimed that Russia and Ukraine agreed to a short-term energy truce. The deal was brokered during negotiations in the UAE. The pause will continue for the duration of the ongoing negotiations. The talks are scheduled to end early next month. Donald Trump later explained that Russia signed on to the truce. “I personally asked President Putin not to fire on Kyiv and the cities and towns for a week during this … extraordinary cold,” the President said, adding, “and he agreed to it.” The Kremlin has not commented on the proposal, and a Ukrainian official expressed skepticism about the truce. “Only the reality itself can prove it. We will see how tonight goes,” they told Axios. Russia and Ukraine have traded attacks on energy infrastructure. Ukrainian drones have targeted Russian refineries and one of President Vladimir Putin’s residences. Russian missile strikes on Ukraine have left thousands without power and heat. Trump has attempted to negotiate an end to the war in Ukraine, but Kiev and Moscow remain far apart on several key issues. The Kremlin said that they believe Trump is now rushing to complete a deal to end the war.

Massacre Claimed as SDF Fighter Killed 21 in Village Near Syria’s Kobane - The Kurdish SDF has reported that one of their fighters was involved in an apparent massacre in the village of Kharous, near the important border city of Kobane. The incident gained major national attention after a video was released online of the killer bragging about the incident.The fighter in question was posing with the bodies of 21 people he’d killed, and purported that they were all tribal gunmen loyal to the central government. Other reports, however, suggest the killed were detainees that the Kurdish autonomous government had captured and released, and may have included other civilians from the village.The SDF said this was not in keeping with their “military and ethical values” and that the fighter was immediately dismissed from the organization and referred to a military court for his apparent crimes. They added the incident was “individual and unacceptable.” The incident apparently happened on Friday night, amid ongoing reports of a siege against SDF-held Kobane and the surrounding areas. Kurds displaced in the surrounding area have flocked to Kobane, and major displacement camps have been established, raising humanitarian concerns. The SDF statement on that matter accused the government of violating the ceasefire in its attacks on Kobane and the Jazira region. They also claimed that the ongoing military preparations for more offensives against the SDF showed that the government intends to push toward war rather than a political solution. The ceasefire that is nominally still in place was a four-day ultimatum by the Sharaa government demanding the SDF accept all their demands for ceding territory and integrating into the military on their terms. That ceasefire expires Saturday at 8:00 pm, though there have been some reports that an extension has been reached to push the matter further down the road.

Snow Worsens Siege on Syrian Kurdish City of Kobane as Fighting Expands - If you put aside the continued fighting in several parts of northern and eastern Syria, and themounting humanitarian crisis among civilians displaced by the fighting, the ceasefire between the Syrian government and the Kurdish SDF is holding.The tribal-backed offensive against the Kurds that has left the military in control of much of what was once Rojava, the Kurdish autonomous territory in Syria, was lauded by President Trump, who says he is “very happy” about what Syria has accomplished, and did not mention growing humanitarian concerns both in camps for the displaced and in the Kurdish majority city of Kobane. Kobane doesn’t give the impression of a city in a ceasefire. Fuel and water shortages abound, and food is starting to get in short supply as the military continues a siege of the city. While aid has been allowed in through a corridor, intermittently, fighting rages on the outskirts and there is little sign of that abating, with Syrian state media predictably declaring it to be entirely a siege of the SDF’s own making, even though it’s a Kurdish city and one that they already controlled. Locals who remained in Kobane, instead of fleeing to the overcrowded camps, report hearing the sounds of clashes on the outskirts, and the town’s recently blanketing with snow has only worsened access to the city by aid groups, compounding shortages.Further to the east, the town of Çil Axa seems to be the other major location of fighting. Located in the far northeast of Syria’s easternmost Hasakeh Governorate, that town is seen as vital for the Kurds to maintain control of, given it’s along the highway connecting the region to Iraqi Kurdistan. A small town of only about 6,600 during the last census, Çil Axa (called al-Jawadiyah in Arabic) was a mixed town with a slight Kurdish majority at the time, but has thrived since Kurdish forces seized control of the area from ISIS during the Syrian civil war, and locals now report a larger Kurdish majority.In a move intended to calm the Kurdish alarm about the military conquest, the Syrian government has advanced a promise to guarantee citizenship for Kurds in Hasakeh Governorate, with theInterior Ministry ordering the annulment of the 1962 general census which branded many of the local Kurds as stateless “maktoom” people.This announcement follows a pledge from President Sharaa 10 days ago to resolve the citizenship problem with the Hasakeh Kurds and assure them rights. President Bashar al-Assad effectively ordered the same thing in 2011, though implementation was spotty in practice, and many Kurds who have lived in Hasakeh their whole lives remain effectively without citizenship . At the time of Sharaa’s announcement, the Kurds expressed disquiet about him following Assad’s tactic of trying to resolve the situation by unilateral decree and urged the matter to be resolved constitutionally, assuring that the problem actually will finally be fixed and that the Kurds won’t once again find themselves without any legal options if the government decides the promise is no longer worth keeping.

Israel Recovers Body of Final Captive in Gaza - Israel says it recovered the remains of Ran Gvili in Gaza. The Israeli police officer was the final hostage held by Hamas. Gvili was killed fighting Hamas on October 7, 2023, and his body was taken into Gaza. Under the peace agreement between Hamas and Israel in October, the Palestinian group agreed to release the living captives and the remains of the deceased. Hamas immediately released the living hostages, and has returned the remains over the past three months. The Palestinian group said the recovery process was difficult due to the massive destruction in Gaza caused by the Israeli onslaught. While the first 27 bodies were handed over to Hamas by Israel, Israeli forces recovered the remains of Gvili. Israel recovered the body from a cemetery in Gaza. The IDF exhumed over 250 bodies before locating Gvili. The remains were recovered on Israel’s side of the yellow line, meaning Hamas would not have access to the cemetery. Hamas said on Monday that it “exerted significant efforts in the search for the body of the last prisoner” and that it had provided Israel with “all the details and information in our possession regarding the location of the prisoner’s remains.” President Donald Trump confirmed that Hamas aided Israel in recovering Gvili’s remains. With the recovery of the final hostage, Hamas has met its obligations under the first phase of the peace deal that Trump brokered. Israel continues to violate the pact.

IDF Proposes Limiting Aid Deliveries to Gaza to 200 Trucks Per Day - The Israeli military wants to limit aid deliveries to Gaza to a third of what Israel is required to allow to enter the Strip. The Jerusalem Post reported on Thursday that the IDF has recommended restricting aid deliveries to Gaza to 200 trucks per day. The Israeli military claims that this is the amount of aid required to sustain the Palestinians, and additional aid is given to Hamas.Under the deal between Hamas and Israel brokered by President Donald Trump in October, Tel Aviv agreed to allow 600 aid trucks to enter Gaza each day. Throughout most of the ceasefire period, Israel has kept aid deliveries to a minimum. Over the past week, 600 trucks per day have entered Gaza. While the Israeli military claims the Palestinians are “flooded” with supplies, aid agencies say the people of Gaza are still struggling to survive. Most people in Gaza are displaced and living in tents. Israel is refusing to allow temporary housing to enter Gaza, leading to several children freezing to death. The UN’s humanitarian affairs spokesperson, Olga Cherevko, said aid organizations were still facing “severe limitations.”The assertion that Hamas is stealing a large portion of the aid that enters Gaza has also been debunked by multiple investigations. In addition to restricting the number of aid deliveries into Gaza, the IDF wants to maintain that all aid going to Gaza enters through Israel. Gaza’s border crossing with Egypt is scheduled to be reopened within the coming week. The IDF wants to prevent cargo from entering the Strip via Egypt. “In the months leading up to Oct. 7, some 11,000 trucks entered Gaza unchecked via Rafah, four times higher than in previous years. Aid to Gaza must go through Israeli crossings under supervision.” The IDF official continued, “At most, Kerem Shalom could one day serve as a border triangle or resemble the cargo terminals at the Allenby crossing with Jordan.”

Netanyahu: Israel Will Have Control from ‘River to the Sea’ Including Gaza - Israeli Prime Minister Benjamin Netanyahu said Israel will maintain security control over the area between the Jordan River and the Mediterranean Sea. He added that he will not allow the creation of a Palestinian State. “Israel will maintain security control over the entire area from the Jordan River to the sea, and that applies to the Gaza Strip as well,” Netanyahu said on Tuesday. The statement from the Israeli leader is the latest indication that he has no intentions of allowing President Donald Trump’s Middle East peace deal to progress. The agreement signed by Hamas and Israel in October requires Tel Aviv to withdraw its forces from Gaza and creates a pathway for a Palestinian state. During his remarks, Netanyahu made clear that he will not allow the two-state solution to materialize. Notably, Netanyahu used the phrase “from the Jordan River to the sea.” When pro-Palestinian protesters in the US used that chant, Israeli supporters claimed that they were calling for the genocide of Jewish people. The Israeli leader went on to say the next phase of Gaza operations is demilitarizing Hamas. “Now we are focusing on completing the two remaining missions: dismantling Hamas’s weapons and demilitarizing Gaza of arms and tunnels,” Netanyahu explained. “As I agreed with President Trump, there are only two possibilities: either this will be done the easy way, or it will be done the hard way.” He continued, “But in any case, it will happen. I am already hearing the statements that we will allow Gaza’s reconstruction before demilitarization. That will not happen.”Under the October agreement, Hamas did not agree to give up its arms. The group has maintained that it will only demilitarize if it is in the process of creating a Palestinian state. Additionally, Netanyahu explained that Israel will reopen the Rafah border crossing. Rafah is Gaza’s sole crossing with Egypt. The Israeli leader explained that Tel Aviv will only allow a limited number of Palestinians to enter Gaza, but will not hinder any Palestinians from leaving Gaza. Israel is in the process of creating a new camp for Palestinians in Gaza. Israeli forces have flattened half a square mile in southern Gaza. Tel Aviv plans to force Palestinians into the new camp, which will likely be surrounded by Israeli military positions. “What they are building is, in reality, a human-sorting mechanism reminiscent of Nazi-era selection points,” Wissam Afifa, a Gaza-based political analyst, told Al Jazeera. “It is a tool for racial filtering and a continuation of the genocide by other means.”