largest crude inventory build in 54 weeks; gasoline supplies at a 71 month high; distillates demand at a 53 week high

US oil prices finished lower for a second week, following six consecutive increases, after the API and EIA both reported the largest US crude inventory increase in more than a year, and after the International Energy Agency lowered its global oil demand forecast for this year….after falling 2.5% to $63.55 a barrel last week as traders hoped talks between the US and Iran would reduce the threat to Persian Gulf oil supplies, the contract price for the benchmark US light sweet crude for March delivery fell about 1% in Asian trading on Monday, as fears of a potential armed conflict in the Middle East continued to ease after the United States and Iran expressed their willingness to continue talks on Tehran’s nuclear program, but saw its losses limited on global markets on reports that India’s refiners were avoiding purchases of Russian oil for delivery in April, as they looked to sign a trade deal with the U.S, then rallied during the US session to settle 81 cents higher at $64.36 a barrel after the U.S. Department of Transportation issued an advisory to U.S.-flagged vessels to stay as far as possible from Iranian territory while passing through the Strait of Hormuz and Gulf of Oman…March oil traded lower in Asia on Tuesday morning, as traders analyzed the potential for supply disruptions following the US advisory to vessels transiting the Strait of Hormuz, then rose for second day on global markets, as military maneuvers and warnings about shipping safety forced traders to factor in an additional risk premium on fuel prices, but traded in a narrow range during the New York session as the market remained focused on the geopolitical tensions between U.S. and Iran after the U.S. issued its guidance for vessels transiting the Strait of Hormuz, and settled 40 cents lower at $63.96 a barrel as the market waited for direction from news on diplomatic relations between the US and Iran, efforts to end Russia's war in Ukraine, and data on the US economy and US oil inventories…oil prices resumed their upward movement on global markets Wednesday, even after the American Petroleum Institute (API) reported the largest increase in US crude inventories since November 2023, as traders reacted to reports that the US was considering seizing tankers with Iranian oil and sending an additional aircraft carrier strike group to the region, then took a hit early in the US session after the EIA reported the largest crude inventory build in a year, but still settled 67 cents higher at $64.63 a barrel as escalating tensions between Iran and the U.S. offset the weekly reports showing a large build in U.S. crude supplies….oil prices rose in Asian trading on Thursday amid concerns over escalating tensions between the U.S. and Iran and potential disruptions to crude supplies from the Gulf region, but later edged lower on global markets as fresh concerns over weakening demand in the United States and China overshadowed geopolitical tensions tied to ongoing U.S.-Iran negotiations, and then sold off sharply throughout the US trading session, after the International Energy Agency said world oil demand would increase more slowly than expected this year, and settled $1.79 or 2.8% lower at $62.84 a barrel on falling demand, retreating fears of renewed Middle East conflict and expected increases in supply….oil prices held those losses in Asian trading on Friday, as forecasts of a sizeable supply surplus and rising inventories weighed on sentiment, then fell further on global markets after a Reuters report said that OPEC+ was leaning towards a resumption in oil production increases and a softening of trader concern over potential U.S.-Iran conflict that could affect supply, but steadied on the release of US consumer price data, which were seen to support further rate cuts in the US and to boost risk-taking appetite, and recovered to settle 5 cents higher at $62.71 a barrel, after data showed an overall slowdown in U.S. inflation, helping offset supply concerns as OPEC+ is leaning towards a resumption in production increases, but still finished 1.0% lower for the week…

natural gas prices also finished lower for a second straight week, on forecasts for above normal temperatures for most of the country for the rest of February…after falling 21.4% to $3.422 per mmBTU last week on forecasts that the arctic cold would withdraw from the lower 48 by this week, and as the prior week's record withdrawal from storage was less than expected​,​ the price of the benchmark natural gas contract for March delivery opened 26.7 cents lower on Monday morning, knocked down over the weekend as traders eyed warming forecasts and steady production, bounced briefly, then hung around the $3.150 level into the afternoon before settling 28.4 cents lower at $3.138 per mmBTU, on forecasts for milder weather than previously expected for the rest of the month….natural gas prices opened 2.5 cents higher Tuesday and rose through the morning to cross midday at $3.169, buoyed by bargain buyers entering the market, then pulled back to record an intraday low of $3.108 at 2:25 PM, before settling at 2.3 cents lower at $3.115 per mmBTU on forecasts calling for milder weather later in February…prices opened 2.4 lower on Wednesday, but trended higher throughout the morning, as a possible new cold front entered the radar and LNG demand remained strong, and settled 4.4 cents higher at $3.159 per mmBTU on near-record flows to LNG export plants…natural gas opened a penny higher on Thursday and rose to a high of $3.316 ahead of the storage report, but dropped 10 cents shortly after the historically bullish withdrawal was reported​, and traded in a narrow range throughout the afternoon to settle 5.8 cents higher $3.217 per mmBTU on near-record flows to LNG export plants and a storage report showing a larger withdrawal than usual for a second week in a row to meet surging heating demand during the lingering Arctic freeze….natural gas futures struggled to find their footing in early Friday trading, as markets digested a second straight bearish storage miss and braced for mild weather next week, then traded on either side of even heading into midday, held in check by rapidly waning weather demand but supported by steady LNG activity, and settled 2.6 cents higher at $3.243 per mmBTU, after a smaller-than-expected storage draw from storage bolstered confidence in ample end-of-season supplies amid bearish sentiment and warming forecasts, and hence finished 5.2% lower for the week…

The EIA’s natural gas storage report for the week ending February 6th indicated that the amount of working natural gas held in underground storage fell by 249 billion cubic feet to 2,214 billion cubic feet by the end of the week, which left our natural gas supplies 97 billion cubic feet, or 4.2% below the 2,311 billion cubic feet of gas that were in storage on February 6th of last year, and 130 billion cubic feet, or 5.5% below the five-year average of 2,490 billion cubic feet of natural gas that had typically been in working storage as of the 6th of February over the most recent five years….the 249 billion cubic foot withdrawal from natural gas storage for the cited week was less than the 257 billion cubic foot withdrawal from storage that was forecast in a Reuters poll of analysts ahead of the report, but was quite a bit more than the 111 billion cubic foot of gas that were pulled out of natural gas storage during the corresponding week of 2025, and also much more than the average 146 billion cubic foot withdrawal from natural gas storage that has been typical for the same early February week over the past five years…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending February 6th indicated that after a sizable increase in our imports and a​ post-storm rebound in our oilfield production, we had has surplus oil to add to our stored crude supplies for the 18th time in thirty-seven weeks, and for the 46th time in eighty-two weeks, in spite of a decrease in demand for oil that the EIA could not account for….Our imports of crude oil rose by an average of 604,000 barrels per day to 5,642,000 barrels per day, after rising by an average of 558,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 308,000 barrels per day to average 3,739,000 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 3,066,000 barrels of oil per day during the week ending February 6th, an average of 912,000 more barrels per day than the net of our imports minus our exports during the prior week... At the same time, transfers to our oil supplies from Alaskan gas liquids, from natural gasoline, from condensate, and from unfinished oils were 31,000 barrels per day lower at 751,000 barrels per day, while during the same week, production of crude from US wells was 498,000 barrels per day higher than the prior week at 13,713,000 barrels per day. Hence, our daily supply of oil from the net of our international trade in oil, from transfers, and from domestic well production appears to have averaged a total of 17,530,000 barrels per day during the February 6th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,000,000 barrels of crude per day during the week ending February 6th, an average of 29,000 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 1,218,000 barrels of oil per day were being added to the supplies of oil stored in the US… So, based on that reported & estimated data, the crude oil figures provided by the EIA appear to indicate that our total working supply of oil from net imports, from transfers, and from oilfield production during the week ending February 6th averaged a rounded 312,000 more barrels per day than what was added to storage plus what our oil refineries reported they used during the week. To account for the difference between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a [ -312,000 ] 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…since 586,000 barrels per day of demand for oil supply could not be accounted for in the prior week’s EIA data, that means there was rounded 273,000 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 not very useful.... However, since most oil traders react to these weekly EIA reports as if they were gospel, and since these weekly figures therefore often drive oil pricing and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it’s published, and just as it’s watched & believed to be reasonably reliable by most everyone in the industry…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil supply, see this EIA explainer….also see this old twitter thread from an EIA administrator addressing these ongoing weekly errors, and what they had once hoped to do about it).

This week’s rounded 1,218,000 barrel per day average increase in our overall crude oil inventories came as an average of 1,219,000 barrels per day were being​ added to our commercially available stocks of crude oil, while no oil was being added to our Strategic Petroleum Reserve for the first time since last February… Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports fell to 6,274,000 barrels per day last week, which was 5.0% less than the 6,604,000 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 498,000 barrels per day higher at 13,713,000 barrels per day because the EIA’s estimate of the output from wells in the lower 48 states was 500,000 barrels per day higher at 13,284,000 barrels per day, while Alaska’s oil production was 2,000 barrels per day lower at 429,000 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 4.7% higher than that of our pre-pandemic production peak, and was also 41.4% 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 89.4% of their capacity while processing those 16,000,000 barrels of crude per day during the week ending February 6th, down from 90.5% the prior week, and down from the 93.3% utilization rate of the week ending January 16th, with​ the lower utilization levels of the past three weeks reflecting impacts of ​n​ear zero temperatures on refinery operations, as well as partial shutdowns as refineries start to change over to producing Spring blends of fuel….the 16,000,000 barrels of oil per day that were refined that week was 3.7% more than the 15,431,000 barrels of crude that were being processed daily during the cold-impacted week ending February 7th of 2025, but 0.1% less than the 16,020,000 barrels that were being refined during the prepandemic week ending February 7th, 2020, when our refinery utilization rate was at 88.0%, which was on the low side of the pre-pandemic normal range for this time of year…

In spite of the modest decrease in the amount of oil that was refined this week, gasoline output from our refineries was higher, increasing by 139,000 barrels per day to 9,148,000 barrels per day during the week ending February 6th, after our refineries’ gasoline output had decreased by 565,000 barrels per day during the prior week... This week’s gasoline production was 2.1% less than the 9,346,000 barrels of gasoline that were being produced daily over the week ending February 7th of last year, and also 1.0% less than the gasoline production of 9,241,000 barrels per day seen during the prepandemic week ending February 7th, 2020….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased 45,000 barrels per day to 4,859,000 barrels per day, after our distillates output had decreased by 5,000 barrels per day during the prior week. After that production increase, our distillates output was 7.0% more than the 4,543,000 barrels of distillates that were being produced daily during the week ending February 7th of 2025, and 0.5% more than the 4,837,000 barrels of distillates that were being produced daily during the pre-pandemic week ending February 7th, 2020....

After this week’s increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the thirteenth consecutive week, increasing by 1,160,000 barrels to a 71 month high of 259,058,000 barrels during the week ending February 6th, after our gasoline inventories had increased by 685,000 barrels during the prior week. Our gasoline supplies increased by more this week e ven though the amount of gasoline supplied to US users rose by 147,000 barrels per day to 8,300,000 barrels per day, while our imports of gasoline fell by 29,000 barrels per day to 365,000 barrels per day, and while our exports of gasoline rose by 20,000 barrels per day to 978,000 barrels per day … In spite of thirty-one gasoline inventory withdrawals over the past fifty-three weeks, the recent surge of additions meant our gasoline supplies were 4.4% higher than last February 7th’s gasoline inventories of 248,053,000 barrels, and about 4% above the five year average of our gasoline supplies for this time of year…

Even after this week’s increase in distillates production, our supplies of distillate fell for the third time in thirteen weeks, decreasing by 2,703,000 barrels to 124,665,000 barrels during the week ending January 30th, after our distillates supplies had decreased by 5,553,000 barrels to during the prior week… Our distillates supplies fell by less this week even though the amount of distillates supplied to US markets, an indicator of domestic demand, rose by 139,000 barrels to a 53 week high of 4,449,000 barrels per day, because our exports of distillates fell by 546,000 barrels per day to 948,000 barrels per day, while our imports of distillates fell by 46,000 barrels per day to 151,000 barrels per day, ... With 19 additions to distillates inventories over the past 31 weeks, our distillates supplies at the end of the week were 5.1% higher than the 118,615,000 barrels of distillates that we had in storage on February 7th of 2025, but about 4% below the five year average of our distillates inventories for this time of the year…

Finally, after the increase in our oil production and the increase in our oil imports, our commercial supplies of crude oil in storage rose for the 14th time in twenty-six weeks, and for the 30th time over the past year, and by the most since January 2025, increasing by 8,530,000 barrels over the week, from 420,299,000 barrels on January 30th to 428,829,000 barrels on February 6th, after our commercial crude supplies had decreased by 3,455,000 barrels over the prior week… After this week’s increase, our commercial crude oil inventories were still about 3% below the recent five-year average of commercial oil supplies for this time of year, while they were ​a​bout 33% above the average of our available crude oil stocks as of the first weekend of February over the 5 years at the beginning of the past decade, with the big difference between those comparisons arising because it wasn’t until early 2015 that our oil inventories had first topped 400 million barrels. After our commercial crude oil inventories had jumped to record highs during the Covid lockdowns in the Spring of 2020, then jumped again after February 2021’s winter storm Uri froze off US Gulf Coast refining, but then fell sharply due to increased exports to Europe following the onset of the Ukraine war, only to jump again following the Christmas 2022 refinery freeze-offs, changes in our commercial crude supplies have generally leveled off since, and as of this February 6th were 0.2% more than the 427,860,000 barrels of oil left in commercial storage on February 7th of 2025, but were 1.7% less than the 439,450,000 barrels of oil that we had in storage on February 9th of 2024, and 5.7% less than the 455,111,000 barrels of oil we had left in commercial storage on February 27th of 2023…

This Week's Rig Count

The US rig count was unchanged over the week ending February 13th, as the number of rigs targeting natural gas was up by three while the count of rigs targeting oil was down by three, and miscellaneous rigs were unchanged…for a quick snapshot of this week's rig count, we are again including below a screenshot of the rig count summary pdf from Baker Hughes...in the table below, the first column shows the active rig count as of February 13th, the second column shows the change in the number of working rigs between last week’s count (February 6th) and this week’s (February 13th) count, the third column shows last week’s February 6th 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 14th of February, 2025…

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Seismic events in Southeast Ohio reach high in 2025 -  Earthquakes have increased over the past few years in the state of Ohio, according to entries from an Ohio Earthquake database. There were 213 earthquakes reported in Ohio in 2025 and 129 earthquakes reported in 2024. As of Feb. 9, there were nine so far for the new year. Earthquakes are caused by a sudden slip on a fault, in which the edges of tectonic plates get stuck due to the friction, according to the U.S. Geological Survey. Michael Brudzinski, professor of geology and environmental earth science at Miami University, works with the Ohio Department of Natural Resources to research the relationship between seismic activity in Ohio and the extraction of oil and gas from the subsurface. Brudzinski said the new technology to quickly extract oil and gas from older and less permeable rock is called hydraulic fracking. “The whole purpose of it is to drill down into those rocks and inject fluid that will crack open the rock, that's the fracturing part, and hydraulic just means we're pumping fluid to hydraulically open up cracks in the rock,” Brudzinski said. “Then, when you pull the water back out, it brings oil and gas with the water.”Through his research, Brudzinski found that due to fluid from hydraulic fracking unknowingly being pumped into fault zones, the technology creates a higher risk for earthquakes.The U.S. Geological Survey states tremors can be caused by human activity, including surface or underground mining, injection of fluids into underground formations, impoundment of reservoirs and withdrawal of fluids or gas from subsurface and waste water disposal in deep wells. “While most induced earthquakes are small and present little hazard, larger and potentially damaging manmade earthquakes have occurred in the past,” the U.S Geological Survey states.Ohio Department of Natural Resources Press Secretary Karina Cheung wrote in an email, the seismic activity in Southeast Ohio is induced. In contrast to natural tectonic events, induced activity stops after extraction activities end, rather than continuing aftershock.“Earthquakes cannot be predicted,“ Cheung wrote in an email. "The increase in detection of earthquakes, often at lower magnitudes, can be attributed to the expansion of seismic networks in Ohio over the past decade."Cheung concluded although seismic activity has increased, damage to the environment has and will continue to be minimal due to the shallow nature of the events.“Since 2011, the development of the Utica Shale in Southeast Ohio has resulted in induced seismicity; however, it is still rare, with magnitudes infrequently reaching felt levels,” ODNR said.The Utica Shale stretches under Ohio, Pennsylvania, West Virginia, New York, Quebec and other parts of eastern North America. Eastern Ohio drills into the Utica Shale for natural resources.The Utica Shale contains about 38 trillion cubic feet of natural gas, about 940 million barrels of oil and 208 million barrels of natural gas liquids.ODNR also attributes seismic activity in Ohio to the Appalachian Mountains and the terminus of the Grenville orogeny. The latter refers to an ancient mountain-building event, which created deep metamorphic rocks, now exposed in the Canadian shield and below the Appalachian mountains. Brudzinski highlights environments similar to Athens, low-lying areas close to mountains, which allow for easier drilling of oil and gas. Throughout the formation of the Utica Shale, it has gone under Grenville and other mountain formations that create dormant faults under Eastern Ohio.“The eastern half of the state is underlain by many faults, some of which (but not all) have been mapped. As earthquakes happen in areas with previously unmapped faults, we get more detailed insights into location, size and orientation of the faults,” Cheung wrote in an email.Two ODNR divisions are researching seismic activity in multiple ways. The Ohio Geological Survey relies on its operation of a 37-station seismic network that expands throughout the state, along with efforts from Miami University to conduct research regarding seismic activity.“The division also operates a highly sensitive seismic network that assists to develop understanding of seismic hazards in Ohio, regulates oil and gas operations and protects Ohioans,” Cheung wrote in an email.Brudzinski mentioned the many nuances regarding the regulation of oil and gas operations, including economic benefits, increased seismic activity and carbon dioxide impacts.“Overall, (seismic activity) is a fluctuating event,” Brudzinski said. “As activity fluctuates ... we try to best deduce what is the right strategy to keep it on the down low.”

What to know about reseeding right-of-ways - Across Ohio, landowners are receiving offers to lease their property for the development of oil and natural gas wells, pipelines or utility-scale solar projects. It is important to note that the land after this level of disturbance will require mitigation, potentially renovation, and this often happens at the most inopportune times. The bottleneck in the oil and gas industry has been and continues to be pipeline infrastructure. It really does not matter what side of the state you reside in, that pipeline easement/right-of-way can impact your farm any time of the year. It is important to realize that you and the pipeline company have different concerns when it comes to that easement. The pipeline company is worried about their timeline and erosion — as long as the ground is covered, they are covered! You, on the other hand, have a much more complex system. Of course, you care about the timeline and erosion, but you also care about your crops, weeds, compaction, soil health and the time of the season this happens. That pipeline company will likely seed only once; what happens later is on you. There are communication barriers that farmers need to be aware of. I have seen farmers state they desire cool-season forages, and that is what they got from the pipeline company, but it was seeded in July. Annual grass weeds came up, the foxtail prevented erosion and that was the end of that conversation. Using cover crops just to mitigate damages and hold the land over for an optimal seeding could be an option for the landowner. Sometimes, you get what you wish for. But seeding something that your livestock does not typically graze can have consequences. A ROW can easily be 100-feet-plus in width and stretch for miles. This can significantly impact pastures, and altering the species can have consequences for livestock diet and health. A lush growth of legumes coming out of a low-quality hay winter can cause livestock to bloat and cost you more than you anticipated.

Antis’ Ethics Complaint Against OH Senator “Crashed and Burned” –- Marcellus Drilling News - in January, a coalition of so-called environmental groups lodged an ethics complaint against Ohio Senator Brian Chavez, alleging that he failed to disclose ownership in five natural gas LLCs while leading the Senate Energy Committee (see Antis Attack Ohio State Senator with Ethics Complaint). As we reported, what’s really going on is a dirty fight by the enviro-left to try to stop a fifth injection well from operating near Marietta, OH. We’re happy to report that the antis’ ethics complaint has “crashed and burned.”

Antero Resources Plans Redemption Tied to Ohio Asset Sale - On February 9, 2026, Antero Resources Corporation issued a conditional notice to fully redeem its 7.625% senior notes due 2029, covering $365.4 million in outstanding principal, at 101.271% of par plus accrued interest, with a planned redemption date of February 24, 2026. The redemption is contingent on closing the divestiture of substantially all of Antero’s Ohio Utica Shale oil and gas assets and on the board’s continued support for the move, underscoring that the company’s planned balance sheet actions are closely tied to its asset sale strategy and subject to execution risk. Antero Resources Corporation is an independent oil and natural gas company focused on exploration and production, with significant shale assets including holdings in the Utica Shale in Ohio. The company finances its operations in part through senior notes and other debt instruments issued to capital markets investors.

24 New Shale Well Permits Issued for PA-OH-WV Feb 2 – 8 -- Marcellus Drilling News - The Marcellus/Utica region received a combined 24 new drilling permits last week, Feb. 2 – 8, up 2 from the permits issued two weeks ago. Pennsylvania issued 10 new permits, Ohio issued 10, and West Virginia issued 4. The drillers receiving new permits last week included: Arsenal Resources, Ascent Resources, Blackhill Energy, EQT, Expand Energy, and Infinity Natural Resources. ARSENAL RESOURCES | ASCENT RESOURCES | BELMONT COUNTY | BLACKHILL ENERGY | BRADFORD COUNTY | EQT CORP | EXPAND ENERGY | GREENE COUNTY (PA) | GUERNSEY COUNTY | INFINITY NATURAL RESOURCES | MONROE COUNTY | TAYLOR COUNTY WETZEL COUNTY

Two Birds, One Stone – Efforts to Plug Orphaned Oil and Gas Wells Can Help Cut Methane Emissions Too | RBN Energy -The U.S. has been drilling for oil and natural gas for more than 160 years, and what to do with those wells once they are no longer productive has long been an issue, especially for those wells without a reliable party to manage their future re-use or plugging and abandonment. The issue has drawn additional attention in recent years because those “orphaned” wells can also be significant emitters of methane, a potent greenhouse gas (GHG). In today’s RBN blog, we’ll look at the number of orphaned oil and gas wells across the U.S., how they contribute to methane emissions, and discuss an approach that aims to address both issues simultaneously. There are nearly 120,000 documented orphaned and unplugged wells across 27 states, according to the U.S. Geological Survey (USGS). To be included in the USGS total, a well generally needs to have no production for an average of 12 months, although that varies by state. The states with the most orphaned wells (red states in Figure 1 below) are Ohio and Pennsylvania, with more than 16,000 each, followed by Oklahoma, Kentucky and Illinois (dark-orange states), with at least 8,000; with several other states (medium-orange states) close behind. (We should note that there are thought to be many more undocumented wells, with the Interstate Oil & Gas Compact Commission, or IOGCC, putting that number at anywhere from 310,000 to 800,000, a result of poor recordkeeping and insufficient policy and/or enforcement over several decades.) Since orphaned wells can have a number of financial and environmental consequences (more on those below), efforts have been made at the federal and state levels to address the issue. The Infrastructure, Investment and Jobs Act (IIJA), which was signed into law in 2021, provided $4.7 billion for states, tribes and landowners to plug, remediate and reclaim orphaned oil and gas wells. The Department of the Interior’s online dashboard shows that more than 10,500 orphaned wells were plugged through the program, the vast majority of them oil and gas wells (8,771), with a much smaller number of injection wells and disposal wells also plugged. While that is not an insignificant reduction, it’s just a fraction of the overall total of orphaned wells. Most oil- and gas-producing states also have their own programs to plug orphaned wells; 26 states applied for funding under the IIJA’s well-plugging program. How does a well end up as an orphan? As noted above, recordkeeping about wells was often incomplete or inconsistent in past decades (particularly compared to today’s standards), making it easier for some operators, especially smaller ones, to walk away from a well once it was no longer profitable, even though there are state and federal rules in place designed to prevent that from happening. For example, most states require an operator to put up a bond intended to cover costs if that operator goes away. Depending on the state, that bond value may be insufficient to complete the plugging operations on that one well, often leaving states under-resourced. Orphaned wells can lead to a number of financial and environmental issues. On the economic side, they can be expensive to plug (often at the public’s expense), decrease land values (and productive acreage) and create significant long-term liabilities. On the environmental side, orphaned wells can leak methane and volatile organic compounds, contaminate groundwater and require extensive restoration efforts, with potential short- and long-term consequences. Efforts to reduce methane emissions have been a particular focus in recent years (see our Cover Me series). Carbon dioxide (CO2) has often been the primary focus of the emissions debate, but methane is a particularly powerful GHG, with a Global Warming Potential (GWP) that is 25-36 times that of CO2 when normalized to a 100-year timeline — and more than 80 times that of CO2 if normalized to a 20-year timeline (since it degrades more quickly than CO2 in the atmosphere) — making it an obvious target in efforts to reduce the impacts of GHG emissions, especially in the near-term. Those efforts have left producers looking for ways to mitigate methane emissions during gas production and transportation (see It Don’t Come Easy and Paradise), giving rise to the market for certified natural gas (see A Whole New World). But while most efforts to mitigate methane emissions have focused on producing wells, there’s a lot more that could be done, as companies like Rebellion Energy Solutions demonstrate, one of a handful that focus on orphaned wells. As noted above, there are nearly 120,000 documented orphaned wells in the U.S. Most of them do not leak methane, although they may in the future. While identifying and testing orphaned wells requires a lot of field work, the wells most likely to leak generally share some common denominators: A well that produced natural gas during its lifetime is more likely to leak methane. The deeper a well is, the more energy it is likely to have held behind surface equipment. (Deeper wells are also more expensive to maintain, which means they may be less likely to have received proper care and maintenance during their producing life.) The older a well is, the more apt it is to leak. (Some wells can produce at low levels for decades before they are abandoned, which means some were drilled and completed using older techniques and technology.) A well that had been operated by a smaller operator may be more likely to leak, as a well operated by a known entity is more likely to have been better maintained over its productive life. A well-plugging strategy starts with identifying and locating orphaned wells that would be good candidates for plugging. Sites are selected by targeting the highest‑emitting, highest‑risk orphaned wells where methane abatement would generate the most carbon credits (more on those below) while also considering landowner impacts and operational feasibility. Following that, a landowner and/or community is approached for permission to visit a well site to evaluate methane and other emissions, after which a comprehensive plugging-and-restoration plan may be initiated. Before a well is plugged, it must undergo a measurement process to quantify the amount of methane leaking into the atmosphere. Multiple tests lasting several hours are often necessary to get the proper data. Next up is plugging and restoration, but there are some key differences with the typical plugging process, where the rules can vary significantly from one state to another. For example, 24 state agencies have well-plugging rules that require cement to be placed above the producing zones (yellow bar in Figure 2 below) and 23 specify where plugs should be located (dark-red bar), while only eight specify how strong cement plugs should be (brown bar) and just five mandate that the wellbore must be essentially static after plugging (green bar). Once the plugging is done, the next step is verification. As noted above, an orphaned well’s methane emissions are extensively measured before any plugging work begins. (The goal is to determine how much methane would leak over a 20-year period. This step requires oil and gas expertise, this time on the reservoir engineering side.) Post-plugging measurements confirm that emissions have dropped to near zero, demonstrating that the future emissions that would have occurred have been effectively prevented. Once the emissions data is compiled and documented, a third-party validation and verification body performs a review to ensure it meets the ACR’s methodology requirements. (The ACR is a carbon crediting program that operates in the global compliance and voluntary carbon markets.) A completed project is only approved for carbon credit issuance after the review confirms that the abated emissions are real, measurable and permanent. After validation and verification, the ACR issues carbon credits that correspond to the verified reduction in methane emissions (in CO₂-equivalent terms). The ownership of these credits is due to an industry-specific land and legal program that ensures all rights, title and interest are addressed. The credits are then tradable or sellable in regulated or voluntary carbon markets.

Antis Convince Montour County to Reject Talen Data Center Rezoning - Marcellus Drilling News - Antis somehow got to the board of commissioners in Montour County, PA. Yesterday, the commissioners voted unanimously to reject Talen Energy’s request to rezone empty agricultural land near Talen’s Montour Power Plant (converted from coal to run on Marcellus gas in 2023) for a proposed data center. This decision followed community concerns stoked by lying groups like Food & Water Watch regarding “potential environmental impacts” on the nearby Montour Preserve.

Long-running Lawsuit Against XTO Energy Over Royalties in W. Pa.-- Marcellus Drilling News - We stumbled across a mention of a lawsuit (Kriley v. XTO Energy) that we previously were not aware of—a lawsuit that had its beginning back in 2019 and involves seven landowners in Butler County, PA. The landowners claim that XTO Energy (a subsidiary of ExxonMobil) systematically underpaid natural gas royalties. Over the past six years, the lawsuit has evolved and was certified as a class action in late 2025, meaning it has expanded from affecting seven landowners to potentially hundreds. XTO, in its latest court filing, is attempting to limit the class action.

Antis Flood PA DEP Hearing Against Drilling in Loyalsock Forest - Marcellus Drilling News - In December, MDN told you that three anti-shale drilling groups—the PA Council of Trout Unlimited, the Keystone Trails Association, and the Responsible Drilling Alliance—requested the Pennsylvania Department of Environmental Protection (DEP) hold a hearing on the Chapter 105 permit requested for a 3.9-mile shale gas access road and staging area proposed by PA General Energy (PGE) in the Loyalsock State Forest (see PA Antis Want DEP Hearing on 3.9-Mile Rd to Shale Pad in Loyalsock). The antis kept up the pressure. The DEP held a virtual public hearing on February 3 regarding PGE’s proposal to construct the shale gas access road. The hearing centered on Chapter 105 water quality permits. The PGE plan includes drilling 90 new shale wells in Loyalsock State Forest (Lycoming County).

Natural Gas Production Issues Linger in Appalachia After 17 Consecutive Days of Subfreezing Temps Even as natural gas production has rebounded across much of the country since Winter Storm Fern late last month, nearly 2 Bcf/d of freeze-offs are lingering in the Appalachian Basin where subzero temperatures have persisted for over two weeks. Line chart showing NGI’s Appalachia regional average daily natural gas prices from February 2025 through early February 2026, with prices mostly between $2/MMBtu and $5/MMBtu before a sharp winter spike above $70/MMBtu in late January 2026, followed by a rapid decline. At A Glance:

• Freeze-offs still at 1.8 Bcf/d
• Region sees historic stretch of cold
• Warmer temperatures forecast

M-U Pipes Including TGP Continue to Experience Major Restrictions - Marcellus Drilling News - We’ve recently begun actively tracking flow restrictions on pipelines that carry Marcellus/Utica molecules. Current pipeline flow data for February 2026 show that the Marcellus/Utica (M-U) region is experiencing significant, albeit weather-driven, volatility. While the basin remains a production powerhouse, a combination of recent Arctic weather and localized maintenance has triggered several flow restrictions, including a restriction along the Tennessee Gas Pipeline.

Nearly 75% of Planned On-Site Power at U.S. Data Centers is Natgas - Marcellus Drilling News - A Cleanview report reveals that nearly 75% of planned on-site power for U.S. data centers is natural gas-fired as operators bypass traditional grid connections. Driven by surging AI demands and grid delays of up to seven years, this trend involves 46 projects totaling 56 gigawatts. While developers publicly highlight renewables, immediate capacity remains dominated by gas due to its reliability. Development is concentrated in gas-rich regions like Texas and Pennsylvania. To overcome equipment shortages, some firms use creative solutions, such as repurposed jet engines. This shift underscores natural gas’s vital role in supporting the rapid expansion of American AI infrastructure.

New England Receives Another LNG Import Cargo as Winter Takes its Toll - The Excelerate Shenandoah delivered another full cargo this week from the Atlantic LNG terminal in Trinidad and Tobago to the Everett import facility in Boston Harbor as winter weather has stoked demand and kept prices elevated in the Northeast. Kpler vessel tracking shows Everett has received four cargoes this winter. It received another in September. The Shenandoah last unloaded a cargo at Everett Jan. 22. The terminal received six cargoes last winter.

Opposition to Iroquois Compressor in CT Includes Some Republicans - Marcellus Drilling News - - Residents in Brookfield, Connecticut, are leading a “bipartisan” campaign to block a $272 million expansion of the Iroquois Gas Transmission System, despite national efforts to boost fossil fuel infrastructure. The project would add two compressors to an existing station, primarily increasing gas flow to New York markets. Local officials and residents, including some Republicans, cite health and safety risks due to the facility’s proximity to homes and Whisconier Middle School. Although the project has tentative state support, opponents argue that environmental impacts and explosion risks outweigh regional energy benefits, particularly since Brookfield receives no direct supply increase from the expansion.

In Connecticut, opposition to Iroquois natural gas project crosses party lines - Expanding natural gas infrastructure is a centerpiece of President Donald Trump’s agenda to lower energy costs and boost the fossil fuel industry. He has referred to Democrats opposed to such projects as “ anti-energy zealots.” But political support for gas pipelines has run into powerful local opposition in a relatively conservative community in Connecticut, where residents are leading a campaign to block a $272 million buildout of the Iroquois Gas Transmission System. The epicenter of the debate is Brookfield, on the far edge of suburban Fairfield County, where Iroquois’ owners are seeking approval to add two new compressors to an existing station in order to push an additional 125 million cubic feet of gas through the pipeline each day, without having to lay new pipes. The project has received tentative support from the administration of Gov. Ned Lamont, a Democrat, and is awaiting final approval on air quality permits from the state. But beyond typical opposition from climate-focused organizations such as the Sierra Club and the League of Conservation Voters, the Iroquois project has also faced pushback from a bipartisan group of local officials, including members of the town’s Board of Selectmen and the town’s all-Republican statehouse delegation. During a public meeting on the project — which company representatives attended — in January, state Senate Minority Leader Stephen Harding, who represents Brookfield, said he lives just a few miles away from the compressor station. Harding echoed the concerns of many of his constituents regarding the compressor station’s proximity to nearby homes and a middle school. “These are health risks for our kids, for our families, these are environmental risks for everyone in our community,” Harding said. “This is being put up literally yards away from a school, a middle school, which my children are going to be attending. This needs a full, transparent process where every single one of my constituents, every single one of my neighbors have an ability to object to this.” And Harding made his own position clear. “This should not be approved in any circumstance,” he said. Similar sentiments can be seen in signs protesting the expansion that dot lawns around Brookfield, a mixture of rural and suburban neighborhoods adjacent to Candlewood Lake. The town narrowly voted for Trump in 2024 and has backed the Republican candidate in four of the last five presidential elections. Now, the town’s opposition to Iroquois’ plans have put local Republicans at odds with a key part of the national party’s energy agenda.The latest backlash in Brookfield follows a similar pattern of strong local resistance to energy infrastructure upgrades throughout Connecticut. Community opposition has delayed, threatened or led to the cancellation of projects to build new transmission lines, solar arrays,windmills, and battery storage facilities. While political leaders on both sides of the aisle often tout the benefits of energy expansion, their support tends to fade when local considerations come into play.

U.S. Factories Can’t Get Enough Natgas Due to Lack of Pipelines - Marcellus Drilling News - Despite record-breaking domestic production, U.S. manufacturers increasingly face gas shortages and price spikes during extreme weather. While the shale boom promised cheap energy, insufficient pipeline infrastructure prioritizes residential heating, power plants, and long-term export contracts over industrial users. This disparity forced companies like Evonik and International Paper to halt production or pay exorbitant spot prices during recent winter storms. Consequently, manufacturing trade groups are urging federal regulators to reform pipeline contracting and prioritize domestic supply over exports.

US gas producer's CEO is out, headquarters heading to Houston - US natural gas producer Expand Energy's chief executive Nick Dell'Osso is leaving the company immediately, while its headquarters is moving to the Houston area from Oklahoma City, it revealed Monday.Dell’Osso also will leave his post as a board member and will serve as an external adviser “for a period of time to ensure a smooth transition”, Expand said, without saying why the chief executive is departing. He will be replaced on an interim basis by board chair Michael Wichterich.The leadership changes were effective immediately and the headquarters move will happen in mid-2026, according to Expand.The chief executive's sudden departure comes after Expand had revealed last August in a filing with the US Securities and Exchange Commission that its chief financial officer, Mohit Singh, was departing “due to a termination without cause, effective August 13, 2025.” It designated Brittany Raiford, 39, as interim CFO, effective the same day. Raiford had been the company's vice president - treasurer since the merger, and had joined Southwestern in 2011. Expand operates primarily in the Haynesville, Marcellus and Utica shales. It produced about 7.33 billion cubic feet equivalent per day in the third quarter, about 92% of which was natural gas. Expand Energy formed in 2024, when Chesapeake Energy merged with Southwestern Energy for US$7.4 billion.

Williams weighs buying gas-producing assets to enhance AI energy supply to hyperscalers, sources say (Reuters) - Williams Companies is exploring buying natural gas production in the United States, a rare foray for an energy infrastructure operator, as it aims to secure natural gas supplies to support its one-stop-shop offering to hyperscalers and data center clients, three people familiar with the matter said.The Tulsa, Oklahoma-based firm has spent the last year positioning itself as a leader in providing energy to companies building out artificial intelligence infrastructure, supplementing its traditional pipeline business with new power generation capabilities. Williams is now searching for upstream assets that would allow it to pitch itself as a single energy partner to hyperscalers, the sources said, giving it a competitive advantage in courting digital infrastructure operators that would otherwise need to negotiate with multiple parties.The sources cautioned there was no guarantee that the company would move forward with the plan, and also spoke on condition of anonymity to discuss confidential deliberations.In a statement, Williams said it "continuously evaluates opportunities that align with and advance our natural gas-focused strategy", but declined to comment further. Securing the necessary power to support data centers has become one of the biggest challenges for hyperscalers and other developers of AI infrastructure.As well as needing huge amounts of consistent electricity, data centers are placing stress on a grid experiencing demand growth for the first time in two decades. Power providers are struggling to keep up, with existing generation affected by weather extremes and new projects stymied by local opposition and wait times for key power-plant components.Williams has put power generation at the heart of its strategic planning. Its $2 billion Socrates project in Ohio, due online in the second half of this year, has Meta Platforms buying the 440 megawatts of power it is due to generate. On October 1, Williams disclosed plans for two further power projects in Ohio, called Apollo and Aquila, backed by 10-year power purchase agreements with an unnamed party. Williams anticipates spending around $3.1 billion on these two projects, with both due online in the first half of 2027. Adding power projects to its existing infrastructure, which includes around 33,000 miles of pipelines carrying predominantly natural gas and associated storage assets, is expected to bolster its earnings in coming years.Williams' current target is to grow earnings before interest, taxes, depreciation and amortization (EBITDA) by between 5% and 7% annually. Analysts at UBS said in a February 4 note that they were watching to see whether Williams will increase this target to more than 7% compounded annual growth through 2030 at next week's analyst day. An integrated model, in which a U.S. oil and gas company would own a combination of production, storage, transportation and refining assets had been commonplace. However, the industry moved to favor specialization in the early part of the 21st century and most companies - outside of giants such as Exxon Mobil (XOM.N), opens new tab and Chevron (CVX.N), opens new tab - divested their non-preferred components. Williams spun off most of its upstream business into WPX Energy at the start of 2012. WPX remained independent until the beginning of 2021, when it completed a $12 billion merger with Devon Energy.

Global Buyers Seeking More U.S. Natural Gas Exposure Fueled 2025 M&A Activity -International buying in U.S. oil and gas upstream markets reached a seven-year high of $7.4 billion last year in a series of deals that helped drive mergers and acquisitions (M&A), according to Enverus Intelligence Research (EIR). Map Of Lower 48 Shale Plays Showing Major U.S. Basins Including Permian, Marcellus, Utica, Bakken, Eagle Ford, Haynesville, Niobrara, Anadarko, DJ Basin, Barnett, Appalachian Basin And Other Sedimentary Basins, Source Energy Information Administration (EIA). At A Glance:

• U.S. M&A hit $65B in 2025
• 4Q foreign investment reach $6B
• Canadian M&A strong too

Florida!!! – The Sunshine State Is a Heavyweight in Natural Gas Consumption | RBN Energy --Florida is the nation’s fourth-largest consumer of natural gas, but unlike the three states ahead of it — Texas, Louisiana and California — the Sunshine State produces virtually no gas of its own. And get this: Florida’s gas consumption has tripled over the past 25 years, mostly due to the development of nearly 30 gigawatts (GW) of new gas-fired power plants. That buildout spurred the expansion of existing gas pipelines and the construction of new ones. In today’s RBN blog, we examine Florida’s remarkable growth and whether additional pipeline capacity might be needed. This is an awesome time of year to go to Florida, so long as you’re OK with alligators, long lines at Walt Disney World and $38 hamburgers. Hurricane season is long past, the weather is balmy, and February is one of the driest months, so the odds are good that your round of golf or afternoon at the beach won’t be marred by a nasty thunderstorm. If you haven’t visited in a few years, you’ll be amazed at how crowded it is. The state is now home to more than 24 million (up from 16 million in 2000), and during the winter months “snowbirds” from up north swell the population by a million or so and shorter-term tourists add another half-a-mil, mostly in Orlando and along the coasts. All that growth — and the shift away from coal-fired generation to other sources — has helped to transform Florida’s energy profile, especially gas. Back in 2000, the state’s natural gas consumption averaged just under 1.5 Bcf/d; by 2024-25, usage had 3X’ed to more than 4.6 Bcf/d. Gas consumption there is heavily weighted toward power generation. As shown in Figure 1 below, an astonishing 87% (blue bar segments) is now used to fuel gas-fired combined-cycle and combustion-turbine units the state’s electric utilities have been building with abandon, mostly to keep pace with the double-headed monster of population growth and air-conditioning demand. The rest is split between industrial use (orange bar segments; 8%) and residential/commercial (res/comm; green bar segments; 5%). As we said in the introduction to today’s blog, Florida’s electric utilities, led by Florida Power & Light (FPL) and Duke Energy Florida, have been on a gas-plant construction binge for many years now, adding an average of more than 1 GW of new gas-fired capacity a year since the turn of the century. (Utilities also have been adding a lot of solar.) On an annual-average basis, the state’s gas generation fleet consumes about 4 Bcf/d, but (as you would expect) there is a strong seasonality to that use. During the summer months — especially July and August, when a potent combo of heat and humidity pushes many Floridians to the edge of sanity — power-plant gas use typically averages about 5 Bcf/d, or about 50% more than what’s consumed during the winter months, when AC demand is much less intense. The pipeline networks that transport gas to Florida from the Gulf Coast and, more recently, from Appalachia have been expanding in fits and starts since the turn of the century. Florida Gas Transmission (FGT; hot-pink line in Figure 2 below), co-owned by Kinder Morgan and Energy Transfer, is an interstate system whose initial run from Texas to Florida came online way back in 1959-60. FGT has been expanded several times over the intervening decades; it currently has more than 5,400 miles of pipe (including 3,000-plus miles within Florida) and a capacity of as much as 3.7 Bcf/d. The system’s most recent expansion was the East-West Project, which added 275 MMcf/d of bidirectional capacity — via looping, or construction of a parallel pipeline — in central Florida’s Osceola and Polk counties in 2019. FGT continues to supply about half of Florida’s gas needs. The state’s other two major long-haul delivery systems are the 1.3-Bcf/d Gulfstream Natural Gas System (Gulfstream; orange line) and the 1-Bcf/d Sabal Trail Pipeline (green line). Gulfstream, an undersea facility co-owned by Williams Cos. and Enbridge, was the first major interstate gas pipeline to Florida in more than 40 years when it started operation as a 1.1-Bcf/d conduit from Pascagoula, MS, to Port Manatee, FL, in 2002. Two extensions of the now-745-mile pipeline to Palm Beach County on Florida’s Atlantic Coast in 2005-08 coincided with a 200-MMcf/d expansion of Gulfstream’s capacity to its current 1.3 Bcf/d. With Florida’s demand for gas rising steadily through the 2010s — and with gas production in the Marcellus/Utica taking off — the trio of Enbridge (with a 50% stake), FPL (42.5%) and Duke Energy Florida (7.5%) developed the 515-mile Sabal Trail Pipeline, which runs from an interconnection with Williams’s Transcontinental Gas Pipeline (Transco; dark-blue line; see Don’t Stop Believin’) in west-central Alabama’s Tallapoosa County, AL, and flows to the Central Florida Hub in Osceola County, FL. The pipeline’s 830-MMcf/d Phase 1 began service in June 2017 and the 170-MMcf/d Phase 2, which expanded Sabal Trail’s capacity to 1 Bcf/d, started up in May 2020. (FPL and Duke are the anchor shippers.) The pipeline’s owners have been planning a 76-MMcf/d Phase 3 expansion of Sabal Trail for several years now, and finally expect to complete it in Q2 2027. The other major addition to Florida’s gas grid over the past several years is FPL’s Florida Southeast Connection (burgundy line), a 126-mile, 640-MMcf/d pipeline from the Central Florida Hub (the terminus of Sabal Trail mentioned just above) to FPL’s Martin County generating station, where the utility operates about 2,200 MW of gas-fired combined-cycle capacity. Like Sabal Trail, the Florida Southeast Connection came online in June 2017. Two years later, FPL added a 5-mile lateral (not shown) to its then-new Okeechobee station, which has 1,720 MW of combined-cycle capacity. (We should note here that most of Florida’s gas-fired plants were designed and built to run on other fuels — typically diesel — when gas is not available.) Figure 3 below shows gas flows into Florida on the three main pipelines into the state: FGT (left graph), Gulfstream (center graph), and Sabal Trail (right graph). Each of the three systems appears to have ample capacity during the shoulder and winter months but approach their capacity during the peak summer demand periods.

U.S. Propane Posts Strong Draw as Inventories Remain Elevated --U.S. propane/propylene inventories posted a 5.4 MMbbl draw for the week ended February 6 — outpacing industry expectations for a 4.2 MMbbl decline and topping the five-year average draw of 3.6 MMbbl by 1.8 MMbbl. Despite the stronger-than-normal pull, total stocks remain historically elevated at 77.3 MMbbl, standing 18.4 MMbbl (31%) above the same week last year, 10.9 MMbbl (17%) above the five-year maximum, and 22.2 MMbbl (40%) above the five-year average. The weekly draw trimmed inventories, though overall stock levels remain historically high. Total U.S. propane/propylene production rose by 334 Mb/d week over week to about 2.7 MMb/d, reflecting a rebound following winter storm disruptions. Meanwhile, weekly propane exports averaged 1.87 MMb/d, down 46 Mb/d from the prior week and falling below both the year-to-date average of 1.94 MMb/d and the four-week average of 1.92 MMb/d. Even so, export volumes remain well above the 1.66 MMb/d reported during the same week last year.

Small Town – Mom-and-Pop Shops Remain the Heart of the Retail Propane Industry | RBN Energy - The retail propane market delivers about 9 billion gallons to U.S. consumers each year, with its heart anchored in the “mom-and-pop” retailers serving rural and small-town communities. These small, owner-operated businesses — the backbone of the market — know their customers, regions and their challenges, which is a key reason the propane industry is thriving and has avoided the sweeping consolidation seen in so many other sectors of the small-business economy. In today’s RBN blog, we’ll examine why the small-business model has been so durable and effective in retail propane, and why the industry has seen relatively little large-scale consolidation.. Winter Storm Fern hit parts of the country with some of the toughest conditions in recent memory, as bitter cold drove high demand and snow and ice made transportation very difficult. Plus, there were freeze-offs and refinery issues cutting into supply. We can’t publish a propane blog so soon after the storm without acknowledging the industry’s strong performance under pressure. The industry deserves kudos for a job well done, but it’s not quite spring yet. There is still some winter left. We’ve written a lot about the propane industry and its structure in recent months. In Part 1 of our propane series, we outlined the journey of propane from wellhead to burner tip and discussed the various segments of the domestic market, including industrial, petrochemical, commercial, residential and agricultural demand. The wholesale-to-retail value chain starts at processing plants and refineries (left column of Figure 1 below), where propane is extracted and often placed into underground storage. In Part 2, we detailed the role of wholesalers (middle column), the companies that sell propane to retailers by aggregating supplies, operating logistics networks, trading physical volumes, and other supply functions. Wholesalers help move propane through pipelines and railcars to retailers (right column), which range in size from small, owner-run operations serving a local market to companies with fleets of railcars and dozens of supply points. In Part 3, we outlined retailers’ roles and functions in the market. Today, we take a deeper look at propane retailers and why even smaller and midsized operations have been able to thrive without the large-scale consolidation seen in many other markets. About 8.8 billion gallons of propane were sold in the U.S. in 2024. Last year, 2025, total sales will probably be closer to 9 billion gallons when the final numbers come in. (For those of you who think in barrels, that’s 587 Mb/d.) We carve up the retail market into the following three buckets: The top 11 retailers sold 3.2 billion gallons total, or about 290 million gallons each, accounting for 36% of the market. The next 64 retailers sold 1.1 billion gallons, or about 17 million gallons each, and accounted for 12% of the market. The remaining 3,880 retailers sold the final 4.7 billion gallons, or 1.2 million gallons each. So, more than 50% of the market is supplied by small retailers, which may look striking on paper, but it comes as no surprise to anyone with even a passing familiarity with the retail propane business. This is how the business has always worked — going back to when grandpa started a small retail propane operation decades ago. Let’s look at a graphic that brings the point home, using data from 2024. Figure 2 below illustrates the numbers more clearly and shows the relative size of the nearly 4,000 propane retailers by sales volume, comparing the top 75 retailers (colored boxes) with the remaining small-market players (gray boxes). The top two retailers (boxes 1-2) serve as much of the market as the next eight retailers (boxes 3-10), which serve as much of the market as the following 34 retailers (boxes 11-45) and so on. Looking at it this way paints a clear picture of the leadership position played by the small retail players. One advantage large propane retailers have is the ability to leverage economies of scale, allowing them to bulk-purchase propane while benefiting from centralized operations and lower per-unit costs, potentially enabling more competitive pricing. Large retailers also provide operational advantages — such as advanced logistics, automated routing and optimized delivery systems — which further increase efficiency and reduce costs. Larger retailers also tend to have a broader geographic reach and the ability to serve larger, more diverse markets, including commercial and industrial users as well as the typical residential customer, and also have greater access to capital, allowing investments in technology, infrastructure and acquisitions. Finally, a large retailer such as Suburban Propane or Ferrellgas has brand recognition that can build customer trust and attract larger accounts. Given all those advantages, why do so many smaller retailers not only survive but thrive? The propane industry supports nearly 3,900 of these small businesses, many of them family-run operations passed down through multiple generations. These companies have deep roots in their communities, long-standing customer relationships that often span decades, and a reputation for highly personal service. In rural and small-town markets — especially during outages, extreme weather, and emergencies — local knowledge, trust and responsiveness can be more valuable than scale. Further, much about the retail propane industry doesn’t lend itself to economic models that attract venture capital or aggressive merger-and-acquisition “roll up” strategies. This business is shaped by weather-driven demand, local relations and steady, disciplined margins that favor operators who know their customers personally. It’s a lot like the way families once knew their milk delivery driver. They knew when they’d arrive and where they left the bottles. In many communities, it’s the same way for propane. Customers don’t just recognize the propane truck; they might even know the driver. Most importantly, they always know someone will consistently show up, even when it’s bitterly cold outside.

U.S. Feedgas Demand Strengthens - U.S. LNG feedgas demand rebounded sharply last week as Gulf Coast terminals returned to peak winter operations following Winter Storm Fern. Feedgas demand was up more than 2 Bcf/d last week to average 18.7 Bcf/d (see blue dotted line in figure below). All the Gulf Coast terminals are back to pre-storm, peak winter levels. Feedgas intake at Sabine Pass is especially strong, mostly above 5 Bcf/d since January 30.Cove Point and Elba Island, the non-Gulf terminals, are both operating below full capacity. It remains very cold in the Northeast, and prices in the Northeast and Southeast are elevated and well above Henry Hub, incentivizing the sale of feedgas back into the domestic market. Temperatures are expected to climb in the two-week forecast, which should normalize prices and LNG feedgas intake. For more insights on the U.S. LNG industry, check out our LNG Voyager Weekly Report.

Pipeline Data Signals Sharp Rebound in LNG Feed Gas Demand* A look at the global natural gas and LNG markets by the numbers.NGI North America LNG Export Flow Tracker shows U.S. LNG deliveries by terminal as of Feb 11, 2026, with daily export volumes in million Dth, facility utilization rates and map of export locations. Source: NGI, Wood Mackenzie data.

• 19.3 Bcf/d: Feed gas nominations to U.S. LNG terminals have reportedly swung back with a vengeance, according to pipeline data, indicating exporters could be looking to make up for lost time during the winter storm. Wood Mackenzie estimated nominations could reach 19.3 Bcf/d Wednesday and average 18.7 Bcf/d in the coming seven days. The firm noted the persistent rise over the past few days “has been driven by the largest feedgas nominations we have ever seen” at East Coast terminals, but cautioned that those numbers could be revised in a later cycle.
• 45%: LNG inventories at Cameron LNG are building to the highest point in more than seven months as feed gas nominations to the plant run near maximum capacity, according to pipeline and Kpler data. Inventories at the facility reached 45% of capacity this week, with 1,229 GWh — around 4 Bcf — in storage, according to Kpler. It could be the highest point reported since last June. The build comes as feed gas nominations to the Cameron LNG receipt point continue to hover at 99% of capacity for the 11th day in a row, according to Wood Mackenzie pipeline data.
• 6 Mt: Taiwan’s state-owned CPC Corp. plans to increase U.S. LNG imports as a part of a trade deal with the United States, according to Reuters and the Taipei Times. Taiwan plans to increase its intake of LNG from the United States to 6 million tons/year (Mt/y), boosted by volumes from the developing Alaska LNG project. Taiwanese imports of U.S. LNG reached an all-time high of 2.57 Mt last year, according to Kpler data. However, the country continues to get the majority of its supplies from Qatar and Australia, respectively.
• 6%/year: The International Energy Agency’s latest data drop for European Union (EU) electricity markets shows natural gas is still an important part of the grid, but the buildout of renewables is outpacing gas consumption. IEA estimated gas demand in the EU could decline 6%/year through 2030, despite a boom in LNG exports. Part of the decline is attributed to efficiency gains and economic impacts to the power market following the 2022 invasion of Ukraine. EU electricity demand isn’t expected to surpass pre-2022 levels until 2028, according to IEA.

Survey Finds Big LNG Buyers Changing Strategy to Short-Term Deals - Marcellus Drilling News - McKinsey & Company’s 2025 LNG Buyers Survey (full copy below) reveals a strategic shift toward flexibility and risk mitigation as global markets stabilize with upcoming supply from North America and the Middle East. Faced with geopolitical uncertainty, buyers are prioritizing supply diversification and flexible contract terms, specifically regarding destination and volume. While demand is expected to rise in Asia due to price-sensitive coal-to-gas switching, European demand will likely decline as renewables expand. To manage volatility, 70% of buyers are pursuing a mix of short- and long-term contracts (instead of just long-term). Overall, the survey emphasizes that adaptive procurement strategies are essential for navigating today’s evolving energy landscape.

Aramco Signs 20-Year LNG Deal With Caturus, Advancing Commonwealth Toward FID -- Caturus Energy LLC has solidified a long-term LNG supply deal with Saudi Arabian Oil Co. (Aramco), pushing its Louisiana export project closer to a final investment decision (FID) in the coming months, according to the company. At A Glance:

• Up to 1 Mt/y contracted
• Project now 84% subscribed
• Deal supports Aramco trading ambitions

Delfin LNG Potentially Facing Delays as Regulatory Hurdles Mount, Lawsuit Filed After Pipeline Failure -- Developers of the Delfin LNG export project in Louisiana will have to navigate additional regulatory scrutiny and possible delays as federal orders and lawsuits crop up following a pipeline explosion. Map of the Delfin LNG Project in the Gulf of Mexico showing offshore floating LNG vessels (FLNGs) connected by pipelines to Port Delfin Deepwater Port, UTOS pipeline route, WC 167 and WC 327 blocks, onshore facilities and compressor station along the Texas Gulf Coast near Louisiana.At A Glance:
Restart pressure capped at 20%
Hydrostatic test outcome critical for FID
Lawsuit adds legal risk exposure

Cheniere Locks in LNG Vessel Charters as U.S. Export Growth Tightens Shipping Capacity -Cheniere Energy Inc.’s marketing unit has clinched more shipping capacity for its expanding portfolio of Gulf Coast exports as the U.S. LNG boom ushers in a squeeze on carrier supply. At A Glance:

• Cheniere contracts align with capacity growth
• Carrier shortage pressures global gas traders
• LNG carrier build times drive urgency

LNG Buyers Seek Short-Term Deals, Caps on Volumes From Single Sellers in Push to Diversify Supplies --Global buyers plan to continue signing contracts for additional LNG volumes in the coming years, with more of them aiming for short-term deals as they work to diversify supplies and enhance flexibility after energy flows were upended by the war in Ukraine, according to McKinsey & Co. Stacked bar chart showing global LNG export terminal final investment decisions by country from 2014 through 2025, measured in Bcm/y, highlighting major contributions from the United States, Qatar, Russia, and other LNG-producing nations. At A Glance:
Prices expected to stabilize by 2030
Buyers value flexible purchase volumes
Asian buyers want more partnerships

US natural gas exporters brace for global glut - The liquefied natural gas export industry in the United States could be riding a wave of growth into choppy waters. A big LNG plant is about to open in Texas, another is set to start a new production line in the state and one of the largest export facilities in North America is set to deliver a full year of production outside New Orleans.On top of that, companies approved plans for a record-breaking six more LNG projects in 2025, indicating the growth isn’t slowing down anytime soon.The domestic surge — along with new facilities in other countries such as Canada and Qatar — is raising concerns of a global oversupply of natural gas that could drive down prices abroad and create financial headwinds for the U.S. LNG industry.And some analysts warn that LNG exports are driving up utility bills for U.S. households — an issue that could that become a political liability. Federal officials say LNG drove a sharp increase in the benchmark price of natural gas in 2025, but projections are that the price won’t surge again until after November’s midterm elections.The question for the industry is what happens to domestic prices as exports divert nearly one-fifth of U.S. gas production overseas and whether global demand can absorb all of that supply.“That’s where the rubber meets the road,” said Ira Joseph, an analyst who tracks gas and power markets at Columbia University’s Center on Global Energy Policy. “How is the market going to absorb such a large amount of LNG in such a short period of time?”The answer depends on a dizzying array of possibilities driven by how markets react to any oversupply, he said. Will U.S. gas producers cut back, or will low prices motivate more countries to use gas, driving up demand and prices. Both are likely, and the result will be determined by timing.“There’s this dance between supply and demand that happens over time,” said Dan Byers, vice president for policy at the U.S. Chamber of Commerce’s Global Energy Institute.While the expected glut will probably cause temporary turbulence for LNG exporters, Kenneth Medlock, an energy economist at Rice University’s Baker Institute for Public Policy, said the industry will continue to grow in the long term.“In the industrial sector, the demand for natural gas is going to keep rising,” Medlock said. “A lot of those places where it’s rising are in developing economies where they don’t have a lot of gas resources, so they’re going to need LNG.”Medlock said the industry also hit a soft spot in 2017 and 2018, when customers were wary of signing long-term contracts. But the end of the Covid-19 pandemic and Europe’s shift away from Russian gas after the 2022 invasion of Ukraine drove a surge in demand and made LNG a significant part of the U.S. economy.Federal energy forecasters have been saying for some time that LNG exports are putting upward pressure on utility prices.But 2026 could be a lull, as the U.S. Energy Information Administration forecasts that the average U.S. benchmark price of gas will stay steady or drop slightly this year. On Friday, U.S. gas futures were trading for about $3.50 per million British thermal units.Last year, LNG and weather drove a 50 percent rise in the average benchmark natural price, according to EIA, as political concerns about affordability and power prices also surged. Still, the 2025 average price, $3.52 per MM Btu, was still far below the average in 2022, $6.45 per MM Btu, when Russia’s invasion of Ukraine caused oil and gas prices to skyrocket.In 2027, EIA forecasts that LNG exports and data centers will again outpace production and push the average price of gas above $4.50 per MM Btu, an increase over 2025 of more than 30 percent.That would be another punch in the wallet for American ratepayers. According to the American Gas Association, the cost of natural gas made up about 41 percent of the average household gas bill as of 2024.

Aramco Signs 20-Year LNG Deal With Caturus, Advancing Commonwealth Toward FID -- Caturus Energy LLC has solidified a long-term LNG supply deal with Saudi Arabian Oil Co. (Aramco), pushing its Louisiana export project closer to a final investment decision (FID) in the coming months, according to the company. At A Glance:

• Up to 1 Mt/y contracted
• Project now 84% subscribed
• Deal supports Aramco trading ambitions

Delfin LNG Potentially Facing Delays as Regulatory Hurdles Mount, Lawsuit Filed After Pipeline Failure -- Developers of the Delfin LNG export project in Louisiana will have to navigate additional regulatory scrutiny and possible delays as federal orders and lawsuits crop up following a pipeline explosion. Map of the Delfin LNG Project in the Gulf of Mexico showing offshore floating LNG vessels (FLNGs) connected by pipelines to Port Delfin Deepwater Port, UTOS pipeline route, WC 167 and WC 327 blocks, onshore facilities and compressor station along the Texas Gulf Coast near Louisiana.At A Glance:
Restart pressure capped at 20%
Hydrostatic test outcome critical for FID
Lawsuit adds legal risk exposure

US natural gas futures fall more than 8% on milder forecasts (Reuters) - U.S. natural gas futures fell by more than 8% on Monday on forecasts for milder weather than previously expected for the rest of the month, erasing the previous session's gains. Gas futures for March delivery on the New York Mercantile Exchange fell 28.4 cents, or 8.3%, to $3.138 per million British thermal units (mmBTU). On Friday, the contract hit a session high of $3.659 per mmBtu. "The strong gas price advance through most of last week was obviously reversed by continued above normal temperature forecasts that have been extended into the last week of this month," Meteorologists forecast warmer than normal temperatures nationwide through February 23, with Heating Degree Days falling from 374 on Friday to 358 on Monday. HDDs measure energy demand to heat buildings. Colder weather earlier in the winter in the U.S. drove heavy withdrawals from underground storage, but forecasts now point to easing demand. A Reuters poll shows U.S. utilities likely withdrew 249 billion cubic feet (bcf) of gas in the week ended February 6. This compares to a record 360 bcf pulled out of storage during the week ended January 30 to meet surging heating demand during an Arctic blast, putting stockpiles on track to drop from around 5% above normal during the week ended January 23 to around 6% below normal during the week ended February 6. LSEG said average gas output in the Lower 48 states climbed to 106.99 billion cubic feet per day (bcfd) so far in February, up from 106.3 bcfd in January. That compares with a monthly record high of 109.7 bcfd in December. LSEG projected average gas demand in the Lower 48 states, including exports, would fall from 142.5 bcfd this week to 130 bcfd next week. Average gas flows to the eight large U.S. LNG export plants rose to 18.3 bcfd so far in February, up from 17.8 bcfd in January. That compares with a monthly record high of 18.5 bcfd in December. "While we continue to cite an expected upswing in export activity to a record pace in the coming weeks/months, recent patterns strongly suggest that this increase in demand could be countered by stronger production now that well freeze-offs are being largely taken off the table as winter begins to wind down," Ritterbusch added. Dutch and British wholesale gas prices also fell on Monday morning on forecasts for milder temperatures

Natural gas price slips again as warm U.S. forecasts linger - U.S. natural gas futures slipped again Tuesday morning, following up on losses from the previous session as warmer weather projections pressured prices. By 6:15 a.m. EST, the March contract had fallen 2.3 cents, or 0.7%, to $3.115 per million British thermal units (mmBtu). (Investing.com)The pullback is grabbing attention as traders scramble to factor in the remainder of winter. January’s swings set the stage—now, upcoming weather-model updates and storage numbers will drive the outlook for heating demand and the pace of inventory changes.March futures tumbled over 8% in early action Monday, giving up the previous session’s gains as forecasts turned milder for the rest of the month, Reuters reported. Meteorologists now expect above-normal temperatures across the U.S. through Feb. 23, driving heating degree days (HDDs) down from 374 to 358. LSEG kept Lower 48 natural gas output at 106.99 billion cubic feet per day (bcfd) so far in February, and sees total demand—including exports—shrinking from 142.5 bcfd this week to 130 bcfd next week. Feedgas flows to U.S. LNG export plants, meanwhile, edged up to 18.3 bcfd. (BOE Report)The storage overhang from the last major benchmark surprise hasn’t faded just yet. As of Jan. 30, working gas inventories in the Lower 48 clocked in at 2,463 billion cubic feet (bcf). Traders now look to the next official tally, due out Feb. 12 at 10:30 a.m. Eastern—as always, that’s a Thursday. (EIA)LNG links the global market back to U.S. gas flows. Chinese LNG imports should see a mild bump in 2026 as increased supply drags prices lower. Still, analysts warn that demand could remain tied to price, facing stiff competition from cheaper pipeline and domestic gas. That could limit any big gains for spot LNG—and U.S. exports along with it. “Even if prices fall in 2026, LNG still can’t compete with domestic or imported pipeline gas,” said Xiong Wei at Rystad. Yuanda Wang at ICIS echoed a note of caution, adding that “how much extra demand a lower price can stir remains debatable.” (Reuters)Cash prices can bolt when a cold snap rolls in, as the market knows all too well. Equinor CFO Torgrim Reitan told Reuters the firm kept around 30% of its U.S. onshore gas linked to spot pricing during January’s chill, selling some flows into New York for “more than $100 per MMBtu.” Benchmark prices eventually eased off. (Reuters)Bulls face a clear risk here: should the warmer pattern persist, late-winter demand eases off, and production doesn’t budge, the market could end up drawing less from storage and pushing prices down. Add to that the possibility of LNG feedgas flows stumbling, or the shoulder season kicking in ahead of schedule, and downside pressure only builds.Weather risk is the wild card here. A burst of cold hitting key cities could quickly drive HDDs up. Freeze-offs remain a threat to production, which could squeeze supply right when export demand holds steady. Traders are glued to daily output projections and LNG feedgas numbers this week, but the date circled on calendars is Feb. 12 for the U.S. storage report, followed by another set of late-February forecast updates.

US natural gas futures edge up with LNG export surge (Reuters) - U.S. natural gas futures edged up on Wednesday on near-record flows to liquefied natural gas export plants. Gas futures for March delivery NGc1 on the New York Mercantile Exchange rose 4.4 cents, or 1.4%, to settle at $3.159 per million British thermal units (mmBTU). On Tuesday, the contract closed at its lowest since January 16 for a second day in a row. That small price increase came despite forecasts for warmer weather and lower demand next week than previously expected. In the cash market, meanwhile, average prices at the Waha Hub in the Permian Basin in West Texas remained in negative territory for a fifth day in a row and the 14th time this year, as pipeline constraints trapped gas in the nation's biggest oil-producing basin. Daily Waha prices first fell below zero in 2019. They did so 17 times in 2019, six times in 2020, once in 2023, a record 49 times in 2024, and 39 times in 2025. Waha prices have averaged $1.49 per mmBTU so far this year, compared with $1.15 in 2025 and a five-year average (2021-2025) of $2.88. Financial firm LSEG said average gas output in the Lower 48 states has climbed to 107.5 billion cubic feet per day (bcfd) so far in February, up from 106.3 bcfd in January. That figure compares with a monthly record high of 109.7 bcfd in December. After extreme cold over the past couple of weeks, meteorologists projected weather across the country would remain mostly warmer than normal through February 26. Energy firms pulled a record 360 billion cubic feet of gas out of storage during the week ended January 30 to meet surging heating demand during an Arctic blast, cutting stockpiles to around 1% below normal levels for this time of year. Continued cold weather last week likely cut inventories further to around 6% below normal during the week ended February 6. Energy analysts, however, noted mild weather expected over the next few weeks could wipe out much of that storage deficit by early March. Energy firms stockpile gas during the summer (April-October) when demand is generally lower than daily output and pull that gas out of storage during the winter (November-March) when demand for heating is usually higher than daily output. LSEG projected average gas demand in the Lower 48 states, including exports, would fall from 141.2 bcfd this week to 124.6 bcfd next week. The forecast for next week was lower than LSEG's outlook on Tuesday. Average gas flows to the eight large U.S. LNG export plants have risen to 18.5 bcfd so far in February, up from 17.8 bcfd in January. That reading compares with a monthly record high of 18.5 bcfd in December.

US natgas futures rise 2% on near-record LNG export flows, big storage withdrawal (Reuters) - U.S. natural gas futures climbed 2% on Thursday on near-record flows to liquefied natural gas export plants and a federal report showing energy firms pulled more gas than usual out of storage for a second week in a row to meet surging heating demand during a lingering Arctic freeze. Gas futures for March delivery NGc1 on the New York Mercantile Exchange rose 5.8 cents, or 1.8%, to settle at $3.217 per million British thermal units. After pulling a record 360 billion cubic feet of gas from storage during the week ended January 30, energy firms pulled 249 bcf from stockpiles during the week ended February 6, the U.S. Energy Information Administration said on Thursday. That was smaller than the 257-bcf withdrawal analysts forecast in a Reuters poll but much bigger than the decline of 111 bcf during the same week last year and a fiveyear (2021-2025) average withdrawal of 146 bcf for the week. In the cash market, average prices at the Waha Hub in the Permian Basin in West Texas remained in negative territory for a sixth day in a row and the 15th time this year, as pipeline constraints trapped gas in the nation's biggest oil-producing basin. Financial firm LSEG said average gas output in the Lower 48 states climbed to 107.6 billion cubic feet per day so far in February, up from 106.3 bcfd in January. That figure compares with a monthly record high of 109.7 bcfd in December. After extreme cold over the past couple of weeks, meteorologists projected weather across much of the country would remain mostly warmer than normal through at least February 27. With last week's storage withdrawal, stockpiles fell from around 1% below normal levels for this time of year during the week ended January 30 to around 6% below normal during the week ended February 6. Energy analysts, however, noted mild weather expected over the next few weeks could wipe out much of that storage deficit by early March. LSEG projected average gas demand in the Lower 48 states, including exports, would fall from 141.3 bcfd this week to 124.0 bcfd next week. The forecast for next week was lower than LSEG's outlook on Wednesday. Average gas flows to the eight large U.S. LNG export plants have risen to 18.5 bcfd so far in February, up from 17.8 bcfd in January. That reading compares with a monthly record high of 18.5 bcfd in December.

Danaos sees need for up to 10 Alaska LNG carriers - Greek container vessel owner Danaos Shipping may need to order up to ten liquefied natural gas carriers to serve Glenfarne's Alaska LNG project, according to Danaos CEO John Coustas. The exact number of vessels to be employed will depend on how far exported natural gas volumes will be transported.

WTI Crude-to-Gas Ratio Rebounds in February - -The NYMEX crude-to-gas ratio for February 2026 to date — shown by the green bar in the chart below — has risen to 18.5, up from 15.6 in January. February crude is averaging $63.78/bbl, while Henry Hub gas is averaging $3.48/MMBtu. Despite the month-over-month increase, the ratio remains slightly below year-ago levels, compared with 19.5 in February 2025 — shown by the red bar — when crude averaged $71.18/bbl and gas $3.69/MMBtu. Overall, the ratio is up about 18% from January but still roughly 5% lower year-on-year.

Bearish Fundamentals Lift Crude Oil and Motor Gasoline Inventories - According to the EIA’s Weekly Petroleum Status Report (WPSR) released this morning for the week ended February 6, crude balances tilted bearish as rebounding U.S. production, stronger imports, and softer exports combined with lower refinery runs to drive a sizeable commercial inventory build. As discussed in our Crude Billboard, U.S. commercial crude inventories increased by over 8.5 MMbbl to 429 MMbbl. Although this fell short of the 13.4 MMbbl build projected by the API survey results, it marks the largest weekly stock build since the same week in 2025. PADD 3 accounted for the bulk of the increase, with inventories rising by more than 5.8 MMbbl, reinforcing the view that Gulf Coast balances bore the brunt of the week’s bearish fundamentals. Smaller builds were observed across all other PADD regions. On the products side, gasoline inventories also moved higher, climbing to 259 MMbbl (far right of red line below), their highest level since May 2020, with builds seen in PADDs 1, 2, 4, and 5.

How Cold Weather Impacts Refinery Margins & Prices ---A wave of frigid Arctic air gripped much of the United States in late January and early February, shocking national energy markets. This cold snap demonstrated how interconnected the modern energy system is and how quickly market conditions can change. Here are four ways the extreme winter weather impacted diesel supply and pricing. As temperatures fell into single digits and even negative territory across the country, demand for heating fuels like natural gas, heating oil, and diesel fuel rose sharply. According to the National Oceanic and Atmospheric Administration (NOAA), the nation experienced a period of sustained cold, which created immediate stress across the energy market. This initial surge in consumption was the first domino to fall, creating higher demand and tightening supply across all heating fuels. One of the most significant consequences of the cold was the spike in natural gas demand for residential and commercial heating. This prioritization tightened supply for power generators just as overall electricity demand soared. When natural gas becomes expensive or constrained, utilities with dual-fuel capabilities often switch to diesel to maintain grid reliability. Approximately 13 percent of U.S. power generation capacity, about 138 gigawatts, can run on either natural gas or diesel. This fuel switching, especially common in the pipeline-constrained Northeast, placed additional pressure on already tight distillate markets and contributed to rising prices.. Winter storms forced refinery capacity being taken offline. Cold weather can cause significant disruptions for a refinery. Freezing temperatures can lead to mechanical failures, power interruptions, and equipment malfunctions. To prevent long-term damage, refineries, especially those in warmer climates like the Gulf Coast that are not winterized, are often forced to reduce production or shut down temporarily. While demand was rising, winter storms delivered heavy snow and freezing rain that disrupted production. These conditions are especially challenging for refinery operations, particularly in the Gulf Coast and Midwest. Refining facilities are not designed to operate in extreme cold. When equipment begins to ice over, production is often reduced or temporarily shut down. Freezing conditions caused mechanical failures, power interruptions, and precautionary shutdowns. Across the affected regions, the refineries impacted by these outages represent approximately 1.3 to 1.4 million barrels per day of refining capacity. This sudden reduction in operational capacity occurred at the exact moment demand was peaking. The combination of rising demand and falling supply made a quick appearance in refinery margins. This margin—the difference between the cost of crude oil and the commodity value of diesel—represents the cost of turning crude into a usable product and accounts for roughly 25 to 27 percent of the price of diesel. In January, refinery margins surged from around $30 per barrel to well over $48 per barrel, a level not seen since the previous November. This rapid increase pushed wholesale diesel prices back above $3 per gallon. Although temperatures have moderated and provided some short-term relief, the structural dynamics of the fuel market suggest continued volatility. The U.S. and Europe are experiencing a multi-year decline in refining capacity as facilities permanently close or convert to renewable production. Recent and upcoming closures, like those in California, are reducing the nation’s ability to meet distillate demand, especially during periods of disruption. The events of this winter serve as a clear reminder that in a more constrained refining environment, weather events like those we experienced in January can have an outsized impact on fuel markets. For shippers, staying informed on these trends is essential for navigating the complexities of fuel procurement and managing transportation spend.

Fuel – The Pipelines, Tankers and Trucks That Move Refined Products to the Lower Half of PADD 1 - There’s a staggeringly large disconnect between the vast volumes of gasoline, diesel and jet fuel consumed within the six states in EIA’s PADD 1C subregion — Florida, Georgia, South Carolina, North Carolina, Virginia and West Virginia — and the truly paltry amounts of transportation fuels produced there. That dichotomy spurred a multi-decade buildout of what are now highly efficient pipeline, marine and trucking networks that now deliver about 1.3 MMb/d of refined products to what EIA refers to as the “Lower Atlantic” states. In today’s RBN blog, we’ll discuss these networks and explain how they keep the region running. The half-dozen states in PADD 1C have a combined population of more than 60 million and a GDP of more than $4 trillion. That puts the Lower Atlantic region on par with the U.K. or France or Italy — in other words, a real economic powerhouse. But PADD 1C has only one small refinery within its borders, a 23-Mb/d facility at the northern tip of West Virginia’s panhandle that focuses on lubricant production and markets virtually all of its modest gasoline and diesel output very locally. That’s a roundabout way of saying that the region needs to pipe, truck, tanker or barge in more than 99.9% of the gasoline and diesel it consumes, as well as literally every drop of jet fuel. (Ergon Refining’s Newell, WV, refinery doesn't typically make any “jet,” as the refined, kerosene-based fuel is commonly referred to.)As we said in the introduction, the volumes that need to be hauled in are significant. Florida is the #3 consumer of gasoline in the U.S., behind only California and Texas, and Georgia (#5), North Carolina (#6) and Virginia (#11) aren’t far behind. It’s a similar story for diesel, with Florida trailing only Texas and California (in that order), and as for jet fuel, Florida — a top tourist destination with a slew of busy airports — is #2, bested only by California. (Ironically, as you’ll see, Florida is the only state in PADD 1C that depends almost entirely on barged-in and trucked-in volumes of refined products — its portfolio of pipelines is very limited.) The vast majority of the refined products consumed in the Lower Atlantic states are produced at refineries in Texas and Louisiana and piped through the spine of PADD 1C through two pipeline systems: the Colonial Pipeline and the Products (SE) Pipeline, the latter of which used to be called the Plantation Pipeline. (Note: The latest edition of our Future of Fuels report, coming out in just a few days, provides a detailed forecast for how PADD-to-PADD movements are expected to change on an annualized basis out to 2050.) The 2.5-MMb/d Colonial Pipeline, which started operating in 1963, is a roughly 5,500-mile system whose main route (dark-blue line in Figure 1 below) runs from Houston to Linden, NJ, and has several spurs or laterals (light-blue lines) that pipe fuel to key consumption areas. The main route consists of four distinct pipeline sections: two pipes from Houston to Greensboro, NC, and two pipes from Greensboro north — one that runs to the Baltimore area and another that terminates in northern New Jersey. Since July 2025, Colonial has been owned by Brookfield Infrastructure Partners, which paid previous co-owners KKR, Koch Industries, CDPQ (Quebec’s largest pension fund), Shell Midstream, and IFM Investors $9 billion for the massive asset.Colonial’s operators traditionally have dedicated one of the system’s two Houston-to-Greensboro pipelines to transporting gasoline and the other to moving middle distillates (diesel and jet fuel). At Greensboro, these products go into breakout tanks; from there they are sent in batches further through the system. (See Refined, Piped, Delivered, They’re Yours for an explanation of how batching works.) As we said, there are a few spurs off Colonial — north into Tennessee, south to central and southwestern Georgia, east in North Carolina to Raleigh/Durham, and east and west in Virginia to Richmond, Norfolk/Virginia Beach, and Roanoke. Along Colonial’s route there are more than 20 delivery points (orange triangles) as well as four major refined product terminals owned by the pipeline system (yellow tank icons).The Products (SE) Pipeline (purple line in main map in Figure 2 below) — the SE stands for Southeast — is smaller but still quite large, with about 3,100 miles of pipe and a capacity of 660 Mb/d. Jointly owned by Kinder Morgan (with a 51% stake) and ExxonMobil (49%), the pipeline formerly known as Plantation runs from near Baton Rouge, LA, to northern Virginia (close to Washington, DC). The pipeline’s history goes back to the start of World War II; the initial Louisiana-to-Greensboro, NC, section started operating in January 1942, moving 48 Mb/d for four customers. (As we said 10 years ago in Move It on Over, the new pipeline was seen as being a genius move: Japan had just attacked Pearl Harbor, German submarines were sinking tankers off the East Coast, and U.S. railroads — the other alternative for transporting gasoline, etc. — were operating flat-out to move freight and troops.)The pipeline’s capacity has been expanded repeatedly since WWII, and in 1964 it was extended to northern Virginia. Also, several spurs were built: to Birmingham and Montgomery (in Alabama); Columbus, Macon and Atlanta’s Hartsfield-Jackson Airport (in Georgia); Knoxville, TN; Charlotte Douglas Airport and the Colonial Pipeline at Greensboro (in North Carolina); and Dulles and Reagan National airports (in northern Virginia). Gasoline, diesel and jet fuel is batched through the pipeline to delivery terminals along its route (orange triangles).With the exception of several large airports that receive jet fuel directly by pipe, virtually all the refined products delivered to terminals along the Colonial and Products (SE) pipelines and their spurs are trucked to their other, off-system terminals or directly to service stations and other customers.

U.S. Rig Count Holds Steady as Oil Drilling Slips and Gas Activity Climbs - The total number of active drilling rigs for oil and gas in the United States stayed the same this week, according to new data that Baker Hughes published on Friday, keeping the total rig count in the US at 551 this week, down 37 from this same time last year. The number of active oil rigs fell by 3 5o 409 during the latest reporting period, according to the data. This is 72 below this same time last year. The number of gas rigs rose by 3, reaching 133, which is 32 more than this time last year. The miscellaneous rig count stayed the same at 9.The latest EIA data showed that weekly U.S. crude oil production rose this week, by 498,000 bpd in the week ending February 6, to 13.713 million bpd on average, 149,000 bpd under the all-time high. Primary Vision’s Frac Spread Count, an estimate of the number of crews completing wells, fell again during the week ending February 6, sinking by 3 after losing 15 crews in the week prior. The number of active drilling rigs in the Permian Basin fell again this week, falling by 3 to 238, which is 66 rigs under year-ago levels. The count in the Eagle Ford held steady at 40, which is 8 fewer than this same time last year.Oil prices were trading higher on the day prior to the data release. Brent futures are trading at $67.87 per barrel (+0.52%). WTI was trading up $0.18 per barrel on the day at $63.02, down week over week.

Feds issue final environmental review for Michigan oil tunnel - The Army Corps of Engineers has released a final environmental review for Enbridge’s proposed oil tunnel in Michigan, clearing the path for the agency to issue a permit as early as next month.The agency’s Detroit District, which issued the final environmental impact statement for the Line 5 tunnel project last week, said a 30-day waiting period is underway.The Army Corps said it will issue a record of decision on the proposal sometime after the waiting period ends March 9. Canada-based Enbridge, the developer of the Line 5 tunnel project, called Friday’s announcement a “true milestone” that reflects nearly six years of “rigorous review” by the Army Corps. If the agency does issue a permit for the project, it will be the last federal approval needed, according to Enbridge spokesperson Ryan Duffy.

Hess Midstream Says Winter Impacting Operations But Still Expects to Match 2026 Volume Guidance --Severe winter weather in January and February has led to lower volumes across its system but Hess Midstream said it still expects to match its previous guidance for full-year 2026 (see chart below), which called for relatively flat volumes compared to 2025, executives said during the company’s quarterly earnings call February 2.Gas processing volumes averaged 444 MMcf/d in Q4 2025, with crude terminaling at 122 Mb/d and water gathering at 124 Mb/d, down from the previous quarter due to severe weather in December. For full-year 2025, gas processing averaged 445 MMcf/d, with crude terminaling at 129 Mb/d and water gathering at 131 Mb/d.The company said it grew its gas gathering and compression system in 2025 and completed its multi-year projects on time and on budget. With its system now substantially built, CEO Jonathan Stein said Hess expects about $150 million in capital spending in 2026, down 40% from 2025. Hess now has about 500 MMcf/d of gas processing capacity, 675 MMcf/d of gas gathering pipeline capacity, 505 Mb/d of crude oil terminaling capacity, 290 Mb/d of crude oil gathering capacity, and 330 miles of water gathering pipelines. Chevron has a 37.8% interest in Hess Midstream after its $60 billion acquisition of Hess, which closed in July 2025. About 90% of Hess Midstream's volumes are from Chevron production, with third parties making up the other 10%.

Alaska LNG Pipeline Developer Plans Early Construction By Mid-April - The developer of the 739-mile, 42-inch-diameter pipeline project to feed Alaska LNG is looking to start early construction work within the next two months, according to a federal regulatory filing. At A Glance:

• Full mobilization expected in June
• Mechanical installation targeted for November
• Pipeline completion planned for 2028

400 barrels of crude oil spilled near Arnegard (KXNET) — 400 barrels of crude oil were released this weekend in a spill about three miles northeast of Arnegard in McKenzie County. According to the North Dakota Department of Mineral Resources, Devon Energy Williston LLC reported that the spill happened Saturday at the Sturgeon East Pad site. As of Monday, 320 of the 400 barrels have been recovered. A North Dakota Oil and Gas inspector has been to the location and will monitor any additional cleanup needed.

Over 1,000 gallons of fuel, oil recovered from fallen North Slope oil rig as deconstruction begins- Crews responding to the collapse of Doyon Drilling Rig 26 on the North Slope have moved into a new phase of cleanup and removal, recovering around 1,132 gallons of spilled oil and diesel and beginning to dismantle the structure, according to an update released Thursday. The Jan. 23 collapse of the rig known as “The Beast” occurred while crews attempted to move the rig along a gravel road near Nuiqsut. In the weeks since, response teams have focused on containment and site stabilization. On Feb. 12, Doyon Drilling Inc. said those efforts have progressed enough to allow the second phase of its three part response plan to begin. That phase includes further structural inspections, removal of any remaining fluids or debris and transporting the rig to another location. Spill response crews have flushed contaminated areas with water and recovered an estimated 1,132 gallons of spilled product for disposal, the company said. Ice road and pad construction have also advanced, allowing crews to begin removing the rig from the tundra, staring with deconstructing and removing the crown of the rig. ‘The Beast’ of the North Slope: Oil rig that toppled over described by someone who helped build it The dismantled structure will be cleaned and ultimately transported to a recycling facility, according to Doyon’s update. Doyon said it continues to lead response activities under a Unified Command structure and that crews are working through periods of unsafe weather conditions on the North Slope. Officials with Doyon said there remains no immediate risk to the community, infrastructure, air quality drinking water sources, waterways , traffic or wildlife. The full response is highlighted in three phases:

• “Containment, cleanup, and mitigation of the impacted area, as well as ongoing safety evaluations for working around the rig.”
• “Further inspection of the structure, removal of any remaining fluids or debris, and transportation of the rig to another location. (This phase is now underway.)”
• “Final cleanup, mitigation, and remediation of the entire affected area.”

Regulator shuts Wandoo oil field off WA after spill - Canadian firm Vermilion judged the chance of the December spill as "rare" - the same probability it claims for seven planned exploration wells that could affect anywhere along the Pilbara coast. Following a minor oil spill in December, the offshore environment regulator has shut down the Wandoo oil field, 80km off the Pilbara coast, until the Canadian owner, Vermillion, can demonstrate it is safe.Regulator NOPSEMA called out "systemic failures" in Vermilion's management of Wandoo, including inadequate inspection and maintenance, and repeated instances of not complying with Wandoo's approved environment plan.NOPSEMA's current assessment is that the hydrocarbon release was small with minimal environmenal impact, according to the regulator's spokesman. However, it is the fourth minor spill since 2021. The condemnation of the $2.5 billion company's ability to operate Wandoo safely comes as it is seeking environmental approval to drill up to seven exploration wells starting in 2026 or 2027, in the search for more oil.Vermilion claims in its environment plan for the drilling under assessment by NOPSEMA to be committed to meeting all regulatory requirements and to maintain a strong health, safety, and environmental risk management system.It has not met either of these benchmarks with its current management of Wandoo, according to NOPSEMA's direction.NOPSEMA identified problems with Vermilion's management of Wandoo during inspections in October 2025 and after the December 11, 2025, oil spill."These issues reflect recurring themes from earlier inspections and show that corrective actions and assurance processes have not fully addressed the underlying causes," the February 6 NOPSEMA direction published on Friday said.The NOPSEMA direction said the systemic weaknesses it identified may have contributed to the oil spill. Vermilion has operated the wholly owned Wandoo field since 2005. Wells reach out as far as three kilometres from two platforms: the unmanned Wandoo A and the crewed Wandoo B. NOPSEMA has ordered Vermilion not to export any oil from Wandoo until it can demonstrate that it has implemented measures to make the existing system safe.Vermilion then has to have a completely new export system from the pipeline end manifold (PLEM) to the floating export hose in place by December 2027.A NOPSEMA spokesman said its direction to stop oil exports will be in place until it is satisfied Vermilion has reduced the risk to the environment to as low as reasonably practicable."The General Direction also requires independent third-party reviews, corrective actions to strengthen environmental and integrity management systems, and a transition to a fully replaced oil export system by the end of 2027," he said."NOPSEMA will continue to closely monitor the titleholder’s compliance ... and will take further regulatory action if required."Vermilion had a NOPSEMA direction issued three years ago over concerns that its inadequate maintenance of pipework on the platforms could lead to oil or gas escaping, resulting in a fire or explosion.

Cedar LNG Advances as Exmar Signs Marine Services Deal -- Developers of the Cedar LNG export facility proposed for British Columbia (BC) have selected a marine speciality firm for its floating LNG (FLNG) vessel currently under construction.Map of Western Canada natural gas pipelines, LNG export facilities operating, under construction and proposed, highlighting Montney, Duvernay, Alliance Pipeline, NOVA/AECO hub and NGI price index locations. At A Glance:
megúgu FLNG vessel under construction
Project targets 2028 startup
Cedar LNG adds 3.8 Mt/y capacity

TC Energy Tops Q4 Profit Estimate on Strong U.S. Natural Gas Demand - TC Energy Corporation beat analyst estimates for fourth-quarter profits amid soaring demand for natural gas in the United States which boosted its pipeline flows to an all-time delivery record early this year. TC Energy on Friday reportedearnings per common share from continuing operations at US$0.72 (C$0.98), beating the average consensus estimate of US$0.68 (C$0.92). TC Energy’s deliveries on the Canadian Natural Gas Pipelines averaged 27.2 Bcf/d, up by 5% compared to the fourth quarter of 2024, and set a new all-time delivery record of 33.2 Bcf on January 22, 2026. U.S. Natural Gas Pipelines' daily average flows were 29.6 Bcf/d, a 9.5% jump compared to the fourth quarter of 2024. Following the end of the reporting quarter, TC Energy’s U.S. Natural Gas Pipelines achieved an all-time delivery record of 39.9 Bcf on January 29, 2026, the company said. Deliveries to U.S. LNG facilities averaged 3.9 Bcf/d, up by 21% on the year, and set a new daily record of nearly 4.4 Bcf on December 4, 2025. In addition, TC Energy achieved all-time delivery records on the Columbia Gulf, GTN, and Gillis Access gas pipelines in December 2025. “Strong asset availability and reliability drove a 13 per cent year-over-year increase in fourth quarter comparable EBITDA and a 15 per cent increase in segmented earnings over the same period,” said François Poirier, TC Energy’s president and CEO. “In the fourth quarter 2025 and early 2026, record power demand from data centres, coal-to-gas conversions and LNG exports drove all-time delivery records across our U.S. and Canadian Natural Gas Pipeline Systems of 39.9 Bcf and 33.2 Bcf, respectively,” Poirier said. TC Energy also moved to expand critical infrastructure projects “to respond to rising power generation demand in the U.S. Midwest, strengthening system flexibility and reinforcing the long?term value of our storage portfolio,” the executive added.

Enbridge Books Record-High Core Earnings for 2025 - Canadian pipeline giant Enbridge reported record-high core earnings for 2025 and consensus-beating earnings for the fourth quarter amid growing demand for oil and gas egress from production centers to consumption and export hubs. Enbridge on Friday reportedfull-year adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA) of US$14.7 billion (C$20.0 billion) for 2025, up by 7% from 2024. Full-year adjusted earnings also rose, by 9%, compared to 2024. For the fourth quarter, adjusted earnings per common share of US$0.65 (C$0.88), higher than the average analyst estimate ‌of US$0.56 (C$0.77). “Despite tariffs and geopolitical tension, 2025 showcased our low-risk commercial framework delivering predictable results amid macroeconomic uncertainty,” Enbridge’s president and CEO Greg Ebel said. “We’re proud to announce that Enbridge has once again achieved record EBITDA and DCF per share, marking the 20th consecutive year of achieving or exceeding financial guidance.” In recent months, Enbridge has advanced with enhancing pipeline takeaway capacity in the Western Canada Sedimentary Basin (WCSB), expand natural gas transmission capacity in the U.S. Northeast, boost natural gas storage businesses on the Gulf Coast and in British Columbia, and building on its partnership with Meta in the power space. This quarter, Enbridge sanctioned the Mainline Optimization Phase 1 project, which will add 150,000 barrels per day of additional WCSB takeaway capacity and is expected to enter service in 2027. The project includes a 100,000-bpd expansion of the Flanagan South Pipeline system, adding critical full-path service to the U.S. Gulf Coast, Ebel said. In the natural gas transmission business, the company upsized the Eiger Express Pipeline in November, driven by growing demand for Permian natural gas egress capacity. “We continue to advance over 50 data center opportunities across North America, requiring up to 10 Bcf/d of new takeaway capacity in close proximity to our existing Gas Transmission assets and expect to sanction additional projects supporting power generation and data centers in 2026 and the years ahead,” Ebel said.

Alberta Plans New Crude Oil Pipeline to Ship Energy Exports to Asia --After years of antagonism between the federal government and Alberta over additional outlets for crude, Canada and the oil-producing province are finally on the same page regarding Canadian,/ oil exports. It took a major geopolitical and trade shift from Canada’s long-term ally and top trade partner, the United States, to have the federal government of Canada support a new oil pipeline from Alberta to the Canadian West Coast. The pipeline is expected to boost Canadian oil exports to Asia, the world’s driver of global oil demand growth, by shipping about 1 million barrels per day (bpd) of crude from Alberta to the West Coast. Canada seeks to diversify its trade and economic relations in the face of tariffs from the Trump Administration and continued threats of additional tariffs that have soured the relations between the two closest allies and trade partners in North America. The government led by Prime Minister Mark Carney wants to make Canada an energy superpower. This includes moving more of Alberta’s crude out of the country on tankers to Asia. Increased seaborne shipments to the world’s most important oil-consuming region is also a way for Canada to diversify its oil export markets, dominated by the U.S. with over 95% of all Canadian oil exports.The expanded Trans Mountain route is currently the only pipeline shipping Alberta’s landlocked crude for exports on tankers from the West Coast. Alberta has long called for additional outlets to the British Columbia coast to monetize the growing crude supply in the province. The province’s oil production hit a new record-high in 2025, with average daily production up by 166,000 bpd, or 4.2%, compared to 2024. Alberta produced 4.1 million bpd last year, 84% of which was from the oil sands. TMX, whose nameplate capacity was tripled to 890,000 bpd from 300,000 bpd before the expansion, was the key driver of Alberta’s record oil production while enabling more oil exports from Alberta to Asia.The value of Alberta’s oil exports to Asia went from zero before the expanded pipeline began operations to over US$804 million, or C$1.1 billion, as of October 2025, according to data from ATB Economics. “At some point, though, without a new pipeline in place, a lack of pipeline capacity will once again act as a constraint on output growth, possibly as soon as 2028,” The strained U.S.-Canada relations have prompted Carney’s federal government to support a new oil pipeline west, while TMX looks to boost crude flows within its existing capacity. Trans Mountain Corporation this week moved to boostoil flows via the pipeline by 10%, seeking approval to use drag-reducing agents (DRA) to increase volumes. As early as July, Canada’s PM Carney said that a new oil pipeline to Canada’s Pacific coast is highly likely to make it to the federal government’s list of projects of national interest. Carney visited China last month and signed a strategic energy and trade cooperation agreement in a major policy shift that hailed “a new era” in bilateral relations. Even before that, the governments of Canada and Alberta in November signed an agreement to increase oil exports to Asian markets, address investment uncertainty holding back Alberta’s energy economy, and reduce emissions. This agreement lays out the path forward for an Indigenous co-owned pipeline to Asian markets, with both governments supporting its approval and construction. Provisionally named West Coast Oil Pipeline, the project is now in the stage in which a technical advisory group is doing preliminary assessment work on the potential routes. Alberta’s government expects to submit by July 2026 the project to Canada’s federal Major Projects Office for designation as a project of national interest.Currently, Alberta is considering five ports on the West Coast, Premier Smith told Bloomberg News in aninterview this week.So far it appears that northwest British Columbia, with the port of Prince Rupert, holds more advantages compared to other locations.At any rate, a new pipeline will have to eventually include potentially difficult negotiations with First Nations and the provincial government of British Columbia. However, this time around, both Alberta and the federal government are backing a new oil pipeline that would boost Canadian oil exports and make them less dependent on the U.S.

Over 120 scientists and academics say 'no' to Tantramar shale gas plant - We are over 120 scientists and academics from all four universities in New Brunswick (Université de Moncton, University of New Brunswick, St. Thomas University, Mount Allison University), from various disciplines, expressing our solidarity with the citizen movement in Tantramar and the surrounding communities. At a time when climate emergency demands a rapid transition to carbon-free energy sources, when proven and affordable solutions exist, and when the population can no longer afford another increase in the cost of living, this project appears scientifically, environmentally and economically nonsensical.

• 1. Choosing renewable energy: wind turbines, solar power and battery systems The global energy landscape has changed dramatically. According to the International Energy Agency, almost all new electricity generation projects worldwide in 2024 will be based on renewable energy. Building a shale gas power plant today contradicts the global energy shift and New Brunswick’s climate commitments.
• NB Power claims that this plant would be necessary to increase electricity generation capacity and ensure grid stability. However, cheaper solutions already exist. Battery storage can now meet peak demand at a much lower cost than thermal power plants. In addition, renewable energy projects come online much faster—between six and eighteen months for solar—and carry less risk of cost overruns. Today, renewable energy makes the most sense on purely economic term.
• 2. Choosing demand management strategies Reducing electricity consumption costs much less than increasing production. However, demand management programs remain underdeveloped in the province. Ambitious energy efficiency initiatives could reduce demand by up to 400 megawatts by 2030. In addition, active demand management strategies, such as time-of-use pricing and the use of smart thermostats, could reduce consumption peaks. These strategies are quick to implement, create local jobs and lower electricity bills for NB Power customers.
• 3. No to an American gas plant in New Brunswick PROENERGY the company promoting the project, is headquartered in Missouri, and the gas burned in the proposed plant will come from the Marcellus and Utica shales in the United States. Against a backdrop of financial uncertainty surrounding customs tariffs, the proposed power plant will be entirely dependent on the United States for its construction, for its fuel, and for its operation. Further, shale gas is a risky energy resource: several analysts anticipate a peak in North American production in the short term. Relying on this energy source exposes New Brunswick to future price fluctuations on global markets. In our view, energy security is better served by renewable resources produced locally, by and for New Brunswick communities.
• 5. No to pollution threatening human and animal health Burning gas produces various pollutants that increase the risk of respiratory and cardiovascular diseases, neurological disorders and premature mortality. These effects primarily affect children, seniors, pregnant women and those already living with health problems. Such pollution will put additional strain on our health system already under immense pressure. It will also affect the health of 165 species of rare or protected animals in the area.
• 6. Showing strong leadership in clean energy Investments in energy efficiency, renewable energy and battery storage generate more local and sustainable jobs, particularly in rural areas, than large-scale centralized fossil fuel projects, while reducing greenhouse gas emissions and protecting public health. For all these reasons, we are calling for this shale gas power plant project to be suspended immediately and for investments to be redirected towards solutions for the future: renewable energy and energy efficiency. Signed by over 120 scientists and academics from all four universities in New Brunswick: Mount Allison University, Université de Moncton, University of New Brunswick and St. Thomas University Complete letter to the Premier and complete list of signatories available here.

The Sad Story of Quebec: Huge Utica Deposits, Imports All NatGas - Marcellus Drilling News - - The Canadian province of Quebec has significant natural gas potential in the Utica and Lorraine shale formations and on the Gaspé Peninsula, yet these resources remain untapped due to politics. The left has hoodwinked residents into believing hydraulic fracturing is from Satan and that it will pollute groundwater and cause earthquakes. Quebec became the first jurisdiction to permanently ban oil and gas exploration in 2022, prioritizing climate mythology over energy development. Consequently, the province imports nearly all its supplies from Western Canada and the United States. The province’s future strategy focuses on transitioning to renewable natural gas (which emits as much CO2 when burned as shale gas) and hydrogen, while maintaining a strict moratorium on local extraction.

Shell Weighs Multibillion Dollar Venezuela Gas Investments - Shell’s CEO Wael Sawan told CNBC the company is actively considering multibillion-dollar offshore natural gas investments in Venezuela that could start production in the next few years, pending regulatory approvals. The comments mark one of the clearest public signals yet that Shell is weighing a major push into Venezuelan energy assets after years of sanctions and uncertainty. The potential targets are offshore gas opportunities. Sawan said these projects could be activated within months, which is about as tight a timeline as Big Oil ever commits to publicly. The interest follows a broader industry trend of revisiting Venezuelan hydrocarbon development, including shared gas fields with Trinidad and Tobago that Shell and BP have sought U.S. licences for after sanctions eased.What’s not clear yet is the scale, structure or terms of any deal, and Shell’s comment doesn’t mean final investment decisions have been made. The CEO was explicit that approvals are still pending — in other words, this is a strategic consideration, not a signed contract.That context matters because Shell’s latest financialsout this week show the company is under pressure even as it keeps rewarding investors. Shell reported adjusted earnings of roughly $3.3 billion in the fourth quarter of 2025, down from prior quarters, and missed some analyst expectations. The company boosted its dividend by about 4 percent and kept a $3.5 billion share buyback in place, but net debt climbed and earnings were the weakest in nearly five years as lower oil and gas prices and losses in its chemicals and products segment weighed on results.Shell is generating enough cash to keep shareholders happy. It’s not, however, making enough to make massive new bets without a clear path to approvals and returns. The Venezuela talk is real and potentially big if it leads to sanctioned operations, but it’s not a done deal.

USA Allows Oilfield Contractors to Go to Work in VEN Fields- Rigzone -The US government issued a general license to allow oilfield-service companies to work in Venezuela as the Trump administration eases sanctions and pushes to rebuild the nation’s crude infrastructure. The license issued by the Treasury Department allows US firms to explore, develop and produce oil and natural gas in Venezuela under certain limited conditions, according to a statement Tuesday. The move is the latest in a series of steps Washington has taken to entice US companies to revive output from Venezuela’s vast crude reserves after last month’s capture of strongman Nicolás Maduro. Carlos Bellorin, an executive vice president at Welligence Energy Analytics, said investors are interpreting the license “as a stepping stone, raising expectations that a broader license for operators could follow. In January, the US issued a general license that allowed for a wide range of crude operations, including exporting, transporting, refining and buying and selling crude. The general license announced Tuesday involves tasks such as geological mapping, reservoir analysis and related tasks that augment the commencement of oil production. However, the license does not allow new joint ventures in Venezuela. US people and firms will need to provide detailed plans to the State Department and Department of Energy for any work in the country, according to the statement.

'Fabricated': Venezuela Rejects Bloomberg Claim of Oil Shipment to Israel - Palestine Chronicle --Venezuelan authorities dismissed as false a report claiming Caracas exported crude oil to Israel, stating that no official evidence supports the allegation, TeleSur reported on Wednesday.Miguel Pérez Pirela, sectoral vice-president for Communication and Culture, published a screenshot of the article marked “FAKE” and accused the report of spreading disinformation intended to undermine the country’s sovereignty and stability. Officials stressed that the claim contradicts Venezuela’s political position and diplomatic record, noting that relations with Israel were severed in 2009 and that Caracas has consistently expressed support for Palestine in international forums.The rejection addressed both the alleged shipment and the broader political narrative contained in the report, which authorities described as factually incorrect.Bloomberg reported on Tuesday that Venezuela was sending its first crude shipment to Israel in years, allegedly destined for the Bazan Group refinery, Israel’s largest oil processor.According to the agency, the information came from “people with knowledge of the deal” who requested anonymity because the matter was not public. The shipment would mark the first such cargo since 2020.The report also claimed that oil trade routes shifted after what it described as the capture of President Nicolás Maduro by US forces and Washington’s takeover of Venezuelan oil sales, an assertion Venezuelan officials rejected outright.Bloomberg added that Israel does not disclose crude suppliers and that tankers sometimes disappear from digital tracking systems near its ports. Neither the Israeli energy ministry nor the refinery commented.

Equinor Divesting Full Onshore Position in Vaca Muerta Basin | Rigzone - Equinor announced, in a statement posted on its website recently, that it has signed an agreement with Vista Energy to divest its full onshore position in Argentina’s Vaca Muerta basin. The company said the transaction includes Equinor’s 30 percent non-operated interest in the Bandurria Sur asset and its 50 percent non-operated interest in the Bajo del Toro asset. Equinor noted that its Argentinian offshore acreage is not affected by the transaction. The total consideration is valued at around $1.1 billion, Equinor highlighted in the statement, adding that, at closing, the company will receive an upfront cash payment of $550 million as well as shares in Vista. The consideration also includes contingent payments linked to production and oil prices over a five-year period, according to the statement, which noted that the transaction has an effective date of July 1, 2025. “We are realizing value from two high-quality assets we have actively developed as we continue to high-grade our international portfolio,” Philippe Mathieu, executive vice president for Exploration & Production International at Equinor, said in the statement. “This transaction strengthens Equinor’s financial flexibility as we evaluate opportunities in our core international markets, where we see substantial growth towards 2030. At the same time, we retain optionality through our offshore positions in Argentina,” he added. Chris Golden, senior vice president for the U.S. and Argentina in Exploration & Production International, said in the statement, “this is a value-driven decision that enhances the resilience of our international portfolio and sharpens our focus in Argentina”.

European Natural Gas Prices Again Swing Lower as LNG Imports Near Record High - European natural gas prices are struggling to find footing after falling again Monday when forecasts shifted warmer and LNG imports were forecast to reach some of their highest levels in years. European Union natural gas storage dashboard shows inventories at 423.6 TWh, or 37.1% full, as of Feb. 7, 2026, well below last year and the five-year average, with charts tracking storage volumes, year/year deficits and seasonal trends.At A Glance:
European imports estimated at 3.96 Mt
LNG prices under pressure
Storage withdrawals accelerate

Global Gas Prices Ease as Europe Warms Briefly, Asian LNG Imports Slip --Global natural gas futures shifted to reset mode as European gas traders used a brief weather reprieve to weigh forecasts and Asian demand continued to ebb. Four-panel chart showing trailing 365-day mean temperatures versus normal for Northwest Europe, Beijing, Seoul, and Tokyo, measured in °F, from February 2025 through February 2026. At A Glance:
Curve weakens across spring contracts
Cold threatens return of late-February demand
East Asia prices drift toward $10

The U.S. LNG Boom Is Lowering Europe’s Energy Costs and Raising America’s The United States has cemented its position as the world's leading exporter of Liquefied Natural Gas (LNG) over the past couple of years, thanks to surging natural gas demand in Europe and Asia. U.S. LNG exports hit a record 111 million tons in 2025, surpassing 100 million metric tons for the first time, driven by high utilization and new capacity additions from projects like Plaquemines LNG. But this could be just the beginning of the U.S. LNG boom: the EIA has predicted that U.S. LNG export capacity will more than double by 2029, with an estimated 13.9 Bcf/d of new capacity added between 2025 and 2029 as projects like Plaquemines LNG Phase 1 and Corpus Christi Stage 3 reach full operations. Meanwhile, additional projects such as Delta LNG, CP2 LNG, and others are expected to further bolster capacity toward 2030. However, the energy experts are now warning that all this growth will come at cost, as does everything. According to Wood Mackenzie, European demand for industrial natural gas has declined by 21% since 2021 while industrial power demand has decreased by 4%, driven by soaring gas prices after Russia’s invasion of Ukraine. However, WoodMac has projected that the ongoing massive wave of new global LNG supply, primarily from the U.S. and Qatar, is expected to nearly halve European traded gas prices by 2030 compared to 2025 levels, saving European industry roughly $46 billion annually by 2032. Conversely, surging LNG exports and soaring demand from AI data centers are projected to push domestic U.S. gas prices to an average of $4.90/MMBtu between 2030 and 2035, a nearly 50% increase from 2025 levels. This constitutes a narrowing competitive gap, with the large cost advantage that U.S. manufacturers have enjoyed for over a decade poised to shrink despite U.S. energy remaining cheaper than European energy in absolute terms. That doesn’t mean that European manufacturers will be complaining, though. The EU has become heavily reliant on the U.S., which supplied more than 57% of EU LNG imports by early 2026, up from 45% in 2024. Consequently, falling energy prices will benefit energy-intensive industries sectors such as petrochemicals, metals, and chemicals, which have been under severe cost pressure since the global energy crisis hit four years ago, with WoodMac reporting they are going through a "price reversal window" that will allow them to stabilize or recover. Lower European energy costs are expected to open up growth opportunities, with WoodMac predicting that the continent’s pharmaceuticals, food processing, and data center sectors are likely to capture a larger share of the international market. This could, however, prove to be a double-edged sword for the U.S. economy. Indeed, the U.S. LNG boom is poised to create a complex, often contradictory impacton the U.S. economy, acting as a major driver for GDP growth, job creation, and infrastructure investments while simultaneously raising domestic energy costs and complicating the energy transition. The LNG boom is expected to contribute up to $1.3 trillion to the U.S. GDP by 2040 and generate $166 billion in federal and state tax revenues, according to an S&P Global study. The industry is expected to create nearly 500,000 jobs, encompassing direct, indirect, and induced employment. Over $50 billion is projected to flow into new, massive infrastructure projects (e.g., Plaquemines, Golden Pass, Port Arthur). In contrast, experts warn that even relatively modest increases in gas and energy prices can lead to large increases in operating costs, potentially taking a toll on margins. An analysis by the Industrial Energy Consumers of America (IECA) found that every $1 increase in the Henry Hub price costs U.S. consumers and manufacturers ~$54 billion annually in combined gas and electricity expenses, including $20 billion more in electricity expenses as well as $34 billion increase in direct natural gas costs for consumers and manufacturers. For manufacturers, who often cannot pass on energy costs as easily as regulated utilities, a $1 increase in the Henry Hub price poses a direct threat to competitive advantage. Industries that rely heavily on natural gas, such as manufacturing, chemicals, and fertilizers, face increased operational costs, with estimates of up to $125 billion in added costs by 2050. But it’s not just large industries that could suffer the negative consequences of the ongoing AI and LNG boom. Increased exports connect the U.S. domestic natural gas market to higher global prices, driving higher electricity and heating bills for U.S. households. Meanwhile, analysts have warned that the U.S. could face a domestic energy crunch that could trigger spikes in energy prices if natural gas production growth fails to meet export demand growth. This could negatively impact the clean energy transition, with higher natural gas prices making coal power more competitive in the domestic electricity market.

Left Says LNG will Raise Price in U.S. but Crash it Everywhere Else -- Marcellus Drilling News - According to an E&E News – Energywire article, U.S. natural gas exporters are bracing for a “global glut” in LNG. While the Trump administration champions LNG exports for “energy dominance,” lefty analysts warn that diverting one-fifth of domestic production abroad could inflate American utility bills (a long-disproven canard). These analysts expect a temporary price lull in 2026, followed by a significant spike in 2027. On the one hand, analysts say the U.S. will flood the global market with LNG, and the world won’t be able to “absorb” all of that energy, crashing prices. On the other hand, the same analysts say exporting “one-fifth” of our production will cause price spikes here at home. So, we’ll crash the price for everyone else, but cause a price increase here? You see the contradiction.

RWE Eyes Long-Term UAE LNG Deal as Europe Seeks to Curb Reliance on U.S. Gas --Germany’s largest power generator is working to secure more LNG from the United Arab Emirates as key European gas players look to trim reliance on U.S. supplies.At A Glance:

• Deal could add 12 cargoes annually
• Russian LNG phaseout boosts demand urgency
• RWE, Adnoc explore short-term LNG trading

Eni Eyes Bigger LNG Trading Role as Congo Phase 2 Exports Begin-- The first cargo has been shipped from the second phase of Congo LNG, marking the next step in Eni SpA’s plans to build a massive export portfolio backed by African natural gas reserves. At A Glance:

• Congo LNG capacity climbs toward 3 Mt/y
• DR Congo exports reach 0.55 Mt
• Eni builds toward 20 Mt/y LNG portfolio

Authorities race to contain oil spill after cargo ship sinks off Thailand -- Marine authorities are racing to contain an oil spill in the Andaman Sea after a Panama-flagged cargo ship sank off southern Phuket, Thailand, on its way from Malaysia to Bangladesh, Bangkok Post reported on Sunday. All 16 crew members of the SEALLOYD ARC were rescued and brought to safety after the vessel took on water and went down south of Phuket’s popular viewpoint on Saturday. The ship was carrying 297 containers, including 14 with hazardous materials, according to the Thai Maritime Enforcement Command Centre. All containers sank with the 4,339-tonne vessel. An aerial survey later detected an oil slick stretching about 4.5 miles (7.2 kilometers) westward and one mile wide. No oil has reached Phuket’s coastline so far, officials said. Authorities have classified the incident as large-scale, citing growing environmental risks and potential hazards to navigation.

Crude oil prices decline as US-Iran talks ease supply concerns - Crude oil futures traded lower on Monday morning as diplomatic talks between the US and Iran eased concerns over global supply disruptions.At 9.58 am on Monday, April Brent oil futures were at $67.36, down by 1.01 per cent, and March crude oil futures on WTI (West Texas Intermediate) were at $62.93, down by 0.98 per cent. February crude oil futures were trading at ₹5712 on Multi Commodity Exchange (MCX) during the initial hour of trading on Monday against the previous close of ₹5824, down by 1.92 per cent, and March futures were trading at ₹5714 against the previous close of ₹5829, down by 1.97 per cent.In their Commodities Feed for Monday, Warren Patterson, Head of Commodities Strategy of ING Think, and Ewa Manthey, Commodities Strategist, said oil prices came under renewed pressure in early Monday morning trading in Asia after nuclear talks between the US and Iran were seen as constructive. A further round of talks is being planned.Mentioning that there is still plenty of uncertainty over how things will evolve, they said this suggests the market will likely continue to price in a risk premium.Though the indirect talks were reportedly constructive, the US on Friday imposed additional sanctions targeting Iranian oil exports. US President Donald Trump also signed an executive order on the same day. It will allow tariffs on goods from countries that do business with Iran. He stopped short of applying the tariffs, they said. “We’re likely to get plenty of noise over the week concerning views on the oil market, with International Energy Week kicking off in London this week. In addition, the EIA will release its Short-Term Energy Outlook on Tuesday. This is followed by OPEC’s monthly oil market report on Wednesday, and the IEA’s monthly oil report on Thursday,” they said. February natural gas futures were trading at ₹291.80 on MCX during the initial hour of trading on Monday against the previous close of ₹320.20, down by 8.87 per cent.On the National Commodities and Derivatives Exchange (NCDEX), February castorseed contracts were trading at ₹6422 in the initial hour of trading on Monday against the previous close of ₹6393, up by 0.45 per cent. April dhaniya futures were trading at ₹11026 on NCDEX in the initial hour of trading on Monday against the previous close of ₹11210, down by 1.64 per cent.

Oil Prices Slide As US–Iran Talks Ease Supply Concerns --Global oil prices edged lower on Monday as market sentiment shifted following signs of de-escalation in Middle East tensions, particularly after confirmation that diplomatic engagements between the United States and Iran would continue. Brent crude slipped to $67.09 per barrel, representing a 0.8% decline from the previous session’s close of $67.66. Similarly, US benchmark West Texas Intermediate (WTI) crude fell by 0.8% to trade at $62.76 per barrel, down from $63.31. The pullback followed comments from US President Donald Trump, who described the indirect talks held between Washington and Tehran in Muscat, Oman, as constructive. According to Trump, Iran had shown a strong inclination toward reaching a fresh agreement over its nuclear programme. Speaking on the outcome of the discussions, Trump said the talks with Iran had progressed positively, adding that Tehran appeared eager to secure a deal. He also referenced ongoing diplomatic engagements involving Russia and Ukraine, portraying the broader geopolitical environment as showing signs of improvement. Despite the optimistic tone, Trump noted that a substantial US naval presence had been deployed to the region in response to Iran, stating that the force would arrive shortly as developments continued to unfold. Iranian President Masoud Pezeshkian separately acknowledged the talks, describing them as a meaningful step forward in diplomatic engagement between the two countries. These developments helped reduce market fears around potential supply disruptions involving Iran, one of the world’s major oil producers situated near the Strait of Hormuz — a critical chokepoint for global crude shipments. The easing of perceived geopolitical risk weighed on crude prices. However, Trump simultaneously signed an executive order authorising the United States to impose additional trade penalties on countries that maintain commercial ties with Iran. The order allows for an extra 25% tariff on imports from nations that directly or indirectly purchase goods or services from Tehran. In parallel developments, US monetary policy signals also influenced market dynamics. Federal Reserve Vice Chair Philip Jefferson said he remained cautiously optimistic about the US economic outlook, noting that productivity gains could assist in steering inflation back toward the central bank’s target. San Francisco Federal Reserve President Mary Daly echoed a dovish tone, suggesting that one or two further interest rate cuts might be necessary to support a softening labour market. Following these comments, yields on the US 10-year Treasury note climbed by two basis points to 4.23%, while the dollar index remained steady at 97.6. Expectations of continued monetary easing by the Federal Reserve helped cushion the downside in oil prices.

Geopolitical Tensions and Shifting Trade Flows Lift the Oil Market - The crude market ended the session higher as the market weighed the geopolitical tension between the U.S. and Iran and the news that India is stepping away from Russian crude purchases. The crude market posted a low of $62.62 in overnight trading as the market’s oil supply fear eased following the U.S. and Iran pledge to continue their talks regarding Iran’s nuclear program. However, the market’s losses were limited by reports that India’s refiners are avoiding purchases for delivery in April as the country looks to sign a trade deal with the U.S. The market was later further supported and extended its gains to over $1.30 following the news that the U.S. recommended U.S.-flagged vessels to stay as far as possible from Iran while voyaging the Strait of Hormuz and the Gulf of Oman. The market posted a high of $64.88 by mid-day. The market later settled in a sideways trading range during the remainder of the session. The March WTI contract settled up 81 cents at $64.36 and the April Brent contract settled up 99 cents at $69.04. The product markets ended the session higher, with the heating oil market settling up 36 points at $2.4169 and the RB market settling up 3.23 cents at $1.9855. The United States issued new guidance on Monday to commercial vessels transiting the Strait of Hormuz. The U.S. Department of Transportation’s Maritime Administration advised U.S.-flagged commercial vessels to stay as far from Iran’s territorial waters as possible and to verbally decline Iranian forces permission to board if asked. Platts reported that Indian refiners are avoiding Russian oil purchases for delivery in April and are expected to stay away from such trades for longer. A trader said Indian Oil, Bharat Petroleum and Reliance Industries are not accepting offers from traders for Russian oil loading in March and April. However, refining sources said the refiners had already scheduled some deliveries of Russian oil in March. Russia-backed private refiner Nayara, which relies solely on Russian oil for its 400,000 bpd refinery, may be allowed to keep buying Russian oil because other crude sellers pulled back after the European Union sanctioned the refiner in July. Bloomberg reported that India’s imports of Russian oil are expected to fall by about half by April from an average of 1.2 million bpd in January. Ukrainian President, Volodymyr Zelenskiy, said Russian energy infrastructure is a legitimate target for Ukrainian strikes because the energy sector is a source of funds for the production of weapons. IIR Energy said U.S. oil refiners are expected to shut in about 1.23 million bpd of capacity in the week ending February 13th, increasing available refining capacity by 81,000 bpd. Offline capacity is expected to fall to 1.09 million bpd in the week ending February 20th.

Crude oil futures trade lower after a rally as markets analyse US advisory to vessels - Crude oil futures traded lower on Tuesday morning after markets analysed the potential for supply disruptions following a US advisory to vessels transiting the Strait of Hormuz and Gulf of Oman. Crude oil prices rose over 1 per cent on Monday following a US advisory to its vessels. At 10.04 am on Tuesday, April Brent oil futures were at $68.91, down by 0.19 per cent, and March crude oil futures on WTI (West Texas Intermediate) were at $64.19, down by 0.26 per cent. February crude oil futures were trading at ₹5832 on Multi Commodity Exchange (MCX) during the initial hour of trading on Tuesday against the previous close of ₹5870, down by 0.65 per cent, and March futures were trading at ₹5835 against the previous close of ₹5875, down by 0.68 per cent. An advisory issued by the US Department of Transportation’s Maritime Administration on Monday warned that the US-flagged vessels transiting the Strait of Hormuz could face illegal boarding, detention or seizure by Iranian authorities. The advisory said commercial vessels transiting the Strait of Hormuz and Gulf of Oman have long been at risk of being hailed, queried, boarded, detained, or seized by Iranian forces. Iranian forces have historically utilized small boats and helicopters during boarding operations and have attempted to force commercial vessels into Iranian territorial waters, including as recently as February 3. The US government is continually assessing the maritime security situation in the region to identify and differentiate threats and safeguard freedom of navigation, ensure the free flow of commerce, and protect US vessels, personnel, and interests, it said. The advisory said: “It is recommended that US-flagged commercial vessels transiting these waters remain as far as possible from Iran’s territorial sea without compromising navigational safety. When transiting eastbound in the Strait of Hormuz, it is recommended that vessels transit close to Oman’s territorial sea.” Talks between the US and Iran, which were mediated by Oman, saw some progress on Friday. February natural gas futures were trading at ₹283.90 on MCX during the initial hour of trading on Tuesday against the previous close of ₹287.50, down by 1.25 per cent. On the National Commodities and Derivatives Exchange (NCDEX), February guargum contracts were trading at ₹10119 in the initial hour of trading on Tuesday against the previous close of ₹10086, up by 0.33 per cent. April dhaniya futures were trading at ₹10984 on NCDEX in the initial hour of trading on Tuesday against the previous close of ₹11018, down by 0.31 per cent.

Strait of Hormuz Tensions Keep the Oil Market in a Tight Trading Range - The crude market posted an inside trading day as the market remained focused on the geopolitical tensions between U.S. and Iran after the U.S. issued its guidance for vessels transiting the Strait of Hormuz on Monday. The market traded sideways and posted a high of $64.71 by mid-morning before it erased its gains. The market sold off to a low of $63.65 ahead of the close, despite U.S. President Donald Trump once again threatening to do “something very tough” if a deal is not reached with Iran on its nuclear program. The March WTI contract settled down 40 cents at $63.96 and the April Brent contract settled down 24 cents at $68.80. The product markets ended the session lower, with the heating oil market settling down 1.81 cents at $2.3988 and the RB market settling down 2.63 cents at $1.9592. The EIA, in its Short Term Energy Outlook, forecast 2026 world oil demand at 104.8 million bpd, unchanged from a previous forecast and forecast demand will increase by 1.3 million barrels to 106.1 million bpd in 2027. U.S. oil demand is forecast at 20.6 million bpd in 2026, also unchanged from a previous forecast, and will increase by 100,000 bpd to 20.7 million bpd in 2027. World oil output in 2026 is expected to average 107.8 million bpd, up 100,000 bpd from a previous forecast and increase by 1 million bpd to 108.8 million bpd in 2027, up 600,000 bpd from a previous estimate. U.S. crude oil output in 2026 is estimated at 13.6 million bpd, up 10,000 bpd from a previous forecast, while output in 2027 is expected to fall to 13.32 million bpd, which was up 70,000 bpd from a previous forecast. The EIA sees the price of WTI crude averaging $53.42/barrel in 2026 and $49.34/barrel in 2027, while the price of Brent crude is seen averaging $57.69/barrel in 2026 and $53/barrel in 2027. In an interview with Israel’s Channel 12, U.S. President Donald Trump said the U.S. will have to do “something very tough” if a deal is not reached with Iran. Axios and Channel 12 reported that President Trump has said he is considering sending a second aircraft carrier to the Middle East, amid simmering tensions between Washington and Tehran over Iran’s nuclear program and over its recent crackdown on protesters. Iran’s Foreign Ministry spokesperson said nuclear talks with the United States allowed Tehran to gauge Washington’s seriousness and showed enough consensus to continue on the diplomatic track. The Trump administration said a sale of oil and gas drilling rights in Alaska’s National Petroleum Reserve will take place on March 18th, nine days later than originally planned. The U.S. Bureau of Land Management said the change stemmed from a regulation requiring the agency to provide public notice of the sale in the Federal Register at least 30 days before the sale. The EIA said expanded U.S. licenses for Venezuela-related deals are expected to restore the South American country’s oil production by mid-2026 to the level it was at prior to a U.S. naval blockade of the country in December.

Oil prices flat as markets await geopolitical and economic news -Oil prices were little changed on Tuesday as the market waited for direction from news on diplomatic relations between the US and Iran, efforts to end Russia's war in Ukraine and data on the US economy and US oil inventories. Brent futures fell 24 cents, or 0.3 per cent, to settle at $68.80 a barrel, while US West Texas Intermediate crude fell 40 cents, or 0.6 per cent, to settle at $63.96. Traders are, "hesitant to press either direction until there is a clearer signal from diplomacy, the next inventory prints, or any confirmation that supply flows are being materially affected rather than merely threatened," Nuclear talks with the US allowed Tehran to gauge Washington's seriousness and showed enough consensus to continue on the diplomatic track, Iran's foreign ministry spokesperson said on Tuesday. US and Iranian diplomats held talks through mediators in Oman last week in an effort to revive diplomacy, after US President Donald Trump positioned a naval flotilla in the region, raising fears of new military action. "The market is still focussed on the tensions between Iran and the US," "But unless there are concrete signs of supply disruptions, prices will likely start going lower." About one-fifth of the oil consumed globally passes through the Strait of Hormuz between Oman and Iran, making any escalation in the area a major risk to global oil supplies. Iran and fellow Organisation of the Petroleum Exporting Countries (OPEC) members Saudi Arabia, United Arab Emirates, Kuwait and Iraq export most of their crude via the strait, mainly to Asia. Iran was the third-biggest crude producer in OPEC behind Saudi Arabia and Iraq in 2025, according to US Energy Information Administration data. European Union foreign policy chief Kaja Kallas said on Tuesday she would propose a list of concessions that Europe should demand from Russia as part of a settlement to end the war in Ukraine. The move is part of efforts to squeeze Russian revenue. Russia was the world's third-biggest crude producer behind the US and Saudi Arabia in 2025, according to EIA data. Indian Oil Corporation bought six million barrels of crude from West Africa and the Middle East, traders said, as India steered clear of Russian oil in New Delhi's push for a trade deal with Washington. In Venezuela, expanded US licences are expected to restore the South American OPEC member's oil production by mid-2026 to levels seen before a US naval blockade in December, the EIA said on Tuesday. US retail sales were unexpectedly unchanged in December as households scaled back spending on motor vehicles and other big-ticket items, potentially setting consumer spending and the economy on a slower growth path heading into the new year. Analysts said investors will scrutinize US economic data releases scheduled for this week, including January's non-farm payrolls report on Wednesday and inflation data on Friday, for clues to the Federal Reserve's interest rate path. Central banks, like the Fed, raise and lower interest rates to keep inflation in check. US President Trump has pressured the Fed to lower interest rates, which is politically popular because it reduces consumers' costs and can boost economic growth and energy demand, but could also result in an unwanted rise in inflation. In the energy market, traders are waiting for weekly US oil inventory data from the American Petroleum Institute trade group on Tuesday and the EIA on Wednesday. Analysts forecast US crude stockpiles rose by 0.1 million barrels last week. That compares with an increase of 4.1 million barrels during the same week last year and an average increase of 1.4 million barrels over the past five years (2021-2025)

Oil Prices Rise as U.S.-Iran Tensions Simmer | OilPrice.com -

• Oil prices, with WTI Crude near $65 and Brent Crude near $70, rose by over 1% early Wednesday due to ongoing tensions between the U.S. and Iran.
• The oil market is closely watching U.S.-Iran negotiations and Israeli Prime Minister Benjamin Netanyahu's meeting with President Trump, where he is expected to ask for limits on Iranian uranium enrichment and support for groups like Hamas and Hezbollah.
• The upward pressure on prices has persisted despite an estimated increase of 13.4 million barrels in U.S. crude oil inventories, with reports of the U.S. considering seizing sanctioned Iranian tankers also contributing to a larger risk premium.

Oil prices rose by 1% early on Wednesday as the U.S.-Iran tensions continue to rise and Israeli Prime Minister Benjamin Netanyahu is set to meet U.S. President Donald Trump. In morning trade in Europe on Wednesday, the U.S. benchmark, WTI Crude, was up by 1.39% to $64.85 per barrel. The front-month futures traded at $64.85. The international benchmark, Brent Crude, traded very close to the $70 per barrel mark, as it was up 1.29% on the day to $69.69. This week, the U.S.-Iran tensions and negotiations have been in the spotlight, with the oil market assessing the chances of a deal.Israel’s Netanyahu said before departing for Washington, D.C., “I will present to the president our outlook regarding the principles of these negotiations.”Israel is expected to ask President Trump to seek a deal that would put an end to Iranian uranium enrichment, and limit its support for Hamas and Hezbollah. “The Prime Minister believes that any negotiations must include limiting ballistic missiles and ending support for the Iranian axis,” Netanyahu’s office said ahead of his trip to the U.S. President Trump has warned the U.S. could send a second aircraft carrier to the region if the talks fail. The ongoing tensions have supported oil prices this week, although they wobbled in Tuesday trade after the American Petroleum Institute (API) estimated that crude oil inventories in the United States increased by a whopping 13.4 million barrels in the week ending February 6. The estimated increased more than offset the prior week’s draw of 11.1 million barrels. Reports that the U.S. was considering seizing sanctioned tankers carrying Iranian oil have also pushed prices higher. But such an action with Iran “would be escalatory and would likely see the market needing to price in an even larger risk premium than it already is, given the potential for Iranian retaliation,” ING's commodities strategists Warren Patterson and Ewa Manthey said in a Wednesday note.

WTI Slides On Biggest Crude Build In A Year, Production Rebound; But... (w/ Bloomberg graphics) Oil prices continued their recent rally this morning as traders hiked its risk premium as Israeli PM Netanyahu arrived in Washington to pressure President Trump to take a hard line in talks with Iran, even as the API report overnight showed a huge rise in US inventories last week. "Oil trades firmer, with Brent back above USD 69 as Middle East tensions sustain a modest risk premium. The US signaled it is considering seizing tankers carrying Iranian oil, while President Trump threatened to deploy another aircraft carrier should nuclear talks with Iran fail," Saxo Bank noted. The threats of violence in the Persian Gulf - a region that supplies about a fifth of the world's daily oil consumption - comes even as signs supply remains well ahead of demand. "While rhetoric remains belligerent at times, there are no signs, at least for now, of escalation, and the U.S. President believes that Iran will ultimately want to strike a deal on its nuclear missile programme," If API's huge build is confirmed by the official data, the battle between geopolitical risk premia and over-supply gets harder (but admittedly this is very much affected by the freezing storms). Expect another volatile week of EIA data with “significant winter freeze noise,” Macquarie energy strategist Walt Chancellor said referring to last month’s storm. API:

• Crude +13.4mm
• Cushing
• Gasoline +3.3mm
• Distillates -2.0mm

DOE

• Crude +8.53mm (-400k exp) - biggest build since Jan 2025
• Cushing +1.07mm
• Gasoline +1.16mm
• Distillates -2.70mm

The official data confirmed a large crude build (largest since Jan 2025), but smaller than feared from API. Gasoline stocks rose for the 13th straight week while Distillates saw stocks fall for the second week... This build pushed total crude stocks up to their highest since June... Stockpiles at Cushing, Oklahoma, rose to 25.1 million barrels, the highest level since April 2025. The weekly build is the largest in almost a month, and the first increase on inventories since the week ending Jan. 16. US Crude production rebounded as expected from its winter storm plunge... Crude prices started giving some back before the inventory data as stocks tumbled following the 'good' jobs news. However, WTI remains higher on the day (back near its highest since January)...

Middle East Tensions Support the Oil Market Despite Large Inventory Build --The crude oil market traded higher on Wednesday as the market weighed the continuing concerns over the possible escalation of tension between the U.S. and Iran against a large build in crude inventories that limited gains. The market, which posted a low of $64.15 in overnight trading, retraced some of its previous losses posted on Tuesday as it rallied to a high of $65.83 early in the session, ahead of the release of the EIA’s weekly petroleum stocks report. The oil market was buoyed by tension in the Middle East, with U.S. President Donald Trump stating that he was considering sending a second aircraft carrier to the Middle East if a deal is not reached with Iran, even as the two countries prepare for the next round of talks. However, the market’s gains were limited after the EIA reported a larger than expected build in crude stocks of 8.5 million barrels on the week. The crude market later erased most of its earlier gains during the remainder of the session. The March WTI contract ended the session up 67 cents at $64.63 and the April Brent contract settled up 60 cents at $69.40. The product markets ended the session higher, with the heating oil market settling up 4.16 cents at $2.4404 and the RB market settling up 1.97 cents at $1.9789. In its monthly report, OPEC forecast world oil demand for crude from the wider OPEC+ producer group will fall by 400,000 bpd in the second quarter from the first three months of this year. World demand for OPEC+ crude will average 42.20 million bpd in the second quarter, down from 42.60 million bpd in the first quarter. Both forecasts were unchanged from last month’s report. In the report, OPEC also left unchanged its forecasts that world oil demand will increase by 1.34 million bpd in 2027 and by 1.38 million bpd this year. OPEC also reported that OPEC+ produced 42.45 million bpd in January 2026, down 439,000 bpd from December 2025, driven by reductions in Kazakhstan, Russia, Venezuela and Iran.On Tuesday, the U.S. Treasury Department issued a general license to facilitate the exploration and production of oil and gas in Venezuela. The new general license authorizes the provision of U.S. goods, technology, software or services for the exploration, development or production of oil and gas in Venezuela. The permit mandates that any contract for the authorized transactions to be signed with Venezuela’s government or state energy company PDVSA must follow U.S. laws, with disputes to be resolved in the United States. Payments to any sanctioned entity must be made into a U.S.-overseen fund.IIR Energy said U.S. oil refiners are expected to shut in about 1.4 million bpd of capacity in the week ending February 13th cutting available refining capacity by 54,000 bpd.IIR Energy said Marathon Petroleum shut its 255,000 bpd refinery in Catlettsburg, Kentucky due to power supply interruption yesterday evening.A hydrocracker at Chevron’s 285,000 bpd El Segundo refinery in southern California remains offline following a large fire, with repair efforts still underway. A large fire erupted in an isomax unit at the refinery in October. The Isomax unit remains down at El Segundo as repairs progress. Industry monitor IIR Energy expects the fire-damaged unit to be back online by the end of March.Valero Energy Corp reported maintenance activities at its 205,000 bpd Houston, Texas refinery.

U.S.-Iran Tensions Push Oil Prices Higher - Oil prices rose in Thursday trading amid investor concerns over escalating tensions between the United States and Iran and potential disruptions to crude supplies from the Gulf region. As of 09:15 Moscow time, U.S. West Texas Intermediate (WTI) crude futures for March traded at $64.86 per barrel, up 0.36% from the previous settlement. Meanwhile, Brent crude futures for April traded at $69.58 per barrel, an increase of 0.26% from the previous close. Both benchmarks rose in the previous session, with Brent up 0.87% and WTI up 1.05%, as investor fears over U.S.-Iran tensions outweighed the impact of rising U.S. crude inventories. U.S. President Donald Trump, following talks with Israeli Prime Minister Benjamin Netanyahu on Wednesday, said no “specific” decision had been made regarding Iran, but emphasized that negotiations with Tehran would continue. The day before, Trump mentioned he was considering sending a second aircraft carrier to the Middle East if a deal with Iran is not reached, while Washington and Tehran prepare to resume talks. U.S. and Iranian diplomats held indirect discussions last week in Amman. The timing and location of the next round of talks have not yet been announced. Tony Sycamore, an analyst at IG, noted that further escalation in the Middle East would be needed for oil prices to exceed $65–66 per barrel, while a de-escalation would likely prompt profit-taking, keeping U.S. crude in the $60–61 range.

Oil Prices Slip As U.S. Inventory Surge, Weak China Data Weigh On Demand Outlook - Crude oil prices edged lower on Thursday as fresh concerns over weakening demand in the United States and China overshadowed geopolitical tensions tied to ongoing U.S.-Iran negotiations. Brent crude, the global benchmark, declined 0.39 percent to settle at $69.11 per barrel, compared with $69.38 at the previous close. Meanwhile, U.S. benchmark West Texas Intermediate (WTI) crude fell 0.37 percent to trade at $64.61 per barrel, down from $64.85 recorded in the prior session. The downward pressure followed the release of new inventory data from the United States, which indicated a sharp and unexpected rise in crude and gasoline stockpiles. The data intensified concerns that fuel consumption in the world’s largest oil-consuming nation may be slowing. Figures published by the U.S. Energy Information Administration (EIA) showed that commercial crude oil inventories increased by approximately 8.5 million barrels in the week ending February 6. The build significantly exceeded analysts’ projections of roughly 700,000 barrels. Gasoline inventories also climbed by about 1.2 million barrels during the same reporting period. Market analysts noted that such a substantial inventory build typically reflects either softer refinery demand or reduced end-user consumption, both of which signal cooling economic momentum. In addition to U.S. demand concerns, oil traders are closely monitoring economic indicators from China, the second-largest consumer of crude globally. Recent inflation data pointed to persistent weakness in domestic demand conditions. China’s Consumer Price Index (CPI) rose just 0.2 percent year-on-year in January, undershooting market expectations. At the same time, the Producer Price Index (PPI) contracted by 1.4 percent, extending an ongoing deflationary trend in the manufacturing sector. The subdued inflation environment suggests restrained consumer spending and industrial activity, reinforcing expectations of softer fuel consumption growth in Asia’s largest economy. Analysts say the combination of weak CPI growth and persistent producer deflation continues to cloud the medium-term demand outlook for energy markets. However, some seasonal support may emerge from increased travel activity ahead of China’s Lunar New Year celebrations, traditionally a period of heightened transportation demand. Still, broader economic signals continue to point to sluggish recovery momentum. Geopolitical developments offered limited counterbalance to the demand-driven weakness. U.S. President Donald Trump stated that his recent meeting with Israeli Prime Minister Benjamin Netanyahu did not produce definitive outcomes but reiterated that diplomatic engagement with Iran remains ongoing. In comments to Axios earlier in the week, Trump indicated he was considering the deployment of a second aircraft carrier strike group to the Middle East, suggesting preparations for possible military escalation should negotiations with Tehran falter. U.S. and Iranian representatives met in Oman on February 6, describing the discussions as constructive. Nevertheless, lingering geopolitical tensions have maintained a modest risk premium in oil prices, preventing deeper losses. For now, traders appear to be prioritizing macroeconomic demand signals over geopolitical risk, leaving crude benchmarks vulnerable to further volatility as fresh economic data emerges from both Washington and Beijing.

Oil prices tumble more than $1 as IEA cuts demand forecast | Khaleej Times - Global oil demand will rise more slowly than previously expected this year, the IEA said on Thursday, while projecting a sizeable surplus despite outages that cut supply in January. Oil prices tumbled by more than $1 a barrel on Thursday as investors gave more weight to the International Energy Agency lowering its global oil demand forecast for 2026 against the receding risk of U.S. attacks on Iran. Brent crude oil futures were down $1.26, or 1.82%, at $68.14 a barrel by 1616 GMT. US West Texas Intermediate crude fell $1.24, or 1.92%, to $63.39. Global oil demand will rise more slowly than previously expected this year, the IEA said on Thursday, while projecting a sizeable surplus despite outages that cut supply in January. The Brent and WTI benchmarks reversed gains to turn negative after the IEA's monthly report, having derived support earlier from concerns over the U.S.-Iran backdrop. "It just ran out of steam," said Phil Flynn, senior analyst with the Price Futures Group. "The market's doubling down on the lowering demand forecast." On Wednesday, US President Donald Trump said after talks with Israeli Prime Minister Benjamin Netanyahu that they had yet to reach a definitive agreement on how to move forward with Iran but that negotiations with Tehran would continue. On Tuesday, Trump had said he was considering sending a second aircraft carrier to the Middle East if a deal is not reached with Iran. The date and venue of the next round of talks have yet to be announced. A hefty build in US crude inventories had capped the early price gains. U.S. crude inventories rose by 8.5 million barrels to 428.8 million barrels last week, the Energy Information Administration said, far exceeding the 793,000 increase expected by analysts in a Reuters poll. US refinery utilisation rates dropped by 1.1 percentage points in the week to 89.4%, EIA data showed. On the supply side, Russia's seaborne oil products exports in January rose by 0.7% from December to 9.12 million metric tons on high fuel output and a seasonal drop in domestic demand, data from industry sources and Reuters calculations showed.

IEA Demand Downgrade Triggers Sharp Selloff in the Oil Market - The oil market tumbled more than $2 in light of the IEA lowering its global oil demand forecast for 2026. The IEA stated that global oil demand will increase more slowly than previously expected this year, while forecasting a sizeable surplus despite outages that cut supply in January. Also, geopolitical risk seemed to be easing as U.S. President Donald Trump appeared to be framing a resolution to the tension with Iran over its nuclear program. The crude market traded sideways in overnight trading before it began to erase its previous gains and sold off sharply throughout the session, posting a low of $62.39 ahead of the close. The March WTI contract settled down $1.79 at $62.84 and the April Brent contract settled down $1.88 at $67.52. The product markets ended the session in negative territory, with the heating oil market settling down 4.77 cents at $2.3927 and the RB market settling down 6.3 cents at $1.9159. The International Energy Agency said world oil demand will increase more slowly than expected this year, while projecting that the global market continues to face a sizeable surplus despite outages that cut supply in January. The IEA, in its monthly oil report, projected global oil supply would exceed demand by 3.73 million bpd in 2026, similar to last month’s projection. A surplus of that size would be about 4% of world demand and is larger than other predictions. World oil demand will increase by 850,000 bpd this year, down 80,000 bpd from last month’s forecast. Referring to the lower demand growth forecast, the IEA said “economic uncertainties and higher oil prices” are weighing on consumption. The IEA trimmed its projection for the growth in world oil supply this year to 2.4 million bpd, from 2.5 million bpd last month, although this is much faster than the rate of demand growth. U.S. President Donald Trump said the United States has to make a deal with Iran and thinks a deal could be struck over the next month. Turkey’s Foreign Minister, Hakan Fidan, told the Financial Times in an interview that the U.S. and Iran appeared ready to compromise to secure a nuclear deal, but broadening talks to cover Tehran’s ballistic missile program would risk “nothing but another war”. He said “It is positive that the Americans appear willing to tolerate Iranian enrichment within clearly set boundaries.” On Wednesday, Ukrainian President Volodymyr Zelenskiy said the U.S. needed to put more pressure on Russia if it wanted the war to end by summer, adding it was unclear whether Moscow would attend U.S.-brokered peace talks next week. He said Ukraine was ready to attend the meeting, which follows two rounds of trilateral negotiations in Abu Dhabi over the past month that have failed to produce a breakthrough. The Kremlin said that it expected the next round of peace talks on Ukraine to happen soon and that there was already an understanding about their timing and location.

Oil prices slide as Iran risk eases - Crude oil prices edged lower on Friday and looked set for a second straight weekly decline as concerns about a possible US‑Iran conflict eased. The slide matters for global energy markets and traders who had priced geopolitical risk into crude prices. Brent and US benchmarks both reflected weakening risk premiums amid mixed supply and demand signals. Brent crude futures were down about 0.1 per cent near $67.4 a barrel, while US West Texas Intermediate (WTI) slipped roughly 0.2 per cent toward $62.7. Both benchmarks fell sharply in the prior session and are on track to register weekly losses of roughly 0.8 per cent for Brent and 1.1 per cent for WTI. Prices had climbed earlier this week on worries the United States might strike key Middle Eastern oil producer Iran over its nuclear programme, but comments from President Donald Trump about a potential deal within the next month helped reduce near‑term geopolitical risk premiums. Analysts said the market also faces oversupply pressures as global forecasts show supply outpacing demand this year. A build in US crude inventories and expectations that Venezuelan output could rise further have added to the bearish backdrop, tempering earlier gains. Traders will continue to monitor geopolitical developments and demand outlooks for additional direction. For now, the easing of conflict fears and hints of broader supply growth are keeping downward pressure on crude prices as markets adjust to evolving fundamentals.

Oil prices drop on report that OPEC+ is leaning towards output increases -Oil prices fell ‌on Friday after a Reuters report said that OPEC+ was leaning towards a resumption in oil production increases and a softening of investor concern over potential U.S.-Iran conflict that could affect supply. Brent crude futures lost 11 cents, or 0.2%, to $67.41 a barrel by 1306 GMT after falling 2.7% in the previous session. U.S. West Texas Intermediate crude dropped 15 cents, or 0.2%, to $62.69 after a 2.8% decline the previous day. Both oil benchmarks were poised to register weekly declines, with ⁠Brent and WTI set to drop by 1% and 1.3% respectively. Prices had strengthened earlier in the week on concerns that the U.S. could attack Middle Eastern oil producer Iran over its nuclear programme. But comments on Thursday from U.S. President Donald Trump that the U.S. could make a deal with Iran over the next month drove down prices on ‌Thursday. U.S. media outlets ⁠reported late on Thursday, ⁠however, that the U.S. was sending a second aircraft carrier to the Middle East. Away from the Middle East, the Kremlin said on Friday that the next round of peace talks on Ukraine will take ‌place next week. Kremlin spokesperson Dmitry Peskov confirmed that Moscow and Washington have ⁠been discussing bilateral trade and economic cooperation. He said Moscow hoped that dialogue would continue, but added that it was unlikely such discussions would move beyond talk before the conflict in Ukraine was settled. Price pressure has also come from the International Energy Agency's latest forecasts, saying in its monthly report that global oil demand growth this year will be weaker than previously expected, with overall supply set to exceed demand. Thursday's price falls were amplified by U.S. data showing a massive build in crude stockpiles and growing expectations that increased Venezuelan supply could soon hit the market, IG analyst Tony Sycamore said in a note. "There is an expectation that Venezuelan ‌oil supply will return to pre-blockade levels in the months ahead," he ⁠said, adding that supply is expected to rise from 880,000 barrels per day to about 1.2 million bpd. The U.S. Treasury will issue more allowances easing sanctions on Venezuelan energy this week, a White House energy official said on Thursday. U.S. Secretary of Energy Chris Wright said on Thursday that U.S.-controlled oil sales from Venezuela have totalled more ‌than $1 billion since the capture of President Nicolas Maduro in January and will ⁠bring in a further $5 billion in the next few months

Oil prices settle slightly higher as optimism around US inflation data outweighs OPEC supply concerns (Reuters) - Oil prices settled marginally higher on Friday after data showed an overall slowdown in U.S. inflation, helping offset supply concerns as OPEC+ is leaning towards a resumption in production increases. Brent crude futures closed 23 cents, or 0.3%, higher at $67.75 a barrel, while U.S. West Texas Intermediate crude settled 5 cents, or 0.08% higher at $62.89. Both benchmarks posted weekly declines after incurring near 3% losses on Thursday. Brent settled down about 0.5%, while WTI lost 1% in the week. U.S. consumer prices increased less than expected in January amid cheaper gasoline prices and a moderation in rental inflation. "Looks like inflation is stabilizing. So, I think that's going to be a boon for interest rates to probably continue to move a little bit lower. And I think as rates start to move lower... that's a positive to the economy," said Dennis Kissler, senior vice president of trading at BOK Financial. "The negative is going to be that OPEC could possibly increase production a little further," he added. Prices fell earlier in the session as investors reacted to a Reuters report that OPEC is leaning towards a resumption in oil output increases from April, ahead of upcoming peak summer fuel demand, and amid firmer crude prices owing to tensions over U.S.-Iran relations. On the U.S. supply side, Baker Hughes said oil rigs fell by three to 409 this week. Oil prices had strengthened earlier in the week on concerns that the U.S. could attack Middle Eastern oil producer Iran over its nuclear programme. But comments on Thursday from U.S. President Donald Trump that Washington could make a deal with Iran over the next month drove down prices on Thursday. The Pentagon, however, is sending an aircraft carrier from the Caribbean to the Middle East, U.S. officials said on Friday, a move that would put two carriers in the region as tensions soar between the United States and Iran. Russia, meanwhile, said on Friday that the next round of peace talks on Ukraine will take place next week. Negotiations with Iran and Russia will be the near-term market movers, Kissler said, adding that near-term global crude supplies remain ample and crude futures likely have a $5 to $7 per barrel geopolitical premium baked in. The U.S. also eased sanctions on Venezuela's energy sector on Friday, issuing two general licenses that allow global energy companies to operate oil and gas projects in the OPEC member and for other companies to negotiate contracts to bring in fresh investments. Oil sales from Venezuela controlled by the U.S. have totalled over $1 billion so far and in the next few months will bring in another $5 billion, U.S. Secretary of Energy Chris Wright told NBC News on Thursday. Money managers raised their net long U.S. crude futures and options positions in the week to February 10, the U.S. Commodity Futures Trading Commission said on Friday.

Ukrainian Strikes Take a Heavy Toll on Russia’s Oil Refineries - Ukrainian attacks on Russian oil refineries cost Russia’s oil and gas sector as much as $12.9 billion (1 trillion Russian rubles) last year, according to a local insurance broker. Direct losses for the sector topped $1.3 billion (100 billion rubles) in 2025. If these are added to the indirect losses and missed sales and profits, the total losses for Russia’s oil and gas industry amounted to $13 billion, Yevgeny Borovikov, deputy CEO at insurance broker Mains, told Russian daily Kommersant. Last year, Russian insurers booked losses as insurance claims for sabotage and terrorism skyrocketed amid intensified Ukrainian attacks on key infrastructure, including energy infrastructure and refineries, market participants told Kommersant. Crude oil deliveries to Russia’s refineries slumped in 2025 to the lowest level in at least 15 years, mostly due to unplanned outages in the second half of the year following intensified Ukrainian drone strikes on key Russian energy infrastructure.Last year, crude supply to Russian refineries slumped to 228.34 million tons. The decline in deliveries also led to lower crude processing rates, which dropped by 1.7% in 2025 from a year earlier, according to data cited Kommersant last month.Analysts attributed the drop in supplies to unscheduled maintenance at refineries following “a series of external factors” in the second half of 2025, while the Russian Energy Ministry has not commented on the matter.Russia has not publicly commented on or shared details of any refinery shutdowns or unplanned outages. In the second half of 2025, Ukraine intensified attacks on Russia’s oil refineries, depots, and export terminals in an escalation of the war on energy infrastructure, which has also seen Russia targeting Ukraine’s gas producing facilities and gas and power distribution networks as temperatures dropped. At one point in September, nearly 15% of Russia’s crude processing capacity was offline and in need of repairs following drone hits.

India Moves Against the Shadow Fleet With First-Ever Tanker Seizures - India has seized three oil tankers involved in oil smuggling in what is believed to be the country’s first move against the growing shadow fleet of tankers. The Indian Coast Guard has said that it busted on February 6 “an international oil-smuggling racket” in a land and sea operation. “The syndicate exploited mid-sea transfers in international waters to move cheap oil from conflict-ridden regions to motor tankers, evading duties owed to coastal states,” the Coast Guard added. The authorities intercepted three suspect vessels west of Mumbai.“The vessels known to frequently change identity are being escorted to Mumbai for further legal action, reinforcing India’s role as a net provider of maritime security and guardian of the rules-based international order,” the Coast Guard said. This is the first time India has moved to take action against shadow fleet tankers, sources with knowledge of India’s shipping industry told Bloomberg on Tuesday.India’s move to seize vessels of the dark fleet follows intensified efforts from Western countries, most of all the U.S. and EU, to act more decisively against shadow vessels making illicit trips to deliver sanctioned oil.The move also comes as the United States is pressuring India to halt imports of Russian crude oil as part of the U.S.-India trade deal. Indian refiners are still avoiding Russian oil as deals for delivery in April begin to be made. India’s largest state-owned refiner, Indian Oil Corporation (IOC), has boosted purchases of crude oil from West Africa and the Middle East, as New Delhi steers clear of Russian crude in the wake of the trade deal with the United States. Indian Oil and Bharat Petroleum Corporation Limited (BPCL), as well as the top private refiner Reliance Industries, have not made any fresh spot orders for Russian crude in the past week, sources with direct knowledge of the oil procurement deals told Bloombergon Monday.

Ceasefire Deal in Place, But Siege Continues for Syrian Kurds in Kobane - A deal between the Syrian government and the Kurdish SDF remains more or less in place in the Hasakeh Governorate, with the central government putting more and more of the former Kurdish-held territory under direct control.But the latest ceasefire not immediately collapsing like all the others doesn’t mean the situation is really resolved, as the major Kurdish city of Kobane remains under a state of effective siege, with massive displacement and reports of looting of Kurdish villages in the area.The humanitarian situation is increasingly worsening, according to the UN, even though they also noted a significant decline in the fighting. As recently as Sunday, the Kobane government noted that the Aleppo Governorate’s promises to withdraw troops and lift the siege hadn’t amounted to much of anything, beyond governorate-level officials seeking to formally rename the city to its Arabic name, Ayn al-Arab. Across the rest of what was formally Rojava, the autonomous Syrian Kurdistan region, major demonstrations were reported in the big cities, centering on calls for the Syrian constitution to formally recognize the rights of the Kurdish population and of women. Rallies against the siege of Rojava were also held by the Kurdish diaspora in Europe.Seeking to codify Kurdish rights in the constitution is a big issue for the minority. President Ahmed al-Sharaa last month issued a decree promising to respect their rights in an attempt to tamp down unrest.The Kurds, however, noted that former President Assad issued similar decrees promising concessions to the Kurds, and that government officials largely ignored things like the decree promise to grant citizenship to stateless Kurds in Hasakeh Governorate. They instead want an actual constitutional codification of those rights, to preclude it being a temporary promise by a single ruler.

Six Killed, Scores Wounded as Saudi-backed Forces Shoot Separatist Protesters in South Yemen - Rallies in favor of the separatist STC group in South Yemen continue to grow, and while the largest have been in the city of Aden, substantial protests are being reported elsewhere, including the Shabwa Governorate capital of Ataq.The rally in Ataq turned ugly today, however, when demonstrators were reported to have attempted to enter a building to remove the Yemeni flag from it, and pro-Saudi forces aligned with the self-proclaimed “government” opened fire on them, killing at least six. Scores of protesters were also reportedly wounded in the incident, and the reported toll continues to rise, as the “government” attempts to revise the narrative away from silencing dissent and “dispersing” protesters to claims that the protesters were “heavily armed” and actually started the fighting. There’s no evidence of the protesters in Ataq being armed at all, and local activists insisted the protests were entirely peaceful, with a focus on slogans calling for the withdrawal of Saudi military assets from the country.“Government” officials also claimed the protesters were affiliated with the STC, which is a curious claim because they also insist that the STC doesn’t even exist anymore since the Saudis kidnapped their negotiating team last month and announced that they agreed to disband.

Eight Muslim Countries Strongly Condemn Israel's Steps To Tighten Grip on Occupied West Bank - A group of eight Muslim countries issued a statement on Monday strongly condemning a raft of measures approved by the Israeli cabinet on Sunday to tighten Israel’s grip on the Israeli-occupied West Bank, which are explicitly designed to prevent the creation of a Palestinian state.According to a statement released by the Saudi Foreign Ministry, the foreign ministers of Saudi Arabia, the UAE, Egypt, Jordan, Turkey, Qatar, Indonesia, and Pakistan “condemned in the strongest terms the illegal Israeli decisions and measures aimed at imposing unlawful Israeli sovereignty, entrenching settlement activity, and enforcing a new legal and administrative reality in the occupied West Bank, thereby accelerating attempts at its illegal annexation and the displacement of the Palestinian people.” The ministers also “expressed their absolute rejection of these illegal actions, which constitute a blatant violation of international law, undermine the two-state solution, and represent an assault on the inalienable right of the Palestinian people to realize their independent and sovereign state on the 4 June 1967 lines, with occupied Jerusalem as its capital.”Each country that signed the statement is a member of President Trump’s new “Board of Peace,” formed to oversee the White House’s Gaza ceasefire plan, which does nothing to address the Israeli occupation of the West Bank and the dramatic increase in settlement expansion and settler violence against Palestinians. The new measures approved by the Israeli cabinet include changes to land registry laws to speed up the expansion of ilegal Jewish settlements, giving Israel more control of religious sites, and increasing Israeli enforcement in areas under the control of the Palestinian Authority. The PA has also strongly condemned the changes, calling them “de facto annexation” and urging the US to prevent the further displacement of Palestinians.Israeli Finance Minister Bezalel Smotrich, who also holds a position in the Defense Ministry that puts him in charge of expanding settlements, vowed in a statement on the changes to Israel’s West Bank occupation that he will “continue to kill the idea of a Palestinian state,” language he frequently uses when announcing new settlement projects.

Israeli Court Denies Life-Saving Cancer Treatment to 5-Year-Old Registered in Gaza - Palestine Chronicle - An Israeli court has rejected a request to allow a five-year-old Palestinian boy suffering from aggressive cancer to receive life-saving treatment, ruling that his registration as a resident of the Gaza Strip bars him from entering Israel even though he has lived in the occupied West Bank for years. The Jerusalem District Court dismissed a petition seeking permission to transfer the child from Ramallah to Tel HaShomer Hospital near Tel Aviv for a bone marrow transplant and antibody immunotherapy — procedures unavailable in both Gaza and the occupied West Bank. According to the British newspaper The Guardian, doctors treating the boy determined that the treatment was urgently required. Despite the child being in the occupied West Bank since 2022 for medical care, Israeli authorities classified him as a Gaza resident according to population registry records, placing him under Israel’s post-October 7 restrictions on Gaza entry. Judge Ram Winograd ruled on Sunday that granting an exception would undermine the broader policy preventing Gaza residents from entering Israel, writing that the petitioners failed to demonstrate a meaningful distinction between the child and other patients barred under the restrictions. The boy’s mother described the ruling as a “death sentence” for her son, Israeli newspaper Haaretz reported, adding that the boy’s father died of cancer three years earlier. Before October 2023, Palestinian patients from Gaza could apply for permits to reach specialized hospitals in East Jerusalem and Israel, but access was never guaranteed. Medical organizations and academic studies documented that roughly one-third of patient permit applications were delayed or denied in recent years, including many cancer cases, significantly increasing mortality risks for critically ill patients. Patients are forced to seek treatment outside Gaza because advanced oncology services do not exist in the territory. Gaza lacks radiotherapy facilities and comprehensive cancer centers, while the Israeli blockade restricts the entry of medical equipment, medications and specialist training, leaving hospitals unable to provide many life-saving treatments locally. Following the start of the genocidal war on October 7, 2023, Israeli occupation authorities largely halted medical exit permits for Gaza residents, including patients who had already begun treatment programs. The Guardian reported that Israeli human rights organization Gisha, which pursued the case in court, said the ruling effectively prioritizes registry classification over medical urgency even in the absence of any security allegations against the patient or family.