natural gas price falls by most in 4 years; distillates output at an 83 month high; gasoline supplies rise by most in 11 months

US oil prices fell for the first time in three weeks on fears that an end to the war in Ukraine and ​to sanctions on Russian oil would exacerbate the global oil glut…after rising 2.6% to $60.08 a barrel last week after Putin threatened Europe and Trump threatened Venezuela, the contract price for the benchmark US light sweet crude for January delivery hovered around a two-week high above $60 in Asian trading on Monday, as traders anticipated a U.S. interest rate cut this week that would support economic growth and energy demand, but then dropped 2% during the US session as concerns about abundant global supply overshadowed concerns about sanctions on Russian oil, and settled $1.20 lower at $58.88 a barrel after Iraq restored production ​t​o an oilfield which accounts for 0.5% of world oil supply, while traders weighed ongoing talks to end the war in Ukraine...oil futures traded lower in Asia on Tuesday morning as traders focused on developments in ​the peace talks between Russia and Ukraine to end the​ir war, and remained soft in early US trading as the Kremlin reacted favorably to a new U.S. national security strategy that called for better relations with Russia, and settled 63 cents lower at $58.25 a barrel with traders watching peace talks to end the war in Ukraine and a looming decision on U.S. interest rates, amid concerns about ample supply…. oil prices perked up in after hours trading Tuesday after the American Petroleum Institute reported a large unexpected draw from US crude oil inventories, then steadied in early Asian trading on Wednesday as a modest technical recovery lifted prices while traders reassessed the sharp drop in refining margins that had accelerated the recent sell-off, but extended their recent decline in US​ morning trading as concerns about global oversupply continued to weigh on sentiment, before bouncing off its low and settling 21 cents higher at $58.46 a barrel after officials said the U.S. seized an oil tanker off the coast of Venezuela, adding to concerns about immediate supplies… oil prices continued to rise on worldwide markets Thursday, on the news that the United States seized a sanctioned tanker off the coast of Venezuela, raising concerns about potential disruptions to oil supplies, but then traded lower in New York after the market saw no immediate fallout from the U.S. seizure of the sanctioned tanker, and settled 86 cents lower at $57.60 a barrel​, as traders shifted their attention back to the Russia-Ukraine peace talks and focused on large surpluses in U.S. gasoline and diesel inventories…. oil prices rose in Asian trading on Friday as the prospect th​at the U.S. ​would intercept more Venezuelan oil tankers deepened concerns about supply, but inched lower ​later on global markets as traders focused on an oil supply glut and a potential Russia-Ukraine peace deal, which outweighed concerns over Venezuelan supply disruptions, and settled 16 cents lower at $57.44 a barrel after the IEA forecast a 3.84 million bpd supply surplus, reinforcing bearish sentiment across crude oil futures, and left the January contract down 4.4% on the week….

Meanwhile, natural gas prices fell for the first time in eight weeks after weather forecasts were revised to indicate above normal temperatures the 2nd half of December….after rising 9.1% to a new 35 month high of $5.289 per mmBTU last week on forecasts for waves of polar air to plunge thru the eastern half of the US over the following two weeks, the price of the benchmark natural gas contract for January delivery opened 27.4 cents lower on Monday, gapping lower over the weekend a​fter weather models indicated a bearish shift and profit-taking took hold​​, and continued to tumble to settle 37.7 cents lower at $4.912 per mm BTU on forecasts for less cold weather over the next two weeks than​ was previously expected, near-record output, ample amounts of gas in storage​, and lower​ gas prices around the world….January natural gas opened 18.1 cents lower on Tuesday, falling overnight again, as the latest forecasts were calling for a mid-month thaw that could last until the 23rd, and again continued to tumble to settle 33.8 cents lower at $4.574 per mmBTU on more moderate two-week forecasts for weather and demand, near-record output, ample amounts of gas in storage and lower prices around the world….natural gas prices opened 2.4 cents higher on Wednesday, as analysts weighed the impending storage release and heating demand against stout storage levels and forecasts for a mid-month thaw, and rose to the intraday high of $4.696 at 1:10 PM, before falling to $4.542 forty minutes later, but settling 2.1 cents higher at $4.595 per mmBTU​, on forecasts for more demand over the next two weeks than had been expected, and on near-record gas flows LNG export plants…the January natural gas contract opened 16.5 cents lower on Thursday, falling overnight as a forecasted mid-month thaw that could last until Christmas has put bears in the driver’s seat, ​b​ut momentarily jumped ​back up to $4.387 as a report of a large withdrawal from storage hit the wire, but again pulled back to settle 36.4 cents lower at $4.231 per mmBTU​, as ​t​he larger-than-expected storage withdrawal was not enough to shake the bearish trend, a​nd traders stayed focused on milder mid-range forecasts and weakening demand expectations…natural gas prices were modestly lower again early Friday, as markets shrugged off the steep storage draw and focused on the ‘exceptionally warmer’ pattern ahead, and continued to fall in afternoon trading as forecasts pointed to a much warmer-than-normal second half of December, and settled 11.8 cents lower at $4.113 as traders appeared to be giving up on winter​ even before its official start on December 21, leaving prices 22.2% lower for the week, the largest weekly drop since ​November 29, 2021…

The EIA’s natural gas storage report for the week ending December 5th indicated that the amount of working natural gas held in underground storage fell by 177 cubic feet to 3,746 billion cubic feet by the end of the week, which left our natural gas supplies 28 billion cubic feet, or 0.7% lower than the 3,774 billion cubic feet of gas that were in storage on December 5th of last year, but 103 billion cubic feet, or 2.8% more than the five-year average of 3,732 3,643 billion cubic feet of natural gas that had typically been in working storage as of the 5th of December over the most recent five years….the 177 billion cubic foot withdrawal from natural gas storage for the cited week exceeded the 169 billion cubic foot withdrawal from storage that analysts had forecast in a Reuters poll ahead of the report, and was also more than the 167 billion cubic foot of gas that were pulled out of natural gas storage during the corresponding week of 2024, and was ​n​early double the average 89 billion cubic foot withdrawal from natural gas storage that had been typical for the same early December 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 December 5th indicated that even after an increase in our oil exports was more than offset by an increase in our oil imports, we still had to pull oil out of our stored crude supplies for the 20th time in forty-four weeks, and for the 33rd time in seventy-four weeks, largely because of an increase in demand for oil that the EIA could not account for….Our imports of crude oil rose by an average of 609,000 barrels per day to average 6,589,000 barrels per day, after falling by an average of 456,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 396,000 barrels per day to average 4,009,000 barrels per day, which, when used to offset our imports, meant that the net of our trade of oil worked out to an import average of 2,580,000 barrels of oil per day during the week ending December 5th, an average of 213,000 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 2,000 barrels per day lower at 605,000 barrels per day, while during the same week, production of crude from US wells was 38,000 barrels per day higher than the prior week at 13,853,000 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 17,038,000 barrels per day during the December 5th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,860,000 barrels of crude per day during the week ending December 5th, an average of 17,000 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 224,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US… So, based on that reported & estimated data, the crude oil figures provided by the EIA appear to indicate that our total working supply of oil from storage, from net imports, from transfers, and from oilfield production during the week ending December 5th averaged a rounded 402,000 more barrels per day than what our oil refineries reported they used during the week. To account for the difference between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a ​[ -402,000 ] barrel per day figure onto line 16 of the weekly U.S. Petroleum Balance Sheet, in order to make the reported data for the supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus indicating there must have been an error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed.…moreover, since 205,000 barrels per day of oil supplies could not be accounted for in the prior week’s EIA data, that means there was a 607,000 barrel per day difference between this week’s oil balance sheet error and the EIA’s crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week’s report are also off by that much, and also useless.... But since most oil traders react to these weekly EIA reports as if they were gospel, and since these weekly figures therefore often drive oil pricing and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it’s published, and just as it’s watched & believed to be reasonably reliable by most everyone in the industry…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil supply, see this EIA explainer….also see this old twitter thread from an EIA administrator addressing these ongoing weekly errors, and what they had once hoped to do about it)

This week’s rounded 224,000 barrel per day average decrease in our overall crude oil inventories came as an average of 259,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while an average of 35,000 barrels per day were being added to our Strategic Petroleum Reserve, extending the string of nearly continuous weekly additions to the SPR since September 2023, which followed nearly continuous SPR withdrawals over the 39 months prior to August 2023… Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports rose to 6,239,000 barrels per day last week, which was still 7.7% less than the 6,760,000 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 38,000 barrels per day higher at 13,853,000 barrels per day as the EIA’s estimate of the output from wells in the lower 48 states was 37,000 barrels per day higher at 13,416,000 barrels per day, while Alaska’s oil production was 1,000 barrels per day higher at 437,000 barrels per day...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 5.7% higher than that of our pre-pandemic production peak, and was also 42.8% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021.

US oil refineries were operating at 94.5% of their capacity while processing those 16,860,000 barrels of crude per day during the week ending December 5th, up from the 94.1% utilization rate of a week earlier, with increasing utilization largely due to the end of routine Fall refinery maintenance….the 16,860,000 barrels of oil per day that were refined that week were 1.2% more than the 16,659,000 barrels of crude that were being processed daily during the week ending December 6th of 2024, and were 1.6% more than the 16,597,000 barrels that were being refined during the prepandemic week ending December 6th, 2019, when our refinery utilization rate was at 90.6%, which was somewhat below the pre-pandemic normal range for this time of year…

With the decrease in the quantity of oil that was refined this week, gasoline output from our refineries was also lower, decreasing by 178,000 barrels per day to 9,576,000 barrels per day during the week ending December 5th, after our refineries’ gasoline output had increased by 197,000 barrels per day during the prior week.. This week’s gasoline production was 2.9% less than the 10,045,000 barrels of gasoline that were being produced daily over the week ending December 6th of last year, but virtually unchanged from the gasoline production of 9,753,000 barrels per day seen during the prepandemic week ending December 6th, 2019….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 380,000 barrels per day to an 83 month high of 5,431,000 barrels per day, after our distillates output had increased by 53,000 barrels per day during the prior week. After that near record production increase, our distillates output was 3.9% more than the 5,229,000 barrels of distillates that were being produced daily during the week ending December 6th of 2024, and also 3.9% more than the 5,228,000 barrels of distillates that were being produced daily during the pre-pandemic week ending December 6th, 2019....​

Even with this week’s increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the fourth consecutive week, but for just the sixth time in twenty-one weeks, increasing by 6,397,000 barrels to 220,819,000 barrels during the week ending December 5th, the largest increase in eleven months, coming after our gasoline inventories had increased by 4,518,000 barrels during the prior week. Our gasoline supplies increased by more this week even though the amount of gasoline supplied to US users rose by 130,000 barrels per day to 8,456,000 barrels per day, because our exports of gasoline fell by 161,000 barrels per day to 1,085,000 barrels per day, while our imports of gasoline fell by 113,000 barrels per day to 659,000 barrels per day… Even after thirty gasoline inventory withdrawals over the past forty-four weeks, our gasoline supplies were 0.5% more than last December 6th’s gasoline inventories of 219,689,000 barrels, and just about 1% below the five year average of our gasoline supplies for this time of the year…

After this week’s big increase in distillates production, our supplies of distillate fuels rose for the 22nd time in 47 weeks, increasing by 2,502,000 barrels to 116,788,000 barrels during the week ending December 5th, after our distillates supplies had increased by 2,059,000 barrels during the prior week.. Our distillates supplies rose by more this week even as the amount of distillates supplied to US markets, an indicator of domestic demand, rose by 728,000 barrels to 4,158,000 barrels per day, because our exports of distillates fell by 420,000 barrels per day to 1,097,000 barrels per day, while our imports of distillates fell by 9,000 barrels per day to 181,000 barrels per day... With 55 withdrawals from distillates inventories over the past 97 weeks, our distillates supplies at the end of the week were 3.7% less than the 121,335,000 barrels of distillates that we had in storage on December 6th of 2024, and about 7% below the five year average of our distillates inventories for this time of the year…

Finally, even with the increase in our oil imports, our commercial supplies of crude oil in storage fell for the 13th time in twenty-six weeks, and for the 22nd time over the past year, decreasing by 1,812,000 barrels over the week, from 425,691,000 barrels on December 5th to 427,503,000 barrels on November 28th, after our commercial crude supplies had increased by 574,000 barrels over the prior week… After this week’s decrease, our commercial crude oil inventories were 4% below the recent five-year average of commercial oil supplies for this time of year, while they were about 22% above the average of our available crude oil stocks as of the first weekend of December 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 December 5th were 0.9% more than the 421,950,000 barrels of oil left in commercial storage on December 6th of 2024, but were 3.4% below the 440,773,000 barrels of oil that we had in storage on December 8th of 2023, while 0.4% more than the 424,129,000 barrels of oil we had left in commercial storage on December 25th of 2022…

This Week's Rig Count

The US rig count was down by one over the week ending December 12th, the 4th decrease in fifteen weeks, as the number of rigs targeting oil rose by one to 413, while the count of rigs targeting natural gas was down by two, 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 December 12th, the second column shows the change in the number of working rigs between last week’s count (December 5th) and this week’s (December 12th) count, the third column shows last week’s December 5thactive rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting period a year ago, which in this week’s case was the 13th of December, 2024…

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Tailwater Capital Buys Central Midstream, Including OH Utica Assets -- Marcellus Drilling News - Tailwater Capital LLC, an energy and infrastructure private equity firm based in Dallas, Texas, yesterday announced it has closed on the acquisition of a majority interest in Central Midstream Partners, LLC (originally established as Central Crude). Central Midstream provides liquids transportation, storage, and terminal services to support demand-pull customers across the Gulf Coast and in the Utica region. We have to confess we had not heard about nor written about Central Midstream before this announcement.

NOG & INR Partner to Buy Antero Resources’ Ohio Utica for $1.2B - The second round of big news coming from Antero Resources today is the sale of the company’s Utica Shale assets. We told you in November that Antero, the largest Marcellus/Utica (M-U) driller in West Virginia, officially began to market its Ohio Utica assets for sale (see Antero Returns to Dry Gas Drilling; Confirms Ohio Utica for Sale). They found a buyer (actually, buyers). Northern Oil and Gas, Inc. (NOG), a company that invests in non-operated oil and gas assets (they let others do the drilling), and Marcellus/Utica driller Infinity Natural Resources (INR) announced a partnership to purchase the Ohio Utica assets of Antero Resources Corporation and Antero Midstream Corporation for a combined purchase price of $1.2 billion in cash.

NOG Announces $1.2 Billion Joint Acquisition with Infinity Natural Resources --Northern Oil and Gas, Inc. today announced that it has entered into a definitive agreement to acquire a 49% stake in Ohio Utica Shale Assets in partnership with Infinity for a purchase price, net to NOG, of $588.0 million in cash, subject to customary closing adjustments. The Acquired Assets are located in the Utica shale of eastern Ohio and include approximately 35,000 net acres with over 100 gross identified undeveloped locations. The acquired upstream asset is one of the few remaining growth assets in the core of the Utica that can support a full rig development pace for multiple years. The upstream asset has an expected 2026 production, net to NOG, of ~65 MMcfe per day (2-stream, 92% gas) for 2026 with a 30%+ compound annual growth rate in production through the end of the decade, assuming a development plan with a continuous one rig program. The upstream asset represents a ~43% working interest net to NOG. In addition, the asset features a low PDP decline rate of ~15% in the next twelve months, falling to ~13% over the next several years. The asset is expected to generate ~$100MM in unhedged cash flow from operations net to NOG in 2026 at recent strip prices with ~19% generated by the midstream assets. The substantial growth expected on the assets on a go-forward basis is based on an average annual capital program of ~$100 million at a single rig cadence. Captive midstream offers opportunity to drive best in class margins with limited incremental midstream growth-capital required. The midstream system has been built to accommodate a peak historical gross level of ~600 MMcfe per day. Significant midstream infrastructure with 140 miles of pipe supporting low- and high-pressure gathering, compression and 90 miles of water delivery systems. The Acquired Assets are positioned to realize improved pricing via direct connections to premium out of basin markets via the Tallgrass Rex pipeline. The midstream system has ample capacity at regional processing plants (MPLX/Blue Racer) to grow future volumes and provides optionality across phase windows driven by both a rich and dry gas system. Midstream cash flows are expected to grow by 75% by 2028. NOG also believes that third party volume opportunities exist over time driving higher throughput and generating fee-based revenue, creating further upside. Upon closing and transition of services, Infinity will be the operator of substantially all of the assets, with NOG participating in development pursuant to cooperation and multi-year joint development agreements entered into in connection with the acquisition. The effective date for the transaction is July 1, 2025, and closing is expected by the end of the first quarter of 2026. Due to the effective date, NOG expects to receive a material downward closing purchase price adjustment. In connection with signing, NOG is placing a $58.8 million deposit in escrow. The obligations of the parties to complete the acquisition are subject to satisfaction or waiver of customary closing conditions.

Infinity Natural Resources Announces Transformational Acquisition in the Ohio Utica Shale ... Infinity Natural Resources, Inc. today announced that on December 5, 2025 its subsidiary Infinity Natural Resources, LLC entered into agreements to acquire upstream and midstream assets in Ohio from Antero Resources Corporation and Antero Midstream Corporation for a combined $1.2 billion. Concurrently, Northern Oil and Gas, Inc. will acquire an undivided 49% interest in the assets for $588 million, resulting in a $612 million purchase price net to Infinity for its undivided 51% interest. Infinity expects to fund the Transaction with cash on hand and borrowings under an expanded senior secured revolving credit facility (the “Credit Facility”). The Agreements have an effective date of July 1, 2025, with closing anticipated in the first quarter of 2026, and the Transaction is subject to customary purchase price adjustments and closing conditions. Transaction Highlights

• Significant Addition to Top Tier Utica Acreage Position: Pro forma INR will control ~102k Ohio net horizontal Utica Shale acres with ~1.4 Tcfe of undeveloped net reserves
• Extends Premium Drilling Inventory: Highly contiguous acreage improves long lateral well development and adds high quality inventory across all phase windows, improving overall break-evens
• Captures Vertical Integration Benefits through Acquired Midstream Assets: ~141 miles of gathering lines with capacity to support 600 mmcf/d along with ~90 miles of water lines, reducing operating costs and cash break-evens
• Delivers Significant Operational and Financial Synergies: Estimated $25 million of synergies expected to be realized in 2026 alone, driven by lower operating costs and complementary acreage positions
• Immediately Accretive and Value Enhancing: Accretive across key financial metrics, including Adjusted EBITDAX margins, cash flow per share, and net asset value per share
• Strong Growth with Financial Discipline: Expected to complement Infinity’s best in class production growth amongst our Appalachian peers for 2026 and 2027. Accelerated Adjusted EBITDAX growth creates path to <1.0x net leverage by YE 2027

“This transformational and strategic acquisition represents the largest transaction in Infinity’s history, continuing our track record of aggregation within the Appalachian basin,” said Zack Arnold, President and CEO of Infinity. “We are acquiring high-quality, cash-generating assets in the heart of the Utica Shale that immediately compete for capital and significantly enhance our operational scale.” “The Antero Ohio Assets complement our existing footprint, providing substantial inventory depth with over 110 low break-even locations across multiple development windows. The addition of strategic midstream infrastructure provides an additional growth engine for the Company. We are pleased that Northern recognized the value of these assets, and we are excited to partner with them on this highly accretive transaction that creates compelling value for both Infinity and Northern in the near and long term.” Upstream assets:

• Approximately 71,000 net acres in the core of the Utica Shale concentrated in Ohio’s Guernsey, Belmont and Harrison counties
• 3^rd quarter 2025 net daily production of approximately 133 MMcfe/d (81% gas, 19% liquids) from 255 producing laterals (241 operated)
• Low decline PDP assets
• Over 110 undeveloped laterals totaling 1.6 million lateral feet across volatile oil, rich gas and dry gas windows
• 764 billion cubic feet of undeveloped reserves, primarily natural gas

Midstream and marketing assets

• Approximately 141 miles of wholly owned midstream gathering lines
• Approximately 90 miles of water lines
• 600 mmcfe/d of throughput capacity to support asset growth and regional third party gathering
• RexZone3 marketing contract further enhances margins and provides additional synergies

The Transaction creates a highly complementary asset base that leverages Infinity’s proven operational expertise in the Utica Shale. The contiguous nature of the acquired acreage, which is adjacent to Infinity’s existing operations in Ohio, enables optimized development planning, shared infrastructure utilization, and operational cost reductions, creating enhanced scale and meaningful operational synergies across the combined portfolio.The Transaction significantly extends Infinity’s inventory runway by adding high-quality drilling locations that immediately compete for capital allocation. This expanded inventory base provides multiple development options across various commodity price environments while offering greater flexibility in capital deployment strategies. Additionally, the acquired gathering infrastructure and marketing contracts provide enhanced control over product transportation and pricing, creating additional margin opportunities across the combined asset base through improved midstream value capture.Infinity’s demonstrated ability to optimize spacing, lateral length, and completion designs positions the Company to drive improvements in the economics of the acquired assets. This operational expertise, combined with the scale benefits of the expanded asset base, is expected to accelerate capital efficiency gains and enhance overall returns across the integrated operations.

US: Northern Oil and Gas announces $1.2 billion joint acquisition with Infinity Natural Resources

• NOG to partner with Infinity Natural Resources to purchase the Ohio Utica assets of Antero Resources Corporation and Antero Midstream Corporation, for a combined unadjusted purchase price of $1.2 billion in cash
• NOG’s non-operated interest will represent a 49% undivided ownership in the Utica Assets for $588 million in cash, with 67% of the Purchase Price allocated to the upstream assets and 33% of the Purchase Price allocated to the midstream assets
• Upstream comprised of ~35,000 acres net to NOG with exposure to dry gas, rich gas, and condensate production and future development locations
• Midstream comprised of over 140 miles of low- and high-pressure gathering pipelines, compression and 90 miles of water sourcing and handling systems that are ready-built to immediately service development inventory
• Estimated 2026 production net to NOG of ~65 MMcfe per day (2-stream, 92% gas, <15% decline rate) with an anticipated 30%+ CAGR through the end of the decade, with volumes expected to more than triple
• Over 100 gross identified undeveloped locations provides substantial opportunities for continued growth
• Premier, economically resilient inventory with average PV-10 breakeven price below $2 per MMBtu, immediately competes for

Northern Oil and Gas (NOG) has entered into a definitive agreement to acquire a 49% stake in Ohio Utica Shale Assets in partnership with Infinity for a purchase price, net to NOG, of $588.0 million in cash, subject to customary closing adjustments.The Acquired Assets are located in the Utica shale of eastern Ohio and include approximately 35,000 net acres with over 100 gross identified undeveloped locations.The acquired upstream asset is one of the few remaining growth assets in the core of the Utica that can support a full rig development pace for multiple years. The upstream asset has an expected 2026 production, net to NOG, of ~65 MMcfe per day (2-stream, 92% gas) for 2026 with a 30%+ compound annual growth rate in production through the end of the decade, assuming a development plan with a continuous one rig program. The upstream asset represents a ~43% working interest net to NOG. In addition, the asset features a low PDP decline rate of ~15% in the next twelve months, falling to ~13% over the next several years. The asset is expected to generate ~$100MM in unhedged cash flow from operations net to NOG in 2026 at recent strip prices with ~19% generated by the midstream assets. The substantial growth expected on the assets on a go-forward basis is based on an average annual capital program of ~$100 million at a single rig cadence.Captive midstream offers opportunity to drive best in class margins with limited incremental midstream growth-capital required. The midstream system has been built to accommodate a peak historical gross level of ~600 MMcfe per day. Significant midstream infrastructure with 140 miles of pipe supporting low- and high-pressure gathering, compression and 90 miles of water delivery systems. The Acquired Assets are positioned to realize improved pricing via direct connections to premium out of basin markets via the Tallgrass Rex pipeline.The midstream system has ample capacity at regional processing plants (MPLX/Blue Racer) to grow future volumes and provides optionality across phase windows driven by both a rich and dry gas system. Midstream cash flows are expected to grow by 75% by 2028. NOG also believes that third party volume opportunities exist over time driving higher throughput and generating fee-based revenue, creating further upside.Upon closing and transition of services, Infinity will be the operator of substantially all of the assets, with NOG participating in development pursuant to cooperation and multi-year joint development agreements entered into in connection with the acquisition.The effective date for the transaction is July 1, 2025, and closing is expected by the end of the first quarter of 2026. Due to the effective date, NOG expects to receive a material downward closing purchase price adjustment. In connection with signing, NOG is placing a $58.8 million deposit in escrow. The obligations of the parties to complete the acquisition are subject to satisfaction or waiver of customary closing conditions.

Northern to Acquire 49% Stake in Ohio Utica Shale Assets  - Northern Oil and Gas, Inc.NOG has made a major strategic move in the oil and gas sector by entering into a definitive agreement to acquire a 49% stake in the Ohio Utica Shale assets. This acquisition, in partnership with Infinity Natural Resources INR, is valued at $588 million (net to NOG) in cash, subject to customary closing adjustments. The transaction marks a significant milestone in NOG’s growth strategy and further strengthens the portfolio, as it expands footprint in one of the most promising natural gas regions in the United States. The assets acquired by NOG are located in the heart of the Utica play, in eastern Ohio. The assets encompass approximately 35,000 net acres with more than 100 gross identified undeveloped locations. The acquisition gives NOG access to one of the last remaining growth assets in the core of the Utica, which has the potential to support full rig development for several years.NOG anticipates that these assets will produce approximately 65 MMcfe per day (2-stream, 92% gas) by 2026. This expected production is underpinned by more than 30% compound annual growth rate of output through the end of the decade, assuming a continuous development plan. The asset is expected to generate significant cash flow, with projections indicating $100 million in unhedged cash flow from operations for NOG in 2026, based on recent strip prices.The upstream assets acquired by NOG represent a substantial opportunity for growth and long-term production. These assets are situated in the highly productive Utica Shale region, where NOG has identified substantial development potential. The acreage holds more than 100 gross locations that are yet to be developed, creating an attractive investment opportunity for long-term value generation. With an expected 43% working interest net to NOG, the acquired assets are expected to produce significant natural gas volumes, mainly from gas-rich formations. The development strategy will involve a single-rig program, which is anticipated to generate continuous production growth through the remainder of the decade. Furthermore, the assets have a low decline rate of around 15% over the next year, with a long-term decline rate expected to stabilize around 13% in the following years, making them highly resilient and generating steady free cash flow. The development of the upstream assets will be bolstered by a substantial capital program, estimated at around $100 million annually, helping NOG unlock additional production and value over time. This consistent reinvestment in the assets positions NOG well for sustained growth and cash flow generation.The acquisition of midstream assets in conjunction with upstream production represents a key value driver for NOG. The midstream system associated with the Ohio Utica Shale assets is highly integrated, with 140 miles of gathering pipeline and 90 miles of water delivery systems already in place. The existing infrastructure provides ample capacity to support production growth, with the potential for incremental expansion with minimal capital outlay.Additionally, the midstream system is designed to facilitate direct connections to premium out-of-basin markets through the Tallgrass Rex pipeline, enabling NOG to realize superior pricing for its natural gas production. The proximity to key infrastructure and regional processing plants, such as MPLX and Blue Racer, positions the assets for significant growth, both in terms of production volumes and margins.Midstream cash flows are expected to grow 75% by 2028, attributed to higher throughput and an increasing volume of third-party volumes. The combination of NOG’s upstream and midstream assets creates a unique opportunity to leverage existing infrastructure while driving long-term value creation.In this transaction, NOG has partnered with Infinity, a proven operator in the Utica Shale region. Infinity will assume the role of the operator for the majority of the assets, with NOG actively participating in the development through cooperation and joint development agreements. This partnership is expected to enhance NOG’s ability to execute its development strategy efficiently, benefiting from Infinity’s operational expertise and focus on long-term value creation.Both companies share a commitment to delivering strong returns to investors, and this collaboration is expected to accelerate the development of the assets, unlocking substantial value for shareholders in the years to come. The transaction also aligns with NOG’s strategy of acquiring high-quality, high-return assets that can deliver immediate cash flow while offering substantial upside potential. NOG’s CEO, Nick O’Grady,stated that the Utica region is a target-rich natural gas play, and the acquisition positions NOG to take advantage of the area's significant growth potential. With Infinity as an operating partner, NOG is confident that the acquisition will deliver substantial returns for both companies' shareholders. The deal is expected to add significant value to NOG’s Appalachian portfolio, offering visible growth prospects well into the next decade.The acquisition of the Ohio Utica Shale assets is a pivotal move in NOG’s ongoing strategy of expansion and growth in high-return shale plays. This acquisition provides the company with a substantial foothold in one of the most productive natural gas regions in the United States, further setting NOG’s position as a leader in non-operated working interest ownership.The long-term growth potential of the Utica Shale, combined with NOG’s expertise in capital-efficient development, positions it to generate substantial returns for investors. In summary, the strategic acquisition of the Ohio Utica Shale assets represents a significant step forward for Northern Oil and Gas. With a clear focus on value creation, a proven partnership with Infinity and a robust development plan, NOG is well-positioned to generate substantial long-term returns from this transaction. The company’s integrated approach to upstream and midstream assets provides a solid foundation for continued growth and value creation in the years ahead.

Kirkland Represents Infinity Natural Resources, Inc. on Joint Acquisition in the Ohio Utica Shale for $1.2 Billion - Kirkland & Ellis advised Infinity Natural Resources, Inc. (NYSE: INR) on a definitive agreement to acquire upstream and midstream assets in Ohio from Antero Resources Corporation (NYSE: AR) and Antero Midstream Corporation (NYSE: AM) for a combined $1.2 billion. Concurrently, Northern Oil and Gas, Inc. (NYSE: NOG) will acquire an undivided 49% interest in the assets for $588 million, resulting in a $612 million purchase price net to Infinity for its undivided 51% interest. The agreements have an effective date of July 1, 2025, with closing anticipated in the first quarter of 2026, subject to customary purchase price adjustments and closing conditions. Read Infinity Natural’s press release

EMG, Which Owns 30% of Ascent Resources, Blocked from Selling -- Marcellus Drilling News -- Ascent Resources, formerly American Energy Partners, was founded by gas legend Aubrey McClendon and is a privately held company focused 100% on the Ohio Utica Shale. Ascent, headquartered in Oklahoma City, OK, is Ohio’s largest natural gas producer and the 8th largest natural gas producer in the U.S. The largest shareholder in the privately owned company is the private equity firm Energy & Minerals Group (EMG), with an "over 30% stake" in the company. EMG plans to sell that stake in one of its portfolio companies to another EMG company. Another (smaller) investor, the Abu Dhabi Investment Council, has sued to block the transfer, alleging a "conflicted sale" that will short-change existing investors.

Antero Unloads Utica Assets, Goes All in on Marcellus to Bolster Natural Gas Liquids Development Antero Resources Corp. said Monday it would exit the Utica Shale in Ohio and bolt on 385,000 net acres in West Virginia’s Marcellus Shale in a series of transactions valued at more than $5 billion.A line chart titled “NGI’s Appalachia Regional Avg. Daily Prices” showing natural gas spot prices across 2025. The graph tracks daily Appalachia regional averages in $/MMBtu, highlighting sharp winter price spikes above $12 in early 2025, a secondary peak near $8 in March, followed by a decline into the $2–$3 range through summer before a steady rebound toward $5 by late November. At A Glance:

• Company exiting Ohio
• NOG, Infinity to purchase Utica assets
• Transactions value at over $5 billion

US operator buys in Marcellus, sells in Utica in deals worth $4 billion - Appalachian-focused Antero Resources announced on Monday that it will acquire Marcellus shale assets in West Virginia, in the US, and sell its Utica shale position in Ohio in two deals worth a total of $4 billion. Antero said it will pay $2.8 billion to HG Energy in a deal that includes about 385,000 net acres in West Virginia that produce approximately 850 million cubic feet equivalent per day. It will add to Antero’s existing 475,000 net acre position in the Marcellus. Antero said it has identified about $950 million in potential synergies over the next decade for the HG Energy acreage. The acquisition is expected to close in the second quarter of 2026. “The acquired assets will also bolster our industry leading maintenance capital efficiency while providing us with further dry gas optionality for local demand from data centres and natural gas fired power plants,” Antero chief executive Michael Kennedy said in a statement. Meanwhile, Antero is selling its Utica upstream and midstream assets to Infinity Natural Resources and Northern Oil & Gas in a $1.2 billion deal that should close in the first quarter of next year. The deal includes about 71,000 net acres in the Utica across Ohio’s Guernsey, Belmont and Harrison counties. The acreage produced about 133 MMcfed in the third quarter from 255 producing lateral wells, according to Infinity. Meanwhile, the divested midstream assets include about 141 miles (227 kilometres) of gathering lines that can handle approximately 600 MMcfed. Antero said the upstream assets will sell for about $800 million, while the midstream assets were tagged at $400 million. Antero chief financial officer Brendan Krueger said the deal allowed the company to sell a “non-core asset at an attractive valuation”. Infinity will hold a 51% interest in the acreage, while Northern Oil and Gas will hold the remaining 49%, according to Infinity. Infinity said it is putting up $612 million for the deal, while Northern Oil & Gas will contribute $588 million. (Copyright)

Antero Expands In Appalachia With $3.9 Billion Deal Shuffle - Antero Resources is shaking up its Appalachian portfolio, spending nearly $4 billion to acquire West Virginia shale assets and exit its Ohio positions in a sweeping asset trade covering both production and pipelines. Antero Resources just announced a $2.8 billion deal to snap up HG Energy II’s upstream assets in West Virginia’s Marcellus Shale, instantly boosting next year’s expected production by about 850 million cubic feet equivalent per day. That move further establishes Antero as a powerhouse in Appalachia. On the flip side, the firm is selling off its Ohio Utica Shale assets for $800 million, exiting a region it now considers non-core. Meanwhile, Antero Midstream is paying $1.1 billion for HG Energy II’s regional pipeline network, which adds significant capacity and future development sites. To square things up, Antero Midstream will offload its Utica pipes for $400 million, while Northern Oil and Gas and Infinity Natural Resources are taking on the Ohio assets for $1.2 billion. It all adds up to a focused bet on Marcellus gas and infrastructure. Antero’s move to hone in on the Marcellus Shale could bump its production by more than 30% next year, highlighting how firms are funneling capital into regions with better returns and established infrastructure. Nearly $4 billion changing hands points to renewed deal activity in the US oil and gas sector, as players target efficiency and scale. The new owners of Ohio’s 71,000 net upstream acres and extensive pipelines are placing their bets too, reinforcing the strong demand for pipeline access in major basins. Moves like Antero’s show how US energy firms are retooling shale portfolios as natural gas demand grows, fueled by exports and power needs. Doubling down on the Marcellus underlines ongoing faith in Appalachia as a long-term gas giant. All this trading keeps the region competitive, with money still pouring into pipeline and drilling projects, even as the sector faces big questions over future supply and climate goals.

Antero Midstream Announces Pricing of Upsized $600 Million Offering of Senior Notes - Antero Midstream Corporation (NYSE: AM) ("Antero Midstream") announced today the pricing of its upsized private placement to eligible purchasers of $600 million in aggregate principal amount of 5.75% senior unsecured notes due 2034 at par (the "Notes"). The offering is expected to close on December 23, 2025, subject to customary closing conditions. Antero Midstream estimates that it will receive net proceeds of approximately $593 million, after deducting the initial purchasers' discounts and estimated expenses. Antero Midstream intends to use the net proceeds from the offering, together with borrowings under Antero Midstream Partners LP's ("Antero Midstream Partners") revolving credit facility and the net proceeds from the disposition of all of Antero Midstream's Utica Shale midstream assets (the "Utica Disposition"), to fund the acquisition of HG Energy II Midstream Holdings, LLC from HG Energy II LLC (the "HG Acquisition"), and related fees and expenses. The completion of this offering is not contingent on the consummation of the HG Acquisition or the Utica Disposition and the HG Acquisition and the Utica Disposition are not contingent on the closing of this offering. If (i) the closing of the HG Acquisition has not occurred on or prior to the later of (x) June 2, 2026 and (y) such date to which the outside date under the Membership Interest Purchase Agreement, dated December 5, 2025, by and among by and among Antero Midstream Partners, Antero Resources Corporation, HG Energy II LLC, HG Energy II Production Holdings LLC and HG Energy II Midstream Holdings LLC (the "HG Purchase Agreement") as in effect on the closing date of this offering may be extended in accordance with the terms thereof, which date shall be no later than September 2, 2026, any such extension to be set forth in an officers' certificate delivered to the trustee prior to the close of business on June 2, 2026 or such other extended outside date as shall then be applicable (the "Special Mandatory Redemption Outside Date"), (ii) prior to the Special Mandatory Redemption Outside Date, the HG Purchase Agreement is terminated according to its terms without the closing of the HG Acquisition or (iii) Antero Midstream Partners determines based on its reasonable judgment that the HG Acquisition will not close prior to the Special Mandatory Redemption Outside Date or at all, Antero Midstream Partners will be required to redeem all of the outstanding Notes at a redemption price equal to 100% of the initial issue price of the Notes plus accrued and unpaid interest, if any, to but excluding the special mandatory redemption date. The Notes to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes are being offered only to persons reasonably believed to be qualified institutional buyers in reliance on Rule 144A under the Securities Act and outside the United States pursuant to Regulation S under the Securities Act. This press release is neither an offer to sell nor a solicitation of an offer to buy the Notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the Notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful. Antero Midstream Corporation is a Delaware corporation that owns, operates and develops midstream gathering, compression, processing and fractionation assets located in the Appalachian Basin, as well as integrated water assets that primarily service Antero Resources Corporation's properties. This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Midstream's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Midstream expects, believes or anticipates will or may occur in the future, such as statements regarding the proposed offering and the intended use of proceeds are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended. All forward-looking statements speak only as of the date of this release. Although Antero Midstream believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Midstream expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements. Antero Midstream cautions you that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond Antero Midstream's control. These risks include, but are not limited to, the risk that one or both of the HG Acquisition and the Utica Disposition will not close on the timeline anticipated, or at all, commodity price volatility, inflation, supply chain or other disruptions, environmental risks, Antero Resources Corporation's drilling and completion and other operating risks, regulatory changes or changes in law, the uncertainty inherent in projecting Antero Resources Corporation's future rates of production, cash flows and access to capital, the timing of development expenditures, impacts of world health events, cybersecurity risks, the state of markets for, and availability of, verified quality carbon offsets and the other risks described under the heading "Item 1A. Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2024 and its subsequently filed Quarterly Reports on Form 10-Q.

Take Me Home, Country Roads – With M&A, Antero Homes In on West Virginia and Exits Ohio | RBN Energy - The consolidation of upstream and midstream assets in the Marcellus/Utica continued this week with announcements by Antero Resources and Antero Midstream that they had reached agreements to acquire privately held HG Energy II’s extensive holdings in “almost heavenly” West Virginia and to divest non-core assets in Ohio to Infinity Natural Resources and Northern Oil & Gas. In today’s RBN blog, we detail the deals, which will make “the two Anteros” West Virginia-only companies, and discuss how the transactions affirm recent trends in Appalachia. The four deals that Antero Resources and Antero Midstream — two separate but closely aligned, publicly owned companies — announced on December 8 hit a lot of the same notes as the EOG and EQT transactions. Let’s start with the agreements with HG Energy II, which is backed primarily by Quantum Energy Partners. Antero Resources said it has entered into a definitive agreement to acquire HG Energy’s upstream assets for $2.8 billion in cash plus the assumption of HG Energy’s commodity hedge book. At the same time, Antero Midstream said it has agreed to buy HG Energy’s midstream assets for $1.1 billion in cash. Both deals are expected to close in Q2 2026. Antero Resources currently holds about 475,000 acres in northern West Virginia — yellow-shaded areas in Figure 1 below show their general location — and produced about 3.4 Bcfe/d in Q3 2025 or, more precisely, 2.2 Bcf/d of natural gas and 206 Mb/d of NGLs. HG Energy, in turn, holds about 385,000 net acres (green-shaded areas) and produces about 850 MMcfe/d. (No gas/NGLs breakdown of HG Energy’s production was provided.) HG Energy also comes to Antero with more than 400 remaining drilling locations with average lateral lengths of about 20,300 feet. (More on that in a moment.) Antero Resources’ and HG Energy’s production is close to two of the region’s largest gas processing complexes (MPLX’s Sherwood and Smithburg facilities; plant icons in map) and to two important gas pipelines. One is the EQT-operated Mountain Valley Pipeline (MVP; magenta line in map), which can transport up to 2 Bcf/d — and soon, with a planned expansion, up to 2.5 Bcf/d — to gas consumers in Virginia, the Carolinas and other parts of the Southeast. The other is the 1.5-Bcf/d Stonewall Pipeline (orange line), which is co-owned by operator DT Midstream (85% stake) and Antero Midstream (15%) and which shuttles gas to the Columbia Gas Transmission (CGT) pipeline. (A Stonewall-MVP interconnection has been proposed.) Before we get to the Antero Midstream/HG Energy deal, we should note that a significant portion of Antero Resources’ and HG Energy’s acreage is contiguous, allowing for more efficient drilling and completion. As shown in the left graphic in Figure 2 below, pre-acquisition development of the two companies’ side-by-side acreage (yellow- and green-shaded areas) would typically involve two well pads — one for each company (small yellow and green squares) — and a total of 10 relatively short laterals (arrows within yellow- and green-shaded areas) averaging 9,570 feet. In contrast, the pro forma development (right graphic) will require only one pad (yellow square near bottom) and only five laterals (arrows within yellow-shaded area), averaging a much longer 19,140 feet. As you would expect, that change will significantly increase both the location’s PV-10 metric (present value discounted at an annual rate of 10%) and its internal rate of return (IRR; see “Key Stats” tables below graphics). Antero has estimated it will see $950 million in synergy-related savings over 10 years. The assets Antero Midstream will acquire from HG Energy include about 50 miles of gathering pipelines (green lines in Figure 1) that can bidirectionally transport dry, lean, and liquids-rich natural gas under a fixed-fee agreement with Antero Resources. The to-be-acquired assets also include about 50 miles of water pipelines, aboveground storage and associated water withdrawal points. Antero Midstream said it expects to integrate the acquired gathering pipelines into its own system immediately upon closing and to integrate the water assets into its closed-loop fresh water and recycled water system over a period of several months next year. The company noted that HG Energy’s gathering system has a capacity of about 900 MMcf/d and that the more than 400 undeveloped well locations Antero Resources will be acquiring in its deal will be dedicated to Antero Midstream. Next, let’s look at the two Anteros’ divestitures in the Utica in eastern Ohio. First, Antero Resources is selling its acreage and production assets for $800 million to a team of two E&Ps: Infinity Natural Resources, which will take a 51% ownership interest, and Northern Oil & Gas (NOG), which will hold a 49% stake. Similarly, Antero Midstream is selling its related midstream assets to the same 51/49 team for $400 million. The deals are expected to close in Q1 2026. The upstream deal will give Infinity and NOG a total of about 71,000 net acres, the vast majority of them in Ohio’s Guernsey, Belmont and Harrison counties — the heart of the Utica production area. In Q3 2025, Antero Resources’ 255 producing wells there — 241 of them operated by Antero — churned out an average of about 133 MMcfe/d, 81% of it gas and 19% either NGLs or condensate. The transaction also will give Infinity and NOG “over 110 undeveloped laterals totaling 1.6 million lateral feet across volatile oil, rich gas and dry gas windows” in the play, Infinity said in a statement. It added that there are an estimated 764 Bcf of undeveloped reserves beneath the acreage to be acquired, most of it natural gas. The midstream deal will give the buyers about 141 miles of low- and high-pressure gathering pipelines with 600 MMcf/d of throughput capacity as well as 90 miles of water lines. ​  As we noted in our Hit the Lights blog series on rising condensate production in the Utica, Infinity is a leading condensate producer in eastern Ohio — #2 now that EOG has acquired EAP — and became a publicly held company on January 30 with its long-anticipated initial public offering (IPO). NOG, in turn, is a “non-op” specialist that over the past few years has entered into a number of deals in which it took a minority interest in production assets and left their operation to its partners, NOG said it expects production from the upstream assets it and Infinity will be acquiring from Antero Resources to triple by 2030, and noted that the related midstream system “has ample capacity at regional processing plants (MPLX/Blue Racer) to grow future volumes.” To sum up, the deals Antero Resources and Antero Midstream recently reached with HG Energy in West Virginia and the Infinity/NOG team in Ohio continue the upstream and midstream consolidation trends that have characterized the Marcellus/Utica and other major U.S. production areas through the first half of the 2020s. While there are fewer E&Ps and midstreamers than five years ago, we expect that the “urge to merge” will extend into the latter half of this decade.

Gas Deals Take Center Stage in Q4 – Rigzone -After being overshadowed by oil focused transactions, gas deals have taken center stage in the final quarter of 2025 as strong current pricing and a bullish outlook for the commodity motivates buyers. That’s what Andrew Dittmar, Principal Analyst at Enverus Intelligence Research (EIR), said in a statement sent to Rigzone recently, adding that “the latest round of deals include Antero Resources acquiring West Virginia producer HG Energy’s upstream assets for $2.8 billion plus the purchase of its midstream infrastructure by Antero Midstream for $1.1 billion”. “Concurrently Antero and Antero Midstream are divesting their Ohio Utica position to a partnership of Infinity Natural Resources and Northern Oil and Gas [NOG] for a total of $1.2 billion, with the upstream portion garnering $800 million and the balance from midstream,” Dittmar continued. In the statement, Dittmar said the deals “have an obvious strategic rationale for Antero as the company blocks up its core operating region in West Virginia and adds the second largest private E&P in the Marcellus by remaining inventory”. “HG’s more than 400 remaining locations compliment Antero’s legacy position with comparable quality. The acquisition of HG by Antero had a sense of inevitability given their relative positions within the play and likely just needed the right time and commodity price environment for the two companies to come together,” he added. “Along with the strategic fit between leasehold positions, the deal offers the opportunity to add further midstream infrastructure to Antero Midstream’s holdings,” he continued. Dittmar highlighted in the statement that Antero “says it has identified $950 million in cumulative synergies (P-10 over 10 years) with more than half coming from drilling and completion savings and development optimization including longer laterals”, noting that “that is the type of strategic fit that investors want to see in acquisitions”. Looking at HG “and their sponsor Quantum Energy Partners” in the statement, Dittmar noted that “strong gas prices and improved market sentiment around Appalachian gas including from data center demand make this an opportune time to pursue an exit”. Dittmar went on to point out that Antero “is matching the HG purchase with the divestment of its Ohio Utica position to Infinity”, adding that this “has the dual benefits of partially offsetting the acquisition cost while also streamlining its portfolio and removing an asset that was not slated for material capital investment”. “The deal gives Infinity, a small and only relatively recently public E&P, a chance to expand its scale in the Utica with an asset that compliments its legacy acreage,” he highlighted. Dittmar pointed out in the statement that, “with the combined Antero deals”, U.S. upstream mergers and acquisitions stand at “nearly $19 billion in 4Q25 for the highest quarterly total since the first half of 2024”. “Gas transactions have played a material role in that, contributing about $6.6 billion in deal value. There is likely more to come, but gas M&A will start to run into the same problem that has slowed oil weighted deals, which is a dwindling of large-scale attractive targets,” he warned. “That makes both Anteros and Infinity’s decision to jump on strategic assets a sensible move to close out the year,” Dittmar continued. In a statement posted on its website on December 8, Antero Resources Corporation announced it had entered into a definitive agreement to acquire the upstream assets of HG Energy II LLC for total consideration of $2.8 billion in cash plus the assumption of HG Energy’s commodity hedge book, subject to customary closing adjustments. Antero also announced in that statement that it had entered into a definitive agreement to sell its Ohio Utica shale upstream assets for total consideration of $800 million in cash, subject to customary closing adjustments. It went on to state that Antero Midstream announced that it had entered into a definitive agreement to acquire the midstream assets from HG Energy for total consideration of $1.1 billion in cash, subject to customary closing adjustments. Antero added in that statement that Antero Midstream also announced it had entered into a definitive agreement to sell its Utica shale midstream assets for total consideration of $400 million, subject to customary closing adjustments. A segment of the statement listing “transaction highlights” pointed out the identification of “approximately $950 million of synergies over 10 years (PV-10)”. The statement noted “capital synergies of approximately $550 million” and “income related synergies of approximately $400 million”. “Today’s [December 8] acquisition expands our core acreage and enhances our position as the premier liquids developer in the Marcellus,” Michael Kennedy, President and CEO of Antero Resources, said in the statement. “Importantly, we have clear line of sight to financing the acquired assets with Antero’s near-term free cash flow generation, proceeds from the non-core Utica divestiture, and the 3-year hedged free cash flow generated by the acquired assets,” he added. “The acquired assets will also bolster our industry leading maintenance capital efficiency while providing us with further dry gas optionality for local demand from data centers and natural gas fired power plants,” he continued. Brendan Krueger, CFO of Antero Resources, said in the statement, “the strategic transactions announced today are highly accretive on a per share basis across key metrics including operating cash flow, free cash flow, and net asset value”. “We were able to divest a non-core asset at an attractive valuation and pair the expected use of proceeds with the acquisition of assets directly in the core of where we operate today,” he said. “Importantly, as a result of managing Antero’s business with a strong balance sheet, executing the divestiture of the Utica assets and generating significant free cash flow, we expect to reduce leverage to 1.0x or lower in 2026 based on current strip pricing,” he continued. A statement posted on Infinity Natural Resources Inc’s website on December 8 announced that the company’s subsidiary Infinity Natural Resources LLC entered into agreements to acquire upstream and midstream assets in Ohio from Antero Resources Corporation and Antero Midstream Corporation for a combined $1.2 billion. That statement also announced that Northern Oil and Gas Inc will acquire an undivided 49 percent interest in the assets for $588 million, “resulting in a $612 million purchase price net to Infinity for its undivided 51 percent interest”. “This transformational and strategic acquisition represents the largest transaction in Infinity’s history, continuing our track record of aggregation within the Appalachian basin,” Zack Arnold, President and CEO of Infinity, said in that statement. “We are acquiring high-quality, cash-generating assets in the heart of the Utica Shale that immediately compete for capital and significantly enhance our operational scale,” he added. “The Antero Ohio assets complement our existing footprint, providing substantial inventory depth with over 110 low break-even locations across multiple development windows. The addition of strategic midstream infrastructure provides an additional growth engine for the company,” he continued. “We are pleased that Northern recognized the value of these assets, and we are excited to partner with them on this highly accretive transaction that creates compelling value for both Infinity and Northern in the near and long term,” he went on to state. In a statement posted on its site on December 8, NOG Inc announced that it had entered into a definitive agreement to acquire a 49 percent stake in Ohio Utica shale assets in partnership with Infinity for a purchase price, net to NOG, of $588.0 million in cash, subject to customary closing adjustments. “NOG is singularly focused on executing transactions that add value to our platform for the long-term,” Nick O’Grady, NOG’s Chief Executive Officer, said in this statement. “We are extremely pleased to be partnering with Infinity on one of the last growth assets in the core of the Utica. The vertical integration of this asset adds an incremental dimension of value creation for shareholders and enhances resiliency with lower breakevens to generate free cash flow through cycle,” he added. In the statement, O’Grady said the Utica has emerged as one of the target rich natural gas plays in the United States. “Infinity has already been a strong operating partner for NOG, and we share their focus on creating value. Our alignment in that vein sets the ground for a successful partnership, and we look forward to working together to achieve our mutual desire to generate returns for our respective investors,” he said. “This transaction is now the largest we have done to date and is an excellent addition to our Appalachian portfolio, offering the benefit of an integrated midstream and a long-term, visible growth path well past the end of the decade,” he added. Adam Dirlam, NOG’s President, said in the statement, “this Utica transaction exemplifies the intersection where NOG shines - identifying and acquiring best in class assets with the potential for significant long-term upside while also providing valuable capital to like-minded operators seeking to expand their footprint”. “These assets epitomize our returns-focused strategy: delivering immediately while offering significant growth potential further enhancing NOG’s optionality. Importantly, like our precedent joint development transactions, we have devised an aligned, conservative development and governance plan with a proven E&P company,” he added. “We continue to be the partner of choice for our operators as the largest, best capitalized, and most dependable non-op working interest owner in the United States,” he went on to state.

DEP Issued Violations To Chesapeake Appalachia For Casing/Cementing Failures In 4 Shale Gas Wells At The Linski Well Pad In Bradford County- On November 13, 2025, the Department of Environmental Protection issued Chesapeake Appalachia LLC new violations for casing/cementing failures in four shale gas wells at the Linski well pad in Tuscarora Township, Bradford County.There are 11 shale gas wells on the pad.Testing on the 4H [DEP inspection report], 24H [DEP inspection report], 25H [DEP inspection report] and 101H [DEP inspection report] shale gas wells found natural gas was detected outside the surface casing or in one case the intermediate casing.The 4H well was spud (drilling began) in December 2011. The 24H and 25H wells were spud on the same day-- July 19, 2021-- and the 101H well was spud on March 28, 2025.Violations were issued for failing to notify DEP of the casing/cement failures and for failing to prevent the flow of gas in the well annulus.DEP requested a response to the violations from Chesapeake Appalachia by January 2.In these cases, the well owner prepares a schedule for doing a detailed analysis on the wells to identify the cause of the failure and then suggest remedies, if they are available.Long-term monitoring and retesting of the wells is usually part of the proposed plan.To report oil and gas violations or any environmental emergency or complaint, visit DEP’s Environmental Complaint webpage. Text photos and the location of abandoned wells to 717-788-8990. (Photos: The 4H, 24H, 25H and 101H shale gas wells and the Linski well pad.)

DEP Issued Violations To Repsol Oil & Gas For Casing/Cementing Failures In 4 Shale Gas Wells After A 34-Hour Uncontrolled Wastewater Release At The Broadleaf Well Pad In Bradford County - The Department of Environmental Protection has now issued violations to Repsol Oil & Gas USA LLC for casing/cementing failures in four shale gas wells at the Broadleaf Holdings well pad in Troy Township, Bradford County after one of the wells experienced an uncontrolled release of wastewater in July. There are a total of eight shale gas wells on the Broadleaf well pad. The four wells with casing/cement failures-- 3H, 5H, 7H and 8H-- all had the same spud date-- February 20, 2025-- the date drilling started.The other four wells were all drilled in December 2018.A well control incident on July 13 in the Broadleaf 7H shale gas well resulted in a 34-hour uncontrolled lease of wastewater that spilled onto the well pad and contaminated areas nearby. Read more here. Significant cleanup efforts at the well pad continued through August. Read more here.DEP issued violations related to casing/cement failure in the 7H well on July 13, 2025 and additional for the wastewater contamination [DEP Aug. 28 inspection report].Monitoring of the 7H well will continue on a long-term basis related to the casing/cement failure, as will an analysis of the well to determine more about its failure and possible corrective measures. DEP inspection report. In follow-up inspections of the other shale gas wells on the Broadleaf well pad, DEP issued violations to Repsol for defective casing/cementing for three other wells on July 24, 2025-- the 3H well [DEP inspection report], the 5H well [DEP inspection report] and the 8H well [DEP inspection report].Monitoring of the 3H, 5H and 8H wells will also continue on a long-term basis related to the casing/cement failure, as will an analysis of the well to determine more about its failure and possible corrective measures. To report oil and gas violations or any environmental emergency or complaint, visit DEP’s Environmental Complaint webpage.Text photos and the location of abandoned wells to 717-788-8990.

DEP: MarkWest Liberty Midstream Pipeline Construction Results In 36,000 And 29,000 Gallon Spills Into Coal Mine Voids Under Washington County; Total Of 329,900 Gallons Lost So Far On This Project - On November 25, 2025 and December 1, 2025, the Department of Environmental Protection was notified by MarkWest Liberty Midstream & Resources LLC that horizontal drilling operations on the construction of the shale gas-related Chiarelli to Imperial pipeline resulted in two more incidents of losing drilling fluids into coal mine voids under Mount Pleasant Township, Washington County. On November 25, 36,000 gallons were lost and on December 1 another 29,000 gallons. The losses occurred when drilling was at about 110 feet deep. No mine subsidence was reported on the pipeline route that is inspected frequently by the company. DEP’s Bureau of Abandoned Mines was again notified of the incidents. MarkWest reported to DEP in a November 26 email that up until that point they had lost a total of 300,900 gallons of drilling fluid into mine voids from this drilling project. With the December 1 incident that brings the total up to at least 329,900 gallons. A DEP inspector at the site on November 26 did not observe any drilling fluid on the surface at the construction site.These were at least the fifth and sixth incidents of this type on this pipeline construction project and they occurred during the drilling of the same general section of the pipeline as the last incident on November 21. Read more here. No violations were issued by DEP for these latest incidents, so far. To report oil and gas violations or any environmental emergency or complaint, visit DEP’s Environmental Complaint webpage. Text photos and the location of abandoned wells to 717-788-8990. Check These Resources:

• Visit DEP’s Compliance Reporting Database and Inspection Reports Viewer webpages to search their compliance records by date and owner.
• Sign up for DEP’s eNOTICE service which sends you information on oil and gas and other permits submitted to DEP for review in your community.
• Use DEP’s Oil and Gas Mapping Tool to find if there are oil and gas wells near or on your proprty and to find wells using latitude and longitude on well inspection reports.

PA Bill Would Expand 1971 Tax Credit to NatGas-Fired Power Plants - Marcellus Drilling News -- Pennsylvania has a big problem. The state is retiring older coal- and gas-fired power plants faster than it can add new plants. Plus, the state needs to *grow* its electric generation capacity to meet new demand from AI data centers. PA State Senator Gene Yaw has a solution: modify the existing 1971 Economic Development for a Growing Economy (EDGE) tax credit program by adding a provision granting a tax credit for any $400+ million investment in “baseload power generation” (i.e., gas-fired power generation). Yaw wants to make it a no-brainer for power plant builders to make the Keystone State their destination for new projects.

SRBC Stops Water Withdrawals for Fracking Use at 58 Locations - The highly functional and responsible Susquehanna River Basin Commission (SRBC), unlike its highly dysfunctional and irresponsible counterpart, the Delaware River Basin Commission (DRBC), continues to support the shale energy industry by approving water withdrawals and consumptive use for responsible and safe shale drilling. The SRBC also tells shale drillers when to stop withdrawing if low water flow (i.e., drought) conditions exist. Or when a body of water is frozen or blocked by ice. That’s what the SRBC did yesterday. The agency, via its Hydrologic Conditions Monitor, warned shale drillers that, at 58 listed locations (all in Pennsylvania), they must stop water withdrawals until streamflow reaches a specific “trigger flow” target (different for each location) or until the ice thaws.

60 New Shale Well Permits Issued for PA-OH-WV Dec 1 – 7 -- Marcellus Drilling News - After a pathetic showing two weeks ago (just 8 permits), last week was a barnstormer—the most permits we’ve seen issued in a single week since we’ve been chronicling permits here on MDN. But, there’s a catch. Last week’s report for the combined three states shows 60 (!) permits issued, with 22 going to Pennsylvania, 24 to Ohio, and 14 to West Virginia. However, Ohio’s numbers are inflated because the Ohio Department of Natural Resources (ODNR) reported numbers last week that stretch back three weeks in time. You may recall Ohio didn’t issue permits for two weeks in a row. They actually issued permits but didn’t report them. So, this report includes 6 permits for the two missing weeks. Still, removing six from the total means 54 permits were issued last week, which remains a record high. Could the spike in the spot price for natural gas in the M-U be the reason? ANTERO RESOURCES | ASCENT RESOURCES | BELMONT COUNTY | BRADFORD COUNTY | COTERRA ENERGY (CABOT O&G) | DODDRIDGE COUNTY | ENCINO ENERGY | EOG RESOURCES | EQT CORP | EXPAND ENERGY | FAYETTE COUNTY | GREENE COUNTY (PA) | GUERNSEY COUNTY | GULFPORT ENERGY | HARRISON COUNTY | LYCOMING COUNTY | MARION COUNTY | MONONGALIA COUNTY | MONROE COUNTY | NORTHEAST NATURAL ENERGY | PENNSYLVANIA GENERAL ENERGY | SUSQUEHANNA COUNTY | TUSCARAWAS COUNTY | WETZEL COUNTY

U.S. Rig Count Falls Despite Sizable Gain In Haynesville - U.S. oil and gas rig count fell to 548 for the week ending December 12 according to Baker Hughes, despite some significant gains in gas-directed basins. Rigs were added in the Haynesville (+4), Anadarko (+1), Eagle Ford (+1) and Appalachia (+1), while the Permian (-2), Niobrara (-1), Gulf of Mexico (-2) and All Other (-3) all declined week on week. Total U.S. rig count is up 11 in the last 90 days, but remains down 41 from this week a year ago.

EPA's Delay Of Oil & Gas Industry Methane Emissions Reductions Harms Pennsylvanians; Reactions From PA, Related Groups -Pennsylvania and related groups said the US Environmental Protection Agency’s compliance delay of the 2024 U.S. EPA Methane Rule, which requires industry polluters to cut dangerous methane emissions and harmful volatile organic compounds (VOCs), puts Pennsylvania’s public health, climate, and natural resources at risk. According to EPA’s own estimates, nationwide, delaying the implementation of standards for existing sources will result in 3.8 million tons of methane, 960,000 tons of VOCs, and 36,000 tons of toxic air pollutants that otherwise would have been prevented. Pennsylvanians are already paying the price, including the over 1.2 million Pennsylvanians who live within a half mile of active oil and gas wells:

• -- Methane is a potent greenhouse gas that is more than 80 times more powerful than carbon dioxide in the near term and is responsible for one-third of the climate warming we are experiencing today.
• -- $178 million worth of methane was wasted in 2023 — enough gas to meet the heating and cooking needs of 820,000 households.
• -- Increased air pollution in counties like Allegheny, Bucks, and Philadelphia, which already receive failing ozone grades.

Delaying implementation of methane standards exacerbates energy waste, blocks the benefits of cost-effective methane mitigation technologies already being deployed in Pennsylvania’s fast-growing methane mitigation industry - a sector that grew 42 percent in PA between 2021 and 2024. Timely implementation is essential not only to protect public health but also to reduce energy waste and ensure economic growth in a sector where Pennsylvania is already poised to lead. In response to this announcement, Kim Anderson, Evangelical Environmental Network’s Director of Member Mobilization, shared-- “Delaying these much-needed protections against methane pollution endangers our health and is fiscally irresponsible. As evangelicals, we believe that all human life is worth defending, including the nearly 1.5 million Pennsylvanians who live, work, and go to school near oil and gas facilities, exposing them to higher rates of dangerous pollutants.“In one year, oil and gas operations wasted $178 million worth of natural gas–enough to serve the heating and cooling needs of every household in Philadelphia and Pittsburgh for a whole year. In a time when energy costs are on the rise, this is a waste of valuable resources. This leaking gas also poses a risk to human health, but it is preventable. “That’s why nearly 50,000 pro-life evangelicals in our commonwealth supported a strong and swift State Implementation Rule over the last two years. “Our federal government should listen to these residents and ensure there is no delay to the rule. Similarly, our state should move forward with a strong plan to defend our health. “Any delay will harm the hearts, minds, and lungs of Pennsylvanians, especially our children, both born and unborn.”

Ethane Petchem Cracker Margin Lowest in Over Two Years -Petchem margins for ethane feedstocks in Gulf Coast steam crackers have plunged to about 6.5 cents per pound (c/lb) — the lowest level this year and the weakest since September 2023. That’s a 66% drop from late July, when margins were nearing 20 c/lb. Ethane prices have been pushed higher by surging natural gas values, which are up more than 80% over the past three months, making ethane rejection more attractive when gas prices significantly exceed liquid-ethane values — as they do today. At the same time, prices for key petrochemical steam cracker products such as ethylene and propylene remain soft amid a sluggish global petchem market. The combination of strong gas prices and weak product prices is crushing cracker economics. Ethane makes up about 85% of the total U.S. cracker feedslate. Note in the left graph below that the ethane margin has averaged 15 c/lb with a high of 31.5 c/lb in 2021 and a low of 6.8 c/lb in 2018.

U.S. Rig Count Falls Despite Sizable Gain In Haynesville - U.S. oil and gas rig count fell to 548 for the week ending December 12 according to Baker Hughes, despite some significant gains in gas-directed basins. Rigs were added in the Haynesville (+4), Anadarko (+1), Eagle Ford (+1) and Appalachia (+1), while the Permian (-2), Niobrara (-1), Gulf of Mexico (-2) and All Other (-3) all declined week on week. Total U.S. rig count is up 11 in the last 90 days, but remains down 41 from this week a year ago.

2025 Record-Breaking Year for U.S. Natural Gas Production & Sales -- Marcellus Drilling News - U.S. natural gas production and demand reached record highs in 2025, with the U.S. Energy Information Administration (EIA) projecting continued growth in output and LNG exports through 2026. Driven by surging international demand in Europe and Asia, the U.S. has become the world’s largest LNG exporter. This natural gas resurgence is bolstered by the Trump administration’s support and significant investments from major energy firms prioritizing gas as a so-called transition fuel (it’s actually a destination fuel). Consequently, U.S. natural gas pipeline capacity is set for its biggest one-year expansion since 2008. Surging demand from LNG exporters, data centers, and manufacturing is driving a $50 billion investment boom.

U.S. LNG Feedgas Demand at Record Levels - U.S. LNG feedgas demand inched up last week, hitting new records with nearly every terminal operating at full or peak winter levels. The feedgas demand averaged 19.2 Bcf/d last week up 0.11 Bcf/d from the previous week. U.S. feedgas demand is more than 5 Bcf/d higher than this time last year. Much of this year's growth comes from commissioning terminals. See the blue-dotted line in the graph below, which shows the rise of feedgas demand, including those commissioning terminals. The commissioning Plaquemines terminal ticked up again last week, averaging 4.2 Bcf/d. Corpus Christi’s Stage III commissioning volumes are also boosting the terminal's overall intake.

U.S. LNG Feed Gas Deliveries Hold Near Record Highs Despite Operational Hiccups -- The ramp up of commissioning projects and winter export demand are sustaining U.S. LNG feed gas deliveries near all-time highs despite operational upsets at the Freeport and Corpus Christi terminals. NGI graphic showing North America LNG Export Flow Tracker as of Dec. 8, 2025, including daily U.S. LNG feed gas deliveries from Nov. 29–Dec. 8 (ranging ~18.4–19.5 million Dth), individual facility delivery volumes and capacity utilization for Corpus Christi, Freeport, Golden Pass, Calcasieu Pass, Cameron, Plaquemines, Sabine Pass, Elba Island, and Cove Point, plus a map marking LNG export terminals across the U.S., Canada, and Mexico, with total U.S. deliveries at 19.16 million Dth, down 72,052 Dth from the prior day. At A Glance:
Feed gas demand hovers around 19 Bcf/d
Two outages reported at CCL since Nov. 25
Nominations to Freeport LNG still reduced

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

“Cool Down Cargo” Arrives at Golden Pass LNG, Startup Coming - Marcellus Drilling News - The arrival of a “cool down” liquefied natural gas (LNG) cargo from Qatar at the Golden Pass LNG terminal marks a pivotal step toward the facility’s first production. This delivery supports the $10 billion project’s commissioning phase by providing necessary LNG to pre-cool storage tanks and equipment. Signaling significant progress for the Sabine Pass facility, Golden Pass LNG projects that exports from Train 1 will officially commence early next year.

Golden Pass Expects First LNG Exports Early Next Year After Cooldown Cargo Unloads -- Golden Pass LNG’s developers marked “a major step” toward producing the super-chilled fuel for the first time on Tuesday after a cooldown cargo arrived and unloaded to prep the facility’s equipment ahead of startup. At A Glance:

• First train expected to startup soon
• U.S. feed gas deliveries already climbing
• LNG offtakers squeezed as Henry Hub rises

Energy Transfer Expects FID for Lake Charles LNG Early Next Year - Marcellus Drilling News - A month ago, MDN reported that Energy Transfer was holding off on a final investment decision (FID) for its Lake Charles LNG export project until 80% of the project had been sold to equity partners (see Energy Transfer Taps the Brakes on Lake Charles LNG Export FID). Good news! ET has now secured enough agreements to move forward with the FID and plans to do so “early next year.”

Lake Charles LNG Moves Toward ‘26 Green Light; Early Site Prep Targeted --Energy Transfer LP (ET) is looking to make a final investment decision (FID) and start early site preparations for its Lake Charles LNG export project early next year, according to management and regulatory filings. At A Glance:

• Early construction work planned for 2026
• Project adds 16.45 Mt/y to export capacity outlook
• Commercial operations targeted for 2029

NFE Secures Natural Gas Deal With Puerto Rico Amid Rising Energy Prices - New Fortress Energy Inc. (NFE) has secured a seven-year natural gas supply agreement with Puerto Rico as the U.S. territory works to improve energy security and tamper rising costs. Map of the Sur de Texas–Tuxpan Pipeline in northeastern Mexico, showing operational and proposed natural gas pipelines, LNG export facilities, LNG import terminals under construction, gas processing plants, underground storage sites, and NGI Mexico gas price index locations across regions including Matamoros, Reynosa, San Fernando, Tampico, Altamira, Tuxpan, and Veracruz. At A Glance:
Puerto Rico seeks stable energy supply
Altamira flows support LNG shipments
Henry Hub strengthening

US natural gas futures drop 7% on less cold forecasts, near-record output (Reuters) - U.S. natural gas futures fell about 7% on Monday on forecasts for less cold weather over the next two weeks than previously expected, near-record output, ample amounts of gas in storage and lower prices around the world. Front-month gas futures for January delivery on the New York Mercantile Exchange fell 37.7 cents, or 7.1%, to settle at $4.912 per million British thermal units (mmBtu). On Friday, the contract closed at its highest since December 21, 2022. That price drop pushed the front-month out of technically overbought territory for the first time in four days and was the contract's biggest daily percentage decline since June 30 when prices fell around 7.6%. In the cash market, extreme cold over the past week caused next-day gas prices to soar to their highest since February 2023 in New England, their highest since January 2025 in California, , and their highest since February 2025 at the U.S. Henry Hub benchmark in Louisiana and in Pennsylvania, Chicago , New York and Alberta in Canada. Next-day electricity prices in New England, where more than half the power comes from gas-fired plants, rose to their highest since January 2025. Financial firm LSEG said average gas output in the Lower 48 states rose to 109.7 billion cubic feet per day (bcfd) so far in December, up from a monthly record high of 109.6 bcfd in November. Record output has allowed energy companies to stockpile more gas than usual, leaving the amount of fuel in storage at about 5% above normal for this time of year. Meteorologists forecast weather across the country would remain mostly near normal through Dec. 23. LSEG projected average gas demand in the Lower 48 states, including exports, would rise from 143.8 bcfd this week to 146.0 bcfd next week. Those forecasts were higher than LSEG's outlook on Friday. Average gas flows to the eight large liquefied natural gas (LNG) export plants in the U.S. rose to 18.9 bcfd so far this month, up from a monthly record high of 18.2 bcfd in November. Around the world, gas prices were trading around 19-month lows near $9 per mmBtu at the Dutch Title Transfer Facility benchmark in Europe and $11 at the Japan-Korea Marker in Asia. Global prices have declined in recent weeks with a slow start to winter heating demand and hopes that peace talks over Ukraine could result in the lifting of sanctions against Moscow. That could allow Russia, the world's second-biggest gas producer behind the U.S., to export more fuel in the future.

US Natural Gas Futures Drop 7% for Second Day as Mild Weather Trims Demand - (Reuters) – U.S. natural gas futures dropped about 7% for the second straight day to a one-week low on Tuesday, on more moderate two-week forecasts for weather and demand, near-record output, ample amounts of gas in storage and lower prices around the world. Front-month gas futures for January delivery on the New York Mercantile Exchange fell 33.8 cents, or 6.9%, to settle at $4.574 per million British thermal units (mmBtu), their lowest since November 26. Financial firm LSEG said average gas output in the Lower 48 states held at 109.6 billion cubic feet per day (bcfd) so far in December, the same as November’s monthly record high of 109.6 bcfd. On a daily basis, however, output was on track to fall to around 108.4 bcfd on Tuesday, putting it down about 2.8 bcfd since hitting a daily record high of 111.3 bcfd on November 28. Meteorologists forecast weather across the country would remain mostly warmer than normal through Dec. 24, reducing the amount of gas needed to heat homes and businesses. LSEG projected average gas demand in the Lower 48 states, including exports, would slide from 143.7 bcfd this week to 142.6 bcfd next week. The forecast for next week was lower than LSEG’s outlook on Monday. Average gas flows to the eight large U.S. LNG export plants rose to 18.8 bcfd so far this month, up from a monthly record high of 18.2 bcfd in November. Freeport LNG’s 2.4-bcfd export plant in Texas was on track to take in more gas on Tuesday in a sign that one of its three liquefaction trains returned to service after shutting down on Monday. The Imsaikah LNG vessel, meanwhile, docked at Exxon Mobil /QatarEnergy’s 2.4-bcfd Golden Pass LNG export plant under construction in Texas, according to LSEG data. The ship is carrying LNG from Qatar that traders and analysts say will be used to cool equipment as part of the plant’s commissioning. The facility is expected to start producing LNG later this year or early next year.

US natural gas futures drop 8% on mild weather forecasts, data center demand worries — U.S. natural gas futures dropped about 8% on Thursday to a five-week low on forecasts for milder weather and lower demand next week than previously expected, near-record output, ample amounts of gas in storage, and worries about future gas demand for power generation from data centers. Front-month gas futures for January delivery on the New York Mercantile Exchange fell 36.4 cents, or 7.9%, to settle at $4.231 per million British thermal units (mmBtu), their lowest close since October 31. It was the biggest daily percentage drop since March 2025 and left prices down about 20% since hitting a 35-month high on December 5. The decline came despite a federal report showing a bigger-than-expected storage withdrawal last week when extreme cold boosted the amount of gas consumers burned to heat homes and businesses. The U.S. Energy Information Administration (EIA) said energy firms pulled 177 billion cubic feet (bcf) of gas out of storage during the week ended December 5. That figure exceeded the 166-bcf withdrawal analysts forecast in a Reuters poll and compared with a decline of 167 bcf during the same week last year and an average withdrawal of 89 bcf over the past five years (2020-2024). While LNG exports were expected to hit a record high for a 10th year in a row in 2025, the amount of gas used to generate power was on track to decline in 2025 after hitting a record high in 2024. Financial firm LSEG said average gas output in the Lower 48 states has risen to 109.7 billion cubic feet per day (bcfd) so far in December, up from a monthly record high of 109.6 bcfd in November. Meteorologists forecast weather across the country would remain mostly warmer than normal through December 26, keeping the amount of gas needed to heat homes and businesses lower than usual during that time. LSEG projected average gas demand in the Lower 48 states, including exports, would slide from 145.4 bcfd this week to 143.8 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 18.7 bcfd so far this month, up from a monthly record high of 18.2 bcfd in November.

Analyst Looks at Natural Gas Price Moves - In a natural gas focused EBW Analytics Group report sent to Rigzone by the EBW team on Friday, Eli Rubin, an energy analyst at the company, warned that late December heating demand “continues to disintegrate”. “Yesterday’s 177 billion cubic foot withdrawal did little to stop the massive sell-off in natural gas, with the NYMEX front-month plummeting to close at a seven-week low of $4.231 [per million British thermal units (MMBtu)],” Rubin said in the report. “Although a frigid early December may erode storage surpluses over the next two EIA [U.S. Energy Information Administration] reports, the market is focused on eroding late-December heating demand,” he added. In the report, Rubin noted that the week leading into Christmas “shed another seven gHDDs over the past 24 hours, with exceptionally mild weather anticipated across the country in the back half of the month”. “Daily demand may still surge into Sunday’s peak - but is expected to plunge 26 billion cubic feet per day [Bcfpd] into mid-next week, likely delivering a blow to physical gas prices,” he added. Rubin went on to warn in the report that technicals also appear weak, “with prices falling below the 20-day, 50-day, 100-day and 200-day moving averages”. “Shorts may take profits off the table ahead of the weekend, and medium to long term fundamentals appear more supportive than recent price action suggests, but momentum is bearish and this week’s 133 billion cubic foot loss of weather-driven demand will leave an enduring mark on NYMEX futures,” he said. This EBW report highlighted that the January natural gas contract closed at $4.231 per MMBtu on Thursday. It outlined that this was down 36.4 cents, or 7.9 percent, from Wednesday’s close. In an EBW report sent to Rigzone by the EBW team on December 10, Rubin highlighted that a “weather collapse plunge[d]… natural gas into freefall”. “The January natural gas contract plummeted to $4.455 early this morning - a $1.041 implosion from Friday’s intraday high - as late December continues to hemorrhage demand,” Rubin said in that report. “Since Friday, Week 3 has shed 42 gHDDs, with initial forecasts for a cold end to 2025 flipping to a blowtorch solution for most of the Lower 48,” he added. “Week over week demand may shed 9.5 Bcfpd into Week 3, with a counter-seasonal warmup negating last week’s supply concerns,” he continued. “Still, Henry Hub spot prices cleared at $4.76 per MMBtu with daily heating demand to jump 15.6 Bcfpd into the weekend. Weekly average LNG is at a record high, production readings are declining, and the storage surplus vs. five-year average may disappear into early 2026,” he noted. In this report, Rubin went on to state that, “although it is difficult to ascertain when weather models will stop shedding demand and selling pressure will cease, the medium-term fundamental outlook is sounder than early-week price action suggests”. Rubin also warned that “weather forecast evolution will continue to play a dominant role in the price trajectory for NYMEX gas futures”. This EBW report highlighted that the January natural gas contract closed at $4.574 per MMBtu on Tuesday. The report outlined that this was down 33.8 cents, 6.9 percent, from Monday’s close. In another EBW report sent to Rigzone on December 11, Rubin noted that the “Week 3 weather-driven demand collapse” was continuing. “The NYMEX front-month staged a half-hearted 2.1 cent bounce yesterday - with the lack of a more sizable relief rally relative to the 71.5 cent early-week collapse a cautionary signal,” Rubin said in that report. “The ongoing Week 3 weather collapse remains a bearish weight on the near-term outlook,” he added. In this report, Rubin said “consensus expectations” for that day’s EIA storage report “span 165-174 billion cubic feet”. “The first sizable storage pull of the year often includes linepack to bias withdrawals higher-and pipeline flow-derived draws also hint at risks of a possible bullish surprise,” he added. Rubin highlighted in this report that “LNG feedgas figures have ticked lower” but added that the “overwhelming catalyst remains the 116-billion cubic foot collapse in demand since Friday”. “Heating demand may surge 16 Bcfpd into the coming weekend, only to collapse 25 Bcfpd into the middle of next week,” he warned. “Although medium-term fundamentals appear supportive, if late-December weather does not stabilize, further near-term downside cannot be ruled out,” he went on to note. In this report, EBW highlighted that the January natural gas contract closed at $4.595 per MMBtu on Wednesday. The report outlined that this figure was up 2.1 cents, or 0.5 percent, from Tuesday’s close. In its latest weekly natural gas storage report, which was released on December 11 and included data for the week ending December 5, the EIA stated that working gas in storage was 3,746 Bcf as of Friday, according to its estimates. “This represents a net decrease of 177 billion cubic feet from the previous week,” the EIA said in this report. “Stocks were 28 billion cubic feet less than last year at this time and 103 billion cubic feet above the five-year average of 3,643 billion cubic feet. At 3,746 billion cubic feet, total working gas is within the five-year historical range,” they added.

EIA Sees Henry Hub Natural Gas Prices Strengthening Substantially Amid Winter’s Bullish Grip -- Natural gas spot prices at benchmark Henry Hub could rise to an average well above $4.00/MMBtu during the current winter as robust heating demand and escalating calls for U.S. LNG soak up supply, according to an updated federal estimate. Line chart titled “US Natural Gas Prices” comparing Henry Hub bidweek prices, annual averages, and forward-look projections with U.S. residential natural gas prices, annual averages, and forecast values from 2021 to 2026. The chart shows Henry Hub prices rising through 2022, declining in 2023–24, and gradually increasing into 2026, while residential prices display pronounced seasonal spikes peaking near $25/MMBtu before moderating in the 2026 forecast. NGI branding appears in the upper right corner. At A Glance:
EIA sees winter Henry Hub near $4.30
Agency expects $4.01 average for 2026
Futures exceed $5.00 amid cold blasts

Oil and gas lease sale starts new era in Gulf energy production – Auction of oil and gas drilling rights in the Gulf of America for the first time since 2023 was held Wednesday in New Orleans, marking a key milestone in the Trump administration’s effort to unleash energy production in federal waters. Statistical reports on the Bureau of Ocean Energy Management website show 26 companies submitted 219 bids spread across 1.02 million acres, representing about 1.3% of the total area offered in Big Beautiful Gulf 1, the official name of the auction. Companies could bid on more than 80 million acres in total. The bureau’s acting director, Matt Giacona, said Wednesday in a livestream broadcast that the auction, the first of 30 mandated over the next 15 years by the One Big Beautiful Bill Act, reflects President Donald Trump’s commitment to accelerate the development of domestic oil and gas resources and critical minerals. “By expanding U.S. offshore capabilities, we're strengthening domestic industry, protecting consumers, creating jobs, and reinforcing this nation's position as the world's energy leader,” said Giacona. The last lease sale in the Gulf, in December 2023, attracted interest from 26 companies submitting 311 bids spread across 1.7 million acres. The 2023 lease sale was twice delayed by lawsuits, with the 5th U.S. Circuit Court of Appeals in New Orleans eventually mandating that the auction be held within 37 days. The One Big Beautiful Bill Act, signed by Trump on July 4, set the royalties oil and gas companies will pay to the U.S. government for production in federal waters at 12.5%. That's well below the 18.75% rate established for the 2023 lease sale by the Biden administration. The bureau said the high bids in the Wednesday lease sale totaled about $279 million, less than the $382.17 million in high bids recorded in the December 2023 auction, which was the highest amount for an offshore sale since 2015. The 26 firms submitting bids include international oil and gas companies like Chevron USA, Shell Offshore, and TotalEnergies E&P, and independents such as LLOG Exploration Offshore and Anadarko US Offshore. Most of the bidding focused on acreage in the Keathley Canyon off the Louisiana coast and in the Mississippi Canyon, both areas with long histories of deepwater oil and gas production. The Mississippi Canyon is home to several of the largest deepwater fields in the Gulf, with top production blocks including Mars, Ursa and Mensa. In the Keathley Canyon, major oil fields include Tiber, Kaskida, Lucius, Buckskin, Leon and Castile. The Salamanca Floating Production Unit, operated by Louisiana independent LLOG Exploration, began processing oil from the Leon and Castile fields in September 2025 and will connect to additional wells in late 2025 and 2026. Covington-based LLOG is an innovator in the use of subsea tie-backs, a cost-effective method for developing new oil fields in deepwater environments. In fiscal year 2024, offshore oil and gas development in federal waters generated $6.5 billion in royalties, $372.5 million in bonuses, and $122.8 million in rental payments, according to U.S. Interior Department.

U.S. Crude Exports Slide in November Amid Weak APAC and Africa Demand - Crude oil exports out of the U.S. Gulf Coast (USGC) averaged 3.6 MMb/d for the month of November, down 580 Mb/d from October and 200 Mb/d below the 2025 year-to-date (YTD) average. Month-on-month declines were recorded out of the Houston, Beaumont, and Louisiana regions, with Corpus Christi being the only region posting a small gain month-on-month. Exports have been highly volatile throughout 2025. After starting the year at an average of 4 MMb/d, volumes began to slip, ultimately falling to just 3.1 MMb/d amid heightened geopolitical tensions and tariff uncertainty before improving once again in Q3. However, November marked another sharp downturn, with a drop in volumes sent to overseas buyers in the Asia-Pacific (APAC) and Africa regions. In short, November’s slump reinforces the volatile nature of 2025 export activity as discussed in our Crude Voyager Report, highlighting the sensitivity of U.S. export volumes to shifts in global demand and regional buying patterns.

November Retrench — Gulf Coast Re-Exports of Canadian Heavy Crude Oil Take a Swoon Re-exports of Canadian heavy crude oil are estimated to have been an 11-month low of 81 Mb/d in November 2025 (rightmost column in chart below), a decrease of 65 Mb/d from October, and 3 Mb/d less than a year ago based on tanker tracking data compiled by Bloomberg. Since the departure last year of China (red columns) from the Gulf Coast in favor of Canada’s west coast as a buyer of Canadian crude, two nations have remained prominent in purchasing Canadian barrels from the Gulf Coast: India and Spain. India (gray columns) is estimated to have purchased 81 Mb/d, 18 Mb/d greater than October and 14 Mb/d more than a year ago. Spain (blue columns) was absent in November, the first zero reading since May, a decline of 83 Mb/d from October, and unchanged from a year ago (also zero). Data for the most recent three months are derived from Bloomberg tanker tracking estimates. Official monthly data from the U.S. Census Bureau has been updated to August which revealed an upward revision of 21 Mb/d to 181 Mb/d, with re-exports to India and Spain being increased by about 10 Mb/d each versus prior estimates based on Bloomberg data. India’s purchases of Canadian crude oil have proven to variable in the past two years with recent volatility likely arising from its attempts to maneuver around sanctions on portions of the global oil tanker fleet and those directed against Russian crude oil of which it has been a frequent buyer. It is unclear if re-export volumes will increase in the months ahead as India has signaled that it remains open to purchases of Russian crude oil despite international sanctions.

More Permian Barrels Headed to Corpus Christi, Nederland as Pipelines Thrive --Houston and Corpus Christi have been locked in a battle for the top spot as the primary outlet for Permian crude. Lately, the pendulum has been swinging toward Corpus — and not by accident — as most major new or expanded Permian pipelines in recent years have pointed straight there. In today’s RBN blog, we’ll discuss the significant shifts that have reshaped the market along the South Texas coast, sending crude to Corpus and Nederland, and preview our latest Drill Down Report.First, let’s offer up some background. There’s been fierce competition between Houston and Corpus Christi for Permian barrels for some time; Corpus took a tiny lead earlier this year and the two destinations — which together handle about 75% of Permian output — are in a dead heat. Through June, roughly 2.45 MMb/d of Permian crude had flowed to Corpus in 2025, just ahead of the 2.44 MMb/d headed to Houston, according to RBN’s Crude Oil Permian report, with about 860 Mb/d destined for Nederland. And the pipelines feeding Corpus — Cactus I, Cactus II, Gray Oak and EPIC Crude — have in total been cranking above 90% utilization almost every month since late 2022.RBN Energy’s South Texas Energy Infrastructure Map brings together all the pieces of the critical and complex puzzle of the greater Corpus Christi region. Spanning from Point Comfort, TX to Corpus Christ, TX and south of the Agua Dulce natural gas hub, the map details the processing, transportation and export facilities in RBN Energy’s classic clear, concise and easy to comprehend style.All of this is helping to lock in Corpus Christi as one of the Gulf Coast’s leading export hubs. It supports 857 Mb/d of refining capacity — Valero (370 Mb/d), Flint Hills (320 Mb/d) and CITGO (167 Mb/d) — but Corpus’s key strength is its export capabilities. According to our Crude Voyager report, 2.25 MMb/d has been exported from Corpus Christi so far this year, with the majority of that coming from the Permian Basin. Enbridge Ingleside Energy Center (EIEC) and South Texas Gateway (STG) are the region’s top two crude export terminals by volume, and each can partially load Very Large Crude Carriers (VLCCs). EIEC has exported 1.09 MMb/d as of the end of November and STG has exported about 661 Mb/d in the same time period. Four pipelines constructed over the last 10 years have been a major catalyst for getting rising Permian oil to Corpus Christi.

• Cactus I (light-green line in Figure 1 below) was an early mover. The original Cactus Pipeline, a 310-mile, 20-inch-diameter line from McCamey to Gardendale, began operations in 2015 to move Permian and Eagle Ford crude. Capacity grew from 250 Mb/d in 2015 to 390 Mb/d today via additional pumps and other upgrades. It is owned and operated by Plains All American.
• Cactus II (dark-green line) was built in 2019 as a 585-Mb/d, 26-inch, 575-mile pipe from Orla to Corpus Christi and later expanded to 670 Mb/d. The two pipelines account for about one-third of total Permian-to-Corpus activity in operation today. For the first six months of 2025, the pair of pipes were at 95% utilization, bringing them very close to the system’s total capacity. Plains owns 70% of Cactus II and Enbridge own the other 30%.
• Gray Oak (teal line in Figure 1) is an 850-mile, 30-inch pipeline operated by Enbridge that runs from West Texas toward Corpus Christi and Ingleside. It came online in 2019, and its capacity was expanded from 900 Mb/d to 980 Mb/d in April, with a Phase 2 expansion expected to add another 40 Mb/d in 2026. (More on that below.)
• EPIC Crude (yellow line in Figure 1), a 600-Mb/d, 30-inch pipeline, began full service in 2020 and also facilitates the transportation of crude oil from the Permian to Corpus Christi, serving the Delaware, Midland and Eagle Ford basins along the way. It has operated above its original nameplate capacity for more than a year. EPIC is now fully owned by Plains, which had previously bought a 55% stake from Diamondback Energy and Kinetik Holdings and purchased the other 45% from Ares Management in November.

Those four pipelines have been pulling crude from all corners of the Permian and funneling it to Corpus Christi, which has evolved into a solid, viable destination for Permian crude on the strength of its robust export capacity (particularly at EIEC and STG) and its refining capacity in the area. The combined volume of the four pipelines (sum of stacked areas in Figure 2 below) is just below their total overall capacity (dotted black line).

EIA raises oil price forecast for 2025, 2026 -- US Energy Information Administration (EIA) has revised up its average oil price projections for this year and 2026, taking into account recent developments in global oil markets. In its Short-Term Energy Outlook (STEO) released late Tuesday, the EIA raised its 2025 and 2026 average Brent crude price forecast to $68.91 per barrel, up from $68.76, while West Texas Intermediate (WTI) was revised to $65.32 per barrel from $65.15 For 2026, EIA projects Brent crude to average $55.08 per barrel and WTI to average $51.42 per barrel. In its previous outlook, the agency had estimated prices at $54.92 and $51.26 per barrel, respectively. The agency said that crude oil prices continue to fall as growing crude oil production outweighs the effect of increased drone attacks on Russia's oil infrastructure and the latest sanctions on Russia's oil sector. EIA forecasts that growing global oil production and lower demand over the winter months will accelerate the accumulation of oil inventories, resulting in further crude oil price declines in the coming period. Meanwhile, although the agency expects prices to fall in 2026, it assesses that OPEC+ policy and China's continued inventory builds will limit the declines. US crude oil output is forecast to average 13.61 million bpd in 2025, up from the 13.59 million barrels projected in the previous report. For 2026, production is expected to average 13.53 million bpd, compared to the earlier estimate of 13.58 million barrels. Meanwhile, global oil production is forecast to average 106.18 million bpd in 2025 and 107.43 million bpd in 2026. Consumption is estimated to reach 103.94 million bpd in 2025 and 105.17 million bpd in 2026.

Glory Days – With Most of Its Best Well Sites Already Drilled, Are the Bakken’s Best Days Behind It? | RBN Energy - A new, AI-based analysis suggests that while Bakken crude oil production is humming along at a steady 1.2 MMb/d, about 75% of the shale play’s top-quartile locations have already been drilled and only 6,100 well sites — about six years of inventory at the current drilling pace — could generate a good return at the prices we’ve seen the past couple of years. That raises a long list of questions. Are the Bakken’s best days behind it? Which producers are well-positioned from a best-rock perspective, and which are less so? And what would happen if crude oil prices were to settle in below $60/bbl? In today’s RBN blog, we’ll discuss highlights from Novi Labs’ fresh take on the U.S.’s second-largest onshore production area.From 2009 to 2015, crude oil production in western North Dakota and the eastern edge of Montana increased 6X, to 1.2 MMb/d — a growth rate so outrageous that more than two-thirds of the oil produced there in 2013-14 needed to be loaded into tank cars and railed out. (Takeaway pipeline capacity didn’t catch up ’til 2017.) A mid-decade price crash trimmed Bakken production to less than 1 MMb/d, but by 2019 E&Ps had pushed the basin’s output to a record 1.4 MMb/d. Then came Covid, another price crash and another rebound — this time only to the 1.2-MMb/d level where production stands today. As shown in Figure 1 below, the vast majority of Bakken crude production comes from four North Dakota counties: McKenzie (dark-blue layer), Williams (magenta layer), Dunn (red layer) and Mountrail (orange layer). Our recent blog on Enbridge and Energy Transfer exploring the possibility of using a portion of the midstreamers’ underutilized 750-Mb/d Dakota Access Pipeline (DAPL) out of the Bakken to move Western Canadian crude down to the Midwest and the Gulf Coast got us wondering, are the best days of the shale play behind it? Is Bakken production a straight, horizontal line to the right — or worse — from here on out?​ It turns out that our friends at Novi Labs have been asking the same thing and undertaking a detailed analysis of crude oil production and resources in the Bakken. As we discussed a couple of months ago in a Drill Down Report on the Uinta Basin, the company employs a data-based, machine-learning-enhanced approach to analyzing the many layers (aka benches) in shale plays to determine not only how much crude remains underground but how much is likely to be produced under various price scenarios. Rather than the traditional approach of using a type-curve analysis to forecast the performance of future wells, Novi uses machine learning to integrate a wide range of geologic, operational and spatial data collected from thousands of drilled wells to recognize patterns and identify the primary drivers of well performance. It does this through the development and use of “Shapley values,” a concept from game theory that quantifies the contribution of individual input categories — say, geology, pressure, well spacing and proppant intensity — to production from a given well compared to the average of the wells in the area. Machine learning then enables operators to assess how changing variables (like drilling in a higher pressure area, tightening well spacing or increasing proppant intensity) would affect production outcomes in wells yet to be drilled. It also gives operators guidance on how best to lay out, space and sequence the development of the benches. More importantly for our purposes, this approach also reveals the relative quality of the rock in various parts of a shale basin and how much of the remaining resource is likely to be developed at various crude oil price points. Regarding rock quality in the Bakken, the basin’s existing and potential wells are separated into four quartiles or tiers, with Tier 1 wells being the juiciest and most economic and Tier 4 wells having the lowest quality, which are economic only if oil prices are very high. As for the economics of new-well development, there are two common ways to assess whether it makes sense to drill and complete a well: using a straight two-year breakeven or a more conservative NPV25 breakeven, with NPV referring to net present value. Under the former, a Bakken well costing, say, $8 million would break even if it generated $8 million in undiscounted cash flows over the first 24 months of operation. Under an NPV25 breakeven, cash flows from crude oil production are discounted by a sizable 25% to compensate — many would say overcompensate — for the time value of money and producers’ opportunity cost. So, what did the analysis determine? From a big-picture perspective, it found that the crude oil productivity per lateral foot of Bakken wells has been declining at an accelerating pace since its peak a few years ago. As shown by the red line in Figure 2 above, that metric rose from about 11 bbl/ft in 2015 to more than 18 bbl/ft in 2020-21, but plummeted to 12 bbl/ft in 2024. In part, the fall-off reflects the fact that 75% of the basin’s Tier 1 locations have already been drilled and completed and an increasing share of the wells being developed are higher-tier locations with less-desirable, less-productive rock. Figure 3 below shows the more than 21,000 wells drilled so far by tier, with Tier 1/top-quartile wells (dark-green areas) accounting for nearly half of the total drilled locations (10,228), followed by Tier 2 (light-green areas; 5,861 locations), Tier 3 (orange areas; 3,831), and Tier 4 (red areas; 1,176). This heavy tilt toward the best locations isn’t surprising, really. Why wouldn’t producers focus on the well sites that offer the highest returns? But the focus on top-quartile locations may be taking its toll. As shown in Figure 4 below, the nearly 38,000 remaining “proved” undrilled well sites in the Bakken lean heavily toward the lower-quality end of the scale. The analysis shows that only 12% of the sites left have Tier 1 rock (dark-green areas; 4,474 locations), with another 23% having Tier 2 rock (light-green areas; 8,861). Locations in Tier 3 (orange areas; 10,904) and Tier 4 (red areas; 13,563) dominate the yet-to-be-drilled list. Novi said the relative shortage of Tier 1 sites is even worse than it appears, noting that a majority of the 4,400-odd locations in that category are subject to surface constraints, such as terrain, that may prevent them from being developed. Still, the situation isn’t as dire as it might appear. It’s estimated that, at $75/bbl oil and $3/MMBtu natural gas, about 8,800 of the remaining drilling locations, or about eight years of inventory at the current pace of drilling, would offer breakeven economics using the NPV25 approach. Also, as we said at the start of today’s blog, about 6,100 locations can generate a solid return — a two-year payback — at those same prices. As you’d expect, lower crude oil prices reduce the number of remaining wells offering NPV25 breakevens: Only about 5,900 would break even with an oil price of $70/bbl and a scant 2,200 would do the same with oil at $60/bbl. (That’s about where prices stand today, by the way.)

4,000 gallons of oil and toxic wastewater spilled near Monterey County creek – – 4,000 gallons of oil and toxic wastewater spilled from a pipeline in the San Ardo Oil Field on Friday, according to a Hazardous Materials Spill Report from the Governor’s Office Emergency Services. According to the report, around 6:30 a.m., 96 barrels of “produced fluid” consisting of a mixture of oil and processing water was released from an eight-inch line pipe near Sargent Creek. A crew is working on site to make repairs to the affected pipeline and cleanup is underway on the impacted soil surrounding the spill site. While according to the Hazardous Materials Spill Report the spill was contained to the immediate area and reports that no storm drains or waterways were affected, according to Hollin Kretzmann, an attorney at the Center for Biological Diversity’s Climate Law Institute, the incident’s location near Sargent Creek is less than a mile from where the creek merges with the Salinas River. Kretzmann noted that if the spilled materials entered the Salinas River, drinking and irrigation water for the Salinas Valley could be affected. “In the past few weeks, we’ve seen numerous examples of how oil production threatens California’s communities and water supplies,” said Kretzmann in a statement. “California needs to move away from dirty fossil fuel production as quickly as possible and force polluters to pay for the damage they’ve caused,” Kretzmann said. “As long as we allow these dangerous operations to continue, we can expect to see more spills like this.”

Washington delegation demands answers from BP after weeks-long Olympic Pipeline gas leak — In a letter addressed to BP North America CEO Murray Auchincloss, a cohort of Washington delegates is demanding answers from the energy behemoth after a leak in the Olympic Pipeline released thousands of gallons of fuel near Everett. The leak was discovered by a blueberry farmer on Nov. 11, who then alerted BP. Hundreds of feet of the two consecutive pipes, carrying gas and airliner fuel, were excavated as crews attempted to locate the leak. The leak briefly disrupted fuel delivery to SeattleTacoma International Airport (SEA), prompting a regional emergency response.On Nov. 19, Gov. Bob Ferguson declared a state of emergency to enable trucking alternatives for jet fuel delivery during the shutdown.BP eventually located the leak source in a 20-inch segment of the pipeline and restored service on unaffected sections. The last publicly known amount of fuel released into the environment was 2.300 gallons.Representatives Suzan DelBene, Rick Larsen, Kim Schrier, Marilyn Strickland, Emily Randall, Adam Smith, Pramila Jayapal, and Marie Gluesenkamp Perez are now insisting BP release detailed information about the leak, its causes, and BP’s response plan.In their letter, the lawmakers, representing Washington’s entire congressional delegation, raise more than a dozen specific questions, including: exactly how much fuel was released, whether contamination spread to local water sources or soil, what remediation plans are in place, and what steps BP will take to prevent future leaks.They also demand full public disclosure of spill data, a full spill history for Washington pipelines, and cooperation with state regulators.The full list of questions includes:

1. What volume of refined products did the November 11, 2025 leak release?
2. What efforts are BP North America and the Olympic Pipeline undertaking to determine the full extent of refined products that may have leaked into surrounding water sources or soil?
3. Provide an outline of BP’s plan to remediate any contamination, including the timeline for these activities and an assessment of local businesses or residences impacted.
4. Do you commit to timely public disclosure of all spill data, such as volume, location, environmental sampling results, and remediation efforts, for review by public and relevant state and local agencies? If so, what is your projected timeline for this information disclosure?
5. Provide a complete list of spills and volume spilled since November 25, 2005, from any pipelines owned by BP in Washington State.
6. What corrective measures will BP North America and the Olympic Pipeline take to reduce future spill risk?
7. Do you commit to fully cooperating with the Washington Utilities and Transportation Commission to determine the cause of the leak and make any necessary corrective actions?
8. Do you commit to fully cooperating with the Washington Department of Ecology for assessment of the extent of the spill as well as all clean-up operations?
9. The Washington Department of Ecology issued a $3.8 million fine for the 2023 Olympic Pipeline leak in Conway, WA. Following that leak, how did BP update its monitoring and maintenance practices?
10. Since the 2023 leak in Conway, has BP found any other leaks along the Olympic pipeline? Is there a connection between the 2023 leak in Conway, or any subsequent leaks, and this one?
11. Governor Ferguson’s emergency declaration following the shutdown of the Olympic Pipeline highlights the need to develop further emergency plans to service airline operation needs in the event of future fuel incidents. Do you commit to working with the state and relevant transit authorities to address emergency planning needs?

The delegates wrote:“This malfunction jeopardized airline operations, farmlands, water safety, wildlife habitat, and public health.” The letter expresses concern that this latest leak adds to a decades-long record of ruptures and spills involving the Olympic Pipeline ,including a 2023 gasoline spill near Conway that led to a $3.8 million fine by the Washington Department of Ecology.

Trump Reopens Alaska’s Arctic to Oil Drilling President Trump has removed legislative protections from the Biden presidency that restricted oil and gas exploration in Alaska, including the Arctic National Wildlife Refuge and federal lands in the state. Bloomberg reported today that the changes came in the form of several congressional measures under the Congressional Review Act and prompted a quick reaction from the environmentalist lobby. The president’s move was “a direct attack on public input, science, and responsible stewardship of public lands, wildlife, water, Indigenous communities, and rural economies,” said the National Wildlife Federation. The Brooks Range Coalition said that the move “leaves Alaska’s rural communities, hunters, and Tribal governments with fewer protections at a time when climate change and resource pressures are rapidly intensifying.” Trump’s measures follow an earlier decision by the administration to reopen more of the Arctic National Wildlife Refuges for oil and gas drilling. The Interior Department said in October it will restore the full 1.5-million-acre Coastal Plain to leasing, along with reinstating previously canceled leases held by the Alaska Industrial Development and Export Authority. The decision marked the most aggressive push yet to expand exploration in Alaska’s far north since the original Trump-era lease sale in 2021. Alaska is one of the biggest legacy oil-producing regions in the United States. Oil production there peaked at 2 million barrels per day in 1988 and now accounts for barely 3% of U.S. output. High costs, aging fields, and limited leasing have stalled investment for decades. With the U.S. chasing energy security and Asian buyers showing renewed interest in long-term crude and LNG supply, Washington appears ready to bet once again on Alaska’s North Slope. Earlier this year, the Trump administration moved to boost crude oil production from the National Petroleum Reserve by removing restrictions and opening 82% of the area for new drilling.

Cold Start to Heating Season Sends Ontario Gas Storage Below Five-Year Average - Natural gas storage in Canada’s most populous province of Ontario has quickly descended below the five-year range and reached its lowest level for this time of year since 2014 based on data in RBN’s Canadian NatGas Billboard. With a reading of 234 Bcf (blue text and line in chart below) on December 10, the province’s gas storage was 26 Bcf less than a year ago, 26 Bcf less than the five-year average and 23 Bcf below the low end of the five-year range. This is the lowest for Ontario gas storage since 228 Bcf was recorded on the same date in 2014. As has been the case for much of the eastern half of North America since the traditional start of the heating season on November 1, and more specifically for Central Canada (defined in this context as Ontario and Quebec), average temperatures have been much colder than last year and versus the historic average (defined as “normal” based on the 30-year average). Using RBN’s calculation of population weighted heating degree days (a measure of how cold is the weather) for Central Canada, cumulative heating degree days from November 1 to December 10 (blue column in chart below) have been 25% greater than last year (green column), 12% greater than normal (gray column), and the coldest start to a heating season in Central Canada in 25 years.

Canadian Drilling – Next to Last Gasp Before the Holidays? *-- For the week of December 5, Baker Hughes reported that the Western Canadian gas-directed rig count fell two to 65 (blue line and text in left hand chart below), five less than a year ago and the lowest for this time of year since 2021. The oil-directed rig count gained five to 126 (red line and text in right hand chart), four more than a year ago, the first year-on-year gain since mid-May, and its highest level for this time of year since 2022. Rig counts are within a few weeks of rolling lower as part of the traditional holiday break for rig crews at the end of each year.Of the three western provinces in which gas drilling takes place (table below), three were dropped in Alberta, while one was added in British Columbia (BC). In terms of drilling by formation, one rig was added in the BC Montney, two fell away from the Alberta Montney/Deep Basin, while one was lost in Other Western Canada, which was Alberta shallow gas in the southeastern part of the province. The BC Montney remained the biggest laggard versus last year with a loss of five rigs. For the provinces in which oil drilling takes place (table below), three rigs were added in Alberta and two picked up in Saskatchewan. By formation/region, gains were generally widespread while there was a loss of two rigs from Alberta’s Duvernay Oil/NGLs. The biggest year-on-year loss came for Alberta’s Peace River heavy oil with a decline of seven, while Alberta’s oil sands recorded the largest year-on-year gain with an increase of seven.

Trans Mountain Waterborne Crude Exports Rise to Near Record, Exports to China Soar to New High | RBN - Waterborne crude oil exports from the expanded Trans Mountain Pipeline (TMX) averaged 490 Mb/d in November 2025 (rightmost stacked column in chart below), an increase of 60 Mb/d versus a revised October level of 430 Mb/d, and an increase of 123 Mb/d from a year ago based on tanker tracking data compiled by Bloomberg. The latest exports are just 8 Mb/d short of the record reached in March 2025 of 498 Mb/d. The most recent increase confirmed market reports that tanker export bookings off TMX would increase in response to favorable pricing opportunities versus other overseas crude streams and wider sanctions on exports of Russian crude oil in an attempt to target importing countries such as China, with the result of more tanker bookings from non-sanctioned countries such as Canada. Senior management at TMX noted in its latest quarterly report that tanker bookings appear to have remained strong into December. China (red columns) held its position as the largest purchaser of Canadian crude oil for the eleventh consecutive month and at a record level with November’s exports pegged at 394 Mb/d, 47 Mb/d higher than October’s revised level of 347 Mb/d, and a very strong 191 Mb/d more than a year ago. A distant second in the month were exports to the United States (blue columns), landing at 97 Mb/d, an increase of 14 Mb/d from the prior month and 68 Mb/d less than one year ago. No other countries were reported by Bloomberg as destinations for Canadian crude in October. China’s most recent purchases were exclusively geared to heavy oil consisting of Access Western Blend (AWB), a sour, higher acid blend of diluted bitumen (grey columns in chart above), while purchases of Cold Lake Blend (teal columns), another sour diluted bitumen closer to Western Canadian Select (WCS), Western Canada’s benchmark heavy oil, with lower acid and sulfur content than AWB, fell to zero in November for the first time since June. Exports to China of AWB were a record 394 Mb/d in November, up from 279 Mb/d in October and zero one year ago. New refineries and growing experience in handling the higher sour and acid content of Canadian barrels have shifted China’s focus to AWB for both logistical and economic reasons. Combining the latest waterborne exports with RBN’s estimates of crude oil and refined product flows from TMX to land-based destinations in British Columbia and Washington state, resulted in a pipeline utilization rate for TMX of 93% in November, the highest since the expanded system began operations in late May 2024.

Cooling Atlantic Spot Prices Shift LNG Flows Toward Asia - A look at the global natural gas and LNG markets by the numbers. Table titled “Prompt Month Statistics – Previous 5 Trading Days” displaying U.S., Europe, Latin America, and Asia natural gas fundamentals from Dec. 3–9, including Max GOM Netback, Henry Hub futures, LNG feedgas demand, global LNG shipping costs, landed price arbitrage values, regional temperatures versus 30-year normals, European TTF and NBP futures, gas storage fullness, spark and dark spreads, PVB/TTF premium, and January DES prices for Mexico, Argentina, Brazil, Chile, Colombia, and Panama. The right side lists Asia metrics including JPN/KOR futures, oil parity slope, Brent and coal price parity, and major Asian city temperature deviations from normal.

• 90%: European Union (EU) members have agreed to the outline of a climate plan that calls for a 90% reduction of greenhouse gas emissions by 2040. The provisional agreement concluded Tuesday called for accelerating carbon-cutting after the target of 55% of 1990 emission levels by 2030. The plan also relies on a model of 40-60% less gas demand in Europe by 2040 and the implementation of methane reporting for imported fuels.
• $10.85/MMBtu: East Asian LNG prices have fallen to a point to redirect Middle Eastern supply away from Europe, according to Kpler ship tracking data. The analytics firm recorded the diversion of a QatarEnergy controlled vessel from Belgium to India as spot prices in the Atlantic Basin continue to cool. The prompt Japan-Korea Marker settled at $10.85/MMBtu Tuesday, while Europe’s Title Transfer Facility slipped more than $1.20 compared to the same time last week.
• 4.4 Bcf/d: Venture Global Inc. has been cleared to begin construction on a key component for its CP Express Pipeline project. FERC approved the company’s request to construct the Moss Lake Compressor Station, a 187,000 horsepower facility in Calcasieu Parish, LA. The station is a part of Venture Global’s plan to move up to 4.4 Bcf/d in feed gas from East Texas and Southwest Louisiana through CP Express for its CP2 LNG export project currently under construction.
• 2.9 Mt/y: The Federal Energy Regulatory Commission also authorized project partners to introduce gas to the newly constructed condensate plant at the Southern LNG export facility operated by Kinder Morgan Inc. The condensate plant is a part of an optimization project planned to boost output at the Elba Island, GA, facility from 2.5 million tons/year (Mt/y) to 2.9 Mt/y. The facility hasn’t exported its full nameplate capacity since loading its first cargo in 2019. Southern LNG is on track to lift around 1.75 Mt by the end of December, according to Kpler predictive data.

Russia In Talks To Extend Gazprom Gas Contracts With Turkey - Russian energy giant Gazprom is currently negotiating with Turkish partners to extend critical natural gas supply contracts set to expire at the end of this year. Russian Deputy Prime Minister Alexander Novak told the Russian state news agency that Gazprom and Turkish buyers are discussing options to roll over existing agreements into 2026. Speaking in Riyadh, Novak confirmed, “Gazprom is in contact with its Turkish partners,” in response to questions on the potential contract extensions. The talks focus on agreements between Gazprom and Turkey’s state oil and gas company Botas for gas transported via the Blue Stream and Turkish Stream pipelines beneath the Black Sea. These contracts collectively cover approximately 21.75 billion cubic meters of gas annually and are scheduled to expire at the end of 2025. Since 2007, Gazprom has also maintained long-term contracts with several private Turkish gas importers, some of which are due to end between 2025 and 2026, adding further impetus to renegotiation efforts. In 2025, Gazprom held five meetings with Turkish partners, including Botas and private firm Bosphorus Gaz Corporation, to review the status and future of gas supplies to Turkey. Turkey heavily depends on imported gas for electricity, heating, and industrial use, with Russia remaining its largest supplier despite Western sanctions on Moscow over the Ukraine conflict. According to Turkey’s energy regulator, the country imported around 50 billion cubic meters of natural gas in 2023, with more than 21 billion cubic meters—about 40% of total imports—coming from Russia. Ankara has been attempting to diversify supplies by increasing liquefied natural gas (LNG) imports from the U.S. and other producers. In September, Botas signed a 20-year LNG agreement with Mercuria, securing around 4 billion cubic meters annually from U.S. export terminals starting in 2026. Turkish officials present these LNG deals as a move to ensure energy security and reduce dependence on Russian and Iranian gas. At the same time, Turkey and Russia continue to strengthen gas transport cooperation. Turkish Stream now supplies Russian gas not only to Turkey but also to EU countries in Southeast Europe after other transit routes via Ukraine and the Baltic Sea were disrupted. Reuters estimates, based on European network data, show that Turkish Stream has delivered roughly 20 billion cubic meters of gas annually to Turkey and Europe in recent years, making Turkey Russia’s last major gas market in Europe. The U.S. has granted Turkey exemptions allowing payments for Russian gas despite sanctions on Russian banks, highlighting concerns that abrupt supply disruptions could destabilize Turkey’s economy and energy system. Russian President Vladimir Putin has repeatedly promoted the idea of Turkey as a regional gas hub, blending Russian supplies with other sources for resale to Europe. The current discussions reported by Novak indicate that Moscow aims to secure its foothold in the Turkish market, even as Ankara continues to pursue LNG deals and strengthen energy relations with the U.S.

Crude oil shoots from damaged pipeline in eastern Germany -- State authorities in Brandenburg reported a major oil spill north of Berlin late on Wednesday, saying there had been an accident affecting a pipeline connecting a major oil refinery to the Baltic Sea port of Rostock. "An accident occurred on the PCK pipeline near Gramzow/Zehnebeck, resulting in a large oil spill," a spokesman for Brandenburg's Environment Ministry said. "Emergency services are on site. No information can be provided at this time about the cause or the exact extent of the damage." The fire department later estimated that roughly 200,000 liters (about 52,835 gallons) of oil had escaped from the pipeline at a pumping station in Gramzow. For orientation, that amount of liquid would fill a little less than one-tenth of an Olympic swimming pool. Alexander Trenn of the Schwedt fire department said the leak had a pressure of around 20 bar (roughly 290 psi) at its peak, causing a fountain of oil several meters high to spew out. Specialist machinery was being used to remove the spilled oil. Clean-up operations would continue into Thursday morning, he said. Trenn said around 100 fire department officers and some 25 company employees were working on site. A major oil refinery is located near the border to Poland in Schwedt, operated by PCK. The company says on its website that the facility can process 11.5 million metric tons of oil a year, "making it one of the largest crude oil processing sites in Germany." Meanwhile, the AFP news agency cited a PCK spokeswoman as saying that "deliberate external influence" such as sabotage could already be "ruled out." Local public broadcaster rbb reported that by 7:45 p.m. local time (1845 UTC/GMT), "the leak was for the most part plugged, although some oil was still leaking out." Pipelines connect the refinery to the major port of Rostock to the northwest. Gramzow is situated slightly northwest of Schwedt, on the northern tip of a large nature reserve to the north of Berlin. The refinery is also next to another national park. The areas between Berlin and the Polish border are heavily forested and also the site of the Oder River, which serves as the border much of the time.

Pipeline Leak Spills 200,000 Litres of Oil in German Farmland - Emergency crews have completed the cleanup of a pipeline leak that spilt at least 200,000 litres (about 53,000 gallons) of crude oil onto farmland in the state of Brandenburg, north of Berlin. The leak in the pipeline, which transports oil from the Baltic Sea port of Rostock to the Schwedt refinery, occurred on Wednesday evening near the village of Gramzow during what officials described as a workplace accident. A spokesman for regional emergency coordination confirmed that firefighters concluded their operation between 2 a.m. and 3 a.m. local time. The Schwedt fire brigade reported that the oil initially shot several meters into the air from a small leak at a pumping station before settling on the adjacent agricultural land. Refinery operator PCK said preliminary findings indicate the incident was caused by preparatory work for a scheduled safety test on the pipeline, ruling out any deliberate interference. Alexander Trenn, head of the Schwedt fire brigade, told German news agency dpa that crews successfully removed all visible spillage. He noted that special suction vehicles and heavy machinery were used to collect the significant quantity of oil and contain its spread. Roughly 100 firefighters and 25 PCK employees were involved in the overnight response, with PCK now responsible for handling the subsequent environmental remediation efforts. Brandenburg’s environment minister, Hanka Mittelstädt, was expected to visit the site on Thursday to assess the extent of the damage to the affected countryside.

Kazakhstan Reroutes Kashagan Crude After Black Sea Pipeline Attack - Kazakhstan will reroute some of the oil from at its giant Kashagan oilfield toward China after a Ukrainian drone attack on an export terminal on Russia’s Black Sea reduced loadings of Kazakh crude. At the end of November, a Ukrainian attack damaged infrastructure at the loading terminal of the Caspian Pipeline Consortium (CPC) at the port of Novorossiysk on Russia’s Black Sea coast. CPC operates the pipeline from the Caspian coast in northwest Kazakhstan to the Novorossiysk port, which handles 80% of Kazakhstan’s crude exports from giant oilfields in Kazakhstan operated by international oil firms. Affiliates of Chevron and ExxonMobil are also minority shareholders in CPC, with the Russian Federation as its largest shareholder with a 24% stake.In view of urgent repairs at one of three single point moorings and deferred loadings, Kazakhstan works on rerouting part of its crude exports, Kazakhstan’s Energy Ministry told Reuters on Wednesday. Although the attack did not halt all shipments, Kazakhstan is working to reshuffle exports until the terminal is operating at normal capacity again. “Currently, the Ministry, together with shippers, is carrying out urgent work to redistribute oil volumes,” the Energy Ministry told Reuters. “Measures have also been taken to redirect a certain volume of Kashagan oil to China,” it added.Kazakhstan is also diverting more of its westbound exports to the Baku-Tbilisi-Ceyhan (BTC) pipeline to the Turkish Mediterranean coast after the attack at the CPC terminal on the Black Sea, multiple industry sources toldReuters last week.The Kashagan field is located in the North Caspian Sea in Kazakhstan and is one of the biggest oil discoveries globally of the past 50 years. The oilfield has approximately 35 billion barrels of oil in place, of which nearly half are estimated to be recoverable. The Kashagan oilfield is being developed by the North Caspian Project consortium of international majors and Kazakhstan’s state oil firm KazMunayGas. The shareholders in the consortium include KazMunayGas, Eni, Shell, ExxonMobil, TotalEnergies, China’s CNPC, and Japan’s INPEX Ltd.

Russia Says 90% of Kerch Strait Oil Spill Collected – More than 90 percent of the fuel oil spilled in the Kerch Strait in late 2024 has been collected, Russian Deputy Prime Minister Vitaly Savelyev said Friday. The spill followed the sinking of two Russian oil tankers on Dec. 15 last year. Savelyev said more than 185,000 tonnes of contaminated sand and soil have been gathered for disposal and sale. Fuel oil was pumped out of the stranded stern of one tanker in March, while the bulk was removed from the bow in October and November. Savelyev added that the government has approved installing three cofferdams to contain leaks from the sunken vessels. The first has already been placed, with work on the second and third ongoing.

India’s Russian Oil Imports Are Set to Hit a Six-Month High -- Indian refiners are on track to buy the most Russian crude in six months this December, despite U.S. sanctions on Russia’s top two exporters that went into effect in late November.The average daily arrivals of Russian oil in India are estimated at 1.85 million barrels, according to data from Kpler, cited by Reuters’ Clyde Russell. That would be up from 1.83 million barrels daily in November and the highest since June, when Indian buyers imported Russian crude at a rate of 2.1 million barrels daily.The November figure itself was a downward revision on an earlier estimate that had pegged the month’s average daily import rate at 1.855 million barrels. Even at 1.83 million barrels, however, the November daily average was higher than the figure for October, which was 1.48 million barrels daily, again per Kpler. Rosneft and Lukoil, the targets of the latest U.S. sanctions, handled around half of Russia’s total oil exports, or some 2 million barrels daily, until November 21, when the sanctions came into effect. Since then, importers and exporters alike have been looking for—and finding—ways around the sanctions. As many expected, while exports by Rosneft and Lukoil are down, exports of crude by non-sanctioned companies have spiked since November 21.According to data recently quoted by Goldman Sachs, since the sanctions came into effect, oil flows from Rosneft and Lukoil abroad had dropped by around 1 million barrels daily. However, in the same period, flows from non-sanctioned Russian oil companies to clients overseas have gained half a million barrels daily.Some analysts predicted that Indian purchases of Russian oil would tank in December as sanctions came into effect, but this does not seem to have been the case. This confirms the expectation that oil flows would continue, under a new name, as it were, coming from companies other than Lukoil and Rosneft.

Liberian ship sinks off Kerala coast, 24 crew rescued; oil spill feared --A Liberian vessel carrying 640 containers, including 13 with hazardous cargo, sank off the Kochi coast on Sunday, sparking fears of a possible oil spill. All 24 crew members were rescued after the ship developed a critical tilt on Saturday, according to officials. So far, no oil spill has been reported, the Ministry of Defence said on Sunday as full pollution response preparedness was activated by the Indian Coast Guard which was monitoring the situation along with the Indian Navy. "Liberian container vessel MSC ELSA 3 (IMO NO. 9123221) sank off the Kochi coast at around 0750 hrs today on May 25, 2025, due to flooding... "The vessel went down with 640 containers, including 13 with hazardous cargo and 12 containing calcium carbide. It was also loaded with 84.44 metric tons of diesel and 367.1 metric tons of furnace oil," the ministry said in a statement. Of the 24 crew members, 21 had been rescued by the Indian Coast Guard on Saturday, and the remaining three were later rescued by INS Sujata, which joined the rescue operation launched by the ICG. Given the sensitive marine ecosystem along Kerala's coast, the ICG has activated "full pollution response preparedness" and ICG aircraft equipped with advanced oil spill detection systems are conducting aerial surveillance, officials said. "ICG ship Saksham, carrying pollution response equipment, remains deployed at the site. So far, no oil spill has been reported," the defence ministry said. The Kerala State Disaster Management Authority (KSDMA) has cautioned the general public against touching any cargo containers or oil spills that may wash ashore. The coast guard has confirmed that the vessel was carrying Marine Gas Oil (MGO) and Very Low Sulphur Fuel Oil (VLSFO). Deploying its ships and aircraft, the Indian Coast Guard had launched a rescue operation on Saturday following a distress call from the Liberian container vessel that developed a critical 26-degree list nearly 38 nautical miles southwest of Kochi.

Oil Tanker Rates Skyrocket 467% --The supertanker market has tightened this year as crude supply from OPEC+ and the Americas rises and vessels make increasingly longer trips. So much has the market tightened that several new-built very large crude carriers (VLCC) have made empty maiden voyages from yards in Asia to pick supply from producing countries in the Middle East, the Americas, and Africa, instead of loading fuels made in Asia on their first journey. As many as six VLCC, or supertankers as they are commonly known, have traveled this year empty on their maiden voyages, according to vessel-tracking data reviewed by Bloomberg and shipping analytics firm Signal Ocean. Last year, only one tanker made an empty maiden voyage. Usually, supertankers travel with gasoline cargoes on these first trips, but apparently the market shortage has prompted owners to forego this loading and rush to send the tankers on load crude as daily rates have soared. The daily rates for chartering a vessel to transport commodities have surged this year, with oil tanker ratesskyrocketing by 467%, as shippers of a growing commodity supply are grappling with a series of route disruptions and sanctions. Despite the typically weaker commodity demand period toward the end of each year, the last weeks of 2025 don’t show any weakness in the vessel rates for transporting crude oil, LNG, iron ore, or wheat. The unusual strength at the end of the year has seen oil tanker rates on the key shipping routes surge by 467% year to date, according to Bloomberg’s estimates based on data from the Baltic Exchange and commodity markets data provider Spark Commodities. At the end of November, supertanker rates on the route between the Middle East and China hit their highest in five years as traders sought alternatives to Russian crude after the U.S. sanctioned Russia’s biggest oil producers and exporters, Rosneft and Lukoil. Rates for smaller tankers have also shot up as traders turn to all available vessels to transport crude. Tanker rates have been climbing for over a month amid sanction-related disruptions that led to a surge in oil in transit.

Pakistan and Turkey Strengthen Energy and Mining Partnership with Over $300 Million Investments in Offshore Drilling, Oil and Gas Exploration - Pakistan and Turkey have strengthened their partnership in energy and mining, signing key agreements on Tuesday that are expected to attract over $300 million in investment, primarily for offshore drilling and exploration projects. Turkish Minister of Energy and Natural Resources, Alparslan Bayraktar, who visited Pakistan, highlighted plans for additional joint ventures in oil and gas exploration, energy infrastructure, and mining, emphasizing that deeper collaboration in these sectors would help achieve the shared goal of $5 billion in bilateral trade. Prime Minister Shehbaz Sharif witnessed the signing of several memoranda of understanding (MoUs) and agreements, including petroleum concessions for multiple offshore and onshore blocks such as Eastern Offshore Indus-C, Ziarat North, Sukhpur-II, Deep-C, and Deep-F. Minister for Petroleum Ali Pervaiz Malik welcomed the deals, noting that these investments will boost the energy sector and strengthen Pakistan-Turkey relations. PM Shehbaz Sharif regards Turkish President Recep Tayyip Erdogan as a brother, reflecting a spirit of friendship that drives collaboration across strategic sectors. Executives from Mari Energies, OGDC, and PPL presented ongoing and planned projects, highlighting opportunities for Turkish partners to engage in oil, gas, and mining ventures, including unconventional hydrocarbon projects like shale and tight gas exploration and the Reko Diq copper and gold project. As part of the agreements, a Turkish Petroleum office will open in Islamabad in December, with 10 Turkish nationals working alongside local staff. A unified approach to petroleum procurement through a joint trading company was also discussed to strengthen energy security for both countries. The MoUs included an assignment of a 25% working interest of Indus Offshore Block-C to Turkish Petroleum Overseas Company (TPOC), with Mari Energies and OGDC as joint-venture partners. Exploration licenses were granted for Offshore Deep-C and Deep-F Blocks, and onshore blocks including Sukhpur-II and Ziarat North, involving Mari Energies, TPOC, OGDC, PPL, and GHPL. Looking ahead, Pakistan is encouraging private-sector participation in the privatization of power distribution companies (DISCOs). Turkish firms, with their expertise in energy, are expected to play a pivotal role. Federal Minister for Power Awais Ahmed Khan Leghari noted the opportunity for Pakistan’s energy experts to learn from Turkey’s private-sector-driven energy model and announced that three DISCOs will soon be offered for privatization. This collaboration reflects a shared commitment to sustainable development, investment, and long-term energy security, strengthening bonds between Pakistan and Turkey while opening doors for innovation, growth, and humanitarian benefits in the energy sector.

Turkey Mulls US Gas Investments to Hedge Against LNG Deals - Turkey is mulling investing in upstream natural gas developments across the globe, including in the US, in order to hedge against its growing natural gas and LNG import portfolio needed to meet the country’s growing domestic consumption and export ambitions, Energy Minister Alparslan Bayraktar said last week.

Turkish tanker incident prompts Senegal response to stop oil spill --Authorities in Senegal have launched urgent measures to prevent a potential oil spill after water entered the engine room of the Panamanian-flagged oil tanker Mersin off the coast of Dakar, the port authority said on Sunday. The vessel is owned by Turkey's Mersin Shipping Inc and managed by Besiktas Shipping, according to data from the London Stock Exchange Group. The incident, which led to the vessel issuing a distress signal, occurred overnight from 27 to 28 November, prompting the deployment of tugboats and specialised teams from Senegal's navy and maritime authority, the port authority said. Authorities did not give details about the incident. All crew members were safely rescued with no reported injuries, it said. "Authorities are working to stabilise the vessel, prevent hydrocarbon leaks, and mitigate environmental risks," Dakar's port authority said in the statement. It added that immediate measures included stopping the leak, transferring the fuel cargo, and deploying an anti-pollution boom around the tanker as a precautionary step. Images of the vessel shared online showed its stern close to the waterline, which could indicate it is carrying a full cargo or experiencing flooding. Reuters has not independently verified the images.

NGO reiterates N50b demand over spills -Environmental rights group, Save the Earth and Secure the Future (SESF), has reiterated its demand for N50 billion compensation and full cleanup of affected communities, and investigation of concerned National Oil Spill Detection and Response Agency (NOSDRA) officials over perceived “ecocide” linked to multiple oil spills in OML 40. In a statement signed by Mr. Nehemiah Tobolayefa and Mrs. Tari Gideon, the group accused Nigeria Exploration and Production Limited (NEPL) and ELCREST of failing to clean up the October 28, 2023 spill and two subsequent spills, as well as allegedly dumping hazardous waste around the Opuama Flow Station. “They have become the mouthpiece of the companies. A rat defends the snake that bites him, while the forest burns,” the group said, criticising community leaders who recently defended the operators. SESF said a joint investigation visit occurred nearly two weeks after the 2023 spill and confirmed equipment failure. It cited earlier petitions and press briefings by community elders in 2024 which it said were ignored by the companies. The group invoked Section 54 of the Petroleum Industry Act and EGASPIN guidelines to argue that NEPL and ELCREST are legally responsible for cleanup, including so-called legacy spills. It also claimed rising deaths and cancer cases in the area, referencing the UNEP Ogoniland report. Efforts to get reactions from NEPL and NOSDRA were unsuccessful, as both did not respond to earlier messages seeking comments on the matter.

Pipeline Leak Forces Major Outage at Iraq's West Qurna-2 -A leak on a pipeline used to export oil from the giant West Qurna-2 field, operated by US-sanctioned Lukoil, has forced a production cut of 300,000 barrels per day on Monday, according to a senior Iraqi oil official.The incident follows a fatal explosion at the Zubair-1 storage depot and pumping station in southern Iraq in late October, and underscores the serious constraint on Iraq’s ability to maintain current oil output and export levels — never mind raise them — due to its decrepit infrastructure.“Production was reduced to control a leak that happened at the Tuba depot pipelines,” the official said, referring to the Tuba oil depot that West Qurna-2 feeds into, and which is linked by two pipelines to the Fao export terminal on the coast.The official declined to specify how long the production cut, which reduced output at the field to around one-third of its previous level of about 480,000 b/d, would last. Reuters reported on Monday that the field was due to be brought back on line overnight.The same Iraqi official, speaking last week, confirmed that the accident at the Zubair-1 depot had forced Iraq to redirect some of its crude exports via the Zubair-2 depot, which has a lower pumping capacity. The blast at Zubair-1 was triggered by a gas leak at the pumping station, one of four that Iraq relies on to export Basrah crude. Those exports stood at around 3.34 million b/d in October and dropped by about 40,000 b/d in November. The official also mentioned unplanned maintenance at the Tuba depot and the nearby PS-1 pipeline in October, “due to some corrosion and other reasons” that halted operations at those two facilities for a couple of hours. Monday’s pipeline leak appears unrelated to the uncertainty surrounding the future of West Qurna-2 following the US announcement in October that it was blacklisting Lukoil, which holds a 75% stake in the field, alongside fellow Russian oil giant Rosneft. The US sanctions prompted state oil marketer Somo to cancel crude cargo nominations for Lukoil as payment in kind for managing operations at West Qurna-2, raising questions about how long the Russian firm could continue working at the field.The last Basrah cargo lifted by Lukoil’s trading subsidiary Litasco departed in late October, shipping data showed, and the Iraqi oil official suggested the Russian firm had already exited the field.“Maybe Lukoil is not operating there anymore. But it’s going to be replaced by either a national company or international company,” the official said.Iraq’s oil ministry said last week that it had issued “direct and exclusive invitations” to US oil majors to bid for the management of West Qurna-2. The announcement came against the backdrop of renewed interest in Iraq’s upstream from the two largest US oil firms, Chevron and Exxon Mobil, which signed heads of agreement with the oil ministry in August and October, respectively.

Saudi energy companies secure contracts for oil and gas projects in Syria --Syria’s state-owned oil and gas company, Syrian Petroleum Company (SPC), has signed agreements with four Saudi Arabia-based companies to provide technical services for the development of oil and gas fields in Syria. The contracted companies are TAQA, ADES Holding, the Arabian Drilling Company and the Arabian Geophysical and Surveying Company (ARGAS). These contracts, signed under the supervision of the Saudi Ministry of Energy, aim to provide development, services and technical support for the oil and gas fields. SPC’s contract with ADES Holding outlines the primary principles for oil field development, operation and production. It also states the key terms for the final technical services contract, which will cover the development and operation of gas fields and related facilities. This contract covers five gas fields – Abu Rabah, Qamqam, North Al-Faydh, Al-Tiyas and Zumlat al-Mahar – with additional areas to be determined. TAQA signed a master service agreement with SPC to deliver integrated solutions and services for constructing and maintaining oil and gas fields and wells in Syria. This agreement aims to improve operational processes and production by leveraging advanced technologies and equipment. The service contract signed between ARGAS and SPC supports exploration and drilling through 2D and 3D seismic surveying and related technical services. This deal is said to establish a long-term cooperation framework for petroleum exploration and development in Syria, with a focus on rapid response and operational flexibility. Arabian Drilling’s agreement is focused on drilling and workover services for oil and gas wells, including the leasing and operation of onshore rigs. The company has agreed to supply the necessary rigs, carry out workover operations and operational support, and provide workforce training and development.

Funding in place for multi-well offshore drilling campaign to boost oil flow rates - - Jasmine Energy (JEL), a subsidiary of Singapore’s Rex International, has revealed a multimillion-dollar bond issue, which will enable it to undertake a drilling campaign off the coast of Oman to augment oil production. While disclosing that Jasmine Energy has raised $25 million in senior secured bonds with a three-year tenor, Rex highlights that the proceeds will be used to fund a three-well drilling campaign at the Yumna field in Block 50 next year and for general corporate purposes by Masirah Oil, an indirect 87.5% subsidiary of JEL. Per Lind, Interim Chief Executive Officer of Rex, commented: “The successful completion of the bond issue is timely, and will allow us to execute a planned drilling campaign to drill new producer wells to increase oil flow rates in the Yumna field in Block 50, Oman, which is targeted to start in the first quarter of 2026. “We are pleased to have garnered strong support from bondholders with our track record of increasing reserves volumes in the mature Yumna Field. With strengthened income from the oil production from the new producer wells, we will continue our efforts to extend the lifetime of the field, in line with our commitment to create long-term value for our stakeholders.” According to the company, the settlement of the bonds, which will carry a coupon of 14%, is expected to take place on December 12, 2025. The closing and draw-down are subject to certain conditions and approvals.

OPEC Maintains Bullish Oil Demand Outlook, IEA Trims Oil Glut Forecast --Oil prices are lower this morning despite a less-hawkish-than-feared Fed cut and a double-whammy of relative optimism from OPEC and the IEA... OilPrice.com's Tsvetana Paraskova reports that the oil market still faces record oversupply next year, according to the monthly report by the International Energy Agency (IEA), but the glut estimate is now trimmed by about 230,000 barrels per day compared to the November forecast. The market is headed to as much as 3.84 million barrels per day (bpd) of supply exceeding demand in 2026, the IEA said on Thursday in its closely-watched report for December. While this still is a considerable glut, it’s lower than the 4.09 million bpd implied oversupply expected in the November report. In today’s report, the IEA said that the projected global oil surplus in the fourth quarter of 2025 has narrowed since last month’s report, “as the relentless surge in global oil supply came to an abrupt halt.” Total global oil supply dipped by 610,000 bpd in November compared to October and by a whopping 1.5 million bpd from September’s all-time high, the IEA noted. OPEC+ accounted for 80% of the decline over October and November, reflecting significant unplanned outages in Kuwait and Kazakhstan, while oil output from sanctions-hit Russia and Venezuela plunged. Russia’s total oil exports are estimated to have plummeted by about 400,000 bpd in November to 6.9 million bpd, as buyers assessed the implications and risks associated with more stringent sanctions. Buyers, especially in Russia’s second-biggest crude oil customer, India, are steering clear of any Rosneft and Lukoil-related cargoes, for fear of running afoul of the U.S. Administration while India and the United States are still locked in difficult trade negotiations. The IEA noted in its report the apparent disconnect between the current global oil surplus and inventories near decade lows at key pricing hubs. Despite record volumes of oil piling up on water, benchmark crude oil prices eased only marginally in November, because “in stark contrast to the broader picture, crude and refined product stocks in key pricing hubs have seen only marginal builds,” the agency said. As Charles Kennedy reports at OilPrice.com, global oil demand will rise by about 1.4 million barrels per day (bpd) next year, supported by solid economic growth, OPEC said in its monthly report ton Thursday, keeping its demand forecasts unchanged from last month. Unlike other forecasters, investment banks, and analysts, OPEC continues to expect robust demand growth in 2026 that will be higher than the estimated increase for 2025 of about 1.3 million bpd, forecasts in the cartel’s Monthly Oil Market Report (MOMR) showed on Thursday. Figures about the balance of supply and demand in OPEC’s report also suggest that the cartel expects a balanced market next year.Demand for crude from the OPEC+ producers is expected at 43.0 million bpd in 2026, up by 60,000 bpd compared to the projection for 2025, OPEC said. At the same time, crude oil production by the countries in the OPEC+ pact averaged 43.06 million bpd in November, a rise by 43,000 bpd from October, compared to the available secondary sources in OPEC’s report. After December, OPEC+ producers will be pausing their targeted monthly production increases during the first quarter of 2026. OPEC expects rival non-OPEC+ oil supply to grow by about 600,000 bpd next year, versus growth of some 1 million bpd expected for 2025. This projection, while not new for OPEC, reiterates the cartel’s view that U.S. oil production growth will slow down next year. Signals have started to emerge in the shale patch and from industry executives that WTI crude prices below the $60 per barrel mark will put the brakes on America’s shale growth.

IEA revises oil demand forecast upward on improving economic outlook --Global oil demand is expected to increase by 830,000 b/d in 2025, supported by an improving macroeconomic and trade environment, according to the International Energy Agency (IEA)’s December Oil Market Monthly Report (OMR). This was reflected by resurgent third-quarter demand of 1.1 million b/d, more than doubling from the second-quarter’s underwhelming 450,000 b/d. “After a spate of breakthrough US trade deals were reached over the summer, economic sentiment rebounded quickly, helping emerging and developing economies return to their pre-April trend. Still, the tariff turbulence has essentially rendered 2025 second-quarter a lost quarter for non-OECD oil consumption and the as yet unresolved negotiations over tariffs with a number of countries will continue to weigh on markets,” IEA said. The stronger outlook also carries into 2026, where IEA has raised its demand growth forecast by 90,000 b/d to 860,000 b/d year-on-year (y-o-y). Falling oil prices, along with the weaker US dollar—both of which are currently hovering around 4-year lows—will likely boost oil demand in the coming year. “Gasoil and jet/kerosene together make up half of this year’s growth, while fuel oil continues to lose share to natural gas and solar in power generation. In 2026, petrochemical feedstocks will drive the bulk of demand expansion, with their share rising to more than 60%, up from 40% in 2025,” IEA continued. On the supply side, global oil supply dropped by 610,000 b/d month-on-month (m-o-m) to 107.5 million b/d in November, extending the decline from September’s record high of 109 million b/d. OPEC+ accounted for 80% of the decline over the 2-month period, reflecting significant unplanned outages in Kuwait and Kazakhstan, while output from sanctions-hit Russia and Venezuela contracted sharply. Meantime, Russian oil exports fell by 420,000 b/d in November, and together with weaker prices, reduced export revenues to $11 billion—$3.6 billion less than a year earlier. In IEA's latest monthly report, global oil supply growth has been revised down by 100,000 b/d to 3 million b/d for 2025 and by 20,000 b/d to 2.4 million b/d for 2026, bringing total supply to 106.2 million b/d and 108.6 million b/d, respectively. After navigating substantial unplanned refinery outages in November, refined product markets have loosened somewhat, but new sanctions in first-quarter 2026 will pose additional challenges, according to IEA. The sharp contrast between surging crude supply and unexpectedly tight product markets has pushed refinery margins back to levels not seen since the aftermath of Russia’s invasion of Ukraine. Refinery run forecasts for 2026 have been raised to 84.4 million b/d, with annual growth of 750,000 b/d. Global observed inventories climbed to a 4-year high in October, reaching 8,030 million bbl. Stock builds averaged 1.2 million b/d over the first 10 months of the year. October alone saw a 42 million bbl increase (+1.4 million b/d), driven by an 83 million bbl rise in oil on water, while on-land inventories fell by 41 million bbl, including a 26 million bbl drop in OECD stocks. Preliminary November data points to another increase in global stocks, largely reflecting a rise in non-OECD on-land crude. North Sea Dated crude declined by around $1/bbl m-o-m to $63.63/bbl in November—its fifth straight monthly decrease and the longest losing streak in 11 years. Near-record oil on water, soft crude fundamentals, and low volatility kept prices near 4-year lows of around $63/bbl, despite tightening sanctions and strong diesel cracks. “Much has been made about the apparent disconnect between the current global oil surplus on the one hand and inventories near decade lows at key pricing hubs on the other. Indeed, despite record volumes of oil piling up on water, benchmark crude oil prices eased only marginally in November, with North Sea Dated last trading at around $63/bbl and WTI at $59/bbl, with lower forward prices disincentivizing storage. Still, the market trends have clearly been affecting prices over time, with ICE Brent down by nearly $20/bbl since January,” IEA commented in the report.

Oil Steadies as Growth Hopes Offset Fears of a Supply Glut - Oil is trading with little direction in early Asian hours as markets weigh the risk of a supply glut against the possibility of stronger demand if the Federal Reserve cuts rates this week. Front-month WTI is stable near 60.11 dollars per barrel and Brent is unchanged around 63.77 dollars. The lack of movement reflects a market caught between geopolitical uncertainty and macro policy optimism. The stalling of Ukraine-Russia peace negotiations has revived concerns about disrupted trade flows and uneven supply distribution across Europe. At the same time, analysts warn that global inventories are starting to edge higher, particularly in the Atlantic Basin, raising the possibility that excess barrels will limit the ability of prices to respond to geopolitical shocks. These factors have kept physical markets cautious, with refiners resisting higher procurement while traders assess shipping and storage dynamics. Yet the demand side of the equation is receiving support from growing confidence that the Federal Reserve is preparing to cut rates. Lower U.S. borrowing costs would help stabilize industrial activity in early 2026 and could lift fuel consumption at a time when airlines, freight carriers, and manufacturers are already signaling stronger forward bookings. The pricing stasis in WTI and Brent shows that futures markets are waiting for clear confirmation of the Fed’s decision. A cut would ease financial conditions and soften the dollar, which typically improves purchasing power for importers and provides a mild tailwind for crude benchmarks. Energy equities remain in a holding pattern as well, since producers are reluctant to update capex guidance until they see whether macro conditions can absorb additional output. Inflation expectations are also stable since crude remains well below recent highs, helping central banks outside the U.S. maintain a neutral stance. Investors will focus on several catalysts over the coming week. Any restart of Ukraine-Russia negotiations would shift attention back to supply stability, while new OPEC communication could clarify whether the group intends to adjust targets if inventories continue to build. U.S. inventory data will be crucial, particularly product stocks, because a rise in gasoline and distillates would reinforce the supply glut narrative. The base case is for crude to trade sideways until the Fed meeting provides a demand signal. The risk scenario centers on inventories expanding faster than expected, which could push WTI toward the upper 50s and pressure Brent toward the low 60s. The key takeaway for traders is that crude is sitting at an inflection point where policy expectations are strong enough to prevent a selloff but not strong enough to spark a sustained rally. Positioning should remain light until the Fed delivers clarity.

The Market Weighed Ongoing Talks to End the War in Ukraine - The oil market sold off on Monday following the news that Iraq restored output at one of its oilfields, while the market also weighed ongoing talks to end the war in Ukraine. The market traded mostly sideways in overnight trading, posting a high of $60.30, in light of the news that Iraq shut down production at Lukoil’s West Qurna 2 field due to a leak on an export pipeline. However, the market sold off and extended its losses to $1.40 as it posted a low of $58.68. The market was pressured by the news that Iraq restored production at the 460,000 bpd Iraqi oilfield. The crude market later settled in a sideways trading range ahead of the close. The January WTI contract settled down $1.20 at $58.88 and the February Brent contract settled down $1.26 at $62.49. The product markets ended the session in negative territory, with the heating oil market settling down 6.47 cents at $2.2982 and the RB market settling down 3.6 cents at $1.7981. Ukrainian President Volodymyr Zelenskiy said unity between Europe, Ukraine and the U.S. was important when negotiating an end to Russia’s war in Ukraine. Ukraine’s President said on Sunday ahead of his planned consultations with European leaders in coming days that talks with U.S. representatives on a peace plan for Ukraine have been constructive but not easy. He held a call on Saturday with U.S. President Donald Trump’s special envoy Steve Witkoff and Trump’s son-in-law Jared Kushner, and is expected to meet French, British and German leaders on Monday in London. Further talks are planned in Brussels. China’s crude oil imports in November increased 4.88% on the year, with daily import volumes reaching the highest level since August 2023. According to data from the General Administration of Customs, China imported 50.89 million metric tons or 12.38 million bpd of oil in November, up 5.24% on the month. China imported 521.87 million tons of crude oil from January to November, up 3.2% from the same period last year. Platts reported that India and Russia on Friday pledged to deepen their energy ties following Russian President Vladimir Putin’s two day meeting with Indian Prime Minister Narendra Modi, with Russia ensuring uninterrupted fuel supplies to India, while New Delhi emphasized that ensuring energy security has been a key component of India-Russia bilateral relations. Russia’s President said Russia will continue to develop long-term energy ties with India, despite political hurdles that have hit overall trade turnover in 2025. IIR Energy said U.S. oil refiners are expected to shut in about 54,000 bpd of capacity in the week ending December 12th, unchanged from the previous week. Offline capacity is expected to remain at 54,000 bpd in the week ending December 19th.

Oil falls 2% as Iraqi oilfield production restored, Ukraine talks continue (Reuters) - Oil prices slipped 2% on Monday after Iraq restored production at one of its oilfields which accounts for 0.5% of world oil supply, while investors weighed ongoing talks to end the war in Ukraine. Brent crude futures were down $1.26, or 1.98%, at $62.49 a barrel, while U.S. West Texas Intermediate crude was at $58.88, down $1.20, or 2%. Iraq restored production at Lukoil's West Qurna 2 oilfield, one of the world's largest, after a leak on an export pipeline slashed its output, two Iraqi energy officials told Reuters on Monday. Prices had marginally pared losses earlier after sources told Reuters that Iraq had shut down production at the field, which produces around 460,000 barrels per day. Both contracts closed Friday's trading session at their highest levels since November 18. "If there's any kind of agreement reached in the near future on Ukraine, then Russian oil exports should increase and put downward pressure on oil prices," Markets are meanwhile pricing in an 84% chance of a quarter-point cut at the Fed meeting on Tuesday and Wednesday, LSEG data showed. However, board member comments indicate the meeting is likely to be one of the most divisive in years, intensifying investor focus on the bank's policy direction and internal dynamics. Progress on Ukraine peace talks remains slow, with disputes over security guarantees for Kyiv and the status of Russian-occupied territory still unresolved even as U.S. President Donald Trump presses for a deal. Ukrainian President Volodymyr Zelenskiy was meeting European leaders in London on Monday. "The various potential outcomes from Trump's latest push to end the war could release a swing in oil supply of more than 2 million barrels per day," Any geopolitical risk premium will be weighed against signs of a growing global surplus, with rising OPEC+ and non-OPEC supply outpacing modest demand growth, Vivek Dhar said a ceasefire is the main downside risk to the outlook for oil prices, while sustained damage to Russia's oil infrastructure is a significant upside risk. In the meantime, Group of Seven countries and the European Union are in talks to replace a price cap on Russian oil exports with a full maritime services ban, people familiar with the matter told Reuters. That would likely further curb supply from the world's second-largest oil producer. The U.S. has also ramped up pressure on OPEC member Venezuela, including strikes against boats it said were attempting to smuggle illegal drugs, and talk of military action to overthrow President Nicolas Maduro. Elsewhere, Chinese independent refiners have stepped up purchases of sanctioned Iranian oil from onshore storage tanks using newly issued import quotas, trade sources and analysts said, easing a supply glut.

Crude oil prices decline as Ukraine and Western allies discuss US-brokered peace plan -- Crude oil futures traded lower on Tuesday morning as traders focussed on developments related to proposed peace talks between Russia and Ukraine to end the war. At 9.57 am on Tuesday, February Brent oil futures were at $62.38, down by 0.18 per cent, and January crude oil futures on WTI (West Texas Intermediate) were at $58.74, down by 0.24 per cent. December crude oil futures were trading at ₹5305 on Multi Commodity Exchange (MCX) during the initial hour of trading on Tuesday against the previous close of ₹5334, down by 0.54 per cent, and January futures were trading at ₹5310 against the previous close of ₹5330, down by 0.38 per cent. On Monday, Ukrainian President Volodymyr Zelenskiy met British Prime Minister Keir Starmer, French President Emmanuel Macron, German Chancellor Friedrich Merz in London to discuss the US-proposed peace plan with Russia. Zelenskiy told reporters after the meeting that the revised plan included 20 points. However, there was no agreement on the issue of giving up territory that Russia has pushed for. In their recent analysis, Warren Patterson, Head of Commodities Strategy of ING Think, and Ewa Manthey, Commodities Strategist of ING Think, said the developments related to Russia-Ukraine peace talks will be important to watch in 2026, with any progress towards ending the war likely to put further pressure on energy markets. “For 2026, we remain bearish towards energy markets, with the global oil market set to be in large surplus, following OPEC+ rapidly ramping up output as it shifts policy, while demand growth remains modest. There is plenty of uncertainty about Russian oil supply following US sanctions, but as we move through 2026, markets will get a clearer picture of the full impact. For now, we believe the impact will be limited in the medium to long term. However, there is potential for greater volatility, given that OPEC’s spare production capacity has shrunk as the group has increased output,” they said. Meanwhile, Iraq’s plan to restore production at Lukoil’s West Qurna 2 oilfield also put pressure on oil prices. Quoting two unnamed Iraqi energy officials, a Reuters report said Iraq restored production at West Qurna 2 oilfield, one of the world’s largest, after a leak on an export pipeline slashed its output. With output of around 460,000 barrels a day, this oil field accounts for about 0.5 per cent of world oil supply and 9 per cent of total output in Iraq, the Reuters report said. December natural gas futures were trading at ₹438 on MCX during the initial hour of trading on Tuesday against the previous close of ₹448.90, down by 2.43 per cent. On the National Commodities and Derivatives Exchange (NCDEX), December jeera contracts were trading at ₹20870 in the initial hour of trading on Tuesday against the previous close of ₹20810, up by 0.29 per cent. December dhaniya futures were trading at ₹10480 on NCDEX in the initial hour of trading on Tuesday against the previous close of ₹10638, down by 1.49 per cent.

Oil Prices Ease on Russia Watch, Ahead of Fed Rate Decision -- Oil futures remained soft on Tuesday, Dec. 9, as the Kremlin reacted favorably to a new U.S. national security strategy that called for better relations with Russia, which faces both U.S. and European sanctions on its energy exports. The start of a two-day Federal Reserve meeting that could end Wednesday, Dec. 10, with the year's third straight interest rate cut of 25 basis points, however, limited the downside in energy prices, which are typically sensitive to any economic boosting measures. The NYMEX WTI futures contract for January delivery was down by $0.07 to $58.81 bbl. ICE Brent for February shipments slipped by $0.11 to $62.38 bbl. The front-month RBOB futures contract slid by $0.0004 to $1.7977 gallon. NYMEX front-month ULSD futures slipped by $0.0203 to $2.2769 gallon. The U.S. Dollar Index was little changed at 99.12 against a basket of foreign currencies. A new U.S. national security strategy document released Friday, Dec. 5, that spoke of Washington's desire to improve its relationship with Russia was welcomed by the Kremlin. The Trump administration also said in the document that ending the war in Ukraine -- which is key to the removal of sanctions on Russian oil -- is a core U.S. interest to "reestablish strategic stability with Russia." "The nuances that we see in the new concept certainly look appealing to us," Kremlin spokesman Dmitry Peskov said, referring to the new U.S. strategy, the Associated Press reported. Without sanctions, Russian oil could resume its free flow to global markets, adding to a crude glut. OPEC, or the Organization of the Petroleum Exporting Countries, had already cautioned that the crude market was in a surplus of 500,000 bpd as of the third quarter.

The Market Extended its Losses Amid Peace Talks and U.S. Interest Rates - The crude market continued to trend lower on Tuesday, extending its previous losses, as the markets focused on peace talks to end Russia’s war in Ukraine and a decision on U.S. interest rates on Wednesday afternoon. The market, which was pressured on Monday after Iraq restored output at Lukoil’s West Qurna 2 oilfield, remained pressured as Ukraine planned to share a revised peace plan with the U.S. on Tuesday following talks in London on Monday between Ukraine’s President Volodymyr Zelenskiy and the leaders of France, Germany and Britain. The market traded sideways in overnight trading, posting a high of $59.17 in early morning trading. However, the market retraced more than 62% of its move from a low of $57.10 to a high of $60.50 as it sold off to a low of $58.12 by mid-day. The market settled in a sideways trading range during the remainder of the session. The January WTI contract settled down 63 cents at $58.25 and the February Brent contract settled down 55 cents at $61.94. The product markets ended the session lower, with the heating oil market settling down 3.81 cents at $2.2601 and the RB market settling down 84 points at $1.7897. In its Short Term Energy Outlook, the U.S. EIA raised its 2025 oil production forecast, but lowered its expectations for 2026 production levels. It reported that oil production will average 13.61 million bpd in 2025, the highest level on record. Next year, total output will decline 80,000 bpd to 13.53 million bpd. The EIA raised its forecast for 2026 U.S. oil demand by 100,000 bpd and expects demand to be flat year on year at 20.6 million bpd. The EIA said the price of WTI will average $65.32/barrel in 2025, up from its estimate last month of $65.15/barrel. Brent crude prices will average $68.91/barrel in 2025, up from a previous forecast of $68.76/barrel. Ukraine will share a revised peace plan with the U.S. on Tuesday that is aimed at ending Russia’s war, following talks in London between Ukraine’s President Volodymyr Zelenskiy and the leaders of France, Germany and Britain. He said that the revised plan comprised 20 points, but that there was still no agreement on the issue of giving up territory. Ukraine’s President Volodymyr Zelenskiy said that Ukraine was ready for an energy ceasefire if Russia agrees, and that it would do whatever it can to organize a high-level meeting with the U.S. within the next two weeks on a peace deal. Platts reported that Russia’s oil exports to India and China are under threat from tougher Western sanctions, forcing refiners to seek alternative supplies while discounted Russian crude continues to make its way to market through non-sanctioned entities. The U.S. Treasury sanctioned Russia’s Lukoil and Rosneft in October, forcing markets to rebalance as buyers face secondary restriction risks. Despite a decline in Russian crude flows to the region, most exports have shifted toward non-sanctioned entities to offset sharp declines from Rosneft and Lukoil since November. Platts stated that sanctions targeting Lukoil and Rosneft have disrupted traditional supply chains, though pipeline flows are expected to be unaffected. Shell said output at two of its offshore platforms in the U.S. Gulf of Mexico has been temporarily shut due to a shutdown of the Hoover Offshore Oil Pipeline System. Shell said it expects its Whale and Perdido platforms to resume production by the end of the day.

Oil Prices Perk Up As Report Shows US Crude Inventories Fall Further - The American Petroleum Institute (API) estimated that crude oil inventories in the United States saw a large draw of 4.8 million barrels in the week ending December 5. Crude oil inventories shrank by 2.48 million barrels in the week prior.Crude oil inventories in the United States are so far showing a net increase of just 121,000 barrels for the year, according to Oilprice calculations of API data. Earlier this week, the Department of Energy (DoE) reported that crude oil inventories in the Strategic Petroleum Reserve (SPR) have risen by 200,000 barrels to 411.9 million barrels in the week ending December 5 as the Trump Administration slowly works to replenish depleted stockpiles. US production stayed relatively flat during the week of November 28, rebounding just slightly from 13.814 million bpd in the week prior, to 13.815 million bpd in the current, according to the latest EIA data. This is 252,000 bpd more than the beginning of the year levels.At 3:11 pm ET, Brent crude was trading down by $0.43 (-0.69%) on the day, slipping to $62.06 per barrel—a $0.40 decline week over week. WTI was also trading down on the day, by $0.48 (-0.82%) at $58.40—a $0.20 per barrel loss week over week.Gasoline inventories saw a sizeable increase of 7 million barrels in the week ending December 5. In the week prior, gasoline inventories grew by 3.14 million barrels. As of last week, gasoline inventories were 2% below the five-year average for this time of year, according to the latest EIA data.Distillate inventories also rose in the reporting period, gaining 1 million barrels, compared to the week prior’s 2.88-million-barrel build. Distillate inventories were 7% below the five-year average as of the week ending November 28, the latest EIA data shows. Cushing inventory—the inventory kept at the delivery hub for the WTI Crude futures contract—dipped by 890,000 barrels, after falling by 89,000 barrels in the prior week.

Oil Finds a Floor as Refining Margins Flash Stress Signals - Oil steadied in early Asian trading as a modest technical recovery lifted prices after two consecutive sessions of losses. Front-month WTI rose 0.2 percent to 58.35 dollars a barrel and Brent gained 0.2 percent to 62.05 dollars. The rebound came as traders reassessed the sharp drop in refining margins that had accelerated the recent sell-off. The pressure across refined products has been the dominant force shaping sentiment. Crack spreads, which reflect the profitability of turning crude into gasoline, fell to their lowest level since February. That collapse signals soft demand for finished fuels relative to crude and helped trigger broad selling across the oil complex earlier in the week. The recovery in futures is therefore less a shift in fundamentals than a stabilizing move after momentum-driven losses. Weak margins typically indicate that refiners will process less crude, which can depress near-term demand unless supply cuts or outages counterbalance the decline. Market behavior has been consistent with that narrative. WTI’s drop toward the upper-50s has eased inflation expectations at the margin and reduced pressure on oil-linked currencies such as the Mexican peso and Canadian dollar, both of which tend to react to shifts in energy demand. Brent holding near the low-60s shows that global supply concerns have not fully disappeared, but refiners’ margins are dictating short-term pricing more than geopolitics. Energy equities remain sensitive to this dynamic because narrow product spreads translate into weaker downstream earnings even when crude stabilizes. The next catalysts will come from U.S. inventory data, any fresh communication from OPEC members about supply discipline, and updated economic indicators from major consuming regions. If crack spreads recover and inventories draw, crude could drift back toward the mid-60s for Brent and low-60s for WTI. If margins deteriorate further or if refinery utilization slips, the downside risk grows and prices could retest recent lows. For investors, the key is to distinguish between transitory technical selling and genuine demand weakness. The current bounce does not resolve the underlying margin stress, so positioning should remain flexible until refining indicators begin to turn.

WTI Holds Losses After Big Product Inventory Builds, US Crude Production Nears Record Highs - Oil prices extended their recent decline this morning as concerns about global oversupply continued to weigh on sentiment. Crude has been trapped in a tight $4-a-barrel range since the start of November, as oversupply concerns vie with geopolitical risks surrounding the flow of sanctioned Russian barrels into nations including India. “I’m increasingly becoming a bit of a contrarian here, given the limited selling response to all the negative news," said Ole Hansen, head of commodities strategy at Saxo Bank AS. "The biggest risk to prices could be to the upside if next year’s oversupply is already priced in," he added. Overnight saw API report a large crude draw but sizable product builds...

• Crude -4.78mm (-1.7mm exp)
• Cushing
• Gasoline +3.14mm
• Distillates +2.88mm

DOE:

• Crude -1.812mm
• Cushing +308k
• Gasoline +6.397mm - biggest build since Dec 2024
• Distillates +2.5mm

US crude stocks fell last week but products saw notable builds (4th straight week) as Cushing inventories hover near 'tank bottoms'... Graphs Source: Bloomberg. US Crude production picked up again to a new record high as rig counts remain near cycle lows... Oil prices have stuck within a tight range in recent weeks as rising geopolitical risks amid Ukrainian attacks on Russian oil infrastructure and shipping counter rising global inventories of the fuel. In its monthly Short-Term Energy Outlook released Tuesday, the EIA warned rising global production has outpaced demand and it expects inventories to continue rising by two-million barrels per day in 2026, pressuring prices.

The U.S. Seized an Oil Tanker Off the Coast of Venezuela - - The oil market traded higher ahead of the close on Wednesday after officials said the U.S. seized an oil tanker off the coast of Venezuela. The market, which traded to $58.67 early in the morning before it erased some of those gains and sold off to a low of $57.66 in light of a 1.8 million barrel draw in crude stocks in the week ending December 5th. The crude market later bounced off its low and settled in a sideways trading range as the market awaited a decision by the Federal Reserve on U.S. interest rates. The market later traded mostly sideways in light of the expected 25 basis point interest rate cut. The January WTI contract settled up 21 cents at $58.46. The market was further supported in the post settlement period and rallied to a high of $59.05 in light of the news of the oil tanker seizure off the coast of Venezuela by the U.S. The February Brent contract settled up 27 cents at $62.21. The product markets ended the session in mixed territory, with the heating oil market settling up 1.29 cents at $2.2730 and the RB market settling down 82 points at $1.7815. Three officials said the U.S. seized an oil tanker off the coast of Venezuela on Wednesday. The officials, speaking on the condition of anonymity, said the operation was led by the U.S. Coast Guard. They did not name the tanker, which country’s flag it was flying or exactly where the interdiction took place. Bloomberg is reporting with that with spot Russian crude oil being offered at deep discounts into the Indian market, at least four of the seven largest oil refiners in the country appear to be active in acquiring Russian barrels recently. Prices for these barrels reportedly are being traded between $40 and $45 per barrel. The largest buyer of Russian crude oil until recently, Reliance Industries Ltd though has been reluctant to be active in the spot market for Russian barrels over concerns of running afoul of current U.S. or European sanctions. In fact Reliance reportedly has even reduced its current imports of Russian crude oil under its 500,000 b/d term contract with Rosneft PJSC. Ship tracking service Kpler is estimating that Indian imports of Russian crude oil in December could average 1.0-1.2 million b/d, down from the over 2 million b/d imported back in June. British Prime Minister Keir Starmer’s office said leaders of Britain, France and Germany discussed with U.S. President Donald Trump ongoing U.S.-led peace talks for Ukraine, welcoming efforts to secure a just and lasting settlement. The leaders agreed this was a critical moment for Ukraine and said intensive work on the peace plan would continue in the coming days. Two European Union diplomats said European leaders including French President Emmanuel Macron and British Prime Minister Keir Starmer are set to convene in Berlin on Monday to discuss the situation in Ukraine. The diplomats said at least a dozen leaders, all allies of Ukraine, are expected. IIR Energy said U.S. oil refiners are expected to shut in about 241,000 bpd of capacity in the week ending December 12th, cutting available refining capacity by 27,000 bpd. Offline capacity is expected to fall to 186,000 in the week ending December 19th.

US-Venezuela Tensions Reignite a Geopolitical Premium in Oil Markets - Oil prices are firmer in early Asian trading as geopolitical tensions between Washington and Caracas overshadow the broader demand narrative. The U.S. seizure of a tanker near Venezuelan waters has lifted front-month WTI to about 58.81 dollars a barrel and pushed Brent to roughly 62.51 dollars, reflecting a market that is quick to price geopolitical risk when physical flows appear vulnerable.The move matters because Venezuela remains a marginal but symbolically important supplier in an already fragile supply environment, especially as U.S. sanctions enforcement shifts again. China has become the primary buyer of Venezuelan crude in recent years, so any additional U.S. actions near Venezuelan ports raise questions about freight risk, route diversification, and the reliability of supply channels into Asia.At the same time, sentiment is being supported by an unexpected draw in US crude inventories according to EIA figures, which reinforces the idea that the physical market may be tighter than recent macro concerns suggest. This mix of geopolitical disruption and domestic supply contraction creates a pricing environment where traders are more sensitive to risk premiums and less responsive to cyclical demand worries.The immediate market impact is concentrated in crude benchmarks and energy-linked assets. WTI’s move toward the high 58-dollar range and Brent’s lift into the mid-62-dollar area show that traders are willing to add a modest geopolitical premium after the tanker seizure. The energy equity complex is likely to reflect the same pattern, with producers benefiting from firmer spot prices while refiners remain cautious because freight disruptions can complicate crude sourcing.Inflation expectations could also edge higher if crude sustains these levels since U.S. gasoline and diesel markets remain sensitive to any supply constraint as winter demand picks up. FX markets may show mild support for commodity-linked currencies, but the scale of the move in oil remains too modest to produce a broad shift in currency flows.Investors will now watch for further US statements on enforcement around Venezuelan ports, potential diplomatic responses from Caracas and Beijing, and the next EIA inventory release. Evidence of additional tanker delays or further draws in U.S. stockpiles would reinforce the current upward bias in crude.The alternative scenario is a rapid de-escalation, which would strip out the geopolitical premium and return pricing to a more fundamental range driven by global demand and refinery margins. In the near term, the base case is for crude to trade with a modest upward tilt as long as physical flows around Venezuela remain under scrutiny and inventories stay on a tightening path. For investors, the takeaway is straightforward. The market is reintroducing a small but meaningful geopolitical risk premium, and short-term positioning should account for higher volatility around supply headlines. Maintaining discipline around position size is prudent until clarity emerges on U.S. enforcement actions and the direction of U.S. inventories.

Crude Dips as Geopolitical Tensions Shift From Venezuela Seizure to Ukraine Peace Efforts - The crude oil market on Thursday traded lower after the market saw no immediate fallout from the U.S. seizure of a sanctioned oil tanker off the coast of Venezuela. The market shifted its focus back on the Russia-Ukraine peace talks after Russia’s Foreign Minister said the visit to Moscow by U.S. envoys Steve Witkoff and Jared Kushner had resolved misunderstanding between the two countries, while the leaders of Britain, France and Germany held a call with President Trump to discuss Washington’s latest peace efforts to end the war in Ukraine. The oil market posted a high of $58.94 on the opening and erased its previous gains as it sold off to a low of $57.01 by mid-day. The market later retraced some of its losses on news of the U.S. issuing new Venezuela related sanctions, including adding six crude oil tankers to its sanctions list. The January WTI contract settled down 86 cents at $57.60 and the Brent contract settled down 93 cents at $61.28. The product markets ended the session in negative territory, with the heating oil market settling down 4.41 cents at $2.2289 and the RB market setting down 2.17 cents at $1.7598. Axios reported that the U.S. imposed new sanctions on Thursday on three nephews of Venezuelan President Nicolas Maduro and six companies shipping the country’s oil. On Wednesday, U.S. President Donald Trump said the U.S. has seized a sanctioned oil tanker off the coast of Venezuela. In response, the Venezuelan government in a statement accused the U.S. of “blatant theft” and described the seizure as “an act of international piracy”. It said it would denounce the incident before international bodies. The seizure is the first of a Venezuelan oil cargo amid U.S. sanctions that have been in force since 2019. It is also the Trump administration’s first known action against a Venezuela-related tanker since President Trump ordered a massive military buildup in the region. The U.S. has already carried out several strikes against suspected drug vessels, which has raised concerns among lawmakers and legal experts. British maritime risk management group Vanguard said the very large crude carrier, Skipper, was believed to have been seized off Venezuela early on Wednesday. The U.S. has imposed sanctions on the tanker for what it says was involvement in Iranian oil trading when the vessel was called the Adisa. The Skipper left Venezuela’s main oil port of Jose between December 4th and 5th after loading some 1.8 million barrels of Venezuela’s Merey heavy crude. According to satellite information analyzed by TankerTrackers.com and internal data from PDVSA, the tanker transferred about 200,000 barrels near Curacao to the Panama-flagged Neptune 6 bound for Cuba before the seizure. On Thursday, White House spokeswoman Karoline Leavitt said the U.S.-seized oil vessel linked to Venezuela is expected to sail to a U.S. port, where the government intends to seize its cargo of oil through a formal legal process. Separately, sources stated that the U.S. is preparing to intercept more ships transporting Venezuelan oil following the seizure of a tanker this week. Further direct interventions by the U.S. are expected in the coming weeks targeting ships carrying Venezuelan oil that may also have transported oil from other countries targeted by U.S. sanctions, such as Iran. The sources stated that the U.S. has assembled a target list of several more sanctioned tankers for possible seizure. The White House said U.S. President Donald Trump will send a representative to talks in Europe on Ukraine this weekend if there is a real chance of signing a peace agreement.

Oil retreats as investors' focus on Ukraine, US fuel supplies (Reuters) - Oil prices fell on Thursday as investors focused on Russia-Ukraine peace talks and eyed large surpluses in U.S. gasoline and diesel inventories. Brent crude futures settled at $61.28 a barrel, down 93 cents or 1.49%. U.S. West Texas Intermediate crude finished at $57.60 a barrel, down 86 cents or 1.47%. For most of the session, Brent and WTI were down more than $1 and nearly 2%, falling past lows last seen in October. "The market has been weighed under by significant surpluses in gasoline and diesel inventories,". "You're seeing that play out in poor refining margins." The U.S. Energy Information Administration reported on Wednesday that gasoline inventories rose by 2.5 million barrels in the previous week and distillate stockpiles grew by a similar amount. The prospect of a possible peace agreement between Russia and Ukraine also appeared to be driving the market lower. Such a deal would likely increase the supply of Russian oil that is currently off the market for most of the world. "There was a little bit of support following news of the drone strikes,". "But there seems to be some movement on a possible path to peace between Russia and Ukraine. That took the support out of the market." Ukrainian drones struck an oil rig belonging to Russia in the Caspian Sea for the first time, halting the facility's extraction of oil and gas, a source at the Security Service of Ukraine told Reuters on Thursday. The leaders of Britain, France and Germany held a call on Wednesday with U.S. President Donald Trump to discuss Washington's latest peace efforts to end the war in Ukraine, in what they said was a "critical moment" in the process. Russian Foreign Minister Sergei Lavrov said on Thursday that a visit to Moscow this month by U.S. envoy Steve Witkoff had resolved misunderstandings between the two countries. Lavrov added that Moscow had handed over Russia's proposals on collective security guarantees for Ukraine to Washington. Both benchmarks had settled higher a day earlier after the U.S. said it seized an oil tanker off the coast of Venezuela, as escalating tensions between the two countries raised concerns about supply disruptions. "So far, the seizure has not trickled down to the market, but further escalation will impose heavy crude price volatility," The seizure was announced by Trump, whose administration did not name the vessel. British maritime risk management group Vanguard said the tanker, named Skipper, was believed to have been seized off the coast of Venezuela. Traders and industry sources said Asian buyers were demanding steep discounts on Venezuelan crude, pressured by a surge of sanctioned oil from Russia and Iran and heightened loading risks in the South American country as the U.S. boosts its military presence in the Caribbean. The International Energy Agency upgraded its 2026 global oil demand growth forecasts while trimming its supply growth predictions in its latest monthly oil market report on Thursday, implying a slightly narrower surplus next year. The Organization of the Petroleum Exporting Countries, which also released its monthly report on Thursday, kept its forecasts for 2025 and 2026 world oil demand growth unchanged.

Oil Prices Rise Amid Venezuela Supply Concerns and Ukraine Russia Peace Talks | Ukraine news - Prices for oil rose on Friday, December 12, amid growing concerns about possible disruptions to supply from Venezuela. At the same time, the market remains on track for a weekly decline due to cautious investor sentiment and hopes for peaceful talks between Ukraine and Russia. Brent crude futures rose to $61.71 per barrel, up 0.70%, while WTI climbed to $58.03 per barrel, up 0.75%. Compared with the previous day, both benchmarks fell by about 1.5% on Thursday, leaving the market under pressure from overall uncertainty. The rise is linked to reports of possible supply disruptions from Venezuela after the United States intensified pressure on Maduro’s government. Expectations of stronger measures include possible interception of additional vessels carrying Venezuelan oil. “Peace talks between Ukraine and Russia will remain the main focus next week” Over the week, both key contracts fell by more than 3%, signaling overall market uncertainty and the impact of external factors. ANZ Research analysts explain the real concerns among investors, driven by sluggish demand prospects and the general instability in the oil sector. A lower expected Federal Reserve rate and remarks by Federal Reserve Chair Jerome Powell, which are considered less hawkish, heightened uncertainty in financial markets about future US monetary policy. According to the International Energy Agency, world oil supply is set to exceed demand by 3.84 million barrels per day, somewhat lower than the previous November estimate of 4.09 million b/d. As previously reported, the removal of a US-sanctioned tanker off the Venezuelan coast weighed on global financial markets and dampened investors’ risk appetite.

Oil inches lower on oversupply concerns, on track for weekly loss - Oil prices inched lower on Friday and were on track for a weekly decline as investors focussed on a supply glut and potential Russia-Ukraine peace deal, which outweighed concerns over Venezuelan supply disruptions. Brent crude futures were down 14 cents, or 0.2%, to $61.14 a barrel at 1441 GMT. U.S. West Texas Intermediate crude was down 3 cents at $57.57. Both benchmarks fell by about 1.5% on Thursday. While there might be sporadic support from hits to supply, the general market mood reflects supply exceeding demand, and any rallies are expected to be brief, said PVM Oil Associates analyst Tamas Varga. Brent and WTI have lost more than 4% this week. International Energy Agency forecasts published on Thursday indicated that global oil supply will exceed demand by 3.84 million barrels per day next year - a volume equal to almost 4% of world demand. Data in OPEC’s report, also issued on Thursday, indicated that world oil supply will match demand closely in 2026, in contrast to the IEA’s view. Some price-supportive factors remain, including the ramping up of tensions between the U.S. and Venezuela and Ukrainian drone strikes on a Russian oil rig in the Caspian Sea, said Janiv Shah, analyst at Rystad Energy. The U.S. is preparing to intercept more ships transporting Venezuelan oil after the seizure of a tanker this week, six sources close to the matter said on Thursday.

Oil posts weekly loss on oversupply concerns (Reuters) - Oil prices closed lower on Friday, marking a 4% weekly decline as a supply glut and a potential Russia-Ukraine peace deal outweighed worries about any impact from the U.S. seizure of an oil tanker near Venezuela. Brent crude futures settled 16 cents down at $61.12 a barrel, while U.S. West Texas Intermediate crude was down 16 cents at $57.44. Both benchmarks fell by about 1.5% on Thursday and have lost more than 4% this week. "The market continues to be weighed down by the crude oil supply situation... on the other hand, the oil market is ignoring the tension between the U.S. and Venezuela," said Andrew Lipow, president of Lipow Oil Associates. The U.S. seized a sanctioned oil tanker off the coast of Venezuela, President Donald Trump said on Wednesday. The U.S. is preparing to intercept more ships transporting Venezuelan oil after the seizure of a tanker this week, six sources close to the matter said on Thursday. Traders and analysts largely shrugged off worries about the impact of the tanker seizure, pointing to ample supply in the markets. International Energy Agency forecasts published on Thursday indicated that global oil supply will exceed demand by 3.84 million barrels per day next year - a volume equal to almost 4% of world demand. Data in OPEC's report, also issued on Thursday, indicated that world oil supply will match demand closely in 2026, in contrast to the IEA's view. Some price-supportive factors remain, including the ramping up of tensions between the U.S. and Venezuela, and Ukrainian drone strikes on a Russian oil rig in the Caspian Sea, said Janiv Shah, analyst at Rystad Energy. Russia's seaborne oil product exports in November fell by just 0.8% from October, with the completion of refinery maintenance helping to offset a slump in fuel exports from southern routes such as the Black Sea and Azov Sea, data from industry sources and Reuters calculations showed.

Explosion at Critical Nigerian Gas Pipeline Disrupts Operations - An explosion occurred earlier this week at a key onshore natural gas pipeline in Nigeria, disrupting operations at the link shipping gas to industrial users and power plants, Nigeria’s state oil company NNPC confirmed late on Thursday. The explosion occurred on the evening of December 10 on the Escravos–Lagos pipeline near the Tebijor, Okpele, and Ikpopo communities in the Delta State. Initial observations indicate a pressure drop consistent with a loss of containment at the gas pipeline, NNPC said in a statement. “The cause of the explosion is still unknown but would be confirmed after a detailed investigation has been concluded. Our priority at this time is the safety of nearby communities and the protection of the environment,” the state company said, adding that it has activated emergency response procedures and teams. The Escravos–Lagos gas pipeline is a major conduit of gas to industrial users and power plants in southwestern Nigeria. The incident of still unknown cause took place days after NNPC and local producer Heirs Energies signed a deal to capture and use the gas flared at their onshore OML 17 joint venture near Port Harcourt in a bid to monetize the resource and reduce flaring. Under the deal, the companies will capture the gas flared across OML 17 and deploy it for use in power generation, industrial applications, liquefied petroleum gas (LPG), and compressed natural gas (CNG). The move is aligned with Nigeria’s gas development priorities and energy transition goals. Gas flaring has been a major issue at Nigeria’s oilfields—it is wasted instead of used for many industrial purposes, and holds back the country’s targets to reduce emissions. Nigeria saw flaring volumes jump by 12% in 2024, which was the second largest increase globally behind Iran, the World Bank said in a report earlier this year.

Watch: Third Russian Oil Tanker Hit By Sea Drone In Black Sea -- Ukraine has carried out another drone attack on a Russia-linked so-called 'shadow fleet' tanker in the Black Sea on Wednesday, which marks a third such attack in less than two weeks, and which seeks to disrupt Moscow's maritime oil trade.Local reports have identified the Comoros Islands-flagged Dashan as being struck while sailing en route to the Russian port terminal of Novorossiysk. The Ukrainians were quick to release drone-perspective video confirming the attack, and the vessel appeared to be unladen at the time. The some $30 million tanker "sustained critical damage and was completely put out of action - powerful explosions can be clearly seen in video footage shown by the sources," according to Ukrainian media.Ukraine's SBU security service says its Sea Baby naval drones today struck another Russian “shadow fleet” tanker in the Black Sea. Video from an SBU source purports to show the oil tanker "Dashan" being hit by the attack drone and explosions in the stern area. "The vessel,… pic.twitter.com/mtfBqYe1gQThe Dashan was under US-led sanctions, as well as sanctions by the European Union, the United Kingdom, Canada, Australia, and Switzerland.When the tanker Kairo was hit late last month it was towed to Bulgaria, but it was also deemed a complete loss.Reuters has recently noted that "War insurance costs for ships sailing to the Black Sea have spiked again, with insurers reviewing policies daily as the conflict in Ukraine spills into sea lanes, five shipping and insurance sources said on Thursday."Moscow is outraged at recent attacks on tankers transporting Russian oil. Also on Wednesday, a cargo vessel carrying grain from Crimea was detained by Ukrainian authorities at Odessa port:Ukrainian security officials have detained a cargo vessel in the port of Odesa that authorities say is part of Russia’s so-called "shadow fleet," the Security Service of Ukraine (SBU) said Wednesday.The ship, whose name was not disclosed, arrived under the flag of an African country to load a shipment of steel pipes. The captain and 16 crew members holding passports from unspecified Middle Eastern countries were on board at the time of the seizure.According to the SBU, the vessel illegally transported nearly 7,000 tons of Russian grain from annexed Crimea to North Africa in January 2021. The SBU claims it found evidence of "illegal operations in ports on temporarily occupied Ukrainian territory" after a search of the ship.

Zelensky Rules Out Ceding Territory for Peace Deal - Ukrainian President Volodymyr Zelensky on Monday ruled out the idea of ceding any territory to Russia, a key term of a US-drafted peace proposal to end the war.“Russia is insisting that we give up territories, but we don’t want to cede anything,” Zelensky told reporters after meeting with the leaders of the UK, France, and Germany in London, according toCBS News. “We have no legal right to do so, under Ukrainian law, our constitution, and international law. And we don’t have any moral right either,” Zelensky added. The initial US-drafted peace proposal that was leaked to the media called for Ukraine to cede the remaining territory it controls in the Donbas region, where Russian forces continue to make gains. President Trump has previously said that it’s better to give up the area now than lose tens of thousands of troops attempting to defend it. “Eventually, that’s land that, over the next couple of months, might be gotten by Russia anyway,” Trump said late last month. “So do you want to fight and lose another 50,000-60,000 people? Or do you want to do something now?”Russia has made clear that it’s willing to continue the war if Ukraine doesn’t agree to its territorial demands. The other major sticking point in the negotiations is the idea of security guarantees, as Ukraine wants a NATO-style guarantee from the US, something Russia won’t go for.“There is one question I — and all Ukrainians — want to get an answer to: if Russia again starts a war, what will our partners do?” Zelensky said on Monday before the meeting with British Prime Minister Keir Starmer, French President Emmanuel Macron, and German Chancellor Friedrich Merz.Starmer and Macron have been pushing for a NATO troop deployment to a post-war Ukraine, an idea that Moscow has repeatedly rejected. European leaders have also backed Zelensky’s other positions and released a counter-proposal that removed the territorial concessions and commitments that would prevent Ukraine from joining NATO.

Ukraine open to demilitarized zone on frontline in lieu of ceding land - Ukraine included the establishment of a demilitarized zone in the Donbas region as part of its latest proposal to end its war with Russia, an apparent alternative to territorial concessions being demanded by Moscow, according to Ukrainian President Volodymyr Zelensky. Zelensky said Thursday that Ukraine presented the U.S. with a revised peace plan after the Trump administration proposed creating a “free economic zone” in parts of eastern Donbas. The U.S. wants a “full understanding” of the plan by Christmas, Zelensky said. The Ukrainian leader told reporters that questions of territory remain unresolved because the Russians “want the whole of the Donbas, but we, of course, do not accept this.” He added: “Our position is that it is fair to stand where we stand — that is, on the contact line. Therefore, there is a discussion between these different positions, and it has not yet been decided.” As a compromise, Zelensky said U.S. negotiators discussed creating a demilitarized “free economic zone” in the parts of the Donbas from which Ukrainian and Russian troops would withdraw. The U.S. has been pressuring Ukraine to cede land in exchange for peace with Russia, which has been fighting in the Donbas region since 2014 and fully invaded Ukraine in February 2022. President Trump has turned up the heat on Zelensky in recent days, pushing him to agree to a U.S.-authored peace plan. An initial version of the plan heavily favored the Kremlin’s demands, but a revised version — hammered out in talks between American and Ukrainian negotiators — was rejected by Russian President Vladimir Putin in talks last week.

Russia Rejects New Zelensky Offer Of 'Energy Ceasefire' As Grid Repair Woes Worsen Russia has rejected a new Zelensky proposal for an "energy ceasefire." Kremlin spokesman Dmitry Peskov has explained that Russia wants a "long-term peace" and not a just a temporary ceasefire. Zelensky has offered a mutual halt to strikes on energy infrastructure if Russia agreed, mirroring something which had only briefly been in effect at the start of this year. This 'offer' comes at a moment that Ukraine is suffering perhaps its worst energy crisis of the war, with lengthy blackouts not just being experienced in the country's east and south - but long outages in and around the capital as well. Oleksandr Kharchenko, director of the Ukrainian Energy Research Center, has in recent comments confirmed that resources for repairing damaged energy facilities have almost run out. "Now I don't see the resources from either Ukrenergo, the generating or distribution companies to purchase the equipment they already need and will need in two or three months," he said in televised remarks."Ukraine may run out of equipment to restore its energy system if Russia continues to launch attacks," he has explained.The new proposal for a fresh energy ceasefire comes as Moscow is still livid at recent attacks on tankers transporting Russian oil. And now a cargo vessel carrying grain from Crimea has been detained at Odessa port: Ukrainian security officials have detained a cargo vessel in the port of Odessa that authorities say is part of Russia’s so-called “shadow fleet,” the Security Service of Ukraine (SBU) said Wednesday. The ship, whose name was not disclosed, arrived under the flag of an African country to load a shipment of steel pipes. The captain and 16 crew members holding passports from unspecified Middle Eastern countries were on board at the time of the seizure. According to the SBU, the vessel illegally transported nearly 7,000 tons of Russian grain from annexed Crimea to North Africa in January 2021.

Israeli Tanks Fire on UN Peacekeepers in Southern Lebanon - In yet another incident of UN peacekeepers in Lebanon finding themselves a target of the Israeli military, the UNIFIL reported yesterday that an Israeli Merkava tank fired on a UNIFIL patrol near the border village of Sarda. The patrol reported a burst of machine gun fire from the tank fired directly at them, and four other bursts of machine gun fire in the same vicinity. Firing on UNIFIL patrols, or even near them, is a violation of UN Security Council resolution 1701. The UNIFIL reported contacting the IDF through liaison channels and asked them to stop firing on them. No one was hurt in this incident, and the IDF has yet to comment on this attack, only the most recent of a long string of recent attacks.UNIFIL personnel come under fire from Israel on a fairly regular basis, and as with most cases, the UN had informed the IDF of this latest patrol when they were in the area, which was meant to avoid any confusion. Israeli officials have been condemning the UNIFIL for years, and just last week alleged that the peacekeepers were secretly aiding Hezbollah by taking photographs of the border area. They also complained the UNIFIL was a barrier to Israeli military operations against Lebanon, which indeed is one of the points of the peacekeepers in the first place. The UNIFIL, however, maintains their neutrality.

New Leader of Gaza's Biggest Israeli-Backed Militia Previously Fought for ISIS-Aligned Group - After the killing of Yasser Abu Shabab, the Israeli-backed gang leader who led the largest anti-Hamas militia in Gaza, his deputy, Ghassan al-Duhaini, has taken over as head of the group, officially known as the “Popular Forces.” According to Al Jazeera, al-Duhaini’s history includes working for the Palestinian Authority and later joining the Army of Islam, or Jaysh al-Islam (not to be confused with a Syrian group with the same name), a Gaza-based Salafi jihadist group with a similar ideology to al-Qaeda that declared its allegiance to ISIS in 2015. Israeli media has also reported on al-Duhaini’s jihadist past, with The Jerusalem Post saying he was once a “commander in a terrorist group in Gaza that was associated with al-Qaeda.” In 2011, the Egyptian government accused the Army of Islam of being responsible for a New Year’s Eve bombing of a Coptic Orthodox church in Alexandria, which killed 24 Christians. According toreports at the time, the group denied responsibility but also expressed support for the attack. Over the years, the Army of Islam has clashed with both Israel and Hamas, which it considers an “apostate” group. “The Jaysh al-Islam group believes that all who rule by man-made laws are apostate disbelievers,” a member of the Army of Islam said in a 2019 interview when asked about Hamas. “The Hamas government has arrested a number of members of Jaysh al-Islam, and that deed has been repeated.” It’s unclear when exactly al-Duhaini joined the Army of Islam or what he did for the group. Other members of the Popular Forces have ties to ISIS, including Issam Nabahin, who was previously identified by Hamas and Egyptian intelligence as an ISIS militant. Israeli media reported that Nabahin had fought for ISIS against the Egyptian army in Sinai. Abu Shabab himself was also accused of maintaining arms smuggling ties with ISIS-Sinai, and was previously imprisoned for drug trafficking. He broke out of jail following Hamas’s October 7, 2023, attack on Israel amid Israel’s bombing campaign in Gaza, and formed a gang that was later armed by Israel and became the Popular Forces, which is based in Israeli-occupied southern Gaza. Last year, an internal UN memo identified Abu Shabab’s gang as “the main and most influential stakeholder behind systematic and massive looting” of aid trucks in southern Gaza. Abu Shabab once admitted to looting aid trucks in an interview with The Washington Post, saying that he “takes from the trucks” but claimed he didn’t touch “food, tents, or supplies for children.” Abu Shabab’s death, which, according to Israeli media, was the result of an internal dispute, was seen as a blow to Israel’s efforts to use the group against Hamas, but al-Duhaini made clear in an interview with Israeli media that he’s ready to carry on the mission. “Why would I be afraid of Hamas when I am fighting Hamas?” he told Israel’s N12 News on Friday. “I fight them, arrest their people, confiscate their equipment, fight them, and push them away. I do what they deserve in the name of the people and the free individuals.”

Hamas Official Says Group Willing To Discuss 'Freezing or Storing' Its Weapons - -- Bassem Naim, a member of Hamas’s political bureau who is based outside of Gaza, told The Associated Press on Sunday that Hamas is willing to discuss the idea of “freezing or storing” its weapons to advance the US’s Gaza plan.The 20-point US plan calls for the “demilitarization” of Gaza, and Israel has been demanding Hamas’s disarmament, but so far, Israel and Hamas have just signed a much narrower deal to enact a ceasefire, which Israel continues to violate, and the details of a long-term agreement still need to be worked out.Naim reaffirmed Hamas’s position that it’s willing to disarm as part of a process that leads to a Palestinian state, something the Israeli government strongly opposes. But Naim added that Hamas was “very open-minded” about what it could do with its weapons and suggested some sort of temporary deal.“We can talk about freezing or storing or laying down, with the Palestinian guarantees, not to use it at all during this ceasefire time or truce,” Naim told AP during an interview in Doha, Qatar. The Hamas official also said the group supports the idea of an international peacekeeping force being deployed to Gaza, but not one that’s tasked with disarmament.‘We are welcoming a UN force to be near the borders, supervising the ceasefire agreement, reporting about violations, preventing any kind of escalations,” Naim said. “But we don’t accept that these forces have any kind of mandates authorizing them to do or to be implemented inside the Palestinian territories.”The US plan, which has been backed by a UN Security Council resolution that places Gaza under the control of a US-led board, calls for an “International Stabilization Force” to be deployed to replace IDF troops in the Strip. But progress has been slow on forming the force since the mission is unclear, and countries fear their troops could end up fighting Hamas on behalf of Israel.Israel currently occupies more than 50% of Gaza’s territory, and there are signs that Israeli officials are planning a permanent occupation. Qatar Prime Minister Sheikh Mohammed bin Abdulrahman al-Thani, a key mediator, said on Saturday that a full Israeli withdrawal from Gaza is needed for a real ceasefire.

South Sudan Deploys Troops to Secure Heglig Oil Field -South Sudan has moved troops into Sudan’s Heglig oil field under what it calls a tripartite agreement with Sudan’s two warring factions. The move is a rare arrangement aimed at shielding critical oil infrastructure as fighting escalates across West Kordofan. South Sudan’s army chief of staff, Paul Nang, appeared in a video address from Heglig, saying South Sudanese forces entered the field following an agreement between President Salva Kiir, Sudanese Armed Forces leader Abdelfattah El Burhan, and Rapid Support Forces commander Mohamed Hamdan Dagalo. Under the deal, both Sudanese factions are to withdraw from the area, allowing South Sudanese troops to secure oil installations and prevent sabotage. Nang said the deployment is strictly limited to protecting infrastructure and that South Sudanese forces will not take part in military operations inside Sudan. The objective, he said, is to “completely neutralise” the oil field as a combat zone, even as battles intensify elsewhere in the region. Heglig matters far more to Juba than to Khartoum. The field hosts a central processing facility capable of handling about 130,000 barrels per day of South Sudanese crude, which is exported via pipelines running through Sudan to Port Sudan. South Sudan resumed oil exports through Sudan in January after a near year-long suspension. While Sudanese economists say the loss of Heglig has limited impact on Sudan’s finances, South Sudan has far less room for disruption. Production at Heglig has already fallen sharply, from about 65,000 barrels per day to roughly 20,000 since fighting between the SAF and RSF erupted in April 2023. The outlook darkened further this week when China National Petroleum Corporation confirmed it had withdrawn from Sudan after three decades, citing deteriorating security in West Kordofan.

US-Trained Somali Forces Kill Dozens of Civilians in Attack on Village in Southern Somalia - A US-trained Somali government force killed dozens of civilians during an attack on a village in southern Somalia that started Tuesday night and continued until Wednesday morning, according to Somali media reports.According to the Somali Guardian, the attack targeted the village of Jambaluul, about 40 kilometers west of Mogadishu, and was launched after the arrival of the Alpha Group, a special operations branch of Somalia’s National Intelligence and Security Agency that has received training from the US.Garowe Online reported similar details, though it said the attack was conducted by the Danab, a special operations force of the Somali military that is armed and trained by the US. Both reports said that more than 30 civilians were killed and that the village was flattened by the attack, which involved artillery fire.The Somali government said the attack was a “special operation” against al-Shabaab fighters, but residents strongly denied that there were militants in the area. According to Garowe, doctors at a hospital in the nearby town of Afgoye said more than 100 wounded civilians arrived and that some of them were transferred to Mogadishu.The raid came less than a month after a suspected US airstrike killed 12 civilians, including eight children, in an attack on a village in the southern Jubaland province. The US has conducted a record number of airstrikes in Somalia this year, both against al-Shabaab in southern and central Somalia and against the ISIS affiliate in the northeastern Puntland region, where the US backs local forces.

Investigators Say Somali Clan Elder Killed by US Airstrike Was a Peace Delegate, Not a Militant - A committee in Somalia tasked with investigating the killing of a Somali clan elder who was hit by a US airstrike has found that he was a peaceful figure with no links to militant groups, rejecting claims from US Africa Command that he was an al-Shabaab weapons dealer.According to Hiraan Online, a Somali news site, the report on the killing of Abdullahi Omar Abdi was based on findings from Puntland security agencies and testimony from witnesses. Local officials and family members have already strongly rejected the US claims, saying that Abdi was known for his efforts at peacemaking.Abdi was killed by a US airstrike on September 13 while driving by himself in a car in Somalia’s northern Sanag region, to the west of Puntland. The investigators said that he had left the town of Ceelbuh and was on his way to the Badhan district to participate in talks aimed at resolving a dispute between two local clans. The Hiraan report said that the investigation found that Abdi was “officially registered traditional leader under the Puntland Ministry of Interior and played a significant role in peacebuilding and community mobilization in the Sanaag region.”According to Brig. Gen. Abdillahi Omar Anshuur, the commander of a battalion in the Puntland Dervish Force, the official military wing of the Puntland government, Abdi met with Puntland’s president not long before he was killed.“He was a peacemaker who helped defend Puntland during conflicts with al-Shabab and ISIS. His killing was illegal and unjust. He had been in Bosaso for 20 days and had even met President Said Abdullahi Deni. If he were guilty of anything, he would have been arrested, not bombed,” Anshuur said in October.Before AFRICOM took credit for the strike, locals initially suspected the UAE and thought it was related to a minerals deal between Puntland and Abu Dhabi that Abdi opposed.AFRICOM told Antiwar.com last month that it was “aware” of the reports that the September 13 strike killed a civilian and said that it “takes all reports of possible civilian casualties seriously and has a process in place to conduct thorough assessments using all available information.” Antiwar.com has asked AFRICOM for a comment on the new report and if the command is investigating the attack, and has yet to receive a reply.The bombing of Abdi’s car is just one of the 111 airstrikes AFRICOM has conducted in Somalia this year, an unprecedented number as the Trump administration shattered the previous record for annual US airstrikes in the country, which President Trump set at 63 during his first term in 2019. Despite the record-setting bombing campaign, the US war in Somalia receives virtually no coverage in US media.