production of crude from US wells equals record high; Strategic Petroleum Reserve the lowest since November 1982; refinery utilization rate is highest in 8 years; barrels of oil refined are highest in seven years; gasoline inventories at a 42 week low, combined road fuel inventories at their lowest in 18 years.
US oil prices rose for the third time in four weeks after the US launched a new wave of attacks on Iranian infrastructure and shipping and Iran retaliated against US bases and allies in the region and their shipping…after falling 4.2% to $83.40 a barrel last week as the US policy impetus seemed to have shifted to economic sanctions on Iran, reducing the level of violence around the Persian Gulf, the contract price for the benchmark US light sweet crude for October delivery climbed more than 2% in early Asian trading on Monday after the United States carried out strikes against Iran’s Larak Island in the Strait of Hormuz, prompting an Iranian response and raising fresh concerns over the security of the vital global energy route, and was up 3% as markets opened in the US following the first exchange of fire between Washington and Tehran in over a month, and settled $2.36 higher at $85.76 a barrel on the renewed military strikes in the Middle East and concerns of further oil supply disruptions… oil prices rose again during Asian trading on Tuesday as renewed fighting between the United States and Iran in the Middle East revived concerns over potential disruptions to supplies from the key global oil-producing region, and likewise moved nearly 2% higher Tuesday morning in New York as the renewed military exchanges between Washington and Tehran stoked supply disruption fears, and then rallied to settle $4.46 or 5.2% higher at a five week high of $90.22 a barrel following attacks on two tankers carrying Saudi crude oil in the Strait of Hormuz….the October oil contract rose another 0.8% in early Asian trading on Wednesday, as concerns grew over supply disruptions after the United States and Iran exchanged strikes overnight, dashing hopes that tensions in the Middle East would ease quickly, but retreated in early US trading as traders awaited official U.S. petroleum inventory data for the prior week amid mixed signals for energy freight on the Strait of Hormuz from the U.S.-Iran war. then was little changed in volatile trading after the EIA reported that both the SPR and the Cushing OK oil depot were near tank bottoms, despite record production, and settled 79 cents higher at $91.01 a barrel after Iran responded to US strikes on Tuesday by striking what it said were U.S. assets in Bahrain, Jordan, Kuwait and Iraq….oil prices edged lower during Asian trading on Thursday as traders assessed the uncertainty surrounding the renewed military strikes between the United States and Iran, and their potential impact on Middle East supplies, but turned around and rallied to a six week high during morning trade in London after renewed US attacks on Iran, along with fresh Israeli threats against Tehran, heightened concerns over potential disruptions to Middle East supplies, then gave back most of those gains Thursday morning in New York as the market balanced concerns over the impact of heightened fighting in the Middle East with U.S. President Trump's hints that current hostilities might wind down again, before settling 29 cents higher at $91.30 a barrel as Iran continued to strike U.S. Gulf allies, with Kuwait intercepting incoming missiles and drones and after Israel’s Defense Minister said Israel would destroy Iran’s military and civilian infrastructure, including energy facilities, if Iran launched attacks against it…oil prices rose half a percent during Asian trading on Friday and were headed for their biggest weekly increase since mid-July as renewed hostilities between the US and Iran intensified concerns over potential disruptions to oil supplies, but they were little changed Friday morning in London amid the renewed tensions in the Middle East, and then retreated in early trading Friday morning in New York as renewed U.S.-Iran hostilities sustained fears of prolonged supply disruptions through the Strait of Hormuz, before rolling over and settling 18 cents higher at $91.48 a barrel on renewed US-Iran strikes and record high diesel prices, and thus finished 9.7% higher for the week….
meanwhile, natural gas prices finished higher for a fourth straight week on lower production, higher LNG demand and forecasts for record cooling demand in September…after rising 3.4% to $2.888 per mmBTU last week on a smaller than normal injection of gas into storage, and on forecasts for the exceptionally hot weather in the South to continue into early September, the price of the benchmark natural gas contract for October delivery opened 2.1 cents lower on Monday, but quickly trended higher, as the latest forecasts were calling for a historically warm September, and settled 4.7 cents higher at $2.935 per mmBTU as forecasts put September among the hottest on record, with recovering LNG demand and shrinking storage surpluses stacked against production running near record highs....however, October natural gas opened 7.5 cents lower on Tuesday, as traders shrugged off the bullish weather forecasts to focus on high supply levels, but pared those early losses to settle 3.1 cents lower at $2.904 per mmBTU, as the season’s first Gulf Coast tropical storm bore down on the Texas-Louisiana LNG corridor without denting feedgas nominations… natural gas prices started 0.4 cents lower on Wednesday, but trended higher through the morning amid continued forecasts for elevated cooling demand in September and steady LNG exports, and settled 5.2 cents higher at $2.956 per mmBTU as increasingly bullish September heat forecasts gave traders another reason to test the $3 mark, while renewed US-Iran fighting added a fresh jolt from overseas….natural gas prices opened 1.8 cents higher on Thursday and traded near $2.985 ahead of the weekly storage report, then momentarily jumped to the intraday high of $3.005 when the report hit the wire, only to plummet minutes later and ultimately settle 4.3 cents lower at $2.913 per mmBTU, despite unseasonably hot near-term forecasts and formidable year/year storage deficits in multiple regions…natural gas futures ticked up early Friday as traders digested a narrowing but still substantial storage surplus, choppy yet seasonally solid production, robust late-summer cooling demand and strong LNG volumes, then strengthened as midday approached, underpinned by lower production and a warmer extended outlook, and settled 6.2 cents higher at $2.975 per mmBTU amid impressive late summer cooling demand, tightening storage balances and rejuvenated LNG feedgas flows, leaving natural gas prices 3.0% higher for the week…
The EIA’s natural gas storage report for the week ending August 28th indicated that the amount of working natural gas held in underground storage rose by 30 billion cubic feet to 3,214 billion cubic feet by the end of the week, which left our natural gas supplies 50 billion cubic feet, or 1.5% below the 3,264 billion cubic feet of gas that were in storage on August 28th of last year, but 160 billion cubic feet, or 5.2% above the five-year average of 3,054 billion cubic feet of natural gas that had typically been in working storage as of the 28th of August over the most recent five years….the 30 billion cubic foot injection into natural gas storage for the cited week was close to the 31 billion cubic foot injection into storage that the market had been expecting ahead of the report, but it was less than the 50 billion cubic foot of gas that were injected into natural gas storage during the corresponding week of 2025, and also less than the average 37 billion cubic foot injection into natural gas storage that had been typical for the fourth week in August 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 August 28th showed that after an increase in our oil exports an increase in our refining, and an increase in demand for oil the EIA could not account for, we had we had to pull oil out of our stored crude supplies for the eighteenth time in nineteen weeks, and for the 40th time in sixty-six weeks, including another big withdrawal of oil from the SPR and a large withdrawal from commercial crude supplies…. Our imports of crude oil rose by an average of 612,000 barrels per day to 6,770,000 barrels per day, after falling by an average of 435,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 691,000 barrels per day to average 4,483,000 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 2,287,000 barrels of oil per day during the week ending August 28th, an average of 79,000 fewer barrels per day than the net of our imports minus our exports during the prior week... At the same time, transfers to our oil supplies from Alaskan gas liquids, from natural gasoline, from condensate, and from unfinished oils were 4,000 barrels per day higher than the prior week at 887,000 barrels per day, while during the same week, production of crude from US wells was 19,000 barrels per day higher at a 43 week high of 13,862,000 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 17,036,000 barrels per day during the August 28th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 17,496,000 barrels of crude per day during the week ending August 28th, an average of 102,000 more barrels per day than the amount of oil that our refineries reported they were processing during the prior week and the most we’ve refined in one week in seven years, while over the same period, the EIA’s surveys indicated that a total of 1,082,000 barrels of oil per day were being pulled from the supplies of oil stored in the US… So, based on all 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 August 28th averaged a rounded 623,000 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 [ -623,000 ] barrel per day figure onto line 16 of the weekly U.S. Petroleum Balance Sheet, in order to make the reported data for the supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus indicating there must have been a error or omission of that amount in the week’s oil supply & demand figures that we have just transcribed.... Since 214,000 barrels per day of demand for could not be accounted for in the prior week’s EIA data, that means there was a 409,000 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 somehow off by that much, and therefore pretty useless... However, since most oil traders react to the figures in 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 March 2023 twitter thread from an EIA administrator addressing these ongoing weekly errors, and what they had once hoped to do about it).
This week’s rounded 1,082,000 barrel per day average decrease in our overall crude oil inventories came as an average of 636,000 barrels per day were being pulled out of our commercial stocks of crude oil, while 446,000 barrels per day were being pulled out of our Strategic Petroleum Reserve, the twenty-third consecutive Iran war related withdrawal from the SPR, including the four largest draws in SPR history, which left the SPR level at 286,604,000 barrels, the lowest since it was initially being filled in November 1982....Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports rose to 6,715,000 barrels per day last week, which was 1.8% more than the 6,598,000 barrel per day average that we were importing over the same four-week period last year, while the four week average of our exports rose to 3,884,000 barrels per day last week, which was 1.6% less than the 3,911,000 barrel per day average that we were exporting last year year at this time... This week’s crude oil production was reported to be 19,000 barrels per day higher at 13,862,000 barrels per day, matching it’s all time high set November 7, 2025, as the EIA’s estimate of the output from wells in the lower 48 states was 6,000 barrels per day higher at 13,419,000 barrels per day, while Alaska’s oil production was 13,000 barrels per day higher at 443,000 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 5.8% higher than that of our pre-pandemic production peak, and was also 42.9% 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 98.0% of their capacity while processing those 17,496,000 barrels of crude per day during the week ending August 28th, up from 97.4% the prior week, and the highest refinery utilization rate since the week ending August 17th, 2018….the 17,496,000 barrels of oil per day that were refined that week were the most we’ve refined in one week since August 16th, 2019, 3.7% more than the 16,869,000 barrels of crude that were being processed daily during the week ending August 29th of 2025, and 0.7% more than the 17,381,000 barrels that were being refined during the pre-pandemic week ending August 30th, 2019, when our refinery utilization rate was at 94.8%, which was close to the pre-pandemic normal utilization rate for this time of year…
With the increase in the amount of oil that was being refined this week, gasoline output from our refineries was also higher, increasing by 73,000 barrels per day to 9,845,000 barrels per day during the week ending August 28th, after our refineries’ gasoline output had increased by 61,000 barrels per day during the prior week... This week’s gasoline production was 0.3% lower than the 9,872,000 barrels of gasoline that were being produced daily over the week ending August 29th of last year, and 4.2% less than the gasoline production of 10,272,000 barrels per day seen during the prepandemic week ending August 30th, 2019….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 9,000 barrels per day to 5,126,000 barrels per day, after our distillates output had decreased by 81,000 barrels per day during the prior week. With three straight production decreases, our distillates output was 2.4% less than the 5,253,000 barrels of distillates that were being produced daily during the week ending August 29th of 2025, and 0.5% less than the 5,154,000 barrels of distillates that were being produced daily during the pre-pandemic week ending August 30th, 2019....
Even with this week’s increase in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the 25rd time in twenty-nine weeks, decreasing by 1,173,000 barrels to a 42 week low of 205,669,000 barrels during the week ending August 28th, after our gasoline inventories had decreased by 2,536,000 barrels during the prior week. Our gasoline supplies fell this week even though the amount of gasoline supplied to US users fell by 121,000 barrels per day to 8,922,000 barrels per day because our imports of gasoline fell by 195,000 barrels per day to 370,000 barrels per day, and because our exports of gasoline rose by 44,000 barrels per day to 934,000 barrels per day… After fifty-four gasoline inventory withdrawals over the past eighty weeks, our gasoline supplies were 5.9% lower than last August 29th’s gasoline inventories of 218,539,000 barrels, and about 6% below the five year average of our gasoline supplies for this time of year…
After this week’s modest decrease in distillates production, our supplies of distillates rose for the sixteenth time in twenty-nine weeks, increasing by 796,000 barrels to 104,187,000 barrels during the week ending August 28th, after our distillates supplies had decreased by 2,228,000 barrels during the prior week... Our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of domestic demand, fell by 449,000 barrels per day to 3,390,000 barrels per day, and because our exports of distillates fell by 55,000 barrels per day to 1,735,000 barrels per day, while our imports of distillates fell by 63,000 barrels per day to 113,000 barrels per day... After 28 withdrawals from distillates inventories over the past 59 weeks, our distillates supplies at the end of the week were 10.1% lower than the 115,923,000 barrels of distillates that we had in storage on August 29th of 2025, and were about 14% below the five year average of our distillates inventories for this time of the year…since our gasoline inventories fell more than distillates inventories rose, our combined road fuel inventories were again at their lowest in 18 years..
Finally, after the increase in our refining and in our oil imports, our commercial supplies of crude oil in storage fell for the 13th time in twenty-six weeks, and for the 25th time over the past year, decreasing by 4,450,000 barrels over the week, from 428,910,000 barrels on August 21st to 424,460,000 barrels on August 28th, after our commercial crude supplies had increased by 95,000 barrels over the prior week….After this week’s decrease, our commercial crude oil inventories were still about 1% above the recent five-year average of commercial oil supplies for this time of year, while they were about 28% above the average of our available crude oil stocks as of the last weekend of August over the 5 years at the beginning of the past decade, with the 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 inventories had been less extreme up until the onset of the Iran war, when they were initially built up to a three year high by mid-April, before falling to the lowest in nearly eight years by late July…This week’s decrease was the first in five weeks, and as of August 28th our commercial crude inventories were 0.9% above the 420,707,000 barrels of oil we had in commercial storage on August 29th of 2025, and were 1.5% more than the 418,310,000 barrels of oil that we had in storage on August 30th of 2024, and 0.4% more than the 422,944,000 barrels of oil we had left in commercial storage on August 25th of 2023…
This Week's Rig Count
The US rig count was unchanged for a second week over the week ending September 4th, as the number of rigs targeting oil was up by two, 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 table from Baker Hughes...in the table below, the first column shows the active rig count as of September 4th, the second column shows the change in the number of working rigs between last week’s count (August 28th) and this week’s (September 4th) count, the third column shows last week’s August 28th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday of the same week of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting period a year ago, which in this week’s case was Friday, the 4th of September, 2025…
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Hope and concern swirl for Ohioans around ‘world’s largest datacenter’ On a winding road tucked away behind forests in the Appalachian foothills of southern Ohio is where OpenAI, Nvidia and Japanese investors are set to spend $500bn on one of the largest artificial intelligence datacenters on the planet. Last March, the energy secretary, Chris Wright, the commerce secretary, Howard Lutnick and a host of Japanese and other dignitaries briefly descended on Piketon to enthusiastically break ground on a project to build 8GW worth of AI computing power. SB Energy, a subsidiary of Japanese bank SoftBank Group Corp, will own and operate the project with OpenAI signing a 20-year lease with the company to use the computing capacity delivered by the site. OpenAI would deploy Nvidia AI computing infrastructure at the datacenter, which will open in 2028. To meet its major energy demands, a natural gas plant would be built nearby, infrastructure expected to be paid for by Japanese money through a $33bn investment. However, the project has fueled concern from environmental groups, with part of it situated on a decommissioned uranium enrichment site that operated for nearly 60 years until 2001. For decades, communities in Pike county have blamed the department of energy-run facility, known locally as the “A-Plant”, for fueling above-average cancer rates and a host of other health issues. In 2019, a local middle school was forced to close after high levels of radiation were recorded in the building. The project is in large part a consequence of the Trump administration’s tariff and reshoring efforts: the government of Japan in July 2025 agreed to invest $550bn in the US in exchange for lowering tariffs on Japanese products entering the US. America is Japan’s biggest trade partner. However, a new administration could prevail in Washington after the 2028 presidential election and it could be one that could end Trump’s tariffs and consequently erase any motivation for Japanese investment in the project. That is not lost on Spencer.“But this is part of Japan’s deal – if you don’t put tariffs on us, we’ll spend money here [is Japan’s motivation],” he says. “So anytime it’s a political football like that, it’s subject to change, whether you support Trump or not.” Datacenters and their electricity and water needs have created a lightning rod of anger for communities across America. In July, the state of New York announced a pause in permitting the development of hyperscale datacenters, the first state in the country to do so.But the allure of huge sums of money is hard to ignore in Pike county, a part of America where the poverty rate, at over 19%, is almost double the national level.The project has promised to generate 35,000 construction jobs and 2,500 long-term, operating jobs respectively, with the datacenter expected to take up about 640 acres (260 hectares), or an area about three-fourths the size of New York City’s Central Park. “Since the [enrichment] plant closed, people have been wondering where the jobs will come from,” says Spencer.“Pike county certainly can’t handle that alone,” he says of the estimated tens of thousands of construction workers expected to descend on the area over the next six years.Environmentalists, however, say there are a host of issues with the plan.Creating what would be the country’s largest natural gas power plant could see millions of pounds of noxious chemicals released into the air.Flaring produces huge volumes of carbon monoxide, carbon dioxide, sulfur dioxide and nitrogen oxides.“As one of the largest natural gas facilities ever proposed, the greenhouse gas emissions and air pollution associated with a project of this size represents an astronomical contribution to climate change, not to mention the public health risks associated with the air pollution created by natural gas combustion,” says Carol Kauffman, the chief executive officer of the Ohio Environmental Council.“There are also upstream impacts, too, with fracking wells and methane leakage from pipelines.” The US Energy Information Administration estimates that in 2022, “CO2 emissions from burning natural gas for energy accounted for about 35% of total US energy-related CO2 emissions”. What’s more, local leaders suggest that during the construction phase up to 2m gallons of water may be required for waste purposes. Residents, including Spencer, have previously voiced opposition to a $650m waste disposal facility at the site, where low-level radioactive and other materials from the disassembled uranium-enrichment plant have been buried. Many are concerned that leaching, over time, could see hazardous waste enter the aquifer underground.Project managers, however, say that has been taken into account. “SB Energy performs thorough site reviews and due diligence for each of our infrastructure projects, including soil sampling,” a SB Energy spokesperson told the Guardian.“SB Energy has committed to paying for accelerated cleanup and remediation at the site.”Headquartered in Redwood City, California, SB Energy has said that Ohio ratepayers won’t have to pay into the cost for connecting the facility to the local electricity grid, and that additional electricity produced at the natural gas plant would go back onto the local grid, helping reduce costs for local customers.Many locals support any effort that would hasten funding for safer use and storage of the radioactive material that dots the site, which covers 6 sq miles, or almost 4,000 acres.For its part, OpenAI announced this month plans to “invest $40m in a community grant fund supporting priorities identified by local residents” in Pike county. It also plans to give college students across Ohio a $100 credit to use one of its ChatGPT AI tools. But all this money being pumped into a community where the median household income is $41,313 or 40% less than the Ohio figure, could set off a wealth gap between land and property owners and everyone else.Locals say SB Energy is actively buying up large tracts of land, a move that has reset the local property market. A report filed by SB Energy with the Ohio Environmental Protection Agency says part of the project would be located on more than 1,000 acres of private land immediately adjacent to the former enrichment facilityAnd at the time of writing, SB Energy had posted just four jobs based in Piketon. On the streets of Piketon, several residents in the village of about 2,200 people declined to comment on the project due to having no information about it.Dawn Winters, who runs several local gas stations, says her business is likely to benefit from the project.“I think it’s going to be a good thing for businesses like mine,” she says.“But on the other hand, we are seeing rent prices go up already. A friend of mine had to sell their land [to the project] and relocate. People are already needing affordable housing.”
A Village in Southern Ohio Is Bucking the Data Center Backlash. Why? -On Monday, August 17, OpenAI signed a 20-year lease agreement for a data center in the small southern Ohio town of Piketon, population 2,300. Piketon is roughly 50 miles south of Columbus, and its data center will likely be the largest in the world. The 10-gigawatt facility will consume enough electricity to power seven million homes. Given the growth of “no data centers in my backyard” populist backlash, one might expect a deal this size to have spurred mass opposition from local residents. However, when Commerce Secretary Howard Lutnick declared the Piketon project “the largest bet on a construction facility ever made in history,” Ohioans readily “embraced” or “welcomed” the development. Why?The proposed PORTS-Pike Technology Campus, as its developers have christened the site, takes advantage of the least utilized resource in America’s race to build data centers: brownfields. Brownfields, as the U.S. Environmental Protection Agency defines them, are properties that often contain hazardous substances, pollutants, or other contaminants that are hard to clean up. Examples include abandoned factories, warehouses, air strips, and other industrial sites. Our best estimates point to between 450,000 and 1 million brownfields in the U.S. As the figure below suggests, it’s highly likely that you live near one, or pass it by on a regular basis.In July 2025, Trump signed an executive order to streamline permitting for data centers on federal lands — including brownfields. The PORTS-Pike data center is the first of its kind on brownfields held by the Department of Energy (DOE). The success or failure of OpenAI’s data center in Piketon will determine whether AI companies and the federal government can work together to create a better path forward for America’s data center buildout.OpenAI’s data center will be built by SoftBank 3,777-acre plot of federal land where the United States once produced its bomb-grade uranium.1The Portsmouth Gaseous Diffusion Plant in Piketon was one of three uranium enrichment plants the U.S. operated throughout the Cold War. Since the plant closed in 2001, the DOE has evacuated toxic waste and managed the site. Now, OpenAI and its partners plan to finish the cleanup and thrust the Portsmouth site, once again, onto the high-tech production frontier reshaping the American economy, geopolitics, and everyday life alike.Portsmouth’s past, and the economic vibrancy and dignified work it buoyed, helps explain why Ohioans support the data center today. “We dream big, but I don’t know that anybody could dream this big,” Steve Shepherd, head of a local organization titling land for the project, told reporters. “I think this is a model for the country.”To see what he means — and what it would take for him to be right — go back to the first time the country asked Piketon to build the infrastructure of an age.In August 1952 the Atomic Energy Commission (AEC) chose a stretch of flat Scioto River farmland in Pike County as the site of a $1.2 billion plant to enrich uranium — the third and newest node in the complex enrichment infrastructure that built the Cold War arsenal and fueled American power plants. The New York Times announced the decision on page one beneath a headline promising “3 Towns to Be Leveled”; the story beneath it was quieter, recording some 50 farm families to be resettled with the AEC’s help. Residents were assured the plant would pose “no more hazards than an average industry.” Against that assurance, they weighed 17,000 jobs and took the wager.2 It is a bet Piketon is weighing again today. What rose from the cornfields was a labor-intensive and local “city of knowledge” in America’s nuclear infrastructure. At the Portsmouth plant, engineers put the physics of uranium enrichment to work in three windowless buildings, each a mile and a half end to end, where uranium gas was blasted through fine barriers 4,020 times, separating usable U-235 from dross.3 Electricity powered that process. A new utility, the Ohio Valley Electric Corporation, was chartered for the sole purpose of powering the plant. It filed what was then “the largest financing project ever presented to the Government for its approval,” and built two coal plants for a single customer. The Ohio Valley Electric Corporation provided 1,950 megawatts around the clock — a quarter more power than all of New York City drew, the Wall Street Journal marveled.4 The natural gas complex SoftBank is building at the same site today recreates this midcentury arrangement. Sam Sapirie, who ran operations at another enrichment plant in Oak Ridge, made the hope for nuclear infrastructure clear for all Americans: “We are creating wealth here, treasure worth more than all the gold at Fort Knox … It doesn’t rust or rot or go out of style.”5
Massive AI data center complex eyes buyouts, 'record speed' in southern Ohio - Columbus Dispatch. SoftBank exec calls Piketon AI complex 'World's largest construction project' (paywalled; details via Google: SoftBank and SB Energy executives, alongside U.S. federal officials, have described the massive 10-gigawatt AI and energy campus in Piketon, Ohio, as the "world's largest construction project, period". [1, 2] The project is taking shape on a 3,700-acre plot at the former Portsmouth Gaseous Diffusion Plant site in Pike County. Key details of the undertaking include: [1, 2]
- The Scale: Designed to reach a 10-gigawatt data center capacity paired with a massive 9.2-gigawatt natural gas power plant (and potential small modular nuclear reactors). [1, 2]
- The Partners: Developed by SoftBank's SB Energy in collaboration with the U.S. Department of Energy, OpenAI, and Nvidia. [1]
- The Investment & Jobs: Billed as a multidecade project with overall investments potentially scaling toward $500 billion, projected to pull in roughly 35,000 peak construction jobs. [1, 2]
- The Timeline: Construction is advancing at record speed with initial phases targeted to come online around 2028. [1, 2, 3]
Massive OH Project Has Its Turbines; Changes the Utica Gas Math - Marcellus Drilling News -- A pile of poster boards in a YMCA gymnasium is not usually where you find the most important number in a $33 billion project. But on Aug. 27, at the Pike County YMCA in Waverly, Ohio, an SB Energy executive told a Columbus Dispatch reporter something that ought to get every Utica producer’s attention: the turbines are already bought. Not ordered. Not “in negotiations.” Bought — for the first phase of what will be the largest gas-fired power plant in American history.
Landowners Take Note: Data Center Buyouts Are Not Royalty Checks -Marcellus Drilling News - At the Aug. 27 open house for the Piketon power project, an SB Energy poster showing an aerial view of the site drew the biggest crowd in the gym. It wasn’t the environmental impact board or the electricity charts. It was the map — because it showed people their own houses. The Columbus Dispatch was in the room. What its reporter found is a story MDN readers are going to see repeated across Ohio over the next decade, and it is worth understanding clearly before it lands in your county and before you get a knock on your door asking if you want to sell.
Yet another way that data centers put enormous costs on everyday Ohioans: Today in Ohio --- Ohioans are paying for $1.6 billion in transmission lines for the power-sucking demands of new data centers. And energy companies can legally make money on the new electricity transmission projects they build.We’re talking about how regular Ohioans are subsidizing data centers and energy companies on Today in Ohio.
Another $1.6 billion cost for Ohioans for all those data centers - cleveland.com -The century-old bargain behind America’s utility system is pretty straightforward: everyone chips in for the power grid because everyone benefits from it. It’s the same logic that built the interstate highway system — even if you never drive a particular stretch of road, you help pay for it because it keeps the whole economy moving.Today in Ohio podcast hosts said Monday that tech companies are abusing that longstanding communal commitment to get Ohioans to pay $1.6 billion to assist data centers being built here.Ohio utilities have told state regulators they need $1.6 billion to build high-voltage transmission lines and substations to serve a handful of massive new data center customers, not the general public. The cost is being spread across all ratepayers.“This is a century old bargain,” host Laura Johnston said. “Basically, everyone pays for the power grid that benefits everyone.”Host Chris Quinn noted that Ohio does not have a growing population. The only reason ratepayrs now have to pay that gigantic sum is to power data centers, which have almost no benefit to Ohio. Ratepayers will empty their pockets so tech companies can collect billions in profit.The problems go beyond who’s paying. Ohio utilities aren’t required to seek competitive bids when choosing contractors to build this infrastructure. As Johnston put it, “There’s no requirement for them to get bids and choose the lowest bidder to build this stuff. So they could choose whoever they want and then charge us and they make a profit on it.”By law, utilities are allowed to earn a return on top of the base project cost — which means ratepayers fund both the construction and the profit margin for companies like FirstEnergy on top of it. The oversight gaps are just as striking, according to reporting by Anna Staver. PJM, the regional grid operator covering Ohio and 12 other states, doesn’t examine supplemental power requests at the local level. The Public Utilities Commission of Ohio doesn’t independently assess whether the projects are necessary or whether cheaper alternatives exist. Independent estimates suggest that requiring competitive processes could reduce costs by 30 percent. That possibility isn’t even being explored.Meanwhile, most of the original deals that brought data centers to Ohio were wrapped in non-disclosure agreements. Johnston pointed out that many local governments don’t fully understand the agreements made on their behalf. “If this were all out in the open, that would be a very different story,” she said. “And then people would be allowed to be heard. And it’s their government, this is the people’s government. They should get to decide.”Quinn tied it back to the political decisions that set all of this in motion — leaders who recruited data centers with secret incentives without asking whether the grid could support them, and who left ratepayers to absorb the cost of finding out it couldn’t.The answer to who pays isn’t complicated. It’s all of us. Listen to the conversation here.
What Ohio communities can gain from data center deals - — As data centers expand across Ohio, communities are weighing the impact of construction, land use and increased demand for power against the potential economic benefits. Greg Lawson, a senior fellow at The Buckeye Institute, said local leaders should negotiate those benefits before construction begins. “Communities that negotiate very well with the data centers when they come into a community can get a ton of benefits,” Lawson said. “This is in terms of property taxes or other sorts of things like payments that go into the local community.” The Buckeye Institute recently co-authored a report examining Ohio’s data center build-out. Lawson pointed to New Albany as one Ohio community that negotiated well. However, he said smaller communities may need help from development or legal experts to negotiate their own terms. To show what those agreements can mean over time, Lawson pointed to Loudoun County, Virginia. Buddy Rizer, executive director of Loudoun Economic Development, said in a written response that data centers occupy less than 3% of the county’s land but generate more than $1 billion in annual revenue, funding nearly one-third of its budget. Loudoun County already has over 43 million square feet of operational data center space. “And what they’ve been able to do there is actually lower property taxes for residents who live there because they’re obtaining so much property tax from the data centers,” Lawson said. Since 2012, Loudoun County’s property tax rate has fallen from about $1.29 to roughly 81 cents per $100 of assessed value. County officials estimate that saves the average homeowner between $3,000 and $4,000 each year. The revenue also helps fund schools, roads and other community services. Over 15,000 jobs are directly or indirectly connected to the industry, including construction, support work and high-skill technical positions. Loudoun County’s approach is now changing as the industry continues to grow. After years of development, county officials said they are no longer proactively recruiting data centers. Instead, the county is managing future growth through zoning, infrastructure planning, buffers and stronger protections for residents. For Ohio communities earlier in the development process, Lawson said the question is not only how much investment data centers bring. It is also whether residents share in the benefits and whether local rules protect them as the industry grows.
Ohio Utility Cuts Off 43 Gas Customers as Old Wells Run Dry - Marcellus Drilling News -Ohio pumped roughly 2 trillion cubic feet of natural gas out of the ground last year, most of it from the Utica Shale. And yet 43 families in Washington County are being told to find another way to heat their homes by October 29 — because the wells that feed their gas line are running out of gas. The Marietta Times and the Parkersburg News & Sentinel both reported last week that Knox Energy has notified 43 customers in the Belpre area that their natural gas service ends October 29. The reason isn't a billing dispute or a rate case. It's geology.
EQT Quietly Launches Open Season for New 1 Bcf/d PA-OH Pipeline -Marcellus Drilling News - EQT is planning another pipeline — and this one is big. Through a brand-new subsidiary called Appalachian Transmission Gateway LLC (ATG), the Marcellus/Utica’s largest driller has opened bidding on the “POWER Pipeline,” a 42-inch, 50-mile line that would carry a full 1 billion cubic feet per day (Bcf/d) of gas from Greene County, Pennsylvania, west to the Clarington hub in Monroe County, Ohio. The open season quietly began Aug. 26 and runs through Oct. 26. We found no press release announcing it — the notice simply went up, and the trade press caught it a week later. further details via Google:
- On August 26, 2026, a newly formed subsidiary of EQT Corporation called Appalachian Transmission Gateway LLC (ATG) quietly launched an open season bidding window for the "POWER Pipeline". [1, 2]
- Specifications: The proposed project is a massive 42-inch diameter, 50-mile natural gas pipeline engineered to move 1 billion cubic feet per day (Bcf/d) of supply. [1]
- The Route: It is designed to transport Marcellus and Utica shale gas from production areas in Greene County, Pennsylvania, westward to the highly connected Clarington hub in Monroe County, Ohio. [1, 2]
- Timeline: The open season for shippers to commit to capacity runs from August 26 through October 26, 2026. [1]
- Market Context: This proposal comes amid a significant regional push by EQT Corporation to bypass pipeline bottlenecks and supply rapid energy demand in the Midwest, heavily driven by multi-billion dollar natural gas power plants and a surge in electricity demand for regional AI data centers. [1, 2, 3]
Rover-Fed Data Center Campus in Wash County, PA Faces 4 Hearings -- Marcellus Drilling News - A Dallas-based hyperscaler wants to build a 1.7-million-square-foot computing campus — plus its very own 450-megawatt natural gas power plant — on a reclaimed strip mine in Washington County, PA. The gas would come off a lateral tied to Energy Transfer’s Rover Pipeline, which runs right past the property line. Prime Data Centers made its first real presentation to the Hanover Township Board of Supervisors Monday night, in front of a fire hall packed past capacity with residents who are, to put it mildly, not sold. Three hours of testimony later, the supervisors scheduled four more hearings.
Protect PT Tries to Undo Approval for SWPA Gas-Fired Data Center -- Marcellus Drilling News - Anti-drilling group Protect PT has opened a new front against the biggest gas-fired AI project in Westmoreland County, Pennsylvania. On Aug. 25, Protect PT and two Upper Burrell residents — Allen Uhler and Guy Fuller — filed a land use appeal in Westmoreland County Court challenging the township supervisors’ approval of TECfusions’ work at the former Alcoa/Arconic research campus. Notably, the appeal doesn’t attack the gas turbines or the Marcellus wells feeding them. It attacks a piece of paper. Or rather, the absence of one.
Gas Fuels 59% of PA Power as PUC Forecasts Data Center Surge -- Marcellus Drilling News - Pennsylvania’s utility regulators just told the General Assembly what Marcellus drillers have been saying for two years: the electricity business is about to get very busy, and natural gas is going to be the one doing the heavy lifting. On Tuesday, September 1, the Pennsylvania Public Utility Commission (PUC) released its annual Electric Power Outlook for Pennsylvania, this one covering 2025 through 2030. The report is required by state law — the PUC has to collect demand forecasts from the state’s 11 electric distribution companies (EDCs, the utilities that run the poles and wires to your house) and hand a summary to the Legislature and the Governor every September. Usually it’s a snoozer. Not this year.
Edge LNG, Marcellus Virtual Pipeline Pioneer, Sold to Sapphire Gas -- Marcellus Drilling News - - A press release crossed the wire yesterday announcing that Edge LNG — the little company that showed the Marcellus how to truck its stranded gas to market — has been sold. Sapphire Gas Solutions of Conroe, Texas, is the buyer. Blue Water Energy, the private equity firm that backed Edge from the beginning, is the seller. And here’s the part that caught our eye: the announcement calls Edge “a Texas-based LNG company” serving customers in the Southern U.S. The Marcellus, where Edge made its name, doesn’t get a single mention.
39 New Shale Well Permits Reported for PA-OH-WV Aug 24 – 30 - Marcellus Drilling News - The Marcellus/Utica region received 39 new drilling permits last week, August 24 – 30, up significantly from the 19 permits issued two weeks ago. Pennsylvania finally bounced back, issuing the vast majority of the new permits, with 25. Ohio issued 8 permits. And West Virginia issued 6 new permits. The drillers who received new permits were: Antero Resources, Campbell Oil & Gas, CNX Resources, EOG Resources, EQT, Expand Energy, Infinity Natural Resources, PennEnergy Resources, and Repsol Oil & Gas. Antero Resources | Beaver County | Bradford County | Campbell Oil & Gas | Clearfield County | CNX Resources | EOG Resources | EQT Corp | Expand Energy | Harrison County | INR/Infinity Natural Resources | Marshall County | Noble County | PennEnergy Resources | Repsol | Susquehanna County | Washington County | Westmoreland County
Seneca Expanding Appalachian Footprint as Natural Gas Demand Outlook Strengthens - Seneca Resources is joining a growing list of Appalachian pure-plays working to bolt on acreage to strengthen inventories and expand development runways as natural gas demand is poised to strengthen. NGI chart shows Tennessee Zone 4 Marcellus daily natural gas prices spiking above $60/MMBtu in late January 2026 before retreating. At a Glance:
Up to $240 million budgeted
Core acreage targeted in Pennsylvania
Other Appalachian operators adding acreage
Split Casing at INR Pad Spills Frack Water into Indiana Co. Stream -- Marcellus Drilling News - -A frack job gone sideways in Indiana County, PA, kept 14 volunteer fire companies on scene for more than 12 hours last month — and, according to a Pennsylvania Department of Environmental Protection (DEP) inspection report, sent an unknown quantity of frack flowback water off the pad and into a nearby stream. We don’t sugarcoat things at MDN, so let’s walk through what actually happened, what DEP says it found, and — just as important — what nobody has established yet.
DEP: 336,000 Gallons of Frack Water Spilled at INR Indiana Co. Pad -- Marcellus Drilling News - We finally have a number. Two weeks after a casing failure sent frack water gushing across the Infinity Natural Resources Cooper well pad in Young Township, Indiana County, PA, the Department of Environmental Protection (DEP) has put an estimate on it: 336,000 gallons of frack flowback water released during the incident. An “undetermined amount” of that reached Whiskey Run, the small stream below the pad. Here’s what that number actually means — and what it still doesn’t tell us.
Cove Point LNG Outage to Cut Appalachian Natural Gas Demand - Annual maintenance at Cove Point LNG in Maryland could remove about 850 MMcf/d of feedgas demand from Appalachia for up to three weeks starting Sept. 19 if recent outage patterns repeat, just as the fall shoulder season weighs on power demand. Cove Point LNG feedgas deliveries in 2024-2026 show seasonal maintenance declines, with 2026 flows near 850,000 Dth/d in early September. At a Glance:
Pleasant Valley work Sept. 19–Oct. 2
Past outages cut feedgas to 15,000 Dth/d
East storage 6% above 5-year average
850 MMcf/d of M-U Demand Vanishes Sept. 19 as Cove Point Shuts -- Marcellus Drilling News - -It’s that time of year again. Cove Point LNG, the Berkshire Hathaway-operated export terminal on the Maryland shore of the Chesapeake Bay, is heading into its annual maintenance turnaround — and when the plant goes down, roughly 850 million cubic feet per day (MMcf/d) of demand for Marcellus/Utica gas simply evaporates. MDN has obtained the official notice from pipeline operator BHE GT&S laying out exactly what happens and when.
FERC Enviro Assessment for Constitution Pipe: No Significant Impact - Marcellus Drilling News - - In April, we told you the Federal Energy Regulatory Commission (FERC) was taking a fresh look at the revived Constitution Pipeline and the associated Wright Interconnect project, and that the agency had to decide whether a relatively quick Environmental Assessment (EA) would do the job — or whether it would drag the projects through a full-blown, years-long Environmental Impact Statement (EIS). We got our answer on August 21. FERC staff issued the EA for both projects — 79 pages plus appendices — and the bottom line is the one supporters have been waiting on: building Constitution “would not constitute a major federal action significantly affecting the quality of the human environment.” In plain English — no significant impact. No years-long supplemental EIS is needed.
DEEP Memo Undercuts Antis in Iroquois CT Compressor Permit Fight -- Marcellus Drilling News - Iroquois Gas Transmission System’s Enhancement by Compression (ExC) project has cleared FERC. It has cleared New York. The one thing standing between it and a shovel is a state air permit for two gas-fired compressor units in Brookfield, Connecticut. The Hartford Courant checked in on that fight yesterday — and buried the two most important facts halfway down the story. Quick refresher for anyone joining late: ExC is a $272 million upgrade that adds horsepower at three existing compressor stations — Dover and Athens in New York, Brookfield in Connecticut. No new pipe. Just more compression, squeezing an additional 125 MMcf/d (125 million cubic feet per day) through the existing 414-mile line into New York City and New England. That’s roughly a 10% throughput gain on a line that already exists, feeding two of the most gas-starved, highest-priced energy markets in the country. (The Courant puts the project at $275 million; we’ve used the $272 million figure Iroquois has cited. Small gap, worth pinning down.)
DC Circuit Backs FERC on Enbridge’s East Tennessee Gas Upgrade -Marcellus Drilling News - Here’s a pipeline fight where the bad guys aren’t the greens. Last Friday, the U.S. Court of Appeals for the D.C. Circuit sided with the Federal Energy Regulatory Commission (FERC) and Enbridge subsidiary East Tennessee Natural Gas (ETNG), tossing out a challenge brought not by environmental radicals but by the pipeline’s own customers — a group of small-town gas utilities in Tennessee, Virginia, and Alabama who said they were being stuck with the bill for an upgrade they never asked for.
WI Gas Plant Plan Could Pull More Marcellus Gas Westward -- Marcellus Drilling News - A Chicago-based developer wants to build a pair of natural gas-fired power plants in a Wisconsin farm town of 1,650 people — and together they’d crank out enough electricity to light up two million homes. It’s another data center story, and it’s another reminder that the demand pull for our Marcellus and Utica gas keeps stretching farther west. Invenergy has submitted engineering plans to Wisconsin regulators for two gas-fired plants in Brillion, Calumet County, about 15 miles from Appleton. The 750-megawatt (MW) Union Depot Energy Center would run around the clock. The 1.2-gigawatt (GW) Forest Junction Energy Center would be a “peaker” — a plant that fires up only when the grid is straining. Combined output: 1.95 GW. If built, Forest Junction would be the second-largest gas plant in Wisconsin.
LNG Feedgas Demand Retreats Ahead of Sabine-Neches Waterway Reopening - A look at the global natural gas and LNG markets by the numbers. Graphic: LNG Export Flow Tracker -
- 17.37 Bcf/d: US LNG feedgas demand slipped to roughly 17.37 Bcf/d in Wednesday’s nominations, a decline of about 892 MMcf/d from Tuesday, according to NGI’s Entropic Analytics data. Lower nominations at all four of Sabine Pass’s feeder points accounted for roughly three-quarters of the pullback, with smaller declines at Calcasieu Pass and Cameron. Feedgas nominations have not topped 18.5 Bcf/d since April 26 and remain below the 19.50 Bcf/d high set March 28. The Sabine-Neches Waterway serving Beaumont and Port Arthur reopened to outbound traffic at 12 p.m. ET Wednesday after closing late Aug. 31 for Tropical Depression Edouard, which produced a peak gust of 91 mph about two miles south of Port Arthur, according to the US Coast Guard Marine Safety Unit Port Arthur.
- 70%: The National Oceanic and Atmospheric Administration’s Weather Prediction Center (WPC) placed the Houston area under its highest risk category for flooding starting at 8 a.m. ET Thursday as the remnants of Tropical Depression Edouard continue to track across Texas. Meteorologists estimated flood risks at 70% or higher across a swath northwest of Houston as the National Hurricane Center advised of 35–45 mph gusts near the depression’s center. A marginal flood risk extended east to near New Orleans. While feedgas nominations to Gulf Coast terminals were reduced significantly by Wednesday afternoon, pipeline and export facility operators didn’t report any technical issues to customers or state regulators.
- 1.73 Mt: Global LNG exports fell 1.73 Mt short of year-ago levels in August, totaling 32.83 Mt even as loadings rose 1.21 Mt from July, according to Kpler vessel tracking data. The gap was attributed almost entirely to the Middle East, where exports dropped by 4.98 Mt from the year-ago period in 2025 to 2.94 Mt as Qatari volumes collapsed 78% to 1.46 Mt. Growth elsewhere covered only part of the loss, adding a combined 3.25 Mt year/year. The Americas led at 12.30 Mt, up 1.97 Mt, followed by the Pacific at 12.24 Mt. Europe rose 0.66 Mt to 2.08 Mt, and Africa gained 0.15 Mt to 3.26 Mt. Global imports totaled 32.06 Mt, down 3.37 Mt year/year, with Asia accounting for most of the pullback at 22.31 Mt, off 3.25 Mt.
- 10.19 Mt: US LNG exporters loaded 10.19 Mt in August, up 15% from a year earlier. The United States marked the largest year/year increase of any exporting country for August, according to Kpler vessel tracking data. US LNG exports were essentially flat compared to July. Europe took 5.47 Mt in US LNG during the month, up 1.47 Mt and 0.32 Mt year/year. Meanwhile Asia took 2.91 Mt, accounting for a 0.93 Mt decrease from July but still 1.19 Mt above the same period last year. US volumes accounted for roughly 31% of the 32.83 Mt global total for the month, and the Americas as a region exported 12.30 Mt, up 1.97 Mt year/year.
Cheniere Completes Corpus Christi LNG Expansion Project, Exports 5,000th Cargo - Cheniere Energy said Monday it completed its Corpus Christi LNG (CCL) Stage 3 project after bringing the seventh and final liquefaction train online at the expansion in South Texas. At a Glance:
- Stage 3 expansion finished
- Seventh liquefaction train online
- Cheniere output rises 20%
Edouard Set to Cool East Texas After Sparing Gulf Coast LNG Feedgas -Feedgas nominations Tuesday held near recent levels at Gulf Coast LNG terminals as Tropical Storm Edouard made landfall near the Texas/Louisiana border, with forecasters putting the storm's heaviest rains west of the export complex and its threat to production at zero. NGI North America LNG Export Flow Tracker shows LNG feedgas volumes, terminal flows and export facility locations across North America. At a Glance:
Storm surge warnings covered four terminals
Golden Pass trims 109 MMcf/d
National LNG demand steady near 19.1 Bcf/d
US LNG Exports Surge 23% — So Why Is Henry Hub Still Below $3? --Despite an enormous increase in US LNG output this year, benchmark Henry Hub prices have barely budged. At a Glance:
LNG feed gas tops 19 Bcf/d
Production hovers near record levels
Storage stays above five-year average
Stubborn Inflation, Erratic Hiring — What It Means for Natural Gas Demand - Despite a resilient job market in August, a broadly softening US economy and slower global activity could take some heat out of natural gas demand just as end-of-summer cooling needs fade. NGI Henry Hub daily natural gas spot prices fluctuate between about $2.50 and $3.35/MMBtu from May through early September 2026. At a Glance:
- Economic easing could drag on gas demand
- US job market choppy, inflation elevated
- Interest rates high, pressuring debt cost
Permian Gas Production High Even as East Outflows Dip - Permian production was relatively flat last week, averaging 23.1 Bcf/d, in line with where it has been throughout the month of August (see dark orange line in chart below). However, the rig count is climbing, setting the basin up for future growth when Blackcomb and Hugh Brinson pipelines come on later this year. Hugh Brinson has some capacity online but will ramp up to 1.5 Bcf/d this year, and then to 2.2 Bcf/d next year. Blackcomb is commissioning and will have a capacity of 2.5 Bcf/d by the end of the year. Combined, these will provide ample room for production to grow. RBN expects production to climb to around 23.9 Bcf/d by the end of the year and then continue growing in 2027 with production exceeding 25 Bcf/d by year-end. Outflows from the Permian to other regions were down last week, with high in-basin demand alleviating some pressure on flows to the East. Outflows to the East averaged 13.5 Bcf/d, down 0.3 Bcf/d week-on-week. Outflows on all the greenfield pipelines remained strong, with flows on legacy pipelines falling. This is typical for the basin, the newer routes tend to stay full, with flows on legacy routes adjusting based on the overall supply demand balance of the basin. Outflows to Mexico average 2.1 Bcf/d last week. Exports to Mexico through Waha continue to be very strong this summer. Outflows to the West averaged 2.7 Bcf/d, consistent with the prior week. Outflows to the North averaged 1.8 Bcf/d, up 0.1 Bcf/d week-on-week with rebounding flows on Northern Natural and on El Paso towards San Juan.
Fly Like An Eagle – Second Wave of Natural Gas Pipelines Has the Permian Cleared for Takeoff | RBN Energy - The Permian Basin is poised to gain several new natural gas pipelines over the next year or two, finally easing its long-standing takeaway constraints. But the changes won’t stop there. A new wave of proposed projects could further reshape the basin beyond 2027 and into the 2030s. In today’s RBN blog, we look at the major, longer-horizon plans, what they could mean for the Permian, and the new challenges that could arise as this infrastructure comes online. This is the second blog in our series on the outlook for major U.S. producing basins, starting with the largest: the Permian. A major topic at our upcoming School of Energy: Fundamentals, the Permian is the nation’s largest oil-producing basin and a key driver of U.S. gas growth. Its oil-focused wells also generate substantial and growing volumes of associated gas. But moving that gas out of West Texas and southeastern New Mexico has become one of the market’s biggest challenges and a constraint on further oil production. In our first blog, we covered the major pipeline projects expected to enter service this year and next, which will add about 5.3 Bcf/d of egress capacity from the Waha area. In the blogs ahead, we will examine the Permian’s major producers and the challenges still to come, including the implications of rising NGL production. Today, we explore how the Permian’s gas takeaway picture could evolve beyond 2027 and into the early 2030s. Plans can change, of course, but our outlook is based on proposed projects and their current level of development. The growing number of LNG export facilities planned along the Texas Gulf Coast is a major reason more natural gas pipeline capacity is needed. New and expanding LNG projects at Corpus Christi and Port Arthur will increase demand for gas in markets that Permian pipelines increasingly serve, including the Agua Dulce and Katy hubs and the broader Houston-area corridor. That means the takeaway challenge is no longer simply moving gas out of West Texas. It also involves ensuring sufficient downstream infrastructure to carry those volumes from Gulf Coast market hubs to LNG export facilities (more on that below). Kinder Morgan’s Gulf Coast Express expansion (0.57 Bcf/d; aqua-blue line in Figure 1 below) is already flowing more gas to the Agua Dulce Hub in South Texas. This lifts the pipeline’s total capacity to 2.6 Bcf/d and has helped the Waha Hub recover from negative prices, though it has not fully resolved Permian takeaway constraints. Energy Transfer’s Hugh Brinson Pipeline (blue line) is starting to ramp up flows to Northeast Texas. It will eventually have a capacity of 2.2 Bcf/d. The Blackcomb Pipeline (dashed red line) is set to enter service later this year, providing an extra 2.5 Bcf/d of takeaway to Agua Dulce, and the planned 2.4-Bcf/d Traverse Pipeline (not shown) would provide onward access from Agua Dulce to Katy/Houston in 2027.
Center of My Universe – A New Bidirectional Header Aims to Facilitate Rising Gas Flows Through Katy | RBN Energy - Massive volumes of mostly Permian-sourced natural gas are already converging on the Katy, TX, area just west of Houston, and much more will be arriving soon as planned pipelines — including the newly proposed, 4.5-Bcf/d Solitude Pipeline System — come online in the months and years ahead. Now, a new, bidirectional header system is being built to help ease the flow of gas through the increasingly important Katy Hub, which serves as a key aggregation and distribution point for gas bound for existing and planned Gulf Coast industrial and power-generation load as well as a slew of LNG export terminals. In today’s RBN blog, we’ll discuss the Aspen Katy Hub project, which is slated for startup early next year. Consider for a moment a conventional cloverleaf interchange where two multilane highways intersect. It generally works well, at least as long as the volume of car-and-truck traffic doesn’t get out of hand. But when volumes soar and the traffic jams, highway engineers often turn to “stacked” interchanges with several “flyover” ramps that help speed the transfer of vehicles from one highway to the other. As it turns out, one of the most amazing of these transportation “spaghetti bowls” is in Katy itself, where Interstate 10 (aka the Katy Freeway) and State Highway 99 (aka the Grand Parkway) meet — see photo below.With that image in mind, consider the Aspen Katy Hub project, a bidirectional header system being planned by Aspen Midstream, a Dallas-based company backed by EnCap Flatrock Midstream. Aspen Midstream is already an active player in the region. In the late 2010s and early 2020s, it built:
- An extensive high-pressure, low-nitrogen (N2) gas gathering system (lavender lines in Figure 1 below) in the northeastern Eagle Ford — more specifically, the Austin Chalk/Gidding Field area in Fayette and Washington counties.
- A 200-MMcf/d gas processing plant (Battle Horse; magenta pentagon) and 260 MMcf/d of amine treating facilities for carbon dioxide (CO2) removal.
- The 57-mile, 30-inch-diameter AMP Intrastate Pipeline (green line), a residue-gas pipeline from the Battle Horse plant to the Katy Hub (white circle).
Along its way to Katy, the pipeline interconnects with both the in-service, 2.5-Bcf/d Matterhorn Express pipeline (yellow line), which runs from the Permian’s Waha Hub to the Katy area, and the under-construction, 3.5-Bcf/d Blackfin Pipeline (dashed red line), which will run from just west of Katy to just north of Beaumont, TX, and is slated to come online in a few months.In May, Aspen Midstream reached a final investment decision (FID) on its Aspen Katy Hub project, which calls for installing new low- and high-pressure header systems and extensive compression capacity near the current terminus of the company’s AMP Intrastate Pipeline at the Katy Hub. Most of that new infrastructure will be built within the bounds of a 65-acre, Aspen Midstream-owned site that adjoins the existing hub, providing both the footprint for the initial buildout and room for future expansion. The Aspen Katy Hub project is backed by long-term, take-or-pay contracts with investment-grade shippers — both those bringing gas to Katy and sending it out.Before we go further, we should provide some background on the Katy Hub and what’s already there. The Katy area, spanning parts of Fort Bend and Waller counties, through the middle years of the 20th century was primarily known for natural gas production. The volumes produced by the extensive gas fields there declined in the ensuing decades, and in the mid-1990s a massive, depleted reservoir was repurposed as an underground gas storage facility. Enstor, then part of ScottishPower’s PPM Energy subsidiary*, purchased the storage facility in 2004 and built out a dual header system that now connects the company’s 23.5 Bcf of Katy storage capacity to 16 gas pipelines that flow into and out of the hub (see Figure 2 below).For many years now, Enstor’s Katy Hub (also known as Katy Storage & Transportation) has served as a critically important gas-transportation junction/switching station and one of the U.S.’s most liquid gas trading hubs. Notably, its depleted-reservoir storage facility, with a gas-injection rate of up to about 750 MMcf/d and a withdrawal rate of up to ~700 MMcf/d, provides a physical buffer for gas — receiving gas when regional supply exceeds demand and sending gas out when demand exceeds supply. The rapid growth in Permian crude oil production — and, more relevant to our discussion today, the boom in associated gas production in West Texas and southeastern New Mexico in the early 2020s — has spurred the development of several new, high-capacity gas pipelines from the Permian to the Katy area. These include the 2.5-Bcf/d Matterhorn Express (yellow line in Figure 3 below; already online), the 3.7-Bcf/d Eiger Express (dashed orange line; scheduled to come online in 2028-29), and the recently announced, 4.5-Bcf/d Solitude Pipeline System (dashed blue line; online in 2029-30).As new takeaway capacity eases the Permian’s long-running egress constraints, an increasing share of the gas leaving West Texas will need to be sorted, redirected and moved onward once it reaches the Gulf Coast, increasing the importance of hubs like Katy.Other planned pipelines designed to move large volumes of gas up and down the Texas coast also will flow to or through the Katy area, including the 3.5-Bcf/d Blackfin Pipeline (dashed red line; online in Q4 2026 or Q1 2027); the 2-Bcf/d Trident Pipeline from Katy to the Golden Pass LNG terminal in Port Arthur, TX (dashed pink line; 1.5 Bcf/d online in Q1 2027 and an additional 500 MMcf/d in Q4 2028); the 2-Bcf/d Traverse Pipeline between South Texas’s Agua Dulce Hub and the Katy area (dashed purple line; online in H2 2027); and the 2.5-Bcf/d Mustang Express system (dashed green line; online in 2028-29). Note that Mustang Express’s mainline will run from Katy to Port Arthur, while its Cougar Lateral will connect Katy and Enbridge’s Tres Palacios gas storage facility (magenta tank icon) in Matagorda County.Much as fast-rising traffic volumes through the Katy Freeway/Grand Parkway interchange led transportation planners to make major improvements there a dozen years ago, the prospect of sharply increasing volumes of gas heading to and out of Katy led Aspen Midstream to pursue the development of its Aspen Katy Hub project. The new hub (dark-blue circle in Figure 4 below) will consist of two new, parallel, 30/36-inch-diameter header systems, each of them several thousand feet in length. One of the headers will be low-pressure and the other will be high-pressure to accommodate the widely varying gas pressure in the pipelines that will connect to it. The header systems will be linked to Enstor’s storage facility and at least a half-dozen pipelines, including the Atmos Energy system, Matterhorn Express (MXP), Kinder Morgan Texas Pipeline (KMTP) and Kinder’s recently acquired Monument Pipeline.Aspen Midstream also is installing a large, central compressor station at the site to enable the rerouting, compression/decompression and switching of up to 3 Bcf/d of gas flows on the header systems. The station also will enable bilateral flows on the company’s AMP Intrastate Pipeline (also known as the Austin Chalk Extension, or ACE), turning that pipe into a western extension of the new header systems and letting gas flow west from Katy to Blackfin. (The compressor station and header systems are being developed on Aspen Midstream’s fully owned, 65-acre footprint, with the facilities designed to allow for additional compression in the future, if needed.) The new compressor capacity, the new header systems, and the pipeline and storage interconnections are expected not only to help minimize future gas-flow bottlenecks in the Katy area but also to provide shippers with greater flexibility to source, redirect and wheel gas among the growing number of pipelines converging there. That flexibility should become increasingly valuable and will help speed the flow of gas through the Katy area as new pipelines come online, new power plants are built in the region, and new LNG export terminals are added along the coasts of both Texas and southwestern Louisiana. Aspen Midstream’s Katy project is yet another example of the extraordinary and ongoing buildout of new, gas-related infrastructure in the Lone Star State — gas gathering systems, gas processing plants, long-haul pipelines, hubs like Waha and Katy, gas-fired power plants, and new LNG export capacity.
Here You Come Again – Is Gas Production in the San Juan Basin’s Mancos Shale About to Rebound? | RBN Energy - A small cadre of E&Ps active in the San Juan Basin’s Mancos Shale is anticipating breakout growth in natural gas production there if and when gas prices rise, and a well-known midstreamer is planning what could eventually be a high-capacity gas pipeline to the burgeoning Arizona market. Still to be determined, however, is whether the moonscape-like region along the New Mexico-Colorado border emerges as a mini-Haynesville or the optimism withers and dies under the hot desert sun. In today’s RBN blog, we discuss what producers have been saying about their results in — and hopes for — the Mancos and the plan by Tallgrass Energy to build a new, large-diameter pipeline out of the play.In our 2026 prognostications blog back in January, we said, “There’s been a lot of market buzz around a handful of niche gas plays that share a common profile: the gas is dry, wells are deeper than legacy development in the area, reservoirs are often overpressured, initial production (IP) rates are high, and economics look compelling.” We noted that in the San Juan Basin, “operators are ignoring legacy coalbed methane and targeting the deeper, horizontally drilled Mancos Shale. Our prognostication? These smaller ‘dry-gas islands’ ... are likely to command much more attention in 2026.”In fact, there has been a lot of talk about the Mancos this year — and a major acquisition (following a big deal last year) — but it’s likely that the production breakout some are predicting may still be a year or two away (and maybe more).First, a little history. Gas production in the San Juan Basin in northwestern New Mexico and southwestern Colorado has experienced a lot of ups and downs since the first commercially successful gas well was drilled there 105 years ago. In the years up to and just after World War II, the challenge was getting gas to market; the San Juan was hundreds of miles from large population centers and there was hardly any pipeline infrastructure in place. The completion of the El Paso Natural Gas (EPNG) pipeline to California in the early 1950s spurred a boom in conventional gas production in the basin, and (after a handful of mini-booms and mini-busts) there was a late-century surge in coalbed methane production from the uppermost Fruitland Formation (dark-brown layer on right side of Figure 1 below). By 2000, the San Juan Basin was among the U.S.’s top gas production areas, churning out nearly 4.5 Bcf/d of gross gas, or about 8% of total U.S. onshore production at the time. But gas production there has been sliding over the past quarter-century. As we said a while back in I‘m Still Standing, production in the three counties that account for virtually all the San Juan’s gas (Rio Arriba and San Juan counties in New Mexico and La Plata County in Colorado) fell to 3 Bcf/d or so by the mid-2010s and about 2 Bcf/d in recent years — no slouch, certainly, but no Marcellus, Permian or Haynesville either.That may be changing, according to E&Ps active in the Mancos Shale (medium-gray layer on right side of Figure 1), a thick marine shale formation located several thousand feet below ground level. Gas production from horizontal drilling in the Mancos geologic layer (see Figure 2 below) increased from less than 100 MMcf/d in the first half of 2021 to more than 500 MMcf/d from December 2025 through March 2026 before sliding to less than 400 MMcf/d in April, May and June. Producers there attributed the recent decline to lower regional gas prices and, in response to the Iran conflict, a shift by at least a couple of E&Ps to crude-oil-focused drilling in other U.S. playsDespite sagging production lately, there’s optimism among Mancos Shale E&Ps that it will shine in time. “Our Mancos Shale position represents one of the most compelling emerging natural gas opportunities in North America,” Mach Natural Resources CEO Tom Ward said during the company’s August 7 earnings call. “The well performance rivals that of the better-known Haynesville and Marcellus shale plays, with operators recently reporting Mancos initial production rates exceeding 25 MMcf/d of gas.”Mach Natural Resources only entered the San Juan/Mancos Shale last September, when it closed on the acquisition of international asset manager IKAV Energy’s San Juan Basin assets. That $771 million transaction gave Mach 570,000 net acres and 336 MMcf/d of gas production in the San Juan — most of it coalbed methane and gas from conventional wells.Ward noted during the call that the cost of a typical 3-mile lateral in the Mancos Shale has been declining fast over the past couple of years, from nearly $20 million to less than $15 million, with the expectation that costs for the E&P’s ongoing drilling program will be “in the $13 million range for a completed well.” He added that the San Juan Basin more generally “benefits from a mature natural gas transportation network developed over decades of conventional gas production. We expect over the next five years that additional takeaway capacity will be installed to get to premium gas markets of Arizona” as well as LNG export markets in western Mexico. (More on gas takeaway pipelines and regional markets later.)Woodside Energy has placed its Beaumont New Ammonia facility under strategic review and is evaluating its options for the site, the company said during its H1 2026 earnings presentation on August 25. CEO Liz Westcott said the company’s assets “must all compete for capital equally,” and that new energy opportunities must be supported by clear customer demands and commercial markets and compete for capital with other investment opportunities. An even larger M&A deal happened just a couple of months ago: In June, asset management and investment firm Sixth Street Partners acquired privately held LOGOS Energy for about $1 billion. LOGOS has more than 240,000 net acres in the heart of the Mancos Shale production area and for the past couple of years has accounted for a substantial portion — typically more than 60% — of total gas production from horizontal wells there.Back in January, LOGOS Energy provided a detailed report on what it called “record-breaking results from its 2025 Mancos Shale development program,” noting that its operated production had tripled since 2022 and that the company had drilled “28 of the top 36 producing wells in San Juan Basin history ranked by peak monthly production.” More specifically, LOGOS said that its Rosa Unit 756H in the core of the Mancos just south of the Colorado-New Mexico border achieved a peak IP30 of 26.6 MMcfe/d from about 13,700 feet of completed lateral, “the highest 30-day rate ever recorded in the basin.” It said that the milestone followed the E&P’s 2024 success with Rosa Unit 704H, which reached 25.5 MMcfe/d from a similar-length lateral.LOGOS Energy also has been successful in the Mancos Shale across the state line. In July 2025, it placed online its first Mancos horizontal well in Colorado, the Ignacio 33-7 29P. That well had a peak IP30 of 19.9 MMcfe/d, LOGOS said, adding that the E&P “believes these results demonstrate the consistency of the Mancos reservoir across its acreage in both New Mexico and Colorado.”Other leading unconventional producers in the Mancos Shale include Enduring Resources and Hilcorp Energy, the latter of which is also a top producer of coalbed methane in the San Juan Basin. It’s common among E&Ps in the Mancos to be thinking — and talking — more medium- and long-term than next month or even next year. At a recent energy conference, Brent Clum, co-CEO at TXO Partners, a smaller, privately held E&P, said that if you asked executives at the company the past couple of years what their plans were for the Mancos, “we would tell you next year we're going to drill ... and do a two- to four-well program ... and every year the commodity prices don’t really allow us to do that. I would expect once we commit to drilling wells there, you will see us spend meaningful capital.”Clum added, “At this point, it's probably not going to be 2027. Maybe if commodity markets change in that regard. We think we probably need a $3.50 to $4 (per MMBtu) realized price in the basin, and basis has not been particularly favorable in the San Juan Basin in the last 18 months.” Gas produced in the San Juan Basin typically sells at a significant discount to Henry Hub — generally between $0.40 and $1.10/MMBtu in recent months, with a wider basis during the shoulder months when power-sector demand is lower.
Diesel Disaster Looms After Gas Price-Spike - The exploding cost of energy is most obviously being felt at the gasoline pumps for Americans as evidenced in this Visual Capitalist graphic where prices in some states are up over 60% in six months in the wake of the Iran war. While Gasoline is the biggest visible causality of the war, the even bigger one as we shall see is Diesel prices at the pump. The thing is, diesel is more prevalent in use globally and factors into many things that will be seeing increased costs in 2027 like food (Wheat is up over 50% this year) and finished goods. Here then is Goldman’s take on the diesel disaster we are in the middle of right now. Siphoning off the SPR to keep oil prices down has limited success of late. But there is no way to keep crack spreads down when refining capacity is maxed out and the economy needs diesel . Diesel markets entered September under renewed pressure after further US-Iran strikes pushed Brent crude above $91 a barrel and US diesel crack spreads back toward $100. The move extends a refined-products shortage that has been building since spring, as disruptions across the Persian Gulf and Russia reduce the world’s ability to convert crude oil into diesel, gasoline and jet fuel. In an Aug. 28 report titled “Higher Product Margins for Longer on Higher Outages and Lower Stocks,” Goldman analysts Yulia Zhestkova Grigsby, Filippo Cuscito and Daan Struyven argue that geopolitical disruptions have intensified an existing shortage of refining capacity. They expect product margins to remain elevated through 2027 as refinery outages restrict production, inventories decline and geopolitical uncertainty adds a security premium to prices. Global refined-product prices remain nearly $50 higher than a year ago after doubling during the first two months of the US-Iran war. Diesel contributed more than 40% of the $40-per-barrel increase in average wholesale product prices since the end of February, making it the largest driver of the rally. The supply losses are concentrated in regions that produce high volumes of diesel and jet fuel. Middle Eastern and Russian refineries have relatively high middle-distillate yields, while much of the disrupted crude supply involves heavier grades that are particularly suitable for diesel production. Seasonal demand should also favor diesel as gasoline consumption weakens after summer and heating demand strengthens into winter. The larger rise in product margins relative to crude reflects a sharper contraction in refined-product supply. Diesel and jet fuel margins are approximately three times their year-earlier levels, while dated Brent has risen 34%. Global refined-product exports have declined by 6 million barrels a day, or 25%, from a year earlier, with the Persian Gulf and Russia responsible for three-quarters of the reduction. Although Gulf crude exports have recovered to an estimated 70% to 80% of prewar levels, the region’s product exports remain at only 40%. Russian refinery runs have also fallen following repeated strikes, contributing to restrictions on most Russian gasoline and diesel exports through February. Global refinery outages are running approximately 60% above seasonal norms. Disrupted crude deliveries to Asia and restrictions on Chinese product exports have further limited the supply response, even as high margins encourage operating refineries to raise production.
Basket Case – The $100/bbl Diesel Crack, or How 2026 Exposed the Fragility of Global Refining | RBN Energy -For many, 2026 will be remembered as the year that diesel cracks topped the century mark ($100/bbl) for the first time. On August 17, the U.S. Gulf Coast diesel crack spread (vs. WTI Cushing) surpassed that sky-high level, and although it has since fallen into the $90s/bbl, it remains at levels never seen before, even exceeding those during the post-COVID boom year of 2022. In today’s RBN blog, we examine the various factors driving this run-up and what they say about the overall physical refined products market.Let’s start with some background about where things stand today. The global crude markets are not short of crude in the traditional sense (despite various geopolitically caused constraints). Instead, the world is struggling to refine enough crude oil into middle distillates to satisfy demand. That distinction is critical. According to the EIA’s Weekly Petroleum Status Report (WPSR) for the week ended August 21, distillate inventories fell for a fourth consecutive week, dropping to just above 103 MMbbl (see our Crude Billboard for more details). Distillate stocks are on track for their lowest end-of-month level since April 2005, and are the lowest they have been in the month of August since 1951. The events of 2026 have created a series of simultaneous disruptions to global refining capacity and refined-product flows. Middle Eastern refineries have been affected by damage inflicted during the Iran conflict and disruptions around the Strait of Hormuz, while Russian refining and exports have been repeatedly set back by Ukrainian drone attacks. This is all coming at a time when global refining capacity was already tight due to a number of permanent shutdowns (many during the COVID years) and limited new capacity coming online. As a result, even as U.S. refiners have been running exceptionally hard and exporting record volumes, the world supply of middle distillates (including diesel and jet fuel) is playing catch-up with demand, resulting in a market in which every additional diesel barrel has become extremely valuable.A crack spread measures the difference between the value of refined products and the crude oil used to produce them. A $100/bbl diesel crack (right end of orange line and left axis in Figure 1 below), therefore, does not mean a refinery is earning $100/bbl in net profit. Refiners still have operating expenses, transportation costs, financing costs, hedging effects and the economics of the other products produced by the refinery. Instead, it means that the market value of diesel relative to crude has become extraordinarily high. That distinction gives us the first major clue about what is happening. If crude (blue line and left axis) is expensive because the world is short of barrels, crude prices should be doing most of the work. But when diesel prices (green dashed line and right axis) rise dramatically relative to crude, the problem is further downstream.There are three major factors that have impacted the diesel markets on the supply side of the equation that have led to record-breaking cracks this year: the Middle East/Strait of Hormuz, Russia, and the cost of diesel and complying with the Renewable Fuel Standard (RFS). Let’s take them one by one.The Iran conflict has created one of the most significant disruptions to global petroleum markets in decades, with much of the market attention focused on crude oil and the potential loss of flows through the Strait of Hormuz. As we discussed in Stuck in a (Gulf) You Can’t Get Out Of, the volume of products flowing out of the strait has plummeted since the start of the war. After averaging an aggregate 3.3 MMb/d between January and February (sum of stacked areas in Figure 2 below), they cratered in the following months, dropping to as little as 100 Mb/d in April (dashed blue circle). Reuters estimates that more than 20% of Middle Eastern refining capacity has been knocked offline or impaired by physical damage, while the conflict has dramatically reduced normal flows through the region. Global refinery runs fell by roughly 5.1 MMb/d year over year in Q2 2026. Middle Eastern refineries don't simply produce crude-derived products for their domestic markets. They are important suppliers of refined products to the rest of the world. And the Strait of Hormuz is typically weighted more toward diesel than other products as well. When those barrels disappear, Europe and Asia must find replacement supplies.That creates competition for diesel from every available exporting region. The market therefore moves from a relatively balanced system to a bidding process for the marginal barrel. The Middle East would have been a major problem even without the continued Ukrainian attacks on Russian refineries and other infrastructure, which have accelerated dramatically in the past few months in both volume and effectiveness, leading to major disruptions in refinery operations and petroleum exports (see Rock Bottom). Reuters reported in August that crude oil and petroleum products shipped by major Russian export terminals on its western side were running approximately 15% below plan. Disruptions around Novorossiysk, the Russian port city on the Black Sea in southern Russia, had significantly reduced shipments, as some cargoes were running more than two weeks behind schedule following disruptions associated with Ukrainian attacks. An estimated 700 Mb/d of Russian refining capacity was knocked out between January and May across 16 refineries, twice the number hit for the same period of 2025 and the attacks and impacts have only increased since then. In fact, estimated Russian refinery throughput dropped below 4 MMb/d in July and so far in August, equal to less than 60% of capacity, the lowest level in over 20 years. Net exports of gasoline, jet fuel/kerosene and diesel products by Russia plunged from 1.2 MMb/d in January to less than 100 Mb/d by July (far right of stacked bars in Figure 3 below). Russian net diesel exports (green bar segments) crashed from just above 1 MMb/d in January to 160 Mb/d in July, with net gasoline exports (red bar segments) and jet fuel/kerosene exports (blue bar segments) even dropping into negative territory (indicating Russia was a net importer of these products in those months). We’ll note here that Russia instituted an official export ban on diesel beginning on July 8, so as that becomes fully enacted, exports have continued to fall and will approach zero. (There are always some exceptions to bans of this type.)Russian and Persian Gulf diesel has been hard to replace because of a lack of spare refining capacity and a lack of strategic reserves. We came into March with significant excess global crude production capacity and significant strategic reserves, which the world has leaned on over the past several months. Crude prices have risen meaningfully from before the U.S.-Iran war and have seen significant volatility, but these buffers have, for the most part, kept them under $100/bbl. The buffers on the refining side were much smaller, allowing for the much larger rise in crack spreads.The third piece is not the price of renewable diesel itself. It is the cost of complying with the RFS. On March 27, the Environmental Protection Agency (EPA) finalized the highest renewable-fuel requirements in the program's history, including a 70% reallocation of earlier small-refinery exemptions. (The required minimum is known as the Renewable Volume Obligation, or RVO.) The EPA estimates that meeting the new standards will require biodiesel and renewable diesel production and use to rise more than 60% from 2025. By early June, D4 and D6 Renewable Identification Number (RIN) prices had roughly doubled from the start of the year and were trading near record highs, as we explained in Runaway. (A RIN is the regulatory mechanism for tracking the production and blending of renewable fuels and also allows refiners and importers to prove they’ve met their RVO mandates.)Feedstocks are the other side of that equation. Strong domestic demand for soybean oil, tallow, used cooking oil and other fats has pushed those feedstocks higher relative to petroleum diesel, widening the soybean-oil-to-ULSD, or BOHO, spread. As that gap widens, the marginal biodiesel or renewable diesel producer needs a more valuable RIN to stay economic. In 2026, RIN values rose even faster than BOHO, improving producer margins but sharply increasing the compliance cost borne by obligated refiners and importers.That distinction matters for the $100/bbl number. The RIN obligation is passed through in the wholesale price of the petroleum component, so an unadjusted ULSD-minus-crude crack includes the total RVO cost embedded in the ULSD price. An obligated refiner must surrender those RINs, whether they are purchased or generated elsewhere in its system. Subtracting the per-gallon total RVO cost (multiplied by 42) gives a much better RIN-adjusted diesel crack. The physical diesel market is still extremely tight, but the headline crack overstates the margin available to an obligated refiner by the RIN component.The high cracks tell a complex story. Gulf refinery and shipping disruptions, together with the loss of Russian exports, have created a real shortage of immediately available diesel-making capacity. Strong March RVOs and a wider BOHO spread have also raised RIN costs, lifting the U.S. diesel price and the gross crack through compliance-cost pass-through. In our next blog, we’ll look at the indicators that will help tell us whether the squeeze is easing (or worsening).
U.S. Diesel Prices Hit All-Time High as Global Fuel Squeeze Deepens | OilPrice.com -The average U.S. diesel price hit a record high late on Thursday, exceeding the previous record from 2022, as the Middle East crisis tightened global fuel markets and sent prices soaring this summer. As of Thursday afternoon, the live U.S. national average price of diesel set a new record at $5.820 per gallon, according to GasBuddy data. This average price has now surpassed the previous daily $5.819 per gallon all-time high that occurred June 17, 2022, Patrick De Haan, head of petroleum analysis at GasBuddy, said.Record-high diesel prices are a major concern, including for the U.S. economy and the interest rate path of the Fed, as diesel is essential for economic growth and inflation in the price of goods.Moreover, diesel demand is further set to grow in the coming weeks and months with the harvest season for the farmers and the holiday season for retailers, who will need to haul more goods with trucks to stock up for the holidays.Diesel markets in the United States and globally have severely tightened in recent weeks, amid crippled fuel supply from the Middle East and Russia, due to the Iran and Ukraine wars, rising seasonal demand with the harvest season, and insufficient capacity elsewhere to compensate for the lost diesel flows from the Strait of Hormuz and Russia.The re-escalation in the Middle East and the Russian ban on diesel exports amid incessant Ukrainian drone attacks on refineries pushed middle distillate cracks to record highs this week.U.S. diesel prices have been rallying this week, and now they have hit an all-time high, which analysts, including GasBuddy, expected to occur before Labor Day.Meanwhile, the national average price of gasoline at $4.125 per gallon, per GasBuddy live data, is now 92 cents above Labor Day 2025 and on track for the most expensive gasoline price in nominal terms for a Labor Day weekend ever. This Labor Day weekend will cost Americans about $1.39 billion more on gasoline spending compared to last year, GasBuddy’s De Haan said.
US diesel prices hit a record high at $5.85 pushing up transportation costs for a long list of goods (AP) — Diesel hit a record price in the U.S. on Friday, soaring to an average of $5.85 a gallon for the first time as the six-month war with Iran disrupts the world’s flow of fuel. Because diesel is used for many freight and delivery networks, higher diesel prices mean higher transportation costs for a long list of everyday goods. Some businesses have already passed on costs to consumers in the form of added fees on online orders and packages in the mail. And shoppers may see more and more sticker shock trickle down to store shelves. One of the most immediate strains is being felt in the grocery aisle, particularly with produce, meat and other perishable foods that need to be hauled in and restocked frequently — or even harvested using diesel-powered farm equipment. It can take time for all of those costs to trickle down. Still, experts warn that price hikes could mount the longer diesel remains expensive. A range of other products are also transported by diesel trucks, trains and boats, including clothing, cosmetics and furniture.Diesel fuel has hit a new record price in the US. AP correspondent Donna Warder reports.This could add to Republicans’ political challenges ahead of November’s midterm elections, with many voters already sour on President Donald Trump’s management of the economy and fallout of the war he launched. AP-NORC polling this summer showed 2 out of 3 U.S. adults disapproved of how Trump is handling the economy.The price for regular gasoline has also been going up, although not as fast as the price of diesel. The average price was $4.15 a gallon, compared with $3.20 at this time last year, according to motor club AAA, which says gas has never been above $4 a gallon on Labor Day.American diesel prices are now nearly 56% more expensive than they were before the U.S. and Israel launched their war against Iran in late February, when the national average sat at about $3.76 per gallon per AAA. Prices quickly climbed as the cost of crude oil — the main ingredient in diesel, as well as gasoline — soared amid supply chain disruptions across the Middle East, notably with most tanker traffic bottlenecked in the key Strait of Hormuz.Despite prices cooling some during hopes for peace earlier in the summer, oil has now renewed its climb as fighting once more escalates between the U.S. and Iran. Brent crude, the international standard, was trading at more than $95 a barrel Friday, up from roughly $70 before the war. Prices at the pump always follow closely behind. The last time businesses and drivers saw sky-high fuel prices was in June 2022, when diesel reached nearly $5.82 a gallon on average months after the Ukraine war began and world leaders imposed sanctions against Russia, a leading oil producer.When adjusted for inflation, however, prices have been higher in the past. Ahead of the 2008 financial crisis, for example, diesel hit about $4.74 a gallon — equivalent to $7.20 in 2026, according to the government’s latest data. And 2022’s record of nearly $5.82 would be about $6.56 this year when accounting for inflation.
Enbridge temporarily halts work on Line 5 reroute after 1.3M gallon gas leak - Enbridge says it’s temporarily halting work on rerouting its Line 5 oil and gas pipeline following a gas leak in Iron County on Tuesday. The move comes after the Wisconsin Department of Natural Resources asked the company to halt work until a gas leak is resolved and measures are in place to prevent future spills. Enbridge estimates around 31,000 barrels, or 1.3 million gallons, of natural gas liquids containing mainly propane and butane vaporized into the atmosphere after a subcontractor’s unoccupied truck rolled into an excavation site, striking the pipeline on Sitan Road near Saxon.Enbridge spokesperson Juli Kellner said in a statement that the safety of people, property and the environment is at the forefront of its activities. “This 48-hour period will commence on August 31, 2026, and will reinforce our existing safety practices and identify opportunities to further enhance our strong safety culture,” Kellner wrote.The company said around 150 people are responding to the leak. Local emergency crews have left the site as a private contractor has arrived to support the response. No injuries have been reported. A nearby home was evacuated, and power was shut off to 55 residents. Electricity was restored Thursday to all but five homeowners. Line 5 remains shut down.Enbridge began using trailer-mounted flare stacks that were brought in over the weekend to begin burning off around 2,000 barrels, or 84,000 gallons, of remaining natural gas liquids in a safe and controlled manner.“Extensive air monitoring will continue during this work, at the flare site, the incident site, and in the surrounding area,” Kellner said. “While monitoring continues to show safe air quality where crews are working, the half mile evacuation zone around the incident remains in place, as does the ‘no-fly’ zone over the site issued by the Iron County Sheriff.”The company has been working with refineries to reduce the effects of the shutdown and hopes to restore service to the pipeline by Sept. 5. Enbridge’s Line 5 carries up to 23 million gallons of crude oil and natural gas liquids daily from Superior to Sarnia, Ontario. Construction of Enbridge’s $1 billion reroute of Line 5 has been ongoing. The company is building a new 41-mile stretch around the Bad River Band of Lake Superior Chippewa’s reservation in Ashland and Iron counties. The 30-inch pipeline runs 645 miles from Superior through northern Wisconsin and Michigan to Sarnia, Ontario.Enbridge said construction crews have completed about 65 percent of the Line 5 reroute around the reservation of the Bad River tribe. Crews have finished boring 25 underground tunnels to install the pipe and completed horizontal directional drilling at three sites. The company has now reached peak construction with around 700 workers on the project.Details of the leak still remain unknown. It’s not clear what led the truck to roll into the excavation site. In a Thursday letter, DNR Secretary Karen Hyun said the agency is “deeply concerned” by the spill and “immensely frustrated” by other events where the company has failed to comply with state regulations.The DNR has asked for multiple details on the release. On Friday, the agency said it may halt work on the company’s project to enforce compliance with state permits granted to Enbridge. The DNR said it hasn’t been authorized to access the site due to safety concerns, and the federal Pipeline Hazardous Materials Safety Administration is the lead agency on site. An investigator from PHMSA has been deployed to investigate the incident.In 2020, Enbridge proposed the reroute after the Bad River tribe sued the company in 2019 to shut down and remove Line 5 from tribal lands where Enbridge lacked easements for the pipeline. Three years ago, a federal judge found the company was trespassing and ordered Enbridge to pay roughly $5 million and shut down or reroute Line 5 by June of this year. The tribe and Enbridge appealed the decision, and the shutdown order was placed on hold this year.Earlier this month, a federal appeals panel ruled that Enbridge has been trespassing and must remove the pipeline from the Bad River reservation, but it gave the company more time to complete the Line 5 reroute.At least four releases of drilling fluid, or frac-outs, have occurred on the Line 5 project, ranging from roughly 5 gallons to up to 1,900 gallons spilled in late June. A DNR spokesperson said the agency has issued four notices of non-compliance on the project, all of which have been resolved.
LINE 5 SHUTDOWN – Canada /U.S. Economic Collaborations Becoming Even More Complicated - Since October 1, 1977, the Enbridge Line 5 has been protected by a 1977 treaty between the United States and Canada regarding the flow of oil and natural gas across borders. The treaty has specific language regarding the rights of both countries and is enacted: “Believing that pipelines can be an efficient, economical and safe means of transporting hydrocarbons from producing areas to consumers, in both Canada and the United States.” Article II of the treaty states “No public authority in the territory of either Party shall institute any measures, other than those provided for in Article V, which are intended to, or which would have the effect of, impeding, diverting, redirecting or interfering with in any way the transmission of hydrocarbon in transit.” The shutdown of Line 5 has been the focus of Michigan Governor Gretchen Whitmer since 2019, and that fight has held the spotlight for years. But a quieter dispute has been flying under the radar for many years. About 12 miles of Enbridge’s Line 5 pipeline runs across the Bad River Band of Lake Superior’s reservation along the shores of Lake Superior. The tribe sued Enbridge in 2019 to force the company to remove the section from its land, arguing land easements allowing operation expired six years earlier and the 73-year-old pipeline was prone to a catastrophic spill. In 2023, a federal judge gave Enbridge 3 years to close Line 5 on Bad River tribal land, giving the company until June 2026 to remove the segment from the reservation. The Bad River and conservation groups want the line completely shut down and have kept the reroute project tied up with legal challenges. Impacts of a Possible Shutdown According to Enbridge’s analyses, published on their website, the ramifications of the shutdown of Line 5 are clearly equally detrimental to both U.S. and Canadian economies. “Shutting down Line 5 would have immediate and severe consequences on the economies of Michigan, Ohio, Ontario, and elsewhere. Refineries served by Enbridge in Michigan, Ohio, Pennsylvania, Ontario and Quebec would receive approximately 45% less crude from Enbridge than their current demand. Michigan would face a 756,000-US-gallons-per-day propane supply shortage, since there are no short-term alternatives for transporting NGL to market.” In the current complicated and uneven energy landscape shaped by geopolitical tensions between the U.S. and Canada as well as abroad, the deadline delivered by the U.S. judge is critical. Information from PBF Energy, which operates one of two refineries in Toledo, provides perspective on the impact of a total Line 5 shutdown – whether for a reroute or for other reasons.
- “ A Line 5 shutdown would put Ohio refineries at risk. The closure of one of those refineries could result in the loss of $5.4 billion in annual economic output to Ohio and southeast Michigan, and the loss of thousands of direct and contracted skilled trades jobs.
- A Line 5 shutdown would compromise crude supply to 10 refineries in the region to varying degrees, directly affecting fuel prices.
- Closing Line 5 would hurt Ohio and Michigan economies and threaten union jobs.
- There are no viable options for replacing the volume of light crude delivered by Line 5, with rail able to provide less than 10% of that volume.
- A Line 5 shutdown puts at least 15% of northwest Ohio’s fuel supply at risk, as well as more than half of the jet fuel supplies for the Detroit Metro Airport.”
By February 2026, an administrative law judge upheld Enbridge’s state wetlands permit, removing the project’s last legal hurdle and clearing the way for construction. On Feb 24, 2026, Enbridge started the Line 5 reroute around Bad River Reservation. Just last month, on July 30th, a U.S. Federal Appeals Court affirmed that Enbridge had trespassed on Bad River Reservation, rejecting Enbridge’s challenge to the ordered Line 5 reroute and involving a recalculation of millions in awards for damages. So the latest development in this long saga of roadblocks to U.S./Canadian energy collaboration and energy security comes at the worst time- when U.S. and Canadian leaders are at loggerheads in a storm of retaliatory tariffs and measures that are becoming at times as ridiculous as the renaming of Lake Ontario. Last week, a collision resulted in a leak of natural gas liquids less than five miles east of the Bad River Band of Lake Superior Chippewa Indians Reservation, shutting down Line 5, which continues to be shut down this week as emergency response continues. On Tuesday, August 25th, a parked, unoccupied semi-truck rolled into the pipeline, striking it and resulting in the release of natural gas liquids, with witnesses reporting large white plumes of smoke emitting from the rupture. The section of pipeline was exposed at an open excavation site for a valve repair project near Saxon, Wisconsin, a section of the pipeline approximately 1.5 miles away from an ongoing project to re-route the pipeline so that it no longer passes through the Bad River Reservation. Local U.S. media reports that Enbridge currently estimates the return to service of Line 5 between Aug. 31 and Sept. 5, 2026. Considering the profound impacts of a Line 5 closure, even a brief shutdown, Canadian media is strangely quiet about this incident that would have wide impacts on operations in both countries-in Michigan, Ohio, Pennsylvania, Ontario and Quebec.
EIA: US crude inventories down 4.5 million bbl | Oil & Gas Journal - US crude oil inventories for the week ended Aug. 28, excluding the Strategic Petroleum Reserve, decreased by 4.5 million bbl from the previous week, according to data from the US Energy Information Administration (EIA). At 424.5 million bbl, US crude oil inventories are about 1% above the 5-year average for this time of year, the EIA report indicated. EIA said total motor gasoline inventories decreased by 1.2 million bbl from last week and are 6% below the 5-year average for this time of year. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories increased by 800,000 bbl last week and are 14% below the 5-year average for this time of year. Propane-propylene inventories decreased by 2.1 million bbl from last week and are 25% above the 5-year average for this time of year, EIA said. US crude oil refinery inputs averaged 17.5 million b/d for the week ended Aug. 28, which was 102,000 b/d more than the previous week’s average. Refineries operated at 98% of capacity. Gasoline production increased, averaging 9.8 million b/d. Distillate fuel production decreased, averaging 5.1 million b/d. US crude oil imports averaged 6.8 million b/d, up 612,000 b/d from the previous week. Over the last 4 weeks, crude oil imports averaged about 6.7 million b/d, 2% more than the same 4-week period last year. Total motor gasoline imports averaged 370,000 b/d. Distillate fuel imports averaged 113,000 b/d.
Turn, Turn, Turn — Commodity Price Swings Reshape E&P Earnings in Q2 2026 | RBN Energy --The second quarter of 2026 was a tale of two commodity markets for U.S. exploration and production companies. A 29% quarter-over-quarter increase in WTI oil prices to $92.53/bbl provided a more powerful tailwind for Oil-Weighted E&Ps, who experienced a pre-tax operating profit turnaround with a war-driven late Q1 price surge. In stark contrast, plunging natural gas prices wounded Gas-Weighted producers after bountiful Q1 results. In today’s RBN blog, we review the Q2 2026 results of the 37 publicly traded E&Ps we cover and analyze the remarkably wide performance gap they reveal.The oil price climb (gray line and right axis in Figure 1 below) from the Iran conflict and a spike in natural gas prices driven by an unusually cold winter across the eastern U.S. combined to double the average pre-tax profits for our 37-company universe from Q4 2025 to Q1 2026 to $15.12/boe, the highest result since mid-2023. The continuing rise in oil prices spurred another 31% increase in pre-tax operating profits in Q2 2026 to $19.83/boe (far-right blue bar and left axis), the richest since 2022. Cash flow also reached a post-2022 peak, increasing 8% to $29.72/boe (far-right orange bar and left axis). Upstream revenues rose 6% to $44.67/boe. Costs provided little resistance to the improvement in commodity realizations. Lifting costs increased 2% to $12.71/boe, primarily because of a 16% increase in price-sensitive production taxes to $2.50/boe. Production costs declined 1% to $10.20/boe, while depreciation, depletion and amortization (DD&A) expenses increased 2% to $11.78/boe. Impairment charges, which had weighed heavily on earnings in recent quarters, virtually disappeared, declining 97% to just $0.09/boe, while exploration expenses fell 25% to $0.26/boe. However, the overall results show a wide variation in returns between companies with different portfolio weightings. The Oil-Weighted E&Ps more than doubled earnings and generated $40.16/boe of cash flow, while the Diversified producers also benefited handsomely from stronger crude prices. Gas-Weighted E&Ps moved sharply in the opposite direction, with earnings plunging 75% as Appalachian gas prices collapsed. With oil prices already retreating in the third quarter and Permian natural gas prices staging a dramatic recovery, the commodity-price deck is shifting again. The Q2 improvement was overwhelmingly a price story rather than a volume or cost story. Oil and gas production, at just under 1.5 billion boe, was up about 1% from Q1 2026. With production and underlying costs little changed, higher commodity realizations flowed directly through to revenues and the bottom line. The near disappearance of impairment charges provided an additional boost to reported earnings, although the rise in cash flow — which is unaffected by those non-cash charges — confirms the underlying improvement in operating performance. The earnings of the Oil-Weighted E&Ps more than doubled in Q2 2026 to $25.97/boe (far-right blue bar and left axis in Figure 2 below), up from $12.74/boe in Q1 2026 as WTI oil prices (gray line and right axis) surged 29% to $92.53/bbl. Cash flow (far-right orange bar and left axis) increased 38% to $40.16/boe, while upstream revenues rose 29% to $54.21/boe. However, extremely weak Waha natural gas prices somewhat dampened the revenue boost, averaging -$3.04/MMBtu during the quarter. The results demonstrate the considerable operating leverage these producers have to crude prices. A 29% increase in WTI was accompanied by a 104% increase in per-unit earnings, as most operating costs changed little compared with the first quarter. Cash flow responded less dramatically but still increased faster than crude prices, rising 38%. The primary cost offset was production taxes, which typically move with commodity prices and increased 30% to $3.39/boe. Four companies earned more than $2 billion during the quarter. ConocoPhillips led the way, posting a profit of $6.2 billion and generating $9.2 billion in cash flow. Occidental Petroleum earned $3 billion while generating nearly $5 billion in cash flow, Diamondback Energy posted a $2.5 billion profit and $3.8 billion in cash flow, and Devon Energy earned $2.3 billion while generating $3.7 billion. On a per-unit basis, California Resources posted the largest profit at $37.72/boe, while Talos Energy registered the strongest cash flow at nearly $60/boe.Reported oil and gas production by the peer group was down 3.1% in Q2 2026, primarily because of the impact of the Coterra Energy-Devon Energy merger, which closed May 7. Excluding Devon Energy from the comparison, peer-group oil and gas production was flat during the quarter. That lack of organic volume growth further underscores that Q2’s earnings improvement resulted primarily from stronger crude prices rather than increased production.For company-by-company results, including details on lifting costs, production costs, production taxes, DD&A expenses, impairment charges and exploration expenses, expand the tables below.The Diversified E&Ps also had a strong second quarter, with profits surging 71% to $20.90/boe (far-right blue bar and left axis in Figure 3 below). Cash flow (far-right orange bar and left axis) increased 16% to $32.93/boe, while upstream revenues rose 13% to $44.80/boe on the back of strong crude prices (gray line and right axis). Total costs declined 13% to $23.89/boe, primarily because of the near elimination of impairment charges. Lifting costs increased 4% to $11.87/boe as price-sensitive production taxes jumped 16% to $2.60/boe, while production costs increased just 1% to $9.27/boe. Impairment charges fell 96% to $0.16/boe, while exploration expenses increased 9% to $0.49/boe. EOG Resources posted the largest profit among the Diversified E&Ps at $2.2 billion while generating $3.3 billion in cash flow. Continental Resources was the only other company to eclipse the $1 billion earnings threshold, reporting $1.1 billion and generating $1.7 billion in cash flow. SM Energy ($987 million), APA Corp. ($981 million) and Ovintiv ($978 million) were close behind, with each generating between $1.5 billion and $1.6 billion in cash flow. On a per-unit basis, Magnolia Oil & Gas posted the group's highest earnings at $28.35/boe, while Murphy Oil led in cash flow at $45.36/boe.Oil and gas production by the group increased 0.6% to 418.3 MMboe in Q2 2026. SM Energy and Infinity Natural Resources posted production gains of 20% and 18%, respectively, largely reflecting acquisitions completed earlier this year.For company-by-company results, expand the table below.The Gas-Weighted E&Ps moved in the opposite direction during Q2. Earnings plunged 75% to $4.14/boe (far-right blue bar and left axis in Figure 4 below) as Appalachian gas prices (Transco Zone 6; gray line and right axis) fell sharply from $12.41/MMBtu to $2.24/MMBtu. Cash flow (far-right orange bar and left axis) declined 55% to $9.91/boe, while realized prices dropped 42% to $17.84/boe. Lower commodity prices did provide some relief on costs. Lifting costs declined 8% to $7.92/boe as production taxes fell 40% to $0.39/boe, while production costs declined 5% to $7.53/boe. DD&A expenses increased 6% to $5.67/boe. Impairment charges increased 73%, but remained negligible at just $0.03/boe, while exploration expenses declined 19% to $0.07/boe. The dramatic reversal from Q1 illustrates the Gas-Weighted group’s earnings sensitivity to short-term changes in commodity prices. Appalachian natural gas had been an important contributor to Q1 results, but the collapse in regional pricing erased much of that benefit just one quarter later. Unlike the Oil-Weighted E&Ps, whose relatively stable operating costs magnified the impact of rising crude prices, the Gas-Weighted E&Ps faced the same operating leverage working in reverse. EQT Corp. posted the largest profit and cash flow in the peer group during Q2 2026 at $369 million and $1.1 billion, respectively. Antero Resources ranked second in profits at $269 million, while Expand Energy was second in cash flow generation at $968 million. On a per-unit basis, Diversified Energy was the most profitable company in the Gas-Weighted group, earning $10.79/boe and generating a peer-leading $16.23/boe in cash flow. Its outperformance also illustrates the importance of commodity mix during the quarter. Although classified as a Gas-Weighted E&P, 14% of Diversified Energy's production was oil and another 15% was NGLs. That 29% liquids exposure provided an earnings buffer to weak natural gas prices.Oil and gas production by the gas-focused peer group increased 2% from the prior quarter. Comstock Resources posted a 15% gain, reflecting strong Haynesville drilling results, while Antero Resources increased production 9%, primarily through acquisitions.For company-by-company results, expand the table below.
BLM Moves to Fast-Track Oil Permits in Alaska Petroleum Reserve - The Bureau of Land Management wants to cut the permitting time for some oil and gas projects in Alaska’s National Petroleum Reserve to as little as 60 days, according to a Friday press release. The proposed rule would replace separate case-by-case reviews for qualifying production sites with a standardized process covering common, repeatable activities that BLM says have already been studied extensively. Rights-of-way and some drilling permit applications meeting predetermined criteria could receive decisions within 60 days. The National Petroleum Reserve-Alaska covers roughly 23 million acres on Alaska’s North Slope. About 3.5 million acres are currently under lease. There are considerably more leases to develop after this year. BLM’s March NPR-A auction drew bids on 187 tracts and generated more than $163 million, the highest revenue ever collected in a lease sale for the reserve. The auction also produced the largest number of tracts receiving bids and the second-largest acreage total sold in a single NPR-A sale. ExxonMobil, ConocoPhillips, and a Repsol-Shell consortium were among the successful bidders. Getting acreage leased and getting oil out of it are two very different timelines in Alaska. Operators still need drilling permits, rights-of-way and approvals for roads, pipelines, pads and other permanent infrastructure. BLM says more than two decades of permitting work in the reserve gives it enough environmental data to standardize reviews for projects similar to infrastructure already approved there. The proposal followed a petition from the Alaska Oil and Gas Association requesting a uniform approval process and a 60-day timeline for qualifying projects. BLM is preparing an environmental impact statement alongside the new rule. The agency has already rescinded a 2024 rule that restricted development in the reserve and reopened nearly 82% of the NPR-A to oil and gas leasing. The administration has also expanded leasing elsewhere in Alaska, including this year’s first auction of drilling rights in the Coastal Plain of the Arctic National Wildlife Refuge. The NPR-A proposal now enters a 60-day public comment period ending November 9. For companies holding acreage from the record March auction, the more immediate number is 60 days, which is the proposed clock for turning at least some permit applications into decisions.
Harvest Pushes Back Timeline for Reviving Alaska LNG Imports -Harvest Midstream said it is now aiming for early 2029 to begin importing LNG at the long dormant Kenai terminal in Alaska. At a Glance:
- Kenai LNG being repurposed
- Harvest had targeted 2028 startup
- Facility would serve Railbelt demand
LNG Canada Feedgas Demand Hits Six-Month Low Amid July Flare Repairs - LNG Canada's Kitimat terminal drew less feedgas in July than in any month since January, with export volumes falling over the same period as crews worked through mechanical repairs, according to regulatory and Kpler data. At a Glance:
- July exports fell to 10 cargoes
- Flare tip replaced during July repairs
- BC pipeline limits pinned Station 2
The Waiting Is the Hardest Part – West Coast LPG Export Capacity Set to Jump Next Year and Beyond | RBN Energy - The startup of two propane export terminals in British Columbia since 2019 has helped drive significant growth of Western Canadian LPG exports to Asia over the past several years, averaging nearly 150 Mb/d last year. With limited opportunities for expansions at those two terminals, as well as one in Washington state, AltaGas and partner Vopak have been busy building the first phase of what they hope will eventually become a 200-Mb/d (or larger) LPG export facility. The Ridley Island Energy Export Facility (REEF) will also be Canada’s first marine facility to move butane. In today’s RBN blog, the second of this short series, we’ll go over industry plans to more than double LPG export capacity on North America’s west coast over the next several years. As we said in Part 1, AltaGas recently announced a short delay to the planned startup of its 56-Mb/d REEF project on the northwestern coast of British Columbia (BC) from year-end 2026 to March 2027. Phase 1 of REEF is expected to be the first of several planned projects to add LPG export capacity along the BC coast over the next few years. That is coming at the same time that more LNG export capacity is also being built (see our Shut Up and Drive mini-series), and more crude oil pipeline capacity to the west coast is also in the works, as industry and governments in Canada look to expand hydrocarbon exports and further diversify customer bases.Total LPG marine export capacity from the area is currently about 180 Mb/d, comprised of 85 Mb/d of propane capacity at AltaGas and Vopak’s Ridley Island Propane Export Terminal (RIPET; orange diamond in Figure 1 below) near Prince Rupert, BC; 25 Mb/d of propane capacity at Pembina Pipeline’s Prince Rupert Terminal (PRT; blue diamond) about a mile east of RIPET; and 70 Mb/d of propane/butane capacity at AltaGas’s Ferndale facility (dark-green diamond) in Washington state. Japan, South Korea, and increasingly China have bought the vast majority of west coast LPG exports in recent years.
Trans Mountain Expects to Add 90 Mb/d Capacity by Year-End - The Trans Mountain pipeline's owner Trans Mountain Corporation said in its Q2 results press release on August 28 that it expects to increase the pipeline's "nominal system capacity by approximately 90,000 bpd by the end of 2026". Previously the company had been pointing to an early 2027 completion of the planned 90 Mb/d Drag-Reducing Agent (DRA) project (see our blog Kind of a Drag for an explanation of drag-reducing agents).Volumes on the pipeline system averaged 840 Mb/d in Q2, or 94% utilization of the system's 890 Mb/d capacity, an increase of 137 Mb/d vs. Q2 2025. Approximately 510 Mb/d went to the Westridge marine terminal for export, which saw 82 vessels loaded in the quarter vs. 56 in Q2 2025, 96 Mb/d was delivered to British Columbia receipt points, and 234 Mb/d delivered by pipeline to Washington State. While China continued to receive the bulk of exports out of the Westridge terminal, Q2 also saw an increase to shipments to India/Brunei (see green bars in the chart below).The target year-end 2028 start-up timing for the 210 Mb/d Mainline Optimization Project (MOP) was reiterated in the press release.
Canadian Refinery Runs - August Update | RBN Energy - Weekly Canadian refinery crude oil runs saw a dip in July, but had since recovered (see red line in left chart below), according to weekly data through August 4 released by the Canadian Energy Regulator on August 25. The drop in utilization was in Ontario (see red line in right chart below) and likely reflects unplanned downtime at the Nanticoke refinery noted by Imperial Oil on its Q2 conference call. Year-to-date through August 4, Canadian refinery crude throughput has averaged 1.634 Million b/d, up about 54 Mb/d year-over-year (see table below), boosted by a lack of downtime at refineries east of Ontario (see green line in right chart above). Note that this data is based on voluntary submissions from refinery operators, and excludes data for FCL's 130 Mb/d refinery in Regina, Saskatchewan.
‘Who knows if it will survive’: Experts question how long Trump’s Venezuela oil deal will last – --Oil company executives and Venezuela experts are looking skeptically at the Trump administration’s $100 billion plan to boost Venezuelan oil production, raising questions about whether the deal will yield significant oil any time soon — or ever. Under the deal the White House announced Monday, the United States would receive a 35 percent stake in oil company North American Blue Energy Partners to drill for oil in Venezuela, the latest instance of the Trump administration taking shares in a private business. As part of the deal, the U.S. would have “preferential access” to 20 percent of the oil the company produces at cost. The partnership, if successful, would kick-start oil production in Venezuela, something President Donald Trump has wanted since his administration plucked Venezuelan President Nicolás Maduro from power in January. Trump and the GOP are promoting increased imports of Venezuelan crude into the United States as a possible balm for the high fuel prices that have plagued voters since the U.S. launched its attacks against Iran in late February. Oil executives are warning, however, that the fields targeted for production will take years to develop and expressed little confidence that the White House announced with a company few are familiar with would lead to much.“Fuck all, what is this?” said an executive at one oil company granted anonymity to speak frankly about the administration’s plans. “This thing is way too big for a company with no capabilities and no credibility.” Some in Caracas, too, said the Trump administration’s support should extend to a wider range of firms, especially smaller operators.“Investing in one company could be a starting point, but I think it needs a bigger approach,” said Alejandro Sucre, a Caracas-based investor who is pitching a fund backing oil and mining projects in Venezuela. “You’re not going to give 65 billion barrels of reserves to one company, right? That doesn’t make any sense.”It’s not just industry officials expressing doubt. Giving the U.S. ownership of an asset seen as a national treasure is already drawing heat from across the political spectrum, according to Liliana Diaz, a senior fellow at the Atlantic Council Global Energy Center.“The criticism is arriving from opposite directions,” Diaz said. ”Hardliners object on sovereignty over the resource. The opposition objects on constitutional legitimacy. Something attacked from both flanks at once tends not to last, whatever its economics.”NABEP has become one of the largest private operators in Venezuela in recent years. The agreement gives the Barbados-based company the right to develop 65 billion barrels of crude across 17 Venezuelan fields and includes a near-term goal of increasing production to more than 1 million barrels a day.
Energy Secretary Wright Says Venezuela Could More Than Double Oil Production Venezuela’s crude oil production rate could double in the next few years thanks to new deals set to be signed with U.S. and other foreign energy companies, U.S. Energy Secretary Chris Wright has said. “The investment in these deals will massively grow available oil production, which will give downward pressure on oil prices, but the biggest kink right now in gasoline and diesel prices is refining capacity,” Wright said during a one-day visit to Caracas, as quoted by OilPrice. Venezuela’s peak oil production rate was about 3 million barrels daily, but that was in the late 1990s. Since then, amid U.S. sanctions and underinvestment, production has dropped to 1.25 million barrels daily this year. Exports are running slightly above 1 million barrels daily, with the biggest portion going to U.S. refiners along the Gulf Coast.Last week, news broke that the U.S. federal government was negotiating a direct ownership stake in the country’s high-yield field that contains combined reserves of 90 billion barrels of crude. At the end of last week, President Trump called the deal “historic”, covering 17 fields with target production of 1.5 million barrels per day. The deal will involve a U.S.-based company owned by a Venezuelan tycoon, which has already been granted 14 oil deals by the Venezuelan government.The U.S. government will have rights to a 35% stake in the company plus access to 20% of North American Blue Energy Partners’ production at cost. The U.S. federal government will also have the right of first refusal for the purchase of the other 80% of NABEP’s production from Venezuelan fields.Analysts have noted that such a major boost in Venezuelan crude oil production would require substantial investments, with Rystad Energy putting the total at some $180 billion, which would need to be invested over the next ten years.
Feedstock Is Not Fuel: Why Venezuelan Crude Is No Near-Term Fix - On August 27 2026, President Trump announced what he called the biggest oil deal in world history — a US-Venezuela agreement giving the United States majority control of more than 65 billion barrels of Venezuelan reserves, which he said would “substantially lower Gas Prices for all Americans.” The pitch landed with gasoline near $4.09 a gallon, about 27% higher than a year earlier and on track for the most expensive August on record, as a six-month Iran war and the Hormuz disruption kept a fifth of world supply under strain — and with the midterms two months away. Independent analysts noted the arithmetic fails on that timeline: the 30 to 50 million barrels Trump floated is less than half a day of global consumption, the 65 billion is an in-ground estimate rather than available supply, and any price effect would take years. Miller’s briefing goes underneath that objection to the more fundamental one: Venezuelan crude is the wrong substance to fix the shortage Americans feel at the pump. It is not a magical fix. In the near term it is not a fix at all. The shortage that bites right now is in product — diesel and jet fuel — and extra-heavy Venezuelan crude is not product. It is refinery feedstock. You cannot relieve a middle-distillate shortage with a barrel that still has to be diluted, blended, upgraded, coked, and hydroprocessed before it yields a usable gallon of anything. This is why the “turn Venezuela on” reflex fails on its own terms. Even setting aside whether Caracas can produce more, the barrels that already exist do not add supply where the market is tight. Prompt US cargoes would largely be diverted from Venezuela’s current buyers — China, India, Europe — not created on top of global production. That reshuffles refinery slates and trade routes; it does not repair a physical shortage. A barrel moved from a Chinese refiner to a US one is a change of address, not a new barrel, and certainly not a new gallon of jet fuel. The nature of the crude is the reason. Roughly three-quarters of Venezuelan production through 2028 is expected to be heavy, extra-heavy, or bitumen, with the Orinoco Belt supplying about 60%. That material is the raw input at the very front of the conversion process; the finished distillate barrel sits many capital-intensive steps downstream — coking and hydroprocessing capacity, hydrogen, refinery uptime, yields, distribution — none of which a cargo of Merey crude supplies. The price tells the same story: Merey 16 averaged $67.36/bbl in July 2026, about $12.35 under the OPEC basket, the market pricing in the cost of converting this crude into something useful. Venezuela cannot repair a current crude or middle-distillate shortage, because the missing piece was never the crude. Nor can the volume be conjured quickly. July 2026 output was near 1.1 million b/d — about a third of the 3.4 million b/d peak of 1998 — and the system that would lift it has been hollowed out: the EIA documents pipelines over 50 years old, power outages, constrained diluent, and impaired refineries, with PDVSA estimating some $8 billion for pipelines alone. Rystad puts full-cycle breakevens at $70–$80/bbl or higher and its base case adds only about 194,000 b/d through 4Q 2028; a return toward 3 million b/d would take well over $150 billion across 10–15 years. Large in-ground reserves, Miller stresses, are not deliverable supply — and the 65 billion barrels in the President’s announcement is exactly that kind of number: a resource estimate, not a delivery schedule. The strongest confirmation is not a model but the behavior of the companies that would have to fund the rebuild. At the White House on January 9 2026, shortly after the US removal of Maduro, Trump insisted the industry would spend more than $100 billion to rebuild Venezuela’s oil sector. The room did not agree. ExxonMobil’s Darren Woods told the President to his face that Venezuela is, as it stands, “uninvestable” — that durable legal frameworks, commercial terms, and stability must come first, and that Exxon would send only a technical team to assess. ConocoPhillips’ Ryan Lance said the system needs major restructuring first; both firms had their assets expropriated under Chávez, and by 30 January both Exxon and Chevron said they had no plans to raise Venezuela spending that year. The figures put before that meeting matched Miller’s: Rystad estimated roughly $110 billion merely to double output by 2030, and closer to $185 billion to climb back toward 2000-era levels. Also, Paul Saladino: "We have to deal with all the issues of collapsed infrastructure and a failed state." The one enthusiast underscores the point. Chevron — the sole US major already producing there, at nearly 250,000 b/d under a special license — says it could raise flows about 50% in under two years, but even that lifts Venezuela’s total only to just above 1.1 million b/d, against a peak near 4 million. Smaller entrants like Hunt Oil and SLB signed the first fresh PDVSA deals in August, but the supermajors best equipped to finance a rebuild are, on the record, declining to write the checks. When the people holding the capital call a resource uninvestable, it is not a near-term supply solution. Venezuela is a long-duration heavy-crude redevelopment option, not an emergency supply source — and specifically not a fuel solution. Existing cargoes can be rerouted, but that changes trade maps without adding a net barrel or a finished gallon; meaningful new production is years and well over a hundred billion dollars away, and the firms who would fund it have said so out loud. Whatever the “biggest oil deal in world history” is worth over a decade, it will not lower the price of diesel or jet fuel this year. The distillate shortage will not be solved in Caracas.
European Heat Widens LNG Price Premium Over Asia as Storage Clock Ticks - Cooling demand forecasts eased across both Europe and Asia this week, but European natural gas buyers are raising competitive bids for US LNG volumes as thin storage and Middle East supply risk outweigh temperatures. At a Glance:
TTF holds premium over JKM
Feedgas recovers from maintenance lows
Edouard spares Gulf gas production
Europe’s Fight for LNG Puts TTF Back on the Upswing - European natural gas prices spiked Monday as competition with Asia for LNG cargoes intensified amid renewed clashes between the United States and Iran. European Union natural gas storage chart showing inventories at 64.7% full as of Aug. 29, 2026, below the five-year average, with historical storage levels from 2021 through 2026. At a Glance:
Europe’s LNG imports highest since April
Asian demand remains strong
Hot weather forecast for both regions
Inflamed US-Iran Tensions Imperil Hormuz Shipping, Stoke LNG Supply Fears - Escalating US-Iran hostilities this week raised fresh concerns over prolonged disruptions to energy shipments through the Strait of Hormuz. The flare-up added to already simmering concerns about global LNG supply and could add demand for American exports — and impact pricing — should the war drag into the winter months.Map of Persian Gulf LNG import and export terminals near the Strait of Hormuz, including QatarEnergy, Al Zour, Bahrain LNG and UAE facilities. At a Glance:
US-Iran tensions flare up again
Hormuz vessel traffic pressured
Global LNG supplies at high risk
VLCC Freight Surge Squeezes the Asia Arb | RBN Energy - The cost to charter a Very Large Crude Carrier (VLCC) has quickly emerged as a growing headwind for U.S. Gulf Coast crude exports to Asia. Voyage costs for VLCCs to Asia surged 38% last week to $25.61 million per voyage (far right of green line in chart below), the highest since early March, when rates skyrocketed to above $29 million at the onset of the War in Iran. This recent move marks a sharp escalation in the cost of placing U.S. barrels into Asian markets and stands in stark contrast to USGC-to-Europe Aframax rates (red line in chart below), which fell 14% over the same period. As discussed in our Crude Voyager, this divergence has shifted relative freight economics increasingly in favor of shorter-haul Atlantic Basin movements, while raising the hurdle for U.S. crude to clear into Asia. The freight spike is particularly noteworthy given the simultaneous buildup in VLCC activity around the Gulf. Nine VLCCs entered the region last week, the highest count in six weeks, while five departed, leaving a sizable pipeline of vessels positioned for upcoming export programs. That creates an interesting tension in the market: vessel activity points toward stronger long-haul exports, but the cost of moving those barrels east has risen substantially. If VLCC rates remain elevated, Gulf Coast crude differentials or the Brent-WTI spread may need to weaken or widen, respectively, to restore Asian export economics.
Panic as oil spill pollutes Nembe Creek in Bayelsa There is panic in several fishing communities in Nembe Local Government Area of Bayelsa State following an oil spill from crude loading operations at Nembe Creek oilfield. The Nembe Creek oilfield within Oil Mining Lease 29 (OML) is operated by Nembe Exploration & Production Limited, formerly Aiteo Eastern Exploration and Production Limited. A field report by Environmental Conservation Agriculture and Rural Development (ECARD) stated that it observed crude oil along the creek and mangrove banks. Its Lead Field Monitor, Chief Alagoa Morris, said the pungent smell of crude oil became noticeable about two kilometres from Nembe Creek during the visit. ECARD said the spill had spread to several fishing settlements, with residents reporting loss of fishing activities and damage to fishing equipment. The paramount ruler of Nembe Creek communities, HRH Agent Waya, said the incident had worsened the hardship faced by residents. Waya said the community reported the spill to naval personnel after Aiteo officials allegedly failed to respond immediately to their concerns. He said women from the affected communities later protested at the Aiteo facility, demanding relief materials, assessment of damages and compensation. According to him, the affected communities requested relief materials within three days because residents could no longer engage in fishing. Waya said the spill reportedly occurred while crude oil was being loaded into a barge, which subsequently tilted and discharged crude into the river. He listed Mile 1, Mile 2, Mile 3, Roka, Williamkiri, Atonbarakiri, Korukiri and Madam Wanwakiri among the affected communities. Others, he said, included Ewelesuo, Kpongbokiri, Victorkiri, ‘Abuja’ 1, 2 and 3, Pipeline 1, 2, 3 and 4, Kalakububogo and Etikiri. The women leader, Mrs Ebi Otokolo, said the pollution had made the river waters unusable for fishing, domestic activities and other livelihood purposes. She said residents had been forced to remain indoors because of the crude oil odour, while fishermen could no longer access their means of livelihood. A community woman, Mrs Love Mark, said some fishing nets contaminated by crude oil had become unusable. Mark said individual fishing nets cost between N150,000 and N170,000, adding that affected residents needed urgent assistance from the operator. Also, a former youth president of neighbouring Ewelesuo community, Mr Daukoru Benjaka, called for the inclusion of the community and its fishing camps in the Joint Investigation Visit. Benjaka said the spill had affected fish catches and other aquatic resources, including periwinkles, while threatening the survival of fishing communities. ECARD said its observations showed substantial crude oil on the water and along mangrove roots, despite residents’ reports that tidal movement had thinned the pollution. The organisation said rising tides could carry crude oil deeper into the mangrove ecosystem and further affect aquatic organisms, including crabs, oysters and periwinkles. ECARD said information from the Bayelsa Ministry of Environment and Nembe Oil and Gas Committee indicated that the Joint Investigation Visit had identified operational failure as the cause. However, it said the volume of crude spilled and the extent of the affected area remained inconclusive as of Aug. 26. The organisation said the latest incident was part of a history of oil spills associated with operations in OML 29.
Iran seizes bulk carrier after alleged oil and sludge discharge - Iranian authorities have seized a bulk carrier carrying sugar after accusing it of dumping oil, bilge water and industrial sludge into the Strait of Hormuz, state media reported on Monday. Esmaeil Makizadeh, deputy head of Hormozgan’s Ports and Maritime Department, told IRNA that the vessel was seized after images showed oil being discharged into the sea. “Following the publication of images of the discharge of oil into the sea… expert and clean-up teams were dispatched to the site and seized the ship causing the pollution,” Makizadeh said. He said the bulk carrier had dumped a mixture of burnt oil, bilge water and industrial sludge directly into the sea. The department said the pollution spread into several small slicks because of sea currents, but clean-up teams contained the waste. The waste has since been removed from the water, and the vessel has been handed over to the judiciary, Makizadeh said. Iranian authorities did not identify the ship or say which country it was flagged in. They also did not provide the nationalities of the crew. The seizure comes after several oil spills in the region in recent weeks. Iran has demanded compensation over some of the incidents, including an oil spill near its Qeshm island. Earlier in August, an oil slick was also spotted near neighbouring Oman after a tanker ran aground. AFP found that the tanker had been stranded for weeks near Oman’s Al-Qibliyyah island after explosions damaged it. Iran has maintained control over the Strait of Hormuz since the outbreak of the Middle East war in February. Iran has also said it plans to charge fees on vessels passing through the strait to help pay for services, including environmental protection. The United States strongly opposes the proposed fees. The bulk carrier remains under judicial proceedings in Iran after authorities said the pollution had been cleaned up.
Oil Prices Jump over 2% after US Attacks Iran -- Oil prices climbed more than 2% on Monday after the United States carried out strikes against Iran’s Larak Island in the Strait of Hormuz, prompting an Iranian response and raising fresh concerns over the security of a vital global energy route. Brent crude futures rose $2.51, or 2.85%, to $90.61 a barrel by 0241 GMT, while US West Texas Intermediate crude gained $2.13, or 2.55%, to $85.53. The increase came as the war on Iran entered its sixth month and efforts to restore normal shipping through the Strait of Hormuz remained stalled. US officials told media that its forces struck two launchers on Iran's Larak Island on Sunday, a move that Tehran stated would garner a response. The Islamic Republic subsequently attacked technical, maintenance, and fighter jet infrastructure at two US air bases in Jordan. The Islamic Revolution Guards [IRG] reported its retaliation caused "heavy damage" to the hostile American site. The rapid exchange of attacks has added another layer of uncertainty to an already fragile energy market. "Looks like we are in another escalation phase. How long that lasts is impossible to determine. Could be days, could be weeks," IG market analyst Tony Sycamore said, Reuters reports. Sycamore said a further escalation could push WTI through resistance around $85.80-$85.90 a barrel, potentially opening the way toward last week’s $87.69 high and July’s $93.50 level. The immediate market reaction demonstrates how quickly military developments around the Gulf can translate into higher energy prices. IRG spokesperson Hossein Mohebi separately stated that Washington's escalating economic and military pressure is a “strategic and fatal mistake that would change the balance against its architects” and carry high costs on both economic and military fronts. Before the US- “Israeli” strikes that caused the war at the end of February, roughly one-fifth of global oil supplies passed through the Strait of Hormuz. Negotiations to end the war remain at an impasse, while mediators try to reopen the strait to regular shipping. Although some oil continues to move through the waterway, shipping activity has shown signs of mounting caution. Shipping data showed that only five visible commodity vessels per day passed through the strait over the weekend, compared with substantially higher levels before the escalation. The United Kingdom Maritime Trade Operations [UKMTO] also reported that a tanker was struck by a projectile while traveling inbound through the strait on Saturday. The combination of reduced vessel traffic and attacks on shipping is increasing the risk premium attached to crude, even as actual oil flows have so far prevented a larger supply shock. Military escalation is being accompanied by additional US economic pressure on Iran. US Treasury Secretary Scott Bessent told Reuters on Sunday that Washington is likely to introduce new secondary sanctions against Iran weekly. The stated objective is to further restrict Iran’s access to the dollar-based financial system, adding economic pressure to Washington's war on the nation. The combination of sanctions and military action creates additional uncertainty for global energy markets, particularly if restrictions affect Iranian oil exports or contribute to further disruption around Hormuz.
Oil Up 3% as Hostilities Return to Hormuz (DTN) -- Crude futures surged 3% Monday morning after U.S. forces struck an Iranian island in the Strait of Hormuz, marking the first exchange of fire between Washington and Tehran in over a month following the end of a ceasefire. By 8:45 a.m. EDT, NYMEX WTI crude for October delivery rose $2.61, or 3.13%, to $86.01 bbl. With markets into their final session for August, the U.S. crude benchmark was up 1.6% on the month. ICE Brent for November delivery advanced $4.58, or 5%, to $90.70 gallon. The global crude benchmark gained 3% on the month. Downstream, NYMEX ULSD for October delivery climbed $0.1150, or 2.76%, to $4.3640 gallon. NYMEX RBOB for September retreated $0.0238, or 0.43%, to $3.4661 gallon. The U.S. Dollar Index slid 0.148 points to 99.510 against a basket of currencies. Market volatility was amplified by thin trading volumes linked to a U.K. public holiday. Crude futures rallied after U.S. forces struck two missile launchers on Iran's Larak Island on Sunday, Aug. 30. Iran's Revolutionary Guards reported Monday they responded by attacking two U.S. air bases in Jordan, reviving fears of widespread supply disruptions. U.S. President Donald Trump added to the geopolitical noise Sunday with a social media post claiming Iran's Kharg Island energy hub was destroyed. Iranian officials quickly denied the Kharg Island claim and confirmed that crude oil operations were continuing. However, the renewed hostilities effectively stalled recent diplomatic efforts aimed at establishing a joint shipping lane through the strategic chokepoint. Shipping data over the weekend showed visible commodity vessels transiting the strait fell to just five a day. Supply risks escalated after the United Kingdom Maritime Trade Operations agency reported a tanker was struck by a projectile entering the strait Saturday. On the economic front, Treasury Secretary Scott Bessent warned Sunday that Washington was likely to impose secondary sanctions on Iran on a weekly basis. Despite Monday's rally, Brent and WTI crude remain on track for modest August declines following last week's sharp drop. On another front, Trump announced plans at the weekend to use reserve oil secured under a deal with Venezuela to replenish the U.S. Strategic Petroleum Reserve, although experts said it would take years and tens of billions of dollars for such an initiative to materialize. U.S. emergency stockpiles have fallen to near their lowest level in 44 years following extensive drawdowns.
Oil Market Rallies on Renewed U.S.-Iran Military Strikes -- The crude market rallied higher on Monday after the U.S. and Iran resumed their military strikes on Sunday. U.S. forces struck two launchers on Iran’s Larak Island in the Strait of Hormuz on Sunday, the first known American strikes on the country since late July. In response, Iran attacked two U.S. air bases in Jordan. The renewed military strikes in the Middle East and concerns of further oil supply disruptions lifted oil prices. The oil market gapped higher on the opening on Sunday evening from $83.87 to $84.69. The market partially backfilled the gap as it erased some of its gains and posted a low of $84.11. However, the market bounced off that level and rallied to a high of $86.79 in light of U.S. President Donald Trump stating that Iran’s Kharg Island was being attacked. The market later gave up some of its gains as Iran denied any attack on the island and said oil operations were continuing and Iran’s President stated that Iran was still open to a negotiated resolution to the conflict. The October WTI contract settled up $2.36 at $85.76 and the October Brent contract settled up $2.39 at $90.49. The product markets ended the session in mixed territory, with the September heating oil market contract going off the board up 13.86 cents at $4.4953 and the September RB contract going off the board down 5.29 cents at $3.4370. Shipping data showed that the number of visible commodity vessels transiting the Strait of Hormuz dropped to five per day over the weekend, as companies tread cautiously amid continued attacks on ships. The actual number of ships passing the strait could be higher as some vessels have switched off their automatic identification system to evade attacks. The European Union said that it would continue to work with the United States and other G7 and international partners to keep up pressure on Iran, as it issued a statement to coincide with this week’s G20 meeting. IIR Energy said U.S. oil refiners are expected to shut in about 27,000 bpd of capacity for the week ending September 4th, cutting available refining capacity by 3,000 bpd. Offline capacity is expected to increase to 230,000 bpd in the week ending September 11th. The U.S. Environmental Protection Agency on Monday granted small refinery exemptions worth 1.76 billion renewable fuel credits for the 2025 compliance year and said it will propose reallocating the waived obligations to larger refiners in future years. The EPA also plans to shift the waived obligations to produce biofuels such as ethanol from corn or sugarcane and biodiesel from oils and fats onto larger refiners in future years. The EPA said it has granted full exemptions to 18 out of 34 refineries that had sought exemptions from their Renewable Fuel Standard obligations for the 2025 compliance year. The agency has delayed 2025 compliance until September 1st and is currently seeking another extension. The EPA statement said it granted 50% exemptions to 11 refineries, denied three petitions and determined two petitions to be ineligible. Motiva Enterprises and Exxon Mobil Corp are preparing their east Texas refineries for high winds and possible flooding as a developing tropical storm nears the U.S. Gulf coast. Sources said Motiva and Exxon have not reduced production at their Port Arthur and Beaumont, Texas refineries, respectively, while securing loose items and equipment that can be blown by high winds or drift in flood waters should those be produced by the developing storm expected to make landfall on Tuesday. Delek said its 73,000 bpd Big Spring, Texas refinery reported an equipment malfunction.
Oil Prices Rise as Middle East Supply Risks Return - Oil prices rose on Tuesday as renewed fighting between the United States and Iran in the Middle East revived concerns over potential disruptions to supplies from a key global oil-producing region. Brent crude futures rose 56 cents, or 0.6%, to $91.05 a barrel by 0044 GMT, while U.S. West Texas Intermediate (WTI) crude gained 83 cents, or 1%, to $86.59 a barrel. In the previous session, Brent settled 2.7% higher after briefly reaching its highest level since Aug. 25. WTI rose 2.8% at settlement, reaching its highest level since Aug. 21. U.S. President Donald Trump on Monday threatened further attacks on Iran following the first direct exchange of strikes between the two countries in a month on Sunday, adding to tensions in a conflict that has recently evolved into an economic confrontation. “These developments bring the possibility of an Iranian response back into focus. That, in turn, raises the risk of damage to energy infrastructure around the Gulf and adds further uncertainty surrounding shipping through the Strait of Hormuz,” said Tim Waterer, a market analyst at KCM Trade. “Both risks are reflected in the stronger tone in crude prices.” Shipping data from Kpler showed that the number of visible commercial cargo vessels passing through the Strait of Hormuz had fallen to five per day at the start of the week. Efforts by mediators, including Qatar and Oman, to reach an agreement to reopen the Strait of Hormuz have made no progress so far. The waterway carried around one-fifth of global oil supplies before the war began in late February. Iran closed the waterway after it was attacked by the United States and Israel on Feb. 28. In another sign of continued risks to shipping and oil supplies, the United Kingdom Maritime Trade Operations agency said Tuesday that a tanker reported being struck by three projectiles while sailing outside the Strait of Hormuz. No injuries or environmental damage were reported. Trump announced on Friday an agreement with Venezuela to take control of the country’s oil reserves and later said the deal would help replenish the U.S. Strategic Petroleum Reserve, which is approaching its lowest level in 44 years. Five people familiar with the arrangements said U.S. oil major Chevron, General Electric Vernova, India’s ONGC, Italy’s Eni and Colombia’s GeoPark are expected to sign final agreements in Venezuela following months of negotiations over energy projects in the OPEC member state. U.S. crude inventories in the Strategic Petroleum Reserve fell by about 3.1 million barrels last week to 286.6 million barrels. Analysts polled by Reuters in August expect oil prices to remain above $80 a barrel in 2026 as shipping disruptions continue.
Oil Begins September Higher on Renewed Hormuz Strikes - (DTN) -- Crude futures moved nearly 2% higher Tuesday morning as renewed military exchanges between Washington and Tehran stoked supply disruption fears. By 9:10 a.m. EDT, NYMEX WTI crude for October delivery rose $2.43, or 2.86%, to $88.19 bbl. ICE Brent for November delivery moved up $2.23, or 2.43%, to $92.72 bbl. Downstream, NYMEX ULSD for October delivery climbed $0.1460, or 3.36%, to $4.5566 gallon. RBOB for October advanced $0.0543, or 1.72%, to $3.1313 gallon. The U.S. Dollar Index moved up 0.175 points to 99.560 against a basket of currencies. Crude futures' advance on the first trading day of September recouped most of their losses last week as escalated hostilities in the Middle East erased recent hopes for a diplomatic breakthrough. Physical risks to regional energy infrastructure escalated Monday after two supertankers carrying Saudi crude were hit by unknown projectiles within minutes of each other in the Strait of Hormuz. Ship tracking data showed visible commodity transits through the chokepoint held at roughly five vessels on Monday, well below the 10-day average of 14. None of the five vessels recorded transiting the waterway on Monday were liquid tankers, underscoring severe caution among commercial fleet operators. Market participants caution that the sudden military escalation deals a blow to short-term prospects for establishing a safe, managed transit corridor through the strait. President Donald Trump warned Monday, Aug. 31, of additional strikes against Iranian targets following the first direct military engagement between the two nations since late July. The escalation marks a sharp turn from last week, when the conflict briefly shifted toward economic sanctions and regional diplomatic talks. Iranian President Masoud Pezeshkian stated Tuesday that Tehran would immediately return to its obligations if Washington honored commitments made under June's interim agreement. However, ongoing mediation efforts led by Qatar and Oman to reopen the Strait of Hormuz remain inconclusive. Traders are expected to be focused later in the day on U.S. petroleum inventory data for the week ended Aug. 28 from the American Petroleum Institute, ahead of official statistics for the same period due on Wednesday, Sept. 2, from the U.S. Energy Information Administration.
Oil Market Surges as Strait of Hormuz Tanker Attacks Raise Supply Fears - The oil market continued on its upward trend on Tuesday amid renewed escalation in tensions between the U.S. and Iran. The market was well supported following strikes in the Persian Gulf, including attacks on two tankers carrying Saudi crude oil in the Strait of Hormuz. The crude market posted a low of $86.13 on the opening and never looked back as it continued to trade higher after U.S. President Donald Trump on Monday threatened further strikes against Iran. The oil market extended its gains to $4.79 as it rallied to a high of $90.55 ahead of the close. The market was supported further amid the news that the U.S. had struck Islamic Revolutionary Guard Corps targets in Iran on Tuesday afternoon. Also, President Trump dismissed the value of any deal with Iran. The October WTI contract settled up $4.46 at $90.22 and continued to rally in the post settlement period, posting a high of $90.97. The November Brent contract settled up $4.16 at $94.65. The product markets ended the session higher, with the heating oil market settling up 26.67 cents at $4.6773 and the RB market settling up 5.81 cents at $3.1351. U.S. Treasury Secretary, Scott Bessent, said the United States is likely to announce sanctions on a bank this week as part of its economic campaign against Iran. Preliminary ship-tracking data showed that the number of vessels sailing through the Strait of Hormuz was little changed on Monday compared with the weekend, remaining around five, below the 10-day average of around 14. Kpler data showed that four of the vessels entered the strait and one exited. According to Iranian media reports, a Saudi oil tanker was stopped on Tuesday while transiting through the southern corridor of the Strait of Hormuz. Meanwhile, at the other chokepoint, the Bab-el Mandeb strait, the number of vessels transiting was at a three-day high of 27, with 14 entering and 13 exiting. Five of the 27 vessel transits were either Aframax- or Suezmax-sized crude tankers. None of the vessels that entered or exited were very large crude carriers or liquefied natural gas tankers. Two U.S. officials said U.S. oil company North American Blue Energy Partners will take over some oilfields previously controlled by several Chinese companies and a Russian firm. The takeover will be part of a sweeping oil production agreement that President Donald Trump announced with Venezuela. The projects were among 14 contracts newly granted to U.S.-backed North American Blue Energy Partners. NABEP is expected to control a total of 17 projects in Venezuela that it plans to develop and ultimately use to supply oil to the U.S. Fourteen of those projects will be newly granted by the Venezuelan government. Five of the 14 fields have been operated by Chinese companies under a model promoted by then-President Nicolas Maduro, while one was previously operated by a Russian company. Motiva, Exxon Mobil and TotalEnergies are maintaining planned production at their East Texas refineries as Tropical Storm Edouard nears landfall later on Tuesday close to those three U.S. Gulf Coast plants. Both the Exxon Beaumont refinery and the TotalEnergies Port Arthur refinery told contractors to stay home on Tuesday or sent them home Tuesday morning while keeping the full staff of employees on hand.
Oil prices settle up more than $4 a barrel on renewed US-Iran fighting - Oil prices jumped more than USD 4 a barrel on Tuesday, settling at a five-week high, as traders feared more supply disruptions from the Middle East due to renewed fighting between the US and Iran. Brent futures rose USD 4.16, or 4.6%, to settle at USD 94.65 a barrel. US West Texas Intermediate (WTI) crude rose USD 4.46, or 5.2%, to settle at USD 90.22. That was the highest close for Brent since July 24 and for WTI since July 23. The US launched new air strikes on Iranian targets, quashing hopes that an exchange of fire last weekend might not presage a wider renewal of hostilities. Oil prices had already risen after that first exchange of direct attacks since July and after reports of two tankers being hit leaving the Strait of Hormuz, the global oil supply waterway that Iran has effectively closed to shipping. Tehran remained defiant, warning that it would prevent oil being exported from the Gulf, despite a threat by US President Donald Trump to hit Iran "hard" in response to the renewed Iranian strikes, and a warning from US Treasury Secretary Scott Bessent that Washington was about to impose new sanctions. "Today at 12 p.m. ET (1600 GMT), US forces began striking Islamic Revolutionary Guard Corps targets in Iran," US Central Command posted on X. "The strikes follow recent attempted attacks by the IRGC against commercial shipping in the Strait of Hormuz and against American service members deployed to the region." The fresh hostilities "raised concerns about prolonged disruptions to energy flows through the Strait of Hormuz," Saxo Bank analyst Ole Hansen said. Disruptions at refineries around the world, especially in the Middle East and in Russia, have caused diesel prices to spike. In the US, diesel futures jumped to a 52-month high on Tuesday after soaring 51% over the past 10 weeks, boosting the diesel crack spread, which measures refining profit margins, to a record high of around USD 107 a barrel, according to LSEG data. Russian air attacks killed 12 people and injured many more in Kyiv and the surrounding region early on Tuesday, authorities said, marking the sixth straight day of intense strikes on the Ukrainian capital. Russia was the world's third-biggest crude oil producer behind the US and Saudi Arabia in 2025, according to US energy data, and is a member of the OPEC+ group of producing countries. The oil market was watching for weekly storage reports from the American Petroleum Institute trade group on Tuesday and the US Energy Information Administration on Wednesday. Analysts estimated energy firms pulled 0.8 million barrels of crude from storage during the week ended August 28. If correct, that would be the first decline in five weeks and compares with an increase of 2.4 million barrels in the same week last year and an average decrease of 5.1 million barrels over the past five years (2021 to 2025).
Oil Prices Rise as US-Iran Strikes Resume - Oil prices rose 0.8% in early trading on Wednesday, extending the previous session’s sharp gains as concerns grew over supply disruptions after the United States and Iran exchanged strikes overnight, dashing hopes that tensions in the Middle East would ease quickly. Brent crude futures rose 75 cents, or 0.8%, to $95.40 a barrel by 03:45 GMT, while U.S. West Texas Intermediate crude futures gained 44 cents, or 0.5%, to $90.66. Both contracts surged by more than $4 on Tuesday, marking Brent’s biggest gain since July 24 and WTI’s largest since July 23. The United States said it had launched a series of airstrikes against targets in Iran overnight, prompting an Iranian response in the most serious escalation in the conflict between the two countries in weeks. Iran’s Revolutionary Guard said the U.S. attacks would further restrict movement through the Strait of Hormuz, a vital waterway through which about one-fifth of the world’s consumed oil passed before the conflict. Iran has effectively closed the strait to commercial shipping. “Developments over the past few days have brought risks to regional oil supplies back into focus,” ING analysts said in a note to clients. “We saw oil continue to flow through the Strait of Hormuz despite the standoff between the U.S. and Iran, but the escalation clearly puts those flows at risk.” The latest exchange of strikes followed an escalation in fighting over the weekend, the first since July, as well as attacks on two oil tankers leaving the Strait of Hormuz on Monday. The incidents caused further disruption to oil supplies and forced traders to seek alternative crude cargoes. “The oil market is no longer pricing in just the risks of war, but increasingly the cost of an unresolved war,” said Priyanka Sachdeva, head of market forecasting at Phillip Nova. “Until there is clear evidence that negotiations can lead to a lasting resolution and that normal oil flows through the strait are returning, we expect the risk premium in crude prices to remain elevated,” she added. In the United States, the world’s largest oil producer, market sources citing American Petroleum Institute data said crude inventories fell by 2.6 million barrels in the week ended August 28. Distillate stocks, which include diesel and heating oil, declined by 265,000 barrels.
Oil Off Month-Highs on Hormuz, US Inventory Watch (DTN) -- Crude futures retreated Wednesday from one-month highs as traders awaited official U.S. petroleum inventory data for last week amid mixed signals for energy freight on the Strait of Hormuz from the U.S.-Iran war. By 9:19 a.m. EDT, NYMEX WTI crude for October delivery fell $0.48, or 0.48%, to $89.74 bbl. ICE Brent for November delivery moved down $0.18, or 0.17%, to $94.47 bbl. Downstream, NYMEX ULSD for October delivery eased $0.0060, or 0.07%, to $4.6713 gallon. RBOB for October advanced $0.0507, or 1.65%, to $3.1858 gallon. The U.S. Dollar Index gained 0.063 points to 99.700 against a basket of currencies. Crude futures rose earlier to a one-month high of $92.29 on WTI and $97.04 on Brent, boosted by Tuesday's, Sept. 1, data from the American Petroleum Institute indicating that U.S. commercial crude oil stocks fell by 2.6 million bbl during the week ended Aug. 28. The U.S. Energy Information Administration will publish official inventory data for last week at 10:30 a.m. ET. The U.S. and Iran were back on a war footing on Wednesday after the most significant exchange of fire in weeks, with Washington threatening more devastating strikes. The Islamic Revolutionary Guard Corps said the U.S. attacks would further restrict traffic through the Strait of Hormuz, a critical waterway that carried about one-fifth of the global oil consumed before the conflict and which Iran has effectively closed to commercial shipping. Two oil tankers hit sea mines and were disabled while attempting to transit the Strait of Hormuz, Iran's Revolutionary Guards said on Wednesday, in a statement shared by state media. U.S. Secretary of Energy Chris Wright said on Tuesday that 17 million bbl transited the Strait of Hormuz on Monday, saying it marked the highest level of crude oil to pass through the waterway since the Iran war had reduced flows. But market participants are wary the flows could drop dramatically if hostilities worsened on the strait.
WTI At 5-Week Highs As US-Iran Fighting Resumes; US Production At Record High As Cushing & SPR Hit 'Tank Bottoms' Oil prices were volatile but are trading around unchanged this morning, but still near the highest closing level in five weeks (WTI topped $92 overnight) as hostilities broke out again between the US and Iran, renewing the threat to energy exports from the Middle East. The US conducted a second day of strikes on the Islamic Republic overnight, with President Donald Trump threatening more attacks if Tehran responded. Within hours, Iran retaliated against Jordan, Bahrain and Kuwait, countries that host American forces. “The market is now clearly pricing in a direct military confrontation, while the prospect of a negotiated solution has diminished,” said Arne Lohmann Rasmussen, chief analyst at Global Risk Management in Copenhagen. “This is a worse combination for the energy market than the situation we faced just a few days ago and even in April. Today, inventories are even more depleted.” Prices pared some gains this morning on Venezuela news and more much-debated news from Secretary Wright about 'shadow' flows through the Strait. API:
- Crude -2.6mm
- Cushing
- Gasoline +348k
- Distillates -265k
DOE
- Crude -4.45mm (+60k exp)
- Cushing +80k
- Gasoline -1.17mm
- Distillates +796k
US Crude stocks declined for the first time in five weeks (more than expected and more than API reported) while Gasoline stocks continued to drawdown and Cushing saw a de minimus build. Distillates stocks did see a build (good news) for the first time in five weeks... Distillate supplies on the East Coast are now at record lows, while supplies on the West Coast are the lowest since May 2025. The vast majority of heating oil demand in the US occurs in the Northeast, so this is less than ideal with just a month to go before heating season starts. Another brutal week for gasoline imports, which fell to 370,000 barrels a day last week. That’s below levels for the same time in 2020. There’s just not a lot of relief for markets desperate for more supply. Amid all the clamor that Venezuela will be used to refill it, the SPR saw yet another drawdown last week (-3.12mm barrels) for the biggest overall crude draw since July... The SPR is now at its lowest level since 1982... US Crude production surged back to record highs... Refinery crude refinery runs soared to the highest in seven years, as oil processing in both the Gulf Coast and Midwest moved higher, with the Midwest at an all-time record high. Runs on the Gulf Coast are the highest for this time of the year. WTI holding around $90... The return to a hot war has once again thrust shipping through the vital Strait of Hormuz into jeopardy, as the two sides remain at loggerheads and diplomatic efforts yield few results.
Oil Market Gains Despite Oil Flows Through Strait of Hormuz -- The crude market on Wednesday ended the session higher as traders weighed the risks of supply disruptions following overnight strikes by the U.S. and Iran against signs that crude supplies continue to flow through the Strait of Hormuz. The U.S. military said it struck air defenses, radar systems, maritime assets, mine-laying capabilities and communications sites on Tuesday. Iran responded by striking what it said were U.S. assets in Bahrain, Jordan, Kuwait and Iraq, and said its aim was now to drive U.S. forces from the network of military bases they have occupied across the Middle East. The crude market continued to trend higher in overnight trading as it rallied to a high of $92.29. However, the market erased its gains after U.S. Energy Secretary, Chris Wright, said that more than 17 million barrels of oil flowed through the Strait of Hormuz on Monday. The market sold off more than $3 from its high to the a low of $88.97 on the U.S. Energy Secretary’s comments ahead of the release of the EIA’s weekly oil stocks report. The market later bounced off its low and retraced some of its losses in light of the EIA report showing a large draw of 4.5 million barrels in crude stocks in the week ending August 28th. The October WTI contract settled up 79 cents at $91.01 and the November Brent contract settled up 98 cents at $95.63. The product markets ended the session in mixed territory, with the heating oil market settling up 49 points at $4.6822 and the RB market settling down 3.13 cents at $3.1038. U.S. Secretary of Energy Chris Wright said that 17 million barrels of oil transited the Strait of Hormuz on Monday, saying it marked the highest level of crude oil to pass through the waterway since the Iran war had reduced flows. Preliminary shipping data showed that four commodity vessels transited the Strait of Hormuz on Tuesday, down from ten a day earlier and below the 10-day average of around 13 on Wednesday. Initial data from shiptracker Kpler showed that the four vessels that transited were one very large crude carrier, one Panamax tanker, one Kamsarmax carrier and one intermediate tanker. Meanwhile, 18 commodity vessels transited through the Bab el-Mandeb Strait on Tuesday, with seven vessels entering and 11 exiting. This compares with an average of around 24 ships going through Bab el-Mandeb over the past 10 days. Among the vessels travelling through the strait were two Aframax tankers and one Suezmax tanker. IIR Energy said U.S. oil refiners are expected to shut in about 35,000 bpd of capacity in the week ending September 4th, decreasing available refining capacity by 11,000 bpd. Offline capacity is expected to increase to 238,000 bpd in the week ending September 11th. Valero Energy Corp’s 385,000 bpd Port Arthur, Texas, refinery was hit by a partial power outage on Tuesday night following the passage of Tropical Storm Edouard. The refinery’s AVU-147 crude distillation unit was shut by the power outage on the south side of the plant and the AVU-146 crude distillation unit was operating at the minimum crude processing level. According to a Texas Commission on Environmental Quality filing, Motiva’s 656,400 bpd Port Arthur, Texas refinery experienced an unexpected interruption and shutdown of several critical pieces of equipment on September 1st, caused by severe weather during Tropical Storm Edouard. The filing added that the facility took immediate action to stabilize affected process units and minimize flaring and emissions to the extent practicable. LyondellBasell said a minor fire occurred within the operating area at its La Porte, Texas complex. The company later issued an all-clear for the incident in a separate alert.
Oil Prices Edge Lower Amid US-Iran Uncertainty- Oil prices edged lower on Thursday as investors assessed uncertainty surrounding renewed military strikes between the United States and Iran and their potential impact on Middle East supplies. Brent crude futures fell 43 cents, or 0.45%, to $95.20 a barrel, while U.S. West Texas Intermediate (WTI) crude futures declined 24 cents, or 0.26%, to $90.77 a barrel. The latest attacks marked the largest exchange of fire between the United States and Iran since July, as the war entered its seventh month. Brent and U.S. crude prices fluctuated between gains of as much as $2 a barrel and losses of up to $1 a barrel during the previous trading session. Both benchmarks reached their highest levels since July 24. U.S. President Donald Trump said on Wednesday that the renewed U.S. campaign against Iran would not continue for “too long” and that U.S. forces had targeted Iranian radar and missile systems. “We destroyed all the new equipment they tried to build near the Strait of Hormuz, some of it defensive and some offensive,” Trump said. “It was a very violent attack last night, and we are ready to launch another attack whenever we want.” Preliminary shipping data from Kpler on Wednesday showed that four commodity-carrying vessels had passed through the Strait of Hormuz, well below the 10-day average of around 13 vessels. Iran also added more vessels to a list of ships it considers non-compliant with its directives, leaving them potentially subject to fines, seizure or detention if they attempt to transit the strait. The United States said Tuesday that 17 million barrels of oil had passed through the Strait of Hormuz on Monday, describing it as the largest volume of crude to transit the waterway since the start of the U.S.-Israeli war on Iran.
Oil prices hit six-week high amid renewed US aggression against Iran -- Oil prices rose to near a six-week high on Thursday after renewed US attacks on Iran, along with fresh Israeli occupation’s threats against Tehran, heightened concerns over potential disruptions to Middle East supplies. Brent crude futures rose $1.76, or 1.8%, to $97.39 a barrel by 10:25 GMT, erasing earlier losses, while U.S. West Texas Intermediate (WTI) futures gained $1.91, or 2.1%, to $92.92, according to Reuters. Both contracts were heading for a fourth consecutive session of gains after reaching their highest levels in six weeks earlier in the session. Preliminary shipping data released earlier in the day showed that six cargo vessels carrying commodities passed through the Strait of Hormuz on Wednesday, down from 11 the previous day and below the 10-day average of around 13 vessels. Iran has also added more vessels to its list of ships deemed non-compliant with its directives, exposing them to fines, seizure or detention if they attempt to sail through the strait.
Oil Eases After 6-Week Highs Amid Hormuz Watch (DTN) -- Crude futures gave back most of the gains that elevated them to six-week highs Thursday as the market balanced concerns over the impact of heightened fighting in the Middle East with U.S. President Donald Trump's hints that current hostilities may wind down again. NYMEX WTI crude for October delivery settled up $0.29, or 0.32%, at $91.30 bbl, after racing to a six-week high of $93.14 bbl earlier. ICE Brent crude for November settled down $0.11, or 0.1%, at $95.52 bbl. It rose to as high as $97.62 bbl during the session, a peak since mid-July. Downstream, NYMEX ULSD for October delivery eased $0.0886, or 1.89%, to finish at $4.5936 gallon. RBOB for October advanced $0.0311, or 1.00%, to end the session at $3.1349 gallon. By 2:30 p.m. EDT, the U.S. Dollar Index slid 0.672 points to 98.880 against a basket of currencies. The rally earlier in the day came after civilian casualties and infrastructure damage were reported across Iranian coastal regions near the Strait of Hormuz following an overnight U.S. bombardment. Iran said those killed and wounded included people at a wedding. Physical energy transits through the Hormuz remain volatile amid the six-month conflict. Preliminary vessel-tracking data showed four to six oil-laden tankers navigated the chokepoint between Tuesday and Wednesday, well below the 10-day average of 13 daily transits -- despite U.S. Energy Secretary Chris Wright noting a transient surge of 17 million bbl on Monday. Trump hinted on Wednesday that the current hostilities might not drag on. "I don't think too long," he told reporters when asked to give a timeframe for the escalation. Tehran expanded its maritime enforcement list Thursday, warning that non-compliant commercial vessels attempting passage through the waterway face fines or cargo confiscation. Outside the Hormuz chokepoint, Iraqi crude exports rose to 2.34 million bpd in August from 1.35 million bpd in July on discounted pricing, with September volumes expected to expand further as Iranian authorities permit select Iraqi tanker transits. Fundamental support also stemmed from domestic inventory data showing U.S. commercial crude stocks fell by 4.5 million bbl last week, marking the first draw in five weeks. Downstream stocks offered a mixed picture, with gasoline inventories falling by 1.2 million bbl while distillate stocks rose by 800,000 bbl. Traders are also monitoring OPEC+, which is expected to hold output policy unchanged at its Sunday meeting after completing the scheduled unwinding of a 1.65 million bpd layer of voluntary production cuts.
Oil Market Hits Six-Week High as Israel Threatens Iranian Energy Sites - The oil market on Thursday continued on its upward trend reaching a six-week high following further U.S. strikes on Iran and renewed Israeli threats against Iran. Israel’s Defense Minister, Israel Katz, said Israel would destroy Iran’s military and civilian infrastructure, including energy facilities, if Iran launched attacks against it. The crude market erased some of its previous gains in overnight trading, posting a low of $89.57. However, the market bounced off that level and extended its gains on the Israeli threats against Iran. Also, oil flows through the Strait of Hormuz were lower on Wednesday, with only six vessels transiting the waterway, down from 11 on Tuesday. The oil market retraced nearly 62% of its move from a high of $109.47 to a low of $67.04 as it posted a high of $93.14 early in the morning. The market later erased some of its gains during the remainder of the session, with the October WTI contract settling up 90 cents at $91.30 and the November Brent contract settling down 11 cents at $95.52. The product markets ended the session in mixed territory once again, with the heating oil market settling down 8.86 cents at $4.5936 and the RB market settling up 3.11 cents at $3.1349. U.S. Vice President JD Vance said that the U.S. does not plan to hold talks with Iran unless Tehran stops attacking commercials shipping in the Strait of Hormuz. Preliminary shipping data showed that six commodity vessels transited the Strait of Hormuz on Wednesday, down from 11 a day earlier and well below the 10-day average of around 13. Kpler data showed that in the Bab el-Mandeb Strait, 31 commodity vessels crossed that waterway on Wednesday, the highest number since August 24th and above the 10-day average of 25 vessels. On Tuesday, 17 vessels transited the waterway. Citi said it raised its mark-to-market Brent average forecast for the third quarter of 2026 to $86/barrel from a previous estimate of $80/barrel, as the reopening of the Strait of Hormuz has taken longer than its prior assumption. Citi said it is maintaining its fourth quarter 2026 and 2027 Brent average forecasts at $70/barrel and $65/barrel, respectively. According to GasBuddy data, average U.S. diesel prices reached $5.820/gallon on Thursday, a new record, as a global supply crunch intensifies following renewed hostilities between the United States and Iran and disruptions caused by Ukrainian attacks on Russian refineries. This surpassed the previous high of $5.819/gallon recorded on June 17, 2022, in the aftermath of Russia’s invasion of Ukraine. Bloomberg reported that U.S. retail diesel prices reached its highest level since mid-2022, surpassing a peak seen during the early stages of the Iran war. Goldman Sachs expects Venezuela’s crude production to increase, but does not see output returning to pre-2018 levels of more than 2 million bpd over the next few years. It said that key bottlenecks, including degraded infrastructure and an unreliable power grid, will be costly and time-consuming to fix. Several international energy firms, including Eni, GE Vernova and Chevron committed on Wednesday to project expansions to increase oil output in Venezuela, in a signing ceremony in Caracas overseen by interim President Delcy Rodriguez and U.S. Energy Secretary Chris Wright.
Oil Prices Set for Weekly Gains Amid Hormuz Security Risks - Oil prices are on track to end the week higher on Friday as renewed military tensions between the US and Iran and persistent security risks in the Strait of Hormuz revived concerns about potential disruptions to global energy supplies. International benchmark Brent crude futures for November delivery traded at $94.77 per barrel at 3:29 p.m. local time (1229 GMT) on Friday, up 7.6% from last Friday’s close of $88.10, The Caspian Post reports, citing Anadolu Agency. US benchmark West Texas Intermediate (WTI) crude futures for October delivery traded at $90.34 per barrel, marking an 8.3% increase from $87.06 a week earlier. Oil prices have been primarily supported by a renewed escalation in hostilities between Washington and Tehran, which has increased uncertainty over the security of energy shipments through the Strait of Hormuz, one of the world’s most important oil transit routes. Tensions intensified over the weekend after US forces struck targets on Iran’s Larak Island near the Strait of Hormuz. Iran retaliated with missile and drone attacks against sites used by US forces across the region. The escalation continued during the week, with the US targeting areas around the Strait of Hormuz and southern Iran, while Tehran reported strikes on several locations, including Qeshm Island, Bandar Abbas, Asaluyeh, Chabahar and Konarak. Iran’s Islamic Revolutionary Guard Corps (IRGC) said the attacks had “further tightened the lock on the Strait of Hormuz,” reinforcing market concerns that continued hostilities could prolong disruptions to energy flows from the Gulf. Security risks to commercial shipping also remained elevated. The UK Maritime Trade Operations (UKMTO) reported Tuesday that a tanker had been struck by three unknown projectiles while exiting the Strait of Hormuz off Oman. Iran also said during the week that it had laid additional naval mines in the strait and reported that oil tankers attempting to pass through what Tehran described as unauthorized routes had struck mines. The developments raised concerns that even if oil shipments continue through the waterway, heightened security risks could disrupt tanker movements, increase insurance and freight costs, and discourage some operators from using the route. Before the conflict, around 20 million barrels per day of crude oil and petroleum products moved through the Strait of Hormuz, accounting for a significant share of global seaborne oil trade. The persistent risk of disruption to these flows added a geopolitical risk premium to crude prices, pushing Brent above $95 per barrel during the week. However, reports of a sharp recovery in oil flows through the Strait of Hormuz and signals from Washington that it does not seek a prolonged conflict with Iran limited further price gains.
Oil Dips Pre-Holiday but Caps 8% Weekly Gain - Oil prices retreated Friday but remained on track for sharp weekly gains ahead of the Labor Day holiday as renewed U.S.-Iran hostilities sustained fears of prolonged supply disruptions through the Strait of Hormuz. By 8:50 a.m. EDT, NYMEX WTI crude for October delivery fell $1.27, or 1.39%, to $90.03 bbl, though heading for an 8% weekly advance before Monday's market holiday. ICE Brent for November dipped by $1.08, or 1.13%, to $94.44 bbl, maintaining a 7% weekly gain. Downstream, NYMEX ULSD for October delivery eased $0.1081, or 2.35%, to $4.4855 gallon, up 5% on the week. RBOB for October retreated $0.0441, or 1.39%, to $3.0908 gallon, pacing toward a 2% weekly rise. The U.S. Dollar Index gained 0.370 points to 99.250 against a basket of currencies, posing additional headwinds for dollar-denominated commodities. Weekly gains reflect heightening geopolitical risks following U.S. airstrikes against Iranian targets and Tehran's retaliatory drone and missile counterfire against U.S. positions across the Gulf region. U.S. Vice President JD Vance stated Thursday that Washington will not engage in diplomatic talks with Tehran until Iran halts attacks on commercial shipping in the Strait of Hormuz. Physical energy flows through the chokepoint and remains severely constrained. Preliminary vessel-tracking data showed daily commodity tanker transits falling to single digits, well below the 10-day average of 13 transits. Prices also find underlying fundamental support from tightening domestic inventories. U.S. Energy Information Administration data showed commercial crude stocks fell 4.5 million bbl last week, marking the first inventory draw in five weeks. Traders are, meanwhile, turning their attention to Sunday's OPEC+ meeting, where the producer group is expected to leave October output policy unchanged after completing the scheduled unwinding of voluntary production cuts. In U.S. economic data, non-farm payrolls surged by 162,000 in August, far exceeding market expectations of a 56,000 gain. The U.S. Bureau of Labor Statistics reported Friday, Sept. 4, that the national unemployment rate held steady at 4.1%.
Oil ends week higher on renewed US-Iran strikes, diesel hits record (Reuters) - Oil prices rose on Friday, ending the week substantially higher after the United States and Iran resumed military exchanges in the seventh month of their conflict, while retail U.S. diesel prices hit a record high. Brent crude futures settled at $92.68 a barrel, up 76 cents, or 0.8%. West Texas Intermediate crude futures finished at $91.48 a barrel, up 18 cents, or 0.20%. For the week, Brent crude rose 7.6% while U.S. crude gained nearly 10% as supply routes in the Middle East remain impaired due to the war. The rally in oil prices combined with a much steeper increase in fuel prices has pushed inflation and government borrowing costs higher around the world and intensified fears that global economic growth might pull back without some relief. "All sectors of the economy are affected by diesel. This is one of the reasons why the government bond yields in the United States are so high, it's the expectation that inflation will continue to go up," said Claudio Galimberti, chief economist at Rystad Energy. Average U.S. diesel prices hit record highs as renewed U.S.-Iran hostilities and Ukrainian attacks on Russian refineries increased supply disruptions. A gallon of diesel now costs $5.85 on average in the U.S., according to AAA data. The price of diesel could rise even further due to the sharp drawdown in inventories and as agricultural states in various parts of the country head into harvesting and planting seasons. Diesel is a primary fuel for ag equipment. Its equivalent futures contract, heating oil, has also surged as winter approaches. Citi raised its average Brent crude price forecast for the third quarter to $86 a barrel from $80, saying the reopening of the Strait of Hormuz was taking longer than previously expected. ANZ analysts raised their short-term Brent crude forecast to $95 a barrel, with upside risk if the Middle East conflict intensifies. The U.S. economy added 162,000 jobs in August, allaying fears of weakness in the labor market, but bolstering the case for the U.S. Federal Reserve to raise rates later in September. "The strong employment figures points to an interest rate hike by the Federal Reserve and that was weighing on WTI," The U.S. government has said Middle Eastern oil flows have returned to near normal levels in recent weeks, but analysts and tanker trackers indicate that flows remain seriously disrupted. Four commodity vessels transited the Strait of Hormuz on Thursday, well below the 10-day average tally of about 15, preliminary shipping data showed. "Oil seems to be in a phase where the conflict’s gridlock and recurring hostilities are regularly awakening a risk premium embedded in prices," . "So far, there is no indication that this week’s escalation materially impacted exports out of the Middle East and tightened the oil market," Rucker said. "Oil’s current rally seems mostly mood and fear driven." U.S. attacks this week that killed and wounded dozens, including Iranian civilians, were the fiercest clashes between the two countries since July. The U.S. campaign to throttle Iran's economy by blockading its oil exports and stopping sanctions evasion is growing increasingly difficult to withstand, three senior Iranian sources said. Iraq increased its August oil exports to about 2.34 million barrels per day from about 1.35 million bpd in July, two Iraqi energy officials said on Wednesday.
Two tankers hit Hormuz naval mines, Iran says amid regional strikes --Two oil tankers struck naval mines while attempting to transit the Strait of Hormuz, Iran’s Revolutionary Guard said Wednesday, after the Iranian military made retaliatory strikes on U.S. bases in the Middle East.In a statement shared by state media, the influential hard-line military group said the vessels had been disabled and forced to disembark their crew after ignoring warnings on taking an “illegal route” through the strait.President Donald Trump said he was “not trying to force Iran to the bargaining table,” as U.S. forces completed a fresh round of attacks against the Middle Eastern country on Tuesday stateside. U.S. Central Command disputed Iran’s claim of striking the two oil tankers, saying in a social media post on Wednesday that “No ships have hit mines in the Strait of Hormuz. This is yet another IRGC attempt to intimidate regional commercial shipping through disinformation.”The latest exchange of military strikes came as the Financial Times published an investigative report claiming Russia was secretly helping Iran to develop advanced supersonic cruise missiles capable of threatening U.S. aircraft carriers and other warships in the region.In a Truth Social post, Trump claimed the U.S. has “almost total control” over the Strait of Hormuz, while adding that Tehran’s economy was collapsing.He said Iran was just “playing out the inevitable” and asked, “When are the Iranian people going to rise up and fight?”In an earlier post on X, U.S. Central Command said that it struck air defense and communications sites, and radar systems in Iran, in retaliation against the “recent attempted attacks” by the country against commercial shipping in the Strait of Hormuz and against American service members.Tehran responded to American strikes, targeting U.S. ally Jordan. The country’s armed forces said it was targeted by a missile attack that originated from Iranian territory.A spokesperson for Jordan’s armed forces said on X that 10 of 13 missiles were intercepted by the country’s air defense systems, with the three fell in remote areas. No injuries or deaths were reported.Bahrain’s armed forces said on Instagram on Wednesday that they had intercepted and destroyed “treacherous Iranian air strikes today,” following an earlier announcement by Bahrain’s Interior Ministry of “an alert of potential threat.”U.S. Treasury Secretary Scott Bessent said in an interview with Fox Business on Tuesday that the Strait of Hormuz will become a “worthless piece of water” in two years, contending that oil will instead flow across land pipelines and bypass the strait.Strikes on Sunday were the first time that the U.S. and Iran traded attacks in about a month, and after the Trump administration said it was launching an “economic D-Day” on Tehran’s backers.
Two Oil Supertankers Hit by Projectiles in Hormuz, Marisks Says - Two oil supertankers were struck by unknown projectiles in quick succession while transiting the Persian Gulf's Strait of Hormuz chokepoint, maritime security consultant Marisks said. The very large crude carrier Sidr, run by Saudi Arabia's Bahri shipping company, was hit while sailing northeast of Khasab, Oman, the consultant said. The Senegal Prosperity, operated by Sinokor, was struck by three projectiles while traveling east of the same country, it said. Both were exiting the Persian Gulf, according to Marisks. Bahri and Sinokor didn't immediately respond to requests for comment. Earlier, the UK Maritime Trade Operations said that one tanker reported being struck by three unknown projectiles while completing an outbound transit of the Strait of Hormuz. It didn't identify the vessel.
Saudi shipping company Bahri says two sailors killed in incident in Hormuz (Reuters) - Saudi Arabia's national shipping company, Bahri, said on Wednesday that two Filipino seafarers were killed in a security incident involving its vessel "SIDR" as it transited through the Strait of Hormuz on August 31. The company did not disclose further details. On August 31, maritime security agency UKMTO said a tanker had reported being struck by three unknown projectiles while outbound through the Strait of Hormuz. Iran has threatened tankers attempting to transit the narrow waterway without authorisation. "Bahri remains in continuous contact with the vessel and is coordinating closely with the relevant authorities and maritime industry stakeholders, while continuing to closely monitor developments," the company said in its statements. A month earlier another Bahri vessel was hit near the strait. The Wedyan supertanker was sailing close to Oman's coast at the time. Two other Bahri vessels, AMZAN and MASA, were attacked in the Red Sea after the Iran-backed Yemen's Houthis declared a naval blockade against Saudi Arabia.
Ansar Allah Launches Major Attacks Targeting Saudi-Backed Forces in Yemen - Yemen’s Ansar Allah, also known as the Houthis, launched significant strikes on Thursday targeting Saudi-backed forces inside Yemen.Yahya Saree, spokesman for the Ansar Allah-led Yemeni Armed Forces, said that drone attacks targeted “Saudi enemy gatherings and vehicles on several fronts” but didn’t specify exactly where the operations were carried out.Saudi media reported that Houthi ballistic missiles targeted Taiz and Hodeidah, provinces that are both partially controlled by Ansar Allah and the Saudi-backed government, which is based in Aden, though its leadership has been based in Riyadh since they were first driven out of the Yemeni capital Sanaa in 2014.The footage released by Saree shows bombs being dropped from the sky onto militant positions, and Yemeni media said the attacks were carried out by Rujum drones, which drop small, grenade-like munitions. Saudi media reported there were significant casualties on both sides during fighting on Thursday and that the Ansar Allah attacks also hit civilian infrastructure, but no death toll was provided.The war in Yemen reignited following Saudi airstrikes that targeted the Sanaa International Airport in July, which prompted Ansar Allah to impose a blockade on Saudi shipping, calling the policy a “blockade for a blockade.”
Iran Urges Japan to Explain F-16 Operations From Misawa Base - Caspianpost.com Iranian Foreign Minister Abbas Araghchi has called on Japanese citizens to demand explanations from their government over the reported use of F-16 fighter jets from the US Misawa Air Base in operations in the Middle East.In an interview with Kyodo, Araghchi said Japanese citizens who value peace should seek accountability from Tokyo over what he described as US actions.“Peace-loving Japanese people should demand responsible explanations from the Japanese government regarding the crimes of the US,” the Iranian diplomat said.Araghchi said that the attack on Iran demonstrated that US military bases in Japan are not used solely for the country’s defense but also support what he described as Washington’s aggressive policies.He specifically pointed to the Misawa Air Base as an example, raising questions about Japan’s role and the use of US military facilities on its territory in operations beyond the region.
Israeli Defense Minister Says Ethnic Cleansing Is the Only 'Real Solution' for Gaza - Israeli Defense Minister Israel Katz said on Wednesday that the only “real solution” for Gaza was the ethnic cleansing of the Palestinian population, which he calls “migration,” and vowed that Israel will achieve this goal.“There is no real solution for Gaza in the end without migration,” Katz told reporters at a conference hosted by the Israeli news site Ynet, according to Middle East Eye. “The moment will come. When will it come? When it becomes clear that Hamas is not meeting its commitment. Then we will get a green light to move forward militarily, territorially, and in other areas, and this thing will gain momentum,” Katz added.While accusing Hamas of “not meeting its commitments,” Israel has constantly violated the October 2025 Gaza ceasefire deal and has rejected a US proposal for a deal under which Hamas would give up its weapons. Katz has previously said that even if Hamas does disarm, Israel wouldn’t withdraw from Gaza and would begin establishing “Nahal outposts,” a type of Jewish settlement in Israeli-occupied territory that are first populated by Israeli soldiers with the goal of transitioning them to permanent civilian communities.In his comments on Wednesday, Katz acknowledged Israel’s main obstacle to carrying out the ethnic cleansing of Gaza was the lack of countries willing to facilitate it and take in Palestinians from Gaza, though he suggested it could happen with US support. “We are fully prepared to move them out if it becomes possible – by sea, by air, by every way possible. Egypt is not willing, so it won’t be through them,” he said.“What’s delaying it is that the accepting countries want US support. Every country that is willing wants American backing. Currently, President Trump didn’t cancel this; he froze it. All the Arab countries came to him due to their pressure on this matter,” Katz added. Katz has been openly advocating for the ethnic cleansing of Gaza since early 2025, around the same time President Trump began saying that Palestinians should leave Gaza, though it’s been clear from the start of Israel’s genocidal war that the Israeli government’s ultimate goal.
Israel's Ben Gvir Unveils Plan To Remove All Palestinians From Gaza - Israeli National Security Minister Itamar Ben Gvir on Thursday unveiled a plan for the ethnic cleansing of Gaza’s Palestinian population, which he and other Israeli ministers refer to as “voluntary migration,” a day after Israeli Defense Minister Israel Katz said the removal of Palestinians was the only “real solution” for Gaza. Ben Gvir dubbed his plan “Disengagement 710” and said that it would involve removing 250,000 Palestinians from Gaza in the first year, 1.11 million within three years, and finally, 1.86 million over seven years. He said that his Jewish Power party would demand the establishment of an “emigration ministry” in the next Israeli government following the upcoming October elections. In remarks on the plan, Ben Gvir said that he had been considered “delusional” for seeking the ethnic cleansing of Gaza until President Trump called for Palestinians to leave the territory early last year. “At first, I was treated as a delusional extremist,” Ben Gvir said, according to The Times of Israel. “Then, one day, everything changed: President Trump publicly declared that encouraging emigration was a solution to the Gaza issue. Suddenly, Ben Gvir’s plan became legitimate. Suddenly, everyone became Ben Gvir.” Katz said a day earlier that Trump had not “canceled” the plan to remove Palestinians from Gaza but just “froze” it and that countries were willing to take in Gaza’s population if they had US support. “What’s delaying it is that the accepting countries want US support. Every country that is willing wants American backing. Currently, President Trump didn’t cancel this; he froze it. All the Arab countries came to him due to their pressure on this matter,” he said. Ben Gvir on Thursday also referenced Rehavam Ze’evi, nicknamed “Gandhi, an Israeli lawmaker who was assassinated in 2001 and was known for wanting to cleanse both Gaza and the West Bank of their entire Palestinian population. “What a shame they didn’t listen to Gandhi,” he said. “It’s time to admit it: Gandhi was right!”
Zelensky Warns 'Safe Days' Are Over for Civilian Aircraft in Russian Airspace as He Vows To Escalate Drone Attacks - Ukrainian President Volodymyr Zelensky vowed on Tuesday that Ukraine would escalate its drone attacks inside Russia and warned that “safe days” are over for civilian aircraft in Russian airspace.“Today, we want to warn every airline that uses Russian airspace, every insurer, and everyone who still uses Russia’s key airports: Russian airspace is becoming completely unsafe,” Zelensky said in a post on X that cited his nightly address. While the statement reads as an implicit threat against civilian aircraft, Zelensky insisted that wasn’t what he was doing. “Ukraine does not threaten civilian aviation as such – not a single civilian aircraft. There will simply be drones in Russia’s skies on a scale that has to be taken into account,” he said. ‘We in Ukraine do not want innocent lives to be lost. That is why we are warning our partners: the safe days in Russia’s skies are over. It is important that this is heard by the ambassadors of countries represented here in Ukraine, as well as by ambassadors working in Moscow,” Zelensky added.The Ukrainian leader also said in his address that at the request of the US, he paused attacks on Moscow and St. Petersburg from August 25 to August 27, which coincided with CIA Director John Ratcliffe’s visit to Moscow, and that he could take similar steps in the future but that for now, the “skies over Russia are for drones – not for civilian aviation.”Ukraine’s long-range drone attacks in Russia, which are supported by US intelligence, have already dramatically escalated this year, resulting in increasing civilian casualties inside Russia. Moscow has responded by escalating its missile and drone strikes across Ukraine, leading to more Ukrainian civilian casualties.
Moscow Says It Won't Let Ukraine Shut Down Russian Airspace After Zelensky's Threat - Russian officials vowed on Wednesday that Ukraine won’t be able to shut down Russian airspace after Ukrainian President Volodymyr Zelensky threatened a major escalation of drone attacks on Russian territory and said Russia’s skies would no longer be safe for civilian aircraft. Ukraine’s drones have disrupted flights in the cities in Russia being targeted for years now, but Zelensky is now vowing that his planned escalation will completely shut down Russian airspace.“We are constantly improving flight safety and airport security requirements, and we have solutions for all of this,” Russian Transportation Minister Andrei Nikitin said on Wednesday, according to Reuters. “We are working in close contact with the Ministry of Defense and the Russian National Guard. And I believe that we will not allow any significant disruption to civil aviation,” Nikitin added.Ukrainian officials have said that they have notified the International Civil Aviation Organization that Russia’s airspace would not be safe, but the Russian civil aviation authority Rosaviatsia said that the Ukrainian notifications “have no legal force and violate the Convention on International Civil Aviation.” Russian President Vladimir Putin was asked about Zelensky’s threat and said it amounted to “state terrorism,” and added that “terrorists” should not be negotiated with.“Look, I haven’t heard such statements, but if this was voiced, it is simply a bid for state terrorism. And I would like to note that they have been asking us to resume negotiations, seeking face-to-face meetings. Terrorists are not negotiated with,” Putin said on Tuesday night at a Shanghai Cooperation Organization (SCO) summit in Kyrgyzstan, according to Russia’s TASS news agency. In the meantime, Russian missile and drone attacks continued to pound Ukraine, where at least two civilians were killed in the city of Dnipro on Wednesday. Russian media also reported that Ukrainian attacks in the Russian-controlled Donetsk Oblast killed four civilians.
Russian Strike on Ukrainian Ammo Depot Kills at Least 38 - News From Antiwar.com -A Friday night Russian strike on a warehouse storing ammunition west of Kyiv has killed at least 38 people, according to Ukrainian officials, as Moscow continues its heavy bombardments across Ukraine, which it frames as a response to Ukraine’s escalated drone attacks on Russian territory.The Associated Press reported that the ammunition stored at the warehouse targeted by Russian forces sparked massive explosions and fires that spread through dozens of nearby homes and other buildings in the village of Myla. At least 52 other people were injured in the carnage. Ukrainian President Volodymyr Zelensky said that the massive casualties were the result of “terrible negligence on the part of those who stored explosives right next to people” and said there would be an investigation into why ammunition was stored at the warehouse.“The first strike was on an ammunition storage site that definitely shouldn’t have been there – a Defense Forces storage facility. Shells, mines, other ammunition, and drones detonated. The scale is significant,” Zelensky said in his nightly address on Saturday. “We have already spoken with the Prosecutor General, the Ministry of Internal Affairs, the Security Service of Ukraine, and the Commander-in-Chief – they have everything necessary for the investigation,” the Ukrainian president added.The strike has been reported as the deadliest Russian attack in Ukraine this year, though the casualties among Ukrainian soldiers along the frontline are never disclosed, and heavy fighting on the front continues. While Ukraine has dramatically ramped up its drone attacks inside Russia this year, Russian forces still have the momentum on the battlefield and continue to slowly make gains.
Germany blames Russia for drone attack on airport, announces countermeasures - Germany blames Russia for drone attack on airport, announces countermeasures After weeks of reticence, German officials on Tuesday blamed Russia for an attempted drone attack last month at Leipzig/Halle Airport and announced they would summon Moscow’s ambassador to Berlin, close a Russian consulate and take other measures in response. A drone stacked with military-grade explosives was found Aug. 4 next to a Ukrainian cargo plane at the airport, a hub that’s also used by European and NATO military aircraft. Security camera footage appeared to show the weapon striking the plane’s wing before falling to the ground without exploding. Later that day, a second drone collided with a cargo plane in flight. Ten days later, German media has reported, a third drone was found with traces of military-grade explosives in a field near the airport. Germany has concluded the attack was plotted by professionals working for the Russian state, Interior Minister Alexander Dobrindt told reporters in Berlin. “The means used — such as the drone configuration, components, explosives and detonation systems — are known to us from other hybrid operations by Russia and its war against Ukraine,” Dobrindt said. The device indicated “a high degree of technical expertise,” he said, but its deployment appeared to have been left to “low-level agents.” “Things didn’t go according to plan, thank God,” he said. Russia denied the allegation. President Vladimir Putin said German leaders were trying to distract voters from what he described as their failing policies ahead of regional elections this weekend. “Chancellor [Friedrich] Merz is facing dire times,” Putin told. “He doesn’t enjoy the trust of his people because he does not protect national interests,” he told reporters in Bishkek, Kyrgyzstan. The allegation, he said, was another “crude mistake” against the interests of the German people. “When such serious accusations are made, they must be backed by something,” Kremlin spokesman Dmitry Peskov warned told reporters. “Unless I am mistaken, no evidence has been presented. It is obvious that Germany is proceeding down a path of further escalation.” German leaders have said they do not intend to invoke Article 4, through which member states that consider themselves under threat may launch formal consultations within the alliance. German Foreign Minister Johann Wadephul described the attempted attack as one in “a long chain” of “aggressive actions in Europe” by Russia. Germany, which has helped lead European opposition to Russia’s war on Ukraine, “is no exception,” he said.
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