US Senate negotiators introduced bipartisan permitting legislation Sept. 30 that would accelerate federal reviews, sharply curtail the window for legal challenges to energy projects, and improve predictability for developers. The agreement is a breakthrough in the Senate, where lawmakers have struggled for years to advance permitting reform. The Bipartisan American Affordability and Jobs Act would impose a 150-day window for certain challenges to federal permitting decisions and provide greater certainty that permitted energy and infrastructure projects retain their approvals. It also would reform Clean Water Act reviews that can delay energy infrastructure, establishing more predictable environmental reviews. The changes could reduce regulatory and litigation uncertainty for interstate gas pipelines, which are often subject to both federal environmental reviews and state water-quality certifications. The four senators behind the deal—Mike Lee (R-Utah), Martin Heinrich (D-NM), Shelley Moore Capito (R-W.Va.), and Sheldon Whitehouse (D-R.I.)—said the agreement also addresses high-profile electricity issues by expanding federal authority over transmission permitting and requiring data centers to pay associated transmission costs rather than shifting them to other electricity customers. The bill, released after months of negotiations, still faces hurdles. Senate negotiators reached an agreement on the legislative text, but Democrats also want assurances that wind and solar projects would benefit from the same streamlining and clarity from the Trump administration on what it means to return wind and solar permitting to “regular order,” issues that remain unresolved. The Senate would consider amendments before voting on the legislation. The target is a vote after the Nov. 3 midterm elections, with Capito noting the permitting bill could be the first vote when the Senate returns. The House has passed its own permitting legislation, the SPEED Act. While both bills would streamline federal permitting and limit litigation, they take different approaches to reforming NEPA, and the Senate legislation addresses transmission

Oil & Natural Gas Corp. Ltd. subsidiary Mangalore Refinery and Petrochemicals Ltd. (MRPL) reported one fatality and one injury after a fire at its refinery in Karnataka, Mangalore, India, on Sept. 30. The incident began at about 12:20 p.m. local time when a high-pressure cold separator ruptured in the refinery’s delayed coker gas oil hydrotreater unit, or coker heavy gas oil hydrotreating unit, MRPL said in separate regulatory filings to BSE Ltd. The company isolated the affected unit’s battery limits and deployed emergency response and firefighting teams. MRPL said the fire was brought under control and completely extinguished by 2:47 p.m. local time. During subsequent combing and inspection operations following the fire’s full extinguishing, personnel found the body of one deceased individual at the affected plant. A second person sustained burn injuries and was receiving hospital treatment, the company said. MRPL issued its first update while firefighting operations were continuing. It said one minor injury had been reported at that stage and that the injured person was out of danger. The company did not provide details on the identities of those involved, the cause of the separator rupture, or the extent of damage to the unit. It also did not disclose whether the incident affected broader refinery operations or production. MRPL said further verified information would be released as it becomes available.

The share of exploration and production (E&P) companies planning to add to their capital spending in 2027 versus this year has grown to 22% from 10% in June, a new Federal Reserve Bank of Dallas survey shows. Of the more than 80 E&P leaders in Texas, northern Louisiana, and southern New Mexico who responded to the latest Dallas Fed Energy Survey earlier this month, a third said their oil production has increased over the past 3 months and only 1 in 8 said they’re pumping less oil. On the capex side, 46% said their spending this quarter was up from this year’s second quarter. Both of those data points were down slightly from the Fed’s June poll. What appears to be changing more substantially on the ground in the Permian basin, Eagle Ford, and other areas in the Dallas Fed’s footprint are expectations about 2027 spending. Only 5% of E&P leaders now expect they’ll trim capex next year while 73% said they’ll keep spending level. Three months ago, those figures were 10% and 81%, respectively. That means 22% of executives now think their capex will climb in 2027 compared to less than 10% 3 months ago. And it suggests that production in the region will climb from here as producers look to take advantage of consistently high prices for their products—even if they’ve retreated from their recent highs. Jon Costello, an analyst at HFI Research, said an industry response—with Texas firms in the vanguard—to higher prices similar to how it recovered starting in late 2016 would grow total US production more than 4% to about 14.4 million b/d.

US crude oil inventories for the week ended Sept. 25, excluding the Strategic Petroleum Reserve, increased by 900,000 bbl from the previous week, according to data from the US Energy Information Administration (EIA). At 427.3 million bbl, US crude oil inventories are 2% above the 5-year average for this time of year, the EIA report indicated. Gasoline output averaged 9.5 million b/d, and distillate production decreased to 5.0 million b/d. Propane-propylene inventories increased 1.8 million bbl, 20% above the 5-year average. Total commercial petroleum inventories decreased by 7 million bbl for the week. Distillate inventories decreased 2.3 million barrels, 14% below the five-year average. US crude oil refinery inputs averaged 16.3 million b/d for the week ended Sept. 25, which was 554,000 b/d less than the previous week’s average. Refineries operated at 92.5% of capacity. Crude oil imports decreased 179,000 million b/d to 5.7 million b/d. The 4-week average of 6.4 million b/d is 4.8% above the year-ago level. Gasoline imports averaged 500,000 b/d; distillate imports averaged 153,000 b/d. Over the past four weeks, total product supplied averaged 20.8 million b/d, up 2.1% year over year. The 4-week average for gasoline product supplied increased 0.3% year over year to 8.7 million b/d, while the 4-week average for distillate product supplied increased 5.2% to 3.8 million b/d. The 4-week average for jet fuel product supplied increased 6.5% year over year.  

INEOS Energy and its partners Harbour Energy PLC and Nordsøfonden AS have begun commercial operations at Project Greensand, the European Union’s (EU) first full-scale site for transport and permanent offshore storage of CO2. The CO2 will come mainly from Danish biomethane plants. Once captured, the CO2 is liquefied, sent by truck to a dedicated CO2 terminal at Port Esbjerg, Denmark, shipped aboard the purpose-built CO2 carrier Carbon Destroyer 1, and injected into the Nini West reservoir in the Danish North Sea. Nini West is a depleted oil field 250 km offshore, and roughly 1,800 m below the seabed in about 200-ft water depths. The initial commercial phase provides storage capacity of up to 400,000 tonnes/year (tpy) of CO2, with plans to expand to 4-8 million tpy as demand increases. The EU is working to meet carbon capture and storage targets of 50 million tpy by 2030, rising to 250–280 million tpy by 2040, but remains far from that scale.

US refiners are benefiting from a tightening global diesel market as disruptions in the Middle East and Russia constrain supply, lift crack spreads, and keep refinery utilization near capacity, according to Morningstar DBRS. Morningstar DBRS said the current market is creating a strong but likely temporary earnings and cash-flow tailwind for US refiners. High utilization, low inventories, and elevated diesel margins are supporting operating cash flow and EBITDA, although the benefit could fade if geopolitical disruptions ease. Global diesel supply has tightened since the start of the Iran war as refinery outages, lower crude runs, and constraints on product exports through the Strait of Hormuz reduced Middle East supply. Saudi Arabia and Kuwait diesel exports were down about 40% year over year in July. Russia, meanwhile, extended restrictions on most diesel exports into October. Russia exported more than 780,000 b/d of diesel in 2025, just under 10% of global exports. US refiners have increased output and exports to help fill the gap. Distillate production averaged 5.1 million b/d during January-August, the highest since 2019. Refinery utilization is already near capacity in several regions, leaving limited room for further increases in output. PADDs 2 and 4 are operating at or near capacity, supported by discounted Canadian crude, strong diesel export demand, and agricultural and rural consumption. Together, the two regions account for more than 27% of US refining capacity and have an average distillate yield of 32%, DBRS said. On the Gulf Coast, PADD 3 refinery utilization exceeded 98% in September. More than half of US refining capacity is concentrated in PADD 3, where complex refineries serve both export markets and other US regions. The stronger operating environment is translating into higher refining margins. The US Gulf Coast ultra-low-sulfur diesel premium over crude has risen to its highest level this year,