The announcement, made at the G20 Energy Ministers’ Meeting in Houston, also included a proposal to eliminate remaining federal greenhouse-gas requirements for fossil-fueled power plants. The proposal could make it more difficult for future administrations to impose similar climate regulations on the power sector under the Clean Air Act. The Edison Electric Institute has previously said that “critically needed new natural gas-fired generation” is crucial to providing baseload and peaking power, supporting grid reliability and balancing renewable resources, and that a stable greenhouse-gas regulatory framework is important to new generation investment. EPA Administrator Lee Zeldin said the rollback would enable development of new generating infrastructure. Gas-fired development expands The change comes as developers are planning a significant expansion of US gas-fired generation to serve growing electricity demand. Global Energy Monitor reported in August that US gas-fired power capacity in development had risen 50% in first-half 2026 to 378 Gw. Of that, 189 Gw was associated with projects intended to serve data-center demand. While not all projects in development will be built, the scope points to significant potential additional demand for natural gas. The repeal could improve the prospects for projects that otherwise faced higher costs or operating restrictions under the Biden-era rules. US electric power-sector natural gas consumption increased 31% to an average 35.8 bcfd in 2025 from 27.3 bcfd in 2016, according to the Energy Information Administration (EIA). EIA now forecasts US electricity use will reach record levels in both 2026 and 2027, driven in part by data-center development and increased manufacturing activity. Overall US gas consumption also is forecast to reach record levels in both years, rising to 92.2 bcfd in 2026 and 94.3 bcfd in 2027 from 91.9 bcfd in 2025. More gas-fired generation would also create additional demand for gas pipelines and storage, particularly in regions

Caturus LLC plans to nearly double the expected capacity of its Commonwealth LNG plant currently under construction in Cameron Parish, La. The company is planning a five-train, 7.75 million tonnes/year (tpy) expansion, which would bring the site’s planned capacity to about 17.25 million tpy, the company noted in a release Sept. 15.  Caturus LLC in May reached final investment decision (FID) on the current design of a six-train, $13.5-billion Commonwealth LNG plant. That sanction included closing of $9.75 billion in project financing and marked the start of full construction of the 9.5 million tpy plant. Phase 1 operations are expected in 2030. Base project construction is progressing on schedule with operations targeted for 2030, with about 8.5 million tpy capacity subscribed under long-term sale and purchase agreements, the company said. The expansion project is targeted to enter service in the early 2030s. Caturus said the expansion reflects strong market demand for additional US LNG volumes and long-term supply security, while capitalizing on infrastructure and commercial momentum already established at Commonwealth LNG. The expansion would leverage land already controlled by Caturus and draw on the engineering, procurement, and construction program established for the initial phase of Commonwealth LNG. The company also said its integrated upstream-to-export model, including gas production from its South Texas acreage, would support the additional liquefaction capacity.

The US Treasury Department Sept. 14 amended Venezuela’s sanctions license to prevent unauthorized changes to the governance of Citgo Petroleum Corp. and its two US corporate parent structures, PDV Holding Inc. and Citgo Holding Inc. The license now explicitly blocks any unauthorized “appointment, removal, or replacement of any director, officer, or other corporate governance official” at the three companies. The move comes as Venezuelan interim President Delcy Rodríguez works to regain control of the country’s overseas assets. Her administration has replaced law firms representing Venezuela and state-owned PDVSA in foreign litigation and arbitration, while opposition-appointed entities that have overseen Citgo are preparing to wind down. The license amendment freezes the current corporate boards until finalization of Amber Energy’s acquisition of PDV Holdings. The acquisition gives Amber Energy, owned by Elliott Investment Management, assets that include about 800,000 b/d of refining capacity on the US Gulf Coast and in the Midwest. It also obligates Amber to disperse $5.89 billion in a structured payout to 15 international creditors, including ConocoPhillips, whose assets were seized by the previous government. While a US federal court approved the deal, Amber still requires a US Treasury license to take title to the shares. The deal would also need to survive an appeal in the US Third Circuit Court of Appeals in Philadelphia, where the Venezuelan government is arguing the price is too low. Venezuela and state-owned PDVSA would still be on the hook for about $15 billion in remaining payouts to companies for seized assets.

Russian refinery runs remain near July 2026 lows and are likely to recover only gradually from September onward. Russia’s ban on diesel exports has already removed 10% of waterborne supply from the global market. Further decline in Russian refinery runs could amplify the risk to global diesel markets by leading Russia to import fuel to backfill domestic needs, compounding the outright loss of the near 1 million b/d of diesel exports. Limited spare capacity raises winter risks Meanwhile, the world’s remaining unconstrained refining capacity is already running at close to maximum levels. Refinery utilization in the US has approached 97% this summer, while Europe and North America continue to operate at or near multi-decade highs in response to record margins. The industry is now approaching fall turnaround season with a significant incentive to keep pushing and little spare capacity left to offset unexpected disruptions. “The market has survived the first phase of the crisis because inventories, trade flows, and refinery flexibility absorbed much of the shock. Those shock absorbers are not disappearing, but they are becoming progressively weaker. Markets are entering winter with less room for error than they had in the spring,” said Daniel Evans, global head of fuels and refining research, S&P Global Energy. For governments and policymakers, the challenge is increasingly likely to center on balancing energy price affordability, inflation, and security of supply. High diesel prices directly impact costs for freight transport, agriculture, construction, manufacturing, and residential heating. Although the market has so far avoided an outright supply crisis, persistently low inventories, high prices, and limited spare capacity have heightened the risk of government interventions. Diesel remains the fuel most vulnerable to shortages. With a surge in demand during the harvest season, the approach of winter heating needs, depleted inventories, and no immediate prospect of supply

Saudi Arabia has shut its 1,200-km (745-mile) East-West pipeline following Sept. 11, 2026, drone attacks. Saudi officials said the drones were launched from Iraq but have not disclosed the extent of any injuries or damage or provided a timetable for repairs. Satellite imagery released Sept. 13 appeared to show substantial damage to a pumping station along the pipeline. East-West, which has a maximum design capacity of 7 million b/d, had been operating at 2 million b/d in August according to Kpler, as increased Houthi attacks in and around Bab El-Mandeb reduced Red Sea traffic. Earlier in the Iran war, flows had been 4-5 million b/d, with the pipeline serving as an alternative to the Strait of Hormuz for Saudi exports. Stay updated on oil price volatility, shipping disruptions, LNG market analysis, and production output at OGJ’s Iran war content hub. Saudi oil buyers and traders told Reuters that stocks at Red Sea terminals could support exports for 5-7 days if the pipeline remains out of service. A prolonged shutdown could remove as much as 4% of global oil supply, according to market estimates. Repair estimates have ranged from several days to as long as 6 weeks. Saudi Arabia reported to the Organization of Petroleum Exporting Countries (OPEC) that its crude production declined to 6.2 million b/d in August, down from 10.9 million b/d in February. Overall OPEC+ crude production fell 1.5 million b/d in August to 33.1 million b/d. Production from the 17 quota-bound OPEC+ members declined 980,000 b/d to 27 million b/d, 7.3 million b/d below their August target. On Sept. 6, OPEC+ agreed to maintain October production targets at September levels. Global oil prices climbed sharply Sept. 14 in the wake of the shutdown. Brent crude futures rose above $108/bbl, reaching levels not seen since May, before retreating.

In this Insights episode of the Oil & Gas Journal ReEnterprised podcast, downstream editor and lead reporter Robert Brelsford talks with Joe Barnes, principal of Barnes’ Engineering Consultants and a veteran oil and gas operations, maintenance, reliability, and major-projects leader with more than 30 years of industry experience. Barnes, who spent roughly half of his career in refining and half in exploration and production, discusses why process safety management must remain a central concern for everyone working in oil and gas—not only safety professionals. Drawing on his experience with a major refinery accident and the aftermath of a separate major offshore incident, Barnes explains why good intentions are not enough to prevent major incidents, particularly in times when the potential for high margins could tempt operator’s into promoting maximized production over execution of maintenance on processing and production installations to ensure safe and reliable operations. During the conversation, Robert and Joe examine recurring root causes identified through Barnes’ review of process-safety incidents dating back to the mid-1980s, including absence of  leadership, poor communication, inadequate risk identification and mitigation, aging equipment, deferred maintenance, workforce turnover, and the loss of experienced personnel. They also discuss why the industry has sometimes failed to consistently share and apply lessons from previous incidents, particularly when investigation findings are not widely accessible. The two consider the difference between personal safety and process safety metrics, the warning signs that preceded the 2005 BP Texas City refinery explosion, and the role of management of change (MOC) in evaluating staffing, maintenance, turnaround, efficiency, and capital-reduction decisions. Barnes also outlines the questions boards and executive leaders should be asking to ensure that process safety remains a business priority across economic cycles. Robert and Joe further explore how refineries can use past incident scenarios as practical training tools, strengthen external oversight