Israeli natural gas flows to Egypt returned to normal levels after a truce with Iran allowed the Jewish state to reopen facilities shuttered by the 12-day conflict. Daily exports have climbed to 1 billion cubic feet per day, according to two people with direct knowledge of the situation. That’s up from 260 million cubic feet when Israel’s Leviathan gas field, the country’s biggest, restarted on Wednesday, they said, declining to be identified because they’re not authorized to speak to the media.  The increased flows have let Egyptian authorities resume supplies to some factories that had been halted because of the shortages. Israel temporarily closed two of its three gas fields – Chevron-operated Leviathan and Energean’s Karish – shortly after launching attacks on Iran on June 13. The facilities that provided the bulk of exports to Egypt and Jordan resumed operations last week after a US-brokered ceasefire with the Islamic Republic took hold. The ramped-up supplies are a relief for Cairo, which has swung from a net exporter to importer of natural gas in recent years. As Israel and Iran traded blows, Egypt enacted contingency plans that included seeking alternative fuel purchases, limiting gas to some industries and switching power stations to fuel oil and diesel to maintain electricity output. What do you think? We’d love to hear from you, join the conversation on the Rigzone Energy Network. The Rigzone Energy Network is a new social experience created for you and all energy professionals to Speak Up about our industry, share knowledge, connect with peers and industry insiders and engage in a professional community that will empower your career in energy.

California’s energy market regulator is backing off a plan to place a profit cap on oil refiners in the state.  Siva Gunda, vice chair of the California Energy Commission, said during a Friday briefing that the cap would “serve as a deterrent” to refiners boosting investments in the state. Gunda said the commission wants to increase gasoline supply in California after two refineries announced plans to close in the next year, accounting for about one-fifth of the state’s crude-processing capacity. The recommendation marks a reversal from years of regulatory scrutiny by Governor Gavin Newsom and the California Energy Commission that contributed to plans by Phillips 66 and Valero Energy Corp. to shut their refineries. The closings prompted Newsom to adjust course in April and urge the energy regulator to collaborate with fuel makers to ensure affordable and reliable supply. Gunda wrote in a Friday letter to Newsom that the commission should pause implementation of a profit margin cap and focus on fuel resupply strategies instead. It comes more than two years after Newsom and state lawmakers gave the energy commission authority to determine a profit margin on refiners and impose financial penalties for violations. The state will be looking to increase fuel imports to make up for the loss of refining capacity, Gunda said. In the short term, California gas prices could rise 15 to 30 cents a gallon because of the loss of production, he said. A spokesperson for the energy commission said the estimated price increases would be mitigated by the plan presented on Friday. Californians already pay the highest gasoline prices in the country. Wade Crowfoot, secretary of the California Natural Resources Agency, said residents want the state to transition away from oil and gas yet they need to prevent cost spikes. “We get it,” he said.

Utility regulators from about 35 states are urging the Federal Energy Regulatory Commission to sharply limit a 0.5% return on equity incentive the agency gives to utilities that join regional transmission organizations. “The time has come for the Commission to eliminate its policy of granting the RTO Participation Adder in perpetuity, if not to eliminate this incentive altogether,” the Organization of PJM States, the Organization of MISO States, the New England States Committee on Electricity and the Southwest Power Pool Regional State Committee said in a Friday letter to FERC. The state regulators and others contends the RTO incentive adds millions to ratepayer costs to encourage behavior — being an RTO member — that they would likely do anyway. In 2021, FERC proposed limiting its ROE adder to three years. FERC Chairman Mark Christie supports the proposal as well as limiting other incentives aimed at encouraging utilities to build transmission lines. However, it appears he has been unable to convince a majority of FERC commissioners to reduce those incentives. Christie’s term ends today, although he plans to stay at the agency until at least FERC’s next open meeting on July 24. Limiting the ROE incentive could reduce utility income. Public Service Enterprise Group, for example, estimates that removing the incentive would cut annual net income and cash inflows by about $40 million for its Public Service Electric & Gas subsidiary, according to a Feb. 25 filing at the U.S. Securities and Exchange Commission. The utility earned about $1.5 billion in 2024. Ending the incentive would reduce American Electric Power’s pretax income by $35 million to $50 million a year, the utility company said in its 2023 annual report with the SEC. In April, WIRES, a transmission-focused trade group, the Edison Electric Institute, which represents investor-owned utilities, and GridWise Alliance, a

Dive Brief: Keeping electricity affordable for consumers is a “formidable challenge” amid projections of declining generation capacity reserves and persistent uncertainty around the scale and pace of future load growth, ICF International Vice President of Energy Markets Maria Scheller said Thursday.  Meanwhile, broad policy uncertainty and an increasingly shaky regulatory environment give utilities and capital markets pause about expensive new infrastructure investments that could become stranded assets, Scheller said in a webinar on ICF’s “Powering the Future: Addressing Surging U.S. Electricity Demand” report. Policy conversations around import tariffs, federal energy tax credits and permitting reform are unfolding as the balance of electricity demand shifts from residential and business consumers to technology and industrial customers, which tend to require around-the-clock power, Scheller added. Dive Insight: The coming shift in U.S. electricity consumption represents less of a new paradigm than a return to the industrial-driven demand the country saw from the 1950s into the 1980s, after which deindustrialization and consumer-centric trends like the widespread adoption of air conditioning, electric resistance heating and personal computing shifted the balance toward the residential segment, Scheller said. The shift is important because unlike residential loads, which show considerable seasonal and intraday variation, industrial loads are flatter, less weather-dependent and more sensitive to voltage fluctuations, Scheller said. By 2035, ICF expects nearly 40% of total U.S. load will have a “flat, power-quality-sensitive profile,” and that overall load will grow faster than peak load, she said. In 2030, ICF projects more than 3% annual power consumption growth, compared with less than 2% annual peak load growth, according to a webinar slide. That’s not to say residential demand won’t also grow in the next few years as consumers electrify home heating and buy more electric vehicles — only that data centers and other industrial demand will “dwarf” it, Scheller

Edwin Lyman is director of nuclear power safety at the Union of Concerned Scientists. A White House executive order issued last month targeting the independence of the Nuclear Regulatory Commission, the federal agency that oversees the safety and security of U.S. commercial nuclear facilities and materials, as well as the possibly illegal firing earlier this month of Commissioner Christopher Hanson by President Donald Trump, are raising serious concerns about the agency’s effectiveness as a regulator going forward. While I’ve often been a critic of the NRC for taking actions favoring the nuclear industry at the expense of public health and safety, preserving the NRC in its current form is the best hope for heading off a U.S. nuclear plant disaster like the 2011 Fukushima Daiichi reactor meltdowns in Japan. My long-standing beef with the NRC has primarily been with its political leadership, not with the rank-and-file staff of highly knowledgeable inspectors, analysts and researchers committed to helping ensure that nuclear power remains safe and secure. These professionals are well aware how quickly things can go south at a nuclear power plant without rigorous oversight. They know from experience what obscure corners to look in and what questions to ask. And they can tell — and are not afraid to push back — when they are getting sold snake oil by fly-by-night startups looking to make easy money by capitalizing on the current nuclear power craze. Technical rigor and expert judgment form the bedrock of this work. But when staff are compelled to sweep legitimate safety concerns under the rug in the interest of political expediency, many will leave rather than compromise their scientific integrity. So there is little wonder that a wave of experienced personnel is headed out the door in the wake of the executive order on NRC “reform,”

North America dropped six rigs week on week, according to Baker Hughes’ latest North America rotary rig count, which was released on June 27. Although the U.S. dropped seven rigs week on week, Canada added one rig during the same timeframe, taking the total North America rig count down to 687, comprising 547 rigs from the U.S. and 140 rigs from Canada, the count outlined. Of the total U.S. rig count of 547, 533 rigs are categorized as land rigs, 12 are categorized as offshore rigs, and two are categorized as inland water rigs. The total U.S. rig count is made up of 432 oil rigs, 109 gas rigs, and six miscellaneous rigs, according to Baker Hughes’ count, which revealed that the U.S. total comprises 496 horizontal rigs, 38 directional rigs, and 13 vertical rigs. Week on week, the U.S. land rig count reduced by five, its offshore rig count decreased by two, and its inland water rig count remained unchanged, the count highlighted. The country’s oil rig count dropped by six, its gas rig count dropped by two, and its miscellaneous rig count increased by one, week on week, the count showed. The U.S. horizontal rig count dropped by six, its directional rig count dropped by two, and its vertical rig count increased by one, week on week, the count revealed. A major state variances subcategory included in the rig count showed that, week on week, Wyoming dropped five rigs, and Oklahoma, Louisiana, and Colorado each dropped one rig. A major basin variances subcategory included in Baker Hughes’ rig count showed that, week on week, the Granite Wash basin dropped one rig and the Permian basin dropped one rig. Canada’s total rig count of 140 is made up of 94 oil rigs and 46 gas rigs, Baker Hughes pointed