Gov. Gavin Newsom, D-Calif., signed into law Monday a bill that will expand the California Energy Commission’s streamlined certification program to allow it to speed approvals for geothermal energy, but he vetoed a bill to speed approvals of well-drilling for geothermal exploratory projects. “In addition to delaying much-needed regulations that are already in process, the [Geologic Energy Management] Division would need to substantially increase fees on geothermal operators to implement the new requirements imposed by the bill,” Newsom wrote in his veto message for the second bill, AB527. Newsom said in the message that while he supports the expansion of geothermal energy in California “as a much-needed source of baseload clean power,” he thinks that the increased fees would disincentivize geothermal development “beyond any incentive provided by a [California Environmental Quality Act] exemption for one part of a project’s permitting process.” The governor also noted that he signed AB1359 last year, which reformed the approval process for geothermal exploration, and he thinks it is “prudent that we understand the effects of these changes before granting wholesale CEQA exemptions with costly and complicated conditions.” AB527 would have allowed geothermal exploratory projects that GEMD deems to meet certain criteria to also be presumed to “have satisfied the requirements of CEQA for the geothermal exploratory project, including to support the issuance of any permit, funding, or other approval by a state or local agency, as provided.” AB531, which Newsom signed, makes geothermal projects one of the types of projects that — once the state Energy Commission certifies them as an “environmental leadership development project” — can benefit from a streamlined approval process under CEQA. The other projects that can receive that certification are solar or wind farms generating 50 MW or more, energy storage systems capable of storing 200 MWh or more, power plants 50 MW or

The broad mood in the oil market remains bearish, although there are discrepancies as to how gloomy crude’s prospects are, according to Citigroup Inc., summarizing views from clients in North America and Europe. “Conviction differs on the depth of downside,” analysts including Francesco Martoccia said in a note. “Some clients doubt that a price floor at $60 a barrel for Brent crude oil would be enough to induce a supply-and-demand reaction to balance a global liquids market generally seen heading for a surplus.” Oil prices have shed more than 10% this year, with global benchmark Brent posting back-to-back monthly losses in August and September. The weakness has been driven largely by expectations that supplies will run ahead of demand as OPEC+ loosens output curbs and rival drillers also step up production. Still, stockpiling by China has acted to support the market, with inventory builds so far seen concentrated away from the market’s main pricing centers. “Other clients expect a more moderate, orderly price correction, arguing that projected stock builds could continue to accumulate outside of key pricing hubs, certainly ex-Cushing,” the analysts said, referring to the storage hub in Oklahoma that’s the physical delivery point for West Texas Intermediate. The Organization of the Petroleum Exporting Countries and its allies endorsed another quota hike last weekend, although the increment — 137,000 barrels a day for November’s production — was smaller than some of the sums that had been reported in the run-up to the gathering. “Today’s slower non-OPEC+ growth and greater OPEC+ optionality, along with heightened geopolitical risks looming on large producers” such as Russia and Iran, could temper the pace of price adjustment, the analysts said. Brent futures — which tumbled 8% last week ahead of the OPEC+ supply decision — traded slightly lower at $65.80 a barrel on Thursday. “Within the energy complex, consensus

U.S. commercial crude oil inventories, excluding those in the Strategic Petroleum Reserve (SPR), increased by 3.7 million barrels from the week ending September 26 to the week ending October 3, the U.S. Energy Information Administration (EIA) highlighted in its latest weekly petroleum status report. That report, which was released on October 8 and included data for the week ending October 3, showed that crude oil stocks, not including the SPR, stood at 420.3 million barrels on October 3, 416.5 million barrels on September 26, and 422.7 million barrels on October 4, 2024. The report highlighted that data may not add up to totals due to independent rounding. Crude oil in the SPR stood at 407.0 million barrels on October 3, 406.7 million barrels on September 26, and 382.9 million barrels on October 4, 2024, the report revealed. Total petroleum stocks – including crude oil, total motor gasoline, fuel ethanol, kerosene type jet fuel, distillate fuel oil, residual fuel oil, propane/propylene, and other oils – stood at 1.694 billion barrels on October 3, the report highlighted. Total petroleum stocks were down 0.9 million barrels week on week and up 52.2 million barrels year on year, the report showed. “At 420.3 million barrels, U.S. crude oil inventories are about four percent below the five year average for this time of year,” the EIA said in its latest weekly petroleum status report. “Total motor gasoline inventories decreased by 1.6 million barrels from last week and are about one percent below the five year average for this time of year. Finished gasoline inventories increased, while blending components inventories decreased last week,” it added. “Distillate fuel inventories decreased by 2.0 million barrels last week and are about six percent below the five year average for this time of year. Propane/propylene inventories decreased by 2.9 million

Jeff Dennis is executive director of the Electricity Customers Alliance, a coalition that advocates for customer-centric solutions to grid modernization and energy affordability challenges. A modern economy requires modern energy solutions to meet the growing energy demand created by reshored manufacturing, increased electrification of homes, businesses, and vehicles, and — of course — data centers. Virginia and the Mid-Atlantic house the data center capital of the Western world, and the Commonwealth is positioned to lead America’s push to win the global artificial intelligence race. Data center growth can deliver many economic benefits to communities. However, this increased electricity demand requires smartly planned power infrastructure and a focus on short- and long-term solutions to address consumers’ concerns about their power bills. Planning and building electricity infrastructure to meet rapidly growing demand while keeping electricity affordable for all consumers will take time. However, data centers and manufacturers need power now to win the AI race and capture new economic opportunities in manufacturing and the digital economy. Virginia must capitalize on short-term opportunities to expand and maximize the use of our existing grid assets to deliver more power while setting the foundation for smart, long-term buildout of our shared electricity grid. To address this challenge, the General Assembly passed, and Gov. Glenn Youngkin signed, legislation to encourage deployment of advanced transmission technologies that maximize the amount of power that can be delivered from our existing lines. Beginning in 2026, the legislation requires the State Corporation Commission to consider the use of new power line technologies called “advanced conductors” when deciding how to bring more power supply onto the grid. Many other Mid-Atlantic states have followed Virginia’s lead in encouraging adoption of these technologies to help meet our needs today while establishing a foundation for an efficient future electricity system. That’s great news for consumers —

Listen to the article 3 min This audio is auto-generated. Please let us know if you have feedback. Dive Brief: Electric utilities are on pace to spend nearly $208 billion on grid upgrades and expansions this year, the highest amount ever, the Edison Electric Institute said Tuesday. The group represents investor-owned utilities. And more growth in capital expenditures is on the way, as the sector rushes to meet growing demand, according to EEI’s 2024 financial review. The group’s members are projected to make capital expenditures of more than $1.1 trillion between 2025 and 2029. U.S electricity generation rose 3% in 2024 “and is expected to rise for the foreseeable future,” EEI said. Generation investments as a share of the industry’s total capital expenditures have risen for four straight years, it said. Dive Insight: After years of relatively stagnant growth, the electric sector is moving quickly to meet new demand from AI data centers, industrial expansion, electrification and other sources. The U.S. generated 4.3 million GWh in 2024, “the largest annual jump in five years,” EEI said. The group anticipates an annual growth rate of 1.7% through 2040, when domestic generation could surpass 5.4 million GWh.     Meeting the new demand requires significant grid investments. IOU capital expenditures grew more than 16% from 2024 to 2025, based on anticipated investments, EEI said. Permission granted by Edison Electric Institute “Our capital expenditures are higher than any other sector in the U.S. economy, outpacing transportation, retail, and other capital-intensive industries,” EEI President and CEO Drew Maloney wrote in a letter accompanying the report. “As always, we remain committed to keeping customer bills as low as possible as we work to deliver the reliable, secure electricity that is enabling innovation and enhancing the energy leadership of the United States.”   But some experts say retail consumers are footing the bill

Listen to the article 11 min This audio is auto-generated. Please let us know if you have feedback. As electricity demand grows, alongside wind and solar’s share in the U.S. energy mix, concerns about renewables’ reliability are being raised more frequently — including at the highest levels of the federal government. “With the electricity grid, you have to match supply and demand in every moment in time,” Energy Secretary Chris Wright said recently on Fox News. “With wind and solar, you don’t know when they’re going to be there, and you don’t know when they’re going to go away.” Wright went on to say the development of renewables has led to an “extra distribution grid” that has raised energy prices.  But utility planners, grid operators and analysts say wind, solar and batteries are an important part of an evolving power system in which intermittent resources can be reliably scheduled and called upon using sophisticated software and other tools. They also point to both the levelized cost of electricity for renewables and their competitiveness in automated energy markets that select the least cost units to run in each hour. “System operators don’t decide whether resources bidding into the market are good or bad,” said Rob Gramlich, president of energy sector consultant Grid Strategies, in an interview. “There is no central decision maker,” he said. “Markets don’t play favorites.” ERCOT’s multi-resource price-selected portfolio for August 20, 2025, at 5:50 PM CDT ERCOT “dashboard” [jpg]. Retrieved from dashboard. With generators retiring, demand rising, and construction, financing, permitting and supply chain challenges growing, operators and analysts acknowledged concerns over the future of the U.S. power system. Many called for diversification of resources, including renewables and storage, to protect electricity reliability and affordability. “The objective of planning is a portfolio of diverse resources at the least cost