Dive Brief: Import tariffs could raise battery costs for U.S. utility-scale energy storage installations by more than 50% and make the United States the world’s most expensive solar market, Wood Mackenzie said on June 2. Prices for four-hour battery systems have already risen 56% to 69% since January and are expected to remain volatile “until clarity returns,” Anza Renewables said Thursday in a separate quarterly pricing report.  U.S. energy storage developers will likely depend on imports well into the future as domestic manufacturing capacity expands from 6% of present-day demand to 40% of expected 2030 demand, Wood Mackenzie said.  Dive Insight: Anza’s quarterly report shows significant market impacts from the Trump administration’s tariff policy. By April, imported batteries faced a universal 10% tariff, a further 145% tariff on Chinese components and stepped-up Section 301 levies dating back to the Biden administration, Anza said.  Every battery manufacturer Anza tracks had paused price quotes by early April, according to the quarterly pricing report. Many resumed quoting on shorter validity windows in late April, ahead of a 90-day reprieve on May 14 that cut the China tariff down to 30%, Anza said. The temporary tariff reduction could indirectly increase final pricing for domestic energy storage developers next quarter as shipping prices rise amid a rush to bring inventory into the U.S., Anza said. Four-hour battery system costs increased more than 50% since January despite a 17% drop in spot prices for lithium carbonate, a key input for lithium-ion batteries, over a similar timeframe. The longer-term energy storage cost outlook depends on where import tariffs settle, Wood Mackenzie said. Its consultants considered a milder “trade tensions” scenario, with stable tariffs of 34% on China and 10% on the rest of the world by year-end 2026, and a more severe “trade war” scenario with a

Legislation directing the U.S. secretary of energy to conduct assessments of the U.S. electricity generation and transmission supply chains was approved by a House energy subcommittee on Thursday and now goes to the House Committee on Energy and Commerce. The Electric Supply Chain Act directs the energy secretary to prepare “periodic assessments” that include “any trends, risks, and vulnerabilities in the supply, demand, and availability of components for or related to generating or transmitting electricity, including components that are necessary for the construction or deployment of facilities that generate or transmit electricity.” The bill would require the secretary of energy to submit a report to Congress within one year of the legislation being enacted. The bill “takes a proactive approach to identifying and addressing emerging issues that affect the power sector,” Rep. Bob Latta, R-Ohio, said in April at a hearing on ensuring domestic energy reliability. Latta, who is chairman of the House Energy and Commerce Committee’s subcommittee on energy, introduced the legislation. Electrical equipment manufacturers say they support the bill. “We must prioritize grid reliability by ensuring all relevant voices involved in supplying energy are at the table, including supply chain vendors and the manufacturers of critical grid components,” Spencer Pederson, senior vice president of public affairs for the National Electrical Manufacturers Association, said in a statement. The legislation would allow grid component manufacturers and supply chain vendors to “provide the energy sector with greater clarity around their current and future capacity, opportunities for growth, and challenges related to maintaining a secure and resilient supply chain,” he said. “More insight into the grid’s component supply chains also will strengthen national security.” Having electrical manufacturers work with the Department of Energy’s supply chain assessment will also help “identify where potential issues related to ‘foreign entities of concern’ and other emerging issues might

Malcolm Woolf is president and CEO of the National Hydropower Association and Dr. Bryant Jones is executive director of Geothermal Rising. When asked about the current version of “The One Big Beautiful Bill,” which recently passed the U.S. House and advanced to the U.S. Senate, President Trump replied, “We will be negotiating that bill, and I’m not happy about certain aspects of it.” He’s not the only one.   As representatives of the nation’s geothermal and hydropower industries, we are deeply concerned that two of the country’s most important baseload energy resources continue to be overlooked in federal energy legislation. This is especially troubling at a time when the nation is urgently seeking clean, reliable and domestically sourced energy solutions.  The timing couldn’t be worse. Forty percent of the non-federal hydropower fleet is currently up for relicensing and at risk of voluntary license surrender (451 facilities; 15,700 MW) Hydropower is one of America’s oldest sources of domestic, renewable power, with facilities in 48 states providing 24/7 reliable, affordable electricity to an estimated 25 million Americans. It also provides a disproportionate share of essential grid services such as “black start,” which is the ability to quickly restart the energy grid when it goes offline.   Geothermal energy is at an inflection point. It is no longer a niche solution — it is an emerging pillar of American energy resilience. There are geothermal heating and cooling systems in all 50 states and 93 geothermal power plants generating over 3,700 MW. Breakthrough technologies are dramatically expanding where geothermal can be deployed — potentially tapping into more than 5,000 GW of heat energy beneath U.S. soil. Next-generation systems are already being piloted in Nevada, Utah, Texas and California.  Importantly, geothermal is a multi-use energy asset: it can provide 24/7 clean electricity, thermal energy for heating and

Spanish power and gas utility Iberdrola SA, through its subsidiary Avangrid Inc., has launched commercial operation at the 202 MWdc-150 MWac Powell Creek Solar project in Putnam County, Ohio. The facility raises Iberdrola’s installed capacity in the United States to 10.5 gigawatts (GW), with nearly 600 megawatts added in the last six months, according to an online statement by Avangrid. Powell Creek, near Miller City, is now generating enough electricity for the annual consumption of 30,000 homes according to Avangrid. The farm has over 300,000 panels. “Powell Creek is a timely addition to the regional electric grid ahead of peak summer demand and represents new American energy capacity that will help to meet the growing power needs from data centers, domestic manufacturing, and electrification”, Avangrid said. Avangrid expects the project to make about $31 million in local taxes and around $1.1 million in annual lease payments. “In a unique relationship, Miller City is capturing significant revenue from the project which it will use to construct a new sewer line to encourage new home and business development. Growth was historically limited there because the village’s homes, businesses, and school run on individual septic systems”, it added. Powell Creek is Avangrid’s second energy project in Ohio, after the 304 MW Blue Creek built 2012. Avangrid now has over 500 MW of installed capacity in the state, enough to power 100,000 homes annually according to the company. Elsewhere Avangrid earlier in May announced five projects with a total investment of $41 million to install additional capacity and improve the reliability of the power grid in Ithaca, New York. Avangrid expects the Ithaca projects to benefit over 42,000 customers of New York State Electric & Gas, an Avangrid unit that operates about 35,000 miles of electric distribution lines and 4,500 miles of electric transmission lines

North America cut two rigs week on week, according to Baker Hughes’ latest North America rotary rig count, which was published on June 6. The U.S. dropped four rigs week on week, while Canada added two rigs during the same timeframe, taking the total North America rig count down to 673, comprising 559 rigs from the U.S. and 114 rigs from Canada, the count outlined. Of the total U.S. rig count of 559, 544 rigs are categorized as land rigs, 13 are categorized as offshore rigs, and two are categorized as inland water rigs. The total U.S. rig count is made up of 442 oil rigs, 114 gas rigs, and three miscellaneous rigs, according to Baker Hughes’ count, which revealed that the U.S. total comprises 505 horizontal rigs, 41 directional rigs, and 13 vertical rigs. Week on week, the U.S. land rig count reduced by four, and its offshore rig count and inland water rig count remained unchanged, the count highlighted. The country’s oil rig count dropped by nine, its gas rig count increased by five, and its miscellaneous rig count remained unchanged, week on week, the count showed. The U.S. horizontal rig count dropped by three week on week, its directional rig count decreased by one week on week, and its vertical rig count remained unchanged during the same timeframe, the count revealed. A major state variances subcategory included in the rig count showed that, week on week, Oklahoma and Texas each dropped two rigs, Utah dropped one rig, and Louisiana added one rig. A major basin variances subcategory included in Baker Hughes’ rig count showed that, week on week, the Eagle Ford and Permian basins each dropped three rigs, the Granite Wash basin dropped one rig, and the Cana Woodford and Haynesville basins each added two rigs. Canada’s

Vermilion Energy Inc. said it has entered into a definitive agreement to sell its U.S. assets for cash proceeds of $87.61 million (CAD 120 million). The assets produce approximately 5,500 barrels of oil equivalent (boepd), consisting of 81 percent oil and liquids, and an estimated approximately 10 million barrels of oil equivalent (MMboe) of proved developed producing reserves as of Dec. 31, 2024, Vermilion said in a news release. The company said it expects the transaction, which has an effective date of January 1, to close in the third quarter, subject to the satisfaction of other customary closing conditions. The transaction agreement includes CAD 10 million of contingent payments based on WTI prices over the two-year period starting July 1. Vermilion said the transaction, combined with the sale of its East Finn assets in 2023, completes the company’s exit from the USA. The company said it plans to focus on its core gas-weighted assets in Canada and Europe. Net proceeds from the transaction will be directed towards debt repayment to “further accelerate deleveraging efforts and strengthen Vermilion’s balance sheet,” the company said. Meanwhile, Vermilion said it is adjusting its 2025 capital budget to a range of CAD 630 to 660 million, reflecting a reduction of approximately CAD 100 million from the mid-point of our previous capital budget range of CAD 730 million to 760 million. The reduction reflects the removal of all remaining exploration and development capital associated with the Saskatchewan and U.S. divested assets post-closing, the company said. Vermilion said it expects full-year and second-half 2025 production to range between 117,000 and 122,000 boepd, 68 percent natural gas-weighted in the second half of 2025. The company said it estimates that over 90 percent of production will come from its global gas portfolio and over 80 percent of capital is