Danville Utilities, a municipal utility based in Danville, Virginia, is contracting for an 11-MW/44-MWh battery storage project to be built and owned by Lightshift Energy, the battery storage company said Wednesday. Danville Utilities plans to use the storage facility to reduce its peak demand, which it expects will lower its demand and transmission charges by about $30 million over the 20-year life of the project. About 40% of Danville Utilities’ power supply costs are demand-related and they are increasing by 10% to 15% a year, according to a Nov. 7 Danville City Council memo on the project, which Lightshift expects will be operating in the second quarter next year. The memo states that PJM Interconnection’s capacity rate for Danville Utilities is jumping to $8.29/kW-month starting June 1 from 96 cents/kW-month. An existing 10.6-MW storage project built by Lightshift has helped reduce the Danville Utilities’ transmission, capacity and congestion charges since it started operating in 2022, according to the memo from Lightshift, formerly Delorean Power. Lightshift expects the project will save the utility $40 million over its life. Lightshift will use the new battery system to sell ancillary services into the PJM market and arbitrage wholesale energy prices, according to the memo.  “The project will help lower transmission and capacity costs and allow the city’s electric rates to be competitive to other neighboring electric utilities when competing for economic development projects,” Jason Grey, Danville director of utilities, said in the press release. Danville Utilities has about 42,000 customers. The project in February received $1.5 million from the Virginia Tobacco Region Revitalization Commission’s Energy Ingenuity Fund. Municipal utilities and rural cooperatives are focused on cost, and energy storage can save them money while adding resilience to their systems, according to Laura Coriell, head of market development for Lightshift, which is based in

Anna Littlefield is the program manager for low carbon energy technologies for the Payne Institute at the Colorado School of Mines. It’s no secret that carbon capture is gaining momentum — and the United States is leading the pack. U.S. capacity alone for carbon capture, utilization and storage, or CCUS, is expected to increase sevenfold by 2035. In 2023, announced carbon capture capacity by 2030 increased by 35%. In the U.S., there are already 14 operational commercial-scale facilities that can capture and store roughly 21.4 million metric tons of CO2 per year, equivalent to the annual emissions of 5 million passenger vehicles. And new projects continue to be announced. Since 2018 when Congress enhanced the 45Q tax credit, which supports CCUS, there have been more than 120 CCUS projects announced in the states. In 2023, Chevron announced it was expanding its Bayou Bend CCS project, positioning it to be one of the largest carbon storage projects in the country. Despite all this investment and decades of proven operations, critics continue to insist the technology doesn’t work — apparently because it hasn’t scaled fast enough. A Scientific American headline from 2017 asked, “Will Carbon Capture and Storage Ever Work?” One environmental group asserted the technology “won’t work,” while others call it a “pipe dream.” This narrative allows other critics to suggest any federal support for the technology is misallocated. Two U.S. lawmakers recently introduced the 45Q Repeal Act, a bill aimed at repealing the 45Q tax credit. Rep. Scott Perry, R-Pa., one of the sponsors of the bill, called CCUS an “inefficient and market-distorting technology.” Opponents of CCUS cheered the legislation. What these critics overlook is that the primary challenge facing CCUS is the regulatory uncertainty created by current federal policies. Fifteen years ago, the Task Force on Carbon Capture and Storage

Low-carbon power can play a “critical role” in delivering energy security around the world, according to UK energy secretary Ed Miliband. Speaking at the first global Future of Energy Summit held at Lancaster House, London on Thursday, Miliband touted renewable and low-carbon energy sources such as nuclear power as the primary “solution” to international energy crises, and a pathway to “abundance”. “For the UK, just to talk about us for a moment, there is an exciting vision of energy security and abundance from cheap, homegrown low-carbon power,” Miliband said. “Following Russia’s invasion of Ukraine, we saw family finances, business finances and public finances wrecked as fossil fuel prices rocketed on the global markets, and therefore, here in Britain.” Renewable energy presents a solution to energy security that was not possible a decade and a half ago, according to Miliband. He attributed this to declines in the cost of solar power, which has plunged globally by 90% since 2010, and offshore wind costs that have declined by over 60%. Last year, $2 trillion was invested in clean energy, double the total amount invested in fossil fuels, data from the International Energy Agency’s latest inventory showed. Meanwhile, 92.5% of new electricity demand was met by renewable and nuclear power globally, according to a separate report by the International Renewable Energy Agency (IRENA). Renewables in 2024: 5 Key Facts Behind a Record-Breaking Year The golden rule Miliband’s words were echoed by IEA executive director Fatih Birol who described homegrown energy as “the best friend of energy security”. Birol warned that, to manufacture clean technologies, the industry needs “critical minerals”. He said diversification is a golden rule, not just of energy sources but also of the countries one imports from, to achieve energy security. Birol also warned that unpredictable economies lead investors to “fly

Eni SpA on Thursday reported EUR 1.41 billion ($1.6 billion) in adjusted net income attributable to shareholders, down 11 percent from the same three-month period a year ago as oil prices weakened and oil and gas output fell. Before adjustment for nonrecurring or extraordinary items, net earnings landed at EUR 1.17 billion, down 3 percent year-on-year. The Italian state-backed integrated energy major saw liquid production in the January-March 2025 period drop 1 percent year-over-year to 786,000 barrels per day. Natural gas production declined 9 percent to 4.5 billion cubic feet a day. “The asset divestments closed in 2024 in Nigeria, Alaska, Congo and the mature fields declines were substantially offset by rampups at organic projects in Côte d’Ivoire, Congo, Mexico, and Italy”, Eni said in a report on its website. Realized liquid prices averaged $69.72 a barrel, down 6 percent against Q1 2024. Gas realizations rose 8 percent to $7.57 per thousand cubic feet. Upstream turnover totaled EUR 5.41 billion, down 4 percent year-on-year. Refining throughput decreased 8 percent year-on-year to 5.86 million metric tons. Sales of chemical products totaled 800,000 metric tons, down 7 percent. The refining and chemicals segment logged EUR 4.93 billion in sales, down 13 percent. “The refining business reported a proforma adjusted loss of EUR 91 mln, lower both y-o-y and sequentially due to a continuing deterioration in products crack spreads”, Eni said. “The chemicals business reported a loss of EUR 0.24 bln amidst a prolonged downturn of the European sector due to lower demand and margin pressure from cost-advantaged players”. Eni sold 2.8 billion cubic meters (98.88 billion cubic feet) of liquefied natural gas in Q1 2025, up 4 percent year-on-year. Total gas sales landed at 12.12 Bcm, down 22 percent. Eni’s “Global Gas and LNG Portfolio” segment generated EUR 5.59 billion in sales,

Honeywell International Inc. has signed an agreement with Argent LNG to deploy Honeywell’s pretreatment solutions at a liquefied natural gas (LNG) terminal to be built at Port Fourchon, Louisiana. Honeywell’s LNG pretreatment solutions help remove contaminants from natural gas, enabling facility operators to enhance production and operational efficiency, the company said in a media release. By combining Honeywell’s modular Mercury Removal Unit (MRU), Acid Gas Removal Unit (AGRU), and SeparSIV Unit, operators can effectively eliminate mercury, carbon dioxide, sulfur, water, and heavy hydrocarbons to meet LNG specifications. Furthermore, Honeywell UOP SeparSIV accommodates different feed compositions and has the potential to reduce lifecycle costs by up to 50 percent compared to conventional removal methods, according to the company. “Argent LNG is committed to delivering clean, secure, and cost-effective energy worldwide. In order to do so, we need to leverage innovative technology and effective pretreatment solutions”, Jonathan Bass, CEO of Argent LNG, said. “Honeywell’s proven technology has the potential to help us transform the United States LNG sector and help deliver the LNG the world needs”. According to the Shell LNG Outlook 2025, global LNG demand is expected to rise 60 percent by 2040. In response, Argent LNG plans its Port Fourchon facility to produce 12 million tons per annum (MMtpa) of LNG, with an expansion potential of up to 25 MMtpa, making it one of the largest LNG export terminals globally. Once operational, Argent LNG will export fuel to Asia, Europe, South America, and the Middle East, Honeywell said. “Honeywell’s innovative LNG technologies will play a pivotal role in addressing energy security by enabling the large-scale production of LNG in countries around the world, including the United States”, Rajesh Gattupalli, president of Honeywell UOP, said. “Honeywell’s LNG portfolio includes end-to-end solutions that can be customized and adapted based on the needs

Dive Brief: The boom in AI data center development is driving significant growth in large-load interconnection requests to not-for-profit public utilities, two experts with the American Public Power Association told Utility Dive. Public power electric utilities tend to be smaller on average than investor-owned utilities,  emphasize affordability and reliability, and are often self-governing, all of which appeal to data center operators, said Patricia Taylor, APPA’s manager for regulatory policy and business programs. But smaller utilities weighing data center proposals that could dramatically increase their system loads must also take steps to protect existing ratepayers and other stakeholders, such as carefully studying the potential grid reliability impacts and ensuring fair compensation for infrastructure upgrades, said Latif Nurani, senior regulatory counsel for APPA. Dive Insight: Smaller, not-for-profit utilities have worked productively with data center operators for decades and have in some cases helped their communities evolve into significant IT hubs, Nurani and Taylor said. In north-central Oregon, Northern Wasco County People’s Utility District nearly quadrupled its annual revenues from $32 million in 2016 to $120 million in 2024 and expects to reach $300 million “in the next few years,” CEO and General Manager Roger Kline said on an APPA podcast in July. Google data centers drove much of that increase. Drawn by abundant hydropower and associated energy infrastructure, a robust workforce and a “business-friendly environment and policies,” the tech giant developed its first data center near The Dalles, Oregon, in 2006 and has since invested more than $2.4 billion in the state, it says. Google’s presence has been transformative for Northern Wasco County PUD, enabling investments in new substations, transmission lines, hydroelectric plants, advanced metering infrastructure and other projects that may have otherwise exceeded the capacity of a “small semi-rural utility” with fewer than 25,000 residential and commercial customers, Kline said last