Atlantic Shores Offshore Wind, the developer behind the 1.5-GW Atlantic Shores 1 wind energy project in progress offshore New Jersey, filed a petition Wednesday asking the state’s Board of Public Utilities to terminate the project’s offshore renewable energy credits and release it from all associated obligations. The petition cites President Donald Trump’s executive order pausing the development of offshore wind, along with other actions from his administration and the overall macroeconomic environment as reasons that “the project is no longer viable upon the terms and conditions set forth in the [Offshore Wind Renewable Energy Certificate] Order,” which was issued in 2021. “This is despite Petitioner’s diligent and good faith efforts to advance the Project toward completion as set forth in Section II of this Petition, including submission of a rebid of the Project in the Fourth Solicitation, which was concluded by the BPU without an award,” the petition said. However, Atlantic Shores Offshore Wind’s CEO Joris Veldhoven said in a Monday release that the project is seeking a “reset period” and that “this filing marks the closing of a chapter, but not the end for Atlantic Shores.” The project in March had its Clean Air Act permit remanded by the Environmental Protection Agency’s Environmental Appeals Board, an action which Atlantic Shores Offshore Wind argued lacked “good cause.” The board maintained that it has “broad discretion to grant a voluntary remand.” The uncertainty caused by Trump’s executive order, the project’s loss of its air permit, “and other actions taken by the current administration more generally” mean that the “Petitioner’s parent company has been forced to materially reduce its personnel, terminate contracts, and cancel planned project investments.” The project was launched as a joint venture between EDF Renewables and Shell. In January, Shell booked a $1 billion impairment associated with the project, which

Utility-scale battery storage in the United States is poised to more than double over the next two years and will close out 2026 at nearly 65 GW — a rapid rise from 17 GW in the first quarter of 2024. The U.S. Energy Information Administration published its Short Term Energy Outlook on Tuesday, showing a rapid increase in anticipated energy storage resources. Counting projects larger than 1 MW in the electric power sector, EIA said domestic storage capacity will rise from about 28 GW at the end of Q1’25 to 64.9 GW at the end of 2026.  Large-scale battery storage resources in the commercial and industrial sectors are expected to rise from about 100 MW to about 300 MW across the same time frame. EIA’s data shows annual U.S. electricity generation rising from 4,180 billion kWh in 2023 to 4,490 billion kWh in 2026. Monthly electricity demand is highest during the summer months in the United States, but despite a cooling degree forecast in line with last year’s weather EIA said it expects total U.S. electricity generation this summer will increase by 1%, or 14 billion kWh, compared with summer 2024.  “We expect strong demand growth in the commercial sector because of the expansion of data centers,” EIA said. EIA anticipates natural gas-fired power plants between June and September 2025 will generate 3% less than they did last summer “because of higher natural gas prices and the continuing increase in new solar generating capacity.” Domestic solar generation this summer will grow by 33%, EIA said, and improving water supply in the western states will contribute to a 6% increase in U.S. hydroelectric generation.

The Midcontinent Independent System Operator on Friday asked the Federal Energy Regulatory Commission to approve a fast-track generation interconnection process after the agency rejected its initial plan last month. MISO runs the grid and wholesale power markets in 15 states and part of Canada, from Louisiana to Manitoba. In response to FERC’s May 16 decision, MISO set more limits around its proposed Expedited Resource Addition Study process, which would allow projects that meet certain criteria to avoid MISO’s generation interconnection queue and potentially receive an interconnection agreement within 90 days. Under the revised proposal, the ERAS process would be capped at 68 projects, with MISO studying only 10 projects each quarter. The proposed cap includes eight projects for the restructured states of Illinois and Michigan as well as 10 projects for independent power producers with power supply agreements with non-utility entities. The revised process requires “relevant electric retail regulatory authorities,” such as state utility commissions, to verify in writing that a proposed project will address either a load addition not already planned for or an identified resource adequacy deficiency within its jurisdictional footprint, MISO said in its filing. The new proposal also requires projects to have a commercial operation date within three years of an application being filed. MISO plans to end the ERAS process by Aug. 31, 2027, or after its 68-project cap is met, whichever happens first. The proposal addresses potential capacity shortfalls driven by load growth and power plant retirements, according to MISO, which pointed to various reports to support its claims. “These surveys and forecasts demonstrate that MISO must address resource adequacy and reliability needs in the next five years and that an accelerated interconnection study process must be established to address time-critical challenges,” the grid operator told FERC. The ERAS process will provide a bridge to 2028,

Electric utilities can make calls and send demand response text messages to customers who have provided their phone number, the Federal Communications Commission said in a Monday declaratory ruling. “When a consumer gives a utility their phone number they give their prior express consent to receive non-telemarketing demand response calls and texts,” the commission wrote. “We confirm that demand response communications are closely related to utility service and thus within the scope of consent customers give when they provide their phone number to their utility,” FCC said. “We thus make clear that a utility can make critical, time-sensitive demand response communications to its customers rather than having to solicit additional consent from each customer, a burdensome and often costly undertaking.” The Edison Electric Institute, which represents investor-owned utilities, requested in March that the FCC clarify that utilities have prior express consent under the Telephone Consumer Protection Act, and utilities can make demand response communications without risking penalties or fines. EEI “appreciates the FCC allowing electric companies to deliver timely and clear communications that help customers conserve electricity — and save money — at times of extremely high demand,” Senior Vice President of Customer Solutions Phil Dion said in a statement. “As summer begins and Americans use more electricity to cool their homes and businesses, demand response programs allow grid operators to maintain reliability while helping to keep customer bills as low as possible.” Utilities see demand response as a key resource to meet growing electricity demand. EEI told the FCC in its March request that the clarification would help “ensure that utilities can continue to provide safe, reliable, and efficient service to customers.” U.S. electricity demand could grow 25% from 2023 to 2030, ICF said in a May report. And utility demand-side management programs, which include demand response, could be able to meet

Chris Crosby is CEO of Compass Datacenters, a Dallas-based data center developer. We at Compass Datacenters have closely followed the discussion around the increasing power demands of data centers and read with interest the Harvard Law study recently released asserting that demand is being serviced on the backs of consumers. The study draws a compelling picture, and we acknowledge the challenges presented by existing regulatory frameworks. However, Compass Datacenters believes that there’s one key shortcoming of the paper, in that it lumps all data center developers into one category when, in reality, not all developers are created equal. There’s a gold rush or dot-com mentality in our space right now. Speculative developers are coming out of the woodwork to flip a piece of powered land for profit. These aren’t real projects, complete with solid financing and tenants waiting in the wings. I’ve been in the business of data center development for decades and I’ve never seen anything quite like it. Because of the will-serve model that utilities currently work under, these spec developers can come to a utility and say they are building a hyperscale data center that’s going to need as much energy as a small power plant and the utility has to put the request in the queue which creates potentially false demand. Speculative requests for service put enormous pressure on the utilities’ resource planning and capital projections. Further, speculation increases risk to the utility investing in infrastructure to serve loads for projects that may never materialize. Put in place during a simpler time, the will-serve model is not suited for an era where the needs of certain customers are growing exponentially compared to others. Responding to requests from speculative investors is tying up power without an actual project and true demand behind it. Indeed, building out infrastructure

Germany’s state-owned SEFE signed a 10-year deal to buy gas from Azerbaijan’s Socar, a move that will help diversify supplies in Europe’s tight market. The agreement, which begins this year, allows the German trading company to buy as much as 15 terawatt-hours of gas annually, according to a release that confirmed an earlier Bloomberg report. That’s equivalent to about 1.5 billion cubic meters per year, or about 0.5% of the European Union’s gas consumption in 2024. The gas is likely to reach Europe via the Trans Adriatic Pipeline, according to two people familiar with the matter, who asked not to be named because the information is private. TAP crosses northern Greece, Albania and the Adriatic Sea before coming ashore in southern Italy. The deal with state-owned Socar will support investments in production and infrastructure, boosting the volumes of pipeline gas coming to Europe, according to the statement. SEFE, which stands for Securing Energy for Europe, has been among the most active companies in negotiating new supply deals. The region increasingly depends on global flows after losing most of its Russian pipeline gas in 2022. With Norwegian production operating pretty much at full capacity, Europe still needs to secure supplies as it awaits the startup of additional liquefied natural gas export facilities in the US.  Socar was a key player in negotiations between European countries and Ukraine about potentially continuing to transit gas after a deal ended at the end of last year. An agreement wasn’t reached at the time and Azerbaijan was keen to secure commitments from Europe on building new infrastructure and longer-term contracts to buy gas.  SEFE, formerly the European trading and supply unit of Gazprom PJSC, was nationalized in 2022 as part of a €6.3 billion ($7.2 billion) rescue package. The company has lined up numerous supply deals with global producers, mainly for