Dive Brief: One Minnesota county’s vision to decarbonize a 15-building district energy system faces economic and practical difficulties in the near term, two people involved in the project said at the International District Energy Association annual conference earlier this month. Eliminating steam completely was infeasible, with a major safety net hospital as the top customer for the Hennepin County system’s well-maintained steam loop,, and switching to electric boilers would likely be prohibitively expensive, said James Bohn, principal with FVB Energy. Over the longer term, Hennepin County envisions serving a major planned hospital expansion with an electric-powered heat exchange system, backed up by the current mix of electric and fossil-fuel equipment, which could eventually run on renewable natural gas as markets develop for that fuel, Bohn said. Dive Insight: The Hennepin County Energy Center supplies high-pressure steam and chilled water to six county-owned buildings and several private customers in downtown Minneapolis, including the hospital. The county, Minnesota’s largest, aims to reduce the facility’s environmental impact over time as it targets a 45% reduction in greenhouse gas emissions by 2030 and net-zero emissions by 2050.  Bohn’s analysis considered a “range of potential options” for near-term decarbonization, including building efficiency improvements, alternative steam sources and a switch from steam to a hot water loop, he said. With Minnesota progressing toward its legislative mandate of 100% carbon-free electricity by 2040, focusing on electrifying as much of the system was tempting, Bohn said. But the hospital’s strict reliability requirements and its use of steam for other critical processes, such as instrument sterilization, made it impractical to eliminate steam in the near term, he said. “You can’t just go into a hospital and say we’re going to change things [and] and you’re going to be up ‘most’ of the time,” Bohn said. “You have important stakeholders

Southwest Power Pool has launched the second phase of development of its western day-ahead and real-time market and remains on track for a 2027 launch, the grid operator said Monday. The second phase of the Markets+ initiative is backed by financing provided by Simmons Bank to cover the $150 million needed for full market implementation, SPP said. During this phase, stakeholders and staff will collaborate to develop the systems needed to operate the market, conduct market trials and parallel operations. “Securing financing for phase two of Markets+ is a pivotal step forward,” SPP Vice President of Markets Carrie Simpson said in a statement. “It allows SPP to continue developing a more efficient, transparent and reliable energy market for our western stakeholders and their customers.” SPP’s funding agreement framework was approved in April by the Federal Energy Regulatory Commission. The agreement details how implementation costs will be recovered over the market’s operational life, and so far eight utilities have signed on, including: Arizona Public Service, Bonneville Power Administration, Chelan County PUD, Grant County PUD, Powerex, Salt River Project, Tacoma Power and Tucson Electric Power. Bonneville announced its plan to join SPP’s Markets+ in March, eschewing a market being launched by the California Independent System Operator. The utilities signing on to SPP’s effort are located across the Desert Southwest, Pacific Northwest and Mountain West regions of the Western Interconnection and demonstrate “broad regional commitment and collaboration,” the grid operator said. “With key regional partners on board, we’re ready to begin the next phase of development,” SPP Senior Director of Seams and Western Services Jim Gonzalez said. Federal regulators say development of SPP’s Markets+ is important to improve grid reliability and energy affordability across the region. In March, The Brattle Group published an analysis showing SPP could need up to $263 billion in

Dive Brief: The Federal Energy Regulatory Commission and other federal agencies on Monday revoked regulations governing their handling of environmental reviews of proposed projects under the National Environmental Policy Act. Federal agencies revoking their NEPA regulations include the Department of Agriculture, the Department of Energy, the Department of Interior, the Department of Transportation and FERC. Some agencies proposed new regulations to replace the old ones while others replaced the rules with nonbinding guidance, according to Earthjustice. “In all cases, the regulations significantly weaken the implementation of the statute by cutting the public out of NEPA reviews and eliminating all references to consider climate change, environmental justice, and other crucial environmental issues,” the environmental advocacy group said Monday. Dive Insight: The action was in response to an executive order issued by President Donald Trump that aims to spur energy development, including by rescinding the Council on Environmental Quality’s NEPA regulations. It also follows a unanimous Supreme Court decision in May limiting the scope of such environmental reviews. CEQ, the White House office that oversees NEPA implementation, removed its NEPA regulations from the Code of Federal Regulations through an interim final rule, effective April 11. That action created “significant legal uncertainty” for project developers, according to attorneys with Foley & Lardner, a law firm. “Until federal courts establish a new ‘doctrine’ for sufficiency of NEPA review in the post-CEQ NEPA regulations world, the future for NEPA lawsuits will likely be fact- and court-specific, potentially leading to variation between circuits and greater uncertainty for infrastructure projects,” John Strom, special counsel, and Peter Tomasi, partner, said in a Feb. 25 blog post. FERC on Monday issued a 20-page staff manual outlining its revised procedures for its environmental reviews for natural gas pipelines and other projects. The change enjoyed unanimous support from FERC’s four sitting

Arun Muthukrishnan is senior manager of development at Arevon Energy. In August 2022, the Inflation Reduction Act was signed into law, unleashing a wave of optimism across the renewable energy sector. As someone who has spent over a decade in utility-scale development — working on more than a gigawatt of solar and hundreds of megawatts of battery energy storage projects — I saw firsthand how the IRA reshaped boardroom conversations, procurement strategies and financial modeling. For the first time, standalone storage had a stable federal foothold, and that unlocked momentum like we had never seen. But now, with growing uncertainty about the IRA’s future amid political shifts, a sobering question looms over our industry: Can energy storage continue its pivotal role in decarbonizing the grid without federal support? In my view — and based on what I see on the ground, in permitting meetings, and in request for proposal negotiations — the answer is unequivocally yes. Storage was never just about subsidies The idea that the IRA is the sole engine behind energy storage’s rise is a convenient but flawed narrative. Storage didn’t suddenly appear in 2022. It’s been a solution in search of a market for the last decade. What’s changed is the context around it — renewable penetration, aging grids, demand volatility and increasing grid interdependencies. All these conditions make storage essential, not optional. Even before the IRA, I worked on projects in Texas and California that penciled out based on merchant revenue and avoided curtailment alone. One of my earliest storage projects in Texas never qualified for investment tax credit support, and yet the business case was strong enough due to energy arbitrage and ancillary services. The market need was — and still is — that compelling. Grid realities are bigger than federal politics The demand for

Capstone Green Energy Holdings Inc. has reported fourth quarter and annual revenues of $27.1 million and $85.6 million respectively for fiscal year 2025, compared to 2024 fourth quarter and annual revenues of $24.3 million and $91.2 million respectively. The company said in its report that the fourth-quarter revenue improved by $2.8 million year-over-year, driven by increased demand for products and services, as well as improved rental utilization rates within the company’s Energy as a Service (EaaS) revenue stream. Slow product sales in the first half of the fiscal year caused a decrease of $5.7 million for the year. This was mainly due to restructuring hesitancy and instability in Europe, it said. Gross profit for the fourth quarter of 2025 was $7.5 million, up $4.9 million from the fourth quarter of fiscal 2024. The company recorded a net loss of $0.1 million, compared to a net loss of $5.3 million for the same period in fiscal 2024. Adjusted earnings before interest, taxes, depreciation, and amortization (EBITDA) for the fourth quarter of fiscal 2025 was $2.8 million, up $0.8 million from the fourth quarter of fiscal 2024. This improvement was mainly due to better gross margins and lower operating expenses, it said. Gross profit for FY2025 was $23.3 million, up from $14.3 million for FY2024, due to sales mix shift and price hikes. Net loss was $7.2 million, swinging from FY2024’s net income of $7.4 million, which included a $32.5 million reorganization gain. Excluding this gain, the net loss was cut by $17.9 million, driven by better gross profit, lower expenses, and reduced costs. Adjusted EBITDA rose to $7.9 million from negative $0.5 million for FY2024, including non-recurring charges related to restructuring, litigation, restatement, and SEC investigations, which concluded in early FY2026. “The company’s full-year results reflect the focus on financial health

Cheniere Energy Partners LP (CQP), part of Cheniere Energy Inc. (Cheniere), is offering $1 billion of senior notes due 2035 with a yearly interest of 5.55 percent. “The CQP 2035 Notes will be issued at a price equal to 99.731 percent of par”, CQP said in a press release. Cheniere Partners expects to close the offering July 10. “Cheniere Partners intends to contribute the proceeds from the offering to its subsidiary, Sabine Pass Liquefaction, LLC, to be used to redeem a portion of the outstanding aggregate principal amount of its senior secured notes due 2026”, the statement added. “The CQP 2035 Notes will rank pari passu in right of payment with the existing senior notes at Cheniere Partners, including the senior notes due 2029, the senior notes due 2031, the senior notes due 2032, the senior notes due 2033 and the senior notes due 2034”, it said. Cheniere Partners owns the Sabine Pass LNG terminal in Cameron Parish, Louisiana. The terminal has a production capacity of about 30 million metric tons per annum (MMtpa). It also has regasification facilities that include five LNG storage tanks, vaporizers and three marine berths. Cheniere Partners also owns the Creole Trail Pipeline, which interconnects Sabine Pass LNG with several interstate and intrastate pipelines. Houston, Texas-based Cheniere, which owns 100 percent of the general partner stake and 48.6 percent of the limited partner interest in CQP, reported $10.55 billion in available liquidity at the end of the first quarter. On June 24 Cheniere announced a positive FID (final investment decision) to add two “midscale” trains to the Corpus Christi LNG facility in South Texas. The two trains will raise the terminal’s capacity by over 3 MMtpa. In July 2023 the United States Department of Energy (DOE) granted CCL Midscale Trains 8 & 9 authorization to export to countries