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December 7, 2025

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U.S. Energy Agencies Lay out Plans for Federal Government Shutdown

The federal government officially shut down as the clock turned to midnight Oct. 1 after the two parties failed to agree on a spending package to keep it open at the start of fiscal year 2026.

While Democrats and Republicans both blamed each other for the impasse, federal agencies released plans to keep vital employees working and to furlough others, at least once any existing funds are exhausted. For now, both FERC and the Department of Energy have some leftover funds from the previous fiscal year, so they can operate normally, but they will wind down most operations if the shutdown lasts too long.

FERC’s plan allows it to use leftover funds and will keep it running with all 1,478 employees working. Once that runs out, however, just 60 employees and 18 contractors who are needed to “protect life and property” will remain working, it said.

“It is anticipated that there would be no disruption to FERC operations during a short lapse in appropriations of one to five days,” the plan says. “FERC has historically had sufficient previously appropriated funds that remain available to support operations during a short-term lapse. In the event of a lapse extending beyond one to five days, FERC will continue operations using balances from prior years until exhausted.”

If the funding is exhausted in a lengthy shutdown, FERC will continue to inspect hydropower dams and LNG projects under construction for safety. It will monitor the reliability of the bulk power system and threats to energy infrastructure. Some remaining employees will monitor jurisdictional energy markets and offer legal advice to commissioners.

The commissioners are presidentially appointed and Senate-confirmed, so they will continue working, and the office of the secretary of the commission will remain open to release any formal actions publicly.

“Federal employees in offices with funding for salaries continue to report for work as scheduled,” DOE’s plan says. “A prolonged lapse in appropriations may require subsequent employee furloughs. If there is an imminent threat to human life or protection of property, a limited number of employees may be recalled from furlough status.”

Like FERC, DOE has historically remained fully open during short lapses of funding that last just one to five days, and if the money runs out, it has been able to wind down operations in half a day.

The department has 15,523 employees, though that was already scheduled to fall to 13,812 at the start of FY26 on Oct. 1 because of the buyouts the Trump administration offered federal workers early in 2025. An additional 1,409 employees are taking the buyout effective Dec. 31, and 71 others have already left.

The Bonneville Power Administration is self-funded, and its 3,266 employees can keep working with regular pay, though 192 were scheduled to leave on Oct. 1 because of the buyout.

“The other power marketing administrations (Southeastern Power Administration, Southwestern Power Administration [and] Western Area Power Administration) will perform functions related to the safety of human life and the protection of property by engaging in controlling and directing power to utilities, transmission of power and repair of the power transmission system,” DOE says in its plan.

The Nuclear Regulatory Commission has already started to wind down operations under its plan.

“The NRC has some appropriations for performing high-priority activities, such as operator licensing, time-sensitive licensing actions and activities related to recent executive orders, with a core group of employees,” the agency’s plan says. “When NRC appropriations no longer support other high-priority activities, the NRC plans to operate at a reduced level for some period of time and to begin a minimal maintenance and monitoring mode in which the NRC will continue to carry out its responsibility to protect public health and safety.”

The law firm Holland & Knight posted a summary and links to other federal agencies’ plans for the shutdown.

The Maryland Public Service Commission issued a notice saying that utility disconnections are forbidden for any federal workers in the state, noting that Gov. Wes Moore has reminded utilities of that rule.

The White House’s Office of Management and Budget and Office of Personnel Management said that federal employees can expect to be paid on time for work through Sept. 30.

The Government Employee Fair Treatment Act of 2019 requires that all employees, including those who are furloughed, get back pay for the shutdown once it ends, though POLITICO reported Sept. 24 that OMB could try to fire many federal employees during a shutdown.

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Gas Industry Sees Political Opportunity in New England

MARLBOROUGH, Mass. — Speaking at an industry conference Sept. 30, representatives of major gas pipeline companies said they are optimistic that political shifts at the federal and state levels will create opportunities for gas infrastructure expansion in New England.

Panelists at the Northeast Energy and Commerce Association’s annual Fuels Conference emphasized the importance of reducing the region’s gas constraints to alleviate affordability and reliability concerns, while downplaying climate concerns about long-term reliance on natural gas.

“After decades of disagreement, a lot of key states are coming around, and a lot of it centers around the need for electric generation,” said Rick Smead, managing director at RBN Energy. He added that data center demand growth in the Boston area has increased the urgency to address gas constraints.

Brooke Thomson, CEO of the Associated Industries of Massachusetts (AIM), the largest business association in the state, said she has “seen a shift” in the political acceptance of natural gas.

“A lot of the change that has come out of the shift in federal administration is trickling down to the local level,” Thomson said, adding that Massachusetts Gov. Maura Healey (D) has emphasized that “everything’s on the table, including natural gas.”

She said the conversation around gas in the state has shifted significantly since the Biden administration, when Massachusetts lawmakers sought to ban new natural gas hookups and succeeded in passing a pilot program allowing 10 municipalities to ban gas connections for most new buildings.

Bill Ryan, chairman of Pilgrim Strategies, a lobbying firm whose largest client is Enbridge, said Healey “has almost gone out of her way to talk about the reality of natural gas in the current energy mix and the future energy mix.”

While the industry was on the defensive in Massachusetts under the Biden administration, “I think we’re in a different arc right now,” with political leaders in the state “singing a different tune,” Ryan said.

Speakers at the event stressed that the gas industry should double down on their efforts to drive the narrative around gas in the state.

“We’ve really made some gains in having people better understand the impact of natural gas,” said Mike Dirrane, director of Northeast marketing at Enbridge. “We’ve seen a change in the narrative, even in the media.”

“I think we need to be even more aggressive in pointing out the benefits of the natural gas industry,” he added.

Earlier in September, Enbridge announced a $300 million project to expand the capacity of its Algonquin pipeline into Massachusetts by about 75,000 Dth/d. Dirrane said the company has reached agreements with seven utilities in New England to support the expansion, which Enbridge expects to be completed in 2029. The project would not require any new compression, he added.

The project would be a relatively small expansion of the pipeline, which has a peak day capacity of over 3 million Dth. It appears to be a significantly scaled-back version of Enbridge’s 2023 proposal to increase Algonquin’s capacity to Massachusetts by 250,000 Dth/d. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

Dirrane said the project will meet “some of the critical needs right now” but speculated that a subsequent project may be necessary “to meet additional needs further down the road.” He said Enbridge has met with “all of the administration officials in New England” and has “had some great dialog and really good education on the benefits of natural gas and its impact on affordability.”

The project will likely be met with significant resistance from climate organizations in the state, which have opposed all efforts to expand gas capacity into the region. Environmentalists argue that increasing the long-term reliance on natural gas is not compatible with reaching net-zero emissions by 2050; methane is a potent near-term greenhouse gas and a key contributor to manmade climate change.

Smead applauded the effort to increase pipeline capacity to the Northeast. While the Algonquin expansion is “not a huge project,” he expressed his hope that “there’s going to be more of these that keep ramping up capacity, rather than a big monster that gets in all the papers.”

He stressed that, despite changing political attitudes around gas expansion, key barriers to addressing New England’s gas constraints remain.

He highlighted a pair of large pipeline projects to the region that were shelved during President Donald Trump’s first term: Kinder Morgan’s Northeast Energy Direct project and Enbridge’s Access Northeast project.

“The reason stuff didn’t get built in New England was because people didn’t want to pay for it, not because environmentalists lay down in the right of way,” Smead said.

The financing challenges for new pipelines in New England are often attributed to the fact that gas utilities have been reluctant to sign long-term contracts to support major projects; electric utilities are not allowed to use ratepayer funds for pipeline contracts; and gas generators typically do not sign long-term firm supply contracts. (See New Pipelines Unlikely for New England, Experts Say.)

While New England generators often struggle to access pipeline gas during the coldest days of the year, gas generation in ISO-NE has increased steadily in recent years, hitting its all-time high in 2024 amid reduced electricity imports from Canada. (See New England Gas Generation Hit a Record High in 2024.)

“It’s not necessarily in the interest of the generators to pay for it if they make their money off of volatility,” Smead added.

The Role of LNG

Multiple speakers emphasized the importance of the Everett LNG import terminal to the region and said there may not be a single solution to replace the facility when its contracts with Massachusetts gas utilities expire in 2030.

When approving the contracts, the Massachusetts Department of Public Utilities directed the utilities to develop a plan to reduce their reliance on the import terminal. (See Massachusetts DPU Approves Everett LNG Contracts.)

Everett, which is north of Boston, supports direct injection into the gas network and the dispatch of LNG trucks to other points on the system.

Jeff Tounge, development lead at Cashman Preload Cryogenics, outlined the company’s proposal to build an LNG storage tank in Northern New England that could supply 200,000 Dth of gas for winter reliability and inject enough gas to supply a 1,300-MW gas plant for 10 days during peak demand.

He said the project would provide reliability benefits during cold winter periods and that Cashman is seeking long-term utility contracts for the project.

Charlie Riedl, executive director for the Center for Liquefied Natural Gas, said he sees an important role for both LNG infrastructure and additional pipeline capacity.

“What the Northeast really needs is additional pipeline capacity to complement LNG,” Riedl said, adding that “pipelines are the most cost-effective way to meet growing demand.”

Emissions Limits

Also at the meeting, several speakers said they hope Massachusetts will re-evaluate its legally binding decarbonization targets, which require the state to cut its emissions by 50% by 2030 and at least 85% by 2050, relative to 1990 levels.

“There should be a real hard look at going back and providing some flexibility there” to account for “what’s potentially feasible right now,” AIM’s Thomson said.

“I think it’s possible that the House does this,” she added. “Do I think the Senate would do this? I don’t think they would, but I hope they consider it.”

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Stakeholders Demand Answers on Repeat MISO South Capacity Advisories

Stakeholders told MISO they need a better explanation of the every-other-day capacity advisories issued for MISO South, which have become customary since the beginning of summer.

Jim Dauphinais, an attorney for multiple industrial end-use customers, commented that there’s been an “extraordinary” number of capacity advisories in MISO South in recent months.

“We don’t know if it’s a change in MISO practices or a change in resource availability,” Dauphinais said at a Resource Adequacy Subcommittee meeting Oct. 1. He asked MISO staff to speak on its raft of declarations in the South.

“It makes people ambivalent. … I don’t know if that’s too strong of a word. The situational awareness goes down because they are happening so frequently,” Dauphinais said.

Mississippi Public Service Commission consultant Bill Booth agreed that the regularity of the alerts has made them easier to ignore.

“An alert is useful if there are instructions following it. We’re not sure what to do with these,” Booth said.

MISO Resource Adequacy Director Neil Shah said one of the drivers behind the advisories is a larger number of outages in the South. Beyond that, he said his colleagues would be better equipped to speak on the continual advisories at an upcoming stakeholder meeting.

The RTO has extended its steady stream of capacity advisories from summer into September, issuing 15 capacity advisories over the month, with a few including MISO Midwest.

At MISO’s quarterly Board Week in September, Executive Director of System Operations Jessica Lucas said the RTO is trying to indicate periods of elevated reliability risk in the South so that no one is caught off guard by potential emergency orders. (See MISO Recounts Tough Summer; Monitor Praises Lack of Emergencies and MISO on Track to Wrap Summer with 122-GW Peak, Addresses Frequent South Advisories.)

Stakeholders have speculated that advisories are the direct outcome of the RTO’s load-shed orders in Greater New Orleans during Memorial Day weekend. (See MISO Says Public Communication Needs Work After NOLA Load Shed.)

Public Utility Commission of Texas economist Werner Roth told Shah to expect similar questioning from the Entergy Regional State Committee at its Oct. 7 meeting.

“We’re going to expect some more clarity around this. We are curious to get more of a dive in this,” Roth said.

Pelican Power’s Tia Elliott said she’s been fielding questions about the advisories.

“Is MISO being more conservative because of what happened in May? More information from MISO would be useful,” she said.

WEC Energy Group’s Chris Plante also said his coworkers have been approaching him for answers.

“Was there a change to operational procedures? And if there was, would that potentially extend to MISO North? Those are questions I don’t have answers for,” Plante said.

Minnesota Power’s Tom Butz asked whether the frequent advisories would affect the resource adequacy hours MISO uses in its availability-based accreditation or have an influence on how it plans to divvy up the planning resource margin requirement among its load-serving entities. (See Stakeholders Question MISO Plan to Reassign LSEs’ MW Duties Based on Risky Periods.)

“All fair comments and questions. I hear you guys loud and clear,” Shah said. He promised to take the concerns to fellow staff members and have them address the advisories publicly.

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DOE Seeking Proposals for Power Generation, AI Data Centers

The U.S. Department of Energy is looking for developers that want to build artificial intelligence data centers — and the power generation to run them — on two nuclear sites.

On Sept. 30, DOE issued a request for private-sector proposals at its Oak Ridge Reservation, and the National Nuclear Security Administration issued an RFP for its Savannah River Site.

The selection of Oak Ridge and Savannah River for this purpose was announced July 24 as part of the Trump administration’s drive for AI and “energy dominance.” Also selected were the Idaho National Laboratory and the Paducah Gaseous Diffusion Plant.

On Sept. 8, the Idaho lab announced a request for applications that can be submitted starting Nov. 7.

Proposals are due Dec. 1 for Oak Ridge and Dec. 5 for Savannah River.

Each of the three announcements indicated private-sector partners would be responsible for building, operating and decommissioning their facilities under a long-term lease and for securing utility interconnection. Each indicated that proposals would be evaluated for technological readiness, financial viability, and the details of their plans to complete regulatory and permitting requirements.

A DOE official called the Oak Ridge RFP a step in the transformation of a nuclear remediation site into a nuclear renaissance hub.

An NNSA official called the Savannah River RFP a public-private partnership to accelerate scientific research in pursuit of technology and energy goals. Ten tracts totaling 3,103 acres have been identified there for energy generation and storage co-located with data centers.

Another DOE official said potential uses for approximately 44,000 acres at Idaho include advanced nuclear and enhanced geothermal generation and cold underground thermal storage.

Energy Secretary Chris Wright said July 24 that Idaho, Oak Ridge, Paducah and Savannah River “are uniquely positioned to host data centers as well as power generation to bolster grid reliability, strengthen our national security and reduce energy costs.”

Funding Announcements

The Oak Ridge and Savannah River announcements were among a series issued late Sept. 30 by DOE.

The department announced it will reallocate up to $365 million to stabilize and harden grid infrastructure in Puerto Rico. It said the island territory has suffered from years of deferred maintenance and mismanagement, leaving ratepayers vulnerable to outages and higher costs, including from storms. DOE’s Grid Deployment Office will administer the funding for the upgrades through the Puerto Rico Electric Power Authority.

The DOE Loan Programs Office, meanwhile, has restructured an October 2024 deal with Lithium Americas to help fund construction of processing facilities at Thacker Pass, Nev., site of the largest confirmed lithium deposit in North America. The terms give the U.S. government a 5% equity ownership of Lithium Americas and a 5% share of the company’s joint venture with General Motors, both in the form of warrants.

The department said the revised deal reduces repayment risk for taxpayers and increases loan resilience; it did not indicate any change to the value of the loan, which Lithium Americas and the Loan Programs Office placed at $2.26 billion in October 2024.

DOE also selected Oklo, Terrestrial Energy, TRISO-X and Valar Atomics for a program to build advanced nuclear fuel production lines. They join Standard Nuclear, which was announced in August.

The five will work in the department’s Fuel Line Pilot Program, which supports the Reactor Pilot Program. Together, the pilot programs are pursuing one of the goals in President Donald Trump’s broader vision of a U.S. nuclear renaissance: reaching criticality with at least three advanced nuclear reactor concepts outside of National Laboratories by July 4, 2026.

Oklo, Terrestrial and Valar also were selected for the Reactor Pilot Program.

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GridFast Tool Gives Insight on Future EV Charging Loads

The Electric Power Research Institute (EPRI) has launched a tool called GridFast that will give utilities a jump start on planning for new EV charging loads.

GridFast will allow EV fleet operators and charging providers to share their project plans with utilities at an early stage — well before they make a service request. Utilities can then use the information to plan for customer loads in aggregate, rather than looking at one customer load at a time.

“Through this single platform, we can now collaborate with customers to plan transportation electrification projects years in advance, giving us the visibility to reliably serve their future electrification needs,” Elyssia Lawrence, Portland General Electric (PGE) senior manager of transportation electrification, said in a statement.

EPRI started its nationwide launch of GridFast on Sept. 30, with participation in 33 states.

GridFast offers benefits to utility customers as well. The GridFast portal matches the project location to the correct utility and the appropriate point of contact. The portal uses the same project intake form no matter which utility is involved. It also shows any EV-related programs that might be available.

GridFast works with another EPRI tool, eRoadMAP, to estimate load hosting capacity and help customers with feasibility planning.

“You enter some project information, even if you don’t yet know everything, and you get an estimate of the power needed and other information to begin a utility conversation,” said Taki Darakos, vice president of vehicle maintenance and fleet services for trucking company PITT OHIO.

The Pennsylvania-based company has been investing in EVs and charging infrastructure, including an electrification project at its Harrisburg terminal. Darakos said PITT OHIO interacts with around a dozen utilities that serve its sites, and each has its own programs and procedures. He sees GridFast as a way to streamline those interactions.

EV Load Impact

EPRI estimates that a fully electrified transportation sector could increase current electricity use by about 40%, adding roughly 1,600 TWh of load to the grid. EVs now in operation use about 1.5% of that expected load.

To address barriers to large-scale transportation electrification, EPRI launched a three-year initiative called EVs2Scale2030. Through the initiative, EPRI plans to work with utilities, fleet operators, vehicle manufacturers, charging providers and federal agencies to support the rapid deployment of millions of EVs while minimizing grid impacts.

GridFast is the initiative’s second key planning tool, following the launch of eRoadMAP, a public tool that shows where and when loads are likely to appear on the grid.

PGE and PITT OHIO are among 15 companies that have signed onto GridFast’s “guiding principles.”

Through the principles, utility customers pledge to submit their EV charging projects through the portal as early as possible, while encouraging utilities to use GridFast. Utilities pledge to promote GridFast to customers. And each side agrees to actively engage with the other on project planning.

The “founding group” supporting the principles includes Ameren, CenterPoint Energy, Con Edison, Consumers Energy, DHL, Great River Energy, IONNA, National Grid, Omaha Public Power District, Pacific Gas & Electric, PITT OHIO, PGE, Republic Services, Sacramento Municipal Utility District and Southern California Edison.

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NERC Staff Call for Resource Accreditation Guideline

A new reliability guideline could help make the capacity accreditation process more transparent and balance “consistency with regional adaptability,” NERC staff wrote in a new report based on discussions in a workshop earlier in 2025.

NERC published the Evaluating Resource Contributions for Reliability and Capacity Supply report Sept. 29. It summarized a workshop held by the ERO in June focusing on current practices for capacity accreditation, including effective load-carrying capability (ELCC), barriers to standardization and opportunities for alignment across planning assessment areas, and it provided recommendations from NERC staff to develop a consistent framework for assessing resource adequacy contributions.

ELCC, which represents the total output with which a generator can be counted on to serve load when added to an existing system, is widely used in capacity accreditation, but approaches vary across planning regions because of different modeling assumptions, system characteristics, regulatory environments and stakeholder processes, the report’s authors wrote. Real-time outputs may also “vary significantly from installed capacity,” with writers citing a day in 2023 when wind resources with an assessed ELCC of 25 GW generated only 300 MW in practice.

Workshop participants identified some reasons behind these different approaches. One driver is diversity of resource types. Accreditation in systems in which a single resource dominates focuses primarily on this resource, while calculations for more diverse systems “must consider the interactions between multiple resource types.”

Even a single resource type can lead to added complexity, participants said, observing that “a wind farm’s performance can vary drastically across geographic areas within the same system.” Additional factors in ELCC creation include regional differences such as state- or province-level regulatory requirements and risk tolerance, along with the software used for calculations.

Participants affirmed the value of ELCC in resource planning but said a more standardized approach to RA studies could “provide both consistency and transparency across regions.” They suggested that NERC contribute to developing criteria to improve consistency of RA studies while not altering existing market constructs or prescribing a single accreditation method to apply across systems.

Based on the discussions, NERC staff recommended that the ERO “provide leadership” on the issue by developing a reliability guideline on ELCC and other accreditation methods that brings structure to their development. Key elements of this guideline, according to staff, should include a “rigid core/flexible edge” model that combines well-defined underlying assumptions with flexibility in regional adaptation.

The report’s authors suggested several common baselines for the core principles, such as weather year assumptions that normalize sample size and weighting for each year; detailed modeling for planned an unplanned resource and transmission outages, weather-dependent outages, energy and fuel constraints and operational limits; and interregional and internal transmission.

Elements of the “flexible edge” include encouraging marginal and multi-scenario ELCC assessments that can reflect changing system portfolios and incorporate anticipated resource additions and retirements, addressing hybrid and demand response resource types through expanded ELCC methods or new metrics and identifying validation techniques for ELCC-based models and benchmarking across regions.

Along with developing the guideline, the authors suggested that the ERO promote transparency and documentation of resource modeling approaches, assumptions in RA constructs and techniques for study processes and validation. They said NERC’s Reliability Assessment Subcommittee and Probabilistic Assessment Working Group could help planners share experiences and establish consistent methodologies.

NERC can also conduct energy assessments for each interconnection that can serve as the basis for a harmonized approach to resource accreditation. Planners can use these studies to benchmark regional practices and identify deficiencies with current tactics.

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CEBA Study Shows How Corporate Offtake Helps Clean Energy Get Built

The Clean Energy Buyers Association released a study Sept. 30 that offers hard evidence that its large corporate customer members have materially contributed to the growth of renewables by guaranteeing projects stable revenue streams.

REsurety, which conducted the study for CEBA, analyzed 251 renewable projects in ERCOT, MISO and PJM, which are home to 70% of corporate procurements forecast for the near future. It found that those with power purchase agreements from large buyers are much more financially stable.

“We commissioned this study because we wanted to definitively confirm what we’ve all known … that voluntary corporate offtake matters: corporate commitments to buy clean energy, [and] get clean energy projects financed and built in the United States,” Misti Groves, CEBA senior vice president of U.S. strategy, said in an interview.

Corporate customers contracted for 100 GW of clean energy between 2014 and 2024, which represent about 40% of the total brought online over that decade. Such deals give renewable projects a steady revenue stream that helps them to get financed, the study says.

“Without extensive voluntary commitments by our members and companies, the U.S. may actually struggle to meet energy demand, which is growing,” Groves said.

The paper was retrospective, so it focused on purchases of wind and solar, but the same financial benefits can help other technologies such as battery storage, geothermal and nuclear power, she added.

REsurety simulated economic performance of the 251 projects by calculating operating income and debt obligations using historic generation, price and operating cost data from 2015 to 2024 and then identifying sustained periods of financial stress, the study says.

“In contrast to fossil fuel generators, wind and solar projects have low operating costs but relatively high capital expenditures that are financed through a combination of sponsor equity, tax equity and back leverage debt,” the study notes. “Once a project becomes operational, it must repay these upfront costs through term loans and dividends to investors. During periods of low wholesale power prices, projects may not earn enough merchant revenue to meet their debt service obligations or their investors’ rates of return, which, absent additional revenue sources, could lead to financial distress and potential default.”

Offtake agreements with corporate customers cut the likelihood of projects entering periods of financial distress by offering steady income. That means debt interest rates and required debt service coverage ratios are lower for projects with offtake agreements.

Power prices can vary significantly, with the paper pointing to three years this decade: Prices were low in 2020 because of the COVID-19 pandemic, jumped up in 2022 because of expensive natural gas and then were low again in 2024 as cheap gas returned. Over the last two years alone, average prices in PJM ranged from $30 to over $70/MWh.

“For a 100-MW project with a 40% capacity factor, this translates to a swing in annual merchant revenue from $10.5 million to over $24 million,” the study reported.

All markets saw benefits from some kind of offtake with renewable energy credit (REC) deals lowering risk somewhat, but virtual PPAs slashing it, the study found. In ERCOT, 38% of merchant projects faced simulated financial distress, which fell to 18% with REC deals and 9% with VPPAs. In MISO the equivalent numbers were 74% for merchant projects, down to 57% with REC deals and just 4% with VPPAs, while PJM saw 71% of merchants with some distress, which fell to 60% with REC deals and 1% with VPPAs.

Corporate offtake is not a subsidy, REsurety Senior Vice President Adam Reeve said. Tax credits have provided a subsidy to renewables, but offtake deals are at market prices.

“The benefit of the corporate purchase is transferring risk away from the project that enables them to secure debt financing and then get built,” Reeve said in an interview. “Debt financing is the cornerstone of infrastructure investment around the world. We’re doing a lot of infrastructure investment in the U.S. We need that right now.”

Regardless of the presence of tax credits for energy projects, that risk transfer is a benefit that will help get power plants built, he said.

“Without continued corporate risk transfer … for these long-term, stable revenues, we won’t see the growth of low-carbon power in the U.S. that I think we would otherwise,” Reeve said.

The study focused on three wholesale power markets, but it argued that the same would hold true for other markets.

“It’s no accident that that voluntary contracts for clean energy happen in deregulated wholesale markets rather than regulated markets,” Groves said. With its transparent wholesale prices, the construct helps corporations enter into VPPAs and other offtake deals, she added.

“In this next year, as renewable energy projects aim to meet deadlines for tax credits, the support and cooperation of corporate buyers will give developers the confidence to advance spending to secure tax credits to reduce the cost of renewable energy,” Joan Hutchinson, Marathon Capital’s managing director of offtake advisory, said in a statement.

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D.C. Circuit Vacates FERC Cancellation of Reactive Power Compensation in MISO

The D.C. Circuit Court of Appeals on Sept. 26 vacated a FERC order allowing MISO to end reactive power compensation, though the decision has no bearing on the nationwide discontinuation of payments for reactive power in Order 904 (23-1134).

The court said that when FERC greenlit MISO’s move to eradicate reactive power revenues, it failed to fully consider the generators’ short-term financial health. The court remanded the matter back to FERC for a fresh decision.

MISO in 2023 ended reactive power charges in transmission rates along with cost-based compensation for generators’ production of reactive power (ER23-523). (See FERC Ends MISO Compensation for Reactive Power Supply.) Since then, the RTO has treated reactive power within the standard power factor range — which plays a hand in stabilizing voltage levels across the grid — as an incidental product of generation and transmission and doesn’t facilitate sales.

Several generators objected and argued that MISO’s immediate removal would disturb their investment-backed interests. The D.C. Circuit agreed, saying FERC neglected to “consider important aspects of the problem before it.”

“The generators explained that they had incurred significant debt and contractual obligations relying on MISO’s longstanding practice of allowing generators to recover cost-based compensation for reactive power. In approving MISO’s proposal to eliminate that compensation, FERC failed to explain why these financial concerns were unjustified, entitled to no weight or outweighed by other considerations,” the court said.

In late 2024, FERC issued Order 904, prohibiting transmission providers from including charges in their rates to compensate generators for reactive power within the deadband range (0.95 leading to 0.95 lagging). The commission decided the normal range of reactive power would simply be a condition of interconnection (RM22-2).

The court acknowledged that FERC’s nationwide ban on reactive power compensation remains in place despite its order to revisit the MISO decision. The court said that the “dispute here remains live because both orders are still under review” and said the generators are free to separately challenge the proceedings “even though success in only one proceeding might not fully redress [their] injury.”

Although its ruling doesn’t restore reactive power compensation in MISO, it does remove one barrier and help establish redressability, the court said.

It pointed out that MISO had been compensating generators for deadband-level reactive power production since the mid-2000s. Before the end of the practice, MISO paid about 400 generators for reactive power, which totaled $200 million annually according to one estimate. The “overnight” elimination of the revenue stream had generators claiming their wholesale power contracts would become unprofitable and undermine their ability to service debt and attract capital, the court noted.

FERC’s reasoning that marginal costs of producing deadband-level reactive power are minor ignores that revenues in MISO have been significant, the court found. It also said FERC’s solution that generators either renegotiate prices in existing power purchase agreements or increase asking prices in new contracts was unsatisfactory.

The court said FERC erroneously tasked generators with proving they relied on reactive power revenue when the commission should have burdened MISO with proving that an immediate end to the compensation was reasonable. It pointed out that FERC never considered a more gradual end to the compensation in MISO, even while Order 904 contained a 60-day phase-in period.

Order 904 is under review in the 5th U.S. Circuit Court of Appeals. The D.C. Circuit said that did not foreclose FERC “from giving a more thorough explanation in support of MISO’s amendments on remand.”

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NRG Secures $562M Loan from Texas Energy Fund

Texas regulators have finalized a third loan agreement through the Texas Energy Fund’s in-ERCOT program with NRG Energy for a 721-MW natural gas-fired plant near Baytown in Houston’s dense petrochemical region.

Under the agreement, the Public Utility Commission of Texas will provide a 20-year loan of $562 million at 3% interest from the TEF. That will cover 60% of the project’s costs, estimated at $936 million.

Construction has already begun on the facility at NRG’s existing Cedar Bayou Generating Station, and the plant is expected to begin producing power by the summer of 2028. The project will be interconnected in the Houston Load Zone, the fifth-largest metropolitan area in the U.S.

“The Texas Energy Fund is bringing reliable, affordable power to ERCOT’s fastest-growing regions,” PUC Chair Thomas Gleeson said in a statement.

The TEF loan is NRG’s second under the fund’s in-ERCOT Generation Loan Program, one of four in the $10 billion program. The Houston-based company secured a $216 million loan in August to help build 456 MW of gas-fired capacity at another existing site in the region. (See NRG Energy Secures $216M Loan from TEF.)

Under the loan agreement, the facility must meet minimum performance standards. The PUC administers the TEF through a competitive application process and financial review of proposed projects.

The three in-ERCOT loans disbursed so far will add 1,299 MW to the Texas grid. A commission spokesperson said 14 applications are still moving through the program’s due diligence process, representing an additional 7,671 MW of capacity.

The $10 billion TEF, approved by voters in 2023, is designed to add 10 GW of gas-fired generation to the Texas grid.

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Reports Quantify Changes in U.S. Energy Storage Sector

New reports give a picture of a U.S. energy storage sector accelerating even faster in 2025 despite policy changes but facing a potential slowdown because of those same policy changes.

American Clean Power Association and Wood Mackenzie reported 5.6 GW of new capacity was installed in the second quarter, a quarterly record.

Troutman Pepper Locke examined the heightened risk facing U.S. storage developers amid the regulatory and tariff uncertainty created by the Trump administration and Congress.

U.S. Energy Information Administration reported that this rapidly expanding class of grid assets increasingly is being used for arbitrage, rather than for grid-stabilizing functions.

ACP and Wood Mackenzie

In their latest “US Energy Storage Monitor” report, released Sept. 26, ACP and Wood Mackenzie said 4.9 GW of utility-scale storage was added in the second quarter of 2025, 63% more than in the same quarter of 2024.

Residential installations totaled 608 MW, up 132% year-over-year, and community/commercial/industrial installations totaled 38 MW, up 11%.

Texas, California and Arizona each added more than 1 GW of utility-scale storage. California, Arizona and Illinois accounted for most of the residential growth. More than 70% of the commercial and industrial installations were in California and New York; community storage deployments remained limited due to cost and policy constraints.

The report predicts U.S. storage capacity will reach 87.8 GW by 2029.

But headwinds facing the sector could reduce utility-scale storage installations 10% in 2027, the report indicates.

And over the next five years, those headwinds could reduce the buildout by 16.5 GW, said Allison Weis, global head of storage at Wood Mackenzie.

“After 2025, utility-scale storage projects must comply with new, stringent battery sourcing requirements to receive the ITC,” Weis said. “While domestic cell supply is ramping up, supply chain shortages are possible, although developers are continuing to consider supply from China to fill in any gaps. A rush to start construction under the more certain near-term regulatory framework uplifts the near-term forecast. Projects that have not met certain milestones by the end of 2025 are at risk of exposure to changing regulations. There is additional downside risk if further permitting delays threaten solar and storage projects.”

Troutman Pepper Locke

Troutman Pepper Locke drilled down on these headwinds in “Brave New World: What’s Next for US Energy Storage After OBBBA and Amid Continued Tariff Risk?”

In its announcement of the report Sept. 23, the law firm said the sector was “bruised but buoyant amid regulatory and tariff uncertainty” and detailed how developers, investors and lenders have prepared for these risk factors.

The report also explains why they remain confident about the storage sector’s growth trajectory in the wake of the One Big Beautiful Bill Act (OBBBA), which dealt so much pain to other parts of the clean energy industry.

“Energy storage’s versatility of use cases has untethered it from the fate of wind and solar to a meaningful degree,” said co-author Vaughn Morrison, a partner in the firm.

Andrew Waranch, CEO of storage developer Spearmint Energy, explained the economics: “So much of the power market and power price is set by expensive and old generators that only need to operate during ramp times in the morning and evening. In contrast, batteries can solve that quickly and cheaply with extremely high reliability.”

The national origin of the batteries will be an important factor moving forward, said John Leonti, a partner in the law firm.

He said: “Although the impact of the OBBBA on energy storage is less severe than some feared, the ambition to onshore battery component manufacturing and the attendant Foreign Entities of Concern (FEOC) provisions issue significant supply challenges for the industry moving forward.”

Headwinds and tailwinds for U.S. battery energy storage systems will mix as demand for their services rises while heavier loads are placed on an aging grid, to a degree that far outstrips U.S. production capacity, the report states.

The majority of battery components come from China, where tariffs and FEOC restrictions will boost material costs.

Energy Information Administration

In an analysis released Sept. 22, the EIA tracks U.S. utility-scale battery storage capacity in the 2020s.

The 230 plants operational in 2020 had a nameplate capacity of 2.09 GW. The 786 plants operational in 2024 had a nameplate capacity of 27.82 GW.

EIA in its surveys has been asking operators since 2020 if arbitrage was among the use cases for their batteries, but it was only in 2023 that EIA started asking if arbitrage was the primary use case.

It found that arbitrage was among the use cases for 66% of all utility-scale battery capacity in 2024 and the primary use case for 41%.

The most common other primary uses, in descending order, were frequency regulation, excess wind/solar generation, system peak shaving, load management and co-located renewable firming.

The EIA data shows other shifts:

    • Lithium-ion batteries accounted for 86% of the projects in 2020 and 96% in 2024.
    • Non-CHP IPPs operated 54% of facilities and 75% of capacity in 2020; that jumped to 72% of facilities and 86% of capacity by 2024.
    • Electric utilities operated 35% of facilities and 23% of capacity in 2020; that dropped to 23% of facilities and 10% of capacity by 2024.
    • Only 22% of facilities and 17% of capacity was operated in support of transmission and distribution assets in 2024.
    • As of 2024, there were 558 facilities with a combined nameplate capacity of 74.64 GW classified as “proposed”; here again, non-CHP IPPs are behind the great majority of the proposals, the great majority of which would entail lithium-ion batteries. Arbitrage would be the primary or secondary use for 402 projects with a combined capacity of 56.3 GW.

EIA breaks U.S. utility-scale battery capacity into three geographic categories: CAISO, ERCOT and everywhere else. 2024 ended with nearly 12 GW of capacity online in CAISO, approximately 8 GW in ERCOT and roughly 7.5 GW in the rest of the country.

ERCOT showed the heaviest activity, with roughly 7 GW sometimes used and 4 GW primarily used for arbitrage.

Arbitrage was somewhat less frequent in CAISO and much less frequent in the rest of the country, where only about 2 GW was primarily used to facilitate buying electricity when cheap and selling it while expensive.