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.
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.
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.
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.
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.
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.”
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.
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.”
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.
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.
The Western Power Pool’s Western Resource Adequacy Program (WRAP) has secured enough participants for the program to enter the first binding phase after 11 utilities reaffirmed their commitment in a Sept. 29 letter.
The utilities’ assurance that they will remain in the program comes shortly before the two-year opt-out deadline. The recommitment means WRAP has secured a “critical mass” of participants to move forward with the first binding season in winter 2027/28, WPP said in a statement on its website.
The letter is signed by Arizona Public Service, Avista, Bonneville Power Administration, Chelan Public Utility District, Clatskanie Public Utility District, NorthWestern Energy, Powerex, Puget Sound Energy, Salt River Project, Tacoma Power and Tucson Electric Power.
“As utilities that have actively participated in WRAP since its inception in 2019, we reaffirm our commitment to the program and to continue building on its strong foundation,” the letter stated. “The signatories to this letter will remain in WRAP and participate in binding operations starting in winter 2027/28.”
“The participants who have voiced their commitment to the program represent a broad and diverse group of organizations,” WPP said in its statement. “In addition to those who signed the letter, there are more participants we expect to remain in WRAP, some that recently joined and even more joining in upcoming years.”
Under the program’s forward-showing requirement, participants must demonstrate they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus capacity must help those with a deficit in the hours of highest need.
The binding phase also includes penalties for participants that enter a binding season with capacity deficiencies compared with their forward showing of resources promised for that season.
In 2024, the binding phase was postponed by one year at the request of participants, who said they were facing challenges including supply chain issues, faster-than-expected load growth and extreme weather events that would make it difficult for them to secure enough resources and avoid penalties. WRAP members voted in September 2024 to delay the binding phase until summer 2027, but that date was pushed forward. (See WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027.)
WRAP has also become a focal point in the competition between SPP and CAISO. Both are developing separate day-ahead markets and are trying to attract as many participants as possible. Supporters of SPP’s Markets+ have highlighted that participants in the market must join WRAP, while arguing that CAISO’s Extended Day-Ahead Market (EDAM) contains no RA framework. Most of the signatories to the letter have committed to Markets+.
The organizations wrote in the Sept. 29 letter that WRAP continues to evolve, highlighting the “multiple task forces” involved in developing the program. One such task force is the WRAP Day-Ahead Market (DAM) Task Force that is working to make the program compatible with Markets+ and EDAM. (See WRAP Day-Ahead Market Task Force Moves Forward on Concept Paper.)
“We are confident the program will continue to grow and adapt,” the organizations said. “The program’s design will evolve alongside emerging day-ahead markets, while its broad participation ensures the collective savings and reliability benefits are delivered for customers.”
The utilities noted also that some current signatories to the program may still exit, but added that “the participants signing this statement represent only a portion of the utilities committed to WRAP’s long-term success.”
“By stepping forward now, we intend to demonstrate early momentum, provide confidence to those still weighing their options and signal that WRAP will continue to deliver value as it enters its binding phase,” the organizations wrote.
“We remain confident in the fundamental premise of WRAP and the value it brings,” WPP said. “Over the next two years, in addition to onboarding new members, we will focus on changes and updates to optimize the program and respond to concerns raised by participants and stakeholders. This will allow WRAP to maximize the benefits it delivers when binding operations begin and help address the growing challenge of resource adequacy.”
Stakeholders Endorse Widened Provisional Interconnection Service
PJM’s Markets and Reliability Committee endorsed by acclamation a set of manual revisions to expand when a new resource could be granted provisional interconnection service to allow for early operation when it becomes capable of injecting a portion of its output while its network upgrades still are under way.
PJM Director of Interconnection Planning Donnie Bielak said the RTO brought the changes against a backdrop of an increasing number of emergency procedures with the objective of making as many resources as possible available to dispatchers in the coming years.
The Planning Committee endorsed the quick fix proposal Sept. 9, including an issue charge to explore creating a process for PJM to proactively identify resources that could take advantage of provisional service. (See PJM Stakeholders Endorse Expansion of Provisional Interconnection Service.)
Interim deliverability studies are conducted to determine if resources that have been completed, but are awaiting completion of assigned network upgrades, can operate without triggering transmission violations.
Under current rules, if a unit cannot reliably inject its full output, it is denied provisional service. The proposal would create a second round of analysis to determine if a resource not capable of full operations could provide output at a fraction of its nameplate. If so, an operational guide would be produced to inform dispatchers how the unit could be operated. Project developers must request, and pay, for PJM to conduct the studies, which would not be changed by the proposal.
Bielak said PJM is processing studies for the 2026/27 delivery year and is planning to present the results in the next few weeks. If the change is approved, it will be applied to the results and no further action is needed from developers who already have sought provisional service for that year.
Stakeholders debated an amendment PJM proposed to add the phrase “consistent with PJM’s governing documents” to language outlining the information the RTO would publish about individual requests for interim deliverability studies, including the location and provisional output desired. After a discussion with stakeholders, PJM revised the amendment to instead state that applicants “agree to waive their rights to confidential treatment of such requests” and agree to the publishing of that information.
Proponents of requiring the disclosures argued transparency is needed around the requests to ensure applicants would not have insider information about the resources likely to be in operation months before other market participants become aware.
Independent Market Monitor Joe Bowring said the proposal is a great step forward on PJM’s part but contended that the resource owner should be obligated to perform when dispatched by PJM. Without such a requirement, the RTO could not rely on any possible reliability benefit from provisional resources.
Committee Approves Changes to DR Participation in Regulation Market
Stakeholders endorsed a proposal to allow demand response resources to enroll to provide regulation-only service when there are energy injections at the point of interconnection. (See “PJM Reviews Proposal on Regulation Resources at NEM Sites,” PJM MRC/MC Briefs: Aug. 20, 2025.)
The changes would allow a DR resource to participate in the regulation market when there is no load or a net injection at its POI with the consent of its relevant electric distribution company memorialized in a net energy metering agreement.
Intelligent Generation CEO Jay Marhoefer said the proposal would restore a mode of DR participation that was lost in previous FERC orders on the regulation market.
During the July 9 Market Implementation Committee meeting, he said some EDCs changed their tariffs in a manner that inadvertently prevented behind-the-meter storage from participating in the regulation market while injecting. (See “Stakeholders Endorse Changes to Storage Participation in Regulation Market,” PJM MIC Briefs: July 9, 2025.)
Bowring said advancing one element of PJM’s Order 2222 compliance filing would provide special treatment for one class of market participants and open the door for others to ask for expedited treatment for their preferred components.
“Clearly the FERC thought it was reasonable to do this, but in 2029,” he said.
Stakeholders Vote for Cost Allocation for DOE Emergency Orders
For orders addressing an RTO-wide resource adequacy issue, PJM would use a pro forma cost allocation that splits the costs a resource owner incurs under the emergency order across all RTO load based on each entity’s share of the monthly unforced capacity obligation. The pro forma approach would be used only when resource owners and PJM agree to use the deactivation avoidable cost credit (DACC) compensation model.
If the RA concern affects specific regions, PJM would initiate an “abbreviated stakeholder consultation” with the goal of drafting Reliability Assurance Agreement revisions addressing cost allocation. The process would pick up where the PJM DOE 202(c) Cost Allocation Senior Task Force left off on identifying recommended approaches for the RTO’s Board of Managers to consider.
If there is an emergency order unrelated to RA, PJM would initiate a Critical Issue Fast Path (CIFP) process, similar to how it proceeded after the U.S. Department of Energy ordered Constellation Energy and PJM to keep the Eddystone Generation Station outside Philadelphia online past its scheduled deactivation at the end of May. (See FERC Approves Cost Allocation for Eddystone Emergency Order.)
The abbreviated stakeholder consultation would be considered a workshop under a new section to be added to Manual 34: PJM Stakeholder Process, with voting at the MC. The pro forma cost allocation would be added to the RAA under Section 7.2A Responsibility to Pay 202(c) Charge.
Denise Foster Cronin, EKPC’s vice president of federal and RTO regulatory affairs, said she is glad PJM adopted a wider perspective on how it could proceed under different scenarios, but argued the proposal remains flawed without any way for PJM to determine the cause of an RA emergency order without direction from DOE. She said the department is unlikely to delve into the drivers of RA needs.
Sophia Dossin, of Middle River Power, said the RTO should think about how to proceed if there is disagreement between PJM and stakeholders about whether to move ahead with the pro forma.
Phil Sussler, of the Maryland Office of People’s Counsel, argued stakeholders should have an opportunity to gain more insight into what costs can be recovered under the DACC methodology. He said units whose deactivations are being deferred are more likely to be older and run into unexpected problems that substantially increase costs. Consumer advocates protested PJM’s cost allocation filing for Eddystone, arguing that the compensation should be subject to FERC oversight rather than a bilateral agreement between PJM and the resource owner.
Responding to a stakeholder question, PJM’s Lisa Morelli said the costs to keep Eddystone online in June were covered by the revenues it received in PJM’s markets.
Regulation Market Manual Revisions Approved
The committee endorsed by acclamation a revision to Manual 11: Energy & Ancillary Services Market Operations to reflect the adoption of a tracking metric for the amount of regulation a resource should be providing. The change was included in the first phase of PJM’s redesign of the regulation market; however, language detailing the calculation of lost opportunity cost credits did not reflect the tracking regulation set point. PJM’s Brian Chmielewski said the changes are to be rolled out at the beginning of October. (See “Update on Regulation Market Design,” PJM OC Briefs: April 3, 2025.)
Members Committee
Stakeholders Endorse Revisions to CIR Transfer Filing
PJM’s Members Committee endorsed a set of revisions to a proposal to rework how capacity interconnection rights (CIRs) can be transferred from a deactivating resource to a replacement following FERC’s rejection of the original tariff changes (ER25-1128). (See PJM Preparing Alterations to Rejected CIR Transfer Proposal.)
The changes to the proposal center on two exemptions from the commercial operational date requirements for the replacement resource — one for resource types known for long development timelines and a one-time allowance for an indefinite COD delay. In its Aug. 8 denial, the commission found that allowing developers deferrals that could last years could open the door for owners to withhold CIRs by tying them up in theoretical planned resources.
The new COD requirement would mandate the replacement unit be in service by the greater of four years from the submission of the replacement generation application or three years from the deactivation date of the original resource. An amendment offered by Vistra added a requirement that the resource be online within three years of its planned in-service date and reserves the right for a developer to seek a FERC waiver from the COD requirements.
Vistra’s Erik Heinle said the change provides room for PJM and developers to negotiate the milestones.
PJM’s Jason Shoemaker said staff designed the revisions around the Reliability Resource Initiative (RRI), a one-time window PJM opened to allow 51 resources to have their interconnection studies processed under Transition Cycle 2. Like the CIR transfer proposal, RRI was intended to allow resources likely able to come quickly into service to have their interconnection process expedited.
The larger proposal aims to speed the process for studying whether a replacement resource requires network upgrades and offer an interconnection agreement within nine months of a request to transfer CIRs. A resource would be permitted to pursue the expedited process even if minor network upgrades are identified, and a categorical prohibition on storage resources would be eliminated. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.)
Discussion with Board Members on Large Load Growth
The Board of Managers discussed with stakeholders an ongoing CIFP process addressing large load growth, continuing a standing item on the MC agenda that board Chair David Mills sought in an effort to improve the transparency and accessibility of the body.
Opening the conversation, Mills said much of the CIFP meetings thus far have focused on the RTO’s non-capacity backed load (NCBL) and bring-your-own generation proposals, but many of the comments submitted at the onset of the process focused on the load forecast and the need to ensure understanding of the scale of the problem. He questioned how the membership prioritizes improving the load forecast relative to solutions focused on serving large loads.
Asthana said PJM has removed NCBL from its CIFP proposal based on opposition from much of the membership. Materials for the Oct. 1 CIFP meeting say PJM is shifting the focus to a price-responsive demand model similar to a voluntary NCBL model and a parallel expedited interconnection queue.
Heinle said the load forecast will dictate the range of solutions stakeholders should focus on, scaling to the size of the problem, and recommended that PJM integrate a “ground-up” perspective on the amount of data center load expected in the region. He said there seems to be an assumption that every data center load is coming to PJM, even while that industry sees many of the same supply chain issues plaguing the electric industry.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said this is one of the biggest discussion points stakeholders face, with load growth expected in the next five to seven years exceeding the total load served by CAISO. If those estimates are accurate, he said he’s not aware of any changes PJM can make to bring on sufficient generation in time.
Exelon’s Alex Stern said the load forecast is an important data point but is one of many the states and utilities use to guide their decisions around ensuring load is served. He said there has been a great deal of work done already at the Load Analysis Subcommittee to improve the transparency of the data presented there, as well as on the large load adjustment submission process.
The Bureau of Ocean Energy Management is seeking to remand its earlier approval of the construction and operations plan for Atlantic Shores Offshore Wind.
The New Jersey project already is on at least a temporary pause. Neither construction nor operation will happen anytime soon, because it terminated its financial agreement with New Jersey, half of the partnership quit the joint venture and the Environmental Protection Agency has remanded its air permit for further review. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)
The Sept. 26 court filing further clouds the future.
The Jersey Shore anti-wind group Save Long Island Beach Inc. applauded the court filing Sept. 27: “It’s a rare and important moment. It confirms the seriousness of the technical and scientific concerns we’ve raised, for many years now — especially regarding the impacts to endangered North Atlantic right whales and cumulative construction and operation harms to the North Atlantic right whale migration corridor.”
An Atlantic Shores spokesperson said Sept. 29: “Atlantic Shores is disappointed by this course of action and has no further comment.”
All 11 of the offshore wind projects approved by BOEM received their approvals during the Biden administration.
Hours after the start of his second term, President Donald Trump set about undoing his predecessor’s work. He or his agencies have canceled future development, halted the progress of existing early-stage projects and moved to block construction of approved middle-stage projects.
One of the 11 projects is complete, one was canceled by the developer in 2023 and five are under construction. The Trump administration has motioned in court to remand the approvals of the other four: Atlantic Shores, New England Wind, SouthCoast Wind and US Wind.
Save Long Beach Island Inc. sued the federal government July 25 in U.S. District Court for D.C. (1:25-cv-02211) seeking to overturn approval of Atlantic Shores project.
The Sept. 26 federal filing is similar to the three other motions to remand: It indicates that BOEM wants to re-examine its earlier approval because it might not have fully accounted for all of the impacts of Atlantic Shores in its initial review.
BOEM intends to conduct a full review and then approve, disapprove or approve with conditions the Atlantic Shores construction and operations plan it approved Oct. 1, 2024, during the waning days of the Biden administration. As such, the wind opponents’ lawsuit should be stayed until conclusion of the review, the federal government asserts, because their case may well become moot.
The Trump administration has shown a sustained antipathy toward offshore wind development. However, the Sept. 26 federal motion asserts Atlantic Shores would merely be speculating if it is worried that BOEM might not reapprove the project.
And if Atlantic Shores did not like the outcome of the review, the Department of Justice wrote in its motion, it is free to file a challenge, assuming all jurisprudential requirements are met.
The Department of Justice further asked the court not to impose any artificial deadline for the remand process, as it might affect BOEM’s ability to conduct a proper and thorough analysis.
