Meta has signed a 20-year power purchase agreement for the output of Constellation Energy’s 1,121-MW Clinton nuclear plant in Central Illinois, the companies announced June 3.
The deal will begin in June 2027, upon expiration of the state’s zero-emission credit program that has been subsidizing operation of the plant. The PPA in effect will replace the ratepayer-funded ZECs.
In their announcements, Constellation and Meta hailed the deal as a landmark market-based solution to keep older nuclear facilities online, producing high-capacity-factor baseload power without carbon emissions.
With 38 years in service, Clinton is among the youngest U.S. commercial reactors. It was operating at a continuing loss in the mid-2010s and was slated for early retirement, but Illinois created the ZEC subsidy in 2017, returning it to profitability.
The facility’s license extends through April 2027. Constellation in 2024 filed an application with the Nuclear Regulatory Commission for a 20-year renewal, with the caveat that how long it actually operated the reactor would depend on the economics and on policy support.
As part of the agreement with Meta, Constellation will perform uprates that will add 30 MW to the existing 1,092-MW nameplate capacity of the facility.
Constellation now is considering seeking an extension of Clinton’s existing early site permit or seeking a construction permit for an advanced reactor or small modular reactor to be co-located with the existing facility, located in Zone 4 of MISO’s capacity market.
In September 2024, the company announced a PPA with Microsoft for output from the Crane Clean Energy Center — the former Three Mile Island Unit 1, which it retired in 2019 for economic reasons. The company had begun the decommissioning process but is working to restart the reactor.
In Constellation’s news release, CEO Joe Dominguez asked rhetorically why Three Mile Island had shut down in the first place, and said Meta had asked a similar question about the future of Clinton.
“They figured out that supporting the relicensing and expansion of existing plants is just as impactful as finding new sources of energy,” Dominguez said. “Sometimes the most important part of our journey forward is to stop taking steps backwards.”
“Securing clean, reliable energy is necessary to continue advancing our AI ambitions,” said Urvi Parekh, Meta’s head of global energy.
Meta also provided an update June 3 on its advanced energy ambitions, as it seeks to match the electricity used in its data centers with 100% clean and renewable energy. It said that as it considers emergent technologies, it recognizes the value of the firm, reliable capacity offered by nuclear fission.
The tech giant said it has received more than 50 qualified submissions in response to its nuclear request for proposals and is in final discussions with shortlisted developers for potential projects.
Meta is focusing on sites where nuclear development can be advanced with speed and certainty as it tries to assemble a 1- to 4-GW portfolio of projects. It hopes to finalize the process this year.
All of this, and the Constellation PPA, are intended to send signals of support and demand to the nuclear sector, Meta said: “Our investments in nuclear energy ensure that we will have the robust energy infrastructure needed to power the AI innovations that are set to spark economic growth and prepare our communities for the future.”
New Jersey legislators have backed clean energy bills that include efforts to promote the development of small modular nuclear reactors and enable the state to better deal with data centers.
The Senate Environment and Energy Committee approved S4423, which would enable the Board of Public Utilities (BPU) to authorize site approval for a small modular reactor (SMR) in a municipality where a nuclear facility previously was located. The agency could supersede municipal and county decisions to authorize reactors able to generate 300 MW of power or less. The reactors would be licensed by the Nuclear Regulatory Commission, and nuclear fuel would be stored on-site.
In a separate vote, the full Senate on June 2 voted 38-0 in support of a third data center bill, A5466, which would direct the BPU to study the “effect of electricity usage by data centers on electricity rates in the state.”
The bill, which goes to the governor’s desk, would require the study to look at:
Cost allocation, to determine if other electricity customers “unreasonably subsidize” the costs of data centers.
Whether other customers incur “unreasonable rate increases” to support new transmission, distribution or generation facilities that serve data centers.
Policy alternatives such as “the use of a special tariff to be applied to data centers, that could be used to mitigate or avoid rate increases caused by increased electricity demand by data centers.”
Fixing an Energy Shortfall
The votes come as New Jersey, an importer of energy, searches for ways to boost its generating capacity. Demand for electricity is expected to rise dramatically over the next decade, fueled in part by the growth in electric vehicle use and the needs of data centers. PJM says its region, which includes New Jersey, faces an energy crunch because new generating sources aren’t coming online as quickly as old, fossil-fueled sources are closing.
The nuclear and data center bills were among a slew of bills — including initiatives focused on storage, solar and geothermal energy — aimed at boosting the state’s clean energy resources and curbing energy use.
Two bills moved by the Senate committee address the expected arrival of data centers, including those supporting artificial intelligence capability. The committee backed S4293, which would require the owner or operator of a data center to prepare an annual report to the BPU of the facility’s water and electricity use.
The report also should include “basic information” on the facility and “performance calculations and indicators for the data center, including the energy reuse factor, power usage effectiveness, renewable energy factor and water usage effectiveness.”
Opposing the bill, Ray Cantor, a lobbyist for the New Jersey Business and Industry Association, said the bill would needlessly add a burden to data centers that might consider coming to the state. State requirements already ensure water permits are not issued unless there is sufficient water, he said.
“From an energy perspective, these data centers are either bringing their own energy, or they’re using energy off the grid, and that’s all being accounted for,” he said.
“On the one hand, we have policies in the state, and the governor has mentioned this as well, where we want business to come and locate here in New Jersey,” he said. “And then [on] the other hand, we pass legislation like this, which, while it’s not the end of the world from a regulatory perspective — it’s just another thing that’s being required. And it’s another thing that’s being required that doesn’t need to be required.”
Erecting Roadblocks
Cantor said he had similar concerns about another bill later backed by the committee, S4307. It aims to protect ratepayers from shouldering the burden of the development of generation systems that support data centers.
The bill is designed to incentivize data centers to increase energy efficiency, including through the use of technologies that use the heat produced by the data center. In addition, it would require that the BPU review each application to ensure the data center creates and submits a tariff that demonstrates the facility’s compliance with the law.
Cantor said enticing data centers to move into the state would be difficult if “we’re continually putting roadblocks in the way or making it more expensive or problematic to develop here in New Jersey.”
“We recognize that data centers are large energy users,” he said. “But they’re not the only large energy users. We have large manufacturing plants that use as much or more energy than data centers. Even hospitals could use more energy than a data center. And yet we don’t single them out for special treatment.”
Senate Environment and Energy Committee Chair Bob Smith said the bill “is absolutely a response” to a $20 hike in the average electricity bill that took effect June 1. State officials say the increase, set by the state’s Basic Generation Services auction, was triggered in large part by PJM’s capacity auction in July 2024, which included a massive jump in prices compared to the previous auction. PJM officials attributed the jump in part to high-demand data centers.
Doug O’Malley, director of Environment New Jersey, disputed Cantor’s claim, saying data centers can be far larger than community institutions, using as much as 1 million gallons a day for cooling and electricity generation.
“We can’t just rely on what we have right now. That’s why this bill is so important,” he said. “This is a reminder that we cannot have water hogs, (or) an energy hog, that literally spikes electricity rates (for) everybody.”
The committee passed the bill with a 3-2 vote. The bill will go to the Senate Budget and Appropriations Committee.
Fixing an Energy Shortfall
In a separate vote, the Environment and Energy Committee voted 5-0 to back a bill, S4100, designed to simplify and speed up the process by which solar projects are permitted.
State officials say developing more solar is one of the quickest ways to address the pending electricity shortfall. But the bill says “New Jersey has the fifth-slowest-known solar permitting timelines of any state.”
“Vestiges of outdated, overly bureaucratic permitting requirements” cause residents to “significantly delay installation efforts and significantly increase costs incurred in installing residential solar energy storage,” the bill states.
Elowyn Corby, mid-Atlantic director for Vote Solar, in supporting the bill, told committee members that “local solar benefits our entire grid and society.”
“While large-scale solar projects are important, they are often facing multiyear delays in the PJM interconnection queue,” she said. “Local solar, on the other hand, can be rapidly deployed without these delays, addressing our immediate energy needs while giving us breathing room to bring large-scale renewables online.”
To speed up the process, the bill calls for a State Smart Solar Permitting Platform that would automate permitting. It would enhance the ability of a local agency to review permit applications and permit revisions for safety and code compliance. The platform also would enable permitting agencies to release permits and permit revisions for residential solar energy systems, residential energy storage systems and main electric panel upgrades.
The state assembly backed a version of the bill, which goes to the Senate Budget and Appropriations Committee for consideration.
Storage and Geothermal
The Senate committee also backed a bill, S4289, that would authorize the BPU to procure and incentivize transmission-scale energy storage projects capable of storing at least 5 MW and connected with PJM.
Under the bill, the BPU would create an incentive program and then solicit applications for a tranche of projects. At its conclusion, the BPU would evaluate the impact on the sector, and, if needed, launch one or more tranches. The board’s 3-2 vote sent the bill to the Senate Budget and Appropriations Committee.
Bob Gordon, a former BPU commissioner now representing a renewable energy company, argued that storage can save ratepayers money by providing energy to the grid at peak times. With the law in place, he said, New Jersey would have saved $100 million to $200 million in the coming year if the state had 500 MW to 1000 MW of transmission-connected battery storage.
“A state-led competitive-procurement program such as this will put New Jersey on the path to getting resources online and be able to provide the immediate benefits and cost relief for wholesale power costs to New Jersey,” he said.
The committee backed by a 5-0 vote a bill, S4424, that would establish a three-year pilot program to replace aging or leaking natural gas pipelines with geothermal energy infrastructure.
The bill would enable gas utilities to submit plans to the BPU for review of the project size, scope and scale, and the expected benefits. The agency would assess the ratepayer impact and whether the benefits justify the cost.
FERC Chair Mark Christie’s tenure running the commission is coming to an end, as President Donald Trump on June 2 nominated Laura Swett of Vinson & Elkins to replace him.
“I learned this evening from a media inquiry that President Trump has appointed Laura Swett to replace me when my term expires,” Christie posted on X. “I congratulate Laura and wish her the best. I will remain in office for a few weeks after June 30 to help get key orders out.”
Christie’s term ends June 30; if confirmed, and depending on when she is sworn in, Swett would be able to serve a full five-year term. Another seat remains open since former Chair Willie Phillips stepped down earlier this year, but that term would extend only into 2026. Any new commissioner in that seat effectively would need to be nominated and confirmed twice to serve longer.
Swett’s nomination has been referred to the Senate Energy and Natural Resources Committee. She has previous experience at FERC serving on the staff of Chair Kevin McIntyre and former Commissioner Bernard McNamee, both Trump nominees in his first term. She also worked at the Office of Enforcement, according to her LinkedIn page.
Former FERC Chair Neil Chatterjee, who overlapped with both Swett and Christie on the commission, called the news bittersweet on X.
“I adore Laura Swett and believe she will be an excellent FERC chair (if given the chance by OIRA and OMB),” Chatterjee said, referencing the White House’s Office of Information and Regulatory Affairs and Office of Management and Budget. “But Christie is a patriot; all he did was run the agency well. He’s a veteran who has dedicated his life to serving America. He deserved better.”
The Trump administration has been skeptical of independent agencies generally, reportedly telling Phillips it would fire him if he did not step down, leading to his resignation. Trump issued an executive order in February trying to bring FERC and other similar agencies more under its control. (See Trump Claims Authority over Independent Agencies in Executive Order.)
Christie spent his first press conference as chair addressing that executive order and has repeatedly answered questions on it since. While he put some of it in the context of normal relations between a president and FERC, he also made it clear he had to follow the laws that govern FERC. (See FERC’s Christie Says Existing Policies Can Align with Trump’s Order.)
One area Christie made clear then that FERC could not tolerate was ex parte communications on cases pending before it.
“We do not allow ex parte communications; that would violate the [Government in the] Sunshine Act,” Christie said at the press conference in February. “It would also violate everything I know about due process in contested proceedings going back to being a state regulator. We didn’t allow it in Virginia, so we’re not going to start allowing ex parte communications.”
Reactions
“I think it’s great that Laura has been nominated by the president,” McNamee said in an interview. “I think she’ll do a fantastic job as a commissioner, and I knew that because she provided great and sound advice to me when she was my attorney adviser, when I was a commissioner.”
Swett advised McNamee on pipeline issues when she was his staffer, and much of her work at Vinson was in that area.
The issue of environmental assessment in pipeline permitting has caused some partisan splits among commissioners in the past decade, especially around how much attention FERC must pay to the downstream greenhouse gas emissions.
Former Chair Richard Glick’s efforts to update the pipeline approval process after some losses in the courts wound up sinking his renomination in 2022, but a recent Supreme Court decision means those debates likely are coming to an end regardless of FERC’s composition.
In Seven County Infrastructure Coalition v. Eagle County, issued May 29, the majority found that the U.S. Surface Transportation Board was right to not consider upstream and downstream effects from approving oil shipments over rail. In a post on X, Christie called the decision “the most important permitting reform in decades.”
Trade associations and other groups active before FERC released statements on June 3 congratulating Swett for the nomination.
Americans for a Clean Energy Grid Executive Director Christina Hayes offered congratulations in a statement and argued for continued action on transmission.
“In her previous stints as a senior leader at FERC, she worked on policies that emphasized grid reliability,” Hayes said. “At a time when American energy demand is set to skyrocket, no policy area is as essential to our energy dominance as transmission planning reform. ACEG’s coalition of transmission policy advocates across the political spectrum looks forward to working with Swett in her new role and urges continued FERC leadership in implementing the bipartisan consensus behind Order No. 1920. America’s energy dominance depends on it.”
In addition to congratulating Swett, Electricity Customer Alliance Executive Director Jeff Dennis thanked Christie for his service and for keeping reliability at the top of FERC’s priorities.
“We look forward to working with her and the rest of the commission to advance customer-centric solutions that support the power system expansion our nation needs to meet the demands of a growing digital economy while keeping energy affordable for all customers,” Dennis said.
Electricity cooperatives, independent power producers and biogas generators have asked IESO to reconsider key components of its proposed Local Generation Program, calling for longer contract terms and special consideration for some generation types.
Twenty-two organizations weighed in with written comments last month on the LGP, which is intended to retain local generation resources whose existing contracts are nearing expiration and provide additional capacity to meet rising demand.
IESO has contracts with about 2,500 facilities with installed capacities between 100 kW and 10 MW. Over the next decade, about 1,600 of the contracts — representing 2,000 of the total 3,300 MW of capacity — will expire. IESO forecasts Ontario’s electricity demand will increase by 75% by 2050 as a result of electrification and industrial and data center growth.
The grid operator says smaller, distribution-connected generation can be built more quickly than large-scale projects and help meet local demand, freeing up transmission capacity.
Generation sources of 100 kW to 10 MW would be eligible to participate in either the re-contracting stream, with proposed five-year contracts, or the new build program, for which IESO is proposing 20-year contracts.
Jonathan Scratch, IESO senior manager of market and system adequacy, said during a webinar in April that the grid operator hopes to sign new contracts with “the lowest-cost 80%” of facilities with target quantities reflecting provincial, local and regional energy needs. “[To be determined] on whether there would be price caps,” he said.
In selecting new projects, the grid operator said it also may weigh policy considerations such as economic participation in the project by an indigenous community and municipal and local distribution company support.
Contract Term
IESO proposed that generators be eligible to seek new contracts if their existing contracts are expiring within five years, making facilities with contracts expiring before 2031 eligible to bid during the 2026 application period.
It proposed five-year terms on renewed contracts, identical to its medium-term procurement program, which it runs every two to three years, as needed.
That is too short for some.
“Where a facility is being recontracted without any refurbishments, upgrades or expansions, the five-year term length proposed is sufficient,” wrote Community Energy Co-operatives Canada (CECC). “However, where any refurbishments, upgrades or expansions are undertaken, the term length of five years will not be sufficient to recoup those costs.”
The Canadian Biogas Association said the recontracting term should be 15 to 20 years to provide sufficient certainty to invest in maintenance and secure feedstock agreements.
Biogas is a renewable source of methane gas produced when organic matter breaks down without oxygen. | Canadian Biogas Association
Twenty of Ontario’s 56 biogas facilities between 100 kW and 10 MW, totaling 79 MW, are seeking new contracts as soon as 2030. Most facilities are 250 kW to 1 MW, according to the group.
“A short-term contract, paired with frequent participating in competitive procurements, creates too much pricing and uncertainty risk for biogas developers,” it said. “Our industry and facility owners (many of whom are small-scale local farmers) will require a longer contract to ensure greater price stability and certainty for a longer term.
“For many facilities, the expiration of current contracts coincides with the end of their engines’ useful life. As a result, significant capital investments in upgrades or replacements may be required,” it added. “If the program does not provide sufficient value, permanent shutdowns may become necessary for some operators.”
The association also said smaller facilities will be at a competitive disadvantage versus larger projects using different technologies that can offer lower prices.
Independent power producer Capstone Infrastructure also called for lengthier contracts. It suggested suppliers be granted the flexibility to select a preferred contract length — with up to 30 years for new builds — which it said would produce lower-cost bids through better financing terms. “We are seeing other regions offer longer-term contracts, and this would align with where the industry is heading,” it said.
Standard Offer vs. Competitive Bidding
Power cooperatives and clean energy advocates also called for the use of standard offer contracts rather than competitive bidding.
The Ontario Clean Air Alliance said it favors competitive bidding for large generation projects. “But … IESO’s proposed LGP competitive bidding process for small power projects does not make sense, since it will impose onerous costs on participants and create unnecessary uncertainty as to whether their projects will be funded,” it said. “Instead of discouraging participation by creating needless red tape, the IESO should establish a fair market value standard offer price(s) for small-scale generation projects. All projects that are willing to accept the fair market value standard offer price(s) should be awarded contracts.”
IESO officials said they attempted to make the application less onerous for cooperatives.
“It sounds simple,” IESO’s Scratch said of the standard offer alternative. “It’s inherently not simple to make an assessment of what the right price is. … So, cognizant of that, we’ve set this up as simplified application process and … the dollar-per-megawatt-hour rate.”
Technology Agnostic
IESO’s proposal that new build procurements be technology agnostic drew mixed reaction, winning support from the Ontario Waterpower Association, which represents the hydropower industry, but opposition from the Canadian Biogas Association.
The biogas group said IESO should conduct technology-specific procurements to acknowledge “the unique operational characteristics, value propositions and cost structures associated with different generation technologies.”
“Biogas projects, in particular, provide distinct and system-critical benefits that are often undervalued in competitive procurement processes when assessed alongside technologies with inherently different generation profiles, cost structures and system services (e.g., solar PV or small hydro). These benefits include: firm, dispatchable generation with high reliability; waste-to-energy capabilities that contribute to circular economy goals and emissions reductions; local environmental and economic co-benefits, such as reduced methane emissions from organic waste and support for agricultural and industrial sectors; and baseload or peak-shaving potential, enhancing grid stability and reducing curtailment risks for intermittent renewables.”
Capstone called for “bucketing” generation sources by technology types, to acknowledge those with capabilities such as peaking support, and by region, to reflect higher site costs in urban areas. “This will support reliability where it is often needed most,” it said.
The CHP Canadian Advisory Network said the projects IESO is seeking to re-contract originally were contracted through a program that was not technology agnostic, “which therefore makes it difficult to re-contract in a technology-agnostic manner.”
“For example, [combined heat and power] offers unique value (grid resiliency, improved overall system efficiency, etc.), which may come at a higher price,” it said.
It also requested the grid operator add a natural gas price hedging mechanism or “a more equitable sharing of risks, enabling more competitive bidding.”
The Ontario Clean Air Alliance countered that fossil fuel generation should be excluded from the program, noting that more than 70% of the gas used in Ontario power generation is imported from the U.S.
IESO’s 2025 Annual Planning Outlook predicts fossil gas will generate 25% of the province’s electricity in 2030, up from 4% in 2017. “It doesn’t make sense to increase our dependence on American gas when Canada’s sovereignty and economy are under attack by President Trump,” it said.
LDCs vs. Cooperatives: Transparency, Weighing Local Benefits
Another fault line is the role of LDCs.
CECC said the program should “reward meaningful community and indigenous ownership where genuine community equity and governance are embedded (while avoiding LDCs and private developers creating nominal co-ops or token partnerships solely for preferential treatment).”
IESO programs strategist Greg Bonser said the grid operator is “exploring” criteria other than price, “but we haven’t decided what those rated criteria might be at this point. For example, we might need to use them for tie breaking.”
The Electricity Distributors Association and Ontario Energy Association said LDCs “should lead re-contracting and new contracting.”
“The EDA and OEA believe that Ontario’s local distribution companies are best positioned to lead both re-contracting of existing distributed generation and the contracting of new DG resources,” they wrote. “LDCs have deep visibility into the local value of existing assets within their distribution networks and can engage directly with facility owners on key issues such as refurbishment needs, term lengths and future operational plans.”
CECC countered that its members’ ability to design new projects is hamstrung because they “mostly do not know if their connection points or local circuits could support an expansion or upgrade.”
“The IESO must work with LDCs to publish real-time or forecasted hosting capacity tools and ensure transparent, fair allocation mechanisms when multiple proponents seek access to the same line. Another suggestion is to establish standardized interconnection cost ranges across the province based on project size,” it said. “This would give community proponents clearer upfront cost expectations, reduce risk and uncertainty, and enable more predictable financial planning.”
Roles for Storage, Rooftop Solar, Virtual Net Metering
IESO also received appeals to expand the LGP program to include storage and smaller facilities such as rooftop solar.
Currently, new rooftop solar generation facilities between 1 kW and 1 MW are eligible for incentives through IESO’s electricity Demand-Side Management (eDSM) programs.
Improved technology could result in increased solar production from existing sites. “Given the realized and anticipated increases in the efficiency of solar panels, it is anticipated that we would plan to explore increases in generation capacity at all sites, even where rooftop size or land area constraints exist,” Community Energy Development (CED) Cooperative said in its written comments.
More efficient solar panels mean facilities can increase their output when they renew their contracts with IESO. But critics say the ISO’s proposed procurement policy may mean some facilities cannot afford to renew. | Shutterstock
But many rooftop solar installations have been in place for nearly two decades, meaning the roofs may need repairs or replacement, adding costs to any re-contracting.
Bonser said the LGP would not offer additional compensation for storage or demand response. “However, if you can cost-effectively integrate those elements into your projects, you may be able to do so,” he said.
The Ontario Clean Air Alliance said “all environmentally responsible renewable energy projects,” including rooftop solar, should be eligible for the LGP, citing its study that found rooftop solar projects in Toronto could meet 50 to 80% of the city’s electricity needs.
CECC said IESO’s SaveOnEnergy program does not provide enough financial support for re-contracting solar facilities. It also said community-scale battery energy storage systems (BESS) should be included in the LGP.
“Cooperative ownership ensures that the benefits of storage — including grid services and cost savings — flow back to communities. This scale of storage is well suited for municipal feeders and can play a pivotal role in supporting local energy reliability projects (LERPs) and reducing the need for large-scale infrastructure upgrades, e.g. transmission lines. Bid evaluation should account for both location and time of generation and the advantages of community-scale BESS paired with solar can deliver.”
John Kirkwood, president of the Ottawa Renewable Energy Cooperative, said co-ops have had difficulty deploying storage because community-scale batteries are too small for participation in IESO “and LDCs can’t contract [with] us.”
“Batteries are part of the solution — we all know that — but it’s not very easy to add them to the grid,” he said.
Kirkwood also urged the grid operator to allow it to aggregate generation from its more than 1,100 members, many of which now have microFIT (feed-in tariff) contracts on individual meters, “which is challenging and costly for the province.”
“We’re willing to take it into consideration,” Bonser responded. “We want to make sure this program is as simple and cost effective as possible for all of the different parties involved, from suppliers such as yourself, who have members, for the LDCs and for the ISO. So, there are a few competing interests.”
Kirkwood and other cooperative representatives also called for co-ops to engage in virtual net metering, which would allow members to purchase electricity directly from cooperatively owned projects, even if they are not located on-site.
Allowing cooperative-owned projects to transition into community net-metering structures at the end of the current contract would allow them to continue, said CED Co-op, which has more than 100 FIT and microFIT contracts.
“If there are no reasonable contracting options available upon conclusion of the current contract, we would likely need to decommission the facility,” it said. “The current spot market rates do not appear that they would adequately exceed the costs of insurance, LDC fees, lease payments, and operations and maintenance expenses.”
Next Steps
IESO expects to report back to the Minister of Energy and Electrification on the LGP this summer and launch the program in 2026.
The grid operator will provide its responses to stakeholders’ feedback and present more details about the program designs in a webinar June 5.
The U.S. Department of Energy has issued an emergency order to keep Constellation Energy’s Eddystone Units 3 and 4, located outside Philadelphia, online under Section 202(c) of the Federal Power Act. The order directs Constellation and PJM to keep the units available for dispatch through Aug. 28.
The order states that retaining the two gas-fired generators, with a combined output of 760 MW, is necessary to prevent emergency conditions in PJM “due to a shortage of facilities for the generation of electric energy, resource adequacy concerns and other causes.”
“Maintaining access to affordable, reliable and secure power is always our top priority, particularly during the summer months when electricity demand reaches its peak,” U.S. Secretary of Energy Chris Wright said in a May 31 announcement of the order. The generators were scheduled to be retired that day.
The order cited PJM CEO Manu Asthana’s March congressional testimony that reliability is challenged by a combination of government policies prompting generation deactivations, data center load growth and an interconnection queue composed mostly of non-dispatchable generation. It also pointed to PJM’s February 2023 “Energy Transition in PJM: Resource Retirements, Replacements & Risks” position paper, which found the RTO could face a capacity shortfall in 2030. (See PJM Whitepaper to Highlight Future RA Concerns.)
PJM voiced its support for the emergency order in a May 31 statement, in which it calls the order a “prudent, time-limited step” that will allow the department, RTO and Constellation to further analyze whether there is a long-term need to retain the Eddystone generators.
“For over two years, PJM has repeatedly documented and voiced its concerns over the growing risk of a supply-and-demand imbalance driven by the confluence of generator retirements and demand growth. Such an imbalance could have serious ramifications for reliability and affordability for consumers,” PJM said.
In its 2025 Summer Outlook, PJM stated it could fall short of peak loads under an “extreme planning scenario,” requiring the deployment of demand response and increased risk of emergency procedures. The extreme scenario looks at maintaining PJM’s reserve requirement under a 90/10 peak load, which is set at 166.6 GW for summer 2025, whereas the Operations Assessment Task Force’s report focuses on the ability to reliably serve the 50/50 forecast peak of 161 GW. The latter report did not identify any reliability violations in the summer. (See “Summer Outlook Finds Possible Reserve Shortage,” PJM OC Briefs: May 8, 2025.)
Constellation requested PJM authorization to bring Eddystone offline on Dec. 1, 2023, on the grounds that “continued operation of these units is expected to be uneconomic.” PJM responded a year later that it found no transmission reliability violations associated with the deactivation, clearing Constellation to retire the units on May 31, 2025.
“Constellation is pleased to work with the Department of Energy and PJM and is taking emergency measures to meet the need for power at this critical time when America must win the AI race,” the company said in an emailed statement. “Constellation is taking immediate steps to continue to operate Eddystone Units 3 and 4 throughout the summer.”
PJM spokesperson Jeff Shields told RTO Insider that PJM does not hold the authority to require generation owners to continue operating when needed for resource adequacy.
“We can only request reliability-must-run to provide us enough time to build transmission to address system issues that will be created by the removal of the resource from the grid. It is not meant for resource adequacy; we can’t ask an owner to continue to run based on current supply/demand challenges,” he said.
The order directs PJM to submit the steps it’s taking to ensure Eddystone remains available by June 15, as well as to provide information as requested about the environmental impact of the order. Both the RTO and Constellation also are directed to file with FERC any necessary tariff revisions or waivers.
Noting that when Section 202(c) emergency orders may conflict with environmental standards, generation run hours should be limited to hours needed to resolve the emergency, the order limits dispatch to “the times and within the parameters determined by PJM for reliability purposes.”
“To minimize adverse environmental impacts, this order limits operation of dispatched units through the expiration of the order. PJM shall provide a daily notification to the department reporting whether the Eddystone Units have operated in compliance with the allowances contained in this order,” it continues.
DOE is developing a methodology “to identify current and anticipated reserve margins for all regions of the bulk-power system” regulated by FERC. The EO “requires this methodology to be published by July 7, 2025, and be used to establish a protocol to identify which generation resources within a region are critical to system reliability and prevent identified generation resources from leaving the bulk-power system.”
Earlier in May, DOE issued another emergency order to keep Consumers Energy’s 1,560-MW J.H. Campbell coal plant in West Olive, Mich., operational beyond its May 31 retirement. The company entered into an agreement with the Michigan Public Service Commission to stop burning coal by the end of 2025. (See DOE Orders Michigan Coal Plant to Reverse Retirement.)
Environmental Organizations Object to Emergency Order
The NRDC wrote that the orders in PJM and MISO are part of a larger effort to promote fossil fuel generation at the expense of impacts to health and consumer rates.
“The Department of Energy’s move to keep these zombie plants online will have significant public health impacts and increase electricity costs for people in Michigan and Pennsylvania,” said Kit Kennedy, power sector managing director at NRDC. “These orders are about a power grab, not a power emergency. These dirty and expensive fossil plants were slated to close because they could not compete with cheaper, cleaner alternatives.”
President Donald Trump issued four executive orders on nuclear power in late May, bizarrely bragging that this number of executive orders is twice the number of new nuclear plants started in the U.S. since 1978.
Say what? We haven’t built new nuclear plants over the past 50 years (other than the Vogtle disaster) because they haven’t made any economic sense, as I discussed years ago.
One of his executive orders directs a program for installing nuclear reactors at critical defense facilities, based on the claim that nuclear reactors can deliver resilient, reliable power to these facilities.
Trump’s claim is wrong and misleading for many reasons.
Reason No. 1: Nuclear reactors cannot provide resilient, reliable power to defense facilities. As FERC has observed, in the event of an outage on the grid the nuclear reactor has to shut down and cannot restart until grid power is restored (page 44).
Steve Huntoon
And as 41 transmission owners in PJMrecently said to FERC: “Further, load that is co-located with a nuclear unit depends on services such as load following, voltage support, black start and other ancillary services that will be and can only be delivered over the grid. Nuclear units cannot move their output up and down from moment to moment to match variations in the load, and because the nuclear units cannot provide these services, they must instead be provided through connection to the grid” (page 13). Thus, nuclear reactors would contribute 0.0 reliability value to critical defense facilities.
Reason No. 2: Critical defense facilities already have backup power, generally on-site diesel generators. Thus, nuclear reactors would be superfluous.
Reason No. 3: A total of 87% of defense facility outages are due to problems on the distribution systems inside the bases. Thus, a nuclear reactor outside a base would provide 0.0 reliability value relative to such outages.
Reason No. 4: Nuclear reactors have lengthy refueling outages and obviously couldn’t provide power during such outages.
Reason No. 5: If nuclear is to have any hope of commercial viability — which it doesn’t have for reasons I’ve given —then it has to achieve economies of scale through modular production. Since every defense facility has its own unique power needs, that means every nuclear reactor for a given defense facility would need to be unique, thus defeating the only conceivable purpose of having taxpayers subsidize this Trump program.
Defense facilities are only one aspect of Trump’s four executive orders, which collectively are intended to increase the U.S. nuclear fleet from today’s 100 GW to 400 GW by 2050.
What’s that going to cost us? If we take the Ontario SMR cost per reactor (excluding the most expensive first unit) of $3.5 billion, optimistically assume no cost overruns, and divide by the SMR capacity of 300 MW, we get $11.5 million/MW. If we plug that capital cost into the Lazard capital cost range, it interpolates to $181/MWh in the levelized cost of energy range (page 38).
That is an excess of $143/MWh over the $38/MWh average cost of generation in PJM (Figure 3, transmission costs excluded). At nuclear’s 90% capacity factor, Trump’s 300 GW would translate to 2.6 million GWh/year, or 2.4 billion MWh/year, and thus into excessive costs of $343 billion/year for the U.S. overall, and an average excessive cost of $1,000/year for each of us. Please note that this would be a total “own goal” relative to the U.S. Energy Information Administration’s base case for 2050, which has nuclear output and electric customer costs essentially unchanged from today.
Simply put, Trump’s extra 300 GW of nuclear means each of us, as taxpayer or electric consumer or both, would lose $1,000 every year.
Now that is one Big (Not So) Beautiful Bill!
Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years.
“The last several Summer Reliability Assessments from [NERC], including this year’s, continue to demonstrate resource adequacy risks facing the power system given hotter summers, load growth and an aging generation fleet,” said co-author Adria Brooks, director of transmission planning for Grid Strategies. “This report demonstrates yet another benefit of interregional transmission, adding to a growing list of reliability and cost benefits. We have to stop ignoring the value of interregional transmission and instead create mechanisms to build it.”
Interregional transmission offers value because different regions have different resource mixes and their peak demand is often at different times, the report says.
“Interregional transmission allows capacity resources to be shared between regions with noncoincident demand,” the report says. “The interregional transmission assets themselves tend to be available nearly 100% of the time. Consumers benefit from this sharing of reserves, both in terms of improved reliability and reduced costs. These reliability and economic benefits are heightened during grid stress events.”
To move forward with more interregional transmission investment, the industry will need to integrate capacity value into its resource adequacy assessments, which can be calculated using standard industry methods such as effective load-carrying capacity (ELCC).
“ELCC considers the difference in loss-of-load expectation (LOLE) — or any other RA metric — for the system with and without the supply resource and calculates how much additional load the resource can serve to return the system to the standard LOLE baseline of one day in 10 years,” the report says. “This method has been successfully applied in several recent transmission facility or resource adequacy studies to derive the capacity value of several interregional transmission lines both in the United States and abroad.”
System planners historically have not calculated the LOLE reduction from an individual transmission line and converted it to a capacity value. But most have calculated the cut in LOLE associated with the current fleet of interregional lines, which is called “external assistance,” “tie benefits” and “firm and non-firm imports” in different regions.
Without a benefit that load-serving entities can credit to their resource adequacy obligations that indirectly provides value to transmission developers, or direct payments to transmission for its resource adequacy contributions, the industry will have fewer incentives to build interregional lines. The valuation and compensation can be done for either fully regulated transmission or merchant lines.
The report argues that considering the benefits of lower planning reserve margins from interregional lines will not worsen reliability; it would represent a cut in the amount of capacity needed to maintain resource adequacy. Those benefits can even come from non-firm imports, with grid planners using a probabilistic treatment of available imports to avoid overcounting such resources.
“All regions we surveyed include firm imports from neighbors in their resource adequacy assessments, but only a handful also consider the contribution of non-firm imports,” the report says. “Those that do incorporate non-firm imports rarely accredit the interregional transmission [that] enables non-firm imports with a capacity value for their contribution to resource adequacy.”
Non-firm imports are a way to quantify the “net load diversity” between regions, such as when one region faces a shortage but its neighbor has excess supply.
“Non-firm imports are a vital resource to the system, allowing operators to keep customers’ lights on even when there are no more internal resources to call on for support,” the report says. “However, these imports are not consistently incorporated into resource adequacy assessments. This omission may result in the over-procurement of capacity resources internal to the planning region to meet the planning reserve requirement, raising costs for ratepayers.”
At the simplest level, planners can look at historic imports to determine how many non-firm imports can be included in LOLE studies. Doing that seasonally, or only during tight-capacity periods, provides more confidence that external support will be available in the future.
SERC Reliability expects above-average temperatures to drive higher demand this summer, and registered entities should have the resources to meet demand under normal operating conditions, the regional entity said in its 2025 Summer Reliability Assessment.
However, SERC also warned that some areas do face a risk of shortfalls should weather conditions become more extreme.
SERC published the SRA on May 29 as a supplement to NERC’s 2025 summer assessment, in which the ERO warned that multiple subregions across North America showed a potential for insufficient operating reserves in above-normal conditions. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.) NERC identified rising demand and the retirement of traditional generation resources as primary contributors to the risk in the summer season, which for both assessments runs from June to September.
SERC’s assessment noted that extreme weather continues to be a major concern for the region, which “contains those areas of the U.S. most likely to be in the path of a hurricane, as well as many of the states that are prone to high summer temperatures.” The RE included data from EPA showing that the frequency, intensity and duration of heat waves in major U.S. cities have all steadily increased since 1961, while the average length of heat wave seasons has lengthened from just over 20 days in the 1960s to 70 days in the 2020s.
“Hotter summer temperatures cause increased demand due to heightened use of commercial and residential air conditioning,” SERC said. “Simultaneously, hotter temperatures can reduce the generation capacity and efficiency of thermal generation units and reduce air density, which decreases the capability of wind turbines. … Extreme heat along with high demand can overwhelm the transmission lines and cause them to sag and touch trees or other objects, which can potentially lead to outages.”
Despite the growing threat of extreme heat, SERC said all of its subregions have enough resources to meet NERC’s recommended 15% reserve margin target under the 50/50 load forecast, which represents a 50% chance that the actual peak load will be higher or lower than the prediction. This prediction held for most areas even under the 90/10 forecast, in which there is a 10% chance that peak load will be higher than expected.
Charts included in SERC’s SRA, based on EPA data, on the frequency, duration and intensity of heat waves in major U.S. cities, along with the length of heat wave season, since the 1960s. | SERC
The one exception was the Central subregion, covering all or parts of Alabama, Georgia, Iowa, Kentucky, Mississippi, Missouri, North Carolina, Oklahoma, Tennessee and Virginia. Its predicted reserve margin was 19% under the 50/50 forecast, but 9% under the 90/10, putting it into the “elevated risk” category.
Natural gas generation constituted the largest share of SERC Central’s summer on-peak generation mix, with 19.7 GW, or 41% of the total generation fleet; coal was next at 12.7 GW (27%); followed by nuclear at 8.2 GW (17%). For comparison, in SERC’s overall footprint, gas accounted for 49% of the nearly 324 GW on-peak generation capacity, with coal at 18% and nuclear at 13%.
The report observed solar generation still is increasing across the SERC region, with 30 GW of on-peak solar capacity expected to be online by this summer, up 7 GW from summer 2024. This growth has driven operators to rely on natural gas to balance the weather dependence of solar generation.
However, SERC noted that “while [gas] generators are capable of quickly ramping up and down to provide ‘load following’ service as necessary, this is only possible if they have access to the full amount of natural gas commodity needed for the periods for which they are dispatched.”
The RE mentioned that one registered entity said, “If operational flow orders (OFO) were issued on the pipelines serving its generating units, the OFOs would require the units to maintain the day-ahead planned fuel usage.” This could prevent operators from redispatching the affected gas units to handle transmission line loading issues.
SERC recommended that reliability coordinators, balancing authorities and transmission operators review their seasonal operating plans with a focus on communication and resolution of potential supply shortfalls during periods of extreme demand. The RE also said utilities should ensure resource availability through conservative generation and transmission outage coordination procedures, and state and provincial regulators should prepare to implement demand-side management mechanisms.
The Nuclear Regulatory Commission has determined there would be no significant environmental impact from restarting the Palisades Nuclear Plant in Michigan.
The NRC decision issued May 30 reaches the same conclusion as its draft decision Jan. 31.
The 800-MW facility in Covert Township formerly operated by Entergy went offline in May 2022 in preparation for decommissioning, but barely a year later, new owner Holtec International began to float the idea of bringing it back into service.
No commercial reactor in the United States has been restarted in such a scenario, although Constellation is working toward that goal with the former Three Mile Island Unit 1, which shut down in 2019, and NextEra has filed notice with the NRC about potentially restarting the Duane Arnold Energy Center, which ceased operations in 2020.
The NRC issued the environmental assessment of the Palisades proposal in cooperation with the U.S. Department of Energy’s Loan Programs Office, which in September 2024 extended a $1.52 billion loan guarantee to Holtec to help financed the effort.
More recently, in March, DOE approved disbursement of $56.8 million for that purpose — a relatively small sum, but notable amid the wholesale slashing under way at the time as the new Trump administration took aim at the clean energy priorities of the Biden administration.
In the determination issued May 30, NRC said restarting Palisades would provide baseload power to meet current system needs. Holtec also noted it would help Michigan reach its targets of at least 80% clean energy by 2035 and 100% by 2040.
NRC said it considered 11 potential direct or indirect environmental impacts from a restart and determined none would be significant. It also determined there are no environmentally preferable alternatives to restarting Palisades.
In an April update, Holtec said the project remains on schedule and on budget. As it refurbishes the physical plant, it is rebuilding its workforce: Staffing has rebounded from a low of 220 to 570, 26 plant operators have requalified, and the first initial operator class was on track to complete their license exams this month.
Also, FERC approved Holtec’s waiver request to maintain the grid interconnection, which was suspended after the plant shut down and otherwise would have been sunsetted.
NYISO and its stakeholders continue to consider different designs as part of their Capacity Market Structure Review, but one idea should be dismissed, according to the Market Monitoring Unit and FTI Consulting: bifurcated pricing.
Though all RTOs with capacity markets may be concerned with their effectiveness in maintaining resource adequacy, NYISO is perhaps more unique in that, according to the MMU, new investment in generation primarily is driven by New York state procurements. In a market based on the net cost of new entry, stakeholders are concerned this could lead to keeping older, more inefficient resources longer than necessary and at a higher cost to consumers. (See NYISO Stakeholders Debate Purpose of Capacity Market.)
A bifurcated — or “discriminatory” — market would have two separate demand prices: one for existing resources and one for new entries to the market. According to NYISO consultant FTI, such markets can result in short-term reductions in costs to consumers, but “in the longer run, as more existing capacity inefficiently exits as a result of the artificially low capacity price and is replaced with high-cost new capacity, the short-run consumer savings will tend to turn into higher costs for future consumers.”
“From a social welfare standpoint, all of this is inefficient,” FTI’s Scott Harvey said in the middle of his presentation to the Installed Capacity Market Working Group on May 22. “It’s going to reduce social welfare because unless we do the price discrimination perfectly, we’re going to shut down some existing capacity that’s got lower cost than new capacity, and that reduces social welfare.”
Biasing the market toward new capacity also incentivizes the construction of short-lived assets because they will make less money as they age, even if initially they are higher cost, he said.
Balancing the market such that it retains enough units to meet reliability needs while incentivizing new entry and economic exit is tricky, Harvey acknowledged, especially amid low reserve margins.
FTI offered several approaches to a bifurcated market: holding a two-stage auction with separate supply curves but a single demand curve, with a lower price cap for existing capacity; a single-stage auction with a single supply curve but separate demand curves; and a two-stage auction with both supply and demand curves completely separated. Each construct, however, had its own drawbacks under certain circumstances, according to FTI’s presentation.
“If you are close to the edge already on reliability, then shutting down existing capacity will have a larger impact,” Harvey said. “Anything that drives up the cost of new capacity and less [generation] comes in than you expected is going to have an impact. If some of the existing capacity is already shut down by the time you realize the new capacity isn’t going to show up, you’re going to have problems.”
FTI noted that the natural gas market was bifurcated by the Natural Gas Policy Act of 1978, but this ultimately resulted in inflated, high prices, and by 1989, the law was repealed.
Potomac Economics’ Joe Coscia presented the MMU’s quantitative model using multiple scenarios showing that price discrimination between new and old units would lead to both “inefficient behavior” and higher investment costs.
Capacity prices also rise relative to status quo, and capacity surpluses decrease.
“That’s a result of the early retirement of existing resources or inability to attract imports and firm gas instead of replacing it with more expensive new capacity,” Coscia said.
He said the MMU’s results pointed toward the advantages of uniform clearing prices based on cost of new entry, even when there isn’t much investment in the peaking technology.
