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December 13, 2025

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MISO Could Replace Up to 3 Board Members by Year End

MISO might replace up to three members on its board of directors as they reach term limits at the end of 2025.  

Board members Todd Raba, H.B. “Trip” Doggett and Barbara Krumsiek are to conclude their third and final terms at the end of 2025. Though they’re term-limited, all have expressed interest in serving a maximum fourth term that is allowable through a special waiver of MISO’s rules. (See Extensions Likely for MISO’s Term-limited Board Members.)  

MISO’s Nominating Committee has said it may decide to use the waiver provision for one or two directors to retain members’ expertise and prevent too much board turnover from one year to the next.  

During an Aug. 13 MISO Advisory Committee teleconference, Nominating Committee member Brian Drumm, of ITC, said Chicago-based search firm Russell Reynolds Associates in the spring presented 20 external board candidates. The Nominating Committee first narrowed that slate down to seven external candidates to be considered alongside the three incumbent directors. Drumm said that after interviewing the three incumbents and seven external candidates in July, the Nominating Committee has assembled a slate of two director candidates for each of the three open Board positions. He declined to comment during the meeting on whether the Nominating Committee is recommending any waivers at all.

Drumm said some MISO members have opposed use of the waiver or have said one to two waivers are necessary to avoid excessive board member attrition. Drumm said MISO’s potential use of waivers and names of outside candidates remain confidential. He said stakeholders would learn more during MISO Board Week in mid-September in Detroit.  

MISO Board Chair Raba said in June that MISO’s Nominating Committee had a lot of work ahead of it to make decisions on who might stay to serve a fourth and final three-year term and how many fresh faces could earn a spot on the board.  

The Nominating Committee is charged with vetting and selecting MISO Board of Director candidates, who are put to a vote of membership. The committee’s members change annually, and the committee is composed of three MISO board members and two MISO stakeholders, one of whom typically is from a state public service commission. This year, directors Bob Lurie, Jeff Lemmer and Nancy Lange sit on the Nominating Committee alongside Drumm and Illinois regulator Michael Carrigan.  

Elections for MISO’s Board of Directors are held in the fall, with the Nominating Committee advancing one candidate per open seat. MISO members vote electronically on whether they support the candidate. MISO’s board elections require candidates to earn a majority of votes in support among membership. MISO members can vote for or against or abstain from selecting any of the candidates. The elections require a minimum 25% participation rate among the voting-eligible members of MISO’s 197 members to achieve a quorum. 

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Trump Officially Names Rosner, a Democratic Appointee, FERC Chair

President Donald Trump made it official Aug. 13, naming David Rosner as the new chair of FERC several workdays after former Chair Mark Christie resigned. 

“I am honored to serve as chairman and excited to continue working with my colleagues on the commission and FERC’s extraordinary staff to enable reliable, affordable and abundant energy for all Americans,” Rosner said in a statement. “Energy lights our homes, powers our businesses, and we need it more than ever to grow the innovative industries of the future.” 

Trump picking a Democratic nominee to run the agency over a well-qualified Republican, Commissioner Lindsay See, was a surprise. (See FERC Independence Likely Coming to an End with Christie’s Exit.) 

But the position could be interim, as two nominees from the president are awaiting Senate confirmation sometime after that body returns from a summer break. Laura Swett is widely reported to be in line for the chair. Like Rosner before he was elevated to the commission, she is a former FERC staffer — having worked for former Chair Kevin McIntyre and former Commissioner Bernard McNamee. 

Rosner has been a commissioner since June 2024 and brings two decades of experience to the job across energy technologies, market design and energy policy issues. He was an energy industry analyst for FERC and spent two years on detail to the Senate Energy and Natural Resources Committee, where former Sen. Joe Manchin (I-W.Va.) became a big supporter for his nomination as commissioner. 

Before coming to FERC, Rosner was a senior policy adviser for the Department of Energy’s Office of Energy Policy and Systems Analysis and was an associate director at the Bipartisan Policy Center’s energy project. 

Rosner earned master’s degrees in economics and public policy from American University and a bachelor’s in economics from Tufts University. He lives in the D.C. area with his family. 

NERC was quick to congratulate Rosner. 

“Chairman Rosner has been a strong voice supporting abundant and reliable electricity to serve the nation’​s growing energy needs,” the ERO said. “We look forward to continued work with Chairman Rosner on advancing the reliability and security of the electric grid.​” 

Other congratulations came through on social media, with McNamee posting on X that Rosner “will do a great job.” 

WIRES Group Executive Director Larry Gasteiger posted congratulations on X, saying the trade group “looks forward to working with you and your colleagues on getting the energy infrastructure built to meet the nation’s growing needs.” 

Coal power trade group America’s Power welcomed Rosner being named chair with a statement from CEO Michelle Bloodworth. 

“Chairman Rosner is an experienced policymaker with the skills, knowledge and open mindedness necessary to assure that FERC continues its work to improve the reliability of our nation’s electricity grid,” she said.

Meanwhile, the environmental group Friends of the Earth said that “a close review of Rosner’s work reveals a disturbing pattern of dirty energy advocacy.”

“Rosner has promoted the gas and the fossil fuel industry for years and is far too biased to hold this position,” said Raena Garcia, senior climate campaigner at Friends of the Earth. “Democrats who care about the climate should reject him out of hand.”

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BPA Supported by Trade Orgs in Suit over Day-ahead Market Decision

Trade organizations for utilities and large energy consumers seek to intervene in the lawsuit filed in the 9th Circuit Court of Appeals challenging the Bonneville Power Administration’s decision to join SPP’s Markets+ instead of CAISO’s Extended Day-Ahead Market (EDAM).

SPP, Public Power Council (PPC), Alliance of Western Energy Consumers (AWEC), Pacific Northwest Generating Cooperative (PNGC) and Northwest Requirements Utilities (NRU) all filed motions to intervene in late July and early August, citing their members’ “interest” in the lawsuit. (See BPA Sued in 9th Circuit over Day-ahead Market Decision.)

PPC represents the Northwest’s extensive network of publicly owned utilities that make up BPA’s base of “preference” customers. The organization has been a strong supporter of BPA’s day-ahead market decision, saying in its motion to intervene that the case could impact BPA’s transmission services and PPC members.

“PPC intervening in the case is an absolute reflection that a strong majority of Northwest public power supports BPA’s decision and the extensive public process they ran to arrive at the Markets+ outcome,” PPC Executive Director Scott Simms said in an email to RTO Insider.

Simms reiterated arguments that supporters of Markets+ have highlighted throughout BPA’s day-ahead market process, such as the market option’s governance approach and “overall design.” (See BPA Selects SPP Markets+ in Draft Policy.)

“As for the significance of the case, it’s interesting to see just how political the day-ahead markets space has become — evidenced by the named plaintiffs in this case,” Simms added.

The dispute stems from a lawsuit filed on July 10 by NW Energy Coalition, Idaho Conservation League, Montana Environmental Information Center, Oregon Citizens’ Utility Board and the Sierra Club.

Represented by Earthjustice, the group asked the court to review and vacate BPA’s day-ahead market decision. They allege BPA did not consider the environmental impacts and failed to properly assess the purported benefits of CAISO’s EDAM.

According to the suit, the agency now risks increasing costs for customers by not joining EDAM, which the group says has a larger market footprint than Markets+. Additionally, the group claims BPA ignored its obligations to prioritize conservation and renewable power.

The suit brings claims under the National Environmental Policy Act, the Pacific Northwest Electric Power Planning and Conservation Act and the Administrative Procedure Act.

“The participation of these intervenors in the case highlights the importance of this decision by Bonneville, which will have a major impact on the cost of electric power in the Pacific Northwest,” Jaimini Parekh, senior attorney with Earthjustice, said in an email. “That is why we have challenged Bonneville’s decision. State agencies in Washington and Oregon found that had Bonneville made a different decision, and joined EDAM, it could have saved ratepayers billions of dollars.”

‘As Disappointing as it is Unsurprising’

More parties could join the case, as the deadline for intervening is early September. Still, those who have filed petitions so far have done so in support of BPA.

For example, SPP said the plaintiffs’ suit challenges the agency’s decision “to pursue participation in SPP’s Markets+ instead of an alternative day-ahead market preferred by petitioners.”

SPP, which is the operator for Markets+, added that it has “significant interest” in the suit, noting that BPA’s participation “will significantly impact the scope and operation of Markets+.”

NRU, whose 58 utility members buy power from BPA on a preferential basis, has similarly supported the agency in its decision-making process and filed a motion to intervene to defend BPA, NRU Executive Director Zabyn Towner told RTO Insider.

“The fact that a few outside interests are taking legal action to try to force BPA to pursue a day-ahead markets policy that is consistent with their own stated goals is as disappointing as it is unsurprising,” Towner said. “NRU takes serious issue with the plaintiffs’ stated grounds for their challenge and joined the case with the intent to zealously defend BPA, its ability to make decisions in the best interests of public power and the resulting decision to pursue participation in SPP’s Markets+ day-ahead market.”

Bill Gaines, executive director of AWEC, also said Markets+ is preferable for the Pacific Northwest region because of the day-ahead market’s design and because of “governance shortcomings in the CAISO EDAM market that the California legislature has been unwilling to remedy.”

Much of the success of EDAM hinges on a bill in the California legislature that would allow CAISO to relinquish market governance to an independent “regional organization” being established by the West-Wide Governance Pathways Initiative. The bill has been delayed after 21 organizations pulled their support following amendments they found concerning. (See Newsom Reiterates Support for Western Regional Market Push.)

Richard Stover, chief legal officer at PNGC, said BPA’s decision “is very important to PNGC as we enter into new long-term contracts with BPA. On behalf of our members, PNGC intervened to protect its long-term interests and that of its members.”

When asked for a response, BPA said it doesn’t comment on active litigation.

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Nexamp Complains of Unfair IC Cost Increases by National Grid

Community solar developer Nexamp has filed a complaint against National Grid with the New York Public Service Commission accusing the utility of unfair price increases and violating state interconnection process agreements (25-E-0469).

The Boston-based company contested about $3.6 million in additional interconnection costs for 14 projects that it says is a 52% increase over what it originally was quoted by the utility. It asked the PSC to “scrutinize” National Grid’s interconnection practices and policies, alleging widespread impacts across all developers.

“Nexamp anticipates receiving similarly egregious and improper final reconciliation invoices for 41 additional Nexamp-owned solar projects in various stages of development with National Grid,” it said in its complaint, filed Aug. 7.

The company said the cost increases were driven by National Grid’s reliance on external contractors that caused final labor costs to “more than double” over the original estimates. It also said the utility had an “egregious disregard” for the PSC regulations, setting a 60-day deadline for issuing reconciliation invoices.

The projects range from 2.3 to 5 MW, totaling more than 61 MW of solar capacity, and took about three to five years to develop. Most received permission to operate (PTO) in late 2024.

“The projects were all in National Grid’s queue for multiple years prior to PTO, raising legitimate concerns about National Grid’s inability (or neglect) to manage its queue in a manner that would have avoided (or at the very least mitigated) the need to mobilize external contractors at the scale and expense that National Grid claims here,” the company said.

The company also complained that National Grid was using stale material cost data and potentially double charging for taxes.

Nexamp did not respond to a request for comment. A National Grid spokesperson said they would not comment on a pending regulatory complaint. 

Nexamp calls itself the largest community solar developer in the U.S., operating 1 GW of projects nationwide and 400 MW of solar and storage in New York. The company says it has 250 MW of assets under development.

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Advanced Nuclear Fast-track Effort Gets First 11 Projects

The U.S. Department of Energy has chosen 11 advanced nuclear projects as the first tranche of its Nuclear Reactor Pilot Program. 

The program was formed in June, a month after President Donald Trump issued a series of executive orders in an attempt to spur a U.S. nuclear renaissance. One of the orders gave the DOE a direct role in facilitating testing of next-generation nuclear power generation technology. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.) 

DOE said Aug. 12 that it will work with the 10 companies on their 11 projects with the goal of constructing, operating and achieving criticality with at least three reactors by July 4, 2026, on sites outside national laboratories. 

It is a new pathway toward fast-tracking commercial licensing. Trump directed this streamlining in his executive orders, saying over-regulation was stifling progress and was unnecessary, given the nuclear industry’s safety record.  

Skeptics countered that nuclear energy is safe because it is well-regulated, and worried about the effects of speeding the regulatory process on new reactor designs. 

And there are many, many new designs in various stages of development: The Nuclear Energy Agency in July updated its Small Modular Reactor (SMR) Dashboard, analyzing no fewer than 74 SMR designs in progress worldwide. The greatest number of designers —27 — have their headquarters in the United States. 

DOE alluded to this in its Aug. 12 news release, writing: “The diversity of applications received shows the remarkable breadth of innovation and ingenuity in American reactor developers.” 

DOE chose two designs from Oklo for the pilot program and one each from Aalo, Antares Nuclear, Atomic Alchemy, Deep Fission, Last Energy, Natura Resources, Radiant Industries, Terrestrial Energy and Valar Atomics. 

Participation in the pilot program will give them a fast-tracked approach to future commercial licensing. It also may help unlock private funding. Each company is responsible for all costs for designing, manufacturing, constructing, operating and decommissioning their test reactors. 

When it announced the pilot program June 18, DOE said it builds on existing efforts to demonstrate advanced reactors on DOE sites through microreactor test beds and other projects led by the Department of Defense or private industry. It is not, however, designed to demonstrate suitability of reactors for commercial purposes. 

One of the companies that won designation for the pilot program, Aalo, said in an Aug. 12 news release that a key part of the pilot program is cutting red tape. 

Participating companies will be assigned a DOE concierge team to cut through governmental red tape, so that, for example, a developer would wait just days for a sign-off authorization that previously might have taken weeks or months to secure. 

“This is a pivotal moment for advanced nuclear, and we’re proud to be at the forefront,” CEO Matt Loszak wrote. 

The Roster

The companies chosen for the pilot program show the diversity of the advanced nuclear sector as it scrambles to develop safe, affordable, workable and scalable reactor designs and fuel supply chains: 

    • Aalo is developing a sodium-cooled, uranium-dioxide-fueled experimental reactor that will form the basis of its Aalo Pod, a highly modular 50-MWe reactor targeted at the data center industry. 
    • Antares is developing a kilowatt-scale reactor for special purposes including underwater and outer space use. 
    • Deep Fission proposes to build 15-MWe SMRs one mile underground. 
    • Last Energy is developing a 20-MWe micro modular nuclear power plant; the company was in the news earlier in 2025 with a plan to place 30 of them behind the meter at a Texas data center. 
    • Natura Resources is advancing a liquid-fueled, molten salt-cooled reactor that could have multiple end uses beyond power generation, including desalination and hydrogen or steel production. 
    • Oklo is updating existing technology to design liquid metal-cooled fast reactors. 
    • Atomic Alchemy, which Oklo acquired earlier in 2025, is developing a radioisotope supply chain. 
    • Radiant is pursuing mass-produced microreactors that can be transported via truck like a shipping container; this month it announced an agreement to deliver its 1-MW Kaleidos to the Department of Defense in 2028. 
    • Valar Atomics is building a 100-kW TRISO-fueled high-temperature gas reactor — in the Philippines, because of the regulatory burden that the company says the Nuclear Regulatory Commission would place on the effort if carried out in the U.S. 

Valar was in the news earlier in 2025 when it joined a group of states and startup companies in a lawsuit arguing that the NRC should regulate the existing fleet of gigawatt-scale reactors and leave regulation of SMRs to states, because SMRs’ small size is accompanied by small potential risk. 

“Should our suit succeed, Valar Atomics and our colleagues in this industry will provide abundant energy for all mankind,” wrote CEO Isaiah Taylor, the self-taught engineer who founded Valar. 

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Calif. Energy Officials Ponder Interconnection Timelines, Load Uncertainty

California energy officials are recognizing the need to work together to prioritize a long list of transmission and distribution interconnection projects as the state’s load growth accelerates due to expected data center development. 

At an Aug. 11 joint agency workshop, representatives from the California Energy Commission, California Public Utilities Commission, CAISO and other entities discussed how to accelerate interconnection timelines in the Golden State, with conversations focusing on the various types of new load coming online and bringing out-of-state wind power to California’s borders. 

“In a big, complicated state like California … it’s really great to have this platform to do some level setting,” CEC Commissioner Andrew McAllister said at the workshop. 

“I’ve really learned to appreciate the complexity of our roles,” CEC Vice Chair Siva Gunda added. “One of the things we’re dealing with across demand forecasts, whether it’s distribution planning or integrated resource planning, is the uncertainty — the vast uncertainty — in demand, because of electrification, climate impacts and new loads that may come [or] may not come.” 

Gunda asked Neil Millar, CAISO vice president of infrastructure and operations planning, to explain how the ISO is thinking about protecting electricity rates while at the same time future-proofing investments in energy infrastructure and resources. 

“I think the most important part [of this effort] is about the sensitivity work that goes into considering options,” Millar said. “And part of that includes picking options that are always a good first step and not necessarily always … going for the fences with a transmission project.” 

Instead, agencies could focus on picking scalable options because, once a project is a few years down the path, there’s “always a risk that the load growth softens,” Millar said.  

“Then you’re not dependent on some next step in order to achieve the actual benefit of the plan,” Millar said. “Our focus has normally been to try to achieve the required in-service data, monitor the load growth, and make adjustments if necessary, but also to [consider] the sequencing of transmission projects.” 

Load forecasts in California and the West have been escalating, which increases energy resource and transmission requirements in the region, Millar said during his presentation. CAISO is dealing with new types of loads, such as those caused by data centers in particular, he said. 

CAISO’s 2025/26 transmission planning process continues to rely on accessing out-of-state resources, particularly wind, Millar said. These out-of-state wind resources will need more attention over the coming years to bring them to California, he added.  

Millar specifically highlighted 12 major transmission projects — each from CAISO’s transmission plans from 2018 to 2025 — that are under development. However, about 12.9 GW of renewable resources could be delayed due to transmission delays, Brian Biering, counsel for American Clean Power, California (ACP), said in a presentation at the workshop. As of April, the region has about 28.4 GW total of new renewable generation and storage resources with signed interconnection agreements, he said. 

To help solve these delays, ACP recommended energy officials consider requiring an independent transmission construction monitor (ITCM) that would increase the transparency and enhance staff understanding of transmission construction for projects above 1,000 MW. The ITCM should be able to request data directly from transmission owners and report directly to the CPUC and CAISO, Biering said. 

Investor-owned utilities in California have 715 transmission projects under development that have planned in-service dates between 2025 and 2033 and an expected cost of $1 million or greater, said Molly Sterkel, interim director of electricity supply, planning and costs at CPUC. Of those 715 projects, CAISO has approved 140, while 575 are non-approved, Sterkel said. 

California needs 100 GW of new resources by 2040, said Danielle Mills, CAISO principal of infrastructure policy development. The ISO has “more than sufficient resources in the queue to meet those needs,” Mills said. 

“In fact, we still worry sometimes … that we have too many projects in the queue that are lingering, that we need to find some alternative pathway for, either withdrawal or transitioning those resources to some other type of resource,” Mills said.  

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DOE Environmental Review of Grain Belt Express Devalues Line’s Carbon-cutting Ability

Drafted during a different presidential administration, the Grain Belt Express’ final environmental impact statement downplays the potential environmental benefits of the line.

The Trump administration’s U.S. Department of Energy Loan Program Office released the final review days after withdrawing a $4.9-billion conditional loan commitment for the 800-mile HVDC line. (See DOE Pulls $4.9B in Funding for Grain Belt Express.) Line owner Invenergy has vowed to move ahead with the project.

While the final impact statement finds the same adverse impacts to soil, vegetation, land, recreation and water and points to mitigation on Invenergy’s part, the completed document also diminishes the emissions that Grain Belt could avoid or reduce from 2.8 to 3.1 million tons to just 175,000 metric tons annually. The 175,000-ton figure is based solely on a 3% percent transmission efficiency improvement that the line, at a capacity of 2,500 MW, would foster through decreased line losses.

The DOE erased a draft finding that an alternative scenario where Grain Belt is not built “would not support” the Biden administration’s circa-2021 target to cut greenhouse gas emissions anywhere from 50-52% from 2005 levels by 2030. The department also excised sections of the more than 440-page report that assumed the line would help new renewable energy projects access the grid, potentially avoiding up to a cumulative 5.15 million tons of greenhouse gases annually while supporting 3 GW of new renewable generation capacity.

Instead, the DOE emphasized that Grain Belt cannot discriminate between coal, natural gas or renewable resources when deciding whose power to transmit. It said it expected the line to carry “diverse power mixes,” including existing baseload and dispatchable energy facilities.

“Following publication of the draft [environmental impact statement] in January 2025, a number of policies were enacted that facilitate the development of baseload and dispatchable energy. It is too soon to foresee the impact that these policies may have on market conditions and demands for certain types of energy in the vicinity of the project,” the DOE said.

The agency deleted a previous finding that there would be a “significant cost barrier for any new or existing coal generation projects to tie into the project” and struck a note that no new natural gas generation projects are planned to be built near the point of injection. It also nixed an explanation that HVDC technology doesn’t “easily allow” for new connections along the line without building intermediate converter stations, “which requires significant modifications to the overall design as well as notable increased costs.”

The DOE edited out a scenario in the draft report where the agency assumed the line wasn’t built because it refused to provide federal financial support to Invenergy.

The department also deleted more than 20 pages on environmental justice considerations, since environmental justice factors now are outside the scope of the environmental review under the National Environmental Policy Act, pursuant to President Donald Trump’s executive orders. It scrapped all mentions of the DOE’s discontinued Climate and Economic Justice Screening Tool that helped track effects on disadvantaged communities.

Grain Belt’s draft environmental impact statement paid special attention as to whether minority and low-income communities would experience about the same construction disruption as wealthier counterparts. The DOE in early 2025 concluded in the draft document that the line wouldn’t disproportionally burden low-income populations.

The DOE eliminated instances of “climate change” from the final report and deleted sentences pondering the potential for more intense weather to affect Grain Belt facilities once built. It also removed references to EPA’s 2022 finding that human-driven greenhouse gas emissions are the “leading cause of the Earth’s rapidly changing climate.”

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PJM Presents Updated Quadrennial Review Inputs

PJM plans to delay votes on several proposals to revise key capacity market parameters by one month to receive updated cost of new entry (CONE) values for combustion turbines and combined cycle generators as part of the ongoing Quadrennial Review process, though no impact to the auction timeline is expected. 

The MIC will vote on the proposals during its Sept. 10 meeting, followed by votes at the Markets and Reliability Committee and Members Committee on Sept. 25, with the aim of a filing being submitted to FERC in October. 

The delay will allow the Brattle Group, retained to assist in the review, to update the CONE values with physical updates — including wet compression, updated technical specifications from General Electric including higher firing temperature, and an adjusted inlet pressure assumption — and financial updates, including the impact of 100% bonus depreciation returning because of the One Big Beautiful Bill Act. Brattle and Sargent & Lundy presented additional information from GE to stakeholders on its standard payment schedule for gas turbines and showed that it was in reasonable agreement with the capital drawdown schedules used for the CC and CT in Brattle’s analysis. 

PJM’s Skyler Marzewski said that if Brattle were to exactly follow the GE turbine payment schedule, it would have little impact and result in the CONE for a CT increasing by less than $7/MW-day and less than $2/MW-day for a CC unit if incorporated into PJM’s proposed variable resource requirement (VRR) curve. He said one reason this impact is relatively small is because turbine payments are just one portion of capital drawdown, with owner-furnished equipment accounting for about 39% of overnight capital costs for a CT and 28% for a CC. 

Independent Market Monitor Joe Bowring said GE’s perspective on the total payments by purchasers, including but not limited to payments to GE, should be treated as informative on its payment schedule, not dispositive on the overall drawdown costs for a new generator. 

“The Market Monitor has built the drawdown schedule from the bottom up, while Sargent and Lundy/Brattle did a top-down analysis based on their general view about industry practice related to all payments associated with buying and installing a turbine,” Bowring wrote in an email. “GE’s general opinion about payments to others involved in the process is anecdotal and not the appropriate standard.” 

Brattle Principal Sam Newell and PJM Chief Economist Walter Graf said they met with GE, joined by Sargent & Lundy, to receive more information about the cost and payment schedule for turbines and confirmed that the capital drawdown schedule in Brattle’s analysis is reasonably aligned with GE’s payment schedule for turbines. They said the payment schedule for turbines has become increasingly front-loaded, which increases installed costs. Graf said the Monitor also was invited to this meeting but refused, and the delayed spend schedule proposed by the Monitor in its proposal results in a drastically different turbine payment schedule from what GE said would be reasonable. 

Bowring said the Monitor has discussed GE’s own payment requirements for the purchase of a turbine directly with GE and has incorporated GE’s required payment schedule in its drawdown schedule. He also disputed Graf’s characterization of the Monitor’s involvement. 

“The fact that the actual payment schedule required by GE differs from the assumptions made by Brattle is a reason to question the Brattle top-down derivation. It is not a question of what Brattle assumes is common practice. It is a question of what GE requires,” he said. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said Brattle and the Monitor should present more details on its discussions with GE and data received from the company to inform their drawdown schedules, along with more documentation from GE and engineering, procurement and construction (EPC) companies. 

“Sunshine is going to be the best disinfectant on this discussion,” he said. 

Presenting an update on the impact the changes could have on the VRR curve, Newell said the 100% bonus depreciation included in the One Big Beautiful Bill Act amounts to a tax break that “pretty significantly lowers the cost to the owner” of a new resource.

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PJM Stakeholders Frustrated by Reliability Requirement Shortfall

The Market Implementation Committee discussed the significance of PJM falling short of its reliability requirement and other details in the results of the 2026/27 Base Residual Auction, which cleared at the $329.17/MW-day cap across the RTO.  

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said the RTO had buried the lede on the importance of failing to meet the reliability requirement, particularly because load is expected to surge higher in the 2027/28 auction scheduled to be conducted in December. (See PJM Capacity Prices Hit $329/MW-day Price Cap.) 

Despite PJM’s efforts to speed interconnection studies and allow more resources to advance toward construction, only 2,400 MW of additional unforced capacity was provided by renewable resources and storage in the auction. Poulos noted that outgoing FERC Chair Mark Christie spoke during a press conference July 24 about his concern that a long-discussed reliability crisis is rearing its head in the 2026/27 BRA as slow generation growth meets data center load growth. (See Christie Says Farewell to FERC at Final Meeting as Chair.) 

Poulos told RTO Insider the advocates are frustrated by the administrative levers PJM decided to pull in the design of the 2026/27 auction, but that those issues are dwarfed by the potential impact of the 30 GW of data center load growth the RTO is projecting. He said the RTO must engage in “ruthless prioritization” as it determines the best approach to meeting its resource adequacy needs, but he said he is not aware of any changes that could handle load growth of that magnitude. 

Exelon Director of RTO Relations and Strategy Alex Stern said the extent of the capacity shortfall is fairly minor, with the auction procuring a reserve margin of 18.9% against a 19.1% requirement, which amounts to 309 MW of installed capacity. He questioned whether there are internal discussions ongoing at PJM related to expanding the options around how to get more generation online “so that we don’t just have customer bills going up but no new plants getting built.” 

PJM Director of Stakeholder Affairs Dave Anders noted that staff brought an issue charge to the Planning Committee on Aug. 5 intended to allow new resources capable of partial operation while their network upgrades are under construction to receive provisional interconnection service. While that wouldn’t move the needle on the capacity market, he said, it could allow more energy to be available to dispatchers during critical periods. 

PJM’s Pete Langbein said there are several initiatives that have resulted in changes effective for the 2027/28 auction, including expanding the availability window for demand response resources and the Reliability Resource Initiative (RRI), which added 51 resources totaling 11,793 MW of nameplate capacity to the Transition Cycle 2 study cluster. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025 and PJM Selects 51 Projects for Expedited Interconnection Studies.) 

“By all means, we are trying to be proactive to look at what can be done,” he said. 

PJM Senior Vice President of Operations Mike Bryson also said the executive leadership team has set resource adequacy as its top focus since the publishing of the RTO’s “4R’s” white paper finding that load growth, generation deactivations and slow new entry could compromise reliability. “It’s a focus of the entire executive team,” he said. 

Langbein said the RTO cleared very close to the requirement, and almost all generation cleared in the auction, aside from some resource owners who did not understand the process to request removal of capacity status or those with external contracts who did not realize they needed to go through the must offer exemption process.  

But “this is not horseshoes. ‘Very close’ is not same as meeting the requirement,” Independent Market Monitor Joe Bowring told RTO Insider in an email. “To the best of my knowledge, PJM has never been short in the capacity market at the total RTO level in the history of the capacity market. This is a clear warning sign. PJM needs to directly address the impact of large data center loads which will overwhelm the grid if not addressed in the very near term. Hand waving is not the appropriate response.” 

Bowring said some of the resources that did not offer ran afoul of the rules because of deadlines, and the Monitor will be looking at the subject closely and release more information. 

John Horstmann, senior director of RTO affairs for AES Ohio, asked if there has been any progress made on estimating the total amount of capacity that was removed from the market after the implementation of effective load-carrying capability (ELCC) and changes in accreditation, as well as the price impact on the total cost of capacity. 

Bowring said the Monitor is working on calculating those values and likely will include them in its series of reports on the auction. 

“The short answer is that ELCC removed a significant level of megawatts from the auction. The calculation of the exact amount requires analysis of the impact both on supply and demand of ELCC on the amount of capacity that would clear,” Bowring said. 

Presenting the auction results, Langbein said 2,669 MW of UCAP in new generation and uprates were offered in the auction, reversing a trend of declining new entry across the prior three auctions. About 1,100 MW of capacity interconnection rights scheduled to be deactivated also were withdrawn, keeping that output in service. He said staff are in the process of updating the auction report to include a note with the amount of ICAP offered in response to stakeholder requests. 

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Ørsted to Raise $9.3B, Self-finance Sunrise Wind

Ørsted is moving to raise as much as $9.33 billion on its own to finish building the Sunrise Wind project off the New York coast. 

The company said Aug. 11 the money will be sought from existing shareholders and that it must take this step because it has been unable to reach a financing deal and secure an equity partner under acceptable terms in the hostile environment President Donald Trump has created for U.S. offshore wind development. 

Ørsted CEO Rasmus Errboe said negotiations with multiple potential partners were progressing well — until April 16, when the Trump administration slapped a stop-work order on Empire Wind 1, an Equinor project off the New York coast, and did not allow construction to resume for more than a month. 

This “extraordinary and unprecedented development” significantly increased the perceived risk in the U.S. offshore wind sector, and those potential partners raised their requirements to a level untenable for Ørsted — so Ørsted must go it alone and fund the entire cost of Sunrise Wind on its balance sheet. 

With the “vast majority” of the expenditures already committed, there is far more value in moving ahead with the project than in abandoning it, Errboe said. Ørsted still expects Sunrise to produce a lifecycle internal rate of return in the mid-single digits. 

So it is seeking $6.22 billion to cover financing and capital costs, plus about $3.11 billion to strengthen the company’s capital structure and give it needed financial flexibility. 

The plan is to offer a rights issue — a discounted sale of additional shares to existing shareholders — in October, if authorized at an extraordinary general meeting in September. The Danish state, which owns a 50.1% share majority of the company, has given its full support, Errboe said, and the rights issue would be fully underwritten by Morgan Stanley. 

Ørsted’s stock tanked on the news, shedding nearly 30% of its value. 

Aside from the U.S. regulatory environment, and aside from the resulting financial squeeze, the largest western offshore wind developer presented a positive state of affairs with its first-half financial results. 

The two projects Ørsted still is actively developing in U.S. waters are on schedule. 

Revolution Wind, a 704-MW project that will send power to Connecticut and Rhode Island, is roughly 80% complete, with all turbine foundations and nearly 70% of the turbines installed. Commercial operation is targeted for the second half of 2026. 

Sunrise, a 924-MW project, is targeted to begin feeding the New York grid starting in the second half of 2027. Onshore construction is nearly complete, and more than a dozen turbine foundations have been installed. 

Sunrise is in a much better position than New Jersey’s Ocean Wind or Maryland’s Skipjack Wind, which Ørsted canceled and shelved, respectively. But Sunrise has had a tortuous path nonetheless. 

It dates to July 2013, when the federal government auctioned off rights to develop wind power on OCS-A 0487, a patch of the Outer Continental Shelf south of Fall River, Mass., and east of Montauk, N.Y. 

Ørsted and then-partner Eversource won an offtake contract from New York in the summer of 2019 for what was then called Sunrise Wind 1, but rising costs in 2022 and 2023 made the terms untenable. 

In 2024, New York renegotiated a much more expensive contract for Sunrise Wind — $146/MWh — and Ørsted bought out Eversource’s ownership stake in the project for $152 million. 

Later in 2024, Donald Trump was elected to a second term as president, and hours after his inauguration in January 2025, he began to fulfill a campaign-trail promise to thwart offshore wind development. Multiple policy changes announced since then have created new setbacks and hurdles for the already-struggling industry. 

Equinor recently recorded a nearly $1 billion impairment it attributed to President Trump, but so far, no other stop-work orders have been issued for the five offshore wind farms under construction and one in full operation in U.S. waters. The Trump administration’s moves have served mainly to block other wind farm plans or concepts from advancing. 

But during Ørsted’s Aug. 11 conference call, an analyst asked if the administration might not shut down Revolution or Sunrise the way it halted work on Empire. He asked: “Are you 100% comfortable the U.S. administration cannot block either of those projects?” 

“We have no indication of a similar decision or stop-work order against our northeast U.S. program, and I’m not going to speculate about potential regulatory changes that are outside our control,” Errboe said. 

Ørsted has followed all state and federal procedures with both projects, he added, “and we remain 100% committed to the continued construction of our program.”