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December 14, 2025

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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.” 

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NERC Posts IBR Standards for Comment

NERC is requesting comments from industry through Sept. 10 on four proposed reliability standards aimed at satisfying FERC’s directive on inverter-based resources.

The ERO posted the standards in its Standards Balloting System on Aug. 8, along with the latest update to the ERO’s Reliability Standards Development Plan (RSDP), which lays out the planned schedule of standards development from 2026 to 2028. Comments on the RSDP are due by Sept. 5.

The following standards are up for comment:

    • MOD-032-2 — Data for power system modeling and analysis;
    • IRO-010-6 — Reliability coordinator data and information specification and collection;
    • TOP-003-8 — Transmission operator and balancing authority data and information ​specification and collection; and
    • MOD-033-3 — Steady-state and dynamic system model validation.

All of the standards were developed under Project 2022-02 (Uniform modeling framework for IBRs) except for MOD-033-3, which originated from Project 2021-01 (System model validation with IBRs). NERC’s Standards Committee approved all of them for posting at its April 16 meeting. (See NERC Standards Committee Approves IBR Posting.)

In Order 901, issued in October 2023, FERC directed NERC to develop requirements pertaining to the reliable connection and operation of IBRs, grouped into four milestones to be submitted over the following three years (RM22-12). (See FERC Orders Reliability Rules for Inverter-Based Resources.) Included in Milestone 3, due Nov. 4, are requirements for providing data on IBRs and distributed energy resources to entities responsible for planning and operating the grid.

To satisfy this mandate, the standard development team for Project 2022-02 decided to update MOD-032-2 to include language from the ERO Unacceptable Models List, renamed Aug. 1 from the ERO Acceptable Models List Criteria Document. A new requirement allows planning coordinators and transmission planners to specify whether they will accept standard-library dynamic models, user-written models or both.

NERC said the requirement is “responsive to FERC concerns about model usability and non-convergence by requiring PCs and TPs … to specify usability requirements and require appropriate model documentation and instructions,” while also allowing a level of flexibility requested by stakeholders in industry engagement workshops.

Another requirement was rewritten “to require estimation of modeling data if the responsible entity … is unable to gather required data.” This is intended to give entities a way to meet FERC’s directive of submitting data even if the actual information is unavailable; however, entities that submit estimates must explain the “limitations of the estimated data” — such as legal prohibitions on requesting certain data, incomplete records of connected facilities and lack of mechanism to enforce collection — “and the method used for estimation.”

The final revisions recorded by the SDT apply to TOP-003-8 and IRO-010-6, and state that “entities responsible for developing and distributing data specifications shall include requirements for model submissions consistent with the model submitted for planning purposes, as applicable.”

The drafting team for Project 2021-01 said that “no substantive changes are needed” for MOD-033, but members did note “opportunities to improve the clarity of both the [standard’s] requirements and measures.” To this end, they proposed to add the glossary term “model validation” — approved in May by industry ballot for inclusion in NERC’s Glossary of Terms — to the standard, along with a requirement that the PC implement a model validation process for its “portion of the existing system.”

Team members also updated additional language in the standard to correspond with the “model validation” definition and to reduce redundancy and wordiness.

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PJM MIC Briefs: Aug. 6, 2025

1st Read on Offer Capping of Advance Scheduled Resources

PJM’s Phil D’Antonio presented a first read on a proposal to cap resources committed ahead of the day-ahead market at their cost-based offer. The proposal is set to be voted on by the MIC at its September meeting, and additional manual, operating agreement and tariff language would need to be drafted and voted on subsequently. (See “Offer Capping Resources with Advance Commitments,” PJM MIC Briefs: March 5, 2025.) 

Advance commitments have been used more widely since the institution of the conservative operations procedure, which allows PJM to schedule resources expected to be necessary to maintain transmission security during strained operating conditions, especially winter storms. The cost of that practice has been criticized by consumer advocates, and the use of out-of-market commitments has been opposed by some generation owners. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.) 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said PJM’s governing documents only allow for offer capping resources with advance commitments to address transmission constraints, arguing that offer capping resources committed for other purposes violates the tariff and negatively impacts price formation. 

“I think this is going down a very dangerous path,” he said. 

PJM’s proposal states that the “PJM tariff and [Operating Agreement] allow for offer capping only for transmission constraints. Current [Manuals 11 and 13] language allows offer capping for units scheduled in advance of the day-ahead market but does not have supporting tariff and OA language.” 

Offer Capping Issue Charge Revised

The committee endorsed by acclamation an expansion of the offer capping issue charge brought by the Monitor to include additional consideration of the treatment of resources with advance commitments in the day-ahead market, how uplift is calculated for resources committed for multiple days and additional transparency into how resources are scheduled. 

The issue charge was renamed to reflect the wider scope, removing references to offer capping to instead read as “resource scheduling prior to the day-ahead energy market.” (See “Monitor Proposes Rewrite of Offer Capping Issue Charge,” PJM MIC Briefs: July 9, 2025.) 

The revisions also add additional education on the triggers for allowing advance commitments, notifications that go out to stakeholders that such action has been taken, commitment instructions to resources, the inputs and models that determine commitment parameters and operational constraints not included in unit parameters, such as fuel inventory, gas nomination cycles and any run hour limitations associated with environmental permits. 

Renewable Dispatch Proposal Endorsed

Stakeholders endorsed a PJM proposal to create a new Effective EcoMax parameter for wind and solar resources intended to better capture how they are capable of operating in real-time energy market dispatching. The proposal passed with 98.9% support. (See “First Read on Real-time Renewable Dispatch,” PJM MIC Briefs: July 9, 2025.) 

The forecast for wind and solar output would be updated ahead of each five-minute interval, which then would feed into the Effective EcoMax parameter and update maximum output the generator can be dispatched up to. The existing EcoMax parameter limits security-constrained economic dispatch (SCED) based on the parameters submitted by resource owners, which can become stale and lead to units being curtailed below their potential. 

The proposal was modified by PJM to retain curtailment flags for wind resources and establish them for solar as well; they had been set to be removed for all resources in July, but a Distributed Resources Subcommittee poll showed 96% support for allowing them for renewables. 

Renewables would be limited to ramping at 20% of their ICAP per minute to minimize the volatility that can come from sudden shifts in renewable output. PJM’s Vijay Shah noted that still would allow those resources to go from 0 to 100% of their capability in a single interval. 

Regulation Market Redesign Endorsed

The committee endorsed by acclamation a slate of manual revisions to conform with PJM’s regulation market redesign, which was approved by FERC in June 2024 (ER24-1772). (See “PJM Presents Manual Revisions for Regulation Market Redesign,” PJM MIC Briefs: July 9, 2025.) 

The reworking of the market creates a single price signal with resources able to offer regulation up and down products, replacing a market model where participants offered bidirectional products to provide either Regulation A for long deployments or Regulation D for fast response. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

The proposal includes revisions to Manual 11: Energy & Ancillary Services Market Operations, which detail offer structure, DR participation and lost opportunity cost credits; Manual 15: Cost Development Guidelines, including a stipulation that regulation resources also participating in the energy market do not receive variable operations and maintenance cost increases; and Manual 28: Operating Agreement Accounting, which outline the regulation clearing price credit formula. 

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July Heat Wave Update, PJM OC Briefs: Aug. 7, 2025

July Heat Wave Update

PJM’s Kevin Hatch presented an update on how two heat waves between July 14-17 and 23-30 affected PJM operations, which involved multiple demand response deployments and emergency alerts and advisories. 

Loads reached their apex on the afternoon of July 29, with a preliminary integrated hourly peak of 157,487 MW, which Hatch said would be the ninth highest the RTO has seen. He said the day saw atypically high load ramping, renewable performance below the seasonal effective load-carrying capability (ELCC) value, and generation outages exceeding the three-year average. Around 3.7 GW of DR was deployed. 

The declaration of maximum generation and load management alerts without extreme temperatures raised concerns for PJM that load growth and renewable penetration could jeopardize resource adequacy. During the Aug. 5 Planning Committee meeting, PJM said it had initiated 11 maximum generation and load management alerts in 2025, more than the prior decade combined. 

The first heat wave saw maximum generation and load management alerts July 15 and 16, which Hatch said included notifications to neighboring balancing authorities that off-system sales could be curtailed. 

A generation maintenance outage recall was issued ahead of the second heat wave, followed by hot weather alerts starting in PJM West on July 22 and for the whole RTO the following day. Maximum generation and load management alerts were issued for July 24, 25, 28, 29 and 30. Pre-emergency load management was called July 28 for the BGE, PEPCO and Dominion zones, expanded to the full RTO the next day, when all available long- and short-lead DR was called. 

Synchronized Reserve Performance Inquiry

The Independent Market Monitor presented the results of a poll of resource owners who saw their units underperform during the July 1 synchronized reserve performance inquiry, which saw 79.5% response for individual resources. The event lasted 10 minutes and 38 seconds, with 2,398 MW of generation and 544 MW of DR assigned.  

Joel Romero Luna, of Monitoring Analytics, said the owners of 33 underperforming resources were contacted and responses covered 20 units. The single-largest identifiable cause of those units’ shortfall was inaccurate parameters having been submitted, accounting for around 50 MW of the 581-MW shortfall. Around 225 MW of shortfall was categorized into an “other” category due to the number of resource owners falling below the confidentiality requirement of at least four generation owners providing the same information, allowing anonymized aggregation. 

He said outreach to generation owners is continuing with the goal of increasing the response rate. 

July Operating Metrics

PJM saw an average hourly forecast error of 1.7% for July and an average peak error of 1.78%, according to the RTO’s monthly operating metrics. The 3% daily peak error benchmark was exceeded three days, with over-forecasting on July 19, 24 and 26 attributed to storms causing load to come in lower than expected. 

The month saw four spin events, two shared reserve events, seven maximum generation and load management alerts, five pre-emergency load management reduction actions, seven shortage cases, 10 hot weather alerts and 39 post-contingency local load relief warnings. All the shortage cases occurred July 28, with one primarily due to generation loss and six due to solar generation falling faster than load was expected to decline between 6:59 p.m. and 7:25 p.m. 

Two of the spin events exceeded 10 minutes, allowing the RTO to begin measuring a rolling average to track synchronized reserve performance for the purpose of potentially backing down a 30% adder to the reserve requirement. PJM established the adder in May 2023 to address poor reserve performance, which PJM aimed to address through changes to reserve deployment implemented in December 2024.  

In March 2025, PJM began measuring reserve performance, backdated to December 2024, and created a paradigm under which the adder could be reduced if reserve performance is above 75% across a rolling average of three events exceeding 10 minutes.  

Under that model, the adder would be reduced by 10% if performance across the rolling average is between 75 and 85%. It would be reduced by 20% if the average is between 85 and 95%, and it would be eliminated at performance above 95%. The adder could be increased by 10% if performance falls below 75%, but the reserve requirement must remain within a 100-to-130% band. (See PJM OC Briefs: March 6, 2025.) 

The July 1 and 22 events, paired with a spin event Feb. 5, carry an average of 74.4% performance, meaning the adder remains untouched. For the next event to reduce the adder by 10%, performance would need to be 66.7% or greater; performance at 96.7% or greater would result in the adder being reduced by 20%. 

The July 22 event lasted 10 minutes and 32 seconds and saw 2,764 MW of generation and 548 MW of DR assigned, with performance at 79 and 80% respectively. A July 30 event last 5 minutes and 57 seconds, with 3,588 MW of generation and 328 MW of DR assigned, with performance at 59 and 72% respectively; the next day another spin event was declared lasting 6 minutes and 16 seconds, with 2,802 MW of generation and 582 MW of DR assigned, with 45 and 63% performance. 

Generation Deactivation Manual Revisions

The Operating Committee endorsed by acclamation revisions to Manual 14D: Generator Operational Requirements to rework the requirements for a resource requesting deactivation. The proposal will advance to the Markets and Reliability Committee for a first read at its Aug. 20 meeting, followed by endorsement on Sept. 25. (See “1st Read on Manual Revisions Detailing Generation Deactivation Process,” PJM OC Briefs: July 10, 2025.) 

Resource owners would be required to provide PJM with at least one year’s notice before going offline and follow the must-offer exemption process if they are seeking to not participate in the capacity market. The proposal also expands transparency requirements, mandating that resource owners entering into a reliability-must-run agreement with PJM provide the RTO and the Monitor with an estimate of the costs that would be recovered under the agreement, which would be publicly posted. Ongoing monthly updates would be required during the term of the RMR agreement. The Monitor also would publicize market power letters. 

The language would remove a $2 million cap on project investments allowable under the deactivation avoidable cost credit (DACC) compensation methodology, limit the adder for investments to 10% and remove language causing the credit to be determined through the daily deficiency rate rather than the deactivation avoidable cost rate (DACR) when the DACR and applicable multiplier exceed the deficiency rate.