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December 13, 2025

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Constellation Optimistic About Nuclear-friendly Federal Policies

Constellation Energy said it is riding high on policy and market support for nuclear energy as it announced its second-quarter results.

“The passage of One Big Beautiful Bill [Act] was an undisputed win for nuclear power,” CEO Joe Dominguez said during an earnings call with analysts Aug. 7.

More than that, the passage of OBBBA was a demonstration of bipartisan support for a power-generation technology that for many years was out of favor with many Americans. Dominguez noted the bill, which passed with only Republican votes, expands tax credits created by the Inflation Reduction Act, which was passed with only Democratic votes.

“It’s one of the only things the two bills have in common, is that it supports existing and new nuclear plants,” he said.

He added that negotiations have reached late stages with one potential power customer and middle stages with others interested in clean, reliable electricity.

“But most importantly, from my perspective, we’re seeing a continued acceleration of interest from a growing number of entities,” Dominguez said.

An analyst asked if Constellation’s nuclear strategy has changed in light of OBBBA.

Evolution seems likely, Dominguez said, rather than abrupt and sharp changes — particularly with small modular reactors, a potential game changer for the industry. Not all of the dozens of SMR designs being advanced will work or be commercially viable, he said.

Constellation’s R.E. Ginna nuclear power plant in Ontario, N.Y., houses the nation’s smallest and second-oldest operating commercial reactor. | Constellation Energy

“But we’ve got a pretty good bead on who we think the winners are going to be,” he said. “I feel better with the passage of each week in terms of better understanding the cost structures and the time to complete the work. And so I would say that our confidence is growing, but it’s growing incrementally, not in terms of major step changes.”

Dominguez said co-location of new SMRs with Constellation’s existing fleet of large reactors just makes sense — the sites have suitable land, an experienced workforce and a supportive community.

He singled out New York for its recent policy moves to support existing and new nuclear generation — announcing plans to develop at least 1 GW of new advanced nuclear capacity, moving toward a decision to extend to 2049 the zero-emissions credits that subsidize Constellation’s four in-state reactors and collaborating with the company to seek federal funding for advanced nuclear development at the Nine Mile Point plant, which has two older-generation reactors. (See N.Y. Makes Case for Extending Nuclear Subsidies to 2049 and N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility.)

“It’s early innings on this work, but I think it is going to be a signpost for other states, and I’m excited for the opportunities to expand nuclear in places like Maryland, Illinois, Texas and Pennsylvania,” Dominguez said.

In other updates:

    • Constellation’s acquisition of natural gas power generator Calpine has cleared most of its key regulatory reviews and is targeted for closure before the end of this year.
    • Big Tech is not the only sector seeking clean energy. Many customers other than data centers are interested in nuclear power.
    • Comcast is among the newest of these customers and has committed to a significant energy transaction that will help support a nuclear reactor uprate.
    • The engineering process is complete on potential uprates of other reactors, and Constellation says it hopes to partner with customers on these projects as well.
    • Constellation and GridBeyond are collaborating on an AI-powered demand-response program in the PJM grid that will allow customers to cut their peak energy costs while helping the market maintain system reliability.

Constellation reported second-quarter 2025 income of $833 million ($2.67/share) on revenue of $6.1 billion, which compares with $809 million ($2.58/share) on $5.48 billion a year earlier.

Its stock price closed 0.6% lower Aug. 7.

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Clean Energy Groups Seek Rehearing on DOE Resource Adequacy Report

Three clean energy trade groups have asked the Department of Energy to reconsider its recent report on resource adequacy, which they contend uses a deterministic approach to stake out a position for not retiring any more power plants in the face of rising electricity demand.  

The American Clean Power Association (ACP), American Council on Renewable Energy (ACORE) and Advanced Energy United (AEU) filed a request for rehearing Aug. 6, saying DOE should rework the report to offer a more clear-eyed view of the risks the industry faces with exploding demand stemming from the growth of data centers and other large energy customers. (See DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030.) 

“As demand for energy surges, grid reliability must rely on sound modeling, reasonable forecasts and unbiased analysis of all technologies,” the groups said in a statement. “Instead, DOE’s protocol relies on inaccurate and inconsistent assumptions that undercut the credibility of certain technologies in favor of others.” 

The report uses forecasts for high demand coupled with projections for limited new supply that include only NERC Tier 1 planned generation — resources already under construction or with firm in-service dates. That means DOE effectively assumes no new generation will go online after 2026 in a report that extends to 2030, John Hensley, ACP senior vice president of markets and policy analysis, said on a call with reporters. 

“We are all kind of cognizant of the challenges facing us over the next 10 years as energy demand is starting to skyrocket, at the same time that there are very active debates going on right now, thinking about taking a lot of resources off the table that could help to meet that demand going forward,” Hensley said. 

A recent RTO Insider story cited industry experts who raised similar concerns about the report, prompting DOE to defend its methodology. (See Industry Experts Find Fault in DOE’s Resource Adequacy Analysis.) 

The agency said its future data center demand estimate represented a midpoint from 2024 studies by the Electric Power Research Institute and the Lawrence Berkeley National Laboratory and acknowledged the report’s “conservative yet realistic baseline” for new generation, but pointed also to supply change challenges the electric sector faces, which could lead to major construction delays.  

Former Kentucky Public Service Commission Chair Kent Chandler said the report relies on one scenario with limited supply growth to push the argument for no retirements. While that could offer evidence of how the industry and its regulators are falling short, it is not enough, he said. 

“It is certainly not, in my opinion, sort of my former regulator hat, useful for the singular purpose of saying all power plants need to stay on at all cost, or build all new power plants at all costs,” Chandler, now a senior fellow with R Street, said in an interview. 

Most studies assessing future resource adequacy would use various scenarios and rank the probabilities of occurring, but by its own admission DOE’s report does not do that, Chandler said.  

A ‘Protocol’ for Retirements

Some industry observers have argued DOE could use the report’s findings to issue more orders under the Federal Power Act to keep plants from retiring, as it did with the Campbell plant in Michigan and the Eddystone plant in Pennsylvania. 

“It’s directly tied to that,” AEU Managing Director Caitlin Maquis said on the call with reporters. “DOE’s analysis came out of Executive Order 1462 back in April that directed DOE to put this analysis together, and then, as part of that same executive order, directs DOE to use all mechanisms available, including FPA Section 202 (c) to retain resources it deems necessary in regions it’s identified as having inadequate reserve margins.” 

A rehearing request for a DOE report is rare, but the groups call the document a “protocol” that will be used to keep more power plants open under the FPA. 

The rehearing request argues the report amounts to “an effective amendment to DOE’s existing regulation governing 202 (c).” 

“In the rehearing request, we go through pretty extensively the reasons that this protocol from DOE may be styled as a report but really looks like agency action that is intended to have real world effects,” Gabe Tabak, ACP general counsel, told reporters. “It is not, as folks sometimes call government reports, a piece of shelf art that is just going to sit there. So, even though it is labeled as a report, in our view, it clears the bar as agency action and therefore qualifies as a type of action where hearing is appropriate to seek.” 

Although preventing retirements in the face of rising demand can be prudent, maintaining all plants that were on the path to closure absent that growth doesn’t make sense, Hensley said. 

“Deferring that decision making to the utilities themselves and their PUCs is the right course of action,” he added. “They understand what their fleet looks like. They understand the available options set in front of them and can make the best decision on what retirements to delay or new resources to bring online to meet that in a most economic way for ratepayers and to balance supply and demand.” 

Taking Politics out of the Picture

Chandler said Kentucky, a coal-friendly state, established a board to review all proposed plant retirements and make recommendations to the PSC regarding approval. He noted the board recently made no filing after a co-op asked to retire a small, broken combustion turbine plant that would have cost more to repair than build new. 

“This body, who basically was put together for the purpose of keeping thermal fossil fuel-fired generation from retiring, was like, ‘We take no position on the retirement either way,’” Chandler said. “They were never going to be for it, but they just couldn’t come up with a reason to say, ‘Yeah, let’s keep it on.’” 

“So, that’s a long way of saying even those folks that are super interested in resource adequacy, or have a bias towards legacy, fossil fuel-fired generation — there are going to be many instances where it just does not make any sense at all for reliability or economic purposes to try to keep some of these plants on way past their economic life,” he said. 

That decision might have been different with a larger 650-MW power plant, which would be a major resource to take offline in one area, he added. 

DOE historically has used Section 202 (c) for limited circumstances when the grid is stressed and a power plant is running up against emissions limits from environmental rules, ensuring it will not be fined for exceeding air permits to maintain reliability — including this summer. 

Chandler said one way to take the politics out of the retirement issue would be broadening how RTOs and ISOs employ reliability must-run (RMR) contracts. While most grid operators use RMRs as a stopgap to prevent grid problems as they address the consequences of removing a retiring plant from the system, ERCOT is one market that relies on the tool for resource adequacy after making a clear case, he said.  

Chandler thinks Congress — or possibly FERC — could change rules to allow RTOs/ISOs to review the impact of retirements on resource adequacy and offer RMRs when needed. 

“That removes a lot of the politics around depending on DOE to do 202 (c) orders, and it frankly makes it probably a more sustainable practice and limits its application to just those instances where it’s most necessary,” he said. 

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NERC Plans to Register 720 IBRs by May 2026

NERC has finished identifying owners of inverter-based resources that will need to register with the ERO and is ready to move on to the final stage of the work plan FERC approved in May 2023, the organization said in a quarterly update filed Aug. 4 (RD22-4).

According to the filing, NERC and the regional entities identified 720 IBRs qualifying for registration that either are or plan to be connected by the registration deadline of May 15, 2026, with a total nameplate capacity of over 32,000 MVA. They were distributed among the regional entities as follows:

    • MRO: 110 IBRs with a total nameplate capacity of 4,454 MVA;
    • NPCC: 50 at 1,752 MVA;
    • ReliabilityFirst: 73 at 3,572 MVA;
    • SERC: 171 at 9,881 MVA;
    • Texas RE: 34 at 1,792 MVA; and
    • WECC: 282 at 10,725 MVA.

The ERO Enterprise arrived at these numbers by revising their initial estimate of 863 IBRs with nameplate capacity of 38,785 MVA, derived from surveys of balancing authorities and transmission owners and submitted to FERC in February. (See NERC Updates FERC on IBR Registration Progress.) NERC refined the estimate by reaching out to generator owners and operators identified as candidates in the initial survey to confirm that their facilities qualify for registration.

GOs and GOPs with facilities requiring registration will be classified as Category 2, a label created by NERC in changes to its Rules of Procedure filed with FERC in 2024. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) Category 2 GOs are entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of [at least] 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage [of at least] 60 kV.” Category 2 GOPs operate such equipment.

NERC emphasized in the filing that these numbers are subject to change. Facilities under development may be canceled or have their expected operational date delayed past the registration deadline. Registered entities also may determine their facilities were inaccurately reported, in which case they will be removed from the list.

The identification of qualifying facilities completes Phase 2 of NERC’s IBR registration work plan, developed in response to a 2022 FERC order to identify and register IBRs that currently are not required to register but, “in the aggregate, have a material impact” on reliable operation. Phase 1 was the creation of the Category 2 designation.

Phase 3, comprising registration of GOs and GOPs, will begin “in the upcoming months,” NERC said. Entities will register through the Centralized Organization Registration ERO System, the common registration portal for all utilities.

The ERO will continue to file quarterly updates on the percentage of registrations completed within each RE’s footprint, with the final update to be filed within a few days of the deadline. NERC also will update its quick reference guide on the registration initiative with links to frequently asked questions and recordings of webinars for candidates.

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SPP Celebrates Novel Consolidated Planning Process

KANSAS CITY — SPP’s Board of Directors has approved a tariff change establishing an integrated, three-year transmission planning cycle that represents a “watershed” moment and a “first-in-the-country” mechanism, RTO officials said. 

The board endorsed the proposal during its quarterly meeting Aug. 5 following a unanimous advisory vote by the Members Committee. The vote added to previous unanimous endorsements from state regulators, the Markets and Operations Policy Committee and five other stakeholder groups. 

The Consolidated Planning Process (CPP) replaces SPP’s current sequential planning and generator interconnection studies that have resulted in clogged queues and an average of six-year wait times before resources go into service. (See SPP ‘Blazes Trail’ with Consolidated Planning Process.) 

The new process comprises a long-term 20-year study and an annual 10-year assessment, aligning system modeling, planning assumptions and cost allocation across load and generation needs. The CPP-10 includes a GI capability study, a GI decision point and a regional transmission assessment that recommends projects for construction. The CPP-20 establishes a 20-year regional vision. 

The CPP also establishes a general contribution funding mechanism, called GRID-C, for upgrades that serve both load and generation, enabling shared cost responsibilities and fewer restudies. 

SPP says the streamlined framework improves cost certainty for stakeholders and promotes equitable cost sharing. Casey Cathey, the grid operator’s vice president of engineering, said the CPP will lead to faster integration of generation and remove “huge challenges” from the current three-phase study process. 

“If you show up and you pay your GRID-C, you’re committed,” Cathey said. “Within seven months on an annual basis, we’ll get to a [generator interconnection agreement], and you may move forward with your build. This is a critical area for modernizing the grid. This is quite innovative across the nation, if not the entire world. We’re blending generator interconnection processes and transmission planning processes in a very elegant solution for providing cost certainty.” 

Cathey may not be wrong about the “elegant solution.” 

“This will be the only RTO that can really offer upfront cost certainty to interconnection customers, which is so incredible for those in the development of assets,” Pine Gate Renewables’ Brett White said. 

The cost-sharing framework assigns GI costs based on transmission usage, projected accreditation needs, the CPP-20 portfolio and future generation.  

The CPP effort grew out of the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT) formed in the last decade to improve SPP’s transmission planning. That led to a task force that continued the work, meeting more than 200 times over three and half years to put together the process. 

Independent Director Steve Wright recalled that the project already was under way when he joined the board in 2023. 

“It is a really big national problem that people new to the industry look at what’s going on here and how long it takes us to figure out interconnections,” he said. “This process is Byzantine and not meeting the moment, because we need electricity. … [The board] was seeing all things going on across the country and saying, ‘What’s going on here is truly creative and can be a national model.’ And here we are at this moment, when it’s actually happened … it’s going to create a model that people can either use or measure against in terms of what are they doing to be able to make this work.” 

Vice Chair Ray Hepper, a Maine resident, said the CPP was a “first-in-the-country” innovation, one that has attracted notice in various corners of the country. 

“I know a lot of people in New England, and they’ll call me and ask, ‘What’s going on?’” he said. “Everybody else is watching. This is a really remarkable feat.” 

EDP Renewables’ David Mindham, apologizing for his “fluffy comments,” added his kudos for CPP. He said it is unlike anything EDP has found in the other RTOs it participates in. 

“It’s very seldom that a process truly comes together, where every interested party sits in a room for years at a time and works through everybody’s issues and … comes to consensus on something. That just doesn’t happen,” Mindham said. “This is probably the first example of a process that I can really think of that was consensus-driven that really balanced stakeholder interests. I think we got an amazing product. I think there could be challenges in implementation. … But if we keep up the same sort of collaboration and atmosphere with that creating this, I think we’ll move through those equally as well.” 

David Mindham, EDP Renewables | © RTO Insider LLC

SPP plans to file the tariff change with FERC by October and will request an effective date of March 1, 2026. Full implementation will begin in 2027, with the first CPP portfolios studied being delivered in 2028. Transitional work will bridge the gap between the CPP framework and the current study process for the 2026 and 2027 assessments. 

“We still have a lot of work to do,” Cathey said. “We have to clean up the backlog. We have to get through and complete the next [study cluster]. We have a lot of individual processes and tools.” 

At the same time, SPP staff are staging internal software to be ready to implement CPP and as part of a recently announced partnership with digital provider Hitachi. The companies have agreed to develop an AI-based solution that the grid operator says will reduce processing times in the GI study process by at least 80%. (See SPP, Hitachi Partner to Use AI in Clearing GI Queue.) 

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NRG Energy Secures $216M Loan from TEF

NRG Energy has closed on a $216 million loan from the Texas Energy Fund that will help it build 456 MW of gas-fired capacity at an existing power plant, the company said in a press release.

The funding will go toward the construction of two new natural gas units at NRG’s TH Wharton power plant in the Houston area, the fifth-largest metropolitan area in the U.S. The company said the units will deliver power to the constrained load zone by summer 2026.

“Demand for electricity across Texas is surging and we’re working quickly to supply new dispatchable natural gas generation to the grid,” said Robert Gaudette, president of NRG Business and Wholesale Operations, in an Aug. 4 statement.

The loan is just the second issued by the Public Utility Commission since the fund’s inception in 2024. The first went to the Kerrville Public Utility Board earlier in 2025. (See First Texas Energy Fund Loan Goes to Kerrville Utility.)

The 20-year loan, executed with the Public Utility Commission, will cover up to 60% of the projected $360 million cost, not to exceed $216 million, at a 3% interest rate through July 2045. The project must meet minimum performance standards, as outlined in the program’s rules.

The two units already are under construction.

NRG has two more projects with another 1 GW of capacity that are progressing through the TEF’s due diligence process. The PUC is reviewing 15 other applications for the TEF’s in-ERCOT program, representing an additional 8.4 GW of capacity. The program, designed to add about 10 GW of gas-fired generation to the Texas grid, was approved by voters in 2023.

Two companies recently withdrew their projects from consideration by the fund, which is administered by the PUC.

LS Power said in June that it pulled a 527-MW project out of due diligence “due to numerous factors” and is no longer pursuing funds from the TEF program. In July, Hunt Energy Network told the PUC that it was withdrawing another due-diligence project because it “does not align with the requirements and conditions of the TEF loan in a cost-effective manner.”

Six projects have been withdrawn by applicants or rejected by the PUC in 2025. (See 2 More Projects Fall out of TEF Loan Program.)

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Interior Reverses Approval of Lava Ridge Wind Project

The Department of the Interior is moving to cancel the Lava Ridge Wind Project, a gigawatt-scale wind farm proposed on thousands of acres of federal land in Idaho. 

The proposal had long been the target of criticism within the state. President Donald Trump ordered all development halted in a Day One memorandum Jan. 20 so Interior could review the record of decision issued six weeks earlier.  

On Aug. 6, Interior announced the review had uncovered crucial legal deficiencies in the “reckless” and “thoughtless” approval issued under lame-duck President Joe Biden. 

“This decisive action defends the American taxpayer, safeguards our land and averts what would have been one of the largest, most irresponsible wind projects in the nation,” Interior Secretary Doug Burgum said. 

Lava Ridge developer Magic Valley Wind and its corporate parent, LS Power, did not respond to requests for comment for this report. 

Interior’s decision is the latest in a series of directives and policy actions by Trump and his cabinet agencies to thwart renewable energy development, one of Biden’s signature initiatives. (See Feds Pile on More Barriers to Wind and Solar and Trump Administration Takes Another Swing at Wind Power.) 

Trump instead is seeking to maximize fossil fuel use. A reminder of this came later Aug. 6, when Interior announced it had advanced the first expedited coal lease under provisions of the One Big Beautiful Bill Act. A day earlier, Interior announced it had approved the second-largest coal mine expansion since Trump returned to office — a move intended to enable extraction of 33 million tons of coal at a Montana mine. 

Lava Ridge was proposed in 2021 with up to 400 wind turbines disturbing 9,114 acres. During the Bureau of Land Management review process, it was reduced to 231 turbines and 992 acres disturbed, with the overall footprint reduced to 38,535 acres. BLM issued a favorable record of decision Dec. 5, 2024. 

Nameplate capacity was to be at least 1,000 MW, which would nearly double the roughly 1,100 MW of wind power installed statewide in 2024. Idaho’s largest existing wind farm in 2024 was rated at only 160 MW, according to the U.S. Energy Information Administration. 

Residents and elected leaders of the solidly Republican state mounted a vocal campaign against the plan on the grounds that it would be ugly; would be too close to the Minidoka National Historic Site, where civilian Americans of Japanese descent were held during World War II; and would send its electricity to California. 

Idaho’s congressional delegation and governor, Republicans all, had fought the Lava Ridge proposal all the way through to BLM approval and then continued after. On Aug. 6, they took a victory lap. 

“I made a promise to Idahoans that I would not rest until the Lava Ridge Wind Energy Project was terminated,” U.S. Sen. Jim Risch said. “Today, President Trump and I delivered on that promise.” 

On X, Gov. Brad Little praised Trump and Burgum: “On behalf of all Idahoans — thank you for your leadership.” 

BLM said in December it had worked to reduce the impacts of the original proposal on wildlife, cultural resources, local aviation, ranchers who use public land and adjacent private landowners.  

Minidoka, where more than 13,000 Japanese Americans were interned, had become a bit of a rallying point for opponents, as alternate iterations of the Lava Ridge plan would have put turbines much closer than the nine miles in the final version. 

Turbines already spin southeast and southwest of the concentration camp site — most of Idaho’s existing wind energy generation is in the Snake River Valley. 

California Impact?

It is unclear what impact the cancellation of Lava Ridge will have on California’s ambitious plans to reduce its electricity emissions, which include extensively tapping output from wind resources in the inland West. As part of that effort, the California Public Utilities Commission’s (CPUC) integrated resource planning portfolio calls for the state to procure more than 1,000 MW of wind generation from Idaho. 

Unclear also is the effect on another LS Power project, the Southwest Intertie Project-North (SWIP-North), a 285-mile, 500-kV transmission line being developed in northern Nevada by the company’s Great Basin Transmission subsidiary. 

Last year, the CAISO Board of Governors finalized approval of a proposal to include SWIP-North as a CAISO participating transmission owner (PTO) after ISO planners determined the project would be the only line completed in time to help deliver Idaho wind to California’s load-serving entities by 2027. 

While development of SWIP-North has not been tied to any single generation project, most of Lava Ridge’s output was expected to be exported on the southbound segment of the line. In response to past stakeholder concerns about the line’s dependence on Lava Ridge, CAISO pointed out that “CPUC portfolios for out-of-state wind resources in Idaho are based upon generic wind resources and not specific to any one specific facility such as Lava Ridge.” 

Sources have told RTO Insider that the CAISO PTO designation for SWIP-North likely influenced Idaho Power’s leaning in favor of joining the CAISO Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+. But even with the Lava Ridge cancellation, Idaho Power’s interest in SWIP-N would appear to be secure, given that the utility plans to use the line to import power from the Southwest and not for exports. 

“The SWIP-North project is the final segment of the larger SWIP project, which began decades ago. The urgency of completing the project has grown as growing energy demand across the Western United States strains the grid,” Idaho Power said on its website. 

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MISO, SPP Still on Hunt for Joint Transmission Under CSP

MISO and SPP appear undaunted in their pursuit of a beneficial interregional project after FERC’s rejection of exemptions to their joint study rules. 

The grid operators announced they still are in search of projects that improve resilience, reliability and transfer capability under their joint Coordinated System Plan (CSP) study process. They also said they are weighing proposing more benefit metrics to FERC to justify projects. 

The RTOs originally set out to perform a different type of CSP this year with more in-depth modeling on a 10-year horizon and a wider variety of benefits they said would have cast a wider net for projects. However, FERC in July denied their requested temporary exemptions. The commission said a limited waiver of requirements was not the best vehicle for changes to the study. (See FERC Denies MISO, SPP Waiver of Joint Study Process.)  

Now the RTOs say they are considering submitting a filing to FERC under Federal Power Act Section 205 to include more types of benefits in business cases for joint projects. They said drawing on more and different benefits is in line with FERC Order 1920, which laid out seven categories of transmission benefits. 

MISO and SPP’s joint operating agreement currently limits them to using only the value of avoided regional projects to measure the reliability and public policy benefits of interregional projects stemming from the CSP. 

The two grid operators have said measuring the reliability value of a project solely on its ability to avoid regional projects constricts their planners from analyzing projects’ usefulness in other areas, like expanded interregional transfer capability or fortification against weather extremes. 

During an interregional planning meeting Aug. 6, SPP Manager of Interregional Strategy and Engagement Clint Savoy said the RTOs would have more details on how the two might expand their benefit definitions under the CSP during the next joint meeting Oct. 24. 

“It’s something that we’re constantly talking about … how to approach changes we want to make to the process itself,” Savoy told MISO and SPP stakeholders. 

The RTOs also said that because FERC rejected the waiver, they will add 15-year-out modeling scenarios to this year’s CSP.

The JOA requires MISO and SPP, when conducting a CSP, to use multiyear modeling, which the RTOs interpret to mean using multiple model years, such as five, 10 or 15 years out. They initially wanted to model several different 2034 scenarios to land on transmission needs instead of studying the system at different points in time. 

MISO Interregional Planning Adviser Ashleigh Moore said 15-year models are in progress and would be complete in October or November. 

Moore said that if transmission needs prove to be “drastically different” with the addition of the 15-year-out modeling, the RTOs might open a second window for stakeholders to propose transmission solutions. MISO and SPP are accepting transmission project ideas for the CSP through Sept. 5 under their first submission window. 

The RTOs still are aiming for a “robust and comprehensive interregional planning process,” she said.  

SPP engineer Spencer Magby said the RTOs will model an extreme temperature scenario that will serve as a sensitivity to the study. However, the modeling would extend only to extremely low winter temperatures, not blistering high summer temperatures. 

Southern Renewable Energy Association Transmission Director Andy Kowalczyk said MISO and SPP probably should model systems stressed by summertime, especially given the springtime instances of load shedding in Louisiana for both RTOs. (See MISO Says Public Communication Needs Work After NOLA Load Shed.) 

MISO and SPP planning engineers said they might consider hot weather modeling additions. 

Missouri Public Service Commission Chief Utility Economist Adam McKinnie asked MISO and SPP to share data on their existing transfer limits so stakeholders can have a better idea of how projects could expand transfer capability. Engineers said they would consider the request. 

MISO and SPP said they would share draft transmission projects in October and prepare to make project recommendations in December. As for cost allocations of the projects, the RTOs plan to hold discussions on a cost-sharing design late in 2025 and over 2026. 

MISO and SPP’s CSP process never has produced a viable interregional project. Their Joint Targeted Interconnection Queue study, on the other hand, has culminated in $1.7 billion in projects to be funded by the interconnecting generation that benefit from the lines. 

MISO and SPP also aim to submit a proposal to FERC in 2026 to institute the smaller, congestion-relieving Targeted Market Efficiency Projects, with a similar process to MISO and PJM’s TMEP studies. 

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NEPGA Seeks Relief for ‘Improper’ Pay-for-Performance Costs in ISO-NE

The New England Power Generators Association (NEPGA) is seeking immediate action from FERC to address what it calls “serious flaws” in the design of ISO-NE’s Pay-for-Performance (PFP) mechanism, which the group says caused capacity resources to face $51 million in “improper charges” incurred during a capacity shortfall event June 24. 

In a complaint filed with FERC in late June, NEPGA wrote that resources with capacity supply obligations (CSOs) were required to provide power above their obligations and that capacity resources that performed during the event were charged millions to make up for the under-collection of penalties on resources that failed to perform (EL25-106). 

The association argued that imposing expensive PFP charges on resources that fulfill their capacity supply obligations undermines performance incentives and could dissuade resources from participating in future capacity auctions. 

ISO-NE’s PFP mechanism is intended to incentivize resource performance during capacity shortfall events. Resources that provide more than their CSO receive PFP credits, while resources that receive less than their obligation face PFP charges. Resources that lack CSOs can also receive payments by providing power during shortfall events.  

The system is intended to insulate ratepayers from the direct effects of charges and credits, with the charges for under-performers directly correlating with the payments to over-performers. To prevent resources from facing excessive penalties due to an outage, the PFP mechanism includes stop-loss provisions capping the total cost of penalties a capacity resource can incur each month. 

ISO-NE’s PFP rules have undergone multiple changes in recent years, and on June 1, the RTO increased the PFP rate from $5,455/MWh to $9,337/MW-hour. 

NEPGA wrote in its complaint that the PFP balancing ratio — which sets the portion of each CSO that resources are required to meet in an event — surpassed 1.0 on June 24 due to higher-than-expected load that exceeded the amount of obligated capacity. (See Extreme Heat Triggers Capacity Deficiency in New England.) 

The association noted that the balancing ratio averaged 1.031 over the three-hour emergency period June 24. NEPGA said this rate would have cost a perfectly performing 500-MW resource nearly $500,000 over the three-hour period and estimated the elevated balancing ratio “caused $25 million in improper charges to capacity resources” during the event. 

“Even suppliers that had delivered 100% of their promised supply obligation now faced charges under ISO-NE’s rules and a large number of resources reached their monthly stop-limit,” NEPGA wrote.  

Quoting from the movie “This Is Spinal Tap,” NEPGA stressed that “generators cannot give 110%. It is as certain as amplifiers not being capable of ‘one louder’ even if ‘these go to 11.’”

NEPGA also wrote that the RTO’s stop-loss rules led to the significant under-collection of PFP payments, which was charged to capacity resources which had not hit the stop-loss limit.  

“Capacity resources that did not reach their monthly stop-loss limit were charged an additional $26 million to make up the negative net surplus of capacity performance payments,” NEPGA said. It noted the PFP balancing fund also included $9 million in excess revenue caused by reserve shortages, which partly offset the under-collection of charges, reducing the balancing fund’s deficit to $17 million. 

When accounting for the offsetting costs, “the ISO-NE tariff charged capacity resources — including fully performing capacity resources — to recover this $42 million to provide maximum $9,337/MWh bonuses to resources performing above their capacity supply obligation,” the association wrote.  

‘Careful Evaluation’

To address the issue, NEPGA proposed to “cap the balancing ratio at 1.0 and split the bonus pool that gets collected to pay over-performers, with no post-hoc secondary charges imposed on capacity supply obligation holders to make up for any under-collection.” 

NEPGA wrote that these changes would mirror the PFP rules at PJM and noted that FERC in 2015 required PJM to impose a cap on its balancing ratio. 

The proposed changes would “adjust bonus payments to performing resources while still sending very strong financial incentives to perform during emergencies,” NEPGA wrote, adding that the changes would “ensure that the capacity market sends incentives to take on a capacity supply obligation.”  

NEPGA requested that FERC “set an immediate refund effective date” on the date of the complaint, noting that similar issues could occur before the end of the summer.  

In a filed response to NEPGA’s complaint, ISO-NE opposed NEPGA’s request for fast-track processing of the complaint, arguing the association failed to justify the need for immediate action. The RTO wrote that the complaint raises “complex questions” about the design of the PFP mechanism that are not well suited for fast-track processing. 

The RTO did not substantively comment on NEPGA’s proposed remedies, but wrote it is “misleading” to say the issues could be easily and quickly resolved by the proposed changes. 

“PJM’s version of pay-for-performance differs from New England’s version in important ways,” ISO-NE wrote, noting that PJM uses separate PFP rates for payments and charges, while ISO-NE uses a single rate. 

“A single performance payment rate that provides the same marginal incentive to perform is central to [ISO-NE’s] two-settlement, pay-for-performance market design,” ISO-NE wrote. “Transitioning to separate payment rates requires careful evaluation to ensure that it does not produce gaming opportunities.” 

ISO-NE also asked FERC to extend the deadline for responses to the complaint from Aug. 14 to Aug. 21, which the commission granted Aug. 5. The RTO said the extension is necessary to “provide the commission with a clearer indication of the full range of issues that are implicated.” 

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Duke Highlights Legislative Wins in Q2 Earnings Call

Duke Energy reported earnings of $1.25/share for the second quarter, and CEO Harry Sideris told analysts Aug. 5 the company also came out ahead with state and federal legislation.

With Republicans in control of both houses, the North Carolina legislature overrode a veto from Gov. Josh Stein (D) on July 29 and made the Power Bill Reduction Act (SB266) law, which cuts the state’s greenhouse gas emission-reduction commitments.

“As we ramp up generation investments to meet accelerating load growth, this legislation allows for annual recovery of financing costs for new baseload generation, supporting our credit profile and minimizing costs to customers,” Sideris said.

Stein’s veto statement argued that the bill would lead to higher costs for customers, as Duke and other load-serving entities have to burn more expensive fuel to generate power in the coming decades.

“Recent independent analysis of Senate Bill 266 shows that this bill could cost North Carolina ratepayers up to $23 billion through 2050 due to higher fuel costs,” Stein said. “This bill not only makes everyone’s utility bills more expensive, but it also shifts the cost of electricity from large industrial users onto the backs of regular people — families will pay more so that industry pays less. Additionally, this bill walks back our state’s commitment to reduce carbon emissions, sending the wrong signal to businesses that want to be a part of our clean energy economy.”

The law eliminates a requirement for Duke and other generators to cut emissions by 70% from 2005 levels by 2030. Sideris highlighted language that authorizes Duke to recover generation investments using construction work in progress (CWIP) adders, meaning it can collect money from ratepayers when plants are being built.

But Sideris said the law will make the state more attractive for growth and help Duke meet the higher demand that comes with new customers, including new data center investment of $10 billion by Amazon Web Services.

“It gives us some credit help with CWIP being able to recover annually,” he added. “But … our plan is still along the same lines as the all-of-the-above [approach] that we filed in the multiple [requests for proposals] that we’ve done. We’ll be … really looking at all resources that can support the growth that we’re seeing in North Carolina, and this bill just helps us manage that but also manage the customer affordability portion.”

On the company’s previous earnings call, Sideris was critical of a draft of the One Big Beautiful Bill Act that would have stripped tax credits for nuclear plants, but that language did not make it into the final law. (See Budget Bills Would End Energy Tax Credits Early, Claw Back Other Funding.)

“On the federal side, the preservation of nuclear production tax credits in the final budget reconciliation bill was a significant win for our customers,” Sideris said. “Only well-run, cost-efficient reactors are eligible to receive the credit. Our 11-GW nuclear fleet is the largest regulated fleet in the nation and earned $500 million of PTCs last year.”

In Ohio, Duke counts the enactment of House Bill 15 as a victory because it eliminates the electric security plans, which had governed utilities there for more than a decade, Sideris said. (See Ohio Governor Signs Utility Law Aimed at Enhancing Competition.)

In Florida, Duke announced a deal with Brookfield Asset Management, which will acquire a 19.7% share of Duke Energy Florida for $6 billion that will support a $4 billion increase in the utility’s five-year capital plan.

Duke is also preparing some regulatory filings that will seek to combine its utilities in the Carolinas, which have maintained some separation since the company bought Progress Energy more than a decade ago. It plans to file requests with FERC and both the North Carolina and South Carolina commissions this month.

In addition to large customers, the Carolinas are seeing demand grow as more people move there, and the company has plans to build 8 GW of new dispatchable supply by 2031 at all of its utilities, including 1 GW of uprates at existing plants and new generators, Sideris said.

“With turbines secured under our framework agreement with GE Vernova and gas supply contracted, we are confident in meeting the in-service timelines we have laid out for these new units,” Sideris said.

While uprates at existing nuclear plants are a firm part of its plan, Sideris said Duke would not commit to building new units until the risks, supply chains and workforces are addressed for both traditional and small modular reactors.

“We’re also going to have to have overrun protection from the federal government or others to be able to protect our customers and our investors from any overruns on these projects,” Sideris said. “And then lastly, we’re going to have to have a means to make sure that we’re protecting the balance sheet as we’re building these facilities. So, until we get those items resolved, we’re still looking at solar, gas, and upgrading and getting everything that we can out of our current assets.”

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Google Strikes Demand Response Deals with I&M, TVA

Google has reached agreements with Indiana Michigan Power (I&M) and the Tennessee Valley Authority to reduce power use by its data centers during critical periods. 

The company said Aug. 4 that it has been working to bring demand flexibility to its data center fleet but the new demand response agreements are the first time it is targeting machine-learning workloads to accomplish this. 

In a demonstration project with Omaha Public Power District, Google reduced the power demands of its machine-learning workloads during three grid events in 2024. This set the stage for similar efforts in other regions. 

The rise of data centers, with their 24/7 demand for large amounts of electricity, has left the electricity sector and policymakers excited about the lucrative potential they represent and anxious about the challenge of realizing that potential: There appears not to be enough capacity to meet the highest projections of peak demand and no way to add capacity quickly and inexpensively. 

A Duke University study released earlier in 2025 addressed this quandary by looking at the kind of arrangement Google is announcing with the two utilities: temporary curtailment of load. 

As much as 126 GW of new demand could be handled with existing generation, the authors concluded, if data centers cut their energy use by as little as 1% during peak periods. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) 

Google said it is working to develop this ability to reduce or shift power demand during certain hours and certain times of the year. 

Along with the benefits to the grid and to grid operators, DR has the advantage of speeding up the interconnection process and bridging the gap to long-term clean energy solutions, Google said. 

The company said its first such efforts involved shifting non-urgent computing tasks such as processing videos for YouTube, and it sees significant further opportunity through development of DR for machine-learning workloads. This will let it grow artificial intelligence capabilities even in regions where generation and transmission are constrained, it said. 

Google said demand flexibility will be possible only in certain locations in these early stages and faces a finite potential, given the high level of reliability the company needs for some of its services. It expects DR to be part of a portfolio of solutions that includes new generation and transmission. 

Contract Details

I&M submitted the Google contract to the Indiana Utility Regulatory Commission on July 30 (46276). 

It pertains to Google’s new data center in Fort Wayne and is similar to programs currently available to the utility’s residential and commercial/industrial customers, I&M President Steve Baker said in a news release. Google announced the $2 billion Fort Wayne project in April 2024; I&M energized it seven months later. 

“Google’s ability to leverage load flexibility will be a highly valuable tool to meet their future energy needs,” Baker said. 

It would also help I&M. The utility said that if the IURC approves the contract, “this agreement will reduce I&M’s long-term generation requirements and financial commitments to benefit all I&M customers.” 

In its petition to the IURC, I&M said the contract has two key aspects: a clean capacity agreement by which Google will transfer to I&M long-term accredited capacity from clean energy resources that the utility will use to meet a portion of its state retail capacity obligations as part of its PJM fixed resource requirement plan, and “a custom demand response offering” to reduce I&M’s peak load in times of high demand, thereby reducing the utility’s capacity obligation and transmission requirements to serve its customers.  

Because the clean capacity agreement will be used to meet its load obligation for all Indiana customers, I&M proposes to recover associated costs in the same way it recovers capacity-related purchase costs: through its Resource Adequacy Rider. It also proposes to recover through the rider any demand response credits provided to Google. 

Two days after I&M submitted the petition, the Citizens Action Coalition of Indiana petitioned to intervene, citing the potential impact on rates charged to residential customers and services provided to them.