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December 26, 2025

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Regulators Focus on Energy Affordability at NECPUC Symposium

MYSTIC, Conn. — Government officials and industry executives discussed how to mitigate rising energy costs in New England at the 77th annual New England Conference of Public Utility Commissioners Symposium May 19 and 20.

Moderating a panel on affordability, Ron Gerwatowski, chair of the Rhode Island Public Utilities Commission, compared the different components of a customer’s bill to a large stack of pancakes. While no one pancake is overwhelming on its own, “when viewed as a tower of components, then you see the problem,” he said.

“With the possible exception of the supply costs … I don’t think it’s fair to blame any one component for the high bills,” he added.

While all speakers emphasized the importance of affordability, there were few easy answers and limited consensus about how to meaningfully cut costs on bills. (See related story, ISO-NE Open to Asset Condition Review Role amid Rising Costs.)

Dan Dolan, president of the New England Power Generators Association, said energy prices have trended down over the past 10 years when adjusting for inflation, and added that “we are in a time of some of the lowest capacity prices in the history of New England.”

Dolan acknowledged that New England faces “massive volatility in cold winters” but argued that “as I look at the data, I don’t know where else to really squeeze on the supply end without pushing out resources that are really performing.”

Looking forward, with above-market-rate clean energy contracts set to take effect and load growth likely to accelerate in the coming years, “the bottom line is that rates are probably going to go up,” Dolan said.

Doug Horton, vice president of distribution rates at Eversource Energy, said “affordability for our customers means looking at the entire stack,” while noting that the company’s distribution charges are “generally aligned with other utilities across the country providing similar services.”

Meanwhile, representatives of climate and energy efficiency organizations made the case their portions of the stack were not the drivers of the region’s high energy costs.

“I don’t see a correlation between recent bill increases and the macro-trends we’re seeing on energy efficiency,” said Maggie Molina, executive director of Northeast Energy Efficiency Partnerships. Molina said energy efficiency typically provides a roughly 2-to-1 return on investment and warned policymakers that rolling back energy efficiency programs would bring long-term affordability consequences.

Jamie Dickerson, senior director of clean energy and climate programs at the Acadia Center, said it was “a cold, tough winter, there’s no doubt about it,” but added that “the primary driver of costs was gas and oil, not renewable energy.”

He said adding more clean energy to the grid will help diversify the supply mix and drive down market volatility. The New England Clean Energy Connect transmission line, which is slated to come online at the end of 2025 should save ratepayers millions annually, while the winter-peaking power production profile of offshore wind should provide significant relief for winter price spikes, Dickerson said.

He resisted the idea that adding new pipeline capacity to the region would lower consumer costs, telling attendees that “we actually don’t see that there is an economic case for the buildout of pipelines into New England.”

Arguments for new pipelines to New England have seen some revived interest under the administration of President Donald Trump, who was elected with strong financial backing from the fossil fuel industry, which spent more than $219 million during the 2024 election cycle, according to Yale Climate Connections.

“We need more pipelines,” said Cynthia Niemeyer-Tieskoetter, natural gas markets policy adviser for the American Petroleum Institute. She added that “the system is already facing constraints” during extreme winter weather, with electricity demand projected to increase in the coming decades.

Niemeyer-Tieskoetter lauded the White House for its “pro-energy agenda” and called for permitting reform to reduce the challenges of building new energy infrastructure.

Earlier in the week, New York Gov. Kathy Hochul (D) appeared to agree to concessions relating to a potential new gas pipeline to the Northeast in exchange for the Trump administration lifting the stop-work order on Empire Wind. (See related story, BOEM Lifts Stop-work Order on Empire Wind.) Connecticut Gov. Ned Lamont (D) also signaled he’s open to a new pipeline project.

Connecticut Gov. Ned Lamont | © RTO Insider 

While increased gas capacity in New England would ease some of the region’s pipeline constraints during cold periods — when heating demand backed by firm contracts limits gas generators’ ability to access fuel — it is unclear who would pay for this new capacity, or whether it would be a cost-effective solution in the long term.

Gas generators generally do not receive enough incentives to contract for firm fuel, and it is not clear whether gas distribution companies in New England would be willing to take on the costs of new pipeline infrastructure. In 2016, the Massachusetts Supreme Judicial Court ruled the state’s electric ratepayers could not be charged with the costs of new gas infrastructure, a major blow to a proposed $3.2 billion pipeline project by Enbridge, which ultimately was canceled in 2017.

Massachusetts Gov. Maura Healey (D) served as the state attorney general at the time of the SJC ruling and was a vocal critic of the plan to fund pipelines through electric rates. (See Massachusetts Regulators Endorse Pipeline Contracts.) Elected governor in 2022, Healey’s administration has taken significant steps to transition Massachusetts away from natural gas reliance as the state works to meet its statutory emissions limits.

Doubling down on natural gas likely would undermine state decarbonization efforts, as methane is an intense short-lived greenhouse gas and could risk creating expensive stranded assets as states electrify and move to renewable power.

Matt Nelson, principal at Apex Analytics and former chair of the Massachusetts Department of Public Utilities, said it is “critical” to coordinate clean energy policy to avoid unnecessary gas investments as states transition to clean energy.

“You could see bills going up in the near term to help avoid these long-term costs, and you have to be good about messaging that,” Nelson said, adding that, in the long term, “you’re going to have to build clean generation to meet electrifying customers.”

“In the short term, you may see some increased emissions as people transition from gas to electric heating,” Nelson said. “If you’re committed to adding clean resources, however, those emissions will come down over time.”

Lamont spoke briefly at the symposium prior to its conclusion, pitching lawmakers on the importance of regional collaboration to help support new and existing generation in the region. He highlighted the Millstone Nuclear Power Plant, which is owned by Dominion Energy and is under contract with Connecticut’s electric distribution companies through 2029.

“I like Millstone. … It represents about half of our power and almost all of our carbon-free power,” Lamont said. “I think we ought to give Dominion the incentives they need to continue, and I can do that a lot more effectively with the other governors.”

Lamont advocated for a formal collaboration between Northeast energy officials to ensure resource adequacy in the coming years. He noted that the Northeastern governors will meet in the coming weeks and said this concept is at the “top of the agenda.”

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BPA Approves $700M Plan to Boost Columbia Generating Station Output

The Bonneville Power Administration has approved a $700 million plan to increase the output of the Pacific Northwest’s only commercial nuclear plant by 162 MW by 2031. 

BPA said May 22 that it approved implementation of an extended power uprate (EPU) project for the 1,207-MW Columbia Generating Station (CGS) it publicly proposed in April. (See Northwest’s Only Nuclear Plant Could Get Uprate.) 

The federal power agency also said CGS will gain an additional 24 MW of capacity from a series of energy efficiency upgrades made during the plant’s 2027, 2029 and 2031 refueling cycles, bringing the total increase to 186 MW. 

Located near Richland, Wash., CGS is owned and operated by Energy Northwest, a consortium of Washington utilities. BPA markets the energy produced by the plant and covers its costs, which are included in the revenue requirements of the agency’s power services rate structure. 

“This is a great value for ratepayers in the Pacific Northwest,” BPA Administrator John Hairston said in a statement. “Upgrading an existing resource to provide additional reliable energy will help BPA keep pace with its customers’ growing electricity needs and keep rates low.” 

“We applaud BPA for its decision to approve this project and for its strategic vision in advancing our region’s future with additional, reliable capacity that nuclear energy can provide,” Energy Northwest CEO Bob Schuetz said. “Their leadership in supporting this initiative underscores a commitment to affordable and carbon-free electricity for the Northwest region, including our public power member utilities and their customers.” 

BPA and Energy Northwest said the EPU will increase electrical output at the plant by upgrading and replacing key pieces of equipment, including turbines, heat exchangers and the plant’s generator. The process also will involve 30 individual upgrades focused on increasing the size of pumps and motors. 

During an April 8 meeting to discuss the proposed uprate, a BPA representative said the agency’s resource program includes the CGS EPU in its least-cost portfolio for meeting future customer needs, reducing the amount of new solar and wind capacity it otherwise would need to procure. 

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2026 to be ‘Bridge Year’ for NERC Budget

NERC has postponed its work on a new three-year plan that would have guided its work starting in 2026 amid recent economic and political uncertainty, CEO Jim Robb said during an informational webinar May 21 on the ERO’s draft 2026 Business Plan and Budget. 

Robb reminded attendees that NERC is nearing the end of its current three-year plan, which the ERO created in 2022. NERC had planned to create another plan in 2025, but leadership decided a different approach was needed in light of the uncertainty that has grown since the beginning of President Donald Trump’s second term in January 2025. 

“When we started that planning process in earnest, we concluded that that was really kind of a fool’s errand at this point in time,” Robb said. “We decided that we should probably not do a robust three-year plan this year, but … let a few things mature over the balance of this year.” 

The efforts that need to “mature” include NERC’s Large Loads Task Force and the Modernization of Standards Processes and Procedures Task Force created by the Board of Trustees in February to examine the ERO’s standard development process for opportunities for improvement. (See “Task Force to Examine Standards Process,” NERC Leaders Highlight Canada-US Collaboration.) 

Instead of setting an overarching plan, Robb said NERC will “approach 2026 as a bridge,” with the budget covering only a single year. The ERO hopes to resume its three-year planning process in 2026, creating a plan for 2027-2029. 

As for the 2026 budget, which NERC posted for public review the day after the webinar along with the draft budgets of the regional entities, Robb said the ERO is “painfully aware of all the austerity measures” underway at the federal government and “took a very hard look at what we really needed [for] the core needs of” the ERO’s mission. 

“We all know that the risks aren’t taking a timeout. If anything, they’re accelerating and expanding,” Robb said. “So you’ll see not a flat budget for 2026, but, I think, a very prudent budget in light of everything going on in the world around us.” 

NERC CFO Andy Sharp provided more details on the draft budget, which is set to increase $5.3 million over the 2025 budget to $128.3 million. The organization’s assessment, which load-serving entities pay to support the ERO’s work, also is expected to rise by $5.3 million, to $113.7 million, with the remaining budgeted expenses to be covered by its other sources of funding, such as fees from the Electricity Information Sharing and Analysis Center’s Cyber Risk Information Sharing Program and vendor affiliate program. 

The biggest driver of the projected budget increase is personnel, Sharp said, with NERC planning to add 9.1 full-time-equivalent positions in 2026 relating to engineering, security and engagement. These additions, along with an average pay increase of 4% and increased spending on benefits, add up to a total budget of $76.2 million, $4.7 million higher than 2025. 

Operating expenses are expected to decrease by 1.4% to $43.3 million, which Sharp attributed primarily to the end of the lease on NERC’s Atlanta office in October 2025. The ERO will move operations to its office in D.C. 

Personnel is the largest increase in the REs’ budgets as well, with every entity except SERC Reliability planning to add staff in the coming year for a total of 30.4 new FTEs across the ERO Enterprise. Nearly 25% of the new hires are earmarked for outreach, training and education, followed by standards with 10%. 

Overall, all of the RE budgets are projected to grow, with the Northeast Power Coordinating Council planning the biggest increase, at $2.7 million — to $28.4 million — and WECC growing the least, with $800,000, to $40.1 million. WECC’s budget is the highest of the REs; the Texas Reliability Entity will remain the lowest, with $21.6 million, up from $20.3 million in 2025. 

NERC will accept comments on the draft business plans and budgets for 30 days beginning May 23, Sharp said. On July 22, the Member Representatives Committee’s Business Plan and Budget Input Group will review NERC’s final budget, which will be submitted to the board at its meeting Aug. 14. NERC and the REs plan to file their final budgets with FERC by Aug. 25. 

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House Passes Reconciliation Package that Would End Energy Tax Credits

The House of Representatives narrowly passed President Donald Trump’s “One, Big Beautiful Bill” that would extend tax cuts for individuals and render energy tax credits effectively useless. 

After meeting through the night, the House passed H.R. 1 by 215-214 in an early morning vote May 22. The Senate has yet to take up the package, but the bill is being passed through reconciliation, meaning it is exempt from the filibuster. 

“Today, the House has passed generational, nation-shaping legislation that reduces spending, permanently lowers taxes for families and job creators, secures the border, unleashes American energy dominance, restores peace through strength, and makes government work more efficiently and effectively for all Americans,” House Speaker Mike Johnson (R-La.) said in a statement. 

The bill would sunset tax credits for renewables, storage and nuclear earlier than current law and add new restrictions to foreign components. (See House Committees Mark up Budget Bill that Guts Energy Tax Credits.) 

It also would require that renewable and storage projects be completed — rather than begin construction — by the end of the year to qualify. Nuclear plants were spared this provision. (See related story, So far, Nuclear Energy Credits Remain in Reconciliation Bill.)

American Clean Power Association CEO Jason Grumet called on the Senate to reject the House’s hardline approach to winding down tax credits, which last were updated by the Inflation Reduction Act of 2022, passed by Democrats using reconciliation. 

“This morning, the House voted to immediately end the clean energy tax incentives that provide economic growth, good-paying jobs and low-cost electricity to millions of Americans,” Grumet said in a statement. “By a margin of one vote, the House voted to retreat in our competition with China for manufacturing jobs and to weaken our technology sector in the global race for digital dominance.” 

American Council on Renewable Energy President Ray Long said growing demand for electricity requires generation of all kinds, and the bill would set back Trump’s goal of reliable and affordable power. 

“ACORE is committed to working with Congress and President Trump to make any improvements to this legislation and help them deliver on his promise to slash energy costs for Americans by 50%,” Long said in a statement. “It’s time to achieve American energy dominance across all technologies.” 

Advanced Energy United also argued that the bill would lead to reliability issues and raise prices. 

“At a time of growing demand, economic uncertainty and fierce competition, we need smart, certain tax policies that are pro-growth,” CEO Heather O’Neill said in a statement. “Last year alone, the advanced energy industry added over 50 GW of new capacity to the U.S. grid, generated an estimated $400 billion in domestic revenue and led the way with critical investments in energy storage, nuclear power and American manufacturing. This work must continue without delay to power the U.S. economy and to keep the lights on across the country.” 

The Solar Energy Industries Association also called on the Senate to change the legislation, with CEO Abigail Ross Hopper saying that deploying solar and storage is the “only way” the grid can keep up with growing demand. 

“If this bill becomes law, America will effectively surrender the AI race to China, and communities nationwide will face blackouts,” Hopper said in a statement. 

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So far, Nuclear Energy Credits Remain in Reconciliation Bill

Nuclear energy got at least a temporary boost May 22 as the reconciliation bill hashed out in the House of Representatives spared it from most of the policy changes aimed at other forms of clean energy.

How nuclear energy fares in Senate deliberations and whether the provisions extend far enough into the future to benefit the slow-moving nuclear industry remains to be seen.

The 45U zero-emission nuclear power production credit would remain in place almost as long as specified in current law rather than gradually phasing out sooner, as specified in one of the drafts of the bill.

Also, a new advanced nuclear facility or expansion of an existing nuclear facility would remain eligible for production tax credits and investment tax credits if construction begins by the end of 2028 — which may be a tight timeline for some of the new designs that still must complete their R&D phases and then undergo regulatory review.

Nonetheless, it is a much better picture than the one that faces other clean energy technologies under the Republican-engineered megabill.

Law firm Akin Gump Strauss Hauer & Feld wrote in a May 22 alert:

“While advanced nuclear facilities would only experience a one-year credit window haircut under the bill, other technologies that currently qualify under the ‘tech-neutral’ Clean Electricity Production Tax Credit (§ 45Y) and the Clean Electricity Investment Tax Credit (§ 48E) would be eliminated under the bill if construction of the applicable facility did not begin before 60 days after enactment.” (See House Passes Reconciliation Package that Would End Energy Tax Credits.)

Also on May 22, Oak Ridge National Laboratory highlighted the work it’s doing to connect nuclear developers with national laboratory resources and expertise amid the push for more and better nuclear generation.

Oak Ridge pointed to its collaboration with Elementl Power on a data-driven approach to siting advanced nuclear projects, intended to make siting less complicated and time-consuming.

Elementl and Google on May 7 announced an agreement to pre-position three sites for development of at least 600 MW of advanced nuclear generation on each.

Google is committing early-stage development capital as Elementl prioritizes sites for development and continues its evaluation of technology, engineering procurement and construction.

Elementl is supplementing its in-house methodology with the Oak Ridge Siting Analysis for power Generation Expansion (OR-SAGE) tool, which uses GIS data including population density, water proximity and seismic data to identify potential sites for small modular reactors.

Google and Kairos Power in October 2024 announced the first corporate agreement for multiple advanced reactors. It envisions deployment by 2035 of 500 MW of the high-temperature salt-cooled reactors Kairos is designing.

Elementl is not designing its own reactor. It is a technology-agnostic developer creating a procurement model that offers turnkey development, finance and ownership solutions to companies that may not want to own or operate reactors themselves.

Elementl COO David Faherty said his company gained access to the national laboratory system through a Gateway for Accelerated Innovation in Nuclear voucher. This allowed it to overcome technological and commercialization challenges and accelerate predevelopment work that Elementl would have needed years to replicate on its own.

The OR-SAGE platform “gives us a data-driven foundation to screen regional siting options efficiently and allows our team to layer in our own project-specific criteria with greater speed and confidence,” Faherty said.

The growing support being shown for advanced nuclear technology can go only so far in making its development and deployment progress at a faster pace and lower cost. Pioneering projects are expected to be expensive, making federal policy support an important part of project finance, and making the timing of credit expiration a critical detail as the reconciliation bill goes to the Senate.

Kairos has begun construction of its Hermes demonstration reactor in Oak Ridge, for example, and intends to use it inform and de-risk subsequent commercial projects. But Hermes is not expected to be operational until 2027.

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Arizona Utilities Explore Expanded Use of Nuclear

Arizona utilities are seeking U.S. Department of Energy funding to help plan for more nuclear power facilities in the state.

Representatives from Arizona Public Service (APS), Tucson Electric Power (TEP) and Salt River Project (SRP) discussed their plans May 21 during an Arizona Corporation Commission workshop on advancing nuclear power generation.

APS is leading the effort, working in partnership with TEP and SRP. The goal is to select a site for a future nuclear facility and submit an early site permit application to the Nuclear Regulatory Commission, according to Brian Cole, vice president for resource management at APS.

In evaluating sites, the utilities will consider the availability of land, water, transmission infrastructure and workers. Coal-fired power plant sites are one possibility, as are the site of the Palo Verde nuclear generating station and other locations.

To help with the planning, the utilities have applied for funding through the Generation III+ Small Modular Reactor program in the DOE’s Office of Clean Energy Demonstrations.

The utilities are applying for funding in the “fast follower” category, which will provide up to $100 million to address hurdles the U.S. nuclear industry has faced in areas such as design, licensing, supply chain and site preparation. Awardees must match the DOE funding.

DOE opened the funding opportunity in October and reissued the solicitation in March. The Arizona utilities submitted a revised application in April. They expect a decision by the end of the year.

Small modular reactors could provide reliable power for energy-intensive applications such as industrial uses, artificial intelligence and data centers, DOE said in a March announcement. SMRs offer flexible deployment due to their compact size and modular design, the agency added.

“Light-water small modular reactors could also leverage the existing service and supply chain supporting the country’s current fleet of light-water reactors, helping speed up the near-term deployment of new nuclear reactors,” DOE said.

Technology Options

Despite the DOE grant’s focus on Generation III+ SMRs, the Arizona utilities are remaining open for now to different types of nuclear technology, Cole said.

“We also want to make sure we keep the door open for both SMRs and large-scale nuclear,” Cole told commissioners.

An early site permit (ESP) from the NRC may consider a range of technologies, according to Tom Cooper, SRP’s senior director of future system assets and strategy. The ESP, which is a voluntary permit, is a way to reduce the risk surrounding a nuclear project, he said.

An early site permit “does not authorize construction or operations, but it is a significant de-risking factor, because it gives you a very strong indication that the … NRC finds that site suitable to host nuclear.”

Palo Verde’s Status

APS operates the 4.2-GW Palo Verde nuclear power plant, the largest power producer on the Western grid. It shares ownership of Palo Verde with six utilities: SRP, El Paso Electric, Southern California Edison, Public Service Company of New Mexico, Southern California Public Power Authority and the Los Angeles Department of Water and Power.

Palo Verde is the only nuclear plant that’s not next to a body of water. The facility uses reclaimed wastewater.

“We continue to evaluate water strategy at the station,” said John Hernandez, vice president of site services at Palo Verde. One idea is to use lower-quality wastewater.

The first of Palo Verde’s three reactors is set to mark 40 years of operation in June. In 2011, the NRC granted Palo Verde a 20-year license extension that runs to 2047. An application for an additional 20-year license extension is being considered, with a target date for approval of 2029, Hernandez said.

Although APS has the largest ownership stake in Palo Verde, at 29%, followed by SRP at 20%, ownership shares in a new nuclear facility would be subject to negotiation, Cole said.

Commissioner Lea Marquez Peterson asked whether California utilities might want to be involved in a new Arizona nuclear facility, a move that might help reduce risk for the Arizona utilities.

California entities “don’t have that political openness to placing a new nuclear plant in their state, but seem to be open to keeping the energy,” she said.

Cole said the current focus for a potential nuclear project is Arizona’s needs.

“We’re looking at this right now as an Arizona project, but that doesn’t mean … that there won’t be additional partners in the future,” he said.

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CAISO Postpones EDAM Congestion Revenue Decision

CAISO has delayed its final decision on how to allocate congestion revenues in its Extended Day-Ahead Market (EDAM) after receiving comments from stakeholders asking for more analysis. 

CAISO planned to vote on its draft final proposal in late May but decided to hold off until June. Adjusting the proposal’s planned approval date has “allowed us to further explore additional enhancements suggested by stakeholders,” said Anna McKenna, CAISO vice president of market design and analysis, at a May 20 WEM Governing Body meeting. 

The congestion revenue initiative is a top priority for CAISO in 2025. The organization received comments from PacifiCorp that questioned the way congestion revenues will be allocated in the proposed EDAM design. The primary concern is whether certain congestion revenues should be allocated to the balancing area in which the congestion costs accrued, or to the neighboring EDAM balancing authority area where the transmission constraint is located, specifically in cases in which parallel — or loop — flows occur. 

On May 19, CAISO published a revised draft final proposal, which fine-tunes the allocation of parallel flow congestion revenues “based on the exercise of eligible firm point-to-point and Network Integration Transmission Service and Open Access Transmission Tariff transmission rights.” 

The revised draft provides details about congestion revenues that are not received under the current design for the EDAM entity. Any remaining parallel flow congestion revenue accrued because of a transmission constraint in a neighboring EDAM balancing area would be allocated to the area where the binding transmission constraint is located, CAISO wrote. 

The revised draft is consistent with FERC requirements that say congestion revenues accruing internal to an EDAM balancing area because of an internal transmission constraint are allocated fully to that balancing area — i.e., where the transmission constraint is located, CAISO wrote.  

“Stakeholders continued to note the concern that the proposed design in the near term may incent self-scheduling by transmission customers in order to receive a congestion hedge, a ‘use it or lose it’ concept to the exercise of transmission rights,” CAISO said in the draft. “In this context, stakeholders indicated broad support for an economic bidding enhancement to enable parallel flow congestion revenue allocation for balanced cleared market schedules based on economic bids, not only self-schedules.” 

The revised proposal includes an example of a load event that shows how much money would be distributed to four balancing areas: BAA-A, BAA-B, BAA-C and BAA-D. In the example, the market footprint net settlement is an over-collection in congestion revenue of $135,800. Under the current EDAM design, all of the congestion revenue is allocated to the BAA where the constraint is modeled, CAISO wrote. However, under the revised draft, the congestion revenue associated to balance OATT self-schedules is allocated to the EDAM entity where OATT rights are exercised. 

CAISO will hold a stakeholder meeting on the revised final draft proposal May 27, with comments due by June 2. CAISO plans to publish a final proposal June 6. 

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U.S. Senate Approves Resolution to End California’s EV Mandate

The U.S. Senate voted 51-46 to approve a resolution of disapproval against California’s Clean Air Act waiver that allows it to mandate that 100% of the cars sold in the state be electric vehicles starting in 2035. 

The measure, which the Senate approved late May 21, was approved by the House of Representatives earlier in the month and now moves to the White House; it was a goal of President Donald Trump’s Day 1 executive order on “Unleashing American Energy.” 

Sen. Shelley Moore Capito (R-W.Va.) helped lead the effort under the Congressional Review Act in the Senate. She welcomed the outcome in a statement decrying Democrats’ efforts to block the vote. 

“The impact of … California’s waiver would have been felt across the country, harming multiple sectors of our economy and costing hundreds of thousands of jobs in the process,” Capito said. 

Democrats said the Republicans “went nuclear” to get around the 60-vote requirement to overcome a filibuster to pass the resolution ending the mandate, overruling the Senate parliamentarian, who had found the waiver was not subject to the CRA. 

“Under this logic, the Trump administration could send an endless stream of non-rule actions to Congress, going back to 1996, including: vaccine approvals, broadcast licenses, merger approvals and any number of government decisions that apply to President Trump’s long list of enemies,” Sen. Alex Padilla (D-Calif.) said in remarks on the Senate floor. “All it would take is a minority of 30 senators to introduce related bills, and the Senate would be bogged down voting on agency grocery lists all day.” 

California Gov. Gavin Newsom (D) blasted the Senate vote for going around normal procedures and promised to challenge the resolution. 

“We won’t stand by as Trump Republicans make America smoggy again — undoing work that goes back to the days of Richard Nixon and Ronald Reagan — all while ceding our economic future to China,” Newsom said in a statement. “We’re going to fight this unconstitutional attack on California in court.” 

World Resources Institute Senior Fellow Dan Lashof said the resolution’s approval goes against nearly 50 years of precedent that has allowed California and other states to adopt vehicle emissions standards that exceed federal rules. 

“The U.S. auto industry’s competitiveness in the global market depends on innovation, which has historically been and continues to be driven by California standards,” Lashof said. “People across the country want cleaner, more efficient cars, trucks and school buses, and the cleaner air that results.” 

Twelve other states have passed measures to use the standards developed under California’s waiver, the Consumer Energy Alliance said in a statement welcoming the Senate’s vote. 

“The Senate’s actions today represent a crucial step toward preserving consumer choice by preventing policies that would make energy and transportation more expensive and less reliable for everyday Americans,” CEA President David Holt said. “We urge President Trump to swiftly sign House Joint Resolution 88 into law.” 

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NERC Standards Committee Rejects IBR Definitions Request

A proposal at the monthly meeting of NERC’s Standards Committee to reject a standard authorization request (SAR), despite its support from industry stakeholders in a 2024 comment round, prompted a debate among the group’s members over the appropriateness of the action.

At issue was an SAR that the SC accepted in July 2024, proposing to update NERC’s Glossary of Terms to add owners and operators of inverter-based resources (including those not currently subject to NERC’s standards) to the glossary definitions of generator owner and generator operator. The SC assigned the SAR to the standard drafting team for Project 2024-01 (Rules of Procedure definitions alignment — generator owner and generator operator).

Presenting the proposal, NERC Manager of Standards Development Alison Oswald explained the SDT reviewed the comments on the SAR from a comment round in August and September 2024. The review was delayed by the need to focus on an SAR assigned to the project earlier.

SDT members concluded they already achieved the SAR’s objective through other revisions to the GO and GOP definitions. The team also considered it best to avoid IBR-related definitions because they are being addressed by Project 2022-02 (Uniform Modeling Framework for IBR). The SDT therefore recommended the committee vote to reject the SAR, with a letter of explanation to the submitters, which include the American Public Power Association, the Electric Power Supply Association, the Large Public Power Council and the Transmission Access Policy Study Group.

But Marty Hostler of the Northern California Power Agency objected, pointing out the SAR received 68 positive comments from industry stakeholders against 22 negative ones and professing himself “not clear exactly why the consensus is being ignored.” He added that the SDT members “haven’t even asked the commenters if they feel that [the team] has addressed the issues.”

“It also says in the Standards Processes Manual [SPM] that NERC staff and the drafting team should be giving ‘prompt consideration to written views and objections.’ Well, this wasn’t prompt at all,” Hostler continued. “The comments were requested and closed in September of last year, and the comments weren’t even addressed till March.” He also pointed out the SAR for Project 2022-02 does not permit the SDT to create definitions.

Responding to Hostler, NERC Director of Standards Development Jamie Calderon described the support from industry in more nuanced terms, saying “there were industry participants who approved of one or more … definitions and some who disapproved of one or more … definitions.” In addition, Calderon clarified that SDTs do have the ability to consider definitions … within the realms of” their work.

SC Chair Todd Bennett, of Associated Electric Cooperative Inc., reminded attendees “the SPM only gives us two options on this … either [to] authorize drafting or … reject the SAR.” But, he continued, NERC’s standards development process provides “other ways to influence that path and provide feedback and input.”

The proposal to reject the SAR ultimately passed, with Hostler and four others voting against it. Nine members voted in favor and six abstained.

Additional Actions

Several other standards items passed the SC with comparatively little discussion and no objections.

First, members voted to approve the posting of proposed reliability standard MOD-026-2 (Verification and validation of dynamic models and data), developed under Project 2020-06 (Verifications of models and data for generators).

The standard, found on Page 11 of the agenda, is meant to address FERC’s Order 901, issued in 2023, which required NERC to develop standards to improve the reliability of IBRs. (See FERC Orders Reliability Rules for Inverter-Based Resources.) It will be posted for a 26-day formal comment period, with ballots conducted during the last 10 calendar days.

The SC next approved the appointing of three new members to the SDT for Project 2020-06, which Calderon explained was intended to “round out the drafting team” after several recent departures.

Finally, the committee voted to accept an SAR aiming to modify NERC’s Critical Infrastructure Protection (CIP) standards by grouping protected cyber assets (PCAs), electronic access control or monitoring systems (EACMS), and physical access control systems (PACS) together in a single standard as “CIP applicable” systems. Oswald told attendees this move will bring clarity to NERC’s enforcement process.

Currently, a failure to appropriately identify PCAs, EACMS and PACS is addressed under CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments). But Oswald said this approach is only a “temporary solution” that poses an administrative burden on both the industry and the ERO.

The SAR will be posted for a 30-day formal comment period and assigned to Project 2021-03 (CIP-002).

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ISO-NE Open to Asset Condition Review Role amid Rising Costs

With projects to replace deteriorating transmission infrastructure adding billions of dollars to New England electric bills, ISO-NE has announced it’s open to taking on a limited “asset condition reviewer” role, intended to help increase oversight on the projects. 

“Given the significant benefits to the region from a robust process and independent review of asset condition projects (ACPs), we are now exploring the issue further,” ISO-NE wrote in a memo May 15. 

While the scope of the role has yet to be determined, the RTO has insisted it could take on only a strictly advisory role and would not review the prudence of investments or assume any legal liability. The regional transmission owners would retain the right to decide whether to move forward with individual projects.  

The rising costs associated with ACPs have drawn increased scrutiny over the past two years. There are about $6 billion in asset condition projects listed as proposed, planned or under construction in ISO-NE’s ACP project list, while more than $5 billion in asset condition projects have come online since the start of 2015. 

According to a 2024 report by the Rocky Mountain Institute (RMI), asset condition spending in New England “increased eightfold from 2016 to 2023” and now makes up a majority of pooled transmission system spending in the region.  

The high costs are not limited to New England; RMI’s report noted that the portion of residential electric bills spent on transmission and distribution increased from 10% in 2005 to 24% in 2020. The bulk of this added spending has gone to local projects, as the U.S. has built far fewer new high voltage transmission lines in the early 2020s compared to the prior decade.  

Along with rising costs, New England officials have expressed concern about a lack of transparency and regulatory oversight on the projects, with some arguing transmission owners have abused the process to increase spending.  

“These asset condition projects frequently do not receive oversight from state regulatory authorities, as rebuilding aging assets is often exempt from state regulatory processes,” said Claire Wayner of RMI, one of the authors of the asset condition report, speaking at the annual symposium for the New England Conference of Public Utility Commissioners (NECPUC) on May 20.  

While the projects are subject to a prudence review at FERC, the formula rate process provides “very few opportunities for oversight of these projects,” Wayner added.  

Some asset condition projects have drawn specific concern from state officials, including a $385 million line rebuilding project proposed by Eversource Energy in New Hampshire. (See New England States Raise Alarm on Eversource Asset Condition Project.) 

Recently, a couple of projects presented at the NEPOOL Reliability Committee highlight potential discrepancies in how transmission owners approach asset condition projects. Vermont Electric Power Co. (VELCO), a transmission company collectively owned by the states’ distribution utilities and structured to return profits back to customers, proposed to replace 41 wooden structures on a 115-kV line, with a projected cost of $5.8 million.  

At the same meeting, Eversource, an investor-owned utility company, presented an update on a project to replace 41 wooden structures on a couple of sections of 115-kV line in Connecticut. The project’s estimated cost is over $16 million, more than double the cost of VELCO’s similar project. 

While Eversource serves roughly half the load in the region, it’s responsible for 79% of all spending in New England on ACPs that have come online since 2015, according to ISO-NE data. The company has stressed its investments are critical to preserving the reliability of its aging grid. 

“Inconsistent decision and design standards across transmission owners that lead to notable cost disparities between the same or very similar asset condition projects is just bad behavior,” said Commissioner Kerrick Johnson of the Vermont Department of Public Service (DPS). Prior to taking his position as a DPS commissioner, Johnson held several senior roles at VELCO. 

“Bad behavior by any New England [transmission owner] impacts every customer in each of the six New England states,” Johnson said, adding that this “undermines trust in the entire regional collaborative transmission enterprise and punishes those least able to pay.” 

Johnson added that he recently reviewed six ACPs flagged as the most “needlessly expensive” by the New England States Committee on Electricity (NESCOE), finding that the “cost delta between that which would have been expected for these projects and that which was submitted for each of these projects … totals nearly half a billion dollars.” 

He said he based his review on VELCO cost analyses and accounted for the varying costs typically seen in different states and utility service areas. 

ISO-NE previously expressed reluctance about taking on an asset condition oversight role, arguing it is not a regulatory entity. However, following discussions with the states and transmission owners, ISO-NE said it is comfortable taking on a limited reviewer role.  

Anne George, chief external affairs and communications officer at ISO-NE, said the RTO’s board met the prior week and offered support for continued discussions “about ISO-NE having an asset condition review role.” 

George stressed the importance of limiting the role to a non-regulatory, advisory function, but said it could “provide additional information and address some of those concerns about information asymmetry, and then people could take that information to FERC or take it to another forum and make the case.” 

NESCOE and the Massachusetts Attorney General’s Office, along with transmission owners Avangrid and National Grid, offered public support for the concept following the announcement.  

“NESCOE expects that the asset condition reviewer will provide states and stakeholders with an independent, objective review of asset condition proposals, including needs, solutions and cost drivers,” NESCOE wrote. “ISO-NE’s asset condition reviewer should provide information necessary to enhance confidence in the proposed investments, or in the alternative, information that others would be able to rely on in challenging a project.” 

NESCOE added there remains a “core need” to better incorporate asset condition needs into the regional planning process, which could enable those projects to be appropriately sized in anticipation of the need for more transmission capacity. ISO-NE has estimated new transmission to meet load growth through 2050 could cost up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B and ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.) 

In March, NESCOE asked FERC to direct the creation of an independent transmission monitor (ITM) with a broader scope, intended to “support the efficacy and efficiency of transmission planning and cost transparency.” Some stakeholders also have supported the concept of a monitor with authority to review the prudency of transmission projects. 

ISO-NE has expressed concern about having a separate independent entity overseeing the RTO’s planning processes and has resisted taking on anything more than an advisory role. 

At the NECPUC symposium, some stakeholders expressed interest in state or federal regulatory changes to go along with a new asset condition reviewer role for ISO-NE.  

“There’s definitely additional work that FERC could do to improve its formula rate-making process,” said Wayner of RMI. Wayner said this could include “looking at the automatic presumption of prudence that transmission projects get through formula rates and maybe reconsidering that for some of these projects if they are not being adequately reviewed at the state level.” 

Johnson of the Vermont DPS expressed his hope “the states pass individual review of asset condition projects like we have in Vermont.” 

In Massachusetts, Gov. Maura Healey (D) recently introduced a bill that would allow the state’s Energy Facilities Siting Board to review “any proposed reconductoring, replacement or rebuilding of a transmission facility or group of transmission facilities on an existing transmission corridor that has an estimated cost of at least $25 million.” (See Mass. Gov. Healey Introduces Energy Affordability Bill.) 

As state officials consider other changes to the asset condition process, ISO-NE has said it’s considering adding the evaluation and creation of an asset condition review role to its 2026 work plan.  

“Following the ISO’s assessment and the development of any preliminary framework, we plan to bring that proposal to our stakeholder community for discussion and feedback,” it added. 

For ACPs proposed in the interim period before a reviewer role can be established, Johnson asked representatives of the transmission companies at the NECPUC symposium to commit to answering all outstanding stakeholder questions before proceeding with a project. Representatives of each company signaled their agreement to the commitment.