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December 10, 2025

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FERC: New England TOs Must Disclose More Info on Asset Upgrades

Eight New England transmission companies must provide the Maine Office of Public Advocate with more information on asset condition projects placed in service in 2022, FERC has ruled.  

The ruling partly granted a formal challenge by the OPA alleging the eight transmission companies, including subsidiaries of Eversource Energy, National Grid, Avangrid and PPL, along with Vermont Transco, “refused to answer questions regarding investment policies and practices related to prudence of these investments” (ER20-2054). 

Commissioner Judy Chang wrote in a concurrence that the Sept. 18 order “should serve as a call to action for transmission owners across the country to provide greater transparency regarding their transmission investments.” 

Asset condition spending has been a major focus for New England consumer advocates in recent years as costs associated with upgrades to existing transmission infrastructure have skyrocketed.  

Although there is broad consensus that significant investments are needed to maintain and upgrade the region’s aging grid, state representatives and consumer advocates have expressed concern about a lack of transparency and oversight over these investments. ISO-NE recently agreed to take on a non-regulatory role in reviewing asset condition project proposals. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.) 

The OPA’s formal challenge stems from a series of questions the office submitted to the companies in September 2023 seeking information on how the companies evaluated asset condition needs, considered solutions and alternatives, and determined when to proceed with projects.  

The OPA wrote in its challenge that the transmission companies violated the formula rate protocols by failing to adequately respond to the information request. 

Consumer advocates from Massachusetts, Connecticut, New Hampshire and Rhode Island supported the OPA’s challenge and emphasized the importance of information requests for providing consumers with the information needed to evaluate — and potentially challenge — the prudence of transmission investments.  

The consumer advocates encouraged FERC to “interpret the [formula rate protocols] liberally and to issue a decision in this matter that fosters open and transparent exchange of information that will allow interested parties to evaluate and determine whether formula rate costs are reasonable and were prudently incurred.” 

In a joint response to the OPA’s challenge, the transmission companies argued that the OPA filing does not meet the requirements for a formal challenge, that the OPA’s challenge is based on many “inaccurate or false” claims and that the companies “did provide responses and supporting documentation in response to Maine OPA’s information and document requests, in addition to objecting to certain questions.” 

The companies asked FERC to reject the challenge, writing that “failure to do so would invite needless litigation and divert resources away from the ongoing New England stakeholder process on transparency enhancements to the transmission regional planning process for asset condition projects.” 

In its ruling, FERC directed the companies to provide more information in response to several of the OPA’s requests, while finding some of the requests to be outside the scope of the companies’ requirements under the protocols.  

“We find that most of Maine OPA’s questions clearly set forth the request for information in a manner such that identified NETOs [New England transmission owners] could make a good faith effort to answer those questions as required by the protocols,” FERC wrote.  

The commission found the OPA’s requests for the identities of individuals involved in asset condition decisions and those seeking an undefined number of documents to be outside the scope of the companies’ requirements. 

FERC also found that, to varying degrees, the companies adequately responded to some of the questions, including the request that the companies describe their procedures for evaluating project alternatives. 

However, FERC ruled that the companies did not adequately explain how they ensure projects are not placed in service before they are needed.  

The commission also found that subsidiaries or Eversource, National Grid and Avangrid failed to make a “good faith effort” to document their procedures for evaluating asset condition needs or disclose whether any employee or consultant “recommended against proceeding with a particular asset condition project.” 

“This refusal to provide information that is reasonably necessary to determine the prudence of actual costs and expenditures included in the 2023 Annual Update could preclude Maine OPA from ever raising a prudence challenge by denying it the information required to raise serious doubt,” FERC wrote. 

It directed the transmission companies to provide more information correcting the deficient answers within 30 days. 

In her concurrence, Commissioner Chang emphasized the importance of transparency regarding transmission investments, along with stakeholders’ “fundamental right to transmission planning and investment information through existing formula rate protocols.” 

“At a time of sharply rising customer bills and increasing concern about the prudence of transmission planning decisions, transmission owners have an obligation to address those concerns and help customers, state regulators and stakeholders better understand how their money is being spent,” Chang said.  

She advocated for more standardization disclosures around transmission investments throughout the country and encouraged stakeholders to collaborate to develop these structures.  

“If further action by the commission is needed to ensure customers have access to information needed to assess the prudence of transmission owners’ investments, I encourage parties to bring the issue to the commission, as Maine OPA has done in this case,” Chang wrote.  

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Newsom Signs Calif. Pathways Bill into Law

California Gov. Gavin Newsom has signed into law the bill that will allow CAISO to transition the governance of its markets to an independent “regional organization,” along with five other bills related to energy and emissions. 

AB 825 implements the West-Wide Governance Pathways Initiative’s “Step 2” plan to create a regional organization to oversee CAISO’s Western Energy Imbalance Market and soon-to-be-launched Extended Day-Ahead Market — and authorize the ISO and California’s investor-owned utilities to participate in the RO. (See Pathways Bill Passes Calif. Legislature in Lopsided Votes.) 

Speaking during a Sept. 19 signing ceremony at the California Academy of Sciences in San Francisco, Newsom said the law will generate almost $1 billion in financial benefits, expand clean energy exports and address reliability. 

Referring to previous failed efforts to pass legislation to regionalize CAISO into a Western RTO, the governor said, “We’ve worked on that for over a decade.” 

“We’re getting it done here today,” Newsom said. “So, finding a balanced approach, setting forth strategies to achieve audacious goals that simply no other large-scale jurisdiction in the world can lay claim to, and do it in a way that reduces the burden on ratepayers and taxpayers at the same time.” 

Supporters of the bill were quick to thank Newsom and the California Legislature after the governor approved the measure. 

“Gov. Newsom’s signing of Assembly Bill 825 is a landmark achievement for the future of energy collaboration and innovation across the western United States,” CAISO said in a statement. “He, along with the California Legislature and the broad coalition of supporters, have recognized the importance of making this crucial next step toward independent governance of Western electricity markets. Now that AB 825 is signed into law, the ISO will work closely with partners across California and the rest of the region to ensure a more reliable and affordable bulk electric system for the benefit of consumers throughout the West.” 

Advanced Energy United highlighted the many stakeholders involved in drafting the legislation. 

“This legislation is the culmination of nearly a decade of work to create a more flexible, reliable and affordable energy future for the West,” said Leah Rubin Shen, managing director at Advanced Energy United. “AB 825 paves the way for an independently governed energy market that will deliver a more reliable grid, broader deployment of clean energy resources and more affordable energy for consumers across the region.”   

Speaking during the signing ceremony, Katelyn Roedner Sutter, California state director at the Environmental Defense Fund, said, “By expanding today’s energy markets, we expand access to clean electricity and lay a strong foundation for the growth of clean energy and jobs.” 

A broad coalition was responsible for getting AB 825 passed, Sen. Josh Becker, the bill’s chief sponsor, told RTO Insider at New York Climate Week.

“This was an unparalleled coalition that we built this year: Environmental Defense Fund, NRDC, Environmental Voter [Project],” Becker said. “This year the Sierra Club supported it — they always opposed it in the past; labor, who always opposed in the past, came on board because of some of the protections built in, and companies and the Chamber of Commerce. People who usually don’t agree on anything, agreed on this. There was still a lot of opposition, but that coalition helped us get it done.”

Becker said there are three positive outcomes of the bill: lower costs, improved reliability, and an expanded grid.

“The Brattle Group and California Energy Commission has projected it’ll be between $800 million and a billion dollars of savings a year to California directly.” Becker said being able to cite the economic benefits of the Western Energy Imbalance Market for 10 years supported the case for the bill: “That’s delivered over $7 billion of economic benefits, $2.2 billion directly to California.”

Second, he said the changes brought about by the bill should improve everyday reliability and decrease reliance on the most polluting peaker plants. The result: a 53% reduction in greenhouse gas emissions in California. “Right now, we spend billions of dollars keeping natural gas peaker plants available to run a few hours a year; literally, a few hours a year. We’re going to be able to use some of these highly polluting assets a little less frequently in California.”

Finally, the expanded grid provides reliability through major weather events: “Especially in the era of climate change, you need a grid bigger than any one weather event. As [California Energy] Commissioner Siva Gunda always says, if we have a massive heat wave, as we did on Sept. 6, 2022, being able to trade with our neighbors can increase reliability.”

In addition to AB 825, Newsom signed into law a measure aimed at extending California’s cap-and-trade program through 2045. The revenues of the program will go toward funding, among other things, California’s high-speed rail project. 

Other measures signed include efforts to stabilize gas prices, funding for air quality monitoring programs and the continuation of studies related to California’s greenhouse gas targets.  

The governor also approved SB 254, a law that will create a “transmission accelerator” to develop low-cost public financing programs for certain transmission projects. The legislation also establishes an $18 billion “continuation account” for the state’s wildfire fund to cover investor-owned utilities’ wildfire liabilities. Contributions to the fund will be split between ratepayers and shareholders. (See Calif. Lawmakers Pass Bill to Accelerate Transmission Development.) 

Dej Knuckey contributed to this article.

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CAISO RA Initiative Moves Forward with 3 Proposals

CAISO is finalizing a set of changes to its resource adequacy program, with plans to vote on three proposals at an upcoming Board of Governors meeting, possibly as early as October.

The proposed RA program revisions are part of CAISO’s RA Modeling and Program Design initiative that began in August 2023.

The first proposal, “Track 1: Modeling and Default Rules,” which was published Aug. 25 and presented to stakeholders at a Sept. 17 workshop, updates certain requirements within CAISO’s qualifying capacity (QC) methodology and planning reserve margin (PRM) process.

The proposal provides a default set of RA rules for local regulatory authorities (LRAs) — that is, publicly owned utilities — that have not established their own methodologies and processes. These RA rules also can be adopted voluntarily by any LRA within the CAISO balancing authority area, the proposal says.

CAISO is specifically looking to replace a “longstanding” default PRM requirement of 15% with a new margin that would be determined periodically based on loss of load expectation (LOLE) studies. The new PRM process would ensure a market participant’s energy resource portfolio meets the industry-standard reliability benchmark of 0.1 LOLE when an LRA does not provide a QC methodology, the proposal says.

Stakeholders involved in the initiative questioned whether existing RA programs or CAISO’s default RA rules for LRAs meet a 0.1 LOLE requirement.

Some LRAs said they rely on CAISO’s default RA rules when developing their own requirements, but these rules have not been revisited or “significantly updated since they were established approximately 20 years ago,” CAISO said in the proposal.

In Sept. 12 comments to CAISO, representatives from the Alliance for Retail Energy Markets (AReM) said the group remains concerned about the differences between the CPUC and CAISO’s modeling and market design requirements.

“While AReM recognizes that other LRAs are seeking single monthly default QC values in contrast to the California Public Utility Commission’s slice-of-day paradigm, which adopts 24 hourly values for each resource each month, it is important all LRAs avoid using divergent methodologies,” AReM said. “Unless CAISO can show its proposed methodology results in consistent outcomes with slice-of-day, it should not adopt its Track 1 proposal.”

AReM also asked CAISO to provide greater clarity on how battery durations will be counted in CAISO’s default QC counting rules.

“CAISO’s proposal would, seemingly, lump all battery capacity together, including eight-hour batteries and four-hour batteries even though the CPUC has ordered LSEs under its jurisdiction to procure eight-hour duration storage resources and the CPUC’s slice-of-day methodology assigns greater value to longer-duration battery resources,” AReM said.

Track 2 Proposal

In the second proposal, published Aug. 26, CAISO pitched the formation of a new energy resource substitution “pool.” The pool would allow a scheduling coordinator (SC) to signal when they need to procure substitute capacity because their energy resources are offline due to a planned outage. The substitution pool would also allow an SC to indicate when it is able to offer substitute capacity for other SCs.

Under current rules, CAISO requires an SC with a resource undergoing a planned outage to provide substitute capacity for that resource. However, securing substitute capacity can be difficult due to “mismatches between contract terms and outage durations, as well as inefficiencies in the bilateral procurement process,” CAISO staff said in the proposal.

Additionally, multiple SCs “hold back RA capacity for outage substitution for a partial-month outage. This practice drives artificial tightness in the RA bilateral market,” staff said.

The cost to procure replacement capacity can be greater than the cost to pay a non-availability penalty under CAISO’s Resource Adequacy Availability Incentive Mechanism, staff added. This has led to forced outage rates going higher than those predicted by CAISO and the California Energy Commission.

The pooling approach would improve price certainty because buyers would be able to choose offers aligned with their willingness to pay.

It also would increase visibility into available supply, “giving buyers greater control over their choices and providing direct contact information for sellers.” Benefits of the proposal include “enhance[d] flexibility, transparency and efficiency in managing planned outages,” the proposal says.

On the other hand, SCs that have scheduled, immovable planned outages might want to continue arranging for substitute capacity outside of the proposed substitute pool process, the proposal says. Sellers also might face uncertainty depending on competing bids and might change their offer structure after seeing other postings in a pool, staff said.

Stakeholders such as the California Community Choice Association and the California Department of Water Resources supported the proposed pooling method.

The Track 2 proposal should be presented only to the CAISO Board of Governors for a decision because the initiative “falls outside the scope of authority of the Western Energy Markets Governing Body,” ISO staff said in the proposal.

Track 3A Proposal

The initiative’s “Track 3A: Resource Visibility” proposal is meant to improve CAISO’s visibility into what resources are available for procurement through the ISO’s backstop measures.

Better visibility into the status of RA-eligible capacity not shown as RA will “help the ISO conduct existing backstop processes more effectively and understand how any emerging trends should be incorporated into backstop program design,” staff said in the proposal.

Backstop procurement helps CAISO find additional energy for the grid when there is a shortage of RA or if conditions require the grid to procure more energy than that supplied by the RA program, staff said.

Part of the problem has been that the number of bids into CAISO’s Capacity Procurement Mechanism (CPM) has dropped significantly over the past five years. CPM is within CAISO’s Competitive Solicitation Process (CSP), which is the primary process for identifying capacity available for CPM designation.

“Conducting efficient and effective backstop procurement requires understanding what capacity is still available after accounting for all RA-shown resources,” CAISO staff said in the proposal. “The CSP is designed to provide this understanding.”

In addition to reliability improvements, the increased visibility under Track 3A can “improve policy and modeling for the CAISO system,” representatives with the CAISO Department of Market Monitoring (DMM) said in Sept. 16 comments on the initiative.

“Additional visibility into RA resources internal to the CAISO balancing authority area would improve a system-wide understanding of recent trends in the CPM and CSP, and potential improvements to the CPM,” DMM said.

The Track 3A proposal specifically includes new annual and monthly reporting requirements for all RA-eligible capacity in CAISO that is not shown as RA, the proposal says. Implementing these reporting requirements could make it easier to see what resources are open for procurement within CAISO’s backstop procurement program.

The proposal designates five categories of supply: supply that is sold outside the CAISO BAA; supply not shown due to being reserved for substitution; supply not shown due to potential unavailability; supply contracted to a CAISO LSE but not shown; and supply not contracted.

The new reporting requirements would apply to SCs that have RA capacity and are located inside the CAISO BAA that appears on the ISO’s Net Qualifying Capacity list, the proposal says. Reporting will be part of CAISO’s existing annual and monthly supply plan timeline requirements.

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FERC Focusing on Large Loads, Clearing the Decks Under Rosner

FERC held its monthly open meeting Sept. 18 amid something of an interregnum period as it awaits two nominees to fill empty seats, with Chair David Rosner saying one of his goals during his tenure is to clear out old proceedings.

“We’ve been focused on methodically clearing out longstanding proceedings that, in some cases, have been pending before the commission for years,” Rosner said. “Several of these are on the agenda today.”

One such longstanding item FERC recently terminated was a Notice of Inquiry that Chair Kevin McIntyre launched in 2018 looking into how the commission could update how it approves natural gas infrastructure, Commissioner Lindsay See noted during the open meeting (PL18-1). McIntyre died in office before the proceeding wrapped up, but it was picked up by Chair Richard Glick, who wanted FERC to address greenhouse emissions from gas infrastructure, a policy that sunk his renomination. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

“The draft statement was getting in the way of this goal of regulatory certainty by introducing potential confusion and giving avenues for legal vulnerability,” See said.

FERC issued an order terminating the proceeding on Sept. 12, two weeks after Energy Secretary Chris Wright wrote to the commission asking it to axe the fallow docket.

The commission also moved on more current issues, with Rosner releasing a letter he sent to all six jurisdictional ISOs and RTOs asking them for information on best practices around load forecasting in light of growing demand driven by data centers and other sources.

“At a time when utilities forecast hundreds or thousands of megawatts of growth, improving forecasts by even a few percentage points in the right direction — up or down — can impact billions of dollars in investments and customer bills,” Rosner said in the letter. “Put simply, we cannot efficiently plan the electric generation and transmission needed to serve new customers if we don’t forecast how much energy they will need as accurately as possible.”

Rosner posed several questions in the letter, including asking grid operators how they, regional utilities and state regulators in their territories obtain information that verifies when and whether prospective large loads will reach commercial operations. He also asked how consistently large loads are screened before being included in forecasts.

Another question is how grid operators forecast the actual consumption of large loads compared to their requested level of interconnection service. FERC also asked how the RTOs coordinate with each other and utilities at the regional or interregional levels to share best practices on large load forecasting and ensure requests are not double counted.

Ultimately, the customers creating the load growth are at the retail level, which means they are regulated by states that play key roles in feeding information up to the ISO/RTO forecasts. Rosner said he was interested only in what the organized markets under FERC’s jurisdiction can do.

“I’m very interested in doing things that are purely within their ability to control,” Rosner said. “We’re not asking any state to do anything different. We’re asking the RTOs to say, ‘Hey, what are your best practices,’ just to make sure we’re accurate, because being either high or low means that we’re not planning for an efficient set of infrastructure to meet the challenge.”

While Rosner said he views reliability as FERC’s most important job, he also is focused on enabling economic growth by ensuring abundant supplies of energy.

“I’m really excited about infrastructure,” Rosner said. “I think we need to build, build, build. America needs every electron on every molecule of every type we can get, and we need more infrastructure to move it.”

Reliable and affordable energy is not just a prerequisite for residents and businesses; it is vital to winning the race for artificial intelligence, he said.

When it comes to AI and the related growth in demand from data centers, FERC has had a pending case on issues around co-locating loads at existing power plants since November 2024, when See and former Commissioner (and later Chair) Mark Christie voted against allowing Amazon Web Services to use more of a Talen Energy nuclear plant’s capacity in such a deal. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.)

FERC Commissioner Lindsay See | © RTO Insider

“We also have our open matter when it comes to co-located load,” See said. “I just want to highlight that FERC is not the only player when it comes to the many questions in these areas.”

See said she is excited to see what policies around large loads come out of states and the grid operators but that it is important that FERC deal with those issues before it, and the co-location proceeding can be brought to a close soon.

“This is a top priority,” Rosner said. “It’s also a very complicated topic. My colleagues and I have been working hard on this. I’m really excited about co-location and everything in between, and getting the rules of the road in place so that we can unlock all these new technologies, get them on the grid and get data centers built.”

The co-location proceeding is pending and contested, meaning commissioners are limited in what they can say publicly under ex parte rules, but Rosner said that FERC was working to adjudicate the record and move something forward.

Load growth is very much top of mind for the industry, and Commissioner Judy Chang noted that the new proposals to help manage it are going to be filed with FERC in the near future.

“I anticipate we will receive more filings in these coming months from utilities and RTOs proposing reforms or changes in how they integrate new resources, integrate those resources with load, or how they integrate those resources with their existing or new transmission planning processes, and really how to handle these large loads on the system,” Chang said. “I’m committed to learning more about these large loads so that I can do my job effectively.”

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N.J. Solar Project Developers Scramble, Wonder What Comes Next

As solar development companies race to meet the deadlines by which they can secure federal investment tax credits (ITCs) before the program expires, developers see a better-than-expected short-term outlook but a grim long term.

Developers say guidelines issued by the Trump administration in August open the window to potentially completing more projects than they expected. In particular, the designation of a four-year period for certain residential and commercial projects to be completed if construction starts before July 2026 will enable more projects to obtain the tax credits, developers say. The credits, for 30% of the cost, are considered a major element toward making a solar project economically viable.

The One Big Beautiful Bill Act, enacted July 4, eliminated the ITC for residential projects that are not in service by Dec. 31. However, guidelines released in mid-August surprised developers by adding some lenience: Commercial projects and some leased residential projects must either be completed by the end of 2027, or, if they begin construction before July 5, 2026, they have four years to be completed.

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said the organization was “reasonably pleased” with the guidelines, saying they give developers “some time to continue to get some work done.”

“So we’re under kind of a burning platform to get as many projects going as soon as possible,” he said, adding that utilities will be under “enormous pressure” to meet the demand in connections.

Annika Colston — president of New York City-based AC Power, which has three New Jersey projects in development and is looking for more to complete before the deadline — said recent weeks have “been a bit of a roller coaster.”

The House of Representatives’ version of the bill, which included a tax on the production of solar and wind power that was not passed by the Senate, was “shocking,” she said, but the release of the guidelines meant the “ultimate outcome felt manageable.”

Uncertain Future

But the removal of the tax credit has thrown a cloud of uncertainty over the long-term strength of New Jersey’s now two-decade-old solar sector, raising questions about whether it can even meet the state’s past capacity goals, let alone the far more expansive current predictions of future needs.

The ITC’s demise comes just as state officials are looking to make solar a key element in the effort to boost in-state electricity generation to meet the dramatic surge in demand expected over the next decade, mainly from the development of data centers.

Officials frequently say that solar projects are the quickest new resources able to interconnect and would provide cheap energy for the energy-importing state, especially now that the state’s offshore wind sector is largely dormant. But developers say the economic viability of many projects will be questionable without the ITC. Some developers see potential support from the rising cost of electricity in the region, the state’s vibrant community solar sector, its new storage incentive program and perhaps another, smaller ITC to help buttress the sector. But they don’t see those making up for the loss of the full credit.

DeSanti said its demise will put “a lot of cost pressure” on companies and hurt the large-scale solar sector the most.

“You’re talking about huge investments — tens of millions of dollars,” he said. “Nobody’s going to put that kind of money on the table without some assurances that they’re going to get the 30% ITC.”

Smaller projects “are going to be limping along,” he said. “They’re going to be a lot tighter, and the market’s going to be shrinking from what it is. … I think we’re going to see a lot of the smaller guys go under from the pressure. The bigger companies, the established companies, I think they’ll be OK.”

Ray Cantor, a lobbyist on environmental issues for the New Jersey Business and Industry Association, said that with solar contributing only about 6% of the state’s electricity use, the sector has plenty of room to grow.

But “while it is part of energy future, it’s not the answer to our long-term capacity needs,” he said. “Solar is part of the solution. It is not the way to get out of our deficit of capacity.”

Colston said she still is optimistic that New Jersey’s established solar sector will help it fare better than states with a shorter history to fall back on, and hopes the four-year completion deadline will give federal legislators time to plan for a new tax credit. She noted that the ITC, which has existed in different forms for more than two decades, had been 20% at one point.

“Projects are viable at a lower ITC, assuming we don’t have outrageous tariffs,” said Colston, whose company develops solar on landfills. “There needs to be some relief somewhere.”

Community Solar Boost

The turbulence comes as New Jersey is far from achieving Gov. Phil Murphy’s goal of having 12.2 GW of solar by 2030 and 32 GW by 2050.

As of July, the state had an installed capacity of 5.2 GW, according to the latest figures from the New Jersey Board of Public Utilities. About 80% is behind the meter, 3.5% is community solar and 16% is utility-scale, but those proportions are changing. Community solar accounts for about 53% of the development pipeline, and 30% is grid supply.

State officials see community solar as a key element of the state’s future generation, and Murphy provided a boost on Aug. 22 by signing a law authorizing the BPU to allocate 3,000 MW of capacity by 2029, or whenever the limit is reached. The state currently allocates 150 MW a year, although a one-time measure increased it to 250 MW in 2025.

Strong demand for community solar allocation in two pilot solicitations and three in the permanent program have produced 119 completed projects and another 435 in the pipeline, BPU figures show. The agency in April said the state’s four utilities reported they had received 1,120 community solar interconnection applications totaling about 1,800 MW of power.

A solar project developed by AC Power on a landfill in Delanco, N.J. | AC Power

Some developers also hope a new law facilitating the development of storage will help meet the electricity demand surge while supporting the solar sector. The law, also signed by Murphy in August, aims to stimulate the development of “transmission-scale energy storage systems,” defined as those with a capacity of at least 5 MW that are connected to PJM. (See N.J. Boosts Storage, Community Solar Program Capacity.)

Some storage projects also retain the federal tax credit. DeSanti said the storage incentives could help make solar more attractive and cushion the blow from the ITC’s disappearance.

“It gives you another source of revenue,” he said. “Because if your battery is charged under the program, if the utility needs power, you can actually sell the power out of the battery.”

The state’s rising electricity rates also could support solar. The average electricity bill rose by 20% on June 1, driven in large part by record-high PJM capacity auction prices in July 2024, which the RTO says were pushed up by forecasts showing that future demand will far exceed the expected supply. Analysts expect auction prices, along with rates, to continue to rise.

“There’s no end in sight for the price of energy going up,” DeSanti said. “As that occurs, it’s going to push more and more people to say, ‘I’ve got to get out from under these utility bills.’ Once you get a deal on solar, you’re basically insulating yourself from those increases completely.”

Accelerating Solar Submissions

For developers, those benefits are distant and uncertain, and their task at hand is to get as many projects planned, and applications submitted, before the credits expire.

Sawyer Morgan, a project manager in the BPU’s clean energy division, said the agency has seen an “acceleration in the number of applications.”

“We currently have 1.4 GW of projects in the pipeline and expect many more projects to join, even in the next year or so, that will be able to qualify for the federal tax credits,” he said.

“Given that most projects in New Jersey are relatively small, we’re hopeful that a lot of projects will be able to meet these milestones and still qualify for the ITC,” he added. “As more homeowners are aware that the residential tax credit ends at the end of the current year, there’s going to be a ton of interest for the residential direct-owned projects to complete construction as soon as possible.”

Still, agency staff are “very concerned that after the expiration of the ITC, there will be a slowdown in the solar industry,” driven in part by developers who “pull forward” projects to get them inside the deadline, he said.

“There’s certainly likely to be a slowdown in installations,” which the BPU is looking to counter, he said. “We anticipate looking at reviewing programs to see what the appropriate mechanisms will be that help drive down costs through streamlining interconnection and other requirements, other costs that are involved in this other installation process or looking at the incentives that the board provides.”

Brian O. Lipman, executive director for the New Jersey Division of Rate Counsel, said that while solar has a “significant role” in the state’s future energy portfolio, it should “no longer plan an active role in incentivizing solar.”

“The solar market has matured greatly,” he said. “New Jersey ratepayers already pay more than those in any other state for solar subsidies. We no longer need, nor can our electric ratepayers afford to pay, such high subsidies that directly impact residential and business electric bills. Even with the loss of federal subsidies, solar in New Jersey should be able to stand on its own.”

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MISO Board Orders More Detail into Monitor’s 2026 Budget

DETROIT — MISO’s Board of Directors has asked the RTO’s Independent Market Monitor to better explain its $10.6 million 2026 budget before it agrees to the amount.

During Board Week, members of the board’s Markets Committee said they wanted greater detail on a $5.9 million budget item the Monitor proposed for “base monitoring and data management tasks.”

Monitor David Patton said “base monitoring” includes screening MISO market activity, data management, reviewing market outcomes and operations, producing reports, and coordination with the RTO. However, he did not allocate specific costs for each of the responsibilities.

Patton said the tasks take up a large share of the monitoring budget because that is his primary responsibility.

Director Robert Lurie said he would not accept a similar level of vagueness in MISO’s proposed budgets. Director Theresa Wise similarly asked for more “visibility” into the budget.

Director H.B. “Trip” Doggett encouraged Patton to “polish it up” and bring the budget back to a nonpublic meeting with the board in October. The board and the Monitor then could present the final product during the next Board Week in December.

Wisconsin Public Service Commissioner Marcus Hawkins said he had “concerns with the timing of the additional scrutiny” into the Monitor’s budget. He said that while he supported efforts into transparency, this year’s heightened examination appeared suspicious because of the recent controversy surrounding the Monitor assessing MISO’s transmission planning. (See FERC Sides with Market Monitor over MISO in Compensation Dispute and MISO IMM Contends he Should Have Role in Tx Planning Oversight.)

Hawkins said the IMM’s budget increase in 2026 appears lower than the national rate of inflation. He asked board members to share the results of their nonpublic meeting in October at the next Board Week in early December.

Over 2024, the Monitor operated with a nearly $10.2 million budget.

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MISO Recounts Tough Summer; Monitor Praises Lack of Emergencies

DETROIT — MISO said the summer of 2025 was the most demanding since 2012, though the RTO steered the grid with only a single maximum generation event.

“This summer was one of the most challenging in a decade,” Executive Director of System Operations Jessica Lucas told the Markets Committee of the MISO Board of Directors on Sept. 16.

Lucas said heat and humidity across the footprint were consistently high and that load exceeded 100 GW or higher for more than 750 hours over the summer, a number not seen since 2012 and nearly triple that of 2024.

The summer heat triggered more than 40 Energy Emergency Alerts across the Eastern Interconnection, but in MISO, “we only had one escalation” to an emergency, Lucas said.

MISO experienced a “sharp increase in outages” over the summer, Lucas said. The RTO reported 46 GW in average daily generation outages, compared to summer 2024’s 31-GW average, culminating in a 48% increase year over year. Lucas said members reported “equipment failure” as the leading cause of outages.

“It’s perhaps too early to call this a trend, but it’s an important data point to monitor to see if this extends into the fall,” Lucas said.

At a MISO board meeting Sept. 18, CEO John Bear said summer 2025 was “exceptionally demanding” and “signals a new normal for grid stress.”

The RTO encountered two rough patches in late June and again in late July. Lucas said that from June 21 to 24, the footprint contended with high demand, low wind output and high outages, leading to a maximum generation emergency on June 23. (See MISO Declares Max Gen Emergency in Heat Wave.)

Independent Market Monitor David Patton said he was impressed MISO avoided an emergency declaration on June 24 when virtually every other control area entered emergency procedures.

“What we saw this summer actually bears out what I’ve been saying: that ‘MISO is the most reliable RTO’ — at least among the ones that we monitor,” Patton said and again criticized NERC’s “high-risk” rating for the RTO.

MISO logged its almost 122-GW summer peak in late July. It also issued several capacity advisories for its South region throughout the season. (See MISO on Track to Wrap Summer with 122-GW Peak, Addresses Frequent South Advisories.)

The RTO kept up a near-daily cadence of capacity advisories for MISO South into September. The grid operator repeatedly said either forced outages, limited transfer capability or a combination of both were the culprits.

“You might have noticed we’ve been leveraging our capacity advisories more frequently,” Lucas said.

Stakeholders can construe the repeat advisories as an “indicator” of heightened reliability risks in MISO South, she said, but the RTO wants to communicate “so it doesn’t feel like anyone is caught by surprise” if it needs to institute emergency actions to deal with transmission or capacity issues.

Lucas also said MISO is developing a “set of criteria or methodology to step out of emergency declarations.” She said determining when gird conditions no longer require emergency actions and terminating declarations is a complicated decision that has operating ramifications.

The MISO IMM’s depiction of the 500-kV transmission outage July 28-29 | Potomac Economics

Amid the late July heat wave, MISO reported it unexpectedly lost a 500-kV line in MISO South on July 28-29, leading it to order a local transmission emergency and 780 MW of long-lead load-modifying resources to dial back demand.

Data from Yes Energy show Entergy Arkansas’ 500-kV Keo-West Memphis transmission line from Little Rock, Ark., to Memphis, Tenn., was offline July 28-29.

Lucas said MISO issued six declarations July 29 to manage the situation.

Patton said MISO’s LMR use means it is learning to use demand response to manage transmission emergencies in addition to capacity emergencies. He also said MISO incurred only about $8 million in uplift charges over the summer because of sharper resource commitments and operating decisions.

“That’s like nothing,” Patton said. “My guess is that PJM is going to be in the hundreds of millions. …This pattern is really impressive.”

Finally, MISO set an all-time solar peak of 14.1 GW on Aug. 3. The new record was double the solar output MISO achieved in summer 2024.

Patton said the larger solar fleet has brought ramping challenges that are growing with the solar fleet. He said cumulative evening net load ramp demand “has grown sharply” from about 1 GW in 2023 to nearly 6 GW in 2025 and asked MISO to continue to keep an eye on its increasing requirements. Evening ramping needs also occur later on summer nights, Patton said, with the largest need moving from 4 p.m. ET to 6 p.m. because of solar tapering down.

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Monroe’s Western Outreach Pays Dividends for SPP

PORTLAND, Ore. — When former SPP COO Carl Monroe hands out his business card these days, it reads, “Carl Monroe, Principal, Munro Advisors.”

“Munro?” Is that a misspelling?

“It’s the traditional way of spelling Monroe. They were Irish,” Monroe says of his ancestors. “‘Munro’ means they’re from the River Roe in Northern Ireland.”

The Munros were also “tenacious fighters” during the 1400s and into the 1600s, centuries punctuated by the Hundred Years’ War, King Henry VIII’s reign, the English Civil War and the beginning of the Jacobite Risings.

“They fought so ferociously that the Scots hired them as mercenaries to fight all the Scottish clans,” Monroe says. “Eventually, they got enough esteem that they are one of the clans that are considered [part of] Scotland, or Scotch-Irish.”

The Munros were so highly respected that the Scots gifted them land for their own castle, Monroe says.

When the story is related to an SPP stakeholder, who had just greeted Monroe on the sidelines of an industry conference, he says, “Had I known that he was so lethal, I would have given him a wider berth.”

Of course, unlike his ancestors, Monroe is anything but “lethal.”

A veteran of more than 45 years in the industry that first included stints with Ameren and Entergy, Monroe spent 15 of his final 22 years with SPP as its COO. That made him responsible for grid operations across the RTO’s 14-state balancing authority area, a footprint that grew from eight states during his tenure with the addition of Nebraska’s public power entities and the Integrated System in the Dakotas.

Independent transmission developer Grid United, for whom Monroe now serves as one of three members of its Advisory Board, credits him for being “instrumental” in expanding SPP’s footprint by 20% and adding $1.5 billion of transactions in the real-time energy market.

“Carl has helped to shepherd us through tremendous change and growth. We just wouldn’t be where we are today without his leadership,” SPP CEO Nick Brown said when Monroe announced his retirement in 2019. (See SPP COO Monroe to Retire in Early 2020.)

The footprint is expanding once again. The RTO’s expansion into the Western Interconnection will be live in April 2026. In 2027, SPP Markets+, a day-ahead service offering that includes real-time commitment and dispatch, will begin operations. It will replace the grid operator’s Western Energy Imbalance Service market, which it has administered on a contract basis since 2021.

SPP has also been serving as a reliability coordinator for primarily future Markets+ participants since 2019, and it was chosen by CAISO and five utilities nearly 10 years ago to administer the Western Interconnection Unscheduled Flow Mitigation Plan, which manages the use of certain controllable devices to mitigate congestion along transmission lines. The RTO was also selected as the program operator for the Western Power Pool’s six-year-old Western Resource Adequacy Program (WRAP).

Much of that is credited toward the “instrumental” Monroe and his outreach for more than a decade to Western Interconnection entities. He led SPP’s effort to add the Mountain West Transmission Group, a Front Range initiative that fell apart after Xcel Energy subsidiary Public Service Company of Colorado pulled out and led to a broader Western Market Exploratory Group that studied the benefits of a regional market. Years later, PSCo is one of seven entities joining Markets+ after Colorado regulators ordered the state’s utilities to join regional markets.

Jack Moore, an SPP IT engineer involved in the Markets+ development effort, spoke recently during a stakeholder meeting here. He prefaced his comments by remembering his first visit to Portland in 2010, when he accompanied Monroe to talk with the Bonneville Power Administration about “an energy market in the West.”

“So, 15 years later, here we are,” Moore said.

“That was one of the things Carl was always doing, just seeing whether there was a way that SPP could meet potential stakeholder needs,” said Jim Gonzalez, SPP’s director of seams and Western services. “As we hear opportunities for help, facilitating and collaborating, that’s one of the things SPP has always really been open to. If we have neighbors and there seem to be needs, can we help meet those needs?”

“That’s a lot of it,” Monroe says by way of agreement. He described a “paradigm shift” that has taken place with wholesale markets and the West’s growing understanding of their benefits.

“That’s why you’re seeing a lot of the development of markets out there. I think you’re starting to see that paradigm shift about having a real real-time [market] and a wholesale market that actually provides more benefits to them than trying to hold onto control of those things,” he says.

“It really gives them a way to mitigate some of the risks. … That’s why you see a whole lot of interest, but there’s some underpinnings that at least we stumbled through in the East,” Monroe adds, listing tariffs, balancing authorities, resource adequacy and “those types of things” that grid operators do. “It just means that a group of utilities can decide how to do those things together in a way that provides a benefit to the whole that is greater than the benefit each of them can provide individually.”

As an example, he points to the WRAP and utilities that got together “with SPP’s help” to understand how they could work together in a resource adequacy program.

“I was an adviser for some of that too,” he says. “Together, they could rely on each other’s resource adequacy more and ensuring that each party was upholding their portion that they had to rely on.”

“In nearly 15 years as a director at SPP, I’ve met no one with greater knowledge of markets and operations or with such ability to collaboratively address complex issues,” SPP Board of Directors Chair Larry Altenbaumer said of Monroe when he announced his retirement.

His decision just happened to coincide with the COVID-19 pandemic, making him something of a forgotten figure. He was asked what he intended to do with his spare time and whether he would go into consulting.

“I didn’t know the difference between retirement or COVID. Everybody just went home to work,” he says. “I spent some time with SPP near the end working with the West trying to help them out, first of all, just to understand what it means to work together and what benefits you get out of it, [and] beyond that, what SPP could do for them. Of course, you’re seeing some of that play out today.”

SPP gave him a contract to “do one little thing,” but when he was finished with the project, he was free to work with others. With his somewhat eponymous consulting firm, Monroe helps clients with bulk power system operations, reliability standards, wholesale energy markets, strategic planning, FERC tariffs and other issues.

“I don’t want to do things that are not interesting to me, but this industry is really interesting,” he says. “The transition that it’s going through … it’s just been fascinating to watch the industry and what the industry needs to do, but at the same time, how it’s needed within the country and what reliability means to the country itself as critical infrastructure. …

“There are things I know that I can help people with,” Monroe adds. “There were a few people that called and wanted some help and just understand SPP and our wholesale markets and stuff like that. So that’s been a lot of fun.”

Besides his work with Grid United and its HVDC projects, Monroe also has consulted with solar and hybrid storage in both interconnections.

“Some are looking at markets, and some are looking at coordinating their activities together with others for optimized operations,” he says. “But the most interesting thing, [which] gets me my 49th state to do work in, is an RTO for Alaska.”

Monroe graduated from Auburn University with a degree in electrical engineering. While at SPP, he decorated his office with a black-and-white photo from his time on The Plains. The image shows Elvis Presley’s 1974 performance on campus at the Memorial Coliseum. Monroe would direct visitors to the AV booth in the background, from where he was responsible for lighting The King.

He joined SPP from Entergy, originally being hired to manage the RTO’s growing IT department. He was elected as an officer and promoted to executive vice president and COO in 2004, where he oversaw operations, the power system’s long-term forecasting and planning, and interregional coordination.

“I believe his personal efforts, contributions and leadership were critical to the tremendous development and success of the Southwest Power Pool,” said longtime member Mike Wise, with Golden Spread Electric Cooperative.

“I’ll do what I can to help people,” Monroe says. “If I can’t help you, I’ll tell you I can’t help you. That’s fine. I’m enjoying what I do, whether I do anything or not.”

Nothing to do? Given Monroe’s history, that’s a little hard to believe.

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Renewables Creating Opportunities for Pumped Hydro in New England

As decarbonization policy and the growth of intermittent renewable power in New England drives increasing needs for clean balancing resources, a developer in Maine is evaluating whether pumped storage hydropower — one of the oldest generation technologies still used in the region — could play an increased role in the grid of the future.

The history of pumped storage dates back about 100 years in New England. The Rocky River facility, which remains in operation today in western Connecticut, was the first of its kind in the U.S. when it came online in 1929. It was built to help balance the variable production profile of run-of-river hydropower.

The facility is based on a simple concept: During periods of low-cost power, two 3.5-MW reversible pump turbines push water from the river to a large reservoir at a higher elevation. When power demand peaks, water flows downhill to produce power through the two turbines and a larger conventional generator.

In the 1960s and 1970s, the proliferation of nuclear power in New England spurred the development of two significantly larger pumped storage facilities in Western Massachusetts.

Northfield Mountain, which has 1,168 MW of qualified capacity with ISO-NE, and the Bear Swamp Generating Station, which has 662 MW of capacity, were built by utilities to help match the production profile of the nuclear resources with demand, allowing the nuclear plants to stay online at a constant level. The pumped storage facilities charged during low-demand periods at night and discharged during peak load periods in the day.

The facilities are open-loop systems, pumping water from rivers to elevated reservoirs. They use large reversible pump turbines that are about 30% less efficient when pumping water uphill than when generating.

In the 50 years since the two plants came online, all but two nuclear plants in New England have been decommissioned, but Northfield Mountain and Bear Swamp remain in service.

“The economics of the projects really haven’t changed. You’re still looking for that price arbitrage: We’re going to try to pump when prices are low, and we’re going to turn around and generate when prices are higher,” said Justin Trudell, CEO of FirstLight Power, which owns and operates the Rocky River and Northfield Mountain facilities. Trudell previously worked at Brookfield Renewable, which co-owns Bear Swamp.

To recover the costs of pumping water, “you’ve got to at least make up that 30-ish-percent loss of efficiency in that price arbitrage; that would set your baseline,” Trudell said.

He added that, over the past decade, the steady increase of solar generation has caused the typical temporal pattern of pumping and discharging to shift.

“On sunny days, especially in the summer, we’re seeing deep troughs in pricing midday when you have this glut of solar online,” Trudell said. “We’re seeing a lot more opportunities now where we’re actually pumping during the day, and we’re generally generating during the evening peak.”

Growing behind-the-meter solar generation has contributed to an increasing difference between midday and evening demand. The RTO recorded a record-low demand around 2 p.m. on Easter Sunday in April, and about two months later, it recorded its highest load in over a decade around 7 p.m. on June 24. (See Growth of BTM Solar Drives Record-low Demand in ISO-NE and Extreme Heat Triggers Capacity Deficiency in New England.)

New Development Possibilities

With the growth of intermittent renewables poised to continue in New England because of clean energy policies, increasing power demand and the challenges of fossil development in the region, states are looking to procure significant amounts of new storage capacity.

Connecticut has set a goal of deploying 1,000 MW of storage by 2030, while Massachusetts in 2024 passed legislation aiming to procure 5,000 MW of energy storage by mid-2030, broken into mid-duration, long-duration and multiday categories.

Western Maine Energy Storage, a company backed by construction corporation Cianbro, is investigating whether new pumped storage facilities could help meet this storage need, and in July it submitted a preliminary permit application for a 400- to 500-MW project in Dixfield (P-15410).

The proposed reservoir system effectively would function as a closed-loop system, featuring two 100-acre reservoirs at different elevations.

The upper reservoir of the Northfield Mountain pumped storage facility | FirstLight

This design may help the project avoid some of the environmental challenges associated with open-loop pumped storage facilities connected to river systems. Northfield Mountain and Bear Swamp are involved in extended relicensing proceedings with FERC and have drawn criticism and opposition from environmental groups over impacts on downstream ecosystems.

Western Maine spokesperson Tom Brennan said the project is enhanced by the increasing arbitrage opportunities brought by renewable production in the region. He highlighted Maine’s goal of achieving 100% clean power by 2040.

“If we’re going to do that, we’re going to need storage,” Brennan said.

He said the company has been evaluating potential sites for a pumped storage project “for many years,” adding that “Maine is, in many ways, ideal because of the topography variation.”

“It’s because of that topographic variation and access to a significant and appropriate transmission line that has us focused in on Dixfield,” he said.

Unique Characteristics

Compared to lithium-ion batteries, pumped storage resources typically have a longer duration, though they rarely discharge to the point of depletion. Northfield Mountain has a duration of nearly eight hours, while Bear Swamp has a duration of about 4.5 hours.

Both facilities also tout their ability to ramp up from no output to full output within about 10 minutes.

“We’re faster[-ramping] than gas, and we’re longer-duration than most batteries,” FirstLight’s Trudell said. “We’re in this sweet spot of being able to provide more of a service for a longer period of time than some of these other technologies.”

Trudell said Northfield Mountain relies primarily on revenues from the ISO-NE wholesale markets and often is held in reserve by the RTO as a first contingency. He emphasized the reliability benefits of the facility’s ability to quickly ramp up or down as needed.

As ISO-NE works to overhaul its methodology for accrediting resources in its capacity market, storage owners have pushed for the RTO to account for ramp-up time in its accreditation methodology, and the storage industry is closely following the accreditation project to see how the changes could affect future capacity market revenues. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)

State revenues generally are not a major revenue source for existing pumped storage resources; while Massachusetts’ Clean Peak Energy Standard does not exclude pumped storage resources from generating Clean Peak Energy Certificates, resources that came online prior to 2019 are not eligible. Bear Swamp, which underwent an upgrade after this deadline, has qualified about 88 MW of its capacity in the program.

In July, Massachusetts issued a procurement of 1,500 MW of mid-duration storage, seeking to buy environmental attributes including Clean Peak certificates. (See Massachusetts Seeks 1,500 MW of Mid-duration Energy Storage.) Bear Swamp bid its full 88 MW of Clean Peak-qualified capacity for the procurement on Sept. 10.

‘Who’s Going to Buy the Power?’

By nature, pumped storage projects are capital intensive, and any new facility likely would need a significant amount of revenue certainty for investors to commit to a project.

“The question is offtake, and you’ve got to get offtake before you get financing,” Trudell said. “We know how to license, from the federal side, a new pumped storage project. The problem is: Who’s going to buy the power?”

Connor Nelson, manager of regulatory affairs and markets at the National Hydropower Association, noted there has been no new pumped storage built in the U.S. in about 30 years, in part because of these barriers.

1980 illustration of the Rocky River pumped storage system | The American Society of Mechanical Engineers

“What you have is a long-lead-time, capital-intensive resource,” Nelson said. “You need patient capital, patient investment, and you need, in a lot of cases, some sort of long-term capacity contract or a strong market signal that can assure developers and investors that this is going to be worth it in the long run.”

However, he stressed that there is an “ever increasing need for long-duration energy storage” and that the “prospects for pumped hydro are as good as they’ve ever been, in part because there’s a lot of good federal incentives right now.”

He noted that the recent federal reconciliation bill did not strip incentives for pumped storage resources, and developers that begin construction by 2033 could get “upwards of 30% of that investment back in the form of a tax credit or direct pay if you’re a utility.”

Western Maine’s Brennan declined to comment on the type of contracts or revenue certainty the company would need to move forward on the Dixfield project.

“We are so early in the process,” Brennan said. “I am very short on details at this point; the design details will be in the works for some time to come.”

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NERC Committee Approves Waivers for IBR Standards Projects

Members of NERC’s Standards Committee approved a set of waivers that could see comment and ballot rounds for several high-priority standards projects reduced to as few as five days during their quarterly in-person meeting, held at Duke Energy headquarters in Charlotte, N.C., on Sept. 17.

The waivers apply to Project 2020-06 (Verifications of models and data for generators), Project 2021-01 (System model validation with inverter-based resources) and Project 2022-02 (Uniform modeling framework for IBRs). All three projects relate to Milestone 3 of FERC Order 901, which directed NERC to develop requirements for modeling of inverter-based resources and submit them to the commission by Nov. 4. (See FERC Orders Reliability Rules for Inverter-Based Resources.)

In light of this tight schedule, the committee already agreed at its April meeting to shorten the initial comment and ballot periods for the projects from the customary 45 calendar days to as few as 25, and to shorten their final ballot periods from 10 to five days. (See NERC Standards Committee Approves IBR Posting.) All three projects conducted their initial ballot periods earlier in 2025, but none reached the required threshold for approval.

Committee Chair Todd Bennett, of Associated Electric Cooperative Inc., reminded members that the waiver request was meant to give the standard drafting team the “flexibility” to reduce the ballot time, acknowledging that the committee had “begun to use waivers a bit more often” in recent years to deal with the growing number of high-priority work items. While attendees generally were supportive of the option, several raised concerns that their implementation could cause problems.

“The concern for some people with a five-day comment period is that you’re almost guaranteed to include a weekend in there, which takes that five days down to three,” said Keith Jonassen of ISO-NE. “The only thing I would want to see is [the projects not] be posted on a Thursday or Friday to encompass that weekend.”

NERC Director of Standards Development Jamie Calderon said the ERO was aware of this possibility and is actively looking for posting dates for the affected projects that would start early in the week. While nothing has been decided yet, she said the next comment period could begin Sept. 22.

Similarly, Maggy Powell of Amazon Web Services warned NERC that extra effort may be needed to make sure stakeholders are aware of the limited time to weigh in on the standards.

“When you shorten it, you do run the risk of it failing, because if people don’t have the time to review it, they vote ‘no,’ or it just gets missed,” Powell said. “So I guess my suggestion is to really drive all the communication as much as possible … so that people have a chance of being aware when it’s coming.”

Calderon acknowledged Powell’s recommendation and said NERC will remind potential voters to take part in the ballot round.

Additional Standards Actions

Members acted on another high-priority item at the meeting, voting to authorize modifying the recently approved standards on internal network security monitoring (INSM) at certain grid-connected cyber systems as directed by FERC.

The commission approved CIP-015-1 (Cybersecurity – INSM) on June 26; the standard requires utilities to implement INSM for all high-impact grid-connected cyber systems with or without external routable connectivity (ERC), as well as medium-impact systems with ERC. FERC also directed NERC to make further changes, due in September 2026, that would extend the implementation of INSM to electronic access control or monitoring systems and physical access control systems outside the electronic borders around their internal networks.

The committee’s authorization follows its acceptance of a standard authorization request and approval of a drafting team for the project, and a 30-day informal comment period for the SAR.

Also approved at the meeting was a 45-day formal comment and ballot period for proposed standard FAC-002-5 (Facility interconnection studies). (See page 46 of the committee’s meeting agenda.) The new standard would “require [transmission planners] and [planning coordinators] to collect electromagnetic transient (EMT) models from applicable entities and conduct EMT studies where necessary, ensure accurate models are provided and verified prior to commercial operation, and clarify requirements on applicable entities providing accurate models.”

One of the final standards items on the agenda saw the committee appoint seven members, including the chair and vice chair, to the drafting team for Project 2025-01 (Canadian-specific revisions to EOP-012-3), which is intended to address potential compliance difficulties that NERC’s cold weather standard could have for Canadian entities.

Members also agreed to authorize posting for a 45-day comment and ballot period a new standard that would require industry to perform energy reliability assessments for the near and long terms. The standard is unnamed; NERC Manager of Standards Development Alison Oswald told attendees the drafting team felt its subject matter could warrant creating “a new family of standards” on which stakeholders will be asked their opinions during the comment period.

Chair, Vice Chair and Member Elections

Committee members approved AECI’s Bennett for another two-year term as chair, with current Vice Chair Troy Brumfield, of American Transmission Co., also retaining his seat for another two years. Their next terms will run from Jan. 1, 2026, through Dec. 31, 2027.

Members were reminded of the upcoming elections for committee membership that will run Oct. 22-31. Members serve staggered two-year terms beginning Jan. 1 of each year; those whose terms will expire Dec. 31 are:

    • Segment 2: RTOs and ISOs — Jamie Johnson, CAISO
    • Segment 3: Load-serving entities — Claudine Fritz, Exelon
    • Segment 4: Transmission-dependent utilities — Marty Hostler, Northern California Power Agency
    • Segment 5: Electric generators — Terri Pyle, Oklahoma Gas & Electric
    • Segment 6: Electricity brokers, aggregators and marketers — Richard Vendetti, NextEra Energy
    • Segment 7: Large electricity end users — AWS’ Powell
    • Segment 8: Small electricity users — Robert Blohm, Keen Resources
    • Segment 9: Federal, state and provincial regulatory or other government entities — Paul MacDonald, New Brunswick Energy and Utilities Board
    • Segment 10: Regional entities — Dave Krueger, SERC Reliability

All of the currently serving members are eligible for re-election; in addition, stakeholders may nominate additional candidates from Sept. 22 to Oct. 13.

Along with those whose terms are expiring, Segment 1 (Transmission owners) is vacant, and Segment 5 will hold a special election to replace Josh Hale of Southern Power, who has moved to another role within the utility. He resigned from the committee at the end of the meeting.