NERC Board Approves Committee Reorganization

At NERC’s final board meeting of 2025, Chair Suzanne Keenan reminded trustees that the ERO’s “mission is simple to say, but enormous to carry.”

“We don’t get the luxury of getting it wrong, and with the system changing fast and demand growing even faster, the stakes keep rising,” Keenan said. “I often think about what this will look like a decade from now, and I imagine a more settled landscape — still challenging, but steadier — where people look back and recognize how this industry rose to the moment, how we embraced change, pushed each other, trusted each other and stayed relentlessly focused on our mission.”

Keenan’s remarks set the tone for the brief but busy Dec. 5 meeting, in which trustees approved updates to the board’s committee structures and assignments, a proposal to retire a regional reliability standard, the ERO’s 2026 work plan priorities and its 2026/28 Reliability Standards Development Plan.

The committee reorganization included: the creation of a new board committee, the Engagement and Outreach Committee; and the disbanding of the Technology and Security Committee, which has overseen the Electricity Information Sharing and Analysis Center and the board’s information technology and information security programs. The new committee will take over E-ISAC oversight, while the Finance and Audit Committee will oversee the IT program. Oversight of information security will be assigned to the full board.

TSC Chair Jane Allen, who will transition to head the EOC, explained to the board the new committee’s goal will be “making sure that the things that NERC produces, the information, reports, standards, etc. [are] getting to the right people at the right time.” Keenan said the EOC’s responsibilities, in addition to E-ISAC oversight, will include “deepening NERC coordination with regional entities to reach decision-makers across North America.”

Keenan presented the board’s committee leaders for next year. Chairs for the committees will remain largely the same as 2025, except for Allen moving from TSC to EOC and Trustee Ken DeFontes taking over leadership of the Nominating Committee. Other committee chairs are:

    • Corporate Governance and Human Resources: Kristine Schmidt
    • Regulatory Oversight: Rob Manning
    • Finance and Audit: Colleen Sidford
    • Enterprise-wide Risk: Jim Piro

Schmidt brought to the board a proposal from the governance committee to set compensation for trustees designated as liaisons to or members of NERC’s standing committees, task forces or working groups to $7,500 or $10,000 per year, respectively. Liaisons are assigned to monitor and observe a standing committee or other group, while members are expected to fully participate in the group to which they are assigned.

NERC’s bylaws now state that the board’s liaisons to the Standards Committee and Reliability and Security Technical Committee — both roles filled now by Trustee Sue Kelly — be paid $7,500 per year. However, the bylaws make no provision for liaisons or members of other committees or groups. Schmidt said the rule change was intended as “a recognition of the effort” that such participation requires.

She added that the committee did not expect the board to assign trustees to committees, work groups or task forces on a regular basis, but “only under extreme circumstances when the board and the CEO feel that it’s necessary.” The board voted unanimously to approve the committee reorganization and the compensation proposal.

Standard Retirement and Development Plan Approved

Trustees also approved the retirement of regional reliability standard BAL-002-WECC-3 (Contingency reserve).

The standard, adopted by NERC’s board in 2019, “specifies the quantity and types of contingency reserves required to ensure reliability under normal and abnormal conditions,” the agenda said on Page 18. Under the standard, an entity must hold reserves based on 3% of load and 3% of generation, which NERC staff wrote is “more stringent than” NERC’s continent-wide standard BAL-002-3 (Disturbance control standard — contingency reserve for recovery from a balancing contingency event).

NERC Director of Standards Development Jamie Calderon told trustees that WECC has considered retiring the standard since 2020 and concluded earlier in 2025 that “the additional reserve requirements did not demonstrably improve reliability and instead created inefficiencies that hindered variable generation integration.”

NERC posted the proposal for a 45-day comment period that ended Oct. 30, with most comments supporting the retirement. Calderon said ERO staff recommended the board support the proposal as well, which trustees did without objection.

Finally, trustees accepted the Reliability Standards Development Plan for 2026/28. The RSDP includes time frames and resources for all standards development projects expected to begin during the relevant time period, and is subject to change based on standard authorization requests or FERC directives received prior to the plan’s submission to FERC.

Supreme Court Justices Seem Skeptical on Agency Independence

The Supreme Court appeared ready to overturn a precedent that has maintained the independence of regulatory agencies like FERC for the past 90 years.

Justices heard oral arguments in Trump v. Slaughter, a case that springs from President Donald Trump firing Federal Trade Commissioner Rebecca Slaughter earlier in 2025. Commissioners at the FTC, FERC and other agencies enjoy “for cause” firing protections under Humphrey’s Executor, which a recent amicus brief argued has ensured agency independence. (See Former FERC Commissioners Ask Supreme Court to Preserve Agency Independence.)

Multiple justices appointed by Republicans questioned Amit Agarwal, the special counsel for Protect Democracy who argued for Slaughter, on why Congress could not just expand multimember commissions to take over the work of EPA or the Commerce Department, thus insulating them from presidential oversight.

Some executive agencies, including the State Department and the Department of Defense, are pre-empted from that entirely under the Constitution because they are wielding the president’s “conclusive and preclusive constitutional authorities,” Agarwal said.

Chief Justice John Roberts asked whether Congress could reorganize the Department of Veterans Affairs, or the Department of Education, so that they are run by a commission with officers that could only be removed for a cause.

“Yeah, I think that it is probably within the realm of possibility for agencies, yes, Chief Justice Roberts,” Agarwal said. “And the constraint historically has been that these types of determinations have been made through a process of political accommodation between Congress and the president.”

Justice Elena Kagan argued that the bigger risk would not be Congress usurping executive authority with new bipartisan commissions, but that if the Trump administration wins, then the Education Department will still be authorized by Congress but without any employees.

“I think you’re absolutely right, Justice Kagan, that there are competing dangers here, and it makes a whole lot of sense to us to weigh the real-world dangers that we know are a virtual certainty that would result from adopting petitioners’ constitutional theory,” Agarwal said.

He then added that Congress has never tried to convert an executive agency, as Roberts and several other justices postulated it could, but Justice Amy Coney Barrett said that does not prevent that from happening in the future.

In Humphrey’s Executor, the court recognized that such agencies exercise legislative and judicial powers while still engaging in some executive function, but that does not make it an executive agency, Justice Ketanji Brown Jackson said.

Many agencies have been involved in civil enforcement cases, and the Supreme Court has never found any of them were therefore ineligible to have principal officers covered by for-cause protection, Agarwal said.

“You are just saying that the way the law has been interpreted by the court here, the existence of Humphrey’s and Congress’ reliance on these kinds of multimember agencies for something like 90 years plus, that’s the background rule,” Jackson said. “And so now it’s up to the government and the solicitor general to come in to suggest that there’s a constitutional problem with that.”

The FTC Act is 111 years old, and Humphrey’s has been case law since 1935, Agarwal noted, and he argued that similar setups go back to the earliest days of the U.S.

Justice Brett Kavanaugh asked whether it would be appropriate to give FTC commissioners or others with protections under Humphrey’s Executor terms of up to 20 years. Agarwal argued that would be prevented by the Take Care Clause in Article II, Section 3 of the Constitution, as commissioners’ time in office would span multiple presidencies.

“We don’t dispute that the activities of these agencies are operating within the purview of the executive branch and they should be subject to constitutionally appropriate presidential supervision,” Agarwal said.

Most of the regulators at issue in the case allow the president to pick a chair from among Senate-approved members for any reason, and Kavanaugh asked if that was required. Agarwal said it was not constitutionally required because when Humphrey’s Executor was decided, the chair of the FTC was not removable, though the law changed 15 years later.

“I think putting those three together, your position would allow Congress to create independent agencies, maybe converting some of the existing executive agencies into independent agencies with no political balance requirement, with a long term, say, 10 or more years, and with the chairs not subject to removal as chair,” Kavanaugh said. “So, you can imagine a situation — and I just want to give you a chance to deal with the hard hypothetical — when both houses of Congress and [the] president are controlled by the same party [and they create] a lot of these independent agencies or extending some of the current independent agencies … so as to thwart future presidents of the opposite party.”

That would be constitutionally untenable because the president needs the authority to enact the law, Agarwal said. He cited Seila Law v. CFPB, in which the court found that the Consumer Financial Protection Bureau, which was run by one executive director, was not covered by Humphrey’s Executor, but the FTC, with its staggered seven-year terms and removeable chair, is on the right side of the line.

“If it is really true that these kinds of for-cause removal protections, which after all authorize the president to fire commissioners just for good cause, if they really pose this fundamental threat to the Republic, petitioners could take their argument across the street and Congress could solve the problem tomorrow,” Agarwal said. “They’re not willing to do that.”

The Federal Reserve Board of Governors benefits from the same protections as the FTC and FERC, but in a decision earlier in 2025 overruling the stay a lower court had placed on Trump’s firing of National Labor Review Board (NLRB) and Merit Systems Protection Board (MSPB) members, the Supreme Court indicated its own separate legislative history.

Kavanaugh asked Solicitor General D. John Sauer about whether the effort to bring other regulatory agencies under greater presidential control would undermine the central bank’s independence.

“We recognize and acknowledge what this court said in the [Trump v. Wilcox] stay opinion, which is that the Federal Reserve is a quasi-private, uniquely structured entity that follows a distinct historical tradition of the First and Second Banks of the United States,” Sauer said.

Any issues of removal restrictions from the Federal Reserve would raise their own unique distinct issues, he added.

Justice Kagan then asked, based on the arguments that all executive power is vested in the president, what would stop the courts from expanding the decision to cover even the civil service.

“Employees are wielding executive power all over the place, and yet we’ve had civil service laws that give them substantial protection from removal for over a century,” Kagan said. “How about those?”

Sauer said the case was not challenging the structure of the civil service, and the court has made clear in past decisions that its impacts are limited to the issues at hand.

“Logic has consequences,” Kagan said. “Once you use a particular kind of argument to justify one thing, you can’t turn your back on that kind of argument if it also justifies another thing in the exact same way. Putting a footnote in an opinion saying, ‘We don’t decide X, Y and Z because it’s not before us,’ doesn’t do much good if the entire logic of the opinion drives you there.”

D.C. Circuit Weighs in

Just days before the Supreme Court heard oral arguments in the Slaughter case, the D.C. Circuit of Appeals issued a decision in the case involving fired members of the NLRB and MSPB.

The court sided with Trump in the firings, but without overturning Humphrey’s Executor.

“Congress may not restrict the president’s ability to remove principal officers who wield substantial executive power,” the two-judge majority said. “As explained below, the NLRB and MSPB wield substantial powers that are both executive in nature and different from the powers that Humphrey’s Executor deemed to be merely quasi-legislative or quasi-judicial.”

The majority noted that after Humphrey’s Executor, other decisions had erased the distinction about “quasi-legislative” and “quasi-judicial,” while others found that only three kinds of constitutional power exist and only executive power can be delegated.

“These considerations suggest that very little remains of Humphrey’s Executor,” the circuit court said.

Judge Florence Pan filed a dissent to the decision, saying some agencies’ independence benefits the public and the multimember commissions at issue in Humphrey’s Executor have been around for 138 years.

“For at least 90 years, it has been settled law that Congress may impose statutory for-cause removal protections in the exercise of its authority to organize and structure the executive branch,” Pan wrote. “But today, my colleagues make us the first court to strike down the independence of a traditional multimember expert agency: They hold that the for-cause removal protections that safeguard the political independence of the National Labor Relations Board and the Merit Systems Protection Board are unconstitutional.”

PJM Operating Committee Briefs: Dec. 4, 2025

November Operating Metrics

PJM’s forecasting of hourly peak loads  continued to improve in November, with an error rate of just 1.17%, lead engineer Marcus Smith told the RTO’s Operating Committee on Dec. 4.

And while the 1.31% error rate for hourly forecasts was higher than October, it remained below the two-year average, Smith said.

He said forecasts held up on Nov. 11, when Veterans Day coincided with the lowest temperatures of the month, while Thanksgiving was the coldest observed since 2018. Holiday load forecasts have taken on pronounced importance since December 2022’s Winter Storm Elliott, when gas generators struggled to determine whether they should nominate for fuel packages spanning the long weekend. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)

Nov. 20 was the only day with a peak error rate exceeding the RTO’s 3% error benchmark, with cooler weather pushing the peak load to 3.15% higher than forecast.

There were three spin events, three shared reserve events, two geomagnetic disturbance warnings, 13 shortage cases and 14 post contingency local load relief warnings in the month.

Eight of the shortage cases were declared on the morning of Nov. 18, leading stakeholders to question whether solar ramping was a factor. PJM’s David Kimmel said there have been a higher number of shortage cases related to solar over the past few months, but staff still are investigating the drivers on that day.

One shortage case was issued on Nov. 16 and four on the following day, which were attributed to software issues.

A Nov. 11 spin event lasted 10 minutes and 17 seconds, meeting PJM’s threshold for including it in a three-event rotating average being tracked for determining whether the RTO should back down a 30% adder on the synchronized and primary reserve requirement implemented in May 2023.

The RTO assigned 2,051 MW of generation, of which 80% responded, and 673 MW of demand response, with a 91% response. If performance across three events longer than 10 minutes exceeds 75%, the adder will be reduced by 10%, with the possibility of it being further reduced if performance is higher than 85 or 95%. (See PJM OC Briefs: March 6, 2025.)

Monitor Presents Synchronized Reserve Performance Inquiry

The Independent Market Monitor updated the results of its ongoing inquiry into the contributors to low synchronized reserve performance, which has involved reaching out to resource owners whose units under- or overperformed their commitments during deployments exceeding 10 minutes.

The Monitor first presented its findings during the OC meeting Nov. 3. (See PJM Monitor Presents Spin Event Performance.)

Communications issues have become less of a factor since the first event the Monitor investigated on July 8, 2024; however, inadequate training and incorrect parameters continue to be issues, it said.

Incorrect parameters were the largest cause of shortfalls during an Oct. 17 spin event, which saw 2,336 MW assigned with a response rate of 81%. The second largest cause was modeling issues, with the remaining contributors having too few respondents to be reportable because of confidentiality rules.

An Oct. 28 event saw 2,015 MW assigned and 69% responding, with software and hardware issues being the main driver, followed by incorrect parameters.

The Monitor recommended that PJM revise its reserve performance metrics by including all assigned reserves and recognizing overperformance in the calculation. Doing so would increase performance during the Oct. 17 event to 100% and result in 81% performance on Oct. 28.

PJM Seeks Quick Fix on Data Communications

PJM presented a quick-fix solution to revise Manual 1: Control Center and Data Exchange Requirements seeking to add clarity around how the RTO and members share information.

Language was added to reflect NERC’s reliability standard CIP-012-2 (Cybersecurity – communications between control centers), which requires entities to have plans to “mitigate the risks posed by unauthorized disclosure, unauthorized modification and loss of availability of real-time assessment and real-time monitoring data in transit between applicable control centers.” It details the RTO’s PJMNet system for internal communications.

The section detailing the RTO’s Energy Management System (EMS) would be revised to require members submitting distributed network protocol links to provide data maps and definitions. The language includes a statement that PJM will not consume or process data not required for its own purposes.

“This policy additionally ensures fair and balanced benefits of PJM [supervisory control and data acquisition] and networking resources, and ensures that PJM does not prematurely surpass inherent data size limits of the EMS,” the manual language reads.

PJM MIC Tackles Issue Charges, Problem Statements

PJM presented a quick fix proposal Dec. 3 to address instances in which offline generators are committed as secondary reserves and granted lost opportunity cost (LOC) credits, despite governing document language stating resources not synchronized have zero LOC. The quick fix pathway allows for an issue charge to be brought concurrent with a proposed solution.

The issue charge focuses on instances in which a resource that is offline when it is dispatched as secondary reserves comes online before that commitment begins. According to the problem statement, real-time security constrained economic dispatch (RT SCED) commits resources 10 minutes before each interval, but settlement is focused on revenue quality meter data when the commitment begins. If the resource begins injecting energy before the interval begins, it would appear as being online and eligible for LOC credits by the settlement calculations.

The proposal would use resources’ output at the time they are committed by RT SCED to determine if they are offline and, if so, set the real-time secondary reserve opportunity cost at zero.

1st Read on Flexible Resource Definition Clarification Issue Charge

PJM presented a first read on a problem statement and issue charge to reconsider how a resource is defined as flexible and eligible for LOC credits when committed in the day-ahead energy market on an offer with flexible parameters, but could be dispatched on schedules that are not flexible in real time. Under such circumstances, intermediate term (IT) SCED may not be able to determine whether the resource is economic and dispatch it.

The problem statement gave an example of a resource with a flexible cost-based schedule and an inflexible price-based schedule, which is committed on the former in the day-ahead market due to it failing the three pivotal supplier test when a transmission constraint is modeled. If that constraint does not materialize, IT SCED would revert to the price-based offer but be unable to evaluate whether it is economic due to the difference in the parameter flexibility. The resource would not be committed and would receive LOC credits for the duration of its day-ahead commitment on the cost-based offer schedule.

“Opportunities exist to consider whether a resource should be considered flexible for commitment and lost opportunity cost purposes if there are differences in startup time, notification time and min run time parameters amongst the available schedules,” the problem statement reads.

PJM’s Susan Kenney said the issue charge would explore whether the parameters in each of a resource’s offers should be reviewed before it is considered eligible for LOC credits.

Stakeholders argued there may be a deeper issue with the dispatching software if economic resources able to operate are not being dispatched.

PJM’s Brian Chmielewski said the issue is that regardless of whether a unit committed on a flexible schedule in the day-ahead run is economic, real-time dispatching is limited to evaluating all offers based on those flexible parameters.

The issue charge includes education on the definition of flexible resources, how they are committed and when a unit is eligible for LOC credits. It envisions changes to the RTO’s governing documents and manuals addressing LOC eligibility for flexible resources, with work expected to take around three months starting in January 2026. Changes to how IT SCED selects schedules would be out of scope.

Fuel Cost Policy Issue Charge

PJM and the Independent Market Monitor brought an issue charge seeking to address the potential for market sellers to inflate cost-based offers by acquiring fuel cost estimates from an affiliated supplier.

“There may be inherent incentives for a fuel supplier to provide a fuel cost estimate to an affiliated market seller or designated agent of such market seller that may not be reflective of the expected fuel cost or the market price. Such an outcome could be used by market sellers that have market power (e.g., fail the three pivotal supplier test) to potentially manipulate the market by obtaining a fuel cost estimate from an affiliated fuel supplier that may not reflect market pricing of fuel costs. Such an approach would allow market sellers to set energy prices at an uncompetitive level,” the problem statement reads.

The issue charge scope is limited to how fuel cost policies reflect affiliated suppliers of fuel versus independent third parties, while broader changes to the policies would be out of scope.

REAL Team Endorses DR Policy, CONE Value

DENVER — The SPP leadership team responsible for strengthening the grid operator’s resource adequacy construct and recommending policy directions closed out 2025 by endorsing two protocol changes related to demand response and the cost of new entry.

Meeting Dec. 3 during Denver’s first snowfall of the season, the Resource Energy and Adequacy Leadership (REAL) Team approved combined policies for demand response and load-responsible entity peak demand assessments and the value of the cost of new energy for 2026, representing the cost to build a new power plant.

The CONE value, increased to $139.85/kW-year for summer 2026, passed unanimously. However, the REAL Team split 7-5 over the DR and peak demand assessments (RR703), emblematic of the difficulty SPP has had in developing a demand response policy since 2017.

“Everyone knows that SPP has been in increasing complex and challenging issues all the time, and here we are again,” REAL Chair Kristie Fiegen, with South Dakota’s Public Utilities Commission, said after the vote. “The stakeholders have worked very, very hard on this. We have listened to a lot of comments the last six months, and we’ve made a lot of changes. Is it perfect? No.

“So, it may not be perfect today, but we can always come back to it, because we will continue to monitor and adjust this in the future.”

“We’re at a point where staff has considered input from a bunch of different stakeholders … It’s gotten us to a point where I think at least staff is comfortable and [can] support the policy, but it’s not ever going to be ideal,” said Natasha Henderson, SPP’s senior director of grid asset utilization. “I think the policy that we have before us does an adequate job of balancing that as we walk forward. We are going to learn and check and adjust.”

Henderson said the policy has reached the point where “hopefully, people can agree that it’s just and reasonable” and that it balances the affordability and reliability equation at the forefront of the utility industry.

SPP says demand response is “increasingly critical” as it looks at a future with rapid load growth, evolving resource mixes and tighter energy conditions. DR supports reliability, stabilizes prices during uncertainty and helps the region adapt to changing system dynamics, it said.

Staff said a structured DR policy provides entities with multiple participation pathways and market, reliability and potential load-modifying products. It will also help defer the cost of new generation and supporting resource adequacy compliance.

The intent is to increase the visibility and ability to deploy demand response by creating a participation model and accreditation framework for non-price-sensitive DR. SPP seeks to incent LREs to manage peak loads by qualifying non-registered or load-modifying demand response capable of performing when their peak loads exceed their qualified resources.

The assessment will require LREs to use qualified resources to meet demand when accounting for the risk considered in the loss-of-load expectation study that sets the planning reserve margin requirements. That will mean an accurate 50-50 forecast and not one that incorporates all risks.

The peak demand assessment (PDA) is a CONE-based evaluation performed after a weather season based on the variation of actual load from the entity’s load forecast.

The measure was opposed by Evergy’s Denise Buffington, Oklahoma Corporation Commission staffer Jason Chaplin, the Advanced Power Alliance’s Steve Gaw, Oklahoma Municipal Power Authority’s Dave Osburn and American Electric Power’s Richard Ross.

Ross proposed what he called a post-season review to identify the LREs with the largest underforecast amount, requiring them to explain their error in a report that would be delivered to the board’s Oversight Committee. He referred to the review as casting sunshine on any chronic forecasting problems and force members to “sharpen their pencils.”

“I think ours is pretty sharp as it is, but we can do more,” Ross said. “Some folks make fun of my cute little phrases, but the framework would be much like SPP is going to do already.”

“I can’t help but point out the irony of Richard’s ‘sunny day’ proposal when it’s snowing,” Henderson said, gesturing to the falling snowflakes outside.

She reminded the REAL Team that SPP’s tariff requires that a post-season analysis be conducted and a report published. Henderson said the report reviews every LRE and is then discussed by the Supply Adequacy Working Group.

Carrie Bivens, vice president of SPP’s Market Monitoring Unit, said the Monitor still had some outstanding issues with the proposed changes, despite its engagement with RTO staff. She called for clarity around dual participation to “clearly prohibit” loads that are already in a retail program from participating in DR but saved the bulk of her comments for the LREs’ peak demand assessment.

“This is a significant one for us,” Bivens said.

She said the MMU supports the policy’s key objective of efficiently deploying load-modifying resources to manage peak loads and could support a PDA to accomplish this if it assesses deficiencies based on actual load but does not support the current framework.

“If we continue down the path … we think that the deficiencies need to be based on actual load, and that would mean no error tolerance and no weather normalization,” she said. “We do think that this framework, the way it is proposed, actually maintains the RA incentive structure. We just think this policy inappropriately socializes risk to the members.”

In response, Henderson said SPP has already opened three DR-related strategic initiative requests (SIRs 812, 814 and 816) to tackle the MMU’s concerns. The grid operator uses SIRs as part of its strategic road map to meet its long-term goals.

CONE Value Changed

The REAL Team endorsed the CONE’s value — setting it at $139.85/kW-year, up from the current $85.61/kW-year — but did not vote on any changes to the calculation’s process.

SPP bifurcated the proposed tariff change (RR729) following feedback from the REAL Team, the Supply Adequacy Working Group and other stakeholders. Staff said a new revision request will be introduced to address broader process changes, allowing additional time for stakeholder feedback and further development of the inputs and assumptions used to recalculate the CONE’s value.

The grid operator sets its CONE value annually by Nov. 1. Resource adequacy staff adjust the value for inflation and update tax rates and interest rates. It uses U.S. Energy Information Administration data for a generic generator in a region without any special considerations for altering cost as part of the calculation.

The REAL Team unanimously endorsed the measure, with Buffington abstaining.

The Board and Directors and Regional State Committee must both approve the CONE value change.

Fall Alert Hours Drop in 2025

SPP staff told the REAL Team that operations alerts and advisories, which have increased over the past three fall seasons, resulted in only 45 alert hours this year. In October 2024, the grid operator issued a conservative operations advisory and went through 194 alert hours.

Staff said mild September weather and fewer resource outages in late October led to the decrease.

More than 26 GW of outages were recorded in mid-October, consistent with outage trends during the shoulder months in the last three years. By early November, outages were tracking as much as 4 GW below the five-year norm.

Still, the grid operator issued its first resource advisory of the winter Nov. 29 for the entire balancing authority because of expected high peak loads, wind forecast uncertainty, severe cold weather and potential for above-normal generation outages.

SPP treats resource advisories to be normal operating conditions, two steps away from a Level 1 energy emergency alert. Resource advisories are issued to raise awareness in the market and don’t require conservation measures.

The RTO issued seven resource advisories and three conservative operations advisories — the last step before an EEA — during the summer. Staff issued 11 resource advisories during the summer of 2024 and three calls for conservative operations.

New Leadership to Meet

The REAL Team meeting was the last for Fiegen, who has chaired the group since its inception in 2023.

Chuck Hutchison, a member of the Nebraska Power Review Board, will succeed Fiegen as chair in 2026. He said he and SPP Board Chair Ray Hepper and SPP’s Henderson and Casey Cathey will meet to discuss the REAL Team’s work plan for next year.

Big Jump in Ontario Capacity Prices Signals Tightening Supplies

Clearing prices in IESO’s latest capacity auction hit a record $645/MW-day (CAD) for summer 2026, nearly double the $332 from last year’s, and $725/MW-day for winter, more than five times the previous $139.

Although IESO said the impact on ratepayers will be minimal, observers said the jump is further evidence of tightening supply/demand conditions in Ontario and other organized markets in the Eastern Interconnection.

IESO said it procured 1,833 MW of supply for summer 2026 (above the ISO’s 1,800-MW target) and 1,125 MW for winter 2026/27 (below its 1,200-MW target).

Ratepayers will feel little impact from the rising prices, IESO said, because its medium- and long-term procurements play a larger role in the ISO’s Resource Adequacy Framework (RAF). “The total cost of the capacity secured is expected to represent approximately 1% of total system costs,” the ISO said in a statement Dec. 4.

Suppliers who secure an obligation receive payments for making their capacity available in the energy market.

IESO spokesman Michael Dodsworth said prices rose because of higher procurement targets and reduced participation by suppliers, some of which secured contracts through other windows of the RAF. Participation also dropped because of a lack of offers by generation-backed imports from NYISO.

“Last year’s auction was very successful in securing capacity at a low cost. While this year’s prices were higher relative to last year’s auction, they are still comparable with the majority of supply under contract,” Dodsworth said. “We’re still procuring the vast majority of electricity through long-term contracts or other procurements or other mechanisms that have the rates regulated by our provincial regulator,” the Ontario Energy Board.

He noted that the ISO “a little unexpectedly” raised its target procurements by 200 MW, with summer 2026 rising to 1,800 MW from 1,600 MW and winter 2026/27 to 1,200 MW from 1,000 MW.

Tom Chapman, The Brattle Group | The Brattle Group

Tom Chapman, an energy economist with The Brattle Group who previously served as IESO’s senior manager for wholesale market development, agreed that the immediate price impact will be minimal because the auction only makes up about 5% of Ontario’s installed capacity.

Chapman said the ISO’s 200-MW increase in its summer and winter targets was just one variable that led to the higher prices. “I think the surprise was perhaps on the supply side. While demand response did increase its contribution by about 40 MW, a large New York gas generator did not participate in the auction, and their contribution in previous years was about 300 MW. So, [with the] combination of the increase in target capacity and the reduction in supply, there’s about a 400-MW swing from this year to last year.”

Takeaways

Power Advisory, a consultant for industrial and commercial customers, cited these takeaways in a report to its clients:

    • In contrast to the last two auctions, summer prices in the Northwest and Northeast zones were the same as other zones with no locational spreads.
    • Although the procurement target was higher, the amount of capacity procured for the winter was lower than that in the last three annual auctions.
    • Most of the winter capacity procured was from virtual resources — aggregated DR resources that are not metered by the IESO — while physical resources, including imports, dominated summer capacity. The import capacity limit from Hydro-Quebec increased from 400 MW to 600 MW. But the increase in aggregated DR imports from Quebec was insufficient to fully offset the lost supply from gas plants that won contracts in the most recent medium-term procurement (MT-2).

MT-2 Impact

IESO purchased more than 3,000 MW of capacity in the MT-2 procurement, completed in June, most of it from 27 natural gas and wind generators. (See IESO Purchasing 3,000 MW of Energy and Capacity.)

Power Advisory identified five resources that participated in previous auctions and did not receive commitments in this round, including two New York imports — GB II New York and Oswego Harbor Power — and three thermal generators that received MT-2 contracts: Iroquois Falls Power, Kingston Cogen and KAP Power.

IESO’s capacity auction uses a downward sloping demand curve. | IESO

“The reduction in summer supply from these resources totaled more than 470 MW,” Power Advisory said. “The MT-2 prices for most successful generators are below the effective annual capacity auction price.”

In MT-2, IESO purchased 2,006 MW of natural gas-fired capacity beginning in May 2026 and 2029 with a weighted average price of $598/MW-business day.

Tightening Supply in Northeast Markets

Brattle’s Chapman said the auction was just the latest indication of tightening supply/demand conditions.

“When you take these results, along with other recent results — in PJM, it cleared at the cap; MISO, where they had record clearing prices; Quebec, where they were a net importer in 2024 and they’re facing strong load growth and challenging hydrological conditions — I think it speaks to a broader tightening of supply and demand across the Northeast markets,” Chapman said. (See PJM Capacity Prices Hit $329/MW-day Price Cap and MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)

Chapman noted that NERC’s Winter Reliability Assessment showed 20 GW of new load since last winter. “It’s tough to build 20 GW of supply at the best of times, but [with a] challenging supply chain and … all the interconnection issues, there’s [an] imbalance, which the markets are highlighting.” (See NERC Winter Reliability Assessment Finds Many Regions Facing Elevated Risk.)

“I would say that we should be thankful to the wholesale markets for signaling the underlying market fundamentals in a very transparent, clear way that sends a very powerful signal to system planners, regulators [and] policymakers on exactly what’s needed and where it’s needed.”

Power Advisory also saw the results as the latest sign of tightening supplies. “Energy and operating reserve prices … have been well above historical levels over the past year. We expect energy prices to remain elevated given forecasted demand growth and the retirement of the Pickering Nuclear Generating Station, which will remove 2,100 MW of baseload supply at the end of 2026.” (See related story, Ontario Greenlights Overhaul of Pickering Nuclear Station.)

Brady Yauch, Power Advisory | Power Advisory

“In short, Ontario’s grid is getting very ‘tight,’ and while that first appeared in the energy market, it is now showing up in the capacity market,” Power Advisory continued. “With that tightening supply/demand balance across such a large region, procuring capacity through the province’s interties will either become challenging from a physical perspective (i.e., the capacity is not available) or expensive.”

“If resources from outside Ontario can participate in other capacity auctions (New York and potentially PJM in particular), they need to consider the potential revenues from those auctions compared to Ontario,” Brady Yauch, Power Advisory’s director of markets and regulatory, explained in an email. “If those prices move higher, the opportunity cost of locking up supply in Ontario is higher, and they would have to adjust their offer accordingly (or would not participate at all).”

Demand Response

Chapman said he was encouraged by the increase in DR.

“This auction is showing that there’s still untapped demand response capacity in Ontario, because the demand response providers were able to extract a further 40 MW. And that’s even after 10 years of auctions, which is pretty encouraging that there’s still that sort of potential in a mature market like Ontario.”

Rodan Energy Solutions, which says it is Ontario’s largest DR provider with over 300 MW under management, said it secured the largest virtual capacity position in the auction.

Power Advisory was less bullish on the potential for additional growth in DR.

“Higher clearing prices should encourage more load customers to offer DR; however, it is not clear how much achievable DR potential remains in Ontario and how quickly new DR supply could enter the market,” it said. “If there is insufficient new capacity in future auctions, participants may feel comfortable pushing offer prices higher. Ontario is facing a new reality when it comes to its supply/demand balance and prices.”

Reliability Concerns

Chapman said the results show system planners need to expedite their decision-making and give interconnection priority to dispatchable resources.

“Everything will be fine as long as conditions remain normal. There’s adequate supply. … But if we see any deviation from that — as SPP and ERCOT saw in 2021 with Winter Storm Uri — it could lead to reliability impacts,” he said. “I think that should really focus people’s minds on the …  need for urgent and quick decision-making. It may require some hard decisions … like which resources should be given priority to connect.

“This is one area I feel that Ontario — I’m not sure whether [by] luck or design — has perhaps got it right under the current market conditions,” he continued. “It’s a single jurisdiction, and it has launched expedited procurements to meet an identified need. It isn’t as overly reliant on a single auction to meet all of its capacity needs; [it doesn’t] have all its eggs in one basket. And it seems to have a balance that’s perhaps better fit for current conditions than some of the other neighboring markets. I think some of the neighboring markets could learn a few lessons from the Ontario experience, if they are so interested.”

NextEra Energy Pursues Gas-fired Data Center Deals

NextEra Energy is pursuing a goal to power 15 to 30 GW of data center hubs by 2035 and a series of nearer-term agreements in the technology sector.

The 2025 Investor Day presentation Dec. 8 did not mince words: “We are in a golden age of power demand,” and NextEra is “America’s premier energy infrastructure company.”

Until recently, NextEra had been promoting itself as the leading renewable energy developer, but now it is an “all-forms-of-energy company.”

The data center hubs are expected to contribute at least 15 GW of new generation by 2035 under a base scenario and 30 GW under an upside scenario. They already have identified more than 20 potential hubs and expect to have more than 40 possibilities by the end of 2026.

Natural gas will play a large role in this, “and we are making excellent progress in our development efforts,” the company reported.

Accompanying the projections was a set of diverse announcements, led off with a partnership with Google Cloud to develop multiple new gigawatt-scale data center campuses with accompanying power generation and capacity.

The two companies expect the collaborative approach to speed land development, load interconnection and development of infrastructure.

Additionally, they will collaborate on NextEra’s internal digital transformation and use technological innovations and artificial intelligence to accelerate the buildout of data centers and the energy infrastructure supporting them.

In Related News

NextEra Energy Resources and Meta Platforms have reached 11 power purchase agreements and two storage agreements totaling approximately 2.5 GW of clean energy. This consists of nine solar projects in ERCOT, MISO and SPP totaling 2.1 GW; two solar projects in New Mexico rated at 190 MW; and 168 MW of battery storage, also in New Mexico. They are expected to come online in 2026 through 2028.

NextEra Energy Transmission and Exelon say they will partner to build an approximately 220-mile bidirectional 765-kV line in PJM territory to facilitate more than 7 GW of power generation. The project carries a $1.7 billion price tag; the PJM board’s final vote on it is expected in early 2026.

NextEra Energy Resources says it will acquire natural gas supply, storage and management company Symmetry Energy Solutions, which has 5,500 commercial/industrial customers and 80,000 mass-market customers in 34 states. The deal is intended to complement NextEra’s buildout of gas transmission and gas-fired generation and is expected to close in the first quarter of 2026, pending regulatory approvals.

NextEra Energy Resources and Basin Electric Power Cooperative say they will explore joint development of a new 1,450-MW combined-cycle gas-fired power plant in North Dakota to serve as the foundation for a multi-gigawatt data center campus. Under Basin’s Large Load Commercial Program, the two submitted an application to the SPP Expedited Resource Adequacy Study process in October.

NextEra Energy Resources is partnering with Comstock Resources on a plan to build up to 8 GW of new gas generation and storage to support hyperscaler data center development in central Texas. Initial power is expected as early as 2027.

NextEra Energy Resources and ExxonMobil are pursuing construction of a 1.2-GW gas-fired, carbon-abated plant on a site with proximity to ExxonMobil’s Denbury carbon dioxide pipeline, gas supply and transmission. They are jointly marketing the plant to hyperscalers, and they view it as a proof of concept that could lead to multisite development opportunities.

Ariz. Regulators Slash APS’ DSM Plan, Express Support for VPP Programs

Arizona regulators approved a demand-side management plan for Arizona Public Service that slashed the plan’s proposed budget by more than half and eliminated many of its programs — but spared and even encouraged virtual power plant programs.

The Arizona Corporation Commission voted 5-0 on Dec. 3 to approve the scaled-back plan with a budget of $40 million rather than the requested $91 million.

ACC staff recommended approval of APS’ DSM plan, finding that the plan’s newly proposed programs would be cost-effective.

But Chair Kevin Thompson proposed an amendment, which the commission approved, that slashed the plan’s programs and budget.

“I’ve been anxious to get this matter before this commission so that we can trim some of the bloat and fat from this budget,” Thompson said.

Thompson blamed the situation on previous commissions that “condoned and even required these programs to expand to the point where they ballooned beyond the intent of the original goals.”

An APS representative said the company didn’t oppose Thompson’s amendment.

ACC rules require utilities to file a DSM plan. The cost of programs in an approved plan can be recovered through a customer fee.

Among programs the commission rejected were APS’ proposed measures to encourage mini-split heat pumps and air conditioners and pool pump recalibrations in existing homes.

The ACC suspended all funding for the residential new construction program, which offered incentives to builders that meet energy efficiency standards in new homes. APS had proposed increasing an incentive, from $100 to $200, for prewiring new homes for EV charging.

Thompson said installing energy efficient appliances in new homes is already required by law.

The ACC axed incentives for electric golf carts, high-frequency golf cart battery chargers and energy-efficient livestock fans. APS said in its plan that golf cart-style utility vehicles are increasingly popular as work vehicles beyond golf courses.

Funding was eliminated for the conservation behavior program, which has provided home energy reports and personalized energy-saving tips to about 500,000 residential customers.

VPP Programs Spared

Spared from the chopping block was a home weatherization program for low-income residents.

The commission also saved APS’ virtual power plant programs, which include commercial and industrial demand response and the Cool Rewards residential program. Cool Rewards gives a $35 annual credit to customers who agree to have their thermostat setting raised when energy demand increases during a summer heat event.

APS wants to expand Cool Rewards beyond its 4 to 7 p.m. timeframe in June through September. Market prices can still be high from 7 to 8 p.m., said Kerri Carnes, director of customer to grid solutions for APS.

“There have been instances where it would have been nice to call on those thermostats in early October, for instance,” Carnes told the commission.

Also spared was a “bring your own device” pilot program for home batteries, which the commission approved in March. APS customers who agree to participate in up to 60 battery-dispatch events from May through October will be compensated with an annual $110/kW capacity payment.

The commission approved an amendment from Vice Chair Nick Myers that directs APS to strengthen its VPP programs.

Myers wants to see APS adopt a “more cohesive” VPP strategy, potentially consolidating separate programs.

“A VPP should not be treated as a niche pilot or a scattered set of incentives,” Myers said. “It should operate as a true grid asset — one capable of delivering firm capacity, supporting reliability events and reducing the pressure on ratepayers to build traditional generation or wires solutions prematurely.”

Raab Associates’ Restructuring Roundtable Looks Back on 30 Years

BOSTON — Raab Associates held its final New England Electricity Restructuring Roundtable on Dec. 5, bringing reflections from speakers about the legacy of restructuring and the future of the power sector in the region.

Several speakers praised the Roundtable for consistently bringing together a wide range of perspectives and interests, and helping to promote collaboration and consensus among stakeholders.

“The diversity of perspectives that are at the table is pretty incredible,” said David Cash, former EPA regional administrator for New England. “There are people here who have sued each other; there are people here who are competitors.”

Dan Sosland, president and co-founder of the Acadia Center, said the Roundtable has been somewhat unique among power industry events for its inclusion of climate and environmental perspectives.

“At the Roundtable we were co-equals,” Sosland said. “We were included, and that’s a testament to” Raab Associates President and Roundtable convenor Jonathan Raab.

The Roundtable was founded in 1995 to bring stakeholders together to discuss the details and challenges of electricity industry restructuring. It opened to the public after Massachusetts passed its restructuring law in 1997, and Raab Associates formally took over the event from the Massachusetts Department of Energy Resources in 2000.

As the states worked through the kinks of restructuring, the Roundtable gradually became “much more of a policy forum,” said Raab, who helped found the Roundtable and moderated the events for most of the 30-year run.

In 2026, the consulting firm Apex Analytics will take control of the Roundtable. The company was selected through a competitive request for proposals and plans to hold its first event in March.

“The Roundtable’s strength lies in its adaptability and commitment to discussing meaningful substance around the evolving energy landscape,” said Matt Nelson, principal at Apex and former chair of the Massachusetts Department of Public Utilities. “Our team is committed to maintaining that core while thoughtfully exploring ways to evolve and provide relevant content as industry needs change.”

Reflections on Restructuring

The event also may mark ISO-NE CEO Gordon van Welie’s last public appearance at the helm of the RTO he has led since 2001. (See Retiring ISO-NE CEO van Welie Reflects on 25 Years at the RTO.)

He emphasized the progress that has been made around collaboration in the region, saying, “Even when things do seem a bit tense, we’ve developed mechanisms to deal with those frictions.”

Restructuring and the move to wholesale markets have brought customers significant savings, though not all initiatives have worked as well as he would have liked, he said.

“I would say we made a mistake in going to the Forward Capacity Market back in 2004,” van Welie said, adding that it “became too much of a crutch” for ensuring resource and energy adequacy.

ISO-NE’s proposed move to a prompt capacity market will “hopefully stimulate bilateral contracting,” he said. “The market needs to invest more on a foundation of bilateral contracting with the spot capacity market really being a deficiency charge for somebody who’s not fully hedged.”

Rebecca Tepper, secretary of the Massachusetts Executive Office of Energy and Environmental Affairs, praised ISO-NE’s reliability record.

“ISO-NE has never had to call a control outage in its history,” Tepper said. “It’s something that we shouldn’t take for granted and a huge benefit for consumers.”

“Some of it has been luck — we dodged the bullet once or twice — but a lot of it has been operational awareness and market design,” van Welie said.

Tepper said it has taken longer to get the retail side of restructuring right, pointing to the lingering problem of predatory supply practices that target residential customers. The growth of municipal aggregation programs in Massachusetts in recent years has enabled better protections and options for residential customers, she said.

As the ongoing deployment of advanced metering infrastructure in the region enables new rate designs that incentivize shifting demand away from peak hours, van Welie said New England should consider “a more command-and-control structure for [demand response],” allowing customers to give up some control of their home appliances in exchange for a lower rate.

Looming Supply Challenges

Both van Welie and Tepper also emphasized the need to focus on bringing in new sources of supply to meet rising demand, and Tepper said regional collaboration will be essential to addressing looming supply challenges.

Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said the states are “working on multiple multistate RFPs; that is becoming much more of the norm than the exception.”

Several speakers stressed the importance of demand-side innovation, new programs and rate reforms to help prevent supply issues in the coming decades.

While most demand growth projections forecast peak demand to roughly double by 2050, “I don’t think these have to be written in stone,” said Jamie Dickerson, senior director of energy and climate programs at Acadia. He pointed to a Brattle Group study indicating that grid flexibility could reduce New York’s 2040 winter peak by about 21%. (See Study Finds Considerable ‘Grid Flexibility’ Potential in New York.)

Jesse Jenkins, a Princeton University associate professor focused on the decarbonization of energy systems, echoed Dickerson’s comments and said even greater demand flexibility gains may be achieved if costs come down for technologies like thermal storage.

“There are lots of ways we can cut [peak demand forecasts], including ground-source geothermal, which is often twice as efficient, if not more, than air-source heat pumps,” he said.

Dickerson also stressed the importance of energy efficiency investments while urging policymakers to find more progressive ways to fund EE programs, including through the tax base.

“We do need to lean on those with a greater ability to pay,” he said.

PJM Stakeholders Endorse Manual Revisions for Modeling DERs

The PJM Planning Committee on Dec. 2 endorsed by acclamation manual revisions to reflect how distributed energy resources would be accredited for participation in the 2028/29 Base Residual Auction in compliance with FERC Order 2222. The market-side rules were endorsed by the Market Implementation Committee in November. (See PJM Stakeholders Endorse Rules for DER Participation.)

The changes to Manual 20A: Resource Adequacy Analysis detail how components of DERs would be reflected in effective load-carrying capability modeling and the reserve requirement study, how hourly output would be simulated for each component technology class, and how accredited unforced capacity would be calculated for each resource. Class ratings would not be produced for DERs as a whole; instead, they would be calculated for each resource based on its composition.

The proposed Manual 21B: PJM Rules and Procedures for Determination of Generating Capability language includes the calculation of installed capacity and effective nameplate capacity values for each DER component and how backcasts of hourly performance would be produced. Aggregations including wind or solar components can substitute PJM’s backcast with their own going back to June 1, 2012, with accompany documentation of the methodology and date used to produce it.

Planning Manual Revisions Endorsed

Stakeholders endorsed revisions to Manual 14B: PJM Region Transmission Planning Process drafted through its periodic review, including several administrative updates and a change to ambient ratings to conform with FERC Order 881.

When PJM is developing the light-load ambient ratings in the assumptions for the Regional Transmission Expansion Plan (RTEP), transmission owners would be permitted to choose either the default 59F thermal rating or 60F.

The RTEP Reliability Planning section was tweaked to add phase angle regulators when referencing phase shifting transformers to improve consistency between manuals and the new equipment energization process checklist. The section was updated with links to the relevant PJM departments.

First Read on Manual Revisions Expanding Dual-fuel Definition

PJM presented a first read on revisions to Manual 21B to reflect FERC-approved changes to the definition of dual-fuel gas generation to include configurations where the secondary fuel is stored off site but connected to the generator with a dedicated firm pipeline (ER25-3413). (See “Reworked Dual-fuel Definition Endorsed,” PJM MRC/MC Briefs: July 23, 2025.)

When first introducing changes to the governing documents in June, Dominion said resources with a dedicated connection to secondary fuels can provide a comparable level of reliability as those where the fuel is stored on site. (See “Dominion Presents Proposal to Change Dual-fuel Definition,” PJM MRC/MC Briefs: June. 18, 2025.)