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December 9, 2025

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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 also 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 are still 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.

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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.

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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 (CONE) for 2026, representing the cost to build a new power plant.

The CONE value, increased to $139.85/kW-yr 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 load responsible entities (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 (MMU), 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-yr, up from the current $85.61/kW-yr — 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 committee Chair Denise Buffington of Evergy 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 (EEA). 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.

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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.”

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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.

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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.”

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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.

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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 (DERs) would be accredited for participation in the 2028/29 Base Residual Auction (BRA) 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 (ELCC) modeling and the reserve requirement study (RRS), how hourly output would be simulated for each component technology class, and how accredited unforced capacity (AUCAP) 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 (ICAP) 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.)

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DOJ, Constellation, Calpine Reach Antitrust Settlement

Under a federal antitrust settlement, Calpine Corp. will divest ownership in several generation assets on the PJM and ERCOT grids as a condition for its acquisition by Constellation Energy.

If approved by a court, the resolution will clear the way for a $26.6 billion transaction that will make Constellation the largest U.S. wholesale power generator.

FERC and regulators in New York and Texas previously approved the deal.

On Dec. 5, Constellation and the Antitrust Division of the U.S. Department of Justice (DOJ) announced a proposed resolution to the final regulatory hurdle.

DOJ said it was concerned the acquisition could harm competition and raise prices in the PJM and ERCOT grids by more than $100 million a year. DOJ and the state of Texas simultaneously initiated a civil antitrust lawsuit (1:25-cv-04235) seeking to block the acquisition and a proposed divestiture settlement that would allow it to go forward.

The companies accepted the terms. DOJ said it was the first settlement consent decree the Antitrust Division had filed in a power industry merger in 14 years.

“This settlement includes a six-plant divestiture to an acquisition that risked harming tens of millions of electricity consumers in the mid-Atlantic and Texas,” Assistant Attorney General Abigail Slater said in a news release. “I am appreciative of the partnership with our co-plaintiff, the state of Texas, to secure relief for consumers.”

Constellation CEO Joe Dominguez hailed the agreement as clearing the way for a foundational step in the next era of American growth and innovation. “We thank the department for its professionalism and tireless work reviewing this transaction through these many months. It’s now time for us to complete the transaction, welcome our new colleagues from Calpine and together begin our journey to light the way to a brilliant tomorrow for all.”

FERC’s approval in July entailed Calpine selling 3,546 MW of generation, all of it in PJM: the 1,134-MW natural gas combined-cycle Bethlehem Energy Center, the 569-MW dual-fuel combined-cycle York Energy Center Unit 1, the 1,136-MW dual-fuel combined-cycle Hay Road Energy Center and the 707-MW simple cycle gas-fired Edge Moor Energy Center. (See FERC Approves Constellation Purchase of Calpine with Conditions.)

The proposed antitrust settlement entails sale of York Unit 2, an 828-MW natural gas-fired, combined-cycle plant in Pennsylvania; the Jack Fusco Energy Center, a 605-MW natural gas-fired combined-cycle facility outside Houston, Texas; and a minority ownership interest in the Gregory Power Plant, a 385-MW natural gas fired combined-cycle near Corpus Christi, Texas.

When it announced the Calpine deal Jan. 10, Constellation anticipated the need for some asset sales in PJM. (See Constellation to Acquire Calpine for $29.1B.)

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CPUC OKs PG&E Request for 2026 Diablo Canyon Cost Recovery

The California Public Utilities Commission on Dec. 4 approved Pacific Gas and Electric’s request to recover about $382 million from ratepayers to continue operating the Diablo Canyon Power Plant in San Luis Obispo in 2026.

The approved 2026 revenue amount covers operations and maintenance activities, resource adequacy substitution capacity forecasts and fuel from 2025 through 2030, among other items, the decision says.

“I know these issues [in the decision] have not been easy,” CPUC Commissioner Darcie Houck said. “The extended operations of Diablo Canyon Power Plant are a critical piece of the state’s electricity reliability requirements, and PG&E does need to be compensated consistent with the statute.”

Diablo Canyon had been scheduled to close by 2025, but in 2023 the CPUC approved a 5-year extension for the plant, keeping its two reactors online until at least 2029 and 2030. The approved 2026 revenue requirement will decrease the average bundled service rate for PG&E customers from about 34.8 cents/kWh to about 34.6 cents/kWh.

The revenue requirement costs will be split among PG&E (44%), Southern California Edison (46%) and San Diego Gas & Electric (10%). The decision requires PG&E to provide a “detailed account” of why it did not seek government funding to offset certain ratepayer costs.

“The tracking of costs is going to continue to be very important to ensure that there is no double recovery at a later date,” Commissioner John Reynolds said.

SGIP Refunds

At the Dec. 4 voting meeting, the CPUC also approved a decision that closes the ratepayer-funded portion of the Self-Generation Incentive Program (SGIP), setting out the return of leftover money to ratepayers, while establishing rules for implementing the portion of the program financed by the Greenhouse Gas Reduction Fund (GGRF).

The SGIP was implemented more than 20 years ago to provide incentives to certain distributed energy resources on the customer’s side of the utility meter to help shave peak demand. Qualifying technologies included internal combustion engines, gas turbines, energy storage systems, and combined solar and energy storage systems, among others.

The structure of the program has gone through multiple iterations, and over time its focus has shifted from reducing peak load to cutting greenhouse gas emissions.

In 2020, SGIP was extended from Jan. 1, 2021, to Jan. 1, 2026, under California Senate Bill 700, which authorized the CPUC to collect $166 million in ratepayer funds per year for the program from 2020 to 2024. In 2022, Assembly Bill 209 removed a requirement that the CPUC administer solar resources separately from other technologies under the SGIP, provided funding for combined solar and storage resources and directed the agency to use AB 209 funds for all residential customers, including those served by publicly owned utilities.

In 2023, SB 102 allocated $280 million in GGRF money to the SGIP and restricted participation to eligible low-income residents installing behind-the-meter storage or solar-plus-storage systems. According to the CPUC’s ruling, the GGRF-funded SGIP budget was opened for reservation in June 2025. The program’s administrators — namely the state’s utilities — are expected to administer the GGRF-funded SGIP similarly to the ratepayer-funded program.

SGIP projects are subject to time-of-use and demand response requirements to support grid reliability and were required to enroll in a TOU rate and DR program for 10 years.

“Once SGIP closes it will be important for the electric investor-owned utilities associated with SGIP projects and customers to monitor ongoing compliance with TOU and DR requirements to ensure that the state is achieving the full ongoing benefits of these systems,” the CPUC said in the decision. “This approach will allow SGIP to close before all projects get through the 10-year permanency period while maintaining program and grid benefits.”

High Stakes on Undergrounding

The CPUC approved a resolution that updates its guidelines for undergrounding electric distribution lines. The updates include new requirements for determining whether cost recovery is reasonable for an undergrounding project; a revised method for choosing the most cost-efficient projects; and an explanation of how to calculate cost-benefit ratios to maximize wildfire risk reduction and minimize costs, among others.

“Our electric grid … has experienced catastrophic failures leading to loss of life and home,” Reynolds said. “This has led us in this regulatory space to rethink our approach to risk on the grid.”

“We know we will need additional standards to judge what undergrounding projects should be funded by ratepayers … the costs here are enormous,” Reynolds added. “We know we will be evaluating 10 to 11 figures in capital costs with average monthly customer bill impacts as high as $25. With stakes that high for a single capital program, we need to get the methodology right.”

The CPUC also approved a new rate for 2026 for the state’s wildfire fund non-bypassable charge. The new rate of $0.00591/kWh rate will add about $909 million to the fund, according to the decision.