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March 28, 2025

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Industry Anxiety over Grid Reliability Overblown, Panel Says

The current debate in the U.S. electricity sector pitting efforts to increase renewables against the need for grid reliability in the face of growing demand could be unnecessary and counterproductive, according to Ric O’Connell, executive director of the nonprofit GridLab. 

Faced with ever-escalating forecasts of demand growth from data centers, “a lot of utilities and grid operators and their regulators are getting a little nervous … that we’re not going to be able to have adequate resources to meet this growing load,” O’Connell said.  

“I actually don’t think that concern is valid. I think we can do both. … We can both grow the clean energy percentage of our electricity and grow the amount of load that we need to meet certain demand,” he said. 

Speaking at a March 26 webinar hosted by the nonprofit Energy Innovation Policy and Technology, O’Connell cited real-world, real-time examples to support his argument.  

Texas now leads the U.S. in terms of total generating capacity, growing 36% over the past decade, while also doubling its share of renewables from 23 to 42%, he said. During times of peak production, carbon-free resources may provide more than 80% of the state’s power.  

ERCOT’s online dashboard, tracking energy supply and demand across the Texas grid, showed solar, wind and nuclear making up about half of its generation mix March 27. 

SPP ran about 47% on carbon-free generation in 2024, with wind power across the region at times providing 90% of the RTO’s power, O’Connell added. 

Such comments, from O’Connell and other speakers, were aimed at fleshing out Energy Innovation’s recent report, “Grid Reliability in the Clean Energy Transition,” which argues for a more expansive, system-level approach to reliability. (See Energy Innovation: US Needs New Approach to Grid Reliability.) 

“Reliability is thrown out a lot, and not always accurately or correctly,” said Sara Baldwin, Energy Innovation’s senior director of electrification policy and co-author of the report. “Reliability is actually a characteristic of the entire electricity system, and individual resources contribute to reliability as part of a balanced portfolio. … 

“So, whenever you hear someone talking about the reliability of a single resource, that should raise a flag.” 

The Energy Innovation report defines reliability as a combination of three core components: resource adequacy (long-range planning for future demand), operational reliability (day-to-day, real-time balancing of supply and demand) and resilience (the ability to ride out and recover from extreme events). 

The traditional arguments raised against renewables are that they are intermittent and therefore cannot provide the 24/7 reliability and grid support services of coal, natural gas or nuclear power. But according to Julia Matevosyan, associate director and chief engineer at the Energy Systems Integration Group, technology is available to allow solar, wind and storage to provide a full range of grid support services, through the inverters that convert the DC power from solar panels and wind turbines into the AC power the grid uses. 

The capabilities of these inverter-based resources have evolved as the percentage of renewables on the grid has increased, said Matevosyan, who previously worked as the lead planning engineer at ERCOT. For example, as renewables hit 10 to 20% of generation, inverters had to be set to ensure a solar or wind project could stay online and in operation in the event of a brief disturbance on the grid.  

As renewables start to replace coal or natural gas, their inverters have to be able to provide voltage and frequency support, she said. At even higher levels, up to 75%, inverter-based resources can provide “essential reliability services,” with “grid-forming” technologies, which are “advanced controls … [that] can provide the suite of reliability services that synchronous generators are providing today,” Matevosyan said. “With that technology, you can potentially go to 100%” renewables.” 

Grid-forming technologies have been demonstrated on small islands and in “large-scale system studies,” she said. “So, from the technology perspective, what I want to say is, just as the grid evolves and we define what the grid needs ― we define it in technology-neutral terms ― technology will step up and provide.” 

Clean, Firm Emerging

But the Energy Innovation report also acknowledges that a significant gap exists between IBRs’ technical capabilities and industry confidence in their ability to deliver when needed in real life.  

“Developers must be disciplined to program their resources to ride through a voltage event [even] if such a setting should compromise their asset or their operating revenues,” the report says. Similarly, utilities and grid operators need to “quantify and understand how IBRs respond during a grid emergency” and ensure appropriate compensation in cases where they “provide a superior response.” 

At present, utilities, grid operators and the Trump administration are looking to natural gas and nuclear to respond to what they see as a looming reliability crisis, while characterizing renewables as intermittent and unreliable. 

In his opening remarks at a March 25 congressional hearing on grid reliability, Rep. Bob Latta (R-Ohio) said EPA regulations limiting emissions from power plants were driving early retirements of dispatchable baseload power. 

“Significant subsidies for intermittent generation undermine the economics of baseload, or on-demand, dispatchable generation resources that are essential to keeping the lights on,” Latta said.  

Speakers at the Energy Innovation webinar offered two potential low- or no-carbon solutions.  

First, demand-side management can provide varied options for improving grid reliability, O’Connell said.  

“We don’t want to just focus on the supply side. … It used to be hard to sort of have load that was responsive to price or other kinds of signals, but now we’ve got smart thermostats; we’ve got customer-sited batteries; we’ve got EV charging,” he said. “Really, this is a load that can be controlled and respond to market signals. This is a really important way that we’re going to be able to meet our reliability [needs].” 

Wilson Ricks, a doctoral researcher at Princeton University, pointed to the second solution: emerging clean, firm technologies, including long-duration energy storage, next-generation nuclear and geothermal, and fossil fuel generation with carbon capture and storage.  

Rising amounts of renewables on the system are flipping seasonal demand peaks from hot summer afternoons, when renewables tend to be plentiful, to winter mornings, when they are not. “Current batteries are not necessarily a cost-effective solution to very long periods of low wind and solar output,” Ricks said. 

“There’s a whole suite of emerging technologies that are designed to help fill these very rare but important gaps and ensure a 100% reliable, clean system,” he said.  

The catch, Ricks said, is that all the promising technologies are still in early stages of development and commercialization and are very expensive. Demonstration projects are in the works, he said, but “ensuring the success of at least some of these projects is going to be crucial to ensuring the availability of a portfolio of clean firm resources that we’re going to need for 100% reliability.” 

Getting clean, firm generation to commercial scale could also change the role of always-on baseload power as a foundation of reliability. While it will always be needed and valuable in some circumstances, “baseload has not been a panacea in the past,” Ricks said. “It’s only one portion of our grid. We still have fluctuating demand, and baseload generators don’t meet that. It’s certainly not the end-all, be-all of reliability going forward.” 

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Meteorologist Warns Climate Bringing Multiple Grid Impacts

NEW ORLEANS — Sunny Wescott, chief meteorologist for the U.S. Department of Homeland Security, opened her presentation at SERC Reliability’s March 26 Members meeting by promising, “It’s only going to get worse.” 

And while she was referring to the font size of the many text boxes crowding her slides, she could just as easily have meant the content of her talk about the growing risks that climate change poses to the electric grid and other critical infrastructure around the globe. 

Wescott has made several appearances at ERO events in recent years, delivering speeches filled with so many warnings about developing dangers that NERC CEO Jim Robb joked at 2024’s GridSecCon security conference that he wanted to find her parents and “ask what they were thinking when they named her ‘Sunny.’” (See Weather-security Connections Highlighted at GridSecCon.) 

The presentation to SERC members followed this pattern, with Wescott — who emphasized that she was there as “Sunny the scientist” rather than in her official capacity — emphasizing that the world faces unprecedented changes to weather patterns. Operators will need to prepare for an era of uncertainty that will challenge the assumptions under which all human infrastructure has been constructed. 

Wescott started by laying out the basics of the changing climate, using a chart based on data from the National Oceanic and Atmospheric Administration that showed 2024 and the 10 warmest years on record — all from the last decade — in terms of monthly differences from the average temperatures in the 20th century. She warned that this trend is pushing conditions beyond what existing atmospheric models were meant to deal with. 

“When we see abnormal temperatures like this, the models could not have been trained on it. It’s impossible, because this is superseding all prior years,” Wescott said. “The 10 hottest years on record all having occurred in the last decade means that this is a continuous growing trend.” 

Scientific models aren’t the only things being pushed past their limits, Wescott continued. All of the materials used to build infrastructure facilities — concrete mixtures, adhesives, metals and others — were formulated to work in climate conditions similar to those that prevailed in earlier decades. 

Those assumptions all need to be re-examined now, she said. Certain formulas for concrete may not set as quickly, or at all, in hotter temperatures. Epoxies may need longer to cure and not be as flexible when they do, leading to cracks. Some chemicals may begin to produce harmful vapors in higher temperatures. Extreme heat can cause metals to expand and weaken the structures of which they are a part, in addition to affecting their electrical resistance and magnetism.  

More dangers will come from the winds and precipitation fueled by the increased evaporation of water. Wescott said that “super cell [storms] are now … covering more area [and] staying on the ground longer,” and went on to mention “a fivefold increase in straight line winds” and hail stones more than 8 inches in diameter recently seen in South Dakota. Hailstones also contain less air than they did 20 years ago, meaning they are heavier and more damaging. 

The problems extend beyond the infrastructure equipment itself. Sustained high heat will create hazards for repair crews: They may dehydrate; their equipment may become hot enough to burn them; and their cell phones may overheat and malfunction. Extreme heat is even known to make animals and humans more aggressive and violent, meaning security could become more of a problem. 

Effects may even be seen below the surface, Wescott said. She explained that aquifers around the world have run low in recent years, with heat causing both accelerated evaporation and increased use for drinking and cooling. Depleting this water leaves large voids underground, which makes these regions more vulnerable to seismic stress. 

Areas of increasing seismic risk in the U.S. with locations of nuclear power plants | USGS

Wescott shared a map of the country based on data from the U.S. Geological Survey, showing areas of increased seismic risk. She overlaid this map with dots representing nuclear reactors, noting that multiple reactors were located in areas the USGS marked red, indicating highest risk. 

“I’d heard it was a killer presentation. I just hadn’t realized it was actually a killer presentation,” SERC board Chair Lee Xanthakos joked after Wescott’s presentation. He asked Wescott for her opinion of the best ways to build infrastructure that could withstand the climate changes of the future. She replied that “it’s both the materials and the shape.” 

“Look at the structures that we have chosen. This room is a great example,” she said, gesturing around the rectangular conference room where the meeting was held. “We know that flat edges do not sustain [wind and water] well [and] domes do. I’ve always [said] that … the future is domed, not doomed. 

“If we were able to go back and choose different shapes, different material types — what does it look like to take a structure like this, not scrap it and say that the structure is weak and needs to be completely redone, but create an exoskeleton that can go over it to increase the tensile strength of the building in full? There are mitigation strategies like that. … There is no reason for most of our sites to be as under the thumb of these weather events as they are. They don’t need to take as much damage.” 

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WEIM Q4 Prices Down on Lower Gas Costs, CAISO DMM Finds

CAISO’s Department of Market Monitoring (DMM) said March 27 that lower natural gas prices helped drive down energy prices in the Western Energy Imbalance Market (WEIM) in the fourth quarter of 2024.

Energy prices across the WEIM averaged about $39/MWh in the 15-minute market — down approximately 31% compared to the fourth quarter of 2023 — despite load being about 2% higher on average, according to Ryan Kurlinski, the DMM’s senior manager of monitoring and reporting.

Similarly, the DMM’s quarterly report found prices in the five-minute market “were also down 31% and day-ahead market prices were down 22% compared to Q4 2023.”

The lower energy prices were largely due to lower gas prices, according to the DMM.

“Average fourth quarter prices at the two main delivery points in California (PG&E Citygate and SoCal Citygate) decreased by 31% and 50% compared to the same quarter of the previous year, respectively,” the DMM report stated.

Prices at the Henry Hub trading point, a reference point for natural gas markets, decreased by 14% in the fourth quarter of 2024 compared to the same quarter of 2023.

Prices at Northwest Sumas and El Paso Permian also dropped by 47% and 26%, respectively, during the same period, according to the DMM.

Compared to the rest of the WEIM region, California recorded the highest average energy price at about $45/MWh in the quarter, while other regions’ 15-minute market prices ranged between $32/MWh and $38/MWh, according to DMM.

“The greenhouse gas costs in California continue to be a significant contributor to the higher prices in California compared to other regions,” Kurlinski said.

The fourth quarter of 2024 also saw an upswing in generation from renewable resources in the WEIM footprint. Renewable output “increased by about 4,320 MW (14%) compared to the fourth quarter of 2023. Over 65% of this growth was from wind and solar generation, both of which increased in every region,” according to the report.

Average hourly battery discharge in the CAISO and Desert Southwest regions also increased by 490 MW (64%) and 300 MW (125%), respectively.

Meanwhile, the report pointed to a continued pattern of congestion revenue rights auction revenues underfunding CRR payments, with the fourth quarter marking a $1.7 million shortfall. (See Congestion Revenue Rents Still Underfunded, CAISO DMM Says.)

“These losses are borne by transmission ratepayers who pay for the full cost of the transmission system through the transmission access charge,” according to the report. “Changes to the auction implemented in 2019 have reduced, but not eliminated, losses to transmission ratepayers from the auction. The [DMM] continues to recommend further changes to eliminate or further reduce these losses.”

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MISO Feb. Real-time Prices Nearly Double from 2024

MISO’s real-time energy prices in February 2025 nearly doubled from a year earlier as the footprint saw higher load and gas prices.

The grid operator recorded an average $41/MWh real-time locational marginal price over the month compared to an average $22/MWh in February 2024, according to an operations report. The RTO’s real-time price closely tracked January 2025’s average, at almost $42/MWh.

While coal prices stayed flat year-over-year in February at an average $2/MMBtu, gas doubled from $2/MMBtu to $4/MMBtu. The RTO’s real-time price was nearly as high in February 2022, when it hovered at $40/MWh as Russia’s invasion of Ukraine began sending gas prices upward.

In a previous winter round-up, MISO’s Independent Market Monitor said the historically low gas prices of 2024 evaporated due to sustained cold weather across the country. (See MISO: Better Preparations Clinched Winter Storm Operations.)

Load in February 2025 also trended higher than in 2024. MISO averaged 80 GW with a 105-GW monthly peak this year and a 71-GW average and 88-GW peak last year. The RTO also reported an average of 39 GW in daily generation outages, 4 GW better than in February 2024.

For February, solar contributions became consequential enough to earn a spot in MISO energy fuel mix totals. The RTO observed an 11.5-GW all-time solar peak Feb. 21, 2025. The figure is in line with MISO’s estimate that it would end winter with a 12-GW solar fleet. (See MISO Estimates Solar Fleet will be 12 GW by Winter’s End.) MISO entered winter registering 8-GW solar output records.

Otherwise, MISO’s reliance on coal in February 2025 was unchanged from 2022, at 18 TWh. Natural gas inched upward to 16 TWh, higher than 2022’s 14 TWh.

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Louisiana PSC Leaves Statewide Energy Efficiency Program As Is For Now

The Louisiana Public Service Commission has selected a contractor to measure its statewide energy efficiency program, days after rumblings that a commissioner was prepared to dismantle the long-awaited program.  

The commission’s March 26 meeting agenda listed a “discussion and possible vote to pause the statewide energy efficiency program.” However, the PSC deferred that item and instead voted 3-2 to contract with Tetra Tech for $7.2 million to evaluate, measure and verify energy savings for Louisiana’s fledging statewide energy efficiency program.  

The step continued a years-in-the-making effort to establish a statewide energy efficiency program in Louisiana. The PSC in 2010 hired Georgia-based consulting firm J. Kennedy & Associates to draft the commission’s energy efficiency rules. The firm spent more than a decade trying to land on parameters that utilities didn’t oppose. The commission finally authorized a program in April 2024.  

Ahead of the meeting, the Alliance for Affordable Energy, Louisiana’s sole utility consumer advocate, sent notice that a commissioner was trying to undo the program altogether. It refrained from naming the commissioner. Commissioner Eric Skrmetta was the most vocally opposed to hiring an evaluation, measurement and verification (EMV) contractor during the meeting. Skrmetta’s office didn’t respond to RTO Insider’s request for comment on whether the call for discussion originated with him.  

In addition to Tetra Tech’s bid, DNV, Opinion Dynamics and ADM Associates submitted bids at $4.5 million, $8.4 million and $10.9 million, respectively.  

Skrmetta said none of the companies attempted to reach out to him to explain their bids. He said the program costs seem “extraordinarily high without explanation” and could have ratepayer impacts.  

“In a time where we’re looking to avoid waste, fraud and abuse in government contracting, this is the type of thing where you question where we are,” Skrmetta said.  

Skrmetta also said it seems “counterintuitive” to spend money to gauge energy savings.  

Commissioner Davante Lewis, on the other hand, said he met with representatives from the companies and believes the move to a statewide energy efficiency program will be worthwhile. He said Louisiana’s investor-owned utilities already have contracted with Tetra Tech to conduct their individual energy efficiency programs. Lewis said he expected no rate impacts from the state taking charge of energy efficiency oversight.  

“It’s not creating new administrative costs. It’s just now the commission sees those costs because the utility typically hires their EMV contractor,” Lewis explained. 

But Skrmetta said he was concerned a contractor could pull off a “double dip,” where it charges the commission in addition to a utility for energy efficiency measurements.  

Skrmetta was joined by Commissioner Mike Francis in his “no” vote; all other commissioners voted in favor.  

“This is not something we can’t unwind if we need to,” Francis said. The Louisiana PSC can cancel the contract with an EMV contractor with 30 days’ written notice.  

“We are relieved to see the commission defer an item that would have stopped efficiency planning in its tracks. Louisianans deserve real action, not delays and political games. Rolling back these programs would mean higher energy bills for Louisiana residents and more money in the pockets of utilities,” Alliance for Affordable Energy’s Alaina DiLaura said in a press release following the meeting.  

The Alliance said Louisiana’s shift to using a third-party administrator to manage an energy efficiency program “ensures that the programs are run efficiently and effectively — not by utilities whose profits depend on selling more energy.”  

DiLaura added that the commission hasn’t found any new evidence to justify a rollback of the program.  

Alliance for Affordable Energy Executive Director Logan Burke also said commissioners should keep their focus on standing up the program and not “not waste time rehashing a settled decision.”  

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GCPA to Honor Kim Casey with Power Star

The Gulf Coast Power Association has awarded its former executive director, Kim Casey, the 2025 Power Star Award in recognition of her contributions to Texas’ competitive energy markets, the organization said in a March 26 press release.

“Kim Casey’s impact on the energy landscape in Texas is profound. Her dedication, knowledge and innovative approach to challenges in the industry have set a standard for excellence,” said Pat Wood III, who chaired both FERC and the Texas Public Utility Commission, in the release. “This award is a well-deserved acknowledgment of her contributions that have shaped competitive energy markets.”

The Power Star Award was created in honor of Wood and recognizes an individual with a distinguished career who has played a crucial role in the advancement of electric markets. Casey was one of the first wholesale power originators in the U.S. and helped develop ERCOT’s first protocols. While at Dynegy, she originated numerous structured wholesale power contracts and oversaw the Texas power generation portfolio.

Casey co-founded Fulcrum, a nationwide energy management services company that evolved into a competitive retail electricity company since acquired by Just Energy. She has served on ERCOT’s Technical Advisory Committee and SPP’s Board of Directors.

The award will be presented at GCPA’s 38th Annual Spring Conference April 14-16 in Houston.

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SERC Members/Board of Directors Meetings Briefs: March 26, 2025

Blake Lauds Winter Grid Performance

NEW ORLEANS — At the March 26 meetings of SERC Reliability’s members and Board of Directors, CEO Jason Blake praised electric utilities in the regional entity’s footprint for their response to the January cold snap.

A “deep trough” of Arctic air brought low temperatures across the entire South on Jan. 19. New Orleans hit a record-low temperature of 26 degrees Fahrenheit on Jan. 22 and even received snowfall.

Despite the extreme conditions, FERC and NERC said the grid operated without any major incidents. The commission and the ERO have pledged to review the grid’s performance along with the REs to determine the impact of winter preparations by the electric and gas industries and any more opportunities to improve winter operations. (See FERC, NERC Praise Grid Performance in Cold Snap.)

“A lot of times when these significant events come through, we’re usually sitting back and talking about how we could do better [and] what went wrong,” Blake said. “But I think it’s so important, when things like this happen, to recognize victory, and the system performed incredibly well under such extreme conditions.”

New Directors and Board Officers

The March meeting was the last as chair for Lee Xanthakos, of Dominion Energy South Carolina, whose two-year term will end on June 1.

Directors voted to elevate the current vice chair, Seminole Electric Cooperative CEO Lisa Johnson, to take over as chair on that date, with Entergy CSO Chris Peters succeeding Johnson as vice chair. Lonni Dieck will remain the lead independent director.

SERC’s members chose several new and returning directors for two-year terms, also beginning June 1. The next class of directors will be:

    • Johnson and Lee Ragsdale of North Carolina’s Electric Cooperatives, representing the cooperative sector;
    • Virgil Hobbs of Southeastern Power Administration, for the federal/state sector;
    • Peters and Chip Whitworth of Tampa Electric, for investor-owned utilities;
    • Tim Lyons of Owensboro Municipal Utilities and Ricky Erixton of JEA, for municipal utilities; and
    • Shirley Bloomfield of the National Telecommunications Cooperative Association and Deborah Wheeler of Delta Airlines, as independent directors.

Former Chair Todd Hillman, of MISO, was elected to replace retiring Director Paul McGlynn, representing the RTO/ISO/reliability coordinator sector. His term will begin immediately.

From left: NERC CEO Jim Robb; SERC Reliability CEO Jason Blake; Lee Xanthakos, Dominion Energy; and Entergy CEO Drew Marsh. | © RTO Insider

Xanthakos will remain with the board through the end of his term on May 31, 2026, as will Denver York of East Kentucky Power Cooperative; Vicky Budreau of Santee Cooper; Beth McFarland of LG&E and KU Energy; Eric Laverty of ACES; Venona Greaff of Occidental Chemical; and Doug Lego of the Municipal Electric Authority of Georgia.

Of the new and returning directors, the board chose Xanthakos to head the Finance and Audit Committee, taking over for departing Director Bob Dalrymple. Wheeler, Bloomfield and Greaff will continue to lead the Risk Committee, Human Resources and Compensation Committee, and Nominating and Governance Committee, respectively.

Board Approves Draft Budget

Directors also approved SERC’s draft 2026 business plan and budget for public posting and submission to NERC.

This is the first step in the budget approval process for SERC, NERC and the other REs, according to a timeline presented at the members meeting by CFO George Krogstie. After the draft budgets are received by NERC, the ERO will present them to FERC staff in June. NERC’s Finance and Audit Committee then will review the budgets and endorse them to NERC’s Board of Trustees for approval. Submission to FERC will follow in August, with the commission’s approval expected in October.

SERC’s budget is expected to grow from $35.3 million in 2025 to $37.5 million in 2026, Krogstie said. The assessment is expected to grow by 8.6%, to $34.3 million; this figure would have been higher if not for the decision to draw $2.85 million from the RE’s reserves. SERC will draw $325,000 from its $2.6 million working capital reserve, which is above its target of 6% of the annual budget, and $2.9 million from its assessment stabilization reserve, which is $9.2 million.

A significant driver of the budget increase is growing costs to the RE’s registration, monitoring, outreach and training programs posed by the entry into the grid of large numbers of inverter-based resources, Krogstie said. Additionally, while Krogstie emphasized that SERC is not planning to add any new full-time-equivalent positions in 2026, he acknowledged personnel costs have continued to increase, including merit-based pay raises and other benefits.

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PJM Receives 94 Applications for Expedited Interconnection Process

PJM has received 94 submissions from generation owners seeking to have new projects or uprates to existing units included in the RTO’s expedited Reliability Resource Initiative (RRI) interconnection study process. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.) 

The applications amount to 26.6 GW of nameplate capacity split evenly across upgrades to existing facilities and new projects, according to a PJM announcement. It includes new battery storage installations and uprates to nuclear and gas units. Once PJM has selected projects, it intends to publicly share that list, including the fuel mix and expected effective load carrying capability (ELCC) ratings. Over the next month, the submissions will be narrowed to 50 based on seven weighted criteria:

    • 35 points based on the project’s unforced capacity (UCAP);
    • 20 points for resources with high effective load-carrying capability (ELCC) ratings;
    • 10 points for projects sited in the Dominion or BGE zones;
    • 10 points for being able to achieve commercial operation between 2028 and 2031;
    • 10 points for evidence of permits, siting and equipment procurement supporting a project’s in-service date;
    • 10 points to projects that are uprates of existing generation or planned projects; and
    • 5 points for projects that take advantage of existing transmission headroom.

The initiative is designed to address a potential capacity shortfall PJM has identified in the 2029/30 delivery year by allowing projects capable of quickly bringing new capacity to the grid to be included in the next cycle. When proposing the program, PJM originally said it would allow 100 projects to be included, which was reduced to 50 to ensure there is no impact to the timeline of existing queue positions. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.) 

The selected RRI submissions will join 550 projects in Transition Cycle 2 (TC2), which together could offer about 50 GW of nameplate if completed. PJM has stated it likely is insufficient given the low historic completion rate of queue projects and the preponderance of generation types with low capacity contributions, namely wind and solar. Generation interconnection agreements (GIAs) are expected to be reached for TC2 projects in late 2026. 

“This will provide an influx of reliable generation needed to help meet demand growth, in tandem with those resources that are already in PJM’s generation interconnection queue,” PJM’s announcement reads. 

PJM said it sees benefit to including projects that are unlikely to come online prior to 2030. 

“Uprates and certain types of generation would be able to come online by 2030. Even for those that can’t, it still benefits the PJM markets to have projects with an overall high score get a head start toward construction and commercial operation through participation in the RRI process,” the announcement said. 

Clean Energy Advocates Opposed to RRI

The RRI has been criticized by environmental groups and clean energy developers, who argue it would allow fossil generation to skip a queue renewables have been languishing in for years. Several have requested rehearing on FERC’s order approving the initiative, including the Environmental Law and Policy Center, Office of the Ohio Consumers’ Counsel (OCC) and Invenergy Renewables and a joint request from the Sierra Club, NRDC, Appalachian Voices and the Sustainable FERC Project. 

“PJM’s RRI is a flawed, unfair proposal that clearly favors dirty, toxic gas plants, when there are plenty of renewable energy projects that have been in the queue for over half a decade that can get online faster, and at a cheaper cost than that of gas plants,” Sierra Club staff attorney Megan Wachspress said in a statement on the organization’s rehearing request. “We are challenging FERC’s decision because we believe our communities deserve clean air and water, and cheaper, more efficient electricity. Renewable energy is the answer that can deliver both.” 

In its rehearing request, the OCC said it supports the RRI in concept, but argued it is incomplete without more transparency and a cost metric to prevent the 50 projects PJM selects from resulting in “uneconomic and costly solutions.” While it said FERC’s order addressed the transparency concern by requiring PJM to post the selected RRI projects and their scores, it said the commission failed to ensure the proposal does not result in unreasonable costs for consumers. 

LS Power Announces Participation

LS Power announced it had submitted five projects to upgrade existing generators under RRI, including converting two gas peakers to combined cycle units. Transforming the peakers — which are located in Troy, Ohio, and Armstrong, Pa. — would add 600 MW in combined output, while an additional 100 MW could be added across the company’s Doswell, Hummel and Hunterstown gas generators. The announcement said the projects would amount to more than $1 billion in investment. 

“With surging demand across the region, LS Power is answering the call for more dispatchable generation to support reliability and resource adequacy, and at a cost less than greenfield new build,” LS Power Generation President Nathan Hanson said. “Our proposed capacity projects are well positioned to meet the requirements of PJM’s RRI and help ensure electric reliability.” 

The Independent Market Monitor has been a proponent of the RRI and has called for its expansion. Rather than being a one-off measure, Monitor Joe Bowring has called for PJM to use it as the basis for a program that could be used to expedite the interconnection study timeline for generation projects that could resolve identified reliability needs. 

In addition to capacity shortfalls, he said, that could include instances where a resource deactivation would cause transmission violations, which can cause PJM to enter into costly reliability-must-run (RMR) agreements to keep those units online. (See PJM Market Monitor Publishes Mixed Views in Annual Report.) 

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WEIM Experience, Reliability Benefit Drove EDAM Decision, BANC Says

For the Balancing Authority of Northern California (BANC), a positive experience with CAISO’s Western Energy Imbalance Market was a key factor in the decision to also join the ISO’s Extended Day-Ahead Market (EDAM).

Before joining WEIM in 2019, BANC had estimated its annual benefits of WEIM participation in the $7 million to $8 million range, according to General Manager Jim Shetler. But those estimates have been far exceeded, Shetler said March 26 during a joint meeting of the CAISO Board of Governors and the Western Energy Markets Governing Body.

BANC’s benefits for participating in WEIM were about $49 million in the third quarter of 2024 and $58 million in the fourth quarter.

“I’ve yet to have any … BANC participants complain about the fact that we are in EIM,” said Shetler, also a key member of the committee driving the efforts of the West-Wide Governance Pathways Initiative, which has been working to bring independent governance to CAISO’s markets. (See Pathways Initiative Receives Praise, Skepticism at Calif. Hearing.)

Shetler gave a short presentation during the joint meeting to explain BANC’s reasons for joining EDAM rather than SPP’s competing day-ahead market, Markets+.

BANC announced its intention to join EDAM In August 2023 and signed a formal implementation agreement in November 2024. (See BANC Moving to Join CAISO’s EDAM and BANC Signs Agreement to Join EDAM.)

Shetler said another positive outcome of WEIM participation was the market’s “support for reliability.” He noted that BANC tends to hit its daily peak in summer about 60 to 90 minutes earlier than CAISO.

“We’ve very actively seen the EIM manage that: Help provide us cost-effective resources during our peak and then redispatch our resources to support the ISO peak as we start to come down,” Shetler said.

In addition, WEIM participation has reduced renewable curtailments, and BANC has been able to maintain a good trading capability.

BANC participated in the development of EDAM and Markets+ but for the past two years has been simply monitoring Markets+ progress.

A Brattle Group analysis found BANC’s benefits from joining EDAM would be about $5.5 million a year – “not a huge benefit … but it was positive,” Shetler said.

And EDAM met other day-ahead market criteria for BANC. Shetler said independence and self-determination are “first and foremost.”

“Members to the maximum extent possible can retain their independent decision-making on key factors,” he said.

Transfer capability was another point in favor of EDAM. BANC has about 2,000 MW of transfer capability with the ISO footprint through seven or eight interconnection points, Shetler said.

BANC is a joint powers authority with six member agencies: Sacramento Municipal Utility District, Modesto Irrigation District, Roseville Electric, Redding Electric Utility, Trinity Public Utility District and the City of Shasta Lake.

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Constellation-Calpine Merger Draws Protests over Market Power Concerns in PJM

Constellation Energy’s proposed merger with Calpine drew several protests at FERC on March 25 urging the commission to reject the deal, or at least to impose more stringent requirements than the companies initially proposed (EC25-43). 

Constellation is buying Calpine for $26.6 billion, with the latter’s current owners — Energy Capital Partners — having a minority share of less than 10% in the combined firm. It proposed selling 3,546 MW of Calpine’s natural gas plants in PJM, which is home to the biggest overlap of the two firm’s nationwide operations. (See Constellation, Calpine Propose Selling PJM Plants to Cut Market Power.) 

PJM’s Independent Market Monitor told FERC it should require specific structural and behavioral commitments on the combined firm, which would not burden the applicants, as they would preserve competition in the RTO’s markets. 

“Constellation has a unique role in PJM markets as a result of its ownership of 18,019 MW of nuclear capacity, 59.1% of all nuclear capacity in PJM,” the IMM said. “The nuclear units operate at a very high capacity factor, meaning that market prices at all hours directly affect Constellation’s net revenues from the energy and ancillary services markets. Calpine is one of the largest owners of natural gas-fired capacity in PJM, providing it with the ability to set prices in the PJM energy and ancillary services markets when it has market power.” 

To actually achieve lower market concentration, Calpine’s gas plants should not be sold to any of the existing pivotal suppliers in PJM. The Monitor suggested it should be sold to a firm that owns less than 3% of installed capacity. 

Constellation owns nuclear and some hydroelectric resources in the ComEd and PECO zones, the latter of which is on the low-priced side of the constraints pertaining to the Conastone transformer along the Pennsylvania-Maryland border. Those constraints impact prices around PJM. 

“Calpine has dispatchable resources in the area around these constraints,” the IMM said. “This means that the transaction will cause Constellation to have greater ability to increase prices in the energy market to the benefit of its large, high-capacity factor generators. This increase in market power can only be mitigated through the use of the behavioral conditions proposed by the Market Monitor.” 

Constellation already has several behavioral agreements with the IMM; those also should apply to all of the new generation it is buying in this deal, the Monitor argued. It filed a report that includes a long list of behavioral requirements, including 18-month notices before retiring a plant, limiting energy offer markups to $1/MWh, self-scheduling nuclear plants at their maximum output and bidding restrictions in the energy market. 

“Additional provisions are needed, given changes in the PJM market rules to address potential withholding of capacity market offers and co-located load,” the IMM said. “Given Constellation’s market power in PJM, as the largest single provider of capacity and energy, the behavioral rules would ensure competitive energy market offers and would prevent physical withholding of Constellation’s resources.” 

Even though ECP will own less than 10% of the combined firm (the actual percentage has not been revealed), the Monitor said that could bring up anticompetitive issues, as the firm owns other resources in PJM. 

“The best structural option would be to not allow ECP to own any part of Constellation following the transaction,” the Monitor said. “The best behavioral option would be for ECP to sign a binding document preventing ECP from knowledge of or any input into any Constellation decisions related to Constellation’s assets.” 

Public Citizen, PennFuture and the Clean Air Council filed a joint protest of the deal, saying FERC should either block it or impose significant structural and behavioral conditions. They argued the companies failed to prove the case that the merger is in the public interest. 

“They do not address the public’s lost benefit of their competition,” they said. “They are silent on the transaction’s likely exacerbation of Constellation’s ability, incentive and propensity to exercise market power in PJM by withholding supply in PJM energy markets and by withdrawing supply entirely from PJM wholesale markets.” 

While the two firms own substantial generation, they also are large retailers in the states that allow shopping for electricity, the groups said. FERC needs to pay attention to how the deal will impact those markets, they argued. 

The Pennsylvania Office of Consumer Advocate said the deal will have a negative impact on the state’s retail market, arguing it would increase concentration in the commercial and industrial sector by nearly 500 points on the Herfindahl-Hirschman Index, when FERC triggers mitigation measures for an increase of just 100 points. Constellation serves 31.7% of the C&I market as the leading competitor, while fourth-place Calpine serves 7.7%. 

Most of Pennsylvania’s mass market residential customers are served on default service auctions, and the deal will combine two of the biggest bidders. The consumer advocate noted the auctions are confidential and it cannot determine how much, if at all, the deal would impact default service. 

“Though the concern about adverse impacts on competition in the market for default service auctions in Pennsylvania is conceptual rather than empirical due to the unavailability of the data required to conduct a thorough analysis of this issue, the potential for large numbers of residential and small commercial customers to be detrimentally affected exists,” the Pennsylvania consumer advocate said. “This determination will hinge on the degree to which Constellation and Calpine have historically participated in these solicitations and the overall degree of market participation.” 

The Maryland Office of People’s Counsel filed its own protest, urging FERC to reject the application or hold more hearings because Constellation and Calpine failed to justify the deal. 

“Even with the divestiture, the proposed transaction in this matter poses specific market power concerns because Calpine and Constellation’s respective generation assets are complementary rather than identical,” the OPC said. “The transaction combines Calpine’s higher-marginal-cost, fossil fuel-fired generating units, providing Constellation the ability to withhold power post-merger for relatively little loss in profits (its ‘ability’ units), with Constellation’s lower-marginal-cost nuclear plants, which would benefit from higher clearing prices and therefore increase Constellation’s incentive to withhold power (its ‘incentive’ units).”