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April 6, 2025

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NERC Board Approves Cold Weather Standard

NERC’s Board of Trustees on April 4 approved the ERO’s new cold weather reliability standard, bringing to a close a development that saw the board use its special authority to streamline the normal stakeholder process for the second time.

The board unanimously found that EOP-012-3 (Extreme cold weather preparedness and operations) is “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” The standard will now be submitted to FERC for final approval.

In her presentation to the board, Soo Jin Kim, NERC vice president of engineering and standards, reviewed the sometimes unorthodox process that brought EOP-012-3 to its final state. FERC kicked off the chain of events in June 2024 by approving the standard’s predecessor EOP-012-2 while ordering a set of “targeted modifications” to be completed by March 27.

NERC first approached the project through its normal standards development process, assigning the task to Project 2024-03 (Revisions to EOP-012-2). But the draft standards created by the team failed to meet the two-thirds, segment-weighted approval of stakeholders, required for passage, in two formal ballot rounds by December 2024, leaving the ERO’s management concerned about being able to satisfy FERC’s directive.

With the commission’s deadline looming, the board agreed in January to invoke Section 321 of NERC’s Rules of Procedure for the second time in five months. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.) The board ordered NERC’s Standards Committee to work with stakeholders and ERO staff to prepare a standard that satisfies FERC’s order, post it for a 45-day public comment period and then submit it to the board after revising it in response to stakeholder feedback. Additional formal ballots were not required under the board’s directive.

The SC formed a group of volunteers, including some members of the 2024-03 drafting team, to revise EOP-012-2. After completing their work, they posted a draft of EOP-012-3 for comment in January; the comment period ended March 12. This left only 15 days before the standard was due to FERC, and NERC formally requested the commission to extend its deadline to April 14, which FERC granted on March 20 (RD24-5). (See NERC: Cold Weather Standards Now Expected in April.)

Kim identified several themes in industry responses to the draft, which the SC addressed in the final standard. First, the team revised the proposed definition of “generator cold weather constraint” — a condition that precludes generator owners from implementing freeze protection measures — to “clarify the scope of … measures that may be precluded by a constraint.” In addition, the final standard will require GOs submitting constraint declarations to add an attestation signed by a company officer.

Commenters also raised concerns about the standard’s requirement that corrective action plans (CAPs) addressing cold weather reliability events be implemented by the start of the next winter season after the event — a mandate that stakeholders said could place unfair pressure on utilities that experienced events late in the season. Kim said the team responded to this concern by clarifying the criteria for “early season CAPs,” without specifying what changes were implemented.

Kim added that the final standard provides for a “compliance abeyance period.” This measure provides a two-year window during which regional entities will not take action against utilities for failing to comply with requirements concerning generating units’ extreme cold weather temperature — defined as the lowest 0.2 percentile of a unit’s winter temperatures since 2000 — as long as the utility is “acting in good faith to comply with the standard in accordance with the implementation plan.”

Board Chair Suzanne Keenan noted that this will be the first standard to have such an abeyance period, one of “a lot of firsts” that the project entailed. These include the first time requesting an extension from FERC, the first time approving a standard without a successful stakeholder ballot and the first time holding an open board meeting on “such a difficult topic” without a closed meeting beforehand.

Keenan emphasized that “the board doesn’t take lightly the action before us,” adding that “if this were easy, we wouldn’t be here now.” She also referred to NERC’s Modernization of Standards Processes and Procedures Task Force, which the board created at its previous meeting in February, and expressed hope that the group could “reimagine how we get [standards] done to avoid this in the future.”

Trustee Sue Kelly, the board’s liaison to the SC, praised the committee’s work under pressure, first to create the new standard and then to revise it after the comment period. She said NERC was “in a much better place than we otherwise would have been” without the committee’s work.

Trustee Ken DeFontes, who was chair both times the board invoked Section 321, echoed Keenan’s thanks for the SC’s efforts while reiterating his belief that the special action was necessary to satisfy the commission’s order.

“It’s clear to me that we have been as reasonable and thoughtful as we can possibly be to make sure that we’ve considered all the feedback from the stakeholders, and I think we have found the right place to balance those concerns while still assuring that we have a standard that will address the risks that we understand are real,” DeFontes said.

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FERC Leaders Focused on Stability amid Political Shifts

LA JOLLA, Calif. — FERC Chair Mark Christie and Commissioner Judy Chang downplayed the current political environment’s impact on the agency, saying during an industry meeting April 3 that its role is to follow the law and ensure the fairness of procedures.

Stability comes from the commission’s dedication to following the Federal Power Act and the Natural Gas Act, Christie said in a conversation with New Mexico Public Regulation Commissioner Gabriel Aguilera during the spring meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body.

FERC’s decisions affect whether investors will put up “literally hundreds of billions of dollars into the assets that we need to invest in,” Christie said. “There has to be a certainty and a stability before those investors are going to put up that kind of money to build the assets that we all know we need.”

Christie also stressed that the commission will adhere to its ex parte rules.

“We’re going to follow the procedural rules. There’s not going to be any violation of our ex parte communications, and we’re going to follow the statutes that apply to each case, whether it’s Federal Power Act; whether it’s Natural Gas Act,” Christie said. “If you’re following the statutes and your procedural rules, that’s where credibility comes from. And we are.”

In a separate panel moderated by Washington Utilities and Transportation Commissioner Milt Doumit, Chang said the new administration will not change FERC’s mission of “keeping the lights on.”

However, she noted “nervousness” around voluntary retirements spurred by the Trump administration’s deferred resignation offer to the entire federal workforce in January.

“There are some uncertainties, but I think we’re keeping … our eye on the road,” Chang said.

Markets in the West

The two FERC commissioners also praised efforts to create day-ahead markets in the West in reference to SPP’s Markets+ and CAISO’s Extended Day-Ahead Markets. Both offered insights into how the industry can navigate issues between the two market options, such as seams.

Chang suggested the West look to MISO and SPP, which have created operating agreements and task forces to navigate seams, she said. She urged stakeholders to avoid imposing barriers to “allow the efficient exchanges to occur and trades to occur.”

Washington Utilities and Transportation Commissioner Milt Doumit and FERC Commissioner Judy Chang | © RTO Insider

“Avoid locking in historical patterns, because when you start creating new markets, things are going to change, or policies might change, or generation fleets mix might change, or transmission buildout will change the flow,” Chang said. “Try to be flexible to future changes. And that includes, really, all kinds of parameters around market design.”

Christie emphasized the importance of state regulators collaborating to tackle challenges.

“You can have the bigger meetings where 90% of the people there are not state regulators, and they’re there with their own interest,” Christie said. “And that’s fine, as long as you, as state regulators, set aside time where you all go in a room and you talk to each other about how you’re going to work through these challenging issues.”

Chang’s Goals

Chang, who joined FERC in July 2024, laid out her goals before her term expires in June 2029.

The West’s market evolution is a priority, with Chang saying she wants “to understand it; to help you develop what you need for your customers.”

Other focus areas include resource adequacy, the interconnection queue and transmission planning.

“I think the rules in [Order] 1920 are very solid,” Chang said. “I would love to see parts of the country, maybe the whole country, implement better transmission planning and cost allocation and get some very needed transmission at least developed, maybe not in my term, but at least prepared for in the future.”

Chang also said she “would love to see more advanced technologies be implemented as part of transmission buildout, because I think we have an obligation to serve customers in the most efficient way, and we can squeeze more out of existing infrastructure and new infrastructure.”

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EDAM Congestion Debate Builds Even as CAISO Moves to Address Issue

LA JOLLA, Calif. — The dispute over how CAISO’s Extended Day-Ahead Market will allocate congestion revenues to market participants might induce a sense of déjà vu among Western electricity sector stakeholders who have closely followed the development of the region’s day-ahead markets.

Last year, a January deep freeze that put much of the Northwest on the brink of rolling blackouts set off a heated debate between supporters of EDAM and SPP’s Markets+. That dispute centered on how CAISO allocated the revenues it collected from the transmission congestion stemming from the weather event. That controversy became a kind of proxy for the competition between the two markets. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.)

A similar development appears to be playing out this spring, even as most Western utilities have already settled on which day-ahead market they will join — although a handful remain uncommitted. The dispute is over the rules by which EDAM will allocate congestion revenues when a constraint in one EDAM balancing authority area produces “parallel” — or loop — flows that result in congestion in a neighboring BAA.

The issue came to light after PacifiCorp in January filed a revised Open Access Transmission Tariff with FERC to reflect the utility’s participation in EDAM, scheduled to begin in 2026.

Shortly after the OATT filing, Vancouver, Canada-based energy trader Powerex — a PacifiCorp transmission customer that has committed to joining SPP’s Markets+ — released a paper pointing to what it called a “design flaw” in EDAM because the market’s rules do not offer “a financial hedge that returns the day-ahead congestion charges on a delivery path back to the entities with firm transmission rights on that delivery path” — as required by FERC. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.)

CAISO and PacifiCorp initially responded sharply, calling Powerex’s paper “misinformed and inflammatory,” but the ISO in March kicked off an “expedited” stakeholder initiative to address the issue after other Western entities filed similar complaints in the FERC docket for the OATT (ER25-951).

The issue was the key agenda item at an April 2 in-person meeting of the Western Energy Markets Body of State Regulators (BOSR), held in La Jolla at the site of the joint spring conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB).

Speaking to the BOSR, Anna McKenna, CAISO vice president of market design and analysis, emphasized that while the ISO is moving quickly to address stakeholder concerns, it disputes the contention that the market’s existing congestion revenue framework is inherently flawed. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.)

“I know that there’s been a perception out there that, because we started an initiative, we’re admitting that there’s some fundamental flaw in the EDAM design. We wholeheartedly disagree,” McKenna said.

McKenna said the new initiative is “revisiting” what CAISO thought was just and reasonable in light of FERC’s approval of the EDAM tariff in December 2023.

“And, by the way, what we have in EDAM is something that’s been in place for 10 years now under [CAISO’s Western Energy Imbalance Market]. … So there was really no change in how that congestion revenue is going to be allocated in EIM and EDAM,” although there will be different implications for the day-ahead market, she noted.

MISO Monitor Weighs in

McKenna delivered her presentation a few days after a new twist in the dispute, when Powerex on March 28 filed additional comments with FERC in the PacifiCorp OATT docket.

The comments included expert testimony from David Patton, president of Potomac Economics, which serves as the Independent Market Monitor for MISO and ERCOT and provides monitoring services for ISO-NE and NYISO.

“All other organized markets provide financial transmission rights that correspond to all of the constraints that are priced in the markets’ LMPs, which is the basis for the congestion costs charged to customers,” Patton wrote. “In sharp contrast, PacifiCorp proposes to only provide a hedge for congestion associated with constraints on PacifiCorp’s system, and no hedge for congestion costs associated with all other constraints in EDAM.”

Patton contended PacifiCorp “has proposed an unprecedented and ultimately unreasonable treatment of its firm transmission service and the customers that have purchased it.” He said the proposal is “clearly inferior to both the financial transmission rights RTOs and ISOs provide their firm transmission customers and to the physical scheduling rights firm transmission customers receive in non-market areas … under the pro forma OATT.”

Patton warned that the lack of “effective” congestion hedges could increase long-term grid reliability risks by deterring investments by “risk-averse market participants.” He said PacifiCorp “could meet the requirement for transmission service that is consistent with or superior to the pro forma OATT, despite the incomplete nature of the current EDAM design,” by submitting a revised OATT that preserves the ability of the utility’s customers to opt out of EDAM “and schedule the use of their firm transmission service ahead” of that market.

In an email to RTO Insider, PacifiCorp spokesperson Omar Granados said the utility “is proceeding toward the implementation of the approved EDAM design in 2026 and continuing to work with market participants and other stakeholders to implement those design features to maximize benefits for participants and support grid reliability. PacifiCorp will engage with stakeholders in the pending FERC proceeding and the CAISO stakeholder process on congestion to address any questions or concerns.”

Patton’s testimony also criticized EDAM itself, saying “the design of EDAM substantially deviates from the design of other day-ahead markets in how congestion costs are collected and distributed back to the EDAM participants.”

“It is highly problematic and somewhat misguided to allocate congestion revenue based on where the transmission facility is located rather than based on the sources and sinks where the congestion revenues are actually collected,” he added.

But Patton also acknowledged that EDAM is not like the other markets he monitors because it does not include other elements of an RTO, such as consolidation of balancing authority areas and transmission service providers.

At the BOSR meeting, McKenna said EDAM provides a “unique” design in that it does not force transmission owners to turn over control of their lines to the market operator, allowing each to determine how to spread congestion revenue allocations among transmission users.

She argued also that implementing a financial instrument such as congestion revenue rights would not solve the problem of which BAA receives revenues stemming from congestion caused by parallel flows.

McKenna expressed confidence in CAISO’s ability to address the issue.

“We’re not unique in that every RTO and every ISO has had to make many filings that impact its markets over the years. That is the nature of markets: learn, react, form, and you proactively address things,” she said.

“I think it’s a good point you made: that markets are not static and continue to evolve as we identify potential improvements or changes — and that’s good, because we get to keep our jobs,” New Mexico Public Regulation Commissioner and BOSR Chair Gabriel Aguilera said.

Henrik Nilsson contributed to reporting in this article.

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Holtec’s Palisades Restart Fends off Challenge from Anti-nuclear Groups

The planned restart of the Palisades Nuclear Plant survived a challenge from anti-nuclear organizations March 31, with a panel of judges of the U.S. Nuclear Regulatory Commission deeming their arguments inadmissible. 

The three judges on the NRC’s Atomic Safety and Licensing Board Panel declined to grant a hearing to a coalition of anti-nuclear groups: Beyond Nuclear, Don’t Waste Michigan, Michigan Safe Energy Future, Three Mile Island Alert and Nuclear Energy Information Service. 

The panel said the coalition’s arguments against steps to resurrect southwest Michigan’s Palisades either lacked factual support or were outside what the NRC was specifically considering for the plant (50-255-LA-3). The groups sought to dispute an exemption and amendments that owner Holtec International first sought from the NRC in 2023. 

To restore Palisades, Holtec needs an exemption on the permanent reactor shutdown certifications granted to the previous owner, Entergy, as it was closing the plant in 2022. The certifications prohibit operation of the reactor or placement of fuel into the reactor vessel. Additionally, Holtec needs four license amendments that will allow it to refuel the plant and restart operations as early as fall 2025. The quartet of amendments would alter technical specifications, revise an emergency plan to support the return of operations and update the methodology for studying the potential consequences of a main steam line rupture. 

Beyond Nuclear and others entered a request for hearing of Holtec’s exemption and amendment requests in February. (See Anti-nuclear Groups Challenge Palisades Reopening.)  

But the panel said the groups and their experts made “bald assertions” about the safety of the plant, the time and costs of repairs, and Holtec’s supposed inexperience with nuclear operations. The judges said the groups’ claims that a restart would not be in the public interest “are conclusory and speculative.”  

They also said the groups’ demand that Holtec obtain a new operating license for Palisades and a fresh environmental impact statement were beyond the scope of the hearing request. The groups had said that Holtec should not be able to seek amendments or exemptions on the existing operating license because it no longer allows reactor operations or fuel in the reactor vessel. 

“The commission has determined that restart requests will be evaluated using the agency’s existing regulatory framework, which provides for license amendment requests and requests for exemptions from regulations,” the judges said. “Therefore … claims that applicants’ operating license may not be amended or that applicants may not seek exemptions from regulations amount to an impermissible challenge to agency policy and regulations.” 

On the matter of requiring an EIS, the judges said the groups merely speculated as to what environmental harms may occur from resurrecting a partly decommissioned plant. 

The judges rejected the groups’ criticism that the NRC is “cobbling together” a restart authorization because it has no dedicated regulatory procedure for restarting a closed reactor. The judges decided their argument is inadmissible because it “challenges NRC regulations and policy, relies on conclusory and speculative claims, and does not otherwise raise a specific challenge to the four license amendment requests that are the subject of this proceeding.” 

The groups contended Holtec should not get a license exemption under hardship provisions because the company knowingly entered “a difficult situation of its own making” by buying a plant entering decommissioning and then pursuing a restart. They also said Holtec did not prove its restart activities should be categorized under special circumstances that should earn a deviation from normal rules. 

But the panel decided those arguments were vague and did not see how they supported denying the exemption request. 

The judges did not terminate the proceeding because the anti-nuclear coalition has put forward more challenges to the NRC’s environmental assessment of Palisades.  

Groups Keep Sounding Safety Alarm

However, the groups said they were ready to appeal the decision and go to court over the state of Palisades steam generator tubes, which they say are degraded. 

Arnie Gundersen, an engineer at anti-nuclear nonprofit Fairewinds Energy Education and an expert witness for the coalition who testified at the pre-hearing trial, maintains that the Palisades steam generators have formed stress corrosion cracks. 

“During my 53 years of professional experience, I am unaware of any steam generator, with so many previously known and newly identified flaws, that has not been replaced,” he said in a press release following the panel’s decision. Gundersen added that he had “never been more concerned about the safety of a nuclear power plant.” 

The groups contend that Palisades’ original owner, CMS Energy, told the Michigan Public Service Commission in 2006 that the steam generators needed replacing. Entergy did not pursue replacements during operations from 2007 to 2022 because the NRC did not require it, the groups said. Holtec estimated in 2022 that steam generator replacements would cost about $510 million. 

“The Japanese parliament concluded that the root cause of the Fukushima Daiichi nuclear catastrophe of 2011 was collusion between the safety regulator, Tokyo Electric and government officials,” Beyond Nuclear’s Kevin Kamps said in the same press release. “There is such potentially catastrophic collusion in spades at Palisades, between the ASLB and NRC, Holtec and government officials here. The entire Great Lakes region is being put at risk.” 

Meanwhile, Holtec’s progress on Palisades continues on other fronts. On March 17, U.S. Energy Secretary Chris Wright announced a $56.8 million loan disbursement for Holtec, the second part of the Department of Energy’s $1.52 billion in loan guarantee for Palisades. 

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FERC Approves Increase in MISO Value of Lost Load to $10K

FERC on April 4 gave MISO the go-ahead to set its value of lost load (VOLL) at $10,000/MWh by early fall, nearly three times as high as the current $3,500/MWh value (ER25-579). 

The new VOLL can take effect Sept. 30, FERC said. It would be used as a price cap for locational marginal prices and market clearing prices during load-shedding events. 

In the same order, FERC also greenlit changes to MISO’s operating reserve demand curve (ORDC), which establishes shortage pricing and is linked to the VOLL. 

Though it can implement the $10,000 VOLL in load shedding, MISO proposed its ORDC peak at a lower, $6,000 VOLL and stay there until about 50% of cleared operating reserves materialize. From there, the curve will slope downward until MISO can confirm more than 80% of cleared operating reserves, at which point the curve becomes two steps: $1,100/MWh until 88% of reserves show up, and $600/MWh until 100%. 

MISO’s current curve sits mostly at $1,100/MWh and $2,100/MWh across two large, flat steps before it tops out at $3,500/MWh. 

The commission decided it was appropriate that MISO be allowed to use two VOLLs, one to set the ORDC and one to estimate the financial blow of shedding load across all customer classes. It said the higher VOLL and more nuanced ORDC “will give market participants efficient financial incentives to respond to scarcity and shortage conditions and act in ways that support system reliability in MISO by either increasing supply or reducing demand.” 

MISO proposed the steeper VOLL at the beginning of 2024; staff said the too-modest $3,500/MWh was set in 2007 and is outdated, no longer reflecting the threshold of customers’ willingness to pay. (See MISO to Limit Use of $10K VOLL During Long-duration Outages.) 

MISO’s Chuck Hansen has said in stakeholder meetings that $10,000/MWh is “a low-end estimate of the negative financial impacts associated with MISO-directed firm load shedding.” He pointed out that MISO has only directed load shedding once in the past 17 years, ordering about 700 MW offline in MISO South during February 2021’s Winter Storm Uri. 

While explaining MISO’s filing to the Market Subcommittee in August 2024, Hansen said MISO “qualitatively” expects the higher scarcity price ceiling to make loss-of-load events rarer and shorter lived, as members are motivated to reduce consumption. He likened a higher VOLL to police using tickets to deter speeding. 

“If the speeding ticket is $2, who cares? If the speeding ticket is $200, well, that’s different. It needs to be high enough that some demand does not want to pay that much,” Hansen said. 

The commission dismissed Cooperative Energy’s criticism that MISO’s capacity auction already delivers revenues that incent new generation builds. The Mississippi cooperative said a higher VOLL would “add a reactive and punitive component to the market design.” 

FERC countered that the VOLL is a needed indicator of when to build. 

“While an appropriate VOLL does guide investment and retirement decisions in the long term, we emphasize that shortage price signals in the day-ahead and real-time markets, which are developed through the VOLL and ORDC, are also near-term signals to incent real-time actions by generation and demand resources during [or before] the operating day … to avoid potential shortage conditions,” FERC said. 

Finally, FERC said the so-called “circuit breaker” that MISO worked into its VOLL design should assuage Cooperative’s fears that the higher value could bankrupt utilities and strain customers’ pocketbooks. The circuit breaker refers to MISO sequentially lowering VOLL during extended load-shedding events. 

MISO plans to cut the VOLL in half to $5,000/MWh after four hours of firm load shedding during a maximum generation emergency. When active load-shedding measures are not lifted in time for MISO’s 10:30 a.m. ET day-ahead market closing, the RTO will extend the lower, $5,000/MWh VOLL into the next operating day. For load shedding that continues into a second day and beyond, MISO will slash its day-ahead and real-time VOLL to $2,000/MWh for successive operating days. 

The $2,000/MWh step can continue indefinitely until the maximum generation emergency is terminated and normal operations resume. RTO staff chose the $2,000/MWh amount partly because it is the hard cap on incremental energy offers, as dictated by FERC Order 831. MISO said it wanted to limit prices for extreme, dayslong outage events. 

“MISO’s proposal strikes a reasonable balance by more accurately reflecting load’s willingness to pay and by providing protection to consumers by limiting the duration of their exposure to higher prices that could result from its proposal,” FERC wrote. 

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EPSA Conference Tackles Markets in a Time of Rapid Demand Growth

WASHINGTON — Load growth caught off guard an industry that was in the middle of a spate of retirements of older fossil fuel-fired power plants, but the markets are starting to respond, experts said at the Electric Power Supply Association’s Competitive Power Summit on April 2.

PJM expects load growth of 32 GW from last year to 2030 when its peak will hit 184 GW, mostly from new data centers coming online in its footprint, said its CEO, Manu Asthana. The RTO is dealing with that through its Reliability Resource Initiative, which recently received 94 applications to build resources that will keep the grid stable in the near term. (See PJM Receives 94 Applications for Expedited Interconnection Process.)

“We’re seeing a reaction,” Asthana said. “We’ve seen over 1,000 MW of generation rescind their retirement notices. We have seen almost 27 GW come into our Reliability Resource Initiative.”

On the morning of the event, it was announced the former Homer City coal plant in Pennsylvania was being redeveloped around natural gas to serve data centers, which comes a few months after the Three Mile Island plant signed a deal with Microsoft to reopen to serve a data center, Asthana said. (See Data Center Campus with up to 4.5 GW of Gas Generation Planned for Pa.)

Policy changes can help with the issue too, Asthana said. The backup generation at data centers as a potential resource cannot be used, he said, because they most often have diesel generators that have limited run-times in their permits, so their ability to offer demand response is limited.

“If we can access that flexibility — or through policy changes, increase that flexibility — even if it’s for a transitional period, I think you can serve more data centers,” Asthana said. “It’s not that we’re short every hour of the year; we’re short some hours of the year.”

PJM is worried about the end of this decade, but MISO has been dealing with a system running at its reserve margin target since 2022, said Todd Ramey, the RTO’s senior vice president of markets and digital strategy. Some of its states are pushing policies to deal with climate change that have retired baseload power plants and favored renewables for new resources, which cannot replace dispatchable power plants on a one-for-one basis.

“So, over the last few years, we rapidly worked down our surplus spinning reserves and kind of hit the minimum,” Ramey said. “Once you get to minimum, it really is all hands on deck at that point — just to figure out what we can do to maintain.”

Several years after that first started, MISO faced zero demand growth. It now expects growth of 2% annually for the next five years, jumping up to 3.5% in the 2030s. In 15 years, MISO expects demand to grow by 60%.

NERC expects summer peak demand to grow by 132 GW around the continent over the next 10 years and winter peak to grow by 150 GW, while 115 GW of older power plants retire, said Camilo Serna, the ERO’s senior vice president of strategy and external engagement.

“More than 50% of the U.S. is at risk of resource energy adequacy issues, so … we’re going to be running very, very tight,” Serna said.

Another issue is the growing use of natural gas on the system, which is concerning in the winter when demand for direct heating use competes with power generation, especially during weather events.

“Weather patterns today are kind of longer, deeper and impact a broader set of regions,” Serna said. “So that will continue to create a lot of resource adequacy issues.”

For years the industry tricked itself into thinking that extreme weather events — such as the 2014 polar vortex, which roiled PJM’s energy markets, and 2021’s Winter Storm Uri, which led to hundreds of deaths in Texas and spiking prices around the country — were random and rare, Asthana said. “I think the lesson from that really is that we need to think differently about resource adequacy.”

NYISO has made changes around its winter requirements, so CEO Rich Dewey said he feels more comfortable about reliability in the season as his operators can call on a fleet of dual-fuel generators to meet demand during cold snaps. But New York faces issues around keeping old legacy plants online for the foreseeable future.

Dewey started his career as a power plant engineer for Niagara Mohawk. He said he was working on plants that were expected to shut down in 2000 and still are running.

“And we’re counting on them being there for at least the next 10 years of our planning horizon, and there is nothing lined up to replace them,” Dewey said. “So, I worry about that. I worry about the adequacy that the plant owners have to do the necessary maintenance and life extension, which is going to be so crucial. I worry about having the right kind of incentives.”

One of the resources New York planned to replace such plants with was offshore wind, which ran into cost overruns and supply-chain issues before an unfriendly administration took over in Washington. Another issue the Trump administration has put front and center in New York and other Northern markets is tariffs.

NYISO has set up rules to collect tariffs on any imports that flow into its system from Canada, though Dewey would prefer not to use them as the trade is mutually beneficial. New York sets its reserve margin and capacity market inputs around some baseline of imports from Canada.

“If we get into a situation where the politics escalate and we suddenly can’t count on that for anything anymore, then there’s going to be a real reliability issue,” Dewey said.

Another issue that tariffs cause for the industry is exacerbating supply chain worries around key grid components like transformers, Asthana said.

“We have 31 tie lines with Canada,” Serna said. “The systems are designed to work together electrically. So, besides the energy adequacy issues that Rich was pointing to, there are some other reliability services that we count on the two systems providing to each other: voltage [and] frequency support. So, if you have an extended period where you don’t get that power from Canada, there could be other implications beyond just having enough energy to meet demand.”

The changes in demand have changed the discussion around new generation, with Vistra CEO Jim Burke saying he had to explain why new natural gas generation is in vogue recently to a conference of oil and gas executives.

“I think the solution set of wind, solar and battery is not set up at the moment to meet 24/7 loads that [data centers] have,” Burke said. “It’s also not set up to meet the retirement of coal and the growth on the electric grid. So, gas has proven itself as a more near-term, viable, dispatchable, reliable solution.”

Debating which specific technology is needed to meet the rising demand is a 1990s issue, Competitive Power Ventures CEO Sherman Knight said. The industry needs to build everything it can.

“If you let the markets work and you send the right price signals, it will react, and we will react to that,” Knight said.

In addition, “taking off the handcuffs” from every type of technology so it can help meet the demand will enable the industry to rise to the challenge. And in the case of markets, both Knight and Burke noted they will pay the price for any wrong bets as they have before.

Vistra’s predecessor firm made a bad bet on building a new coal plant in Texas after Hurricane Katrina caused natural gas prices to spike, Burke said.

“We brought the plant online in 2011, and by 2018 we retired that plant because natural gas prices due to fracking had come down so dramatically,” Burke said. “We wrote off over $1.25 billion as a company. We did not seek any recovery of that. That should be on us; we made a bad decision. The customer didn’t pay for that, and that’s something I think competitive markets are not given enough credit for.”

Earlier in the day, FERC Commissioner David Rosner read off a list of billions of dollars that different organized markets reportedly have saved consumers over the years.

“What’s great about markets?” Rosner said. “It allows us to do more with less. It allows us to optimize around the generation and transmission assets that we have and efficiently use the system.”

While it would help to get better forecasts on what actually is going to show up on the grid, regulators can be certain that demand will rise, he said.

“In places where we have markets, the goal is to make sure that we have a set of rules in place that fit the needs of what businesses want to do,” Rosner said. “I personally don’t have a ‘one-size-fits-all’ in mind on this.”

Rosner said he’s hopeful the commission will be able to set some rules on data center co-location so the industry can move forward and meet that demand.

“The only other thing I’d say is I hope that our open proceeding doesn’t discourage people who have developed things that they might want to bring to the commission from doing that whenever it’s ready, because I personally am willing to consider things on a case-by-case basis,” he added.

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MISO, SPP Solicit Feedback on Joint Transmission Studies

MISO and SPP staff asked for input on a joint system study in 2025 during their annual transmission issues evaluation March 28 with their Interregional Planning Stakeholder Advisory Committee (IPSAC), which was only too happy to discuss stakeholders’ issues with the current process and suggest improvements. 

Missouri regulators called for examining the region encompassing southwest Missouri, southeast Kansas, northeast Oklahoma and northwest Arkansas, rather than just Oklahoma and Arkansas. Clean energy groups urged the RTOs to increase the bidirectional interregional transfer capacity along the seam they say will generate billions of dollars in regional benefits. A transmission developer recommended the staffs follow its road map in working with FERC to enable the “timely development” of interregional projects. 

The staffs will use the feedback in determining whether or not they conduct a Coordinated System Plan (CSP) this year. They told the IPSAC in December they will not perform a CSP in 2025 but will accept transmission issues for their annual review, as per their joint operating agreement (JOA). (See MISO, SPP to Revise Joint Agreement, Focus on TMEP Process in 2025.) 

MISO’s Jon George reminded stakeholders the RTOs have proposed expanding the CSP’s scope to yield a more robust and comprehensive interregional planning process in the 2024/25 planning cycle. They’re focusing on identifying “immediately actionable” system upgrades that improve reliability and resilience and strengthening transfer capability between the two systems. 

The study incorporates reliability, economic and transfer analyses using forward-looking 10-year models and assumptions. It aligns with key elements of FERC Order 1920, staff said. 

SPP and MISO have filed a waiver request with FERC for certain multiyear modeling and benefit valuation requirements in their JOA. Staff said they believe the study can proceed as scoped, but that certain JOA provisions may prove challenging. 

Stakeholders reacted positively to the RTOs’ 2034 blended models for issue identification and benefits evaluation: economic, light-load reliability, and extreme hot and cold events. The blended models also were used in the 2023 CSP. 

The Sustainable FERC Project and Natural Resources Defense Council’s Natalie McIntire said the RTOs should be focused on building a bigger grid, given the increase in extreme weather. 

“We really urge the RTOs to focus on the full seam for future comprehensive interregional studies,” she said. “Things are changing so rapidly that we need to keep our focus on all parts of the seam and how we can optimize that for all consumers. The focus in this interregional transfer capability and resilience study on resilience during the extreme weather is great. We support that, but we think there’s further work that can be done to really move away from the prior silo transmission planning frameworks that have been undertaken across the seam in the past.” 

The CSP builds on each RTO’s respective regional process. The RTOs then coordinate on model development, issues identification and technical analysis throughout the evaluation process. 

“We’re already in a solution-submission window for the 2025 [SPP Integrated Transmission Planning portfolio], but to the best we can, we will definitely cross reference solutions from these studies,” SPP’s Spencer Magby said. “If we see something promising in these regions in the 2025 ITP, we’ll be sure to screen them through this study as well.” 

The JOA, which was updated in 2019, requires that a CSP be performed every two years. Stakeholders have until April 23 to submit their final issues. At that point, the RTOs’ Joint Planning Committee, which comprises staff from both grid operators, will meet and determine whether a study will be conducted. 

Five previous CSP studies have failed to produce any joint projects over differences in allocating costs. That led the RTOs to try a different approach with the Joint Targeted Interconnection Queue, which identified a five-project portfolio estimated to cost as much as $1.6 billion that could support up to 29 GW of interconnecting generation along their seam. 

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West’s Mounting Challenges Require Increased Coordination, Panelists Say

LA JOLLA, Calif. — Regional initiatives aimed at increasing coordination and collaboration among Western power entities are essential to tackle mounting technical and political challenges, panelists said during a discussion at the spring joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body on April 2.

Many of the challenges the Western Interconnection faces are coming out of the White House, according to WECC CEO Melanie Frye.

Frye pointed to executive orders impacting the federal workforce, sweeping tariffs and funding pauses for projects in the West. All of this is coming at a time when the risk to reliability is “out front and center,” Frye said in reference to wildfires in Los Angeles, data center demand growth and cybersecurity threats, among other issues.

Coordination and collaboration are key to facing these challenges, Frye said.

An example of such collaboration, according to Frye, is WECC’s adoption of five risk areas the organization’s board of directors approved last year, including:

    • Effects of drought and long-term aridification on the Western grid
    • Reliability challenges related to inverter-based resources
    • Data accuracy and modeling of the interconnection
    • Coordinated planning of the resources in the transmission system
    • Energy policy

“We know we have an integrated grid, and I think it’s going to take the communication, the coordination, the collaboration and the courage to make sure that we continue to keep those lights on,” Frye said. “Through those four C’s, I think we have tremendous possibilities to advance the desires of all of the various states and provinces that are in our footprint.”

Keegan Moyer, a partner at Energy Strategies, said most of the major successes in the Western interconnection, like the Western Energy Imbalance Market, have come through regional coordinating efforts.

However, successful initiatives require trial and error, and “you have to stick with them sometimes for many, many years for them to have any benefit at the end,” Moyer contended.

Additionally, state leadership in regional initiatives is “paramount,” Moyer said.

“So when you look across … what we’re doing now in the region, whether it be [Western Transmission Expansion Coalition], [Western Resource Adequacy Program], the activities going on in WECC, Markets+, [Extended Day-Ahead Market], all these different efforts, state engagement is critical just like it has been in the past,” Moyer said.

Sarah Edmonds, CEO of Western Power Pool, pointed to WRAP as a successful initiative that has brought together Western resources and helped representatives across the energy industry find common ground “to solve the problem of a very serious and looming threat to reliability and resource adequacy in the West.”

However, referencing the other speakers, Edmonds also noted there are challenges in the West, “and that has been difficult for all of us to manage.”

“There’s a lot of layers that you have to navigate through, and you have to make a lot of connections between initiatives and efforts that seem disconnected, but are, in fact, quite organically connected in a number of ways,” Edmonds said.

Despite the many challenges, the Western Interconnection “will decide its own future,” Frye said.

“And I think it’s really important that we not lose sight of the fact that, you know, we’re operating the grid that’s existed for decades, and we know how to do that,” Frye said. “We know the people in this room, and we know the people in the industry that we need to bring to the table. So I think those are important things to not lose sight of.”

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CAISO CEO, Others Point to Reliability Aspect of BPA’s Market Decision

BPA’s day-ahead market decision will have “major reliability and affordability impacts” on electricity customers in the Northwest and across the West, CAISO CEO Elliot Mainzer said in a report he presented to the ISO’s Board of Governors March 26. 

Mainzer’s statement came weeks after BPA issued a draft policy saying it intends to join SPP’s Markets+, the market competitor to CAISO’s Extended Day-Ahead Market (EDAM). (See BPA Selects SPP Markets+ in Draft Policy.) 

As BPA approaches its final market decision in May, energy leaders and experts in the West are focusing on potential reliability issues should the agency choose Markets+ over EDAM. 

“We’ve seen a lot of changes in the last decade in the West, with gas plant retirements and a rapid rise in solar generation in California,” Fred Heutte, senior policy associate at the Northwest Energy Coalition, said in an interview.  

“Coordination between Bonneville and CAISO has been critical in this decade, especially when things get really tough, like under extreme weather conditions. We depend on transmission and strong coordination in the region to keep the lights on,” Heutte said. 

One central concern is that BPA could choose a different reliability coordinator under the Markets+ option. BPA currently relies on CAISO’s RC West as its reliability coordinator, but could switch to SPP’s reliability coordinator, Western RC Services, BPA’s draft policy says. 

“Then the region will have two coordinators,” Heutte said. “How they will work together, especially when demand is high, needs to be thought about in more detail.” 

Having multiple non-contiguous reliability coordinators and market operators in the Pacific Northwest “will pose many operational and commercial challenges,” BPA’s draft policy acknowledges. 

Switching reliability coordinators could come at a price: BPA’s draft shows the total internal implementation cost of Markets+ could be between $53.7 million and $74.2 million, whereas the cost for joining EDAM ranges from $29.9 million to $38 million.  

Estimated internal implementation costs of market options | BPA

The higher cost estimate for Markets+ is driven in part by an assumption that BPA switches its RC from CAISO to SPP, the draft policy says. While BPA’s draft included the estimated costs for changing RCs for transparency, the agency isn’t certain it will make the change, which will depend on future policy development, the document says.  

In an email to RTO Insider, BPA spokesperson Doug Johnson noted that Markets+ comes with higher upfront costs, while production cost modeling analysis done for the agency shows lower revenue in Markets+ compared to EDAM. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.) 

However, Johnson added, the ongoing participation fees “suggest that these upfront costs could level out over time between the two markets, with Markets+ showing potential for significantly lower market operating costs over the long-term. While EDAM’s implementation fee is quite low at $3 million, the recurring annual fee is double that of Markets+.” 

WRAP Key Factor for BPA

From a resource adequacy standpoint, both day-ahead market options include an evaluation for resource sufficiency. BPA said it prefers the design in Markets+, primarily because the SPP also includes a long-term RA requirement, the agency said in its draft policy. 

Markets+ includes a standardized resource adequacy requirement in which all load responsible entities must participate in the Western Resource Adequacy Program (WRAP) administered by the Western Power Pool, while CAISO’s EDAM does not include any such requirement. 

“While the CAISO BAA has its own RA framework, this framework is not extended to other entities outside of CAISO’s BAA in general,” the draft says. “Bonneville believes that Markets+ requiring participation in WRAP, a standardized RA framework, will better meet this [RA] principle.” 

Regardless of its market decision, BPA will be responsible for its system’s reliability, and will do so by acting as transmission planner, balancing authority and transmission operator. BPA will remain responsible for compliance with applicable NERC reliability standards as well. This is because day-ahead markets and market operators do not assume any of the reliability roles of a utility — as in a full RTO, the draft says. 

‘Valued Partner’

In an email to RTO Insider, Mainzer didn’t elaborate on his comment about the reliability impact of BPA’s decision, but reiterated his support for the agency and its ongoing market decision analysis.  

“BPA has been a valued partner to the CAISO for many years and played an essential role in the development of the Western Energy Imbalance Market (WEIM),” Mainzer said. “There is a seat at the table for BPA to remain an active member and architect of a broad, electrically connected energy market that will build on our shared success with WEIM.” 

Irrespective of how BPA ultimately chooses to proceed, CAISO will maintain focus on EDAM implementation and providing technical support to the West-Wide Governance Pathways Initiative (which is working to bring more independent governance to CAISO markets), Mainzer said in his CEO report.   

“We are proud of the fact that the EDAM market design was crafted through an extensive and transparent process with a wide variety of stakeholders before being approved in full by FERC last year,” he said in the report. This message is “a reiteration of the message that … CAISO and many others in the Northwest have been conveying to BPA over the past year,” Mainer told RTO Insider. 

WECC also is following the formation of both day-ahead markets, Kris Raper, the reliability organization’s vice president of strategic engagement and external affairs, told RTO Insider.  

In general, WECC supports the current developments because market structures allow for more effective and efficient dispatch around transmission constraints — leading to a more reliable system, Raper said.  

“However, it is not WECC’s role to evaluate what market, if any, would be better for a utility to join. That said, as a partner in the Western Interconnection with a mission to mitigate risks to reliability, we [will] address any concerns about reliability as the conversation evolves and the markets develop,” Raper said. 

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Data Center Campus with up to 4.5 GW of Gas Generation Planned for Pa.

A data center campus planned in western Pennsylvania would include up to 4.5 GW of on-site gas-fired generation and be the largest facility of its kind in the U.S., a group of developers announced April 2. 

The 3,200-acre Homer City project would stand on the site of what had been Pennsylvania’s largest coal-fired plant, a 1.88-GW facility decommissioned in 2023. 

The effort brings together GE Vernova, Kiewit Power Constructors and Knighthead Capital Management. It carries a price tag expected to surpass $10 billion — not counting the data centers themselves, which would cost billions more. 

Homer City Redevelopment (HCR), which is leading the effort to restore the site to economic productivity, said it would be the largest investment of its kind in state history and is expected to start producing power by 2027. 

HCR indicated that many of the components already are procured for the project, limiting the chances of supply-chain delays. GE Vernova will deliver the first of seven hydrogen-enabled gas-fired turbines in 2026, for example. And critical infrastructure remains in place from the coal-burning plant, including transmission lines to the PJM and NYISO grids, substations and water access. 

There also is the nearby Marcellus Shale formation, one of the most productive U.S. sources of natural gas. Pennsylvania is the No. 2 gas producer in the U.S., after Texas. 

Not discussed in the announcement is the typically slow pace of interconnection and the controversy surrounding co-located large loads. 

“We are fully aware of the project and recently met with the developers,” a FirstEnergy spokesperson told RTO Insider. “We are working closely with them to determine the necessary steps and milestones for them to move ahead with their plans for the site. FirstEnergy is committed to helping to improve the economies of the communities we serve, and we are eager to work collaboratively with the right parties to achieve their visions.” 

A spokesperson said PJM would not comment in detail without seeing more specifics. New resources are important in an era of increasing demand and tightening supply, they said, and the Homer City proposal would be well situated. 

Comeback Planned

When it was built in 1969, the Homer City Generating Station became a physical and economic standout in the rural region 40 miles east of Pittsburgh, providing jobs and boasting a smokestack variously described as the tallest in the state or in the U.S. 

But it ran into regulatory and financial problems as coal-fired generation fell out of favor, and it finally shut down July 1, 2023. The smokestacks and cooling towers recentlywere leveled with explosives. 

The gap of years between shutdown of the old plant and startup of the new plant may factor into the interconnection process. Generation owners can request the capacity interconnection rights held by a retiring resource be transferred to another queue project for up to one year after the unit shutters. That window already has closed. 

The other pathway for new projects to make their way quickly through PJM’s interconnection queue would be by participating in the RTO’s one-off Reliability Resource Initiative, which will allow 50 projects to be added to the Transition Cycle 2 study cluster. PJM said in March it had received 94 applications for the program and will winnow those down to 50 based on several characteristics, including nameplate capacity, in-service date and location. 

Meanwhile, the PJM spokesperson said the issues surrounding large-load co-location await clarification by FERC. PJM recently submitted comments to FERC in the matter in which it expressed reservations about large co-located load configurations participating behind the meter (EL25-49). (See PJM Responds to FERC Co-located Load Investigation.) 

The RTO said its BTM rules were designed for smaller configurations, such as warehouses with on-site solar generation. PJM proposed several configurations that are permissible under the current rules while floating others the commission could consider exploring.