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November 7, 2024

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PUC’s Gleeson at Texas Clean Energy Summit: Smooth Tenure Turns ‘Interesting’

SAN ANTONIO — Thomas Gleeson, chair of Texas’ Public Utility Commission, has seen it all during his tenure at the PUC.

Named the commission’s executive director in 2021 about a month before a winter storm nearly collapsed the ERCOT grid, Gleeson saw the commissioners whittled in numbers from three to two, then one and finally none as they each resigned under withering criticism in the storm’s aftermath. The commissioners’ numbers have grown to five since then due to legislation passed after storm, with Gleeson appointed as chair in January.

Everything went smoothly for Gleeson and the PUC until Hurricane Beryl caught CenterPoint Energy off-guard in July and then an apparently fraudulent generation project was temporarily included in a grant program for $5 billion in state funds. (See CenterPoint Energy Still in Eye of the Storm and Texas PUC Rejects Possible ‘Fraudulent’ Loan Application.)

Dealing with the fallout of those two events has been added to the commission’s full plate, which includes finishing a market redesign and working to approve enough transmission to meet Texas’ growing industrial demand and deciding whether to use 765-kV facilities in that effort.

“The timeline of my time at the PUC has been quite interesting,” Gleeson told attendees during Infocast’s Texas Clean Energy summit, held Sept. 24-26.

“Transmission in this state is something that we haven’t talked a lot about in recent history, because we’ve been focused on market design,” he said. “I tell the governor and the other elected officials, ‘If you want this state to continue to be the economic center for the country and for the globe, you have to invest in infrastructure, water infrastructure, health communication infrastructure, electric infrastructure.’ Those things have to be done congruently, because you cannot have one without the other.”

Gleeson said demand is increasing in Texas because data centers and crypto miners are being added to the industrial base. ERCOT said earlier this year it expects an additional 150 GW of load by 2030, although not all eventually will be interconnected.

“So, what does that mean? It means a lot of companies, a lot of businesses plan to move here,” Gleeson said, noting some of that is crypto mining that “may show up or may not show up.”

“The load growth is something no other ISO in this country is seeing,” he said. “You hear a lot about the size of our state … so people automatically assume load growth is happening because people are moving within ERCOT. That’s not the truth … load growth on the residential side actually remains really flat. The increase in load is because of commercial and industrial customers coming here.

“That causes its own set of challenges, right?” Gleeson added. “You have residential customers that are paying a lot of the transmission costs, and those transmission costs are caused by non-residential customers, so I think that’ll be another story.”

Until then, Gleeson argues, Texas needs an energy expansion, not an energy transition.

“In this state with our load growth, you need an energy expansion,” he said, nodding to a slide that included ERCOT’s current fuel mix. “These percentages are not nearly as important to me as the underlying data, the total megawatts. I want more of all this to last the summer. If you look and analyze ERCOT data, you’ll see that on multiple occasions, solar and batteries saved us. We also need more gas-fired generation because I have days that no one else sees where we are really thin.”

Market Participants Pan PCM

Several panelists panned the PUC’s proposed performance credit mechanism (PCM), which was selected from among five other potential market designs in 2023.

The PCM has been criticized as favorable to thermal generators. It would reward them with credits based on their performance during a determined number of scarcity hours. Those PCs must be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

“There’s been a lot of discussion about who can participate in the PCM,” Black Mountain Energy Storage’s Kevin Hanson said. “I think it’s very important that it has to be technology neutral, that any resource that can deliver those obligations and needs should be able to participate.”

Gleeson

Emily Mullins, Lightsource | © RTO Insider LLC 

Bob Helton, Engie North America’s vice president of government and regulatory affairs, pointed out that an early analysis of the PCM included renewables.

“By taking the renewables out of there, it does increase the cost,” he said, agreeing the PCM needs to be technology neutral. He also urged patience because it could have a bearish effect on real-time energy pricing. “We don’t want to end up with a PCM market with a large percentage of revenue coming through there and overtaking the energy market as a revenue source. We’ve seen that in capacity markets and other markets,” he added.

“I think what’s been lost in a lot of the discussions about an energy-only market is that it functions via scarcity,” Lightsource’s Emily Mullins, on another panel, said. “Scarcity pricing is important because it signals to developers when, where and what type of resource they need to build. However, since Winter Storm Uri, what we’ve seen is there’s snipping at the edges of the energy only market. So, we’ve ended up in this interesting situation where, by name, we’re in an energy-only market, but we’re sort of riding the fence between an energy-only market and the capacity market.”

Gleeson, who was the PUC’s executive director when it approved the PCM, referred to the design as a “novel approach.” He said given that, the PCM should be placed on the back end of other market changes.

“My feeling is, and I think my colleagues share this feeling, is that we have a number of tools at our disposal,” he said. “We should try to see if we can meet our reliability goals with those tools before we look to implement something that’s new and novel and that we don’t really know how it interacts with the rest of our market.”

Texas Eyes More Nukes

Constellation Energy’s Casey Kelley, vice president of state government affairs in the South, appeared at the conference on the heels of his company’s announcement that it plans to re-open Three Mile Island’s Unit 1 — not the one involved in a 1979 partial nuclear meltdown — as part of a power purchase agreement with Microsoft. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

Shannon McGriff, executive director of The Energy Professionals Association and moderator of Kelley’s panel, said she was with the Constellation executive two days before the announcement.

“So, we know you can keep a secret,” she told Kelley.

“I think nuclear is going to be a big topic in Texas this time around, not because anybody’s going to build a new AP 1000 [plant] or even [small modular reactors] in the short term, but I do believe there will be conversation about how we set up the framework to make Texas a leader in that space,” Kelley said, looking ahead to 2025’s legislative session.

He has a supporter in Gleeson, who is waiting on a task force’s report on small modular reactors (SMRs) due at the end of the year. Texas leaders hope the work will position the state as a leader in nuclear energy. The state already hosts two nuclear plants and their four reactors; each plant has 5,000 MW of installed capacity.

“My feeling is if you care about net zero emissions and you care about reliability, you have to care about nuclear. I don’t think the math works for where people are trying to go [meeting future demand] without adding nuclear power,” Gleeson said. “I think increased nuclear has to be a part of our energy future to meet our demand.”

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Cardinal-Hickory Creek Line Fully Energized 13 Years After MISO Approval

Thirteen years after it was recommended by MISO, the controversial 102-mile, $655 million Cardinal-Hickory Creek line is completely in service. 

Co-owners ITC Midwest, American Transmission Co. and Dairyland Power Cooperative announced the completed 345-kV line was flowing power between the Hickory Creek Substation in Dubuque County, Iowa, and the Cardinal Substation in Middleton, Wis., as of Sept. 26. The developers originally anticipated a June 28 full in-service date. The eastern half of the line was energized months ahead of the western half in December 2023 as court battles played out. 

Cardinal-Hickory Creek was approved in 2011 as part of MISO’s multivalue project portfolio and earned a reputation as the most contentious of the 17-line collection. The line’s construction pitted usual environmental bedfellows — conservationists and renewable energy developers — against one another because the line crossed through the Upper Mississippi River Wildlife and Fish Refuge. For years, conservation groups — the National Wildlife Refuge Association, Driftless Area Land Conservancy and Wisconsin Wildlife Federation — argued that the river crossing would scar and fragment wildlife habitat and ruin floodplains. 

Cardinal-Hickory Creek’s final mile intersecting the refuge was tied up in litigation for months this year as the conservation groups lodged a final lawsuit to halt an ultimately successful land swap between the utilities and the U.S. Fish and Wildlife Service that traded more than 35 acres in Wisconsin for almost 20 acres of the refuge’s Iowa footprint. (See Cardinal-Hickory Creek Developers Appeal Injunction on Line’s Final Mile.) 

The trio of environmental groups argued that the U.S. Fish and Wildlife Service, U.S. Rural Utilities Service and U.S. Army Corps of Engineers violated federal laws when they approved permits and accepted the land exchange.  

In May, the Seventh U.S. Circuit Court of Appeals lifted a Wisconsin federal judge’s preliminary injunction issued in March, clearing the way for the final, mile-long connection. The three-judge panel said the federal judge lacked justification for his decision to grant the injunction. Conservation groups tried for a stay; Environmental Law and Policy Center Executive Director Howard Learner, representing the conservation groups, argued the refuge “should not be bulldozed before the conservation groups receive their long-delayed fair day in court.”  

Dairyland Power Cooperative CEO Brent Ridge characterized line completion as a “victory for energy consumers and the environment.”  

“As a backbone interconnection, the line will finally serve as the vital link to a long waiting list of regional renewable energy projects. While supporting carbon reduction goals, Cardinal-Hickory Creek also strengthens grid reliability and resilience at a time of great change in the energy industry,” Ridge said in a press release.  

“Following years of work, including numerous opportunities for public input, extensive regulatory and environmental review, and construction, the entire Cardinal-Hickory Creek line has been placed in service. This allows the project to begin providing numerous economic benefits for electric consumers and environmental benefits for the entire region,” ITC Midwest President Dusky Terry added. Terry thanked construction crews in particular for building the line “in full compliance with comprehensive environmental standards.” 

ATC Senior Vice President of Construction and Maintenance Jared Winters said Cardinal-Hickory Creek will improve reliability, allow access to lower cost energy and offer interconnection points for new renewable resources.  

ITC estimates that 160 renewable generation projects representing more than 24.5 GW in Wisconsin, Iowa and other parts of the Upper Midwestern states were dependent on the line’s completion.  

The developers said they minimized environmental impacts of construction as much as possible, consulting with federal agencies. They said they used wooden construction mats to reduce soil disturbance and sedimentation, did not perform any grading within the refuge and have restored or will restore any impacted natural areas.  

Clean Grid Alliance also cheered the announcement and said the line was subjected to “unsuccessful and unnecessary” legal challenges.  

“Finally! We can now celebrate the ability to deliver more than 24,000 megawatts of clean, affordable, reliable energy, plus the added benefit of improved grid reliability, all of which is now possible because the Cardinal-Hickory Creek transmission line has been energized,” Clean Grid Alliance Executive Director Beth Soholt said in a press release.  

Even with the line’s energization, the National Wildlife Refuge Association, Driftless Area Land Conservancy and Wisconsin Wildlife Federation remain hopeful in their lawsuit.  

Wendy Bloom, senior attorney at the Environmental Law and Policy Center, said a federal court has never found the crossing through the refuge legal. She said the conservation groups maintain ITC, ATC and Dairyland acted unlawfully by clearing protected refuge land after striking the land exchange. 

“Despite today’s news, we are still awaiting an important decision in our lawsuit in federal court. We are proud to have worked with so many in our community and other committed organizations to oppose construction of this unnecessary line,” Jennifer Filipiak, executive director of the Driftless Area Land Conservancy, said in a statement.  

The groups also said the east-west transmission line bisects a north-south migratory bird flyway used by hundreds of thousands of birds annually.  

Since its multivalue portfolio, MISO has designed two more long-term transmission portfolios: the first, $10 billion long-range transmission plan (LRTP) was approved in 2022, and MISO is advancing a second, nearly $22 billion LRTP package for board approval at the end of the year. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)  

The second LRTP portfolio calls for a 765-kV line crossing the Mississippi River from Wisconsin’s Driftless Area into Minnesota, which has led some members to call on MISO to keep the contested Cardinal-Hickory Creek in mind and carefully examine routing assumptions through protected areas. (See “LRTP Mississippi Crossing Raises Specter of Cardinal-Hickory Creek,” MISO Vouches for 2nd, $25B Long-range Tx Portfolio.)  

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FERC Approves $490K in Penalties for NERC Violations

PPL Electric Utilities will pay $400,000 to ReliabilityFirst for violations of NERC’s reliability standards, according to a settlement approved by FERC last week (NP24-12).  

The commission also approved a settlement between the Northeast Power Coordinating Council and Constellation Energy carrying a $90,000 penalty (NP24-11). 

NERC filed the PPL-ReliabilityFirst settlement in a notice of penalty on Aug. 29. FERC indicated in a Sept. 27 filing that it would not further review the settlement, leaving the penalty intact. 

The settlement stemmed from a violation of FAC-003-4 (Transmission vegetation management), which aims to establish “a defense-in-depth strategy to manage vegetation located on transmission rights of way … and minimize encroachments from vegetation located adjacent to the ROW.” Requirement R2 of the standard mandates that applicable transmission owners (TO) and generator owners (GO) “prevent encroachments into the MVCD [minimum vegetation clearance distance] of [their] applicable lines.” 

According to the agreement, PPL submitted a self-report in September 2023, indicating the utility had experienced a sustained outage the previous month. The outage, which lasted about 10 hours, was the result of a cherry tree that grew into the MVCD of a conductor loop on PPL’s Susquehanna-Wescosville 500-kV line. PPL said the line “tripped to lockout because of this vegetation encroachment.” 

ReliabilityFirst said the utility had not been “sufficiently modeling conductor loops located at transmission poles” in its transmission vegetation management program (TVMP). The TVMP used light detection and ranging data, along with foot patrols, to determine potential future vegetation issues, but PPL’s 3D model did not capture the conductor loops, leaving “blind spots” where vegetation growth was not monitored.

In the agreement, ReliabilityFirst observed that PPL’s violation “occurred nearly 20 years following the 2003 Northeast Blackout,” a major cause of which was trees growing into transmission rights of way. The regional entity noted that FAC-003 was one element of the ERO’s response to the 2003 blackout, and that compliance with the standard “is a fundamental expectation of industry.” ReliabilityFirst said the violation “posed a serious risk to the reliability of the” electric grid. 

To mitigate the issue, PPL removed the tree that caused the outage and restored the affected line. It then performed a gap analysis on its TVMP to find potential areas for improvement, updated its models so LiDAR data will better reflect the reality of the system, updated its TVMP, and completed an extent of condition plan to identify and address any additional issues. The utility certified its completion of mitigation activities to ReliabilityFirst on Jan. 22, 2024. 

NPCC Settles Nuclear Plant’s Issues

NPCC’s settlement was filed in NERC’s monthly spreadsheet notice of penalty Aug. 29. FERC’s Sept. 27 filing said it also would not review this agreement. 

In the settlement, the RE asserted the utility violated three requirements of PRC-023-4 (Transmission relay loadability), which were filed as three separate infringements in the spreadsheet NOP. The infringements involved the utility’s nuclear energy division and its facilities at the Nine Mile Point Nuclear Generating Station: Nine Mile Point Unit 1 (NMP1), Nine Mile Point Unit 2 (NMP2) and the James A. FitzPatrick Nuclear Power Plant (JAF).  

Constellation submitted a self-report for the three violations July 14, 2020, the settlement said. The report indicated that two protective relays at JAF “were misclassified by the previous owner.” According to Constellation, the relays were load responsive and therefore should have been categorized under PRC-023-4, Requirement R1. In a subsequent extent of condition review, the utility found a 115-kV line overcurrent relay at NMP1 also was noncompliant. 

Along with this infringement, Constellation said it was in violation of Requirement R3 for failing to agree with its planning coordinator on the use of two 115-kV lines at NMP2. Constellation owns 82% of NMP2, with the rest held by the Long Island Power Authority; however, Constellation is the sole operator of Units 1 and 2. 

Finally, Constellation told NPCC that it had “failed to provide its [PC], transmission operator and reliability coordinator with an updated list of circuits associated with the applicable JAF transmission line relays,” a violation of PRC-023-4 Requirement R4. The utility indicated it had found two separate instances of noncompliance: the first from January 2018 to November 2019, caused by a failure of the previous owner’s preventive controls, the second from January to April 2022, caused by a failure of the utility’s notification controls. 

To mitigate the issues, Constellation outlined its strategies for modifying preventive relay settings and completed an extent of condition review for the JAF and NMP1 units, enhanced its guidance for implementation of NERC standards on the NMP2 case and generated a recurring activity to track compliance with R4. 

NPCC noted that Constellation’s self-reporting and cooperation during the investigation process, lack of previous noncompliance with the standard and willingness to settle the matter as factors in penalty assessment. It also noted that no events or harm occurred during any of the noncompliances. 

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The Buzz at NCEW: The Election, Permitting and IRA Tax Credits

WASHINGTON ― Rep. John Curtis (R-Utah) had “some really good news and some bad news” on permitting reform for attendees at the National Clean Energy Week Policymakers Symposium held on Sept. 25-26.

“The good news is, everybody wants it,” Curtis said, speaking on the symposium’s second day. “The bad news is, everybody has a different definition of what that is … even within the Republican Party, the Democratic Party and then particularly between Republicans and Democrats.”

For some, streamlining and accelerating federal permitting processes is all about expanding and upgrading transmission, he said. For others, it’s about building new pipelines or mining for critical minerals.

“And so, we have some bills and proposals that are out there, and almost all of them have a lot of very good parts to them, but almost all of them are not comprehensive,” Curtis said. “So, what do we do? Do we take bits and pieces, or do we wait for a comprehensive thing that hits everything? And I don’t have a good answer to that.”

With a very close presidential election five weeks away, the fate of permitting reform and the Biden administration’s clean energy policies ― in particular, tax credits in the Inflation Reduction Act (IRA) ― were top of mind for attendees and speakers at the symposium, hosted by the center-right Citizens for Responsible Energy Solutions (CRES).

During the opening panel Sept. 25, for example, Ryan Abraham, principal at Ernst & Young, warned of a looming “fiscal cliff” facing lawmakers in the 119th Congress, pitting expiring tax cuts against clean energy tax credits.

The opening panel at the NCEW Policymakers Symposium dug into the challenges of tax and climate policy facing lawmakers in the 119th Congress. From left are Tanya Das, Bipartisan Policy Center; Ryan Abraham, Ernst & Young; Beth Viola, Holland & Knight; Emily Domenech, Boundary Stone Partners; and Kellie Donnelly, Lot Sixteen. | © RTO Insider LLC 

The Tax Cuts and Jobs Act (TCJA) of 2017 expires next year, he said, and whether Republicans or Democrats control the White House or Congress, the outcome likely will be “tax increases for Americans and … it’s going to cost a lot of money to fix that.”

Should Republicans make a clean sweep of Congress and the White House, they likely would take aim at the IRA’s tax credits and incentives to pay for continuing the TCJA’s trillions in tax cuts, Abraham said. “There’s a lot of revenue there. Eliminating certain incentives, phasing out policies early; this has been one of [Republicans’] talking points.”

A Democratic sweep could see an even greater push on clean energy incentives. But divided government could result either in more uncertainty or more opportunities for bipartisan policies, Abraham and other panelists said.

Beth Viola, senior policy adviser at Holland & Knight, said her firm has a team that works exclusively with companies finalizing contracts for IRA funds with the Department of Energy and EPA.

With billions on the line, Viola said, “those clients are really anxious [about] what happens if we have [another] Trump administration. Are those dollars going to get put on hold? Are they going to be rescinded? … Just across the board, [there’s] this sense of uncertainty, and when you have industries that are putting up billions and billions to match the billions that this government is investing, it gives them a lot of pause.”

Both DOE and EPA have maintained, repeatedly, that once they finalize funding contracts, the IRA dollars are committed and cannot be clawed back, but Viola is less certain.

“This administration is pushing very hard right now to get as much [money] out the door before Jan. 21 as they can,” she said. “But the reality is, we very much expect [that] if [Donald] Trump is re-elected, that he’s going to come in and … pause and look at every single thing. It may be that they just slow everything down so that nobody gets those dollars or sees those dollars for a very long time, if ever.”

A Trump administration also might put a pause on the Treasury Department’s rollout of guidance on IRA tax credits, such as the still pending rules on the 45V clean hydrogen credits, Abraham said. “I can just see them putting a freeze on all guidance projects,” he said. “They’re going to want to take a fresh look at everything.”

Curtis was more optimistic about the fate of the IRA, pointing to the letter he and 17 other GOP representatives sent to House Speaker Mike Johnson (R-La.) in August arguing for the preservation of at least some of the tax credits, which have spurred investments and created jobs in their districts.

In response, Johnson had said that any GOP action on the IRA should use a scalpel rather than a sledgehammer, a statement that has generated pushback from more conservative Republicans.

How the GOP Talks Climate

With only one Democratic lawmaker on the agenda ― Rep. Scott Peters (D-Calif.), who canceled at the last minute ― the symposium essentially was a showcase for the House Republicans’ Conservative Climate Caucus, and its views on what bipartisan legislation should look like.

Curtis started the group in 2021 to find ways to get Republicans to talk about climate, he recalled, and with more than 80 members, it is the second largest GOP caucus in the House of Representatives.

But caucus members speaking at the symposium generally avoided talking about climate, instead stressing their support for clean air and water and preserving the environment while framing Democratic clean energy policies as radical or impractical.

Rep. Brett Guthrie (R-Ky.), a caucus member who hopes to replace retiring Rep. Cathy McMorris Rodgers (R-Wash.) as chair of the Energy and Commerce Committee, agreed that “less carbon is better” but that Democratic climate policies often are based on radical scare tactics or misinformation.

Pointing to California’s Advanced Clean Car II rule, mandating that all new light-duty vehicles sold in the state be zero-emission vehicles by 2035, Guthrie claimed the rule is “just incredibly disruptive; it’s incredibly inefficient, and in the end, does it really save what they say they’re trying to save? I think that’s questionable; so, why take those drastic steps?”

Rep. Brett Guthrie (R-Ky.) | © RTO Insider LLC 

Emily Domenech, a former GOP House staffer and now senior vice president of Boundary Stone Partners, a lobbying firm, argued that Republicans always have supported energy research and development, the National Laboratories and “making sure we keep government out of the way of allowing people to innovate and build in the United States.”

What will be critical post-election is how these “fundamentally Republican ideas” are communicated to the public in the context of a divided Congress, she said.

The issues that could get stakeholders on both sides of the aisle to the table include, of course, permitting reform, as well as U.S. competitiveness with China and artificial intelligence, Domenech said.

AI has “brought a whole range of tech stakeholders to the table in the energy context and thinking about permitting,” she said. “For the first time, I’ve been meeting with folks in the tech space who said, ‘We really want to lean in on this issue, but we haven’t done it before.’

“Now [they] care about nuclear, and they care about fixing [the National Environmental Policy Act], and they care about coming to the table to make sure they can build and grow this infrastructure in the United States,” she said.

Curtis also brought the discussion back to permitting. “A lot of money in the IRA will never be spent if we don’t get permitting reform,” he said. “Worse than that, there is no path to 2050 — clean or unclean, either way — that meets our energy needs without permitting reform. People are seeing a lot of good discussions and healthy discussion about it, but nobody [has] come up with a bill that everybody can support.”

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PJM MRC Briefs: Sept. 25, 2024

PJM Proposes Reopening Discussion of Storage as a Transmission Asset 

VALLEY FORGE, Pa. — About four years after PJM stakeholders shelved deliberations on rules around how battery storage can be used to address transmission constraints, PJM Director of Stakeholder Affairs Dave Anders presented a first read on reopening the topic with a refreshed problem statement and issue charge.  

Anders framed the issue charge as the second phase in developing market rules for battery storage, following on the implementation of rules for how storage can participate in the markets. A possible third phase could consider how a battery installation could serve simultaneously as transmission and a market asset. But PJM’s Becky Carroll said staff prefer to develop clear rules on the market and transmission sides before trying to create a dual-use structure. 

“It’s not a never, it’s just not right now for the dual-use piece of it,” she said. 

Vistra’s Erik Heinle questioned whether stakeholders should embark on developing a new structure for a class of transmission assets while tackling several other major efforts. He suggested instead waiting six months before initiating the work. 

Anders said staff also was concerned about inundating stakeholders with additional meetings, which played into the issue charge designating the work to the Operating Committee. 

Tom Hyzinski, of the GT Power Group, said the classic use case could be a substation where a transformer failure could lead to excessive loading on other facilities. Rather than installing an additional transformer, he said a battery could alleviate the loading while potentially being cheaper and easier to install. He agreed that transmission rules should be developed before considering how that same battery could participate in the markets. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said there are advocates who believe it should be a priority to enable dual-use storage as quickly as possible. He said the possible elimination of energy efficiency as a resource class and de-rating of demand response have limited the ability for load to respond to market signals and that increased storage could present an ability to mitigate capacity prices. Some advocates may seek an amendment to PJM’s issue charge or an alternative with dual use included. 

Exelon’s Alex Stern said he believes it’s best to take “crawl before we walk approach” to avoid consideration of storage as a transmission asset (SATA) being derailed by arguments over dual use. 

Bowring said market-oriented assets, including storage and generation, can be used as transmission, such as when PJM dispatches them to provide voltage support. He said the capability to install SATA could be practically limited to transmission owners. 

The dual-use concept presents even greater concerns, Bowring said, by creating an “impossible task” of determining if one side is subsidizing the other, either markets or transmission with a regulated return. 

LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance

LS Power presented two issue charges focused on PJM’s marginal effective load-carrying capability (ELCC) accreditation framework. One would focus on making the calculations more transparent and replicable for market participants. The other would aim to replace class accreditation with adjustments for each unit with unit-specific ELCC ratings. (See FERC Approves 1st PJM Proposal out of CIFP.) 

Vice President of Wholesale Market Policy Dan Pierpont said a more comprehensive understanding of how ELCC values are determined and how they influence final unit accreditations could allow generation owners to make investments that would improve unit capacity. 

Pierpont said the issue charge seeks a way for generation owners to validate their accreditation values, understand how physical or managerial changes to a unit would affect accreditation and a set date for PJM to lock in changes to ELCC values to provide more market certainty ahead of auctions. 

“The complexity of the marginal ELCC methodology remains an important determining factor in the ability of PJM’s capacity market to send transparent price signals and attract investment where needed,” the transparency issue charge states. “To make that determination, significantly more data and analytical transparency is needed.” 

The document would hold discussion of alternative accreditation frameworks and a sub-annual capacity market to be out-of-scope. It targets having any changes approved to be implemented for the 2028/29 Base Residual Auction (BRA), scheduled for December 2025. 

Susan Bruce, representing the PJM Industrial Customer Coalition (PJM ICC), said more transparency around ELCC could be beneficial for all market participants and suggested an amendment to provide more data access for all members. LS Power Director of Project Development Tom Hoatson said the company would be open to such an amendment to the issue charge, as long as market sensitive information is protected.  

The unit-specific ELCC issue charge seeks to expand the data considered in the ELCC unit-specific performance adjustment to allow accreditation to reflect any changes made that could improve performance. Pierpont said the adjustment considers a narrow number of hours in which load drop occurred, which in practice results in accreditation values weighted toward performance during the 2014 Polar Vortex and weather and load during winter storms in 1994. Investments made in resources since that event would have minimal impact on how that unit’s potential performance is evaluated compared to the rest of the resource class, he said. 

The problem statement argues the issue is twofold: The incentive for generators to make investments to improve performance could be limited if accreditation values would remain static, and maintenance costs may be ignored if no capacity derate is likely. The issue charge targets a FERC filing in the first quarter of 2025.  

The issue charge focuses on how much historical data PJM includes in its performance, load and weather data; the unit-specific performance adjustment and possible use of a unit-specific ELCC accreditation; how ELCC class average values are applied to new resources; and how transmission headroom factors into ELCC values. 

PJM CEO Manu Asthana said it takes a long time for performance improvements to be reflected in resource accreditation and it’s a valid inquiry to look at how investments can be accounted for more quickly. 

LS Power Senior Vice President of Wholesale Market Policy Marji Philips said if a turbine fails during a performance assessment interval (PAI) and the generation owner replaces the equipment and makes changes to avoid that happening again, that event can lead to diminished accreditation for years. 

“That bad experience during a PAI haunts us for years,” she said. 

The PJM Public Power Coalition’s Carl Johnson said the ELCC construct can be improved upon, but any stakeholder efforts must be approached cautiously to ensure they do not conflict with changes likely to be made through the second phase of PJM’s capacity market redesign. 

Vitol’s Jason Barker said it’s logical to reflect capital expenditures, but the issue charge seems focused on speeding accreditation for thermal resources without addressing the increased accreditation for renewables resources that could be unlocked through a sub-annual market design. He also questioned whether it’s reasonable to expect changes to the ELCC structure could be accomplished within the envisioned 4.5-month timeline. 

Independent Market Monitor Joe Bowring said stakeholders discussed related issues at length during the Critical Issue Fast Path (CIFP) process last year, and he said membership is capable of acting in a disciplined and focused way. 

Poulos said the compressed capacity auction schedules makes the implementation timeline especially important and recommended prioritizing working areas to ensure changes can be in place for the earliest auction possible. 

Stakeholders Endorse Creation of Electric Gas Coordination Subcommittee

The MRC endorsed the sunsetting of the Electric Gas Coordination Senior Task Force (EGCSTF), to be replaced with a new Electric Gas Coordination Subcommittee (EGCS), which is intended to have a wider scope and be more flexible in the topics it can address. (See “PJM Proposes Sunsetting Electric Gas Coordination Senior Task Force,” PJM MRC/MC Briefs: Aug. 21, 2024.) 

The MRC voted in June to endorse part of a proposal drafted by the EGCSTF, greenlighting changes to the day-ahead energy market commitment cycle to align with daily gas pipeline nomination deadlines. Stakeholders rejected a second component that would ask generators to voluntarily notify PJM of whether they have procured fuel necessary to meet their commitments or intend to do so. (See “Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules,” PJM MRC/MC Briefs: June 27, 2024.) 

A subcommittee would allow a more long-term focus on harmonizing aspects of PJM’s markets with how gas pipelines are operated and consider revisions to a broader swath of PJM’s market rules. 

The draft charter states that the responsibilities and scope of the subcommittee include reviewing market and operational conflicts between the electric and gas sectors, assessing and updating participants on state and federal initiatives affecting gas-electric coordination, and “[recommending] necessary enhancements to PJM rules, systems and procedures which can improve grid reliability, efficient market operations, and greater availability and flexibility of natural gas-fired generating resources.” 

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned how it can be ensured that stakeholder efforts to improve market rules around gas generation do not become siloed between different working groups. Anders said part of subcommittee’s charge would be to keep tabs on those efforts with regular updates. 

“The important part is to keep the communication lines open … and frankly I think that’s one of the things this new subcommittee can do, to make sure we’re thinking across the whole horizon,” Anders said. 

Hourly Notification Times in Day-ahead Market Endorsed

Stakeholders endorsed a proposal to add hourly notification times to the day-ahead (DA) energy market, expanding the capability from the real-time (RT) market. (See “Hourly Notification Times,” PJM MRC/MC Briefs: Aug. 21, 2024.) 

PJM’s Joseph Ciabattoni told the MRC that generators are limited to daily notification in the DA market. But reserve price formation market changes have increased the importance of notification times for determining the eligibility and capability of offline resources to be committed as non-synchronized and secondary reserves. 

Sotkiewicz said notification times are an important factor for gas resources and more discussion is needed to continue to refine how they are committed. 

PJM Proposes Elimination of Two Interface Pricing Models

PJM’s Brian Chmielewski presented a first read on tariff revisions to remove the high/low and marginal-cost proxy interface pricing options. (See “PJM Proposes Elimination of 2 Interface Pricing Options,” PJM MIC Briefs: Aug. 7, 2024.) 

Both were designed for pricing imports and exports with neighboring nonmarket regions. But they have gone unused since July 2019, when Duke Energy Progress terminated its dynamic interface, which used marginal-cost proxy pricing. Chmielewski said a nodal aggregate pricing approach has since been implemented, which PJM believes creates accurate price signals based on other interfaces. 

The proposal is set to be voted on by the MRC on Oct. 30 and the MC on Nov. 21 and to be filed at FERC in December. 

First Read on Increased Review of Credit Risk for Bilateral Capacity Transactions

PJM presented a first read on a proposal to strengthen its ability to collect capacity performance (CP) penalties from market participants who have bilaterally sold their capacity rights and revenues. 

Assistant General Counsel Eric Scherling said bilateral transactions separate the payments received by the buyer from the performance obligations held by the seller, which can present issues if the seller does not have proper credit or revenues to cover any possible performance penalties. 

PJM would conduct a credit review of bilateral capacity transactions before they can be completed and both parties’ creditworthiness and the impact the transaction might be considered before PJM signs off. Transactions where both the buyer and seller have external investment grade ratings, and the total notional value of the transaction is less than their unsecured credit allowance would be considered approved unless PJM states otherwise. 

If PJM is notified of a transaction before 1 p.m., it would complete the credit review by the end of the next business day; if the notification came after 1 p.m., PJM would have two days to complete the review. 

PJM’s Gwen Kelly said the intent is not to create any changes to the credit risk evaluation, but to provide more visibility into the transactions before they’re created to allow proactive, rather than reactive, actions to be taken if issues are identified. 

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Texas PUC Approves Permian Reliability Plan

Texas regulators have approved ERCOT’s reliability plan for the petroleum-rich Permian Basin that could rely on the state’s first use of 765-kV transmission facilities.

The plan includes 765- and 345-kV infrastructure to support the region’s current and future power needs and new and upgraded local projects, as well as new import paths that will bring additional power to the region. The Public Utility Commission approved the plan during its Sept. 26 open meeting (55718).

Commissioner Lori Cobos, a native West Texan who has taken the lead on the proceeding, filed a memo recommending the PUC authorize the region’s transmission service providers (TSPs) to begin preparing applications for infrastructure along eight import paths into the basin to serve its projected load in 2030.

She said that would preserve the plan’s “optionality” after recent ERCOT analysis indicated that installing transmission elements capable of either voltage would require additional months of engineering studies. The grid operator initially hoped to use interchangeable import paths capable of both 345- and 765-kV lines.

“The whole goal remains the same in terms of preserving optionality at this time on the import paths into the Permian Basin region, so that ERCOT and the commission can continue their evaluation of EHV [extra high voltage], primarily 765-kV transmission lines,” Cobos said.

She said directing ERCOT to work with the TSPs on the import paths that would be needed for 2030 will provide certainty by prioritizing the applications for certificates of convenience and necessity. At the same time, she said, the grid operator and PUC will be able to continue their evaluation of EHV transmission and determine the import paths so CCNs can be filed. ERCOT has designated five of the import paths as 345-kV and the other three as 765-kV.

Cobos set a date certain of May 1, 2025, for the commission to approve the 765-kV lines. Should the PUC decide not to move forward with the EHV buildout, the 345-kV import paths would be considered approved and the TSPs allowed to file their CCNs, she said.

The grid operator has projected oil and gas load peaking at nearly 15 GW by 2038 and an additional 12 GW of data center and other non-petroleum load by 2030. Based on those projections, ERCOT has said building the transmission facilities to meet that load could cost more than $15 billion. It currently is considering 4,481 miles of 765-kV lines and 20 associated substations. (See EHV Tx Lines Coming into Focus for ERCOT.)

“If you look at some of the cost estimates for building out a 765 backbone throughout the state, it’s going to cost a lot of money just because of how large the state is,” PUC Chair Thomas Gleeson said in a keynote address Sept. 25 at Infocast’s Texas Clean Energy summit in Houston. “I think it’s important for us, for ERCOT, for the transmission and distribution utilities to not only show that cost, but also speak intelligently and clearly about what the benefits of all these transmission upgrades are, because you don’t get all the economic development here unless you’re willing to invest in the infrastructure.”

“It’s going to be a tremendous boon for our state in so many ways,” Cobos said of the plan.

Commissioner Jimmy Glotfelty continued to push for EHV lines, saying he was ready “to do 765.”

“I continue to believe that the deeper we get involved in the process and the deeper ERCOT’s involved in the process, the longer it’s going to take,” he said. “If we continually kick things to ERCOT, I fear that there are things that we can get tripped up on and slow down, and that makes me fearful of the default back to 345. I don’t think that’s the right default. The amount of congestion that we see in West Texas that this could help solve is somewhere between $100 [million] and $300 million a year. That obviously would pay for these lines, not even considering the economic development in the Permian.”

PUC to Review 4CP Program

The commission signaled it is ready to discuss doing away with ERCOT’s Four Coincident Peak (4CP) program, a demand charge that alerts industrial users to high energy costs during peak demand periods and was intended to allocate transmission costs to the drivers of new facilities (34677).

Staff said they were “supportive of opening the dialogue about 4CP.” They noted the program has been in existence for more than two decades and suggested it can be revised to maintain an ERCOT-wide rate based on demand but still “modify the allocation method away from 4CP.”

“I think it’s definitely time to talk about it and be proactive about … reviewing that decision that was made 20 years ago and make sure that it remains the correct one. And if not, then what should we be moving to?” Barksdale English, the PUC’s deputy executive director, told the commissioners, while also noting there is not “uniform [staff] opinion” on the program.

The grid operator’s Independent Market Monitor has recommended since 2015 in its annual market reports that 4CP be changed to better reflect the true drivers for new transmission. It said again in its latest report that the current method “does not apply transmission costs equitably to all loads.”

Under 4CP, pricing signals are sent to industrial customers who might want to avoid peak transmission costs. ERCOT looks at the peak demand over four 15-minute intervals from each of the summer months — June, July, August and September — and then assigns transmission costs to transmission and distribution service providers (TDSPs) based on their share of total peak load.

The TDSPs recover their transmission-cost obligations through wires charges on all loads. Staff use those obligations to calculate 4CP demand charges for industrial customers based on the facilities’ peak demand during the four 15-minute windows. The 4CP charges are then distributed over a 12-month period as part of the facility’s bill over the next year.

“Customer demand during the peak summer hours is no longer the main driver of new transmission in ERCOT today,” the Monitor said in its 2023 State of the Market report. “Decisions to build transmission are based on transmission congestion patterns throughout the year and an analysis of whether generation can be delivered to serve customers reliably.”

Cobos agreed the discussion on 4CP is worth having, given the need to build out the grid to meet demand that continues to increase.

“We have to make sure that we start proactively looking at how we are allocating costs and developing cost allocation and rate design in our rate cases now,” she said. “I’m concerned that all of the massive transmission infrastructure that we’re looking at as a future will be primarily allocated to the small business and residential consumers, so I think that the 4CP discussion needs to start as soon as possible.”

Staff made the suggestion as part of a response to the IMM’s latest market report. They gave an opinion (support, neutral or disagree) on each of the Monitor’s 16 recommendations from the current and previous reports.

The PUC also approved a proposed rulemaking that establishes procedures for utilities outside ERCOT’s footprint to apply for grants from the Texas Energy Fund. The TEF includes an Outside ERCOT Grant Program that will award grants for the modernization of infrastructure, weatherization, reliability and resilience enhancements, and vegetation management for facilities outside ERCOT.

The commission will accept comments on the proposal through Nov. 7 (57004).

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Utilities Working to Restore Power After Helene Tears Through 10 States

The U.S. Department of Energy said Sept. 30 about 2 million customers still were without power after Hurricane Helene knocked out power to about 6 million across 10 states stretching from Florida to Ohio. 

The most affected states were Georgia, North Carolina and South Carolina, which sustained more than half the outages. As of the morning of Sept. 30, about half of those customers remained without power, said a report from DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER). 

The storm hit Florida’s Gulf Coast late on Sept. 26 and moved north the next two days through Georgia, South Carolina, North Carolina, Virginia, West Virginia, Tennessee, Kentucky, Ohio and Indiana. It brought strong winds and heavy rains, which led to flooding in some states, DOE said. 

Restorations remain underway as utility mutual assistance crews totaling about 50,000 workers from 27 states, the District of Columbia and even Canada were working to restore power, although the hardest-hit areas were expected to be without power through the end of this week.

“Restoration efforts after Helene will be a complex, multiday effort in many locations due to the extent of damage and ongoing access issues,” CESER said. “Utilities have been encountering widespread flooding and debris impeding access to damaged infrastructure. Communications disruptions are also impacting restoration efforts.” 

Duke Energy owns utilities in several states the storm affected, including its Florida subsidiary’s territory covering the area where Helene landed — the state’s “Big Bend” region where the panhandle meets the peninsula. Florida saw more than 1.3 million customers lose power, but Duke reported that 95% had been restored by Monday afternoon. 

Georgia Power reported it had 15,000 personnel working to restore power to all of its customers, having completed restoration to 840,000 customers by the afternoon of Sept. 30, with 370,000 still without electricity.  

Those remaining without power were in the hardest-hit parts of Georgia, in its eastern, southern and coastal regions, including Augusta and Savannah. The Southern Co. Affiliate has to replace more than 7,000 power poles, 15,000 spans of wire equivalent to 700 miles and more than 1,200 transformers and also remove more than 3,000 trees from power lines, it said. 

By 4 p.m. on Sept. 30, Duke Energy Carolinas reported it had restored power to 1.35 million customers, with 443,000 still without power in South Carolina and an additional 346,000 out in North Carolina. It expects to restore service to most of the 790,000 customer outages by the night of Oct. 4. 

“We’re beyond grateful to the state and local government workers who have been on the job 24/7 to clear debris, re-open roadways and help those whose lives have been changed forever by this storm,” Jason Hollifield, Duke Energy’s storm director for the Carolinas, said in a statement. “Our thousands of lineworkers and other storm workers are gaining better access to the destruction — allowing them to remove trees, broken poles and downed power lines, log each piece of damaged electrical equipment, and begin repairing and rebuilding major portions of the power grid that were simply wiped away.” 

North Carolina’s Electric Cooperatives reported an additional 90,602 customers among its members without power the afternoon of Sept. 30. 

Around the same time, Duke Energy Ohio still had 1,180 customers out, according to its outrage map, while American Electric Power subsidiary Appalachian Power, which serves western Virginia and parts of West Virginia, reported 110,197 customers still without power. 

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PJM Working to Speed Development of New Capacity

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee discussed how the development of new capacity can be sped, as a growing number of resources have cleared the interconnection queue but not entered commercial operation. 

PJM Vice President of Planning Paul McGlynn said the cluster-based approach to studying interconnection requests has increased the pace of processing projects, estimating that 72 GW of new generation will clear the queue by the end of 2025. Thus far, only 2 GW has actually come into commercial service, and most of that is solar resources with a relatively small capacity contribution. 

Lead time for equipment, local opposition and financing all remain obstacles for developers, McGlynn said, adding that this represents a call to action for stakeholders to identify and work to remove those barriers. 

“We need to get the resources that are going to move forward, we need to get them connected to the grid so they can help us out with the resource adequacy issues that we are having,” he said. During the Aug. 6 Planning Committee, PJM stated that generation deactivations, rising load forecasts and sluggish resource entry are contributing to a possible capacity shortfall in the 2029/30 delivery year. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

The growing number of resources with service agreements that have not entered operation presents planning staff with challenges when identifying possible transmission reliability violations. PJM’s Jason Shoemaker said planned generation resources are modeled the same as operating units, creating instances where resources are assumed to be injecting MWs onto the grid when they actually still will be under development. That is driving up the number of violations and their complexity, he said. 

Vitol’s Jason Barker said PJM has implied that developers are moving through the interconnection process and leaving projects idle, a characterization he said misses work like permitting and siting that must be completed before the “boots on the ground” phase can begin. While some of the legwork used to be done while projects moved through PJM’s interconnection queue, he said the amount of time it now takes for projects to be processed has transformed a concurrent interconnection, permitting and siting process into a serial one. 

“Permitting is time consuming [and] costly, and permits expire. So the development community, as I think you’ve acknowledged, has real work before the shovels go in the ground, boots go on the ground. So, we have a really strong concern with the messaging that PJM has provided here,” primarily because it misleads the stakeholder community as to the diligence developers have in completing their projects, Barker said. 

Some of the same procurement challenges developers have faced also are affecting transmission owners’ ability to complete network upgrades necessary to allow resources to come online, with transformers, breakers and other components in short supply worldwide.  

“We very much want to bring our projects to completion and are working diligently to do so,” he said. 

Rather than focusing on the number of projects that still are in some phase of development, Barker said the focus should be on PJM’s success in canceling the queue positions of projects it has determined are not advancing toward commercial operation. 

Shoemaker said PJM has a cure process when a project misses development milestones, which typically lasts a few months before either a suspension is granted, the breach is remedied or the project is removed from the queue. He said about 75% of developers’ requests to change their agreements are granted by PJM. 

Tangibl Group Director of RTO and Regulatory Affairs Ken Foladare said PJM is making good progress in clearing projects faster. But the amount of time projects already have been in the queue has affected their ability to progress with permitting and financing. He said one project was seeking commercial operation in 2027, but the transmission owner said the earliest that would be possible was 2030 to 2031. Any permits received that far out would expire before work could begin. And financing also is unlikely to materialize that far in advance. 

Shoemaker said transmission delays can happen, and projects affected would be considered in the engineering and procurement phase. He said PJM’s focus when negotiating milestone deadlines is a project-specific review of whether a developer is doing everything in its power to move projects toward completion. On the other hand, he said granting delays can affect other developers in line behind that project, who need to be given a fair shot at advancing as well. 

Calpine’s David “Scarp” Scarpignato said there have been issues with how project suspensions and delays affect others in the queue, as well as possible reliability impacts as PJM models the injection of power from resources that are not built according to schedule. Even if network upgrades are completed on time, he said that could lead to energy not being available where it was expected. 

PJM CEO Manu Asthana said blame is irrelevant and the focus should be on what would improve completion rates. Capacity costs increased in the last Base Residual Auction (BRA) and the price cap is set to increase in the 2026/27 auction, stressing consumers. On the other side, he said forecasts of load growth continue to accelerate and could remain an undercount. 

He said PJM views a recent transaction in the footprint to purchase power outside the market for 20 years as a data point showing that demand is real. He encouraged stakeholders to deconstruct the deal and its implications on the capacity market. On Sept. 20, Constellation Energy announced an agreement with Microsoft to reopen and rename its 835 MW Three Mile Island Unit 1 the Crane Clean Energy Center with a 20-year power purchase agreement. (See Constellation to Reopen, Rename Three Mile Island Unit 1.) 

While solar and wind are viable in PJM and more renewables are beneficial, Asthana said they don’t provide the capacity needed by the end of the decade. If new construction is needed, he said there should be a corresponding price signal and that resource adequacy solutions must come through the interconnection queue. 

“I think it’s a generational challenge for us and we’re going to have to solve it together,” he said. 

Foladare commented that PJM’s wholesale market rules and price signals are leading developers to drop the storage component of some hybrid resources, leaving products that have limited utility as capacity. How batteries are accredited under PJM’s marginal effective load carrying capability (ELCC) approach has made standalone and hybrid installations less economically attractive. 

“Something has to be done in this area if you want to see more solar with storage or wind with storage,” he said. 

Asthana pointed to record-high clearing prices in the 2025/26 BRA and said he is hearing that high prices are needed to enable widespread storage development while consumers are stating prices are unsustainable. 

“We want more storage … but we hear it loud and clear that consumers don’t want high prices and right now those two things do not match,” he said. 

Foladare said capacity prices make up a relatively small portion of the potential revenue for storage. The overall cash flows from energy, ancillary services and capacity are not sufficient to cover the incremental cost of installing storage, he said. He suggested a fast-ramping product could fit the capabilities of storage better. 

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PIO Complaint Faults PJM Treatment of Deactivating Generation

Several public interest organizations (PIOs) have filed a complaint with FERC contending PJM’s capacity market inflates consumer prices by not counting generators operating on reliability must-run (RMR) agreements as a form of capacity (EL24-148).

The complaint argues that RMR contracts already require units to be online and available to PJM dispatchers in a capacity emergency, which positions them similarly to committed capacity.

The PIOs said consumers are being asked to pay for capacity twice: once for an RMR unit’s availability and again to procure the capacity the unit would have offered had it participated in the RTO’s Base Residual Auctions (BRAs).

The complaint was submitted by the Sierra Club, Natural Resources Defense Council, Public Citizen, Sustainable FERC Project and Union of Concerned Scientists.

“Failing to account for resource adequacy provided by RMR units produces capacity market price signals that are disconnected from the actual supply and demand balance on the grid,” the complaint says. “This distorted supply-demand balance is economically inefficient because it signals a degree of scarcity that does not exist. The result is artificially elevated prices that harm the markets by encouraging inefficient decisions by both supply and demand side market participants.”

The complaint also argues that PJM’s position on modeling RMR resource capacity is inconsistent because it does not include RMR units’ output when analyzing the amount of generation available within a locational deliverability area (LDA) when analyzing transmission capability during potential capacity emergencies.

The PIOs present two visions for how RMR resources could interact with capacity markets. The most straightforward would be requiring them to offer into the market at $0/MWh as price-takers; however, the complaint acknowledges the change could make generation owners wary of accepting an RMR agreement — which is a voluntary election in PJM. The alternative they propose would be to model RMR units when determining the reliability requirement and reduce the amount of capacity that must be procured through BRAs.

The complaint also requests the commission delay the 2026/27 BRA, currently scheduled for December, to allow the changes to be implemented for that auction.

RMR Impact Set to Increase

The impact of RMR agreements on consumer rates is likely to increase substantially in the 2025/26 delivery year, when agreements take effect between PJM and Talen Energy to keep the 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators online from June 1, 2025, through Dec. 31, 2028.

The complaint cites analysis from Synapse Energy Economics, on behalf of the Maryland Office of People’s Counsel, and a separate report from the Independent Market Monitor, which found that not counting RMR units as capacity could cost PJM ratepayers $4billion to $5 billion in 2025/26. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

The terms of the Talen agreements are being negotiated through settlement judge proceedings the commission ordered in June. The company requested $175 million in annual fixed costs and $29.9 million in project investments for Brandon Shores and $40.3 million in fixed costs and $4.5 million in additional investments for Wagner. (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)

Stakeholders also are discussing changes to PJM RMR resources in the Deactivations Enhancement Senior Task Force (DESTF), which is set to open a vote on five proposals during its Oct. 2 meeting. The DESTF packages largely focus on extending the notice generation owners must provide PJM ahead of their desired deactivation dates and how compensation under RMR contracts is determined.

None of the DESTF proposals include a capacity must-offer requirement for RMR units, but a proposal from the Sierra Club would model the expected output of RMR resources that do not participate in the capacity market when determining the reliability requirement.

The parties to the complaint argued that even if a proposal passed that satisfies their concerns, changes are unlikely to be implemented in time for the December auction. The PIOs also noted that the PJM Board of Managers rejected a request from six state consumer advocates in an Aug. 30 letter to launch a Critical Issue Fast Path (CIFP) process to require RMR units to participate in the capacity market. In its Sept. 19 response, the board wrote that doing so would undermine the capacity market’s price signals to replace the outgoing generator or make investments to keep units operational.

In the first of a series of reports on the 2025/26 BRA, the Monitor estimated that not including RMR units in the supply stack as capacity price takers would have increased the cost of capacity procured by more than $4 billion, or 41.2%. The Monitor said this would recognize that RMR resources provide reliability while transmission upgrades to address their deactivation are constructed.

“There are times when a price signal for the entry of generation is not needed or appropriate, e.g. when PJM has committed to the construction of new transmission that will eliminate the price signal when complete,” the Monitor wrote.

Monitor Joe Bowring told RTO Insider that requiring an RMR unit to offer into the capacity market also could lead to costs for consumers, as generation owners would be more wary of entering into RMR agreements and would seek to recover the risk of being subject to capacity performance (CP) underperformance penalties. Instead, he suggested including them in the supply curve as a zero-cost offer.

Bowring said one of the issues with how generation deactivations are treated in PJM is the lacking ability for merchant generation to compete with transmission to address any identified reliability violations. He argued that an expedited interconnection process is needed to give new resources a chance to provide a solution to violations or when reliability issues are identified in general, such as the capacity shortfall PJM has been warning about in the 2029/30 delivery year. He has proposed a similar concept at the Planning Committee for allowing PJM to transfer capacity interconnection rights (CIRs) from a deactivating resource to resources which could resolve associated violations. (See “Voting on CIR Transfer Proposals Deferred to October,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)

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CAISO Seeks to Dispel CRR ‘Myths’ Around January Cold Snap

CAISO focused on congestion revenue rights when it served up the latest volley in the ongoing dispute over what played out on the Western grid during the January cold snap that forced Northwest utilities to import unusually high volumes of energy to avoid blackouts. 

“Given all the nuances and complexities with all the dynamics at play during that event, it is always useful to step back and have the opportunity to provide some basic facts of how things actually happened,” Guillermo Bautista Alderete, CAISO director of market performance and advanced analytics, said during a Sept. 27 presentation to the Western Energy Imbalance Market’s Regional Issues Forum (RIF).  

“But in order to reach that point in the discussion, it is critical that we first differentiate between the fact and the myth,” Alderete said.  

The cold snap over the Jan. 12-16 Martin Luther King Jr. holiday weekend saw record low temperatures along with historically high peak demand, prompting five different balancing authority areas (BAAs) to declare energy emergency alerts. Stressed grid conditions also produced price separation between the Northwest and California, with extremely high bilateral prices in the Northwest and at the Malin intertie in particular.   

Central to the dispute over the event was CAISO’s role in supporting the Northwest during extreme weather conditions, as the disagreement quickly became a proxy for the broader competition for members between the ISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+. (See NW Cold Snap Dispute Reflects Divisions Over Western Markets.) 

A Feb. 8 report by the Western Power Pool found that while CAISO and other California BAs exported nearly 3,000 MW of energy to the Northwest, they also were net importers, suggesting the Desert Southwest and Rockies regions — and not California — were the origin of most of the Northwest’s supporting imports.  

That was followed by a Feb. 23 letter from the Portland, Ore.-based Public Power Council (PPC) to Bonneville Power Administration CEO John Hairston, which critiqued the ISO’s allocation of congestion revenue rents (CRRs) during the event. The PPC wrote that “CAISO’s congestion policies resulted in over $100M of congestion revenues being collected by the CAISO BAA, despite most of the generation serving the Northwest coming from outside California.” 

In a March 6 report, Powerex expanded on the CRR complaint and even called on Northwest entities to develop ways to circumvent flowing energy through California, while CAISO that same day issued its own 80-page report defending its actions during the cold snap and explaining the mechanisms used by the WEIM to move power around the grid.    

‘Myth Busting’

Alderete’s Sept. 27 “myth-busting” presentation to the RIF drilled further into the CRR issue, offering a series of seven “facts” and “myths” about what occurred and focusing on the congestion occurring at Malin and on the California-Oregon Intertie (COI) — the main interface between BPA and the ISO. 

The first “myth” Alderete addressed was the assessment that the ISO unilaterally decides on Malin limits to influence congestion. He emphasized that both BPA and the ISO are path operators on the COI and that there is an agreement between the two operators to have a “coordinated operation of the path” and “always enforce the most limiting constraint on the path.”  

According to Alderete, this first “myth” set the stage for the second one: that the ISO directly influenced day-ahead congestion on the Malin intertie. His presentation said the day-ahead congestion occurred “simply because the volume of exports requested for the Northwest exceeded the full Malin capability. Exports at Malin were twice as much as the full Malin capacity, and through the day-ahead market, the ISO positioned internal supply economically to support exports to the Northwest.”  

A third “myth” further perpetuated the belief that CAISO limited COI flows to influence congestion, but Alderete said that COI transfer capability during the MLK weekend was fully available and used in the day-ahead market for the share of the line operated by the ISO.  

“Here is the simple fact for these critical days of the MLK weekend: There were no derates on the Malin intertie. The full capacity of the intertie was used and made available in the day-ahead market,” Alderete said. “I can see how this myth could have been created out of confusion and maybe not appreciating the time frames of the event, and I can clarify that, specific to the MLK weekend, there were indeed weather-related forced outages in the BPA area, and those eventually resulted in derates to the path.”  

But the forced outages and derates affected only the real-time market, Alderete said.  

Delving further into the weeds, Alderete contested the “myth” that CAISO “charged excessive prices to exports flowing to the Northwest, reiterating that congestion prices on Malin were set by export bids, which reflected the price exports were willing to pay to flow.  

Alderete also provided additional color to the process of allocating congestion, saying that while a fifth “myth” holds that parties outside the ISO market have a right to day-ahead congestion revenue, the fact is that it’s sourced “only from re-dispatch of participating resources in the ISO market, including exports.”  

CAISO doesn’t have access to resources outside of its market, such as those north of Malin, to re-dispatch and alleviate congestion on ISO constraints, meaning that the sixth “myth,” that CAISO collected congestion rents on all Malin capability, is incorrect. 

“Congestion on Malin is only collected for the capacity made available to the market, lower than the full capability,” the presentation read. “The ISO operates two-thirds of COI capability; only that portion will be managed in the ISO market with Malin intertie.” 

The final and “biggest myth” that caused significant concern among some Western entities was that CAISO kept all $100 million of day-ahead CRRs collected on the Malin intertie. But Alderete emphasized that CRRs are given to their holders and that any surplus is allocated to demand and exports. Because the Malin capacity wasn’t fully exhausted in the CRR release, over $50 million in surplus congestion rents were allocated to measured demand. 

Alderete’s presentation came after a group of Markets+ supporters released a series of “issue alerts” favorably comparing the SPP day-ahead market with the EDAM. The latest alert, focused on market seams, covered the congestion rent subject. (See Markets+ ‘Equitable’ Solution to Seams Issues, Backers Say.)   

Alderete told RTO Insider in an email that the ISO will continue the conversation about the issue at the RIF’s October meeting, for which an exact date has not yet been announced.