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December 16, 2025

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SEEM Opponents Urge FERC for Clarification

The Sierra Club, Southern Alliance for Clean Energy and 11 other opponents of the Southeast Energy Exchange Market (SEEM) called on FERC to either clarify its March 14 order to update the market’s agreement or allow a rehearing of what they described as a novel legal theory put forward by the commission (ER21-1111-006, et al.).

The April 14 requests by the opponents, jointly filing as the ad hoc Public Interest Organizations (PIOs), arrived the same day as a response filed by SEEM members to FERC’s order. (See SEEM Members File Market Agreement Update.)

That response was an update to the SEEM agreement confirming that utilities may participate in the market via pseudo-ties, addressing a concern of the D.C. Circuit Court of Appeals about the agreement’s requirement that participants have a source or sink physically located within the market’s territory.

The PIOs’ filing concerns a different part of the March 14 order, which FERC issued following briefings from supporters and opponents of SEEM. In the order, FERC affirmed its earlier decision that SEEM’s open access transmission tariff is “consistent with or superior to the pro forma OATT,” justifying the assessment on the basis of the commission’s comparability standard, which FERC said “requires that comparable service be provided to comparable customers.”

This description of the comparability standard is the crux of the PIOs’ filing, which accused FERC of inventing a new definition by adding the term “comparable customers.” The PIOs noted that when FERC initially articulated the standard in 1994, it said that an OATT “should offer third parties access on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider’s uses of its system.” At no point since then has the commission used the “comparable customers” language, the PIOs said.

“Nothing in the March 14 order indicates that the commission intended to modify its precedent regarding” the comparability standard or the alternative undue discrimination analysis of “whether utilities and their native load customers are similarly situated to third parties,” the PIOs continued.

Further, they argued that the same paragraph seems to switch between the two frameworks, finding that “entities located outside the SEEM footprint are not similarly situated to [those within], which justifies SEEM’s requirement that the former utilize a pseudo-tie to participate.” The discrepancy indicates that FERC’s order “did not intend to apply the comparability standard at all,” they said.

To address this “potential confusion,” the PIOs said FERC should clarify the March 14 order. They suggested doing so by removing the sentence that mentions the comparability standard, which would confirm that only the undue discrimination analysis should be applied.

If the commission did intend to apply the comparability standard, it should allow a limited rehearing of the relevant sentence and “modify the discussion to retract this unexplained and unjustified departure from its practice and precedent,” the PIOs argued. Such action is needed to address what they called FERC’s arbitrary and capricious redefinition of the standard.

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EIA Projects Demise of Coal, Rise of Renewables

The U.S. Energy Information Administration predicts sharp increases in renewable power generation and sharp decreases in coal-fired power in its 2025 Annual Energy Outlook, released April 15.

The EIA also projects an overall decrease in U.S. energy consumption over the next decade, with subsequent increases so small that 2050 levels still are lower than 2024 levels.

The agency notes that the numbers vary among the modeling scenarios used, and it makes clear the projections were created using the laws and regulations in place in December 2024 — a month before a president who supported energy conservation was replaced by one moving to increase energy production and consumption.

The EIA and its parent agency, the Department of Energy, now work for President Donald Trump. The April 15 release of the AEO was accompanied by a DOE spokesperson’s attack on President Joe Biden’s policies and affirmation of Trump’s policies.

Some of the projections in the outlook — such as a drop in nuclear generation capacity — seem to run counter to recently stated priorities. Others, such as the rise of renewables and demise of coal, reflect Biden policies that Trump is trying to reverse.

Changes in annual metrics projected from 2024 to 2050 include:

    • Net electricity available to the grid will jump from 4,139 billion kilowatt-hours (BkWh) to 6,045 BkWh.
    • Natural gas generation will drop from 1,901 BkWh to 1,270.
    • Nuclear generation will drop from 777 BkWh to 736.
    • Coal generation will drop from 660 BkWh to 7, with the biggest decrease — 402 BkWh to 52 — coming from 2029 to 2032.
    • Renewables will jump from 1,060 BkWh to 4,680.
    • Average end use electricity prices (in 2024 dollars) across all sectors will drop from 13 cents/kWh to 12.1 cents.
    • Electricity purchased for vehicle charging will jump from 0.06 quadrillion British thermal units (quads) to 2.68 quads, with residential users accounting for 59% of the total and commercial 41%.
    • Heating degree days will decrease 5.4% nationwide per year, and cooling degree days will increase 15.7%.
    • Energy consumption intensity will drop from 91,300 BTU/square foot to 84,900 in commercial settings and from 52,300 to 40,800 in residential settings.
    • Annual generation by major renewables will jump from 0.4 BkWh to 174 BkWh for offshore wind, 16 to 56 for geothermal, 201 to 1,791 for grid-connected solar, 242 to 273 for hydroelectric and 446 to 1,908 for onshore wind.

While the U.S. produced more crude oil and natural gas per year than any other country ever during the Biden administration, Biden also led policy changes that promoted renewables over fossil fuels.

Trump railed against this during his campaign and initiated a sharp change of course on the first day of his second term. His administration continued this narrative as it commented on the AEO.

DOE spokesperson Andrea Woods said the report reflects Biden’s short-sighted energy policies and the disastrous path they set for the countries. It does not, she said, reflect the policies enacted by Trump.

The department, she said, is working now to advance coal, natural gas and nuclear energy to promote affordable, reliable and secure energy and build U.S. energy dominance.

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DC Circuit Rejects Entergy Attempt to Save MISO Capacity Obligation Rule

The D.C. Circuit Court of Appeals has denied Entergy’s repeat attempt to revive a 50% minimum capacity obligation rule for MISO’s load-serving entities.

The court concluded in an April 15 decision that Entergy lacked standing to request the discarded rule be implemented (22-1334). The minimum capacity obligation would have required MISO load-serving entities to demonstrate they obtained at least 50% of the capacity required to serve peak load obligations ahead of and without the assistance of MISO’s capacity auctions.

“Even if we were to consider the standing arguments Entergy now belatedly advances, the company has not demonstrated the necessary concrete, imminent and redressable injury,” the court decided.

The case dates to MISO’s successful bid to create seasonal capacity auctions paired with availability-based resource accreditations.

FERC in 2022 allowed MISO to conduct four seasonal capacity auctions and apply a seasonal accreditation mostly based on a thermal generating unit’s past performance during tight system conditions. However, the commission blocked MISO’s companion proposal to institute a minimum capacity obligation (ER22-496). (See FERC Again Rejects MISO Minimum Capacity Obligation.)

At the time, MISO reasoned that such a rule would keep suppliers from relying too heavily on its capacity auction to serve their customers’ needs. The RTO thought it would encourage proactive bilateral contracting and better maintain resource adequacy.

But FERC said MISO did not fully contemplate how the proposal could give its largest utilities too much market power. The commission rejected the rule a second time on rehearing requests from MISO and Entergy’s operating companies. Entergy took its challenge to the D.C. Circuit Court. (See Entergy Seeks Review of FERC’s Block on MISO Capacity Obligation.) The D.C. Circuit said Entergy’s opening brief lacked argument, analysis and evidence to support its standing in the case.

“The words ‘standing,’ ‘injury,’ ‘traceability’ and ‘redressability’ do not appear in the document,” the court noted. It said it wasn’t until a reply brief that Entergy argued its basis for standing was “apparent.” However, the court said, “no reasonable reader … would walk away with a clear understanding of petitioners’ precise injuries, the chain of causation and how a decision of this court could redress those harms.” The court said it would not “repackage merits arguments as support for a petitioner’s standing.”

Entergy argued that a refusal of the minimum capacity obligation would lead to future grid risks and free ridership by other MISO utilities on the back of Entergy’s investments. The company complained that MISO’s auction clearing prices are too low to recover its generation investments. It said requiring utilities to secure at least 50% of their needed capacity outside the auctions would mean it would be able to recoup costs through more contracts with other MISO market participants.

The court disagreed that Entergy’s standing was self-evident and said its injuries weren’t apparent or traceable. It also didn’t accept Entergy’s explanation that it omitted its reasoning for standing due to a “clerical oversight.” Judges said they saw “no basis for excusing Entergy’s noncompliance.”

The court concluded Entergy failed to submit any proof outlining how it would be harmed financially by heightened reliability risks under the status quo and, conversely, spared from them had FERC accepted the minimum capacity obligation rule. The court said even descriptions of the reliability crisis weren’t uniform in the case record, with some sections referencing an “immediate concern” while other parts called it a nonissue and said it “could result” in an “impact on reliability … over the next decade.”

Lastly, the D.C. Circuit said a complex sequence of hypothetical events must unfold before Entergy’s claims of injury from future free ridership make sense. It said other utilities would have to turn to Entergy for bilateral contracts and negotiate deals containing higher prices to compensate Entergy for its capital expenses.

“Entergy wholly fails to articulate how this chain of events would occur,” the court said, also noting that Entergy’s only evidence of more future contracts was a citation to the Independent Market Monitor’s concern that Entergy, as a pivotal MISO supplier, would be able to use a minimum capacity obligation to charge “anticompetitive” prices to other utilities.

“Implicitly, then, Entergy’s causal chain rests on an exercise of market power — a fact which Entergy repeatedly and strenuously rejects. Entergy cannot credit the market power objections for standing purposes but disavow them on the merits,” the D.C. Circuit said.

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NYISO Announces 2 New Board Members

NYISO has appointed two new members to its Board of Directors, Chair Joseph Oates announced at the board’s meeting with the Management Committee on April 15.

Heather Rivard will join the board in July following her retirement from Southern California Edison, where she has served as senior vice president of transmission and distribution since September 2021. Prior to that she worked for DTE Energy for 28 years, climbing the ladder there until she was senior vice president of electric distribution.

Steve Doyon, who joined the board effective that day, was most recently the president and CEO of Onward Energy, an independent power producer in Denver that operates and manages over 6 GW of wind, solar and gas generation. He has worked in the energy industry for nearly 40 years at several companies, including DTE, Cogentrix Energy, AES and Terra-Gen Power.

“The board is very excited to have the two of them joining us,” Oates said. “And we look forward to engaging with them on the evolving energy issues we face here in New York.”

Oates and Director Gizman Abbas were reelected to the board, while Director David Hill was elected vice chair. Director Mark Lynch will chair the board’s Audit and Compliance Committee for another year, while Director Michael Crowe was assigned the chair of the Commerce and Compensation Committee. Abbas was made chair of the MC’s Liaison Subcommittee. Sally Talberg will chair the Reliability and Markets Committee.

Oates also briefly acknowledged that FERC had approved the ISO’s proposal for collecting import duties on electricity, if the Trump administration determines the president’s tariffs on Canada apply to it. (See FERC Authorizes NYISO, ISO-NE to Collect Tariffs on Electricity.)

A stakeholder asked the ISO whether there was any financial impact from the tariff levied by Ontario on its electricity exports for the short period it was in place and whether it factored into FERC’s ruling. Oates said he could not say.

“We sort of just found out this morning that FERC approved our tariff filing,” Oates said. “We’ll take that back and at the next appropriate working group or committee of the ISO, we’ll report back.”

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Md. Consumer Advocate Seeks Price Cut in PJM 2024 Capacity Auction

The Maryland Office of People’s Counsel has filed a complaint against PJM alleging the rules used in the 2025/26 Base Residual Auction would require consumers to pay twice for capacity provided by generators operating on reliability-must-run agreements.

The auction conducted in July 2024 resulted in a nearly 10-fold increase in capacity prices. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

“PJM ran a flawed auction resulting in prices that — unless corrected — will cost Maryland residential electric customers hundreds of dollars per year in unreasonable and unnecessary capacity costs,” People’s Counsel David Lapp said in an announcement of the complaint April 14. “We are asking FERC to undo those unjust results and direct PJM to reset the prices for the 2024 auction by correcting the same flawed rules that FERC has already accepted the need to fix for future auctions.”

Pointing to a Synapse Energy Economics report commissioned by the OPC, the complaint said excluding RMR units from the supply stack would inflate costs by more than $5 billion. That report found that the 2025/26 BRA design would increase monthly costs by as much as 24% for some Maryland ratepayers. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

OPC also contends the auction allowed market manipulation, improperly exempted 1,600 MW of generation from being required to submit offers and produced prices incapable of incentivizing new entry because of the confluence of long development timelines and a compressed auction schedule. It notes the auction was conducted within a year of the start of the corresponding delivery year on June 1.

“The [FERC] and the courts have made clear that high prices are unjust and unreasonable if they do not reflect market fundamentals or cannot induce a market response. The 2025/2026 BRA results fall short on both grounds,” the complaint says.

The complaint argues that revising the auction results would not violate the filed rate doctrine as they are “intended to govern future performance” that has yet to begin. It pointed to a 2021 remand from the D.C. Circuit Court of Appeals directing FERC to reopen an investigation into MISO’s 2015/16 capacity auction, which set a $150/MW-day clearing price in its Zone 4. (See FERC to Take 2nd Look at 2015 MISO Capacity Auction.)

The complaint effectively would expedite implementation of a change the commission approved in February, granting a PJM request to model the output of RMR units as capacity as long as the resources could meet certain criteria, including being available to RTO dispatchers when called upon.

The proposal is set to go into effect for the 2026/27 and 2027/28 delivery years, with PJM intending to develop a long-term solution with stakeholders. Comments on the docket centered around two Talen Energy resources: the 1,289-MW Brandon Shores coal-fired generator and 843-MW H.A. Wagner oil-fired plant. Both facilities are located near Baltimore and are slated to deactivate after operating on RMR agreements through Dec. 31, 2028 (ER25-682, ER24-1787, ER24-1790). (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

“The 2024 auction results ignore the significant ratepayer-funded reliability contributions of the Brandon Shores and Wagner plants — with devastating consequences to customers from the resulting extraordinarily higher capacity market costs,” Lapp said. “The Federal Power Act prohibits requiring captive utility customers to pay twice for the same service.”

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GCPA Conference Examines the Biggest Change to ERCOT Market in 15 Years

HOUSTON — ERCOT this December will begin implementing a market design change that has been debated for more than a decade, experts said at the Gulf Coast Power Association’s Annual Spring Conference on April 14.

The real-time co-optimization (RTC) of energy and ancillary services means that ERCOT’s security-constrained economic dispatch will solve for both at the same time. Vice President of Commercial Operations Keith Collins said it could save billions of dollars a year in operating the grid, with a study finding RTC plus batteries (RTC+B) could save between $2.5 billion and $6.4 billion annually.

“Ultimately, there’s a lot of benefit this is going to derive to the market, to the ratepayers and consumers,” Collins said. “And you see that this is something that, while it’s been in the works for a long time, we are essentially at the dawn of the RTC location.”

The big difference in the potential benefits has to do with the years the market change was “back cast” for testing, which included the summer of 2023, when conditions in ERCOT were tight and prices were high, Collins said.

R Street Senior Fellow Beth Garza was a big supporter of the move when she was ERCOT’s Independent Market Monitor, saying she got the grid operator and the Texas Public Utility Commission on board with the market change in 2018. The biggest change since that time has been the growth of storage, with 11 GW now competing in the markets.

“This idea of ‘RTC plus B,’ in my mind, has become ‘RTC because of B,’” Garza said. “For storage to be able to easily move into and out of providing energy versus capacity for ancillary services needed something different. And here it is.”

The change will save money by dispatching a plant that had reserved some capacity for ancillary services in the energy market and then shifting the ancillary service to a more expensive plant, lowering the overall cost of power, according to ERCOT.

“We are getting more expensive ancillary services,” ERCOT Principal of Market Design and Development Dave Maggio said. “So that can be a question of, is that necessarily a good thing? And the answer in this case is, yes, it is worth getting more expensive ancillary services because of the overall decreasing energy price.”

The change also comes with a new offer cap in the energy markets, at just $2,000/MWh, down from the current $5,000/MWh. Prices can still go above $2,000/MWh, but as in the FERC-regulated markets, that will only happen when the market is running short. Scarcity pricing will be handled through the “ancillary services demand curve,” which will replace the operating reserves demand curve (ORDC), Maggio said.

While RTC is set to go live Dec. 5, ERCOT is going to be spending the next seven months getting ready for it with market trials starting May 5, and a market notice explaining them is due soon, said Matt Mereness, the grid operator’s senior director of market operations and implementation.

The training will involve weekly calls with market participants and, starting in September, trial runs of the new market design that will cover the morning ramps, Mereness said. ERCOT ran similar tests 15 years ago when it transitioned to a nodal design from zonal.

“Who was here for the nodal go-live 15 years ago?” Mereness asked the audience. “Now raise your hand if you did that. Well, the good news is it’s not that big, but this is still the biggest paradigm shift we’ve had in 15 years.”

The move to RTC is going to mean more efficient energy and ancillary services markets, which means that to drive more resource investments, the market will need to have more scarcity events that drive prices high and send price signals for investments, said NRG Senior Director of Regulatory Affairs Bill Barnes.

“We are becoming more dependent on the demand curve for price elevation,” Barnes said. “I think that’s a good thing. … When we first started, there wasn’t an ORDC. We were solely dependent on submitting high offers. As we’ve evolved over the past 20 years, we’ve moved more towards a demand curve approach, which to me more aligns the price formation with the actual fundamentals of the market, versus one participant deciding to submit the price of the cap on a random day, which can be not a good thing.”

While the move to RTC+B will influence price formation in ERCOT’s markets, consultant Eric Goff said generation investments in the near future are going to be driven by large loads like data centers coming to Texas.

“The reason, among others, that large loads are attracted here is because you can transact in this market,” Goff said. “You can get what you want without having to ask for too much permission, and if those large loads contribute to higher prices because of their demand, which they have been, in the long run, then you get to a price that reflects the cost of entry.”

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FERC Authorizes NYISO, ISO-NE to Collect Tariffs on Electricity

FERC on April 14 approved filings by NYISO and ISO-NE authorizing them to collect tariffs on electricity imports from Canada, if the “relevant federal authorities” deem them responsible for doing so (ER25-1462, ER25-1445).

The grid operators have said President Donald Trump’s tariffs on energy imports do not appear to apply to electricity. However, to prevent potential financial consequences, both saw the need to establish a framework for collecting them.

The commission accepted both grid operators’ proposed open access transmission tariff revisions for allocating Trump’s tariffs. NYISO proposed to charge the “financially responsible party,” while ISO-NE proposed to charge “the entities selling the assessed electricity into the ISO-administered market.” (See ISO-NE Braces for Tariffs on Canadian Electricity and NYISO Preparing to Collect Duties on Canadian Electricity Imports.)

Both grid operators wrote that their cost collection methods would allow importers to include the costs of the duties in market offers. The mechanisms could change if the federal government gives clear instructions to them to collect the tariffs differently. ISO-NE included in its proposal a provision allowing it to collect the duties “in accordance with any federal regulations or guidance,” while FERC directed NYISO to add a similar provision in an additional filing.

FERC emphasized that it makes “no finding regarding whether import duties imposed pursuant to the Canadian tariff executive order apply to Canadian electricity or whether [the grid operators are] required to pay them,” and similarly declined to rule on whether it is legal to apply the import duties to electricity.

Because of the “exigent circumstances present,” FERC directed both grid operators to file “any legal and/or technical guidance and related documentation from the relevant federal authorities showing that a federal agency has assessed an import duty on Canadian electricity imports” that triggers the grid operator’s collection authority, “as soon as practicable after receiving such invoice.”

If they do start collecting the tariffs, the grid operators must provide informational filings to FERC every six months for three years about the costs of the duties.

ISO-NE’s proposal is intended to be a temporary mechanism; if the RTO anticipates tariffs lasting longer than 120 days, it must file a permanent cost collection method within 120 days of the first import duty invoice.

ISO-NE responded: “We still believe the tariffs do not apply to electricity, and that if they do, ISO-NE would not be the entity responsible for implementing them. There is a lot of uncertainty around the situation, and the proposal is a proactive move covering one possible outcome.” They also published a press release, saying ” the ISO is committed to maintaining ongoing dialogue with our stakeholders, state officials, and the federal government.”

NYISO said it had no further comments.

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Report Estimates Billions in Savings from More Interregional Transmission

The authors of a new report released April 4 say better market integration and reduced interregional constraints in the U.S. transmission network would have saved as much as $12 billion in 2022 and 2023.

They note the importance of achieving better grid integration in an era when increasing amounts of renewable generation is coming online but flag the difficulty of achieving it, given the financial incentive existing generators have to delay or block such integration.

The working paper, “Power Flows, Part 2: Transmission Lowers US Generation Costs, But Generator Incentives Are Not Aligned,” was written by Dasom Ham, Owen Kay and Catherine Hausman as part of Resources for the Future’s Obstacles to Energy Infrastructure research project.

They write that geographic constraints and mismatched supply and demand are growing as intermittent wind and solar capacity come online, often far removed from high-demand areas.

Better integration of electricity markets could allow systemwide cost savings and therefore lower consumer costs, the paper says. Integration of existing supply across regions could have saved $5.8 billion to $7.1 billion under 2022 conditions (which included higher natural gas prices) and $3.4 billion to $5 billion under 2023 conditions.

Other savings that could be created by intraregional integration were not estimated, nor does the report offer a full cost-benefit analysis of building new transmission or look at the cost versus societal benefit of building renewables.

But such integration would also create winners and losers, as existing generators in high-demand markets see their net profits drop and renewables in high-supply markets avoid curtailment.

The structure and processes of markets give those incumbents many opportunities to delay or block transmission construction projects that would run counter to their interests, and the report highlights case studies in multiple regions where they appear to have done just that.

This opposition can be hidden within workings of RTOs or it can be publicly visible, such as NextEra Energy’s long-running but unsuccessful fight to thwart Avangrid’s construction of the New England Clean Energy Connect, which will bring up to 1.2 GW of cheap Canadian hydropower to a region where NextEra operates multiple power plants.

The analysis showed these dynamics vary substantially by region: Greater market integration would benefit existing power producers in the Great Lakes, Great Plains and Rocky Mountain regions but hurt producers in the Northeast and Southeast.

The barriers to siting, planning, permitting and construction of transmission are well known, and include cost allocation, land rights and environmental clearance. Importantly, transmission planning and changes to market structure for interregional electricity trade depends largely on the consensus of incumbent generation companies, who hold greater sway than stakeholders who would see cost savings.

Investment patterns in recent years show the result of these dynamics: Only 2% of new circuit miles installed from 2011 to 2020 were for interregional transmission lines, and the majority of all transmission investments were for local reliability concerns rather than generation cost savings.

The new report builds on “Power Flows: Transmission Lines, Allocative Efficiency and Corporate Profits,” a working paper written by Hausman and issued by the National Bureau of Economic Research in January 2024.

The earlier report focused on the MISO and SPP regions, but the new report looks at the entire continental U.S. The dynamics are similar and can be generalized, but MISO and SPP do have some distinctive features, and there were some limitations in extending the research design to the rest of the country.

Data was obtained primarily from the Energy Information Administration and EPA’s Continuous Emissions Monitors Systems datasets.

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PJM CEO Manu Asthana Announces Year-end Resignation

PJM CEO Manu Asthana on April 14 said he will resign from his position at the end of 2025 after more than five years of leading the RTO.

“My five-plus years at the helm of PJM have been some of the most fulfilling of my career,” Asthana said in a statement. “I am especially appreciative of the opportunity to have led PJM’s remarkably talented, diligent and committed people, who work hard every day to keep the power flowing for 67 million people.

“The time has now come for my wife and me to move back to be closer to our family and friends in Texas. I look forward to continuing to lead the organization through the end of the year and to helping facilitate an orderly transition to my successor.”

Asthana relocated to Pennsylvania when he took over as the head of PJM on Jan. 1, 2020, in the wake of the GreenHat Energy default, which led to the resignation of several PJM executives. (See PJM Taps Ex-Direct Energy Exec as New CEO.)

Mark Takahashi, chair of the PJM Board of Managers, said Asthana guided the RTO through several significant changes, including the shift to studying interconnection requests with a cluster-based approach and an overhaul of capacity market rules following Winter Storm Elliott in December 2022. (See FERC Approves 1st PJM Proposal out of CIFP.)

“The PJM board is grateful to Manu for his strong leadership during a time of tremendous change in the electricity industry,” Takahashi said in a statement. “Under his leadership, PJM successfully navigated the COVID-19 pandemic, significant market reforms, interconnection process enhancements, the buildout of a robust risk management function and the delivery of world-class grid reliability through a variety of extreme weather events.”

Takahashi said Asthana has worked with the board to develop “PJM’s internal succession pipeline.”

“We have a strong executive team, including internal succession candidates. We will also consider external candidates for this role,” Takahashi said.

The board has formed a search committee to identify a replacement in the next year. That process will be aided by consulting firm Korn Ferry with input from the RTO’s membership and stakeholders. Asthana is set to stay on as a senior adviser until June 2026.

Electric Power Supply Association CEO Todd Snitchler said Asthana led PJM through a time of rapid change.

“We have appreciated working with him and his willingness to listen to the input of the generator community as he navigated how to deliver reliable power while addressing the challenges posed by varying state and federal policy preferences; a rapid rise in energy demand; and external factors like supply chain hurdles and onerous permitting policies that impede infrastructure development,” Snitchler said.

He said EPSA hopes to see PJM continue to address planning and interconnection queue issues, and “strongly support” a market that balances input from stakeholders and market participants and “provides reasonable certainty and a fair opportunity for a return on investment for resource developers.”

Glen Thomas, president of GT Power Group, said “leading PJM is a challenging job, and Manu led PJM through some very challenging times, from COVID to the data center demand boom. He remained calm, accessible and diligent no matter what the challenge. We look forward to working with PJM to find a successor that can lead PJM to meet its mission to deliver reliability through markets.”

D.C. Public Service Commission Chair Emile Thompson, current president of the Organization of PJM States Inc. (OPSI), pointed to several capacity market changes PJM pursued in recent months that consumer advocates have argued would ward off inappropriately high prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)

“CEO Asthana has been a tremendous partner to work with during my tenure as the president of OPSI,” he said. “Together, we worked to implement a number of reforms in response to the most recent Base Residual Auction. I look forward to continuing to work with him through the remainder of his tenure as we tackle issues such as resource adequacy, sub-annual capacity markets, transmission planning and issues surrounding co-location.”

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SEEM Members File Market Agreement Update

Alabama Power, on behalf of other members of the Southeast Energy Exchange Market (SEEM), has submitted a FERC-ordered filing detailing changes to the market’s agreement intended to comply with a March 14 order from the commission (ER21-1111).

The proposed changes to the agreement detail the ability of utilities to participate in SEEM via pseudo-ties, which are used to represent interconnections between two balancing authorities where no physical connection exists between the load or generation and the power system network. SEEM members proposed the changes take effect April 15.

FERC directed SEEM to update the agreement after members argued in an earlier filing that pseudo-ties offered a means for loads and resources outside the SEEM territory to participate in the market. (See SEEM Members Respond to FERC Briefing Request.) This claim came in response to the commission’s request for briefings after an order from the D.C. Circuit Court of Appeals remanded the commission’s approval of the market in 2021.

One of FERC’s questions concerned whether entities with a source or sink outside SEEM’s territory could meet the technical requirements of the market’s matching platform. SEEM’s supporters have argued the territorial requirement was needed to implement the market platform that matches excess supply with free transmission every 15 minutes. But the court claimed the limitation resembled “discriminatory practices against third-party competitors by monopoly utilities.” (See DC Circuit Sends SEEM Back to FERC.)

FERC’s March 14 order acknowledged “an external source or sink could be a participant in SEEM if it used a pseudo-tie,” but observed that such a practice would significantly affect “rates, terms or conditions of service” to such an extent that it should be included in the market agreement rather than a business practice manual. In their response, SEEM members agreed “there is not a SEEM entity that … would have the authority to evaluate and approve or reject creation of a pseudo-tie” under the current market agreement.

To address this, members proposed amending the agreement in several places. First, the new agreement adds the words “including through the use of a pseudo-tie” to language in the market rules that says a participant must own or control a source, and/or “be contractually obligated to serve a sink,” within the SEEM territory. A new footnote in the same section specifies that a prospective participant seeking to establish a pseudo-tie must coordinate with relevant BAs, transmission providers and reliability coordinators, along with the SEEM Operating Committee.

Members said that “a pseudo-tied resource or load, once established, would appear no differently from any other resource or load registered as a valid source or sink” participating in SEEM.

A change to Article 5 would establish the Operating Committee’s obligation to coordinate with efforts to participate via pseudo-tie. The language of the new section 5.11 requires the committee not to reject a pseudo-tie that has been accepted by the relevant TP, BAs and RCs.

Similar language is found in proposed changes to section 3.4, adding that TPs “shall have a duty to coordinate and act in good faith in interactions with any prospective participant … utilizing a pseudo-tie,” and with all relevant BAs and RCs. Such good-faith interaction must include transparency about the reason for any denial of participation.

The updates also added definitions of the terms “pseudo-tie” and “reliability coordinator” to be consistent with definitions in the SEEM market rules.

“These changes appropriately commit SEEM to working with potential participants on pseudo-ties, including coordinating with the other identified entities necessary to the establishment of any such pseudo-tie,” members said.