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April 25, 2025

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2 More Projects Fall out of TEF Loan Program

The troubled Texas Energy Fund has lost two more projects from its original list of applicants, raising questions about its ability to quickly add 10 GW of gas-fired dispatchable resources to the ERCOT grid.

Connie Corona, executive director of the Texas Public Utility Commission, said in identical filings April 15 that both applicants had “failed to meet due diligence requirements.” The orders are not subject to rehearing or appeal requests, she said (56896).

The loss of the two gas-fired projects from the list of applicants takes another 1,056 MW out of the TEF’s In-ERCOT portfolio. The 14 remaining applications total 7,284 MW of capacity and about $3.96 billion in requested loans, a PUC spokesperson said.

One of the projects belonged to EmberClear and Jupiter Island Capital, which proposed two 900-MW projects west of Houston. The other was proposed by Frontier Group of Companies for the Lone Star Industrial Park in East Texas, comprising two gas units with 162 MW of capacity. A 40-MW natural gas unit, commissioned in 1954 and once operated by Southwestern Public Service, sits in the park.

Four other companies have also withdrawn projects since 2025 began. (See Texas Loan Program Loses 2 More Gas Projects.)

Stoic Energy’s Doug Lewin said the TEF’s travails only emphasize the need for renewable energy and storage. He said that given ERCOT’s current projections of 44 GW of demand growth in the next four years (“As their midline,” he noted), Texas still will be 34 GW short even if the fund meets its 10-GW goal.

“It’s going to be even harder to meet rising demand without robust renewable and storage growth. There’s just no other resource else that can be developed that quickly,” he told RTO Insider.

More than 5,712 MW of capacity has been withdrawn or denied from the original submitted applications. More than 40% of the projects (4,965 of 12,249 MW) advanced to due diligence now have been withdrawn or denied.

The PUC has said staff intend to advance additional applications to due diligence review at a future open meeting. The commission next meets April 24.

George Castellanos, chief power officer for Frontier, said the New York-based firm was disappointed with the decision but praised the TEF’s review process.

“We remain confident in the strategic value of our project to support Texas’ long-term reliability goals,” he said in an email to RTO Insider.

Castellanos said the firm plans to continue the industrial park’s development. That includes reactivating the gas unit on site and adding another 114 MW of new capacity.

The state legislature created the TEF in 2023 to add more dispatchable generation to the grid. Voters approved it later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state.

The fund comprises four programs: In-ERCOT Generation Loans, In-ERCOT Completion Bonus Grants, Outside-ERCOT Grants and the Texas Backup Power Package.

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N.J., Md. Officials Target PJM After Critical Report

A D.C.-based environmental group argues electricity prices will rise by 60% in the PJM region if the RTO does not reform its permitting system to allow more clean energy. 

The Evergreen Collaborative and consultant Synapse Energy Economics of Massachusetts released a report April 15 that predicts a 60% hike in residential bills will be reached by 2036 to 2040 if PJM continues on its current path. Residential rates could decline by 7% over the same period if PJM adopts interconnection reforms, such as accelerating the timeline by which new clean energy sources are approved, providing cheaper energy, the report claims. 

“With swift action to resolve the interconnection queue, it can reduce electricity prices while bringing on new resources to power new demand and enable economic growth,” the report says. Evergreen Collaborative, founded in 2020 by supporters and staffers of former Washington state Gov. Jay Inslee (D), aims to create an “all-out national mobilization to defeat the climate crisis and create millions of jobs in a clean energy economy.” 

The report drew vigorous support from Maryland and New Jersey officials. New Jersey ratepayers will experience a 20% hike in the average bill June 1 due to the basic services generation auction in February. 

State officials say that auction was shaped by record-high prices in the PJM capacity auction in July 2024. An imbalance of supply and demand was the result of several factors: a surge in expected demand due to AI data center developments; limited supply due to the RTO’s slow rate of approval for new clean energy sources; and the faster pace at which fossil fueled generators are closing. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

The sudden price hike and expected supply shortfall have triggered heated words from New Jersey officials, who say PJM failed to anticipate the demand increase. The RTO says the shift was so sudden it couldn’t have been anticipated. (See NJ Lawmakers Sound Energy Supply Alarm.) 

PJM, responding to the Evergreen report, said it has taken “multiple actions, working with stakeholders, to make as much generation capacity available to the grid as quickly as possible.” (See PJM Board Initiates Fast-track Process to Address Reliability.) 

“PJM has already established an expedited process, which recently cleared 18 GW to finalize agreements to interconnect to the grid,” the RTO said in a statement released by spokesperson Jeffrey Shields. “We have about 66 GW of active projects that we will complete in 2025 and 2026 as part of the reform transition period.” 

Leaving PJM

Representatives of New Jersey and Maryland, who took part in a press conference marking the release of the report, titled “Tackling the PJM Electricity Cost Crisis,” said the RTO needs to do a lot more, or see participating states look for alternative energy sources. 

“We’re at a fork in a road. We can’t afford for PJM to continue down the same path,” said Eric Miller, executive director of New Jersey Gov. Phil Murphy’s Office of Climate Action and the Green Economy. “My office is calling on PJM to clear the queue as quickly as possible, adopt reforms that make interconnection timelines more predictable and leverage next generation grid-enhancing technologies.” 

Paul G. Pinsky, director of the Maryland Energy Administration, called PJM “one of the largest obstacles” to the state’s efforts to reach 100% clean energy and “reduce soaring energy bills.” 

“I’m not here to say we’re going to pull out of PJM,” Pinsky said. “PJM is an RTO of importance. But it’s trailing a lot of the other organizations around the country in how quickly they can bring online new energy, and, in our belief, clean energy. So we want to bring as much pressure to bear.” 

New Jersey state Sen. Andrew Zwicker (D) said the reality laid out in the report is that “PJM is sitting on hundreds upon hundreds of renewable and affordable energy projects that, in the end, would lower the bill for New Jersey families and families across the PJM area.” 

Asked by a reporter if he considers the situation so bad that New Jersey and Maryland should consider leaving the RTO, Zwicker said “everything’s on the table right now.” 

“New Jersey doesn’t plan to be rash about this, and we have to do a very careful analysis of what the impact would be on New Jersey ratepayers,” he said. “But it has to be part of the discussion at this point, that’s for certain.”    

Rate Counsel Complaint

New Jersey officials say the high cost of power from PJM stemmed in part from “flawed” modeling by the RTO in the run-up to the July 2024 auction. There was a failure to properly include all the clean capacity expected to come online, they say, leading bidders to think there was less new capacity in the pipeline than in reality. 

The New Jersey Division of Rate Counsel and the Maryland Office of People’s Counsel on April 14 filed a complaint with FERC, arguing PJM’s auction produced “demonstrably unjust and unreasonable outcomes that the commission must now remedy.” 

The complaint alleged that “defective market rules either ignored or allowed market participants to withhold thousands of megawatts of existing capacity, while interconnection delays, a compressed auction forward period, and other entry barriers prevented the participation of new supply capable of disciplining incumbent market power.” 

The complaint demands that PJM redo the 2024 capacity auction, changing the rates for energy not yet delivered and fixing the defects in the process for the next auction. “What is at stake is an enormous and unlawful transfer of wealth from customers to owners of capacity resources: at least $4 [billion to $]5 billion in excess charges resulting from the subset of artificial supply constraints” in the auction, the complaint argues. 

System Reforms

Looking to the future, the Evergreen Collaborative report calculates the average residential household costs under the “status quo,” with the RTO operating as at present, and with the queue reforms suggested in the report implemented. The report does so for seven states and Washington, D.C. 

Under these scenarios, the average annual New Jersey residential bill would be $2,003 if the status quo continues, falling to $1,598 if the suggested reforms are adopted. The average Maryland bill would be $2,358 in the status quo and $1,813 with the reforms, according to the report. The average residential household cost across PJM would be just under $3,000 in the status quo over the period, and $1,062 less with reform implementation, the report says.  

The reforms suggested by Evergreen include:  

    • Requiring PJM to approve projects within a 150-day timeline. A Synapse Energy Economics consultant said this timeline is required by FERC under its Order 2023. But PJM is asking FERC for approval for a timeline of one to two years.
    • Implementing the first-ready, first-served cluster study approach on time for the regular-order queue.
    • Using realistic modeling assumptions for energy storage behavior rather than assuming energy storage will charge during peak periods and require associated transmission upgrades.
    • Studying grid enhancing technologies as part of transmission planning.
    • Making it easier for developers to use interconnection agreements held by existing power plants and continue to use them after the existing plants retire.

     
    PJM, noting that it began “significant interconnection process reform in July 2023,” said it since has “relieved the interconnection backlog by 60% and placed more than 6 GW of new generation into service.”

    PJM suggested the high auction bids confirmed its analysis that “the supply/demand balance has been tightening.” And the RTO added that it “will fully comply with Order 2023 but [has] also petitioned FERC to allow [it] to fit the order to PJM’s already approved and implemented rules.” 

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MISO Forming 4th Tx Planning Scenario Based on Supply Chain Barriers

MISO is on its way to installing a fourth, 20-year future to inform transmission planning in case supply chains remain unsteady.

During an April 14 teleconference to develop MISO’s first new planning future in six years, RTO staff said they are approximating annual build limitations on new capacity. They also said the Trump administration’s tariff decisions could introduce further instability that makes the fourth scenario more difficult to pin down.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said the RTO sees “fairly impactful constraints” on all types of generation into the future.

The RTO is revising its trio of 20-year futures scenarios that it relies on to plan transmission. It has said it must incorporate aggressive load growth and create a fourth scenario specifically designed to study the footprint if fraught supply chains continue to impede new generation construction. (See MISO Aims for 4 New Tx Planning Futures in 9 Months and MISO Fields Divergent Calls for Stronger South Planning, IRA Reversal in Tx Futures.)

MISO has tentatively called the new scenario its “Supply Shift” future. It would contemplate continued “supply frictions” that limit the pace of capacity expansion. MISO envisions that load growth might have to be managed through keeping existing generation online and establishing more demand-side resources.

MISO created its current trio of futures in 2019 and last updated them in 2022. A decade ago, the grid operator used as many as 10 different futures to plan long-range transmission.

DL Oates, MISO executive director of markets and grid research, said the RTO is calculating annual capacity build limits by resource type for its fourth future through an assessment of U.S. manufacturing capability, labor constraints and tariff impacts. It multiplied the limits it found by its share of U.S. installed capacity.

“Preliminary results reveal some tension between member-submitted planned units and projected regional supply constraints,” Director of Economic and Policy Planning Christina Drake told stakeholders.

MISO acknowledged that President Donald Trump’s tariffs could add hurdles for generation and said it wants to adopt a wait-and-see approach on whether they have a material impact on generation expansion.

“What we would like to do is let this information settle,” Drake said.

Oates said MISO put its initial assessment together when the country-specific tariff rates were “volatile.”

“This is a shifting situation with these tariffs, so you’ll have to give us a little leeway to figure out what makes the most sense,” Oates said.

MISO does not plan to apply an age-based retirements assumption on its existing fleet for the supply-squeezed future. The RTO would assume some retirement delay announcements.

The Sustainable FERC Project’s Natalie McIntire said it did not seem realistic for MISO to forgo any age-based retirements. She asked it to maintain the same retirement assumptions it applies to the fleet in its three other futures.

“It doesn’t make sense to me to hardwire it into the model,” McIntire said.

Oates said that if members can’t build enough new generation, they may be forced to put off retirements.

“Our working hypothesis is that we’re not going to be able to balance generation and load,” Drake said. She added that MISO will “keep an eye on” whether age-based retirements might make sense in the scenario.

Even with retirement delays, MISO envisions the future would hold a minimum of 60% in emission reductions from 2005 levels, the same as its middle-of-the-road “Stated Policy” future. That would hold unless MISO finds that throttled build rates stand in the way of reducing greenhouse gases. The RTO’s most dynamic, “Higher Load Growth” future estimates a minimum 80% reduction from 2005 emissions levels.

MISO engineer Brad Decker said an enduring labor force pinch can “be a drag” on capacity expansion, especially to stand up labor-intensive solar farms.

Decker said MISO is contemplating tariffs on solar components anywhere from 17 to 37%, not the 145% the Trump administration has publicized.

“China doesn’t really export a lot of solar to the United States. They send materials through intermediate countries,” he explained, adding that MISO would factor in those intermediate countries’ reciprocal tariffs.

Despite wind component sourcing being largely U.S.-based, recent closures of plants that produce blades have shrunk manufacturing capability, Decker said, “posing a risk to scaling wind deployment until domestic production is expanded.”

Decker said small modular reactors likely won’t be a commercial option for at least 10 years.

“A lot of things have to happen between now and then to make these viable,” Decker said. For example, he said, the nuclear industry needs to stand up a market for high-assay low-enriched uranium to fuel the new type of plants. Decker said SMR projects and demonstrations have lurched in a “stop-and-start trajectory, marked by cost overruns and project cancellations due to undersubscribed offtake agreements.”

The Union of Concerned Scientists’ Sam Gomberg said he worried that MISO was being too “rosy” on SMR emergence within a decade and that its estimates would be biased if it relied on the “shiny FAQ sheets” from nuclear developers. He said the nuclear industry has a poor track record in meeting goals and announcements when bringing new capacity online.

Decker said there is a reluctance among gas turbine manufacturers to ramp up production because they remember overcommitting production in the early 2000s. Oates noted growing order backups for General Electric, Siemens, Mitsubishi and other suppliers because of surging, AI-driven demand for firm generation.

The supply crunch future also would consider a small-scale emergence of 12-hour, long-duration battery storage from advanced lithium-ion batteries and up to 100 hours of stored energy from iron-air batteries.

MISO said it won’t factor in other emerging technologies like extended-duration batteries that can last more than 100 hours, green hydrogen, combined-cycle plants with carbon capture and sequestration, and new geothermal technologies. Those likely are too far down the road to be considered in this round of futures, staff said.

The RTO is taking stakeholders’ reactions to its resource assumptions in its fourth future through April 28. It will refine the futures through the fall before using them in 2026 to plan more long-range transmission.

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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.