Search
April 3, 2025

Posted on

MISO Feb. Real-time Prices Nearly Double from 2024

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

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

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

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

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

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

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

Posted on

Louisiana PSC Leaves Statewide Energy Efficiency Program As Is For Now

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Posted on

GCPA to Honor Kim Casey with Power Star

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

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

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

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

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

Posted on

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

Blake Lauds Winter Grid Performance

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

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

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

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

New Directors and Board Officers

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

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

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

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

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

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

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

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

Board Approves Draft Budget

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

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

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

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

Posted on

PJM Receives 94 Applications for Expedited Interconnection Process

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

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

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

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

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

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

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

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

Clean Energy Advocates Opposed to RRI

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

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

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

LS Power Announces Participation

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

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

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

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

Posted on

WEIM Experience, Reliability Benefit Drove EDAM Decision, BANC Says

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Posted on

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Posted on

ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC

ISO-NE plans to reopen its interconnection queue April 1 as it continues to wait for a ruling from FERC on its Order 2023 compliance proposal, the RTO told the NEPOOL Transmission Committee on March 26.

The queue has been closed since June 13, 2024, which was the RTO’s proposed deadline for projects to have a valid interconnection request to participate in the transition cluster study, which would be the first cluster study run under the new interconnection procedures established by Order 2023.

ISO-NE requested an effective date of Aug. 12, 2024, in its compliance proposal but suspended its work to implement the interconnection changes in September 2024 because of the lack of a ruling from FERC. (See With FERC Inaction, ISO-NE Delays Order 2023 Implementation.)

Given the uncertainty around when and how FERC will rule on ISO-NE’s compliance, the RTO now has opted to reopen the queue and will continue to process requests under the existing “first-come, first-served” study process.

Alex Rost, director of transmission services at ISO-NE, said reopening the queue will enable interconnection customers to submit requests needed to participate in the 2025 interim reconfiguration auction (RA) qualification process.

However, Rost stressed that ISO-NE “cannot guarantee the treatment of [interconnection requests] submitted after the June 13, 2024, eligibility date set by Order No. 2023 until FERC issues an order [that] addresses the eligibility date.”

Also starting on April 1, ISO-NE no longer will allow customers to pause studies that are being processed under the existing serial interconnection rules. The pause was intended to enable resources that did not expect to complete their interconnection studies prior to the transitional cluster to avoid unnecessary study costs.

“Given the indefinite delay in FERC action on the compliance proposal and continuing serial studies, the ISO can no longer allow study pauses without potentially impacting lower-queued projects,” Rost said.

ISO-NE also said it likely will not be able to run a transitional capacity network resource (CNR) group study in coordination with the 2025 interim RA qualification process.

The CNR study was intended to help projects with complete system impact studies — but without capacity interconnection rights — to participate in capacity auctions on a shorter timeline.

The RTO had said it would need an order from FERC by the end of March to align the CNR group study with the 2025 interim RA qualification process, which includes a show of interest submission deadline at the end of April. (See New England Generators Remain in Limbo on Interconnection Reform.)

ISO-NE previously aimed to run the CNR group study in coordination with its 2024 interim RA qualification process. Missing the deadline for 2025 qualification creates significant uncertainty for resources hoping to join the study and could result in the elimination or significant delay of the CNR group study.

In recent months, stakeholders urged FERC to rule on ISO-NE’s compliance proposal as quickly as possible.

Flatiron Energy wrote in February that missing the end-of-March deadline “increases the chances that further process changes are necessary and thereby increases the chances that the transitional CNR group study and transitional cluster study are delayed.”

Delays to the CNR study and transitional cluster study would threaten the ability of resources in the queue to come online for the 2028/29 capacity commitment period (CCP 19), Flatiron wrote.

The company estimated 3 GW of projects eligible for the CNR study are proposed to come online before the start of CCP 19.

The New England States Committee on Electricity (NESCOE) wrote in November 2024 that the delay undermines “the efficient and timely interconnection of new resources” and urged FERC to act quickly “to help alleviate the interconnection queue backlogs and uncertainty that continues to exist in New England.”

Clean energy trade associations RENEW Northeast and Advanced Energy United, the New Hampshire Office of the Consumer Advocate and several environmental advocacy groups all submitted comments echoing the concerns of Flatiron and NESCOE.

In response to ISO-NE’s announcement March 26, Alex Lawton of Advanced Energy United said that “unless FERC issues an order within the next few days, the region will face cascading delays to our desperately needed interconnection reforms, which will result in more challenges to how and when new resources can come online.”

“Given the centrality of a functional interconnection process to ensuring reliable and affordable electricity, ratepayers will ultimately bear the cost of further delays,” Lawton added.

Posted on

Fast-paced Effort will Address EDAM Congestion Revenue Issue

CAISO has launched an “expedited” initiative to address stakeholder concerns about how the Extended Day-Ahead Market (EDAM) will allocate congestion revenues when a transmission constraint in one EDAM balancing authority area causes congestion in a neighboring BAA. 

The issue came to light in February when Powerex published a paper contending that EDAM contains a “design flaw” that could subject non-CAISO market participants to $1 billion in unfair congestion-related charges that would be conveyed as payments to participants operating within the ISO. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

The problem will arise when a transmission constraint in one system “parallel” (or loop) flows on a neighboring system, the Vancouver, leaving the latter system — and its transmission users — to carry the costs of unexpected congestion, the Canada-based electricity marketer said. 

The paper argued that EDAM’s treatment of firm transmission rights and congestion would leave that market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while failing to provide the ability to recover or hedge against those costs — something the company called an “aberration” among organized electricity markets. 

Powerex, which owns transmission rights throughout the West, said the PacifiCorp, NV Energy and Idaho Power BAAs would be most exposed to the issue, including when those utilities use their own transmission to deliver their own generation to their own load.  

The company identified the issue after reviewing the revised Open Access Transmission Tariff (OATT) PacifiCorp filed with FERC in January to reflect its impending participation in EDAM, and other entities since have filed comments in that docket (ER25-951) expressing similar concerns. 

CAISO and PacifiCorp representatives initially responded sharply to Powerex’s assertions, calling the paper “misinformed and inflammatory.” But the new initiative indicates the ISO is taking the congestion issue seriously, even if it and EDAM supporters point out the issue is the byproduct of overlaying elements of an organized electricity market on the legacy OATT system.   

During a March 24 workshop to kick off stakeholder engagement for the initiative, CAISO staff presented an alternative method for calculating the allocation of certain congestion revenues under EDAM, with meeting participants raising concerns about long-term effects of the proposed method and asking for more clarity. 

CAISO outlined the proposed new method in a March 17 issue paper, which was reviewed in detail at the meeting. The alternative method would be “transitional” and would be informed by newly identified patterns of congestion as EDAM adds other balancing areas, Joanne Serina, CAISO vice president of stakeholder engagement and customer experience, said at the meeting. 

The ISO has cleared its calendar over the next two weeks to make room for the expedited initiative, Serina said. The accelerated timeline reflects CAISO’s desire to prioritize stakeholder feedback on EDAM issues, she said. 

“We are wholeheartedly committed to working with stakeholders to come to an equitable solution,” Serina said. 

CAISO could, as early as May, approve the alternative method, develop a different alternative or decide to keep the existing one. 

Question of Intent

The primary question in the initiative is whether certain congestion revenues should be allocated to the balancing area in which the congestion revenue accrued, or to the neighboring EDAM balancing area where the transmission constraint is located. 

Under existing design, the latter is true: EDAM is set to allocate congestion revenues to the BAA in which an internal transmission constraint is located. This approach has been approved by FERC and implemented for the past decade in the WEIM, and it is the practice today.   

The current congestion allocation approach follows cost-causation principles under which congestion revenues flow to the transmission constraint location. This is because the BA with the constraint must pay for and manage the constraint, CAISO said in its paper. Transmission constraints determine in part the congestion price at a pricing location, and congestion revenues then are allocated back to energy market participants, according to the paper. 

However, under the alternative design, congestion revenues associated with parallel flow schedules would be allocated to the BA where the congestion revenue accrued, not the neighboring balancing area where the constraint is located, the paper says. 

In the paper, CAISO said allocating congestion revenues to EDAM balancing areas based on where they are collected will “enable a more complete sub-allocation of congestion revenue from the EDAM balancing area to transmission customers exercising firm Open Access Transmission Tariff (OATT) transmission rights within their balancing area.”  

The alternative approach could increase or decrease the total congestion revenue available for sub-allocation to a balancing area, CAISO wrote. The EDAM area is not managed as a single balancing area or under one transmission tariff, so CAISO must determine what amount of congestion revenue is to be allocated to each EDAM balancing area, according to the paper. A balancing area then allocates revenues based on their specific tariffs. 

CAISO at the March 24 meeting responded to numerous questions and concerns about the alternative design. Many participants asked for clarification on the methodology and examples in the issue paper, while others looked for more information on potential impacts on the power system and suppliers. 

“What do you mean when you say, ‘Managing a constraint in an area’?” PacifiCorp commercial transmission manager Rohan Chatterjee asked at the meeting. 

CAISO regional markets sector manager Milos Bosanac responded: “Depending on the nature of the constraint, there may be additional steps that the balancing area may need to take. Predominantly, there will be dispatch effects associated with a constraint.” 

Jeff Spires, Powerex’s director of power, said his company is concerned that an alternative option would be transitional without agreement on the “guiding principles” around the future evolution of the markets. 

“I agree [with] letting the markets evolve … but at the same time, I would expect the opportunity to determine what principles are needed to provide that long-term confidence. Until we get to a full RTO world, these markets need to be compatible with that framework.” 

Speaking at a March 25 meeting of the Western Energy Markets (WEM) Governing Body, member Anita Decker said she recognized there would be “bumps in the road” with the rollout of EDAM. 

“But I think the important thing here is the intent, and the intent is to end up with a strong market, at the end of the day, for everyone that’s participating — and I think that intent really goes a long way to build confidence,” Decker said. 

“I just want to reinforce our commitment to making this transition from traditional OATT to a marketplace as smooth as possible, and that’s why I think we’re taking up this initiative and trying to find that path forward,” CAISO COO Mark Rothleder said at the WEM meeting.  

Stakeholder comments on the initiative are due by April 7. CAISO plans to publish a full proposal April 14, with the final proposal presented for decision by the ISO Board of Governors and WEM Governing Body at their May 20-22 meetings.  

Posted on

Vote on NYISO Firm Fuel Capacity Accreditation Tariff Language Delayed

NYISO on March 26 unexpectedly pulled a vote on modeling improvements for capacity accreditation from the Management Committee’s agenda, delaying further discussion until April 9.

Shaun Johnson, NYISO vice president of market structures, told the committee the ISO wanted more time to incorporate stakeholder feedback into the proposed tariff language.

“Unfortunately we’ve been entertaining and modifying the tariff up until yesterday,” Johnson said. “And we received feedback from stakeholders that’s really inappropriate for the MC. I completely agree that folks have not had enough time to review and vet the tariff language in advance of the meeting, so we pulled it from today’s agenda.”

Johnson said the revisions would be discussed April 9, on which a meeting of the Installed Capacity Working Group is scheduled. After that the proposal would be brought either to the MC’s normal meeting or a special meeting if needed.

The changes include new requirements for generators that say they are firm, with penalties for those that are unavailable when called upon. (See NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept.)

Johnson acknowledged that many stakeholders had concerns over the penalty structure, which would have two tiers based on the reason why the generator says it did not have fuel. Johnson reiterated that the ISO believed it was important to implement penalties that incentivize the correct behavior from generators attesting that they have guaranteed fuel arrangements.

“We are not in favor of pay-for-performance-type penalties that you’ve seen in other ISOs, which, for lack of a better term, can be called ‘bankruptcy penalties,’” Johnson said. “Penalties of that size can incur such high risk that folks are not going to participate, which is not the purpose of the firm fuel concept.”

A stakeholder representing generator interests said that it would be helpful if a special MC meeting was scheduled directly after the April 9 meeting because generators were running out of time to elect for firm fuel.

“If you file in the middle of May and don’t ask for a waiver of the 60-day period, you’re giving us about a week and a half to confirm if we are going to be firm fuel or not,” they said. “That presumes that FERC does nothing.”

The stakeholder said they understood that the ISO was in a tight place schedule wise but that they wanted to make sure the procedures were followable. They did not want generators to opt not to declare firm fuel when they otherwise were firm because they did not understand the new rules. “I’m hoping we can think about how we can maneuver timing so that we can afford as much time as possible.”

Johnson said the ISO would consider those concerns.

“I think your statement itself identifies part of the problem: You envision having the language that you’re looking for as giving the ISO the ability to apply the penalty when the evidence is gray, rather than black and white,” another stakeholder representing generators said. “That’s a huge problem.”

The Market Monitoring Unit also chimed in, saying the language as written would “weaken the firm fuel capacity accreditation rules relative to the status quo.” This was because generators with deficient operating plans could go many years without being detected or penalized, and the proposed penalty would not be an adequate disincentive against this situation, the Monitor argued.