While NYISO operated reliably last winter, the season provided “continued examples of limited flexibility on the gas system,” ISO staff told the Operating Committee on March 20.
Temperatures were below average last winter, but there was no need for emergency operations, Aaron Markham, NYISO vice president of operations, said in presenting the cold weather operations report.
There were 16 daily peak loads in excess of 22,000 MW, the most since the 2017/18 winter, with the peak load of the season occurring on Jan. 22 at 23,521 MW. NYISO’s record is 25,738 MW, set Jan. 7, 2014.
The peak occurred during a cold snap that began over the Martin Luther King Jr. Day weekend. When the peak load occurred during the 6 p.m. hour Jan. 22, about 18% of the fuel mix was natural gas and 27% was oil. Markham indicated that this, and the high rate of oil consumption over the coldest days, showed that there were problems with gas procurement, leading to stored oil use.
“We did see some larger non-firm gas units actually put in derates during the Martin Luther King weekend as a result of a forecasted inability to get gas in response to the day-ahead schedule,” said Markham. “I don’t think we’ve actually seen that before, so that was kind of noteworthy.”
Markham said that the average forced outage rate was higher than average during the winter. It was a challenge to manage unavailable capacity in gas units between the day-ahead and real-time because gas generators did not have their normal operational flexibility. Many dual-fuel units resorted to oil, leading to depleted oil reserves statewide.
February Operations Report
Markham also presented the operations report for February.
While the month was milder than January, cold weather produced a peak load of 22,651 MW on Feb. 18. Toward the end of the month, Markam said there was a forced outage in the Greenwood/Staten Island load pocket in New York City caused by a transformer coming out of service while another parallel circuit was also out. NYISO implemented a targeted demand response program in the area.
Markham also mentioned that NYISO had found the source of curtailments of wind and solar resources in New York’s southern tier. A circuit breaker at a substation in Union was “stuck,” affecting several other lines nearby.
“We were able to work with the transmission owner to implement a strategy to avoid the stuck breaker contingency,” said Markham, who went on to say that the ISO was evaluating whether their solution met the criteria for a facility to be secured in its market models.
FERC once again decided that neither MISO nor Montana-Dakota Utilities are entitled to recourse over a MISO-SPP flowgate in North Dakota strained by a cryptocurrency mining facility.
The commission denied both MISO and Montana-Dakota Utilities’ requests for rehearing in a March 20 order (EL24-61 et al.). It said it found nothing amiss with the 230-kV Charlie Creek flowgate’s continued eligibility for market-to-market (M2M) coordination despite high congestion costs.
FERC first denied MISO and member Montana-Dakota Utilities Co.’s separate complaints over the Charlie Creek flowgate in September 2024. The two had argued that the congestion caused by the new cryptomining operation should fall to SPP alone because it’s a local issue brought on by data center load growth. But FERC said neither MISO nor Montana-Dakota Utilities proved that Charlie Creek failed to meet the criteria for M2M coordination, nor was SPP in the wrong for continuing to insist on M2M coordination. (See FERC Refuses MISO, MDU Complaints Regarding Crypto-strained MISO-SPP Flowgate.)
FERC kept that stance in its latest order. The commission pointed out that the Charlie Creek flowgate passed some of the studies required under MISO and SPP’s congestion management process to be eligible for M2M coordination. It also said it was unconvinced that MISO and SPP’s interregional coordination process laid out in their joint operating agreement is unreasonable.
MISO had said the flowgate, which serves the 200-MW Atlas Power Data Center, cost its members more than $40 million in unjustified M2M payments. The RTO argued it could provide little congestion relief for SPP’s transmission-constrained northwestern North Dakota load pocket. MISO also accused SPP of defying the two’s M2M coordination protocol by refusing to revoke the line’s M2M designation and insisting on interregional help for a provincial issue that MISO was powerless to resolve. Finally, MISO complained it couldn’t veto the M2M status of the line without SPP’s consent. (See MISO Argues to FERC for 2nd Look at Crypto-stressed Flowgate Management and SPP, MISO Clash over Crypto-strained M2M Flowgate.)
But FERC disagreed with MISO that the M2M process is unfair because it doesn’t account for cost causation. The commission said MISO and SPP’s coordination process is established on forecasted allocations with no requirement that the hundreds of M2M flowgates it serves be reviewed individually. The commission said such a style of cost allocation isn’t meant to be roughly commensurate with estimated benefits.
FERC noted SPP’s argument that about 20 other M2M flowgates at the seams “possess arguably ‘local’ attributes and impose ‘higher than expected’ congestion costs on SPP that require [M2M] payments to flow from SPP to MISO.” The commission said a single flowgate in particular cost SPP $12.5 million in M2M payments to MISO in fall 2023.
FERC also disagreed with MISO that it and SPP’s interregional coordination process is one-sided because it doesn’t allow one RTO the ability to revoke an M2M designation.
The commission also said it didn’t buy MISO’s argument that it doesn’t have enough generation nearby to help alleviate congestion on Charlie Creek. On the contrary, FERC said MISO operations contribute to congestion on the flowgate, where it serves load in the Williston, N.D., area. Flowgate studies from MISO and SPP’s coordination process show the line is “significantly impacted” by MISO flows from generators that exceed 5% in real-time, FERC said. It added that SPP confirmed that if the flowgate was withdrawn, it might have to resort to transmission loading relief.
FERC decided against ordering SPP and MISO to make any specific adjustments to their M2M coordination process, as MISO requested. It ended by asking them to work together.
“We encourage the parties to continue negotiating prospective revisions to their agreements, especially in light of SPP’s and MISO’s positions that similar issues are either currently occurring on other [M2M] flowgates or are likely to recur on other [M2M] flowgates in the future,” FERC wrote.
Additionally, FERC disagreed with Montana-Dakota Utilities’ complaint that a combination of congestion charges and M2M payments stemming from Charlie Creek caused it to be double-charged.
The utility claimed it was billed for the same congestion once under the SPP tariff and again to reimburse MISO for M2M coordination. But FERC said the two are “distinct charges provided for under different frameworks that serve separate purposes.” It explained one is incurred as a customer of SPP while the other is meant to cover interregional coordination charges.
In a separate but related docket on FERC’s March 20 agenda, the commission also turned down MISO’s request to waive SPP’s yearlong statute of limitations on resettlements (ER24-1586-001). MISO was counting on FERC to allow a prolonged resettlement period to refund affected members some of the M2M payments, had FERC directed refunds. SPP said that allowing settlement adjustments outside of the window would amount to retroactive ratemaking.
FERC on March 20 accepted SPP’s proposed tariff revisions incorporating a mark-to-auction (MTA) collateral requirement for its transmission congestion rights (TCR) market while stopping short of terminating a show-cause proceeding dating back to 2022 (ER24-2906).
SPP had requested that the commission terminate the ongoing show-cause proceeding (EL22-65) as part of its proposal, but FERC declined. It said that while the RTO’s proposal included just and reasonable reforms to allow for the re-marking of monthly TCRs acquired in the annual auction, “it does not fully address the commission’s concern that SPP’s TCR collateral requirements may not adequately address the increased risk of default that results from a TCR portfolio that declines in value.”
It further explained that seasonal TCRs — emphasizing the difference with monthly TCRs — would not be re-marked based on clearing prices in subsequent TCR auctions.
“Thus, the associated collateral requirements do not reflect a possible decline in value of those seasonal TCR products. Accordingly, SPP must still respond to the directives in the 2023 show-cause order,” the commission said, referring to an earlier ruling that the RTO’s tariff didn’t include an MTA requirement or comparable alternative. (See FERC Rebuffs PJM, SPP on FTR Credit Rules.)
SPP said it re-evaluated whether an MTA could be developed in its TCR market to address FERC’s concerns over the use of historical price data to calculate collateral requirements. It said the proposed revisions would mitigate a TCR portfolio’s risk of declining in value over time by implementing more frequent updating of collateral requirements based on valuations from more recent TCR auctions.
The RTO said the changes proposed in protests by DC Energy and the Energy Trading Institute would require “nothing short of a complete TCR market redesign.” SPP’s Market Monitoring Unit originally intervened in support of the grid operator but later said the proposal did not appear to be consistent with the commission’s show-cause order.
FERC granted SPP’s request for waiver of the commission’s 120-day notice requirement for good cause shown and accept the proposed tariff revisions effective May 1.
MMU Doesn’t Get Rehearing
In a separate order, FERC rejected the MMU’s rehearing request of its acceptance of SPP’s proposal to establish a winter season resource adequacy requirement (RAR) by modifying its order and sustaining the result (ER24-2397).
The MMU said the commission erred in its November 2024 order approving the RAR. It contended that FERC erred in finding that SPP does not study forced outages and violated the rule of reason by failing to require the inclusion of outage scheduling procedures in the RTO’s tariff. The Monitor requested that FERC direct SPP to define “forced outage” in a compliance filing and to include its outage study procedures in the tariff at issue.
The commission said it was unpersuaded by the MMU’s arguments. It said SPP’s proposed language included the definition of an “authorized outage” that differentiated which resources can be counted toward a load-responsible entity’s RAR from those that cannot. It said the RTO’s outage coordination methodology makes clear that forced outages are those “forced” upon the SPP system, as opposed to other outages that are studied and approved.
FERC also disagreed with the MMU that SPP provided insufficient detail related to the tariff’s outage scheduling procedures to satisfy the rule of reason. It found that the RTO’s proposed language does not need to include the outage study procedures and said the MMU’s specific arguments pertaining to how SPP will study outages and whether the tariff contains sufficient detail on the procedures were beyond the scope of the proceeding.
The commission said it did not find that SPP’s forced-outage definition “‘significantly impacts rates’ in such a manner that the rule of reason” would be included in the tariff. FERC noted that while it found the definition of “seasonal net peak load” in a separate SPP proceeding “significantly affects rates” because it had a direct impact on effective load-carrying capability values, “the relationship between how SPP will study outages and the final resulting rate is only relevant as to the” performance-based accreditation methodology.
Participants in a March 20 workshop hosted by FERC and NERC said their organizations support the development of new supply chain risk management standards but urged the commission not to put overly strong burdens on the electric industry and its partners.
FERC called for the workshop after proposing new reliability standards in 2024 aimed at securing the supply chain of critical electronic components (RM24-4). The proposal was prompted by staff observations of “multiple gaps in” supply chain risk management during audits of utilities’ compliance with NERC’s Critical Infrastructure Protection standards. (See FERC Proposes Further Cybersecurity Measures.)
In his introduction to the workshop, Kal Ayoub, director of FERC’s Office of Electric Reliability, acknowledged that the commission received “a lot of helpful comments from the industry” after publishing its Notice of Proposed Rulemaking last year. But one element of the NOPR that drew “mixed feedback” was a proposed requirement that new standards require entities to “validate the completeness and accuracy of information received from vendors during the procurement process.”
“The commission did state that we are not proposing to require the entities guarantee the accuracy of information provided by the vendors,” Ayoub said. “However, we do believe that entities should be required to take certain steps to validate such information, and that is why we’re here today: to gather information from all of you … to clarify what level of validation should be required from responsible entities to ensure appropriate risk assessment.”
Laura Schepis, executive director of regulatory and industry affairs at the National Electrical Manufacturers Association, said NEMA’s members would be “quite happy” to give utilities any information they can on their equipment and subcontractors. The key, she continued, is to give them a voice in the process so they can provide their own perspectives to produce solutions that are as standardized as possible.
Laura Schepis, NEMA | FERC
“Our manufacturers want to be prepared to be the best possible partners,” Schepis said. “So, like any good partner, our members greatly appreciate [understanding] at the start of a process … all the hurdles and timelines and inflection points that might be on the horizon for the utility. … I think sometimes professionals in complex roles may resist a checklist … but I think the gravity of the risks and vulnerabilities that we’re all combating together means that we need to embrace standardization and trust ourselves to use tools that get us 80 to 90% of the way there.”
Alan Herd, deputy director of OER’s division of cybersecurity, asked panelists how FERC’s final rule could help ensure the process in the resulting standard is a “scalable solution.”
In response, Roy Adams, director of supply chain procurement, planning and analysis at Consolidated Edison, replied that it is “very important to look at benchmarks outside of the energy industry.”
He also suggested scalability can be ensured through standardization and shareability so vendors don’t necessarily have to fill out the same information over and over for different customers.
“I think it’s a bit of a compromise with centralization. If it’s been submitted once, why not reuse it, if the information is accurate and has been verified?” Adams said. “In addition, I think a system needs to be adaptable to new tools. … The system itself can’t be built once and never updated. It needs to be continuously improved to adjust to the environment it’s in.”
As Republicans in Congress debate whether to cut the Inflation Reduction Act’s clean energy tax credits, solar, wind and storage advocates are fighting back with reports arguing that renewables and the IRA tax credits are critical for achieving President Donald Trump’s goals of U.S. energy dominance, creating jobs and cutting consumer utility bills.
A new report from the American Council on Renewable Energy says solar and wind can be deployed cheaply and quickly to meet the country’s rapidly escalating demand growth, while providing support for natural gas and nuclear plants that could take five to 10 years to come online.
In a March 19 press release, ACORE President Ray Long echoed Trump’s rhetoric, calling for “an ‘all of the above’ energy strategy if we want to achieve energy dominance. We have an extraordinary opportunity to meet the demand growth challenge with affordable, reliable and secure energy, so we can’t afford to forfeit this chance by limiting our own advantage.”
Stretching the all-of-the-above argument even further, the ACORE report also frames renewables as a prop for increasing U.S. global dominance in natural gas exports and ensuring national security.
All-of-the-above has made the U.S. “the world’s largest producer of oil and natural gas,” the report says. “Clean energy provides domestic, readily deployable energy solutions to meet Americans’ needs while continuing to enable high-value exports of liquefied natural gas and other resources abroad, and further lessening dependence on unpredictable foreign actors and external shocks.”
A second report, from nonprofit Energy Innovation Policy and Technology, focuses on jobs ― particularly those that could be lost ― state by state, and the impact on consumer energy bills if the tax credits are repealed. The U.S. could lose 790,000 jobs by 2030, while electric bills for all American households could increase by $6 billion by 2030 and $9 billion by 2035, the report says. GDP could drop by as much as $160 billion.
Trump’s freeze on IRA funding already may have stalled as many as 60 clean energy projects, totaling $57 million in investments, the EI report says.
“Reduced clean energy investment will increase fuel and operating expenses across the country,” the report says. “Wind and solar have no fuel costs and lower operation and maintenance (O&M) costs than gas, coal, oil and nuclear power plants. Full repeal of existing federal policies would increase the share of electricity coming from these power plants, creating roughly $20 billion in additional fuel and O&M costs in both 2030 and 2035.”
IRA tax credits and incentives have recharged clean energy manufacturing across the country, with 67 new solar and storage manufacturing plants online and another 48 under construction. | ACP
Both reports stress that Republican states and districts have received the lion’s share of IRA dollars, which in turn have attracted private investment and created jobs. Georgia led the nation, adding an estimated 43,000 new jobs since passage of the law, ACORE says.
But if the law’s tax credits and other incentives are repealed, EI estimates the state could lose 15,200 jobs by 2030 and 28,600 by 2035, along with about $3.4 billion in GDP. Household energy bills could go up $2 billion statewide, with individual electricity bills rising $40 per year in 2030 and $180 per year by 2035, the report says.
Competing with China
Georgia took a big hit in February when Freyr Battery abandoned its plans to build a $2.6 billion battery factory in the state, deciding instead to refocus its business on a solar panel factory it had bought in Texas, according to an Associated Press report. The change in company priorities was driven by high interest rates and competition from cheap Chinese batteries, the company said.
Battery maker Kore Power also backed out of its plans to build a $1.2 billion factory in Arizona after Trump froze IRA funding, according to Canary Media. The company had received a conditional commitment for a $850 million loan from the Department of Energy’s Loan Programs Office in 2023 but had not finalized it before the change in administration.
Similar to Freyr, Kore decided to go with a cheaper option and plans to lease an existing factory site and retrofit it for batteries.
Chinese dominance in clean tech investing provides another argument for keeping the tax credits, the ACORE report says. In 2024, China invested more than $300 billion in solar, wind, geothermal and energy storage technology, versus just over $100 billion in the U.S.
In 2024, China invested about $300 billion in solar, wind, energy storage and geothermal versus about $100 billion in the U.S. | ACORE
“A full repeal of the IRA could create up to $80 billion in energy investment opportunities in other countries, compared to a base case scenario where the IRA is preserved,” the report says. “Under these projections, announced projects and 50% of projects under construction could be canceled, and manufacturers would likely seek to meet global demand through factories abroad.”
ACORE backs up those numbers with a survey of top energy executives at companies “that actively finance or develop clean energy projects.” In a scenario where IRA tax credits remain in place, about 30% of the top companies ― those investing $1 billion or more in clean energy ― said they would increase their investments by 5 to 10% or more.
Faced with potential uncertainty about the tax credits, more than 80% of the companies said they would decrease their investments either significantly or moderately.
“Sponsors are going to start having to think about how much capital they can put at risk for developing assets that take four or five years to develop, if we don’t have some level of certainty around how we’re going to manage the tax credits,” one unnamed institutional investor told ACORE.
Heavy Pressure
The IRA’s clean energy tax credits and incentives have been in the crosshairs of some Republican lawmakers almost from the moment former President Joe Biden signed the bill into law in August of 2022. But outright repeal is not universally supported, exactly because of the projects, jobs and additional economic benefits the law has brought to red states and districts.
In August 2024 and again in March, Rep. Andrew Garbarino (R-N.Y.) led a small group of Republican representatives writing to House leadership to take “a targeted and pragmatic approach” to IRA tax credits. The August letter was signed by 18 representatives, and the most recent one on March 9 had 21 signatures, including Garbarino’s.
The letter’s talking points echo the industry advocates, who have been actively lobbying Garbarino and others on Capitol Hill, The New York Times reports.
The 10-year time frame for tax credits, established in the IRA, has been vital for “capital allocation, planning and project commitments, all of which would be jeopardized by premature credit phaseouts or additional restrictive mechanisms such as limiting transferability,” the letter says. “As energy demand continues to skyrocket, any modifications that inhibit our ability to deploy new energy production risk sparking an energy crisis in our country, resulting in drastically higher power bills for American families.”
Garbarino is also trying to detach the tax credits from the IRA, noting that most of them existed prior to the law, which primarily extended them, according to the Times article.
With Republicans’ razor-thin majority in the House of Representatives, Garbarino and other tax credit supporters could hold a balance of power as leadership looks for ways to fund the trillions of dollars needed to extend the 2017 Tax Cuts and Jobs Act.
But many analysts have noted that if Congress produces a budget reconciliation bill that slashes the IRA tax cuts, even supporters like Garbarino would be under heavy pressure from their colleagues and Trump to vote the party line.
VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee endorsed two proposals to revise the RTO’s effective load carrying capability (ELCC) formula to add two new generation categories and limit the penalties resources face if their accreditation declines between a Base Residual Auction (BRA) and Incremental Auction (IA).
The volatility of unit ratings after auctions has been a sticking point for generation owners, who say it is unfair to commit a resource in the auction only to reduce that unit’s accredited capacity (AUCAP) afterward.
And particularly so when ELCC ratings are falling due to changes in load forecasts, they argued.
The endorsed proposal, Package C, would limit the deficiency rate for a resource that has its rating reduced after being committed in the BRA to 100% of the clearing price, rather than the 120% penalty rate. Resources still could be subject to the penalty rate if they cannot meet their committed capacity because their installed capacity (ICAP) declined, such as due to unit failure, or if a planned unit does not come online according to schedule.
The proposal passed with 80% sector-weighted support, after an initial vote narrowly missed the two-thirds threshold at 66.08%.
PJM’s Pat Bruno said the proposal would retain an incentive for market sellers to avoid the deficiency by procuring additional capacity through bilateral transactions or in the IA without subjecting them to a penalty rate. Resources also would be held to their original commitment during a performance assessment interval (PAI).
He gave the example of a resource with 100 MW of ICAP that is committed at 90 MW in the BRA. If its AUCAP were to fall to 80 MW in an IA, it would be assessed a 10-MW deficiency charge at the clearing price unless it procures more capacity. If that unit were to output at 80 MW during a PAI, without having procured capacity to make up the shortfall, it would be assessed a 10-MW nonperformance charge.
The main motion, Package B, would have frozen resources’ ELCC ratings and AUCAP at the values used in the BRA. While resource ratings would not be changed, PJM would continue to update the installed reserve margin (IRM) and forecast pool requirement (FPR) values, necessitating that PJM modify its capacity buy/sell offers to work around any changes in accreditation.
The proposal was rejected by the MRC with 55% support. The two packages were nearly tied in a poll at the ELCC Senior Task Force (ELCCSTF), with Package B holding 66.5158% support and 68% preference over the status quo, while Package C received 66.5025% and 74.9% preference.
Load-serving entities, consumer advocates and Independent Market Monitor Joe Bowring argued that would shift all the risk of changing ratings to load, whereas Package C would more equitably split the risk between market sellers and buyers. Bowring said he opposed both options because they would shift risk inappropriately from generators to load.
Bowring said it shouldn’t be any surprise that ratings can change between BRAs and IAs — it happened with the prior EFORd model as well, but ELCC is more volatile. The difference with both proposals, he argues, is they would inappropriately shift some or all of that risk to load, when it should remain with market sellers, who are capable of mitigating their risk by maintaining high performance when called upon.
‘Emblematic’ Debate
Several market sellers questioned Bowring and PJM on whether they can adjust their offers to reflect the risk of their ratings changing after an auction, noting that under EFORd, they were able to vary the amount of capacity they offered within a band defined by their annual and 5-year average forced outage values. Bruno responded that the ELCCSTF discussed whether that risk could be included in sellers’ capacity performance quantifiable risk (CPQR) values, but that did not make it into the proposal.
Vitol’s Jason Barker questioned whether generators can mitigate the risk by ensuring their units perform well because the class-based approach to accreditation means even a unit with perfect output when called upon can have its rating impacted by similar resources.
Barker also questioned PJM’s ability to identify whether changes in ELCC ratings stem from resource performance or a change in the load forecast. He suggested PJM should procure more capacity if the demand side is responsible for the increased risk but should reduce ratings if sellers are driving the risk.
“This debate is emblematic of problems with ELCC,” Barker said, adding it is creating unfair outcomes for either load or sellers no matter which approach is selected.
Bowring responded that a unit-specific ELCC approach would address the class average issue and said the Market Monitor has supported a unit-specific approach from the start of ELCC.
“This discussion further illustrates that PJM’s ELCC approach needs significant improvements,” he said.
Bruno said PJM previously explored but found it could lead to convoluted outcomes, such as scenarios where seasonal risk shifts toward the summer while the ratings for solar units decline.
Calpine’s David “Scarp” Scarpignato said the implications of the proposals are very different when auctions are being held a year in advance with only one IA, versus the standard three-year, three-IA cadence. In the latter, he said there is more opportunity for large changes in the load forecast or a PAI, causing significant shifts in ELCC ratings.
The proposal to add new resource classes would establish oil combustion turbines (CTs) as their own bucket, organizing them from the miscellaneous “other unlimited resource” category, and breaking waste-to-energy as its own class from “steam.”
Bruno said PJM ran a sensitivity based on the 2025/26 IA and found waste-to-energy would have an 83% ELCC rating, while oil CTs would be about 85%. Since there is a relatively small amount of capacity offered by waste-to-energy, pulling it out is expected to have little impact on the steam class. Other unlimited resources have unit-specific analysis, so combining their ratings is expected to have minimal impact.
Bruno told RTO Insider that grouping oil CTs together as a class better captures correlated outages and increases the amount of performance data available for modeling a particular unit. Since there is a limited number of PAIs from which to draw performance modeling, he said grouping units can smooth the impact of outages that happen at a consistent rate across that class.
Members of NERC’s Standards Committee voted in favor of expanding the teams behind several existing standards projects at their monthly meeting March 19.
The first standards action to come before the committee concerned Project 2021-01 (system model validation with inverter-based resources), a project intended to satisfy FERC Order 901. Specifically, the project addresses Milestone 3 of the order, which covers data sharing and model validation for all IBRs; standards under this milestone are due by November 2025.
Currently the standard drafting team for Project 2021-01 consists of six members; the proposal before the SC was to add five more members for a total of 11. NERC solicited nominations for SDT members from Nov. 21 to Dec. 20, 2024, receiving 13 nominations that the ERO then narrowed down to five based on “background, experience and skills,” including “expertise in system model validation, system model practices and disturbance-based playback.”
Candidates were not identified by name or corporate affiliation during the meeting, in keeping with NERC’s confidentiality policy.
Sean Bodkin, senior counsel at Dominion Energy, said he supported adding more team members but felt uneasy about the fact that half of the candidates were from WECC’s footprint. He proposed evening out this perceived regional imbalance by replacing one of NERC’s candidates with another industry nominee from SERC Reliability’s territory.
“There’s definitely IBRs throughout the whole country, especially in the Southeast,” Bodkin said. “I don’t think I can support the slate as is. I think we need to balance it out and get some other regions of the country and … people with as good, if not better, expertise as some of the [candidates] put forward by NERC on the team.”
NERC Manager of Standards Development Sandhya Madan explained that NERC chose not to include Bodkin’s preferred candidate because they “didn’t have sufficient IBR experience” compared to the one Bodkin suggested dropping. She suggested increasing the number of candidates to six, but Bodkin stuck with his proposal, saying he wanted to keep the SDT membership “manageable.” Ultimately, however, Bodkin’s motion did not receive a second and SC members voted to approve NERC’s candidate slate without changes.
Members next turned to Project 2020-06 (verifications of models and data for generators), which applies to the same milestone of Order 901.
NERC staff and leadership of the project’s SDT asked for the SC to approve soliciting more team members, both to address recent issues meeting quorum at team meetings due to departing members and to add needed expertise. Madan explained the team recently was assigned a new standard, MOD-034, and leadership wanted to make sure members had the requisite experience. The motion was approved unanimously.
A proposal to reassign the task of revising FAC-001-4 (facility interconnection requirements) and FAC-002-4 (facility interconnection studies) from Project 2022-04 (EMT modeling) to Project 2023-05 (modifications to FAC-001 and FAC-002) met with another suggested change from Bodkin. He said that, rather than move the standard authorization request (SAR) from one team to another, it would be better to create a completely new team for this purpose.
NERC Director of Standards Development Jamie Calderon replied that the team for Project 2023-05 “has not been seated” or started work on their project yet, so it is not the same as adding a SAR to an already active project. She acknowledged the team might feel they need more members but suggested they could come back to the committee to ask for more nominees.
Bodkin still moved to form a separate team for the new SAR, but the motion was defeated with nine votes against, six in favor and two abstentions. The original proposal then passed, with no abstentions and Bodkin, Vicki O’Leary of Eversource and Maggy Powell of Amazon Web Services voting against it.
FERC on March 20 approved Duke Energy’s compliance filing with Order 2023, which revised the commission’s pro forma generator interconnection rules to speed up queues around the country (ER24-1554).
The changes to Duke Energy Carolinas’ and Duke Energy Progress’ large generator interconnection procedures (LGIP) and small generator interconnection procedures (SGIP) will go into effect Nov. 1, 2025, as requested, with the utility having to make an additional compliance filing within 60 days of the order to make some minor changes.
Duke proposed to adopt FERC’s pro forma large generator interconnection agreement (LGIA), pro forma LGIP, pro forma small generator interconnection agreement and pro forma SGIP. Much of the other parts of Order 2023 also were adopted directly, but Duke also proposed some variations, which is allowed as long as they are consistent or superior to its baseline rules.
The utility already implemented a cluster study process before Order 2023, which it proposed to keep in place but change some of the timing requirements to better align with FERC’s new requirements.
It proposed to cut its 180-day cluster request window down to 45 days but leave the customer engagement window at 60 days, the Phase 1 Cluster Study deadline at 90 days, the Phase 2 study at 150 days and the as-needed Cluster Restudy at another 150 days. Individual facility studies are required to be done in 90 days or 180 days based on the interconnection customer’s choice, instead of 150 in the current rules.
The two-phase study process has Duke study power flow and voltage in the first and then stability, short circuit and reactive capability in the second. The process allows the utility to work through the queue more quickly and efficiently and cuts the likelihood that it will need to do restudies, making it better than the default in Order 2023, it told FERC.
“We find that Duke’s two-phase cluster study process overall satisfies the ‘consistent with or superior to’ standard by providing interconnection customers with Phase 1 study results and an opportunity to withdraw earlier in the study process, thereby increasing the speed and efficiency of the Phase 2 study,” FERC said. “Duke’s proposed two-phase process occurring over 90 days is, in this respect, faster than the commission’s single-phase pro forma process, which takes an additional 60 days to conduct the cluster study and provide results to customers, after which they would have their first opportunity to withdraw from the queue.”
Duke’s proposal gives customers an earlier look at network upgrade costs, which allows them to make critical decisions about whether to move forward earlier in the process, the commission said.
Some intervenors were worried that the tight study deadlines left little room for error, but Duke said it has adopted all the aspects of Order 2023 designed to mitigate restudy risk.
“Moreover, Duke presents historical data showing that large percentages of its customers withdraw after Phase 1, and that retaining its two-phase process provides an opportunity to withdraw earlier in the process,” FERC said. “In turn, we agree that a cluster study process that maximizes the likelihood of early withdrawals will also minimize study and queue administration costs for all customers.”
Duke’s proposed withdrawal penalties increase at each stage of the process, which is in line with the structure adopted in Order 2023, FERC said. It had to tweak that to fit its two-study process, requiring interconnection customers dropping out after Phase 1 to pay twice its actual allocated costs of all studies performed up to then, and those that drop out after Phase 2 to pay 5% of estimated network upgrade costs and then increasingly higher shares of network upgrade costs later in the process.
The utility removed penalties for projects not picked in resource solicitation processes, which FERC said was superior to its pro forma process by cutting barriers to entry to the queue.
FERC on March 20 released its State of the Markets report, which showed higher demand and lower wholesale prices across the organized markets in 2024.
The higher demand was driven by a warmer summer, leading to higher demand peaks in CAISO, ERCOT and PJM, but the report also noted demand is expected to increase even more in coming years.
“Going forward, NERC forecasts that U.S. electric loads will grow more quickly and increase by 132 GW by the summer of 2029 and by 149 GW by the winter of 2029,” the report said.
Generation of electricity was higher from 2023 to meet the demand, totaling 4,151 TWh nationally, though the resource mix continued to change. Coal generation was down 3.3% from 2023, utility-scale solar was up 32% and wind generation grew by 7.7%.
The lower national prices masked regional disparities, with ERCOT North Hub and trading hubs in the West seeing the steepest drops, while wholesale prices in the Northeast were up from 2023.
“Compared to the five-year average prior to 2023, electricity prices were down significantly in nearly all representative trading hubs, with the greatest decreases in ERCOT, CAISO, SPP and the Southeast,” the report said. “In RTOs/ISOs, mean load-weighted electricity prices were down 25% compared to the five-year average prior to 2023.”
FERC Chair Mark Christie highlighted the regional differences in prices, saying that the State of the Market report from PJM Monitor Joe Bowring showed an uptick in prices there. (See PJM Market Monitor Publishes Mixed Views in Annual Report.)
“LMPs went up by almost 8%, and the overall total cost of wholesale power went up by almost 5%, so I’m not saying that it’s a discrepancy, but PJM is the largest operator by load, and Dr. Bowring reports that their wholesale power costs went up almost 5%,” Christie said.
The report shows wholesale prices going up by 4% at the node FERC tracks in PJM, but it does not examine all-in costs like Bowring’s does, staffer Taylor Webster said at the commission’s open meeting.
Beyond prices, Christie also highlighted that reserve margins are shrinking around the country.
“This report is consistent with reports we have been regularly receiving from NERC as well as RTO sources, such as from PJM and MISO,” Christie said in a statement. “The combination of rapidly increasing electricity demand, driven by hyperscale customers such as data centers, paired with the alarming rate of baseload generation retirements and lack of new dispatchable generation, is not sustainable and must be addressed.”
Data centers are expected to add 13 to 55 GW across the country over the next five years, with uncertainty about supply chains, questions about how efficient computation in artificial intelligence will be, and the availability of electric generation in some regions. The changing demand, resource mix and weather patterns all have had an impact on capacity markets, with ISO-NE, MISO, NYISO and PJM all seeing prices rise in those markets, the report said.
“Although the mechanisms differ, each of the nation’s RTOs and ISOs are working to preserve resource adequacy by enacting changes consistent with their specific market structures,” the report said. “Some of these changes have been enacted, while others are underway or on the horizon. The full effects of these resource adequacy reforms are not yet fully clear.”
Commissioner Judy Chang noted the markets also feel the effects of cheap natural gas. Prices for the commodity were down from 2023, with the Henry Hub benchmark dropping 11% to average $2.25/MMBtu.
“I just want to make a note that our electricity prices are very sensitive to gas prices, I would say probably across the entire U.S.,” she said. “But also, while energy prices are low, it also puts upward pressure on capacity prices.”
That pressure is felt in regions like PJM, where prices shot up in a very visible way, but also in regions where capacity costs are included in bilateral contracts that power plants sign for offtake, Chang added.
FERC approved a $528,000 settlement March 20 that ends a dispute between EDF Trading North America and CAISO over fuel cost recovery.
The settlement approved by FERC’s order (ER25-526) resolves all issues that had been set for hearing.
EDF Trading has served as scheduling coordinator and fuel supplier for CXA La Paloma, which was also a party to the settlement. CXA La Paloma owns the 1,124-MW natural gas-fired La Paloma power plant in Kern County, Calif.
EDF Trading filed a request in July 2021 to recover “prudently incurred fuel costs” that were not reimbursed through market revenues Feb. 16, 2021. On that date, CAISO committed two units at La Paloma through its Residual Unit Commitment (RUC) process, which the ISO describes as a reliability function for committing resources and procuring RUC capacity not reflected in the day-ahead schedule.
But CAISO did so using gas prices to compensate La Paloma “that were well below the actual gas costs incurred,” EDF Trading wrote in a fuel cost recovery application filed with FERC on July 29, 2021 (ER21-2579).
The cost-recovery issues with CAISO arose from “a perfect storm of events,” including an “untimely notice from CAISO, a long holiday weekend and an extreme weather event,” EDF Trading said in the filing.
CAISO had planned to implement changes to its cost-recovery procedures in early 2021 through tariff changes known as the Commitment Costs and Default Energy Bid Enhancement (CCDEBE).
On Sunday, Feb. 14, 2021, CAISO sent out a notice saying it would begin deploying CCDEBE the following day, which was Presidents Day, a holiday. The notice failed to give the two days advance warning that CAISO had promised, according to EDF Trading’s filing.
That Sunday and Monday were also when Winter Storm Uri was striking Texas. EDF Trading said it faced “operational difficulties” due to rolling blackouts and internet problems.
CAISO denied recovery of fuel costs from the Feb. 16 La Paloma commitment, because the request to adjust the reference level using actual fuel costs was not made before 8 a.m. Feb. 15, EDF Trading said in its filing.
But the actual fuel costs weren’t known at that time, EDF Trading said, because CAISO didn’t commit the units as part of RUC until later that day.
“Equity requires ensuring that EDFT and La Paloma are not penalized for CAISO’s failure to timely plan and notify market participants, particularly when EDFT and La Paloma ultimately performed and ensured system reliability,” the filing said.
In February 2024, CXA La Paloma was purchased by Capital Power Investments LLC. Interest in the cost-recovery proceeding was retained by the seller, CXA La Paloma Holdco LLC.
