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 last year 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 that 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 that 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 that scalability can be ensured through standardization and shareability so that 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.”
How many jobs: Over 70% of jobs created by projects funded with IRA dollars were in states that voted for Trump in 2024. | Climate Power/ACORE
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 could still 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 would also 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 additional 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 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.
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 around 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 were also 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 had 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 that demand is expected to increase by even more in the 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 2024 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 coming from supply chain issues, open questions about how efficient computation in artificial intelligence and other applications will be, and the availability of electric generation in some regions. The changing demand, resource mix and weather patterns have all 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 that the markets are also feeling 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.
NEW ORLEANS — Calls to consider a dissolved or weakened Inflation Reduction Act alongside appeals for stronger MISO South planning epitomized the tough situation and unsteady political climate MISO finds itself in as it tries to establish transmission planning expectations.
In a transmission planning futures teleconference March 19, MISO revealed it plans to proceed in its modeling as if tax credits from the Inflation Reduction Act are a safe bet. However, MISO staff said they would consider performing sensitivities on the side if that federal funding is eliminated or diminished.
MISO is revising the trio of 20-year futures scenarios it uses to plan transmission. The RTO has said it must incorporate more aggressive load growth and would create a fourth scenario specially designed to study the footprint if frayed supply chains continue to present an obstacle to new generation construction.
WPPI Energy’s Steve Leovy asked whether MISO is considering creating a separate resource expansion model should the IRA fall.
MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said the sensitivities would produce “modified” and “miniature” resource expansion directions that wouldn’t be tested for resource adequacy. But she stressed that MISO hasn’t decided whether it will add the additional study step.
Asah said MISO typically uses sensitivities to “test the durability” of its resource expansion assumptions.
“There are a lot of rules and laws that appear to be rolling back this year,” said Kavita Maini, representing MISO industrial customers.
“As of right now, as of March 1, the IRA is in place, so we’re incorporating it into the model,” Asah said, explaining that MISO’s future modeling relies on a “snapshot” in time. MISO began building the futures models on March 1.
Asah said MISO “has no idea” how the IRA will hold up or how funding cancellations or claw backs might be challenged in court.
Multiple stakeholders pointed out the IRA’s demise is not as improbable as it was last year.
Mississippi Public Service Commission consultant Bill Booth asked if MISO could include an IRA downfall in its new, fourth future that’s meant to contemplate long-term supply chain delays and sluggish generation construction.
“I think this will have a major impact on the generation that’s sited,” Booth said. “You have to question which variables MISO wants to include and which variables MISO wants to ignore.”
MISO Director of Strategic Initiatives and Assessments Jordan Bakke said MISO is confronted with uncertainties at every turn in its futures planning. He said that’s why MISO’s futures include a range of possible realities. Bakke also said MISO wants to capture what it knows today, which includes an intact IRA.
“We have not decided which of the futures we will use in expansion planning,” Executive Director of Transmission Planning Laura Rauch added.
MISO plans to focus on its new, fourth future in an upcoming April workshop. Another May workshop will focus on resource expansion assumptions and how resources would be dispersed across the footprint.
Asah asked members to submit their most up-to-date information on planned generation retirements to MISO. The RTO will incorporate those dates in its futures.
Spotlight on MISO South Planning
Stakeholders’ advice to MISO to rethink the IRA’s place in the futures comes as the RTO and its board are fielding calls to action for a long-term transmission plan in MISO South. The two bids appear to come from opposing sides of the political spectrum.
After MISO completes a futures revamp over 2025, it will use them to plan another long-range transmission plan (LRTP) portfolio for MISO Midwest, making a MISO South LRTP portfolio years away while the Midwest region would be the focus of three, multibillion-dollar portfolios within six years.
At MISO’s March Board Week, Windy Beck, of the Deep South Center for Environmental Justice, made a plea for in-depth MISO South planning. She said the region deserves the same planning attention paid to the Midwest. Beck said she’s seen no evidence from MISO that Entergy and other South transmission owners’ billions in annual Transmission Expansion Plan (MTEP) projects are the most cost-effective and efficient projects for the grid.
During the March 13 board meeting in New Orleans, CEO John Bear pushed back on the perception that the RTO is not doing anything on the planning front for MISO South and focusing all planning attention on MISO Midwest.
Bear said planners have “rolled up their sleeves” to ensure the transmission solutions put forward in the South as part of the MTEPs are “efficient, reliable and at the lowest cost.”
However, the Union of Concerned Scientists’ Sam Gomberg said the member-submitted project ideas of MISO South are no substitute for the broad analysis completed under a long-term planning exercise.
He said MISO South desperately needs the added resiliency, reliability, cost savings and delivered clean energy like the billions in Midwestern long-range lines will provide.
FERC granted rate incentives for the priciest project to come out of MISO’s 2024 Transmission Expansion Plan (MTEP 24), setting off friction between commissioners.
FERC approved Allete’s request for abandoned plant and construction work in progress incentives on a $1 billion modernization of subsidiary Minnesota Power’s circa-1970 HVDC line. The March 17 order had two commissioners disagreeing with how incentives were awarded on at least some of the work (ER25-948).
The commission fully allowed the pair of incentives for the portion of the line in Minnesota — where the certificate and route permitting already are approved — and conditioned incentives for the North Dakota portion of the line on state regulators’ approval of construction. In North Dakota, work awaits an order from the Public Service Commission on certificate and route permit applications. Allete said that decision is likely in the third quarter of 2025.
Allete sought transmission rate incentives under FERC’s rebuttable presumption that the line supports reliability or reduces congestion. The company said the project being subjected to MTEP studies and its ultimate inclusion in the portfolio is evidence of its usefulness.
Allete said the aging, 465-mile line stretching from west-central Minnesota to central North Dakota is experiencing more frequent outages. The company breaks down the project into four components: $828 million in converter station replacements, $112 million in AC transmission facilities upgrades, a $68 million HVDC transmission line upgrade and a new, approximately $24.5 million Nelson Lake substation.
However, FERC said the project’s MTEP status didn’t prove it was the result of a fair and open regional planning process that accounts for reliability and congestion benefits. The commission cast doubt that MISO would perform the usual, comprehensive studies on that particular category of project. It also pointed out the project’s Nelson Lake substation is categorized as an “other” reliability project and also not obliged under MISO’s more rigorous studies.
The commission instead relied on the state commission processes in Minnesota and North Dakota for the project to meet the federal standard for incentives.
FERC paused before approving incentives for the $68 million line-upgrade section of the project. The commission acknowledged there’s almost no chance the Minnesota and North Dakota commissions would explicitly evaluate the upgrade of existing line because the work wouldn’t alter the original voltage, and the project would remain within its existing right of way. Nevertheless, FERC decided the line is “integrally related to the other components” and therefore also entitled to incentives.
Commissioner Lindsay See said while she was “glad” to agree with the majority on most of the incentives, she said she would have stopped short of granting Allete incentives for the line-upgrade portion of the project. She dissented in part from the order.
Commissioner Willie Phillips wrote in a separate concurrence that while he was pleased the project ultimately won incentives, he was troubled that FERC would conduct an on-the-spot reevaluation of MISO’s transmission delivery service project classification and deem it deficient against the rebuttable presumption standard.
Phillips also said the commission deviated from precedent without explanation when it made the effective date of a portion of the incentives contingent on North Dakota’s approval of construction instead of the March 18, 2025, effective date Allete requested for the entire project.
“As such, this order represents an attempt by the current commission to modify our longstanding policy on transmission incentives on a case-by-case basis,” Phillips wrote. “Our practices are not set in stone, and I believe it is both reasonable and appropriate to continually reassess and reevaluate them based on experience, changed circumstances, and achieved wisdom.
“But to do so in the context of an uncontested application, without notice or opportunity for interested parties to comment on these changes, lacks transparency and creates regulatory uncertainty that could undermine the very purpose of FPA [the Federal Power Act].”
At the ISO-NE Planning Advisory Committee (PAC) on March 19, Richard Kornitsky and Ellie Ross of ISO-NE presented the results of additional modeling scenarios for ISO-NE’s 2024 Economic Study, which aims to evaluate the effects of state and federal policies and changes to the region’s resource mix through 2050.
Previous findings of the study have illustrated how the region’s resource needs are expected to shift in the 2040s as the power system decarbonizes, corresponding with an exponential increase in the cost of additional carbon reductions. (See “2024 Economic Study,” ISO-NE Details Evaluation Models for Transmission Solicitation.)
Building on the prior results, ISO-NE modeled a scenario evaluating the retirement of thermal resources. The model found the region could retire “up to 5,550 MW of legacy thermal (non-nuclear) generation” by 2050 without exceeding the loss-of-load expectation (LOLE) threshold, which was set at 0.1 days per year with a loss-of-load event.
“The retirement of 5,550 MW of legacy thermal generation has minimal impact on system operations in the 2050 production cost model,” Ross said. “In the model with retirements, this generation is easily replaced by remaining [natural gas] generators.”
She noted that the scenario caused a decrease in generation from thermal resources that burn landfill gas, municipal solid waste and wood waste solids, which resulted in an overall increase in the emissions from natural gas and oil.
ISO-NE also modeled scenarios featuring increased capital costs for offshore wind (OSW) resources and no OSW buildout.
Adopting the National Renewable Energy Laboratory’s conservative cost estimates for OSW — instead of the moderate estimates used in the model’s base case — increased total annualized build costs by about $17 billion, or 10.8%.
This cost estimate still was cheaper than the no-OSW scenario, which increased build costs by about $26 billion, or 16.6%, compared to the base case.
“New England needs new OSW resources to meet state emission goals at the lowest cost,” Ross said. “The buildouts with less or no OSW must rely more on emitting generation, [small modular reactors] and new [solar] resources.”
“Even if OSW capital costs are higher than current estimates, the system will economically benefit from new OSW resources, although the ideal time frame for building OSW shifts to after 2040,” she said.
Asset Condition Projects
Rafael Panos of National Grid introduced an asset condition project (ACP) to replace wooden structures, insulation, conductor and shield wire on a 115-kV line in Massachusetts.
The wooden poles set to be replaced, which have an average age of 30 years, have significant woodpecker damage, Panos said. He said the population of woodpeckers in New England has grown in recent years, causing significant damage to wooden transmission structures.
The company plans to replace the wooden poles with steel structures; Panos said he has observed woodpeckers pecking at steel structures, “but fortunately, they were not able to get through.”
The project’s projected cost is $19 million, and the expected in-service date is the second quarter of 2026. Stakeholder comments are due April 2.
Panos also presented a cost update on a project overhauling a substation in Tewksbury, Mass. The company has increased its cost estimate on the project to about $67 million, compared to the $36 million estimate presented in 2022.
The increase was driven by additional issues found at the substation and rising costs of labor, equipment, materials and permitting, Panos said.
Project List Update
New England transmission owners (TOs) have added 10 ACPs to ISO-NE’s tracking list since the previous update in fall 2024, said Brent Oberlin, executive director of transmission planning at ISO-NE. (See New England Transmission Owners Issue Draft Asset Condition Forecast Database.) The TOs estimate the projects collectively will cost about $730 million.
ACPs categorized in the database as proposed, planned or under construction total $5.97 billion, while the total cost of in-service ACPs is $5.36 billion.
This estimate does not include a series of projects proposed by Eversource to replace its network of underground high-pressure, fluid-filled transmission lines in Eastern Massachusetts. The company estimates the first phase of these replacements will cost between $1.5 and $2 billion and plans to provide more detailed cost estimates to the PAC in the summer. (See Eversource Outlines Billions in New Boston-area Asset-condition Needs.)
ACP costs in New England have ballooned in recent years, spurring calls from some consumer advocates for more transparency and oversight to ensure projects are cost efficient and right sized to account for future transmission needs.
“Despite the eye-watering sums being spent on ACP upgrades, they are not being designed to maximize the amount of power that can be carried via transmission lines in existing rights of way,” the Acadia Center wrote in a recent blog post. “Each ACP that fails to maximize the capacity of existing transmission represents a lost opportunity to prepare New England to meet the projected doubling of the region’s peak demand.”
Connecticut 2034 Needs Assessment
Sarah Lamotte, transmission planning engineer at ISO-NE, presented the results from ISO-NE’s Connecticut 2034 Needs Assessment, which is intended to “identify the time-sensitive and non-time-sensitive needs in the study area.”
The study identified time-sensitive minimum load needs at 21 of the 115-kV buses, and 27 of the 345-kV buses in the region.
Lamotte said the study considered non-transmission solutions and found they would not alleviate the time-sensitive issues. She said ISO-NE plans to initiate a solutions study in the second quarter of 2025 to address the identified needs.
Boston 2033 Solutions Study
Aqeel Ahmed, associated engineer at ISO-NE, presented the preliminary results of the RTO’s Boston 2033 Solution Study, which is intended to address time-sensitive, minimum-load, high-voltage needs.
The preferred solution identified includes the installation of a 115-kV reactor and protection systems upgrades at five substations. The projected cost is $26 million.
