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April 18, 2025

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FERC, NERC Say Grid Winter Recommendations Working

The U.S. electric grid and natural gas system performed well during the cold weather events of January despite record cold temperatures across much of the Southeast, FERC and NERC staff said at the commission’s open meeting on April 17.

Low temperatures blanketed the South in waves from Jan. 3-24, separated into discrete events later dubbed winter storms Blair, Cora, Demi and Enzo. Cities as far south as Louisiana reported extreme low temperatures, with New Orleans hitting 26 degrees F on Jan. 22, while cities across the South also broke snowfall records.

Despite the severe cold, NERC and FERC reported in February that no “major [grid] incidents” occurred, and the grid was also free of “major fuel system disruptions.” The commission and the ERO announced a joint review of the grid’s performance to determine the impact of the electric and gas industries’ winter preparation activities, including changes since the winter storms of 2021 and 2022, and “additional opportunities to enhance winter operations.” (See FERC, NERC Praise Grid Performance in Cold Snap.)

Presenting the results of that review, NERC Manager of Event Analysis Matt Lewis said the U.S. “set winter records in electric demand and natural gas consumption” from Jan. 19-24, with 678 GW generated at the peak hour of 8-9 a.m. EST Jan. 22. PJM, MISO South, VACAR South (a subregion of SERC comprising parts of North and South Carolina) and the Tennessee Valley Authority all set winter peak demand records as well.

Natural gas accounted for the largest share of electric generation during this period, with 291 GW generated during the peak hour. This amounted to 43% of all generation, more than the 19% from coal and 14% from nuclear combined, and contributed to gas consumption reaching 150 Bcf/day from Jan. 21-22. Gas took the same share of generation in the other two 2025 winter events.

Jan. 22 also saw the number of coincident incremental unplanned generator outages across the Texas and Eastern Interconnections peak at 71,022 MW. The largest share of unplanned outages at this time occurred in MISO, with more than 17,000 MW out of service, which was also the highest number of unplanned outages for any electric entity across the two interconnections.

Lewis observed that both interconnections have experienced higher amounts of unplanned generator outages before: The Eastern Interconnection lost 90,500 MW of generation during Winter Storm Elliott of 2022 and Texas lost 34,290 MW during 2021’s Winter Storm Uri. No manual load shed was required as a result of the generator outages.

Cumulative incremental unplanned generator outages in the Eastern and Texas Interconnections from Jan. 3-24. | FERC

Electric entities “reported better internal and external communication compared to prior winter storms” during the 2025 events, the joint report said. Calls between reliability coordinators (RCs) also “played a crucial role in preparing for extreme weather” before the storms.

“The Southeastern RC began such calls … five days prior to each of the January 2025 arctic events,” FERC and NERC said in the report. “In the SERC footprint, calls occurred daily to provide heightened situational awareness … as a direct result of lessons learned from Winter Storm Elliott. SPP noted that enhanced coordination calls with neighboring reliability coordinators provided critical insights into how the … arctic events were impacting the grid, addressed anticipated resource constraints and identified tight operational periods.”

‘We Had No Load Sheds’

Preparations before the storms were extensive, with multiple entities “declaring conservative operations earlier than in past events to defer, recall or cancel planned transmission outages to reduce grid congestion and enhance transfer capability.” Such actions included TVA and MISO returning key transmission lines to service.

Coordination between the gas and electric industries also improved from previous winter events. FERC and NERC noted that natural gas pipelines “regularly hold customer and stakeholder meetings entering the winter seasons,” and in some cases increase the frequency of their coordination phone calls ahead of storms. The report said MISO, TVA and PJM have all worked to build relationships with gas pipelines. TVA credited such relations for enabling it to procure gas needed during the Martin Luther King, Jr. holiday weekend.

Staff credited electric and gas operators with implementing many of the recommendations made after previous extreme winter events for improvements in areas such as generator weatherization, communication and coordination, operations staffing and resource availability risk assessments. Robert Clark of FERC’s Office of Electric Reliability noted that electric generators have shared their burn profiles with gas pipelines, which allows the gas providers to prepare for “the influx of gas that’s going to be needed to meet that demand.”

The report’s authors urged the electric and gas industries to continue implementing the recommendations made in previous winter storm reports, noting that mechanical and electrical generator outages remain “a critical and persistent gap,” accounting for more than half of generator outages with a reported outage cause in the January events. They warned that this trend could point to a “systemic vulnerability … that has yet to be fully addressed.”

FERC Chair Mark Christie thanked FERC and NERC staff for their work on the report, which he said shows the value of the commission and ERO’s work.

“I think it really illustrates … not [in] theory, but real life, the critical role that FERC plays and NERC plays in making the grid more reliable,” Christie said. “Because here is the proof: We had no load sheds. Think about that — we had no load sheds last winter in these storms, and then compare the load sheds that we had in Uri. … It shows you that we can make the grid more reliable.”

In a statement, NERC CEO Jim Robb agreed the report shows progress but that more work remains to be done.

“It’s great to see both electric and gas industries find ways to lean into extreme events like we saw with these winter storms,” Robb said. “As these kinds of events become more frequent, it’s important to codify what works and include that information into performance expectations for both sectors.”

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GCPA Hears Different Tales on Texas Load Growth from 2 CEOs

HOUSTON — Two power industry CEOs at the Gulf Coast Power Association’s spring conference offered two different takes on ERCOT load growth over the rest of the decade — and how the sector should deal with a potential doubling of peak demand by 2031. (See ERCOT: 60 GW in Additional Demand by 2031.) 

“Everything’s bigger in Texas — but is it really that big?” Calpine CEO Andrew Novotny said at the event April 16. “Just a couple weeks ago, we were dealing with a pretty large ERCOT load forecast that was calling for more than 60,000 MW of growth. As of … really just last week … that 60,000 MW was turned into more than 100,000 MW of forecasted demand between now and 2030.” 

Those numbers are creating a lot of angst in an industry that has dealt with steady load growth for decades, but not a more than doubling of demand in five years, he added. 

Part of that forecast is 13 GW of hydrogen electrolyzers, which were already running into major cost issues before the election scrambled federal support for clean fuel solutions, Novotny said. An additional 9 GW was for cryptocurrency mining facilities, which, like hydrogen electrolyzers, would represent price-responsive demand and not have major impacts on the market’s peak. 

“We need to get more transparency in certain data, but they’re all curtailing anytime the price takes over $200,” Novotny said. “Bitcoin is soaking up the cheap wind and solar that exists and curtailing, providing their power back to the grid anytime the grid needs it.” 

The biggest chunk of the forecast is 70 GW of new data centers, compared with fewer than 3 GW of data centers in Texas today. That would lead to $2 trillion of investment in the state over five years. 

“I think it’s impossible because it’s more than two times the amount of chips that Nvidia is expected to make over the next three years,” Novotny said. 

The Nvidia GB 200 chips cost $70,000 apiece and are needed for the artificial intelligence applications driving the data center boom. One of those chips uses the same amount of power as two-and-a-half average Texas homes, Novotny said. 

If Nvidia can double its growth rate, it will sell enough chips in the next three years that, with associated cooling demand, they will require 34 GW to operate. That could increase to 49 GW by 2030, which would be short of the 70 GW projected for Texas — an outlook that doesn’t consider other data center markets that also are projecting huge growth. 

To be included in the forecasts, many of the planned data centers need little more than certification from a corporate officer at the company constructing them, which requires a deposit of several million dollars — a drop in the bucket, given that the industry could spend $300 billion. 

“If we go after this hard as Texas, we can probably get somewhere between [5,000] and 10,000 megs of these things by 2030,” Novotny said. “So a number like 7,000 MW seems like a good midpoint guess to make. But I mean, aren’t we scared to even get that? I mean, how much resource adequacy challenge will we have?” 

Markets That Work

AlphaGen Chair Curt Morgan, who was once CEO of Texas’ largest generator, Vistra Energy, later that day offered a more cautionary — but bullish — view, colored by a fear of the industry missing out. Morgan came out of retirement because he wanted to participate as the industry dealt with national-scale load growth for the first time in decades. 

“This is the first time in my career I’ve seen a demand-led cycle,” Morgan said. “Usually, it’s an overbuild on the supply side. But my biggest concern right now is that if we get this wrong, then the [data center- and manufacturing-led] growth coming to this country is going to find a home somewhere else.” 

The power sector can meet the challenge, Morgan said, but worried it will not unless competitive markets send the right price signals. 

“We need markets that work, and we need the courage of our elected officials and our regulators to put a market system in place and let it work,” he added. 

The evidence from the Texas Energy Fund does not bode well for new builds, as the repeated exits from that program — which offers government subsidies for dispatchable power plants — show that many do not see enough revenues from ERCOT’s market to support the buildout. (See 2 More Projects Fall out of TEF Loan Program.)  

That kind of buildout has been done before, given that the construction of the entire power grid was supported by the balance sheet of large industrial customers who were its largest users. 

“Now we’re talking about data center growth, and the people who are going to benefit from data centers have to put their balance sheet out there to support power growth,” Morgan said. “They can’t sit it out.” 

Calpine CEO Andrew Novotny addresses GCPA on April 16. | © RTO Insider 

Morgan said he tells people he gets paid to be paranoid and right now he is worried the industry is going to miss the huge opportunity in front of it. 

“I’m really concerned because not everybody’s on the same page and there are politics being played,” Morgan said. “And I understand it, you know; it’s just going to be an expensive buildout.” 

The big tech firms that are driving the data center boom need to help because the cost shifts to other consumers would otherwise become politically infeasible, meaning the country misses out on the economic opportunity, he added. 

Markets have overseen huge resource expansions in the past, including the combined cycle boom at the dawn of electricity sector restructuring, which quickly turned into a bust and a wave of independent power producer (IPP) bankruptcies. 

“Every single publicly traded IPP in this country went in and out of bankruptcy,” Morgan said. “Not one penny of those bankruptcy costs was ever borne by a captive ratepayer. The shareholders paid for that. To me, that is the essence of competition.” 

‘Shark-infested Waters’

Some want to get away from that model and are using prospective demand growth as a reason to push for utility-owned generation in states that have banned it for decades, Morgan said.  

Utilities can often still set up competitive subsidiaries that sell generation in the states where they operate, but they would rather put the risk of new power plants on the backs of consumers in rate base, he said. (See Utilities Pushing for Return to Owning Generation in Pennsylvania.) 

“That’s a chicken-you-know-what,” Morgan said, avoiding the expletive. “Come in here, into the shark-infested waters, and figure out how to make it work just like we are. And I’ll tell you, if we get into a situation where we start to bifurcate markets, it’ll never win. I’ll tell you why, because you’ll have retirements that will always outstrip new build, and you’ll just make a bad situation worse.” 

When it comes to Texas, Morgan said the ERCOT market needs to send price signals that support more dispatchable generation that will be needed to meet the growing demand. Capacity markets are a third rail in Texas, but some kind of price signal through ancillary services could work. 

“Markets will overbuild themselves if they believe that there’s a reasonable chance of getting return on investment and they can trust that the market scheme is going to stay the same year after year,” Morgan said. “If they think it’s going to change on them, then markets will not invest.” 

After Winter Storm Uri, the PUC cut ERCOT’s price cap down to $5,000/MWh but ordered more frequent triggering of scarcity pricing and implantation of real-time co-optimization of energy and ancillary services. Those efforts have not worked, especially with the looming need to meet data center demand, Morgan said. 

“I think we need to have something that provides the chance for people to get a return of and on their investment,” Morgan said. “We need to leave it in place. We have to have the courage to trust that it’s going to happen. If we do that, there is a ton of capital out there right now that would love to find a home and support this demand buildout.” 

Another needed regulatory fix involves the natural gas industry, which is going to become more important going forward. Morgan said. 

“I don’t think there’s a regulatory body that really holds anybody’s feet to the fire on the gas side of the business,” he said. 

The Texas gas industry suffered outages during Uri and, like the power industry, does not want to see a repeat, but regulation of its interstate pipelines is very light, he noted.  

Regulators, including FERC, have taken a more laissez faire approach to that industry, and that has its advantages, but in Texas, it is less regulation and more “advocacy,” he said 

“Nobody even batted an eye when we went from less than $3 to $300 gas during Uri,” Morgan said. “‘Ah, that’s just how that market works.’ I mean, that excuse was $8 billion of money that was basically sent through the [local delivery companies] for gas charges that occurred during Uri … and they securitized it and are paying it off over a 20-year period.” 

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Christie Blasts PJM Pursuit of Transource Market Efficiency Project

FERC Chair Mark Christie on April 17 criticized PJM for continuing to consider proceeding with Transource Energy’s Independence Energy Connection (IEC) transmission project years after Pennsylvania regulators denied it a certificate of public convenience and need.

Christie’s comments came in his concurrence with a commission order dismissing as moot a PJM request to waive its deadline to complete an annual reevaluation of the project (ER25-612).

Should Transource “and PJM succeed in persuading a federal court that the mere selection of a transmission project planned by PJM acts to preempt the states’ CPCN laws — a position vigorously opposed by all the states as expressed by the National Association of Regulatory Utility Commissioners — such a ruling will likely be a Pyrrhic victory of monumental proportions,” Christie wrote. “Such an outcome will tell the states, which retain the authority under their inherent police powers to decide whether to allow their utilities to join, not join or leave RTOs, that the rules of the game have been changed radically after the fact — without the states’ agreement and, as the history recounted herein shows, contrary to earlier pledges to respect state laws. So perhaps state perspectives on RTO membership for their utilities should be reconsidered.”

PJM filed the waiver request in November 2024 to ask the commission to allow it to complete its annual reevaluation of the project in the third quarter of 2025, stating that its market efficiency modeling could not be complete until reliability violations had been resolved in the 2024 Regional Transmission Expansion Plan (RTEP).

In December 2023, a federal court ruled that the Pennsylvania Public Utility Commission had violated the U.S. Constitution, finding that the denial was based on economic protectionism rather than siting. The court said PJM must complete a new cost-benefit analysis before the project can proceed. (See Federal Court Rules in Favor of Transource Congestion Project in PJM.)

In the absence of a FERC order Dec. 20, 2024 — PJM’s requested effective date for the waiver request — the RTO proceeded with completing the reevaluation with the same modeling used in the 2023 evaluation, resulting in the same benefit-to-cost ratio of 0.81 as the earlier analysis. That ratio was 1.09 when sunk costs were excluded. In a presentation to the Transmission Expansion Advisory Committee in January, PJM said that using older data could mask impacts affecting the project.

“Significant impacts may be presently and temporarily masked by reliability and other issues which are being addressed by RTEP projects that are expected to be approved in first quarter of 2025,” PJM said.

Comments opposing the waiver request contested the benefits of the project and argued that PJM had not followed its tariff requirements. They argued PJM staff should have recommended that its Board of Managers cancel the project or have considered it canceled when the PUC denied the CPCN for construction.

The commission ruled that PJM’s completion of the reevaluation with “the presently available model” rendered the request moot.

First approved by the PJM board in August 2016, the project includes two 230-kV lines across the border between Pennsylvania and Maryland. It has been suspended since September 2021 after the PUC’s denial. The Maryland Public Service Commission approved the segments of the project running through its state in June 2020 and has issued repeated extensions on deadlines for construction to start as the litigation proceeded.

Christie Argues Ignoring CPCN Denial Would Undermine State Authority

In his concurrence, Christie wrote that it is “remarkable” that the issue was brought before the commission four years after the PUC denied the CPCN for the project.

The idea that PJM planning supersedes state siting authority could undermine states’ ability to require utilities to obtain CPCNs for any projects if they remain RTO members, Christie argued.

“The claim that, because PJM and other RTOs are federally regulated, the inclusion of a PJM-planned transmission project in PJM’s RTEP effectively preempts a state’s inherent police power authority to approve that and other utility projects within its borders is, frankly, outrageous. FERC Order No. 1000, which set up the entire regional planning regime under which PJM and other RTOs now operate, said the opposite,” he wrote.

He linked the possible impact to state jurisdiction to his longstanding opposition to incentives awarded to utilities that join RTOs, saying that awarding developers construction work in progress incentives for projects included in PJM’s RTEP, but which are suspended or have been denied CPCNs, inflates consumer rates. He compared the continuation of the IEC project to PJM’s abandoned Potomac-Appalachian Transmission Highline project, which he said cost consumers a quarter billion dollars with no construction ever commencing. (See Christie Blasts FERC Transmission Incentives in PATH, Brandon Shores Orders.)

“As transmission costs rise rapidly in PJM, as well as in all other RTOs, it is past time for this commission to fulfill its duty to ensure ‘just and reasonable rates’ under the Federal Power Act by protecting consumers from the costs of FERC’s own policies that are inflating those rapidly rising transmission costs,” Christie wrote. “And to be more specific, as the debate continues over whether to give transmission developers/owners a perpetual [return on equity] adder for joining an RTO, the history recited herein is extremely relevant. History matters.”

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SunZia Gets Mixed Decision on Tariff

FERC on April 17 approved the non-rate terms of SunZia Transmission’s proposed transmission owner tariff but sent the tariff’s non-subscriber usage rate to a settlement process and potential hearing (ER25-170). 

Pattern Energy is developing the SunZia transmission line, a 552-mile, 500-kV DC line that will carry wind power from New Mexico into Arizona. The SunZia line, with a planned capacity of 3,021 MW, is expected to begin operations in 2026. 

SunZia plans to join CAISO’s balancing authority area as a subscriber participating transmission owner (PTO). The subscriber PTO model allows transmission developers to join CAISO without the transmission project being selected through CAISO’s transmission planning process.  

Developers of subscriber PTO projects are responsible for funding the transmission project, rather than recovering their transmission revenue requirement through CAISO’s transmission access charge (TAC). FERC approved the subscriber PTO model in March 2024. (See CAISO Wins FERC Approval for Subscriber-funded Tx Plan.) 

In the case of SunZia, the transmission system’s existing capacity has been committed to Pattern subsidiary SunZia Wind, which has entitlements with Salt River Project, Western Area Power Administration and Tucson Electric Power to send its wind power beyond SunZia Transmission’s Pinal Central terminus to Palo Verde, which connects with the CAISO system. 

In the subscriber PTO model, transmission capacity not used by subscribers is available to CAISO market participants. CAISO will pay the subscriber PTO for that usage based on a non-subscriber usage rate (NSUR). 

The NSUR in SunZia’s proposed tariff drew protests from a group of utilities — Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric — as well as from a group of six California cities.  

One complaint about SunZia’s proposed NSUR was that it was developed using the Appalachian methodology, which came from a 1987 FERC case involving Appalachian Power Co. As described by FERC, the methodology is “premised on the assumption that a customer using the transmission system for the 16 peak hours of the day should pay the same contribution to fixed costs as a customer who has reserved capacity on a daily basis.” 

The protesters also said SunZia hadn’t provided support for an annual escalation factor of 0.5%. 

While FERC found the escalation factor to be just and reasonable, it shared the protesters’ concerns about use of the Appalachian methodology in calculating the NSUR. 

Under FERC’s order, the chief judge will appoint a settlement judge within 45 days and a settlement conference will be held to try to resolve the NSUR matter. If a settlement can’t be reached, the issue will go to an evidentiary hearing. 

Expedited Action Requested

SunZia initially filed the proposed transmission owner tariff Oct. 21, 2024, and a month later asked for a decision by Dec. 21. 

Citing its obligation to investors, lenders and customers, SunZia Transmission filed a renewed request for expedited treatment March 14, asking FERC to issue an order by April 30. 

“If the commission does not provide expedited action, SunZia Transmission will be forced to divert its resources to an alternative plan that would require it to form its own balancing authority area (“BAA”) rather than joining CAISO’s BAA,” SunZia said in the filing. 

Forming its own BAA would take several months and require “a significant commitment of resources” from SunZia, NERC and WECC, the filing said. 

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CAISO Issues ‘Expedited’ Plan for Allocating EDAM Congestion Revenues

CAISO on April 17 released a draft final proposal detailing how its Extended Day-Ahead Market (EDAM) will allocate congestion revenues in circumstances when a transmission constraint in one balancing authority area produces “parallel” flows — with resulting transmission congestion — in a neighboring BAA also participating in the market. 

The draft proposal is the product of an “expedited” stakeholder process the ISO kicked off in March to address concerns among some Western electricity market participants that EDAM would leave some non-CAISO participants exposed to congestion charges for constraints occurring outside their systems, while not providing them the ability to adequately recover or hedge against the charges. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.) 

“This proposal for parallel flow congestion revenue allocation is an initial step toward continued evolution of the overall congestion revenue allocation design informed by market operational experience and stakeholder input,” CAISO said in the proposal. 

Vancouver, Canada-based electricity trader Powerex first called attention to the issue in a February paper contending that EDAM’s handling of congestion revenues represented a “design flaw,” which the company identified after reviewing PacifiCorp’s proposed revisions to its open access transmission tariff intended to accommodate its participation in the market, scheduled to begin in 2026. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

Powerex is a firm OATT rights holder in PacifiCorp’s system, and it argued that any such transmission customer stands to lose value in its contracts under the arrangement. 

Seeking Balance

CAISO said its draft proposal seeks to strike a balance between EDAM’s existing FERC-approved rules related to congestion revenues and the alternative scheme it floated in the issue paper kicking off its expedited stakeholder initiative. 

Under EDAM’s existing rules, congestion revenues are allocated to the BAA containing a constraint, with the operator of that BAA allowed to sub-allocate any revenue it receives from the ISO to transmission customers according to the procedure outlined in that BAA’s OATT. 

“This congestion allocation method recognizes that the balancing area where the internal transmission constraint is located bears the effects of that congestion and the reliability impacts associated with the constraint, and thus congestion revenues accruing across the interconnected EDAM footprint associated are allocated fully to the EDAM balancing area where the constraint is located,” CAISO notes in its proposal. 

The ISO said many stakeholders “saw merit” in the existing design but “also recognized the concerns expressed with parallel flow congestion revenue allocation” and the need to develop a new “transitional” approach for allocating revenues “to support the ability to more readily protect or manage congestion cost exposure for OATT transmission rights holders.” 

But stakeholders also expressed concerns about the potential alternative outlined in the issue paper, which proposed to allocate congestion revenues only to the BAA in which the revenues accrued, not to the neighboring area where the constraint was located. Some commenters thought the alternative went too far in reallocating the revenues, while others worried the approach could increase incentives for some transmission users to self-schedule generation to gain a more complete hedge, which would reduce the efficiency of market operations. 

CAISO said its proposed design instead “leverages elements of the transitional alternative introduced in the issue paper and retains aspects of the current, FERC-approved, design to congestion revenue allocation; i.e., it is incremental to the underlying congestion revenue allocation methodology.” 

Under the draft final proposal, parallel flow congestion revenues collected in an EDAM BAA that result from a binding constraint in a neighboring area will first be allocated to the BAA in which the overflow congestion occurs — and the revenues are collected. That will enable that BAA to distribute funds to firm OATT transmission rights holders who possess long-term and monthly point-to-point (PTP) and network integration transmission service (NITS) rights and have submitted “day-ahead balanced source/sink schedules.” 

“Consistent with the existing EDAM design, transmission customers will register their firm PTP and NITS transmission rights, with the market operator identifying the nature of the rights from source to sink. These registered transmission rights will be associated with a contract reference number, which, when included in the bid submission, associates that bid with existing OATT transmission rights,” the proposal states. 

The plan also stipulates that any remaining congestion revenues associated with the parallel flows would be allocated to the EDAM BAA in which the constraint occurred. 

“This aspect of the design mitigates the concerns expressed by stakeholders that, under the transitional alternative described in the issue paper, balancing areas may be exposed to congestion costs (negative congestion revenues) associated with parallel flow effects when generation in the balancing area provides counter flow benefit to the direction of the transmission constraint located in a neighboring balancing area,” according to the proposal. 

Additionally, EDAM would continue to allocate any congestion revenues that accrue within the BAA containing the constraint to that BAA, “consistent with the FERC-approved EDAM framework.” 

Acknowledging “the complexity of the overall topic of congestion revenue accrual and allocation,” the proposal provides multiple illustrated examples of how the plan would work in practice. 

‘Guns Blazing’

CAISO is moving quickly to wrap up the congestion revenue allocation proposal in time for a vote next month by its Board of Governors and the Western Energy Markets (WEM) Governing Body. 

WEM stakeholders appear to largely on board with the ISO’s sense of urgency. 

During an April 9 meeting of the WEM Regional Issues Forum (RIF) in Portland, Ore., representatives from most RIF sectors cited congestion revenue allocation as CAISO’s top priority right now, at the forefront of other issues the ISO will need to address to ensure a smooth launch of EDAM in 2026. 

“We support moving quickly in the congestion revenue allocation initiative,” Vijay Singh, senior organized markets analyst at PacifiCorp, said on behalf of the RIF’s EDAM sector. PacifiCorp will be the first utility to begin participating in the EDAM next spring. 

“We were really ready to come in guns blazing and go after the ISO for not doing more on congestion, but we really got to commend the ISO for kicking off the process and looking to go to the Board of Governors by May,” Avangrid’s Scott Olson said for the Independent Power Producers and Marketers sector. 

The Bonneville Power Administration’s Allie Mace, RIF liaison for the Power Marketing Administration sector, also commended CAISO for moving on the issue, but she noted the “transitional” nature of the proposed solution and encouraged the ISO to include an initiative for longer-term solutions in its policy initiative road map. 

CAISO will hold a stakeholder meeting to discuss the draft final proposal April 23. 

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ISO-NE Prepares Expedited Filing After Ruling on Order 2023 Compliance

The NEPOOL Transmission and Markets Committees voted April 17 to support an ISO-NE proposal to adjust several key dates and deadlines in its compliance proposal for FERC Order 2023, which the commission approved April 4. The committees also voted to support an amendment by RENEW Northeast to extend the deadline for late-stage projects to complete their system impact studies (SISs).

FERC’s ruling accepting ISO-NE’s Order 2023 compliance filing did not alter the RTO’s proposed timeline for its transition process, which includes dates and deadlines that have passed and no longer are viable. (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.) To amend these issues, ISO-NE plans to file “narrowly tailored tariff revisions to only adjust transition related dates in the compliance proposal by approximately one year.”

These changes would allow the RTO to align its transitional capacity network resource (CNR) group study with the 2025 Interim Reconfiguration Auction Qualification Process — a necessary step to run the CNR study in 2025 — and start the transitional cluster study (TCS) in October.

The transitional CNR study is intended to enable interconnection customers with complete SISs to achieve capacity interconnection rights, while the TCS will be open to all other projects with valid interconnection requests. ISO-NE will use the results of the CNR study as an input to the TCS.

The RTO plans to make a Section 205 filing with the timeline changes “immediately following the May 2025 Participants Committee meeting, and request a next day effective date for the revisions to adjust the dates,” said Alex Rost, director of transmission services at ISO-NE.

Rost said ISO-NE has closed the queue again after opening it briefly on April 1 and noted that only resources with valid interconnection requests as of June 13, 2024, will be eligible to enter the TCS. The next opportunity for resources to enter the interconnection queue will be the initial cluster request window, which will open after ISO-NE completes the TCS. If the TCS begins in October 2025, the queue would be slated to reopen in late 2026.

Because the new interconnection rules already are in place — and technically took effect Aug. 12, 2024, despite FERC not ruling until April 4, 2025 — ISO-NE has stopped work on all ongoing interconnection studies under the prior rules, Rost said. He noted that “any on-hand deposits associated with an [interconnection request] that is eligible for the transition can be applied to transition studies.”

He said ISO-NE will honor any SISs completed between the official effective date and the date ISO-NE received the ruling, as these studies were completed under the rules that were in place at the time.

Abigail Krich of Boreas Renewables, speaking on behalf of RENEW Northeast, proposed to amend the expedited filing to allow late-stage requests to continue their SISs until Aug. 29, 2025.

“The only component of the ISO’s originally proposed transition that they do not propose to shift forward by [about] one year is the late-stage SIS completion deadline,” Krich wrote in a memo prior to the meeting. She noted that ISO-NE initially proposed to continue working on late-stage SISs through Aug. 30, 2024.

Krich said late-stage projects already could have spent “on the order of $250,000” on interconnection studies, which would be invalidated if the studies are not completed prior to the TCS. She said there appears to be 10 or fewer projects that could be eligible for this late-stage treatment.

“These [interconnection requests] remain eligible to enter the TCS this fall, but doing so will cost them more money, delay their interconnection and put them at risk of larger withdrawal penalties,” Krich said. She added that completing the system impact studies for as many projects as possible prior to the TCS would reduce the size, complexity and withdrawal risks of the study.

“Continuing work on the few interconnection requests that would potentially be identified as ‘late-stage’ would be a relatively small amount of work for the ISO’s interconnection team and should not take away from the ability to implement the remainder of the Order 2023 transition,” Krich added.

Developers with late-stage interconnection requests have expressed a strong interest in continuing their studies and argued it is in the region’s best interest to complete these studies to help bring new resources online as quickly as possible.

ISO-NE expressed concern about potential issues associated with reintroducing the old interconnection rules for late-stage requests, and that incorporating RENEW’s proposal into its filing could complicate the approval of its proposed timing changes.

The committee voted to support both RENEW’s amendment and ISO-NE’s proposal without the amendment. ISO-NE said it will consider its options before bringing the proposal to the NEPOOL Participants Committee on May 1.

ISO-NE also plans to work with stakeholders to make a second filing to address the series of relatively minor issues that FERC identified with its Order 2023 compliance proposal. This filing is due in early June.

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NJ Gov. Urges FERC to Investigate PJM; Christie and Phillips Defend PJM

New Jersey Gov. Phil Murphy (D) is asking FERC to investigate “potential market manipulations” in the PJM Base Residual Auction (BRA) in July 2024 that state officials say contributed to a 20% hike in electricity rates in New Jersey. 

Murphy, in a letter to FERC commissioners, said he had “deep concerns about the PJM cost crisis.” He said he believes the “exorbitant price increases” in PJM’s July auction “may have been subject to market manipulation.” 

FERC Chairman Mark Christie defended PJM staff in comments at the monthly FERC meeting April 17. 

“A lot of this criticism that I’ve been seeing in the media, directed at PJM and its management, and blaming them for everything that is wrong with the PJM capacity market, is in many ways misplaced,” he said. “And a lot of it is because of state policies that have sort of come to a head just recently.” 

Christie particularly cited the work of outgoing PJM CEO Manu Asthana and other PJM executives. (See PJM CEO Manu Asthana Announces Year-end Resignation.)  

“Manu had the unlucky job of coming in when a lot of factors that were put in play 20 years ago sort of started to come to a head,” Christie said. “These factors, such as the big increase in load that we’ve been seeing in the last few years, the loss of resources has been ongoing for years, and all this sort of came to a head. But he has done, I think, an outstanding job. I’ve always found him to be very, very straightforward and open in dealing with me.” 

Commissioner Willie Phillips agreed with Christie. “I want to echo the comments you made about Manu and PJM leadership. I think what you said was spot on and very well said.” 

Asked whether FERC would launch an investigation, Christie said he had to be careful about commenting because the commission has pending cases dealing with the high prices from the last capacity auction. But he noted he has been a skeptic/critic of the capacity market construct since it first was launched. 

“I think that a lot of the problems that PJM is facing today are the result of trends that have been going on for 21 years,” Christie said. “And again, I’m a fact-witness to that. I’ve been there, and I think a lot of decisions were made years ago that are now showing up and causing problems for a lot of the states that are complaining the most. One of the biggest problems, I think, was 20 some years ago. They made a decision to use the PJM capacity market as their mandatory sole source of resource adequacy, and so that put them at the mercy of the PJM capacity market.” 

Many of the member states have pointed the finger solely at PJM for those problems, but Christie argued some of their state policies are to blame as well. FERC is holding a two-day technical conference in June to look at resource adequacy, where the issues will be discussed. 

Gov. Murphy’s letter urged FERC to “determine the extent to which any such manipulation may have resulted in higher capacity auction prices that are being passed on to retail electricity customers in the PJM market, particularly in New Jersey.”  

“I believe that billions of dollars in excessive costs for [consumers] are the direct result of fundamental flaws in PJM’s capacity market and were foreseeable and preventable,” the letter said. 

In response, PJM released a statement that said the organization “has not seen evidence that supports a finding of market manipulation in the 2025/26 capacity auction, but we take such allegations very seriously.” FERC’s Office of Enforcement “is the right place to address such a concern, and PJM will follow any directives we receive from FERC,” the statement said. 

“New Jersey has insufficient generation in-state to meet its needs, and has to make up this difference through imports,” said the statement, released by spokesman Jeffrey Shields. “A seven-year-long effort by New Jersey to fill this gap with offshore wind has failed to deliver any results whatsoever, and consumers are now paying the price for this failure.” 

Murphy’s statement marks a new stage in the friction between PJM and New Jersey and other states over the rapidly increasing cost of electricity and the region’s ability to generate enough power in the future. 

New Jersey and Maryland officials on April 16 attended a press conference for the release of a report by Evergreen Collaborative, a national environmental group that promotes solutions to climate change. The report predicted a 60% hike in electricity rates unless PJM takes steps to reform the process by which new clean energy sources are added. (See NJ, Md. Officials Target PJM After Critical Report.)  

Pennsylvania in January filed a complaint with FERC about PJM, which resulted in the RTO’s agreement to cap future auctions’ capacity prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

New Jersey’s draft master plan, released March 13, predicts demand for electricity will increase by 66% by 2050, and state officials are concerned about how they will meet that need. (See NJ Releases Electrification-focused Energy Master Plan.) 

PJM says the expected shortfall in power is in part due to the slow pace of new energy sources coming online compared to the far faster pace at which older generating sources — mainly fossil-fueled sources — are going offline, often in line with state policies. In addition, PJM says the region can expect an influx of high-energy-using entities, especially artificial intelligence data centers. 

New Jersey, and other states, say PJM has failed to plan for the surge and the problem is exacerbated by the slow pace at which the agency approves new energy sources, especially renewable energy sources. 

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Data Centers’ Reliability Impacts Examined at FERC Meeting

Sudden trips offline by data centers in Virginia and cryptominers in ERCOT present new reliability challenges that must be managed, NERC Chief Engineer Mark Lauby told FERC at its monthly open meeting April 17.

The grid in Loudoun County, Va., home to the largest concentration of data centers in the world, was experiencing some voltage sensitivities last summer, Lauby testified.

“In July 2024 we saw about a 1,500-MW drop as a result of some system conditions — in this case, switching after a fault on the system,” Lauby said. “And within 50 seconds, three of those voltage excursions occurred, and the load is monitoring that, and when it sees that happen, it comes offline because it wants to protect its cooling load.”

NERC released a report on the incident in January that details the grid conditions before and after the data center load went offline. (See NERC Report Highlights Data Center Load Loss Issues.)

A similar event happened in Loudoun and neighboring Fairfax County, where 1,800 MW of load suddenly dropped off the system. Lauby said while that is still being investigated, he suspects it will be similar to the July 2024 incident.

Texas has seen more frequent but smaller events as grid conditions have caused cryptocurrency mining facilities to trip offline 25 times between November 2023 and this January, leading to 100 to 400 MW of losses in each incident.

“Historically, if we lose generators, it can trip off the grid,” FERC Chair Mark Christie said during the meeting. “Now we’ve got another issue, which is if large load users simultaneously go off together, it affects the frequency and potentially trips off the whole system.”

The grid can be engineered to avoid those cascading outages across multiple data centers to avoid a situation where the grid’s largest single contingency comes from demand (as opposed to a large power plant or transmission line), Lauby said.

“That comes down to engineering, modeling and continuing to work with the industry — in this case, the large load industry and the power industry — to see how we manage that interconnection,” he added.

NERC is considering rule changes to deal with the newfound risk, which is going to be exacerbated as individual data centers’ load grows to the size of major cities. The grid has dealt with large industrial facilities at 100 to 200 MW for decades, but some of the proposals for large data centers run to thousands of megawatts, which compares to the total loads of San Francisco or D.C. in a single place, Lauby told FERC.

“We need to, obviously, make sure that’s managed well, and the engineering is done to ensure that we minimize the chances for things to happen,” he added.

NERC stood up a Large Loads Task Force in 2024 that is expected to issue papers and guidelines to address the risks associated with the issue. The ERO is also working on industry guidance on large loads, incorporating work from the task force.

Part of that analysis is to determine how to register the loads, either by requiring the customers themselves to register with NERC, or if that is not legally feasible, then getting their load-serving entities to do it for them, Lauby said. Then once the facilities are registered, NERC will craft reliability standards so that the chances of such incidents are minimized.

“Large numbers actually really scare me; the potential reliability impact of these drops sound pretty severe,” Commissioner Judy Chang said.

Modeling can help NERC secure the grid against uncontrollable outages of data centers; Chang asked what kind of data are needed to effectuate that.

Losing 1,500 MW of load is akin to one and a half large nuclear units tripping offline, but the grid has reserves that can maintain reliability in such cases, Lauby replied. NERC has the authority to get data from the industry under the Federal Power Act.

“For the loads, they’ve just been good enough to work with us,” Lauby said. “And, so, is that going to be good for the long term? Probably not … [it’s] something we need to think about.”

Large loads tripping offline is one part of the reliability equation when it comes to data centers, with the other key part being meeting their demand with an adequate supply of resources, Lauby said.

“The definition of reliability is adequacy and operation reliability,” he said. “So, we’ve got both problems.”

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CAISO Pauses Study of New Market Run Proposal for Gas Resources

CAISO on April 16 sidelined a proposal to provide an additional market run for gas resources due to a lack of information on the subject and a need for operational experience with the ISO’s Extended Day-Ahead Market (EDAM).  

The proposed new market run, known as D+1.5, would occur between CAISO’s two-day-ahead market run, D+2, and day-ahead market run. D+1.5 would provide a better estimate of next-day markets as a potential to reduce reliability concerns, said NV Energy, a stakeholder in CAISO’s Gas Resource Management Working Group. 

Currently, CAISO uses two two-day-ahead market processes: D+2 and the residual unit commitment (RUC) look-ahead advisory. Stakeholders raised concerns about the RUC’s timing and forecasting accuracy and said there is a general “lack of confidence” using such information to inform fuel procurement decisions, per CAISO’s latest issue paper on the subject, published in January. 

D+1.5 could provide new information to participants that was not available in time for the D+2 but becomes available and accessible to CAISO. For example, scheduling coordinators could submit new or updated bids, informed by the next-day gas day trading activity, into the day-ahead market to inform the D+1.5, the paper says. 

However, to provide a D+1.5 market run, CAISO would need to establish a new process to collect gas trading data and run new forecasts. If not, D+1.5 would use the same forecasting information already used by the market processes on the trade day. Adding new forecasting services would increase vendor and personnel costs to monitor and maintain the new forecasting suite, the paper says.  

The “highest-priority scope item” for CAISO’s Gas Resource Management Working Group is to provide more market information to participants prior to the day-ahead market to support fuel procurement, the paper says. But the value of a new market run “must be weighed against the cost of gathering new information, running the optimization and validating a new stream of market results made available to market participants,” the paper says. 

“While we support the continued consideration of this new market run, we think it should be after we complete an assessment of D+2 and have some operational experience with EDAM and the new D+2 market run,” Sylvie Spewak, CAISO senior policy developer, said at the April 16 working group meeting. “At this time, we don’t intend on including the D+1.5 proposal in this upcoming straw proposal in detail. Let us know if you disagree with this approach.” 

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FERC Upholds Preliminary Permit for Pumped Hydro Concept

FERC has upheld the fourth preliminary permit (P-15332) granted in three decades for a pumped hydro concept in southeastern Pennsylvania. 

FERC in November 2024 granted a 48-month preliminary permit to York Energy Storage LLC for an 858-MW facility along the Susquehanna River near Lancaster and York that could produce 1.5 million MWh per year. 

Environmental advocates, local governments and other interested parties protested and requested a rehearing. 

FERC’s April 17 order shot down the various arguments they submitted with their request. 

The ruling states that concerns raised about the potential impact of the YES project — should it be built — are speculative and premature; one of the purposes of a preliminary permit is to give the permittee a chance to determine the potential impacts and design the project to avoid or mitigate them. 

Issuance of a preliminary permit also does not require a finding of public interest or a balancing of interests, FERC wrote; licensing, construction and operation of the YES project might cause environmental and other impacts, but preliminary licensing would not. 

FERC also rejected the contention that it should have found YES unfit for a preliminary permit for reasons including that it is a paper entity, has not demonstrated how it will fund its activities and has a history of noncompliance. FERC wrote that its past practice does not dictate a financial review for a preliminary permit, and that YES has no history of serious violations of hydropower licenses. 

Finally, FERC rejected the argument that it had violated the Federal Power Act by granting multiple preliminary permits for the same project, three of them to entities with a common principal. 

FERC issued two to Mid-Atlantic Energy Engineers LTD in the 1990s and one to Cuffs Run Pumped Storage LLC in 2011. But FERC said in its April 17 order that even if it treated Mid-Atlantic as the same entity as YES, more than 20 years separated the permits, so it is reasonable to treat the YES request as a new application rather than a successive application. 

The issues raised in the rehearing request are speculative, the order reads.  

It concludes: “We continue to find that it is in the public interest to consider such impacts at the licensing stage, when such impacts are more defined, after York Energy has completed preliminary study, thereby resulting in a more accurate and complete record, and that declining to issue a preliminary permit based on speculative impacts or incomplete impacts is not appropriate at this stage of potential development.”