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February 24, 2025

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Incumbent Utilities Make Case for ROFR Laws in New Report

A band of incumbent utilities has collected case studies that they say demonstrate the need to instate or maintain right-of-first-refusal laws for the good of grid expansion.

The Developers Advocating Transmission Advancements (DATA) — comprising Ameren, Eversource Energy, Exelon, ITC Holdings, National Grid USA and Xcel Energy — released a white paper Feb. 5 faulting FERC’s Order 1000 and solicitation processes for hindering more effective grid expansion.

Competitive bidding “isn’t compatible with what’s needed now,” ITC Director of Federal Affairs Devin McMackin said in an interview with RTO Insider. “We think it’s well established now that the cost benefits of competitive bidding haven’t materialized. It creates more litigation than it does transmission.”

On the other hand, McMackin said the ROFR is “a model that we know works.”

The report, “Recent Experience with Competitive Transmission Projects and Solicitations,” emphasizes four recent project scenarios from MISO, PJM, CAISO and New England that DATA says put the flaws of competitive processes on display.

The group said a competitive bidding and selection process can fail to take full projects costs into account; fail to “right-size” projects; fail to consider the feasibility of siting and routing proposals; and can come equipped with “illusory” cost caps.

“Order No. 1000 policy has created the incentive for developers to relentlessly argue over the right to build projects, fostering uncertainty that is to the detriment of actual infrastructure development,” DATA wrote. It argued that competitive solicitations have not resulted in benefits, instead contributing to a development environment rife with “litigation and administrative challenges, protracted solicitation processes and re-scoping of projects” — all without “demonstrated countervailing benefit to consumers.”

“There remains no evidence that FERC’s competitive transmission policy has improved the process of developing needed transmission infrastructure. Instead, there is an ever growing body of evidence that reform is needed,” the group said.

MISO

In MISO, DATA said ongoing uncertainty over Iowa’s ROFR law placed 447 miles of planned 345-kV circuits at a temporary standstill. The $2.1 billion worth of lines originate from the RTO’s first long-range transmission plan (LRTP) approved in 2022.

At first, MISO automatically assigned the lines to ITC Midwest and MidAmerican Energy, but in late 2023, a state court struck down the law in a case brought by competitive developer LS Power. (See Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.) Appeals from the incumbents and the Iowa attorney general are pending. After conducting a variance analysis, MISO reaffirmed the lines should continue to be developed by ITC and MidAmerican.

DATA said litigation over Iowa’s ROFR could have an “adverse, cascading effect” on MISO’s first LRTP projects and delay economic and reliability benefits. Rather than reduce costs, Order 1000 has “created the incentive for competitive developers to fight a constant and multifront battle for the opportunity to develop transmission projects, even if the result is to the detriment of actual infrastructure development,” it said.

LS Power also has filed a complaint with FERC against MISO for effectively ignoring a preliminary injunction against Indiana’s ROFR law. The company argued it is being denied the opportunity to bid on about $1 billion in LRTP projects. (See LS Power Files Complaint Against MISO over Indiana ROFR.)

McMackin said once grid planners go through the “arduous” process of assembling a transmission portfolio, the last thing anyone wants is to spend years deciding which developer should build it.

McMackin said the certainty ROFRs deliver is evident in MISO, where long-range transmission projects in states with such laws move straight to development, while projects in non-ROFR states are ushered through yearslong solicitation processes.

“States without ROFRs won’t even get bids out for two years,” McMackin said, adding that DATA’s “core contention is that ROFR is pro-transmission policy.”

PJM

Competitive processes, DATA said, can have planners selecting projects that are not the best in the long term or the most cost-effective.

DATA singled out the $513 million, 500-kV MidAtlantic Resiliency Link (MARL), which PJM awarded to NextEra Energy in Window 3 of its 2022 Regional Transmission Expansion Plan. NextEra was tasked with routing the project through the notoriously difficult-to-site Loudoun County, Va., in the Dominion zone. The company initially used Google Maps to chart an ultimately infeasible corridor and skipped deeper routing analyses. Eventually, Exelon and FirstEnergy assisted with an alternative route and construction on their existing rights of way, and NextEra and PJM agreed to cancel a portion of the project in favor of incumbent utilities building sections. PJM’s Board of Managers approved the changes to the project in 2024, at a net increase in costs.

DATA said NextEra’s bid on MARL shows how developers can submit “unsophisticated and incomplete proposals” to an “artificially constrained assessment.” It said competitive bidders don’t instinctively reach out to other utilities for the type of collaboration that might come naturally to incumbent developers.

“Challenges with siting transmission … along the initial MARL route should not have been a surprise to NextEra, or to PJM,” DATA wrote. “We will never know if a project collaboratively developed by incumbent utilities in the first instance would have avoided the increased cost or identified a superior, more holistic, more robust solution.”

New England

DATA also pointed to the $2.78 billion, 345-kV Aroostook Renewable Gateway project in Northern Maine that the Public Utilities Commission awarded in 2022 and subsequently withdrew because selected developer LS Power announced it would exceed its original fixed-price bid.

The PUC since has initiated a new docket to contemplate an alternative project and developer.

DATA said hard cost caps are ill suited for the “development challenges and commercial realities of electric transmission,” which include long lead times, high capital costs and regulatory hurdles, among other cost pressures.

CAISO

Finally, DATA called out two HVDC transmission projects in the San Francisco South Bay region — Newark-to-Northern Receiving Station and Metcalf-to-San Jose B — from CAISO’s 2021/22 transmission plan, also awarded to LS Power.

According to the report, when significant load growth entered the picture and brought hypothetical overloads with the original design, CAISO was forced to modify the Newark project into a 230-kV switchyard and a 230-kV AC circuit. CAISO said it will set apart a San Jose B substation expansion as part of the project for incumbent Pacific Gas and Electric instead of allowing LS Power to build a new station to avoid building duplicative substations on scarce land.

CAISO also must include a new Northern Receiving Station-to-San Jose B circuit that is set to be awarded through bidding later this year.

DATA said CAISO’s convoluted rescoping and involvement of new developers on the project shows how competitive processes can “lead to fractured and inferior planning outcomes that fail to make project selections accounting for the full costs that will be borne by customers and do not maximize or ‘right-size’ the value of solutions to meet immediate and future needs.”

‘Unintended Consequences’

What the case studies “collectively demonstrate is … a full range of unintended consequences,” McMackin said. Competitive developers may make “routing choices that might not be compatible with the project with the expectation that it can all be renegotiated later.”

As of publication time, LS Power did not respond to RTO Insider’s request for comment on whether it believes the shift in projects can be construed as misfires, or whether it views its litigation as postponing transmission construction.

The Electricity Transmission Competition Coalition (ETCC) recently renewed its argument that monopoly incumbents continue to price gouge. It noted that according to the U.S. Bureau of Labor Statistics’ Consumer Price Index Summary for January, annual electricity price inflation climbed at four times the rate of the average U.S. grocery bill.

ETCC maintains MISO ratepayers could save several million dollars if all projects in its second, nearly $22 billion LRTP portfolio are competitively bid.

Two months ago, MISO was compelled to conduct a variance analysis on one of the LRTP projects from its first portfolio following a more than 2.5 times cost increase in the project under incumbent Northern Indiana Public Service Co. The planned 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana climbed from an estimated $261 million to $675 million. (See Cost Overruns on Project in 1st LRTP Prompt MISO Analysis.)

‘Meeting the Moment’

McMackin characterized DATA’s members as investor-owned utilities that are supportive of regional transmission. They are “deeply engaged” in building the grids that can “meet the moment” of demand growth from artificial intelligence, electrification and decarbonization.

“Right now, what’s best for customers is getting transmission built,” McMackin said.

He acknowledged it is natural that incumbent utilities would want project opportunities.

“I think that’s a fair question that goes to motivation,” he said. But he said ROFRs have “strong track records of working,” having been the default before Order 1000. He argued ROFRs are needed to “reestablish certainty to get infrastructure built expeditiously.”

McMackin recognized that getting transmission built is complicated and challenging.

“We do not make the claim that incumbent developers don’t encounter the same challenges that non-incumbent developers do, because developing large-scale transmission is hard. And it’s hard across the board,” McMackin said. However, he said non-incumbent development of projects more routinely results in “cost escalations beyond what’s expected.”

“Non-incumbent development has a host of issues,” he said, adding that he expects the issues to escalate with FERC’s Order 1920. “To the extent that there’s not ROFR certainty from FERC, there will be more examples.”

DATA would like to see FERC reopen the ROFR topic so the group can share the “data we now have about how this process is working,” McMackin said. “We need more federal certainty on the issue.”

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NYISO Liaison Subcommittee Briefs: Feb. 11, 2025

ISO Still Working on Trump Tariff Clarity

NYISO still is looking for clarification on President Donald Trump’s pending 10% tariff on energy imports, Joe Oates, chairman of NYISO’s Board of Directors, told the Liaison Subcommittee.  

The Board of Directors “has authorized [NYISO] to seek any tariff authority necessary to comply with legal obligations that may be imposed on it,” Oates said. “Management is working through these issues internally and with members of the ISO/RTO community,” and with FERC. (See NYISO Assessing Impact of Trump’s Canada Tariff on Electricity Market.) 

Oates said the ISO would address the issue in detail with stakeholders Feb. 25. He also said the ISO had not yet received any guidance from “anyone down in D.C,” as Kevin Lang, representing New York City, put it. 

Clean Path

Oates told the subcommittee the board approved the changes to the 2025 Project Grant Plan, specifically approving the removal of its initiative to develop market participation rules for internal controllable lines. 

This was done because of the New York Power Authority’s proposed changes to the Clean Path NY transmission project. (See NYPA Files Petition with New York PSC to Save Clean Path Project.) 

“We remain ready to support the project in the future once updated details and plans are available,” Oates said.  

A representative from NYPA thanked the ISO for its continued support of the project.  

Cybersecurity Updates

Oates said NYISO successfully completed its triennial critical infrastructure audit by the Northeast Power Coordinating Council. The ISO scored “excellent,” and there were no areas of concern. 

NYISO also continues to monitor cybersecurity developments with respect to “nation-state threat actors and global attack campaigns.” The ISO is implementing “three micro segmentation enforcement environments” within its networks to prevent persistent threats. Oates said this was a key element of the “zero trust” cybersecurity strategy the ISO was implementing. 

The subcommittee receiving a classified briefing late in 2024 on Volt Typhoon, a Chinese state-sponsored hacking group. The Cybersecurity and Infrastructure Security Agency has warned that China has sponsored persistent intrusions into critical infrastructure. (See CISA Leader Reiterates China Cyber Warnings.) 

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Pathways ‘Step 2’ Plan Elicits Praise, Concerns — and Advice

A recent workshop on the West-Wide Governance Pathways Initiative has sparked praise for the proposal as well as concerns, including uneasiness over plans to share staffing between CAISO and a new regional organization that would govern Western electricity markets. 

“Shared staffing could lead to undue influence over governance decisions and compromise the impartiality needed for effective oversight and market rule promulgation and implementation,” Rob Creager, executive director of the Wyoming Energy Authority, said in a letter to the California Energy Commission.  

Even if the arrangement is temporary as part of Pathways Step 2, it could have long-term impacts and “create a precedent for the market operation moving forward,” Creager wrote.  

The letter was one of several submitted as a follow-up to a CEC workshop Jan. 24 on regional electricity markets and coordination, including the Pathways Initiative. (See CEC Workshop to Focus on Impact of Pathways Initiative; Ariz. Commissioner Questions Utility Decisions to Join SPP’s Markets+.) 

Pathways proposes to create a new independent “regional organization” (RO) to govern rules for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).  

The move could alleviate concerns of potential participants who are uncomfortable with markets led by CAISO, whose Board of Governors members are appointed by the California governor. 

Pathways backers are waiting for a bill to be introduced in the California legislature that would allow a change to CAISO’s governance with the introduction of the RO. 

The International Brotherhood of Electrical Workers, which opposed previous efforts to “regionalize” CAISO, plans to sponsor the bill, an IBEW representative said in October. The deadline for introducing bills this session is Feb. 21. (See California Labor, (Possibly) Public Power to Sponsor Pathways Legislation.) 

While the potential legislation has garnered support, including from some past opponents, Creager pointed out it’s typical for bills to be revised as they move through the legislature. He recommended stakeholders clearly state what they want in the bill — as well as what they don’t want — “to ensure true political independence of the RO is established and to ensure any market designs and market rules are fair and transparent.” 

WEA was formed in 2020 when the Wyoming State Energy Office merged with the Wyoming Infrastructure Authority and the Wyoming Pipeline Authority. Creager noted that Wyoming was the largest electricity exporter in the Western Interconnection as of 2023. 

EDAM vs. Markets+

While acknowledging the competition between CAISO’s Extended Day Ahead Market and SPP’s Markets+, Creager said WEA realizes that “with PacifiCorp’s long-term participation in the WEIM and first-mover to commit to the EDAM, combined with Black Hills Energy’s (dba Cheyenne Light, Fuel & Power) decision to join the WEIM, Wyoming’s attention will be more focused on the evolution of CAISO’s market offerings with the potential to expand to a RO.” 

In August, two Black Hills Energy subsidiaries serving parts of Montana, Wyoming and South Dakota announced their move from SPP’s Western Energy Imbalance Service (WEIS) to CAISO’s WEIM. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.) 

Other stakeholders who submitted letters to the CEC commended the Pathways Initiative. 

Leanne Bober, director of regulatory affairs for the California Community Choice Association, said CalCCA supports Pathways because of its potential to “capture reliability, affordability and environmental benefits of regional coordination.”  

Pathways continues the incremental approach to regional coordination that has been working well for the region so far, Bober wrote, pointing to CAISO’s WEIM and soon-to-be-implemented EDAM as examples. 

Shifting energy market governance to an RO with board members from across the West “will promote trust across Western entities, attract a diverse range of potential regional market participants and maximize the potential benefits of a regional market,” Bober said. 

Adam Smith, director of regulatory relations at Southern California Edison, also wrote in support of Pathways. 

“Independent governance is crucial for greater regional market integration,” Smith wrote. The Pathways Initiative “has now provided a clear proposal for implementing such governance.” 

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NEPOOL Markets Committee Briefs: Feb. 11, 2025

Resource Retirement Changes

ISO-NE continued discussions with stakeholders on its capacity auction reform project at the NEPOOL Markets Committee (MC) meeting Feb. 11, providing more information on planned changes to the resource retirement process.

The RTO plans to decouple the retirement process from its capacity market as it works to reduce the time between auctions and capacity commitment periods (CCPs). Under current procedures, resources signal their plans to retire through the forward capacity auction process, about four years before their actual retirement.

ISO-NE proposes to require resources to give a two-year advance notification of their plans to retire for a given CCP. The reduced timeline is intended to give resources more clarity around the economics that motivate retirement decisions, while still providing enough time to conduct market power and reliability analyses, deploy transmission solutions if needed and enable market participants to respond. (See ISO-NE Introduces Proposed Resource Retirement Changes.)

While the two-year notification timeline would not provide enough time to develop long lead-time resources, some resources, including batteries and demand response, likely could be developed in this period, said Kevin Coopey, principal analyst at ISO-NE.

“If a market response takes longer than two years, the notification lead time will reduce the gap between when the deactivation occurs and when the market responds,” Coopey said.

ISO-NE plans for retirement submissions — including retirement dates — to be binding. This is intended to preserve the market signal sent by retirements and prevent resources from “fishing” for reliability retention contracts, Coopey said. He added that allowing withdrawals could unintentionally create “incentives for resources to ‘test’ if they can get away with exercising market power with limited repercussions.”

The RTO plans to discuss reliability reviews for deactivation requests at the MC in March.

FERC Order 904

ISO-NE opted to delay a planned vote on compliance with FERC Order 904, which prohibits transmission providers from compensating generators for reactive power within the standard power factor range.

The standard power factor range is defined as “the power factor range set forth in the generating facility’s interconnection agreement when the unit is online and synchronized to the transmission system,” FERC wrote in the order.

Prior to the order, the RTO unsuccessfully argued the commission should let it maintain its procedures for compensating reactive resources.

To comply with the order, ISO-NE proposes to eliminate its volt ampere reactive capacity cost compensation program. The compliance proposal would not change compensation for resources following ISO-NE dispatch instructions, the RTO noted.

Multiple stakeholders expressed concern that the compliance proposal is too broad and argued the RTO should continue compensating resources for reactive power outside of the standard range. Responding to the concerns, ISO-NE delayed the vote until Feb. 27, when it will hold a joint meeting of the MC and the Transmission Committee.

The compliance filing is due on March 27; ISO-NE proposes for the changes to take effect on June 1.

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Type One, TVA to Cooperate on Fusion Plant

Another target is set for commercial nuclear fusion power: The Tennessee Valley Authority and Type One Energy have a cooperative agreement for a potential commercial plant. 

TVA and Type One announced Feb. 11 that the project could go online as early as the mid-2030s. 

This would put it slightly behind another effort — Commonwealth Fusion Systems’ collaboration with Dominion Energy, which aims to get the world’s first commercial fusion reactor online by the early 2030s in Virginia. (See Oklo, Commonwealth Fusion Unveil Ambitious Nuclear Plans.) 

The commercially viable fusion reactor is a goal that has eluded researchers for decades but that still is being pursued closely: The analytics firm ABI Research recently calculated third-quarter 2024 investment in fusion at a record $7 billion. 

Type One’s agreement with TVA calls for “Infinity Two,” a 350-MWe pilot fusion plant, to provide base load generation for the Tennessee Valley region, potentially repurposing retired TVA fossil-burning power plant infrastructure. 

It expands on Project Infinity, which was announced in early 2024 and calls for a prototype “Infinity One” reactor to be placed at the site of TVA’s Bull Run Fossil Plant, an 865-MW coal-fired facility retired in late 2023. 

Type One and TVA said in a news release they will collaborate on siting studies, environmental reviews, licensing and financing for Infinity Two. 

Also, TVA’s Power Service Shops in Alabama will assist Type One as it shapes its supply chain and develops modular manufacturing and assembly techniques. TVA in turn will “benefit from the subsequent scaling of fusion energy on a global basis, following the successful deployment of Infinity Two.” 

Type One CEO Christofer Mowry said the agreement allows his company to use TVA’s existing infrastructure and expertise rather than duplicating it as it goes through phases of research and development. 

“Instead, we can focus on completing the design of Infinity Two and testing it with the Infinity One prototype in TVA’s Bull Run plant. The ability for us to focus on developing and delivering the core stellarator technology materially derisks our path to fusion power plant commercialization.” 

Also Feb. 11, Commonwealth Fusion and Type One announced a licensing agreement for Type One to use Commonwealth Fusion’s high-temperature superconducting cable technology in development of its fusion magnets. 

Both companies have first-to-market aspirations, but with different reactors. Commonwealth Fusion is developing a tokamak reactor, and Type One is going with the more complex stellarator design. 

They said in a news release their agreement has benefits beyond the Infinity Two project: It gives Commonwealth Fusion a new market for its cable technology and gives Type One access to demonstrated background technologies and capabilities. 

As with the TVA agreement, the deal saves Type One the time, risk and expense of re-creating what Commonwealth Fusion already has. 

Commonwealth Fusion CEO Bob Mumgaard said this would accelerate Type One’s development efforts. 

“At CFS, we are confident in our approach using magnetic confinement in tokamaks, but we also want to support companies pursuing other promising magnetic confinement applications given the scale necessary to address the urgent transition to fusion energy and the transformative nature of high-field magnets,” he added. 

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NASEO Panel Explores Coordinated Planning to Meet Demand Growth

WASHINGTON — The U.S. electric power industry faces unprecedented challenges from the size, pace and impacts of demand growth and should look to new approaches for possible solutions, according to speakers at the National Association of State Energy Officials’ Energy Policy Outlook Conference on Feb. 5.

“There’s not a one-size-fits-all solution for dealing with data centers or load growth in general,” said Paul Spitsen, energy technology specialist in the U.S. Department of Energy’s Office of Strategic Programs. “You’re really going to need to take a portfolio approach, depending upon what your objectives are and what resources you have.”

Speaking on a panel on leveraging demand growth to meet state energy goals, Spitsen called for “better productive planning to minimize the buildout.”

“How do we speed up interconnection for both the end-use customer, as well as the generators that are coming online? How do we think about new financing structures to mitigate risk for all the different customer types? How do we get up to a secure supply chain?”

Such a portfolio of strategies also should move toward integrated, regional planning, said Joe Paladino, a senior adviser at DOE’s Office of Electricity. “The current institutional processes we have in place are not integrated enough for us to be able to work collectively together to really figure out what the grid investment strategy should be.

“Where we need to really head is … to enable coordinated planning across jurisdictions, from community- and customer-based systems to distribution systems to regional systems,” he said. “A key element within that is an integrated distribution planning process.”

Paladino also argued for “coordinated operations, because now, with all the myriad players that are starting to play together regionally … we have to actually start thinking about how to coordinate our operations. Grid operations work in the millisecond time frame; so, we’re going to have to understand what the latency of the information flow has to be in the system” and what kind of distributed intelligence will be needed.

Offering a real-life case study, Carl Mas — vice president for policy, analysis and research at the New York State Energy Research and Development Authority — said the state is working to develop a more coordinated approach to grid planning. (See New York Orders Utilities to Join in Proactive Grid Planning.)

NYSERDA is collaborating with NYISO, the New York Public Service Commission and other agencies on “a core, high capacity-expansion modeling and scenario-driven approach,” Mas said. “We have a lot of uncertainty in what those large loads will be. We have uncertainty as to the types of resources; so, we’re going to do a multi-scenario approach where we bring together our utilities, our ISO planners and our state planners.

“We build a database of what are the possible futures. We then take it down to each utility, analyzing their local assessment of how it can be met. We review those local solutions and then bring it back up to a least-cost planning assessment.”

An immediate challenge is that computer tools for joint optimization of local and bulk power systems are being developed at the National Renewable Energy Laboratory but don’t yet exist, he said.

NYSERDA does have an electric system infrastructure assessment tool, which provides information for “folks who are looking to site grid-edge technologies like solar, like battery storage, to be able to see where is the headroom in the system; where there is existing solar and existing storage,” Mas said.

The agency also is looking to develop “geographically specific planning tools” for local communities and even for individual buildings and lots, producing data that then can be integrated into state and regional planning, he said.

Electric, Gas Integration

In his keynote presentation at the NASEO conference, NERC CEO Jim Robb provided an overview of the ERO’s most recent long-term reliability assessment and the 132 GW of new power that, he said, will be needed over the next 10 years. (See NERC Warns Challenges ‘Mounting’ in Coming Decade.)

“A gigawatt is a load about the size of the city of San Francisco,” Robb said. “So … we’re talking about adding like 130 mid-sized cities to the country over the next 10 years.”

Taking into account the time it takes to permit generation and transmission, “about half of the country over the course of the next five years [is] at elevated risk of electricity shortfalls,” an unprecedented level of risk, Robb said. The country needs to get major amounts of new generation online “very, very quickly,” as well as the transmission required to get power to demand centers.

NERC CEO Jim Robb | © RTO Insider LLC

And because most of the projects in RTO and ISO interconnection queues are renewables — solar, wind and storage — Robb favors natural gas generation to balance the grid. But he cautioned that deregulation and restructuring of both sectors took place in “a very, very different world than what we’re in right now.”

The electric and natural gas systems need to be viewed as “a much more integrated system. Securing balancing resources is going to be really, really critical,” he said.

Citing a recent study from the Lawrence Berkeley National Laboratory, Spitsen’s estimate for demand growth was slightly less than Robb’s — 128 GW — but Spitsen stressed that data centers were not the only drivers for new generation, pointing to manufacturing, transportation and building electrification, and even oil and gas production.

“We also have extreme weather conditions across the entire country, which drive up electricity demand, and the point I want to make really is that this is going to require a kind of paradigm of transformation … [for] the utility sector and also the regulatory sector.”

The LBNL report projected that by 2028, data centers and artificial intelligence could account for as much as 12% of U.S. electricity demand.

Spitsen also said that demand from data centers will vary, from huge hyperscale centers to small enterprise systems, “and each of these different types of data centers and the different processes they have changes both the size of our load, but also the temporal profile as well.”

Freeze Update

The challenges ahead for state energy officials are shrouded in uncertainty as President Donald Trump and Energy Secretary Chris Wright push for a wholesale retreat from the climate and clean electricity goals of the Biden administration. (See DOE Official to NASEO: ‘There is not an Energy Transition’.)

The status of federal funds from the Inflation Reduction Act and Infrastructure Investment and Jobs Act has remained in flux. In a Feb. 10 order, Judge John J. McConnell Jr., of the U.S. District Court for Rhode Island, found that the White House has not fully complied with his previous temporary restraining order and stated that the administration must restore paused federal dollars as long as the order is in force.

McConnell’s order, in response to a lawsuit filed by state attorneys general, was separate from that of D.C. District Court Judge Loren AliKhan, who also issued a restraining order on the White House in a case brought by several groups, led by the National Council of Nonprofits. (See Judge Issues Restraining Order on Trump Admin over Funding Pause.)

“The states have presented evidence in this motion that the defendants in some cases have continued to improperly freeze federal funds and refused to resume disbursement of appropriated federal funds,” McConnell wrote. “The broad categorical and sweeping freeze of federal funds is, as the court found, likely unconstitutional and has caused and continues to cause irreparable harm to a vast portion of this country.”

In his first speech to DOE staff on Feb. 5, Wright did not mention renewables, energy efficiency or demand management as tools for meeting demand growth and the need for more energy in the U.S.

In contrast, Spitsen pitched the role of flexibility, including energy efficiency, in meeting demand growth, calling it “one of the untapped things we have to look forward to. But … how do you tap that? Is it a price-responsive flexibility? Is it more a centralized, control-based flexibility?”

“It’s really hard to ascertain, looking at the future, who can be flexible, who can’t, how that might change over time as their own processes and technologies change,” he said. “But it is really important. It’s a level we need to think about … to plan for.”

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PJM MIC Briefs: Feb. 5, 2025

Expanded Demand Response Modeling Endorsed

PJM’s Market Implementation Committee narrowly endorsed a PJM proposal to use effective load-carrying capability (ELCC) to model the availability of demand response resources in all hours, along with other changes to how DR accreditation is determined.  

The package received 77% support for implementation in the 2027/28 delivery year, which shrunk to 54.3% for implementation in the preceding year, while a third proposal from the Independent Market Monitor received 40.1% support. (See “Discussions Continue on Demand Response Availability Window,” PJM MIC Briefs: Jan. 8, 2025.) 

PJM’s Pat Bruno said the proposal seeks to capture more of the reduction capability DR can provide and apply performance requirements to those hours. Modeling of curtailment capability currently is limited to 6 a.m.-9 p.m. in the winter and 10 a.m.-10 p.m. in the summer, which DR providers argue fails to account for the growth of consumers with flat load profiles and how the DR resources interact overall with reliability risks occurring during a larger number of winter hours. 

Calpine’s David “Scarp” Scarpignato said the proposal would be cutting it too close to the auction. 

“Even if it looks like it’s financially better for us, the disruption is too much. … It’s not that we oppose the proposal; it’s just that there’s a reason there’s pre-auction schedules,” he said. 

Representing DR providers, Bruce Campbell of Campbell Energy Advisors said while he’s sensitive to concerns about uncertainty, the current setup represents a barrier to entry for DR that is excluding resources at a time when PJM says new entry is needed.  

The proposal also would revise how DR resources’ winter peak load (WPL) is determined to be measured fleetwide at a point that aligns capability with identified system risks, in this case the hour ending at 9 a.m. The status quo allows the WPL for individual resources to be measured at their highest output whatever time of day that may be, which Bruno said can result in a fleetwide WPL that never can be achieved. 

When modeling reliability risks under the ELCC framework, the proposal also would create a classwide load profile for DR capability in winter and derate the amount of curtailment expected by hour. Bruno said no change to summer modeling is needed, since reliability risks tend to be concentrated in a few hours correlated with peak loads, whereas winter risk is more diffused. 

Given the short amount of time between the beginning of pre-auction activities for the 2026/27 Base Residual Auction (BRA) and the significant number of market design changes pending at FERC, several stakeholders said PJM instead should target the 2027/28 delivery year, scheduled to be conducted in December. Curtailment service providers countered that some locational deliverability areas (LDAs) cleared short of the reliability requirement in the 2025/26 BRA and there are concerns that could widen in the 2026/27 auction. Expanding the amount of DR considered available could add several gigawatts to the market, they said. 

Bruno said PJM intends to seek same-day endorsement during the Feb. 20 meeting of the Markets and Reliability Committee to allow for the package to be implemented for the 2026/27 delivery year, if stakeholders endorse that alternative. 

The Monitor’s package would base accreditation on historical performance of DR resources akin to how generation is modeled and rated. It also would use ongoing analysis of load data to determine resource WPL and aim to account for the possibility that load may exceed WPL at the time that a performance assessment interval (PAI) is initiated. A separate stakeholder process would be initiated to consider the role DR plays in the capacity market overall. 

PJM Discusses Market Performance During January Winter Storms

Stakeholders said PJM’s markets and operations teams performed well in maintaining reliability during two cold snaps seen in January, but more work is needed to ensure that needs during emergency conditions are reflected in economics. (See “Performance Strong During Record Winter Peak,” PJM MRC/MC Briefs: Jan. 23, 2025.) 

Senior Dispatch Manager Kevin Hatch said forecasts showed significant increases in load as cold weather began Jan. 18, with Jan. 22 setting a new winter peak of 145,060 MW. PJM initiated several emergency procedures ahead of the storms, including the use of conservative operations to commit resources — mainly gas generators — thought to be at risk of underperforming. The RTO added conservative operations to its toolbelt after December 2022’s Winter Storm Elliott, when significant amounts of gas generation failed to perform. Gas operators have sought to lay the blame on how PJM dispatches units and have largely supported the ability to make out-of-market commitments. 

PJM principal fuel supply strategist Brian Fitzpatrick said last month’s Martin Luther King Jr. Day weekend proved to be challenging because of warm weather Friday, Jan. 17, that shifted to a winter storm with subzero temperatures in some regions. Ensuring the availability of gas resources is especially challenging on such weekends since fuel delivery on pipelines tends to be sold in ratable take packages, which can cause generation owners to lose money if gas providers don’t follow through on procurement contracts. 

Constellation Director of Wholesale Market Development Adrien Ford said PJM’s conservative operations declaration resulted in significant uplift payments to generators, creating unhedgeable costs for load-serving entities. PJM’s response to the storm was successful from a reliability perspective, but not economically, she said. 

PJM Senior Director of Market Design Rebecca Carroll said the Reserve Certainty Senior Task Force (RCSTF) is trying to address the fact PJM does not have an in-market way of committing resources under those circumstances. 

First Read on Black Start Compensation Proposals

PJM and the Monitor presented first reads on competing proposals to revise how black start units are compensated under the Base Formula Rate (BFR). (See “PJM Presents Changes to Black Start Compensation,” PJM MIC Briefs: Jan. 8, 2025.) 

The PJM proposal would remove the net cost of new entry (CONE) component of the BFR calculation to instead use a fixed value derived from the average net CONE between 2020 and 2024 with an inflation escalator. The change was spurred by analysis finding that net CONE could fall to zero in some LDAs in the 2026/27 BRA under the shift to a combined cycle reference resource. While PJM has asked FERC to allow it to revert the reference resource back to a dual-fuel combustion turbine, PJM has argued net CONE values could remain low and impact black start compensation. 

The BFR is used to compensate black start units that do not require new capital investments to provide black start service, whereas the Capital Recovery Rate (CRR) is used when upgrades are required. PJM’s Glen Boyle said many resources already providing the service could pull their capability if low net CONE values reduce compensation under the BFR. Requiring new resources to make costly upgrades to provide black start service, such as installing diesel generators, could drive up costs he said. 

Monitor Joe Bowring’s proposal would temporarily pay black start units an RTO-wide net CONE value while stakeholders embark on a long-term effort to untie the BFR from net CONE entirely to instead focus on the ongoing cost to provide the service. 

Bowring has said PJM has acknowledged that net CONE does not relate to black start costs; however, it proposes to arbitrarily create a static value derived from net CONE with an inflation modifier to be the basis of revenues. Rather than changing the rule in an “arbitrary and [illogical] fashion,” he said PJM should let market sellers tell PJM their cost so it can ensure they are compensated with a fair return. 

Issue Charge Seeks to Address Offer Capping Advance Commitments

PJM presented a problem statement and issue charge focused on the potential for market power and manipulation when resources are scheduled in advance of the day-ahead energy market. 

Key work activities (KWAs) include education on how resources are scheduled ahead of the day-ahead market; governing document revisions related to how those units are scheduled; possible market power mitigation protections; and aligning how the process is detailed across the governing documents.  

Two phases are envisioned: the first drafting a proposal on how to select which schedule should be committed in advance of the DA market, and the second focusing on incorporating fuel costs in cost-based offers. Day-ahead and real-time offer capping would be out of the issue charge’s scope. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he finds it troubling PJM has implemented processes detailed in the manuals that are not appropriately defined in the governing documents and is attempting to codify them after the fact. He said the wording of the problem statement also gives the impression there have been specific accusations of market power abuse. 

Other Committee Business

The MIC endorsed by acclamation a second slate of manual revisions conforming to FERC’s order granting PJM’s changes to risk modeling, accreditation and resource testing. The proposed revisions to Manuals 11, 14D, 18 and 28 would rewrite the rules for testing resource capability in summer and winter and operational testing, and also require that dual-fuel generators offer schedules with both fuels into the energy market. 

PJM’s Joseph Tutino presented revisions to Manual 11 drafted through the document’s periodic review. The changes include grammatical and spelling corrections, updating web links and removing outdated references to the day-ahead scheduling reserve. 

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PJM OC Briefs: Feb. 6, 2025

Resource Performance Improves During January Winter Storms

VALLEY FORGE, Pa. — PJM credited emergency procedures with improving generator performance during a pair of winter storms in January, including a new all-time winter peak of 145,060 MW on Jan. 22.

Executive Director of System Operations Dave Souder told the Operating Committee on Feb. 6 that PJM identified as much as 42,687 MW of generation at risk of not being able to perform during the extreme cold days because of a combination of potential start-up and operational issues.

Emergency procedures such as conservative operations allowed dispatchers to schedule units in advance to ensure they were running when cold weather began and to avoid cycling those units on and off if they might have trouble restarting. The conservative operations emergency procedure was established following December 2022’s Winter Storm Elliott.

Tests also were scheduled a week in advance of the storms, with about 20% of tested units running into mechanical issues that largely were able to be resolved before the storms began.

The forced outage rate peaked at 9.24% on Jan. 22, with 16,857 MW offline because of lacking gas for fuel, equipment failures, freezing temperatures and other causes. The forced outage rate during Elliott was 24%, and it was 22% during the 2014 polar vortex.

Souder said PJM continues to refine the risks that are incorporated into its determination of what resources are considered at risk ahead of periods of high system strain. Part of that is the cold weather operating limits created after Elliott, which allow generation owners to report conditions that could impede resource performance.

Senior Vice President of Operations Mike Bryson said generation owners also were more diligent about reporting operating restrictions on their units, giving dispatchers more insight into the status of the fleet and what units were most likely to be available. Generation owners also were forthcoming about how they procure fuel and how their strategies could interact with PJM dispatch instructions. As stakeholders consider changes to the intersection between the electric and gas sectors, Bryson recommended avoiding one-size-fits-all approaches that would not recognize those differences.

“We have probably 40 different flavors, so what was important was for each [generation owner] to tell us what their strategy was,” he said.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the performance data show the idea that gas generation struggles to meet its obligations during winter storms is untrue. He argued that if gas resources had been provided advanced commitments as they had in January, their performance would have been significantly better. He said this raises questions about how gas should be modeled in PJM’s effective load-carrying capability risk modeling and accreditation framework if a significant amount of the class’ risk comes from how it is committed.

Generation forced outage rates during a January winter storm | PJM

“Now that we understand everything, why is gas being punished” for how it was dispatched under a different set of rules? he asked.

Sotkiewicz also said PJM should find a venue where the interactions between market design and dispatcher actions can be discussed. He said the two presentations PJM gave on the storm during the Market Implementation Committee and OC meetings were siloed into each committee’s scope, limiting the ability for stakeholders to have substantive discussion.

“Markets help determine the reliability outcomes … and now we’re separating these two into silos, and I fear we’re going to be losing a lot of details doing that,” he said.

January Operating Metrics

PJM saw an average hourly forecast error rate of 1.67% during January, with two days exceeding the RTO’s 3% peak error benchmark, Marcus Smith, lead engineer for markets coordination, told the OC.

Smith attributed a 3.54% peak load overforecast on Jan. 20 to the impact of the Martin Luther King Jr. Day holiday weekend, and a 3.67% overforecast of the Jan. 28 peak to temperatures being significantly higher than expected.

Winter storms led to several emergency procedures and alerts being declared, including a conservation alert, maximum generation alert, spin event, low voltage alert, six cold weather alerts and six shared reserve events.

The spin event was initiated Jan. 21 at 12:20 a.m. and lasted four minutes and 40 seconds, with 694 MW of generation and 40 MW of demand response being committed. Performance for generation resources was 160% and 139% for DR.

Other Committee Business

Stakeholders endorsed by acclamation revisions to Manual 40: Training and Certification Requirements drafted through the document’s periodic review. The changes include updating references to PJM departments and clarifying that member training liaisons should respond to RTO-initiated data verification requests.

The committee also endorsed by acclamation revisions to Manual 14-D: Generation Operational Requirements conforming to FERC’s order accepting PJM’s generation operational testing requirements (ER24-99). The testing is one component of a larger proposal that came out of the Critical Issue Fast Path process the RTO conducted in 2023.

The revisions allow PJM to initiate two tests each in the summer and winter with the aim of validating that resources are able to operate as needed for reliability. If a resource fails a test, it can be required to undergo a retest, which, if also failed, would subject the unit to a daily generation capacity resource operational test failure charge.

Finally, the OC endorsed by acclamation a proposal to sunset the Data Management Subcommittee and shift its work to a new Modeling Users Forum. PJM’s Jeff Schmitt said the change would allow for a focus on long-term goals and initiatives.

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ERCOT Board of Directors Briefs: Feb. 3-4, 2025

ERCOT CEO Pablo Vegas says the grid operator’s proposal to build more than $30 billion of extra-high-voltage transmission infrastructure is part of a “new era in planning” and just an incremental step from its normal practices. 

Speaking in front of the ISO’s Board of Directors Feb. 4, Vegas said the $33.9 billion and $32.6 billion estimates for 765-kV and 345-kV backbones, respectively, “effectively” amount to about $5 billion a year. 

“Last year, we approved almost $3.8 billion of transmission costs, so it’s a little bit of a step up from what we’re doing,” he said, “but it’s not a radical step up from what we are already used to developing and building here in the ERCOT grid.”

Vegas said the massive buildout, which includes ERCOT’s first foray into 765-kV infrastructure, is necessary to add generation to a grid that is maxed out. The two plans are intended to address industrial and electrification load growth in West Texas’ oil-rich Permian Basin. (See 765-kV Lines in West Texas Inch Closer to Reality.) 

“We see that the current system that we’re operating is really getting close to its full utilization capacity,” he said. “Not only do we see the load growth being very significant, but we have seen the rapid increase in supply … significant growth in solar, significant growth in batteries recently on the grid. That requires transmission to carry that supply and then to the grid.” 

Vegas said the increase in generic transmission constraints (GTCs), which are used to monitor and control flows using market-based mechanisms to maintain stability and other non-thermal reliability limits, is “evidence” of the grid’s full use. 

“[GTCs] have grown over the last several years,” he said. 

ERCOT says its Texas 765-kV Strategic Transmission Expansion Plan will require 1,443 fewer miles of transmission and provide $229 million in annual consumer energy cost savings and $28 million more a year in production cost savings. The EHV lines will increase power transfer capability by 600 MW to 3,000 MW and reduce annual energy losses by 560 GWh. 

The Texas Public Utility Commission last year approved ERCOT’s Permian Basin plan, which includes both the 765-kV and 345-kV plans. The PUC has said it will decide between the two plans and their import paths into the Permian by May 1. (See Texas PUC Approves Permian Reliability Plan.) 

ERCOT also has filed with the PUC a regional transmission plan. 

“765-kV systems have been around for decades, have been used throughout the United States for decades and in other parts of the world,” Vegas said. “There is a robust experience set in the engineering procurement and construction world, as well as a robust supply chain globally to support the infrastructure that’s needed to develop 765. That is something Texas could benefit from when we looked at the comparison for the broader regional transmission plan.” 

SPP earlier in February also approved its first 765-kV project in its history, a $1.69 billion, 293-mile circuit in Southwestern Public Service Co.’s Texas and New Mexico service territory. (See related story, SPP Board Approves 8 Urgent Short-term Projects.) 

Staff Still Looking at Braunig

ERCOT General Counsel Chad Seely told the board that staff still is working to execute a reliability-must-run contract with San Antonio municipality CPS Energy for one of three aging gas plants slated for retirement this year, even as its costs continue to rise. 

Seely said CPS’s original estimated budget for Braunig Unit 3 has risen from $82 million to $93 million due to inspection outage, equipment and compliance costs. (CPS submitted an additional $1.5 million budget increase Feb. 3 as it “fine-tunes” overall labor costs.) The all-in costs, which include an incentive factor and fuel expenses, have gone from $90 million to $105 million. 

“Our analysis still shows that it is cost-effective to move forward with Unit 3 relative to the overall value of lost load from a system-wide perspective if we had to end up in a load-shed situation,” Seely said. 

ERCOT is close to executing an RMR contract with CPS in advance of the inspection outage, scheduled to begin in early March, Seely said. Discussions are ongoing over two addendums addressing CPS’ environmental emissions exceedances and communications and work approvals during the RMR contract’s term. That will start the clock ticking on a 90-day exit plan for Unit 3; staff plan to present the plan to directors during their April 8 meeting.  

Costs for the smaller Braunig units 1 and 2 also have risen slightly to $54 million as submitted by CPS and $60 million for all-in costs. ERCOT is continuing talks with CPS, CenterPoint Energy and LifeCycle Power about using mobile generators as an alternative to RMRs for the other two Braunig units. Units 1 and 2 have a combined maximum summer rating of 392 MW, while Unit 3 has a 412-MW summer rating. 

Seely said ERCOT still believes the LifeCycle mobile generators are the most “cost-effective reliability solution” for Units 1 and 2. He said CenterPoint has indicated it is willing to release the generators to CPS for two years. The Houston utility leased the 15 32-MW generators from LifeCycle for $800 million over eight years. 

LifeCycle has estimated it will cost $26 million to move the generators to San Antonio, while CPS has projected costs of $27 million to connect the units to substations. ERCOT says the cost estimates are subject to change as discussions continue. 

“This whole thing is so wasteful,” Stoic Energy principal Doug Lewin said as he followed the meeting on Substack. “Perhaps [Elon Musk’s Department of Government Efficiency] can look into ERCOT,” he cracked. 

The grid operator has scheduled a special meeting Feb. 25 to discuss the alternative proposal with the board. 

CPS told ERCOT last year it planned to retire the Braunig units, which date to the 1960s, in March. However, the grid operator said the plant’s units were needed to address transmission constraints and congestion in the San Antonio area. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.) 

3 Tx Projects Endorsed

The board approved three Tier 1 reliability projects — those with capital costs over $100 million — previously endorsed by the ISO’s Reliability and Markets Committee (R&M) during its Feb. 3 meeting and the Technical Advisory Committee. The projects, located east and south of Dallas, were submitted by Oncor Electric Delivery and have a combined cost of $380.6 million: 

    • $103.5 million rebuild of a 345/138-kV switch in Forney.
    • $118.9 million reconstruction of 76 miles of 345-kV lines south of Dallas.
    • $158.2 rebuild of 40 miles of 138kV- and 69-kV lines and two 345/138-kV transformers south of Dallas. 

The directors also approved R&M’s recommendation to add ERCOT’s COO (currently Woody Rickerson) as one of the delegates responsible for monitoring and reporting the market’s credit risk to the board, and the ISO’s annual methodologies for determining minimum ancillary services in 2025. The methodology limits the amount of a resource’s responsive reserve service using primary frequency response to 157 MW. 

Board Approves 17 Revision Changes

The directors unanimously approved 11 nodal protocol revision requests (NPRRs), two changes each to the Nodal Operation Guide (NOGRRs) and Planning Guide (PGRRs) and single other binding document (OBDRR) and system change requests (SCR) on their consent agenda:  

    • NPRR1246, NOGRR268, OBDRR052, PGRR118: Inserts terminology associated with energy storage resources (ESRs) in the appropriate places throughout the protocols, aligning provisions and requirements for ESRs with those already in place for generation resources and controllable load resources. This NPRR applies to ESRs in the future single-model era and should be implemented simultaneously with NPRR1014 (BESTF-4 Energy Storage Resource Single Model). 
    • NPRR1243: Revises requirements regarding notice and disclosure of protected information and ERCOT Critical Energy Infrastructure Information (ECEII). 
    • NPRR1250: Updates the protocols to comply with state law retiring the renewable portfolio standard program (ERCOT will continue to administer a voluntary renewable energy credit trading program).
    • NPRR1251: Implements several improvements to the firm fuel supply service’s (FFSS) cost recovery process by clarifying qualified scheduling entities representing FFSS resources are able to accelerate restocking reserved fuel using existing fuel inventories or based on new purchases.
    • NPRR1252: Permits ERCOT to provide ECEII or protected information materials to vendors or prospective vendors without a pre-notice of the provision to a market participant’s vendor or prospective vendor, if they have executed an appropriate confidentiality agreement. The NPRR adds a definition of “ERCOT research and innovation” (R&I) and “ERCOT R&I partner” to clarify notice requirements prior to those entities receiving protected information from ERCOT.
    • NPRR1253: Includes wholesale storage load charging-load to the dataset ERCOT provides through its inter-control center communications protocol.
    • NPRR1257, NOGRR271: Establishes a maximum limit on the amount of responsive reserve that a resource can provide using primary frequency response. Proposes an initial static limit of 157 MW, intended to be reevaluated annually as part of the ancillary services methodology review and approval process.
    • NPRR1258: Removes protocol language duplicative of requirements that are detailed in Management Activities for the ERCOT System and provides model update requirements designed to ensure network data is in common information model format and uses the required naming convention.
    • NPRR1259: Clarifies that retail transaction response timing requirements will not include the duration of a planned and approved ERCOT retail system outage.
    • NPRR1260: Reinstates requirements applicable to controllable load resources that inadvertently were removed during the approval and implementation of NPRR863 (Creation of ERCOT Contingency Reserve Service and Revisions to Responsive Reserve).
    • NPRR1261: Removes references to TAC-approved congestion revenue right (CRR) transaction limits and per-CRR account holder transaction limits, replacing the existing limits with a framework specific to each auction to maximize market bidding and liquidity while minimizing the risk of performance issues and/or triggering a transaction adjustment period.
    • PGRR117: Revises the Planning Guide to reflect the PUC’s rulemaking on certification criteria, which requires the ISO to conduct a biennial assessment of the ERCOT grid’s reliability and resiliency in extreme weather scenarios and recommend transmission projects to address the assessment’s resiliency issues.
    • SCR828: Increases the number of resource certificates permitted for email domains within the Resource Integration and Ongoing Operations system.