The Federal Highway Administration last week announced the suspension of the National Electric Vehicle Infrastructure (NEVI) program.
In a letter to state transportation directors, the administration said the Department of Transportation is rescinding all guidance related to the NEVI program and updating the guidance to “align with current U.S. DOT policy and priorities.” The FHWA said new guidance will be published for public comment in the spring but that “no new obligations may occur” under the existing program.
The $5 billion program was funded by already allocated and approved Bipartisan Infrastructure Law funds. More than $3 billion has already been disbursed.
SCOTUS Won’t Pause California Emissions Case amid Trump Policy Shifts
The U.S. Supreme Court last week declined to place on hold a dispute over California’s standards for vehicle emissions and electric cars even as the Trump administration considers policy shifts that touch upon pending litigation at the high court.
The justices denied the administration’s request to pause further action in the case, as well as two cases concerning which courts may hear challenges to EPA rules. The justices previously agreed to take up the cases but have not yet heard arguments in them.
The justices on Dec. 13 agreed to hear the dispute over California’s vehicle standards, which involves a 2022 exception given to national vehicle emission standards set by the Clean Air Act.
House and Senate Republicans last week introduced legislation to roll back the EPA’s recently finalized fee on methane emissions.
The Waste Emissions Charge was part of the Inflation Reduction Act that Congress passed in 2022 and applies only to large emitters of methane if their emissions exceed certain thresholds.
The Congressional Review Act allows Congress to overturn any regulation finalized within the last 60 days of the previous Congress. If the president agrees with the decision, all it takes is a majority vote in the House and Senate. Any future administration would then be blocked from implementing a new rule that is “substantially the same.”
Lawsuit Filed Against Vistra, PG&E over Moss Landing Fire
Community members last week filed a lawsuit against Vistra, PG&E and other defendants over the Moss Landing battery storage facility fire that occurred Jan. 16.
The civil complaint alleges the burning of lithium-ion batteries caused “the release of massive plumes of smoke, ash and toxic chemicals into the surrounding communities.” The defendants are accused of negligence, reckless, intentional, and/or abnormally dangerous actions and inactions that created conditions to exist that were harmful to health. It also says they failed to implement adequate safety measures despite previous incidents in 2021, 2022 and 2023.
Tesla’s sales in the state fell almost 8% in the fourth quarter and 12% for the year, according to data sourced by the California New Car Dealers Association.
The company also registered fewer cars in all four quarters of 2024, as sales of its second-most important model — the Model 3 — plunged 36% for the year.
Tesla did manage to maintain most of the state’s zero-emission vehicle registrations last year, although its share dropped to 52.5% from 60.1%.
Lamont Gives up on Effort to Phase out Gas Vehicles
After being forced to retreat last year from an effort to phase out sales of new gas-powered cars, Gov. Ned Lamont said he has little desire to resume the fight under the Trump administration.
“I said a year ago, whatever it was, we’re going to follow the federal standards,” Lamont said. “I’m sorry that there probably are no federal standards now.”
Lamont was referring to the fact that the state automatically reverted to federal emissions standards on the sale of new vehicles after lawmakers balked at the idea of following California’s timeline requiring manufacturers to offer only electric and other zero-emission vehicles by 2035.
Utilities Oppose Bill that Would Consolidate Power at PURA
Avangrid and Eversource last week voiced their displeasures with a bill that would shrink the Public Utilities Regulatory Authority to a three-person panel and give it the ability to place cases in the hands of a single commissioner.
The public comments come a week after the utilities filed a lawsuit contending that PURA Chair Marissa Gillett had usurped the power of fellow commissioners by placing herself in charge of hundreds of cases and issuing decisions without a full vote.
The legislation was introduced by Sen. Norm Needleman (D), who said the bill mirrored the language of the law prior to the expansion of PURA’s board from three to five members in 2019.
PUC Approves Rules Restricting Utilities from Passing Lobbying Costs to Customers
The Public Utilities Commission last week voted 3-0 to restrict utilities from passing costs related to political activities, advertising and education initiatives onto customers.
The regulation requires utilities to file annual reports describing their political activities, charitable contributions, educational spending and other similar activities. Utilities also must detail expenses associated with these activities, and the regulation prohibits any utility from providing promotional allowances without first getting PUC approval.
The regulation is based on a law enacted in 2023 by the Legislature and Gov. Janet Mills requiring greater transparency in utilities’ spending on advertising.
National Grid Pulls Plug on Geothermal Pilot Program
National Grid has canceled plans for a project that may have brought geothermal energy to communities in Lowell, citing higher-than-anticipated costs.
The program was one of three pilots across the state testing whether geothermal energy could displace fossil fuels in heating, air conditioning and gas appliances. All three programs were placed in environmental justice communities.
The project’s estimated cost was $15.6 million over five years. National Grid declined to specify how much more the project would have cost.
State Superior Court Judge Douglas Hurd last week dismissed the state’s lawsuit that claimed deceptive actions by oil companies encouraged the unchecked burning of fossil fuels and worsened climate change.
Hurd wrote in his opinion that only federal law can govern the claims made by the state, agreeing with arguments made by the oil companies’ lawyers.
3 FirstEnergy Subsidiaries File Electric Security Plan with PUC
Ohio Edison, The Illuminating Company and Toledo Edison — three FirstEnergy companies — have filed a proposed electric security plan (ESP) with the Public Utilities Commission.
The companies said the ESP supports their commitment to investing in and maintaining the grid while providing customer assistance programs and energy efficiency initiatives. Specifically, this sixth ESP preserves customers’ ability to select their own energy supplier and maintains an auction process to determine the pricing and supply.
If approved, the average residential customer could see an increase of $3.40 (2.7%) on their monthly bill.
A jury last week awarded nearly $50 million in damages to seven survivors of the 2020 Labor Day wildfires.
In financial filings, PacifiCorp executives have estimated that the 2020 and 2022 wildfires have cost the company nearly $2.7 billion. It’s the fourth jury verdict against PacifiCorp. At least eight more trials are scheduled.
PUC Approves Permit for Portion of Big Stone South to Alexandria Tx Line
The Public Utilities Commission has approved a facility permit for the state’s portion of the Big Stone South to Alexandria 345-kV transmission line.
Otter Tail Power Co. and Western Minnesota Municipal Power Agency will co-own the 100-mile line. The companies have also filed a route permit application with the Minnesota Public Utilities Commission for that portion of the project. That decision is expected in mid-2026 with the companies targeting an in-service date by the end of 2030.
Enel North America last week announced its solar-plus-storage facility in Texas is now operational.
The project combines 202 MW of solar capacity with a 104-MW battery storage system.
Enel is among the largest renewable operators in Texas, having around 5 GW of installed wind and solar capacity, along with 1.3 GW of installed battery storage.
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.
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.”
Too many state pension funds are failing to take adequate steps to address climate-related financial risk, said a report released Feb. 10 by the Sierra Club and “Stand.earth.”
The Hidden Risk in State Pensions examined 32 of the largest public pension funds representing $3.8 trillion in assets under management and graded some of them well on climate issues but found that most were not adequately addressing climate change.
Pensions are a key source of capital for asset managers like BlackRock and Brookfield Asset Management, which have invested their money heavily in the power industry through stock purchases and direct infrastructure investments.
“As investors on the longest-term horizons, pensions must read the writing that’s been on the wall for decades: live up to their fiduciary duty, and protect pensioners and climate alike through updated proxy voting guidelines, and voting in line with climate and human rights,” Stand’s Associate Director of Climate Finance Amy Gray said in a statement. “It is disappointing to see so many funds not accessing such a powerful strategy to defend climate and the working-class communities they serve.”
The pension funds were evaluated based on their proxy voting guidelines, which signal investor priorities on corporate governance and direct how a shareholder votes, and proxy voting records in 2024. The votes came from various sectors including financial institutions, automakers, utilities, industry and the consumer sector.
Only one pension got an “A” grade on guidelines — the New York State Common Retirement Fund — while an additional seven from California, Connecticut, Massachusetts, New York and Vermont received “B” grades. Two thirds of the funds analyzed got a “D” or an “F.”
As for actual voting records, eight funds scored an “A,” and they were based in California, Massachusetts, New Jersey, New York, Ohio and Oregon. Pensions in Connecticut and Los Angeles County got “B” grades, while the State of Wisconsin Investment Board and the Washington State Investment Board got “C” grades.
Some of the funds have begun voting for climate-friendly policies, with two issuing new guidelines in 2024 to cover biodiversity, director accountability on climate and human rights.
“While this progress is noteworthy, all the pensions highlighted in this report could do more to shield their beneficiaries from growing climate- and environment-related financial risks,” the report said.
Many pensions might underestimate the financial risks posed by climate change as they rely on models the report criticized as significantly flawed. One study in 2024 estimated that equity valuations could plunge 40 to 50% if emissions are not addressed, which would affect public sector workers’ ability to retire with economic security.
“Pension funds are universal owners, meaning that they have highly diversified and long-term portfolios that are representative of global capital markets,” the report said. “The performance of diversified long-term portfolios is largely driven by the overall growth and stability of the global economy, more so than the fluctuations in the value of various companies and sectors.”
Pensions hold shares for the long term because they need to ensure payments for retirees for decades.
“Only by taking an approach that seeks to mitigate systemic risks and risks to their overall portfolios can long-term and diversified investors, such as pensions, best preserve the value of their investments,” the report said.
Exercising shareholder rights by voting at annual corporate meetings is a way pension funds can influence actions.
“Institutional investors, such as pensions, hold a large number of corporate shares, granting them disproportionate influence over corporate behavior,” the paper said. “This means that how pensions vote on who sits on a company’s boards of directors or on shareholder proposals asking companies to decarbonize will be influential in determining whether or not the world will rein in catastrophic climate and ecological crises.”
Eight pensions in the report operate in states with “anti-ESG” (environment, social and governance) investing principles: Arizona, Florida, Indiana, Missouri, North Carolina, Tennessee, Texas and Virginia. They scored lower than their peers and had fewer guidelines than their counterparts.
While the funds in anti-ESG states scored lower, the report noted that many funds without legal barriers have “minimally better guidelines,” and the non-participation of those two groups limits the effectiveness of shareholder engagement on climate.
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.
Resource Performance Improves During January Winter Storms
VALLEY FORGE, Pa. — PJMcredited 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.
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.
PJM Presents Preliminary Congestion in 2024/25 Base Case
PJM’s Nick Dumitriu presented the Transmission Expansion Advisory Committee with the preliminary 2029 congestion results in the 2024/25 Base Case, which previously had been unable to offer a workable solution without the transmission upgrades included in the first window of the 2024 Regional Transmission Expansion Plan (RTEP).
The final base case and congestion drivers are expected to be published in March, with a long-term market efficiency project proposal window open between April and July. The TEAC and PJM Board of Managers may review any project recommendations to come out of that process toward the end of 2025.
The 345-kV Green Acre-P9701 West and Douglas-Francisco lines saw the greatest amount of annual congestion at $164 million and $107 million, respectively. Around 35 lines were identified with congestion exceeding $1 million annually.
RTEP Changes Include Doubling of Tx Costs for Brandon Shores Deactivation
The network upgrades necessary to allow the deactivation of Talen Energy’s Brandon Shores coal-fired generator outside Baltimore have doubled in cost from $738.83 million to more than $1.513 billion, PJM Director of Transmission Planning Sami Abdulsalam said.
Part of the increase came as more detailed engineering studies were conducted and assessments were made on site conditions. Abdulsalam said an example of that can be seen with the plan to build a new Batavia Road substation, which originally was planned to be air-insulated but has been upgraded to a gas-insulated substation due to limited land and wetlands on site.
Quotes received through the conceptual design phase also tended to be lower than those received once competitive bidding opened and constructability reviews were conducted with the aim of improving right of way access and limiting the potential for cost overruns. Abdulsalam said labor costs for construction and engineering have increased since the project was announced.
The cost of transmission upgrades to interconnect New Jersey’s offshore wind projects under the State Agreement Approach has decreased by $8.2 million with the removal of prebuild extension work, such as duct banks, for four high-voltage direct current lines to each of the converter station areas for the generators.
FirstEnergy has canceled the $37.5 million Whippany–Montville 230-kV line included in PJM’s package of transmission upgrades in the first window for the 2025 RTEP, citing “routing and permitting issues.” The upgrade was intended to resolve the potential for two 230-kV circuits in the Montville area to be lost and cause a voltage collapse dropping over 300 MW of load. FirstEnergy informed PJM that an alternative project should be identified and included in the RTEP.
Supplemental Projects
Dominion presented a $110 million project to build a new substation, named Duval, to serve more than 100 MW of residential and commercial load forecast in Chesterfield County. The $30 million substation would be connected to the Midlothian substation with four 230-kV lines for $80 million. The project has an in-service date of Jan. 1, 2028, and is in the engineering phase.
Dominion presented a pair of projects to replace two 230/115/13.2-kV transformer banks at its Landstown facility due to their age and maintenance issues. The projects would cost $9.86 million, with one expected to come online in December 2025 and the second a year later.
Dominion presented a series of projects to build a string of four substations networked between its planned Cirrus, Potato Run and Oak Green substations to serve new data center load in the Culpepper area.
At one end, the $14.3 million, six-breaker ring Palomino substation would be connected to the Cirrus substation with two 230-kV lines for $24.2 million. Palomino would be connected to the $14.3 million Chandler substation with double circuit 230-kV lines for $6.5 million.
The similarly priced McDevitt substation would be connected to Chandler with double circuit 230-kV lines for $5.5 million. The last facility, Mount Pony, would cost $11.6 million and would be connected to McDevitt with double circuit 230-kV lines for $28.2 million. Mount Pony also would connect to both Potato Run and Oak Green with 230-kV lines for $100 million in transmission and $40.8 million in upgrades at the existing sites. Each component has an in-service date in the second quarter of 2028 and is in the conceptual phase.
FirstEnergy presented two projects totaling $14.8 million to replace 230/34.5-kV transformers at its Glen Gardner and Larrabee substations, along with circuit breakers and disconnect switches to address maintenance issues associated with the end of life for the transformers. The Glen Gardner transformer would be installed by May 1, 2025, while the transformer at Larrabee would go in-service on April 12, 2027.
NYISO opened the Installed Capacity Working Group’s meeting Feb. 4 by telling stakeholders it is assessing the impact of President Donald Trump’s 10% tariff on “energy resources from Canada” on its markets.
“NYISO is actively pursuing guidance pertaining to the impact on electricity markets and which Canadian energy resources qualify,” it said in a statement read at the start of the meeting. “We will communicate to all stakeholders as soon as we receive clarification.
“The U.S. and Canada have one of the most integrated electric grids in the world, allowing system operators in both countries to pool resources for improved reliability and economic efficiency. We are in close and regular contact with Hydro-Quebec and Ontario’s Independent Electricity System Operator to ensure a reliable grid and stable flows of electricity across interregional transmission lines.”
In addition to the applicability of the tariff to electricity imports from Canada to New York, NYISO is investigating:
whether the ISO has any responsibility in collecting the tariff;
whether the ISO’s tariff (that is, its filed rate) requires any amendments to fulfill a collection obligation;
software and administrative procedures to effectuate tariffs; and
reliability considerations over the short and long terms.
NYISO spokesperson Andrew Gregory declined to say who or what the ISO is consulting or when it expected answers.
A spokesperson for New York Gov. Kathy Hochul told RTO Insider the governor’s office did not know what the tariff would include, if it proceeded. The New York Department of Public Service said in a statement that it was “closely reviewing the situation.”
Celeste Miller, acting director of media relations for FERC, declined to comment.
FERC Order 904
Amanda Myott, NYISO senior market design specialist, presented an update to the ISO’s compliance filing for FERC Order 904, which prohibits transmission providers from including charges in their rates to compensate generators for reactive power that falls “within the standard power factor range by generating facilities.”
In keeping with the order, NYISO intends to discontinue compensation to voltage support service (VSS) suppliers for reactive power within the standard range.
“NYISO is also proposing to continue compensation for suppliers that offer voltage support outside the standard power factor range, with compensation being based on demonstrated capability using existing VSS testing and payment procedures,” Myott said.
The ISO also proposes to define the standard range of 0.95 leading to 0.95 lagging, which is industry standard.
Suppliers who want to participate will be subject to the same VSS capability testing rules and procedures that exist. The penalty structure for VSS program participants will be retained. Performance failures within the standard range for suppliers who do not participate in the new program will not be subject to penalties but may be reviewed under the tariff for a market violation.
The new VSS program will be integrated into the capacity market through an adder to account for VSS revenues for each peaking plant technology. The adder’s value will be determined formulaically based on the Rate Schedule 2 compensation structure. This will come into effect on May 1 to align with the 2026/27 capability year.
Several stakeholders asked to be allowed to review the tariff revisions necessitated by these changes before NYISO submitted its compliance filing, which is due March 28. The ISO stated they would return to the working group if necessary for more feedback.
