PJM CEO Manu Asthana on April 14 said he will resign from his position at the end of 2025 after more than five years of leading the RTO.
“My five-plus years at the helm of PJM have been some of the most fulfilling of my career,” Asthana said in a statement. “I am especially appreciative of the opportunity to have led PJM’s remarkably talented, diligent and committed people, who work hard every day to keep the power flowing for 67 million people.
“The time has now come for my wife and me to move back to be closer to our family and friends in Texas. I look forward to continuing to lead the organization through the end of the year and to helping facilitate an orderly transition to my successor.”
Asthana relocated to Pennsylvania when he took over as the head of PJM on Jan. 1, 2020, in the wake of the GreenHat Energy default, which led to the resignation of several PJM executives. (See PJM Taps Ex-Direct Energy Exec as New CEO.)
Mark Takahashi, chair of the PJM Board of Managers, said Asthana guided the RTO through several significant changes, including the shift to studying interconnection requests with a cluster-based approach and an overhaul of capacity market rules following Winter Storm Elliott in December 2022. (See FERC Approves 1st PJM Proposal out of CIFP.)
“The PJM board is grateful to Manu for his strong leadership during a time of tremendous change in the electricity industry,” Takahashi said in a statement. “Under his leadership, PJM successfully navigated the COVID-19 pandemic, significant market reforms, interconnection process enhancements, the buildout of a robust risk management function and the delivery of world-class grid reliability through a variety of extreme weather events.”
Takahashi said Asthana has worked with the board to develop “PJM’s internal succession pipeline.”
“We have a strong executive team, including internal succession candidates. We will also consider external candidates for this role,” Takahashi said.
The board has formed a search committee to identify a replacement in the next year. That process will be aided by consulting firm Korn Ferry with input from the RTO’s membership and stakeholders. Asthana is set to stay on as a senior adviser until June 2026.
Electric Power Supply Association CEO Todd Snitchler said Asthana led PJM through a time of rapid change.
“We have appreciated working with him and his willingness to listen to the input of the generator community as he navigated how to deliver reliable power while addressing the challenges posed by varying state and federal policy preferences; a rapid rise in energy demand; and external factors like supply chain hurdles and onerous permitting policies that impede infrastructure development,” Snitchler said.
He said EPSA hopes to see PJM continue to address planning and interconnection queue issues, and “strongly support” a market that balances input from stakeholders and market participants and “provides reasonable certainty and a fair opportunity for a return on investment for resource developers.”
Glen Thomas, president of GT Power Group, said “leading PJM is a challenging job, and Manu led PJM through some very challenging times, from COVID to the data center demand boom. He remained calm, accessible and diligent no matter what the challenge. We look forward to working with PJM to find a successor that can lead PJM to meet its mission to deliver reliability through markets.”
D.C. Public Service Commission Chair Emile Thompson, current president of the Organization of PJM States Inc. (OPSI), pointed to several capacity market changes PJM pursued in recent months that consumer advocates have argued would ward off inappropriately high prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)
“CEO Asthana has been a tremendous partner to work with during my tenure as the president of OPSI,” he said. “Together, we worked to implement a number of reforms in response to the most recent Base Residual Auction. I look forward to continuing to work with him through the remainder of his tenure as we tackle issues such as resource adequacy, sub-annual capacity markets, transmission planning and issues surrounding co-location.”
Alabama Power, on behalf of other members of the Southeast Energy Exchange Market (SEEM), has submitted a FERC-ordered filing detailing changes to the market’s agreement intended to comply with a March 14 order from the commission (ER21-1111).
The proposed changes to the agreement detail the ability of utilities to participate in SEEM via pseudo-ties, which are used to represent interconnections between two balancing authorities where no physical connection exists between the load or generation and the power system network. SEEM members proposed the changes take effect April 15.
FERC directed SEEM to update the agreement after members argued in an earlier filing that pseudo-ties offered a means for loads and resources outside the SEEM territory to participate in the market. (See SEEM Members Respond to FERC Briefing Request.) This claim came in response to the commission’s request for briefings after an order from the D.C. Circuit Court of Appeals remanded the commission’s approval of the market in 2021.
One of FERC’s questions concerned whether entities with a source or sink outside SEEM’s territory could meet the technical requirements of the market’s matching platform. SEEM’s supporters have argued the territorial requirement was needed to implement the market platform that matches excess supply with free transmission every 15 minutes. But the court claimed the limitation resembled “discriminatory practices against third-party competitors by monopoly utilities.” (See DC Circuit Sends SEEM Back to FERC.)
FERC’s March 14 order acknowledged “an external source or sink could be a participant in SEEM if it used a pseudo-tie,” but observed that such a practice would significantly affect “rates, terms or conditions of service” to such an extent that it should be included in the market agreement rather than a business practice manual. In their response, SEEM members agreed “there is not a SEEM entity that … would have the authority to evaluate and approve or reject creation of a pseudo-tie” under the current market agreement.
To address this, members proposed amending the agreement in several places. First, the new agreement adds the words “including through the use of a pseudo-tie” to language in the market rules that says a participant must own or control a source, and/or “be contractually obligated to serve a sink,” within the SEEM territory. A new footnote in the same section specifies that a prospective participant seeking to establish a pseudo-tie must coordinate with relevant BAs, transmission providers and reliability coordinators, along with the SEEM Operating Committee.
Members said that “a pseudo-tied resource or load, once established, would appear no differently from any other resource or load registered as a valid source or sink” participating in SEEM.
A change to Article 5 would establish the Operating Committee’s obligation to coordinate with efforts to participate via pseudo-tie. The language of the new section 5.11 requires the committee not to reject a pseudo-tie that has been accepted by the relevant TP, BAs and RCs.
Similar language is found in proposed changes to section 3.4, adding that TPs “shall have a duty to coordinate and act in good faith in interactions with any prospective participant … utilizing a pseudo-tie,” and with all relevant BAs and RCs. Such good-faith interaction must include transparency about the reason for any denial of participation.
The updates also added definitions of the terms “pseudo-tie” and “reliability coordinator” to be consistent with definitions in the SEEM market rules.
“These changes appropriately commit SEEM to working with potential participants on pseudo-ties, including coordinating with the other identified entities necessary to the establishment of any such pseudo-tie,” members said.
(Editor’s note: An earlier version of this article contained information about a company, Zeem, that’s unconnected to the Kearny Point project.)
New Jersey is investing up to $13 million in a pilot project to put six hydrogen-fueled trucks to work in the Port of New York and New Jersey as the port authority prepares to launch an unrelated initiative to cut trucking emissions by opening the first publicly accessible heavy-duty truck chargers at the port.
The New Jersey Economic Development Authority (EDA) on April 9 agreed to pay Rutgers University to develop the hydrogen project with money from the Regional Greenhouse Gas Initiative (RGGI). Rutgers researchers will buy six Class 8 hydrogen fuel-cell trucks, as well as fueling facilities and fuel, and partner with one or two logistics companies to operate the trucks at the port.
The project will add to the ongoing effort to cut emissions in and around the largest port on the East Coast. Pollution from the port has attracted attention because of its location in a densely populated area already burdened with fossil fuel electricity generators and highways. Much of the port is in Newark, the state’s largest city, and the marine terminals contributed about 8.5% of the greenhouse gas emissions in the area, according to the EDA’s memorandum of understanding for the hydrogen project.
The 15-month-long hydrogen project, with the option to extend by a year, will be carried out at Port Newark and Port Elizabeth marine terminals and aims to “position New Jersey as a leader in clean hydrogen innovation,” according to a memo outlining the project that was submitted to the board by EDA CEO Tim Sullivan.
Rutgers researchers will “gather raw data to assess the vehicle’s feasibility” and will submit quarterly reports to the EDA that address issues including “procurement, health and safety, equipment operations, vehicle mileage, fuel consumption and maintenance,” the memo says. “This data will emphasize economic and environmental factors, including but not limited to total cost of ownership and tailpipe emission,” the memo adds.
EV Advances in the Ports
The EDA’s approval came as two heavy-duty electric charging initiatives are close to coming online. The Port Authority of New York and New Jersey (PANYNJ) is ready to open four EV DC fast chargers (DCFC) in the port that will be available to the owners and operators of drayage trucks, which move shipping containers in and out of the port.
In an unrelated project, EV Edison is completing construction on Kearny Point, a heavy-duty trucking depot that will be able to handle 200 Class 8 trucks a day. “The hub is currently in its final stages of construction and will be ready in a few weeks,” said Yazan Harasis, director of engineering at the company.
Located on the edge of the Port of New York and New Jersey, the Kearny Point depot will have 30 ports, each with up to 180 kW of power, which will take about two hours to fully charge a truck, he said.
Drayage trucks make more than 14,000 trips in and out of the port each day, but the drayage sector and truck owners in New Jersey have been slow to embrace electricity or any other alternative truck fuel, as they have been in other states.
PANYNJ in July 2024 said the use of electric trucks and container handling equipment increased by about 8% from 2022 to 2023. But that growth started from a small base. The authority’s March 2025 report shows there are 19 electric trucks serving the port, compared to 10,875 diesel trucks.
Drayage trucks typically pick up containers imported through port terminals and deliver them to a distribution center or a warehouse, often returning the same day to the port with empty containers. As such, the distance of a typical drayage delivery is much less than, say, those made by cross-country truckers.
A National Renewable Energy Laboratory (NREL) report in 2023 found that existing electric trucks on the market had sufficient range to replace 20% of diesel trucks in the port, because the average route they completed each day was 140 miles. (See NREL Report Sees Role for Electric Trucks at Port of NY-NJ.)
Trucker Skepticism
Truckers, however, say electric trucks on the market are too expensive, the number of models available is limited and the range for those EV trucks on the market still is too small. A diesel truck typically costs $180,000 and an electric truck upward of $400,000, according to the American Trucking Associations. Studies have shown EV trucks can be cheaper than diesel over the life of the vehicle, due to the lower fuel and maintenance costs. (See NRDC Report Predicts a Decline in NJ’s EV Truck Costs.)
Truckers say the hefty EV battery takes up space that otherwise would be used for carrying goods and products, making the trucks less efficient. And they say the time taken to charge the battery also reduces truck efficiency, compared to the relative speed with which a diesel truck can be filled up.
The cost factor is particularly important because many of the trucks that serve the port are owned and operated by small businesses that operate a handful of trucks and have little capital to buy an electric truck.
Lisa Yakomin, president of the Association of Bi-State Motor Carriers, which represents drayage truckers in the port, said she’s not familiar with the hydrogen pilot proposed by the EDA, but said the state lacks charging or fueling infrastructure for hydrogen trucks, as it does for electric trucks.
“If you compared the two side by side, I think there are, from a charging standpoint, advantages to the hydrogen fuel cell” over electric trucks, Yakomin said. “But the challenges relating to infrastructure are the same for both, and the challenges in terms of cost are the same for both. And those are two very big issues that keep them from being taken seriously.
“I’m not aware of any public fueling stations for hydrogen (around the port). I think there’s one private one in the entire state of New Jersey,” she said. Still, she added, “one of the advantages that hydrogen fuel cell trucks have over EVs is that they charge about as quickly as a diesel truck does. They also go twice as far as an electric truck. But when you compare it to a diesel truck, they still go a fraction of the distance of a diesel truck on a full tank of gas.”
While a diesel truck can go about 1,300 miles on a tank of gas, and an electric vehicle can do 200 miles or so on a charge, a hydrogen truck can go about 400 miles, she said. She added that port officials have said the chargers planned for the new electric charging sites are 350 kW, which would charge a truck in about two hours — a time she suggested is too long for the rapid-turnaround needs of the drayage sector.
The website for Phoenix-based Nikola, which makes hydrogen fuel-cell trucks, says its vehicles have a range of 500 miles and can be refueled in “20 minutes or less.”
Hydrogen is made by electrolyzers splitting water molecules into their components of hydrogen and water. For hydrogen produced this way to be clean, or green, as it is commonly called, the electrolyzers have to be powered by zero-emissions renewable or nuclear energy.
The EDA, in memorandum outlining the hydrogen project, said “hydrogen is most applicable to industries that are difficult to decarbonize through battery electrification. In the transportation sector, electrifying medium- and heavy-duty vehicles remains a challenge.”
The Department of Energy in 2024 allocated $750 million to fund 52 projects in 24 states across the nation, with an aim to advance electrolysis technologies and manufacturing and recycling capabilities for clean hydrogen. The goal of the projects, with funding from the Infrastructure Investment and Jobs Act, is to boost the manufacture of electrolyzers to produce up to 1.3 million tons of clean hydrogen yearly and boost the production of fuel cells, which run on the clean hydrogen, by 14 GW yearly. (See DOE Announces $750M in Clean Hydrogen Funding.)
Business groups and environmental advocates expressed divergent views on a proposal by the Massachusetts Department of Public Utilities that would require new gas customers to cover the entire cost of connecting to the system.
The department’s draft policy would end the utility practice of including the costs of connecting new customers into rate base. This is currently allowed if the utility expects to recover the costs through distribution fees from the new customers over an extended period.
The DPU, along with the state Department of Energy Resources and Attorney General’s Office, has expressed concern that the practice is not in line with the state’s climate laws and risks creating stranded costs as the state transitions away from natural gas (DPU 20-80). (See Mass. DPU Proposes Major Shift in Gas Line Extension Policies.)
The department proposed to allow exemptions to the requirement for new customers to cover their entire connection costs if they can prove the project would create a “demonstrable reduction” in carbon emissions, has no “feasible alternatives” to gas service and is consistent with the state’s statutory climate limits.
Climate and consumer advocates have supported the proposal, while the gas utilities, real estate groups and large business associations have voiced their opposition. Many of the arguments raised in the proceeding reflect significant underlying disagreements about the future of the natural gas system as the state decarbonizes. In an earlier phase of the proceeding, the DPU concluded that decarbonization of the state’s gas network should be based on electrification. (See Massachusetts Moves to Limit New Gas Infrastructure.)
In comments submitted in early April, gas distribution companies argued that the proposal would increase the cost of new gas service and push developers to use heating oil in new buildings. Eversource Energy wrote it would create “significant unintended consequences that will work directly against the commonwealth’s ability to reach its 2050 goals.”
National Grid and the Associated Industries of Massachusetts (AIM) — whose membership includes both National Grid and Eversource — both argued that the proposal would hurt economic development in the state.
“We are concerned that this proposal could impede economic growth, contribute to higher energy costs, and hinder vital housing and infrastructure development,” AIM wrote. “This change is likely to impose unreasonably high upfront costs to necessary energy infrastructure for commercial and industrial facilities.”
The Greater Boston Real Estate Board wrote that the draft policy would hurt housing development in the state and said the exemptions included in the proposal “offer no benefit.” It also argued that, in light of recent delays to offshore wind projects, “the department should reconsider the climate impact of this draft policy as more load is added to an already constrained electric grid.”
In contrast, the Massachusetts AGO — which serves as the official ratepayer advocate in the state — expressed support for ending the existing line extension policies, arguing that “such outdated policies encourage expansion of the gas system and increased gas infrastructure investment at a time when the commonwealth has made clear and decisive steps towards decarbonization through electrification by 2050.”
The AGO highlighted the emissions sub-limits in Massachusetts’ 2025-2030 Clean Energy and Climate Plan, which requires a 49% reduction in both the residential and the commercial and industrial heating and cooling sectors by 2030 (relative to 1990 levels).
“The LDCs’ [local gas distribution companies’] current policies are both antithetical to achieving the commonwealth’s climate mandates and inconsistent with the financial interests of ratepayers,” the AGO wrote.
It warned of a “price vortex,” in which customers exiting the gas system would increase distribution costs for the remaining customers. This phenomenon would likely disproportionately affect low- and moderate-income households that cannot afford the upfront costs required to convert to electrified heating, the AGO wrote.
“Line extension allowances exacerbate the price vortex because the new gas investments will become stranded costs as customers reduce natural gas consumption and possibly leave the gas distribution system before the end of the assumed repayment period,” the AGO noted.
Supporters of the DPU’s proposal highlighted a 2024 analysis by Groundwork Data, which found that the costs of all-electric construction have reached near parity with buildings that rely on fossil fuels and concluded that all-electric buildings will likely provide long-term savings for building owners. (See Report Outlines Cost Savings of All-electric Buildings in Mass.)
“Despite claims to the contrary by real estate developers and other similarly aligned industry members, there is a clear trend toward building electrification in Massachusetts and beyond,” the Conservation Law Foundation, Environmental Defense Fund and Sierra Club wrote in joint comments.
The AGO and a range of environmental nonprofits called for the DPU to add language establishing strict criteria for the exemptions that would allow a project’s connection costs to be covered by ratepayers.
“The draft policy should establish a clear and consistent methodology for assessing a demonstrable reduction in GHG emissions for proposed line extensions serving new construction,” wrote a coalition of environmental groups led by Rewiring America and the Acadia Center.
The AGO said the payback periods should be cut in half, which would bring the payback period for residential projects to 10 years and the period for commercial and industrial projects to five years. It recommended that the connecting customer be required “to pay for the remaining balance of outstanding costs of the line extension if the customer leaves the gas distribution system before the end of the assumed repayment period.”
The DOER agreed that utilities’ line extension policies are inconsistent with the state’s climate mandates and fail to account for the risk that line extensions will become stranded assets. But it called on the DPU to convene technical sessions to seek consensus among stakeholders around the best way to update the policies.
The department also noted that it met with a wide range of stakeholders before submitting its comments and found “a broadly shared concern that the language of the proposed policy, specifically of the proposed exceptions, was vague and raised significant questions regarding implementation.”
It said technical sessions could help achieve “alignment and clarity” more efficiently than another round of written comments.
The last couple weeks remind me of the 1971 comedy record by David Frye during the Nixon administration. Richard Nixon (Frye) hosts yippie Jerry Rubin (Gabe Kaplan) in the White House, trying to make a political connection.
Steve Huntoon |
And I need to stop to clarify that “yippie” back then meant members of the Youth International Party.
Nixon asks, “Tell me, Mr. Rubin, what would you do after everything was torn down?” And Rubin replies, “I don’t know, man, maybe we’ll just sit there and groove on the rubble.”
Yeah man, just groove on the rubble.
We’ll skip over everything else in the past couple weeks and ask what to make of the Trump administration’s latest executive order directing FERC, an independent agency, to sunset its regulations in no more than five years (or explain why not). In apparently unintended irony, this is “to provide certainty and order.”
The “fact sheet” for the executive order talks repeatedly about “energy production,” which suggests the Trump administration doesn’t know what FERC does. FERC has no direct role in the production of energy except for the licensing of hydroelectric plants (and arguably qualifying facilities under the Public Utility Regulatory Policies Act, which the executive order inexplicably excludes).
FERC is told to sunset all its regulations implementing the Federal Power Act of 1935 and the Natural Gas Act of 1938 in one year but no more than five years. But these statutes don’t exist in any intelligible way without the implementing regulations that have been promulgated and judicially affirmed over the last 80-some years.
Most recently we have the long-term transmission planning regulations in Order 1920. So let’s see how this works: They govern transmission planning for the next 20-plus years, but they’re terminated in one year or five years?
The executive order requires FERC to issue a “sunset rule” for each of its regulations by Sept. 30, 2025, to eliminate each of its regulations by Sept. 30, 2026, except for such regulations that FERC finds should be extended based on “costs and benefits.”
How can FERC get rid of regulations it is required by statute to have? How can FERC amend each of its regulations to add a sunset date without conducting formal rulemakings to do so? How can FERC apply a “costs and benefits” standard (whatever that might be) to its regulations rather than the statutory standards?
FERC is required to coordinate all this with its “DOGE team lead” and with the Office of Management and Budget (OMB). Does FERC have a DOGE team lead employee, as it apparently is required to have per an earlier executive order? How can the DOGE team lead, a FERC employee, coordinate with DOGE, and how can FERC coordinate with OMB, on rulemakings to sunset FERC’s regulations without violating FERC’s ex parte rules?
This comes on the heels of a February executive order regarding FERC and other “so-called independent agencies” (note the “so-called” pejorative) that:
gives OMB control of FERC resources.
requires the FERC chairman to “regularly consult with and coordinate policies and priorities with the directors of OMB, the White House Domestic Policy Council and the White House National Economic Council.”
gives the attorney general control of all “questions of law” involving FERC.
subjects all draft FERC regulations to review by OMB.
Good luck to Chair Mark Christie, his FERC colleagues and our industries.
(P.S. And let us pray for the return of Kilmar Armando Abrego Garcia so none of us have to fear arbitrary U.S. government kidnapping to foreign gulags where we must spend the rest of our lives.)
Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years.
The California Energy Commission on April 10 approved revised guidelines for a reliability program after the state’s utility regulator in March said the effort could undermine certain benefits of a separate reliability program run by Pacific Gas and Electric (PG&E).
The CEC program in question — the Demand Side Grid Support (DSGS) program — is part of the agency’s Strategic Reliability Reserve (SRR) initiative, developed in 2022 as part of Assembly Bill 205. When the DSGS began in 2022, participants contributed 315 MW to help meet grid needs during a summer 2022 heat wave.
In March, the CEC planned to approve revised DSGS program guidelines, but held off on the decision due to a California Public Utilities Commission letter to the CEC saying the revised guidelines “overlap substantially” with PG&E’s Automated Response Technology (ART) program.
The DSGS targets the same market segments and devices and is “likely to undermine the new resource adequacy benefits and other goals of the market-integrated ART program,” Leuwam Tesfai, CPUC deputy executive director for energy and climate policy, said in the letter.
PG&E’s ART program has begun enrolling customers and has capacity commitments under contract, Tesfai said.
The CPUC was specifically concerned that DSGS’s Option 4, the Emergency Load Flexibility virtual power plant (VPP) pilot, conflicted with ART. The revised DSGS therefore excludes PG&E distribution service customers from participation in Incentive Option 4.
If a participant joins a conflicting program, such as ART, the participant’s DSGS provider will be notified, and the participant will be suspended indefinitely until the conflict is resolved, the guidelines say.
In the DSGS, entities such as publicly owned electric utilities (POUs) and community choice aggregators (CCAs) are eligible to serve as load flexibility VPP aggregators, the revised guidelines say. A load flexibility VPP event contains up to two core hours, which are the peak price hours defined as the two consecutive hours in the daily availability window with the highest mean CAISO energy price, the guidelines say.
Stakeholders raised concerns with the delay in approving the guidelines, saying waiting interferes with providers’ and participants’ plans for program participation for 2025.
“It is especially concerning that the CPUC requested a delay on the date of the business meeting at which approval was to happen, given that the proposal to add Option 4 was publicly available and the CEC invited input beginning in October 2024,” Kate Unger, senior policy adviser at the California Solar & Storage Association, said in a March 21 letter to the CEC. “PG&E and the CPUC had sufficient opportunity to raise concerns about the ART program throughout the revision process this year.”
CEC Approves Air Capture Grants
At the meeting, the CEC also approved three grants for companies working on direct air capture (DAC) methods. A major issue with DACs is that they require a large amount of water: 1.6 tons of water per ton of CO2 captured for most commercial DAC systems, according to the CEC. To help solve this issue, the CEC awarded Circularity Fuels funding to improve its technology by eliminating the need for steam (and thus water). The project will also help the company demonstrate scalability from 5-kW to 50-kW systems and validate the product’s performance in real-world conditions.
The second grant went to Noya, an Oakland-based company, to improve its product’s materials and CO2 regeneration. The third and final grant went to Berkeley-based AirCapture, allowing the company to design, develop and test a DAC system that uses microwave energy for sorbent regeneration.
RMR Contract for CPS Energy Unit Faces Increased Costs, Delays
ERCOT’s plans to continue running a 55-year-old San Antonio gas plant scheduled for retirement are being endangered by increased costs and timeline delays.
CEO Pablo Vegas told the Board of Directors during its April 8 meeting that “pretty significant findings” during CPS Energy’s inspection of its Braunig Unit 3 found that the boiler superheater header must be replaced. What originally was thought to be a two- or three-month delay could be as long as 12 months, he said.
The cost to replace the heater header has not yet been estimated, but Vegas said the contractor inspecting the unit — built during the late 1960s and with a summer maximum rating of 400 MW — has found $2.7 million of incremental costs to repair and replace core components “of significant vintage.” ERCOT and the market already are on the hook for $45.85 million under the terms of Braunig 3’s reliability must-run contract. The budgeted amount is a 33% increase since CPS’ first estimate in November.
Vegas said staff are working to validate the cost estimate of the heater header — “a fairly costly [replacement item],” he said — and other components with the original manufacturers and other potential suppliers.
“We have gotten signals that there may be some components that need to be replaced that have longer lead times to get those components in and get the unit up and running,” he said. “We’ll be looking at the impact of those delays to understand what that means in terms of the actual availability potential and then evaluate the cost benefit of continuing to work through this maintenance and repair cycle with Braunig Unit 3, versus looking at some other alternative. That data is very new.”
The delays have placed added importance on the use of 15 mobile generators as an alternative to extending the life of V.H. Braunig Power Station’s other two aging gas units, slated for retirement this year. The grid operator determined the generators and their 450 MW combined capacity is less risky and more cost-effective than using the two small units from the “Swinging ‘60s” with a combined summer maximum rating of 392 MW. (See ERCOT Board OKs Mobile Generators in San Antonio.)
Vegas said final negotiations are ongoing between LifeCycle Power, the mobile generators’ owner; CenterPoint Energy, which leases the generators; and CPS Energy, which plans to deploy them in the San Antonio region.
“We are planning to do everything we can to incentivize bringing these units on as quickly as possible in the San Antonio area,” he said. “Given the fact that we are seeing significant cost and potential schedule delays on the Braunig unit, it increases the importance of having these resources available during the peak parts of this summer.”
“We’re putting as much pressure on those parties to get those issues wrapped up, but I’m pretty optimistic that we should be able to get all this resolved,” General Counsel Chad Seely said. “Getting those assets onto the grid sometime this summer … they’re all kind of contingent on everything being folded up together.”
LifeCycle’s generators were projected in February to cost $54 million, including fuel costs and incentives. They can reach full output in 10 minutes, faster start times than the three Braunig units.
Seely said that as every day passes without an agreement with the parties, more risk is placed on their availability by August, “when we really need them.”
Responding to questions from directors as to whether there is a drop-dead date before “punting” the generators, Vegas responded, “There isn’t a scenario where we’re going to punt this for this summer.”
Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told the board staff has been work with CPS, AEP Texas and South Texas Electric Cooperative to accelerate portions of a $435 million reliability project south of San Antonio. The rebuild addresses a transmission constraint that has led to Braunig 3’s RMR contact and the mobile generator must-run alternative.
The CPS board on March 31 agreed to a $150 million contract with Quanta Services to work on 58 miles of energized transmission lines. Quanta has agreed to complete the work by December 2026, shortening the original 2029 timeline.
“We would be able to potentially exit both the Braunig 3 as well as the LifeCycle agreement as early as September of 2026,” Hobbs said.
ERCOT’s RMR contract with Braunig is its first since 2016, when it entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Ending Greens Bayou RMR May 29.)
CPS told ERCOT in 2024 that it planned to retire the Braunig units in March 2025. However, ERCOT said the plant’s retirement would lead to reliability issues in the San Antonio area until the transmission constraint is resolved. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)
Costs Increase for Permian EHV
Hobbs also told the board that staff has filed updated cost estimates for EHV transmission paths into the Permian Basin with the Public Utility Commission, which will determine whether to go with 345- or 765-kV lines. (See “EHV Lines Offer a Lifeline,” Texas Stakeholders Grappling with Tsunami of Large Loads.)
The estimates provided by transmission providers have increased for both voltage options from the original May 2024 projections. The 345-kV option has increased 7.6% to $8.28 billion, while the 765-kV option has increased 11.6% to $10.11 billion.
“We recognize it’s going to be an investment for the consumers to be able to get the transmission built that they need,” Hobbs told directors. “We’ve often said that we feel like our current transmission system has maximized its capability, meaning we have squeezed all we can out of the current transmission system.”
ERCOT said its analysis indicates that 765-kV circuits would provide “significant economic and reliability benefits” to the system because they are more efficient in moving power over long distances. Transmission providers and vendors said during a March 7 workshop that supply chain issues are not a concern.
The PUC is scheduled to take up the issue during its April 24 open meeting.
Operations Vice President Dan Woodfin also updated the board on a “pretty eventful” March for renewable energy. Multiple wind, solar and total renewable records were set during the month:
Wind generation: 28.5 GW, March 3.
Solar generation: 26.3 GW, March 20.
Solar penetration: 56.60%, March 20.
Renewable generation: 39.99 GW, March 18.
Renewable penetration: 76.11%, March 2.
Designing Residential DR Program
ERCOT is working with stakeholders to develop a residential demand response program to address short-time reliability problems, Keith Collins, vice president of commercial operations, told the board.
“We do think that there’s an opportunity in terms of smart devices, thermostat, pool pumps, water heaters, things along that line, and to allow for a program that [focuses] on those types of resources,” he said.
Collins said expanding the DR program is a top priority for ERCOT. As envisioned, it would provide an incentive payment to retail electric providers — and possibly public power entities in the competitive market — based on residential DR performance during highest net-load periods.
“The intent of the program is something that’s quick to develop, simple in its administration, can be popular for folks to be a part of and ultimately is cost-effective in the end,” he said. “We do think we have some novel concepts that we’ll be able to accomplish.”
ERCOT expects to complete the program’s design this year, develop it in 2026 and implement it in 2027, Collins said.
Aguilar Resigns, R&M Dissolved
Board Chair Bill Flores opened the meeting by announcing Carlos Aguilar resigned as an independent director. Aguilar was one of the first two directors to sit on ERCOT’s revamped board following Winter Storm Uri in 2021. His second term began in October 2024.
“His expertise and guidance have been instrumental in this board’s decision-making,” Flores said.
The ERCOT Board Selection Committee, composed of three members selected by Texas’ governor, lieutenant governor and speaker of the House of Representatives, will begin the selection process in coming weeks, Flores said. Under state law, all board members must be Texas residents.
The board voted to dissolve its Reliability and Markets Committee and move its discussion to the full board. The R&M committee was created in 2022 and was responsible for core ISO functions and several technology-related functions that later were shifted to the Technology and Security Committee.
Flores moved the R&M’s jurisdiction to allow all board members more direct participation in policy matters associated with the core functions of operations, planning and markets. He said future board meetings likely will be held over two days to manage business more efficiently.
Possible Admin Fee Decrease in ’26
The board’s Finance and Audit Committee began its review of the ISO’s proposed 2026/27 budget, which could result in a 2-cent decrease in the system administration fee, said Flores, who presided over the committee meeting after Aguilar’s resignation.
He said staff has proposed the fee be reduced from $0.63/MWh to $0.61/MWh, effective Jan. 1, 2026. The budget’s total authorized spend is $474 million in 2026 and $557 million in 2027. The increase is due to the start of ERCOT’s data center refresh project.
The F&A will review the budget again during its June meeting. Flores said the committee has asked staff to bake in several uncertainties during the planning process, including trade tariffs and disruptions and a potential economic downturn’s effect on electric demand.
Seely said the company’s patents may be a barrier to entry for increased market participation by controllable-load resources (CLRs) if that risks intellectual-property infringement disputes. Lancium is registered with ERCOT as a qualified-scheduling entity (QSE), load-serving entity and resource entity. It owns a portfolio that includes a patent focusing on determining performance strategies for loads using power option data based on a power option agreement.
“This is a longstanding issue that’s been kind of playing around the surface in the stakeholder process for a couple of years,” Seely said. There have been “arguments around the patents” with stakeholders. “ERCOT has been engaged with Lancium for quite some time trying to understand the impact of what those patents could mean to our CLR program.”
Under the agreement, Lancium will license its relevant patents to ERCOT at no cost. The grid operator then will sublicense the patents to CLRs and any other applicable market participants or entities.
“This is a good outcome in which we can resolve this issue for the ERCOT region,” Seely said.
Board Approves RTC Protocols
The board approved a key protocol change (NPRR1269) related to ERCOT’s real-time co-optimization project, thought to be the foundation for future market improvements and scheduled to be deployed in December. (See “Stakeholders Approve Protocol Changes for Real-time Co-optimization,” ERCOT Technical Advisory Committee Briefs: March 26, 2025.)
NPRR1269 determines and codifies policy changes that were deferred from the original RTC-related protocols developed after the project’s inception in 2019: ramping scaling factor values; ancillary service (AS) proxy offer floor parameters; and ancillary service demand curves’ (ASDC) use in reliability unit commitment (RUC) studies.
Two other RTC protocol changes, NPRR1268 and NPRR1270, were placed on the board’s consent agenda.
Benjamin Barkley, the Office of Public Utility Counsel’s CEO, voted against the motion, saying setting the ASDC demand floor at $15 without seeing how it would perform with RTC is “premature.”
“Set [the floor] at $0 just to see how the market would respond in that circumstance,” he said.
Barkley again cast the lone dissenting vote against NPRR1190, which allows recovery of a “demonstrable financial loss” arising from a manual high dispatch limit override reducing real power output, when the output is intended to meet QSEs’ load obligations. The Technical Advisory Committee lowered the $10 million threshold that would trigger a review to $3.5 million. (See “Amended NPRR Passes,” ERCOT TAC Opens Discussion on Proposed RTC Changes.)
The directors also approved a correction of real-time prices for some operating days between Aug. 12 and Sept. 11 in 2024. A software update to ERCOT’s energy management system resulted in stale telemetered MW values, leaving the ISO short $3.3 million in statement charges.
The board’s consent agenda included six other NPRRs, two changes to the Planning Guide (PGRRs), single changes to the Nodal Operating and Settlement Metering Operating (NOGRR, SMOGRR), a system change request (SCR) and a modification to the Verifiable Cost Manual (VCMRR):
NPRR1234, PGRR115: Establishes interconnection and modeling requirements for large loads, defined as one or more facilities at a single site with an aggregate peak power demand of 75 MW or more.
NPRR1241: Clarifies the hourly standby fee clawbacks for firm fuel supply service during a winter weather watch by using a sliding scale.
NPRR1256: Changes language in adjustment period and real-time operations protocols related to must-run alternatives (MRAs), primarily in grey-boxed language from NPRR885 (Must-Run Alternative Details and Revisions Resulting from PUCT Project No. 46369, Rulemaking Relating to Reliability Must-Run Service) to align the terminology for energy storage resources (ESRs) in the single-model era. It also specifies how qualified scheduling entities representing ESR MRAs would be settled for providing MRA service.
NPRR1268: Defines the methodology for disaggregating the operating reserve demand curve into blended ancillary service demand curves.
NPRR1270: Updates requirements for load resources that are changing under RTC and were not updated in earlier revisions; removes language associated with group assignments in the day-ahead market; and eliminates the automatic qualification of all resources to provide on-line non-spinning reserve and SCED-dispatchable ERCOT contingency reserve service, among other changes. Resources will be required to undergo a qualification test to provide each of these services.
NPRR1273: Modifies ESRs’ capacity to the amount sustained for 45 minutes included in the physical responsive capability’s calculation.
NOGRR274: Conforms the guide to NPRR1217’s (Remove Verbal Dispatch Instruction Requirement for Deployment and Recall of Load Resources and Emergency Response Service Resources) protocol changes.
PGRR119: Codifies that a reliability margin will be used when limits associated with a stability constraint are modeled in the Regional Transmission Plan’s reliability and economic base cases.
SCR829: Adds an application programming interface to upload and download unit testing data from the net dependable capability and reactive capability application.
SMOGRR028: Gives guidance for allowing loss compensation for current limiting reactors.
VCMRR042: Adds seasonal sulfur dioxide and nitrogen oxide prices obtained from indices to calculate emission costs from May through September; annual prices would continue to be used from October through April.
ALBANY, N.Y. — The state with some of the most ambitious goals for offshore wind energy continues to pursue them as federal policy changes force a slowdown.
At the April 7-9 New York Energy Summit, updates on energy development efforts off the New York coastline did not gloss over President Donald Trump’s war on wind turbines but did not focus on it, either.
Some milestones have been achieved, panelists said, and just as important, no one has given up on reaching the next milestones.
Gregory Lampman, director of offshore wind at the New York State Energy Research and Development Authority, called the present situation a pause: The offshore wind industry and the various entities working with it are waiting to see how federal regulators interpret and execute President Trump’s directives targeting offshore wind.
NYSERDA wants developers to continue to invest in their lease areas during this period, Lampman said. It also would like shorter timelines between key milestones in the development process, which would lessen the risks and costs that grow with delay.
“Continue to invest in those areas, continue to refine and get more prepared, so that when we start moving through this regulatory process again, we can jump on it, make some progress, and then move much more projects into construction, very quickly,” he said.
New York Offshore Wind Alliance Director Alicia Gené Artessa said the nine offshore wind developers she represents remain interested in the New York market. “They want to build here because we have New York City and Long Island, which need power, and those are a lot of needy customers to say the least.”
As an early-stage project, Bluepoint Wind is taking a longer view for its lease area in the New York Bight, CEO John Dempsey said.
“We still would not see turbines spinning until the early 2030s regardless of who was president,” he said. “So it’s more for us about using the time to get the ecosystem in a good spot for the future.”
The lack of that ecosystem — a supply chain, institutional knowledge, manufacturing capacity, port infrastructure — was one of the challenges limiting attempts to quickly build a large U.S. offshore wind sector a few years ago.
Offshore wind produces electricity on a larger scale than any other renewable, Dempsey said, and its problems have been larger as well. But the underlying basis for building offshore wind remains strong, he added — demand in the wholesale electricity markets will persist.
“Offshore wind is one of a handful of generation assets that deliver scale once we’re going,” he said, “so to me, it’s just about using the time we have here to get everything right, and particularly around transmission and offtake.”
New York is giving more attention to offshore power transmission as it plans offshore power generation.
The first New York projects — South Fork, Sunrise Wind, Empire Wind 1 — rely on a radial model in which each wind farm has its own export cable and shoreline landing point. In its sixth solicitation, NYSERDA plans to effectively separate generation from transmission with a meshed transmission model that serves multiple wind farms.
Neither model is without challenges, and the overall cost and value of a meshed model would depend on the offshore wind generation attached to it. But Lampman said a meshed system such as the ones proposed into the NYISO’s public policy transmission needs solicitation could be “a great solution for growing the industry.”
He added: “It’s a bit of a challenge, though, because we’ve solved one problem and we sort of moved to another problem, which is, what are the commercial terms between the transmission developers and the offshore wind generators? And what’s the technical terms that get used? Because one group is building the transmission, the other one’s building the generation. How do you bring these things together?”
Bluepoint is farther from land than any other lease area in the New York Bight, and it could send power to New York or New Jersey. So it has a close interest in these potential transmission solutions.
Dempsey said New Jersey got an early start on offshore transmission development solicitations but had to pull back on the process, which affected Bluepoint’s own planning.
“So my hope is that New York continues with its plans around the PPTN, I think it’s a tremendous opportunity,” he said. “It obviously has some wrinkles to it that we need to iron out, but I think most of those are commercial in nature that we can figure out.”
The elephant in the room through all the conversations at the summit was the Trump administration and its ability to slow down renewable energy projects or boost their construction costs to untenable levels.
After the summit, a NYSERDA spokesperson told NetZero Insider the state still is waiting to see the practical impact of Trump’s Day 1 directives targeting offshore wind. The planning can continue amid this uncertainty because construction would be years away under any scenario.
“NYSERDA is carefully reviewing federal actions that impact our work. It is too soon to determine what impact, if any, federal actions might have on New York advancing the state’s energy policies. In the meantime, we will continue to work with colleagues across state government to realize the benefits promised by our state energy policy.”
LA JOLLA, Calif. — Western lawmakers have advanced efforts to provide the power industry with guidance amid increased wildfire risk, regulators discussed during the joint spring conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB).
After California passed Assembly Bill 1054 in 2019, the Golden State has launched several initiatives aimed at ensuring the law is integrated with how utilities “build, operate and maintain California’s electric system,” Caroline Thomas Jacobs, director of the Office of Energy Infrastructure Safety at the California Natural Resources Agency, said during a panel discussion on April 2.
AB 1054 established a wildfire fund that paying utilities can tap into to pay claims for damages resulting from a wildfire caused by utility equipment. Money in the fund comes equally from utility ratepayers and shareholders. (See California Wildfire Fund Could be Model for US, Panelists Say.)
The law also established a fire certification element. Safety certification requirements in California include having a wildfire mitigation plan, safety culture assessments and evidence of making progress on previous plans. In addition, executive compensation must be based at least 50% on safety metrics.
Thomas Jacobs said utilities have made significant progress, but “clearly, the risk has not been eliminated.”
“There’s 150 years of infrastructure out there that is built to allow sparks,” Thomas Jacobs said. “So, in today’s given environment, we’re not going to eliminate that risk overnight, but we are trying to layer that now into what the broader state effort is.”
Recent efforts to integrate utility efforts with the broader state system under AB 1054 include developing partnerships “so that we can start leveraging the massive amounts of investments that the utilities are investing on wildfire and making sure that’s paired with … the broader state system around wildfire resilience,” Thomas Jacobs said.
Also, the state’s Wildfire Mitigation Advisory Committee is coordinating initiatives with the Department of Insurance, communities and utilities to integrate wildfire mitigation work “into that broader state effort, Thomas Jacobs added.
‘Collective Responsibility’
Wyoming has similarly stepped up its wildfire prevention work. The state’s Legislature passed House Bill 192 in March following wildfires that burned thousands of acres in 2024.
The fires gave stakeholders a sense of urgency, said Mary Throne, a member of the Wyoming Public Service Commission and chair of WIRAB.
Wyoming’s wildfire law, which goes into effect on July 1, does not create a wildfire fund, but it requires all utilities to file wildfire plans with the PSC, Throne said.
“The exchange for a wildfire plan that we approve, there’s limited liability protection,” Throne said. “It creates a presumption, a standard, a duty of care that applies as long as the company is in compliance with its wildfire plan and not engaged in gross negligence or malice.”
Throne noted that wildfire mitigation is a “collective responsibility,” adding that the utilities are not primarily responsible for the heightened fire risk.
Utilities “do have a duty of safe, adequate and reliable service for their infrastructure,” Throne said. “But again, we cannot put what is really sort of a broader societal burden on an entity and entities that keep the lights on. There’s got to be some collective skin in the game.”
Wildfires also pose economic risks, and the West has already seen examples of utilities going bankrupt after being found liable, said Spencer Gray, executive director at the Northwest & Intermountain Power Producers Coalition (NIPPC).
NIPPC represents power producers and marketers. The organization’s members “need entities on the other side of the contract who are going to attract capital, who are liable for the course of the contract, who don’t face unexpected bankruptcy or a suspension of their ability to pay,” Gray said.
“We’re in a situation now, in many states, where the risk is not knowable,” Gray said. “You can’t mitigate it sufficiently to go back to your shareholders or to the debt markets to address it, and so that that really is an untenable situation,” Gray added.
Efforts in Washington and Oregon are underway to address risk sharing, including enhanced wildfire planning requirements and the establishment of a fund for the benefit of wildfire victims, Gray said.
NIPPC has been supportive of these efforts and “we will continue to be supportive of creating a risk environment that’s more knowable — not riskless — for our counterparties,” Gray said.
NYISO’s market monitor claims the ISO’s firm fuel capacity accreditation proposal would incentivize generators to rely on inferior types of firm fuel service that could undermine the winter reliability benefits of firming up.
“The current tariff is enforced through documentation, the need to obtain agreements that commit to firm fuel obligations,” said Pallas LeeVanSchaick, vice president of Potomac Economics. “The NYISO proposal fundamentally changes the obligation … by switching to something with a performance-based rule.”
The NYISO proposal asks that generators elect as firm or non-firm roughly 16 months in advance of the capability period they are electing for. The proposal requires that generators electing firm notify the ISO they have secured firm contracts by Dec. 1 of the capability year.
Generators that elect firm need to have fuel supply, transportation and replenishment strategies in place by the December deadline to ensure they can operate 56 hours over a consecutive seven-day period during the winter. Failure to perform during the capability period could result in sanctions.
LeeVanSchaick said in a presentation April 9 to the Installed Capacity Working Group (ICAP WG) that NYISO’s current proposal creates an incentive for generators to rely on “inferior types of firm fuel service” to qualify as firm. That’s because of the way it interacts with the natural gas import infrastructure.
During most periods, “firm” gas used by generators is made available on the system through capacity release, LeeVanSchaick said. Capacity release is the reselling of firm fuel rights to another entity. These can be pre-arranged for set terms of time.
“Most of the gas that’s available during winter is mostly a function of capacity release,” LeeVanSchaick said. “It’s not something that’s going to be available under all circumstances.”
During the worst winter periods, more generators are called on, reducing available fuel. If more generation is called on than there is natural gas available, then they must rely on fuel injections at the LNG ports in New Brunswick and the Boston area. These periods are infrequent. Most generators, LeeVanSchaick said, don’t bother coming up with firm fuel transportation contracts.
“A performance-based penalty doesn’t provide a very strong incentive to do this,” LeeVanSchaick said. “You’re sort of relying on generators to ignore their incentives.”
LeeVanSchaick said the purpose of firm fuel capacity accreditation is to try to incentivize generators to have capacity for infrequent conditions. He said it requires either verification of firm fuel and transport contracts on the front end, which the NYISO proposal does not do, or extreme penalties to make a violation too risky.
He proposed levying an additional firm fuel penalty on any generator that notifies the ISO of failure to contract by Dec. 1. For generators that are discovered to have not informed the ISO of a failure to get firm fuel contacts in place, he recommends a financial sanction and FERC referral. He also recommended moving the deadline up to March before the capability period.
Representatives of the generator sector took issue with this analysis, saying there were penalties beyond the firm fuel sanction that they would be exposed to if they misrepresented how firm their fuel was. Specifically, misrepresenting how firm a contract was already could get a generator in trouble with FERC for a tariff violation.
“I think the concern you raised is that this (getting firm fuel) is not a black-and-white behavior and therefore the ISO should allocate penalties,” said Mark Younger of Hudson Energy Economics. “I think if we’ve got issues that need to be evaluated where it’s not black and white, that FERC is the appropriate place to do that.”
Younger said he was more comfortable with the clarity of the ISO proposal and there was nothing in it to prohibit the ISO from asking generators what they did to secure a firm resource.
Doreen Saia, chair of the energy law practice at Greenberg Traurig LLP, said she wasn’t comfortable with a system that forced generators to declare they could lock down fuel supplies 15 months in advance, combined with a penalty if they couldn’t secure a contract because of market reasons.
“It’s like having a cop on a road seeing a car go really fast and not know if it went 70 or 90 and therefore not know what kind of ticket it should get,” Saia said. “I think that’s a FERC question and FERC should decide whether any additional penalty should be required or not.”
NYISO staff attending the working group disappeared during the lunch break to confer in private on the MMU proposal and the discussion it generated. They came back with an ellipsis.
“We’d like to get any additional feedback or thoughts on the proposal that was put forward today,” said Shaun Johnson, vice president of market structures for NYISO. “We’ll take that feedback, process it and consider our next steps going forward.”
Zack Smith, senior manager capacity and new resource integration market solutions for NYISO, said they would move “rapidly” with their considerations.
Julia Popova, chair of the ICAP WG, asked about the timing of NYISO returning with an answer. The ISO is running out of time to file with FERC and avoid jostling the current Aug. 1 deadline.
Smith said the ISO would return “soon” but didn’t provide a clearer timeline.
