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December 19, 2025

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NY Floats Initial Grid of the Future Plan

New York on March 31 issued the first iteration of a plan to move the state toward greater use of flexible resources to meet future power needs while preserving reliability and affordability.

The plan is part of the Grid of the Future proceeding (Case 24-E-0165) initiated by the Public Service Commission in April 2024. (See NY PSC Launches Grid of the Future Proceeding.) It is intended to guide development of a more expansive process for distributed system implementation plans (DSIPs) prepared by the six investor-owned utilities as they implement a distributed system platform (DSP). The second iteration of the plan is expected by the end of this year.

Earlier this year, as part of the same effort, Volumes 1 and 2 of the Grid Flexibility Study prepared by The Brattle Group were released by the Department of Public Service and New York State Energy Research and Development Authority. (See Study Finds Considerable ‘Grid Flexibility’ Potential in New York.)

The First Iteration of the Grid of the Future Plan was prepared by DNV Energy Insights USA and was released along with Volume 3 of Brattle’s Grid Flexibility Study, which provides supplemental analysis.

A central goal of the Grid of the Future proceeding is to meet the state’s ambitious clean energy goals at a manageable cost while maintaining system reliability. Flexible solutions such as distributed energy resources and virtual power plants are potential means to accomplish this.

The plan seeks to develop a DSIP process better aligned with the Grid of the Future proceeding, and to provide short- and long-term recommendations to ensure that DSIP filings are aligned with the state’s 2030 and 2040 goals.

After a series of reviews, DNV offered several conclusions:

    • The DSIPs as currently prepared do not provide outcome- or goal-oriented information and do not contain clear objectives or metrics, so it is difficult to assess whether a utility is progressing toward a functional DSP.
    • Reporting, detail and organization are inconsistent among the DSIPs, and some answers to complex questions are incomplete; collective action among the utilities resulted in more comprehensive answers.
    • New York’s regulatory environment is not an undue obstacle to development of a DSP; instead, the most significant headwinds are grid investment costs and market design, which hinder efficiency and slow adoption. The most significant tailwinds are data access and standardized interconnection requirements.
    • Some of the capabilities critical to a DSP are fully deployed and integrated but many have not been automated, are not well-integrated or are not deployed utility-wide.

DNV offered recommendations along the themes of reorganization, clarity and standardization:

    • Department of Public Service staff should clarify their guidance to utilities to elicit clearer and more consistent responses, and to reduce the inconsistencies between DSIPs.
    • Multipronged questions should be eliminated; content organization should be prescribed; and explicit expectations about answers should be offered.
    • Technical topic areas can be further streamlined and reorganized to better reflect the evolving needs of a DSP.

DNV also offered recommendations to transform the DSIP process from a regulatory check-in to a strategic tool to guide utilities, regulators and stakeholders:

    • Future versions of the DSIPs could focus on the value and intended outcomes of the processes and activities rather than just documenting them, and could include specific metrics to track progress.
    • More detailed and streamlined guidance that includes standardized templates and metrics would make DSIPs more consistent and digestible, as well as easier to compare.
    • Addressing gaps identified by the capabilities in the DSP framework will ensure DSIPs are comprehensive; including a focus on market design and implementation will allow reporting on grid edge capabilities.

The authors expect the Second Iteration of the Grid of the Future Plan to provide more specific recommendations. It is due to be released by Dec. 31, although the First Iteration and the Grid Flexibility Study both were delivered after their original target dates.

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NYPA to Buy Former Power Plant Site for $206M

The New York Power Authority plans to buy a New York City site where a power plant once stood and reuse it for clean energy infrastructure. 

The state-owned entity is working to expand its generation and transmission portfolio as part of New York’s long-term efforts to generate more electricity with less carbon emissions. 

The 15.7-acre site in Astoria, near the waterfront in the northwest corner of Queens, could support that initiative: It is adjacent to existing NYPA assets, zoned for utility infrastructure and situated within a load pocket. 

NYPA’s Board of Trustees in late March approved its purchase for $206 million; the deal is expected to close in June. 

The recent history of the site reflects the changing nature of New York’s power portfolio. 

A subsidiary of NRG Energy sought to refurbish its aging 558-MW peaker plant with a new 437-MW turbine but was denied permission by state regulators, who determined the move would not comply with greenhouse gas emission limits. (See New York Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.) 

So instead, NRG decided to demolish it and sell the land to an entity created by bp and Equinor. (See NRG to Demolish Astoria Plant, Sell Site to OSW Firm.) They planned to build the Astoria Gateway for Renewable Energy there, as a landing site for electricity from their Beacon Wind project. 

But Beacon Wind ran into economic trouble in 2023 and canceled its New York offtake contract. Equinor and bp dissolved their partnership, with bp taking full ownership of the Astoria site. 

More recently, bp withdrew its request for state authorization of the Beacon Wind export cable. A spokesperson noted that New York now is considering coordinated offshore transmission for multiple projects, an approach the company supports. (See Beacon Wind Withdraws Export Cable Request.) 

The sale of the Astoria site is conditioned on the Public Service Commission declaring it is not subject to review under Public Service Law. A petition to that effect was submitted March 20 (Case 25-E-0192). 

NYPA did not indicate a specific plan or intended use for the site, only that it would be used for future energy system enhancements and energy infrastructure to support integration of clean energy in New York City, where NYPA now operates multiple fossil fuel-fired plants — including in Astoria. 

The same legislation that expanded NYPA’s authority to develop renewables also mandated that it stop using fossil fuels to run its peaker plants by 2030. 

“Acquiring this land adjacent to our existing Astoria energy complex is yet another step forward to support New York’s clean energy future,” NYPA Chair John Koelmel said in a press release. “This strategic investment enables the Power Authority to explore options for reliable, sustainable energy infrastructure that aligns with the state’s ambitious decarbonization goals while also ensuring resiliency of the state power grid.” 

New York City is heavily reliant on fossil-fired generation even as a large percentage of upstate New York’s power comes from emissions-free sources. Emissions from power plants and vehicles in high-traffic areas degrade the air quality significantly in some city neighborhoods: Astoria and adjoining areas are known as “Asthma Alley,” for example. 

As a result, even incremental steps toward decarbonization of the city’s grid are celebrated by neighborhood leaders such as state Rep. Jessica Gonzalez-Rojas, whose district includes the Astoria site. 

“Acquiring this land in Astoria is a significant achievement and a major step toward New York’s ambitious — but achievable — environmental goals,” she said in NYPA’s release. “Transforming a former fossil fuel site into a space for sustainable energy is especially redemptive for the Queens communities, which have long faced some of the highest rates of pollution-related illnesses.” 

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Citing Inflation and Load Growth, Dominion Asks Virginia for Higher Rates

Dominion Energy Virginia has filed for its first base rate increase in decades, citing pressure from inflation and the need to reliably serve a growing customer base.

The request would raise the typical residential customer’s bill by $8.51/month starting Jan. 1, 2026, and another $2/month starting Jan. 1, 2027, Dominion said in an application filed March 31 with the State Corporation Commission (PUR-2025-00058). The new rates would mark the first increase in base rates since 1992. Dominion said its residential rates have increased by 40% lower than the rate of inflation over the past decade.

“We’re focused on providing exceptional value for our customers every single day,” Ed Baine, Dominion president of utility operations, said in a statement. “Outside of major storms, we deliver uninterrupted power 99.9% of the time, and we’re significantly reducing storm-related outages as well. This proposal allows us to continue investing in reliability and to serve our customers’ growing needs.”

The last biennial rate case came in 2023, and since then the company has faced higher costs of labor and materials including cables and wires, poles, transformers and power generation equipment.

In a separate application to the SCC (PUR-2025-00059), Dominion asked to move higher power capacity costs from its base rate to the annual fuel rate that would take effect July 1 and raise the monthly fuel rate paid by a typical residential customer by $10.92. The higher bills also include the fuel cost from extended cold weather this January and a $3.99 fuel credit from a previous rate case. Dominion passes through those costs and does not earn a profit on them.

Moving capacity expenses to fuel will increase the fuel factor by $1.98 for the typical residential customer, but it leads to a drop in base rates of $6.22 starting Jan. 1, 2026, according to the firm’s public application with the SCC.

Separating out PJM capacity prices into base rates and energy market costs in its fuel rates predates Dominion’s membership in the RTO and likely would not be done today given how much the company has to pay under the Reliability Pricing Model.

The delays in running auctions also prompted Dominion to make the request as it cannot accurately forecast what the price will be through the end of 2027, with two more auctions yet to run and one that will come after its rate case, it told the SCC.

On top of the new rates, Dominion also proposed creating a new rate class for high energy users that would cover data centers, and ensuring that those high-use customers pay their full cost of service and others are protected from stranded costs. Under the proposal, high energy users would have to make a 14-year commitment to pay for their requested power, even if they use less.

The Piedmont Environmental Council said that because the General Assembly failed to pass any meaningful reforms to how data centers are handled, the SCC’s review of Dominion’s rate case and its integrated resource plan are important to ensuring their growth is handled while keeping prices reasonable and environmental goals within reach. The group said it would work to ensure data centers pay their fair share.

“Virginia is in danger of falling behind and becoming the ‘how not to’ example that other states are using to avoid what has happened here. Ohio, Georgia, Texas, Indiana, Washington and Maryland are doing what Virginia’s policymakers and regulators have failed to do thus far,” PEC President Chris Miller said in a statement. “The SCC has the opportunity to take action now — and ensure data centers won’t overwhelm the power grid, drain statewide water resources and further intrude on areas never meant to be industrialized.”

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Wash. Relaunches Cap-and-trade Rulemaking to Link with Calif., Quebec

Washington state has relaunched rulemaking that will pave the way for linking the state’s cap-and-trade program with the already-linked programs of California and Quebec. 

The new rulemaking will replace previous linkage rulemaking for Washington’s cap-and-invest program, which is the state’s name for cap-and-trade. The latest rulemaking will cover a wider range of topics, the Washington Department of Ecology announced March 31. 

The earlier rulemaking started in April 2024. The Department of Ecology held public meetings and released draft rules July 1. Comments and information gathered during the previous linkage rulemaking will be used as part of the new rulemaking, the department said. 

The potential rule changes will help Washington’s cap-and-invest program align with cap-and-trade programs in California and Quebec, although a new rule won’t create a linkage among the programs on its own. 

In cap-and-trade programs, major greenhouse gas emitters must buy allowances that correspond to the amount of their emissions; the state also imposes an emissions cap that decreases over time. The state may use proceeds from allowance auctions to fund climate projects. 

Linking carbon markets of multiple jurisdictions allows for joint allowance auctions, a common allowance price and trading of allowances between jurisdictions. With a larger pool of buyers and sellers, the linked markets generally have more consistent pricing and fewer price swings, the Department of Ecology said. 

California and Quebec linked their cap-and-trade programs in 2014. Washington launched its cap-and-invest program in January 2023, and last year, the state legislature passed Senate Bill 6058, intended to facilitate the linkage with the California-Quebec market. 

“We believe linkage will strengthen our respective efforts to fight climate change and reduce air pollution, while also encouraging more governments to adopt scalable, market-based climate policies in the future,” the three jurisdictions said in a joint statement issued in September.  

Topics Covered

The new Washington state rulemaking involves changes to two rules: the Climate Commitment Act Program Rule and Reporting of Emissions of Greenhouse Gases Rule. 

The previous rulemaking considered a range of topics, including compliance period length, program registration requirements and allowance purchase limits. 

Electricity sector topics included reporting for electric power entities, coverage for imported electricity from unspecified sources, participation requirements for federal power marketing administrations and greenhouse gas emissions reporting methods. 

Additional topics will be considered in the new rulemaking, including: 

    • imported electricity associated with centralized electricity markets; 
    • the amount of allowances allocated at no cost to electric utilities that must be consigned to auction during the second compliance period; and 
    • adoption of allowance budgets for the second compliance period (2027-2030) to ensure that emissions reductions are aligned with the state’s greenhouse gas emissions limits for 2030, 2040 and 2050. 

The rulemaking topics may continue to evolve, the Department of Ecology noted, as California and Quebec work on potential changes to their cap-and-trade regulations. And legislation enacted in Washington state this year could prompt further rule changes. 

The department will hold public meetings for the new rulemaking this spring through fall. The department expects to release a proposed rule early next year and adopt rule changes in summer 2026. An environmental justice assessment will also be conducted as part of the rulemaking. 

The department previously projected that a linkage agreement could be in place in 2026, with linked markets beginning to operate in 2026 or 2027. 

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Reliability Projects Dominate CAISO’s $4.8B Draft Transmission Plan

CAISO’s 2024/25 draft transmission plan recommends 31 new projects at an estimated cost of $4.8 billion, slanting heavily toward reliability needs.

The plan is based on California Public Utilities Commission forecasts projecting the state must add more than 76 GW of new capacity by 2039, the ISO said in the draft.

“This reflects greenhouse gas reduction goals and load growth, including the potential for increased electrification occurring in other sectors of the economy, most notably in transportation and the building industry,” CAISO wrote.

The new capacity needs include 30 GW of solar generation spread throughout the state, 7 GW of in-state wind resources in existing wind development regions, and more than 4.5 GW of offshore wind in the Morro Bay and Humboldt call areas.

The plan also factors in the need to import an additional 9 GW of wind energy from Idaho, Wyoming and New Mexico, which will require “enhancing corridors from the ISO border in southeastern Nevada and from western Arizona into California load centers.”

The plan additionally considers the transmission access needs of co-located battery storage projects across California, as well as for standalone projects close to major load centers in the Los Angeles Basin, the Greater Bay Area and San Diego.

“Our draft plan reflects the ISO’s proactive approach to transmission planning and underscores our ongoing collaboration with local, state and regional partners to ensure California has the necessary infrastructure to deliver clean energy reliably and cost-effectively to consumers,” Neil Millar, CAISO vice president for transmission planning and infrastructure development, said in a statement.

The ISO noted some of the projects would use grid-enhancing technologies.

Mostly Reliability

Twenty-eight reliability-driven projects account for nearly all the proposed spending, at roughly $4.56 billion.

“While the resource planning needs have not increased materially from those reflected in last year’s transmission plan, the increased rate of load growth reflected in the most recent load forecast associated with building and other electrification, data center growth and transportation electrification results in significant reliability-driven needs in this year’s transmission plan,” the plan says.

The 2024/25 plan assumes the state’s peak demand will increase at a 1.53% yearly rate, compared with a 0.99% forecasted growth rate in the previous plan. Peak demand in the Greater Bay Area now is expected to grow by 2.14% annually (up from 1.22%), translating into a 2,000-MW increase in the region’s 2035 peak load forecast, “with most of the growth coming from electrification of the transportation and building sectors of the state’s economy and an anticipated increase in data centers associated with artificial intelligence.” (See Data Centers Contribute to 60% Increase in San Jose Load Forecast.)

The Bay Area would host the priciest reliability projects in the plan, including Pacific Gas and Electric’s North Oakland ($1.13 billion) and Greater Bay 500-kV transmission ($700 million) reinforcement projects. San Diego Gas & Electric’s Downtown Reliability reinforcement project comes in third at $500 million.

Three policy-driven projects would entail about $289.5 million in spending.

All three recommended policy projects are in PG&E’s territory, including two in Fresno and one in the North Coast/North Bay local area. “They are needed to meet the renewable generation requirements established in the CPUC-developed renewable generation portfolios,” the ISO said.

CAISO said the plan identified no economically driven projects, representing those that would reduce costs for ratepayers but are not needed for reliability.

The ISO said the 31 recommended projects “represent significant investments that are phased in over lead times of up to eight to 10 years, which are reasonable for some of the projects to be completed.”

Costs would translate into about 0.5 cents/kWh over the life of the projects and will be phased in as lines come into service, the ISO said.

CAISO will hold an April 15 public stakeholder call on the draft plan and is taking comments through April 29. The ISO’s Board of Governors is expected to vote on the plan at its May meeting.

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Maine Floating OSW Negotiations Halted

Negotiations on what could have become the first floating offshore wind array in the U.S. have halted amid the uncertainty that has gripped the country’s offshore wind industry. 

The Maine Public Utilities Commission on March 28 granted the request of Pine Tree Offshore Wind to suspend talks on a contract to support construction of a research project with up to 12 turbines with a capacity of up to 144 MW. 

The move is the latest setback for the state of Maine’s long-running ambitions to exploit the windy waters off its coast for environmental and economic benefit through installation of wind turbines and creation of a new commercial/industrial sector:

    • The depth of the Gulf of Maine dictates that floating turbines be used there, and floating wind technology still is in development.
    • The state lost out on a $456 million federal grant to develop an offshore wind port; also, the chosen site is a nature preserve, and development is strongly opposed by some advocates. (See Maine Chooses Nature Preserve for Floating Wind Port.)
    • The first-ever Gulf of Maine commercial lease auction was a lackluster affair, with four of the eight offered lease areas drawing just $22 million in combined winning bids and the other four going unsold. (See Gulf of Maine OSW Auction Results in Four Leases Worth $21.9M.)
    • And of course, Donald Trump was elected president on a platform that included halting offshore wind development. Pine Tree is only the latest of several developers to pause their efforts in U.S. waters amid Trump’s efforts to follow through on his campaign pledge.

The state of Maine requested the research lease in October 2021 and designated Pine Tree as its operator. The U.S. Bureau of Ocean Energy Management executed the research lease (OCS-A 0553) in August 2024. (See Maine Approved for Floating Wind Research Lease.) 

The zone totals nearly 15,000 acres roughly 28 nautical miles southeast of Portland. 

The Maine PUC opened the docket (Case 2022-00100) for consideration of Pine Tree’s contract in April 2022. In December 2024, Pine Tree requested and received an extension to March 31, 2025, of the deadline to submit a proposed contract supporting the offshore wind research array. 

The negotiations apparently were fruitless: Pine Tree subsequently requested they be suspended “due to recent shifts in the energy landscape that have in particular caused uncertainty in the offshore wind industry.” 

On March 28, the PUC approved the request for suspension, finding that “good cause exists” and noting that no objections were raised by the other negotiating parties: the governor’s Energy Office, the Office of the Public Advocate, Central Maine Power and Versant Power. 

The suspension will continue until Pine Tree requests that negotiations resume. 

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Newsom Issues Order to Speed Undergrounding of Lines in Los Angeles

California Gov. Gavin Newsom has suspended environmental laws to accelerate the undergrounding and hardening of utility equipment in communities ravaged by the Los Angeles wildfires.  

Newsom’s executive order removes requirements under the California Environmental Quality Act and the California Coastal Act in an effort to speed up “the rebuilding of utility and telecommunication infrastructure, including the undergrounding of equipment,” according to a March 27 news release. 

A previous executive order similarly suspended the environmental laws and applied to infrastructure damaged in the wildfires. However, that order was limited, and projects to move equipment underground or upgrade existing infrastructure may not qualify under the previous suspension, the most recent order stated. 

“We are determined to rebuild Altadena, Malibu and Pacific Palisades stronger and more resilient than before,” Newsom said in a statement. “Speeding up the pace that we rebuild our utility systems will help get survivors back home faster and prevent future fires.” 

In a Feb. 27 letter, Newsom urged Southern California Edison and Los Angeles Department of Water and Power to develop plans by the end of March on how the utilities can rebuild safer and resilient electric infrastructure, including by placing electric distribution infrastructure underground. 

Jeff Monford, a spokesperson for SCE, told RTO Insider the utility appreciates “Gov. Newsom’s action to help expedite permitting so the fire-damaged communities can rebuild stronger. We look forward to continuing our work with federal, state and local officials to shorten permitting times under this executive order.” 

SCE already has launched efforts to underground several miles of lines in Altadena and Pacific Palisades, “and some sections of the grid will be completed in a few months,” Monford said. 

Monford would not share specific cost information but noted that undergrounding costs significantly more than building the grid with power poles. 

“There’s a lot going on in these burn areas, and the expedited permitting, siting and permitting that the governor’s order will allow will certainly help move that along,” he added. 

Local utility Pasadena Water and Power, which operates in the Altadena region that was devastated following the Eaton fire, said in an email that “nothing in the orders change any policy direction and capital projects that we have planned.” 

The Eaton Fire began shortly after 6 p.m. Jan. 7 and burned more than 14,000 acres and killed 17 people. The deadly fire engulfed parts of the Altadena community, with thousands of structures either damaged or destroyed, according to Cal Fire. 

The Pacific Palisades fire burned 23,448 acres, destroyed 6,837 structures and killed 12 people. 

SCE faces several lawsuits, alleging the utility’s lines started the Eaton fire. SCE has said it is investigating possible links between its equipment and the fire. (See SCE Probes Link Between Equipment and Eaton Fire.) 

The utility previously acknowledged its equipment may have sparked the Hurst Fire, which burned roughly 799 acres and damaged two homes. There were no reports of fatalities or injuries associated with the fire. SCE said it is cooperating with a Los Angeles Fire Department investigation. 

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TVA Board Promotes Nuclear Veteran from COO to CEO

The Tennessee Valley Authority board of directors announced it will elevate COO Don Moul to become the fourth CEO of the federal utility.

The promotion further positions TVA for a nuclear-dominant future. Moul previously served as a chief nuclear officer and senior nuclear reactor operator, among other primarily nuclear roles at American Electric Power, Duquesne Light Co., FirstEnergy, GPU Nuclear Corp. and Public Service Electric & Gas.

Moul, who has 38 years of experience in the power industry, replaces outgoing CEO Jeff Lyash, who also has an extensive background in nuclear operations. (See TVA CEO Jeff Lyash Announces Plans to Retire.) The appointment becomes effective April 9 and makes Moul the second TVA COO to earn a CEO promotion. TVA’s first CEO, Tom Kilgore, also was COO before Congress established the CEO position in 2005.

Before joining TVA in mid-2021, Moul was executive vice president and chief nuclear officer at NextEra Energy, where he oversaw operations at seven units as well as decommissioning of the Duane Arnold Energy Center.

Announcement After Senator Criticism, Board Member Dismissal

Moul’s advancement follows Sens. Marsha Blackburn and Bill Hagerty, both Republicans of Tennessee, authoring a March 20 op-ed in POWER Magazine calling for the next TVA leader to lead the “nation’s nuclear energy revival” and fall in step with President Donald Trump’s vision for more nuclear power.

The senators criticized the utility’s leadership and board for moving too slowly on nuclear development and said they were concerned “TVA’s next CEO would be hired from within.”

TVA holds the country’s only early site permit for small modular reactor (SMR) construction at its Clinch River Nuclear Site in Oak Ridge, Tenn. U.S. Energy Secretary Chris Wright and Hagerty toured the site in mid-March. While TVA’s board authorized $350 million in 2024 to explore nuclear solutions, it has not yet voted to approve an SMR at the site. Lyash has said TVA eventually aims to build a fleet of SMRs in its footprint.

“The presidentially appointed, Senate-confirmed, TVA board of directors lacks the talent, experience and gravitas to meet a challenge that clearly requires visionary industrial leaders. The group looks more like a collection of political operatives than visionary industrial leaders,” Blackburn and Hagerty wrote.

A week later, TVA board member L. Michelle Moore, an appointee of former President Joe Biden, was fired at the direction of Trump, according to a Securities and Exchange Commission report. The Trump administration has not provided a reason for Moore’s termination. In a statement, TVA said its board members serve at the pleasure of the president.

Moore’s term would have expired on May 18, 2026. The Southern Alliance for Clean Energy called the firing a “hyper-partisan action.”

The board currently has five members and four vacancies.

TVA Underscores Nuclear in Announcement

In a press release on Moul’s hiring, TVA focused on its nuclear advancements. It said under Moul’s leadership, “TVA is a national leader in driving advanced nuclear technologies forward.”

“Don is ready to be the hand guiding TVA in a time of rapid change and growth, and he will continue to propel TVA’s nuclear leadership,” Lyash said. “In his role as COO, he has led the development of next-generation nuclear technologies and has a deep knowledge and appreciation for nuclear power — the most reliable power the world’s ever known.” Lyash also said TVA hired Moul four years ago “with succession planning in mind.”

Moul said he expected his transition to be “seamless” for TVA.

“We’re in a period of growth like we’ve not seen before, and to meet that growth, we are making one of the largest capital investments in our history,” Moul said. “TVA needs a steady hand right now. I will build on the momentum that Jeff and our team have created — making sure we continue to invest in new generation, strengthen our grid and enhance system reliability.”

Moul told the Knoxville News Sentinel the board conducted an internal and external search for a new CEO before they offered him the job after a series of interviews. TVA confirmed that the offer was extended on March 25 and predated Moore’s termination.

Board Chair Joe Ritch said the board search was exhaustive.

“The TVA board took a structured, deliberative approach to CEO succession — evaluating a strong slate of both internal and external candidates,” Ritch said in a statement to RTO Insider. “The board evaluated multiple search firms, reviewing in detail their process for candidate identification and assessment, ultimately selecting a firm with deep experience and expertise in the energy industry. The board also leveraged a third-party leadership assessment firm and an independent compensation consultant.”

Lyash is set to retire as the highest-paid federal employee, making $10.5 million in total compensation over 2024.

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FERC Announces Impending Order on ISO-NE Order 2023 Compliance

FERC plans to rule on ISO-NE’s compliance proposal for Order 2023 on or before April 4, the commission announced in a short notice March 31 (ER24-2009, ER24-2007). 

The announcement came on the date of a key deadline for ISO-NE’s compliance timeline after repeated requests for rapid action by state officials and generation developers. 

ISO-NE initially requested FERC accept its compliance proposal with an effective date of Aug. 12, 2024. The RTO suspended its work implementing its proposal in October 2024 because of the lack of a ruling from FERC. (See With FERC Inaction, ISO-NE Delays Order 2023 Implementation.) 

In recent months, stakeholders have voiced worries the delay may hinder resource development in the region and increase prices in upcoming capacity auctions. (See New England Clean Energy Developers Struggle with Order 2023 Uncertainty.) 

Some stakeholders have expressed particular concern about the fate of ISO-NE’s proposed transitional capacity network resource (CNR) group study, which is intended to enable late-stage projects with complete system impact studies to achieve capacity interconnection rights.

In its original filing, ISO-NE wrote that the transitional CNR study, set to occur prior to the transitional cluster study (which would include all other interconnection requests), “avoids the need to include these requests in the transitional cluster study, thereby creating efficiencies by reducing the number of requests included in that study.” 

ISO-NE said it would need an order by the end of March to align the transitional CNR study with the 2025 Interim Reconfiguration Auction Qualification process, which includes a show-of-interest submission deadline at the end of April. But in late March, ISO-NE told stakeholders it likely would not be able to proceed with the transitional CNR study. (See ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC.) 

In response to FERC’s announcement, an ISO-NE spokesperson said the RTO will assess its options once the order is issued.  

ISO-NE also confirmed it reopened the interconnection queue April 1. The queue had been closed since June 13, 2024, which is the RTO’s proposed deadline for projects to have a valid interconnection request to participate in the transitional cluster. 

It is unclear if projects that enter the queue after this date will be eligible for the cluster, and ISO-NE has said it “cannot guarantee the treatment of [interconnection requests] submitted after the June 13, 2024, eligibility date.” 

Alex Lawton of Advanced Energy United said FERC’s announcement “has given us renewed hope that the ISO can reverse course and proceed with the transitional CNR group study as previously planned. Should the FERC order largely accept the compliance filing, we are confident the ISO will explore how to proceed in a manner that causes the fewest delays and resembles our stakeholder-supported original plan as much as possible.” 

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NERC Responds to Interregional Transfer Capability Study Comments

NERC’s Interregional Transfer Capability Study represents “a crucial input in development of a modern, reliable, grid” despite its limited congressional mandate and time frame, the agency said in responding to comments on the report March 25.  

NERC filed the ITCS with FERC in November 2024 as directed by the Fiscal Responsibility Act of 2023. In accordance with Congress’ order, the study outlined current transfer capabilities across the U.S. grid, recommendations for prudent additions that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability (AD25-4).  

After the public comment period ordered by the FRA, FERC will submit recommendations for statutory changes, if any, to Congress. 

The ERO’s recommendations included 35 GW of additional transfer capability across FERC’s planning regions, with more than 14 GW in ERCOT across the SPP-South connection and two entirely new connections. (See NERC Releases Final ITCS Draft Installments.) This suggestion prompted a comment from ERCOT, which pointed out that about 32 GW of solar and wind resources have come online in Texas since Winter Storm Uri in 2021 and said NERC’s analysis may not have fully accounted for these additions. 

“The nameplate capacity these resources have added to the ERCOT system is more than double the 14 GW of interregional transmission the ITCS recommends for the ERCOT region,” ERCOT said. “The ITCS’ attempt to account for future resource growth on the ERCOT system likely underestimates the resource additions that will actually occur as ERCOT continues to commission new resources at a record pace, connecting over 12 GW of new generation in 2024 alone, on top of the 7 GW connected in 2023.” 

ERCOT also cautioned that the ITCS “may be overly optimistic” in its expectations for the proposed transmission expansions, noting that “generation resources must still be available to provide power … over those transmission lines.”  

The ISO said market incentives, which the ITCS did not take into account, “are an indispensable part of energy adequacy and future generation growth [and] are actively being examined and refined in the ERCOT region.” 

In response, NERC said it recognizes the potential impact of market mechanisms on energy adequacy, although they were not a part of the ITCS. In addition, the ERO acknowledged that the effect of “connections such as ERCOT to” SERC Southeast — mentioned in the report — needed more study than Congress allotted time for. It pointed out the report contains a chapter with areas for future study to understand the relationship between transfer capability and grid reliability. 

NERC also replied to a comment from the Eastern Interconnection Planning Collaborative, an association of 18 planning authorities from the Eastern and Central U.S., which argued for expanding the ITCS by “adding credit for transmission products and plans” and warned against using the study “as a metric for determining prudent additions.” (See EIPC: Transmission Studies Need More ‘Granularity’.) 

The ERO observed that such a change “would have exceeded the scope of the” FRA and might even have usurped FERC’s responsibility to recommend regulatory action. However, NERC said it would continue separately to highlight the issues raised by EIPC and would urge policymakers and industry to take them under consideration. 

Finally, NERC pushed back on a comment from sponsors of the South Carolina Regional Transmission Planning Process and the Southeastern Regional Transmission Planning Process, which between them comprise a number of utilities, including Dominion Energy South Carolina, Santee Cooper, Associated Electric Cooperative and Duke Energy. The SCRTP and SERTP sponsors claimed that while NERC facilitated stakeholder engagement during the first phase of analysis, for the most part the ERO could not engage stakeholders during the second phase “due to time constraints.” 

NERC countered this assertion, saying it had engaged in outreach at every stage, including “consulting with transmitting utilities and other stakeholders” in the Southeast. The ERO also emphasized that its consultation process for the second phase of analysis consisted of multiple steps that continued through more than half of 2024, and that the ITCS Advisory Group of grid stakeholders “included two representatives from the Southeastern U.S.”